Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Please read this discussion of our financial condition and results of operations with the consolidated financial statements and related notes in Item 8 of this report.
General
We were founded in 1963 as a contract drilling company. Today, we operate, manage, and analyze our results of operations through our three principal business segments:
•Oil and Natural Gas – carried out by our subsidiary Unit Petroleum Company. This segment explores, develops, acquires, and produces oil and natural gas properties for our own account.
•Contract Drilling – carried out by our subsidiary Unit Drilling Company. This segment contracts to drill onshore oil and natural gas wells for others and for our own account.
•Mid-Stream – carried out by our subsidiary Superior Pipeline Company, L.L.C. and its subsidiaries. This segment buys, sells, gathers, processes, and treats natural gas for third parties and for our own account. We own 50% of this subsidiary.
Recent Developments
Emergence From Voluntary Reorganization Under Chapter 11 of the Bankruptcy Code
On May 22, 2020, the Debtors filed petitions for reorganization under Chapter 11 of Title 11 of the United States Code in the United States Bankruptcy Court for the Southern District of Texas, Houston Division. The Chapter 11 proceedings were jointly administered under the caption In re Unit Corporation, et al., Case No. 20-32740 (DRJ) (Chapter 11 Cases). During the pendency of the Chapter 11 Cases, the Debtors operated their business as "debtors-in-possession" under the authority of the bankruptcy court and under the Bankruptcy Code.
The Debtors filed their Plan and the related disclosure statement with the bankruptcy court on June 9, 2020. 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” [Docket No. 340] (Confirmation Order) confirming the Plan. On the Effective Date, the Debtors emerged from the Chapter 11 Cases. For more information regarding the Chapter 11 Cases and other related matters, please read Note 2 – Emergence From Voluntary Reorganization Under Chapter 11.
Fresh Start Accounting
On the Effective Date, we qualified for and adopted fresh start accounting under the provisions set forth in FASB Topic ASC 852 as (i) the reorganization value of the company’s assets immediately before the date of confirmation was less than the post-petition liabilities and allowed claims, and (ii) the holders of the existing voting shares of the Predecessor prior to emergence received less than 50% of the voting shares of the emerging entity. As a result of the application of fresh start accounting and the effects of the implementation of the Plan, the Successor financial statements will not be comparable to the financial statements prepared before the Effective Date.
Changes in Accounting Policies
On the Effective Date, we elected to change the accounting policies related to depreciation of fixed assets of our Contract Drilling segment and the allocation of earnings and losses between Unit and its partners in Superior.
•Regarding our Contract Drilling segment, we elected to depreciate all drilling assets using the straight-line method over the useful lives of the assets ranging from four to ten years.
•We elected to begin allocating earnings and losses between Unit and the partners in Superior using the Hypothetical Liquidation at Book Value (HLBV) method of accounting.
Business Outlook
Strategy
Following our emergence from bankruptcy, we are focused on value accretion through generation of free cash flows, repayment of debt, and selective investment in each of our business segments. Investments are expected to be funded using free cash flows from operations, proceeds from divestitures of non-core assets, and available capacity under the Exit Credit Agreement, all subject to the various terms and conditions of the Exit Credit Agreement as referenced in Note 9 – Long-Term Debt and Other Long-Term Liabilities.
In our oil and natural gas segment, we are optimizing production from our existing reserves and converting non-producing reserves to producing, with no exploratory drilling currently planned. We plan to divest non-core properties and use those proceeds along with free cash flows to acquire producing properties in our core areas.
In our contract drilling segment, we are focused on increasing the use of our BOSS drilling rigs, as well as upgrading certain of our SCR drilling rigs. We also plan to continue seeking opportunities to divest non-core, idle drilling equipment.
In our mid-stream segment, we are focused on generating predictable free cash flows with limited exposure to commodity prices. We also plan to continue seeking business development opportunities in our core areas using the Superior credit agreement (which Unit is not a party to nor guarantees) or other financing sources that are available to it.
COVID-19 Pandemic and Commodity Price Environment
As discussed in other parts of this report, among other things, our success depends, to a large degree, on the prices we receive for our oil and natural gas production, the demand for oil, natural gas, and NGLs, and the demand for our drilling rigs which influences the amounts we can charge for those drilling rigs. While our operations are all within the United States, events outside the United States affect us and our industry.
We are continuously monitoring the current and potential impacts of the COVID-19 pandemic on our business. This includes how it has and may continue to impact our operations, financial results, liquidity, customers, employees, and vendors. In response to the pandemic, we have implemented various measures to ensure we are conducting our business in a safe and secure manner. COVID-19 and the response of governments around the world to contain the pandemic have contributed to an economic downturn, reduced demand for oil and natural gas, and together with a price war between Saudi Arabia and Russia, depressed oil and natural gas prices in 2020. The global oil and natural gas supply and demand imbalance continues to be uncertain, with possible on-going and future adverse effects on the oil and gas industry.
During the last two years, commodity prices have been volatile. We reduced our operated rig count in the first quarter of 2019 before getting as high as six drilling rigs in the second quarter of 2019. Due to declining prices, we shut down our own drilling program in July 2019 and used no drilling rigs for the remainder of 2019 and 2020.
The following chart reflects the significant fluctuations in the prices for oil and natural gas:
The following chart reflects the significant fluctuations in the prices for NGLs:
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1.NGLs prices reflect a weighted-average, based on production, of Mont Belvieu and Conway prices.
Executive Summary
Oil and Natural Gas
Fourth quarter 2020 production from our oil and natural gas segment was 2,592 MBoe, a decrease of 9% and 38% from the third quarter of 2020 and the fourth quarter of 2019, respectively. The decreases came from fewer net wells being drilled in 2020 to replace the declines in existing drilled wells. Oil and NGLs production during the fourth quarter of 2020 and the fourth quarter of 2019 were each 48% of our total production.
Fourth quarter 2020 oil and natural gas revenues increased 6% over the third quarter of 2020 and decreased 48% from the fourth quarter of 2019. The increase over the third quarter of 2020 was primarily due an increase in commodity prices partially offset by a decrease in equivalent production. The decrease from the fourth quarter of 2019 was primarily due to a decrease in equivalent production and oil and NGLs prices.
Our hedged natural gas prices for the fourth quarter of 2020 increased 56% over third quarter of 2020 and increased 1% over fourth quarter of 2019. Our hedged oil prices for the fourth quarter of 2020 increased 43% over the third quarter of 2020 and decreased 29% from the fourth quarter of 2019, respectively. Our hedged NGLs prices for the fourth quarter of 2020 increased 21% over the third quarter of 2020 and decreased 24% from the fourth quarter of 2019.
Direct profit (oil and natural gas revenues less oil and natural gas operating expense) increased 35% over the third quarter of 2020 and decreased 52% from the fourth quarter of 2019. The increase over the third quarter of 2020 was primarily due to an increase in commodity prices and a reduction in saltwater disposal expense and G&A partially offset by a decrease in equivalent production. The decrease from the fourth quarter of 2019 was primarily due to lower revenues due to lower commodity prices and volumes partially offset by lower LOE and G&A.
Operating cost per Boe produced for the fourth quarter of 2020 decreased 10% from the third quarter of 2020 and decreased 3% from the fourth quarter of 2019. The decrease from the third quarter of 2020 was primarily due to lower G&A and saltwater disposal expense. The decrease from the fourth quarter of 2019 was primarily due to lower LOE and G&A partially offset by no longer capitalizing directly related overhead costs in 2020 due to the absence of drilling in 2020.
At December 31, 2020, these non-designated hedges were outstanding:
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Term
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Commodity
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Contracted Volume
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Weighted Average
Fixed Price for Swaps
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Contracted Market
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Jan'21 - Dec'21
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Natural gas - basis swap
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30,000 MMBtu/day
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$(0.215)
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NGPL TEXOK
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Jan'21 - Oct'21
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Natural gas - swap
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50,000 MMBtu/day
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$2.82
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IF - NYMEX (HH)
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Nov'21 - Dec'21
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Natural gas - swap
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45,000 MMBtu/day
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$2.90
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IF - NYMEX (HH)
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Jan'22 - Dec'22
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Natural gas - swap
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5,000 MMBtu/day
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$2.61
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IF - NYMEX (HH)
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Jan'23 - Dec'23
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Natural gas - swap
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22,000 MMBtu/day
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$2.46
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IF - NYMEX (HH)
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Jan'22 - Dec'22
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Natural gas - collar
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35,000 MMBtu/day
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$2.50 - $2.68
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IF - NYMEX (HH)
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Jan'21 - Dec'21
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Crude oil - swap
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3,000 Bbl/day
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$44.65
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WTI - NYMEX
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Jan'22 - Dec'22
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Crude oil - swap
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2,300 Bbl/day
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$42.25
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WTI - NYMEX
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Jan'23 - Dec'23
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Crude oil - swap
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1,300 Bbl/day
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$43.60
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WTI - NYMEX
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In western Oklahoma, annual production averaged 73 MMcfe per day (31% oil, 22% NGLs, 47% natural gas) which was a decrease of approximately 24% compared to 2019. During 2020, we did not drill any operated wells in this area and participated in one net non-operated well.
In the Texas panhandle, annual production averaged 67 MMcfe per day (8% oil, 37% NGLs, 55% natural gas) which was a decrease of approximately 27% compared to 2019. During 2020, we did not drill any operated wells in this area, nor did we participate in any non-operated wells.
In our Wilcox play located primarily in Polk, Tyler, Hardin and Goliad Counties, Texas, annual production averaged 45 MMcfe per day (9% oil, 29% NGL’s, 62% natural gas) which is a decrease of approximately 41% compared to 2019. During 2020, we did not drill any operated wells in this area, nor did we participate in any non-operated wells.
During the Successor Period and Predecessor Period of 2020, we participated in the drilling of three wells (0.30 net wells) and 16 wells (0.35 net wells), respectively.
Contract Drilling
The average number of drilling rigs we operated in the fourth quarter of 2020 was 7.6 compared to 5.1 and 18.3 in the third quarter of 2020 and fourth quarter of 2019, respectively. As of December 31, 2020, nine of our drilling rigs were operating.
Revenue for the fourth quarter of 2020 increased 24% over the third quarter of 2020 and decreased 59% from the fourth quarter of 2019. The increase over the third quarter of 2020 was due to more drilling rigs operating and increasing dayrates. The decrease from the fourth quarter of 2019 was due to less drilling rigs operating and lower dayrates.
Dayrates for the fourth quarter of 2020 averaged $17,923, which was a 6% increase over the third quarter of 2020 and a 7% decrease from the fourth quarter of 2019. The increase over the third quarter of 2020 was primarily due to more drilling rigs operating. The decrease from the fourth quarter of 2019 was primarily due to less drilling rigs operating.
Operating costs for the fourth quarter of 2020 increased 29% over the third quarter of 2020 and decreased 59% from the fourth quarter of 2019. The increase over the third quarter of 2020 was primarily due to more drilling rigs operating. The decrease from the fourth quarter of 2020 was primarily due to less drilling rigs operating. Operating cost per day for the fourth quarter of 2020 decreased 15% from the third quarter of 2020 and decreased 2% from the fourth quarter of 2019. Revenue days for the fourth quarter of 2020 increased 51% over the third quarter of 2020 and decreased 58% from the fourth quarter of 2019.
Direct profit (contract drilling revenue less contract drilling operating expense) for the fourth quarter of 2020 increased 13% over the third quarter of 2020 and decreased 59% from the fourth quarter of 2019. The increase over the third quarter of 2020 was primarily due to more drilling rigs operating. The decrease from the fourth quarter of 2019 was primarily due to less drilling rigs operating.
The contract drilling segment has operations in Oklahoma, Texas, New Mexico, Wyoming, and North Dakota. As of December 31, 2020, three drilling rigs were working in Oklahoma, three in the Permian Basin of West Texas, two in Wyoming and one drilling rig in the Bakken Shale of North Dakota.
During 2020, almost all our working drilling rigs were drilling horizontal or directional wells for oil and NGLs. The future demand for and the availability of drilling rigs to meet that demand will affect our future dayrates.
As of December 31, 2020, we had five term drilling contracts with original terms ranging from two months to one year. Three of these contracts are up for renewal in 2021, (two in the first quarter and one in the second quarter) and two are up for renewal in 2022 and beyond. Term contracts may contain a fixed rate during the contract or provide for rate adjustments within a specific range from the existing rate. Some operators who had signed term contracts have opted to release the drilling rig and pay an early termination penalty for the remaining term of the contract. We recorded $9.2 million and $4.8 million in early termination fees in 2020 and 2019, respectively.
Six of our 14 existing BOSS drilling rigs were under contract as of December 31, 2020.
All our contracts are daywork contracts.
For 2021, capital expenditures for this segment are expected to primarily be for maintenance capital on operating drilling rigs and the possible conversion of certain SCR drilling rigs to AC drilling rigs if practicable. We also plan to pursue the disposal or sale of our non-core, older drilling rig fleet.
Mid-Stream
Fourth quarter 2020 liquids sold per day decreased 31% from the third quarter of 2020 and decreased 24% from the fourth quarter of 2019. The decreases were primarily due to declining volumes and fewer wells connected to our major systems resulting in lower liquids production. For the fourth quarter of 2020, gas processed per day decreased 11% from the third quarter of 2020 and decreased 19% from the fourth quarter of 2019. The decreases were primarily due to declining volumes and fewer wells connected to our major systems. For the fourth quarter of 2020, gas gathered per day decreased 11% from the third
quarter of 2020 and decreased 20% from the fourth quarter of 2019. The decreases were primarily due to lower volumes from our major gathering and processing systems resulting from fewer wells connected and declining wellhead volumes.
NGLs prices in the fourth quarter of 2020 increased 35% over the prices received in the third quarter of 2020 and increased 5% over the prices received in the fourth quarter of 2019. Because certain of the contracts used by our mid-stream segment for NGLs transactions are commodity-based contracts – under which we receive a share of the proceeds from the sale of the NGLs – our revenues from those commodity-based contracts fluctuate based on NGLs prices.
Direct profit (mid-stream revenues less mid-stream operating expense) for the fourth quarter of 2020 decreased 45% from the third quarter of 2020 and decreased 12% from the fourth quarter of 2019, respectively. The decrease from the third quarter of 2020 was primarily due to recognizing a shortfall fee in the third quarter of 2020 in the amount of $5.3 million and due to declining volumes on our major systems. The decrease from the fourth quarter of 2019 was primarily due to lower volume on our major systems and lower condensate prices. Total operating cost for this segment for the fourth quarter of 2020 increased 17% over the third quarter of 2020 and decreased 3% from the fourth quarter of 2019. The increase over the third quarter of 2020 was primarily due to an increase in gas purchase cost due to higher purchase prices. The decrease from the fourth quarter of 2019 was primarily due to declining wellhead volumes and fewer wells connected resulting in lower purchased volumes.
At the Cashion processing facility in central Oklahoma, total throughput volume for the fourth quarter of 2020 averaged approximately 64.2 MMcf per day and total production of natural gas liquids averaged approximately 252,000 gallons per day. For 2020, we continued to connect new wells to this system for third party producers. Since the first of 2020, we connected 18 new wells to this system from producers. The total processing capacity of the Cashion system is 105 MMcf per day.
In the Appalachian region at the Pittsburgh Mills gathering system, average gathered volume for the fourth quarter of 2020 was 131.7 MMcf per day and average gathered volume for 2020 was 152.3 MMcf per day. During 2020, we connected four new infill wells to an existing well pad.
Also, in the Appalachian area at our Snow Shoe gathering system, the average gathering volume for the fourth quarter was 2.5 MMcf per day and the average gathered volume for 2020 was 3.0 MMcf per day. In 2020, we did not connect any new wells to this system. At Snow Shoe for 2020, we also charged a demand fee based on a volume of 55 MMcf per day. This demand fee volume will be reduced in 2021 to 51 MMcf per day. Additionally, in 2020, we recognized a shortfall fee from a producer on this system for $5.3 million. This fee will be invoiced in the first quarter of 2021.
At the Hemphill processing facility located in the Texas panhandle, average total throughput volume for the fourth quarter of 2020 was 46.6 MMcf per day and average total throughput volume for 2020 was 51.3 MMcf per day. Total average production of natural gas liquids for the fourth quarter of 2020 decreased to approximately 110,000 gallons per day due to operating in ethane rejection. Total production of natural gas liquids for 2020 averaged approximately 152,000 gallons per day. The total processing capacity of the Hemphill system is 135 MMcf per day. In 2020, we did not connect any new wells to this system. Currently there are no active rigs in the area, and we do not anticipate any new well connects for this system.
At the Segno gathering system located in East Texas, the average throughput volume for the fourth quarter of 2020 decreased to approximately 31.0 MMcf per day due to declining production volume along with no new drilling activity in the area. For 2020, the average throughput volume for this system was approximately 40 MMcf per day. During 2020, we did not connect any new wells to this system.
Anticipated 2021 capital expenditures for this segment will be approximately $15.0 million, a 61% increase over 2020.
Critical Accounting Policies and Estimates
Summary
In this section, we identify those critical accounting policies we follow in preparing our financial statements and related disclosures. Many policies require us to make difficult, subjective, and complex judgments while making estimates of matters inherently imprecise. Some accounting policies involve judgments and uncertainties to such an extent that there is a reasonable likelihood that materially different amounts could have been reported under different conditions, or had different assumptions been used. We evaluate our estimates and assumptions regularly. We base our estimates on historical experience and various other assumptions we believe are reasonable under the circumstances, the results of which support making judgments about the carrying values of assets and liabilities not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our financial statements. In this discussion we explain the nature of these estimates,
assumptions and judgments, and the likelihood that materially different amounts would be reported in our financial statements under different conditions or using different assumptions.
Significant Estimates and Assumptions
Full Cost Method of Accounting for Oil, NGLs, and Natural Gas Properties. Determining our oil, NGLs, and natural gas reserves is a subjective process. It entails estimating underground accumulations of oil, NGLs, and natural gas that cannot be measured in an exact manner. Accuracy of these estimates depends on several factors, including, the quality and availability of geological and engineering data, the precision of the interpretations of that data, and individual judgments. Each year, we hire an independent petroleum engineering firm to audit our internal evaluation of our reserves. That audit as of December 31, 2020 covered those reserves we projected to comprise 85% of the total proved developed future net income discounted at 10% (based on the SEC's unescalated pricing policy). Included in Part I, Item 1 of this report are the qualifications of our independent petroleum engineering firm and our employees responsible for preparing our reserve reports.
The accuracy of estimating oil, NGLs, and natural gas reserves varies with the reserve classification and the related accumulation of available data, as shown in this table:
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Type of Reserves
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Nature of Available Data
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Degree of Accuracy
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Proved undeveloped
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Data from offsetting wells, seismic data
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Less accurate
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Proved developed non-producing
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The above and logs, core samples, well tests, pressure data
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More accurate
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Proved developed producing
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The above and production history, pressure data over time
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Most accurate
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Assumptions of future oil, NGLs, and natural gas prices and operating and capital costs also play a significant role in estimating these reserves and the estimated present value of the cash flows to be received from the future production of those reserves. Volumes of recoverable reserves are influenced by the assumed prices and costs due to the economic limit (that point when the projected costs and expenses of producing recoverable oil, NGLs, and natural gas reserves are greater than the projected revenues from the oil, NGLs, and natural gas reserves). But more significantly, the estimated present value of the future cash flows from our oil, NGLs, and natural gas reserves is sensitive to prices and costs and may vary materially based on different assumptions. Companies, like ours, using full cost accounting use the unweighted arithmetic average of the commodity prices existing on the first day of each of the 12 months before the end of the reporting period to calculate discounted future revenues, unless prices were otherwise determined under contractual arrangements.
We compute DD&A on a units-of-production method. Each quarter, we use these formulas to compute the provision for DD&A for our producing properties:
•DD&A Rate = Unamortized Cost / End of Period Reserves Adjusted for Current Period Production
•Provision for DD&A = DD&A Rate x Current Period Production
Unamortized cost 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.
Oil, NGLs, and natural gas reserve estimates have a significant impact on our DD&A rate. If future reserve estimates for a property or group of properties are revised downward, the DD&A rate will increase because of the revision. If reserve estimates are revised upward, the DD&A rate will decrease.
The DD&A expense on our oil and natural gas properties is calculated each quarter using period end reserve quantities adjusted for period production.
We account for our oil and natural gas exploration and development activities using the full cost method of accounting. Under this method, we capitalize all costs incurred in the acquisition, exploration, and development of oil and natural gas properties. At the end of each quarter, the net capitalized costs of our oil and natural gas properties are limited to that amount which is the lower of unamortized costs or a ceiling. The ceiling is defined as the sum of the present value (using a 10% discount rate) of the estimated future net revenues from our proved reserves (based on the unescalated 12-month average price
on our oil, NGLs, and natural gas adjusted for any cash flow hedges), plus the cost of properties not being amortized, plus the lower of the cost or estimated fair value of unproved properties included in the costs being amortized, less related income taxes. If the net capitalized costs of our oil and natural gas properties exceed the ceiling, we are required to write-down the excess amount. A ceiling test write-down is a non-cash charge to earnings. If required, it reduces earnings and impacts shareholders’ equity in the period of occurrence and results in lower DD&A expense in future periods. Once incurred, a write-down cannot be reversed.
The risk we will be required to write-down the carrying value of our oil and natural gas properties increases when the prices for oil, NGLs, and natural gas are depressed or if we have large downward revisions in our estimated proved oil, NGLs, and natural gas reserves. Application of these rules during periods of relatively low prices, even if temporary, increases the chance of a ceiling test write-down. At December 31, 2020, our reserves were calculated based on applying 12-month 2020 average unescalated prices of $39.57 per barrel of oil, $18.70 per barrel of NGLs, and $1.98 per Mcf of natural gas (then adjusted for price differentials) over the estimated life of each of our oil and natural gas properties.
Successor Period Impairment
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 during the Successor Period of 2020, 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.
Under full cost accounting rules we must review the carrying value of our oil and natural gas properties at the end of each quarter. Under those rules, the maximum amount allowed as the carrying value is called the ceiling. The ceiling is the sum of the present value (using a 10% discount rate) of the estimated future net revenues from our proved reserves (using the most recent unescalated historical 12-month average price of our oil, NGLs, and natural gas), plus the cost of properties not being amortized, plus the lower of cost or estimated fair value of unproved properties in the costs being amortized, less related income taxes. If the net book value of the oil, NGLs, and natural gas properties being amortized exceeds the full cost ceiling, the excess amount is charged to expense in the period during which the excess occurs, even if prices are depressed for only a short while. Once incurred, a write-down of oil and natural gas properties is not reversible.
We do not anticipate a non-cash ceiling test write-down in the first quarter of 2021 of our proved reserves. 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
Oil and Natural Gas. During the Predecessor Period of 2020, we incurred non-cash ceiling test write-downs of our oil and natural gas properties of $393.7 million pre-tax ($346.6 million net of tax) due to the reduction in the 12-month average commodity prices and the impairment of our unproved oil and gas properties described below. In 2019, we incurred non-cash ceiling test write-downs of our oil and natural gas properties of $559.4 million pre-tax ($422.4 million net of tax) due to the reduction of the 12-month average commodity prices and the removal of proved undeveloped reserves due to the uncertainty regarding our ability to finance future capital expenditures.
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 asset utilization, we determined certain assets were no longer expected to be used and wrote off certain salt water disposal assets that we no longer considered abandoned. We recorded expense of $17.6 million related to the write-down of our salt water disposal assets in the first quarter of 2020.
Mid-stream. We determined that the carrying value of certain long-lived asset groups in our mid-stream segment, 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.
Contract Drilling. On a periodic basis, we evaluate our fleet of drilling rigs for marketability based on the condition of inactive rigs, the expenditures necessary to bring them into working condition and the expected demand for drilling services by rig type. The components comprising inactive rigs are evaluated, and those components with continuing utility to our other marketed rigs are transferred to rigs or to our yards to be used as spare equipment. The remaining components of these rigs are retired.
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 charges of $3.0 million for other miscellaneous drilling equipment.
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.
We recorded expense of $1.1 million related to the write-down of certain equipment in the third quarter of 2020 that we consider abandoned.
Costs Withheld from Amortization. Costs associated with unproved properties are excluded from our amortization base until we have evaluated the properties. The costs associated with unevaluated leasehold acreage and related seismic data, the drilling of wells, and capitalized interest are initially excluded from our amortization base. Leasehold costs are transferred to our amortization base with the costs of drilling a well on the lease or are assessed at least annually for possible impairment or reduction in value. Leasehold costs are transferred to our amortization base to the extent a reduction in value has occurred.
Our decision to withhold costs from amortization and the timing of transferring those costs into the amortization base involve significant judgment determinations which may change over time based on several factors, including our drilling plans, availability of capital, project economics and results of drilling on adjacent acreage. During the first quarter of 2020, we determined that, because of the increased uncertainty in our business, our undeveloped acreage would not be fully developed and thus certain unproved oil and gas properties carrying values were not recoverable. This resulted in an impairment of $226.5 million, which had a corresponding increase to our depletion base and contributed to our full cost ceiling impairment recorded during the first quarter of 2020. In 2019, 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 $73.9 million of costs being added to the total of our capitalized costs being amortized. At December 31, 2020, we had approximately $1.6 million of costs excluded from the amortization of our full cost pool.
Accounting for ARO for Oil, NGLs, and Natural Gas Properties. We record the fair value of liabilities associated with the future plugging and abandonment of wells. In our case, when the reserves in each of our oil or gas wells deplete or the wells otherwise become uneconomical, we must incur costs to plug and abandon the wells. These costs are recorded in the period in which the liability is incurred (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, natural gas, or both), 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 current present value of this obligation. To the extent any change in these assumptions affect future revisions and impacts the present value of the existing ARO, a corresponding adjustment is made to the full cost pool.
Drilling Contracts. The type of contract used determines our compensation. All our contracts in 2020 and 2019 were daywork contracts. Under a daywork contract, we provide the drilling rig with the required personnel and the operator supervises the drilling of the well. Our compensation is based on a negotiated rate to be paid for each day the drilling rig is used.
Accounting for Value of Stock Compensation Awards. To account for stock-based compensation, compensation cost is measured at the grant date based on the fair value of an award and is recognized over the service period, which is usually the vesting period. We elected to use the modified prospective method, which requires compensation expense to be recorded for all unvested stock options and other equity-based compensation beginning in the first quarter of adoption. Determining the fair value of an award requires significant estimates and subjective judgments regarding the appropriate option pricing model, the expected life of the award and performance vesting criteria assumptions. As there are inherent uncertainties related to these factors and our judgment in applying them to the fair value determinations, there is risk that the recorded stock compensation may not accurately reflect the amount ultimately earned by the employee. All our previously reported awards were terminated because of our Chapter 11 Cases and no awards were outstanding as of December 31, 2020.
Accounting for Derivative Instruments and Hedging. 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) along with any derivatives settled are reported in gain (loss) on derivatives in our Consolidated Statements of Operations.
Bankruptcy Reorganization. We have applied Accounting Standards Codification (ASC) 852, Reorganizations (ASC 852) in preparing our consolidated financial statements. ASC 852 requires that the financial statements, for periods subsequent to the Chapter 11 Cases, distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, certain expenses, realized gains and losses and provisions for losses that are realized or incurred in the bankruptcy proceedings, are recorded in reorganization items, net on our accompanying consolidated statements of operations.
Fresh Start. The company qualified for and adopted fresh start accounting under the provisions of ASC 852. When applying ASC 852, an entity determines its reorganization value and enterprise value. Reorganization value, as determined under ASC 820, Fair Value Measurement, represents the fair value of the entity's total assets before the consideration of liabilities and is intended to approximate the amount a willing buyer would pay for the assets immediately after a restructuring. The entity's enterprise value represents the estimated fair value of an entity’s long-term debt and equity. The assumptions used in estimating these values are inherently uncertain and require significant judgment.
New Accounting Standards
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 should 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.
Adopted Standards
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.
Financial Condition and Liquidity
Summary
Our financial condition and liquidity primarily depend on the cash flow from our operations and borrowings under our credit agreements. The principal factors determining our cash flow are:
•the amount of natural gas, oil, and NGLs we produce;
•the prices we receive for our natural gas, oil, and NGLs production;
•the use of our drilling rigs and the dayrates we receive for those drilling rigs; and
•the fees and margins we obtain from our natural gas gathering and processing contracts.
Our Chapter 11 Cases allowed us to significantly reduce our level of indebtedness and our future cash interest obligations. We currently expect that cash and cash equivalents, cash generated from operations, and available funds under the Exit Credit Agreement and the Superior credit agreement are adequate to cover our liquidity requirements for at least the next 12 months.
Below is a summary of certain financial information for the periods indicated:
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Successor
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Predecessor
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Period
September 1, 2020
through
December 31, 2020
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Period
January 1, 2020 through
August 31, 2020
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For the Year Ended
December 31, 2019
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(In thousands)
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Net cash provided by operating activities
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$
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29,807
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$
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44,956
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$
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269,396
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Net cash used in investing activities
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(2,258)
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(20,139)
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(394,563)
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Net cash provided by (used in) financing activities
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(47,775)
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7,552
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119,286
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Net increase (decrease) cash, restricted cash, and cash equivalents
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$
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(20,226)
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$
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32,369
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$
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(5,881)
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Cash Flows from Operating Activities
Our operating cash flow is primarily influenced by the prices we receive for our oil, NGLs, and natural gas production, the oil, NGL, and natural gas we produce, settlements of derivative contracts, third-party use for our drilling rigs and mid-stream services, and the rates we can charge for those services. Our cash flows from operating activities are also affected by changes in working capital.
Net cash provided by operating activities decreased by $194.6 million in 2020 compared to 2019 primarily due to lower revenues due to lower commodity prices and lower drilling rig utilization partially offset by an increase in operating assets and liabilities related to the timing of cash receipts and disbursements.
Cash Flows from Investing Activities
We have historically dedicated a substantial portion of our capital budgets to our exploration for and production of oil, NGLs, and natural gas. These expenditures are necessary to off-set the inherent production declines typically experienced in oil and gas wells. Although we curtailed our spending in 2020, we expect that any future capital budgets would be focused on development or acquisitions of producing oil and gas properties, but not exploration.
Cash flows used in investing activities decreased by $372.2 million in 2020 compared to 2019. The change was due
primarily to a decrease in capital expenditures due to a decrease in operated wells drilled and a decrease in oil and gas property acquisitions partially offset by a decrease in the proceeds received from the disposition of assets. See additional information on capital expenditures below under Capital Requirements.
Cash Flows from Financing Activities
Cash flows provided by (used in) financing activities decreased by $159.5 million in 2020 compared to 2019. The decrease was primarily due to a decrease in the net borrowings and a decrease in bank overdrafts.
At December 31, 2020, we had unrestricted cash and cash equivalents totaling $12.1 million and had borrowed $99.0 million of the amounts available under the Exit Credit Agreement. We did not have any outstanding borrowings under our Superior credit agreement.
Below is a summary of certain financial information as of December 31:
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Successor
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Predecessor
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2020
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2019
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(In thousands)
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Working capital
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$
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2,575
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$
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(154,998)
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Current portion of long-term debt
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$
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600
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$
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108,200
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Long-term debt (1)
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$
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98,400
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$
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663,216
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Shareholders' equity attributable to Unit Corporation
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$
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179,222
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$
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853,878
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_________________________
1.Long-term debt is net of unamortized discount and debt issuance costs for the Predecessor Period.
Working Capital
Typically, our working capital balance fluctuates, in part, because of the timing of our trade accounts receivable and accounts payable and the fluctuation in current assets and liabilities associated with the mark to market value of our derivative activity. We had positive working capital of $2.6 million at December 31, 2020 and negative working capital of $155.0 million as of December 31, 2019. The increase in working capital is primarily due to more cash and cash equivalents and lower accounts payable and accrued liabilities from to the settlement of the liabilities subject to compromise partially offset by lower accounts receivable. Both the Superior credit agreement and the Exit Credit Agreement are used for working capital. At December 31, 2020, we had borrowed $99.0 million under the Exit Credit Agreement and we did not have any outstanding borrowings under our Superior credit agreement. The effect of our derivatives decreased working capital by $1.0 million as of December 31, 2020 and increased working capital by $0.6 million as of December 31, 2019.
Long-Term Debt
Our Exit Credit Agreement is primarily used for working capital purposes as it limits the amount that can be borrowed for capital expenditures. These limitations restrict future capital projects using the Exit Credit Agreement. The Exit Credit Agreement also requires that any proceeds from the disposition of certain assets be used to repay amounts outstanding.
Oil and Natural Gas Operations
Any significant change in oil, NGLs, or natural gas prices has a material effect on our revenues, cash flow, and the value of our oil, NGLs, and natural gas reserves. Generally, prices and demand for domestic natural gas are influenced by weather conditions, supply imbalances, by worldwide oil price levels, and recently by the worldwide economic impact from the coronavirus. Domestic oil prices are primarily influenced by world oil market developments. These factors are beyond our control and we cannot predict nor measure their future influence on the prices we will receive.
Contract Drilling Operations
Many factors influence the number of drilling rigs we have working, and the costs and revenues associated with that work. These factors include the demand for drilling rigs in our areas of operation, competition from other drilling contractors,
the prevailing prices for oil, NGLs, and natural gas, availability and cost of labor to run our drilling rigs, and our ability to supply the equipment needed.
Competition to keep qualified labor continues. Our drilling rig personnel are a key component to the overall success of our drilling services. With the present conditions in the drilling industry, we do not anticipate increases in the compensation paid to those personnel in the near term.
During 2020, most of our working drilling rigs were drilling horizontal or directional wells for oil and NGLs. The continuous fluctuations in commodity prices for oil and natural gas changes demand for drilling rigs. These factors ultimately affect the demand and mix of the type of drilling rigs used by our customers. The future demand for and the availability of drilling rigs to meet that demand will affect our future dayrates. For the Successor Period and Predecessor Period of 2020, our average dayrate was $17,807 and $18,911 per day, respectively, compared to $18,762 per day for 2019. Our average number of drilling rigs used (utilization %) for the Successor Period and Predecessor Period of 2020 were 7.2 (12%) and 11.5 (20%), respectively, compared with 24.6 (43%) in 2019. Based on the average utilization of our drilling rigs during 2020, a $100 per day change in dayrates has a $1,010 per day ($0.4 million annualized) change in our pre-tax operating cash flow.
Our contract drilling segment provides drilling services for our exploration and production segment. Some of the drilling services we perform on our properties are, depending on the timing of those services, deemed associated with acquiring an ownership interest in the property. In those cases, revenues and expenses for those services are eliminated in our statement of operations, with any profit recognized as a reduction in our investment in our oil and natural gas properties. The contracts for these services are issued under the same conditions and rates as the contracts entered into with unrelated third parties. By providing drilling services for the oil and natural gas segment, we eliminated revenue of $15.8 million during 2019 from our contract drilling segment and eliminated the associated operating expense of $14.2 million yielding $1.6 million as a reduction to the carrying value of our oil and natural gas properties. We did not eliminate any revenue or expense in 2020.
There were no impairment triggering events identified in the Successor Period of 2020 for our contract drilling assets.
Mid-Stream Operations
This segment is engaged primarily in the buying, selling, gathering, processing, and treating of natural gas. It operates three natural gas treatment plants, 11 processing plants, 17 gathering systems, and approximately 2,090 miles of pipeline. Its operations are in Oklahoma, Texas, Kansas, Pennsylvania, and West Virginia. This segment enhances our ability to gather and market not only our own natural gas and NGLs but also natural gas and NGLs owned by third parties and serves as a mechanism through which we can construct or acquire existing natural gas gathering and processing facilities. During the Successor Period of 2020, Predecessor Period of 2020, and the year 2019, Superior purchased $10.6 million, $11.8 million, and $40.6 million, respectively, of our oil and natural gas segment's natural gas and NGLs production, and provided gathering and transportation services of $1.2 million, $2.8 million, and $6.9 million, respectively. Intercompany revenue from services and purchases of production between this business segment and our oil and natural gas segment has been eliminated in our consolidated financial statements.
Our mid-stream segment gathered an average of 367,302 Mcf per day in 2020 compared to 435,646 Mcf per day in 2019. It processed an average of 150,559 Mcf per day in 2020 compared to 164,482 Mcf per day in 2019, and sold NGLs of 555,454 gallons per day in 2020 compared to 625,873 gallons per day in 2019. Gas gathering volumes per day in 2020 decreased primarily due to lower volumes from most of our major gathering and processing systems resulting from declining wellhead volumes and fewer wells connected except from the Cashion facility. Volumes processed and NGLs sold in 2020 decreased mainly due to lower volumes from our processing facility in the Texas panhandle resulting from declines and not connecting any new wells in 2020.
Our Credit Agreements and Predecessor Debt
Exit Credit Agreement. On the Effective Date, under the Plan, we entered into an amended and restated credit agreement (the Exit Credit Agreement), providing for a $140.0 million senior secured revolving credit facility and a $40.0 million senior secured term loan facility, among (i) the company, UDC, and UPC, (ii) the guarantors, including the company and all its subsidiaries existing as of the Effective Date (other than Superior Pipeline Company, L.L.C. and its subsidiaries), (iii) the lenders under the agreement, and (iv) BOKF, NA dba Bank of Oklahoma as administrative agent and collateral agent (the Administrative Agent).
The maturity date of borrowings under the 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.
The Exit Credit Agreement requires that we comply with certain financial ratios, including a covenant that we will not permit the Net Leverage Ratio (as defined in the Exit Credit Agreement) as of the last day of the fiscal quarters ending (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 ending December 31, 2020, we 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 0.50 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, restrict certain asset sales and the related use of proceeds, and require certain hedging activities. The Exit Credit Agreement further requires that we 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. For the quarter ended September 30, 2020, the syndicate banks allowed for an extension.
The Exit Credit Agreement is secured by first-priority liens on substantially all the personal and real property assets of the borrowers and the guarantors, including our ownership interests in Superior Pipeline Company, L.L.C.
On the Effective Date, we had (i) $40.0 million in principal amount of Term Loans outstanding, (ii) $92.0 million in principal amount of Revolving Loans outstanding, and (iii) approximately $6.7 million of outstanding letters of credit. At December 31, 2020, we had $0.6 million and $98.4 million outstanding current and long-term borrowings, respectively, under the Exit Credit Agreement.
Predecessor's Credit Agreement. Before the filing of the Chapter 11 Cases, the Unit credit agreement had a scheduled maturity date of October 18, 2023 that would have accelerated to November 16, 2020 if, by that date, all the Notes were not repurchased, redeemed, or refinanced with indebtedness having a maturity date at least six months following October 18, 2023 (Credit Agreement Extension Condition). The Debtors' filing of the Chapter 11 Cases constituted an event of default that accelerated the Debtors' obligations under the Unit credit agreement and the indenture governing the Notes. Due to the Credit Agreement Extension Condition, our debt associated with the Unit credit agreement is reflected as a current liability in our Consolidated Balance Sheets as of December 31, 2019. The classification as a current liability due to the Credit Agreement Extension Condition was based on the uncertainty regarding our ability to repay or refinance the Notes before November 16, 2020. In addition, on May 22, 2020, the lenders' remaining commitments under the Unit credit agreement were terminated.
Before filing the Chapter 11 Cases, we were charged a commitment fee of 0.375% on the amount available but not borrowed. That fee varied based on the amount borrowed as a percentage of the total borrowing base. Total amendment fees of $3.3 million in origination, agency, syndication, and other related fees were being amortized over the life of the Unit credit agreement. Due to the termination of the remaining commitments of the lenders under the Unit credit agreement, the unamortized debt issuance costs of $2.4 million were written off during the second quarter of 2020. Under the Unit credit agreement, we pledged as collateral 80% of the proved developed producing (discounted as present worth at 8%) total value of our oil and gas properties. Under the mortgages covering those oil and gas properties, UPC also pledged certain items of its personal property.
Before filing the Chapter 11 Cases, any part of the outstanding debt under the Unit credit agreement could be fixed at a London Interbank Offered Rate (LIBOR). LIBOR interest was computed as the LIBOR base for the term plus 1.50% to 2.50% depending on the level of debt as a percentage of the borrowing base and was payable at the end of each term, or every 90 days, whichever is less. Borrowings not under LIBOR bear interest equal to the higher of the prime rate specified in the Unit credit agreement and the sum of the Federal Funds Effective Rate (as defined in the Unit credit agreement) plus 0.50%, but in no event would the interest on those borrowings be less than LIBOR plus 1.00% plus a margin. Interest was payable at the end of each month or at the end of each LIBOR contract and the principal may be repaid in whole or in part at any time, without a premium or penalty.
Filing the bankruptcy petitions on May 22, 2020 constituted an event of default that accelerated our obligations under the Unit credit agreement, and the lenders’ rights of enforcement under the Unit credit agreement were automatically stayed because of the Chapter 11 Cases.
On the Effective Date, each lender under the Unit credit agreement and the DIP Credit Agreement received its pro rata share of revolving loans, term loans and letter-of-credit participations under the Exit Credit Agreement, in exchange for that lender’s allowed claims under the Unit credit agreement or the DIP Credit Agreement.
Superior Credit Agreement. On May 10, 2018, Superior entered into 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 (the Superior credit agreement). 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) third day LIBOR plus 1.00%) 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 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 to Lender in the London Interbank Market or if that 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. Superior paid $1.7 million in origination, agency, syndication, and other related fees. These fees are being amortized over the life of the Superior credit agreement.
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. Additionally, the Superior credit agreement contains several customary covenants that, among other things, restrict (subject to certain exceptions) Superior’s ability to incur additional indebtedness, create additional liens on its assets, make investments, pay distributions, enter into sale and leaseback transactions, engage in certain transactions with affiliates, engage in mergers or consolidations, enter into hedging arrangements, and acquire or dispose of assets. As of December 31, 2020, Superior was in compliance with the Superior credit agreement covenants.
Borrowings from the Superior credit agreement will be used to fund capital expenditures and acquisitions, provide general working capital, and for letters of credit for Superior.
Unit is not a party to and does not guarantee Superior's credit agreement. Superior and its subsidiaries were not debtors in the Chapter 11 Cases, and the Superior credit agreement was not affected by Unit's bankruptcy.
6.625% Senior Subordinated Notes. The Notes were issued under an Indenture dated as of May 18, 2011, between the company and Wilmington Trust, National Association (successor to Wilmington Trust FSB), as Trustee (Trustee), as supplemented by the First Supplemental Indenture dated as of May 18, 2011, between us, the Guarantors, and the Trustee, and as further supplemented by the Second Supplemental Indenture dated as of January 7, 2013, between us, the Guarantors, and the Trustee (as supplemented, the 2011 Indenture), establishing the terms of and providing for issuing the Notes.
As a result of Unit's emergence from bankruptcy, the Notes were cancelled and our liability under the Notes was discharged as of the Effective Date. Holders of the Notes were issued shares of New Common Stock in accordance with the Plan.
DIP Credit Agreement. As contemplated by the Restructuring Support Agreement between the company and certain of the Note holders and our lenders, the company and the other Debtors entered into a Superpriority Senior Secured Debtor-in-Possession Credit Agreement dated May 27, 2020 ( DIP credit agreement), among the Debtors, the lenders under the facility (the DIP lenders), and BOKF, NA dba Bank of Oklahoma, as administrative agent, under which the DIP lenders agreed to provide us with the $36.0 million multiple-draw loan facility (DIP credit facility). The bankruptcy court entered an interim order on May 26, 2020 approving the DIP credit facility, permitting the Debtors to borrow up to $18.0 million on an interim basis. On June 19, 2020, the bankruptcy court granted final approval of the DIP credit facility.
Before its repayment and termination on the Effective Date, borrowings under the DIP credit facility matured on the earliest of (i) September 22, 2020 (subject to a two-month extension to be approved by the DIP Lenders), (ii) the sale of all or substantially all the assets of the Debtors under Section 363 of the Bankruptcy Code or otherwise, (iii) the effective date of a
plan of reorganization or liquidation in the Chapter 11 Cases, (iv) the entry of an order by the bankruptcy court dismissing any of the Chapter 11 Cases or converting such Chapter 11 Cases to a case under Chapter 7 of the Bankruptcy Code and (v) the date of termination of the DIP lenders’ commitments and the acceleration of any outstanding extensions of credit, in each case, under the DIP credit facility under and subject to the DIP Credit Agreement and the bankruptcy court’s orders.
On the Effective Date, the DIP credit facility was paid in full and terminated. On the Effective Date, each holder of an allowed claim under the DIP credit facility received its pro rata share of revolving loans, term loans, and letter-of-credit participations under the Exit Credit Agreement. In addition, each holder received (or was entitled to receive) its pro rata share of an equity fee under the Exit Credit Agreement equal to 5% of the New Common Stock (subject to dilution by shares reserved for issuance under a management incentive plan and on exercise of the Warrants).
For further information about the DIP Credit Agreement, please see Note 2 – Emergence From Voluntary Reorganization Under Chapter 11.
Warrants
Each holder of the Old Common Stock outstanding before the Effective Date that did not opt out of the release under the Plan, is entitled to receive its pro rata share of seven-year warrants (Warrants) to purchase an aggregate of 12.5% of the shares of New Common Stock, at an aggregate exercise price equal to the $650.0 million principal amount of the Notes plus interest thereon to the May 15, 2021 maturity date of the Notes. On the Effective Date, we entered into a Warrant Agreement (Warrant Agreement) with American Stock Transfer & Trust Company, LLC. The Warrants expire on the earliest of (i) September 3, 2027, (ii) consummation of a Cash Sale (as defined in the Warrant Agreement) or (iii) the consummation of a liquidation, dissolutions or winding up of the company (such earliest date, the Expiration Date). Each Warrant that is not exercised on or before the Expiration Date will expire, and all rights under that Warrant and the Warrant Agreement will cease on the Expiration Date. On December 21, 2020, we issued approximately 1.8 million Warrants to the holders of the Old Common Stock that did not opt out of the releases under the Plan and owned their shares of Old Common Stock in street name through the facilities of the DTC. On February 11, 2021, we issued 42,511 Warrants to certain holders of the Old Common Stock that did not opt out of the releases under the Plan and owned their shares through direct registration with the company’s transfer agent (Direct Registration). We expect to issue approximately 37,000 additional Warrants to the holders of the Old Common Stock that did not opt out of the releases under the Plan and owned their shares through Direct Registration. Under the Plan, additional Warrants will be issued in book-entry form through the facilities of the DTC, and each holder owning shares of Old Common Stock through Direct Registration must provide that holder’s brokerage account information to the company to receive such holder’s distribution of Warrants. Holders of shares of the Old Common Stock that owned shares through Direct Registration should contact Prime Clerk, LLC at (877) 720-6581 (Toll Free) or (646) 979-4412 (Local) to obtain the forms necessary to receive their distribution. Any distribution not made will be deemed forfeited at the first anniversary of the Effective Date.
Capital Requirements
Oil and Natural Gas Dispositions, Acquisitions, and Capital Expenditures. Most of our capital expenditures in our oil and natural gas are discretionary and directed toward growth. Any decision to increase our oil, NGLs, and natural gas reserves through acquisitions or through drilling depends on the prevailing or expected market conditions, potential return on investment, future drilling potential, and opportunities to obtain financing, which provide us flexibility in deciding when and if to incur these costs. During the Successor Period and Predecessor Period of 2020, we participated in the drilling of three wells (0.30 net wells) and 16 wells (0.35 net wells), respectively, compared to 115 gross wells (29.15 net wells) in 2019.
During the Successor Period of 2020, capital expenditures by this segment for oil and gas properties on the full cost method, excluding a $1.7 million reduction in the ARO liability and no acquisitions, totaled $4.0 million. During the Predecessor Period of 2020, capital expenditures, excluding a $29.2 million reduction in the ARO liability and $0.4 million in acquisitions (including associated ARO), totaled $5.4 million compared to 2019 capital expenditures of $264.9 million (excluding a $0.1 million reduction in the ARO liability and $3.7 million in acquisitions).
For 2021, we plan to focus our capital expenditures on development of proved properties and acquisition of proved and producing properties.
We sold non-core oil and natural gas assets, net of related expenses, for $0.4 million, $1.2 million and $21.8 million during the Successor Period, and Predecessor Period of 2020, and the year 2019, respectively. Proceeds from those dispositions
reduced the net book value of our full cost pool with no gain or loss recognized. We plan to pursue additional dispositions of non-core assets in 2021.
Contract Drilling Dispositions, Acquisitions, and Capital Expenditures. During 2019, we completed construction and placed into service our 12th, 13th, and 14th BOSS drilling rigs. These drilling rigs were subject to long-term contracts with third party operators.
We did not build any new BOSS drilling rigs during 2020. We have no commitments or current plans to build any additional BOSS drilling rigs in 2021.
For 2021, capital expenditures are expected to primarily be for maintenance capital on operating drilling rigs and the possible conversion of certain SCR drilling rigs to AC drilling rigs if practicable. We also plan to pursue the disposal or sale of our non-core, idle drilling rig fleet. For 2020, we incurred $0.6 million during the Successor Period and $2.4 million during the Predecessor Period in capital expenditures, compared to $40.6 million in 2019.
Mid-Stream Dispositions, Acquisitions, and Capital Expenditures. At the Cashion processing facility in central Oklahoma, total throughput volume for the fourth quarter of 2020 averaged approximately 64.2 MMcf per day and total production of natural gas liquids averaged approximately 252,000 gallons per day. For 2020, we continued to connect new wells to this system for third party producers. Since the first of 2020, we connected 18 new wells to this system from producers. The total processing capacity of the Cashion system is 105 MMcf per day.
In the Appalachian region at the Pittsburgh Mills gathering system, average gathered volume for the fourth quarter of 2020 was 131.7 MMcf per day and average gathered volume for 2020 was 152.3 MMcf per day. During 2020, we connected four new infill wells to an existing well pad.
Also, in the Appalachian area at our Snow Shoe gathering system, the average gathering volume for the fourth quarter was 2.5 MMcf per day and the average gathered volume for 2020 was 3.0 MMcf per day. In 2020, we did not connect any new wells to this system. At Snow Shoe for 2020, we also charged a demand fee based on a volume of 55 MMcf per day. This demand fee volume will be reduced in 2021 to 51 MMcf per day. Additionally, in 2020, we recognized a shortfall fee from a producer on this system for $5.3 million. This fee will be invoiced in the first quarter of 2021.
At the Hemphill processing facility located in the Texas panhandle, average total throughput volume for the fourth quarter of 2020 was 46.6 MMcf per day and average total throughput volume for 2020 was 51.3 MMcf per day. Total average production of natural gas liquids for the fourth quarter of 2020 decreased to approximately 110,000 gallons per day due to operating in ethane rejection. Total production of natural gas liquids for 2020 averaged approximately 152,000 gallons per day. The total processing capacity of the Hemphill system is 135 MMcf per day. In 2020, we did not connect any new wells to this system. Currently there are no active rigs in the area, and we do not anticipate any new well connects for this system.
At the Segno gathering system located in East Texas, the average throughput volume for the fourth quarter of 2020 decreased to approximately 31.0 MMcf per day due to declining production volume along with no new drilling activity in the area. For 2020, the average throughput volume for this system was approximately 40 MMcf per day. During 2020, we did not connect any new wells to this system.
Our mid-stream segment incurred $1.3 million during the Successor Period and $9.3 million during the Predecessor Period in capital expenditures as compared to $64.4 million in 2019, which included $16.1 million for an acquisition. For 2021, our estimated capital expenditures will be approximately $15.0 million which we expect to be primarily for the maintenance and operation of our assets and connection of new wells.
Contractual Commitments
At December 31, 2020, we had these contractual obligations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due by Period
|
|
|
Total
|
|
Less Than
1 Year
|
|
2-3
Years
|
|
4-5
Years
|
|
After
5 Years
|
|
|
(In thousands)
|
|
Long-term debt (1)
|
$
|
118,637
|
|
|
$
|
6,494
|
|
|
$
|
12,696
|
|
|
$
|
99,447
|
|
|
$
|
—
|
|
|
Operating leases (2)
|
5,520
|
|
|
4,075
|
|
|
1,376
|
|
|
16
|
|
|
53
|
|
|
Finance lease interest and maintenance (3)
|
558
|
|
|
558
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Firm transportation commitments (4)
|
1,379
|
|
|
1,020
|
|
|
359
|
|
|
—
|
|
|
—
|
|
|
Total contractual obligations
|
$
|
126,094
|
|
|
$
|
12,147
|
|
|
$
|
14,431
|
|
|
$
|
99,463
|
|
|
$
|
53
|
|
_________________________
1.See previous discussion in MD&A regarding our long-term debt. This obligation is presented in accordance with the terms of the Exit Facility and includes interest calculated using our December 31, 2020 interest rates of 6.6% for our Exit Credit Agreement. The Exit Credit Agreement has a maturity date of March 1, 2024 and had an outstanding balance as of December 31, 2020 of $99.0 million ($0.6 million is reflected as a current liability in our Consolidated Balance Sheets). The Superior credit agreement has a maturity date of May 10, 2023 and had no outstanding balance as of December 31, 2020.
2.We lease certain office space, land, and equipment, including pipeline equipment and office equipment under the terms of operating leases under ASC 842 expiring through March 2031. We also have short-term lease commitments of $0.2 million. This is lease office space or yards in Oklahoma City, Oklahoma; Houston and Odessa, Texas; Englewood, Colorado; and Pinedale, Wyoming under the terms of operating leases expiring through January 2022. Additionally, we have several equipment leases and lease space on short-term commitments to stack excess drilling rig equipment and production inventory.
3.Maintenance and interest payments are included in our finance lease agreements. The finance leases are discounted using annual rates of 4.0%. Total maintenance and interest remaining are $0.5 million and less than $0.1 million, respectively.
4.We have firm transportation commitments to transport our natural gas from various systems for approximately $1.0 million over the next twelve months and $0.4 million for the one year thereafter.
During the second quarter of 2018, as part of the Superior transaction (see Note 19 – 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 our consolidated mid-stream subsidiary. At December 31, 2020, 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 December 31, 2020 was $24.8 million. We do not anticipate meeting the contractual obligation over the remaining commitment period.
At December 31, 2020, we also had these commitments and contingencies that could create, increase or accelerate our liabilities:
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated Amount of Commitment Expiration Per Period
|
|
Other Commitments
|
Total
Accrued
|
|
Less
Than 1
Year
|
|
2-3
Years
|
|
4-5
Years
|
|
After 5
Years
|
|
|
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
Separation benefit plans (1)
|
$
|
4,201
|
|
|
$
|
1,543
|
|
|
Unknown
|
|
Unknown
|
|
Unknown
|
|
ARO liability (2)
|
$
|
23,356
|
|
|
$
|
2,121
|
|
|
$
|
3,240
|
|
|
$
|
3,159
|
|
|
$
|
14,836
|
|
|
Gas balancing liability (3)
|
$
|
3,997
|
|
|
Unknown
|
|
Unknown
|
|
Unknown
|
|
Unknown
|
|
|
|
|
|
|
|
|
|
|
|
|
Workers’ compensation liability (4)
|
$
|
10,164
|
|
|
$
|
1,705
|
|
|
Unknown
|
|
Unknown
|
|
Unknown
|
|
Finance lease obligations (5)
|
$
|
3,216
|
|
|
$
|
3,216
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Contract liability (6)
|
$
|
4,172
|
|
|
$
|
2,583
|
|
|
$
|
1,560
|
|
|
$
|
12
|
|
|
$
|
18
|
|
|
Other long-term liabilities (7)
|
$
|
1,321
|
|
|
$
|
—
|
|
|
$
|
1,321
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Derivative liabilities—commodity hedges
|
$
|
5,706
|
|
|
$
|
1,047
|
|
|
$
|
4,659
|
|
|
$
|
—
|
|
|
$
|
—
|
|
_________________________
1.As of the Effective Date, the Board adopted (i) the Amended and Restated Separation Benefit Plan of Unit Corporation and Participating Subsidiaries (Amended Separation Benefit Plan), (ii) the Amended and Restated Special Separation Benefit Plan of Unit Corporation and Participating Subsidiaries (Amended Special Separation Benefit Plan) and (iii) the Separation Benefit Plan of Unit Corporation and Participating Subsidiaries (New Separation Benefit Plan). In accordance with the Plan, the Amended Separation Benefit Plan and the Amended Special Separation Benefit Plan allow former employees or retained employees with vested severance benefits under either plan to receive certain cash payments in full satisfaction for their allowed separation claim under the Chapter 11 Cases. In accordance with the Plan, the New Separation Benefit Plan is a comprehensive severance plan for retained employees, including retained employees whose severance did not already vest under the Amended Separation Benefit Plan or the Amended Special Separation Benefit Plan. The New Separation Benefit Plan provides that eligible employees will be entitled to two weeks of severance pay per year of service, with a minimum of four weeks and a maximum of 13 weeks of severance pay.
2.When a well is drilled or acquired, under ASC 410 “Accounting for Asset Retirement Obligations,” we record the fair value of liabilities associated with the retirement of long-lived assets (mainly plugging and abandonment costs for our depleted wells).
3.We have recorded a liability for those properties we believe do not have sufficient oil, NGLs, and natural gas reserves to allow the under-produced owners to recover their under-production from future production volumes.
4.We have recorded a liability for future estimated payments related to workers’ compensation claims primarily associated with our contract drilling segment.
5.This amount includes commitments under finance lease arrangements for compressors in our mid-stream segment.
6.We have recorded a liability related to the timing of the revenue recognized on certain demand fees in our mid-stream segment.
7.Due to the issuance of the Coronavirus Aid, Relief, and Economic Security Act (CARES Act), we have deferred our FICA tax payment.
Derivative Activities
Periodically we enter into derivative transactions locking in the prices to be received for a portion of our oil, NGLs, or natural gas production. Any change in the fair value of all our derivatives are reflected in our Consolidated Statements of Operations.
Commodity Derivatives. Our commodity derivatives reduce our exposure to price volatility and manage price risks. Our decision on the type and quantity of our production and the price(s) of our derivative(s) is based, in part, on our view of current and future market conditions. As of December 31, 2020, based on our fourth quarter 2020 average daily production, the approximated percentages of our production under derivative contracts were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2021
|
|
2022
|
|
2023
|
|
Daily oil production
|
66
|
%
|
|
46
|
%
|
|
26
|
%
|
|
Daily natural gas production
|
55
|
%
|
|
45
|
%
|
|
25
|
%
|
For commodities subject to derivative contracts, those contracts limit the risk of downward price movements. But they also limit increases in future revenues that would otherwise result from price movements above the contracted prices.
Derivative transactions carry with them the risk that the counterparties may not be able to meet their financial obligations under the transactions. Based on our evaluation at December 31, 2020, we believe the risk of non-performance by our counterparties is not material. At December 31, 2020, the fair values of the net assets we had with each of the counterparties to our commodity derivative transactions was:
|
|
|
|
|
|
|
|
|
December 31, 2020
|
|
|
(In millions)
|
|
Bank of Oklahoma
|
$
|
(5.4)
|
|
|
Bank of Montreal
|
(0.3)
|
|
|
Total net liabilities
|
$
|
(5.7)
|
|
If a legal right of set-off exists, we net the value of the derivative arrangements we have with the same counterparty in our Consolidated Balance Sheets. At December 31, 2020, we recorded the fair value of our commodity derivatives on our balance sheet as current derivative liabilities of $1.0 million and long-term derivative liabilities of $4.7 million. At December 31, 2019, we recorded the fair value of our commodity derivatives on our balance sheet as current derivative assets of $0.6 million and long-term derivative liabilities of less than $0.1 million.
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.
These gains (losses) as of the periods indicated were:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
|
|
|
|
|
(In thousands)
|
|
Gain (loss) on derivatives, included are amounts settled during the period of ($1,133), ($4,244), and $16,196, respectively
|
$
|
(985)
|
|
|
|
$
|
(10,704)
|
|
|
$
|
4,225
|
|
|
|
Stock and Incentive Compensation
During 2020, we did not grant any awards. We recognized compensation expense of $6.1 million for all our prior restricted stock awards including the acceleration of the unrecorded stock compensation expense. We did not capitalize any compensation cost to oil and natural gas properties since we are currently not drilling.
During 2019, we granted awards covering 1,500,213 shares of restricted stock. These awards were granted as retention incentive awards and are being recognized over the awards' three-year vesting period. These awards were granted as retention incentive awards and are being recognized over their two- and three-year vesting periods.
On the Effective Date, all equity-based awards that were 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.
Insurance
We are self-insured for certain losses relating to workers’ compensation, general liability, 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 coverage we have will 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.
Oil and Natural Gas Limited Partnerships and Other Entity Relationships.
We were the general partner of 13 oil and natural gas partnerships formed privately or publicly. Each partnership’s revenues and costs were shared under formulas set out in that partnership’s agreement. The partnerships repaid us for contract
drilling, well supervision, and general and administrative expense. Related party transactions for contract drilling and well supervision fees were the related party’s share of such costs. These costs were billed the same as billings to unrelated third parties for similar services. General and administrative reimbursements consisted of direct general and administrative expense incurred on the related party’s behalf and indirect expenses assigned to the related parties. Allocations are based on the related party’s level of activity and were considered by us to be reasonable. Our proportionate share of assets, liabilities, and net income relating to the oil and natural gas partnerships is included in our consolidated financial statements for the years prior to termination. The partnerships were terminated during 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.
Effects of Inflation
The effect of inflation in the oil and natural gas industry is primarily driven by the prices for oil, NGLs, and natural gas. Increases in these prices increase the demand for our contract drilling rigs and services. This increase in demand affects the dayrates we can obtain for our contract drilling services. During periods of higher demand for our drilling rigs we have experienced increases in labor costs and the costs of services to support our drilling rigs. Historically, during this same period, when oil, NGLs, and natural gas prices declined, labor rates did not come back down to the levels existing before the increases. If commodity prices increase substantially for a long period, shortages in support equipment (like drill pipe, third party services, and qualified labor) can cause additional increases in our material and labor costs. Increases in dayrates for drilling rigs also increase the cost of drilling our oil and natural gas properties. How inflation will affect us in the future will depend on increases, if any, realized in our drilling rig rates, the prices we receive for our oil, NGLs, and natural gas, and the rates we receive for gathering and processing natural gas.
Off-Balance Sheet Arrangements
We do not currently utilize any off-balance sheet arrangements with unconsolidated entities to enhance liquidity and capital resource positions, or for any other purpose. However, as is customary in the oil and gas industry, we are subject to various contractual commitments.
Results of Operations
Provided below is a comparison of selected operating and financial data after eliminations (in thousands unless otherwise specified):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
|
|
Period
September 1, 2020
through
December 31, 2020
|
|
|
Period
January 1, 2020 through
August 31, 2020
|
|
Year Ended
|
|
|
|
|
|
|
|
December 31,
2019
|
|
Percent
Change (1)
|
|
Total revenue
|
$
|
133,528
|
|
|
|
$
|
276,957
|
|
|
$
|
674,634
|
|
|
(39)
|
%
|
|
Net loss
|
$
|
(13,988)
|
|
|
|
$
|
(890,624)
|
|
|
$
|
(553,828)
|
|
|
(63)
|
%
|
|
Net income attributable to non-controlling interest
|
$
|
4,152
|
|
|
|
$
|
40,388
|
|
|
$
|
51
|
|
|
NM
|
|
Net loss attributable to Unit Corporation
|
$
|
(18,140)
|
|
|
|
$
|
(931,012)
|
|
|
$
|
(553,879)
|
|
|
(71)
|
%
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Natural Gas:
|
|
|
|
|
|
|
|
|
|
Revenue
|
$
|
57,578
|
|
|
|
$
|
103,439
|
|
|
$
|
325,797
|
|
|
(51)
|
%
|
|
Operating costs excluding depreciation, depletion, amortization, and impairment
|
$
|
25,256
|
|
|
|
$
|
117,691
|
|
|
$
|
135,124
|
|
|
6
|
%
|
|
Depreciation, depletion, and amortization
|
$
|
14,869
|
|
|
|
$
|
68,762
|
|
|
$
|
168,651
|
|
|
(50)
|
%
|
|
Impairment of oil and natural gas properties
|
$
|
26,063
|
|
|
|
$
|
393,726
|
|
|
$
|
559,867
|
|
|
(25)
|
%
|
|
Average oil price received (Bbl)
|
$
|
37.29
|
|
|
|
$
|
31.98
|
|
|
$
|
57.49
|
|
|
(45)
|
%
|
|
Average oil price per barrel received excluding derivatives
|
$
|
39.23
|
|
|
|
$
|
35.14
|
|
|
$
|
55.13
|
|
|
(36)
|
%
|
|
Average NGL price received (Bbl)
|
$
|
9.28
|
|
|
|
$
|
4.83
|
|
|
$
|
12.42
|
|
|
(59)
|
%
|
|
Average NGLs price per barrel received excluding derivatives
|
$
|
9.28
|
|
|
|
$
|
4.83
|
|
|
$
|
12.42
|
|
|
(59)
|
%
|
|
Average natural gas price received (Mcf)
|
$
|
1.92
|
|
|
|
$
|
1.14
|
|
|
$
|
2.04
|
|
|
(41)
|
%
|
|
Average natural gas price per mcf received excluding derivatives
|
$
|
1.91
|
|
|
|
$
|
1.11
|
|
|
$
|
1.88
|
|
|
(38)
|
%
|
|
Oil production (MBbls)
|
626
|
|
|
|
1,562
|
|
|
3,208
|
|
|
(32)
|
%
|
|
NGLs production (MBbls)
|
1,045
|
|
|
|
2,399
|
|
|
4,773
|
|
|
(28)
|
%
|
|
Natural gas production (MMcf)
|
11,006
|
|
|
|
26,563
|
|
|
53,065
|
|
|
(29)
|
%
|
|
Depreciation, depletion, and amortization rate (Boe)
|
$
|
4.21
|
|
|
|
$
|
7.77
|
|
|
$
|
9.66
|
|
|
(30)
|
%
|
|
|
|
|
|
|
|
|
|
|
|
Contract Drilling:
|
|
|
|
|
|
|
|
|
|
Revenue
|
$
|
19,413
|
|
|
|
$
|
73,519
|
|
|
$
|
168,383
|
|
|
(45)
|
%
|
|
Operating costs excluding depreciation
|
$
|
13,852
|
|
|
|
$
|
51,810
|
|
|
$
|
115,998
|
|
|
(43)
|
%
|
|
Depreciation
|
$
|
2,102
|
|
|
|
$
|
15,544
|
|
|
$
|
51,552
|
|
|
(66)
|
%
|
|
Impairment of contract drilling equipment
|
$
|
—
|
|
|
|
$
|
410,126
|
|
|
$
|
—
|
|
|
—
|
%
|
|
Impairment of goodwill
|
$
|
—
|
|
|
|
$
|
—
|
|
|
$
|
62,809
|
|
|
(100)
|
%
|
|
Percentage of revenue from daywork contracts
|
100
|
%
|
|
|
100
|
%
|
|
100
|
%
|
|
—
|
%
|
|
Average number of drilling rigs in use
|
7.2
|
|
|
|
11.5
|
|
|
24.6
|
|
|
(59)
|
%
|
|
Total drilling rigs available for use at the end of the period
|
58
|
|
|
|
58
|
|
|
58
|
|
|
—
|
%
|
|
Average dayrate on daywork contracts
|
$
|
17,807
|
|
|
|
$
|
18,911
|
|
|
$
|
18,762
|
|
|
(1)
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
|
|
Period
September 1, 2020
through
December 31, 2020
|
|
|
Period
January 1, 2020 through
August 31, 2020
|
|
Year Ended
|
|
|
|
|
|
|
|
December 31,
2019
|
|
Percent
Change (1)
|
|
Mid-Stream:
|
|
|
|
|
|
|
|
|
|
Revenue
|
$
|
56,537
|
|
|
|
$
|
99,999
|
|
|
$
|
180,454
|
|
|
(13)
|
%
|
|
Operating costs excluding depreciation and amortization
|
$
|
42,169
|
|
|
|
$
|
68,045
|
|
|
$
|
133,606
|
|
|
(18)
|
%
|
|
Depreciation and amortization
|
$
|
10,659
|
|
|
|
$
|
29,371
|
|
|
$
|
47,663
|
|
|
(16)
|
%
|
|
Impairment of gas gathering and processing equipment and line fill
|
$
|
—
|
|
|
|
$
|
63,962
|
|
|
$
|
3,040
|
|
|
NM
|
|
Gas gathered—Mcf/day
|
324,892
|
|
|
|
388,506
|
|
|
435,646
|
|
|
(16)
|
%
|
|
Gas processed—Mcf/day
|
135,615
|
|
|
|
158,031
|
|
|
164,482
|
|
|
(8)
|
%
|
|
Gas liquids sold—gallons/day
|
441,761
|
|
|
|
612,301
|
|
|
625,873
|
|
|
(11)
|
%
|
|
Number of natural gas gathering systems
|
17
|
|
|
|
18
|
|
|
19
|
|
|
(7)
|
%
|
|
Number of processing plants
|
11
|
|
|
|
11
|
|
|
11
|
|
|
—
|
%
|
|
|
|
|
|
|
|
|
|
|
|
Corporate and other:
|
|
|
|
|
|
|
|
|
|
Loss on abandonment of assets
|
$
|
—
|
|
|
|
$
|
18,733
|
|
|
$
|
—
|
|
|
—
|
%
|
|
General and administrative expense
|
$
|
6,702
|
|
|
|
$
|
42,766
|
|
|
$
|
38,246
|
|
|
29
|
%
|
|
Other depreciation
|
$
|
332
|
|
|
|
$
|
1,819
|
|
|
$
|
7,707
|
|
|
(72)
|
%
|
|
Gain (loss) on disposition of assets
|
$
|
619
|
|
|
|
$
|
89
|
|
|
$
|
(3,502)
|
|
|
120
|
%
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
Interest income
|
$
|
—
|
|
|
|
$
|
58
|
|
|
$
|
49
|
|
|
18
|
%
|
|
Interest expense, net
|
$
|
(3,275)
|
|
|
|
$
|
(22,882)
|
|
|
$
|
(37,061)
|
|
|
(29)
|
%
|
|
Reorganization costs, net
|
$
|
(2,273)
|
|
|
|
$
|
133,975
|
|
|
$
|
—
|
|
|
—
|
%
|
|
Write-off debt issuance costs
|
$
|
—
|
|
|
|
$
|
(2,426)
|
|
|
$
|
—
|
|
|
—
|
%
|
|
Gain (loss) on derivatives
|
$
|
(985)
|
|
|
|
$
|
(10,704)
|
|
|
$
|
4,225
|
|
|
NM
|
|
Other
|
$
|
100
|
|
|
|
$
|
2,034
|
|
|
$
|
(236)
|
|
|
NM
|
|
Income tax benefit
|
$
|
(302)
|
|
|
|
$
|
(14,630)
|
|
|
$
|
(132,326)
|
|
|
89
|
%
|
|
Average interest rate
|
6.8
|
%
|
|
|
5.5
|
%
|
|
6.4
|
%
|
|
(14)
|
%
|
|
Average long-term debt outstanding
|
$
|
121,740
|
|
|
|
$
|
526,167
|
|
|
$
|
744,978
|
|
|
(35)
|
%
|
_________________________
1.NM – A percentage calculation is not meaningful due to a zero-value denominator or a percentage change greater than 200.
Oil and Natural Gas
Oil and natural gas revenues decreased $164.8 million or 51% in 2020 as compared to 2019 due primarily to lower commodity prices and production. Oil production decreased 32%, NGLs production decreased 28%, and natural gas production decreased 29%. Average oil prices between the comparative years decreased 45% to $31.61 per barrel, NGLs prices decreased 59% to $5.10 per barrel, and natural gas prices decreased 41% to $1.20 per Mcf.
Oil and natural gas operating costs increased $7.8 million or 6% between the comparative years of 2020 and 2019 primarily due to higher G&A expenses from the litigation settlements and no longer capitalizing directly related overhead costs in 2020 partially offset by lower LOE and gross production taxes.
DD&A decreased $85.0 million or 50% primarily due to a 30% decrease in our DD&A rate and a 29% decrease in equivalent production. The decrease in our DD&A rate resulted primarily from the effect of the ceiling test write-downs during 2020.
During the Successor Period of 2020, we recorded non-cash ceiling test write-downs of $26.1 million pre-tax 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. During the Predecessor Period of 2020, we recorded non-cash ceiling test write-downs of $393.7 million, pre-tax ($346.6 million, net of tax) due to the reduction for the 12-month average commodity prices and the impairment of our unproved oil and gas properties. We also recorded an expense of $17.6 million related to the write-down of our salt water disposal asset that we considered abandoned. During 2019, we recorded non-cash ceiling test write-downs of $559.4 million, pre-tax ($422.4 million, net of tax) due to the reduction of the 12-month average commodity prices and the removal of proved undeveloped reserves due to the uncertainty regarding our ability to finance future capital expenditures. We also recorded in 2019 a $0.5 million impairment on gathering systems with wells no longer producing.
Contract Drilling
Drilling revenues decreased $75.5 million or 45% in 2020 as compared to 2019. The decrease was due primarily to a 59% decrease in the average number of drilling rigs in use compared to 2019. Average drilling rig utilization decreased from 24.6 drilling rigs in 2019 to 10.1 drilling rigs in 2020.
Drilling operating costs decreased $50.3 million or 43% in 2020 compared to 2019. The decrease was due primarily to less drilling rigs operating. Contract drilling depreciation decreased $33.9 million or 66% also due primarily to less drilling rigs operating and from lower depreciable net book value due to impairments recognized in the first half of 2020.
At March 31, 2020, due to market conditions, we performed impairment testing on two asset groups which were comprised of the SCR diesel-electric drilling rigs and the 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 drilling equipment. These charges are included within impairment charges in our Consolidated Statements of Operations. No impairment was needed on the BOSS drilling rigs asset group as the undiscounted cash flows exceeded the carrying value of the asset group.
In 2019, we recognized goodwill impairment charges of $62.8 million, pre-tax ($59.8 million, net of tax) representing all our goodwill which is related to our contract drilling segment.
Mid-Stream
Our mid-stream revenues decreased $23.9 million or 13% in 2020 as compared to 2019 primarily due to decreased NGLs, gas, and condensate sales as a result of lower prices and lower volumes resulting from fewer wells connected and declining wellhead volumes. Gas processing volumes per day decreased 8% between the comparative years primarily due to lower purchased volumes from our processing facility in the Texas panhandle. Gas gathering volumes per day decreased 16% primarily due to lower volumes from most of our major gathering and processing systems resulting from fewer wells connected and declining wellhead volumes except from the Cashion facility.
Operating costs decreased $23.4 million or 18% in 2020 compared to 2019 primarily due to a decrease in purchase prices. Depreciation and amortization decreased $7.6 million or 16% primarily due to lower depreciable net book value from the impairment recognized in the first quarter of 2020.
During the first quarter of 2020, we determined that the carrying value of certain long-lived asset groups located 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. In 2019, we recorded a $3.0 million impairment due to decreased value of line fill due to lower prices and from the retirement of two older systems.
Loss on Abandonment of Assets
During the first quarter of 2020, we evaluated the carrying value of our salt water disposal assets. Based on our revised forecast of asset utilization, we determined certain assets were no longer expected to be used and wrote off certain salt water disposal assets that we now consider abandoned. We recorded expense of $17.6 million related to the write-down of our salt water disposal asset in the first quarter of 2020. In the third quarter of 2020, we recorded expense of $1.2 million related to the write-down of our drilling line asset.
General and Administrative
General and administrative expenses increased $11.2 million or 29% in 2020 compared to 2019 primarily due to consulting fees paid prior to filing for bankruptcy and costs incurred for separation benefits provided to employees that were part of our reduction in force in April 2020. We incurred $20.2 million in advisory and restructuring fees.
Gain (Loss) on Disposition of Assets
(Gain) loss on disposition of assets decreased $4.2 million in 2020 compared to 2019. The loss in 2020 was primarily related to the sale of vehicles, drilling rigs, and other drilling equipment, while the gain in 2019 was primarily from the retirement of old rig inventory.
Other Income (Expense)
Interest expense, net of capitalized interest, decreased $10.9 million between the comparative years of 2020 and 2019. We capitalized interest based on the net book value associated with unproved properties not being amortized, the construction of additional drilling rigs, and the construction of gas gathering systems. Because we are not currently undergoing any capital projects, we had no capitalized interest for 2020 compared to $16.2 million in 2019 that was netted against our gross interest of $53.2 million for 2019. Our average interest rate increased due to the new Exit Credit Agreement terms and our average debt outstanding was decreased primarily due to the Notes being settled with the Plan.
Reorganization Items, Net
Reorganization items, net represent any of the expenses, gains, and losses incurred subsequent to and as a direct result of the Chapter 11 proceedings. For more detail, see Note 2 – Emergence From Voluntary Reorganization Under Chapter 11.
Write-off of Debt Issuance Costs
Due to the remaining commitments of the Unit credit agreement being terminated by the lenders, the unamortized debt issuance costs of $2.4 million were written off during the second quarter of 2020.
Gain (Loss) on Derivatives
Gain (loss) on derivatives decreased $15.9 million primarily due to fluctuations in forward prices used to estimate the fair value in mark-to-market accounting.
Income Tax Benefit
Income tax benefit decreased $117.4 million in 2020 compared to 2019. We recognized an income tax benefit of $14.9 million in 2020 compared to an income tax benefit of $132.6 million in 2019. The 2020 income tax benefit was lower primarily due to the recognition of a full valuation allowance against our net deferred tax assets due to our emergence from bankruptcy in 2020 and fresh start accounting principles.
Our effective tax rate was 1.6% for 2020 compared to 19.3% for 2019. The effective tax rate for the current year was lower as compared to 2019 because of the recognition of a full valuation allowance as described above. The increase in our valuation allowance was due to determining it was more likely than not that the net deferred tax assets would not be fully realizable. We paid no federal or state income taxes during 2020.
Item 8. Financial Statements and Supplementary Data
Index to Financial Statements
Unit Corporation and Subsidiaries
|
|
|
|
|
|
|
|
|
Page
|
|
|
|
|
Consolidated Financial Statements:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Report of Independent Registered Public Accounting Firm
Board of Directors and Shareholders
Unit Corporation
Opinion on the financial statements
We have audited the accompanying consolidated balance sheet of Unit Corporation (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2020 (Successor), the related consolidated statements of operations, comprehensive income (loss), changes in shareholders’ equity, and cash flows for the period from September 1, 2020 to December 31, 2020 (Successor) and for the period from January 1, 2020 to August 31, 2020 (Predecessor), and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2020, and the results of its operations and its cash flows for the periods from September 1, 2020 to December 31, 2020 (Successor) and from January 1, 2020 to August 31, 2020 (Predecessor), in conformity with accounting principles generally accepted in the United States of America.
Basis of presentation
As discussed in Note 2 to the financial statements, the United States Bankruptcy Court for the District of Delaware entered an order confirming the plan for reorganization on August 6, 2020, and the Company emerged from bankruptcy on September 3, 2020. Accordingly, the accompanying financial statements have been prepared in conformity with FASB Accounting Standards Codification 852, Reorganizations, for the Successor as a new entity with assets, liabilities and a capital structure having carrying amounts not comparable with prior periods, as described in Note 3.
Basis for opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audit. We are a public accounting firm registered with the Public Company Accounting Oversight Board (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audit we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audit included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audit also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audit provides a reasonable basis for our opinion.
Critical audit matters
The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
Proved oil and natural gas property and depletion and proved property impairment — oil and natural gas reserve quantities and future cash flows
As described further in Note 4 to the financial statements, the Company accounts for its oil and natural gas properties using the full cost method of accounting which requires management to make estimates of proved reserve volumes and future net revenues to record depletion expense and to determine if any full cost ceiling impairment exists for its oil and natural gas properties, and if applicable, record impairment. To estimate the volume of proved oil and gas reserve quantities and future cash flows, management makes significant estimates and assumptions including forecasting the production decline rate of producing properties. In addition, the estimation of proved oil and gas reserve quantities is also impacted by management's judgments and estimates regarding the financial performance of wells associated with proved reserves to determine if wells are expected, with reasonable certainty, to be economical under the appropriate pricing assumptions required in the estimation of depletion expense and impairment expense. We identified the estimation of proved reserves of oil and natural gas properties to be a critical audit matter due to its impact on depletion expense and impairment of oil and natural gas properties.
The principal consideration for our determination that the estimation of proved reserves is a critical audit matter is that changes in certain inputs and assumptions, which require a high degree of management subjectivity, necessary to estimate the volume and future revenues of the Company's proved reserves could have a significant impact on the measurement of depletion expense or impairment expense. In turn, auditing those inputs and assumptions required complex auditor judgment.
Our audit procedures related to the estimation of proved reserves included the following, among others.
•We evaluated the knowledge, skill, and ability of the Company's third-party reservoir engineering specialists and their relationship to the Company, made inquiries of those reservoir engineers regarding the process followed and judgments made to estimate the proved reserve volumes, and read the reserve report prepared by the reservoir engineering specialists.
•We tested the accuracy of the Company’s depletion and impairment calculations that included these proved reserves.
•We evaluated sensitive inputs and assumptions used to determine proved reserve volumes and other financial inputs and assumptions, including certain assumptions that are derived from the Company's accounting records. These assumptions included historical pricing differentials, future operating costs, estimated future capital costs, and ownership interests.
•We tested management's process for determining the assumptions, including examining the underlying support, on a sample basis. Specifically, our audit procedures involved testing management's assumptions as follows:
◦We compared the estimated pricing differentials used in the reserve report to realized prices related to revenue transactions recorded in the current year and examined contractual support for the pricing differentials.
◦We evaluated the models used to estimate the future operating costs at year-end and compared the models to historical operating costs.
◦We evaluated the ownership interests used in the reserve report by inspecting lease and title records on a sample basis.
◦We applied analytical procedures to the reserve report by comparing the reserve report to historical actual results and to the prior year reserve report.
Emergence from bankruptcy — application of fresh start accounting
As described further in Notes 2 and 3, on September 3, 2020, the Company emerged from Chapter 11 bankruptcy. In connection with its emergence, the Company qualified for and adopted fresh start accounting. Management calculated a reorganization value, which represents the estimated fair value of the Successor's assets before considering liabilities and allocated the value to its individual assets based on their estimated fair values with the assistance of a third-party valuation specialist. We identified the application of fresh start accounting to be a critical audit matter.
The principal consideration for our determination that the Company’s application of fresh start accounting is a critical audit matter is that fresh start accounting requires assets and liabilities, including deferred income taxes, to be remeasured as described above. The remeasurement required management to make significant judgments in determining the relative fair values of assets and liabilities that existed at the emergence from bankruptcy and to record the income tax impact of the
Company’s emergence from bankruptcy and our audit procedures involved increased audit effort due to the high degree of auditor judgment necessary.
Our audit procedures related to the fair value measurements and income tax adjustments resulting from the Company’s application of fresh start accounting included the following, among others.
•With the assistance of our valuation specialists, we evaluated the qualifications and objectivity of the Company’s third-party valuation specialists that assisted management in applying fresh start accounting.
•We evaluated the methodology used by management to estimate the fair values of the Successor’s assets upon emergence from bankruptcy and tested certain key data and assumptions impactful to those valuations.
•We performed procedures similar to those described above on the estimated oil and natural gas reserves that were a key input to the valuation of proved oil and natural gas properties at emergence from bankruptcy.
•We assessed the appropriateness of market data, such as recent transactions, comparable multiples and discount rates, used by the Company’s third-party valuation specialists to value other tangible assets of the Successor.
•We evaluated the key assumptions used in certain discounted cash flow analysis supporting asset values including forecasted revenues, operating income, and discount rates by comparing to historical results and comparable transactions.
•With the assistance of our income tax specialists, we evaluated the income tax adjustments recorded by management to reflect the effects of the bankruptcy reorganization and the application of fresh start accounting. Our procedures included the following, among others:
◦We evaluated the qualifications and objectivity of the Company’s third-party income tax specialists that assisted management in applying fresh start accounting.
◦We evaluated management’s judgments made with respect to changes in tax attributes, net operating loss carryforwards, and other asset basis and tax election changes that resulted from the application of fresh start accounting.
◦We tested management’s calculation of cancellation of debt income, including the computations of adjusted issue price.
◦We tested the completeness and accuracy of data used by management and the Company’s income tax specialists to measure the deferred income taxes of the Successor Company following emergence from bankruptcy.
Investment in Superior Pipeline Company, L.L.C. — accounting for a variable interest entity
As described further in Note 19, the Company accounts for its investment in Superior Pipeline Company, L.L.C. (“Superior”) as a variable interest entity (“VIE”). Management determined that the Company is the primary beneficiary of the VIE and therefore consolidates the accounts of Superior and records a non-controlling interest related to the other owner’s interest in Superior. The determination that the Company is the primary beneficiary of the VIE results in material amounts of assets, liabilities, revenues, and expenses being recorded in the Company’s financial statements. We identified the accounting for the Company’s investment in Superior as a critical audit matter.
The principal consideration for our determination that the accounting for the Company’s investment in Superior is a critical audit matter is that the determination of which owner of Superior represents the primary beneficiary of the VIE required management to make a subjective assessment of what activities are the most impactful to the VIE and which partner has the power to direct those activities. Management’s assessment process included evaluating rights of each owner as outlined in various organizational documents and management services agreements which govern the operations of the VIE. Auditing management’s conclusions with respect to the accounting for the VIE involved complex auditor judgment.
Our audit procedures related to the accounting for the Company’s investment in Superior included the following, among others.
•We inspected certain documents of Superior pertaining to how the entity is managed and governed to test management’s assertion regarding various rights of each owner.
•We inquired of management and the owners regarding the business purpose of the VIE and who directs the activities that are most impactful to the VIE.
•We consulted with our national office resources to assess management’s conclusions that Superior is a VIE and that the Company is the primary beneficiary.
/s/ GRANT THORNTON LLP
Tulsa, Oklahoma
March 31, 2021
We have served as the Company's auditor since 2020.
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders of Unit Corporation
Opinion on the Financial Statements
We have audited the consolidated balance sheet, statements of operations, comprehensive income (loss), changes in shareholders’ equity, and cash flows of Unit Corporation and its subsidiaries (the “Company”) for the year ended December 31, 2019, including the related notes and financial statement schedule listed in the index appearing under Item 15(a)(2) (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the results of operations and cash flows of the Company for the year ended December 31, 2019 in conformity with accounting principles generally accepted in the United States of America.
Substantial Doubt About the Company’s Ability to Continue as a Going Concern
The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 2 to the consolidated financial statements, the Company has incurred significant losses, is in a negative working capital position, and does not anticipate that forecasted cash and available credit capacity will be sufficient to meet their commitments over the next twelve months, which raises substantial doubt about its ability to continue as a going concern. Management’s plan in regard to these matters are also described in Note 2. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audit. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit of these consolidated financial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud.
Our audit included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audit also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audit provides a reasonable basis for our opinion.
/s/ PricewaterhouseCoopers LLP
Tulsa, Oklahoma
March 16, 2020
We served as the Company’s auditor from 1989 to 2020.
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
December 31,
2020
|
|
|
December 31,
2019
|
|
|
(In thousands except share and par value amounts)
|
|
ASSETS
|
|
|
|
|
|
Current assets:
|
|
|
|
|
|
Cash and cash equivalents
|
$
|
12,145
|
|
|
|
$
|
571
|
|
|
Restricted cash
|
569
|
|
|
|
—
|
|
|
Accounts receivable, net of allowance for doubtful accounts of $3,783 and $2,332 at December 31, 2020 and December 31, 2019, respectively
|
57,846
|
|
|
|
82,656
|
|
|
Materials and supplies
|
—
|
|
|
|
449
|
|
|
Current derivative asset (Note 15)
|
—
|
|
|
|
633
|
|
|
Current income taxes receivable
|
1,150
|
|
|
|
1,756
|
|
|
Assets held for sale (Note 4)
|
—
|
|
|
|
5,908
|
|
|
Prepaid expenses and other
|
11,212
|
|
|
|
13,078
|
|
|
Total current assets
|
82,922
|
|
|
|
105,051
|
|
|
Property and equipment:
|
|
|
|
|
|
Oil and natural gas properties, on the full cost method:
|
|
|
|
|
|
Proved properties
|
238,581
|
|
|
|
6,341,582
|
|
|
Unproved properties not being amortized
|
1,591
|
|
|
|
252,874
|
|
|
Drilling equipment
|
63,687
|
|
|
|
1,295,713
|
|
|
Gas gathering and processing equipment
|
251,404
|
|
|
|
824,699
|
|
|
Saltwater disposal systems
|
—
|
|
|
|
69,692
|
|
|
Corporate land and building
|
32,635
|
|
|
|
59,080
|
|
|
Transportation equipment
|
3,130
|
|
|
|
29,723
|
|
|
Other
|
9,961
|
|
|
|
57,992
|
|
|
|
600,989
|
|
|
|
8,931,355
|
|
|
Less accumulated depreciation, depletion, amortization, and impairment
|
54,189
|
|
|
|
6,978,669
|
|
|
Net property and equipment
|
546,800
|
|
|
|
1,952,686
|
|
|
Right of use asset (Note 17)
|
5,592
|
|
|
|
5,673
|
|
|
Other assets
|
14,389
|
|
|
|
26,642
|
|
|
Total assets (1)
|
$
|
649,703
|
|
|
|
$
|
2,090,052
|
|
The accompanying notes are an integral part of the consolidated financial statements.
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS - (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
December 31,
2020
|
|
|
December 31,
2019
|
|
|
(In thousands except share and par value amounts)
|
|
LIABILITIES AND SHAREHOLDERS’ EQUITY
|
|
|
|
|
|
Current liabilities:
|
|
|
|
|
|
Accounts payable
|
$
|
40,829
|
|
|
|
$
|
84,481
|
|
|
Accrued liabilities (Note 8)
|
21,743
|
|
|
|
46,562
|
|
|
|
|
|
|
|
|
Current operating lease liability (Note 17)
|
4,075
|
|
|
|
3,430
|
|
|
Current portion of long-term debt (Note 9)
|
600
|
|
|
|
108,200
|
|
|
Current derivative liabilities (Note 15)
|
1,047
|
|
|
|
—
|
|
|
Warrant liability (Note 2)
|
885
|
|
|
|
—
|
|
|
Current portion of other long-term liabilities (Note 9)
|
11,168
|
|
|
|
17,376
|
|
|
Total current liabilities
|
80,347
|
|
|
|
260,049
|
|
|
Long-term debt less debt issuance costs (Note 9)
|
98,400
|
|
|
|
663,216
|
|
|
Non-current derivative liabilities (Note 15)
|
4,659
|
|
|
|
27
|
|
|
Operating lease liability (Note 17)
|
1,445
|
|
|
|
2,071
|
|
|
Other long-term liabilities (Note 9)
|
39,259
|
|
|
|
95,341
|
|
|
Deferred income taxes (Note 11)
|
—
|
|
|
|
13,713
|
|
|
Commitments and contingencies (Note 18)
|
|
|
|
|
|
Shareholders’ equity:
|
|
|
|
|
|
Predecessor preferred stock, $1.00 par value, 5,000,000 shares authorized, none issued at December 31, 2019
|
—
|
|
|
|
—
|
|
|
Successor preferred stock, $0.01 par value, 1,000,000 shares authorized, none issued at December 31, 2020
|
—
|
|
|
|
—
|
|
|
Predecessor common stock, $0.20 par value, 175,000,000 shares authorized, 55,443,393 shares issued as of December 31, 2019
|
—
|
|
|
|
10,591
|
|
|
Successor common stock, $0.01 par value, 25,000,000 shares authorized, 12,000,000 shares issued as of December 31, 2020
|
120
|
|
|
|
—
|
|
|
Predecessor capital in excess of par value
|
—
|
|
|
|
644,152
|
|
|
Successor capital in excess of par value
|
197,242
|
|
|
|
—
|
|
|
Retained earnings (deficit)
|
(18,140)
|
|
|
|
199,135
|
|
Total shareholders' equity attributable to Unit Corporation
|
179,222
|
|
|
|
853,878
|
|
|
Non-controlling interests in consolidated subsidiaries
|
246,371
|
|
|
|
201,757
|
|
|
Total shareholders’ equity
|
425,593
|
|
|
|
1,055,635
|
|
|
Total liabilities and shareholders’ equity (1)
|
$
|
649,703
|
|
|
|
$
|
2,090,052
|
|
_________________________
1.Unit Corporation's consolidated total assets as of December 31, 2020 include current and long-term assets of its variable interest entity (VIE) (Superior) of $45.8 million and $247.8 million, respectively, which can only be used to settle obligations of the VIE. Unit Corporation's consolidated total liabilities as of December 31, 2020 include current and long-term liabilities of the VIE of $28.4 million and $2.6 million, respectively, for which the creditors of the VIE have no recourse to Unit Corporation. Unit Corporation's consolidated total assets as of December 31, 2019 include current and long-term assets of its variable interest entity (VIE) (Superior) of $28.8 million and $434.3 million, respectively, which can only be used to settle obligations of the VIE. Unit Corporation's consolidated total liabilities as of December 31, 2019 include current and long-term liabilities of the VIE of $32.2 million and $26.0 million, respectively, for which the creditors of the VIE have no recourse to Unit Corporation. See Note 19 – Variable Interest Entity Arrangements.
The accompanying notes are an integral part of the consolidated financial statements.
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
|
|
|
|
|
(In thousands except per share amounts)
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
Oil and natural gas
|
$
|
57,578
|
|
|
|
$
|
103,439
|
|
|
$
|
325,797
|
|
|
|
|
Contract drilling
|
19,413
|
|
|
|
73,519
|
|
|
168,383
|
|
|
|
|
Gas gathering and processing
|
56,537
|
|
|
|
99,999
|
|
|
180,454
|
|
|
|
|
Total revenues
|
133,528
|
|
|
|
276,957
|
|
|
674,634
|
|
|
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
Operating costs:
|
|
|
|
|
|
|
|
|
|
Oil and natural gas
|
25,256
|
|
|
|
117,691
|
|
|
135,124
|
|
|
|
|
Contract drilling
|
13,852
|
|
|
|
51,810
|
|
|
115,998
|
|
|
|
|
Gas gathering and processing
|
42,169
|
|
|
|
68,045
|
|
|
133,606
|
|
|
|
|
Total operating costs
|
81,277
|
|
|
|
237,546
|
|
|
384,728
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion, and amortization
|
27,962
|
|
|
|
115,496
|
|
|
275,573
|
|
|
|
|
Impairments (Note 4)
|
26,063
|
|
|
|
867,814
|
|
|
625,716
|
|
|
|
|
Loss on abandonment of assets
|
—
|
|
|
|
18,733
|
|
|
—
|
|
|
|
|
General and administrative
|
6,702
|
|
|
|
42,766
|
|
|
38,246
|
|
|
|
|
(Gain) loss on disposition of assets
|
(619)
|
|
|
|
(89)
|
|
|
3,502
|
|
|
|
|
Total operating expenses
|
141,385
|
|
|
|
1,282,266
|
|
|
1,327,765
|
|
|
|
|
Loss from operations
|
(7,857)
|
|
|
|
(1,005,309)
|
|
|
(653,131)
|
|
|
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
Interest, net
|
(3,275)
|
|
|
|
(22,824)
|
|
|
(37,012)
|
|
|
|
|
Write-off debt issuance costs
|
—
|
|
|
|
(2,426)
|
|
|
—
|
|
|
|
|
Gain (loss) on derivatives
|
(985)
|
|
|
|
(10,704)
|
|
|
4,225
|
|
|
|
|
Reorganization items, net
|
(2,273)
|
|
|
|
133,975
|
|
|
—
|
|
|
|
|
Other
|
100
|
|
|
|
2,034
|
|
|
(236)
|
|
|
|
|
Total other income (expense)
|
(6,433)
|
|
|
|
100,055
|
|
|
(33,023)
|
|
|
|
|
Loss before income taxes
|
(14,290)
|
|
|
|
(905,254)
|
|
|
(686,154)
|
|
|
|
|
Income tax benefit:
|
|
|
|
|
|
|
|
|
|
Current
|
(302)
|
|
|
|
(917)
|
|
|
(1,281)
|
|
|
|
|
Deferred
|
—
|
|
|
|
(13,713)
|
|
|
(131,045)
|
|
|
|
|
Total income taxes
|
(302)
|
|
|
|
(14,630)
|
|
|
(132,326)
|
|
|
|
|
Net loss
|
(13,988)
|
|
|
|
(890,624)
|
|
|
(553,828)
|
|
|
|
|
Net income attributable to non-controlling interest
|
4,152
|
|
|
|
40,388
|
|
|
51
|
|
|
|
|
Net loss attributable to Unit Corporation
|
$
|
(18,140)
|
|
|
|
$
|
(931,012)
|
|
|
$
|
(553,879)
|
|
|
|
|
Net loss attributable to Unit Corporation per common share (Note 7):
|
|
|
|
|
|
|
|
|
|
Basic
|
$
|
(1.51)
|
|
|
|
$
|
(17.45)
|
|
|
$
|
(10.48)
|
|
|
|
|
Diluted
|
$
|
(1.51)
|
|
|
|
$
|
(17.45)
|
|
|
$
|
(10.48)
|
|
|
|
The accompanying notes are an integral part of the consolidated financial statements.
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
|
|
|
|
|
|
|
|
(In thousands)
|
|
Net loss
|
$
|
(13,988)
|
|
|
|
$
|
(890,624)
|
|
|
$
|
(553,828)
|
|
|
|
|
Other comprehensive income (loss), net of taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reclassification adjustment for write-down of securities, net of tax of $0, $0, and $(47)
|
—
|
|
|
|
—
|
|
|
481
|
|
|
|
|
Comprehensive loss
|
(13,988)
|
|
|
|
(890,624)
|
|
|
(553,347)
|
|
|
|
|
Less: Comprehensive income attributable to non-controlling interest
|
4,152
|
|
|
|
40,388
|
|
|
51
|
|
|
|
|
Comprehensive loss attributable to Unit Corporation
|
$
|
(18,140)
|
|
|
|
$
|
(931,012)
|
|
|
$
|
(553,398)
|
|
|
|
The accompanying notes are an integral part of the consolidated financial statements.
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY
Year Ended December 31, 2019 and Predecessor Period and Successor Period of 2020
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shareholders' Equity Attributable to Unit Corporation
|
|
|
|
|
|
|
Common
Stock
|
|
Capital In Excess
of Par Value
|
|
Accumulated Other Comprehensive Loss
|
|
Retained Earnings (Deficit)
|
|
Non-controlling Interest in Consolidated Subsidiaries
|
|
Total
|
|
|
(In thousands except per share amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances, January 1, 2019
|
10,414
|
|
|
628,108
|
|
|
(481)
|
|
|
752,840
|
|
|
202,563
|
|
|
1,593,444
|
|
|
Cumulative effect adjustment for adoption of ASUs
|
—
|
|
|
—
|
|
|
—
|
|
|
174
|
|
|
—
|
|
|
174
|
|
|
Net income (loss)
|
—
|
|
|
—
|
|
|
—
|
|
|
(553,879)
|
|
|
51
|
|
|
(553,828)
|
|
|
Other comprehensive income (net of tax $(47))
|
—
|
|
|
—
|
|
|
481
|
|
|
—
|
|
|
—
|
|
|
481
|
|
|
Total comprehensive loss
|
|
|
|
|
|
|
|
|
|
|
(553,347)
|
|
|
Distribution to non-controlling interest
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(918)
|
|
|
(918)
|
|
|
Activity in employee compensation plans
|
177
|
|
|
16,044
|
|
|
—
|
|
|
—
|
|
|
61
|
|
|
16,282
|
|
|
Balances, December 31, 2019
|
10,591
|
|
|
644,152
|
|
|
—
|
|
|
199,135
|
|
|
201,757
|
|
|
1,055,635
|
|
|
Net income (loss)
|
—
|
|
|
—
|
|
|
—
|
|
|
(931,012)
|
|
|
40,388
|
|
|
(890,624)
|
|
|
Activity in employee compensation plans
|
113
|
|
|
6,001
|
|
|
—
|
|
|
—
|
|
|
55
|
|
|
6,169
|
|
|
Balances, August 31, 2020 (Predecessor)
|
10,704
|
|
|
650,153
|
|
|
—
|
|
|
(731,877)
|
|
|
242,200
|
|
|
171,180
|
|
|
Cancellation of Predecessor equity
|
(10,704)
|
|
|
(650,153)
|
|
|
—
|
|
|
731,877
|
|
|
—
|
|
|
71,020
|
|
|
Issuance of Successor equity
|
120
|
|
|
197,203
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
197,323
|
|
|
Balances, September 1, 2020 (Successor)
|
120
|
|
|
197,203
|
|
|
—
|
|
|
—
|
|
|
242,200
|
|
|
439,523
|
|
|
Net income (loss)
|
—
|
|
|
—
|
|
|
—
|
|
|
(18,140)
|
|
|
4,152
|
|
|
(13,988)
|
|
|
Activity in employee compensation plans
|
—
|
|
|
39
|
|
|
—
|
|
|
—
|
|
|
19
|
|
|
58
|
|
|
Balances, December 31, 2020 (Successor)
|
$
|
120
|
|
|
$
|
197,242
|
|
|
$
|
—
|
|
|
$
|
(18,140)
|
|
|
$
|
246,371
|
|
|
$
|
425,593
|
|
The accompanying notes are an integral part of the consolidated financial statements.
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
|
|
|
|
|
(In thousands)
|
|
OPERATING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
Net loss
|
$
|
(13,988)
|
|
|
|
$
|
(890,624)
|
|
|
$
|
(553,828)
|
|
|
|
|
Adjustments to reconcile net loss to net cash provided by operating activities:
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion, and amortization
|
27,962
|
|
|
|
115,496
|
|
|
275,573
|
|
|
|
|
Impairments (Note 4)
|
26,063
|
|
|
|
867,814
|
|
|
625,716
|
|
|
|
|
Loss on abandonment of assets (Note 4)
|
—
|
|
|
|
18,733
|
|
|
—
|
|
|
|
|
Amortization of debt issuance costs and debt discount (Note 9)
|
—
|
|
|
|
1,079
|
|
|
2,241
|
|
|
|
|
(Gain) loss on derivatives (Note 15)
|
985
|
|
|
|
10,704
|
|
|
(4,225)
|
|
|
|
|
Cash receipts (payments) on derivatives settled (Note 15)
|
(1,133)
|
|
|
|
(4,244)
|
|
|
16,196
|
|
|
|
|
(Gain) loss on disposition of assets
|
(619)
|
|
|
|
(89)
|
|
|
3,502
|
|
|
|
|
Write-off of debt issuance costs
|
—
|
|
|
|
2,426
|
|
|
—
|
|
|
|
|
Deferred tax benefit (Note 11)
|
—
|
|
|
|
(13,713)
|
|
|
(131,045)
|
|
|
|
|
Employee stock compensation plans
|
58
|
|
|
|
4,786
|
|
|
12,932
|
|
|
|
|
Bad debt expense
|
—
|
|
|
|
3,155
|
|
|
527
|
|
|
|
|
ARO liability accretion (Note 10)
|
467
|
|
|
|
1,545
|
|
|
2,343
|
|
|
|
Contract assets and liabilities, net (Note 5)
|
1,316
|
|
|
|
2,459
|
|
|
(2,577)
|
|
|
|
|
Noncash reorganization items
|
67
|
|
|
|
(138,797)
|
|
|
—
|
|
|
|
|
Other, net
|
(3,046)
|
|
|
|
12,164
|
|
|
1,766
|
|
|
|
Changes in operating assets and liabilities increasing (decreasing) cash:
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
(7,226)
|
|
|
|
28,880
|
|
|
33,323
|
|
|
|
|
Materials and supplies
|
—
|
|
|
|
89
|
|
|
24
|
|
|
|
|
Prepaid expenses and other
|
1,795
|
|
|
|
(3,849)
|
|
|
195
|
|
|
|
|
Accounts payable
|
1,484
|
|
|
|
(18,381)
|
|
|
(15,558)
|
|
|
|
|
Accrued liabilities
|
(4,048)
|
|
|
|
44,811
|
|
|
3,142
|
|
|
|
|
Income taxes
|
(301)
|
|
|
|
906
|
|
|
298
|
|
|
|
|
Contract advances
|
(29)
|
|
|
|
(394)
|
|
|
(1,149)
|
|
|
|
|
Net cash provided by operating activities
|
29,807
|
|
|
|
44,956
|
|
|
269,396
|
|
|
|
|
INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
(4,057)
|
|
|
|
(25,775)
|
|
|
(406,665)
|
|
|
|
|
Producing property and other oil and natural gas acquisitions
|
—
|
|
|
|
(382)
|
|
|
(3,653)
|
|
|
|
|
Other acquisitions
|
—
|
|
|
|
—
|
|
|
(16,109)
|
|
|
|
|
Proceeds from disposition of property and equipment
|
1,799
|
|
|
|
6,018
|
|
|
31,864
|
|
|
|
|
Net cash used in investing activities
|
(2,258)
|
|
|
|
(20,139)
|
|
|
(394,563)
|
|
|
|
The accompanying notes are an integral part of the consolidated financial statements.
72
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
|
|
|
|
|
(In thousands)
|
|
FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
Borrowings under line of credit, including borrowings under DIP credit facility
|
$
|
—
|
|
|
|
$
|
87,400
|
|
|
$
|
493,500
|
|
|
|
|
Payments under line of credit
|
(49,000)
|
|
|
|
(64,100)
|
|
|
(368,800)
|
|
|
|
|
DIP financing costs
|
—
|
|
|
|
(990)
|
|
|
—
|
|
|
|
|
Exit facility financing costs
|
—
|
|
|
|
(3,225)
|
|
|
—
|
|
|
|
|
Net payments on finance leases
|
(1,406)
|
|
|
|
(2,757)
|
|
|
(4,001)
|
|
|
|
|
Proceeds from investments in non-controlling interest
|
—
|
|
|
|
—
|
|
|
—
|
|
|
|
|
Employee taxes paid by withholding shares
|
—
|
|
|
|
(43)
|
|
|
(4,158)
|
|
|
|
|
Transaction costs associated with sale of non-controlling interest
|
—
|
|
|
|
—
|
|
|
—
|
|
|
|
|
Distributions to non-controlling interest
|
—
|
|
|
|
—
|
|
|
(918)
|
|
|
|
|
Bank overdrafts (Note 4)
|
2,631
|
|
|
|
(8,733)
|
|
|
3,663
|
|
|
|
|
Net cash provided by (used in) financing activities
|
(47,775)
|
|
|
|
7,552
|
|
|
119,286
|
|
|
|
|
Net increase (decrease) in cash, restricted cash, and cash equivalents
|
(20,226)
|
|
|
|
32,369
|
|
|
(5,881)
|
|
|
|
|
Cash, restricted cash, and cash equivalents, beginning of period
|
32,940
|
|
|
|
571
|
|
|
6,452
|
|
|
|
|
Cash, restricted cash, and cash equivalents, end of period
|
$
|
12,714
|
|
|
|
$
|
32,940
|
|
|
$
|
571
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental disclosure of cash flow information:
|
|
|
|
|
|
|
|
|
|
Cash paid during the year for:
|
|
|
|
|
|
|
|
|
|
Interest paid (net of capitalized)
|
$
|
2,571
|
|
|
|
$
|
6,417
|
|
|
$
|
33,694
|
|
|
|
|
Income taxes
|
$
|
—
|
|
|
|
$
|
—
|
|
|
$
|
273
|
|
|
|
|
Reorganization items
|
$
|
2,206
|
|
|
|
$
|
4,822
|
|
|
$
|
—
|
|
|
|
|
Changes in accounts payable and accrued liabilities related to purchases of property, plant, and equipment
|
$
|
1,902
|
|
|
|
$
|
8,561
|
|
|
$
|
54,549
|
|
|
|
|
Non-cash reductions to oil and natural gas properties related to asset retirement obligations
|
$
|
1,702
|
|
|
|
$
|
29,189
|
|
|
$
|
(76)
|
|
|
|
|
Non-cash trade of property, plant, and equipment
|
$
|
—
|
|
|
|
$
|
1,403
|
|
|
$
|
—
|
|
|
|
The accompanying notes are an integral part of the consolidated financial statements.
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 – ORGANIZATION
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 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, 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 Colorado, Kansas, Louisiana, Montana, New Mexico, North Dakota, Utah, and Wyoming.
Contract Drilling. Carried out by our subsidiary, Unit Drilling Company, 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, North Dakota, and to a lesser extent in Colorado.
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.
NOTE 2 – EMERGENCE FROM VOLUNTARY REORGANIZATION UNDER CHAPTER 11
Voluntary Reorganization Under Chapter 11 of the Bankruptcy Code
On May 22, 2020, the Debtors filed voluntary petitions for reorganization under Chapter 11 of the Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas, Houston Division. The Chapter 11 proceedings were jointly administered under Case No. 20-32740 (DRJ). During the pendency of the Chapter 11 Cases, the Debtors operated their business as "debtors-in-possession" under the authority of the bankruptcy court and under the Bankruptcy Code.
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 Plan on a final basis. On September 3, 2020, the conditions to effectiveness for the Plan were satisfied, and the Debtors emerged from Chapter 11.
Following emergence, we implemented the Plan as follows:
•Each lender under the (i) the Unit credit agreement, and (ii) the DIP Credit Agreement received (or was entitled to receive) its pro rata share of revolving loans, term loans, and letter of credit participations under the Exit Credit Agreement, in exchange for the lender’s allowed claims under the Unit credit agreement or DIP Credit Agreement;
•Each lender under the Unit credit agreement and the DIP Credit Agreement received its pro rata share of an equity fee under the exit facility equal to 5% of the New Common Stock (subject to dilution by shares reserved for issuance under a management incentive plan and upon exercise of the warrants described below);
•The company issued a total of 12.0 million shares of New Common Stock at a par value of $0.01 per share to be subsequently distributed in accordance with the Plan;
•Each holder of the Notes received its pro rata share of New Common Stock based on equity allocations at each of Unit, UDC, and UPC in exchange for the holder’s allowed Notes claim;
•Each holder of an allowed general unsecured claim against Unit or UPC was entitled to receive its pro rata share of New Common Stock based on equity allocations at each of Unit and UPC, respectively;
•A disputed claims reserve was established for distribution of New Common Stock on allowance of certain disputed general unsecured claims;
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
•Each holder of an allowed general unsecured claim against UDC, 8200 Unit, Unit Drilling Colombia and Unit Drilling USA received payment or will receive payment in full for that claim in the ordinary course of business; and
•Each retained or former employee with a claim for vested severance benefits, who opted into a settlement, received or will receive cash payment(s) for the claim in lieu of an allocation of New Common Stock otherwise provided to holders of general unsecured claims.
On December 11, 2020, approximately 10.5 million shares of New Common Stock were distributed to the holders of the Notes entitled to receive their pro rata share of New Common Stock based on equity allocations at each of Unit, UDC, and UPC in exchange for the holder’s allowed Notes claim. The remaining 0.9 million shares are being held for the Disputed Claims Reserve.
All shares of New Common Stock are subject to the transfer restrictions in the company’s Amended and Restated Certificate of Incorporation (Charter). Article XIV of the Charter provides that, subject to the exceptions provided in Article XIV, any attempted transfer of the New Common Stock will be prohibited and void ab initio if (i) because of the transfer, any person becomes a Substantial Stockholder (as defined below) other than by reason of Treasury Regulations section 1.382-2T(j)(3) or (ii) the Percentage Stock Ownership (as defined in the Charter) interest of any Substantial Stockholder will be increased. A “Substantial Stockholder” means a person with a Percentage Stock Ownership of 4.75% or more.
Warrants
Each holder of the company’s Old Common Stock outstanding before the Effective Date that did not opt out of the release under the Plan, may receive its pro rata share of seven-year warrants (Warrants) to purchase an aggregate of 12.5% of the shares of New Common Stock, at an aggregate exercise price equal to the $650.0 million principal amount of the Notes plus interest thereon to the May 15, 2021 maturity date of the Notes. On the Effective Date, the company entered into a Warrant Agreement (Warrant Agreement) with American Stock Transfer & Trust Company, LLC. The Warrants will expire on the earliest of (i) September 3, 2027, (ii) the consummation of a Cash Sale (as defined in the Warrant Agreement) or (iii) the consummation of a liquidation, dissolutions or winding up of the company (such earliest date, the Expiration Date). Each Warrant not exercised by the Expiration Date will expire, and all rights under that Warrant and the Warrant Agreement will cease on the Expiration Date. On December 21, 2020, the company issued approximately 1.8 million Warrants to the holders of the Old Common Stock that did not opt out of the releases under the Plan and owned their shares of Old Common Stock in street name through the facilities of the DTC. On February 11, 2021, we issued approximately 43,000 Warrants to certain holders of the Old Common Stock that did not opt out of the releases under the Plan and owned their shares through direct registration with the company’s transfer agent (Direct Registration). The company expects to issue approximately 37,000 more Warrants to the holders of the Old Common Stock that did not opt out of the releases under the Plan and owned their shares through Direct Registration. Under the Plan, additional Warrants will be issued in book-entry form through the facilities of the DTC, and each holder owning shares of Old Common Stock through Direct Registration must provide that holder’s brokerage account information to the company to receive such holder’s distribution of Warrants. Any distribution not made will be deemed forfeited at the first anniversary of the Effective Date.
Events of Default
The filing of the Chapter 11 Cases constituted an event of default that accelerated the company's obligations under the Unit credit agreement and the indenture governing the Notes. Additionally, other events of default, including cross-defaults, existed, or occurred under these debt agreements. The amounts owed regarding the Notes were classified as liabilities subject to compromise. Under the Bankruptcy Code, the creditors under these debt agreements were stayed from taking any action against the company. Superior and its subsidiaries were not debtors in the Chapter 11 Cases, and the Chapter 11 Cases did not result in an event of default under the Superior credit agreement. In addition, the Debtors' filing of the bankruptcy petitions constituted a termination event under the Debtors' hedge agreements, which allowed the counterparties to those hedge agreements to terminate the outstanding hedges, as those termination events were not stayed by the Chapter 11 Cases.
On filing the Chapter 11 Cases, Unit entered into a Continuation Agreement (Continuation Agreement) with Superior, SPC Midstream Operating, L.L.C., and SP Investor to continue the parties' contractual relationships during the Chapter 11 Cases under the governance, operational, and related agreements entered into by those parties at the formation of the company’s midstream joint venture with SP Investor, which agreements contained certain provisions that otherwise would have been triggered by filing the Chapter 11 Cases.
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Liquidity, Unit Credit Facility, and Debtor-in-Possession Credit Agreement
To provide liquidity to fund our operations and the Chapter 11 Cases, the Debtors entered into the DIP Credit Agreement. Before repayment and termination on the Effective Date, borrowings under the DIP Credit Agreement would have matured on the earliest of (i) September 22, 2020 (subject to a two-month extension to be approved by the DIP lenders), (ii) the sale of all or substantially all the assets of the Debtors under Section 363 of the Bankruptcy Code or otherwise, (iii) the effective date of a plan of reorganization or liquidation in the Chapter 11 Cases, (iv) the entry of an order by the bankruptcy court dismissing any of the Chapter 11 Cases or converting such Chapter 11 Cases to a case under Chapter 7 of the Bankruptcy Code, and (v) the date of termination of the DIP lenders’ commitments and the acceleration of any outstanding extensions of credit, in each case, under the DIP Credit Agreement and subject to the bankruptcy court’s orders.
On the Effective Date, the DIP Credit Agreement was repaid in full and terminated. Following the Debtors’ emergence from the Chapter 11 Cases, each holder of an allowed claim under the DIP Credit Agreement received its pro rata share of revolving loans, term loans, and letter-of-credit participations under the Exit Credit Agreement. In addition, each holder received or was entitled to receive its pro rata share of an equity fee under the exit facility equal to 5% of the New Common Stock (subject to dilution by shares reserved for issuance under a management incentive plan and on exercise of the Warrants).
Going Concern
At June 30, 2020, the significant risks and uncertainties related to the company’s liquidity and Chapter 11 Cases raised substantial doubt about the company’s ability to continue as a going concern. The company, therefore, concluded as of that date there was substantial doubt about the company’s ability to continue as a going concern. The company implemented changes that (i) minimized capital expenditures, (ii) aggressively managed its working capital, and (iii) reduced recurring operating expenses. As a result of those changes and the successful reorganization of our long term debt, we determined that there is no longer substantial doubt about the company's ability to continue operating as a going concern for a period of at least one year.
Exit Credit Agreement
On the Effective Date, under the Plan, we entered into an amended and restated credit agreement (Exit Credit Agreement). Refer to Note 9 – Long-Term Debt and Other Long-Term Liabilities for the terms of the Exit Credit Agreement.
Interest Expense
The Debtors discontinued recording interest on liabilities subject to compromise as of the filing of the Chapter 11 Cases. Contractual interest on liabilities subject to compromise not reflected in the Consolidated Statements of Operations for the eight months ended August 31, 2020 was approximately $12.4 million, respectively, representing interest expense from the filing date through August 31, 2020. In addition, the Debtors did not make the May 15, 2020 $21.5 million required interest payment on the Notes.
NOTE 3 – FRESH START ACCOUNTING
On the Effective Date, the company qualified for and adopted fresh start accounting under the provisions in FASB Topic ASC 852, Reorganizations, as (i) the Reorganization Value of the company’s assets immediately before the date of confirmation was less than the post-petition liabilities and allowed claims, and (ii) the holders of the Old Common Stock received less than 50% voting shares of the Successor. Refer to Note 2 – Emergence From Voluntary Reorganization Under Chapter 11 for the terms of the Plan.
Reorganization Value
Reorganization value, as determined under ASC 820, Fair Value Measurement, represents the fair value of the Successor's total assets before the consideration of liabilities and is intended to approximate the amount a willing buyer would pay for the assets immediately after a restructuring. The reorganization value was derived from the Successor's enterprise value, which represents the estimated fair value of an entity’s long-term debt and equity. The Successor’s enterprise value, confirmed by the bankruptcy court, was estimated to be within a range of $270.0 million to $380.0 million, with a midpoint of $325.0 million. Based on the estimates and assumptions necessary for fresh start accounting, as further discussed below, the estimated enterprise value was determined to be $317.0 million before consideration of cash and cash equivalents, restricted
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
cash and outstanding debt at the Effective Date. As a result, the reorganization value was determined to be $726.3 million at the Effective Date, as reconciled below.
We estimated the enterprise value of the Successor using three valuation methods: net asset value (NAV), comparable public company analysis, and discounted cash flow (DCF). The NAV is a looking forward methodology under which future cash flows are discounted using various discount rates depending on reserve category. Similarly, DCF projects future cash flows which are discounted at rates above and below the company’s estimated weighted average cost of capital. The comparable public company analysis is based on the enterprise values of selected public companies with operating and financial characteristics comparable to the company. Under this methodology, certain financial multiples that measure financial performance and value are calculated for each selected company and then applied to imply an estimated enterprise value of the company.
The following table reconciles the enterprise value to the estimated fair value of the Successor's equity at the Effective Date (in thousands):
|
|
|
|
|
|
|
|
Enterprise value
|
$
|
559,205
|
|
|
Less: Fair value of noncontrolling interest
|
(242,200)
|
|
|
Enterprise value of Unit interests
|
317,005
|
|
|
Plus: Cash and cash equivalents
|
25,482
|
|
|
Plus: Restricted cash
|
7,458
|
|
|
Less: Fair value of capital leases
|
(4,622)
|
|
|
Less: Fair value of debt (including the fair value of current debt)
|
(148,000)
|
|
|
Fair value of Successor equity
|
$
|
197,323
|
|
The following table reconciles the enterprise value to the reorganization value of the Successor’s assets as of the Effective Date (in thousands):
|
|
|
|
|
|
|
|
Enterprise value
|
$
|
559,205
|
|
|
Plus: Cash and cash equivalents
|
25,482
|
|
|
Plus: Restricted cash
|
7,458
|
|
|
Plus: Current liabilities (excluding the fair value of capital leases and current debt)
|
86,897
|
|
|
Plus: Long-term asset retirement obligation
|
22,415
|
|
|
Plus: Other long-term liabilities (excluding long-term asset retirement obligation)
|
24,886
|
|
|
Reorganization value of Successor assets
|
$
|
726,343
|
|
Although we believe the assumptions and estimates used to develop the Enterprise Value and the Reorganization Value were reasonable and appropriate, different assumptions and estimates would materially impact the analysis and our resulting conclusions. The assumptions used in estimating these values are inherently uncertain and require significant judgment.
Valuation Process
Oil and Natural Gas Properties
Our oil and natural gas properties are accounted for under the full cost accounting method. We determined the fair value of our oil and gas properties based on the anticipated cash flows associated with our proved reserves and discounted those cash flows using a weighted average cost of capital rate of 13.5%. The discount rate is commonly based on empirical studies of investment rates of return of publicly traded equity securities with investment return and risk characteristics similar to the subject company, which follows a market-based approach. Weighted average commodity prices used in determining the fair value of oil and natural gas properties were $48.98 per barrel of oil, $2.68 per million cubic feet of natural gas and $18.51 per barrel of oil equivalent of natural gas liquids. Base pricing was derived from an average of forward strip prices. Our unproved acreage was determined to have no value due to the capital constraints contained in our debt agreement along with our plans to not drill in our proved reserves cash flows. Our salt water disposal assets were included in the cash flows of the proved reserves forecast, therefore, those values are included in the total value of our proved properties.
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Drilling Equipment
The value of our drilling rigs in operation (approximately $37.0 million) was estimated using an income-based approach using discounted free cash flows over the remaining useful lives of the drilling rigs. Anticipated cash flows associated with operating drilling rigs were discounted using a weighted average cost of capital rate of 13.8% for five years with a terminal value at the conclusion of the forecast period.
The fair value of our non-operating drilling rigs, and other related drilling equipment (approximately $26.5 million), was valued using a market-based approach with varying ranges of economic obsolescence rates to adjust for the impact of the oil and gas downturn.
Land and Building
Our corporate headquarters building in Tulsa, Oklahoma was completed in May 2016 and resides on approximately 30 acres. To determine its fair value, we used a market-based approach based on comparable tenant rates in our area.
Gas Gathering and Processing Equipment, Transportation Equipment, and Other Property
Gas gathering and processing equipment, transportation equipment and other equipment was valued using a market-based approach estimating what a market participant would pay for similar equipment in an orderly transaction. We used varying ranges of economic obsolescence rates depending on the underlying asset group. For pipelines and right-of-ways, we used a value per acre based on the location of the asset and estimated an average value of $129 per rod. We then applied an economic obsolescence rate of approximately 64% to determine the ultimate fair value.
Unit's Investment in Superior
To determine the net equity value of our investment in Superior, we simulated paths for Superior's total equity value through the expected liquidation date, where we simulated equity value using a Geometric Brownian Motion (GBM). The expected value (i.e., average of all simulations) of each security class was discounted to present value using the concluded risk-free rate to conclude on the respective allocated values.
Consolidated Balance Sheet
The adjustments included in the following Consolidated Balance Sheets reflect the effect of the transactions contemplated by the Plan (reflected in the column "Reorganization Adjustments") and fair value and other required accounting adjustments resulting from the adoption of fresh start accounting (reflected in the column "Fresh Start Adjustments"). The explanatory notes provide additional information with regard to the adjustments recorded, the methods used to determine the fair values and significant assumptions.
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of September 1, 2020
|
|
|
|
Predecessor
|
|
Reorganization Adjustments (1)
|
|
Fresh Start Adjustments (11)
|
|
Successor
|
|
ASSETS
|
|
(In thousands)
|
|
Current assets:
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
32,280
|
|
|
$
|
(6,798)
|
|
(2)
|
|
$
|
—
|
|
|
$
|
25,482
|
|
|
Restricted cash
|
|
—
|
|
|
7,458
|
|
(3)
|
|
—
|
|
|
7,458
|
|
|
Accounts receivable, net
|
|
50,621
|
|
|
—
|
|
|
—
|
|
|
50,621
|
|
|
Materials and supplies
|
|
64
|
|
|
—
|
|
|
(64)
|
|
(12)
|
|
—
|
|
|
Current income tax receivable
|
|
850
|
|
|
—
|
|
|
—
|
|
|
850
|
|
|
Prepaid expenses and other
|
|
13,692
|
|
|
6,382
|
|
(4)
|
|
(990)
|
|
(13)
|
|
19,084
|
|
|
Total current assets
|
|
97,507
|
|
|
7,042
|
|
|
(1,054)
|
|
|
103,495
|
|
|
Property and equipment:
|
|
|
|
|
|
|
|
|
|
Oil and natural gas properties, on the full cost method:
|
|
|
|
|
|
|
|
|
|
Proved properties
|
|
6,539,816
|
|
|
—
|
|
|
(6,301,532)
|
|
(14)
|
|
238,284
|
|
|
Unproved properties not being amortized
|
|
30,205
|
|
|
—
|
|
|
(30,205)
|
|
(14)
|
|
—
|
|
|
Drilling equipment
|
|
1,285,024
|
|
|
—
|
|
|
(1,221,566)
|
|
(15)
|
|
63,458
|
|
|
Gas gathering and processing equipment
|
|
833,788
|
|
|
—
|
|
|
(583,690)
|
|
(15)
|
|
250,098
|
|
|
Saltwater disposal systems
|
|
43,541
|
|
|
—
|
|
|
(43,541)
|
|
(15)
|
|
—
|
|
|
Land and building
|
|
59,080
|
|
|
—
|
|
|
(26,445)
|
|
(15)
|
|
32,635
|
|
|
Transportation equipment
|
|
15,577
|
|
|
—
|
|
|
(12,263)
|
|
(15)
|
|
3,314
|
|
|
Other
|
|
57,427
|
|
|
—
|
|
|
(47,469)
|
|
(15)
|
|
9,958
|
|
|
|
|
8,864,458
|
|
|
—
|
|
|
(8,266,711)
|
|
|
597,747
|
|
|
Less accumulated depreciation, depletion, amortization, and impairment
|
|
7,923,868
|
|
|
—
|
|
|
(7,923,868)
|
|
(14) (15)
|
—
|
|
|
Net property and equipment
|
|
940,590
|
|
|
—
|
|
|
(342,843)
|
|
|
597,747
|
|
|
Right of use asset
|
|
7,476
|
|
|
—
|
|
|
(659)
|
|
(16)
|
|
6,817
|
|
|
Other assets
|
|
24,666
|
|
|
(6,382)
|
|
(4)
|
|
—
|
|
|
18,284
|
|
|
Total assets
|
|
$
|
1,070,239
|
|
|
$
|
660
|
|
|
$
|
(344,556)
|
|
|
$
|
726,343
|
|
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of September 1, 2020
|
|
|
|
Predecessor
|
|
Reorganization Adjustments (1)
|
|
Fresh Start Adjustments (11)
|
|
Successor
|
|
LIABILITIES AND SHAREHOLDERS’ EQUITY
|
|
(In thousands)
|
|
Current liabilities:
|
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
$
|
27,354
|
|
|
$
|
6,382
|
|
(4)
|
|
$
|
—
|
|
|
$
|
33,736
|
|
|
Accrued liabilities
|
|
36,990
|
|
|
(4,115)
|
|
(5)
|
|
—
|
|
|
32,875
|
|
|
Current operating lease liability
|
|
4,643
|
|
|
—
|
|
|
(669)
|
|
(16)
|
|
3,974
|
|
|
Current portion of long-term debt
|
|
124,000
|
|
|
(123,600)
|
|
(6)
|
|
—
|
|
|
400
|
|
|
Current derivative liabilities
|
|
5,089
|
|
|
—
|
|
|
—
|
|
|
5,089
|
|
|
Warrant liability
|
|
—
|
|
|
—
|
|
|
885
|
|
(17)
|
|
885
|
|
|
Current portion of other long-term liabilities
|
|
11,201
|
|
|
3,743
|
|
(7)
|
|
16
|
|
(18)
|
|
14,960
|
|
|
Total current liabilities
|
|
209,277
|
|
|
(117,590)
|
|
|
232
|
|
|
91,919
|
|
|
Long-term debt
|
|
16,000
|
|
|
131,600
|
|
(6)
|
|
—
|
|
|
147,600
|
|
|
Non-current derivative liabilities
|
|
766
|
|
|
—
|
|
|
—
|
|
|
766
|
|
|
Operating lease liability
|
|
2,760
|
|
|
—
|
|
|
11
|
|
(16)
|
|
2,771
|
|
|
Other long-term liabilities
|
|
61,393
|
|
|
(3,220)
|
|
(4) (7)
|
(14,409)
|
|
(18)
|
|
43,764
|
|
|
Liabilities subject to compromise
|
|
762,215
|
|
|
(762,215)
|
|
(8)
|
|
—
|
|
|
—
|
|
|
Deferred income taxes
|
|
4,466
|
|
|
—
|
|
|
(4,466)
|
|
(19)
|
|
—
|
|
|
Commitments and contingencies
|
|
|
|
|
|
|
|
|
|
Shareholders’ equity:
|
|
|
|
|
|
|
|
|
|
Predecessor preferred stock, $1.00 par value, 5,000,000 shares authorized, none issued at December 31, 2019
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Predecessor common stock, $0.20 par value, 175,000,000 shares authorized, 55,443,393 shares issued as of December 31, 2019
|
|
10,704
|
|
|
(10,704)
|
|
(9)
|
|
—
|
|
|
—
|
|
|
Predecessor capital in excess of par value
|
|
650,153
|
|
|
(650,153)
|
|
(9)
|
|
—
|
|
|
—
|
|
|
Successor preferred stock, $0.01 par value, 1,000,000 shares authorized, none issued at September 1, 2020
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Successor common stock, $0.01 par value, 25,000,000 authorized, 12,000,000 issued at September 1, 2020
|
|
—
|
|
|
120
|
|
(8)
|
|
—
|
|
|
120
|
|
|
Successor capital in excess of par value
|
|
—
|
|
|
197,203
|
|
(8)
|
|
—
|
|
|
197,203
|
|
|
Retained earnings (deficit)
|
|
(818,679)
|
|
|
1,215,619
|
|
(10)
|
|
(396,940)
|
|
(20)
|
|
—
|
|
|
Total shareholders’ equity attributable to Unit Corporation
|
|
(157,822)
|
|
|
752,085
|
|
|
(396,940)
|
|
|
197,323
|
|
|
Non-controlling interests in consolidated subsidiaries
|
|
171,184
|
|
|
—
|
|
|
71,016
|
|
(21)
|
|
242,200
|
|
|
Total shareholders' equity
|
|
13,362
|
|
|
752,085
|
|
|
(325,924)
|
|
|
439,523
|
|
|
Total liabilities and shareholders’ equity
|
|
$
|
1,070,239
|
|
|
$
|
660
|
|
|
$
|
(344,556)
|
|
|
$
|
726,343
|
|
Reorganization Adjustments
(1)Reflects accounts recorded as of the Effective Date, including among other items, settlement of the Predecessor's liabilities subject to compromise, cancellation of the Predecessor's equity, issuance of the New Common Stock and the Warrants, repayment of certain of Predecessor's liabilities and settlement with holders of the Notes.
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(2)The table below details the company’s uses of cash, under the terms of the Plan described in Note 2 – Emergence From Voluntary Reorganization Under Chapter 11 (in thousands):
|
|
|
|
|
|
|
|
Funding of the professional fees escrow account
|
$
|
(7,458)
|
|
|
Proceeds from Exit credit facility
|
8,000
|
|
|
Payment of debt issuance costs on the Exit credit facility
|
(3,225)
|
|
|
Payment of professional fees
|
(3,943)
|
|
|
Payment of accrued interest payable under the Predecessor credit facility
|
(172)
|
|
|
Changes in cash and cash equivalents
|
$
|
(6,798)
|
|
(3)Represents the reserve for professional fee escrow of $7.5 million.
(4)Represents the reclassification of other long-term assets related to deferred compensation to prepaid expenses and other assets as the deferred compensation payout must be paid within 12 months from the date of emergence under the Plan. Simultaneously, the current portion of deferred compensation liability was reclassified from other long-term liabilities to accounts payable.
(5)Represents the payment of the DIP facility interest of $0.2 million and professional fees for $3.9 million.
(6)Represents the transition of the DIP Credit Agreement and the Predecessor Credit Agreement of $124.0 million into the Exit Facility and issuing an additional $8.0 million of borrowings under the Exit Credit Agreement.
(7)Represents the reclassification of the short-term portion of the separation benefit liabilities from non-current to current liabilities which was offset by the increase in non-current portion of liabilities.
(8)Settlement of liabilities subject to compromise and the resulting net gain were determined as follows (in thousands):
|
|
|
|
|
|
|
|
Liabilities subject to compromise before the Effective Date:
|
|
|
6.625% senior subordinated notes due 2021 (including accrued interest as of the petition date)
|
$
|
672,369
|
|
|
Accounts payable
|
1,179
|
|
|
Employee separation benefit plan obligations
|
23,394
|
|
|
Litigation settlements
|
45,000
|
|
|
Royalty suspense accounts payable
|
20,273
|
|
|
Total liabilities subject to compromise
|
762,215
|
|
|
Separation settlement treatment
|
(6,905)
|
|
|
Successor Common Stock and APIC(1) issued to allowed claim holders
|
(175,521)
|
|
|
Successor Common Stock and APIC for disputed claims reserve
|
(11,936)
|
|
|
Gain on settlement of liabilities subject to compromise
|
$
|
567,853
|
|
(1) Balance excludes the Successor Common Stock and APIC of $9.9 million to the 5% Equity Facility which was not a liability subject to compromise.
(9)Represents the cancellation of Old Common Stock.
(10)Represents the cumulative impact to Predecessor retained earnings of the reorganization adjustments described above.
Fresh Start Adjustments
(11)Reflects accounts recorded as of the Effective Date for the fresh start adjustments based on the methodologies noted below.
(12)Represents the reclassification of materials and supplies to proved properties.
(13)Represents the write off of the Predecessor's unamortized debt fees related to the DIP facility.
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(14)Reflects a decrease of oil and natural gas properties, net, based on the methodology discussed above, and the elimination of accumulated depletion and amortization. The following table summarizes the components of oil and natural gas properties as of the Effective Date:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
Fair Value
|
|
|
Historical Book Value
|
|
|
(In thousands)
|
|
Proved properties
|
$
|
238,284
|
|
|
|
$
|
6,539,816
|
|
|
Unproved properties
|
—
|
|
|
|
30,205
|
|
|
|
238,284
|
|
|
|
6,570,021
|
|
|
Less accumulated depletion, amortization, and impairment
|
—
|
|
|
|
(6,305,113)
|
|
|
|
$
|
238,284
|
|
|
|
$
|
264,908
|
|
(15)Reflects a decrease in fair value of drilling equipment, gas gathering and processing equipment, saltwater disposal systems, land and building, transportation equipment, and other property and equipment and the elimination of accumulated depreciation, based on the methodologies discussed above. The following table summarizes the components of other property and equipment as of the Effective Date:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
Fair Value
|
|
|
Historical Book Value
|
|
|
(In thousands)
|
|
Drilling equipment
|
$
|
63,458
|
|
|
|
$
|
1,285,024
|
|
|
Gas gathering and processing equipment
|
250,098
|
|
|
|
833,788
|
|
|
Saltwater disposal systems
|
—
|
|
|
|
43,541
|
|
|
Land and building
|
32,635
|
|
|
|
59,080
|
|
|
Transportation equipment
|
3,314
|
|
|
|
15,577
|
|
|
Other
|
9,958
|
|
|
|
57,427
|
|
|
|
359,463
|
|
|
|
2,294,437
|
|
|
Less accumulated depreciation and impairment
|
—
|
|
|
|
(1,618,754)
|
|
|
|
$
|
359,463
|
|
|
|
$
|
675,683
|
|
(16)Reflects the valuation adjustments to the company’s right of use assets, current operating lease liability, and operating lease liability, adjusted for fair value of favorable and unfavorable lease terms, and the revised incremental borrowing rates of the Successor.
(17)Represents the liability for the Warrants using a Black-Scholes-Merton model which uses various market-based inputs including: stock prices, strike price, time to maturity, risk-free rate, annual volatility rate, and annual dividend yield.
(18)Represents the reclassification of the short-term portion of ARO from non-current liabilities to current and the fair value adjustment, which was determined using our fresh start updates to these obligations, including the application of the Successor's credit adjusted risk free rate, which now incorporates a term structure based on the estimated timing of well plugging activity, and resetting all ARO to a single layer.
(19)Represents the adjustments to deferred tax liability as a result of the cumulative tax impact of the fresh start adjustments.
The significant revisions to the carrying value of our assets and liabilities because of applying fresh start accounting resulted in the company increasing its overall net deferred tax asset position on emergence from bankruptcy. Besides the changes in book value, the company has as of the Effective Date, approximately $726.4 million of net operating losses (NOLs) carried forward to offset taxable income in the future years. Approximately $584.2 million of this NOL will expire commencing in fiscal 2021 through 2037. The NOLs of approximately $142.2 million from years ended
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
after December 31, 2017 have an indefinite carryforward period. The amount of these NOLs which is available to offset future income may be severely limited due to change-in-control tax provisions.
Because of our history of operating losses and the uncertainty surrounding the realization of the deferred tax assets in future years, we have determined that it is more likely than not that the deferred tax assets will not be realized in future periods. Accordingly, we recorded a 100% valuation allowance against our net deferred tax assets.
(20)Represents the cumulative impact of the fresh start accounting adjustments discussed above.
(21)The valuation of the non-controlling interest was calculated by taking an income-based approach in valuing Superior. The value of the non-controlling interest was then determined based on a market-based approach for similar type investments, given the contractual rights of the related parties.
Reorganization Items. As described below in Note 4 – Summary Of Significant Accounting Policies, our Consolidated Statements of Operations for the periods ended August 31, 2020 and December 31, 2020 include "Reorganization items, net," which reflects gains recognized on the settlement of liabilities subject to compromise and costs and other expenses associated with the Chapter 11 proceedings, primarily professional fees, and the costs associated with the DIP Credit Agreement. These post-petition costs for professional fees, and administrative fees charged by the U.S. trustee, have been reported in "Reorganization items, net" in our Consolidated Statements of Operations as described above. Similar costs were incurred during the pre-petition period have been reported in "General and administrative" expenses.
The following table summarizes the components included in "Reorganization items, net" in our Consolidated Statements of Operations for the periods presented:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
Four Months Ended
|
|
|
Eight Months Ended
|
|
|
December 31, 2020
|
|
|
August 31,
2020
|
|
|
(In thousands)
|
|
Gains on settlement of liabilities subject to compromise
|
$
|
—
|
|
|
|
$
|
(567,853)
|
|
|
Fresh start accounting adjustments
|
—
|
|
|
|
401,406
|
|
|
Legal and professional fees and expenses
|
2,273
|
|
|
|
15,745
|
|
|
Acceleration of Predecessor stock compensation expense
|
—
|
|
|
|
1,431
|
|
|
Exit Facility fees
|
—
|
|
|
|
3,225
|
|
|
5% Exit Facility equity fee
|
—
|
|
|
|
9,866
|
|
|
Adjustment to unamortized debt issuance costs associated with the 6.625% senior subordinated notes due 2021
|
—
|
|
|
|
2,205
|
|
|
Total reorganization items, net
|
$
|
2,273
|
|
|
|
$
|
(133,975)
|
|
NOTE 4 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
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.
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
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
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
many customers comprising our customer base. Below are the third-party customers that accounted for over 10% of each of our segment’s revenues:
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Successor
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Predecessor
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Period
September 1, 2020
through
December 31, 2020
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Period
January 1, 2020 through
August 31, 2020
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For the Year Ended
December 31, 2019
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Oil and Natural Gas:
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CVR Refining, LP
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14
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%
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15
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%
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14
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%
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Plains Marketing L.P.
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*
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11
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%
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*
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Drilling:
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EOG Resources, Inc.
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28
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%
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20
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%
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12
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%
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QEP Resources, Inc.
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23
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%
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10
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%
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12
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%
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Citizen Energy III, LLC
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16
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%
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*
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*
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Slawson Exploration Company, Inc.
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16
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%
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21
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%
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11
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%
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Cimarex Energy Co.
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12
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%
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*
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*
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Mid-Stream:
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ONEOK, Inc.
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28
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%
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31
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%
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33
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%
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Range Resources Corporation
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15
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%
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21
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%
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13
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%
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Centerpoint Energy Service, Inc.
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*
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*
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10
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%
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_______________________
* Revenue accounted for less than 10% of the segment's revenues.
We had a concentration of cash of $21.4 million and $1.7 million at December 31, 2020 and 2019, respectively with one bank.
Using derivative transactions also involves the risk that the counterparties cannot meet the financial terms of the transactions. We considered this non-performance risk regarding our counterparties and our own non-performance risk in our derivative valuation at December 31, 2020 and determined there was no material risk at that time. At December 31, 2020, the fair values of the net liabilities we had with each of the counterparties regarding our commodity derivative transactions are listed in the table below:
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December 31, 2020
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(In millions)
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Bank of Oklahoma
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$
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(5.4)
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Bank of Montreal
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(0.3)
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Total net liabilities
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$
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(5.7)
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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
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
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.
We recorded expense of $1.1 million related to the write-down of certain equipment in the third quarter of 2020 that we now consider abandoned. These amounts are reported in loss on abandonment of assets in our Consolidated Statements of Operations.
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.
Goodwill. Goodwill represents the excess of the cost of an acquisition over the fair value of the net assets acquired. Goodwill is not amortized, but an impairment test is performed annually to determine whether the fair value has decreased or
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
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
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
disposal assets for the eight months ended August 31, 2020. These amounts are reported in loss on abandonment of assets in our Consolidated Statements of Operations.
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.
We do not engage in derivative transactions solely for speculative purposes.
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.
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
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.
New Accounting Standards
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.
Adopted Standards
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.
NOTE 5 – REVENUE FROM CONTRACTS WITH CUSTOMERS
Our revenue streams are reported under our three segments: oil and natural gas, contract drilling, and mid-stream. This is our disaggregation of revenue and how our segment revenue is reported (as reflected in Note 20 – Industry Segment Information). Revenue from the oil and natural gas segment is derived from sales of our oil and natural gas production. Revenue from the contract drilling segment is derived by 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 production and selling those commodities. We sell the hydrocarbons (from the oil and natural gas and mid-stream segments) to other mid-stream and downstream oil and gas companies.
We satisfy the performance obligation under each segment's contracts as follows:
•contract drilling and mid-stream contracts - satisfy the performance obligations over the agreed-on time;
•oil and natural gas contracts - satisfy the performance obligation with each volume delivery.
For oil and natural gas contracts, as it is more feasible, we account for these deliveries monthly.
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
Per the contracts for all segments, customers pay for the services/goods received monthly within an agreed number of days following the end of the month. Other than the mid-stream demand fees and shortfall fees discussed further below, there were no other contract assets or liabilities falling within the scope of this accounting pronouncement.
Oil and Natural Gas Contracts, Revenues, Implementation Impact to Retained Earnings, and Performance Obligations
Typical types of revenue contracts signed by our oil and gas segments are Oil Sales Contracts, North American Energy Standards Board (NAESB) Contracts, Gas Gathering and Processing Agreements, and revenues earned as the non-operated party with the operator serving as an agent on our behalf under our Joint Operating Agreements. Contract terms can range from a single month to a term spanning a decade or more; some may also include evergreen provisions. Revenues from our sales are recognized when our customer obtains control of the sold product. For sales we make to other mid-stream and downstream oil and gas companies, control typically occurs at a point on delivery to the customer. Sales generated from our non-operated interest are recorded based on the information obtained from the operator. Our adoption of this standard required no adjustment to opening retained earnings.
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 are 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.
Our performance obligation for all commodity contracts is the delivery of oil and gas volumes to the customer. Typically, the contract is for a specified period (for example, a month or a year); however, each delivery under that contract can be considered as separately identifiable since each delivery provides its own benefits to the customer. For feasibility, as accounting for a monthly performance obligation is not materially different than identifying a more granular performance obligation, we conclude this performance obligation is satisfied monthly. We typically receive a payment within a set number of days following the end of the month of performance which includes payment for all deliveries in that month. Subject to any contract terms, judgment could be required to determine when the transfer of control occurs. Generally, depending on the facts and circumstances, we consider the change of control of the asset in a commodity sale to occur at the point the commodity transfers to the customer.
The consideration we receive for oil and gas sales is variable. Most of our contracts state the consideration is calculated by multiplying a variable quantity by a variable price less deductions related to any allowed gathering, transportation, fractionation, and related fuel charges. All variable consideration is settled at the end of the month; therefore, the variability does not affect accounting for revenue under ASC 606 as the variability is known before each reporting period. An estimation and allocation of transaction price and future obligations are not required.
Contract Drilling Contracts, Revenues, Implementation impact to retained earnings, and Performance Obligations
The contract drilling segment uses contracts with terms ranging from two months to three or more years or that can be based on terms to drill a specific number of wells. The allocation rules in ASC 606 (called the "series guidance") provide that a contract may contain a single performance obligation composed of a series of distinct goods or services if 1) each distinct good or service is substantially the same and would meet the criteria to be a performance obligation satisfied over time and 2) each distinct good or service is measured using the same method as it relates to the satisfaction of the overall performance obligation. We have determined that the delivery of drilling services is within the scope of the series guidance as both criteria noted above are met. Specifically, 1) each distinct increment of service (i.e., hour available to drill) that the drilling contractor promises to transfer represents a performance obligation that would meet the criteria for recognizing revenue over time, and 2) the drilling contractor would use the same method for measuring progress toward satisfaction of the performance obligation for each distinct increment of service in the series. At inception, the total transaction price is estimated to include any applicable fixed consideration, unconstrained variable consideration (estimated day rate mobilization and demobilization revenue, estimated operating day rate revenue to be earned over the contract term, expected bonuses (if material and can be reasonably estimated without significant reversal)), and penalties (if material and can be reasonably estimated without significant reversal). The estimation of the transaction price for unconstrained variable consideration does not differ materially from the previous revenue accounting standard. A contract liability will be recorded for consideration received before the corresponding transfer of services. Those liabilities will generally only arise in relation to upfront mobilization fees paid in advance and are allocated/recognized over the entire performance obligation. Such balances if material will be amortized over the recognition period based on the same method of measure used for revenue.
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
Our performance obligation for all drilling contracts is to drill the agreed-on number of wells or drill over an agreed-on period as stated in the contract. Any mobilization and demobilization activities are not considered distinct within the context of the contract and therefore, any associated revenue is allocated to the overall performance obligation of drilling services and recognized ratably over the initial term of the related drilling contract. It typically takes from 10 to 90 days to complete drilling a well; therefore, depending on the number of wells under a contract, the contract term could be up to three years. Most of the drilling contracts are for less than one year. As the customer simultaneously receives and consumes the benefits provided by the company’s performance, and the company’s performance enhances an asset that the customer controls, the performance obligation to drill the well occurs over time. We typically receive payment within a set number of days following the end of the month and that payment includes payment for all services performed during that month (calculated on an hourly basis). The company satisfies its overall performance obligation when the well included in the contract is drilled to an agreed-on depth or by a set date.
All consideration received for contract drilling is variable, excluding termination fees. The consideration is calculated by multiplying a variable quantity (number of days/hours) by an agreed-on daily price (for the daily rate, mobilization, and demobilization revenue). Other revenue items under the contract may include bonus/penalty revenue, reimbursable revenue, drilling fluid rates, and early termination fees. All variable consideration is not constrained but is settled at the end of the month; therefore, whether the variability is constrained or not does not affect accounting for revenue under ASC 606 as the variability is known before each reporting period excluding certain bonuses/penalties which might be based on activity that occurs over the entire term of the contract. We have evaluated the mobilization and de-mobilization charges on outstanding contracts, however, the impact to the financial statements was immaterial. As of December 31, 2020, we had nine drilling contracts (five of which are term contracts) for a duration of two months to one year.
Under the guidance in relation to disclosures regarding the remaining performance obligations, there is a practical expedient for contracts with an original expected duration of one year or less (ASC 606-10-50-14) and for contracts where the entity can recognize revenue as invoiced (ASC 606-10-55-18). Most of our drilling contracts have an original term of less than one year; however, the remaining performance obligations under the contracts with a longer duration are not material.
Mid-stream Contracts Revenues, and Implementation impact to retained earnings, and Performance Obligations
Revenues are generated from the fees earned for gas gathering and processing services provided to a customer or by selling of 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. Our gas gathering and processing revenues are generally variable because the volumes are dependent on throughput by third-party customers for which the service provided is only specified on a daily or monthly basis. We deliver natural gas, NGLs and condensate to purchasers at contractually agreed-upon delivery points at which the purchaser takes custody, title, and risk of loss of the commodity. We recognize revenue at the point in time when control transfers to the purchaser at the delivery point based on the contractually agreed upon fixed or index-based price received.
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.
Before implementing ASC 606, we immediately recognized the entire demand fee since the fee was payable within the first five years from the effective date of the contract and not over the entire term of the contract. However, the demand fee is a stand-ready obligation under ASC 606 and is now to be recognized over the life of the contract. Therefore, the demand fee previously recognized for $1.7 million ($1.3 million, net of tax) was adjusted to retained earnings as of January 1, 2018 and is recognized over the remaining term of the contract.
Included below is the adjustment to demand fees from adopting ASC 606 over the remaining term of the contracts as of December 31, 2020.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contract
|
Remaining Term of Contract
|
2021
|
2022
|
2023 and beyond
|
Total Remaining Impact to Revenue
|
|
|
|
|
|
|
Demand fee contracts
|
2-8 years
|
$
|
(3,501)
|
|
$
|
1,380
|
|
$
|
36
|
|
$
|
(2,085)
|
|
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
The adjustment to revenue for these demand fees was $(3.8) million and $2.6 million in 2020 and 2019, respectively.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
|
|
Classification on the Consolidated Balance Sheets
|
|
December 31, 2020
|
|
|
December 31,
2019
|
|
Change
|
|
|
|
|
(In thousands)
|
|
Assets
|
|
|
|
|
|
|
|
|
|
Current contract assets
|
Prepaid expenses and other
|
|
$
|
6,084
|
|
|
|
$
|
6,664
|
|
|
$
|
(580)
|
|
|
Non-current contract assets
|
Other assets
|
|
173
|
|
|
|
6,257
|
|
|
(6,084)
|
|
|
Total contract assets
|
|
|
$
|
6,257
|
|
|
|
$
|
12,921
|
|
|
$
|
(6,664)
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities
|
|
|
|
|
|
|
|
|
|
Current contract liabilities
|
Current portion of other long-term liabilities
|
|
$
|
2,583
|
|
|
|
$
|
2,889
|
|
|
$
|
(306)
|
|
|
Non-current contract liabilities
|
Other long-term liabilities
|
|
1,589
|
|
|
|
4,172
|
|
|
(2,583)
|
|
|
Total contract liabilities
|
|
|
4,172
|
|
|
|
7,061
|
|
|
(2,889)
|
|
|
Contract assets (liabilities), net
|
|
|
$
|
2,085
|
|
|
|
$
|
5,860
|
|
|
$
|
(3,775)
|
|
Shortfall fees are minimum volume commitment arrangements where a customer agrees to pay the contractually agreed upon gathering fees for a minimum volume of natural gas irrespective of whether or not the minimum volume of natural gas is delivered, which results in performance obligations for each individual unit of volume. If the actual volumes exceed the minimum volume of natural gas, the customer pays the contractually agreed upon gathering fees for the excess volumes in addition to the fees paid for the minimum volume of natural gas. Once the services have been completed, or the customer no longer has the ability to utilize the services, the performance obligation is met, and revenue is recognized. In addition, when certain minimum volume commitment fee arrangements include commitments of one year or more, significant judgment is used in interim commitment periods in which a customer’s actual volumes are deficient in relation to the minimum volume commitment. Revenue is recognized when the likelihood of the customer meeting the minimum volume commitment becomes remote. During the Successor Period and Predecessor Period of 2020, we recognized revenue from shortfall fees of $4.0 million and $1.3 million, respectively. No shortfall fees were recognized in the year 2019.
NOTE 6 – ACQUISITIONS AND DIVESTITURES
Acquisitions
Oil and Natural Gas
During the Successor Period of 2020, there was no significant acquisition activity. During the Predecessor Period of 2020, we had $0.4 million in acquisitions, while for 2019, we had approximately $3.7 million in acquisitions.
Mid-Stream
There was no significant acquisition activity in 2020.
In December 2019, we closed on an acquisition for $16.1 million that included approximately 572 miles of pipeline and related compressor stations. The transaction closed on December 30, 2019 with an effective date of December 01, 2019 and was accounted for as an asset acquisition.
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
Divestitures
Oil and Natural Gas
We had non-core asset sales with proceeds, net of related expenses, of $0.4 million, $1.2 million and $21.8 million in the Successor Period and Predecessor Period of 2020 and the year 2019, respectively. Proceeds from these dispositions reduced the net book value of the full cost pool with no gain or loss recognized.
Contract Drilling
During 2019, we sold six of the drilling rigs and other equipment to unaffiliated third parties. The proceeds of those sales, less costs to sell, was more than the $5.7 million net book value resulting in a gain of $1.1 million. Seven drilling rigs and equipment remained classified as assets held for sale and were to be marketed for sale throughout the next twelve months. The net book value of those assets was $5.9 million.
During the first quarter of 2020, due to market conditions, it was determined those assets would not be sold in the next twelve months and were reclassified to long-lived assets. As of December 31, 2020, we have no assets that meet the criteria to be classified as held for sale. We do have plans to sell drilling rigs but they have zero net book value after fresh start so they are not reported as assets held for sale.
NOTE 7 – LOSS PER SHARE
Successor Period
On the Effective Date, the company issued 12.0 million shares of New Common Stock at a par value of $0.01 per share that were to be subsequently distributed in accordance with the Plan.
Information related to the calculation of loss per share attributable to the company is:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (Loss)
(Numerator)
|
|
Weighted
Shares
(Denominator)
|
|
Per-Share
Amount
|
|
|
|
(In thousands except per share amounts)
|
|
For the four months ended December 31, 2020
|
|
|
|
|
|
|
|
Basic loss attributable to Unit Corporation per common share
|
|
$
|
(18,140)
|
|
|
12,000
|
|
|
$
|
(1.51)
|
|
Predecessor Period
Information related to the calculation of loss per share attributable to the company is:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (Loss)
(Numerator)
|
|
Weighted
Shares
(Denominator)
|
|
Per-Share
Amount
|
|
|
(In thousands except per share amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the year ended December 31, 2019:
|
|
|
|
|
|
|
Basic loss attributable to Unit Corporation per common share
|
$
|
(553,879)
|
|
|
52,849
|
|
|
$
|
(10.48)
|
|
|
Effect of dilutive stock options and restricted stock
|
—
|
|
|
—
|
|
|
—
|
|
|
Diluted loss attributable to Unit Corporation per common share
|
$
|
(553,879)
|
|
|
52,849
|
|
|
$
|
(10.48)
|
|
|
For the eight months ended August 31, 2020
|
|
|
|
|
|
|
Basic loss attributable to Unit Corporation per common share
|
$
|
(931,012)
|
|
|
53,368
|
|
|
$
|
(17.45)
|
|
The following options were not included in the weighted shares above as their affect would be anti-dilutive to the computation of loss per share for the year ended December 31:
|
|
|
|
|
|
|
|
|
|
|
2019
|
|
|
|
Stock options
|
42,000
|
|
|
|
|
Average exercise price
|
$
|
48.56
|
|
|
|
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
NOTE 8 – ACCRUED LIABILITIES
Accrued liabilities consisted of the following as of December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
2020
|
|
|
2019
|
|
|
(In thousands)
|
|
Employee costs
|
$
|
8,878
|
|
|
|
$
|
17,832
|
|
|
Lease operating expenses
|
6,405
|
|
|
|
9,200
|
|
|
Taxes
|
2,324
|
|
|
|
3,450
|
|
|
Legal settlement (Note 18)
|
2,070
|
|
|
|
—
|
|
|
Interest payable
|
884
|
|
|
|
6,562
|
|
|
Third-party credits
|
—
|
|
|
|
3,691
|
|
|
Other
|
1,182
|
|
|
|
5,827
|
|
|
Total accrued liabilities
|
$
|
21,743
|
|
|
|
$
|
46,562
|
|
NOTE 9 – LONG-TERM DEBT AND OTHER LONG-TERM LIABILITIES
Long-Term Debt
Long-term debt consisted of the following as of December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
2020
|
|
|
2019
|
|
|
(In thousands)
|
|
Current portion of long-term debt:
|
|
|
|
|
|
Predecessor credit facility with an average interest rate of 4.0%
|
$
|
—
|
|
|
|
$
|
108,200
|
|
|
Successor Exit Facility with an average interest rate of 6.6%
|
600
|
|
|
|
—
|
|
|
Long-term debt:
|
|
|
|
|
|
Successor Exit Facility with an average interest of 6.6%
|
98,400
|
|
|
|
—
|
|
|
Superior credit agreement with an average interest rate of 3.9% at December 31, 2019
|
—
|
|
|
|
16,500
|
|
|
Predecessor 6.625% senior subordinated notes due 2021
|
—
|
|
|
|
650,000
|
|
|
Total principal amount
|
$
|
98,400
|
|
|
|
$
|
666,500
|
|
|
Less: unamortized discount
|
—
|
|
|
|
(971)
|
|
|
Less: debt issuance costs, net
|
—
|
|
|
|
(2,313)
|
|
|
Total long-term debt
|
$
|
98,400
|
|
|
|
$
|
663,216
|
|
Successor Exit Credit Agreement. On the Effective Date, under the Plan, we entered into the Exit Credit Agreement, providing for a $140.0 million senior secured revolving credit facility and a $40.0 million senior secured term loan facility, among (i) the company, UDC, and UPC, (ii) the guarantors, including the company and all its subsidiaries existing as of the Effective Date (other than Superior Pipeline Company, L.L.C. and its subsidiaries), (iii) the lenders under the agreement, and (iv) BOKF, NA dba Bank of Oklahoma as administrative agent and collateral agent (the Administrative Agent).
The maturity date of borrowings under the 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.
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
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 ending (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 ending 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 0.50 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, restrict certain asset sales and the related use of proceeds, and require certain hedging activities. The Exit Credit Agreement further requires that we 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 December 31, 2020, we were in compliance with these covenants.
The Exit Credit Agreement is secured by first-priority liens on substantially all the personal and real property assets of the borrowers and the guarantors, including our ownership interests in Superior Pipeline Company, L.L.C.
On the Effective Date, we had (i) $40.0 million in principal amount of Term Loans outstanding, (ii) $92.0 million in principal amount of Revolving Loans outstanding, and (iii) approximately $6.7 million of outstanding letters of credit. At December 31, 2020, we had $0.6 million and $98.4 million outstanding current and long-term borrowings, respectively, under the Exit Credit Agreement.
Predecessor's Credit Agreement. Before the filing of the Chapter 11 Cases, the Unit credit agreement had a scheduled maturity date of October 18, 2023 that would have accelerated to November 16, 2020 if, by that date, all the Notes were not repurchased, redeemed, or refinanced with indebtedness having a maturity date at least six months following October 18, 2023 (Credit Agreement Extension Condition). The Debtors' filing of the Chapter 11 Cases constituted an event of default that accelerated the Debtors' obligations under the Unit credit agreement and the indenture governing the Notes. Due to the Credit Agreement Extension Condition, our debt associated with the Unit credit agreement is reflected as a current liability in our Consolidated Balance Sheets as of December 31, 2019. The classification as a current liability due to the Credit Agreement Extension Condition was based on the uncertainty regarding our ability to repay or refinance the Notes before November 16, 2020. In addition, on May 22, 2020, the lenders' remaining commitments under the Unit credit agreement were terminated.
Before filing the Chapter 11 Cases, we were charged a commitment fee of 0.375% on the amount available but not borrowed. That fee varied based on the amount borrowed as a percentage of the total borrowing base. Total amendment fees of $3.3 million in origination, agency, syndication, and other related fees were being amortized over the life of the Unit credit agreement. Due to the remaining commitments under the Unit credit agreement being terminated by the lenders', the unamortized debt issuance costs of $2.4 million were written off during the second quarter of 2020. Under the Unit credit agreement, we pledged as collateral 80% of the proved developed producing (discounted as present worth at 8%) total value of our oil and gas properties. Under the mortgages covering those oil and gas properties, UPC also pledged certain items of its personal property.
Before filing the Chapter 11 Cases, any part of the outstanding debt under the Unit credit agreement could be fixed at a London Interbank Offered Rate (LIBOR). LIBOR interest was computed as the LIBOR base for the term plus 1.50% to 2.50% depending on the level of debt as a percentage of the borrowing base and was payable at the end of each term, or every 90 days, whichever is less. Borrowings not under LIBOR bear interest equal to the higher of the prime rate specified in the Predecessor credit agreement and the sum of the Federal Funds Effective Rate (as defined in the Unit credit agreement) plus 0.50%, but in no event would the interest on those borrowings be less than LIBOR plus 1.00% plus a margin. Interest was payable at the end of each month or at the end of each LIBOR contract and the principal may be repaid in whole or in part at any time, without a premium or penalty.
Filing the bankruptcy petitions on May 22, 2020 constituted an event of default that accelerated our obligations under the Unit credit agreement, and the lenders’ rights of enforcement under the Unit credit agreement were automatically stayed because of the Chapter 11 Cases.
On the Effective Date, each lender under the Unit credit agreement and the DIP Credit Agreement received its pro rata share of revolving loans, term loans and letter-of-credit participations under the Exit Credit Agreement, in exchange for that lender’s allowed claims under the Unit credit agreement or the DIP Credit Agreement.
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
Superior Credit Agreement. On May 10, 2018, Superior entered into 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. 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 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 to Lender in the London Interbank Market or if such index no longer exists or accurately reflects the rate available to Administrative Agent in the London Interbank Market, 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. Superior paid $1.7 million in origination, agency, syndication, and other related fees. These fees are being amortized over the life of the Superior credit agreement.
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 December 31, 2020, Superior was in compliance with these covenants.
Borrowings under the Superior credit agreement will fund capital expenditures and acquisitions, provide general working capital, and for letters of credit for Superior.
Unit is not a party to and does not guarantee Superior's credit agreement. Superior and its subsidiaries were not debtors in the Chapter 11 Cases, and the Superior credit agreement was not affected by Unit's bankruptcy.
Predecessor 6.625% Senior Subordinated Notes. The Notes were issued under an Indenture dated as of May 18, 2011, between the company and Wilmington Trust, National Association (successor to Wilmington Trust FSB), as Trustee (Trustee), as supplemented by the First Supplemental Indenture dated as of May 18, 2011, between us, the Guarantors, and the Trustee, and as further supplemented by the Second Supplemental Indenture dated as of January 7, 2013, between us, the Guarantors, and the Trustee (as supplemented, the 2011 Indenture), establishing the terms of and providing for issuing the Notes.
As a result of Unit's emergence from bankruptcy, the Notes were cancelled and our liability under the Notes was discharged as of the Effective Date. Holders of the Notes were issued shares of New Common Stock in accordance with the Plan.
Predecessor DIP Credit Agreement. As contemplated by the Restructuring Support Agreement between the company and certain of the Note holders and our lenders, the company and the other Debtors entered into a Superpriority Senior Secured Debtor-in-Possession Credit Agreement dated May 27, 2020 ( DIP credit agreement), among the Debtors, the lenders under the facility (the DIP lenders), and BOKF, NA dba Bank of Oklahoma, as administrative agent, under which the DIP lenders agreed to provide us with the $36.0 million multiple-draw loan facility (DIP credit facility). The bankruptcy court entered an interim order on May 26, 2020 approving the DIP credit facility, permitting the Debtors to borrow up to $18.0 million on an interim basis. On June 19, 2020, the bankruptcy court granted final approval of the DIP credit facility.
Before its repayment and termination on the Effective Date, borrowings under the DIP credit facility matured on the earliest of (i) September 22, 2020 (subject to a two-month extension to be approved by the DIP Lenders), (ii) the sale of all or substantially all the assets of the Debtors under Section 363 of the Bankruptcy Code or otherwise, (iii) the effective date of a plan of reorganization or liquidation in the Chapter 11 Cases, (iv) the entry of an order by the bankruptcy court dismissing any of the Chapter 11 Cases or converting such Chapter 11 Cases to a case under Chapter 7 of the Bankruptcy Code and (v) the date of termination of the DIP lenders’ commitments and the acceleration of any outstanding extensions of credit, in each case, under the DIP credit facility under and subject to the DIP Credit Agreement and the bankruptcy court’s orders.
On the Effective Date, the DIP credit facility was paid in full and terminated. On the Effective Date, each holder of an allowed claim under the DIP credit facility received its pro rata share of revolving loans, term loans, and letter-of-credit participations under the Exit Credit Agreement. In addition, each holder was issued its pro rata share of an equity fee under the
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
Exit Credit Agreement equal to 5% of the New Common Stock (subject to dilution by shares reserved for issuance under a management incentive plan and on exercise of the Warrants).
For further information about the DIP Credit Agreement, please see Note 2 – Emergence From Voluntary Reorganization Under Chapter 11.
Other Long-Term Liabilities
Other long-term liabilities consisted of the following as of December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
2020
|
|
|
2019
|
|
|
(In thousands)
|
|
ARO liability
|
$
|
23,356
|
|
|
|
$
|
66,627
|
|
|
Workers’ compensation
|
10,164
|
|
|
|
11,510
|
|
|
Separation benefit plans (1)
|
4,201
|
|
|
|
10,122
|
|
|
Contract liability
|
4,172
|
|
|
|
7,061
|
|
|
Gas balancing liability
|
3,997
|
|
|
|
3,838
|
|
|
Finance lease obligations
|
3,216
|
|
|
|
7,379
|
|
|
Other long-term liability
|
1,321
|
|
|
|
—
|
|
|
Deferred compensation plan
|
—
|
|
|
|
6,180
|
|
|
|
50,427
|
|
|
|
112,717
|
|
|
Less current portion
|
11,168
|
|
|
|
17,376
|
|
|
Total other long-term liabilities
|
$
|
39,259
|
|
|
|
$
|
95,341
|
|
_______________________
1.As of the Effective Date, the Board adopted (i) the Amended and Restated Separation Benefit Plan of Unit Corporation and Participating Subsidiaries (Amended Separation Benefit Plan), (ii) the Amended and Restated Special Separation Benefit Plan of Unit Corporation and Participating Subsidiaries (Amended Special Separation Benefit Plan) and (iii) the Separation Benefit Plan of Unit Corporation and Participating Subsidiaries (New Separation Benefit Plan). In accordance with the Plan, the Amended Separation Benefit Plan and the Amended Special Separation Benefit Plan allow former employees or retained employees with vested severance benefits under either plan to receive certain cash payments in full satisfaction for their allowed separation claim under the Chapter 11 Cases. In accordance with the Plan, the New Separation Benefit Plan is a comprehensive severance plan for retained employees, including retained employees whose severance did not already vest under the Amended Separation Benefit Plan or the Amended Special Separation Benefit Plan. The New Separation Benefit Plan provides that eligible employees will be entitled to two weeks of severance pay per year of service, with a minimum of four weeks and a maximum of 13 weeks of severance pay.
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 (AROs). 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 plugging costs associated with our oil and gas wells.
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
The following table shows certain information about our estimated AROs for the periods indicated (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ARO liability, December 31, 2019 (Predecessor)
|
|
66,627
|
|
|
Accretion of discount
|
|
1,545
|
|
|
Liability incurred
|
|
465
|
|
|
Liability settled
|
|
(838)
|
|
|
Liability sold
|
|
(487)
|
|
|
Revision of estimates (1)
|
|
(28,328)
|
|
|
ARO liability, August 31, 2020 (Predecessor)
|
|
38,984
|
|
|
Fresh start adjustments
|
|
(14,393)
|
|
|
ARO liability, August 31, 2020 (Successor)
|
|
24,591
|
|
|
Accretion of discount
|
|
467
|
|
|
Liability incurred
|
|
151
|
|
|
Liability settled
|
|
(95)
|
|
|
Liability sold
|
|
—
|
|
|
Revision of estimates (1)
|
|
(1,758)
|
|
|
ARO liability, December 31, 2020 (Successor)
|
|
23,356
|
|
|
Less current portion (Successor)
|
|
2,121
|
|
|
Total long-term ARO (Successor)
|
|
$
|
21,235
|
|
_______________________
1.Plugging liability estimates were revised in 2019 and 2020 for updates in the cost of services used to plug wells over the preceding year and estimated dates to be plugged.
NOTE 11 – INCOME TAXES
As previously stated, we filed for Chapter 11 Bankruptcy protection during the second quarter of 2020 and emerged from the cases in the third quarter of 2020. This event had a significant impact on income taxes during 2020. Under the Plan, the Company's pre-petition debt securities were extinguished and holders of those securities received their pro-rata share of New Common Stock. Holders of Old Common Stock that did not opt out of the release under the Plan received its pro-rata share of Warrants. Please refer to Note 2 – Emergence From Voluntary Reorganization Under Chapter 11 for more information.
As a result of the Plan, the company experienced an ownership change under Sec. 382 of the Internal Revenue Code (IRC). Under IRC Sec. 382, the company’s tax attributes, most notably its net operating loss carryovers, are potentially subject to various limitations going forward. The company believes it has satisfied the requirements of Sec. 382(l)(5) whereby our tax attributes are generally not subject to limitations under Sec. 382(a) and have reflected that result in our financials accordingly. While cancellation of debt income (CODI) is generally considered taxable income under IRC Sec. 108, it provides an exception to that rule for CODI realized under a Title 11 case of the United States Code. In exchange for this exception, the taxpayer must reduce certain tax attributes including its net operating loss carryovers, credit carryovers, and tax basis in its assets in the amount of the CODI not recognized under the IRC Sec. 108 exception. The amount of CODI not recognized as a result of the IRC Sec. 108 exception was $506.3 million. As a result, our net operating loss carryovers were reduced by $457.5 million and the tax basis of our assets were reduced by $48.8 million. Even though these tax attribute reductions are not effective until January 1, 2021, the first day of the tax year after emergence, they have been recognized and reflected as such in the tables below.
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
A reconciliation of income tax expense (benefit), computed by applying the federal statutory rate to pre-tax income (loss) to our effective income tax expense (benefit) is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
|
|
|
|
|
(In thousands)
|
|
Income tax benefit computed by applying the statutory rate
|
$
|
(3,001)
|
|
|
|
$
|
(190,103)
|
|
|
$
|
(144,092)
|
|
|
|
|
State income tax benefit, net of federal benefit
|
(500)
|
|
|
|
(31,684)
|
|
|
(21,733)
|
|
|
|
|
Deferred tax liability revaluation
|
—
|
|
|
|
—
|
|
|
—
|
|
|
|
|
Restricted stock shortfall
|
—
|
|
|
|
7,404
|
|
|
347
|
|
|
|
Non-controlling interest in Superior
|
(1,017)
|
|
|
|
7,504
|
|
|
(11)
|
|
|
|
|
Goodwill impairment
|
—
|
|
|
|
—
|
|
|
12,346
|
|
|
|
|
Valuation allowance
|
4,047
|
|
|
|
177,284
|
|
|
19,654
|
|
|
|
|
Reorganization adjustments
|
—
|
|
|
|
14,152
|
|
|
—
|
|
|
|
|
Statutory depletion and other
|
169
|
|
|
|
813
|
|
|
1,163
|
|
|
|
|
Income tax benefit
|
$
|
(302)
|
|
|
|
$
|
(14,630)
|
|
|
$
|
(132,326)
|
|
|
|
For the periods indicated, the total provision for income taxes consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
|
|
|
|
|
(In thousands)
|
|
Current taxes:
|
|
|
|
|
|
|
|
|
|
Federal
|
$
|
—
|
|
|
|
$
|
(917)
|
|
|
$
|
(918)
|
|
|
|
|
State
|
(302)
|
|
|
|
—
|
|
|
(363)
|
|
|
|
|
|
(302)
|
|
|
|
(917)
|
|
|
(1,281)
|
|
|
|
|
Deferred taxes:
|
|
|
|
|
|
|
|
|
|
Federal
|
—
|
|
|
|
(16,663)
|
|
|
(108,440)
|
|
|
|
|
State
|
—
|
|
|
|
2,950
|
|
|
(22,605)
|
|
|
|
|
|
—
|
|
|
|
(13,713)
|
|
|
(131,045)
|
|
|
|
|
Total provision
|
$
|
(302)
|
|
|
|
$
|
(14,630)
|
|
|
$
|
(132,326)
|
|
|
|
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
Deferred tax assets and liabilities are comprised of the following at December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
2020
|
|
|
2019
|
|
|
(In thousands)
|
|
Deferred tax assets:
|
|
|
|
|
|
Allowance for losses and nondeductible accruals
|
$
|
22,051
|
|
|
|
$
|
31,822
|
|
|
Net operating loss carryforward
|
100,236
|
|
|
|
246,927
|
|
|
Depreciation, depletion, amortization, and impairment
|
80,947
|
|
|
|
—
|
|
|
Alternative minimum tax and research and development tax credit carryforward
|
1,738
|
|
|
|
2,656
|
|
|
|
204,972
|
|
|
|
281,405
|
|
|
Deferred tax liability:
|
|
|
|
|
|
Depreciation, depletion, amortization, and impairment
|
—
|
|
|
|
(226,034)
|
|
|
Investment in Superior
|
(3,987)
|
|
|
|
(49,430)
|
|
|
Net deferred tax asset (liability)
|
200,985
|
|
|
|
5,941
|
|
|
Valuation allowance
|
(200,985)
|
|
|
|
(19,654)
|
|
|
Non-current—deferred tax liability
|
$
|
—
|
|
|
|
$
|
(13,713)
|
|
A valuation allowance is established to reduce deferred tax assets if it is determined that it is more likely than not that the related tax benefit will not be realized. On a quarterly basis, management evaluates the need for and adequacy of valuation allowances based on the expected realizability of the deferred tax assets and adjusts the amount of such allowances, if necessary. To the extent a valuation allowance is established or is increased or decreased during a period, there is a corresponding expense or reduction of expense within the tax provision in the Consolidated Statements of Operations.
During the year ended December 31, 2019, in evaluating whether it was more likely than not that the company's deferred tax assets were realizable through future net income, we considered all available positive and negative evidence, including (i) our earnings history exclusive of the loss that created the future deductible amount coupled with evidence indicating that the loss is an aberration rather than a continuing condition, (ii) our ability to recover net operating loss carryforward deferred tax assets in future years, (iii) the existence of significant proved oil, NGL and natural gas reserves, (iv) future revenue and operating cost projections that indicate the company will produce more than enough taxable income to realize the deferred tax asset based on existing sales prices and cost structures and (vii) current market prices for oil, NGL and natural gas. Based on all the evidence available, we determined it was more likely than not that the deferred tax asset for net operating loss carryforwards were not fully realizable. As of December 31, 2019, a total valuation allowance of $19.7 million has been recorded. As of December 31, 2020, the valuation allowance had increased to $201.0 million to reflect a full valuation allowance against our net deferred tax assets due to the impacts of the Plan from our bankruptcy proceedings, fresh start accounting, and tax attribute reductions as prescribed by IRC Section 108.
We file income tax returns in the U.S. federal jurisdiction and various states. We are no longer subject to U.S. federal tax examinations for years before 2016 or state income tax examinations by state taxing authorities for years before 2015. At December 31, 2020, we had expected federal net operating loss carryforwards of approximately $409.1 million of which $223.0 million would expire from 2021 to 2037.
NOTE 12 – EMPLOYEE BENEFIT PLANS
Under our 401(k) Employee Thrift Plan, employees who meet specified service requirements may contribute a percentage of their total compensation, up to a specified maximum, to the plan. We may match each employee’s contribution, up to a specified maximum, in full or on a partial basis with cash or common stock. We made discretionary contributions under the plan of 310,797 shares of common stock in 2019 for the plan year 2018. The 2019 plan year matching contribution was made in cash instead of shares of common stock. On the Effective Date, all the shares of old common stock under the 401(k) Employee Thrift Plan were cancelled and each holder that did not opt out of the release under the Plan was entitled to receive his or her pro rata share of the Warrants in accordance with the Plan.
Total 401(k) employer matching expense was $0.7 million, $1.4 million, and $5.2 million in the Successor Period of 2020, the Predecessor Period of 2020, and the year 2019, respectively.
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
We provided a salary deferral plan for our executives (Deferral Plan) which allowed participants to defer the recognition of salary for income tax purposes until actual distribution of benefits occurred at either termination of employment, death, or certain defined unforeseeable emergency hardships. The liability recorded under the Deferral Plan at December 31, 2019 was $6.2 million. We recognized payroll expense and recorded a liability at the time of deferral. As of December 31, 2020, investments held in the Deferral Plan had been paid out to plan participants and the plan was terminated.
As of the Effective Date, the Board adopted (i) the Amended and Restated Separation Benefit Plan of Unit Corporation and Participating Subsidiaries (Amended Separation Benefit Plan), (ii) the Amended and Restated Special Separation Benefit Plan of Unit Corporation and Participating Subsidiaries (Amended Special Separation Benefit Plan) and (iii) the Separation Benefit Plan of Unit Corporation and Participating Subsidiaries (New Separation Benefit Plan). In accordance with the Plan, the Amended Separation Benefit Plan and the Amended Special Separation Benefit Plan allow former employees or retained employees with vested severance benefits under either plan to receive certain cash payments in full satisfaction for their allowed separation claim under the Chapter 11 Cases. In accordance with the Plan, the New Separation Benefit Plan is a comprehensive severance plan for retained employees, including retained employees whose severance did not already vest under the Amended Separation Benefit Plan or the Amended Special Separation Benefit Plan. The New Separation Benefit Plan provides eligible employees with two weeks of severance pay per year of service, with a minimum of four weeks and a maximum of 13 weeks of severance pay. These benefits vest after 20 years of service provided to the company. We recognized expense of $1.4 million. $18.1 million, and $3.8 million in the Successor Period of 2020, the Predecessor Period of 2020, and the year 2019, respectively, for benefits associated with anticipated payments from these separation plans.
NOTE 13 – TRANSACTIONS WITH RELATED PARTIES
Unit Petroleum Company served as the general partner of 13 oil and gas limited partnerships (the employee partnerships) which were formed to allow certain of our qualified employees and our directors to participate in Unit Petroleum’s oil and gas exploration and production operations. Employee partnerships were formed for each year beginning with 1984 and ending with 2011. 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.
One former director, G. Bailey Peyton IV, also serves as Manager and 99.5% owner of Peyton Royalties, LP, a family-controlled limited partnership that owns royalty rights in wells in several states. The company in the ordinary course of business, paid royalties, or lease bonuses, primarily due to its status as successor in interest to prior transactions and as operator of the wells involved and, sometimes, as lessee, regarding certain wells in which Mr. Peyton, members of Mr. Peyton's family, and Peyton Royalties, LP have an interest. Such payments totaled approximately $0.2 million and $0.4 million during the Predecessor period ended August 31, 2020 and the year ended December 31, 2019, respectively.
NOTE 14 – 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 shares under the LTIP have been awarded since the Effective Date through December 31, 2020.
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 further information, see Note 2 – Emergence From Voluntary Reorganization Under Chapter 11.
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
For restricted stock awards, we had:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Predecessor
|
|
|
Period
January 1, 2020 through
August 31, 2020
|
|
For the Year Ended
December 31, 2019
|
|
|
|
|
|
(In millions)
|
|
Recognized stock compensation expense (1)
|
$
|
6.1
|
|
|
$
|
12.8
|
|
|
|
|
Capitalized stock compensation cost for our oil and natural gas properties
|
$
|
—
|
|
|
$
|
2.4
|
|
|
|
|
Tax benefit on stock-based compensation
|
$
|
1.5
|
|
|
$
|
3.1
|
|
|
|
_______________________
1.When the company's equity-based awards were cancelled on the Effective Date, we immediately recognized the expense for the cancelled awards of $1.4 million as reorganization costs, net.
The Second Amended and Restated Unit Corporation Stock and Incentive Compensation Plan effective May 6, 2015 (the amended plan) allowed us to grant stock-based and cash-based compensation to our employees (including employees of subsidiaries) and to non-employee directors. There were 7,230,000 shares of the company's common stock authorized for issuance to eligible participants under the amended plan with 2.0 million shares being the maximum number of shares that could be issued as “incentive stock options.” The amended plan was terminated under the Plan.
Restricted Stock
Activity pertaining to restricted stock awards granted under the amended plan is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Employees
|
Number of Time Vested Shares
|
|
Number of Performance Vested Shares
|
|
Total Number of
Shares
|
|
Weighted
Average
Price
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nonvested at January 1, 2019 (Predecessor)
|
1,268,883
|
|
|
608,125
|
|
|
1,877,008
|
|
|
$
|
19.70
|
|
|
Granted
|
927,173
|
|
|
500,256
|
|
|
1,427,429
|
|
|
16.09
|
|
|
Vested
|
(570,107)
|
|
|
(233,835)
|
|
|
(803,942)
|
|
|
15.56
|
|
|
Forfeited
|
(98,301)
|
|
|
(33,172)
|
|
|
(131,473)
|
|
|
19.36
|
|
|
Nonvested at December 31, 2019 (Predecessor)
|
1,527,648
|
|
|
841,374
|
|
|
2,369,022
|
|
|
$
|
18.95
|
|
|
Granted
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Vested
|
(677,076)
|
|
|
—
|
|
|
(677,076)
|
|
|
19.95
|
|
|
Forfeited
|
(272,396)
|
|
|
(503,809)
|
|
|
(776,205)
|
|
|
19.28
|
|
|
Nonvested at August 31, 2020 (Predecessor)
|
578,176
|
|
|
337,565
|
|
|
915,741
|
|
|
$
|
17.92
|
|
|
Cancelled
|
(578,176)
|
|
|
(337,565)
|
|
|
(915,741)
|
|
|
17.92
|
|
|
Nonvested at September 1, 2020 (Successor)
|
—
|
|
|
—
|
|
|
—
|
|
|
$
|
—
|
|
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-Employee Directors
|
Number of
Shares
|
|
Weighted
Average
Price
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nonvested at January 1, 2019 (Predecessor)
|
107,045
|
|
|
$
|
17.07
|
|
|
Granted
|
72,784
|
|
|
12.09
|
|
|
Vested
|
(61,141)
|
|
|
15.49
|
|
|
Forfeited
|
—
|
|
|
—
|
|
|
Nonvested at December 31, 2019 (Predecessor)
|
118,688
|
|
|
$
|
14.83
|
|
|
Granted
|
—
|
|
|
—
|
|
|
Vested
|
(48,475)
|
|
|
15.88
|
|
|
Forfeited
|
—
|
|
|
—
|
|
|
Nonvested at August 31, 2020 (Predecessor)
|
70,213
|
|
|
$
|
14.10
|
|
|
Cancelled
|
(70,213)
|
|
|
14.10
|
|
|
Nonvested at September 1, 2020 (Successor)
|
—
|
|
|
$
|
—
|
|
The time vested restricted stock awards granted were being recognized over a three-year vesting period. There also were performance vested restricted stock awards granted to certain executive officers. All of these awards were cancelled on the Effective Date. We recognized a reversal of expense previously recorded for the unvested awards of $2.2 million for these awards upon cancellation.
The fair value of the restricted stock granted in 2019 at the grant date was $22.6 million.
Non-Employee Directors' Stock Option Plan
Under the Unit Corporation 2000 Non-Employee Directors’ Stock Option Plan, on the first business day following each annual meeting of shareholders, each person who was then a member of our Board of Directors and who was not then an employee of the company or any of its subsidiaries was granted an option to purchase 3,500 shares of common stock. These awards and the plan were cancelled on the Effective Date.
Activity pertaining to the Directors’ Plan is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of
Shares
|
|
Weighted
Average
Exercise
Price
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nonvested at January 1, 2019 (Predecessor)
|
66,500
|
|
|
$
|
44.42
|
|
|
Granted
|
—
|
|
|
—
|
|
|
Exercised
|
—
|
|
|
—
|
|
|
Forfeited
|
(24,500)
|
|
|
37.31
|
|
|
Nonvested at December 31, 2019 (Predecessor)
|
42,000
|
|
|
$
|
48.56
|
|
|
Granted
|
—
|
|
|
—
|
|
|
Exercised
|
—
|
|
|
—
|
|
|
Forfeited
|
(14,000)
|
|
|
41.21
|
|
|
Outstanding at August 31, 2020 (Predecessor)
|
28,000
|
|
|
$
|
52.24
|
|
|
Cancelled
|
(28,000)
|
|
|
52.24
|
|
|
Outstanding at September 1, 2020 (Successor)
|
—
|
|
|
$
|
—
|
|
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
NOTE 15 – 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 December 31, 2020, 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 balance sheet 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 gain (loss) on derivatives in our Consolidated Statements of Operations.
At December 31, 2020, the following non-designated hedges were outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Term
|
|
Commodity
|
|
Contracted Volume
|
|
Weighted Average
Fixed Price for Swaps
|
|
Contracted Market
|
|
Jan'21 - Dec'21
|
|
Natural gas - basis swap
|
|
30,000 MMBtu/day
|
|
$(0.215)
|
|
NGPL TEXOK
|
|
Jan'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)
|
|
Jan'21 - Dec'21
|
|
Crude oil - swap
|
|
3,000 Bbl/day
|
|
$44.65
|
|
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 in our Consolidated Balance Sheets at December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative Assets
Fair Value
|
|
|
|
|
|
Successor
|
|
Predecessor
|
|
|
|
Balance Sheet Location
|
|
2020
|
|
2019
|
|
|
|
|
|
(In thousands)
|
|
Commodity derivatives:
|
|
|
|
|
|
|
|
Current
|
|
Current derivative assets
|
|
$
|
—
|
|
|
$
|
633
|
|
|
Long-term
|
|
Non-current derivative assets
|
|
—
|
|
|
—
|
|
|
Total derivative assets
|
|
|
|
$
|
—
|
|
|
$
|
633
|
|
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative Liabilities
Fair Value
|
|
|
|
|
|
Successor
|
|
Predecessor
|
|
|
|
Balance Sheet Location
|
|
2020
|
|
2019
|
|
|
|
|
|
(In thousands)
|
|
Commodity derivatives:
|
|
|
|
|
|
|
|
Current
|
|
Current derivative liabilities
|
|
$
|
1,047
|
|
|
$
|
—
|
|
|
Long-term
|
|
Non-current derivative liabilities
|
|
4,659
|
|
|
27
|
|
|
Total derivative liabilities
|
|
|
|
$
|
5,706
|
|
|
$
|
27
|
|
If a legal right of set-off exists, we net the value of the derivative transactions we have with the same counterparty in our Consolidated Balance Sheets.
The following is the Effect of derivative instruments on the Consolidated Statements of Operations for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives Instruments
|
|
Location of Gain or (Loss)
Recognized in Income on
Derivative
|
|
Amount of Gain or (Loss) Recognized in Income on Derivative
|
|
|
|
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
|
|
|
|
|
|
|
|
|
|
|
|
(In thousands)
|
|
Commodity derivatives
|
|
Gain (loss) on derivatives, included are amounts settled during the period of $(1,133), $(4,244), and $16,196, respectively
|
|
$
|
(985)
|
|
|
|
$
|
(10,704)
|
|
|
$
|
4,225
|
|
|
|
|
Total
|
|
|
|
$
|
(985)
|
|
|
|
$
|
(10,704)
|
|
|
$
|
4,225
|
|
|
|
NOTE 16 – FAIR VALUE MEASUREMENTS
Fair value is defined as the amount that would be received from the sale of an asset or paid for the transfer of 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 that are 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 which are developed based on the best information available and may include our own internal data.
The inputs available determine the valuation technique we use to measure the fair values presented in our financial instruments.
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
The following tables set forth our recurring fair value measurements:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
December 31, 2020
|
|
|
Level 2
|
|
Level 3
|
|
Effect of Netting
|
|
Total
|
|
|
(In thousands)
|
|
Financial assets (liabilities):
|
|
|
|
|
|
|
|
|
Commodity derivatives:
|
|
|
|
|
|
|
|
|
Assets
|
$
|
3,436
|
|
|
$
|
—
|
|
|
$
|
(3,436)
|
|
|
$
|
—
|
|
|
Liabilities
|
(9,142)
|
|
|
—
|
|
|
3,436
|
|
|
(5,706)
|
|
|
|
$
|
(5,706)
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(5,706)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Predecessor
|
|
|
December 31, 2019
|
|
|
Level 2
|
|
Level 3
|
|
Effect of Netting
|
|
Total
|
|
|
(In thousands)
|
|
Financial assets (liabilities):
|
|
|
|
|
|
|
|
|
Commodity derivatives:
|
|
|
|
|
|
|
|
|
Assets
|
$
|
177
|
|
|
$
|
1,204
|
|
|
$
|
(748)
|
|
|
$
|
633
|
|
|
Liabilities
|
(775)
|
|
|
—
|
|
|
748
|
|
|
(27)
|
|
|
|
$
|
(598)
|
|
|
$
|
1,204
|
|
|
$
|
—
|
|
|
$
|
606
|
|
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 any cash collateral with our counterparties and no collateral has been posted as of December 31, 2020.
The following methods and assumptions were used 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 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 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.
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
The following tables are reconciliations of our recurring level 3 fair value measurements:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Derivatives
|
|
|
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
|
|
|
|
|
|
|
|
(In thousands)
|
|
Beginning of period
|
$
|
—
|
|
|
|
$
|
1,204
|
|
|
$
|
10,630
|
|
|
|
|
Total gains or losses:
|
|
|
|
|
|
|
|
|
|
Included in earnings
|
—
|
|
|
|
978
|
|
|
(1,494)
|
|
|
|
|
Settlements
|
—
|
|
|
|
(2,182)
|
|
|
(7,932)
|
|
|
|
|
End of period
|
$
|
—
|
|
|
|
$
|
—
|
|
|
$
|
1,204
|
|
|
|
|
Total gains (losses) for the period included in earnings attributable to the change in unrealized loss relating to assets still held at end of period
|
$
|
—
|
|
|
|
$
|
(1,204)
|
|
|
$
|
(9,426)
|
|
|
|
Based on our valuation at December 31, 2020, we determined that the non-performance risk regarding our counterparties was immaterial.
Fair Value of Other Financial Instruments
We have determined the estimated fair values of other financial instruments by using available market information and valuation methodologies. Considerable judgment is required in interpreting market data to develop the estimates of fair value. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.
At December 31, 2020, the carrying values on the Consolidated Balance Sheets for cash, restricted cash, and cash equivalents (classified as Level 1), accounts receivable, accounts payable, other current assets, and current liabilities approximate their fair value because of their short-term nature.
The Warrants are accounted for as a derivative liability as they are not indexed to the New Common Stock until all outstanding disputed claims against the company and UPC have been finally resolved and the strike price for the Warrants can be determined. Accordingly, the Warrants are recorded at their fair value using the Black-Scholes-Merton option model. The inputs to the model require various judgements, including estimating the strike price, expected term and the associated volatility. The Warrants are adjusted to fair value at each reporting period until determined to be an equity instrument, at which time they will be reported as shareholders' equity and no longer be subject to future fair value adjustment. At December 31, 2020, the Warrants have a fair value of $0.9 million. The Warrants are considered Level 3 fair value measurements.
Based on the borrowing rates currently available to us for credit agreement debt with similar terms and maturities and considering the risk of our non-performance, long-term debt under our credit agreements at December 31, 2020 would approximate its fair value. This debt is classified as Level 2.
The carrying amount of long-term debt, net of unamortized discount and debt issuance costs, associated with the Notes reported in the Consolidated Balance Sheets at December 31, 2019 was $646.7 million. On the Effective Date, our obligations with respect to the Notes were cancelled and holders of the Notes subsequently received their agreed on pro-rata share of New Common Stock. For further information, please see Note 2 – Emergence From Voluntary Reorganization Under Chapter 11. The estimated fair value of these Notes using quoted market prices at December 31, 2019 was $357.5 million. These Notes were classified as Level 2.
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 the company’s AROs is presented in Note 10 – Asset Retirement Obligations.
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
Non-recurring fair value measurements are also applied, when applicable, to determine the fair value of our long-lived assets and goodwill. During 2020 and 2019, we recorded non-cash impairment charges discussed further in Note 4 – Summary Of Significant Accounting Policies. The valuation of these assets requires the use of significant unobservable inputs classified as Level 3.
See Note 3 - Fresh Start Accounting for additional disclosures of non-recurring fair value measurements associated with the qualification of fresh start under ASC 852.
NOTE 17 – LEASES
Operating Leases under ASC 842
Adoption of Accounting Standards Codification (ASC) Topic 842, “Leases." We adopted Topic 842 on January 1, 2019, using the modified retrospective method and the optional transition method to record the adoption impact through a cumulative adjustment to equity. Results for reporting periods beginning after January 1, 2019, are presented under Topic 842, while prior periods are presented under ASC 840.
We determine whether a contract is or contains a lease at inception of the contract based on whether an identified asset exists and whether we have the right to obtain substantially all the benefit of the assets and to control its use over the full term of the agreement. When available, we use the rate explicit in the lease to discount lease payments to present value; however, most of our leases do not provide a readily determinable explicit rate. Therefore, we must estimate our incremental borrowing rate considering both the revolving credit rates and a credit notching approach to discount the lease payments based on information available at lease commencement. There are no material residual value guarantees and no restrictions or covenants included in our lease agreements. Certain of our leases include provisions for variable payments. These variable payments are typically determined based on a measure of throughput or actual days or another measure of usage and are not included in the calculation of lease liabilities and right-of-use assets.
Related to our oil and natural gas segment, our short-term lease costs include those that are recognized in profit or loss during the period and those that are capitalized as part of the cost of our full cost pool. As the costs related to our drilling and production activities are reflected at our net ownership consistent with the principals of proportional consolidation, and lease commitments are generally considered gross as the operator, the costs may not reasonably reflect the company’s short-term lease commitments.
Practical Expedients and Policies Elected. We elected the hindsight expedient, which allows us to use hindsight in assessing lease term; the package of practical expedients permitted under the guidance, which among other things, allowed us to carry forward the historical lease classification; and the land easement expedient, which allowed us to apply the guidance prospectively at adoption for land easements on existing agreements. We applied the short-term policy election, which allowed us to exclude from recognition on the balance sheet leases with an initial term of 12 months or less. We considered quantitative and qualitative factors when determining the application of the practical expedient that allowed us not to separate lease and non-lease components and are accounting for the agreements as a single lease component.
We routinely enter into related party agreements between our three segments. These agreements have been evaluated under the guidance of ASC 842. Our oil and natural gas segment may contract for the use of drilling equipment from our drilling segment. We have determined that the contracting of our drilling segment's drilling rigs will be accounted for under ASC 606 as the service has been deemed the predominate component of the contract per the lessor practical expedient.
Adoption. Adoption of Topic 842 resulted in new operating lease assets and lease liabilities on our Consolidated Balance Sheet of $3.7 million and $3.5 million, respectively, as of January 1, 2019, which represents noncash operating activity. The immaterial difference between the lease assets and lease liabilities was recorded as an adjustment to the beginning balance of retained earnings, which represents the cumulative impact of adopting the standard. Our accounting for finance leases remained substantially unchanged.
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 lease agreements do not include options to purchase the leased property.
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
The following table sets forth the maturity of our operating lease liabilities as of December 31, 2020:
|
|
|
|
|
|
|
|
|
|
|
|
|
Amount
|
|
|
|
(In thousands)
|
|
Ending December 31,
|
|
|
|
2021
|
|
$
|
4,232
|
|
|
2022
|
|
1,305
|
|
|
2023
|
|
96
|
|
|
2024
|
|
12
|
|
|
2025
|
|
12
|
|
|
2026 and beyond
|
|
63
|
|
|
Total future payments
|
|
5,720
|
|
|
Less: Interest
|
|
200
|
|
|
Present value of future minimum operating lease payments
|
|
5,520
|
|
|
Less: Current portion
|
|
4,075
|
|
|
Total long-term operating lease payments
|
|
$
|
1,445
|
|
Finance Leases under ASC 842
During 2014, our mid-stream segment entered into finance lease agreements for 20 compressors with initial terms of seven years. The underlying assets are included in gas gathering and processing equipment. The current portion of our finance lease obligations of $3.2 million is included in current portion of other long-term liabilities in the accompanying Consolidated Balance Sheets as of December 31, 2020. These finance leases are discounted using annual rates of 4.0%. Total maintenance and interest remaining related to these leases were $0.5 million at December 31, 2020. At the end of the term, our mid-stream segment has the option to purchase the assets at 10% of the fair market value of the assets at that time.
Future payments required under the finance leases at December 31, 2020 are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
Amount
|
|
Ending December 31,
|
|
(In thousands)
|
|
2021
|
|
$
|
3,774
|
|
|
Total future payments
|
|
3,774
|
|
|
Less payments related to:
|
|
|
|
Maintenance
|
|
525
|
|
|
Interest
|
|
33
|
|
|
Present value of future minimum payments
|
|
3,216
|
|
|
Less: Current portion
|
|
3,216
|
|
|
Total long-term finance lease payments
|
|
$
|
—
|
|
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
Information about our lease assets and liabilities included in our Consolidated Balance Sheets as of December 31, 2020 and 2019 are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
|
Classification on the Consolidated Balance Sheets
|
|
December 31,
2020
|
|
|
December 31,
2019
|
|
|
|
|
|
(In thousands)
|
|
Assets
|
|
|
|
|
|
|
|
|
Operating right of use assets
|
|
Right of use assets
|
|
$
|
5,592
|
|
|
|
$
|
5,673
|
|
|
Finance right of use assets
|
|
Property, plant, and equipment, net
|
|
7,281
|
|
|
|
17,396
|
|
|
Total right of use assets
|
|
|
|
$
|
12,873
|
|
|
|
$
|
23,069
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities
|
|
|
|
|
|
|
|
|
Current liabilities:
|
|
|
|
|
|
|
|
|
Operating lease liabilities
|
|
Current operating lease liabilities
|
|
$
|
4,075
|
|
|
|
$
|
3,430
|
|
|
Finance lease liabilities
|
|
Current portion of other long-term liabilities
|
|
3,216
|
|
|
|
4,164
|
|
|
Non-current liabilities:
|
|
|
|
|
|
|
|
|
Operating lease liabilities
|
|
Operating lease liabilities
|
|
1,445
|
|
|
|
2,071
|
|
|
Finance lease liabilities
|
|
Other long-term liabilities
|
|
—
|
|
|
|
3,215
|
|
|
Total lease liabilities
|
|
|
|
$
|
8,736
|
|
|
|
$
|
12,880
|
|
The following table shows certain information related to the lease costs for our finance and operating leases for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
|
Period
September 1, 2020
through
December 31, 2020
|
|
|
Period
January 1, 2020 through
August 31, 2020
|
|
Year Ended December 31, 2019
|
|
|
|
|
|
|
|
|
(In thousands)
|
|
Components of total lease cost:
|
|
|
|
|
|
|
|
|
Amortization of finance leased assets
|
|
$
|
1,406
|
|
|
|
$
|
2,757
|
|
|
$
|
4,001
|
|
|
Interest on finance lease liabilities
|
|
54
|
|
|
|
165
|
|
|
382
|
|
|
Operating lease cost
|
|
1,331
|
|
|
|
3,604
|
|
|
4,034
|
|
|
Short-term lease cost, included are amounts capitalized related to our oil and natural gas segment of less than $0.2 million, $1.5 million, and $24.7 million, respectively
|
|
3,664
|
|
|
|
8,190
|
|
|
38,868
|
|
|
Variable lease cost
|
|
64
|
|
|
|
223
|
|
|
351
|
|
|
Total lease cost
|
|
$
|
6,519
|
|
|
|
$
|
14,939
|
|
|
$
|
47,636
|
|
The following table provides supplemental cash flow information related to leases for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
Period
September 1, 2020
through
December 31, 2020
|
|
|
Period
January 1, 2020 through
August 31, 2020
|
|
Year Ended December 31, 2019
|
|
|
|
|
|
|
|
(In thousands)
|
|
Cash paid for amounts included in the measurement of lease liabilities:
|
|
|
|
|
|
|
|
Operating cash flows for operating leases
|
$
|
1,489
|
|
|
|
$
|
3,849
|
|
|
$
|
4,034
|
|
|
Financing cash flows for finance leases
|
1,407
|
|
|
|
2,757
|
|
|
4,001
|
|
|
Lease liabilities recognized in exchange for new operating lease right of use assets
|
—
|
|
|
|
—
|
|
|
5
|
|
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
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 at December 31, 2020:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average Remaining Lease Term
|
|
Weighted Average Discount
Rate (1)
|
|
|
|
(In years)
|
|
|
|
Operating leases
|
|
1.6
|
|
4.41%
|
|
Finance leases
|
|
0.7
|
|
4.00%
|
_______________________
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.
We lease office space in Oklahoma City, Oklahoma; Houston and Odessa, Texas; Englewood, Colorado; and Pinedale, Wyoming under the terms of operating leases expiring through January 2022. We also have compressor rentals, equipment leases, and lease space on short-term commitments to stack excess drilling rig equipment and production inventory.
NOTE 18 – COMMITMENTS AND CONTINGENCIES
Commitments
Our mid-stream segment has firm transportation commitments to transport our natural gas from various systems for approximately $1.0 million over the next twelve months and $0.4 million for the one year thereafter.
During the second quarter of 2018, as part of the Superior transaction (see Note 19 – 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 our consolidated mid-stream subsidiary. At December 31, 2020, 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. Total spent towards the $150.0 million as of December 31, 2020 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. The amount of any potential liability is determined by considering, among other matters, incremental direct costs of any likely remediation and the proportionate cost of employees who are expected to devote a significant amount of 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 any significant environmental liabilities while being a contract driller since the greatest portion of risk is borne by the operator. Any liabilities we have incurred have been small and have been resolved while the drilling rig is on the location and the cost has been included 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.
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
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. For further information on the Chapter 11 Cases, please see Note 2 – Emergence From Voluntary Reorganization Under Chapter 11.
In 2013, the company’s exploration and production subsidiary, Unit Petroleum Company (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 it was pending review in the Oklahoma Court of Civil Appeals. In February 2021, UPC finalized a settlement agreement with the working interest owner for $2.1 million in damages. As of December 31, 2020, the company's total accrual for loss contingencies was $2.1 million.
Below is a summary of two other 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. 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 proofs 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 settlement amounts will be treated as allowed general unsecured claims against UPC. The settlement amounts will be satisfied by distribution of the plaintiffs’ proportionate share of New Common Stock in accordance with the Plan.
Subsequent Event: Winter Storm
In February of 2021, a severe winter storm impacted many of our operating areas in Oklahoma, Texas, and Kansas, resulting in certain disruptions to our operations. Although some uncertainties remain as to the ultimate impact and severity of these disruptions, we do not believe any such matters will have a material impact on our financial position.
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
NOTE 19 – 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 Holdings, LLC, 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 the 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, such as operations and maintenance support, accounting, legal, and human resources to Superior for a monthly service fee of $260,560. Superior's creditors have no recourse to our general credit. Unit 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 18 – Commitments and Contingencies or a cumulative return to SP Investor Holdings, LLC of less than the 7% Liquidation IRR Hurdle provided for SP Investor Holdings, LLC in the Agreement. Generally, the 7% Liquidation IRR Hurdle calculation requires cumulative distributions to SP Investor Holdings, LLC in excess of its original $300.0 million investment sufficient to provide SP Investor Holdings, LLC 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, 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.
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 as of December 31, 2020.
As the primary beneficiary of this VIE, we consolidate in the 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 the 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.
With consolidation of the VIE, the assets and liabilities of Superior were subject to fair value adjustments in accordance with ASC 852, Reorganizations. Therefore, the periods presented below are not comparative. The assets and liabilities of Superior at December 31, 2020 include the company’s application of fresh start accounting as described in Note 3 - Fresh Start Accounting, while the asset and liabilities at December 31, 2019, reflect historical basis, prior to any fresh start accounting
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
adjustments. The amounts below reflect the eliminations of intercompany transactions and balances consistent with the presentation in the Consolidated Balance Sheets.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
2020
|
|
December 31,
2019
|
|
|
|
(In thousands)
|
|
Current assets:
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
11,642
|
|
|
$
|
—
|
|
|
Accounts receivable
|
|
27,427
|
|
|
21,073
|
|
|
Prepaid expenses and other
|
|
6,746
|
|
|
7,686
|
|
|
Total current assets
|
|
45,815
|
|
|
28,759
|
|
|
Property and equipment:
|
|
|
|
|
|
Gas gathering and processing equipment
|
|
251,403
|
|
|
824,699
|
|
|
Transportation equipment
|
|
1,748
|
|
|
3,390
|
|
|
|
|
253,151
|
|
|
828,089
|
|
|
Less accumulated depreciation, depletion, amortization, and impairment
|
|
10,466
|
|
|
407,144
|
|
|
Net property and equipment
|
|
242,685
|
|
|
420,945
|
|
|
Right of use assets
|
|
2,823
|
|
|
3,948
|
|
|
Other assets
|
|
2,309
|
|
|
9,442
|
|
|
Total assets
|
|
$
|
293,632
|
|
|
$
|
463,094
|
|
|
|
|
|
|
|
|
Current liabilities:
|
|
|
|
|
|
Accounts payable
|
|
$
|
17,045
|
|
|
$
|
18,511
|
|
|
Accrued liabilities
|
|
3,777
|
|
|
4,198
|
|
|
Current operating lease liability
|
|
1,762
|
|
|
2,407
|
|
|
Current portion of other long-term liabilities
|
|
5,799
|
|
|
7,060
|
|
|
Total current liabilities
|
|
28,383
|
|
|
32,176
|
|
|
Long-term debt less debt issuance costs
|
|
—
|
|
|
16,500
|
|
|
Operating lease liability
|
|
1,013
|
|
|
1,404
|
|
|
Other long-term liabilities
|
|
1,589
|
|
|
8,126
|
|
|
Total liabilities
|
|
$
|
30,985
|
|
|
$
|
58,206
|
|
NOTE 20 – INDUSTRY SEGMENT INFORMATION
We have three main business segments offering different products and services:
•Oil and natural gas,
•Contract drilling, and
•Mid-stream
The oil and natural gas segment is engaged in the development, acquisition, 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.
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
The following table provides certain information about the operations of each of our segments:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
|
Four Months Ended December 31, 2020
|
|
|
|
Oil and Natural Gas
|
|
Contract Drilling
|
|
Mid-stream
|
|
Corporate and Other
|
|
Eliminations
|
|
Total Consolidated
|
|
|
|
(In thousands)
|
|
Revenues: (1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas
|
|
$
|
57,580
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(2)
|
|
|
$
|
57,578
|
|
|
Contract drilling
|
|
—
|
|
|
19,413
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
19,413
|
|
|
Gas gathering and processing
|
|
—
|
|
|
—
|
|
|
68,369
|
|
|
—
|
|
|
(11,832)
|
|
|
56,537
|
|
|
Total revenues
|
|
57,580
|
|
|
19,413
|
|
|
68,369
|
|
|
—
|
|
|
(11,834)
|
|
|
133,528
|
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas
|
|
26,111
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(855)
|
|
|
25,256
|
|
|
Contract drilling
|
|
—
|
|
|
13,852
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
13,852
|
|
|
Gas gathering and processing
|
|
—
|
|
|
—
|
|
|
53,147
|
|
|
—
|
|
|
(10,978)
|
|
|
42,169
|
|
|
Total operating costs
|
|
26,111
|
|
|
13,852
|
|
|
53,147
|
|
|
—
|
|
|
(11,833)
|
|
|
81,277
|
|
|
Depreciation, depletion, and amortization
|
|
14,869
|
|
|
2,102
|
|
|
10,659
|
|
|
332
|
|
|
—
|
|
|
27,962
|
|
|
Impairments (2)
|
|
26,063
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
26,063
|
|
|
Total expenses
|
|
67,043
|
|
|
15,954
|
|
|
63,806
|
|
|
332
|
|
|
(11,833)
|
|
|
135,302
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative
|
|
—
|
|
|
—
|
|
|
—
|
|
|
6,702
|
|
|
—
|
|
|
6,702
|
|
|
Gain on disposition of assets
|
|
(24)
|
|
|
(521)
|
|
|
(55)
|
|
|
(19)
|
|
|
—
|
|
|
(619)
|
|
|
Income (loss) from operations
|
|
(9,439)
|
|
|
3,980
|
|
|
4,618
|
|
|
(7,015)
|
|
|
(1)
|
|
|
(7,857)
|
|
|
Loss on derivatives
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(985)
|
|
|
—
|
|
|
(985)
|
|
|
Reorganization items, net
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(2,273)
|
|
|
—
|
|
|
(2,273)
|
|
|
Interest, net
|
|
—
|
|
|
—
|
|
|
(501)
|
|
|
(2,774)
|
|
|
—
|
|
|
(3,275)
|
|
|
Other
|
|
56
|
|
|
4
|
|
|
34
|
|
|
6
|
|
|
—
|
|
|
100
|
|
|
Income (loss) before income taxes
|
|
$
|
(9,383)
|
|
|
$
|
3,984
|
|
|
$
|
4,151
|
|
|
$
|
(13,041)
|
|
|
$
|
(1)
|
|
|
$
|
(14,290)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Identifiable assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas (3)
|
|
$
|
236,073
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(3,326)
|
|
|
$
|
232,747
|
|
|
Contract drilling
|
|
—
|
|
|
81,612
|
|
|
—
|
|
|
—
|
|
|
(4)
|
|
|
81,608
|
|
|
Gas gathering and processing
|
|
—
|
|
|
—
|
|
|
293,632
|
|
|
—
|
|
|
(335)
|
|
|
293,297
|
|
|
Total identifiable assets (4)
|
|
236,073
|
|
|
81,612
|
|
|
293,632
|
|
|
—
|
|
|
(3,665)
|
|
|
607,652
|
|
|
Corporate land and building
|
|
—
|
|
|
—
|
|
|
—
|
|
|
32,382
|
|
|
—
|
|
|
32,382
|
|
|
Other corporate assets (5)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
13,671
|
|
|
(4,002)
|
|
|
9,669
|
|
|
Total assets
|
|
$
|
236,073
|
|
|
$
|
81,612
|
|
|
$
|
293,632
|
|
|
$
|
46,053
|
|
|
$
|
(7,667)
|
|
|
$
|
649,703
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures:
|
|
$
|
4,018
|
|
|
$
|
616
|
|
|
$
|
1,323
|
|
|
$
|
3
|
|
|
$
|
—
|
|
|
$
|
5,960
|
|
_______________________
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. During the Successor Period of 2020, we recorded non-cash ceiling test write-downs on our oil and natural gas properties of $26.1 million pre-tax.
3.Oil and natural gas assets include oil and natural gas properties, saltwater disposal systems, and other non-full cost pool assets.
4.Identifiable assets are those used in Unit’s operations in each industry segment.
5.Other corporate assets are principally cash and cash equivalents, short-term investments, transportation equipment, furniture, and equipment.
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Predecessor
|
|
|
|
Eight Months Ended August 31, 2020
|
|
|
|
Oil and Natural Gas
|
|
Contract Drilling
|
|
Mid-stream
|
|
Corporate and Other
|
|
Eliminations
|
|
Total Consolidated
|
|
|
|
(In thousands)
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas
|
|
$
|
103,443
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(4)
|
|
|
$
|
103,439
|
|
|
Contract drilling
|
|
—
|
|
|
73,519
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
73,519
|
|
|
Gas gathering and processing
|
|
—
|
|
|
—
|
|
|
114,531
|
|
|
—
|
|
|
(14,532)
|
|
|
99,999
|
|
|
Total revenues (1)
|
|
103,443
|
|
|
73,519
|
|
|
114,531
|
|
|
—
|
|
|
(14,536)
|
|
|
276,957
|
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas
|
|
119,664
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1,973)
|
|
|
117,691
|
|
|
Contract drilling
|
|
—
|
|
|
51,811
|
|
|
—
|
|
|
—
|
|
|
(1)
|
|
|
51,810
|
|
|
Gas gathering and processing
|
|
—
|
|
|
—
|
|
|
80,607
|
|
|
—
|
|
|
(12,562)
|
|
|
68,045
|
|
|
Total operating costs
|
|
119,664
|
|
|
51,811
|
|
|
80,607
|
|
|
—
|
|
|
(14,536)
|
|
|
237,546
|
|
|
Depreciation, depletion, and amortization
|
|
68,762
|
|
|
15,544
|
|
|
29,371
|
|
|
1,819
|
|
|
—
|
|
|
115,496
|
|
|
Impairments (2)
|
|
393,726
|
|
|
410,126
|
|
|
63,962
|
|
|
—
|
|
|
—
|
|
|
867,814
|
|
|
Total expenses
|
|
582,152
|
|
|
477,481
|
|
|
173,940
|
|
|
1,819
|
|
|
(14,536)
|
|
|
1,220,856
|
|
|
Loss on abandonment of assets
|
|
17,641
|
|
|
1,092
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
18,733
|
|
|
General and administrative
|
|
—
|
|
|
—
|
|
|
—
|
|
|
42,766
|
|
|
—
|
|
|
42,766
|
|
|
(Gain) loss on disposition of assets
|
|
(160)
|
|
|
(1,390)
|
|
|
(18)
|
|
|
1,479
|
|
|
—
|
|
|
(89)
|
|
|
Loss from operations
|
|
(496,190)
|
|
|
(403,664)
|
|
|
(59,391)
|
|
|
(46,064)
|
|
|
—
|
|
|
(1,005,309)
|
|
|
Loss on derivatives
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(10,704)
|
|
|
—
|
|
|
(10,704)
|
|
|
Write-off of debt issuance costs
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(2,426)
|
|
|
—
|
|
|
(2,426)
|
|
|
Reorganization items, net
|
|
15,504
|
|
|
(183,664)
|
|
|
(71,016)
|
|
|
373,151
|
|
|
—
|
|
|
133,975
|
|
|
Interest, net
|
|
—
|
|
|
—
|
|
|
(1,888)
|
|
|
(20,936)
|
|
|
—
|
|
|
(22,824)
|
|
|
Other
|
|
458
|
|
|
1,449
|
|
|
50
|
|
|
77
|
|
|
—
|
|
|
2,034
|
|
|
Income (loss) before income taxes
|
|
$
|
(480,228)
|
|
|
$
|
(585,879)
|
|
|
$
|
(132,245)
|
|
|
$
|
293,098
|
|
|
$
|
—
|
|
|
$
|
(905,254)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures:
|
|
$
|
5,350
|
|
|
$
|
2,438
|
|
|
$
|
9,342
|
|
|
$
|
83
|
|
|
$
|
—
|
|
|
$
|
17,213
|
|
_______________________ ____________________
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.During the Predecessor Period of 2020, we recorded non-cash ceiling test write-downs on our oil and natural gas properties of $393.7 million, pre-tax ($346.6 million, net of tax). Impairment for contract drilling equipment includes a $410.1 million pre-tax write-down for SCR drilling rigs and other drilling equipment. Impairment for mid-stream assets includes a $64.0 million pre-tax write-down for certain long-lived asset groups.
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Predecessor
|
|
|
|
Year Ended December 31, 2019
|
|
|
|
Oil and Natural Gas
|
|
Contract Drilling
|
|
Mid-stream
|
|
Other
|
|
Eliminations
|
|
Total Consolidated
|
|
|
|
(In thousands)
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas
|
|
$
|
325,797
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
325,797
|
|
|
Contract drilling
|
|
—
|
|
|
184,192
|
|
|
—
|
|
|
—
|
|
|
(15,809)
|
|
|
168,383
|
|
|
Gas gathering and processing
|
|
—
|
|
|
—
|
|
|
227,939
|
|
|
—
|
|
|
(47,485)
|
|
|
180,454
|
|
|
Total revenues (1)
|
|
325,797
|
|
|
184,192
|
|
|
227,939
|
|
|
—
|
|
|
(63,294)
|
|
|
674,634
|
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas
|
|
140,026
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(4,902)
|
|
|
135,124
|
|
|
Contract drilling
|
|
—
|
|
|
130,188
|
|
|
—
|
|
|
—
|
|
|
(14,190)
|
|
|
115,998
|
|
|
Gas gathering and processing
|
|
—
|
|
|
—
|
|
|
176,189
|
|
|
—
|
|
|
(42,583)
|
|
|
133,606
|
|
|
Total operating costs
|
|
140,026
|
|
|
130,188
|
|
|
176,189
|
|
|
—
|
|
|
(61,675)
|
|
|
384,728
|
|
|
Depreciation, depletion, and amortization
|
|
168,651
|
|
|
51,552
|
|
|
47,663
|
|
|
7,707
|
|
|
—
|
|
|
275,573
|
|
|
Impairments (2)
|
|
559,867
|
|
|
62,809
|
|
|
3,040
|
|
|
—
|
|
|
—
|
|
|
625,716
|
|
|
Total expenses
|
|
868,544
|
|
|
244,549
|
|
226,892
|
|
7,707
|
|
|
(61,675)
|
|
|
1,286,017
|
|
|
General and administrative
|
|
—
|
|
|
—
|
|
|
—
|
|
|
38,246
|
|
|
—
|
|
|
38,246
|
|
|
(Gain) loss on disposition of assets
|
|
(199)
|
|
|
3,872
|
|
|
(160)
|
|
|
(11)
|
|
|
—
|
|
|
3,502
|
|
|
Income (loss) from operations
|
|
(542,548)
|
|
|
(64,229)
|
|
|
1,207
|
|
|
(45,942)
|
|
|
(1,619)
|
|
|
(653,131)
|
|
|
Gain on derivatives
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4,225
|
|
|
—
|
|
|
4,225
|
|
|
Interest expense, net
|
|
—
|
|
|
—
|
|
|
(1,546)
|
|
|
(35,466)
|
|
|
—
|
|
|
(37,012)
|
|
|
Other
|
|
(481)
|
|
|
(605)
|
|
|
827
|
|
|
23
|
|
|
—
|
|
|
(236)
|
|
|
Income (loss) before income taxes
|
|
$
|
(543,029)
|
|
|
$
|
(64,834)
|
|
|
$
|
488
|
|
|
$
|
(77,160)
|
|
|
$
|
(1,619)
|
|
|
$
|
(686,154)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Identifiable assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas (3)
|
|
851,662
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(4,264)
|
|
|
847,398
|
|
|
Contract drilling
|
|
—
|
|
|
708,510
|
|
|
—
|
|
|
—
|
|
|
(42)
|
|
|
708,468
|
|
|
Gas gathering and processing
|
|
—
|
|
|
—
|
|
|
463,699
|
|
|
—
|
|
|
(4,255)
|
|
|
459,444
|
|
|
Total identifiable assets (4)
|
|
851,662
|
|
|
708,510
|
|
|
463,699
|
|
|
—
|
|
|
(8,561)
|
|
|
2,015,310
|
|
|
Corporate land and building
|
|
—
|
|
|
—
|
|
|
—
|
|
|
54,155
|
|
|
—
|
|
|
54,155
|
|
|
Other corporate assets (5)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
23,092
|
|
|
(2,505)
|
|
|
20,587
|
|
|
Total assets
|
|
$
|
851,662
|
|
|
$
|
708,510
|
|
|
$
|
463,699
|
|
|
$
|
77,247
|
|
|
$
|
(11,066)
|
|
|
$
|
2,090,052
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures:
|
|
$
|
268,622
|
|
|
$
|
40,636
|
|
|
$
|
64,438
|
|
|
$
|
673
|
|
|
$
|
—
|
|
|
$
|
374,369
|
|
_______________________
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.We incurred non-cash ceiling test write-downs of our oil and natural gas properties of $559.4 million pre-tax ($422.4 million, net of tax). We also recognized goodwill impairment charges of $62.8 million pre-tax ($59.8 million, net of tax).
3.Oil and natural gas assets include oil and natural gas properties, saltwater disposal systems, and other non-full cost pool assets.
4.Identifiable assets are those used in Unit’s operations in each industry segment.
5.Other corporate assets are principally cash and cash equivalents, short-term investments, transportation equipment, furniture, and equipment.
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
NOTE 21 – SELECTED QUARTERLY FINANCIAL INFORMATION
Summarized unaudited quarterly financial information is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First
Quarter
|
|
Second
Quarter
|
|
Third
Quarter (1)
|
|
Fourth
Quarter
|
|
|
|
(In thousands except per share amounts)
|
|
|
2020 (Successor)
|
|
|
|
|
|
|
|
|
|
Revenues
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
32,846
|
|
|
$
|
100,682
|
|
|
|
Gross income (loss) (2)
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(7,373)
|
|
|
$
|
5,599
|
|
|
|
Net loss attributable to Unit Corporation
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(8,968)
|
|
(3)
|
$
|
(9,172)
|
|
(4)
|
|
Net loss attributable to Unit Corporation per common share:
|
|
|
|
|
|
|
|
|
|
Basic
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(0.75)
|
|
|
$
|
(0.76)
|
|
|
|
Diluted
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(0.75)
|
|
|
$
|
(0.76)
|
|
|
|
2020 (Predecessor)
|
|
|
|
|
|
|
|
|
|
Revenues
|
$
|
122,376
|
|
|
$
|
89,007
|
|
|
$
|
65,574
|
|
|
$
|
—
|
|
|
|
Gross loss(2)
|
$
|
(764,888)
|
|
|
$
|
(171,374)
|
|
|
$
|
(7,637)
|
|
|
$
|
—
|
|
|
|
Net income (loss) attributable to Unit Corporation
|
$
|
(770,494)
|
|
(5)
|
$
|
(215,649)
|
|
(6)
|
$
|
55,131
|
|
(7)
|
$
|
—
|
|
|
|
Net income (loss) attributable to Unit Corporation per common share:
|
|
|
|
|
|
|
|
|
|
Basic
|
$
|
(14.50)
|
|
|
$
|
(4.03)
|
|
|
$
|
1.03
|
|
|
$
|
—
|
|
|
|
Diluted
|
$
|
(14.50)
|
|
|
$
|
(4.03)
|
|
|
$
|
1.03
|
|
|
$
|
—
|
|
|
|
2019 (Predecessor)
|
|
|
|
|
|
|
|
|
|
Revenues
|
$
|
189,691
|
|
|
$
|
165,146
|
|
|
$
|
155,439
|
|
|
$
|
164,358
|
|
|
|
Gross income (loss) (2)
|
$
|
24,095
|
|
|
$
|
813
|
|
|
$
|
(242,308)
|
|
|
$
|
(393,983)
|
|
|
|
Net loss attributable to Unit Corporation
|
$
|
(3,504)
|
|
|
$
|
(8,509)
|
|
|
$
|
(206,886)
|
|
(8)
|
$
|
(334,980)
|
|
(9)
|
|
Net loss attributable to Unit Corporation per common share:
|
|
|
|
|
|
|
|
|
|
Basic
|
$
|
(0.07)
|
|
|
$
|
(0.16)
|
|
|
$
|
(3.91)
|
|
|
$
|
(6.33)
|
|
|
|
Diluted
|
$
|
(0.07)
|
|
|
$
|
(0.16)
|
|
|
$
|
(3.91)
|
|
|
$
|
(6.33)
|
|
|
_________________________
1.Third quarter for the 2020 Predecessor Period is for the period July 1, 2020 through August 31, 2020. Third quarter for the 2020 Successor Period is the period September 1, 2020 through September 30, 2020.
2.Gross income (loss) excludes general and administrative expense, interest expense, (gain) loss on disposition of assets, loss on abandonment of assets, gain (loss) on derivatives, reorganization items, net, income taxes, and other income (loss).
3.During the one-month Successor Period for the third quarter of 2020, we recorded a non-cash ceiling test write-down of $13.2 million pre-tax.
4.During the fourth quarter of 2020, we recorded a non-cash ceiling test write-down of $12.9 million pre-tax.
5.During the first quarter of 2020, we recorded a non-cash ceiling test write-down of $267.8 million pre-tax ($220.8 million, net of tax). We also recorded total expense of $17.6 million related to the abandonment of salt water disposal assets, $407.1 million related to the write-down of the SCR drilling rigs, $3.0 million related to the write-down of other miscellaneous drilling equipment, and $64.0 million related to the write-down of mid-stream assets.
6.During the second quarter of 2020, we recorded a non-cash ceiling test write-down of $109.3 million pre-tax.
7.During the two months ended August 31, 2020, we recorded a non-cash test write-down of $16.6 million pre-tax and $1.2 million related to the abandonment of other miscellaneous drilling equipment. We also recorded $141.0 million gain in reorganization items, net.
8.During the third quarter of 2019, we recorded a non-cash ceiling test write-down of $169.3 million pre-tax ($127.9 million, net of tax). We also recognized goodwill impairment charges of $62.8 million, pre-tax ($59.8 million, net of tax).
9.During the fourth quarter of 2019, we recorded a non-cash ceiling test write-down of $390.1 million pre-tax ($294.5 million, net of tax).
NOTE 22 – 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 to Rule 3-10 of the SEC's Regulation S-X, Financial Statements of Guarantors and Issuers of Guaranteed Securities Registered
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
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, 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 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 Balances Sheets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Predecessor
|
|
|
December 31, 2019
|
|
|
Parent
|
|
Combined Guarantor Subsidiaries
|
|
Combined Non-Guarantor Subsidiaries
|
|
Consolidating Adjustments
|
|
Total Consolidated
|
|
|
(In thousands)
|
|
ASSETS
|
|
|
|
|
|
|
|
|
|
|
Current assets:
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
$
|
503
|
|
|
$
|
68
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
571
|
|
|
Accounts receivable, net of allowance for doubtful accounts of $2,332 (Guarantor of $1,116 and Parent of $1,216)
|
2,645
|
|
|
64,805
|
|
|
24,653
|
|
|
(9,447)
|
|
|
82,656
|
|
|
Materials and supplies
|
—
|
|
|
449
|
|
|
—
|
|
|
—
|
|
|
449
|
|
|
Current derivative asset
|
633
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
633
|
|
|
Income tax receivable
|
1,756
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,756
|
|
|
Assets held for sale
|
—
|
|
|
5,908
|
|
|
—
|
|
|
—
|
|
|
5,908
|
|
|
Prepaid expenses and other
|
2,019
|
|
|
3,373
|
|
|
7,686
|
|
|
—
|
|
|
13,078
|
|
|
Total current assets
|
7,556
|
|
|
74,603
|
|
|
32,339
|
|
|
(9,447)
|
|
|
105,051
|
|
|
Property and equipment:
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas properties on the full cost method:
|
|
|
|
|
|
|
|
|
|
|
Proved properties
|
—
|
|
|
6,341,582
|
|
|
—
|
|
|
—
|
|
|
6,341,582
|
|
|
Unproved properties not being amortized
|
—
|
|
|
252,874
|
|
|
—
|
|
|
—
|
|
|
252,874
|
|
|
Drilling equipment
|
—
|
|
|
1,295,713
|
|
|
—
|
|
|
—
|
|
|
1,295,713
|
|
|
Gas gathering and processing equipment
|
—
|
|
|
—
|
|
|
824,699
|
|
|
—
|
|
|
824,699
|
|
|
Saltwater disposal systems
|
—
|
|
|
69,692
|
|
|
—
|
|
|
—
|
|
|
69,692
|
|
|
Corporate land and building
|
—
|
|
|
59,080
|
|
|
—
|
|
|
—
|
|
|
59,080
|
|
|
Transportation equipment
|
9,712
|
|
|
16,621
|
|
|
3,390
|
|
|
—
|
|
|
29,723
|
|
|
Other
|
28,927
|
|
|
29,065
|
|
|
—
|
|
|
—
|
|
|
57,992
|
|
|
|
38,639
|
|
|
8,064,627
|
|
|
828,089
|
|
|
—
|
|
|
8,931,355
|
|
|
Less accumulated depreciation, depletion, amortization, and impairment
|
33,794
|
|
|
6,537,731
|
|
|
407,144
|
|
|
—
|
|
|
6,978,669
|
|
|
Net property and equipment
|
4,845
|
|
|
1,526,896
|
|
|
420,945
|
|
|
—
|
|
|
1,952,686
|
|
|
Intercompany receivable
|
1,048,785
|
|
|
—
|
|
|
—
|
|
|
(1,048,785)
|
|
|
—
|
|
|
Investments
|
865,252
|
|
|
—
|
|
|
—
|
|
|
(865,252)
|
|
|
—
|
|
|
Right of use asset
|
46
|
|
|
1,733
|
|
|
3,948
|
|
|
(54)
|
|
|
5,673
|
|
|
Other assets
|
8,107
|
|
|
9,094
|
|
|
9,441
|
|
|
—
|
|
|
26,642
|
|
|
Total assets
|
$
|
1,934,591
|
|
|
$
|
1,612,326
|
|
|
$
|
466,673
|
|
|
$
|
(1,923,538)
|
|
|
$
|
2,090,052
|
|
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Predecessor
|
|
|
December 31, 2019
|
|
|
Parent
|
|
Combined Guarantor Subsidiaries
|
|
Combined Non-Guarantor Subsidiaries
|
|
Consolidating Adjustments
|
|
Total Consolidated
|
|
|
(In thousands)
|
|
LIABILITIES AND SHAREHOLDERS’ EQUITY
|
|
|
|
|
|
|
|
|
|
|
Current liabilities:
|
|
|
|
|
|
|
|
|
|
|
Accounts payable
|
$
|
12,259
|
|
|
$
|
61,002
|
|
|
$
|
18,511
|
|
|
$
|
(7,291)
|
|
|
$
|
84,481
|
|
|
Accrued liabilities
|
28,003
|
|
|
14,024
|
|
|
6,691
|
|
|
(2,156)
|
|
|
46,562
|
|
|
Current operating lease liability
|
20
|
|
|
1,009
|
|
|
2,407
|
|
|
(6)
|
|
|
3,430
|
|
|
Current portion of long-term debt
|
108,200
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
108,200
|
|
|
Current portion of other long-term liabilities
|
3,003
|
|
|
7,313
|
|
|
7,060
|
|
|
—
|
|
|
17,376
|
|
|
Total current liabilities
|
151,485
|
|
|
83,348
|
|
|
34,669
|
|
|
(9,453)
|
|
|
260,049
|
|
|
Intercompany debt
|
—
|
|
|
1,047,599
|
|
|
1,186
|
|
|
(1,048,785)
|
|
|
—
|
|
|
Long-term debt less debt issuance costs
|
646,716
|
|
|
—
|
|
|
16,500
|
|
|
—
|
|
|
663,216
|
|
|
Non-current derivative liability
|
27
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
27
|
|
|
Operating lease liability
|
25
|
|
|
690
|
|
|
1,404
|
|
|
(48)
|
|
|
2,071
|
|
|
Other long-term liabilities
|
12,553
|
|
|
74,662
|
|
|
8,126
|
|
|
—
|
|
|
95,341
|
|
|
Deferred income taxes
|
68,150
|
|
|
(54,437)
|
|
|
—
|
|
|
—
|
|
|
13,713
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total shareholders' equity
|
1,055,635
|
|
|
460,464
|
|
|
404,788
|
|
|
(865,252)
|
|
|
1,055,635
|
|
|
Total liabilities and shareholders’ equity
|
$
|
1,934,591
|
|
|
$
|
1,612,326
|
|
|
$
|
466,673
|
|
|
$
|
(1,923,538)
|
|
|
$
|
2,090,052
|
|
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
Condensed Consolidating Statements of Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Predecessor
|
|
|
Eight Months Ended August 31, 2020
|
|
|
Parent
|
|
Combined Guarantor Subsidiaries
|
|
Combined Non-Guarantor Subsidiaries
|
|
Consolidating Adjustments
|
|
Total Consolidated
|
|
|
(In thousands)
|
|
Revenues
|
$
|
—
|
|
|
$
|
176,962
|
|
|
$
|
114,531
|
|
|
$
|
(14,536)
|
|
|
$
|
276,957
|
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
Operating costs
|
—
|
|
|
171,476
|
|
|
80,607
|
|
|
(14,537)
|
|
|
237,546
|
|
|
Depreciation, depletion, and amortization
|
1,819
|
|
|
84,306
|
|
|
29,371
|
|
|
—
|
|
|
115,496
|
|
|
Impairments
|
—
|
|
|
803,852
|
|
|
63,962
|
|
|
—
|
|
|
867,814
|
|
|
Loss on abandonment of assets
|
—
|
|
|
18,733
|
|
|
—
|
|
|
—
|
|
|
18,733
|
|
|
General and administrative
|
—
|
|
|
42,766
|
|
|
—
|
|
|
—
|
|
|
42,766
|
|
|
(Gain) loss on disposition of assets
|
1,479
|
|
|
(1,550)
|
|
|
(18)
|
|
|
—
|
|
|
(89)
|
|
|
Total operating costs
|
3,298
|
|
|
1,119,583
|
|
|
173,922
|
|
|
(14,537)
|
|
|
1,282,266
|
|
|
Income (loss) from operations
|
(3,298)
|
|
|
(942,621)
|
|
|
(59,391)
|
|
|
1
|
|
|
(1,005,309)
|
|
|
Interest, net
|
(20,936)
|
|
|
—
|
|
|
(1,888)
|
|
|
—
|
|
|
(22,824)
|
|
|
Write-off of debt issuance costs
|
(2,426)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(2,426)
|
|
|
Loss on derivatives
|
(10,704)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(10,704)
|
|
|
Reorganization items
|
373,151
|
|
|
(168,160)
|
|
|
(71,016)
|
|
|
—
|
|
|
133,975
|
|
|
Other, net
|
79
|
|
|
1,906
|
|
|
49
|
|
|
—
|
|
|
2,034
|
|
|
Income (loss) before income taxes
|
335,866
|
|
|
(1,108,875)
|
|
|
(132,246)
|
|
|
1
|
|
|
(905,254)
|
|
|
Income tax benefit
|
(14,630)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(14,630)
|
|
|
Equity in net earnings from investment in subsidiaries, net of taxes
|
(1,241,120)
|
|
|
—
|
|
|
—
|
|
|
1,241,120
|
|
|
—
|
|
|
Net loss
|
(890,624)
|
|
|
(1,108,875)
|
|
|
(132,246)
|
|
|
1,241,121
|
|
|
(890,624)
|
|
|
Less: net income attributable to non-controlling interest
|
40,388
|
|
|
—
|
|
|
40,388
|
|
|
(40,388)
|
|
|
40,388
|
|
|
Net loss attributable to Unit Corporation
|
$
|
(931,012)
|
|
|
$
|
(1,108,875)
|
|
|
$
|
(172,634)
|
|
|
$
|
1,281,509
|
|
|
$
|
(931,012)
|
|
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Predecessor
|
|
|
Twelve Months Ended December 31, 2019
|
|
|
Parent
|
|
Combined Guarantor Subsidiaries
|
|
Combined Non-Guarantor Subsidiaries
|
|
Consolidating Adjustments
|
|
Total Consolidated
|
|
|
(In thousands)
|
|
Revenues
|
$
|
—
|
|
|
$
|
494,180
|
|
|
$
|
227,939
|
|
|
$
|
(47,485)
|
|
|
$
|
674,634
|
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
Operating costs
|
—
|
|
|
256,024
|
|
|
176,189
|
|
|
(47,485)
|
|
|
384,728
|
|
|
Depreciation, depletion, and amortization
|
7,707
|
|
|
220,203
|
|
|
47,663
|
|
|
—
|
|
|
275,573
|
|
|
Impairments
|
—
|
|
|
622,676
|
|
|
3,040
|
|
|
—
|
|
|
625,716
|
|
|
General and administrative
|
—
|
|
|
38,246
|
|
|
—
|
|
|
—
|
|
|
38,246
|
|
|
(Gain) loss on disposition of assets
|
(11)
|
|
|
3,673
|
|
|
(160)
|
|
|
—
|
|
|
3,502
|
|
|
Total operating costs
|
7,696
|
|
|
1,140,822
|
|
|
226,732
|
|
|
(47,485)
|
|
|
1,327,765
|
|
|
Income (loss) from operations
|
(7,696)
|
|
|
(646,642)
|
|
|
1,207
|
|
|
—
|
|
|
(653,131)
|
|
|
Interest, net
|
(35,466)
|
|
|
—
|
|
|
(1,546)
|
|
|
—
|
|
|
(37,012)
|
|
|
Gain on derivatives
|
4,225
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4,225
|
|
|
Other, net
|
786
|
|
|
(1,086)
|
|
|
64
|
|
|
—
|
|
|
(236)
|
|
|
Loss before income taxes
|
(38,151)
|
|
|
(647,728)
|
|
|
(275)
|
|
|
—
|
|
|
(686,154)
|
|
|
Income tax expense (benefit)
|
7,238
|
|
|
(139,564)
|
|
|
—
|
|
|
—
|
|
|
(132,326)
|
|
|
Equity in net earnings from investment in subsidiaries, net of taxes
|
(508,439)
|
|
|
—
|
|
|
—
|
|
|
508,439
|
|
|
—
|
|
|
Net loss
|
(553,828)
|
|
|
(508,164)
|
|
|
(275)
|
|
|
508,439
|
|
|
(553,828)
|
|
|
Less: net income attributable to non-controlling interest
|
51
|
|
|
—
|
|
|
51
|
|
|
(51)
|
|
|
51
|
|
|
Net loss attributable to Unit Corporation
|
$
|
(553,879)
|
|
|
$
|
(508,164)
|
|
|
$
|
(326)
|
|
|
$
|
508,490
|
|
|
$
|
(553,879)
|
|
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
Condensed Consolidating Statements of Comprehensive Income (Loss)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Predecessor
|
|
|
Eight Months Ended August 31, 2020
|
|
|
Parent
|
|
Combined Guarantor Subsidiaries
|
|
Combined Non-Guarantor Subsidiaries
|
|
Consolidating Adjustments
|
|
Total Consolidated
|
|
|
(In thousands)
|
|
Net loss
|
$
|
(890,624)
|
|
|
$
|
(1,108,875)
|
|
|
$
|
(132,246)
|
|
|
$
|
1,241,121
|
|
|
$
|
(890,624)
|
|
|
Other comprehensive loss, net of taxes:
|
|
|
|
|
|
|
|
|
|
|
Unrealized gain on securities, net of tax of $0
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Comprehensive loss
|
(890,624)
|
|
|
(1,108,875)
|
|
|
(132,246)
|
|
|
1,241,121
|
|
|
(890,624)
|
|
|
Less: Comprehensive income attributable to non-controlling interests
|
40,388
|
|
|
—
|
|
|
40,388
|
|
|
(40,388)
|
|
|
40,388
|
|
|
Comprehensive loss attributable to Unit Corporation
|
$
|
(931,012)
|
|
|
$
|
(1,108,875)
|
|
|
$
|
(172,634)
|
|
|
$
|
1,281,509
|
|
|
$
|
(931,012)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Predecessor
|
|
|
Twelve Months Ended December 31, 2019
|
|
|
Parent
|
|
Combined Guarantor Subsidiaries
|
|
Combined Non-Guarantor Subsidiaries
|
|
Consolidating Adjustments
|
|
Total Consolidated
|
|
|
(In thousands)
|
|
Net loss
|
$
|
(553,828)
|
|
|
$
|
(508,164)
|
|
|
$
|
(275)
|
|
|
$
|
508,439
|
|
|
$
|
(553,828)
|
|
|
Other comprehensive loss, net of taxes:
|
|
|
|
|
|
|
|
|
|
|
Reclassification adjustment for write-down of securities, net of tax $(47)
|
—
|
|
|
481
|
|
|
—
|
|
|
—
|
|
|
481
|
|
|
Comprehensive loss
|
(553,828)
|
|
|
(507,683)
|
|
|
(275)
|
|
|
508,439
|
|
|
(553,347)
|
|
|
Less: Comprehensive income attributable to non-controlling interests
|
51
|
|
|
—
|
|
|
51
|
|
|
(51)
|
|
|
51
|
|
|
Comprehensive loss attributable to Unit Corporation
|
$
|
(553,879)
|
|
|
$
|
(507,683)
|
|
|
$
|
(326)
|
|
|
$
|
508,490
|
|
|
$
|
(553,398)
|
|
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
Condensed Consolidating Statements of Cash Flows
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Predecessor
|
|
|
Eight Months Ended August 31, 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
|
$
|
(207,593)
|
|
|
$
|
82,769
|
|
|
$
|
32,922
|
|
|
$
|
136,858
|
|
|
$
|
44,956
|
|
|
INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
(986)
|
|
|
(14,585)
|
|
|
(10,204)
|
|
|
—
|
|
|
(25,775)
|
|
|
Producing properties and other acquisitions
|
—
|
|
|
(382)
|
|
|
—
|
|
|
—
|
|
|
(382)
|
|
|
Proceeds from disposition of assets
|
1,169
|
|
|
4,772
|
|
|
77
|
|
|
—
|
|
|
6,018
|
|
|
Net cash provided by (used in) investing activities
|
183
|
|
|
(10,195)
|
|
|
(10,127)
|
|
|
—
|
|
|
(20,139)
|
|
|
FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
Borrowings under credit agreement, including borrowings under DIP credit facility
|
55,300
|
|
|
—
|
|
|
32,100
|
|
|
—
|
|
|
87,400
|
|
|
Payments under credit agreement
|
(31,500)
|
|
|
—
|
|
|
(32,600)
|
|
|
—
|
|
|
(64,100)
|
|
|
DIP financing costs
|
(990)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(990)
|
|
|
Exit facility financing costs
|
(3,225)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(3,225)
|
|
|
Intercompany borrowings (advances), net
|
210,398
|
|
|
(72,642)
|
|
|
(898)
|
|
|
(136,858)
|
|
|
—
|
|
|
Payments on finance leases
|
—
|
|
|
—
|
|
|
(2,757)
|
|
|
—
|
|
|
(2,757)
|
|
|
Employee taxes paid by withholding shares
|
(43)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(43)
|
|
|
Bank overdrafts
|
(7,269)
|
|
|
—
|
|
|
(1,464)
|
|
|
—
|
|
|
(8,733)
|
|
|
Net cash provided by (used in) financing activities
|
222,671
|
|
|
(72,642)
|
|
|
(5,619)
|
|
|
(136,858)
|
|
|
7,552
|
|
|
Net increase (decrease) in cash and cash equivalents
|
15,261
|
|
|
(68)
|
|
|
17,176
|
|
|
—
|
|
|
32,369
|
|
|
Cash and cash equivalents, beginning of period
|
503
|
|
|
68
|
|
|
—
|
|
|
—
|
|
|
571
|
|
|
Cash and cash equivalents, end of period
|
$
|
15,764
|
|
|
$
|
—
|
|
|
$
|
17,176
|
|
|
$
|
—
|
|
|
$
|
32,940
|
|
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Predecessor
|
|
|
Twelve Months Ended December 31, 2019
|
|
|
Parent
|
|
Combined Guarantor Subsidiaries
|
|
Combined Non-Guarantor Subsidiaries
|
|
Consolidating Adjustments
|
|
Total Consolidated
|
|
|
(In thousands)
|
|
OPERATING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) operating activities
|
$
|
(9,681)
|
|
|
$
|
217,883
|
|
|
$
|
48,856
|
|
|
$
|
12,338
|
|
|
$
|
269,396
|
|
|
INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
65
|
|
|
(355,258)
|
|
|
(51,472)
|
|
|
—
|
|
|
(406,665)
|
|
|
Producing properties and other acquisitions
|
—
|
|
|
(3,653)
|
|
|
—
|
|
|
—
|
|
|
(3,653)
|
|
|
Other acquisitions
|
—
|
|
|
—
|
|
|
(16,109)
|
|
|
—
|
|
|
(16,109)
|
|
|
Proceeds from disposition of assets
|
11
|
|
|
31,153
|
|
|
700
|
|
|
—
|
|
|
31,864
|
|
|
Net cash provided by (used in) investing activities
|
76
|
|
|
(327,758)
|
|
|
(66,881)
|
|
|
—
|
|
|
(394,563)
|
|
|
FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
Borrowings under credit agreement
|
400,600
|
|
|
—
|
|
|
92,900
|
|
|
—
|
|
|
493,500
|
|
|
Payments under credit agreement
|
(292,400)
|
|
|
—
|
|
|
(76,400)
|
|
|
—
|
|
|
(368,800)
|
|
|
Intercompany borrowings (advances), net
|
(97,455)
|
|
|
109,735
|
|
|
58
|
|
|
(12,338)
|
|
|
—
|
|
|
Payments on finance leases
|
—
|
|
|
—
|
|
|
(4,001)
|
|
|
—
|
|
|
(4,001)
|
|
|
Employee taxes paid by withholding shares
|
(4,158)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(4,158)
|
|
|
Distributions to non-controlling interest
|
919
|
|
|
—
|
|
|
(1,837)
|
|
|
—
|
|
|
(918)
|
|
|
Bank overdrafts
|
2,199
|
|
|
—
|
|
|
1,464
|
|
|
—
|
|
|
3,663
|
|
|
Net cash provided by (used in) financing activities
|
9,705
|
|
|
109,735
|
|
|
12,184
|
|
|
(12,338)
|
|
|
119,286
|
|
|
Net increase (decrease) in cash and cash equivalents
|
100
|
|
|
(140)
|
|
|
(5,841)
|
|
|
—
|
|
|
(5,881)
|
|
|
Cash and cash equivalents, beginning of period
|
403
|
|
|
208
|
|
|
5,841
|
|
|
—
|
|
|
6,452
|
|
|
Cash and cash equivalents, end of period
|
$
|
503
|
|
|
$
|
68
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
571
|
|
SUPPLEMENTAL OIL AND GAS DISCLOSURES
(UNAUDITED)
The supplemental data presented herein reflects information for all our oil and natural gas producing activities. Our oil and gas operations are substantially located in the United States.
Capitalized Costs
The capitalized costs at year end were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
2020
|
|
|
2019
|
|
|
(In thousands)
|
|
Proved properties
|
$
|
238,581
|
|
|
|
$
|
6,341,582
|
|
|
Unproved properties (wells in progress)
|
1,591
|
|
|
|
252,874
|
|
|
|
240,172
|
|
|
|
6,594,456
|
|
|
Accumulated depreciation, depletion, amortization, and impairment
|
(40,806)
|
|
|
|
(5,846,177)
|
|
|
Net capitalized costs
|
$
|
199,366
|
|
|
|
$
|
748,279
|
|
Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration, and Development Activities
The following table sets forth costs incurred related to our oil and natural gas activities for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
|
|
|
|
|
(In thousands)
|
|
Unproved properties acquired
|
$
|
26
|
|
|
|
$
|
2,373
|
|
|
$
|
34,668
|
|
|
|
|
Proved properties acquired
|
—
|
|
|
|
382
|
|
|
3,653
|
|
|
|
|
Exploration
|
—
|
|
|
|
—
|
|
|
16,480
|
|
|
|
|
Development
|
3,992
|
|
|
|
6,440
|
|
|
211,443
|
|
|
|
|
Asset retirement obligation
|
(1,702)
|
|
|
|
(29,189)
|
|
|
76
|
|
|
|
|
Total costs incurred
|
$
|
2,316
|
|
|
|
$
|
(19,994)
|
|
|
$
|
266,320
|
|
|
|
Unproved properties not subject to amortization relates to properties which are not individually significant and consist primarily of lease acquisition costs. The evaluation process associated with these properties has not been completed and therefore, the company is unable to estimate when these costs will be included in the amortization calculation.
The results of operations for producing activities are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
|
|
|
|
|
(In thousands)
|
|
Revenues
|
$
|
55,272
|
|
|
|
$
|
96,033
|
|
|
$
|
314,925
|
|
|
|
|
Production costs
|
(20,510)
|
|
|
|
(46,633)
|
|
|
(116,051)
|
|
|
|
|
Depreciation, depletion, amortization, and impairment
|
(40,840)
|
|
|
|
(461,901)
|
|
|
(727,529)
|
|
|
|
|
|
(6,078)
|
|
|
|
(412,501)
|
|
|
(528,655)
|
|
|
|
|
Income tax (expense) benefit
|
128
|
|
|
|
6,698
|
|
|
101,952
|
|
|
|
|
Results of operations for producing activities (excluding corporate overhead and financing costs)
|
$
|
(5,950)
|
|
|
|
$
|
(405,803)
|
|
|
$
|
(426,703)
|
|
|
|
Estimated quantities of proved developed oil, NGLs, and natural gas reserves and changes in net quantities of proved developed and undeveloped oil, NGLs, and natural gas reserves were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
Bbls
|
|
NGLs
Bbls
|
|
Natural Gas
Mcf
|
|
Total
MBoe
|
|
|
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2019
|
|
|
|
|
|
|
|
|
Proved developed and undeveloped reserves:
|
|
|
|
|
|
|
|
|
Beginning of year
|
22,558
|
|
|
47,796
|
|
|
535,963
|
|
|
159,681
|
|
|
Revision of previous estimates (1)
|
(8,263)
|
|
|
(20,961)
|
|
|
(234,852)
|
|
|
(68,366)
|
|
|
Extensions and discoveries (1)
|
703
|
|
|
845
|
|
|
8,798
|
|
|
3,015
|
|
|
Infill reserves in existing proved fields
|
271
|
|
|
434
|
|
|
4,806
|
|
|
1,506
|
|
|
Purchases of minerals in place
|
183
|
|
|
101
|
|
|
1,316
|
|
|
503
|
|
|
Production
|
(3,208)
|
|
|
(4,773)
|
|
|
(53,064)
|
|
|
(16,825)
|
|
|
Sales
|
(48)
|
|
|
(412)
|
|
|
(42,780)
|
|
|
(7,590)
|
|
|
Net proved reserves at December 31, 2019
|
12,196
|
|
|
23,030
|
|
|
220,187
|
|
|
71,924
|
|
|
Proved developed reserves, December 31, 2019
|
12,196
|
|
|
23,030
|
|
|
220,187
|
|
|
71,924
|
|
|
Proved undeveloped reserves, December 31, 2019
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2020
|
|
|
|
|
|
|
|
|
Proved developed and undeveloped reserves:
|
|
|
|
|
|
|
|
|
Beginning of year
|
12,196
|
|
|
23,030
|
|
|
220,187
|
|
|
71,924
|
|
|
Revision of previous estimates
|
(1,909)
|
|
|
(4,477)
|
|
|
(38,901)
|
|
|
(12,870)
|
|
|
Extensions and discoveries
|
8
|
|
|
13
|
|
|
110
|
|
|
39
|
|
|
Infill reserves in existing proved fields
|
97
|
|
|
66
|
|
|
452
|
|
|
238
|
|
|
Purchases of minerals in place
|
62
|
|
|
20
|
|
|
172
|
|
|
112
|
|
|
Production
|
(2,186)
|
|
|
(3,444)
|
|
|
(37,567)
|
|
|
(11,891)
|
|
|
Sales
|
(1)
|
|
|
—
|
|
|
(62)
|
|
|
(11)
|
|
|
Net proved reserves at December 31, 2020
|
8,267
|
|
|
15,208
|
|
|
144,391
|
|
|
47,541
|
|
|
Proved developed reserves, December 31, 2020
|
8,267
|
|
|
15,208
|
|
|
144,391
|
|
|
47,541
|
|
|
Proved undeveloped reserves, December 31, 2020
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
_________________________
1.Revisions of previous estimates and extensions and discoveries decreased primarily due to the removal of proved undeveloped reserves due to uncertainty regarding our ability to finance the development of our proved undeveloped reserves over a five-year period and from lower commodity prices.
Estimates of oil, NGLs, and natural gas reserves require extensive judgments of reservoir engineering data. Assigning monetary values to such estimates does not reduce the subjectivity and changing nature of such reserve estimates. Indeed, the uncertainties inherent in the disclosure are compounded by applying additional estimates of the rates and timing of production and the costs that will be incurred in developing and producing the reserves. The information set forth in this report is, therefore, subjective and, since judgments are involved, may not be comparable to estimates submitted by other oil and natural gas producers. In addition, since prices and costs do not remain static, and no price or cost escalations or de-escalations have been considered, the results are not necessarily indicative of the estimated fair market value of estimated proved reserves, nor of estimated future cash flows.
The standardized measure of discounted future net cash flows (SMOG) was calculated using 12-month average prices and year end costs adjusted for permanent differences that relate to existing proved oil, NGLs, and natural gas reserves. Future income tax expenses consider the Tax Act statutory tax rates. SMOG as of December 31 is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
2020
|
|
|
2019
|
|
|
|
|
(In thousands)
|
|
Future cash flows
|
$
|
698,685
|
|
|
|
$
|
1,386,777
|
|
|
|
|
Future production costs
|
(416,095)
|
|
|
|
(698,357)
|
|
|
|
|
Future development costs
|
—
|
|
|
|
—
|
|
|
|
|
Future income tax expenses
|
(39)
|
|
|
|
(321)
|
|
|
|
|
Future net cash flows
|
282,551
|
|
|
|
688,099
|
|
|
|
|
10% annual discount for estimated timing of cash flows
|
(89,530)
|
|
|
|
(226,390)
|
|
|
|
|
Standardized measure of discounted future net cash flows relating to proved oil, NGLs, and natural gas reserves
|
$
|
193,021
|
|
|
|
$
|
461,709
|
|
|
|
The principal sources of changes in the standardized measure of discounted future net cash flows were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2020
|
|
2019
|
|
|
|
|
|
|
Sales and transfers of oil and natural gas produced, net of production costs
|
$
|
(84,163)
|
|
|
$
|
(200,233)
|
|
|
|
|
Net changes in prices and production costs
|
(165,978)
|
|
|
(508,066)
|
|
|
|
|
Revisions in quantity estimates and changes in production timing
|
(50,979)
|
|
|
(338,994)
|
|
|
|
|
Extensions, discoveries, and improved recovery, less related costs
|
2,827
|
|
|
53,123
|
|
|
|
|
Changes in estimated future development costs
|
—
|
|
|
311,190
|
|
|
|
|
Previously estimated cost incurred during the period
|
—
|
|
|
64,362
|
|
|
|
|
Purchases of minerals in place
|
852
|
|
|
6,416
|
|
|
|
|
Sales of minerals in place
|
(46)
|
|
|
(25,813)
|
|
|
|
|
Accretion of discount
|
46,203
|
|
|
110,571
|
|
|
|
|
Net change in income taxes
|
282
|
|
|
121,708
|
|
|
|
|
Changes in timing and other
|
(17,686)
|
|
|
(116,233)
|
|
|
|
|
Net change
|
(268,688)
|
|
|
(521,969)
|
|
|
|
|
Beginning of year
|
461,709
|
|
|
983,678
|
|
|
|
|
End of year
|
$
|
193,021
|
|
|
$
|
461,709
|
|
|
|
Certain information concerning the assumptions used in computing SMOG and their inherent limitations are discussed below. We believe this information is essential for a proper understanding and assessment of the data presented.
The assumptions used to compute SMOG do not necessarily reflect our expectations of actual revenues to be derived from neither those reserves nor their present worth. Assigning monetary values to the reserve quantity estimation process does not reduce the subjective and ever-changing nature of reserve estimates. Additional subjectivity occurs when determining present values because the rate of producing the reserves must be estimated. In addition to difficulty inherent in predicting the future, variations from the expected production rate could result from factors outside of our control, such as unintentional delays in development, environmental concerns or changes in prices or regulatory controls. Also, the reserve valuation assumes that all reserves will be disposed of by production. However, other factors such as the sale of reserves in place could affect the amount of cash eventually realized.
The December 31, 2020, future cash flows were computed by applying the unescalated 12-month average prices of $39.57 per barrel for oil, $18.70 per barrel for NGLs, and $1.98 per Mcf for natural gas (then adjusted for price differentials) relating to proved reserves and to the year-end quantities of those reserves. Future price changes are considered only to the extent provided by contractual arrangements in existence at year-end.
Future production and development costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil, NGLs, and natural gas reserves at the end of the year, based on continuation of existing economic conditions.
Future income tax expenses are computed by applying the appropriate year-end statutory tax rates to the future pretax net cash flows relating to proved oil, NGLs, and natural gas reserves less the tax basis of our properties. The future income tax expenses also give effect to permanent differences and tax credits and allowances relating to our proved oil, NGLs, and natural gas reserves.
Care should be exercised in the use and interpretation of the above data. As production occurs over the next several years, the results shown may be significantly different as changes in production performance, petroleum prices and costs are likely to occur.