UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
☒ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For The Quarterly Period Endedthe quarterly period ended March 31, 20212022
or
☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from ____________ to ____________
Commission File Number 001-14039
Callon Petroleum Company
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| (Exact Name of Registrant as Specified in Its Charter) | |
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Delaware | | 64-0844345 |
State or Other Jurisdiction of Incorporation or Organization | | I.R.S. Employer Identification No. |
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One Briarlake Plaza | | |
2000 W. Sam Houston Parkway S., Suite 2000 | | |
Houston, | Texas | | 77042 |
Address of Principal Executive Offices | | Zip Code |
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| (281) | 589-5200 | |
| Registrant’s Telephone Number, Including Area Code | |
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| Former Name, Former Address and Former Fiscal Year, if Changed Since Last Report | |
Securities registered pursuant to Section 12(b) of the Act:
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Title of Each Class | | Trading Symbol(s) | | Name of Each Exchange on Which Registered |
Common Stock, $0.01 par value | | CPE | | New York Stock Exchange |
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act:
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Large accelerated filer | ☐☒ | Accelerated filer | ☒☐ | | |
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Non-accelerated filer | ☐ | Smaller reporting company | ☐ | | |
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| | Emerging growth company | ☐ | | |
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒
The Registrant had 46,264,87061,689,752 shares of common stock outstanding as of April 30, 2021.29, 2022.
For certain industry specific terms used in this Form 10-Q, please see “Glossary of Certain Terms” in our 2021 Annual Report on Form 10-K
Table of Contents
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Part I. Financial Information | |
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Item 1. Financial Statements (Unaudited) | |
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Part II. Other Information | |
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GLOSSARY OF CERTAIN TERMS
All defined terms under Rule 4-10(a) of Regulation S-X shall have their prescribed meanings when used in this report. As used in this document:
•ASU: accounting standards update.
•Bbl: barrel or barrels of oil or natural gas liquids.
•Boe: barrel of oil equivalent, determined by using the ratio of one Bbl of oil or NGLs to six Mcf of natural gas. The ratio of one barrel of oil or NGLs to six Mcf of natural gas is commonly used in the industry and represents the approximate energy equivalence of oil or NGLs to natural gas, and does not represent the economic equivalency of oil and NGLs to natural gas. The sales price of a barrel of oil or NGLs is considerably higher than the sales price of six Mcf of natural gas.
•Boe/d: Boe per day.
•Btu: a British thermal unit, which is a measure of the amount of energy required to raise the temperature of one pound of water one degree Fahrenheit.
•Completion: the process of treating a drilled well followed by the installation of permanent equipment for the production of oil or natural gas or, in the case of a dry hole, the reporting of abandonment to the appropriate agency.
•Cushing: an oil delivery point that serves as the benchmark oil price for West Texas Intermediate.
•FASB: Financial Accounting Standards Board.
•GAAP: Generally Accepted Accounting Principles in the United States.
•Henry Hub: a natural gas pipeline delivery point that serves as the benchmark natural gas price underlying NYMEX natural gas futures contracts.
•Horizontal drilling: a drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at an angle within a specified interval.
•LOE: lease operating expense.
•MBbls: thousand barrels of oil.
•MBoe: thousand Boe.
•Mcf: thousand cubic feet of natural gas.
•MEH: Magellan East Houston, a delivery point in Houston, Texas that serves as a benchmark for crude oil.
•MMBoe: million Boe.
•MMBtu: million Btu.
•MMcf: million cubic feet of natural gas.
•NGL or NGLs: natural gas liquids, such as ethane, propane, butane and natural gasoline that are extracted from natural gas production streams.
•NYMEX: New York Mercantile Exchange.
•Oil: includes crude oil and condensate.
•OPEC: Organization of Petroleum Exporting Countries.
•Proved reserves: Those reserves which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced, or the operator must be reasonably certain that it will commence the project, within a reasonable time.
The area of the reservoir considered as proved includes all of the following:
a.The area identified by drilling and limited by fluid contacts, if any, and
b.Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.
Reserves that can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when both of the following occur:
a.Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based, and
b.The project has been approved for development by all necessary parties and entities, including governmental entities.
Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12‑month period before the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
•Realized price: the cash market price less all expected quality, transportation and demand adjustments.
•RSU: restricted stock units.
•SEC: United States Securities and Exchange Commission.
•Waha: a delivery point in West Texas that serves as the benchmark for natural gas.
•Working interest: an operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production and requires the owner to pay a share of the costs of drilling and production operations.
•WTI: West Texas Intermediate grade crude oil, used as a pricing benchmark for sales contracts and NYMEX oil futures contracts.
With respect to information relating to our working interest in wells or acreage, “net” oil and gas wells or acreage is determined by multiplying gross wells or acreage by our working interest therein. Unless otherwise specified, all references to wells and acres are gross.
Part I. Financial Information
Item 1. Financial Statements
Callon Petroleum Company
Consolidated Balance Sheets
(In thousands, except par and share amounts)
(Unaudited)
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| | March 31, 2021 | | December 31, 2020 |
ASSETS | | | | |
Current assets: | | | | |
Cash and cash equivalents | | $24,350 | | | $20,236 | |
Accounts receivable, net | | 179,127 | | | 133,109 | |
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Other current assets | | 32,878 | | | 25,024 | |
Total current assets | | 236,355 | | | 178,369 | |
Oil and natural gas properties, full cost accounting method: | | | | |
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Evaluated properties, net | | 2,394,339 | | | 2,355,710 | |
Unevaluated properties | | 1,754,768 | | | 1,733,250 | |
Total oil and natural gas properties, net | | 4,149,107 | | | 4,088,960 | |
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Other property and equipment, net | | 31,435 | | | 31,640 | |
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Deferred financing costs | | 22,177 | | | 23,643 | |
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Other assets, net | | 37,792 | | | 40,256 | |
Total assets | | $4,476,866 | | | $4,362,868 | |
LIABILITIES AND STOCKHOLDERS’ EQUITY | | | | |
Current liabilities: | | | | |
Accounts payable and accrued liabilities | | $374,749 | | | $341,519 | |
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Fair value of derivatives | | 224,446 | | | 97,060 | |
Other current liabilities | | 72,854 | | | 58,529 | |
Total current liabilities | | 672,049 | | | 497,108 | |
Long-term debt | | 2,937,239 | | | 2,969,264 | |
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Asset retirement obligations | | 55,935 | | | 57,209 | |
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Fair value of derivatives | | 1,400 | | | 88,046 | |
Other long-term liabilities | | 42,221 | | | 40,239 | |
Total liabilities | | 3,708,844 | | | 3,651,866 | |
Commitments and contingencies | | 0 | | 0 |
Stockholders’ equity: | | | | |
| | | | |
Common stock, $0.01 par value, 52,500,000 shares authorized; 46,156,854 and 39,758,817 shares outstanding, respectively | | 462 | | | 398 | |
Capital in excess of par value | | 3,360,322 | | | 3,222,959 | |
Accumulated deficit | | (2,592,762) | | | (2,512,355) | |
Total stockholders’ equity | | 768,022 | | | 711,002 | |
Total liabilities and stockholders’ equity | | $4,476,866 | | | $4,362,868 | |
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| | March 31, 2022 | | December 31, 2021 |
ASSETS | | | | |
Current assets: | | | | |
Cash and cash equivalents | | $4,150 | | | $9,882 | |
Accounts receivable, net | | 347,593 | | | 232,436 | |
Fair value of derivatives | | — | | | 22,381 | |
Other current assets | | 33,249 | | | 30,745 | |
Total current assets | | 384,992 | | | 295,444 | |
Oil and natural gas properties, full cost accounting method: | | | | |
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Evaluated properties, net | | 3,426,156 | | | 3,352,821 | |
Unevaluated properties | | 1,847,790 | | | 1,812,827 | |
Total oil and natural gas properties, net | | 5,273,946 | | | 5,165,648 | |
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Other property and equipment, net | | 28,985 | | | 28,128 | |
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Deferred financing costs | | 16,543 | | | 18,125 | |
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Other assets, net | | 41,054 | | | 40,158 | |
Total assets | | $5,745,520 | | | $5,547,503 | |
LIABILITIES AND STOCKHOLDERS’ EQUITY | | | | |
Current liabilities: | | | | |
Accounts payable and accrued liabilities | | $516,440 | | | $569,991 | |
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Fair value of derivatives | | 392,928 | | | 185,977 | |
Other current liabilities | | 163,936 | | | 116,523 | |
Total current liabilities | | 1,073,304 | | | 872,491 | |
Long-term debt | | 2,623,282 | | | 2,694,115 | |
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Asset retirement obligations | | 55,160 | | | 54,458 | |
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Fair value of derivatives | | 34,434 | | | 11,409 | |
Other long-term liabilities | | 44,750 | | | 49,262 | |
Total liabilities | | 3,830,930 | | | 3,681,735 | |
Commitments and contingencies | | 0 | | 0 |
Stockholders’ equity: | | | | |
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Common stock, $0.01 par value, 78,750,000 shares authorized; 61,493,753 and 61,370,684 shares outstanding, respectively | | 615 | | | 614 | |
Capital in excess of par value | | 4,021,442 | | | 4,012,358 | |
Accumulated deficit | | (2,107,467) | | | (2,147,204) | |
Total stockholders’ equity | | 1,914,590 | | | 1,865,768 | |
Total liabilities and stockholders’ equity | | $5,745,520 | | | $5,547,503 | |
The accompanying notes are an integral part of these consolidated financial statements.
Callon Petroleum Company
Consolidated Statements of Operations
(In thousands, except per share amounts)
(Unaudited)
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| Three Months Ended March 31, | | |
| 2021 | | 2020 | | | | |
Operating Revenues: | | | | | | | |
Oil | $267,045 | | | $265,767 | | | | | |
Natural gas | 24,220 | | | 6,029 | | | | | |
Natural gas liquids | 29,357 | | | 18,123 | | | | | |
Sales of purchased oil and gas | 39,259 | | | 0 | | | | | |
Total operating revenues | 359,881 | | | 289,919 | | | | | |
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Operating Expenses: | | | | | | | |
Lease operating | 40,453 | | | 52,383 | | | | | |
Production and ad valorem taxes | 18,439 | | | 19,680 | | | | | |
Gathering, transportation and processing | 17,981 | | | 14,378 | | | | | |
Cost of purchased oil and gas | 40,917 | | | 0 | | | | | |
Depreciation, depletion and amortization | 70,987 | | | 131,463 | | | | | |
General and administrative | 16,799 | | | 8,325 | | | | | |
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Merger and integration | 0 | | | 15,830 | | | | | |
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Other operating | 929 | | | 0 | | | | | |
Total operating expenses | 206,505 | | | 242,059 | | | | | |
Income From Operations | 153,376 | | | 47,860 | | | | | |
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Other (Income) Expenses: | | | | | | | |
Interest expense, net of capitalized amounts | 24,416 | | | 20,478 | | | | | |
(Gain) loss on derivative contracts | 214,523 | | | (251,969) | | | | | |
Other (income) expense | (4,235) | | | (1,262) | | | | | |
Total other (income) expense | 234,704 | | | (232,753) | | | | | |
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Income (Loss) Before Income Taxes | (81,328) | | | 280,613 | | | | | |
Income tax benefit (expense) | 921 | | | (64,048) | | | | | |
Net Income (Loss) | ($80,407) | | | $216,565 | | | | | |
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Net Income (Loss) Per Common Share (1): | | | | | | | |
Basic | ($1.89) | | | $5.46 | | | | | |
Diluted | ($1.89) | | | $5.46 | | | | | |
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Weighted Average Common Shares Outstanding (1): | | | | | | | |
Basic | 42,590 | | | 39,667 | | | | | |
Diluted | 42,590 | | | 39,684 | | | | | |
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| Three Months Ended March 31, | | |
| 2022 | | 2021 | | | | |
Operating Revenues: | | | | | | | |
Oil | $553,249 | | | $267,045 | | | | | |
Natural gas | 43,976 | | | 24,220 | | | | | |
Natural gas liquids | 67,618 | | | 29,357 | | | | | |
Sales of purchased oil and gas | 112,375 | | | 39,259 | | | | | |
Total operating revenues | 777,218 | | | 359,881 | | | | | |
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Operating Expenses: | | | | | | | |
Lease operating | 67,328 | | | 40,453 | | | | | |
Production and ad valorem taxes | 37,678 | | | 18,439 | | | | | |
Gathering, transportation and processing | 20,775 | | | 17,981 | | | | | |
Cost of purchased oil and gas | 111,271 | | | 40,917 | | | | | |
Depreciation, depletion and amortization | 102,979 | | | 70,987 | | | | | |
General and administrative | 17,121 | | | 16,799 | | | | | |
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Merger, integration and transaction | 769 | | | — | | | | | |
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Total operating expenses | 357,921 | | | 205,576 | | | | | |
Income From Operations | 419,297 | | | 154,305 | | | | | |
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Other (Income) Expenses: | | | | | | | |
Interest expense, net of capitalized amounts | 21,558 | | | 24,416 | | | | | |
Loss on derivative contracts | 358,300 | | | 214,523 | | | | | |
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Other income | (782) | | | (3,306) | | | | | |
Total other expense | 379,076 | | | 235,633 | | | | | |
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Income (Loss) Before Income Taxes | 40,221 | | | (81,328) | | | | | |
Income tax benefit (expense) | (484) | | | 921 | | | | | |
Net Income (Loss) | $39,737 | | | ($80,407) | | | | | |
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Net Income (Loss) Per Common Share: | | | | | | | |
Basic | $0.65 | | | ($1.89) | | | | | |
Diluted | $0.64 | | | ($1.89) | | | | | |
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Weighted Average Common Shares Outstanding: | | | | | | | |
Basic | 61,487 | | | 42,590 | | | | | |
Diluted | 62,065 | | | 42,590 | | | | | |
(1) All share and per share amounts have been retroactively adjusted for the Company’s 1-for-10 reverse stock split effective August 7, 2020. See “Note 10 -The accompanying notes are an integral part of these consolidated financial statements.
Callon Petroleum Company
Consolidated Statements of Stockholders’ Equity” for additional information.Equity
(In thousands)
(Unaudited)
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| | Common | | Capital in | | | | Total |
| | Stock | | Excess | | Accumulated | | Stockholders’ |
| | Shares | | $ | | of Par | | Deficit | | Equity |
Balance at December 31, 2021 | | 61,371 | | | $614 | | | $4,012,358 | | | ($2,147,204) | | | $1,865,768 | |
Net income | | — | | | — | | | — | | | 39,737 | | | 39,737 | |
Restricted stock | | 6 | | | — | | | 2,790 | | | — | | | 2,790 | |
Common stock issued for Primexx Acquisition | | 117 | | | 1 | | | 6,294 | | | — | | | 6,295 | |
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Balance at March 31, 2022 | | 61,494 | | | $615 | | | $4,021,442 | | | ($2,107,467) | | | $1,914,590 | |
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| | Common | | Capital in | | | | Total |
| | Stock | | Excess | | Accumulated | | Stockholders’ |
| | Shares | | $ | | of Par | | Deficit | | Equity |
Balance at December 31, 2020 | | 39,759 | | | $398 | | | $3,222,959 | | | ($2,512,355) | | | $711,002 | |
Net loss | | — | | | — | | | — | | | (80,407) | | | (80,407) | |
Restricted stock | | 13 | | | — | | | 2,609 | | | — | | | 2,609 | |
Warrant exercises | | 6,385 | | | 64 | | | 134,754 | | | — | | | 134,818 | |
Balance at March 31, 2021 | | 46,157 | | | $462 | | | $3,360,322 | | | ($2,592,762) | | | $768,022 | |
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The accompanying notes are an integral part of these consolidated financial statements.
Callon Petroleum Company
Consolidated Statements of Cash Flows
(In thousands)
(Unaudited) | | | | | | | | | | | |
| Three Months Ended March 31, |
Cash flows from operating activities: | 2022 | | 2021 |
Net income (loss) | $39,737 | | | ($80,407) | |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | | | |
Depreciation, depletion and amortization | 102,979 | | | 70,987 | |
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Amortization of non-cash debt related items, net | 1,716 | | | 2,256 | |
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Loss on derivative contracts | 358,300 | | | 214,523 | |
Cash paid for commodity derivative settlements, net | (101,525) | | | (42,162) | |
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Non-cash expense related to share-based awards | 4,166 | | | 7,608 | |
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Other, net | 2,894 | | | 1,217 | |
Changes in current assets and liabilities: | | | |
Accounts receivable | (116,322) | | | (45,683) | |
Other current assets | (4,180) | | | (2,856) | |
Accounts payable and accrued liabilities | (12,987) | | | 12,182 | |
Cash received for settlements of contingent consideration arrangements, net | 6,492 | | | — | |
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Net cash provided by operating activities | 281,270 | | | 137,665 | |
Cash flows from investing activities: | | | |
Capital expenditures | (201,478) | | | (101,341) | |
Acquisition of oil and gas properties | (9,409) | | | (768) | |
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Proceeds from sales of assets | 4,484 | | | — | |
Cash paid for settlement of contingent consideration arrangement | (19,171) | | | — | |
Other, net | 3,635 | | | 3,595 | |
Net cash used in investing activities | (221,939) | | | (98,514) | |
Cash flows from financing activities: | | | |
Borrowings on Credit Facility | 673,000 | | | 303,000 | |
Payments on Credit Facility | (746,000) | | | (338,000) | |
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Cash received for settlement of contingent consideration arrangement | 8,512 | | | — | |
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Other, net | (575) | | | (37) | |
Net cash used in financing activities | (65,063) | | | (35,037) | |
Net change in cash and cash equivalents | (5,732) | | | 4,114 | |
Balance, beginning of period | 9,882 | | | 20,236 | |
Balance, end of period | $4,150 | | | $24,350 | |
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The accompanying notes are an integral part of these consolidated financial statements.
Callon Petroleum Company
Consolidated Statements of Stockholders’ Equity
(In thousands)
(Unaudited)
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| | Common | | Capital in | | | | Total |
| | Stock | | Excess | | Accumulated | | Stockholders’ |
| | Shares | | $ | | of Par | | Deficit | | Equity |
Balance at December 31, 2020 | | 39,759 | | | $398 | | | $3,222,959 | | | ($2,512,355) | | | $711,002 | |
Net loss | | — | | | — | | | — | | | (80,407) | | | (80,407) | |
Restricted stock | | 13 | | | — | | | 2,609 | | | — | | | 2,609 | |
Warrant exercises | | 6,385 | | | 64 | | | 134,754 | | | — | | | 134,818 | |
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Balance at March 31, 2021 | | 46,157 | | | $462 | | | $3,360,322 | | | ($2,592,762) | | | $768,022 | |
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| | Common | | Capital in | | | | Total |
| | Stock | | Excess | | Retained | | Stockholders’ |
| | Shares (1) | | $ | | of Par | | Earnings | | Equity |
Balance at December 31, 2019 | | 39,659 | | | $3,966 | | | $3,198,076 | | | $21,266 | | | $3,223,308 | |
Net income | | — | | | — | | | — | | | 216,565 | | | 216,565 | |
Restricted stock | | 14 | | | 1 | | | 3,141 | | | — | | | 3,142 | |
Other | | — | | | — | | | (112) | | | — | | | (112) | |
Balance at March 31, 2020 | | 39,673 | | | $3,967 | | | $3,201,105 | | | $237,831 | | | $3,442,903 | |
(1) All share amounts have been retroactively adjusted for the Company’s 1-for-10 reverse stock split effective August 7, 2020. See “Note 10 - Stockholders’ Equity” for additional information.
The accompanying notes are an integral part of these consolidated financial statements.
Callon Petroleum Company
Consolidated Statements of Cash Flows
(In thousands)
(Unaudited)
| | | | | | | | | | | |
| Three Months Ended March 31, |
Cash flows from operating activities: | 2021 | | 2020 |
Net income (loss) | ($80,407) | | | $216,565 | |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | | | |
Depreciation, depletion and amortization | 70,987 | | | 131,463 | |
| | | |
Amortization of non-cash debt related items, net | 2,256 | | | 407 | |
Deferred income tax expense | 0 | | | 64,048 | |
(Gain) loss on derivative contracts | 214,523 | | | (251,969) | |
Cash received (paid) for commodity derivative settlements, net | (42,162) | | | 2,613 | |
| | | |
| | | |
Non-cash expense (benefit) related to share-based awards | 7,608 | | | (2,972) | |
| | | |
| | | |
Other, net | 1,217 | | | 136 | |
Changes in current assets and liabilities: | | | |
Accounts receivable | (45,683) | | | 115,873 | |
Other current assets | (2,856) | | | (781) | |
Accounts payable and accrued liabilities | 12,182 | | | (83,688) | |
| | | |
Net cash provided by operating activities | 137,665 | | | 191,695 | |
Cash flows from investing activities: | | | |
Capital expenditures | (101,341) | | | (213,459) | |
Acquisition of oil and gas properties | (768) | | | (10,989) | |
| | | |
Proceeds from sale of assets | 0 | | | 10,240 | |
Cash paid for settlements of contingent consideration arrangements, net | 0 | | | (40,000) | |
Other, net | 3,595 | | | (158) | |
Net cash used in investing activities | (98,514) | | | (254,366) | |
Cash flows from financing activities: | | | |
Borrowings on Credit Facility | 303,000 | | | 4,291,000 | |
Payments on Credit Facility | (338,000) | | | (4,226,000) | |
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Other, net | (37) | | | (870) | |
Net cash provided by (used in) financing activities | (35,037) | | | 64,130 | |
Net change in cash and cash equivalents | 4,114 | | | 1,459 | |
Balance, beginning of period | 20,236 | | | 13,341 | |
Balance, end of period | $24,350 | | | $14,800 | |
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The accompanying notes are an integral part of these consolidated financial statements.
Index to the Notes to the Consolidated Financial Statements
| | | | | | | | | | | |
| | 8. | |
2. | | 9. | Share-based Compensation |
3. | Property and Equipment, Net | 10. | Stockholders’ Equity |
4. | | 11. | Accounts Receivable, Net |
5. | | 12. | Accounts Payable and Accrued Liabilities |
6. | | 13. | Supplemental Cash Flow |
7. | | 14. | Subsequent Events |
| | | | | | | | | | | |
| | 9. | |
2. | | 10. | Share-Based Compensation |
3. | Acquisitions and Divestitures | 11. | Stockholders’ Equity |
4. | Property and Equipment, Net | 12. | Accounts Receivable, Net |
5. | | 13. | Accounts Payable and Accrued Liabilities |
6. | | 14. | Supplemental Cash Flow |
7. | | 15. | Subsequent Events |
8. | | | |
Note 1 - Description of Business and Basis of Presentation
Description of Business
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. As used herein, the “Company,” “Callon,” “we,” “us,” and “our” refer to Callon Petroleum Company and its predecessors and subsidiaries unless the context requires otherwise.
The Company’s activities are primarily focused on horizontal development in the Midland and Delaware Basins, both of which are part of the larger Permian Basin in West Texas, as well as the Eagle Ford.Ford in South Texas. The Company’s primary operations in the Permian reflect a high-return, oil-weighted drilling inventory with multiple prospective horizontal development intervals and are complemented by a well-established and repeatable cash flow generatingflow-generating business in the Eagle Ford.
Basis of Presentation
The accompanying unaudited interim consolidated financial statements include the accounts of the Company after elimination of intercompany transactions and balances andbalances. These financial statements have been prepared pursuant to the rules and regulations of the SEC and therefore do not include all disclosures required for financial statements prepared in conformity with U.S. GAAP. In the opinion of management, these financial statements includereflect all adjustments (consisting of normal, recurring adjustments and accruals and adjustments)considered necessary to present fairly, in all material respects, the Company’s interim financial position, results of operations and cash flows. However, the results of operations for the periods presented are not necessarily indicative of the results of operations that may be expected for the full year. Certain reclassifications have been made to prior period amounts to conform to the current period presentation. Such reclassifications did not have a material impact on prior period financial statements.
Significant Accounting Policies
The Company’s significant accounting policies are described in “Note 2.2 - Summary of Significant Accounting Policies” of the Notes to Consolidated Financial Statements in its Annual Report on Form 10-K for the year ended December 31, 20202021 (“20202021 Annual Report”) and are supplemented by the notes included in this Quarterly Report on Form 10-Q. The financial statements and related notes included in this report should be read in conjunction with the Company’s 20202021 Annual Report.
Recently Adopted Accounting Standards
Income Taxes.Debt. In December 2019,August 2020, the FASB releasedissued ASU No. 2019-122020-06, Debt - Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging - Contracts in Entity’s Own Equity (Subtopic 815-40) (“ASU 2019-12”2020-06”), Income Taxes (Topic 740) – Simplifying the Accounting for Income Taxes, which removes certain exceptions for recognizing deferred taxes for investments, performing intraperiod allocation and calculating income taxes in interim periods. The. ASU also adds guidance2020-06 was issued to reduce the complexity inassociated with accounting for certain areas, including recognizing deferred taxes for tax goodwillfinancial instruments with characteristics of liabilities and allocating taxesequity. The guidance is to members ofbe applied using either a consolidated group. The amended standardmodified retrospective or a fully retrospective method. ASU 2020-06 is effective for fiscal years beginning after December 15, 2020,2021, with early adoption permitted. The Company adopted ASU 2019-122020-06 on January 1, 2021.2022. The adoption of ASU 2019-122020-06 did not have a material impact to the Company’s consolidated financial statements or disclosures.
Recently Issued Accounting PronouncementsStandards
In March 2020, the FASB issued ASU No. 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting (“ASU 2020-04”) followed by ASU No. 2021-01, Reference Rate Reform (Topic 848): Scope (“ASU 2021-01”), issued in January 2021 to provide clarifying guidance regarding the scope of Topic 848. ASU 2020-04 was issued to provide optional guidance for a limited period of time to ease the potential burden in accounting for (or recognizing the effects of) reference rate reform on financial reporting. Generally, the guidance is to be applied as of any date from the beginning of an interim period that includes or is subsequent to March 12, 2020, or prospectively from a date within an interim period that includes or is subsequent to March 12, 2020, up to the date that the financial statements are available to be issued. ASU 2020-04 and ASU 2021-01 are effective for all entities through December 31, 2022. In April 2022, the FASB proposed to defer the effective date from December 31, 2022 to December 31, 2024, however a final ruling has not been issued. As of March 31, 2021,2022, the Company has not elected to use the optional guidance and continues to evaluate the options provided by ASU 2020-04 and ASU 2021-01. Please refer to “Note 56 –
Borrowings” for discussion of the use of the adjusted LIBO rate in connection with borrowings under the Company’s senior secured revolving credit facility.
In August 2020, the FASB issued ASU No. 2020-06, Debt - Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging - Contracts in Entity’s Own Equity (Subtopic 815-40) (“ASU 2020-06”). ASU 2020-06 was issued to reduce the complexity associated with accounting for certain financial instruments with characteristics of liabilities and equity. The guidance is to be applied using either a modified retrospective or a fully retrospective method. ASU 2020-06 is effective for fiscal years beginning after December 15, 2021, with early adoption permitted. As of March 31, 2021, the Company has not elected to early adopt and is evaluating the impact on the Company’s accompanying consolidated financial statements and related disclosures.
Subsequent Events
The Company evaluates subsequent events through the date the financial statements are issued. See “Note 1415 - Subsequent Events” for further discussion.
Note 2 - Revenue Recognition
Revenue from contractsContracts with customersCustomers
Oil sales
Under the Company’sThe Company recognizes oil, sales contracts it sells oilnatural gas, and NGL production revenue at the point of delivery and collects an agreed upon index price, net of pricing differentials. The Company recognizes revenuein time when control of the product transfers to the purchaser, atwhich differs depending on the pointapplicable contractual terms. Transfer of delivery atcontrol also drives the net price received. The Company has certain oil sales that occur at market locations downstreampresentation of the production area. Given the structure of these arrangements and where control transfers, the Company separately recognizes fees and other deductions incurred prior to control transfer as “Gathering,gathering, transportation and processing”processing in itsthe consolidated statements of operations.
Natural See “Note 3 - Revenue Recognition” of the Notes to Consolidated Financial Statements in the 2021 Annual Report for more information regarding the types of contracts under which oil, natural gas, and NGL sales
Under the Company’s natural gas sales processing contracts, it delivers natural gas to a midstream processing entity which gathers and processes the natural gas and remits proceeds to the Company for the resulting sale of NGLs and residue gas. The Company evaluates whether the processing entityproduction revenue is the principal or the agent in the transaction for each of the Company’s natural gas processing agreements and have concluded that the Company maintains control through processing or the Company has the right to take residue gas and/or NGLs in-kind at the tailgate of the midstream entity’s processing plant and subsequently market the product. The Company recognizes revenue when control transfers to the purchaser at the delivery point based on the contractual index price received.
The Company recognizes revenue for natural gas and NGLs on a gross basis with gathering, transportation and processing fees recognized separately as “Gathering, transportation and processing” in its consolidated statements of operations as the Company maintains control throughout processing.
Oil and gas purchase and sale arrangements
Sales of purchased oil and gas represent revenues the Company receives from sales of commodities purchased from a third-party. The Company recognizes these revenues and the purchase of the third-party commodities, as well as any costs associated with the purchase, on a gross basis, as the Company acts as a principal in these transactions by assuming control of the purchased commodity before it is transferred to the customer.generated.
Accounts receivableReceivable from revenuesRevenues from contractsContracts with customersCustomers
Net accounts receivable include amounts billed and currently due from revenues from contracts with customers of our oil and natural gas production, which had a balance at March 31, 20212022 and December 31, 20202021 of $125.6$262.4 million and $100.3$171.8 million, respectively, and are presented in “Accounts receivable, net” in the consolidated balance sheets.
Transaction price allocated to remaining performance obligations
For the Company’s product sales that have a contract term greater than one year, it has utilized the practical expedient in Accounting Standards Codification 606-10-50-14, which states the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate performance obligation, therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.
Prior period performance obligationsPeriod Performance Obligations
The Company records revenue in the month production is delivered to the purchaser. However, settlement statements for sales may not be received for 30 to 90 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The Company records the differences between estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. The Company has existing internal controls for its revenue estimation process and related accruals, and any identified differences between its revenue estimates and actual revenue received historically have not been significant.
Note 3 - Acquisitions and Divestitures
2021 Acquisitions and Divestitures
Primexx Acquisition
On October 1, 2021, the Company closed on the acquisition of certain producing oil and gas properties, undeveloped acreage and associated infrastructure assets in the Delaware Basin from Primexx Resource Development, LLC (“Primexx”) and BPP Acquisition, LLC (“BPP”) for an adjusted purchase price of approximately $444.8 million in cash, inclusive of the deposit paid at signing, 8.84 million shares of the Company’s common stock and approximately $25.2 million paid upon final closing for total consideration of $880.8 million (the “Primexx Acquisition”), subject to potential adjustments for applicable indemnification claims as discussed below. The Company funded the cash portion of the total consideration with borrowings under its Credit Facility, as defined below. Of the 8.84 million shares of the Company’s common stock issued upon closing, 2.6 million shares were held in escrow pursuant to the purchase and sale agreements with Primexx and BPP (collectively, the “Primexx PSAs”). Pursuant to the Primexx PSAs, 50% of the shares held in escrow were released six months after the closing date, which was on April 1, 2022, and the remaining shares will be released twelve months after the closing date, which will be on October 1, 2022, in each case subject to holdback for the satisfaction of any applicable indemnification claims that may be made under the Primexx PSAs.
Also, pursuant to the Primexx PSAs, certain interest owners exercised their option to sell their interest in the properties included in the Primexx Acquisition to the Company for consideration structured similarly to the Primexx Acquisition, for an incremental purchase price totaling approximately $33.1 million, net of customary purchase price adjustments, of which $10.7 million closed during the first quarter of 2022.
The Primexx Acquisition was accounted for as a business combination; therefore, the purchase price was allocated to the assets acquired and the liabilities assumed based on their estimated acquisition date fair values with information available at that time. A combination of a discounted cash flow model and market data was used by a third-party specialist in determining the fair value of the oil and gas properties. Significant inputs into the calculation included future commodity prices, estimated volumes of oil and gas reserves, expectations for timing and amount of future development and operating costs, future plugging and abandonment costs and a
risk adjusted discount rate. Certain data necessary to complete the purchase price allocation is not yet available. The Company expects to complete the purchase price allocation during the 12-month period following the acquisition date.
The following table sets forth the Company’s preliminary allocation of the total estimated consideration of $914.0 million to the assets acquired and liabilities assumed as of the acquisition date.
| | | | | | | | |
| | Preliminary Purchase Price Allocation |
| | (In thousands) |
Assets: | | |
Other current assets | | $10,250 | |
Evaluated oil and natural gas properties | | 686,393 | |
Unevaluated properties | | 278,602 | |
Total assets acquired | | $975,245 | |
| | |
Liabilities: | | |
Suspense payable | | $16,447 | |
Other current liabilities | | 33,482 | |
Asset retirement obligation | | 1,898 | |
Other long-term liabilities | | 9,425 | |
Total liabilities assumed | | $61,252 | |
| | |
Total consideration | | $913,993 | |
Approximately $138.1 million of revenues and $28.8 million of direct operating expenses attributed to the Primexx Acquisition are included in the Company’s consolidated statements of operations for the three months ended March 31, 2022.
Pro Forma Operating Results (Unaudited). The following unaudited pro forma combined condensed financial data for the year ended December 31, 2021 was derived from the historical financial statements of the Company giving effect to the Primexx Acquisition, as if it had occurred on January 1, 2020. The below information reflects pro forma adjustments for the issuance of the Company’s common stock and the borrowings under the Credit Facility as total consideration, as well as pro forma adjustments based on available information and certain assumptions that the Company believes provide a reasonable basis for reflecting the significant pro forma effects directly attributable to the Primexx Acquisition.
The pro forma consolidated statements of operations data has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the Primexx Acquisition taken place on January 1, 2020 and is not intended to be a projection of future results.
| | | | | | | | | | |
| | For the Year Ended |
| | December 31, 2021 | | |
| | (In thousands) |
Revenues | | $2,294,893 | | | |
Income from operations | | 1,151,493 | | | |
Net income | | 482,690 | | | |
Basic earnings per common share | | $8.37 | | | |
Diluted earnings per common share | | $8.13 | | | |
Non-Core Asset Divestitures
During 2021, we completed divestitures of certain non-core assets in the Delaware Basin, Midland Basin, and Eagle Ford Shale as well as the divestiture of certain non-core water infrastructure for total net proceeds of $181.8 million, subject to post-closing adjustments. The aggregate net proceeds for each of the 2021 divestitures were recognized as a reduction of evaluated oil and gas properties with no gain or loss recognized as the divestitures did not significantly alter the relationship between capitalized costs and estimated proved reserves. For additional discussion, see “Note 4 - Acquisitions and Divestitures” of the Notes to Consolidated Financial Statements in the 2021 Annual Report.
Note 34 - Property and Equipment, Net
As of March 31, 20212022 and December 31, 2020,2021, total property and equipment, net consisted of the following:
| | | March 31, 2021 | | December 31, 2020 | | March 31, 2022 | | December 31, 2021 |
Oil and natural gas properties, full cost accounting method | Oil and natural gas properties, full cost accounting method | | (In thousands) | Oil and natural gas properties, full cost accounting method | | (In thousands) |
Evaluated properties | Evaluated properties | | $8,001,847 | | | $7,894,513 | | Evaluated properties | | $9,412,921 | | | $9,238,823 | |
Accumulated depreciation, depletion, amortization and impairments | Accumulated depreciation, depletion, amortization and impairments | | (5,607,508) | | | (5,538,803) | | Accumulated depreciation, depletion, amortization and impairments | | (5,986,765) | | | (5,886,002) | |
Evaluated properties, net | Evaluated properties, net | | 2,394,339 | | | 2,355,710 | | Evaluated properties, net | | 3,426,156 | | | 3,352,821 | |
Unevaluated properties | Unevaluated properties | | Unevaluated properties | |
Unevaluated leasehold and seismic costs | Unevaluated leasehold and seismic costs | | 1,530,897 | | | 1,532,304 | | Unevaluated leasehold and seismic costs | | 1,567,076 | | | 1,557,453 | |
Capitalized interest | Capitalized interest | | 223,871 | | | 200,946 | | Capitalized interest | | 280,714 | | | 255,374 | |
Total unevaluated properties | Total unevaluated properties | | 1,754,768 | | | 1,733,250 | | Total unevaluated properties | | 1,847,790 | | | 1,812,827 | |
Total oil and natural gas properties, net | Total oil and natural gas properties, net | | $4,149,107 | | | $4,088,960 | | Total oil and natural gas properties, net | | $5,273,946 | | | $5,165,648 | |
| Other property and equipment | Other property and equipment | | $60,388 | | | $60,287 | | Other property and equipment | | $59,428 | | | $58,367 | |
Accumulated depreciation | Accumulated depreciation | | (28,953) | | | (28,647) | | Accumulated depreciation | | (30,443) | | | (30,239) | |
Other property and equipment, net | Other property and equipment, net | | $31,435 | | | $31,640 | | Other property and equipment, net | | $28,985 | | | $28,128 | |
The Company capitalized internal costs of employee compensation and benefits, including share-based compensation, directly associated with acquisition, exploration and development activities totaling $11.2$11.6 million and $7.5$11.2 million for the three months ended March 31, 2022 and 2021, and 2020, respectively.
The Company capitalized interest costs to unproved properties totaling $25.5 million and $24.0 million for both the three months ended March 31, 2021 and 2020.
Impairment of Evaluated Oil and Gas Properties
For the three months ended March 31, 2021, the capitalized costs of oil and gas properties did not exceed the cost center ceiling. As a result, the Company did not recognize an impairment in the carrying value of evaluated oil and gas properties for the three months ended March 31, 2021. The Company also did 0t recognize an impairment of evaluated oil2022 and gas properties for the three months ended March 31, 2020.2021, respectively.
Details of the average realized prices for sales of oil on the first calendar day of each month during the trailing 12-month period (“12-Month Average Realized Price”) of crude oil for the three months ended March 31, 2021 and 2020 are summarized in the table below:
| | | | | | | | | | | | | | | | | | |
| | Three Months Ended March 31, | | |
| | 2021 | | 2020 | | | | |
Impairment of evaluated oil and gas properties (in thousands) | | $0 | | $0 | | | | |
Beginning of period 12-Month Average Realized Price ($/Bbl) | | $37.44 | | $53.90 | | | | |
End of period 12-Month Average Realized Price ($/Bbl) | | $37.51 | | $54.63 | | | | |
Percent increase in 12-Month Average Realized Price | | 0 | % | | 1 | % | | | | |
The Company does not expect to record an impairment in the carrying value of evaluated oil and gas properties in the second quarter of 2021 based on an estimated 12-Month Average Realized Price of crude oil of approximately $49.35 per Bbl as of June 30, 2021, which is based on the average realized price for sales of crude oil on the first calendar day of each month for the first 10 months and an estimate for the eleventh and twelfth months based on a quoted forward price. Declines in the 12-Month Average Realized Price of crude oil in subsequent quarters could result in a lower present value of the estimated future net revenues from proved oil and gas reserves and may result in impairments of evaluated oil and gas properties.
Note 45 - Earnings Per Share
Basic earnings (loss) per share is computed by dividing net income (loss) by the weighted average number of shares outstanding for the periods presented. The calculation of diluted earnings per share includes the potential dilutive impact of non-vested restricted sharesstock units and unexercised warrants outstanding during the periods presented, as calculated using the treasury stock method, unless their effect is anti-dilutive. For the three months ended March 31, 2021, the Company reported a net loss. As a result, the calculation of diluted weighted average common shares outstanding excluded all potentially dilutive common shares outstanding.
The following table sets forth the computation of basic and diluted earnings per share:
| | | | | | | | | | | | | | | |
| Three Months Ended March 31, | | |
| 2021 | | 2020 | | | | |
| (In thousands, except per share amounts) |
| | | | | | | |
| | | | | | | |
| | | | | | | |
Net Income (Loss) | ($80,407) | | | $216,565 | | | | | |
Basic weighted average common shares outstanding (1) | 42,590 | | | 39,667 | | | | | |
Dilutive impact of restricted stock (1) | 0 | | | 17 | | | | | |
Dilutive impact of warrants (1) | 0 | | | 0 | | | | | |
Diluted weighted average common shares outstanding (1) | 42,590 | | | 39,684 | | | | | |
| | | | | | | |
Net Income (Loss) Per Common Share (1) | | | | | | | |
Basic | ($1.89) | | | $5.46 | | | | | |
Diluted | ($1.89) | | | $5.46 | | | | | |
| | | | | | | |
Restricted stock (1)(2) | 702 | | | 337 | | | | | |
Warrants (1)(2) | 5,826 | | | 481 | | | | | |
| | | | | | | | | | | | | | | |
| Three Months Ended March 31, | | |
| 2022 | | 2021 | | | | |
| (In thousands, except per share amounts) | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
Net Income (Loss) | $39,737 | | | ($80,407) | | | | | |
Basic weighted average common shares outstanding | 61,487 | | | 42,590 | | | | | |
Dilutive impact of restricted stock units | 578 | | | — | | | | | |
| | | | | | | |
Diluted weighted average common shares outstanding | 62,065 | | | 42,590 | | | | | |
| | | | | | | |
Net Income (Loss) Per Common Share | | | | | | | |
Basic | $0.65 | | | ($1.89) | | | | | |
Diluted | $0.64 | | | ($1.89) | | | | | |
| | | | | | | |
Restricted stock units (1) | 3 | | | 702 | | | | | |
Warrants (1) | 327 | | | 5,826 | | | | | |
(1) Shares and per share data have been retroactively adjusted to reflect the Company’s 1-for-10 reverse stock split effective August 7, 2020. See “Note 10 - Stockholders’ Equity” for additional information.
(2) Shares excluded from the diluted earnings per share calculation because their effect would be anti-dilutive.
Note 56 - Borrowings
The Company’s borrowings consisted of the following:
| | | | | | | | | | | | | | |
| | March 31, 2021 | | December 31, 2020 |
| | (In thousands) |
Senior Secured Revolving Credit Facility due 2024 | | $950,000 | | | $985,000 | |
9.00% Second Lien Senior Secured Notes due 2025 | | 516,659 | | | 516,659 | |
6.25% Senior Notes due 2023 | | 542,720 | | | 542,720 | |
6.125% Senior Notes due 2024 | | 460,241 | | | 460,241 | |
8.25% Senior Notes due 2025 | | 187,238 | | | 187,238 | |
6.375% Senior Notes due 2026 | | 320,783 | | | 320,783 | |
Total principal outstanding | | 2,977,641 | | | 3,012,641 | |
Unamortized discount on Second Lien Notes | | (39,006) | | | (41,820) | |
Unamortized premium on 6.25% Senior Notes | | 2,688 | | | 2,917 | |
Unamortized premium on 6.125% Senior Notes | | 3,020 | | | 3,236 | |
Unamortized premium on 8.25% Senior Notes | | 3,050 | | | 3,240 | |
Unamortized deferred financing costs for Second Lien Notes | | (3,662) | | | (3,931) | |
Unamortized deferred financing costs for Senior Notes | | (6,492) | | | (7,019) | |
Total carrying value of borrowings (1) | | $2,937,239 | | | $2,969,264 | |
| | | | | | | | | | | | | | |
| | March 31, 2022 | | December 31, 2021 |
| | (In thousands) |
6.125% Senior Notes due 2024 | | $460,241 | | | $460,241 | |
Senior Secured Revolving Credit Facility due 2024 | | 712,000 | | | 785,000 | |
9.00% Second Lien Senior Secured Notes due 2025 | | 319,659 | | | 319,659 | |
8.25% Senior Notes due 2025 | | 187,238 | | | 187,238 | |
6.375% Senior Notes due 2026 | | 320,783 | | | 320,783 | |
8.00% Senior Notes due 2028 | | 650,000 | | | 650,000 | |
Total principal outstanding | | 2,649,921 | | | 2,722,921 | |
Unamortized premium on 6.125% Senior Notes | | 2,157 | | | 2,373 | |
Unamortized discount on 9.00% Second Lien Senior Secured Notes | | (13,591) | | | (14,852) | |
Unamortized premium on 8.25% Senior Notes | | 2,287 | | | 2,477 | |
Unamortized deferred financing costs for Second Lien Notes | | (2,663) | | | (2,910) | |
Unamortized deferred financing costs for Senior Notes | | (14,829) | | | (15,894) | |
Total carrying value of borrowings (1) | | $2,623,282 | | | $2,694,115 | |
(1) Excludes unamortized deferred financing costs related to the Company’s senior secured revolving credit facility of $22.2$16.5 million and $23.6$18.1 million as of March 31, 20212022 and December 31, 2020,2021, respectively, which are classified in “Deferred financing costs” in the consolidated balance sheets.
Senior secured revolving credit facilitySecured Revolving Credit Facility
The Company has a senior secured revolving credit facility with a syndicate of lenders (the “Credit Facility”) that, as of March 31, 2021,2022, had a maximum credit amount of $5.0 billion, a borrowing base and elected commitment amount of $1.6 billion, with borrowings outstanding of $950.0$712.0 million at a
weighted-average interest rate of 2.62%2.74%, and letters of credit outstanding of $24.0$23.0 million. The credit agreement governing the Credit Facility provides for interest-only payments until December 20, 2024 (subjectwhen the credit agreement matures and any outstanding borrowings are due. The Credit Facility is subject to specified springing maturity dates of (i) January 14, 2023 if the 6.25% Senior Notes due 2023 (the “6.25% Senior Notes”) are outstanding at such time, (ii) July 2, 2024 if the 6.125% Senior Notes due 2024 (the “6.125% Senior Notes”) are outstanding at such time, and (iii) ifmore than $100.0 million principal amount of the 9.00% Second Lien Senior Secured Notes due 2025 (the “Second Lien Notes”) are outstanding at such time, the date which is 182 days prior to the maturity of any of the 6.25% Senior Notes or theand 6.125% Senior Notes in each case, toare outstanding. The Credit Facility is secured by first preferred mortgages covering the extent a principal amount of more than $100.0 million with respect to each such issuance is outstanding as of such date), when the credit agreement matures and any outstanding borrowings are due. Company’s major producing properties.
The borrowing base under the credit agreement is subject to regular redeterminations in the spring and fall of each year, as well as special redeterminations described in the credit agreement, which in each case may reduce the amount of the borrowing base. The Credit Facility is secured by first preferred mortgages coveringOn May 2, 2022, as part of the Company’s major producing properties. The capitalized terms which are not defined in this description of the Credit Facility shall have the meaning given to such terms in the credit agreement.
On May 3, 2021, the Company entered into the fourth amendment to its credit agreement governing the Credit Facility which, among other things, reaffirmedspring 2022 redetermination, the borrowing base and elected commitment amount of $1.6 billion as a result of the spring 2021 scheduled redetermination. See “Note 14 - Subsequent Events” for further discussion.were reaffirmed.
Borrowings outstanding under the credit agreement bear interest at the Company’s option at either (i) a base rate for a base rate loan plus a margin between 1.00% to 2.00%, where the base rate is defined as the greatest of the prime rate, the federal funds rate plus 0.50% and the adjusted LIBO rate plus 1.00%, or (ii) an adjusted LIBO rate for a Eurodollar loan plus a margin between 2.00% to 3.00%. The Company also incurs commitment fees at rates ranging between 0.375% to 0.500% on the unused portion of lender commitments, which are included in “Interest expense, net of capitalized amounts” in the consolidated statements of operations.
Restrictive covenantsCovenants
The Company’s credit agreement contains certain covenants including restrictions on additional indebtedness, payment of cash dividends and maintenance of certain financial ratios.
Under the credit agreement, the Company must maintain the following financial covenants determined as of the last day of the quarter: (1) a Secured Leverage Ratio of no more than 3.00 to 1.00 and (2) a Current Ratio of not less than 1.00 to 1.00. The Company was in compliance with these covenants at March 31, 2021.
The credit agreement and the indentures governing the Company’s 6.25% Senior Notes,Credit Facility, the 6.125% Senior Notes, the 8.25% Senior Notes, due 2025, andthe 6.375% Senior Notes due 2026 (togetherand the 8.00% Senior Notes (collectively, the “Senior Unsecured Notes”) also place restrictions onand the Second Lien Notes limit the Company and certain of its subsidiaries with respect to the amount of additional indebtedness, liens, dividends and other payments to shareholders, repurchases or redemptions of the Company’s common stock, redemptions of senior notes, investments, acquisitions, mergers, asset dispositions, transactions with affiliates, hedging transactions and other matters.matters, along with maintenance of certain financial ratios.
Under the credit agreement, the Company must maintain the following financial covenants determined as of the last day of the quarter: (1) a Leverage Ratio (as defined in the credit agreement governing the Credit Facility) of no more than 4.00 to 1.00 and (2) a Current Ratio (as defined in the credit agreement governing the Credit Facility) of not less than 1.00 to 1.00. The Company was in compliance with these covenants at March 31, 2022.
The credit agreement and indentures are subject to customary events of default. If an event of default occurs and is continuing, the holders or lenders may elect to accelerate amounts due (except in the case of a bankruptcy event of default, in which case such amounts will automatically become due and payable).
Note 67 - Derivative Instruments and Hedging Activities
Objectives and strategiesStrategies for using derivative instrumentsUsing Derivative Instruments
The Company is exposed to fluctuations in oil, natural gas and NGL prices received for its production. Consequently, the Company believes it is prudent to manage the variability in cash flows on a portion of its oil, natural gas and NGL production. The Company utilizes a mix of collars, swaps, and put and call options to manage fluctuations in cash flows resulting from changes in commodity prices. The Company does not use these instruments for speculative or trading purposes.
Counterparty riskRisk and offsettingOffsetting
The Company typically has numerous commodity derivative instruments outstanding with a counterparty that were executed at various dates, for various contract types, commodities and time periods. This often results in both commodity derivative asset and liability positions with that counterparty. The Company nets its commodity derivative instrument fair values executed with the same counterparty to a single asset or liability pursuant to International Swap Dealers Association Master Agreements (“ISDA Agreements”), which provide for net settlement over the term of the contract and in the event of default or termination of the contract. In general, if a party to a derivative transaction incurs an event of default, as defined in the applicable agreement, the other party will have the right to demand the posting of collateral, demand a cash payment transfer or terminate the arrangement.
As of March 31, 2021,2022, the Company has outstanding commodity derivative instruments with 1510 counterparties to minimize its credit exposure to any individual counterparty. All of the counterparties to the Company’s commodity derivative instruments are also lenders under the Company’s credit agreement. Therefore, each of the Company’s counterparties allow the Company to satisfy any
need for margin obligations associated with commodity derivative instruments where the Company is in a net liability position with the collateral securing the credit agreement, thus eliminating the need for independent collateral posting.
Because each of the Company’s counterparties has an investment grade credit rating, the Company believes it does not have significant credit risk and accordingly does not currently require its counterparties to post collateral to support the net asset positions of its commodity derivative instruments. Although the Company does not currently anticipate nonperformance from its counterparties, it continually monitors the credit ratings of each counterparty.
While the Company monitors counterparty creditworthiness on an ongoing basis, it cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, the Company may be limited in its ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, the Company may not realize the benefit of some of its derivative instruments under lower commodity prices while continuing to be obligated under higher commodity price contracts subject to any right of offset under the agreements. Counterparty credit risk is considered when determining the fair value of a derivative instrument. See “Note 78 - Fair Value Measurements” for further discussion.
Financial statement presentationContingent Consideration Arrangements
The Company met certain oil pricing thresholds for 2021 associated with certain contingent consideration arrangements described in “Note 8 - Derivative Instruments and settlements
SettlementsHedging Activities” of the Company’s commodity derivative instruments are based on the difference between the contract priceNotes to Consolidated Financial Statements in its 2021 Annual Report. Cash received or prices specified in the derivative instrument and a benchmark price, such as the NYMEX price. To determine the fair value of the Company’s derivative instruments, the Company utilizes present value methods that include assumptions about commodity prices based on those observed in underlying markets. See “Note 7 - Fair Value Measurements” for additional information regarding fair value.
Contingent consideration arrangements
Ranger Divestiture. In the second quarter of 2019, the Company completed its divestiture of certain non-core assets in the southern Midland Basin (the “Ranger Divestiture”). The Company’s Ranger Divestiture provided for potential contingent consideration to be received by the Company if commodity prices exceed specified thresholds. See “Note 7 - Fair Value Measurements” for further discussion. This contingent consideration arrangement is summarized in the table below (in thousands except for per Bbl amounts):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Year | | Threshold (1) | | Contingent Receipt - Annual | | Threshold (1) | | Contingent Receipt - Annual | | Period Cash Flow Occurs | | Statement of Cash Flows Presentation | | Remaining Contingent Receipt - Aggregate Limit |
Remaining Potential Settlement | | 2021 | | Greater than $60/Bbl, less than $65/Bbl | | $9,000 | | Equal to or greater than $65/Bbl | | $20,833 | | (2) | | (2) | | $20,833 | |
(1) The price used to determine whether the specified thresholds have been met is the average of the final monthly settlements for each month during each annual period end for NYMEX Light Sweet Crude Oil Futures, as reported by the CME Group.
(2) Cash receivedpaid for settlements of contingent consideration arrangements are classified as cash flows from financing activities or cash flows from investing activities, respectively, up to the divestiture or acquisition date fair value, respectively, with any excess classified as cash flows from operating activities. If eitherAs a result, the Company received $20.8 million, of the commodity price thresholds is reached in 2021,which $8.5 million of the contingent receipt will beis presented in cash flows from financing activities with the remainderremaining $12.3 million presented in cash flows from operating activities.
As a resultactivities, and paid $25.0 million, of the acquisition of Carrizo Oil & Gas, Inc. (“Carrizo”) in late 2019 (the “Carrizo Acquisition”), the Company assumed all contingent consideration arrangements previously entered into by Carrizo. Only one of the contingent consideration arrangements remain and is summarized below:
Contingent ExL Consideration
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Year | | Threshold (1) | | Period Cash Flow Occurs | | Statement of Cash Flows Presentation | | Contingent Payment - Annual | | Remaining Contingent Payments - Aggregate Limit |
| | | | | | | | | | (In thousands) |
Remaining Potential Settlement | | 2021 | | $50.00 | | | (2) | | (2) | | ($25,000) | | | ($25,000) | |
(1) The price used to determine whether the specified threshold for the year has been met is the average daily settlement price of the front month NYMEX WTI futures contract as published by the CME Group.
(2) Cash paid for settlements of contingent consideration arrangements are classified as cash flows from investing activities up to the acquisition date fair value with any excess classified as cash flows from operating activities. If the commodity price threshold is reached in 2021,which $19.2 million of the contingent payment will beis presented in cash flows from investing activities with the remainderremaining $5.8 million presented in cash flows from operating activities.
Warrants
On September 30, 2020,activities, in the Company issued $300.0 million in aggregate principal amountfirst quarter of its Second Lien Notes and warrants for 7.3 million shares2022. Both of these contingent consideration arrangements expired at the Company’s common stock exercisable only on a net share settlement basis (the “September 2020 Warrants”).end of 2021.
The Company determined that the September 2020 Warrants are required to be accounted for as a derivative instrument. The Company recorded the September 2020 Warrants as a liability on its consolidated balance sheet measured at fair value as a component of “Fair value of derivatives” with gainsFinancial Statement Presentation and losses as a result of changes in the fair value of the September 2020 Warrants recorded as “(Gain) loss on derivative contracts” in the consolidated statements of operations in the period in which the changes occur. See “Note 7 - Fair Value Measurements” for additional details.
In February 2021, holders of the September 2020 Warrants provided notice and exercised all of their outstanding warrants. As a result of this exercise, the Company issued 5.6 million shares of its common stock in exchange for all of the outstanding September 2020 Warrants. The exercise of the September 2020 Warrants resulted in settlement of the associated derivative liability, which was $134.8 million at the time of exercise, and the fair value of the September 2020 Warrants at exercise, less the par value of the shares of common stock issued in the exercise, was reclassified to “Capital in excess of par value” in the consolidated balance sheets.
Derivatives not designated as hedging instrumentsSettlements
The Company records its derivative instruments at fair value in the consolidated balance sheets and records changes in fair value as “(Gain) loss on derivative contracts” in the consolidated statements of operations. Settlements are also recorded as a gain or“(Gain) loss on derivative contractscontracts” in the consolidated statements of operations. As previously discussed, the Company’s commodity derivative contracts are subject to master netting arrangements. The Company’s policy is to presentCompany presents the fair value of derivative contracts on a net basis in the consolidated balance sheets.sheets as they are subject to master netting arrangements. The following presents the impact of this presentation to the Company’s recognized assets and liabilities for the periods indicated:
| | | | | | | | | | | | | | | | | |
| As of March 31, 2021 |
| Presented without | | | | As Presented with |
| Effects of Netting | | Effects of Netting | | Effects of Netting |
| (In thousands) |
Assets | | | | | |
Commodity derivative instruments | $69,473 | | | ($69,352) | | | $121 | |
Contingent consideration arrangements | 5,375 | | | 0 | | | 5,375 | |
Other current assets | $74,848 | | | ($69,352) | | | $5,496 | |
Commodity derivative instruments | 3,790 | | | (3,351) | | | 439 | |
Contingent consideration arrangements | 0 | | | 0 | | | 0 | |
Other assets, net | $3,790 | | | ($3,351) | | | $439 | |
| | | | | |
Liabilities | | | | | |
Commodity derivative instruments (1) | ($275,885) | | | $69,352 | | | ($206,533) | |
Contingent consideration arrangements | (17,913) | | | 0 | | | (17,913) | |
Fair value of derivatives - current | ($293,798) | | | $69,352 | | | ($224,446) | |
Commodity derivative instruments (2) | (4,751) | | | 3,351 | | | (1,400) | |
Contingent consideration arrangements | 0 | | | 0 | | | 0 | |
Fair value of derivatives - non-current | ($4,751) | | | $3,351 | | | ($1,400) | |
| | | | | | | | | | | | | | | | | |
| As of March 31, 2022 |
| Presented without | | | | As Presented with |
| Effects of Netting | | Effects of Netting | | Effects of Netting |
| (In thousands) |
Derivative Assets | | | | | |
Fair value of derivatives - current | $10,939 | | | ($10,939) | | | $— | |
Other assets, net | $15,773 | | | ($15,773) | | | $— | |
| | | | | |
Derivative Liabilities | | | | | |
Fair value of derivatives - current (1) | ($403,867) | | | $10,939 | | | ($392,928) | |
Fair value of derivatives - non-current | ($50,207) | | | $15,773 | | | ($34,434) | |
(1) Includes approximately $14.1 million of deferred premiums, which the Company will pay as the applicable contracts settle.
(2) Includes approximately $0.9 million of deferred premiums, which the Company will paybe paid as the applicable contracts settle.
| | | | | | | | | | | | | | | | | |
| As of December 31, 2020 |
| Presented without | | | | As Presented with |
| Effects of Netting | | Effects of Netting | | Effects of Netting |
| (In thousands) |
Assets | | | | | |
Commodity derivative instruments | $21,156 | | | ($20,235) | | | $921 | |
Contingent consideration arrangements | 0 | | | 0 | | | 0 | |
Other current assets | $21,156 | | | ($20,235) | | | $921 | |
Commodity derivative instruments | $0 | | | $0 | | | $0 | |
Contingent consideration arrangements | 1,816 | | | 0 | | | 1,816 | |
Other assets, net | $1,816 | | | $0 | | | $1,816 | |
| | | | | |
Liabilities | | | | | |
Commodity derivative instruments (1) | ($117,295) | | | $20,235 | | | ($97,060) | |
Contingent consideration arrangements | 0 | | | 0 | | | 0 | |
Fair value of derivatives - current | ($117,295) | | | $20,235 | | | ($97,060) | |
Commodity derivative instruments | $0 | | | $0 | | | $0 | |
Contingent consideration arrangements | (8,618) | | | 0 | | | (8,618) | |
September 2020 Warrants liability | (79,428) | | | 0 | | | (79,428) | |
Fair value of derivatives - non-current | ($88,046) | | | $0 | | | ($88,046) | |
| | | | | | | | | | | | | | | | | |
| As of December 31, 2021 |
| Presented without | | | | As Presented with |
| Effects of Netting | | Effects of Netting | | Effects of Netting |
| (In thousands) |
Assets | | | | | |
Commodity derivative instruments | $25,469 | | | ($23,921) | | | $1,548 | |
Contingent consideration arrangements | 20,833 | | | — | | | 20,833 | |
Fair value of derivatives - current | $46,302 | | | ($23,921) | | | $22,381 | |
Commodity derivative instruments | $1,119 | | | ($869) | | | $250 | |
Contingent consideration arrangements | — | | | — | | | — | |
Other assets, net | $1,119 | | | ($869) | | | $250 | |
| | | | | |
Liabilities | | | | | |
Commodity derivative instruments (1) | ($184,898) | | | $23,921 | | | ($160,977) | |
Contingent consideration arrangements | (25,000) | | | — | | | (25,000) | |
Fair value of derivatives - current | ($209,898) | | | $23,921 | | | ($185,977) | |
Commodity derivative instruments | ($12,278) | | | $869 | | | ($11,409) | |
Contingent consideration arrangements | — | | | — | | | — | |
| | | | | |
Fair value of derivatives - non-current | ($12,278) | | | $869 | | | ($11,409) | |
(1) Includes approximately $11.2$2.9 million of deferred premiums, which the Company will paybe paid as the applicable contracts settle.
The components of “(Gain) loss“Loss on derivative contracts” are as follows for the respective periods: | | | | | | | | | | | | | | | |
| Three Months Ended March 31, | | |
| 2022 | | 2021 | | | | |
| (In thousands) |
Loss on oil derivatives | $325,348 | | | $149,561 | | | | | |
Loss on natural gas derivatives | 28,181 | | | 2,697 | | | | | |
Loss on NGL derivatives | 4,771 | | | 1,138 | | | | | |
Loss on contingent consideration arrangements | — | | | 5,737 | | | | | |
Loss on September 2020 Warrants liability (1) | — | | | 55,390 | | | | | |
Loss on derivative contracts | $358,300 | | | $214,523 | | | | | |
| | | | | | | | | | | | | | | |
| Three Months Ended March 31, | | |
| 2021 | | 2020 | | | | |
| (In thousands) |
(Gain) loss on oil derivatives | $149,561 | | | ($257,323) | | | | | |
(Gain) loss on natural gas derivatives | 2,697 | | | 6,829 | | | | | |
(Gain) loss on NGL derivatives | 1,138 | | | 0 | | | | | |
(Gain) loss on contingent consideration arrangements | 5,737 | | | (1,475) | | | | | |
(Gain) loss on September 2020 Warrants liability | 55,390 | | | 0 | | | | | |
(Gain) loss on derivative contracts | $214,523 | | | ($251,969) | | | | | |
(1) Further details of the Company’s September 2020 Warrants and the loss on the associated September 2020 Warrants liability are described in “Note 7 - Borrowings”, “Note 8 - Derivative Instruments and Hedging Activities” and “Note 9 - Fair Value Measurements” of the Notes to Consolidated Financial Statements in its 2021 Annual Report.
The components of “Cash received (paid)paid for commodity derivative settlements, net” and “Cash paidreceived (paid) for settlements of contingent consideration arrangements, net” are as follows for the respective periods:
| | | | | | | | | | | | | | | |
| Three Months Ended March 31, | | |
| 2021 | | 2020 | | | | |
| (In thousands) |
Cash flows from operating activities | | | | | | | |
Cash received (paid) on oil derivatives | ($39,947) | | | ($1,777) | | | | | |
Cash received (paid) on natural gas derivatives | (1,369) | | | 4,390 | | | | | |
Cash received (paid) on NGL derivatives | (846) | | | 0 | | | | | |
Cash received (paid) for commodity derivative settlements, net | ($42,162) | | | $2,613 | | | | | |
| | | | | | | |
Cash flows from investing activities | | | | | | | |
Cash paid for settlements of contingent consideration arrangements, net | $0 | | | ($40,000) | | | | | |
| | | | | | | | | | | | | | | |
| Three Months Ended March 31, | | |
| 2022 | | 2021 | | | | |
| (In thousands) |
Cash flows from operating activities | | | | | | | |
Cash paid on oil derivatives | ($95,353) | | | ($39,947) | | | | | |
Cash paid on natural gas derivatives | (4,644) | | | (1,369) | | | | | |
Cash paid on NGL derivatives | (1,528) | | | (846) | | | | | |
Cash paid for commodity derivative settlements, net | ($101,525) | | | ($42,162) | | | | | |
Cash received for settlements of contingent consideration arrangements, net | $6,492 | | | $— | | | | | |
| | | | | | | |
Cash flows from investing activities | | | | | | | |
Cash paid for settlement of contingent consideration arrangement | ($19,171) | | | $— | | | | | |
| | | | | | | |
Cash flows from financing activities | | | | | | | |
Cash received for settlement of contingent consideration arrangement | $8,512 | | | $— | | | | | |
Derivative positionsPositions
Listed in the tables below are the outstanding oil, natural gas and NGL derivative contracts as of March 31, 2021: 2022:
| | | | | | | | | | | | | | | | | | | | |
| For the Remainder | | | For the Full Year | | | | |
Oil contracts (WTI) | of 2021 | | | of 2022 | | | | |
Swap contracts | | | | | | | | |
Total volume (Bbls) | 1,832,000 | | | | 0 | | | | | |
Weighted average price per Bbl | $43.24 | | | | $0 | | | | | |
Collar contracts | | | | | | | | |
Total volume (Bbls) | 8,298,800 | | | | 1,807,500 | | | | | |
Weighted average price per Bbl | | | | | | | | |
Ceiling (short call) | $48.30 | | | | $60.63 | | | | | |
Floor (long put) | $40.24 | | | | $46.25 | | | | | |
Short call contracts | | | | | | | | |
Total volume (Bbls) | 2,432,480 | | (1) | | 0 | | | | | |
Weighted average price per Bbl | $63.62 | | | | $0 | | | | | |
Short call swaption contracts | | | | | | | | |
Total volume (Bbls) | 0 | | | | 1,825,000 | | (2) | | | |
Weighted average price per Bbl | $0 | | | | $52.18 | | | | | |
| | | | | | | | |
Oil contracts (Brent ICE) | | | | | | | | |
Swap contracts | | | | | | | | |
Total volume (Bbls) | 221,300 | | (3) | | 0 | | | | | |
Weighted average price per Bbl | $37.35 | | | | $0 | | | | | |
Collar contracts | | | | | | | | |
Total volume (Bbls) | 550,000 | | | | 0 | | | | | |
Weighted average price per Bbl | | | | | | | | |
Ceiling (short call) | $50.00 | | | | $0 | | | | | |
Floor (long put) | $45.00 | | | | $0 | | | | | |
| | | | | | | | |
Oil contracts (Midland basis differential) | | | | | | | | |
Swap contracts | | | | | | | | |
Total volume (Bbls) | 2,171,900 | | | | 0 | | | | | |
Weighted average price per Bbl | $0.24 | | | | $0 | | | | | |
| | | | | | | | |
Oil contracts (Argus Houston MEH) | | | | | | | | |
Collar contracts | | | | | | | | |
Total volume (Bbls) | 409,500 | | | | 452,500 | | | | | |
Weighted average price per Bbl | | | | | | | | |
Ceiling (short call) | $47.00 | | | | $63.15 | | | | | |
Floor (long put) | $41.00 | | | | $51.25 | | | | | |
| | | | | | | | | | | |
| For the Remainder | | For the Full Year |
Oil Contracts (WTI) | 2022 | | 2023 |
Swap Contracts | | | |
Total volume (Bbls) | 3,676,000 | | (1) | 905,000 | |
Weighted average price per Bbl | $62.77 | | (1) | $71.20 | |
Collar Contracts | | | |
Total volume (Bbls) | 4,712,500 | | | 2,096,500 | |
Weighted average price per Bbl | | | |
Ceiling (short call) | $68.77 | | | $80.25 | |
Floor (long put) | $57.83 | | | $69.48 | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
Short Call Swaption Contracts (2) | | | |
Total volume (Bbls) | — | | | 1,825,000 | |
Weighted average price per Bbl | $— | | | $72.00 | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
Oil Contracts (Midland Basis Differential) | | | |
Swap Contracts | | | |
Total volume (Bbls) | 1,787,500 | | | — | |
Weighted average price per Bbl | $0.50 | | | $— | |
| | | |
Oil Contracts (Argus Houston MEH) | | | |
Collar Contracts | | | |
Total volume (Bbls) | 227,500 | | | — | |
Weighted average price per Bbl | | | |
Ceiling (short call) | $63.15 | | | $— | |
Floor (long put) | $51.25 | | | $— | |
(1) Premiums from the sale of call options were used to increase the fixed price of certain simultaneously executed price swaps and three-way collars.
(2) The short call swaption contracts have an exercise expiration date of December 31, 2021.
(3) In February 2021,March 2022, the Company entered into certain offsetting ICE BrentWTI swaps for the second quarter of 2022 to reduce its exposure to rising oil prices. Those offsetting swaps resulted in a locked-inrecognized loss of approximately $2.9$39.3 million of which $1.6 million will be settled in the thirdsecond quarter of 2021 with2022 as the remaining $1.3 million to be settled in the fourth quarterapplicable contracts settle.
(2) The 2023 short call swaption contracts have exercise expiration dates of 2021.December 30, 2022.
| | | | | | | | | | | | | | | | | | | | |
| For the Remainder | | | For the Full Year | | | | |
Natural gas contracts (Henry Hub) | of 2021 | | | of 2022 | | | | |
Swap contracts | | | | | | | | |
Total volume (MMBtu) | 11,123,000 | | | | 0 | | | | | |
Weighted average price per MMBtu | $2.60 | | | | $0 | | | | | |
Collar contracts | | | | | | | | |
Total volume (MMBtu) | 5,500,000 | | | | 1,800,000 | | | | | |
Weighted average price per MMBtu | | | | | | | | |
Ceiling (short call) | $2.80 | | | | $3.88 | | | | | |
Floor (long put) | $2.50 | | | | $2.78 | | | | | |
Short call contracts | | | | | | | | |
Total volume (MMBtu) | 5,500,000 | | (1) | | 0 | | | | | |
Weighted average price per MMBtu | $3.09 | | | | $0 | | | | | |
| | | | | | | | |
Natural gas contracts (Waha basis differential) | | | | | | | | |
Swap contracts | | | | | | | | |
Total volume (MMBtu) | 12,375,000 | | | | 0 | | | | | |
Weighted average price per MMBtu | ($0.42) | | | | $0 | | | | | |
(1) Premiums from the sale of call options were used to increase the fixed price of certain simultaneously executed price swaps and three-way collars.
| | | | | | | | | | | | | | | | | | | | |
| For the Remainder | | | For the Full Year | | | | |
NGL contracts (OPIS Mont Belvieu Purity Ethane) | of 2021 | | | of 2022 | | | | |
Swap contracts | | | | | | | | |
Total volume (Bbls) | 1,375,000 | | | | 0 | | | | | |
Weighted average price per Bbl | $7.62 | | | | $0 | | | | | |
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| For the Remainder | | For the Full Year | |
Natural Gas Contracts (Henry Hub) | 2022 | | 2023 | |
Swap Contracts | | | | |
Total volume (MMBtu) | 10,700,000 | | | — | | |
Weighted average price per MMBtu | $3.62 | | | $— | | |
Collar Contracts | | | | |
Total volume (MMBtu) | 6,110,000 | | | 2,700,000 | | |
Weighted average price per MMBtu | | | | |
Ceiling (short call) | $4.51 | | | $5.56 | | |
Floor (long put) | $3.68 | | | $4.58 | | |
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Natural Gas Contracts (Waha Basis Differential) | | | | |
Swap Contracts | | | | |
Total volume (MMBtu) | 1,220,000 | | | 6,080,000 | | |
Weighted average price per MMBtu | ($0.75) | | | ($0.75) | | |
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Note 78 - Fair Value Measurements
Accounting guidelines for measuring fair value establish a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows:
Level 1 – Observable inputs such as quoted prices in active markets at the measurement date for identical, unrestricted assets or liabilities.
Level 2 – Other inputs that are observable directly or indirectly such as quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability.
Level 3 – Unobservable inputs for which there is little or no market data and which the Company makes its own assumptions about how market participants would price the assets and liabilities.
Fair valueValue of financial instrumentsFinancial Instruments
Cash, cash equivalents,Cash Equivalents, and restricted investments.Restricted Investments. The carrying amounts for these instruments approximate fair value due to the short-term nature or maturity of the instruments.
Debt. The carrying amount of borrowings outstanding under the Credit Facility approximates fair value as the borrowings bear interest at variable rates and are reflective of market rates. The following table presents the principal amounts of the Company’s Second Lien Notes and Senior Unsecured Notes with the fair values measured using quoted secondary market trading prices which are designated as Level 2 within the valuation hierarchy. See “Note 56 - Borrowings” for further discussion.
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| | March 31, 2021 | | December 31, 2020 |
| | Principal Amount | | Fair Value | | Principal Amount | | Fair Value |
| | (In thousands) |
Second Lien Notes | | $516,659 | | | $524,409 | | | $516,659 | | | $470,160 | |
6.25% Senior Notes | | 542,720 | | | 483,021 | | | 542,720 | | | 344,627 | |
6.125% Senior Notes | | 460,241 | | | 388,904 | | | 460,241 | | | 260,036 | |
8.25% Senior Notes | | 187,238 | | | 161,961 | | | 187,238 | | | 100,172 | |
6.375% Senior Notes | | 320,783 | | | 252,617 | | | 320,783 | | | 161,995 | |
Total | | $2,027,641 | | | $1,810,912 | | | $2,027,641 | | | $1,336,990 | |
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| | March 31, 2022 | | December 31, 2021 |
| | Principal Amount | | Fair Value | | Principal Amount | | Fair Value |
| | (In thousands) |
6.125% Senior Notes | | $460,241 | | | $456,789 | | | $460,241 | | | $455,639 | |
9.00% Second Lien Notes | | 319,659 | | | 339,638 | | | 319,659 | | | 343,633 | |
8.25% Senior Notes | | 187,238 | | | 189,110 | | | 187,238 | | | 184,429 | |
6.375% Senior Notes | | 320,783 | | | 317,575 | | | 320,783 | | | 309,556 | |
8.00% Senior Notes | | 650,000 | | | 684,125 | | | 650,000 | | | 663,000 | |
Total | | $1,937,921 | | | $1,987,237 | | | $1,937,921 | | | $1,956,257 | |
Assets and liabilities measuredLiabilities Measured at fair valueFair Value on a recurring basisRecurring Basis
Certain assets and liabilities are reported at fair value on a recurring basis in the consolidated balance sheets. The following methods and assumptions were used to estimate fair value:
Commodity derivative instruments.Derivative Instruments. The fair value of commodity derivative instruments is derived using a third-party income approach valuation model that utilizes market-corroborated inputs that are observable over the term of the commodity derivative contract. The Company’s fair value calculations also incorporate an estimate of the counterparties’ default risk for commodity derivative assets and an estimate of the Company’s default risk for commodity derivative liabilities. As the inputs in the model are substantially observable over the term of the commodity derivative contract and there is a wide availability of quoted market prices for similar commodity derivative contracts, the Company designates its commodity derivative instruments as Level 2 within the fair value hierarchy. See “Note 67 - Derivative Instruments and Hedging Activities” for further discussion.
Contingent consideration arrangements - embedded derivative financial instruments.
The embedded options within the contingent consideration arrangements are considered financial instruments under ASC 815. The Company engages a third-party valuation specialist using an option pricing model approach to measure the fair value of the embedded options on a recurring basis. The valuation includes significant inputs such as forward oil price curves, time to expiration, and implied volatility. The model provides for the probability that the specified pricing thresholds would be met for each settlement period, estimates undiscounted payouts, and risk adjusts for the discount rates inclusive of adjustments for each of the counterparty’s credit quality. As these inputs are substantially observable for the full term of the contingent consideration arrangements, the inputs are considered Level 2 inputs within the fair value hierarchy. See “Note 6 - Derivative Instruments and Hedging Activities” for further discussion.
The following tables present the Company’s assets and liabilities measured at fair value on a recurring basis as of March 31, 20212022 and December 31, 2020:2021:
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| March 31, 2021 |
| Level 1 | | Level 2 | | Level 3 |
| (In thousands) |
Assets | | | | | |
Commodity derivative instruments | $0 | | | $560 | | | $0 | |
Contingent consideration arrangements | 0 | | | 5,375 | | | 0 | |
Liabilities | | | | | |
Commodity derivative instruments (1) | 0 | | | (207,933) | | | 0 | |
Contingent consideration arrangements | 0 | | | (17,913) | | | 0 | |
Total net assets (liabilities) | $0 | | | ($219,911) | | | $0 | |
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| December 31, 2020 |
| Level 1 | | Level 2 | | Level 3 |
| (In thousands) |
Assets | | | | | |
Commodity derivative instruments | $0 | | | $921 | | | $0 | |
Contingent consideration arrangements | 0 | | | 1,816 | | | 0 | |
Liabilities | | | | | |
Commodity derivative instruments (2) | 0 | | | (97,060) | | | 0 | |
Contingent consideration arrangements | 0 | | | (8,618) | | | 0 | |
September 2020 Warrants | 0 | | | 0 | | | (79,428) | |
Total net assets (liabilities) | $0 | | | ($102,941) | | | ($79,428) | |
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| March 31, 2022 |
| Level 1 | | Level 2 | | Level 3 |
| (In thousands) |
Commodity derivative assets | $— | | | $— | | | $— | |
| | | | | |
Commodity derivative liabilities (1) | — | | | (427,362) | | | — | |
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| December 31, 2021 |
| Level 1 | | Level 2 | | Level 3 |
| (In thousands) |
Assets | | | | | |
Commodity derivative instruments | $— | | | $1,798 | | | $— | |
Contingent consideration arrangements | — | | | 20,833 | | | — | |
Liabilities | | | | | |
Commodity derivative instruments (2) | — | | | (172,386) | | | — | |
Contingent consideration arrangements | — | | | (25,000) | | | — | |
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Total net assets (liabilities) | $— | | | ($174,755) | | | $— | |
(1) Includes approximately $15.0$0.9 million of deferred premiums, which the Company will paybe paid as the applicable contracts settle.
(2) Includes approximately $11.2$2.9 million of deferred premiums, which the Company will paybe paid as the applicable contracts settle.
There were no transfers between any of the fair value levels during any period presented.
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
September 2020 Warrants.Acquisitions. The fair value of assets acquired and liabilities assumed are measured as of the September 2020 Warrants was calculatedacquisition date by a third-party valuation specialist using a Black Scholes-Merton option pricing model. As historical volatility is a significant input intocombination of income and market approaches, which are not observable in the model, the September 2020 Warrants weremarket and are therefore designated as Level 3 within the valuation hierarchy.
In February 2021, holders of the September 2020 Warrants provided noticeinputs. Significant inputs include expected discounted future cash flows from estimated reserve quantities, estimates for timing and exercised all of their outstanding warrants. The exercise of the September 2020 Warrants resulted in settlement of the associated derivative liability of $134.8 million.costs to produce and develop reserves, oil and natural gas forward prices, and a risk-adjusted discount rate. See “Note 63 - Derivative InstrumentsAcquisitions and Hedging Activities”Divestitures” for additional details.
The following table presents a reconciliation of the change in the fair value of the liability related to the September 2020 Warrants, which was designated as Level 3 within the valuation hierarchy, for the three months ended March 31, 2021.
| | | | | | | | |
| | Three Months Ended March 31, 2021 |
| | (In thousands) |
Beginning of period | | $79,428 | |
(Gain) loss on changes in fair value (1)
| | 55,390 | |
Transfers into (out of) Level 3 | | (134,818) | |
End of period | | $0 | |
(1) Included in “(Gain) loss on derivative contracts” in the consolidated statements of operations.
Assets and liabilities measured at fair value on a nonrecurring basis
Asset retirement obligations.Retirement Obligations. The Company measures the fair value of asset retirement obligations as of the date a well begins drilling or when production equipment and facilities are installed using a discounted cash flow model based on inputs that are not observable in the market and therefore are designated as Level 3 within the valuation hierarchy. Significant inputs to the fair value measurement of asset retirement obligations include estimates of the costs of plugging and abandoning oil and gas wells, removing production equipment and facilities, and restoring the surface of the land as well as estimates of the economic lives of the oil and gas wells and future inflation rates.
Note 89 - Income Taxes
The Company provides for income taxes at the statutory rate of 21%. Reported income tax benefit (expense) differs from the amount of income tax benefit (expense) that would result from applying domestic federal statutory tax rates to pretax income (loss). These differences primarily relate to non-deductible executive compensation expenses, restricted stock windfalls, changes in valuation allowances, and state income taxes.
For both the three months ended March 31, 20212022 and 2020,2021, the Company’s effective income tax rates wererate was approximately 1% and 23%, respectively.. The primary differences between the effective tax rates for the three months ended March 31, 2022 and 2021 and 2020 were a result ofthe statutory rate resulted from the valuation allowance recorded against the Company’s net deferred tax assets beginning in the second quarter of 2020 and the effect of state income taxes.
Deferred Tax Asset Valuation Allowance
Management monitors company-specific, oil and natural gas industry and worldwide economic factors and assesses the likelihood that
the Company’s net deferred tax assets will be utilized prior to their expiration. A significant item of objective negative evidence considered was the cumulative historical three yearthree-year pre-tax loss and a net deferred tax asset position at March 31, 2021,2022, driven primarily by the impairments of evaluated oil and gas properties recognized beginning in the second quarter of 2020 and continuing through the fourth quarter of 2020. This limits the ability to consider other subjective evidence such as the Company’s potential for future growth. Since the second quarter of 2020, based on the evaluation of the evidence available, the Company concluded that it is more likely than not that the net deferred tax assets will not be realized. As a result, the Company has recorded a valuation allowance, reducing the net deferred tax assets as of March 31, 20212022 to 0.zero. As long as the Company continues to conclude that the valuation
allowance against its net deferred tax assets is necessary, the Company does not expect to have no significant deferred income tax expense or benefit.
The Company will continue to evaluate whether the valuation allowance is needed in future reporting periods. The valuation allowance will remain until the Company can conclude that the net deferred tax assets are more likely than not to be realized. Future events or new evidence which may lead the Company to conclude that it is more likely than not its net deferred tax assets will be realized include, but are not limited to, cumulative historical pre-tax earnings, improvements in crude oil prices, and taxable events that could result from one or more future potential transactions. The valuation allowance does not preclude the Company from utilizing the tax attributes if the Companyit recognizes taxable income. As long as the Company continues to conclude that the valuation allowance against its net deferred tax assets is necessary, the Company will have no significant deferred income tax expense or benefit.
Note 9 - Share-based Compensation
All share and per share numbers included in this footnote have been adjusted for the reverse stock split. See “Note 10 - Stockholders’ Equity” for discussion of the reverse stock split and reduction in authorized shares.Share-Based Compensation
RSU Equity Awards
The following table summarizes activity for restricted stock units that may be settled in common stock (“RSU Equity Awards”) for the three months ended March 31, 2021 and 2020:2022:
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| | Three Months Ended March 31, |
| | 2021 | | 2020 |
| | RSU Equity Awards (in thousands) | | Weighted Average Grant Date Fair Value | | RSU Equity Awards (in thousands) | | Weighted Average Grant Date Fair Value |
Unvested, beginning of the period | | 677 | | | $34.57 | | | 269 | | | $102.48 | |
Granted (1) | | 570 | | | $38.41 | | | 232 | | | $33.19 | |
Vested (2) | | (21) | | | $70.03 | | | (16) | | | $98.36 | |
Forfeited | | (16) | | | $15.42 | | | 0 | | | $0 | |
Unvested, end of the period | | 1,210 | | | $36.02 | | | 485 | | | $69.50 | |
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(1)Includes 0 and 85.4 thousand target performance-based RSU Equity Awards granted during the three months ended March 31, 2021 and 2020, respectively.
(2)The fair value of shares vested was $0.3 million and $0.7 million during the three months ended March 31, 2021 and 2020, respectively. | | | | | | | | | | | | | | |
| | Three Months Ended March 31, 2022 |
| | RSU Equity Awards (In thousands) | | Weighted Average Grant-Date Fair Value Per Share |
Unvested at beginning of the period | | 968 | | | $34.04 | |
Granted | | 328 | | | $60.63 | |
Vested | | (10) | | | $53.38 | |
Forfeited | | (11) | | | $33.36 | |
Unvested at end of the period | | 1,275 | | | $40.73 | |
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Grant activity for the three months ended March 31, 20212022 primarily consisted of RSU Equity Awards granted to executives and employees as part of the annual grant of long-term equity incentive awards as compared to the annualwith a weighted-average grant date fair value of long-term equity to only executives during the first quarter of 2020.$60.63.
NaN performance-basedThe aggregate fair value of RSU Equity Awards were grantedthat vested during the three months ended March 31, 2021. For the performance-based RSU Equity Awards granted in the first quarter of 2020, the number of outstanding performance-based RSU Equity Awards that can vest is based on a calculation that compares the Company’s total shareholder return (“TSR”) to the same calculated return of a group of peer companies selected by the Company and can range between 0% and 300% of the target units for the awards granted. These awards include an absolute TSR modifier, which 2022was added as a second factor in the calculation, which could increase the number of awards that vest or reduce the number of awards that vest if the absolute TSR is less than 5% over the performance period.
The Company recognizes expense for performance-based RSU Equity Awards based on the fair value of the awards at the grant date. Awards with a performance-based provision do not allow for the reversal of previously recognized expense, even if the market metric is not achieved and 0 shares ultimately vest. The grant date fair value of performance-based RSU Equity Awards, calculated using a Monte Carlo simulation, was $2.9 million for the three months ended March 31, 2020. The following table summarizes the assumptions used to calculate the grant date fair value of the performance-based RSU Equity Awards granted during the three months ended March 31, 2020:
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Performance-based Awards | | | | January 31, 2020 |
Expected term (in years) | | | | 2.9 |
Expected volatility | | | | 54.8 | % |
Risk-free interest rate | | | | 1.3 | % |
Dividend yield | | | | 0 | % |
$0.5 million. As of March 31, 2021,2022, unrecognized compensation costs related to unvested RSU Equity Awards were $32.7$37.3 million and will be recognized over a weighted average period of 2.5 years.
Cash-Settled RSU Awards
The table below summarizes the activity forNo restricted stock units that may be settled in cash (“Cash-Settled RSU Awards”) for the three months ended March 31, 2021 and 2020:
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| | Three Months Ended March 31, |
| | 2021 | | 2020 |
| | Cash-Settled RSU Awards (in thousands) | | Weighted Average Grant Date Fair Value | | Cash-Settled RSU Awards (in thousands) | | Weighted Average Grant Date Fair Value |
Unvested, beginning of the period | | 196 | | | $47.56 | | | 86 | | | $124.22 | |
Granted | | 0 | | | $0 | | | 86 | | | $33.98 | |
Vested | | (1) | | | $107.80 | | | (1) | | | $122.96 | |
Did not vest at end of performance period | | (1) | | | $107.80 | | | 0 | | | $166.60 | |
Forfeited | | 0 | | | $0 | | | 0 | | | $0 | |
Unvested, end of the period | | 194 | | | $47.15 | | | 171 | | | $78.54 | |
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NaN Cash-Settled RSU Awardsor cash-settled stock appreciation rights (“Cash SARs”) were granted to employees during the three months ended March 31, 2022 and 2021. Grant activity in the first quarter of 2020 primarily consisted of Cash-Settled RSU Awards to executives as part of the annual grant of long-term equity incentive awards. These awards cliff vest after an approximate three-year performance period.
The Company’s outstanding Cash-Settled RSU Awards include the same performance-based vesting conditions as the performance-based RSU Equity Awards, which are described above. Additionally, the assumptions used to calculate the grant date fair value per Cash-Settled RSU Award granted during the three months ended March 31, 2020 are the same as the performance-based RSU Equity Awards presented above.
The following table summarizes the Company’s liabilityliabilities for Cash-Settled RSU Awardscash-settled awards and the classification in the consolidated balance sheets for the periods indicated:
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| | March 31, 2021 | | December 31, 2020 |
| | (In thousands) |
Other current liabilities | | $850 | | | $182 | |
Other long-term liabilities | | 4,928 | | | 1,336 | |
Total Cash-Settled RSU Awards | | $5,778 | | | $1,518 | |
As of March 31, 2021, unrecognized compensation costs related to unvested Cash-Settled RSU Awards were $5.4 million and will be recognized over a weighted average period of 1.7 years.
Cash-Settled SARs
As a result of the Carrizo Acquisition, cash-settled stock appreciation rights (“Cash SARs”) previously granted by Carrizo that were outstanding at closing were canceled and converted into a Cash SAR covering shares of the Company’s common stock, with the conversion calculated as prescribed in the agreement governing the Carrizo Acquisition. The liabilities for Cash SARs as of March 31, 2021 and December 31, 2020 were $6.5 million and $1.7 million, respectively, all of which were classified as “Other current liabilities” in the consolidated balance sheets in the respective periods. Changes in the fair value of the Cash SARs are included in “General and administrative” in the consolidated statements of operations. | | | | | | | | | | | | | | |
| | March 31, 2022 | | December 31, 2021 |
| | (In thousands) |
Cash SARs | | $10,324 | | | $7,884 | |
Cash-Settled RSU Awards | | 4,563 | | | 1,382 | |
Other current liabilities | | 14,887 | | | 9,266 | |
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Cash-Settled RSU Awards | | 1,972 | | | 6,366 | |
Other long-term liabilities | | 1,972 | | | 6,366 | |
Total Cash-Settled RSU Awards | | $16,859 | | | $15,632 | |
Share-Based Compensation Expense (Benefit), Net
Share-based compensation expense associated with the RSU Equity Awards, Cash-Settled RSU Awards, and Cash SARs, net of amounts capitalized, is included in “General and administrative” in the consolidated statements of operations. The following table presents share-based compensation expense (benefit), net for each respective period:
| | | Three Months Ended March 31, | | | Three Months Ended March 31, | |
| | 2021 | | 2020 | | | 2022 | | 2021 | |
| | (In thousands) | | (In thousands) |
RSU Equity Awards | RSU Equity Awards | | $2,608 | | | $3,948 | | | RSU Equity Awards | | $3,366 | | | $2,608 | | |
Cash-Settled RSU Awards | Cash-Settled RSU Awards | | 4,442 | | | (1,996) | | | Cash-Settled RSU Awards | | 237 | | | 4,442 | | |
Cash SARs | Cash SARs | | 4,866 | | | (4,756) | | | Cash SARs | | 2,440 | | | 4,866 | | |
| | 11,916 | | | (2,804) | | | | 6,043 | | | 11,916 | | |
Less: amounts capitalized to oil and gas properties | Less: amounts capitalized to oil and gas properties | | (4,308) | | | (168) | | | Less: amounts capitalized to oil and gas properties | | (1,877) | | | (4,308) | | |
Total share-based compensation expense (benefit), net | Total share-based compensation expense (benefit), net | | $7,608 | | | ($2,972) | | | Total share-based compensation expense (benefit), net | | $4,166 | | | $7,608 | | |
See “Note 10 - Share-Based Compensation” of the Notes to Consolidated Financial Statements in the 20202021 Annual Report for details of the Company’s equity-based incentive plans.
Note 1011 - Stockholders’ Equity
Warrant Exercises
During the three months ended March 31, 2021, certain holders of the September 2020 Warrants and warrants issued in conjunction with the exchange of Senior Unsecured Notes on November 2, 2020 (the “November 2020 Warrants”)Warrants provided notice and exercised all of their outstanding warrants. As a result of the exercises, the Company issued a total of 6.4 million shares of its common stock in exchange for 8.4 million outstanding warrants determined on a net share settlement basis. See “Note 6 - Derivative Instruments and Hedging Activities” and “Note 7 - Fair Value Measurements”Borrowings” of the Notes to Consolidated Financial Statements in the Company’s 2021 Annual Report for additional details regarding the September 2020 Warrants and the November 2020 Warrants.
As of March 31, 2021, 0.6 million November 2020 Warrants remain outstanding.
Reverse Stock Split
On August 7, 2020, the Board of Directors effected a reverse stock split of the Company’s outstanding shares of common stock at a ratio of 1-for-10 and reduced the total number of authorized shares of the Company’s common stock from 525,000,000 to 52,500,000 shares pursuant to an amendment to the Company’s Certificate of Incorporation, which was approved by the Company’s shareholders at the Company’s annual meeting of shareholders on June 8, 2020. The Company’s common stock began trading on a split-adjusted basis on August 10, 2020 upon opening of the markets. All share and per share amounts, except par value per share, in the consolidated financial statements and notes thereto for periods prior to August 2020 were retroactively adjusted to give effect to this reverse stock split.
Note 1112 - Accounts Receivable, Net
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| March 31, 2021 | | December 31, 2020 |
| (In thousands) |
Oil and natural gas receivables | $125,648 | | | $100,257 | |
Joint interest receivables | 21,185 | | | 11,530 | |
Other receivables | 35,163 | | | 24,191 | |
Total | 181,996 | | | 135,978 | |
Allowance for credit losses | (2,869) | | | (2,869) | |
Total accounts receivable, net | $179,127 | | | $133,109 | |
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| March 31, 2022 | | December 31, 2021 |
| (In thousands) |
Oil and natural gas receivables | $262,389 | | | $171,837 | |
Joint interest receivables | 21,044 | | | 13,751 | |
Other receivables | 66,388 | | | 49,053 | |
Total | 349,821 | | | 234,641 | |
Allowance for credit losses | (2,228) | | | (2,205) | |
Total accounts receivable, net | $347,593 | | | $232,436 | |
Note 1213 - Accounts Payable and Accrued Liabilities
| | | | | | | | | | | |
| March 31, 2021 | | December 31, 2020 |
| (In thousands) |
Accounts payable | $78,869 | | | $101,231 | |
Revenues payable | 187,261 | | | 162,762 | |
Accrued capital expenditures | 45,408 | | | 32,493 | |
Accrued interest | 63,211 | | | 45,033 | |
Total accounts payable and accrued liabilities | $374,749 | | | $341,519 | |
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| March 31, 2022 | | December 31, 2021 |
| (In thousands) |
Accounts payable | $134,690 | | | $151,836 | |
Revenues and royalties payable | 277,368 | | | 294,143 | |
Accrued capital expenditures | 56,388 | | | 64,412 | |
Accrued interest | 47,994 | | | 59,600 | |
Total accounts payable and accrued liabilities | $516,440 | | | $569,991 | |
Note 1314 - Supplemental Cash Flow
| | | | | | | | | | | |
| Three Months Ended March 31, |
| 2021 | | 2020 |
Supplemental cash flow information: | | | |
Interest paid, net of capitalized amounts | $12,983 | | | $15,820 | |
Income taxes paid | 0 | | | 0 | |
Cash paid for amounts included in the measurement of lease liabilities: | | | |
Operating cash flows from operating leases | $8,065 | | | $11,821 | |
Investing cash flows from operating leases | 6,005 | | | 5,716 | |
Non-cash investing and financing activities: | | | |
Change in accrued capital expenditures | $18,903 | | | $84,594 | |
Change in asset retirement costs | 1,151 | | | 905 | |
ROU assets obtained in exchange for lease liabilities: | | | |
Operating leases | $6,476 | | | $8,366 | |
| | | | | | | | | | | |
| Three Months Ended March 31, |
| 2022 | | 2021 |
| (In thousands) |
Supplemental cash flow information: | | | |
Interest paid, net of capitalized amounts | $25,144 | | | $12,983 | |
Income taxes paid | — | | | — | |
Cash paid for amounts included in the measurement of lease liabilities: | | | |
Operating cash flows from operating leases | $7,382 | | | $8,065 | |
Investing cash flows from operating leases | 6,189 | | | 6,005 | |
Non-cash investing and financing activities: | | | |
Change in accrued capital expenditures | ($8,897) | | | $18,903 | |
Change in asset retirement costs | 289 | | | 1,151 | |
ROU assets obtained in exchange for lease liabilities: | | | |
Operating leases | $8,505 | | | $6,476 | |
Note 1415 - Subsequent Events
Credit Agreement Reaffirmation
Fourth Amendment toOn May 2, 2022, as part of the Credit Agreement
On May 3, 2021, the Company entered into the fourth amendment to its credit agreement governing the Credit Facility. The amendment, among other things, (a) reaffirmedCompany’s spring 2022 redetermination, the borrowing base and the elected commitment amount of $1.6 billion as a result of the spring 2021 scheduled redetermination; and (b) permits the prepayment, repurchase or redemption of Junior Debt (as defined in the credit agreement governing the Credit Facility), which includes the Senior Unsecured Notes and the Second Lien Notes, in an aggregate amount not to exceed $100.0 million, commencing April 1, 2021, if certain liquidity and free cash flow thresholds are met.
Non-Core Asset Divestitures
In April 2021, the Company entered into purchase and sale agreements for the divestiture of certain non-core assets in the Delaware Basin. The transactions, which are primarily comprised of natural gas producing properties in the Western Delaware Basin as well as a small undeveloped acreage position, have agreed upon purchase prices totaling approximately $40.0 million and are expected to close during the second quarter of 2021.were reaffirmed.
Special Note Regarding Forward Looking Statements
This report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). These statements involve known and unknown risks, uncertainties and other factors that may cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by the forward-looking statements. In some cases, you can identify forward-looking statements in this Form 10-Q by words such as “anticipate,” “project,” “intend,” “estimate,” “expect,” “believe,” “predict,” “budget,” “projection,” “goal,” “plan,” “forecast,” “target” or similar expressions.
All statements, other than statements of historical facts, included in this report that address activities, events or developments that we expect or anticipate will or may occur in the future are forward-looking statements, including such things as:
•our oil and natural gas reserve quantities, and the discounted present value of these reserves;
•the amount and nature of our capital expenditures;
•our future drilling and development plans and our potential drilling locations;
•the timing and amount of future capital and operating costs;
•production decline rates from our wells being greater than expected;
•commodity price risk management activities and the impact on our average realized prices;
•business strategies and plans of management;
•our ability to consummate and efficiently integrate recent acquisitions; and
•prospect development and property acquisitions.
We caution you that the forward-looking statements contained in this Form 10-Q are subject to all of the risks and uncertainties, many of which are beyond our control, incident to the exploration for and development, production and sale of oil and natural gas. TheseWe disclose these and other risks include, but are not limitedimportant factors that could cause our actual results to the risks describeddiffer materially from our expectations under “Risk Factors” in Part I, Item 1A of our 20202021 Annual Report and in all quarterly reports on Form 10-Q filed subsequently thereto.Report. These factors include:
•the volatility of oil, natural gas and NGL prices or a prolonged period of low oil, natural gas or NGLsNGL prices;
•general economic conditions including the availability of credit and access to existing lines of credit;
•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;
•the uncertainty of estimates of oil and natural gas reserves;
•impairments;
•the impact of competition;
•the availability and cost of seismic, drilling, completions and other equipment, waste and water disposal infrastructure, and personnel;
•operating hazards inherent in the exploration for and production of oil and natural gas;
•difficulties encountered during the exploration for and production of oil and natural gas;
•the potential impact of future drilling on production from existing wells;
•difficulties encountered in delivering oil and natural gas to commercial markets;
•the uncertainty of our ability to attract capital and obtain financing on favorable terms;
•compliance with, or the effect of changes in, the extensive governmental regulations regarding the oil and natural gas business including those related to climate change and greenhouse gases;
•the impact of government regulation, including regulation of hydraulic fracturing and water disposal wells;
•any increase in severance or similar taxes;
•the financial impact of accounting regulations and critical accounting policies;
•the comparative cost of alternative fuels;
•credit risk relating to the risk of loss as a result of non-performance by our counterparties;
•cyberattacks on the Company or on systems and infrastructure used by the oil and natural gas industry;
•weather conditions; and
•weather conditions.risks associated with acquisitions.
Should one or more of these risks or uncertainties occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. Additional risks or uncertainties that are not currently known to us, that we currently deem to be immaterial, or that could apply to any company could also materially adversely affect our business, financial condition, or future results. Any forward-looking statement speaks only as of the date of which such statement is made and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law.
In addition, we caution that reserve engineering is a process of estimating oil and natural gas accumulated underground and cannot be measured exactly. Accuracy of reserve estimates depend on a number of factors including data available at the point in time, engineering interpretation of the data, and assumptions used by the reserve engineers as it relates to price and cost estimates and recoverability. New results of drilling, testing, and production history may result in revisions of previous estimates and, if significant,
would impact future development plans. As such, reserve estimates may differ from actual results of oil and natural gas quantities ultimately recovered.
Except as required by applicable law, all forward-looking statements attributable to us are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
General
The following management’s discussion and analysis describes the principal factors affecting the Company’sour results of operations, liquidity, capital resources and contractual cash obligations. This discussion should be read in conjunction with the accompanying unaudited consolidated financial statements and our 20202021 Annual Report, on Form 10-K, which include additional information about our business practices, significant accounting policies, risk factors, and the transactions that underlie our financial results. Our website address is www.callon.com. All of our filings with the SEC are available free of charge through our website as soon as reasonably practicable after we file them with, or furnish them to, the SEC. Information on our website does not form part of this Quarterly Report on Form 10-Q.
General
We are an independent oil and natural gas company with roots that go back over 70 years to our establishment in 1950. We are focused on the acquisition, exploration and development of high-quality assets in the leading oil plays of South and West Texas. Our activities are primarily focused on horizontal development in the Midland and Delaware Basins, both of which are part of the larger Permian Basin in West Texas, as well as the Eagle Ford.Ford in South Texas.
Our operating culture is centered on responsible development of hydrocarbon resources, safety and the environment, which we believe strengthens our operational performance. Our drilling activity is predominantly focused on the horizontal development of several prospective intervals in the Permian, including multiple levels of the Wolfcamp formation and the Lower Spraberry shales, and the Eagle Ford. We have assembled a multi-year inventory of potential horizontal well locations and intend to add to this inventory through delineation drilling of emerging zones on our existing acreage and through acquisition of additional locations through working interest acquisitions, leasing programs, acreage purchases, joint ventures and asset swaps.
Recent Developments and Overview
Fourth Amendment to the Credit Agreement
On May 3, 2021, we entered into the fourth amendment to our credit agreement governing the Credit Facility which, among other things, reaffirmed the borrowing base and elected commitment amount of $1.6 billion as a result of the spring 2021 scheduled redetermination. See “Note 14 - Subsequent Events” for further discussion.
Non-Core Asset Divestitures
In April 2021, we entered into purchase and sale agreements for the divestiture of certain non-core assets in the Delaware Basin. The transactions, which are primarily comprised of natural gas producing properties in the Western Delaware Basin as well as a small undeveloped acreage position, have agreed upon purchase prices totaling approximately $40.0 million and are expected to close during the second quarter of 2021.
First Quarter 20212022 Highlights
•Total production for the three months ended March 31, 20212022 was 81.0102.7 MBoe/d, a decrease of 15% and 20%9% from the three months ended December 31, 2020 and March 31, 2020, respectively,2021, primarily due to normal production decline and the shut-in of our operatedpartially offset by new wells placed on production during the severe winter stormsfirst quarter of 2022. Total production for the three months ended March 31, 2022 increased 27% from the three months ended March 31, 2021, primarily due to new wells acquired in Februarythe Primexx Acquisition as well as new wells placed on production, partially offset by normal production decline as well as non-core asset divestitures which occurred primarily in the fourth quarter of 2021.
•Operated drilling and completion activity for the three months ended March 31, 20212022 along with our drilled but uncompleted and producing wells as of March 31, 20212022 are summarized in the table below.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended March 31, 2021 | | As of March 31, 2021 |
| | Drilled | | Completed | | Drilled But Uncompleted | | Producing |
Region | | Gross | | Net | | Gross | | Net | | Gross | | Net | | Gross | | Net |
Permian | | 10 | | | 8.4 | | | 9 | | | 8.2 | | | 28 | | | 23.8 | | | 850 | | | 741.8 | |
Eagle Ford | | 8 | | | 8.0 | | | 10 | | | 9.8 | | | 35 | | | 35.0 | | | 660 | | | 592.1 | |
Total | | 18 | | | 16.4 | | | 19 | | | 18.0 | | | 63 | | | 58.8 | | | 1,510 | | | 1,333.9 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended March 31, 2022 | | As of March 31, 2022 |
| | Drilled | | Completed | | Drilled But Uncompleted | | Producing |
Region | | Gross | | Net | | Gross | | Net | | Gross | | Net | | Gross | | Net |
Permian | | 22 | | | 19.2 | | | 16 | | | 14.3 | | | 27 | | | 23.4 | | | 588 | | | 533.0 | |
Eagle Ford | | 9 | | | 7.2 | | | — | | | — | | | 15 | | | 13.0 | | | 756 | | | 671.3 | |
Total | | 31 | | | 26.4 | | | 16 | | | 14.3 | | | 42 | | | 36.4 | | | 1,344 | | | 1,204.3 | |
•Operational capital expenditures, exclusive of leasehold and seismic, for the first quarter of 20212022 were $95.6$157.4 million,, of which approximately 58%90% were in the Permian with the remaining balance in the Eagle Ford. We expect to operate an average of three drilling rigs throughout the remainder of 2021 and will average just over two completion crews through the second quarter before reducing to a single completion crew during the third quarter. See “—Liquidity and Capital Resources—20212022 Capital Budget and Funding Strategy” for additional details.
•ReducedAs of March 31, 2022, borrowings outstanding under our Credit Facility by $35.0was $712.0 million reflecting our continued emphasis on deleveraging our balance sheet.compared to $785.0 million as of December 31, 2021.
•We recordedRecorded net income for the three months ended March 31, 2022 of $39.7 million, or $0.64 per diluted share, compared to net loss for the three months ended March 31, 2021 of $80.4 million, or $1.89 per diluted share, as compared to net income for the three months ended March 31, 2020 of $216.6$80.4 million, or $5.46$1.89 per diluted share. The change from net
income to net lossvariance between the respective periods was driven primarily by a loss on derivative contracts of approximately $214.5 million during the first quarter of 2021 compared to a gain on derivative contracts of approximately $252.0 million during the first quarter of 2020, partially offset by an increase in operating revenues primarilyin the first quarter of 2022 driven by an approximate 39%64% increase in the total average realized sales price and an increase of 27% in production volumes compared to the first quarter of 20202021. This increase was partially offset by an increase in the loss on derivative contracts to approximately $358.3 million during the first quarter of 2022 compared to approximately $214.5 million during the first quarter of 2021, as well as a decreasean increase in depreciation, depletion and amortization primarily driven by the recording of impairments of evaluated oil and gas properties during 2020.operating expenses. See “—Results of Operations” below for further details.
•In February 2021, severe winter storms affected field operations in both the Permian and Eagle Ford resulting in the shut-in of nearly 100% of our operated production. While all of our wells returned to production by the end of February, the shut-in resulted in the deferral of approximately 7.6 MBoe/d for the quarter. The impact to our drilling and completion operations were not significant enough to alter our expectations for the full year development schedule and the impact to lease operating expenses was immaterial.
Results of Operations
The following table sets forth certain operating information with respect to the Company’s oil and natural gas operations for the periods indicated:
| | | Three Months Ended | | Three Months Ended March 31, | | Three Months Ended | | Three Months Ended |
| | | March 31, 2021 | | December 31, 2020 | | $ Change | | % Change | | 2021 | | 2020 | | $ Change | | % Change | | | March 31, 2022 | | December 31, 2021 | | Change | | % Change | | March 31, 2022 | | March 31, 2021 | | Change | | % Change |
Total production | Total production | | | | | | | | | | | | | | | | | Total production | | | | | | | | | | | | | | | | |
Oil (MBbls) | Oil (MBbls) | | Oil (MBbls) | |
Permian | Permian | | 3,088 | | 3,445 | | (357) | | | (10 | %) | | 3,088 | | 3,594 | | (506) | | | (14 | %) | Permian | | 4,469 | | 4,727 | | (258) | | | (5 | %) | | 4,469 | | 3,088 | | 1,381 | | | 45 | % |
Eagle Ford | Eagle Ford | | 1,593 | | 1,980 | | (387) | | | (20 | %) | | 1,593 | | 2,253 | | (660) | | | (29 | %) | Eagle Ford | | 1,377 | | 1,839 | | (462) | | | (25 | %) | | 1,377 | | 1,593 | | (216) | | | (14 | %) |
Total oil (MBbls) | | 4,681 | | 5,425 | | (744) | | | (14 | %) | | 4,681 | | 5,847 | | (1,166) | | | (20 | %) | |
Total oil | | Total oil | | 5,846 | | 6,566 | | (720) | | | (11 | %) | | 5,846 | | 4,681 | | 1,165 | | | 25 | % |
| Natural gas (MMcf) | Natural gas (MMcf) | | | | | | Natural gas (MMcf) | |
Permian | Permian | | 6,208 | | 7,474 | | (1,266) | | | (17 | %) | | 6,208 | | 8,009 | | (1,801) | | | (22 | %) | Permian | | 8,590 | | 9,183 | | (593) | | | (6 | %) | | 8,590 | | 6,208 | | 2,382 | | | 38 | % |
Eagle Ford | Eagle Ford | | 1,627 | | 2,264 | | (637) | | | (28 | %) | | 1,627 | | 1,784 | | (157) | | | (9 | %) | Eagle Ford | | 1,525 | | 2,090 | | (565) | | | (27 | %) | | 1,525 | | 1,627 | | (102) | | | (6 | %) |
Total natural gas (MMcf) | | 7,835 | | 9,738 | | (1,903) | | | (20 | %) | | 7,835 | | 9,793 | | (1,958) | | | (20 | %) | |
Total natural gas | | Total natural gas | | 10,115 | | 11,273 | | (1,158) | | | (10 | %) | | 10,115 | | 7,835 | | 2,280 | | | 29 | % |
| NGLs (MBbls) | NGLs (MBbls) | | | | | | NGLs (MBbls) | |
Permian | Permian | | 1,075 | | 1,331 | | (256) | | | (19 | %) | | 1,075 | | 1,368 | | (293) | | | (21 | %) | Permian | | 1,455 | | 1,549 | | (94) | | | (6 | %) | | 1,455 | | 1,075 | | 380 | | | 35 | % |
Eagle Ford | Eagle Ford | | 224 | | 353 | | (129) | | | (37 | %) | | 224 | | 339 | | (115) | | | (34 | %) | Eagle Ford | | 252 | | 344 | | (92) | | | (27 | %) | | 252 | | 224 | | 28 | | | 13 | % |
Total NGLs (MBbls) | | 1,299 | | 1,684 | | (385) | | | (23 | %) | | 1,299 | | 1,707 | | (408) | | | (24 | %) | |
Total NGLs | | Total NGLs | | 1,707 | | 1,893 | | (186) | | | (10 | %) | | 1,707 | | 1,299 | | 408 | | | 31 | % |
| Total Production (MBoe) | | | | | | |
Total production (MBoe) | | Total production (MBoe) | |
Permian | Permian | | 5,198 | | 6,022 | | (824) | | | (14 | %) | | 5,198 | | 6,297 | | (1,099) | | | (17 | %) | Permian | | 7,356 | | 7,806 | | (450) | | | (6 | %) | | 7,356 | | 5,198 | | 2,158 | | | 42 | % |
Eagle Ford | Eagle Ford | | 2,088 | | 2,710 | | (622) | | | (23 | %) | | 2,088 | | 2,889 | | (801) | | | (28 | %) | Eagle Ford | | 1,883 | | 2,532 | | (649) | | | (26 | %) | | 1,883 | | 2,088 | | (205) | | | (10 | %) |
Total barrels of oil equivalent (MBoe) | | 7,286 | | 8,732 | | (1,446) | | | (17 | %) | | 7,286 | | 9,186 | | (1,900) | | | (21 | %) | |
Total barrels of oil equivalent | | Total barrels of oil equivalent | | 9,239 | | 10,338 | | (1,099) | | | (11 | %) | | 9,239 | | 7,286 | | 1,953 | | | 27 | % |
| Total daily production (Boe/d) | Total daily production (Boe/d) | | 80,957 | | 94,914 | | (13,957) | | | (15 | %) | | 80,957 | | 100,955 | | (19,998) | | | (20 | %) | Total daily production (Boe/d) | | 102,655 | | 112,365 | | (9,710) | | | (9 | %) | | 102,655 | | 80,957 | | 21,698 | | | 27 | % |
Oil as % of total daily production | Oil as % of total daily production | | 64 | % | | 62 | % | | | | | | 64 | % | | 64 | % | | Oil as % of total daily production | | 63 | % | | 64 | % | | | | | | 63 | % | | 64 | % | |
| Benchmark prices (1) | Benchmark prices (1) | | | | | | Benchmark prices (1) | |
WTI (per Bbl) | WTI (per Bbl) | | $57.80 | | $42.60 | | $15.20 | | | 36 | % | | $57.80 | | $46.08 | | $11.72 | | | 25 | % | WTI (per Bbl) | | $94.38 | | $77.17 | | $17.21 | | | 22 | % | | $94.38 | | $57.80 | | $36.58 | | | 63 | % |
Henry Hub (per Mcf) | Henry Hub (per Mcf) | | 2.72 | | 2.76 | | (0.04) | | | (1 | %) | | 2.72 | | 1.87 | | 0.85 | | | 45 | % | Henry Hub (per Mcf) | | 4.57 | | 4.84 | | (0.27) | | | (6 | %) | | 4.57 | | 2.72 | | 1.85 | | | 68 | % |
| Average realized sales price (excluding impact of settled derivatives) | | | | | | |
Average realized sales price (excluding impact of derivative settlements) | | Average realized sales price (excluding impact of derivative settlements) | | | | | |
Oil (per Bbl) | Oil (per Bbl) | | Oil (per Bbl) | |
Permian | Permian | | $56.66 | | $41.02 | | $15.64 | | | 38 | % | | $56.66 | | $45.61 | | $11.05 | | | 24 | % | Permian | | $94.52 | | $76.86 | | $17.66 | | | 23 | % | | $94.52 | | $56.66 | | $37.86 | | | 67 | % |
Eagle Ford | Eagle Ford | | 57.80 | | 41.12 | | 16.68 | | | 41 | % | | 57.80 | | 45.21 | | 12.59 | | | 28 | % | Eagle Ford | | 95.02 | | 77.84 | | 17.18 | | | 22 | % | | 95.02 | | 57.80 | | 37.22 | | | 64 | % |
Total oil (per Bbl) | | 57.05 | | 41.06 | | 15.99 | | | 39 | % | | 57.05 | | 45.45 | | 11.60 | | | 26 | % | |
Total oil | | Total oil | | 94.64 | | 77.13 | | 17.51 | | | 23 | % | | 94.64 | | 57.05 | | 37.59 | | | 66 | % |
| Natural gas (per Mcf) | Natural gas (per Mcf) | | | | | | Natural gas (per Mcf) | |
Permian | Permian | | 3.11 | | 1.68 | | 1.43 | | | 85 | % | | 3.11 | | 0.33 | | 2.78 | | | 842 | % | Permian | | 4.20 | | 4.81 | | (0.61) | | | (13 | %) | | 4.20 | | 3.11 | | 1.09 | | | 35 | % |
Eagle Ford | Eagle Ford | | 3.03 | | 2.65 | | 0.38 | | | 14 | % | | 3.03 | | 1.88 | | 1.15 | | | 61 | % | Eagle Ford | | 5.18 | | 6.00 | | (0.82) | | | (14 | %) | | 5.18 | | 3.03 | | 2.15 | | | 71 | % |
Total natural gas (per Mcf) | | 3.09 | | 1.91 | | 1.18 | | | 62 | % | | 3.09 | | 0.62 | | 2.47 | | | 398 | % | |
Total natural gas | | Total natural gas | | 4.35 | | 5.03 | | (0.68) | | | (14 | %) | | 4.35 | | 3.09 | | 1.26 | | | 41 | % |
| NGL (per Bbl) | NGL (per Bbl) | | | | | | NGL (per Bbl) | |
Permian | Permian | | 22.68 | | 15.00 | | 7.68 | | | 51 | % | | 22.68 | | 11.02 | | 11.66 | | | 106 | % | Permian | | 40.25 | | 37.50 | | 2.75 | | | 7 | % | | 40.25 | | 22.68 | | 17.57 | | | 77 | % |
Eagle Ford | Eagle Ford | | 22.24 | | 16.16 | | 6.08 | | | 38 | % | | 22.24 | | 9.00 | | 13.24 | | | 147 | % | Eagle Ford | | 35.93 | | 34.00 | | 1.93 | | | 6 | % | | 35.93 | | 22.24 | | 13.69 | | | 62 | % |
Total NGLs (per Bbl) | | 22.60 | | 15.24 | | 7.36 | | | 48 | % | | 22.60 | | 10.62 | | 11.98 | | | 113 | % | |
Total NGLs | | Total NGLs | | 39.61 | | 36.86 | | 2.75 | | | 7 | % | | 39.61 | | 22.60 | | 17.01 | | | 75 | % |
| Total average realized sales price (per Boe) | | Total average realized sales price (per Boe) | |
Permian | | Permian | | 70.29 | | 59.64 | | 10.65 | | | 18 | % | | 70.29 | | 42.06 | | 28.23 | | | 67 | % |
Eagle Ford | | Eagle Ford | | 78.50 | | 66.10 | | 12.40 | | | 19 | % | | 78.50 | | 48.85 | | 29.65 | | | 61 | % |
Total average realized sales price | | Total average realized sales price | | $71.97 | | $61.22 | | $10.75 | | | 18 | % | | $71.97 | | $44.01 | | $27.96 | | | 64 | % |
| | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended | | Three Months Ended March 31, |
| | March 31, 2021 | | December 31, 2020 | | $ Change | | % Change | | 2021 | | 2020 | | $ Change | | % Change |
Total average realized sales price (per Boe) | | | | | | | | | | | | | | |
Permian | | 42.06 | | 28.87 | | 13.19 | | | 46 | % | | 42.06 | | 28.85 | | 13.21 | | | 46 | % |
Eagle Ford | | 48.85 | | 34.36 | | 14.49 | | | 42 | % | | 48.85 | | 37.48 | | 11.37 | | | 30 | % |
Total (per Boe) | | $44.01 | | $30.57 | | $13.44 | | | 44 | % | | $44.01 | | $31.56 | | $12.45 | | | 39 | % |
| | | | | | | | | | | | | | | | |
| | | | |
| | | | | | | | | | | | | | | | |
Average realized sales price (including impact of settled derivatives) | | | | | | | | | | | | |
Oil (per Bbl) | | $44.33 | | $39.62 | | $4.71 | | | 12 | % | | $44.33 | | $48.90 | | ($4.57) | | | (9 | %) |
Natural gas (per Mcf) | | 2.88 | | 1.89 | | 0.99 | | | 52 | % | | 2.88 | | 1.13 | | 1.75 | | | 155 | % |
NGLs (per Bbl) | | 21.77 | | 15.24 | | 6.53 | | | 43 | % | | 21.77 | | 10.62 | | 11.15 | | | 105 | % |
Total (per Boe) | | $35.46 | | $29.66 | | $5.80 | | | 20 | % | | $35.46 | | $34.30 | | $1.16 | | | 3 | % |
| | | | | | | | | | | | | | | | |
Revenues (in thousands) | | | | | | | | | | | | | | | | |
Oil | | | | | | | | | | | | | | | | |
Permian | | $174,967 | | $141,320 | | $33,647 | | | 24 | % | | $174,967 | | $163,906 | | $11,061 | | | 7 | % |
Eagle Ford | | 92,078 | | 81,413 | | 10,665 | | | 13 | % | | 92,078 | | 101,861 | | (9,783) | | | (10 | %) |
Total oil | | 267,045 | | 222,733 | | 44,312 | | | 20 | % | | 267,045 | | 265,767 | | 1,278 | | | — | % |
| | | | | | | | | | | | | | | | |
Natural gas | | | | | | | | | | | | | | | | |
Permian | | 19,290 | | 12,560 | | 6,730 | | | 54 | % | | 19,290 | | 2,675 | | 16,615 | | | 621 | % |
Eagle Ford | | 4,930 | | 6,001 | | (1,071) | | | (18 | %) | | 4,930 | | 3,354 | | 1,576 | | | 47 | % |
Total natural gas | | 24,220 | | 18,561 | | 5,659 | | | 30 | % | | 24,220 | | 6,029 | | 18,191 | | | 302 | % |
| | | | | | | | | | | | | | | | |
NGLs | | | | | | | | | | | | | | | | |
Permian | | 24,376 | | 19,964 | | 4,412 | | | 22 | % | | 24,376 | | 15,072 | | 9,304 | | | 62 | % |
Eagle Ford | | 4,981 | | 5,704 | | (723) | | | (13 | %) | | 4,981 | | 3,051 | | 1,930 | | | 63 | % |
Total NGLs | | 29,357 | | 25,668 | | 3,689 | | | 14 | % | | 29,357 | | 18,123 | | 11,234 | | | 62 | % |
| | | | | | | | | | | | | | | | |
Total Revenues | | | | | | | | | | | | | | | | |
Permian | | 218,633 | | 173,844 | | 44,789 | | | 26 | % | | 218,633 | | 181,653 | | 36,980 | | | 20 | % |
Eagle Ford | | 101,989 | | 93,118 | | 8,871 | | | 10 | % | | 101,989 | | 108,266 | | (6,277) | | | (6 | %) |
Total revenues | | $320,622 | | $266,962 | | $53,660 | | | 20 | % | | $320,622 | | $289,919 | | $30,703 | | | 11 | % |
| | | | | | | | | | | | | | | | |
Additional per Boe data | | | | | | | | | | | | | | | | |
Lease operating | | | | | | | | | | | | | | | | |
Permian | | $4.31 | | $4.43 | | ($0.12) | | | (3 | %) | | $4.31 | | $5.00 | | ($0.69) | | | (14 | %) |
Eagle Ford | | 8.65 | | 6.77 | | 1.88 | | | 28 | % | | 8.65 | | 7.24 | | 1.41 | | | 19 | % |
Total lease operating | | $5.55 | | $5.15 | | $0.40 | | | 8 | % | | $5.55 | | $5.70 | | ($0.15) | | | (3 | %) |
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Production and ad valorem taxes | | | | | | | | | | | | | | | | |
Permian | | $2.32 | | $1.71 | | $0.61 | | | 36 | % | | $2.32 | | $1.99 | | $0.33 | | | 17 | % |
Eagle Ford | | 3.07 | | 2.29 | | 0.78 | | | 34 | % | | 3.07 | | 2.47 | | 0.60 | | | 24 | % |
Total production and ad valorem taxes | | $2.53 | | $1.89 | | $0.64 | | | 34 | % | | $2.53 | | $2.14 | | $0.39 | | | 18 | % |
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Gathering, transportation and processing | | | | | | | | | | | | | | | | |
Permian | | $2.54 | | $2.42 | | $0.12 | | | 5 | % | | $2.54 | | $1.87 | | $0.67 | | | 36 | % |
Eagle Ford | | 2.29 | | 2.25 | | 0.04 | | | 2 | % | | 2.29 | | 0.89 | | 1.40 | | | 157 | % |
Total gathering, transportation and processing | | $2.47 | | $2.37 | | $0.10 | | | 4 | % | | $2.47 | | $1.57 | | $0.90 | | | 57 | % |
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| | Three Months Ended | | Three Months Ended |
| | March 31, 2022 | | December 31, 2021 | | $ Change | | % Change | | March 31, 2022 | | March 31, 2021 | | $ Change | | % Change |
Revenues (in thousands) | | | | | | | | | | | | | | | | |
Oil | | | | | | | | | | | | | | | | |
Permian | | $422,404 | | $363,306 | | $59,098 | | | 16 | % | | $422,404 | | $174,967 | | $247,437 | | | 141 | % |
Eagle Ford | | 130,845 | | 143,139 | | (12,294) | | | (9 | %) | | 130,845 | | 92,078 | | 38,767 | | | 42 | % |
Total oil | | 553,249 | | 506,445 | | 46,804 | | | 9 | % | | 553,249 | | 267,045 | | 286,204 | | | 107 | % |
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Natural gas | | | | | | | | | | | | | | | | |
Permian | | 36,069 | | 44,133 | | (8,064) | | | (18 | %) | | 36,069 | | 19,290 | | 16,779 | | | 87 | % |
Eagle Ford | | 7,907 | | 12,541 | | (4,634) | | | (37 | %) | | 7,907 | | 4,930 | | 2,977 | | | 60 | % |
Total natural gas | | 43,976 | | 56,674 | | (12,698) | | | (22 | %) | | 43,976 | | 24,220 | | 19,756 | | | 82 | % |
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NGLs | | | | | | | | | | | | | | | | |
Permian | | 58,563 | | 58,085 | | 478 | | | 1 | % | | 58,563 | | 24,376 | | 34,187 | | | 140 | % |
Eagle Ford | | 9,055 | | 11,697 | | (2,642) | | | (23 | %) | | 9,055 | | 4,981 | | 4,074 | | | 82 | % |
Total NGLs | | 67,618 | | 69,782 | | (2,164) | | | (3 | %) | | 67,618 | | 29,357 | | 38,261 | | | 130 | % |
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Total revenues | | | | | | | | | | | | | | | | |
Permian | | 517,036 | | 465,524 | | 51,512 | | | 11 | % | | 517,036 | | 218,633 | | 298,403 | | | 136 | % |
Eagle Ford | | 147,807 | | 167,377 | | (19,570) | | | (12 | %) | | 147,807 | | 101,989 | | 45,818 | | | 45 | % |
Total revenues | | $664,843 | | $632,901 | | $31,942 | | | 5 | % | | $664,843 | | $320,622 | | $344,221 | | | 107 | % |
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Additional per Boe data | | | | | | | | | | | | | | | | |
Lease operating expense | | | | | | | | | | | | | | | | |
Permian | | $6.85 | | $7.22 | | ($0.37) | | | (5 | %) | | $6.85 | | $4.31 | | $2.54 | | | 59 | % |
Eagle Ford | | 8.99 | | 6.77 | | 2.22 | | | 33 | % | | 8.99 | | 8.65 | | 0.34 | | | 4 | % |
Total lease operating expense | | $7.29 | | $7.11 | | $0.18 | | | 3 | % | | $7.29 | | $5.55 | | $1.74 | | | 31 | % |
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Production and ad valorem taxes | | | | | | | | | | | | | | | | |
Permian | | $3.89 | | $3.15 | | $0.74 | | | 23 | % | | $3.89 | | $2.32 | | $1.57 | | | 68 | % |
Eagle Ford | | 4.82 | | 3.60 | | 1.22 | | | 34 | % | | 4.82 | | 3.07 | | 1.75 | | | 57 | % |
Total production and ad valorem taxes | | $4.08 | | $3.26 | | $0.82 | | | 25 | % | | $4.08 | | $2.53 | | $1.55 | | | 61 | % |
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Gathering, transportation and processing | | | | | | | | | | | | | | | | |
Permian | | $2.33 | | $2.26 | | $0.07 | | | 3 | % | | $2.33 | | $2.54 | | ($0.21) | | | (8 | %) |
Eagle Ford | | 1.92 | | 1.76 | | 0.16 | | | 9 | % | | 1.92 | | 2.29 | | (0.37) | | | (16 | %) |
Total gathering, transportation and processing | | $2.25 | | $2.14 | | $0.11 | | | 5 | % | | $2.25 | | $2.47 | | ($0.22) | | | (9 | %) |
(1) Reflects calendar average daily spot market prices.
Revenues
The following table is intended to reconcilereconciles the changechanges in oil, natural gas, NGLs, and total revenue for the respective period presented by reflecting the effect of changes in volume and in the underlying commodity prices:
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| | Three Months Ended | | |
| | Oil | | Natural Gas | | NGLs | | Total | | | | | | | | |
| | (In thousands) |
Revenues for the period ended in December 31, 2020 (1) | | $222,733 | | $18,561 | | $25,668 | | $266,962 | | | | | | | | | |
Volume increase (decrease) | | (30,546) | | (3,627) | | (5,868) | | (40,041) | | | | | | | | | |
Price increase (decrease) | | 74,858 | | 9,286 | | 9,557 | | 93,701 | | | | | | | | | |
Net increase (decrease) | | 44,312 | | 5,659 | | 3,689 | | 53,660 | | | | | | | | | |
Revenues for the period ended in March 31, 2021 (1) | | $267,045 | | $24,220 | | $29,357 | | $320,622 | | | | | | | | | |
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Percent of total revenues | | 83 | % | | 8 | % | | 9 | % | | | | | | | | | | |
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| | Oil | | Natural Gas | | NGLs | | Total | | | | | | | | |
| | (In thousands) |
Revenues for the three months ended December 31, 2021 (1) | | $506,445 | | $56,674 | | $69,782 | | $632,901 | | | | | | | | | |
Volume increase (decrease) | | (55,535) | | (5,822) | | (6,857) | | (68,214) | | | | | | | | | |
Price increase (decrease) | | 102,339 | | (6,876) | | 4,693 | | 100,156 | | | | | | | | | |
Net increase (decrease) | | 46,804 | | (12,698) | | (2,164) | | 31,942 | | | | | | | | | |
Revenues for the three months ended March 31, 2022 (1) | | $553,249 | | $43,976 | | $67,618 | | $664,843 | | | | | | | | | |
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Percent of total revenues | | 83 | % | | 7 | % | | 10 | % | | | | | | | | | | |
(1) Excludes sales of oil and gas purchased from third parties.parties and sold to our customers.
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| | Three Months Ended March 31, | | |
| | Oil | | Natural Gas | | NGLs | | Total | | | | | | | | |
| | (In thousands) |
Revenues for the period ended in 2020 | | $265,767 | | $6,029 | | $18,123 | | $289,919 | | | | | | | | | |
Volume increase (decrease) | | (52,999) | | (1,205) | | (4,332) | | (58,536) | | | | | | | | | |
Price increase (decrease) | | 54,277 | | 19,396 | | 15,566 | | 89,239 | | | | | | | | | |
Net increase (decrease) | | 1,278 | | 18,191 | | 11,234 | | 30,703 | | | | | | | | | |
Revenues for the period ended in 2021 (1) | | $267,045 | | $24,220 | | $29,357 | | $320,622 | | | | | | | | | |
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Percent of total revenues | | 83 | % | | 8 | % | | 9 | % | | | | | | | | | | |
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| | Oil | | Natural Gas | | NGLs | | Total | | | | | | | | |
| | (In thousands) |
Revenues for the three months ended March 31, 2021 (1) | | $267,045 | | $24,220 | | $29,357 | | $320,622 | | | | | | | | | |
Volume increase | | 66,462 | | 7,048 | | 9,221 | | 82,731 | | | | | | | | | |
Price increase | | 219,742 | | 12,708 | | 29,040 | | 261,490 | | | | | | | | | |
Net increase | | 286,204 | | 19,756 | | 38,261 | | 344,221 | | | | | | | | | |
Revenues for the three months ended March 31, 2022 (1) | | $553,249 | | $43,976 | | $67,618 | | $664,843 | | | | | | | | | |
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Percent of total revenues | | 83 | % | | 7 | % | | 10 | % | | | | | | | | | | |
(1) Excludes sales of oil and gas purchased from third parties.parties and sold to our customers.
Oil revenue
ForRevenues for the three months ended March 31, 2021, oil revenues2022 of $267.0$664.8 million increased $44.3$31.9 million, or 20%5%, compared to revenues of $222.7$632.9 million for the three months ended December 31, 2020.2021. The increase was primarily attributable to a 39%23% increase in the average realized sales price for oil which rose to $57.05$94.64 per Bbl from $41.06$77.13 per Bbl. The increase in average realized price for oil was partially offset by a 9% decrease in production, as discussed above, as well as a 14% decrease in the average realized price for natural gas.
Revenues for the three months ended March 31, 2022 of $664.8 million increased $344.2 million, or 107%, compared to revenues of $320.6 million for the same period of 2021. The increase was primarily attributable to a 66% increase in the average realized sales price was partially offset by a 14% decrease in production primarily as a result of normal production decline and the February 2021 winter storms.
For the three months ended March 31, 2021, oil revenues of $267.0 million increased $1.3 million, or less than 1%, compared to revenues of $265.8 million for the same period of 2020. The slight increase was primarily attributable to a 26% increase in the average realized sales price which rose to $94.64 per Bbl from $57.05 per Bbl from $45.45 per Bbl. Theas well as a 27% increase in the average realized sales price was almost completely offset by a 20% decrease in production primarily as a result of normal production decline and the February 2021 winter storms.
Natural gas revenue
For the three months ended March 31, 2021, natural gas revenues of $24.2 million increased $5.7 million, or 30%, compared to revenues of $18.6 million for the three months ended December 31, 2020. The increase was primarily attributable to the 62% increase in the average realized sales price which rose to $3.09 per Mcf from $1.91 per Mcf. The increase in the average realized sales price was partially offset by a 20% decrease in production primarily as a result of normal production decline and the February 2021 winter storms.
For the three months ended March 31, 2021, natural gas revenues of $24.2 million increased $18.2 million, or 302%, compared to revenues of $6.0 million for the same period of 2020. The increase was primarily attributable to a 398% increase in the average realized sales price which rose to $3.09 per Mcf from $0.62 per Mcf. The increase in the average realized sales price was partially offset by a 20% decrease in production primarily as a result of normal production decline and the February 2021 winter storms.discussed above.
NGL revenue
For the three months ended March 31, 2021, NGL revenues of $29.4 million increased $3.7 million, or 14%, compared to revenues of $25.7 million for three months ended December 31, 2020. The increase was primarily attributable to a 48% increase in the average realized sales price which rose to $22.60 per Bbl from $15.24 per Bbl. The increase in the average realized sales price was partially offset by a 23% decrease in production primarily as a result of normal production decline and the February 2021 winter storms.
For the three months ended March 31, 2021, NGL revenues of $29.4 million increased $11.2 million, or 62%, compared to revenues of $18.1 million for the same period of 2020. The increase was primarily attributable to a 113% increase in the average realized sales price which rose to $22.60 per Bbl from $10.62 per Bbl. The increase in the average realized sales price was partially offset by a 24% decrease in production primarily as a result of normal production decline and the February 2021 winter storms.
Operating Expenses
| | | Three Months Ended | | Three Months Ended |
| | March 31, 2021 | | Per | | December 31, 2020 | | Per | | Total Change | | Boe Change | | March 31, 2022 | | Per | | December 31, 2021 | | Per | | Total Change | | Boe Change |
| | Boe | | Boe | | $ | | % | | $ | | % | | Boe | | Boe | | $ | | % | | $ | | % |
| | (In thousands, except per Boe and % amounts) | | (In thousands, except per Boe and % amounts) |
Lease operating | Lease operating | | $40,453 | | | $5.55 | | | $45,010 | | | $5.15 | | | ($4,557) | | | (10 | %) | | $0.40 | | | 8 | % | Lease operating | | $67,328 | | | $7.29 | | | $73,522 | | | $7.11 | | | ($6,194) | | | (8 | %) | | $0.18 | | | 3 | % |
Production and ad valorem taxes | Production and ad valorem taxes | | 18,439 | | | 2.53 | | | 16,487 | | | 1.89 | | | 1,952 | | | 12 | % | | 0.64 | | | 34 | % | Production and ad valorem taxes | | 37,678 | | | 4.08 | | | 33,693 | | | 3.26 | | | 3,985 | | | 12 | % | | 0.82 | | | 25 | % |
Gathering, transportation and processing | Gathering, transportation and processing | | 17,981 | | | 2.47 | | | 20,694 | | | 2.37 | | | (2,713) | | | (13 | %) | | 0.10 | | | 4 | % | Gathering, transportation and processing | | 20,775 | | | 2.25 | | | 22,083 | | | 2.14 | | | (1,308) | | | (6 | %) | | 0.11 | | | 5 | % |
Depreciation, depletion and amortization | Depreciation, depletion and amortization | | 70,987 | | | 9.74 | | | 96,037 | | | 11.00 | | | (25,050) | | | (26 | %) | | (1.26) | | | (11 | %) | Depreciation, depletion and amortization | | 102,979 | | | 11.15 | | | 112,551 | | | 10.89 | | | (9,572) | | | (9 | %) | | 0.26 | | | 2 | % |
General and administrative | General and administrative | | 16,799 | | | 2.31 | | | 10,614 | | | 1.22 | | | 6,185 | | | 58 | % | | 1.09 | | | 89 | % | General and administrative | | 17,121 | | | 1.85 | | | 13,116 | | | 1.27 | | | 4,005 | | | 31 | % | | 0.58 | | | 46 | % |
Impairment of evaluated oil and gas properties | | — | | | — | | | 585,767 | | | 67.08 | | | (585,767) | | | (100 | %) | | (67.08) | | | (100 | %) | |
Merger and integration | | — | | | — | | | 2,120 | | | 0.24 | | | (2,120) | | | (100 | %) | | (0.24) | | | (100 | %) | |
| Merger, integration and transaction | | Merger, integration and transaction | | 769 | | | 0.08 | | | 11,271 | | | 1.09 | | | (10,502) | | | (93 | %) | | (1.01) | | | (93 | %) |
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| | Three Months Ended March 31, |
| | | | Per | | | | Per | | Total Change | | Boe Change |
| | 2021 | | Boe | | 2020 | | Boe | | $ | | % | | $ | | % |
| | (In thousands, except per Boe and % amounts) |
Lease operating | | $40,453 | | | $5.55 | | | $52,383 | | | $5.70 | | | ($11,930) | | | (23 | %) | | ($0.15) | | | (3 | %) |
Production and ad valorem taxes | | 18,439 | | | 2.53 | | | 19,680 | | | 2.14 | | | (1,241) | | | (6 | %) | | 0.39 | | | 18 | % |
Gathering, transportation and processing | | 17,981 | | | 2.47 | | | 14,378 | | | 1.57 | | | 3,603 | | | 25 | % | | 0.90 | | | 57 | % |
Depreciation, depletion and amortization | | 70,987 | | | 9.74 | | | 131,463 | | | 14.31 | | | (60,476) | | | (46 | %) | | (4.57) | | | (32 | %) |
General and administrative | | 16,799 | | | 2.31 | | | 8,325 | | | 0.91 | | | 8,474 | | | 102 | % | | 1.40 | | | 154 | % |
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Merger and integration | | — | | | — | | | 15,830 | | | 1.72 | | | (15,830) | | | (100 | %) | | (1.72) | | | (100 | %) |
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| | Three Months Ended |
| | March 31, 2022 | | Per | | March 31, 2021 | | Per | | Total Change | | Boe Change |
| | | Boe | | | Boe | | $ | | % | | $ | | % |
| | (In thousands, except per Boe and % amounts) |
Lease operating | | $67,328 | | | $7.29 | | | $40,453 | | | $5.55 | | | $26,875 | | | 66 | % | | $1.74 | | | 31 | % |
Production and ad valorem taxes | | 37,678 | | | 4.08 | | | 18,439 | | | 2.53 | | | 19,239 | | | 104 | % | | 1.55 | | | 61 | % |
Gathering, transportation and processing | | 20,775 | | | 2.25 | | | 17,981 | | | 2.47 | | | 2,794 | | | 16 | % | | (0.22) | | | (9 | %) |
Depreciation, depletion and amortization | | 102,979 | | | 11.15 | | | 70,987 | | | 9.74 | | | 31,992 | | | 45 | % | | 1.41 | | | 14 | % |
General and administrative | | 17,121 | | | 1.85 | | | 16,799 | | | 2.31 | | | 322 | | | 2 | % | | (0.46) | | | (20 | %) |
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Merger, integration and transaction | | 769 | | | 0.08 | | | — | | | — | | | 769 | | | — | % | | 0.08 | | | — | % |
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Lease operating expenses.Operating Expenses. These are daily costs incurred to extract oil, natural gas and NGLs and maintain our producing properties. Such costs also include maintenance, repairs, salt water disposal, insurance and workover expenses related to our oil and natural gas properties.
Lease operating expenses for the three months ended March 31, 20212022 decreased to $40.5$67.3 million compared to $45.0$73.5 million for the three months ended December 31, 2020,2021, primarily due to a 9% decrease in production, volumes decreasing 17%.as discussed above, as well as changing service providers and improving the efficiency of operations, partially offset by an increase in workover expenses as well as an increase in certain operating expenses such as repairs and maintenance. Lease operating expense per Boe for the three months ended March 31, 20212022 increased to $5.55$7.29 compared to $5.15$7.11 for the three months ended December 31, 2020,2021, primarily due to increasedhigher workover costs as well asand the distribution of fixed costs spread over lower production volumes.
Lease operating expenses for the three months ended March 31, 2021 decreased2022 increased to $40.5$67.3 million compared to $52.4$40.5 million for the same period of 2020,2021, primarily due to the increase in production volumes decreasing 21%.from wells acquired in the Primexx Acquisition as well as increases in certain operating expenses such as repairs and maintenance. Lease operating expense per Boe for the three months ended March 31, 2021 decreased2022 increased to $5.55$7.29 compared to $5.70$5.55 for the same period of 20202021, primarily due to improved field practicesthe increase in certain operating expenses as discussed above as well as the increase in certain operating expenses associated with the Primexx Acquisition.
Production and operational efficiencies.
Ad Valorem Taxes. For the three months ended March 31, 2022, production and ad valorem taxes increased 12% to $37.7 million compared to $33.7 million for the three months ended December 31, 2021, which is primarily related to a 5% increase in total revenues which increased production taxes, as well as an increase in ad valorem taxes due to higher expected property tax valuations for the first quarter of 2022 as a result of higher commodity prices during 2021 compared to 2020. Production and ad valorem taxes. In general, severance taxes are based upon current year commodity prices whereasas a percentage of total revenues increased to 5.7% for the first quarter of 2022 as compared to 5.3% of total revenues for the three months ended December 31, 2021, primarily due to an increase in ad valorem taxes are based upon prior year commodity prices. Severance taxes are paid on produced oil and natural gas based on a percentageduring the first quarter of revenues from products sold at fixed rates established by federal, state or local taxing authorities. We benefit from tax credits and exemptions in our various taxing jurisdictions where available and applicable. In the counties where our production is located, we are also subject to ad valorem taxes, which are generally based on the taxing jurisdictions’ valuation of our oil and gas properties.2022 as discussed above.
For the three months ended March 31, 2021,2022, production and ad valorem taxes increased 12%104% to $37.7 million compared to $18.4 million compared to $16.5 million for the three months ended December 31, 2020,same period of 2021, which is primarily related to a 20%107% increase in total revenues which increased production taxes.taxes, as well as an increase in ad valorem taxes as discussed in the paragraph above. Production and ad valorem taxes as a percentage of total revenues decreased to 5.8%5.7% for the first quarter of 2021 as
compared to 6.2% of total revenues for the three months ended December 31, 2020, primarily due to lower expected property tax valuations for the first quarter of 2021 as a result of lower commodity prices during 2020.
For the three months ended March 31, 2021, production and ad valorem taxes decreased 6% to $18.4 million compared to $19.7 million for the same period of 2020, which is primarily related to lower expected property tax valuations for the first quarter of 2021 as a result of lower commodity prices during 2020 compared to higher property tax valuations for the first quarter of 2020 as a result of higher commodity prices during 2019. The impact of the lower expected property tax valuations for the first quarter of 2021 is partially offset by a 11% increase in total revenues which led to higher production taxes. Production and ad valorem taxes as a percentage of total revenues decreased to 5.8% for the first quarter of 20212022, as compared to 6.8%5.8% of total revenues for the same period of 2020, primarily due to lower expected property tax valuations for the first quarter of 2021, as a result of lower commodity prices during 2020.the 107% increase in total revenues was greater than the increase in ad valorem taxes, which does not increase proportionately with revenues.
Gathering, transportationTransportation and processing expensesProcessing Expenses. For the three months ended March 31, 2021,2022, gathering, transportation and processing expenses decreased 13%6% to $18.0$20.8 million compared to $20.7$22.1 million for the three months ended December 31, 2020,2021, which is primarily related to the 17%9% decrease in production volumes between the two periods.
For the three months ended March 31, 2021,2022, gathering, transportation and processing expenses increased 25%16% to $18.0$20.8 million compared to $14.4$18.0 million for the same period of 2020,2021, which iswas primarily related to new oil transportation agreements which were executed subsequent to the three months ended March 31, 2020.27% increase in production volumes between the two periods.
Depreciation, depletionDepletion and amortizationAmortization (“DD&A”). Under the full cost accounting method, we capitalize costs within a cost center and then systematically amortize those costs on an equivalent unit-of-production method based on production and estimated proved oil and gas reserve quantities. Depreciation of other property and equipment is computed using the straight line method over their estimated useful lives, which range from three to twenty years. The following table sets forth the components of our depreciation, depletion and amortizationDD&A for the periods indicated:
| | | Three Months Ended | | Three Months Ended March 31, | | | Three Months Ended | | Three Months Ended | |
| | March 31, 2021 | | December 31, 2020 | | 2021 | | 2020 | | | March 31, 2022 | | December 31, 2021 | | March 31, 2022 | | March 31, 2021 | |
| | Amount | | Per Boe | | Amount | | Per Boe | | Amount | | Per Boe | | Amount | | Per Boe | | | Amount | | Per Boe | | Amount | | Per Boe | | Amount | | Per Boe | | Amount | | Per Boe | |
| | (In thousands, except per Boe) | | (In thousands, except per Boe) |
DD&A of evaluated oil and gas properties | DD&A of evaluated oil and gas properties | | $68,705 | | | $9.43 | | | $93,721 | | | $10.73 | | | $68,705 | | | $9.43 | | | $129,436 | | | $14.09 | | | DD&A of evaluated oil and gas properties | | $100,763 | | | $10.91 | | | $110,169 | | | $10.66 | | | $100,763 | | | $10.91 | | | $68,705 | | | $9.43 | | |
Depreciation of other property and equipment | Depreciation of other property and equipment | | 516 | | | 0.07 | | | 640 | | | 0.07 | | | 516 | | | 0.07 | | | 943 | | | 0.10 | | | Depreciation of other property and equipment | | 476 | | | 0.05 | | | 473 | | | 0.05 | | | 476 | | | 0.05 | | | 516 | | | 0.07 | | |
Amortization of other assets | Amortization of other assets | | 839 | | | 0.11 | | | 854 | | | 0.10 | | | 839 | | | 0.11 | | | 262 | | | 0.03 | | | Amortization of other assets | | 780 | | | 0.08 | | | 980 | | | 0.09 | | | 780 | | | 0.08 | | | 839 | | | 0.11 | | |
Accretion of asset retirement obligations | Accretion of asset retirement obligations | | 927 | | | 0.13 | | | 822 | | | 0.10 | | | 927 | | | 0.13 | | | 822 | | | 0.09 | | | Accretion of asset retirement obligations | | 960 | | | 0.11 | | | 929 | | | 0.09 | | | 960 | | | 0.11 | | | 927 | | | 0.13 | | |
DD&A | DD&A | | $70,987 | | | $9.74 | | | $96,037 | | | $11.00 | | | $70,987 | | | $9.74 | | | $131,463 | | | $14.31 | | | DD&A | | $102,979 | | | $11.15 | | | $112,551 | | | $10.89 | | | $102,979 | | | $11.15 | | | $70,987 | | | $9.74 | | |
|
For the three months ended March 31, 2021,2022, DD&A decreased to $71.0$103.0 million from $96.0$112.6 million for the three months ended December 31, 2020. The decrease in DD&A was primarily related to DD&A of evaluated oil and gas properties, which was2021 primarily attributable to a production decrease of 17% and lower DD&A rates between the periods. For the three months ended March 31, 2021, DD&A per Boe decreased to $9.74 compared to $11.00 for the three months ended December 31, 2020, primarily as a result of the impairment of evaluated oil and gas properties that was recognized during the three months ended December 31, 2020.9%.
For the three months ended March 31, 2021,2022, DD&A decreasedincreased to $71.0$103.0 million from $131.5$71.0 million for the same period in 2020. The decrease in DD&A was primarily related to DD&A of evaluated oil and gas properties, which was2021 primarily attributable to a production decreaseincrease of 21% and lower DD&A rates between27% as well as the periods. Foraddition of properties acquired in the three months ended March 31, 2021, DD&A per Boe decreased to $9.74 compared to $14.31 for the same period in 2020, primarily as a result of the impairments of evaluated oil and gas properties that were recognized during 2020.Primexx Acquisition.
General and administrative, netAdministrative, Net of amounts capitalizedAmounts Capitalized (“G&A”). G&A for the three months ended March 31, 20212022 increased to $16.8$17.1 million compared to $10.6$13.1 million for the three months ended December 31, 2020,2021, primarily as a result ofdue to an increase in the fair value of Cash-Settled RSU Awards and Cash SARs due toas a result of the increase in our stock price duringbetween the first quarter of 2021.two periods.
G&A for the three months ended March 31, 20212022 increased to $16.8$17.1 million compared to $8.3$16.8 million for the same period in 20202021 primarily due to an increase in compensation costs as we increased headcount during 2021, partially offset by a reduction in expense associated with the Cash-Settled RSU Awards and Cash SARs as a result of a smaller increase in the fair value associated with these awards during the first quarter of 2022 as compared to the same reason discussed above.
Impairment of evaluated oil and gas properties. We did not recognize an impairment of evaluated oil and gas properties for the three months ended March 31, 2021, compared to an impairment of evaluated oil and gas properties of $585.8 million for the three months ended December 31, 2020, which was due primarily to declinesperiod in the 12-Month Average Realized Price of crude oil. There was no impairment of evaluated oil and gas properties for the three months ended March 31, 2020. See “Note 3 - Property and Equipment, Net” for further discussion.
Merger and integration expense. For the three months ended March 31, 2021, the Company incurred no merger and integration expenses compared to $2.1 million and $15.8 million for the three months ended December 31, 2020 and March 31, 2020, respectively, which were related to the Carrizo Acquisition.2021.
Other Income and Expenses
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended | | Three Months Ended March 31, |
| | March 31, 2021 | | December 31, 2020 | | $ Change | | % Change | | 2021 | | 2020 | | $ Change | | % Change |
| | (In thousands, except % amounts) |
Interest expense | | $48,454 | | | $49,501 | | | ($1,047) | | | (2 | %) | | $48,454 | | | $44,463 | | | $3,991 | | | 9 | % |
Capitalized interest | | (24,038) | | | (23,015) | | | (1,023) | | | 4 | % | | (24,038) | | | (23,985) | | | (53) | | | — | % |
Interest expense, net of capitalized amounts | | 24,416 | | | 26,486 | | | (2,070) | | | (8 | %) | | 24,416 | | | 20,478 | | | 3,938 | | | 19 | % |
(Gain) loss on derivative contracts | | $214,523 | | | $125,739 | | | $88,784 | | | 71 | % | | $214,523 | | | ($251,969) | | | $466,492 | | | (185 | %) |
Interest expense, netExpense, Net of capitalized amountsCapitalized Amounts.. We finance a portion of our capital expenditures, acquisitions and working capital requirements with borrowings under our Credit Facility or with term debt. We incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. We reflect interest paid to our lender in interest expense, net of capitalized amounts. In addition, we include the amortization of deferred financing costs (including origination and amendment fees), commitment fees and annual agency fees, and interest from our financing leases in interest expense. The following table sets forth the components of our interest expense, net of capitalized amounts for the periods indicated:
| | | Three Months Ended | | Three Months Ended March 31, | | Three Months Ended | | Three Months Ended |
| | March 31, 2021 | | December 31, 2020 | | $ Change | | 2021 | | 2020 | | $ Change | | March 31, 2022 | | December 31, 2021 | | Change | | March 31, 2022 | | March 31, 2021 | | Change |
| | (In thousands) | | (In thousands) |
Interest expense on Senior Unsecured Notes | | Interest expense on Senior Unsecured Notes | | $29,022 | | | $29,022 | | | $— | | | $29,022 | | | $24,502 | | | $4,520 | |
Interest expense on Second Lien Notes | | Interest expense on Second Lien Notes | | 7,192 | | | 8,916 | | | (1,724) | | | 7,192 | | | 11,625 | | | (4,433) | |
Interest expense on Credit Facility | Interest expense on Credit Facility | | $7,817 | | | $8,411 | | | ($594) | | | $7,817 | | | $12,574 | | | ($4,757) | | Interest expense on Credit Facility | | 7,110 | | | 8,613 | | | (1,503) | | | 7,110 | | | 7,817 | | | (707) | |
Interest expense on Second Lien Notes | | 11,625 | | | 9,188 | | | 2,437 | | | 11,625 | | | — | | | 11,625 | | |
Interest expense on Senior Unsecured Notes | | 24,502 | | | 27,688 | | | (3,186) | | | 24,502 | | | 30,875 | | | (6,373) | | |
Amortization of debt issuance costs, premiums and discounts | Amortization of debt issuance costs, premiums and discounts | | 4,478 | | | 4,176 | | | 302 | | | 4,478 | | | 948 | | | 3,530 | | Amortization of debt issuance costs, premiums and discounts | | 3,750 | | | 4,235 | | | (485) | | | 3,750 | | | 4,478 | | | (728) | |
Other interest expense | Other interest expense | | 32 | | | 38 | | | (6) | | | 32 | | | 66 | | | (34) | | Other interest expense | | 22 | | | 32 | | | (10) | | | 22 | | | 32 | | | (10) | |
Capitalized interest | Capitalized interest | | (24,038) | | | (23,015) | | | (1,023) | | | (24,038) | | | (23,985) | | | (53) | | Capitalized interest | | (25,538) | | | (25,592) | | | 54 | | | (25,538) | | | (24,038) | | | (1,500) | |
Interest expense, net of capitalized amounts | Interest expense, net of capitalized amounts | | $24,416 | | | $26,486 | | | ($2,070) | | | $24,416 | | | $20,478 | | | $3,938 | | Interest expense, net of capitalized amounts | | $21,558 | | | $25,226 | | | ($3,668) | | | $21,558 | | | $24,416 | | | ($2,858) | |
Interest expense, net of capitalized amounts, incurred during the three months ended March 31, 20212022 decreased $2.1$3.7 million to $24.4$21.6 million compared to $26.5$25.2 million for the three months ended December 31, 2020.2021. The decrease is primarily due to a decrease in borrowings on the Credit Facility, lower average principal balances on our Senior Unsecured Notes as a portion was exchanged for Second Lien Notes during the three months ended December 31, 2020, as well as an increase in capitalized interest. The decrease in interest expense was offset by an increasereduction in interest expense associated with the Second Lien Notes which wereas a result of our exchange of $197.0 million of our outstanding duringSecond Lien Notes for a notional amount of approximately $223.1 million of our common stock in November 2021, as well as lower borrowings on the entire first quarter ofCredit Facility compared to the three months ended December 31, 2021.
Interest expense, net of capitalized amounts, incurred during the three months ended March 31, 2021 increased $3.92022 decreased $2.9 million to $24.4$21.6 million compared to $20.5$24.4 million for the same period of 2020.2021. The increasedecrease is primarily due to the issuance of the Second Lien Notesreduction in exchange for a portion of our outstanding Senior Unsecured Notes during the three months ended December 31, 2020 as well as amortization of the discountinterest expense associated with the Second Lien Notes offset by the reduction in Senior Unsecured Notes outstanding as a result of the exchange anddiscussed above, lower borrowings on the Credit Facility duringcompared to the same period of 2020.
(Gain) loss on derivative contracts. We utilize commodity derivative financial instruments to reduce our exposure to fluctuations2021 and an increase in commodity prices. This amount represents the (i) (gain) losscapitalized interest, partially offset by an increase in interest expense related to fair value adjustments on our open derivative contracts and (ii)the issuance of the 8.00% Senior Notes in July 2021.
(gains) losses(Gain) Loss on settlements of derivative contracts for positions that have settled within the period.Derivative Contracts. The net (gain) loss on derivative instrumentscontracts for the periods indicated includes the following:
| | | Three Months Ended | | Three Months Ended March 31, | | Three Months Ended | | Three Months Ended | |
| | March 31, 2021 | | December 31, 2020 | | 2021 | | 2020 | | | March 31, 2022 | | December 31, 2021 | | March 31, 2022 | | March 31, 2021 | |
| | (In thousands) | | | (In thousands) | |
(Gain) loss on oil derivatives | | $149,561 | | | $70,317 | | | $149,561 | | | ($257,323) | | | |
Loss on oil derivatives | | Loss on oil derivatives | | $325,348 | | | $35,364 | | | $325,348 | | | $149,561 | | |
(Gain) loss on natural gas derivatives | (Gain) loss on natural gas derivatives | | 2,697 | | | (3,936) | | | 2,697 | | | 6,829 | | | (Gain) loss on natural gas derivatives | | 28,181 | | | (14,918) | | | 28,181 | | | 2,697 | | |
(Gain) loss on NGL derivatives | (Gain) loss on NGL derivatives | | 1,138 | | | 8 | | | 1,138 | | | — | | | (Gain) loss on NGL derivatives | | 4,771 | | | (8,346) | | | 4,771 | | | 1,138 | | |
(Gain) loss on contingent consideration arrangements | (Gain) loss on contingent consideration arrangements | | 5,737 | | | 3,831 | | | 5,737 | | | (1,475) | | | (Gain) loss on contingent consideration arrangements | | — | | | (1,955) | | | — | | | 5,737 | | |
(Gain) loss on September 2020 Warrants liability | | 55,390 | | | 55,519 | | | 55,390 | | | — | | | |
(Gain) loss on derivative contracts | | $214,523 | | | $125,739 | | | $214,523 | | | ($251,969) | | | |
Loss on September 2020 Warrants liability | | Loss on September 2020 Warrants liability | | — | | | — | | | — | | | 55,390 | | |
Loss on derivative contracts | | Loss on derivative contracts | | $358,300 | | | $10,145 | | | $358,300 | | | $214,523 | | |
See “Note 67 - Derivative Instruments and Hedging Activities” and “Note 78 - Fair Value Measurements” for additional information.
Income tax expense.Tax Expense. We use the asset and liability methodrecorded income tax expense of accounting for$0.5 million compared to income taxes, under which deferred tax assets and liabilities are recognizedbenefit of $0.8 million for the future tax consequences of (1) temporary differences between the financial statement carrying amountsthree months ended March 31, 2022 and the tax bases of existing assets and liabilities and (2) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period the rate change is enacted. When appropriate, based on our analysis, we record a valuation allowance for deferred tax assets when it is more likely than not that the deferred tax assets will not be realized.December 31, 2021, respectively.
We recorded anincome tax expense of $0.5 million compared to income tax benefit of $0.9 million for the three months ended March 31, 2022 and 2021, compared to income tax expense of $6.8 million forrespectively.
Since the three months ended December 31, 2020. The decrease in income tax expense is due to an increase in the fourthsecond quarter of 2020, inwe have concluded that it is more likely than not that the deferred tax assets acquired in the Carrizo Acquisition due to the filing of the final tax returns which provided the underlying tax basis of Carrizo’s assets and liabilities and the subsequent valuation allowance against those deferred tax assets.
As a result of the valuation allowance that we recorded against our net deferred tax assets will not be realized and have recorded a full valuation allowance against our deferred tax assets. As long as we recorded an income tax benefit of $0.9 million forcontinue to conclude that the three months ended March 31, 2021 comparedvaluation allowance is necessary, we do not expect to anhave significant deferred income tax expense of $64.0 million for the same period of 2020.or benefit. See “Note 89 - Income Taxes” for further discussion.
Liquidity and Capital Resources
2022 Outlook. Oil prices steadily increased throughout 2021 and into the first quarter of 2022, reaching a 13-year high in March 2022. As a result of a corresponding increase in industry drilling and completion activity over that period, combined with the supply chain and labor constraints, we have begun to experience inflationary cost pressures on many different service items including labor, materials, and equipment. We expect to continue to face inflationary pressure throughout the remainder of 2022.
2022 Capital Budget and Funding Strategy. Our primary uses of capital are for the exploration and development of our oil and natural gas properties. Our 2021 Capital Budget2022 capital budget has been established at up to $430.0$725.0 million, with approximately 80% directed towards drilling, completion, and equipment expenditures. Approximately 70% of the 2021 Capital Budget isover 85% allocated towards development in the Permian with the remaining 30%balance towards development in the Eagle Ford. As part of our 2021 operated horizontal drilling program, we expect to drill approximately 55 to 65 gross operated wells and complete approximately 90 to 100 gross operated wells.
During the three months ended March 31, 2021, we drilled 18 gross (16.4 net) and completed 19 gross (18.0 net) wells approximately evenly split between the Permian and Eagle Ford in each category, effectively maintaining the drilled but uncompleted inventory that we had as of December 31, 2020. We expect to operate an average of three drilling rigs throughout the remainder of 2021 and will average just over two completion crews through the second quarter before reducing to a single completion crew during the third quarter.
The following table is a summary of our capital expenditures(1) for the three months ended March 31, 2021:
| | | | | | | | |
| | Three Months Ended March 31, 2021 |
| | (In millions) |
Operational capital | | $95.6 | |
Capitalized interest | | 24.0 | |
Capitalized G&A | | 11.2 | |
Total | | $130.8 | |
(1) Capital expenditures, presented on an accrual basis, includes drilling, completions, facilities, and equipment, but excludes land, seismic, and asset retirement costs.
We continually evaluate our capital expenditure needs and compare them to our capital resources. Because we are the operator of a high percentage of our properties, we can control the amount and timing of our capital expenditures. We can chooseplan to defer or accelerateexecute a portionmoderated capital expenditure program through reduced reinvestment rates and balanced capital deployment for a more consistent cash flow generation and will be focused to further enhance our multi-zone, scaled development program to drive capital efficiency.
The following table is a summary of our plannedcapital expenditures(1) for the three months ended March 31, 2022:
| | | | | | | | | | | | | | |
| | Three Months Ended | | |
| | March 31, 2022 | | | | | | |
| | (In millions) |
Operational capital | | $157.4 | | | | | | | |
Capitalized interest | | 25.5 | | | | | | | |
Capitalized G&A | | 11.6 | | | | | | | |
Total | | $194.5 | | | | | | | |
(1) Capital expenditures, presented on an accrual basis, includes drilling, completions, facilities, and equipment, and excludes land, seismic, and asset retirement costs.
We believe that existing cash and cash equivalents, any positive cash flows from operations and available borrowings under our revolving credit facility will be sufficient to support working capital, capital expenditures dependingand other cash requirements for at least the next 12 months and, based on variousour current expectations, for the foreseeable future thereafter. Our future capital requirements, both near-term and long-term, will depend on many factors, including, but not limited to, depressed commodity prices, market conditions, our available liquidity and financing, acquisitions and divestitures of oil and gas properties, the availability of drilling rigs and completion crews, the cost of completion services, success of drilling programs, land and industry partner issues, weather delays, the acquisition of leases with drilling commitments, and other factors. We plan to execute a more
moderated capital expenditure program through reduced reinvestment rates and balanced capital deployment for a more consistent cash flow generation and will be focused to further enhance our multi-zone, scale development program while leveraging a robust drilled, but uncompleted backlog to drive capital efficiency.
Historically, our primary sources of capital have been cash flows from operations, borrowings under our Credit Facility, proceeds from the issuance of debt securities and public equity offerings, and non-core asset dispositions. We regularly consider which resources, including debt and equity financings, are available to meet our future financial obligations, planned capital expenditures and
liquidity requirements. In addition, dependingwe may consider divesting certain properties or assets that are not part of our core business or are no longer deemed essential to our future growth or enter into joint venture agreements, provided we are able to divest such assets or enter into joint venture agreements on terms that are acceptable to us.
Depending upon our actual and anticipated sources and uses of liquidity, prevailing market conditions and other factors, we may, from time to time, seek to retire or repurchase our outstanding debt or equity securities through cash purchases in the open market or through privately negotiated transactions or otherwise. The amounts involved in any such transactions, individually or in aggregate, may be material.
We also may consider divesting certain properties or assets that are not part of our core business or are no longer deemed essential to our future growth or enter into joint venture agreements, provided we are able to divest such assets or enter into joint venture agreements on terms that are acceptable to us.
CommodityPrices
Prices of oil, natural gas, and NGLs remain volatile and will affect the following aspects of our business:
•our revenues, cash flows and earnings;
•the amount of oil and natural gas that we are economically able to produce;
•our ability to attract capital to finance our operations and cost of the capital;
•the amount we are allowed to borrow under the Credit Facility; and
•the value of our oil and natural gas properties.
Overview of Cash Flow Activities. For the three months ended March 31, 2021,2022, cash and cash equivalents increased $4.2decreased $5.7 million to $24.4$4.2 million compared to $20.2$9.9 million at December 31, 2020.2021.
| | | Three Months Ended March 31, | | Three Months Ended March 31, |
| | 2021 | | 2020 | | 2022 | | 2021 |
| | (In thousands) | | (In thousands) |
Net cash provided by operating activities | Net cash provided by operating activities | | $137,665 | | | $191,695 | | Net cash provided by operating activities | | $281,270 | | | $137,665 | |
Net cash used in investing activities | Net cash used in investing activities | | (98,514) | | | (254,366) | | Net cash used in investing activities | | (221,939) | | | (98,514) | |
Net cash provided by (used in) financing activities | | (35,037) | | | 64,130 | | |
Net cash used in financing activities | | Net cash used in financing activities | | (65,063) | | | (35,037) | |
Net change in cash and cash equivalents | Net change in cash and cash equivalents | | $4,114 | | | $1,459 | | Net change in cash and cash equivalents | | ($5,732) | | | $4,114 | |
Operating activities.Activities. For the three months ended March 31, 2021,2022, net cash provided by operating activities was $137.7$281.3 million compared to $191.7$137.7 million for the same period in 2020.2021. The change in net cash provided by operating activities was predominantly attributable to the following:
•A decrease in the cash received from commodity derivative settlements,
•Changes in working capital as accounts receivable has increased from December 31, 2020 as a result of the increase in the price of oil,
•An offsetting increase in revenue primarily driven by a 26%66% increase in realized oil price, partially offset byas well as a decrease27% increase in production volumes, and
•An offsetting decreaseincrease in operating expenses as a result of lower production volumes as well as our continued improvement of managing our field operating costs.the cash paid for commodity derivative settlements.
Production, realized prices, and operating expenses are discussed in Results of Operations. See “Note 67 - Derivative Instruments and Hedging Activities” and “Note 78 - Fair Value Measurements” for a reconciliation of the components of our derivative contracts and disclosures related to derivative instruments including their composition and valuation.
Investing activities.Activities. For the three months ended March 31, 2021,2022, net cash used in investing activities was $98.5$221.9 million compared to $254.4$98.5 million for the same period in 2020.2021. The decreaseincrease in net cash used in investing activities was primarily attributed to the following:
•A decreaseAn increase in operational capex, in the first quarter of 2021 compared to the same period in 2020, and
•A decreaseAn increase in cash paid for the settlement of contingent consideration agreements as neta cash paymentspayment of $40.0$19.2 million werewas paid in January 2020 related to contingent considerations acquired in the Carrizo Acquisition.2022.
Financing activities.Activities. We finance a portion of our capital expenditures, acquisitions and working capital requirements with borrowings under the Credit Facility, term debt and equity offerings. For the three months ended March 31, 2021,2022, net cash used in financing activities was $35.0$65.1 million compared to net cash provided by financing activities of $64.1$35.0 million for the same period of 2020.2021. This change was primarily attributable to repayment of approximately $35.0$73.0 million on the Credit Facility during the three months ended March 31, 2021,2022, which reflects our continued commitment and focus on deleveraging.
See “Note 5 - Borrowings” for additional information on our debt transactions.
Contractual Obligations. Our contractual obligations primarily consist of long-term debt, operating leases, asset retirement obligations, produced water disposal commitments, and gathering, processing and transportation service commitments. Since December 31, 2020, there have been no material changes to our contractual obligations other than the changes to the borrowings under our Credit Facility as discussed further in “Note 5 - Borrowings”.
Credit Facility. As of March 31, 2021,2022, our Credit Facility had a borrowing base of $1.6 billion, with an elected commitment amount of $1.6 billion, borrowings outstanding of $950.0$712.0 million at a weighted average interest rate of 2.62%2.74%, and $24.0$23.0 million in letters of credit outstanding. The borrowing base under the credit agreement is subject to regular redeterminations inOn May 2, 2022, as a result of the spring and fall of each year, as well as special redeterminations described in the credit agreement, which in each case may reduce the amount of the borrowing base. The Credit Facility is secured by first preferred mortgages covering our major producing properties. Upon a2022 redetermination, if any borrowings in excess of the revised borrowing base were outstanding, we could be forced to immediately repay a portion of the borrowings outstanding under the credit agreement. On May 3, 2021, the Company entered into the fourth amendment to its credit agreement governing the Credit Facility which, among other things, reaffirmed the borrowing base and elected commitment amount of $1.6 billion as a result of the spring 2021 scheduled redetermination.were reaffirmed.
Our Credit Facility contains certain covenants including restrictions on additional indebtedness, payment of cash dividends and maintenance of certain financial ratios. Under the Credit Facility, we must maintain the following financial covenants determined as of the last day of the quarter, each as described above:quarter: (1) a Secured Leverage Ratio of no more than 3.004.00 to 1.00 and (2) a Current Ratio of not less than 1.00 to 1.00. We were in compliance with these covenants at March 31, 2021. If the commodity price environment reverted back to levels the industry saw in 2020 and were to persist for an extended period, our ability to remain in compliance with our restrictive financial covenants could be challenged. If we are unable to remain in compliance with our restrictive financial covenants, we could be subject to lender elections for default resolution. However, we expect to have sufficient liquidity to pay interest on our Credit Facility (as well as on the Second Lien Notes and our Senior Unsecured Notes and to fund our development program).2022.
The Credit Facility also places restrictions on us and certain of our subsidiaries with respect to additional indebtedness, liens, dividends and other payments to shareholders, repurchases or redemptions of our common stock, redemptions of senior notes, investments, acquisitions, mergers, asset dispositions, transactions with affiliates, hedging transactions and other matters.
See “Note 56 – Borrowings” for additional information related to the Credit FacilityFacility.
Material Cash Requirements. As of March 31, 2022, we have financial obligations associated with our outstanding long-term debt, including interest payments and principal repayments. See “Note 147 - Subsequent Events”Borrowings” of the Notes to Consolidated Financial Statements in our 2021 Annual Report for further discussion of the fourth amendment tocontractual commitments under our debt agreements, including the credit agreement governing the Credit Facility.
timing of
principal repayments. Additionally, we have operational obligations associated with long-term, non-cancelable leases, drilling rig contracts, frac service contracts, gathering, processing and transportation service agreements and estimates of future asset retirement obligations. See “Note 14 - Asset Retirement Obligations” and “Note 17 - Commitments and Contingencies” of the Notes to Consolidated Financial Statements in our 2021 Annual Report for additional details.
Hedging. As of April 30, 2021, the Company had the following outstanding oil, natural gas and NGL derivative contracts:
| | | | | | | | | | | | | | | | | | | | |
| For the Remainder | | | For the Full Year | | | | |
Oil contracts (WTI) | of 2021 | | | of 2022 | | | | |
Swap contracts | | | | | | | | |
Total volume (Bbls) | 1,832,000 | | | | 225,000 | | | | | |
Weighted average price per Bbl | $43.24 | | | | $60.00 | | | | | |
Collar contracts | | | | | | | | |
Total volume (Bbls) | 8,298,800 | | | | 2,032,500 | | | | | |
Weighted average price per Bbl | | | | | | | | |
Ceiling (short call) | $48.30 | | | | $61.11 | | | | | |
Floor (long put) | $40.24 | | | | $47.22 | | | | | |
Short call contracts | | | | | | | | |
Total volume (Bbls) | 2,432,480 | | (1) | | — | | | | | |
Weighted average price per Bbl | $63.62 | | | | $— | | | | | |
Short call swaption contracts | | | | | | | | |
Total volume (Bbls) | — | | | | 1,825,000 | | (2) | | | |
Weighted average price per Bbl | $— | | | | $52.18 | | | | | |
| | | | | | | | |
Oil contracts (Brent ICE) | | | | | | | | |
Swap contracts | | | | | | | | |
Total volume (Bbls) | 221,300 | | (3) | | — | | | | | |
Weighted average price per Bbl | $37.35 | | | | $— | | | | | |
Collar contracts | | | | | | | | |
Total volume (Bbls) | 550,000 | | | | — | | | | | |
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) | 2,171,900 | | | | — | | | | | |
Weighted average price per Bbl | $0.24 | | | | $— | | | | | |
| | | | | | | | |
Oil contracts (Argus Houston MEH) | | | | | | | | |
Collar contracts | | | | | | | | |
Total volume (Bbls) | 409,500 | | | | 452,500 | | | | | |
Weighted average price per Bbl | | | | | | | | |
Ceiling (short call) | $47.00 | | | | $63.15 | | | | | |
Floor (long put) | $41.00 | | | | $51.25 | | | | | |
(1) Premiums from the sale of call options were used to increase the fixed price of certain simultaneously executed price swaps and three-way collars.
(2) The short call swaption contracts have an exercise expiration date ofSince December 31, 2021.
(3) In February 2021, there have been no material changes from what was disclosed in our 2021 Annual Report other than the Company entered into certain offsetting ICE Brent swapschanges to reduce its exposure to rising oil prices. Those offsetting swaps resulted in a locked-in lossthe borrowings under our Credit Facility as well as an amended frac service contract through the remainder of 2022 for 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) | 11,123,000 | | | | — | | | | | |
Weighted average price per MMBtu | $2.60 | | | | $— | | | | | |
Collar contracts | | | | | | | | |
Total volume (MMBtu) | 5,500,000 | | | | 2,700,000 | | | | | |
Weighted average price per MMBtu | | | | | | | | |
Ceiling (short call) | $2.80 | | | | $3.75 | | | | | |
Floor (long put) | $2.50 | | | | $2.77 | | | | | |
Short call contracts | | | | | | | | |
Total volume (MMBtu) | 5,500,000 | | (1) | | — | | | | | |
Weighted average price per MMBtu | $3.09 | | | | $— | | | | | |
| | | | | | | | |
Natural gas contracts (Waha basis differential) | | | | | | | | |
Swap contracts | | | | | | | | |
Total volume (MMBtu) | 12,375,000 | | | | 5,475,000 | | | | | |
Weighted average price per MMBtu | ($0.42) | | | | ($0.21) | | | | | |
(1) Premiums from the sale of call options were used to increase the fixed price of certain simultaneously executed price swaps and three-way collars.
| | | | | | | | | | | | | | | | | | | | |
| For the Remainder | | | For the Full Year | | | | |
NGL contracts (OPIS Mont Belvieu Purity Ethane) | of 2021 | | | of 2022 | | | | |
Swap contracts | | | | | | | | |
Total volume (Bbls) | 1,375,000 | | | | — | | | | | |
Weighted average price per Bbl | $7.62 | | | | $— | | | | | |
$30.0 million.
Critical Accounting PoliciesEstimates
The preparation of financial statements in conformity with GAAP requires management to make judgments affecting estimates and assumptions that affect thefor reported amounts of assets, and liabilities, and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the periods reported. Certain of such estimates and assumptions are inherently unpredictable and will differ from actual results. We have identified the following critical accountingOur policies and estimates used in the preparation of our financial statements: use of estimates, oil and gas properties, oil and gas reserve estimates, derivative instruments, contingent consideration arrangements, income taxes, and commitments and contingencies. These policies and estimates are described in “Note 2 - Summary of Significant Accounting Policies” of the Notes to Consolidated Financial Statements in our 20202021 Annual Report. See “Note 6 - Derivative InstrumentsExcept as set forth below, there have been no material changes to our critical accounting estimates since December 31, 2021, which are disclosed in “Part II, Item 7A. Management’s Discussion and Hedging Activities”Analysis of Financial Condition and “Note 7 - Fair Value Measurements” for detailsResults of the contingent consideration arrangements. We evaluate subsequent events through the date the financial statements are issued.Operations” of our 2021 Annual Report
Oil and Natural Gas PropertiesThe table below presents various pricing scenarios to demonstrate the sensitivity of our March 31, 20212022 cost center ceiling to changes in 12-month average benchmark crude oil and natural gas prices underlying the 12-month average realized prices.12-Month Average Realized Prices. The sensitivity analysis is as of March 31, 20212022 and, accordingly, does not consider drilling and completion activity, acquisitions or dispositions of oil and gas properties, production, changes in crude oil and natural gas prices, and changes in development and operating costs occurring subsequent to March 31, 20212022 that may require revisions to estimates of proved reserves. See also “Part I, Item 1A. Risk Factors—If oil and natural gas prices remain depressed for extended periods of time, we may be required to make significant downward adjustments to the carrying value of our oil and natural gas properties” in our 20202021 Annual Report.
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 12-Month Average Realized Prices | | Excess (deficit) of cost center ceiling over net book value, less related deferred income taxes | | Increase (decrease) of cost center ceiling over net book value, less related deferred income taxes |
Full Cost Pool Scenarios | | Crude Oil ($/Bbl) | | Natural Gas ($/Mcf) | | (In millions) | | (In millions) |
March 31, 2021 Actual | | $37.51 | | $1.31 | | $89 | | |
| | | | | | | | |
Crude Oil and Natural Gas Price Sensitivity | | | | | | | | |
Crude Oil and Natural Gas +10% | | $41.51 | | $1.53 | | $612 | | $523 |
Crude Oil and Natural Gas -10% | | $33.52 | | $1.09 | | ($552) | | ($641) |
| | | | | | | | |
Crude Oil Price Sensitivity | | | | | | | | |
Crude Oil +10% | | $41.51 | | $1.31 | | $568 | | $479 |
Crude Oil -10% | | $33.52 | | $1.31 | | ($496) | | ($585) |
| | | | | | | | |
Natural Gas Price Sensitivity | | | | | | | | |
Natural Gas +10% | | $37.51 | | $1.53 | | $133 | | $44 |
Natural Gas -10% | | $37.51 | | $1.09 | | $45 | | ($44) |
Income taxes
The amount of income taxes recorded requires interpretations of complex rules and regulations of federal and state tax jurisdictions. We recognize current tax expense based on estimated taxable income for the current period and the applicable statutory tax rates. We routinely assess potential uncertain tax positions and, if required, estimate and establish accruals for such amounts. We have recognized deferred tax assets and liabilities for temporary differences, operating losses and other tax carryforwards.
Management monitors company-specific, oil and natural gas industry and worldwide economic factors and assesses the likelihood that
our net deferred tax assets will be utilized prior to their expiration. A significant item of objective negative evidence considered was the cumulative historical three year pre-tax loss and a net deferred tax asset position at March 31, 2021, driven primarily by impairments of evaluated oil and gas properties recognized beginning in the second quarter of 2020 and continuing through the fourth quarter of 2020, which limits the ability to consider other subjective evidence such as our potential for future growth. Since the second quarter of 2020, based on the evaluation of the evidence available, we concluded that it is more likely than not that the net deferred tax assets will not be realized. As a result, we recorded a valuation allowance, reducing the net deferred tax assets as of March 31, 2021 to zero.
We will continue to evaluate whether the valuation allowance is needed in future reporting periods. The valuation allowance will remain until we can conclude that the net deferred tax assets are more likely than not to be realized. Future events or new evidence which may lead us to conclude that it is more likely than not our net deferred tax assets will be realized include, but are not limited to, cumulative historical pre-tax earnings, improvements in crude oil prices, and taxable events that could result from one or more transactions. The valuation allowance does not preclude us from utilizing the tax attributes if we recognize taxable income. As long as we continue to conclude that the valuation allowance against our net deferred tax assets is necessary, we will have no significant deferred income tax expense or benefit. See “Note 8 - Income Taxes” for additional discussion. | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 12-Month Average Realized Prices | | Excess (deficit) of cost center ceiling over net book value, less related deferred income taxes | | Increase (decrease) of cost center ceiling over net book value, less related deferred income taxes |
Full Cost Pool Scenarios | | Crude Oil ($/Bbl) | | Natural Gas ($/Mcf) | | (In millions) | | (In millions) |
March 31, 2022 Actual | | $74.41 | | $4.02 | | $3,749 | | |
| | | | | | | | |
Crude Oil and Natural Gas Price Sensitivity | | | | | | | | |
Crude Oil and Natural Gas +10% | | $81.94 | | $4.43 | | $4,724 | | $975 |
Crude Oil and Natural Gas -10% | | $66.89 | | $3.61 | | $2,774 | | ($975) |
| | | | | | | | |
Crude Oil Price Sensitivity | | | | | | | | |
Crude Oil +10% | | $81.94 | | $4.02 | | $4,643 | | $894 |
Crude Oil -10% | | $66.89 | | $4.02 | | $2,855 | | ($894) |
| | | | | | | | |
Natural Gas Price Sensitivity | | | | | | | | |
Natural Gas +10% | | $74.41 | | $4.43 | | $3,829 | | $80 |
Natural Gas -10% | | $74.41 | | $3.61 | | $3,669 | | ($80) |
Recently Adopted and Recently Issued Accounting PronouncementsStandards
See “Note 1 - Description of Business and Basis of Presentation” for discussion.
Item 3. Quantitative and Qualitative Disclosures about Market Risk
We are exposed to a variety of market risks including commodity price risk, interest rate risk and counterparty and customer credit risk. We mitigate these risks through a program of risk management including the use of commodity derivative instruments.
Except as set forth below, there have been no material changes to the sources and effects of our market risk since December 31, 2021, which are disclosed in “Part II, Item 7A. Quantitative and Qualitative Disclosures about Market Risk” of our 2021 Annual Report on Form 10-K.
Commodity price riskPrice Risk
Our revenues are derived from the sale of our oil, natural gas and NGL production. The prices for oil, natural gas and NGLs remain volatile and sometimes experience large fluctuations as a result of relatively small changes in supply, government actions, economic conditions, and weather conditions.
The following table sets forth oil, natural gas and NGL revenues for the three months ended March 31, 2021 as well as the impact on the oil, natural gas and NGL revenues assuming a 10% increase or decrease in our average realized sales prices for oil, natural gas and NGLs, excluding the impact ofWe enter into commodity derivative settlements:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended March 31, 2021 | | |
| | Oil | | Natural Gas | | NGLs | | Total | | | | | | | | |
| | (In thousands) |
Revenues | | $267,045 | | $24,220 | | $29,357 | | $320,622 | | | | | | | | |
| | | | | | | | | | | | | | | | |
Impact of a 10% fluctuation in average realized prices | | $26,704 | | $2,422 | | $2,936 | | $32,062 | | | | | | | | |
From time to time, we enter into derivative financial instruments to manage oil, natural gas and NGL price risk, related both to NYMEX benchmark prices and regional basis differentials.
The total volumes we hedge through usefollowing table sets forth the fair values of our commodity derivative instruments varies from period to period. Generally our objective is to hedge approximately 60% of our anticipated internally forecasted production for the next 12 to 24 months, subject to the covenants under our Credit Facility. Our hedge policies and objectives may change significantly with movements in commodities prices or futures prices.
As of March 31, 2021, for the remainder of 2021, we had 11,311,600 Bbls of fixed price oil hedges across NYMEX WTI, ICE Brent and Argus WTI-Houston benchmarks. We also had 2,171,900 Bbls of WTI Midland-Cushing oil basis hedges. Additionally, for the remainder of 2021, we had 16,623,000 MMBtus of fixed price NYMEX natural gas hedges and 12,375,000 MMBtus of Waha natural gas basis hedges. See “Note 6 - Derivative Instruments and Hedging Activities” for a description of our outstanding derivative contracts as of March 31, 2021.2022, excluding deferred premium obligations, as well as the impact on the fair values assuming a 10% increase and decrease in the underlying forward oil and gas price curves as of March 31, 2022:
We may utilize fixed price swaps, which reduce our exposure to decreases in commodity | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended March 31, 2022 |
| | Oil | | Natural Gas | | Total |
| | (In thousands) |
Fair value liability as of March 31, 2022 (1) | | ($339,160) | | | ($23,881) | | | ($363,041) | |
| | | | | | |
Impact of a 10% increase in forward commodity prices | | ($451,638) | | | ($32,264) | | | ($483,902) | |
Impact of a 10% decrease in forward commodity prices | | ($229,700) | | | ($15,607) | | | ($245,307) | |
(1)Spot prices but limits the benefit we might otherwise have received from any increases in commodity prices. Swap contracts may also be enhanced by the simultaneous sale of call or put options to effectively increase the effective swap price as a result of the receipt of premiums from the option sales.
We also may utilize price collars to reduce the risk of changes infor oil and natural gas prices. Under these arrangements, no payments are due by either partywere $99.66 and $5.64, respectively, as long as the applicable market price is above the floor price (purchased put option) and below the ceiling price (sold call option) set in the collar. If the price falls below the floor, the counterparty to the collar pays the difference to us, and if the price rises above the ceiling, the counterparty receives the difference from us. Additionally, we may sell put options at a price lower than the floor price in conjunction with a collar (three-way collar) and use the proceeds to increase either or both the floor or ceiling prices. In a three-way collar, to the extent that realized prices are below the floor price of the sold put option (or above the ceiling price of the sold call option), our net realized benefit from the three-way collar will be reduced on a dollar-for-dollar basis.
We may purchase put options, which reduce our exposure to decreases in oil and natural gas prices while allowing realization of the full benefit from any increases in oil and natural gas prices. If the price falls below the floor, the counterparty pays the difference to us.
We enter into these various agreements from time to time to reduce the effects of volatile oil, natural gas and NGL prices and do not enter into derivative transactions for speculative or trading purposes. Presently, none of our derivative positions are designated as hedges for accounting purposes.March 31, 2022.
Interest rate riskRate Risk
We are subject to market risk exposure related to changes in interest rates on our indebtedness under our Credit Facility. As of March 31, 2021,2022, we had $950.0$712.0 million outstanding under the Credit Facility with a weighted average interest rate of 2.62%2.74%. An increase or decrease of 1.00% in the interest rate would have a corresponding increase or decrease in our annual interest expense of approximately $9.5$7.1 million, based on the balance outstanding as of March 31, 2021.2022. See “Note 56 - Borrowings” for more information on our Credit Facility.
Counterparty and customer credit risk
Our principal exposures to credit risk are through receivables from the sale of our oil and natural gas production, joint interest receivables and receivables resulting from derivative financial contracts.
We market our oil, natural gas and NGL production to energy marketing companies and are subject to credit risk due to the concentration of our oil, natural gas and NGL receivables with several significant customers. The inability of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. In order to mitigate potential exposure to credit risk, we may require from time to time for our customers to provide financial security. At March 31, 2021, our total receivables from the sale of our oil, natural gas and NGL production were approximately $125.6 million.
Joint interest receivables arise from billings to entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we have or intend to drill. We have little ability to control whether these entities will participate in our wells. We generally have the right to withhold future revenue distributions to recover past due receivables from joint interest owners. The allowance for credit losses related to our joint interest receivables is immaterial. At March 31, 2021, our joint interest receivables were approximately $21.2 million.
Our oil, natural gas and NGL commodity derivative arrangements expose us to credit risk in the event of nonperformance by counterparties. All of the counterparties of our commodity derivative instruments currently in place are lenders under our Credit Facility. We are likely to enter into additional commodity derivative instruments with these or other lenders under our Credit Facility, representing institutions with investment grade ratings. We have existing ISDA Agreements with our commodity derivative counterparties. The terms of the ISDA Agreements provide us and the counterparties with rights of offset upon the occurrence of defined acts of default by either us or a counterparty to a commodity derivative, whereby the party not in default may offset all commodity derivative liabilities owed to the defaulting party against all commodity derivative asset receivables from the defaulting party. At March 31, 2021, we had a net commodity derivative liability position of $207.4 million.
Item 4. Controls and Procedures
Disclosure controlsControls and procedures.Procedures. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Exchange Act is accumulated and communicated to the issuer’s management, including its principal executive and financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. Our management, with the participation of the Chief Executive Officer and Chief Financial Officer, performed an evaluation of the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act). Based on this evaluation, our principal executive and principal financial officers have concluded that the Company’s disclosure controls and procedures were effective as of March 31, 2021.2022.
Changes in internal control over financial reportingInternal Control Over Financial Reporting. There were no changes in our internal control over financial reporting (as such term is defined in Rule 13a-15(f) under the Exchange Act) that occurred during the first quarter of 20212022 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
Part II. Other Information
Item 1. Legal Proceedings
We are not currently a party to, nor is our property currently subject to, any materialin various legal proceedings other thanand claims, which arise in the ordinary routine litigation incidental tocourse of our business. While the business, andoutcome of these events cannot be predicted with certainty, we are not awarebelieve that the ultimate resolution of any such proceedings contemplated by governmental authorities.actions will not have a material effect on our financial position or results of operations.
In January 2022, we received a Notice of Violation from the United States Environmental Protection Agency related to the Clean Air Act. The enforcement action will likely result in monetary sanctions yet-to-be specified and corrective actions, which may increase our development costs and/or operating costs. We are unable to predict the ultimate outcome of this matter at this time, however, we believe that any penalties, mitigation costs, or corrective actions that may result from this matter will not have a material adverse effect on our consolidated financial position, results of operations, or cash flows.
Item 1A. Risk Factors
There have been no material changes to the risk factors set forth under the heading “Part I, Item 1A. Risk Factors” included in our 20202021 Annual Report on Form 10-K. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
On January 20, 2021, we issued 0.5 million shares of common stock upon the cashless exercise of a portion of the outstanding November 2020 Warrants by the holders thereof. On February 23, 2021, we issued 5.6 million shares of common stock upon the cashless exercise of all of the September 2020 Warrants by the holders thereof. Also on February 23, 2021, we issued 0.3 million shares of common stock upon the cashless exercise of a portion of the outstanding November 2020 Warrants by the holders thereof. These warrant exercises were exempt from registration pursuant to Section 3(a)(9) of the Securities Act.None.
Item 3. Defaults Upon Senior Securities
None.
Item 4. Mine Safety Disclosures
Not applicable.
Item 5. Other Information
None.
Item 6. Exhibits
The following exhibits are filed as part of this Form 10-Q.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | Incorporated by reference (File No. 001-14039, unless otherwise indicated) |
Exhibit Number | Description | | Form | | Exhibit | | Filing Date |
3.1 | | | | | 10-Q | | 3.1 | | 11/03/2016 |
3.2 | | | | | 8-K | | 3.1 | | 11/20/2019 |
3.3 | | | | | 8-K | | 3.1 | | 8/07/2020 |
3.4 | | | | | 10-K | | 3.2 | | 2/27/2019 |
10.1 | (c) | | | | 8-K | | 10.1 | | 4/16/2021 |
10.2 | (c) | | | | 8-K | | 10.2 | | 4/16/2021 |
10.3 | (c) | | | | 8-K | | 10.3 | | 4/16/2021 |
10.4 | (c) | | | | 8-K | | 10.4 | | 4/16/2021 |
10.5 | (c) | | | | 8-K | | 10.5 | | 4/16/2021 |
10.6 | (a) | | | | | | | | |
31.1 | (a) | | | | | | | | |
31.2 | (a) | | | | | | | | |
32.1 | (b) | | | | | | | | |
101.INS | (a) | | XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document. | | | | | | |
101.SCH | (a) | | Inline XBRL Taxonomy Extension Schema Document | | | | | | |
101.CAL | (a) | | Inline XBRL Taxonomy Extension Calculation Linkbase Document. | | | | | | |
101.DEF | (a) | | Inline XBRL Taxonomy Extension Definition Linkbase Document. | | | | | | |
101.LAB | (a) | | Inline XBRL Taxonomy Extension Label Linkbase Document. | | | | | | |
101.PRE | (a) | | Inline XBRL Taxonomy Extension Presentation Linkbase Document. | | | | | | |
104 | (a) | | Cover Page Interactive Data File - the cover page interactive data file does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document. | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | Incorporated by reference (File No. 001-14039, unless otherwise indicated) |
Exhibit Number | Description | | Form | | Exhibit | | Filing Date |
3.1 | | | | | 10-Q | | 3.1 | | 11/3/2016 |
3.2 | | | | | 8-K | | 3.1 | | 12/20/2019 |
3.3 | | | | | 8-K | | 3.1 | | 8/7/2020 |
3.4 | | | | | 8-K | | 3.1 | | 5/14/2021 |
3.5 | | | | | 10-K | | 3.2 | | 2/27/2019 |
10.1 | (a)(c) | | | | | | | | |
10.2 | (a)(c) | | | | | | | | |
31.1 | (a) | | | | | | | | |
31.2 | (a) | | | | | | | | |
32.1 | (b) | | | | | | | | |
101.INS | (a) | | XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document. | | | | | | |
101.SCH | (a) | | Inline XBRL Taxonomy Extension Schema Document | | | | | | |
101.CAL | (a) | | Inline XBRL Taxonomy Extension Calculation Linkbase Document. | | | | | | |
101.DEF | (a) | | Inline XBRL Taxonomy Extension Definition Linkbase Document. | | | | | | |
101.LAB | (a) | | Inline XBRL Taxonomy Extension Label Linkbase Document. | | | | | | |
101.PRE | (a) | | Inline XBRL Taxonomy Extension Presentation Linkbase Document. | | | | | | |
104 | (a) | | Cover Page Interactive Data File - the cover page interactive data file does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document. | | | | | | |
(a)Filed herewith.
(b)Furnished herewith. Pursuant to SEC Release No. 33-8212, this certification will be treated as “accompanying” this report and not “filed” as part of such report for purposes of Section 18 of the Exchange Act or otherwise subject to the liability of Section 18 of the Exchange Act, and this certification will not be deemed to be incorporated by reference into any filing under the Securities Act, except to the extent that the registrant specifically incorporates it by reference.
(c)Indicates management compensatory plan, contract, or arrangement.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
Callon Petroleum Company
| | | | | | | | |
Signature | Title | Date |
| | |
/s/ Joseph C. Gatto, Jr. | President and | May 6, 20215, 2022 |
Joseph C. Gatto, Jr. | Chief Executive Officer | |
| | | | | | | | |
/s/ James P. Ulm, IIKevin Haggard | Senior Vice President and | May 6, 20215, 2022 |
James P. Ulm, IIKevin Haggard | Chief Financial Officer | |