UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2021
OR
☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission file number: 1-9260
UNIT CORPORATION
(Exact name of registrant as specified in its charter)
| Delaware | 73-1283193 | ||||||||||||||||
| (State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) | ||||||||||||||||
| 8200 South Unit Drive, | Tulsa, | Oklahoma | US | 74132 | |||||||||||||
| (Address of principal executive offices) | (Zip Code) | ||||||||||||||||
(Registrant’s telephone number, including area code) (918) 493-7700
Securities registered pursuant to Section 12(b) of the Act:
| Title of each class | Trading Symbol(s) | Name of each exchange on which registered | ||||||
| N/A | N/A | N/A | ||||||
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No ☒
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes ☒ No ☐
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☐ No ☒ *
* Effective January 1, 2021, the registrant's obligations to file reports under Section 15(d) of the Exchange Act were automatically suspended.
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer”, “accelerated filer”, “smaller reporting company”, and "emerging growth company" in Rule 12b-2 of the Exchange Act.
Large accelerated filer ☐ Accelerated filer ☐ Non-accelerated filer ☒
Smaller reporting company ☒ Emerging growth company ☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☐
Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. Yes ☒ No ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act) Yes ☐ No ☒
As of June 30, 2021, the aggregate market value of the voting and non-voting common equity (based on the closing price of the stock on the OTC Pink on June 30, 2021) held by non-affiliates was approximately $127.7 million. Determination of stock ownership by non-affiliates was made solely for the purpose of this requirement, and the registrant is not bound by these determinations for any other purpose.
As of March 31, 2022, 10,050,561 shares of the registrant’s common stock were outstanding.
FORM 10-K
UNIT CORPORATION
TABLE OF CONTENTS
| Page | ||||||||
| PART I | ||||||||
| Item 1. | ||||||||
| Item 1A. | ||||||||
| Item 1B. | ||||||||
| Item 2. | ||||||||
| Item 3. | ||||||||
| Item 4. | ||||||||
| PART II | ||||||||
| Item 5. | ||||||||
| Item 6. | ||||||||
| Item 7. | ||||||||
| Item 7A. | ||||||||
| Item 8. | ||||||||
| Item 9. | ||||||||
| Item 9A. | ||||||||
| Item 9B. | ||||||||
| Item 9C. | ||||||||
| PART III | ||||||||
| Item 10. | ||||||||
| Item 11. | ||||||||
| Item 12. | ||||||||
| Item 13. | ||||||||
| Item 14. | ||||||||
| PART IV | ||||||||
| Item 15. | ||||||||
| Item 16. | ||||||||
The following are explanations of some of the industry and general terms we use in this report:
ARO – Asset retirement obligations.
ASC – FASB Accounting Standards Codification.
ASU – Accounting Standards Update.
Bbl – Barrel, or 42 U.S. gallons liquid volume.
Boe – Barrel of oil equivalent. Determined using the ratio of six Mcf of natural gas to one barrel of crude oil or NGLs.
Btu – British thermal unit, used in gas volumes. Btu is used to refer to the natural gas required to raise the temperature of one pound of water by one-degree Fahrenheit at one atmospheric pressure.
Development drilling – The drilling of a well within the proven area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.
DD&A – Depreciation, depletion, and amortization.
FASB – Financial and Accounting Standards Board.
FERC – Federal Energy Regulatory Commission.
Finding and development costs – Costs associated with acquiring and developing proved natural gas and oil reserves capitalized under generally accepted accounting principles, including any capitalized general and administrative expenses.
G&A – General and administrative expenses.
Gross acres or gross wells – The total acres or wells in which a working interest is owned.
IF – Inside FERC (U.S. Federal Energy Regulatory Commission).
LIBOR – London Interbank Offered Rate.
LOE – Lease operating expense.
MBbls – Thousand barrels of crude oil or other liquid hydrocarbons.
Mcf – Thousand cubic feet of natural gas.
MBoe – Thousand barrels of oil equivalent.
MMBtu – Million Btu’s.
MMcf – Million cubic feet of natural gas.
MMcfe – Million cubic feet of natural gas equivalent. It is determined using the ratio of one barrel of crude oil or NGLs to six Mcf of natural gas.
Net acres or net wells – The total fractional working interests owned in gross acres or gross wells.
NGLs – Natural gas liquids.
NYMEX – The New York Mercantile Exchange.
OPEC – The Organization of Petroleum Exporting Countries.
Play – A term applied by geologists and geophysicists identifying an area with potential oil and gas reserves.
Producing property – A natural gas or oil property with existing production.
Proved developed reserves – Reserves expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and through installed extraction equipment and infrastructure operational at the time of the reserves estimate. For additional information, see the SEC’s definition in Rule 4-10(a)(6) of Regulation S-X.
Proved reserves – Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs and under existing economic conditions, operating methods, and government regulations – prior to the time at which the contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. For additional information, see the SEC’s definition in Rule 4-10(a)(22)(i) through (v) of Regulation S-X.
Proved undeveloped reserves – Proved reserves expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. For additional information, see the SEC’s definition in Rule 4-10(a)(431) of Regulation S-X.
Reasonable certainty (regarding reserves) – If deterministic methods are used, reasonable certainty means high confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate.
Reliable technology – A grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.
Ryder Scott – Ryder Scott Company, L.P., independent petroleum consultants.
SARs – Stock appreciation rights.
SEC – Securities and Exchange Commission.
SOFR - Secured Overnight Financing Rate.
Undeveloped acreage – Lease acreage on which wells have not been drilled or completed to the point that would permit the production of economic quantities of natural gas or oil regardless of whether the acreage contains proved reserves.
The following are explanations of some of the terms we use that are specific to us:
2011 Notes – The $250.0 million 6.625% senior subordinated notes due 2021 issued in 2011.
2012 Notes – The $400.0 million 6.625% senior subordinated notes due 2021 issued in 2012.
BOKF – Bank of Oklahoma Financial Corporation.
Chapter 11 Cases – The cases filed by the Debtors on May 22, 2020 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). 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 emerged from bankruptcy on September 3, 2020.
Debtors – Unit and its wholly owned subsidiaries UDC, UPC, 8200 Unit, Unit Drilling Colombia, and Unit Drilling USA, all of which were parties to the Chapter 11 Cases.
DIP Credit Agreement – The credit agreement the company entered into on May 27, 2020 with the lenders under its then existing Unit credit agreement.
Effective Date – September 3, 2020, the date the Debtors emerged from bankruptcy.
Exit Credit Agreement – The credit agreement the company entered into on September 3, 2020 with the lenders replacing the DIP Credit Agreement and the Unit credit agreement.
MSA – The Amended and Restated Master Services and Operating Agreement for Superior.
New Common Stock – The company common stock issued under the Plan and following the Effective Date.
Plan – The Chapter 11 plan of reorganization (including all exhibits and schedules, as amended, supplemented, or modified) and the related disclosure statement we filed with the bankruptcy court on June 9, 2020.
Predecessor – The company before the Effective Date.
Old Common Stock – The company's common stock existing immediately before the company filed for bankruptcy protection. As part of the Plan, the Old Common Stock was terminated as of the Effective Date.
Predecessor Period – Relates to the financial position and results of operations of the company for the period of January 1, 2020 through August 31, 2020.
Successor Period – Relates to the financial position and results of operations of the company for the period of September 1, 2020 through December 31, 2021.
Superior – Our 50% owned subsidiary Superior Pipeline Company, L.L.C., and its subsidiaries.
The Notes – Collectively, the 2011 Notes and 2012 Notes.
FORWARD-LOOKING STATEMENTS/CAUTIONARY STATEMENTS
This report contains “forward-looking statements” – meaning, statements related to future events within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Other than statements of historical facts, included or incorporated by reference in this document addressing activities, events, or developments we expect or anticipate will or may occur, are forward-looking statements. Forward-looking statements often contain words such as “believes,” “intends,” “expects,” “anticipates,” “projects,” “estimates,” “predicts,” and similar expressions. This report modifies and supersedes documents filed by us before this report. Also, certain information we file with the SEC will automatically update and supersede information in this report.
Forward-looking statements are not guarantees of performance. They involve risks, uncertainties, and assumptions. Future actions, conditions or events, and future results may differ materially from those expressed in our forward-looking statements. Many factors that will determine these results are beyond our ability to control or accurately predict. Specific factors that could cause actual results to differ from those in our forward-looking statements include:
•the amount and nature of our future capital expenditures and how we expect to fund our capital expenditures;
•prices for oil, NGLs, and natural gas;
•demand for oil, NGLs, and natural gas;
•our exploration and drilling prospects;
•the estimates of our proved oil, NGLs, and natural gas reserves;
•oil, NGLs, and natural gas reserve potential;
•development and infill drilling potential;
•expansion and other development trends in the oil and natural gas industry;
•our business strategy;
•our plans to maintain or increase the production of oil, NGLs, and natural gas;
•our ability, and the market's receptiveness, to execute a strategic divestiture process;
•our ability to utilize the benefits of net operating losses and other deferred tax assets against potential future taxable income, including those that may be generated by a strategic divestiture process;
•our ability to retain or recruit key personnel throughout a strategic divestiture process;
•the number of gathering systems and processing plants we may plan to construct or acquire;
•volumes and prices for the natural gas we gather and process;
•expansion and growth of our business and operations;
•demand for our drilling rigs and the rates we charge for the rigs;
•our belief that the outcome of our legal proceedings will not materially affect our financial results;
•our ability to timely secure third-party services used in completing our wells;
•our ability to transport or convey our oil, NGLs, or natural gas production to existing pipeline systems;
•the impact of federal and state legislative and regulatory actions affecting our costs and increasing operating restrictions or delays and other adverse impacts on our business;
•the possibility of security threats, including terrorist attacks and cybersecurity breaches, against or otherwise affecting our facilities and systems;
•any projected production guidelines we may issue;
•our anticipated capital budgets;
•our financial condition and liquidity;
•the number of wells our oil and natural gas segment plans to drill;
•our estimates of any ceiling test write-downs or other potential asset impairments we may have to record in future periods; and
•our ability to carry out our post reorganization plans.
These statements are based on our assumptions and analyses considering our experience and our perception of historical trends, current conditions, expected future developments, and other factors we believe are appropriate in the circumstances. Whether actual results and developments will meet our expectations and predictions is subject to risks and uncertainties, any one or combination of which could cause our actual results to differ materially from our expectations and predictions. Some of these risks and uncertainties are:
•the risk factors discussed in this document and the documents (if any) we incorporate by reference;
•general economic, market, or business conditions;
•the availability and nature of (or lack of) business opportunities we pursue;
•demand for our land drilling services;
•changes in laws and regulations;
•changes in the current geopolitical situation, such as the current conflict occurring between Russia and Ukraine;
•risks relating to financing, including restrictions in our debt agreements and availability and cost of credit;
•risks associated with future weather conditions;
•decreases or increases in commodity prices;
•the amount and terms of our debt;
•future compliance with covenants under our credit agreements;
•pandemics, epidemics, outbreaks, or other public health events, such as COVID-19; and
•other factors, most of which are beyond our control.
You should not construe this list to be exhaustive. We believe the forward-looking statements in this report are reasonable. However, there is no assurance that the actions, events, or results expressed in forward-looking statements will occur, or if any of them do, of their timing or what impact they will have on our results of operations or financial condition. Because of these uncertainties, you should not put undue reliance on any forward-looking statements. Except as required by law, we disclaim any obligation to update forward-looking information and to release publicly the results of any future revisions we may make to forward-looking statements to reflect events or circumstances after this document to reflect incorrect assumptions or unanticipated events.
Additional discussion of factors that may affect our forward-looking statements appear elsewhere in this report, including in Item 1A “Risk Factors,” Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and Item 7A “Quantitative and Qualitative Disclosures About Market Risk-Energy Commodity Market Risk.”
UNIT CORPORATION
Annual Report
For The Year Ended December 31, 2021
PART I
Item 1. Business
Unless otherwise indicated or required by the context, the terms “company,” “Unit,” “us,” “our,” “we,” and “its” refer to Unit Corporation or, as appropriate, one or more of its subsidiaries. References to our Mid-Stream segment refer to Superior Pipeline Company, L.L.C. (and its subsidiaries) of which we own 50%.
Our executive offices are at 8200 South Unit Drive, Tulsa, Oklahoma 74132; our telephone number is (918) 493-7700.
Information regarding our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to these reports, will be provided free in print to any shareholders who request them. They are also available on our website at www.unitcorp.com, as soon as reasonably possible after we electronically file these reports with or furnish them to the SEC. The SEC maintains a website at www.sec.gov that contains reports, proxy and information statements, and other information about us we file electronically with the SEC.
Our corporate governance guidelines and code of ethics are available for free on our website at www.unitcorp.com or in print to any shareholder who requests them. We may occasionally provide important disclosures to investors by posting them in the investor information section of our website, as allowed by SEC rules.
GENERAL
We were founded in 1963 as an oil and natural gas contract drilling company. Today, besides our drilling operations, we have operations in the exploration and production and mid-stream areas. 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 account. 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.
•Contract Drilling – carried out by our subsidiary Unit Drilling Company. This segment contracts to drill onshore oil and natural gas wells for others and our account.
•Mid-Stream – carried out by Superior. This segment buys, sells, gathers, processes, and treats natural gas for third parties and our account.
Each company may conduct operations through subsidiaries of its own. We also have several other subsidiaries, none of which conduct material operations.
1
This table provides certain information about our assets as of December 31, 2021:
| Oil and Natural Gas | |||||
| Total number of wells in which we own an interest | 5,253 | ||||
| Contract Drilling | |||||
| Total number of drilling rigs available for use | 21 | ||||
| Mid-Stream | |||||
| Number of natural gas treatment plants we own | 3 | ||||
| Number of processing plants we own | 12 | ||||
Number of natural gas gathering systems we own | 18 | ||||
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 (Bankruptcy 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). 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 September 3, 2020, the Debtors emerged from the Chapter 11 Cases.
2021 SEGMENT OPERATIONS HIGHLIGHTS
Oil and Natural Gas
•Revenues before eliminations increased by 69% from 2020 primarily due to higher average commodity pricing, partially offset by lower production volumes.
•Operating costs before eliminations decreased 43% from 2020.
•Capital expenditures increased 89% from 2020.
Contract Drilling
•Revenues decreased 18% from 2020 primarily due to the absence of 2020 rig termination and standby fees. Average rig utilization increased 8% to 10.9 rigs during 2021 while there was a 4% decrease in average dayrate to $17,987.
•Operating costs decreased 7% from 2020 primarily due to a decrease in rig fleet from 58 to 21 in 2021.
Mid-Stream
•Revenues before eliminations increased 87% and operating expenses before eliminations increased 114% from 2020 primarily due to higher commodity pricing, partially offset by lower volumes.
•Acquired a cryogenic processing plant, approximately 1,620 miles of low-pressure gathering pipeline, and related compressor stations located in southern Kansas in November 2021.
FINANCIAL INFORMATION ABOUT SEGMENTS
See Note 23 - Industry Segment Information of our Notes to Consolidated Financial Statements in Item 8 of this report for information about each of our segment’s revenues, profits or losses, and total assets.
OIL AND NATURAL GAS
General. All our oil and natural gas properties are in the United States. Our producing oil and natural gas properties, unproved properties, and related assets are mainly in Oklahoma and Texas, and to a lesser extent Kansas, Louisiana, Montana, North Dakota, Utah, and Wyoming.
2
When we are the operator of a property, we try to use one of our drilling rigs to drill any wells on the property, and we also use our mid-stream segment to gather our gas if it is economical to do so.
This table presents certain information regarding our oil and natural gas operations as of December 31, 2021:
Number of Gross Wells | Number of Net Wells | Number of Gross Wells in Process | Number of Net Wells in Process | 2021 Average Net Daily Production | |||||||||||||||||||||||||||||||||||||
Natural Gas (Mcf) | Oil (Bbls) | NGLs (Bbls) | |||||||||||||||||||||||||||||||||||||||
| Total | 5,253 | 1,450.67 | 5 | 0.02 | 79,485 | 4,424 | 7,189 | ||||||||||||||||||||||||||||||||||
Dispositions. 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.
On March 8, 2022, the company closed on the sale of wells and related leases located near the Oklahoma Panhandle for $5.0 million, subject to customary closing and post-closing adjustments with an effective date of December 1, 2021. No gain or loss was recognized as the sale of these assets did not result in a significant alteration of the full cost pool.
On August 16, 2021, the company closed on the sale of substantially all of our wells and related leases located near Oklahoma City, Oklahoma for $19.5 million, subject to customary closing and post-closing adjustments. No gain or loss was recognized as the sale of these assets did not result in a significant alteration of the full cost pool.
On May 6, 2021, the company closed on the sale of substantially all of our wells and related leases located in Reno and Stafford Counties, Kansas for $7.1 million, subject to customary closing and post-closing adjustments. No gain or loss was recognized as the sale of these assets did not result in a significant alteration of the full cost pool.
We also sold $5.0 million of other non-core oil and natural gas assets, net of related expenses, during the year ended December 31, 2021. No gain or loss was recognized as the sale of these assets did not result in a significant alteration of the full cost pool.
3
Well and Leasehold Data. The following tables identify certain information regarding our oil and natural gas exploratory and development drilling operations:
| Successor | Predecessor | |||||||||||||||||||||||||||||||||||||
| Year Ended December 31, 2021 | Four Months Ended December 31, 2020 | Eight Months Ended August 31, 2020 | ||||||||||||||||||||||||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||||||||||||||||
| Wells drilled: | ||||||||||||||||||||||||||||||||||||||
| Development: | ||||||||||||||||||||||||||||||||||||||
| Oil | 10 | 3.7 | 2 | 0.3 | 10 | 0.1 | ||||||||||||||||||||||||||||||||
| Natural Gas | — | — | 1 | — | 12 | 0.3 | ||||||||||||||||||||||||||||||||
| Dry | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||
| Total development | 10 | 3.7 | 3 | 0.3 | 22 | 0.4 | ||||||||||||||||||||||||||||||||
| Exploratory: | ||||||||||||||||||||||||||||||||||||||
| Oil | 13 | 0.7 | — | — | — | — | ||||||||||||||||||||||||||||||||
| Natural gas | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||
| Dry | 1 | — | — | — | — | — | ||||||||||||||||||||||||||||||||
| Total exploratory | 14 | 0.7 | — | — | — | — | ||||||||||||||||||||||||||||||||
| Total wells drilled | 24 | 4.4 | 3 | 0.3 | 22 | 0.4 | ||||||||||||||||||||||||||||||||
| Year Ended December 31, | |||||||||||||||||||||||
| 2021 | 2020 | ||||||||||||||||||||||
| Gross | Net | Gross | Net | ||||||||||||||||||||
Wells producing or capable of producing: | |||||||||||||||||||||||
| Oil | 736 | 141.2 | 1,534 | 604.8 | |||||||||||||||||||
| Natural gas | 2,380 | 649.0 | 4,601 | 1,598.3 | |||||||||||||||||||
| Total | 3,116 | 790.2 | 6,135 | 2,203.1 | |||||||||||||||||||
We did not develop any previously booked proved undeveloped oil and natural gas reserves in 2021 or 2020.
The following table summarizes our leasehold acreage at December 31, 2021:
| Developed | Undeveloped | Total | |||||||||||||||||||||||||||||||||
| Gross | Net | Gross | Net (1) | Gross | Net | ||||||||||||||||||||||||||||||
| Total | 489,308 | 270,457 | 8,470 | 4,212 | 497,778 | 274,669 | |||||||||||||||||||||||||||||
_________________________
1.Approximately 100% of the net undeveloped acres are covered by leases that will expire in the years 2022—2024 unless drilling or production extends those leases.
4
Price and Production Data. The following tables identify the average sales price, production volumes, and average production cost per equivalent barrel for our oil, NGLs, and natural gas production for the periods indicated:
| Successor | Predecessor | |||||||||||||||||||
| Year Ended December 31, 2021 | Four Months Ended December 31, 2020 | Eight Months Ended August 31, 2020 | ||||||||||||||||||
| Average sales price per barrel of oil produced: | ||||||||||||||||||||
| Price before derivatives | $ | 66.50 | $ | 39.23 | $ | 35.14 | ||||||||||||||
| Effect of derivatives | (16.47) | (1.94) | (3.16) | |||||||||||||||||
| Price including derivatives | $ | 50.03 | $ | 37.29 | $ | 31.98 | ||||||||||||||
| Average sales price per barrel of NGLs produced: | ||||||||||||||||||||
| Price before derivatives | $ | 23.41 | $ | 9.28 | $ | 4.83 | ||||||||||||||
| Effect of derivatives | — | — | — | |||||||||||||||||
| Price including derivatives | $ | 23.41 | $ | 9.28 | $ | 4.83 | ||||||||||||||
| Average sales price per Mcf of natural gas produced: | ||||||||||||||||||||
| Price before derivatives | $ | 3.55 | $ | 1.91 | $ | 1.11 | ||||||||||||||
| Effect of derivatives | (0.62) | 0.01 | 0.03 | |||||||||||||||||
| Price including derivatives | $ | 2.93 | $ | 1.92 | $ | 1.14 | ||||||||||||||
| Successor | Predecessor | |||||||||||||||||||
| Year Ended December 31, 2021 | Four Months Ended December 31, 2020 | Eight Months Ended August 31, 2020 | ||||||||||||||||||
| Oil production (MBbls): | ||||||||||||||||||||
| Jazz Wilcox field | 126 | 61 | 184 | |||||||||||||||||
| Buffalo Wallow field | 108 | 48 | 118 | |||||||||||||||||
| Mendota field | 88 | 35 | 76 | |||||||||||||||||
| All other fields | 1,293 | 482 | 1,184 | |||||||||||||||||
| Total oil production | 1,615 | 626 | 1,562 | |||||||||||||||||
| NGLs production (MBbls): | ||||||||||||||||||||
| Jazz Wilcox field | 433 | 206 | 601 | |||||||||||||||||
| Buffalo Wallow field | 581 | 261 | 618 | |||||||||||||||||
| Mendota field | 437 | 155 | 327 | |||||||||||||||||
| All other fields | 1,173 | 423 | 853 | |||||||||||||||||
| Total NGLs production | 2,624 | 1,045 | 2,399 | |||||||||||||||||
| Natural gas production (MMcf): | ||||||||||||||||||||
| Jazz Wilcox field | 5,169 | 2,414 | 7,003 | |||||||||||||||||
| Buffalo Wallow field | 5,860 | 2,651 | 6,214 | |||||||||||||||||
| Mendota field | 2,623 | 967 | 2,059 | |||||||||||||||||
| All other fields | 15,360 | 4,974 | 11,287 | |||||||||||||||||
| Total natural gas production | 29,012 | 11,006 | 26,563 | |||||||||||||||||
| Total production (MBoe): | ||||||||||||||||||||
| Jazz Wilcox field | 1,420 | 669 | 1,952 | |||||||||||||||||
| Buffalo Wallow field | 1,665 | 751 | 1,772 | |||||||||||||||||
| Mendota field | 963 | 352 | 746 | |||||||||||||||||
| All other fields | 5,026 | 1,734 | 3,918 | |||||||||||||||||
| Total production | 9,074 | 3,506 | 8,388 | |||||||||||||||||
Average production cost per equivalent Bbl (1) | $ | 5.56 | $ | 5.27 | $ | 4.86 | ||||||||||||||
_______________________
1.Excludes ad valorem taxes and gross production taxes.
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Our Buffalo Wallow field in Hemphill County, Texas, contained 20% and 16% of our total proved reserves in 2021 and 2020, respectively, expressed on an oil-equivalent barrels basis. Our Mendota field, in the Granite Wash play in the Texas Panhandle, contained 15% and 16% of our total proved reserves for those same years also expressed on an oil-equivalent barrels basis. There are no other fields that accounted for over 15% of our proved reserves.
Oil, NGLs, and Natural Gas Reserves. The table below identifies our estimated proved developed and undeveloped oil, NGLs, and natural gas reserves:
| Year Ended December 31, 2021 | |||||||||||||||||||||||
Oil (MBbls) | NGLs (MBbls) | Natural Gas (MMcf) | Total Proved Reserves (MBoe) | ||||||||||||||||||||
| Total proved developed | 9,019 | 21,525 | 220,640 | 67,317 | |||||||||||||||||||
| Total proved undeveloped | — | — | — | — | |||||||||||||||||||
| Total proved | 9,019 | 21,525 | 220,640 | 67,317 | |||||||||||||||||||
Oil, NGLs, and natural gas reserves cannot be measured exactly. Estimates of those reserves require extensive judgments of reservoir engineering data and are generally less precise than other estimates made in financial disclosures.
Company Reserve Estimation and Technical Qualifications
Our Reservoir Engineering department is responsible for reserve determination for the wells in which we have an interest. Their primary objective is to estimate the wells' future reserves and future net value to us. Data is incorporated from multiple sources including geological, production engineering, marketing, production, land, and accounting departments. The engineers review this information for accuracy as it is incorporated into the reservoir engineering database. Management reviews our internal controls to help provide assurance all the data has been provided. New well reserve estimates are provided to management and the respective operational divisions for additional scrutiny. Major reserve changes on existing wells are reviewed regularly with the operational divisions to confirm completeness and accuracy. As the external audit is being completed, the reservoir department reviews all properties for accuracy of forecasting.
Responsibility for overseeing the preparation of our reserve report is shared by our reservoir engineers Derek Smith and Troy Pickens.
Mr. Smith received a Bachelor of Science in Petroleum Engineering with a Minor in Business from the University of Tulsa in 2005. He then worked for Apache Corporation through 2008 and joined Unit in 2009 as a Corporate Reserves Engineer involved in reserve evaluation, acquisition appraisals, and prospect reviews with increasing levels of responsibility. In 2020, he was given the responsibility of managing the Corporate Reserves. He has been a member of SPE since 2000 and joined the SPEE in 2018.
Mr. Pickens earned a Bachelor of Science degree in Mechanical Engineering with Minors in Math and Entrepreneurship from Baylor University in 2014. He began employment with Unit as an Engineering Intern in the Summers of 2012 and 2013 and joined the company full time as a Production Engineer in 2014. He worked as a production engineer over various company assets with increasing levels of responsibility through 2019. In 2019 he transitioned into a Reservoir Engineering role, where he has been involved in reserve evaluation, project and asset development planning, and acquisition and divestiture assessment.
As part of their continuing education Mr. Smith and Mr. Pickens have attended various seminars and forums to enhance their understanding of current standards and issues for reserves presentation. These forums have included those sponsored by various professional societies and professional service firms including Ryder Scott.
Ryder Scott Audit and Technical Qualifications
We use Ryder Scott to audit the reserves prepared by our reservoir engineers. Ryder Scott has been providing petroleum consulting services internationally since 1937. Their summary report is attached as Exhibit 99.1 to this Form 10-K. The wells or locations for which reserve estimates were audited were taken from our reserve and income projections as of December 31, 2021, and comprised approximately 85% of the total proved developed future net income discounted at 10% (based on the SEC's unescalated pricing policy).
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Mr. Robert J. Paradiso was the primary technical person responsible for overseeing the estimate of the reserves prepared by Ryder Scott.
Mr. Paradiso, an employee of Ryder Scott since 2008, is a Vice President and serves as Project Coordinator, responsible for coordinating and supervising staff and consulting engineers in ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Paradiso served in several engineering positions with Getty Oil Company, Texaco, Union Texas Petroleum, Amax Oil and Gas, Inc., Norcen Explorer, Inc., Amerac Energy Corporation, Halliburton Energy Services, Santa Fe Snyder Corp., and Devon Energy Corporation.
Mr. Paradiso earned a Bachelor of Science degree in Petroleum Engineering from Texas Tech University in 1979 and is a registered Professional Engineer in the State of Texas. He is also a member of the Society of Petroleum Engineers (SPE).
Besides gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires at least fifteen hours of continuing education annually, including at least one hour in professional ethics, which Mr. Paradiso fulfills. Based on his educational background, professional training and over 41 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Paradiso has attained the professional qualifications as a Reserves Estimator and Reserves Auditor in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the SPE as of June 2019. For more information regarding Mr. Paradiso’s geographic and job-specific experience, please refer to the Ryder Scott Company website at http://www.ryderscott.com/Company/Employees.
Definitions and Other Proved Reserve Information.
For proved reserves, the area of the reservoir considered as "proved" includes:
•The area identified by drilling and limited by any fluid contacts, and
•Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with the reservoir and to contain economically producible oil or gas based on available geosciences and engineering data.
Absent data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as incurred in a well penetration unless geosciences, engineering, or performance data and reliable technology establish a lower contact with reasonable certainty.
Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geosciences, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:
•Successful testing by a pilot project in an area of the reservoir with properties no more favorable than the reservoir as a whole;
•The operation of an installed program in the reservoir or other evidence using reliable technology establishes reasonable certainty of the engineering analysis on which the project or program was based; and
•The project has been approved for development by all necessary parties and entities, including governmental entities.
Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price used is the average of the prices over the 12 months before the ending date of the period covered by the report and is an unweighted arithmetic average of the first day of the month price for each month within the period, unless prices are defined by contractual arrangements, excluding escalations based on future conditions.
Proved Undeveloped Reserves. As of December 31, 2021, we had no proved undeveloped reserves.
Our estimated proved reserves and the standardized measure of discounted future net cash flows of the proved reserves at December 31, 2021 and 2020, the changes in quantities, and standardized measure of those reserves for the years then ended, are shown in the Supplemental Oil and Gas Disclosures in Item 8 of this report.
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Contracts. Our oil production is sold at or near our wells under purchase contracts at prevailing prices under arrangements customary in the oil industry. Our natural gas production is sold to intrastate and interstate pipelines and independent marketing firms under contracts with terms generally ranging from one month to a year. Few of these contracts contain provisions for readjustment of price as most are market sensitive.
Customers. One customer accounted for 11% of our oil and natural gas revenues during the year ended December 31, 2021 and no other company accounted for over 10% of our oil and natural gas revenues besides our mid-stream segment. Our mid-stream segment purchased $48.0 million of our natural gas and NGLs production and provided gathering and transportation services of $3.3 million. Intercompany revenue from services and purchases of production between our mid-stream segment and our oil and natural gas segment has been eliminated in our consolidated financial statements.
CONTRACT DRILLING
General. Our contract drilling business is conducted through Unit Drilling Company. Through this company we drill onshore oil and natural gas wells for ourselves and for others. Our drilling operations are mainly in Oklahoma, Texas, and New Mexico.
The following table identifies certain information about our contract drilling segment assets and activity:
| Successor | Predecessor | |||||||||||||||||||
| Year Ended December 31, 2021 | Four Months Ended December 31, 2020 | Eight Months Ended August 31, 2020 | ||||||||||||||||||
| Number of drilling rigs available for use | 21 | 58 | 58 | |||||||||||||||||
| Average number of drilling rigs owned | 30 | 58 | 58 | |||||||||||||||||
| Average number of drilling rigs utilized | 10.9 | 7.2 | 11.5 | |||||||||||||||||
Utilization rate (1) | 36 | % | 12 | % | 20 | % | ||||||||||||||
Average revenue per day (2) | $ | 19,097 | $ | 21,974 | $ | 26,106 | ||||||||||||||
| Total footage drilled (feet in 1,000’s) | 4,487 | 1,062 | 2,999 | |||||||||||||||||
| Number of wells drilled | 251 | 67 | 179 | |||||||||||||||||
_________________________
1.Utilization rate is determined by dividing the average number of drilling rigs used by the average number of drilling rigs available for use during the year. See Drilling Rig Fleet below for discussion on the 2021 reduction in drilling rigs available for use.
2.Represents the total revenues from our contract drilling segment divided by the total days our drilling rigs were used during the year.
Description and Location of Our Drilling Rigs. An on-shore drilling rig is composed of major equipment components like engines, drawworks or hoists, derrick or mast, substructure, mud pumps, blowout preventers, top drives, and drill pipe. Because of the normal wear and tear from operating 24 hours a day, several of the major components, like engines, mud pumps, top drives, and drill pipe, must be replaced or overhauled periodically. Other major components, like the substructure, mast, and drawworks, can be used for extended periods with proper inspections and maintenance. We also own additional equipment used in operating our drilling rigs, including iron roughnecks, automated catwalks, skidding systems, large air compressors, trucks, and other support equipment. The maximum depth capacities of our various drilling rigs range from 9,500 to 40,000 feet allowing us to cover a wide range of our customers' drilling requirements.
The following table shows certain information about our drilling rigs as of December 31, 2021:
Contracted Rigs | Non-Contracted Rigs | Total Rigs | Average Rated Drilling Depth (ft) | ||||||||||||||||||||
| Drilling Rigs | 16 | 5 | 21 | 20,238 | |||||||||||||||||||
Fluctuating commodity prices directly affect the number of drilling rigs we can put to work, both positively and negatively. Generally, sustained higher commodity prices lead to greater demand for drilling rigs, while demand and rates tends to fall as commodity prices decline for any extended period. Drilling rig utilization increased during 2021 as commodity prices increased. The number of drilling rigs we can work also depends on several conditions besides demand, including the availability of qualified labor as well as the availability of needed drilling supplies and equipment.
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The following table shows the average number of our drilling rigs working by quarter for the years indicated:
| 2021 | 2020 | ||||||||||
| First quarter | 9.4 | 18.7 | |||||||||
| Second quarter | 10.0 | 9.1 | |||||||||
| Third quarter | 11.0 | 5.1 | |||||||||
| Fourth quarter | 13.2 | 7.6 | |||||||||
Drilling Rig Fleet. We reduced the number of drilling rigs available for use from 58 at December 31, 2020 to 21 during the second quarter of 2021 in order to focus on utilization of our BOSS drilling rigs and certain SCR rigs that are either currently under contract or candidates for future upgrades.
Dispositions. We sold non-core contract drilling assets for proceeds of $12.7 million, net of related expenses, resulting in net gains of $10.1 million during the year ended December 31, 2021.
Drilling Contracts. Our third-party drilling contracts are generally obtained through competitive bidding on a well-by-well basis. Contract terms and payment rates vary depending on the type of contract used, the duration of the work, the equipment and services supplied, and other matters. We pay certain operating expenses, including the wages of our drilling rig personnel, maintenance expenses, and incidental drilling rig supplies and equipment. The contracts are usually subject to early termination by the customer subject to the payment of a fee. Our contracts also contain provisions regarding indemnification against certain types of claims involving injury to persons, property, and for acts of pollution. The specific terms of these indemnifications are negotiated on a contract-by-contract basis.
Most of our drilling contracts during 2021 and 2020 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 daywork compensation is based on a negotiated rate to be paid for each day the drilling rig is used.
Most of our contracts are term contracts, with the rest being well-to-well contracts. Term contracts can range from months to multiple years and the rates can either be fixed throughout the term or allow for periodic adjustments.
Customers. Five customers accounted for 79% of our contract drilling revenues during the year ended December 31, 2021. No other third-party customer accounted for 10% or more of our contract drilling revenues.
Our contract drilling segment may also provide drilling services for our oil and natural gas segment. The contract drilling segment did not drill any wells for our oil and natural gas segment in 2021. Depending on the timing of the drilling services performed on our properties, those services may be deemed, for financial reporting purposes, to be associated with acquiring an ownership interest in the property. 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.
MID-STREAM
General. Our mid-stream operations are conducted through Superior Pipeline Company, L.L.C. and its subsidiaries, of which we presently own a 50% interest. Superior's operations consist of buying, selling, gathering, processing, and treating natural gas. It operates 3 natural gas treatment plants, 12 processing plants, 18 active gathering systems, and approximately 3,822 miles of pipeline. Superior and its subsidiaries operate in Oklahoma, Texas, Kansas, Pennsylvania, and West Virginia.
Superior is governed and managed under the Amended and Restated Limited Liability Company Agreement (Agreement) and a Management Services Agreement (MSA). The MSA is between our wholly-owned subsidiary, SPC Midstream Operating, L.L.C. (the Operator) and Superior. As the Operator, we provide services, such as operations and maintenance support, accounting, legal, and human resources to Superior for a monthly service fee of $0.3 million.
The Agreement specifies how future distributions are to be allocated among 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.
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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 December 31, 2021, liquidation distributions paid first to SP Investor of $361.7 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 $361.7 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.
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 will no longer consolidate the financial position, operating results, and cash flows of Superior as of March 1, 2022. We will subsequently account for our investment in Superior as an equity method investment under the HLBV method.
The following table presents certain information regarding our mid-stream segment for the periods indicated:
| Successor | Predecessor | |||||||||||||||||||
| Year Ended December 31, 2021 | Four Months Ended December 31, 2020 | Eight Months Ended August 31, 2020 | ||||||||||||||||||
| Gas gathered—Mcf/day | 319,394 | 324,892 | 388,506 | |||||||||||||||||
| Gas processed—Mcf/day | 130,000 | 135,615 | 158,031 | |||||||||||||||||
| NGLs sold—gallons/day | 442,796 | 441,761 | 612,301 | |||||||||||||||||
Dispositions and Acquisitions. In November 2021, we closed on an acquisition for $13.0 million, subject to customary closing and post-closing adjustments, that included a cryogenic processing plant, approximately 1,620 miles of low-pressure gathering pipeline, and related compressor stations located in southern Kansas.
Impairment. In December 2021, we determined that the carrying value of a gathering system in Pennsylvania was not recoverable and exceeded its estimated fair value due to unfavorable forecasted economics. We recorded non-cash impairment charges of $10.7 million based on the estimated fair value of the asset group.
Contracts. Our mid-stream segment provides its customers with a full range of gathering, processing, and treating services. These services are usually provided to each customer under long-term contracts (more than one year), but we also have short-term contracts. Our customer agreements include these types of contracts:
•Fee-Based Contracts. These contracts provide for a set fee for gathering, transporting, compressing, and treating services. Our mid-stream’s revenue is a function of the volume of natural gas and is not directly dependent on the value of natural gas. For the year ended December 31, 2021, 76% of our mid-stream segment’s total volumes and 73% of its operating margins (as defined below) were under fee-based contracts.
•Commodity-Based Contracts. These contracts consist of several contract structure types. Under these contract structures, our mid-stream segment purchases the raw well-head natural gas and settles with the producer at a stipulated price while retaining all sales proceeds from third parties or retains a negotiated percentage of the sales proceeds from the residue natural gas and NGLs it gathers and processes, with the remainder being paid to the producer. For the year ended December 31, 2021, 24% of our mid-stream segment’s total volumes and 27% of operating margins (as defined below) were under commodity-based contracts.
For each of the above contract types, operating margin is defined as total operating revenues less operating expenses and does not include depreciation, amortization, and impairment, general and administrative expenses, interest expense, or income taxes.
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Customers. Three customers accounted for 58% of our mid-stream revenues. We believe that there are other customers available to purchase our natural gas and NGLs if we were to lose these customers. Superior purchased $48.0 million of our oil and natural gas segment's natural gas and NGLs production, and provided gathering and transportation services of $3.3 million. Intercompany revenue from services and purchases of production between Superior and our oil and natural gas segment has been eliminated in our consolidated financial statements.
COMPETITION
All our businesses are highly competitive and price sensitive. Competition in the contract drilling business traditionally involves factors such as demand, price, efficiency, the condition of equipment, availability of labor and equipment, reputation, and customer relations.
Our oil and natural gas operations likewise encounter strong competition from other oil and natural gas companies. Many competitors have greater financial, technical, and other resources than we do and have more experience than we do in the exploration for and production of oil and natural gas.
Our drilling success and the success of other activities integral to our operations will depend, in part, during times of increased competition on our ability to attract and retain experienced geologists, engineers, and other professionals. Competition for these professionals can be intense.
Our mid-stream segment competes with purchasers and gatherers of all types and sizes, including those affiliated with various producers, other major pipeline companies, and independent gatherers for the right to purchase natural gas and NGLs, build gathering and processing systems, and deliver the natural gas and NGLs once the gathering and processing systems are established. The principal elements of competition include the rates, terms, and availability of services, reputation, and the flexibility and reliability of service.
HUMAN CAPITAL
We believe that our employees are critical to our future success, and seek to provide competitive compensation and benefits in order to attract and retain a skilled workforce. We care about the well-being and development of our employees, and aim to provide a culture of respect and collaboration by supporting employee training and development. We are also very focused on maintaining a culture of continuous improvement in safety and environmental practices - safety and environmental stewardship are at the forefront of everything that we do.
As of March 3, 2022, we had 788 employees, none of whom are members of a union or labor organization. Our workforce includes 478 employees in our contract drilling segment, 136 employees in our oil and natural gas segment, 128 employees in our mid-stream segment, and 46 in our general corporate group. We also periodically utilize the services of independent contractors. We have not experienced any strikes or work-force stoppages.
GOVERNMENTAL REGULATIONS
General. Our business depends on the demand for services from the oil and natural gas exploration and development industry, and therefore our business can be affected by political developments and changes in laws and regulations that control or curtail drilling for oil and natural gas for economic, environmental, or other policy reasons.
Various state and federal regulations affect the production and sale of oil and natural gas. All states in which we conduct activities impose varying restrictions on the drilling, production, transportation, and sale of oil and natural gas. This discussion of certain laws and regulations affecting our operations should not be relied on as an exhaustive review of all regulatory considerations affecting us, due to the multitude of complex federal, state, and local regulations, and their susceptibility to change at any time by later agency actions and court rulings that may affect our operations.
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Natural Gas Sales and Transportation. Under the Natural Gas Act of 1938, FERC regulates the interstate transportation and the sale in interstate commerce for resale of natural gas. FERC’s authority over interstate natural gas sales has been substantially modified by the Natural Gas Policy Act under which FERC continued to regulate the maximum selling prices of certain categories of gas sold in “first sales” in interstate and intrastate commerce. Effective January 1, 1993, however, the Natural Gas Wellhead Decontrol Act (the Decontrol Act) deregulated natural gas prices for all “first sales” of natural gas. Because “first sales” include typical wellhead sales by producers, all-natural gas produced from our natural gas properties is sold at market prices, subject to the terms of any private contracts which may be in effect. FERC’s authority over interstate natural gas transportation is not affected by the Decontrol Act.
Our sales of natural gas are affected by intrastate and interstate gas transportation regulation. Beginning in 1985, FERC adopted regulatory changes that have significantly altered the transportation and marketing of natural gas. These changes are intended by FERC to foster competition by, among other things, transforming the role of interstate pipeline companies from wholesale marketers of natural gas to the primary role of gas transporters. All-natural gas marketing by the pipelines must divest to a marketing affiliate, which operates separately from the transporter and in direct competition with all other merchants. Because of the various omnibus rulemaking proceedings in the late 1980s and the later individual pipeline restructuring proceedings of the early to mid-1990s, interstate pipelines must provide open and nondiscriminatory transportation and transportation-related services to all producers, natural gas marketing companies, local distribution companies, industrial end users, and other customers seeking service. Through similar orders affecting intrastate pipelines that provide similar interstate services, FERC expanded the impact of open access regulations to certain aspects of intrastate commerce.
FERC has pursued other policy initiatives that affected natural gas marketing. Most notable are (1) the large-scale divestiture of interstate pipeline-owned gas gathering facilities to affiliated or non-affiliated companies; (2) further development of rules governing the relationship of the pipelines with their marketing affiliates; (3) the publication of standards relating to using electronic bulletin boards and electronic data exchange by the pipelines to make available transportation information timely and to enable transactions to occur on a purely electronic basis; (4) further review of the role of the secondary market for released pipeline capacity and its relationship to open access service in the primary market; and (5) development of policy and promulgation of orders pertaining to its authorization of market-based rates (rather than traditional cost-of-service based rates) for transportation or transportation-related services on the pipeline’s demonstration of lack of market control in the relevant service market.
Because of these changes, independent sellers and buyers of natural gas have gained direct access to the pipeline services they need and can better conduct business with a larger number of counter parties. These changes generally have improved the access to markets for natural gas while substantially increasing competition in the natural gas marketplace. However, we cannot predict what new or different regulations FERC and other regulatory agencies may adopt or what effect later regulations may have on production and marketing of natural gas from our properties.
Although in the past Congress has been very active in natural gas regulation as discussed above, the more recent trend has been for deregulation and the promotion of competition in the natural gas industry. In addition to “first sales” deregulation, Congress also repealed incremental pricing requirements and natural gas use restraints previously applicable. There continually are legislative proposals pending in the Federal and state legislatures which, if enacted, would significantly affect the petroleum industry. It is impossible to predict what proposals might be enacted by Congress or the various state legislatures and what effect these proposals might have on the production and marketing of natural gas by us. Similarly, and despite the trend toward federal deregulation of the natural gas industry, whether or to what extent that trend will continue or what the ultimate effect will be on the production and marketing of natural gas by us cannot be predicted.
Oil and Natural Gas Liquids Sales and Transportation. Our sales of oil and natural gas liquids currently are not regulated and are at market prices. The prices received from the sale of these products are affected by the cost of transporting these products to market. Much of that transportation is through interstate common carrier pipelines. Effective as of January 1, 1995, FERC implemented regulations generally grandfathering all previously approved interstate transportation rates and establishing an indexing system for those rates by which adjustments are made annually based on the rate of inflation, subject to certain conditions and limitations. These regulations may increase the cost of transporting oil and natural gas liquids by interstate pipeline, although the annual adjustments could cause decreased rates in a given year. These regulations have generally been approved on judicial review. Every five years, FERC examines the relationship between the annual change in the index and the actual cost changes experienced by the oil pipeline industry and makes any necessary adjustment in the index to be used during the ensuing five years. We cannot predict with certainty what effect the periodic review of the index by FERC will have on us.
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Exploration and Production Activities. Federal, state, and local agencies also have promulgated extensive rules and regulations applicable to our oil and natural gas exploration, production, and related operations. The states we operate in require permits for drilling operations, drilling bonds, and filing reports about operations and impose other requirements relating to the exploration of oil and natural gas. Many states also have statutes or regulations addressing conservation matters including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from oil and natural gas wells, and regulating spacing, plugging and, abandonment of such wells. The statutes and regulations of some states limit the rate at which oil and natural gas is produced from our properties. The federal and state regulatory burden on the oil and natural gas industry increases our cost of doing business and affects our profitability. Because these rules and regulations are amended or reinterpreted frequently, we cannot predict the future cost or impact of complying with these laws.
Environmental.
General. Our operations are subject to federal, state, and local laws and regulations governing protection of the environment. These laws and regulations may require acquisition of permits before certain of our operations may be commenced and may restrict the types, quantities, and concentrations of various substances that can be released into the environment. Planning and implementation of protective measures must prevent accidental discharges. Spills of oil, natural gas liquids, drilling fluids, and other substances may subject us to penalties and cleanup requirements. Handling, storage, and disposal of both hazardous and non-hazardous wastes are subject to regulatory requirements.
The federal Clean Water Act, as amended by the Oil Pollution Act, the federal Clean Air Act, the federal Resource Conservation and Recovery Act (RCRA), and their state counterparts, are the primary vehicles for imposition of such requirements and for civil, criminal, and administrative penalties and other sanctions for violation of their requirements. In addition, the federal Comprehensive Environmental Response Compensation and Liability Act (CERCLA) and similar state statutes impose strict liability, without regard to fault or the legality of the original conduct, on certain classes of persons considered responsible for the release of hazardous substances into the environment. Such liability, which may be imposed for the conduct of others and for conditions others have caused, includes the cost of remedial action and damages to natural resources. The Oil Pollution Act of 1990 amends the Clean Water Act and establishes strict liability for owners and operators of
facilities that cause a release of oil into waters of the United States. In addition, this law requires owners and operators of
facilities that store oil above specified threshold amounts to develop and implement spill prevention, control and
countermeasure plans.
Water Discharges. The Federal Water Pollution Control Act, or the Clean Water Act, and comparable state laws impose restrictions and strict controls regarding the discharge of pollutants, including produced waters and other oil and natural gaswastes, into federal and state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the U.S. Environmental Protection Agency (EPA) or a state equivalent agency. The discharge of dredge and fill material in regulated waters, including wetlands, is also prohibited, unless authorized by a permit issued by the U.S. Army Corps of Engineers (Corps). The scope of the Clean Water Act’s jurisdiction has been the subject of significant uncertainty and litigation in recent years. For example, under the Obama Administration, the EPA and the U.S. Army Corp of Engineers proposed a new expansive definition of the “waters of the United States,” known as the “Clean Water Rule.” However, during the Trump Administration, the EPA and the Corps replaced the Clean Water Rule with the Navigable Waters Protection Rule (NWPR), which narrows the definition of “waters of the United States” to four categories of jurisdictional waters and includes twelve categories of exclusions, including groundwater; however, these rulemakings are currently subject to litigation and it is possible that the Biden Administration could propose a broader definition for these regulated waters. Both the Clean Water Rule and the NWPR are subject to ongoing litigation, with the Clean Water Rule in effect in certain states and the NWPR in effect in others. In addition, in an April 2020 decision defining the scope of the Clean Water Act that was handed down just days after the NWPR was published, the U.S. Supreme Court held that, in certain cases, discharges from a point source to groundwater could fall within the scope of the Clean Water Act and require a permit. The Court rejected the EPA’s and Corps’ assertion that groundwater should be totally excluded from the Clean Water Act. The Court’s decision is expected to bolster challenges to the NWPR.” As a result of these developments, the scope of jurisdiction under the Clean Water Act is uncertain at this time.
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To the extent any rule expands the scope of the Clean Water Act’s jurisdiction in areas where we operate, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas, which could delay the development of our natural gas and oil projects. Similarly, any increased costs or delays for such permits may impact the development of pipeline infrastructure, which may impact our ability to transport our products. Also, pursuant to these laws and regulations, we may be required to obtain and maintain approvals or permits for the discharge of wastewater or storm water and are required to develop and implement spill prevention, control and countermeasure plans, also referred to as “SPCC plans,” in connection with on-site storage of significant quantities of oil. These laws and any implementing regulations provide for administrative, civil and criminal penalties for any unauthorized discharges of oil and other substances in reportable quantities and may impose substantial potential liability for the costs of removal, remediation and damages.
Hazardous Substances and Waste Management. RCRA and comparable state statutes regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Pursuant to rules issued by the EPA, individual state governments administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters and most of the other wastes associated with the exploration, development and production of oil or natural gas are currently regulated under RCRA’s non-hazardous waste provisions. However, it is possible that certain oil, natural gas, and drilling and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future.
CERCLA, also known as the Superfund law, imposes joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the current and former owners and operators of the site where the release occurred and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. We generate materials during our operations that may be regulated as hazardous substances. Despite the “petroleum exclusion” of CERCLA, which currently encompasses crude oil and natural gas, we may nonetheless generate or handle hazardous substances within the meaning of CERCLA, or similar state statutes, in the course of our ordinary operations and, as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment. In addition, we currently own, lease, or operate numerous properties that have been used for oil and natural gas exploration, production and processing for many years. Although we believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes, or hydrocarbons may have been released on, under or from the properties owned or leased by us, or on, under or from other locations, including off-site locations, where such substances have been taken for disposal. Under such laws, we could be required to undertake investigatory, response, or corrective measures, which could include soil and groundwater sampling, the removal of previously disposed substances and wastes, the cleanup of contaminated property, or remedial plugging or pit closure operations to prevent future contamination, the costs of which could be substantial.
Endangered Species Act. The federal Endangered Species Act (ESA) and analogous state laws regulate many activities, including oil and gas development, which could have an adverse effect on species listed as threatened or endangered under the ESA or their habitats. Designating previously unidentified endangered or threatened species could cause oil and natural gas exploration and production operators and service companies to incur additional costs or become subject to operating delays, restrictions or bans in affected areas, which impacts could adversely reduce drilling activities in affected areas. All three of our business segments could be subject to the effect of one or more species being listed as threatened or endangered within the areas of our operations. Numerous species have been listed or are under consideration for protected status under the ESA in areas in which we provide or could undertake operations, such as the dunes sagebrush lizard, lesser prairie chicken, and greater sage grouse. In addition, the Supreme Court held in 2018 that only the actual habitat of an endangered species can be designated critical habitat, meaning that an uninhabited area that otherwise meets the definition of critical habitat should not be so designated. Following this decision, the U.S. Fish and Wildlife Service (FWS) and the National Marine Fisheries Service NMFS) issued joint regulations in December 2020 defining critical habitat to mean an area that currently or periodically contains the resources and conditions necessary to support a species listed under the ESA. The Department of Interior (DOI) also finalized rules in January 2021 under the Migratory Bird Treaty Act, which imposes similar restrictions and penalties as those found under the ESA, that limit the imposition of criminal sanctions in instances where only an incidental take of protected birds occurs. The Biden Administration has stated that it plans to review the FWS, NMFS, and DOI regulations and has paused implementation of the DOI rules.The presence of protected species in areas where we provide contract drilling or mid-stream services or conduct exploration and production operations could impair our ability to timely complete or carry out those services and, consequently, hurt our results of operations and financial position.
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Air Emissions. The federal Clean Air Act and comparable state laws restrict the emission of air pollutants from many sources, such as tank batteries and compressor stations, through air emissions standards, construction and operating permitting programs and the imposition of other compliance requirements. These laws and regulations may require us to obtain preapproval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions of certain pollutants. The EPA has also adopted rules under the Clean Air Act that require the reduction of volatile organic compound emissions from certain fractured and refractured natural gas wells for which well completion operations are conducted and further require that most wells use reduced emission completions, also known as “green completions.” These regulations also establish specific new requirements regarding emissions from production-related wet seal and reciprocating compressors and from pneumatic controllers and storage vessels. The EPA expanded on its emission standards for volatile organic compounds in June 2016 with the issuance of first-time standards, known as Subpart OOOOa, to address emissions of methane from equipment and processes across oil and natural gas production, storage, processing and transmission sources, including hydraulically fractured oil natural gas and well completions.
In September 2020, the Trump Administration finalized regulations that removed the transmission and storage segments from the oil and natural gas source category and rescinded the methane specific requirements of OOOOa across all sources. These changes are currently subject to litigation, and Congress is considering repealing the September 2020 revisions pursuant to the Congressional Review Act. In addition, in January 2021, President Biden signed an executive order calling for the suspension, revision, or rescission of the September 2020 rule and the reinstatement or issuance of methane emissions standards for new, modified, and existing oil and gas facilities. As a result, more stringent regulation of methane emissions from the oil and natural gas industry is expected.
Several states, including Colorado, Pennsylvania, New Mexico and Wyoming, have separately imposed their own regulations on methane emissions from the oil and natural gas sector. These regulations cover a variety of upstream and midstream sources and typically limit the venting and flaring of gas, require the installation of certain types of low-emitting equipment, and impose leak inspection and repair requirements. These and other air pollution control and permitting requirements have the potential to delay the development of oil and natural gas projects, increase our costs of development and operations, and increase costs for well decommissioning and abandonment.
Climate Change. Climate change continues to attract considerable public and scientific attention. As a result, our operations as well as the operations of our operators are subject to a series of regulatory, political, litigation, and financial risks associated with the production and processing of fossil fuels and emission of greenhouse gases (GHGs). At the federal level, no comprehensive climate change law or regulation has been implemented to date. The EPA has, however, adopted regulations that, among other things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources, and together with the U.S. Department of Transportation, implement GHG emissions limits on vehicles manufactured for operation in the United States. The federal regulation of methane emissions from oil and gas facilities has been subject to controversy in recent years. For more information, see our regulatory disclosure titled “Air Emissions.”
Governmental, scientific, and public concern over the threat of climate change arising from GHG emissions has resulted in increasing political risks in the United States, including climate change related pledges made by the recently elected administration. These have included promises to limit emissions and curtail the production of oil and gas on federal lands, such as through the cessation of leasing public land for hydrocarbon development. For example, in January 2021, President Biden issued an executive order that commits to substantial action on climate change, calling for, among other things, the increased use of zero-emissions vehicles by the federal government, the elimination of subsidies provided to the fossil fuel industry, and increased emphasis on climate-related risk across governmental agencies and economic sectors. Additionally, President Biden has signed executive orders recommitting the United States to the Paris Agreement, which requires member nations to submit non-binding, individually determined GHG emission reduction goals every five years after 2020. The impacts of these orders and the terms of any legislation or regulation to implement the United States’ commitment under the Paris Agreement remain unclear at this time. There are also increasing financial risks for fossil fuel producers as shareholders currently invested in fossil-fuel energy companies may elect in the future to shift some or all of their investments into non-energy related sectors. Institutional lenders who provide financing to fossil-fuel energy companies also have become more attentive to sustainable lending practices and some of them may elect not to provide funding for fossil fuel energy companies. There is also a risk that financial institutions will be required to adopt policies that have the effect of reducing the funding provided to the fossil fuel sector. Recently, the Federal Reserve announced that it has joined the Network for Greening the Financial System, a consortium of financial regulators focused on addressing climate-related risks in the financial sector. Limitation of investments in and financings for fossil fuel energy companies could result in the restriction, delay or cancellation of drilling programs or development or production activities.
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The adoption and implementation of new or more stringent international, federal or state legislation, regulations or other regulatory initiatives that impose more stringent standards upon GHG emissions from the oil and natural gas sector could result in increased costs of compliance. Concerns related to the impacts of climate change could also result in reduced demand for oil and natural gas and adversely impact the value of reserves. In addition, increased financial scrutiny of climate risks could result in restrictions on our access to capital. Moreover, there are increasing risks to operations resulting from the potential physical impacts of climate change, such as drought, wildfires, damage to infrastructure and resources from flooding, storms, and other natural disasters and other physical disruptions. One or more of these developments could have a material adverse effect on our business, financial condition and results of operation.
Hydraulic Fracturing. Our oil and natural gas segment routinely apply hydraulic fracturing techniques to many of our oil and natural gas properties, including our unconventional resource plays in the Granite Wash of Texas and Oklahoma, the Marmaton of Oklahoma, the Wilcox of Texas, and the Mississippian of Kansas. Hydraulic fracturing has been the subject of public scrutiny over the past several years. While states typically have primary authority with respect to regulating oil and natural gas production activities, including hydraulic fracturing, from time to time Congress has considered passing new laws to regulate this practice, and the U.S. Government has asserted regulatory authority over certain aspects of hydraulic fracturing. For example, the EPA finalized rules under the Clean Water Act in June 2016 that prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants. Most recently, on March 23, 2021 the Fracturing Responsibility and Awareness of Chemicals Act was reintroduced in Congress, which includes resolutions that would authorize the EPA to regulate unconventional drilling activities, including requiring the disclosure of chemicals used, and end various exemptions for hydraulic fracturing in federal laws such as RCRA, the Safe Drinking Water Act, and the federal Clean Air Act. In addition, certain states in which we operate, including Texas, Oklahoma, Kansas, Colorado, and Wyoming have adopted, and other states and municipalities and other local governmental entities in some states, have and others are considering adopting regulations and ordinances that could impose more stringent permitting, require the public disclosure of chemicals in fracking fluids, flaring limitations, waste disposal, and well construction requirements on these operations, and even restrict or ban hydraulic fracturing in certain circumstances.
In December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The final report concluded that certain activities associated with hydraulic fracturing may impact drinking water resources under certain limited circumstances. Both the EPA and the United States Geological Survey (USGS) have made statements indicating that the disposal of wastes associated with hydraulic fracturing via injection wells may result in induced seismic events. Several states, including Texas, Oklahoma, and Kansas, have adopted measures limiting disposal well operations in areas under certain circumstances.
At the state level, several states, including Texas, have adopted or are considering legal requirements that require oil and natural gas operators to disclose chemical ingredients and water volumes used to hydraulically fracture wells, in addition to more stringent well construction and monitoring requirements. Local governments may also adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular.Any new laws, regulation, or permitting requirements regarding hydraulic fracturing could lead to operational delay, or increased operating costs or third party or governmental claims, and could result in additional burdens that could delay or limit the drilling services we provide to third parties whose drilling operations could be affected by these regulations or increase our costs of compliance and doing business and delay the development of unconventional gas resources from shale formations which are not commercial without using hydraulic fracturing. Restrictions on hydraulic fracturing could also reduce the oil and natural gas we can ultimately produce from our reserves.
Other; Compliance Costs. We cannot predict future legislation or regulations. It is possible that some future laws, regulations, and/or ordinances could increase our compliance costs and/or impose additional operating restrictions on us as well as those of our customers. Such future developments also might curtail the demand for fossil fuels which could hurt the demand for our services, which could hurt our future results of operations. Likewise, we cannot predict with any certainty whether any changes to temperature, storm intensity or precipitation patterns because of climate change (or otherwise) will have a material impact on our operations.
Compliance with applicable environmental requirements has not, to date, had a material effect on the cost of our operations, earnings, or competitive position. However, as noted above in our discussion of the regulation of GHG and hydraulic fracturing, compliance with amended, new, or more stringent requirements of existing environmental regulations or requirements may cause us to incur additional costs or subject us to liabilities that may have a material adverse effect on our results of operations and financial condition.
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Item 1A. Risk Factors
RISK FACTORS
RISKS CONCERNING COMMODITY PRICES
Our business is heavily affected by commodity prices. Oil, NGLs, and natural gas prices are volatile, and low prices have hurt our financial results and could do so in the future.
Our revenues, operating results, cash flow, and growth depend on prevailing prices for oil, NGLs, and natural gas. Oil, NGLs, and natural gas prices and markets have been volatile, and they are likely to remain volatile.
The prices we receive for our oil, NGLs, and natural gas production affect our revenues, profitability, cash flow, and ability to meet our projected financial and operational goals. Prices also tend to influence third parties use of our services. Those prices are decided by many factors beyond our control, including:
•the demand for and supply of oil, NGLs, and natural gas;
•weather conditions in the continental United States (which can influence the demand and prices for natural gas);
•the amount and timing of oil, natural gas, and liquefied petroleum gas imports and exports;
•the ability of distribution systems in the United States to effectively meet the demand for oil, NGLs, and natural gas, particularly in times of peak demand which may result because of adverse weather conditions;
•the ability or willingness of OPEC to set and support production levels for oil;
•oil and gas production levels by non-OPEC countries;
•political and economic uncertainty and geopolitical activity, such as the current conflict occurring between Russia and Ukraine;
•governmental policies and subsidies;
•the costs of exploring for, producing, and delivering oil and natural gas;
•technological advances affecting energy consumption;
•United States storage levels of oil, NGLs, and natural gas;
•price, availability, and acceptance of alternative fuels;
•volatility in ethane prices causing rejection of ethane as part of the liquids processed stream;
•pandemics, epidemics, outbreaks, or other public health events, such as COVID-19; and
•worldwide economic conditions.
Oil prices are sensitive to domestic and foreign influences based on political, social, or economic underpinnings, any of which could have an immediate and significant effect on the price and supply of oil. Prices of oil, NGLs, and natural gas can also be influenced by trading on the commodities markets which has increased the volatility associated with these prices, causing large differences in prices on even a weekly and monthly basis.
Based on our production for the year ended December 31, 2021, a $0.10 per Mcf change in what we receive for our natural gas production, without the effect of derivatives, would cause a corresponding $250 per month ($3.0 million annualized) change in our pre-tax operating cash flow. A $1.00 per barrel change in our oil price, without the effect of derivatives, would result in a $130 per month ($1.6 million annualized) change in our pre-tax operating cash flow and a $1.00 per barrel change in our NGLs price, without the effect of derivatives, would result in a $220 per month ($2.6 million annualized) change in our pre-tax operating cash flow.
These factors and the volatile nature of the energy markets make it impossible to predict with any certainty the future prices of oil, NGLs, and natural gas.
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Our derivative arrangements might limit the benefit of increases in oil, NGLs, and/or natural gas prices.
To reduce our exposure to short-term fluctuations in the price of oil, NGLs, and natural gas, we may use derivative contracts like swaps and collars. To date, we have derivatives covering part, but not all of our production, which provides price protection only against declines in market prices on the production covered by those derivatives, but not otherwise. Should market prices for the production we have derivatives on exceed the prices due under our derivative contracts, our derivative contracts expose us to the risk of financial loss and limit the benefit to us of those increases in market prices. Volumes not covered by derivative contracts are subject to market prices. The Management’s Discussion and Analysis of Financial Condition and Results of Operations section of this report in Item 7 has a more thorough discussion of our derivative arrangements.
If one or more of our counterparties are unable or unwilling to pay us under our commodity derivative contracts, it could have a material adverse effect on our financial condition and operating results.
If oil, NGLs, and natural gas prices decrease or are unusually volatile, we may have to take write-downs of our oil and natural gas properties, the carrying value of our drilling rigs, or our natural gas gathering and processing systems.
Each quarter we review the carrying value of our oil and natural gas properties under the SEC’s full cost accounting rules. Under these rules, capitalized costs of proved oil and natural gas properties may not exceed the present value of estimated future net revenues from proved reserves, discounted at 10% per year. Application of the ceiling test generally requires pricing future revenue at the unweighted arithmetic average of the price on the first day of the month for each month within the 12 months before the end of the reporting period (unless contractual arrangements define the prices) and requires a write-down for accounting purposes if the ceiling is exceeded. We may have to write-down the carrying value of our oil and natural gas properties when oil, NGLs, and natural gas prices are depressed. A write-down, if required, would cause a charge to earnings but would not impact cash flow from operating activities. Once incurred, a write-down is not reversible. Because our ceiling tests use a rolling 12-month look back average price, it is possible that a write-down during a reporting period will not remove the need for us to take future write-downs. This could occur when months with higher commodity prices roll off the 12 months and are replaced with more recent months having lower commodity prices.
Our drilling equipment, transportation equipment, gas gathering and processing systems, and other property and equipment are carried at cost. We must periodically test to see if these values have been impaired whenever events or changes in circumstances suggest the carrying amount may not be recoverable. If these assets are determined to be impaired, the loss is measured as the amount by which the carrying amount of the asset exceeds its fair value. An 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 the property, equipment, and related intangible assets. Once these values are reduced, they are not reversible.
RISKS RELATED TO OIL, NGL, AND NATURAL GAS RESERVES
Many uncertainties are inherent in estimating quantities of oil, NGLs, and natural gas reserves and their values, including factors beyond our control. Actual production, revenues, and expenditures regarding our oil, NGLs, and natural gas reserves will likely vary from estimates, and those variances may be material.
Many uncertainties are inherent in estimating quantities of oil, NGLs, and natural gas reserves and their values, including factors beyond our control. The oil, NGLs, and natural gas reserve information in this report is only an estimate of these reserves. Oil, NGLs, and natural gas reservoir engineering is a subjective and inexact process of estimating underground accumulations of oil, NGLs, and natural gas that cannot be measured precisely. Estimates of economically recoverable oil, NGLs, and natural gas reserves depend on several variable factors, including historical production from the area compared with production from other producing areas, and assumptions about: reservoir size; the effects of regulations by governmental agencies; future oil, NGLs, and natural gas prices; future operating costs; severance and excise taxes; operational risks; development costs; and workover and remedial costs.
Some or all these assumptions may vary considerably from actual results. For these and other reasons, estimates of the economically recoverable quantities of oil, NGLs, and natural gas attributable to any group of properties, classifications of those oil, NGLs, and natural gas reserves based on the risk of recovery, and estimates of the future net cash flows from oil, NGLs, and natural gas reserves prepared by different engineers or by the same engineers but at different times may vary substantially. Oil, NGLs, and natural gas reserve estimates may be subject to periodic downward or upward adjustments. Actual production, revenues, and expenditures regarding our oil, NGLs, and natural gas reserves will likely vary from estimates, and those variances may be material.
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The information about discounted future net cash flows in this report is not necessarily the current market value of the estimated oil, NGLs, and natural gas reserves attributable to our properties. Using full cost accounting requires us to 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. Actual future prices and costs may be materially higher or lower. Actual future net cash flows are also affected by these factors:
•the amount and timing of oil, NGLs, and natural gas production;
•supply and demand for oil, NGLs, and natural gas;
•increases or decreases in consumption; and
•changes in governmental regulations or taxation.
What’s more, the 10% discount factor, required by the SEC for calculating discounted future net cash flows for reporting purposes, is not necessarily the most appropriate discount factor based on interest rates in effect from time to time and the risks associated with our operations or the oil and natural gas industry.
Estimated quantities of oil, NGLs, and natural gas reserves and their values used to prepare our consolidated financial statements and supplemental oil and gas disclosures may differ from estimates used in other strategic or economic purposes.
As described above, the information about discounted future net cash flows in this report is not necessarily the current market value of the estimated oil, NGLs, and natural gas reserves attributable to our properties so estimates used by management for strategic or economic purposes may differ.
RISKS RELATED TO FINANCING OUR BUSINESS
Our inability to satisfy our debt obligations and covenants could result in our failure to meet our capital needs and adversely affect our operations.
We may incur substantial capital expenditures in our operations. Historically, we have funded our capital needs through a combination of internally generated cash flow and borrowings under our bank credit agreements. We have, and may continue to have, some indebtedness. As of December 31, 2021, we had no outstanding borrowings under the Exit credit agreement and $19.2 million of borrowings outstanding under the Superior credit agreement (as defined below).
Depending on our debt, the cash flow needed to satisfy that debt and the covenants in our bank credit agreements could:
•limit funds otherwise available for financing our capital expenditures, our drilling program, or other activities or cause us to curtail these activities;
•limit our flexibility in planning for or reacting to changes in our business;
•place us at a competitive disadvantage to those of our competitors less indebted than we are;
•make us more vulnerable during periods of low oil, NGLs, and natural gas prices or if a downturn in our business occurs; and
•prevent us from obtaining more financing on acceptable terms or limit amounts available under our existing or future credit facilities.
Our ability to meet our debt obligations depends on our future performance. If such obligations are not satisfied, a default could be deemed to occur, and our lenders could accelerate the payment of the outstanding indebtedness. If that were to happen, we would not have sufficient funds available (and probably could not obtain the financing required) to meet our obligations. See “Our long-term liquidity requirements and the adequacy of our capital resources are difficult to predict” below.
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Our existing debt and our future debt are based mainly on the costs of the projects we undertake and our cash flow. Generally, our expected operating costs are those resulting from the drilling of oil and natural gas wells, acquiring producing properties, the costs associated with the maintenance, upgrade, or expansion of our drilling rig fleet, and the operations of our natural gas buying, selling, gathering, processing, and treating systems. To some extent, these costs, mainly the first two, are discretionary, and we maintain some control on the timing or the need to incur them. Sometimes, unforeseen circumstances may arise, like an unexpected chance to make a large acquisition or the need to replace a costly drilling rig component due to an unexpected loss, which could force us to incur more debt above what we had expected or forecasted. Likewise, if our cash flow should prove insufficient to cover our cash requirements, we would need to increase our debt either through bank borrowings or otherwise.
Restrictive covenants in our credit facilities may limit our financial and operating flexibility and our ability to pursue our business strategies.
As of December 31, 2021, we had no outstanding borrowings under our Exit credit agreement and $19.2 million outstanding under our Superior credit agreement. Our financing agreements permit us to incur more indebtedness and other obligations. We may also seek amendments or waivers from our existing lenders if we need to incur indebtedness above amounts permitted by our financing agreements.
Our credit facilities contain certain restrictions, which may have adverse effects on our business, financial condition, cash flows or results of operations, limiting our ability, among other things, to:
•incur additional indebtedness;
•incur additional liens;
•pay dividends or make other distributions;
•make investments, loans, or advances;
•sell or discount receivables;
•enter into mergers;
•sell properties;
•enter into or terminate swap agreements;
•enter into transactions with affiliates;
•maintain gas imbalances;
•enter into take-or-pay contracts or make other prepayments;
•enter into sale and leaseback agreements;
•amend our organizational documents; and
•make capital expenditures.
The credit facilities also require us to comply with certain financial maintenance covenants as discussed elsewhere in this report.
A breach of any of these restrictive covenants could cause a default. If a default occurs, the lenders under our credit facilities may elect to declare all borrowings outstanding, together with accrued interest and other fees, to be immediately due. The lenders would also have the right in that case to terminate any commitments they have to provide more borrowings. If we cannot repay our indebtedness when due or declared due, the lenders may also proceed against the collateral pledged to secure the indebtedness. If the indebtedness was accelerated, our assets might not fully repay our secured indebtedness.
Under the Exit credit agreement, the borrowing base is determined semi-annually at the lenders’ discretion and is based largely on the prices for oil, NGLs, and natural gas.
Significant declines in oil, NGLs, and natural gas prices may cause a decrease in our borrowing base. The lenders can unilaterally adjust the borrowing base, and therefore the borrowings permitted to be outstanding under the Exit credit agreement. If outstanding borrowings are over the borrowing base, we must (a) repay the amount over the borrowing base, (b) dedicate additional properties to the borrowing base, or (c) begin monthly principal payments.
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The amount Superior can borrow under its credit agreement may be affected by its cash flow.
Superior must maintain a funded debt to consolidated EBITDA ratio (as defined in the Superior credit agreement) of not greater than 4.00 to 1.00. If Superior’s EBITDA falls below $50.0 million, its maximum funded debt would be limited to 4.00 times consolidated EBITDA.
Disruptions in the financial markets could affect our ability to obtain financing or refinance existing indebtedness on reasonable terms and may have other adverse effects.
Commercial-credit and equity market disruptions may cause tight capital markets in the United States. Liquidity in the global capital markets can be severely contracted by market disruptions making financing less attractive. In some cases, it leads to the unavailability of certain types of financing. Because of credit and equity market turmoil, we may not obtain debt or equity financing or refinance existing indebtedness on favorable terms, which could affect operations and financial performance.
Changes in the method of determining LIBOR, or the replacement of LIBOR with an alternative reference rate, may hurt our indebtedness.
Our variable rate debt under both the Exit credit agreement and the Superior credit agreement is tied to LIBOR. On July 27, 2017, the Financial Conduct Authority announced that it would phase out LIBOR as a benchmark by the end of 2021. It is unclear whether new methods of calculating LIBOR will be established so that it continues to exist after 2021. There is no guarantee that a transition from LIBOR to an alternative will not cause financial market disruptions, significant increases in benchmark rates, or borrowing costs to borrowers, any of which could hurt our business, financial condition, and operations results.
RISKS RELATED TO OPERATING OUR BUSINESS
Increasing attention to environmental, social and governance (ESG) matters may adversely impact our business.
Organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters. Such ratings are used by some investors to evaluate their investment and voting decisions. Unfavorable ESG ratings may lead to increased negative investor sentiment toward us and to the diversion of their investment away from the fossil fuel industry to other industries which could have a negative impact on our stock price and our access to and costs of capital.
Public health events outside our control, including pandemics, epidemics, and infectious disease outbreaks, like the recent global outbreak of COVID-19, have materially hurt and may further materially hurt our business.
We face risks related to epidemics, pandemics, outbreaks, or other public health events outside our control and could disrupt our operations and hurt their financial condition. The outbreak of the COVID-19 virus has spread across the globe and affected financial markets and worldwide economic activity. It may continue to negatively impact our operations or our workforce’s health by rendering employees or contractors unable to work or unable to access our facilities for an indefinite period. The effects of COVID-19 and concerns about its global spread have, during certain periods, weakened the domestic and international demand for crude oil and natural gas, hurting crude oil prices and causing significant price volatility. As the duration and full impact from COVID-19 is difficult to predict, how much it may hurt our operating results, or the duration of any potential business disruption is unknown. Any potential impact will depend on future developments, and new information that may emerge about the severity and duration of COVID-19 and the actions taken by authorities to contain it or treat its impact are beyond our control. These potential impacts, while unknown, could hurt our operating results.
The industries in which we operate are highly competitive, and many of our competitors have resources more significant than we do.
The drilling industry in which we operate is generally very competitive. Most drilling contracts are awarded based on competitive bids, which may cause intense price competition. Some of our competitors in the contract drilling industry have greater financial and human resources than we do. These resources may enable them to withstand periods of low drilling rig use better, compete more effectively based on price and technology, build new drilling rigs, or acquire existing drilling rigs, and provide drilling rigs more quickly than we do in periods of high drilling rig use.
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The oil and natural gas industry is also highly competitive. We compete in property acquisitions and oil and natural gas exploration, development, production, and marketing with major oil companies, other independent oil and natural gas concerns, and individual producers and operators. Many of our competitors in the oil and natural gas industry have resources substantially greater than we do.
The mid-stream industry is also highly competitive. We compete in gathering, processing, transporting, and treating natural gas with other mid-stream companies. We are continually competing with larger mid-stream companies for acquisitions and construction projects. Many of our competitors have greater financial resources, human resources, and geographic presence larger than we do.
Competition for experienced technical personnel may hurt our operations or financial results.
Our three segments’ success and the success of our other activities integral to our operations will depend, in part, on our ability to attract and retain experienced geologists, engineers, drilling rig hands, and other employees. Competition for these employees can be intense, particularly when the industry is experiencing favorable conditions.
Our operations are subject to inherent risks that, if material, could harm our results of operations.
Our contract drilling operations are subject to many hazards, including blowouts, cratering, explosions, fires, loss of well control, loss of hole, damaged or lost drilling equipment, and damage or loss from inclement weather. Our exploration and production and mid-stream operations are subject to these and similar risks. These events could cause personal injury or death, damage to or destruction of equipment and facilities, suspension of operations, environmental damage, and damage to others’ property. Generally, drilling contracts provide for the division of responsibilities between a drilling company and its customer. We seek to obtain contractual indemnification from our drilling customers for some of these risks. If we cannot transfer these risks to drilling customers by contract or indemnification agreements (or if we assume obligations of indemnity or assume liability for certain risks under our drilling contracts), we seek protection from some of these risks through insurance. Still, some risks are not covered by insurance. We cannot assure you that the insurance we have or the indemnification agreements we have will adequately protect us against liability from the consequences of the hazards described above. An event not fully insured or indemnified against, or a customer’s failure to meet its indemnification obligations, could cause substantial losses. We cannot assure you that insurance will be available to cover any or all of these risks. Even if available, the insurance might not be adequate to cover all of our losses, or we might decide against obtaining that insurance because of high premiums or other costs.
Our exploration and development operations involve many risks that may cause dry holes, the failure to produce oil, NGLs, and natural gas in commercial quantities, and the inability to fully produce discovered reserves. The cost of drilling, completing, and operating wells is substantial and uncertain. Many of these factors are beyond our control and may cause the curtailment, delay, or cancellation of drilling operations.
Exploratory drilling is a speculative activity. Although we may disclose our overall drilling success rate, those rates may decline. Although we may discuss drilling prospects we have identified or budgeted for, we may ultimately not lease or drill these prospects within the expected period, or at all. Lack of drilling success will hurt our future results of operations and financial condition. We do not operate many wells in which we own an interest. Our operational risks for those wells and our ability to influence those wells’ operations are less subject to our control and the operators of those wells may act in ways not in our best interests.
Our oil and natural gas segment’s prospective drilling locations are in various evaluation stages, ranging from a prospect ready to drill to a prospect that will require additional geological and engineering analysis. Based on many factors, including future oil, NGLs, natural gas prices, the generation of additional seismic or geological information, and other factors, we may decide not to drill one or more of these prospects. We may not increase or maintain our reserves or production, which could hurt our business, financial position, and operating results. The SEC’s reserve reporting rules require that, subject to limited exceptions, proved undeveloped reserves may be booked only if they relate to wells scheduled to be drilled within five years of booking. At December 31, 2021, we had no proved undeveloped drilling locations.
Our mid-stream operations involve many risks, both financial and operational. The cost of developing gathering systems and processing plants is substantial, and our ability to recoup these costs is uncertain. Our operations may be curtailed, delayed, or canceled because of many things beyond our control, including:
•unexpected changes in the deliverability of natural gas reserves from the wells connected to the gathering systems;
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•availability of competing pipelines in the area;
•the capacity of pipeline systems;
•equipment failures or accidents;
•adverse weather conditions;
•compliance with governmental requirements;
•delays in developing other producing properties within the gathering system’s area of operation; and
•demand for natural gas and its constituents.
New technologies may cause our exploration and drilling methods to become obsolete, causing an adverse effect on our production.
Our industry is subject to rapid and significant technological advancements, including the introduction of new products and services using new technologies. As competitors use or develop new technologies, we may be at a competitive disadvantage, and competitive pressures may force us to implement new technologies at a substantial cost. In addition, our competitors may have greater financial, technical, and personnel resources that allow them to enjoy technological advantages and may allow them to implement new technologies before we can. We cannot be sure that we can implement technologies timely or at an acceptable cost. One or more technologies we use or that we may implement may become obsolete or may not work as we expected, and we may be hurt financially and operationally as a result.
Our operating results depend on our ability to transport oil, NGLs, and gas production to key markets.
The marketability of our oil, NGLs, and natural gas production depends in part on the availability, proximity, and capacity of pipeline systems, refineries, and other transportation sources. The unavailability of or lack of capacity on these systems and facilities could cause the shut-in of producing wells or the delay or discontinuance of development plans for properties. Federal and state regulation of oil, NGLs, and natural gas production and transportation, tax, and energy policies, changes in supply and demand, pipeline pressures, damage to or destruction of pipelines, and general economic conditions could hurt our ability to produce, gather, and, transport oil, NGLs, and natural gas.
Losing one or several of our larger customers could have a material adverse effect on our financial condition and results of operations.
During the year ended December 31, 2021, one customer accounted for 11% of our oil and natural gas revenue, five customers accounted for 79% of our contract drilling revenues, and three customers accounted for 58% of our Mid-Stream revenues. No other third-party customer accounted for 10% or more of any of our segment revenues. Any customer may choose not to use our services or purchase oil, natural gas, or NGLS from us, and losing one or several of our larger customers could have a material adverse effect on our financial condition and results of operations if we could not find replacements.
Superior depends on certain natural gas producers and pipeline operators for a significant portion of its supply of natural gas and NGLs. Losing any of these producers could cause a decline in our volumes and revenues.
We rely on certain natural gas producers for a significant portion of our natural gas and NGLs supply. While some of these producers are subject to long-term contracts, we may not negotiate extensions or replacements of these contracts on favorable terms, if at all. Losing all or even a portion of the natural gas volumes supplied by these producers, because of competition or otherwise, could have a material adverse effect on our mid-stream segment unless we acquired comparable volumes from other sources.
We rely on management and other key employees.
We depend significantly on the efforts of our executive officers and other key employees to manage our operations. The loss or unavailability of any of our executive officers or other key employees could have a material adverse effect on our business.
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We are subject to various claims and litigation that could ultimately be resolved against us, requiring material future cash payments or future material charges against our operating income, and materially impairing our financial position.
The nature of our business makes us highly susceptible to claims and litigation. We are subject to various existing legal claims and lawsuits, which could have a material adverse effect on our consolidated financial position, results of operations, or cash flows. Even if indemnified or insured, any claims or litigation could hurt our reputation among our customers and the public and make it harder for us to compete effectively or obtain adequate insurance in the future.
Demand for our contract drilling and mid-stream services depends on the levels of spending by the oil and gas industry. A substantial or an extended decline in oil and gas prices could cause lower spending by the oil and gas industry, which could have a material adverse effect on our financial condition, results of operations, and cash flows.
Demand for our contract drilling and mid-stream services depends on the oil and gas industry’s level of expenditures for the exploration, development, and production of oil and natural gas reserves. These expenditures generally depend on the industry’s view of future oil and natural gas prices and are sensitive to the industry’s view of future economic growth and the resulting effect on demand for oil and natural gas. Declines and anticipated declines in oil and gas prices could also cause project modifications, delays, or cancellations, general business disruptions, and delays in payment of, or nonpayment of, amounts owed to us. These effects could have a material adverse effect on our financial condition, results of operations, and cash flows.
Climate change legislation or other regulatory initiatives restricting emissions of GHGs could result in increased operating costs and reduced demand for the oil, natural gas and NGL we produce.
Climate change continues to attract considerable public and scientific attention. As a result, numerous proposals have been made and may continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of GHGs. These efforts have included consideration of cap-and-trade programs, carbon taxes, GHG reporting and tracking programs, mandates for the production of renewable fuels, and regulations that directly limit GHG emissions from certain sources. At the federal level, no comprehensive climate change legislation has been implemented to date. The EPA has, however, adopted regulations that, among other things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources, and together with the U.S. Department of Transportation, implement GHG emissions limits on vehicles manufactured for operation in the United States. The federal regulation of methane emissions from oil and gas facilities has been subject to controversy in recent years. For more information, see our regulatory disclosure titled “Air Emissions.”
Governmental, scientific, and public concern over the threat of climate change arising from GHG emissions has resulted in increasing political risks in the United States, including climate change related pledges made by the recently elected administration. These have included promises to limit emissions and curtail the production of oil and gas on federal lands, such as through the cessation of leasing public land for hydrocarbon development. For example, in January 2021, President Biden issued an executive order that commits to substantial action on climate change, calling for, among other things, the increased use of zero-emissions vehicles by the federal government, the elimination of subsidies provided to the fossil fuel industry, and increased emphasis on climate-related risk across governmental agencies and economic sectors. Additionally, President Biden has signed executive orders recommitting the United States to the Paris Agreement, which requires member nations to submit non-binding, individually determined GHG emission reduction goals every five years after 2020. The impacts of these orders and the terms of any legislation or regulation to implement the United States’ commitment under the Paris Agreement remain unclear at this time. There are also increasing financial risks for fossil fuel producers as shareholders currently invested in fossil-fuel energy companies may elect in the future to shift some or all of their investments into non-energy related sectors. Institutional lenders who provide financing to fossil-fuel energy companies also have become more attentive to sustainable lending practices and some of them may elect not to provide funding for fossil fuel energy companies. There is also a risk that financial institutions will be required to adopt policies that have the effect of reducing the funding provided to the fossil fuel sector. Recently, the Federal Reserve announced that it has joined the Network for Greening the Financial System, a consortium of financial regulators focused on addressing climate-related risks in the financial sector. Limitation of investments in and financings for fossil fuel energy companies could result in the restriction, delay or cancellation of drilling programs or development or production activities.
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The adoption and implementation of new or more stringent international, federal or state legislation, regulations or other regulatory initiatives that impose more stringent standards upon GHG emissions from the oil and natural gas sector could result in increased costs of compliance. Concerns related to the impacts of climate change could also result in reduced demand for oil and natural gas and adversely impact the value of reserves. In addition, increased financial scrutiny of climate risks could result in restrictions on our access to capital. Moreover, there are increasing risks to operations resulting from the potential physical impacts of climate change, such as drought, wildfires, damage to infrastructure and resources from flooding, storms, and other natural disasters and other physical disruptions. One or more of these developments could have a material adverse effect on our business, financial condition and results of operations.
Geopolitical tensions from the conflict between Russia and Ukraine may create market volatility or other disruptions which could negatively impact our ability to carry out our business plan.
Although we have no direct transactional or supply chain exposure to the areas of conflict, the current conflict between Russia and Ukraine, and related geopolitical and economic responses, could significantly impact the global financial markets and supply chains, or cause other disruptions which could negatively impact our business plan and operations.
RISKS TO OUR POTENTIAL GROWTH PLANS
Our long-term liquidity requirements and the adequacy of our capital resources are difficult to predict.
Any growth plans may require significant cash. Our principal sources of liquidity include the available borrowing capacity under the Exit credit agreement and cash flow generated from operations. If our cash flow from operations decreases, we may be unable to expend the capital to maintain our operations, hurting our future revenues. Our liquidity, including our ability to meet our ongoing operational obligations, depends on, among other things: (i) our ability to comply with the terms of the Exit credit agreement, (ii) our ability to maintain adequate cash on hand, and (iii) our ability to generate cash flow from operations.
Growth through acquisitions is not assured.
We have historically grown through mergers and acquisitions. The contract land drilling industry, the exploration and development industry, and the gas gathering and processing industry have experienced significant consolidation over the past several years. There is no assurance that acquisition opportunities will be available or viable. Even if available, there is no assurance we would have the financial ability to pursue the opportunity. We expect the competition for acquisition opportunities to persist or intensify.
We may incur substantial indebtedness to finance future acquisitions and may issue debt instruments, equity securities, or convertible securities in connection with any acquisitions. Debt service requirements could represent a significant burden on our operations and financial condition and issuing more equity would be dilutive to existing shareholders. In addition, continued growth could strain our management, operations, employees, and other resources.
Successful acquisitions, particularly those of oil and natural gas companies or oil and natural gas properties, require assessing several factors, many of which are beyond our control. These factors include recoverable reserves, exploration potential, future oil, NGLs, and natural gas prices, operating costs, and potential environmental and other liabilities. Such assessments are inexact, and their accuracy is inherently uncertain.
Our future performance may depend on our ability to find or acquire more oil, NGLs, and natural gas reserves that are economically recoverable.
Production from oil and natural gas properties declines as reserves are depleted, with a well's decline rate depending on reservoir characteristics. Unless we replace the reserves, we produce, our reserves will decline, resulting in a decrease in oil, NGLs, and natural gas production and lower revenues and cash flow. Historically, we have increased reserves after considering our production through exploration and development. We have conducted these activities on our existing oil and natural gas properties and newly acquired properties. We may not be able to continue to replace reserves from these activities at acceptable costs. Lower prices for oil, NGLs, and natural gas may further limit the reserves that can economically be developed. Lower prices also decrease our cash flow and may cause us to decrease capital expenditures.
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If we are to construct new proprietary BOSS drilling rigs, the process would be subject to risks, including delays and cost overruns, and rigs that may not meet our expectations.
We have designed and built several proprietary 1,500 horsepower AC electric drilling rigs called BOSS drilling rigs. This new design should position us to meet the demands of our customers better. Constructing any future new BOSS drilling rigs is subject to the risks of delays or cost overruns in any large construction project because of many possible factors.
BOSS drilling rig designs may be subject to intellectual property rights claims.
While we hold certain patents on our BOSS drilling rig design, it is still possible that third parties may claim that our BOSS drilling rig design infringes on their intellectual property rights. In that event, we may resolve these claims by signing royalty and licensing agreements, redesigning the drilling rig, or paying damages. These outcomes may cause operating margins to decline. In addition to money damages, plaintiffs may seek injunctive relief in some jurisdictions that may limit or prevent marketing and use of our drilling rigs if they are determined to be an infringement upon a third party's intellectual property rights.
RISKS RELATED TO REGULATIONS
New laws, policies, regulations, rulemaking, and oversight, as well as changes to those currently in effect, could adversely impact our earnings, cash flows, and operations.
Our business is subject to federal, state, and local laws and regulations on taxation, the exploration for and development, production, and marketing of oil and natural gas, and safety matters. Many laws and regulations require drilling permits and govern the spacing of wells, production rates, prevention of waste, unitization and pooling of properties, and other matters. These laws and regulations have increased the costs of planning, designing, drilling, installing, operating, and abandoning our oil and natural gas wells and other facilities. These laws and regulations, and any others passed by the jurisdictions where we have production, could limit the number of wells drilled or the allowable production from successful wells, limiting our revenues.
We are (or could become) subject to complex environmental laws and regulations adopted by the jurisdictions where we own properties or operate. We could incur liability to governments or third parties for discharges of oil, natural gas, or other pollutants into the air, soil, or water, including responsibility for remedial costs. We could discharge these materials into the environment in many ways, including:
•from a well or drilling equipment at a drill site;
•from gathering systems, pipelines, transportation facilities, and storage tanks;
•damage to oil and natural gas wells resulting from accidents during normal operations;
•sabotage; and
•blowouts, cratering, and explosions.
Because the requirements imposed by laws and regulations often change, we cannot assure you that future laws and regulations, including changes to existing laws and regulations, will not have a material adverse effect on our business or results of operations. The United States Congress and White House administration may impose more stringent environmental requirements on our operations or change existing laws and regulations in a manner that could adversely impact our business. Stricter standards, greater regulation, and more extensive permit requirements could increase our future risks and costs related to environmental matters. Because we acquire interests in properties operated in the past by others, we may be liable for environmental damage caused by the former operators, which liability could be material.
We could be subject to increased compliance costs related to the regulation of our pipelines.
Our pipelines are also subject to regulation by the Department of Transportation (DOT) under the Natural Gas Pipeline Safety Act of 1968, as amended, Hazardous Liquid Pipeline Safety Act of 1979, as amended, the Pipeline Safety Act of 1992, as reauthorized and amended, and the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (2011 Pipeline Safety Act). The federal Pipeline and Hazardous Materials Safety Administration (PHMSA) implements these statutes. Recently, PHMSA has taken several steps to expand its jurisdiction over crude oil and natural gas pipelines, including gathering lines.
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PHMSA issued three separate final rulemakings in 2019 that significantly expand the regulation of natural gas gathering lines, subjecting previously unregulated pipelines to requirements regarding damage prevention, corrosion control, public education programs, and maximum allowable operating pressure limits, among others. PHMSA has also finalized rules for hazardous liquids pipelines that expand existing pipeline integrity management requirements. In addition, the final rule extends annual and accident reporting requirements to gravity lines and all gathering lines and also imposes inspection requirements on pipelines in areas affected by extreme weather events, natural disasters, such as hurricanes, landslides, floods, earthquakes, or other similar events that are likely to interfere with our production, increase our cost and damage infrastructure.
On August 3, 2020, the United States Senate reauthorized the Protecting our Infrastructure of Pipelines and Enhancing Safety (PIPES) Act to reauthorize pipeline safety programs through fiscal year 2023. The PIPES Act contains provisions for methane leak detection, monitoring, and repair, the maintenance of emergency response plans, and other pipeline safety regulations. Therefore, additional future regulatory action expanding PHMSA’s jurisdiction and imposing stricter integrity management requirements is possible. The adoption of laws or regulations that apply more comprehensive or stringent safety standards could require us to install new or modified safety controls, pursue new capital projects, or conduct maintenance programs on an accelerated basis, all of which could require us to incur increased operating costs that could be significant. In addition, should we fail to comply with PHMSA or comparable state regulations, we could be subject to substantial fines and penalties. Effective January 11, 2021, the maximum civil penalties PHMSA can impose are $222,504 per violation per day, with a maximum of $2,225,034 for a related series of violations.
Proposed federal and state legislative and regulatory initiatives relating to hydraulic fracturing could cause increased costs and additional operating restrictions or delays.
Hydraulic fracturing is an essential and common practice in the oil and gas industry used to stimulate the production of oil, natural gas, and associated liquids from dense subsurface rock formations. Our oil and natural gas segment routinely applies hydraulic-fracturing techniques to many of our oil and natural gas properties, including our unconventional resource plays in the Granite Wash of Texas and Oklahoma, the Marmaton and Hoxbar of Oklahoma, the Wilcox of Texas. Hydraulic-fracturing involves using water, sand, and certain chemicals to fracture the hydrocarbon-bearing rock formation to allow hydrocarbons’ flow into the wellbore. State oil and natural gas commissions process typically regulate this process, but the EPA has asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel under the Safe Drinking Water Act and published permitting guidance addressing the performance of such activities. The EPA has also finalized rules under the Clean Water Act in June 2016 that prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants. Separately, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The final report concluded that certain activities associated with hydraulic fracturing may impact drinking water resources under certain limited circumstances.
Some states where we operate, including Texas, Oklahoma, Kansas, Colorado, and Wyoming, have adopted, and other states are considering adopting, regulations that could impose more stringent permitting, public disclosure of fracking fluids, waste disposal, and well construction requirements on hydraulic-fracturing operations or otherwise seek to ban fracturing activities altogether. Local governments may also seek to restrict or prohibit well-drilling, hydraulic fracturing, or both. If state, local, or municipal legal restrictions are adopted in areas where we are conducting or plan to conduct operations, we may incur added costs to comply with such requirements that may be significant, experience delays or curtailment pursuing exploration, development, or production activities, and perhaps even be precluded from the drilling and completion of wells.
In addition, our ability to produce crude oil, natural gas, and associated liquids economically and in commercial quantities could be impaired if we cannot get adequate supplies of water for our drilling and completion operations or cannot dispose of or recycle the water we use at a reasonable cost and under applicable environmental rules. Any new laws, regulation, or permitting requirements regarding hydraulic fracturing could lead to operational delays, or increased operating costs or third party or governmental claims, and could result in additional burdens that could delay or limit the drilling services we provide to third parties whose drilling operations could be affected by these regulations or increase our costs of compliance and doing business and delay the development of unconventional gas resources from shale formations which are not commercial without using hydraulic fracturing. Restrictions on hydraulic fracturing could also reduce the oil and natural gas we can ultimately produce from our reserves.
To our knowledge, there have been no citations, suits, or contamination of potable drinking water arising from our fracturing operations. We do not have insurance policies in effect intended to supply coverage for losses solely related to hydraulic fracturing operations, but our general liability and excess liability insurance policies might cover third-party claims related to hydraulic fracturing operations and associated legal expenses depending on the specific nature of the claims, the timing of the claims, and the specific terms of such policies.
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Uncertainty about increased seismic activity in Oklahoma could have adverse effect on our business and results of operations.
We conduct oil and natural gas exploration, development, and drilling activities in Oklahoma and nearby. In recent years, Oklahoma, Texas, and Kansas have experienced an upturn in earthquakes and other seismic activity. Some parties believe there is a correlation between certain oil and gas activities and earthquakes’ increased occurrence. The extent of this correlation is the subject of studies by both state and federal agencies, the results of which remain unclear. We cannot say what impact this seismic activity may have on us or our industry.
The hydraulic fracturing process on which we depend to produce commercial quantities of crude oil, natural gas, and associated NGLs from many reservoirs requires the use and disposal of significant water quantities.
Our inability to secure enough water or dispose of or recycle the water used in our oil and natural gas segment operations could hurt our operations. Imposing new environmental initiatives and regulations could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of wastes, including, but not limited to, produced water, drilling fluids, and other wastes associated with the exploration, development, or production of oil and natural gas.
Compliance with environmental regulations and permit requirements governing the withdrawal, storage and, use of surface water or groundwater necessary for hydraulic fracturing of wells may increase our operating costs and cause delays, interruptions, or termination of our operations, the extent of which cannot be predicted, all of which could hurt our operations and financial condition.
The potential listing of species as “endangered” under the federal Endangered Species Act could cause increased costs and new operating restrictions or delays on our operations and of our customers, which could hurt our operations and financial results.
The ESA and similar state laws regulate various activities, including oil and gas development, which could harm species listed as threatened or endangered under the ESA or their habitats. Designating previously unidentified endangered or threatened species could cause oil and natural gas exploration and production operators and service companies to incur added costs or become subject to operating delays, restrictions, or bans in affected areas, which impacts could reduce drilling activities in affected areas. All three of our business segments could be subject to the effect of one or more species being listed as threatened or endangered within the areas of our operations. Many species have been listed or are under consideration for protected status in areas we operate or could undertake operations, such as the dunes sagebrush lizard, lesser prairie chicken, and greater sage grouse.
Terrorist attacks or cyber-attacks could have a material adverse effect on our business, financial condition, or results of operations.
Terrorist attacks or cyber-attacks may affect the energy industry and economic conditions, including our operations and our customers, general economic conditions, consumer confidence and spending, and market liquidity. Strategic targets, such as energy-related assets, may be at greater risk of future attacks than other United States targets. A cyber incident could cause information theft, data corruption, operational disruption, and financial loss. Our insurance may not protect us against such occurrences. It is possible that any of these occurrences, or a combination of them, could have a material adverse effect on our business, financial condition, and results of operations.
We are increasingly dependent on digital technologies, including information systems, infrastructure, and cloud applications and services, to operate our businesses, process and record financial and operating data, communicate with our employees and business partners, analyze seismic and drilling information, estimate quantities of natural gas reserves, and perform other activities related to our businesses. Our business partners, including vendors, service providers, and financial institutions, also depend on digital technology.
As dependence on digital technologies has increased, cyber incidents, including deliberate attacks or unintentional events, have also increased. A cyber-attack could include gaining unauthorized access to digital systems to misappropriate assets or sensitive information, corrupting data, or causing operational disruption, or result in denial-of-service on websites.
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Our technologies, systems, networks, and those of our business partners may become the target of cyber-attacks or information security breaches that could cause the unauthorized release, gathering, monitoring, misuse, loss, or destruction of proprietary and other information, or other disruption of our business operations. Some cyber incidents, like surveillance, may remain undetected for a long time.
Deliberate attacks on our assets, or security breaches in our systems or infrastructure, the systems or infrastructure of third-parties or the cloud could lead to corruption or loss of our proprietary data and potentially sensitive data, delays in production or delivery, difficulty completing and settling transactions, challenges in maintaining our books and records, environmental damage, communication interruptions, other operational disruptions, and third-party liability, including:
•a cyber-attack on a vendor or service provider could cause supply chain disruptions, which could delay or halt the development of more infrastructure, effectively delaying the start of cash flows from the project;
•a cyber-attack on our facilities may cause equipment damage or failure;
•a cyber-attack on mid-stream or downstream pipelines could prevent our products from being delivered, leading to losing revenues;
•a cyber-attack on a communications network or power grid could cause operational disruption resulting in loss of revenues;
•deliberate corruption of our financial or operational data could cause events of non-compliance leading to regulatory fines or penalties; and
•business interruptions could cause expensive remediation efforts, the distraction of management, or damage to our reputation.
Implementation of various controls and processes to monitor and mitigate security threats and increase security for our information, facilities and infrastructure are costly and labor-intensive. There can be no assurance that such measures will prevent security breaches from occurring. As cyber threats continue to evolve, we may have to spend significant additional resources to modify or enhance our protective measures or investigate and remediate any information security vulnerabilities.
Ineffective internal controls could affect the accuracy and timely reporting of our business and financial results.
Our internal control over financial reporting (ICFR) may not prevent or detect misstatements because of its inherent limitations, including the possibility of human error, the circumvention or overriding of controls, or fraud. Even effective internal controls can provide only reasonable assurance about the preparation and fair presentation of financial statements. If we do not maintain our internal controls’ adequacy, including any failure to implement needed new or improved controls, or if we experience difficulties in their implementation, our business and financial results could be harmed, and we could fail to meet our financial reporting obligations.
POST REORGANIZATION RISKS
Because our consolidated financial statements reflect fresh start accounting adjustments made on emergence from bankruptcy, financial information in our financial statements are not comparable to our financial information from prior periods.
With our emergence from bankruptcy on the Effective Date, we determined that the company qualified for fresh start accounting under ASC Topic 852, Reorganizations, under which our reorganization value, which represents the fair value of the entity before considering liabilities, is distributed to the fair value of assets in conformity with the purchase method of accounting for business combinations. We state our liabilities, other than deferred taxes, at a present value of amounts expected to be paid. Thus, our consolidated balance sheets and consolidated statements of operations are not comparable in many respects to consolidated balance sheets and consolidated statements of operations data for periods before we adopted fresh start accounting. You cannot compare information reflecting our post-emergence financial statements to information for periods before we emerged from bankruptcy without adjusting for fresh start accounting.
Even though the Plan has been consummated, we may not achieve our stated goals.
Even though the Plan has been substantially consummated, we may continue to face several risks, such as further deterioration or other changes in economic conditions, changes in our industry, changes in demand for our services, and increasing expenses. We cannot guarantee that the Plan and subsequent performance will achieve our stated goals.
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Even though our debts were reduced through the Plan, we may need to raise additional funds through public or private debt or equity financing, or other various means to fund our business after completing the Chapter 11 Cases. Our access to additional financing may be limited, if available at all. Thus, adequate funds may not be available when needed or may not be available on favorable terms.
RISKS RELATED TO OWNERSHIP OF OUR CAPITAL STOCK
Holders of the New Common Stock and Warrants could be subject to U.S. federal withholding tax and/or U.S. federal income tax and corresponding tax reporting obligations on the sale, exchange, or other disposition of the New Common Stock and Warrants, which could adversely affect the trading and liquidity of the New Common Stock and Warrants.
The company believes that it is, and will remain for the foreseeable future, a “U.S. real property holding corporation” for U.S. federal income tax purposes. Under the Foreign Investment in Real Property Tax Act (FIRPTA), non-U.S. holders may be subject to U.S. federal income tax on the gain from the sale, exchange, or other disposition of shares of New Common Stock and Warrants, in which case they would also have to file U.S. federal income tax returns about that gain and may be subject to a U.S. federal withholding tax on a disposition of shares of New Common Stock and Warrants. Whether these FIRPTA provisions apply depends on the amount of New Common Stock or Warrants that the non-U.S. holders hold and whether, when they dispose of their New Common Stock or Warrants, the New Common Stock is treated as regularly traded on an established securities market under the Treasury Regulations (regularly traded).
If the New Common Stock is regularly traded during a calendar quarter, (A) no withholding requirements would be imposed under FIRPTA on transfers of New Common Stock or Warrants and (B) only a non-U.S. holder who has held, actually or constructively, (i) over 5% of New Common Stock or (ii) Warrants with a fair market value greater than 5% of the New Common Stock into which it is convertible, in each case at any time during the shorter of (x) the five years ending on the date of disposition, and (y) the non-U.S. holder’s holding period for its shares of New Common Stock or Warrants, would be subject to U.S. federal income tax on the sale, exchange, or disposition of such shares of New Common Stock or Warrants during such calendar quarter under FIRPTA.
If during any calendar quarter the New Common Stock is not regularly traded, any purchaser of New Common Stock or Warrants generally will have to withhold (and remit to the Internal Revenue Service (IRS)) 15% of the gross proceeds from the sale of the New Common Stock or Warrants unless provided with a certificate of non-foreign status or an IRS withholding certificate from the seller. Because the New Common Stock and Warrants were issued in book-entry form through DTC, sellers may not provide the necessary documentation to the purchasers to establish an exemption from withholding. Additionally, the purchasers may not withhold from the purchase price and remit the withheld amount to the IRS if they cannot obtain the sellers’ identifying information. It may be difficult or impossible to complete a transfer in compliance with tax laws in any calendar quarter when the New Common Stock is not regularly traded.
Our New Common Stock is currently quoted on the OTC Pink Marketplace and may be treated as regularly traded during any calendar quarter in which it is regularly quoted on one of the OTC markets by brokers or dealers making a market in the New Common Stock. But no assurances can be given that brokers or dealers will regularly quote the New Common Stock on such OTC market. If the New Common Stock is not regularly traded, the trading and liquidity of the New Common Stock and Warrants could be hurt because of the withholding and other tax obligations under FIRPTA.
Our New Common Stock may have a limited market and lack liquidity.
While our New Common Stock is being quoted on the OTC Pink marketplace, the OTC Pink marketplace is a more limited market than the NYSE or The Nasdaq Stock Market. The quotation of our shares on such a marketplace may cause a less liquid market available for existing and potential stockholders to trade shares of our New Common Stock, depress the trading price of our New Common Stock, and have a long-term adverse impact on our ability to raise capital. There can be no assurance there will be an active market for our shares of New Common Stock, either now or in the future, or that stockholders can liquidate their investment or liquidate it at a price that reflects the business’ value.
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Our charter and by-laws contain provisions that could delay or discourage a change in control transaction or prevent stockholders from receiving a premium on their investment.
Our charter and bylaws contain provisions that may delay or discourage change in control transactions or changes in our management or transactions that our stockholders might otherwise deem to be in their best interests or that might result in a premium over the market price for our shares, including, among other things:
•For so long as we do not have a class of securities registered under Section 12 of the Exchange Act, until the earlier to occur of (x) the Consenting Noteholders (as defined in the Plan) ceasing to hold at least 50% of the outstanding voting stock and (y) a public offering of common stock having occurred and shares of the company’s common stock with a value of at least $250.0 million having been listed for trading on a national securities exchange, the company cannot take certain actions without the consent of holders of at least 50% of the voting stock. Such actions include, among other things and subject to certain exceptions, (i) increasing or decreasing the size of the board, (ii) undertaking any fundamental change to the nature of the business, or (iii) consummating a public offering of common stock.
•The board is divided into two classes, Group I and Group II. The Group I directors initially served until the company’s 2023 annual meeting of stockholders, and the Group II directors will initially serve until the company’s 2022 annual meeting of stockholders. Each nominee for director will stand for election to a two-year term expiring at the second annual meeting of stockholders after that director’s election and until such director’s successor is duly elected and qualified, subject to that director’s earlier resignation, retirement, removal from office, death, or incapacity.
•Courts in Delaware are the exclusive forum for derivative actions and certain other actions and claims.
•To ensure the preservation of certain tax attributes to benefit the company and its stockholders, the charter contains certain restrictions on transfer of the company’s equity securities by persons with a percentage stock ownership of 4.75% or more.
•Special meetings of the stockholders may only be called by the board or by the secretary of the company at the request of stockholders owning at least 25% of the voting stock.
•The board has the ability to authorize undesignated preferred stock. This ability makes it possible for our board to issue, without stockholder approval, preferred stock with voting or other rights or preferences that could impede the success of any attempt to change control of us.
•Vacancies on our board of directors and newly created directorships will be filled solely by the affirmative vote of a majority of directors then in office, even if less than a quorum, or by a sole remaining director.
Item 1B. Unresolved Staff Comments
None.
Item 2. Properties
The information called for by this item was consolidated with and disclosed in connection with Item 1 above.
Item 3. Legal Proceedings
For more information regarding legal proceedings, see Note 21 - Commitments And Contingencies of our Notes to Consolidated Financial Statements in Item 8 of this report.
Item 4. Mine Safety Disclosures
Not applicable.
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PART II
Item 5. Market for the Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities
New Common Stock
After the Effective Date, we authorized 12.0 million shares of New Common Stock to be distributed under the Plan. The New Common Stock is not registered under Section 12 of the Exchange Act. On March 23, 2021, FINRA authorized a broker dealer to initiate a priced quotation of the New Common Stock on the OTC Pink Marketplace under the symbol "UNTC". See “Risk Factors — Our New Common Stock may have a limited market and lack liquidity” under Item 1A of this report.
Since all of our stockholders maintain their shares in “street name” accounts and are not, individually, stockholders of record, as of March 31, 2022, there was one holder of record of our common stock.
Allocation of New Common Stock
As contemplated by the Plan, the company distributed 10,527,507 and 683,038 shares of New Common Stock to holders of the subordinated notes claims on December 11, 2020 and July 26, 2021, respectively, as well as 161,328 and 3,055 shares of New Common Stock to holders of allowed general unsecured claims on October 20, 2021 and February 23, 2022, respectively, as a result of the pro rata distribution of shares of New Common Stock out of the equity reserves established under the Plan for certain disputed claims against the company and UPC. The shares of New Common Stock were distributed pursuant to Section 1145 of the Bankruptcy Code (which generally exempts from registration under the federal and state securities laws the issuance of securities in exchange for interests in or claims against a debtor under a plan of reorganization). Pursuant to the Plan, all shares of New Common Stock were distributed in book-entry form through the facilities of The Depository Trust Company (DTC).
Common Stock Dividends
We have declared no cash dividends on our common stock. Any future determination by our board of directors to pay dividends on our common stock will be made only after considering our financial condition, results of operations, capital requirements, and other relevant factors. Under certain circumstances, none of which applied as of December 31, 2021, our bank credit agreements may restrict the payment of cash dividends on our common stock. For further information regarding how our bank credit agreements may impact our ability to pay dividends, see “Credit Agreements” under Item 7 of this report.
Share Repurchases
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. The cash purchase price and direct acquisition costs are reflected as treasury stock on the consolidated balance sheets as of December 31, 2021.
In June 2021, our board of directors (the Board) authorized repurchasing up to $25.0 million of our 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. We have no obligation to repurchase any shares under the repurchase program and may suspend or discontinue it at any time without prior notice.
As of December 31, 2021, 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 December 31, 2021 totaled 1,949,963, resulting in outstanding shares of 10,050,037.
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The table below represents all share repurchases for the three months ended December 31, 2021:
| Period | Total number of shares purchased | Average price paid per share | Total number of shares purchased as part of publicly announced program | Approximate dollar value of shares that may yet be purchased under the program | ||||||||||
| (in thousands) | ||||||||||||||
| October 1, 2021 through October 31, 2021 | — | $ | — | — | $ | 40,653 | ||||||||
| November 1, 2021 through November 30, 2021 | 861,926 | $ | 34.80 | 861,926 | $ | 10,658 | ||||||||
| December 1, 2021 through December 31, 2021 | 60,000 | $ | 34.80 | 60,000 | $ | 8,570 | ||||||||
Item 6. [Reserved]
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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.
Introduction
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.
In our oil and natural gas segment, we are optimizing production and converting non-producing reserves to producing, with selective drilling activities in core areas. 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.
In our contract drilling segment, management reduced the number of drilling rigs available for use from 58 at December 31, 2020 to 21 during the second quarter of 2021 in order to focus on utilization of our BOSS drilling rigs and certain SCR rigs that are either currently under contract or candidates for future upgrades. Of the 21 rigs available for use, 14 are currently working, 3 are actively being marketed, and the remaining 4 will be considered for upgrade and marketing as future conditions warrant. We also plan to continue seeking opportunities to divest non-core, idle drilling equipment.
In our mid-stream segment, we are focused on continuing to generate predictable free cash flows with limited exposure to commodity prices. We also plan to continue seeking business development opportunities in our core areas utilizing the Superior credit agreement (which Unit is not a party to and does not guarantee) or other financing sources that are available to it.
Upon our emergence from the Chapter 11 Cases on September 3, 2020, we adopted fresh start accounting as required by US GAAP. As a result of the application of fresh start accounting, as well as the effects of the implementation of the Plan, our consolidated financial statements after August 31, 2020 are not comparable with our consolidated financial statements prior to that date.
Recent Developments
Commodity Price Environment and COVID-19 Pandemic
Our success depends, among other things, on 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, including political and economic uncertainty and geopolitical activity.
We are continuously monitoring the current and potential impacts of the COVID-19 pandemic, including any new variants, on our business. This includes how it has and may continue to impact our operations, financial results, liquidity, customers, employees, and vendors as new COVID-19 variants may have undetermined impacts to our business. In response to the pandemic, we have implemented various measures to ensure we are conducting our business in a safe and secure manner.
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During the last two years commodity prices have been volatile, and the outlook for future oil and gas prices remains uncertain and subject to many factors. The following chart reflects the significant fluctuations in the historical prices for oil and natural gas:
The following chart reflects the significant fluctuations in the prices for NGLs(1):
_________________________
1.NGLs prices reflect a weighted-average, based on production, of Mont Belvieu and Conway prices.
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Stock Repurchase Activity
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, our board of directors (the Board) authorized repurchasing up to $25.0 million of our 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. We have no obligation to repurchase any shares under the repurchase program and may suspend or discontinue it at any time without prior notice.
As of December 31, 2021, 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 December 31, 2021 totaled 1,949,963, resulting in outstanding shares of 10,050,037.
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 0.03460447 warrants for every share of Old Common Stock owned. Each warrant will initially be exercisable for one share of New Common Stock, subject to adjustment as provided in the Warrant Agreement. The exercise price of the Warrants will be determined, and the Warrants will become exercisable, once the Debtors have completed the claims reconciliation process and resolved any objections to disputed claims under the Bankruptcy Petitions. The initial exercise price per share for the Warrants will be set at an amount that implies a recovery by holders of the Subordinated Notes of the $650 million principal amount of the Subordinated Notes plus interest thereon to the May 15, 2021 maturity date of the Notes. 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.
The warrants issued to holders of the company’s Old Common Stock that did not opt-out of the releases under the Plan and that owned their shares of old common stock through Direct Registration are outlined below:
| Issuance Date | Warrants Issued | ||||
| December 21, 2020 | 1,764,164 | ||||
| February 11, 2021 | 42,511 | ||||
| July 29, 2021 | 10,521 | ||||
| October 13, 2021 | 5,005 | ||||
| Total | 1,822,201 | ||||
The company expects to issue approximately 21,117 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.
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Superior MSA and LLC amendments
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 will no longer consolidate the financial position, operating results, and cash flows of Superior as of March 1, 2022. We will subsequently account for our investment in Superior as an equity method investment under the HLBV method.
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.
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, 2021 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:
| Type of Reserves | Nature of Available Data | Degree of Accuracy | ||||||||||||
| Proved undeveloped | Data from offsetting wells, seismic data | Less accurate | ||||||||||||
| Proved developed non-producing | The above and logs, core samples, well tests, pressure data | More accurate | ||||||||||||
| Proved developed producing | The above and production history, pressure data over time | Most accurate | ||||||||||||
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. We use full cost accounting which factors in the unweighted arithmetic average of the commodity prices existing on the first day of each of the twelve 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
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•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 reducing earnings and shareholders’ equity in the period of occurrence, resulting in lower DD&A expense in future periods. A write-down cannot be reversed once incurred.
The risk that 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, 2021, our reserves were calculated based on applying 12-month 2021 average unescalated prices of $66.56 per barrel of oil, $44.22 per barrel of NGLs, and $3.60 per Mcf of natural gas (then adjusted for price differentials) over the estimated life of each of our oil and natural gas properties.
Impairment of Other Property and Equipment. We review the carrying amounts of long-lived assets for potential impairment when events occur or changes in circumstances suggest these carrying amounts may not be recoverable. Changes that could prompt an assessment include equipment obsolescence, changes in the market demand for a specific asset, changes in commodity prices, periods of relatively low drilling rig utilization, declining revenue per day, declining cash margin per day, or overall changes in general market conditions. Assets are determined to be impaired if a forecast of undiscounted estimated future net operating cash flows directly related to the asset, including disposal value if any, is less than the carrying amount of the asset. If any asset is determined to be impaired, the loss is measured as the amount by which the carrying asset exceeds its fair value. The estimate of fair value is based on the best information available, including prices for similar assets. Changes in these estimates could cause us to reduce the carrying value of property and equipment. Asset impairment evaluations are, by nature, highly subjective. They involve expectations about future cash flows generated by our assets and reflect our assumptions and judgments regarding future industry conditions and their effect on future utilization levels, dayrates, and costs. Using different estimates and assumptions could result in materially different carrying values of our assets.
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 estimated liabilities related to these future costs are recorded at the time the wells are drilled or acquired. We use historical experience to determine the estimated plugging costs considering the well's type, depth, physical location, and ultimate productive life. A risk-adjusted discount rate and an inflation factor are applied to estimate the present value of these obligations. We depreciate the capitalized asset retirement cost and accrete the obligation over time. Revisions to the obligations and assets are recognized at the appropriate risk-adjusted discount rate with a corresponding adjustment made to the full cost pool. Our mid-stream segment has property and equipment at locations leased or under right of way agreements which may require asset removal or site restoration, however, we are not able to reasonably measure the fair value of the obligations as the potential settlement dates are indeterminable.
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Warrant Liability. 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.
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.
Recently Issued Accounting Standards
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. 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.
Debt—Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging— Contracts in Entity’s Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity. The FASB issued ASU 2020-06 which simplifies the accounting for convertible instruments by removing certain accounting models which separate the embedded conversion features from the host contract for convertible instruments. The ASU further removes certain settlement conditions that are required for equity contracts to qualify for the derivative scope exception and simplifies the diluted earnings per share calculation in certain areas. The ASU is effective for fiscal years beginning after December 15, 2021, including interim periods within those fiscal years. We will adopt ASU 2020-06 effective January 1, 2022. The adoption of this ASU is not expected to have a material impact on our consolidated financial statements.
Recently Adopted Accounting Standards
Income Taxes (Topic 740)—Simplifying the Accounting for Income Taxes. The FASB issued ASU 2019-12 to simplify the accounting for income taxes by removing certain exceptions to the general principles in Topic 740. The amendments also improve consistent application of and simplify GAAP for other areas of Topic 740 by clarifying and amending existing guidance. The amendment is effective for reporting periods beginning after December 15, 2020. The adoption of this standard did not have a material impact to our consolidated financial statements.
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.
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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:
| Successor | Predecessor | |||||||||||||||||||
| Year Ended December 31, 2021 | Four Months Ended December 31, 2020 | Eight Months Ended August 31, 2020 | ||||||||||||||||||
| (In thousands) | ||||||||||||||||||||
| Net cash provided by operating activities | $ | 175,969 | $ | 29,807 | $ | 44,956 | ||||||||||||||
| Net cash provided by (used in) investing activities | 36,205 | (2,258) | (20,139) | |||||||||||||||||
| Net cash provided by (used in) financing activities | (160,748) | (47,775) | 7,552 | |||||||||||||||||
| Net increase (decrease) cash, restricted cash, and cash equivalents | $ | 51,426 | $ | (20,226) | $ | 32,369 | ||||||||||||||
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 during the year ended December 31, 2021 increased by $101.2 million as compared to the year ended December 31, 2020 primarily due to increased operating profit in all three segments partially offset by changes 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 have curtailed our spending throughout 2020 and into 2021, we expect the majority of future capital budgets to be focused on low cost capital projects to enhance production and reserves in this favorable price environment.
Net cash provided by (used in) investing activities increased by $58.6 million during the year ended December 31, 2021 compared to the year ended December 31, 2020 primarily due to proceeds received from the disposition of our corporate headquarters building and land, an increase in proceeds received from the disposition of other non-core assets, and a decrease in capital expenditures resulting from a decrease in the number of wells drilled and oil and gas property acquisitions, partially offset by the Superior gathering system acquisition.
Cash Flows from Financing Activities
Net cash provided by (used in) financing activities decreased by $120.5 million during the year ended December 31, 2021 compared to the year ended December 31, 2020 primarily due to higher payments on our credit agreements, the repurchase of common stock, lower borrowings under our credit agreements, distributions made to non-controlling interests, and lower bank overdrafts.
As of December 31, 2021, we had unrestricted cash and cash equivalents totaling $64.1 million, which includes $17.2 million of cash and cash equivalents held by Superior, and $19.2 million of outstanding borrowings, all of which was borrowed under the Superior credit agreement. Unit had no outstanding borrowings under the Exit credit agreement.
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Below, we summarize certain financial information as of December 31:
| Successor | Successor | |||||||||||||
| 2021 | 2020 | |||||||||||||
(In thousands) | ||||||||||||||
| Working capital | $ | 5,792 | $ | 2,575 | ||||||||||
| Current portion of long-term debt | $ | — | $ | 600 | ||||||||||
Long-term debt (1) | $ | 19,200 | $ | 98,400 | ||||||||||
| Shareholders' equity attributable to Unit Corporation | $ | 187,397 | $ | 179,222 | ||||||||||
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 $5.8 million at December 31, 2021 compared to positive working capital of $2.6 million as of December 31, 2020. The increase in working capital is primarily due to higher cash and cash equivalents and accounts receivable, partially offset by higher current derivative liabilities, warrant liability, and accounts payable. Both the Superior credit agreement and the Exit credit agreement may be used for working capital. As of December 31, 2021, we had no outstanding borrowings under the Exit credit agreement and $19.2 million of outstanding borrowings under the Superior credit agreement. The effect of our derivatives decreased working capital by $40.9 million as of December 31, 2021 and decreased working capital by $1.0 million as of December 31, 2020.
Credit Agreements
Exit Credit Agreement. On the Effective Date, under the terms of the Plan, the company entered into an amended and restated credit agreement (the Exit credit agreement), providing for a $140.0 million senior secured revolving credit facility (RBL Facility) and a $40.0 million senior secured term loan facility, among (i) the company, UDC, and UPC (together, the Borrowers), (ii) the guarantors party thereto, including the company and all of its subsidiaries existing as of the Effective Date (other than Superior Pipeline Company, L.L.C. and its subsidiaries), (iii) the lenders party thereto from time to time (Lenders), and (iv) BOKF, NA dba Bank of Oklahoma as administrative agent and collateral agent (in such capacity, the Administrative Agent). The maturity date of borrowings under this Exit credit agreement is March 1, 2024.
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 proceeds from the disposition of certain assets be used to repay amounts outstanding.
On April 6, 2021, the company finalized the first amendment to the Exit credit agreement. Under the first amendment, the company reaffirmed its borrowing base of $140.0 million of the RBL, amended certain financial covenants, and received less restrictive terms 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 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.
During the year ended December 31, 2021, the company repaid $145.1 million of borrowings under the Exit credit agreement with cash generated from operations as well as from proceeds from divestitures of non-core assets. As of December 31, 2021, we had no outstanding long-term borrowings under the Exit credit agreement.
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Superior Credit Agreement. On May 10, 2018, Superior signed a five-year, $200.0 million senior secured revolving credit facility with an option to increase the credit amount up to $250.0 million, subject to certain conditions (Superior credit agreement). The maturity date of borrowings under the Superior credit agreement is March 10, 2023. As of December 31, 2021, we had $19.2 million of borrowings and $0.5 million of letters of credit outstanding under the Superior credit agreement.
Capital Requirements
Oil and Natural Gas Segment Dispositions, Acquisitions, and Capital Expenditures. Most of our capital expenditures for this segment are discretionary and directed toward growth. Our decisions 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.
Capital expenditures for oil and gas properties on the full cost method for the year ended December 31, 2021 by this segment, excluding a $0.5 million increase in the ARO liability, totaled $17.3 million. Capital expenditures for the four months ended December 31, 2020, excluding a $1.7 million reduction in the ARO liability, totaled $4.0 million while capital expenditures for the eight months ended August 31, 2020, excluding a $29.2 million reduction in the ARO liability and $0.4 million for acquisitions (including associated ARO), totaled $5.4 million. We participated in the completion of 12 gross wells (1.75 net wells) drilled by other operators during the year ended December 31, 2021 compared to 3 gross wells (0.30 net wells) drilled by other operators in which we participated during the four months ended December 31, 2020 and 16 gross wells (0.35 net wells) drilled by other operators in which we participated during the eight months ended August 31, 2020.
On June 25, 2021, the company entered into a purchase and sale agreement to which we agreed to sell substantially all of our wells and the leases related thereto located near Oklahoma City, Oklahoma for $19.5 million, subject to customary closing and post-closing adjustments. The divestiture closed on August 16, 2021, with an effective date of May 1, 2021. The sale of these assets did not result in a significant alteration of the full cost pool, and therefore no gain or loss was recognized.
On March 30, 2021, the company entered into a purchase and sale agreement to which we agreed to sell substantially all of our wells and the leases related thereto located in Reno and Stafford Counties, Kansas for $7.1 million, subject to customary closing and post-closing adjustments. This divestiture closed on May 6, 2021, with an effective date of February 1, 2021. The sale of these assets did not result in a significant alteration of the full cost pool and therefore, no gain or loss was recognized.
We also sold $5.0 million of other non-core oil and natural gas assets, net of related expenses, during the year ended December 31, 2021, compared to $0.4 million during the four months ended December 31, 2020, and $1.2 million during the eight months ended August 31, 2020. No gain or loss was recognized as the sale of these assets did not result in a significant alteration of the full cost pool.
Contract Drilling Segment Dispositions, Acquisitions, and Capital Expenditures. Capital expenditures for 2021 were primarily related to maintenance capital on operating drilling rigs. We also pursued the disposal or sale of our non-core, idle drilling rig fleet. We incurred $2.9 million in capital expenditures during the year ended December 31, 2021 compared to $0.6 million and $2.4 million during the four months ended December 31, 2020 and eight months ended August 31, 2020, respectively.
We sold non-core contract drilling assets for proceeds of $12.7 million, net of related expenses, during the year ended December 31, 2021, compared to $1.3 million during the four months ended December 31, 2020, and $4.8 million during the eight months ended August 31, 2020. These proceeds resulted in net gains of $10.1 million during the year ended December 31, 2021, compared to $0.5 million during the four months ended December 31, 2020, and $1.4 million during the eight months ended August 31, 2020.
Mid-Stream Dispositions, Acquisitions, and Capital Expenditures. During the year ended December 31, 2021, our mid-stream segment incurred $24.5 million in capital expenditures (including the $13.0 million acquisition of a gathering and processing system in southern Kansas) compared to $1.3 million and $9.3 million during the four months ended December 31, 2020 and eight months ended August 31, 2020, respectively.
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Contractual Commitments
We had the following contractual commitments as of December 31, 2021:
| Payments Due by Period | |||||||||||||||||||||||||||||
| Total | Less Than 1 Year | 2-3 Years | 4-5 Years | After 5 Years | |||||||||||||||||||||||||
| (In thousands) | |||||||||||||||||||||||||||||
Long-term debt (1) | $ | 19,200 | $ | — | $ | 19,200 | $ | — | $ | — | |||||||||||||||||||
Operating leases (2) | 14,001 | 4,382 | 6,004 | 3,565 | 50 | ||||||||||||||||||||||||
Firm transportation commitments (3) | 880 | 880 | — | — | — | ||||||||||||||||||||||||
| Total contractual obligations | $ | 34,081 | $ | 5,262 | $ | 25,204 | $ | 3,565 | $ | 50 | |||||||||||||||||||
_________________________
1.Represents outstanding borrowings as of December 31, 2021 under the Superior credit agreement with a maturity date of May 10, 2023. Unit's Exit credit agreement has a maturity date of March 1, 2024, but no outstanding balance as of December 31, 2021.
2.Represents payments related to the noncancellable terms of certain leases for office space, land, and equipment, including pipeline equipment and office equipment capitalized on the consolidated balance sheets as of December 31, 2021.
3.Represent firm transportation commitments to transport our natural gas from various systems.
Derivative Activities
Commodity Derivatives. Our commodity derivatives are intended to reduce our exposure to price volatility and manage price risks. Those contracts limit the risk of downward price movements for commodities subject to derivative contracts, but they also limit increases in future revenues that would otherwise result from price movements above the contracted prices. 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, 2021, based on our fourth quarter 2021 average daily production, the approximated percentages of our production under derivative contracts are as follows:
| 2022 | 2023 | |||||||||||||
| Daily oil production | 53% | 24% | ||||||||||||
| Daily natural gas production | 50% | 28% | ||||||||||||
Using derivative instruments 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, 2021 and determined there was no material risk at that time. The fair value of the net liabilities we had with Bank of Oklahoma, our only commodity derivative counterparty, was $58.7 million as of December 31, 2021.
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.
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Below is the effect of derivative instruments on the consolidated statements of operations for the periods indicated:
| Successor | Predecessor | |||||||||||||||||||
| Year Ended December 31, 2021 | Four Months Ended December 31, 2020 | Eight Months Ended August 31, 2020 | ||||||||||||||||||
| (In thousands) | ||||||||||||||||||||
| Loss on derivatives | $ | (97,615) | $ | (985) | $ | (10,704) | ||||||||||||||
| Cash settlements paid on commodity derivatives | (44,591) | (1,133) | (4,244) | |||||||||||||||||
| Loss on derivatives less cash settlements paid on commodity derivatives | $ | (53,025) | $ | 148 | $ | (6,460) | ||||||||||||||
| Loss on change in fair value of warrants | $ | (18,937) | $ | — | $ | — | ||||||||||||||
If a legal right of set-off exists, we net the value of the derivative arrangements we have with the same counterparty on our consolidated balance sheets. The fair value of our commodity derivatives on our consolidated balance sheets were current derivative liabilities of $40.9 million and long-term derivative liabilities of $17.9 million as of December 31, 2021 compared to current derivative liabilities of $1.0 million and non-current derivative liabilities of $4.7 million as of December 31, 2020.
Stock-Based Compensation
We granted 315,529 restricted stock units (RSU) with an aggregate grant date fair value of $8.4 million and 361,418 stock options with an aggregate grant date fair value of $4.1 million. Director RSU grants will 25% vest on each of the following dates: May 27, 2022, September 3, 2022, September 3, 2023, and September 3, 2024 while employee RSU grants will one-third vest on each of the following dates: November 21, 2022, October 1, 2023, and October 1, 2024. The stock option grants will one-third vest on each of the following dates: October 1, 2022, October 1, 2023, and October 1, 2024. We recognized compensation expense of $0.8 million during the year ended December 31, 2021. We did not capitalize any compensation cost to oil and natural gas properties due to the absence of significant drilling.
We did not grant any new awards during the four months ended December 31, 2020 or the eight months ended August 31, 2020. 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 eight months ended August 31, 2020. 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 due to the absence of significant drilling.
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.
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Results of Operations
Year Ended December 31, 2021 versus Year Ended December 31, 2020
Provided below is a comparison of selected operating and financial data (in thousands unless otherwise specified):
| Successor | Successor | Predecessor | Percent Change (1) | ||||||||||||||||||||||||||
| Year Ended December 31, 2021 | Four Months Ended December 31, 2020 | Eight Months Ended August 31, 2020 | |||||||||||||||||||||||||||
| Total revenue, before eliminations | $ | 690,012 | $ | 145,362 | $ | 291,493 | 58 | % | |||||||||||||||||||||
| Total revenue, after eliminations | $ | 638,716 | $ | 133,528 | $ | 276,957 | 56 | % | |||||||||||||||||||||
| Net income (loss) | $ | 48,216 | $ | (13,988) | $ | (890,624) | 105 | % | |||||||||||||||||||||
| Net income (loss) attributable to non-controlling interest | $ | (12,431) | $ | 4,152 | $ | 40,388 | (128) | % | |||||||||||||||||||||
| Net income (loss) attributable to Unit Corporation | $ | 60,647 | $ | (18,140) | $ | (931,012) | 106 | % | |||||||||||||||||||||
| Oil and Natural Gas: | |||||||||||||||||||||||||||||
| Revenue, before eliminations | $ | 272,231 | $ | 57,580 | $ | 103,443 | 69 | % | |||||||||||||||||||||
| Operating costs, before eliminations | $ | 83,221 | $ | 26,111 | $ | 119,664 | (43) | % | |||||||||||||||||||||
| Average oil price (Bbl) | $ | 50.03 | $ | 37.29 | $ | 31.98 | 49 | % | |||||||||||||||||||||
| Average oil price excluding derivatives (Bbl) | $ | 66.50 | $ | 39.23 | $ | 35.14 | 83 | % | |||||||||||||||||||||
| Average NGLs price (Bbl) | $ | 23.41 | $ | 9.28 | $ | 4.83 | NM | ||||||||||||||||||||||
| Average NGLs price excluding derivatives (Bbls) | $ | 23.41 | $ | 9.28 | $ | 4.83 | NM | ||||||||||||||||||||||
| Average natural gas price (Mcf) | $ | 2.93 | $ | 1.92 | $ | 1.14 | 114 | % | |||||||||||||||||||||
| Average natural gas price excluding derivatives (Mcf) | $ | 3.55 | $ | 1.91 | $ | 1.11 | 163 | % | |||||||||||||||||||||
| Oil production (MBbls) | 1,615 | 626 | 1,562 | (26) | % | ||||||||||||||||||||||||
| NGLs production (MBbls) | 2,624 | 1,045 | 2,399 | (24) | % | ||||||||||||||||||||||||
| Natural gas production (MMcf) | 29,012 | 11,006 | 26,561 | (23) | % | ||||||||||||||||||||||||
| Contract Drilling: | |||||||||||||||||||||||||||||
| Revenue, before eliminations | $ | 76,107 | $ | 19,413 | $ | 73,519 | (18) | % | |||||||||||||||||||||
| Operating costs, before eliminations | $ | 60,973 | $ | 13,852 | $ | 51,810 | (7) | % | |||||||||||||||||||||
| Average number of drilling rigs in use | 10.9 | 7.2 | 11.5 | 8 | % | ||||||||||||||||||||||||
| Total drilling rigs available for use at the end of the period | 21 | 58 | 58 | (64) | % | ||||||||||||||||||||||||
| Average dayrate on daywork contracts | $ | 17,987 | $ | 17,807 | $ | 18,911 | (4) | % | |||||||||||||||||||||
| Mid-Stream: | |||||||||||||||||||||||||||||
| Revenue, before eliminations | $ | 341,674 | $ | 68,369 | $ | 114,531 | 87 | % | |||||||||||||||||||||
| Operating costs, before eliminations | $ | 286,199 | $ | 53,147 | $ | 80,607 | 114 | % | |||||||||||||||||||||
| Gas gathered--Mcf/day | 319,394 | 324,892 | 388,506 | (13) | % | ||||||||||||||||||||||||
| Gas processed--Mcf/day | 130,000 | 135,615 | 158,031 | (14) | % | ||||||||||||||||||||||||
| Gas liquids sold--gallons/day | 442,796 | 441,761 | 612,301 | (20) | % | ||||||||||||||||||||||||
| Number of natural gas gathering systems | 18 | 17 | 18 | 6 | % | ||||||||||||||||||||||||
| Number of processing plants | 12 | 11 | 11 | 9 | % | ||||||||||||||||||||||||
| Corporate and Other: | |||||||||||||||||||||||||||||
| General and administrative expense, before eliminations | $ | 21,399 | $ | 6,702 | $ | 42,766 | (57) | % | |||||||||||||||||||||
| Interest expense, net | $ | (4,266) | $ | (3,275) | $ | (22,882) | (84) | % | |||||||||||||||||||||
| Write-off of debt issuance costs | $ | — | $ | — | $ | (2,426) | (100) | % | |||||||||||||||||||||
| Reorganization items, net | $ | (4,294) | $ | (2,273) | $ | 133,975 | (103) | % | |||||||||||||||||||||
| Loss on derivatives | $ | (97,615) | $ | (985) | $ | (10,704) | NM | ||||||||||||||||||||||
| Loss on change in fair value of warrants | $ | (18,937) | $ | — | $ | — | — | % | |||||||||||||||||||||
| Income tax (benefit) expense | $ | 173 | $ | (302) | $ | (14,630) | 101 | % | |||||||||||||||||||||
| Average interest rate | 6.4 | % | 6.8 | % | 5.5 | % | 14 | % | |||||||||||||||||||||
| Average long-term debt outstanding | $ | 46,222 | $ | 121,740 | $ | 526,167 | (88) | % | |||||||||||||||||||||
1.NM – A percentage calculation is not meaningful due to a zero-value denominator or a percentage change greater than 200.
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Oil and Natural Gas
Oil and natural gas revenues increased $111.2 million or 69% during the year ended December 31, 2021 compared to the year ended December 31, 2020 primarily due to higher commodity prices partially offset by lower production volumes. The decrease in volumes was due to normal well production declines and divestitures of producing properties which have not been offset by new drilling or acquisitions.
Oil and natural gas operating costs decreased $62.6 million or 43% during the year ended December 31, 2021 compared to the year ended December 31, 2020 primarily due to the absence of gains recognized on the settlement of Predecessor Period liabilities subject to compromise under the Plan offset by increased production tax expenses due to increased revenues.
Impairment of oil and natural gas properties decreased $419.8 million during the year ended December 31, 2021 compared to the year ended December 31, 2020 due to the absence of the ceiling test write-downs and salt water disposal asset impairment recorded during the year ended December 31, 2020.
Depreciation, depletion, and amortization of oil and natural gas properties decreased $59.0 million or 71% during the year ended December 31, 2021 compared to the year ended December 31, 2020 primarily due to a lower depreciable base subsequent to fresh start accounting and lower average production.
Contract Drilling
Contract drilling revenues decreased $16.8 million or 18% during the year ended December 31, 2021 compared to the year ended December 31, 2020 primarily due to lower rig termination and standby fees of $0.1 million in 2021 compared to $18.5 million in 2020. Additionally, there was an 8% increase in the average number of drilling rigs in use and a 4% decrease in the average dayrate. Average drilling rig utilization increased from 10.1 drilling rigs in the year ended December 31, 2020 to 10.9 drilling rigs in the year ended December 31, 2021.
Contract drilling operating costs decreased 4.7 million or 7% during the year ended December 31, 2021 compared to the year ended December 31, 2020 primarily due to the reduced number of drilling rigs operating.
Impairment of contract drilling equipment decreased $410.1 million during the year ended December 31, 2021 compared to the year ended December 31, 2020 due to the absence of impairments of SCR drilling rigs and other equipment recorded during the year ended December 31, 2020.
Depreciation of contract drilling equipment decreased $11.3 million or 64% during the year ended December 31, 2021 compared to the year ended December 31, 2020 primarily due to fewer rigs available for use and a lower depreciable base subsequent to fresh start accounting, partially offset by higher average drilling rig utilization.
Mid-Stream
Mid-Stream revenues increased $158.8 million or 87% during the year ended December 31 2021 compared to the year ended December 31, 2020 primarily due to higher prices, partially offset by lower volumes. Gas processed volumes per day decreased 14% between the comparative periods primarily due to declining volumes and fewer new wells connected to our processing systems. Gas gathered volumes per day decreased 13% between the comparative periods also due to declining volumes and fewer new wells connected to our gathering systems. We also experienced overall lower volumes due to the February 2021 winter storm.
Operating costs increased $152.4 million or 114% during the year ended December 31, 2021 compared to the year ended December 31, 2020 primarily due to higher gas, NGLs, and condensate prices, partially offset by lower purchase volumes.
Impairment of mid-stream assets decreased $53.3 million during the year ended December 31, 2021 compared to the year ended December 31, 2020 primarily due to the absence of $64.0 million of impairment of certain assets in southern Kansas and central Oklahoma recorded during the year ended December 31, 2020, partially offset by $10.7 million of impairment to a gathering system in Pennsylvania during the year ended December 31, 2021.
Depreciation of mid-stream assets decreased $7.5 million or 19% primarily due to a lower depreciable base subsequent to fresh start accounting.
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General and Administrative
General and administrative expenses decreased $28.1 million or 57% during the year ended December 31, 2021 compared to the year ended December 31, 2020 primarily due to lower headcount, the absence of separation benefits recognized during 2020 as well as lower legal spend.
Interest, net
Interest expense decreased $21.9 million during the year ended December 31, 2021 compared to the year ended December 31, 2020 primarily due to a reduction in average long-term debt outstanding, partially offset by a higher average interest rate. Our average long-term debt outstanding decreased $345.1 million during the year ended December 31, 2021 compared to the year ended December 31, 2020 primarily due to the Notes being settled in conjunction with the Plan as well as subsequent payments made under the Exit credit agreement while our average interest rate increased from 5.6% during the year ended December 31, 2020 to 6.4% during the year ended December 31, 2021.
Write-off of Debt Issuance Costs
Unamortized debt issuance costs of $2.4 million were written off during the year ended December 31, 2020 due to the termination of the remaining commitments of the Predecessor Period Unit credit agreement.
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.
Loss on Derivatives
Loss on derivatives increased by $85.9 million during the year ended December 31, 2021 compared to the year ended December 31, 2020 primarily due to increases in commodity market pricing.
Loss on Change in Fair Value of Warrants
Loss on change in fair value of warrants increased by $18.9 million during the year ended December 31, 2021 compared to the year ended December 31, 2020 primarily due to increases in Unit's share price as well as higher volatility assumptions, partially offset by lower duration to exercise given the passage of time.
Income Tax
Income tax expense was $0.2 million during the year ended December 31, 2021 compared to an income tax benefit of $14.9 million during the year ended December 31, 2020 primarily due to the absence of the losses generated during the year ended December 31, 2020 and the full valuation allowance against our net deferred tax asset.
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.
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Item 7A. Quantitative and Qualitative Disclosures about Market Risk
Commodity Price Risk. Our major market risk exposure is in the prices we receive for our oil, NGLs, and natural gas production. Those prices are primarily driven by the prevailing worldwide price for crude oil and market prices applicable to our natural gas production. Historically, these prices have fluctuated, and they will probably continue to do so. The price of oil, NGLs, and natural gas also affects both the demand for our drilling rigs and the amount we can charge for our drilling rigs. Based on our 2021 production, a $0.10 per Mcf change in what we are paid for our natural gas production would cause a corresponding $250 per month ($3.0 million annualized) change in our pre-tax cash flow. A $1.00 per barrel change in our oil price would have a $130 per month ($1.6 million annualized) change in our pre-tax operating cash flow and a $1.00 per barrel change in our NGLs prices would have a $220 per month ($2.6 million annualized) change in our pre-tax cash flow.
We use derivative transactions to manage the risk associated with price volatility. 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. The transactions we use include financial price swaps under which we will receive a fixed price for our production and pay a variable market price to the contract counterparty. We do not hold or issue derivative instruments for speculative trading purposes.
At December 31, 2021, these non-designated hedges were outstanding:
| Term | Commodity | Contracted Volume | Weighted Average Fixed Price for Swaps | Contracted Market | ||||||||||||||||||||||
| 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'22 - Jun'22 | Crude oil - swap | 986 Bbl/day | $70.3 | 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 | ||||||||||||||||||||||
Interest Rate Risk. Our interest rate exposure relates to our long-term debt under our credit agreements. Borrowings under our Exit credit agreement and Superior credit agreement bear interest at variable interest rates. Based on our average outstanding long-term debt subject to a variable rate in 2021, a 1% increase in the interest rate on the outstanding borrowings under these facilities would reduce our annual pre-tax cash flow by approximately $0.5 million.
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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 (PCAOB ID Number 248) | |||||
49
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 sheets of Unit Corporation (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2021 and 2020 (Successor), the related consolidated statements of operations, comprehensive income (loss), changes in shareholders’ equity, and cash flows for the year ended December 31, 2021 and 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, 2021 and 2020, and the results of its operations and its cash flows for the year ended December 31, 2021 and 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 25.
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 audits. 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 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 audits 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 audits 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 audits 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 audits provide a reasonable basis for our opinion.
Critical audit matter
The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved especially challenging, subjective, or complex judgments. The communication of a critical audit matter 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 a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
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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 3 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 potential 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 certain 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, 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.
/s/ GRANT THORNTON LLP
We have served as the Company's auditor since 2020.
Tulsa, Oklahoma
March 31, 2022
51
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
_________________________
1.Unit Corporation's consolidated total assets as of December 31, 2021 include current and long-term assets of its variable interest entity (VIE) (Superior) of $61.1 million and $229.5 million, respectively, which can only be used to settle obligations of the VIE. Unit Corporation's consolidated cash and cash equivalents of $64.1 million as of December 31, 2021 includes $17.2 million held by Superior. 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 cash and cash equivalents of $12.1 million as of December 31, 2020 includes $11.6 million held by Superior.
The accompanying notes are an integral part of the consolidated financial statements.
52
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS - (Continued)
_________________________
1.Unit Corporation's consolidated total liabilities as of December 31, 2021 include current and long-term liabilities of Superior of $42.3 million and $21.2 million, respectively, for which the creditors of the VIE have no recourse to Unit Corporation. All of Unit Corporation's consolidated long-term debt of $19.2 million as of December 31, 2021 was held by Superior. 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. None of Unit Corporation's consolidated long-term debt of $98.4 million as of December 31, 2020 was held by Superior.
The accompanying notes are an integral part of the consolidated financial statements.
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UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
| Successor | Predecessor | |||||||||||||||||||
| Year Ended December 31, 2021 | Four Months Ended December 31, 2020 | Eight Months Ended August 31, 2020 | ||||||||||||||||||
| (In thousands except per share amounts) | ||||||||||||||||||||
| Revenues: | ||||||||||||||||||||
| Oil and natural gas | $ | 224,232 | $ | 57,578 | $ | 103,439 | ||||||||||||||
| Contract drilling | 76,107 | 19,413 | 73,519 | |||||||||||||||||
| Gas gathering and processing | 338,377 | 56,537 | 99,999 | |||||||||||||||||
| Total revenues | 638,716 | 133,528 | 276,957 | |||||||||||||||||
| Expenses: | ||||||||||||||||||||
| Operating costs: | ||||||||||||||||||||
| Oil and natural gas | 79,924 | 25,256 | 117,691 | |||||||||||||||||
| Contract drilling | 60,973 | 13,852 | 51,810 | |||||||||||||||||
| Gas gathering and processing | 234,684 | 42,169 | 68,045 | |||||||||||||||||
| Total operating costs | 375,581 | 81,277 | 237,546 | |||||||||||||||||
| Depreciation, depletion, and amortization | 64,326 | 27,962 | 115,496 | |||||||||||||||||
| Impairments (Note 4) | 10,673 | 26,063 | 867,814 | |||||||||||||||||
| Loss on abandonment of assets (Note 4) | — | — | 18,733 | |||||||||||||||||
| General and administrative | 24,915 | 6,702 | 42,766 | |||||||||||||||||
| Gain on disposition of assets | (10,877) | (619) | (89) | |||||||||||||||||
| Total operating expenses | 464,618 | 141,385 | 1,282,266 | |||||||||||||||||
| Income from operations | 174,098 | (7,857) | (1,005,309) | |||||||||||||||||
| Other income (expense): | ||||||||||||||||||||
| Interest, net | (4,266) | (3,275) | (22,824) | |||||||||||||||||
| Write-off debt issuance costs | — | — | (2,426) | |||||||||||||||||
| Gain (loss) on derivatives (Note 17) | (97,615) | (985) | (10,704) | |||||||||||||||||
| Loss on change in fair value of warrants (Note 17) | (18,937) | — | — | |||||||||||||||||
| Reorganization items, net (Note 25) | (4,294) | (2,273) | 133,975 | |||||||||||||||||
| Other, net | (597) | 100 | 2,034 | |||||||||||||||||
| Total other income (expense) | (125,709) | (6,433) | 100,055 | |||||||||||||||||
| Income (loss) before income taxes | 48,389 | (14,290) | (905,254) | |||||||||||||||||
| Income tax expense (benefit): | ||||||||||||||||||||
| Current | 173 | (302) | (917) | |||||||||||||||||
| Deferred | — | — | (13,713) | |||||||||||||||||
| Total income taxes | 173 | (302) | (14,630) | |||||||||||||||||
| Net income (loss) | 48,216 | (13,988) | (890,624) | |||||||||||||||||
| Net income (loss) attributable to non-controlling interest | (12,431) | 4,152 | 40,388 | |||||||||||||||||
| Net income (loss) attributable to Unit Corporation | $ | 60,647 | $ | (18,140) | $ | (931,012) | ||||||||||||||
| Net income (loss) attributable to Unit Corporation per common share (Note 8): | ||||||||||||||||||||
| Basic | $ | 5.32 | $ | (1.51) | $ | (17.45) | ||||||||||||||
| Diluted | $ | 5.26 | $ | (1.51) | $ | (17.45) | ||||||||||||||
The accompanying notes are an integral part of the consolidated financial statements.
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UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
| Successor | Predecessor | |||||||||||||||||||
| Year Ended December 31, 2021 | Four Months Ended December 31, 2020 | Eight Months Ended August 31, 2020 | ||||||||||||||||||
| (In thousands) | ||||||||||||||||||||
| Net income (loss) | $ | 48,216 | $ | (13,988) | $ | (890,624) | ||||||||||||||
| Other comprehensive income (loss), net of taxes: | ||||||||||||||||||||
| Reclassification adjustment for write-down of securities | — | — | — | |||||||||||||||||
| Comprehensive income (loss) | 48,216 | (13,988) | (890,624) | |||||||||||||||||
| Less: Comprehensive income (loss) attributable to non-controlling interest | (12,431) | 4,152 | 40,388 | |||||||||||||||||
| Comprehensive income (loss) attributable to Unit Corporation | $ | 60,647 | $ | (18,140) | $ | (931,012) | ||||||||||||||
The accompanying notes are an integral part of the consolidated financial statements.
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UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY
Shareholders' Equity Attributable to Unit Corporation | |||||||||||||||||||||||||||||||||||
Common Stock | Treasury Stock | Capital In Excess of Par Value | Retained Earnings (Deficit) | Non-controlling Interest in Consolidated Subsidiaries | Total | ||||||||||||||||||||||||||||||
| (In thousands) | |||||||||||||||||||||||||||||||||||
| Balances, December 31, 2019 (Predecessor) | 10,591 | — | 644,152 | 199,135 | 201,757 | 1,055,635 | |||||||||||||||||||||||||||||
| Net income (loss) | — | — | — | (931,012) | 40,388 | (890,624) | |||||||||||||||||||||||||||||
| Activity in stock-based 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 stock-based compensation plans | — | — | 39 | — | 19 | 58 | |||||||||||||||||||||||||||||
| Balances, December 31, 2020 (Successor) | 120 | — | 197,242 | (18,140) | 246,371 | 425,593 | |||||||||||||||||||||||||||||
| Net income (loss) | 60,647 | (12,431) | 48,216 | ||||||||||||||||||||||||||||||||
| Activity in stock-based compensation plans | — | — | 929 | — | 31 | 960 | |||||||||||||||||||||||||||||
| Distributions to non-controlling interests | — | — | — | — | (23,136) | (23,136) | |||||||||||||||||||||||||||||
| Balance correction (Note 3) | — | — | — | (1,436) | 1,436 | — | |||||||||||||||||||||||||||||
| Repurchases of common stock | — | (51,965) | — | — | — | (51,965) | |||||||||||||||||||||||||||||
| Balances, December 31, 2021 (Successor) | $ | 120 | $ | (51,965) | $ | 198,171 | $ | 41,071 | $ | 212,271 | $ | 399,668 | |||||||||||||||||||||||
The accompanying notes are an integral part of the consolidated financial statements.
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UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
| Successor | Predecessor | |||||||||||||||||||
| Year Ended December 31, 2021 | Four Months Ended December 31, 2020 | Eight Months Ended August 31, 2020 | ||||||||||||||||||
| (In thousands) | ||||||||||||||||||||
| OPERATING ACTIVITIES: | ||||||||||||||||||||
| Net income (loss) | $ | 48,216 | $ | (13,988) | $ | (890,624) | ||||||||||||||
| Adjustments to reconcile net income operating activities: | ||||||||||||||||||||
| Depreciation, depletion, and amortization | 64,326 | 27,962 | 115,496 | |||||||||||||||||
| Impairments (Note 4) | 10,673 | 26,063 | 867,814 | |||||||||||||||||
| Loss on abandonment of assets (Note 4) | — | — | 18,733 | |||||||||||||||||
| Amortization of debt issuance costs and debt discount (Note 10) | — | — | 1,079 | |||||||||||||||||
| Loss on derivatives (Note 17) | 97,615 | 985 | 10,704 | |||||||||||||||||
| Cash receipts (payments) on derivatives settled (Note 17) | (44,591) | (1,133) | (4,244) | |||||||||||||||||
| Loss on change in fair value of warrants (Note 17) | 18,937 | — | — | |||||||||||||||||
| Gain on disposition of assets | (10,877) | (619) | (89) | |||||||||||||||||
| Write-off of debt issuance costs | — | — | 2,426 | |||||||||||||||||
| Deferred tax expense (Note 13) | — | — | (13,713) | |||||||||||||||||
| Stock-based compensation plans | 929 | 58 | 4,786 | |||||||||||||||||
| Credit loss expense | 1,633 | — | 3,155 | |||||||||||||||||
| ARO liability accretion (Note 11) | 1,893 | 467 | 1,545 | |||||||||||||||||
| Contract assets and liabilities, net (Note 5) | 3,699 | 1,316 | 2,459 | |||||||||||||||||
| Capitalized contract fulfillment costs, net | (537) | — | — | |||||||||||||||||
| Noncash reorganization items | 10 | 67 | (138,797) | |||||||||||||||||
| Other, net | (843) | (3,046) | 12,164 | |||||||||||||||||
| Changes in operating assets and liabilities increasing (decreasing) cash: | ||||||||||||||||||||
| Accounts receivable | (31,034) | (7,226) | 28,880 | |||||||||||||||||
| Materials and supplies | — | — | 89 | |||||||||||||||||
| Prepaid expenses and other | (4,953) | 1,795 | (3,849) | |||||||||||||||||
| Accounts payable | 23,141 | 1,484 | (18,381) | |||||||||||||||||
| Accrued liabilities | (3,331) | (4,048) | 44,811 | |||||||||||||||||
| Income taxes | 1,160 | (301) | 906 | |||||||||||||||||
| Contract advances | (97) | (29) | (394) | |||||||||||||||||
| Net cash provided by operating activities | 175,969 | 29,807 | 44,956 | |||||||||||||||||
| INVESTING ACTIVITIES: | ||||||||||||||||||||
| Capital expenditures | (30,305) | (4,057) | (25,775) | |||||||||||||||||
| Producing property and other oil and natural gas acquisitions | — | — | (382) | |||||||||||||||||
| Other acquisitions | (13,000) | — | — | |||||||||||||||||
| Proceeds from disposition of property and equipment | 79,510 | 1,799 | 6,018 | |||||||||||||||||
| Net cash provided by (used in) investing activities | $ | 36,205 | $ | (2,258) | $ | (20,139) | ||||||||||||||
The accompanying notes are an integral part of the consolidated financial statements.
57
| Successor | Predecessor | |||||||||||||||||||
| Year Ended December 31, 2021 | Four Months Ended December 31, 2020 | Eight Months Ended August 31, 2020 | ||||||||||||||||||
| (In thousands) | ||||||||||||||||||||
| FINANCING ACTIVITIES: | ||||||||||||||||||||
| Borrowings under line of credit, including borrowings under DIP credit facility | $ | 65,300 | $ | — | $ | 87,400 | ||||||||||||||
| Payments under line of credit | (145,100) | (49,000) | (64,100) | |||||||||||||||||
| DIP financing costs | — | — | (990) | |||||||||||||||||
| Exit facility financing costs | — | — | (3,225) | |||||||||||||||||
| Net payments on finance leases | (3,216) | (1,406) | (2,757) | |||||||||||||||||
| Employee taxes paid by withholding shares | — | — | (43) | |||||||||||||||||
| Distributions to non-controlling interest | (23,136) | — | — | |||||||||||||||||
| Repurchase of common stock | (51,965) | — | — | |||||||||||||||||
| Bank overdrafts (Note 3) | (2,631) | 2,631 | (8,733) | |||||||||||||||||
| Net cash provided by (used in) financing activities | (160,748) | (47,775) | 7,552 | |||||||||||||||||
| Net increase (decrease) in cash, restricted cash, and cash equivalents | 51,426 | (20,226) | 32,369 | |||||||||||||||||
| Cash, restricted cash, and cash equivalents, beginning of period | 12,714 | 32,940 | 571 | |||||||||||||||||
| Cash, restricted cash, and cash equivalents, end of period | $ | 64,140 | $ | 12,714 | $ | 32,940 | ||||||||||||||
| Supplemental disclosure of cash flow information: | ||||||||||||||||||||
| Cash paid for: | ||||||||||||||||||||
| Interest paid (net of capitalized) | $ | 4,769 | $ | 2,571 | $ | 6,417 | ||||||||||||||
| Income taxes | $ | — | $ | — | $ | — | ||||||||||||||
| Reorganization items | $ | 4,283 | $ | 2,206 | $ | 4,822 | ||||||||||||||
| Changes in accounts payable and accrued liabilities related to purchases of property and equipment | $ | (1,249) | $ | 1,902 | $ | 8,561 | ||||||||||||||
| Non-cash reductions (increases) to oil and natural gas properties related to asset retirement obligations | $ | (478) | $ | 1,702 | $ | 29,189 | ||||||||||||||
| Non-cash trade of property and equipment | $ | — | $ | — | $ | 1,403 | ||||||||||||||
The accompanying notes are an integral part of the consolidated financial statements.
58
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 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, and North Dakota.
Mid-Stream. Carried out by our subsidiary, Superior, we buy, sell, gather, transport, process, and treat natural gas for our own account and for third parties. Mid-stream operations are performed in Oklahoma, Texas, Kansas, Pennsylvania, and West Virginia.
NOTE 2 – 2020 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 participation 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;
59
•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.
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 Old Common Stock outstanding before the Effective Date that did not opt out of the release under the Plan, is entitled to receive 0.03460447 warrants for every share of Old Common Stock owned. Each warrant will initially be exercisable for one share of New Common Stock, subject to adjustment as provided in the Warrant Agreement. The exercise price of the Warrants will be determined, and the Warrants will become exercisable, once the Debtors have completed the claims reconciliation process and resolved any objections to disputed claims under the Bankruptcy Petitions. The initial exercise price per share for the Warrants will be set at an amount that implies a recovery by holders of the Subordinated Notes of the $650 million principal amount of the Subordinated Notes plus interest thereon to the May 15, 2021 maturity date of the Notes. 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.
The warrants issued to holders of the company’s Old Common Stock that did not opt-out of the releases under the Plan and that owned their shares of old common stock through Direct Registration are outlined below:
| Issuance Date | Warrants Issued | ||||
| December 21, 2020 | 1,764,164 | ||||
| February 11, 2021 | 42,511 | ||||
| July 29, 2021 | 10,521 | ||||
| October 13, 2021 | 5,005 | ||||
| Total | 1,822,201 | ||||
The company expects to issue approximately 21,117 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.
Events of Default
The filing of the Chapter 11 Cases, in addition to other events of default including cross-defaults, constituted an event of default that accelerated the company's obligations under the Unit credit agreement and the indenture governing the Notes. 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.
60
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.
Liquidity and Borrowings
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).
Also on the Effective Date, under the Plan, we entered into an amended and restated credit agreement (Exit credit agreement). Refer to Note 10 – Long-Term Debt And Other Long-Term Liabilities for the terms of the Exit credit agreement.
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 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation. The consolidated financial statements include the accounts of Unit Corporation and its subsidiaries. We have consolidated 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 (U.S. GAAP), for each of the periods presented in the consolidated financial statements. 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 20 – Variable Interest Entities. All intercompany transactions and accounts have been eliminated.
During 2021, management identified an error in the initial allocation of equity between Unit Corporation and non-controlling interests as of the Fresh Start Reporting Date. The impact of the error was not material to any of our prior period financial statements and the error was corrected with one-time adjustment during the year ended December 31, 2021. As a result, during the year ended December 31, 2021, retained earnings (deficit) was reduced by $1.4 million with a corresponding decrease to non-controlling interest in consolidated subsidiaries.
Certain amounts presented 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.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
2020 Reorganization and Fresh Start Accounting. The consolidated financial statements in Note 25 - 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. 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, and 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 periods.
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. That guidance requires certain transactions and events that were directly related to our reorganization be distinguished from our normal business operations for periods after our bankruptcy filing on May 22, 2020 or post-petition periods. 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.
Accounting Estimates. Preparing financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts and disclosures in the consolidated financial statements. Actual results could differ from those estimates. Significant estimates and assumptions include:
•oil and gas reserves quantities and values;
•full cost ceiling test and impairment assessments for property and equipment;
•asset retirement obligations;
•fair value of commodity derivative assets and liabilities;
•fair value of the warrant liability;
•reorganization fair value as of the Effective Date,
•grant date fair value of stock-based compensation;
•workers' compensation liabilities;
•contingency, litigation, and environmental liabilities;
•and realizability of deferred tax assets;
Cash and Cash Equivalents. We include as cash and cash equivalents all cash on hand and on deposit, as well as highly liquid investments with maturities of three months or less which are readily convertible into known amounts of cash. The financing section of our consolidated statements of cash flows reflects bank overdraft activity. 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. There were no bank overdrafts as of December 31, 2021 and $2.6 million as of December 31, 2020.
Accounts Receivable, Net of Allowance for Credit Losses. Accounts receivable are carried on a gross basis, with no discounting, less an allowance for expected credit losses. We estimate the allowance for credit losses 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 credit losses only after all collection attempts have been unsuccessful.
Property and Equipment.
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 under which we capitalize 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. We did not capitalize any directly related overhead costs in 2021 or 2020.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
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 $2.67, $4.21, and $7.77 per Boe for the year ended December 31, 2021, the four months ended December 31, 2020, and the eight months ended August 31, 2020.
Our contract drilling segment may provide drilling services for our oil and natural gas segment. Revenues and expenses from these services are eliminated in our consolidated statements of operations, with any recognized profit reducing our investment in our oil and natural gas properties. There were no intercompany drilling services provided for elimination in the year ended December 31, 2021, four months ended December 31, 2020, or eight months ended August 31, 2020.
No gains or losses are recognized on the sale, conveyance, or other disposition of oil and natural gas properties unless it results in a significant alteration to our full cost pool.
Drilling equipment, gas gathering and processing equipment, corporate land and building, transportation equipment, and other property and equipment. Drilling equipment, gas gathering and processing equipment, corporate land and building, transportation equipment, 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 and thereafter, we elected to depreciate all drilling assets utilizing the straight-line method over the estimated useful lives of the assets ranging from four to ten years. Depreciation on our former corporate building was computed using the straight-line method over the estimated useful life of 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 to 15 years.
Impairment and disposal. We review the carrying amounts of long-lived assets for potential impairment when events occur or changes in circumstances suggest these carrying amounts may not be recoverable. Changes that could prompt an assessment include equipment obsolescence, changes in the market demand for a specific asset, changes in commodity prices, periods of relatively low drilling rig utilization, declining revenue per day, declining cash margin per day, or overall changes in general market conditions. Assets are determined to be impaired if a forecast of undiscounted estimated future net operating cash flows directly related to the asset, including disposal value if any, is less than the carrying amount of the asset. If any asset is determined to be impaired, the loss is measured as the amount by which the carrying asset exceeds its fair value. The estimate of fair value is based on the best information available, including prices for similar assets. Changes in these estimates could cause us to reduce the carrying value of property and equipment. Asset impairment evaluations are, by nature, highly subjective. They involve expectations about future cash flows generated by our assets and reflect our assumptions and judgments regarding future industry conditions and their effect on future utilization levels, dayrates, and costs. Using different estimates and assumptions could result in materially different carrying values of our assets.
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.
Capitalized Interest. Interest costs associated with major asset additions are capitalized during the construction period using a weighted average interest rate based on our outstanding borrowings. We did not capitalize any interest costs in 2021 or 2020.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
Leases. We enter into various agreements to lease equipment and buildings, and we review each agreement to determine if they contain operating or finance leases with a term greater than 12 months. We recognize a lease liability on identified leases for the obligation to make lease payments and a right-of-use asset for the right to use the underlying asset for the lease term based on the present value of lease payments over the lease term which includes all noncancelable periods as well as periods covered by options to extend the lease that we are reasonably certain to exercise. Leases with an initial term of 12 months or less are not recorded as a lease right-of-use asset and liability. Most leases are valued using an incremental borrowing rate, which is determined based on information available at the commencement date of a lease, as an implicit borrowing rate cannot be determined under most of our leases. Leases may include renewal, purchase or termination options that can extend or shorten the term of the lease. These options are evaluated at inception and throughout the contract term to determine if a modification of the lease term is required. Leases with an initial term of 12 months or less are not recorded as a lease right-of-use asset and liability.
Expenses related to leases determined to be operating leases will be recognized on a straight-line basis over the lease term including any reasonably certain renewal periods, while those determined to be finance leases will be recognized following a front-loaded expense profile in which interest and amortization are presented separately in the consolidated statements of operations. The determination of whether a lease is accounted for as a finance lease or an operating lease requires management's estimates of the fair value of the underlying asset and its estimated economic useful life, among other considerations.
ARO. 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 estimated liabilities related to these future costs are recorded at the time the wells are drilled or acquired. We use historical experience to determine the estimated plugging costs considering the well's type, depth, physical location, and ultimate productive life. A risk-adjusted discount rate and an inflation factor are applied to estimate the present value of these obligations. We depreciate the capitalized asset retirement cost and accrete the obligation over time. Revisions to the obligations and assets are recognized at the appropriate risk-adjusted discount rate with a corresponding adjustment made to the full cost pool. Our mid-stream segment has property and equipment at locations leased or under right of way agreements which may require asset removal or site restoration, however, we are not able to reasonably measure the fair value of the obligations as the potential settlement dates are indeterminable.
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.
Commodity Derivatives. All commodity derivatives are recognized on the consolidated balance sheets as either an asset or liability measured at fair value and all our commodity derivative counterparties are subject to master netting agreements. We net the value of the derivative transactions with the same counterparty if a legal right to set-off exists. Changes in the fair value of our commodity derivatives and gains or losses on commodity derivative settlement are reported in gain (loss) on derivatives in our consolidated statements of operations. Cash settlements received or paid for matured, early-terminated, and/or modified derivatives are reported in cash receipts (payments) on derivatives settled in our consolidated statements of cash flows.
Income Taxes. Income taxes are recognized based on earnings reported for tax return purposes in addition to a provision for deferred income taxes. Deferred income taxes are recognized at the end of each reporting period for the future tax consequences of cumulative temporary differences between the tax basis of assets and liabilities and their reported amounts in the Company’s consolidated financial statements based on existing tax laws and enacted statutory tax rates applicable to the periods in which the temporary differences are expected to affect taxable income. U.S. GAAP requires the recognition of a deferred tax asset for net operating loss carryforwards and tax credit carryforwards. We periodically assesses the realizability of the deferred tax assets by considering all available evidence (both positive and negative) to determine whether it is more likely than not that all or a portion of the deferred tax assets will not be realized and a valuation allowance is required.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
Natural Gas Balancing. When there are insufficient remaining reserves to offset a gas imbalance, we recognize an asset or a liability for the under-produced or over-produced position. We have recorded a receivable of $0.6 million on certain wells where we estimate that insufficient reserves are available for us to recover our under-production from future production volumes and a liability of $1.1 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 as of December 31, 2021. 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.
Stock-Based Compensation. We recognize the cost of stock-based compensation over the requisite service periods, which is generally the vesting period, based on the grant date fair value of those awards and account for forfeitures as they occur.
Warrant Liability. 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.
Recently Issued Accounting Standards
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. 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.
Debt—Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging— Contracts in Entity’s Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity. The FASB issued ASU 2020-06 which simplifies the accounting for convertible instruments by removing certain accounting models which separate the embedded conversion features from the host contract for convertible instruments. The ASU further removes certain settlement conditions that are required for equity contracts to qualify for the derivative scope exception and simplifies the diluted earnings per share calculation in certain areas. The ASU is effective for fiscal years beginning after December 15, 2021, including interim periods within those fiscal years. We will adopt ASU 2020-06 effective January 1, 2022. The adoption of this ASU is not expected to have a material impact on our consolidated financial statements.
Recently Adopted Accounting Standards
Income Taxes (Topic 740)—Simplifying the Accounting for Income Taxes. The FASB issued ASU 2019-12 to simplify the accounting for income taxes by removing certain exceptions to the general principles in Topic 740. The amendments also improve consistent application of and simplify GAAP for other areas of Topic 740 by clarifying and amending existing guidance. The amendment is effective for reporting periods beginning after December 15, 2020. The adoption of this standard did not have a material impact to our consolidated financial statements.
NOTE 4 - IMPAIRMENTS
Oil and Natural Gas Properties
2021
There were no impairments recorded during the year ended December 31, 2021.
2020
During the four months ended December 31, 2020, the application of the full cost accounting rules resulted in 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 the forward prices used for our Fresh Start fair value estimates. These charges are included within impairments in our consolidated statements of operations.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
During the eight months ended August 31, 2020, we determined our undeveloped acreage would not be fully developed and thus the carrying values of certain of our unproved oil and gas properties were not recoverable resulting in an impairment of $226.5 million. That impairment had a corresponding increase to our depletion base and contributed to our recorded full cost ceiling impairment. We recorded a non-cash ceiling test write-down of $393.7 million pre-tax ($346.6 million, net of tax) during the eight months ended August 31, 2020 due to the reduction for the 12-month average commodity prices and the impairment of our unproved oil and gas properties described above. These charges are included within impairments in our consolidated statements of operations.
In addition to the impairment evaluations of our proved and unproved oil and gas properties in the eight months ended August 31, 2020, we also evaluated the carrying value of our salt water disposal assets. Based on our revised forecast, we determined that some were no longer expected to be used and wrote off the assets for total expense of $17.6 million during the eight months ended August 31, 2020. These amounts are reported in loss on abandonment of assets in our consolidated statements of operations.
Contract Drilling
2021
There were no impairments recorded during the year ended December 31, 2021.
2020
During the eight months ended August 31, 2020, we recorded expense of $1.1 million related to the write-down of certain equipment that we consider abandoned. These amounts are reported in loss on abandonment of assets in our consolidated statements of operations.
During the eight months ended August 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 addition to non-cash impairment charges of $3.0 million for other miscellaneous drilling equipment. These charges are included within impairments in our consolidated statements of operations. We concluded that no impairment was needed on the BOSS drilling rigs asset group as of March 31, 2020 as the undiscounted cash flows exceeded the $242.5 million carrying value of the asset group by a relatively minor margin. Some of the more sensitive assumptions used in evaluating the contract drilling rigs asset groups for potential impairment included forecasted utilization, gross margins, salvage values, discount rates, and terminal values. There were no additional triggering events identified during the eight months ended August 31, 2020 or four months ended December 31, 2020.
Mid-Stream
2021
In December 2021, we determined that the carrying value of a gathering system in Pennsylvania was not recoverable and exceeded its estimated fair value due to unfavorable forecasted economics. We recorded non-cash impairment charges of $10.7 million based on the estimated fair value of the asset group. These charges are included within impairments in our consolidated statements of operations.
2020
During the three months ended March 31, 2020, we determined that the carrying value of certain long-lived asset groups in southern Kansas, and central Oklahoma where lower pricing is expected to impact drilling and production levels, are not recoverable and exceeded their estimated fair value. We recorded non-cash impairment charges of $64.0 million based on the estimated fair value of the asset groups. These charges are included within impairments in our consolidated statements of operations. There were no additional triggering events identified during the eight months ended August 31, 2020 or one month ended September 30, 2020.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
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 23 – 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 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.
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 Revenues
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 Revenues
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 related to a distinct good or service within the contract, but are recognized as revenue when received as deferral for ratable recognition over the contract term is not material to the consolidated financial statements. 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 Contracts Revenues
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. We recognize 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.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
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.
The table below shows the changes in our contract asset and contract liability balances during periods presented which are primarily associated with demand fees and the impact to gas gathering and processing revenues:
| Successor | Successor | ||||||||||||||||||||||
| Classification on the Consolidated Balance Sheets | December 31, 2021 | December 31, 2020 | Change | ||||||||||||||||||||
| (In thousands) | |||||||||||||||||||||||
| Assets | |||||||||||||||||||||||
| Current contract assets | Prepaid expenses and other | $ | 174 | $ | 6,084 | $ | (5,910) | ||||||||||||||||
| Non-current contract assets | Other assets | — | 173 | (173) | |||||||||||||||||||
| Total contract assets | $ | 174 | $ | 6,257 | $ | (6,083) | |||||||||||||||||
| Liabilities | |||||||||||||||||||||||
| Current contract liabilities | Current portion of other long-term liabilities | $ | 1,588 | $ | 2,583 | $ | (995) | ||||||||||||||||
| Non-current contract liabilities | Other long-term liabilities | 200 | 1,589 | (1,389) | |||||||||||||||||||
| Total contract liabilities | 1,788 | 4,172 | (2,384) | ||||||||||||||||||||
| Contract assets (liabilities), net | $ | (1,614) | $ | 2,085 | $ | (3,699) | |||||||||||||||||
Included below is the adjustment to demand fees from adopting ASC 606 over the remaining term of the contracts as of December 31, 2021.
| Contract | Remaining Term of Contract | 2022 | 2023 and beyond | Total Remaining Impact to Revenue | ||||||||||
| (In thousands) | ||||||||||||||
| Demand fee contracts | 1 - 10 months | $ | 1,374 | $ | — | $ | 1,374 | |||||||
NOTE 6 – ACQUISITIONS AND DIVESTITURES
Oil and Natural Gas
There was no significant acquisition activity during the year ended December 31, 2021 or the four months ended December 31, 2020. We acquired $0.4 million of producing and other oil and natural gas properties during the eight months ended August 31, 2020.
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.
On March 8, 2022, the company closed on the sale of wells and related leases located near the Oklahoma Panhandle for $5.0 million, subject to customary closing and post-closing adjustments with an effective date of December 1, 2021. No gain or loss was recognized as the sale of these assets did not result in a significant alteration of the full cost pool.
On August 16, 2021, the company closed on the sale of substantially all of our wells and related leases located near Oklahoma City, Oklahoma for $19.5 million, subject to customary closing and post-closing adjustments. No gain or loss was recognized as the sale of these assets did not result in a significant alteration of the full cost pool.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
On May 6, 2021, the company closed on the sale of substantially all of our wells and related leases located in Reno and Stafford Counties, Kansas for $7.1 million, subject to customary closing and post-closing adjustments. No gain or loss was recognized as the sale of these assets did not result in a significant alteration of the full cost pool.
We also sold $5.0 million of other non-core oil and natural gas assets, net of related expenses, during the year ended December 31, 2021, compared to $0.4 million during the four months ended December 31, 2020, and $1.2 million during the eight months ended August 31, 2020. No gain or loss was recognized as the sale of these assets did not result in a significant alteration of the full cost pool.
Contract Drilling
There was no significant acquisition activity during the year ended December 31, 2021, the four months ended December 31, 2020, or eight months ended August 31, 2020.
We sold non-core contract drilling assets for proceeds of $12.7 million, net of related expenses, during the year ended December 31, 2021, compared to $1.3 million during the four months ended December 31, 2020, and $4.8 million during the eight months ended August 31, 2020. These proceeds resulted in net gains of $10.1 million during the year ended December 31, 2021, compared to $0.5 million during the four months ended December 31, 2020, and $1.4 million during the eight months ended August 31, 2020.
Mid-Stream
In November 2021, we closed on an acquisition for $13.0 million, subject to customary closing and post-closing adjustments, that included a cryogenic processing plant, approximately 1,620 miles of low-pressure gathering pipeline, and related compressor stations located in southern Kansas. The transaction was accounted for as an asset acquisition.
There was no significant acquisition activity during the year ended December 31, 2020.
There was no significant divestiture activity during the year ended December 31, 2021, the four months ended December 31, 2020, or eight months ended August 31, 2020.
Corporate and Other
In September 2021, we closed the sale of our corporate headquarters building and land for $35.0 million resulting in a gain of $0.9 million, net of $2.2 million of transaction costs. In conjunction with the closing, we entered into a multi-year lease for a portion of the building.
NOTE 7 – CAPITAL STOCK
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. The cash purchase price and direct acquisition costs are reflected as treasury stock on the consolidated balance sheets as of December 31, 2021.
In June 2021, our board of directors (the Board) authorized repurchasing up to $25.0 million of our 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. We have no obligation to repurchase any shares under the repurchase program and may suspend or discontinue it at any time without prior notice.
As of December 31, 2021, 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.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
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 December 31, 2021 totaled 1,949,963, resulting in outstanding shares of 10,050,037.
NOTE 8 – EARNINGS (LOSS) PER SHARE
Information related to the calculation of earnings (loss) per share attributable to Unit Corporation for the year ended December 31, 2021, four months ended December 31, 2020, and eight months ended August 31, 2020 is as follows:
| Earnings (Loss) (Numerator) | Weighted Shares (Denominator) | Per-Share Amount | ||||||||||||||||||
| (In thousands except per share amounts) | ||||||||||||||||||||
| For the year ended December 31, 2021 (Successor) | ||||||||||||||||||||
| Basic earnings attributable to Unit Corporation per common share | $ | 60,647 | 11,405 | $ | 5.32 | |||||||||||||||
| Effect of dilutive restricted stock units | — | 115 | (0.06) | |||||||||||||||||
| Diluted earnings attributable to Unit Corporation per common share | $ | 60,647 | 11,520 | $ | 5.26 | |||||||||||||||
| For the four months ended December 31, 2020 (Successor) | ||||||||||||||||||||
| Basic loss attributable to Unit Corporation per common share | $ | (18,140) | 12,000 | $ | (1.51) | |||||||||||||||
| For the eight months ended August 31, 2020 (Predecessor) | ||||||||||||||||||||
| Basic loss attributable to Unit Corporation per common share | $ | (931,012) | 53,368 | $ | (17.45) | |||||||||||||||
There were no potentially dilutive shares for inclusion during the eight months ended August 31, 2020 and four months ended December 31, 2020 as the company's stock-based awards outstanding immediately before the Effective Date were cancelled on the Effective Date.
The following stock options were not included in the computation of diluted earnings (loss) per share because the option exercise prices were greater than the average market price of our common stock for the year ended December 31, 2021:
| 2021 | |||||
| Stock options | 361,418 | ||||
| Average exercise price | $ | 45.00 | |||
NOTE 9 – ACCRUED LIABILITIES
Accrued liabilities consisted of the following as of December 31:
| Successor | Successor | ||||||||||
| 2021 | 2020 | ||||||||||
| (In thousands) | |||||||||||
| Employee costs | $ | 10,005 | $ | 8,878 | |||||||
| Lease operating expenses | 3,451 | 6,405 | |||||||||
| Capital expenditures | 3,962 | — | |||||||||
| Taxes | 3,320 | 2,324 | |||||||||
| Interest payable | 296 | 884 | |||||||||
| Legal settlement (Note 21) | — | 2,070 | |||||||||
| Other | 1,416 | 1,182 | |||||||||
| Total accrued liabilities | $ | 22,450 | $ | 21,743 | |||||||
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NOTE 10 – LONG-TERM DEBT AND OTHER LONG-TERM LIABILITIES
Long-Term Debt
Long-term debt consisted of the following as of December 31:
| Successor | Successor | |||||||||||||
| 2021 | 2020 | |||||||||||||
| (In thousands) | ||||||||||||||
| Current portion of long-term debt: | ||||||||||||||
Exit credit agreement with an average interest rate of 6.7% | $ | — | $ | 600 | ||||||||||
| Long-term debt: | ||||||||||||||
Exit credit agreement with an average interest of 6.7% | — | 98,400 | ||||||||||||
Superior credit agreement with an average interest rate of 2.1% at December 31, 2021 | 19,200 | — | ||||||||||||
| Total long-term debt | $ | 19,200 | $ | 98,400 | ||||||||||
Exit Credit Agreement. On the Effective Date, under the terms of the Plan, the company entered into an amended and restated credit agreement (the Exit credit agreement), providing for a $140.0 million senior secured revolving credit facility (RBL Facility) and a $40.0 million senior secured term loan facility, among (i) the company, UDC, and UPC, (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 (Lenders), and (iv) BOKF, NA dba Bank of Oklahoma as administrative agent and collateral agent (in such capacity, the Administrative Agent).
The maturity date of borrowings under 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.
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.
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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 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. Unit was in compliance with these covenants as of December 31, 2021.
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 the company's ownership interests in Superior.
We had no current or long-term borrowings, and $2.4 million of letters of credit outstanding under the Exit credit agreement as of December 31, 2021, compared to $0.6 million current and $98.4 million long-term borrowings, and $5.5 million of letters of credit outstanding as of December 31, 2020.
Predecessor Unit Credit Agreement. Before the filing of the Chapter 11 Cases, the Predecessor 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). 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.
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 eight months ended August 31, 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.
On the Effective Date, each lender under the Predecessor Unit credit agreement and the DIP Credit Agreement (as defined below) 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 Predecessor Unit credit agreement or the DIP Credit Agreement.
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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.
The Superior credit agreement requires that Superior maintain a Consolidated EBITDA to interest expense ratio (as defined in the Superior credit agreement) for the most-recently ended rolling four quarters of at least 2.50 to 1.00, and a funded debt to Consolidated EBITDA ratio (as defined in the Superior credit agreement) 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. Superior was in compliance with these covenants as of December 31, 2021
The Superior credit agreement is used to fund capital expenditures and acquisitions and provide general working capital and letters of credit. We had $19.2 million of borrowings and $0.5 million of letters of credit outstanding under the Superior credit agreement as of December 31, 2021, compared to no borrowings and $2.6 million of letters of credit outstanding as of December 31, 2020.
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 Predecessor 6.625% Notes (Predecessor 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 Predecessor Notes.
As a result of Unit's emergence from bankruptcy, the Predecessor Notes were cancelled and our liability under the Predecessor Notes was discharged as of the Effective Date. Holders of the Predecessor 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 Predecessor 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 a $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.
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UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
On the Effective Date, the DIP credit facility was paid in full and terminated, and 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 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 – 2020 Emergence From Voluntary Reorganization Under Chapter 11.
Other Long-Term Liabilities
Other long-term liabilities consisted of the following as of December 31:
| Successor | Successor | ||||||||||
| 2021 | 2020 | ||||||||||
| (In thousands) | |||||||||||
| Asset retirement obligation (ARO) liability | $ | 25,688 | $ | 23,356 | |||||||
| Workers’ compensation | 7,925 | 10,164 | |||||||||
| Finance lease obligations | — | 3,216 | |||||||||
| Contract liabilities | 1,788 | 4,172 | |||||||||
| Separation benefit plans | 2,022 | 4,201 | |||||||||
| Gas balancing liability | 1,090 | 3,997 | |||||||||
| Other long-term liabilities | — | 1,321 | |||||||||
| 38,513 | 50,427 | ||||||||||
| Less: current portion | 5,574 | 11,168 | |||||||||
| Total other long-term liabilities | $ | 32,939 | $ | 39,259 | |||||||
NOTE 11 – ASSET RETIREMENT OBLIGATIONS
The following table summarizes activity for our estimated AROs during the year ended December 31, 2021 (in thousands):
| December 31, 2020 (Successor) | $ | 23,356 | ||||||
| Accretion of discount | 1,892 | |||||||
| Liability incurred | 7 | |||||||
| Liability settled | (1,140) | |||||||
| Liability sold | (1,935) | |||||||
Revision of estimates (1) | 3,507 | |||||||
| December 31, 2021 (Successor) | 25,688 | |||||||
| Less: current portion (Successor) | 2,537 | |||||||
| Long-term ARO liability (Successor) | $ | 23,151 | ||||||
_______________________
1.Plugging liability estimates were revised for updates in the cost of services used to plug wells over the preceding year and estimated dates to be plugged.
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The following table summarizes activity for our estimated AROs during the eight months ended August 31, 2020 and the four months ended December 31, 2020 (in thousands):
| 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) | |||||||
| August 31, 2020 (Predecessor) | 38,984 | |||||||
| Fresh start adjustments | (14,393) | |||||||
| August 31, 2020 (Successor) | 24,591 | |||||||
| Accretion of discount | 467 | |||||||
| Liability incurred | 151 | |||||||
| Liability settled | (95) | |||||||
Revision of estimates (1) | (1,758) | |||||||
| December 31, 2020 (Successor) | 23,356 | |||||||
| Less: current portion (Successor) | 2,121 | |||||||
| Long-term ARO liability (Successor) | $ | 21,235 | ||||||
_______________________
1.Plugging liability estimates were revised for updates in the cost of services used to plug wells over the preceding year and estimated dates to be plugged.
NOTE 12 – 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 year ended December 31, 2021 (in thousands):
| December 31, 2020 (Successor) | $ | 10,164 | ||||||
| Claims and valuation adjustments | (1,834) | |||||||
| Payments | (405) | |||||||
| December 31, 2021 (Successor) | 7,925 | |||||||
| Less: current portion (Successor) | 1,221 | |||||||
| Long-term workers' compensation liability (Successor) | $ | 6,704 | ||||||
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The following table summarizes activity for our workers' compensation liability during the eight months ended August 31, 2020 and the four months ended December 31, 2020 (in thousands):
| December 31, 2019 (Predecessor) | $ | 11,511 | ||||||
| Claims and valuation adjustments | 906 | |||||||
| Payments | (427) | |||||||
| August 31, 2020 (Predecessor) | 11,990 | |||||||
| Fresh start adjustments | — | |||||||
| August 31, 2020 (Successor) | 11,990 | |||||||
| Claims and valuation adjustments | (1,679) | |||||||
| Payments | (147) | |||||||
| December 31, 2020 (Successor) | 10,164 | |||||||
| Less: current portion (Successor) | 1,705 | |||||||
| Long-term workers' compensation liability (Successor) | $ | 8,459 | ||||||
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 December 31, 2021 and 2020 are $4.0 million and $5.2 million, respectively, and are included in Other assets on our consolidated balance sheets.
NOTE 13 – INCOME TAXES
As a result of the Plan in 2020, 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 $456.3 million and the tax basis of our assets were reduced by $50.0 million.
76
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) during the periods indicated is as follows:
| Successor | Predecessor | |||||||||||||||||||
| Year Ended December 31, 2021 | Four Months Ended December 31, 2020 | Eight Months Ended August 31, 2020 | ||||||||||||||||||
| (In thousands) | ||||||||||||||||||||
| Income tax expense (benefit) computed by applying the statutory rate | $ | 12,772 | $ | (3,001) | $ | (190,103) | ||||||||||||||
| State income tax expense (benefit), net of federal benefit | 2,129 | (500) | (31,684) | |||||||||||||||||
Warrant liability revaluation | 4,640 | — | — | |||||||||||||||||
| Restricted stock shortfall | — | — | 7,404 | |||||||||||||||||
| Non-controlling interest in Superior | (3,046) | (1,017) | 7,504 | |||||||||||||||||
| Goodwill impairment | — | — | — | |||||||||||||||||
| Valuation allowance | (16,612) | 4,047 | 177,284 | |||||||||||||||||
| Reorganization adjustments | — | — | 14,152 | |||||||||||||||||
| Statutory depletion and other | 290 | 169 | 813 | |||||||||||||||||
| Income tax expense (benefit) | $ | 173 | $ | (302) | $ | (14,630) | ||||||||||||||
The company's total provision for income taxes consisted of the following during the periods indicated:
| Successor | Predecessor | |||||||||||||||||||
| Year Ended December 31, 2021 | Four Months Ended December 31, 2020 | Eight Months Ended August 31, 2020 | ||||||||||||||||||
| (In thousands) | ||||||||||||||||||||
| Current taxes: | ||||||||||||||||||||
| Federal | $ | — | $ | — | $ | (917) | ||||||||||||||
| State | 173 | (302) | — | |||||||||||||||||
| 173 | (302) | (917) | ||||||||||||||||||
| Deferred taxes: | ||||||||||||||||||||
| Federal | — | — | (16,663) | |||||||||||||||||
| State | — | — | 2,950 | |||||||||||||||||
| — | — | (13,713) | ||||||||||||||||||
| Total provision for income taxes | $ | 173 | $ | (302) | $ | (14,630) | ||||||||||||||
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Net deferred tax assets and liabilities are comprised of the following as of December 31:
| Successor | Successor | ||||||||||
| 2021 | 2020 | ||||||||||
| (In thousands) | |||||||||||
| Deferred tax assets: | |||||||||||
| Allowance for losses and nondeductible accruals | $ | 23,819 | $ | 22,051 | |||||||
| Net operating loss carryforward | 94,441 | 100,236 | |||||||||
| Depreciation, depletion, amortization, and impairment | 68,001 | 80,947 | |||||||||
| Alternative minimum tax and research and development tax credit carryforward | 1,738 | 1,738 | |||||||||
| 187,999 | 204,972 | ||||||||||
| Deferred tax liability: | |||||||||||
| Investment in Superior | (3,626) | (3,987) | |||||||||
| Net deferred tax asset | 184,373 | 200,985 | |||||||||
| Valuation allowance | (184,373) | (200,985) | |||||||||
| Non-current—deferred tax liability | $ | — | $ | — | |||||||
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. The company has maintained this conclusion as of December 31, 2021 and 2020. The company will continue to evaluate whether the valuation allowance is needed in future reporting periods and it will remain until the company can conclude that the net deferred tax assets are more likely than not to be realized. Future events or new evidence which may lead the company to conclude that it is more likely than not its net deferred tax assets will be realized include, but are not limited to, cumulative historical pre-tax earnings, 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 the company continues to conclude that the valuation allowance against its net deferred tax assets is necessary, the company will not have significant deferred income tax expense or benefit.
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 2017 or state income tax examinations by state taxing authorities for years before 2016. As of December 31, 2021, and after consideration of the tax attribute reductions of IRC Section 108 and finalization of the company’s 2020 federal income tax return, the company has an expected federal net operating loss carryforward of $385.5 million 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 14 – EMPLOYEE BENEFIT PLANS
Separation Benefit Plans. 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 allowed 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.
Also in accordance with the Plan, the New Separation Benefit Plan was 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 provided eligible employees that are involuntarily separated with two weeks of severance pay per year of service, with a minimum of four weeks and a maximum of 13 weeks. These benefits also vested for voluntary separation after 20 years of service provided to the company.
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UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
On November 1, 2021, the New Separation Benefit Plan was amended (Amended New Separation Benefit Plan) with consideration to the Divestiture Program to redefine which employees are entitled to the two weeks of severance pay per year of service with a minimum of four weeks and a maximum of 13 weeks as well as introduce new employee groups entitled to involuntary separation benefits equal to four months of base salary, six months of base salary, or 12 months of base salary if eligible upon involuntary separation. The Amended New Separation Benefit Plan maintains a 13 week severance benefit for voluntary separation which vests after 20 years of service provided to the company.
We recognized expense for benefits associated with anticipated payments from these separation plans of $3.4 million, $1.4 million, and $18.1 million during the year ended December 31, 2021, the four months ended December 31, 2020, and the eight months ended August 31, 2020, respectively.
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 401(k) Employee Thrift 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. The 2019 and 2020 plan year matching contributions were made in cash. Total 401(k) employer matching expense was $1.6 million, $0.7 million, and $1.4 million in the year ended December 31, 2021, four months ended December 31, 2020, and eight months ended August 31, 2020, respectively.
Salary Deferral Plan. We provided a salary deferral plan for our executives (Deferral Plan) during the eight months ended August 31, 2020 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. As of December 31, 2020, investments held in the Deferral Plan had been paid out to plan participants and the Deferral Plan was terminated.
NOTE 15 – 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 and Cactus Drilling Company. The company in the ordinary course of business, made payments for working interests, joint interest billings, drilling services, and product purchases to, and received payments for working interests, joint interest billings, and contract drilling services from, Kaiser Francis Oil Company and Cactus Drilling Company. Payments made to Kaiser Francis Oil Company totaled $5.7 million, $0.5 million, and $1.8 million while payments received totaled $6.2 million, $0.3 million, and $1.6 million during the year ended December 31, 2021, four months ended December 31, 2020, and eight months ended August 31, 2020, respectively. Payments made to Cactus Drilling Company totaled $0.8 million during the year ended December 31, 2021.
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 $0.4 million and $0.2 million during year ended December 31, 2021 and the eight months ended August 31, 2020, respectively.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
NOTE 16 – STOCK-BASED COMPENSATION
Unit Corporation Long Term Incentive Plan. 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, 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.
Predecessor Amended Plan and Non-Employee Directors Plan. 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. We recognized a reversal of expense previously recorded for the unvested awards of $2.2 million for these awards upon cancellation.
Under the Unit Corporation 2000 Non-Employee Directors’ Stock Option Plan (Non-employee directors plan), on the first business day following each annual meeting of shareholders, each person who was then a member of our Board 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.
On the Effective Date, the company's equity-based awards outstanding immediately before the Effective Date were cancelled along with the Amended plan and the Non-employee directors plan. The cancellations resulted in an acceleration of unrecorded stock compensation expense during the eight months ended August 31, 2020. 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 – 2020 Emergence From Voluntary Reorganization Under Chapter 11.
The following table summarizes the stock-based compensation expense activity recognized during the following periods:
| Successor | Predecessor | |||||||||||||||||||
| Year Ended December 31, 2021 | Four Months Ended December 31, 2020 | Eight Months Ended August 31, 2020 (1) | ||||||||||||||||||
| (In thousands) | ||||||||||||||||||||
| Recognized stock compensation expense | $ | 826 | $ | — | $ | 6,065 | ||||||||||||||
| Capitalized stock compensation cost for our oil and natural gas properties | $ | — | $ | — | $ | — | ||||||||||||||
| Tax benefit on stock-based compensation | $ | 202 | $ | — | $ | 1,486 | ||||||||||||||
_______________________
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.
80
Successor Period activity pertaining to nonvested RSUs under the LTIP is as follows:
Number of Shares | Weighted Average Grant Date Fair Value | ||||||||||
Nonvested at December 31, 2020 (Successor) (1) | — | $ | — | ||||||||
Granted (2) | 315,529 | 26.71 | |||||||||
| Vested | — | — | |||||||||
| Forfeited | — | — | |||||||||
Nonvested at December 31, 2021 (Successor) (3) | 315,529 | $ | 26.71 | ||||||||
_______________________
1.There was no activity during the four months ended December 31, 2020.
2.The grants had an aggregate grant date fair value of $8.4 million. Director grants will vest 25% on each of the following dates: May 27, 2022, September 3, 2022, September 3, 2023, and September 3, 2024. Employee grants will one-third vest on each of the following dates: November 21, 2022, October 1, 2023, and October 1, 2024.
3.The aggregate compensation cost related to nonvested RSUs not yet recognized as of December 31, 2021 was $7.9 million with a weighted average remaining service period of 1.7 years.
Successor Period activity pertaining to outstanding stock options under the LTIP is as follows:
Number of Shares | Weighted Average Exercise Price | ||||||||||
Outstanding at December 31, 2020 (Successor) (1) | — | $ | — | ||||||||
Granted (2) | 361,418 | 45.00 | |||||||||
| Exercised | — | — | |||||||||
| Forfeited or expired | — | — | |||||||||
Outstanding at December 31, 2021 (Successor) (3) | 361,418 | $ | 45.00 | ||||||||
_______________________
1.There was no activity during the four months ended December 31, 2020.
2.The grants had an aggregate grant date fair value of $4.1 million and will one-third vest on each of the following dates: October 1, 2022, October 1, 2023, and October 1, 2024. The options have a five year term from the grant date.
3.The stock options outstanding as of December 31, 2021 had a weighted average remaining contractual term of 4.8 years and no aggregate intrinsic value. None of the stock options outstanding as of December 31, 2021 were exercisable. The aggregate compensation cost related to outstanding options not yet recognized as of December 31, 2021 was $3.9 million with a weighted average remaining service period of 1.8 years.
Predecessor Period activity pertaining to nonvested RSUs 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 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) | — | — | — | $ | — | ||||||||||||||||||
81
| Non-Employee Directors | Number of Shares | Weighted Average Price | |||||||||
| 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) | — | $ | — | ||||||||
Predecessor Period activity pertaining to outstanding stock options under the Non-Employee Directors' Stock Option Plan for the identified periods is as follows:
Number of Shares | Weighted Average Exercise Price | ||||||||||
| Outstanding 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) | — | $ | — | ||||||||
NOTE 17 – 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 December 31, 2021, our commodity 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. We are not required to post any cash collateral with our counterparties and no collateral has been posted as of December 31, 2021.
82
The following non-designated hedges were outstanding as of December 31, 2021:
| Term | Commodity | Contracted Volume | Weighted Average Fixed Price for Swaps | Contracted Market | ||||||||||||||||||||||
| Jan'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) | ||||||||||||||||||||||
| Jan'22 - Dec'22 | Natural gas - collar | 35,000 MMBtu/day | $2.50 - $2.68 | IF - NYMEX (HH) | ||||||||||||||||||||||
| Jan'22 - Jun'22 | Crude oil - swap | 986 Bbl/day | $70.30 | 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 | ||||||||||||||||||||||
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.
The following tables present the recognized derivative assets and liabilities on our consolidated balance sheets as of the dates identified:
| 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 | ||||||||||||||||||||
| As of December 31, 2020 | ||||||||||||||||||||||||||
| Balance Sheet Classification | Presented Gross | Effects of Netting | Presented Net | |||||||||||||||||||||||
| (In thousands) | ||||||||||||||||||||||||||
| Assets: | ||||||||||||||||||||||||||
| Current commodity derivatives | Current derivative assets | $ | 3,292 | $ | (3,292) | $ | — | |||||||||||||||||||
| Long-term commodity derivatives | Non-current derivative assets | 144 | (144) | — | ||||||||||||||||||||||
| Total derivative assets | $ | 3,436 | $ | (3,436) | $ | — | ||||||||||||||||||||
| Liabilities: | ||||||||||||||||||||||||||
| Current Commodity Derivatives | Current derivative liabilities | $ | 4,339 | $ | (3,292) | $ | 1,047 | |||||||||||||||||||
| Long-term Commodity Derivatives | Non-current derivative liabilities | 4,803 | (144) | 4,659 | ||||||||||||||||||||||
| Warrant Liability | Warrant liability | 885 | — | 885 | ||||||||||||||||||||||
| Total derivative liabilities | $ | 10,027 | $ | (3,436) | $ | 6,591 | ||||||||||||||||||||
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The following table shows the activity related to derivative instruments in the consolidated statements of operations for the periods indicated:
| Successor | Predecessor | |||||||||||||||||||
| Year Ended December 31, 2021 | Four Months Ended December 31, 2020 | Eight Months Ended August 31, 2020 | ||||||||||||||||||
| (In thousands) | ||||||||||||||||||||
| Loss on derivatives | $ | (97,615) | $ | (985) | $ | (10,704) | ||||||||||||||
| Cash settlements paid on commodity derivatives | (44,591) | (1,133) | (4,244) | |||||||||||||||||
| Loss on derivatives less cash settlements paid on commodity derivatives | $ | (53,025) | $ | 148 | $ | (6,460) | ||||||||||||||
| Loss on change in fair value of warrants | $ | (18,937) | $ | — | $ | — | ||||||||||||||
NOTE 18 – FAIR VALUE MEASUREMENTS
The inputs available determine the valuation technique that we use to measure the fair value of the assets and liabilities presented in our 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 present our recurring fair value measurements as of the identified dates:
| Successor | |||||||||||||||||||||||
| 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) | ||||||||||||||||
| Successor | |||||||||||||||||||||||
| December 31, 2020 | |||||||||||||||||||||||
| Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||
| (In thousands) | |||||||||||||||||||||||
| Financial assets (liabilities): | |||||||||||||||||||||||
| Commodity derivative assets | $ | — | $ | 3,436 | $ | — | $ | 3,436 | |||||||||||||||
| Commodity derivative liabilities | — | (9,142) | — | (9,142) | |||||||||||||||||||
| Warrant liability | — | — | (885) | (885) | |||||||||||||||||||
| $ | — | $ | (5,706) | $ | (885) | $ | (6,591) | ||||||||||||||||
84
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
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).
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 measure the fair values of our natural gas and crude oil three-way collars using estimated 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. We consider this a Level 3 measurement within the fair value hierarchy as the calculation uses certain generally unobservable inputs.
We determined that the non-performance risk regarding our commodity derivative counterparties was immaterial based on our valuation at December 31, 2021.
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:
| Successor | Predecessor | |||||||||||||||||||
| Year Ended December 31, 2021 | Four Months Ended December 31, 2020 | Eight Months Ended August 31, 2020 | ||||||||||||||||||
| (In thousands) | ||||||||||||||||||||
| Beginning of period | $ | 885 | $ | — | $ | 1,204 | ||||||||||||||
| Issuance of warrants | — | 885 | — | |||||||||||||||||
| Loss on change in warrant liability | 18,937 | — | — | |||||||||||||||||
Gain/(loss) on unsettled three-way collars | — | — | 978 | |||||||||||||||||
| Settlement loss on three-way collars | — | — | (2,182) | |||||||||||||||||
| End of period | $ | 19,822 | $ | 885 | $ | — | ||||||||||||||
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.
The carrying values on the 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.
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, 2021 would approximate its fair value. This debt is classified as Level 2.
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UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
Fair Value of Non-Financial Instruments
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 11 – Asset Retirement Obligations.
Stock-Based Compensation. We use the Black-Scholes option pricing model to estimate the fair value of stock options and SARs 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.
Impairments. Non-recurring fair value measurements are also applied, when applicable, to determine the fair value of our long-lived assets and goodwill. We recorded non-cash impairment charges as discussed further in Note 3 – Impairments. The fair value measurement of these assets is categorized as a Level 3 measurement as the discounted cash flow models require the use of significant unobservable inputs.
Fresh Start Accounting. See Note 26 - Fresh Start Accounting for additional disclosures of non-recurring fair value measurements associated with the qualification of fresh start under ASC 852.
NOTE 19 – 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. In September 2021, we entered into an operating lease agreement for our headquarters office space which generated right of use assets and liabilities at lease inception of $8.4 million.
The following table sets forth the maturities of our operating lease liabilities as of December 31, 2021:
| Amount | ||||||||
| (In thousands) | ||||||||
| Ending December 31, | ||||||||
| 2022 | $ | 4,382 | ||||||
| 2023 | 3,321 | |||||||
| 2024 | 2,683 | |||||||
| 2025 | 2,081 | |||||||
| 2026 | 1,484 | |||||||
| 2027 and beyond | 50 | |||||||
| Total future payments | 14,001 | |||||||
| Less: Interest | 1,533 | |||||||
| Present value of future minimum operating lease payments | 12,468 | |||||||
| Less: Current portion | 3,791 | |||||||
| Total long-term operating lease payments | $ | 8,677 | ||||||
| Weighted average remaining lease term (years) | 3.8 | |||||||
Weighted average discount rate (1) | 5.54 | % | ||||||
_______________________
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.
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UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
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.
Information about the operating and finance lease assets and liabilities on our consolidated balance sheets as of December 31, 2021 and 2020 is as follows:
| Successor | Successor | ||||||||||||||||||||||
| Balance Sheet Classification | December 31, 2021 | December 31, 2020 | |||||||||||||||||||||
| (In thousands) | |||||||||||||||||||||||
| Assets | |||||||||||||||||||||||
| Operating lease right of use assets | Right of use assets | $ | 12,445 | $ | 5,592 | ||||||||||||||||||
| Property and equipment, net | — | 7,281 | |||||||||||||||||||||
| Total lease right of use assets | $ | 12,445 | $ | 12,873 | |||||||||||||||||||
| Liabilities | |||||||||||||||||||||||
| Current liabilities: | |||||||||||||||||||||||
| Operating lease liabilities | Current operating lease liabilities | $ | 3,791 | $ | 4,075 | ||||||||||||||||||
| Current portion of other long-term liabilities | — | 3,216 | |||||||||||||||||||||
| Non-current liabilities: | |||||||||||||||||||||||
| Operating lease liabilities | Operating lease liabilities | 8,677 | 1,445 | ||||||||||||||||||||
| Total lease liabilities | $ | 12,468 | $ | 8,736 | |||||||||||||||||||
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The following table presents the components of total lease cost for our operating and finance leases during the periods indicated:
| Successor | Predecessor | |||||||||||||||||||
| Year Ended December 31, 2021 | Four Months Ended December 31, 2020 | Eight Months Ended August 31, 2020 | ||||||||||||||||||
| (In thousands) | ||||||||||||||||||||
| Components of total lease cost: | ||||||||||||||||||||
| Amortization of finance leased assets | $ | 1,248 | $ | 1,406 | $ | 2,757 | ||||||||||||||
| Interest on finance lease liabilities | 33 | 54 | 165 | |||||||||||||||||
| Operating lease cost | 4,546 | 1,331 | 3,604 | |||||||||||||||||
Short-term lease cost (1) | 12,898 | 3,664 | 8,190 | |||||||||||||||||
| Variable lease cost | — | 64 | 223 | |||||||||||||||||
| Total lease cost | $ | 18,725 | $ | 6,519 | $ | 14,939 | ||||||||||||||
1.Short-term lease cost includes amounts capitalized related to our oil and natural gas segment of $1.5 million, $0.2 million, and $1.5 million for the year ended December 31, 2021, the four months ended December 31, 2020, and the eight months ended August 31, 2020, respectively.
The following table provides supplemental cash flow information related to our operating and finance leases during the periods indicated:
| Successor | Predecessor | |||||||||||||||||||
| Year Ended December 31, 2021 | Four Months Ended December 31, 2020 | Eight Months Ended August 31, 2020 | ||||||||||||||||||
| (In thousands) | ||||||||||||||||||||
| Cash paid for amounts included in the measurement of lease liabilities: | ||||||||||||||||||||
| Operating cash flows for operating leases | $ | 4,605 | $ | 1,489 | $ | 3,849 | ||||||||||||||
| Financing cash flows for finance leases | 3,216 | 1,406 | 2,757 | |||||||||||||||||
| Lease liabilities recognized in exchange for new operating lease right of use assets | $ | 8,745 | $ | — | $ | — | ||||||||||||||
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UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
NOTE 20 – VARIABLE INTEREST ENTITIES
On April 3, 2018, we sold 50% of the ownership interest in Superior. The 50% interest in Superior we sold was acquired by SP Investor, a holding company jointly owned by OPTrust and funds managed and/or advised by Partners Group, a global private markets investment manager. Superior is governed and managed under the Amended and Restated Limited Liability Company Agreement (Agreement) and 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 $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.
We have determined that Superior is a VIE as the equity holders as a group (Unit Corporation and SP Investor) (Members) lack the power to control without the Operator. The Agreement and MSA give us the power to direct the activities that most significantly affect Superior's operating performance through common control of the Operator. Accordingly, Unit is considered the primary beneficiary and consolidates the financial position, operating results, and cash flows of Superior.
The Agreement specifies how future distributions are to be allocated among 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.
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 December 31, 2021, liquidation distributions paid first to SP Investor of $361.7 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 $361.7 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.
Superior paid cash distributions totaling $24.7 million in April 2021 related to cumulative available cash as of March 31, 2021, $7.7 million in July 2021 related to available cash generated during the three months ended June 30, 2021, $13.9 million in October 2021 related to available cash generated during the three months ended September 30, 2021, and $19.0 million in January 2022 related to available cash generated during the three months ended December 31, 2021. Unit and SP Investor each received 50% of these distributions.
Subsequent to the Effective Date, we have allocated Unit's and SP Investor's share of earnings and losses from Superior in our consolidated statement of operations using the hypothetical liquidation at 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.
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The amounts below reflect the Superior balance sheet accounts consolidated in our consolidated balance sheets without elimination of intercompany receivables from and payables to Unit:
| December 31, 2021 | December 31, 2020 | |||||||||||||
| (In thousands) | ||||||||||||||
| Current assets: | ||||||||||||||
| Cash and cash equivalents | $ | 17,246 | $ | 11,642 | ||||||||||
| Accounts receivable | 42,628 | 27,427 | ||||||||||||
| Prepaid expenses and other | 1,263 | 6,746 | ||||||||||||
| Total current assets | 61,137 | 45,815 | ||||||||||||
| Property and equipment: | ||||||||||||||
| Gas gathering and processing equipment | 274,748 | 251,403 | ||||||||||||
| Transportation equipment | 2,801 | 1,748 | ||||||||||||
| 277,549 | 253,151 | |||||||||||||
| Less accumulated depreciation, depletion, amortization, and impairment | 53,792 | 10,466 | ||||||||||||
| Net property and equipment | 223,757 | 242,685 | ||||||||||||
| Right of use assets | 3,485 | 2,823 | ||||||||||||
| Other assets | 2,226 | 2,309 | ||||||||||||
| Total assets | $ | 290,605 | $ | 293,632 | ||||||||||
| Current liabilities: | ||||||||||||||
| Accounts payable | $ | 34,010 | $ | 17,045 | ||||||||||
| Accrued liabilities | 5,292 | 3,777 | ||||||||||||
| Current operating lease liability | 1,548 | 1,762 | ||||||||||||
| Current portion of other long-term liabilities | 1,450 | 5,799 | ||||||||||||
| Total current liabilities | 42,300 | 28,383 | ||||||||||||
| Long-term debt less debt issuance costs | 19,200 | — | ||||||||||||
| Operating lease liability | 2,036 | 1,013 | ||||||||||||
| Other long-term liabilities | — | 1,589 | ||||||||||||
| Total liabilities | $ | 63,536 | $ | 30,985 | ||||||||||
Subsequent Amendments to Superior Agreement and MSA
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 will no longer consolidate the financial position, operating results, and cash flows of Superior as of March 1, 2022. A loss on deconsolidation during the three months ended March 31, 2022 is possible as any difference between the March 1, 2022 estimated fair value of our retained investment in Superior and our net investment in Superior, which totaled $14.8 million as of December 31, 2021, will be recognized as a gain or loss. We will subsequently account for our investment in Superior as an equity method investment under the HLBV method.
90
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
NOTE 21 – COMMITMENTS AND CONTINGENCIES
Commitments
We have firm transportation commitments to transport our natural gas from various systems for approximately $0.9 million over the next twelve months.
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, 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.
Chapter 11 Cases
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.
The commencement of the Chapter 11 Cases also automatically stayed all proceedings and actions against the Predecessor company (other than certain regulatory enforcement matters). Effective at emergence from the Chapter 11 Cases, the automatic stay was terminated and replaced with the injunction provisions in the Confirmation Order and the Plan.
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UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
Below is a summary of two lawsuits and the respective treatment and settlement of those cases.
Cockerell Oil Properties, Ltd., v. Unit Petroleum Company, No. 16-cv-135-JHP, United States District Court for the
Eastern District of Oklahoma.
On March 11, 2016, a putative class action lawsuit was filed against UPC styled Cockerell Oil Properties, Ltd., v. Unit Petroleum Company in LeFlore County, Oklahoma. We removed the case to federal court in the Eastern District of Oklahoma. The plaintiff alleges that UPC wrongfully failed to pay interest with respect to late paid oil and gas proceeds under Oklahoma’s Production Revenue Standards Act. The lawsuit seeks actual and punitive damages, an accounting, disgorgement, injunctive relief, and attorney fees. Plaintiff is seeking relief on behalf of royalty and working interest owners in our Oklahoma wells.
Chieftain Royalty Company v. Unit Petroleum Company, No. CJ-16-230, District Court of LeFlore County, Oklahoma.
On November 3, 2016, a putative class action lawsuit was filed against UPC styled Chieftain Royalty Company v. Unit Petroleum Company in LeFlore County, Oklahoma. The plaintiff alleges that UPC breached its duty to pay royalties on natural gas used for fuel off the lease premises. The lawsuit seeks actual and punitive damages, an accounting, injunctive relief, and attorney’s fees. Plaintiff is seeking relief on behalf of Oklahoma citizens who are or were royalty owners in our Oklahoma wells.
Settlement
In August 2020, UPC reached an agreement to settle the above class actions. Under the settlement, UPC agreed to recognize class proof of claims in the amount of $15.75 million for Cockerell Oil Properties, Ltd. vs. Unit Petroleum Company, and $29.25 million in Chieftain Royalty Company vs. Unit Petroleum Company. Under the Plan, these settlements will be treated as allowed general unsecured claims against UPC. This settlement has been approved 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. and, in accordance with the Plan, the settlement amounts have been satisfied by distribution of the plaintiffs’ proportionate share of New Common Stock.
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UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
NOTE 22 - CONCENTRATION OF CREDIT RISK AND MAJOR CUSTOMERS
Our financial instruments that potentially subject us to concentrations of credit risk primarily consist of trade receivables with a variety of oil and natural gas companies. Our credit risk is considered limited due to the many customers comprising our customer base and we do not generally require collateral related to our receivables.
Below is a table of the third-party customers that accounted for over 10% of each of our segments' revenues:
| Successor | Predecessor | |||||||||||||||||||
| Year Ended December 31, 2021 | Four Months Ended December 31, 2020 | Eight Months Ended August 31, 2020 | ||||||||||||||||||
| Oil and Natural Gas: | ||||||||||||||||||||
| Coffeyville Resources | 11% | * | * | |||||||||||||||||
| CVR Refining, LP | * | 14% | 15% | |||||||||||||||||
| Plains Marketing L.P. | * | * | 11% | |||||||||||||||||
| Drilling: | ||||||||||||||||||||
| EOG Resources, Inc. | 21% | 28% | 20% | |||||||||||||||||
| Citizen Energy III, LLC | 20% | 16% | * | |||||||||||||||||
| Diamondback E&P, LLC | 15% | * | * | |||||||||||||||||
| Slawson Exploration Company, Inc. | 12% | 16% | 21% | |||||||||||||||||
| Earthstone Operating, LLC | 11% | * | * | |||||||||||||||||
| Cimarex Energy Co. | * | 12% | * | |||||||||||||||||
| QEP Resources, Inc. | * | 23% | 10% | |||||||||||||||||
| Mid-Stream: | ||||||||||||||||||||
| ONEOK, Inc. | 37% | 28% | 31% | |||||||||||||||||
| Range Resources Corporation | 11% | 15% | 21% | |||||||||||||||||
| Koch Energy Services | 10% | * | * | |||||||||||||||||
| Centerpoint Energy Service, Inc. | * | * | * | |||||||||||||||||
_______________________
* Revenue accounted for less than 10% of the segment's revenues.
We also had a concentration of cash with one bank of $36.6 million and $21.4 million as of December 31, 2021 and 2020, respectively, as well as a concentration of cash equivalents of $27.0 million in a money market fund comprised of U.S. Government and U.S. Treasury securities as of December 31, 2021.
Using derivative instruments 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, 2021 and determined there was no material risk at that time. The fair value of the net liabilities we had with Bank of Oklahoma, our only commodity derivative counterparty, was $58.7 million of December 31, 2021.
93
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
NOTE 23 – 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.
94
The following tables provide certain information about the operations and assets for each of our segments:
| Successor | ||||||||||||||||||||||||||||||||||||||
| Year Ended December 31, 2021 | ||||||||||||||||||||||||||||||||||||||
| Oil and Natural Gas | Contract Drilling | Mid-Stream | Corporate and Other | Eliminations | Total Consolidated | |||||||||||||||||||||||||||||||||
| (In thousands) | ||||||||||||||||||||||||||||||||||||||
Revenues: (1) | ||||||||||||||||||||||||||||||||||||||
| Oil and natural gas | $ | 272,231 | $ | — | $ | — | $ | — | $ | (47,999) | $ | 224,232 | ||||||||||||||||||||||||||
| Contract drilling | — | 76,107 | — | — | 76,107 | |||||||||||||||||||||||||||||||||
| Gas gathering and processing | — | 341,674 | — | (3,297) | 338,377 | |||||||||||||||||||||||||||||||||
| Total revenues | 272,231 | 76,107 | 341,674 | — | (51,296) | 638,716 | ||||||||||||||||||||||||||||||||
| Expenses: | ||||||||||||||||||||||||||||||||||||||
| Operating costs: | ||||||||||||||||||||||||||||||||||||||
| Oil and natural gas | 83,221 | — | — | — | (3,297) | 79,924 | ||||||||||||||||||||||||||||||||
| Contract drilling | — | 60,973 | — | — | — | 60,973 | ||||||||||||||||||||||||||||||||
| Gas gathering and processing | — | — | 286,199 | — | (51,515) | 234,684 | ||||||||||||||||||||||||||||||||
Total operating costs | 83,221 | 60,973 | 286,199 | — | (54,812) | 375,581 | ||||||||||||||||||||||||||||||||
Depreciation, depletion, and amortization | 24,612 | 6,308 | 32,566 | 840 | — | 64,326 | ||||||||||||||||||||||||||||||||
| Impairment | — | — | 10,673 | — | — | 10,673 | ||||||||||||||||||||||||||||||||
| Total expenses | 107,833 | 67,281 | 329,438 | 840 | (54,812) | 450,580 | ||||||||||||||||||||||||||||||||
General and administrative | — | — | — | 21,399 | 3,516 | 24,915 | ||||||||||||||||||||||||||||||||
| (Gain) loss on disposition of assets | 171 | (10,143) | 49 | (954) | — | (10,877) | ||||||||||||||||||||||||||||||||
| Income (loss) from operations | 164,227 | 18,969 | 12,187 | (21,285) | — | 174,098 | ||||||||||||||||||||||||||||||||
| Loss on derivatives | — | — | — | (97,615) | — | (97,615) | ||||||||||||||||||||||||||||||||
| Loss on change in fair value of warrants | — | — | — | (18,937) | — | (18,937) | ||||||||||||||||||||||||||||||||
| Reorganization items, net | — | — | — | (4,294) | — | (4,294) | ||||||||||||||||||||||||||||||||
| Interest, net | — | — | (924) | (3,342) | — | (4,266) | ||||||||||||||||||||||||||||||||
| Other | 187 | 57 | (844) | 3 | — | (597) | ||||||||||||||||||||||||||||||||
| Income (loss) before income taxes | $ | 164,414 | $ | 19,026 | $ | 10,419 | $ | (145,470) | $ | — | $ | 48,389 | ||||||||||||||||||||||||||
| Identifiable assets: | ||||||||||||||||||||||||||||||||||||||
Oil and natural gas (2) | $ | 203,796 | $ | — | $ | — | $ | — | $ | (4,917) | $ | 198,879 | ||||||||||||||||||||||||||
| Contract drilling | — | 78,554 | — | — | (78) | 78,476 | ||||||||||||||||||||||||||||||||
| Gas gathering and processing | — | — | 290,605 | — | (269) | 290,336 | ||||||||||||||||||||||||||||||||
Total identifiable assets (3) | 203,796 | 78,554 | 290,605 | — | (5,264) | 567,691 | ||||||||||||||||||||||||||||||||
| Corporate land and building | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||
Other corporate assets (4) | — | — | — | 66,227 | (4,441) | 61,786 | ||||||||||||||||||||||||||||||||
| Total assets | $ | 203,796 | $ | 78,554 | $ | 290,605 | $ | 66,227 | $ | (9,705) | $ | 629,477 | ||||||||||||||||||||||||||
| Capital expenditures: | $ | 17,752 | $ | 2,877 | $ | 24,316 | $ | 340 | $ | — | $ | 45,285 | ||||||||||||||||||||||||||
_______________________
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.Oil and natural gas assets include oil and natural gas properties, saltwater disposal systems, and other non-full cost pool assets.
3.Identifiable assets are those used in Unit’s operations in each industry segment.
4.Other corporate assets are principally cash and cash equivalents, transportation equipment, furniture, and equipment.
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| 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.
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| 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 $10.7 million pre-tax write-down for certain long-lived asset groups.
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.
97
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
NOTE 24 – 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 or Being Registered. Our 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.
98
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) | |||||||||||||||||||
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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) | |||||||||||||||||||
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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 | |||||||||||||||||||
101
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
NOTE 25 – 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.
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 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 | |||
102
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
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 at the Effective Date 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.
Drilling Equipment
The value of our drilling rigs in operation at the Effective Date (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 at the Effective Date (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 at the Effective Date, 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 at the Effective Date 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 at the Effective Date, 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.
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| 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 | ||||||||||||||||||
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| 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.
105
(2)The table below details the company’s uses of cash, under the terms of the Plan (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):
(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.
106
(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 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.
107
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
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 in Note 3 – Summary Of Significant Accounting Policies, our consolidated statements of operations for the year ended December 31, 2021, the four months ended December 31, 2020, and the eight months ended August 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 | |||||||||||||||||||
| Year Ended December 31, 2021 | Four Months Ended December 31, 2020 | Eight Months Ended 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 | 4,294 | 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 | $ | 4,294 | $ | 2,273 | $ | (133,975) | ||||||||||||||
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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 as of December 31, 2021 and 2020 were as follows:
| Successor | Successor | |||||||||||||
| 2021 | 2020 | |||||||||||||
| (In thousands) | ||||||||||||||
| Proved properties | $ | 225,014 | $ | 238,581 | ||||||||||
| Unproved properties (wells in progress) | 422 | 1,591 | ||||||||||||
| 225,436 | 240,172 | |||||||||||||
| Accumulated depreciation, depletion, amortization, and impairment | (64,966) | (40,806) | ||||||||||||
| Net capitalized costs | $ | 160,470 | $ | 199,366 | ||||||||||
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 | Successor | Predecessor | ||||||||||||||||||
| Year Ended December 31, 2021 | Four Months Ended December 31, 2020 | Eight Months Ended August 31, 2020 | ||||||||||||||||||
| (In thousands) | ||||||||||||||||||||
| Unproved properties acquired | $ | 522 | $ | 26 | $ | 2,373 | ||||||||||||||
| Proved properties acquired | — | — | 382 | |||||||||||||||||
| Exploration | — | — | — | |||||||||||||||||
| Development | 16,279 | 3,992 | 6,440 | |||||||||||||||||
| Asset retirement obligation | 478 | (1,702) | (29,189) | |||||||||||||||||
| Total costs incurred | $ | 17,279 | $ | 2,316 | $ | (19,994) | ||||||||||||||
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.
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The results of operations for producing activities are as follows:
| Successor | Successor | Predecessor | ||||||||||||||||||
| Year Ended December 31, 2021 | Four Months Ended December 31, 2020 | Eight Months Ended August 31, 2020 | ||||||||||||||||||
| (In thousands) | ||||||||||||||||||||
| Revenues | $ | 223,681 | $ | 55,272 | $ | 96,033 | ||||||||||||||
| Production costs | (62,443) | (20,510) | (46,633) | |||||||||||||||||
| Depreciation, depletion, amortization, and impairment | (24,261) | (40,840) | (461,901) | |||||||||||||||||
| 136,977 | (6,078) | (412,501) | ||||||||||||||||||
| Income tax (expense) benefit | 168 | 128 | 6,698 | |||||||||||||||||
Results of operations for producing activities (excluding corporate overhead and financing costs) | $ | 137,145 | $ | (5,950) | $ | (405,803) | ||||||||||||||
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 (MBbls) | NGL (MBbls) | Gas (Mcf) | Total (MBoe) | ||||||||||||||||||||
| 2020 | |||||||||||||||||||||||
| Proved developed and undeveloped reserves: | |||||||||||||||||||||||
| Beginning of year | 12,196 | 23,030 | 220,187 | 71,924 | |||||||||||||||||||
Revision of previous estimates (1) | (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 | — | — | — | — | |||||||||||||||||||
| 2021 | |||||||||||||||||||||||
| Proved developed and undeveloped reserves: | |||||||||||||||||||||||
| Beginning of year | 8,267 | 15,208 | 144,391 | 47,541 | |||||||||||||||||||
Revision of previous estimates (2) | 2,651 | 8,723 | 103,866 | 28,685 | |||||||||||||||||||
| Extensions and discoveries | 218 | 93 | 961 | 471 | |||||||||||||||||||
| Infill reserves in existing proved fields | 713 | 293 | 2,158 | 1,366 | |||||||||||||||||||
| Purchases of minerals in place | — | — | — | — | |||||||||||||||||||
| Production | (1,615) | (2,624) | (29,012) | (9,074) | |||||||||||||||||||
| Sales | (1,215) | (169) | (1,725) | (1,672) | |||||||||||||||||||
| Net proved reserves at December 31, 2021 | 9,019 | 21,525 | 220,640 | 67,317 | |||||||||||||||||||
| Proved developed reserves, December 31, 2021 | 9,019 | 21,525 | 220,640 | 67,317 | |||||||||||||||||||
| Proved undeveloped reserves, December 31, 2021 | — | — | — | — | |||||||||||||||||||
_________________________
1.Revisions of previous estimates 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.
2.Revisions of previous estimates increased primarily due to changes in the unescalated 12-month average product prices which increased approximately 68% for oil, 136% for NGLs, and 82% for natural gas compared to the December 31, 2020 pricing.
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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, 2021 and 2020 is as follows:
| Successor | Successor | |||||||||||||
| 2021 | 2020 | |||||||||||||
| (In thousands) | ||||||||||||||
| Future cash flows | $ | 1,977,529 | $ | 698,685 | ||||||||||
| Future production costs | (835,430) | (416,095) | ||||||||||||
| Future development costs | — | — | ||||||||||||
| Future income tax expenses | (87,117) | (39) | ||||||||||||
| Future net cash flows | 1,054,982 | 282,551 | ||||||||||||
| 10% annual discount for estimated timing of cash flows | (483,838) | (89,530) | ||||||||||||
Standardized measure of discounted future net cash flows relating to proved oil, NGLs, and natural gas reserves | $ | 571,144 | $ | 193,021 | ||||||||||
The principal sources of changes in the standardized measure of discounted future net cash flows were as follows:
| 2021 | 2020 | |||||||||||||
| (In thousands) | ||||||||||||||
| Sales and transfers of oil and natural gas produced, net of production costs | $ | (161,238) | $ | (84,163) | ||||||||||
| Net changes in prices and production costs | 334,291 | (165,978) | ||||||||||||
| Revisions in quantity estimates and changes in production timing | 320,774 | (50,979) | ||||||||||||
| Extensions, discoveries, and improved recovery, less related costs | 45,019 | 2,827 | ||||||||||||
| Changes in estimated future development costs | — | — | ||||||||||||
| Previously estimated cost incurred during the period | — | — | ||||||||||||
| Purchases of minerals in place | — | 852 | ||||||||||||
| Sales of minerals in place | (4,161) | (46) | ||||||||||||
| Accretion of discount | 19,306 | 46,203 | ||||||||||||
| Net change in income taxes | (87,078) | 282 | ||||||||||||
| Changes in timing and other | (88,791) | (17,686) | ||||||||||||
| Net change | 378,123 | (268,688) | ||||||||||||
| Beginning of year | 193,021 | 461,709 | ||||||||||||
| End of year | $ | 571,144 | $ | 193,021 | ||||||||||
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.
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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, 2021 future cash flows were computed by applying the unescalated 12-month average prices of $66.56 per barrel for oil, $44.22 per barrel for NGLs, and $3.60 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.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A. Controls and Procedures
Our management, including our Chief Executive Officer (CEO) and Chief Financial Officer (CFO), does not expect that our disclosure controls and procedures (as defined in Rules 13a - 15(e) and 15d - 15(e) of the Securities Exchange Act of 1934, as amended (the Exchange Act)) (Disclosure Controls) or our internal control over financial reporting (as defined in Rules 13a - 15(f) and 15d - 15(f) of the Exchange Act) will prevent or detect all errors and all fraud. A control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of a simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the controls. The design of any system of controls also is based in part on certain assumptions about the likelihood of future events, and there is no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of the inherent limitations in a cost-effective control system, misstatements due to an error or fraud may occur and not be detected. We monitor our Disclosure Controls and internal control over financial reporting and make modifications as necessary; our intent in this regard is that the Disclosure Controls and internal control over financial reporting will be modified as systems change, and conditions warrant.
Evaluation of Disclosure Controls and Procedures
As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with the participation of our management, including our CEO and CFO, of the effectiveness of the design and operation of our disclosure controls and procedures under Exchange Act Rule 13a-15. Based on that evaluation, our CEO and CFO concluded that our disclosure controls and procedures were effective as of December 31, 2021.
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Remediation of Previously Reported Material Weaknesses in Internal Control Over Financial Reporting
As disclosed in Part II, Item 9A, Controls and Procedures in our Annual Report on Form 10-K for the year ended December 31, 2020, we determined that a material weakness related to management review controls over complex accounting matters was present. Key elements of effectively designed management review controls include the establishment of documentation standards for process owners to document the substance of their work related to critical accounting estimates, complex accounting matters, and non-routine transactions. Effectively designed management review controls must also have an established process that allows senior accounting personnel having the appropriate knowledge of the subject matter to have enough time to perform effective reviews. Necessary elements for effectively designed management review controls were either not present or not present for a sufficient period of time in order to conclude our disclosure controls and procedures were effective at December 31, 2020.
Management, with oversight from the Audit Committee, developed a remediation plan to address the material weakness and operated new or enhanced processes, procedures, and controls for a sufficient period of time. Specifically, management redesigned certain management review controls related to complex accounting matters, established documentation standards, reassessed the structure of the accounting organization, provided additional training for employees responsible for performing important management review controls, and supplemented internal resources with external expertise when appropriate. Management also hired new personnel and re-assigned certain existing personnel into key positions, and conducted process improvement sessions with third party experts to enhance and augment business processes and utilization of system capabilities for greater effectiveness, efficiency, and scalability. As of December 31, 2021, management concluded that such measures had effectively addressed and resolved the previously identified material weakness.
Management’s Annual Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Exchange Act Rule 13a-15(f). Our management, including our CEO and CFO, conducted an evaluation of the effectiveness of our internal control over financial reporting based on the Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on the results of this evaluation, our management concluded that our internal control over financial reporting was effective as of December 31, 2021.
Changes in Internal Control Over Financial Reporting
Except as described above, there were no changes in internal control over financial reporting during the quarter ended December 31, 2021, that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Item 9B. Other Information
None.
Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections
Not applicable.
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PART III
Item 10. Directors, Executive Officers, and Corporate Governance
Information About Our Executive Officers
The table below and accompanying text sets forth certain information as of March 16, 2022, concerning each of our executive officers and certain officers of our subsidiaries. There were no arrangements or understandings between any of the officers and any other person(s) under which the officers were elected.
| Name | Age | Positions Held | ||||||||||||
| Philip B. Smith | 70 | Director since September 3, 2020, Chairman since September 8, 2020, President and Chief Executive Officer since October 22, 2020 | ||||||||||||
| David P. Dunham | 42 | Senior Vice President and Chief Operating Officer since October 22, 2020, Senior Vice President of Business Development from August 2017 to October 22, 2020, Vice President of Corporate Planning from January 2012 to August 28, 2017, Director of Corporate Planning from November 2007 to January 2012 | ||||||||||||
| Andrew E. Harding | 44 | Vice President, Secretary, and General Counsel since October 27, 2020, Associate General Counsel from March 2005 to October 27, 2020, Staff Attorney from August 2004 to March 2005 | ||||||||||||
| Thomas D. Sell | 57 | Chief Financial Officer and Controller since June 23, 2021; Chief Accounting Officer since December 31, 2020; Interim Chief Financial Officer from October 22, 2020 to June 23, 2021 | ||||||||||||
| Christopher K. Menefee | 44 | President, Unit Drilling Company since November 9, 2020 | ||||||||||||
Mr. Smith was named to the Board of Directors on September 3, 2020 and became Chairman on September 8, 2020. In October 2020, Unit's Board of Directors named him to the positions of President and Chief Executive Officer. Before his appointment to Unit's Board, he was self-employed since 2002. Mr. Smith served on the Board of Directors of Eagle Rock Energy LP from 2007 to 2015. Mr. Smith was Chief Executive Officer and Chairman of Prize Energy Corp., which he co-founded with Natural Gas Partners in 1999, until the Company's merger with Magnum Hunter Resources in 2002. Mr. Smith also served as Chief Executive Officer of Tide West Oil Company until it was sold to HS Resources in 1997. He received a Bachelor of Science in Mechanical Engineering from Oklahoma State University and a Master of Business Administration from the University of Tulsa.
Mr. Dunham joined Unit in November 2007 as Director of Corporate Planning. In January 2012, he was promoted to the position of Vice President of Corporate Planning. In August 2017, he was promoted to Senior Vice President of Business Development. In October 2020, he was promoted to Senior Vice President and Chief Operating Officer. Prior to Unit, he held positions of increasing responsibility at Williams Power, Leggett & Platt, and Williams Energy Marketing & Trading. Mr. Dunham received his Bachelor of Arts degree in Psychology from Northwestern University, his Master of Science in Finance degree from The University of Tulsa and his Master of Business Administration from The Wharton School of the University of Pennsylvania.
Mr. Harding joined Unit in August 2004 as a Staff Attorney. In March 2005, he was promoted to the position of Associate General Counsel. In October 2020, he was promoted to Vice President, General Counsel, and Secretary. Mr. Harding received his Bachelor of Business Administration from Baylor University in 2001, and his Juris Doctorate from the University of Tulsa College of Law in 2004. He is a member of the Oklahoma Bar Association. He is also a member of the Petroleum Alliance of Oklahoma board of directors and is chairman of the legal committee.
Mr. Sell joined Unit in October 2020 as Interim Chief Financial Officer. In December 2020, he also become Chief Accounting Officer ("CAO"), and in June 2021 he became Chief Financial Officer, CAO and Controller. From March 2020 to October 2020, he was the Chief Financial Officer for Montereau, Inc., a retirement community. From 2016 to March 2020, Mr. Sell served as Chief Accounting Officer and Controller for SemGroup Corporation, a gathering, transportation, storage, distribution, marketing and other midstream services company. From 1996 to 2016, Mr. Sell was with Williams Companies, Inc., where he held several different management positions in finance and accounting. Mr. Sell was with Deloitte & Touche from 1987 to 1996. Mr. Sell received his Bachelor of Science in Accounting from Oral Roberts University, where he graduated magna cum laude. He is a certified public accountant.
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Mr. Menefee was appointed President of Unit Drilling Company in November 2020. He most recently served as Senior Vice President, Business Development at Independence Contract Drilling, Inc., an onshore oil and gas contract drilling services company, from May 2012 to April 2020. Before that, he spent over 15 years at Rowan Companies, Inc. where he held many operational and management roles, including the Director of Marketing from 2006 to 2012. Mr. Menefee graduated from The University of Mississippi in Oxford with a Bachelor of Arts in Psychology. He holds a graduate certificate in corporate finance from the Cox School of Business at Southern Methodist University.
Information About Our Directors
The table below and accompanying text sets forth certain information as of March 16, 2022, concerning each member of our Board of Directors (the "board"). There is currently a vacancy in Group 1.
| Name | Age | Director | Committees of the Board | Term Expires | Primary Occupation | ||||||||||||||||||||||||||||||
| Since | Group | ||||||||||||||||||||||||||||||||||
| Robert R. Anderson | 64 | 2020 | II | 2022 | Executive, GBK Corporation, Tulsa, Oklahoma | ||||||||||||||||||||||||||||||
| Alan J. Carr | 51 | 2020 | II | Compensation (Chair) Strategic Transactions | 2022 | Chief Executive Officer, Drivetrain, LLC, New York City, New York | |||||||||||||||||||||||||||||
| Phil Frohlich | 67 | 2020 | II | Audit | 2022 | Managing Partner, Prescott Capital Management, Tulsa, Oklahoma | |||||||||||||||||||||||||||||
| Steven B. Hildebrand | 67 | 2008 | I | Audit (Chair) Strategic Transactions | 2023 | Investments, Tulsa, Oklahoma | |||||||||||||||||||||||||||||
| Philip B. Smith | 70 | 2020 | II | 2022 | President, Chief Executive Officer and Chairman of the Board, Unit Corporation, Tulsa, Oklahoma | ||||||||||||||||||||||||||||||
| Andrei Verona | 43 | 2020 | I | Strategic Transactions (Chair) Audit, Compensation | 2023 | Spectrum Fund Portfolio Manager at Saye Capital Management, headquartered in Redondo Beach, California | |||||||||||||||||||||||||||||
Mr. Anderson is and has been since 2010 an executive with GBK Corporation, a holding company with numerous energy industry subsidiaries and affiliates, including Kaiser Francis Oil Company, which has extensive domestic upstream oil & gas interests, and Cactus Drilling Company, which is a major domestic contract drilling company, serving on numerous private boards including Summit ESP which was acquired by Halliburton in 2017. Between 2002 and 2010 Mr. Anderson engaged primarily in personal investing with a focus on oil & gas supply/demand fundamentals while simultaneously serving on the University of Kansas Chemical & Petroleum Engineering Board of Advisors. In 1998, he was co-founder and CEO of privately held Sapient Energy Corp which was subsequently sold to Chesapeake Energy in 2002. During his time with Sapient, Mr. Anderson was also actively involved on the IPAA's Capital Markets Committee. Prior to establishing Sapient Energy, Mr. Anderson worked for Kaiser-Francis Oil Company in various roles of increasing responsibilities from 1984 through 1997. After graduating from the University of Kansas in 1980 with a B.S. degree in Chemical Engineering, he worked for Amoco Production Company until 1984. Attributes, experience, and qualifications for board and committee service: energy industry experience, executive expertise, entrepreneurial expertise; capital markets expertise.
Mr. Carr is and has been since September 2013 the Managing Member and Chief Executive Officer of Drivetrain, LLC, an independent fiduciary services firm. He has been a distressed investing and turnaround professional, with 25 years of experience in principal investing, advisory mandates, and board of directors' service, including complex financial restructurings and reorganizations in the U.S. and Europe. From 2003 to 2013, Mr. Carr was Managing Director at Strategic Value Partners, a global investment firm focused on distressed debt and private equity opportunities. Carr started his career at Skadden, Arps, Slate, Meagher & Flom LLC and Ravin, Sarasohn, Baumgarten, Fisch & Rosen in corporate restructuring advisory. He received a B.A. in Economics and Sociology from Brandeis University in 1992, and earned a J.D. from Tulane Law School in 1995. Mr. Carr currently serves as a director for the following public companies: Sears Holdings Corporation (since 2018) and Basic Energy Services (since 2021). Public companies for which Mr. Carr no longer serves as director but on which he served as a director in the last five years include: Atlas Iron Limited; TEAC Corporation; Tidewater Inc.; Midstates Petroleum Company, Inc.; Verso Corporation; McDermott International, Inc.; and J.C. Penney Corporation, Inc., a subsidiary of J. C. Penney Co. Attributes, experience, and qualifications for board and committee service: executive leadership experience; complex financial restructuring and reorganization expertise; financial analysis expertise; board of director service experience; and legal expertise.
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Mr. Frohlich founded Prescott Capital Management in 1992 and has been serving as Managing Partner since. The Oklahoma-based hedge fund focuses on small and mid-cap stocks. Mr. Frohlich was formerly president of Tulsa-based Siegfried Companies Inc. and a tax principal with what is now the international accounting firm Ernst & Young. He received a B.B.A. in Economics from the University of Oklahoma in 1976, an M.B.A. at the University of Texas at Austin in 1980, and a J.D. from the University of Tulsa in 1993. Attributes, experience, and qualifications for board and committee service: executive and entrepreneurial experience; accounting, investment, business and legal expertise.
Mr. Hildebrand has been engaged in personal investments since March 2008. He retired in 2008 from Dollar Thrifty Automotive Group, Inc. (NYSE: DTG), a car rental business, where he had served as Executive Vice President and Chief Financial Officer since 1997. Prior to that, Mr. Hildebrand served as Executive Vice President and Chief Financial Officer of Thrifty Rent-A-Car System, Inc., a subsidiary of Dollar Thrifty. Mr. Hildebrand joined Thrifty Rent-A-Car System, Inc. in 1987 as Vice President and Treasurer and became Chief Financial Officer in 1989. Mr. Hildebrand was with Franklin Supply Company, an oilfield supply business, from 1980 to 1987 where he held several positions including Controller and Vice President of Finance. From 1976 to 1980, Mr. Hildebrand was with the accounting firm Coopers & Lybrand, most recently as Audit Supervisor. Mr. Hildebrand earned a B.S.B.A. degree in accounting from Oklahoma State University, and he is a certified public accountant. Attributes, experience, and qualifications for board and committee service: experience and expertise in accounting and finance, including many years of experience as a CPA; qualifications as an audit committee financial expert; executive leadership experience at a public company, including experience with strategic planning, SEC reporting, Sarbanes - Oxley compliance, investor relations, enterprise risk management, executive compensation, corporate compliance, internal audit, bank facilities, private placement debt transactions and working with ratings agencies.
Mr. Smith's biographical information is listed in the section above setting forth information about our officers. Attributes, experience, and qualifications for board and committee service: executive leadership experience and industry familiarity; entrepreneurial and business experience; engineering background.
Mr. Verona is and since 2013 has been a Portfolio Manager at Saye Capital Management, an opportunistic credit hedge fund headquartered in Redondo Beach, California. He manages the corporate portion of the portfolio, which invests primarily in high yield and distressed bonds with a focus on restructurings and other event-driven opportunities. From 2009 to 2013, Mr. Verona was with Gleacher & Company's Investment Banking Group, serving most recently as Vice President. At Gleacher he focused on middle market corporates, advising clients on in-court and out-of-court restructurings, financings, and M&A transactions. Prior to Gleacher, he was a Senior Associate in GSC Partners' Corporate Credit Group. Mr. Verona started his career in the convertible bond and structured credit groups at Pacific Investment Management Company (PIMCO). He graduated cum laude from the University of California Los Angeles with a degree in Economics. Mr. Verona is a director for lracore International, a private company, where he is the Audit Chair. From November 2020 to October 2021, he served as a director for the public company Lonestar Resources US Inc., where he was the Audit Chair and a member of the Compensation Committee. Attributes, experience, and qualifications for board and committee service: complex investment and securitization experience; financial analysis expertise; M&A expertise; restructuring experience; and director experience.
Disclosure of Officer or Director Involvement in Bankruptcy-related Matters
Director Steven B. Hildebrand and Executive Officer David P. Dunham were Director and Executive Officer, respectively, at the time of the filing of our Chapter 11 Cases.
Director Phil Frohlich has also been an officer or director of a company filing bankruptcy in the last ten years.
Director Alan J. Carr is a restructuring professional and during the last ten years has been on the board of numerous companies during or after their filing for bankruptcy.
Corporate Governance and Board Matters
General Governance Matters
Our Code of Business Conduct and Ethics is available at https://unitcorp.com/investor-relations/#governance and a copy may also be obtained, without charge, on request, from our corporate secretary. We have posted and will continue to post any amendments or waivers to our Code of Business Conduct and Ethics that are required to be disclosed by the rules of the SEC on our website.
Each year, our directors and executive officers are asked to complete a director and officer questionnaire which requires disclosure of any transactions with us in which the director or executive officer, or any member of his or her immediate family, have a direct or indirect material interest. Our CEO and general counsel are charged with resolving any conflict of interests not otherwise resolved under one of our other policies.
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We have three committees of the board: the audit committee, the compensation committee, and the strategic transactions committee. Charters for each committee are available on the governance page of our website, linked above.
Audit Committee Financial Experts
The board has designated Messrs. Hildebrand, Frohlich, and Verona as Audit Committee Financial Experts as defined by SEC rules.
Material Changes to Procedures for Nominating Directors
There have been no material changes to our director nominating procedures since they were last published.
Item 11. Executive Compensation
Directors' 2021 Compensation
Our board of directors' 2020 compensation was determined by a group of our bondholders during our bankruptcy and the fees remained unchanged for 2021. That group looked at director compensation for companies of a size similar to our reduced post-bankruptcy size to determine recommended director compensation.
Directors' 2021 Cash Compensation
The various components of 2021 cash compensation paid to our directors, including employee directors, are as follows:
| Annual retainer | $65,000 | ||||
| Annual retainer for each committee a board member serves on | $10,000 | ||||
| Additional compensation for service as board chair | $15,000 | ||||
| Reimbursement for expenses incurred attending stockholder, board, and committee meetings | Yes | ||||
| Range of total cash compensation (excluding reimbursements) earned by current directors during 2021 | $65,000 to $85,274 | ||||
Directors' 2021 Equity Awards
Under the Unit Corporation Long Term Incentive Plan ("LTIP"), we may make annual equity awards to our directors. For information regarding equity awards granted to our non-employee directors during 2021, see the Director Compensation Table. For information regarding equity awards granted to our employee director Mr. Smith during 2021, see the Summary Compensation Table.
Director Compensation Table
The following table shows the total compensation received in 2021 by each of our non-employee directors.
| Director Compensation for 2021 | |||||||||||||||||||||||
Name (1) | Fees Earned or Paid in Cash (2) ($) | Stock Awards (3) ($) | Option Awards ($) | Non-Equity Incentive Plan Compensation ($) | Nonqualified Deferred Compensation Earnings ($) | All Other Compensation ($) | Total ($) | ||||||||||||||||
| (a) | (b) | (c) | (d) | (e) | (f) | (g) | (h) | ||||||||||||||||
| Robert R. Anderson | 65,000 | 234,367 | — | — | — | — | 299,367 | ||||||||||||||||
| Alan J. Carr | 75,274 | 234,367 | — | — | — | — | 309,641 | ||||||||||||||||
| Phil Frohlich | 75,000 | 234,367 | — | — | — | — | 309,367 | ||||||||||||||||
| Steven B. Hildebrand | 75,274 | 234,367 | — | — | — | — | 309,641 | ||||||||||||||||
| Andrei Verona | 85,274 | 234,367 | — | — | — | — | 319,641 | ||||||||||||||||
1.Excludes Director Philip B. Smith, who is also a Named Executive Officer whose compensation, including director compensation, is set forth in the Summary Compensation Table.
2.Represents cash compensation earned in 2021 for service on the board or a committee of the board.
3.The amounts included in the "Stock Awards" column represent the aggregate grant date fair value of restricted stock units computed in accordance with FASB ASC Topic 718 "Stock Compensation," which excludes the effect of estimated forfeitures. The amount is based on the closing sales
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price of our common stock on the grant date. Represents 18,168 restricted stock units granted to each non-employee director under the LTIP on April 27, 2021, having a grant date fair value of $12.90 per share. These 18,168 restricted stock units represent the total outstanding equity awards at fiscal year-end 2021 for each non-employee director, and they will vest in four equal installments on May 27, 2022, September 3, 2022, September 3, 2023, and September 3, 2024. The outstanding equity awards at fiscal 2021 year-end for our employee director Mr. Smith are set forth in the Outstanding Equity Awards at Fiscal Year-End Table.
Executive Compensation
Overview
The 2021 salaries for Messrs. Dunham and Menefee were determined by our CEO in October 2020 based on what was deemed to be current market levels at the time. Mr. Smith, originally working for no salary, was granted a nominal salary of $12,000 per year beginning in June 2021, which salary was determined in order to allow him to participate in our health insurance plan. Restricted stock unit awards ("RSUs") and stock option awards were granted to the named executive officers ("NEOs") under the LTIP in October 2021, and annual bonuses were determined in December 2021.
Summary Compensation Table for 2021
The following table sets forth information regarding the compensation paid, distributed, or earned by or for our NEOs for the stated fiscal years.
| Summary Compensation Table | |||||||||||||||||||||||
| Name and Principal Position | Year | Salary (1) ($) | Bonus (1) ($) | Stock Awards (2) ($) | Option Awards (3) ($) | All Other Compensation (4) ($) | Total ($) | ||||||||||||||||
| (a) | (b) | (c) | (d) | (e) | (f) | (g) | (h) | ||||||||||||||||
| Philip B. Smith, CEO and President | 2021 | 6,500 | 600 | 1,374,659 | 669,089 | 80,000 | 2,130,848 | ||||||||||||||||
| 2020 | — | — | — | — | 26,667 | 26,667 | |||||||||||||||||
| David P. Dunham, Senior Vice President and COO | 2021 | 350,000 | 17,500 | 615,502 | 361,163 | 33,698 | 1,377,863 | ||||||||||||||||
| 2020 | 318,458 | 85,270 | — | — | 34,892 | 438,620 | |||||||||||||||||
| Christopher K. Menefee, President, Unit Drilling Company | 2021 | 300,000 | 100,000 | 571,540 | 335,365 | 24,628 | 1,331,533 | ||||||||||||||||
| 2020 | 43,750 | — | — | — | — | 43,750 | |||||||||||||||||
1.Compensation deferred is listed in the year earned. Mr. Smith began receiving a nominal salary of $1,000 per month effective June 16, 2021, which salary was granted to permit him to participate in our health insurance plan.
2.The amounts included in the "Stock Awards" column represent the aggregate grant date fair value of restricted stock units computed in accordance with FASB ASC Topic 718 "Stock Compensation," which excludes the effect of estimated forfeitures. The amount is based on the closing sales price of our common stock on the grant date. Mr. Smith was granted 18,168 restricted stock units on April 27, 2021, with a grant date fair value of $12.90 per share. Both Mr. Smith and the other two NEOs were granted restricted stock units on October 21, 2021, with a grant date fair value of $34.00 per share. The amount shown does not represent amounts paid to the NEOs.
3.The amounts included in the "Option Awards" column represent the aggregate grant date fair value computed in accordance with FASB ASC Topic 718 "Stock Compensation" but does not include any impact of estimated forfeitures. For a discussion of the valuation assumptions used in calculating these values, see Note 16 to our Consolidated Financial Statements included in this annual report on Form 10-K. The amount shown does not represent amounts paid to the NEOs.
4.Components of the items in this column for 2021 are detailed in the table below:
| Name | Director Compensation (a) ($) | Executive Disability Insurance Premium ($) | 401(k) Match (b) ($) | Personal Car Allowance ($) | Club Membership ($) | Total "All Other Compensation" ($) | ||||||||||||||
| Philip B. Smith | 80,000 | — | — | — | — | 80,000 | ||||||||||||||
| David P. Dunham | — | 5,246 | 11,600 | 6,000 | 10,852 | 33,698 | ||||||||||||||
| Christopher K. Menefee | — | 1,801 | 11,600 | — | 11,227 | 24,628 | ||||||||||||||
a. Reflects fees earned or paid in cash for service as a member of our board of directors and its chair.
b. Match was made in cash.
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Outstanding Equity Awards at End of 2021
The following table sets forth information about our NEOs' outstanding equity awards at the end of 2021:
| Outstanding Equity Awards at Fiscal Year-End | ||||||||||||||||||||
| Options Awards | Stock Awards | |||||||||||||||||||
| Name | Number of securities underlying unexercised options - exercisable (#) | Number of securities underlying unexercised options - unexercisable (1) (#) | Option exercise price ($) | Option expiration date | Number of shares or units of stock that have not vested (2) (#) | Market value of shares or units of stock that have not vested (3) ($) | ||||||||||||||
| (a) | (b) | (c) | (d) | (e) | (f) | (g) | ||||||||||||||
| Philip B. Smith | — | 58,692 | 45.00 | 10/21/2026 | 51,706 | 1,670,104 | ||||||||||||||
| David P. Dunham | — | 31,681 | 45.00 | 10/21/2026 | 18,103 | 584,727 | ||||||||||||||
| Christopher K. Menefee | — | 29,418 | 45.00 | 10/21/2026 | 16,810 | 542,963 | ||||||||||||||
1.Each option grant has a five-year term. Option awards were granted on October 21, 2021, and become exercisable in three equal installments on October 1st of each of 2022, 2023, and 2024. The option exercise price is $45.00 per share.
2.The vesting schedule for the restricted stock units that have not vested are as follows for each NEO: For Messrs. Dunham and Menefee, and for 33,538 shares held by Mr. Smith, the awards vest in three equal installments on November 21, 2022, October 1, 2023, and October 1, 2024; Mr. Smith has an additional award of 18,168 shares that vests in four equal installments on May 27, 2022, September 3, 2022, September 3, 2023, and September 3, 2024.
3.Market value is determined based on the market value of our common stock of $32.30, the quoted closing price of our common stock on the OTC Pink on December 31, 2021, the last trading day of the year.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Directors and Executive Officers
This table shows the number of shares of our common stock beneficially owned by each current director, each NEO, and all current directors and executive officers as a group as of March 16, 2022, with all shares directly owned unless otherwise noted:
| Stock Owned by Our Directors and Executive Officers | |||||||||||
| Name of Beneficial Owner | Common Stock (a) | Options Exercisable and RSUs Vesting within 60 days (b) | Total (c) | ||||||||
| Robert R. Anderson | 524 | 523 (1) | 1,047 | ||||||||
| Alan J. Carr | — | — | — | ||||||||
Phil Frohlich (2) | — | — | — | ||||||||
| Steven B. Hildebrand | — | — | — | ||||||||
| Philip B. Smith | — | — | — | ||||||||
| Andrei Verona | — | — | — | ||||||||
| David P. Dunham | — | — | — | ||||||||
| Christopher K. Menefee | — | — | — | ||||||||
All directors and executive officers as a group (10 people) (3) | 524 | 523 | 1,047 | ||||||||
1.Represents restricted stock units that will vest under the terms of Mr. Anderson's January 2022 Consulting Contract with the company, as follows: 261 shares on April 7, 2022, and 262 shares on May 7, 2022.
2.Mr. Frohlich manages Prescott Group Capital Management, which owns 3,517,707 shares, or approximately 35% of our issued and outstanding shares of common stock as of March 16, 2022, as set forth in the table below and not included in Mr. Frohlich's share count in this table.
3.No officer or director individually owns more than 1% of our issued and outstanding shares of common stock, nor do our officers and directors as a group. Ownership percentages are based on the number of our issued and outstanding shares of common stock on March 16, 2022.
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Stockholders Owning More Than 5% of Our Common Stock
This table sets forth information about the beneficial ownership of our common stock by the only stockholders we know of who own over five percent of our common stock. Holders of more than five percent of our common stock have not been required to file ownership reports with the SEC.
| Stockholders Who Own More Than 5% of Our Common Stock | ||||||||
| Name and Address | Amount and Nature of Beneficial Ownership (1) | Percent of Class (2) | ||||||
Prescott Group Capital Management, LLC 1924 S. Utica Avenue, Suite 1120 Tulsa, Oklahoma 74104 | 3,517,707 | 35.10% | ||||||
RBC Global Asset Management Inc. RBC Centre 155 Wellington Street West, Suite 2300 Toronto, Ontario, Canada M5V 3K7 | 923,224 | 9.21% | ||||||
NYL Investors LLC 51 Madison Avenue New York, New York 10010 | 623,361 | 6.22% | ||||||
1.Beneficial ownership for Prescott Group Capital Management, LLC and RBC Global Asset Management Inc. is as confirmed by the stockholders in March 2022. Information for NYL Investors LLC is based on Schedule 13G filed with the SEC on January 10, 2022. Information is provided for reporting purposes only and should not be construed as an admission of actual beneficial ownership.
2.Based on the number of issued and outstanding shares of our common stock as of March 16, 2022.
Securities Authorized for Issuance Under Equity Compensation Plans as of December 31, 2021
| Securities Authorized for Issuance Under Equity Compensation Plans | |||||||||||
| Plan category | Number of securities to be issued upon exercise of outstanding options, warrants and rights (1) (a) | Weighted-average exercise price of outstanding options, warrants and rights (2) ($) (b) | Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) (3) (c) | ||||||||
Equity compensation plans approved by security holders | — | — | — | ||||||||
Equity compensation plans not approved by security holders | 676,947 | 45.00 | 226,279 | ||||||||
Total | 676,947 | 45.00 | 226,279 | ||||||||
1.Includes 315,529 shares of RSUs, all of which were not approved by security holders. Our Long Term Incentive Plan was approved by the requisite creditors as part of our plan of reorganization, which was confirmed by order of the U.S. Bankruptcy Court on August 6, 2020. The material terms of our LTIP are described below.
2.Excludes the shares issuable upon the vesting of RSUs included in column (a), for which there is no weighted-average exercise price.
3.Represents shares available for issuance under our Long Term Incentive Plan.
Material Terms of Long Term Incentive Plan
Overview. Our LTIP was adopted in connection with our reorganization and became effective as of September 3, 2020. The following is a summary of the material terms of the LTIP. This summary is not complete. For more information concerning the LTIP, we refer you to the full text of the plan, which was filed as an exhibit to our Current Report on Form 8-K filed September 10, 2020.
The purpose of the LTIP is to attract, retain and motivate employees, officers, directors, consultants, 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 board committee, of Options, SARs, Restricted Stock, Restricted Stock Units, Stock Awards, Dividend Equivalents, Other Stock-Based Awards, Cash Awards, Performance Awards, Substitute Awards, or any combination of those awards.
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Subject to adjustment in the event of certain transactions or changes of capitalization in accordance with the LTIP, 903,226 shares of the new common stock of the reorganized company, par value $0.01 per share ("stock") have been reserved for issuance by awards to be issued under the LTIP. Shares available to be delivered under the LTIP will be made available from (i) authorized but unissued shares of stock; (ii) stock held in the treasury of the company; or (iii) previously-issued shares of stock reacquired by the company. 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 by issuance of other awards under the LTIP.
Eligible recipients of awards under the LTIP include any individual who, as of the date of grant, is an officer or employee of the company or its affiliates and any other individual who provides services to the company or its affiliates, including one of its directors. An employee on leave from the company is considered eligible for awards under the LTIP.
Administration. The LTIP is administered by our compensation committee, which has discretion to determine the individuals to whom awards may be granted under the plan, the number of shares of our stock or the amount of cash subject to each award, the type of award, the manner in which such awards will vest and the other conditions applicable to awards. The compensation committee is empowered to clarify, construe or resolve any ambiguity in any provision of the LTIP or any award agreement and adopt such rules, forms, instruments and guidelines for administering the LTIP as it deems necessary or proper. The committee may delegate its powers to a subcommittee, a director, or an officer, if the delegation does not violate any applicable law.
Agreements. Awards granted under the LTIP will be evidenced by award agreements that provide additional terms and conditions associated with such awards, as determined by the compensation committee in its discretion. In the event of any conflict between the provisions of the LTIP and any such award agreement, the provisions of the LTIP will control.
Award Types. Types of awards available under the LTIP, which may be granted either alone, in addition to, or in tandem with any other award, include:
•Options - These include Incentive Stock Options ("ISO"s), which are intended to meet the ISO definition of Section 422 of the Internal Revenue Code, as well as Nonstatutory Options, which are any option that is not an ISO. Net settlement and cashless exercise are available methods of payment. No option may be exercisable for more than ten years following the grant date or, for persons owning stock with more than 10% of the total combined voting power of all classes of stock of the company or its subsidiaries, five years from the grant date.
•Stock Appreciation Rights ("SAR"s) - A SAR is the right to receive, on exercise, an amount equal to the product of the excess of the fair market value of a share of stock on the date of exercise over the grant price of the SAR and the number of shares of stock subject to the exercise of the SAR. No SAR may be exercisable for more than ten years following the grant date.
•Restricted Stock - Restricted Stock is stock granted subject to certain restrictions and a risk of forfeiture. During the period of restriction, the stock may not be transferred, sold, pledge, hedged, hypothecated, margined or otherwise encumbered by the recipient.
•Restricted Stock Units ("RSU"s) - An RSU is a grant to receive stock, cash, or a combination of stock and cash at the end of a specified period, and may include any restrictions imposed by the compensation committee. Settlement of RSUs will occur on vesting or expiration of the specified period, and will be done by delivery of a number of shares of stock equivalent to the number of RSUs for which settlement is due, or cash in the amount of the fair market value of the specified number of shares of stock equal to the number of RSUs for which settlement is due, or a combination thereof, as determined by the compensation committee.
•Stock Awards - Stock awards are unrestricted shares of stock, and may be granted as a bonus, as additional compensation, or in lieu of cash in such amounts and subject to such terms as the compensation committee determines.
•Dividend Equivalents - Dividend Equivalents are rights to receive cash, stock or other awards or other property equal in value to dividends paid with respect to a specified number of shares of stock, or other periodic payments. Dividend Equivalents granted in connection with another award will be subject to the same restrictions or forfeiture risk as the award with respect to which the dividends accrue and will not be paid until that award has vested and been earned.
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•Other Stock-Based Awards - The compensation committee may grant other awards denominated in or payable in, valued in whole or part by reference to, or otherwise based on, or related to, stock, as determined by the compensation committee, including convertible or exchangeable debt securities, other rights convertible or exchangeable into stock, purchase rights for stock, awards with value and payment contingent on performance of the company or other factors determined by the compensation committee, and awards valued by reference to the book value of stock or the value of securities of, or the performance of, affiliates of the company.
•Cash Awards - Cash Awards are awards denominated in cash.
•Substitute Awards - The compensation committee may grant awards in substitution or exchange for any other award granted under the LTIP or another plan of the company or an affiliate. Substitute Awards may be granted in connection with a merger, consolidation, or acquisition of another entity or the assets of another entity.
•Performance Awards - The compensation committee may grant awards under the LTIP that are conditioned on one or more business criteria or individual performance criteria and a targeted level or levels of performance with respect to each criteria. Conditions or goals may be based on business criteria for the company, on a consolidated basis, and/or for specified affiliates or business units of the company. Conditions and goals may be set on an absolute or relative basis, and can differ for different award recipients. If significant events occur which the compensation committee expects to have a substantial effect on the applicable performance conditions, the compensation committee may revise the performance conditions. The performance period will be as determined by the compensation committee in its discretion but shall not exceed ten years. Amounts determined to have vested will be paid by March 15th of the year following the year included in the last day of the applicable performance period. Settlement may be made in cash, stock, or other awards or property, as determined by the compensation committee. Awards may be increased or decreased in the compensation committee's discretion.
Tax Withholding. The company or its affiliates may withhold from any award or payment under an award the amount needed to cover taxes due or potentially payable and take such other action to satisfy payment of withholding taxes and other tax obligations related to any award in amounts as may be determined by the compensation committee in its sole discretion.
Transferability of Awards. Other than as permitted to be transferred by the compensation committee to an immediate family member or a family trust (or similar entities), or as transferred under a domestic relations orders, options and SARs shall be exercisable only by the participant during the participant's lifetime or by the person to whom those rights pass by will or the laws of descent and distribution. ISOs may not be transferred other than by will or the laws of descent and distribution. If provided by the compensation committee in an award agreement, an award may be transferred without consideration to immediate family members or related family trusts, limited partnerships, or similar entities or on such terms and conditions as the compensation committee may from time to time establish, and awards may be transferred under a qualified domestic relations order.
Form and Timing of Payment under Awards. Payments may be made in such forms as the compensation committee may determine in its discretion, including cash, stock, other awards or property, and may be made in lump sum, installments or on a deferred basis as long as the deferred or installment basis is set forth in an award agreement. Payments may include provisions for crediting or paying reasonable interest on installment or deferral amounts or the granting of Dividend Equivalents or other amounts in respect of installment or deferred payments denominated in stock.
Form of Stock Awards. Stock or other securities of the company under an award under the LTIP may be evidenced in any manner deemed appropriate by the compensation committee including certificated stock, book entry, electronic or otherwise, and shall be subject to such restrictions as the compensation committee deems advisable or as required by applicable law. Appropriate legends will be inscribed.
Adjustment of Awards. In the event of a corporate event or transaction such as a merger, consolidation, reorganization, recapitalization, stock dividend, stock split, reverse stock split or similar event or transaction the compensation committee may make certain adjustments to awards, including, in its sole discretion, substitution or adjustment of the number and kind of shares that may be issued under the LTIP or under particular awards, the grant price or purchase price applicable to outstanding awards, and other value determinations applicable to the LTIP or outstanding awards. In the event we experience a change in control (as defined in the LTIP), the compensation committee may, but is not obligated to, make adjustments to the terms and conditions of outstanding awards, including, without limitation:
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•acceleration of vesting and exercisability of awards, including subjecting the accelerated award to a time limitation after which rights under the award terminate;
•redemption or assumption in whole or in part of awards, for fair value or no value, depending on the award type and the price of the company's stock at the time of the change of control;
•cancellation of awards remaining subject to restriction, with no payment for the award;
•make adjustments to outstanding awards as the committee deems appropriate to reflect the change of control or other such event, including the substitution, assumption, or continuation of awards by the successor company or a parent or subsidiary of the successor company.
Limitations on Transfer of Stock Awarded under the LTIP. Prior to any Qualifying Public Offering, as defined in the LTIP, the company has a right of first refusal and a purchase option to purchase shares of stock from LTIP participants ceasing to be employees or service providers of the company, as detailed in Section 9 of the LTIP. Appropriate stock legends will be inscribed denoting the foregoing transfer restrictions. Also as detailed in Section 9 of the LTIP, in connection with a Qualifying Public Offering, as defined in the LTIP, holders of shares of company stock awarded under the LTIP may be restricted from transferring those shares for a specified "lock-up" period of time following the date of such an offering.
Section 409A of the Internal Revenue Code. Awards granted under the LTIP are intended but not required to comply with Section 409A of the Internal Revenue Code ("Section 409A"). The compensation committee may adjust the timing of award payments to comply with requirements of Section 409A and the "Nonqualified Deferred Compensation Rules," as defined in the LTIP. The LTIP provides that the Nonqualified Deferred Compensation Rules as so defined are incorporated by reference into the LTIP and control over the LTIP or any award agreement.
Clawback. The LTIP and all awards granted under it are subject to any clawback policies the company may adopt, which could result in reduction, cancellation, forfeiture, or recoupment in certain circumstances of wrongful conduct.
Amendment and Termination. The compensation committee may amend or terminate the LTIP or any award agreement at any time without the consent of the company's stockholders or LTIP participants, except that any amendment or alteration, including any increase in any share limitation, will be subject to stockholder approval if required by any federal or state law or regulation. The committee may otherwise in its discretion determine to submit changes to the plan for stockholder approval. Without the consent of an affected participant under a previously granted and outstanding award, the committee may not act to materially diminish the participants' rights under the LTIP or any award, provided that any adjustment in connection with any subdivision, consolidation, recapitalization, change of control or other reorganization is deemed not to materially and adversely affect the rights of any participant. No awards will be granted under the LTIP after September 3, 2030.
Item 13. Certain Relationships and Related Transactions, and Director Independence
Certain Transactions Between the Company and Its Officers, Directors, and Their Associates
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 and Cactus Drilling Company. The company in the ordinary course of business, made payments for working interests, joint interest billings, drilling services, and product purchases to, and received payments for working interests, joint interest billings, and contract drilling services from, Kaiser Francis Oil Company and Cactus Drilling Company. Payments made to Kaiser Francis Oil Company totaled $5.7 million and $2.3 million during 2021 and 2020, respectively, while payments received totaled $6.2 million and $1.9 million during 2021 and 2020, respectively. Payments made to Cactus Drilling Company totaled $0.8 million during 2021. Additionally, on January 7, 2022 (the "grant date"), Mr. Anderson entered into a consulting contract with the company. Under the terms of the consulting contract, Mr. Anderson agreed to provide advisory consulting services related to the company's sale of up to all of the assets of its exploration and production segment in exchange for awards of 7,850 restricted stock units and 13,416 stock options having a total estimated grant date fair value of $0.3 million. The restricted stock units vest in equal monthly installments beginning one month from the grant date, and will be fully vested within thirty months of the grant date. The stock options become 100% exercisable at $45.00 per share one year from the grant date, and they expire on the date that is thirty months after the grant date. The consulting contract has a six-month term, renewing in one-month terms thereafter until formally terminated.
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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 $0.4 million and $0.2 million during 2021 and 2020, respectively.
Director Independence Determination
Our common stock is not listed on any national exchange or quoted on any inter-dealer quotation service that imposes independence requirements on our board of directors or any committee thereof. Under the corporate governance standards of the New York Stock Exchange ("NYSE"), generally a director does not qualify as independent if the director (or in some cases, members of the director's immediate family) has, or in the past three years has had, certain relationships or affiliations with us, our external or internal auditors or other companies that do business with us.
The board has determined that all of our directors, except Messrs. Smith, Frohlich, and Anderson are independent under the NYSE standards. The board determined that none of the independent directors has any material relationship with us that could impair such individual's independence. Mr. Smith is not considered to be an independent director because of his employment as one of our executive officers. Mr. Frohlich is not considered to be independent because he is considered to be an affiliate based on his management of Prescott Group Capital Management LLC, which controls approximately 35% of our issued and outstanding common stock as of March 16, 2022. Mr. Anderson is not considered to be independent because he has a consulting contract with us.
Each member of each of our Audit and Compensation Committees also qualifies as independent under NYSE standards, other than Mr. Frohlich, who serves on our Audit Committee.
Item 14. Principal Accountant Fees and Services
Fees Incurred for Grant Thornton LLP
Grant Thornton LLP was our independent registered accounting firm for fiscal years 2021 and 2020. This table shows the fees for professional audit services provided for the audit of our annual financial statements paid to Grant Thornton LLP for the stated years.
| Type of Service | 2021 | 2020 | ||||||
Audit Fees (1) | $909,153 | $1,259,347 | ||||||
| Audit-Related Fees | — | — | ||||||
Tax Fees (2) | $21,865 | $10,868 | ||||||
All Other Fees | — | — | ||||||
Total | $931,018 | $1,270,215 | ||||||
1.Audit fees include professional services for the audits of our consolidated financial statements and the Superior Pipeline Company, L.L.C. financial statements, review of our quarterly condensed consolidated financial statements, audit services provided for the issuance of consents, and assistance with review of documents filed with the SEC.
2.For tax compliance fees.
Policy on Audit Committee Pre-Approval of Audit and Permissible Non-Audit Services of Independent Auditor
Consistent with SEC policies regarding auditor independence, the audit committee has responsibility for appointing, setting compensation, and overseeing the work of the independent registered public accounting firm. In recognition of this responsibility, the audit committee has established a policy to pre-approve all audit and permissible non-audit services provided by the independent registered public accounting firm.
Before incurring the following, management will submit to the audit committee for approval a list of services and related fees expected to be rendered by our independent registered public accounting firm during that year within these four categories of services:
(1) Audit services include audit work performed on the financial statements, internal control over financial reporting, and work that generally only the independent registered public accounting firm can reasonably be expected to provide, including comfort letters, statutory audits, and discussions surrounding the proper application of financial accounting and reporting standards.
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(2) Audit-related services are for assurance and related services traditionally performed by the independent registered public accounting firm, including due diligence related to mergers and acquisitions, employee benefit plan audits, and special procedures required to meet certain regulatory requirements.
(3) Tax services include all services, except those services specifically related to the audit of the financial statements performed by the independent registered public accounting firm's tax personnel, including tax analysis; assisting with coordination of execution of tax related activities, primarily in corporate development; supporting other tax related regulatory requirements; and tax compliance and reporting.
(4) Other Fees are those associated with services not captured in the other categories.
The audit committee pre-approves the independent registered public accounting firm's services within each category. The fees are budgeted and the audit committee requires the independent registered public accounting firm and management to report actual fees versus the budget periodically throughout the year. Circumstances may arise when it may become necessary to engage the independent registered public accounting firm for additional services not contemplated in the original pre-approval categories. In those instances (subject to certain de minimus exceptions), the audit committee requires specific pre-approval before engaging the independent registered public accounting firm.
The audit committee may (and has at various times in the past) delegate pre-approval authority to one or more of its members. The member to whom such authority is delegated must report, for informational purposes only, any pre-approval decisions to the audit committee at its next scheduled meeting.
PART IV
Item 15. Exhibits and Financial Statement Schedules
(a) Financial Statements, Schedules, and Exhibits:
1. Financial Statements:
Included in Part II of this report:
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets as of December 31, 2021 and 2020
Consolidated Statements of Operations for the year ended December 31, 2021, four months ended December 31, 2020, and eight months ended August 31, 2020
Consolidated Statements of Comprehensive Income (Loss) for the year ended December 31, 2021, four months ended December 31, 2020, and eight months ended August 31, 2020
Consolidated Statements of Changes in Shareholders' Equity for the year ended December 31, 2021, four months ended December 31, 2020, and eight months ended August 31, 2020
Consolidated Statements of Cash Flows for the year ended December 31, 2021, four months ended December 31, 2020, and eight months ended August 31, 2020
Notes to Consolidated Financial Statements
2. Financial Statement Schedules:
Included in Part IV of this report for the years ended December 31, 2021 and 2020:
Schedule II—Valuation and Qualifying Accounts and Reserves
Other schedules are omitted because of the absence of conditions under which they are required or because the required information is included in the consolidated financial statements or notes thereto.
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3. Exhibits:
The exhibit numbers in the following list correspond to the numbers assigned such exhibits in the Exhibit Table of Item 601 of Regulation S-K.
| 2.1 | ||||||||
| 3.1 | ||||||||
| 3.2 | ||||||||
| 10.1† | ||||||||
| 10.2† | ||||||||
| 10.3† | ||||||||
| 10.4† | ||||||||
| 10.5 | ||||||||
| 10.6 | ||||||||
| 10.7† | ||||||||
| 10.8† | ||||||||
| 10.9† | ||||||||
| 10.10 | ||||||||
| 10.11 | ||||||||
| 10.12 | ||||||||
| 10.13 | ||||||||
| 10.14 | ||||||||
| 10.15 | ||||||||
| 10.16 | ||||||||
| 10.17 | ||||||||
| 10.18 | ||||||||
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| 10.19 | ||||||||
| 10.20 | ||||||||
| 10.21 | ||||||||
| 10.22 | ||||||||
| 21 | ||||||||
| 23.1 | ||||||||
| 31.1 | ||||||||
| 31.2 | ||||||||
| 32 | ||||||||
| 99.1 | ||||||||
| 101.INS | XBRL Instance Document. The instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the inline XBRL document. | |||||||
| 101.SCH | XBRL Taxonomy Extension Schema Document. | |||||||
| 101.CAL | XBRL Taxonomy Extension Calculation Linkbase Document. | |||||||
| 101.DEF | XBRL Taxonomy Extension Definition Linkbase Document. | |||||||
| 101.LAB | XBRL Taxonomy Extension Labels Linkbase Document. | |||||||
| 101.PRE | XBRL Taxonomy Extension Presentation Linkbase Document. | |||||||
| 104 | Cover Page Interactive Data File. The cover page interactive data file does not appear in the interactive data file because its XBRL tags are embedded within the inline XBRL document (contained in Exhibit 101) | |||||||
† Indicates a management contract or compensatory plan identified under the requirements of Item 15 of Form 10-K.
Item 16. Form 10-K Summary
Not applicable.
Schedule II
UNIT CORPORATION AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
Allowance for Credit Losses:
| Description | Balance at Beginning of Period | Additions Charged to Costs & Expenses | Deductions & Net Write-Offs | Balance at End of Period | |||||||||||||||||||
| (In thousands) | |||||||||||||||||||||||
| Year ended December 31, 2021 | $ | 3,783 | $ | 1,640 | $ | (2,912) | $ | 2,511 | |||||||||||||||
| Year ended December 31, 2020 | $ | 2,332 | $ | 3,155 | $ | (1,704) | $ | 3,783 | |||||||||||||||
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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
| UNIT CORPORATION | |||||||||||
| DATE: | March 31, 2022 | By: | /s/ PHILIP B. SMITH | ||||||||
| PHILIP B. SMITH | |||||||||||
President and Chief Executive Officer and Chairman of the Board (Principal Executive Officer) | |||||||||||
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities indicated on the 31st day of March, 2022.
| Name | Title | |||||||
/s/ PHILIP B. SMITH | President and Chief Executive Officer and Chairman of the Board (Principal Executive Officer) | |||||||
| Philip B. Smith | ||||||||
/s/ THOMAS D. SELL | Chief Financial Officer and Chief Accounting Officer (Principal Financial and Accounting Officer) | |||||||
| Thomas D. Sell | ||||||||
/s/ ROBERT ANDERSON | Director | |||||||
| Robert Anderson | ||||||||
/s/ ALAN J. CARR | Director | |||||||
| Alan J. Carr | ||||||||
/s/ PHIL FROHLICH | Director | |||||||
| Phil Frohlich | ||||||||
/s/ STEVEN B. HILDEBRAND | Director | |||||||
| Steven B. Hildebrand | ||||||||
/s/ ANDREI VERONA | Director | |||||||
| Andrei Verona | ||||||||
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