Notes to Consolidated Financial Statements
1. Organization and Operations of the Company
Oasis Petroleum Inc. (together with its consolidated subsidiaries, “Oasis” or the “Company”) is an independent exploration and production (“E&P”) company with quality and sustainable long-lived assets. Oasis Petroleum North America LLC (“OPNA”) conducts the Company’s E&P activities and owns its oil and gas properties located in the North Dakota and Montana regions of the Williston Basin.
As of December 31, 2021, the Company owned approximately 70% of the outstanding limited partner units of Oasis Midstream Partners LP (“OMP”). On February 1, 2022, the Company completed the OMP Merger (defined in Note 5—Oasis Midstream Partners), which qualified for reporting as a discontinued operation. See Note 5—Oasis Midstream Partners and Note 6—Discontinued Operations for additional information.
2. Emergence from Voluntary Reorganization under Chapter 11
Due to the volatile market environment that drove a severe downturn in crude oil and natural gas prices in early 2020, as well as the unprecedented impact of the novel coronavirus 2019 (“COVID-19”) pandemic, the Company evaluated strategic alternatives to reduce its debt, increase financial flexibility and position the Company for long-term success. On September 30, 2020 (the “Petition Date”), Oasis Petroleum Inc. and its affiliates Oasis Petroleum LLC (“OP LLC”), OPNA, Oasis Well Services LLC (“OWS”), Oasis Petroleum Marketing LLC, OP Permian LLC, OMS Holdings LLC, Oasis Midstream Services LLC (“OMS”) and OMP GP LLC (“OMP GP”) (collectively, the “Debtors”) filed voluntary petitions (the “Chapter 11 Cases”) for relief under chapter 11 of title 11 (“Chapter 11”) of the United States Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”). On November 10, 2020, the Bankruptcy Court confirmed the Joint Prepackaged Chapter 11 Plan of Reorganization of Oasis Petroleum Inc. and its Debtor Affiliates (the “Plan”), and on November 19, 2020 (the “Emergence Date”), the Debtors implemented the Plan and emerged from the Chapter 11 Cases. OMP and its subsidiaries, OMP Operating LLC (“OMP Operating”), Bighorn DevCo LLC (“Bighorn DevCo”), Bobcat DevCo LLC (“Bobcat DevCo”), Beartooth DevCo LLC (“Beartooth DevCo”) and Panther DevCo LLC (“Panther DevCo”), were not included in the Chapter 11 Cases.
At the Emergence Date, the Company adopted fresh start accounting in accordance with Financial Accounting Standards Board’s (“FASB”) Accounting Standards Codification (“ASC”) 852, Reorganizations (“ASC 852”), which resulted in a new basis of accounting and the Company becoming a new entity for financial reporting purposes (see Note 3—Fresh Start Accounting). As a result of the adoption of fresh start accounting and the effects of the implementation of the Plan, the consolidated financial statements after the Emergence Date are not comparable to the consolidated financial statements prior to that date. References to “Successor” relate to the reorganized Company’s financial position and results of operations as of and subsequent to the Emergence Date. References to “Predecessor” relate to the Company’s financial position prior to, and results of operations through and including, the Emergence Date.
The Predecessor operated as a debtor-in-possession from the Petition Date through the Emergence Date. As such, certain aspects of the Chapter 11 Cases and related matters are described below in order to provide context to the Company’s financial condition and results of operations for the period presented.
In accordance with the Plan, the following significant transactions occurred on the Emergence Date:
•Shares of the Predecessor’s common stock outstanding immediately prior to the Emergence Date were cancelled, and on the Emergence Date, the Company issued (i) 20,000,000 shares of the Successor’s common stock pro rata to holders of the Predecessor’s senior unsecured notes and (ii) 1,621,622 warrants (the “Warrants”) pro rata to holders of the Predecessor’s common stock.
•All outstanding obligations under the following notes (collectively, the “Predecessor Notes”) issued by the Predecessor were cancelled: (i) 6.50% senior unsecured notes due 2021; (ii) 6.875% senior unsecured notes due 2022; (iii) 6.875% senior unsecured notes due 2023; (iv) 6.250% senior unsecured notes due 2026; and (v) 2.625% senior unsecured convertible notes due 2023.
•Oasis Petroleum Inc., as parent, OPNA, as borrower, and Wells Fargo Bank, N.A. (“Wells Fargo”), as administrative agent, issuing bank and swingline lender, and the lenders party thereto entered into a reserves-based credit agreement (the “Oasis Credit Facility”).
•The Amended and Restated Credit Agreement, dated as of October 16, 2018 (as amended prior to the Emergence Date, the “Predecessor Credit Facility”), by and among the Predecessor, as borrower, the lenders party thereto, and Wells Fargo, as administrative agent, was terminated and holders of claims under the Predecessor Credit Facility had such obligations refinanced through the Oasis Credit Facility.
•The Senior Secured Superpriority Debtor-in-Possession Credit Agreement, dated as of October 2, 2020 (the “DIP Credit Facility”), by and among the Predecessor, as borrower, its subsidiaries party thereto, as guarantors, the lenders party thereto, and Wells Fargo, as administrative agent, was terminated and the holders of claims under the DIP Credit Facility had such obligations refinanced through the Oasis Credit Facility.
•Mirada Claims (as defined in the Plan) were treated in accordance with the Settlement and Mutual Release Agreement dated September 28, 2020 (the “Mirada Settlement Agreement”) with Mirada Energy, LLC and certain related parties (collectively, “Mirada”). See Note 22—Commitments and Contingencies.
•The holders of other secured claims, other priority claims and general unsecured claims received payment in full in cash upon emergence or through the ordinary course of business after the Emergence Date.
•The Company adopted the Oasis Petroleum Inc. 2020 Long Term Incentive Plan (the “2020 LTIP”) effective on the Emergence Date and reserved 2,402,402 shares of its Successor’s common stock for distribution under the 2020 LTIP.
3. Fresh Start Accounting
On the Emergence Date, the Company was required to adopt fresh start accounting in accordance with ASC 852 as (i) the holders of existing voting shares of the Predecessor received less than 50% of the voting shares of the Successor and (ii) the reorganization value of the Company’s assets immediately prior to confirmation of the Joint Prepackaged Chapter 11 Plan of Reorganization of Oasis Petroleum Inc. and its Debtor Affiliates (the “Plan”) of $2.2 billion was less than the total of post-petition liabilities and allowed claims of $3.2 billion. Refer to Note 2—Emergence from Voluntary Reorganization under Chapter 11 for the terms of the Plan.
Reorganization Value
Under fresh start accounting, reorganization value represents the value of the entity before considering liabilities and is intended to represent the approximate amount a willing buyer would pay for the assets immediately after the restructuring. Upon the adoption of fresh start accounting, the Company allocated the reorganization value to its individual assets and liabilities based on their fair values (except for deferred income taxes) in conformity with Accounting Standards Codification 805, Business Combinations. Deferred income tax amounts were determined in accordance with Accounting Standards Codification 740, Income Taxes (“ASC 740”).
Reorganization value is derived from an estimate of enterprise value, or the fair value of the Company’s interest-bearing debt and stockholders’ equity. As set forth in the Plan and related disclosure statement approved by the Bankruptcy Court, the enterprise value of the Successor was estimated to be between $1.3 billion and $1.7 billion. The enterprise value was prepared using reserve information, development schedules, other financial information and financial projections, and applying standard valuation techniques, including risked net asset value analysis, discounted cash flow analysis, public comparable company analysis and precedent transactions analysis. On the Emergence Date, the Company estimated the enterprise value to be $1.3 billion based on the estimates and assumptions used in determining the enterprise value coupled with consideration of the indicated enterprise value implied by the trading value of the Company’s Notes prior to the Emergence Date, as the reorganized Successor’s equity would be issued to the holders of the Notes under the Plan.
The Company’s principal E&P segment assets are its oil and gas properties, which were valued using primarily an income approach. The fair value of proved oil and natural gas properties was estimated using a discounted cash flow model, which is subject to management’s judgment and expertise and includes, but is not limited to, estimates of proved reserves, future commodity pricing, future production estimates, estimates of operating and development costs and a discount rate. Estimated proved reserves were risked by reserve category and were limited to wells included in the Company's five-year development plan. The underlying future commodity prices used to estimate future cash flows were based on NYMEX forward strip prices as of Emergence Date through 2022, escalating 2% per year thereafter (based on historical average annual consumer price index percentage changes) until reaching $75 per barrel for crude oil and $4.80 per Mcf for natural gas in 2051 after which prices were held flat. These prices were adjusted for transportation fees and quality and geographical differentials. Future operating and development costs were estimated based on the Company's recent actual costs, excluding the cost benefits the Company realizes from consolidating its midstream business segment. The cash flow models also included estimates not typically included in proved reserves, such as general and administrative expenses and income tax expenses, and estimated future cash flows were discounted using a weighted average cost of capital discount rate of 11%. In estimating the fair value of the Company’s unproved acreage, a market approach was used in which a review of recent transactions involving properties in the same geographical location were considered when estimating the fair value of the Company’s acreage.
The Company’s midstream business segment was primarily operated through OMP, which has been classified as a discontinued operation (see Note 6—Discontinued Operations). OMP’s enterprise value as of the Emergence Date was determined using the market approach based on a volume weighted average price calculation for OMP’s outstanding limited partner units. The
Company estimated the fair value of its retained interests as of the Emergence Date in Bobcat DevCo and Beartooth DevCo of 64.7% and 30%, respectively, using an income approach, which was based on the anticipated future cash flows associated with the respective DevCos and discounted using a weighted average cost of capital discount rate of 13%.
The midstream segment’s tangible assets primarily consisted of pipelines, natural gas processing plants, compressor stations, produced water gathering lines and disposal wells, tanks, other facilities and equipment and rights of way. The estimated fair value of these midstream assets was determined using a cost approach, based on current replacement costs of the assets less depreciation based on the estimated useful lives of the assets and ages of the assets. Economic and functional obsolescence were also considered and applied in the form of inutility and excess capital costs. The midstream segment’s identifiable intangible assets included third-party customer contracts and its interest in OMP GP. The Company determined the estimated fair value of customer contracts based on the excess earnings method of the income approach, which consists of estimating the incremental after-tax cash flows attributable to the intangible assets only. The Company estimated the fair value of its interest as of the Emergence Date in OMP GP using a combination of an income approach and market approach.
The excess reorganization value over the fair value of identified tangible and intangible assets was attributable to the midstream segment and recorded as goodwill, which has been classified as held for sale on the Consolidated Balance Sheets as of December 31, 2021 and 2020.
Although the Company believes the assumptions and estimates used to develop enterprise value and reorganization value are reasonable and appropriate, different assumptions and estimates could materially impact the analysis and resulting conclusions. The assumptions used in estimating these values are inherently uncertain and require judgment. See below under “Fresh Start Adjustments” for additional information regarding assumptions used in the measurement of the Company’s various other significant assets and liabilities.
The following table reconciles the Company’s enterprise value to the estimated fair value of the Successor’s stockholders’ equity at the Emergence Date: | | | | | |
| November 19, 2020 |
| |
| (In thousands) |
Enterprise value | $ | 1,300,000 | |
Plus: Cash(1) | 5,615 | |
Less: Fair value of Oasis Credit Facility(2) | (340,000) | |
Fair value of Oasis share of Successor stockholders’ equity(3) | 965,615 | |
Plus: Fair value of non-controlling interests | 92,816 | |
Fair value of total Successor stockholders’ equity | $ | 1,058,431 | |
__________________
(1)Cash excludes $4.5 million of cash attributable to OMP and includes $1.4 million that was initially classified as restricted cash as of November 19, 2020 but subsequently released from escrow and returned to the Successor. A total of $10.4 million of restricted cash as of November 19, 2020 was used to pay professional fees and is not included in the table above.
(2)Enterprise value includes the value of the Company’s interests in OMP and OMP GP, which is net of debt under the OMP Credit Facility, and as such, only the fair value of debt under the Oasis Credit Facility is subtracted in order to determine the value of the Successor’s stockholders’ equity.
(3)Reflects Successor equity issued in accordance with the Plan, including 20,000,000 shares of common stock and 1,621,622 warrants (the “Warrants”).
The following table reconciles the Company’s enterprise value to the estimated reorganization value as of the Emergence Date: | | | | | |
| November 19, 2020 |
| |
| (In thousands) |
Enterprise value | $ | 1,300,000 | |
Plus: Fair value of OMP Credit Facility held for sale(1) | 455,500 | |
Plus: Fair value of non-controlling interests | 92,816 | |
Plus: Cash(2) | 5,615 | |
Plus: Current liabilities | 266,796 | |
Plus: Asset retirement obligations (non-current portion) | 45,161 | |
Plus: Other non-current liabilities | 28,086 | |
Plus: Current liabilities held for sale | 38,796 | |
Plus: Non-current liabilities held for sale | 5,221 | |
Reorganization value of Successor assets | $ | 2,237,991 | |
_________________
(1) Enterprise value includes the value of the Company’s interests in OMP and OMP GP, which is net of debt under the OMP Credit Facility, and as such, the fair value of the OMP Credit Facility is considered in the reconciliation of enterprise value to the reorganization value of the Successor’s assets.
(2) Cash excludes $4.5 million of cash attributable to OMP and includes $1.4 million that was initially classified as restricted cash as of November 19, 2020 but subsequently released from escrow and returned to the Successor. A total of $10.4 million of restricted cash as of November 19, 2020 was used to pay professional fees and is not included in the table above.
Reorganization value and enterprise value were estimated using numerous projections and assumptions that are inherently subject to significant uncertainties and resolution of contingencies that are beyond the Company’s control. Accordingly, the estimates included in this report are not necessarily indicative of actual outcomes, and there can be no assurance that the estimates, projections or assumptions will be realized.
Condensed Consolidated Balance Sheet
The adjustments set forth in the following fresh start Condensed Consolidated Balance Sheet reflect the effect of the transactions contemplated by the Plan (“Reorganization Adjustments”) and the fair value and other required adjustments as a result of applying fresh start accounting (“Fresh Start Adjustments”). The explanatory notes provide additional information with regard to the adjustments recorded, the methods used to determine fair values as well as significant assumptions.
| | | | | | | | | | | | | | | | | | | | | | | |
| As of November 19, 2020 |
| Predecessor | | Reorganization Adjustments | | Fresh Start Adjustments | | Successor |
| | | | | | | |
| (In thousands) |
ASSETS | | | | | | | |
Current assets | | | | | | | |
Cash and cash equivalents | $ | 69,558 | | | $ | (65,317) | | (a) | $ | — | | | $ | 4,241 | |
Restricted cash | — | | | 11,800 | | (b) | — | | | 11,800 | |
Accounts receivable, net | 234,413 | | | — | | | — | | | 234,413 | |
Inventory | 19,867 | | | — | | | 2,102 | | (q) | 21,969 | |
Prepaid expenses | 8,085 | | | (4,325) | | (c) | — | | | 3,760 | |
Derivative instruments | 728 | | | — | | | — | | | 728 | |
Other current assets | 104 | | | — | | | — | | | 104 | |
Current assets held for sale | 62,070 | | | — | | | — | | | 62,070 | |
Total current assets | 394,825 | | | (57,842) | | | 2,102 | | | 339,085 | |
Property, plant and equipment | | | | | | | |
Oil and gas properties (successful efforts method) | 9,301,065 | | | — | | | (8,505,818) | | (r) | 795,247 | |
Other property and equipment | 105,410 | | | — | | | (60,411) | | (r) | 44,999 | |
| | | | | | | | | | | | | | | | | | | | | | | |
Less: accumulated depreciation, depletion, amortization and impairment | (8,332,534) | | | — | | | 8,332,534 | | (r) | — | |
Total property, plant and equipment, net | 1,073,941 | | | — | | | (233,695) | | | 840,246 | |
Derivative instruments | 47 | | | — | | | — | | | 47 | |
Long-term inventory | 12,526 | | | — | | | (292) | | (q) | 12,234 | |
Operating right-of-use assets | 11,509 | | | — | | | (797) | | (s) | 10,712 | |
Other assets | 19,876 | | | 7,017 | | (d) | (8,139) | | (t) | 18,754 | |
Non-current assets held for sale | 921,031 | | | — | | | 95,882 | | (u) | 1,016,913 | |
Total assets | $ | 2,433,755 | | | $ | (50,825) | | | $ | (144,939) | | | $ | 2,237,991 | |
LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT) | | | | | | | |
Current liabilities | | | | | | | |
Accounts payable | $ | (291) | | | $ | 21,809 | | (e) | $ | — | | | $ | 21,518 | |
Revenues and production taxes payable | 129,031 | | | — | | | — | | | 129,031 | |
Accrued liabilities | 46,561 | | | 57,470 | | (f) | 1,885 | | (v) | 105,916 | |
Current maturities of long-term debt | 360,640 | | | (360,640) | | (g) | — | | | — | |
Accrued interest payable | 32,538 | | | (32,496) | | (h) | — | | | 42 | |
Derivative instruments | 4,902 | | | 49 | | (i) | 18 | | (w) | 4,969 | |
Advances from joint interest partners | 170 | | | 2,555 | | (i) | — | | | 2,725 | |
Current operating lease liabilities | 109 | | | 924 | | (i) | (76) | | (s) | 957 | |
Other current liabilities | (102) | | | 1,774 | | (i) | (34) | | (s) | 1,638 | |
Current liabilities held for sale | 66,810 | | | (28,014) | | (j) | — | | | 38,796 | |
Total current liabilities | 640,368 | | | (336,569) | | | 1,793 | | | 305,592 | |
Long-term debt | — | | | 340,000 | | (k) | — | | | 340,000 | |
Deferred income taxes | 1,097 | | | 9,746 | | (l) | (6,412) | | (x) | 4,431 | |
Asset retirement obligations | 283 | | | 57,306 | | (i) | (12,428) | | (v) | 45,161 | |
Derivative instruments | 5,316 | | | — | | | 41 | | (w) | 5,357 | |
Operating lease liabilities | 72 | | | 15,462 | | (i) | (740) | | (s) | 14,794 | |
Other liabilities | 80 | | | 3,456 | | (i) | (32) | | (s) | 3,504 | |
Liabilities subject to compromise | 2,051,294 | | | (2,051,294) | | (m) | — | | | — | |
Non-current liabilities held for sale | 461,859 | | | — | | | (1,138) | | (y) | 460,721 | |
Total liabilities | 3,160,369 | | | (1,961,893) | | | (18,916) | | | 1,179,560 | |
Commitments and contingencies | | | | | | | |
Stockholders’ equity (deficit) | | | | | | | |
Predecessor common stock | 3,233 | | | (3,233) | | (n) | — | | | — | |
Successor common stock | — | | | 200 | | (o) | — | | | 200 | |
Predecessor treasury stock, at cost | (36,637) | | | 36,637 | | (n) | — | | | — | |
Predecessor additional paid-in capital | 3,131,446 | | | (3,131,446) | | (n) | — | | | — | |
Successor additional paid-in capital | — | | | 965,415 | | (o) | — | | | 965,415 | |
Retained earnings (accumulated deficit) | (3,995,209) | | | 4,034,401 | | (p) | (39,192) | | (z) | — | |
Oasis share of stockholders’ equity (deficit) | (897,167) | | | 1,901,974 | | | (39,192) | | | 965,615 | |
Non-controlling interests | 170,553 | | | 9,094 | | (p) | (86,831) | | (z) | 92,816 | |
Total stockholders’ equity (deficit) | (726,614) | | | 1,911,068 | | | (126,023) | | | 1,058,431 | |
Total liabilities and stockholders’ equity (deficit) | $ | 2,433,755 | | | $ | (50,825) | | | $ | (144,939) | | | $ | 2,237,991 | |
Reorganization Adjustments
(a)The table below reflects the uses of cash on the Emergence Date from the implementation of the Plan: | | | | | |
| (In thousands) |
| |
| |
| |
| |
Payment of Oasis Credit Facility principal(1) | $ | 20,640 | |
Payment pursuant to the Mirada Settlement Agreement | 20,000 | |
Funding of the professional fees escrow account | 11,800 | |
Payment of Oasis Credit Facility fees | 6,900 | |
Payment of professional fees | 3,766 | |
Payment of DIP Credit Facility accrued interest and fees | 1,375 | |
Payment of Predecessor Credit Facility accrued interest and fees | 836 | |
Total uses of cash | $ | 65,317 | |
| |
_________________ (1)On the Emergence Date, the principal amounts under the Senior Secured Superpriority Debtor-in-Possession Credit Agreement (the “DIP Credit Facility”) and the Amended and Restated Credit Agreement (as amended prior to the Emergence Date, the “Predecessor Credit Facility”) of $300.0 million and $60.6 million, respectively, were converted to principal amounts of revolving loans under the Oasis Credit Facility in accordance with the Plan.
(b)Reflects the funding of an escrow account for professional fees associated with the Chapter 11 Cases, as required by the Plan.
(c)Reflects the remaining unamortized amount of prepaid cash incentives under the 2020 Incentive Compensation Program (as defined in Note 17—Equity-Based Compensation), which vested on the Emergence Date as a result of implementing the Plan, and was recorded in general and administrative expenses.
(d)Represents $7.3 million of fees related to the Oasis Credit Facility paid or accrued on the Emergence Date, which were capitalized as deferred financing costs and are being amortized to interest expense through the maturity date of May 19, 2024, offset by approximately $0.2 million of deferred financing costs related to the Predecessor Credit Facility, which were eliminated with a corresponding charge to reorganization items, net.
(e)Represents the reinstatement of $19.9 million of accounts payable included in liabilities subject to compromise to be satisfied in the ordinary course of business, coupled with a $1.9 million reclassification from accrued liabilities to accounts payable related to certain equity-based compensation awards classified as liabilities that vested on the Emergence Date.
(f)Changes in accrued liabilities include the following: | | | | | |
| (In thousands) |
Reinstatement of accrued expenses from liabilities subject to compromise | $ | 73,778 | |
Accrual for professional fees incurred upon Emergence Date | 4,603 | |
Vesting of equity-based compensation awards classified as liabilities | 1,142 | |
Payment pursuant to Mirada Settlement Agreement | (20,000) | |
Reclassification of payable for vested liability awards to accounts payable | (1,913) | |
Payment of certain professional fees accrued prior to Emergence Date | (140) | |
Net impact to accrued liabilities | $ | 57,470 | |
(g)Reflects the refinancing of the borrowings outstanding under the DIP Credit Facility and Predecessor Credit Facility of $300.0 million and $60.6 million, respectively, through the Oasis Credit Facility on the Emergence Date.
(h)Reflects the write-off of Specified Default Interest of $30.3 million which was waived on the Emergence Date, and the payment of accrued interest for the DIP Credit Facility and Predecessor Credit Facility of $1.4 million and $0.8 million, respectively, on the Emergence Date.
(i)Reflects the reinstatement of obligations that were classified as liabilities subject to compromise.
(j)Reflects the write-off of Specified Default Interest of $28.0 million related to the OMP Credit Facility that was waived on the Emergence Date.
(k)Reflects borrowings drawn under the Oasis Credit Facility on the Emergence Date, consisting of principal amounts that were converted from principal amounts under the DIP Credit Facility and the Predecessor Credit Facility of $300.0 million and $60.6 million, respectively, in accordance with the Plan, partially offset by a principal repayment amount of $20.6 million.
(l)Reflects an increase in the deferred tax liability recorded as a result of an ownership change under Section 382 (as defined in Note 17—Income Taxes).
(m)On the Emergence Date, liabilities subject to compromise were settled in accordance with the Plan as follows: | | | | | |
| (In thousands) |
Notes | $ | 1,825,757 | |
Accrued interest on Notes | 50,337 | |
Asset retirement obligations | 57,306 | |
Accounts payable and accrued liabilities | 93,674 | |
Other liabilities | 24,220 | |
Total liabilities subject to compromise of the Predecessor | 2,051,294 | |
Reinstatement of liabilities for general unsecured claims | (175,200) | |
Issuance of common stock to Notes holders | (941,810) | |
Gain on settlement of liabilities subject to compromise | $ | 934,284 | |
(n)Reflects the cancellation of the Predecessor’s accumulated deficit, common stock and treasury stock and changes in the Predecessor’s additional paid-in capital as follows: | | | | | |
| (In thousands) |
Cancellation of accumulated deficit | $ | (3,086,292) | |
Cancellation of common stock | 3,233 | |
Cancellation of treasury stock | (36,637) | |
Equity-based compensation for vesting of awards classified as equity | 12,055 | |
Issuance of Warrants to Predecessor common stockholders | (23,805) | |
Net impact to Predecessor additional paid-in capital | $ | (3,131,446) | |
(o)Reflects the distribution of Successor equity instruments in accordance with the Plan, including the issuance of 20,000,000 shares of common stock at a par value of $0.01 per share and 1,621,622 Warrants. The fair value of the Warrants was estimated at $14.68 per Warrant using a Black-Scholes model. | | | | | |
| (In thousands) |
Common stock to Notes holders | $ | 941,810 | |
Warrants to Predecessor common stockholders | 23,805 | |
Total fair value of Successor equity | $ | 965,615 | |
(p)The table below reflects the cumulative impact of the reorganization adjustments discussed above: | | | | | |
| (In thousands) |
Gain on settlement of liabilities subject to compromise | $ | 934,284 | |
Write-off of Specified Default Interest | 30,285 | |
Gain on debt discharge | 964,569 | |
Professional fees incurred on the Emergence Date | (7,869) | |
Write-off of Predecessor Credit Facility deferred financing costs | (243) | |
Total reorganization items from reorganization adjustments | 956,457 | |
Equity-based compensation expense for vesting of awards on Emergence Date | (13,197) | |
Vesting of prepaid cash incentive compensation | (4,325) | |
Income from reorganization adjustments from continuing operations before income taxes | 938,935 | |
Income tax expense | (9,746) | |
Net income from reorganization adjustments from continuing operations | $ | 929,189 | |
| |
Gain on debt discharge from discontinued operations | 28,014 | |
Less: Net income from reorganization adjustments attributable to non-controlling interests | (9,094) | |
Net income from reorganization adjustments from discontinued operations | $ | 18,920 | |
| |
Net income from reorganization adjustments attributable to Oasis | $ | 948,109 | |
Cancellation of accumulated deficit | 3,086,292 | |
Net impact to Predecessor retained earnings (accumulated deficit) | $ | 4,034,401 | |
Fresh Start Adjustments
(q)Reflects fair value adjustments to the Company’s crude oil inventory, equipment inventory, and long-term linefill inventory of $1.6 million, $0.5 million and $(0.3) million, respectively, based on market prices as of the Emergence Date. Crude oil prices were estimated using NYMEX West Texas Intermediate crude oil index prices (“NYMEX WTI”) based on the estimated timing of liquidation and adjusted for quality and location differentials.
(r)Reflects adjustments to present the Company's proved oil and gas properties, unproved acreage and other property and equipment at their estimated fair values based on the valuation methodology discussed above as well as the elimination of accumulated depreciation, depletion, amortization and impairment. The following table summarizes the components of property, plant and equipment as of the Emergence Date: | | | | | | | | | | | | | | |
| Fair Value | | | Historical Book Value |
| | | | |
| (In thousands) |
Proved oil and gas properties | $ | 755,247 | | | | $ | 9,126,507 | |
Less: Accumulated depreciation, depletion, amortization and impairment | — | | | | (8,259,334) | |
Proved oil and gas properties, net | 755,247 | | | | 867,173 | |
Unproved oil and gas properties | 40,000 | | | | 174,558 | |
Other property and equipment | 44,999 | | | | 105,410 | |
Less: Accumulated depreciation and impairment | — | | | | (73,200) | |
Other property and equipment, net | 44,999 | | | | 32,210 | |
Total property, plant and equipment, net | $ | 840,246 | | | | $ | 1,073,941 | |
(s)Reflects adjustments required to present operating lease right-of-use assets and operating and finance lease liabilities at fair value. The Company's remaining lease obligations were remeasured using incremental borrowing rates applicable to the Company as of the Emergence Date and commensurate with the Successor's capital structure. The incremental borrowing rates ranged from 3.06% to 6.58% based on the tenor of the leases. Finance lease liabilities are included in other current liabilities and other liabilities on the Company’s Consolidated Balance Sheet.
(t)Reflects adjustments to eliminate certain deferred costs determined to have no fair value, including electrical infrastructure costs of $8.1 million and a $0.1 million adjustment to present finance lease right-of-use assets at fair value.
(u)Reflects the adjustments to non-current assets held for sale as follows:
| | | | | |
| (In thousands) |
Proved oil and gas properties | $ | 44,533 | |
Other property and equipment | (312,657) | |
Accumulated depreciation and impairment | 247,162 | |
Goodwill | 70,534 | |
Interest in OMP GP | 28,000 | |
Customer contracts | 15,000 | |
Equipment inventory | 705 | |
Deferred financing costs related to the OMP Credit Facility | (1,515) | |
Non-current assets held for sale from discontinued operations, net | 91,762 | |
Non-current assets held for sale from continuing operations | 4,120 | |
Total non-current assets held for sale, net | $ | 95,882 | |
_________________
(1)Represents the adjustment to certain assets from continuing operations held for sale as of the Emergence Date for the sales price agreed upon with the buyer, less estimated costs to sell.
(v)Reflects the adjustment to present the Company's asset retirement obligations (“ARO”) at fair value using assumptions as of the Emergence Date, including an inflation factor of 2% and an estimated 30-year credit-adjusted risk-free rate of 8.5%.
(w)Reflects the fair value adjustment to the Company’s derivative instruments using the Company’s estimated credit-adjusted risk-free rate as of the Emergence Date of 5.12%.
(x)Reflects the adjustment to deferred income taxes to reflect the change in the financial reporting basis of assets as a result of the adoption of fresh start accounting.
(y)Reflects the adjustment to present ARO from discontinued operations at fair value.
(z)The table below reflects the cumulative impact of the fresh start adjustments discussed above: | | | | | |
| (In thousands) |
Loss on revaluation adjustments from continuing operations | $ | (225,336) | |
Income tax benefit | 6,412 | |
Net loss from fresh start adjustments from continuing operations | $ | (218,924) | |
| |
Gain on revaluation adjustments from discontinued operations | $ | 92,901 | |
Less: Net loss from fresh start adjustments attributable to non-controlling interests | 86,831 | |
Net gain from fresh start adjustments from discontinued operations | $ | 179,732 | |
| |
Net loss from fresh start adjustments attributable to Oasis | $ | (39,192) | |
Reorganization Items, Net
Any expenses, gains and losses that were realized or incurred between the Petition Date and the Emergence Date and as a direct result of the Chapter 11 Cases and the implementation of the Plan were recorded in reorganization items, net in the Company’s Consolidated Statement of Operations for the period from January 1, 2020 through November 19, 2020 (Predecessor). The
following table summarizes the components of reorganization items, net: | | | | | |
| (In thousands) |
Continuing operations: | |
Gain on debt discharge | $ | 964,569 | |
Loss on revaluation adjustments | (225,336) | |
Write-off of unamortized debt discount | (38,373) | |
Professional fees | (16,352) | |
Write-off of unamortized deferred financing costs | (12,739) | |
DIP Credit Facility fees | (5,853) | |
Total reorganization items from continuing operations, net | $ | 665,916 | |
| |
Discontinued operations: | |
Gain on debt discharge | $ | 28,014 | |
Gain on revaluation adjustments | 92,901 | |
Total reorganization items from discontinued operations | $ | 120,915 | |
4. Summary of Significant Accounting Policies
Basis of Presentation
The accompanying consolidated financial statements of the Company have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”).
Consolidation. The Company’s financial statements include the accounts of Oasis, the accounts of its wholly-owned subsidiaries and the accounts of OMP and its general partner, OMP GP. All intercompany balances and transactions have been eliminated upon consolidation.
Fresh Start Accounting
Subsequent to the Petition Date, the Company applied ASC 852 in preparing its consolidated financial statements. At the Emergence Date, the Company adopted fresh start accounting in accordance with ASC 852, which resulted in a new basis of accounting and the Company becoming a new entity for financial reporting purposes. As a result of the adoption of fresh start accounting and the effects of the implementation of the Plan, the consolidated financial statements of the Successor are not comparable to the consolidated financial statements of the Predecessor. See Note 2—Emergence from Voluntary Reorganization under Chapter 11 and Note 3—Fresh Start Accounting for further details.
Discontinued Operations
The OMP Merger (defined in Note 5—Oasis Midstream Partners) represented a strategic shift for the Company and qualified for reporting as a discontinued operation in accordance with FASB ASC 205-20, Presentation of financial statements – Discontinued Operations (“ASC 205-20”). Accordingly, the results of operations of OMP were classified as discontinued operations in the Consolidated Statement of Operations for the year ended December 31, 2021 (Successor), and the assets and liabilities of OMP were classified as held for sale in the Consolidated Balance Sheet as of December 31, 2021. Prior periods have been recast so that the basis of presentation is consistent with that of the 2021 consolidated financial statements. The Consolidated Statements of Cash Flows were not required to be reclassified for discontinued operations for any period. See Note 6—Discontinued Operations.
Business Segments
As of December 31, 2021, the Company had two business segments related to E&P and midstream operations. The Company’s midstream segment was classified as a discontinued operation in connection with the OMP Merger and is no longer presented as a separate reporting segment in accordance with ASC 280, Segment Reporting.
Following the OMP Merger, the Company has one reportable business segment related to its E&P operations that is engaged in the acquisition and development of oil and gas properties. Revenues from the E&P segment are primarily derived from the sale of crude oil and natural gas production.
Use of Estimates
Preparation of the Company’s consolidated financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved crude oil and natural gas reserves and related cash flow estimates used in impairment tests of long-lived assets, estimates of future development, dismantlement and abandonment costs, estimates relating to certain crude oil and natural gas revenues and expenses and estimates of expenses related to legal, environmental and other contingencies. Certain of these estimates require assumptions regarding future commodity prices, future costs and expenses and future production rates. Actual results could differ from those estimates.
Estimates of crude oil and natural gas reserves and their values, future production rates and future costs and expenses are inherently uncertain for numerous reasons, including many factors beyond the Company’s control. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of data available and of engineering and geological interpretation and judgment. In addition, estimates of reserves may be revised based on actual production, results of subsequent exploration and development activities, prevailing commodity prices, operating costs and other factors. These revisions may be material and could materially affect future depreciation, depletion and amortization (“DD&A”) expense, dismantlement and abandonment costs, and impairment expense.
Risks and Uncertainties
As a crude oil and natural gas producer, the Company’s revenue, profitability and future growth are substantially dependent upon the prevailing and future prices for crude oil and natural gas, which are dependent upon numerous factors beyond its control such as economic, political and regulatory developments and competition from other energy sources. The energy markets have historically been volatile and there can be no assurance that crude oil and natural gas prices will not be subject to wide fluctuations in the future. A substantial or extended decline in prices for crude oil and, to a lesser extent, natural gas, could have a material adverse effect on the Company’s financial position, results of operations, cash flows and quantities of crude oil and natural gas reserves that may be economically produced.
Cash Equivalents and Restricted Cash
The Company invests in certain money market funds, commercial paper and time deposits, all of which are stated at fair value or cost which approximates fair value due to the short-term maturity of these investments. The Company classifies all such investments with original maturity dates less than 90 days as cash equivalents. The Company may maintain balances of cash and cash equivalents in excess of amounts that are federally insured by the Federal Deposit Insurance Corporation. The Company invests with financial institutions that it believes are creditworthy and has not experienced any material losses in such accounts.
The following table provides a reconciliation of cash, cash equivalents and restricted cash reported within the Consolidated Balance Sheets and Consolidated Statements of Cash Flows (in thousands): | | | | | | | | | | | | |
| | |
| December 31, | |
| 2021 | | 2020 | |
| | | | |
Cash and cash equivalents | $ | 172,114 | | | $ | 10,709 | | |
Restricted cash | — | | | 4,370 | | |
Cash and cash equivalents classified as held for sale | 2,669 | | | 5,147 | | |
Total cash, cash equivalents and restricted cash | $ | 174,783 | | | $ | 20,226 | | |
Restricted cash as of December 31, 2020 consisted of funds in an escrow account for professional fees associated with the Chapter 11 Cases.
Accounts Receivable
Accounts receivable are carried at cost on a gross basis, with no discounting, which approximates fair value due to their short-term maturities. The Company’s accounts receivable consist mainly of receivables from crude oil and natural gas purchasers and joint interest owners on properties the Company operates.
The Company regularly assesses the recoverability of all material trade and other receivables to determine their collectability. The Company accrues a reserve on a receivable when, based on management’s judgment, it is probable that a receivable will not be collected and the amount of such reserve may be reasonably estimated. For receivables from joint interest owners, the Company typically has the ability to withhold future revenue disbursements to recover non-payment of joint interest billings. Generally, the Company’s crude oil and natural gas receivables are collected within two months.
In the first quarter of 2020, the Company adopted Accounting Standards Update No. 2016-13, Financial Instruments — Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments (“ASU 2016-13”), which replaces the incurred loss impairment methodology with a methodology that reflects expected credit losses and requires consideration of a broader range of reasonable and supportable information, including forecasts, to develop credit loss estimates. The Company’s exposure to credit losses is primarily related to its joint interest and crude oil and natural gas sales receivables. In accordance with ASU 2016-13, the Company estimates expected credit losses on its accounts receivable at each reporting date, which may result in earlier recognition of credit losses than under previous GAAP. These estimates are based on historical data, current and future economic and market conditions to determine expected collectability. To date, the Company’s credit losses on joint interest and crude oil and natural gas sales receivables have been immaterial. The Company continually monitors the creditworthiness of its counterparties by reviewing credit ratings, financial statements and payment history. The adoption of ASU 2016-13 was applied using a modified retrospective approach by recognizing a cumulative-effect adjustment to retained earnings (accumulated deficit) of $0.4 million in the first quarter of 2020 to increase its allowance for expected credit losses, and prior periods were not retrospectively adjusted. The adoption of ASU 2016-13 did not result in a material impact to the Company’s financial position, cash flows or results of operations (see Note 9— Additional Balance Sheet Information).
Inventory
The Company’s inventory includes equipment and materials and crude oil inventory. Equipment and materials consist primarily of well equipment, tanks and tubular goods to be used in the Company’s exploration and production activities. Crude oil inventory includes crude oil in tanks and linefill. Linefill that represents the minimum volume of product in a pipeline system that enables the system to operate is generally not available to be withdrawn from the pipeline system until the expiration of the transportation contract. Crude oil and NGL linefill in third-party pipelines that is not expected to be withdrawn within one year is included in long-term inventory on the Company’s Consolidated Balance Sheets (see Note 8—Inventory).
Inventory, including long-term inventory, is stated at the lower of cost and net realizable value with cost determined on an average cost method. The Company assesses the carrying value of inventory and uses estimates and judgment when making any adjustments necessary to reduce the carrying value to net realizable value. Among the uncertainties that impact the Company’s estimates are the applicable quality and location differentials to include in the Company’s net realizable value analysis. Additionally, the Company estimates the upcoming liquidation timing of the inventory. Changes in assumptions made as to the timing of a sale can materially impact net realizable value.
Joint Interest Partner Advances
The Company participates in the drilling of crude oil and natural gas wells with other working interest partners. Due to the capital intensive nature of crude oil and natural gas drilling activities, the working interest partner responsible for conducting the drilling operations may request advance payments from other working interest partners for their share of the costs. The Company expects such advances to be applied by working interest partners against joint interest billings for its share of drilling operations within 90 days from when the advance is paid. Advances to joint interest partners are included in other current assets on the Company’s Consolidated Balance Sheets.
Property, Plant and Equipment
Proved Oil and Gas Properties
Crude oil and natural gas exploration and development activities are accounted for using the successful efforts method. Under this method, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending determination of whether the well has found proved reserves. If an exploratory well does not find proved reserves, the costs of drilling the well are charged to expense. The costs of development wells are capitalized whether productive or nonproductive. Expenditures for maintenance, repairs and minor renewals necessary to maintain properties in operating condition are expensed as incurred. Major betterments, replacements and renewals are capitalized to the appropriate property and equipment accounts. Estimated dismantlement and abandonment costs for oil and gas properties are capitalized at their estimated net present value.
The provision for DD&A of oil and gas properties is calculated using the unit-of-production method. All capitalized well costs (including future abandonment costs, net of salvage value) and leasehold costs of proved properties are amortized on a unit-of-production basis over the remaining life of proved developed reserves and total proved reserves, respectively, related to the associated field. Natural gas is converted to barrel equivalents at the rate of six thousand cubic feet of natural gas to one barrel of crude oil.
Costs of retired, sold or abandoned properties that constitute a part of an amortization base are charged or credited, net of proceeds, to accumulated DD&A unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized currently.
The Company reviews its proved oil and gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of its carrying value may have occurred. The Company estimates the expected undiscounted future cash flows of its oil and gas properties by field and compares such undiscounted future cash flows to the carrying amount of the oil and gas properties in the applicable field to determine if the carrying amount is recoverable. The factors used to determine the undiscounted future cash flows are subject to management’s judgment and expertise and include, but are not limited to, estimates of proved reserves, future commodity pricing, future production estimates and estimates of operating and development costs. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will adjust the carrying amount of the oil and gas properties to fair value. The factors used to determine fair value are subject to management’s judgment and expertise and include, but are not limited to, the Company’s estimated undiscounted future cash flows and the discount rate commensurate with the risk and current market conditions associated with realizing the expected cash flows projected. Because of the uncertainty inherent in these factors, the Company cannot predict when or if future impairment charges for proved oil and gas properties will be recorded.
Unproved Oil and Gas Properties
Unproved properties consist of costs incurred to acquire unproved leases, or lease acquisition costs. Lease acquisition costs are capitalized until the leases expire or when the Company specifically identifies leases that will revert to the lessor, at which time the Company expenses the associated lease acquisition costs. The expensing of the lease acquisition costs is recorded as impairment in the Consolidated Statements of Operations. Lease acquisition costs related to successful exploratory drilling are reclassified to proved properties and depleted on a unit-of-production basis.
The Company assesses its unproved properties periodically for impairment on a property-by-property basis based on remaining lease terms, drilling results or future plans to develop acreage. The Company considers the following factors in its assessment of the impairment of unproved properties:
•the remaining amount of unexpired term under its leases;
•its ability to actively manage and prioritize its capital expenditures to drill leases and to make payments to extend leases that may be close to expiration;
•its ability to exchange lease positions with other companies that allow for higher concentrations of ownership and development;
•its ability to convey partial mineral ownership to other companies in exchange for their drilling of leases; and
•its evaluation of the continuing successful results from the application of completion technology in the Bakken and Three Forks formations in the Williston Basin by the Company or by other operators in areas adjacent to or near the Company’s unproved properties.
For sales of entire working interests in unproved properties, a gain or loss is recognized to the extent of the difference between the proceeds received and the net carrying value of the property. Proceeds from sales of partial interests in unproved properties are accounted for as a recovery of costs unless the proceeds exceed the entire cost of the property.
Capitalized Interest
The Company capitalizes a portion of its interest expense incurred on its outstanding debt. The amount capitalized is determined by multiplying the capitalization rate by the average amount of eligible accumulated capital expenditures and is limited to actual interest costs incurred during the period. The accumulated capital expenditures included in the capitalized interest calculation begin when the first costs are incurred and end when the asset is either placed into production or written off. For the year ended December 31, 2021 (Successor), the Company capitalized interest costs of $2.1 million. For the period from November 20, 2020 through December 31, 2020 (Successor) and the period from January 1, 2020 through November 19, 2020 (Predecessor), the Company capitalized interest costs of $0.1 million and $6.4 million, respectively. For the year ended December 31, 2019 (Predecessor), the Company capitalized interest costs of $12.0 million. Capitalized interest costs are amortized over the life of the related assets.
Other Property and Equipment
The Company’s produced and flowback water disposal facilities, natural gas processing plants, pipelines, buildings, furniture, software, equipment and leasehold improvements are recorded at cost and are depreciated on the straight-line method based on expected lives of the individual assets. The Company uses estimated lives of 30 years for its produced and flowback water disposal facilities, natural gas processing plants and pipelines, 20 years for its buildings, two to seven years for its furniture, software and equipment and the remaining lease term for its leasehold improvements. The calculation for the straight-line DD&A method for its produced and flowback water disposal facilities takes into consideration estimated future dismantlement, restoration and abandonment costs, which are net of estimated salvage values. The cost of assets disposed of and the associated accumulated DD&A are removed from the Company’s Consolidated Balance Sheets with any gain or loss realized upon the sale or disposal included in the Company’s Consolidated Statements of Operations.
Exploration Expenses
Exploration costs, including certain geological and geophysical expenses and the costs of carrying and retaining undeveloped acreage, are charged to expense as incurred.
Costs from drilling exploratory wells are initially capitalized, but charged to expense if and when a well is determined to be unsuccessful. Determination is usually made on or shortly after drilling or completing the well, however, in certain situations a determination cannot be made when drilling is completed. The Company defers capitalized exploratory drilling costs for wells that have found a sufficient quantity of producible hydrocarbons but cannot be classified as proved because they are located in areas that require major capital expenditures or governmental or other regulatory approvals before production can begin. These costs continue to be deferred as wells-in-progress as long as development is underway, is firmly planned for in the near future or the necessary approvals are actively being sought.
Net changes in capitalized exploratory well costs are reflected in the following table for the periods presented (in thousands): | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Successor | | | Predecessor |
| Year Ended December 31, 2021 | | Period from November 20, 2020 through December 31, 2020 | | | Period from January 1, 2020 through November 19, 2020 | | Year Ended December 31, 2019 |
| | | | |
| | | | | | | | |
| | | | | | |
Beginning of period | $ | — | | | $ | — | | | | $ | — | | | $ | 4,457 | |
Exploratory well cost additions (pending determination of proved reserves) | — | | | — | | | | — | | | — | |
Exploratory well cost reclassifications (successful determination of proved reserves) | — | | | — | | | | — | | | (4,222) | |
Exploratory well dry hole costs (unsuccessful in adding proved reserves) | — | | | — | | | | — | | | (235) | |
Exploratory well cost reclassifications (canceled wells written off to predrill write-off) | 1 | | | — | | | | — | | | — | |
End of period | $ | 1 | | | $ | — | | | | $ | — | | | $ | — | |
As of December 31, 2021, the Company had no exploratory well costs that were capitalized for a period of greater than one year after the completion of drilling.
Assets Held for Sale
The Company occasionally markets non-core oil and gas properties and other property and equipment. At the end of each reporting period, the Company evaluates the properties being marketed to determine whether any should be reclassified as held for sale. The held for sale criteria include: management commits to a plan to sell; the asset is available for immediate sale; an active program to locate a buyer exists; the sale of the asset is probable and expected to be completed within one year; the asset is being actively marketed for sale; and it is unlikely that significant changes to the plan will be made. If each of these criteria is met, the property is reclassified as held for sale on the Company’s Consolidated Balance Sheets and measured at the lower of their carrying amount or estimated fair value less costs to sell. Fair values are estimated using accepted valuation techniques, such as a discounted cash flow model, valuations performed by third parties, earnings multiples, indicative bids or indicative market pricing, when available. Management considers historical experience and all available information at the time the estimates are made; however, the fair value that is ultimately realized upon the sale of the assets to be divested may differ from the estimated fair values reflected in the consolidated financial statements. DD&A expense is not recorded on assets to be divested once they are classified as held for sale.
Deferred Financing Costs
The Company capitalizes costs incurred in connection with obtaining financing. These costs are amortized over the term of the related financing using the straight-line method, which approximates the effective interest method. The amortization expense is recorded as a component of interest expense in the Company’s Consolidated Statements of Operations. Deferred financing costs related to the Oasis Credit Facility are included in other assets on the Company’s Consolidated Balance Sheets, while deferred financing costs related to the Oasis Senior Notes are included as a reduction of long-term debt on the Company’s Consolidated Balance Sheets.
Asset Retirement Obligations
In accordance with the FASB’s authoritative guidance on ARO, the Company records the fair value of a liability for a legal obligation to retire an asset in the period in which the liability is incurred and can be reasonably estimated with the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. For oil and gas properties and produced water disposal wells, this is the period in which the well is drilled or acquired. The ARO represents the estimated
amount the Company will incur to plug, abandon and remediate the properties at the end of their productive lives, in accordance with applicable state laws. The liability is accreted to its present value each period, and the capitalized costs are amortized using the unit-of-production method. The accretion expense is recorded as a component of DD&A in the Company’s Consolidated Statements of Operations.
The Company determines the ARO by calculating the present value of estimated cash flows related to the liability. Estimating the future ARO requires management to make estimates and judgments regarding timing and existence of a liability, as well as what constitutes adequate restoration. Inherent in the fair value calculation are numerous assumptions and judgments including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. These assumptions represent Level 3 inputs, as further discussed in Note 10—Fair Value Measurements. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the related asset.
Revenue Recognition
The Company recognizes revenue in accordance with Accounting Standards Codification 606, Revenue from Contracts with Customers (“ASC 606”). ASC 606 includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the Company expects to be entitled in exchange for those goods or services. Enhanced disclosures in accordance with ASC 606 have been provided in Note 7—Revenue Recognition.
The unit of account in ASC 606 is a performance obligation, which is a promise in a contract to transfer to a customer either a distinct good or service (or bundle of goods or services) or a series of distinct goods or services provided over a period of time. ASC 606 requires that a contract’s transaction price, which is the amount of consideration to which an entity expects to be entitled in exchange for transferring promised goods or services to a customer, is to be allocated to each performance obligation in the contract based on relative standalone selling prices and recognized as revenue when (point in time) or as (over time) the performance obligation is satisfied.
Crude oil, natural gas and natural gas liquids (“NGL”) revenues from the Company’s interests in producing wells are recognized when it satisfies a performance obligation by transferring control of a product to a customer. Substantially all of the Company’s crude oil and natural gas production is sold to purchasers under short-term (less than 12-month) contracts at market-based prices, and the Company’s NGL production is sold to purchasers under long-term (more than 12-month) contracts at market-based prices. The sales prices for crude oil, natural gas and NGLs are adjusted for transportation and other related deductions. These deductions are based on contractual or historical data and do not require significant judgment. Subsequently, these revenue deductions are adjusted to reflect actual charges based on third-party documents. Since there is a ready market for crude oil, natural gas and NGLs, the Company sells the majority of its production soon after it is produced at various locations. As a result, the Company maintains a minimum amount of product inventory in storage.
The Company’s purchased crude oil and natural gas sales are derived from the sale of crude oil and natural gas purchased from third parties. Revenues and expenses from these sales and purchases are recorded on a gross basis when the Company acts as a principal in these transactions by assuming control of the purchased crude oil or natural gas before it is transferred to the customer. In certain cases, the Company enters into sales and purchases with the same counterparty in contemplation of one another, and these transactions are recorded on a net basis in accordance with Accounting Standards Codification 845, Nonmonetary Transactions (“ASC 845”).
Other services revenues result from equipment rentals, and also included revenues for well completion services and product sales prior to the Company transitioning its well fracturing services from Oasis Well Services LLC (“OWS”) to a third-party provider during the first quarter of 2020 (the “Well Services Exit”). Other services revenues are recognized when services have been performed or related volumes or products have been delivered. Substantially all of the Company’s other services revenues are from services provided to its operated wells. The revenues related to work performed for the Company’s ownership interests are eliminated in consolidation, and only the revenues related to non-affiliated interest owners and other third-party customers are included in the Company’s Consolidated Statements of Operations.
Revenues and Production Taxes Payable
The Company calculates and pays taxes and royalties on crude oil and natural gas in accordance with the particular contractual provisions of the lease, license or concession agreements and the laws and regulations applicable to those agreements.
Leases
In February 2016, the FASB issued Accounting Standards Update No. 2016-02, Leases (Topic 842), which requires lessees to recognize a right-of-use (“ROU”) asset and related liability on the balance sheet for leases with durations greater than 12 months and also requires certain quantitative and qualitative disclosures about leasing arrangements. Accounting Standards Codification 842, Leases (“ASC 842”), was subsequently amended by Accounting Standards Update No. 2018-01, Land easement practical expedient for transition to Topic 842; Accounting Standards Update No. 2018-10, Codification
Improvements to Topic 842; Accounting Standards Update No. 2018-11, Targeted Improvements; and Accounting Standards Update No. 2019-01, Leases (Topic 842): Codification Improvements.
The Company adopted ASC 842 as of January 1, 2019 using the modified retrospective method. There was no impact to the opening equity balance as a result of adoption as the difference between the asset and liability balance is attributable to reclassifications of pre-existing balances, such as deferred rent, into the lease asset balance. Prior period amounts were not adjusted and continue to be reported in accordance with the previous guidance, Accounting Standards Codification 840 (“ASC 840”).
ASU 2018-01 provided a number of optional practical expedients in transition. The Company elected the package of practical expedients under the transition guidance within the new standard, including the practical expedient to not reassess under the new standard any prior conclusions about lease identification, lease classification and initial direct costs; the use-of hindsight practical expedient; the practical expedient to not reassess the prior accounting treatment for existing or expired land easements; and the practical expedient pertaining to combining lease and non-lease components for all asset classes. In addition, the Company elected not to apply the recognition requirements of ASC 842 to leases with terms of one year or less, and as such, recognition of lease payments for short-term leases are recognized in net income on a straight line basis.
In accordance with the adoption of ASC 842, management determines whether an arrangement is a lease at its inception. The Company’s operating and finance leases consist primarily of office space, drilling rigs, vehicles and other property and equipment used in its operations. The operating lease ROU asset also includes any lease incentives received in the recognition of the present value of future lease payments. The Company considers renewal and termination options in determining the lease term used to establish its ROU assets and lease liabilities to the extent the Company is reasonably certain to exercise the renewal or termination. The Company’s lease agreements do not contain any material residual value guarantees or material restrictive covenants.
As most of the Company’s leases do not provide an implicit rate, the Company uses its incremental borrowing rate based on the information available at commencement date in determining the present value of future lease payments. The Company has determined their respective incremental borrowing rates based upon the rate of interest that would have been paid on a collateralized basis over similar tenors to that of the leases. See Note 20—Leases for the disclosures required by ASC 842.
Fair Value Measurement
In the first quarter of 2020, the Company adopted Accounting Standards Update No. 2018-13, Fair Value Measurement (Topic 820): Disclosure Framework — Changes to the Disclosure Requirements for Fair Value Measurement (“ASU 2018-13”), which improves the effectiveness of the disclosure requirements for fair value measurements. The adoption of ASU 2018-13 did not result in a material impact to the Company’s financial position, cash flows or results of operations. See Note 10 — Fair Value Measurements for disclosures in accordance with ASU 2018-03.
Concentrations of Market and Credit Risk
The future results of the Company’s E&P operations will be affected by the market prices of crude oil, natural gas and NGLs. The availability of a ready market for crude oil and natural gas products in the future will depend on numerous factors beyond the Company’s control, including weather, imports, marketing of competitive fuels, proximity and capacity of crude oil and natural gas pipelines and other transportation facilities, any oversupply or undersupply of crude oil, natural gas and liquid products, the regulatory environment, the economic environment, and other regional and political events, none of which can be predicted with certainty. Commodity prices have been volatile in recent years. Due to a combination of the impacts of the COVID-19 pandemic and geopolitical pressures on the global supply and demand balance for crude oil and related products, commodity prices sharply declined in early 2020, which adversely affected the Company’s business, operating results and liquidity. A substantial or extended decline in the price of crude oil could have a further material adverse effect on the Company’s financial position, cash flows and results of operations.
The Company’s receivables include amounts due from purchasers of its crude oil and natural gas production and amounts due from joint interest partners for their respective portions of operating expenses and exploration and development costs. While certain of these customers and joint interest partners are affected by periodic downturns in the economy in general or in their specific segment of the crude oil or natural gas industry, including the current commodity price environment, the Company believes that its level of credit-related losses due to such economic fluctuations has been and will continue to be immaterial to the Company’s results of operations over the long term.
The Company manages and controls market and counterparty credit risk. In the normal course of business, collateral is not required for financial instruments with credit risk. Financial instruments, which potentially subject the Company to credit risk, consist principally of temporary cash balances and derivative financial instruments. The Company maintains cash and cash equivalents in bank deposit accounts which, at times, may exceed the federally insured limits. The Company has not experienced any significant losses from such investments. The Company attempts to limit the amount of credit exposure to any one financial institution or company. The Company believes the credit quality of its customers is generally high. In the normal
course of business, letters of credit or parent guarantees are required for counterparties which management perceives to have a higher credit risk.
Risk Management
The Company utilizes derivative financial instruments to manage risks related to changes in crude oil and natural gas prices. As of December 31, 2021, the Company utilized fixed price swaps to reduce the volatility of crude oil prices on a portion of its future expected crude oil production (see Note 11—Derivative Instruments).
The Company records all derivative instruments on the Consolidated Balance Sheets as either assets or liabilities measured at their estimated fair value. Derivative assets and liabilities arising from derivative contracts with the same counterparty are reported on a net basis, as all counterparty contracts provide for net settlement. The Company has not designated any derivative instruments as hedges for accounting purposes and does not enter into such instruments for speculative trading purposes. Gains and losses from valuation changes in commodity derivative instruments are reported in the other income (expense) section of the Company’s Consolidated Statements of Operations. The Company’s cash flow is only impacted when the actual settlements under the derivative contracts result in making or receiving a payment to or from the counterparty. These cash settlements represent the cumulative gains and losses on the Company’s derivative instruments for the periods presented and do not include a recovery of costs that were paid to acquire or modify the derivative instruments that were settled. Cash settlements are reflected as investing activities in the Company’s Consolidated Statements of Cash Flows.
Derivative financial instruments that hedge the price of crude oil and natural gas are executed with major financial institutions that expose the Company to market and credit risks and which may, at times, be concentrated with certain counterparties or groups of counterparties. At December 31, 2021, the Company had derivatives in place with eight counterparties which are all lenders under the Oasis Credit Facility. Although notional amounts are used to express the volume of these contracts, the amounts potentially subject to credit risk in the event of nonperformance by the counterparties are substantially smaller. The credit worthiness of the counterparties is subject to continual review. The Company believes the risk of nonperformance by its counterparties is low. Full performance is anticipated, and the Company has no past-due receivables from the counterparties to its commodity derivative contracts. The Company’s policy is to execute financial derivatives only with major, credit-worthy financial institutions.
The Company’s derivative contracts are documented with industry standard contracts known as a Schedule to the Master Agreement and International Swaps and Derivatives Association, Inc. Master Agreement (“ISDA”). Typical terms for the ISDAs include credit support requirements, cross default provisions, termination events and set-off provisions. The Company is not required to provide any credit support to its counterparties other than cross collateralization with the properties securing the Oasis Credit Facility. As of December 31, 2021, the Company was in compliance with these requirements.
Contingencies
Certain conditions may exist as of the date the Company’s consolidated financial statements are issued that may result in a loss to the Company, but which will only be resolved when one or more future events occur or fail to occur. The Company’s management, with input from legal counsel, assesses such contingent liabilities, and such assessment inherently involves judgment. In assessing loss contingencies related to legal proceedings that are pending against the Company or unasserted claims that may result in proceedings, the Company’s management, with input from legal counsel, evaluates the perceived merits of any legal proceedings or unasserted claims as well as the perceived merits of the amount of relief sought or expected to be sought therein.
If the assessment of a contingency indicates that it is probable that a loss has been incurred and the amount of liability can be estimated, then the estimated undiscounted liability is accrued in the Company’s consolidated financial statements. If the assessment indicates that a potentially material loss contingency is not probable but is reasonably possible, or is probable but cannot be estimated, then the nature of the contingent liability, together with an estimate of the range of possible loss if determinable and material, is disclosed. Actual results could vary from these estimates and judgments.
Loss contingencies considered remote are generally not disclosed unless they involve guarantees, in which case the guarantees would be disclosed. See Note 22—Commitments and Contingencies for additional information regarding the Company’s contingencies.
Environmental Costs
Environmental expenditures are expensed or capitalized, as appropriate, depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations, and which do not have future economic benefit, are expensed. Liabilities related to future costs are recorded on an undiscounted basis when environmental assessments and/or remediation activities are probable and the costs can be reasonably estimated.
Equity-Based Compensation
The Board of Directors adopted the Oasis Petroleum Inc. 2020 Long Term Incentive Plan (the “2020 LTIP”), which provides for the grant of incentive stock options, nonstatutory stock options, restricted stock, restricted stock units, stock appreciation rights, dividend equivalents, other stock-based awards, cash awards, performance awards or any combination of the foregoing. Upon adopting the 2020 LTIP, 2,402,402 shares of common stock were reserved for grants of awards.
The Company determines the compensation expense for share-settled awards based on the grant date fair value, and such expense is recognized ratably over the requisite service period, which is generally the vesting period. Cash-settled awards are classified as liabilities. Compensation expense for cash-settled awards is recognized over the requisite service period and is remeasured at the fair value of such awards at the end of each reporting period. Forfeitures are accounted for as they occur by reversing the expense previously recognized for awards that were forfeited during the period.
The fair values of awards are determined based on the type of award and may utilize market prices on the date of grant (for service-based equity awards) or at the end of the reporting period (for liability-classified awards), Monte Carlo simulations or other acceptable valuation methodologies, as appropriate for the type of award. A Monte Carlo simulation model uses assumptions regarding random projections and must be repeated numerous times to achieve a probabilistic assessment (see Note 17—Equity-Based Compensation for more information).
Any excess tax benefit arising from the Company’s equity-based compensation plan is recognized as a credit to income tax expense or benefit in the Company’s Consolidated Statements of Operations.
Treasury Stock
Treasury stock represents shares of common stock repurchased under the Company’s share repurchase program and shares withheld by the Company equivalent to the payroll tax withholding obligations due from employees upon the vesting of restricted stock awards.
Income Taxes
The Company’s provision for taxes includes both federal and state income taxes. The Company records its income taxes in accordance with ASC 740, which results in the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between the book carrying amounts and the tax basis of assets and liabilities. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.
The Company applies significant judgment in evaluating its tax positions and estimating its provision for income taxes. During the ordinary course of business, there may be transactions and calculations for which the ultimate tax determination is uncertain. The actual outcome of these future tax consequences could differ significantly from the Company’s estimates, which could impact its financial position, results of operations and cash flows.
The Company also accounts for uncertainty in income taxes recognized in the financial statements in accordance with GAAP by prescribing a recognition threshold and measurement attribute for a tax position taken or expected to be taken in a tax return. Authoritative guidance for accounting for uncertainty in income taxes requires that the Company recognize the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit. For tax positions meeting the more-likely-than-not threshold, the amount recognized in the financial statements is the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority. The Company did not have any uncertain tax positions outstanding and, as such, did not record a liability as of December 31, 2021 or 2020. All deferred tax assets and liabilities, along with any related valuation allowance, are classified as non-current on the Company’s Consolidated Balance Sheets.
In the fourth quarter of 2020, the Company adopted Accounting Standards Update No. 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes (“ASU 2019-12”), which simplifies the accounting for income taxes by removing certain exceptions to the general principles in Topic 740 related to the approach for intraperiod tax allocation and calculating income taxes in interim periods, among other changes. The adoption of ASU 2019-12 did not result in a material impact to the Company’s financial position, cash flows or result of operations.
Recent Accounting Pronouncements
Reference rate reform. In March 2020, the FASB issued Accounting Standards Update 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting (“ASU 2020-04”). The amendments provide optional guidance for a limited time to ease the potential burden in accounting for reference rate reform. The new guidance provides optional expedients and exceptions for applying GAAP to contracts, hedging relationships and other transactions
affected by reference rate reform if certain criteria are met. The amendments apply only to contracts and hedging relationships that reference the London Interbank Offered Rate (“LIBOR”) or another reference rate expected to be discontinued due to reference rate reform. These amendments are effective immediately and may be applied prospectively to contract modifications made and hedging relationships entered into or evaluated on or before December 31, 2022. The Company is currently evaluating its contracts and the optional expedients provided by ASU 2020-04 and the impact the new standard will have on its financial statements and related disclosures.
5. Oasis Midstream Partners
OMP is a gathering and processing master limited partnership formed by the Company to own, develop, operate and acquire a diversified portfolio of midstream assets in North America. OMP’s assets are located in the Williston and Permian Basins. As of December 31, 2021, the Company owned approximately 70% of OMP’s outstanding limited partner units.
OMP Merger
On October 25, 2021, OMP and OMP GP entered into an Agreement and Plan of Merger (the “Merger Agreement”) with Crestwood Equity Partners LP, a Delaware limited partnership (“Crestwood”), Project Falcon Merger Sub LLC, a Delaware limited liability company and direct wholly-owned subsidiary of Crestwood, Project Phantom Merger Sub LLC, a Delaware limited liability company and direct wholly-owned subsidiary of Crestwood, and, solely for the purposes of Section 2.1(a)(i) of the Merger Agreement, Crestwood Equity GP LLC, a Delaware limited liability company and the general partner of Crestwood (“Crestwood GP”).
Pursuant to the Merger Agreement, the Company agreed to sell to Crestwood its entire ownership of OMP common units and all of the limited liability company interests of OMP GP in exchange for $160.0 million in cash and approximately 21 million common units of Crestwood (the “OMP Merger”). The OMP Merger was unanimously approved by the Board of Directors of both Oasis and Crestwood and was also unanimously approved by the Board of Directors and Conflicts Committee of OMP GP.
In addition, the Company and Crestwood executed a director nomination agreement pursuant to which Oasis appointed two directors to the Board of Directors of Crestwood GP. In accordance with the director nomination agreement, and for so long as Oasis and its affiliates own at least 15% of Crestwood’s issued and outstanding common units, Oasis may designate two directors to the Board of Directors of Crestwood GP. Oasis may designate one director if Oasis and its affiliates hold at least 10% (but less than 15%) of Crestwood’s issued and outstanding common units.
On February 1, 2022, the OMP Merger was completed and the Company received $160.0 million in cash and approximately 21 million common units of Crestwood in exchange for the Company’s ownership of OMP common units and all of the limited liability company interests of OMP GP. The Company owns approximately 21.7% of Crestwood’s issued and outstanding common units and is Crestwood’s largest single customer. The OMP Merger represents a strategic shift for the Company and qualified for reporting as a discontinued operation. See Note 6—Discontinued Operations.
Contractual arrangements
The Company had previously entered into several long-term, fee-based contractual arrangements with OMP for midstream services, including (i) natural gas gathering, compression, processing and gas lift supply services; (ii) crude oil gathering, terminaling and transportation services; (iii) produced and flowback water gathering and disposal services; and (iv) freshwater distribution services. These contracts were assigned to Crestwood upon completion of the OMP Merger, and the Company will depend on Crestwood for a large portion of its midstream services.
In addition, the Company provided substantial labor and overhead support to OMP pursuant to a services and secondment agreement. The Company had also seconded to OMP certain of its employees to operate, construct, manage and maintain its assets. The expenses of executive officers and non-executive employees were allocated to OMP based on the amount of time spent managing its business and operations. In connection with the closing of OMP Merger, certain employees of the Company were transferred to Crestwood. In addition, the Company and Crestwood entered into a transition services agreement pursuant to which Oasis will provide customary transition services to Crestwood for a limited duration in exchange for a monthly service fee.
Midstream Simplification
On March 30, 2021, the Company completed the transactions contemplated by a contribution and simplification agreement (the “Contribution and Simplification Agreement”), dated as of March 22, 2021.
Pursuant to the Contribution and Simplification Agreement, among other things, (a) the Company contributed to OMP its remaining limited liability company interests in Bobcat DevCo and Beartooth DevCo of 64.7% and 30.0%, respectively, in exchange for total consideration of approximately $512.5 million composed of (x) a cash distribution of $231.5 million and (y) 12,949,644 common units representing limited partner interests in OMP, (b) OMP’s incentive distribution rights were cancelled and converted into 1,850,356 OMP common units (the “IDR Conversion Common Units”), and (c) OMP GP distributed the
IDR Conversion Common Units on a pro rata basis to holders of its Class A units and Class B units, such that following such distribution, Oasis, through its wholly-owned subsidiary OMS Holdings LLC (“OMS Holdings”), is the sole member of OMP GP (the foregoing clauses (a), (b) and (c), the “Midstream Simplification”). The effective date of the Midstream Simplification was January 1, 2021.
6. Discontinued Operations
The OMP Merger represents a strategic shift for the Company and qualifies as a discontinued operation in accordance with ASC 205-20.
As of October 25, 2021, the operating results of OMP were classified as discontinued operations on the Company’s Consolidated Statements of Operations. The Company will have continuing involvement with Crestwood following the completion of the OMP Merger for midstream services pursuant to contractual arrangements between the Company and OMP that were assigned to Crestwood at closing. Intercompany transactions between Oasis and OMP have historically been eliminated in consolidation within lease operating expenses and gathering, processing and transportation expenses for operated properties and within oil and gas revenues for non-operated properties. In addition, the intercompany purchase and sale of residue gas and NGLs between the Company and OMP has historically been eliminated in consolidation within midstream revenues and midstream expenses. The Company has reclassified these transactions to purchased oil and gas expenses and purchased oil and gas sales, respectively, to reflect their continuing impact.
Consolidated Statements of Operations
The results of operations reported as discontinued operations in connection with the OMP Merger are as follows for the periods presented (in thousands):
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Successor | | | Predecessor |
| Year Ended December 31, 2021 | | November 20, 2020 through December 31, 2020 | | | January 1, 2020 through November 19, 2020 | | Year Ended December 31, 2019 |
| | | | | | | | |
Revenues | | | | | | | | |
Oil and gas revenues | $ | 1,013 | | | $ | 297 | | | | $ | 2,075 | | | $ | 962 | |
Purchased oil and gas sales (1) | (131,369) | | | (13,406) | | | | (50,744) | | | (72,223) | |
Midstream revenues | 254,228 | | | 26,031 | | | | 166,631 | | | 212,208 | |
Total revenues | 123,872 | | | 12,922 | | | | 117,962 | | | 140,947 | |
Operating expenses | | | | | | | | |
Lease operating expenses (1) | (62,142) | | | (4,676) | | | | (42,034) | | | (65,306) | |
Midstream expenses | 122,040 | | | 10,572 | | | | 42,987 | | | 62,146 | |
Gathering, processing and transportation expenses (1) | (49,795) | | | (4,074) | | | | (31,988) | | | (45,220) | |
Purchased oil and gas expenses (1) | (125,709) | | | (12,921) | | | | (43,163) | | | (65,734) | |
Depreciation, depletion and amortization | 31,868 | | | 2,305 | | | | 20,113 | | | 15,552 | |
Impairment | 2 | | | — | | | | 111,613 | | | — | |
General and administrative expenses (1) | 4,193 | | | (579) | | | | 594 | | | (5,089) | |
Total operating expenses | (79,543) | | | (9,373) | | | | 58,122 | | | (103,651) | |
Operating income | 203,415 | | | 22,295 | | | | 59,840 | | | 244,598 | |
Other income (expense) | | | | | | | | |
Interest expense, net of capitalized interest | (36,945) | | | (1,148) | | | | (39,648) | | | (16,936) | |
Reorganization items | — | | | — | | | | 120,915 | | | — | |
Other income (expense) | (115) | | | (1) | | | | 136 | | | (129) | |
Total other income (expense), net | (37,060) | | | (1,149) | | | | 81,403 | | | (17,065) | |
Income from discontinued operations before income taxes | 166,355 | | | 21,146 | | | | 141,243 | | | 227,533 | |
Income tax expense | (17) | | | — | | | | — | | | — | |
Income from discontinued operations, net of income tax | 166,338 | | | 21,146 | | | | 141,243 | | | 227,533 | |
Net income (loss) attributable to non-controlling interests | 35,696 | | | 3,950 | | | | (84,283) | | | 37,596 | |
Income from discontinued operations attributable to Oasis, net of income tax | $ | 130,642 | | | $ | 17,196 | | | | $ | 225,526 | | | $ | 189,937 | |
__________________
(1)Includes discontinued intercompany eliminations.
Consolidated Balance Sheets
The carrying amounts of the major classes of assets and liabilities related to the OMP Merger are as follows for the periods presented (in thousands):
| | | | | | | | | | | |
| December 31, |
| 2021 | | 2020 |
| | | |
ASSETS | | | |
Current assets | | | |
Cash and cash equivalents | $ | 2,669 | | | $ | 5,147 | |
| | | |
Accounts receivable, net | 6,509 | | | 4,299 | |
Inventory | 8,541 | | | 12,305 | |
Prepaid expenses | 456 | | | 3,914 | |
| | | |
Other current assets | — | | | 649 | |
Total current assets of discontinued operations | 18,175 | | | 26,314 | |
Property, plant and equipment | | | |
Oil and gas properties (successful efforts method)(1) | (3,207) | | | (276) | |
Other property and equipment | 933,667 | | | 884,445 | |
Less: accumulated depreciation, depletion and amortization | (32,102) | | | (3,207) | |
Total property, plant and equipment, net | 898,358 | | | 880,962 | |
| | | |
| | | |
| | | |
Operating right-of-use assets | 671 | | | 1,643 | |
Intangible assets | 40,277 | | | 43,000 | |
Goodwill | 70,534 | | | 70,534 | |
| | | |
Other assets | 1,303 | | | 665 | |
Total non-current assets of discontinued operations | 1,011,143 | | | 996,804 | |
Total assets of discontinued operations | $ | 1,029,318 | | | $ | 1,023,118 | |
| | | |
LIABILITIES | | | |
Current liabilities | | | |
Accounts payable | $ | 43 | | | $ | 680 | |
Revenues and production taxes payable | 1,635 | | | 1,632 | |
Accrued liabilities | 36,183 | | | 18,142 | |
Accrued interest payable | 9,296 | | | 360 | |
| | | |
| | | |
Current operating lease liabilities | 733 | | | 945 | |
Other current liabilities | 564 | | | 350 | |
Total current liabilities of discontinued operations | 48,454 | | | 22,109 | |
Long-term debt | 644,078 | | | 450,000 | |
| | | |
Asset retirement obligations | 904 | | | 831 | |
| | | |
Operating lease liabilities | — | | | 733 | |
Other liabilities | 6,217 | | | 4,187 | |
Total non-current liabilities of discontinued operations | 651,199 | | | 455,751 | |
Total liabilities of discontinued operations | $ | 699,653 | | | $ | 477,860 | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
___________________________
(1) Includes discontinued intercompany eliminations.
Consolidated Statements of Cash Flows
Depreciation, depletion and amortization contained in “Cash flows from operating activities” from discontinued operations was $31.9 million for the year ended December 31, 2021 (Successor), $2.3 million for the period from November 20, 2020 through
December 31, 2020 (Successor), $20.1 million for the period from January 1, 2020 through November 19, 2020 (Predecessor) and $15.6 million for the year ended December 31, 2019 (Predecessor). Capital expenditures contained in “Cash flows used in investing activities” that were attributable to discontinued operations were $38.5 million for the year ended December 31, 2021 (Successor), $2.5 million for the period from November 20, 2020 through December 31, 2020 (Successor), $54.8 million for the period from January 1, 2020 through November 19, 2020 (Predecessor) and $222.2 million for the year ended December 31, 2019 (Predecessor). There were no significant non-cash activities from discontinued operations for the periods presented.
7. Revenue Recognition
The Company’s revenues are derived from contracts for crude oil, natural gas and NGL sales and other services, as described below. Generally, for the crude oil, natural gas, and NGL contracts: (i) each unit (barrel (“Bbl”), Mcf, gallon, etc.) of commodity product is a separate performance obligation, as the Company’s promise is to sell multiple distinct units of commodity product at a point in time; (ii) the transaction price principally consists of variable consideration, which amount is determinable each month end based on the Company’s right to invoice at month end for the value of commodity product sold to the customer that month; and (iii) the transaction price is allocated to each performance obligation based on the commodity product’s standalone selling price and recognized as revenue upon delivery of the commodity product, which is the point in time when the customer obtains control of the commodity product and the Company’s performance obligation is satisfied. The sales of crude oil, natural gas and NGLs as presented on the Company’s Consolidated Statements of Operations represent the Company’s share of revenues net of royalties and excluding revenue interests owned by others. When selling crude oil, natural gas and NGLs on behalf of royalty owners or working interest owners, the Company is acting as an agent and thus reports the revenue on a net basis. To the extent actual volumes and prices of crude oil and natural gas sales are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and prices for those properties are estimated and recorded. The Company’s contracts with customers typically require payments for crude oil, natural gas and NGL sales within 30 days following the calendar month of delivery.
Crude oil revenues. The Company sells a substantial majority of its crude oil through bulk sales at delivery points on crude oil gathering systems to a variety of customers under short-term contracts that include a specified quantity of crude oil to be delivered and sold to the customer at a specified delivery point. The customer pays a market-based transaction price, which incorporates differentials that include, but are not limited to, transportation costs.
Natural gas and NGL revenues. The Company’s natural gas sales consist of unprocessed gas sales and residue gas sales. Unprocessed gas is sold at delivery points at or near the wellhead under various contracts, in which the customer pays a transaction price based on its sale of the bifurcated NGLs and residue gas, less any associated fees. Revenue is recorded on a net basis, with processing fees deducted within revenue rather than as a separate expense line item, as title and control transfer at the delivery point. Residue gas from the Company’s gas processing plants located in Wild Basin is sold at the tailgate or transported and sold at other downstream sales points, and the customer pays a transaction price based on a market indexed per-unit rate for the quantities sold. NGLs from the Company’s gas processing plants located in Wild Basin are sold at the tailgate or trucked and sold at other downstream locations, and the customer pays a transaction price based on a market indexed per-unit rate for the quantities sold.
Purchased crude oil and natural gas sales. The Company’s purchased crude oil and natural gas sales are derived from the sale of crude oil and natural gas purchased from a third party. The Company sells the purchased commodities to a variety of customers under short-term contracts that include specified quantities of crude oil and natural gas to be sold and delivered to the customer at a specified delivery point. The customer pays a market-based transaction price, which is based on the price index applicable for the location of the sale. Revenues and expenses from these sales and purchases are generally recorded on a gross basis, as the Company acts as a principal in these transactions by assuming control of the purchased crude oil or natural gas before it is transferred to the customer. In certain cases, the Company enters into sales and purchases with the same counterparty in contemplation of one another, and these transactions are recorded on a net basis in accordance with ASC 845.
Other Services. The Company’s other services revenues are from services provided by OWS for the Company’s operated wells, including equipment rental revenues and, prior to the Well Services Exit, hydraulic fracturing revenues. Intercompany revenues for work performed for the Company’s working interests are eliminated in consolidation, and only the revenues related to non-affiliated working interest owners are included in consolidated revenues.
•Equipment rental revenues. Equipment rental revenue is generated when OWS provides equipment rentals to the Company’s operated wells. Equipment rental revenues are calculated based on the equipment’s daily rental rate and the number of days that the equipment was rented by the customer. The Company’s performance obligation is satisfied when the entire rental period is completed. Equipment rental revenues are recognized over a period of time due to the customer simultaneously receiving and consuming the benefits of the rental equipment provided by the Company on a daily basis. Satisfaction of the Company’s performance obligation is measured at the completion of each day of the rental period, which directly corresponds with its right to consideration from the
customer. Revenues associated with these contracts are recognized at the time of invoicing for the entire rental period under the right to invoice practical expedient.
•Hydraulic fracturing revenues. Prior to the Company’s Well Services Exit, hydraulic fracturing revenues were generated when OWS provided hydraulic fracturing services and related materials to the Company’s operated wells. These services were composed of various components, such as personnel, equipment and hydraulic fracturing materials, but management determined that each component was not distinct, as it could not be used on its own or together with a resource readily available to the customer. The Company’s performance obligation was satisfied when the hydraulic fracturing of a well was completed. Revenue was recognized over a period of time upon the completion of each stage of hydraulic fracturing of a well.
Revenues associated with contracts with customers for crude oil, natural gas and NGL sales and other services were as follows for the periods presented (in thousands): | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Successor | | | Predecessor |
| Year Ended December 31, 2021 | | Period from November 20, 2020 through December 31, 2020 | | | Period from January 1, 2020 through November 19, 2020 | | Year Ended December 31, 2019 |
| | | | |
| | | | | | | | |
| | | |
Crude oil revenues | $ | 910,381 | | | $ | 69,075 | | | | $ | 522,812 | | | $ | 1,261,413 | |
Purchased crude oil sales | 247,252 | | | 6,861 | | | | 181,320 | | | 401,584 | |
Natural gas and NGL revenues | 289,875 | | | 17,070 | | | | 78,698 | | | 146,396 | |
Purchased natural gas sales | 131,731 | | | 13,772 | | | | 55,791 | | | 79,430 | |
Other services revenues | 687 | | | 215 | | | | 6,836 | | | 41,974 | |
Total revenues | $ | 1,579,926 | | | $ | 106,993 | | | | $ | 845,457 | | | $ | 1,930,797 | |
The Company has elected practical expedients, pursuant to ASC 606, to exclude from the presentation of remaining performance obligations: (i) contracts with index-based pricing or variable volume attributes in which such variable consideration is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct service that forms part of a series of distinct services and (ii) contracts with an original expected duration of one year or less.
8. Inventory
The following table sets forth the Company’s inventory: | | | | | | | | | | | |
| December 31, |
| 2021 | | 2020 |
| | | |
| (In thousands) |
Inventory | | | |
Equipment and materials | $ | 12,175 | | | $ | 12,798 | |
Crude oil inventory | 16,781 | | | 8,826 | |
Total inventory | $ | 28,956 | | | $ | 21,624 | |
| | | |
Long-term inventory | | | |
Linefill in third-party pipelines | $ | 17,510 | | | $ | 14,522 | |
Long-term inventory | $ | 17,510 | | | $ | 14,522 | |
| | | |
Total | $ | 46,466 | | | $ | 36,146 | |
9. Additional Balance Sheet Information
Certain balance sheet amounts are comprised of the following: | | | | | | | | | | | |
| December 31, |
| 2021 | | 2020 |
| | | |
| (In thousands) |
Accounts receivable, net | | | |
Trade accounts | $ | 309,756 | | | $ | 159,862 | |
Joint interest accounts | 40,890 | | | 31,920 | |
Other accounts | 28,270 | | | 10,564 | |
Total | 378,916 | | | 202,346 | |
Allowance for credit losses | (1,714) | | | (106) | |
Total accounts receivable, net | $ | 377,202 | | | $ | 202,240 | |
| | | |
Revenues and production taxes payable | | | |
Revenue suspense | $ | 103,693 | | | $ | 66,602 | |
Royalties payable | 147,932 | | | 65,412 | |
Production taxes payable | 18,681 | | | 12,851 | |
Total revenue and production taxes payable | $ | 270,306 | | | $ | 144,865 | |
| | | |
Accrued liabilities | | | |
Accrued capital costs | $ | 33,085 | | | $ | 36,051 | |
Accrued lease operating expenses | 29,478 | | | 18,635 | |
Accrued oil and gas purchases | 35,211 | | | 8,967 | |
Accrued general and administrative expenses | 13,270 | | | 35,471 | |
Other accrued liabilities | 39,630 | | | 9,018 | |
Total accrued liabilities | $ | 150,674 | | | $ | 108,142 | |
10. Fair Value Measurements
In accordance with the FASB’s authoritative guidance on fair value measurements, the Company’s financial assets and liabilities are measured at fair value on a recurring basis. The Company’s financial instruments, including certain cash and cash equivalents, accounts receivable, accounts payable and other payables, are carried at cost, which approximates their respective fair market values due to their short-term maturities. The Company recognizes its non-financial assets and liabilities, such as ARO (see Note 15—Asset Retirement Obligations) and proved oil and gas properties upon impairment (see Note 12—Property, Plant and Equipment), at fair value on a non-recurring basis.
As defined in the authoritative guidance, fair value is 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 (exit price). To estimate fair value, the Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable.
The authoritative guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (“Level 1” measurements) and the lowest priority to unobservable inputs (“Level 3” measurements). The three levels of the fair value hierarchy are as follows:
Level 1 — Unadjusted quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
Level 2 — Pricing inputs, other than unadjusted quoted prices in active markets included in Level 1, are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including
quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument and can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.
Level 3 — Pricing inputs are generally unobservable from objective sources, requiring internally developed valuation methodologies that result in management’s best estimate of fair value.
Financial Assets and Liabilities
Financial assets and liabilities are classified in their entirety 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 requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.
The following tables set forth by level within the fair value hierarchy the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis: | | | | | | | | | | | | | | | | | | | | | | | |
| Fair value at December 31, 2021 |
| Level 1 | | Level 2 | | Level 3 | | Total |
| | | | | | | |
| (In thousands) |
Assets: | | | | | | | |
| | | | | | | |
Commodity derivative instruments (see Note 11) | $ | — | | | $ | 55 | | | $ | — | | | $ | 55 | |
Total assets | $ | — | | | $ | 55 | | | $ | — | | | $ | 55 | |
Liabilities: | | | | | | | |
Commodity derivative instruments (see Note 11) | $ | — | | | $ | 204,729 | | | $ | — | | | $ | 204,729 | |
Total liabilities | $ | — | | | $ | 204,729 | | | $ | — | | | $ | 204,729 | |
| | | | | | | |
| Fair value at December 31, 2020 |
| Level 1 | | Level 2 | | Level 3 | | Total |
| | | | | | | |
| (In thousands) |
Assets: | | | | | | | |
| | | | | | | |
Commodity derivative instruments (see Note 11) | $ | — | | | $ | 467 | | | $ | — | | | $ | 467 | |
Total assets | $ | — | | | $ | 467 | | | $ | — | | | $ | 467 | |
Liabilities: | | | | | | | |
Commodity derivative instruments (see Note 11) | $ | — | | | $ | 94,558 | | | $ | — | | | $ | 94,558 | |
Total liabilities | $ | — | | | $ | 94,558 | | | $ | — | | | $ | 94,558 | |
The Level 2 instruments presented in the tables above consist of commodity derivative instruments (see Note 11—Derivative Instruments). The fair values of the Company’s commodity derivative instruments are based upon a third-party preparer’s calculation using mark-to-market valuation reports provided by the Company’s counterparties for monthly settlement purposes to determine the valuation of its derivative instruments. The Company has the third-party preparer evaluate other readily available market prices for its derivative contracts as there is an active market for these contracts. The third-party preparer performs its independent valuation using a moment matching method similar to Turnbull-Wakeman for Asian options. The significant inputs used are commodity prices, volatility, skew, discount rate and the contract terms of the derivative instruments. The Company does not have access to the specific proprietary valuation models or inputs used by its counterparties or third-party preparer. The Company compares the third-party preparer’s valuation to counterparty valuation statements, investigating any significant differences, and analyzes monthly valuation changes in relation to movements in commodity forward price curves. The determination of the fair value for derivative instruments also incorporates a credit adjustment for non-performance risk, as required by GAAP. The Company calculates the credit adjustment for derivatives in a net asset position using current credit default swap values for each counterparty. The credit adjustment for derivatives in a net liability position is based on the market credit spread of the Company or similarly rated public issuers. The Company recorded an adjustment to reduce the fair value of its net derivative liability by $5.3 million at December 31, 2021 and an adjustment to reduce the fair value of its net derivative liability by $4.3 million at December 31, 2020.
Permian Basin Sale Contingent Consideration. The fair value of the Permian Basin Sale Contingent Consideration (defined in Note 11— Derivative Instruments) was determined by a third-party valuation specialist as of the close date and at the end of each reporting period using a Monte Carlo simulation model and Ornstein-Uhlenbeck pricing process. The significant inputs include NYMEX WTI forward price curve, volatility, mean reversion rate and counterparty credit risk adjustment. The Company determined these were Level 2 fair value inputs that are substantially observable in active markets or can be derived from observable data.
Non-Financial Assets and Liabilities
The fair value of the Company’s non-financial assets measured at fair value on a non-recurring basis is determined using valuation techniques that include Level 3 inputs.
Asset retirement obligations. The initial measurement of ARO at fair value is recorded in the period in which the liability is incurred. Fair value is determined by calculating the present value of estimated future cash flows related to the liability. Estimating the future ARO requires management to make estimates and judgments regarding the timing and existence of a liability, as well as what constitutes adequate restoration when considering current regulatory requirements. Inherent in the fair value calculation are numerous assumptions and judgments, including the ultimate costs, inflation factors, credit-adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments.
Oil and gas and other properties. The Company records its properties at fair value when acquired in a business combination or upon impairment for proved oil and gas properties and other properties. Fair value is determined using a discounted cash flow model. The inputs used are subject to management’s judgment and expertise and include, but are not limited to, estimates of crude oil and natural gas proved reserves, future commodity pricing, future rates of production, estimates of operating and development costs, risk-adjusted discount rates and estimates of throughput volumes for the Company’s midstream assets. These inputs are classified as Level 3 inputs, except the underlying commodity price assumptions are based on NYMEX forward strip prices (Level 1) and adjusted for price differentials.
Williston Basin Acquisition. The Company recognized the assets acquired in the Williston Basin Acquisition at cost on a relative fair value basis (see Note 13—Acquisitions and Divestitures). Fair value was determined using a discounted cash flow model. The underlying future commodity prices included in the Company’s estimated future cash flows of its proved oil and gas properties were determined using NYMEX forward strip prices as of October 21, 2021 for five years, escalating 2% per year thereafter. The estimated future cash flows also included a 2% inflation factor applied to the future operating and development costs after five years and every year thereafter. The estimated future cash flows were discounted at a market-based weighted average cost of capital of 11%.
2020 Impairments. As a result of the significant decline in expected future commodity prices in the first quarter of 2020, the Company reviewed its properties for impairment as of March 31, 2020. The underlying future commodity prices included in the Company’s estimated future cash flows of its proved oil and gas properties were determined using NYMEX forward strip prices as of March 31, 2020 for five years, escalating 2.5% per year thereafter. The estimated future cash flows also included a 2.5% inflation factor applied to the future operating and development costs after five years and every year thereafter. The estimated future cash flows for the Company’s proved oil and gas properties and midstream assets were discounted at market-based weighted average costs of capital of 12.7% and 10.4%, respectively (see Note 12—Property, Plant and Equipment).
Fresh start accounting. On the Emergence Date, the Company emerged from the Chapter 11 Cases and adopted fresh start accounting, which resulted in the Company becoming a new entity for financial reporting purposes. Upon the adoption of fresh start accounting, the Company’s assets and liabilities were recorded at their fair values as of November 19, 2020. The inputs utilized in the valuation of the Company’s most significant assets, its oil and gas properties and midstream long-lived assets, included mostly unobservable inputs which fall within Level 3 of the fair value hierarchy. Such inputs included estimates of future oil and gas production from the Company’s reserve reports, commodity prices based on forward strip price curves (adjusted for basis differentials) as of November 19, 2020, operating and development costs, expected future development plans for the properties, estimated replacement costs and weighted-average cost of capital discount rates. The Company also recorded its ARO at fair value as a result of fresh start accounting. The inputs utilized in valuing the ARO liability, which are discussed above, are mostly Level 3 unobservable inputs. Refer to Note 3—Fresh Start Accounting for a detailed discussion of the fair value approaches and significant inputs used by the Company.
11. Derivative Instruments
The Company utilizes derivative financial instruments to manage risks related to changes in crude oil and natural gas prices. The Company’s crude oil contracts will settle monthly based on the average NYMEX WTI. The Company’s natural gas contracts will settle monthly based on the average NYMEX Henry Hub natural gas index price (“NYMEX HH”).
The Company primarily utilizes fixed price swaps and collars to reduce the volatility of crude oil and natural gas prices on future expected production. Swaps are designed to establish a fixed price for the volumes under contract, while collars are designed to establish a minimum price (floor) and a maximum price (ceiling) for the volumes under contract. The Company may, from time to time, restructure existing derivative contracts or enter into new transactions to effectively modify the terms of current contracts in order to improve the pricing parameters in existing contracts.
All derivative instruments are recorded on the Company’s Consolidated Balance Sheets as either assets or liabilities measured at their fair value (see Note 10—Fair Value Measurements). The Company has not designated any derivative instruments as hedges for accounting purposes and does not enter into such instruments for speculative trading purposes. If a derivative does not qualify as a hedge or is not designated as a hedge, the changes in fair value are recognized in the other income (expense)
section of the Company’s Consolidated Statements of Operations as a net gain or loss on derivative instruments. The Company’s cash flow is only impacted when cash settlements on matured, modified or liquidated derivative contracts result in making a payment to or receiving a payment from a counterparty. Cash settlements are reflected as investing activities in the Company’s Consolidated Statements of Cash Flows.
2021 derivative contract modifications. During 2021, the Company entered into a series of transactions with derivative counterparties to modify the swap price of certain commodity derivative contracts. The Company modified the strike price of its 2022 crude oil swap contracts to $70.00 per barrel from a weighted average price of $40.89 per barrel and its 2023 crude oil swap contracts to $50.00 per barrel from a weighted average price of $43.68 per barrel. The commodity contracts modified included total notional volumes of 6,935 MBbl which settle in 2022 and 5,110 MBbl which settle in 2023. The Company paid $220.9 million to modify these commodity derivative contracts, which is reflected as a cash outflow from investing activities in the Consolidated Statement of Cash Flows for the year ended December 31, 2021 (Successor).
2020 liquidations. In June 2020, following a decrease in crude oil commodity prices and the related increase in the fair value of derivative assets, the Company liquidated a portion of its crude oil three-way costless collar contracts prior to the expiration of their contractual maturities, resulting in cash proceeds of $25.3 million, which are reflected as investing activities in the Company’s Consolidated Statement of Cash Flows during the Predecessor period from January 1, 2020 through November 19, 2020.
On September 15, 2020, the Company entered into a Direction Letter and Specified Swap Liquidation Agreement (the “Letter Agreement”), which, among other things, amended its Predecessor Credit Facility. Pursuant to the Letter Agreement, beginning on September 15, 2020 and ending on the earlier of (1) October 15, 2020 and (2) the occurrence of an event of default under the Predecessor Credit Facility, the Company was required to use commercially reasonable efforts with respect to each of its swap agreements, to either (x) terminate such swap agreement or (y) reset such swap agreement to current market terms in existence at the time of such reset in exchange for a lump-sum cash payment substantially similar to the payment it would have received in respect of a termination of such swap agreement (each a “Specified Swap Liquidation”). The Letter Agreement also contained an agreement by the Company to apply the proceeds of any such Specified Swap Liquidation to prepayment of its loans under the Predecessor Credit Facility. Each Specified Swap Liquidation reduced the borrowing base and the aggregate elected commitment amounts under the Predecessor Credit Facility by an amount equal to any prepayment of the loans using the proceeds of such Specified Swap Liquidation (see Note 14—Long-Term Debt). During the period from September 15, 2020 through the Petition Date of the Chapter 11 Cases, which constituted an event of default under the Predecessor Credit Facility, the Company liquidated its outstanding swap agreements and received cash proceeds of $37.4 million for Specified Swap Liquidations, which are reflected as investing activities in the Company’s Consolidated Statement of Cash Flows during the Predecessor period from January 1, 2020 through November 19, 2020.
Minimum hedging requirements. In order to secure exit financing upon emerging from the Chapter 11 Cases, the Oasis Credit Facility included certain conditions that were required before closing, including minimum hedge volumes and prices. OPNA, as borrower, was required to enter into hedges covering minimum hedge volumes of (i) 10,303 MBbl for the first year after the closing date, (ii) 6,761 MBbl for the second year after the closing date and (iii) 4,945 MBbl for the third year after the closing date; provided that, two-thirds of such hedging shall be entered into on the closing date of the Oasis Credit Facility, with the remainder to be entered into 30 days after the closing date. The target pricing for the hedges shall not be less than (i) $43.04 per barrel for the first year after the closing date, (ii) $43.94 per barrel for the second year after the closing date and (iii) $44.79 per barrel for the third year after the closing date. On December 22, 2021, the Company entered into the Sixth Amendment to Credit Agreement to, among other things, remove the minimum hedging requirements under the Oasis Credit Facility.
At December 31, 2021, the Company had the following outstanding commodity derivative instruments: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Commodity | | Settlement Period | | Derivative Instrument | | | | Volumes | | Weighted Average Prices | | Fair Value Assets (Liabilities) |
| | | | | Fixed Price Swaps | | | | Floor | | Ceiling | |
| | | | | | | | | | | | | (In thousands) |
Crude oil | | 2021 | | Two-way collar | | | | 248,000 | | Bbl | | | | | | $ | 51.25 | | | $ | 68.24 | | | $ | (855) | |
Crude oil | | 2021 | | Fixed price swaps | | | | 899,000 | | Bbl | | $ | 42.09 | | | | | | | | | (26,606) | |
Crude oil | | 2022 | | Two-way collar | | | | 4,551,000 | | Bbl | | | | | | $ | 49.40 | | | $ | 66.53 | | | (41,719) | |
Crude oil | | 2022 | | Fixed price swaps | | | | 6,346,000 | | Bbl | | $ | 70.00 | | | | | | | | | (15,753) | |
Crude oil | | 2023 | | Two-way collar | | | | 4,380,000 | | Bbl | | | | | | $ | 45.42 | | | $ | 65.05 | | | (33,415) | |
Crude oil | | 2023 | | Fixed price swaps | | | | 5,265,000 | | Bbl | | $ | 52.24 | | | | | | | | | (73,650) | |
Crude oil | | 2024 | | Two-way collar | | | | 372,000 | | Bbl | | | | | | $ | 45.00 | | | $ | 64.88 | | | (2,269) | |
Crude oil | | 2024 | | Fixed price swaps | | | | 434,000 | | Bbl | | $ | 50.00 | | | | | | | | | (5,892) | |
Natural gas | | 2021 | | Fixed price swaps | | | | 930,000 | | MMBtu | | $ | 2.82 | | | | | | | | | (1,121) | |
Natural gas | | 2022 | | Fixed price swaps | | | | 4,500,000 | | MMBtu | | $ | 2.82 | | | | | | | | | (3,394) | |
| | | | | | | | | | | | | | | | | | | $ | (204,674) | |
Permian Basin Sale Contingent Consideration. Pursuant to the Primary Permian Basin Sale PSA (defined in Note 13 – Acquisitions and Divestitures), the Company is entitled to receive up to three earn-out payments of $25.0 million per year for each of 2023, 2024 and 2025 if the average daily settlement price of NYMEX WTI crude oil exceeds $60 per barrel for such year (the “Permian Basin Sale Contingent Consideration”). If the NYMEX WTI crude oil price for calendar year 2023 or 2024 is less than $45 per barrel, then each calendar year thereafter the buyer’s obligation to make any remaining earn-out payments is terminated. The Company determined that the Permian Basin Sale Contingent Consideration was an embedded derivative in accordance with the FASB ASC 815, Derivatives and Hedging. The Company bifurcated the Permian Basin Sale Contingent Consideration from the host contract and accounted for it separately at fair value. The fair value of the Permian Basin Sale Contingent Consideration was estimated to be $32.9 million as of the close date on June 29, 2021. The Permian Basin Sale Contingent Consideration is marked-to-market each reporting period, with changes in fair value recorded to net gain (loss) on derivative instruments on the Consolidated Statements of Operations. As of December 31, 2021, the estimated fair value of the Permian Basin Sale Contingent Consideration was $44.8 million, which was classified as a non-current derivative asset on the Consolidated Balance Sheet.
The following table summarizes the location and amounts of gains and losses from the Company’s commodity derivative instruments recorded in the Company’s Consolidated Statements of Operations for the periods presented (in thousands): | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Successor | | | Predecessor |
| | | | Year Ended December 31, 2021 | | Period from November 20, 2020 through December 31, 2020 | | | Period from January 1, 2020 through November 19, 2020 | | Year Ended December 31, 2019 |
Derivative Instrument | | Statement of Operations Location | | | | | |
| | | | | | | | | | | |
Commodity derivative instrument | | Net gain (loss) on derivative instruments | | $ | (601,591) | | | $ | (84,615) | | | | $ | 233,565 | | | $ | (106,314) | |
Contingent consideration | | Net gain (loss) on derivative instruments | | 11,950 | | | — | | | | — | | | — | |
Contingent consideration | | Gain on sale of properties | | 32,860 | | | — | | | | — | | | — | |
In accordance with the FASB’s authoritative guidance on disclosures about offsetting assets and liabilities, the Company is required to disclose both gross and net information about instruments and transactions eligible for offset in the statement of financial position as well as instruments and transactions subject to an agreement similar to a master netting agreement. The Company’s derivative instruments are presented as assets and liabilities on a net basis by counterparty, as all counterparty contracts provide for net settlement. No margin or collateral balances are deposited with counterparties, and as such, gross amounts are offset to determine the net amounts presented in the Company’s Consolidated Balance Sheets.
The following tables summarize the location and fair value of all outstanding commodity derivative instruments recorded in the Company’s Consolidated Balance Sheets: | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | |
| | | | December 31, 2021 |
Derivative Instrument | | Balance Sheet Location | | Gross Recognized Assets/Liabilities | | Gross Amount Offset | | Net Recognized Fair Value Assets/Liabilities |
| | | | | | | | |
| | | | (In thousands) |
Derivatives assets: | | | | | | | | |
| | | | | | | | |
Contingent consideration | | Derivative instruments — non-current assets | | $ | 44,810 | | | $ | — | | | $ | 44,810 | |
Commodity contracts | | Derivative instruments — non-current assets | | 55 | | | — | | | 55 | |
Total derivatives assets | | | | $ | 44,865 | | | $ | — | | | $ | 44,865 | |
Derivatives liabilities: | | | | | | | | |
Commodity contracts | | Derivative instruments — current liabilities | | $ | 96,172 | | | $ | (6,725) | | | $ | 89,447 | |
Commodity contracts | | Derivative instruments — non-current liabilities | | 133,655 | | | (18,373) | | | 115,282 | |
Total derivatives liabilities | | $ | 229,827 | | | $ | (25,098) | | | $ | 204,729 | |
| | | | | | | | |
| | | | |
| | | | December 31, 2020 |
Derivative Instrument | | Balance Sheet Location | | Gross Recognized Assets/Liabilities | | Gross Amount Offset | | Net Recognized Fair Value Assets/Liabilities |
| | | | | | | | |
| | | | (In thousands) |
Derivatives assets: | | | | | | | | |
Commodity contracts | | Derivative instruments — current assets | | $ | 467 | | | $ | — | | | $ | 467 | |
Commodity contracts | | Derivative instruments — non-current assets | | — | | | — | | | — | |
Total derivatives assets | | | | $ | 467 | | | $ | — | | | $ | 467 | |
Derivatives liabilities: | | | | | | | | |
Commodity contracts | | Derivative instruments — current liabilities | | $ | 59,262 | | | $ | (2,318) | | | $ | 56,944 | |
Commodity contracts | | Derivative instruments — non-current liabilities | | 38,426 | | | (812) | | | 37,614 | |
Total derivatives liabilities | | $ | 97,688 | | | $ | (3,130) | | | $ | 94,558 | |
12. Property, Plant and Equipment
The following table sets forth the Company’s property, plant and equipment: | | | | | | | | | | | |
| December 31, |
| 2021 | | 2020 |
| | | |
| (In thousands) |
Proved oil and gas properties | $ | 1,393,836 | | | $ | 770,393 | |
Less: Accumulated depreciation, depletion, amortization and impairment | (107,277) | | | (12,403) | |
Proved oil and gas properties, net | 1,286,559 | | | 757,990 | |
Unproved oil and gas properties | 2,001 | | | 40,211 | |
Other property and equipment | 48,981 | | | 51,505 | |
Less: Accumulated depreciation and impairment | (17,109) | | | (1,881) | |
Other property and equipment, net | 31,872 | | | 49,624 | |
Total property, plant and equipment, net | $ | 1,320,432 | | | $ | 847,825 | |
Impairment
The Company reviews its property, plant and equipment for impairment by asset group whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. If events occur that indicate an asset group may not be recoverable, the asset group is tested for recoverability. The Company determined no impairment indicators existed for its asset groups as of December 31, 2021 or December 31, 2020.
Proved oil and gas properties. The Company estimates the expected undiscounted future cash flows of its proved oil and gas properties by field and then compares such amount to the carrying amount of the proved oil and gas properties in the applicable field to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company adjusts the carrying amount of the proved oil and gas properties to fair value. The factors used to determine fair value are subject to management’s judgment and expertise and include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows net of estimated operating and development costs using estimates of proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows projected. These assumptions represent Level 3 inputs, as further discussed under Note 10—Fair Value Measurements.
In the first quarter of 2020, as a result of the significant decline in expected future commodity prices coupled with the Company’s liquidity concerns, and the resulting decrease in its estimated proved reserves, the Company reviewed its proved oil and gas properties in both the Williston Basin and the Permian Basin for impairment. During the period from January 1, 2020 through November 19, 2020 (Predecessor), the Company recorded impairment charges of $4.4 billion, including $3.8 billion related to the Williston Basin and $637.3 million related to the Permian Basin, to reduce the carrying values of its proved oil and gas properties to their estimated fair values. For the year ended December 31, 2021 (Successor), the period from November 20, 2020 through December 31, 2020 (Successor) and the year ended December 31, 2019 (Predecessor), the Company did not record impairment of proved oil and gas properties.
Unproved oil and gas properties. The Company assessed its unproved oil and gas properties for impairment and recorded impairment charges on its unproved oil and gas properties of $401.1 million for the period from January 1, 2020 through November 19, 2020 (Predecessor), and $5.4 million for the year ended December 31, 2019 (Predecessor) as a result of expiring leases, periodic assessments and drilling plan uncertainty on certain acreage of unproved properties. For the year ended December 31, 2021 (Successor) and the period from November 20, 2020 through December 31, 2020 (Successor), the Company did not record impairment of unproved oil and gas properties.
Other property and equipment. The Company reviews its other property and equipment for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. Due to the significant decline in expected future commodity prices during the first quarter of 2020, the Company and other crude oil and natural gas producers changed their development plans, which resulted in lower forecasted throughput volumes for the Company’s midstream assets. As a result, the Company reviewed its midstream assets, grouped by commodity for each basin, for impairment as of March 31, 2020. The carrying amounts exceeded the estimated undiscounted future cash flows for certain midstream asset groups in the Williston Basin and the Permian Basin, and as a result, the Company recorded impairment charges of $108.3 million during the period from January 1, 2020 through November 19, 2020 (Predecessor) to reduce the carrying values of these midstream assets to their estimated fair values. In addition, during the period from January 1, 2020 through November 19, 2020 (Predecessor), the Company recorded impairment charge of $1.6 million on certain midstream equipment, including a right-of-use asset associated with mechanical refrigeration units leased at the Company’s natural gas
processing complex in the Williston Basin. These amounts were recorded as a component of income from discontinued operations, net of income tax in the Company’s Consolidated Statements of Operations. No impairment charges were recorded on the Company’s midstream assets for the years ended December 31, 2021 (Successor) or December 31, 2019 (Predecessor).
13. Acquisitions and Divestitures
Acquisitions
Williston Basin Acquisition. On October 21, 2021, the Company completed the acquisition of approximately 95,000 net acres in the Williston Basin, effective April 1, 2021, from QEP Energy Company (“QEP”), a wholly-owned subsidiary of Diamondback Energy Inc., for total cash consideration of $585.8 million (the “Williston Basin Acquisition”). The Company paid a deposit to QEP of $74.5 million on May 3, 2021 and $511.3 million at closing on October 21, 2021. The Company funded the Williston Basin Acquisition with cash on hand, including proceeds from the Permian Basin Sale (defined below) and the Oasis Senior Notes (defined in Note 14 – Long-Term Debt).
The Williston Basin Acquisition was accounted for as an asset acquisition under FASB ASC 805, Business Combinations (“ASC 805”), since substantially all of the fair value of the assets acquired related to proved oil and gas properties. The Company applied the cost accumulation model under ASC 805, and as such, recognized the assets acquired in the Williston Basin Acquisition at cost, including transaction costs, on a relative fair value basis. There were no material deferred income taxes from the Williston Basin Acquisition, as the tax basis of the assets acquired and liabilities assumed was equal to the book basis at closing.
Divestitures
Permian Basin Sale. On May 20, 2021, Oasis Petroleum Permian LLC (“OP Permian”), a wholly-owned subsidiary of the Company, entered into a purchase and sale agreement (the “Primary Permian Basin Sale PSA”) with Percussion Petroleum Operating II, LLC (“Percussion”). Pursuant to the Primary Permian Basin Sale PSA, OP Permian agreed to sell to Percussion its remaining upstream assets in the Texas region of the Permian Basin with an effective date of March 1, 2021, for an aggregate purchase price of $450.0 million (the “Primary Permian Basin Sale”). The aggregate purchase price consists of $375.0 million cash at closing and up to three earn-out payments of $25.0 million per year for each of 2023, 2024 and 2025 if the average daily settlement price of NYMEX WTI crude oil exceeds $60.00 per barrel for such year. The Company determined the Permian Basin Sale Contingent Consideration was an embedded derivative. See Note 11—Derivative Instruments.
On June 29, 2021, the Company completed the Primary Permian Basin Sale and received cash proceeds of $342.3 million. In addition to the Primary Permian Basin Sale, the Company divested certain wellbore interests in the Texas region of the Permian Basin to separate buyers in the second quarter of 2021 and received cash proceeds of $30.0 million (the “Additional Permian Basin Sale” and together with the Primary Permian Basin Sale, the “Permian Basin Sale”).
During the year ended December 31, 2021 (Successor), the Company recorded income before income taxes related to the Permian Basin Sale assets of $262.5 million, which included a gain on sale of properties of $221.6 million. During the period from January 1, 2020 through November 19, 2020 (Predecessor), the Company recorded a loss before income taxes related to the Permian Basin Sale assets of $1,105.8 million, and during the period from November 20, 2020 through December 31, 2020 (Successor), the Company recorded income before income taxes related to the Permian Basin Sale assets of $7.3 million. During the year ended December 31, 2019 (Predecessor), the Company recorded income before income taxes related to the Permian Basin Sale assets of $23.3 million.
The Company accounted for revenues and expenses related to the Permian Basin Sale assets as income from continuing operations in the Consolidated Statements of Operations because the Permian Basin Sale did not cause a strategic shift for the Company and as a result, did not qualify as discontinued operations under ASC 205-20. The Permian Basin Sale assets were in the Company’s E&P segment.
Other. On March 22, 2021, the Company completed the sale of certain well services equipment and inventory in connection with its 2020 exit from the well services business for total consideration of $5.5 million, comprised of cash proceeds of $2.6 million and a $2.9 million 6.6% promissory note due within one year, which is included in other current assets in the Consolidated Balance Sheet.
The Predecessor sold certain oil and gas properties through various transactions and recognized a net gain on sale of properties of $11.1 million and a net loss on sale of properties of $0.4 million during the period from January 1, 2020 through November 19, 2020 and the year ended December 31, 2019, respectively.
14. Long-Term Debt
The Company’s long-term debt consists of the following:
| | | | | | | | | | | |
| December 31, |
| 2021 | | 2020 |
| | | |
| (In thousands) |
Oasis Credit Facility | $ | — | | | $ | 260,000 | |
Oasis Senior Notes | 400,000 | | | — | |
Less: unamortized deferred financing costs on Oasis Senior Notes | (7,476) | | | — | |
Total long-term debt, net | $ | 392,524 | | | $ | 260,000 | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
The carrying amount of the Company’s long-term debt reported in the Consolidated Balance Sheets at December 31, 2021 is $392.5 million, which includes $400.0 million of senior unsecured notes and no borrowings under the Oasis Credit Facility. The fair value of the Oasis Senior Notes, which are publicly traded among qualified institutional investors and represent a Level 1 fair value measurement, was $419.0 million at December 31, 2021. The Oasis Credit Facility matures in 2024 and the Oasis Senior Notes mature in 2026. The Company does not have any other debt maturities within the five years ending December 31, 2026.
Oasis Credit Facility
The Company has the Oasis Credit Facility, which has a maturity date of May 19, 2024. As of December 31, 2021, the Oasis Credit Facility has an overall senior secured line of credit of $1,500.0 million, a borrowing base of $900.0 million and an aggregate amount of elected commitments of $450.0 million. The Oasis Credit Facility is restricted to a borrowing base, which is reserve-based and subject to semi-annual redeterminations on April 1 and October 1 of each year, with one interim “wildcard” redetermination available to each of the Company and the administrative agent between scheduled redeterminations during any 12-month period. The next scheduled redetermination will be on or around April 1, 2022.
A portion of the Oasis Credit Facility, in an aggregate amount not to exceed $100.0 million, may be used for the issuance of letters of credit. Additionally, the Oasis Credit Facility provides the ability for the Company to request swingline loans subject to a swingline loans sublimit of $50.0 million.
Borrowings under the Oasis Credit Facility are collateralized by perfected first priority liens and security interests on substantially all of the Credit Parties’ assets, including mortgage liens on oil and gas properties having at least 90% of the reserve value as determined by reserve reports.
Borrowings under the Oasis Credit Facility are subject to varying rates of interest based on (i) the total outstanding borrowings (including the value of all outstanding letters of credit) in relation to the borrowing base and (ii) whether the loan is a LIBOR loan (defined in the Oasis Credit Facility as a Eurodollar loan) or a domestic bank prime interest rate loan (defined in the Oasis Credit Facility as an Alternate Based Rate or “ABR” loan). As of December 31, 2021, any outstanding Eurodollar and ABR loans would have borne their respective interest rates plus the applicable margin indicated in the following table:
| | | | | | | | | | | |
Total Commitment Utilization Percentage | Applicable Margin for Eurodollar Loans | | Applicable Margin for ABR Loans |
Less than 25% | 3.00 | % | | 2.00 | % |
Greater than or equal to 25% but less than 50% | 3.25 | % | | 2.25 | % |
Greater than or equal to 50% but less than 75% | 3.50 | % | | 2.50 | % |
Greater than or equal to 75% but less than 90% | 3.75 | % | | 2.75 | % |
Greater than or equal to 90% | 4.00 | % | | 3.00 | % |
A loan may be repaid at any time before the scheduled maturity of the Oasis Credit Facility upon the Company providing advance notification to the lenders. Interest is paid quarterly on ABR loans based on the number of days an ABR loan is outstanding as of the last business day in March, June, September and December. The Company has the option to convert an ABR loan to a Eurodollar loan upon providing advance notification to the lenders. The minimum available loan term is one month and the maximum available loan term is six months for Eurodollar loans (or 12 months with the consent of each leader). Interest for Eurodollar loan is paid at the end of the applicable interest period for each loan or every three months for Eurodollar loans that have loan terms greater than three months. At the end of a Eurodollar loan term, the Oasis Credit Facility allows the Company to elect to repay the borrowing, continue a Eurodollar loan with the same or differing loan term or convert the borrowing to an ABR loan.
On a quarterly basis, the Company also pays a commitment fee of 0.5% on the average amount of borrowing base capacity not utilized during the quarter and fees calculated on the average amount of letter of credit balances outstanding during the quarter. Solely for purposes of calculating the commitment fee, swingline loans will not be deemed to be a utilization of the Company’s commitments.
The Oasis Credit Facility contains customary affirmative and negative covenants, including, among other things, as to compliance with laws (including environmental laws and anti-corruption laws), delivery of quarterly and annual financial statements, conduct of business, maintenance of property, maintenance of insurance, restrictions on the incurrence of liens, indebtedness, investments, asset dispositions, fundamental changes, restricted payments, transactions with affiliates, and other customary covenants.
The financial covenants in the Oasis Credit Facility include:
•a requirement that the Company maintain a Ratio of Total Net Debt to EBITDAX (as defined in the Oasis Credit Facility, the “Leverage Ratio”) of less than 3.00 to 1.00 as of the last day of any fiscal quarter; and
•a requirement that the Company maintain a Current Ratio (as defined in the Oasis Credit Facility) of no less than 1.0 to 1.0 as of the last day of any fiscal quarter.
The Oasis Credit Facility contains customary events of default, as well as cross-default provisions with other indebtedness of OPNA and the restricted subsidiaries under the Oasis Credit Facility. If an event of default occurs and is continuing, the lenders may declare all amounts outstanding under the Oasis Credit Facility to be immediately due and payable.
At December 31, 2021, the Company had no borrowings outstanding and $2.4 million of outstanding letters of credit issued under the Oasis Credit Facility, resulting in an unused borrowing capacity of $447.6 million. At December 31, 2020, the Company had $260.0 million of borrowings outstanding and $6.8 million of outstanding letters of credit issued under the Oasis Credit Facility. For the year ended December 31, 2021 (Successor), the weighted average interest rate incurred on borrowings under the Oasis Credit Facility was 4.2%, compared to 3.6% for the period from January 1, 2020 through November 19, 2020 (Predecessor) and 4.6% for the period from November 20, 2020 through December 31, 2020 (Successor). The Company was in compliance with the financial covenants under the Oasis Credit Facility at December 31, 2021.
Oasis Senior Notes
On June 9, 2021, the Company issued in a private placement $400.0 million of 6.375% senior unsecured notes due June 1, 2026 (the “Oasis Senior Notes”). The Oasis Senior Notes were issued at par and resulted in net proceeds of $391.6 million, after deducting the underwriters’ discounts, commissions and other expenses. The proceeds were used to fund a portion of the consideration for the Williston Basin Acquisition (see Note 13 – Acquisitions and Divestitures).
In connection with the issuance of the Oasis Senior Notes, the Company recorded deferred financing costs of $8.4 million, which are being amortized over the term of the notes.
Interest on the Oasis Senior Notes is payable semi-annually on June 1 and December 1 of each year. The Oasis Senior Notes are guaranteed on a senior unsecured basis by the Company, along with its wholly-owned subsidiaries (the “Oasis Guarantors”). These guarantees are full and unconditional and joint and several among the Oasis Guarantors, subject to certain customary release provisions. The indentures governing the Oasis Senior Notes contain customary events of default. In addition, the indenture governing the Oasis Senior Notes contains cross-default provisions with other indebtedness of Oasis and its restricted subsidiaries.
The indentures governing the Oasis Senior Notes restrict the Company’s ability and the ability of certain of its subsidiaries to, among other things: (i) make investments; (ii) incur additional indebtedness or issue preferred stock; (iii) create liens; (iv) sell assets; (v) enter into agreements that restrict dividends or other payments by restricted subsidiaries; (vi) consolidate, merge or transfer all or substantially all of the Company’s assets with another company; (vii) enter into transactions with affiliates; (viii) pay dividends or make other distributions on capital stock or prepay subordinated indebtedness; and (ix) create unrestricted subsidiaries. These covenants are subject to a number of important exceptions and qualifications. If at any time when the Oasis Senior Notes are rated investment grade by two out of the three rating agencies and no default (as defined in the indentures) has occurred and is continuing, many of such covenants will terminate and the Company will cease to be subject to such covenants. The Company was in compliance with the terms of the indentures for the Oasis Senior Notes as of December 31, 2021.
Oasis Bridge Facility
On May 3, 2021, the Company entered into a commitment letter to provide for a senior secured second lien facility and incurred a fee of $7.8 million, which was recorded to interest expense on the Company’s Consolidated Statement of Operations for the year ended December 31, 2021. The senior secured second lien facility was terminated prior to being drawn.
OMP Debt
OMP’s long-term debt consisted of the OMP Credit Facility and OMP Senior Notes (each defined below). The Company classified OMP’s long-term debt as held for sale in the Consolidated Balance Sheets at December 31, 2021 and 2020. See Note 6—Discontinued Operations.
OMP Credit Facility. OMP had a senior secured revolving credit facility (the “OMP Credit Facility”). At December 31, 2021, there were $203.0 million of borrowings outstanding and $5.5 million of outstanding letters of credit issued under the OMP Credit Facility. At December 31, 2020, there were $450.0 million of borrowings outstanding and no outstanding letters of credit issued under the OMP Credit Facility. OMP was in compliance with the financial covenants under the OMP Credit Facility at December 31, 2021. The OMP Credit Facility was paid in full by Crestwood in connection with the closing of the OMP Merger.
OMP Senior Notes. On March 30, 2021, OMP issued in a private placement $450.0 million of 8.00% senior unsecured notes due April 1, 2029 (the “OMP Senior Notes”). The OMP Senior Notes were issued at par and resulted in net proceeds of $440.1 million. Interest on the OMP Senior Notes is payable semi-annually on April 1 and October 1 of each year. The OMP Senior Notes were assumed by Crestwood in connection with the closing of the OMP Merger.
15. Asset Retirement Obligations
The following table reflects the changes in the Company’s ARO (in thousands): | | | | | |
| |
Asset retirement obligation as of December 31, 2019 (Predecessor) | $ | 54,909 | |
Liabilities incurred during period | 535 | |
Liabilities settled during period | (196) | |
Accretion expense during period | 2,696 | |
Fresh start adjustment(1) | (10,552) | |
Asset retirement obligation as of November 19, 2020 (Predecessor) | $ | 47,392 | |
| |
| |
Asset retirement obligation as of November 20, 2020 (Successor) | $ | 47,392 | |
Liabilities incurred during period | 35 | |
Accretion expense during period | 336 | |
Asset retirement obligation as of December 31, 2020 (Successor) | $ | 47,763 | |
Liabilities incurred through acquisitions | 14,850 | |
Liabilities incurred during period | 729 | |
Liabilities settled during period(2) | (5,193) | |
Accretion expense during period | 4,068 | |
Revisions to estimates | 199 | |
Asset retirement obligation as of December 31, 2021 (Successor) | $ | 62,416 | |
__________________
(1)Upon emergence from bankruptcy and the adoption of fresh start accounting, ARO liabilities were adjusted to their estimated fair value. Refer to Note 3—Fresh Start Accounting for more information on Fresh Start Adjustments.
(2)Includes $4.9 million related to liabilities settled during the period related to properties sold in the Permian Basin Sale (see Note 13—Acquisitions and Divestitures).
Accretion expense is included in depreciation, depletion and amortization on the Company’s Consolidated Statements of Operations. At December 31, 2021 and 2020, the current portion of the total ARO balance was approximately $4.8 million and $2.2 million, respectively, and is included in accrued liabilities on the Company’s Consolidated Balance Sheets.
16. Income Taxes
The Company’s income tax benefit consists of the following (in thousands): | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Successor | | | Predecessor |
| Year Ended December 31, 2021 | | Period from November 20, 2020 through December 31, 2020 | | | Period from January 1, 2020 through November 19, 2020 | | Year Ended December 31, 2019 |
| | | | |
| | | | | | | | |
| | | | | | |
Current: | | | | | | | | |
Federal | $ | — | | | $ | — | | | | $ | (36) | | | $ | (43) | |
State | 4 | | | — | | | | — | | | 27 | |
| 4 | | | — | | | | (36) | | | (16) | |
Deferred: | | | | | | | | |
Federal | (977) | | | (2,918) | | | | (221,277) | | | (28,148) | |
State | — | | | (529) | | | | (41,649) | | | (4,551) | |
| (977) | | | (3,447) | | | | (262,926) | | | (32,699) | |
Total income tax benefit | $ | (973) | | | $ | (3,447) | | | | $ | (262,962) | | | $ | (32,715) | |
The reconciliation of income taxes calculated at the U.S. federal tax statutory rate to the Company’s effective tax rate is set forth below:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Successor | | | Predecessor |
| Year Ended December 31, | | Period from November 20, 2020 through December 31, 2020 | | | Period from January 1, 2020 through November 19, 2020 | | Year Ended December 31, |
| 2021 | | | | | 2019 |
| | | | | | | | | | | | | | | | |
| (%) | | (In thousands) | | (%) | | (In thousands) | | | (%) | | (In thousands) | | (%) | | (In thousands) |
U.S. federal tax statutory rate | 21.0 | % | | $ | 74,412 | | | 21.0 | % | | $ | (10,376) | | | | 21.0 | % | | $ | (837,391) | | | 21.0 | % | | $ | (25,906) | |
State income taxes, net of federal income tax benefit | 2.6 | % | | 9,161 | | | 2.8 | % | | (1,373) | | | | 2.3 | % | | (93,063) | | | 2.9 | % | | (3,573) | |
Effects of non-controlling interest | (2.1) | % | | (7,496) | | | 1.7 | % | | (830) | | | | (0.4) | % | | 17,699 | | | 6.4 | % | | (7,895) | |
Non-deductible executive compensation | 0.7 | % | | 2,510 | | | — | % | | — | | | | — | % | | 1,372 | | | (1.7) | % | | 2,094 | |
Equity-based compensation windfall (shortfall) | — | % | | — | | | — | % | | — | | | | (0.2) | % | | 8,687 | | | (1.8) | % | | 2,163 | |
| | | | | | | | | | | | | | | | |
Change in valuation allowance | (46.8) | % | | (165,639) | | | (18.1) | % | | 8,936 | | | | (13.9) | % | | 553,580 | | | — | % | | — | |
| | | | | | | | | | | | | | | | |
Discharge of debt and other reorganization items | 24.6 | % | | 87,070 | | | (0.5) | % | | 232 | | | | (2.1) | % | | 85,149 | | | — | % | | — | |
Other | (0.3) | % | | (991) | | | 0.1 | % | | (36) | | | | — | % | | 1,005 | | | (0.3) | % | | 402 | |
Annual effective tax benefit | (0.3) | % | | $ | (973) | | | 7.0 | % | | $ | (3,447) | | | | 6.7 | % | | $ | (262,962) | | | 26.5 | % | | $ | (32,715) | |
Significant components of the Company’s deferred tax assets and liabilities as of December 31, 2021 and 2020, were as follows: | | | | | | | | | | | |
| December 31, |
| 2021 | | 2020 |
| | | |
| (In thousands) |
Deferred tax assets | | | |
Net operating loss carryforward | $ | 51,942 | | | $ | 34,691 | |
Oil and natural gas properties | 237,051 | | | 566,856 | |
Bonus and equity-based compensation | 6,718 | | | 1,732 | |
Derivative instruments | 91,213 | | | 22,248 | |
Investment in partnerships | 12,924 | | | — | |
Other deferred tax assets | 14,843 | | | 7,424 | |
Total deferred tax assets | 414,691 | | | 632,951 | |
Less: Valuation allowance | (399,770) | | | (565,409) | |
Total deferred tax assets, net | $ | 14,921 | | | $ | 67,542 | |
Deferred tax liabilities | | | |
| | | |
| | | |
Investment in partnerships | — | | | 67,210 | |
Other deferred tax liabilities | 14,928 | | | 1,316 | |
Total deferred tax liabilities | $ | 14,928 | | | $ | 68,526 | |
Total deferred tax liabilities, net | $ | 7 | | | $ | 984 | |
As of December 31, 2021, the Company had gross U.S. federal net operating loss carryforwards of $219.8 million and $169.6 million of gross state net operating loss carryforwards, which expire between 2028 and 2041. The tax benefits of carryforwards are recorded as an asset to the extent that management assesses the utilization of such carryforwards to be more likely than not, and when the future utilization of some portion of the carryforwards is determined not to be more likely than not a valuation allowance is provided to reduce the recorded tax benefits from such assets. As of December 31, 2021 and 2020, the Company’s valuation allowance balance was $399.8 million and $565.4 million, respectively. The Company concluded it is more likely than not that some or all of the benefits from its deferred tax assets will not be realized, and as such, recorded a valuation allowance on these assets as of December 31, 2021 and 2020. Management assesses the available positive and negative evidence to estimate whether sufficient future taxable income will be generated to realize the benefit of deferred tax assets. A significant piece of objective negative evidence evaluated is the cumulative loss incurred over recent years. Such objective negative evidence limits the ability to consider other subjective positive evidence. The amount of the deferred tax asset considered realizable could be adjusted if estimates of future taxable income are reduced or increased or if objective negative evidence in the form of cumulative losses is no longer present and additional weight is given to subjective evidence such as future growth. The Company will continue to assess the valuation allowance on an ongoing basis.
Accounting for uncertainty in income taxes prescribes a recognition threshold and measurement methodology for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. As of December 31, 2021 and 2020, the Company had no unrecognized tax benefits. With respect to income taxes, the Company’s policy is to account for interest charges as interest expense and any penalties as tax expense in its Consolidated Statements of Operations. The Company files income tax returns in the U.S. federal jurisdiction and in North Dakota, Montana and Texas. The Company has carried forward NOLs from previous years to utilize in 2021, which will allow the IRS to examine the loss years, the earliest of which is 2010. The federal statute of limitation for the year ended December 31, 2021 will expire in 2025.
Upon emergence from bankruptcy, the Company experienced an “ownership change” as defined by Section 382 of the Internal Revenue Code of 1986, as amended (the “Code”). Under Section 382 of the Code, the Company’s net operating loss carryforwards and other tax attributes (collectively, the “Tax Benefits”) are potentially subject to various limitations going forward. However, the Company believes that it qualified for, and as a result, utilized an exception under Section 382(l)(5) of the Code from the limitation that would otherwise be imposed under Section 382 of the Code. However, if the Company were to experience a subsequent ownership change within the two year period immediately following its emergence from bankruptcy, the Company would be precluded from utilizing any remaining pre-emergence NOLs following such subsequent ownership change. Prior to determining it could utilize the exception under Section 382(l)(5) of the Code, the Company made an estimated U.S. federal income tax payment of $20.0 million during the second quarter of 2021, which the Company expects to be refunded in 2022. This amount is recorded under accounts receivable, net on the Consolidated Balance Sheet at December 31, 2021.
17. Equity-Based Compensation
Successor equity-based compensation
The Company has granted restricted stock awards (“RSAs”), restricted stock units (“RSUs”), performance share units (“PSUs”), leveraged stock units (“LSUs”) and phantom unit awards under the 2020 LTIP. In accordance with the FASB’s authoritative guidance for share-based payments, the RSAs, RSUs, PSUs and LSUs are accounted for as equity classified awards, and the phantom unit awards are accounted for as liability classified awards.
Equity-based compensation expense from continuing operations is recognized in general and administrative expenses on the Company’s Consolidated Statements of Operations, and equity-based compensation expense from discontinued operations is recognized on the Company’s Consolidated Statements of Operations in discontinued operations, net of income tax. During the year ended December 31, 2021 (Successor), the Company recognized $14.7 million in stock-based compensation expense related to equity classified awards and $0.5 million related to liability classified awards that were attributable to continuing operations. The Company recognized $0.8 million in stock-based compensation expense related to equity classified awards that was attributable to discontinued operations during the year ended December 31, 2021 (Successor). Stock-based compensation expenses were not material for both continuing operations and discontinued operations during the period from November 20, 2020 through December 31, 2020 (Successor).
Restricted stock awards. RSAs are legally issued shares which vest over a three-year period subject to a service condition. The fair value of RSAs is based on the closing sales price of the Company’s common stock on the date of grant or, if applicable, the date of modification. Compensation expense is recognized ratably over the requisite service period.
The following table summarizes information related to RSAs held by non-employee directors of the Company: | | | | | | | | | | | |
| Shares | | Weighted Average Grant Date Fair Value per Share |
Non-vested shares outstanding December 31, 2020 | 93,000 | | | $ | 37.35 | |
Granted | 2,916 | | | 126.89 | |
Vested | (30,996) | | | 37.35 | |
Forfeited | — | | | — | |
Non-vested shares outstanding December 31, 2021 | 64,920 | | | $ | 41.37 | |
| | | |
The fair value of awards vested was $4.0 million for the year ended December 31, 2021 (Successor). Unrecognized expense as of December 31, 2021 for all outstanding RSAs was $2.7 million and will be recognized over a weighted average period of approximately 1.8 years.
Restricted stock units. RSUs are contingent shares that are scheduled to vest 25% each year over a four-year period. The fair value is based on the closing price of the Company’s common stock on the date of grant or, if applicable, the date of modification. Compensation expense is recognized ratably over the requisite service period.
The following table summarizes information related to RSUs held by employees of the Company: | | | | | | | | | | | |
| Shares | | Weighted Average Grant Date Fair Value per Share |
Non-vested shares outstanding December 31, 2020 | — | | | $ | — | |
Granted | 518,375 | | | 62.61 | |
Vested | (69) | | | 127.91 | |
Forfeited | (5,500) | | | 56.86 | |
Non-vested shares outstanding December 31, 2021 | 512,806 | | | $ | 62.66 | |
The fair value of awards vested was immaterial for the year ended December 31, 2021 (Successor). The weighted average grant date fair value of RSUs was $62.61 per share for the year ended December 31, 2021 (Successor). Unrecognized expense as of December 31, 2021 for all outstanding RSUs was $26.9 million and will be recognized over a weighted average period of approximately 3.1 years.
Performance share units. PSUs are contingent shares that may be earned over three-year and four-year performance periods. The number of PSUs to be earned is subject to a market condition, which is based on a comparison of the total shareholder return (“TSR”) achieved with respect to shares of the Company’s common stock against the TSR achieved by a defined peer group at the end of the applicable performance periods, with 50% of the PSU awards eligible to be earned based on performance relative to a certain group of the Company’s oil and gas peers and 50% of the PSU awards eligible to be earned
based on performance relative to the broad-based Russell 2000 index. Depending on the Company’s TSR performance relative to the defined peer group, award recipients may earn between 0% and 150% of target.
The following table summarizes information related to PSUs held by employees of the Company: | | | | | | | | | | | |
| Shares | | Weighted Average Grant Date Fair Value per Share |
Non-vested shares outstanding December 31, 2020 | — | | | $ | — | |
Granted | 183,915 | | | 63.95 | |
Vested | — | | | — | |
Forfeited | — | | | — | |
Non-vested shares outstanding December 31, 2021 | 183,915 | | | $ | 63.95 | |
No awards vested for the year ended December 31, 2021 (Successor). The weighted average grant date fair value was $63.95 per share for the year ended December 31, 2021 (Successor). Unrecognized expense as of December 31, 2021 for all outstanding PSUs was $8.8 million and will be recognized over a weighted average period of approximately 2.7 years.
Leveraged stock units. LSUs are contingent shares that may be earned over a three-year or four-year performance period. The number of LSUs to be earned is subject to a market condition, which is based on the TSR performance of the Company’s common stock measured against specific premium return objectives. Depending on the Company’s TSR performance, award recipients may earn between 0% and 300% of target; however, the number of shares delivered in respect to these awards during the grant cycle may not exceed ten times the fair value of the award on the grant date.
The following table summarizes information related to LSUs held by employees of the Company: | | | | | | | | | | | |
| Shares | | Weighted Average Grant Date Fair Value per Share |
Non-vested shares outstanding December 31, 2020 | — | | | $ | — | |
Granted | 262,406 | | | 78.79 | |
Vested | — | | | — | |
Forfeited | — | | | — | |
Non-vested shares outstanding December 31, 2021 | 262,406 | | | $ | 78.79 | |
No awards vested for the year ended December 31, 2021 (Successor). The weighted average grant date fair value was $78.79 per share for the year ended December 31, 2021 (Successor). Unrecognized expense as of December 31, 2021 for all outstanding LSUs was $15.4 million and will be recognized over a weighted average period of approximately 2.6 years.
Fair value assumptions. The aggregate grant date fair value of PSUs and LSUs was determined by a third-party valuation specialist using a Monte Carlo simulation model. The key valuation inputs were: (i) the forecast period, (ii) risk-free interest rate, (iii) implied equity volatility, (iv) stock price on the date of grant and, for PSUs, (v) correlation coefficient. The risk-free interest rates are the U.S. Treasury bond rates on the date of grant that correspond to each performance period. Implied equity volatility is derived by solving for an asset volatility and equity volatility based on the leverage of the Company and each of its peers. For the PSUs, the correlation coefficient measures the strength of the linear relationship between and amongst the Company and its peers based on historical stock price data.
The following table summarizes the assumptions used in the Monte Carlo simulation model to determine the grant date fair value and associated equity-based compensation expenses by grant date:
| | | | | | | | | | | | | | | | | |
Grant date | January 18, 2021 | | February 11, 2021 | | April 13, 2021 |
Forecast period (years) | 3 - 4 | | 3 - 4 | | 3 - 4 |
Risk-free interest rates | 0.2% - 0.3% | | 0.2% - 0.3% | | 0.3% - 0.6% |
Implied equity volatility | 55% - 60% | | 55% - 60% | | 45% - 50% |
| | | | | |
Stock price on date of grant | $44.41 | | $49.66 | | $68.07 |
Phantom unit awards. Phantom unit awards represent the right to receive, upon vesting of the award, a cash payment equal to the fair market value of one share of common stock. The phantom unit awards generally vest in equal installments each year over a three-year period from the date of grant, and compensation expense is recognized over the requisite service period.
The following table summarizes information related to phantom unit awards held by employees of the Company:
| | | | | | | | | | | |
| Phantom Unit Awards | | Weighted Average Grant Date Fair Value per Share |
Non-vested phantom unit awards outstanding December 31, 2020 | — | | | $ | — | |
Granted | 16,422 | | | 127.91 | |
Vested | (38) | | | 127.91 | |
Forfeited | (604) | | | 127.91 | |
Non-vested phantom unit awards outstanding December 31, 2021 | 15,780 | | | $ | 127.91 | |
The fair value of vested phantom unit awards was immaterial for the year ended December 31, 2021 (Successor). Unrecognized expense as of December 31, 2021 for outstanding phantom unit awards was $1.9 million and will be recognized over a weighted average period of approximately 2.9 years.
Predecessor equity-based compensation
The Predecessor granted equity awards to its officers, employees and directors under the Amended and Restated 2010 Long Term Incentive Plan (the “2010 LTIP”).
During the period from January 1, 2020 through November 19, 2020 (Predecessor) for continuing operations, the Company recognized $29.8 million in stock-based compensation expense related to equity classified awards and $1.2 million related to liability classified awards. During the period from January 1, 2020 through November 19, 2020 (Predecessor) for discontinued operations, the Company recognized $1.5 million in stock-based compensation expense related to equity classified awards and $0.2 million related to liability classified awards. During the year ended December 31, 2019 (Predecessor) for continuing operations, the Company recognized $32.8 million in stock-based compensation expense related to equity classified awards and $2.4 million related to liability classified awards. During the year ended December 31, 2019 (Predecessor) for discontinued operations, the Company recognized $0.9 million in stock-based compensation expense related to equity classified awards and $0.1 million related to liability classified awards.
Restricted stock awards. The Company granted restricted stock awards to its employees and directors under the 2010 LTIP, the majority of which vest over a three-year period. The fair value of restricted stock grants was based on the closing sales price of the Company’s common stock on the date of grant or, if applicable, the date of modification. Compensation expense was recognized ratably over the requisite service period.
The fair value of awards vested was $47.3 million for the period from January 1, 2020 through November 19, 2020 (Predecessor), and $14.6 million for the year ended December 31, 2019 (Predecessor). The weighted average grant date fair value of restricted stock awards granted was $3.06 per share for the period from January 1, 2020 through November 19, 2020 (Predecessor), and $6.61 per share for the year ended December 31, 2019 (Predecessor).
Performance share units. The Company granted PSUs to its officers under the 2010 LTIP. The PSUs are awards of restricted stock units that may be earned based on the level of achievement with respect to the applicable performance metric, and each PSU that is earned represents the right to receive one share of the Company’s common stock.
The Company accounted for the PSUs as equity awards pursuant to the FASB’s authoritative guidance for share-based payments. The number of PSUs to be earned is subject to a market condition, which is based on a comparison of the TSR achieved with respect to shares of the Company’s common stock against the TSR achieved by a defined peer group at the end of the performance periods. Depending on the Company’s TSR performance relative to the defined peer group, award recipients will earn between 0% and 240% of the initial PSUs granted. All compensation expense related to the PSUs will be recognized if the requisite performance period is fulfilled, even if the market condition is not achieved.
The fair value of PSUs vested was $7.6 million for the period from January 1, 2020 through November 19, 2020 (Predecessor) and $2.6 million for the year ended December 31, 2019 (Predecessor). The weighted average grant date fair value of PSUs granted was $2.56 per share for the period from January 1, 2020 through November 19, 2020 (Predecessor) and $6.80 per share for the year ended December 31, 2019 (Predecessor).
The aggregate grant date fair value of the market-based awards was determined using a Monte Carlo simulation model. The Monte Carlo simulation model uses assumptions regarding random projections and must be repeated numerous times to achieve a probabilistic assessment. The key valuation assumptions for the Monte Carlo model are the forecast period, risk-free interest rates, stock price volatility, initial value, stock price on the date of grant and correlation coefficients. The risk-free interest rates are the U.S. Treasury bond rates on the date of grant that corresponds to each performance period. The initial value is the average of the volume weighted average prices for the 30 trading days prior to the start of the performance cycle for the Company and each of its peers. Volatility is the standard deviation of the average percentage change in stock price over a historical period for the Company and each of its peers. The correlation coefficients are measures of the strength of the linear relationship between and amongst the Company and its peers estimated based on historical stock price data.
The following assumptions were used for the Monte Carlo model to determine the grant date fair value and associated equity-based compensation expense of the PSUs granted during the periods presented (Predecessor): | | | | | | | | | | | |
| 2020 | | 2019 |
Forecast period (years) | 2 - 4 | | 2 - 4 |
Risk-free interest rates | 1.53% - 1.55% | | 2.55% - 2.56% |
Oasis stock price volatility | 68.56 | % | | 71.17 | % |
Oasis initial value | $ | 3.19 | | | $ | 5.85 | |
Oasis stock price on date of grant | $ | 2.77 | | | $ | 6.63 | |
Associated tax benefit. For the year ended December 31, 2019 (Predecessor), the Company had an associated tax benefit of $7.8 million related to all equity-based compensation. The Company did not have any associated tax benefits related to equity-based compensation during the period from January 1, 2020 through November 19, 2020 (Predecessor) as a result of recording a valuation allowance on its deferred tax assets or during the period from November 20, 2020 through December 31, 2020 (Successor) as a result of the vesting of equity-based awards on the Emergence Date.
Class B units in OMP GP. OMP GP previously granted restricted Class B units, representing membership interests in OMP GP, to certain employees, including OMP’s named executive officers, under the 2010 LTIP. The Class B units granted to employees other than the named executive officers vested on the Emergence Date. In connection with the Midstream Simplification, the Class B units granted to OMP’s named executive officers were converted into and exchanged for restricted common units in OMP. On March 30, 2021, 34% of these awards vested, and the remaining awards vested on February 1, 2022.
2020 Incentive Compensation Program. In order to effectively incentivize employees in the then-current environment, the Board of Directors approved a revised 2020 incentive compensation program applicable to all employees effective June 12, 2020 (the “2020 Incentive Compensation Program”).
Under the 2020 Incentive Compensation Program, all 2020 equity-based awards of the Predecessor previously granted under the 2010 LTIP, were forfeited and concurrently replaced with cash retention incentives, which were accounted for as modifications of such 2020 awards. In addition, all employees waived participation in the Company’s 2020 annual cash incentive plan and instead became eligible to earn cash performance incentives based on the achievement of certain specified incentive metrics measured on a quarterly basis from July 1, 2020 to June 30, 2021. The 2020 Incentive Compensation Program resulted in $15.6 million being paid in June 2020 with the remainder of the target amount under such program payable over the following 12 months.
For the Company’s officers and certain other senior employees, the prepaid cash incentives paid in June 2020 could be clawed back if (i) certain specified incentive metrics measured on a quarterly basis were not achieved from July 1, 2020 to December 31, 2020, and (ii) such individuals did not remain employed for a period of up to 12 months, unless such individuals were terminated without cause or resigned for good reason. The after-tax value of the cash incentives paid to the Company’s officers and certain other senior employees of $8.8 million was capitalized to prepaid expenses and amortized over the relevant service periods. The Company immediately expensed the difference between the cash and after-tax value of the prepaid cash incentives of $4.1 million, which was not subject to the clawback provisions of the 2020 Incentive Compensation Program, and recognized additional compensation expense of $0.4 million to adjust for the grant date fair value of certain original 2020 equity-based awards that exceeded the replacement cash retention incentives less amounts previously recognized for the original 2020 equity-based awards. On the Emergence Date and pursuant to the Plan, the remaining unamortized amount of prepaid cash incentives of $4.3 million was vested and included in general and administrative expenses on the Company’s Consolidated Statement of Operations for the period from January 1, 2020 through November 19, 2020 (Predecessor).
For all other employees, the June 2020 incentive payment of $2.7 million was not subject to any clawback provisions, and $2.1 million, which represented the excess of the cash retention payment over amounts previously recognized for the original 2020 equity-based awards in which these cash incentives replaced, was immediately expensed.
The expenses related to the 2020 Incentive Compensation Program are included in general and administrative expenses on the Company’s Consolidated Statements of Operations.
18. Stockholders’ Equity
Dividends. During the year ended December 31, 2021 (Successor), the Company paid regular cash dividends of $1.625 per share of common stock, or $32.3 million in aggregate, and a special cash dividend of $4.00 per share of common stock, or $80.0 million in aggregate. On February 9, 2022, the Company declared a dividend of $0.585 per share of common stock payable on March 4, 2022 to shareholders of record as of February 21, 2022.
Common Stock. On the Emergence Date, the Company filed an amended and restated certificate of incorporation with the Delaware Secretary of State to provide for, among other things, the authority to issue a total of 65,000,000 shares of all classes
of capital stock, of which 60,000,000 shares are common stock, par value $0.01 per share and 5,000,000 shares are preferred stock, par value $0.01 per share.
Treasury Stock. In March 2021, the Board of Directors authorized a share-repurchase program covering up to $100.0 million of the Company’s common stock which expires on December 31, 2022. During the year ended December 31, 2021 (Successor), the Company completed the entire share-repurchase program and repurchased an aggregate amount of 871,018 shares of common stock at a weighted average price of $114.79 per common share for a total cost of $100.0 million. In February 2022, the Board of Directors authorized a new $150.0 million share-repurchase program.
Warrants. On the Emergence Date and pursuant to the Plan, the Company issued 1,621,622 Warrants pro rata to holders of the Predecessor’s common stock. The Warrants, which are classified as equity, are initially exercisable to purchase one share of Successor common stock per Warrant at an initial exercise price of $94.57 per Warrant (the “Exercise Price”). In connection with the Company’s payment of a special dividend, the Exercise Price decreased to $90.57 per Warrant on July 12, 2021. As of December 31, 2021, there were 1,507,976 warrants outstanding.
The Warrants are exercisable from the date of issuance until November 19, 2024, at which time all unexercised Warrants will expire and the rights of the holders of such Warrants to purchase Successor common stock will terminate. The number of shares of Successor common stock for which a Warrant is exercisable, and the Exercise Price, are subject to adjustment from time to time upon the occurrence of certain events, including: (1) stock splits, reverse stock splits or stock dividends to holders of Successor common stock or (2) a reclassification in respect of Successor common stock.
Tax benefits preservation plan. On August 3, 2021, the Board of Directors adopted a Tax Benefits Preservation Plan (the “Tax Plan”) designed to protect the availability of the Company’s Tax Benefits.
In adopting the Tax Plan, the Board of Directors declared a dividend of one preferred share purchase right (a “Right”) for each outstanding share of the Company’s common stock. The Rights traded with the Company’s common stock and were exercisable if, among other things, a person or group of persons acquired 4.95% or more of the Company’s outstanding common stock. On February 1, 2022, the Company announced the termination of the Tax Plan after the Board of Directors determined the Tax Plan was no longer necessary or desirable for the preservation of the Tax Benefits. See Note 17—Income Taxes for more information on the Tax Plan.
19. Earnings (Loss) Per Share
Basic earnings (loss) per share is computed by dividing the earnings (loss) attributable to Oasis common stockholders by the weighted average number of shares outstanding for the periods presented. The calculation of diluted earnings (loss) per share includes the effect of potentially dilutive shares outstanding for the period using the treasury stock method, unless its effect is anti-dilutive. For the Successor periods, potentially dilutive shares outstanding include unvested restricted stock awards, warrants and contingently issuable shares related to RSUs, PSUs and LSUs. For the Predecessor periods, potentially dilutive shares outstanding included Predecessor unvested restricted stock awards, Predecessor contingently issuable shares related to PSUs and Predecessor senior convertible notes. There were no adjustments made to the income (loss) attributable to Oasis available to common stockholders in the calculation of diluted earnings (loss) per share during either the Successor period or Predecessor period.
The following table summarizes the basic and diluted weighted average common shares outstanding and the weighted average common shares excluded from the calculation of diluted weighted average common shares outstanding due to the anti-dilutive effect for the periods presented (in thousands): | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Successor | | | Predecessor |
| Year Ended December 31, 2021 | | Period from November 20, 2020 through December 31, 2020 | | | Period from January 1, 2020 through November 19, 2020 | | Year Ended December 31, 2019 |
| | | | |
| | | | | | | | |
Weighted average common shares outstanding: | | | | | | | | |
Basic | 19,792 | | 19,991 | | | 317,644 | | 315,002 |
Dilutive effect of equity-classified awards | 856 | | | — | | | | — | | | — | |
Dilutive effect of warrants | — | | | — | | | | — | | | — | |
Diluted | 20,648 | | | 19,991 | | | | 317,644 | | | 315,002 | |
Anti-dilutive weighted average common shares: | | | | | | | | |
Potential common shares | 2,144 | | | 1,631 | | | | 5,216 | | | 9,242 | |
For the year ended December 31, 2021 (Successor), the diluted earnings per share calculation excludes the impact of unvested share based awards and outstanding warrants that were anti-dilutive under the treasury stock method. During the period from November 20, 2020 through December 31, 2020 (Successor), the period from January 1, 2020 through November 19, 2020 (Predecessor) and the year ended December 31, 2019 (Predecessor), the Company incurred a net loss, and therefore the diluted loss per share calculation for those periods excludes the anti-dilutive effect of unvested share based awards and outstanding warrants.
20. Leases
The Company’s leases consist primarily of office space, vehicles and other property and equipment used in its operations. The components of lease costs attributable to continuing operations were as follows for the periods presented (in thousands): | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Successor | | | Predecessor |
| Year Ended December 31, 2021 | | Period from November 20, 2020 through December 31, 2020 | | | Period from January 1, 2020 through November 19, 2020 | | Year Ended December 31, |
| | | | | 2019 |
| | | | | | | | |
| | | | | | |
Operating lease costs | $ | 2,966 | | | $ | 666 | | | | $ | 3,245 | | | $ | 23,137 | |
Variable lease costs(1) | 1,737 | | | 425 | | | | 2,433 | | | 8,776 | |
Short-term lease costs | 8,244 | | | 554 | | | | 9,807 | | | 4,513 | |
Finance lease costs: | | | | | | | | |
Amortization of ROU assets | 1,578 | | | 151 | | | | 1,959 | | | 2,543 | |
Interest on lease liabilities | 86 | | | 9 | | | | 145 | | | 260 | |
Total lease costs | $ | 14,611 | | | $ | 1,805 | | | | $ | 17,589 | | | $ | 39,229 | |
___________________
(1)Based on payments made by the Company to lessors for the right to use an underlying asset that vary because of changes in circumstances occurring after the commencement date, other than the passage of time, such as property taxes, operating and maintenance costs, which do not depend on an index or rate.
The amounts disclosed herein include costs associated with properties operated by the Company that are presented on a gross basis and do not reflect the Company’s net proportionate share of such amounts. A portion of these costs have been or will be billed to other working interest owners.
The Company’s share of operating, variable and short-term lease costs are either capitalized and included in property, plant and equipment on the Company’s Consolidated Balance Sheets or are recognized in the Company’s Consolidated Statements of Operations in lease operating expenses and general and administrative expenses, as applicable. The finance lease costs for the amortization of ROU assets and the interest on lease liabilities disclosed above are included in depreciation, depletion and amortization and interest expense, net of capitalized interest, respectively, on the Company’s Consolidated Statements of Operations.
Total lease costs attributable to discontinued operations were recorded in income from discontinued operations, net of income tax on the Consolidated Statements of Operations. Total lease costs attributable to discontinued operations were $1.3 million for the year ended December 31, 2021 (Successor), $0.1 million for the period from November 20, 2020 through December 31, 2020 (Successor), $2.8 million for the period from January 1, 2020 through November 19, 2020 (Predecessor) and $3.8 million for the year ended December 31, 2019 (Predecessor).
As of December 31, 2021, maturities of the Company’s lease liabilities were as follows: | | | | | | | | | | | |
| Operating Leases | | Finance Leases |
| | | |
| (In thousands) |
2022 | $ | 8,251 | | | $ | 1,029 | |
2023 | 5,845 | | | 181 | |
2024 | 598 | | | — | |
2025 | 409 | | | — | |
2026 | — | | | — | |
Thereafter | — | | | — | |
Total future lease payments | 15,103 | | | 1,210 | |
Less: Imputed interest | 486 | | | 22 | |
Present value of future lease payments | $ | 14,617 | | | $ | 1,188 | |
Supplemental balance sheet information related to the Company’s leases were as follows: | | | | | | | | | | | | | | | | | | | | |
| | Balance Sheet Location | | December 31, 2021 | | December 31, 2020 |
| | | | | | |
| | | | (In thousands) |
Assets | | | | | | |
Operating lease assets(1) | | Operating right-of-use assets | | $ | 15,782 | | | $ | 4,440 | |
Finance lease assets(2) | | Other assets | | 1,124 | | | 2,849 | |
Total lease assets | | | | $ | 16,906 | | | $ | 7,289 | |
Liabilities | | | | | | |
Current | | | | | | |
Operating lease liabilities(1) | | Current operating lease liabilities | | $ | 7,893 | | | $ | 1,662 | |
Finance lease liabilities | | Other current liabilities | | 1,008 | | | 1,605 | |
Long-term | | | | | | |
Operating lease liabilities(1) | | Operating lease liabilities | | 6,724 | | | 1,629 | |
Finance lease liabilities | | Other liabilities | | 180 | | | 1,355 | |
Total lease liabilities | | | | $ | 15,805 | | | $ | 6,251 | |
___________________
(1)The Company acquired certain operating leases for generators and compressors in connection with the Williston Basin Acquisition. As of December 31, 2021, these included operating lease assets of $11.0 million, current operating lease liabilities of $6.7 million and long-term operating lease liabilities of $4.5 million.
(2)Finance lease ROU assets are recorded net of accumulated amortization of $0.9 million as of December 31, 2021 and $0.2 million as of December 31, 2020.
Operating lease assets and liabilities and finance lease assets and liabilities that were attributable to discontinued operations were classified as held for sale as of December 31, 2021 and December 31, 2020. As of December 31, 2021, the Company had $0.7 million of operating lease assets and liabilities and immaterial finance lease assets and liabilities that were classified as held for sale on the Consolidated Balance Sheet. As of December 31, 2020, the Company had $1.6 million of operating lease assets, $1.7 million of operating lease liabilities and $0.6 million of finance lease assets and liabilities that were classified as held for sale on the Consolidated Balance Sheet.
Supplemental cash flow information and non-cash transactions related to the Company’s leases were as follows (in thousands): | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Successor | | | Predecessor |
| Year Ended December 31, 2021 | | Period from November 20, 2020 through December 31, 2020 | | | Period from January 1, 2020 through November 19, 2020 | | December 31, |
| | | | | 2019 |
| | | | | | | | |
Cash paid for amounts included in the measurement of lease liabilities | | | | | | | | |
Operating cash flows from operating leases | $ | 3,420 | | | $ | 1,992 | | | | $ | 6,624 | | | $ | 30,316 | |
Operating cash flows from finance leases | 62 | | | 9 | | | | 145 | | | 260 | |
Financing cash flows from finance leases | 1,161 | | | 202 | | | | 1,989 | | | 2,382 | |
ROU assets obtained in exchange for lease obligations | | | | | | | | |
Operating leases(1) | $ | 14,140 | | | $ | — | | | | $ | 797 | | | $ | 12,746 | |
Finance leases | 127 | | | — | | | | 24 | | | 3,433 | |
Reductions to ROU assets resulting from reductions to lease obligations | | | | | | | | |
Operating leases(2) | $ | — | | | $ | (6,255) | | | | $ | — | | | $ | — | |
___________________
(1)The year ended December 31, 2021 includes $12.3 million related to operating leases acquired in the Williston Basin Acquisition.
(2)The period from November 20, 2020 through December 31, 2020 includes amounts added to or reduced from the carrying amount of ROU assets resulting from lease modifications and remeasurements in connection with the Company’s emergence from bankruptcy.
Weighted-average remaining lease terms and discount rates for the Company’s leases were as follows: | | | | | | | | | | | |
| December 31, |
| | | |
| 2021 | | 2020 |
Operating Leases | | | |
Weighted average remaining lease term | 1.9 years | | 2.6 years |
Weighted average discount rate | 3.4 | % | | 3.9 | % |
Finance Leases | | | |
Weighted average remaining lease term | 1.1 years | | 4.6 years |
Weighted average discount rate | 3.5 | % | | 3.6 | % |
21. Significant Concentrations
Major customers. For the year ended December 31, 2021 (Successor), sales to Phillips 66 Company accounted for approximately 13% of the Company’s total product sales. For the Successor period of November 20, 2020 through December 31, 2020, sales to ExxonMobil Oil Corporation and Phillips 66 Company accounted for approximately 22% and 15%, respectively, of the Company’s total product sales. For the Predecessor period of January 1, 2020 through November 19, 2020, Phillips 66 Company and Gunvor USA LLC accounted for approximately 11% and 10%, respectively, of the Company’s total product sales. For the year ended December 31, 2019 (Predecessor), sales to Phillips 66 Company accounted for approximately 14% of the Company’s hydrocarbon product sales. No other purchasers accounted for more than 10% of the Company’s total sales for the years ended December 31, 2021, 2020 or 2019.
Substantially all of the Company’s accounts receivable result from sales of crude oil, natural gas and NGLs as well as joint interest billings to third-party companies who have working interest payment obligations in projects completed by the Company. This concentration of customers and joint interest owners may impact the Company’s overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions, including the current downturn in crude oil prices. Management believes that the loss of any of these purchasers would not have a material adverse effect on the Company’s operations, as there are a number of alternative crude oil, natural gas and NGL purchasers in the Company’s producing regions.
22. Commitments and Contingencies
Included below is a discussion of various future commitments of the Company as of December 31, 2021. The commitments under these arrangements are not recorded in the accompanying Consolidated Balance Sheets. The amounts disclosed represent undiscounted cash flows on a gross basis and no inflation elements have been applied. As of December 31, 2021, the Company’s material off-balance sheet arrangements and transactions include $2.4 million in outstanding letters of credit issued under the Oasis Credit Facility and $6.7 million in net surety bond exposure issued as financial assurance on certain agreements.
Volume commitment agreements. As of December 31, 2021, the Company had certain agreements with an aggregate requirement to deliver, transport or purchase a minimum quantity of approximately 45.8 MMBbl of crude oil, 603.3 Bcf of natural gas and 22.5 MMBbl of NGLs, prior to any applicable volume credits, within specified timeframes, the majority of which are ten years or less.
The estimable future commitments under these volume commitment agreements as of December 31, 2021 are as follows: | | | | | |
| (In thousands) |
2022 | $ | 111,323 | |
2023 | 108,006 | |
2024 | 94,573 | |
2025 | 85,986 | |
2026 | 66,363 | |
Thereafter | 81,447 | |
| $ | 547,698 | |
The future commitments under certain agreements cannot be estimated and are therefore excluded from the table above as they are based on fixed differentials relative to a commodity index price under the agreements as compared to the differential relative to a commodity index price for the production month.
The Company enters into long-term contracts to provide production flow assurance in oversupplied basins and/or areas with limited infrastructure, which provides for optimization of transportation and processing costs. As properties are undergoing development activities, the Company may experience temporary delivery or transportation shortfalls until production volumes grow to meet or exceed the minimum volume commitments. The Company recognizes any monthly deficiency payments in the period in which the underdelivery takes place and the related liability has been incurred. The table above does not include any such deficiency payments that may be incurred under the Company’s physical delivery contracts, since it cannot be predicted with accuracy the amount and timing of any such penalties incurred.
In connection with the Williston Basin Acquisition, the Company acquired gathering and transportation contracts that include minimum volume commitments. The Company believes it is probable it will not be able to meet the minimum volume commitment in certain of these contracts and has recorded a liability of $11.9 million on the Consolidated Balance Sheet as of December 31, 2021, of which $5.5 million was recorded to accrued liabilities and $6.4 million was recorded to other liabilities. The future commitments related to these contracts are included in the table above.
Litigation. The Company is party to various legal and/or regulatory proceedings from time to time arising in the ordinary course of business. When the Company determines that a loss is probable of occurring and is reasonably estimable, the Company accrues an undiscounted liability for such contingencies based on its best estimate using information available at the time. The Company discloses contingencies where an adverse outcome may be material, or in the judgment of management, the matter should otherwise be disclosed.
Mandan, Hidatsa and Arikara Nation (“MHA Nation”) Title Dispute. This matter relates to certain leases acquired by the Company from QEP in October 2021: In June 2018, the MHA Nation notified QEP of its position that QEP has no valid lease covering certain minerals underlying the Missouri and Little Missouri Riverbeds on the Fort Berthold Reservation in North Dakota. The MHA Nation also passed a resolution purporting to rescind those portions of QEP's IMDA lease covering the disputed minerals underlying the Missouri River. QEP responded in September 2018 stating that the minerals underlying the Missouri River are properly leased. In May 2020, the Office of the Solicitor of the United States Department of the Interior (the “Department of the Interior”) issued an opinion (the “Missouri River Opinion”) finding that the State of North Dakota, not the MHA Nation, is the legal owner of the minerals underlying the Missouri River. The MHA Nation filed actions in two federal courts seeking to overturn the May 2020 decision, and in March 2021, the Department of the Interior withdrew the Missouri River Opinion and only recently, on February 4, 2022, the Department of the Interior issued a new opinion on the matter stating that the minerals beneath the Missouri River riverbed located on the Fort Berthold Indian Reservation belong to the MHA Nation and not the state of North Dakota.
Mirada litigation. As previously disclosed in the Company’s 2020 Annual Report, the Company entered the Mirada Settlement Agreement with Mirada on September 28, 2020. The Mirada Settlement Agreement provides for, among other things, payment by OPNA to Mirada of $42.8 million. The Company paid Mirada $20.0 million on the Emergence Date and $22.8 million in May 2021. These amounts were previously accrued for in the Company’s Consolidated Balance Sheet at December 31, 2020, and there are no remaining settlement payments outstanding as of December 31, 2021.
23. Subsequent Events
The Company has evaluated the period after the balance sheet date, noting no subsequent events or transactions that required recognition or disclosure in the financial statements, other than the closing of the OMP Merger and other matters as previously disclosed herein.
24. Supplemental Oil and Gas Disclosures — Unaudited
The supplemental data presented below reflects information for all of the Company’s oil and gas producing activities. Prior periods have not been recast for discontinued operations.
Capitalized Costs
The following table sets forth the capitalized costs related to the Company’s oil and gas producing activities (in thousands): | | | | | | | | | | | |
| |
| December 31, |
| 2021 | | 2020 |
| | | |
| |
Proved oil and gas properties | $ | 1,393,836 | | | $ | 770,117 | |
Less: Accumulated depreciation, depletion, amortization and impairment | (107,277) | | | (12,403) | |
Proved oil and gas properties, net | 1,286,559 | | | 757,714 | |
Unproved oil and gas properties | 2,001 | | | 40,211 | |
Total oil and gas properties, net | $ | 1,288,560 | | | $ | 797,925 | |
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities
The following table sets forth costs incurred related to the Company’s oil and gas activities for the periods presented (in thousands): | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Successor | | | Predecessor |
| Year Ended December 31, 2021 | | Period from November 20, 2020 through December 31, 2020 | | | Period from January 1, 2020 through November 19, 2020 | | Year Ended December 31, 2019 |
| | | | |
| | | | | | | | |
| | | | | | |
Acquisition costs: | | | | | | | | |
Proved oil and gas properties | $ | 605,868 | | | $ | — | | | | $ | — | | | $ | — | |
Unproved oil and gas properties | 85 | | | 336 | | | | 536 | | | 23,058 | |
Exploration costs | 1 | | | 105 | | | | 1,225 | | | 67,470 | |
Development costs | 170,178 | | | 14,624 | | | | 199,537 | | | 542,133 | |
Asset retirement costs | 15,750 | | | 35 | | | | 181 | | | 2,083 | |
Total costs incurred | $ | 791,882 | | | $ | 15,100 | | | | $ | 201,479 | | | $ | 634,744 | |
| | | | | | | | |
Results of Operations for Oil and Gas Producing Activities
The following table sets forth the results of operations for oil and gas producing activities, which exclude general and administrative expenses and interest expense, for the periods presented (in thousands): | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Successor | | | Predecessor |
| Year Ended December 31, 2021 | | Period from November 20, 2020 through December 31, 2020 | | | Period from January 1, 2020 through November 19, 2020 | | Year Ended December 31, 2019 |
| | | | |
| | | | | | | | |
| | | | | | |
Revenues | $ | 1,200,256 | | | $ | 86,442 | | | | $ | 603,585 | | | $ | 1,408,771 | |
Production costs | 403,382 | | | 32,903 | | | | 249,707 | | | 464,782 | |
Depreciation, depletion and amortization | 109,881 | | | 12,745 | | | | 264,822 | | | 759,900 | |
Exploration costs | 2,760 | | | — | | | | 2,748 | | | 6,658 | |
Rig termination | — | | | — | | | | 1,279 | | | 384 | |
Impairment | 3 | | | — | | | | 4,800,785 | | | 5,389 | |
Income tax (benefit) expense | 162,163 | | | 9,648 | | | | (1,115,276) | | | 40,745 | |
Results of operations for oil and gas producing activities | $ | 522,067 | | | $ | 31,146 | | | | $ | (3,600,480) | | | $ | 130,913 | |
25. Supplemental Oil and Gas Reserve Information — Unaudited
The reserve estimates presented in the table below are based on reports prepared by DeGolyer and MacNaughton, the Company’s independent reserve engineers, in accordance with the FASB’s authoritative guidance on crude oil and natural gas reserve estimation and disclosures. All of the Company’s oil and gas reserves are attributable to properties within the United States.
Proved oil and gas reserves are the estimated quantities of crude oil and natural gas that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating
conditions (i.e., prices and costs) existing at the time the estimate is made. Proved developed oil and gas reserves are proved reserves that can be expected to be recovered through existing wells and equipment in place and under operating methods being utilized at the time the estimates were made. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established proved producing oil and gas properties. Accordingly, these estimates are expected to change as future information becomes available.
Estimated Quantities of Proved Crude Oil and Natural Gas Reserves
The following table summarizes changes in quantities of the Company’s estimated net proved reserves for the periods presented: | | | | | | | | | | | | | | | | | |
| Crude Oil (MBbl) | | Natural Gas (MMcf) | | MBoe(1) |
2019 | | | | | |
Proved reserves | | | | | |
Beginning balance (Predecessor) | 228,416 | | | 552,726 | | | 320,537 | |
Revisions of previous estimates | (51,965) | | | (68,301) | | | (63,349) | |
Extensions, discoveries and other additions | 49,297 | | | 87,382 | | | 63,861 | |
Sales of reserves in place | (2,136) | | | (2,368) | | | (2,531) | |
Production | (22,825) | | | (55,906) | | | (32,142) | |
Net proved reserves at December 31, 2019 (Predecessor) | 200,787 | | | 513,533 | | | 286,376 | |
Proved developed reserves, December 31, 2019 (Predecessor) | 113,418 | | | 314,000 | | | 165,751 | |
Proved undeveloped reserves, December 31, 2019 (Predecessor) | 87,369 | | | 199,533 | | | 120,625 | |
2020 | | | | | |
Proved reserves | | | | | |
Beginning balance (Predecessor) | 200,787 | | | 513,533 | | | 286,376 | |
Revisions of previous estimates | (69,782) | | | (98,815) | | | (86,251) | |
Extensions, discoveries and other additions | 4,578 | | | 8,659 | | | 6,021 | |
Production | (15,818) | | | (47,207) | | | (23,686) | |
Net proved reserves at December 31, 2020 (Successor) | 119,765 | | | 376,170 | | | 182,460 | |
Proved developed reserves, December 31, 2020 (Successor) | 85,428 | | | 262,676 | | | 129,207 | |
Proved undeveloped reserves, December 31, 2020 (Successor) | 34,337 | | | 113,494 | | | 53,253 | |
2021 | | | | | |
Proved reserves | | | | | |
Beginning balance (Successor) | 119,765 | | | 376,170 | | | 182,460 | |
Revisions of previous estimates | 42,411 | | | 68,768 | | | 53,871 | |
Extensions, discoveries and other additions | 7,734 | | | 14,539 | | | 10,157 | |
Sales of reserves in place | (24,760) | | | (40,211) | | | (31,461) | |
Purchases of reserves in place | 42,656 | | | 86,153 | | | 57,015 | |
Production | (13,489) | | | (46,157) | | | (21,182) | |
Net proved reserves at December 31, 2021 (Successor) | 174,317 | | | 459,262 | | | 250,860 | |
Proved developed reserves, December 31, 2021 (Successor) | 114,041 | | | 361,836 | | | 174,347 | |
Proved undeveloped reserves, December 31, 2021 (Successor) | 60,276 | | | 97,426 | | | 76,513 | |
__________________
(1)Natural gas is converted to barrel of oil equivalents at the rate of six thousand cubic feet of natural gas to one barrel of oil.
Revisions of Previous Estimates
In 2021, the Company had net positive revisions of 53.9 MMBoe, or 30% of the beginning of the year estimated net proved reserves balance. These net positive revisions were attributable to positive revisions of 38.6 MMBoe associated with alignment to the five-year development plan, 37.2 MMBoe associated with higher realized prices and 6.2 MMBoe due to lower operating expenses, partially offset by negative revisions of 22.9 MMBoe attributable to reservoir analysis and well performance across our Bakken asset and 5.2 MMBoe due to the impact of removing the benefits of midstream operations from operating expenses. Proved developed net revisions of 20.3 MMBoe were primarily due to positive revisions of 36.5 MMBoe associated with higher realized prices and 6.0 MMBoe due to lower operating expenses, partially offset by negative revisions of 17.6 MMBoe attributable to reservoir analysis and well performance across our Bakken asset and 4.6 MMBoe due to the impact of removing the benefits of our midstream operations from operating expenses. Proved undeveloped (“PUD”) net revisions were primarily due to positive revisions of 38.6 MMBoe associated with alignment to the five-year development plan, offset by negative revisions of 5.1 MMBoe attributable to reservoir analysis and well performance across our Bakken asset.
In 2020, the Company had net negative revisions of 86.3 MMBoe, or 30% of the beginning of the year estimated net proved reserves balance. These net negative revisions were attributable to negative revisions of 60.1 MMBoe associated with alignment
to the five-year development plan and 31.9 MMBoe due to lower realized prices, offset by positive revisions of 5.6 MMBoe for the addition of PUD reserves that were previously removed from the five-year development plan. Proved developed revisions were primarily due to negative revisions of 29.3 MMBoe due to lower realized prices, partially offset by positive revisions of 1.5 MMBoe due to lower operating expenses. The PUD revisions were primarily due to negative revisions of 54.5 MMBoe associated with alignment to the five-year development plan and 2.6 MMBoe due to lower realized price.
In 2019, the Company had net negative revisions of 63.3 MMBoe, or 20% of the beginning of the year estimated net proved reserves balance. These net negative revisions were attributable to negative revisions of 51.2 MMBoe due to well performance, 11.2 MMBoe due to lower realized prices and 7.6 MMBoe associated with alignment to the five-year development plan, offset by positive revisions of 6.7 MMBoe due to lower operating expenses. Proved developed revisions were primarily due to negative revisions of 30.2 MMBoe for performance largely related to higher than anticipated decline rates in recently developed spacing units and 9.6 MMBoe due to lower realized prices, partially offset by positive revisions of 5.1 MMBoe due to lower operating expenses. The PUD revisions were primarily due to negative revisions of 21.1 MMBoe for performance largely related to reductions in the anticipated hydrocarbon recoveries of proved areas during full field development due to changes in anticipated well densities and well performance and 7.0 MMBoe associated with alignment to the anticipated five-year development plan, offset by positive revisions of 1.7 MMBoe due to lower operating expenses.
Extensions, Discoveries and Other Additions
In 2021, the Company had a total of 10.2 MMBoe of additions due to extensions and discoveries. An estimated 7.6 MMBoe of PUDs were added associated with the Company’s anticipated five-year development plan, and an additional 2.6 MMBoe of these extensions and discoveries were associated with new producing wells at December 31, 2021.
In 2020, the Company had a total of 6.0 MMBoe of additions due to extensions and discoveries. An estimated 3.2 MMBoe of these extensions and discoveries were associated with new producing wells at December 31, 2020, with 99% of these reserves from wells producing in the Permian Basin and 1% of these reserves from wells producing in the Williston Basin. An additional 2.8 MMBoe of PUDs were added in the Williston Basin associated with the Company’s anticipated five-year development plan.
In 2019, the Company had a total of 63.9 MMBoe of additions due to extensions and discoveries. An estimated 10.3 MMBoe of these extensions and discoveries were associated with new producing wells at December 31, 2019, with 60% of these reserves from wells producing in the Bakken or Three Forks formations and 40% of reserves from wells producing in the Permian Basin. An additional 53.6 MMBoe of PUDs were added in the Williston and Permian Basins associated with the Company’s anticipated five-year development plan, with 63% of these PUDs in the Bakken or Three Forks formations and 37% in the Permian Basin.
Sales of Reserves in Place
In 2021 and 2019, the Company divested 31.5 MMBoe of reserves associated with reservoirs in the Permian Basin and 2.5 MMBoe of reserves associated with reservoirs in the Williston Basin, respectively. The Company divested no reserves in 2020. See Note 13—Acquisitions and Divestitures for more information.
Purchases of Reserves in Place
In 2021, the Company purchased estimated net proved reserves of 57.0 MMBoe associated with reservoirs in the Williston Basin. In 2020 and 2019 there were no purchased estimated net proved reserves from acquisitions. See Note 13—Acquisitions and Divestitures for more information.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves
The Standardized Measure represents the present value of estimated future net cash flows from estimated net proved oil and natural gas reserves, less future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect timing of future cash flows. Production costs do not include DD&A of capitalized acquisition, exploration and development costs.
The Company’s estimated net proved reserves and related future net revenues and Standardized Measure were determined using index prices for crude oil and natural gas, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The unweighted arithmetic average first-day-of-the-month prices for the prior 12 months were $66.55 per Bbl for crude oil and $3.64 per MMBtu for natural gas, $39.54 per Bbl for crude oil and $2.03 per MMBtu for natural gas and $55.85 per Bbl for crude oil and $2.62 per MMBtu for natural gas for the years ended December 31, 2021, 2020 and 2019, respectively. These prices were adjusted by lease for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead. Future operating costs, production taxes and capital costs were based on current costs as of each year-end.
The following table sets forth the Standardized Measure of discounted future net cash flows from projected production of the Company’s estimated net proved reserves at December 31, 2021, 2020 and 2019: | | | | | | | | | | | | | | | | | |
| At December 31, |
| 2021 | | 2020 | | 2019 |
| | | | | |
| (In thousands) |
Future cash inflows | $ | 13,366,064 | | | $ | 5,197,220 | | | $ | 12,385,040 | |
Future production costs | (6,548,794) | | | (2,792,921) | | | (5,509,127) | |
Future development costs | (1,322,207) | | | (610,658) | | | (1,490,521) | |
Future income tax expense | (717,721) | | | (232,849) | | | (188,823) | |
Future net cash flows | 4,777,342 | | | 1,560,792 | | | 5,196,569 | |
10% annual discount for estimated timing of cash flows | (2,080,404) | | | (611,915) | | | (2,352,200) | |
Standardized measure of discounted future net cash flows | $ | 2,696,938 | | | $ | 948,877 | | | $ | 2,844,369 | |
The following table sets forth the changes in the Standardized Measure of discounted future net cash flows applicable to estimated net proved reserves for the periods presented: | | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 |
| | | | | |
| (In thousands) |
January 1 | $ | 948,877 | | | $ | 2,844,369 | | | $ | 4,050,306 | |
Net changes in prices and production costs | 1,617,331 | | | (1,088,936) | | | (1,070,192) | |
Net changes in future development costs | (36,645) | | | 4,640 | | | 131,003 | |
Sales of crude oil and natural gas, net | (796,874) | | | (407,417) | | | (943,989) | |
Extensions | 98,125 | | | 47,693 | | | 437,700 | |
| | | | | |
Purchases of reserves in place | 780,442 | | | — | | | — | |
Sales of reserves in place | (204,153) | | | — | | | (36,907) | |
Revisions of previous quantity estimates | 639,320 | | | (694,320) | | | (732,253) | |
Previously estimated development costs incurred | 102,519 | | | 87,640 | | | 246,311 | |
Accretion of discount | 94,090 | | | 293,445 | | | 467,426 | |
Net change in income taxes | (252,347) | | | (76,066) | | | 533,872 | |
Changes in timing and other | (293,747) | | | (62,171) | | | (238,908) | |
December 31 | $ | 2,696,938 | | | $ | 948,877 | | | $ | 2,844,369 | |