CIVITAS RESOURCES, INC. - Quarter Report: 2021 September (Form 10-Q)
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
☒ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2021
or
☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission File Number: 001-35371
Bonanza Creek Energy, Inc.
(Exact name of registrant as specified in its charter)
| Delaware | 61-1630631 | |||||||
| (State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) | |||||||
| 410 17th Street, | Suite 1400 | |||||||||||||
| Denver, | Colorado | 80202 | ||||||||||||
| (Address of principal executive offices) | (Zip Code) | |||||||||||||
(720) 440-6100
(Registrant’s telephone number, including area code)
| Securities registered pursuant to Section 12(b) of the Act: | ||||||||
| Title of each class | Trading Symbol | Name of exchange on which registered | ||||||
| Common Stock, par value $0.01 per share | BCEI | New York Stock Exchange | ||||||
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. ☒ Yes ☐ No
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). ☒ Yes ☐ No
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer”, “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
| Large Accelerated Filer | ☐ | Accelerated Filer | ☒ | ||||||||||||||
| Non-accelerated Filer | ☐ | ||||||||||||||||
| Emerging growth company | ☐ | 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 Sections 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
As of October 25, 2021, the registrant had 30,861,324 shares of common stock outstanding.
BONANZA CREEK ENERGY, INC.
INDEX
| PAGE | ||||||||||||||
Condensed Consolidated Balance Sheets as of September 30, 2021 and December 31, 2020 | ||||||||||||||
Condensed Consolidated Statements of Operations and Comprehensive Income for the Three and Nine Months Ended September 30, 2021 and 2020 | ||||||||||||||
Condensed Consolidated Statements of Stockholders' Equity for the Three and Nine Months Ended September 30, 2021 and 2020 | ||||||||||||||
Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2021 and 2020 | ||||||||||||||
PART I - FINANCIAL INFORMATION
Item 1. Financial Statements.
BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
(in thousands, except share amounts)
| September 30, 2021 | December 31, 2020 | ||||||||||
| ASSETS | |||||||||||
| Current assets: | |||||||||||
| Cash and cash equivalents | $ | 40,410 | $ | 24,743 | |||||||
| Accounts receivable, net: | |||||||||||
| Oil and gas sales | 86,414 | 32,673 | |||||||||
| Joint interest and other | 14,512 | 14,748 | |||||||||
| Prepaid expenses and other | 6,421 | 3,574 | |||||||||
| Inventory of oilfield equipment | 12,161 | 9,185 | |||||||||
| Derivative assets (note 10) | — | 7,482 | |||||||||
| Total current assets | 159,918 | 92,405 | |||||||||
Property and equipment (successful efforts method): | |||||||||||
| Proved properties | 1,707,481 | 1,056,773 | |||||||||
| Less: accumulated depreciation, depletion, and amortization | (299,028) | (211,432) | |||||||||
| Total proved properties, net | 1,408,453 | 845,341 | |||||||||
| Unproved properties | 96,419 | 98,122 | |||||||||
| Wells in progress | 68,013 | 50,609 | |||||||||
Other property and equipment, net of accumulated depreciation of $4,256 in 2021 and $3,737 in 2020 | 5,562 | 3,239 | |||||||||
| Total property and equipment, net | 1,578,447 | 997,311 | |||||||||
| Right-of-use assets (note 4) | 28,046 | 29,705 | |||||||||
| Deferred income tax assets (note 12) | 165,666 | 60,520 | |||||||||
| Other noncurrent assets | 5,007 | 2,871 | |||||||||
| Total assets | $ | 1,937,084 | $ | 1,182,812 | |||||||
| LIABILITIES AND STOCKHOLDERS’ EQUITY | |||||||||||
| Current liabilities: | |||||||||||
| Accounts payable and accrued expenses (note 2) | $ | 95,051 | $ | 37,425 | |||||||
| Oil and gas revenue distribution payable | 62,644 | 18,613 | |||||||||
| Lease liability (note 4) | 11,624 | 12,044 | |||||||||
| Derivative liability (note 10) | 92,784 | 6,402 | |||||||||
| Total current liabilities | 262,103 | 74,484 | |||||||||
| Long-term liabilities: | |||||||||||
| Senior notes (note 5) | 100,000 | — | |||||||||
| Credit facility (note 5) | 60,000 | — | |||||||||
| Lease liability (note 4) | 16,733 | 17,978 | |||||||||
| Ad valorem taxes and other | 21,192 | 15,069 | |||||||||
| Derivative liability (note 10) | 9,044 | 1,330 | |||||||||
| Asset retirement obligations for oil and gas properties (note 9) | 50,762 | 28,699 | |||||||||
| Total liabilities | 519,834 | 137,560 | |||||||||
| Commitments and contingencies (note 6) | |||||||||||
| Stockholders’ equity: | |||||||||||
Preferred stock, $0.01 par value, 25,000,000 shares authorized, none outstanding | — | — | |||||||||
Common stock, $0.01 par value, 225,000,000 shares authorized, 30,858,813 and 20,839,227 issued and outstanding as of September 30, 2021 and December 31, 2020, respectively | 4,378 | 4,282 | |||||||||
| Additional paid-in capital | 1,085,968 | 707,209 | |||||||||
| Retained earnings | 326,904 | 333,761 | |||||||||
| Total stockholders’ equity | 1,417,250 | 1,045,252 | |||||||||
| Total liabilities and stockholders’ equity | $ | 1,937,084 | $ | 1,182,812 | |||||||
The accompanying notes are an integral part of these condensed consolidated financial statements.
1
BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (UNAUDITED)
(in thousands, except per share amounts)
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
| 2021 | 2020 | 2021 | 2020 | ||||||||||||||||||||
| Operating net revenues: | |||||||||||||||||||||||
| Oil and gas sales | $ | 189,963 | $ | 58,858 | $ | 420,157 | $ | 155,455 | |||||||||||||||
| Operating expenses: | |||||||||||||||||||||||
| Lease operating expense | 11,560 | 5,393 | 28,649 | 16,887 | |||||||||||||||||||
| Midstream operating expense | 3,163 | 3,970 | 11,314 | 11,338 | |||||||||||||||||||
| Gathering, transportation, and processing | 14,105 | 4,778 | 32,793 | 11,970 | |||||||||||||||||||
| Severance and ad valorem taxes | 9,205 | (7,063) | 23,622 | 1,588 | |||||||||||||||||||
| Exploration | 1,513 | 66 | 5,156 | 551 | |||||||||||||||||||
| Depreciation, depletion, and amortization | 35,604 | 23,439 | 89,433 | 67,306 | |||||||||||||||||||
| Abandonment and impairment of unproved properties | — | 223 | 2,215 | 30,589 | |||||||||||||||||||
| Unused commitments | 3,364 | — | 7,692 | — | |||||||||||||||||||
| Bad debt expense | 279 | 102 | 279 | 678 | |||||||||||||||||||
| Merger transaction costs | 5,580 | 888 | 27,121 | 909 | |||||||||||||||||||
General and administrative expense (including $2,289, $1,723, $6,096, and $4,436 respectively, of stock-based compensation) | 11,724 | 8,031 | 33,119 | 25,845 | |||||||||||||||||||
| Total operating expenses | 96,097 | 39,827 | 261,393 | 167,661 | |||||||||||||||||||
| Other income (expense): | |||||||||||||||||||||||
| Derivative gain (loss) | (36,224) | (10,670) | (133,613) | 64,603 | |||||||||||||||||||
| Interest expense, net | (3,025) | (356) | (6,685) | (1,557) | |||||||||||||||||||
| Gain (loss) on property transactions, net | 951 | — | 951 | (1,398) | |||||||||||||||||||
| Other income (expense) | 687 | (65) | 964 | (1,853) | |||||||||||||||||||
| Total other income (expense) | (37,611) | (11,091) | (138,383) | 59,795 | |||||||||||||||||||
| Income from operations before taxes | 56,255 | 7,940 | 20,381 | 47,589 | |||||||||||||||||||
| Income tax expense | (15,596) | (4,689) | (5,160) | (4,689) | |||||||||||||||||||
| Net income | $ | 40,659 | $ | 3,251 | $ | 15,221 | $ | 42,900 | |||||||||||||||
| Comprehensive income | $ | 40,659 | $ | 3,251 | $ | 15,221 | $ | 42,900 | |||||||||||||||
| Net income per common share: | |||||||||||||||||||||||
| Basic | $ | 1.32 | $ | 0.16 | $ | 0.55 | $ | 2.07 | |||||||||||||||
| Diluted | $ | 1.31 | $ | 0.16 | $ | 0.55 | $ | 2.06 | |||||||||||||||
| Weighted-average common shares outstanding: | |||||||||||||||||||||||
| Basic | 30,849 | 20,832 | 27,485 | 20,753 | |||||||||||||||||||
| Diluted | 31,138 | 20,903 | 27,839 | 20,826 | |||||||||||||||||||
The accompanying notes are an integral part of these condensed consolidated financial statements.
2
BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (UNAUDITED)
(in thousands, except share amounts)
| Additional | |||||||||||||||||||||||||||||
| Common Stock | Paid-In | Retained | |||||||||||||||||||||||||||
| Shares | Amount | Capital | Earnings | Total | |||||||||||||||||||||||||
| Balances, December 31, 2020 | 20,839,227 | $ | 4,282 | $ | 707,209 | $ | 333,761 | $ | 1,045,252 | ||||||||||||||||||||
| Restricted common stock issued | 109 | — | — | — | — | ||||||||||||||||||||||||
| Stock used for tax withholdings | (38) | — | — | — | — | ||||||||||||||||||||||||
| Exercise of stock options | 429 | — | 15 | — | 15 | ||||||||||||||||||||||||
| Stock-based compensation | — | — | 1,612 | — | 1,612 | ||||||||||||||||||||||||
| Net loss | — | — | — | (119) | (119) | ||||||||||||||||||||||||
| Balances, March 31, 2021 | 20,839,727 | 4,282 | 708,836 | 333,642 | 1,046,760 | ||||||||||||||||||||||||
| Issuance pursuant to acquisition | 9,802,166 | 98 | 374,835 | — | 374,933 | ||||||||||||||||||||||||
| Restricted common stock issued | 261,539 | — | — | — | — | ||||||||||||||||||||||||
| Stock used for tax withholdings | (70,330) | (2) | (2,814) | — | (2,816) | ||||||||||||||||||||||||
| Exercise of stock options | 11,523 | — | 394 | — | 394 | ||||||||||||||||||||||||
| Stock-based compensation | — | — | 2,195 | — | 2,195 | ||||||||||||||||||||||||
| Dividends declared | — | — | — | (11,033) | (11,033) | ||||||||||||||||||||||||
| Net loss | — | — | — | (25,319) | (25,319) | ||||||||||||||||||||||||
| Balances, June 30, 2021 | 30,844,625 | 4,378 | 1,083,446 | 297,290 | 1,385,114 | ||||||||||||||||||||||||
| Restricted common stock issued | 5,987 | — | — | — | — | ||||||||||||||||||||||||
| Stock used for tax withholdings | (1,725) | — | (74) | — | (74) | ||||||||||||||||||||||||
| Exercise of stock options | 9,926 | — | 307 | — | 307 | ||||||||||||||||||||||||
| Stock-based compensation | — | — | 2,289 | — | 2,289 | ||||||||||||||||||||||||
| Dividends declared | — | — | — | (11,045) | (11,045) | ||||||||||||||||||||||||
| Net income | — | — | — | 40,659 | 40,659 | ||||||||||||||||||||||||
| Balances, September 30, 2021 | 30,858,813 | $ | 4,378 | $ | 1,085,968 | $ | 326,904 | $ | 1,417,250 | ||||||||||||||||||||
| Balances, December 31, 2019 | 20,643,738 | $ | 4,284 | $ | 702,173 | $ | 230,233 | $ | 936,690 | ||||||||||||||||||||
| Restricted common stock issued | 13,674 | — | — | — | — | ||||||||||||||||||||||||
| Stock used for tax withholdings | (2,330) | — | (61) | — | (61) | ||||||||||||||||||||||||
| Stock-based compensation | — | — | 1,239 | — | 1,239 | ||||||||||||||||||||||||
| Net income | — | — | — | 78,551 | 78,551 | ||||||||||||||||||||||||
| Balances, March 31, 2020 | 20,655,082 | 4,284 | 703,351 | 308,784 | 1,016,419 | ||||||||||||||||||||||||
| Restricted common stock issued | 228,149 | — | — | — | — | ||||||||||||||||||||||||
| Stock used for tax withholdings | (56,904) | (2) | (951) | — | (953) | ||||||||||||||||||||||||
| Stock-based compensation | — | — | 1,474 | — | 1,474 | ||||||||||||||||||||||||
| Net loss | — | — | — | (38,902) | (38,902) | ||||||||||||||||||||||||
| Balances, June 30, 2020 | 20,826,327 | 4,282 | 703,874 | 269,882 | 978,038 | ||||||||||||||||||||||||
| Restricted common stock issued | 10,849 | — | — | — | — | ||||||||||||||||||||||||
| Stock used for tax withholdings | (3,148) | — | (60) | — | (60) | ||||||||||||||||||||||||
| Stock-based compensation | — | — | 1,723 | — | 1,723 | ||||||||||||||||||||||||
| Net income | — | — | — | 3,251 | 3,251 | ||||||||||||||||||||||||
| Balances, September 30, 2020 | 20,834,028 | $ | 4,282 | $ | 705,537 | $ | 273,133 | $ | 982,952 | ||||||||||||||||||||
The accompanying notes are an integral part of these condensed consolidated financial statements.
3
BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
(in thousands)
The accompanying notes are an integral part of these condensed consolidated financial statements.
| Nine Months Ended September 30, | |||||||||||
| 2021 | 2020 | ||||||||||
| Cash flows from operating activities: | |||||||||||
| Net income | $ | 15,221 | $ | 42,900 | |||||||
| Adjustments to reconcile net income to net cash provided by operating activities: | |||||||||||
| Depreciation, depletion, and amortization | 89,433 | 67,306 | |||||||||
| Deferred income tax expense | 5,368 | 4,689 | |||||||||
| Abandonment and impairment of unproved properties | 2,215 | 30,589 | |||||||||
| Stock-based compensation | 6,096 | 4,436 | |||||||||
| Non-cash lease component | 14 | (168) | |||||||||
| Amortization of deferred financing costs | 963 | 772 | |||||||||
| Derivative (gain) loss | 133,613 | (64,603) | |||||||||
| Derivative cash settlement gain (loss) | (50,536) | 42,494 | |||||||||
| (Gain) loss on property transactions, net | (951) | 1,398 | |||||||||
| Other | — | (1,166) | |||||||||
| Changes in current assets and liabilities: | |||||||||||
| Accounts receivable, net | (17,050) | 24,262 | |||||||||
| Prepaid expenses and other assets | 2,244 | 3,364 | |||||||||
| Accounts payable and accrued liabilities | 9,504 | (41,692) | |||||||||
| Settlement of asset retirement obligations | (3,891) | (3,137) | |||||||||
| Net cash provided by operating activities | 192,243 | 111,444 | |||||||||
| Cash flows from investing activities: | |||||||||||
| Acquisition of oil and gas properties | (620) | (853) | |||||||||
| Cash acquired | 49,827 | — | |||||||||
| Exploration and development of oil and gas properties | (104,207) | (56,216) | |||||||||
| Additions to other property and equipment | (72) | (440) | |||||||||
| Proceeds from note receivable | 204 | — | |||||||||
| Net cash used in investing activities | (54,868) | (57,509) | |||||||||
| Cash flows from financing activities: | |||||||||||
| Proceeds from credit facility | 155,000 | 45,000 | |||||||||
| Payments to credit facility | (249,000) | (105,000) | |||||||||
| Proceeds from exercise of stock options | 716 | — | |||||||||
| Payment of employee tax withholdings in exchange for the return of common stock | (2,890) | (1,074) | |||||||||
| Dividends paid | (21,598) | — | |||||||||
| Deferred financing costs | (3,915) | (13) | |||||||||
| Principal payments on finance lease obligations | (21) | (71) | |||||||||
| Net cash used in financing activities | (121,708) | (61,158) | |||||||||
| Net change in cash, cash equivalents, and restricted cash | 15,667 | (7,223) | |||||||||
| Cash, cash equivalents, and restricted cash: | |||||||||||
| Beginning of period | 24,845 | 11,095 | |||||||||
| End of period | $ | 40,512 | $ | 3,872 | |||||||
Supplemental cash flow disclosure(1): | |||||||||||
| Cash paid for interest, net of capitalization | $ | 1,684 | $ | 1,472 | |||||||
| Receivables exchanged for additional interests in oil and gas properties | $ | — | $ | 8,299 | |||||||
| Changes in working capital related to drilling expenditures | $ | (22,175) | $ | 610 | |||||||
(1) Refer to Note 4 - Leases in the notes to the condensed consolidated financial statements for supplemental cash flows related to leases. | |||||||||||
4
BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
NOTE 1 - ORGANIZATION AND BUSINESS
Bonanza Creek Energy, Inc. (“BCEI” or, together with our consolidated subsidiaries, the “Company”) is engaged primarily in acquiring, developing, extracting, and producing oil and gas properties. The Company’s assets and operations are concentrated in the rural portions of the Wattenberg Field in Colorado.
NOTE 2 - BASIS OF PRESENTATION
These unaudited condensed consolidated financial statements have been prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) for interim financial statements and pursuant to the rules and regulations of the Securities and Exchange Commission. In the opinion of management, the accompanying unaudited condensed consolidated financial statements reflect all adjustments consisting of normal recurring adjustments as necessary for a fair presentation of our financial position and results of operations.
The financial information as of December 31, 2020, has been derived from the audited financial statements contained in our Annual Report on Form 10-K for the year ended December 31, 2020 (“2020 Form 10-K”), but does not include all disclosures, including notes required by GAAP. As such, this quarterly report should be read in conjunction with the consolidated financial statements and related notes included in our 2020 Form 10-K. The Company follows the same accounting principles for preparing quarterly and annual reports. Certain prior period amounts have been reclassified to conform to the current period presentation. In connection with the preparation of the condensed consolidated financial statements, the Company evaluated subsequent events after the balance sheet date of September 30, 2021, through the filing date of this report.
Principles of Consolidation
The condensed consolidated balance sheets (“balance sheets”) include the accounts of the Company and its wholly owned subsidiaries. All intercompany accounts and transactions have been eliminated.
Use of Estimates
The preparation of the Company’s condensed consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of oil and gas reserves, assets and liabilities, and disclosure of contingent assets and liabilities at the date of the balance sheet and the reported amounts of revenue and expenses during the reporting period. Actual results could differ from those estimates. The results of operations for the three and nine months ended September 30, 2021, are not necessarily indicative of the results that may be expected for the year ending December 31, 2021. Further these estimates and other factors, including those outside of the Company's control, such as the impact of commodity prices, may impact the Company's business, financial condition, results of operations and cash flows.
Industry Segment and Geographic Information
The Company operates in one industry segment, which is the development and production of oil, natural gas, and natural gas liquids (“NGLs”), and all of the Company's operations are conducted in the continental United States.
Revenue Recognition
Sales of oil, natural gas, and NGLs are recognized when performance obligations are satisfied at the point control of the product is transferred to the customer. The Company's contracts' pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of the oil or natural gas, and prevailing supply and demand conditions. As a result, the price of the oil, natural gas, and NGLs fluctuates to remain competitive with other available oil, natural gas, and NGLs supplies.
As further described in Note 6 - Commitments and Contingencies, one contract with NGL Crude Logistics, LLP (“NGL Crude”, known as the “NGL Crude agreement”) has an additional aspect of variable consideration related to the minimum volume commitments (“MVCs”) as specified in the agreement. On an on-going basis, the Company performs an analysis of expected risk adjusted production applicable to the NGL Crude agreement based on approved production plans to determine if liquidated damages to NGL Crude are probable. As of September 30, 2021, the Company believes that the volumes delivered to NGL Crude will be in excess of the MVCs required based on our approved future production plan. As a result of
5
this analysis, to date, no variable consideration related to potential liquidated damages has been considered in the transaction price for the NGL Crude agreement.
Under the oil sales contracts, the Company sells oil production at the wellhead, or other contractually agreed-upon delivery points, and collects an agreed-upon index price, net of pricing differentials. In this scenario, the Company recognizes revenue when control transfers to the purchaser at the wellhead, or other contractually agreed-upon delivery point, at the net contracted price received.
Under the natural gas processing contracts, the Company delivers natural gas to an agreed-upon delivery point. The delivery points are specified within each contract, and the transfer of control varies between the inlet and outlet of the midstream processing facility. The midstream processing entity gathers and processes the natural gas and remits proceeds to the Company for the resulting sales of NGLs and residue gas. For the contracts where the Company maintains control through the outlet of the midstream processing facility, the Company recognizes revenue on a gross basis, with gathering, transportation, and processing fees presented as an expense in the Company's accompanying condensed consolidated statements of operations and comprehensive income (loss) (“statements of operations”). Alternatively, for those contracts where the Company relinquishes control at the inlet of the midstream processing facility, the Company recognizes natural gas and NGLs revenues based on the contracted amount of the proceeds received from the midstream processing entity and, as a result, the Company recognizes revenue on a net basis.
Under the product sales contracts, the Company invoices customers once the performance obligations have been satisfied, at which point payment is unconditional. Accordingly, the Company's product sales contracts do not give rise to contract assets or liabilities under this guidance. At September 30, 2021 and December 31, 2020, the Company's receivables from contracts with customers were $86.4 million and $32.7 million, respectively. Payment is generally received within 30 to 60 days after the date of production.
The Company records revenue in the month production is delivered to the purchaser. However, as stated above, settlement statements for certain natural gas and NGLs sales may not be received for 30 to 60 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The Company records the differences between its estimates and the actual amounts received for product sales in the month in which payment is received from the purchaser. For the period from January 1, 2021 through September 30, 2021, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was insignificant.
Revenue attributable to each identified revenue stream is disaggregated below (in thousands):
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
| 2021 | 2020 | 2021 | 2020 | ||||||||||||||||||||
| Operating Revenues: | |||||||||||||||||||||||
| Crude oil sales | $ | 131,360 | $ | 47,251 | $ | 297,515 | $ | 127,331 | |||||||||||||||
| Natural gas sales | 24,764 | 5,742 | 53,064 | 16,472 | |||||||||||||||||||
| Natural gas liquids sales | 33,839 | 5,865 | 69,578 | 11,652 | |||||||||||||||||||
| Oil and gas sales | $ | 189,963 | $ | 58,858 | $ | 420,157 | $ | 155,455 | |||||||||||||||
Restricted Cash
The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the balance sheets, which sums to the total of such amounts shown in the accompanying condensed consolidated statements of cash flows (“statements of cash flows”) (in thousands):
__________________________
| As of September 30, | |||||||||||
| 2021 | 2020 | ||||||||||
| Cash and cash equivalents | $ | 40,410 | $ | 3,777 | |||||||
Restricted cash(1) | 102 | 95 | |||||||||
| Total cash, cash equivalents, and restricted cash | $ | 40,512 | $ | 3,872 | |||||||
(1) Included in other noncurrent assets and consists of funds for road maintenance and repairs.
6
Unproved Property
Unproved oil and gas property costs are evaluated for impairment when there is an indication that the carrying costs may not be fully recoverable. During the three and nine months ended September 30, 2021, the Company incurred zero and $2.2 million, respectively, in abandonment and impairment of unproved properties compared to $0.2 million and $30.6 million during the three and nine months ended September 30, 2020, respectively, due to the reassessment of estimated probable and possible reserve locations based primarily upon economic viability and the expiration of non-core leases.
Accounts Payable and Accrued Expenses
Accounts payable and accrued expenses contain the following (in thousands):
As of September 30, 2021 | As of December 31, 2020 | ||||||||||
| Accrued drilling and completion costs | $ | 22,628 | $ | 453 | |||||||
| Accounts payable trade | 11,740 | 1,931 | |||||||||
| Accrued general and administrative expense | 6,667 | 4,942 | |||||||||
| Accrued merger transaction costs | 991 | 2,587 | |||||||||
| Accrued lease operating expense | 2,893 | 1,793 | |||||||||
| Accrued interest expense | 4,359 | 322 | |||||||||
| Accrued oil and gas hedging | 6,767 | — | |||||||||
| Accrued production and ad valorem taxes and other | 39,006 | 25,397 | |||||||||
| Total accounts payable and accrued expenses | $ | 95,051 | $ | 37,425 | |||||||
Accounting Pronouncements Recently Adopted and Issued
In March 2020, the FASB issued Update No. 2020-04, Reference Rate Reform (Topic 848), which provides temporary optional guidance to companies impacted by the transition away from the LIBOR. The amendment provides certain expedients and exceptions to applying GAAP in order to lessen the potential accounting burden when contracts, hedging relationships, and other transactions that reference LIBOR as a benchmark rate are modified. Further, in January 2021, the FASB issued Update No. 2021-01, Reference Rate Reform (Topic 848), which clarifies the scope of Topic 848 so that derivatives affected by the discounting transition are explicitly eligible for certain optional expedients and exceptions in Topic 848. These amendments are effective upon issuance and expire on December 31, 2022. The Company is currently assessing the impact of the LIBOR transition on the Company's condensed consolidated financial statements.
There are no other accounting standards applicable to the Company that would have a material effect on the Company's condensed consolidated financial statements and disclosures that have been issued but not yet adopted by the Company as of September 30, 2021, and through the filing date of this report.
NOTE 3 - ACQUISITIONS & DIVESTITURES
HighPoint Acquisition
On April 1, 2021, Bonanza Creek completed its previously announced acquisition of HighPoint Resources Corporation, a Delaware corporation (“HighPoint”), pursuant to the terms of HighPoint’s prepackaged plan of reorganization under Chapter 11 of the United States Bankruptcy Code (the “Prepackaged Plan”), which was confirmed by the U.S. Bankruptcy Court for the District of Delaware on March 18, 2021 pursuant to a confirmation order, and went effective on April 1, 2021 (the “HighPoint Merger”).
The Prepackaged Plan implements the merger and restructuring transactions in accordance with the Agreement and Plan of Merger, dated as of November 9, 2020 (the “HighPoint Merger Agreement”), by and among Bonanza Creek, HighPoint and Boron Merger Sub, Inc., a wholly-owned subsidiary of Bonanza Creek (“Merger Sub”). Pursuant to the Prepackaged Plan and the HighPoint Merger Agreement, at the effective time of the HighPoint Merger (the “Effective Time”) and the effective date under the Prepackaged Plan, Merger Sub merged with and into HighPoint, with HighPoint continuing as the surviving corporation and wholly-owned subsidiary of Bonanza Creek. At the Effective Time, each eligible share of common stock, par value $0.001 per share, of HighPoint issued and outstanding immediately prior to the Effective Time was automatically converted into the right to receive 0.11464 shares of common stock, par value $0.01 per share, of Bonanza Creek (“Bonanza Creek Common Stock”), with cash paid in lieu of the issuance of any fractional shares. As a result, the Company issued approximately 487,952 shares of Bonanza Creek Common Stock to former HighPoint stockholders.
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Concurrently with the HighPoint Merger and pursuant to the Prepackaged Plan, and in exchange for the $625 million in aggregate principal amount outstanding of 7.0% Senior Notes due 2022 of HighPoint Operating Corporation (“HighPoint OpCo”) and 8.75% Senior Notes due 2025 of HighPoint OpCo (collectively, the “HighPoint Senior Notes”), Bonanza Creek issued to all holders of HighPoint Senior Notes an aggregate of (i) 9,314,214 shares of Bonanza Creek Common Stock and (ii) $100 million aggregate principal amount of 7.5% Senior Notes due 2026 of Bonanza Creek (“Bonanza Creek 7.5% Senior Notes”). Please refer to Note 5 - Long-term Debt for further discussion of the Bonanza Creek 7.5% Senior Notes.
Immediately after the Effective Time, in connection with the HighPoint Merger, Bonanza Creek entered into the Second Amendment, dated April 1, 2021, to the Credit Facility. Please refer to Note 5 - Long-term Debt for further discussion.
The following tables present the HighPoint Merger consideration and purchase price allocation of the assets acquired and the liabilities assumed in the HighPoint Merger:
| Merger Consideration (in thousands except per share amount) | ||||||||
Shares of Bonanza Creek Common Stock issued to existing holders of HighPoint Common Stock(1) | 488 | |||||||
| Shares of Bonanza Creek Common Stock issued to existing holders of HighPoint Senior Notes | 9,314 | |||||||
| Total additional shares of Bonanza Creek Common Stock issued as merger consideration | 9,802 | |||||||
Closing price per share of Bonanza Creek Common Stock(2) | $ | 38.25 | ||||||
| Merger consideration paid in shares of Bonanza Creek Common Stock | $ | 374,933 | ||||||
Aggregate principal amount of Bonanza Creek 7.5% Senior Notes | 100,000 | |||||||
| Total merger consideration | $ | 474,933 | ||||||
_________________________
(1) Based on the number of shares of HighPoint Common Stock issued and outstanding as of April 1, 2021 and the conversion ratio of 0.11464 per share of Bonanza Creek Common Stock.
(2) Based on the closing stock price of Bonanza Creek Common Stock on April 1, 2021.
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| Purchase Price Allocation (in thousands) | ||||||||
| Assets Acquired | ||||||||
| Cash and cash equivalents | $ | 49,827 | ||||||
| Accounts receivable - oil and gas sales | 26,343 | |||||||
| Accounts receivable - joint interest and other | 9,161 | |||||||
| Prepaid expenses and other | 3,608 | |||||||
| Inventory of oilfield equipment | 4,688 | |||||||
| Proved properties | 539,820 | |||||||
| Other property and equipment, net of accumulated depreciation | 2,769 | |||||||
| Right-of-use assets | 4,010 | |||||||
| Deferred income tax assets | 110,513 | |||||||
| Other noncurrent assets | 797 | |||||||
| Total assets acquired | $ | 751,536 | ||||||
| Liabilities Assumed | ||||||||
| Accounts payable and accrued expenses | $ | 51,088 | ||||||
| Oil and gas revenue distribution payable | 20,786 | |||||||
| Lease liability | 744 | |||||||
| Derivative liability | 13,481 | |||||||
| Current portion of long-term debt | 154,000 | |||||||
| Lease liability (long-term) | 3,266 | |||||||
| Ad valorem taxes | 3,746 | |||||||
| Derivative liability (long-term) | 5,019 | |||||||
| Asset retirement obligations for oil and gas properties | 24,473 | |||||||
| Total liabilities assumed | 276,603 | |||||||
| Net assets acquired | $ | 474,933 | ||||||
As part of the HighPoint Merger, the Company obtained net operating losses of $170.6 million. The HighPoint Merger was accounted for under the acquisition method of accounting for business combinations. Accordingly, we conducted assessments of the net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values, while transaction and integration costs associated with the acquisition were expensed as incurred. The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market, and therefore represent Level 3 inputs. The fair values of crude oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of proved oil and gas properties include estimates of reserves, future operating and development costs, future commodity prices, estimated future cash flows, and a market-based weighted-average cost of capital rate of approximately 13%. These inputs require significant judgments and estimates by management at the time of the valuation.
The following unaudited pro forma financial information represents a summary of the consolidated results of operations for the nine months ended September 30, 2021 and for the three and nine months ended September 30, 2020, assuming the acquisition had been completed as of January 1, 2020. The financial information for the three months ended September 30, 2021 is included in our statement of operations and therefore does not require a pro forma disclosure. The pro forma financial information includes certain non-recurring pro forma adjustments that were directly attributable to the business combination. The pro forma financial information is not necessarily indicative of the results of operations that would have been achieved if the acquisition had been effective as of these dates, or of future results.
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| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||
| 2020 | 2021 | 2020 | |||||||||||||||
| (in thousands, except per share data) | |||||||||||||||||
| Total revenue | $ | 126,163 | $ | 492,176 | $ | 345,626 | |||||||||||
| Net income (loss) | 16,030 | (26,058) | (1,007,643) | ||||||||||||||
| Net income (loss) per common share: | |||||||||||||||||
| Basic | $ | 0.52 | $ | (0.84) | $ | (32.98) | |||||||||||
| Diluted | $ | 0.52 | $ | (0.84) | $ | (32.98) | |||||||||||
Extraction Merger
On May 9, 2021, Bonanza Creek, Raptor Eagle Merger Sub, Inc., a Delaware corporation and a wholly owned subsidiary of Bonanza Creek, and Extraction Oil & Gas, Inc., a Delaware corporation (“XOG”), entered into an Agreement and Plan of Merger (the “XOG Merger Agreement”), providing for a merger of equals between Bonanza Creek and XOG (the “XOG Merger”). The XOG Merger is expected to close in November 2021, contingent upon a number of factors disclosed in the XOG Merger Agreement. Once closed, the Company intends to increase annual dividend payments to approximately $1.60 per share.
Crestone Peak Merger
On June 6, 2021, Bonanza Creek, Raptor Condor Merger Sub 1, Inc., a Delaware corporation and a wholly owned subsidiary of Bonanza Creek (“Merger Sub 1”), Raptor Condor Merger Sub 2, LLC, a Delaware limited liability company and a wholly owned subsidiary of BCEI (“Merger Sub 2”), Crestone Peak Resources LP, a Delaware limited partnership (“CPR”), CPPIB Crestone Peak Resources America Inc., a Delaware corporation (“Crestone Peak”), Crestone Peak Resources Management LP, a Delaware limited partnership (“CPR Management LP”), and, Extraction Oil & Gas, Inc., a Delaware corporation, entered into an Agreement and Plan of Merger (the “Crestone Peak Merger Agreement”).
The Crestone Peak Merger Agreement, among other things, provides for the Company's acquisition of Crestone Peak through (i) the merger of Merger Sub 1 with and into Crestone Peak (the “Merger Sub 1 Merger”), with Crestone Peak continuing its existence as the surviving corporation following the Merger Sub 1 Merger (the “Surviving Corporation”), and (ii) the subsequent merger of the Surviving Corporation with and into Merger Sub 2 (the “Merger Sub 2 Merger” and together with the Merger Sub 1 Merger, the “Crestone Peak Merger”), with Merger Sub 2 continuing as the surviving entity as a wholly owned subsidiary of Bonanza Creek.
The closing of the Crestone Peak Merger is expressly conditioned on the closing of the previously announced XOG Merger pursuant to the XOG Merger Agreement. The Crestone Peak Merger is expected to close in conjunction with the XOG merger in November 2021, contingent upon a number of factors disclosed in the Crestone Peak Merger Agreement. Once closed, the Company intends to increase annual dividend payments to approximately $1.85 per share.
Merger transaction costs of $5.6 million and $27.1 million related to the aforementioned mergers and acquisitions were accounted for separately from the assets and liabilities assumed and are included in merger transaction costs in the Company's statements of operations for the three and nine months ended September 30, 2021, respectively.
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NOTE 4 - LEASES
The Company's right-of-use assets and lease liabilities are recognized at their discounted present value on the balance sheet, which include leases related to the asset classes reflected as of the dates indicated in the table below (in thousands):
__________________________
| September 30, 2021 | December 31, 2020 | |||||||||||||
| Operating leases | ||||||||||||||
Field equipment(1) | $ | 20,716 | $ | 27,537 | ||||||||||
| Corporate leases | 6,519 | 1,481 | ||||||||||||
| Vehicles | 811 | 468 | ||||||||||||
| Total right-of-use asset | $ | 28,046 | $ | 29,486 | ||||||||||
Field equipment(1) | $ | 20,716 | $ | 27,537 | ||||||||||
| Corporate leases | 6,830 | 1,900 | ||||||||||||
| Vehicles | 811 | 468 | ||||||||||||
| Total lease liability | $ | 28,357 | $ | 29,905 | ||||||||||
| Finance leases | ||||||||||||||
Right-of-use asset - field equipment(1) | $ | — | $ | 219 | ||||||||||
Lease liability - field equipment(1) | $ | — | $ | 117 | ||||||||||
(1) Includes compressors, certain gas processing equipment, and other field equipment.
The lease amounts disclosed are presented on a gross basis. A portion of these costs may have been or will be billed to other working interest owners, and the Company's net share of these costs, once paid, are included in various line items on the statements of operations or capitalized to oil and gas properties or other property and equipment, as applicable.
The Company recognizes operating lease expense on a straight-line basis. Finance lease expense is recognized based on the effective interest method for the lease liability and straight-line amortization for the right-of-use asset, resulting in more cost being recognized in earlier lease periods. Short-term and variable lease payments are recognized as incurred. Short-term lease cost represents payments for leases with a lease term of one year or less, excluding leases with a term of one month or less. Short-term leases include drilling rigs and other equipment. Drilling rig contracts are structured based on an allotted number of wells to be drilled consecutively at a daily operating rate. Short-term drilling rig costs include a non-lease labor component, which is treated as a single lease component.
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The following table summarizes the components of the Company's gross lease costs incurred during the three and nine months ended September 30, 2021 and 2020 (in thousands):
| Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||||||||||
| 2021 | 2020 | 2021 | 2020 | |||||||||||||||||||||||
Operating lease cost(1) | $ | 3,635 | $ | 3,462 | $ | 10,529 | $ | 10,560 | ||||||||||||||||||
| Finance lease cost: | ||||||||||||||||||||||||||
Amortization of right-of-use assets | — | 6 | 3 | 13 | ||||||||||||||||||||||
| Interest on lease liabilities | — | 1 | 1 | 3 | ||||||||||||||||||||||
| Short-term lease cost | 281 | 129 | 492 | 2,011 | ||||||||||||||||||||||
Variable lease cost(2) | (9) | (89) | 56 | (133) | ||||||||||||||||||||||
Sublease income(3) | (91) | (89) | (274) | (267) | ||||||||||||||||||||||
| Total lease cost | $ | 3,816 | $ | 3,420 | $ | 10,807 | $ | 12,187 | ||||||||||||||||||
____________________________
(1) Includes office rent expense of $0.5 million and $0.3 million for the three months ended September 30, 2021 and 2020, respectively, and $1.3 million and $0.8 million for the nine months ended September 30, 2021 and 2020, respectively.
(2) Variable lease cost represents differences between lease obligations and actual costs incurred for certain leases that do not have fixed payments related to both lease and non-lease components. Such incremental costs include lease payment increases or decreases driven by market price fluctuations and leased asset maintenance costs.
(3) The Company has subleased a portion of one of its office spaces for the remainder of the office lease term.
The Company does not have any leases with an implicit interest rate that can be readily determined. As a result, the Company used the incremental borrowing rate, based on the Credit Facility benchmark rate, adjusted for facility utilization and lease term, to calculate the respective discount rates. Please refer to Note 5 - Long-term Debt for additional information.
The Company has certain lease agreements that provide for the option to extend, purchase, or terminate early, which was evaluated on each lease to arrive at the proper lease term. There were some leases for which the option to extend or purchase was factored into the resulting lease term. There were no leases where early termination was factored into the resulting lease term. The Company's weighted-average remaining lease terms and discount rates for operating leases as of September 30, 2021 are as follows:
| Operating Leases | ||||||||
| Weighted-average lease term (years) | 3.2 | |||||||
| Weighted-average discount rate | 3.97% | |||||||
Supplemental cash flow information related to leases for the three and nine months ended September 30, 2021 and 2020 consisted of the following (in thousands):
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
| 2021 | 2020 | 2021 | 2020 | ||||||||||||||||||||
| Cash paid for amounts included in the measurement of lease liabilities: | |||||||||||||||||||||||
| Operating cash flows from operating leases | $ | 3,293 | $ | 3,187 | $ | 9,783 | $ | 9,599 | |||||||||||||||
| Operating cash flows from finance leases | — | 1 | 1 | 3 | |||||||||||||||||||
| Financing cash flows from finance leases | — | 31 | 21 | 71 | |||||||||||||||||||
| Right-of-use assets obtained in exchange for new operating lease obligations | $ | 3,136 | $ | 918 | $ | 8,635 | $ | 8,306 | |||||||||||||||
| Right-of-use assets obtained in exchange for new finance lease obligations | — | — | — | 219 | |||||||||||||||||||
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As of September 30, 2021, future commitments by year for the Company's operating with a lease term of one year or more are presented in the table below. Such commitments are reflected at undiscounted values and are reconciled to the discounted present value recognized on the balance sheet as follows (in thousands):
| Operating Leases | ||||||||
| Remainder of 2021 | $ | 3,557 | ||||||
| 2022 | 11,594 | |||||||
| 2023 | 7,509 | |||||||
| 2024 | 3,564 | |||||||
| 2025 | 1,290 | |||||||
| Thereafter | 2,765 | |||||||
| Total lease payments | 30,279 | |||||||
| Less: imputed interest | (1,922) | |||||||
| Total lease liability | $ | 28,357 | ||||||
NOTE 5 - LONG-TERM DEBT
Senior Notes
In conjunction with the HighPoint Merger, Bonanza Creek issued $100 million aggregate principal amount of 7.5% Senior Notes due 2026 pursuant to an indenture (the “Indenture”), dated April 1, 2021, by and among Bonanza Creek, U.S. Bank National Association, as trustee (the “Trustee”), and the subsidiary guarantors party thereto. The Bonanza Creek 7.5% Senior Notes are the senior unsecured obligations of Bonanza Creek and the subsidiaries of Bonanza Creek that are guarantors of the Bonanza Creek 7.5% Senior Notes. The Indenture contains restrictive covenants that, among other things, restrict the ability of Bonanza Creek and each of its restricted subsidiaries to: (i) incur additional indebtedness and issue preferred stock; (ii) pay dividends or make other distributions in respect of Bonanza Creek common stock; (iii) make other restricted payments and investments; (iv) create liens; (v) restrict distributions or other payments from Bonanza Creek’s restricted subsidiaries; (v) sell assets, including capital stock of restricted subsidiaries; (vi) merge or consolidate with other entities; and (vi) enter into transactions with affiliates. These restrictive covenants are subject to a number of important qualifications and limitations. In addition, certain of these restrictive covenants will be suspended before the Bonanza Creek 7.5% Senior Notes mature if at any time no default or event of default exists under the Indenture and the Bonanza Creek 7.5% Senior Notes receive an investment grade rating from at least two ratings agencies. The Indenture also contains customary events of default.
The Bonanza Creek 7.5% Senior Notes will be redeemable at the Company’s option (an “Optional Redemption”), in whole or in part, prior to April 30, 2022 at a redemption price equal to 107.5% of the aggregate principal to be redeemed, plus unpaid accrued interest, if any, through the Optional Redemption date. On or after April 30, 2022, the Optional Redemption price will be equal to 100.00% of the aggregate principal amount of the Bonanza Creek 7.5% Senior Notes to be redeemed, plus unpaid accrued interest, if any, through Optional Redemption date.
The Bonanza Creek 7.5% Senior Notes will be fully and unconditionally guaranteed, jointly and severally, on a senior basis by each restricted subsidiary that guarantees a credit facility (as defined in the Indenture) of Bonanza Creek.
Immediately after the Effective Time, HighPoint, HighPoint OpCo, and Fifth Pocket Production, LLC, a Colorado limited liability company (collectively, the “HighPoint guarantors”), Bonanza Creek, and the Trustee entered into a first supplemental indenture (the “First Supplemental Indenture”), dated April 1, 2021, to the Indenture, pursuant to which such HighPoint guarantors unconditionally guaranteed all of Bonanza Creek’s obligations under the Bonanza Creek 7.5% Senior Notes and the Indenture.
Credit Facility
In December 2018, the Company entered into a reserve-based revolving facility, as the borrower, with JPMorgan Chase Bank, N.A., as the administrative agent, and a syndicate of financial institutions, as lenders (the “Credit Facility”). The Credit Facility has a maturity date of December 7, 2023. The April 2021 redetermination as part of the Second Amendment (defined below) resulted in a borrowing base of $500.0 million, with elected commitments set at $400.0 million. The most recent redetermination was concluded in July 2021, resulting in a reaffirmation of the borrowing base at $500.0 million and aggregate elected commitments at $400.0 million. The next redetermination is set to occur in November 2021, unless otherwise redetermined through the closing of the XOG and Crestone Peak mergers.
13
The Credit Facility is guaranteed by all wholly owned subsidiaries of the Company (each, a “Guarantor” and, together with the Company, the “Credit Parties”), and is secured by first priority security interests on substantially all assets of each Credit Party, subject to customary exceptions.
The Credit Facility contains customary representations and affirmative covenants. The Credit Facility also contains customary negative covenants, which, among other things, and subject to certain exceptions, include restrictions on (i) liens, (ii) indebtedness, guarantees and other obligations, (iii) restrictions in agreements on liens and distributions, (iv) mergers or consolidations, (v) asset sales, (vi) restricted payments, (vii) investments, (viii) affiliate transactions, (ix) change of business, (x) foreign operations or subsidiaries, (xi) name changes, (xii) use of proceeds, letters of credit, (xiii) gas imbalances, (xiv) hedging transactions, (xv) additional subsidiaries, (xvi) changes in fiscal year or fiscal quarter, (xvii) operating leases, (xviii) prepayments of certain debt and other obligations, (xix) sales or discounts of receivables, (xx) dividend payment thresholds, and (xi) cash balances. The Credit Parties are subject to certain financial covenants under the Credit Facility, as tested on the last day of each fiscal quarter, including, without limitation, (i) a maximum ratio of the Company's consolidated indebtedness (subject to certain exclusions) to earnings before interest, income taxes, depreciation, depletion, and amortization, exploration expense, and other non-cash charges (“EBITDAX”) and (ii) a current ratio, as defined in the agreement, inclusive of the unused commitments then available to be borrowed, to not be less than 1.00 to 1.00.
Under the terms of the Credit Facility, as amended in June 2020 (the “First Amendment”), borrowings bore interest at a per annum rate equal to, at the option of the Company, either (i) a LIBOR, subject to a 0% LIBOR floor plus a margin of 2.00% to 3.00%, based on the utilization of the Credit Facility (the “Eurodollar Rate”) or (ii) a fluctuating interest rate per annum equal to the greatest of (a) the rate of interest publicly announced by JPMorgan Chase Bank, N.A. as its prime rate, (b) the rate of interest published by the Federal Reserve Bank of New York as the federal funds effective rate, (c) the rate of interest published by the Federal Reserve Bank of New York as the overnight bank funding rate, or (d) a LIBOR offered rate for a one-month interest period, subject to a 0% LIBOR floor plus a margin of 1.00% to 2.00%, based on the utilization of the Credit Facility (the “Reference Rate”). Interest on borrowings that bear interest at the Eurodollar Rate shall be payable on the last day of the applicable interest period selected by the Company, which shall be one, two, three, or six months, and interest on borrowings that bear interest at the Reference Rate shall be payable quarterly in arrears.
On April 1, 2021, in conjunction with the HighPoint Merger, the Company, together with certain of its subsidiaries, entered into the Second Amendment (the “Second Amendment”) to the Credit Facility (as amended, restated, supplemented or otherwise modified) to, among other things: (i) increase the aggregate maximum commitment amount from $750.0 million to $1.0 billion; (ii) increase the available borrowing base from $260.0 million to $500.0 million; (iii) increase the Eurodollar Rate margin to 3.00% to 4.00%; (iv) increase the Reference Rate margin to 2.00% to 3.00%; (v) increase (A) the LIBOR floor from 0% to .50% and (B) the alternate base rate floor from 0% to 1.50%; (vi) decrease for any fiscal quarter ending on or after April 1, 2021, the maximum permitted net leverage ratio from 3.50 to 3.0; and (viii) amend certain other covenants and provisions.
The Company was in compliance with all covenants as of September 30, 2021, and through the filing date of this report.
As of September 30, 2021 and December 31, 2020, the Company had $60.0 million and zero, respectively, outstanding on the Credit Facility. As of the date of this filing, the outstanding balance was zero. The Company's Credit Facility approximates fair value as the applicable interest rates are floating.
In connection with the Second Amendment, the Company capitalized an incremental $3.9 million in deferred financing costs. Of the total post-amortization net capitalized deferred financing costs, (i) $2.2 million and $0.7 million, as of September 30, 2021 and December 31, 2020, respectively, are presented within other noncurrent assets and (ii) $1.8 million and $0.4 million, as of September 30, 2021 and December 31, 2020, respectively, are presented within prepaid expenses and other line items in the accompanying balance sheets.
Interest Expense
For the three months ended September 30, 2021 and 2020, the Company incurred interest expense of $3.7 million and $0.7 million, respectively, and capitalized $0.6 million and $0.3 million during the three months ended September 30, 2021 and 2020, respectively. For the nine months ended September 30, 2021 and 2020, the Company incurred interest expense of $7.9 million and $3.3 million, respectively, and capitalized $1.2 million and $1.7 million during the nine months ended September 30, 2021 and 2020, respectively.
14
NOTE 6 - COMMITMENTS AND CONTINGENCIES
Legal Proceedings
From time to time, the Company is involved in various commercial and regulatory claims, litigation, and other legal proceedings that arise in the ordinary course of its business. The Company assesses these claims in an effort to determine the degree of probability and range of possible loss for potential accrual in its condensed consolidated financial statements. In accordance with authoritative accounting guidance, an accrual is recorded for a loss contingency when its occurrence is probable and damages can be reasonably estimated based on the most likely anticipated outcome or the minimum amount within a range of possible outcomes. Because legal proceedings are inherently unpredictable and unfavorable resolutions could occur, assessing contingencies is highly subjective and requires judgments about uncertain future events. When evaluating contingencies, the Company may be unable to provide a meaningful estimate due to a number of factors, including the procedural status of the matter in question, the presence of complex or novel legal theories, and/or the ongoing discovery and development of information important to the matters. The Company regularly reviews contingencies to determine the adequacy of its accruals and related disclosures. No claims have been made, nor is the Company aware of any material uninsured liability which the Company may have, as it relates to any environmental cleanup, restoration, or the violation of any rules or regulations. As of the filing date of this report, there were no probable, material pending, or overtly threatened legal actions against the Company of which it was aware.
Upon closing of the HighPoint Merger, the Company assumed all obligations, whether asserted or unasserted, of HighPoint Resources Corporation. As of the filing date of this report, there were no probable, material pending, or overtly threatened legal actions against the Company that were associated with HighPoint of which it was aware, other than the following:
On June 15, 2020, Sterling Energy Investments LLC (“Sterling”) filed a complaint against HighPoint OpCo, a subsidiary of HighPoint Resources Corporation, for breach of contract related to a Gas Purchase Agreement, effective November 1, 2017. Sterling alleges that HighPoint OpCo breached the contract by failing to use reasonable commercial efforts to deliver to Sterling at Sterling’s receipt points all quantities of gas not otherwise dedicated to other gas purchase agreements. HighPoint Resources OpCo filed a counterclaim against Sterling for breach of Sterling’s obligations under the Gas Purchase Agreement. The case was adjudicated in July 2021, and a decision was issued on October 25, 2021, finding in favor of HighPoint and awarding approximately $2.4 million in damages with respect to HighPoint’s counterclaim.
Disclosure of certain environmental matters is required when a governmental authority is a party to the proceedings and the proceedings involve potential monetary sanctions that the Company believes could exceed $0.3 million. HighPoint Resources Corporation received Notices of Alleged Violations (“NOAV”) from the Colorado Oil and Gas Conservation Commission (“COGCC”) alleging violations of various Colorado statutes and COGCC regulations governing oil and gas operations. The Company continues to engage in discussions regarding resolution of the alleged violations. There were approximately $0.9 million worth of NOAVs dismissed by the COGCC during the quarter ended September 30, 2021. As of September 30, 2021, the Company has recognized approximately $0.9 million associated with the NOAVs, as they are probable and reasonably estimable.
Commitments
Firm Transportation Agreements. As part of the HighPoint Merger, the Company became party to two firm transportation contracts. Both firm transportation contracts required the pipeline to provide a guaranteed outlet for production through July 2021. The Company did not utilize the firm capacity on the natural gas pipelines and incurred deficiency payments totaling $3.4 million and $7.7 million for the three and nine months ended September 30, 2021, respectively, which are included in unused commitments expense in the statements of operations.
Additionally, the Company is party to one firm pipeline transportation contract to provide a guaranteed outlet for production on an oil pipeline system. The contract requires the Company to pay minimum volume transportation charges on 8,500 gross barrels per day through April 2022 and 12,500 barrels per day thereafter through April 2025, regardless of the amount of pipeline capacity utilized by the Company. The aggregate financial commitment fee over the remaining term was $49.6 million as of September 30, 2021. The Company expects to utilize most, if not all, of the firm capacity on the oil pipeline system.
Minimum Volume Agreements. The Company is party to a purchase agreement to deliver fixed determinable quantities of crude oil to NGL Crude. The NGL Crude agreement includes defined volume commitments over a term ending in 2023. Under the terms of the NGL Crude agreement, the Company is required to make periodic deficiency payments for any shortfalls in delivering minimum gross volume commitments, which are set in six-month periods. The minimum gross volume commitment will increase approximately 3% each year for the remainder of the contract, to a maximum of approximately
15
16,000 gross barrels per day. The aggregate financial commitment fee over the remaining term was $41.7 million as of September 30, 2021. Upon notifying NGL Crude at least twelve months prior to the expiration date of the NGL Crude agreement, the Company may elect to extend the term of the NGL Crude agreement for up to additional years. Since the commencement of the NGL Crude agreement and through the remainder of the term of the agreement, the Company has not and does not expect to incur any deficiency payments.
The Company is also party to minimum volume commitments to purchase fresh water from water suppliers as well as one minimum volume commitment for the delivery of natural gas volumes to a midstream entity for gathering and processing. These commitments require the Company to pay a fee associated with the minimum volumes regardless of the amount delivered. The aggregate financial commitment fee over the remaining term for these contracts was $3.0 million as of September 30, 2021.
The minimum annual payments under the these agreements for the next five years as of September 30, 2021 are presented below (in thousands):
| Firm Transportation | Minimum Volume(1) | ||||||||||
| Remainder of 2021 | $ | 2,502 | $ | 6,209 | |||||||
| 2022 | 13,064 | 29,207 | |||||||||
| 2023 | 14,600 | 9,314 | |||||||||
| 2024 | 14,640 | — | |||||||||
| 2025 | 4,800 | — | |||||||||
| 2026 and thereafter | — | — | |||||||||
| Total | $ | 49,606 | $ | 44,730 | |||||||
____________________________
(1) The above calculation is based on the minimum volume commitment schedule (as defined in the relevant agreements) and applicable differential fees.
There have been no other material changes from the commitments disclosed in the notes to the Company's consolidated financial statements included in our 2020 Form 10-K. Refer to Note 4 - Leases, for lease commitments.
NOTE 7 - STOCK-BASED COMPENSATION
Long Term Incentive Plans
In 2017, the Company adopted a Long Term Incentive Plan (“2017 LTIP”), which allows for the issuance of restricted stock units (“RSUs”), performance stock units (“PSUs”), and options, and reserved 2,467,430 shares of common stock. Additionally, in June 2021, the Company adopted the 2021 Long Term Incentive Plan (“2021 LTIP”), which reserved an incremental 700,000 shares of common stock in addition to the 2017 LTIP. The 2017 LTIP and 2021 LTIP shall be collectively referred herein as the “LTIP”. See below for further discussion of awards granted under the LTIP.
The Company recorded compensation expense related to the awards granted under the LTIP as follows (in thousands):
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
| 2021 | 2020 | 2021 | 2020 | ||||||||||||||||||||
| Restricted stock units | $ | 1,561 | $ | 1,350 | $ | 4,628 | $ | 3,935 | |||||||||||||||
| Performance stock units | 728 | 373 | 1,468 | 375 | |||||||||||||||||||
| Stock options | — | — | — | 126 | |||||||||||||||||||
| Total stock-based compensation | $ | 2,289 | $ | 1,723 | $ | 6,096 | $ | 4,436 | |||||||||||||||
As of September 30, 2021, unrecognized compensation expense will be amortized through the relevant periods as follows (in thousands):
| Unrecognized Compensation Expense | Final Year of Recognition | ||||||||||
| Restricted stock units | $ | 8,886 | 2024 | ||||||||
| Performance stock units | 4,911 | 2023 | |||||||||
| $ | 13,797 | ||||||||||
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Restricted Stock Units
The LTIP allows for the issuance of RSUs to members of the Board of Directors (the “Board”) and employees of the Company at the discretion of the Board. Each RSU represents one share of the Company's common stock to be released from restriction upon completion of the vesting period. The awards typically vest in one-third increments over three years. The RSUs are valued at the grant date share price and are recognized as general and administrative expense over the vesting period of the award.
During the nine months ended September 30, 2021, the Company granted 178,567 RSUs with a fair value of $6.1 million. A summary of the status and activity of non-vested restricted stock units for the nine months ended September 30, 2021 is presented below:
| Restricted Stock Units | Weighted-Average Grant-Date Fair Value | ||||||||||
| Non-vested, beginning of year | 550,056 | $ | 20.30 | ||||||||
| Granted | 178,567 | 34.35 | |||||||||
| Vested | (267,635) | 21.12 | |||||||||
| Forfeited | (23,586) | 17.25 | |||||||||
| Non-vested, end of quarter | 437,402 | $ | 25.69 | ||||||||
Cash flows resulting from excess tax benefits are to be classified as part of cash flows from operating activities. Excess tax benefits are realized tax benefits from tax deductions for vested restricted stock in excess of the deferred tax asset attributable to stock compensation costs for such restricted stock. The Company recorded no excess tax benefits for the periods presented.
Performance Stock Units
The LTIP allows for the issuance of PSUs to employees at the sole discretion of the Board. The number of shares of the Company's common stock that may be issued to settle PSUs ranges from zero to two times the number of PSUs awarded. The PSUs vest in their entirety at the end of the three-year performance period. The first criterion is based on a comparison of the Company's absolute and relative total shareholder return (“TSR”) for the performance period compared with the TSRs of a group of peer companies for the same performance period. The TSR for the Company and each of the peer companies is determined by dividing (A) (i) the volume-weighted average share price for the last 30 trading days of the performance period minus (ii) the volume-weighted average share price for the 30 trading days preceding the beginning of the performance period, by (B) the volume-weighted average share price for the 30 trading days preceding the beginning of the performance period. The second criterion, when applicable, is based on the Company's annual return on average capital employed (“ROCE”) for each year during the three-year performance period. The total number of PSUs granted was split as follows for the relevant grant years:
| 2021 | 2020 | 2019 | |||||||||||||||
| TSR | 100 | % | 67 | % | 50 | % | |||||||||||
| ROCE | — | % | 33 | % | 50 | % | |||||||||||
Compensation expense associated with PSUs is recognized as general and administrative expense over the performance period. Because these awards depend on a combination of performance-based and market-based settlement criteria, compensation expense may be adjusted in future periods as the number of units expected to vest increases or decreases based on the Company's expected ROCE performance. As of September 30, 2021, the Company does not expect any of the ROCE portion of the PSUs granted in 2019 to vest and has accordingly adjusted the related compensation expense.
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The fair value of the PSUs was measured at the grant date. The portion of the PSUs tied to the TSR required a stochastic process method using a Brownian Motion simulation. A stochastic process is a mathematically defined equation that can create a series of outcomes over time. These outcomes are not deterministic in nature, which means that by iterating the equations multiple times, different results will be obtained for those iterations. In the case of the Company's TSRs, the Company could not predict with certainty the path its stock price or the stock prices of its peers would take over the performance period. By using a stochastic simulation, the Company created multiple prospective stock pathways, statistically analyzed these simulations, and ultimately made inferences regarding the most likely path the stock price would take. As such, because future stock prices are stochastic, or probabilistic with some direction in nature, the stochastic method, specifically the Brownian Motion Model, was deemed an appropriate method by which to determine the fair value of the portion of the PSUs tied to the TSR. Significant assumptions used in this simulation include the Company's expected volatility, risk-free interest rate based on U.S. Treasury yield curve rates with maturities consistent with the performance period, as well as the volatilities for each of the Company's peers.
During the nine months ended September 30, 2021, the Company granted 64,258 PSUs with a fair value of $4.4 million. The PSUs granted in 2018 expired as of December 31, 2020, with zero distribution of shares to the recipients, as neither the TSR nor the ROCE performance criteria were met. A summary of the status and activity of performance stock units for the nine months ended September 30, 2021 is presented below:
Performance Stock Units(1) | Weighted-Average Grant-Date Fair Value | ||||||||||
Non-vested, beginning of year | 185,588 | $ | 22.63 | ||||||||
Granted | 64,258 | 68.99 | |||||||||
Vested | — | — | |||||||||
Forfeited | — | — | |||||||||
| Non-vested, end of quarter | 249,846 | $ | 34.56 | ||||||||
___________________________
(1)The number of awards assumes that the associated performance condition is met at the target amount. The final number of shares of the Company's common stock issued may vary depending on the performance multiplier, which ranges from zero to two, depending on the level of satisfaction of the performance condition.
Stock Options
The LTIP allows for the issuance of stock options to the Company's employees at the sole discretion of the Board. Options expire ten years from the grant date unless otherwise determined by the Board. Compensation expense on the stock options is recognized as general and administrative expense over the vesting period of the award.
There were no stock options granted during the nine months ended September 30, 2021. A summary of the status and activity of stock options for the nine months ended September 30, 2021 is presented below:
| Stock Options | Weighted-Average Exercise Price | Weighted-Average Remaining Contractual Term (in years) | Aggregate Intrinsic Value (in thousands) | ||||||||||||||||||||
| Outstanding, beginning of year | 72,368 | $ | 34.36 | ||||||||||||||||||||
| Granted | — | — | |||||||||||||||||||||
| Exercised | (21,878) | 34.36 | |||||||||||||||||||||
| Forfeited | (510) | 34.36 | |||||||||||||||||||||
| Outstanding, end of quarter | 49,980 | $ | 34.36 | 5.6 | $ | 677 | |||||||||||||||||
| Number of options outstanding and exercisable | 49,980 | $ | 34.36 | 5.6 | $ | 677 | |||||||||||||||||
The aggregate intrinsic value of options exercised during the nine months ended September 30, 2021 was $0.2 million.
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NOTE 8 - FAIR VALUE MEASUREMENTS
The Company follows fair value measurement authoritative guidance, which defines fair value, establishes a framework for using fair value to measure assets and liabilities, and expands disclosures about fair value measurements. The authoritative accounting guidance 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. The statement establishes a hierarchy for inputs used in measuring fair value that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. The hierarchy is broken down into three levels based on the reliability of the inputs as follows:
Level 1: Quoted prices are available in active markets for identical assets or liabilities
Level 2: Quoted prices in active markets for similar assets and liabilities, quoted prices for identical or similar instruments in markets that are not active, and model-derived valuations whose inputs are observable or whose significant value drivers are observable
Level 3: Significant inputs to the valuation model are unobservable
Financial and non-financial assets and liabilities are to be classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.
Derivatives
Fair value of all derivative instruments are estimated with industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value of money, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. All valuations were compared against counterparty statements to verify the reasonableness of the estimate. The Company’s commodity swaps, collars, and puts were validated by observable transactions for the same or similar commodity options using the NYMEX futures index and were designated as Level 2 within the valuation hierarchy. The following tables present the Company's financial assets and liabilities that were accounted for at fair value on a recurring basis and their classification within the fair value hierarchy (in thousands):
| As of September 30, 2021 | |||||||||||||||||
| Level 1 | Level 2 | Level 3 | |||||||||||||||
Derivative liabilities | $ | — | $ | 101,828 | $ | — | |||||||||||
| As of December 31, 2020 | |||||||||||||||||
| Level 1 | Level 2 | Level 3 | |||||||||||||||
Derivative assets | $ | — | $ | 7,482 | $ | — | |||||||||||
Derivative liabilities | $ | — | $ | 7,732 | $ | — | |||||||||||
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Senior Notes
The Bonanza Creek 7.5% Senior Notes of $100.0 million, issued on April 1, 2021, are recorded at carrying value. There were no debt issuance costs, discounts or premiums associated with the Bonanza Creek 7.5% Senior Notes. The estimated fair value of the Bonanza Creek 7.5% Senior Notes of $100.8 million as of September 30, 2021 was based on quoted market prices, and as such, is designated as Level 1 within the valuation hierarchy.
Proved Oil and Gas Properties
Proved oil and gas property costs are evaluated for impairment on a nonrecurring basis and reduced to fair value when there is an indication that the carrying costs exceed the sum of the undiscounted cash flows of the underlying oil and gas reserves. Depending on the availability of data, the Company uses Level 3 inputs and either the income valuation technique, which converts future amounts to a single present value amount to measure the fair value of proved properties through an application of risk-adjusted discount rates and price forecasts selected by the Company’s management, or the market valuation approach. The calculation of the risk-adjusted discount rate is a significant management estimate based on the best information available. Management believes that the risk-adjusted discount rate is representative of current market conditions and reflects the following factors: estimates of future cash payments, expectations of possible variations in the amount and/or timing of cash flows, the risk premium, and nonperformance risk. The price forecast is based on the Company's internal budgeting model derived from the NYMEX strip pricing, adjusted for management estimates and basis differentials. Future operating costs are also adjusted as deemed appropriate for these estimates. Proved properties classified as held for sale are valued using a market approach, based on an estimated selling price, as evidenced by the most current bid prices received from third parties. If a relevant estimated selling price is not available, the Company utilizes the income valuation technique discussed above. There were no proved oil and gas property impairments during the three and nine months ended September 30, 2021 and 2020.
NOTE 9 - ASSET RETIREMENT OBLIGATIONS
The Company recognizes an estimated liability for future costs to abandon its oil and gas properties. The fair value of the asset retirement obligation is recorded as a liability when incurred, which is typically at the time the asset is acquired or placed in service. There is a corresponding increase to the carrying value of the asset, which is included in the proved properties line item in the accompanying balance sheets. The Company depletes the amount added to proved properties and recognizes expense in connection with accretion of the discounted liability over the remaining estimated economic lives of the properties.
The Company’s estimated asset retirement obligation liability is based on historical experience in abandoning wells, estimated economic lives, estimated costs to abandon the wells, and regulatory requirements. The liability is discounted using the credit-adjusted risk-free rate estimated at the time the liability is incurred.
A roll-forward of the Company's asset retirement obligation is as follows (in thousands):
| Amount | |||||
Beginning balance as of December 31, 2020 | $ | 28,699 | |||
| Liabilities settled | (3,885) | ||||
| Additions | 24,658 | ||||
| Accretion expense | 1,290 | ||||
Ending balance as of September 30, 2021 | $ | 50,762 | |||
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NOTE 10 - DERIVATIVES
The Company enters into commodity derivative contracts to mitigate a portion of its exposure to potentially adverse market changes in commodity prices and the associated impact on cash flows. All contracts are entered into for other-than-trading purposes. The Company’s derivatives include swaps, collars, and puts for oil and natural gas, and none of the derivative instruments qualify as having hedging relationships.
In a typical commodity fixed-price swap agreement, if the agreed upon published third-party index price is lower than the swap strike price, the Company receives the difference between the index price and the agreed upon swap strike price. If the index price is higher than the swap strike price, the Company pays the difference. A swaption allows the counterparty, on a specific date, to extend an existing fixed-price swap for a certain period of time or to increase the notional volumes of an existing fixed-price swap.
A basis swap arrangement guarantees a price differential from a specified delivery point to an agreed upon reference point. The Company receives the difference between the price differential and the stated terms, if the price differential is greater than the stated terms. The Company pays the difference between the price differential and the stated terms, if the stated terms are greater than the price differential.
Certain NYMEX calendar month average (“CMA”) settlement contracts contain a “CMA Roll Adjustment,” the calculation of which includes futures prices for contracts deliverable in, at the time, two forward months. The physical trade month average is compared to the prompt month futures contracts and weighted to reflect the amount of time during the delivery month that the forward months traded as the prompt month. The weighted adjustment values are added to the basic calendar month average to arrive at the Roll Adjusted settlement price for the month. “Oil roll swaps” fix the value of the roll adjustment. If the futures curve becomes more backwardated after entering the oil roll swap, we will pay the difference between the CMA Roll Adjustment and the oil roll swap price. If the futures curve becomes more in contango, we will receive the difference between the CMA Roll Adjustment and the oil roll swap price.
A cashless collar arrangement establishes a floor and ceiling price on future oil and gas production. When the settlement price is above the ceiling price, the Company pays the difference between the settlement price and the ceiling price. When the settlement price is below the floor price, the Company receives the difference between the settlement price and floor price. In the event that the settlement price is between the ceiling and the floor, no payment or receipt occurs.
A put gives the owner the right to sell the underlying commodity at a set price over the term of the contract. If the index settlement price is higher than the put fixed price, the put will expire worthless. If the settlement price is lower than the put fixed price, the Company will exercise the put and receive the difference between the settlement price and the put fixed price.
21
As of September 30, 2021 and the filing date of this report, the Company had entered into the following commodity derivative contracts:
| Crude Oil (NYMEX WTI) | Natural Gas (NYMEX Henry Hub) | Natural Gas (CIG Basis) | Natural Gas (CIG) | |||||||||||||||||||||||||||||||||||||||||||||||
| Bbls/day | Weighted Avg. Price per Bbl | MMBtu/day | Weighted Avg. Price per MMBtu | MMBtu/day | Weighted Avg. Basis Differential to CIG Price per MMBtu | MMBtu/day | Weighted Avg. Price per MMBtu | |||||||||||||||||||||||||||||||||||||||||||
| 4Q21 | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Cashless Collar | 10,500 | $48.81/$67.63 | 20,000 | $2.25/$2.52 | — | — | 20,000 | $2.15/$2.75 | ||||||||||||||||||||||||||||||||||||||||||
| Swap | 8,000 | $54.49 | — | — | 20,000 | $0.43 | 13,370 | $2.13 | ||||||||||||||||||||||||||||||||||||||||||
Oil Roll Swap(1) | 4,500 | $0.16 | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||
| 1Q22 | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Cashless Collar | 6,500 | $35.10/$59.44 | — | — | — | — | 20,000 | $2.15/$2.75 | ||||||||||||||||||||||||||||||||||||||||||
| Swap | 1,000 | $50.15 | — | — | — | — | 10,000 | $2.13 | ||||||||||||||||||||||||||||||||||||||||||
Oil Roll Swap(1) | 2,000 | $0.22 | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||
| Swaptions | 4,000 | $55.06 | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||
| 2Q22 | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Cashless Collar | 5,000 | $36.64/$63.52 | — | — | — | — | 20,000 | $2.15/$2.75 | ||||||||||||||||||||||||||||||||||||||||||
| Swap | 1,000 | $50.15 | — | — | — | — | 10,000 | $2.13 | ||||||||||||||||||||||||||||||||||||||||||
Oil Roll Swap(1) | 2,000 | $0.22 | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||
| Swaptions | 4,000 | $55.06 | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||
| 3Q22 | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Cashless Collar | 4,200 | $40.64/$67.74 | 20,000 | $2.80/$4.20 | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||
| Swap | 1,000 | $50.15 | — | — | — | — | 10,000 | $2.13 | ||||||||||||||||||||||||||||||||||||||||||
Oil Roll Swap(1) | 2,000 | $0.22 | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||
| Swaptions | 2,000 | $55.13 | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||
| 4Q22 | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Cashless Collar | 3,700 | $41.40/$69.50 | 20,000 | $2.80/$4.20 | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||
| Swap | 1,000 | $50.15 | — | — | — | — | 10,000 | $2.13 | ||||||||||||||||||||||||||||||||||||||||||
Oil Roll Swap(1) | 2,000 | $0.22 | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||
| Swaptions | 2,000 | $55.13 | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||
_______________________________
(1) The weighted average differential represents the amount of reduction to NYMEX WTI prices for the notional volumes covered by the swap contracts.
Derivative Assets and Liabilities Fair Value
The Company’s commodity derivatives are measured at fair value and are included in the accompanying balance sheets as derivative assets and liabilities. The following table contains a summary of all the Company’s derivative positions reported on the accompanying balance sheets as of the dates indicated in the table below (in thousands):
| September 30, 2021 | December 31, 2020 | |||||||||||||
| Derivative Assets: | ||||||||||||||
| Commodity contracts – current | $ | — | $ | 7,482 | ||||||||||
| Commodity contracts – noncurrent | — | — | ||||||||||||
| Derivative Liabilities: | ||||||||||||||
| Commodity contracts – current | (92,784) | (6,402) | ||||||||||||
| Commodity contracts – noncurrent | (9,044) | (1,330) | ||||||||||||
| Total derivative assets (liabilities), net | $ | (101,828) | $ | (250) | ||||||||||
22
The following table summarizes the components of the derivative gain (loss) presented on the accompanying statements of operations for the periods below (in thousands):
| Three Months Ended September 30, | Nine months ended September 30, | ||||||||||||||||||||||
| 2021 | 2020 | 2021 | 2020 | ||||||||||||||||||||
| Derivative cash settlement gain (loss): | |||||||||||||||||||||||
| Oil contracts | $ | (19,838) | $ | 9,165 | $ | (41,454) | $ | 42,088 | |||||||||||||||
| Gas contracts | (6,708) | (538) | (9,082) | 406 | |||||||||||||||||||
Total derivative cash settlement gain (loss)(1) | (26,546) | 8,627 | (50,536) | 42,494 | |||||||||||||||||||
| Change in fair value gain (loss) | (9,678) | (19,297) | (83,077) | 22,109 | |||||||||||||||||||
Total derivative gain (loss)(1) | $ | (36,224) | $ | (10,670) | $ | (133,613) | $ | 64,603 | |||||||||||||||
_______________________________
(1)Total derivative gain (loss) and total derivative cash settlement gain (loss) for the nine months ended September 30, 2021 and 2020 are reported in the derivative (gain) loss line item and derivative cash settlement gain (loss) line item in the accompanying statements of cash flows, within the cash flows from operating activities.
NOTE 11 - EARNINGS PER SHARE
The Company issues RSUs, which represent the right to receive, upon vesting, one share of the Company's common stock. The number of potentially dilutive shares related to RSUs is based on the number of shares, if any, that would be issuable at the end of the respective reporting period, assuming that date was the end of the vesting period. The Company issues PSUs, which represent the right to receive, upon settlement of the PSUs, a number of shares of the Company's common stock that ranges from zero to two times the number of PSUs granted on the award date. The number of potentially dilutive shares related to PSUs is based on the number of shares, if any, that would be issuable at the end of the respective reporting period, assuming that date was the end of the performance period applicable to such PSUs. The Company issued stock options and warrants, which both represent the right to purchase the Company's common stock at a specified price. The number of potentially dilutive shares related to the stock options and warrants is based on the number of shares, if any, that would be exercisable at the end of the respective reporting period, assuming that date was the end of such stock options' or warrants' term.
Please refer to Note 7 - Stock-Based Compensation for additional discussion.
The Company uses the treasury stock method to calculate earnings per share as shown in the following table (in thousands, except per share amounts):
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
| 2021 | 2020 | 2021 | 2020 | ||||||||||||||||||||
| Net income | $ | 40,659 | $ | 3,251 | $ | 15,221 | $ | 42,900 | |||||||||||||||
| Basic net income per common share | $ | 1.32 | $ | 0.16 | $ | 0.55 | $ | 2.07 | |||||||||||||||
| Diluted net income per common share | $ | 1.31 | $ | 0.16 | $ | 0.55 | $ | 2.06 | |||||||||||||||
| Weighted-average shares outstanding - basic | 30,849 | 20,832 | 27,485 | 20,753 | |||||||||||||||||||
| Add: dilutive effect of contingent stock awards | 276 | 71 | 343 | 73 | |||||||||||||||||||
| Add: dilutive effect of exercisable stock options | 13 | — | 11 | — | |||||||||||||||||||
| Weighted-average shares outstanding - diluted | 31,138 | 20,903 | 27,839 | 20,826 | |||||||||||||||||||
There were 115,448 and 549,967 shares that were anti-dilutive for the three months ended September 30, 2021 and 2020, respectively, and 81,142 and 427,857 that were anti-dilutive for the nine months ended September 30, 2021 and 2020.
The exercise price of the Company's stock warrants were in excess of the Company's stock price during the three and nine months ended September 30, 2020; therefore, they were excluded from the earnings per share calculation. The Company's warrants expired on April 30, 2020.
23
NOTE 12 - INCOME TAXES
Deferred tax assets and liabilities are measured by applying the provisions of enacted tax laws to determine the amount of taxes payable or refundable currently or in future years related to cumulative temporary differences between the tax basis of assets and liabilities and amounts reported in the Company's balance sheets. The tax effect of the net change in the cumulative temporary differences during each period in the deferred tax assets and liabilities determines the periodic provision for deferred taxes.
The Company assesses the recoverability of its deferred tax assets each period by considering whether it is more likely than not that all or a portion of the deferred tax assets will be realized. In making such determination, the Company considers all available (both positive and negative) evidence, including future reversals of temporary differences, tax-planning strategies, projected future taxable income, and results of operations. The Company has cumulative book income for the prior three years and is forecasting future book income, which resulted in the full valuation allowance being removed as of December 31, 2020.
Federal income tax expense differs from the amount that would be provided by applying the statutory United States federal income tax rate of 21% to income before income taxes primarily due to the effect of state income taxes, changes in valuation allowances, and other permanent differences. During the three and nine months ended September 30, 2021, the Company recorded income tax expense of $15.6 million and $5.2 million, respectively, compared to $4.7 million of income tax expense for both the three and nine months ended September 30, 2020.
As of September 30, 2021 and December 31, 2020, the Company had no unrecognized tax benefits. The Company's management does not believe that there are any new items or changes in facts or judgments that would impact the Company's tax position taken thus far in 2021.
NOTE 13 - SUBSEQUENT EVENTS
5.0% Senior Notes due 2026
On October 13, 2021, Bonanza Creek completed its previously announced offering (the “Offering”) of $400.0 million aggregate principal amount of 5.0% Senior Notes due 2026 (the “Bonanza Creek 5.0% Senior Notes”). Following the closing of the Offering, the Company used the net proceeds from the Offering and cash on hand to repay all borrowings under the Credit Facility and expects to use the remainder to repay all borrowings outstanding under the Crestone Peak credit facility and for general corporate purposes.
The Bonanza Creek 5.0% Senior Notes are subject to a special mandatory redemption (a “Special Mandatory Redemption”) in the event that the consummation of the XOG Merger and the Crestone Peak Merger, and, collectively, the “Mergers” does not occur on or before December 31, 2021 or if Bonanza Creek notifies the trustee that it will not pursue the consummation of the Mergers. In the event of a Special Mandatory Redemption, Bonanza Creek is required to redeem the Bonanza Creek 5.0% Senior Notes then outstanding at a redemption price equal to 100% of the principal amount of the notes to be redeemed plus accrued and unpaid interest to, but excluding, the Special Mandatory Redemption date.
At any time prior to October 15, 2023, Bonanza Creek may redeem the Bonanza Creek 5.0% Senior Notes, in whole or in part, at a redemption price equal to the sum of (i) the principal amount thereof, plus (ii) the “make-whole” premium at the redemption date, plus (iii) accrued and unpaid interest, if any, to, but excluding, the date of redemption (subject to the right of the noteholders on the relevant record date to receive interest on the relevant interest payment date). On or after October 15, 2023, Bonanza Creek may redeem all or part of the Bonanza Creek 5.0% Senior Notes at redemption prices (expressed as percentages of the principal amount redeemed) equal to (i) 102.5% for the twelve-month period beginning on October 15, 2023; (ii) 101.25% for the twelve-month period beginning on October 15, 2024; and (iii) 100.0% for the twelve-month period beginning October 15, 2025 and at any time thereafter, plus accrued and unpaid interest, if any, to, but excluding, the redemption date (subject to the right of the noteholders on the relevant record date to receive interest on the relevant interest payment date).
Bonanza Creek may redeem up to 35% of the aggregate principal amount of the Bonanza Creek 5.0% Senior Notes at any time prior to October 15, 2023 with an amount not to exceed the net cash proceeds from certain equity offerings at a redemption price equal to 105.0% of the principal amount of the Bonanza Creek 5.0% Senior Notes redeemed, plus accrued and unpaid interest, if any, thereon to, but not including, the redemption date, provided, however, that (i) at least 65.0% of the aggregate principal amount of the Bonanza Creek 5.0% Senior Notes originally issued on the issue date (but excluding Bonanza Creek 5.0% Senior Notes held by BCEI and its subsidiaries) remains outstanding immediately after the occurrence of such redemption (unless all such Bonanza Creek 5.0% Senior Notes are redeemed substantially concurrently) and (ii) the redemption occurs within 180 days after the date of the closing of such equity offering.
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The Bonanza Creek 5.0% Senior Notes were issued by Bonanza Creek pursuant to an indenture, dated October 13, 2021, among BCEI, the guarantors party thereto and Wells Fargo Bank, National Association, as trustee. The Notes are fully and unconditionally guaranteed on a senior unsecured basis by all of Bonanza Creek’s existing subsidiaries that incur or guarantee indebtedness under the Credit Facility and will be guaranteed by the entities that will become guarantors under the Credit Facility upon consummation of the Mergers as well as by certain other future subsidiaries that may be required to guarantee the Bonanza Creek 5.0% Senior Notes.
The Bonanza Creek 5.0% Senior Notes will mature on October 15, 2026. Interest on the Bonanza Creek 5.0% Senior Notes will accrue at the rate of 5.0% per annum and will be payable semiannually in arrears on April 15 and October 15, commencing on April 15, 2022.
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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” contained in our Annual Report on Form 10-K for the year ended December 31, 2020, as well as the unaudited condensed consolidated financial statements and notes thereto included in this Quarterly Report on Form 10-Q.
Executive Summary
We are an independent Denver-based exploration and production company focused on the acquisition, development, and extraction of oil and associated liquids-rich natural gas in the United States. Our oil and liquids-weighted assets and operations are concentrated in the rural portions of the Wattenberg Field in Colorado. Our development and extraction activities are primarily directed at the horizontal development of the Niobrara and Codell formations in the Denver-Julesburg (“DJ”) Basin. The majority of our revenues are generated through the sale of oil, natural gas, and natural gas liquids production.
The Company’s primary objective is to maximize shareholder returns by responsibly developing our oil and gas resources, paying down debt, and returning excess cash via dividends. We seek to balance production and company growth with maintaining a conservative balance sheet. Key aspects of our strategy include well-balanced asset mergers and acquisitions, multi-well pad development across our leasehold, enhanced completions through continuous design evaluation, utilization of scaled infrastructure, continuous safety improvement, strict adherence to health and safety regulations, and environmental stewardship.
Financial and Operating Results
Our financial and operational results include:
•Crude oil equivalent sales volumes increased 67% for the three months ended September 30, 2021 when compared to the same period in 2020 due to the HighPoint Merger;
•Lease operating expense increased in line with expectations by 29% per Boe for the three months ended September 30, 2021 when compared to the same period in 2020;
•General and administrative expense decreased by 13% per Boe for the three months ended September 30, 2021 when compared to the same period in 2020;
•Borrowings under our Credit Facility were reduced by $95.0 million to $60.0 million during the nine months ended September 30, 2021 from the $155.0 million borrowed at the closing of the HighPoint Merger to pay down the HighPoint credit facility, and were further reduced to zero outstanding as of the date of this filing;
•Total liquidity of $372.4 million at September 30, 2021, consisting of cash on hand plus funds available under our Credit Facility, after giving effect to undrawn letters of credit. Please refer to Liquidity and Capital Resources below for additional discussion;
•Cash dividends of $21.6 million, or $0.35 per share, declared and paid during the nine months ended September 30, 2021;
•Cash flows provided by operating activities for the nine months ended September 30, 2021 were $192.2 million compared to $111.4 million during the nine months ended September 30, 2020. Please refer to Liquidity and Capital Resources below for additional discussion; and
•Capital expenditures, inclusive of accruals, of $128.5 million during the nine months ended September 30, 2021.
26
Rocky Mountain Infrastructure
The Company's gathering, treating, and production facilities, maintained under its Rocky Mountain Infrastructure, LLC (“RMI”) subsidiary, provide many operational benefits to the Company and provide cost economies of a centralized system. The RMI facilities reduce gathering system pressures at the wellhead, thereby improving hydrocarbon recovery. Additionally, with eleven interconnects to four different natural gas processors, RMI helps ensure that the Company's production is not constrained by any single midstream service provider. Furthermore, in 2019, the Company installed a new oil gathering line to Riverside Terminal (on the Grand Mesa Pipeline), which resulted in a corresponding $1.25 to $1.50 per barrel reduction to our oil differentials for barrels transported on such gathering line. Additionally, the Company commenced construction of an additional oil interconnect in late June 2021, thus providing additional outlets to provide flow assurance and minimize differentials. The total value of reduced oil differentials during the nine months ended September 30, 2021 and 2020 was approximately $3.3 million and $4.7 million, respectively. Finally, the RMI system reduces facility site footprints, leading to more cost-efficient operations and reduced emissions and surface disturbance. The net book value of the Company's RMI assets was $196.7 million as of September 30, 2021.
Current Events and Outlook
The worldwide outbreak of COVID-19, the uncertainty regarding the impact of COVID-19, and various governmental actions taken to mitigate the impact of COVID-19, resulted in an unprecedented decline in demand for oil and natural gas. At the same time, the decision by Saudi Arabia in March 2020 to drastically reduce export prices and increase oil production further increased the excess supply of oil and natural gas throughout 2020. However, during 2021, expectations surrounding the demand for oil and natural gas stimulated a rise in oil and natural gas prices.
The COVID-19 outbreak and its development into a pandemic in March 2020 also required that we take precautionary measures intended to help minimize the risk to our business, employees, customers, suppliers, and the communities in which we operate. Our operational employees are currently still able to work on site. However, we have taken various precautionary measures with respect to our operational employees such as requiring them to verify they have not experienced any symptoms consistent with COVID-19, or been in close contact with someone showing such symptoms, before reporting to the work site, quarantining any operational employees who have shown signs of COVID-19 (regardless of whether such employee has been confirmed to be infected), and imposing social distancing requirements on work sites, all in accordance with the guidelines released by the Centers for Disease Control and Prevention. We have not experienced any material operational disruptions (including disruptions from our suppliers and service providers) as a result of a COVID-19 outbreak.
The Company's stand-alone first quarter 2021 capital budget of $35 million to $40 million and combined second through fourth quarter 2021 capital budget (reflecting the closing of the HighPoint Merger on April 1, 2021) of $115 million to $130 million includes completing 45 gross (39.9 net) drilled, uncompleted wells, and picking up a drilling rig in the fourth quarter of 2021, with completions of those newly drilled wells to begin in 2022. Actual capital expenditures could vary significantly based on, among other things, market conditions, commodity prices, drilling and completion costs, and well results.
On April 1, 2021, we completed the previously announced acquisition of HighPoint. While we have already achieved significant synergies across several areas of the Company, there is an expected delay in realizing certain synergies and benefits due to the time and effort required to renegotiate and wait out certain contracts and integrate the formerly stand-alone companies. Consequently, the financial and operating results of the combined companies for the three and nine months ended September 30, 2021 reflect a slightly higher cost metric that we anticipate will decline through the end of 2021. Additionally, while the significant curtailment of the respective drilling and completion programs during 2020, in response to the drop in commodity prices, resulted in an overall decline in combined companies' sales volumes period over period, we expect sales volumes will recover considerably through 2021 completion activity as well as the return of a drilling rig in the fourth quarter of 2021.
The Company has successfully integrated the operations, production and accounting databases derived from the HighPoint Merger. The Company is confident it has the appropriate level of skills and personnel to successfully integrate the XOG and Crestone Peak mergers. The go-forward Company will incorporate the best practices and processes from each organization.
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Results of Operations
The following table summarizes our product revenues, sales volumes, and average sales prices for the periods indicated:
| Three Months Ended September 30, | |||||||||||||||||||||||
| 2021 | 2020 | Change | Percent Change | ||||||||||||||||||||
| Revenues (in thousands): | |||||||||||||||||||||||
Crude oil sales(1) | $ | 131,103 | $ | 46,808 | $ | 84,295 | 180 | % | |||||||||||||||
Natural gas sales(2) | 23,387 | 4,803 | 18,584 | 387 | % | ||||||||||||||||||
Natural gas liquids sales | 33,838 | 5,866 | 27,972 | 477 | % | ||||||||||||||||||
| Product revenue | $ | 188,328 | $ | 57,477 | $ | 130,851 | 228 | % | |||||||||||||||
| Sales Volumes: | |||||||||||||||||||||||
Crude oil (MBbls) | 2,036.4 | 1,284.0 | 752.4 | 59 | % | ||||||||||||||||||
Natural gas (MMcf) | 6,647.5 | 3,629.3 | 3,018.2 | 83 | % | ||||||||||||||||||
Natural gas liquids (MBbls) | 880.2 | 524.9 | 355.3 | 68 | % | ||||||||||||||||||
Crude oil equivalent (MBoe)(3) | 4,024.5 | 2,413.8 | 1,610.7 | 67 | % | ||||||||||||||||||
Average Sales Prices (before derivatives): | |||||||||||||||||||||||
| Crude oil (per Bbl) | $ | 64.38 | $ | 36.45 | $ | 27.93 | 77 | % | |||||||||||||||
| Natural gas (per Mcf) | $ | 3.52 | $ | 1.32 | $ | 2.20 | 167 | % | |||||||||||||||
| Natural gas liquids (per Bbl) | $ | 38.44 | $ | 11.18 | $ | 27.26 | 244 | % | |||||||||||||||
Crude oil equivalent (per Boe)(3) | $ | 46.80 | $ | 23.81 | $ | 22.99 | 97 | % | |||||||||||||||
Average Sales Prices (after derivatives)(4): | |||||||||||||||||||||||
| Crude oil (per Bbl) | $ | 54.64 | $ | 43.59 | $ | 11.05 | 25 | % | |||||||||||||||
| Natural gas (per Mcf) | $ | 2.51 | $ | 1.18 | $ | 1.33 | 113 | % | |||||||||||||||
| Natural gas liquids (per Bbl) | $ | 38.44 | $ | 11.18 | $ | 27.26 | 244 | % | |||||||||||||||
Crude oil equivalent (per Boe)(3) | $ | 40.20 | $ | 27.39 | $ | 12.81 | 47 | % | |||||||||||||||
_____________________________
(1)Crude oil sales excludes $0.2 million and $0.4 million of oil transportation revenues from third parties, which do not have associated sales volumes, for the three months ended September 30, 2021 and 2020, respectively.
(2)Natural gas sales excludes $1.4 million and $1.0 million of gas gathering revenues from third parties, which do not have associated sales volumes, for the three months ended September 30, 2021 and 2020, respectively.
(3)Determined using the ratio of 6 Mcf of natural gas to 1 Bbl of crude oil.
(4)Derivatives economically hedge the price we receive for crude oil and natural gas. For the three months ended September 30, 2021, the derivative cash settlement loss for oil and natural gas contracts was $19.8 million and $6.7 million, respectively. For the three months ended September 30, 2020, the derivative cash settlement gain for oil contracts was $9.2 million, and the derivative cash settlement loss for natural gas contracts was $0.5 million. Please refer to Note 10 - Derivatives of Part I, Item 1 of this report for additional disclosures.
Product revenues increased by 228% to $188.3 million for the three months ended September 30, 2021 compared to $57.5 million for the three months ended September 30, 2020. The drivers of the increase in revenue are the 97%, or $22.99 per Boe, increase in oil equivalent pricing and the 67% increase in sales volumes. The increase in sales volumes is primarily due to the HighPoint Merger that closed on April 1, 2021. Additionally, we turned 30 gross wells to sales during the twelve-month period ending September 30, 2021.
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The following table summarizes our operating expenses for the periods indicated:
| Three Months Ended September 30, | |||||||||||||||||||||||
| 2021 | 2020 | Change | Percent Change | ||||||||||||||||||||
| Expenses (in thousands): | |||||||||||||||||||||||
| Lease operating expense | $ | 11,560 | $ | 5,393 | $ | 6,167 | 114 | % | |||||||||||||||
| Midstream operating expense | 3,163 | 3,970 | (807) | (20) | % | ||||||||||||||||||
| Gathering, transportation, and processing | 14,105 | 4,778 | 9,327 | 195 | % | ||||||||||||||||||
| Severance and ad valorem taxes | 9,205 | (7,063) | 16,268 | 230 | % | ||||||||||||||||||
| Exploration | 1,513 | 66 | 1,447 | 2,192 | % | ||||||||||||||||||
| Depreciation, depletion, and amortization | 35,604 | 23,439 | 12,165 | 52 | % | ||||||||||||||||||
| Abandonment and impairment of unproved properties | — | 223 | (223) | (100) | % | ||||||||||||||||||
| Unused commitments | 3,364 | — | 3,364 | 100 | % | ||||||||||||||||||
| Bad debt expense | 279 | 102 | 177 | 174 | % | ||||||||||||||||||
| Merger transaction costs | 5,580 | 888 | 4,692 | 528 | % | ||||||||||||||||||
| General and administrative expense | 11,724 | 8,031 | 3,693 | 46 | % | ||||||||||||||||||
| Operating Expenses | $ | 96,097 | $ | 39,827 | $ | 56,270 | 141 | % | |||||||||||||||
| Selected Costs ($ per Boe): | |||||||||||||||||||||||
| Lease operating expense | $ | 2.87 | $ | 2.23 | $ | 0.64 | 29 | % | |||||||||||||||
| Midstream operating expense | 0.79 | 1.64 | (0.85) | (52) | % | ||||||||||||||||||
| Gathering, transportation, and processing | 3.50 | 1.98 | 1.52 | 77 | % | ||||||||||||||||||
| Severance and ad valorem taxes | 2.29 | (2.93) | 5.22 | (178) | % | ||||||||||||||||||
| Exploration | 0.38 | 0.03 | 0.35 | 1,167 | % | ||||||||||||||||||
| Depreciation, depletion, and amortization | 8.85 | 9.71 | (0.86) | (9) | % | ||||||||||||||||||
| Abandonment and impairment of unproved properties | — | 0.09 | (0.09) | (100) | % | ||||||||||||||||||
| Unused commitments | 0.84 | — | 0.84 | 100 | % | ||||||||||||||||||
| Bad debt expense | 0.07 | 0.04 | 0.03 | 75 | % | ||||||||||||||||||
| Merger transaction costs | 1.39 | 0.37 | 1.02 | 276 | % | ||||||||||||||||||
| General and administrative expense | 2.91 | 3.33 | (0.42) | (13) | % | ||||||||||||||||||
| Operating Expenses | $ | 23.89 | $ | 16.49 | $ | 7.40 | 45 | % | |||||||||||||||
Lease operating expense. Our lease operating expense increased by $6.2 million, or 114%, to $11.6 million for the three months ended September 30, 2021 from $5.4 million for the three months ended September 30, 2020, and 29% on an equivalent basis per Boe. Lease operating expense on an aggregate basis increased as a result of the HighPoint Merger. Additionally, our overall lease operating expense during the three months ended September 30, 2020 was at an unprecedented low due to the Company's concerted effort to reduce costs in response to the decline in commodity pricing during the 2020 period. The increase in lease operating expense outpaced the increase in sales volumes causing the per Boe to increase, which is within expectations and guidance on a per Boe basis.
Midstream operating expense. Our midstream operating expense decreased to $3.2 million for the three months ended September 30, 2021 compared to $4.0 million for the three months ended September 30, 2020, and decreased 52% on a per Boe basis during the comparable periods. The aggregate decrease is due to reduced compression rentals resulting from the acquisition of a significant number of owned compressors through the HighPoint Merger. Additionally, while certain midstream operating expenses correlate to sales volumes, the majority of the costs, such as compression, are fixed and thereby result in a decrease in midstream operating expense per Boe period over period.
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Gathering, transportation, and processing. Gathering, transportation, and processing expense increased by $9.3 million to $14.1 million for the three months ended September 30, 2021, from $4.8 million for the three months ended September 30, 2020, and increased 77% on a per Boe basis during the comparable periods. Natural gas and NGLs sales volumes have a direct correlation to gathering, transportation, and processing expense, and natural gas and NGLs sales volumes increased 76% during the comparable periods. Additionally, our value-based percentage of proceeds sales contract is now our largest sales contract post the HighPoint Merger, which tracks solely with natural gas and NGLs pricing. Natural gas and NGLs pricing increased at a faster pace than the natural gas and NGLs sales volumes associated with said pricing causing the per Boe to increase.
Severance and ad valorem taxes. Our severance and ad valorem taxes increased to $9.2 million for the three months ended September 30, 2021, from a credit of $7.1 million for the three months ended September 30, 2020. Severance and ad valorem taxes primarily correlate to revenues, and revenues increased by 228% during the three months ended September 30, 2021 compared to the three months ended September 30, 2020. Offsetting this increase is a decrease in the Company's overall severance and ad valorem tax rates as a result of the HighPoint Merger, due to HighPoint having a substantial amount of wells in lower taxing districts. Finally, we refined our tax estimate based on then mill levies, taxing districts, and company results based on commodity prices during the third quarter 2020, which resulted in a one-time adjustment of $12.6 million. Excluding this adjustment, our severance and ad valorem taxes were $5.5 million for the three months ended September 30, 2020.
Exploration. Our exploration expense increased to $1.5 million for the three months ended September 30, 2021, from $0.1 million for the three months ended September 30, 2020 primarily due to the initiation of geologic science studies on certain locations to determine drilling viability.
Depreciation, depletion, and amortization. Our depreciation, depletion, and amortization expense increased 52% to $35.6 million for the three months ended September 30, 2021, from $23.4 million for the three months ended September 30, 2020, and decreased 9% on a per Boe basis during the comparable periods. The increase in depreciation, depletion, and amortization expense during the comparable periods is due to a $655.5 million increase in the depletable property base primarily due to the HighPoint Merger. The decrease on a per Boe basis is due to a decrease in the depletion rate.
Unused commitments. During the three months ended September 30, 2021 and 2020, we incurred $3.4 million and zero, respectively, in unused commitments. As part of the HighPoint Merger, we assumed two firm natural gas pipeline transportation contracts to provide a guaranteed outlet for production from properties HighPoint had previously sold. Both firm transportation contracts required the pipeline to provide transportation capacity and required us to pay transportation charges regardless of the amount of pipeline capacity utilized. The agreements expired July 31, 2021.
Merger transaction costs. Our merger transaction costs increased by $4.7 million for the three months ended September 30, 2021 compared to the three months ended September 30, 2020 due to the closed HighPoint Merger and the anticipated XOG and Crestone Peak mergers.
General and administrative. Our general and administrative expense for the three months ended September 30, 2021 increased to $11.7 million compared to $8.0 million for three months ended September 30, 2020, and decreased 13% on a per Boe basis. The primary drivers of the aggregate increase relate to an increase in salaries, benefits, and stock compensation expense due to the HighPoint Merger. Additionally, certain one-time nonrecurring fees were incurred as it relates to the HighPoint Merger as further discussed in Note 3 - Acquisitions & Divestitures of Part I, Item 1 of this report. General and administrative expense per Boe decreased due to sales volumes being 67% higher during the three months ended September 30, 2021 as compared to the same period in 2020.
Derivative gain (loss). Our derivative losses for the three months ended September 30, 2021 and 2020 of $36.2 million and $10.7 million, respectively, were due to settlements and fair market value adjustments caused by market prices being higher than our contracted hedge prices. Please refer to Note 10 - Derivatives of Part I, Item 1 of this report for additional discussion.
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Interest expense. Our interest expense for the three months ended September 30, 2021 and 2020 was $3.0 million and $0.4 million, respectively. Average debt outstanding for the three months ended September 30, 2021 and 2020 was $86.8 million and $54.1 million, respectively. The components of interest expense for the periods presented are as follows (in thousands):
| Three Months Ended September 30, | |||||||||||
| 2021 | 2020 | ||||||||||
| Senior Notes | $ | 1,875 | $ | — | |||||||
| Credit Facility | 777 | 334 | |||||||||
| Commitment and letter of credit fees under the Credit Facility | 577 | 264 | |||||||||
| Amortization of deferred financing costs | 437 | 92 | |||||||||
| Capitalized interest | (641) | (334) | |||||||||
| Total interest expense, net | $ | 3,025 | $ | 356 | |||||||
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The following table summarizes our product revenues, sales volumes, and average sales prices for the periods indicated:
| Nine Months Ended September 30, | |||||||||||||||||||||||
| 2021 | 2020 | Change | Percent Change | ||||||||||||||||||||
| Revenues (in thousands): | |||||||||||||||||||||||
Crude oil sales(1) | $ | 296,826 | $ | 125,956 | $ | 170,870 | 136 | % | |||||||||||||||
Natural gas sales(2) | 50,451 | 13,696 | 36,755 | 268 | % | ||||||||||||||||||
Natural gas liquids sales | 69,578 | 11,652 | 57,926 | 497 | % | ||||||||||||||||||
| Product revenue | $ | 416,855 | $ | 151,304 | $ | 265,551 | 176 | % | |||||||||||||||
| Sales Volumes: | |||||||||||||||||||||||
Crude oil (MBbls) | 4,884.3 | 3,787.6 | 1,096.7 | 29 | % | ||||||||||||||||||
Natural gas (MMcf) | 16,267.0 | 10,490.6 | 5,776.4 | 55 | % | ||||||||||||||||||
Natural gas liquids (MBbls) | 2,156.9 | 1,399.9 | 757.0 | 54 | % | ||||||||||||||||||
Crude oil equivalent (MBoe)(3) | 9,752.4 | 6,935.9 | 2,816.5 | 41 | % | ||||||||||||||||||
Average Sales Prices (before derivatives): | |||||||||||||||||||||||
| Crude oil (per Bbl) | $ | 60.77 | $ | 33.25 | $ | 27.52 | 83 | % | |||||||||||||||
| Natural gas (per Mcf) | $ | 3.10 | $ | 1.31 | $ | 1.79 | 137 | % | |||||||||||||||
| Natural gas liquids (per Bbl) | $ | 32.26 | $ | 8.32 | $ | 23.94 | 288 | % | |||||||||||||||
Crude oil equivalent (per Boe)(3) | $ | 42.74 | $ | 21.81 | $ | 20.93 | 96 | % | |||||||||||||||
Average Sales Prices (after derivatives)(4): | |||||||||||||||||||||||
| Crude oil (per Bbl) | $ | 52.28 | $ | 44.37 | $ | 7.91 | 18 | % | |||||||||||||||
| Natural gas (per Mcf) | $ | 2.54 | $ | 1.34 | $ | 1.20 | 90 | % | |||||||||||||||
| Natural gas liquids (per Bbl) | $ | 32.26 | $ | 8.32 | $ | 23.94 | 288 | % | |||||||||||||||
Crude oil equivalent (per Boe)(3) | $ | 37.56 | $ | 27.94 | $ | 9.62 | 34 | % | |||||||||||||||
_____________________________
(1)Crude oil sales excludes $0.7 million and $1.4 million of oil transportation revenues from third parties, which do not have associated sales volumes, for the nine months ended September 30, 2021 and 2020, respectively.
(2)Natural gas sales excludes $2.6 million and $2.8 million of gas gathering revenues from third parties, which do not have associated sales volumes, for the nine months ended September 30, 2021 and 2020, respectively.
(3)Determined using the ratio of 6 Mcf of natural gas to 1 Bbl of crude oil.
(4)Derivatives economically hedge the price we receive for crude oil and natural gas. For the nine months ended September 30, 2021, the derivative cash settlement loss for oil and natural gas contracts was $41.5 million and $9.1 million, respectively. For the nine months ended September 30, 2020, the derivative cash settlement gain for oil and natural gas contracts was $42.1 million and $0.4 million, respectively. Please refer to Note 10 - Derivatives of Part I, Item 1 of this report for additional disclosures.
Product revenues increased by 176% to $416.9 million for the nine months ended September 30, 2021 compared to $151.3 million for the nine months ended September 30, 2020. The primary drivers of the increase in revenue are the 96%, or $20.93 per Boe, increase in oil equivalent pricing and the 41% increase in sales volumes. The increase in sales volumes is due to turning 30 gross wells to sales during the twelve-month period ending September 30, 2021 as well as the HighPoint Merger that closed on April 1, 2021.
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The following table summarizes our operating expenses for the periods indicated:
| Nine Months Ended September 30, | |||||||||||||||||||||||
| 2021 | 2020 | Change | Percent Change | ||||||||||||||||||||
| Expenses (in thousands): | |||||||||||||||||||||||
| Lease operating expense | $ | 28,649 | $ | 16,887 | $ | 11,762 | 70 | % | |||||||||||||||
| Midstream operating expense | 11,314 | 11,338 | (24) | — | % | ||||||||||||||||||
| Gathering, transportation, and processing | 32,793 | 11,970 | 20,823 | 174 | % | ||||||||||||||||||
| Severance and ad valorem taxes | 23,622 | 1,588 | 22,034 | 1,388 | % | ||||||||||||||||||
| Exploration | 5,156 | 551 | 4,605 | 836 | % | ||||||||||||||||||
| Depreciation, depletion, and amortization | 89,433 | 67,306 | 22,127 | 33 | % | ||||||||||||||||||
| Abandonment and impairment of unproved properties | 2,215 | 30,589 | (28,374) | (93) | % | ||||||||||||||||||
| Unused commitments | 7,692 | — | 7,692 | 100 | % | ||||||||||||||||||
| Bad debt expense | 279 | 678 | (399) | (59) | % | ||||||||||||||||||
| Merger transaction costs | 27,121 | 909 | 26,212 | 2,884 | % | ||||||||||||||||||
| General and administrative expense | 33,119 | 25,845 | 7,274 | 28 | % | ||||||||||||||||||
| Operating Expenses | $ | 261,393 | $ | 167,661 | $ | 93,732 | 56 | % | |||||||||||||||
| Selected Costs ($ per Boe): | |||||||||||||||||||||||
| Lease operating expense | $ | 2.94 | $ | 2.43 | $ | 0.51 | 21 | % | |||||||||||||||
| Midstream operating expense | 1.16 | 1.63 | (0.47) | (29) | % | ||||||||||||||||||
| Gathering, transportation, and processing | 3.36 | 1.73 | 1.63 | 94 | % | ||||||||||||||||||
| Severance and ad valorem taxes | 2.42 | 0.23 | 2.19 | 952 | % | ||||||||||||||||||
| Exploration | 0.53 | 0.08 | 0.45 | 563 | % | ||||||||||||||||||
| Depreciation, depletion, and amortization | 9.17 | 9.70 | (0.53) | (5) | % | ||||||||||||||||||
| Abandonment and impairment of unproved properties | 0.23 | 4.41 | (4.18) | (95) | % | ||||||||||||||||||
| Unused commitments | 0.79 | — | 0.79 | 100 | % | ||||||||||||||||||
| Bad debt expense | 0.03 | 0.10 | (0.07) | (70) | % | ||||||||||||||||||
| Merger transaction costs | 2.78 | 0.13 | 2.65 | 2,038 | % | ||||||||||||||||||
| General and administrative expense | 3.40 | 3.73 | (0.33) | (9) | % | ||||||||||||||||||
| Operating Expenses | $ | 26.81 | $ | 24.17 | $ | 2.64 | 11 | % | |||||||||||||||
Lease operating expense. Our lease operating expense increased 70% to $28.6 million for the nine months ended September 30, 2021 from $16.9 million for the nine months ended September 30, 2020 and increased 21% on an equivalent basis per Boe. Lease operating expense on an aggregate basis increased as a result of the HighPoint Merger. Additionally, our overall lease operating expense during the nine months ended September 30, 2020 was at an unprecedented low due to the Company's concerted effort to reduce costs in response to the decline in commodity pricing during the 2020 period. The increase in lease operating expense outpaced the increase in sales volumes causing the per Boe to increase, which is within expectations and guidance on a per Boe basis.
Midstream operating expense. Our midstream operating expense remained relatively consistent at $11.3 million for the nine months ended September 30, 2021 compared to the nine months ended September 30, 2020, and decreased 29% on a per Boe basis during the comparable periods. While certain midstream operating expenses correlate to sales volumes, the majority of the costs, such as compression, are fixed and result in a decrease in midstream operating expense per Boe period over period.
Gathering, transportation, and processing. Gathering, transportation, and processing expense increased by $20.8 million, or 174%, to $32.8 million for the nine months ended September 30, 2021, from $12.0 million for the nine months ended September 30, 2020. Generally, natural gas and NGLs sales volumes have a direct correlation to gathering, transportation, and processing expense. Natural gas and NGLs sales volumes increased 55% during the comparable periods. Additionally, our value-based percentage of proceeds sales contract is now our largest sales contract post the HighPoint Merger, which tracks solely with natural gas and NGLs pricing. Natural gas and NGLs pricing increased at a faster pace than the natural gas and NGLs sales volumes associated with said pricing causing the per Boe to increase.
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Severance and ad valorem taxes. Our severance and ad valorem taxes increased to $23.6 million for the nine months ended September 30, 2021, from $1.6 million for the nine months ended September 30, 2020. Severance and ad valorem taxes primarily correlate to revenues, and revenues increased by 176% during the nine months ended September 30, 2021 compared to the nine months ended September 30, 2020. Offsetting this increase is a decrease in the Company's overall severance and ad valorem tax rates as a result of the HighPoint Merger, due to HighPoint having a substantial amount of wells in lower taxing districts. Finally, we refined our tax estimate based on current mill levies, taxing districts, and company results based on commodity prices during the third quarter 2020, which resulted in a one-time adjustment of $12.6 million. Excluding this adjustment, our severance and ad valorem taxes were $14.2 million for the nine months ended September 30, 2020.
Exploration. Our exploration expense increased to $5.2 million for the nine months ended September 30, 2021, from $0.6 million for the nine months ended September 30, 2020 primarily due to a one-time purchase of seismic and core data as well as the initiation of geologic science studies on certain locations to determine drilling viability.
Depreciation, depletion, and amortization. Our depreciation, depletion, and amortization expense increased 33% to $89.4 million for the nine months ended September 30, 2021, from $67.3 million for the nine months ended September 30, 2020, and decreased 5% on a per Boe basis during the comparable periods. The increase in depreciation, depletion, and amortization expense during the comparable periods is due to a $655.5 million increase in the depletable property base primarily due to the HighPoint Merger. The decrease on a per Boe basis is due to a decrease in the depletion rate.
Abandonment and impairment of unproved properties. During the nine months ended September 30, 2021 and 2020, we incurred $2.2 million and $30.6 million, respectively, in abandonment and impairment of unproved properties primarily due to the reassessment of estimated probable and possible reserve locations based primarily upon economic viability and the expiration of non-core leases.
Unused commitments. During the nine months ended September 30, 2021 and 2020, we incurred $7.7 million and zero, respectively, in unused commitments. As part of the HighPoint Merger, we assumed two firm natural gas pipeline transportation contracts to provide a guaranteed outlet for production from properties HighPoint had previously sold. Both firm transportation contracts required the pipeline to provide transportation capacity and required us to pay transportation charges regardless of the amount of pipeline capacity utilized. The agreements expired July 31, 2021.
Merger transaction costs. Our merger transaction costs increased by $26.2 million for the nine months ended September 30, 2021 compared to the nine months ended September 30, 2020 largely due to the closed HighPoint Merger and, to a lesser degree, the anticipated XOG and Crestone Peak mergers.
General and administrative. Our general and administrative expense for the nine months ended September 30, 2021 increased to $33.1 million, from $25.8 million for the nine months ended September 30, 2020, and decreased 9% on a per Boe basis. The primary drivers of the increase relate to an increase in salaries, benefits, and stock compensation expense due to the HighPoint Merger. Additionally, certain one-time nonrecurring fees were incurred as it relates to the HighPoint Merger as further discussed in Note 3 - Acquisitions & Divestitures of Part I, Item 1 of this report. General and administrative expense per Boe decreased due to sales volumes being 41% higher in the later period as a result of the HighPoint Merger.
Derivative gain (loss). Our derivative loss for the nine months ended September 30, 2021 was $133.6 million due to settlements and fair market value adjustments caused by market prices being higher than our contracted hedge prices. Our derivative gain of $64.6 million for the nine months ended September 30, 2020 was due to settlements and fair market value adjustments caused by market prices being lower than our contracted hedge prices. Please refer to Note 10 - Derivatives of Part I, Item 1 of this report for additional discussion.
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Interest expense. Our interest expense for the nine months ended September 30, 2021 and 2020 was $6.7 million and $1.6 million, respectively. Average debt outstanding for the nine months ended September 30, 2021 and 2020 was $70.3 million and $67.5 million, respectively. The components of interest expense for the periods presented are as follows (in thousands):
| Nine Months Ended September 30, | |||||||||||
| 2021 | 2020 | ||||||||||
| Senior Notes | $ | 3,750 | $ | — | |||||||
| Credit Facility | 1,937 | 1,701 | |||||||||
| Commitment and letter of credit fees under the Credit Facility | 1,232 | 785 | |||||||||
| Amortization of deferred financing costs | 963 | 772 | |||||||||
| Capitalized interest | (1,197) | (1,701) | |||||||||
| Total interest expense, net | $ | 6,685 | $ | 1,557 | |||||||
Liquidity and Capital Resources
The Company's anticipated sources of liquidity include cash from operating activities, borrowings under the Credit Facility, proceeds from sales of assets, and potential proceeds from capital and/or debt markets. Our cash flows from operating activities are subject to significant volatility due to changes in commodity prices, as well as variations in our production. The prices for these commodities are driven by a number of factors beyond our control, including global and regional product supply and demand, weather, product distribution, refining and processing capacity, regulatory constraints, and other supply chain dynamics, among other factors. To mitigate some of the pricing risk, as of September 30, 2021, we have hedged approximately 18,500 Bbls per day for the remainder of 2021, representing almost 84% of our oil sales volume during the three months ended September 30, 2021.
As of September 30, 2021, our liquidity was $372.4 million, consisting of $40.4 million of cash on hand and $332.0 million of available borrowing capacity on the Credit Facility, after giving effect to an aggregate of $8.0 million of undrawn letters of credit.
Our weighted-average interest rate on borrowings from the Credit Facility was 3.5% for the three months ended September 30, 2021. As of September 30, 2021 and the date of this filing, we had $60.0 million and zero, respectively, outstanding on our Credit Facility.
On April 1, 2021, in conjunction with the HighPoint Merger, the Company, together with certain of its subsidiaries, entered into the Second Amendment to the Credit Facility. Please refer to Note 3 - Acquisitions and Divestitures under Part I, Item 1 for additional information.
The following table summarizes our cash flows and other financial measures for the periods indicated (in thousands):
| Nine Months Ended September 30, | |||||||||||
| 2021 | 2020 | ||||||||||
| Net cash provided by operating activities | $ | 192,243 | $ | 111,444 | |||||||
| Net cash used in investing activities | (54,868) | (57,509) | |||||||||
| Net cash used in financing activities | (121,708) | (61,158) | |||||||||
| Cash, cash equivalents, and restricted cash | 40,512 | 3,872 | |||||||||
| Acquisition of oil and gas properties | (620) | (853) | |||||||||
| Exploration and development of oil and gas properties | (104,207) | (56,216) | |||||||||
Cash flows provided by operating activities
Our cash flows for the nine months ended September 30, 2021 and 2020 include cash receipts and disbursements attributable to our normal operating cycle. See Results of Operations above for more information on the factors driving these changes.
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Cash flows used in investing activities
Expenditures for development of oil and natural gas properties are the primary use of our capital resources. The Company spent $104.2 million and $56.2 million on the exploration and development of oil and gas properties during the nine months ended September 30, 2021 and 2020, respectively. Partially offsetting these cash outflows for the nine months ended September 30, 2021 is the $49.8 million of cash acquired through the HighPoint Merger.
Cash flows provided by financing activities
Net cash used in financing activities for the nine months ended September 30, 2021 and 2020 was $121.7 million and $61.2 million, respectively. The change was primarily due to a $34.0 million increase in net payments on our Credit Facility between the comparable periods as well as the dividends paid in June and September 2021 totaling $21.6 million.
Non-GAAP Financial Measures
Adjusted EBITDAX represents earnings before interest, income taxes, depreciation, depletion, and amortization, exploration expense, and other non-cash and non-recurring charges. Adjusted EBITDAX excludes certain items that we believe affect the comparability of operating results and can exclude items that are generally non-recurring in nature or whose timing and/or amount cannot be reasonably estimated. Adjusted EBITDAX is a non-GAAP measure that we present because we believe it provides useful additional information to investors and analysts, as a performance measure, for analysis of our ability to internally generate funds for exploration, development, and acquisitions and to service debt. We are also subject to financial covenants under our Credit Facility based on adjusted EBITDAX ratios as further described Note 5 - Long-Term Debt in Part I, Item I of this document. In addition, adjusted EBITDAX is widely used by professional research analysts and others in the valuation, comparison, and investment recommendations of companies in the oil and gas exploration and production industry. Adjusted EBITDAX should not be considered in isolation or as a substitute for net income, income from operations, net cash provided by operating activities, or other profitability or liquidity measures prepared under GAAP. Because adjusted EBITDAX excludes some, but not all, items that affect net income (loss) and may vary among companies, the adjusted EBITDAX amounts presented may not be comparable to similar metrics of other companies.
The following table presents a reconciliation of the GAAP financial measure of net income to the non-GAAP financial measure of Adjusted EBITDAX (in thousands):
| Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||||||||||
| 2021 | 2020 | 2021 | 2020 | |||||||||||||||||||||||
| Net income | $ | 40,659 | $ | 3,251 | $ | 15,221 | $ | 42,900 | ||||||||||||||||||
| Exploration | 1,513 | 66 | 5,156 | 551 | ||||||||||||||||||||||
| Depreciation, depletion, and amortization | 35,604 | 23,439 | 89,433 | 67,306 | ||||||||||||||||||||||
| Abandonment and impairment of unproved properties | — | 223 | 2,215 | 30,589 | ||||||||||||||||||||||
| Unused commitments | 3,364 | — | 7,692 | — | ||||||||||||||||||||||
Stock-based compensation (1) | 2,289 | 1,723 | 6,096 | 4,436 | ||||||||||||||||||||||
Non-recurring general and administrative expense (1) | 150 | 140 | 1,444 | 1,337 | ||||||||||||||||||||||
Merger transaction costs | 5,580 | 888 | 27,121 | 909 | ||||||||||||||||||||||
| (Gain) loss on property transactions, net | (951) | — | (951) | 1,398 | ||||||||||||||||||||||
| Interest expense, net | 3,025 | 356 | 6,685 | 1,557 | ||||||||||||||||||||||
Severance and ad valorem taxes adjustment (2) | — | (12,586) | — | (12,586) | ||||||||||||||||||||||
| Derivative (gain) loss | 36,224 | 10,670 | 133,613 | (64,603) | ||||||||||||||||||||||
| Derivative cash settlements gain (loss) | (26,546) | 8,627 | (50,536) | 42,494 | ||||||||||||||||||||||
| Income tax expense | 15,596 | 4,689 | 5,160 | 4,689 | ||||||||||||||||||||||
| Adjusted EBITDAX | $ | 116,507 | $ | 41,486 | $ | 248,349 | $ | 120,977 | ||||||||||||||||||
_____________________________ | ||||||||||||||||||||||||||
(1) Included as a portion of general and administrative expense in the accompanying statements of operations. | ||||||||||||||||||||||||||
(2) Included as a portion of severance and ad valorem taxes in the accompanying statements of operations. | ||||||||||||||||||||||||||
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New Accounting Pronouncements
Please refer to Note 2 — Basis of Presentation under Part I, Item 1 of this report for any recently issued or adopted accounting standards.
Critical Accounting Policies and Estimates
Information regarding our critical accounting policies and estimates is contained in Part II, Item 7 of our 2020 Form 10-K. During the nine months ended September 30, 2021, there were no significant changes in the application of critical accounting policies.
Material Commitments
There have been no significant changes from our 2020 Form 10-K in our obligations and commitments, other than what is disclosed within Note 4 - Leases and Note 6 - Commitments and Contingencies under Part I, Item 1 of this report.
Cautionary Note Regarding Forward-Looking Statements
This Quarterly Report on Form 10-Q contains various statements, including those that express belief, expectation, or intention, as well as those that are not statements of historic fact, that are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities and Exchange Act of 1934, as amended (the “Exchange Act”). When used in this Quarterly Report on Form 10-Q, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project,” “plan,” “will,” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on management's current belief, based on currently available information, as to the outcome and timing of future events.
Forward-looking statements include statements related to, among other things:
•the Company's business strategies;
•reserves estimates;
•estimated sales volumes;
•amount and allocation of forecasted capital expenditures and plans for funding capital expenditures and operating expenses;
•ability to modify future capital expenditures;
•anticipated costs;
•compliance with debt covenants;
•ability to fund and satisfy obligations related to ongoing operations;
•compliance with government regulations, including environmental, health, and safety regulations and liabilities thereunder;
•adequacy of gathering systems and continuous improvement of such gathering systems;
•impact from the lack of available gathering systems and processing facilities in certain areas;
•impact of any pandemic or other public health epidemic, including the ongoing COVID-19 pandemic;
•natural gas, oil, and natural gas liquid prices and factors affecting the volatility of such prices;
•impact of lower commodity prices;
•sufficiency of impairments;
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•the ability to use derivative instruments to manage commodity price risk and ability to use such instruments in the future;
•our drilling inventory and drilling intentions;
•impact of potentially disruptive technologies;
•our estimated revenue gains and losses;
•the timing and success of specific projects;
•our implementation of standard and long reach laterals;
•our use of multi-well pads to develop the Niobrara and Codell formations;
•intention to continue to optimize enhanced completion techniques and well design changes;
•stated working interest percentages;
•management and technical team;
•outcomes and effects of litigation, claims, and disputes;
•primary sources of future production growth;
•full delineation of the Niobrara B, C, and Codell benches in our legacy, French Lake, and northern acreage;
•our ability to replace oil and natural gas reserves;
•our ability to convert proved undeveloped reserves to producing properties within five years of their initial proved booking;
•impact of recently issued accounting pronouncements;
•impact of the loss a single customer or any purchaser of our products;
•timing and ability to meet certain volume commitments related to purchase and transportation agreements;
•the impact of customary royalty interests, overriding royalty interests, obligations incident to operating agreements, liens for current taxes, and other industry-related constraints;
•our financial position;
•our cash flow and liquidity;
•the adequacy of our insurance;
•the expected timetable for completing the XOG Merger and the Crestone Peak Merger, the results, effects, benefits and synergies of the mergers, future opportunities for the combined company, other plans and expectations with respect to the mergers, and the anticipated impact of the mergers on the combined company’s results of operations, financial position, growth opportunities and competitive position; and
•other statements concerning our operations, economic performance, and financial condition.
We have based these forward-looking statements on certain assumptions and analyses we have made in light of our experience and our perception of historical trends, current conditions, and expected future developments as well as other factors we believe are appropriate under the circumstances. They can be affected by inaccurate assumptions or by known or unknown risks and uncertainties. Many such factors will be important in determining actual future results. The actual results or developments anticipated by these forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control, and may not be realized or, even if substantially realized, may not have the expected consequences. Actual results could differ materially from those expressed or implied in the forward-looking statements.
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Factors that could cause actual results to differ materially include, but are not limited to, the following:
•the risk factors discussed in Part I, Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2020 and in Part II, Item 1A of this report;
•further declines or volatility in the prices we receive for our oil, natural gas liquids, and natural gas;
•general economic conditions, whether internationally, nationally or in the regional and local market areas in which we do business;
•the effects of disruption of our operations or excess supply of oil and natural gas due to the COVID-19 pandemic and the actions by certain oil and natural gas producing countries;
•the scope, duration and severity of the COVID-19 pandemic, including any recurrence, as well as the timing of the economic recovery following the pandemic;
•ability of our customers to meet their obligations to us;
•our access to capital;
•our ability to generate sufficient cash flow from operations, borrowings, or other sources to enable us to fully develop our undeveloped acreage positions;
•the presence or recoverability of estimated oil and natural gas reserves and the actual future sales volume rates and associated costs;
•uncertainties associated with estimates of proved oil and gas reserves;
•the possibility that the industry may be subject to future local, state, and federal regulatory or legislative actions (including additional taxes and changes in environmental regulation);
•environmental risks;
•seasonal weather conditions;
•lease stipulations;
•drilling and operating risks, including the risks associated with the employment of horizontal drilling and completion techniques;
•our ability to acquire adequate supplies of water for drilling and completion operations;
•availability of oilfield equipment, services, and personnel;
•exploration and development risks;
•operational interruption of centralized gas and oil processing facilities;
•competition in the oil and natural gas industry;
•management’s ability to execute our plans to meet our goals;
•our ability to attract and retain key members of our senior management and key technical employees;
•our ability to maintain effective internal controls;
•access to adequate gathering systems and pipeline take-away capacity;
•our ability to secure adequate processing capacity for natural gas we produce, to secure adequate transportation for oil, natural gas, and natural gas liquids we produce, and to sell the oil, natural gas, and natural gas liquids at market prices;
•costs and other risks associated with perfecting title for mineral rights in some of our properties;
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•continued hostilities in the Middle East, South America, and other sustained military campaigns or acts of terrorism or sabotage; and
•other economic, competitive, governmental, legislative, regulatory, geopolitical, and technological factors that may negatively impact our businesses, operations, or pricing.
All forward-looking statements speak only as of the date of this report. We disclaim any obligation to update or revise these statements unless required by law, and you should not place undue reliance on these forward-looking statements. Although we believe that our plans, intentions, and expectations reflected in or suggested by the forward-looking statements we make in this report are reasonable, we can give no assurance that these plans, intentions, or expectations will be achieved. We disclose important factors that could cause our actual results to differ materially from our expectations under Part II, Item 1A. Risk Factors and Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations and elsewhere in this report. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.
Item 3. Quantitative and Qualitative Disclosures About Market Risk.
Oil and Natural Gas Price Risk
Our financial condition, results of operations, and capital resources are highly dependent upon the prevailing market prices of oil and natural gas. These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond our control. Factors influencing oil and natural gas prices include the level of global demand for oil and natural gas, the global supply of oil and natural gas, the establishment of and compliance with production quotas by oil exporting countries, weather conditions which determine the demand for natural gas, the price and availability of alternative fuels, local and global politics, and overall economic conditions. It is impossible to predict future oil and natural gas prices with any degree of certainty. Sustained weakness in oil and natural gas prices may adversely affect our financial condition and results of operations, and may also reduce the amount of oil and natural gas reserves that we can produce economically. Any reduction in our oil and natural gas reserves, including reductions due to price fluctuations, can have an adverse effect on our ability to obtain capital for our exploration and development activities.
Commodity Derivative Contracts
Our primary commodity risk management objective is to protect the Company’s balance sheet via the reduction in cash flow volatility. We enter into derivative contracts for oil, natural gas, and natural gas liquids using NYMEX futures or over-the-counter derivative financial instruments. The types of derivative instruments that we use include swaps, collars, and puts.
Upon settlement of the contract(s), if the relevant market commodity price exceeds our contracted swap price, or the collar’s ceiling strike price, we are required to pay our counterparty the difference for the volume of production associated with the contract. Generally, this payment is made up to 15 business days prior to the receipt of cash payments from our customers. This could have an adverse impact on our cash flows for the period between derivative settlements and payments for revenue earned.
While we may reduce the potential negative impact of lower commodity prices, we may also be prevented from realizing the benefits of favorable commodity price changes.
Presently, our derivative contracts have been executed with eight counterparties, all of which are members of our Credit Facility syndicate. We enter into contracts with counterparties whom we believe are well capitalized. However, if our counterparties fail to perform their obligations under the contracts, we could suffer financial loss.
Please refer to the Note 10 - Derivatives in Part I, Item 1 of this report for summary derivative activity tables.
Interest Rates
As of September 30, 2021 and the filing date of this report, we had $60.0 million and zero, respectively, outstanding under our Credit Facility. Borrowings under our Credit Facility bear interest at a fluctuating rate that is tied to an adjusted Base Rate or LIBOR, at our option. Any increases in these interest rates can have an adverse impact on our results of operations and cash flow. As of September 30, 2021, and through the filing date of this report, the Company was in compliance with all financial and non-financial covenants in the Credit Facility.
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Counterparty and Customer Credit Risk
In connection with our derivatives activity, we have exposure to financial institutions in the form of derivative transactions. Eight members of our Credit Facility syndicate are counterparties on our derivative instruments currently in place and currently have investment grade credit ratings.
We are also subject to credit risk due to concentration of our oil and natural gas receivables with certain significant customers. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. We review the credit rating, payment history, and financial resources of our customers, but we do not require our customers to post collateral.
Marketability of Our Production
The marketability of our production depends in part upon the availability, proximity, and capacity of third-party refineries, access to regional trucking, pipeline, and rail infrastructure, natural gas gathering systems, and processing facilities. We deliver crude oil and natural gas produced through trucking services, pipelines, and rail facilities that we do not own. The lack of availability or capacity on these systems and facilities could reduce the price offered for our production or result in the shut-in of producing wells or the delay or discontinuance of development plans for properties.
A portion of our production may also be interrupted, or shut in, from time to time for numerous other reasons, including as a result of accidents, weather, or field labor issues or strikes, or we might voluntarily curtail production in response to market conditions. If a substantial amount of our production is interrupted at the same time, it could adversely affect our cash flow.
Currently, there are no pipeline systems that service wells in our French Lake area of the Wattenberg Field. If neither we nor a third-party constructs the required pipeline system, we may not be able to fully test or develop our resources in French Lake.
There have not been material changes to the interest rate risk analysis or oil and gas price sensitivity analysis disclosed in our Annual Report on Form 10-K for the year ended December 31, 2020.
Item 4. Controls and Procedures.
Evaluation of Disclosure Controls and Procedures
Our management, with the participation of our principal executive officer and principal financial officer, evaluated the effectiveness of our disclosure controls and procedures as of September 30, 2021. The term “disclosure controls and procedures,” as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act, means controls and other procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized, and reported, within the time periods specified in SEC rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is accumulated and communicated to the company’s management, including its principal executive and principal financial officers and internal audit function, as appropriate, to allow timely decisions regarding required disclosure. Based on the evaluation of our disclosure controls and procedures as of September 30, 2021, our principal executive officer and principal financial officer concluded that, as of such date, our disclosure controls and procedures were effective at the reasonable assurance level.
Management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving their objectives, and management necessarily applies its judgment in evaluating the cost-benefit relationship of possible controls and procedures. To assist management, we have established an internal audit function to verify and monitor our internal controls and procedures. The Company’s internal control system is supported by written policies and procedures, contains self-monitoring mechanisms, and is audited by the internal audit function. Appropriate actions are taken by management to correct deficiencies as they are identified.
Changes in Internal Control over Financial Reporting
There were no changes in our internal control over financial reporting identified in management’s evaluation pursuant to Rules 13a-15(d) or 15d-15(d) of the Exchange Act during the quarter ended September 30, 2021 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
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PART II - OTHER INFORMATION
Item 1. Legal Proceedings.
Information regarding our legal proceedings can be found in Note 6 - Commitments and Contingencies of Part I, Item 1 of this report.
Item 1A. Risk Factors.
Our business faces many risks. Any of the risk factors discussed in this report or our other SEC filings could have a material impact on our business, financial position, or results of operations. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also impair our business operation. For a discussion of our potential risks and uncertainties, see the risk factors in Part I, Item 1A in our Annual Report on Form 10-K for the year ended December 31, 2020, together with other information in this report and other reports and materials we file with the SEC. We have identified these risk factors as important factors that could cause our actual results to differ materially from those contained in any written or oral forward-looking statements made by us or on our behalf.
Risks Relating to the XOG Merger and the Crestone Peak Merger
The XOG Merger and the Crestone Peak Merger are subject to a number of regulatory approvals and conditions to the obligations of the parties, which may delay the XOG Merger, the Crestone Peak Merger or both, result in additional expenditures of money and resources, or reduce the anticipated benefits or result in termination of the XOG Merger Agreement, the Crestone Peak Merger Agreement, or both.
The completion of the XOG Merger and the Crestone Peak Merger are subject to antitrust review in the United States. The waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, expired for the XOG Merger on June 21, 2021 and for the Crestone Peak Merger on July 26, 2021. Nevertheless, the DOJ or the FTC, or any state, could take such action under the antitrust laws as it deems necessary or desirable in the public interest, including seeking to enjoin the completion of the XOG Merger, the Crestone Peak Merger or both. Private parties may also seek to take legal action under the antitrust laws under certain circumstances.
Our obligations and the obligations of XOG and Crestone Peak to consummate the XOG Merger and the Crestone Peak Merger, respectively, are subject to the satisfaction (or waiver by all parties, to the extent permissible under applicable laws) of a number of conditions described in the XOG Merger Agreement and the Crestone Peak Merger Agreement, including the approval of the XOG Merger by our and the XOG stockholders and the approval of the Crestone Peak Merger by our stockholders. Many of the conditions to completion of the XOG Merger and the Crestone Peak Merger are not within our control and we cannot predict when, or if, these conditions will be satisfied. If any of these conditions are not satisfied or waived prior to the outside date, as such term is defined in the XOG and Crestone Peak Merger Agreements, it is possible that the XOG Merger Agreement, the Crestone Peak Merger Agreement or both may be terminated.
Although the parties have agreed to use reasonable best efforts, subject to certain limitations, to complete the XOG Merger and the Crestone Peak Merger as promptly as practicable, these and other conditions may fail to be satisfied. In addition, completion of each merger may take longer, and could cost more, than we expect. The requirements for obtaining the required clearances and approvals could delay the completion of the XOG Merger, the Crestone Peak Merger or both for a significant period of time or prevent them from occurring. Any delay in completing the XOG Merger or the Crestone Peak Merger may adversely affect the cost savings and other benefits that we expect to achieve if the XOG Merger and the Crestone Peak Merger and the integration of businesses are completed within the expected timeframe.
Each of the XOG Merger Agreement and the Crestone Peak Merger Agreement subject us to restrictions on our business activities prior to closing the XOG Merger and the Crestone Peak Merger, respectively.
Each of the XOG Merger Agreement and the Crestone Peak Merger Agreement subject us to restrictions on our business activities prior to closing the XOG Merger and the Crestone Peak Merger, respectively. Each of the XOG Merger Agreement and the Crestone Peak Merger Agreement obligate us to generally conduct our businesses in the ordinary course until the closing and to use our reasonable best efforts to (i) preserve substantially intact our present business organization, goodwill and assets, (ii) keep available the services of our current officers and employees and (iii) preserve our existing relationships with governmental entities and significant customers, suppliers, licensors, licensees, distributors, lessors and others having significant business dealings with us. These restrictions could prevent us from pursuing certain business opportunities that arise prior to the closing and are outside the ordinary course of business.
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We may not realize anticipated benefits and synergies expected from acquisitions, including the XOG Merger and the Crestone Peak Merger.
We seek to complete acquisitions in order to strengthen our position and to create the opportunity to realize certain benefits, including, among other things, potential cost savings. Achieving the benefits of acquisitions depends in part on successfully consolidating functions and integrating operations and procedures in a timely and efficient manner, as well as being able to realize the anticipated growth opportunities and synergies from combining the acquired businesses and operations. We may fail to realize the anticipated benefits and synergies expected from acquisitions, which could adversely affect our business, financial condition and operating results.Acquisitions could also result in difficulties in being able to hire, train or retain qualified personnel to manage and operate such properties.
With respect to the XOG Merger and the Crestone Peak Merger, we believe that the addition of XOG and Crestone Peak will complement our strategy by providing operational and financial scale, increasing free cash flow, and enhancing our corporate rate of return. However, achieving these goals requires, among other things, realization of the targeted cost synergies expected from the merger, and there can be no assurance that we will be able to successfully integrate XOG's and Crestone Peak’s assets or otherwise realize the expected benefits of the transaction. This growth and the anticipated benefits of the XOG Merger and the Crestone Peak Merger may not be realized fully or at all, or may take longer to realize than expected. Difficulties in integrating XOG and Crestone Peak may result in the combined company performing differently than expected, or in operational challenges or failures to realize anticipated efficiencies. Potential difficulties in realizing the anticipated benefits of the XOG Merger and the Crestone Peak Merger include:
•disruptions of relationships with customers, distributors, suppliers, vendors, landlords, joint venture partners and other business partners as a result of uncertainty associated with the XOG Merger and the Crestone Peak Merger;
•difficulties integrating our business with the business of XOG and Crestone Peak in a manner that permits us to achieve the full revenue and cost savings anticipated from the transaction;
•complexities associated with managing a larger and more complex business, including difficulty addressing possible inconsistencies in, standards, controls or operational philosophies and the challenge of integrating complex systems, technology, networks and other assets of each of the companies in a seamless manner that minimizes any adverse impact on customers, suppliers, employees and other constituencies;
•difficulties realizing anticipated operating synergies;
•difficulties integrating personnel, vendors and business partners;
•loss of key employees of XOG or Crestone Peak who are critical to our future operations due to uncertainty about their roles within our company following the XOG Merger and the Crestone Peak Merger or other concerns regarding the XOG Merger and the Crestone Peak Merger;
•potential unknown liabilities and unforeseen expenses;
•performance shortfalls at one or more of the companies as a result of the diversion of management’s attention to integration efforts; and
•disruption of, or the loss of momentum in, each company’s ongoing business.
We have also incurred, and expect to continue to incur, a number of costs associated with completing the XOG Merger and the Crestone Peak Merger and combining the businesses of XOG, Crestone Peak and Bonanza Creek. The elimination of duplicative costs, as well as the realization of other efficiencies related to the integration of the two companies, may not initially offset integration-related costs or achieve a net benefit in the near term, or at all. Matters relating to the mergers (including integration planning) require substantial commitments of time and resources by our management, which may result in the distraction of management from ongoing business operations and pursuing other opportunities that could have been beneficial to us.
Our future success will depend, in part, on our ability to manage our expanded business by, among other things, integrating the assets, operations and personnel of XOG, Crestone Peak and Bonanza Creek in an efficient and timely manner; consolidating systems and management controls; and successfully integrating relationships with customers, vendors and business partners. Failure to successfully manage the combined company may have an adverse effect on our business, reputation, financial condition and results of operations.
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The XOG Merger and the Crestone Peak Merger will trigger a limitation on the utilization of our historic U.S. net operating loss carryforwards (“NOLs”), XOG’s NOLs and Crestone Peak’s NOLs.
Our ability to utilize NOLs (including NOLs of XOG and Crestone Peak) to reduce future taxable income following the XOG Merger and the Crestone Peak Merger depends on many factors, including our future income, which cannot be assured. Section 382 of the Code generally imposes an annual limitation upon the occurrence of an “ownership change” resulting from issuances of a company’s stock or the sale or exchange of such company’s stock by certain stockholders if, as a result, there is an aggregate change of more than 50% in the beneficial ownership of such company’s stock by such stockholders within a rolling three-year period. The limitation with respect to such loss carryforwards generally would be equal to (i) the fair market value of the company’s equity immediately prior to the ownership change multiplied by (ii) a percentage approximately equivalent to the yield on long-term tax-exempt bonds during the month in which the ownership change occurs. Based on the information currently available, we believe that the transactions in connection with the XOG Merger and the Crestone Peak Merger, if consummated, will result in an ownership change with respect to us, XOG, and Crestone Peak, which would trigger a limitation (calculated as described above) on our ability to utilize any historic NOLs following the XOG Merger and the Crestone Peak Merger. XOG’s NOLs are already limited under Section 382 of the Code as a result of an ownership change that occurred in connection with XOG’s Chapter 11 cases.
The market price for our common stock following the XOG Merger and the Crestone Peak Merger may be affected by factors different from those that historically have affected or currently affect our common stock.
Our financial position following the XOG Merger and the Crestone Peak Merger may differ from our financial position before the XOG Merger and the Crestone Peak Merger, and the results of operations of the combined company may be affected by factors that are different from those currently affecting the results of our operations. Accordingly, the market price and performance of our common stock is likely to be different from the performance of our common stock in the absence of the XOG Merger and the Crestone Peak Merger.
Our stockholders, XOG stockholders and Crestone Peak stockholders, in each case as of immediately prior to the mergers, will have reduced ownership in the combined company.
We anticipate issuing 30,936,254 shares of Common Stock to XOG stockholders pursuant to the XOG Merger Agreement and 22,500,000 shares of Common Stock to Crestone Peak stockholders pursuant to the Crestone Peak Merger Agreement. The issuance of these new shares could have the effect of depressing the market price of our Common Stock, through dilution of earnings per share or otherwise. Any dilution of, or delay of any accretion to, our earnings per share could cause the price of our Common Stock to decline or increase at a reduced rate.
Following the completion of the XOG Merger, assuming the Crestone Peak Merger is not consummated, it is anticipated that persons who were stockholders of Bonanza Creek and XOG immediately prior to the XOG Merger will own approximately 50% and 50% of the combined company, respectively. Following the completion of the Crestone Peak Merger, it is anticipated that persons who were stockholders of Bonanza Creek, XOG and Crestone Peak immediately prior to the Crestone Peak Merger will own approximately 37%, 37% and 26% of the combined company, respectively. As a result, our current stockholders, XOG’s current stockholders and Crestone Peak’s stockholders will have less influence on the policies of the combined company than they currently have on our policies and the polices of Extraction and Crestone Peak, respectively.
The Kimmeridge Fund will become a significant holder of our Common Stock following completion of the XOG Merger.
Upon completion of the XOG Merger, assuming there is no decrease in the Kimmeridge Fund’s holdings of XOG common stock prior to completion of the XOG Merger, the Kimmeridge Fund would be expected to own approximately 19% of our Common Stock, representing approximately 19% of our combined voting power (That percentage would be reduced to approximately 14% if the Crestone Peak Merger closes.). In addition, upon completion of the XOG Merger, Mr. Benjamin Dell, independent chairman of the XOG board and a Managing Director of the Kimmeridge Fund, will serve as chairman of the board of directors of the combined company. As a result, we believe that the Kimmeridge Fund may or will have some ability to influence our management and affairs. Further, the existence of a new significant stockholder may have the effect of deterring hostile takeovers, delaying or preventing changes in control or changes in management, or limiting the ability of our other stockholders to approve transactions that they may view as being in their best interests or in our best interests.
In the event that the Kimmeridge Fund becomes and continues to be the owner of a significant amount of our Common Stock, the prospect that it may be able to influence matters requiring stockholder approval may continue. In any of these matters, the interests of the Kimmeridge Fund and of our other stockholders may differ or conflict. Moreover, in the event that the Kimmeridge Fund becomes and continues to be the owner of a significant concentration of our Common Stock, such an ownership stake may also adversely affect the trading price of our Common Stock to the extent investors perceive a disadvantage in owning stock of a company with a significant stockholder.
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CPPIB Crestone Peak Resources Canada Inc., a Canadian corporation (the “Crestone Peak Stockholder”) will become a significant holder of our Common Stock following completion of the Crestone Peak Merger.
Upon completion of the Crestone Peak Merger, assuming there is no decrease in the Crestone Peak Stockholder’s holdings of Crestone Peak common stock prior to completion of the Crestone Peak Merger, the Crestone Peak Stockholder would be expected to own approximately 25% of our Common Stock, representing approximately 25% of our combined voting power. As a result, we believe that the Crestone Peak Stockholder may have some ability to influence our management and affairs. Further, the existence of a new significant stockholder may have the effect of deterring hostile takeovers, delaying or preventing changes in control or changes in management, or limiting the ability of our other stockholders to approve transactions that they may view as being in their best interests or in our best interests.
In the event that the Crestone Peak Stockholder becomes and continues to be the owner of a significant amount of our Common Stock, the prospect that it may be able to influence matters requiring stockholder approval may continue. In any of these matters, the interests of the Crestone Peak Stockholder may differ or conflict from those of our other stockholders. Moreover, in the event that the Crestone Peak Stockholder becomes and continues to be the owner of a significant concentration of our Common Stock, such an ownership stake may also adversely affect the trading price of our Common Stock to the extent investors perceive a disadvantage in owning stock of a company with a significant stockholder.
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Risks Relating to the HighPoint Merger
We may not achieve the anticipated benefits of the HighPoint Merger.
The success of the HighPoint Merger will depend, in part, on our ability to realize the anticipated benefits and cost savings from combining our and HighPoint’s businesses, and there can be no assurance that we will be able to realize the anticipated benefits of the HighPoint Merger. The combined company may perform differently than expected, face operational challenges, or fail to realize anticipated expense-related efficiencies. Potential difficulties that may be encountered in the integration process include, among others:
•complexities associated with managing a larger, more complex, integrated business;
•not realizing anticipated operating synergies;
•potential unknown liabilities and unforeseen expenses associated with the HighPoint Merger; and
•managing expanded environmental and other regulatory compliance obligations related to HighPoint's facilities and operations.
Our results may suffer if we do not effectively manage our expanded operations following the HighPoint Merger.
Following completion of the HighPoint Merger, the size of our business has increased significantly. Our future success will depend, in part, on our ability to manage this expanded business, which poses numerous risks and uncertainties, including the need to integrate the operations and business of HighPoint into our existing business in an efficient and timely manner, to combine systems and management controls and to integrate relationships with various business partners. Failure to successfully manage the combined company may have an adverse effect on our financial condition, results of operations or cash flows.
Following the HighPoint Merger, we are proportionately more exposed to regulatory and operational risks associated with oil and gas operations in Colorado and other risks associated with a more geographically-concentrated asset base.
Substantially all of HighPoint’s properties, production and reserves immediately prior to the HighPoint Merger were located in Colorado. As a result of the HighPoint Merger, the amount of our properties, production and reserves that are located in Colorado have increased and our exposure to the risk of unfavorable regulatory developments in the state have therefore increased as well. The increase of our combined production located in the Wattenberg Field following the HighPoint Merger has proportionately increased our exposure to this risk, as well as other risks associated with operating in a more concentrated geographic area.
The market price of our common stock will continue to fluctuate, and may decline if the benefits of the HighPoint Merger do not meet the expectations of financial analysts.
The market price of our common stock may fluctuate significantly, including if we do not achieve the anticipated benefits of the HighPoint Merger as rapidly, or to the extent anticipated by, financial analysts or if the effect of the HighPoint Merger on our financial results is not consistent with the expectations of financial analysts.
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Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.
Unregistered sales of securities. There were no sales of unregistered equity securities during the three month period ended September 30, 2021.
Issuer purchases of equity securities. The following table contains information about acquisitions of our equity securities during the three month period ended September 30, 2021:
| Total Number of Shares | Maximum Number of | ||||||||||||||||||||||
| Total Number | Purchased as Part of | Shares that May Be | |||||||||||||||||||||
| of Shares | Average Price | Publicly Announced | Purchased Under Plans | ||||||||||||||||||||
Purchased(1) | Paid per Share | Plans or Programs | or Programs | ||||||||||||||||||||
| July 1, 2021 - July 31, 2021 | 1,388 | $ | 40.32 | — | — | ||||||||||||||||||
| August 1, 2021 - August 31, 2021 | 337 | $ | 38.47 | — | — | ||||||||||||||||||
| September 1, 2021 - September 30, 2021 | — | $ | — | — | — | ||||||||||||||||||
| Total | 1,725 | $ | 40.06 | — | — | ||||||||||||||||||
_____________________________
(1)Represents shares that employees surrendered back to us that equaled in value the amount of taxes required for payroll tax withholding obligations upon the vesting of equity awards under the LTIP. These repurchases were not part of a publicly announced plan or program to repurchase shares of our common stock, nor do we have a publicly announced plan or program to repurchase shares of our common stock.
Our Credit Facility contains restrictive thresholds on the payment of dividends.
Item 3. Defaults Upon Senior Securities.
None.
Item 4. Mine Safety Disclosures.
Not applicable.
Item 5. Other Information.
None.
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Item 6. Exhibits.
| Exhibit No. | Description of Exhibit | |||||||
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| 101.INS* | XBRL Instance Document | |||||||
| 101.SCH* | XBRL Taxonomy Extension Schema | |||||||
| 101.CAL* | XBRL Taxonomy Extension Calculation Linkbase | |||||||
| 101.DEF* | XBRL Taxonomy Extension Definition Linkbase | |||||||
| 101.LAB* | XBRL Taxonomy Extension Label Linkbase | |||||||
| 101.PRE* | XBRL Taxonomy Extension Presentation Linkbase | |||||||
| 104 | Cover Page Interactive Data File (formatted as Inline XBRL) | |||||||
| __________________________________________ | ||||||||
| * | Filed with this report | |||||||
| ** | Furnished with this report | |||||||
| † | Management Contract or Compensatory Plan or Agreement | |||||||
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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.
| BONANZA CREEK ENERGY, INC. | ||||||||||||||
| Date: | October 28, 2021 | By: | /s/ Eric T. Greager | |||||||||||
| Eric T. Greager | ||||||||||||||
| President and Chief Executive Officer | ||||||||||||||
| (principal executive officer) | ||||||||||||||
| By: | /s/ Brant DeMuth | |||||||||||||
| Brant DeMuth | ||||||||||||||
| Executive Vice President and Chief Financial Officer | ||||||||||||||
| (principal financial officer) | ||||||||||||||
| By: | /s/ Sandi K. Garbiso | |||||||||||||
| Sandi K. Garbiso | ||||||||||||||
| Vice President and Chief Accounting Officer | ||||||||||||||
| (chief accounting officer) | ||||||||||||||
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