NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 – ORGANIZATION AND BUSINESS
Unless the context clearly indicates otherwise, references in this report to “Unit”, “company”, “we”, “our”, “us”, or like terms refer to Unit Corporation or, as appropriate, one or more of its subsidiaries. References to our mid-stream segment refers to Superior Pipeline Company, L.L.C. (Superior) of which we own 50%.
We are primarily engaged in the development, acquisition, and production of oil and natural gas properties, the land contract drilling of natural gas and oil wells, and the buying, selling, gathering, processing, and treating of natural gas. Our operations are all in the United States and are organized in the following three reporting segments: (1) Oil and Natural Gas, (2) Contract Drilling, and (3) Mid-Stream.
Oil and Natural Gas. Carried out by our subsidiary, Unit Petroleum Company (UPC), we develop, acquire, and produce oil and natural gas properties for our own account. Our producing oil and natural gas properties, unproved properties, and related assets are primarily located in Oklahoma and Texas, and to a lesser extent, in Arkansas, Kansas, Louisiana, Montana, North Dakota, Utah, and Wyoming.
Contract Drilling. Carried out by our subsidiary, Unit Drilling Company (UDC), we drill onshore oil and natural gas wells for a wide range of other oil and natural gas companies as well as for our own account. Our drilling operations are primarily located in Oklahoma, Texas, New Mexico, Wyoming, and North Dakota.
Mid-Stream. Carried out by Superior of which we own 50%, buys, sells, gathers, transports, processes, and treats natural gas for UPC and for third parties. Mid-Stream operations are primarily located in Oklahoma, Texas, Kansas, Pennsylvania, and West Virginia.
NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation
These interim financial statements are unaudited and have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (SEC) regarding interim financial reporting. Certain disclosures have been condensed or omitted from these financial statements. Accordingly, they do not include all of the information and notes required by accounting principles generally accepted in the United States (GAAP) for complete consolidated financial statements, and should be read in conjunction with the audited consolidated financial statements and notes thereto for the year ended December 31, 2021 included in the company’s Annual Report on Form 10-K as filed with the SEC on March 31, 2022.
In the opinion of management, the unaudited condensed consolidated financial statements are fairly stated and contain all normal recurring adjustments (including the elimination of all intercompany transactions). Our financial statements are prepared in conformity with GAAP, which requires us to make certain estimates and assumptions that may affect the amounts reported in our unaudited condensed consolidated financial statements and notes. Actual results may differ from those estimates. The results for interim periods are not necessarily indicative of annual results. The company evaluates subsequent events through the date the financial statements are issued.
The consolidated financial statements include the accounts of Unit Corporation and its subsidiaries. We consolidated the financial position, operating results, and cash flows of Superior prior to March 1, 2022, on which date the Master Services and Operating Agreement (MSA) was amended and restated, with the result that we no longer consolidate Superior's financial position, operating results, and cash flows during periods subsequent to March 1, 2022. Accordingly, the unaudited condensed consolidated financial statements and notes reflect Superior activity on a consolidated basis for the two months prior to March 1, 2022. See Note 15 – Superior Investment for more information on the Superior investment and consolidation conclusions. All intercompany transactions and accounts between consolidated entities have been eliminated, including activity between Unit and Superior during the two months prior to March 1, 2022. Intercompany transactions and accounts between Unit and Superior subsequent to March 1, 2022 are not eliminated.
Certain amounts in this report for prior periods have been reclassified to conform to current year presentation. There was no impact from these reclassifications to consolidated net income/(loss) or shareholders' equity.
Recent Accounting Pronouncements
Reference Rate Reform (Topic 848)—Facilitation of the Effects of Reference Rate Reform on Financial Reporting. The FASB issued ASU 2020-04 and ASU 2021-01 which provide and clarify 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 amendments within these ASUs 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. In April 2022, the FASB proposed to defer the effective date to December 31, 2024, but a final ruling has not been issued. We have not yet elected to use the optional guidance and continue to evaluate the options provided by ASU 2020-04 and ASU 2021-01.
NOTE 3 – REVENUE FROM CONTRACTS WITH CUSTOMERS
Our revenue streams are reported under three segments: oil and natural gas, contract drilling, and mid-stream which is consistent with how we report our segment revenue (as reflected in Note 19 – Industry Segment Information). Revenue from the oil and natural gas segment is from sales of our oil and natural gas production. Revenue from the contract drilling segment comes from contracting with upstream companies to drill an agreed-on number of wells or provide drilling rigs and services over an agreed-on period. Revenues from the mid-stream segment 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.
Oil and Natural Gas Revenue
Typical types of revenue contracts entered into by our oil and gas segment 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 joint operating agreements. Consideration received is variable and settled monthly while contract terms can range from a single month or evergreen to terms of a decade or more. Revenues from oil and natural gas sales are recognized when the customer obtains control of the sold product which typically occurs at the point of delivery to the customer.
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.
Contract Drilling Revenue
Contract drilling revenues and expenses are primarily recognized as services are performed and collection is reasonably assured. Payments for mobilization and demobilization activities do not relate to a distinct good or service within the contract and are deferred for ratable recognition when material. Costs incurred to relocate rigs and other drilling equipment to areas in which a contract has not been secured are expensed as incurred and any reimbursements received for out-of-pocket expenses are recorded as both revenues and direct costs.
Most of our drilling contracts have a term of one year or less and the remaining performance obligations under the contracts without a fixed term are not material.
Mid-Stream Revenue
The typical revenue contracts used by this segment are gas gathering and processing agreements as well as product sales. Superior recognizes sales revenue at the point in time when control transfers to the purchaser, typically at a specified 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 or shortfall fees exist in arrangements where a customer agrees to pay a fixed fee for a contractually agreed upon pipeline capacity or shortfall fees for any minimum volumes not utilized, which create performance obligations for each individual period of reservation. Revenue for these fees is recognized once the services have been completed, the customer no longer has access to the contracted capacity, or the likelihood of the customer exercising all or a portion of their remaining rights becomes remote.
Contract Assets and Liabilities
The table below shows the changes in our contract asset and contract liability balances during periods presented:
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | |
| Classification on the unaudited condensed consolidated balance sheets | | March 31,
2022 | | December 31,
2021 | | Change |
| | | (In thousands) |
| Assets | | | | | | | |
| Current contract assets | Prepaid expenses and other | | $ | — | | | $ | 174 | | | $ | (174) | |
| Non-current contract assets | Other assets | | — | | | — | | | — | |
| Total contract assets | | | $ | — | | | $ | 174 | | | $ | (174) | |
| | | | | | | |
| Liabilities | | | | | | | |
| Current contract liabilities | Current portion of other long-term liabilities | | $ | 670 | | | $ | 1,588 | | | $ | (918) | |
| Non-current contract liabilities | Other long-term liabilities | | 194 | | | 200 | | | (6) | |
| Total contract liabilities | | | 864 | | | 1,788 | | | (924) | |
| Contract assets (liabilities), net | | | $ | (864) | | | $ | (1,614) | | | $ | 750 | |
NOTE 4 – DIVESTITURES
Oil and Natural Gas
The company initiated an asset divestiture program at the beginning of 2021 to sell certain non-core oil and gas properties and reserves (the “Divestiture Program”). On October 4, 2021, the company announced that it is expanding the Divestiture Program to now include the potential sale of additional properties, including up to all of UPC’s oil and gas properties and reserves. On January 20, 2022, the company announced that it has retained a financial advisor and launched the process, which is still ongoing.
On March 8, 2022, the company closed on the sale of certain non-core wells and related leases located near the Oklahoma Panhandle for cash proceeds of $4.1 million net of customary closing and post-closing adjustments based on an effective date of December 1, 2021. These proceeds reduced the net book value of our full cost pool with no gain or loss recognized as the sale did not result in a significant alteration of the full cost pool.
We sold other non-core oil and natural gas assets for net proceeds of $0.5 million and $1.7 million during the three months ended March 31, 2022 and 2021, respectively. These proceeds reduced the net book value of our full cost pool with no gain or loss recognized as the sales did not result in a significant alteration of the full cost pool.
Contract Drilling
We sold non-core contract drilling assets for proceeds of $2.2 million and $2.0 million during the three months ended March 31, 2022 and 2021, respectively. These proceeds resulted in net gains of $2.1 million and 0.6 million during the three months ended March 31, 2022 and 2021, respectively.
NOTE 5 – CAPITAL STOCK
Stock Repurchase Program
In June 2021, we repurchased an aggregate of 600,000 shares of our common stock from the Lenders (as defined in Note 10 - Long-Term Debt And Other Long-Term Liabilities) which received these shares as an exit fee during our reorganization. The Lenders were paid $15.00 per share for their respective shares, for an aggregate cash purchase price of $9.0 million.
In June 2021, the company's board of directors (the Board) authorized repurchasing up to $25.0 million of the company’s outstanding common stock. In October 2021, the Board authorized an increase from $25.0 million of authorized repurchases to $50.0 million. The repurchases will be made through open market purchases, privately negotiated transactions, or other available means. The company has no obligation to repurchase any shares under the repurchase program and may suspend or discontinue it at any time without prior notice. As of March 31, 2022, we had repurchased a total of 1,271,963 shares at an average share price of $32.57 for an aggregate purchase price of $41.4 million under the repurchase program.
During the year ended December 31, 2021, we also repurchased 78,000 shares in a privately negotiated transaction at a share price of $19.07 which were not part of the repurchase program.
The cumulative number of shares repurchased as of March 31, 2022 totaled 1,949,963. The cash purchase price and any direct acquisition costs are reflected as treasury stock on the unaudited condensed consolidated balance sheets as of March 31, 2022.
Warrants
Each holder of Unit common stock outstanding ("Old Common Stock") before the September 3, 2020 emergence from bankruptcy ("Emergence Date") that did not opt out of the release under the Chapter 11 plan of reorganization filed with the bankruptcy court on June 9, 2020 is entitled to receive 0.03460447 warrants for every share of Old Common Stock owned. Each warrant is exercisable for one share of common stock, subject to adjustment as provided in the Warrant Agreement. 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, dissolution or winding up of the company. As of March 31, 2022, the company had issued 1,822,203 warrants.
Among other provisions, the Warrant Agreement outlines potential adjustments to the warrants if certain events occur, including (i) stock dividends payable in shares of common stock or stock splits, (ii) reverse stock splits or similar combination events, (iii) Liquidity Events (as defined in the Warrant Agreement), and (iv) other events not explicitly contemplated which may have an adverse impact to the intent and purpose of the warrants as set forth in the Plan, provided, however, the warrants will not be adjusted for (a) any issuances of securities in connection with a merger, share exchange, asset acquisition, stock purchase, recapitalization, reorganization or other similar business combination, (b) the issuance of any securities by Unit on or after the Effective Date (as defined in the Plan) pursuant to the Plan or upon the issuance of shares of common stock upon the exercise of such securities, (c) the issuance of any shares of common stock pursuant to the exercise of the warrants, (d) the issuance of shares of common stock pursuant to any management stock option incentive or similar plan, (e) a dividend or distribution to holders of common stock of cash, property, or securities (other than common stock), and/or (f) any change in the par value of the common stock.
Pursuant to the terms of the Warrant Agreement, the company determined the initial exercise price of the warrants to be $63.74. On April 7, 2022, the company delivered notice of the initial exercise price to the Warrant Agent and the warrants became exercisable for shares of the company’s common stock. On or about April 25, 2022, the warrants began trading over-the-counter under the symbol "UNTCW".
NOTE 6 – 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 will be administered by the Board or a committee thereof and 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 (RSUs), 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 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 table below summarizes the stock-based compensation expense activity recognized during the following periods:
| | | | | | | | | | | |
| Three Months Ended March 31, |
| 2022 | | 2021 |
| (In thousands) |
| Recognized stock compensation expense | $ | 1,038 | | | $ | — | |
Capitalized stock compensation cost for our oil and natural gas properties | — | | | — | |
| Tax benefit on stock-based compensation | $ | 254 | | | $ | — | |
There were no RSUs granted or outstanding during the three months ended March 31, 2021. The table below summarizes the activity pertaining to nonvested RSUs during the three months ended March 31, 2022:
| | | | | | | | | | | |
| Three Months Ended March 31, |
| 2022 |
| Number of Shares | | Weighted Average Grant Date Fair Value |
| Nonvested RSUs, beginning of period | 315,529 | | | $ | 26.71 | |
Granted (1) | 7,850 | | | 30.50 | |
| Vested | (524) | | | 30.50 | |
| Forfeited | — | | | — | |
Nonvested RSUs, end of period (2) | 322,855 | | | $ | 26.80 | |
1.RSUs were granted on January 7, 2022 with an aggregate grant date fair value of $0.2 million and will vest equally each month for thirty months.
2.The aggregate compensation cost related to nonvested RSUs not yet recognized as of March 31, 2022 was $7.5 million with a weighted average remaining service period of 1.4 years.
There were no stock options granted or outstanding during the three months ended March 31, 2021. The table below summarizes the activity pertaining to outstanding stock options during the three months ended March 31, 2022:
| | | | | | | | | | | |
| Three Months Ended March 31, |
| 2022 |
| Number of Shares | | Weighted Average Exercise Price |
| Outstanding stock options, beginning of period | 361,418 | | | $ | 45.00 | |
Granted (1) | 13,416 | | | 45.00 | |
| Exercised | — | | | — | |
| Forfeited or expired | — | | | — | |
Outstanding stock options, end of period (2) | 374,834 | | | $ | 45.00 | |
1.Stock options were granted on January 7, 2022 with an aggregate grant date fair value of $0.1 million and will 100% vest on the first anniversary of the grant date.
2.The stock options outstanding as of March 31, 2022 had a weighted average remaining contractual term of 4.5 years and an aggregate intrinsic value of $6.2 million. None of the stock options outstanding as of March 31, 2022 were exercisable. The aggregate compensation cost related to outstanding options not yet recognized as of March 31, 2022 was $3.5 million with a weighted average remaining service period of 1.5 years.
NOTE 7 – LOSS PER SHARE
The table below shows information related to the calculation of loss per share attributable to Unit Corporation using the treasury stock method for the periods indicated below:
| | | | | | | | | | | | | | | | | | | | |
| | Earnings (Loss)
(Numerator) | | Weighted
Shares
(Denominator) | | Per-Share
Amount |
| | | (In thousands except per share amounts) |
| Three months ended March 31, 2022 | | | | | | |
| Basic loss attributable to Unit Corporation per common share | | $ | (46,877) | | | 10,050 | | | $ | (4.66) | |
| | | | | | |
| Diluted loss attributable to Unit Corporation per common share | | $ | (46,877) | | | 10,050 | | | $ | (4.66) | |
| Three months ended March 31, 2021 | | | | | | |
| Basic loss attributable to Unit Corporation per common share | | $ | (1,937) | | | 12,000 | | | $ | (0.16) | |
| | | | | | |
| Diluted loss attributable to Unit Corporation per common share | | $ | (1,937) | | | 12,000 | | | $ | (0.16) | |
The effects related to 319,192 average outstanding restricted stock units and 368,126 average outstanding stock options were excluded from the loss per share calculation for the three months ended March 31, 2022 because their inclusion would be antidilutive.
NOTE 8 – ACCRUED LIABILITIES
The table below provides detail on our accrued liabilities as of the dates indicated:
| | | | | | | | | | | | | | |
| | | | |
| | March 31,
2022 | | December 31,
2021 |
| | | (In thousands) |
| Employee costs | | $ | 7,708 | | | $ | 10,005 | |
| Lease operating expenses | | 3,910 | | | 3,451 | |
| Capital expenditures | | 4,715 | | | 3,962 | |
| Taxes | | 1,481 | | | 3,320 | |
| Interest payable | | 96 | | | 296 | |
| | | | |
| Other | | 1,259 | | | 1,416 | |
| Total accrued liabilities | | $ | 19,169 | | | $ | 22,450 | |
NOTE 9 – LONG-TERM DEBT AND OTHER LONG-TERM LIABILITIES
Long-Term Debt
The table below provides detail on our outstanding long-term debt as of the dates indicated:
| | | | | | | | | | | | | | |
| | March 31,
2022 | | December 31,
2021 |
| | | (In thousands) |
| | | | |
| | | | |
| Long-term debt: | | | | |
| Exit credit agreement | | $ | — | | | $ | — | |
Superior credit agreement (1) | | | | $ | 19,200 | |
1.Unit Corporation no longer consolidates the financial position of Superior as of March 31, 2022 as discussed in Note 2 - Summary Of Significant Accounting Policies and Note 15 - Superior Investment.
Exit Credit Agreement. On the Effective Date, under the terms of the Plan, the company entered into an amended and restated credit agreement (the Exit credit agreement), providing for a $140.0 million senior secured revolving credit facility (RBL Facility) and a $40.0 million senior secured term loan facility, among (i) the company, UDC, and UPC (together, the Borrowers), (ii) the guarantors party thereto, including the company and all of its subsidiaries existing as of the Effective Date (other than Superior and its subsidiaries), (iii) the lenders party thereto from time to time (Lenders), and (iv) BOKF, NA dba Bank of Oklahoma as administrative agent and collateral agent (in such capacity, the Administrative Agent).
On April 6, 2021, the company finalized the first amendment to the Exit credit agreement. Under the first amendment, the company reaffirmed its borrowing base of $140.0 million of the RBL Facility, amended certain financial covenants, and received less restrictive terms, among others, as it relates to the disposition of assets and the use of proceeds from those dispositions.
On July 27, 2021, the company finalized the second amendment to the Exit credit agreement. Under the second amendment, the company obtained confirmation that the Term Loan had been paid in full prior to the amendment date and received one-time waivers related to the disposition of assets.
On October 19, 2021, the company finalized the third amendment to the Exit credit agreement. Under the third amendment, the company requested, and was granted, a reduction in the RBL Facility borrowing base from $140.0 million to $80.0 million in addition to less restrictive terms as it relates to capital expenditures, required hedges, and the use of proceeds from the disposition of certain assets, while also amending certain financial covenants.
On March 30, 2022, the RBL Facility borrowing base of $80.0 million was reaffirmed.
The maturity date of borrowings under this Exit credit agreement is March 1, 2024. Revolving Loans and Term Loans (each as defined in the Exit credit agreement) may be Eurodollar Loans or ABR Loans (each as defined in the Exit credit agreement). Revolving Loans that are Eurodollar Loans will bear interest at a rate per annum equal to the Adjusted LIBO Rate (as defined in the Exit credit agreement) for the applicable interest period plus 525 basis points. Revolving Loans that are ABR Loans will bear interest at a rate per annum equal to the Alternate Base Rate (as defined in the Exit credit agreement) plus 425 basis points. Term Loans that are Eurodollar Loans will bear interest at a rate per annum equal to the Adjusted LIBO Rate for the applicable interest period plus 625 basis points. Term Loans that are ABR Loans will bear interest at a rate per annum equal to the Alternate Base Rate plus 525 basis points.
The Exit credit agreement requires the company to comply with certain financial ratios, including a covenant that the company will not permit the Net Leverage Ratio (as defined in the Exit credit agreement) as of the last day of the fiscal quarters ended (i) December 31, 2020 and March 31, 2021, to be greater than 4.00 to 1.00, (ii) June 30, 2021 and September 30, 2021, to be greater than 3.75 to 1.00, and (iii) December 31, 2021 and any fiscal quarter thereafter, to be greater than 3.25 to 1.00. In addition, beginning with the fiscal quarter ended December 31, 2020, the company may not (a) permit the Current Ratio (as defined in the Exit credit agreement) as of the last day of any fiscal quarter to be less than 1.00 to 1.00 or (b) permit the Interest Coverage Ratio (as defined in the Exit credit agreement) as of the last day of any fiscal quarter to be less than 2.50 to 1.00. The Exit credit agreement also contains provisions, among others, that limit certain capital expenditures, and require certain hedging activities. The Exit credit agreement further requires the company to 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 March 31, 2022, Unit was in compliance with these covenants.
The Exit credit agreement is secured by first-priority liens on substantially all of the personal and real property assets of the Borrowers and the Guarantors, including the company’s ownership interests in Superior.
As of March 31, 2022, we had no long-term borrowings and $2.4 million of letters of credit outstanding under the Exit 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 (Superior credit agreement). The amounts borrowed under the Superior credit agreement bore 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 Superior credit agreement required 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 contained 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. Superior was in compliance with these covenants as of March 31, 2022.
On April 29, 2022, Superior entered into an Amended and Restated Credit Agreement for a four-year, $135.0 million senior secured revolving credit facility with an option to increase the credit amount up to $200.0 million, subject to certain conditions (Amended Superior credit agreement). The amounts borrowed under the Amended Superior credit agreement bear annual interest at a rate, at Superior’s option, equal to (a) SOFR plus the applicable margin of 2.75% to 3.75% or (b) the alternate base rate (greater of (i) the federal funds rate plus 0.5%, (ii) the prime rate, and (iii) SOFR plus 0.10%). The obligations under the Amended Superior credit agreement are secured by, among other things, mortgage liens on certain of Superior’s processing plants and gathering systems. Unit is not a party to and does not guarantee the Amended Superior credit agreement.
The Amended 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 3.50 to 1.00. Additionally, the Amended Superior credit agreement contains a number of 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.
Other Long-Term Liabilities
The table below provides detail on our other long-term liabilities as of the dates indicated:
| | | | | | | | | | | | | | |
| | | | |
| | March 31,
2022 | | December 31,
2021 |
| | | (In thousands) |
| Asset retirement obligation (ARO) liability | | $ | 24,939 | | | $ | 25,688 | |
| Workers’ compensation | | 7,673 | | | 7,925 | |
| Contract liability | | 864 | | | 1,788 | |
| Separation benefit plans | | 1,776 | | | 2,022 | |
| Gas balancing liability | | 1,082 | | | 1,090 | |
| | | | |
| | 36,334 | | | 38,513 | |
| Less: current portion | | 4,537 | | | 5,574 | |
| Total other long-term liabilities | | $ | 31,797 | | | $ | 32,939 | |
NOTE 10 – ASSET RETIREMENT OBLIGATIONS
We are required to record the estimated fair value of the liabilities relating to the future retirement of our long-lived assets. Our oil and natural gas wells are plugged and abandoned when the oil and natural gas reserves in those wells are depleted or the wells are no longer able to produce. The plugging and abandonment liability for a well is recorded in the period in which the obligation is incurred (at the time the well is drilled or acquired). None of our assets are restricted for purposes of settling these AROs. All our AROs relate to the plugging costs associated with our oil and gas wells.
The following table shows certain information about our estimated AROs for the periods indicated:
| | | | | | | | | | | |
| Three Months Ended March 31, |
| 2022 | | 2021 |
| (In thousands) |
| ARO liability, beginning of period | $ | 25,688 | | | $ | 23,356 | |
| Accretion of discount | 493 | | | 461 | |
| Liability incurred | — | | | — | |
| Liability settled | (55) | | | (16) | |
| Liability sold | (2,670) | | | (2) | |
Revision of estimates (1) | 1,483 | | | 44 | |
| ARO liability, end of period | 24,939 | | | 23,843 | |
| Less: current portion | 2,654 | | | 2,161 | |
| Total long-term ARO | $ | 22,285 | | | $ | 21,682 | |
1.Plugging liability estimates were revised in 2022 and 2021 for updates in the cost of services used to plug wells over the preceding year as well as estimated inflation and discount rates. We had various upward and downward adjustments.
NOTE 11 – WORKERS' COMPENSATION
We are liable for workers' compensation benefits for traumatic injuries through our self-insured program to provide income replacement and medical treatment for work-related traumatic injury claims as required by applicable state laws. Workers' compensation laws also compensate survivors of workers who suffer employment related deaths. Our liability for traumatic injury claims is the estimated present value of current workers' compensation benefits, based on our actuarial estimates. Our actuarial calculations are based on a blend of actuarial projection methods and numerous assumptions including claim development patterns, mortality, medical costs and interest rates.
The following table summarizes activity for our workers' compensation liability during the periods indicated:
| | | | | | | | | | | |
| Three months ended March 31, |
| | 2022 | | 2021 |
| | (In thousands) |
| Workers' compensation liability, beginning of period | $ | 7,925 | | | $ | 10,164 | |
| Claims and valuation adjustments | (160) | | | 1,646 | |
| Payments | (92) | | | (75) | |
| Workers' compensation liability, end of period | 7,673 | | | 11,735 | |
| Less: current portion | 1,169 | | | 1,882 | |
| Long-term workers' compensation liability | $ | 6,504 | | | $ | 9,853 | |
Our workers' compensation liability above is presented on a gross basis and does not include our expected receivables on our insurance policy. Our receivables for traumatic injury claims under these policies as of March 31, 2022 and December 31, 2021 are $3.9 million and $4.0 million, respectively, and are included in Other assets on our unaudited condensed consolidated balance sheets.
NOTE 12 – DERIVATIVES
Commodity Derivatives
We have entered into various types of derivative transactions covering some of our projected natural gas, NGLs, and oil production. These transactions are intended to reduce our exposure to market price volatility by setting the price(s) we will receive for that production. Our decisions on the price(s), type, and quantity of our production subject to a derivative contract are based, in part, on our view of current and future market conditions as well as certain requirements stipulated in the Exit credit agreement. As of March 31, 2022, our commodity derivative transactions consisted of the following types of hedges:
•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. We are not required to post any cash collateral with our counterparties and no collateral has been posted as of March 31, 2022.
The following non-designated commodity hedges were outstanding as of March 31, 2022:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Term | | Commodity | | Contracted Volume | | Weighted Average Fixed Price for Swaps | | Contracted Market |
| Apr'22 - Dec'22 | | Natural gas - swap | | 5,000 MMBtu/day | | $2.61 | | IF - NYMEX (HH) |
| Jan'23 - Dec'23 | | Natural gas - swap | | 22,000 MMBtu/day | | $2.46 | | IF - NYMEX (HH) |
| Apr'22 - Dec'22 | | Natural gas - collar | | 35,000 MMBtu/day | | $2.50 - $2.68 | | IF - NYMEX (HH) |
| Apr'22 - Jun'22 | | Crude oil - swap | | 824 Bbl/day | | $70.30 | | WTI - NYMEX |
| Apr'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 |
Warrants
We recognize the fair value of the warrants as a derivative liability on our consolidated balance sheets with changes in the liability reported as loss on change in fair value of warrants in our consolidated statements of operations. The liability will continue to be adjusted to fair value at each reporting period until the warrants meet the definition of an equity instrument, at which time they will be reported as shareholders' equity and no longer subject to future fair value adjustments.
On April 7, 2022, the company delivered notice of the initial $63.74 exercise price resulting in the warrants meeting the definition of an equity instrument. We will estimate the fair value of the warrants as of April 7, 2022 and they will be reported as shareholders' equity in future periods.
The following tables present the recognized derivative assets and liabilities on our unaudited condensed consolidated balance sheets:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Balances as of March 31, 2022 |
| | Balance Sheet Classification | | Presented
Gross | | Effects of
Netting | | Presented
Net |
| | | | | (In thousands) |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| Liabilities: | | | | | | | | |
| Current Commodity Derivatives | | Current derivative liabilities | | $ | 78,868 | | | $ | — | | | $ | 78,868 | |
| Long-term Commodity Derivatives | | Non-current derivative liabilities | | 22,699 | | | — | | | 22,699 | |
| Warrant Liability | | Warrant liability | | 56,434 | | | — | | | 56,434 | |
| Total derivative liabilities | | | | $ | 158,001 | | | $ | — | | | $ | 158,001 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Balances as of December 31, 2021 |
| | Balance Sheet Classification | | Presented
Gross | | Effects of
Netting | | Presented
Net |
| | | | | (In thousands) |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| Liabilities: | | | | | | | | |
| Current Commodity Derivatives | | Current derivative liabilities | | $ | 40,876 | | | $ | — | | | $ | 40,876 | |
| Long-term Commodity Derivatives | | Non-current derivative liabilities | | 17,855 | | | — | | | 17,855 | |
| Warrant Liability | | Warrant liability | | 19,822 | | | — | | | 19,822 | |
| Total derivative liabilities | | | | $ | 78,553 | | | $ | — | | | $ | 78,553 | |
The following table shows the activity related to derivative instruments in the unaudited condensed consolidated statements of operations for the periods indicated:
| | | | | | | | | | | | | |
| Three Months Ended March 31, | | |
| 2022 | | 2021 | |
| | (In thousands) |
| Loss on derivatives | $ | (64,076) | | | $ | (22,831) | | | |
| Cash settlements paid on commodity derivatives | (21,239) | | | (3,304) | | | |
| Loss on derivatives less cash settlements paid on commodity derivatives | $ | (42,837) | | | $ | (19,527) | | | |
| | | | | |
| Loss on change in fair value of warrants | $ | (36,612) | | | $ | — | | | |
NOTE 13 – FAIR VALUE MEASUREMENTS
This disclosure of the estimated fair value of financial instruments is made under accounting guidance for financial instruments. We have determined the estimated fair values by using market information and certain valuation methodologies. Considerable judgment is required in interpreting market data to develop the estimates of fair value. Using different market assumptions or valuation methodologies may have a material effect on our estimated fair value amounts.
The inputs available determine the valuation technique that we use to measure the fair value of the assets and liabilities presented in our unaudited condensed consolidated financial statements. Fair value measurements are categorized into one of three different levels depending on the observability of the inputs used in the measurement. The levels are summarized as follows:
•Level 1—observable inputs such as quoted prices in active markets for identical assets and liabilities.
•Level 2—other observable pricing inputs, such as quoted prices in inactive markets, or other inputs that are either directly or indirectly observable as of the reporting date, including inputs that are derived 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 or estimates about how market participants would value such assets and liabilities.
Recurring Fair Value Measurements
The following tables set forth our recurring fair value measurements by level:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Balances as of March 31, 2022 |
| | | Level 1 | | Level 2 | | Level 3 | | Total |
| | | (In thousands) |
| Financial liabilities: | | | | | | | | |
| Commodity derivative liabilities | | $ | — | | | $ | 101,567 | | | $ | — | | | $ | 101,567 | |
| Warrant liability | | — | | | — | | | 56,434 | | | 56,434 | |
| | $ | — | | | $ | 101,567 | | | $ | 56,434 | | | $ | 158,001 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Balances as of December 31, 2021 |
| | | Level 1 | | Level 2 | | Level 3 | | Total |
| | | (In thousands) |
| Financial liabilities: | | | | | | | | |
| Commodity derivative liabilities | | $ | — | | | $ | 58,731 | | | $ | — | | | $ | 58,731 | |
| Warrant liability | | — | | | — | | | 19,822 | | | 19,822 | |
| | $ | — | | | $ | 58,731 | | | $ | 19,822 | | | $ | 78,553 | |
The carrying values on the unaudited condensed consolidated balance sheets for cash and cash equivalents, accounts receivable, accounts payable, other current assets, and current liabilities approximate their fair value because of their short-term nature. 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 liabilities.
Commodity Derivatives. We measure the fair values of our crude oil and natural gas swaps and collars using estimated discounted cash flow calculations based on the NYMEX futures index. We consider these Level 2 measurements within the fair value hierarchy as the inputs in the model are substantially observable over the term of the commodity derivative contract and there is a wide availability of quoted market prices for similar commodity derivative contracts.
We determined that the non-performance risk regarding our commodity derivative counterparties was immaterial based on our valuation at March 31, 2022.
Warrant Liability. We use the Black-Scholes option pricing model to measure the fair value of the warrants. Key inputs for the Black-Scholes model include the stock price, exercise price, expected term, risk-free rate, volatility, and dividend yield. We consider this a Level 3 measurement within the fair value hierarchy as estimated volatility is generally unobservable and requires management's estimation.
The following tables summarize the activity of our recurring Level 3 fair value measurements during the periods presented:
| | | | | | | | | | | |
| Three Months Ended March 31, |
| 2022 | | 2021 |
| | (In thousands) |
| Beginning of period | $ | 19,822 | | | $ | 885 | |
| Loss on change in warrant liability | 36,612 | | | — | |
| End of period | $ | 56,434 | | | $ | 885 | |
Nonrecurring Fair Value Measurements
ARO. The initial measurement of ARO at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with property and equipment. Significant Level 3 inputs used in the calculation of AROs include plugging costs and remaining reserve lives. A summary of the company’s ARO activity is presented in Note 10 – Asset Retirement Obligations.
Stock-Based Compensation. We use the Black-Scholes option pricing model to estimate the fair value of stock option grants while the value of our restricted stock grants is based on the grant date closing stock price. Key assumptions for the Black-Scholes models include the stock price, exercise price, expected term, risk-free rate, volatility, and dividend yield. We consider this a Level 3 measurement within the fair value hierarchy as estimated volatility is generally unobservable and requires management's estimation.
See Note 15 - Superior Investment for discussion on the estimated fair value of our retained equity method investment in Superior as of March 1, 2022.
NOTE 14 – LEASES
Operating Leases. We are a lessee through noncancellable lease agreements for property and equipment consisting primarily of office space, land, vehicles, and equipment used in both our operations and administrative functions.
The following table sets forth the maturities, weighted average remaining lease term, and weighted average discount rate of our operating lease liabilities as of March 31, 2022:
| | | | | |
| Amount |
| (In thousands) |
| Ending March 31, | |
| 2022 | $ | 2,423 | |
| 2023 | 1,994 | |
| 2024 | 2,014 | |
| 2025 | 2,055 | |
| 2026 | 954 | |
| 2027 and beyond | — | |
| Total future payments | 9,440 | |
| Less: Interest | 1,247 | |
| Present value of future minimum operating lease payments | 8,193 | |
| Less: Current portion | 1,949 | |
| Total long-term operating lease payments | $ | 6,244 | |
| |
| Weighted average remaining lease term (years) | 4.3 |
Weighted average discount rate (1) | 6.64 | % |
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.
Finance Leases. During 2014, Superior entered into finance lease agreements for 20 compressors with initial terms of seven years and an option to purchase the assets at 10% of their then fair market value at the end of the term. These finance leases were discounted using annual rates of 4.0% and the underlying assets are included in gas gathering and processing equipment. Superior purchased the leased assets for $3.0 million in May 2021.
The following table shows information about our lease assets and liabilities on our unaudited condensed consolidated balance sheets:
| | | | | | | | | | | | | | | | | | | | |
| | Classification on the unaudited condensed consolidated balance sheets | | March 31,
2022 | | December 31,
2021 |
| | | | (In thousands) |
| Assets | | | | | | |
| Operating lease right of use assets | | Right of use assets | | $ | 8,151 | | | $ | 12,445 | |
| Total right of use assets | | | | $ | 8,151 | | | $ | 12,445 | |
| | | | | | |
| Liabilities | | | | | | |
| Current liabilities: | | | | | | |
| Operating lease liabilities | | Current operating lease liabilities | | $ | 1,949 | | | $ | 3,791 | |
| Non-current liabilities: | | | | | | |
| Operating lease liabilities | | Operating lease liabilities | | 6,244 | | | 8,677 | |
| Total lease liabilities | | | | $ | 8,193 | | | $ | 12,468 | |
The following table shows certain information related to the lease costs for our finance and operating leases for the periods indicated:
| | | | | | | | | | | |
| Three Months Ended March 31, |
| 2022 | | 2021 |
| (In thousands) |
| Components of total lease cost: | | | |
| Amortization of finance leased assets | $ | — | | | $ | 1,067 | |
| Interest on finance lease liabilities | — | | | 29 | |
| Operating lease cost | 1,308 | | | 1,047 | |
Short-term lease cost (1) | 3,536 | | | 1,444 | |
| Variable lease cost | — | | | 58 | |
| Total lease cost | $ | 4,844 | | | $ | 3,645 | |
1.Short-term lease cost includes amounts capitalized related to our oil and natural gas segment of $0.5 million and $0.1 million for the three months ended March 31, 2022 and 2021, respectively.
The following table shows supplemental cash flow information related to leases for the periods indicated:
| | | | | | | | | | | |
| Three Months Ended March 31, |
| 2022 | | 2021 |
| (In thousands) |
| Cash paid for amounts in the measurement of lease liabilities: | | | |
| Operating cash flows for operating leases | $ | 1,284 | | | $ | 1,048 | |
| Financing cash flows for finance leases | $ | — | | | $ | 1,067 | |
| Lease liabilities recognized in exchange for new operating lease right of use assets | $ | 909 | | | $ | 102 | |
NOTE 15 – SUPERIOR INVESTMENT
On April 3, 2018, we sold 50% of the ownership interest in Superior to SP Investor Holdings, LLC (SP Investor), a holding company jointly owned by OPTrust, and funds managed and/or advised by Partners Group, a global private markets investment manager. Superior is governed and managed under the Amended and Restated Limited Liability Company Agreement (Agreement) and Amended and Restated Master Services and Operating Agreement (MSA). The MSA was between our wholly-owned subsidiary, SPC Midstream Operating, L.L.C. (the Operator), and Superior. As the Operator, we provided services, such as operations and maintenance support, accounting, legal, and human resources to Superior for a monthly service fee of $0.3 million. Superior's creditors have no recourse to our general credit. Unit is not a party to and does not guarantee Superior's credit agreement. The obligations under Superior's credit agreement are secured by, among other things, mortgage liens on certain of Superior’s processing plants and gathering systems.
Distributions. The Agreement specifies how future distributions are to be allocated among Unit Corporation and SP Investor (the Members). Distributions from Available Cash (as defined in the Agreement) were generally split evenly between the Members prior to December 31, 2021, when the three-year period for Unit's commitment to spend $150.0 million (Drilling Commitment Amount) to drill wells in the Granite Wash/Buffalo Wallow area ended. The total amount spent by Unit towards the Drilling Commitment Amount was $24.6 million. Accordingly, SP Investor will receive 100% of Available Cash distributions related to periods subsequent to December 31, 2021 until the $72.7 million Drilling Commitment Adjustment Amount (as defined in the Agreement) is satisfied.
Superior paid cash distributions of $9.5 million to each of the Members in January 2022 representing Available Cash generated during the three months ended December 31, 2021 and paid $10.5 million of distributions to SP Investor in April 2022 representing Available Cash generated during the three months ended March 31, 2022. The distributions paid to SP Investor in April 2022 reduced the remaining Drilling Commitment Adjustment Amount to $62.2 million.
Sale Event. After April 1, 2023, either Member may initiate a sale process of Superior to a third-party or a liquidation of Superior's assets (Sale Event). In a Sale Event, the Agreement generally requires cumulative distributions to SP Investor in excess of its original $300.0 million investment sufficient to provide SP Investor a 7% internal rate of return on its capital contributions to Superior before any liquidation distribution is made to Unit. As of March 31, 2022, liquidation distributions paid first to SP Investor of $358.2 million would be required for SP Investor to reach its 7% Liquidation IRR Hurdle at which point Unit would then be entitled to receive up to $358.2 million of the remaining liquidation distributions to satisfy Unit's 7% Liquidation IRR Hurdle with any remaining liquidation distributions paid as outlined within the Agreement.
Consolidation. From April 3, 2018 to March 1, 2022, we treated Superior as a variable interest entity (VIE) because the equity holders as a group (Unit Corporation and SP Investor) lacked the power to control without the Operator. The Agreement and MSA gave us the power to direct the activities that most significantly affect Superior's operating performance through common control of the Operator. Accordingly, Unit was considered the primary beneficiary and consolidated the financial position, operating results, and cash flows of Superior.
Effective March 1, 2022, the employees of the Operator were transferred to Superior and the MSA was amended and restated to remove the operating services the Operator was providing to Superior. There was no change to the monthly service fee for shared services. The power to direct the activities that most significantly affect Superior's operating performance is now shared by the equity holders (Unit Corporation and SP Investor) rather than held by the Operator. Superior no longer qualifies as a VIE subsequent to these amendments and we no longer consolidate the financial position, operating results, and cash flows of Superior as of, and subsequent to, March 1, 2022.
We subsequently account for our investment in Superior as an equity method investment using the hypothetical liquidation book value (HLBV) method, which is a balance sheet approach that calculates the change in the hypothetical amount Unit and SP Investor would be entitled to receive if Superior were liquidated at book value at the end of each period, adjusted for any contributions made and distributions received during the period. We recognized no equity earnings from our investment in Superior during the three months ended March 31, 2022.
Estimated Fair Value of Equity Method Investment in Superior. As of the Effective Date, in conjunction with fresh start accounting under ASC Topic 852, Reorganizations, the estimated fair value of the net equity attributable to Unit's ownership interest in Superior was $14.8 million. Since then, Unit has received cumulative distributions from Superior of $32.6 million, which were recognized as net income attributable to Unit under the HLBV method. As of March 1, 2022, upon deconsolidation of Superior, the fair value of our retained equity method investment in Superior was estimated at $1.7 million. To estimate this fair value, we simulated paths for Superior's total equity value through the potential sales process initiation date using a Geometric Brownian Motion. The expected value (i.e., average of all simulations) of each security class was then discounted to present value using the relevant risk-free rate. The simulations reflect forecasted future cash distributions as impacted by the Drilling Commitment Adjustment Amount described above, as well as the future liquidation preference of each investor in a potential Sale Event also as described above. We consider this a Level 3 measurement within the fair value hierarchy as the discounted simulation models require the use of significant unobservable inputs.
We recognized a $13.1 million loss on deconsolidation during the three months ended March 31, 2022 as the difference between the $1.7 million estimated fair value of our retained equity method investment in Superior as of March 1, 2022 and Superior's net equity attributable to Unit's ownership interest prior to deconsolidation.
Superior Balance Sheet Disclosure. The amounts below reflect the Superior balance sheet accounts, without elimination of intercompany receivables from and payables to Unit, consolidated in our unaudited condensed consolidated balance sheets as of December 31, 2021 which was the last reporting date as of which we consolidated the financial position of Superior:
| | | | | |
| December 31,
2021 |
| | (In thousands) |
| Current assets: | |
| Cash and cash equivalents | $ | 17,246 | |
| Accounts receivable | 42,628 | |
| Prepaid expenses and other | 1,263 | |
| Total current assets | 61,137 | |
| Property and equipment: | |
| Gas gathering and processing equipment | 274,748 | |
| Transportation equipment | 2,801 | |
| 277,549 | |
| Less accumulated depreciation, depletion, amortization, and impairment | 53,792 | |
| Net property and equipment | 223,757 | |
| Right of use asset | 3,485 | |
| Other assets | 2,226 | |
| Total assets | $ | 290,605 | |
| |
| Current liabilities: | |
| Accounts payable | $ | 34,010 | |
| Accrued liabilities | 5,292 | |
| Current operating lease liability | 1,450 | |
| Current portion of other long-term liabilities | 1,548 | |
| Total current liabilities | 42,300 | |
| Long-term debt | 19,200 | |
| Operating lease liability | 2,036 | |
| |
| Total liabilities | $ | 63,536 | |
Affiliate Activity. UPC recorded oil and natural gas revenues with Superior of $16.3 million and $8.6 million as well as gas gathering and processing expenses of $0.8 million and $0.8 million during the three months ended March 31, 2022 and 2021, respectively. Portions of this activity was eliminated for the periods during which Superior was consolidated by Unit.
NOTE 16 – COMMITMENTS AND CONTINGENCIES
Environmental
We manage our exposure to environmental liabilities on properties to be acquired by identifying existing problems and assessing the potential liability. We also conduct periodic reviews, on a company-wide basis, to identify changes in our environmental risk profile. These reviews evaluate whether there is a probable liability, its amount, and the likelihood that the liability will be incurred. Any potential liability is determined by considering, among other matters, incremental direct costs of any likely remediation and the proportionate cost of employees expected to devote significant time directly to any possible remediation effort. As it relates to evaluations of purchased properties, depending on the extent of an identified environmental problem, we may exclude a property from the acquisition, require the seller to remediate the property to our satisfaction, or agree to assume liability for the remediation of the property.
We have not historically experienced significant environmental liability while being a contract driller since the greatest portion of that risk is borne by the operator. Any liabilities we have incurred have been small and were resolved while the drilling rig was on the location. Those costs were in the direct cost of drilling the well.
Litigation
The company is subject to litigation and claims arising in the ordinary course of business which may include environmental, health and safety matters, commercial disputes with customers, 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.
In February 2021, UPC finalized a settlement agreement for $2.1 million related to a well drilled in Beaver County, Oklahoma during 2013. 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 finalized the settlement agreement while the case was pending review in the Oklahoma Court of Civil Appeals.
NOTE 17 – INCOME TAXES
For the three months ended March 31, 2022 and 2021, the company’s effective income tax rate was 0.0% which differs from the statutory rate of 21.0% primarily due to changes in, and continued need of, our full valuation allowance, changes in the warrant liability valuation, and state income taxes.
We concluded that it is more likely than not that the net deferred tax asset will not be realized and has recorded a full valuation allowance, reducing the net deferred tax asset to zero. We maintained this conclusion as of March 31, 2022 and December 31, 2021. We will continue to evaluate whether the valuation allowance is needed in future reporting periods and it will remain until we can conclude that the net deferred tax assets are more likely than not to be realized. Future events or new evidence which may lead us to conclude that it is more likely than not its net deferred tax assets will be realized include, but are not limited to, cumulative historical pre-tax earnings, sustained significant improvements in commodity prices, a sustained significant increase in rig utilization and/or rates, a material and sizable asset acquisition or disposition, and taxable events that could result from one or more future potential transactions. The valuation allowance does not prohibit the company from utilizing the tax attributes if the company recognizes taxable income. As long as we continue to conclude that the valuation allowance against the net deferred tax assets is necessary, the company will not have significant deferred income tax expense or benefit.
As of December 31, 2021, the company has an expected federal net operating loss carryforward of $385.5 million after consideration of the tax attribute reductions of IRC Section 108, finalization of the company’s 2020 federal income tax return, and pending finalization of the company's 2021 federal income tax return of which $190.5 million is subject to expiration between 2036 and 2037. As of December 31, 2021, our tax basis in UPC's properties was approximately $475.0 million.
NOTE 18 – TRANSACTIONS WITH RELATED PARTIES
One current director, Robert Anderson, also serves as an executive with GBK Corporation, a holding company with numerous energy and industry subsidiaries and affiliates, including Kaiser Francis Oil Company. The company in the ordinary course of business, made payments for working interests, joint interest billings, and product purchases to, and received payments for working interests, drilling services, and joint interest billings from, Kaiser Francis Oil Company. Payments made to Kaiser Francis Oil Company totaled $3.4 million and $0.5 million while payments received totaled $3.9 million and $1.1 million during the three months ended March 31, 2022 and 2021, respectively.
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 $0.1 million and $0.1 million during the three months ended March 31, 2022 and 2021, respectively.
NOTE 19 – INDUSTRY SEGMENT INFORMATION
We have three main business segments offering different products and services within the energy industry:
•Oil and natural gas - the oil and natural gas segment is engaged in the acquisition, development, and production of oil, NGLs, and natural gas properties.
•Contract drilling - the contract drilling segment is engaged in the land contract drilling of oil and natural gas wells.
•Mid-Stream - the mid-stream segment buys, sells, gathers, processes, and treats natural gas and NGLs for third parties and for our own account. We presently own 50% of this subsidiary, and subsequent to the deconsolidation of Superior as of March 1, 2022 (as discussed in Note 2 - Summary Of Significant Accounting Policies and Note 15 - Superior Investment), we will continue to include our equity method investment in Superior and related earnings in our mid-stream segment.
We evaluate each consolidated segment’s performance based on its operating income, which is defined as operating revenues less operating expenses and depreciation, depletion, amortization, and impairment. We have no oil and natural gas production or other operations outside the United States.
The following tables provide certain information about the operations of each of our segments:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended March 31, 2022 |
| | | Oil and Natural Gas | | Contract Drilling | | Mid-Stream (2) | | Corporate and Other | | Eliminations (2) | | Total Consolidated |
| | | (In thousands) |
Revenues: (1) | | | | | | | | | | | | |
| Oil and natural gas | | $ | 87,582 | | | $ | — | | | $ | — | | | $ | — | | | $ | (10,772) | | | $ | 76,810 | |
| Contract drilling | | — | | | 28,882 | | | — | | | — | | | — | | | 28,882 | |
| Gas gathering and processing | | — | | | — | | | 83,198 | | | — | | | (525) | | | 82,673 | |
| Total revenues | | 87,582 | | | 28,882 | | | 83,198 | | | — | | | (11,297) | | | 188,365 | |
| Expenses: | | | | | | | | | | | | |
| Operating costs: | | | | | | | | | | | | |
| Oil and natural gas | | 24,000 | | | — | | | — | | | — | | | (525) | | | 23,475 | |
| Contract drilling | | — | | | 26,237 | | | — | | | — | | | — | | | 26,237 | |
| Gas gathering and processing | | — | | | — | | | 73,771 | | | — | | | (11,383) | | | 62,388 | |
Total operating costs | | 24,000 | | | 26,237 | | | 73,771 | | | — | | | (11,908) | | | 112,100 | |
Depreciation, depletion, and amortization | | 4,048 | | | 1,534 | | | 5,614 | | | 74 | | | — | | | 11,270 | |
| | | | | | | | | | | | |
| Total expenses | | 28,048 | | | 27,771 | | | 79,385 | | | 74 | | | (11,908) | | | 123,370 | |
| | | | | | | | | | | | |
General and administrative | | — | | | — | | | — | | | 5,915 | | | 611 | | | 6,526 | |
| (Gain) loss on disposition of assets | | (53) | | | (2,125) | | | — | | | 3 | | | — | | | (2,175) | |
| Income (loss) from operations | | 59,587 | | | 3,236 | | | 3,813 | | | (5,992) | | | — | | | 60,644 | |
| Loss on derivatives | | — | | | — | | | — | | | (64,076) | | | — | | | (64,076) | |
| Loss on change in fair value of warrants | | — | | | — | | | — | | | (36,612) | | | — | | | (36,612) | |
| | | | | | | | | | | | |
| Loss on deconsolidation of Superior | | — | | | — | | | — | | | (13,141) | | | — | | | (13,141) | |
| Reorganization items, net | | — | | | — | | | — | | | (3) | | | — | | | (3) | |
| Interest, net | | — | | | — | | | (178) | | | (96) | | | — | | | (274) | |
| Other | | 708 | | | 20 | | | 17 | | | 12 | | | — | | | 757 | |
| Income (loss) before income taxes | | $ | 60,295 | | | $ | 3,256 | | | $ | 3,652 | | | $ | (119,908) | | | $ | — | | | $ | (52,705) | |
_______________________
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.Includes Superior activity for the two months prior to the March 1, 2022 deconsolidation, as discussed in Note 2 - Summary Of Significant Accounting Policies and Note 15 - Superior Investment.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended March 31, 2021 |
| | | Oil and Natural Gas | | Contract Drilling | | Mid-Stream | | Corporate and Other | | Eliminations | | Total Consolidated |
| | | (In thousands) |
Revenues: (1) | | | | | | | | | | | | |
| Oil and natural gas | | $ | 55,025 | | | $ | — | | | $ | — | | | $ | — | | | $ | (1) | | | $ | 55,024 | |
| Contract drilling | | — | | | 15,674 | | | — | | | — | | | — | | | 15,674 | |
| Gas gathering and processing | | — | | | — | | | 59,610 | | | — | | | (9,411) | | | 50,199 | |
| Total revenues | | 55,025 | | | 15,674 | | | 59,610 | | | — | | | (9,412) | | | 120,897 | |
| Expenses: | | | | | | | | | | | | |
| Operating costs: | | | | | | | | | | | | |
| Oil and natural gas | | 19,993 | | | — | | | — | | | — | | | (844) | | | 19,149 | |
| Contract drilling | | — | | | 11,871 | | | — | | | — | | | — | | | 11,871 | |
| Gas gathering and processing | | — | | | — | | | 49,111 | | | — | | | (8,568) | | | 40,543 | |
Total operating costs | | 19,993 | | | 11,871 | | | 49,111 | | | — | | | (9,412) | | | 71,563 | |
Depreciation, depletion, and amortization | | 7,655 | | | 1,575 | | | 8,032 | | | 249 | | | — | | | 17,511 | |
| Total expenses | | 27,648 | | | 13,446 | | | 57,143 | | | 249 | | | (9,412) | | | 89,074 | |
General and administrative | | — | | | — | | | — | | | 6,289 | | | — | | | 6,289 | |
| (Gain) loss on disposition of assets | | (19) | | | (529) | | | 75 | | | 1 | | | — | | | (472) | |
| Income (loss) from operations | | 27,396 | | | 2,757 | | | 2,392 | | | (6,539) | | | — | | | 26,006 | |
| Loss on derivatives | | — | | | — | | | — | | | (22,831) | | | — | | | (22,831) | |
| Reorganization items, net | | — | | | — | | | — | | | (1,136) | | | — | | | (1,136) | |
| Interest, net | | — | | | — | | | (1,057) | | | (1,649) | | | — | | | (2,706) | |
| Other | | 57 | | | 5 | | | 12 | | | 2 | | | — | | | 76 | |
| Income (loss) before income taxes | | $ | 27,453 | | | $ | 2,762 | | | $ | 1,347 | | | $ | (32,153) | | | $ | — | | | $ | (591) | |
_______________________
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.
