Callon Petroleum Company Announces Third Quarter 2021 Results
HOUSTON, Nov. 3, 2021 /PRNewswire/ -- Callon Petroleum Company (NYSE: CPE) ("Callon" or the "Company") today reported results of operations for the three and nine months ended September 30, 2021.
Presentation slides accompanying this earnings release are available on the Company's website at www.callon.com located on the "Presentations" page within the Investors section of the site.
Third Quarter 2021 and Recent Highlights
- Delivered production of approximately 99.7 MBoe/d (64% oil) in the third quarter of 2021
- Generated net cash provided by operating activities of $294.6 million and adjusted free cash flow1 of $119.5 million
- Net income of $171.9 million, or $3.65 per diluted share, adjusted EBITDA1 of $292.2 million, and adjusted income1 of $137.9 million, or $2.93 per diluted share
- Achieved an operating margin of $45.16 per Boe, a 20% increase from the previous quarter
- Finalized the acquisition of Delaware Basin assets from Primexx, significantly increasing operating cash flow and accelerating the projected timeline for corporate deleveraging
- Entered into agreements to divest non-core assets for cash consideration of approximately $170 million, bringing estimated gross asset sales proceeds to approximately $210 million for the year
- Completed the fall redetermination for Callon's credit facility with the borrowing base and elected commitment maintained at $1.6 billion
- Obtained shareholder approval for the conversion of $197 million of second lien debt into common shares, lowering net debt outstanding and reducing Callon's future interest burden by nearly $20 million annually
Joe Gatto, President and Chief Executive Officer commented, "Our third quarter performance demonstrates Callon's continued commitment to operational excellence, balance sheet strength and delivering on our promises to shareholders. Our development program and financial results reflect both strong well performance and resilient capital efficiency. The team has been able to mitigate the majority of the inflationary pressures we have seen throughout the year which has bolstered our top-tier operating margins. The recent rise in commodity prices has been a welcome surprise and has enhanced our free cash flow generation, increasing our estimates for 2021 to over $250 million. This increase to bottom line cash flow will be dedicated to our deleveraging efforts and provides a clear path for Callon to reach our target debt metrics and absolute debt levels much sooner than originally anticipated, opening the door for meaningful discussions regarding shareholder return strategies in the future."
He continued, "Our acquisition of the Primexx assets, coupled with multiple non-core divestitures, has not only improved our balance sheet, but will also allow us to expand our scaled model of life-of-field development in our core areas that will preserve long-term inventory quality. With an acreage position of over 186,000 net acres, our future development plans will be primarily focused on our Permian asset base, building upon the efficiency of current operations and delivering synergies from deployment of operational best practices. We have made significant progress integrating the acquired assets into our near-term activity and look forward to sharing more details about our 2022 plans for the broader Company in the coming months."
Credit Facility and Liquidity
On November 1, 2021, Callon completed the fall redetermination for its senior secured credit facility. The borrowing base and elected commitment were both reaffirmed at $1.6 billion. As of September 30, 2021, the drawn balance on the facility was $723.0 million and cash balances were $3.7 million. The Company expects to continue applying organic free cash flow and divestiture proceeds towards repayment of the credit facility balance.
Close of Primexx Acquisition, Conversion of Second Lien Notes, and Additional Sale of Non-Core Assets
On October 1, 2021, Callon completed the acquisition of leasehold interests and related infrastructure from Primexx Energy Partners and its affiliates. At closing, Callon paid an adjusted purchase price of $453.7 million in cash and 8.84 million shares of common stock, subject to post-closing adjustments.
On November 3, 2021, shareholders voted to authorize the issuance of approximately 5.5 million shares of common stock to Chambers Investments, LLC, a private investment vehicle managed by Kimmeridge Energy, as part of the conversion of just under $200 million of our second lien notes. This conversion eliminates nearly $20 million of future annual interest payments and is expected to close on November 5, 2021.
The Company recently entered into an agreement to sell certain non-core Midland Basin assets for approximately $38 million. The assets include approximately 1,150 net acres located in central Howard County and a single section in Midland County. Current average daily production for these assets is approximately 900 Boe per day (48% oil).
Additionally, Callon entered into an agreement to divest certain non-core water infrastructure assets for $30 million in upfront cash proceeds and potential earnout payments of up to $18 million. Callon's broader water infrastructure footprint of 14 saltwater disposal wells with approximately 325,000 barrels per day of capacity, associated gathering lines and 140,000 barrels per day of recycling capacity are not impacted by the transaction.
The previously announced divestiture of Eagle Ford properties in northern La Salle and Frio counties for $100 million is expected to close in mid-November.
Scotiabank served as financial advisor to the Company for the water transaction, Wells Fargo Securities LLC for the Eagle Ford sale and TenOaks Energy Advisors, LLC for the Midland divestiture.
Callon Operations Update
At September 30, 2021, Callon had 1,562 gross (1,382.8 net) wells producing from established flow units in the Permian and Eagle Ford. Net daily production for the three months ended September 30, 2021 was 99.7 MBoe/d (64% oil).
For the three months ended September 30, 2021, Callon drilled 15 gross (13.5 net) wells and placed a combined 26 gross (23.6 net) wells on production. Wells placed on production during the quarter were completed in the Eagle Ford in South Texas, the Delaware Basin and the Midland Basin.
Third quarter completion activity was focused primarily in the Permian Basin, with approximately 75% of the new wells placed on production coming from larger projects in both the Delaware Basin and Midland Basin. Within the Midland Basin, multi-well projects in Howard County targeted multi-zone development of the Wolfcamp A and Lower Spraberry. In the Delaware Basin, a four-well project targeting Third Bone Spring and Lower Wolfcamp A zones was brought online in September and has exceeded production expectations. As part of the optimization of producing assets, Callon continues to convert gas lift systems to electric submersible pumps, positively impacting the production profile of the existing asset base across the Delaware position.
In the Eagle Ford, Callon turned one two-well pad and a separate four-well project to production in July and August, respectively. All six wells are producing as expected. During the quarter, the Company expanded its electrification efforts in the area, advancing sustainability initiatives and improving productivity. The project has resulted in the removal of another 25 generators, providing a cleaner and more reliable source of energy for field operations. Altogether, these efforts are expected to save approximately $1.5 million annually in lease operating expenses. Additional field electrification efforts are progressing and are expected to be completed by year-end.
Primexx Asset Updates
During the third quarter, Primexx placed 12 gross wells on production with eight wells achieving first production in July and the remaining four wells coming online during late August. These wells have demonstrated a high level of productivity, averaging peak oil rates of more than 1,200 barrels per day. Callon recently placed on production a three-well pad that was drilled and completed by Primexx. Through the first 20 days of production, all three wells are performing ahead of the Callon type curve for the area with peak production yet to be reached. There are no additional wells on the acquired acreage that are expected to be placed on production in the fourth quarter of 2021 as Callon builds an operational well inventory that will facilitate a transition to a larger scale development model going forward.
Fourth Quarter Activity Outlook
Callon is currently running six rigs across the combined acreage position with approximately 1.5 completion crews scheduled for the fourth quarter. Completion activity during the quarter will be spread across the Midland and legacy Delaware positions, moving to the acquired Delaware acreage towards year end. Drilling activity is currently ongoing with four rigs in the Delaware Basin, one rig in the Eagle Ford and one rig in the Midland Basin.
Capital Expenditures
For the three months ended September 30, 2021, Callon incurred $115.0 million in operational capital expenditures on an accrual basis. Total capital expenditures, inclusive of capitalized expenses, are detailed below on an accrual and cash basis:
Three Months Ended September 30, 2021 | ||||||||||||
Operational | Capitalized | Capitalized | Total Capital | |||||||||
Capital (a) | Interest | G&A | Expenditures | |||||||||
(In thousands) | ||||||||||||
Cash basis (b) | $151,086 | $16,429 | $9,034 | $176,549 | ||||||||
Timing adjustments (c) | (30,160) | 7,161 | — | ($22,999) | ||||||||
Non-cash items | (5,962) | 2,500 | 1,392 | ($2,070) | ||||||||
Accrual basis | $114,964 | $26,090 | $10,426 | $151,480 | ||||||||
(a) | Includes drilling, completions, facilities, and equipment, but excludes land and seismic. |
(b) | Cash basis is presented here to help users of financial information reconcile amounts from the cash flow statement to the balance sheet by accounting for timing related changes in working capital that align with our development pace and rig count. |
(c) | Includes timing adjustments related to cash disbursements in the current period for capital expenditures incurred in the prior period. |
Hedge Portfolio Summary
As of October 29, 2021, Callon had the following outstanding oil, natural gas and NGL derivative contracts:
For the Remainder | For the Full Year | For the Full Year | |||||||
Oil contracts (WTI) | 2021(a) | 2022(a) | 2023 | ||||||
Swap contracts | |||||||||
Total volume (Bbls) | 1,748,000 | 4,066,000 | 315,000 | ||||||
Weighted average price per Bbl | $56.87 | $65.84 | $70.01 | ||||||
Collar contracts | |||||||||
Total volume (Bbls) | 2,290,450 | 7,097,500 | — | ||||||
Weighted average price per Bbl | |||||||||
Ceiling (short call) | $46.97 | $67.70 | $— | ||||||
Floor (long put) | $39.37 | $56.15 | $— | ||||||
Long put contracts | |||||||||
Total volume (Bbls) | 414,000 | — | — | ||||||
Weighted average price per Bbl | $62.50 | $— | $— | ||||||
Short call contracts | |||||||||
Total volume (Bbls) | 1,216,240 | (b) | — | — | |||||
Weighted average price per Bbl | $63.62 | $— | $— | ||||||
Short call swaption contracts | |||||||||
Total volume (Bbls) | — | 1,825,000 | (c) | 1,825,000 | (c) | ||||
Weighted average price per Bbl | $— | $52.18 | $72.00 | ||||||
Oil contracts (Brent ICE) (d) | |||||||||
Collar contracts | |||||||||
Total volume (Bbls) | 184,000 | — | — | ||||||
Weighted average price per Bbl | |||||||||
Ceiling (short call) | $50.00 | $— | $— | ||||||
Floor (long put) | $45.00 | $— | $— | ||||||
Oil contracts (Midland basis differential) | |||||||||
Swap contracts | |||||||||
Total volume (Bbls) | 892,400 | — | — | ||||||
Weighted average price per Bbl | $0.33 | $— | $— | ||||||
Oil contracts (Argus Houston MEH) | |||||||||
Collar contracts | |||||||||
Total volume (Bbls) | — | 452,500 | — | ||||||
Weighted average price per Bbl | |||||||||
Ceiling (short call) | $— | $63.15 | $— | ||||||
Floor (long put) | $— | $51.25 | $— | ||||||
_____________ | |
(a) | The Company has approximately $6.6 million of deferred premiums, of which $3.7 million are associated with contracts that will settle in 2021 and $2.9 million for contracts that will settle in 2022. |
(b) | Premiums from the sale of call options were used to increase the fixed price of certain simultaneously executed price swaps and three-way collars. |
(c) | The 2022 and 2023 short call swaption contracts have exercise expiration dates of December 31, 2021 and December 30, 2022, respectively. |
(d) | In February 2021, the Company entered into certain offsetting ICE Brent swaps to reduce its exposure to rising oil prices. Those offsetting swaps resulted in a locked-in loss of approximately $2.9 million, of which $1.6 million settled in the third quarter of 2021 with the remaining $1.3 million to be settled in the fourth quarter of 2021. |
For the Remainder | For the Full Year | |||||
Natural gas contracts (Henry Hub) | 2021 | 2022 | ||||
Swap contracts | ||||||
Total volume (MMBtu) | 4,357,000 | 7,320,000 | ||||
Weighted average price per MMBtu | $2.96 | $3.08 | ||||
Collar contracts | ||||||
Total volume (MMBtu) | 1,840,000 | 5,740,000 | ||||
Weighted average price per MMBtu | ||||||
Ceiling (short call) | $2.80 | $3.64 | ||||
Floor (long put) | $2.50 | $2.83 | ||||
Short call contracts | ||||||
Total volume (MMBtu) | 1,840,000 | (a) | — | |||
Weighted average price per MMBtu | $3.09 | $— | ||||
Natural gas contracts (Waha basis differential) | ||||||
Swap contracts | ||||||
Total volume (MMBtu) | 4,140,000 | 5,475,000 | ||||
Weighted average price per MMBtu | ($0.42) | ($0.21) | ||||
__________ | |
(a) | Premiums from the sale of call options were used to increase the fixed price of certain simultaneously executed price swaps and three-way collars. |
For the Remainder | For the Full Year | |||||
NGL contracts (OPIS Mont Belvieu Purity Ethane) | 2021 | 2022 | ||||
Swap contracts | ||||||
Total volume (Bbls) | 460,000 | 378,000 | ||||
Weighted average price per Bbl | $7.62 | $15.70 | ||||
NGL contracts (OPIS Mont Belvieu Propane) | ||||||
Swap contracts | ||||||
Total volume (Bbls) | 266,800 | 252,000 | ||||
Weighted average price per Bbl | $52.15 | $48.43 | ||||
NGL contracts (OPIS Mont Belvieu Butane) | ||||||
Swap contracts | ||||||
Total volume (Bbls) | 101,200 | 99,000 | ||||
Weighted average price per Bbl | $59.43 | $54.39 | ||||
NGL contracts (OPIS Mont Belvieu Isobutane) | ||||||
Swap contracts | ||||||
Total volume (Bbls) | 55,200 | 54,000 | ||||
Weighted average price per Bbl | $58.96 | $54.29 | ||||
Operating and Financial Results
The following table presents summary information for the periods indicated:
Three Months Ended | |||||||||
September 30, 2021 | June 30, 2021 | September 30, 2020 | |||||||
Total production | |||||||||
Oil (MBbls) | |||||||||
Permian | 3,428 | 3,232 | 3,441 | ||||||
Eagle Ford | 2,447 | 1,870 | 2,434 | ||||||
Total oil (MBbls) | 5,875 | 5,102 | 5,875 | ||||||
Natural gas (MMcf) | |||||||||
Permian | 7,153 | 7,138 | 7,868 | ||||||
Eagle Ford | 2,242 | 1,745 | 2,393 | ||||||
Total natural gas (MMcf) | 9,395 | 8,883 | 10,261 | ||||||
NGLs (MBbls) | |||||||||
Permian | 1,315 | 1,216 | 1,423 | ||||||
Eagle Ford | 417 | 299 | 379 | ||||||
Total NGLs (MBbls) | 1,732 | 1,515 | 1,802 | ||||||
Total production (MBoe) | |||||||||
Permian | 5,936 | 5,637 | 6,175 | ||||||
Eagle Ford | 3,237 | 2,460 | 3,212 | ||||||
Total barrels of oil equivalent (MBoe) | 9,173 | 8,097 | 9,387 | ||||||
Total daily production (Boe/d) | |||||||||
Permian | 64,517 | 61,948 | 67,117 | ||||||
Eagle Ford | 35,186 | 27,033 | 34,912 | ||||||
Total barrels of oil equivalent (Boe/d) | 99,703 | 88,981 | 102,029 | ||||||
Oil as % of total daily production | 64% | 63% | 63% | ||||||
Average realized sales price (excluding impact of settled derivatives) | |||||||||
Oil (per Bbl) | |||||||||
Permian | $69.60 | $65.08 | $39.42 | ||||||
Eagle Ford | 69.76 | 65.83 | 39.44 | ||||||
Total oil (per Bbl) | $69.67 | $65.36 | $39.43 | ||||||
Natural gas (per Mcf) | |||||||||
Permian | $3.78 | $2.68 | $1.31 | ||||||
Eagle Ford | 4.22 | 2.82 | 1.99 | ||||||
Total natural gas (per Mcf) | $3.89 | $2.71 | $1.47 | ||||||
NGLs (per Bbl) | |||||||||
Permian | $34.41 | $24.71 | $12.68 | ||||||
Eagle Ford | 30.81 | 22.00 | 13.13 | ||||||
Total NGLs (per Bbl) | $33.54 | $24.17 | $12.78 | ||||||
Average realized sales price (per Boe) | |||||||||
Permian | $52.37 | $46.04 | $26.55 | ||||||
Eagle Ford | 59.63 | 54.72 | 32.92 | ||||||
Total average realized sales price (per Boe) | $54.93 | $48.68 | $28.73 | ||||||
Average realized sales price (including impact of settled derivatives) | |||||||||
Oil (per Bbl) | $54.00 | $46.82 | $39.00 | ||||||
Natural gas (per Mcf) | 2.21 | 2.25 | 1.17 | ||||||
NGLs (per Bbl) | 31.71 | 23.21 | 12.78 | ||||||
Total average realized sales price (per Boe) | $42.84 | $36.31 | $28.14 | ||||||
Three Months Ended | |||||||||
September 30, 2021 | June 30, 2021 | September 30, 2020 | |||||||
Revenues (in thousands)(a) | |||||||||
Oil | |||||||||
Permian | $238,582 | $210,340 | $135,648 | ||||||
Eagle Ford | 170,711 | 123,102 | 96,006 | ||||||
Total oil | $409,293 | $333,442 | $231,654 | ||||||
Natural gas | |||||||||
Permian | $27,065 | $19,152 | $10,271 | ||||||
Eagle Ford | 9,454 | 4,928 | 4,763 | ||||||
Total natural gas | $36,519 | $24,080 | $15,034 | ||||||
NGLs | |||||||||
Permian | $45,249 | $30,047 | $18,049 | ||||||
Eagle Ford | 12,848 | 6,578 | 4,976 | ||||||
Total NGLs | $58,097 | $36,625 | $23,025 | ||||||
Total revenues | |||||||||
Permian | $310,896 | $259,539 | $163,968 | ||||||
Eagle Ford | 193,013 | 134,608 | 105,745 | ||||||
Total revenues | $503,909 | $394,147 | $269,713 | ||||||
Additional per Boe data | |||||||||
Sales price (b) | |||||||||
Permian | $52.37 | $46.04 | $26.55 | ||||||
Eagle Ford | 59.63 | 54.72 | 32.92 | ||||||
Total sales price | $54.93 | $48.68 | $28.73 | ||||||
Lease operating | |||||||||
Permian | $4.19 | $4.60 | $4.38 | ||||||
Eagle Ford | 5.51 | 8.34 | 5.86 | ||||||
Total lease operating | $4.66 | $5.74 | $4.89 | ||||||
Production and ad valorem taxes | |||||||||
Permian | $2.80 | $2.53 | $1.57 | ||||||
Eagle Ford | 2.89 | 3.12 | 2.00 | ||||||
Total production and ad valorem taxes | $2.84 | $2.71 | $1.72 | ||||||
Gathering, transportation and processing | |||||||||
Permian | $2.70 | $2.75 | $2.55 | ||||||
Eagle Ford | 1.49 | 1.84 | 2.00 | ||||||
Total gathering, transportation and processing | $2.28 | $2.47 | $2.36 | ||||||
Operating margin | |||||||||
Permian | $42.68 | $36.16 | $18.05 | ||||||
Eagle Ford | 49.74 | 41.42 | 23.06 | ||||||
Total operating margin | $45.16 | $37.76 | $19.76 | ||||||
Depreciation, depletion and amortization | $9.80 | $10.27 | $12.17 | ||||||
General and administrative | $1.04 | $1.37 | $0.88 | ||||||
Adjusted G&A 1 | |||||||||
Cash component (c) | $1.13 | $0.71 | $0.87 | ||||||
Non-cash component | $0.17 | $0.21 | $0.18 | ||||||
(a) | Excludes sales of oil and gas purchased from third parties. |
(b) | Excludes the impact of settled derivatives. |
(c) | Excludes the change in fair value and amortization of share-based incentive awards and other non-recurring expenses. |
Revenue. For the quarter ended September 30, 2021, Callon reported revenue of $503.9 million, which excluded revenue from sales of commodities purchased from a third party of $48.7 million. Revenues including the gain or loss from the settlement of derivative contracts ("Adjusted Total Revenue"1) were $392.9 million, reflecting the impact of a $111.0 million loss from the settlement of derivative contracts. Average daily production for the quarter was 99.7 MBoe/d, compared to average daily production of 89.0 MBoe/d in the second quarter of 2021. Average realized prices, including and excluding the effects of hedging, are detailed above.
Commodity Derivatives. For the quarter ended September 30, 2021, the net loss on commodity derivative contracts includes the following (in thousands):
Three Months Ended | ||
Loss on oil derivatives | $67,198 | |
Loss on natural gas derivatives | 33,026 | |
Loss on NGL derivatives | 10,242 | |
Loss on commodity derivative contracts | $110,466 | |
For the quarter ended September 30, 2021, the cash paid for commodity derivative settlements includes the following (in thousands):
Three Months Ended | ||
Cash paid on oil derivatives | ($98,752) | |
Cash paid on natural gas derivatives | (9,592) | |
Cash paid on NGL derivatives | (2,463) | |
Cash paid for commodity derivative settlements, net | ($110,807) | |
Lease Operating Expenses, including workover ("LOE"). LOE per Boe for the three months ended September 30, 2021 was $4.66 per Boe, compared to LOE of $5.74 per Boe in the second quarter of 2021. The decrease in LOE per Boe was primarily due to the distribution of fixed costs spread over higher production volumes as well as a reduction in certain operating expenses such as saltwater disposal and compression.
Production and Ad Valorem Taxes. Production and ad valorem taxes for the three months ended September 30, 2021 represented approximately 5.2% of total revenue excluding revenue from sales of commodities purchased from a third-party and before the impact of derivative settlements.
Gathering, Transportation and Processing. Gathering, transportation and processing for the three months ended September 30, 2021 was $20.9 million, or $2.28 per Boe, as compared to $20.0 million, or $2.47 per Boe in the second quarter of 2021. This increase is related to the 13% increase in production volumes between the two periods.
Depreciation, Depletion and Amortization ("DD&A"). DD&A for the three months ended September 30, 2021 was $9.80 per Boe compared to $10.27 per Boe in the second quarter of 2021. The decrease in DD&A per Boe was primarily attributable to a larger percentage increase in production as compared to the depletion rate of our proved reserves from the second quarter of 2021 to the third quarter of 2021.
General and Administrative Expense ("G&A"). G&A for the three months ended September 30, 2021 and June 30, 2021 was $9.5 million, or $1.04 per Boe, and $11.1 million, or $1.37 per Boe, respectively. G&A, excluding certain non-cash incentive share-based compensation valuation adjustments, ("Adjusted G&A"1) was $12.0 million, or $1.31 per Boe, for the three months ended September 30, 2021 compared to $7.5 million, or $0.93 per Boe, for the second quarter of 2021. The cash component of Adjusted G&A increased to $10.4 million, or $1.13 per Boe, for the three months ended September 30, 2021 compared to $5.8 million, or $0.71 per Boe, for the second quarter of 2021 primarily as a result of higher compensation costs during the quarter.
The following table reconciles total G&A to Adjusted G&A - cash component and full cash G&A (in thousands):
Three Months Ended | ||||||||
September 30, 2021 | June 30, 2021 | September 30, 2020 | ||||||
Total G&A | $9,503 | $11,065 | $8,224 | |||||
Change in the fair value of liability share-based awards (non-cash) | 2,492 | (3,555) | 1,582 | |||||
Adjusted G&A – total | 11,995 | 7,510 | 9,806 | |||||
Equity-settled, share-based compensation (non-cash) and other non-recurring expenses | (1,589) | (1,724) | (1,674) | |||||
Adjusted G&A – cash component | $10,406 | $5,786 | $8,132 | |||||
Capitalized cash G&A | 9,034 | 7,404 | 6,831 | |||||
Full cash G&A | $19,440 | $13,190 | $14,963 | |||||
Income Tax. Callon provides for income taxes at the statutory rate of 21% adjusted for permanent differences expected to be realized. We recorded income tax expense of $2.4 million compared to income tax benefit of $0.5 million for the three months ended September 30, 2021 and June 30, 2021, respectively. Since the second quarter of 2020, we have concluded that it is more likely than not that the net deferred tax assets will not be realized and have recorded a full valuation allowance against our deferred tax assets. As long as we continue to conclude that the valuation allowance is necessary, we will not have significant deferred tax expense or benefit.
Adjusted EBITDA. Net income was $171.9 million and adjusted EBITDA was $292.2 million for the third quarter of 2021 as compared to net loss of $11.7 million and adjusted EBITDA of $196.8 million for the second quarter of 2021. The increase in adjusted EBITDA from the second quarter of 2021 was primarily due to an increase in revenues.
Adjusted Income and Adjusted EBITDA. The following tables reconcile the Company's net income (loss) to adjusted income and adjusted EBITDA:
Three Months Ended | ||||||||
September 30, 2021 | June 30, 2021 | September 30, 2020 | ||||||
(In thousands, except per share data) | ||||||||
Net income (loss) | $171,902 | ($11,695) | ($680,384) | |||||
Loss on derivative contracts | 107,169 | 190,463 | 27,038 | |||||
Loss on commodity derivative settlements, net | (110,960) | (100,128) | (5,540) | |||||
Non-cash expense (benefit) related to share-based awards | (903) | 5,279 | (94) | |||||
Impairment of evaluated oil and gas properties | — | — | 684,956 | |||||
Merger, integration and transaction | 3,018 | — | 2,465 | |||||
Other (income) expense | 4,305 | 5,584 | 3,567 | |||||
Gain on extinguishment of debt | (2,420) | — | — | |||||
Tax effect on adjustments above(a) | (44) | (21,252) | (149,602) | |||||
Change in valuation allowance | (34,190) | 2,079 | 143,152 | |||||
Adjusted income | $137,877 | $70,330 | $25,558 | |||||
Adjusted income per diluted share | $2.93 | $1.49 | $0.64 | |||||
Basic WASO | 46,290 | 46,267 | 39,746 | |||||
Diluted WASO (GAAP) | 47,096 | 46,267 | 39,746 | |||||
Effect of potentially dilutive instruments | — | 862 | 35 | |||||
Adjusted Diluted WASO | 47,096 | 47,129 | 39,781 | |||||
(a) Calculated using the federal statutory rate of 21%. | ||||||||
Three Months Ended | ||||||||
September 30, 2021 | June 30, 2021 | September 30, 2020 | ||||||
(In thousands) | ||||||||
Net income (loss) | $171,902 | ($11,695) | ($680,384) | |||||
Loss on derivative contracts | 107,169 | 190,463 | 27,038 | |||||
Loss on commodity derivative settlements, net | (110,960) | (100,128) | (5,540) | |||||
Non-cash expense (benefit) related to share-based awards | (903) | 5,279 | (94) | |||||
Impairment of evaluated oil and gas properties | — | — | 684,956 | |||||
Merger, integration and transaction | 3,018 | — | 2,465 | |||||
Other (income) expense | 4,305 | 5,584 | 3,567 | |||||
Income tax (benefit) expense | 2,416 | (478) | — | |||||
Interest expense, net | 27,736 | 24,634 | 24,683 | |||||
Depreciation, depletion and amortization | 89,890 | 83,128 | 114,201 | |||||
Gain on extinguishment of debt | (2,420) | — | — | |||||
Adjusted EBITDA | $292,153 | $196,787 | $170,892 | |||||
Adjusted Free Cash Flow. The following table reconciles the Company's net cash provided by operating activities to adjusted EBITDA and adjusted free cash flow:
Three Months Ended | ||||||||
September 30, 2021 | June 30, 2021 | September 30, 2020 | ||||||
(In thousands) | ||||||||
Net cash provided by operating activities | $294,565 | $175,603 | $135,701 | |||||
Changes in working capital and other | (30,355) | 13,520 | 14,473 | |||||
Change in accrued hedge settlements | (153) | (14,719) | (5,993) | |||||
Cash interest expense, net | 25,078 | 22,383 | 24,246 | |||||
Merger, integration and transaction | 3,018 | — | 2,465 | |||||
Adjusted EBITDA | 292,153 | 196,787 | 170,892 | |||||
Less: Operational capital expenditures (accrual) | 114,964 | 138,321 | 38,408 | |||||
Less: Capitalized interest | 23,590 | 21,740 | 20,675 | |||||
Less: Interest expense, net of capitalized amounts | 25,078 | 22,383 | 24,683 | |||||
Less: Capitalized cash G&A | 9,034 | 7,404 | 6,831 | |||||
Adjusted free cash flow (a) | $119,487 | $6,939 | $80,295 | |||||
(a) | Effective January 1, 2021, non-cash interest expense amounts consisting primarily of amortization of debt issuance costs, premiums, and discounts associated with our long-term debt are excluded from our calculation of adjusted free cash flow. |
Adjusted Discretionary Cash Flow. The following table reconciles the Company's net cash provided by operating activities to adjusted discretionary cash flow:
Three Months Ended | ||||||||
September 30, 2021 | June 30, 2021 | September 30, 2020 | ||||||
(In thousands) | ||||||||
Cash flows from operating activities: | ||||||||
Net income (loss) | $171,902 | ($11,695) | ($680,384) | |||||
Adjustments to reconcile net income (loss) to cash provided by operating activities: | ||||||||
Depreciation, depletion and amortization | 89,890 | 83,128 | 114,201 | |||||
Impairment of evaluated oil and gas properties | — | — | 684,956 | |||||
Amortization of non-cash debt related items, net | 2,658 | 2,252 | 437 | |||||
Deferred income tax expense | — | — | — | |||||
Loss on derivative contracts | 107,169 | 190,463 | 27,038 | |||||
Cash received (paid) for commodity derivative settlements, net | (110,807) | (85,409) | 453 | |||||
Gain on extinguishment of debt | (2,420) | — | — | |||||
Non-cash expense (benefit) related to share-based awards | (903) | 5,279 | (94) | |||||
Merger, integration and transaction | 3,018 | — | 2,465 | |||||
Other, net | 6,495 | 3,294 | 2,099 | |||||
Adjusted discretionary cash flow | $267,002 | $187,312 | $151,171 | |||||
Changes in working capital | 30,581 | (11,709) | (13,005) | |||||
Merger, integration and transaction | (3,018) | — | (2,465) | |||||
Net cash provided by operating activities | $294,565 | $175,603 | $135,701 | |||||
Adjusted Total Revenue. Adjusted total revenue is reconciled to total operating revenues, which excludes revenue from sales of commodities purchased from a third party, in the following table:
Three Months Ended | |||||||||
September 30, 2021 | June 30, 2021 | September 30, 2020 | |||||||
(In thousands) | |||||||||
Operating revenues | |||||||||
Oil | $409,293 | $333,442 | $231,654 | ||||||
Natural gas | 36,519 | 24,080 | 15,034 | ||||||
NGLs | 58,097 | 36,625 | 23,025 | ||||||
Total operating revenues | $503,909 | $394,147 | $269,713 | ||||||
Impact of settled derivatives | (110,960) | (100,128) | (5,540) | ||||||
Adjusted total revenue | $392,949 | $294,019 | $264,173 | ||||||
Callon Petroleum Company | ||||||
Consolidated Balance Sheets | ||||||
(In thousands, except par and share amounts) | ||||||
(Unaudited) | ||||||
September 30, 2021 | December 31, 2020 | |||||
ASSETS | ||||||
Current assets: | ||||||
Cash and cash equivalents | $3,699 | $20,236 | ||||
Accounts receivable, net | 216,116 | 133,109 | ||||
Fair value of derivatives | 18,605 | 921 | ||||
Other current assets | 30,110 | 24,103 | ||||
Total current assets | 268,530 | 178,369 | ||||
Oil and natural gas properties, full cost accounting method: | ||||||
Evaluated properties, net | 2,565,601 | 2,355,710 | ||||
Unevaluated properties | 1,712,428 | 1,733,250 | ||||
Total oil and natural gas properties, net | 4,278,029 | 4,088,960 | ||||
Other property and equipment, net | 30,591 | 31,640 | ||||
Deferred financing costs | 19,274 | 23,643 | ||||
Other assets, net | 89,992 | 40,256 | ||||
Total assets | $4,686,416 | $4,362,868 | ||||
LIABILITIES AND STOCKHOLDERS' EQUITY | ||||||
Current liabilities: | ||||||
Accounts payable and accrued liabilities | $442,053 | $341,519 | ||||
Fair value of derivatives | 324,682 | 97,060 | ||||
Other current liabilities | 61,641 | 58,529 | ||||
Total current liabilities | 828,376 | 497,108 | ||||
Long-term debt | 2,809,610 | 2,969,264 | ||||
Asset retirement obligations | 58,703 | 57,209 | ||||
Fair value of derivatives | 15,250 | 88,046 | ||||
Other long-term liabilities | 41,448 | 40,239 | ||||
Total liabilities | 3,753,387 | 3,651,866 | ||||
Commitments and contingencies | ||||||
Stockholders' equity: | ||||||
Common stock, $0.01 par value, 78,750,000 and 52,500,000 shares authorized; 46,290,611 and 39,758,817 shares outstanding, respectively | 463 | 398 | ||||
Capital in excess of par value | 3,365,121 | 3,222,959 | ||||
Accumulated deficit | (2,432,555) | (2,512,355) | ||||
Total stockholders' equity | 933,029 | 711,002 | ||||
Total liabilities and stockholders' equity | $4,686,416 | $4,362,868 | ||||
Callon Petroleum Company | |||||||||||
Consolidated Statements of Operations | |||||||||||
(In thousands, except per share data) | |||||||||||
(Unaudited) | |||||||||||
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||
2021 | 2020 | 2021 | 2020 | ||||||||
Operating Revenues: | |||||||||||
Oil | $409,293 | $231,654 | $1,009,780 | $627,934 | |||||||
Natural gas | 36,519 | 15,034 | 84,819 | 33,305 | |||||||
Natural gas liquids | 58,097 | 23,025 | 124,079 | 55,627 | |||||||
Sales of purchased oil and gas | 48,653 | 20,313 | 134,164 | 21,469 | |||||||
Total operating revenues | 552,562 | 290,026 | 1,352,842 | 738,335 | |||||||
Operating Expenses: | |||||||||||
Lease operating | 42,706 | 45,870 | 129,619 | 149,091 | |||||||
Production and ad valorem taxes | 26,070 | 16,110 | 66,467 | 46,151 | |||||||
Gathering, transportation and processing | 20,875 | 22,200 | 58,887 | 56,615 | |||||||
Cost of purchased oil and gas | 49,392 | 21,282 | 139,558 | 22,450 | |||||||
Depreciation, depletion and amortization | 89,890 | 114,201 | 244,005 | 384,594 | |||||||
General and administrative | 9,503 | 8,224 | 37,367 | 26,573 | |||||||
Impairment of evaluated oil and gas properties | — | 684,956 | — | 1,961,474 | |||||||
Merger, integration and transaction | 3,018 | 2,465 | 3,018 | 26,362 | |||||||
Other operating | — | 4,425 | 3,366 | 8,548 | |||||||
Total operating expenses | 241,454 | 919,733 | 682,287 | 2,681,858 | |||||||
Income (Loss) From Operations | 311,108 | (629,707) | 670,555 | (1,943,523) | |||||||
Other (Income) Expenses: | |||||||||||
Interest expense, net of capitalized amounts | 27,736 | 24,683 | 76,786 | 67,843 | |||||||
(Gain) loss on derivative contracts | 107,169 | 27,038 | 512,155 | (97,966) | |||||||
Gain on extinguishment of debt | (2,420) | — | (2,420) | — | |||||||
Other (income) expense | 4,305 | (1,044) | 3,217 | (149) | |||||||
Total other (income) expense | 136,790 | 50,677 | 589,738 | (30,272) | |||||||
Income (Loss) Before Income Taxes | 174,318 | (680,384) | 80,817 | (1,913,251) | |||||||
Income tax expense | (2,416) | — | (1,017) | (115,299) | |||||||
Net Income (Loss) | $171,902 | ($680,384) | $79,800 | ($2,028,550) | |||||||
Net Income (Loss) Per Common Share: | |||||||||||
Basic | $3.71 | ($17.12) | $1.77 | ($51.09) | |||||||
Diluted | $3.65 | ($17.12) | $1.69 | ($51.09) | |||||||
Weighted Average Common Shares Outstanding: | |||||||||||
Basic | 46,290 | 39,746 | 45,063 | 39,707 | |||||||
Diluted | 47,096 | 39,746 | 47,119 | 39,707 | |||||||
Callon Petroleum Company | |||||||||||
Consolidated Statements of Cash Flows | |||||||||||
(In thousands) | |||||||||||
(Unaudited) | |||||||||||
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||
2021 | 2020 | 2021 | 2020 | ||||||||
Cash flows from operating activities: | |||||||||||
Net income (loss) | $171,902 | ($680,384) | $79,800 | ($2,028,550) | |||||||
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |||||||||||
Depreciation, depletion and amortization | 89,890 | 114,201 | 244,005 | 384,594 | |||||||
Impairment of evaluated oil and gas properties | — | 684,956 | — | 1,961,474 | |||||||
Amortization of non-cash debt related items, net | 2,658 | 437 | 7,166 | 1,582 | |||||||
Deferred income tax expense | — | — | — | 115,299 | |||||||
(Gain) loss on derivative contracts | 107,169 | 27,038 | 512,155 | (97,966) | |||||||
Cash received (paid) for commodity derivative settlements, net | (110,807) | 453 | (238,378) | 101,754 | |||||||
Gain on extinguishment of debt | (2,420) | — | (2,420) | — | |||||||
Non-cash expense (benefit) related to share-based awards | (903) | (94) | 11,984 | (305) | |||||||
Other, net | 6,495 | 2,084 | 11,006 | 5,740 | |||||||
Changes in current assets and liabilities: | |||||||||||
Accounts receivable | (15,870) | (16,930) | (83,227) | 96,110 | |||||||
Other current assets | (1,278) | (2,208) | (8,701) | (6,556) | |||||||
Accounts payable and accrued liabilities | 47,729 | 6,148 | 74,443 | (107,979) | |||||||
Net cash provided by operating activities | 294,565 | 135,701 | 607,833 | 425,197 | |||||||
Cash flows from investing activities: | |||||||||||
Capital expenditures | (176,549) | (136,534) | (427,552) | (555,222) | |||||||
Acquisition of oil and gas properties | (4,904) | (643) | (7,119) | (12,524) | |||||||
Deposit for acquisition of oil and gas properties | (60,117) | — | (60,117) | — | |||||||
Proceeds from sale of assets | 3,804 | 139,739 | 35,415 | 149,818 | |||||||
Cash paid for settlements of contingent consideration arrangements, net | — | — | — | (40,000) | |||||||
Other, net | (14) | 1,427 | 4,206 | 8,261 | |||||||
Net cash provided by (used in) investing activities | (237,780) | 3,989 | (455,167) | (449,667) | |||||||
Cash flows from financing activities: | |||||||||||
Borrowings on Credit Facility | 500,000 | 312,000 | 1,236,500 | 5,087,500 | |||||||
Payments on Credit Facility | (652,000) | (737,000) | (1,498,500) | (5,347,500) | |||||||
Redemption of 6.25% Senior Notes | (542,755) | — | (542,755) | — | |||||||
Issuance of 8.00% Senior Notes due 2028 | 650,000 | — | 650,000 | — | |||||||
Issuance of 9.00% Second Lien Senior Secured Notes due 2025 | — | 300,000 | — | 300,000 | |||||||
Discount on the issuance of 9.00% Second Lien Senior Secured Notes due 2025 | — | (35,270) | — | (35,270) | |||||||
Issuance of September 2020 Warrants | — | 23,909 | — | 23,909 | |||||||
Payment of deferred financing costs | (12,131) | (301) | (12,168) | (6,312) | |||||||
Tax withholdings related to restricted stock units | — | (107) | (2,280) | (495) | |||||||
Other, net | — | 79 | — | (203) | |||||||
Net cash provided by (used in) financing activities | (56,886) | (136,690) | (169,203) | 21,629 | |||||||
Net change in cash and cash equivalents | (101) | 3,000 | (16,537) | (2,841) | |||||||
Balance, beginning of period | 3,800 | 7,500 | 20,236 | 13,341 | |||||||
Balance, end of period | $3,699 | $10,500 | $3,699 | $10,500 | |||||||
Non-GAAP Financial Measures
This news release refers to non-GAAP financial measures such as "adjusted free cash flow," "adjusted discretionary cash flow," "adjusted G&A," "full cash G&A," "adjusted income," "adjusted income per diluted share," "adjusted EBITDA," and "adjusted total revenue." These measures, detailed below, are provided in addition to, and not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP (including the notes), included in our filings with the U.S. Securities and Exchange Commission (the "SEC") and posted on our website.
- Adjusted free cash flow is a supplemental non-GAAP measure that is defined by the Company as adjusted EBITDA less operational capital, cash capitalized interest, net cash interest expense and capitalized cash G&A (which excludes capitalized expense related to share-based awards). We believe adjusted free cash flow is a comparable metric against other companies in the industry and is a widely accepted financial indicator of an oil and natural gas company's ability to generate cash for the use of internally funding their capital development program and to service or incur debt. Adjusted free cash flow is not a measure of a company's financial performance under GAAP and should not be considered as an alternative to net cash provided by operating activities, or as a measure of liquidity, or as an alternative to net income (loss).
- Adjusted discretionary cash flow is a supplemental non-GAAP measure that Callon believes is a comparable metric against other companies in the industry and is a widely accepted financial indicator of an oil and natural gas company's ability to generate cash for the use of internally funding their capital development program and to service or incur debt. Adjusted discretionary cash flow is defined by Callon as net cash provided by operating activities before changes in working capital and merger, integration and transaction expenses. Callon has included this information because changes in operating assets and liabilities relate to the timing of cash receipts and disbursements, which the Company may not control and the cash flow effect may not be reflected the period in which the operating activities occurred. Adjusted discretionary cash flow is not a measure of a company's financial performance under GAAP and should not be considered as an alternative to net cash provided by operating activities, or as a measure of liquidity, or as an alternative to net income (loss).
- Adjusted G&A is a supplemental non-GAAP financial measure that excludes certain non-cash incentive share-based compensation valuation adjustments. Callon believes that the non-GAAP measure of adjusted G&A is useful to investors because it provides a meaningful measure of our recurring G&A expense and provides for greater comparability period-over-period.
- Full cash G&A is a supplemental non-GAAP financial measure that Callon defines as adjusted G&A – cash component plus capitalized G&A excluding capitalized expense related to share-based awards. Callon believes that the non-GAAP measure of full cash G&A is useful because it provides users with a meaningful measure of our total recurring cash G&A costs, whether expensed or capitalized, and provides for greater comparability on a period-over-period basis.
- Adjusted income and adjusted income per diluted share are supplemental non-GAAP measures that Callon believes are useful to investors because they provide readers with a meaningful measure of our profitability before recording certain items whose timing or amount cannot be reasonably determined. These measures exclude the net of tax effects of these items and non-cash valuation adjustments, which are detailed in the reconciliation provided. Adjusted income and adjusted income per diluted share are not measures of financial performance under GAAP. Accordingly, it should not be considered as a substitute for net income (loss), operating income (loss), or other income data prepared in accordance with GAAP. However, the Company believes that adjusted income and adjusted income per diluted share provide additional information with respect to our performance. Because adjusted income and adjusted income per diluted share exclude some, but not all, items that affect net income (loss) and may vary among companies, the adjusted income and adjusted income per diluted share presented above may not be comparable to similarly titled measures of other companies.
- Adjusted diluted weighted average common shares outstanding ("Adjusted Diluted WASO") is a non-GAAP financial measure which includes the effect of potentially dilutive instruments that, under certain circumstances described below, are excluded from diluted weighted average common shares outstanding ("Diluted WASO"), the most directly comparable GAAP financial measure. When a net loss exists, all potentially dilutive instruments are anti-dilutive to the net loss per common share and therefore excluded from the computation of Diluted WASO. The effect of potentially dilutive instruments are included in the computation of Adjusted Diluted WASO for purposes of computing adjusted income per diluted share.
- Callon calculates adjusted EBITDA as net income (loss) before interest expense, income tax expense (benefit), depreciation, depletion and amortization, (gains) losses on derivative instruments excluding net settled derivative instruments, impairment of evaluated oil and gas properties, non-cash stock-based compensation expense, merger, integration and transaction expense, (gain) loss on extinguishment of debt, and other operating expenses. Adjusted EBITDA is not a measure of financial performance under GAAP. Accordingly, it should not be considered as a substitute for net income (loss), operating income (loss), cash flow provided by operating activities or other income or cash flow data prepared in accordance with GAAP. However, the Company believes that adjusted EBITDA provides additional information with respect to our performance or ability to meet our future debt service, capital expenditures and working capital requirements. Because adjusted EBITDA excludes some, but not all, items that affect net income (loss) and may vary among companies, the adjusted EBITDA presented above may not be comparable to similarly titled measures of other companies.
- Callon believes that the non-GAAP measure of adjusted total revenue (which is revenue including the gain or loss from the settlement of derivative contracts) is useful to investors because it provides readers with a revenue value more comparable to other companies who engage in price risk management activities through the use of commodity derivative instruments and reflects the results of derivative settlements with expected cash flow impacts within total revenues. See the reconciliation provided above for further details.
Earnings Call Information
The Company will host a conference call on Thursday, November 4, 2021, to discuss third quarter 2021 financial and operating results, 2021 outlook, and current corporate strategy and initiatives.
Please join Callon Petroleum Company via the Internet for a webcast of the conference call:
Date/Time: | Thursday, November 4, 2021, at 8:00 a.m. Central Time (9:00 a.m. Eastern Time) |
Webcast: | Select "News and Events" under the "Investors" section of the Company's website: www.callon.com. |
An archive of the conference call webcast will also be available at www.callon.com under the "Investors" section of the website.
About Callon Petroleum Company
Callon Petroleum Company is an independent oil and natural gas company focused on the acquisition, exploration and development of high-quality assets in the leading oil plays of South and West Texas.
Cautionary Statement Regarding Forward-Looking Information
This news release contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements include all statements regarding wells anticipated to be drilled and placed on production; future levels of development activity and associated production, capital expenditures and cash flow expectations; the Company's 2021 production expense guidance and capital expenditure guidance; estimated reserve quantities and the present value thereof; and the implementation of the Company's business plans and strategy, as well as statements including the words "believe," "expect," "plans," "may," "will," "should," "could," and words of similar meaning. These statements reflect the Company's current views with respect to future events and financial performance based on management's experience and perception of historical trends, current conditions, anticipated future developments and other factors believed to be appropriate. No assurances can be given, however, that these events will occur or that these projections will be achieved, and actual results could differ materially from those projected as a result of certain factors. Any forward-looking statement speaks only as of the date on which such statement is made and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law. Some of the factors which could affect our future results and could cause results to differ materially from those expressed in our forward-looking statements include the volatility of oil and natural gas prices; changes in the supply of and demand for oil and natural gas, including as a result of the COVID-19 pandemic and various governmental actions taken to mitigate its impact or actions by, or disputes among members of OPEC and other oil and natural gas producing countries with respect to production levels or other matters related to the price of oil; our ability to drill and complete wells; operational, regulatory and environment risks; the cost and availability of equipment and labor; our ability to finance our development activities at expected costs or at expected times or at all; our inability to realize the benefits of recent transactions; currently unknown risks and liabilities relating to the newly acquired assets and operations; adverse actions by third parties involved with the transactions; risks that are not yet known or material to us; and other risks more fully discussed in our filings with the SEC, including our most recent Annual Reports on Form 10-K and subsequent Quarterly Reports on Form 10-Q, available on our website or the SEC's website at www.sec.gov. Any forward-looking statement speaks only as of the date on which such statement is made, and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law.
Contact Information
Mark Brewer
Director of Investor Relations
Callon Petroleum Company
[email protected]
(281) 589-5200
1) | See "Non-GAAP Financial Measures" included within this release for related disclosures. |
SOURCE Callon Petroleum Company
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