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 June 30, 20222023
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 July 31, 2022,2023, was 49,722,204.50,902,023.
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)
| | | | | | | | | | | | | | |
| | |
| | June 30, 2022 | | December 31, 2021 |
Assets | | | | |
Current assets | | | | |
Cash and cash equivalents | | $ | 517 | | | $ | 3,671 | |
Accrued production receivable | | 229,151 | | | 143,365 | |
Trade and other receivables, net | | 30,918 | | | 19,270 | |
Derivative assets | | 2,829 | | | — | |
Prepaids | | 18,686 | | | 9,099 | |
Total current assets | | 282,101 | | | 175,405 | |
Property and equipment | | | | |
Oil and natural gas properties (using full cost accounting) | | | | |
Proved properties | | 1,217,778 | | | 1,109,011 | |
Unevaluated properties | | 155,901 | | | 112,169 | |
CO2 properties | | 184,861 | | | 183,369 | |
Pipelines | | 226,318 | | | 224,394 | |
CCUS storage sites and related assets | | 24,026 | | | — | |
Other property and equipment | | 98,777 | | | 93,950 | |
Less accumulated depletion, depreciation, amortization and impairment | | (240,133) | | | (181,393) | |
Net property and equipment | | 1,667,528 | | | 1,541,500 | |
Operating lease right-of-use assets | | 18,118 | | | 19,502 | |
Derivative assets | | 2,071 | | | — | |
| | | | |
Intangible assets, net | | 83,688 | | | 88,248 | |
Restricted cash for future asset retirement obligations | | 46,869 | | | 46,673 | |
Other assets | | 38,305 | | | 31,625 | |
Total assets | | $ | 2,138,680 | | | $ | 1,902,953 | |
Liabilities and Stockholders’ Equity | | | | |
Current liabilities | | | | |
Accounts payable and accrued liabilities | | $ | 262,752 | | | $ | 191,598 | |
Oil and gas production payable | | 109,228 | | | 75,899 | |
Derivative liabilities | | 162,551 | | | 134,509 | |
| | | | |
Operating lease liabilities | | 4,670 | | | 4,677 | |
Total current liabilities | | 539,201 | | | 406,683 | |
Long-term liabilities | | | | |
Long-term debt, net of current portion | | — | | | 35,000 | |
Asset retirement obligations | | 273,852 | | | 284,238 | |
Derivative liabilities | | 5,415 | | | — | |
Deferred tax liabilities, net | | 17,630 | | | 1,638 | |
Operating lease liabilities | | 15,571 | | | 17,094 | |
Other liabilities | | 18,170 | | | 22,910 | |
Total long-term liabilities | | 330,638 | | | 360,880 | |
Commitments and contingencies (Note 9) | | 0 | | 0 |
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; 50,875,988 and 50,193,656 shares issued, respectively | | 51 | | | 50 | |
Paid-in capital in excess of par | | 1,137,575 | | | 1,129,996 | |
Retained earnings | | 159,966 | | | 5,344 | |
Treasury stock, at cost, 457,549 and 0 shares, respectively | | (28,751) | | | — | |
Total stockholders’ equity | | 1,268,841 | | | 1,135,390 | |
Total liabilities and stockholders’ equity | | $ | 2,138,680 | | | $ | 1,902,953 | |
| | | | | | | | | | | | | | |
| | |
| | June 30, 2023 | | December 31, 2022 |
Assets | | | | |
Current assets | | | | |
Cash and cash equivalents | | $ | 531 | | | $ | 521 | |
Accrued production receivable | | 131,422 | | | 144,277 | |
Trade and other receivables, net | | 21,800 | | | 27,343 | |
Derivative assets | | 36,809 | | | 15,517 | |
Prepaids | | 20,117 | | | 18,572 | |
Total current assets | | 210,679 | | | 206,230 | |
Property and equipment | | | | |
Oil and natural gas properties (using full cost accounting) | | | | |
Proved properties | | 1,751,158 | | | 1,414,779 | |
Unevaluated properties | | 114,320 | | | 240,435 | |
CO2 properties | | 193,432 | | | 190,985 | |
Pipelines | | 219,748 | | | 220,125 | |
CCUS storage sites and related assets | | 114,190 | | | 64,971 | |
Other property and equipment | | 115,086 | | | 107,133 | |
Less accumulated depletion, depreciation, amortization and impairment | | (382,591) | | | (306,743) | |
Net property and equipment | | 2,125,343 | | | 1,931,685 | |
Operating lease right-of-use assets | | 19,425 | | | 18,017 | |
Derivative assets | | 1,269 | | | — | |
| | | | |
Intangible assets, net | | 74,571 | | | 79,128 | |
Restricted cash for future asset retirement obligations | | 48,405 | | | 47,359 | |
Other assets | | 61,927 | | | 45,080 | |
Total assets | | $ | 2,541,619 | | | $ | 2,327,499 | |
Liabilities and Stockholders’ Equity | | | | |
Current liabilities | | | | |
Accounts payable and accrued liabilities | | $ | 221,173 | | | $ | 248,800 | |
Oil and gas production payable | | 70,455 | | | 80,368 | |
Derivative liabilities | | — | | | 13,018 | |
| | | | |
Operating lease liabilities | | 5,098 | | | 4,676 | |
Total current liabilities | | 296,726 | | | 346,862 | |
Long-term liabilities | | | | |
Long-term debt, net of current portion | | 85,153 | | | 29,000 | |
Asset retirement obligations | | 312,372 | | | 315,942 | |
| | | | |
Deferred tax liabilities, net | | 118,171 | | | 71,120 | |
Operating lease liabilities | | 16,075 | | | 15,431 | |
Other liabilities | | 12,969 | | | 16,527 | |
Total long-term liabilities | | 544,740 | | | 448,020 | |
Commitments and contingencies (Note 9) | | | | |
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; 50,473,001 and 49,814,874 shares issued, respectively | | 50 | | | 50 | |
Paid-in capital in excess of par | | 1,058,119 | | | 1,047,063 | |
Retained earnings | | 641,984 | | | 485,504 | |
| | | | |
Total stockholders’ equity | | 1,700,153 | | | 1,532,617 | |
Total liabilities and stockholders’ equity | | $ | 2,541,619 | | | $ | 2,327,499 | |
See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.
Denbury Inc.
Unaudited Condensed Consolidated Statements of Operations
(In thousands, except per-share data)
| | | Three Months Ended June 30, | | Six Months Ended June 30, | | Three Months Ended June 30, | | Six Months Ended June 30, |
| | 2022 | | 2021 | | 2022 | | 2021 | | 2023 | | 2022 | | 2023 | | 2022 |
Revenues and other income | Revenues and other income | | | | | | | | | Revenues and other income | | | | | | | | |
Oil, natural gas, and related product sales | Oil, natural gas, and related product sales | | $ | 451,970 | | | $ | 282,708 | | | $ | 836,881 | | | $ | 518,153 | | Oil, natural gas, and related product sales | | $ | 302,946 | | | $ | 451,970 | | | $ | 617,435 | | | $ | 836,881 | |
CO2 sales and transportation fees | CO2 sales and transportation fees | | 12,610 | | | 10,134 | | | 26,032 | | | 19,362 | | CO2 sales and transportation fees | | 11,164 | | | 12,610 | | | 21,850 | | | 26,032 | |
Oil marketing revenues | Oil marketing revenues | | 16,786 | | | 7,819 | | | 30,062 | | | 13,945 | | Oil marketing revenues | | 13,983 | | | 16,786 | | | 28,531 | | | 30,062 | |
Other income | Other income | | 790 | | | 707 | | | 1,040 | | | 1,067 | | Other income | | 890 | | | 790 | | | 2,185 | | | 1,040 | |
Total revenues and other income | Total revenues and other income | | 482,156 | | | 301,368 | | | 894,015 | | | 552,527 | | Total revenues and other income | | 328,983 | | | 482,156 | | | 670,001 | | | 894,015 | |
Expenses | Expenses | | | | | | | | | Expenses | | | | | | | | |
Lease operating expenses | Lease operating expenses | | 124,351 | | | 110,225 | | | 242,179 | | | 192,195 | | Lease operating expenses | | 130,291 | | | 124,351 | | | 259,465 | | | 242,179 | |
Transportation and marketing expenses | Transportation and marketing expenses | | 4,802 | | | 8,522 | | | 9,447 | | | 16,319 | | Transportation and marketing expenses | | 5,159 | | | 4,802 | | | 10,548 | | | 9,447 | |
CO2 operating and discovery expenses | CO2 operating and discovery expenses | | 1,681 | | | 1,531 | | | 4,498 | | | 2,524 | | CO2 operating and discovery expenses | | 1,597 | | | 1,681 | | | 2,793 | | | 4,498 | |
Taxes other than income | Taxes other than income | | 36,317 | | | 22,382 | | | 67,698 | | | 41,345 | | Taxes other than income | | 26,937 | | | 36,317 | | | 55,975 | | | 67,698 | |
Oil marketing purchases | Oil marketing purchases | | 15,027 | | | 7,738 | | | 28,067 | | | 13,823 | | Oil marketing purchases | | 13,922 | | | 15,027 | | | 28,390 | | | 28,067 | |
General and administrative expenses | General and administrative expenses | | 19,235 | | | 15,450 | | | 37,927 | | | 47,433 | | General and administrative expenses | | 26,895 | | | 19,235 | | | 49,872 | | | 37,927 | |
Interest, net of amounts capitalized of $975, $1,168, $2,133 and $2,251, respectively | | 1,526 | | | 1,252 | | | 2,183 | | | 2,788 | | |
Interest, net of amounts capitalized of $2,259, $975, $3,952 and $2,133, respectively | | Interest, net of amounts capitalized of $2,259, $975, $3,952 and $2,133, respectively | | 825 | | | 1,526 | | | 1,752 | | | 2,183 | |
Depletion, depreciation, and amortization | Depletion, depreciation, and amortization | | 35,400 | | | 36,381 | | | 70,745 | | | 75,831 | | Depletion, depreciation, and amortization | | 49,767 | | | 35,400 | | | 91,799 | | | 70,745 | |
Commodity derivatives expense | | 56,854 | | | 172,664 | | | 249,573 | | | 288,407 | | |
Commodity derivatives expense (income) | | Commodity derivatives expense (income) | | (19,677) | | | 56,854 | | | (42,800) | | | 249,573 | |
| Write-down of oil and natural gas properties | | — | | | — | | | — | | | 14,377 | | |
| Other expenses | Other expenses | | 6,621 | | | 3,214 | | | 8,733 | | | 5,360 | | Other expenses | | 3,990 | | | 6,621 | | | 5,481 | | | 8,733 | |
Total expenses | Total expenses | | 301,814 | | | 379,359 | | | 721,050 | | | 700,402 | | Total expenses | | 239,706 | | | 301,814 | | | 463,275 | | | 721,050 | |
Income (loss) before income taxes | | 180,342 | | | (77,991) | | | 172,965 | | | (147,875) | | |
Income tax provision (benefit) | | 24,848 | | | (296) | | | 18,343 | | | (538) | | |
Net income (loss) | | $ | 155,494 | | | $ | (77,695) | | | $ | 154,622 | | | $ | (147,337) | | |
Income before income taxes | | Income before income taxes | | 89,277 | | | 180,342 | | | 206,726 | | | 172,965 | |
Income tax provision | | Income tax provision | | 21,996 | | | 24,848 | | | 50,246 | | | 18,343 | |
Net income | | Net income | | $ | 67,281 | | | $ | 155,494 | | | $ | 156,480 | | | $ | 154,622 | |
| Net income (loss) per common share | | |
Net income per common share | | Net income per common share | |
Basic | Basic | | $ | 3.00 | | | $ | (1.52) | | | $ | 2.99 | | | $ | (2.91) | | Basic | | $ | 1.30 | | | $ | 3.00 | | | $ | 3.03 | | | $ | 2.99 | |
Diluted | Diluted | | $ | 2.83 | | | $ | (1.52) | | | $ | 2.81 | | | $ | (2.91) | | Diluted | | $ | 1.25 | | | $ | 2.83 | | | $ | 2.90 | | | $ | 2.81 | |
| Weighted average common shares outstanding | Weighted average common shares outstanding | | | | Weighted average common shares outstanding | | | |
Basic | Basic | | 51,757 | | | 50,999 | | | 51,680 | | | 50,661 | | Basic | | 51,817 | | | 51,757 | | | 51,661 | | | 51,680 | |
Diluted | Diluted | | 54,886 | | | 50,999 | | | 54,931 | | | 50,661 | | Diluted | | 53,999 | | | 54,886 | | | 53,882 | | | 54,931 | |
See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.
Denbury Inc.
Unaudited Condensed Consolidated Statements of Cash Flows
(In thousands)
| | | Six Months Ended June 30, | | Six Months Ended June 30, |
| | | 2022 | | 2021 | | | 2023 | | 2022 |
Cash flows from operating activities | Cash flows from operating activities | | | | | Cash flows from operating activities | | | | |
Net income (loss) | | $ | 154,622 | | | $ | (147,337) | | |
Adjustments to reconcile net income (loss) to cash flows from operating activities | | | |
Net income | | Net income | | $ | 156,480 | | | $ | 154,622 | |
Adjustments to reconcile net income to cash flows from operating activities | | Adjustments to reconcile net income to cash flows from operating activities | | |
Depletion, depreciation, and amortization | Depletion, depreciation, and amortization | | 70,745 | | | 75,831 | | Depletion, depreciation, and amortization | | 91,799 | | | 70,745 | |
Write-down of oil and natural gas properties | | — | | | 14,377 | | |
| Deferred income taxes | Deferred income taxes | | 15,992 | | | (87) | | Deferred income taxes | | 47,051 | | | 15,992 | |
Stock-based compensation | Stock-based compensation | | 7,075 | | | 20,232 | | Stock-based compensation | | 11,486 | | | 7,075 | |
Commodity derivatives expense | | 249,573 | | | 288,407 | | |
Payment on settlements of commodity derivatives | | (221,016) | | | (101,796) | | |
Debt issuance costs | | 1,934 | | | 1,370 | | |
Commodity derivatives expense (income) | | Commodity derivatives expense (income) | | (42,800) | | | 249,573 | |
Receipt (payment) on settlements of commodity derivatives | | Receipt (payment) on settlements of commodity derivatives | | 7,222 | | | (221,016) | |
Debt issuance cost amortization | | Debt issuance cost amortization | | 1,063 | | | 1,934 | |
| Other, net | Other, net | | (3,155) | | | 744 | | Other, net | | (4,176) | | | (3,155) | |
Changes in assets and liabilities, net of effects from acquisitions | Changes in assets and liabilities, net of effects from acquisitions | | | Changes in assets and liabilities, net of effects from acquisitions | | |
Accrued production receivable | Accrued production receivable | | (85,786) | | | (48,881) | | Accrued production receivable | | 12,855 | | | (85,786) | |
Trade and other receivables | Trade and other receivables | | (11,783) | | | (5,578) | | Trade and other receivables | | 5,545 | | | (11,783) | |
Other current and long-term assets | Other current and long-term assets | | (12,175) | | | 1,294 | | Other current and long-term assets | | (315) | | | (12,175) | |
Accounts payable and accrued liabilities | Accounts payable and accrued liabilities | | 52,010 | | | 27,292 | | Accounts payable and accrued liabilities | | (25,623) | | | 52,010 | |
Oil and natural gas production payable | Oil and natural gas production payable | | 33,329 | | | 20,224 | | Oil and natural gas production payable | | (9,914) | | | 33,329 | |
Asset retirement obligations and other liabilities | Asset retirement obligations and other liabilities | | (11,257) | | | (2,554) | | Asset retirement obligations and other liabilities | | (19,660) | | | (11,257) | |
| Net cash provided by operating activities | Net cash provided by operating activities | | 240,108 | | | 143,538 | | Net cash provided by operating activities | | 231,013 | | | 240,108 | |
| Cash flows from investing activities | Cash flows from investing activities | | | Cash flows from investing activities | | |
Oil and natural gas capital expenditures | Oil and natural gas capital expenditures | | (139,522) | | | (53,411) | | Oil and natural gas capital expenditures | | (210,418) | | | (139,522) | |
CCUS storage sites and related capital expenditures | CCUS storage sites and related capital expenditures | | (17,758) | | | — | | CCUS storage sites and related capital expenditures | | (49,289) | | | (17,758) | |
Acquisitions of oil and natural gas properties | Acquisitions of oil and natural gas properties | | (374) | | | (10,811) | | Acquisitions of oil and natural gas properties | | (42) | | | (374) | |
Pipelines and plants capital expenditures | Pipelines and plants capital expenditures | | (20,264) | | | (4,851) | | Pipelines and plants capital expenditures | | (1,291) | | | (20,264) | |
Net proceeds from sales of oil and natural gas properties and equipment | Net proceeds from sales of oil and natural gas properties and equipment | | 237 | | | 18,456 | | Net proceeds from sales of oil and natural gas properties and equipment | | — | | | 237 | |
Equity investments | | Equity investments | | (19,034) | | | — | |
Other | Other | | (5,623) | | | (4,159) | | Other | | (13,631) | | | (5,623) | |
Net cash used in investing activities | Net cash used in investing activities | | (183,304) | | | (54,776) | | Net cash used in investing activities | | (293,705) | | | (183,304) | |
| Cash flows from financing activities | Cash flows from financing activities | | | Cash flows from financing activities | | |
Bank repayments | Bank repayments | | (524,000) | | | (485,000) | | Bank repayments | | (865,000) | | | (524,000) | |
Bank borrowings | Bank borrowings | | 489,000 | | | 450,000 | | Bank borrowings | | 921,000 | | | 489,000 | |
| Pipeline financing repayments | | — | | | (33,510) | | |
| Common stock repurchase program | Common stock repurchase program | | (23,374) | | | — | | Common stock repurchase program | | — | | | (23,374) | |
| Other | Other | | (1,388) | | | (2,735) | | Other | | 7,748 | | | (1,388) | |
Net cash used in financing activities | | (59,762) | | | (71,245) | | |
Net cash provided by (used in) financing activities | | Net cash provided by (used in) financing activities | | 63,748 | | | (59,762) | |
Net increase (decrease) in cash, cash equivalents, and restricted cash | Net increase (decrease) in cash, cash equivalents, and restricted cash | | (2,958) | | | 17,517 | | Net increase (decrease) in cash, cash equivalents, and restricted cash | | 1,056 | | | (2,958) | |
Cash, cash equivalents, and restricted cash at beginning of period | Cash, cash equivalents, and restricted cash at beginning of period | | 50,344 | | | 42,248 | | Cash, cash equivalents, and restricted cash at beginning of period | | 47,880 | | | 50,344 | |
Cash, cash equivalents, and restricted cash at end of period | Cash, cash equivalents, and restricted cash at end of period | | $ | 47,386 | | | $ | 59,765 | | Cash, cash equivalents, and restricted cash at end of period | | $ | 48,936 | | | $ | 47,386 | |
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 ($.001 Par Value) | | Paid-In Capital in Excess of Par | | Retained Earnings | | Treasury Stock (at cost) | | | | Common Stock ($.001 Par Value) | | Paid-In Capital in Excess of Par | | Retained Earnings | | Treasury Stock (at cost) | |
| | Shares | | Amount | Shares | | Amount | Total Equity | | Shares | | Amount | Shares | | Amount | | Total Equity |
Balance – December 31, 2021 | 50,193,656 | | | $ | 50 | | | $ | 1,129,996 | | | $ | 5,344 | | | — | | | $ | — | | | $ | 1,135,390 | | |
Balance – December 31, 2022 | | Balance – December 31, 2022 | 49,814,874 | | | $ | 50 | | | $ | 1,047,063 | | | $ | 485,504 | | | — | | | $ | — | | | $ | 1,532,617 | |
Issued pursuant to stock compensation plans | Issued pursuant to stock compensation plans | 141,581 | | | 0 | | | — | | | — | | | — | | | — | | | 0 | | Issued pursuant to stock compensation plans | 268,748 | | | — | | | — | | | — | | | — | | | — | | | — | |
Stock-based compensation | Stock-based compensation | — | | | — | | | 3,142 | | | — | | | — | | | — | | | 3,142 | | Stock-based compensation | — | | | — | | | 5,320 | | | — | | | — | | | — | | | 5,320 | |
| Tax withholding for stock compensation plans | Tax withholding for stock compensation plans | — | | | — | | | (58) | | | — | | | — | | | — | | | (58) | | Tax withholding for stock compensation plans | (16,281) | | | — | | | (2,683) | | | — | | | — | | | — | | | (2,683) | |
Issued pursuant to exercise of warrants | Issued pursuant to exercise of warrants | 14,153 | | | 0 | | | 47 | | | — | | | — | | | — | | | 47 | | Issued pursuant to exercise of warrants | 209,185 | | | — | | | 130 | | | — | | | — | | | — | | | 130 | |
Net loss | — | | | — | | | — | | | (872) | | | — | | | — | | | (872) | | |
Balance – March 31, 2022 | 50,349,390 | | | 50 | | | 1,133,127 | | | 4,472 | | | — | | | — | | | 1,137,649 | | |
Net income | | Net income | — | | | — | | | — | | | 89,199 | | | — | | | — | | | 89,199 | |
Balance – March 31, 2023 | | Balance – March 31, 2023 | 50,276,526 | | | $ | 50 | | | $ | 1,049,830 | | | $ | 574,703 | | | — | | | $ | — | | | $ | 1,624,583 | |
| Stock repurchase program | (457,549) | | | — | | | — | | | — | | | 457,549 | | | (28,751) | | | (28,751) | | |
| Forfeited pursuant to stock compensation plans | Forfeited pursuant to stock compensation plans | (3,264) | | | — | | | — | | | — | | | — | | | — | | | — | | Forfeited pursuant to stock compensation plans | (1,013) | | | — | | | — | | | — | | | — | | | — | | | — | |
Stock-based compensation | Stock-based compensation | — | | | — | | | 4,400 | | | — | | | — | | | — | | | 4,400 | | Stock-based compensation | — | | | — | | | 7,246 | | | — | | | — | | | — | | | 7,246 | |
Tax withholding for stock compensation plans | — | | | — | | | (5) | | | — | | | — | | | — | | | (5) | | |
| Employee stock purchase plan | | Employee stock purchase plan | 11,115 | | | — | | | 815 | | | — | | | — | | | — | | | 815 | |
Issued pursuant to exercise of warrants | Issued pursuant to exercise of warrants | 987,411 | | | 1 | | | 53 | | | — | | | — | | | — | | | 54 | | Issued pursuant to exercise of warrants | 186,373 | | | — | | | 228 | | | — | | | — | | | — | | | 228 | |
Net income | Net income | — | | | — | | | — | | | 155,494 | | | — | | | — | | | 155,494 | | Net income | — | | | — | | | — | | | 67,281 | | | — | | | — | | | 67,281 | |
Balance – June 30, 2022 | 50,875,988 | | | $ | 51 | | | $ | 1,137,575 | | | $ | 159,966 | | | 457,549 | | | $ | (28,751) | | | $ | 1,268,841 | | |
Balance – June 30, 2023 | | Balance – June 30, 2023 | 50,473,001 | | | $ | 50 | | | $ | 1,058,119 | | | $ | 641,984 | | | — | | | $ | — | | | $ | 1,700,153 | |
| |
| | | Common Stock ($.001 Par Value) | | Paid-In Capital in Excess of Par | | Retained Earnings (Accumulated Deficit) | | Treasury Stock (at cost) | | | | Common Stock ($.001 Par Value) | | Paid-In Capital in Excess of Par | | Retained Earnings (Accumulated Deficit) | | Treasury Stock (at cost) | |
| | Shares | | Amount | Shares | | Amount | Total Equity | | Shares | | Amount | Shares | | Amount | | Total Equity |
Balance – December 31, 2020 | 49,999,999 | | | $ | 50 | | | $ | 1,104,276 | | | $ | (50,658) | | | — | | | $ | — | | | $ | 1,053,668 | | |
Balance – December 31, 2021 | | Balance – December 31, 2021 | 50,193,656 | | | $ | 50 | | | $ | 1,129,996 | | | $ | 5,344 | | | — | | | $ | — | | | $ | 1,135,390 | |
Issued pursuant to stock compensation plans | | Issued pursuant to stock compensation plans | 141,581 | | | — | | | — | | | — | | | — | | | — | | | — | |
Stock-based compensation | Stock-based compensation | — | | | — | | | 19,172 | | | — | | | — | | | — | | | 19,172 | | Stock-based compensation | — | | | — | | | 3,142 | | | — | | | — | | | — | | | 3,142 | |
Tax withholding for stock compensation plans | Tax withholding for stock compensation plans | — | | | — | | | (1,467) | | | — | | | — | | | — | | | (1,467) | | Tax withholding for stock compensation plans | — | | | — | | | (58) | | | — | | | — | | | — | | | (58) | |
Issued pursuant to exercise of warrants | Issued pursuant to exercise of warrants | 5,620 | | | 0 | | | 195 | | | — | | | — | | | — | | | 195 | | Issued pursuant to exercise of warrants | 14,153 | | | — | | | 47 | | | — | | | — | | | — | | | 47 | |
Net loss | Net loss | — | | | — | | | — | | | (69,642) | | | — | | | — | | | (69,642) | | Net loss | — | | | — | | | — | | | (872) | | | — | | | — | | | (872) | |
Balance – March 31, 2021 | 50,005,619 | | | 50 | | | 1,122,176 | | | (120,300) | | | — | | | — | | | 1,001,926 | | |
Balance – March 31, 2022 | | Balance – March 31, 2022 | 50,349,390 | | | $ | 50 | | | $ | 1,133,127 | | | $ | 4,472 | | | — | | | $ | — | | | $ | 1,137,649 | |
Stock repurchase program | | Stock repurchase program | (457,549) | | | — | | | — | | | — | | | 457,549 | | | (28,751) | | | (28,751) | |
Forfeited pursuant to stock compensation plans | | Forfeited pursuant to stock compensation plans | (3,264) | | | — | | | — | | | — | | | — | | | — | | | — | |
Stock-based compensation | Stock-based compensation | — | | | — | | | 2,682 | | | — | | | — | | | — | | | 2,682 | | Stock-based compensation | — | | | — | | | 4,400 | | | — | | | — | | | — | | | 4,400 | |
Tax withholding for stock compensation plans | Tax withholding for stock compensation plans | — | | | — | | | (7) | | | — | | | — | | | — | | | (7) | | Tax withholding for stock compensation plans | — | | | — | | | (5) | | | — | | | — | | | — | | | (5) | |
Issued pursuant to exercise of warrants | Issued pursuant to exercise of warrants | 11,872 | | | 0 | | | 292 | | | — | | | — | | | — | | | 292 | | Issued pursuant to exercise of warrants | 987,411 | | | 1 | | | 53 | | | — | | | — | | | — | | | 54 | |
Net loss | — | | | — | | | — | | | (77,695) | | | — | | | — | | | (77,695) | | |
Balance – June 30, 2021 | 50,017,491 | | | $ | 50 | | | $ | 1,125,143 | | | $ | (197,995) | | | — | | | $ | — | | | $ | 927,198 | | |
Net income | | Net income | — | | | — | | | — | | | 155,494 | | | — | | | — | | | 155,494 | |
Balance – June 30, 2022 | | Balance – June 30, 2022 | 50,875,988 | | | $ | 51 | | | $ | 1,137,575 | | | $ | 159,966 | | | 457,549 | | | $ | (28,751) | | | $ | 1,268,841 | |
|
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., a Delaware corporation, is an independent energy company with operations focused in the Gulf Coast and Rocky Mountain regions of the United States. 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.
Proposed Merger of the Company with Exxon Mobil Corporation. On July 13, 2023, we entered into a definitive merger agreement (“Merger Agreement”) with Exxon Mobil Corporation (“ExxonMobil”), providing for Denbury to merge with a wholly owned subsidiary of ExxonMobil (the “Merger”) and survive as a wholly owned subsidiary of ExxonMobil. Under the terms of the Merger Agreement, each issued and outstanding share of our common stock (other than certain excluded shares held by us as treasury stock or owned by ExxonMobil or its merger subsidiary), par value $0.001 per share, will be converted into the right to receive 0.84 shares of ExxonMobil common stock, without par value (the “Exchange Ratio”). Completion of the Merger remains subject to certain conditions, including the approval of the Merger by our stockholders, as well as certain governmental and regulatory approvals. The Merger is currently expected to close in the fourth quarter of 2023; however, no assurance can be given as to when, or if, the Merger will occur.
In connection with the Merger, any Company restricted stock awards, deferred stock awards, and performance shares that are outstanding immediately prior to completion of the Merger will generally become vested and converted into the right to receive shares of ExxonMobil common stock based on the Exchange Ratio. Any unexercised Series A warrants remaining at the closing date will be canceled for no consideration in accordance with the terms of the underlying warrant agreements. In order for the shares of Denbury common stock underlying the warrants to be converted into the right to receive shares of ExxonMobil common stock in the Merger, the holders must exercise their warrants in accordance with the time periods and under the terms specified in the applicable warrant agreement to receive shares of Denbury common stock prior to the closing of the Merger.
The Merger Agreement contains termination rights for each of the Company and ExxonMobil, including, among others: (1) if the consummation of the Merger does not occur on or before July 13, 2024 (the “End Date”); except that if the effective time of the Merger has not occurred by July 13, 2024 due to the fact that all required applicable regulatory approvals have not been obtained on acceptable terms but all other conditions to closing have been satisfied (other than those conditions that by their terms are to be satisfied at the closing, each of which is capable of being satisfied) or (to the extent permitted by law) waived, the End Date may be extended by either party to January 13, 2025; (2) subject to certain conditions, if the Company wishes to terminate the Merger Agreement to enter into a definitive agreement with respect to a Superior Proposal; and (3) subject to certain conditions, if ExxonMobil wishes to terminate the Merger Agreement upon the occurrence of a Specified Pipeline Event. Upon termination of the Merger Agreement under specified circumstances, including, among others, the termination by ExxonMobil in the event of a change of recommendation by the Board of Directors of the Company or by the Company in order to enter into a definitive agreement with respect to a Superior Proposal, the Company would be required to pay ExxonMobil a termination fee of $144,000,000. In addition, upon termination of the Merger Agreement by ExxonMobil due to the occurrence of a Specified Pipeline Event, ExxonMobil would be required to pay the Company a reverse termination fee of $144,000,000.
The above description of the Merger Agreement and the transactions contemplated thereby, including certain referenced terms, is a summary of certain principal terms and conditions contained in the Merger Agreement.
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, 20212022 (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.
Denbury Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
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 June 30, 2022,2023, our consolidated results of operations for the three and six months ended June 30, 20222023 and 2021,2022, our consolidated cash flows for the six months ended June 30, 20222023 and 2021,2022, and our consolidated statements of changes in stockholders’ equity for the three and six months ended June 30, 20222023 and 2021.2022.
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
We consider all highly liquid investments to be cash equivalents if they have maturities of three months or less at the date of purchase. 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:
| In thousands | In thousands | | June 30, 2022 | | December 31, 2021 | In thousands | | June 30, 2023 | | June 30, 2022 |
Cash and cash equivalents | Cash and cash equivalents | | $ | 517 | | | $ | 3,671 | | Cash and cash equivalents | | $ | 531 | | | $ | 517 | |
| Restricted cash for future asset retirement obligations | Restricted cash for future asset retirement obligations | | 46,869 | | | 46,673 | | Restricted cash for future asset retirement obligations | | 48,405 | | | 46,869 | |
Total cash, cash equivalents, and restricted cash shown in the Unaudited Condensed Consolidated Statements of Cash Flows | Total cash, cash equivalents, and restricted cash shown in the Unaudited Condensed Consolidated Statements of Cash Flows | | $ | 47,386 | | | $ | 50,344 | | Total cash, cash equivalents, and restricted cash shown in the Unaudited Condensed Consolidated Statements of Cash Flows | | $ | 48,936 | | | $ | 47,386 | |
Restricted cash for future asset retirement obligations in the table above consists of escrow accounts that are legally restricted for certain of our asset retirement obligations.
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. Basic weighted average common shares exclude shares of nonvested restricted stock (although nonvested restricted stock is issued and outstanding upon grant). As these restricted shares vest, they will be included in the shares outstanding used to calculate basic net income (loss) per common share. Restricted stock units and performance stock units are also excluded from basic weighted
Denbury Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
average common shares outstanding until the vesting date. Basic weighted average common shares during the three and six months ended June 30, 20222023 includes 1,404,6491,775,182 performance-based and restricted stock units which are fully vested as of June 30, 2022;2023; however, the shares underlying these stock unitsawards are not included in shares currently issued or outstanding as actual delivery of the shares is not scheduled to occur until December 4, 2023.
Diluted net income (loss) per common share is calculated in the same manner but includes the impact of all potentially dilutive securities. Potentially dilutive securities include restricted stock, restricted stock units, performance stock units, shares to be issued under the employee stock purchase plan (“ESPP”), and seriesSeries A and seriesSeries B warrants.
For each of the three and six months ended June 30, 20222023 and 2021,2022, there were no adjustments to net income (loss) for purposes of calculating basic and diluted net income (loss) per common share.
Denbury Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
The following table reconcilessets forth the weighted average shares used in thefor purposes of calculating basic and diluted net income (loss) per common share calculations for the periods indicated:
| | | Three Months Ended | | Six Months Ended | | Three Months Ended | | Six Months Ended |
| | June 30, | | June 30, | | June 30, | | June 30, |
In thousands | In thousands | | 2022 | | 2021 | | 2022 | | 2021 | In thousands | | 2023 | | 2022 | | 2023 | | 2022 |
| Weighted average common shares outstanding – basic | Weighted average common shares outstanding – basic | | 51,757 | | | 50,999 | | | 51,680 | | | 50,661 | | Weighted average common shares outstanding – basic | | 51,817 | | | 51,757 | | | 51,661 | | | 51,680 | |
Effect of potentially dilutive securities | Effect of potentially dilutive securities | | Effect of potentially dilutive securities | |
Restricted stock, restricted stock units and performance stock units | Restricted stock, restricted stock units and performance stock units | | 603 | | | — | | | 591 | | | — | | Restricted stock, restricted stock units and performance stock units | | 475 | | | 603 | | | 418 | | | 591 | |
| Warrants | Warrants | | 2,526 | | | — | | | 2,660 | | | — | | Warrants | | 1,706 | | | 2,526 | | | 1,802 | | | 2,660 | |
Employee Stock Purchase Plan | | Employee Stock Purchase Plan | | 1 | | | — | | | 1 | | | — | |
Weighted average common shares outstanding – diluted | Weighted average common shares outstanding – diluted | | 54,886 | | | 50,999 | | | 54,931 | | | 50,661 | | Weighted average common shares outstanding – diluted | | 53,999 | | | 54,886 | | | 53,882 | | | 54,931 | |
For the three and six months ended June 30, 2021, thepurposes of calculating diluted weighted average common shares, outstanding used to calculate basic earnings per share and diluted earnings per share were the same, since the Company recorded net losses each period. Assuming the Company had recorded net income during the three and six months ended June 30, 2021, the weighted average diluted shares outstanding would have been 54.3 million (including the impact of 0.8 millionunvested restricted stock units, and 2.4 million shares with respect to warrants) and 52.7 million (including the impact of 0.6 millionunvested restricted stock, unvested performance stock units, unissued ESPP shares and 1.4 millionunexercised warrants are included in the diluted shares with respect to warrants), respectively.computation using the treasury stock method.
The following outstanding securities could potentially dilute earnings per share in the future, but were excluded from the computation of diluted net income (loss) per share for the six months ended June 30, 2023 and June 30, 2022, as their effect would have been antidilutive, as of the respective dates:
| | | June 30, | | | June 30, | |
In thousands | In thousands | | 2022 | | 2021 | | In thousands | | 2023 | | 2022 | |
Restricted stock, restricted stock units and performance stock units(1) | Restricted stock, restricted stock units and performance stock units(1) | | 124 | | | 1,255 | | | Restricted stock, restricted stock units and performance stock units(1) | | 5 | | | 191 | | |
| Warrants | | — | | | 5,503 | | | |
|
(1) Antidilutive shares for the six-month periods ended June 30, 2023 and 2022 reflect total shares excluded from the computation of diluted net income per share that are potentially dilutive in the future, assuming performance stock units at the target level. Shares disclosed for the period ended June 30, 2022 have been revised to be consistent with the current year presentation.
At June 30, 2022,2023, the Company had approximately 3.42.6 million warrants outstanding that can be exercised for shares of our common stock, at an exercise price of $32.59 per share for the 1.8 million seriesSeries A warrants outstanding and at an exercise price of $35.41 per share for the 1.60.8 million seriesSeries B warrants outstanding. The warrants may be exercised for cash or on a cashless basis. The seriesSeries A warrants are exercisable until the earliest of (1) September 18, 2025, (2) the date of consummation of a Sale Transaction (as defined in the applicable warrant agreement), and (3) a Winding Up (as defined in the seriesapplicable warrant agreement), at which time the Series A warrants expire. The Series B warrants are exercisable until the earliest of (1) September 18, 2023, (2) the date of consummation of a Sale Transaction (as defined in the applicable warrant agreement), and (3) a Winding Up (as defined in the applicable warrant agreement), at which times the Series B warrants expire. During the three and six months endedThrough June 30, 2022, 1,796,2372023, a total of 0.9 million Series A warrants and 1,822,013a total of 2.1 million Series B warrants werehave been exercised for a total of 987,4111.7 million shares, and 1,001,564 shares, respectively, most of which were exercised on a cashless basis. During July 2023, 0.6 million Series A warrants were exercised resulting in the issuance of 0.4 million shares, leaving 1.2 million Series A warrants outstanding as of July 31, 2023. If the Merger with ExxonMobil is consummated, any unexercised warrants remaining at the closing date will be canceled for no consideration in accordance with the terms of the underlying warrant agreements. In order for the shares of Denbury common stock underlying the warrants to be converted into the right to receive shares of ExxonMobil common stock in the Merger, the holders must exercise their warrants in accordance with the time periods and under the terms specified in the applicable warrant agreement to receive shares of Denbury common stock prior to the closing of the Merger.
Oil and Natural Gas Properties
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)
Denbury Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
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
Denbury Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
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. The write-down was primarily a result of the March 2021 acquisition of Wyoming CO2 EOR properties (see Note 2, Acquisition and Divestiture) 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. We did not record a ceiling test write-down during the three or six months ended June 30, 2023 or June 30, 2022.
CCUS Storage Sites and Related AssetsEquity Method Investments
Capitalized Costs.In accordance with equity method accounting, we record our initial equity investments at cost and periodically adjust the value of the investment balance to recognize (1) the proportionate share of the investee’s net income or losses after the date of investment, (2) additional contributions made and dividends or distributions received, and (3) impairment losses resulting from adjustments to net realizable value. The investments are included in “Other assets” in the Unaudited Condensed Consolidated Balance Sheet as of June 30, 2023. We capitalize various costs that we incur to acquire and develop storage sitesevaluate our equity method investments for the injection of CO2. These costs generally include, or are expected to include, expenditures for acquiring surface and subsurface rights; third-party acquisition costs; permitting; drilling; facilities; environmental monitoring equipment for groundwater and storage site gas; engineering; capitalized interest; on-site road construction and other capital infrastructure costs. Ifother-than temporary impairment on a storage site is no longer deemed probable of being developed, all previously capitalized costs are expensed.
Amortization. Our CCUS storage sites are not yet operational. Accordingly, we currently have no amortization of capitalized costs. Amortization of these costs will begin when CO2 storage operations commence.periodic basis.
Note 2. Acquisition and Divestiture
2021 Acquisition of Wyoming CO2 EOR Properties
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, including surface facilities and a 46-mile CO2 transportation pipeline to the acquired fields. The acquisition purchase price was $10.9 million (after final closing adjustments) plus two contingent $4 million cash payments if NYMEX WTI oil prices average at least $50 per Bbl during each of 2021 and 2022. We made the first contingent payment in January 2022 and if the price condition is met, the second $4 million payment will be due in January 2023. The fair value of the contingent consideration recorded on our Unaudited Condensed Consolidated Balance Sheets was $3.8 million as of June 30, 2022.
The fair values allocated to our assets acquired and liabilities assumed for the acquisition, based on significant inputs not observable in the market and considered level 3 inputs, were finalized during the third quarter of 2021, after consideration of
Denbury Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
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 | |
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 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.
Note 3.2. Revenue Recognition
We record revenue in accordance with Financial Accounting Standards Board (“FASB”) Codification (“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 one 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. In certain situations, the Company enters into marketing arrangements for the purchase and subsequent sale of crude oil from third parties. We recognize the revenuesrevenue received and the associated expensesexpense incurred on these sales on a gross basis, as “Oil marketing revenues” and “Oil marketing purchases” in our Unaudited Condensed Consolidated Statements of Operations, since 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 table summarizes our revenues by product type for the three and six months ended June 30, 20222023 and 2021:2022:
| | | Three Months Ended | | Six Months Ended | | Three Months Ended | | Six Months Ended |
| | June 30, | | June 30, | | June 30, | | June 30, |
In thousands | In thousands | | 2022 | | 2021 | | 2022 | | | 2021 | In thousands | | 2023 | | 2022 | | 2023 | | 2022 |
Oil sales | Oil sales | | $ | 446,592 | | | $ | 280,577 | | | $ | 827,834 | | | | $ | 513,621 | | Oil sales | | $ | 301,543 | | | $ | 446,592 | | | $ | 614,115 | | | $ | 827,834 | |
Natural gas sales | Natural gas sales | | 5,378 | | | 2,131 | | | 9,047 | | | | 4,532 | | Natural gas sales | | 1,403 | | | 5,378 | | | 3,320 | | | 9,047 | |
CO2 sales and transportation fees | CO2 sales and transportation fees | | 12,610 | | | 10,134 | | | 26,032 | | | | 19,362 | | CO2 sales and transportation fees | | 11,164 | | | 12,610 | | | 21,850 | | | 26,032 | |
Oil marketing revenues | Oil marketing revenues | | 16,786 | | | 7,819 | | | 30,062 | | | | 13,945 | | Oil marketing revenues | | 13,983 | | | 16,786 | | | 28,531 | | | 30,062 | |
Total revenues | Total revenues | | $ | 481,366 | | | $ | 300,661 | | | $ | 892,975 | | | | $ | 551,460 | | Total revenues | | $ | 328,093 | | | $ | 481,366 | | | $ | 667,816 | | | $ | 892,975 | |
Denbury Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
Note 4.3. Long-Term Debt
The table below reflects long-term debt outstanding as of the dates indicated:
| | | | | | | | | | | | | | |
In thousands | | June 30, 2022 | | December 31, 2021 |
Senior Secured Bank Credit Agreement | | $ | — | | | $ | 35,000 | |
| | | | |
| | | | |
| | | | |
Long-term debt | | $ | — | | | $ | 35,000 | |
| | | | | | | | | | | | | | |
In thousands | | June 30, 2023 | | December 31, 2022 |
Senior Secured Bank Credit Agreement | | $ | 85,000 | | | $ | 29,000 | |
| | | | |
Capital lease obligations | | 153 | | | — | |
| | | | |
| | | | |
Long-term debt and capital lease obligations | | $ | 85,153 | | | $ | 29,000 | |
Senior Secured Bank Credit Agreement
OnIn September 18, 2020, we entered into a $575 million credit agreement for a senior secured revolving credit facility with JPMorgan Chase Bank, N.A., as administrative agent, and other lenders party thereto (the(as amended, the “Bank Credit Agreement”). The Bank Credit Agreement is a senior secured revolving credit facility with a maturity date of May 4, 2027. Under the Bank Credit Agreement, letters of credit are available in an aggregate amount not to exceed $100 million, and short-term swingline loans are available in an aggregate amount not to exceed $25 million, each subject to the available commitments under the Bank Credit Agreement. 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 November 1, 2022.year. 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. As part of our Spring 2023 semiannual borrowing base redetermination, the borrowing base and lender commitments for our Bank Credit Agreement were reaffirmed at $750 million, with our next scheduled redetermination around November 1, 2023. The undrawn portion of the aggregate lender commitments under the Bank Credit Agreement is subject to a commitment fee of 0.5% per annum. As of June 30, 2023, we had $10.1 million of outstanding letters of credit.
On May 4, 2022,January 20, 2023, we entered into a SecondThird Amendment to the Bank Credit Agreement, which among other things:
•Increasedthings, provides us the borrowing baseability to make and lender commitments from $575 million to $750 million;
•Extended the maturity date from January 30, 2024 to May 4, 2027;
•Modified the interest provisions on loans under the Bank Credit Agreement to (1) reduce the applicable margin for alternate base rate loans from 2% to 3% per annum to 1.5% to 2.5% per annum and (2) replace provisions referencing LIBOR loans withrepay certain Secured Overnight Financing Rate loans, with an applicable margin of 2.5% to 3.5% per annum; and
•Permitted us to pay dividends(“SOFR”) loan borrowings on our common stock and make other unlimited restricted payments and investments so long as (1) no event of default or borrowing base deficiency exists; (2) our total leverage ratio is 1.5 to 1 or lower; and (3) availability under the Bank Credit Agreement is at least 20% of the borrowing base.a weekly basis.
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 certain customary exceptions to such limitations, as specified in the Bank Credit Agreement. Our Bank Credit Agreement required certain minimum commodity hedge levels in connection with our emergence from bankruptcy; however, these conditions were met as of December 31, 2020, and we currently have no ongoing hedging requirements under the Bank Credit Agreement.
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
Denbury Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
agreements; (4) a pledge of deposit accounts, securities accounts and our commodity accounts;accounts of Denbury Inc. and such subsidiaries (as applicable); 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. The weighted average interest rate on borrowings outstanding as of June 30, 2023 under the Bank Credit Agreement was 8%. As of June 30, 2022,2023, we were in compliance with all debt covenants under the Bank Credit Agreement.
Denbury Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
The above description of our Bank Credit Agreement, is qualified by the express language andincluding certain referenced defined terms, is a summary of certain principal terms and conditions contained in the Bank Credit Agreement and amendments thereto.
Note 4. Investments
Equity Method Investments
Our equity-method investments and their book value balances consisted of the following:
| | | | | | | | | | | | | | |
In thousands | | June 30, 2023 | | December 31, 2022 |
Equity method investments (1) | | | | |
Clean Hydrogen Works, LA-1, L.L.C. | | $ | 20,218 | | | $ | 10,218 | |
Libra, CO2 Storage Solutions, LLC | | 1,927 | | | — | |
Total equity method investments | | 22,145 | | | 10,218 | |
(1) The investment balances in this table include capitalized transaction costs.
Clean Hydrogen Works. In April 2023, based on the achievement of certain milestones, we invested the remaining $10 million of our total $20 million commitment to invest in Clean Hydrogen Works (“CHW”), the project development company of a planned blue hydrogen/ammonia multi-block facility for which we have signed a definitive agreement for the transportation and storage of CO2 for the first two blocks of the proposed plant. We account for the investment in CHW under the equity method of accounting.
When an entity makes an investment that qualifies for the equity method of accounting, there may be a difference in the cost basis of the investment and the proportional interest in the underlying equity in the net assets of the investee (“basis difference”). At the acquisition date, the Company identified a basis difference of $17.7 million associated with its investment in CHW. The basis difference was allocated to finite lived intangible assets identified and equity method goodwill. The Company will amortize the basis differences attributable to finite lived intangible assets and record the amortization as a reduction of earnings from equity method investments, net in the accompanying Condensed Consolidated Statements of Operations.
Libra, CO2 Storage Solutions, LLC. During the second quarter, we invested $1.5 million in Libra CO2 Storage Solutions, LLC in connection with a joint venture related to a CO2 sequestration project in St. Charles Parish, Louisiana.
Other Investments
During the first quarter of 2023, we made two investments in carbon capture technology companies, including a $2 million investment in Aqualung Carbon Capture AS and a $5 million investment in ION Clean Energy, Inc.
All investments are included in “Other assets” in the Unaudited Condensed Consolidated Balance Sheet as of June 30, 2023.
Note 5. Stockholders'Stockholders’ Equity
2022 Share Repurchase ProgramRepurchases
In early May 2022, our Board of Directors authorized a common share repurchase program for up to $250 million of outstanding Denbury common stock. During the second quarter of 2022, the Company repurchased 457,549 shares of Denbury common stock for $28.8 million, or $62.84 per share. Cumulatively throughJune and July 31, 2022, the Company repurchased 1,615,356 shares of Denbury common stock under this program for approximately $100 million, orat an average price of $61.92 per share. OnNo share repurchases have been made under this program since that time. In August 2, 2022, the Board increased Denbury’s stock repurchase authorization by $100 million to a total of Directors increased the dollar amount of Denbury common stock that can be purchased$250 million for future repurchases under the program to an aggregate of $350 million, and at that date, we were authorized to repurchase up to an additional $250.0 million of common stock. The program has no pre-established ending date and may be suspendedprogram. With limited exceptions, the Merger Agreement precludes the Company from any future repurchases or discontinued at any time. The Company is not obligated to repurchase any dollar amount or specific numberacquisition of shares of its commoncapital stock, including under the program.a repurchase program, without ExxonMobil’s consent.
Denbury Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
Retirement of Treasury Stock Purchase Plan
AtDuring the annual meetingyear ended December 31, 2022, we retired 1.6 million shares of stockholders onexisting treasury stock, with a carrying value of $100 million, acquired through our stock repurchase program. Upon the retirement of treasury stock, we reduce common stock by the par value of common stock retired, and we reduce additional paid-in capital by the value of those shares in excess of par value.
Tax Withholding and Treasury Stock Retirement in Connection with Stock Compensation Plans
During the six months ended June 1, 2022, the Company’s stockholders voted to approve the Denbury Inc. Employee Stock Purchase Plan (“ESPP”) authorizing the sale of up to 2,000,00030, 2023, employees surrendered 16,281 shares of common stock, thereunder. In accordance with the ESPP, eligible employees may contribute up to 10% of eligible compensation, subject to certain limitations, to purchase previously unissued Denbury common stock. Participants in the ESPP may purchase common stock at a 15% discount to the fair marketcarrying value of a shareapproximately $1.4 million, to cover employee tax withholdings upon vesting of restricted stock awards, which shares were concurrently retired. For restricted stock units (“RSUs”), when the awards are settled the Company issues the net shares of common stock, determined as the lower of the closing sales price on the first or last trading day of each offering period. We currently anticipate the first offering period under the ESPP will commence on September 1, 2022 and end on December 31, 2022. The plan is administeredreduced by the Compensation Committee of our Board of Directors.units surrendered to cover tax withholding. For the six months ended June 30, 2023, we decreased additional paid in capital by $1.3 million for tax withholdings on RSUs.
Note 6. Income Taxes
We make estimates and judgments in determining our income tax expense for financial reporting purposes. These estimates and judgments occur in the calculation of certain tax assets and liabilities that arise from differences in the timing and recognition of revenue and expense for tax and financial reporting purposes. Significant judgment is required in estimating valuation allowances, and in making this determination we consider all available positive and negative evidence and make certain assumptions. The realization of a deferred tax asset ultimately depends on the existence of sufficient taxable income in the applicable carryback or carryforward periods. In our assessment, we consider the nature, frequency, and severity of current and cumulative losses, as well as historical and forecasted financial results, the overall business environment, our industry’s historic cyclicality, the reversal of existing deferred tax assets and liabilities, and tax planning strategies.
We assess the valuation allowance recorded on our deferred tax assets on a quarterly basis, which was $125.5$59.2 million at December 31, 2021, on a quarterly basis.2022. This valuation allowance onrelates primarily to our federal and certain stateLouisiana net deferred tax assets was recorded in September 2020
Denbury Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
after the application of fresh start accounting,$55.4 million, as (1) the tax basis ofwell as our assets, primarily our oil and gas properties, was in excess of the carrying value, as adjusted for fresh start accounting and (2) our historical pre-tax income reflected a three-year cumulative loss primarily due to ceiling test write-downs and reorganization items that were recorded in 2020. While we continued to be in a cumulative three-year-loss position through the first quarter of 2022, we initially determined as of March 31, 2022, that there was sufficient positive evidence, primarily related to a substantial increase in worldwide oil prices, to conclude that $64.9 million of our federal and certain stateAlabama net deferred tax assets and certain Mississippi tax credits totaling $3.8 million. We have concluded that the benefits of such deferred tax assets are not more likely than not to be realized. Accordingly, we reversed $5.9 millionrealized due to lack of this valuation allowance duringsufficient taxable income to fully realize the three months ended March 31, 2022, $18.8 million during the three months ended June 30, 2022, and currently expect to reverse the remaining $40.2 million during the second halfbenefits of 2022, resulting in a reduction to our annualized effectivesuch deferred tax rate. We continue to maintain a valuation allowance of $60.6 million for certain state tax benefits that we currently do not expect to realize before their expiration.assets.
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 20222023 and 2021.2022. Our effective tax rate for the three months ended June 30, 2023 was in line with our estimated statutory rate and our effective tax rate for the six months ended June 30, 2023 was slightly lower than our estimated statutory rate primarily due to excess stock compensation deductions that were recorded discretely in the first quarter. Our effective tax rate for the three and six months ended June 30, 2022 was significantly lower than our estimated statutory rate primarily due to the release of a portion of the valuation allowance that was recorded in the three and six months ended June 30, 2022.on our deferred tax assets.
Note 7. 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”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,Over the last few years 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.costless collars. The production that we hedge has varied from year to year depending on our levels of debt, financial strength and expectation of future commodity prices.prices, and occasionally requirements under our bank credit facility. We currently have no hedging requirements under our bank credit facility.
Denbury Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
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 June 30, 2022,2023, 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.
Denbury Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
The following table summarizes our commodity derivative contracts as of June 30, 2022,2023, none of which are classified as hedging instruments in accordance with the FASC Derivatives and Hedging topic:
| Months | Months | | Index Price | | Volume (Barrels per day) | | Contract Prices ($/Bbl) | Months | | Index Price | | Volume (Barrels per day) | | Contract Prices ($/Bbl) |
Weighted Average Price | Weighted Average Price |
Swap | | Floor | | Ceiling | Swap | | Floor | | Ceiling |
Oil Contracts: | Oil Contracts: | | | | | | | | | Oil Contracts: | | | | | | | | |
2022 Fixed-Price Swaps | | |
2023 Fixed-Price Swaps | | 2023 Fixed-Price Swaps | |
July – Dec | July – Dec | | NYMEX | | 9,500 | | $ | 57.52 | | | $ | — | | | $ | — | | July – Dec | | NYMEX | | 18,000 | | $ | 78.51 | | | $ | — | | | $ | — | |
2022 Collars | | |
2023 Collars | | 2023 Collars | |
July – Dec | July – Dec | | NYMEX | | 11,500 | | $ | — | | | $ | 52.39 | | | $ | 67.29 | | July – Dec | | NYMEX | | 9,000 | | $ | — | | | $ | 68.33 | | | $ | 100.69 | |
2023 Fixed-Price Swaps | | |
2024 Fixed-Price Swaps | | 2024 Fixed-Price Swaps | |
Jan – June | Jan – June | | NYMEX | | 4,500 | | $ | 74.88 | | | $ | — | | | $ | — | | Jan – June | | NYMEX | | 5,000 | | $ | 75.34 | | | $ | — | | | $ | — | |
July – Dec | July – Dec | | NYMEX | | 2,000 | | 76.80 | | | — | | | — | | July – Dec | | NYMEX | | 1,000 | | 75.12 | | | — | | | — | |
2023 Collars | | |
Jan – June | | NYMEX | | 17,500 | | $ | — | | | $ | 69.71 | | | $ | 100.42 | | |
July – Dec | | NYMEX | | 9,000 | | — | | | 68.33 | | | 100.69 | | |
Note 8. 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).NYMEX. Our costless 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.
Denbury Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
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.
Denbury Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
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: | | | Fair Value Measurements Using: |
In thousands | In thousands | | Quoted Prices in Active Markets (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Unobservable Inputs (Level 3) | | Total | In thousands | | Quoted Prices in Active Markets (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Unobservable Inputs (Level 3) | | Total |
June 30, 2022 | | | | | | | | | |
June 30, 2023 | | June 30, 2023 | | | | | | | | |
Assets | Assets | | Assets | |
Oil derivative contracts – current | Oil derivative contracts – current | | $ | — | | | $ | 2,829 | | | $ | — | | | $ | 2,829 | | Oil derivative contracts – current | | $ | — | | | $ | 36,809 | | | $ | — | | | $ | 36,809 | |
Oil derivative contracts – long-term | Oil derivative contracts – long-term | | — | | | 2,071 | | | — | | | 2,071 | | Oil derivative contracts – long-term | | — | | | 1,269 | | | — | | | 1,269 | |
Total Assets | Total Assets | | $ | — | | | $ | 4,900 | | | $ | — | | | $ | 4,900 | | Total Assets | | $ | — | | | $ | 38,078 | | | $ | — | | | $ | 38,078 | |
| Liabilities | | |
Oil derivative contracts – current | | $ | — | | | $ | (162,551) | | | $ | — | | | $ | (162,551) | | |
Oil derivative contracts – long-term | | — | | | (5,415) | | | — | | | (5,415) | | |
Total Liabilities | | $ | — | | | $ | (167,966) | | | $ | — | | | $ | (167,966) | | |
| December 31, 2021 | | | | | | | | | |
| | | December 31, 2022 | | December 31, 2022 | | | | | | | | |
Assets | | Assets | | | | | | | | |
Oil derivative contracts – current | | Oil derivative contracts – current | | $ | — | | | $ | 15,517 | | | $ | — | | | $ | 15,517 | |
Total Assets | | Total Assets | | $ | — | | | $ | 15,517 | | | $ | — | | | $ | 15,517 | |
| Liabilities | Liabilities | | Liabilities | |
Oil derivative contracts – current | Oil derivative contracts – current | | $ | — | | | $ | (134,509) | | | $ | — | | | $ | (134,509) | | Oil derivative contracts – current | | $ | — | | | $ | (13,018) | | | $ | — | | | $ | (13,018) | |
| Total Liabilities | Total Liabilities | | $ | — | | | $ | (134,509) | | | $ | — | | | $ | (134,509) | | Total Liabilities | | $ | — | | | $ | (13,018) | | | $ | — | | | $ | (13,018) | |
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”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. We had no debt outstanding as of June 30, 2022, and theThe estimated fair value of the principal amount of our debt was $35.0 million as of June 30, 2023 and December 31, 2021.2022 was $85.0 million and $29.0 million, respectively. 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 9. Commitments and Contingencies
Litigation and Regulatory Proceedings
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 and regulatory proceedings are 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.
Denbury Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
On May 26, 2022, the Pipeline and Hazardous Materials Safety Administration (“PHMSA”) of the U.S. Department of Transportation issued a Notice of Probable Violation, Proposed Civil Penalty, and Proposed Compliance Order (“NOPV”) relating to the February 2020 CO2 release from a pipeline failure near Satartia, Mississippi in our CO2 pipeline running between the Tinsley and Delhi fields. The NOPV proposesfields, and assessed a preliminarily assessedpreliminary civil penalty of $3.9 million, which the Company recorded in connection withits financial statements in the incident, which
2022. On March 24, 2023, Denbury Inc.
Notesand PHMSA entered into a final Consent Order and Consent Agreement that settled all of the allegations in the NOPV and also reduced the assessed penalty to $2.9 million. The $1.0 million reduction was reflected in “Other Expenses” in our Unaudited Condensed Consolidated Financial Statements
we recordedStatement of Operations in our secondthe first quarter of 2022 financial statements. We have responded to the NOPV and are pursuing discussions with PHMSA regarding the probable violations alleged in the NOPV, the proposed civil penalty, and the nature of the compliance order contained in the NOPV.2023.
Note 10. Additional Balance Sheet Details
Trade and Other Receivables, Net
| | | | | | | | | | | | | | |
In thousands | | June 30, 2022 | | December 31, 2021 |
Trade accounts receivable, net | | $ | 18,014 | | | $ | 10,832 | |
Federal income tax receivable, net | | 597 | | | 597 | |
Other receivables | | 12,307 | | | 7,841 | |
Total | | $ | 30,918 | | | $ | 19,270 | |
Accounts Payable and Accrued Liabilities
| | | | | | | | | | | | | | |
In thousands | | June 30, 2022 | | December 31, 2021 |
Accounts payable | | $ | 53,007 | | | $ | 25,700 | |
Accrued derivative settlements | | 46,888 | | | 27,336 | |
Accrued lease operating expenses | | 44,195 | | | 27,901 | |
Accrued asset retirement obligations – current | | 34,400 | | | 18,373 | |
Accrued compensation | | 21,270 | | | 23,735 | |
Taxes payable | | 12,506 | | | 14,453 | |
Accrued exploration and development costs | | 10,363 | | | 18,936 | |
Other | | 40,123 | | | 35,164 | |
Total | | $ | 262,752 | | | $ | 191,598 | |
Note 11. Subsequent Event
Delhi Insurance Receivable
In July 2022, we finalized a settlement agreement with certain of our insurance carriers, pursuant to which they agreed to pay Denbury $7.0 million ($6.7 million net to Denbury’s interest) as a reimbursement of previously incurred property damage costs at Delhi Field. The reimbursement is included as a reduction of “Lease operating expenses” in the accompanying Unaudited Condensed Consolidated Statements of Operations during the three and six months ended June 30, 2022, as a result of the resolution of these claims which arose in 2013.
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, 20212022 (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.
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.
Proposed Merger of the Company with Exxon Mobil Corporation. On July 13, 2023, we entered into a definitive merger agreement (“Merger Agreement”) with Exxon Mobil Corporation (“ExxonMobil”), providing for Denbury to merge with a wholly owned subsidiary of ExxonMobil (the “Merger”) and survive as a wholly owned subsidiary of ExxonMobil. Under the terms of the Merger Agreement, each issued and outstanding share of our common stock (other than certain excluded shares held by us as treasury stock or owned by ExxonMobil or its merger subsidiary), par value $0.001 per share, will be converted into the right to receive 0.84 shares of ExxonMobil common stock, without par value. Completion of the Merger remains subject to certain conditions, including the approval of the Merger Agreement by our stockholders, as well as certain governmental and regulatory approvals. The Merger is currently expected to close in the fourth quarter of 2023; however, no assurance can be given as to when, or if, the Merger will occur.
The foregoing summary of the Merger Agreement and the transactions contemplated thereby does not purport to be complete and is qualified in its entirety by reference to the terms and conditions of the Merger Agreement, a copy of which is attached as Exhibit 2.1 to the Company’s Current Report on Form 8-K, filed with the Securities and Exchange Commission (“SEC”) on July 14, 2023, as amended by the Form 8-K/A, filed with the SEC on July 31, 2023.
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,utilization, 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 CO2e emissions negative today, withtoday. We have set a goaltarget, within the decade, to be net-zero on itsreach Net Zero for our Scope 1, Scope 2 and those Scope 3 emissions that result from consumers’ use of the oil and natural gas we sell (defined as Category 11 emissions by the Greenhouse Gas Protocol).
Our CO2 EOR oil recovery operations result in associated underground storage of CO2. This means that Denbury’s activities are currently supporting and advancing the national energy transition through the increasing use of industrially sourced CO2 in EOR operations, and we are building out a dedicated CCUS platform for the transportation and permanent storage of captured industrial CO2 emissions by 2030, primarily through increasing the amount of captured industrial-sourced CO2 used in its operations.
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 lead 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.at scale. During the first half of 2022,six months ended June 30, 2023, approximately 39%41% of the CO2 utilized in our operated oil and gas operations was industrial-sourced CO2, equivalentcompared to 39% of the CO2 utilized during the six months ended June 30, 2022. Our industrial-sourced CO2 usage in the first half of 2023 equates to an annualized average CO2usage rate of over 44.5 million metric tons in 2022. This compares to 34% utilized during the first half of 2021, with the increase related to commencing CO2 injection in the first phase of our Cedar Creek Anticline (“CCA”) EOR project. We anticipate this percentage will 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 CO2 offtake, transportation and storage solutions. In the nearer term, while the energy transition is still evolving nationally, we believe that a key driver in speeding that transition is identifying and securing the long-term supply of industrial CO2, while also identifying potential future sequestration sites and landowners of those locations. We continue to make material progress in both of these areas, and thus far have signed agreements securing the rights to five future sequestration sites which we believe have the potential to store up to 1.5 billion metric tons of CO2. In addition, we have executed several term sheets for the future transportation and sequestration of CO2. During the first half of 2022, we capitalized $24.0 million in “CCUS storage sites and related assets” in our Unaudited Condensed Consolidated Balance Sheets, primarily consisting of acquisition costs associated with sequestration sites. While our use of CO2 in EOR is the only CCUS operation reflected in our historical financial and operational results (as a cost), we believe the incentives offered under Section 45Q of the Internal Revenue Code and the proposed Inflation Reduction Act of 2022 or otherwise will drive demand for CCUS and allow us to collect a fee for the transportation and storage of captured industrial-sourced CO2, including CO2 utilized in our EOR operations. It will likely take several years to construct new capture facilities and for dedicated storage sites to be developed. We believe our existing CO2 pipeline infrastructure, EOR operations, and experience and expertise in working with CO2 all position us to be a leader in this rapidly developing industry.tons.
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 belowOil prices have historically been volatile and can fluctuate significantly over short periods of time for many different reasons, such as global supply and demand and geopolitical events. Average NYMEX WTI oil prices were approximately $74 per Bbl during the second quarter of 2023, a slight decrease from $76 per Bbl in the first quarter of 2023, and a decrease from $109 per Bbl during the second quarter of 2022.
Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
The table below 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 | | June 30, 2022 | | March 31,2022 | | Dec. 31, 2021 | | Sept. 30, 2021 | | June 30, 2021 | | |
Oil, natural gas, and related product sales | | $ | 451,970 | | | $ | 384,911 | | | $ | 333,348 | | | $ | 308,454 | | | $ | 282,708 | | | | | |
Payment on settlements of commodity derivatives | | (127,959) | | | (93,057) | | | (97,774) | | | (77,670) | | | (63,343) | | | | | |
Oil, natural gas, and related product sales and commodity derivative settlements, combined | | $ | 324,011 | | | $ | 291,854 | | | $ | 235,574 | | | $ | 230,784 | | | $ | 219,365 | | | | | |
| | | | | | | | | | | | | | |
Average daily sales (BOE/d) | | 46,561 | | | 46,925 | | | 48,882 | | | 49,682 | | | 49,133 | | | | | |
| | | | | | | | | | | | | | |
Average net realized oil prices | | | | | | | | | | | | | | |
Oil price per Bbl - excluding impact of derivative settlements | | $ | 108.81 | | | $ | 93.17 | | | $ | 75.68 | | | $ | 68.88 | | | $ | 64.70 | | | | | |
Oil price per Bbl - including impact of derivative settlements | | 77.63 | | | 70.43 | | 53.21 | | | 51.35 | | | 50.10 | | | | | |
Average NYMEX WTI oil prices increased from the mid-$70s per Bbl range in the fourth quarter of 2021 to approximately $95 per Bbl during the first quarter of 2022, then increasing to approximately $109 per Bbl during the second quarter of 2022. This increase in oil prices was due in part to worldwide oil supply disruptions associated with the Russian invasion of Ukraine during the first half of 2022. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended | | |
In thousands, except per-unit data | | June 30, 2023 | | March 31, 2023 | | Dec. 31, 2022 | | Sept. 30, 2022 | | June 30, 2022 | | |
Oil, natural gas, and related product sales | | $ | 302,946 | | | $ | 314,489 | | | $ | 346,578 | | | $ | 395,223 | | | $ | 451,970 | | | | | |
Receipt (payment) on settlements of commodity derivatives | | 5,157 | | | 2,065 | | | (38,956) | | | (55,780) | | | (127,959) | | | | | |
Oil, natural gas, and related product sales and commodity derivative settlements, combined | | $ | 308,103 | | | $ | 316,554 | | | $ | 307,622 | | | $ | 339,443 | | | $ | 324,011 | | | | | |
| | | | | | | | | | | | | | |
Average daily sales (BOE/d) | | 46,982 | | | 47,655 | | | 46,641 | | | 47,109 | | | 46,561 | | | | | |
| | | | | | | | | | | | | | |
Average net realized oil prices | | | | | | | | | | | | | | |
Oil price per Bbl - excluding impact of derivative settlements | | $ | 72.59 | | | $ | 74.87 | | | $ | 82.54 | | | $ | 92.77 | | | $ | 108.81 | | | | | |
Oil price per Bbl - including impact of derivative settlements | | 73.83 | | | 75.36 | | 73.13 | | 79.49 | | | 77.63 | | | | | |
| | | | | | | | | | | | | | |
Average NYMEX oil differential per Bbl | | (1.14) | | | $ | (1.28) | | | $ | 0.03 | | | $ | 0.82 | | | $ | 0.09 | | | | | |
As shown in the table above, our oil and natural gas revenues increased significantly duringhave decreased since 2022 primarily due to the last four quarters asdecrease in oil prices increased. However,prices. During 2022, the benefit of high oil prices during the increase in revenues over this time periodfirst half of the year was offset in part by the impact of higher cash payments on our commodity derivative contracts. Thesecontracts, which contracts were largely required to be entered into during the fourth quarter ofgenerally put in place in late 2020 as a requirement under the one-time requirement of our September 18, 2020 bank credit facility. During the second quarter of 2022,facility shortly after we paid $128.0 million related to the expiration of commodity derivative contracts and expect to make additional payments on the settlement of our contracts expiring during the remainder of 2022. In the second half of 2022, less of our production is hedged, and our hedges are at more favorable prices and with a greater mix of collars, providing the potential for us to realize a greater portion of increased oil prices.exited bankruptcy.
Second Quarter 20222023 Financial Results and Highlights. We recognized net income of $67.3 million, or $1.25 per diluted common share, during the second quarter of 2023, compared to a net income of $155.5 million, or $2.83 per diluted common share, during the second quarter of 2022, compared to a net loss2022. Drivers of $77.7 million, or $1.52 per diluted common share, duringthe comparative operating results between the second quarter of 2021. The primary drivers of the comparative second quarter operating results2023 and 2022 include the following:
•Oil and natural gas revenues increased $169.3decreased by $149.0 million (60%(33%) during the second quarter of 2023 due primarily to an increase inlower oil prices;
•Commodity derivatives expense decreased by $115.8$76.5 million consisting of a $180.4$133.1 million increasedecrease in cash payments upon derivative contract settlements ($5.2 million in cash receipts during the second quarter of 2023 compared to $127.9 million in payments during the second quarter of 2022), partially offset by a $56.6 million decrease in noncash fair value changes between periods ($71.114.5 million gain during the second quarter of 20222023 compared to a $109.3$71.1 million loss ingain during the prior-year period), partially offset by a $64.6 million increase in cash payments upon derivative contract settlements;second quarter of 2022);
•Lease operating expensesDepletion, depreciation and amortization increased by $14.4 million (41%) during the second quarter of 2023 due to higher depletable costs, most significantly attributable to capital spending and the transfer of unevaluated costs to the full cost pool associated with the recognition of proved reserves; $14.1 million (13%), primarily consisting of increases of $6.5 million in power and fuel costs, $4.6 million in workovers, $2.8 million in labor costs, and $2.4 million in CO2 expense, partially offset by a $6.7 million insurance recovery of costs incurred in 2013 from property damage at Delhi Field;
•Taxes other than income increased $13.9decreased by $9.4 million (62%(26%) primarilyduring the second quarter of 2023 due to an increasea decrease in oil production taxes resulting from highertax expense corresponding to the decline in oil revenues.
June 2023 West Yellow Creek Divestiture. On June 30, 2023, we closed on a transaction exchanging our 49% non-operated interest in West Yellow Creek Field for a term overriding royalty interest in the field (7% for the first 8 years and gas revenues;3.4% for the next 5 years). Our existing CO2 sales contract to supply CO2 to the field was also amended as part of the transaction, so that we will continue to supply CO2 to the West Yellow Creek Field for a fee. As a result of this transaction, we anticipate that our future production will decrease by approximately 400 Bbls/d with a corresponding reduction in revenues, and
Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
•Income taxes increased to an expense of $24.8we will no longer be obligated for lease operating expenses or capital expenditures for this field. Our lease operating costs at West Yellow Creek Field were approximately $2.6 million duringfor the second quarter of 2022 compared to a benefit of $0.3 million during the prior-year period.three months ended June 30, 2023.
Commencement of Cedar Creek Anticline CO2 Injection.EOR Development. In early February 2022,During the six months ended June, 30, 2023, we commenced CO2 injection in the first phaseincurred 44% of our total oil & gas development capital expenditures, or $88.7 million, on the CCA EOR project, and have subsequently continued to increase CO2 injections intoprimarily focused on the field. In order to stay aheadconstruction of potential supply chain delays, we plan to increase capital investment in the second half of the year at CCA to accelerate our procurement of compression equipment and construction offour planned CO2 recycle facilities, well conversions, and drilling the Interlake Pennel CO2 pilot. Commissioning of the initial CO2 recycle facility within the Cedar Hills South field was completed late in the first quarter of 2023, and commissioning of the second facility was completed during the second quarter of 2023, with the remaining two recycle facilities currently expected to ensure facilities are in place to handle anticipatedbe completed during the second half of 2023. Initial EOR production fromcommenced during the field. Wesecond quarter of 2023, averaging 574 Bbls/d for the full quarter, and we continue to expect tertiary oilanticipate incremental EOR production response from CCA into increase throughout the second halfremainder of 2023.
Common Share Repurchase Program.Carbon Capture, Utilization and Storage Activities. During the six months ended June 30, 2023, we invested $48.1 million of development capital into CCUS assets, primarily for the acquisition of new sequestration sites, the drilling of a stratigraphic test well in our Alabama sequestration site, and the acquisition of seismic data. In the first quarter of 2023, we obtained the rights to develop a new sequestration site in Wyoming, located adjacent to our Greencore CO2 In early May 2022, our Boardpipeline, with estimated CO2 storage potential of Directors authorized a common share repurchase program for up to $25040 million of outstanding Denbury common stock. Duringmetric tons. In the second quarter of 2022,2023, we obtained the Company repurchased 457,549 sharesrights to another sequestration site in Wyoming with estimated CO2 storage potential of Denbury common stock for $28.8 million, or $62.84 per share. Cumulatively through July 31, 2022, the Company repurchased 1,615,356 shares of Denbury common stock (approximately 3.2% of our outstanding shares of common stock at March 31, 2022) for approximately $100.0 million, or an average price of $61.92 per share. On August 2, 2022, the Board of Directors increased the dollar amount of Denbury common stock that can be purchased under the program to an aggregate of $350 million, and at that date, we were authorized to repurchase up to an additional $250.0another 40 million metric tons, for a total of common stock. The program has no pre-established ending date and may be suspended or discontinued at any time. The Company is not obligatedup to repurchase any dollar amount or specific number of shares of its common stock under80 million metric tons in Wyoming adjacent to the program.Greencore CO
2
Increase pipeline. Additionally, we acquired the right to develop a 30,000 acre dedicated CO2 sequestration site in 2022 Capital Expenditure Plans. Based on inflationary cost increases and the desire to accelerate capital spending to offset potential supply chain delays, we are increasing our 2022 capital expenditures estimate for oil and gas development activities from the previously anticipated upper end of $320 million toMatagorda County, Texas, approximately $360 million. Approximately half60 miles southwest of the increase relates to overall service cost inflation impactingterminus of the Company’s operations, primarily relatedGreen CO2 pipeline, with estimated CO2 storage potential of more than 115 million metric tons. We also acquired the right to labor and steel costs, anddevelop an 8,500-acre dedicated CO2 sequestration site in St. Helena Parish, Louisiana, with estimated CO2 storage potential of at least 100 million metric tons. In total, we have agreements securing the rest ofrights to eleven future storage sites which we believe have the increase is associated with CCA EOR development activities, where the Company is accelerating the purchase of compression equipment and constructionpotential to store more than 2 billion metric tons of CO2 recycle facilities to ensure the field is ready to process the expected oil production response. In addition, our original budget for CCUS capital is still estimated at $50 million, but could increase depending on activity in the second half of the year. See further discussion under Capital Resources and Liquidity – 2022 Plans and Capital Budget.
May 2022 AmendmentOn the transportation and storage side of our CCUS business, in the first quarter of 2023, we executed two agreements with eFuels companies, HIF Global and Monarch Energy Development LLC, to Senior Secured Bank Credit Agreement.source and transport up to 2.4 million metric tons of CO2 In early May 2022,per year to planned projects in southeast Texas. During the second quarter of 2023, we amended our bank creditexecuted an agreement with SunGas Renewables Inc. (“SunGas”) to provide CO2 transportation and storage services associated with SunGas’ low carbon methanol facility to among other things, (1) increasebe constructed in Pineville, Louisiana. SunGas’ project is planned to commence operation in 2027 with an estimated one million metric tons per year of associated CO2 emissions. To date, we have signed agreements covering the borrowing basepotential future transportation and lender commitmentsstorage of up to $750 million, (2) extend23 Mmtpa from the maturity date to May 4, 2027, (3) modify certain interest rate provisions,planned capture of CO2 emissions from existing and (4) provide additional flexibility regarding our ability to make restricted payments and investments. See further discussion of this amendment under Capital Resources and Liquidity – Senior Secured Bank Credit Agreement. As of June 30, 2022, we had no outstanding borrowings on our senior secured bank credit facility.proposed industrial plants.
Warrant Exercises. DuringIn addition to the three andCCUS development activities discussed above, during the six months ended June 30, 2022, 1,796,2372023, we made several investments in carbon capture technology companies. During first quarter, we invested $2 million in Aqualung Carbon Capture AS and 1,822,013 warrants were exercised$5 million in ION Clean Energy, Inc. During the second quarter, we invested $1.5 million in Libra CO2 Storage Solutions, LLC in connection with a joint venture related to a CO2 sequestration project at a 14,000-acre site in St. Charles Parish, Louisiana, with estimated CO2 storage potential of at least 200 million metric tons. Also, in the second quarter of 2023, based on the achievement of certain milestones, we invested the remaining $10 million of our original $20 million commitment in Clean Hydrogen Works, the project development company of a planned blue hydrogen/ammonia multi-block facility for which we have signed a totaldefinitive agreement for the transportation and storage of 987,411 shares and 1,001,564 shares, respectively, mostCO2 for the first two blocks of which were exercised on a cashless basis. Atthe proposed plant. These investments are included in “Other assets” in the Unaudited Condensed Consolidated Balance Sheet as of June 30, 2022, the Company had approximately 3.4 million warrants outstanding that can be exercised for shares of our common stock, which represents approximately 60.9% of the aggregate series A and B warrants issued in September 2020, at an exercise price of $32.59 per share for the 1.8 million series A warrants outstanding and at an exercise price of $35.41 per share for the 1.6 million series B warrants outstanding. The warrants may be exercised for cash or on a cashless basis. The series A warrants are exercisable until September 18, 2025, and the series B warrants are exercisable until September 18, 2023, at which times the warrants expire.2023.
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 relate to our oil and gas development capital expenditures and CCUS initiatives.
During the six months ended June 30, 2023, we generated $231.0 million in cash flow from operations, or $268.1 million before working capital changes, as the first half of 2023 included $37.1 million in cash outflows for working capital items primarily related to annual ad valorem tax and bonus payments. We invested cash of $293.7 million, primarily in oil and gas and CCUS activities, including equity investments during the first half of 2023 and financing activities supplemented our cash flow by $63.7 million, primarily from borrowings under our bank credit facility. As of June 30, 2022,2023, we had no outstanding borrowings and $12.0$85.0 million of outstanding letters of credit under our $750borrowings, up from $68.0 million senior secured bank credit facility, leaving us with $738.0at March 31, 2023, and $10.1 million of borrowing base availability and approximately $738.5 million of total liquidity including our cash position at June 30, 2022. This liquidity is more than adequate to meet ouroutstanding
Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
letters of credit under our $750 million senior secured bank credit facility, leaving us with $654.9 million of borrowing base availability. This liquidity is more than adequate to meet our currently planned operating and capital needs asneeds.
2023 Capital Expenditure Plans. Consistent with our original 2023 budget, we currently projectcontinue to estimate that our oil and natural gas development capital expenditures, excluding acquisitions and capitalized interest, will be in a range of $350 million to $370 million, and our CCUS capital expenditures will be in a range of $140 million to $160 million, for a total of $510 million at the combined midpoints. In addition to the Company’s budgeted capital expenditures, we expect to incur approximately $21 million for CCUS equity investments and approximately $36 million for plugging and abandonment costs. During the first half of 2023, we incurred $203.2 million of oil and natural gas development capital expenditures and $48.1 million of CCUS capital expenditures, or approximately 56% and 32% of our total annual budgets, respectively. During the first half of 2023, we also incurred $19.8 million of plugging and abandonment costs or approximately 55% of our 2023 expected costs.
Based on current projections, including estimated production costs, oil price differentials and other assumptions, we continue to anticipate that our 2023 cash flowflows from operations, to significantly exceedexcluding working capital changes, will approximate our plannedbudgeted capital expenditures and planned asset retirement obligation activities for the year, assuming oil prices of approximately $75 per Bbl in 2022. In early May 2022, we amended2023. We have more than adequate availability under our bank credit facility to amongcover any shortfall in operating cash flow relative to our 2023 capital expenditure plans, investments, and other things, increaseworking capital needs. In the borrowing base availabilityfourth quarter of 2023, we estimate a $65 million cash payment for withholding taxes for shares anticipated to be surrendered to the Company for post-emergence equity awards granted in December 2020 and lender commitmentsscheduled to $750 million (see further discussion of this amendment under Senior Secured Bank Credit Agreement below).be delivered to the recipients in December 2023.
Six Months EndedCapital Expenditure Summary. For purposes of tracking and comparing our capital budget to capital expenditure activity, we base those comparisons on when the capital expenditures are incurred, which is generally different than what is reported in our cash flow statements which reflect when cash is actually paid. The information included in the following table reflects our incurred capital expenditures:
| | | | | | | | | | | | | | |
| | Six Months Ended |
| | June 30, |
In thousands | | 2023 | | 2022 |
Capital expenditure summary(1) | | | | |
CCA EOR field expenditures(2) | | $ | 87,775 | | | $ | 39,205 | |
CCA CO2 pipelines | | 965 | | | 1,241 | |
CCA tertiary development | | 88,740 | | | 40,446 | |
Non-CCA tertiary and non-tertiary fields | | 92,988 | | | 86,437 | |
CO2 sources, other CO2 pipelines and other | | 3,306 | | | 2,110 | |
| | | | |
Capitalized internal costs(3) | | 18,152 | | | 14,903 | |
Oil and gas development capital expenditures | | 203,186 | | | 143,896 | |
CCUS storage sites and related capital expenditures | | 48,078 | | | 23,900 | |
Oil and gas and CCUS development capital expenditures | | 251,264 | | | 167,796 | |
Capitalized interest | | 3,952 | | | 2,133 | |
Acquisitions of oil and natural gas properties | | 42 | | | 374 | |
| | | | |
Equity investments(4) | | 19,034 | | | — | |
Total capital expenditures | | $ | 274,292 | | | $ | 170,303 | |
(1)Capital expenditures in this summary are presented on an as-incurred basis (including accruals) and are $10.4 million and $9.3 million lower than the capital expenditures in the Unaudited Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 2023 and 2022, Sources and Uses. respectively, which are presented on a cash basis.
(2)DuringIncludes pre-production CO2 costs associated with the CCA EOR development project totaling $9.3 million during the first half of 2022, we generated cash flows from operations of $240.12023 and $10.8 million while incurring capital costs of $169.9 million, consisting primarily of oil and gas development capital expenditures of $143.9 million, CCUS related capital expenditures of $23.9 million, and capitalized interest of $2.1 million. Duringduring the second quarter of 2022, the Company also repurchased 457,549 shares of Denbury common stock for $28.8 million, or $62.84 per share.
As further discussed below, based on oil price futures as of early August 2022, we currently anticipate funding all of our 2022 capital budget from projected operating cash flow while also generating excess cash flow. As the level of excess cash we expect to generate in 2022 and future periods has increased with the rise in oil prices during 2022, our Board of Directors adopted a share repurchase program in early May 2022 authorizing the repurchase of up to $250 million of Denbury’s common stock. Cumulatively through July 31, 2022, the Company repurchased 1,615,356 shares of Denbury common stock (approximately 3.2% of our outstanding shares of common stock at March 31, 2022) for approximately $100 million, or an average price of $61.92 per share. On August 2, 2022, the Board of Directors increased the dollar amount of Denbury common stock that can be purchased under the program to an aggregate of $350 million, and at that date, we were authorized to repurchase up to an additional $250.0 million of common stock. The ultimate level of excess cash we may generate in 2022 and future periods will be highly dependent on oil prices and many other factors, but we currently believe our level of cash flow generation will be adequate to fund our EOR and CCUS strategic priorities while also returning capital to our shareholders through our share repurchase program.
2022 Plans and Capital Budget. Based on inflationary cost increases and the desire to accelerate capital spending to offset potential supply chain delays, we are increasing our 2022 capital expenditures estimate for oil and gas development activities from the previously anticipated upper end of our range of $320 million to approximately $360 million. Approximatelyfirst half of the increase relates to overall service cost inflation impacting the Company’s operations, primarily related to labor and steel costs, and the rest of the increase is associated with CCA EOR development activities, where the Company is accelerating the purchase of compression equipment and construction of CO2 recycle facilities to ensure the field is ready to process the expected oil production response. In addition, anticipated spending for our CCUS business of approximately $50 million remains unchanged but could increase depending on activity levels in the second half of the year, with expenditures primarily focused on securing CO2 sequestration sites and drilling one or more stratigraphic test wells in those sequestration sites.
2022.
Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Capital Expenditure Summary. The following table reflects incurred capital expenditures for the six months ended June 30, 2022 and 2021:
| | | | | | | | | | | | | | |
| | Six Months Ended |
| | June 30, |
In thousands | | 2022 | | 2021 |
Capital expenditure summary(1) | | | | |
CCA EOR field expenditures(2) | | $ | 39,205 | | | $ | 9,100 | |
CCA CO2 pipelines | | 1,241 | | | 9,999 | |
CCA tertiary development | | 40,446 | | | 19,099 | |
Non-CCA tertiary and non-tertiary fields | | 86,437 | | | 40,297 | |
CO2 sources and other CO2 pipelines | | 2,110 | | | — | |
| | | | |
Capitalized internal costs(3) | | 14,903 | | | 14,785 | |
Oil & gas development capital expenditures | | 143,896 | | | 74,181 | |
CCUS storage sites and related capital expenditures | | 23,900 | | | — | |
Acquisitions of oil and natural gas properties(4) | | 374 | | | 10,811 | |
| | | | |
Capitalized interest | | 2,133 | | | 2,251 | |
Total capital expenditures | | $ | 170,303 | | | $ | 87,243 | |
(1)Capital expenditures in this summary are presented on an as-incurred basis (including accruals), and are $7.6 million lower than the capital expenditures in the Unaudited Condensed Consolidated Statements of Cash Flows which are presented on a cash basis.
(2)Includes pre-production CO2 costs associated with the CCA EOR development project totaling $10.8 million during the first half of 2022.
(3)Includes capitalized internal acquisition, exploration and development costs and pre-production tertiary startup costs.costs, excluding CCA.
(4)Primarily consists of working interest positionsRepresents investments made in carbon capture technology companies during the six months ended June 30, 2023, including a $2 million investment in Aqualung Carbon Capture AS, a $5 million investment in ION Clean Energy, Inc, a $1.5 million equity investment in Libra CO2 Storage Solutions, LLC, as well as an additional $10 million equity investment in Clean Hydrogen Works. The investments are included in “Other assets” in the Wind River Basin enhanced oil recovery fields acquired on March 3, 2021.Unaudited Condensed Consolidated Balance Sheet as of June 30, 2023.
Supply Chain Issues and Potential Cost Inflation. Recent worldwideWorldwide and U.S. supply chain issues, together with risinghigher commodity prices, power costs, service costs and tight labor markets in the U.S., have increased our costs during late 2021throughout 2022 and thus farcontinue to have ongoing impacts in 2022. Based on2023. Although the inflationary cost increases and shortages experienced across the industrysupply chain issues have begun to level off in certain areas, we still expect additional cost and higher fuel and power costs thus far in 2022, we anticipate additionaldemand increases in the costcertain categories of and demand for, goods, and services and wages in our operations during the remainder of 20222023, which could negatively impact our results of operations and cash flows in future periods. See Results of Operations – Production Expenses below for further discussion.
Senior Secured Bank Credit Agreement. In September 2020, we entered into a $575 million bank credit agreement for a senior secured revolving credit facility with JPMorgan Chase Bank, N.A., as administrative agent, and other lenders party thereto (the(as amended, the “Bank Credit Agreement”). The Bank Credit Agreement is a senior secured revolving credit facility with a maturity date of May 4, 2027. Under the Bank Credit Agreement, letters of credit are available in an aggregate amount not to exceed $100 million, and short-term swingline loans are available in an aggregate amount not to exceed $25 million, each subject to the available commitments under the Bank Credit Agreement. Availability under the Bank Credit Agreement is subject to a borrowing base, which is redetermined semiannually on or around May 1 orand November 1 of each year,year. As part of our Spring 2023 semiannual borrowing base redetermination, the borrowing base and lender commitments for our Bank Credit Agreement were reaffirmed at $750 million, with our next scheduled redetermination around November 1, 2022.2023. 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.
On May 4, 2022,January 20, 2023, we entered into a SecondThird Amendment to the Bank Credit Agreement, which among other things:
•Increasedtargeted at providing us the borrowing base and lender commitments from $575 millionability to $750 million;
•Extended the maturity date from January 30, 2024elect to May 4, 2027;
•Modified themake interest provisionspayments on loans under the Bank Credit Agreement to (1) reduce the applicable margin for alternate base rate loans from 2% to 3% per annum to 1.5% to 2.5% per annum and (2) replace provisions referencing LIBOR loans withcertain Secured Overnight Financing Rate (“SOFR”) loans with an applicable margin of 2.5% to 3.5% per annum; and
•Permitted us to pay dividends on our common stock and make other unlimited restricted payments and investments so long as (1) no event of default or borrowing base deficiency exists; (2) our total leverage ratio is 1.5 to 1 or lower; and (3) availability under the Bank Credit Agreement is at least 20% of the borrowing base.a weekly basis.
Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
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 certain customary exceptions to such limitations, as specified in the Bank Credit Agreement. Our Bank Credit Agreement required certain minimum commodity hedge levels in connection with our emergence from bankruptcy; however, these conditions were met as of December 31, 2020, and we currently have no ongoing hedging requirements under the Bank Credit Agreement.
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 June 30, 2022,2023, our ratio of consolidated total debt to consolidated EBITDAX was 0.000.15 to 1.0 (with a maximum permitted ratio of 3.5 to 1.0) and our current ratio was 2.702.79 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 August 3, 2022,1, 2023, and current oil commodity futures prices, we currently anticipate continuing to be in compliance with our financial performance covenants during the foreseeable future.
Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
The above description of our Bank Credit Agreement, is qualified by the express language andincluding certain referenced defined terms, is a summary of certain principal terms and conditions contained in the Bank Credit Agreement and amendments thereto, each of which is filed as an exhibit to our periodic reports filed with the Securities and Exchange Commission (“SEC”). The Second Amendment to the Credit Agreement, which is attached as Exhibit 10(d) to the Form 10-Q filed on May 6, 2022, contains the full text of the current version of the Bank Credit Agreement inclusive of all changes made by virtue of both the First and Second Amendments thereto.SEC.
Commitments, Obligations and Obligations.Off-Balance Sheet Arrangements. We haveincur numerous contractual commitments in the ordinary course of business including debt service requirements, operating 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 off-balance sheet arrangements include obligations for various development and exploratory expenditures that arise from our normal oil and natural gas or CCUS capital expenditure program or from other transactions common to our industry, none of which are recorded on our balance sheet. During 2022 and 2023, we entered into storage contracts to secure rights to underground pore space in anticipation of future CCUS operations. Noncancelable commitments under those contracts total $2.0 million as of June 30, 2023. 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.
Our commitments, obligations and obligations consist of those detailedoff-balance sheet arrangements as of December 31, 2021,2022, are detailed 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.
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
Financial and Operating Results Tables
Certain of our operating results and statistics for the comparative three and six months ended June 30, 20222023 and 20212022 are included in the following table:
| | | Three Months Ended | | Six Months Ended | | Three Months Ended | | Six Months Ended |
| | June 30, | | June 30 | | June 30, | | June 30 |
In thousands, except per-share and unit data | In thousands, except per-share and unit data | | 2022 | | 2021 | | 2022 | | 2021 | In thousands, except per-share and unit data | | 2023 | | 2022 | | 2023 | | 2022 |
Financial results | Financial results | | | | | | | | | Financial results | | | | | | | | |
Net income (loss)(1) | | $ | 155,494 | | | $ | (77,695) | | | $ | 154,622 | | | $ | (147,337) | | |
Net income (loss) per common share – basic(1) | | 3.00 | | | (1.52) | | | 2.99 | | | (2.91) | | |
Net income (loss) per common share – diluted(1) | | 2.83 | | | (1.52) | | | 2.81 | | | (2.91) | | |
Net income | | Net income | | $ | 67,281 | | | $ | 155,494 | | | $ | 156,480 | | | $ | 154,622 | |
Net income per common share – basic | | Net income per common share – basic | | 1.30 | | | 3.00 | | | 3.03 | | | 2.99 | |
Net income per common share – diluted | | Net income per common share – diluted | | 1.25 | | | 2.83 | | | 2.90 | | | 2.81 | |
Net cash provided by operating activities | Net cash provided by operating activities | | 149,965 | | | 90,882 | | 240,108 | | | 143,538 | Net cash provided by operating activities | | 142,491 | | | 149,965 | | 231,013 | | | 240,108 |
Average daily sales volumes | Average daily sales volumes | | | | | | | Average daily sales volumes | | | | | | |
Bbls/d | Bbls/d | | 45,104 | | | 47,653 | | | 45,284 | | | 46,834 | | Bbls/d | | 45,648 | | | 45,104 | | | 46,016 | | | 45,284 | |
Mcf/d | Mcf/d | | 8,741 | | | 8,882 | | | 8,747 | | | 8,494 | | Mcf/d | | 8,004 | | | 8,741 | | | 7,803 | | | 8,747 | |
BOE/d(2)(1) | BOE/d(2)(1) | | 46,561 | | | 49,133 | | | 46,742 | | | 48,250 | | BOE/d(2)(1) | | 46,982 | | | 46,561 | | | 47,317 | | | 46,742 | |
Oil and natural gas sales | Oil and natural gas sales | | | | | | | Oil and natural gas sales | | | | | | |
Oil sales | Oil sales | | $ | 446,592 | | | $ | 280,577 | | | $ | 827,834 | | | $ | 513,621 | | Oil sales | | $ | 301,543 | | | $ | 446,592 | | | $ | 614,115 | | | $ | 827,834 | |
Natural gas sales | Natural gas sales | | 5,378 | | | 2,131 | | | 9,047 | | | 4,532 | | Natural gas sales | | 1,403 | | | 5,378 | | | 3,320 | | | 9,047 | |
Total oil and natural gas sales | Total oil and natural gas sales | | $ | 451,970 | | | $ | 282,708 | | | $ | 836,881 | | | $ | 518,153 | | Total oil and natural gas sales | | $ | 302,946 | | | $ | 451,970 | | | $ | 617,435 | | | $ | 836,881 | |
Commodity derivative contracts(3)(2) | Commodity derivative contracts(3)(2) | | | | | | | | | Commodity derivative contracts(3)(2) | | | | | | | | |
Payment on settlements of commodity derivatives | | $ | (127,959) | | | $ | (63,343) | | | $ | (221,016) | | | $ | (101,796) | | |
Receipt (payment) on settlements of commodity derivatives | | Receipt (payment) on settlements of commodity derivatives | | $ | 5,157 | | | $ | (127,959) | | | $ | 7,222 | | | $ | (221,016) | |
Noncash fair value gains (losses) on commodity derivatives | Noncash fair value gains (losses) on commodity derivatives | | 71,105 | | | (109,321) | | | (28,557) | | | (186,611) | | Noncash fair value gains (losses) on commodity derivatives | | 14,520 | | | 71,105 | | | 35,578 | | | (28,557) | |
Commodity derivatives expense | | $ | (56,854) | | | $ | (172,664) | | | $ | (249,573) | | | $ | (288,407) | | |
Commodity derivatives income (expense) | | Commodity derivatives income (expense) | | $ | 19,677 | | | $ | (56,854) | | | $ | 42,800 | | | $ | (249,573) | |
Unit prices – excluding impact of derivative settlements | Unit prices – excluding impact of derivative settlements | | | | | | | | | Unit prices – excluding impact of derivative settlements | | | | | | | | |
Oil price per Bbl | Oil price per Bbl | | $ | 108.81 | | | $ | 64.70 | | | $ | 101.00 | | | $ | 60.59 | | Oil price per Bbl | | $ | 72.59 | | | $ | 108.81 | | | $ | 73.73 | | | $ | 101.00 | |
Natural gas price per Mcf | Natural gas price per Mcf | | 6.76 | | | 2.64 | | | 5.71 | | | 2.95 | | Natural gas price per Mcf | | 1.93 | | | 6.76 | | | 2.35 | | | 5.71 | |
Unit prices – including impact of derivative settlements(3)(2) | Unit prices – including impact of derivative settlements(3)(2) | | | | Unit prices – including impact of derivative settlements(3)(2) | | | |
Oil price per Bbl | Oil price per Bbl | | $ | 77.63 | | | $ | 50.10 | | | $ | 74.03 | | | $ | 48.58 | | Oil price per Bbl | | $ | 73.83 | | | $ | 77.63 | | | $ | 74.60 | | | $ | 74.03 | |
Natural gas price per Mcf | Natural gas price per Mcf | | 6.76 | | | 2.64 | | | 5.71 | | | 2.95 | | Natural gas price per Mcf | | 1.93 | | | 6.76 | | | 2.35 | | | 5.71 | |
Oil and natural gas operating expenses | Oil and natural gas operating expenses | | | | | | Oil and natural gas operating expenses | | | | | |
Lease operating expenses | Lease operating expenses | | $ | 124,351 | | | $ | 110,225 | | | $ | 242,179 | | | $ | 192,195 | | Lease operating expenses | | $ | 130,291 | | | $ | 124,351 | | | $ | 259,465 | | | $ | 242,179 | |
Transportation and marketing expenses | Transportation and marketing expenses | | 4,802 | | | 8,522 | | | 9,447 | | | 16,319 | | Transportation and marketing expenses | | 5,159 | | | 4,802 | | | 10,548 | | | 9,447 | |
Production and ad valorem taxes | Production and ad valorem taxes | | 35,570 | | | 21,836 | | | 66,013 | | | 39,731 | | Production and ad valorem taxes | | 26,193 | | | 35,570 | | | 54,456 | | | 66,013 | |
Oil and natural gas operating revenues and expenses per BOE | Oil and natural gas operating revenues and expenses per BOE | | | | | | Oil and natural gas operating revenues and expenses per BOE | | | | | |
Oil and natural gas revenues | Oil and natural gas revenues | | $ | 106.67 | | | $ | 63.23 | | | $ | 98.92 | | | $ | 59.33 | | Oil and natural gas revenues | | $ | 70.86 | | | $ | 106.67 | | | $ | 72.09 | | | $ | 98.92 | |
Lease operating expenses | Lease operating expenses | | 29.35 | | | 24.65 | | | 28.63 | | | 22.01 | | Lease operating expenses | | 30.48 | | | 29.35 | | | 30.30 | | | 28.63 | |
Transportation and marketing expenses | Transportation and marketing expenses | | 1.13 | | | 1.91 | | | 1.12 | | | 1.87 | | Transportation and marketing expenses | | 1.21 | | | 1.13 | | | 1.23 | | | 1.12 | |
Production and ad valorem taxes | Production and ad valorem taxes | | 8.40 | | | 4.88 | | | 7.80 | | | 4.55 | | Production and ad valorem taxes | | 6.13 | | | 8.40 | | | 6.36 | | | 7.80 | |
CO2 – revenues and expenses | CO2 – revenues and expenses | | | | | | | CO2 – revenues and expenses | | | | | | |
CO2 sales and transportation fees | CO2 sales and transportation fees | | $ | 12,610 | | | $ | 10,134 | | | $ | 26,032 | | | $ | 19,362 | | CO2 sales and transportation fees | | $ | 11,164 | | | $ | 12,610 | | | $ | 21,850 | | | $ | 26,032 | |
CO2 operating and discovery expenses | CO2 operating and discovery expenses | | (1,681) | | | (1,531) | | | (4,498) | | | (2,524) | | CO2 operating and discovery expenses | | (1,597) | | | (1,681) | | | (2,793) | | | (4,498) | |
CO2 revenue and expenses, net | CO2 revenue and expenses, net | | $ | 10,929 | | | $ | 8,603 | | | $ | 21,534 | | | $ | 16,838 | | CO2 revenue and expenses, net | | $ | 9,567 | | | $ | 10,929 | | | $ | 19,057 | | | $ | 21,534 | |
(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.
(2)Barrel of oil equivalent using the ratio of one barrel of oil to six Mcf of natural gas (“BOE”).
(3)(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 20212022 and for the first and second quarters of 2022 is2023 are shown below:
| | | | Average Daily Sales Volumes (BOE/d) | | | Average Daily Sales Volumes (BOE/d) |
| | Second Quarter | | | First Quarter | | | Fourth Quarter | | Third Quarter | | Second Quarter | | First Quarter | | Second Quarter | | | First Quarter | | | Fourth Quarter | | Third Quarter | | Second Quarter | | First Quarter |
Operating Area | Operating Area | | 2022 | | | 2022 | | | 2021 | | 2021 | | 2021 | | 2021 | Operating Area | | 2023 | | | 2023 | | | 2022 | | 2022 | | 2022 | | 2022 |
Tertiary oil sales volumes | Tertiary oil sales volumes | | | | | | | | | | | | | | | Tertiary oil sales volumes | | | | | | | | | | | | | | |
Gulf Coast region | Gulf Coast region | | | | | | Gulf Coast region | | | | | |
Delhi | Delhi | | 2,478 | | | | 2,675 | | | | 2,731 | | | 2,859 | | | 2,931 | | | 2,925 | | Delhi | | 2,151 | | | | 2,514 | | | | 2,528 | | | 2,557 | | | 2,478 | | | 2,675 | |
Hastings | Hastings | | 4,304 | | | | 4,430 | | | | 4,212 | | | 4,343 | | | 4,487 | | | 4,226 | | Hastings | | 4,502 | | | | 4,450 | | | | 4,198 | | | 4,211 | | | 4,304 | | | 4,430 | |
Heidelberg | Heidelberg | | 3,528 | | | | 3,653 | | | | 3,797 | | | 3,895 | | | 3,942 | | | 4,054 | | Heidelberg | | 3,481 | | | | 3,539 | | | | 3,670 | | | 3,571 | | | 3,528 | | | 3,653 | |
Oyster Bayou | Oyster Bayou | | 3,423 | | | | 3,745 | | | | 4,039 | | | 3,942 | | | 3,791 | | | 3,554 | | Oyster Bayou | | 3,615 | | | | 3,832 | | | | 3,417 | | | 3,490 | | | 3,423 | | | 3,745 | |
Tinsley | Tinsley | | 3,050 | | | | 3,015 | | | | 3,353 | | | 3,390 | | | 3,455 | | | 3,424 | | Tinsley | | 2,686 | | | | 3,205 | | | | 2,248 | | | 3,133 | | | 3,050 | | | 3,015 | |
Other(1) | Other(1) | | 5,422 | | | | 5,498 | | | | 5,801 | | | 5,907 | | | 6,074 | | | 6,098 | | Other(1) | | 5,606 | | | | 5,585 | | | | 5,652 | | | 5,541 | | | 5,422 | | | 5,498 | |
Total Gulf Coast region | Total Gulf Coast region | | 22,205 | | | | 23,016 | | | | 23,933 | | | 24,336 | | | 24,680 | | | 24,281 | | Total Gulf Coast region | | 22,041 | | | | 23,125 | | | | 21,713 | | | 22,503 | | | 22,205 | | | 23,016 | |
Rocky Mountain region | Rocky Mountain region | | | | | | | | | | | | | | | Rocky Mountain region | | | | | | | | | | | | | | |
Bell Creek | Bell Creek | | 4,122 | | | | 4,474 | | | | 4,331 | | | 4,330 | | | 4,394 | | | 4,614 | | Bell Creek | | 3,300 | | | | 3,808 | | | | 3,767 | | | 3,975 | | | 4,122 | | | 4,474 | |
Wind River Basin | | Wind River Basin | | 3,866 | | | | 3,872 | | | | 3,726 | | | 3,121 | | | 2,703 | | | 2,517 | |
Cedar Creek Anticline | | Cedar Creek Anticline | | 574 | | | | — | | | | — | | | — | | | — | | | — | |
Other(2) | Other(2) | | 5,064 | | | | 4,746 | | | | 4,551 | | | 4,703 | | | 4,378 | | | 2,573 | | Other(2) | | 2,501 | | | | 2,744 | | | | 2,824 | | | 2,759 | | | 2,361 | | | 2,229 | |
Total Rocky Mountain region | Total Rocky Mountain region | | 9,186 | | | | 9,220 | | | | 8,882 | | | 9,033 | | | 8,772 | | | 7,187 | | Total Rocky Mountain region | | 10,241 | | | | 10,424 | | | | 10,317 | | | 9,855 | | | 9,186 | | | 9,220 | |
Total tertiary oil sales volumes | Total tertiary oil sales volumes | | 31,391 | | | | 32,236 | | | | 32,815 | | | 33,369 | | | 33,452 | | | 31,468 | | Total tertiary oil sales volumes | | 32,282 | | | | 33,549 | | | | 32,030 | | | 32,358 | | | 31,391 | | | 32,236 | |
Non-tertiary oil and gas sales volumes | Non-tertiary oil and gas sales volumes | | | | | | | | | | | | | | | Non-tertiary oil and gas sales volumes | | | | | | | | | | | | | | |
Gulf Coast region | Gulf Coast region | | | | | | Gulf Coast region | | | | | |
Total Gulf Coast region | Total Gulf Coast region | | 3,566 | | | | 3,630 | | | | 3,929 | | | 3,763 | | | 3,415 | | | 3,621 | | Total Gulf Coast region | | 3,506 | | | | 3,398 | | | | 3,666 | | | 3,727 | | | 3,566 | | | 3,630 | |
Rocky Mountain region | Rocky Mountain region | | | | | | | | | | | | | | | Rocky Mountain region | | | | | | | | | | | | | | |
Cedar Creek Anticline | Cedar Creek Anticline | | 10,224 | | | | 9,721 | | | | 10,784 | | | 11,182 | | | 10,918 | | | 11,150 | | Cedar Creek Anticline | | 9,661 | | | | 9,316 | | | | 9,366 | | | 9,593 | | | 10,224 | | | 9,721 | |
Other(3) | Other(3) | | 1,380 | | | | 1,338 | | | | 1,354 | | | 1,368 | | | 1,348 | | | 1,118 | | Other(3) | | 1,533 | | | | 1,392 | | | | 1,579 | | | 1,431 | | | 1,380 | | | 1,338 | |
Total Rocky Mountain region | Total Rocky Mountain region | | 11,604 | | | | 11,059 | | | | 12,138 | | | 12,550 | | | 12,266 | | | 12,268 | | Total Rocky Mountain region | | 11,194 | | | | 10,708 | | | | 10,945 | | | 11,024 | | | 11,604 | | | 11,059 | |
Total non-tertiary sales volumes | Total non-tertiary sales volumes | | 15,170 | | | | 14,689 | | | | 16,067 | | | 16,313 | | | 15,681 | | | 15,889 | | Total non-tertiary sales volumes | | 14,700 | | | | 14,106 | | | | 14,611 | | | 14,751 | | | 15,170 | | | 14,689 | |
| Total sales volumes | Total sales volumes | | 46,561 | | | | 46,925 | | | | 48,882 | | | 49,682 | | | 49,133 | | | 47,357 | | Total sales volumes | | 46,982 | | | | 47,655 | | | | 46,641 | | | 47,109 | | | 46,561 | | | 46,925 | |
(1)Includes Brookhaven, Cranfield, Eucutta, Little Creek, Mallalieu, Martinville, McComb, Soso, and West Yellow Creek fields.
(2)Includes tertiary sales volumes related to our working interest positions in the Big Sand Draw and Beaver Creek EOR fields (collectively “Wind River Basin”) acquired on March 3, 2021, as well as Salt Creek and Grieve fields.
(3)Includes non-tertiary sales volumes from Wind River Basin, as well as Hartzog Draw and Bell Creek fields.
Total sales volumes during the second quarter of 20222023 averaged 46,56146,982 BOE/d, including 31,391 Bbls/ddown approximately 1% from tertiary properties and 15,170 BOE/d from non-tertiary properties. This sales volume was relatively flat withthe first quarter of 20222023. Compared to the first quarter of 2023, the decrease in sales volumes as sales volume increaseswas primarily driven by anticipated declines at CCA, Wind River Basin (262 BOE/d increase)Tinsley and GrieveDelhi fields, (297 BOE/d increase) in the Rocky Mountain region were offset by declines across various fields, with the largest declinesand higher than anticipated downtime at Bell Creek and Oyster Bayoufield, offset in part by increases in CCA tertiary volumes in the second quarter due to downtime relatedinitial tertiary production commencing during the quarter. The anticipated sales volume decline at Tinsley field was due to compressor and workover activities. On a year-over-year basis,first quarter 2023 sales volumes decreased 2,572 BOE/d (5%)including higher than normal inventory sale volumes due to inventory built in the fourth quarter of 2022, and the decline at Delhi field was due to scheduled facility downtime. Second quarter 2023 sales volumes increased slightly compared to sales levels in the second quarter of 2021 primarily attributable2022, due to low levels of capital investment and development spending in recent years (excluding the new EORadditional development at CCA). We currently expect sales volumes during the third quarter of 2022Wind River Basin and initial tertiary production at CCA, partially offset by the reduction in non-tertiary production at CCA primarily due to be consistent with the second quarter of 2022curtailed production stemming from CO2 development activities, and sales volumes to increase during the fourth quarter of 2022, as a result of incremental production increases from development projects completed in the first half of the year.downtime and natural decline at Bell Creek Field.
Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Our sales volumes during the three and six months ended June 30, 20222023 were 97% oil, consistent with our sales during the comparable prior-year periods.
Oil and Natural Gas Revenues
Our oil and natural gas revenues during the three and six months ended June 30, 2022 increased 60%2023 decreased 33% and 62%26%, respectively, compared to these revenues for the same periods in 2021.2022. The changes in our oil and natural gas revenues are due to higherlower realized commodity prices (excluding any impact of our commodity derivative contracts), as reflected in the following table:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended | | Six Months Ended |
| | June 30, | | June 30, |
| | 2022 vs. 2021 | | 2022 vs. 2021 |
In thousands | | Increase (Decrease) in Revenues | | Percentage Increase (Decrease) in Revenues | | Increase (Decrease) in Revenues | | Percentage Increase (Decrease) in Revenues |
Change in oil and natural gas revenues due to: | | | | | | | | |
Decrease in sales volumes | | $ | (14,799) | | | (5) | % | | $ | (16,191) | | | (3) | % |
Increase in realized commodity prices | | 184,061 | | | 65 | % | | 334,919 | | | 65 | % |
Total increase in oil and natural gas revenues | | $ | 169,262 | | | 60 | % | | $ | 318,728 | | | 62 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended | | Six Months Ended |
| | June 30, | | June 30, |
| | 2023 vs. 2022 | | 2023 vs. 2022 |
In thousands | | Increase (Decrease) in Revenues | | Percentage Increase (Decrease) in Revenues | | Increase (Decrease) in Revenues | | Percentage Increase (Decrease) in Revenues |
Change in oil and natural gas revenues due to: | | | | | | | | |
Increase in sales volumes | | $ | 4,083 | | | 1 | % | | $ | 10,287 | | | 1 | % |
Decrease in realized commodity prices | | (153,107) | | | (34) | % | | (229,733) | | | (27) | % |
Total decrease in oil and natural gas revenues | | $ | (149,024) | | | (33) | % | | $ | (219,446) | | | (26) | % |
Excluding any impact of our commodity derivative contracts, our average net realized commodity prices and NYMEX differentials were as follows during the three months ended March 31, 20222023 and 20212022 and the three and six months ended June 30, 20222023 and 2021:2022:
| | | Three Months Ended | | Three Months Ended | | | Six Months Ended | | Three Months Ended | | | Six Months Ended |
| | March 31, | | June 30, | | | June 30, | | June 30, | | March 31, | | | June 30, |
| | | 2022 | | 2021 | | 2022 | | 2021 | | | 2022 | | 2021 | | | 2023 | | 2022 | | 2023 | | 2022 | | | 2023 | | 2022 |
Average net realized prices | Average net realized prices | | | | | | | | | | | | | | Average net realized prices | | | | | | | | | | | | | |
Oil price per Bbl | Oil price per Bbl | | $ | 93.17 | | | $ | 56.28 | | | $ | 108.81 | | | $ | 64.70 | | | | $ | 101.00 | | | $ | 60.59 | | Oil price per Bbl | | $ | 72.59 | | | $ | 108.81 | | | $ | 74.87 | | | $ | 93.17 | | | | $ | 73.73 | | | $ | 101.00 | |
Natural gas price per Mcf | Natural gas price per Mcf | | 4.66 | | | 3.29 | | | 6.76 | | | 2.64 | | | | 5.71 | | | 2.95 | | Natural gas price per Mcf | | 1.93 | | | 6.76 | | | 2.80 | | | 4.66 | | | | 2.35 | | | 5.71 | |
Price per BOE | Price per BOE | | 91.14 | | | 55.24 | | | 106.67 | | | 63.23 | | | | 98.92 | | | 59.33 | | Price per BOE | | 70.86 | | | 106.67 | | | 73.32 | | | 91.14 | | | | 72.09 | | | 98.92 | |
Average NYMEX differentials | Average NYMEX differentials | | | | | | | | | | | | Average NYMEX differentials | | | | | | | | | | | | |
Gulf Coast region | Gulf Coast region | | | | Gulf Coast region | | | |
Oil per Bbl | Oil per Bbl | | $ | (1.37) | | | $ | (1.37) | | | $ | 0.16 | | | $ | (1.13) | | | | $ | (0.72) | | | $ | (1.23) | | Oil per Bbl | | $ | (0.92) | | | $ | 0.16 | | | $ | (1.29) | | | $ | (1.37) | | | | $ | (1.08) | | | $ | (0.72) | |
Natural gas per Mcf | Natural gas per Mcf | | 0.16 | | | 0.68 | | | 0.02 | | | (0.11) | | | | 0.01 | | | 0.30 | | Natural gas per Mcf | | (0.30) | | | 0.02 | | | (0.05) | | | 0.16 | | | | (0.15) | | | 0.01 | |
Rocky Mountain region | Rocky Mountain region | | | | Rocky Mountain region | | | |
Oil per Bbl | Oil per Bbl | | $ | (1.38) | | | $ | (1.80) | | | $ | 0.01 | | | $ | (1.59) | | | | $ | (0.59) | | | $ | (1.54) | | Oil per Bbl | | $ | (1.41) | | | $ | 0.01 | | | $ | (1.28) | | | $ | (1.38) | | | | $ | (1.35) | | | $ | (0.59) | |
Natural gas per Mcf | Natural gas per Mcf | | 0.08 | | | 0.49 | | | (1.12) | | | (0.47) | | | | (0.49) | | | (0.04) | | Natural gas per Mcf | | (0.42) | | | (1.12) | | | 0.04 | | | 0.08 | | | | (0.22) | | | (0.49) | |
Total Company | Total Company | | | | Total Company | | | |
Oil per Bbl | Oil per Bbl | | $ | (1.37) | | | $ | (1.54) | | | $ | 0.09 | | | $ | (1.32) | | | | $ | (0.67) | | | $ | (1.36) | | Oil per Bbl | | $ | (1.14) | | | $ | 0.09 | | | $ | (1.28) | | | $ | (1.37) | | | | $ | (1.20) | | | $ | (0.67) | |
Natural gas per Mcf | Natural gas per Mcf | | 0.11 | | | 0.58 | | | (0.71) | | | (0.33) | | | | (0.31) | | | 0.11 | | Natural gas per Mcf | | (0.39) | | | (0.71) | | | 0.01 | | | 0.11 | | | | (0.20) | | | (0.31) | |
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.
•COGulf Coast Region2. Our average NYMEX oil differential in Revenues and Expenses
We sell a portion of the Gulf Coast region was a positive $0.16 per Bbl duringCO2 we produce from Jackson Dome to third-party industrial users at various contracted prices primarily under long-term contracts. We recognize the second quarter of 2022, an improvement compared to a negative $1.13 per Bbl during the second quarter of 2021revenue received on these CO2 sales as “CO2 sales and a negative $1.37 per Bbl during the first quarter of 2022. During the second quarter of 2022, the Companytransportation
Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
modified certain of its sales contracts and benefited from improved pricing for its Gulf Coast grades relative to NYMEX WTI prices.
•Rocky Mountain Region. NYMEX oil differentials in the Rocky Mountain region were essentially flat with NYMEX WTI prices during the second quarter of 2022, compared to $1.59 per Bbl below NYMEX during the second quarter of 2021 and $1.38 per Bbl below NYMEX during the first quarter of 2022. Similar to our differentials in the Gulf Coast region, differentials in the Rocky Mountain region improved significantly during the second quarter of 2022 as regional demand for our Rockies crude was strong. 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 a portion of the CO2 we own 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 $11.2 million and $21.9 million during the three and six months ended June 30, 2023, respectively, compared to $12.6 million and $26.0 million during the three and six months ended June 30, 2022, respectively, compared to $10.1 million and $19.4 million during the three and six-month periods ended June 30, 2021, respectively. The increases from the prior-year periods were primarily due to new contracts and an increasedecrease in CO2 sales volumes.and transportation fees from the prior-year periods is primarily due to a short-term contract in place in 2022 as well as unplanned downtime of third-party purchasers.
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
We have routinely entered 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. These contracts currently consist of fixed-price swaps and costless collars. The following table summarizes the impact our crude oil derivative contracts had on our operating results for the three and six months ended June 30, 20222023 and 2021:2022:
| | | Three Months Ended | | Six Months Ended | | Three Months Ended | | Six Months Ended |
| | | June 30, | | June 30, | | | June 30, | | June 30, |
In thousands | In thousands | | 2022 | | 2021 | | 2022 | | 2021 | In thousands | | 2023 | | 2022 | | 2023 | | 2022 |
Payment on settlements of commodity derivatives | | $ | (127,959) | | | $ | (63,343) | | | $ | (221,016) | | | $ | (101,796) | | |
Receipt (payment) on settlements of commodity derivatives | | Receipt (payment) on settlements of commodity derivatives | | $ | 5,157 | | | $ | (127,959) | | | $ | 7,222 | | | $ | (221,016) | |
Noncash fair value gains (losses) on commodity derivatives | Noncash fair value gains (losses) on commodity derivatives | | 71,105 | | | (109,321) | | | (28,557) | | | (186,611) | | Noncash fair value gains (losses) on commodity derivatives | | 14,520 | | | 71,105 | | | 35,578 | | | (28,557) | |
Total expense | | $ | (56,854) | | | $ | (172,664) | | | $ | (249,573) | | | $ | (288,407) | | |
Total income (expense) | | Total income (expense) | | $ | 19,677 | | | $ | (56,854) | | | $ | 42,800 | | | $ | (249,573) | |
Commodity derivatives income (expense) is comprised of (1) payments or receipts on settlements of commodity derivatives and (2) noncash changes in the fair values of commodity derivatives. Changes in ourthe fair values of commodity derivatives expense are relateddue to changes in oil futures prices since the prior period or subsequent to entering into new derivative agreements. During the first half of 2023, we received $7.2 million upon expiration of commodity derivative contracts, changes in oil futures prices between the second quartercompared to cash payments upon settlement of 2021 and 2022, and new commodity derivative contract commitments for future periods. During$221.0 million during the first half of 2022, we paid $221.0 million upon settlement of commodity derivative contracts, corresponding with the large increase in oil prices and the Company’s oil revenues during that same period.2022.
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 20232024 using NYMEX fixed-price swaps and costless collars. Upon emergence from bankruptcy in September 2020, we were required to hedge through mid-2022 at certain levels of estimated production under our post-emergence bank credit facility. Those hedges resulted in significant cash losses to us during 2022 as oil prices subsequently improved beyond our hedged prices. We no longer have any hedging requirements under our bank credit facility; however, we plan to continue to hedge a portion of our production in order to provide a level of certainty in our cash flows. See Note 7, Commodity Derivative Contracts, to the Unaudited Condensed Consolidated Financial Statements for additional details of our outstanding commodity derivative contracts as of June 30, 2023, 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 August 1, 2023:
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | 2H 2023 | | 1H 2024 | | 2H 2024 |
WTI NYMEX | Volumes Hedged (Bbls/d) | | | | 18,000 | | 17,000 | | 2,000 |
Fixed-Price Swaps | Weighted Average Swap Price | | | | $78.51 | | $75.02 | | $75.75 |
WTI NYMEX | Volumes Hedged (Bbls/d) | | | | 9,000 | | — | | — |
Collars | Weighted Average Floor / Ceiling Price | | | | $68.33 / $100.69 | | — | | — |
| Total Volumes Hedged (Bbls/d) | | | | 27,000 | | 17,000 | | 2,000 |
Based on current contracts in place and NYMEX oil futures prices as of August 1, 2023, which averaged approximately $81 per Bbl for the remainder of 2023, we currently expect that we would make cash payments of approximately $5 million during 2023 upon settlement of these contracts, the amount of which is primarily dependent upon fluctuations in future NYMEX oil prices in relation to the prices of our 2023 fixed-price swaps (which have a weighted average NYMEX oil price of $78.12 per Bbl). Changes in commodity prices, expiration of contracts, and new commodity contracts entered into cause
Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
derivative contracts as of June 30, 2022, 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 August 3, 2022:
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | 2H 2022 | | 1H 2023 | | 2H 2023 |
WTI NYMEX | Volumes Hedged (Bbls/d) | | | | 9,500 | | 4,500 | | 2,000 |
Fixed-Price Swaps | Weighted Average Swap Price | | | | $57.52 | | $74.88 | | $76.80 |
WTI NYMEX | Volumes Hedged (Bbls/d) | | | | 11,500 | | 17,500 | | 9,000 |
Collars | Weighted Average Floor / Ceiling Price | | | | $52.39 / $67.29 | | $69.71 / $100.42 | | $68.33 / $100.69 |
| Total Volumes Hedged (Bbls/d) | | | | 21,000 | | 22,000 | | 11,000 |
Based on current contracts in place and NYMEX oil futures prices as of August 3, 2022, which averaged approximately $89 per Bbl, we currently expect that we would make cash payments of approximately $115 million upon settlement of our July through December 2022 contracts, the amount of which is primarily dependent upon fluctuations in future NYMEX oil prices in relation to the prices of our remaining 2022 fixed-price swaps which have a weighted average NYMEX oil price of $57.52 per Bbl and weighted average ceiling prices of our 2022 collars of $67.29 per Bbl. Changes in commodity prices, expiration of contracts, and new commodity contract commitments 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
| | | Three Months Ended | | Six Months Ended | | Three Months Ended | | Six Months Ended |
| | June 30, | | June 30, | | June 30, | | June 30, |
In thousands, except per-BOE data | In thousands, except per-BOE data | | 2022 | | 2021 | | 2022 | | 2021 | In thousands, except per-BOE data | | 2023 | | 2022 | | 2023 | | 2022 |
Total lease operating expenses | Total lease operating expenses | | $ | 124,351 | | | $ | 110,225 | | | $ | 242,179 | | | $ | 192,195 | | Total lease operating expenses | | $ | 130,291 | | | 124,351 | | | $ | 259,465 | | | $ | 242,179 | |
| Total lease operating expenses per BOE | Total lease operating expenses per BOE | | $ | 29.35 | | | $ | 24.65 | | | $ | 28.63 | | | $ | 22.01 | | Total lease operating expenses per BOE | | $ | 30.48 | | | $ | 29.35 | | | $ | 30.30 | | | $ | 28.63 | |
TotalTotal lease operating expenses increased $14.1$5.9 million (13%(5%) and $50.0 $17.3 million (26%(7%) on an absolute-dollar basis, or $4.70 (19%$1.13 (4%) and $6.62 (30%$1.67 (6%) on a per-BOE basis, during the three and six months ended June 30, 2022,2023, respectively, compared to the same prior-year periods. The increasesincrease on an absolute-dollar and per-BOE basis during the three months ended June 30, 2023 was primarily due to the absence in the 2023 period of a $6.7 million insurance reimbursement received during the three months ended June 30, 2022 were primarily due related to increases of $6.5 million in power and fuel costs, $4.6 million in workovers, $2.8 million in labor costs, and $2.4 million in CO2 expense, partially offset by an insurance reimbursement totaling $6.7 million recorded for property damage costs incurred during 2013 at Delhi Field. TheAlso, lower power and fuel costs benefited the second quarter of 2023 when compared to the same 2022 period, partially offset by higher labor and repair and maintenance costs due to inflation and higher activity levels. In addition to the fluctuations noted above, the comparative increase in lease operating expenses during the six months ended June 30, 2023 and 2022 was further impacted by (a) a benefitinclude first quarter 2023 comparative increases in labor and repair and maintenance costs as well as higher workover and CO2 costs. The increase to CO2 costs is largely the result of $16.3 million during the six months ended June 30, 2021 resulting from compensation under the Company’s power agreements for power interruption during the severe winter storm in February 2021 which related to power outages in Texas and disrupted the Company’s operations and (b) an additional $9.5 million of expense as the 2022 period reflects an entire six month’s worth of lease operating expenses from our March 2021 acquisition of Wind River Basin properties. industrial contract change.
Compared to the first quarter of 20222023, lease operating expenses in the most recent quarter increased $6.5$1.1 million (6%(1%) on an absolute-dollar basis and $1.45 (5%$0.36 (1%) on a per-BOE basis, due primarily to higher workover, labor costs, CO2 expense, and power and fuel costs, partially offset by the insurance reimbursement discussed above.other costs.
Transportation and Marketing Expenses
Transportation and marketing expenses primarily consist of amounts incurred relatingrelated to the transportation, marketing, and processing of oil and natural gas production. Transportation and marketing expenses were $4.8$5.2 million and $8.5$4.8 million for the three months ended June 30, 20222023 and 2021,2022, respectively, and $9.4$10.5 million and $16.3$9.4 million for the six months ended June 30, 20222023 and 2021,2022, respectively. The decreases during the most recent comparative three and six-month periodsincreases were primarily due to a change in the sales contracts of certain of our sales contracts.
Taxes Other Than Income
Taxes other than income includes production, which reduced our transportation expense.ad valorem and franchise taxes. Taxes other than income decreased $9.4 million (26%) and $11.7 million (17%) during the three and six months ended June 30, 2023, respectively, compared to the same prior-year periods, due primarily to a decrease in production taxes resulting from lower oil and natural gas revenues.
Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Taxes Other Than Income
Taxes other than income includes production, ad valorem and franchise taxes. Taxes other than income increased $13.9 million (62%) and $26.4 million (64%) during the three and six months ended June 30, 2022, respectively, compared to the same prior-year periods, due primarily to an increase in production taxes resulting from higher oil and natural gas revenues.
General and Administrative Expenses (“G&A”)
| | | Three Months Ended | | Six Months Ended | | Three Months Ended | | Six Months Ended |
| | June 30, | | June 30, | | June 30, | | June 30, |
In thousands, except per-BOE data and employees | In thousands, except per-BOE data and employees | | 2022 | | 2021 | | 2022 | | 2021 | In thousands, except per-BOE data and employees | | 2023 | | 2022 | | 2023 | | 2022 |
Cash G&A costs | Cash G&A costs | | $ | 15,131 | | | $ | 12,898 | | | $ | 30,852 | | | $ | 27,201 | | Cash G&A costs | | $ | 20,347 | | | $ | 15,131 | | | $ | 38,386 | | | $ | 30,852 | |
Stock-based compensation | Stock-based compensation | | 4,104 | | | 2,552 | | | 7,075 | | | 20,232 | | Stock-based compensation | | 6,548 | | | 4,104 | | | 11,486 | | | 7,075 | |
G&A expense | G&A expense | | $ | 19,235 | | | $ | 15,450 | | | $ | 37,927 | | | $ | 47,433 | | G&A expense | | $ | 26,895 | | | $ | 19,235 | | | $ | 49,872 | | | $ | 37,927 | |
| G&A per BOE | G&A per BOE | | | | G&A per BOE | | | |
Cash G&A costs | Cash G&A costs | | $ | 3.57 | | | $ | 2.89 | | | $ | 3.65 | | | $ | 3.11 | | Cash G&A costs | | $ | 4.76 | | | $ | 3.57 | | | $ | 4.48 | | | $ | 3.65 | |
Stock-based compensation | Stock-based compensation | | 0.97 | | | 0.57 | | | 0.83 | | | 2.32 | | Stock-based compensation | | 1.53 | | | 0.97 | | | 1.34 | | | 0.83 | |
G&A expenses | G&A expenses | | $ | 4.54 | | | $ | 3.46 | | | $ | 4.48 | | | $ | 5.43 | | G&A expenses | | $ | 6.29 | | | $ | 4.54 | | | $ | 5.82 | | | $ | 4.48 | |
| Employees as of period end | Employees as of period end | | 740 | | 690 | | | Employees as of period end | | 793 | | 740 | | |
Our G&A expense on an absolute-dollar basis was $19.2$26.9 million during the three months ended June 30, 2022,2023, an increase of $3.8$7.7 million from the same prior-year period, primarily due to higher employee-related costs, ($1.6 million for stock-based compensation)including salaries and higher professional service fees.stock compensation expense. During the six months ended June 30, 2022, our2023, G&A expense decreased $9.5on an absolute-dollar basis was $49.9 million, an increase of $11.9 million when compared to the same prior-year period, also primarily due to a decrease in stock-based compensation as the six months ended June 30, 2021 included $15.3 million of stock-based compensation expense in the first quarter of 2021 resulting from the accelerated performance achievement and vesting of performance-based equity awards granted in late 2020, partially offset by higher employee-related costs, including salaries and professional service fees.stock compensation expense.
Interest and Financing Expenses
| | | Three Months Ended | | Six Months Ended | | Three Months Ended | | Six Months Ended |
| | June 30, | | June 30, | | June 30, | | June 30, |
In thousands, except per-BOE data and interest rates | In thousands, except per-BOE data and interest rates | | 2022 | | 2021 | | 2022 | | 2021 | In thousands, except per-BOE data and interest rates | | 2023 | | 2022 | | 2023 | | 2022 |
Cash interest(1) | Cash interest(1) | | $ | 1,252 | | | $ | 1,735 | | | $ | 2,382 | | | $ | 3,669 | | Cash interest(1) | | $ | 2,553 | | | $ | 1,252 | | | $ | 4,641 | | | $ | 2,382 | |
| Noncash interest expense | Noncash interest expense | | 1,249 | | | 685 | | | 1,934 | | | 1,370 | | Noncash interest expense | | 531 | | | 1,249 | | | 1,063 | | | 1,934 | |
| Less: capitalized interest | Less: capitalized interest | | (975) | | | (1,168) | | | (2,133) | | | (2,251) | | Less: capitalized interest | | (2,259) | | | (975) | | | (3,952) | | | (2,133) | |
Interest expense, net | Interest expense, net | | $ | 1,526 | | | $ | 1,252 | | | $ | 2,183 | | | $ | 2,788 | | Interest expense, net | | $ | 825 | | | $ | 1,526 | | | $ | 1,752 | | | $ | 2,183 | |
Interest expense, net per BOE | Interest expense, net per BOE | | $ | 0.36 | | | $ | 0.28 | | | $ | 0.26 | | | $ | 0.32 | | Interest expense, net per BOE | | $ | 0.19 | | | $ | 0.36 | | | $ | 0.20 | | | $ | 0.26 | |
Average debt principal outstanding | Average debt principal outstanding | | $ | 29,088 | | | $ | 107,542 | | | $ | 31,669 | | | $ | 121,392 | | Average debt principal outstanding | | $ | 89,291 | | | $ | 29,088 | | | $ | 75,893 | | | $ | 31,669 | |
Average cash interest rate(2) | Average cash interest rate(2) | | 6.0 | % | | 4.2 | % | | 5.7 | % | | 4.1 | % | Average cash interest rate(2) | | 7.8 | % | | 6.0 | % | | 7.8 | % | | 5.7 | % |
(1)Includes commitment fees paid on the Company’s bank credit facility but excludes debt issue costs.
(2)Excludes commitmentcommitment fees paid on the Company’s bank credit facility and debt issue costs.
Cash interest during the three and six months ended June 30, 2022 decreased $0.52023 increased $1.3 million (28%(104%) and $1.3$2.3 million (35%(95%) when compared to the same prior-year periods. The decreasesincreases between periods were primarily due to repayment of our pipeline financings in October 2021 and a decreasean increase in the average principal outstanding on our senior secured bank credit facility. The
Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
increase decrease in noncash interest expense during the three and six months ended June 30, 2022,2023, compared to the same prior-year periods, was due to a write-off of debt issuance costs related to lenders who exited our senior secured bank credit facility in conjunction with our May 2022 amendment.
Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Depletion, Depreciation, and Amortization (“DD&A”)
| | | Three Months Ended | | Six Months Ended | | | Three Months Ended | | Six Months Ended | |
| | June 30, | | June 30, | | | June 30, | | June 30, | |
In thousands, except per-BOE data | In thousands, except per-BOE data | | 2022 | | 2021 | | 2022 | | 2021 | | In thousands, except per-BOE data | | 2023 | | 2022 | | 2023 | | 2022 | |
Oil and natural gas properties | Oil and natural gas properties | | $ | 29,084 | | | $ | 28,550 | | | $ | 57,752 | | | $ | 60,565 | | | Oil and natural gas properties | | $ | 42,652 | | | $ | 29,084 | | | $ | 76,851 | | | $ | 57,752 | | |
CO2 properties, pipelines, plants and other property and equipment | CO2 properties, pipelines, plants and other property and equipment | | 6,316 | | | 7,831 | | | 12,993 | | | 15,266 | | | CO2 properties, pipelines, plants and other property and equipment | | 7,073 | | | 6,316 | | | 13,789 | | | 12,993 | | |
| Accelerated depreciation charge | | Accelerated depreciation charge | | 42 | | | — | | | 1,159 | | | — | | |
Total DD&A | Total DD&A | | $ | 35,400 | | | $ | 36,381 | | | $ | 70,745 | | | $ | 75,831 | | | Total DD&A | | $ | 49,767 | | | $ | 35,400 | | | $ | 91,799 | | | $ | 70,745 | | |
| DD&A per BOE | DD&A per BOE | | | | | DD&A per BOE | | | | |
Oil and natural gas properties | Oil and natural gas properties | | $ | 6.86 | | | $ | 6.39 | | | $ | 6.83 | | | $ | 6.94 | | | Oil and natural gas properties | | $ | 9.98 | | | $ | 6.86 | | | $ | 8.97 | | | $ | 6.83 | | |
CO2 properties, pipelines, plants and other property and equipment | CO2 properties, pipelines, plants and other property and equipment | | 1.49 | | | 1.75 | | | 1.53 | | | 1.74 | | | CO2 properties, pipelines, plants and other property and equipment | | 1.65 | | | 1.49 | | | 1.61 | | | 1.53 | | |
| Accelerated depreciation charge | | Accelerated depreciation charge | | 0.01 | | | — | | | 0.14 | | | — | | |
Total DD&A cost per BOE | Total DD&A cost per BOE | | $ | 8.35 | | | $ | 8.14 | | | $ | 8.36 | | | $ | 8.68 | | | Total DD&A cost per BOE | | $ | 11.64 | | | $ | 8.35 | | | $ | 10.72 | | | $ | 8.36 | | |
| Write-down of oil and natural gas properties | | $ | — | | | $ | — | | | $ | — | | | $ | 14,377 | | | |
|
The decrease in DD&A expense duringincreased $14.4 million between the three months ended June 30, 2023 and 2022, when compared to the same period in 2021, was primarily due to lower depreciation on other fixed assets and CO2 sources, partially offset by higher accretion expense related to asset retirement obligations at our oil and gas properties. DD&A expense decreased $5.1$21.1 million duringbetween the six months ended June 30, 2023 and 2022 when compareddue to higher depletable costs, most significantly attributable to capital spending and the transfer of unevaluated costs to the same prior-year period, primarily due to a lower depletion rate as a resultfull cost pool associated with the recognition of an increase in our estimate ofinitial proved reserves between the periods based on higher commodity pricing and lower depreciation on other fixed assets andassociated with our new CCA CO2 sources.Phase I development.
First Quarter 2021 Full Cost Pool Ceiling Test Write-Down
Under full cost accounting rules,During the second quarter of 2023, we are required each quarteradded 6.4 MMBOE of new proved reserves related to perform a ceiling test calculation. Under these rules,our new CCA CO2 Phase I development. Concurrent with the full cost ceiling value is calculated using the average first-day-of-the-month oiladdition of new reserves, all unevaluated costs for that development were transferred to proved properties, and natural gas price for each month during a 12-month rolling period priorthose costs aggregated with associated estimated future development costs were added to the end of a particular reporting period. We recognized aour full cost pool ceiling test write-downfor purposes of $14.4 millioncalculating depletion. Although the oil reserves added for Phase I of CCA during the three months ended March 31, 2021. The write-down was primarilysecond quarter represent only a resultportion of the March 2021 acquisitionpotential oil reserves that we believe are recoverable, our depletion calculation includes a significant portion of Wyoming CO2 EOR properties (see Note 2, Acquisitionthe expected costs for Phase I CCA future anticipated barrels, resulting in virtually all of the increase to our oil and Divestiture) which was recorded basedgas DD&A rate on a valuation that utilized NYMEX strip oil prices atsequential quarter basis. Our DD&A expense and DD&A rate per BOE could fluctuate significantly in the acquisition date, which were significantly higher thanfuture with the average first-day-of-the-month NYMEX oil prices used to value the cost ceiling. We did not record a ceiling test write-down during the three or six months ended June 30, 2022.recognition of additional proved reserves.
Other Expenses
Other expenses during the three and six months ended June 30, 2022 include a $3.9 million accrual for a preliminarily assessed civil penalty proposed by the Pipeline and Hazardous Materials Safety Administration of the U.S. Department of Transportation in a Notice of Probable Violation (see Item 1, Legal Proceedings – Notice of Probable Violation from Pipeline and Hazardous Materials Safety Administration (“PHMSA”) Regarding Delta-Tinsley CO2 Pipeline Failure). Other expenses2023 totaled $3.2$4.0 million and $5.4$5.5 million, respectively, compared to $6.6 million and $8.7 million, respectively, during the three and six months ended June 30, 2021, respectively.2022. Other expenses during the six months ended June 30, 2023 primarily includes $3.0 million in CCUS-related expenses (including $0.5 million of expense related to the Gulf Coast Midstream Partners sequestration site which we no longer intend to pursue), $1.8 million in plant operating expenses and $1.1 million in Merger-related expenses. Other expenses during the six months ended June 30, 2022 included $4.3 million in Delta Pipeline incident costs, $1.9 million in plant operating expenses, and $1.0 million in legal settlements. We expect other expenses will be higher during the second half of 2023, primarily related to Merger-related expenses such as legal and advisory fees.
Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Income Taxes
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended | | Six Months Ended |
| | June 30, | | June 30, |
In thousands, except per-BOE amounts and tax rates | | 2022 | | 2021 | | 2022 | | 2021 |
Current income tax expense (benefit) | | $ | 2,912 | | | $ | (260) | | | $ | 2,351 | | | $ | (451) | |
Deferred income tax expense (benefit) | | 21,936 | | | (36) | | | 15,992 | | | (87) | |
Total income tax expense (benefit) | | $ | 24,848 | | | $ | (296) | | | $ | 18,343 | | | $ | (538) | |
Average income tax expense (benefit) per BOE | | $ | 5.87 | | | $ | (0.07) | | | $ | 2.17 | | | $ | (0.06) | |
Effective tax rate | | 13.8 | % | | 0.4 | % | | 10.6 | % | | 0.4 | % |
Total net deferred tax liability | | $ | 17,630 | | | $ | 1,187 | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended | | Six Months Ended |
| | June 30, | | June 30, |
In thousands, except per-BOE amounts and tax rates | | 2023 | | 2022 | | 2023 | | 2022 |
Current income tax expense | | $ | 857 | | | $ | 2,912 | | | $ | 3,195 | | | $ | 2,351 | |
Deferred income tax expense | | 21,139 | | | 21,936 | | | 47,051 | | | 15,992 | |
Total income tax expense | | $ | 21,996 | | | $ | 24,848 | | | $ | 50,246 | | | $ | 18,343 | |
Average income tax expense per BOE | | $ | 5.14 | | | $ | 5.87 | | | $ | 5.86 | | | $ | 2.17 | |
Effective tax rate | | 24.6 | % | | 13.8 | % | | 24.3 | % | | 10.6 | % |
Total net deferred tax liability | | $ | 118,171 | | | $ | 17,630 | | | | | |
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 20222023 and 2021.2022. Our effective tax rate for the three months ended June 30, 2023 was in line with our estimated statutory rate and our effective tax rate for the six months ended June 30, 2023 was slightly lower than our estimated statutory rate primarily due to excess stock compensation deductions that were recorded discretely in the first quarter. Our effective tax rate for the three and six months ended June 30, 2022 was significantly lower than our estimated statutory rate primarily due to the release of a portion of the valuation allowance that was recorded in the three and six months ended June 30, 2022.on our deferred tax assets. Our annualized effective tax rate for the year ended December 31, 20222023 is currently estimated to be approximately 15%, as it includes the impact of the release of an additional $40.2 million of valuation allowances over the remaining two quarters of 2022. This rate could move higher or lower based on our ultimate level of income.24.5%.
We make estimates and judgments in determining our income tax expense for financial reporting purposes. These estimates and judgments occur in the calculation of certain tax assets and liabilities that arise from differences in the timing and recognition of revenue and expense for tax and financial reporting purposes. Significant judgment is required in estimating valuation allowances, and in making this determination we consider all available positive and negative evidence and make certain assumptions. The realization of a deferred tax asset ultimately depends on the existence of sufficient taxable income in the applicable carryback or carryforward periods. In our assessment, we consider the nature, frequency, and severity of current and cumulative losses, as well as historical and forecasted financial results, the overall business environment, our industry’s historic cyclicality, the reversal of existing deferred tax assets and liabilities, and tax planning strategies.
We assess the valuation allowance recorded on our deferred tax assets on a quarterly basis, which was $125.5$59.2 million at December 31, 2021, on a quarterly basis.2022. This valuation allowance onrelates primarily to our federal and certain stateLouisiana net deferred tax assets was recorded in September 2020 after the application of fresh start accounting,$55.4 million, as (1) the tax basis ofwell as our assets, primarily our oil and gas properties, was in excess of the carrying value, as adjusted for fresh start accounting and (2) our historical pre-tax income reflected a three-year cumulative loss primarily due to ceiling test write-downs and reorganization items that were recorded in 2020. While we continued to be in a cumulative three-year-loss position during the first quarter of 2022, we initially determined, at that time, that there was sufficient positive evidence, primarily related to a substantial increase in worldwide oil prices, to conclude that $64.9 million of our federal and certain stateAlabama net deferred tax assets and certain Mississippi tax credits totaling $3.8 million. We have concluded that the benefits of such deferred tax assets are not more likely than not to be realized. Accordingly, we reversed $5.9 millionrealized due to lack of this valuation allowance duringsufficient taxable income to fully realize the three months ended March 31, 2022, $18.8 million duringbenefits of such deferred tax assets.
During the threesix months ended June 30, 2022, and currently expect to reverse the remaining $40.2 million during the second half of 2022, resulting in a reduction to our annualized effective tax rate. We will continue to maintain a valuation allowance of $60.6 million for certain state tax benefits that2023, we currently do not expect to realize before their expiration.
As of June 30, 2022, we hadreceived $0.6 million of refundable alternative minimum tax credits which under the Tax Cut and Jobs Act, will be refundable by 2022 and arewhich amount was recorded as a receivable on the balance sheet. Our significantsheet at December 31, 2022. We have state net operating loss carryforwards that expire in various years, starting in 2025. Our Louisiana net operating loss carryforwards may be carried forward indefinitely.
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 | | Six Months Ended | | Three Months Ended | | Six Months Ended |
| | June 30, | | June 30, | | June 30, | | June 30, |
Per-BOE data | Per-BOE data | | 2022 | | 2021 | | 2022 | | 2021 | Per-BOE data | | 2023 | | 2022 | | 2023 | | 2022 |
Oil and natural gas revenues | Oil and natural gas revenues | | $ | 106.67 | | | $ | 63.23 | | | $ | 98.92 | | | $ | 59.33 | | Oil and natural gas revenues | | $ | 70.86 | | | $ | 106.67 | | | $ | 72.09 | | | $ | 98.92 | |
Payment on settlements of commodity derivatives | | (30.20) | | | (14.17) | | | (26.13) | | | (11.65) | | |
Receipt (payment) on settlements of commodity derivatives | | Receipt (payment) on settlements of commodity derivatives | | 1.21 | | | (30.20) | | | 0.85 | | | (26.13) | |
Lease operating expenses | Lease operating expenses | | (29.35) | | | (24.65) | | | (28.63) | | | (22.01) | | Lease operating expenses | | (30.48) | | | (29.35) | | | (30.30) | | | (28.63) | |
Production and ad valorem taxes | Production and ad valorem taxes | | (8.40) | | | (4.88) | | | (7.80) | | | (4.55) | | Production and ad valorem taxes | | (6.13) | | | (8.40) | | | (6.36) | | | (7.80) | |
Transportation and marketing expenses | Transportation and marketing expenses | | (1.13) | | | (1.91) | | | (1.12) | | | (1.87) | | Transportation and marketing expenses | | (1.21) | | | (1.13) | | | (1.23) | | | (1.12) | |
Production netback | Production netback | | 37.59 | | | 17.62 | | | 35.24 | | | 19.25 | | Production netback | | 34.25 | | | 37.59 | | | 35.05 | | | 35.24 | |
CO2 sales, net of operating and discovery expenses | CO2 sales, net of operating and discovery expenses | | 2.58 | | | 1.93 | | | 2.55 | | | 1.93 | | CO2 sales, net of operating and discovery expenses | | 2.24 | | | 2.58 | | | 2.22 | | | 2.55 | |
General and administrative expenses(1) | General and administrative expenses(1) | | (4.54) | | | (3.46) | | | (4.48) | | | (5.43) | | General and administrative expenses(1) | | (6.29) | | | (4.54) | | | (5.82) | | | (4.48) | |
Interest expense, net | Interest expense, net | | (0.36) | | | (0.28) | | | (0.26) | | | (0.32) | | Interest expense, net | | (0.19) | | | (0.36) | | | (0.20) | | | (0.26) | |
Stock compensation and other | Stock compensation and other | | (1.01) | | | 0.12 | | | (0.45) | | | 1.95 | | Stock compensation and other | | 0.05 | | | (1.01) | | | 0.05 | | | (0.45) | |
Changes in assets and liabilities relating to operations | Changes in assets and liabilities relating to operations | | 1.13 | | | 4.40 | | | (4.22) | | | (0.94) | | Changes in assets and liabilities relating to operations | | 3.27 | | | 1.13 | | | (4.33) | | | (4.22) | |
Cash flows from operations | Cash flows from operations | | 35.39 | | | 20.33 | | | 28.38 | | | 16.44 | | Cash flows from operations | | 33.33 | | | 35.39 | | | 26.97 | | | 28.38 | |
DD&A | DD&A | | (8.35) | | | (8.14) | | | (8.36) | | | (8.68) | | DD&A | | (11.63) | | | (8.35) | | | (10.58) | | | (8.36) | |
DD&A – accelerated depreciation charge | | DD&A – accelerated depreciation charge | | (0.01) | | | — | | | (0.14) | | | — | |
| Write-down of oil and natural gas properties | | — | | | — | | | — | | | (1.65) | | |
Deferred income taxes | Deferred income taxes | | (5.18) | | | 0.01 | | | (1.89) | | | 0.01 | | Deferred income taxes | | (4.94) | | | (5.18) | | | (5.49) | | | (1.89) | |
| Noncash fair value gains (losses) on commodity derivatives | Noncash fair value gains (losses) on commodity derivatives | | 16.78 | | | (24.45) | | | (3.37) | | | (21.37) | | Noncash fair value gains (losses) on commodity derivatives | | 3.39 | | | 16.78 | | | 4.15 | | | (3.37) | |
Other noncash items | Other noncash items | | (1.94) | | | (5.13) | | | 3.52 | | | (1.62) | | Other noncash items | | (4.40) | | | (1.94) | | | 3.36 | | | 3.52 | |
Net income (loss) | Net income (loss) | | $ | 36.70 | | | $ | (17.38) | | | $ | 18.28 | | | $ | (16.87) | | Net income (loss) | | $ | 15.74 | | | $ | 36.70 | | | $ | 18.27 | | | $ | 18.28 | |
(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 six months ended June 30, 2021, resulting in a significant non-recurring expense, which if excluded, would have caused these expenses to average $3.68 per BOE.
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 such as those related to our CCUS storage sites and related assets, or updates to existing accounting policies as a result of new accounting pronouncements have been included in the notesNotes 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,particularly statements found in the section Management’s“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 other plans and objectives for the future operations of Denbury, projections or assumptions as to oil markets or general economic conditions and the economics of a carbon capture, use and storage industry (“CCUS”),” that are not historical facts, 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.uncertainties, and include, but are not limited to: possible or assumed future results of operations, cash flows, production and capital expenditures; goals, predictions, economics and timing as to the Company’s future carbon capture, use and storage (“CCUS”) activities; and assumptions as to oil markets or general economic conditions.
Such forward-looking statements may be or may concern, among other things, the level and sustainabilityvolatility of recent higher worldwideposted or realized oil prices; the extentadequacy of future oil price volatility; current or futureour liquidity sources or their adequacy to support our future activities; statements or predictions related to the ultimate timing and financial impact of our proposed CCUS arrangements, including the estimated emissions storage capacity of storage sites, predictions of long-term cumulative capital investments in CCUS, the volumes of CO2 emissions available from third-party emitters for transportation and storage through our CCUS platform and the dates that new or add-on facilities will become
Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
anticipated future activities; statements or predictions related tooperational, along with the ultimate timing and financial impact of our current or proposed carbon capture, use andreceipt of first revenues from storage arrangements;of CO2; our projected production levels, oil and natural gas revenues oil and gas prices andor oilfield costs, the impact of current supply chain issues and inflation on our results of operations; current or future expectations or estimations of our cash flows or the impact of changes in commodity prices on cash flows; availability, terms and financial statement and cash settlement impact of commodity derivative contracts or their predicted downside cash flow protection; forecasted drilling activity or methods, including the timing and location thereof; estimatedanticipated timing of commencement of CO2 injectionsinitial production responses in tertiary flooding projects in particular fields or areas or initial production responses in tertiary flooding projects;the volumes thereof; 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 tax or environmental laws or regulations;regulations or in any future regulation of CO2 pipelines, long-term CO2 storage sites or industrial facilities or processes that emit CO2; the outcomes of any pending litigation or regulatory proceedings; 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 that could significantly and adversely affect current plans, anticipated outcomes, the timing of such actions andbe affected by various factors discussed below, along with currently unknowable events beyond our financial condition and results of operations.control. 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 from current projections are fluctuations in worldwide or U.S. oil prices, especially in light of existing global economic uncertainties or geopolitical events such as oil prices are affected by the war in Ukraine and geopolitical and economic consequencesfuture levels of such war and resulting financial sanctions;oil demand in China; widespread inflation in economies across the world; future decisions or actions as to production levels and/or pricing by OPECOPEC; any adverse changes to business relationships due to our pending merger with ExxonMobil; as to our CCUS activities, the successful completion of technical and feasibility evaluations of future sequestration sites and third-party emission facilities or U.S. producers in future periods;processes, the impactavailability of COVID-19funds to us and third parties sufficient to build and operate add-on or other viral outbreaks onnew infrastructure and facilities, and the assessment by third parties of the economic activity levels and ultimately oil prices;feasibility of constructing such facilities, the pace and terms of agreements reachedfinalization of CCUS arrangements with third parties, for the capture, transportation, usereceipt of required regulatory approval or classifications, and ultimate permanent sequestration of CO2; the timing and success ofcoordination necessary to bring together numerous industry and governmental entities in order to create a CCUS projects that, while undertaken by third parties, are related to our CCUS efforts;industry at scale; success of our risk management techniques; 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 currency and credit markets; the risks and uncertainties inherent in oil and gas drilling and production activities; and the risks and uncertainties set forth from time to time in this or our other periodic public reports, other 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,Over the last few years, these contracts have consisted of various combinations of price floors,costless collars three-way collars,and 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 June 30, 2022,2023, we do not have any 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 20232024 using NYMEX fixed-price swaps and costless collars. Depending on market conditions, we may continue to add to our existing 20222023 and 20232024 hedges. See also Note 6,7, Income TaxesCommodity Derivative Contracts, and Note 8, 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 beare charged to earnings instead of charging the effective portion to other comprehensive income and the ineffective portion to earnings.
At June 30, 2022, the fair value of2023, our commodity derivative contracts were recorded at their fair value, which was a net liabilityasset of $163.1$38.1 million, a $71.1$14.5 million decreasechange from the $234.2$23.6 million net liabilityasset recorded at March 31, 20222023, and a $28.6$35.6 million increasechange from the $134.5$2.5 million net liabilityasset recorded at December 31, 2021.2022. The changes are primarily related to the expiration of commodity derivative contracts during the three and six months ended June 30, 2022, increase2023, new commodity derivative contracts entered during 2023 for future periods, and to the changes in oil futures prices between December 31, 20212022 and June 30, 2022, and new commodity derivative contract commitments during 2022 for future periods.2023.
Commodity Derivative Sensitivity Analysis
Based on NYMEX crude oil futures prices and derivative contracts in place as of June 30, 2022,2023, and assuming both a 10% increase and decrease thereon, we would expect to make payments on our crude oil derivative contracts as shown in the following table:
| | | | | | | | |
In thousands | | Receipt / (Payment) |
Based on: | | |
Futures prices as of June 30, 20222023 | | $ | (156,344)35,061 | |
10% increase in prices | | (216,621)2,845 | |
10% decrease in prices | | (102,227)72,283 | |
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 ofon 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.
Debt and Interest Rate Sensitivity
As of June 30, 2023, we had $85.0 million of outstanding borrowings under our Bank Credit Agreement. At this level of variable-rate debt, an increase or decrease of 10% in interest rates would have an immaterial effect on our interest expense. Our Bank Credit Agreement does not have any triggers or covenants regarding our debt ratings with rating agencies. The following table presents the principal and fair values of our outstanding debt as of June 30, 2023:
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In thousands | | 2023 - 2026 | | 2027 | | Total | | Fair Value |
Variable rate debt: | | | | | | | | |
Senior Secured Bank Credit Facility (weighted average interest rate of 7.77% at June 30, 2023) | | $ | — | | | $ | 85,000 | | | $ | 85,000 | | | $ | 85,000 | |
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See Note 3, Long-Term Debt, to the Unaudited Condensed Consolidated Financial Statements for details regarding our long-term debt.
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 June 30, 2022,2023, 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 second quarter of fiscal 2022,2023, 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
We are involved in various lawsuits, claims and regulatory proceedings incidental to our businesses. 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 and regulatory proceedings are 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.
Notice of Probable Violation from Pipeline and Hazardous Materials Safety Administration (“PHMSA”) Regarding Delta-Tinsley CO2 Pipeline Failure
On May 26, 2022, the PHMSAPipeline and Hazardous Materials Safety Administration (“PHMSA”) of the U.S. Department of Transportation issued a Notice of Probable Violation, Proposed Civil Penalty, and Proposed Compliance Order (“NOPV”) relating to the February 2020 CO2 release from a pipeline failure near Satartia, Mississippi in our CO2pipeline in Yazoo County, Mississippi running between theour Tinsley and Delhi fields. The NOPV proposesfields, and assessed a preliminarily assessedpreliminary civil penalty of $3.9 million, which the Company recorded in connection with the incident, which we accrued duringits financial statements in the second quarter of 2022. We have responded toOver the NOPV and are pursuingensuing 10 months, the Company has engaged in settlement discussions with PHMSA regardingrelated to the nature and extent of the alleged probable violations alleged in the NOPV, the proposedviolation and civil penalty and the naturefuture actions required in connection with the operation of the compliance order contained in the NOPV.Company’s CO2 pipeline.
On March 24, 2023, Denbury and PHMSA entered into a final Consent Order and Consent Agreement that settled all of the allegations in the NOPV and also reduced the assessed penalty to $2.9 million. The $1.0 million reduction was reflected in “Other Expenses” in our Unaudited Condensed Consolidated Statement of Operations in the first quarter of 2023. Under the Consent Agreement, the Company has agreed to take numerous preventative and mitigative steps related to geohazard risks of its pipeline operations and related safety and community informational issues.
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, 2021. There2022. Except as disclosed below, 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, 2021.2022. The following risk factors relate to the proposed Merger with ExxonMobil:
Because the Exchange Ratio is fixed and the market price of ExxonMobil common stock has fluctuated and will continue to fluctuate, Denbury stockholders cannot be sure of the value of the consideration they will receive in the Merger, if completed.
If the Merger is completed, each share of Denbury common stock outstanding immediately prior to the Merger (except for the excluded shares) will automatically be converted into the right to receive 0.840 shares of ExxonMobil common stock, with cash to be paid in lieu of fractional shares. Because the Exchange Ratio is fixed, the value of the Merger consideration will depend on the market price of ExxonMobil common stock at the time the Merger is completed. Prior to completion of the Merger, the market price of ExxonMobil common stock is also expected to impact the market price of Denbury common stock. The value of ExxonMobil common stock has fluctuated since the date of the announcement of the Merger Agreement and will continue to fluctuate. Accordingly, Denbury stockholders will not know or be able to determine the market value of the Merger consideration they would receive upon completion of the Merger. Stock price changes may result from a variety of factors, including, among others, general market and economic conditions, changes in ExxonMobil’s and Denbury’s respective businesses, operations and prospects, market assessments of the likelihood that the Merger will be completed, the timing of the Merger, regulatory considerations and COVID-19. Many of these factors are beyond ExxonMobil’s and Denbury’s control.
Denbury may have difficulty attracting, motivating and retaining employees in light of the Merger.
Uncertainty about the effect of the Merger on Denbury employees may impair Denbury’s ability to attract, retain and motivate personnel prior to and following the Merger. Employee retention may be particularly challenging during the pendency of the Merger, as employees of Denbury may experience uncertainty about their future roles with the combined business.
Completion of the Merger is subject to certain conditions and if these conditions are not satisfied or waived, the Merger will not be completed.
The obligation of each of ExxonMobil, Denbury and EMPF Corporation, ExxonMobil’s wholly owned merger subsidiary (“Merger Sub”) to complete the Merger is subject to the satisfaction (or, to the extent permitted by applicable law, waiver) of a number of conditions, including, among others: (i) the affirmative vote of the holders of a majority of the shares of Denbury common stock outstanding and entitled to vote at the date of the special meeting of Denbury stockholders approving and adopting the Merger Agreement (which condition described in this clause (i) may not be waived), (ii) the expiration or termination of any applicable waiting period, or any extension thereof, under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 (the “HSR Act”) (in the case of ExxonMobil and Merger Sub’s obligation to complete the Merger, without the imposition of a Burdensome Condition, as defined in the Merger Agreement), (iii) absence of any injunction or other order or applicable law preventing or making illegal the consummation of the Merger (in the case of ExxonMobil and Merger Sub’s obligation to complete the Merger, without the imposition of a Burdensome Condition to the extent such law or prohibition relates to the matters in clause (i) above), (iv) the future registration statement being declared effective and no stop order suspending the effectiveness of the registration statement being in effect and no proceedings for such purpose pending or threatened by the SEC, (v) approval for the listing on the New York Stock Exchange of the shares of ExxonMobil common stock to be issued in the Merger, subject to official notice of issuance, (vi) accuracy of the representations and warranties made in the Merger Agreement by, in the case of ExxonMobil and Merger Sub’s obligations to complete the Merger, Denbury and, in the case of Denbury’s obligation to complete the Merger, ExxonMobil and Merger Sub, in each case, as of the date of the Merger Agreement and as of the date of completion of the Merger, subject to certain materiality thresholds, (vi) performance in all material respects by, in the case of ExxonMobil and Merger Sub’s obligations to complete the Merger, Denbury and, in the case of Denbury’s obligation to complete the Merger, ExxonMobil and Merger Sub, of the obligations required to be performed by it at or prior to the effective time of the Merger, (vii) the absence since the date of the Merger Agreement of a material adverse effect on, in the case of ExxonMobil and Merger Sub’s obligations to complete the Merger, Denbury and (viii) the absence since the date of the Merger Agreement of a material adverse effect on, in the case of Denbury’s obligations to complete the Merger, ExxonMobil and Merger Sub.
There can be no assurance that the conditions to the closing of the Merger will be satisfied or waived or that the Merger will be completed.
Denbury’s business relationships may be subject to disruption due to uncertainty associated with the Merger.
Parties with which Denbury does business may experience uncertainty associated with the Merger, including with respect to current or future business relationships with ExxonMobil, Denbury or the combined business. Denbury’s business relationships may be subject to disruption as parties with which ExxonMobil or Denbury does business may attempt to negotiate changes in existing business relationships or consider entering into business relationships with parties other than ExxonMobil, Denbury or the combined business. These disruptions could have an adverse effect on the businesses, financial condition, results of operations or prospects of the combined business, including an adverse effect on ExxonMobil’s ability to realize the anticipated benefits of the Merger. The risk, and adverse effect, of such disruptions could be exacerbated by a delay in completion of the Merger or termination of the Merger Agreement.
Completion of the Merger may trigger change in control or other provisions in certain agreements to which Denbury is a party.
Denbury is a party to certain agreements that give the counterparty certain rights following a “change in control,” including in some cases the right to terminate such agreements. Under some such agreements, the Merger may constitute a change in control and therefore the counterparty may exercise certain rights under the agreement upon the closing of the Merger. Any such counterparty may request modifications of its respective agreements as a condition to granting a waiver or consent under its agreement. There is no assurance that such counterparties will not exercise their rights under the agreements, including termination rights where available and/or requiring payment of substantial financial penalties.
The Merger Agreement limits Denbury’s ability to pursue alternatives to the Merger and may discourage other companies from trying to acquire Denbury for greater consideration than what ExxonMobil has agreed to pay pursuant to the Merger Agreement.
The Merger Agreement contains provisions that make it more difficult for Denbury to sell its business to a party other than ExxonMobil. These provisions include a general prohibition on Denbury soliciting any acquisition proposal or offer for a competing transaction. Further, subject to certain exceptions, the Denbury board of directors will not withdraw or modify in a manner adverse to ExxonMobil the recommendation of the Denbury board of directors in favor of the approval and adoption of the Merger Agreement, and ExxonMobil generally has a right to match any competing acquisition proposals that may be made. Notwithstanding the foregoing, at any time prior to the approval and adoption of the Merger Agreement by Denbury stockholders, the Denbury board of directors is permitted to withdraw or modify in a manner adverse to ExxonMobil the recommendation of the Denbury board of directors in favor of the approval and adoption of the Merger Agreement in certain circumstances if it determines in good faith that the failure to take such action would be reasonably likely to be inconsistent with its fiduciary duties to Denbury stockholders under applicable law. The Merger Agreement does not require that Denbury submit the approval and adoption of the Merger Agreement to a vote of Denbury stockholders if the Denbury board of directors changes its recommendation in favor of the approval and adoption of the Merger Agreement in a manner adverse to ExxonMobil and terminates the Merger Agreement in order to enter into an alternative acquisition agreement with respect to a competing transaction in accordance with the terms of the Merger Agreement. In certain circumstances, upon termination of the Merger Agreement, Denbury will be required to pay a termination fee of $144 million to ExxonMobil, including if Denbury terminates the Merger Agreement prior to obtaining Denbury stockholder approval in order to enter into an alternative acquisition agreement with respect to a competing transaction in accordance with the terms of the Merger Agreement.
While both Denbury and ExxonMobil believe these provisions and agreements are reasonable and customary and are not preclusive of other offers, the restrictions, including the added expense of the $144 million termination fee that may become payable by Denbury to ExxonMobil in certain circumstances, might discourage a third party that has an interest in acquiring all or a significant part of Denbury from considering or proposing that acquisition, even if that party were prepared to pay consideration with a higher per-share value than the consideration payable in the Merger pursuant to the Merger Agreement.
Failure to complete the Merger could negatively impact the stock price and the future business and financial results of Denbury.
If the Merger is not completed for any reason, including as a result of Denbury stockholders failing to approve the Merger or any other condition not being satisfied or waived, the ongoing businesses of Denbury may be adversely affected, and without realizing any of the benefits of having completed the Merger, Denbury would be subject to a number of risks, including the following:
•Denbury may experience negative reactions from the financial markets, including negative impacts on its stock price;
•Denbury may experience negative reactions from its clients, regulators and employees;
•Denbury will be required to pay certain costs relating to the Merger, whether or not the Merger is completed;
•the Merger Agreement places certain restrictions on the conduct of Denbury’s businesses prior to completion of the Merger, and such restrictions, the waiver of which are subject to the written consent of ExxonMobil (in certain cases, not to be unreasonably withheld, conditioned or delayed), and subject to certain exceptions and qualifications, may prevent Denbury from taking certain other specified actions or otherwise pursuing business opportunities during the pendency of the Merger that Denbury would have made, taken or pursued if these restrictions were not in place; and
•matters relating to the Merger (including integration planning) will require substantial commitments of time and resources by Denbury management, which would otherwise have been devoted to day-to-day operations and other opportunities that may have been beneficial to Denbury as an independent company. In the event of a termination of the Merger Agreement under certain circumstances specified in the Merger Agreement, Denbury may be required to pay a termination fee of $144 million to ExxonMobil. To the extent that a termination fee is not promptly paid by Denbury when due, Denbury will be required to pay ExxonMobil interest on such fee at the annual rate equal to the prime rate, as published in The Wall Street Journal in effect on the date such payment was required to be made, through the date such payment was actually received, or such lesser rate as is the maximum permitted by applicable law.
There can be no assurance that the risks described above will not materialize. If any of those risks materialize, they may materially and adversely affect Denbury’s businesses, financial condition, financial results, ratings and/or stock price.
In addition, Denbury could be subject to litigation related to any failure to complete the Merger or related to any enforcement proceeding commenced against Denbury to perform its obligations under the Merger Agreement. If the Merger is not completed, these risks may materialize and may adversely affect Denbury’s businesses, financial condition, financial results, ratings, stock prices and/or bond prices.
Potential litigation against Denbury could result in substantial costs, an injunction preventing the completion of the Merger and/or a judgment resulting in the payment of damages.
Securities class action lawsuits and derivative lawsuits are often brought against public companies that have entered into merger agreements. Even if such a lawsuit is unsuccessful, defending against these claims can result in substantial costs.
Stockholders of Denbury may file lawsuits against ExxonMobil, Denbury and/or the directors and officers of either company in connection with the Merger. These lawsuits could prevent or delay the completion of the Merger and result in significant costs to Denbury, including any costs associated with the indemnification of directors and officers. There can be no assurance that any of the defendants will be successful in the outcome of any potential lawsuits.
Denbury will incur significant transaction and Merger-related costs in connection with the Merger.
Denbury expects to incur a number of non-recurring costs associated with the Merger and combining the operations of the two companies. The significant, non-recurring costs associated with the Merger include, among others, fees and expenses of financial advisors and other advisors and representatives, certain employment-related costs relating to employees of Denbury, filing fees due in connection with filings required under the HSR Act and filing fees and printing and mailing costs for a proxy statement/prospectus. Some of these costs have already been incurred or may be incurred regardless of whether the Merger is completed, including a portion of the fees and expenses of financial advisors and other advisors and representatives and filing fees for a proxy statement/prospectus.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
Issuer Purchases of Equity Securities
The following table summarizes purchasesSecond Quarter Purchases of our common stock duringEquity Securities by the second quarter of 2022:Issuer and Affiliated Purchasers
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Month | | Total Number of Shares Purchased | | Average Price Paid per Share | | Total Number of Shares Purchased as Part of Publicly Announced Plans of Programs | | Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs (in millions)(1) |
April 2022 | | — | | | $ | — | | | — | | | $ | — | |
May 2022 | | — | | | — | | | — | | | 250.0 | |
June 2022 | | — | | | — | | | 457,549 | | | 221.2 | |
Total | | — | | | | | 457,549 | | | |
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Month | | Total Number of Shares Purchased | | Average Price Paid per Share | | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs | | Approximate Dollar Value of Shares that May Yet Be Purchased Under Plans or Programs
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April 2023 | | — | | | $ | — | | | — | | | $ | 250,000,000 | |
May 2023 | | — | | | — | | | — | | | $ | 250,000,000 | |
June 2023 | | — | | | — | | | — | | | $ | 250,000,000 | |
Total | | — | | | | | — | | | |
2022 Share Repurchases
(1)
In early May 2022, our Board of Directors approved a common share repurchase program authorizing the repurchase of up to an aggregate of $250.0$250 million of Denbury common shares. The program has no pre-established ending dateDuring June and may be suspended or discontinued at any time. We are not obligated to repurchase any dollar amount or specific number of shares of our common stock under the program.
An aggregateJuly 2022, we purchased a total of 1,615,356 shares of Denbury common stock (approximately 3.2%for $100 million under the program, at an average price of our outstanding$61.92 per share. No share repurchases have been made under this program since that time. In August 2022, the Board increased Denbury’s stock repurchase authorization by $100 million to a total of $250 million for future repurchases under the program. With limited exceptions, the Merger Agreement precludes the Company from any future repurchases or acquisition of shares of commonits capital stock, at March 31, 2022) were repurchased during thisincluding under a repurchase program, through July 31, 2022 for $100.0 million. As of August 2, 2022, an additional $250.0 million remains authorized for purchases of common stock under this repurchase program.without ExxonMobil’s consent.
Item 3. Defaults Upon Senior Securities
None.
Item 4. Mine Safety Disclosures
None.
Item 5. Other Information
None.During the three months ended June 30, 2023, no director nor Section 16 officer of the Company adopted or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as each term is defined in Item 408(a) of Regulation S-K, pertaining to the common stock of the Company.
Item 6. Exhibits
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Exhibit No. | | Exhibit |
10(a)2.1 | | Agreement and Plan of Merger, dated as of July 13, 2023, by and among Denbury Inc. Employee Stock Purchase Plan, Exxon Mobil Corporation and EMPF Corporation (incorporated by reference to Exhibit 10.12.1 of Form 8-K filed by the Company on June 6, 2022,July 14, 2023, as amended by the Form 8-K/A filed by the Company on July 31, 2023, File No. 001-12935).
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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 June 30, 2022,2023, has been formatted in Inline XBRL.
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* 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.
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| | DENBURY INC. |
| | |
August 4, 20223, 2023 | | /s/ Mark C. Allen |
| | Mark C. Allen Executive Vice President and Chief Financial Officer |
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August 4, 20223, 2023 | | /s/ Nicole Jennings |
| | Nicole Jennings Vice President and Chief Accounting Officer |