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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 ended September 30, 2021
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: 001-12935
DENBURY INC.
(Exact name of registrant as specified in its charter)
| | | | | | | | | | | | | | |
Delaware | | 20-0467835 |
(State or other jurisdiction of incorporation or organization) | | (I.R.S. Employer Identification No.) |
| | | | |
5851 Legacy Circle, | | |
Plano, | TX | | | 75024 |
(Address of principal executive offices) | | (Zip Code) |
| | | | | | | | | | | |
Registrant’s telephone number, including area code: | | (972) | 673-2000 |
Securities registered pursuant to Section 12(b) of the Act:
| | | | | | | | |
Title of Each Class: | Trading Symbol: | Name of Each Exchange on Which Registered: |
Common Stock $.001 Par Value | DEN | New York Stock Exchange |
Not applicable
(Former name, former address and former fiscal year, if changed since last report)
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 and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ☑ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a 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. (Check one):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Large accelerated filer | ☐ | Accelerated filer | ☑ | Non-accelerated filer | ☐ | Smaller reporting company | ☑ | Emerging growth company | ☐ |
| | | | (Do not check if a smaller reporting 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 ☑
Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. Yes ☑ No ☐
The number of shares outstanding of the registrant’s Common Stock, $.001 par value, as of October 31, 2021, was 50,122,417.
Table of Contents
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
Denbury Inc.
Unaudited Condensed Consolidated Balance Sheets
(In thousands, except par value and share data)
| | | | | | | | | | | | | | |
| | |
| | Successor |
| | September 30, 2021 | | December 31, 2020 |
Assets | | | | |
Current assets | | | | |
Cash and cash equivalents | | $ | 1,783 | | | $ | 518 | |
Restricted cash | | — | | | 1,000 | |
Accrued production receivable | | 144,370 | | | 91,421 | |
Trade and other receivables, net | | 20,867 | | | 19,682 | |
Derivative assets | | — | | | 187 | |
Prepaids | | 10,872 | | | 14,038 | |
Total current assets | | 177,892 | | | 126,846 | |
Property and equipment | | | | |
Oil and natural gas properties (using full cost accounting) | | | | |
Proved properties | | 1,011,545 | | | 851,208 | |
Unevaluated properties | | 108,258 | | | 85,304 | |
CO2 properties | | 188,752 | | | 188,288 | |
Pipelines | | 193,669 | | | 133,485 | |
Other property and equipment | | 94,763 | | | 86,610 | |
Less accumulated depletion, depreciation, amortization and impairment | | (151,844) | | | (41,095) | |
Net property and equipment | | 1,445,143 | | | 1,303,800 | |
Operating lease right-of-use assets | | 18,253 | | | 20,342 | |
| | | | |
Intangible assets, net | | 90,533 | | | 97,362 | |
Other assets | | 80,444 | | | 86,408 | |
Total assets | | $ | 1,812,265 | | | $ | 1,634,758 | |
Liabilities and Stockholders’ Equity | | | | |
Current liabilities | | | | |
Accounts payable and accrued liabilities | | $ | 211,894 | | | $ | 112,671 | |
Oil and gas production payable | | 69,717 | | | 49,165 | |
Derivative liabilities | | 193,015 | | | 53,865 | |
Current maturities of long-term debt | | 17,332 | | | 68,008 | |
Operating lease liabilities | | 3,338 | | | 1,350 | |
Total current liabilities | | 495,296 | | | 285,059 | |
Long-term liabilities | | | | |
Long-term debt, net of current portion | | — | | | 70,000 | |
Asset retirement obligations | | 243,184 | | | 179,338 | |
Derivative liabilities | | 16,435 | | | 5,087 | |
Deferred tax liabilities, net | | 1,241 | | | 1,274 | |
Operating lease liabilities | | 17,362 | | | 19,460 | |
Other liabilities | | 25,954 | | | 20,872 | |
Total long-term liabilities | | 304,176 | | | 296,031 | |
Commitments and contingencies (Note 8) | | | | |
Stockholders’ equity | | | | |
Preferred stock, $.001 par value, 50,000,000 shares authorized, none issued and outstanding | | — | | | — | |
Common stock, $.001 par value, 250,000,000 shares authorized; 50,120,895 and 49,999,999 shares issued, respectively | | 50 | | | 50 | |
Paid-in capital in excess of par | | 1,128,030 | | | 1,104,276 | |
Accumulated deficit | | (115,287) | | | (50,658) | |
Total stockholders’ equity | | 1,012,793 | | | 1,053,668 | |
Total liabilities and stockholders’ equity | | $ | 1,812,265 | | | $ | 1,634,758 | |
See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.
Denbury Inc.
Unaudited Condensed Consolidated Statements of Operations
(In thousands, except per-share data)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Successor | | | Predecessor | | | | | |
| | Three Months Ended Sept. 30, 2021 | | Period from Sept. 19, 2020 through Sept. 30, 2020 | | | Period from July 1, 2020 through Sept. 18, 2020 | | | | | |
| | | | | | | | | | | | |
Revenues and other income | | | | | | | | | | | | |
Oil, natural gas, and related product sales | | $ | 308,454 | | | $ | 22,321 | | | | $ | 153,090 | | | | | | |
CO2 sales and transportation fees | | 12,237 | | | 967 | | | | 6,517 | | | | | | |
Oil marketing revenues | | 12,593 | | | 151 | | | | 3,332 | | | | | | |
Other income | | 10,451 | | | 94 | | | | 7,097 | | | | | | |
Total revenues and other income | | 343,735 | | | 23,533 | | | | 170,036 | | | | | | |
Expenses | | | | | | | | | | | | |
Lease operating expenses | | 116,536 | | | 11,484 | | | | 59,708 | | | | | | |
Transportation and marketing expenses | | 5,985 | | | 1,344 | | | | 8,155 | | | | | | |
CO2 operating and discovery expenses | | 1,963 | | | 242 | | | | 955 | | | | | | |
Taxes other than income | | 24,154 | | | 2,073 | | | | 13,473 | | | | | | |
Oil marketing purchases | | 11,940 | | | 139 | | | | 3,288 | | | | | | |
General and administrative expenses | | 15,388 | | | 1,735 | | | | 15,013 | | | | | | |
Interest, net of amounts capitalized of $1,249, $183 and $4,704, respectively | | 669 | | | 334 | | | | 7,704 | | | | | | |
Depletion, depreciation, and amortization | | 37,691 | | | 5,283 | | | | 36,317 | | | | | | |
Commodity derivatives expense (income) | | 41,745 | | | (4,035) | | | | 4,609 | | | | | | |
| | | | | | | | | | | | |
Write-down of oil and natural gas properties | | — | | | — | | | | 261,677 | | | | | | |
Reorganization items, net | | — | | | — | | | | 849,980 | | | | | | |
Other expenses | | 4,553 | | | 2,164 | | | | 22,084 | | | | | | |
Total expenses | | 260,624 | | | 20,763 | | | | 1,282,963 | | | | | | |
Income (loss) before income taxes | | 83,111 | | | 2,770 | | | | (1,112,927) | | | | | | |
Income tax provision (benefit) | | 403 | | | 12 | | | | (303,807) | | | | | | |
Net income (loss) | | $ | 82,708 | | | $ | 2,758 | | | | $ | (809,120) | | | | | | |
| | | | | | | | | | | | |
Net income (loss) per common share | | | | | | | | | | | | |
Basic | | $ | 1.62 | | | $ | 0.06 | | | | $ | (1.63) | | | | | | |
Diluted | | $ | 1.51 | | | $ | 0.06 | | | | $ | (1.63) | | | | | | |
| | | | | | | | | | | | |
Weighted average common shares outstanding | | | | | | | | | | | | |
Basic | | 51,094 | | | 50,000 | | | | 497,398 | | | | | | |
Diluted | | 54,714 | | | 50,000 | | | | 497,398 | | | | | | |
See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.
Denbury Inc.
Unaudited Condensed Consolidated Statements of Operations
(In thousands, except per-share data)
| | | | | | | | | | | | | | | | | | | | | | | |
| | Successor | | | Predecessor |
| | Nine Months Ended Sept. 30, 2021 | | Period from Sept. 19, 2020 through Sept. 30, 2020 | | | Period from Jan. 1, 2020 through Sept. 18, 2020 |
Revenues and other income | | | | | | | |
Oil, natural gas, and related product sales | | $ | 826,607 | | | $ | 22,321 | | | | $ | 492,101 | |
CO2 sales and transportation fees | | 31,599 | | | 967 | | | | 21,049 | |
Oil marketing revenues | | 26,538 | | | 151 | | | | 8,543 | |
Other income | | 11,518 | | | 94 | | | | 8,419 | |
Total revenues and other income | | 896,262 | | | 23,533 | | | | 530,112 | |
Expenses | | | | | | | |
Lease operating expenses | | 308,731 | | | 11,484 | | | | 250,271 | |
Transportation and marketing expenses | | 22,304 | | | 1,344 | | | | 27,164 | |
CO2 operating and discovery expenses | | 4,487 | | | 242 | | | | 2,592 | |
Taxes other than income | | 65,499 | | | 2,073 | | | | 43,531 | |
Oil marketing purchases | | 25,763 | | | 139 | | | | 8,399 | |
General and administrative expenses | | 62,821 | | | 1,735 | | | | 48,522 | |
Interest, net of amounts capitalized of $3,500, $183 and $22,885, respectively | | 3,457 | | | 334 | | | | 48,267 | |
Depletion, depreciation, and amortization | | 113,522 | | | 5,283 | | | | 188,593 | |
Commodity derivatives expense (income) | | 330,152 | | | (4,035) | | | | (102,032) | |
Gain on debt extinguishment | | — | | | — | | | | (18,994) | |
Write-down of oil and natural gas properties | | 14,377 | | | — | | | | 996,658 | |
Reorganization items, net | | — | | | — | | | | 849,980 | |
Other expenses | | 9,913 | | | 2,164 | | | | 35,868 | |
Total expenses | | 961,026 | | | 20,763 | | | | 2,378,819 | |
Income (loss) before income taxes | | (64,764) | | | 2,770 | | | | (1,848,707) | |
Income tax provision (benefit) | | (135) | | | 12 | | | | (416,129) | |
Net income (loss) | | $ | (64,629) | | | $ | 2,758 | | | | $ | (1,432,578) | |
| | | | | | | |
Net income (loss) per common share | | | | | | | |
Basic | | $ | (1.27) | | | $ | 0.06 | | | | $ | (2.89) | |
Diluted | | $ | (1.27) | | | $ | 0.06 | | | | $ | (2.89) | |
| | | | | | | |
Weighted average common shares outstanding | | | | | | | |
Basic | | 50,807 | | | 50,000 | | | | 495,560 | |
Diluted | | 50,807 | | | 50,000 | | | | 495,560 | |
See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.
Denbury Inc.
Unaudited Condensed Consolidated Statements of Cash Flows
(In thousands)
| | | | | | | | | | | | | | | | | | | | | | | |
| | Successor | | | Predecessor |
| | Nine Months Ended Sept. 30, 2021 | | Period from Sept. 19, 2020 through Sept. 30, 2020 | | | Period from Jan. 1, 2020 through Sept. 18, 2020 |
Cash flows from operating activities | | | | | | | |
Net income (loss) | | $ | (64,629) | | | $ | 2,758 | | | | $ | (1,432,578) | |
Adjustments to reconcile net income (loss) to cash flows from operating activities | | | | | | | |
Noncash reorganization items, net | | — | | | — | | | | 810,909 | |
Depletion, depreciation, and amortization | | 113,522 | | | 5,283 | | | | 188,593 | |
Write-down of oil and natural gas properties | | 14,377 | | | — | | | | 996,658 | |
Deferred income taxes | | (34) | | | 6 | | | | (408,869) | |
Stock-based compensation | | 22,788 | | | — | | | | 4,111 | |
Commodity derivatives expense (income) | | 330,152 | | | (4,035) | | | | (102,032) | |
Receipt (payment) on settlements of commodity derivatives | | (179,466) | | | 6,660 | | | | 81,396 | |
Gain on debt extinguishment | | — | | | — | | | | (18,994) | |
Debt issuance costs and discounts | | 2,055 | | | 114 | | | | 11,571 | |
Gain from asset sales and other | | (7,026) | | | — | | | | (6,723) | |
Other, net | | (2,448) | | | 589 | | | | 7,162 | |
Changes in assets and liabilities, net of effects from acquisitions | | | | | | | |
Accrued production receivable | | (52,948) | | | 38,537 | | | | 26,575 | |
Trade and other receivables | | (1,809) | | | 1,366 | | | | (22,343) | |
Other current and long-term assets | | 7,337 | | | 705 | | | | 743 | |
Accounts payable and accrued liabilities | | 47,484 | | | (7,980) | | | | (16,102) | |
Oil and natural gas production payable | | 23,168 | | | (11,064) | | | | (6,792) | |
Other liabilities | | (4,966) | | | (29) | | | | 123 | |
Net cash provided by operating activities | | 247,557 | | | 32,910 | | | | 113,408 | |
| | | | | | | |
Cash flows from investing activities | | | | | | | |
Oil and natural gas capital expenditures | | (113,041) | | | (2,125) | | | | (99,582) | |
Acquisitions of oil and natural gas properties | | (10,927) | | | (1) | | | | — | |
Pipelines and plants capital expenditures | | (19,123) | | | (6) | | | | (11,601) | |
Net proceeds from sales of oil and natural gas properties and equipment | | 19,053 | | | 880 | | | | 41,322 | |
Other | | 5,797 | | | (308) | | | | 12,747 | |
Net cash used in investing activities | | (118,241) | | | (1,560) | | | | (57,114) | |
| | | | | | | |
Cash flows from financing activities | | | | | | | |
Bank repayments | | (697,000) | | | (55,000) | | | | (551,000) | |
Bank borrowings | | 627,000 | | | — | | | | 691,000 | |
Interest payments treated as a reduction of debt | | — | | | — | | | | (46,417) | |
Cash paid in conjunction with debt repurchases | | — | | | — | | | | (14,171) | |
| | | | | | | |
Costs of debt financing | | — | | | — | | | | (12,482) | |
Pipeline financing repayments | | (50,676) | | | (54) | | | | (51,792) | |
Other | | (2,426) | | | — | | | | (9,363) | |
Net cash provided by (used in) financing activities | | (123,102) | | | (55,054) | | | | 5,775 | |
Net increase (decrease) in cash, cash equivalents, and restricted cash | | 6,214 | | | (23,704) | | | | 62,069 | |
Cash, cash equivalents, and restricted cash at beginning of period | | 42,248 | | | 95,114 | | | | 33,045 | |
Cash, cash equivalents, and restricted cash at end of period | | $ | 48,462 | | | $ | 71,410 | | | | $ | 95,114 | |
See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.
Denbury Inc.
Unaudited Condensed Consolidated Statements of Changes in Stockholders' Equity
(Dollar amounts in thousands)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Common Stock ($.001 Par Value) | | Paid-In Capital in Excess of Par | | Retained Earnings (Accumulated Deficit) | | Treasury Stock (at cost) | | |
| Shares | | Amount | Shares | | Amount | Total Equity |
Balance – December 31, 2020 (Successor) | 49,999,999 | | | $ | 50 | | | $ | 1,104,276 | | | $ | (50,658) | | | — | | | $ | — | | | $ | 1,053,668 | |
Stock-based compensation | — | | | — | | | 19,172 | | | — | | | — | | | — | | | 19,172 | |
Tax withholding for stock compensation plans | — | | | — | | | (1,467) | | | — | | | — | | | — | | | (1,467) | |
Issued pursuant to exercise of warrants | 5,620 | | | 0 | | | 195 | | | — | | | — | | | — | | | 195 | |
Net loss | — | | | — | | | — | | | (69,642) | | | — | | | — | | | (69,642) | |
Balance – March 31, 2021 (Successor) | 50,005,619 | | | 50 | | | 1,122,176 | | | (120,300) | | | — | | | — | | | 1,001,926 | |
Stock-based compensation | — | | | — | | | 2,682 | | | — | | | — | | | — | | | 2,682 | |
Tax withholding for stock compensation plans | — | | | — | | | (7) | | | — | | | — | | | — | | | (7) | |
Issued pursuant to exercise of warrants | 11,872 | | | 0 | | | 292 | | | — | | | — | | | — | | | 292 | |
Net loss | — | | | — | | | — | | | (77,695) | | | — | | | — | | | (77,695) | |
Balance – June 30, 2021 (Successor) | 50,017,491 | | | 50 | | | 1,125,143 | | | (197,995) | | | — | | | — | | | 927,198 | |
| | | | | | | | | | | | | |
Stock-based compensation | — | | | — | | | 2,686 | | | — | | | — | | | — | | | 2,686 | |
| | | | | | | | | | | | | |
Issued pursuant to exercise of warrants | 103,404 | | | 0 | | | 201 | | | — | | | — | | | — | | | 201 | |
Net income | — | | | — | | | — | | | 82,708 | | | — | | | — | | | 82,708 | |
Balance – September 30, 2021 (Successor) | 50,120,895 | | | $ | 50 | | | $ | 1,128,030 | | | $ | (115,287) | | | — | | | $ | — | | | $ | 1,012,793 | |
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| Common Stock ($.001 Par Value) | | Paid-In Capital in Excess of Par | | Retained Earnings (Accumulated Deficit) | | Treasury Stock (at cost) | | |
| Shares | | Amount | Shares | | Amount | Total Equity |
Balance – December 31, 2019 (Predecessor) | 508,065,495 | | | $ | 508 | | | $ | 2,739,099 | | | $ | (1,321,314) | | | 1,652,771 | | | $ | (6,034) | | | $ | 1,412,259 | |
Issued pursuant to stock compensation plans | 312,516 | | | — | | | — | | | — | | | — | | | — | | | — | |
Issued pursuant to directors’ compensation plan | 37,367 | | | — | | | — | | | — | | | — | | | — | | | — | |
Stock-based compensation | — | | | — | | | 3,204 | | | — | | | — | | | — | | | 3,204 | |
Tax withholding for stock compensation plans | — | | | — | | | — | | | — | | | 175,673 | | | (34) | | | (34) | |
Net income | — | | | — | | | — | | | 74,016 | | | — | | | — | | | 74,016 | |
Balance – March 31, 2020 (Predecessor) | 508,415,378 | | | 508 | | | 2,742,303 | | | (1,247,298) | | | 1,828,444 | | | (6,068) | | | 1,489,445 | |
Canceled pursuant to stock compensation plans | (6,218,868) | | | (6) | | | 6 | | | — | | | — | | | — | | | — | |
Issued pursuant to notes conversion | 7,357,450 | | | 8 | | | 11,453 | | | — | | | — | | | — | | | 11,461 | |
Stock-based compensation | — | | | — | | | 987 | | | — | | | — | | | — | | | 987 | |
Net loss | — | | | — | | | — | | | (697,474) | | | — | | | — | | | (697,474) | |
Balance – June 30, 2020 (Predecessor) | 509,553,960 | | | 510 | | | 2,754,749 | | | (1,944,772) | | | 1,828,444 | | | (6,068) | | | 804,419 | |
Canceled pursuant to stock compensation plans | (95,016) | | | — | | | — | | | — | | | — | | | — | | | — | |
Issued pursuant to notes conversion | 14,800 | | | — | | | 40 | | | — | | | — | | | — | | | 40 | |
Stock-based compensation | — | | | — | | | 10,126 | | | — | | | — | | | — | | | 10,126 | |
Tax withholding for stock compensation plans | — | | | — | | | — | | | — | | | 567,189 | | | (134) | | | (134) | |
Net loss | — | | | — | | | — | | | (809,120) | | | — | | | — | | | (809,120) | |
Cancellation of Predecessor equity | (509,473,744) | | | (510) | | | (2,764,915) | | | 2,753,892 | | | (2,395,633) | | | 6,202 | | | (5,331) | |
Issuance of Successor equity | 49,999,999 | | | 50 | | | 1,095,369 | | | — | | | — | | | — | | | 1,095,419 | |
Balance – September 18, 2020 (Predecessor) | 49,999,999 | | | $ | 50 | | | $ | 1,095,369 | | | $ | — | | | — | | | $ | — | | | $ | 1,095,419 | |
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Balance – September 19, 2020 (Successor) | 49,999,999 | | | $ | 50 | | | $ | 1,095,369 | | | $ | — | | | — | | | $ | — | | | $ | 1,095,419 | |
Net income | — | | | — | | | — | | | 2,758 | | | — | | | — | | | 2,758 | |
Balance – September 30, 2020 (Successor) | 49,999,999 | | | 50 | | | 1,095,369 | | | 2,758 | | | — | | | — | | | 1,098,177 | |
Stock-based compensation | — | | | — | | | 8,907 | | | — | | | — | | | — | | | 8,907 | |
Net loss | — | | | — | | | — | | | (53,416) | | | — | | | — | | | (53,416) | |
Balance – December 31, 2020 (Successor) | 49,999,999 | | | $ | 50 | | | $ | 1,104,276 | | | $ | (50,658) | | | — | | | $ | — | | | $ | 1,053,668 | |
See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.
Denbury Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
Note 1. Basis of Presentation
Organization and Nature of Operations
Denbury Inc. (“Denbury,” “Company” or the “Successor”), a Delaware corporation, is an independent energy company with operations focused in the Gulf Coast and Rocky Mountain regions. The Company is differentiated by its focus on CO2 enhanced oil recovery (“EOR”) and the emerging carbon capture, use, and storage (“CCUS”) industry, supported by the Company’s CO2 EOR technical and operational expertise and its extensive CO2 pipeline infrastructure. The utilization of captured industrial-sourced CO2 in EOR significantly reduces the carbon footprint of the oil that Denbury produces, making the Company’s scope 1 and 2 CO2 emissions negative today, with a goal to also fully offset scope 3 CO2 emissions within this decade, primarily through increasing the amount of captured industrial-sourced CO2 used in its operations.
Emergence from Voluntary Reorganization Under Chapter 11 of the Bankruptcy Code
On July 30, 2020 (the “Petition Date”), Denbury Resources Inc. (the “Predecessor”) and its subsidiaries filed petitions for reorganization in a “prepackaged” voluntary bankruptcy (the “Chapter 11 Restructuring”) under chapter 11 of the Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”) under the caption “In re Denbury Resources Inc., et al., Case No. 20-33801”. On September 2, 2020, the Bankruptcy Court entered an order (the “Confirmation Order”) confirming the prepackaged joint plan of reorganization (the “Plan”) and approving the Disclosure Statement, and on September 18, 2020 (the “Emergence Date”), the Plan became effective in accordance with its terms and the Company emerged from Chapter 11 as the successor reporting company of Denbury Resources Inc. On April 23, 2021, the Bankruptcy Court entered a final decree closing the Chapter 11 case captioned “In re Denbury Resources Inc., et al., Case No. 20-33801”; therefore, we have no remaining obligations related to this reorganization.
Upon emergence from bankruptcy, we met the criteria and were required to adopt fresh start accounting in accordance with Financial Accounting Standards Board Codification (“FASC”) Topic 852, Reorganizations. Fresh start accounting requires that new fair values be established for the Company’s assets, liabilities and equity as of the Emergence Date, and therefore certain values and operational results of the condensed consolidated financial statements subsequent to September 18, 2020 are not comparable to those in the Company’s condensed consolidated financial statements prior to, and including September 18, 2020. The Emergence Date fair values of the Successor’s assets and liabilities differ materially from their recorded values as reflected on the historical balance sheets of the Predecessor contained in periodic reports previously filed with the Securities and Exchange Commission. References to “Successor” relate to the financial position and results of operations of the Company subsequent to September 18, 2020, and references to “Predecessor” relate to the financial position and results of operations of the Company prior to, and including, September 18, 2020.
Reorganization Items, Net
Reorganization items, net, include (i) expenses incurred during the Chapter 11 Restructuring subsequent to the Petition Date as a direct result of the Plan, (ii) gains or losses from liabilities settled and (iii) fresh start accounting adjustments and are recorded in “Reorganization items, net” in our Unaudited Condensed Consolidated Statements of Operations. Professional service provider charges associated with our restructuring that were incurred before the Petition Date and after the Emergence Date are recorded in “Other expenses” in our Unaudited Condensed Consolidated Statements of Operations.
Denbury Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
The following table summarizes the losses (gains) on reorganization items, net:
| | | | | | | | |
| | Predecessor |
In thousands | | Period from July 1, 2020 through Sept. 18, 2020 |
Gain on settlement of liabilities subject to compromise | | $ | (1,024,864) | |
Fresh start accounting adjustments | | 1,834,423 | |
Professional service provider fees and other expenses | | 11,267 | |
Success fees for professional service providers | | 9,700 | |
Loss on rejected contracts and leases | | 10,989 | |
Valuation adjustments to debt classified as subject to compromise | | 757 | |
Debtor-in-possession credit agreement fees | | 3,107 | |
Acceleration of Predecessor stock compensation expense | | 4,601 | |
Total reorganization items, net | | $ | 849,980 | |
Interim Financial Statements
The accompanying unaudited condensed consolidated financial statements of Denbury Inc. and its subsidiaries have been prepared in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”) and do not include all of the information and footnotes required by accounting principles generally accepted in the United States for complete financial statements. These financial statements and the notes thereto should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2020 (the “Form 10-K”). Unless indicated otherwise or the context requires, the terms “we,” “our,” “us,” “Company” or “Denbury,” refer to Denbury Inc. and its subsidiaries.
Accounting measurements at interim dates inherently involve greater reliance on estimates than at year end, and the results of operations for the interim periods shown in this report are not necessarily indicative of results to be expected for the year. In management’s opinion, the accompanying unaudited condensed consolidated financial statements include all adjustments of a normal recurring nature necessary for a fair presentation of our consolidated financial position as of September 30, 2021 (Successor); our consolidated results of operations and consolidated statement of changes in stockholders’ equity for the three and nine months ended September 30, 2021 (Successor), for the period September 19, 2020 through September 30, 2020 (Successor), for the period July 1, 2020 through September 18, 2020 (Predecessor) and January 1, 2020 through September 18, 2020 (Predecessor); and our consolidated cash flows for the nine months ended September 30, 2021 (Successor), for the period September 19, 2020 through September 30, 2020 (Successor) and for the period January 1, 2020 through September 18, 2020 (Predecessor). Upon the adoption of fresh start accounting, the Company’s assets and liabilities were recorded at their fair values as of the fresh start reporting date. As a result of the adoption of fresh start accounting, certain values and operational results of the Company’s condensed consolidated financial statements subsequent to September 18, 2020 are not comparable to those in its condensed consolidated financial statements prior to, and including September 18, 2020.
Reclassifications
Certain prior period amounts have been reclassified to conform to the current year presentation. Such reclassifications had no impact on our reported net income (loss), current assets, total assets, current liabilities, total liabilities or stockholders’ equity.
Denbury Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
Cash, Cash Equivalents, and Restricted Cash
The following table provides a reconciliation of cash, cash equivalents, and restricted cash as reported within the Unaudited Condensed Consolidated Balance Sheets to “Cash, cash equivalents, and restricted cash at end of period” as reported within the Unaudited Condensed Consolidated Statements of Cash Flows:
| | | | | | | | | | | | | | |
| | Successor |
In thousands | | September 30, 2021 | | December 31, 2020 |
Cash and cash equivalents | | $ | 1,783 | | | $ | 518 | |
Restricted cash, current | | — | | | 1,000 | |
Restricted cash included in other assets | | 46,679 | | | 40,730 | |
Total cash, cash equivalents, and restricted cash shown in the Unaudited Condensed Consolidated Statements of Cash Flows | | $ | 48,462 | | | $ | 42,248 | |
Restricted cash included in other assets in the table above consists of escrow accounts that are legally restricted for certain of our asset retirement obligations, and are included in “Other assets” in the accompanying Unaudited Condensed Consolidated Balance Sheets.
Net Income (Loss) per Common Share
Basic net income (loss) per common share is computed by dividing the net income (loss) attributable to common stockholders by the weighted average number of shares of common stock outstanding during the period. Diluted net income per common share is calculated in the same manner but includes the impact of potentially dilutive securities. Potentially dilutive securities during the Successor periods consist of nonvested restricted stock units and outstanding series A and series B warrants, and during the Predecessor periods consisted of nonvested restricted stock, nonvested performance-based equity awards, and convertible senior notes. For each of the three and nine months ended September 30, 2021 and for the periods September 19, 2020 through September 30, 2020 (Successor), July 1, 2020 through September 18, 2020 (Predecessor) and January 1, 2020 through September 18, 2020 (Predecessor), there were no adjustments to net income (loss) for purposes of calculating basic and diluted net income (loss) per common share.
The following table reconciles the weighted average shares used in the basic and diluted net income (loss) per common share calculations for the periods indicated:
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| | Successor | | | Predecessor | | | | | |
In thousands | | Three Months Ended Sept. 30, 2021 | | Period from Sept. 19, 2020 through Sept. 30, 2020 | | | Period from July 1, 2020 through Sept. 18, 2020 | | | | | |
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Weighted average common shares outstanding – basic | | 51,094 | | | 50,000 | | | | 497,398 | | | | | | |
Effect of potentially dilutive securities | | | | | | | | | | | | |
Restricted stock units | | 908 | | | — | | | | — | | | | | | |
Warrants | | 2,712 | | | — | | | | — | | | | | | |
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Weighted average common shares outstanding – diluted | | 54,714 | | | 50,000 | | | | 497,398 | | | | | | |
For the nine months ended September 30, 2021 and for each of the periods from July 1, 2020 through September 18, 2020 (Predecessor) and from January 1, 2020 through September 18, 2020 (Predecessor), the weighted average common shares outstanding used to calculate basic earnings per share and diluted earnings per share were the same, since the Company generated a net loss during those periods. The weighted average diluted shares outstanding would have been 53.4 million for the nine months ended September 30, 2021, 580.0 million for the period July 1, 2020 through September 18, 2020, and 584.4 million for the period January 1, 2020 through September 18, 2020 if the Company had recognized net income during those periods.
Denbury Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
Basic weighted average common shares during the Successor periods includes 987,987 and 767,228 performance stock units during the three and nine months ended September 30, 2021, respectively, with vesting parameters tied to the Company’s common stock trading prices and which became fully vested on March 3, 2021. Although the performance measures for vesting of these awards have been achieved, the shares underlying these awards are not currently outstanding as actual delivery of the shares is not scheduled to occur until after the end of the performance period, December 4, 2023. Basic weighted average common shares includes time-vesting restricted stock units during the Successor periods and restricted stock during the Predecessor periods that vested during the periods.
For purposes of calculating diluted weighted average common shares for the three months ended September 30, 2021, the nonvested restricted stock units and warrants are included in the computation using the treasury stock method.
The following outstanding securities were excluded from the computation of diluted net loss per share for the nine months ended September 30, 2021 and from diluted net income per share for the period September 19, 2020 to September 30, 2020, as their effect would have been antidilutive, as of the respective dates:
| | | | | | | | | | | | | | | | | | | |
| | Successor | | | | | |
In thousands | | September 30, 2021 | | September 30, 2020 | | | | | |
Restricted stock units | | 1,255 | | | — | | | | | | |
Warrants | | 5,314 | | | 5,526 | | | | | | |
For the nine months ended September 30, 2021 Successor period, the Company’s restricted stock units and series A and series B warrants were antidilutive based on the Company’s net loss position for the period. Despite the Company’s net income position for the period September 19, 2020 to September 30, 2020, the Company’s series A and series B warrants were antidilutive because the Company’s stock price during the period was lower than the warrant exercise prices. At September 30, 2021, the Company had approximately 5.3 million warrants outstanding that can be exercised for shares of the Successor’s common stock, at an exercise price of $32.59 per share for the 2.6 million series A warrants outstanding and at an exercise price of $35.41 per share for the 2.7 million series B warrants outstanding. The series A warrants are exercisable until September 18, 2025, and the series B warrants are exercisable until September 18, 2023, at which time the warrants expire. The warrants were issued pursuant to the Plan to holders of the Predecessor’s convertible senior notes, senior subordinated notes, and equity. As of September 30, 2021, 8,390 series A warrants and 203,501 series B warrants had been exercised. The warrants may be exercised for cash or on a cashless basis. If warrants are exercised on a cashless basis, the amount of dilution will be less than 5.3 million shares.
Oil and Natural Gas Properties
Unevaluated Costs. Under full cost accounting, we exclude certain unevaluated costs from the amortization base and full cost ceiling test pending the determination of whether proved reserves can be assigned to such properties. These costs are transferred to the full cost amortization base as these properties are developed, tested and evaluated. At least annually, we test these assets for impairment based on an evaluation of management’s expectations of future pricing, evaluation of lease expiration terms, and planned development activities. In the first quarter of 2020 Predecessor period, given the significant declines in NYMEX oil prices in March and April 2020, we reassessed our development plans and transferred $244.9 million of our unevaluated costs to the full cost amortization base. Upon emergence from bankruptcy, the Company adopted fresh start accounting which resulted in our oil and natural gas properties, including unevaluated properties, being recorded at their fair values at the Emergence Date.
Write-Down of Oil and Natural Gas Properties. Under full cost accounting, the net capitalized costs of oil and natural gas properties are limited to the lower of unamortized cost or the cost center ceiling. The cost center ceiling is defined as (1) the present value of estimated future net revenues from proved oil and natural gas reserves before future abandonment costs (discounted at 10%), based on the average first-day-of-the-month oil and natural gas price for each month during a 12-month rolling period prior to the end of a particular reporting period; plus (2) the cost of properties not being amortized; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less (4) related income tax effects. Our future net revenues from proved oil and natural gas reserves are not reduced for development costs related to the cost of drilling for and developing CO2 reserves nor those related to the cost of constructing CO2 pipelines, as we do not have to incur additional CO2 capital costs to develop the proved oil and natural gas reserves. Therefore, we include in the ceiling test, as a reduction of future net revenues, that portion of our capitalized CO2 costs related to CO2 reserves and CO2
Denbury Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
pipelines that we estimate will be consumed in the process of producing our proved oil and natural gas reserves. The fair value of our oil and natural gas derivative contracts is not included in the ceiling test, as we do not designate these contracts as hedge instruments for accounting purposes. The cost center ceiling test is prepared quarterly.
We recognized a full cost pool ceiling test write-down of $14.4 million during the three months ended March 31, 2021, with first-day-of-the-month NYMEX oil prices for the preceding 12 months averaging $36.40 per Bbl, after adjustments for market differentials and transportation expenses by field. The write-down was primarily a result of the March 2021 acquisition of Wyoming property interests (see Note 2, Acquisition and Divestitures) which was recorded based on a valuation that utilized NYMEX strip oil prices at the acquisition date, which were significantly higher than the average first-day-of-the-month NYMEX oil prices used to value the cost ceiling.
The Predecessor also recognized full cost pool ceiling test write-downs of $261.7 million during the period from July 1, 2020 through September 18, 2020, $662.4 million during the three months ended June 30, 2020 and $72.5 million during the three months ended March 31, 2020. We did not record any ceiling test write-downs during the Successor periods from September 19, 2020 through September 30, 2020, for the three months ended June 30, 2021, or for the three months ended September 30, 2021.
Recent Accounting Pronouncements
Recently Adopted
Income Taxes. In December 2019, the Financial Accounting Standards Board (“FASB”) issued ASU 2019-12, Income Taxes (Topic 740) – Simplifying the Accounting for Income Taxes (“ASU 2019-12”). The objective of ASU 2019-12 is to simplify the accounting for income taxes by removing certain exceptions to the general principles in Topic 740 and to provide more consistent application to improve the comparability of financial statements. Effective January 1, 2021, we adopted ASU 2019-02. The implementation of this standard did not have a material impact on our consolidated financial statements and related footnote disclosures.
Note 2. Acquisition and Divestitures
Acquisition of Wyoming CO2 EOR Fields
On March 3, 2021, we acquired a nearly 100% working interest (approximately 83% net revenue interest) in the Big Sand Draw and Beaver Creek EOR fields located in Wyoming from a subsidiary of Devon Energy Corporation for $10.9 million cash (after final closing adjustments), including surface facilities and a 46-mile CO2 transportation pipeline to the acquired fields. The acquisition agreement provides for us to make two contingent cash payments, one in January 2022 and one in January 2023, of $4 million each, conditioned on NYMEX WTI oil prices averaging at least $50 per Bbl during each of 2021 and 2022. The fair value of the contingent consideration on the acquisition date was $5.3 million, and as of September 30, 2021, the fair value of the contingent consideration recorded on our Unaudited Condensed Consolidated Balance Sheets was $7.4 million. The $2.1 million increase at September 30, 2021 from the March 2021 acquisition date fair value was the result of higher NYMEX WTI oil prices and was recorded to “Other expenses” in our Unaudited Condensed Consolidated Statements of Operations.
The fair values allocated to our assets acquired and liabilities assumed for the acquisition were based on significant inputs not observable in the market and considered level 3 inputs. The fair value of the assets acquired and liabilities assumed was finalized during the third quarter of 2021, after consideration of final closing adjustments and evaluation of reserves and
Denbury Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
liabilities assumed. The following table presents a summary of the fair value of assets acquired and liabilities assumed in the acquisition:
| | | | | | | | |
In thousands | | |
Consideration: | | |
Cash consideration | | $ | 10,906 | |
| | |
Less: Fair value of assets acquired and liabilities assumed: | | |
Proved oil and natural gas properties | | 60,101 | |
Other property and equipment | | 1,685 | |
Asset retirement obligations | | (39,794) | |
Contingent consideration | | (5,320) | |
Other liabilities | | (5,766) | |
Fair value of net assets acquired | | $ | 10,906 | |
Divestitures
Hartzog Draw Deep Mineral Rights
On June 30, 2021, we closed the sale of undeveloped, unconventional deep mineral rights in Hartzog Draw Field in Wyoming. The cash proceeds of $18 million were recorded to “Proved properties” in our Unaudited Condensed Consolidated Balance Sheets. The proceeds reduced our full cost pool; therefore, no gain or loss was recorded on the transaction, and the sale had no impact on our production or reserves.
Houston Area Land Sales
During the third quarter of 2021, we completed sales of a portion of certain non-producing surface acreage in the Houston area. We recognized cash proceeds of $11.8 million from the sales and recorded a $7.0 million gain to “Other income” in our Unaudited Condensed Consolidated Statements of Operations.
Note 3. Revenue Recognition
We record revenue in accordance with FASC Topic 606, Revenue from Contracts with Customers. The core principle of FASC Topic 606 is that an entity should recognize revenue for the transfer of goods or services equal to the amount of consideration that it expects to be entitled to receive for those goods or services. Once we have delivered the volume of commodity to the delivery point and the customer takes delivery and possession, we are entitled to payment and we invoice the customer for such delivered production. Payment under most oil and CO2 contracts is received within a month following product delivery, and for natural gas and NGL contracts, payment is generally received within two months following delivery. Timing of revenue recognition may differ from the timing of invoicing to customers; however, as the right to consideration after delivery is unconditional based on only the passage of time before payment of the consideration is due, upon delivery we record a receivable in “Accrued production receivable” in our Unaudited Condensed Consolidated Balance Sheets. From time to time, the Company enters into marketing arrangements for the purchase and sale of crude oil for third parties. Revenues and expenses from these transactions are presented on a gross basis, as we act as a principal in the transaction by assuming control of the commodities purchased and responsibility to deliver the commodities sold. Revenue is recognized when control transfers to the purchaser at the delivery point based on the price received from the purchaser.
Denbury Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
Disaggregation of Revenue
The following tables summarize our revenues by product type for the periods indicated:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Successor | | | Predecessor | | | | | |
In thousands | | Three Months Ended Sept. 30, 2021 | | Period from Sept. 19, 2020 through Sept. 30, 2020 | | | Period from July 1, 2020 through Sept. 18, 2020 | | | | | |
Oil sales | | $ | 305,093 | | | $ | 22,311 | | | | $ | 152,136 | | | | | | |
Natural gas sales | | 3,361 | | | 10 | | | | 954 | | | | | | |
CO2 sales and transportation fees | | 12,237 | | | 967 | | | | 6,517 | | | | | | |
Oil marketing revenues | | 12,593 | | | 151 | | | | 3,332 | | | | | | |
Total revenues | | $ | 333,284 | | | $ | 23,439 | | | | $ | 162,939 | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | Successor | | | Predecessor |
In thousands | | Nine Months Ended Sept. 30, 2021 | | Period from Sept. 19, 2020 through Sept. 30, 2020 | | | Period from Jan. 1, 2020 through Sept. 18, 2020 |
Oil sales | | $ | 818,714 | | | $ | 22,311 | | | | $ | 489,251 | |
Natural gas sales | | 7,893 | | | 10 | | | | 2,850 | |
CO2 sales and transportation fees | | 31,599 | | | 967 | | | | 21,049 | |
Oil marketing revenues | | 26,538 | | | 151 | | | | 8,543 | |
Total revenues | | $ | 884,744 | | | $ | 23,439 | | | | $ | 521,693 | |
Note 4. Long-Term Debt
The table below reflects long-term debt outstanding as of the dates indicated:
| | | | | | | | | | | | | | |
| | Successor |
In thousands | | September 30, 2021 | | December 31, 2020 |
Senior Secured Bank Credit Agreement | | $ | — | | | $ | 70,000 | |
Pipeline financings | | 17,332 | | | 68,008 | |
Total debt principal balance | | 17,332 | | | 138,008 | |
Less: current maturities of long-term debt | | (17,332) | | | (68,008) | |
Long-term debt | | $ | — | | | $ | 70,000 | |
Senior Secured Bank Credit Agreement
On the Emergence Date, we entered into a credit agreement with JPMorgan Chase Bank, N.A., as administrative agent, and other lenders party thereto (the “Bank Credit Agreement”). The Bank Credit Agreement is a senior secured revolving credit facility with a borrowing base and lender commitments of $575 million. Availability under the Bank Credit Agreement is subject to a borrowing base, which is redetermined semiannually on or around May 1 and November 1 of each year, with our next scheduled redetermination around May 1, 2022. The borrowing base is adjusted at the lenders’ discretion and is based, in part, upon external factors over which we have no control. If our outstanding debt under the Bank Credit Agreement exceeds the then-effective borrowing base, we would be required to repay the excess amount over a period not to exceed six months. The Bank Credit Agreement matures on January 30, 2024. The undrawn portion of the aggregate lender commitments under the Bank Credit Agreement is subject to a commitment fee of 0.5% per annum.
Denbury Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
The Bank Credit Agreement limits our ability to pay dividends on our common stock or make other restricted payments in an amount not to exceed “Distributable Free Cash Flow”, but only if (1) no event of default or borrowing base deficiency exists; (2) our total leverage ratio is 2 to 1 or lower; and (3) availability under the Bank Credit Agreement is at least 20%. The Bank Credit Agreement also limits our ability to, among other things, incur and repay other indebtedness; grant liens; engage in certain mergers, consolidations, liquidations and dissolutions; engage in sales of assets; make acquisitions and investments; make other restricted payments (including redeeming, repurchasing or retiring our common stock); and enter into commodity derivative agreements, in each case subject to customary exceptions.
The Bank Credit Agreement is secured by (1) our proved oil and natural gas properties, which are held through our restricted subsidiaries; (2) the pledge of equity interests of such subsidiaries; (3) a pledge of our commodity derivative agreements; (4) a pledge of deposit accounts, securities accounts and our commodity accounts; and (5) a security interest in substantially all other collateral that may be perfected by a Uniform Commercial Code filing, subject to certain exceptions.
The Bank Credit Agreement contains certain financial performance covenants including the following:
•A Consolidated Total Debt to Consolidated EBITDAX covenant (as defined in the Bank Credit Agreement), with such ratio not to exceed 3.5 times; and
•A requirement to maintain a current ratio (i.e., Consolidated Current Assets to Consolidated Current Liabilities) of 1.0.
For purposes of computing the current ratio per the Bank Credit Agreement, Consolidated Current Assets exclude the current portion of derivative assets but include available borrowing capacity under the Bank Credit Agreement, and Consolidated Current Liabilities exclude the current portion of derivative liabilities as well as the current portions of long-term indebtedness outstanding. As of September 30, 2021, we were in compliance with all debt covenants under the Bank Credit Agreement.
The above description of our Bank Credit Agreement is qualified by the express language and defined terms contained in the Bank Credit Agreement.
Pipeline Financing Transactions
During the first nine months of 2021, Denbury paid $52.5 million to Genesis Energy, L.P. in accordance with the October 2020 restructuring of the financing arrangements of our NEJD CO2 pipeline system. The final quarterly installment of $17.5 million was paid on October 29, 2021.
Note 5. Income Taxes
As of September 30, 2021, the tax basis of our assets, primarily our oil and gas properties, is in excess of their carrying value, as adjusted for fresh start accounting on September 18, 2020; therefore, we are currently in a net deferred tax asset position. Based on all available evidence, both positive and negative, we continue to record a valuation allowance on our underlying deferred tax assets as of September 30, 2021, as we believe our deferred tax assets are not more-likely-than-not to be realized. We intend to maintain the valuation allowances on our deferred tax assets until there is sufficient evidence to support the reversal of all or some portion of the allowances, which will largely be determined based on oil prices and the Company’s ability to generate positive pre-tax income.
We evaluate our estimated annual effective income tax rate based on current and forecasted business results and enacted tax laws on a quarterly basis and apply this tax rate to our ordinary income or loss to calculate our estimated tax liability or benefit. Our income taxes are based on an estimated combined federal and state statutory rate of approximately 25% in 2021 and 2020. Our effective tax rates for the three and nine months ended September 30, 2021 (Successor) differed from our estimated statutory rate as the deferred tax expense generated by the operating income for the three months ended September 30, 2021 and the deferred tax benefit generated from our operating loss for the nine months ended September 30, 2021 were offset by a valuation allowance applied to our underlying federal and state deferred tax assets.
Denbury Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
Note 6. Commodity Derivative Contracts
We do not apply hedge accounting treatment to our oil and natural gas derivative contracts; therefore, the changes in the fair values of these instruments are recognized in income in the period of change. These fair value changes, along with the settlements of expired contracts, are shown under “Commodity derivatives expense (income)” in our Unaudited Condensed Consolidated Statements of Operations.
Historically, we have entered into various oil and natural gas derivative contracts to provide an economic hedge of our exposure to commodity price risk associated with anticipated future oil and natural gas production and to provide more certainty to our future cash flows. We do not hold or issue derivative financial instruments for trading purposes. Generally, these contracts have consisted of various combinations of price floors, collars, three-way collars, fixed-price swaps, fixed-price swaps enhanced with a sold put, and basis swaps. The production that we hedge has varied from year to year depending on our levels of debt, financial strength, expectation of future commodity prices, and occasionally requirements under our bank credit facility. As of December 31, 2020, we were in compliance with the hedging requirements under our Bank Credit Agreement requiring certain minimum commodity hedge levels through July 31, 2022, and we do not have any additional hedging requirements under the Bank Credit Agreement.
We manage and control market and counterparty credit risk through established internal control procedures that are reviewed on an ongoing basis. We attempt to minimize credit risk exposure to counterparties through formal credit policies, monitoring procedures and diversification, and all of our commodity derivative contracts are with parties that are lenders under our Bank Credit Agreement (or affiliates of such lenders). As of September 30, 2021, all of our outstanding derivative contracts were subject to enforceable master netting arrangements whereby payables on those contracts can be offset against receivables from separate derivative contracts with the same counterparty. It is our policy to classify derivative assets and liabilities on a gross basis on our balance sheets, even if the contracts are subject to enforceable master netting arrangements.
The following table summarizes our commodity derivative contracts as of September 30, 2021, none of which are classified as hedging instruments in accordance with the FASC Derivatives and Hedging topic:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Months | | Index Price | | Volume (Barrels per day) | | Contract Prices ($/Bbl) |
Range(1) | | Weighted Average Price |
Swap | | Floor | | Ceiling |
Oil Contracts: | | | | | | | | | | | | | |
2021 Fixed-Price Swaps | | | | | | | | | | | | | |
Oct – Dec | | NYMEX | | 29,000 | | $ | 38.68 | | – | 56.00 | | | $ | 43.86 | | | $ | — | | | $ | — | |
2021 Collars | | | | | | | | | | | | | |
Oct – Dec | | NYMEX | | 4,000 | | $ | 45.00 | | – | 59.30 | | | $ | — | | | $ | 46.25 | | | $ | 53.04 | |
2022 Fixed-Price Swaps | | | | | | | | | | | | | |
Jan – June | | NYMEX | | 15,500 | | $ | 42.65 | | – | 58.15 | | | $ | 49.01 | | | $ | — | | | $ | — | |
July – Dec | | NYMEX | | 9,000 | | | 50.13 | | – | 60.35 | | | 56.35 | | | — | | | — | |
2022 Collars | | | | | | | | | | | | | |
Jan – June | | NYMEX | | 11,000 | | $ | 47.50 | | – | 70.75 | | | $ | — | | | $ | 49.77 | | | $ | 64.31 | |
July – Dec | | NYMEX | | 10,000 | | | 47.50 | | – | 70.75 | | | — | | | 49.75 | | | 64.18 | |
(1)Ranges presented for fixed-price swaps represent the lowest and highest fixed prices of all open contracts for the period presented. For collars, ranges represent the lowest floor price and highest ceiling price for all open contracts for the period presented.
Note 7. Fair Value Measurements
The FASC Fair Value Measurement topic defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (often referred to as the “exit price”). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the income approach for recurring fair value measurements
Denbury Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
and endeavor to utilize the best available information. Accordingly, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. We are able to classify fair value balances based on the observability of those inputs. The FASC establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are as follows:
•Level 1 – Quoted prices in active markets for identical assets or liabilities as of the reporting date.
•Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reported date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. Instruments in this category include non-exchange-traded oil derivatives that are based on NYMEX and regional pricing other than NYMEX (e.g., Light Louisiana Sweet). Our costless collars and the sold put features of our three-way collars are valued using the Black-Scholes model, an industry standard option valuation model that takes into account inputs such as contractual prices for the underlying instruments, maturity, quoted forward prices for commodities, interest rates, volatility factors and credit worthiness, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.
•Level 3 – Pricing inputs include significant inputs that are generally less observable. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value.
We adjust the valuations from the valuation model for nonperformance risk, using our estimate of the counterparty’s credit quality for asset positions and our credit quality for liability positions. We use multiple sources of third-party credit data in determining counterparty nonperformance risk, including credit default swaps.
The following table sets forth, by level within the fair value hierarchy, our financial assets and liabilities that were accounted for at fair value on a recurring basis as of the periods indicated:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Fair Value Measurements Using: |
In thousands | | Quoted Prices in Active Markets (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Unobservable Inputs (Level 3) | | Total |
September 30, 2021 | | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
Liabilities | | | | | | | | |
Oil derivative contracts – current | | $ | — | | | $ | (193,015) | | | $ | — | | | $ | (193,015) | |
Oil derivative contracts – long-term | | — | | | (16,435) | | | — | | | (16,435) | |
Total Liabilities | | $ | — | | | $ | (209,450) | | | $ | — | | | $ | (209,450) | |
| | | | | | | | |
December 31, 2020 | | | | | | | | |
Assets | | | | | | | | |
Oil derivative contracts – current | | $ | — | | | $ | 187 | | | $ | — | | | $ | 187 | |
Total Assets | | $ | — | | | $ | 187 | | | $ | — | | | $ | 187 | |
| | | | | | | | |
Liabilities | | | | | | | | |
Oil derivative contracts – current | | $ | — | | | $ | (53,865) | | | $ | — | | | $ | (53,865) | |
Oil derivative contracts – long-term | | — | | | (5,087) | | | — | | | (5,087) | |
Total Liabilities | | $ | — | | | $ | (58,952) | | | $ | — | | | $ | (58,952) | |
Denbury Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
Since we do not apply hedge accounting for our commodity derivative contracts, any gains and losses on our assets and liabilities are included in “Commodity derivatives expense (income)” in the accompanying Unaudited Condensed Consolidated Statements of Operations.
Other Fair Value Measurements
The carrying value of our loans under our Bank Credit Agreement approximate fair value, as they are subject to short-term floating interest rates that approximate the rates available to us for those periods. The estimated fair value of the principal amount of our debt as of December 31, 2020, excluding pipeline financing obligations, was $70.0 million. We have other financial instruments consisting primarily of cash, cash equivalents, U.S. Treasury notes, short-term receivables and payables that approximate fair value due to the nature of the instrument and the relatively short maturities.
Note 8. Commitments and Contingencies
Litigation
We are involved in various lawsuits, claims and regulatory proceedings incidental to our businesses. We are also subject to audits for various taxes (income, sales and use, and severance) in the various states in which we operate, and from time to time receive assessments for potential taxes that we may owe. While we currently believe that the ultimate outcome of these proceedings, individually and in the aggregate, will not have a material adverse effect on our financial position, results of operations or cash flows, litigation is subject to inherent uncertainties. We accrue for losses from litigation and claims if we determine that a loss is probable and the amount can be reasonably estimated.
Note 9. Additional Balance Sheet Details
Accounts Payable and Accrued Liabilities
| | | | | | | | | | | | | | |
| | Successor |
In thousands | | September 30, 2021 | | December 31, 2020 |
Accounts payable | | $ | 38,578 | | | $ | 18,629 | |
Accrued compensation | | 33,961 | | | 7,512 | |
Accrued derivative settlements | | 26,311 | | | 3,908 | |
Accrued lease operating expenses | | 25,724 | | | 21,294 | |
Accrued exploration and development costs | | 20,728 | | | 1,861 | |
Taxes payable | | 14,468 | | | 17,221 | |
Accrued general and administrative expenses | | 2,595 | | | 21,825 | |
Other | | 49,529 | | | 20,421 | |
Total | | $ | 211,894 | | | $ | 112,671 | |
Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis should be read in conjunction with our Unaudited Condensed Consolidated Financial Statements and Notes thereto included herein and our Consolidated Financial Statements and Notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2020 (the “Form 10-K”), along with Management’s Discussion and Analysis of Financial Condition and Results of Operations contained in the Form 10-K. Any terms used but not defined herein have the same meaning given to them in the Form 10-K.
As a result of the Company’s emergence from bankruptcy and adoption of fresh start accounting on September 18, 2020 (the “Emergence Date”), certain values and operational results of the condensed consolidated financial statements subsequent to September 18, 2020 are not comparable to those in the Company’s condensed consolidated financial statements prior to, and including September 18, 2020. The Emergence Date fair values of the Successor’s assets and liabilities differ materially from their recorded values as reflected on the historical balance sheets of the Predecessor contained in periodic reports previously filed with the Securities and Exchange Commission. References to “Successor” relate to the financial position and results of operations of the Company subsequent to September 18, 2020, and references to “Predecessor” relate to the financial position and results of operations of the Company prior to, and including, September 18, 2020.
Our discussion and analysis includes forward-looking information that involves risks and uncertainties and should be read in conjunction with Risk Factors under Item 1A of the Form 10-K, along with Forward-Looking Information at the end of this section for information on the risks and uncertainties that could cause our actual results to be materially different than our forward-looking statements.
OVERVIEW
Denbury is an independent energy company with operations focused in the Gulf Coast and Rocky Mountain regions. The Company is differentiated by its focus on CO2 enhanced oil recovery (“EOR”) and the emerging carbon capture, use, and storage (“CCUS”) industry, supported by the Company’s CO2 EOR technical and operational expertise and its extensive CO2 pipeline infrastructure. The utilization of captured industrial-sourced CO2 in EOR significantly reduces the carbon footprint of the oil that Denbury produces, making the Company’s scope 1 and 2 CO2 emissions negative today, with a goal to also fully offset its scope 1, 2, and 3 CO2 emissions within this decade, primarily through increasing the amount of captured industrial-sourced CO2 used in its operations.
Oil Price Impact on Our Business. Our financial results are significantly impacted by changes in oil prices, as 97% of our sales volumes are oil. Changes in oil prices impact all aspects of our business; most notably our cash flows from operations, revenues, capital allocation and budgeting decisions, and oil and natural gas reserves volumes. The table below
Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
outlines selected financial items and sales volumes, along with changes in our realized oil prices, before and after commodity derivative impacts, for our most recent comparative quarterly periods:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended | | |
In thousands, except per-unit data | | Sept. 30, 2021 | | June 30, 2021 | | March 31, 2021 | | Dec. 31, 2020 | | Sept. 30, 2020 | | |
Oil, natural gas, and related product sales | | $ | 308,454 | | | $ | 282,708 | | | $ | 235,445 | | | $ | 178,787 | | | $ | 175,411 | | | | | |
Receipt (payment) on settlements of commodity derivatives | | (77,670) | | | (63,343) | | | (38,453) | | | 14,429 | | | 17,789 | | | | | |
Oil, natural gas, and related product sales and commodity settlements, combined | | $ | 230,784 | | | $ | 219,365 | | | $ | 196,992 | | | $ | 193,216 | | | $ | 193,200 | | | | | |
| | | | | | | | | | | | | | |
Average daily sales (BOE/d) | | 49,682 | | | 49,133 | | | 47,357 | | | 48,805 | | | 49,686 | | | | | |
| | | | | | | | | | | | | | |
Average net realized oil prices | | | | | | | | | | | | | | |
Oil price per Bbl - excluding impact of derivative settlements | | $ | 68.88 | | | $ | 64.70 | | | $ | 56.28 | | | $ | 40.63 | | | $ | 39.23 | | | | | |
Oil price per Bbl - including impact of derivative settlements | | 51.35 | | | 50.10 | | | 47.00 | | | 43.94 | | | 43.23 | | | | | |
NYMEX WTI oil prices strengthened from the mid-$40s per Bbl range in December 2020 to an average of approximately $71 per Bbl during the third quarter of 2021, reaching highs of over $75 per Bbl in early-July 2021 and late-September 2021.
The benefit of the steady growth in our oil sales over the last four quarters due to rising oil prices has been offset in part by our payments on settlement of commodity derivative contracts, especially in the second and third quarters of 2021, principally due to the strike prices of our fixed-price swaps which were entered into in late 2020 based on the hedging requirements we were obligated to meet under our bank credit facility. During the first nine months of 2021, we paid $179.5 million related to the expiration of commodity derivative contracts and expect to make additional payments on the settlement of our contracts expiring during the fourth quarter of 2021. Our current hedging levels decrease significantly in 2022, and we are hedged at more favorable prices and with a greater mix of collars, allowing for additional upside. We do not have any additional hedging requirements under our bank credit facility.
Third Quarter 2021 Financial Results and Highlights. We recognized net income of $82.7 million, or $1.51 per diluted common share, during the third quarter of 2021. As a result of Denbury filing for bankruptcy and emerging from bankruptcy during the same quarter, our prior-year quarterly financial results are broken out between the predecessor period (July 1, 2020 through September 18, 2020) and the successor period (September 19, 2020 through September 30, 2020). For the predecessor period from July 1, 2020 through September 18, 2020, we recognized a net loss of $809.1 million, and for the successor period from September 19, 2020 through September 30, 2020, we recognized net income of $2.8 million. The principal determinant of our comparative third quarter results between 2020 and 2021 were (a) an $850.0 million charge for reorganization items, net, during the prior-year predecessor period, primarily consisting of fresh start accounting adjustments and (b) a $261.7 million full cost pool ceiling test write-down during the prior-year predecessor period. Additional drivers of the comparative operating results include the following:
•Oil and natural gas revenues increased $133.0 million (76%), nearly entirely due to an increase in commodity prices;
•Lease operating expenses increased $45.3 million, primarily due to (a) a $15.4 million insurance reimbursement that reduced lease operating expenses in the prior-year period, (b) an increase of $8.1 million related to the March 2021 Wind River Basin acquisition, and (c) higher expenses across all lease operating expense categories, largely driven by higher commodity prices and increased workover activity; and
•Commodity derivatives expense increased by $41.2 million consisting of a $95.5 million decrease in cash receipts upon contract settlements ($77.7 million in payments during the third quarter of 2021 compared to $17.8 million in receipts upon settlements during the third quarter of 2020), partially offset by a $54.3 million improvement in noncash fair value changes ($35.9 million of income in the current period compared to $18.4 million of expense in the prior-year period).
Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Third Quarter 2021 Houston Area Land Sales. During the third quarter of 2021, we completed sales of a portion of certain non-producing surface acreage in the Houston area. We recognized cash proceeds of $11.8 million from the sales and recorded a $7.0 million gain to “Other income” in our Unaudited Condensed Consolidated Statements of Operations.
June 2021 Divestiture of Hartzog Draw Deep Mineral Rights. On June 30, 2021, we closed the sale of undeveloped, unconventional deep mineral rights in Hartzog Draw Field in Wyoming. The cash proceeds of $18 million were recorded to “Proved properties” in our Unaudited Condensed Consolidated Balance Sheets. The proceeds reduced our full cost pool; therefore, no gain or loss was recorded on the transaction, and the sale had no impact on our production or reserves.
March 2021 Acquisition of Wyoming CO2 EOR Fields. On March 3, 2021, we acquired a nearly 100% working interest (approximately 83% net revenue interest) in the Big Sand Draw and Beaver Creek EOR fields (collectively “Wind River Basin”) located in Wyoming from a subsidiary of Devon Energy Corporation for $10.9 million cash (after final closing adjustments), including surface facilities and a 46-mile CO2 transportation pipeline to the acquired fields. The acquisition agreement provides for us to make two contingent cash payments, one in January 2022 and one in January 2023, of $4 million each, conditioned on NYMEX WTI oil prices averaging at least $50 per Bbl during each of 2021 and 2022. As of September 30, 2021, the contingent consideration was recorded on our unaudited condensed consolidated balance sheets at its fair value of $7.4 million, a $2.1 million increase from the March 2021 acquisition date fair value. This $2.1 million increase at September 30, 2021 was the result of higher NYMEX WTI oil prices and was recorded to “Other expenses” in our Unaudited Condensed Consolidated Statements of Operations. Wind River Basin sales averaged approximately 3,015 BOE/d during the third quarter of 2021 and utilize 100% industrial-sourced CO2.
Carbon Capture, Use and Storage. CCUS is a process that captures CO2 from industrial sources and reuses it or stores the CO2 in geologic formations in order to prevent its release into the atmosphere. We utilize CO2 from industrial sources in our EOR operations, and our extensive CO2 pipeline infrastructure and operations, particularly in the Gulf Coast, are strategically located in close proximity to large sources of industrial emissions. We believe that the assets and technical expertise required for CCUS are highly aligned with our existing CO2 EOR operations, providing us with a significant advantage and opportunity to participate in the emerging CCUS industry, as the building of a permanent carbon sequestration business requires both time and capital to build assets such as those we own and have been operating for years. During the nine months ended September 30, 2021, approximately 34% of the CO2 utilized in our oil and gas operations was industrial-sourced CO2, and we anticipate this percentage could increase in the future as supportive U.S. government policy and public pressure on industrial CO2 emitters will provide strong incentives for these entities to capture their CO2 emissions.
As we seek to grow our CCUS business and pursue new CCUS opportunities, we have been engaged in discussions with existing and potential third-party industrial CO2 emitters regarding transportation and storage solutions, while also identifying potential future sequestration sites and landowners of those locations. We continue to make progress in these discussions and have recently executed several term sheets for the future transportation and sequestration of CO2. While EOR is the only CCUS operation reflected in our current and historical financial and operational results, and development of our permanent carbon sequestration business is likely to take several years, we believe Denbury is well positioned to leverage our existing CO2 pipeline infrastructure and EOR expertise to be a leader in this industry.
CAPITAL RESOURCES AND LIQUIDITY
Overview. Our cash flows from operations and availability under our senior secured bank credit facility are our primary sources of capital and liquidity. Our most significant cash capital outlays in 2021 relate to our budgeted development capital expenditures and payment of $70 million of pipeline financing obligations associated with the NEJD pipeline. Based on our current 2021 full-year projections using recent oil price futures, our cash flow from operations in 2021 should be more than adequate to cover our remaining budgeted development capital expenditures and also cover a significant portion of our $70 million repayment of pipeline financing obligations. In addition, $29.8 million of non-producing property sales in the first nine months of 2021 provided cash to further reduce our debt.
As of September 30, 2021, we had no outstanding borrowings on our $575 million senior secured bank credit facility, leaving us with $563.2 million of borrowing base availability after consideration of $11.8 million of outstanding letters of credit. Our borrowing base availability, coupled with unrestricted cash of $1.8 million provides us total liquidity of
Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
$565.0 million as of September 30, 2021, which is more than adequate to meet our currently planned operating and capital needs.
2021 Capital Expenditures. Capital expenditures during the first nine months of 2021 were $173.8 million. We continue to anticipate that our full-year 2021 development capital spending, excluding capitalized interest and acquisitions, will be in a range of $250 million to $270 million. Approximately 45% of our 2021 capital expenditures through September 30, 2021 have been focused on the previously announced development of the EOR CO2 flood at Cedar Creek Anticline (“CCA”). The project is currently underway, with completion of the 105-mile extension of the Greencore CO2 pipeline from Bell Creek to CCA expected before the end of November 2021, first CO2 injection planned during the first quarter of 2022, and first tertiary production expected in the second half of 2023.
Capital Expenditure Summary. The following table reflects incurred capital expenditures for the nine months ended September 30, 2021 and 2020:
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| | Nine Months Ended |
| | September 30, |
In thousands | | 2021 | | 2020 |
Capital expenditure summary(1) | | | | |
Tertiary and non-tertiary fields | | $ | 102,640 | | | $ | 41,679 | |
Capitalized internal costs(2) | | 22,639 | | | 26,695 | |
Oil and natural gas capital expenditures | | 125,279 | | | 68,374 | |
CCA CO2 pipeline | | 48,542 | | | 9,192 | |
Development capital expenditures | | 173,821 | | | 77,566 | |
Acquisitions of oil and natural gas properties(3) | | 10,927 | | | 95 | |
Capital expenditures, before capitalized interest | | 184,748 | | | 77,661 | |
Capitalized interest | | 3,500 | | | 23,068 | |
Capital expenditures, total | | $ | 188,248 | | | $ | 100,729 | |
(1)Capital expenditures in this summary are presented on an as-incurred basis (including accruals), and are $45.2 million higher than the capital expenditures in the Unaudited Condensed Consolidated Statements of Cash Flows which are presented on a cash basis.
(2)Includes capitalized internal acquisition, exploration and development costs and pre-production tertiary startup costs.
(3)Primarily consists of working interest positions in the Wind River Basin enhanced oil recovery fields acquired on March 3, 2021.
Supply Chain Issues and Potential Cost Inflation. Recent worldwide and U.S. supply chain issues, together with rising commodity prices and tight labor markets in the U.S., could increase our costs in 2022 and future periods. Most of the cost inflation pressures we have experienced during 2021 have been tied to rising fuel and power costs in our operations; however, there is the potential for more significant increases in the cost of goods and services and wages in our operations which could negatively impact our results of operations and cash flows in future periods.
Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Senior Secured Bank Credit Agreement. In September 2020, we entered into a bank credit agreement with JPMorgan Chase Bank, N.A., as administrative agent, and other lenders party thereto (the “Bank Credit Agreement”). The Bank Credit Agreement is a senior secured revolving credit facility with a maturity date of January 30, 2024. As part of our fall 2021 semiannual borrowing base redetermination, the borrowing base and lender commitments for our Bank Credit Agreement were reaffirmed at $575 million, with our next scheduled redetermination around May 1, 2022. The borrowing base is adjusted at the lenders’ discretion and is based, in part, upon external factors over which we have no control. If our outstanding debt under the Bank Credit Agreement exceeds the then-effective borrowing base, we would be required to repay the excess amount over a period not to exceed six months. The Bank Credit Agreement contains certain financial performance covenants including the following:
•A Consolidated Total Debt to Consolidated EBITDAX covenant (as defined in the Bank Credit Agreement), with such ratio not to exceed 3.5 times; and
•A requirement to maintain a current ratio (i.e., Consolidated Current Assets to Consolidated Current Liabilities) of 1.0.
For purposes of computing the current ratio per the Bank Credit Agreement, Consolidated Current Assets exclude the current portion of derivative assets but include available borrowing capacity under the Bank Credit Agreement, and Consolidated Current Liabilities exclude the current portion of derivative liabilities as well as the current portions of long-term indebtedness outstanding. Under these financial performance covenant calculations, as of September 30, 2021, our ratio of consolidated total debt to consolidated EBITDAX was 0.05 to 1.0 (with a maximum permitted ratio of 3.5 to 1.0) and our current ratio was 2.60 to 1.0 (with a required ratio of not less than 1.0 to 1.0). Based upon our currently forecasted levels of production and costs, hedges in place as of November 3, 2021, and current oil commodity derivative futures prices, we currently anticipate continuing to be in compliance with our financial performance covenants during the foreseeable future.
The above description of our Bank Credit Agreement is qualified by the express language and defined terms contained in the Bank Credit Agreement, which is an exhibit to our Form 8-K Report filed with the SEC on September 18, 2020.
Commitments and Obligations. We have numerous contractual commitments in the ordinary course of business including debt service requirements, operating and finance leases, purchase obligations, and asset retirement obligations. Our operating leases primarily consist of our office leases. Our purchase obligations represent future cash commitments primarily for purchase contracts for CO2 captured from industrial sources, CO2 processing fees, transportation agreements and well-related costs.
Our commitments and obligations consist of those detailed as of December 31, 2020, in our Form 10-K under Management’s Discussion and Analysis of Financial Condition and Results of Operations – Capital Resources and Liquidity – Commitments, Obligations and Off-Balance Sheet Arrangements. During the nine months ended September 30, 2021, our long-term asset retirement obligations increased by $63.8 million, primarily related to our acquisition of working interest positions in Wyoming CO2 EOR fields (see Note 2, Acquisition and Divestitures).
Off-Balance Sheet Arrangements. Our off-balance sheet arrangements include obligations for various development and exploratory expenditures that arise from our normal capital expenditure program or from other transactions common to our industry, none of which are recorded on our balance sheet. In addition, in order to recover our undeveloped proved reserves, we must also fund the associated future development costs estimated in our proved reserve reports.
Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
RESULTS OF OPERATIONS
Certain of our financial results for our Successor and Predecessor periods are presented in the following tables:
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| | Successor | | | Predecessor | | |
In thousands, except per-share and unit data | | Three Months Ended Sept. 30, 2021 | | Period from Sept. 19, 2020 through Sept. 30, 2020 | | | Period from July 1, 2020 through Sept. 18, 2020 | | | | |
Operating results | | | | | | | | | | | |
Net income (loss)(1) | | $ | 82,708 | | | $ | 2,758 | | | | $ | (809,120) | | | | | |
Net income (loss) per common share – basic(1) | | 1.62 | | | 0.06 | | | | (1.63) | | | | | |
Net income (loss) per common share – diluted(1) | | 1.51 | | | 0.06 | | | | (1.63) | | | | | |
Net cash provided by operating activities | | 104,019 | | | 32,910 | | | | 40,597 | | | | | |
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| | Successor | | | Predecessor |
In thousands, except per-share and unit data | | Nine Months Ended Sept. 30, 2021 | | Period from Sept. 19, 2020 through Sept. 30, 2020 | | | Period from Jan. 1, 2020 through Sept. 18, 2020 |
Operating results | | | | | | | |
Net income (loss)(1) | | $ | (64,629) | | | $ | 2,758 | | | | $ | (1,432,578) | |
Net income (loss) per common share – basic(1) | | (1.27) | | | 0.06 | | | | (2.89) | |
Net income (loss) per common share – diluted(1) | | (1.27) | | | 0.06 | | | | (2.89) | |
Net cash provided by operating activities | | 247,557 | | | 32,910 | | | | 113,408 | |
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(1)Includes a pre-tax full cost pool ceiling test write-down of our oil and natural gas properties of $14.4 million during the first quarter of 2021, as compared to write-downs of $261.7 million and $996.7 million for the Predecessor periods July 1, 2020 through September 18, 2020 and January 1, 2020 through September 18, 2020, respectively. In addition, includes reorganization adjustments, net totaling $850.0 million during the 2020 Predecessor periods.
Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Certain of our operating results and statistics for the comparative three and nine months ended September 30, 2021 and 2020 are included in the following table:
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| | Three Months Ended | | Nine Months Ended |
| | September 30 | | September 30 |
In thousands, except per-share and unit data | | 2021 | | 2020 | | 2021 | | 2020 |
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Average daily sales volumes | | | | | | | | |
Bbls/d | | 48,145 | | | 48,334 | | | 47,276 | | | 50,619 | |
Mcf/d | | 9,222 | | | 8,110 | | | 8,739 | | | 7,916 | |
BOE/d(1) | | 49,682 | | | 49,686 | | | 48,732 | | | 51,939 | |
Oil and natural gas sales | | | | | | | | |
Oil sales | | $ | 305,093 | | | $ | 174,447 | | | $ | 818,714 | | | $ | 511,562 | |
Natural gas sales | | 3,361 | | | 964 | | | 7,893 | | | 2,860 | |
Total oil and natural gas sales | | $ | 308,454 | | | $ | 175,411 | | | $ | 826,607 | | | $ | 514,422 | |
Commodity derivative contracts(2) | | | | | | | | |
Receipt (payment) on settlements of commodity derivatives | | $ | (77,670) | | | $ | 17,789 | | | $ | (179,466) | | | $ | 88,056 | |
Noncash fair value gains (losses) on commodity derivatives | | 35,925 | | | (18,363) | | | (150,686) | | | 18,011 | |
Commodity derivatives income (expense) | | $ | (41,745) | | | $ | (574) | | | $ | (330,152) | | | $ | 106,067 | |
Unit prices – excluding impact of derivative settlements | | | | | | | | |
Oil price per Bbl | | $ | 68.88 | | | $ | 39.23 | | | $ | 63.44 | | | $ | 36.88 | |
Natural gas price per Mcf | | 3.96 | | | 1.29 | | | 3.31 | | | 1.32 | |
Unit prices – including impact of derivative settlements(2) | | | | | | | | |
Oil price per Bbl | | $ | 51.35 | | | $ | 43.23 | | | $ | 49.53 | | | $ | 43.23 | |
Natural gas price per Mcf | | 3.96 | | | 1.29 | | | 3.31 | | | 1.32 | |
Oil and natural gas operating expenses | | | | | | | | |
Lease operating expenses | | $ | 116,536 | | | $ | 71,192 | | | $ | 308,731 | | | $ | 261,755 | |
Transportation and marketing expenses | | 5,985 | | | 9,499 | | | 22,304 | | | 28,508 | |
Production and ad valorem taxes | | 23,464 | | | 13,697 | | | 63,195 | | | 40,450 | |
Oil and natural gas operating revenues and expenses per BOE | | | | | | | | |
Oil and natural gas revenues | | $ | 67.48 | | | $ | 38.37 | | | $ | 62.13 | | | $ | 36.15 | |
Lease operating expenses | | 25.50 | | | 15.57 | | | 23.21 | | | 18.39 | |
Transportation and marketing expenses | | 1.31 | | | 2.08 | | | 1.68 | | | 2.00 | |
Production and ad valorem taxes | | 5.13 | | | 3.00 | | | 4.75 | | | 2.84 | |
CO2 – revenues and expenses | | | | | | | | |
CO2 sales and transportation fees | | $ | 12,237 | | | $ | 7,484 | | | $ | 31,599 | | | $ | 22,016 | |
CO2 operating and discovery expenses | | (1,963) | | | (1,197) | | | (4,487) | | | (2,834) | |
CO2 revenue and expenses, net | | $ | 10,274 | | | $ | 6,287 | | | $ | 27,112 | | | $ | 19,182 | |
(1)Barrel of oil equivalent using the ratio of one barrel of oil to six Mcf of natural gas (“BOE”).
(2)See also Commodity Derivative Contracts below and Item 3. Quantitative and Qualitative Disclosures about Market Risk for information concerning our derivative transactions.
Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Sales Volumes
Average daily sales volumes by area for each of the four quarters of 2020 and for the first three quarters of 2021 is shown below:
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| | Average Daily Sales Volumes (BOE/d) |
| | First Quarter | | Second Quarter | | Third Quarter | | | First Quarter | | Second Quarter | | Third Quarter | | Fourth Quarter |
Operating Area | | 2021 | | 2021 | | 2021 | | | 2020 | | 2020 | | 2020 | | 2020 |
Tertiary oil sales | | | | | | | | | | | | | | | |
Gulf Coast region | | | | | | | | | | | | | | | |
Delhi | | 2,925 | | | 2,931 | | | 2,859 | | | | 3,813 | | | 3,529 | | | 3,208 | | | 3,132 | |
Hastings | | 4,226 | | | 4,487 | | | 4,343 | | | | 5,232 | | | 4,722 | | | 4,473 | | | 4,598 | |
Heidelberg | | 4,054 | | | 3,942 | | | 3,895 | | | | 4,371 | | | 4,366 | | | 4,256 | | | 4,198 | |
Oyster Bayou | | 3,554 | | | 3,791 | | | 3,942 | | | | 3,999 | | | 3,871 | | | 3,526 | | | 3,880 | |
Tinsley | | 3,424 | | | 3,455 | | | 3,390 | | | | 4,355 | | | 3,788 | | | 4,042 | | | 3,654 | |
Other(1) | | 6,098 | | | 6,074 | | | 5,907 | | | | 7,161 | | | 5,944 | | | 6,271 | | | 6,332 | |
Total Gulf Coast region | | 24,281 | | | 24,680 | | | 24,336 | | | | 28,931 | | | 26,220 | | | 25,776 | | | 25,794 | |
Rocky Mountain region | | | | | | | | | | | | | | | |
Bell Creek | | 4,614 | | | 4,394 | | | 4,330 | | | | 5,731 | | | 5,715 | | | 5,551 | | | 5,079 | |
Other(2) | | 2,573 | | | 4,378 | | | 4,703 | | | | 2,199 | | | 1,393 | | | 2,167 | | | 2,007 | |
Total Rocky Mountain region | | 7,187 | | | 8,772 | | | 9,033 | | | | 7,930 | | | 7,108 | | | 7,718 | | | 7,086 | |
Total tertiary oil sales | | 31,468 | | | 33,452 | | | 33,369 | | | | 36,861 | | | 33,328 | | | 33,494 | | | 32,880 | |
Non-tertiary oil and gas sales | | | | | | | | | | | | | | | |
Gulf Coast region | | | | | | | | | | | | | | | |
Total Gulf Coast region | | 3,621 | | | 3,415 | | | 3,763 | | | | 4,173 | | | 3,805 | | | 3,728 | | | 3,523 | |
Rocky Mountain region | | | | | | | | | | | | | | | |
Cedar Creek Anticline | | 11,150 | | | 10,918 | | | 11,182 | | | | 13,046 | | | 11,988 | | | 11,485 | | | 11,433 | |
Other(2) | | 1,118 | | | 1,348 | | | 1,368 | | | | 1,105 | | | 1,069 | | | 979 | | | 969 | |
Total Rocky Mountain region | | 12,268 | | | 12,266 | | | 12,550 | | | | 14,151 | | | 13,057 | | | 12,464 | | | 12,402 | |
Total non-tertiary sales | | 15,889 | | | 15,681 | | | 16,313 | | | | 18,324 | | | 16,862 | | | 16,192 | | | 15,925 | |
Total continuing sales | | 47,357 | | | 49,133 | | | 49,682 | | | | 55,185 | | | 50,190 | | | 49,686 | | | 48,805 | |
Property sales | | | | | | | | | | | | | | | |
Gulf Coast Working Interests Sale(3) | | — | | | — | | | — | | | | 780 | | | — | | | — | | | — | |
Total sales | | 47,357 | | | 49,133 | | | 49,682 | | | | 55,965 | | | 50,190 | | | 49,686 | | | 48,805 | |
(1)Includes our mature properties (Brookhaven, Cranfield, Eucutta, Little Creek, Mallalieu, Martinville, McComb and Soso fields) and West Yellow Creek Field.
(2)Includes sales volumes related to our working interest positions in the Big Sand Draw and Beaver Creek fields acquired on March 3, 2021.
(3)Includes non-tertiary sales related to the March 2020 sale of 50% of our working interests in Webster, Thompson, Manvel, and East Hastings fields (the “Gulf Coast Working Interests Sale”).
Total sales volumes during the third quarter of 2021 averaged 49,682 BOE/d, including 33,369 Bbls/d from tertiary properties and 16,313 BOE/d from non-tertiary properties. This sales volume represents a slight increase of 549 BOE/d (1%) compared to sales levels in the second quarter of 2021 and was essentially flat with third quarter of 2020 sales volumes. The increase on a sequential-quarter basis was primarily attributable to higher sales volumes at our Wind River Basin properties acquired in March 2021 and sales of non-tertiary production at Conroe Field in our Gulf Coast region.
Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Our sales volumes during the three and nine months ended September 30, 2021 were 97% oil, consistent with our sales during the same prior-year periods.
Oil and Natural Gas Revenues
Our oil and natural gas revenues during the three and nine months ended September 30, 2021 increased 76% and 61%, respectively, compared to these revenues for the same periods in 2020. The changes in our oil and natural gas revenues are due primarily to higher realized commodity prices (excluding any impact of our commodity derivative contracts), with the change during the nine months ended September 30, 2021 offset somewhat by changes in sales volumes, as reflected in the following table:
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| | Three Months Ended | | Nine Months Ended |
| | September 30, | | September 30, |
| | 2021 vs. 2020 | | 2021 vs. 2020 |
In thousands | | Increase (Decrease) in Revenues | | Percentage Increase in Revenues | | Increase (Decrease) in Revenues | | Percentage Increase (Decrease) in Revenues |
Change in oil and natural gas revenues due to: | | | | | | | | |
Decrease in sales volumes | | $ | (14) | | | 0 | % | | $ | (33,517) | | | (6) | % |
Increase in realized commodity prices | | 133,057 | | | 76 | % | | 345,702 | | | 67 | % |
Total increase in oil and natural gas revenues | | $ | 133,043 | | | 76 | % | | $ | 312,185 | | | 61 | % |
Excluding any impact of our commodity derivative contracts, our average net realized commodity prices and NYMEX differentials were as follows during each of the first three quarters and nine months ended September 30, 2021 and 2020:
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| | Three Months Ended | | Nine Months Ended |
| | March 31, | | June 30, | | September 30, | | September 30, |
| | 2021 | | 2020 | | 2021 | | 2020 | | 2021 | | 2020 | | 2021 | | 2020 |
Average net realized prices | | | | | | | | | | | | | | | | |
Oil price per Bbl | | $ | 56.28 | | | $ | 45.96 | | | $ | 64.70 | | | $ | 24.39 | | | $ | 68.88 | | | $ | 39.23 | | | $ | 63.44 | | | $ | 36.88 | |
Natural gas price per Mcf | | 3.29 | | | 1.46 | | | 2.64 | | | 1.21 | | | 3.96 | | | 1.29 | | | 3.31 | | | 1.32 | |
Price per BOE | | 55.24 | | | 45.09 | | | 63.23 | | | 23.95 | | | 67.48 | | | 38.37 | | | 62.13 | | | 36.15 | |
Average NYMEX differentials | | | | | | | | | | | | | | | | |
Gulf Coast region | | | | | | | | | | | | | | | | |
Oil per Bbl | | $ | (1.37) | | | $ | 1.18 | | | $ | (1.13) | | | $ | (3.59) | | | $ | (1.77) | | | $ | (1.38) | | | $ | (1.40) | | | $ | (0.86) | |
Natural gas per Mcf | | 0.68 | | | (0.06) | | | (0.11) | | | (0.09) | | | 0.16 | | | (0.06) | | | 0.26 | | | (0.07) | |
Rocky Mountain region | | | | | | | | | | | | | | | | |
Oil per Bbl | | $ | (1.80) | | | $ | (2.78) | | | $ | (1.59) | | | $ | (4.68) | | | $ | (1.72) | | | $ | (2.03) | | | $ | (1.49) | | | $ | (2.89) | |
Natural gas per Mcf | | 0.49 | | | (0.91) | | | (0.47) | | | (1.04) | | | (0.65) | | | (1.74) | | | (0.22) | | | (1.25) | |
Total Company | | | | | | | | | | | | | | | | |
Oil per Bbl | | $ | (1.54) | | | $ | (0.38) | | | $ | (1.32) | | | $ | (4.03) | | | $ | (1.75) | | | $ | (1.64) | | | $ | (1.44) | | | $ | (1.67) | |
Natural gas per Mcf | | 0.58 | | | (0.41) | | | (0.33) | | | (0.54) | | | (0.33) | | | (0.83) | | | (0.02) | | | (0.60) | |
Prices received in a regional market fluctuate frequently and can differ from NYMEX pricing due to a variety of reasons, including supply and/or demand factors, crude oil quality, and location differentials.
•Gulf Coast Region. Our average NYMEX oil differential in the Gulf Coast region was a negative $1.77 per Bbl during the third quarter of 2021, compared to a negative $1.38 per Bbl during the third quarter of 2020 and a negative $1.13 per Bbl during the second quarter of 2021. NYMEX WTI oil prices continued to strengthen during the third quarter of 2021; however, the pricing for our Gulf Coast grades weakened relative to NYMEX WTI index prices. For
Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
our crude oil sold under Light Louisiana Sweet (“LLS”) index prices, the LLS-to-NYMEX differential averaged a positive $0.98 per Bbl on a trade-month basis for the third quarter of 2021, compared to a positive $1.52 per Bbl differential in the third quarter of 2020 and a positive $2.10 per Bbl in the second quarter of 2021.
•Rocky Mountain Region. NYMEX oil differentials in the Rocky Mountain region averaged $1.72 per Bbl and $2.03 per Bbl below NYMEX during the third quarters of 2021 and 2020, respectively, and $1.59 per Bbl below NYMEX during the second quarter of 2021. Differentials in the Rocky Mountain region tend to fluctuate with regional supply and demand trends and can fluctuate significantly on a month-to-month basis due to weather, refinery or transportation issues, and Canadian and U.S. crude oil price index volatility.
CO2 Revenues and Expenses
We sell CO2 produced from Jackson Dome to third-party industrial users at various contracted prices primarily under long-term contracts. We recognize the revenue received on these CO2 sales as “CO2 sales and transportation fees” with the corresponding costs recognized as “CO2 operating and discovery expenses” in our Unaudited Condensed Consolidated Statements of Operations. CO2 sales and transportation fees were $12.2 million and $31.6 million during the three and nine months ended September 30, 2021, respectively, compared to $7.5 million and $22.0 million during the combined Predecessor and Successor periods included within the three and nine-month periods ended September 30, 2020, respectively. The increases from the prior-year periods were primarily due to an increase in CO2 sales volumes to our industrial CO2 customers.
Oil Marketing Revenues and Purchases
In certain situations, we purchase and subsequently sell oil from third parties. We recognize the revenue received and the associated expenses incurred on these sales on a gross basis as “Oil marketing revenues” and “Oil marketing purchases” in our Unaudited Condensed Consolidated Statements of Operations.
Commodity Derivative Contracts
The following tables summarize the impact our crude oil derivative contracts had on our operating results for the three and nine months ended September 30, 2021 and 2020:
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| | Successor | | | Predecessor | | | | | |
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In thousands | | Three Months Ended Sept. 30, 2021 | | Period from Sept. 19, 2020 through Sept. 30, 2020 | | | Period from July 1, 2020 through Sept. 18, 2020 | | | | | |
Receipt (payment) on settlements of commodity derivatives | | $ | (77,670) | | | $ | 6,660 | | | | $ | 11,129 | | | | | | |
Noncash fair value gains (losses) on commodity derivatives | | 35,925 | | | (2,625) | | | | (15,738) | | | | | | |
Total income (expense) | | $ | (41,745) | | | $ | 4,035 | | | | $ | (4,609) | | | | | | |
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| | Successor | | | Predecessor |
In thousands | | Nine Months Ended Sept. 30, 2021 | | Period from Sept. 19, 2020 through Sept. 30, 2020 | | | Period from Jan. 1, 2020 through Sept. 18, 2020 |
Receipt (payment) on settlements of commodity derivatives | | $ | (179,466) | | | $ | 6,660 | | | | $ | 81,396 | |
Noncash fair value gains (losses) on commodity derivatives(1) | | (150,686) | | | (2,625) | | | | 20,636 | |
Total income (expense) | | $ | (330,152) | | | $ | 4,035 | | | | $ | 102,032 | |
Changes in our commodity derivatives expense were primarily related to the expiration of commodity derivative contracts, new commodity derivative contracts entered into for future periods, and to the changes in oil futures prices between the third quarters of 2020 and 2021. The period-to-period changes reflect the very large fluctuations in oil prices between March 2020 ($30.45 per barrel), when worldwide financial markets were first beginning to absorb the potential impact of a global pandemic,
Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
and September 2021 oil prices ($71.54 per barrel) as prospects for increased economic activity and oil demand showed improvement.
Largely based on the hedging requirements that we were obligated to meet under our bank credit facility, which required certain minimum commodity hedge levels through July 31, 2022, we have oil commodity hedges in place for a portion of our estimated oil production through 2022 using NYMEX fixed-price swaps and costless collars. We do not have any additional hedging requirements under our Bank Credit Agreement. See Note 6, Commodity Derivative Contracts, to the Unaudited Condensed Consolidated Financial Statements for additional details of our outstanding commodity derivative contracts as of September 30, 2021, and Item 3, Quantitative and Qualitative Disclosures about Market Risk below for additional discussion. In addition, the following table summarizes our commodity derivative contracts as of November 3, 2021:
| | | | | | | | | | | | | | | | | | | | | | | |
| | | 4Q 2021 | | 1H 2022 | | 2H 2022 |
WTI NYMEX | Volumes Hedged (Bbls/d) | | 29,000 | | 15,500 | | 9,000 |
Fixed-Price Swaps | Swap Price(1) | | $43.86 | | $49.01 | | $56.35 |
WTI NYMEX | Volumes Hedged (Bbls/d) | | 4,000 | | 11,000 | | 10,000 |
Collars | Floor / Ceiling Price(1) | | $46.25 / $53.04 | | $49.77 / $64.31 | | $49.75 / $64.18 |
| Total Volumes Hedged (Bbls/d) | | 33,000 | | 26,500 | | 19,000 |
(1)Averages are volume weighted.
Based on current contracts in place and NYMEX oil futures prices as of November 3, 2021, which averaged approximately $81 per Bbl, we currently expect that we would make cash payments of approximately $110 million upon settlement of our October through December 2021 contracts, the amount of which is primarily dependent upon fluctuations in future NYMEX oil prices in relation to the prices of our remaining 2021 fixed-price swaps which have a weighted average NYMEX oil price of $43.86 per Bbl. Changes in commodity prices, expiration of contracts, and new commodity contracts entered into cause fluctuations in the estimated fair value of our oil derivative contracts. Because we do not utilize hedge accounting for our commodity derivative contracts, the period-to-period changes in the fair value of these contracts, as outlined above, are recognized in our statements of operations.
Production Expenses
Lease Operating Expenses
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Successor | | | Predecessor | | | | | |
| | | | | | | | | | | | |
In thousands, except per-BOE data | | Three Months Ended Sept. 30, 2021 | | Period from Sept. 19, 2020 through Sept. 30, 2020 | | | Period from July 1, 2020 through Sept. 18, 2020 | | | | | |
Total lease operating expenses | | $ | 116,536 | | | $ | 11,484 | | | | $ | 59,708 | | | | | | |
| | | | | | | | | | | | |
Total lease operating expenses per BOE | | $ | 25.50 | | | $ | 19.20 | | | | $ | 15.03 | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | Successor | | | Predecessor |
In thousands, except per-BOE data | | Nine Months Ended Sept. 30, 2021 | | Period from Sept. 19, 2020 through Sept. 30, 2020 | | | Period from Jan. 1, 2020 through Sept. 18, 2020 |
Total lease operating expenses | | $ | 308,731 | | | $ | 11,484 | | | | $ | 250,271 | |
| | | | | | | |
Total lease operating expenses per BOE | | $ | 23.21 | | | $ | 19.20 | | | | $ | 18.36 | |
Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Total lease operating expenses were $116.5 million, or $25.50 per BOE, during the three months ended September 30, 2021, compared to $71.2 million, or $15.57 per BOE, for the combined Predecessor and Successor periods included within the three months ended September 30, 2020. Total lease operating expenses were $308.7 million, or $23.21 per BOE, during the nine months ended September 30, 2021, compared to $261.8 million, or $18.39, for the combined Predecessor and Successor periods included within the nine months ended September 30, 2020. The increases on an absolute-dollar basis and per-BOE basis were primarily due to (a) an insurance reimbursement totaling $15.4 million recorded in the third quarter of 2020 for previously-incurred well control costs, cleanup costs, and damages associated with a 2013 incident at Delhi Field (b) $8.1 million and $17.0 million of expense during the three and nine months ended September 30, 2021, respectively, related to the Wind River Basin acquisition in March 2021, as these properties have higher operating costs than our other fields (c) higher expenses across nearly all expense categories as our costs are correlated to varying degrees with changes in oil prices (reflecting rising oil prices in 2021) and (d) 2020 period reduced spending and shut-in production in response to significantly lower oil prices in the third quarter of 2020. Lease operating expenses for the nine months ended September 30, 2021 were offset by a $7.6 million reduction in power and fuel costs. The significant reduction in power and fuel costs was associated with the severe winter storm in February 2021 which created widespread power outages in Texas and disrupted the Company’s operations. Under certain of the Company’s power agreements the Company is compensated for its reduced power usage, which resulted in a benefit to the Company of approximately $16.1 million; as of September 30, 2021; $10.3 million of these savings were included in “Trade and other receivables, net” and $1.7 million included in “Other assets” in our Unaudited Condensed Consolidated Balance Sheets. Compared to the second quarter of 2021, lease operating expenses in the most recent quarter increased $6.3 million (6%) on an absolute-dollar basis and $0.85 (3%) on a per-BOE basis, due primarily to higher power and fuel costs and contract labor.
Transportation and Marketing Expenses
Transportation and marketing expenses primarily consist of amounts incurred relating to the transportation, marketing, and processing of oil and natural gas production. Transportation and marketing expenses were $6.0 million for the three months ended September 30, 2021, compared to $9.5 million for the combined Predecessor and Successor periods included within the three months ended September 30, 2020. Transportation and marketing expenses were $22.3 million for the nine months ended September 30, 2021, compared to $28.5 million for the combined Predecessor and Successor periods included within the nine months ended September 30, 2020. The decrease during the comparative three-month periods was primarily due to changes to a portion of our transportation agreements in the Rocky Mountain region during the third quarter of 2021 to begin selling our production at Guernsey, Wyoming versus Cushing, Oklahoma. The decrease between the comparative nine-month periods was primarily due to lower sales volumes during 2021.
Taxes Other Than Income
Taxes other than income includes production, ad valorem and franchise taxes. Taxes other than income were $24.2 million during the three months ended September 30, 2021, compared to $15.5 million for the combined Predecessor and Successor periods included within the three months ended September 30, 2020. Taxes other than income were $65.5 million during the nine months ended September 30, 2021, compared to $45.6 million for the combined Predecessor and Successor periods included within the nine months ended September 30, 2020. The increases in both periods when compared to 2020 were due primarily to an increase in production taxes resulting from higher oil and natural gas revenues.
Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
General and Administrative Expenses (“G&A”)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Successor | | | Predecessor | | | | | | | |
| | | | | | | | | | | | | | |
In thousands, except per-BOE data and employees | | Three Months Ended Sept. 30, 2021 | | Period from Sept. 19, 2020 through Sept. 30, 2020 | | | Period from July 1, 2020 through Sept. 18, 2020 | | | | | | | | | |
Cash G&A costs | | $ | 12,832 | | | $ | 1,735 | | | | $ | 14,442 | | | | | | | | | | |
Stock-based compensation | | 2,556 | | | — | | | | 571 | | | | | | | | | | |
G&A expense | | $ | 15,388 | | | $ | 1,735 | | | | $ | 15,013 | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
G&A per BOE | | | | | | | | | | | | | | | | |
Cash G&A costs | | $ | 2.81 | | | $ | 2.90 | | | | $ | 3.64 | | | | | | | | | | |
Stock-based compensation | | 0.56 | | | — | | | | 0.14 | | | | | | | | | | |
G&A expenses | | $ | 3.37 | | | $ | 2.90 | | | | $ | 3.78 | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
Employees as of period end | | 698 | | 663 | | | | 662 | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | Successor | | | Predecessor |
| | | | | | | |
In thousands, except per-BOE data | | Nine Months Ended Sept. 30, 2021 | | Period from Sept. 19, 2020 through Sept. 30, 2020 | | | Period from Jan. 1, 2020 through Sept. 18, 2020 |
Cash G&A costs | | $ | 40,033 | | | $ | 1,735 | | | | $ | 44,411 | |
Stock-based compensation | | 22,788 | | | — | | | | 4,111 | |
G&A expense | | $ | 62,821 | | | $ | 1,735 | | | | $ | 48,522 | |
| | | | | | | |
G&A per BOE | | | | | | | |
Cash G&A costs | | $ | 3.01 | | | $ | 2.90 | | | | $ | 3.26 | |
Stock-based compensation | | 1.71 | | | — | | | | 0.30 | |
G&A expenses | | $ | 4.72 | | | $ | 2.90 | | | | $ | 3.56 | |
Our G&A expense on an absolute-dollar basis was $15.4 million during the three months ended September 30, 2021, a decrease of $1.4 million (8%) from the combined Predecessor and Successor periods included within the three months ended September 30, 2020. The decrease in G&A expense during the three months ended September 30, 2021 compared to 2020, was primarily due to higher operator labor and overhead recovery charges in the current period, partially offset by higher long-term incentives for employees. Our G&A expenses on an absolute-dollar basis were $62.8 million during the nine months ended September 30, 2021, an increase of $12.6 million (25%) from the combined Predecessor and Successor periods within the nine months ended September 30, 2020. The increase in our G&A expenses during the nine months ended September 30, 2021 was primarily due to $15.3 million of stock-based compensation expense in the first quarter of 2021 resulting from the full vesting of performance-based equity awards with vesting parameters tied to the Company’s common stock trading prices, partially offset by higher operator labor and overhead recovery charges. The shares underlying these awards are not currently outstanding as actual delivery of the shares is not scheduled to occur until after the end of the performance period, December 4, 2023.
Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Interest and Financing Expenses
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Successor | | | Predecessor | | | | | |
In thousands, except per-BOE data and interest rates | | Three Months Ended Sept. 30, 2021 | | Period from Sept. 19, 2020 through Sept. 30, 2020 | | | Period from July 1, 2020 through Sept. 18, 2020 | | | | | |
Cash interest(1) | | $ | 1,233 | | | $ | 403 | | | | $ | 17,734 | | | | | | |
Less: interest not reflected as expense for financial reporting purposes(1) | | — | | | — | | | | (6,976) | | | | | | |
Noncash interest expense | | 685 | | | 114 | | | | 347 | | | | | | |
Amortization of debt discount(2) | | — | | | — | | | | 1,303 | | | | | | |
Less: capitalized interest | | (1,249) | | | (183) | | | | (4,704) | | | | | | |
Interest expense, net | | $ | 669 | | | $ | 334 | | | | $ | 7,704 | | | | | | |
Interest expense, net per BOE | | $ | 0.15 | | | $ | 0.56 | | | | $ | 1.94 | | | | | | |
Average debt principal outstanding(3) | | $ | 55,667 | | | $ | 185,877 | | | | $ | 815,025 | | | | | | |
Average cash interest rate(4) | | 8.9 | % | | 6.6 | % | | | 10.0 | % | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | Successor | | | Predecessor |
In thousands, except per-BOE data and interest rates | | Nine Months Ended Sept. 30, 2021 | | Period from Sept. 19, 2020 through Sept. 30, 2020 | | | Period from Jan. 1, 2020 through Sept. 18, 2020 |
Cash interest(1) | | $ | 4,902 | | | $ | 403 | | | | $ | 108,824 | |
Less: interest not reflected as expense for financial reporting purposes(1) | | — | | | — | | | | (49,243) | |
Noncash interest expense | | 2,055 | | | 114 | | | | 2,439 | |
Amortization of debt discount(2) | | — | | | — | | | | 9,132 | |
Less: capitalized interest | | (3,500) | | | (183) | | | | (22,885) | |
Interest expense, net | | $ | 3,457 | | | $ | 334 | | | | $ | 48,267 | |
Interest expense, net per BOE | | $ | 0.26 | | | $ | 0.56 | | | | $ | 3.54 | |
Average debt principal outstanding(3) | | $ | 99,243 | | | $ | 185,877 | | | | $ | 1,767,605 | |
Average cash interest rate(4) | | 6.6 | % | | 6.6 | % | | | 8.6 | % |
(1)Cash interest during the Predecessor periods includes the portion of interest on certain debt instruments accounted for as a reduction of debt for GAAP financial reporting purposes in accordance with FASC 470-60, Troubled Debt Restructuring by Debtors. The portion of interest treated as a reduction of debt related to the Predecessor’s 9% Senior Secured Second Lien Notes due 2021 (the “2021 Notes”) and 9¼% Senior Secured Second Lien Notes due 2022 (the “2022 Notes”). Amounts related to the 2021 Notes and 2022 Notes remaining in future interest payable were written-off on July 30, 2020 (the “Petition Date”).
(2)Represents amortization of debt discounts during the Predecessor periods related to the 7¾% Senior Secured Second Lien Notes due 2024 (the “7¾% Senior Secured Notes”) and 6⅜% Convertible Senior Notes due 2024 (the “2024 Convertible Senior Notes”). Remaining debt discounts were written-off on the Petition Date.
(3)Excludes debt discounts related to the Predecessor’s 7¾% Senior Secured Notes and 2024 Convertible Senior Notes.
(4)Includes commitment fees but excludes debt issue costs and amortization of discount.
Cash interest was $1.2 million during the three months ended September 30, 2021, compared to $18.1 million for the combined Predecessor and Successor periods included within the three months ended September 30, 2020. Cash interest was $4.9 million during the nine months ended September 30, 2021, compared to $109.2 million for the combined Predecessor and Successor periods included within the nine months ended September 30, 2020. The decreases between periods were primarily due to a decrease in the average debt principal outstanding, with the Successor periods reflecting the full extinguishment of all outstanding obligations under our previously outstanding senior secured second lien notes, convertible senior notes, and senior subordinated notes on the Emergence Date, pursuant to the terms of the prepackaged joint plan of reorganization, relieving us of approximately $2.1 billion of debt by issuing equity and/or warrants in the Successor period to the holders of that debt.
Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Depletion, Depreciation, and Amortization (“DD&A”)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Successor | | | Predecessor | | | | | | | |
| | | | | | | | | | | | | | |
In thousands, except per-BOE data | | Three Months Ended Sept. 30, 2021 | | Period from Sept. 19, 2020 through Sept. 30, 2020 | | | Period from July 1, 2020 through Sept. 18, 2020 | | | | | | | | | |
Oil and natural gas properties | | $ | 29,269 | | | $ | 4,105 | | | | $ | 21,636 | | | | | | | | | | |
CO2 properties, pipelines, plants and other property and equipment | | 8,422 | | | 1,178 | | | | 12,890 | | | | | | | | | | |
Accelerated depreciation charge(1) | | — | | | — | | | | 1,791 | | | | | | | | | | |
Total DD&A | | $ | 37,691 | | | $ | 5,283 | | | | $ | 36,317 | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
DD&A per BOE | | | | | | | | | | | | | | | | |
Oil and natural gas properties | | $ | 6.40 | | | $ | 6.86 | | | | $ | 5.45 | | | | | | | | | | |
CO2 properties, pipelines, plants and other property and equipment | | 1.85 | | | 1.97 | | | | 3.24 | | | | | | | | | | |
Accelerated depreciation charge(1) | | — | | | — | | | | 0.45 | | | | | | | | | | |
Total DD&A cost per BOE | | $ | 8.25 | | | $ | 8.83 | | | | $ | 9.14 | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
Write-down of oil and natural gas properties | | $ | — | | | $ | — | | | | $ | 261,677 | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | Successor | | | Predecessor |
| | | | | | | |
In thousands, except per-BOE data | | Nine Months Ended Sept. 30, 2021 | | Period from Sept. 19, 2020 through Sept. 30, 2020 | | | Period from Jan. 1, 2020 through Sept. 18, 2020 |
Oil and natural gas properties | | $ | 89,834 | | | $ | 4,105 | | | | $ | 104,495 | |
CO2 properties, pipelines, plants and other property and equipment | | 23,688 | | | 1,178 | | | | 44,939 | |
Accelerated depreciation charge(1) | | — | | | — | | | | 39,159 | |
Total DD&A | | $ | 113,522 | | | $ | 5,283 | | | | $ | 188,593 | |
| | | | | | | |
DD&A per BOE | | | | | | | |
Oil and natural gas properties | | $ | 6.75 | | | $ | 6.86 | | | | $ | 7.66 | |
CO2 properties, pipelines, plants and other property and equipment | | 1.78 | | | 1.97 | | | | 3.30 | |
Accelerated depreciation charge(1) | | — | | | — | | | | 2.87 | |
Total DD&A cost per BOE | | $ | 8.53 | | | $ | 8.83 | | | | $ | 13.83 | |
| | | | | | | |
Write-down of oil and natural gas properties | | $ | 14,377 | | | $ | — | | | | $ | 996,658 | |
(1)Represents an accelerated depreciation charge related to capitalized amounts associated with unevaluated properties that were transferred to the full cost pool.
DD&A expense was $37.7 million during the three months ended September 30, 2021, compared to $41.6 million for the combined Predecessor and Successor periods included within the three months ended September 30, 2020. DD&A expense was $113.5 million during the nine months ended September 30, 2021, compared to $193.9 million for the combined Predecessor and Successor periods within the nine months ended September 30, 2020. The decreases during the three and nine-month periods ended September 30, 2021 compared to the comparable 2020 periods were primarily due to lower depletable costs due to the step down in book value resulting from fresh start accounting as of September 18, 2020, with the year-over-
Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
year decrease further impacted by accelerated depreciation of $37.4 million in the first quarter of 2020 related to unevaluated properties that were transferred to the full cost pool.
Full Cost Pool Ceiling Test Write-Downs
Under full cost accounting rules, we are required each quarter to perform a ceiling test calculation. Under these rules, the full cost ceiling value is calculated using the average first-day-of-the-month oil and natural gas price for each month during a 12-month rolling period prior to the end of a particular reporting period. We recognized a full cost pool ceiling test write-down of $14.4 million during the three months ended March 31, 2021, with first-day-of-the-month NYMEX oil prices for the preceding 12 months averaging $36.40 per Bbl, after adjustments for market differentials and transportation expenses by field. The write-down was primarily a result of the March 2021 acquisition of Wyoming property interests (see Overview – March 2021 Acquisition of Wyoming CO2 EOR Fields) which was recorded based on a valuation that utilized NYMEX strip oil prices at the acquisition date, which were significantly higher than the average first-day-of-the-month NYMEX oil prices used to value the cost ceiling. The Predecessor also recognized full cost pool ceiling test write-downs of $261.7 million during the period from July 1, 2020 through September 18, 2020, $662.4 million during the three months ended June 30, 2020 and $72.5 million during the three months ended March 31, 2020. We did not record any ceiling test write-down during the Successor periods from September 19, 2020 through September 30, 2020, for the three months ended June 30, 2021, or the three months ended September 30, 2021.
Reorganization Items, Net
Reorganization items, net, include (i) expenses incurred during the Company’s “prepackaged” voluntary bankruptcy subsequent to the Petition Date as a direct result of the Plan, (ii) gains or losses from liabilities settled and (iii) fresh start accounting adjustments and are recorded in “Reorganization items, net” in our Unaudited Condensed Consolidated Statements of Operations. Professional service provider charges associated with our restructuring that were incurred before the Petition Date and after the Emergence Date are recorded in “Other expenses” in our Unaudited Condensed Consolidated Statements of Operations. The following table summarizes the losses (gains) on reorganization items, net:
| | | | | | | | |
| | Predecessor |
In thousands | | Period from July 1, 2020 through Sept. 18, 2020 |
Gain on settlement of liabilities subject to compromise | | $ | (1,024,864) | |
Fresh start accounting adjustments | | 1,834,423 | |
Professional service provider fees and other expenses | | 11,267 | |
Success fees for professional service providers | | 9,700 | |
Loss on rejected contracts and leases | | 10,989 | |
Valuation adjustments to debt classified as subject to compromise | | 757 | |
Debtor-in-possession credit agreement fees | | 3,107 | |
Acceleration of Predecessor stock compensation expense | | 4,601 | |
Total reorganization items, net | | $ | 849,980 | |
Other Expenses
Other expenses totaled $4.6 million and $9.9 million during the three and nine months ended September 30, 2021. Other expenses during 2021 periods primarily include litigation accruals and noncash fair value adjustments for contingent consideration payments related to our March 2021 Wind River Basin CO2 EOR field acquisition. Other expenses totaled $24.2 million for the combined Predecessor and Successor periods included within the three months ended September 30, 2020, and $38.0 million for the combined Predecessor and Successor periods included within the nine months ended September 30, 2020. Other expenses during 2020 primarily are comprised of $24.1 million of professional fees associated with restructuring activities, $4.2 million of write-off of certain trade receivables, $3.8 million of costs associated with the Delta-Tinsley CO2 pipeline incident, and $1.6 million of costs associated with the APMTG Helium, LLC helium supply contract ruling.
Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Income Taxes
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Successor | | | Predecessor | | | | | |
| | | | | | | | | |
In thousands, except per-BOE amounts and tax rates | | Three Months Ended Sept. 30, 2021 | | Period from Sept. 19, 2020 through Sept. 30, 2020 | | | Period from July 1, 2020 through Sept. 18, 2020 | | | | | |
Current income tax expense (benefit) | | $ | 350 | | | $ | 6 | | | | $ | (1,451) | | | | | | |
Deferred income tax expense (benefit) | | 53 | | | 6 | | | | (302,356) | | | | | | |
Total income tax expense (benefit) | | $ | 403 | | | $ | 12 | | | | $ | (303,807) | | | | | | |
Average income tax expense (benefit) per BOE | | $ | 0.09 | | | $ | 0.02 | | | | $ | (76.47) | | | | | | |
Effective tax rate | | 0.5 | % | | 0.4 | % | | | 27.3 | % | | | | | |
Total net deferred tax liability | | $ | 1,241 | | | $ | 3,836 | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | Successor | | | Predecessor |
| | | | | | | |
In thousands, except per-BOE amounts and tax rates | | Nine Months Ended Sept. 30, 2021 | | Period from Sept. 19, 2020 through Sept. 30, 2020 | | | Period from Jan. 1, 2020 through Sept. 18, 2020 |
Current income tax expense (benefit) | | $ | (101) | | | $ | 6 | | | | $ | (7,260) | |
Deferred income tax expense (benefit) | | (34) | | | 6 | | | | (408,869) | |
Total income tax expense (benefit) | | $ | (135) | | | $ | 12 | | | | $ | (416,129) | |
Average income tax expense (benefit) per BOE | | $ | (0.01) | | | $ | 0.02 | | | | $ | (30.52) | |
Effective tax rate | | 0.2 | % | | 0.4 | % | | | 22.5 | % |
We evaluate our estimated annual effective income tax rate based on current and forecasted business results and enacted tax laws on a quarterly basis and apply this tax rate to our ordinary income or loss to calculate our estimated tax liability or benefit. Our income taxes are based on an estimated combined federal and state statutory rate of approximately 25% in 2021 and 2020. Our effective tax rates for the Successor three and nine months ended September 30, 2021 were significantly lower than our estimated statutory rate, primarily due to our overall deferred tax asset position and the valuation allowance offsetting those assets. As we had a pre-tax loss for the nine months ended September 30, 2021, the income tax benefit resulting from these losses is fully offset by the change in valuation allowance, resulting in essentially no tax provision.
As of September 30, 2021, the tax basis of our assets, primarily our oil and gas properties, is in excess of their carrying value, as adjusted for fresh start accounting on September 18, 2020; therefore, we are currently in a net deferred tax asset position. Based on all available evidence, both positive and negative, we continue to record a valuation allowance on our underlying deferred tax assets as of September 30, 2021, as we believe our deferred tax assets are not more-likely-than-not to be realized. We intend to maintain the valuation allowances on our deferred tax assets until there is sufficient evidence to support the reversal of all or some portion of the allowances, which will largely be determined based on oil prices and the Company’s ability to generate positive pre-tax income.
The current income tax benefits for the Predecessor period ended September 18, 2020 represent amounts estimated to be receivable resulting from alternative minimum tax credits and certain state tax obligations.
As of September 30, 2021, we had $0.6 million of alternative minimum tax credits, which under the Tax Cut and Jobs Act will be refunded in 2021 and are recorded as a receivable on the balance sheet. Our state net operating loss carryforwards expire in various years, starting in 2025.
Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Per-BOE Data
The following table summarizes our cash flow and results of operations on a per-BOE basis for the comparative periods. Each of the significant individual components is discussed above.
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended | | Nine Months Ended |
| | September 30, | | September 30, |
Per-BOE data | | 2021 | | 2020 | | 2021 | | 2020 |
Oil and natural gas revenues | | $ | 67.48 | | | $ | 38.37 | | | $ | 62.13 | | | $ | 36.15 | |
Receipt (payment) on settlements of commodity derivatives | | (16.99) | | | 3.90 | | | (13.49) | | | 6.19 | |
Lease operating expenses | | (25.50) | | | (15.57) | | | (23.21) | | | (18.39) | |
Production and ad valorem taxes | | (5.13) | | | (3.00) | | | (4.75) | | | (2.84) | |
Transportation and marketing expenses | | (1.31) | | | (2.08) | | | (1.68) | | | (2.00) | |
Production netback | | 18.55 | | | 21.62 | | | 19.00 | | | 19.11 | |
CO2 sales, net of operating and discovery expenses | | 2.25 | | | 1.38 | | | 2.04 | | | 1.35 | |
General and administrative expenses(1) | | (3.37) | | | (3.66) | | | (4.72) | | | (3.53) | |
Interest expense, net | | (0.15) | | | (1.76) | | | (0.26) | | | (3.42) | |
Reorganization items settled in cash | | — | | | (8.55) | | | — | | | (2.75) | |
Stock compensation and other | | (0.31) | | | (2.72) | | | 1.18 | | | (0.74) | |
Changes in assets and liabilities relating to operations | | 5.79 | | | 9.77 | | | 1.37 | | | 0.26 | |
Cash flows from operations | | 22.76 | | | 16.08 | | | 18.61 | | | 10.28 | |
DD&A – excluding accelerated depreciation charge | | (8.25) | | | (8.71) | | | (8.53) | | | (10.87) | |
DD&A – accelerated depreciation charge(2) | | — | | | (0.39) | | | — | | | (2.75) | |
Write-down of oil and natural gas properties | | — | | | (57.25) | | | (1.08) | | | (70.03) | |
Deferred income taxes | | (0.01) | | | 66.14 | | | — | | | 28.73 | |
Gain on extinguishment of debt | | — | | | — | | | — | | | 1.33 | |
Noncash fair value gains (losses) on commodity derivatives | | 7.86 | | | (4.03) | | | (11.33) | | | 1.26 | |
Noncash reorganization items, net | | — | | | (177.40) | | | — | | | (56.98) | |
Other noncash items | | (4.26) | | | (10.85) | | | (2.53) | | | (1.44) | |
Net income (loss) | | $ | 18.10 | | | $ | (176.41) | | | $ | (4.86) | | | $ | (100.47) | |
(1)General and administrative expenses include $15.3 million of performance stock-based compensation related to the full vesting of outstanding performance awards during the nine months ended September 30, 2021, resulting in a significant non-recurring expense, which if excluded, would have caused these expenses to average $3.58 per BOE.
(2)Represents an accelerated depreciation charge related to impaired unevaluated properties that were transferred to the full cost pool.
CRITICAL ACCOUNTING POLICIES
For additional discussion of our critical accounting policies, see Management’s Discussion and Analysis of Financial Condition and Results of Operations in our Form 10-K. Any new accounting policies or updates to existing accounting policies as a result of new accounting pronouncements have been included in the notes to the Company’s Unaudited Condensed Consolidated Financial Statements contained in this Quarterly Report on Form 10-Q.
FORWARD-LOOKING INFORMATION
The data and/or statements contained in this Quarterly Report on Form 10-Q that are not historical facts, including, but not limited to, statements found in the section Management’s Discussion and Analysis of Financial Condition and Results of Operations, regarding possible or assumed future results of operations, cash flows, production and capital expenditures, and
Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
other plans and objectives for the future operations of Denbury, projections or assumptions as to general economic conditions and the economics of a carbon capture, use and storage industry (“CCUS”), and anticipated effects of COVID-19 on U.S. and global oil demand, are forward-looking statements, as that term is defined in Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), that involve a number of risks and uncertainties. Such forward-looking statements may be or may concern, among other things, the level and sustainability of the recent increases in worldwide oil prices from their COVID-19 coronavirus caused downturn, financial forecasts, oil price volatility, current or future liquidity sources or their adequacy to support our anticipated future activities, statements or predictions related to the ultimate nature, timing and economic aspects of proposed carbon capture, use and storage industry arrangements, possible future write-downs of oil and natural gas reserves, together with assumptions based on current and projected production levels, oil and gas prices and oilfield costs, the impact of current supply chain and inflationary pressures or expectations on our operational or other assets, current or future expectations or estimations of our cash flows or the impact of changes in commodity prices on cash flows, borrowing capacity, price and availability of advantageous commodity derivative contracts or their predicted downside cash flow protection or cash settlement payments required, mark-to-market commodity derivative values, forecasted drilling activity or methods, including the timing and location thereof, the nature of any future asset purchases or sales or the timing or proceeds thereof, estimated timing of commencement of CO2 injections in particular fields or areas, including Cedar Creek Anticline (“CCA”), or initial production responses in tertiary flooding projects, other development activities, finding costs, interpretation or prediction of formation details, hydrocarbon reserve quantities and values, CO2 reserves and supply and their availability, potential reserves, barrels or percentages of recoverable original oil in place, the impact of changes or proposed changes in Federal or state laws or outcomes of any pending litigation, prospective legislation, orders or regulations affecting the oil and gas industry or environmental regulations, competition, rates of return, and overall worldwide or U.S. economic conditions, and other variables surrounding operations and future plans. Such forward-looking statements generally are accompanied by words such as “plan,” “estimate,” “expect,” “predict,” “forecast,” “to our knowledge,” “anticipate,” “projected,” “preliminary,” “should,” “assume,” “believe,” “may” or other words that convey, or are intended to convey, the uncertainty of future events or outcomes. Such forward-looking information is based upon management’s current plans, expectations, estimates, and assumptions and is subject to a number of risks and uncertainties that could significantly and adversely affect current plans, anticipated actions, the timing of such actions and our financial condition and results of operations. As a consequence, actual results may differ materially from expectations, estimates or assumptions expressed in or implied by any forward-looking statements made by us or on our behalf. Among the factors that could cause actual results to differ materially are fluctuations in worldwide oil prices or in U.S. oil prices and consequently in the prices received or demand for our oil produced; decisions as to production levels and/or pricing by OPEC+ or production levels by U.S. producers in future periods; success of our risk management techniques; access to and terms of credit in the commercial banking or other debt markets; fluctuations in the prices of goods and services; the uncertainty of drilling results and reserve estimates; operating hazards and remediation costs; disruption of operations and damages from cybersecurity breaches, or from well incidents, climate events such as hurricanes, tropical storms, floods, forest fires, or other natural occurrences; conditions in the worldwide financial, trade and credit markets; general economic conditions; competition; government regulations, including changes in tax or environmental laws or regulations and consequent unexpected delays, as well as the risks and uncertainties inherent in oil and gas drilling and production activities or that are otherwise discussed in this quarterly report, including, without limitation, the portions referenced above, and the uncertainties set forth from time to time in our other public reports, filings and public statements including, without limitation, the Company’s most recent Form 10-K.
Item 3. Quantitative and Qualitative Disclosures about Market Risk
Commodity Derivative Contracts
We enter into oil derivative contracts to provide an economic hedge of our exposure to commodity price risk associated with anticipated future oil production and to provide more certainty to our future cash flows. We do not hold or issue derivative financial instruments for trading purposes. Generally, these contracts have consisted of various combinations of price floors, collars, three-way collars, fixed-price swaps, fixed-price swaps enhanced with a sold put, and basis swaps. The production that we hedge has varied from year to year depending on our levels of debt, financial strength, expectation of future commodity prices, and occasionally requirements under our bank credit facility. As of December 31, 2020, we were in compliance with hedging requirements under our Bank Credit Agreement requiring certain non-recurring minimum commodity hedge levels covering anticipated crude oil production through July 31, 2022, and we do not have any additional hedging requirements under our Bank Credit Agreement. In order to provide a level of price protection to a portion of our oil production, we have hedged a portion of our estimated oil production through 2022 using NYMEX fixed-price swaps and costless collars. Depending on market conditions, we may continue to add to our existing 2022 hedges. See also Note 6, Commodity Derivative Contracts, and Note 7, Fair Value Measurements, to the Unaudited Condensed Consolidated Financial Statements for additional information regarding our commodity derivative contracts.
All of the mark-to-market valuations used for our commodity derivatives are provided by external sources. We manage and control market and counterparty credit risk through established internal control procedures that are reviewed on an ongoing basis. We attempt to minimize credit risk exposure to counterparties through formal credit policies, monitoring procedures and diversification. All of our commodity derivative contracts are with parties that are lenders under our senior secured bank credit facility (or affiliates of such lenders). We have included an estimate of nonperformance risk in the fair value measurement of our commodity derivative contracts, which we have measured for nonperformance risk based upon credit default swaps or credit spreads.
For accounting purposes, we do not apply hedge accounting treatment to our commodity derivative contracts. This means that any changes in the fair value of these commodity derivative contracts will be charged to earnings instead of charging the effective portion to other comprehensive income and the ineffective portion to earnings.
At September 30, 2021, our commodity derivative contracts were recorded at their fair value, which was a net liability of $209.5 million, a $35.9 million decrease from the $245.4 million net liability recorded at June 30, 2021, and a $150.7 million increase from the $58.8 million net liability recorded at December 31, 2020. These changes are primarily related to the expiration of commodity derivative contracts during the three and nine months ended September 30, 2021, new commodity derivative contracts entered into during 2021 for future periods, and to the changes in oil futures prices from period to period.
Commodity Derivative Sensitivity Analysis
Based on NYMEX crude oil futures prices as of September 30, 2021, and assuming both a 10% increase and decrease thereon, we would expect to make payments on our crude oil derivative contracts outstanding at September 30, 2021 as shown in the following table:
| | | | | | | | |
In thousands | | Receipt / (Payment) |
Based on: | | |
Futures prices as of September 30, 2021 | | $ | (197,214) | |
10% increase in prices | | (277,213) | |
10% decrease in prices | | (125,537) | |
Our commodity derivative contracts are used as an economic hedge of our exposure to commodity price risk associated with anticipated future production. As a result, changes in receipts or payments of our commodity derivative contracts due to changes in commodity prices, as reflected in the above table, would be mostly offset by a corresponding increase or decrease in the cash receipts on sales of our oil production to which those commodity derivative contracts relate.
Item 4. Controls and Procedures
Evaluation of Disclosure Controls and Procedures. As of the end of the period covered by this report, an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) was performed under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of September 30, 2021, to ensure that information that is required to be disclosed in the reports the Company files and submits under the Securities Exchange Act of 1934 is recorded, that it is processed, summarized and reported within the time periods specified in the SEC’s rules and forms; and that information that is required to be disclosed under the Exchange Act is accumulated and communicated to management, including our Chief Executive Officer and our Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosures.
Evaluation of Changes in Internal Control over Financial Reporting. Under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, we have determined that, during the third quarter of fiscal 2021, there were no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
The information under Note 8, Commitments and Contingencies, to the Unaudited Condensed Consolidated Financial Statements is incorporated herein by reference.
Item 1A. Risk Factors
Please refer to Part I, Item 1A of the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2020. There have been no material changes to our risk factors contained in our Annual Report on Form 10-K for the year ended December 31, 2020.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
None.
Item 3. Defaults Upon Senior Securities
None.
Item 4. Mine Safety Disclosures
None.
Item 5. Other Information
None.
Item 6. Exhibits
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Exhibit No. | | Exhibit |
10(a)* | |
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31(a)* | |
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31(b)* | |
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32** | |
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101.INS* | | Inline 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
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101.SCH* | | Inline XBRL Taxonomy Extension Schema Document
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101.CAL* | | Inline XBRL Taxonomy Extension Calculation Linkbase Document
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101.DEF* | | Inline XBRL Taxonomy Extension Definition Linkbase Document
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101.LAB* | | Inline XBRL Taxonomy Extension Label Linkbase Document
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101.PRE* | | Inline XBRL Taxonomy Extension Presentation Linkbase Document
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104 | | The cover page from the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2021, has been formatted in Inline XBRL.
|
* Included herewith.
** Furnished herewith in accordance with Item 601(b)(32) of Regulation S-K.
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.
| | | | | | | | |
| | DENBURY INC. |
| | |
November 4, 2021 | | /s/ Mark C. Allen |
| | Mark C. Allen Executive Vice President and Chief Financial Officer |
| | |
November 4, 2021 | | /s/ Nicole Jennings |
| | Nicole Jennings Vice President and Chief Accounting Officer |
Exhibit 10.1
FIRST AMENDMENT TO CREDIT AGREEMENT
This FIRST AMENDMENT TO CREDIT AGREEMENT (this “First Amendment”) is entered into as of November 3, 2021 (the “First Amendment Effective Date”), by and among DENBURY INC., a Delaware corporation (the “Borrower”), the Guarantors party hereto, JPMORGAN CHASE BANK, N.A., as Administrative Agent (the “Administrative Agent”), and the Lenders party hereto.
RECITALS
WHEREAS, the Borrower, the Administrative Agent and the Lenders are parties to that certain Credit Agreement dated as of September 18, 2020 (as amended, supplemented or otherwise modified prior to the date hereof, the “Credit Agreement”; unless otherwise defined herein, all terms used herein with their initial letter capitalized shall have the meaning given such terms in the Credit Agreement, including, to the extent applicable, after giving effect to the amendments set forth in Section 1 of this First Amendment);
WHEREAS, pursuant to the Credit Agreement, the Lenders have extended credit in the form of Loans to the Borrower and provided certain other credit accommodations to the Borrower;
WHEREAS, the Borrower has requested that Lenders amend certain provisions contained in the Credit Agreement as more specifically provided for herein; and
WHEREAS, subject to and upon the terms and conditions set forth herein, the Lenders have agreed to enter into this First Amendment to, among other things, (i) evidence the reaffirmation of the Borrowing Base of $575,000,000 as set forth in Section 2 hereof and (ii) amend certain provisions of the Credit Agreement as more specifically provided for herein, in each case, effective as of the First Amendment Effective Date.
NOW THEREFORE, for and in consideration of the mutual covenants and agreements herein contained and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged and confessed, the Borrower, the Administrative Agent and the Lenders party hereto hereby agree as follows:
Section 1.Amendments to Credit Agreement. In reliance on the representations, warranties, covenants and agreements contained in this First Amendment, and subject to the satisfaction or waiver of the condition precedent set forth in Section 3 hereof, the Credit Agreement shall be amended effective as of the First Amendment Effective Date in the manner provided in this Section 1.
1.1Additional Definitions. Section 1.1 of the Credit Agreement shall be amended to add thereto in alphabetical order the following definitions, which shall read in full as follows:
“CCUS Acquisitions” shall mean acquisitions and expenditures made in the ordinary course of, and of a nature that is or shall have become customary in, the business of capturing, transporting, using, treating, and storing carbon dioxide from either natural or anthropogenic carbon dioxide sources (or both), within the
geographic boundaries of the United States of America (or the Outer Continental Shelf adjacent to the United States of America), as a means of actively engaging therein through agreements, transactions, interests or arrangements that permit a Person to own assets, to comply with regulatory requirements regarding local ownership or to satisfy other objectives customarily achieved through the conduct of such business, including: (a) direct or indirect ownership or leasehold interests in carbon capture projects, transportation systems, injection wells, storage sites and related infrastructure; gathering, transportation, processing, and related systems, or other material properties, (b) direct or indirect ownership, participation or other interests in projects, facilities and related infrastructure, systems and material properties associated with industries generating or using anthropogenic carbon dioxide, and (c) acquisitions and expenditures in the form of or pursuant to capture agreements, transportation agreements, offtake agreements, injection agreements, storage agreements, disposal agreements, operating agreements, processing agreements, pipeline construction agreements, development agreements, area of mutual interest agreements, unitization agreements, pooling arrangements, joint bidding agreements, service contracts, and other similar agreements; provided, however, that in no event will “CCUS Acquisitions” include (i) Joint Venture Investments or (ii) Investments of the type described in clauses (a) through (c) of the definition thereof.
“First Amendment” shall mean that certain First Amendment to Credit Agreement dated as of November 3, 2021, among the Borrower, the Guarantors, the Administrative Agent and the Lenders party thereto.
1.2Restatement of Definitions. The following definitions contained in Section 1.1 of the Credit Agreement are hereby amended and restated in their respective entireties to read in full as follows:
“Credit Documents” shall mean this Agreement, the First Amendment, the Guarantee, the Security Documents and any promissory notes issued by the Borrower under this Agreement and any other agreements executed by Credit Parties in connection with this Agreement and expressly identified as “Credit Documents” therein.
“Excluded Subsidiary” shall mean (a) each Immaterial Subsidiary, (b) any Unrestricted Subsidiary, (c) any direct or indirect Subsidiary that owns no material assets other than the Stock or Indebtedness of one or more direct or indirect Foreign Subsidiaries to the extent such Foreign Subsidiaries are permitted to exist under this Agreement (such entity described in this clause (c), a “FSHCO”), (d) each Domestic Subsidiary of a Foreign Subsidiary to the extent such Foreign Subsidiary is permitted to exist under this Agreement (other than such Domestic Subsidiary with respect to which each direct and indirect foreign parent entity is a Disregarded Entity), (e) each Subsidiary that is prohibited by any applicable Contractual Requirement from guaranteeing or granting Liens to secure the Obligations at the time such Subsidiary becomes a Restricted Subsidiary (and for so long as such restriction or any replacement or renewal thereof is in effect) or that would require
consent, approval, license or authorization of a Governmental Authority to guarantee or grant Liens to secure the Obligations at the time such Subsidiary becomes a Restricted Subsidiary (unless such consent, approval, license or authorization has been received), (f) any other Subsidiary with respect to which, (i) in the reasonable judgment of the Administrative Agent, the cost or other consequences of providing a Guarantee of the Obligations shall be excessive in view of the benefits to be obtained by the Lenders therefrom or (ii) providing such a Guarantee would result in material adverse tax consequences as reasonably determined by the Borrower, (g) any Foreign Subsidiary to the extent permitted to exist under this Agreement and (h) any Subsidiary that is a non-wholly owned Subsidiary. Notwithstanding anything to the contrary in the foregoing, any Subsidiary that owns Borrowing Base Properties shall not constitute as an “Excluded Subsidiary”. As of the Closing Date, the only Excluded Subsidiaries are those set forth on Schedule 1.1(b).
“Free Cash Flow Utilizations” means, for any period, the aggregate amount of each of the following transactions during such period: (a) Restricted Payments made pursuant to Section 10.6(g) and (b) exchanges, prepayments, repurchases or redemptions of Permitted Additional Debt (and any Permitted Refinancing Indebtedness thereof) made pursuant to Section 10.7(a).
“Industry Acquisitions” shall mean acquisitions and expenditures made in the ordinary course of, and of a nature that is or shall have become customary in, the oil and gas business located within the geographic boundaries of the United States of America (or the Outer Continental Shelf adjacent to the United States of America) as a means of actively engaging therein through agreements, transactions, interests or arrangements that permit a Person to own assets, to comply with regulatory requirements regarding local ownership or to satisfy other objectives customarily achieved through the conduct of oil and gas business, including: (a) direct or indirect ownership interests in Oil and Gas Properties, Carbon Dioxide Interests, enhanced oil recovery business arrangements (including natural and anthropogenic carbon dioxide sources), gathering, transportation, processing, related systems, or other material properties and (b) acquisitions and expenditures in the form of or pursuant to operating agreements, processing agreements, farm-in agreements, farm-out agreements, development agreements, area of mutual interest agreements, unitization agreements, pooling arrangements, joint bidding agreements, service contracts, and other similar agreements; provided, however, that in no event will “Industry Acquisitions” include (i) Joint Venture Investments or (ii) Investments of the type described in clauses (a) through (c) of the definition thereof.
“Industry Competitor” shall mean any Person (other than the Borrower or any of its Affiliates or Subsidiaries) that, directly or indirectly, is actively engaged as one of its principal businesses in lease acquisitions, exploration and production operations or development of oil and gas properties (including the drilling and completion of producing wells) or carbon capture, transportation, gathering, processing, storage, disposal or related infrastructure projects and have production,
capture, transportation, storage or disposal operations within the same geographical basins as the Borrower or its Restricted Subsidiaries.
“Joint Venture Investments” shall mean Investments in general or limited partnerships or other types of entities, entered into by the Borrower or a Restricted Subsidiary with one or more Persons that are not Restricted Subsidiaries.
“Permitted Acquisition” shall mean the acquisition, by merger or otherwise, by the Borrower or any of the Restricted Subsidiaries of assets (including any assets constituting a business unit, line of business or division) or Stock or Stock Equivalents, so long as (a) such acquisition and all transactions related thereto shall be consummated in all material respects in accordance with Requirements of Law; (b) if such acquisition involves the acquisition of Stock or Stock Equivalents of a Person, such acquisition shall result in the issuer of such Stock becoming a wholly owned Restricted Subsidiary and, to the extent required by Section 9.10(a), a Guarantor (subject to the time periods set forth therein); (c) such acquisition shall result in the Administrative Agent, for the benefit of the Secured Parties, being granted a security interest in any Stock or any assets so acquired to the extent required by Section 9.10(a) and (b) (subject to the time periods set forth therein); (d) after giving effect to such acquisition, no Event of Default shall have occurred and be continuing; (e) after giving effect to such acquisition, the Borrower and its Restricted Subsidiaries shall be in compliance with Section 10.13; and (f) the Borrower shall be in compliance, on a pro forma basis after giving effect to such acquisition, with the Financial Performance Covenants, as such covenants are recomputed as at the last day of the most recently ended Test Period for which Section 9.1 Financials have been delivered as if such acquisition had occurred on the first day of such Test Period.
1.3Amendment to Definition. The definition of “Free Cash Flow” contained in Section 1.1 of the Credit Agreement is hereby amended by deleting the reference to “(other than those made in reliance on Section 10.5(g))” contained in clause (g)(i) therein.
1.4Amendments to Section 10.5 of the Credit Agreement. Section 10.5 of the Credit Agreement is hereby amended by:
(a)amending and restating clause (g) therein in its entirety to read in full as follows:
(g) Investments so long as, immediately after giving pro forma effect to the making of any such Investment (and any Borrowings incurred in connection therewith), (i) the aggregate amount of Investments made pursuant to this Section 10.5(g) shall not exceed $200,000,000, (ii) no Event of Default has occurred and is continuing, (iii) the Available Commitment is not less than 20% of the then effective Loan Limit and (iv) the Consolidated Total Leverage Ratio is less than or equal to 2.00 to 1.00;
(b)amending clause (h) therein by replacing the reference to “$10,000,000” therein with “$25,000,000”;
(c)amending and restating clause (q) therein in its entirety to read in full as follows:
(q) Joint Venture Investments; provided that (i) any such Person in which a Joint Venture Investment is made is engaged exclusively in oil and gas exploration, development, production, processing, transportation or related activities or any other business or activity permitted under Section 10.13 and (ii) the aggregate amount of Joint Venture Investments at any time outstanding shall not exceed $25,000,000;
(d)amending and restating clause (v) therein in its entirety to read in full as follows:
(v) subject to Section 10.13, Industry Acquisitions and CCUS Acquisitions.
1.5Amendment to Section 10.8 of the Credit Agreement. Section 10.8 of the Credit Agreement is hereby amended by inserting a reference to “, “CCUS Acquisitions”” immediately after the reference to “Industry Acquisitions” appearing in clause (v) therein.
1.6Amendment to Section 10.9(i) of the Credit Agreement. Clause (ii) of Section 10.9(i) of the Credit Agreement is hereby amended and restated in its entirety to read in full as follows:
(ii) other customary encumbrances or restrictions pursuant to any agreement of the type described in the definition of “Industry Acquisitions”, “CCUS Acquisitions” and “Joint Venture Investments” relating solely to such “Industry Acquisitions”, “CCUS Acquisitions” and “Joint Venture Investments” or the property relating thereto, and in the case of clause (ii) above, entered into in the ordinary course of business;
1.7Amendment to Section 10.13 of the Credit Agreement. Section 10.13 of the Credit Agreement is hereby amended and restated in its entirety to read in full as follows:
10.13 Change in Business. The Borrower and its Restricted Subsidiaries, taken as a whole, will not fundamentally and substantively alter the character of their business, taken as a whole, from the business of (a) oil and gas exploration, development, production, processing, transportation and related activities, including the making of any Industry Acquisition and any other permitted Investments related thereto and (b) capturing, transporting, using, treating and storing carbon dioxide, including the making of any CCUS Acquisitions and any other permitted Investments related thereto, in each case, by the Borrower and its Restricted Subsidiaries and other business activities incidental or reasonably related to any of the foregoing.
Section 2.Borrowing Base Redetermination. In reliance on the representations, warranties, covenants and agreements contained in this First Amendment, and subject to the satisfaction or waiver of the conditions precedent set forth in Section 3 hereof, the Administrative Agent and the Lenders party hereto hereby agree that the Borrowing Base of $575,000,000 is hereby reaffirmed, and the Borrowing Base shall remain at $575,000,000 until the next Scheduled Redetermination, Interim Redetermination or other adjustment to the Borrowing Base thereafter, whichever occurs first pursuant to the Credit Agreement. The redetermination of the Borrowing Base provided for in this Section 2 shall be deemed to be the Scheduled Redetermination scheduled for on or about November 1, 2021 for purposes of Section 2.14 of the Credit Agreement. This First Amendment constitutes a New Borrowing Base Notice delivered pursuant to Section 2.14(d) of the Credit Agreement with respect to the Borrowing Base redetermination provided for in this Section 2.
Section 3.Condition Precedent to First Amendment. The amendments to the Credit Agreement contained in Section 1 hereof and the reaffirmation of the Borrowing Base set forth in Section 2 shall each be effective on the First Amendment Effective Date, subject to the satisfaction (or waiver) of the Administrative Agent having received (a) counterparts hereof duly executed by an Authorized Officer of the Borrower and the Guarantors and (b) executed counterparts of the Administrative Agent and the Lenders constituting the Required Lenders.
Each Lender, by delivering its signature page to this First Amendment, shall be deemed to have acknowledged receipt of, and consented to and approved, this First Amendment and each other document, agreement and/or instrument or other matter required to be approved by Lenders on the First Amendment Effective Date. The Administrative Agent is hereby authorized and directed to declare the amendments in Section 1 hereof to be effective on the date it confirms to the Borrower in writing that the foregoing conditions have been met to the reasonable satisfaction of the Administrative Agent (or the waiver of such conditions as permitted hereby). Such declaration shall be final, conclusive and binding upon the Lenders and all other parties to the Credit Agreement for all purposes.
Section 4.Representations and Warranties. To induce the Lenders and the Administrative Agent to enter into this First Amendment, each Credit Party hereby represents and warrants to the Lenders and the Administrative Agent as follows as of the First Amendment Effective Date:
4.1Reaffirm Existing Representations and Warranties. Each representation and warranty of such Credit Party contained in the Credit Agreement and the other Credit Documents to which it is a party is true and correct in all material respects (unless such representations and warranties are already qualified by materiality, Material Adverse Effect or a similar qualification in which case such representations and warranties shall be true and correct in all respects) with the same effect as though each such representation and warranty had been made on and as of the First Amendment Effective Date (except where any such representation and warranty expressly relates to an earlier date, in which case each such representation and warranty shall have been true and correct in all material respects as of such earlier date).
4.2Due Authorization. The execution, delivery and performance by such Credit Party of this First Amendment are within such Credit Party’s corporate, limited liability, limited partnership or other organizational powers, have been duly authorized by all necessary action, and require no action by or in respect of, or filing with, any governmental body, agency or official.
4.3Validity and Enforceability. This First Amendment constitutes the valid and binding obligation of such Credit Party enforceable in accordance with its terms, except as (a) the enforceability thereof may be limited by bankruptcy, insolvency or similar laws affecting creditor’s rights generally, and (b) the availability of equitable remedies may be limited by equitable principles of general application.
4.4No Defense. (a) The Borrower acknowledges that the Borrower has no defense to Borrower’s obligation to pay the Obligations when due, and (b) each Credit Party acknowledges that such Credit Party has no defense to the validity, enforceability or binding effect against such Credit Party of any of the Credit Documents to which it is a party or any Liens intended to be created thereby.
Section 5.Miscellaneous.
5.1No Waivers. No failure or delay on the part of the Administrative Agent or the Lenders to exercise any right or remedy under the Credit Agreement, any other Credit Documents or applicable law shall operate as a waiver thereof, nor shall any single or partial exercise of any right or remedy preclude any other or further exercise of any right or remedy, all of which are cumulative and may be exercised without notice except to the extent notice is expressly required (and has not been waived) under the Credit Agreement, the other Credit Documents and applicable law.
5.2Reaffirmation of Credit Documents. Any and all of the terms and provisions of the Credit Agreement and the other Credit Documents shall remain in full force and effect as amended and modified hereby. The amendments contemplated hereby shall not limit or impair any Liens securing the Obligations nor limit or impair any guarantees of any Guarantor under the Credit Documents, each of which are hereby ratified, affirmed and extended to secure the Obligations.
5.3Legal Expenses. The Borrower hereby agrees to pay on demand all reasonable fees and expenses of counsel to the Administrative Agent incurred by the Administrative Agent in connection with the preparation, negotiation and execution of this First Amendment and all related documents.
5.4Parties in Interest. All of the terms and provisions of this First Amendment shall bind and inure to the benefit of the parties to the Credit Agreement and the other Credit Documents and their respective successors and assigns.
5.5Counterparts. This First Amendment may be executed in counterparts (including, without limitation, by electronic signature), and all parties need not execute the same counterpart; however, no party shall be bound by this First Amendment until the Borrower, the Guarantors, the Administrative Agent and the Lenders constituting the Required Lenders have executed a counterpart. Facsimiles and counterparts executed by electronic signature (e.g., .pdf) shall be effective as originals.
5.6Complete Agreement. THIS FIRST AMENDMENT, THE CREDIT AGREEMENT AND THE OTHER CREDIT DOCUMENTS REPRESENT THE FINAL AGREEMENT BETWEEN THE PARTIES AND MAY NOT BE CONTRADICTED BY
EVIDENCE OF PRIOR, CONTEMPORANEOUS OR ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN OR AMONG THE PARTIES.
5.7Headings. The headings, captions and arrangements used in this First Amendment are, unless specified otherwise, for convenience only and shall not be deemed to limit, amplify or modify the terms of this First Amendment, nor affect the meaning thereof.
5.8Governing Law. THIS FIRST AMENDMENT SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK.
5.9Severability. Any provision of this First Amendment which is prohibited or unenforceable in any jurisdiction shall, as to such jurisdiction, be ineffective to the extent of such prohibition or unenforceability without invalidating the remaining provisions hereof, and any such prohibition or unenforceability in any jurisdiction shall not invalidate or render unenforceable such provision in any other jurisdiction.
[Signature pages follow.]
IN WITNESS WHEREOF, the parties hereto have caused this First Amendment to be duly executed by their respective authorized officers effective as of the First Amendment Effective Date.
| | | | | | | | |
| BORROWER: |
| | |
| DENBURY INC., |
| a Delaware corporation |
| | |
| By: | /s/ James Matthews |
| Name: | James Matthews |
| Title: | Executive Vice President, Chief Administrative Officer, General Counsel and Secretary |
[SIGNATURE PAGE TO FIRST AMENDMENT TO CREDIT AGREEMENT – DENBURY INC.]
Each of the undersigned Guarantors (a) consent and agree to this First Amendment, and (b) agree that the Credit Documents to which it is a party shall remain in full force and effect and shall continue to be the legal, valid and binding obligation of such Person, enforceable against it in accordance with its terms.
| | | | | | | | |
| GUARANTORS: |
| | |
| DENBURY HOLDINGS, INC. |
| DENBURY OPERATING COMPANY |
| DENBURY ONSHORE, LLC |
| DENBURY PIPELINE HOLDINGS, LLC |
| DENBURY GREEN PIPELINE-TEXAS, LLC |
| DENBURY GULF COAST PIPELINES, LLC |
| GREENCORE PIPELINE COMPANY LLC |
| DENBURY GREEN PIPELINE-MONTANA, LLC |
| DENBURY GREEN PIPELINE-RILEY RIDGE, LLC |
| DENBURY THOMPSON PIPELINE, LLC |
| DENBURY BROOKHAVEN PIPELINE, LLC |
| DENBURY GREEN PIPELINE-NORTH DAKOTA, LLC |
| DENBURY CARBON SOLUTIONS, LLC |
| | |
| By: | /s/ James Matthews |
| Name: | James Matthews |
| Title: | Executive Vice President, Chief Administrative Officer, General Counsel and Secretary |
| | |
| DENBURY BROOKHAVEN PIPELINE PARTNERSHIP, LP |
| | |
| By: | Denbury Brookhaven Pipeline, LLC, its general partner |
| | |
| By: | /s/ James Matthews |
| Name: | James Matthews |
| Title: | Executive Vice President, Chief Administrative Officer, General Counsel and Secretary |
[SIGNATURE PAGE TO FIRST AMENDMENT TO CREDIT AGREEMENT – DENBURY INC.]
| | | | | | | | |
| ADMINISTRATIVE AGENT/LENDER: |
| |
| JPMORGAN CHASE BANK, N.A., |
| as the Administrative Agent and a Lender |
| | |
| By: | /s/ Anca Loghin |
| Name: | Anca Loghin |
| Title: | Authorized Officer |
[SIGNATURE PAGE TO FIRST AMENDMENT TO CREDIT AGREEMENT – DENBURY INC.]
| | | | | | | | |
| LENDERS: |
| |
| BANK OF AMERICA, N.A., |
| as a Lender |
| | |
| By: | /s/ Ronald E. McKaig |
| Name: | Ronald E. McKaig |
| Title: | Managing Director |
[SIGNATURE PAGE TO FIRST AMENDMENT TO CREDIT AGREEMENT – DENBURY INC.]
| | | | | | | | |
| |
| |
| WELLS FARGO BANK, NATIONAL ASSOCIATION, |
| as a Lender |
| | |
| By: | /s/ Michael Real |
| Name: | Michael Real |
| Title: | Managing Director |
[SIGNATURE PAGE TO FIRST AMENDMENT TO CREDIT AGREEMENT – DENBURY INC.]
| | | | | | | | |
| |
| |
| CAPITAL ONE, NATIONAL ASSOCIATION, |
| as a Lender |
| | |
| By: | /s/ Christopher Kuna |
| Name: | Christopher Kuna |
| Title: | Senior Director |
[SIGNATURE PAGE TO FIRST AMENDMENT TO CREDIT AGREEMENT – DENBURY INC.]
| | | | | | | | |
| |
| |
| CREDIT SUISSE AG, CAYMAN ISLANDS BRANCH, |
| as a Lender |
| | |
| By: | /s/ Nupur Kumar |
| Name: | Nupur Kumar |
| Title: | Authorized Signatory |
| | |
| By: | /s/ Daniel Kogan |
| Name: | Daniel Kogan |
| Title: | Authorized Signatory |
[SIGNATURE PAGE TO FIRST AMENDMENT TO CREDIT AGREEMENT – DENBURY INC.]
| | | | | | | | |
| |
| |
| ROYAL BANK OF CANADA, |
| as a Lender |
| | |
| By: | /s/ Jay T. Sartain |
| Name: | Jay T. Sartain |
| Title: | Authorized Signatory |
[SIGNATURE PAGE TO FIRST AMENDMENT TO CREDIT AGREEMENT – DENBURY INC.]
| | | | | | | | |
| |
| |
| COMERICA BANK, |
| as a Lender |
| | |
| By: | /s/ Garrett R. Merrell |
| Name: | Garrett R. Merrell |
| Title: | Senior Vice President |
[SIGNATURE PAGE TO FIRST AMENDMENT TO CREDIT AGREEMENT – DENBURY INC.]
| | | | | | | | |
| |
| |
| CANADIAN IMPERIAL BANK OF COMMERCE, NEW YORK BRANCH, |
| as a Lender |
| | |
| By: | /s/ Jacob W. Lewis |
| Name: | Jacob W. Lewis |
| Title: | Authorized Signatory |
| | |
| By: | /s/ Donovan C. Broussard |
| Name: | Donovan C. Broussard |
| Title: | Authorized Signatory |
[SIGNATURE PAGE TO FIRST AMENDMENT TO CREDIT AGREEMENT – DENBURY INC.]
| | | | | | | | |
| |
| |
| TRUIST BANK, |
| as a Lender |
| | |
| By: | /s/ Greg Krablin |
| Name: | Greg Krablin |
| Title: | Director |
[SIGNATURE PAGE TO FIRST AMENDMENT TO CREDIT AGREEMENT – DENBURY INC.]
| | | | | | | | |
| |
| |
| KEYBANK NATIONAL ASSOCIATION, |
| as a Lender |
| | |
| By: | /s/ George McKean |
| Name: | George McKean |
| Title: | SVP |
[SIGNATURE PAGE TO FIRST AMENDMENT TO CREDIT AGREEMENT – DENBURY INC.]
| | | | | | | | |
| |
| |
| GOLDMAN SACHS BANK USA, |
| as a Lender |
| | |
| By: | /s/ Mahesh Mohan |
| Name: | Mahesh Mohan |
| Title: | Authorized Signatory |
[SIGNATURE PAGE TO FIRST AMENDMENT TO CREDIT AGREEMENT – DENBURY INC.]
Exhibit 31(a)
CERTIFICATION UNDER SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, Chris Kendall, certify that:
1.I have reviewed this report on Form 10-Q of Denbury Inc. (the registrant);
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
(c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
| | | | | | | | |
November 4, 2021 | | /s/ Chris Kendall |
| | Chris Kendall |
| | President and Chief Executive Officer |
Exhibit 31(b)
CERTIFICATION UNDER SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, Mark C. Allen, certify that:
1.I have reviewed this report on Form 10-Q of Denbury Inc. (the registrant);
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
(c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
| | | | | | | | |
November 4, 2021 | | /s/ Mark Allen |
| | Mark C. Allen |
| | Executive Vice President, Chief Financial Officer, Treasurer, and Assistant Secretary |
Exhibit 32
Certification of Chief Executive Officer and Chief Financial Officer
Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
In connection with the accompanying Quarterly Report on Form 10-Q for the quarter ended September 30, 2021 (the Report) of Denbury Inc. (Denbury) as filed with the Securities and Exchange Commission, each of the undersigned, in his capacity as an officer of Denbury, hereby certifies pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to his knowledge:
1.The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and
2.The Information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of Denbury.
| | | | | | | | | | | |
Dated: | November 4, 2021 | | /s/ Chris Kendall |
| | | Chris Kendall |
| | | President and Chief Executive Officer |
| | | |
| | | |
Dated: | November 4, 2021 | | /s/ Mark C. Allen |
| | | Mark C. Allen |
| | | Executive Vice President, Chief Financial Officer, Treasurer, and Assistant Secretary |
v3.21.2
Document and Entity Information - shares
|
9 Months Ended |
|
Sep. 30, 2021 |
Oct. 31, 2021 |
Cover [Abstract] |
|
|
Document Type |
10-Q
|
|
Document Quarterly Report |
true
|
|
Document Period End Date |
Sep. 30, 2021
|
|
Document Transition Report |
false
|
|
Entity File Number |
001-12935
|
|
Entity Registrant Name |
DENBURY INC.
|
|
Entity Incorporation, State or Country Code |
DE
|
|
Entity Tax Identification Number |
20-0467835
|
|
Entity Address, Address Line One |
5851 Legacy Circle,
|
|
Entity Address, City or Town |
Plano,
|
|
Entity Address, State or Province |
TX
|
|
Entity Address, Postal Zip Code |
75024
|
|
City Area Code |
(972)
|
|
Local Phone Number |
673-2000
|
|
Title of 12(b) Security |
Common Stock $.001 Par Value
|
|
Trading Symbol |
DEN
|
|
Security Exchange Name |
NYSE
|
|
Entity Current Reporting Status |
Yes
|
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Entity Interactive Data Current |
Yes
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Entity Filer Category |
Accelerated Filer
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Entity Small Business |
true
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Entity Emerging Growth Company |
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Entity Shell Company |
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Entity Bankruptcy Proceedings, Reporting Current |
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Entity Common Stock, Shares Outstanding |
|
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Entity Central Index Key |
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v3.21.2
Condensed Consolidated Balance Sheets (Unaudited) - USD ($) $ in Thousands |
Sep. 30, 2021 |
Dec. 31, 2020 |
Current assets |
|
|
Cash and cash equivalents |
$ 1,783
|
$ 518
|
Restricted cash |
0
|
1,000
|
Accrued production receivable |
144,370
|
91,421
|
Trade and other receivables, net |
20,867
|
19,682
|
Derivative assets |
0
|
187
|
Prepaids |
10,872
|
14,038
|
Total current assets |
177,892
|
126,846
|
Oil and natural gas properties (using full cost accounting) |
|
|
Proved properties |
1,011,545
|
851,208
|
Unevaluated properties |
108,258
|
85,304
|
CO2 properties |
188,752
|
188,288
|
Pipelines |
193,669
|
133,485
|
Other property and equipment |
94,763
|
86,610
|
Less accumulated depletion, depreciation, amortization and impairment |
(151,844)
|
(41,095)
|
Net property and equipment |
1,445,143
|
1,303,800
|
Operating lease right-of-use assets |
18,253
|
20,342
|
Intangible assets, net |
90,533
|
97,362
|
Other assets |
80,444
|
86,408
|
Total assets |
1,812,265
|
1,634,758
|
Current liabilities |
|
|
Accounts payable and accrued liabilities |
211,894
|
112,671
|
Oil and gas production payable |
69,717
|
49,165
|
Derivative liabilities |
193,015
|
53,865
|
Current maturities of long-term debt |
17,332
|
68,008
|
Operating lease liabilities |
3,338
|
1,350
|
Total current liabilities |
495,296
|
285,059
|
Long-term liabilities |
|
|
Long-term debt, net of current portion |
0
|
70,000
|
Asset retirement obligations |
243,184
|
179,338
|
Derivative liabilities |
16,435
|
5,087
|
Deferred tax liabilities, net |
1,241
|
1,274
|
Operating lease liabilities |
17,362
|
19,460
|
Other liabilities |
25,954
|
20,872
|
Total long-term liabilities |
304,176
|
296,031
|
Commitments and contingencies (Note 8) |
|
|
Stockholders' equity |
|
|
Preferred stock, $.001 par value, 50,000,000 shares authorized, none issued and outstanding |
0
|
0
|
Common stock, $.001 par value, 250,000,000 shares authorized; 50,120,895 and 49,999,999 shares issued, respectively |
50
|
50
|
Paid-in capital in excess of par |
1,128,030
|
1,104,276
|
Accumulated deficit |
(115,287)
|
(50,658)
|
Total stockholders' equity |
1,012,793
|
1,053,668
|
Total liabilities and stockholders' equity |
$ 1,812,265
|
$ 1,634,758
|
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v3.21.2
Condensed Consolidated Balance Sheets (Unaudited) (Parenthetical) - $ / shares
|
Sep. 30, 2021 |
Dec. 31, 2020 |
Stockholders' equity |
|
|
Preferred stock, par value |
$ 0.001
|
$ 0.001
|
Preferred stock, shares authorized |
50,000,000
|
50,000,000
|
Preferred stock, shares issued |
0
|
0
|
Preferred stock, shares outstanding |
0
|
0
|
Common stock, par value |
$ 0.001
|
$ 0.001
|
Common stock, shares authorized |
250,000,000
|
250,000,000
|
Common stock, shares issued |
50,120,895
|
49,999,999
|
X |
- DefinitionFace amount or stated value per share of common stock.
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v3.21.2
Condensed Consolidated Statements of Operations (Unaudited) - USD ($) shares in Thousands |
|
3 Months Ended |
9 Months Ended |
Sep. 30, 2020 |
Sep. 30, 2021 |
Sep. 18, 2020 |
Sep. 30, 2021 |
Sep. 18, 2020 |
Revenues and other income |
$ 23,533,000
|
$ 343,735,000
|
$ 170,036,000
|
$ 896,262,000
|
$ 530,112,000
|
Expenses |
|
|
|
|
|
Taxes other than income |
2,073,000
|
24,154,000
|
13,473,000
|
65,499,000
|
43,531,000
|
General and administrative expenses |
1,735,000
|
15,388,000
|
15,013,000
|
62,821,000
|
48,522,000
|
Interest, net of amounts capitalized |
334,000
|
669,000
|
7,704,000
|
3,457,000
|
48,267,000
|
Depletion, depreciation, and amortization |
5,283,000
|
37,691,000
|
36,317,000
|
113,522,000
|
188,593,000
|
Commodity derivatives expense (income) |
(4,035,000)
|
41,745,000
|
4,609,000
|
330,152,000
|
(102,032,000)
|
Gain on debt extinguishment |
0
|
|
|
0
|
(18,994,000)
|
Write-down of oil and natural gas properties |
0
|
0
|
261,677,000
|
14,377,000
|
996,658,000
|
Reorganization items, net |
0
|
0
|
849,980,000
|
0
|
849,980,000
|
Other expenses |
2,164,000
|
4,553,000
|
22,084,000
|
9,913,000
|
35,868,000
|
Total expenses |
20,763,000
|
260,624,000
|
1,282,963,000
|
961,026,000
|
2,378,819,000
|
Income (loss) before income taxes |
2,770,000
|
83,111,000
|
(1,112,927,000)
|
(64,764,000)
|
(1,848,707,000)
|
Income tax provision (benefit) |
12,000
|
403,000
|
(303,807,000)
|
(135,000)
|
(416,129,000)
|
Net income (loss) |
$ 2,758,000
|
$ 82,708,000
|
$ (809,120,000)
|
$ (64,629,000)
|
$ (1,432,578,000)
|
Net income (loss) per common share |
|
|
|
|
|
Basic |
$ 0.06
|
$ 1.62
|
$ (1.63)
|
$ (1.27)
|
$ (2.89)
|
Diluted |
$ 0.06
|
$ 1.51
|
$ (1.63)
|
$ (1.27)
|
$ (2.89)
|
Weighted average common shares outstanding |
|
|
|
|
|
Basic |
50,000
|
51,094
|
497,398
|
50,807
|
495,560
|
Diluted |
50,000
|
54,714
|
497,398
|
50,807
|
495,560
|
Other income |
|
|
|
|
|
Revenues and other income |
$ 94,000
|
$ 10,451,000
|
$ 7,097,000
|
$ 11,518,000
|
$ 8,419,000
|
Transportation and marketing |
|
|
|
|
|
Operating expenses |
1,344,000
|
5,985,000
|
8,155,000
|
22,304,000
|
27,164,000
|
Oil, natural gas, and related product sales |
|
|
|
|
|
Revenues and other income |
22,321,000
|
308,454,000
|
153,090,000
|
826,607,000
|
492,101,000
|
Operating expenses |
11,484,000
|
116,536,000
|
59,708,000
|
308,731,000
|
250,271,000
|
CO2 |
|
|
|
|
|
Revenues and other income |
967,000
|
12,237,000
|
6,517,000
|
31,599,000
|
21,049,000
|
Operating expenses |
242,000
|
1,963,000
|
955,000
|
4,487,000
|
2,592,000
|
Oil marketing |
|
|
|
|
|
Revenues and other income |
151,000
|
12,593,000
|
3,332,000
|
26,538,000
|
8,543,000
|
Operating expenses |
$ 139,000
|
$ 11,940,000
|
$ 3,288,000
|
$ 25,763,000
|
$ 8,399,000
|
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- DefinitionTotal costs of sales and operating expenses for the period.
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|
3 Months Ended |
9 Months Ended |
Sep. 30, 2020 |
Sep. 30, 2021 |
Sep. 18, 2020 |
Sep. 30, 2021 |
Sep. 18, 2020 |
Expenses |
|
|
|
|
|
Capitalized interest |
$ 183
|
$ 1,249
|
$ 4,704
|
$ 3,500
|
$ 22,885
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|
|
9 Months Ended |
Sep. 30, 2020 |
Sep. 30, 2021 |
Sep. 18, 2020 |
Cash flows from operating activities |
|
|
|
Net income (loss) |
$ 2,758,000
|
$ (64,629,000)
|
$ (1,432,578,000)
|
Adjustments to reconcile net income (loss) to cash flows from operating activities |
|
|
|
Noncash reorganization items, net |
0
|
0
|
810,909,000
|
Depletion, depreciation, and amortization |
5,283,000
|
113,522,000
|
188,593,000
|
Write-down of oil and natural gas properties |
0
|
14,377,000
|
996,658,000
|
Deferred income taxes |
6,000
|
(34,000)
|
(408,869,000)
|
Stock-based compensation |
0
|
22,788,000
|
4,111,000
|
Commodity derivatives expense (income) |
(4,035,000)
|
330,152,000
|
(102,032,000)
|
Receipt (payment) on settlements of commodity derivatives |
6,660,000
|
(179,466,000)
|
81,396,000
|
Gain on debt extinguishment |
0
|
0
|
(18,994,000)
|
Debt issuance costs and discounts |
114,000
|
2,055,000
|
11,571,000
|
Gain from asset sales and other |
0
|
(7,026,000)
|
(6,723,000)
|
Other, net |
589,000
|
(2,448,000)
|
7,162,000
|
Changes in assets and liabilities, net of effects from acquisitions |
|
|
|
Accrued production receivable |
38,537,000
|
(52,948,000)
|
26,575,000
|
Trade and other receivables |
1,366,000
|
(1,809,000)
|
(22,343,000)
|
Other current and long-term assets |
705,000
|
7,337,000
|
743,000
|
Accounts payable and accrued liabilities |
(7,980,000)
|
47,484,000
|
(16,102,000)
|
Oil and natural gas production payable |
(11,064,000)
|
23,168,000
|
(6,792,000)
|
Other liabilities |
(29,000)
|
(4,966,000)
|
123,000
|
Net cash provided by operating activities |
32,910,000
|
247,557,000
|
113,408,000
|
Cash flows from investing activities |
|
|
|
Oil and natural gas capital expenditures |
(2,125,000)
|
(113,041,000)
|
(99,582,000)
|
Acquisitions of oil and natural gas properties |
(1,000)
|
(10,927,000)
|
0
|
Pipelines and plants capital expenditures |
(6,000)
|
(19,123,000)
|
(11,601,000)
|
Net proceeds from sales of oil and natural gas properties and equipment |
880,000
|
19,053,000
|
41,322,000
|
Other |
(308,000)
|
5,797,000
|
12,747,000
|
Net cash used in investing activities |
(1,560,000)
|
(118,241,000)
|
(57,114,000)
|
Cash flows from financing activities |
|
|
|
Bank repayments |
(55,000,000)
|
(697,000,000)
|
(551,000,000)
|
Bank borrowings |
0
|
627,000,000
|
691,000,000
|
Interest payments treated as a reduction of debt |
0
|
0
|
(46,417,000)
|
Cash paid in conjunction with debt repurchases |
0
|
0
|
(14,171,000)
|
Costs of debt financing |
0
|
0
|
(12,482,000)
|
Pipeline financing repayments |
(54,000)
|
(50,676,000)
|
(51,792,000)
|
Other |
0
|
(2,426,000)
|
(9,363,000)
|
Net cash provided by (used in) financing activities |
(55,054,000)
|
(123,102,000)
|
5,775,000
|
Net increase (decrease) in cash, cash equivalents, and restricted cash |
(23,704,000)
|
6,214,000
|
62,069,000
|
Cash, cash equivalents, and restricted cash at beginning of period |
95,114,000
|
42,248,000
|
33,045,000
|
Cash, cash equivalents, and restricted cash at end of period |
$ 71,410,000
|
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v3.21.2
Condensed Consolidated Statement of Changes in Stockholders' Equity (Unaudited) - USD ($) $ in Thousands |
Total |
Common Stock ($.001 Par Value) |
Paid-In Capital in Excess of Par |
Retained Earnings (Accumulated Deficit) |
Treasury Stock (at cost) |
Beginning balance, shares at Dec. 31, 2019 |
|
508,065,495
|
|
|
1,652,771
|
Beginning balance at Dec. 31, 2019 |
$ 1,412,259
|
$ 508
|
$ 2,739,099
|
$ (1,321,314)
|
$ (6,034)
|
Issued pursuant to stock compensation plans, shares |
|
312,516
|
|
|
|
Issued pursuant to directors' compensation plan, shares |
|
37,367
|
|
|
|
Stock-based compensation, value |
3,204
|
|
3,204
|
|
|
Tax withholding for stock compensation plans, shares |
|
|
|
|
175,673
|
Tax withholding for stock compensation plans, value |
(34)
|
|
|
|
$ (34)
|
Net income (loss) |
74,016
|
|
|
74,016
|
|
Ending balance, shares at Mar. 31, 2020 |
|
508,415,378
|
|
|
1,828,444
|
Ending balance at Mar. 31, 2020 |
1,489,445
|
$ 508
|
2,742,303
|
(1,247,298)
|
$ (6,068)
|
Beginning balance, shares at Dec. 31, 2019 |
|
508,065,495
|
|
|
1,652,771
|
Beginning balance at Dec. 31, 2019 |
1,412,259
|
$ 508
|
2,739,099
|
(1,321,314)
|
$ (6,034)
|
Net income (loss) |
(1,432,578)
|
|
|
|
|
Ending balance, shares at Sep. 18, 2020 |
|
49,999,999
|
|
|
|
Ending balance at Sep. 18, 2020 |
1,095,419
|
$ 50
|
1,095,369
|
|
|
Beginning balance, shares at Mar. 31, 2020 |
|
508,415,378
|
|
|
1,828,444
|
Beginning balance at Mar. 31, 2020 |
1,489,445
|
$ 508
|
2,742,303
|
(1,247,298)
|
$ (6,068)
|
Canceled pursuant to stock compensation plans, shares |
|
(6,218,868)
|
|
|
|
Canceled pursuant to stock compensation plans, value |
|
$ (6)
|
6
|
|
|
Issued pursuant to notes conversion, shares |
|
7,357,450
|
|
|
|
Issued pursuant to notes conversion, value |
11,461
|
$ 8
|
11,453
|
|
|
Stock-based compensation, value |
987
|
|
987
|
|
|
Net income (loss) |
(697,474)
|
|
|
(697,474)
|
|
Ending balance, shares at Jun. 30, 2020 |
|
509,553,960
|
|
|
1,828,444
|
Ending balance at Jun. 30, 2020 |
804,419
|
$ 510
|
2,754,749
|
(1,944,772)
|
$ (6,068)
|
Canceled pursuant to stock compensation plans, shares |
|
(95,016)
|
|
|
|
Issued pursuant to notes conversion, shares |
|
14,800
|
|
|
|
Issued pursuant to notes conversion, value |
40
|
|
40
|
|
|
Stock-based compensation, value |
10,126
|
|
10,126
|
|
|
Tax withholding for stock compensation plans, shares |
|
|
|
|
567,189
|
Tax withholding for stock compensation plans, value |
(134)
|
|
|
|
$ (134)
|
Cancellation of Predecessor equity, shares |
|
(509,473,744)
|
|
|
(2,395,633)
|
Cancellation of Predecessor equity, value |
(5,331)
|
$ (510)
|
(2,764,915)
|
2,753,892
|
$ 6,202
|
Issuance of Successor equity, shares |
|
49,999,999
|
|
|
|
Issuance of Successor equity, value |
1,095,419
|
$ 50
|
1,095,369
|
|
|
Net income (loss) |
(809,120)
|
|
|
(809,120)
|
|
Ending balance, shares at Sep. 18, 2020 |
|
49,999,999
|
|
|
|
Ending balance at Sep. 18, 2020 |
1,095,419
|
$ 50
|
1,095,369
|
|
|
Net income (loss) |
2,758
|
|
|
2,758
|
|
Ending balance, shares at Sep. 30, 2020 |
|
49,999,999
|
|
|
|
Ending balance at Sep. 30, 2020 |
1,098,177
|
$ 50
|
1,095,369
|
2,758
|
|
Stock-based compensation, value |
8,907
|
|
8,907
|
|
|
Net income (loss) |
$ (53,416)
|
|
|
(53,416)
|
|
Ending balance, shares at Dec. 31, 2020 |
49,999,999
|
49,999,999
|
|
|
|
Ending balance at Dec. 31, 2020 |
$ 1,053,668
|
$ 50
|
1,104,276
|
(50,658)
|
|
Stock-based compensation, value |
19,172
|
|
19,172
|
|
|
Tax withholding for stock compensation plans, value |
(1,467)
|
|
(1,467)
|
|
|
Issued pursuant to exercise of warrants, shares |
|
5,620
|
|
|
|
Issued pursuant to exercise of warrants, value |
195
|
$ 0
|
195
|
|
|
Net income (loss) |
(69,642)
|
|
|
(69,642)
|
|
Ending balance, shares at Mar. 31, 2021 |
|
50,005,619
|
|
|
|
Ending balance at Mar. 31, 2021 |
$ 1,001,926
|
$ 50
|
1,122,176
|
(120,300)
|
|
Beginning balance, shares at Dec. 31, 2020 |
49,999,999
|
49,999,999
|
|
|
|
Beginning balance at Dec. 31, 2020 |
$ 1,053,668
|
$ 50
|
1,104,276
|
(50,658)
|
|
Net income (loss) |
$ (64,629)
|
|
|
|
|
Ending balance, shares at Sep. 30, 2021 |
50,120,895
|
50,120,895
|
|
|
|
Ending balance at Sep. 30, 2021 |
$ 1,012,793
|
$ 50
|
1,128,030
|
(115,287)
|
|
Beginning balance, shares at Mar. 31, 2021 |
|
50,005,619
|
|
|
|
Beginning balance at Mar. 31, 2021 |
1,001,926
|
$ 50
|
1,122,176
|
(120,300)
|
|
Stock-based compensation, value |
2,682
|
|
2,682
|
|
|
Tax withholding for stock compensation plans, value |
(7)
|
|
(7)
|
|
|
Issued pursuant to exercise of warrants, shares |
|
11,872
|
|
|
|
Issued pursuant to exercise of warrants, value |
292
|
$ 0
|
292
|
|
|
Net income (loss) |
(77,695)
|
|
|
(77,695)
|
|
Ending balance, shares at Jun. 30, 2021 |
|
50,017,491
|
|
|
|
Ending balance at Jun. 30, 2021 |
927,198
|
$ 50
|
1,125,143
|
(197,995)
|
|
Stock-based compensation, value |
2,686
|
|
2,686
|
|
|
Issued pursuant to exercise of warrants, shares |
|
103,404
|
|
|
|
Issued pursuant to exercise of warrants, value |
201
|
$ 0
|
201
|
|
|
Net income (loss) |
$ 82,708
|
|
|
82,708
|
|
Ending balance, shares at Sep. 30, 2021 |
50,120,895
|
50,120,895
|
|
|
|
Ending balance at Sep. 30, 2021 |
$ 1,012,793
|
$ 50
|
$ 1,128,030
|
$ (115,287)
|
|
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v3.21.2
Basis of Presentation
|
9 Months Ended |
Sep. 30, 2021 |
Accounting Policies [Abstract] |
|
Basis of Presentation |
Note 1. Basis of Presentation
Organization and Nature of Operations
Denbury Inc. (“Denbury,” “Company” or the “Successor”), a Delaware corporation, is an independent energy company with operations focused in the Gulf Coast and Rocky Mountain regions. The Company is differentiated by its focus on CO2 enhanced oil recovery (“EOR”) and the emerging carbon capture, use, and storage (“CCUS”) industry, supported by the Company’s CO2 EOR technical and operational expertise and its extensive CO2 pipeline infrastructure. The utilization of captured industrial-sourced CO2 in EOR significantly reduces the carbon footprint of the oil that Denbury produces, making the Company’s scope 1 and 2 CO2 emissions negative today, with a goal to also fully offset scope 3 CO2 emissions within this decade, primarily through increasing the amount of captured industrial-sourced CO2 used in its operations.
Emergence from Voluntary Reorganization Under Chapter 11 of the Bankruptcy Code
On July 30, 2020 (the “Petition Date”), Denbury Resources Inc. (the “Predecessor”) and its subsidiaries filed petitions for reorganization in a “prepackaged” voluntary bankruptcy (the “Chapter 11 Restructuring”) under chapter 11 of the Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”) under the caption “In re Denbury Resources Inc., et al., Case No. 20-33801”. On September 2, 2020, the Bankruptcy Court entered an order (the “Confirmation Order”) confirming the prepackaged joint plan of reorganization (the “Plan”) and approving the Disclosure Statement, and on September 18, 2020 (the “Emergence Date”), the Plan became effective in accordance with its terms and the Company emerged from Chapter 11 as the successor reporting company of Denbury Resources Inc. On April 23, 2021, the Bankruptcy Court entered a final decree closing the Chapter 11 case captioned “In re Denbury Resources Inc., et al., Case No. 20-33801”; therefore, we have no remaining obligations related to this reorganization.
Upon emergence from bankruptcy, we met the criteria and were required to adopt fresh start accounting in accordance with Financial Accounting Standards Board Codification (“FASC”) Topic 852, Reorganizations. Fresh start accounting requires that new fair values be established for the Company’s assets, liabilities and equity as of the Emergence Date, and therefore certain values and operational results of the condensed consolidated financial statements subsequent to September 18, 2020 are not comparable to those in the Company’s condensed consolidated financial statements prior to, and including September 18, 2020. The Emergence Date fair values of the Successor’s assets and liabilities differ materially from their recorded values as reflected on the historical balance sheets of the Predecessor contained in periodic reports previously filed with the Securities and Exchange Commission. References to “Successor” relate to the financial position and results of operations of the Company subsequent to September 18, 2020, and references to “Predecessor” relate to the financial position and results of operations of the Company prior to, and including, September 18, 2020.
Reorganization Items, Net
Reorganization items, net, include (i) expenses incurred during the Chapter 11 Restructuring subsequent to the Petition Date as a direct result of the Plan, (ii) gains or losses from liabilities settled and (iii) fresh start accounting adjustments and are recorded in “Reorganization items, net” in our Unaudited Condensed Consolidated Statements of Operations. Professional service provider charges associated with our restructuring that were incurred before the Petition Date and after the Emergence Date are recorded in “Other expenses” in our Unaudited Condensed Consolidated Statements of Operations. The following table summarizes the losses (gains) on reorganization items, net: | | | | | | | | | | | Predecessor | In thousands | | Period from July 1, 2020 through Sept. 18, 2020 | Gain on settlement of liabilities subject to compromise | | $ | (1,024,864) | | Fresh start accounting adjustments | | 1,834,423 | | Professional service provider fees and other expenses | | 11,267 | | Success fees for professional service providers | | 9,700 | | Loss on rejected contracts and leases | | 10,989 | | Valuation adjustments to debt classified as subject to compromise | | 757 | | Debtor-in-possession credit agreement fees | | 3,107 | | Acceleration of Predecessor stock compensation expense | | 4,601 | | Total reorganization items, net | | $ | 849,980 | |
Interim Financial Statements
The accompanying unaudited condensed consolidated financial statements of Denbury Inc. and its subsidiaries have been prepared in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”) and do not include all of the information and footnotes required by accounting principles generally accepted in the United States for complete financial statements. These financial statements and the notes thereto should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2020 (the “Form 10-K”). Unless indicated otherwise or the context requires, the terms “we,” “our,” “us,” “Company” or “Denbury,” refer to Denbury Inc. and its subsidiaries.
Accounting measurements at interim dates inherently involve greater reliance on estimates than at year end, and the results of operations for the interim periods shown in this report are not necessarily indicative of results to be expected for the year. In management’s opinion, the accompanying unaudited condensed consolidated financial statements include all adjustments of a normal recurring nature necessary for a fair presentation of our consolidated financial position as of September 30, 2021 (Successor); our consolidated results of operations and consolidated statement of changes in stockholders’ equity for the three and nine months ended September 30, 2021 (Successor), for the period September 19, 2020 through September 30, 2020 (Successor), for the period July 1, 2020 through September 18, 2020 (Predecessor) and January 1, 2020 through September 18, 2020 (Predecessor); and our consolidated cash flows for the nine months ended September 30, 2021 (Successor), for the period September 19, 2020 through September 30, 2020 (Successor) and for the period January 1, 2020 through September 18, 2020 (Predecessor). Upon the adoption of fresh start accounting, the Company’s assets and liabilities were recorded at their fair values as of the fresh start reporting date. As a result of the adoption of fresh start accounting, certain values and operational results of the Company’s condensed consolidated financial statements subsequent to September 18, 2020 are not comparable to those in its condensed consolidated financial statements prior to, and including September 18, 2020.
Reclassifications
Certain prior period amounts have been reclassified to conform to the current year presentation. Such reclassifications had no impact on our reported net income (loss), current assets, total assets, current liabilities, total liabilities or stockholders’ equity. Cash, Cash Equivalents, and Restricted Cash
The following table provides a reconciliation of cash, cash equivalents, and restricted cash as reported within the Unaudited Condensed Consolidated Balance Sheets to “Cash, cash equivalents, and restricted cash at end of period” as reported within the Unaudited Condensed Consolidated Statements of Cash Flows: | | | | | | | | | | | | | | | | | Successor | In thousands | | September 30, 2021 | | December 31, 2020 | Cash and cash equivalents | | $ | 1,783 | | | $ | 518 | | Restricted cash, current | | — | | | 1,000 | | Restricted cash included in other assets | | 46,679 | | | 40,730 | | Total cash, cash equivalents, and restricted cash shown in the Unaudited Condensed Consolidated Statements of Cash Flows | | $ | 48,462 | | | $ | 42,248 | |
Restricted cash included in other assets in the table above consists of escrow accounts that are legally restricted for certain of our asset retirement obligations, and are included in “Other assets” in the accompanying Unaudited Condensed Consolidated Balance Sheets.
Net Income (Loss) per Common Share
Basic net income (loss) per common share is computed by dividing the net income (loss) attributable to common stockholders by the weighted average number of shares of common stock outstanding during the period. Diluted net income per common share is calculated in the same manner but includes the impact of potentially dilutive securities. Potentially dilutive securities during the Successor periods consist of nonvested restricted stock units and outstanding series A and series B warrants, and during the Predecessor periods consisted of nonvested restricted stock, nonvested performance-based equity awards, and convertible senior notes. For each of the three and nine months ended September 30, 2021 and for the periods September 19, 2020 through September 30, 2020 (Successor), July 1, 2020 through September 18, 2020 (Predecessor) and January 1, 2020 through September 18, 2020 (Predecessor), there were no adjustments to net income (loss) for purposes of calculating basic and diluted net income (loss) per common share.
The following table reconciles the weighted average shares used in the basic and diluted net income (loss) per common share calculations for the periods indicated: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Successor | | | Predecessor | | | | | | In thousands | | Three Months Ended Sept. 30, 2021 | | Period from Sept. 19, 2020 through Sept. 30, 2020 | | | Period from July 1, 2020 through Sept. 18, 2020 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Weighted average common shares outstanding – basic | | 51,094 | | | 50,000 | | | | 497,398 | | | | | | | Effect of potentially dilutive securities | | | | | | | | | | | | | Restricted stock units | | 908 | | | — | | | | — | | | | | | | Warrants | | 2,712 | | | — | | | | — | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Weighted average common shares outstanding – diluted | | 54,714 | | | 50,000 | | | | 497,398 | | | | | | |
For the nine months ended September 30, 2021 and for each of the periods from July 1, 2020 through September 18, 2020 (Predecessor) and from January 1, 2020 through September 18, 2020 (Predecessor), the weighted average common shares outstanding used to calculate basic earnings per share and diluted earnings per share were the same, since the Company generated a net loss during those periods. The weighted average diluted shares outstanding would have been 53.4 million for the nine months ended September 30, 2021, 580.0 million for the period July 1, 2020 through September 18, 2020, and 584.4 million for the period January 1, 2020 through September 18, 2020 if the Company had recognized net income during those periods. Basic weighted average common shares during the Successor periods includes 987,987 and 767,228 performance stock units during the three and nine months ended September 30, 2021, respectively, with vesting parameters tied to the Company’s common stock trading prices and which became fully vested on March 3, 2021. Although the performance measures for vesting of these awards have been achieved, the shares underlying these awards are not currently outstanding as actual delivery of the shares is not scheduled to occur until after the end of the performance period, December 4, 2023. Basic weighted average common shares includes time-vesting restricted stock units during the Successor periods and restricted stock during the Predecessor periods that vested during the periods.
For purposes of calculating diluted weighted average common shares for the three months ended September 30, 2021, the nonvested restricted stock units and warrants are included in the computation using the treasury stock method.
The following outstanding securities were excluded from the computation of diluted net loss per share for the nine months ended September 30, 2021 and from diluted net income per share for the period September 19, 2020 to September 30, 2020, as their effect would have been antidilutive, as of the respective dates: | | | | | | | | | | | | | | | | | | | | | | Successor | | | | | | In thousands | | September 30, 2021 | | September 30, 2020 | | | | | | Restricted stock units | | 1,255 | | | — | | | | | | | Warrants | | 5,314 | | | 5,526 | | | | | | |
For the nine months ended September 30, 2021 Successor period, the Company’s restricted stock units and series A and series B warrants were antidilutive based on the Company’s net loss position for the period. Despite the Company’s net income position for the period September 19, 2020 to September 30, 2020, the Company’s series A and series B warrants were antidilutive because the Company’s stock price during the period was lower than the warrant exercise prices. At September 30, 2021, the Company had approximately 5.3 million warrants outstanding that can be exercised for shares of the Successor’s common stock, at an exercise price of $32.59 per share for the 2.6 million series A warrants outstanding and at an exercise price of $35.41 per share for the 2.7 million series B warrants outstanding. The series A warrants are exercisable until September 18, 2025, and the series B warrants are exercisable until September 18, 2023, at which time the warrants expire. The warrants were issued pursuant to the Plan to holders of the Predecessor’s convertible senior notes, senior subordinated notes, and equity. As of September 30, 2021, 8,390 series A warrants and 203,501 series B warrants had been exercised. The warrants may be exercised for cash or on a cashless basis. If warrants are exercised on a cashless basis, the amount of dilution will be less than 5.3 million shares.
Oil and Natural Gas Properties
Unevaluated Costs. Under full cost accounting, we exclude certain unevaluated costs from the amortization base and full cost ceiling test pending the determination of whether proved reserves can be assigned to such properties. These costs are transferred to the full cost amortization base as these properties are developed, tested and evaluated. At least annually, we test these assets for impairment based on an evaluation of management’s expectations of future pricing, evaluation of lease expiration terms, and planned development activities. In the first quarter of 2020 Predecessor period, given the significant declines in NYMEX oil prices in March and April 2020, we reassessed our development plans and transferred $244.9 million of our unevaluated costs to the full cost amortization base. Upon emergence from bankruptcy, the Company adopted fresh start accounting which resulted in our oil and natural gas properties, including unevaluated properties, being recorded at their fair values at the Emergence Date.
Write-Down of Oil and Natural Gas Properties. Under full cost accounting, the net capitalized costs of oil and natural gas properties are limited to the lower of unamortized cost or the cost center ceiling. The cost center ceiling is defined as (1) the present value of estimated future net revenues from proved oil and natural gas reserves before future abandonment costs (discounted at 10%), based on the average first-day-of-the-month oil and natural gas price for each month during a 12-month rolling period prior to the end of a particular reporting period; plus (2) the cost of properties not being amortized; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less (4) related income tax effects. Our future net revenues from proved oil and natural gas reserves are not reduced for development costs related to the cost of drilling for and developing CO2 reserves nor those related to the cost of constructing CO2 pipelines, as we do not have to incur additional CO2 capital costs to develop the proved oil and natural gas reserves. Therefore, we include in the ceiling test, as a reduction of future net revenues, that portion of our capitalized CO2 costs related to CO2 reserves and CO2 pipelines that we estimate will be consumed in the process of producing our proved oil and natural gas reserves. The fair value of our oil and natural gas derivative contracts is not included in the ceiling test, as we do not designate these contracts as hedge instruments for accounting purposes. The cost center ceiling test is prepared quarterly.
We recognized a full cost pool ceiling test write-down of $14.4 million during the three months ended March 31, 2021, with first-day-of-the-month NYMEX oil prices for the preceding 12 months averaging $36.40 per Bbl, after adjustments for market differentials and transportation expenses by field. The write-down was primarily a result of the March 2021 acquisition of Wyoming property interests (see Note 2, Acquisition and Divestitures) which was recorded based on a valuation that utilized NYMEX strip oil prices at the acquisition date, which were significantly higher than the average first-day-of-the-month NYMEX oil prices used to value the cost ceiling.
The Predecessor also recognized full cost pool ceiling test write-downs of $261.7 million during the period from July 1, 2020 through September 18, 2020, $662.4 million during the three months ended June 30, 2020 and $72.5 million during the three months ended March 31, 2020. We did not record any ceiling test write-downs during the Successor periods from September 19, 2020 through September 30, 2020, for the three months ended June 30, 2021, or for the three months ended September 30, 2021.
Recent Accounting Pronouncements
Recently Adopted
Income Taxes. In December 2019, the Financial Accounting Standards Board (“FASB”) issued ASU 2019-12, Income Taxes (Topic 740) – Simplifying the Accounting for Income Taxes (“ASU 2019-12”). The objective of ASU 2019-12 is to simplify the accounting for income taxes by removing certain exceptions to the general principles in Topic 740 and to provide more consistent application to improve the comparability of financial statements. Effective January 1, 2021, we adopted ASU 2019-02. The implementation of this standard did not have a material impact on our consolidated financial statements and related footnote disclosures.
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- DefinitionThe entire disclosure for the basis of presentation and significant accounting policies concepts. Basis of presentation describes the underlying basis used to prepare the financial statements (for example, US Generally Accepted Accounting Principles, Other Comprehensive Basis of Accounting, IFRS). Accounting policies describe all significant accounting policies of the reporting entity.
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v3.21.2
Acquisition and Divestitures
|
9 Months Ended |
Sep. 30, 2021 |
Business Combinations [Abstract] |
|
Acquisition and Divestitures |
Note 2. Acquisition and Divestitures
Acquisition of Wyoming CO2 EOR Fields
On March 3, 2021, we acquired a nearly 100% working interest (approximately 83% net revenue interest) in the Big Sand Draw and Beaver Creek EOR fields located in Wyoming from a subsidiary of Devon Energy Corporation for $10.9 million cash (after final closing adjustments), including surface facilities and a 46-mile CO2 transportation pipeline to the acquired fields. The acquisition agreement provides for us to make two contingent cash payments, one in January 2022 and one in January 2023, of $4 million each, conditioned on NYMEX WTI oil prices averaging at least $50 per Bbl during each of 2021 and 2022. The fair value of the contingent consideration on the acquisition date was $5.3 million, and as of September 30, 2021, the fair value of the contingent consideration recorded on our Unaudited Condensed Consolidated Balance Sheets was $7.4 million. The $2.1 million increase at September 30, 2021 from the March 2021 acquisition date fair value was the result of higher NYMEX WTI oil prices and was recorded to “Other expenses” in our Unaudited Condensed Consolidated Statements of Operations.
The fair values allocated to our assets acquired and liabilities assumed for the acquisition were based on significant inputs not observable in the market and considered level 3 inputs. The fair value of the assets acquired and liabilities assumed was finalized during the third quarter of 2021, after consideration of final closing adjustments and evaluation of reserves and liabilities assumed. The following table presents a summary of the fair value of assets acquired and liabilities assumed in the acquisition:
| | | | | | | | | In thousands | | | Consideration: | | | Cash consideration | | $ | 10,906 | | | | | Less: Fair value of assets acquired and liabilities assumed: | | | Proved oil and natural gas properties | | 60,101 | | Other property and equipment | | 1,685 | | Asset retirement obligations | | (39,794) | | Contingent consideration | | (5,320) | | Other liabilities | | (5,766) | | Fair value of net assets acquired | | $ | 10,906 | |
Divestitures
Hartzog Draw Deep Mineral Rights
On June 30, 2021, we closed the sale of undeveloped, unconventional deep mineral rights in Hartzog Draw Field in Wyoming. The cash proceeds of $18 million were recorded to “Proved properties” in our Unaudited Condensed Consolidated Balance Sheets. The proceeds reduced our full cost pool; therefore, no gain or loss was recorded on the transaction, and the sale had no impact on our production or reserves.
Houston Area Land Sales
During the third quarter of 2021, we completed sales of a portion of certain non-producing surface acreage in the Houston area. We recognized cash proceeds of $11.8 million from the sales and recorded a $7.0 million gain to “Other income” in our Unaudited Condensed Consolidated Statements of Operations.
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- DefinitionThe entire disclosure for business combinations, including leverage buyout transactions (as applicable), and divestitures. This may include a description of a business combination or divestiture (or series of individually immaterial business combinations or divestitures) completed during the period, including background, timing, and assets and liabilities recognized and reclassified or sold. This element does not include fixed asset sales and plant closings.
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v3.21.2
Revenue Recognition
|
9 Months Ended |
Sep. 30, 2021 |
Revenue from Contract with Customer [Abstract] |
|
Revenue Recognition |
Note 3. Revenue Recognition
We record revenue in accordance with FASC Topic 606, Revenue from Contracts with Customers. The core principle of FASC Topic 606 is that an entity should recognize revenue for the transfer of goods or services equal to the amount of consideration that it expects to be entitled to receive for those goods or services. Once we have delivered the volume of commodity to the delivery point and the customer takes delivery and possession, we are entitled to payment and we invoice the customer for such delivered production. Payment under most oil and CO2 contracts is received within a month following product delivery, and for natural gas and NGL contracts, payment is generally received within two months following delivery. Timing of revenue recognition may differ from the timing of invoicing to customers; however, as the right to consideration after delivery is unconditional based on only the passage of time before payment of the consideration is due, upon delivery we record a receivable in “Accrued production receivable” in our Unaudited Condensed Consolidated Balance Sheets. From time to time, the Company enters into marketing arrangements for the purchase and sale of crude oil for third parties. Revenues and expenses from these transactions are presented on a gross basis, as we act as a principal in the transaction by assuming control of the commodities purchased and responsibility to deliver the commodities sold. Revenue is recognized when control transfers to the purchaser at the delivery point based on the price received from the purchaser. Disaggregation of Revenue
The following tables summarize our revenues by product type for the periods indicated: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Successor | | | Predecessor | | | | | | In thousands | | Three Months Ended Sept. 30, 2021 | | Period from Sept. 19, 2020 through Sept. 30, 2020 | | | Period from July 1, 2020 through Sept. 18, 2020 | | | | | | Oil sales | | $ | 305,093 | | | $ | 22,311 | | | | $ | 152,136 | | | | | | | Natural gas sales | | 3,361 | | | 10 | | | | 954 | | | | | | | CO2 sales and transportation fees | | 12,237 | | | 967 | | | | 6,517 | | | | | | | Oil marketing revenues | | 12,593 | | | 151 | | | | 3,332 | | | | | | | Total revenues | | $ | 333,284 | | | $ | 23,439 | | | | $ | 162,939 | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | Successor | | | Predecessor | In thousands | | Nine Months Ended Sept. 30, 2021 | | Period from Sept. 19, 2020 through Sept. 30, 2020 | | | Period from Jan. 1, 2020 through Sept. 18, 2020 | Oil sales | | $ | 818,714 | | | $ | 22,311 | | | | $ | 489,251 | | Natural gas sales | | 7,893 | | | 10 | | | | 2,850 | | CO2 sales and transportation fees | | 31,599 | | | 967 | | | | 21,049 | | Oil marketing revenues | | 26,538 | | | 151 | | | | 8,543 | | Total revenues | | $ | 884,744 | | | $ | 23,439 | | | | $ | 521,693 | |
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v3.21.2
Long-Term Debt
|
9 Months Ended |
Sep. 30, 2021 |
Debt Disclosure [Abstract] |
|
Long-Term Debt |
Note 4. Long-Term Debt
The table below reflects long-term debt outstanding as of the dates indicated: | | | | | | | | | | | | | | | | | Successor | In thousands | | September 30, 2021 | | December 31, 2020 | Senior Secured Bank Credit Agreement | | $ | — | | | $ | 70,000 | | Pipeline financings | | 17,332 | | | 68,008 | | Total debt principal balance | | 17,332 | | | 138,008 | | Less: current maturities of long-term debt | | (17,332) | | | (68,008) | | Long-term debt | | $ | — | | | $ | 70,000 | |
Senior Secured Bank Credit Agreement
On the Emergence Date, we entered into a credit agreement with JPMorgan Chase Bank, N.A., as administrative agent, and other lenders party thereto (the “Bank Credit Agreement”). The Bank Credit Agreement is a senior secured revolving credit facility with a borrowing base and lender commitments of $575 million. Availability under the Bank Credit Agreement is subject to a borrowing base, which is redetermined semiannually on or around May 1 and November 1 of each year, with our next scheduled redetermination around May 1, 2022. The borrowing base is adjusted at the lenders’ discretion and is based, in part, upon external factors over which we have no control. If our outstanding debt under the Bank Credit Agreement exceeds the then-effective borrowing base, we would be required to repay the excess amount over a period not to exceed six months. The Bank Credit Agreement matures on January 30, 2024. The undrawn portion of the aggregate lender commitments under the Bank Credit Agreement is subject to a commitment fee of 0.5% per annum. The Bank Credit Agreement limits our ability to pay dividends on our common stock or make other restricted payments in an amount not to exceed “Distributable Free Cash Flow”, but only if (1) no event of default or borrowing base deficiency exists; (2) our total leverage ratio is 2 to 1 or lower; and (3) availability under the Bank Credit Agreement is at least 20%. The Bank Credit Agreement also limits our ability to, among other things, incur and repay other indebtedness; grant liens; engage in certain mergers, consolidations, liquidations and dissolutions; engage in sales of assets; make acquisitions and investments; make other restricted payments (including redeeming, repurchasing or retiring our common stock); and enter into commodity derivative agreements, in each case subject to customary exceptions.
The Bank Credit Agreement is secured by (1) our proved oil and natural gas properties, which are held through our restricted subsidiaries; (2) the pledge of equity interests of such subsidiaries; (3) a pledge of our commodity derivative agreements; (4) a pledge of deposit accounts, securities accounts and our commodity accounts; and (5) a security interest in substantially all other collateral that may be perfected by a Uniform Commercial Code filing, subject to certain exceptions.
The Bank Credit Agreement contains certain financial performance covenants including the following:
•A Consolidated Total Debt to Consolidated EBITDAX covenant (as defined in the Bank Credit Agreement), with such ratio not to exceed 3.5 times; and •A requirement to maintain a current ratio (i.e., Consolidated Current Assets to Consolidated Current Liabilities) of 1.0.
For purposes of computing the current ratio per the Bank Credit Agreement, Consolidated Current Assets exclude the current portion of derivative assets but include available borrowing capacity under the Bank Credit Agreement, and Consolidated Current Liabilities exclude the current portion of derivative liabilities as well as the current portions of long-term indebtedness outstanding. As of September 30, 2021, we were in compliance with all debt covenants under the Bank Credit Agreement.
The above description of our Bank Credit Agreement is qualified by the express language and defined terms contained in the Bank Credit Agreement.
Pipeline Financing Transactions
During the first nine months of 2021, Denbury paid $52.5 million to Genesis Energy, L.P. in accordance with the October 2020 restructuring of the financing arrangements of our NEJD CO2 pipeline system. The final quarterly installment of $17.5 million was paid on October 29, 2021.
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v3.21.2
Income Taxes
|
9 Months Ended |
Sep. 30, 2021 |
Income Tax Disclosure [Abstract] |
|
Income Taxes |
Note 5. Income Taxes
As of September 30, 2021, the tax basis of our assets, primarily our oil and gas properties, is in excess of their carrying value, as adjusted for fresh start accounting on September 18, 2020; therefore, we are currently in a net deferred tax asset position. Based on all available evidence, both positive and negative, we continue to record a valuation allowance on our underlying deferred tax assets as of September 30, 2021, as we believe our deferred tax assets are not more-likely-than-not to be realized. We intend to maintain the valuation allowances on our deferred tax assets until there is sufficient evidence to support the reversal of all or some portion of the allowances, which will largely be determined based on oil prices and the Company’s ability to generate positive pre-tax income.
We evaluate our estimated annual effective income tax rate based on current and forecasted business results and enacted tax laws on a quarterly basis and apply this tax rate to our ordinary income or loss to calculate our estimated tax liability or benefit. Our income taxes are based on an estimated combined federal and state statutory rate of approximately 25% in 2021 and 2020. Our effective tax rates for the three and nine months ended September 30, 2021 (Successor) differed from our estimated statutory rate as the deferred tax expense generated by the operating income for the three months ended September 30, 2021 and the deferred tax benefit generated from our operating loss for the nine months ended September 30, 2021 were offset by a valuation allowance applied to our underlying federal and state deferred tax assets.
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- DefinitionThe entire disclosure for income taxes. Disclosures may include net deferred tax liability or asset recognized in an enterprise's statement of financial position, net change during the year in the total valuation allowance, approximate tax effect of each type of temporary difference and carryforward that gives rise to a significant portion of deferred tax liabilities and deferred tax assets, utilization of a tax carryback, and tax uncertainties information.
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v3.21.2
Commodity Derivative Contracts
|
9 Months Ended |
Sep. 30, 2021 |
Derivative Instruments and Hedging Activities Disclosure [Abstract] |
|
Commodity Derivative Contracts |
Note 6. Commodity Derivative Contracts
We do not apply hedge accounting treatment to our oil and natural gas derivative contracts; therefore, the changes in the fair values of these instruments are recognized in income in the period of change. These fair value changes, along with the settlements of expired contracts, are shown under “Commodity derivatives expense (income)” in our Unaudited Condensed Consolidated Statements of Operations.
Historically, we have entered into various oil and natural gas derivative contracts to provide an economic hedge of our exposure to commodity price risk associated with anticipated future oil and natural gas production and to provide more certainty to our future cash flows. We do not hold or issue derivative financial instruments for trading purposes. Generally, these contracts have consisted of various combinations of price floors, collars, three-way collars, fixed-price swaps, fixed-price swaps enhanced with a sold put, and basis swaps. The production that we hedge has varied from year to year depending on our levels of debt, financial strength, expectation of future commodity prices, and occasionally requirements under our bank credit facility. As of December 31, 2020, we were in compliance with the hedging requirements under our Bank Credit Agreement requiring certain minimum commodity hedge levels through July 31, 2022, and we do not have any additional hedging requirements under the Bank Credit Agreement.
We manage and control market and counterparty credit risk through established internal control procedures that are reviewed on an ongoing basis. We attempt to minimize credit risk exposure to counterparties through formal credit policies, monitoring procedures and diversification, and all of our commodity derivative contracts are with parties that are lenders under our Bank Credit Agreement (or affiliates of such lenders). As of September 30, 2021, all of our outstanding derivative contracts were subject to enforceable master netting arrangements whereby payables on those contracts can be offset against receivables from separate derivative contracts with the same counterparty. It is our policy to classify derivative assets and liabilities on a gross basis on our balance sheets, even if the contracts are subject to enforceable master netting arrangements.
The following table summarizes our commodity derivative contracts as of September 30, 2021, none of which are classified as hedging instruments in accordance with the FASC Derivatives and Hedging topic: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Months | | Index Price | | Volume (Barrels per day) | | Contract Prices ($/Bbl) | Range(1) | | Weighted Average Price | Swap | | Floor | | Ceiling | Oil Contracts: | | | | | | | | | | | | | | 2021 Fixed-Price Swaps | | | | | | | | | | | | | | Oct – Dec | | NYMEX | | 29,000 | | $ | 38.68 | | – | 56.00 | | | $ | 43.86 | | | $ | — | | | $ | — | | 2021 Collars | | | | | | | | | | | | | | Oct – Dec | | NYMEX | | 4,000 | | $ | 45.00 | | – | 59.30 | | | $ | — | | | $ | 46.25 | | | $ | 53.04 | | 2022 Fixed-Price Swaps | | | | | | | | | | | | | | Jan – June | | NYMEX | | 15,500 | | $ | 42.65 | | – | 58.15 | | | $ | 49.01 | | | $ | — | | | $ | — | | July – Dec | | NYMEX | | 9,000 | | | 50.13 | | – | 60.35 | | | 56.35 | | | — | | | — | | 2022 Collars | | | | | | | | | | | | | | Jan – June | | NYMEX | | 11,000 | | $ | 47.50 | | – | 70.75 | | | $ | — | | | $ | 49.77 | | | $ | 64.31 | | July – Dec | | NYMEX | | 10,000 | | | 47.50 | | – | 70.75 | | | — | | | 49.75 | | | 64.18 | |
(1)Ranges presented for fixed-price swaps represent the lowest and highest fixed prices of all open contracts for the period presented. For collars, ranges represent the lowest floor price and highest ceiling price for all open contracts for the period presented.
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- DefinitionThe entire disclosure for derivative instruments and hedging activities including, but not limited to, risk management strategies, non-hedging derivative instruments, assets, liabilities, revenue and expenses, and methodologies and assumptions used in determining the amounts.
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v3.21.2
Fair Value Measurements
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9 Months Ended |
Sep. 30, 2021 |
Fair Value Disclosures [Abstract] |
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Fair Value Measurements |
Note 7. Fair Value Measurements
The FASC Fair Value Measurement topic defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (often referred to as the “exit price”). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the income approach for recurring fair value measurements and endeavor to utilize the best available information. Accordingly, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. We are able to classify fair value balances based on the observability of those inputs. The FASC establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are as follows:
•Level 1 – Quoted prices in active markets for identical assets or liabilities as of the reporting date.
•Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reported date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. Instruments in this category include non-exchange-traded oil derivatives that are based on NYMEX and regional pricing other than NYMEX (e.g., Light Louisiana Sweet). Our costless collars and the sold put features of our three-way collars are valued using the Black-Scholes model, an industry standard option valuation model that takes into account inputs such as contractual prices for the underlying instruments, maturity, quoted forward prices for commodities, interest rates, volatility factors and credit worthiness, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.
•Level 3 – Pricing inputs include significant inputs that are generally less observable. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value.
We adjust the valuations from the valuation model for nonperformance risk, using our estimate of the counterparty’s credit quality for asset positions and our credit quality for liability positions. We use multiple sources of third-party credit data in determining counterparty nonperformance risk, including credit default swaps.
The following table sets forth, by level within the fair value hierarchy, our financial assets and liabilities that were accounted for at fair value on a recurring basis as of the periods indicated: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Fair Value Measurements Using: | In thousands | | Quoted Prices in Active Markets (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Unobservable Inputs (Level 3) | | Total | September 30, 2021 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Liabilities | | | | | | | | | Oil derivative contracts – current | | $ | — | | | $ | (193,015) | | | $ | — | | | $ | (193,015) | | Oil derivative contracts – long-term | | — | | | (16,435) | | | — | | | (16,435) | | Total Liabilities | | $ | — | | | $ | (209,450) | | | $ | — | | | $ | (209,450) | | | | | | | | | | | December 31, 2020 | | | | | | | | | Assets | | | | | | | | | Oil derivative contracts – current | | $ | — | | | $ | 187 | | | $ | — | | | $ | 187 | | Total Assets | | $ | — | | | $ | 187 | | | $ | — | | | $ | 187 | | | | | | | | | | | Liabilities | | | | | | | | | Oil derivative contracts – current | | $ | — | | | $ | (53,865) | | | $ | — | | | $ | (53,865) | | Oil derivative contracts – long-term | | — | | | (5,087) | | | — | | | (5,087) | | Total Liabilities | | $ | — | | | $ | (58,952) | | | $ | — | | | $ | (58,952) | |
Since we do not apply hedge accounting for our commodity derivative contracts, any gains and losses on our assets and liabilities are included in “Commodity derivatives expense (income)” in the accompanying Unaudited Condensed Consolidated Statements of Operations.
Other Fair Value Measurements
The carrying value of our loans under our Bank Credit Agreement approximate fair value, as they are subject to short-term floating interest rates that approximate the rates available to us for those periods. The estimated fair value of the principal amount of our debt as of December 31, 2020, excluding pipeline financing obligations, was $70.0 million. We have other financial instruments consisting primarily of cash, cash equivalents, U.S. Treasury notes, short-term receivables and payables that approximate fair value due to the nature of the instrument and the relatively short maturities.
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- DefinitionThe entire disclosure for the fair value of financial instruments (as defined), including financial assets and financial liabilities (collectively, as defined), and the measurements of those instruments as well as disclosures related to the fair value of non-financial assets and liabilities. Such disclosures about the financial instruments, assets, and liabilities would include: (1) the fair value of the required items together with their carrying amounts (as appropriate); (2) for items for which it is not practicable to estimate fair value, disclosure would include: (a) information pertinent to estimating fair value (including, carrying amount, effective interest rate, and maturity, and (b) the reasons why it is not practicable to estimate fair value; (3) significant concentrations of credit risk including: (a) information about the activity, region, or economic characteristics identifying a concentration, (b) the maximum amount of loss the entity is exposed to based on the gross fair value of the related item, (c) policy for requiring collateral or other security and information as to accessing such collateral or security, and (d) the nature and brief description of such collateral or security; (4) quantitative information about market risks and how such risks are managed; (5) for items measured on both a recurring and nonrecurring basis information regarding the inputs used to develop the fair value measurement; and (6) for items presented in the financial statement for which fair value measurement is elected: (a) information necessary to understand the reasons for the election, (b) discussion of the effect of fair value changes on earnings, (c) a description of [similar groups] items for which the election is made and the relation thereof to the balance sheet, the aggregate carrying value of items included in the balance sheet that are not eligible for the election; (7) all other required (as defined) and desired information.
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v3.21.2
Commitments and Contingencies
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9 Months Ended |
Sep. 30, 2021 |
Commitments and Contingencies Disclosure [Abstract] |
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Commitments and Contingencies |
Note 8. Commitments and Contingencies
Litigation
We are involved in various lawsuits, claims and regulatory proceedings incidental to our businesses. We are also subject to audits for various taxes (income, sales and use, and severance) in the various states in which we operate, and from time to time receive assessments for potential taxes that we may owe. While we currently believe that the ultimate outcome of these proceedings, individually and in the aggregate, will not have a material adverse effect on our financial position, results of operations or cash flows, litigation is subject to inherent uncertainties. We accrue for losses from litigation and claims if we determine that a loss is probable and the amount can be reasonably estimated.
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- DefinitionThe entire disclosure for commitments and contingencies.
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v3.21.2
Additional Balance Sheet Details
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9 Months Ended |
Sep. 30, 2021 |
Disclosure Text Block [Abstract] |
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Additional Balance Sheet Details |
Note 9. Additional Balance Sheet Details
Accounts Payable and Accrued Liabilities | | | | | | | | | | | | | | | | | Successor | In thousands | | September 30, 2021 | | December 31, 2020 | Accounts payable | | $ | 38,578 | | | $ | 18,629 | | Accrued compensation | | 33,961 | | | 7,512 | | Accrued derivative settlements | | 26,311 | | | 3,908 | | Accrued lease operating expenses | | 25,724 | | | 21,294 | | Accrued exploration and development costs | | 20,728 | | | 1,861 | | Taxes payable | | 14,468 | | | 17,221 | | Accrued general and administrative expenses | | 2,595 | | | 21,825 | | Other | | 49,529 | | | 20,421 | | Total | | $ | 211,894 | | | $ | 112,671 | |
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v3.21.2
Basis of Presentation (Policies)
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9 Months Ended |
Sep. 30, 2021 |
Accounting Policies [Abstract] |
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Organization and Nature of Operations |
Organization and Nature of Operations
Denbury Inc. (“Denbury,” “Company” or the “Successor”), a Delaware corporation, is an independent energy company with operations focused in the Gulf Coast and Rocky Mountain regions. The Company is differentiated by its focus on CO2 enhanced oil recovery (“EOR”) and the emerging carbon capture, use, and storage (“CCUS”) industry, supported by the Company’s CO2 EOR technical and operational expertise and its extensive CO2 pipeline infrastructure. The utilization of captured industrial-sourced CO2 in EOR significantly reduces the carbon footprint of the oil that Denbury produces, making the Company’s scope 1 and 2 CO2 emissions negative today, with a goal to also fully offset scope 3 CO2 emissions within this decade, primarily through increasing the amount of captured industrial-sourced CO2 used in its operations.
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Interim Financial Statements - Basis of Accounting, Policy |
Interim Financial Statements
The accompanying unaudited condensed consolidated financial statements of Denbury Inc. and its subsidiaries have been prepared in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”) and do not include all of the information and footnotes required by accounting principles generally accepted in the United States for complete financial statements. These financial statements and the notes thereto should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2020 (the “Form 10-K”). Unless indicated otherwise or the context requires, the terms “we,” “our,” “us,” “Company” or “Denbury,” refer to Denbury Inc. and its subsidiaries.
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Interim Financial Statements - Use of Estimates |
Accounting measurements at interim dates inherently involve greater reliance on estimates than at year end, and the results of operations for the interim periods shown in this report are not necessarily indicative of results to be expected for the year. In management’s opinion, the accompanying unaudited condensed consolidated financial statements include all adjustments of a normal recurring nature necessary for a fair presentation of our consolidated financial position as of September 30, 2021 (Successor); our consolidated results of operations and consolidated statement of changes in stockholders’ equity for the three and nine months ended September 30, 2021 (Successor), for the period September 19, 2020 through September 30, 2020 (Successor), for the period July 1, 2020 through September 18, 2020 (Predecessor) and January 1, 2020 through September 18, 2020 (Predecessor); and our consolidated cash flows for the nine months ended September 30, 2021 (Successor), for the period September 19, 2020 through September 30, 2020 (Successor) and for the period January 1, 2020 through September 18, 2020 (Predecessor). Upon the adoption of fresh start accounting, the Company’s assets and liabilities were recorded at their fair values as of the fresh start reporting date. As a result of the adoption of fresh start accounting, certain values and operational results of the Company’s condensed consolidated financial statements subsequent to September 18, 2020 are not comparable to those in its condensed consolidated financial statements prior to, and including September 18, 2020.
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Reclassifications |
Reclassifications
Certain prior period amounts have been reclassified to conform to the current year presentation. Such reclassifications had no impact on our reported net income (loss), current assets, total assets, current liabilities, total liabilities or stockholders’ equity.
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Cash, Cash Equivalents, and Restricted Cash |
Cash, Cash Equivalents, and Restricted Cash
The following table provides a reconciliation of cash, cash equivalents, and restricted cash as reported within the Unaudited Condensed Consolidated Balance Sheets to “Cash, cash equivalents, and restricted cash at end of period” as reported within the Unaudited Condensed Consolidated Statements of Cash Flows: | | | | | | | | | | | | | | | | | Successor | In thousands | | September 30, 2021 | | December 31, 2020 | Cash and cash equivalents | | $ | 1,783 | | | $ | 518 | | Restricted cash, current | | — | | | 1,000 | | Restricted cash included in other assets | | 46,679 | | | 40,730 | | Total cash, cash equivalents, and restricted cash shown in the Unaudited Condensed Consolidated Statements of Cash Flows | | $ | 48,462 | | | $ | 42,248 | |
Restricted cash included in other assets in the table above consists of escrow accounts that are legally restricted for certain of our asset retirement obligations, and are included in “Other assets” in the accompanying Unaudited Condensed Consolidated Balance Sheets.
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Net Loss per Common Share |
Net Income (Loss) per Common Share
Basic net income (loss) per common share is computed by dividing the net income (loss) attributable to common stockholders by the weighted average number of shares of common stock outstanding during the period. Diluted net income per common share is calculated in the same manner but includes the impact of potentially dilutive securities. Potentially dilutive securities during the Successor periods consist of nonvested restricted stock units and outstanding series A and series B warrants, and during the Predecessor periods consisted of nonvested restricted stock, nonvested performance-based equity awards, and convertible senior notes. For each of the three and nine months ended September 30, 2021 and for the periods September 19, 2020 through September 30, 2020 (Successor), July 1, 2020 through September 18, 2020 (Predecessor) and January 1, 2020 through September 18, 2020 (Predecessor), there were no adjustments to net income (loss) for purposes of calculating basic and diluted net income (loss) per common share.
The following table reconciles the weighted average shares used in the basic and diluted net income (loss) per common share calculations for the periods indicated: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Successor | | | Predecessor | | | | | | In thousands | | Three Months Ended Sept. 30, 2021 | | Period from Sept. 19, 2020 through Sept. 30, 2020 | | | Period from July 1, 2020 through Sept. 18, 2020 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Weighted average common shares outstanding – basic | | 51,094 | | | 50,000 | | | | 497,398 | | | | | | | Effect of potentially dilutive securities | | | | | | | | | | | | | Restricted stock units | | 908 | | | — | | | | — | | | | | | | Warrants | | 2,712 | | | — | | | | — | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Weighted average common shares outstanding – diluted | | 54,714 | | | 50,000 | | | | 497,398 | | | | | | |
For the nine months ended September 30, 2021 and for each of the periods from July 1, 2020 through September 18, 2020 (Predecessor) and from January 1, 2020 through September 18, 2020 (Predecessor), the weighted average common shares outstanding used to calculate basic earnings per share and diluted earnings per share were the same, since the Company generated a net loss during those periods. The weighted average diluted shares outstanding would have been 53.4 million for the nine months ended September 30, 2021, 580.0 million for the period July 1, 2020 through September 18, 2020, and 584.4 million for the period January 1, 2020 through September 18, 2020 if the Company had recognized net income during those periods. Basic weighted average common shares during the Successor periods includes 987,987 and 767,228 performance stock units during the three and nine months ended September 30, 2021, respectively, with vesting parameters tied to the Company’s common stock trading prices and which became fully vested on March 3, 2021. Although the performance measures for vesting of these awards have been achieved, the shares underlying these awards are not currently outstanding as actual delivery of the shares is not scheduled to occur until after the end of the performance period, December 4, 2023. Basic weighted average common shares includes time-vesting restricted stock units during the Successor periods and restricted stock during the Predecessor periods that vested during the periods.
For purposes of calculating diluted weighted average common shares for the three months ended September 30, 2021, the nonvested restricted stock units and warrants are included in the computation using the treasury stock method.
The following outstanding securities were excluded from the computation of diluted net loss per share for the nine months ended September 30, 2021 and from diluted net income per share for the period September 19, 2020 to September 30, 2020, as their effect would have been antidilutive, as of the respective dates: | | | | | | | | | | | | | | | | | | | | | | Successor | | | | | | In thousands | | September 30, 2021 | | September 30, 2020 | | | | | | Restricted stock units | | 1,255 | | | — | | | | | | | Warrants | | 5,314 | | | 5,526 | | | | | | |
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Oil and Natural Gas Properties |
Oil and Natural Gas Properties
Unevaluated Costs. Under full cost accounting, we exclude certain unevaluated costs from the amortization base and full cost ceiling test pending the determination of whether proved reserves can be assigned to such properties. These costs are transferred to the full cost amortization base as these properties are developed, tested and evaluated. At least annually, we test these assets for impairment based on an evaluation of management’s expectations of future pricing, evaluation of lease expiration terms, and planned development activities. In the first quarter of 2020 Predecessor period, given the significant declines in NYMEX oil prices in March and April 2020, we reassessed our development plans and transferred $244.9 million of our unevaluated costs to the full cost amortization base. Upon emergence from bankruptcy, the Company adopted fresh start accounting which resulted in our oil and natural gas properties, including unevaluated properties, being recorded at their fair values at the Emergence Date.
Write-Down of Oil and Natural Gas Properties. Under full cost accounting, the net capitalized costs of oil and natural gas properties are limited to the lower of unamortized cost or the cost center ceiling. The cost center ceiling is defined as (1) the present value of estimated future net revenues from proved oil and natural gas reserves before future abandonment costs (discounted at 10%), based on the average first-day-of-the-month oil and natural gas price for each month during a 12-month rolling period prior to the end of a particular reporting period; plus (2) the cost of properties not being amortized; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less (4) related income tax effects. Our future net revenues from proved oil and natural gas reserves are not reduced for development costs related to the cost of drilling for and developing CO2 reserves nor those related to the cost of constructing CO2 pipelines, as we do not have to incur additional CO2 capital costs to develop the proved oil and natural gas reserves. Therefore, we include in the ceiling test, as a reduction of future net revenues, that portion of our capitalized CO2 costs related to CO2 reserves and CO2 pipelines that we estimate will be consumed in the process of producing our proved oil and natural gas reserves. The fair value of our oil and natural gas derivative contracts is not included in the ceiling test, as we do not designate these contracts as hedge instruments for accounting purposes. The cost center ceiling test is prepared quarterly.
We recognized a full cost pool ceiling test write-down of $14.4 million during the three months ended March 31, 2021, with first-day-of-the-month NYMEX oil prices for the preceding 12 months averaging $36.40 per Bbl, after adjustments for market differentials and transportation expenses by field. The write-down was primarily a result of the March 2021 acquisition of Wyoming property interests (see Note 2, Acquisition and Divestitures) which was recorded based on a valuation that utilized NYMEX strip oil prices at the acquisition date, which were significantly higher than the average first-day-of-the-month NYMEX oil prices used to value the cost ceiling.
The Predecessor also recognized full cost pool ceiling test write-downs of $261.7 million during the period from July 1, 2020 through September 18, 2020, $662.4 million during the three months ended June 30, 2020 and $72.5 million during the three months ended March 31, 2020. We did not record any ceiling test write-downs during the Successor periods from September 19, 2020 through September 30, 2020, for the three months ended June 30, 2021, or for the three months ended September 30, 2021.
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Recent Accounting Pronouncements |
Recent Accounting Pronouncements
Recently Adopted
Income Taxes. In December 2019, the Financial Accounting Standards Board (“FASB”) issued ASU 2019-12, Income Taxes (Topic 740) – Simplifying the Accounting for Income Taxes (“ASU 2019-12”). The objective of ASU 2019-12 is to simplify the accounting for income taxes by removing certain exceptions to the general principles in Topic 740 and to provide more consistent application to improve the comparability of financial statements. Effective January 1, 2021, we adopted ASU 2019-02. The implementation of this standard did not have a material impact on our consolidated financial statements and related footnote disclosures.
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Revenue Recognition |
We record revenue in accordance with FASC Topic 606, Revenue from Contracts with Customers. The core principle of FASC Topic 606 is that an entity should recognize revenue for the transfer of goods or services equal to the amount of consideration that it expects to be entitled to receive for those goods or services. Once we have delivered the volume of commodity to the delivery point and the customer takes delivery and possession, we are entitled to payment and we invoice the customer for such delivered production. Payment under most oil and CO2 contracts is received within a month following product delivery, and for natural gas and NGL contracts, payment is generally received within two months following delivery. Timing of revenue recognition may differ from the timing of invoicing to customers; however, as the right to consideration after delivery is unconditional based on only the passage of time before payment of the consideration is due, upon delivery we record a receivable in “Accrued production receivable” in our Unaudited Condensed Consolidated Balance Sheets. From time to time, the Company enters into marketing arrangements for the purchase and sale of crude oil for third parties. Revenues and expenses from these transactions are presented on a gross basis, as we act as a principal in the transaction by assuming control of the commodities purchased and responsibility to deliver the commodities sold. Revenue is recognized when control transfers to the purchaser at the delivery point based on the price received from the purchaser.
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Income Taxes |
We evaluate our estimated annual effective income tax rate based on current and forecasted business results and enacted tax laws on a quarterly basis and apply this tax rate to our ordinary income or loss to calculate our estimated tax liability or benefit. Our income taxes are based on an estimated combined federal and state statutory rate of approximately 25% in 2021 and 2020.
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Commodity Derivative Contracts |
We do not apply hedge accounting treatment to our oil and natural gas derivative contracts; therefore, the changes in the fair values of these instruments are recognized in income in the period of change. These fair value changes, along with the settlements of expired contracts, are shown under “Commodity derivatives expense (income)” in our Unaudited Condensed Consolidated Statements of Operations.
Historically, we have entered into various oil and natural gas derivative contracts to provide an economic hedge of our exposure to commodity price risk associated with anticipated future oil and natural gas production and to provide more certainty to our future cash flows. We do not hold or issue derivative financial instruments for trading purposes. Generally, these contracts have consisted of various combinations of price floors, collars, three-way collars, fixed-price swaps, fixed-price swaps enhanced with a sold put, and basis swaps. The production that we hedge has varied from year to year depending on our levels of debt, financial strength, expectation of future commodity prices, and occasionally requirements under our bank credit facility. As of December 31, 2020, we were in compliance with the hedging requirements under our Bank Credit Agreement requiring certain minimum commodity hedge levels through July 31, 2022, and we do not have any additional hedging requirements under the Bank Credit Agreement.
We manage and control market and counterparty credit risk through established internal control procedures that are reviewed on an ongoing basis. We attempt to minimize credit risk exposure to counterparties through formal credit policies, monitoring procedures and diversification, and all of our commodity derivative contracts are with parties that are lenders under our Bank Credit Agreement (or affiliates of such lenders). As of September 30, 2021, all of our outstanding derivative contracts were subject to enforceable master netting arrangements whereby payables on those contracts can be offset against receivables from separate derivative contracts with the same counterparty. It is our policy to classify derivative assets and liabilities on a gross basis on our balance sheets, even if the contracts are subject to enforceable master netting arrangements.
|
Fair Value Measurements |
The FASC Fair Value Measurement topic defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (often referred to as the “exit price”). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the income approach for recurring fair value measurements and endeavor to utilize the best available information. Accordingly, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. We are able to classify fair value balances based on the observability of those inputs. The FASC establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are as follows:
•Level 1 – Quoted prices in active markets for identical assets or liabilities as of the reporting date.
•Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reported date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. Instruments in this category include non-exchange-traded oil derivatives that are based on NYMEX and regional pricing other than NYMEX (e.g., Light Louisiana Sweet). Our costless collars and the sold put features of our three-way collars are valued using the Black-Scholes model, an industry standard option valuation model that takes into account inputs such as contractual prices for the underlying instruments, maturity, quoted forward prices for commodities, interest rates, volatility factors and credit worthiness, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.
•Level 3 – Pricing inputs include significant inputs that are generally less observable. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value.
We adjust the valuations from the valuation model for nonperformance risk, using our estimate of the counterparty’s credit quality for asset positions and our credit quality for liability positions. We use multiple sources of third-party credit data in determining counterparty nonperformance risk, including credit default swaps.
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v3.21.2
Basis of Presentation (Tables)
|
9 Months Ended |
Sep. 30, 2021 |
Accounting Policies [Abstract] |
|
Schedule of reorganization items, net |
The following table summarizes the losses (gains) on reorganization items, net: | | | | | | | | | | | Predecessor | In thousands | | Period from July 1, 2020 through Sept. 18, 2020 | Gain on settlement of liabilities subject to compromise | | $ | (1,024,864) | | Fresh start accounting adjustments | | 1,834,423 | | Professional service provider fees and other expenses | | 11,267 | | Success fees for professional service providers | | 9,700 | | Loss on rejected contracts and leases | | 10,989 | | Valuation adjustments to debt classified as subject to compromise | | 757 | | Debtor-in-possession credit agreement fees | | 3,107 | | Acceleration of Predecessor stock compensation expense | | 4,601 | | Total reorganization items, net | | $ | 849,980 | |
|
Schedule of cash, cash equivalents, and restricted cash |
The following table provides a reconciliation of cash, cash equivalents, and restricted cash as reported within the Unaudited Condensed Consolidated Balance Sheets to “Cash, cash equivalents, and restricted cash at end of period” as reported within the Unaudited Condensed Consolidated Statements of Cash Flows: | | | | | | | | | | | | | | | | | Successor | In thousands | | September 30, 2021 | | December 31, 2020 | Cash and cash equivalents | | $ | 1,783 | | | $ | 518 | | Restricted cash, current | | — | | | 1,000 | | Restricted cash included in other assets | | 46,679 | | | 40,730 | | Total cash, cash equivalents, and restricted cash shown in the Unaudited Condensed Consolidated Statements of Cash Flows | | $ | 48,462 | | | $ | 42,248 | |
|
Schedule of earnings per share, basic and diluted reconciliation |
The following table reconciles the weighted average shares used in the basic and diluted net income (loss) per common share calculations for the periods indicated: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Successor | | | Predecessor | | | | | | In thousands | | Three Months Ended Sept. 30, 2021 | | Period from Sept. 19, 2020 through Sept. 30, 2020 | | | Period from July 1, 2020 through Sept. 18, 2020 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Weighted average common shares outstanding – basic | | 51,094 | | | 50,000 | | | | 497,398 | | | | | | | Effect of potentially dilutive securities | | | | | | | | | | | | | Restricted stock units | | 908 | | | — | | | | — | | | | | | | Warrants | | 2,712 | | | — | | | | — | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Weighted average common shares outstanding – diluted | | 54,714 | | | 50,000 | | | | 497,398 | | | | | | |
|
Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share |
The following outstanding securities were excluded from the computation of diluted net loss per share for the nine months ended September 30, 2021 and from diluted net income per share for the period September 19, 2020 to September 30, 2020, as their effect would have been antidilutive, as of the respective dates: | | | | | | | | | | | | | | | | | | | | | | Successor | | | | | | In thousands | | September 30, 2021 | | September 30, 2020 | | | | | | Restricted stock units | | 1,255 | | | — | | | | | | | Warrants | | 5,314 | | | 5,526 | | | | | | |
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v3.21.2
Acquisition and Divestitures (Tables)
|
9 Months Ended |
Sep. 30, 2021 |
Business Combinations [Abstract] |
|
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed |
The following table presents a summary of the fair value of assets acquired and liabilities assumed in the acquisition: | | | | | | | | | In thousands | | | Consideration: | | | Cash consideration | | $ | 10,906 | | | | | Less: Fair value of assets acquired and liabilities assumed: | | | Proved oil and natural gas properties | | 60,101 | | Other property and equipment | | 1,685 | | Asset retirement obligations | | (39,794) | | Contingent consideration | | (5,320) | | Other liabilities | | (5,766) | | Fair value of net assets acquired | | $ | 10,906 | |
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v3.21.2
Revenue Recognition (Tables)
|
9 Months Ended |
Sep. 30, 2021 |
Revenue from Contract with Customer [Abstract] |
|
Disaggregation of Revenue |
The following tables summarize our revenues by product type for the periods indicated: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Successor | | | Predecessor | | | | | | In thousands | | Three Months Ended Sept. 30, 2021 | | Period from Sept. 19, 2020 through Sept. 30, 2020 | | | Period from July 1, 2020 through Sept. 18, 2020 | | | | | | Oil sales | | $ | 305,093 | | | $ | 22,311 | | | | $ | 152,136 | | | | | | | Natural gas sales | | 3,361 | | | 10 | | | | 954 | | | | | | | CO2 sales and transportation fees | | 12,237 | | | 967 | | | | 6,517 | | | | | | | Oil marketing revenues | | 12,593 | | | 151 | | | | 3,332 | | | | | | | Total revenues | | $ | 333,284 | | | $ | 23,439 | | | | $ | 162,939 | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | Successor | | | Predecessor | In thousands | | Nine Months Ended Sept. 30, 2021 | | Period from Sept. 19, 2020 through Sept. 30, 2020 | | | Period from Jan. 1, 2020 through Sept. 18, 2020 | Oil sales | | $ | 818,714 | | | $ | 22,311 | | | | $ | 489,251 | | Natural gas sales | | 7,893 | | | 10 | | | | 2,850 | | CO2 sales and transportation fees | | 31,599 | | | 967 | | | | 21,049 | | Oil marketing revenues | | 26,538 | | | 151 | | | | 8,543 | | Total revenues | | $ | 884,744 | | | $ | 23,439 | | | | $ | 521,693 | |
|
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v3.21.2
Long-Term Debt (Tables)
|
9 Months Ended |
Sep. 30, 2021 |
Debt Disclosure [Abstract] |
|
Components of Long-Term Debt |
The table below reflects long-term debt outstanding as of the dates indicated: | | | | | | | | | | | | | | | | | Successor | In thousands | | September 30, 2021 | | December 31, 2020 | Senior Secured Bank Credit Agreement | | $ | — | | | $ | 70,000 | | Pipeline financings | | 17,332 | | | 68,008 | | Total debt principal balance | | 17,332 | | | 138,008 | | Less: current maturities of long-term debt | | (17,332) | | | (68,008) | | Long-term debt | | $ | — | | | $ | 70,000 | |
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v3.21.2
Commodity Derivative Contracts (Tables)
|
9 Months Ended |
Sep. 30, 2021 |
Derivative Instruments and Hedging Activities Disclosure [Abstract] |
|
Commodity derivative contracts not classified as hedging instruments |
The following table summarizes our commodity derivative contracts as of September 30, 2021, none of which are classified as hedging instruments in accordance with the FASC Derivatives and Hedging topic: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Months | | Index Price | | Volume (Barrels per day) | | Contract Prices ($/Bbl) | Range(1) | | Weighted Average Price | Swap | | Floor | | Ceiling | Oil Contracts: | | | | | | | | | | | | | | 2021 Fixed-Price Swaps | | | | | | | | | | | | | | Oct – Dec | | NYMEX | | 29,000 | | $ | 38.68 | | – | 56.00 | | | $ | 43.86 | | | $ | — | | | $ | — | | 2021 Collars | | | | | | | | | | | | | | Oct – Dec | | NYMEX | | 4,000 | | $ | 45.00 | | – | 59.30 | | | $ | — | | | $ | 46.25 | | | $ | 53.04 | | 2022 Fixed-Price Swaps | | | | | | | | | | | | | | Jan – June | | NYMEX | | 15,500 | | $ | 42.65 | | – | 58.15 | | | $ | 49.01 | | | $ | — | | | $ | — | | July – Dec | | NYMEX | | 9,000 | | | 50.13 | | – | 60.35 | | | 56.35 | | | — | | | — | | 2022 Collars | | | | | | | | | | | | | | Jan – June | | NYMEX | | 11,000 | | $ | 47.50 | | – | 70.75 | | | $ | — | | | $ | 49.77 | | | $ | 64.31 | | July – Dec | | NYMEX | | 10,000 | | | 47.50 | | – | 70.75 | | | — | | | 49.75 | | | 64.18 | |
(1)Ranges presented for fixed-price swaps represent the lowest and highest fixed prices of all open contracts for the period presented. For collars, ranges represent the lowest floor price and highest ceiling price for all open contracts for the period presented.
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v3.21.2
Fair Value Measurements (Tables)
|
9 Months Ended |
Sep. 30, 2021 |
Fair Value Disclosures [Abstract] |
|
Fair value hierarchy of financial assets and liabilities |
The following table sets forth, by level within the fair value hierarchy, our financial assets and liabilities that were accounted for at fair value on a recurring basis as of the periods indicated: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Fair Value Measurements Using: | In thousands | | Quoted Prices in Active Markets (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Unobservable Inputs (Level 3) | | Total | September 30, 2021 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Liabilities | | | | | | | | | Oil derivative contracts – current | | $ | — | | | $ | (193,015) | | | $ | — | | | $ | (193,015) | | Oil derivative contracts – long-term | | — | | | (16,435) | | | — | | | (16,435) | | Total Liabilities | | $ | — | | | $ | (209,450) | | | $ | — | | | $ | (209,450) | | | | | | | | | | | December 31, 2020 | | | | | | | | | Assets | | | | | | | | | Oil derivative contracts – current | | $ | — | | | $ | 187 | | | $ | — | | | $ | 187 | | Total Assets | | $ | — | | | $ | 187 | | | $ | — | | | $ | 187 | | | | | | | | | | | Liabilities | | | | | | | | | Oil derivative contracts – current | | $ | — | | | $ | (53,865) | | | $ | — | | | $ | (53,865) | | Oil derivative contracts – long-term | | — | | | (5,087) | | | — | | | (5,087) | | Total Liabilities | | $ | — | | | $ | (58,952) | | | $ | — | | | $ | (58,952) | |
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v3.21.2
Additional Balance Sheet Details (Tables)
|
9 Months Ended |
Sep. 30, 2021 |
Table Text Block [Abstract] |
|
Accounts Payable and Accrued Liabilities |
Accounts Payable and Accrued Liabilities | | | | | | | | | | | | | | | | | Successor | In thousands | | September 30, 2021 | | December 31, 2020 | Accounts payable | | $ | 38,578 | | | $ | 18,629 | | Accrued compensation | | 33,961 | | | 7,512 | | Accrued derivative settlements | | 26,311 | | | 3,908 | | Accrued lease operating expenses | | 25,724 | | | 21,294 | | Accrued exploration and development costs | | 20,728 | | | 1,861 | | Taxes payable | | 14,468 | | | 17,221 | | Accrued general and administrative expenses | | 2,595 | | | 21,825 | | Other | | 49,529 | | | 20,421 | | Total | | $ | 211,894 | | | $ | 112,671 | |
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v3.21.2
Basis of Presentation (Reorganization Items, Net) (Details) - USD ($) $ in Thousands |
|
3 Months Ended |
9 Months Ended |
Sep. 30, 2020 |
Sep. 30, 2021 |
Sep. 18, 2020 |
Sep. 30, 2021 |
Sep. 18, 2020 |
Reorganizations [Abstract] |
|
|
|
|
|
Gain on settlement of liabilities subject to compromise |
|
|
$ (1,024,864)
|
|
|
Fresh start accounting adjustments |
|
|
1,834,423
|
|
|
Professional service provider fees and other expenses |
|
|
11,267
|
|
|
Success fees for professional service providers |
|
|
9,700
|
|
|
Loss on rejected contracts and leases |
|
|
10,989
|
|
|
Valuation adjustments to debt classified as subject to compromise |
|
|
757
|
|
|
Debtor-in-possession credit agreement fees |
|
|
3,107
|
|
|
Acceleration of Predecessor stock compensation expense |
|
|
4,601
|
|
|
Total reorganization items, net |
$ 0
|
$ 0
|
$ 849,980
|
$ 0
|
$ 849,980
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v3.21.2
Basis of Presentation (Cash, Cash Equivalents, and Restricted Cash) (Details) - USD ($) $ in Thousands |
Sep. 30, 2021 |
Dec. 31, 2020 |
Sep. 30, 2020 |
Sep. 18, 2020 |
Dec. 31, 2019 |
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents [Abstract] |
|
|
|
|
|
Cash and cash equivalents |
$ 1,783
|
$ 518
|
|
|
|
Restricted cash, current |
0
|
1,000
|
|
|
|
Restricted cash included in other assets |
46,679
|
40,730
|
|
|
|
Total cash, cash equivalents, and restricted cash shown in the Unaudited Condensed Consolidated Statements of Cash Flows |
$ 48,462
|
$ 42,248
|
$ 71,410
|
$ 95,114
|
$ 33,045
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v3.21.2
Basis of Presentation (Reconciliation of Weighted Average Shares Table) (Details) - shares shares in Thousands |
|
3 Months Ended |
9 Months Ended |
Sep. 30, 2020 |
Sep. 30, 2021 |
Sep. 18, 2020 |
Sep. 30, 2021 |
Sep. 18, 2020 |
Earnings Per Share Reconciliation [Abstract] |
|
|
|
|
|
Weighted average common shares outstanding - basic |
50,000
|
51,094
|
497,398
|
50,807
|
495,560
|
Restricted stock units |
0
|
908
|
0
|
|
|
Warrants |
0
|
2,712
|
0
|
|
|
Weighted average common shares outstanding - diluted |
50,000
|
54,714
|
497,398
|
50,807
|
495,560
|
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v3.21.2
Basis of Presentation (Weighted Avg Shares) (Details Textuals) - shares shares in Thousands |
|
3 Months Ended |
9 Months Ended |
Sep. 30, 2020 |
Sep. 30, 2021 |
Sep. 18, 2020 |
Sep. 30, 2021 |
Sep. 18, 2020 |
Weighted average number of dilutive shares |
50,000
|
54,714
|
497,398
|
50,807
|
495,560
|
Net Income Scenario |
|
|
|
|
|
Weighted average number of dilutive shares |
|
|
580,000
|
53,400
|
584,400
|
X |
- DefinitionThe average number of shares or units issued and outstanding that are used in calculating diluted EPS or earnings per unit (EPU), determined based on the timing of issuance of shares or units in the period.
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v3.21.2
Basis of Presentation (Details Textuals)
|
|
3 Months Ended |
9 Months Ended |
Sep. 30, 2020
shares
|
Sep. 30, 2021
warrants
$ / shares
shares
|
Sep. 18, 2020
shares
|
Sep. 30, 2021
warrants
$ / shares
shares
|
Sep. 18, 2020
shares
|
Class of Warrant or Right [Line Items] |
|
|
|
|
|
Weighted average common shares outstanding - basic |
50,000,000
|
51,094,000
|
497,398,000
|
50,807,000
|
495,560,000
|
Number of warrants outstanding |
|
5,300,000
|
|
5,300,000
|
|
Shares issuable upon exercise of series A and B warrants |
|
5,300,000
|
|
5,300,000
|
|
Performance share units |
|
|
|
|
|
Class of Warrant or Right [Line Items] |
|
|
|
|
|
Weighted average common shares outstanding - basic |
|
987,987
|
|
767,228
|
|
Series A Warrants |
|
|
|
|
|
Class of Warrant or Right [Line Items] |
|
|
|
|
|
Number of warrants outstanding |
|
2,600,000
|
|
2,600,000
|
|
Exercise price of warrants | $ / shares |
|
$ 32.59
|
|
$ 32.59
|
|
Number of warrants exercised | warrants |
|
8,390
|
|
8,390
|
|
Series B Warrants |
|
|
|
|
|
Class of Warrant or Right [Line Items] |
|
|
|
|
|
Number of warrants outstanding |
|
2,700,000
|
|
2,700,000
|
|
Exercise price of warrants | $ / shares |
|
$ 35.41
|
|
$ 35.41
|
|
Number of warrants exercised | warrants |
|
203,501
|
|
203,501
|
|
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v3.21.2
Basis of Presentation (Details Textuals 2)
|
|
3 Months Ended |
9 Months Ended |
Sep. 30, 2020
USD ($)
|
Sep. 30, 2021
USD ($)
|
Jun. 30, 2021
USD ($)
|
Mar. 31, 2021
USD ($)
$ / Barrel
|
Sep. 18, 2020
USD ($)
|
Jun. 30, 2020
USD ($)
|
Mar. 31, 2020
USD ($)
|
Sep. 30, 2021
USD ($)
|
Sep. 18, 2020
USD ($)
|
Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items] |
|
|
|
|
|
|
|
|
|
Impairment of unevaluated costs |
|
|
|
|
|
|
$ 244,900,000
|
|
|
Write-down of oil and natural gas properties |
$ 0
|
$ 0
|
$ 0
|
$ 14,400,000
|
$ 261,677,000
|
$ 662,400,000
|
$ 72,500,000
|
$ 14,377,000
|
$ 996,658,000
|
Oil |
|
|
|
|
|
|
|
|
|
Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items] |
|
|
|
|
|
|
|
|
|
Average price | $ / Barrel |
|
|
|
36.40
|
|
|
|
|
|
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v3.21.2
Acquisition and Divestitures (Details Textuals)
|
|
|
|
3 Months Ended |
7 Months Ended |
9 Months Ended |
Jun. 30, 2021
USD ($)
|
Mar. 03, 2021
USD ($)
|
Sep. 30, 2020
USD ($)
|
Sep. 30, 2021
USD ($)
|
Sep. 30, 2021
USD ($)
|
Sep. 30, 2021
USD ($)
$ / Barrel
|
Sep. 18, 2020
USD ($)
|
Business Acquisition, Contingent Consideration [Line Items] |
|
|
|
|
|
|
|
Approximate working interest percentage acquired |
|
100.00%
|
|
|
|
|
|
Approximate net revenue interest percentage acquired |
|
83.00%
|
|
|
|
|
|
Acquisitions of oil and natural gas properties |
|
$ 10,900,000
|
$ 1,000
|
|
|
$ 10,927,000
|
$ 0
|
Contingent consideration |
|
|
|
$ 7,400,000
|
$ 7,400,000
|
7,400,000
|
|
Contingent consideration at acquisition date |
|
$ 5,300,000
|
|
|
|
|
|
Increase in contingent consideration |
|
|
|
|
2,100,000
|
|
|
Cash proceeds on sale of Hartzog Draw deep mineral rights |
$ 18,000,000
|
|
880,000
|
|
|
19,053,000
|
41,322,000
|
Gain (loss) on disposition of oil and gas properties |
$ 0
|
|
|
|
|
|
|
Gross proceeds from land sales |
|
|
|
11,800,000
|
|
|
|
Gain from asset sales and other |
|
|
$ 0
|
7,000,000
|
|
7,026,000
|
$ 6,723,000
|
2021 | Devon Energy Corporation's Wind River Basin properties |
|
|
|
|
|
|
|
Business Acquisition, Contingent Consideration [Line Items] |
|
|
|
|
|
|
|
Contingent cash payment |
|
|
|
4,000,000
|
4,000,000
|
$ 4,000,000
|
|
2021 | Minimum | Devon Energy Corporation's Wind River Basin properties |
|
|
|
|
|
|
|
Business Acquisition, Contingent Consideration [Line Items] |
|
|
|
|
|
|
|
Average price | $ / Barrel |
|
|
|
|
|
50
|
|
2022 | Devon Energy Corporation's Wind River Basin properties |
|
|
|
|
|
|
|
Business Acquisition, Contingent Consideration [Line Items] |
|
|
|
|
|
|
|
Contingent cash payment |
|
|
|
$ 4,000,000
|
$ 4,000,000
|
$ 4,000,000
|
|
2022 | Minimum | Devon Energy Corporation's Wind River Basin properties |
|
|
|
|
|
|
|
Business Acquisition, Contingent Consideration [Line Items] |
|
|
|
|
|
|
|
Average price | $ / Barrel |
|
|
|
|
|
50
|
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v3.21.2
Revenue Recognition (Disaggregation of Revenue) (Details) - USD ($) $ in Thousands |
|
3 Months Ended |
9 Months Ended |
Sep. 30, 2020 |
Sep. 30, 2021 |
Sep. 18, 2020 |
Sep. 30, 2021 |
Sep. 18, 2020 |
Disaggregation of Revenue [Line Items] |
|
|
|
|
|
Revenues |
$ 23,439
|
$ 333,284
|
$ 162,939
|
$ 884,744
|
$ 521,693
|
Oil sales |
|
|
|
|
|
Disaggregation of Revenue [Line Items] |
|
|
|
|
|
Revenues |
22,311
|
305,093
|
152,136
|
818,714
|
489,251
|
Natural gas sales |
|
|
|
|
|
Disaggregation of Revenue [Line Items] |
|
|
|
|
|
Revenues |
10
|
3,361
|
954
|
7,893
|
2,850
|
CO2 sales and transportation fees |
|
|
|
|
|
Disaggregation of Revenue [Line Items] |
|
|
|
|
|
Revenues |
967
|
12,237
|
6,517
|
31,599
|
21,049
|
Oil marketing revenues |
|
|
|
|
|
Disaggregation of Revenue [Line Items] |
|
|
|
|
|
Revenues |
$ 151
|
$ 12,593
|
$ 3,332
|
$ 26,538
|
$ 8,543
|
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v3.21.2
Long-Term Debt (Components of Long-Term Debt) (Details) - USD ($) $ in Thousands |
Sep. 30, 2021 |
Dec. 31, 2020 |
Debt and Lease Obligation [Abstract] |
|
|
Senior Secured Bank Credit Agreement |
$ 0
|
$ 70,000
|
Pipeline financings |
17,332
|
68,008
|
Total debt principal balance |
17,332
|
138,008
|
Less: current maturities of long-term debt |
(17,332)
|
(68,008)
|
Long-term debt |
$ 0
|
$ 70,000
|
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Long-Term Debt (Details Textuals) - USD ($)
|
|
9 Months Ended |
Oct. 29, 2021 |
Sep. 30, 2021 |
Senior Secured Bank Credit Facility [Abstract] |
|
|
Borrowing base |
|
$ 575,000,000
|
Lender commitments |
|
$ 575,000,000
|
Commitment fee percentage |
|
0.50%
|
NEJD Pipeline |
|
|
Senior Secured Bank Credit Facility [Abstract] |
|
|
Payments to reacquire pipeline |
|
$ 52,500,000
|
NEJD Pipeline | Subsequent Event |
|
|
Senior Secured Bank Credit Facility [Abstract] |
|
|
Payments to reacquire pipeline |
$ 17,500,000
|
|
Minimum |
|
|
Senior Secured Bank Credit Facility [Abstract] |
|
|
Current ratio requirement |
|
1.0
|
Minimum | Dividend or Other Restricted Payment |
|
|
Senior Secured Bank Credit Facility [Abstract] |
|
|
Borrowing base availability requirement |
|
20.00%
|
Maximum |
|
|
Senior Secured Bank Credit Facility [Abstract] |
|
|
Consolidated total debt to consolidated EBITDAX requirement |
|
3.5
|
Maximum | Dividend or Other Restricted Payment |
|
|
Senior Secured Bank Credit Facility [Abstract] |
|
|
Consolidated total debt to consolidated EBITDAX requirement |
|
2
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v3.21.2
v3.21.2
Commodity Derivative Contracts (Commodity Derivatives Outstanding Table) (Details) - NYMEX
|
Sep. 30, 2021
bbl / d
$ / Barrel
|
Swap | Q4 2021 |
|
Derivative [Line Items] |
|
Volume per day | bbl / d |
29,000
|
Weighted average swap price |
43.86
|
Swap | Q4 2021 | Minimum |
|
Derivative [Line Items] |
|
Derivative, Swap Type, Fixed Price |
38.68
|
Swap | Q4 2021 | Maximum |
|
Derivative [Line Items] |
|
Derivative, Swap Type, Fixed Price |
56.00
|
Swap | Q1 - Q2 2022 |
|
Derivative [Line Items] |
|
Volume per day | bbl / d |
15,500
|
Weighted average swap price |
49.01
|
Swap | Q1 - Q2 2022 | Minimum |
|
Derivative [Line Items] |
|
Derivative, Swap Type, Fixed Price |
42.65
|
Swap | Q1 - Q2 2022 | Maximum |
|
Derivative [Line Items] |
|
Derivative, Swap Type, Fixed Price |
58.15
|
Swap | Q3 - Q4 2022 |
|
Derivative [Line Items] |
|
Volume per day | bbl / d |
9,000
|
Weighted average swap price |
56.35
|
Swap | Q3 - Q4 2022 | Minimum |
|
Derivative [Line Items] |
|
Derivative, Swap Type, Fixed Price |
50.13
|
Swap | Q3 - Q4 2022 | Maximum |
|
Derivative [Line Items] |
|
Derivative, Swap Type, Fixed Price |
60.35
|
Collars | Q4 2021 |
|
Derivative [Line Items] |
|
Volume per day | bbl / d |
4,000
|
Derivative, Floor Price |
45.00
|
Derivative, Cap Price |
59.30
|
Weighted average floor price |
46.25
|
Weighted average ceiling price |
53.04
|
Collars | Q1 - Q2 2022 |
|
Derivative [Line Items] |
|
Volume per day | bbl / d |
11,000
|
Derivative, Floor Price |
47.50
|
Derivative, Cap Price |
70.75
|
Weighted average floor price |
49.77
|
Weighted average ceiling price |
64.31
|
Collars | Q3 - Q4 2022 |
|
Derivative [Line Items] |
|
Volume per day | bbl / d |
10,000
|
Derivative, Floor Price |
47.50
|
Derivative, Cap Price |
70.75
|
Weighted average floor price |
49.75
|
Weighted average ceiling price |
64.18
|
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v3.21.2
Fair Value Measurements (Fair Value Hierarchy Table) (Details) - USD ($) $ in Thousands |
Sep. 30, 2021 |
Dec. 31, 2020 |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] |
|
|
Oil derivative contracts - current assets |
$ 0
|
$ 187
|
Total Assets |
|
187
|
Oil derivative contracts - current liabilities |
(193,015)
|
(53,865)
|
Oil derivative contracts - long-term liabilities |
(16,435)
|
(5,087)
|
Total Liabilities |
(209,450)
|
(58,952)
|
Quoted Prices in Active Markets (Level 1) |
|
|
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] |
|
|
Oil derivative contracts - current assets |
|
0
|
Total Assets |
|
0
|
Oil derivative contracts - current liabilities |
0
|
0
|
Oil derivative contracts - long-term liabilities |
0
|
0
|
Total Liabilities |
0
|
0
|
Significant Other Observable Inputs (Level 2) |
|
|
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] |
|
|
Oil derivative contracts - current assets |
|
187
|
Total Assets |
|
187
|
Oil derivative contracts - current liabilities |
(193,015)
|
(53,865)
|
Oil derivative contracts - long-term liabilities |
(16,435)
|
(5,087)
|
Total Liabilities |
(209,450)
|
(58,952)
|
Significant Unobservable Inputs (Level 3) |
|
|
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] |
|
|
Oil derivative contracts - current assets |
|
0
|
Total Assets |
|
0
|
Oil derivative contracts - current liabilities |
0
|
0
|
Oil derivative contracts - long-term liabilities |
0
|
0
|
Total Liabilities |
$ 0
|
$ 0
|
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v3.21.2
Additional Balance Sheet Details (Accounts Payable and Accrued Liabilities) (Details) - USD ($) $ in Thousands |
Sep. 30, 2021 |
Dec. 31, 2020 |
Accounts Payable and Accrued Liabilities, Current [Abstract] |
|
|
Accounts payable |
$ 38,578
|
$ 18,629
|
Accrued compensation |
33,961
|
7,512
|
Accrued derivative settlements |
26,311
|
3,908
|
Accrued lease operating expenses |
25,724
|
21,294
|
Accrued exploration and development costs |
20,728
|
1,861
|
Taxes payable |
14,468
|
17,221
|
Accrued general and administrative expenses |
2,595
|
21,825
|
Other |
49,529
|
20,421
|
Total |
$ 211,894
|
$ 112,671
|
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This regulatory filing also includes additional resources:
den-20210930.pdf
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