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04.08.2021 07:35:00
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Callon Petroleum Company Announces Second Quarter 2021 Results
HOUSTON, Aug. 4, 2021 /PRNewswire/ -- Callon Petroleum Company (NYSE: CPE) ("Callon" or the "Company") today reported results of operations for the three and six months ended June 30, 2021.
Presentation slides accompanying this earnings release are available on the Company's website at www.callon.com located on the "Presentations" page within the Investors section of the site.
Second Quarter 2021 and Recent Highlights
- Delivered production of approximately 89.0 MBoe/d (63% oil) in the second quarter of 2021
- Generated net cash provided by operating activities of $175.6 million and adjusted free cash flow1 of $6.9 million
- Net loss of $11.7 million, or $0.25 per diluted share, driven primarily by a loss on derivative contracts of $190.5 million, adjusted EBITDA1 of $196.8 million, and adjusted income1 of $70.3 million, or $1.49 per diluted share
- Achieved an operating margin of $37.76 per Boe, a 13% increase from the previous quarter
- Completed the divestiture of certain non-core assets for aggregate net cash proceeds of $30.7 million
- Issued $650 million of new 8.00% senior unsecured notes due 2028 and completed the redemption of the 6.25% senior unsecured notes due 2023
- Received company credit rating upgrades from both Moody's and S&P following successful senior notes offering
- Reduced the outstanding balance on Callon's senior secured credit facility to approximately $780 million, representing less than 50% utilization of the available capacity2
- Executed Callon's largest multi-well project in history, the 29-well Irvin West project, driving robust production growth with July volumes estimated to be approximately 10% above second quarter average daily production
- Issued the company's second annual sustainability report, highlighting meaningful improvement in key categories as well as incremental transparency measures and alignment with both SASB and TCFD reporting standards.
Joe Gatto, President and Chief Executive Officer, commented, "Our team advanced critical priorities during the second quarter, preparing ourselves for a very strong second half of 2021. We generated positive adjusted free cash flow for the fourth consecutive quarter, despite the second quarter being our highest projected capital spending period of the year. We actively managed our nearest maturities and further reduced our credit facility borrowings, both of which support a continued upward trajectory in our credit profile. The third quarter is off to a tremendous start with July production volumes well ahead of our second quarter average and our commodity price realizations are projected to benefit from the reduction in overall hedged production. Our adjusted free cash flow during the third and fourth quarter should further reduce our credit facility borrowings and continue to advance our deleveraging goals with the potential to accelerate that timeline through selective monetizations."
He continued, "We recently issued our 2020 Sustainability report showing meaningful improvement in numerous critical areas including greenhouse gas emissions reductions, flaring, and safety. In addition, we have aligned our disclosure with both the Sustainability Accounting Standards Board ("SASB") and the Task Force on Climate-Related Financial Disclosures ("TCFD") frameworks providing additional clarity and transparency on issues that our shareholders and stakeholders value. This represents another step towards achieving alignment with shareholder expectations."
Issuance of 2028 Senior Unsecured Notes and Redemption of 2023 Senior Unsecured Notes
On June 21, 2021, the Company entered into a Purchase Agreement where it issued $650.0 million in aggregate principal amount of 8.00% senior unsecured notes due 2028 (the "8.00% Senior Notes") through private placement, which closed on July 6, 2021 for net proceeds of approximately $638.1 million, net of underwriting discounts and commissions and offering costs.
Also on June 21, 2021, the Company delivered a redemption notice with respect to all $542.7 million of its outstanding 6.25% senior unsecured notes due 2023 (the "6.25% Senior Notes"), which became redeemable on July 21, 2021. The Company used a portion of the net proceeds from the 8.00% Senior Notes to redeem all of its outstanding 6.25% Senior Notes with the remaining proceeds used to partially repay amounts outstanding under its Credit Facility.
Following the issuance of the new 8.00% Senior Notes, Callon was upgraded by both Moody's and S&P at the corporate level due to improving credit metrics and corporate outlooks. Moody's raised Callon's corporate family ratings to B3 and S&P raised its issuer credit rating to B- with a stable outlook.
Credit Facility and Liquidity
On May 3, 2021, Callon completed the spring redetermination for its senior secured credit facility. The borrowing base and elected commitment were both reaffirmed at $1.6 billion. As of June 30, 2021, the drawn balance on the facility was $875.0 million and cash balances were $3.8 million. Upon completion of the redemption of the 6.25% Senior Notes, the remaining proceeds from the issuance of the 8.00% Senior Notes were used to repay outstanding borrowings on the credit facility further reducing the outstanding balance to approximately $780.0 million2.
Sale of Delaware Basin Assets
During the second quarter of 2021, the Company completed its divestitures of certain non-core assets in the Delaware Basin for aggregate net cash proceeds of $30.7 million, subject to post-closing adjustments. The divestitures were primarily comprised of natural gas producing properties in the Western Delaware Basin as well as a small undeveloped acreage position.
Operations Update
At June 30, 2021, Callon had 1,536 gross (1,359.2 net) wells producing from established flow units in the Permian and Eagle Ford. Net daily production for the three months ended June 30, 2021 was 89.0 MBoe/d (63% oil).
For the three months ended June 30, 2021, Callon drilled 8 gross (6.5 net) wells and placed a combined 47 gross (44.9 net) wells on production. Wells placed on production during the quarter were completed in the Eagle Ford in South Texas, the Delaware Basin and the Midland Basin.
During the second quarter, Callon placed on production 29 gross wells in the Eagle Ford as part of its Irvin West project, the largest horizontal well development project in Company history. With an average lateral length of approximately 6,200 feet, the project involved the completion of more than 760 unique frac stages and has demonstrated very solid productivity with current rates averaging approximately 400 barrels of oil per day per well.
In the Delaware Basin, the Company turned to production multi-well projects in both Reeves and Ward Counties. In Ward County, the Limber Pine project featured co-development of the Bone Spring, Upper Wolfcamp A, Lower Wolfcamp A and Wolfcamp B. Initial production has been positive and the wells are currently slated to be converted to electric submersible pumps ("ESPs"), which have contributed to strong productivity increases across the Delaware asset base in recent quarters. The Bush Griffin project in Reeves county was placed on production in June and early time results are tracking ahead of estimates.
The only pad placed on production during the second quarter in the Midland Basin was the Chaparral three-well project targeting the Lower Spraberry, Wolfcamp A, and Wolfcamp B. The Chaparral project was a very successful first test of an E-Frac fleet employing a crew from US Well Services. Production from this pad has significantly exceeded production estimates producing an average of more than 90 MBoe per well through the first 75 days online.
Current planned development activity in the second half of 2021 will involve three to four drilling rigs with projects spanning the Eagle Ford, Midland Basin, and Delaware Basin. Completion activity and wells turned to production will focus more heavily on Midland Basin and Delaware Basin projects during the third and fourth quarters.
Capital Expenditures
For the three months ended June 30, 2021, Callon incurred $138.3 million in operational capital expenditures on an accrual basis. Total capital expenditures, inclusive of capitalized expenses, are detailed below on an accrual and cash basis:
Three Months Ended June 30, 2021 | ||||||||||||
Operational | Capitalized | Capitalized | Total Capital | |||||||||
Capital (a) | Interest | G&A | Expenditures | |||||||||
(In thousands) | ||||||||||||
Cash basis (b) | $111,344 | $30,914 | $7,404 | $149,662 | ||||||||
Timing adjustments (c) | 28,379 | (9,174) | — | 19,205 | ||||||||
Non-cash items | (1,402) | 2,187 | 4,647 | 5,432 | ||||||||
Accrual basis | $138,321 | $23,927 | $12,051 | $174,299 | ||||||||
(a) | Includes drilling, completions, facilities, and equipment, but excludes land and seismic. |
(b) | Cash basis is presented here to help users of financial information reconcile amounts from the cash flow statement to the balance sheet by accounting for timing related changes in working capital that align with our development pace and rig count. |
(c) | Includes timing adjustments related to cash disbursements in the current period for capital expenditures incurred in the prior period. |
Guidance
For the third quarter, the Company expects to produce between 95.5 and 97.5 MBoe per day (64% oil). In addition, Callon projects an operational capital spending level of between $120 and $130 million on an accrual basis.
Hedge Portfolio Summary
As of August 2, 2021, Callon had the following outstanding oil, natural gas and NGL derivative contracts:
For the Remainder | For the Full Year | For the Full Year | |||||||
Oil contracts (WTI) | of 2021(a) | of 2022(a) | of 2023 | ||||||
Swap contracts | |||||||||
Total volume (Bbls) | 1,104,000 | 3,015,000 | — | ||||||
Weighted average price per Bbl | $42.10 | $63.55 | $— | ||||||
Collar contracts | |||||||||
Total volume (Bbls) | 5,522,775 | 7,097,500 | — | ||||||
Weighted average price per Bbl | |||||||||
Ceiling (short call) | $49.16 | $67.70 | $— | ||||||
Floor (long put) | $40.71 | $56.15 | $— | ||||||
Long put contracts | |||||||||
Total volume (Bbls) | 414,000 | — | — | ||||||
Weighted average price per Bbl | $62.50 | $— | $— | ||||||
Short call contracts | |||||||||
Total volume (Bbls) | 2,432,480 | (b) | — | — | |||||
Weighted average price per Bbl | $63.62 | $— | $— | ||||||
Short call swaption contracts | |||||||||
Total volume (Bbls) | — | 1,825,000 | (c) | 1,825,000 | (c) | ||||
Weighted average price per Bbl | $— | $52.18 | $72.00 | ||||||
Oil contracts (Brent ICE) | |||||||||
Swap contracts | |||||||||
Total volume (Bbls) | — | (d) | — | — | |||||
Weighted average price per Bbl | $— | $— | $— | ||||||
Collar contracts | |||||||||
Total volume (Bbls) | 368,000 | — | — | ||||||
Weighted average price per Bbl | |||||||||
Ceiling (short call) | $50.00 | $— | $— | ||||||
Floor (long put) | $45.00 | $— | $— | ||||||
Oil contracts (Midland basis differential) | |||||||||
Swap contracts | |||||||||
Total volume (Bbls) | 1,504,400 | — | — | ||||||
Weighted average price per Bbl | $0.25 | $— | $— | ||||||
Oil contracts (Argus Houston MEH) | |||||||||
Collar contracts | |||||||||
Total volume (Bbls) | — | 452,500 | — | ||||||
Weighted average price per Bbl | |||||||||
Ceiling (short call) | $— | $63.15 | $— | ||||||
Floor (long put) | $— | $51.25 | $— | ||||||
(a) | The Company has approximately $9.4 million of deferred premiums, of which $6.5 million are associated with contracts that will settle in 2021 and $2.9 million for contracts that will settle in 2022. | |||||||
(b) | Premiums from the sale of call options were used to increase the fixed price of certain simultaneously executed price swaps and three-way collars. | |||||||
(c) | The 2022 and 2023 short call swaption contracts have exercise expiration dates of December 31, 2021 and December 30, 2022, respectively. | |||||||
(d) | In February 2021, the Company entered into certain offsetting ICE Brent swaps to reduce its exposure to rising oil prices. Those offsetting swaps resulted in a locked-in loss of approximately $2.9 million, of which $1.6 million will be settled in the third quarter of 2021 with the remaining $1.3 million to be settled in the fourth quarter of 2021. | |||||||
For the Remainder | For the Full Year | |||||
Natural gas contracts (Henry Hub) | of 2021 | of 2022 | ||||
Swap contracts | ||||||
Total volume (MMBtu) | 7,301,000 | 7,320,000 | ||||
Weighted average price per MMBtu | $2.61 | $3.08 | ||||
Collar contracts | ||||||
Total volume (MMBtu) | 3,680,000 | 5,740,000 | ||||
Weighted average price per MMBtu | ||||||
Ceiling (short call) | $2.80 | $3.64 | ||||
Floor (long put) | $2.50 | $2.83 | ||||
Short call contracts | ||||||
Total volume (MMBtu) | 3,680,000 | (a) | — | |||
Weighted average price per MMBtu | $3.09 | $— | ||||
Natural gas contracts (Waha basis differential) | ||||||
Swap contracts | ||||||
Total volume (MMBtu) | 8,280,000 | 5,475,000 | ||||
Weighted average price per MMBtu | ($0.42) | ($0.21) | ||||
(a) | Premiums from the sale of call options were used to increase the fixed price of certain simultaneously executed price swaps and three-way collars. | |||||||
For the Remainder | For the Full Year | |||||
NGL contracts (OPIS Mont Belvieu Purity Ethane) | of 2021 | of 2022 | ||||
Swap contracts | ||||||
Total volume (Bbls) | 920,000 | — | ||||
Weighted average price per Bbl | $7.62 | $— | ||||
Operating and Financial Results
The following table presents summary information for the periods indicated:
Three Months Ended | ||||||||||||
June 30, 2021 | March 31, 2021 | June 30, 2020 | ||||||||||
Total production | ||||||||||||
Oil (MBbls) | ||||||||||||
Permian | 3,232 | 3,088 | 3,633 | |||||||||
Eagle Ford | 1,870 | 1,593 | 2,763 | |||||||||
Total oil (MBbls) | 5,102 | 4,681 | 6,396 | |||||||||
Natural gas (MMcf) | ||||||||||||
Permian | 7,138 | 6,208 | 8,736 | |||||||||
Eagle Ford | 1,745 | 1,627 | 2,273 | |||||||||
Total natural gas (MMcf) | 8,883 | 7,835 | 11,009 | |||||||||
NGLs (MBbls) | ||||||||||||
Permian | 1,216 | 1,075 | 1,268 | |||||||||
Eagle Ford | 299 | 224 | 389 | |||||||||
Total NGLs (MBbls) | 1,515 | 1,299 | 1,657 | |||||||||
Total production (MBoe) | ||||||||||||
Permian | 5,637 | 5,198 | 6,357 | |||||||||
Eagle Ford | 2,460 | 2,088 | 3,531 | |||||||||
Total barrels of oil equivalent (MBoe) | 8,097 | 7,286 | 9,888 | |||||||||
Total daily production (Boe/d) | ||||||||||||
Permian | 61,948 | 57,758 | 69,858 | |||||||||
Eagle Ford | 27,033 | 23,199 | 38,806 | |||||||||
Total barrels of oil equivalent (Boe/d) | 88,981 | 80,957 | 108,664 | |||||||||
Oil as % of total daily production | 63 | % | 64 | % | 65 | % | ||||||
Average realized sales price (excluding impact of settled derivatives) | ||||||||||||
Oil (per Bbl) | ||||||||||||
Permian | $65.08 | $56.66 | $23.27 | |||||||||
Eagle Ford | 65.83 | 57.80 | 16.64 | |||||||||
Total oil (per Bbl) | $65.36 | $57.05 | $20.41 | |||||||||
Natural gas (per Mcf) | ||||||||||||
Permian | $2.68 | $3.11 | $0.95 | |||||||||
Eagle Ford | 2.82 | 3.03 | 1.73 | |||||||||
Total natural gas (per Mcf) | $2.71 | $3.09 | $1.11 | |||||||||
NGLs (per Bbl) | ||||||||||||
Permian | $24.71 | $22.68 | $8.77 | |||||||||
Eagle Ford | 22.00 | 22.24 | 8.65 | |||||||||
Total NGLs (per Bbl) | $24.17 | $22.60 | $8.74 | |||||||||
Average realized sales price (per Boe) | ||||||||||||
Permian | $46.04 | $42.06 | $16.35 | |||||||||
Eagle Ford | 54.72 | 48.85 | 15.09 | |||||||||
Total average realized sales price (per Boe) | $48.68 | $44.01 | $15.90 | |||||||||
Average realized sales price (including impact of settled derivatives) | ||||||||||||
Oil (per Bbl) | $46.82 | $44.33 | $33.82 | |||||||||
Natural gas (per Mcf) | 2.25 | 2.88 | 0.97 | |||||||||
NGLs (per Bbl) | 23.21 | 21.77 | 8.74 | |||||||||
Total average realized sales price (per Boe) | $36.31 | $35.46 | $24.42 | |||||||||
Three Months Ended | ||||||||||||
June 30, 2021 | March 31, 2021 | June 30, 2020 | ||||||||||
Revenues (in thousands)(a) | ||||||||||||
Oil | ||||||||||||
Permian | $210,340 | $174,967 | $84,538 | |||||||||
Eagle Ford | 123,102 | 92,078 | 45,975 | |||||||||
Total oil | $333,442 | $267,045 | $130,513 | |||||||||
Natural gas | ||||||||||||
Permian | $19,152 | $19,290 | $8,309 | |||||||||
Eagle Ford | 4,928 | 4,930 | 3,933 | |||||||||
Total natural gas | $24,080 | $24,220 | $12,242 | |||||||||
NGLs | ||||||||||||
Permian | $30,047 | $24,376 | $11,116 | |||||||||
Eagle Ford | 6,578 | 4,981 | 3,363 | |||||||||
Total NGLs | $36,625 | $29,357 | $14,479 | |||||||||
Total revenues | ||||||||||||
Permian | $259,539 | $218,633 | $103,963 | |||||||||
Eagle Ford | 134,608 | 101,989 | 53,271 | |||||||||
Total revenues | $394,147 | $320,622 | $157,234 | |||||||||
Additional per Boe data | ||||||||||||
Sales price (b) | ||||||||||||
Permian | $46.04 | $42.06 | $16.35 | |||||||||
Eagle Ford | 54.72 | 48.85 | 15.09 | |||||||||
Total sales price | $48.68 | $44.01 | $15.90 | |||||||||
Lease operating | ||||||||||||
Permian | $4.60 | $4.31 | $5.01 | |||||||||
Eagle Ford | 8.34 | 8.65 | 5.38 | |||||||||
Total lease operating | $5.74 | $5.55 | $5.14 | |||||||||
Production and ad valorem taxes | ||||||||||||
Permian | $2.53 | $2.32 | $1.11 | |||||||||
Eagle Ford | 3.12 | 3.07 | 0.94 | |||||||||
Total production and ad valorem taxes | $2.71 | $2.53 | $1.05 | |||||||||
Gathering, transportation and processing | ||||||||||||
Permian | $2.75 | $2.54 | $2.31 | |||||||||
Eagle Ford | 1.84 | 2.29 | 1.51 | |||||||||
Total gathering, transportation and processing | $2.47 | $2.47 | $2.03 | |||||||||
Operating margin | ||||||||||||
Permian | $36.16 | $32.89 | $7.92 | |||||||||
Eagle Ford | 41.42 | 34.84 | 7.26 | |||||||||
Total operating margin | $37.76 | $33.46 | $7.68 | |||||||||
Depreciation, depletion and amortization | $10.27 | $9.74 | $14.05 | |||||||||
General and administrative | $1.37 | $2.31 | $1.01 | |||||||||
Adjusted G&A 1 | ||||||||||||
Cash component (c) | $0.71 | $1.26 | $0.69 | |||||||||
Non-cash component | $0.21 | $0.23 | $0.15 | |||||||||
(a) | Excludes sales of oil and gas purchased from third parties. |
(b) | Excludes the impact of settled derivatives. |
(c) | Excludes the change in fair value and amortization of share-based incentive awards and other non-recurring expenses. |
Revenue. For the quarter ended June 30, 2021, Callon reported revenue of $394.1 million, which excluded revenue from sales of commodities purchased from a third party of $46.3 million. Revenues including the gain or loss from the settlement of derivative contracts ("Adjusted Total Revenue"1) were $294.0 million, reflecting the impact of a $100.1 million loss from the settlement of derivative contracts. Average daily production for the quarter was 89.0 MBoe/d, compared to average daily production of 81.0 MBoe/d in the first quarter of 2021. Average realized prices, including and excluding the effects of hedging, are detailed above.
Commodity Derivatives. For the quarter ended June 30, 2021, the net loss on commodity derivative contracts includes the following (in thousands):
Three Months Ended | ||
Loss on oil derivatives | $177,033 | |
Loss on natural gas derivatives | 12,816 | |
Loss on NGL derivatives | 3,734 | |
Loss on commodity derivative contracts | $193,583 | |
For the quarter ended June 30, 2021, the cash paid for commodity derivative settlements includes the following (in thousands):
Three Months Ended | ||
Cash paid on oil derivatives | ($82,413) | |
Cash paid on natural gas derivatives | (1,906) | |
Cash paid on NGL derivatives | (1,090) | |
Cash paid for commodity derivative settlements, net | ($85,409) | |
Lease Operating Expenses, including workover ("LOE"). LOE per Boe for the three months ended June 30, 2021 was $5.74 per Boe, compared to LOE of $5.55 per Boe in the first quarter of 2021. The increase in LOE per Boe was primarily due to increased electrical costs.
Production and Ad Valorem Taxes. Production and ad valorem taxes for the three months ended June 30, 2021 represented approximately 5.6% of total revenue excluding revenue from sales of commodities purchased from a third-party and before the impact of derivative settlements.
Gathering, Transportation and Processing. Gathering, transportation and processing for the three months ended June 30, 2021 was $20.0 million, or $2.47 per Boe, as compared to $18.0 million, or $2.47 per Boe in the first quarter of 2021. This increase is related to the 11% increase in production volumes between the two periods.
Depreciation, Depletion and Amortization ("DD&A"). DD&A for the three months ended June 30, 2021 was $10.27 per Boe compared to $9.74 per Boe in the first quarter of 2021. The increase in DD&A was primarily attributable to a production increase of 11%, higher capital expenditures during the second quarter of 2021 as compared to the first quarter of 2021, and increases in future development cost assumptions.
General and Administrative Expense ("G&A"). G&A for the three months ended June 30, 2021 and March 31, 2021 was $11.1 million, or $1.37 per Boe, and $16.8 million, or $2.31 per Boe, respectively. G&A, excluding certain non-cash incentive share-based compensation valuation adjustments, ("Adjusted G&A" 1) was $7.5 million, or $0.93 per Boe, for the three months ended June 30, 2021 compared to $10.9 million, or $1.49 per Boe, for the first quarter of 2021. The cash component of Adjusted G&A decreased to $5.8 million, or $0.71 per Boe, for the three months ended June 30, 2021 compared to $9.2 million, or $1.26 per Boe, for the first quarter of 2021 primarily as a result of lower compensation costs during the quarter.
The following table reconciles total G&A to Adjusted G&A - cash component and full cash G&A (in thousands):
Three Months Ended | ||||||||
June 30, 2021 | March 31, 2021 | June 30, 2020 | ||||||
Total G&A | $11,065 | $16,799 | $10,024 | |||||
Change in the fair value of liability share-based awards (non-cash) | (3,555) | (5,943) | (1,720) | |||||
Adjusted G&A – total | 7,510 | 10,856 | 8,304 | |||||
Equity-settled, share-based compensation (non-cash) and other non-recurring expenses | (1,724) | (1,665) | (1,509) | |||||
Adjusted G&A – cash component | $5,786 | $9,191 | $6,795 | |||||
Capitalized cash G&A | 7,404 | 6,913 | 6,740 | |||||
Full cash G&A | $13,190 | $16,104 | $13,535 | |||||
Income Tax. Callon provides for income taxes at the statutory rate of 21% adjusted for permanent differences expected to be realized. We recorded income tax benefit of $0.5 million and $0.9 million for the three months ended June 30, 2021 and March 31, 2021, respectively. Since the second quarter of 2020, we have concluded that it is more likely than not that the net deferred tax assets will not be realized and have recorded a full valuation allowance against our deferred tax assets. As long as we continue to conclude that the valuation allowance is necessary, we will not have significant deferred tax expense or benefit.
Adjusted EBITDA. Net loss was $11.7 million and adjusted EBITDA was $196.8 million for the second quarter of 2021 as compared to net loss of $80.4 million and adjusted EBITDA of $170.6 million for the first quarter of 2021. The increase in adjusted EBITDA from the first quarter of 2021 was primarily due to an increase in revenues partially offset by increased payments associated with our commodity derivative settlements.
Adjusted Income and Adjusted EBITDA. The following tables reconcile the Company's net loss to adjusted income and adjusted EBITDA:
Three Months Ended | ||||||||
June 30, 2021 | March 31, 2021 | June 30, 2020 | ||||||
(In thousands, except per share data) | ||||||||
Net loss | ($11,695) | ($80,407) | ($1,564,731) | |||||
Loss on derivative contracts | 190,463 | 214,523 | 126,965 | |||||
Gain (loss) on commodity derivative settlements, net | (100,128) | (62,280) | 84,208 | |||||
Non-cash stock-based compensation expense | 5,279 | 7,608 | 2,761 | |||||
Impairment of evaluated oil and gas properties | — | — | 1,276,518 | |||||
Merger and integration expense | — | — | 8,067 | |||||
Other (income) expense | 5,584 | (3,306) | 6,759 | |||||
Tax effect on adjustments above(a) | (21,252) | (32,874) | (316,108) | |||||
Change in valuation allowance | 2,079 | 26,724 | 377,645 | |||||
Adjusted income | $70,330 | $69,988 | $2,084 | |||||
Adjusted income per diluted share | $1.49 | $1.49 | $0.05 | |||||
Basic WASO(b) | 46,267 | 42,590 | 39,707 | |||||
Diluted WASO (GAAP)(b) | 46,267 | 42,590 | 39,707 | |||||
Effect of potentially dilutive instruments(b) | 862 | 4,354 | 12 | |||||
Adjusted Diluted WASO(b) | 47,129 | 46,944 | 39,719 | |||||
(a) | Calculated using the federal statutory rate of 21%. |
(b) | All share and per share amounts have been retroactively adjusted for the Company's 1-for-10 reverse stock split effective August 7, 2020. |
Three Months Ended | ||||||||
June 30, 2021 | March 31, 2021 | June 30, 2020 | ||||||
(In thousands) | ||||||||
Net loss | ($11,695) | ($80,407) | ($1,564,731) | |||||
Loss on derivative contracts | 190,463 | 214,523 | 126,965 | |||||
Gain (loss) on commodity derivative settlements, net | (100,128) | (62,280) | 84,208 | |||||
Non-cash stock-based compensation expense | 5,279 | 7,608 | 2,761 | |||||
Impairment of evaluated oil and gas properties | — | — | 1,276,518 | |||||
Merger and integration expense | — | — | 8,067 | |||||
Other (income) expense | 5,584 | (3,306) | 6,759 | |||||
Income tax (benefit) expense | (478) | (921) | 51,251 | |||||
Interest expense, net | 24,634 | 24,416 | 22,682 | |||||
Depreciation, depletion and amortization | 83,128 | 70,987 | 138,930 | |||||
Adjusted EBITDA | $196,787 | $170,620 | $153,410 | |||||
Adjusted Free Cash Flow. The following table reconciles the Company's net cash provided by operating activities to adjusted EBITDA and adjusted free cash flow:
Three Months Ended | ||||||||
June 30, 2021 | March 31, 2021 | June 30, 2020 | ||||||
(In thousands) | ||||||||
Net cash provided by operating activities | $175,603 | $137,665 | $97,801 | |||||
Changes in working capital and other | 13,520 | 30,913 | 40,078 | |||||
Change in accrued hedge settlements | (14,719) | (20,117) | (14,480) | |||||
Cash interest expense, net | 22,383 | 22,159 | 21,944 | |||||
Merger and integration expense | — | — | 8,067 | |||||
Adjusted EBITDA | 196,787 | 170,620 | 153,410 | |||||
Less: Operational capital expenditures (accrual) | 138,321 | 95,545 | 85,087 | |||||
Less: Capitalized interest | 21,740 | 21,817 | 20,924 | |||||
Less: Interest expense, net of capitalized amounts | 22,383 | 22,159 | 22,682 | |||||
Less: Capitalized cash G&A | 7,404 | 6,913 | 6,740 | |||||
Adjusted free cash flow (a) | $6,939 | $24,186 | $17,977 | |||||
(a) | Effective January 1, 2021, non-cash interest expense amounts consisting primarily of amortization of debt issuance costs, premiums, and discounts associated with our long-term debt are excluded from our calculation of adjusted free cash flow. |
Adjusted Discretionary Cash Flow. The following table reconciles the Company's net cash provided by operating activities to adjusted discretionary cash flow:
Three Months Ended | ||||||||
June 30, 2021 | March 31, 2021 | June 30, 2020 | ||||||
(In thousands) | ||||||||
Cash flows from operating activities: | ||||||||
Net loss | ($11,695) | ($80,407) | ($1,564,731) | |||||
Adjustments to reconcile net loss to cash provided by operating activities: | ||||||||
Depreciation, depletion and amortization | 83,128 | 70,987 | 138,930 | |||||
Impairment of evaluated oil and gas properties | — | — | 1,276,518 | |||||
Amortization of non-cash debt related items | 2,252 | 2,256 | 738 | |||||
Deferred income tax expense | — | — | 51,251 | |||||
Loss on derivative contracts | 190,463 | 214,523 | 126,965 | |||||
Cash (paid) received for commodity derivative settlements, net | (85,409) | (42,162) | 98,688 | |||||
Non-cash stock-based compensation expense | 5,279 | 7,608 | 2,761 | |||||
Merger and integration expense | — | — | 8,067 | |||||
Other, net | 3,294 | 1,217 | 3,521 | |||||
Adjusted discretionary cash flow | $187,312 | $174,022 | $142,708 | |||||
Changes in working capital | (11,709) | (36,357) | (36,840) | |||||
Merger and integration expense | — | — | (8,067) | |||||
Net cash provided by operating activities | $175,603 | $137,665 | $97,801 | |||||
Adjusted Total Revenue. Adjusted total revenue is reconciled to total operating revenues, which excludes revenue from sales of commodities purchased from a third party, in the following table:
Three Months Ended | |||||||||
June 30, 2021 | March 31, 2021 | June 30, 2020 | |||||||
(In thousands) | |||||||||
Operating revenues | |||||||||
Oil | $333,442 | $267,045 | $130,513 | ||||||
Natural gas | 24,080 | 24,220 | 12,242 | ||||||
NGLs | 36,625 | 29,357 | 14,479 | ||||||
Total operating revenues | $394,147 | $320,622 | $157,234 | ||||||
Impact of settled derivatives | (100,128) | (62,280) | 84,208 | ||||||
Adjusted total revenue | $294,019 | $258,342 | $241,442 | ||||||
Callon Petroleum Company Consolidated Balance Sheets (In thousands, except par and share amounts) (Unaudited) | ||||||
June 30, 2021 | December 31, 2020 | |||||
ASSETS | ||||||
Current assets: | ||||||
Cash and cash equivalents | $3,800 | $20,236 | ||||
Accounts receivable, net | 200,246 | 133,109 | ||||
Fair value of derivatives | 14,941 | 921 | ||||
Other current assets | 24,876 | 24,103 | ||||
Total current assets | 243,863 | 178,369 | ||||
Oil and natural gas properties, full cost accounting method: | ||||||
Evaluated properties, net | 2,517,783 | 2,355,710 | ||||
Unevaluated properties | 1,697,832 | 1,733,250 | ||||
Total oil and natural gas properties, net | 4,215,615 | 4,088,960 | ||||
Other property and equipment, net | 32,805 | 31,640 | ||||
Deferred financing costs | 20,670 | 23,643 | ||||
Other assets, net | 33,444 | 40,256 | ||||
Total assets | $4,546,397 | $4,362,868 | ||||
LIABILITIES AND STOCKHOLDERS' EQUITY | ||||||
Current liabilities: | ||||||
Accounts payable and accrued liabilities | $419,434 | $341,519 | ||||
Fair value of derivatives | 331,702 | 97,060 | ||||
Other current liabilities | 62,668 | 58,529 | ||||
Total current liabilities | 813,804 | 497,108 | ||||
Long-term debt | 2,865,154 | 2,969,264 | ||||
Asset retirement obligations | 57,546 | 57,209 | ||||
Fair value of derivatives | 8,204 | 88,046 | ||||
Other long-term liabilities | 44,401 | 40,239 | ||||
Total liabilities | 3,789,109 | 3,651,866 | ||||
Commitments and contingencies | ||||||
Stockholders' equity: | ||||||
Common stock, $0.01 par value, 78,750,000 and 52,500,000 shares authorized; | 463 | 398 | ||||
Capital in excess of par value | 3,361,282 | 3,222,959 | ||||
Accumulated deficit | (2,604,457) | (2,512,355) | ||||
Total stockholders' equity | 757,288 | 711,002 | ||||
Total liabilities and stockholders' equity | $4,546,397 | $4,362,868 | ||||
Callon Petroleum Company Consolidated Statements of Operations (In thousands, except per share data) (Unaudited) | |||||||||||
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||
2021 | 2020 | 2021 | 2020 | ||||||||
Operating Revenues: | |||||||||||
Oil | $333,442 | $130,513 | $600,487 | $396,280 | |||||||
Natural gas | 24,080 | 12,242 | 48,300 | 18,271 | |||||||
Natural gas liquids | 36,625 | 14,479 | 65,982 | 32,602 | |||||||
Sales of purchased oil and gas | 46,252 | — | 85,511 | — | |||||||
Total operating revenues | 440,399 | 157,234 | 800,280 | 447,153 | |||||||
Operating Expenses: | |||||||||||
Lease operating | 46,460 | 50,838 | 86,913 | 103,221 | |||||||
Production and ad valorem taxes | 21,958 | 10,361 | 40,397 | 30,041 | |||||||
Gathering, transportation and processing | 20,031 | 20,037 | 38,012 | 34,415 | |||||||
Cost of purchased oil and gas | 49,249 | — | 90,166 | — | |||||||
Depreciation, depletion and amortization | 83,128 | 138,930 | 154,115 | 270,393 | |||||||
General and administrative | 11,065 | 10,024 | 27,864 | 18,349 | |||||||
Impairment of evaluated oil and gas properties | — | 1,276,518 | — | 1,276,518 | |||||||
Merger and integration | — | 8,067 | — | 23,897 | |||||||
Other operating | 2,437 | 4,135 | 3,366 | 4,135 | |||||||
Total operating expenses | 234,328 | 1,518,910 | 440,833 | 1,760,969 | |||||||
Income (Loss) From Operations | 206,071 | (1,361,676) | 359,447 | (1,313,816) | |||||||
Other (Income) Expenses: | |||||||||||
Interest expense, net of capitalized amounts | 24,634 | 22,682 | 49,050 | 43,160 | |||||||
(Gain) loss on derivative contracts | 190,463 | 126,965 | 404,986 | (125,004) | |||||||
Other (income) expense | 3,147 | 2,157 | (1,088) | 895 | |||||||
Total other (income) expense | 218,244 | 151,804 | 452,948 | (80,949) | |||||||
Loss Before Income Taxes | (12,173) | (1,513,480) | (93,501) | (1,232,867) | |||||||
Income tax benefit (expense) | 478 | (51,251) | 1,399 | (115,299) | |||||||
Net Loss | ($11,695) | ($1,564,731) | ($92,102) | ($1,348,166) | |||||||
Net Loss Per Common Share (a): | |||||||||||
Basic | ($0.25) | ($39.41) | ($2.07) | ($33.97) | |||||||
Diluted | ($0.25) | ($39.41) | ($2.07) | ($33.97) | |||||||
Weighted Average Common Shares Outstanding (a): | |||||||||||
Basic | 46,267 | 39,707 | 44,439 | 39,687 | |||||||
Diluted | 46,267 | 39,707 | 44,439 | 39,687 | |||||||
(a) | All share and per share amounts have been retroactively adjusted for the Company's 1-for-10 reverse stock split effective August 7, 2020. | |||||
Callon Petroleum Company Consolidated Statements of Cash Flows (In thousands) (Unaudited) | |||||||||||
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||
2021 | 2020 | 2021 | 2020 | ||||||||
Cash flows from operating activities: | |||||||||||
Net loss | ($11,695) | ($1,564,731) | ($92,102) | ($1,348,166) | |||||||
Adjustments to reconcile net loss to net cash provided by operating activities: | |||||||||||
Depreciation, depletion and amortization | 83,128 | 138,930 | 154,115 | 270,393 | |||||||
Impairment of evaluated oil and gas properties | — | 1,276,518 | — | 1,276,518 | |||||||
Amortization of non-cash debt related items, net | 2,252 | 738 | 4,508 | 1,145 | |||||||
Deferred income tax expense | — | 51,251 | — | 115,299 | |||||||
(Gain) loss on derivative contracts | 190,463 | 126,965 | 404,986 | (125,004) | |||||||
Cash received (paid) for commodity derivative settlements, net | (85,409) | 98,688 | (127,571) | 101,301 | |||||||
Non-cash expense (benefit) related to share-based awards | 5,279 | 2,761 | 12,887 | (211) | |||||||
Other, net | 3,294 | 3,520 | 4,511 | 3,656 | |||||||
Changes in current assets and liabilities: | |||||||||||
Accounts receivable | (21,674) | (2,833) | (67,357) | 113,040 | |||||||
Other current assets | (4,567) | (3,567) | (7,423) | (4,348) | |||||||
Accounts payable and accrued liabilities | 14,532 | (30,439) | 26,714 | (114,127) | |||||||
Net cash provided by operating activities | 175,603 | 97,801 | 313,268 | 289,496 | |||||||
Cash flows from investing activities: | |||||||||||
Capital expenditures | (149,662) | (205,229) | (251,003) | (418,688) | |||||||
Acquisition of oil and gas properties | (1,447) | (892) | (2,215) | (11,881) | |||||||
Proceeds from sale of assets | 31,611 | (161) | 31,611 | 10,079 | |||||||
Cash paid for settlements of contingent consideration arrangements, net | — | — | — | (40,000) | |||||||
Other, net | 625 | 6,992 | 4,220 | 6,834 | |||||||
Net cash used in investing activities | (118,873) | (199,290) | (217,387) | (453,656) | |||||||
Cash flows from financing activities: | |||||||||||
Borrowings on Credit Facility | 433,500 | 484,500 | 736,500 | 4,775,500 | |||||||
Payments on Credit Facility | (508,500) | (384,500) | (846,500) | (4,610,500) | |||||||
Payment of deferred financing and debt exchange costs | — | (5,736) | — | (6,011) | |||||||
Tax withholdings related to restricted stock units | (2,280) | — | (2,280) | (388) | |||||||
Other, net | — | (75) | (37) | (282) | |||||||
Net cash provided by (used in) financing activities | (77,280) | 94,189 | (112,317) | 158,319 | |||||||
Net change in cash and cash equivalents | (20,550) | (7,300) | (16,436) | (5,841) | |||||||
Balance, beginning of period | 24,350 | 14,800 | 20,236 | 13,341 | |||||||
Balance, end of period | $3,800 | $7,500 | $3,800 | $7,500 | |||||||
Non-GAAP Financial Measures
This news release refers to non-GAAP financial measures such as "adjusted free cash flow," "adjusted discretionary cash flow," "adjusted G&A," "full cash G&A," "adjusted income," "adjusted income per diluted share," "adjusted EBITDA," and "adjusted total revenue." These measures, detailed below, are provided in addition to, and not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP (including the notes), included in our filings with the U.S. Securities and Exchange Commission (the "SEC") and posted on our website.
- Adjusted free cash flow is a supplemental non-GAAP measure that is defined by the Company as adjusted EBITDA less operational capital, cash capitalized interest, net cash interest expense and capitalized cash G&A (which excludes capitalized expense related to share-based awards). We believe adjusted free cash flow is a comparable metric against other companies in the industry and is a widely accepted financial indicator of an oil and natural gas company's ability to generate cash for the use of internally funding their capital development program and to service or incur debt. Adjusted free cash flow is not a measure of a company's financial performance under GAAP and should not be considered as an alternative to net cash provided by operating activities, or as a measure of liquidity, or as an alternative to net income (loss).
- Adjusted discretionary cash flow is a supplemental non-GAAP measure that Callon believes is a comparable metric against other companies in the industry and is a widely accepted financial indicator of an oil and natural gas company's ability to generate cash for the use of internally funding their capital development program and to service or incur debt. Adjusted discretionary cash flow is defined by Callon as net cash provided by operating activities before changes in working capital and merger and integration expenses. Callon has included this information because changes in operating assets and liabilities relate to the timing of cash receipts and disbursements, which the Company may not control and the cash flow effect may not be reflected the period in which the operating activities occurred. Adjusted discretionary cash flow is not a measure of a company's financial performance under GAAP and should not be considered as an alternative to net cash provided by operating activities, or as a measure of liquidity, or as an alternative to net income (loss).
- Adjusted G&A is a supplemental non-GAAP financial measure that excludes certain non-cash incentive share-based compensation valuation adjustments. Callon believes that the non-GAAP measure of adjusted G&A is useful to investors because it provides a meaningful measure of our recurring G&A expense and provides for greater comparability period-over-period.
- Full cash G&A is a supplemental non-GAAP financial measure that Callon defines as adjusted G&A – cash component plus capitalized G&A excluding capitalized expense related to share-based awards. Callon believes that the non-GAAP measure of full cash G&A is useful because it provides users with a meaningful measure of our total recurring cash G&A costs, whether expensed or capitalized, and provides for greater comparability on a period-over-period basis.
- Adjusted income and adjusted income per diluted share are supplemental non-GAAP measures that Callon believes are useful to investors because they provide readers with a meaningful measure of our profitability before recording certain items whose timing or amount cannot be reasonably determined. These measures exclude the net of tax effects of these items and non-cash valuation adjustments, which are detailed in the reconciliation provided. Adjusted income and adjusted income per diluted share are not measures of financial performance under GAAP. Accordingly, it should not be considered as a substitute for net income (loss), operating income (loss), or other income data prepared in accordance with GAAP. However, the Company believes that adjusted income and adjusted income per diluted share provide additional information with respect to our performance. Because adjusted income and adjusted income per diluted share exclude some, but not all, items that affect net income (loss) and may vary among companies, the adjusted income and adjusted income per diluted share presented above may not be comparable to similarly titled measures of other companies.
- Adjusted diluted weighted average common shares outstanding ("Adjusted Diluted WASO") is a non-GAAP financial measure which includes the effect of potentially dilutive instruments that, under certain circumstances described below, are excluded from diluted weighted average common shares outstanding ("Diluted WASO"), the most directly comparable GAAP financial measure. When a net loss exists, all potentially dilutive instruments are anti-dilutive to the net loss per common share and therefore excluded from the computation of Diluted WASO. The effect of potentially dilutive instruments are included in the computation of Adjusted Diluted WASO for purposes of computing adjusted income per diluted share.
- Callon calculates adjusted EBITDA as net income (loss) before interest expense, income tax expense (benefit), depreciation, depletion and amortization, (gains) losses on derivative instruments excluding net settled derivative instruments, impairment of evaluated oil and gas properties, non-cash stock-based compensation expense, merger and integration expense, (gain) loss on extinguishment of debt, and other operating expenses. Adjusted EBITDA is not a measure of financial performance under GAAP. Accordingly, it should not be considered as a substitute for net income (loss), operating income (loss), cash flow provided by operating activities or other income or cash flow data prepared in accordance with GAAP. However, the Company believes that adjusted EBITDA provides additional information with respect to our performance or ability to meet our future debt service, capital expenditures and working capital requirements. Because adjusted EBITDA excludes some, but not all, items that affect net income (loss) and may vary among companies, the adjusted EBITDA presented above may not be comparable to similarly titled measures of other companies.
- Callon believes that the non-GAAP measure of adjusted total revenue (which is revenue including the gain or loss from the settlement of derivative contracts) is useful to investors because it provides readers with a revenue value more comparable to other companies who engage in price risk management activities through the use of commodity derivative instruments and reflects the results of derivative settlements with expected cash flow impacts within total revenues. See the reconciliation provided above for further details.
Earnings Call Information
The Company will host a conference call on Wednesday, August 4, 2021, to discuss second quarter 2021 financial and operating results, 2021 outlook, and current corporate strategy and initiatives.
Please join Callon Petroleum Company via the Internet for a webcast of the conference call:
Date/Time: Wednesday, August 4, 2021, at 8:00 a.m. Central Time (9:00 a.m. Eastern Time)
Webcast: Select "News and Events" under the "Investors" section of the Company's website: www.callon.com.
An archive of the conference call webcast will also be available at www.callon.com under the "Investors" section of the website.
About Callon Petroleum Company
Callon Petroleum Company is an independent oil and natural gas company focused on the acquisition, exploration and development of high-quality assets in the leading oil plays of South and West Texas.
Cautionary Statement Regarding Forward-Looking Information
This news release contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements include all statements regarding wells anticipated to be drilled and placed on production; future levels of development activity and associated production, capital expenditures and cash flow expectations; the Company's 2021 production expense guidance and capital expenditure guidance; estimated reserve quantities and the present value thereof; and the implementation of the Company's business plans and strategy, as well as statements including the words "believe," "expect," "plans," "may," "will," "should," "could," and words of similar meaning. These statements reflect the Company's current views with respect to future events and financial performance based on management's experience and perception of historical trends, current conditions, anticipated future developments and other factors believed to be appropriate. No assurances can be given, however, that these events will occur or that these projections will be achieved, and actual results could differ materially from those projected as a result of certain factors. Any forward-looking statement speaks only as of the date on which such statement is made and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law. Some of the factors which could affect our future results and could cause results to differ materially from those expressed in our forward-looking statements include the volatility of oil and natural gas prices; changes in the supply of and demand for oil and natural gas, including as a result of the COVID-19 pandemic and various governmental actions taken to mitigate its impact or actions by, or disputes among members of OPEC and other oil and natural gas producing countries, such as Russia, with respect to production levels or other matters related to the price of oil; our ability to drill and complete wells; operational, regulatory and environment risks; the cost and availability of equipment and labor; our ability to finance our activities; and other risks more fully discussed in our filings with the SEC, including our most recent Annual Reports on Form 10-K and subsequent Quarterly Reports on Form 10-Q, available on our website or the SEC's website at www.sec.gov.
Contact Information
Mark Brewer
Director of Investor Relations
Callon Petroleum Company
ir@callon.com
(281) 589-5200
View original content:https://www.prnewswire.com/news-releases/callon-petroleum-company-announces-second-quarter-2021-results-301347937.html
SOURCE Callon Petroleum Company
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