Principles of Consolidation. The consolidated financial statements include the accounts of Unit Corporation and its subsidiaries. We consolidate the activities of Superior, a 50/50 joint venture between Unit and SP Investor Holdings, LLC, which qualifies as a VIE under generally accepted accounting principles in the United States (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 19 – Variable Interest Entity Arrangements.

Effective at emergence, we record our share of earnings and losses from Superior using the HLBV method of accounting. The HLBV 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 Consolidated Statements of Operations. On the sale or liquidation of Superior, distributions would occur in the order and priority specified in the relevant agreements.

Fresh Start Accounting. The consolidated financial statements in Note 3 - Fresh Start Accounting have been prepared in accordance with Financial Accounting Standard Board (FASB) ASC Topic 852, Reorganizations. 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 consolidated financial statements. This was reflected in our Consolidated Balance Sheets as of September 1, 2020. Accordingly, our consolidated financial statements and notes after September 1, 2020, are not comparable to the consolidated financial statements and notes before that date. To facilitate the financial statement presentations, we refer to the reorganized company in these 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 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 have applied the relevant guidance provided in U.S. GAAP regarding the accounting and financial statement disclosures for entities that have filed petitions with the bankruptcy court and reorganized as going concerns in preparing the consolidated financial statements and notes through the period ended August 31, 2020, or the Predecessor Period. That guidance requires, for periods after our bankruptcy filing on May 22, 2020, or post-petition periods, certain transactions and events that were directly related to our reorganization be distinguished from our normal business operations. Accordingly, certain expenses, realized gains, and losses and provisions that were realized or incurred in the Chapter 11 Cases have been included in "Reorganization items, net" on our Consolidated Statements of Operations. In addition, certain liabilities and other obligations incurred before May 22, 2020, or pre-petition periods, have been classified as "Liabilities subject to compromise" on our Predecessor Consolidated Balance Sheets through August 31, 2020. See Note 3 – Fresh Start Accounting for further detail.

Accounting Estimates. Preparing financial statements in conformity with generally accepted accounting principles (GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Drilling Contracts. Because we not do bear the risk of completion of the well, we recognize revenues and expenses generated from “daywork” drilling contracts as the services are performed. Typically, this type of contract can be used for the drilling of one well which can take from 10 to 90 days. At December 31, 2020, all our contracts were daywork contracts of which five were multi-well and had durations which ranged from two months to one year, three of which expire in 2021 and two expiring in 2022. These longer-term contracts may contain a fixed rate for the duration of the contract or provide for the periodic renegotiation of the rate within a specific range from the existing rate.

Cash Equivalents and Bank Overdrafts. We include as cash equivalents all investments with maturities at date of purchase of three months or less which are readily convertible into known amounts of cash. Bank overdrafts are checks issued before the end of the period, but not presented to our bank for payment before the end of the period. At December 31, 2020 and 2019, bank overdrafts were $2.6 million and $8.7 million, respectively.

Accounts Receivable. Accounts receivable is carried on a gross basis, with no discounting, less an allowance for doubtful accounts. We estimate the allowance for doubtful accounts based on existing economic conditions, the financial condition of our customers, and the amount and age of past due accounts. Receivables are considered past due if full payment is not received by the contractual due date. Past due accounts are generally written off against the allowance for doubtful accounts only after all collection attempts have been unsuccessful.

Financial Instruments and Concentrations of Credit Risk and Non-performance Risk. Financial instruments, which potentially subject us to concentrations of credit risk, consist primarily of trade receivables with a variety of oil and natural gas companies. We do not generally require collateral related to our receivables. Our credit risk is considered limited due to the


	Successor		Predecessor
	Period September 1, 2020 through December 31, 2020		Period January 1, 2020 through August 31, 2020		For the Year Ended December 31, 2019

Oil and Natural Gas:
CVR Refining, LP	14	%	15	%	14	%
Plains Marketing L.P.	*		11	%	*
Drilling:
EOG Resources, Inc.	28	%	20	%	12	%
QEP Resources, Inc.	23	%	10	%	12	%
Citizen Energy III, LLC	16	%	*		*
Slawson Exploration Company, Inc.	16	%	21	%	11	%
Cimarex Energy Co.	12	%	*		*
Mid-Stream:
ONEOK, Inc.	28	%	31	%	33	%
Range Resources Corporation	15	%	21	%	13	%
Centerpoint Energy Service, Inc.	*		*		10	%

Using derivative transactions also involves the risk that the counterparties cannot meet the financial terms of the transactions. We considered this non-performance risk regarding our counterparties and our own non-performance risk in our derivative valuation at December 31, 2020 and determined there was no material risk at that time. At December 31, 2020, the fair values of the net liabilities we had with each of the counterparties regarding our commodity derivative transactions are listed in the table below:

Property and Equipment. Drilling equipment, transportation equipment, gas gathering and processing systems, and other property and equipment are carried at cost less accumulated depreciation. Renewals and enhancements are capitalized while repairs and maintenance are expensed. Prior to emergence from bankruptcy, we recorded depreciation of drilling equipment using the units-of-production method based on estimated useful lives starting at 15 years, including a minimum provision of 20% of the active rate when the equipment is idle, unless idle for greater than 48 months, then it was depreciated at the full active rate. We also used the composite method of depreciation for drill pipe and collars and calculate the depreciation by footage drilled compared to total estimated remaining footage. As of emergence, we elected to depreciate all drilling assets utilizing the straight-line method over the useful lives of the assets ranging from four to ten years. Depreciation on our corporate building is computed using the straight-line method over the estimated useful life of the asset for 39 years. Depreciation of other property and equipment is computed using the straight-line method over the estimated useful lives of the assets ranging from 3 to 15 years.

We review the carrying amounts of long-lived assets for potential impairment when events occur or changes in circumstances suggest these carrying amounts may not be recoverable. Changes that could prompt an assessment include equipment obsolescence, changes in the market demand for a specific asset, changes in commodity prices, periods of relatively low drilling rig utilization, declining revenue per day, declining cash margin per day, or overall changes in general market conditions. Assets are determined to be impaired if a forecast of undiscounted estimated future net operating cash flows directly

related to the asset, including disposal value if any, is less than the carrying amount of the asset. If any asset is determined to be impaired, the loss is measured as the amount by which the carrying asset exceeds its fair value. The estimate of fair value is based on the best information available, including prices for similar assets. Changes in these estimates could cause us to reduce the carrying value of property and equipment. Asset impairment evaluations are, by nature, highly subjective. They involve expectations about future cash flows generated by our assets and reflect our assumptions and judgments regarding future industry conditions and their effect on future utilization levels, dayrates, and costs. Using different estimates and assumptions could result in materially different carrying values of our assets.

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 first quarter of 2020. We also recorded an additional non-cash impairment charge of $3.0 million for other miscellaneous drilling equipment. These charges are included within impairment charge in our 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.

We concluded that no impairment was needed on the BOSS drilling rigs asset group as the undiscounted cash flows exceeded the carrying value of the asset group. The carrying value of the asset group was approximately $242.5 million at March 31, 2020. The estimated undiscounted cash flows of the BOSS drilling rigs asset group exceeded the carrying value by a relatively minor margin, which means minor changes in certain key assumptions in future periods may result in material impairment charges in future periods. 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.

During the third quarter of 2019, we determined a triggering event had occurred within our contract drilling segment due to a decline in the number of drilling rigs being used and the overall market performance of the contract drilling industry. As a result, we performed a recoverability test on long-lived assets within that segment. Based on the results of the undiscounted future cash flows of that asset group, the undiscounted projected future cash flows of the asset group exceeded the group's carrying value as of September 30, 2019 and therefore no long-lived asset impairment was recorded for the group.

When property and equipment components are disposed of, the cost and the related accumulated depreciation are removed from the accounts and any resulting gain or loss is generally reflected in operations. For dispositions of drill pipe and drill collars, an average cost for the appropriate feet of drill pipe and drill collars is removed from the asset account and charged to accumulated depreciation and proceeds, if any, are credited to accumulated depreciation.

For our gas gathering and processing systems, 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. Based on the estimated fair value of the asset groups, we recorded non-cash impairment charges of $64.0 million. These charges are included within impairment charges in our Consolidated Statement of Operations.

Capitalized Interest. During 2019, interest of approximately $16.2 million was capitalized based on the net book value associated with unproved oil and gas properties not being amortized, constructing additional drilling rigs, and constructing gas gathering systems. Interest is being capitalized using a weighted average interest rate based on our outstanding borrowings. We did not capitalize any interest in 2020.

additionally when events indicate an impairment may have occurred. For impairment testing, goodwill is evaluated at the reporting unit level. Our goodwill is all related to our contract drilling segment, and, the impairment test is generally based on the estimated discounted future net cash flows of our drilling segment, using discount rates and other factors in determining the fair value of our drilling segment. Inputs in our estimated discounted future net cash flows include drilling rig utilization, day rates, gross margin percentages, and terminal value. Due to the triggering event within the contract drilling segment, we performed an interim goodwill impairment test as of September 30, 2019. Based on the projected discounted cash flows, we recognized a goodwill impairment charge of $62.8 million, pre-tax ($59.8 million, net of tax) which represented total goodwill we previously reported on our Consolidated Balance Sheets. There were no additions to goodwill in 2020 or 2019.

Oil and Natural Gas Properties. We account for our oil and natural gas exploration and development activities using the full cost method of accounting prescribed by the SEC. All productive and non-productive costs incurred in connection with the acquisition, exploration, and development of our oil, NGLs, and natural gas reserves, including directly related overhead costs and related asset retirement costs. Directly related overhead costs of $16.5 million were capitalized in 2019. We did not capitalize any directly related overhead costs in 2020. Capitalized costs are amortized on a units-of-production method based on proved oil and natural gas reserves. The calculation of DD&A includes all capitalized costs, estimated future expenditures to be incurred in developing proved reserves and estimated dismantlement and abandonment costs, net of estimated salvage values less accumulated amortization, unproved properties, and equipment not placed in service. The average rates used for DD&A were $4.21, $7.77, and $9.66 per Boe in the Successor Period of 2020, the Predecessor Period of 2020, and for the year 2019, respectively.

During the fourth quarter 2019, we reassessed estimated salvage values associated with our oil and natural gas operations. Based on market conditions for our industry and the substantial doubt that existed for our ability to continue as a going concern, we revised these estimates downward for a total adjustment of $39.7 million ($25.6 million discounted for our full cost ceiling test) to salvage value estimates.

No gains or losses are recognized on the sale, conveyance, or other disposition of oil and natural gas properties unless a significant reserve amount to our total reserves is involved. Revenue from the sale of oil and natural gas is recognized when title passes, net of royalties.

Successor Period Impairments. As of September 1, 2020, we adopted fresh start accounting and adjusted our assets to fair value. Although under fresh start accounting we recorded our assets at fair value on emergence, the application of the full cost accounting rules resulted in non-cash ceiling test write-downs of $26.1 million pre-tax for Successor Period primarily due to the use of average 12-month historical commodity prices for the ceiling test versus forward prices for our Fresh Start fair value estimates.

It is hard to predict with any certainty the need for or amount of any future impairments given the many factors that go into the ceiling test calculation including, but not limited to, future pricing, operating costs, drilling and completion costs, upward or downward oil and gas reserve revisions, oil and gas reserve additions, and tax attributes. Subject to these inherent uncertainties, if we hold these same factors constant as they existed at December 31, 2020, and only adjust the 12-month average price as of March 2021, our forward-looking expectation is that we will not recognize an impairment in the first quarter of 2021. Given the uncertainty associated with the factors used in calculating our estimate of our future period ceiling test write-down, these estimates should not necessarily be construed as indicative of our future plans or financial results and the actual amount of any write-down may vary significantly from this estimate depending on the final future determination.

Predecessor Period Impairments. We determined the value of certain unproved oil and gas properties were diminished (in part or in whole) based on an impairment evaluation and our anticipated future exploration plans. Those determinations resulted in $226.5 million and $73.9 million in 2020 and 2019, respectively, of costs being added to the total of our capitalized costs being amortized. We recorded non-cash ceiling test write-downs of $393.7 million pre-tax ($346.6 million, net of tax) in the Predecessor Period of 2020 due to the reduction for the 12-month average commodity prices and the impairment of our unproved oil and gas properties described above. We incurred non-cash ceiling test write-downs of $559.4 million pre-tax ($422.4 million, net of tax) in 2019.

In addition to the impairment evaluations of our proved and unproved oil and gas properties in the first quarter of 2020, we also evaluated the carrying value of our salt water disposal assets. Based on our revised forecast of the use of those assets, we determined that some of those assets were no longer expected to be used and we wrote off those salt water disposal assets that we now consider abandoned. We recorded total expense of $17.6 million related to the write-down of those salt water

Our contract drilling segment provides drilling services for our oil and natural gas segment. Revenues and expenses for these services are eliminated in our statement of operations, with any profit recognized reducing our investment in our oil and natural gas properties. The contracts for these services are issued under the similar terms and rates as the contracts entered into with unrelated third parties. By providing drilling services for the oil and natural gas segment, we eliminated $1.6 million of intercompany profit during 2019 as a reduction to the carrying value of our oil and natural gas properties. We did not eliminate any profit in 2020 due to no drilling services being provided during the period.

ARO. We record the fair value of liabilities associated with the future plugging and abandonment of our wells. When the reserves in each of our oil or gas wells becoming fully depleted or otherwise become uneconomical, we incur costs to plug and abandon the wells. These future costs are recorded at the time the wells are drilled or acquired. We have no assets restricted to settle these ARO liabilities. Our engineering staff uses historical experience to determine the estimated plugging costs considering the type of well (either oil or natural gas), the depth of the well, the physical location of the well, and the ultimate productive life to determine the estimated plugging costs. A risk-adjusted discount rate and an inflation factor are used on these estimated costs to determine the present value of this obligation. To the extent any change in these assumptions affect future revisions and impact the present value of the existing ARO, a corresponding adjustment is made to the full cost pool.

Insurance. We are self-insured for certain losses relating to workers’ compensation, control of well and employee medical benefits. Insured policies for other coverage contain deductibles or retentions per occurrence that range from zero to $1.0 million. We have purchased stop-loss coverage to limit, to the extent feasible, per occurrence and aggregate exposure to certain types of claims. There is no assurance that the insurance coverages we have will adequately protect us against liability from all potential consequences. If insurance coverage becomes more expensive, we may choose to self-insure, decrease our limits, raise our deductibles, or any combination of these rather than pay higher premiums.

Derivative Activities. All derivatives are recognized on the balance sheet and measured at fair value. Any changes in our derivatives' fair value before their maturity (i.e., temporary fluctuations in value) are reported in gain (loss) on derivatives in our Consolidated Statements of Operations. Cash settlements received or paid for matured, early-terminated, and modified derivatives are reported in cash receipts (payments) on derivatives settled in our Consolidated Statements of Cash Flows.

Limited Partnerships. Unit Petroleum Company was a general partner in 13 oil and natural gas limited partnerships. Some of our officers, directors, and employees owned the interests in most of these partnerships. We shared in each partnership’s revenues and costs under formulas set out in the limited partnership agreement. The partnerships also reimbursed us for certain administrative costs incurred on behalf of the partnerships. The partnerships were terminated in the second quarter of 2019 with an effective date of January 1, 2019 at a repurchase cost of $0.6 million, net of Unit's interest.

Income Taxes. Measurement of net deferred tax liabilities is based on provisions of enacted tax law; the effects of future changes in tax laws or rates are not included in the measurement. Valuation allowances are established where needed to reduce deferred tax assets to the amount expected to be realized. Income tax expense is the tax payable for the year and the change during that year in deferred tax assets and liabilities.

The accounting for uncertainty in income taxes prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a return. Guidance is also provided on de-recognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition.

Natural Gas Balancing. We account for revenue transactions under ASC 606 for recording natural gas sales, which may be more or less than our share of pro-rata production from certain wells. We estimate our December 31, 2020 balancing position to be approximately 3.3 Bcf on under-produced properties and approximately 3.3 Bcf on over-produced properties. We have recorded a receivable of $3.4 million on certain wells where we estimate that insufficient reserves are available for us to recover our under-production from future production volumes. We have also recorded a liability of $4.0 million on certain properties where there are insufficient reserves available to allow the under-produced owners to recover their under-production from future production volumes. Our policy is to expense the pro-rata share of lease operating costs from all wells as incurred. Such expenses relating to the balancing position on wells in which we have imbalances are not material.

Employee and Director Stock Based Compensation. We recognize the cost of employee services received in exchange for awards of equity instruments based on the grant date fair value of those awards. Our equity compensation cost relating to employees directly involved in exploration activities of our oil and natural gas segment is capitalized to our oil and natural gas properties. Amounts not capitalized to our oil and natural gas properties are recognized in general and administrative expense and operating costs of our business segments. We used the Black-Scholes option pricing model to measure the fair value of stock options and SARs. The value of our restricted stock grants was based on the closing stock price on the date of the grants. On the Effective Date, all unvested restricted stock and un-exercised stock options were cancelled. The cancellation of the awards resulted in an acceleration of unrecorded stock compensation expense during the Predecessor Period. See Note 14 – Stock-Based Compensation for further detail.

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 generally accepted accounting principles 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 consolidated financial statements.

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 will be effective for reporting periods beginning after December 15, 2020. Early adoption is permitted. This standard will not have a material impact on our consolidated financial statements.

Measurement of Credit Losses on Financial Instruments (Topic 326). The FASB issued ASU 2016-13 which replaces current methods for evaluating impairment of financial instruments not measured at fair value, including trade accounts receivable, and certain debt securities, with a current expected credit loss model (CECL). The CECL model is expected to result in more timely recognition of credit losses. The amendment was effective for reporting periods after December 15, 2019. The adoption of this guidance did not have a material impact on our consolidated financial statements or related disclosures.

Fair Value Measurement (Topic 820): Disclosure Framework—Changes to the Disclosure Requirements for Fair Value Measurement. The FASB issued ASU 2018-13 to modify the disclosure requirements in Topic 820. Part of the disclosures were removed or modified, and other disclosures were added. The amendment was effective for reporting periods beginning after December 15, 2019. The adoption of this guidance did not have a material impact on our consolidated financial statements or related disclosures.