NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 – ORGANIZATION AND BUSINESS
Unless the context clearly indicates otherwise, references in this report to “Unit”, “company”, “we”, “our”, “us”, or like terms refer to Unit Corporation or, as appropriate, one or more of its subsidiaries. References to our mid-stream segment refers to Superior Pipeline Company, L.L.C. (Superior) of which we own 50%.
We are primarily engaged in the development, acquisition, and production of oil and natural gas properties, the land contract drilling of natural gas and oil wells, and the buying, selling, gathering, processing, and treating of natural gas. Our operations are all in the United States and are organized in the following three reporting segments: (1) Oil and Natural Gas, (2) Contract Drilling, and (3) Mid-Stream.
Oil and Natural Gas. Carried out by our subsidiary, Unit Petroleum Company (UPC), we develop, acquire, and produce oil and natural gas properties for our own account. Our producing oil and natural gas properties, unproved properties, and related assets are mainly in Oklahoma and Texas, and to a lesser extent, in Arkansas, Kansas, Louisiana, Montana, North Dakota, Utah, and Wyoming.
Contract Drilling. Carried out by our subsidiary, Unit Drilling Company (UDC), we drill onshore oil and natural gas wells for a wide range of other oil and natural gas companies as well as for our own account. Our drilling operations are mainly in Oklahoma, Texas, New Mexico, Wyoming, and North Dakota.
Mid-Stream. Carried out by our subsidiary, Superior, we buy, sell, gather, transport, process, and treat natural gas for our own account and for third parties. Mid-stream operations are performed in Oklahoma, Texas, Kansas, Pennsylvania, and West Virginia.
On May 22, 2020 (Petition Date), Unit together with its wholly owned subsidiaries, UDC; UPC; 8200 Unit Drive, L.L.C. (8200 Unit); Unit Drilling Colombia, L.L.C. (Unit Drilling Colombia); and Unit Drilling USA Colombia, L.L.C. (Unit Drilling USA, together with Unit, UPC, UDC, 8200 Unit and Unit Drilling Colombia, the Debtors), filed voluntary petitions (Bankruptcy Petitions) for reorganization under Chapter 11 of Title 11 of the United States Code (Bankruptcy Code) in the United States Bankruptcy Court for the Southern District of Texas, Houston Division (Bankruptcy Court). The Chapter 11 proceedings were jointly administered under Case No. 20-32740 (DRJ) (Chapter 11 Cases). On August 6, 2020, the Bankruptcy Court entered the “Findings of Fact, Conclusions of Law, and Order (I) Approving the Disclosure Statement on a Final Basis and (II) Confirming the Debtors’ Amended Joint Chapter 11 Plan of Reorganization” (the Plan) [Docket No. 340] (Confirmation Order) confirming the Plan and approving the disclosure statement on a final basis. On September 3, 2020 (Effective Date) the conditions to effectiveness for the Plan were satisfied, and the Debtors emerged from Chapter 11.
NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation
These interim financial statements are unaudited and have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (SEC) regarding interim financial reporting. Certain disclosures have been condensed or omitted from these financial statements. Accordingly, they do not include all of the information and notes required by accounting principles generally accepted in the United States of America (GAAP) for complete consolidated financial statements, and should be read in conjunction with the audited consolidated financial statements and notes thereto for the year ended December 31, 2020 included in the company’s Annual Report on Form 10-K as filed with the SEC on March 31, 2021.
In the opinion of management, the unaudited condensed consolidated financial statements contain all normal recurring adjustments (including the elimination of all intercompany transactions) and are fairly stated. Our financial statements are prepared in conformity with GAAP, which requires us to make certain estimates and assumptions that may affect the amounts reported in our unaudited condensed consolidated financial statements and notes. Actual results may differ from those estimates. The results for interim periods are not necessarily indicative of annual results. The company evaluates subsequent events through the date the financial statements are issued.
In accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) Topic 852, Reorganizations, the company adopted fresh start accounting upon emergence from the Chapter 11 Cases resulting in the company becoming a new entity for financial reporting purposes. We evaluated the events between September 1, 2020 and September 3, 2020 and concluded that the use of an accounting convenience date of September 1, 2020 (Fresh Start Reporting Date) would not have a material impact to the unaudited condensed consolidated financial statements. This was reflected in our unaudited condensed consolidated balance sheet as of September 1, 2020. Accordingly, our unaudited condensed consolidated financial statements and notes after September 1, 2020, are not comparable to the unaudited condensed consolidated financial statements and notes before that date. To facilitate the financial statement presentations, we refer to the reorganized company in these unaudited condensed consolidated financial statements and notes as the "Successor" for periods subsequent to August 31, 2020, and "Predecessor" for periods prior to September 1, 2020. Furthermore, the unaudited condensed consolidated financial statements and notes have been presented with a "black line" division to delineate the lack of comparability between the Predecessor and Successor.
We consolidate the activities of Superior, a 50/50 joint venture between Unit Corporation and SP Investor Holdings, LLC, (SP Investor) which qualifies as a Variable Interest Entity (VIE) under GAAP. We have concluded that we are the primary beneficiary of the VIE, as defined in the accounting standards, since we have the power to direct those activities that most significantly affect the economic performance of Superior as further described in Note 16 – Variable Interest Entity Arrangements.
During second quarter 2021, management identified errors in our inter-segment eliminations presentation between oil and natural gas revenues and gas gathering and processing revenues as well as between gas gathering and processing operating costs and general and administrative expenses. The impacts of the errors were not material to any of our prior period financial statements and the current year impacts on the three months ended March 31, 2021 were corrected with a one-time adjustment in the three months ended June 30, 2021. As a result, during the three months ended June 30, 2021, oil and natural gas revenues were decreased by $8.6 million with a corresponding increase to gas gathering and processing revenues while general and administrative expenses were increased by $0.9 million with a corresponding decrease to gas gathering and processing operating costs.
Also during second quarter 2021, management identified separate errors in our prior period accrual of oil and natural gas revenues as well as oil and natural gas operating costs. The impacts of the errors were not material to any of our prior period financial statements and the errors were corrected with a one-time adjustment in the three months ended June 30, 2021. As a result, during the three months ended June 30, 2021, oil and natural gas revenues were increased by $3.9 million and oil and natural gas operating costs were decreased by $3.4 million.
Certain amounts in this report for prior periods have been reclassified to conform to current year presentation. There was no impact from these reclassifications to consolidated net income/(loss) or shareholders' equity.
Recent Accounting Pronouncements
Debt—Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging— Contracts in Entity’s Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity. The FASB issued ASU 2020-06 which simplifies the accounting for convertible instruments by removing certain accounting models which separate the embedded conversion features from the host contract for convertible instruments. The ASU further removes certain settlement conditions that are required for equity contracts to qualify for the derivative scope exception and simplifies the diluted earnings per share calculation in certain areas. The ASU is effective for fiscal years beginning after December 15, 2021, including interim periods within those fiscal years. Early adoption is permitted. We are currently evaluating the potential impact on our financial statements.
Reference Rate Reform (Topic 848)—Facilitation of the Effects of Reference Rate Reform on Financial Reporting. The FASB issued ASU 2020-04 which provides optional expedients and exceptions for applying GAAP to contract modifications, subject to meeting certain criteria, that reference LIBOR or another reference rate expected to be discontinued. The ASU is intended to help stakeholders during the global market-wide reference rate transition period. The amendments within this ASU will be in effect for a limited time beginning March 12, 2020, and an entity may elect to apply the amendments prospectively through December 31, 2022. The amendments will not have a material impact on our unaudited condensed consolidated financial statements.
Adopted Standards
Income Taxes (Topic 740)—Simplifying the Accounting for Income Taxes. The FASB issued ASU 2019-12 to simplify the accounting for income taxes by removing certain exceptions to the general principles in Topic 740. The amendments also improve consistent application of and simplify GAAP for other areas of Topic 740 by clarifying and amending existing guidance. The amendments were effective for reporting periods beginning after December 15, 2020. This standard had no material impact on our unaudited condensed consolidated financial statements.
NOTE 3 – IMPAIRMENTS
We review and evaluate our long-lived assets, including intangible assets, for impairment when events or changes in circumstances indicate that the related carrying amount of those assets may not be recoverable, and changes to our estimates could affect our assessment of asset recoverability.
Oil and Natural Gas Properties
There were no impairments recorded during the three and six months ended June 30, 2021.
During the three months ended March 31, 2020, due to the increased uncertainty in our business, we determined our undeveloped acreage would not be fully developed and thus the carrying values of certain of our unproved oil and gas properties were not recoverable resulting in an impairment of $226.5 million. That impairment had a corresponding increase to our depletion base and contributed to our recorded full cost ceiling impairment during the three months ended March 31, 2020. We recorded a non-cash full cost ceiling test write-down of $267.8 million pre-tax ($220.8 million, net of tax) in the three months ended March 31, 2020 due to the reduction for the 12-month average commodity prices and the impairment of our unproved oil and gas properties described above. There were no additional triggering events identified during the three months ended June 30, 2020.
In addition to the impairment evaluations of our proved and unproved oil and gas properties in the three months ended March 31, 2020, we also evaluated the carrying value of our salt water disposal assets. Based on our revised forecast, we determined that some were no longer expected to be used and wrote off the assets for total expense of $17.6 million during the three months ended March 31, 2020. These amounts are reported in loss on abandonment of assets in our unaudited condensed consolidated statements of operations. There were no additional triggering events identified during the three months ended June 30, 2020.
Contract Drilling
There were no impairments recorded during the three and six months ended June 30, 2021.
At March 31, 2020, due to market conditions, we performed impairment testing on two asset groups which were comprised of our SCR diesel-electric drilling rigs and our BOSS drilling rigs. We concluded that the net book value of the SCR drilling rigs asset group was not recoverable through estimated undiscounted cash flows and recorded a non-cash impairment charge of $407.1 million in the three months ended March 31, 2020. We also recorded an additional non-cash impairment charges of $3.0 million for other miscellaneous drilling equipment. These charges are included within impairments in our unaudited condensed consolidated statements of operations.
We used the income approach to determine the fair value of the SCR drilling rigs asset group. This approach uses significant assumptions including management’s best estimates of the expected future cash flows and the estimated useful life of the asset group. Fair value determination requires a considerable amount of judgement and is sensitive to changes in underlying assumptions and economic factors. As a result, there is no assurance the fair value estimates made for the impairment analysis will be accurate in the future. There were no additional triggering events identified during the three months ended June 30, 2020.
We concluded that no impairment was needed on the BOSS drilling rigs asset group as of March 31, 2020 as the undiscounted cash flows exceeded the $242.5 million carrying value of the asset group by a relatively minor margin. Some of the more sensitive assumptions used in evaluating the contract drilling rigs asset groups for potential impairment include forecasted utilization, gross margins, salvage values, discount rates, and terminal values. There were no additional triggering events identified during the three months ended June 30, 2020.
Mid-Stream
There were no impairments recorded during the three and six months ended June 30, 2021.
During the three months ended March 31, 2020, we determined that the carrying value of certain long-lived asset groups in southern Kansas, and central Oklahoma where lower pricing is expected to impact drilling and production levels, are not recoverable and exceeded their estimated fair value. We recorded non-cash impairment charges of $64.0 million based on the estimated fair value of the asset groups. These charges are included within impairments in our unaudited condensed consolidated statement of operations. There were no additional triggering events identified during the three months ended June 30, 2020.
NOTE 4 – REVENUE FROM CONTRACTS WITH CUSTOMERS
Our revenue streams are reported under three segments: oil and natural gas, contract drilling, and mid-stream which is consistent with how we report our segment revenue (as reflected in Note 18 – Industry Segment Information). Revenue from the oil and natural gas segment is from sales of our oil and natural gas production. Revenue from the contract drilling segment comes from contracting with upstream companies to drill an agreed-on number of wells or provide drilling rigs and services over an agreed-on period. Revenue from the mid-stream segment is derived from gathering, transporting, and processing natural gas and NGLs and selling those commodities.
Oil and Natural Gas Revenues
Certain costs—as either a deduction from revenue or as an expense—are determined based on when control of the commodity is transferred to our customer, which would affect our total revenue recognized, but will not affect gross profit. For example, gathering, processing, and transportation costs included as part of the contract price with the customer on transfer of control of the commodity are included in the transaction price, while costs incurred while we are in control of the commodity represent operating costs.
Contract Drilling Revenues
Mobilization and de-mobilization charges from our drilling contracts do not relate to a distinct good or service. These revenues should be deferred and recognized ratably over the related contract term that drilling services are provided. We have continued to record these revenues as a distinct service and the impact to our financial statements was immaterial. As of June 30, 2021, we had six contract drilling contracts with remaining terms ranging from two to seven months.
Most of our drilling contracts have an original term of less than one year. The remaining performance obligations under the contracts with a longer duration are not material.
Mid-Stream Contracts Revenues
Revenues are generated from fees earned for gas gathering and processing services provided to a customer or by selling hydrocarbons to other mid-stream companies. The typical revenue contracts used by this segment are gas gathering and processing agreements as well as product sales.
Contracts for gas gathering and processing services may include terms for demand fees or shortfall fees. Demand fees represent an arrangement where a customer agrees to pay a fixed fee for a contractually agreed upon pipeline capacity, which results in performance obligations for each individual period of reservation. Once the services have been completed, or the customer no longer has access to the contracted capacity, revenue is recognized.
The table below shows the changes in our mid-stream contract asset and contract liability balances during periods presented associated with demand fees and the impact to gas gathering and processing revenues:
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Classification on the unaudited condensed consolidated balance sheets
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June 30,
2021
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December 31,
2020
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Change
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|
(In thousands)
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|
Assets
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|
|
|
|
|
|
|
|
Current contract assets
|
Prepaid expenses and other
|
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$
|
3,226
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|
|
$
|
6,084
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|
|
$
|
(2,858)
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|
|
Non-current contract assets
|
Other assets
|
|
—
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|
|
173
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|
|
(173)
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Total contract assets
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|
$
|
3,226
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|
$
|
6,257
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|
$
|
(3,031)
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Liabilities
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Current contract liabilities
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Current portion of other long-term liabilities
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$
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2,098
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|
$
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2,583
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$
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(485)
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Non-current contract liabilities
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Other long-term liabilities
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626
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|
|
1,589
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|
(963)
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Total contract liabilities
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2,724
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|
4,172
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|
(1,448)
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Contract assets (liabilities), net
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$
|
502
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|
|
$
|
2,085
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|
|
$
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(1,583)
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|
Included below is the adjustment to demand fees from adopting ASC 606, Revenue from contracts with customers over the remaining term of the contracts as of June 30, 2021.
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Contract
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Remaining Term of Contract
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2021
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2022
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2023 and beyond
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Total Remaining Impact to Revenue
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(In thousands)
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Demand fee contracts
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4 - 16 months
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$
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(1,876)
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$
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1,374
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|
$
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—
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$
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(502)
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|
NOTE 5 – DIVESTITURES
Oil and Natural Gas
On June 25, 2021, the company entered into a purchase and sale agreement to which we agreed to sell substantially all of our wells and the leases related thereto located near Oklahoma City, Oklahoma for $19.5 million, subject to customary closing and post-closing adjustments. The divestiture closed on August 16, 2021, with an effective date of May 1, 2021. The sale of these assets will not result in a significant alteration of the full cost pool, and therefore no gain or loss will be recognized.
On March 30, 2021, the company entered into a purchase and sale agreement to which we agreed to sell substantially all of our wells and the leases related thereto located in Reno and Stafford Counties, Kansas for $7.1 million, subject to customary closing and post-closing adjustments. This divestiture closed on May 6, 2021, with an effective date of February 1, 2021. The sale of these assets did not result in a significant alteration of the full cost pool, and therefore no gain or loss was recognized.
We sold $4.4 million of other non-core oil and natural gas assets, net of related expenses, during the six months ended June 30, 2021, compared to $0.9 million during the six months ended June 30, 2020. These proceeds reduced the net book value of our full cost pool with no gain or loss recognized.
Contract Drilling
We sold non-core contract drilling assets for proceeds of $3.9 million, net of related expenses, during the six months ended June 30, 2021, compared to proceeds of $2.8 million during the six months ended June 30, 2020. These proceeds resulted in net gains of $2.1 million during the six months ended June 30, 2021, compared to $0.1 million during the six months ended June 30, 2020.
Corporate and Other
The company entered into a purchase and sale agreement to which we agreed to sell our corporate headquarters building and land with an anticipated closing date during the third quarter of 2021. The agreement remains subject to customary closing conditions. If the transaction closes, we plan to enter a multi-year lease for a portion of the building and no material gain or loss is expected.
NOTE 6 – CAPITAL STOCK
On June 16, 2021, the company repurchased an aggregate of 600,000 shares of its common stock from the Lenders (as defined in Note 9 - Long-Term Debt and Other Long-Term Liabilities) which received these shares as an exit fee during the company’s reorganization. The Lenders were paid $15.00 per share for their respective shares, for an aggregate cash purchase price of $9.0 million. The cash purchase price and direct acquisition costs are reflected as treasury stock on the condensed consolidated balance sheets as of June 30, 2021.
In June 2021, the company's board of directors (the Board) authorized repurchasing up to $25.0 million of the company’s outstanding common stock. The repurchases will be made through open market purchases, privately negotiated transactions, or other available means. The company has no obligation to repurchase any shares under the repurchase program and may suspend or discontinue it at any time without prior notice. As of June 30, 2021, no repurchases have been made under the share repurchase program.
NOTE 7 – LOSS PER SHARE
On the Effective Date, the company's shares outstanding immediately before the Effective Date were cancelled. Information related to the calculation of capital stock attributable to Unit Corporation is as follows:
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Earnings (Loss)
(Numerator)
|
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Weighted
Shares
(Denominator)
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Per-Share
Amount
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(In thousands except per share amounts)
|
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For the three months ended June 30, 2021 (Successor)
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|
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Basic loss attributable to Unit Corporation per common share
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|
$
|
(12,994)
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|
|
11,901
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|
|
$
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(1.09)
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|
|
Effect of dilutive stock options and restricted stock
|
|
—
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|
|
—
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|
|
—
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|
|
Diluted loss attributable to Unit Corporation per common share
|
|
$
|
(12,994)
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|
|
11,901
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|
|
$
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(1.09)
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For the three months ended June 30, 2020 (Predecessor)
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Basic loss attributable to Unit Corporation per common share
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|
$
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(215,649)
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|
53,503
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|
|
$
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(4.03)
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|
|
Effect of dilutive stock options and restricted stock
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|
—
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|
|
—
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|
|
—
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|
|
Diluted loss attributable to Unit Corporation per common share
|
|
$
|
(215,649)
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|
|
53,503
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|
|
$
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(4.03)
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Because of the net loss for the three months ended June 30, 2021, approximately 77,863 weighted average shares of restricted stock were antidilutive and were excluded from the earnings per share calculation above.
The following table shows the number of stock options (and their average exercise price) excluded because their option exercise prices were greater than the average market price of our common stock:
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Successor
|
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Predecessor
|
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Three Months Ended June 30, 2021
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Three Months Ended June 30, 2020
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Stock options
|
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—
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28,000
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Average exercise price
|
|
$
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—
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|
|
|
$
|
52.24
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Earnings (Loss) (Numerator)
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Weighted Shares (Denominator)
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Per-Share Amount
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(In thousands except per share amounts)
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For the six months ended June 30, 2021 (Successor)
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Basic loss attributable to Unit Corporation per common share
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$
|
(14,931)
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11,950
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|
|
$
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(1.25)
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|
|
Effect of dilutive stock options and restricted stock
|
|
—
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|
|
—
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|
|
—
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|
|
Diluted loss attributable to Unit Corporation per common share
|
|
$
|
(14,931)
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|
11,950
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|
|
$
|
(1.25)
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For the six months ended June 30, 2020 (Predecessor)
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|
|
|
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|
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Basic loss attributable to Unit Corporation per common share
|
|
$
|
(986,143)
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|
|
53,317
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|
|
$
|
(18.50)
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|
|
Effect of dilutive stock options and restricted stock
|
|
—
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|
|
—
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|
|
—
|
|
|
Diluted loss attributable to Unit Corporation per common share
|
|
$
|
(986,143)
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|
|
53,317
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|
|
$
|
(18.50)
|
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Because of the net loss for the six months ended June 30, 2021, approximately 39,147 weighted average shares of restricted stock were antidilutive and were excluded from the earnings per share calculation above.
The following table shows the number of stock options (and their average exercise price) excluded because their option exercise prices were greater than the average market price of our common stock:
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|
|
|
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|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
|
Six Months Ended June 30, 2021
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|
|
Six Months Ended June 30, 2020
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|
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|
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|
|
Stock options
|
|
—
|
|
|
|
28,000
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|
|
Average exercise price
|
|
$
|
—
|
|
|
|
$
|
52.24
|
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NOTE 8 – ACCRUED LIABILITIES
Accrued liabilities consisted of:
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|
|
|
|
|
|
June 30,
2021
|
|
December 31,
2020
|
|
|
|
(In thousands)
|
|
Employee costs
|
|
$
|
7,184
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|
|
$
|
8,878
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|
|
Lease operating expenses
|
|
3,686
|
|
|
6,405
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|
|
Capital expenditures
|
|
5,500
|
|
|
3,461
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|
|
Taxes
|
|
5,352
|
|
|
2,324
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|
|
Interest payable
|
|
303
|
|
|
884
|
|
|
Legal settlement
|
|
—
|
|
|
2,070
|
|
|
Other
|
|
1,723
|
|
|
1,182
|
|
|
Total accrued liabilities
|
|
$
|
23,748
|
|
|
$
|
25,204
|
|
NOTE 9 – LONG-TERM DEBT AND OTHER LONG-TERM LIABILITIES
Long-Term Debt
As of the date indicated, our long-term debt consisted of the following:
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30,
2021
|
|
December 31,
2020
|
|
|
|
(In thousands)
|
|
Current portion of long-term debt:
|
|
|
|
|
|
Exit credit agreement with an average interest rate of 6.7% and 6.6% at June 30, 2021 and December 31, 2020, respectively
|
|
$
|
—
|
|
|
$
|
600
|
|
|
Long-term debt:
|
|
|
|
|
|
Exit credit agreement with an average interest rate of 6.7% and 6.6% at June 30, 2021 and December 31, 2020, respectively
|
|
$
|
35,000
|
|
|
$
|
98,400
|
|
Exit Credit Agreement. On the Effective Date, under the terms of the Plan, the company entered into an amended and restated credit agreement (the Exit credit agreement), providing for a $140.0 million senior secured revolving credit facility (RBL Facility) and a $40.0 million senior secured term loan facility, among (i) the company, UDC, and UPC (together, the Borrowers), (ii) the guarantors party thereto, including the company and all of its subsidiaries existing as of the Effective Date (other than Superior Pipeline Company, L.L.C. and its subsidiaries), (iii) the lenders party thereto from time to time (Lenders), and (iv) BOKF, NA dba Bank of Oklahoma as administrative agent and collateral agent (in such capacity, the Administrative Agent).
The maturity date of borrowings under this Exit credit agreement is March 1, 2024. Revolving Loans and Term Loans (each as defined in the Exit credit agreement) may be Eurodollar Loans or ABR Loans (each as defined in the Exit credit agreement). Revolving Loans that are Eurodollar Loans will bear interest at a rate per annum equal to the Adjusted LIBO Rate (as defined in the Exit credit agreement) for the applicable interest period plus 525 basis points. Revolving Loans that are ABR Loans will bear interest at a rate per annum equal to the Alternate Base Rate (as defined in the Exit credit agreement) plus 425 basis points. Term Loans that are Eurodollar Loans will bear interest at a rate per annum equal to the Adjusted LIBO Rate for the applicable interest period plus 625 basis points. Term Loans that are ABR Loans will bear interest at a rate per annum equal to the Alternate Base Rate plus 525 basis points.
On April 6, 2021, the company finalized the first amendment to the Exit credit agreement. Under the first amendment, the company reaffirmed its borrowing base of $140.0 million of the RBL, amended certain financial covenants, and received less restrictive terms, among others, as it relates to the disposition of assets and the use of proceeds from those dispositions. On July 27, 2021, the company finalized the second amendment to the Exit credit agreement. Under the second amendment, the company obtained confirmation that the Term Loan had been paid in full prior to the amendment date and received one-time waivers related to the disposition of assets.
The Exit credit agreement requires the company to comply with certain financial ratios, including a covenant that the company will not permit the Net Leverage Ratio (as defined in the Exit credit agreement) as of the last day of the fiscal quarters ended (i) December 31, 2020 and March 31, 2021, to be greater than 4.00 to 1.00, (ii) June 30, 2021, September 30, 2021, December 31, 2021, March 31, 2022, and June 30, 2022, to be greater than 3.75 to 1.00, and (iii) September 30, 2022 and any fiscal quarter thereafter, to be greater than 3.50 to 1.00. In addition, beginning with the fiscal quarter ended December 31, 2020, the company may not (a) permit the Current Ratio (as defined in the Exit credit agreement) as of the last day of any fiscal quarter to be less than 1.00 to 1.00 or (b) permit the Interest Coverage Ratio (as defined in the Exit credit agreement) as of the last day of any fiscal quarter to be less than 2.50 to 1.00. The Exit credit agreement also contains provisions, among others, that limit certain capital expenditures, and require certain hedging activities. The Exit credit agreement further requires the company provide quarterly financial statements within 45 days after the end of each of the first three quarters of each fiscal year and annual financial statements within 90 days after the end of each fiscal year. As of June 30, 2021, Unit was in compliance with these covenants.
The Exit credit agreement is secured by first-priority liens on substantially all of the personal and real property assets of the Borrowers and the Guarantors, including the company’s ownership interests in Superior.
At June 30, 2021, we had $35.0 million of long-term borrowings and $2.8 million of letters of credit outstanding under the Exit credit agreement.
Superior Credit Agreement. On May 10, 2018, Superior signed a five-year, $200.0 million senior secured revolving credit facility with an option to increase the credit amount up to $250.0 million, subject to certain conditions (Superior credit agreement). The maturity date of borrowings under the Superior credit agreement is March 10, 2023. The amounts borrowed under the Superior credit agreement bear annual interest at a rate, at Superior’s option, equal to (a) LIBOR plus the applicable margin of 2.00% to 3.25% or (b) the alternate base rate (greater of (i) the federal funds rate plus 0.5%, (ii) the prime rate, and (iii) the Thirty-Day LIBOR Rate (as defined in the Superior credit agreement)) plus the applicable margin of 1.00% to 2.25%. The obligations under the Superior credit agreement are secured by mortgage liens on certain of Superior’s processing plants and gathering systems. The Superior credit agreement provides that if ICE Benchmark Administration no longer reports the LIBOR or Administrative Agent determines in good faith that the rate so reported no longer accurately reflects the rate available in the London Interbank Market or if such index no longer exists or accurately reflects the rate available to the Administrative Agent in the London Interbank Market, the Administrative Agent may select a replacement index.
Superior is charged a commitment fee of 0.375% on the amount available but not borrowed which varies based on the amount borrowed as a percentage of the total borrowing base.
The Superior credit agreement requires that Superior maintain a Consolidated EBITDA to interest expense ratio for the most-recently ended rolling four quarters of at least 2.50 to 1.00, and a funded debt to Consolidated EBITDA ratio of not greater than 4.00 to 1.00. The agreement also contains several customary covenants that restrict (subject to certain exceptions) Superior’s ability to incur additional indebtedness, create additional liens on its assets, make investments, pay distributions, sign sale and leaseback transactions, engage in certain transactions with affiliates, engage in mergers or consolidations, sign hedging arrangements, and acquire or dispose of assets. As of June 30, 2021, Superior was in compliance with these covenants.
The Superior credit agreement is used to fund capital expenditures and acquisitions and provide general working capital and letters of credit. As of June 30, 2021, we had no borrowings and $1.4 million of letters of credit outstanding under the Superior credit agreement.
Unit is not a party to and does not guarantee Superior's credit agreement.
Other Long-Term Liabilities
Other long-term liabilities consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30,
2021
|
|
December 31,
2020
|
|
|
|
(In thousands)
|
|
Asset retirement obligation (ARO) liability
|
|
$
|
23,172
|
|
|
$
|
23,356
|
|
|
Workers’ compensation
|
|
11,730
|
|
|
10,164
|
|
|
Finance lease obligations
|
|
—
|
|
|
3,216
|
|
|
Contract liability
|
|
2,724
|
|
|
4,172
|
|
|
Separation benefit plans
|
|
3,237
|
|
|
4,201
|
|
|
Gas balancing liability
|
|
4,238
|
|
|
3,997
|
|
|
Other long-term liability
|
|
1,321
|
|
|
1,321
|
|
|
|
|
46,422
|
|
|
50,427
|
|
|
Less current portion
|
|
7,551
|
|
|
11,168
|
|
|
Total other long-term liabilities
|
|
$
|
38,871
|
|
|
$
|
39,259
|
|
NOTE 10 – ASSET RETIREMENT OBLIGATIONS
We are required to record the estimated fair value of the liabilities relating to the future retirement of our long-lived assets. Our oil and natural gas wells are plugged and abandoned when the oil and natural gas reserves in those wells are depleted or the wells are no longer able to produce. The plugging and abandonment liability for a well is recorded in the period in which the obligation is incurred (at the time the well is drilled or acquired). None of our assets are restricted for purposes of settling these AROs. All our AROs relate to the plugging costs associated with our oil and gas wells.
The following table shows certain information about our estimated AROs for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
|
Six Months Ended June 30, 2021
|
|
|
Six Months Ended June 30, 2020
|
|
|
|
(In thousands)
|
|
ARO liability, January 1:
|
|
$
|
23,356
|
|
|
|
$
|
66,627
|
|
|
Accretion of discount
|
|
931
|
|
|
|
1,169
|
|
|
Liability incurred
|
|
1
|
|
|
|
460
|
|
|
Liability settled
|
|
(302)
|
|
|
|
(435)
|
|
|
Liability sold
|
|
(721)
|
|
|
|
(463)
|
|
|
Revision of estimates (1)
|
|
(93)
|
|
|
|
(3,110)
|
|
|
ARO liability, June 30:
|
|
23,172
|
|
|
|
64,248
|
|
|
Less: current portion
|
|
2,132
|
|
|
|
1,104
|
|
|
Total long-term ARO
|
|
$
|
21,040
|
|
|
|
$
|
63,144
|
|
_______________________
1.Plugging liability estimates were revised in 2020 for updates in the cost of services used to plug wells over the preceding year. We had various upward and downward adjustments.
NOTE 11 – STOCK-BASED COMPENSATION
On the Effective Date, the Board adopted the Unit Corporation Long Term Incentive Plan (LTIP) to incentivize employees, officers, directors and other service providers of the company and its affiliates. The LTIP provides for the grant, from time to time, at the discretion of the Board or a committee thereof, of stock options, stock appreciation rights, restricted stock, restricted stock units, stock awards, dividend equivalents, other stock-based awards, cash awards, performance awards, substitute awards or any combination of the foregoing. Subject to adjustment in the event of certain transactions or changes of capitalization in accordance with the LTIP, 903,226 shares of new common stock of the reorganized company (New Common Stock) have been reserved for issuance pursuant to awards under the LTIP. New Common Stock subject to an award that expires or is canceled, forfeited, exchanged, settled in cash, or otherwise terminated without delivery of shares and shares withheld to pay the exercise price of, or to satisfy the withholding obligations with respect to, an award will again be available for delivery pursuant to other awards under the LTIP. The LTIP will be administered by the Board or a committee thereof.
No stock options or restricted stock units were granted during the three or six months ended June 30, 2020, or during the three months ended March 31, 2021. On April 27, 2021, 109,008 aggregate restricted stock units were granted to the members of the Board pursuant to the LTIP with a weighted-average grant date fair value of $12.90 per unit. The fair value of these grants is measured based on the closing stock price on grant date and compensation expense is being recognized over a thirteen month vesting period in general and administrative on the unaudited condensed consolidated statements of operations.
Also on the Effective Date, the company's equity-based awards outstanding immediately before the Effective Date were cancelled. The cancellation of the awards resulted in an acceleration of unrecorded stock compensation expense during the Predecessor Period. Under the Plan, the company issued Warrants to holders of those equity-based awards that were outstanding immediately before the Effective Date who did not opt out of releases under the Plan.
For restricted stock awards and stock options, we had:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
Successor
|
|
|
Predecessor
|
|
|
Three Months Ended June 30, 2021
|
|
|
Three Months Ended June 30, 2020
|
|
Six Months Ended June 30, 2021
|
|
|
Six Months Ended June 30, 2020
|
|
|
(In thousands)
|
|
Recognized stock compensation expense
|
$
|
216
|
|
|
|
$
|
1,567
|
|
|
$
|
216
|
|
|
|
$
|
4,055
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tax benefit on stock-based compensation
|
$
|
53
|
|
|
|
$
|
392
|
|
|
$
|
53
|
|
|
|
$
|
1,014
|
|
NOTE 12 – DERIVATIVES
Commodity Derivatives
We have entered into various types of derivative transactions covering some of our projected natural gas, NGLs, and oil production. These transactions are intended to reduce our exposure to market price volatility by setting the price(s) we will receive for that production. Our decisions on the price(s), type, and quantity of our production subject to a derivative contract are based, in part, on our view of current and future market conditions as well as certain requirements stipulated in the Exit credit agreement. For further details, see Note 9 – Long-Term Debt and Other Long-Term Liabilities. As of June 30, 2021, our derivative transactions consisted of the following types of hedges:
•Basis/Differential Swaps. We receive or pay the NYMEX settlement value plus or minus a fixed delivery point price for the commodity and pay or receive the published index price at the specified delivery point. We use basis/differential swaps to hedge the price risk between NYMEX and its physical delivery points.
•Swaps. We receive or pay a fixed price for the commodity and pay or receive a floating market price to the counterparty. The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty.
•Collars. A collar contains a fixed floor price (put) and a ceiling price (call). If the market price exceeds the call strike price or falls below the put strike price, we receive the fixed price and pay the market price. If the market price is between the call and the put strike price, no payments are due from either party.
We do not engage in derivative transactions for speculative purposes. All derivatives are recognized on the unaudited condensed consolidated balance sheets and measured at fair value. Any changes in our derivatives' fair value occurring before their maturity (i.e., temporary fluctuations in value) are reported in loss on derivatives in our unaudited condensed consolidated statements of operations.
As of June 30, 2021, these derivatives were outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Term
|
|
Commodity
|
|
Contracted Volume
|
|
Weighted Average
Fixed Price
|
|
Contracted Market
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Jul'21 - Dec'21
|
|
Natural gas - basis swap
|
|
30,000 MMBtu/day
|
|
$(0.215)
|
|
NGPL TEXOK
|
|
|
|
|
|
|
|
|
|
|
|
Jul'21 - Oct'21
|
|
Natural gas - swap
|
|
50,000 MMBtu/day
|
|
$2.818
|
|
IF - NYMEX (HH)
|
|
Nov'21 - Dec'21
|
|
Natural gas - swap
|
|
45,000 MMBtu/day
|
|
$2.900
|
|
IF - NYMEX (HH)
|
|
Jan'22 - Dec'22
|
|
Natural gas - swap
|
|
5,000 MMBtu/day
|
|
$2.605
|
|
IF - NYMEX (HH)
|
|
Jan'23 - Dec'23
|
|
Natural gas - swap
|
|
22,000 MMBtu/day
|
|
$2.456
|
|
IF - NYMEX (HH)
|
|
|
|
|
|
|
|
|
|
|
|
Jan'22 - Dec'22
|
|
Natural gas - collar
|
|
35,000 MMBtu/day
|
|
$2.50 - $2.68
|
|
IF - NYMEX (HH)
|
|
|
|
|
|
|
|
|
|
|
|
Jul'21 - Dec'21
|
|
Crude oil - swap
|
|
3,373 Bbl/day
|
|
$45.57
|
|
WTI - NYMEX
|
|
Jan'22 - Dec'22
|
|
Crude oil - swap
|
|
2,300 Bbl/day
|
|
$42.25
|
|
WTI - NYMEX
|
|
Jan'23 - Dec'23
|
|
Crude oil - swap
|
|
1,300 Bbl/day
|
|
$43.60
|
|
WTI - NYMEX
|
The following tables present the fair values and locations of the derivative transactions recorded on our unaudited condensed consolidated balance sheets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative Liabilities
|
|
|
|
|
|
Fair Value
|
|
|
|
|
|
|
|
|
|
|
|
Classification on the unaudited condensed consolidated balance sheets
|
|
June 30,
2021
|
|
December 31,
2020
|
|
|
|
|
|
(In thousands)
|
|
Commodity derivatives:
|
|
|
|
|
|
|
|
Current
|
|
Current derivative liability
|
|
$
|
37,960
|
|
|
$
|
1,047
|
|
|
Long-term
|
|
Non-current derivative liability
|
|
23,270
|
|
|
4,659
|
|
|
Total derivative liabilities
|
|
|
|
$
|
61,230
|
|
|
$
|
5,706
|
|
All our counterparties are subject to master netting arrangements. If we have a legal right of set-off, we net the value of the derivative transactions we have with the same counterparty in our unaudited condensed consolidated balance sheets.
Following is the effect of derivative instruments on the unaudited condensed consolidated statements of operations for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
Successor
|
|
|
Predecessor
|
|
|
|
Three Months Ended June 30, 2021
|
|
|
Three Months Ended June 30, 2020
|
|
Six Months Ended June 30, 2021
|
|
|
Six Months Ended June 30, 2020
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In thousands)
|
|
Loss on derivatives:
|
|
|
|
|
|
|
|
|
|
|
|
Loss on derivatives, included are amounts settled during the period of $(6,403), $(1,243), $(9,707), and $(691), respectively
|
|
$
|
(42,400)
|
|
|
|
$
|
(6,937)
|
|
|
$
|
(65,231)
|
|
|
|
$
|
(6,454)
|
|
|
|
|
$
|
(42,400)
|
|
|
|
$
|
(6,937)
|
|
|
$
|
(65,231)
|
|
|
|
$
|
(6,454)
|
|
NOTE 13 – FAIR VALUE MEASUREMENTS
This disclosure of the estimated fair value of financial instruments is made under accounting guidance for financial instruments. We have determined the estimated fair values by using market information and certain valuation methodologies. Considerable judgment is required in interpreting market data to develop the estimates of fair value. Using different market assumptions or valuation methodologies may have a material effect on our estimated fair value amounts.
Fair value is defined as the amount that would be received from the sale of an asset or paid for transferring a liability in an orderly transaction between market participants (in either case, an exit price). To estimate an exit price, a three-level hierarchy is used prioritizing the valuation techniques used to measure fair value into three levels with the highest priority given to Level 1 and the lowest priority given to Level 3. The levels are summarized as follows:
•Level 1—unadjusted quoted prices in active markets for identical assets and liabilities.
•Level 2—significant observable pricing inputs other than quoted prices included within Level 1 either directly or indirectly observable as of the reporting date. Essentially, inputs (variables used in the pricing models) that are derived principally from or corroborated by observable market data.
•Level 3—generally unobservable inputs developed based on the best information available and may include our own internal data.
The inputs available to us determine the valuation technique we use to measure the fair values of our financial instruments.
The following tables set forth our recurring fair value measurements:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2021
|
|
|
|
Level 2
|
|
Level 3
|
|
Effect
of Netting
|
|
Net Amounts Presented
|
|
|
|
(In thousands)
|
|
Financial assets (liabilities):
|
|
|
|
|
|
|
|
|
|
Commodity derivatives:
|
|
|
|
|
|
|
|
|
|
Assets
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Liabilities
|
|
(61,230)
|
|
|
—
|
|
|
—
|
|
|
(61,230)
|
|
|
Total commodity derivatives
|
|
$
|
(61,230)
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(61,230)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2020
|
|
|
|
Level 2
|
|
Level 3
|
|
Effect
of Netting
|
|
Net Amounts Presented
|
|
|
|
(In thousands)
|
|
Financial assets (liabilities):
|
|
|
|
|
|
|
|
|
|
Commodity derivatives:
|
|
|
|
|
|
|
|
|
|
Assets
|
|
$
|
3,436
|
|
|
$
|
—
|
|
|
$
|
(3,436)
|
|
|
$
|
—
|
|
|
Liabilities
|
|
(9,142)
|
|
|
—
|
|
|
3,436
|
|
|
(5,706)
|
|
|
Total commodity derivatives
|
|
$
|
(5,706)
|
|
|
—
|
|
|
—
|
|
|
(5,706)
|
|
All our counterparties are subject to master netting arrangements. If a legal right of set-off exists, we net the value of the derivative transactions we have with the same counterparty. We are not required to post cash collateral with our counterparties and no collateral has been posted as of June 30, 2021.
We used the following methods and assumptions to estimate the fair values of the assets and liabilities in the table above. There were no transfers between Level 2 and Level 3 financial assets (liabilities).
Level 2 Fair Value Measurements
Commodity Derivatives. We measure the fair values of our crude oil and natural gas swaps and collars using estimated internal discounted cash flow calculations based on the NYMEX futures index.
Level 3 Fair Value Measurements
Commodity Derivatives. The fair values of our natural gas and crude oil three-way collars are estimated using internal discounted cash flow calculations based on forward price curves, quotes obtained from brokers for contracts with similar terms, or quotes obtained from counterparties to the agreements.
The following table is a reconciliation of our commodity derivatives Level 3 fair value measurements:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Derivatives
|
|
|
|
Successor
|
|
|
Predecessor
|
|
Successor
|
|
|
Predecessor
|
|
|
|
Three Months Ended June 30, 2021
|
|
|
Three Months Ended June 30, 2020
|
|
Six Months Ended June 30, 2021
|
|
|
Six Months Ended June 30, 2020
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In thousands)
|
|
Beginning of period
|
|
$
|
—
|
|
|
|
$
|
948
|
|
|
$
|
—
|
|
|
|
$
|
1,204
|
|
|
Total gains or losses (realized and unrealized):
|
|
|
|
|
|
|
|
|
|
|
|
Included in earnings (1)
|
|
—
|
|
|
|
714
|
|
|
—
|
|
|
|
1,277
|
|
|
Settlements
|
|
—
|
|
|
|
(819)
|
|
|
—
|
|
|
|
(1,638)
|
|
|
End of period
|
|
$
|
—
|
|
|
|
$
|
843
|
|
|
$
|
—
|
|
|
|
$
|
843
|
|
|
Total losses for the period included in earnings attributable to the change in unrealized gain (loss) relating to assets still held at end of period
|
|
$
|
—
|
|
|
|
$
|
(105)
|
|
|
$
|
—
|
|
|
|
$
|
(361)
|
|
_______________________
1.Commodity derivative activity is reported in the unaudited condensed consolidated statements of operations in gain (loss) on derivatives.
Our valuation at June 30, 2021 reflected that the risk of non-performance was immaterial.
Warrants. Warrants are recorded at their fair value utilizing the Black-Scholes-Merton option model. The inputs to the model require judgment, including estimating the strike price, expected term, and the associated volatility. The Warrants had fair values of $4.5 million and $0.9 million as of June 30, 2021 and December 31, 2020, respectively, with the change reflected as Loss on change in fair value of warrants in the unaudited condensed consolidated statements of operations. The Warrants will continue to be adjusted to fair value at each reporting period until the Warrants meet the definition of an equity instrument, at which time they will be reported as shareholders' equity and no longer subject to future fair value adjustments.
Fair Value of Other Financial Instruments
At June 30, 2021, the carrying values on the unaudited condensed consolidated balance sheets for cash and cash equivalents, accounts receivable, accounts payable, other current assets, and current liabilities approximate their fair value because of their short-term nature.
Fair Value of Non-Financial Instruments
The initial measurement of AROs at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with property, plant, and equipment. Significant Level 3 inputs used in the calculation of AROs include plugging costs and remaining reserve lives. A reconciliation of our AROs is presented in Note 10 – Asset Retirement Obligations.
NOTE 14 – LEASES
Lease Agreements. We lease certain office space, land, and equipment, including pipeline equipment and office equipment. Our lease payments are generally straight-line and the exercise of lease renewal options, which vary in term, is at our sole discretion. We include renewal periods in our lease term if we are reasonably certain to exercise available renewal options. Our operating lease agreements do not include options to purchase the leased property.
The following table sets forth the maturity of our operating lease liabilities as of June 30, 2021:
|
|
|
|
|
|
|
|
|
|
|
|
|
Amount
|
|
|
|
(In thousands)
|
|
Ending June 30,
|
|
|
|
2022
|
|
$
|
3,686
|
|
|
2023
|
|
1,528
|
|
|
2024
|
|
1,271
|
|
|
2025
|
|
86
|
|
|
2026
|
|
12
|
|
|
2027 and beyond
|
|
57
|
|
|
Total future payments
|
|
6,640
|
|
|
Less: Interest
|
|
269
|
|
|
Present value of future minimum operating lease payments
|
|
6,371
|
|
|
Less: Current portion
|
|
3,515
|
|
|
Total long-term operating lease payments
|
|
$
|
2,856
|
|
Finance Leases under ASC 842
In 2014, Superior entered into finance lease agreements for 20 compressors with initial terms of seven years and an option to purchase the assets at 10% of their then fair market value at the end of the term. These finance leases were discounted using annual rates of 4.00% and the underlying assets were included in gas gathering and processing equipment. In May 2021, Superior purchased the leased assets for $3.0 million.
The following table shows information about our lease assets and liabilities on our unaudited condensed consolidated balance sheets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Classification on the unaudited condensed consolidated balance sheets
|
|
June 30,
2021
|
|
December 31,
2020
|
|
|
|
|
|
(In thousands)
|
|
Assets
|
|
|
|
|
|
|
|
Operating right of use assets
|
|
Right of use assets
|
|
$
|
6,406
|
|
|
$
|
5,592
|
|
|
Finance right of use assets
|
|
Property, plant, and equipment, net
|
|
—
|
|
|
7,281
|
|
|
Total right of use assets
|
|
|
|
$
|
6,406
|
|
|
$
|
12,873
|
|
|
|
|
|
|
|
|
|
|
Liabilities
|
|
|
|
|
|
|
|
Current liabilities:
|
|
|
|
|
|
|
|
Operating lease liabilities
|
|
Current operating lease liabilities
|
|
$
|
3,515
|
|
|
$
|
4,075
|
|
|
Finance lease liabilities
|
|
Current portion of other long-term liabilities
|
|
—
|
|
|
3,216
|
|
|
Non-current liabilities:
|
|
|
|
|
|
|
|
Operating lease liabilities
|
|
Operating lease liabilities
|
|
2,856
|
|
|
1,445
|
|
|
Finance lease liabilities
|
|
Other long-term liabilities
|
|
—
|
|
|
—
|
|
|
Total lease liabilities
|
|
|
|
$
|
6,371
|
|
|
$
|
8,736
|
|
The following table shows certain information related to the lease costs for our finance and operating leases for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
Successor
|
|
|
Predecessor
|
|
|
|
Three Months Ended June 30, 2021
|
|
|
Three Months Ended June 30, 2020
|
|
Six Months Ended June 30, 2021
|
|
|
Six Months Ended June 30, 2020
|
|
|
|
(In thousands)
|
|
Components of total lease cost:
|
|
|
|
|
|
|
|
|
|
|
|
Amortization of finance leased assets
|
|
$
|
181
|
|
|
|
$
|
1,036
|
|
|
$
|
1,248
|
|
|
|
$
|
2,061
|
|
|
Interest on finance lease liabilities
|
|
4
|
|
|
|
60
|
|
|
33
|
|
|
|
130
|
|
|
Operating lease cost
|
|
984
|
|
|
|
1,395
|
|
|
2,011
|
|
|
|
2,640
|
|
|
Short-term lease cost (1)
|
|
3,179
|
|
|
|
2,751
|
|
|
5,771
|
|
|
|
6,742
|
|
|
Variable lease cost
|
|
—
|
|
|
|
83
|
|
|
—
|
|
|
|
165
|
|
|
Total lease cost
|
|
$
|
4,348
|
|
|
|
$
|
5,325
|
|
|
$
|
9,063
|
|
|
|
$
|
11,737
|
|
_______________________
1.Short-term lease cost includes amounts capitalized related to our oil and natural gas segment of $0.1 million, $0.4 million, $0.2 million, and $1.4 million for the three and six months ended June 30, 2021 and June 30, 2020, respectively.
The following table shows supplemental cash flow information related to leases for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
|
Six Months Ended June 30, 2021
|
|
|
Six Months Ended June 30, 2020
|
|
|
|
(In thousands)
|
|
Cash paid for amounts in the measurement of lease liabilities:
|
|
|
|
|
|
|
Operating cash flows for operating leases
|
|
$
|
2,063
|
|
|
|
$
|
2,827
|
|
|
Financing cash flows for finance leases
|
|
$
|
3,216
|
|
|
|
$
|
2,061
|
|
The following table shows certain information related to the weighted average remaining lease terms and the weighted average discount rates for our operating and finance leases:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average Remaining Lease Term
|
|
Weighted Average Discount
Rate (1)
|
|
|
|
(In years)
|
|
|
|
Operating leases
|
|
2.4
|
|
3.81%
|
|
|
|
|
|
|
_______________________
1.Our weighted average discount rates represent the rate implicit in the lease or our incremental borrowing rate for a term equal to the remaining term of the lease.
NOTE 15 – COMMITMENTS AND CONTINGENCIES
Commitments
We have firm transportation commitments to transport our natural gas from various systems for approximately $1.0 million over the next twelve months and $0.2 million for the six months thereafter.
During the second quarter of 2018, as part of the Superior transaction (see description in Note 16 – Variable Interest Entity Arrangements), we entered into a contractual obligation committing us to spend $150.0 million to drill wells in the Granite Wash/Buffalo Wallow area over three years starting January 1, 2019. For each dollar of the $150.0 million we do not spend (over the three-year period), we would forgo receiving $0.58 of future distributions from our ownership interest in Superior. At June 30, 2021, if we elected not to drill or spend any additional money in the designated area before December 31, 2021, the maximum amount we could forgo from distributions would be $72.6 million. The total amount spent towards the $150.0 million as of June 30, 2021 was $24.8 million. We do not anticipate meeting the contractual obligation over the remaining commitment period.
Environmental
We manage our exposure to environmental liabilities on properties to be acquired by identifying existing problems and assessing the potential liability. We also conduct periodic reviews, on a company-wide basis, to identify changes in our environmental risk profile. These reviews evaluate whether there is a probable liability, its amount, and the likelihood that the liability will be incurred. Any potential liability is determined by considering, among other matters, incremental direct costs of any likely remediation and the proportionate cost of employees expected to devote significant time directly to any possible remediation effort. As it relates to evaluations of purchased properties, depending on the extent of an identified environmental problem, we may exclude a property from the acquisition, require the seller to remediate the property to our satisfaction, or agree to assume liability for the remediation of the property.
We have not historically experienced significant environmental liability while being a contract driller since the greatest portion of that risk is borne by the operator. Any liabilities we have incurred have been small and were resolved while the drilling rig was on the location. Those costs were in the direct cost of drilling the well.
Litigation
The company is subject to litigation and claims arising in the ordinary course of business which may include environmental, health and safety matters, or more routine employment related claims. The company accrues for such items when a liability is both probable and the amount can be reasonably estimated. As new information becomes available or because of legal or administrative rulings in similar matters or a change in applicable law, the company's conclusions regarding the probability of outcomes and the amount of estimated loss, if any, may change. Although we are insured against various risks, there is no assurance that the nature and amount of that insurance will be adequate, in every case, to indemnify us against liabilities arising from future legal proceedings.
On May 22, 2020, the Debtors filed petitions for relief under Chapter 11 of the Bankruptcy Code. The commencement of the Chapter 11 Cases automatically stayed all the proceedings and actions against the Debtors (other than certain regulatory enforcement matters). The Debtors emerged from the Chapter 11 Cases on the Effective Date. On the Effective Date, the automatic stay was terminated and replaced with the injunction provisions in the Confirmation Order and the Plan.
In 2013, the company’s exploration and production subsidiary, UPC, drilled a well in Beaver County, Oklahoma. Certain operational issues arose and one of the working interest owners in the well filed a lawsuit claiming that UPC’s actions violated its duties under the joint operating agreement and caused damages to the owners in the well. The case went to trial in January 2019 and the jury issued a verdict in favor of the working interest owner, awarding $2.4 million in damages, including pre- and post-judgment interest. UPC appealed the verdict, and while it was pending review in the Oklahoma Court of Civil Appeals, UPC finalized a settlement agreement with the working interest owner for $2.1 million in February 2021.
The commencement of the Chapter 11 Cases also automatically stayed all proceedings and actions against the Predecessor company (other than certain regulatory enforcement matters). Effective at emergence from the Chapter 11 Cases, the automatic stay was terminated and replaced with the injunction provisions in the Confirmation Order and the Plan.
Below is a summary of two lawsuits and the respective treatment of those cases in the Chapter 11 Cases.
Cockerell Oil Properties, Ltd., v. Unit Petroleum Company, No. 16-cv-135-JHP, United States District Court for the
Eastern District of Oklahoma.
On March 11, 2016, a putative class action lawsuit was filed against UPC styled Cockerell Oil Properties, Ltd., v. Unit Petroleum Company in LeFlore County, Oklahoma. We removed the case to federal court in the Eastern District of Oklahoma. The plaintiff alleges that UPC wrongfully failed to pay interest with respect to late paid oil and gas proceeds under Oklahoma’s Production Revenue Standards Act. The lawsuit seeks actual and punitive damages, an accounting, disgorgement, injunctive relief, and attorney fees. Plaintiff is seeking relief on behalf of royalty and working interest owners in our Oklahoma wells.
Chieftain Royalty Company v. Unit Petroleum Company, No. CJ-16-230, District Court of LeFlore County, Oklahoma.
On November 3, 2016, a putative class action lawsuit was filed against UPC styled Chieftain Royalty Company v. Unit Petroleum Company in LeFlore County, Oklahoma. The plaintiff alleges that UPC breached its duty to pay royalties on natural gas used for fuel off the lease premises. The lawsuit seeks actual and punitive damages, an accounting, injunctive relief, and attorney’s fees. Plaintiff is seeking relief on behalf of Oklahoma citizens who are or were royalty owners in our Oklahoma wells.
Pending Settlement
In August 2020, UPC reached an agreement to settle these class actions. Under the settlement, UPC agreed to recognize class proof of claims in the amount of $15.75 million for Cockerell Oil Properties, Ltd. vs. Unit Petroleum Company, and $29.25 million in Chieftain Royalty Company vs. Unit Petroleum Company. This settlement is subject to certain conditions, including approval by the United States Bankruptcy Court for the Southern District of Texas, Houston Division in Case No. 20-32740 under the caption In re Unit Corporation, et al. Under the Plan, these settlements will be treated as allowed general unsecured claims against UPC. And, in accordance with the Plan, the settlement amounts will be satisfied by distribution of the plaintiffs’ proportionate share of New Common Stock.
NOTE 16 – VARIABLE INTEREST ENTITY ARRANGEMENTS
On April 3, 2018 we sold 50% of the ownership interest in Superior. The 50% interest in Superior we sold was acquired by SP Investor, a holding company jointly owned by OPTrust and funds managed and/or advised by Partners Group, a global private markets investment manager. Superior is governed and managed under the Amended and Restated Limited Liability Company Agreement (Agreement) and a Management Services Agreement (MSA). The MSA is between our wholly-owned subsidiary, SPC Midstream Operating, L.L.C. (the Operator) and Superior. As the Operator, we provide services, like operations and maintenance support, accounting, legal, and human resources to Superior for a monthly service fee of $263,280. Superior's creditors have no recourse to our general credit. Unit is not a party to and does not guarantee Superior's credit agreement. The obligations under Superior's credit agreement are secured by, among other things, mortgage liens on certain of Superior’s processing plants and gathering systems.
The Agreement specifies how future distributions are to be allocated among the Members. Future distributions may be from available cash or made in conjunction with a sale event (both as defined in the Agreement). In certain circumstances, future distributions could result in Unit receiving distributions that are disproportionately lower than its ownership percentage. Circumstances that could result in Unit receiving less than a proportionate share of future distributions include, but may not be limited to, Unit not fulfilling the drilling commitment described in Note 15 – Commitments and Contingencies or a cumulative return to SP Investor of less than the 7% Liquidation IRR Hurdle provided for SP Investor in the Agreement. Generally, the 7% Liquidation IRR Hurdle calculation requires cumulative distributions to SP Investor in excess of its original $300.0 million investment sufficient to provide SP Investor a 7% IRR on its capital contributions to Superior before any liquidation distribution is made to Unit. After the fifth anniversary of the effective date of the sale, either owner may force a sale of Superior to a third-party or a liquidation of Superior's assets.
Effective at emergence from the Chapter 11 Cases, we record our share of earnings and losses from Superior using the hypothetical liquidation at book value (HLBV) method of accounting which is a balance-sheet approach that calculates the amount we would have received if Superior were liquidated at book value at the end of each measurement period. The change in our allocated amount during the period is recognized in our unaudited condensed consolidated statements of operations. On the sale or liquidation of Superior, distributions would occur in the order and priority specified in the relevant agreements.
Under the guidance in ASC 810, Consolidation, we have determined that Superior is a VIE. The two variable interests applicable to Unit include the 50% equity investment in Superior and the MSA. The MSA gives us the power to direct the activities that most significantly affect Superior's operating performance. The MSA is a separate variable interest. Under the MSA, Unit has the power to direct Superior’s most significant activities; reciprocally the equity investors lack the power to direct the activities that most affect the entity’s economic performance. Because of this, Unit is considered the primary beneficiary. There have been no changes to the primary beneficiary during the quarter ended June 30, 2021.
As the primary beneficiary of this VIE, we consolidate in our financial statements the financial position, results of operations, and cash flows of this VIE. All intercompany balances and transactions between us and the VIE are eliminated in our unaudited condensed consolidated financial statements. Cash distributions of income, net of agreed on expenses, and estimated expenses are allocated to the equity owners as specified in the relevant agreements.
Superior paid cash distributions totaling $24.7 million in April 2021 related to cumulative available cash as of March 31, 2021 and $7.7 million in July 2021 related to available cash generated during the three months ended June 30, 2021. Unit and SP Investor each received 50% of these distributions. See Note 15 – Commitments and Contingencies for discussion of the Granite Wash/Buffalo Wallow drilling commitment and the potential impact on future distributions.
The amounts below reflect the eliminations of intercompany transactions and balances consistent with the presentation in the unaudited condensed consolidated balance sheets.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30,
2021
|
|
December 31,
2020
|
|
|
|
(In thousands)
|
|
|
|
|
|
|
|
Current assets:
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
6,484
|
|
|
$
|
11,642
|
|
|
Accounts receivable
|
|
27,034
|
|
|
27,427
|
|
|
Prepaid expenses and other
|
|
3,890
|
|
|
6,746
|
|
|
Total current assets
|
|
37,408
|
|
|
45,815
|
|
|
Property and equipment:
|
|
|
|
|
|
Gas gathering and processing equipment
|
|
255,338
|
|
|
251,403
|
|
|
Transportation equipment
|
|
1,965
|
|
|
1,748
|
|
|
|
|
257,303
|
|
|
253,151
|
|
|
Less accumulated depreciation, depletion, amortization, and impairment
|
|
26,736
|
|
|
10,466
|
|
|
Net property and equipment
|
|
230,567
|
|
|
242,685
|
|
|
Right of use asset
|
|
4,419
|
|
|
2,823
|
|
|
Other assets
|
|
1,973
|
|
|
2,309
|
|
|
Total assets
|
|
$
|
274,367
|
|
|
$
|
293,632
|
|
|
|
|
|
|
|
|
Current liabilities:
|
|
|
|
|
|
Accounts payable
|
|
$
|
20,349
|
|
|
$
|
17,045
|
|
|
Accrued liabilities
|
|
4,541
|
|
|
3,777
|
|
|
Current operating lease liability
|
|
1,646
|
|
|
1,762
|
|
|
Current portion of other long-term liabilities
|
|
2,116
|
|
|
5,799
|
|
|
Total current liabilities
|
|
28,652
|
|
|
28,383
|
|
|
|
|
|
|
|
|
Operating lease liability
|
|
626
|
|
|
1,013
|
|
|
Other long-term liabilities
|
|
2,773
|
|
|
1,589
|
|
|
Total liabilities
|
|
$
|
32,051
|
|
|
$
|
30,985
|
|
NOTE 17 – INCOME TAXES
For the three and six months ended June 30, 2021, the company’s effective income tax rate was 0% compared to 2.9% and 0.96% for the three and six months ended June 30, 2020. The decrease was due to the continued need of a full valuation allowance against our net deferred tax asset coming out of bankruptcy and as a result of fresh start accounting. These rates differ from the statutory rate of 21% mostly due to changes in our valuation allowance, our non-controlling interests in consolidated subsidiaries, and state income taxes.
Deferred Tax Asset Valuation Allowance
The company has concluded that it is more likely than not that the net deferred tax asset will not be realized and has recorded a full valuation allowance, reducing the net deferred tax asset as of June 30, 2021, to zero. The company will continue to evaluate whether the valuation allowance is needed in future reporting periods and it will remain until the company can conclude that the net deferred tax assets are more likely than not to be realized. Future events or new evidence which may lead the company to conclude that it is more likely than not its net deferred tax assets will be realized include, but are not limited to, cumulative historical pre-tax earnings, significant improvements in commodity prices, significant increase in rig utilization, a material and sizable asset acquisition, and taxable events that could result from one or more future potential transactions. The valuation allowance does not prohibit the company from utilizing the tax attributes if the company recognizes taxable income. As long as the company continues to conclude that the valuation allowance against its net deferred tax assets is necessary, the company will not have significant deferred income tax expense or benefit.
NOTE 18 – INDUSTRY SEGMENT INFORMATION
We have three main business segments offering different products and services within the energy industry:
•Oil and natural gas,
•Contract drilling, and
•Mid-Stream
Our oil and natural gas segment is engaged in the acquisition, development, and production of oil, NGLs, and natural gas properties. The contract drilling segment is engaged in the land contract drilling of oil and natural gas wells and the mid-stream segment is engaged in the buying, selling, gathering, processing, and treating of natural gas and NGLs.
We evaluate each segment’s performance based on its operating income, which is defined as operating revenues less operating expenses and depreciation, depletion, amortization, and impairment. We have no oil and natural gas production outside the United States.
The following tables provide certain information about the operations of each of our segments:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
|
Three Months Ended June 30, 2021
|
|
|
|
Oil and Natural Gas
(2)
|
|
Contract Drilling
|
|
Mid-Stream
|
|
Corporate and Other
|
|
Eliminations (3)
|
|
Total Consolidated
|
|
|
|
(In thousands)
|
|
Revenues: (1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas
|
|
$
|
59,776
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(17,806)
|
|
|
$
|
41,970
|
|
|
Contract drilling
|
|
—
|
|
|
18,061
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
18,061
|
|
|
Gas gathering and processing
|
|
—
|
|
|
—
|
|
|
66,323
|
|
|
—
|
|
|
7,703
|
|
|
74,026
|
|
|
Total revenues
|
|
59,776
|
|
|
18,061
|
|
|
66,323
|
|
|
—
|
|
|
(10,103)
|
|
|
134,057
|
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas
|
|
16,350
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(863)
|
|
|
15,487
|
|
|
Contract drilling
|
|
—
|
|
|
14,080
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
14,080
|
|
|
Gas gathering and processing
|
|
—
|
|
|
—
|
|
|
55,176
|
|
|
—
|
|
|
(10,120)
|
|
|
45,056
|
|
|
Total operating costs
|
|
16,350
|
|
|
14,080
|
|
|
55,176
|
|
|
—
|
|
|
(10,983)
|
|
|
74,623
|
|
|
Depreciation, depletion, and amortization
|
|
6,476
|
|
|
1,570
|
|
|
8,064
|
|
|
254
|
|
|
—
|
|
|
16,364
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expenses
|
|
22,826
|
|
|
15,650
|
|
|
63,240
|
|
|
254
|
|
|
(10,983)
|
|
|
90,987
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4,871
|
|
|
880
|
|
|
5,751
|
|
|
Gain on disposition of assets
|
|
(67)
|
|
|
(1,618)
|
|
|
—
|
|
|
(25)
|
|
|
—
|
|
|
(1,710)
|
|
|
Income (loss) from operations
|
|
37,017
|
|
|
4,029
|
|
|
3,083
|
|
|
(5,100)
|
|
|
—
|
|
|
39,029
|
|
|
Loss on derivatives
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(42,400)
|
|
|
—
|
|
|
(42,400)
|
|
|
Loss on change in fair value of warrants
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(3,574)
|
|
|
—
|
|
|
(3,574)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reorganization items, net
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1,852)
|
|
|
—
|
|
|
(1,852)
|
|
|
Interest, net
|
|
—
|
|
|
—
|
|
|
641
|
|
|
(1,128)
|
|
|
—
|
|
|
(487)
|
|
|
Other
|
|
34
|
|
|
11
|
|
|
(850)
|
|
|
(26)
|
|
|
—
|
|
|
(831)
|
|
|
Income (loss) before income taxes
|
|
$
|
37,051
|
|
|
$
|
4,040
|
|
|
$
|
2,874
|
|
|
$
|
(54,080)
|
|
|
$
|
—
|
|
|
$
|
(10,115)
|
|
_______________________
1.The revenues for oil and natural gas occur at a point in time. The revenues for contract drilling and gas gathering and processing occur over time.
2.Reflects one-time adjustments to correct errors discovered in our prior period accrual of oil and natural gas revenues as well as oil and natural gas operating costs, as described in Note 2 - Summary Of Significant Accounting Policies.
3.Reflects one-time adjustments to correct errors discovered in our inter-segment eliminations presentation, as described in Note 2 - Summary Of Significant Accounting Policies.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Predecessor
|
|
|
|
Three Months Ended June 30, 2020
|
|
|
|
Oil and Natural Gas
|
|
Contract Drilling
|
|
Mid-Stream
|
|
Corporate and Other
|
|
Eliminations
|
|
Total Consolidated
|
|
|
|
(In thousands)
|
|
Revenues: (1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas
|
|
$
|
26,957
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(1)
|
|
|
$
|
26,956
|
|
|
Contract drilling
|
|
—
|
|
|
29,202
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
29,202
|
|
|
Gas gathering and processing
|
|
—
|
|
|
—
|
|
|
37,719
|
|
|
—
|
|
|
(4,870)
|
|
|
32,849
|
|
|
Total revenues
|
|
26,957
|
|
|
29,202
|
|
|
37,719
|
|
|
—
|
|
|
(4,871)
|
|
|
89,007
|
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas
|
|
72,354
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(814)
|
|
|
71,540
|
|
|
Contract drilling
|
|
—
|
|
|
20,951
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
20,951
|
|
|
Gas gathering and processing
|
|
—
|
|
|
—
|
|
|
26,669
|
|
|
—
|
|
|
(4,057)
|
|
|
22,612
|
|
|
Total operating costs
|
|
72,354
|
|
|
20,951
|
|
|
26,669
|
|
|
—
|
|
|
(4,871)
|
|
|
115,103
|
|
|
Depreciation, depletion, and amortization
|
|
22,059
|
|
|
2,946
|
|
|
10,348
|
|
|
607
|
|
|
—
|
|
|
35,960
|
|
|
Impairments
|
|
109,318
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
109,318
|
|
|
Total expenses
|
|
203,731
|
|
|
23,897
|
|
|
37,017
|
|
|
607
|
|
|
(4,871)
|
|
|
260,381
|
|
|
General and administrative
|
|
—
|
|
|
—
|
|
|
—
|
|
|
25,814
|
|
|
—
|
|
|
25,814
|
|
|
(Gain) loss on disposition of assets
|
|
(45)
|
|
|
(548)
|
|
|
(9)
|
|
|
1,479
|
|
|
—
|
|
|
877
|
|
|
Income (loss) from operations
|
|
(176,729)
|
|
|
5,853
|
|
|
711
|
|
|
(27,900)
|
|
|
—
|
|
|
(198,065)
|
|
|
Loss on derivatives
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(6,937)
|
|
|
—
|
|
|
(6,937)
|
|
|
Write-off of debt issuance costs
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(2,426)
|
|
|
—
|
|
|
(2,426)
|
|
|
Reorganization items, net
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(7,027)
|
|
|
—
|
|
|
(7,027)
|
|
|
Interest, net
|
|
—
|
|
|
—
|
|
|
(542)
|
|
|
(7,066)
|
|
|
—
|
|
|
(7,608)
|
|
|
Other
|
|
9
|
|
|
6
|
|
|
22
|
|
|
6
|
|
|
—
|
|
|
43
|
|
|
Income (loss) before income taxes
|
|
$
|
(176,720)
|
|
|
$
|
5,859
|
|
|
$
|
191
|
|
|
$
|
(51,350)
|
|
|
—
|
|
|
$
|
(222,020)
|
|
_______________________
1.The revenues for oil and natural gas occur at a point in time. The revenues for contract drilling and gas gathering and processing occur over time.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
|
Six Months Ended June 30, 2021
|
|
|
|
Oil and Natural Gas
(2)
|
|
Contract Drilling
|
|
Mid-Stream
|
|
Corporate and Other
|
|
Eliminations
|
|
Total Consolidated
|
|
|
|
(In thousands)
|
|
Revenues: (1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas
|
|
$
|
114,801
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(17,807)
|
|
|
$
|
96,994
|
|
|
Contract drilling
|
|
—
|
|
|
33,735
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
33,735
|
|
|
Gas gathering and processing
|
|
—
|
|
|
—
|
|
|
125,932
|
|
|
—
|
|
|
(1,707)
|
|
|
124,225
|
|
|
Total revenues
|
|
114,801
|
|
|
33,735
|
|
|
125,932
|
|
|
—
|
|
|
(19,514)
|
|
|
254,954
|
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas
|
|
36,343
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1,707)
|
|
|
34,636
|
|
|
Contract drilling
|
|
—
|
|
|
25,951
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
25,951
|
|
|
Gas gathering and processing
|
|
—
|
|
|
—
|
|
|
104,286
|
|
|
—
|
|
|
(19,567)
|
|
|
84,719
|
|
|
Total operating costs
|
|
36,343
|
|
|
25,951
|
|
|
104,286
|
|
|
—
|
|
|
(21,274)
|
|
|
145,306
|
|
|
Depreciation, depletion, and amortization
|
|
14,131
|
|
|
3,145
|
|
|
16,096
|
|
|
503
|
|
|
—
|
|
|
33,875
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expenses
|
|
50,474
|
|
|
29,096
|
|
|
120,382
|
|
|
503
|
|
|
(21,274)
|
|
|
179,181
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative
|
|
—
|
|
|
—
|
|
|
—
|
|
|
11,160
|
|
|
1,760
|
|
|
12,920
|
|
|
(Gain) loss on disposition of assets
|
|
(87)
|
|
|
(2,146)
|
|
|
75
|
|
|
(24)
|
|
|
—
|
|
|
(2,182)
|
|
|
Income (loss) from operations
|
|
64,414
|
|
|
6,785
|
|
|
5,475
|
|
|
(11,639)
|
|
|
—
|
|
|
65,035
|
|
|
Loss on derivatives
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(65,231)
|
|
|
—
|
|
|
(65,231)
|
|
|
Loss on change in fair value of warrants
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(3,574)
|
|
|
—
|
|
|
(3,574)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reorganization items, net
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(2,988)
|
|
|
—
|
|
|
(2,988)
|
|
|
Interest, net
|
|
—
|
|
|
—
|
|
|
(416)
|
|
|
(2,777)
|
|
|
—
|
|
|
(3,193)
|
|
|
Other
|
|
90
|
|
|
16
|
|
|
(839)
|
|
|
(22)
|
|
|
—
|
|
|
(755)
|
|
|
Income (loss) before income taxes
|
|
$
|
64,504
|
|
|
$
|
6,801
|
|
|
$
|
4,220
|
|
|
$
|
(86,231)
|
|
|
$
|
—
|
|
|
$
|
(10,706)
|
|
_______________________ ____________________
1.The revenues for oil and natural gas occur at a point in time. The revenues for contract drilling and gas gathering and processing occur over time.
2.Reflects a one-time adjustment to correct an error discovered in our prior period accrual of oil and natural gas operating costs, as described in Note 2 - Summary Of Significant Accounting Policies.
.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Predecessor
|
|
|
|
Six Months Ended June 30, 2020
|
|
|
|
Oil and Natural Gas
|
|
Contract Drilling
|
|
Mid-Stream
|
|
Corporate and Other
|
|
Eliminations
|
|
Total Consolidated
|
|
|
|
(In thousands)
|
|
Revenues: (1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas
|
|
$
|
75,481
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(3)
|
|
|
$
|
75,478
|
|
|
Contract drilling
|
|
—
|
|
|
65,834
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
65,834
|
|
|
Gas gathering and processing
|
|
—
|
|
|
—
|
|
|
80,399
|
|
|
—
|
|
|
(10,328)
|
|
|
70,071
|
|
|
Total revenues
|
|
75,481
|
|
|
65,834
|
|
|
80,399
|
|
|
—
|
|
|
(10,331)
|
|
|
211,383
|
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas
|
|
103,769
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1,566)
|
|
|
102,203
|
|
|
Contract drilling
|
|
—
|
|
|
46,400
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
46,400
|
|
|
Gas gathering and processing
|
|
—
|
|
|
—
|
|
|
58,988
|
|
|
—
|
|
|
(8,765)
|
|
|
50,223
|
|
|
Total operating costs
|
|
103,769
|
|
|
46,400
|
|
|
58,988
|
|
|
—
|
|
|
(10,331)
|
|
|
198,826
|
|
|
Depreciation, depletion, and amortization
|
|
58,787
|
|
|
14,691
|
|
|
22,621
|
|
|
1,478
|
|
|
—
|
|
|
97,577
|
|
|
Impairments
|
|
377,154
|
|
|
410,126
|
|
|
63,962
|
|
|
—
|
|
|
—
|
|
|
851,242
|
|
|
Total expenses
|
|
539,710
|
|
|
471,217
|
|
|
145,571
|
|
|
1,478
|
|
|
(10,331)
|
|
|
1,147,645
|
|
|
Loss on abandonment of assets
|
|
17,554
|
|
#N/A
|
—
|
|
#N/A
|
—
|
|
#N/A
|
—
|
|
#N/A
|
—
|
|
#N/A
|
17,554
|
|
|
General and administrative
|
|
—
|
|
|
—
|
|
|
—
|
|
|
37,367
|
|
|
—
|
|
|
37,367
|
|
|
(Gain) loss on disposition of assets
|
|
(58)
|
|
|
(139)
|
|
|
(15)
|
|
|
1,479
|
|
|
—
|
|
|
1,267
|
|
|
Loss from operations
|
|
(481,725)
|
|
|
(405,244)
|
|
|
(65,157)
|
|
|
(40,324)
|
|
|
—
|
|
|
(992,450)
|
|
|
Loss on derivatives
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(6,454)
|
|
|
—
|
|
|
(6,454)
|
|
|
Write-off of debt issuance costs
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(2,426)
|
|
|
—
|
|
|
(2,426)
|
|
|
Reorganization items, net
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(7,027)
|
|
|
—
|
|
|
(7,027)
|
|
|
Interest, net
|
|
—
|
|
|
—
|
|
|
(1,060)
|
|
|
(19,805)
|
|
|
—
|
|
|
(20,865)
|
|
|
Other
|
|
30
|
|
|
23
|
|
|
39
|
|
|
11
|
|
|
—
|
|
|
103
|
|
|
Loss before income taxes
|
|
$
|
(481,695)
|
|
|
$
|
(405,221)
|
|
|
$
|
(66,178)
|
|
|
(76,025)
|
|
|
$
|
—
|
|
|
$
|
(1,029,119)
|
|
_______________________
1.The revenues for oil and natural gas occur at a point in time. The revenues for contract drilling and gas gathering and processing occur over time.
NOTE 19 – SUPPLEMENTAL CONDENSED CONSOLIDATING FINANCIAL INFORMATION
The Notes of the Predecessor company were registered securities until they were cancelled on the Effective Date. As a result, we are required to present the following condensed consolidating financial information for the Predecessor Periods under Rule 3-10 of the SEC's Regulation S-X, Financial Statements of Guarantors and Issuers of Guaranteed Securities Registered or Being Registered. Our Successor Exit credit agreement is not a registered security. Therefore, the presentation of condensed consolidating financial information is not required for the Successor period.
For the following footnote:
•we were called "Parent",
•the direct subsidiaries were 100% owned by the Parent and the guarantee was full and unconditional and joint and several and called "Combined Guarantor Subsidiaries", and
•Superior and its subsidiaries and the Operator were called "Non-Guarantor Subsidiaries."
The following unaudited supplemental condensed consolidating financial information reflects the Parent's separate accounts, the combined accounts of the Combined Guarantor Subsidiaries', the combined accounts of the Non-Guarantor Subsidiaries', the combined consolidating adjustments and eliminations, and the Parent's consolidated amounts for the periods indicated.
Condensed Consolidating Statements of Operations (Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Predecessor
|
|
|
Three Months Ended June 30, 2020
|
|
|
Parent
|
|
Combined Guarantor Subsidiaries
|
|
Combined Non-Guarantor Subsidiaries
|
|
Consolidating Adjustments
|
|
Total Consolidated
|
|
|
(In thousands)
|
|
Revenues
|
$
|
—
|
|
|
$
|
56,159
|
|
|
$
|
37,719
|
|
|
$
|
(4,871)
|
|
|
$
|
89,007
|
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
Operating costs
|
—
|
|
|
93,305
|
|
|
26,671
|
|
|
(4,873)
|
|
|
115,103
|
|
|
Depreciation, depletion, and amortization
|
607
|
|
|
25,005
|
|
|
10,348
|
|
|
—
|
|
|
35,960
|
|
|
Impairments
|
—
|
|
|
109,318
|
|
|
—
|
|
|
—
|
|
|
109,318
|
|
|
General and administrative
|
—
|
|
|
25,814
|
|
|
—
|
|
|
—
|
|
|
25,814
|
|
|
(Gain) loss on disposition of assets
|
1,479
|
|
|
(593)
|
|
|
(9)
|
|
|
—
|
|
|
877
|
|
|
Total operating costs
|
2,086
|
|
|
252,849
|
|
|
37,010
|
|
|
(4,873)
|
|
|
287,072
|
|
|
Income (loss) from operations
|
(2,086)
|
|
|
(196,690)
|
|
|
709
|
|
|
2
|
|
|
(198,065)
|
|
|
Interest, net
|
(7,066)
|
|
|
—
|
|
|
(542)
|
|
|
—
|
|
|
(7,608)
|
|
|
Write-off of debt issuance costs
|
(2,426)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(2,426)
|
|
|
Loss on derivatives
|
(6,937)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(6,937)
|
|
|
Reorganization items, net
|
(2,205)
|
|
|
(4,822)
|
|
|
—
|
|
|
—
|
|
|
(7,027)
|
|
|
Other, net
|
4
|
|
|
18
|
|
|
21
|
|
|
—
|
|
|
43
|
|
|
Income (loss) before income taxes
|
(20,716)
|
|
|
(201,494)
|
|
|
188
|
|
|
2
|
|
|
(222,020)
|
|
|
Income tax benefit
|
(6,455)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(6,455)
|
|
|
Equity in net earnings from investment in subsidiaries, net of taxes
|
(201,304)
|
|
|
—
|
|
|
—
|
|
|
201,304
|
|
|
—
|
|
|
Net income (loss)
|
(215,565)
|
|
|
(201,494)
|
|
|
188
|
|
|
201,306
|
|
|
(215,565)
|
|
|
Less: net income attributable to non-controlling interest
|
84
|
|
|
—
|
|
|
84
|
|
|
(84)
|
|
|
84
|
|
|
Net income (loss) attributable to Unit Corporation
|
$
|
(215,649)
|
|
|
$
|
(201,494)
|
|
|
$
|
104
|
|
|
$
|
201,390
|
|
|
$
|
(215,649)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Predecessor
|
|
|
Six Months Ended June 30, 2020
|
|
|
Parent
|
|
Combined Guarantor Subsidiaries
|
|
Combined Non-Guarantor Subsidiaries
|
|
Consolidating Adjustments
|
|
Total Consolidated
|
|
|
(In thousands)
|
|
Revenues
|
$
|
—
|
|
|
$
|
141,315
|
|
|
$
|
80,399
|
|
|
$
|
(10,331)
|
|
|
$
|
211,383
|
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
Operating costs
|
—
|
|
|
150,169
|
|
|
58,988
|
|
|
(10,331)
|
|
|
198,826
|
|
|
Depreciation, depletion, and amortization
|
1,478
|
|
|
73,478
|
|
|
22,621
|
|
|
—
|
|
|
97,577
|
|
|
Impairments
|
—
|
|
|
787,280
|
|
|
63,962
|
|
|
—
|
|
|
851,242
|
|
|
Loss on abandonment of assets
|
—
|
|
|
17,554
|
|
|
—
|
|
|
—
|
|
|
17,554
|
|
|
General and administrative
|
—
|
|
|
37,367
|
|
|
—
|
|
|
—
|
|
|
37,367
|
|
|
(Gain) loss on disposition of assets
|
1,479
|
|
|
(197)
|
|
|
(15)
|
|
|
—
|
|
|
1,267
|
|
|
Total operating costs
|
2,957
|
|
|
1,065,651
|
|
|
145,556
|
|
|
(10,331)
|
|
|
1,203,833
|
|
|
Loss from operations
|
(2,957)
|
|
|
(924,336)
|
|
|
(65,157)
|
|
|
—
|
|
|
(992,450)
|
|
|
Interest, net
|
(19,805)
|
|
|
—
|
|
|
(1,060)
|
|
|
—
|
|
|
(20,865)
|
|
|
Write-off of debt issuance costs
|
(2,426)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(2,426)
|
|
|
Loss on derivatives
|
(6,454)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(6,454)
|
|
|
Reorganization items, net
|
(2,205)
|
|
|
(4,822)
|
|
|
—
|
|
|
—
|
|
|
(7,027)
|
|
|
Other, net
|
11
|
|
|
53
|
|
|
39
|
|
|
—
|
|
|
103
|
|
|
Loss before income taxes
|
(33,836)
|
|
|
(929,105)
|
|
|
(66,178)
|
|
|
—
|
|
|
(1,029,119)
|
|
|
Income tax benefit
|
(9,880)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(9,880)
|
|
|
Equity in net earnings from investment in subsidiaries, net of taxes
|
(995,283)
|
|
|
—
|
|
|
—
|
|
|
995,283
|
|
|
—
|
|
|
Net loss
|
(1,019,239)
|
|
|
(929,105)
|
|
|
(66,178)
|
|
|
995,283
|
|
|
(1,019,239)
|
|
|
Less: net loss attributable to non-controlling interest
|
(33,096)
|
|
|
—
|
|
|
(33,096)
|
|
|
33,096
|
|
|
(33,096)
|
|
|
Net loss attributable to Unit Corporation
|
$
|
(986,143)
|
|
|
$
|
(929,105)
|
|
|
$
|
(33,082)
|
|
|
$
|
962,187
|
|
|
$
|
(986,143)
|
|
Condensed Consolidating Statements of Cash Flows (Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Predecessor
|
|
|
Six Months Ended June 30, 2020
|
|
|
Parent
|
|
Combined Guarantor Subsidiaries
|
|
Combined Non-Guarantor Subsidiaries
|
|
Consolidating Adjustments
|
|
Total Consolidated
|
|
|
(In thousands)
|
|
OPERATING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) operating activities
|
$
|
(201,699)
|
|
|
$
|
59,486
|
|
|
$
|
20,117
|
|
|
$
|
148,563
|
|
|
$
|
26,467
|
|
|
INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
(760)
|
|
|
(13,428)
|
|
|
(9,616)
|
|
|
—
|
|
|
(23,804)
|
|
|
Producing properties and other acquisitions
|
—
|
|
|
(210)
|
|
|
—
|
|
|
—
|
|
|
(210)
|
|
|
Proceeds from disposition of assets
|
1,169
|
|
|
3,253
|
|
|
75
|
|
|
—
|
|
|
4,497
|
|
|
Net cash provided by (used in) investing activities
|
409
|
|
|
(10,385)
|
|
|
(9,541)
|
|
|
—
|
|
|
(19,517)
|
|
|
FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
Borrowings under credit agreement, including borrowings under DIP credit facility
|
47,300
|
|
|
—
|
|
|
32,100
|
|
|
—
|
|
|
79,400
|
|
|
Payments under credit agreement
|
(23,500)
|
|
|
—
|
|
|
(14,600)
|
|
|
—
|
|
|
(38,100)
|
|
|
DIP financing costs
|
(990)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(990)
|
|
|
Intercompany borrowings (advances), net
|
198,503
|
|
|
(49,169)
|
|
|
(771)
|
|
|
(148,563)
|
|
|
—
|
|
|
Payments on finance leases
|
—
|
|
|
—
|
|
|
(2,061)
|
|
|
—
|
|
|
(2,061)
|
|
|
Employee taxes paid by withholding shares
|
(43)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(43)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Bank overdrafts
|
(7,269)
|
|
|
—
|
|
|
(1,464)
|
|
|
—
|
|
|
(8,733)
|
|
|
Net cash provided by (used in) financing activities
|
214,001
|
|
|
(49,169)
|
|
|
13,204
|
|
|
(148,563)
|
|
|
29,473
|
|
|
Net increase (decrease) in cash and cash equivalents
|
12,711
|
|
|
(68)
|
|
|
23,780
|
|
|
—
|
|
|
36,423
|
|
|
Cash and cash equivalents, beginning of period
|
503
|
|
|
68
|
|
|
—
|
|
|
—
|
|
|
571
|
|
|
Cash and cash equivalents, end of period
|
$
|
13,214
|
|
|
$
|
—
|
|
|
$
|
23,780
|
|
|
$
|
—
|
|
|
$
|
36,994
|
|
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