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, 20172021
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)
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| Delaware | | | 73-1283193 |
| (State or other jurisdiction of incorporation or organization) | | | (I.R.S. Employer Identification No.) |
8200 South Unit Drive, Tulsa, Oklahoma | 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:
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| Title of each class | Trading Symbol(s) | Name of each exchange on which registered |
Common Stock, par value $.20 per shareN/A | NYSEN/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 [x]☐ 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 [x]☐
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 [x]☐ 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 and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted 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 and post such files). Yes [x]☒ No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [x]☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer”, “accelerated filer” and, “smaller reporting company”, and "emerging growth company" in Rule 12b-2 of the Exchange Act.
Large accelerated filer [ x ]☐ Accelerated filer [ ]☐ Non-accelerated filer (Do not check if a smaller reporting company) [ ]☒
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 [x]☒
As of June 30, 2017,2021, the aggregate market value of the voting and non-voting common equity (based on the closing price of the stock on the NYSEOTC Pink on June 30, 2017)2021) held by non-affiliates was approximately $958,140,471.$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.
Indicate the number
As of March 31, 2022, 10,050,561 shares outstanding of each of the issuer’s classes ofregistrant’s common stock aswere outstanding.
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Class | Outstanding at February 13, 2018 |
Common Stock, $0.20 par value per share | 53,061,832 shares |
DOCUMENTS INCORPORATED BY REFERENCE |
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Document | Parts Into Which Incorporated |
Portions of the registrant’s definitive proxy statement (the Proxy Statement) with respect to its annual meeting of shareholders scheduled to be held on May 2, 2018. The Proxy Statement will be filed within 120 days after the end of the fiscal year to which this report relates. | Part III |
Exhibit Index—See Page 122
FORM 10-K
UNIT CORPORATION
TABLE OF CONTENTS
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| PART I | |
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| PART I | |
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| Item 1. | | |
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| Item 1A. | | |
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| Item 1B. | | |
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| Item 2. | | |
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| Item 3. | | |
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| Item 4. | | |
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| PART II | |
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| Item 5. | | |
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| Item 6. | | |
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| Item 7. | | |
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| Item 7A. | | |
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| Item 8. | | |
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| Item 9. | | |
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| Item 9A. | | |
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| Item 9B. | | |
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| Item 9C. | PART III | |
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| PART III | |
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| Item 10. | | |
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| Item 11. | | |
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| Item 12. | | |
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| Item 13. | | |
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| Item 14. | | |
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| PART IV | |
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| Item 15. | | |
| Item 16. | | |
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The following are explanations of some of the industry and general terms usedwe use in this report.report:
ARO – Asset retirement obligations.
ASC – FASB Accounting Standards Codification.
ASU – Accounting Standards Update.
Bcf – Billion cubic feet of natural gas.
Bcfe – Billion cubic feet of natural gas equivalent. Determined using the ratio of one barrel of crude oil or NGLs to six Mcf of natural gas.
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.
BOKF – Bank of Oklahoma Financial Corporation.
Btu – British thermal unit, used in gas volumes. Btu is used to refer to the amount of 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 provedproven 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.
McfeMBoe – Thousand barrels of oil equivalent.
MMBtu – Million Btu’s.
MMcf – Million cubic feet of natural gas.
MMcfe – Million cubic feet of natural gas equivalent. DeterminedIt is determined using the ratio of one barrel of crude oil or NGLs to six Mcf of natural gas.
MMBbls – Million barrels of crude oil or other liquid hydrocarbons.
MMBoe – Million barrels of oil equivalents.
MMBtu – Million Btu’s.
MMcf – Million cubic feet of natural gas.
MMcfe – Million cubic feet of natural gas equivalent. 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.
DEFINITIONS — (Continued)
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)(3)(6) of Regulation S-X.
Proved reserves – Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geosciencesgeoscience 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 – beforeprior to the time whenat 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)(2)(22)(i) through (iii)(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)(4)(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.
Unconventional playSEC – Plays targeting tight sand, carbonates, coal bed, or oilSecurities and gas shale reservoirs. The reservoirs tend to cover large areas and lack the readily apparent traps, seals, and discrete hydrocarbon-water boundaries that typically define conventional reservoirs. These reservoirs generally require horizontal wells and fracture stimulation treatments or other special recovery processes to produce economically.Exchange Commission.
SOFR - Secured Overnight Financing Rate.
Undeveloped acreage – Lease acreage on which wells have not been drilled or completed to athe point that would permit the production of economic quantities of natural gas or oil regardless of whether the acreage contains proved reserves.
Well spacingThe 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 regulationcases filed by the Debtors on May 22, 2020 under Chapter 11 of Title 11 of the number and location of wells over an oil or gas reservoir, as a conservation measure. Well spacing is normally accomplished by order of the appropriate regulatory conservation commission.
Workovers – Operations on a producing well to restore or increase production.
WTI – West Texas Intermediate, the benchmark crude oilUnited States Code in the United States.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, 20172021
PART I
Item 1. Business
Unless otherwise indicated or required by the context, the terms “Company”, “Unit”, “us”, “our”, “we”,“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 internet website at www.unitcorp.com, as soon as reasonably practicablepossible after we electronically file these reports with or furnish them to the Securities and Exchange Commission (SEC). Materials we file with the SEC may be read and copied at the SEC’s Public Reference Room at 100 F. Street, N.E. Room 1580, N.W., Washington, D.C. 20549. Information on the operation of the Public Reference Room may be obtained by calling the SEC at 1-800-SEC-0330.SEC. The SEC also maintains an Interneta website at www.sec.gov that contains reports, proxy and information statements, and other information about us that we file electronically with the SEC.
In addition, we post on our Internet website, www.unitcorp.com, copies of our corporate governance documents. Our corporate governance guidelines and code of ethics and the charters of our Board’s Audit, Compensation, and Nominating and Governance Committees, 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 own 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 for our own account.
•Mid-Stream – carried out by our subsidiary Superior Pipeline Company, L.L.C. and its subsidiaries.Superior. This segment buys, sells, gathers, processes, and treats natural gas for third parties and for our own account.
Each company may conduct operations through subsidiaries of its own. We also have several other subsidiaries, none of which conduct material operations.
This table provides certain information about usour assets as of February 13, 2018:December 31, 2021:
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| Oil and Natural Gas | |
Completed grossTotal number of wells in which we own an interest | 6,375 |
5,253 |
| Contract Drilling | |
NumberTotal number of drilling rigs available for use | 95 |
21 |
| Mid-Stream | |
| Number of natural gas treatment plants we own | 3 |
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| Number of processing plants we own | 13 |
12 |
Number of natural gas gathering systems we own(1) | 22 |
18 |
_________________________
(1)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 2018, two gathering systems were transferred to our oilre 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 natural gas segment.under the Bankruptcy Code.
2017The 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
Acquired certain oil and natural gas assets located•Revenues before eliminations increased by 69% from 2020 primarily in Grady and Caddo Counties in western Oklahoma for approximately $54.3 million.due to higher average commodity pricing, partially offset by lower production volumes.
Total year-end 2017 proved oil and natural gas reserves•Operating costs before eliminations decreased 43% from 2020.
•Capital expenditures increased 27% over 2016.89% from 2020.
Replaced 300% of 2017 production with new reserves.
Sold non-core assets with proceeds of $18.6 million.
Contract Drilling
Utilization cycle•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 2017:
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◦ | Started year with 21 drilling rigs operating; |
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◦ | Placed one new BOSS drilling rig into service at the end of the second quarter; |
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◦ | Returned to service 14 SCR drilling rigs and by mid-July had 36 drilling rigs operating; and |
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◦ | Exited year with 31 drilling rigs operating, following weaker commodity prices in the third quarter and with commodity prices beginning to improve late in the year. |
All ten BOSS drilling rigs were operating during the year.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
Record•Revenues before eliminations increased 87% and operating profit (revenue less operating expense)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 $51.7 million, a 7% increase over 2016.
Connected five wells to our Pittsburgh Millslow-pressure gathering system resulting in increased gathered volume of up to 141 MMcf per day.
Began construction on a $14.0 million pipeline, and related compressor expansion project at our Cashion facility to allow us to gather and process production from a new producer with a significant acreage dedication.stations located in southern Kansas in November 2021.
Connected three new wells to our Segno gathering system increasing our gathered volumes to a record high of 98.2 MMcf per day.
Connected six new wells to our Hemphill facility and upgraded compression facilities to handle expected higher volumes in the Buffalo Wallow area.
FINANCIAL INFORMATION ABOUT SEGMENTS
See Note 1623 - Industry Segment Information of our Notes to Consolidated Financial Statements in Item 8 of this report for information regardingabout 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 these locations:Oklahoma and Texas, and to a lesser extent Kansas, Louisiana, Montana, North Dakota, Utah, and Wyoming.
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Division | Location |
West division | Western and Southern Texas, Colorado, Wyoming, Montana, North Dakota, New Mexico, Southern Louisiana, and Utah |
East division | Eastern Oklahoma and Arkansas |
Central division | Western Oklahoma, Texas Panhandle, and Kansas |
When we are the operator of a property, we attempttry to use aone of our drilling rig owned by our contract drilling segment,rigs to drill any wells on the property, and we also use our mid-stream segment to gather our gas if it is economical for us to do so.
This table presents certain information regarding our oil and natural gas operations as of December 31, 2017:2021:
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| Our Divisions/Area | Number of Gross Wells | | Number of Net Wells | | Number of Gross Wells in Process | | Number of Net Wells in Process | | 2017 Average Net Daily Production |
| | | | | Natural Gas (Mcf) | | Oil (Bbls) | | NGLs (Bbls) |
| West division | 1,163 |
| | 430.75 |
| | — |
| | — |
| | 54,450 |
| | 1,921 |
| | 4,875 |
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| East division | 192 |
| | 105.00 |
| | — |
| | — |
| | 6,195 |
| | 10 |
| | — |
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| Central division | 5,109 |
| | 1,905.18 |
| | 10 |
| | 3.11 |
| | 79,792 |
| | 5,508 |
| | 8,104 |
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| Total | 6,464 |
| | 2,440.93 |
| | 10 |
| | 3.11 |
| | 140,437 |
| | 7,439 |
| | 12,979 |
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| 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 | |
AsDispositions. 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 31, 2017, we had no1, 2021. No gain or loss was recognized as the sale of these assets did not result in a significant water floods, pressure maintenance operations, or any other material related activities that were in process.alteration of the full cost pool.
Description and LocationOn August 16, 2021, the company closed on the sale of Our Core Operations
West division. Insubstantially all of our Wilcox play, located primarily in Polk, Tyler, Hardin, and Goliad Counties, Texas, we completed six vertical and two horizontal wells (average working interest 94.3%) in 2017. Seven wells were completed as gas/condensate producers and one well as an oil producer. Annual production from our Wilcox play averaged 91 MMcfe per day (12% oil, 30% NGLs, 58% natural gas) which is a decrease of approximately 4% compared to 2016. We averaged approximately 0.5 Unit drilling rigs operating during 2017 and we plan to use approximately 0.8 Unit drilling rigs operating during 2018. We anticipate completing approximately eight vertical wells and two horizontal wells during 2018. In addition, we planrelated leases located near Oklahoma City, Oklahoma for $19.5 million, subject to complete approximately 13 behind pipe gascustomary closing and liquids zones.
Central division. In our Southern Oklahoma Hoxbar Oil Trend (SOHOT) play,post-closing adjustments. No gain or loss was recognized as the sale of these assets did not result in western Oklahoma primarily in Grady County, we completed six horizontal oil wells (average working interest 88.8%) in the Marchand zonea significant alteration of the Hoxbar interval. Annual production from western Oklahoma averaged 60.5 MMcfe per day (29%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 22% NGLs, 49%and natural gas) which is a decrease of approximately 7% compared to 2016. During 2017, we averaged approximately 0.75 Unit drilling rigs operating and we currently plan to use approximately one Unit drilling rigs operating during 2018. We anticipate completing approximately nine horizontal Marchand wells in our SOHOT play during 2018 with six being extended laterals.
Also in Oklahoma, we intend to utilize 0.75 Unit drilling rigs throughout 2018 between our Western STACK and Red Fork plays. We anticipate completing one horizontal Osage, two extended lateral horizontal Meramec, one standard length horizontal Meramec, and two horizontal Red Fork wells.
In our Texas Panhandle Granite Wash play, we completed six extended lateral horizontal gas/condensate wells (average working interest 99%) in our Buffalo Wallow field. Annual production from the Texas Panhandle averaged 86.5 MMcfe per day (10% oil, 38% NGLs, 52% natural gas) which is a decrease of approximately 8% compared to 2016. We used one Unit drilling rig during 2017 and plan to continue using that rig during 2018. We anticipate completing approximately 11 extended lateral Granite Wash horizontal wells in our Buffalo Wallow field during 2018.
In our Mississippian play in south central Kansas, we completed one horizontal oil well (working interest 100%). Annual production from Kansas averaged 7.3 MMcfe per day (60% oil, 11% NGLs, 29% natural gas) which is an increase of approximately 18% compared to 2016.
East division. Over the last several years, activity in our East division has been limited due to low gas prices since this area rarely has oil or NGLs associated with the gas. We drilled no wells in this division during 2017.
Dispositions. We had non-core asset sales,assets, net of related expenses, during the year ended December 31, 2021. No gain or loss was recognized as the sale of $18.6 million, $67.2 million, and $1.9 million,these assets did not result in 2017, 2016, and 2015, respectively. Proceeds from these sales reduced the net book valuea significant alteration of the full cost pool with no gain or loss recognized.pool.
During prior years, we determined the value
Well and Leasehold Data. The following tables identify certain information regarding our oil and natural gas exploratory and development drilling operations:
|
| | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| | Gross | | Net | | Gross | | Net | | Gross | | Net |
| Wells drilled: | | | | | | | | | | | |
| Development: | | | | | | | | | | | |
| Oil: | | | | | | | | | | | |
| West division | 1 |
| | 1.00 |
| | — |
| | — |
| | 2 |
| | 0.66 |
|
| East division | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Central division | 44 |
| | 9.98 |
| | 9 |
| | 3.57 |
| | 21 |
| | 8.12 |
|
| Total oil | 45 |
| | 10.98 |
| | 9 |
| | 3.57 |
| | 23 |
| | 8.78 |
|
| Natural gas: | | | | | | | | | | | |
| West division | 7 |
| | 6.55 |
| | 4 |
| | 3.98 |
| | 15 |
| | 13.50 |
|
| East division | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Central division | 16 |
| | 7.35 |
| | 7 |
| | 1.12 |
| | 18 |
| | 11.50 |
|
| Total natural gas | 23 |
| | 13.90 |
| | 11 |
| | 5.10 |
| | 33 |
| | 25.00 |
|
| Dry: | | | | | | | | | | | |
| West division | 2 |
| | 0.83 |
| | — |
| | — |
| | 1 |
| | 1.00 |
|
| East division | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Central division | — |
| | — |
| | — |
| | — |
| | 1 |
| | 0.21 |
|
| Total dry | 2 |
| | 0.83 |
| | — |
| | — |
| | 2 |
| | 1.21 |
|
| Total development | 70 |
| | 25.71 |
| | 20 |
| | 8.67 |
| | 58 |
| | 34.99 |
|
| Exploratory: | | | | | | | | | | | |
| Oil: | | | | | | | | | | | |
| West division | — |
| | — |
| | 1 |
| | 1.00 |
| | — |
| | — |
|
| East division | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Central division | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Total oil | — |
| | — |
| | 1 |
| | 1.00 |
| | — |
| | — |
|
| Natural gas: | | | | | | | | | | | |
| West division | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| East division | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Central division | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Total natural gas | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Dry: | | | | | | | | | | | |
| West division | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| East division | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Central division | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Total dry | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Total exploratory | — |
| | — |
| | 1 |
| | 1.00 |
| | — |
| | — |
|
| Total wells drilled | 70 |
| | 25.71 |
| | 21 |
| | 9.67 |
| | 58 |
| | 34.99 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 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 | | | | | |
|
| | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 (1) | | 2015 |
| | Gross | | Net | | Gross | | Net | | Gross | | Net |
| Wells producing or capable of producing: | | | | | | | | | | | |
| Oil: | | | | | | | | | | | |
| West division | 602 |
| | 124.39 |
| | 648 |
| | 136.59 |
| | 692 |
| | 149.34 |
|
| East division | 11 |
| | — |
| | 18 |
| | 0.72 |
| | 28 |
| | 1.79 |
|
| Central division | 941 |
| | 508.46 |
| | 908 |
| | 497.25 |
| | 907 |
| | 498.75 |
|
| Total oil | 1,554 |
| | 632.85 |
| | 1,574 |
| | 634.56 |
| | 1,627 |
| | 649.88 |
|
| Natural gas: | | | | | | | | | | | |
| West division | 546 |
| | 298.97 |
| | 582 |
| | 296.71 |
| | 659 |
| | 325.57 |
|
| East division | 179 |
| | 104.64 |
| | 181 |
| | 105.85 |
| | 1,358 |
| | 466.22 |
|
| Central division | 4,162 |
| | 1,394.05 |
| | 4,181 |
| | 1,367.87 |
| | 4,217 |
| | 1,376.94 |
|
| Total natural gas | 4,887 |
| | 1,797.66 |
| | 4,944 |
| | 1,770.43 |
| | 6,234 |
| | 2,168.73 |
|
| Total | 6,441 |
| | 2,430.51 |
| | 6,518 |
| | 2,404.99 |
| | 7,861 |
| | 2,818.61 |
|
_________________________
| |
(1) | During 2016, we had divestitures of 1,300 gross (407.70 net) wells. There were no significant divestitures in 2017 or 2015. |
As of February 13, 2018, we were drilling or participating in 12 gross (4.22 net) wells started during 2018.
Cost for development drilling includes $41.6 million, $2.5 million, and $58.6 million in 2017, 2016, and 2015, respectively, toWe did not develop any previously booked proved undeveloped oil and natural gas reserves.reserves in 2021 or 2020.
ThisThe following table summarizes our leasehold acreage at December 31, 2017:2021:
|
| | | | | | | | | | | | | | | | | |
| | Year Ended December 31, 2017 |
| | Developed | | Undeveloped | | Total |
| | Gross | | Net | | Gross | | Net (1) | | Gross | | Net |
| West division | 254,887 |
| | 81,989 |
| | 74,387 |
| | 58,608 |
| | 329,274 |
| | 140,597 |
|
| East division | 88,278 |
| | 23,717 |
| | 3,349 |
| | 2,190 |
| | 91,627 |
| | 25,907 |
|
| Central division | 901,570 |
| | 425,462 |
| | 91,843 |
| | 52,868 |
| | 993,413 |
| | 478,330 |
|
| Total | 1,244,735 |
| | 531,168 |
| | 169,579 |
| | 113,666 |
| | 1,414,314 |
| | 644,834 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 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 70% (West – 76%; East – 95%; and Central – 61%) of the net undeveloped acres are covered by leases that will expire in the years 2018—2020 unless drilling or production extends the terms of those leases. Currently, we do not have any material proved undeveloped (PUD) reserves attributable to acreage where the expiration date precedes the scheduled PUD reserve development plan. |
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.
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 yearsperiods indicated:
| | | | Year Ended December 31, | | Successor | | | Predecessor |
| | 2017 | | 2016 | | 2015 | | 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: | | | | | | Average sales price per barrel of oil produced: | | | | | | | |
| Price before derivatives | $ | 48.98 |
| | $ | 39.05 |
| | $ | 45.04 |
| Price before derivatives | $ | 66.50 | | | $ | 39.23 | | | | $ | 35.14 | | |
| Effect of derivatives | 0.46 |
| | 1.45 |
| | 5.75 |
| Effect of derivatives | (16.47) | | | (1.94) | | | | (3.16) | | |
| Price including derivatives | $ | 49.44 |
| | $ | 40.50 |
| | $ | 50.79 |
| Price including derivatives | $ | 50.03 | | | $ | 37.29 | | | | $ | 31.98 | | |
| Average sales price per barrel of NGLs produced: | | | | | | Average sales price per barrel of NGLs produced: | | | | | | | |
| Price before derivatives | $ | 18.35 |
| | $ | 11.26 |
| | $ | 10.12 |
| Price before derivatives | $ | 23.41 | | | $ | 9.28 | | | | $ | 4.83 | | |
| Effect of derivatives | — |
| | — |
| | — |
| Effect of derivatives | — | | | — | | | | — | | |
| Price including derivatives | $ | 18.35 |
| | $ | 11.26 |
| | $ | 10.12 |
| Price including derivatives | $ | 23.41 | | | $ | 9.28 | | | | $ | 4.83 | | |
| Average sales price per Mcf of natural gas produced: | | | | | | Average sales price per Mcf of natural gas produced: | | | | | | | |
| Price before derivatives | $ | 2.49 |
| | $ | 1.98 |
| | $ | 2.25 |
| Price before derivatives | $ | 3.55 | | | $ | 1.91 | | | | $ | 1.11 | | |
| Effect of derivatives | (0.03 | ) | | 0.09 |
| | 0.38 |
| Effect of derivatives | (0.62) | | | 0.01 | | | | 0.03 | | |
| Price including derivatives | $ | 2.46 |
| | $ | 2.07 |
| | $ | 2.63 |
| Price including derivatives | $ | 2.93 | | | $ | 1.92 | | | | $ | 1.14 | | |
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| Oil production (MBbls): | | | | | |
| West division: | | | | | |
| Jazz Wilcox field | 533 |
| | 589 |
| | 422 |
|
| All other west division fields | 168 |
| | 238 |
| | 258 |
|
| Total west division | 701 |
| | 827 |
| | 680 |
|
| East division | 4 |
| | 8 |
| | 11 |
|
| Central division: | | | | | |
| Buffalo Wallow field | 127 |
| | 120 |
| | 145 |
|
| All other central division fields | 1,883 |
| | 2,019 |
| | 2,947 |
|
| Total central division | 2,010 |
| | 2,139 |
| | 3,092 |
|
| Total oil production | 2,715 |
| | 2,974 |
| | 3,783 |
|
| NGLs production (MBbls): | | | | | |
| West division: | | | | | |
| Jazz Wilcox field | 1,567 |
| | 1,671 |
| | 1,275 |
|
| All other west division fields | 212 |
| | 216 |
| | 266 |
|
| Total west division | 1,779 |
| | 1,887 |
| | 1,541 |
|
| East division | — |
| | — |
| | 6 |
|
| Central division: | | | | | |
| Buffalo Wallow field | 728 |
| | 592 |
| | 724 |
|
| All other central division fields | 2,230 |
| | 2,535 |
| | 3,003 |
|
| Total central division | 2,958 |
| | 3,127 |
| | 3,727 |
|
| Total NGLs production | 4,737 |
| | 5,014 |
| | 5,274 |
|
| Natural gas production (MMcf): | | | | | |
| West division: | | | | | |
| Jazz Wilcox field | 16,799 |
| | 18,145 |
| | 14,538 |
|
| All other west division fields | 3,076 |
| | 2,506 |
| | 3,259 |
|
| Total west division | 19,875 |
| | 20,651 |
| | 17,797 |
|
| East division | 2,261 |
| | 2,956 |
| | 6,846 |
|
| Central division: | | | | | |
| Buffalo Wallow field | 6,228 |
| | 5,506 |
| | 6,895 |
|
| All other central division fields | 22,896 |
| | 26,622 |
| | 34,008 |
|
| Total central division | 29,124 |
| | 32,128 |
| | 40,903 |
|
| Total natural gas production | 51,260 |
| | 55,735 |
| | 65,546 |
|
| Total production (MBoe): | | | | | |
| West division: | | | | | |
| Jazz Wilcox field | 4,900 |
| | 5,284 |
| | 4,120 |
|
| All other west division fields | 893 |
| | 872 |
| | 1,067 |
|
| Total west division | 5,793 |
| | 6,156 |
| | 5,187 |
|
| East division | 381 |
| | 500 |
| | 1,158 |
|
| Central division: | | | | | |
| Buffalo Wallow field | 1,893 |
| | 1,629 |
| | 2,019 |
|
| All other central division fields | 7,929 |
| | 8,992 |
| | 11,618 |
|
| Total central division | 9,822 |
| | 10,621 |
| | 13,637 |
|
| Total production | 15,996 |
| | 17,277 |
| | 19,982 |
|
Average production cost per equivalent Bbl (1) | $ | 5.86 |
| | $ | 5.62 |
| | $ | 7.06 |
|
| | | | | | | | | | | | | | | | | | | | | | |
| 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. |
1.Excludes ad valorem taxes and gross production taxes.
Our Buffalo Wallow field in Hemphill County, Texas, contained 24%, 13%, 10%20% and 16% of our total proved reserves in 2017, 2016,2021 and 2015,2020, respectively, expressed on an oil equivalentoil-equivalent barrels basis. Our Jazz WilcoxMendota field, in Souththe Granite Wash play in the Texas which includes our Gilly, Segno,Panhandle, contained 15% and Wildwood prospects and several smaller prospects, contained 18%, 26%, and 24%16% of our total proved reserves for those same years also expressed on an oil equivalentoil-equivalent barrels basis. There are no other fields that accounted for more thanover 15% of our proved reserves.
Oil, NGLs, and Natural Gas Reserves. The following table below identifies our estimated proved developed and undeveloped oil, NGLs, and natural gas reserves:
|
| | | | | | | | | | | |
| | Year Ended December 31, 2017 |
| | Oil (MBbls) | | NGLs (MBbls) | | Natural Gas (MMcf) | | Total Proved Reserves (MBoe) |
| Proved developed: | | | | | | | |
| West division | 2,902 |
| | 8,812 |
| | 93,456 |
| | 27,290 |
|
| East division | — |
| | — |
| | 41,720 |
| | 6,953 |
|
| Central division | 11,960 |
| | 24,546 |
| | 253,270 |
| | 78,718 |
|
| Total proved developed | 14,862 |
| | 33,358 |
| | 388,446 |
| | 112,961 |
|
| Proved undeveloped: | | | | | | | |
| West division | 329 |
| | 1,220 |
| | 12,255 |
| | 3,592 |
|
| East division | — |
| | — |
| | 1,394 |
| | 232 |
|
| Central division | 4,322 |
| | 10,908 |
| | 106,555 |
| | 32,989 |
|
| Total proved undeveloped | 4,651 |
| | 12,128 |
| | 120,204 |
| | 36,813 |
|
| Total proved | 19,513 |
| | 45,486 |
| | 508,650 |
| | 149,774 |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | 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. We use Ryder Scott
Company L.P., (Ryder Scott), independent petroleum consultants, to audit the reserves prepared by our reservoir engineers. Ryder Scott has been providing petroleum consulting services throughout the world 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 reserveReserve Estimation and income projections as of December 31, 2017, and comprised 83% of the total proved developed future net income discounted at 10% and 86% of the total proved discounted future net income (based on the SEC's unescalated pricing policy).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. Our internal audit groupManagement 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, by Ryder Scott, the reservoir department performs a final review ofreviews 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).
Mr. Robert J. Paradiso was the primary technical person responsible for overseeing the estimate of the reserves future production and income 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. As part of his 2017 continuing education hours, Mr. Paradiso attended 6 hours of formalized training during the 2017 RSC Reserves Conference relating to the definitions and disclosure guidelines in the United States Securities and Exchange Commission Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register. Mr. Paradiso attended an additional 37.5 hours of formalized in-house training during 2017 covering such topics as the SPE/WPC/AAPG/SPEE Petroleum Resources Management System, reservoir engineering, geoscience and petroleum economics evaluation methods, procedures and software and ethics for consultants.
Based on his educational background, professional training and over 3841 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 set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the SPE as of February 19, 2007.June 2019. For more information regarding Mr. Paradiso’s geographic and job specificjob-specific experience, please refer to the Ryder Scott Company website at http://www.ryderscott.com/Company/Employees.
The Company – Responsibility for overseeing the preparation of our reserve report is shared by our reservoir engineers Trenton Mitchell and Derek Smith.
Mr. Mitchell earned a Bachelor of Science degree in Petroleum Engineering from Texas A&M University in 1994. He has been an employee of Unit since 2002. Initially, he was the Outside Operated Engineer and since 2003 he has served in the capacity of Reservoir Engineer and in 2010 he was promoted to Manager of Reservoir Engineering. Before joining Unit, he served in several engineering field and technical support positions with Schlumberger Well Services in their pumping services segment (formerly Dowell Schlumberger). He obtained his Professional Engineer registration from the State of Oklahoma in 2004. He has been a member of SPE since 1991 and joined the Society of Petroleum Evaluation Engineers (SPEE) in 2017.
Mr. Smith received a Bachelor of Science in Petroleum Engineering with a Minor in Business from the University of Tulsa in 2005. He worked for Apache Corporation immediately after in Production Engineering, then Reservoir Engineering, followed by Drilling Engineering for approximately one year each before moving to Corporate Reserves in 2008. He joined Unit in 2009 as a Corporate Reserves Engineer involved in reserve evaluation, acquisition appraisals, and prospect reviews with increasing levels of responsibility. He has been a member of SPE since 2000.
As part of their continuing education Mr. Mitchell and Mr. Smith 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.
Definitions and Other. Other Proved oil, NGLs, and natural gasReserve Information.
For proved reserves, as defined in SEC Rule 4-10(a), 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 – before the time 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 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.
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 itthe 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 establishesestablish 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-month period12 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" oil, NGLs, and natural gas reserves are proved reserves expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expense is required for completion. Reserves on undrilled acreage are limited to those directly offsetting development spacing areas reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time. Under no circumstances can estimates for proved undeveloped reserves be attributable to acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless those techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.
Proved Undeveloped Reserves. As of December 31, 2017,2021, we had 99 grossno proved undeveloped wells all of which we plan to develop within five years of initial disclosure at a net estimated cost of approximately $326.2 million. The future estimated development costs to develop our proved undeveloped oil and natural gas reserves for the years 2018-2022, as disclosed in our December 31, 2017 oil and natural gas reserve report, are shown below:reserves.
|
| | | | | | | |
| Year | | Number of Gross Wells Planned | | Estimated Net Development Cost (In millions) |
| 2018 | | 35 |
| | $ | 78.3 |
|
| 2019 | | 36 |
| | 152.2 |
|
| 2020 | | 19 |
| | 78.3 |
|
| 2021 | | 9 |
| | 17.4 |
|
| 2022 | | — |
| | — |
|
| | | 99 |
| | $ | 326.2 |
|
Our proved undeveloped reserves reported at December 31, 2017 did not include reserves we did not expect to develop within five years of initial disclosure of those reserves. Below is a summary of changes to our proved undeveloped reserves during 2017:
|
| | | | | | | | | | | |
| | Oil (MMBbls) | | NGLs (MMBbls) | | Natural Gas (Bcf) | | Total (MMBoe) |
| Proved undeveloped reserves, January 1, 2017 | 3.0 |
| | 6.0 |
| | 58.5 |
| | 18.7 |
|
| Extensions and discoveries | 2.4 |
| | 7.6 |
| | 75.0 |
| | 22.6 |
|
| Converted to developed | (1.1 | ) | | (1.1 | ) | | (11.7 | ) | | (4.2 | ) |
| Revisions of previous estimates | (0.2 | ) | | (0.7 | ) | | (4.5 | ) | | (1.7 | ) |
| Purchases of reserves | 0.6 |
| | 0.3 |
| | 2.9 |
| | 1.4 |
|
| Proved undeveloped reserves, December 31, 2017 | 4.7 |
| | 12.1 |
| | 120.2 |
| | 36.8 |
|
During 2017, we converted nine proved undeveloped well locations into proved developed wells at a cost of approximately $41.6 million. The increase in the table above to our extensions and discoveries were due to a number of factors including increased drilling activity, higher commodity prices resulting in an increased budget for future capital expenditures, all contributing to more wells being economic to develop in the next five years.
Our estimated proved reserves and the standardized measure of discounted future net cash flows of the proved reserves at December 31, 2017, 2016,2021 and 2015,2020, the changes in quantities, and standardized measure of those reserves for the three years then ended, are shown in the Supplemental Oil and Gas Disclosures in Item 8 of this report.
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 to 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. During 2017, sales to Sunoco LogisticsOne customer accounted for 10%11% of our oil and natural gas revenues. Norevenues 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. During 2017, ourOur mid-stream segment purchased $63.2$48.0 million of our natural gas and NGLs production and provided gathering and transportation services of $6.7$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. In 2016 and 2015, we eliminated intercompany revenues of $51.9 million and $65.2 million, respectively, attributable to the intercompany purchase of our production of natural gas and NGLs and gathering and transportation services.
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 our own accountourselves and for other oil and natural gas companies.others. Our drilling operations are mainly in Oklahoma, Texas, Louisiana, Kansas, Colorado, Wyoming, and North Dakota. Until October 31, 2015, our drilling operations in Texas were conducted under Unit Texas Drilling L.L.C., a subsidiary of Unit Drilling Company. Effective October 31, 2015, that subsidiary was merged into Unit Drilling Company.New Mexico.
ThisThe following table identifies certain information about our contract drilling segment:segment assets and activity:
| | | | | | | | | | Successor | | | Predecessor |
| | Year Ended December 31, | | Year Ended
December 31, 2021 | | Four Months Ended
December 31, 2020 | | | Eight Months Ended
August 31, 2020 | |
| | 2017 | | 2016 | | 2015 | |
| Number of drilling rigs available for use at year end | 95.0 |
| | 94.0 |
| | 94.0 |
| |
| Average number of drilling rigs owned during year | 94.5 |
| | 93.9 |
| | 92.6 |
| |
| Number of drilling rigs available for use | | Number of drilling rigs available for use | 21 | | | 58 | | | | 58 | | |
| Average number of drilling rigs owned | | Average number of drilling rigs owned | 30 | | | 58 | | | | 58 | | |
| Average number of drilling rigs utilized | 30.0 |
| | 17.4 |
| | 34.7 |
| Average number of drilling rigs utilized | 10.9 | | | 7.2 | | | | 11.5 | | |
Utilization rate (1) | 32 | % | | 19 | % | | 38 | % | Utilization rate (1) | 36 | % | | 12 | % | | | 20 | % | |
Average revenue per day (2) | $ | 15,935 |
| | $ | 19,154 |
| | $ | 20,950 |
| Average revenue per day (2) | $ | 19,097 | | | $ | 21,974 | | | | $ | 26,106 | | |
| Total footage drilled (feet in 1,000’s) | 6,864 |
| | 5,112 |
| | 7,237 |
| Total footage drilled (feet in 1,000’s) | 4,487 | | | 1,062 | | | | 2,999 | | |
| Number of wells drilled | 468 |
| | 358 |
| | 516 |
| 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 owned during the year. |
| |
(2)
| Represents the total revenues from our contract drilling segment divided by the total days our drilling rigs were used during the year. |
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 rebuilt on a periodic basis.overhauled periodically. Other major components, like the substructure, mast, and drawworks, can be used for extended periods of time 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. Our drilling rigs can be transferred between divisions.
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 customerscustomers' drilling requirements. In 2017, 36 of our 95 drilling rigs were used in drilling services.
ThisThe following table shows certain information about our drilling rigs (including their distribution) as of February 13, 2018:December 31, 2021:
|
| | | | | | | | | | | |
| Divisions | Contracted Rigs | | Non-Contracted Rigs | | Total Rigs | | Average Rated Drilling Depth (ft) |
| Mid-Continent | 25 |
| | 50 |
| | 75 |
| | 17,260 |
|
| Rocky Mountain | 6 |
| | 14 |
| | 20 |
| | 19,925 |
|
| Totals | 31 |
| | 64 |
| | 95 |
| | 17,821 |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Contracted Rigs | | Non-Contracted Rigs | | Total Rigs | | Average Rated Drilling Depth (ft) |
| | | | | | | |
| | | | | | | |
| Drilling Rigs | 16 | | | 5 | | | 21 | | | 20,238 | |
The cyclical natureFluctuating commodity prices directly affect the number of the contract drilling business is reflected inrigs we can put to work, both positively and negatively. Generally, sustained higher commodity prices lead to greater demand for drilling rig utilization rates.rigs, while demand and rates tends to fall as commodity prices decline for any extended period. Drilling rig utilization at the end of 2015 was 26 drilling rigs. Then in 2016, utilization bottomed out in May at 13 operating drilling rigs. Asincreased during 2021 as commodity prices improved during the remainder 2016, we exited the year with 21 active drilling rigs. The increased rig activity continued on into 2017 as we added one new BOSS drilling rig and returned to service 14 SCR drilling rigs to peak at 36 drilling rigs utilized in the third quarter. Following which commodity prices weakened during the third quarter and our active drilling rig count dropped to 27 drilling rigs. However, commodity prices rebounded late in the year and we finished 2017 with 31 drilling rigs operating.
Mid-Continent. The Mid-Continent division manages operations from Oklahoma, Texas, Louisiana, and Kansas. The division operated an average of 23.8 drilling rigs during 2017. As of December 31, 2017, this division was operating 26 drilling rigs, 18 of which were working in Oklahoma and the Texas Panhandle, one in East Texas, and seven in the Permian Basin of West Texas.
Rocky Mountains. Our Rocky Mountain division covers Colorado, Utah, Wyoming, Montana, and North Dakota. This vast area has produced several conventional and unconventional oil and gas fields. This division operated an average of 6.2 drilling rigs during 2017. We had two drilling rigs operating in Wyoming and three drilling rigs operating in the Bakken Shale of North Dakota at the end of 2017.
increased. The number of drilling rigs we can work also depends on several conditions besides demand, including the availability of qualified labor andas well as the availability of needed drilling supplies and equipment. The impact
The following table shows the average number of our drilling rigs working by quarter for the years indicated:
| | | | 2017 | | 2016 | | 2015 | | 2021 | | 2020 | |
| First quarter | 25.5 |
| | 20.6 |
| | 50.1 |
| First quarter | 9.4 | | | 18.7 | | |
| Second quarter | 28.8 |
| | 13.5 |
| | 30.7 |
| Second quarter | 10.0 | | | 9.1 | | |
| Third quarter | 34.6 |
| | 16.0 |
| | 31.2 |
| Third quarter | 11.0 | | | 5.1 | | |
| Fourth quarter | 31.2 |
| | 19.5 |
| | 27.2 |
| Fourth quarter | 13.2 | | | 7.6 | | |
Drilling Rig Fleet. The following table summarizesWe reduced the changesnumber of drilling rigs available for use from 58 at December 31, 2020 to our drilling rig fleet21 during the second quarter of 2021 in 2017. A more complete discussion of changes over the last three years follows the table:
|
| | |
Drilling rigs available for use at January 1, 2017 | 94 |
|
Drilling rigs constructed | 1 |
|
Total drilling rigs available for use at December 31, 2017 | 95 |
|
Dispositions, Acquisitions, and Construction. During 2015, we recorded a write-downorder to focus on 31utilization of our BOSS drilling rigs and related equipmentcertain SCR rigs that are either currently under contract or candidates for future upgrades.
Dispositions. We sold non-core contract drilling assets for proceeds of approximately $8.3 million pre-tax based on the estimated market value for similar equipment from auctions sales. We then sold all 31 of these drilling rigs and some other drilling equipment to unaffiliated third parties. The proceeds from the sale of those assets, less costs to sell, was less than the $11.3$12.7 million, net book valueof related expenses, resulting in a lossnet gains of $7.3$10.1 million pre-tax.during the year ended December 31, 2021.
During 2015, five BOSS drilling rigs were constructed and placed into service for third-party operators.
During December 2016, we sold an idle 1,500 horsepower SCR drilling rig to an unaffiliated third party. We also built and placed into service for a third party operator our ninth BOSS drilling rig. This new BOSS rig was constructed using the long lead time components purchased in prior years.
During 2017, we built our tenth BOSS drilling rig and placed it into service for a third party operator under a long term contract.
Drilling Contracts. Our third-party drilling contracts are generally obtained through competitive bidding on a well by wellwell-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 negotiablenegotiated on a contract by contractcontract-by-contract basis.
The typeMost of contract used determines our compensation. Contracts are generally one of three types: daywork; footage; or turnkey.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. Footage contracts usually require us to bear some of the drilling costs besides providing the drilling rig. We are paid on completion of the well at a negotiated rate for each foot drilled. Under turnkey contracts we drill the well to a specified depth for a set amount and provide most of the required equipment and services. We bear the risk of drilling the well to the contract depth and are paid when the contract provisions are completed. We may incur losses if we underestimate the costs to drill the well or if unforeseen events occur that increase our costs or result in losing the well. We had no footage or turnkey contracts in 2017, 2016, or 2015. Because market demand for our drilling rigs and the desires of our customers determine the types of contracts we use, we cannot predict when and if a part of our drilling will be conducted under footage or turnkey contracts.
The majorityMost of our contracts are on a well-to-well basis,term contracts, with the rest under termbeing well-to-well contracts. Term contracts can range from six months to twomultiple years and the rates can either be fixed throughout the term or allow for periodic adjustments.
Customers. During 2017, QEP Resources, Inc. was our largest drilling customer accountingFive customers accounted for approximately 26%79% of our total contract drilling revenues. Our work for this customer was under multiple contracts and our business was not substantially dependent on any of these individual contracts. None of these individual contracts were considered to be material.revenues during the year ended December 31, 2021. No other third partythird-party customer accounted for 10% or more of our contract drilling revenues.
Our contract drilling segment may also providesprovide drilling services for our oil and natural gas segment. During 2017, 2016, and 2015, ourThe contract drilling segment drilled 27, 10, and 38did not drill any wells respectively, for our oil and natural gas segment or 6%, 3%, and 7%, respectively, of the total wells drilled by our contract drilling 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. The contracts for these services are issued under similar terms and rates as the contracts signed with unrelated third parties. By providing drilling services for the oil and natural gas segment, we eliminated revenue of $13.4 million and $22.1 million during 2017 and 2015, respectively, from our contract drilling segment and eliminated the associated operating expense of $11.8 million and $18.3 million during 2017 and 2015, respectively, yielding $1.6 million and $3.8 million during 2017 and 2015, respectively, as a reduction to the carrying value of our oil and natural gas properties. We eliminated no revenue or expenses in our contract drilling segment during 2016.
MID-STREAM
General. Our mid-stream operations are conducted through Superior Pipeline Company, L.L.C. and its subsidiaries. Itssubsidiaries, of which we presently own a 50% interest. Superior's operations consist of buying, selling, gathering, processing, and treating natural gas. It operates three3 natural gas treatment plants, 1312 processing plants, 2418 active gathering systems, and approximately 1,4553,822 miles of pipeline. Superior and its subsidiaries operate in Oklahoma, Texas, Kansas, Pennsylvania, and West Virginia.
ThisSuperior 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.
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 yearsperiods indicated:
| | | | Year Ended December 31, | | Successor | | | Predecessor |
| | 2017 | | 2016 | | 2015 | | Year Ended
December 31, 2021 | | Four Months Ended
December 31, 2020 | | | Eight Months Ended
August 31, 2020 | |
| Gas gathered—Mcf/day | 385,209 |
| | 419,217 |
| | 353,771 |
| Gas gathered—Mcf/day | 319,394 | | | 324,892 | | | | 388,506 | | |
| Gas processed—Mcf/day | 137,625 |
| | 155,461 |
| | 182,684 |
| Gas processed—Mcf/day | 130,000 | | | 135,615 | | | | 158,031 | | |
| NGLs sold—gallons/day | 534,140 |
| | 536,494 |
| | 577,513 |
| NGLs sold—gallons/day | 442,796 | | | 441,761 | | | | 612,301 | | |
Dispositions and Acquisitions. This segment had no significant dispositions or acquisitions during 2015, 2016, or 2017.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 some 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 the natural gas. For the year ended December 31, 2017, 71%2021, 76% of our mid-stream segment’s total volumes and 62%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, 2017, 29%2021, 24% of our mid-stream segment’s total volumes and 38%27% of operating margins (as defined below) were under commodity-based contracts.
For each of the above contracts,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.
Customers. During 2017, ONEOK, Inc.Three customers accounted for approximately 36%58% of our mid-stream revenues. We believe that if we lost this customer, there are other customers available to purchase our natural gas and NGLs. During 2017, 2016, and 2015 this segmentNGLs if we were to lose these customers. Superior purchased $63.2$48.0 million $42.7 million, and $57.6 million, respectively, of our oil and natural gas segment's natural gas and NGLs production, and provided gathering and transportation services of $6.7 million, $9.2 million, and $7.6 million,
respectively.$3.3 million. Intercompany revenue from services and purchases of production between this business segmentSuperior and our oil and natural gas segment has been eliminated in our consolidated financial statements.
VOLATILE NATURE OF OUR BUSINESS
The prevailing prices for oil, NGLs, and natural gas significantly affect our revenues, operating results, cash flow and our ability to grow our operations. Oil, NGLs, and natural gas prices have been volatile and they will probably continue to be so. For each period indicated, this table shows the highest and lowest average prices our oil and natural gas segment received for its sales of oil, NGLs, and natural gas without considering the effect of derivatives:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Oil Price per Bbl | | NGLs Price per Bbl | | Natural Gas Price per Mcf |
| Quarter | High | | Low | | High | | Low | | High | | Low |
| 2015 | | | | | | | | | | | |
| First | $ | 46.70 |
| | $ | 43.22 |
| | $ | 18.90 |
| | $ | 1.60 |
| | $ | 2.85 |
| | $ | 2.30 |
|
| Second | $ | 54.37 |
| | $ | 49.28 |
| | $ | 15.41 |
| | $ | 10.21 |
| | $ | 2.50 |
| | $ | 2.11 |
|
| Third | $ | 49.02 |
| | $ | 40.36 |
| | $ | 9.49 |
| | $ | 7.81 |
| | $ | 2.51 |
| | $ | 2.17 |
|
| Fourth | $ | 42.21 |
| | $ | 33.29 |
| | $ | 12.81 |
| | $ | 9.03 |
| | $ | 2.12 |
| | $ | 1.64 |
|
| 2016 | | | | | | | | | | | |
| First | $ | 31.49 |
| | $ | 26.62 |
| | $ | 9.49 |
| | $ | 4.54 |
| | $ | 1.86 |
| | $ | 1.20 |
|
| Second | $ | 45.13 |
| | $ | 36.63 |
| | $ | 13.19 |
| | $ | 8.61 |
| | $ | 1.52 |
| | $ | 1.36 |
|
| Third | $ | 41.75 |
| | $ | 41.40 |
| | $ | 14.95 |
| | $ | 9.87 |
| | $ | 2.48 |
| | $ | 2.32 |
|
| Fourth | $ | 48.80 |
| | $ | 42.71 |
| | $ | 19.07 |
| | $ | 12.14 |
| | $ | 2.85 |
| | $ | 2.25 |
|
| 2017 | | | | | | | | | | | |
| First | $ | 50.48 |
| | $ | 46.85 |
| | $ | 20.71 |
| | $ | 15.04 |
| | $ | 3.76 |
| | $ | 2.14 |
|
| Second | $ | 48.73 |
| | $ | 43.49 |
| | $ | 15.33 |
| | $ | 14.36 |
| | $ | 2.95 |
| | $ | 2.30 |
|
| Third | $ | 49.66 |
| | $ | 44.54 |
| | $ | 19.99 |
| | $ | 16.17 |
| | $ | 2.53 |
| | $ | 2.04 |
|
| Fourth | $ | 57.38 |
| | $ | 49.62 |
| | $ | 22.39 |
| | $ | 21.13 |
| | $ | 2.58 |
| | $ | 1.93 |
|
Prices for oil, NGLs, and natural gas are subject to wide fluctuations in response to relatively minor changes in the actual or perceived supply of and demand for oil and natural gas, market uncertainty, and many additional factors that are beyond our control, including:
political conditions in oil producing regions;
the ability of the members of the Organization of Petroleum Exporting Countries (OPEC) to agree on prices and their ability or willingness to maintain production quotas;
actions taken by foreign oil and natural gas producing nations;
the price of foreign oil imports;
imports and exports of oil and liquefied natural gas;
actions of governmental authorities;
the domestic and foreign supply of oil, NGLs, and natural gas;
the level of consumer demand;
United States storage levels of oil, NGLs, and natural gas;
weather conditions;
domestic and foreign government regulations;
the price, availability, and acceptance of alternative fuels;
volatility in ethane prices causing rejection of ethane as part of the liquids processed stream; and
worldwide economic conditions.
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. You are encouraged to read the Risk Factors discussed in Item 1A of this report for additional risks that can affect our operations.
Our contract drilling operations depend on the level of demand in our operating markets. Both short-term and long-term trends in oil, NGLs, and natural gas prices affect demand. Because oil, NGLs, and natural gas prices are volatile, the level of demand for our services can also be volatile.
Our mid-stream operations provide us greater flexibility in delivering our (and third parties) natural gas and NGLs from the wellhead to major natural gas and NGLs pipelines. Margins received for the delivery of these natural gas and NGLs depend on the price for oil, NGLs, and natural gas and the demand for natural gas and NGLs in our area of operations. If the price of NGLs falls without a corresponding decrease in the cost of natural gas, it may become uneconomical to us to extract certain NGLs. The volumes of natural gas and NGLs processed depend highly on the volume and Btu content of the natural gas and NGLs gathered.
COMPETITION
All of 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.
OIL AND NATURAL GAS PROGRAMS AND CONFLICTS OF INTERESTHUMAN CAPITAL
Unit Petroleum Company serves asWe 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 general partner of 13 oilwell-being and gas limited partnerships (the employee partnerships) which were formed to allow certaindevelopment of our qualified employees, and our directorsaim to participateprovide 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 Unit Petroleum’s oilsafety and gas explorationenvironmental practices - safety and production operations. Employee partnerships were formed for each year beginning with 1984 and ending with 2011. We also had three non-employee partnerships, one formed in 1984 and two formed in 1986 (investments by third parties). Effective December 31, 2014,environmental stewardship are at the 1984 partnership was dissolved and effective December 31, 2016, the two 1986 partnerships were dissolved.forefront of everything that we do.
The employee partnerships formed in 1984 through 1999 have been combined into a single consolidated partnership. The employee partnerships each have a set annual percentage (ranging from 1% to 15%) of our interest that the partnership acquires in most of the oil and natural gas wells we drill or acquire for our own account during the year in which the partnership was formed. The total interest the participants have in our oil and natural gas wells by participating in these partnerships does not exceed one percent of our interest in the wells.
Under our partnership agreements, the general partner has broad discretionary authority to manage the business and operations of the partnership, including the authority to decide regarding the partnership’s participation in a drilling location or a property acquisition, the partnership’s expenditure of funds, and distributing funds to partners. Because the business activities of the limited partners and the general partner are different, conflicts of interest will exist and it is impossible to entirely eliminate these conflicts. Additionally, conflicts of interest may arise when we are the operator of an oil and natural gas well and also provide contract drilling services. In these cases, the drilling operations are conducted under drilling contracts containing terms comparable to those contained in our drilling contracts with non-affiliated operators. We believe we fulfill our responsibility to each contracting party and comply fully with the terms of the agreements which regulate these conflicts.
These partnerships are further described in Notes 2 and 10 to the Consolidated Financial Statements in Item 8 of this report.
EMPLOYEES
As of February 13, 2018,March 3, 2022, we had approximately 910788 employees, none of whom are members of a union or labor organization. Our workforce includes 478 employees in our contract drilling segment, 262136 employees in our oil and natural gas segment, 124128 employees in our mid-stream segment, and 7946 in our general corporate area. Nonegroup. We also periodically utilize the services of our employees are members of a unionindependent contractors. We have not experienced any strikes or labor organization nor have our operations ever been interrupted by a strike or work stoppage. We consider relations with our employees to be satisfactory.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.
Natural Gas Sales and Transportation. Under the Natural Gas Act of 1938, the Federal Energy Regulatory Commission (FERC)FERC regulates the interstate transportation and the sale in interstate commerce for resale of natural gas. FERC’s jurisdictionauthority 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 naturalall-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 jurisdictionauthority 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 naturalAll-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 particular 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 the area of 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.
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 EPA in 2015 established publicly owned treatment works (POTWs) effluent guidelinesFederal Water Pollution Control Act, or the Clean Water Act, and standards forcomparable state laws impose restrictions and strict controls regarding the discharge of pollutants, including produced waters and other oil and gas extraction facilities which reflected industry best practices for unconventional oilnatural gaswastes, into federal and gas extraction facilities.
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 (Army) in 2015 proposed a new expansive definition of the “waters of the United States,” whichknown as the United States Court of Appeals for“Clean Water Rule.�� However, during the Sixth Circuit stayed nationally. On February 28, 2017, an Executive Order was issued and directed thatTrump Administration, the EPA and Army consider interpreting the term “navigable waters” in a manner consistent with Justice Scalia’s opinion in Rapanos v. United States (2006). On March 6, 2017,Corps replaced the EPA and Army announced their intention to review and rescind or revise the 2015 Clean Water Rule and on June 27, 2017 they issued a proposed rule and written recommendations. On January 22, 2018,with the United States Supreme Court in National Association of Manufacturers v.
Department of Defense, et al. vacatedNavigable Waters Protection Rule (NWPR), which narrows the Sixth Circuit’s nationwide stay. As a result, on January 31, 2018, the EPA and Army issued a rule providing that the 2015 definition of “waters of the United States” will not apply until two years followingto 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 dateBiden 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.
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 publishedpossible that certain oil, natural gas, and drilling and production wastes now classified as non-hazardous could be classified as hazardous wastes in the Federal Register.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, Army includes wetlandsit 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 its definitionthe meaning of “watersCERCLA, 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 United States.”costs required to clean up sites at which these hazardous substances have been released into the environment. In 2016,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 United States Supreme Court in U.S. Army Corpsindustry 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 Engineers v. Hawkes held that landowners can challenge in court an Army Corpspreviously disposed substances and wastes, the cleanup of Engineers jurisdictional determination. It is anticipated this decision will provide landowners an important tool in negotiating and resolving conflicts with federal agencies overcontaminated property, or remedial plugging or pit closure operations to prevent future contamination, the extentcosts of wetlands on a property.which could be substantial.
Endangered Species Act. The federal Endangered Species Act called the “ESA,”(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 proposedare under consideration for protected status under the ESA in areas in which we provide or could undertake operations. The U.S. Fishoperations, such as the dunes sagebrush lizard, lesser prairie chicken, and Wildlife Service andgreater sage grouse. In addition, the National Marine FisheriesSupreme Court held in 2016 issued final revised definitions relating to impacts on critical habitats for potentially2018 that only the actual habitat of an endangered species allowing exclusioncan be designated critical habitat, meaning that an uninhabited area that otherwise meets the definition of certain areas if they willcritical habitat should not result in the extinction of the species. In 2017, the Western Governor’s Association issued a Policy Resolution calling on Congress to amend and reauthorize the ESA based upon seven broad goals to make the act more workable and understandable. In December 2017, the Interior Department announced that it is working on possible changes to the ESA withbe 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 revisemean 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 for listing endangered and threatened species and for designationhas paused implementation of critical habitat. Thethe 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.
In 2007, the United States Supreme Court in Massachusetts, et al. v. EPA, held that carbon dioxide may be regulated as an “air pollutant” under theAir Emissions. The federal Clean Air Act if it represents a health hazardand 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 public. On December 7, 2009,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 U.S. Environmental Protection Agency (EPA) responded toClean Air Act that require the Massachusetts, et al. v. EPA decision and issued a finding that the current and projected concentrationsreduction of GHGs in the atmosphere threaten the public health and welfare of current and future generations, and that certain GHGs from new motor vehicles and motor vehicle engines contribute to the atmospheric concentrations of GHG and hence to the threat of climate change. In addition, the EPA issued a final rule, effective in December 2009, requiring the reporting of GHGvolatile organic compound emissions from specified large (25,000 metric tons or more) GHGcertain fractured and refractured natural gas wells for which well completion operations are conducted and further require that most wells use reduced emission sourcescompletions, 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 U.S., beginning in 2011 for emissions in 2010. During 2010, the EPA proposed revisionsissuance of first-time standards, known as Subpart OOOOa, to these reporting requirements to apply to all oil and gas production, transmission, processing, and other facilities exceeding certain emission thresholds. On May 12, 2016, the EPA issued three final rules that together will curbaddress emissions of methane smog-forming volatile organic compounds (VOCs)from equipment and toxic air-pollutants such as benzene from new, reconstructed and modifiedprocesses across oil and natural gas production, storage, processing and transmission sources, while providing greater certainty about Clean Air Act permittingincluding 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 industry. First,suspension, revision, or rescission of the EPA issued updates toSeptember 2020 rule and the New Source Performance Standards (NSPS)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 to add requirements that the industry reduceis expected.
Several states, including Colorado, Pennsylvania, New Mexico and Wyoming, have separately imposed their own regulations on methane emissions of GHGs and to cover additional equipment and activities infrom the oil and natural gas distribution chain by settingsector. 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 require owners/operatorscontroversy 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 findlimit emissions and repair methanecurtail the production of oil and VOC leaks. Second,gas on federal lands, such as through the EPAcessation 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 source determination rule regardingrisk that financial institutions will be required to adopt policies that have the EPA’s air permitting rules as they applyeffect 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.
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 industry. The EPA clarified when multiple piecessector could result in increased costs of equipment and activities must be deemed a single source for determining whether (i) major source Preventioncompliance. Concerns related to the impacts of Significant Deterioration (PSD) and Nonattainment New Source Review requirements apply regarding preconstruction permitting and (ii) a Title V Operating permit is required. Third, the EPA issued a final rule to implement the Minor New Source Review Programclimate change could also result in Indian Countryreduced demand for oil and natural gas production designedand adversely impact the value of reserves. In addition, increased financial scrutiny of climate risks could result in restrictions on our access to limit emissionscapital. Moreover, there are increasing risks to operations resulting from the potential physical impacts of harmful air pollution while making the preconstruction permitting processclimate change, such as drought, wildfires, damage to infrastructure and resources from flooding, storms, and other natural disasters and other physical disruptions. One or more streamlinedof these developments could have a material adverse effect on our business, financial condition and efficient. These regulations will cause additional costs to reduce emissionsresults of GHGs associated with our operations and could hurt demand for the crude oil we gather, transport, store or otherwise handle in connection with our services. Although the EPA announced in April 2017 it will reconsider the GHG oil and gas emissions rule and delay its compliance, lawsuits have prevented such an effort.operation.
Hydraulic Fracturing. Our oil and natural gas segment routinely appliesapply 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. On July 25, 2017,Hydraulic fracturing has been the Bureausubject of Land Management announced a proposalpublic scrutiny over the past several years. While states typically have primary authority with respect to rescind the 2015 Department of Interior final rule onregulating oil and natural gas production activities, including hydraulic fracturing, a rulefrom 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 never in effect due to pending litigation. Multiple bills have been introducedreintroduced in Congress, which includes resolutions that would (i) block federal regulationauthorize the EPA to regulate unconventional drilling activities, including requiring the disclosure of chemicals used, and end various exemptions for hydraulic fracturing in favor of state rules, (ii) allow a state to regulate hydraulic fracturing on federal lands within that state, (iii) prevent federal regulation of hydraulic regulation to apply to any land held in trust or restricted status for the benefit of Indians without their express consent, (iv) repeal the exemption for hydraulic fracturing inlaws such as RCRA, the Safe Drinking Water Act, and/or (v) requireand the disclosure of chemicals used in hydraulic fracturing.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.
OnIn December 31, 2016, the EPA released its scientific Final Reportfinal report on Impacts from Hydraulic Fracturing Activities on Drinking Water. The EPA states the report, which was done at the requestpotential impacts of Congress, provides scientific evidence that hydraulic fracturing on drinking water resources. The final report concluded that certain activities can affectassociated with hydraulic fracturing may impact drinking water resources in the United States under somecertain limited circumstances. The EPA identifies six conditions under which impacts from hydraulic fracturing activities can be more frequent or severe and existing uncertainties and data gaps. Both the EPA and the United States Geological Survey (USGS) have made statements indicating that activitiesthe disposal of wastes associated with hydraulic fracturing via injection wells may be causing earthquakes, withresult 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 focus being on wastewater disposalstate 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, rather than injection wells. In an August 2015 report sentin addition to more stringent well construction and monitoring requirements. Local governments may also adopt ordinances within their jurisdictions regulating the Texas Railroad Commission, the EPA stated it believes there is a significant possibility that North Texas earthquake activity is associated with disposal wells. The USGS has stated thattime, place and manner of drilling activities in general or hydraulic fracturing causes small earthquakes, but they are almost always too small to be detected. Regarding disposal wells, the USGS has stated that the injection of wastewater and salt water by deep wells into the subsurface can cause earthquakes that are large enough to be felt and may cause damage. As a result, the USGS and its university partners have deployed seismometers at sites of known or possible injection induced earthquakesactivities in Arkansas, Colorado, Kansas, Oklahoma, Ohio and Texas and that it is also developing methods to assess the earthquake hazard associated with wastewater injection wells.
Anyparticular.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 cause increasingincrease our compliance costs and/or impose additional operating restrictions andon 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 GHGsGHG 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.
FINANCIAL INFORMATION ABOUT GEOGRAPHIC AREAS
Historically, our revenues from our Canadian operations, and information relating to long-lived assets attributable to those operations were immaterial. We no longer have any interests there or any other international operations.Table of Contents
Item 1A. Risk Factors
FORWARD-LOOKING STATEMENTS/CAUTIONARY STATEMENT AND RISK FACTORS
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 amendedRISKS CONCERNING COMMODITY PRICES
Our business is heavily affected by commodity prices. Oil, NGLs, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, included or incorporated by reference in this document which addresses activities, events or developments which we expect or anticipate will or may occur,natural gas prices are forward-looking statements. The words “believes,” “intends,” “expects,” “anticipates,” “projects,” “estimates,” “predicts,”volatile, and similar expressions are used to identify forward-looking statements. This report modifieslow prices have hurt our financial results and supersedes documents filed by us before this report. In addition, certain information we file with the SECcould do so in the future will automatically updatefuture.
Our revenues, operating results, cash flow, and supersede information in this report.
These forward-looking statements include, among others, such things as:
the amount and nature of our future capital expenditures and how we expect to fund our capital expenditures;
growth depend on prevailing prices for oil, NGLs, and natural gas;
demand for oil,gas. 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 of the oil and natural gas industry;
our business strategy;
our plans to maintain or increase production of oil, NGLs, and natural gas;
the number of gathering systems and processing plants we plan to construct or acquire;
volumes and prices for natural gas gathered and processed;
expansion and growth of our business and operations;
demand for our drilling rigs and drilling rig rates;
our belief that the final 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 established pipeline systems;
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;
our projected production guidelines for the year;
our anticipated capital budgets;
our financial condition and liquidity;
the number of wells our oil and natural gas segment plans to drill during the year; and
our estimates of the amounts of any ceiling test write-downs or other potential asset impairments we may have to record in future periods.
These statements are based on certain assumptions and analyses made by us considering our experience and our perception of historical trends, current conditions, and expected future developments and other factors we believe are appropriate in the circumstances. Whether actual results and developments will conform to our expectations and predictions is subject to several risks and uncertainties any one or combination of which could cause our actual results to differ materially from our expectations and predictions, including:
the risk factors discussed in this document and in the documents (if any) we incorporate by reference;
general economic, market, or business conditions;
the availability of and nature of (or lack of) business opportunities we pursue;
demand for our land drilling services;
changes in laws or regulations;
changes in the current geopolitical situation;
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; and
other factors, most of which are beyond our control.
You should not place undue reliance on these forward-looking statements. Except as required by law, we disclaim any intention 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 the date of this document to reflect unanticipated events.
To help provide you with a more thorough understanding of the possible effects of these influences on any forward-looking statements made by us, this discussion outlines some (but not all) of the factors that could cause our consolidated results to differ materially from those that may be presented in any forward-looking statement made by us or on our behalf.
Demand for our contract drilling and mid-stream services depends substantially on the levels of expenditures by the oil and gas industry. A substantial or an extended decline in oil and gas prices could cause lower expenditures 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 substantially on the level of expenditures by the oil and gas industry for the exploration, development and production of oil and natural gas reserves. These expenditures depend generally 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 impact on demand for oil and natural gas. Declines, and anticipated declines, in oil and gas prices could also result in 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.
The oil and gas industry has historically experienced periodic downturns, whichmarkets have been characterized by diminished demand for oilfield servicesvolatile, and downward pressure on the prices we charge. A significant downturn in the oil and gas industry could cause a reduction in demand for oilfield services and could hurt our financial condition, results of operations and cash flows.they are likely to remain volatile.
Oil, NGLs, and Natural Gas Prices. Besides the impact oil and gas prices may have on our contract drilling and mid-stream segments, theThe prices we receive for our oil, NGLs, and natural gas production directly affect our revenues, profitability, and cash flow, and our ability to meet our projected financial and operational goals. ThePrices also tend to influence third parties use of our services. Those prices for oil, NGLs, and natural gas are determined on severaldecided 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 greatly influence the demand and prices for natural gas);
•the amount and timing of oil, liquid 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 the OPEC to set and maintainsupport production levels for oil;
•oil and gas production levels by non-OPEC countries;
the level of excess production capacity;
•political and economic uncertainty and geopolitical activity;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; and
•technological advances affecting energy consumption.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 extremely sensitive to influences 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. In addition, pricesPrices of oil, NGLs, and natural gas have been at various timescan also be influenced by trading on the commodities markets. That tradingmarkets which has increased the volatility associated with these prices, resulting incausing large differences in prices on even on a week-to-weekweekly and month-to-monthmonthly basis. These factors, especially when coupled with much of our product prices being determined daily, can, and do, lead to wide fluctuations in the prices we receive.
Based on our 2017 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 $410,000$250 per month ($4.93.0 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 haveresult in a $217,000$130 per month ($2.61.6 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 haveresult in a $380,000$220 per month ($4.62.6 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.
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 sometimes enter intomay use derivative contracts such aslike swaps and collars. To date, we have derivatives covering part, but not all of our production, which provides price protection only against declines in oil, NGLs, and natural gasmarket prices on the production subject to ourcovered 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 then expose us to the risk of financial loss and limit the benefit to us of those increases in market prices. During 2017, all of our NGLs volumes, half of our oil, and about a quarter of our natural gas volumes were sold at market responsive prices. To help manage our cash flow and capital expenditure requirements, we hadVolumes not covered by derivative contracts on approximately 50% and 72% of our 2017 average daily production for oil and natural gas, respectively. A more thorough discussion of our derivative arrangements is contained in theare subject to market prices. The Management’s Discussion and Analysis of Financial Condition and Results of Operations section of this report in Item 7.7 has a more thorough discussion of our derivative arrangements.
UncertaintyIf one or more of Oil,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 Reserves; Ceiling Test. 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 manyfactors 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 representsis only an estimate of these reserves. Oil, NGLs, and natural gas reservoir engineering is a subjective and an inexact process of estimating underground accumulations of oil, NGLs, and natural gas that cannot be measured in an exact manner.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 of 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. Accordingly, oil,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.
The information regardingabout 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 in part, 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.
In addition,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.
We review quarterly the carrying valueEstimated quantities of our oil and natural gas properties under the full cost accounting rules of the SEC. Under these rules, capitalized costs of proved oil and natural gas properties may not exceed the present value of estimated future net revenues from those proved reserves, discounted at 10%. Application of this “ceiling test” generally requires pricing future revenue at the unescalated 12-month average price and requires a write-down for accounting purposes if we exceed the ceiling. We may be required to write-down the carrying value of our oil and natural gas properties when oil, NGLs, and natural gas prices are depressed. If a write-down is required, it would cause a chargereserves and their values used to earnings but would not impactprepare 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 flow from operating activities. Once incurred, a write-downflows in this report is not reversible.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.
DebtRISKS RELATED TO FINANCING OUR BUSINESS
Our inability to satisfy our debt obligations and Bank Borrowing. covenants could result in our failure to meet our capital needs and adversely affect our operations.
We have incurred and expect to continue tomay 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 agreement. In 2011 and 2012, we issued $250.0 million (the 2011 Notes) and $400.0 million (the 2012 Notes), respectively, of senior subordinated notes (collectively, the Notes).agreements. We have, and willmay continue to have, a certain amountsome indebtedness. As of indebtedness. At December 31, 2017,2021, we had $178.0 million ofno outstanding long-term debtborrowings under ourthe Exit credit agreement and $642.3$19.2 million net of unamortized discount and debt issuance costs,borrowings outstanding under the Notes.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 agreement and those applicable to the Notesagreements 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 that are 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 additionalmore financing on acceptable terms or limit amounts available under our existing or any future credit facilities.
Our ability to meet our debt obligations depends on our future performance. If the requirements of our indebtednesssuch obligations are not satisfied, a default could be deemed to occur, and our lenders or the holders of the Notes 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.
Our existing debt and our future debt if any, is, largely,are based mainly on the costs associated withof the projects we undertake and of our cash flow. Generally, our normalexpected operating costs are those resulting from the drilling of oil and natural gas wells, the acquisition ofacquiring 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, particularlymainly the first two, are discretionary, and we maintain some control regardingon the timing or the need to incur them. But, sometimes,Sometimes, unforeseen circumstances may arise, like an unanticipated opportunityunexpected 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 additionalmore 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.
RISK FACTORSRestrictive covenants in our credit facilities may limit our financial and operating flexibility and our ability to pursue our business strategies.
ManyAs 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 factors could hurt our business. This discussion describes the material risks currently known to us. However, additional risks we do not know about or that we currently view as immaterialobligations. We may also impairseek 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 hurtresults 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 value oflenders under our securities. You should carefully consider the risks described belowcredit 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 other information containedright in that case to terminate any commitments they have to provide more borrowings. If we cannot repay our indebtedness when due or incorporated by reference into, this report.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.
If demandUnder 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 is reduced, our ability to market and produce our oil, NGLs, and natural gas may be negatively affected.gas.
Historically,Significant declines in oil, NGLs, and natural gas prices have been volatile, with significant increasesmay cause a decrease in our borrowing base. The lenders can unilaterally adjust the borrowing base, and significant price drops being experienced occasionally. Various factors beyond our control will have a significant effect on oil, NGLs, and natural gas prices. Those factors include, among other things,therefore the domestic and foreign supplyborrowings 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.
The oil, NGLs, and natural gas markets are also unsettled due to several factors. Production from oil and natural gas wells in some geographic areas of the United States has been curtailed for considerable periods of time due to a lack of market demand and transportation and storage capacity. It is possible, however, that some of our wellsamount Superior can borrow under its credit agreement may be shut-in or that oil, NGLs, and natural gas willaffected 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 sold on terms less favorable than might otherwise be obtained should demand for oil, NGLs, and natural gas decrease. Competition for markets has been vigorous and there remains great uncertainty about prices that purchasers will pay. Oil, NGLs, and natural gas surpluses could cause our inabilitylimited to market oil, NGLs, and natural gas profitably, causing us to curtail production and/or receive lower prices for our oil, NGLs, and natural gas, situations which would hurt us.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-capitalglobal capital markets can be severely contracted by market disruptions making terms for certain financingsfinancing less attractive, and in certainattractive. In some cases, result init leads to the unavailability of certain types of financing. Because of credit and equity market turmoil, we may not be able to obtain debt or equity financing or refinance existing indebtedness on favorable terms, which could affect operations and financial performance.
Oil, NGLs, and natural gas prices are volatile, and low prices have negatively affected our financial results and could do soChanges in the future.method of determining LIBOR, or the replacement of LIBOR with an alternative reference rate, may hurt our indebtedness.
Our revenues, operating results, cash flow,variable rate debt under both the Exit credit agreement and growth depend substantiallythe 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 prevailing pricescorporate governance and related matters have developed ratings processes for oil, NGLs,evaluating companies on their approach to ESG matters. Such ratings are used by some investors to evaluate their investment and natural gas. Historically, oil, NGLs,voting decisions. Unfavorable ESG ratings may lead to increased negative investor sentiment toward us and natural gas prices and markets have been volatile, and they are likely to continuethe diversion of their investment away from the fossil fuel industry to be volatile. Any decline in prices wouldother industries which could have a negative impact on our future financial resultsstock price and our abilityaccess to growand costs of capital.
Public health events outside our business segments.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.
PricesWe 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 NGLs, and natural gas, are subjecthurting crude oil prices and causing significant price volatility. As the duration and full impact from COVID-19 is difficult to wide fluctuations in responsepredict, 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 relatively minor changes in the actualcontain it or perceived supply of and demand for oil, NGLs, and natural gas, market uncertainty, and many additional factors thattreat its impact are beyond our control. These factors include:
political conditions in oil producing regions;
the ability of the members of the OPEC to agree on prices and their ability or willingness to maintain production quotas;
actions taken by foreign oil and natural gas companies;
the price of foreign oil imports;
imports and exports of oil and liquefied natural gas;
actions of governmental authorities;
the domestic and foreign supply of oil, NGLs, and natural gas;
the level of consumer demand;
United States storage levels of oil, NGLs, and natural gas;
weather conditions;
domestic and foreign government regulations;
the price, availability, and acceptance of alternative fuels;
volatility in ethane prices causing rejection of ethane as part of the liquids processed stream; and
worldwide economic conditions.
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.
Our contract drilling operations depend on levels of activity in the oil, NGLs, and natural gas exploration and production industry.
Our contract drilling operations depend on the level of activity in oil, NGLs, and natural gas exploration and production inpotential impacts, while unknown, could hurt our operating markets. Both short-term and long-term trends in oil, NGLs, and natural gas prices affect the level of that activity. Because oil, NGLs, and natural gas prices are volatile, the level of exploration and production activity can also be volatile. Any decrease from current oil, NGLs, and natural gas prices could further depress the level of exploration and production activity. This, in turn, would likely result in further declines in the demand for our drilling services and would have an adverse effect on our contract drilling revenues, cash flows, and profitability. As a result, the future demand for our drilling services is uncertain.results.
The industries in which we operate are highly competitive, and many of our competitors have resources greatermore 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 better withstand periods of low drilling rig utilization, touse better, compete more effectively based on price and technology, to build new drilling rigs, or acquire existing drilling rigs, and to provide drilling rigs more quickly than we do in periods of high drilling rig utilization.use.
The oil and natural gas industry is also highly competitive. We compete in the areas of 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. In addition, we must compete with major and independent oil and natural gas concerns in recruiting and retaining qualified employees. 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 areas of 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.
Growth through acquisitions is not assured.
We have experienced growth in each segment, in part, 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, and there can be no assurance that acquisition opportunities will be available. Even if available, there is no assurance we would have the financial ability to pursue the opportunity. And we are likely to continue to face intense competition from other companies for acquisition opportunities.
There can be no assurance we will:
be able to identify suitable acquisition opportunities;
have sufficient capital resources to complete additional acquisitions;
successfully integrate acquired operations and assets;
effectively manage the growth and increased size;
maintain the crews and market share to operate any future drilling rigs we may acquire; or
improve our financial condition, results of operations, business or prospects in any material manner because of any completed acquisition.
We may incur substantial indebtedness to finance future acquisitions and also may issue debt instruments, equity securities, or convertible securities in connection with any acquisitions. Debt service requirements could represent a significant burden on our results of operations and financial condition and issuing additional equity would be dilutive to existing shareholders. Also, continued growth could strain our management, operations, employees, and other resources.
Successful acquisitions, particularly those of oil and natural gas companies or of oil and natural gas properties, require an assessment of 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 operations have significant capital requirements, and our indebtedness could have important consequences.
We have experienced and will continue to experience substantial capital needs for our operations. We have $642.3 million of indebtedness outstanding (net of unamortized discount and debt issuance costs) under the senior subordinated notes we have issued to date and, in addition, may borrow up to $475.0 million under our credit agreement. As of February 13, 2018, we had $173.8 million outstanding borrowings under our credit agreement. Our level of indebtedness, the cash flow to satisfy our indebtedness, and the covenants governing our indebtedness could:
limit funds available for financing 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 some of our competitors that are less leveraged than we are;
make us more vulnerable during periods of low oil, NGLs, and natural gas prices or if downturn in our business occurs; and
prevent us from obtaining additional financing on acceptable terms or limit amounts available under our existing or any future credit facilities.
Our ability to meet our debt service and other contractual and contingent obligations will depend on our future performance. In addition, lower oil, NGLs, and natural gas prices could cause future reductions in the amount available for borrowing under our credit agreement, reducing our liquidity, and even triggering mandatory loan repayments.
The instruments governing our indebtedness contain various covenants limiting the conduct of our business.
The indentures governing our senior subordinated notes and our credit agreement contain various restrictive covenants that limit the conduct of our business. These agreements place certain limits on our ability to, among other things:
incur additional indebtedness, guarantee obligations or issue disqualified capital stock;
pay dividends or distributions on our capital stock or redeem, repurchase or retire our capital stock;
make investments or other restricted payments;
grant liens on assets;
enter into transactions with stockholders or affiliates;
sell assets;
issue or sell capital stock of certain subsidiaries; and
merge or consolidate.
In addition, our credit agreement also requires us to maintain a minimum current ratio and a maximum senior indebtedness or leverage ratio.
If we violate the restrictions in the indentures governing our senior subordinated notes, our credit agreement or any other subsequent financing agreements, a default may allow the creditors, if the agreements so provide, to accelerate the related indebtedness and any other indebtedness to which a cross-acceleration or cross-default provision applies. If that occurs, we may not make the required payments or borrow sufficient funds to refinance that debt. Even if new financing were available at that time, it may not be on terms acceptable to us. In addition, lenders may be able to terminate any commitments they had made to make available further funds.
Our future performance depends on our ability to find or acquire additional oil, NGLs, and natural gas reserves that are economically recoverable.
Production from oil and natural gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Unless we replace the reserves we produce, our reserves will decline, resulting eventually in a decrease in oil, NGLs, and natural gas production and lower revenues and cash flow from operations. Historically, we have increased reserves after taking production into account through exploration and development. We have conducted these activities on our existing oil and natural gas properties and on newly acquired properties. We may not continue to replace reserves from these activities at acceptable costs. Lower prices of 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.
We are continually identifying and evaluating opportunities to acquire oil and natural gas properties, including acquisitions significantly larger than those consummated by us. We cannot assure you we will successfully consummate any acquisition, that we can acquire producing oil and natural gas properties that contain economically recoverable reserves or that any acquisition will be profitably integrated into our operations.
The competition for producing oil and natural gas properties is intense. This competition could mean that to acquire properties we must pay higher prices and accept greater ownership risks than we have in the past.
Our exploration and production and mid-stream operations involve high business and financial risk which could hurt us.
Exploration and development involve numerous 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. Numerous factors beyond our control may cause the curtailment, delay, or cancellation of drilling operations, including:
unexpected drilling conditions;
pressure or irregularities in formations;
capacity of pipeline systems;
equipment failures or accidents;
adverse weather conditions;
compliance with governmental requirements; and
shortages or delays in the availability of drilling rigs, pressure pumping services, or delivery crews and the delivery of equipment.
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 time frame, or at all. Lack of drilling success will have an adverse effect on our future results of operations and financial condition.
Our mid-stream operations involve numerous 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;
availability of competing pipelines in the area;
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.
Many of the wells from which we gather and process natural gas are operated by other parties. We have little control over the operations of those wells which can act to increase our risk. Operators of those wells may act in ways not in our best interests.
Competition for experienced technical personnel may negatively affecthurt our operations or financial results.
TheOur three segments’ success of our three segments 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 professionals.employees. Competition for these professionalsemployees can be intense, particularly when the industry is experiencing favorable conditions.
Our derivative arrangements might limit the benefit of increases in oil, NGLs, and natural gas prices.
To reduce our exposure to short-term fluctuations in the price of oil, NGLs, and natural gas, we sometimes enter into derivative contracts. These derivative contracts apply to only a portion of our production and provide only partial price protection against declines in oil, NGLs, and natural gas prices. These derivative contracts may expose us to risk of financial loss and limit the benefit to us of increases in prices.
Estimates of our reserves are uncertain and may prove inaccurate.
Numerous uncertainties are inherent in estimating quantities of proved reserves and their values, including many factors beyond our control. The reserve data represents only estimates. Reservoir engineering is a subjective and inexact process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. 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:
the effects of regulations by governmental agencies;
future oil, NGLs, and natural gas prices;
future operating costs;
severance and excise taxes;
development costs; and
workover and remedial costs.
Some or all of these assumptions may vary considerably from actual results. Estimates of the economically recoverable quantities of oil, NGLs, and natural gas attributable to any group of properties, classifications of those reserves based on risk of recovery, and estimates of the future net cash flows from reserves prepared by different engineers or by the same engineers but at different times may vary substantially. Accordingly, reserve estimates may be subject to downward or upward adjustment. Actual production, revenues and expenditures regarding our reserves will likely vary from estimates, and those variances may be material.
The information regarding discounted future net cash flows should not be considered as the current market value of the estimated oil, NGLs, and natural gas reserves attributable to our properties. As required by the SEC, the estimated discounted future net cash flows from proved reserves are based on prices on the first day of the month for each month within the 12-month period before the end of the reporting period and costs as of the date of the estimate, while actual future prices and costs may be materially higher or lower. Actual future net cash flows also will be affected by these factors:
the amount and timing of actual production;
supply and demand for oil, NGLs, and natural gas;
increases or decreases in consumption; and
changes in governmental regulations or taxation.
In addition, the 10% per year discount factor, which is required by the SEC to be used in 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 risks associated with our operations or the oil and natural gas industry.
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.
We review quarterly the carrying value of our oil and natural gas properties under the full cost accounting rules of the SEC. 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 month for each month within the 12-month period before the end of the reporting period, unless prices were defined by contractual arrangements, and requires a write-down for accounting purposes if the ceiling is exceeded. We may be required to write-down the carrying value of our oil and natural gas properties when oil, NGLs, and natural gas prices are depressed. If a write-down is required, it would cause a charge to earnings, but would not impact cash flow from operating activities. Once incurred, a write-down of oil and natural gas properties is not reversible later. 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 additional write downs in one or more succeeding periods. This would be the case when months with higher commodity prices roll off the 12-month period 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 are required to periodically test to see if these values, including associated goodwill and other intangible assets, have been impaired whenever events or changes in circumstances suggest the carrying amount may not be recoverable. If any of 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 property, equipment, and related intangible assets. Once these values have been reduced, they are not reversible.
Our operations presentare subject to inherent risks of loss that, if not insured or indemnified against,material, could hurtharm our results of operations.
Our contract drilling operations are subject to many hazards, inherent in the drilling industry, 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 the property of others.others’ property. Generally, drilling contracts provide for the division of responsibilities between a drilling company and its customer, and wecustomer. We seek to obtain contractual indemnification from our drilling customers by contract for some of these risks. If we cannot transfer these risks to drilling customers by contract or indemnification agreements (or to the extentif 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. However,Still, some risks are not covered by insurance and weinsurance. 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 thea customer’s failure of a customer to meet its indemnification obligations, could cause substantial losses. In addition, weWe 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 of the wells in which we own an interest. Our operatingoperational risks for those wells and our ability to influence thethose wells’ operations for those wells are less subject to our control. Operatorscontrol and the operators of those wells may act in ways not in our best interests.
Governmental and environmental regulations could hurt our business.
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 requiresegment’s prospective drilling permits and govern the spacing of wells, rates of production, 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. In addition, these laws and regulations, and any others thatlocations are passed by the jurisdictions where we have production, could limit the number of wells drilled or the allowable production from successful wells, which could limit our revenues.
We are (or could become) subject to complex environmental laws and regulations adopted by the jurisdictions where we own 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:
various evaluation stages, ranging from a well or drilling equipment atprospect ready to drill to 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 frequently change, we cannot assure you that future laws and regulations, including changes to existing laws and regulations, will not hurt our business. The Congress and White House administration may impose or change laws and regulationsprospect that will hurt our business. Stricter standards, greater regulation,require additional geological and more extensive permit requirements, could increase our future risks and costs related to environmental matters. In addition, 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.
Any future implementation of price controlsengineering analysis. Based on oil, NGLs, and natural gas would affect our operations.
Certain groups have asserted efforts to have the United States Congress impose price controls on either oil, natural gas, or both. There is no way at this time to know what result these efforts will have nor, if implemented, their effect on our operations. However, it is possible that these efforts, if successful, would limit the amount we might get for ourmany factors, including future oil, NGLs, and natural gas production. Any future limits onprices, the pricegeneration of oil, NGLs,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 could also cause hurtingreserves from the wells connected to the gathering systems;
•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 our drilling services.natural gas and its constituents.
Provisions of Delaware law and our by-laws and charter could discourage change in control transactions and prevent shareholders from receiving a premium on their investment.
Our by-laws and charter provide for a classified board of directors with staggered terms and authorizes the board of directors to set the terms of preferred stock. In addition, our charter and Delaware law contain provisions that impose restrictions on business combinations with interested parties. Because of our by-laws, charter, and Delaware law, persons considering unsolicited tender offers or other unilateral takeover proposals may be more likely to negotiate with our board of directors rather than pursue non-negotiated takeover attempts. These provisions may make it more difficult for our shareholders to benefit from transactions opposed by an incumbent board of directors.
New technologies may cause our exploration and drilling methods to become obsolete, resulting incausing an adverse effect on our production.
Our industry is subject to rapid and significant technological advancements, in technology, including the introduction of new products and services using new technologies. As competitors use or develop new technologies, we may be placed 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 certainsure that we can implement technologies timely or at a costan acceptable to us.cost. One or more technologies that we use or that we may implement may become obsolete or may not work as we expected, and we may be hurt.hurt financially and operationally as a result.
We may be affected by climate change and market or regulatory responses to climate change.
Climate change, including the impact of potential global warming regulations, could have a material adverse effect on ourOur operating results of operations, financial condition, and liquidity. Restrictions, caps, taxes, or other controls on emissions of greenhouse gasses, including diesel exhaust, could significantly increase our operating costs. Restrictions on emissions could also affect our customers that (a) use commodities we carry to produce energy, (b) use significant energy in producing or delivering the commodities we carry, or (c) manufacture or produce goods that consume significant energy or burn fossil fuels, including chemical producers, farmers and food producers, and automakers and other manufacturers. Significant cost increases, government regulation, or changes of consumer preferences for goods or services relating to alternative sources of energy or emissions reductions could materially affect the markets for the commodities associated with our business, which could have a material adverse effect on our results of operations, financial condition, and liquidity. Government incentives encouraging the use of alternative sources of energy could also affect certain of our customers and the markets for certain of the commodities associated with our business in an unpredictable manner that could alter our business activities. Finally, we could face increased costs related to defending and resolving legal claims and other litigation related to climate change and the alleged impact of our operations on climate change. These factors, individually or in operation with one or more of the other factors, or other unforeseen impacts of climate change could reduce the business activity we conduct and have a material adverse effect on our results of operations, financial condition, and liquidity.
The results of our operations 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 2017, sales to Sunoco Logisticsthe year ended December 31, 2021, one customer accounted for 10%11% of our oil and natural gas revenues. QEP Resources, Inc. was our largest drilling customer accountingrevenue, five customers accounted for approximately 26%79% of our total contract drilling revenues. And for our mid-stream segment, ONEOK, Inc.revenues, and three customers accounted for approximately 36%58% of our Mid-Stream revenues. No other third partythird-party customer accounted for 10% or more of any of our individual segment revenues. Any of our customerscustomer 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.
Shortage of completion equipment and services could delay or otherwise hurt our oil and natural gas segment's operations.
As there is an increase in horizontal drilling activity in certain areas, shortages could cause the availability of third party equipment and services required for completing wells drilled by our oil and natural gas segment. We could experience delays in completing some of our wells. Although we can try to reduce the delays associated with these services, we anticipate these services will be in high demand for the immediate future and could delay, restrict, or curtail part of our exploration and development operations, which could in turn harm our results.
Our mid-stream segmentSuperior 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.
The counterparties to our commodity derivative contracts may not perform their obligations to us, which could materially affect our cash flowsWe rely on management and results of operations.other key employees.
To reduce our exposure to adverse fluctuations in the prices of oil and natural gas, we currently, and may in the future, enter into commodity derivative contracts for a significant portion of our forecasted oil, NGLs, and natural gas production. The extent of our commodity price exposure is related largely to the effectiveness and scope of our derivative activities, and to the ability of counterparties under our commodity derivative contracts to satisfy their obligations to us. If one or more of our counterparties is unable or unwilling to pay us under our commodity derivative contracts, it could have a material adverse effect on our financial condition and results of operations.
Reliance on management.
We depend greatlysignificantly 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.
We are subject to various claims and litigation that could ultimately be resolved against us, requiring material future cash payments and/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. AnyEven if indemnified or insured, any claims or litigation even if fully indemnified or insured, could negatively affecthurt our reputation among our customers and the public and make it more difficultharder for us to compete effectively or obtain adequate insurance in the future.
DerivativeDemand 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 currentthe 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 reformrisks 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.
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 impederesult 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 managecarry 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.
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 restricting oursigning 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 derivative instrumentsour 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 hedges against fluctuating commodity priceswell as changes to those currently in effect, could adversely impact our earnings, cash flows, and interest rates.operations.
In July 2010,Our business is subject to federal, state, and local laws and regulations on taxation, the Dodd-Frank Wall Street Reformexploration for and Consumer Protection Act (the Act) wasdevelopment, 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 signed into law. TheWhite 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 contains significant derivative regulations, requiring that certain transactions be cleared on exchangesof 1968, as amended, Hazardous Liquid Pipeline Safety Act of 1979, as amended, the Pipeline Safety Act of 1992, as reauthorized and a requirement to post cash collateral (commonly called margin) for such transactions. The Act provides for a potential exception from these clearing and cash collateral requirements for commercial end-users and it includes several defined terms used in determining how this exception applies to particular derivative transactionsamended, and the partiesPipeline 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 those transactions.
We useexpand its jurisdiction over crude oil and natural gas derivative instrumentspipelines, including gathering lines.
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 a portion ofdamage 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 expected production, to reduce commodity price uncertainty and enhance the predictability of cash flows relating the marketing our crude oil and natural gas. As commodity prices increase our derivative liability positions increase; however, nonecost and damage infrastructure.
On August 3, 2020, the United States Senate reauthorized the Protecting our Infrastructure of our current derivative contracts require posting marginPipelines 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 similar cash collateral when there are changes in the underlying commodity prices referred to in these contracts.
Depending on the rules and definitions adopted by the CFTC, weregulations that apply more comprehensive or stringent safety standards could have to post collateral with our dealer counterparties for our commodities derivative transactions. Such a requirement could have a significant impact on our business by reducing our ability to execute derivative transactions to reduce commodity price uncertainty and to protect cash flows. Requirements to post collateral would cause significant liquidity issues by reducing our ability to use cash for investment or other corporate purposes, or would require us to increase our levelinstall new or modified safety controls, pursue new capital projects, or conduct maintenance programs on an accelerated basis, all of debt.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 requirementmaximum of $2,225,034 for our counterparties to post collateral would likely cause additional costs being passed on to us, thereby decreasing the effectivenessa related series of our derivative contracts and our profitability.violations.
Proposed federal and state legislative and regulatory initiatives relating to hydraulic fracturing could cause increased costs and additional operating restrictions or delays.
Hydraulic-fracturingHydraulic 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 applyapplies 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, and the Mississippian of Kansas.Texas. Hydraulic-fracturing involves using water, sand, and certain chemicals to fracture the hydrocarbon-bearing rock formation to allow thehydrocarbons’ flow of hydrocarbons into the wellbore. The process is typically regulated by stateState oil and natural gas commissions; however,commissions process typically regulate this process, but the EPA has asserted federal regulatory authority over certain hydraulic-fracturinghydraulic fracturing activities involving diesel under the Safe Drinking Water Act and published permitting guidance addressing the performance of such activities using diesel.activities. The EPA ishas also seeking to require companies to disclose information regardingfinalized rules under the chemicals usedClean Water Act in June 2016 that prohibit the discharge of wastewater from hydraulic fracturing andoperations to publicly owned wastewater treatment plants. Separately, in December 2016, the bureauEPA released its final report on the potential impacts of Land Management has imposed requirements for hydraulic fracturing on drinking water resources. The final report concluded that certain activities of federal lands. In addition, Congress has occasionally considered legislation to provide for federal regulation of hydraulic-fracturing and to require disclosure of the chemicals used in the hydraulic-fracturing process.associated with hydraulic fracturing may impact drinking water resources under certain limited circumstances.
CertainSome states in whichwhere 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. For example, Texas adopted a law in June 2011 requiring disclosureLocal governments may also seek to the Railroad Commission of Texas (RCT) and the public of certain information regarding the components used in the hydraulic-fracturing process. Besides state laws, local land use restrictions, such as city ordinances, may restrict or prohibit the performance of well drilling and/well-drilling, hydraulic fracturing, or hydraulic fracturing.both. If state, local, or municipal legal restrictions are adopted in areas where we are conducting or plan to conduct operations, we may incur additionaladded 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/orand completion of wells.
There are certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic-fracturing practices. The White House Council on Environmental Quality is coordinating a review of hydraulic-fracturing practices, and a committee of the United States House of Representatives investigated hydraulic-fracturing practices. Furthermore, several federal agencies are analyzing, or have been requested to review, many environmental issues associated with hydraulic fracturing. The EPA is evaluating the potential environmental effects of hydraulic fracturing on drinking water and groundwater. In addition, the U.S. Department of Energy has investigated practices the agency could recommend to better protect the environment from drilling using hydraulic-fracturing completion methods.
And certain members of the Congress have called on the U.S. Government Accountability Office to investigate how hydraulic fracturing might hurt water resources, the U.S. Securities and Exchange Commission to investigate the natural gas industry and any possible misleading of investors or the public regarding the economic feasibility of pursuing natural gas deposits in shales by means of hydraulic fracturing, and the U.S. Energy Information Administration to provide a better understanding of that agency’s estimates regarding natural gas reserves, including reserves from shale formations, and uncertainties associated with those estimates. These ongoing or proposed studies, depending on their course and results obtained, could spur initiatives to further regulate hydraulic fracturing under the Safe Drinking Water Act or other regulatory processes.
Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition, including litigation, to oil and gas production activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to operational delays or increased operating costs in the production of oil, natural gas, and associated liquids including from developing shale plays, or could make it more difficult to perform hydraulic fracturing. The adoption of additional federal, state or local laws or implementing regulations regarding hydraulic fracturing could cause a decrease in completing of new oil and gas wells, increased compliance costs and time, which could hurt our financial position, results of operations, and cash flows.
Our ability to produce crude oil, natural gas, and associated liquids economically and in commercial quantities could be impaired if we cannot acquireget adequate supplies of water for our drilling and completion operations and/or completions 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 providesupply coverage for losses solely related to
hydraulic fracturing operations; however,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.
Uncertainty regardingabout increased seismic activity in Oklahoma could have adverse effect on our business and Kansas.results of operations.
We conduct oil and natural gas exploration, development, and drilling activities in Oklahoma Kansas, and elsewhere.nearby. In recent years, Oklahoma, Texas, and Kansas hashave experienced a significant increasean upturn in earthquakes and other seismic activity. Some parties believe there is a correlation between certain oil and gas activities and theearthquakes’ increased occurrence of earthquakes.occurrence. The extent of this correlation is the subject of studies by both state and federal agencies, the results of which remain uncertain.unclear. We cannot state at this timesay what if any 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 quantities of water.water quantities.
Our inability to secure sufficient amounts ofenough water or to dispose of or recycle the water used in our oil and natural gas segment operations could adversely affecthurt our operations. The imposition ofImposing 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 have an adverse effect onhurt our operations and financial condition.
We may decide not to drill some prospects we have identified, and locations we drill may not yield oil, NGLs, and natural gas in commercially viable quantities.
Our oil and natural gas segment's prospective drilling locations are in various stages of evaluation, 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. As a result, we may not increase or maintain our reserves or production, which in turn could have an adverse effect on our business, financial position, and results of operations. In addition, the SEC's reserve reporting rules require that, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of booking. At December 31, 2017, we had 99 proved undeveloped drilling locations. If we do not drill these locations within five years of initial booking, they may not continue to qualify for classification as proved reserves, and we may have to reclassify such reserves as unproved reserves. The reclassification of those reserves could also have a negative effect on the borrowing base under our credit facility.
The cost of drilling, completing, and operating a well is often uncertain, and cost factors can hurt the economics of a well. Our efforts will be uneconomic if we drill dry holes or wells that are productive but do not produce enough oil, NGLs, and natural gas to be commercially viable after drilling, operating, and other costs.
The borrowing base under our credit agreement is determined semi-annually at the discretion of the lenders and is based in a large part 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 our credit agreement. If outstanding borrowings are over the borrowing base, we must (a) repay the amount in excess of the borrowing base, (b) dedicate additional properties to the borrowing base, or (c) begin monthly principal payments under our credit agreement.
Potentialpotential 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 that of our customers, which could hurt our operations and financial results.
The federal Endangered Species Act, referred to as the “ESA,”ESA and analogoussimilar state laws regulate a variety ofvarious activities, including oil and gas development, which could have an adverse effect onharm species listed as threatened or endangered under the
ESA or their habitats. The designation ofDesignating previously unidentified endangered or threatened species could cause oil and natural gas exploration and production operators and service companies to incur additionaladded costs or become subject to operating delays, restrictions, or bans in affected areas, which impacts could adversely reduce the amount of 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. NumerousMany species have been listed or proposedare under consideration for protected status in areas in which we provideoperate or could inundertake operations, such as the future undertake operations. The U.S. Fishdunes sagebrush lizard, lesser prairie chicken, and Wildlife Service and the National Marine Fisheries in 2016 issued final revised definitions relating to impacts on critical habitats for potentially endangered species allowing exclusion of certain areas so long as they will not result in the extinction of the species. In 2017, the Western Governor’s Association issued a Policy Resolution calling on Congress to amend and reauthorize the ESA based upon seven broad goals to make the act more workable and understandable. In December 2017, the Interior Department announced that it is working on possible changes to the ESA with the U.S. Fish and Wildlife Service to revise the regulations for listing endangered and threatened species and for designation of critical habitat. 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, adversely affect our results of operations and financial position.greater sage grouse.
Constructing our new proprietary BOSS drilling rigs is subject to risks, including delays and cost overruns, and may not meet our expectations.
We have designed and built several new proprietary 1,500 horsepower AC electric drilling rigs, which we call BOSS drilling rigs. This new design should position us to better meet the demands of our customers. Constructing any future new BOSS drilling rigs is subject to the risks of delays or cost overruns inherent in any large construction project because of numerous possible factors, including:
shortages of equipment, materials or skilled labor;
work stoppages and labor disputes;
unscheduled delays in the delivery of ordered materials and equipment;
unanticipated increases in the cost of equipment, labor and raw materials used in construction of our drilling rigs, particularly steel;
weather interferences;
difficulties in obtaining necessary permits or in meeting permit conditions;
unforeseen design and engineering problems;
failure or delay in obtaining acceptance of the drilling rig from our customer;
failure or delay of third party equipment vendors or service providers; and
lack of demand from the downturn in the oil and gas industry.
On our new BOSS drilling rigs, there can be no assurance we will:
obtain additional new-build contract opportunities; or
improve our financial condition, results of operations or prospects because of the new drilling rigs.
While we hold certain patents regarding our BOSS drilling rig design, it is still possible that third parties may claim we infringe their intellectual property rights. We may receive notices from others claiming 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. Besides money damages, in some jurisdictions plaintiffs can seek injunctive relief that may limit or prevent marketing and use of our drilling rigs that have infringing technologies.
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 significantly affect the energy industry and economic conditions, including our operations and our customers, as well as 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 targets in the United States.States targets. A
cyber incident could result incause information theft, data corruption, operational disruption, and/orand financial loss. Our insurance may not protect us against such occurrences. Consequently, itIt 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.
The oil and natural gas industry has becomeWe are increasingly dependent uponon 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, are also dependentdepend 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 for purposes of misappropriatingto misappropriate assets or sensitive information, corrupting data, or causing operational disruption, or result in denial-of-service on websites.
Our technologies, systems, networks, and those of our business partners may become the target of cyber-attacks or information security breaches that could result incause the unauthorized release, gathering, monitoring, misuse, loss, or destruction of proprietary and other information, or other disruption of our business operations. In addition, certainSome cyber incidents, such aslike surveillance, may remain undetected for an extended period.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 in completing and settling transactions, challenges in maintaining our books and records, environmental damage, communication interruptions, other operational disruptions, and third-party liability, including the following:including:
•a cyber-attack on a vendor or service provider could result incause supply chain disruptions, which could delay or halt the development of additionalmore infrastructure, effectively delaying the start of cash flows from the project;
•a cyber-attack on our facilities may result incause equipment damage or failure;
•a cyber-attack on mid-stream or downstream pipelines could prevent our productproducts from being delivered, resulting in a loss ofleading 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 result incause events of non-compliance which could leadleading to regulatory fines or penalties; and
•business interruptions could result incause expensive remediation efforts, the distraction of management, or damage to our reputation, or a negative impact on the price of our units.reputation.
Implementation of various controls and processes to monitor and mitigate security threats and to increase security for our information, facilities and infrastructure isare costly and labor intensive. Moreover, therelabor-intensive. There can be no assurance that such measures will be sufficient to prevent security breaches from occurring. As cyber threats continue to evolve, we may be requiredhave to expendspend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any information security vulnerabilities. We are not aware that any such breaches have occurred.
We areIneffective internal controls could affect the subjectaccuracy and timely reporting of putative class action lawsuits that may result in substantial expenditures and divert management's attention.
We are the subject of putative class action lawsuits in Oklahoma with respect to the alleged failure to pay interest with on untimely royalty payments and with respect to the alleged underpayment of royalties. These lawsuits seek various remedies, including damages, injunctive relief, and attorney’s fees. For additional information on these lawsuits, see Item 3 Legal Proceedings in this Annual Report on Form 10-K.
Although we believe that the allegations in these lawsuits are without merit and intend to defend such litigation vigorously, litigation is subject to inherent uncertainties, and an adverse result in one of these lawsuits or other matters that may arise from time to time could have a material adverse effect on our business, results of operations and financial condition.
Defending the lawsuits may be costly and, further, could require significant involvement of our senior management and may divert management's attention from our business and operations.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.
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.
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
Panola Independent School District No. 4, et al. v. Unit Petroleum Company, No. CJ-07-215, District Court
For more information regarding legal proceedings, see Note 21 - Commitments And Contingencies of Latimer County, Oklahoma.our Notes to Consolidated Financial Statements in Item 8 of this report.
Panola Independent School District No. 4, Michael Kilpatrick, Gwen Grego, Carla Lessel, Thelma Christine Pate, Juanita Golightly, Melody Culberson, and Charlotte Abernathy are the Plaintiffs and are royalty owners in oil and gas drilling and spacing units for which the company’s exploration segment distributes royalty. The Plaintiffs’ central allegation is that the company’s exploration segment has underpaid royalty obligations by deducting post-production costs or marketing related fees. Plaintiffs sought to pursue the case as a class action on behalf of persons who receive royalty from us for our Oklahoma production. We have asserted several defenses including that the deductions are permitted under Oklahoma law. We have also asserted that the case should not be tried as a class action due to the materially different circumstances that determine what, if any, deductions are taken for each lease. On December 16, 2009, the trial court entered its order certifying the class. On May 11, 2012 the court of civil appeals reversed the trial court’s order certifying the class. The Plaintiffs petitioned the Supreme Court for certiorari and on October 8, 2012, the Plaintiff’s petition was denied. On January 22, 2013, the Plaintiffs filed a second request to certify a class of royalty owners slightly smaller than their first attempt. Since then, the Plaintiffs have further amended their proposed class to just include royalty owners entitled to royalties under certain leases in Latimer, Le Flore, and Pittsburg Counties, Oklahoma. In July 2014, a second class certification hearing was held where, besides the defenses described above, we argued that the amended class definition is still deficient under the court of civil appeals opinion reversing the initial class certification. Closing arguments were held on December 2, 2014. There is no timetable for when the court will issue its ruling. The merits of Plaintiffs’ claims will remain stayed while class certification issues are pending.
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 Unit Petroleum Company 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 Unit Petroleum wrongfully failed to pay interest with respect to untimely royalty payments under Oklahoma’s Production Revenue Standards Act. The lawsuit seeks actual and punitive damages, an accounting, disgorgement, injunctive relief, and attorney’s fees. Plaintiff is seeking relief on behalf of royalty owners in our Oklahoma wells. We have asserted several defenses including that the case cannot be properly certified as a class action because of the wide variety of circumstances that determine whether a royalty payment was timely made or has accrued interest under Oklahoma law. At this point, the court has not taken any action on the issue of class certification.
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 Unit Petroleum Company styled Chieftain Royalty Company v. Unit Petroleum Company in LeFlore County, Oklahoma. Plaintiff alleges that Unit Petroleum 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. We filed a motion to dismiss on the basis that the claims asserted by the Plaintiff and the putative class are barred because they have already been asserted by the putative class in the Panola lawsuit and are subject to its reversal of class certification. The court denied our motion to dismiss and we have asked the court to certify its order so that it can be immediately appealed. That issue is still pending before the court. If we do not ultimately prevail on our claim of issue preclusion, we have several other defenses, including that the case cannot be properly certified as a class action because of the wide variety of circumstances that determine whether a royalty payment was wrongfully withheld. At this point, the issue of class certification has not been set before the court.
We continue to vigorously defend against each of the pending claims. At this time we are unable to express an opinion with respect to the likelihood of an unfavorable outcome or provide an estimate of potential losses, if any.
Item 4. Mine Safety Disclosures
Not applicable.
PART II
Item 5. Market for the Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities
Our common stock tradesNew 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 New York Stock ExchangeOTC Pink Marketplace under the symbol “UNT.” This table identifies the high"UNTC". See “Risk Factors — Our New Common Stock may have a limited market and low closing sales prices per sharelack liquidity” under Item 1A of this report.
Since all of our common stock for the periods indicated:
|
| | | | | | | | | | | | | | | |
| | 2017 | | 2016 |
| Quarter | High | | Low | | High | | Low |
| First | $ | 30.25 |
| | $ | 20.73 |
| | $ | 12.51 |
| | $ | 4.41 |
|
| Second | $ | 24.26 |
| | $ | 16.47 |
| | $ | 17.81 |
| | $ | 8.44 |
|
| Third | $ | 21.55 |
| | $ | 15.42 |
| | $ | 18.82 |
| | $ | 11.29 |
|
| Fourth | $ | 22.83 |
| | $ | 17.20 |
| | $ | 28.11 |
| | $ | 16.44 |
|
On February 13, 2018, the closing sale pricestockholders maintain their shares in “street name” accounts and are not, individually, stockholders of our common stock,record, as reported by the NYSE,of March 31, 2022, there was $20.16 per share. On that date, there were approximately 793 holdersone 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. OurUnder certain circumstances, none of which applied as of December 31, 2021, our bank credit agreement and the Notes prohibitagreements may restrict the payment of cash dividends on our common stock under certain circumstances.stock. For further information regarding how our bank credit agreement and the Notes agreement’sagreements may impact on our ability to pay dividends, see “Our Credit Agreement and Senior Subordinated Notes”“Credit Agreements” under Item 7 of this report.
Share Repurchases
Performance Graph. The following graph and related information shall not be deemed “soliciting material” or be deemed to be “filed” with the SEC, nor will this information be incorporated by reference into any future filing, except to the extent that
In June 2021, we specifically incorporate it by reference into that filing.
Set forth below is a line graph comparing our cumulative total shareholder return onrepurchased an aggregate of 600,000 shares of our common stock withfrom the cumulativeLenders (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 returnof 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 S&P 500 Stock Index, S&P 600 Oil and Gas Exploration & Production and our peer group which includes Helmerich & Payne, Inc., Patterson – UTI Energy Inc., and Pioneer Energy Services Corp. repurchase program.
The graphcumulative number of shares repurchased as of December 31, 2021 totaled 1,949,963, resulting in outstanding shares of 10,050,037.
The table below assumes an investment of $100 atrepresents all share repurchases for the beginning of the period. The shareholder return set forth below is not necessarily indicative of future performance.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. Selected Financial Data[Reserved]
The following table shows selected consolidated financial data. The data should be read in conjunction with Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” for a review of 2017, 2016, and 2015 activity.
|
| | | | | | | | | | | | | | | | | | | | |
| | As of and for the Year Ended December 31, | |
| | 2017 | | 2016 | | 2015 | | 2014 | | 2013 | |
| | (In thousands except per share amounts) | |
| Revenues | $ | 739,640 |
| | $ | 602,177 |
| | $ | 854,231 |
| | $ | 1,572,944 |
| | $ | 1,351,850 |
| |
| Net income (loss) | $ | 117,848 |
| | $ | (135,624 | ) | (3) | $ | (1,037,361 | ) | (2) | $ | 136,276 |
| (1) | $ | 184,746 |
| |
| Net income (loss) per common share: | | | | | | | | | | |
| Basic | $ | 2.31 |
| | $ | (2.71 | ) | | $ | (21.12 | ) | | $ | 2.80 |
| | $ | 3.83 |
| |
| Diluted | $ | 2.28 |
| | $ | (2.71 | ) | | $ | (21.12 | ) | | $ | 2.78 |
| | $ | 3.80 |
| |
| Total assets | $ | 2,581,452 |
| | $ | 2,479,303 |
| (3) | $ | 2,799,842 |
| (2) | $ | 4,463,473 |
| (1) | $ | 4,010,546 |
| |
Long-term debt (4) | $ | 820,276 |
| | $ | 800,917 |
| | $ | 918,995 |
| | $ | 801,908 |
| | $ | 633,852 |
| |
Other long-term liabilities (5) | $ | 100,203 |
| | $ | 103,479 |
| | $ | 140,626 |
| | $ | 148,785 |
| | $ | 158,331 |
| |
| Cash dividends per common share | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| |
| |
(1) | In December 2014, we incurred a non-cash ceiling test write-down of our oil and natural gas properties of $76.7 million pre-tax ($47.7 million, net of tax), a non-cash write-down associated with the removal of 31 drilling rigs from our fleet along with certain other equipment and drill pipe of pre-tax $74.3 million pre-tax ($46.3 million, net of tax), and a non-cash write-down associated with a reduction in the carrying value of three mid-stream segment systems of $7.1 million pre-tax ($4.4 million, net of tax). |
| |
(2) | In total for 2015, we incurred non-cash ceiling test write-downs on our oil and natural gas properties of $1.6 billion pre-tax ($1.0 billion, net of tax). We also incurred a non-cash write-down on certain drilling rigs and other equipment of approximately $8.3 million pre-tax ($5.1 million, net of tax), and a non-cash write-down associated with a reduction in the carrying value of three mid-stream segment systems of $27.0 million pre-tax ($16.8 million, net of tax). |
| |
(3) | For the first three quarters of 2016, we incurred non-cash ceiling test write-downs on our oil and natural gas properties of $161.6 million pre-tax ($100.6 million, net of tax). |
| |
(4) | Long-term debt is net of unamortized discount and debt issuance costs. |
| |
(5) | Includes non-current derivative liabilities, if any. |
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.
GeneralIntroduction
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.
Business Outlook
As discussed in other parts We own 50% of this report,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, to a large degree,among other things, on the prices we receive for our oil and natural gas production, the demand for oil, natural gas, and NGLs, and the demand for our drilling rigs which influences the amounts we can charge for those drilling rigs. While our operations are all within the United States, events outside the United States affect us and our industry.industry, including political and economic uncertainty and geopolitical activity.
DeterioratingWe 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.
During the last two years commodity prices worldwide duringhave been volatile, and the past several years brought aboutoutlook for future oil and gas prices remains uncertain and subject to many factors. The following chart reflects the significant and adverse changes to our industry and us. As a result we reduced or stopped,fluctuations in the historical prices for a time, our oil and natural gas segment's drilling activity. Industry wide reductionsgas:
The following chart reflects the significant fluctuations in drilling activitythe prices for NGLs(1):
_________________________
1.NGLs prices reflect a weighted-average, based on production, of Mont Belvieu and spendingConway prices.
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 extended periodstheir 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 reducesrepurchased 78,000 shares in a privately negotiated transaction at a share price of $19.07 which were not part of the rates for and therepurchase program.
The cumulative number of our drilling rigs we can work. In addition, sustained lower commodity prices impact the liquidity condition of some of our industry partners and customers, which could limit their ability to meet their financial obligations to us.
During 2016, commodity prices improved. In the fourth quarter of 2016, our oil and natural gas segment began using two of our drilling rigs and has been using two to three drilling rigs throughout 2017. Our contract drilling segment completed the construction and contracted the ninth and tenth BOSS drilling rigs in the fourth quarter of 2016 and the second quarter of 2017, respectively. Our drilling rig segment's rig utilization increased from 16 drilling rigs working as of June 30, 2016, to 31 drilling rigs workingshares repurchased as of December 31, 2017.2021 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 extentexercise price of the Warrants will be determined, and durationthe 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 this improvement remains uncertain.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 reduction in oil, NGLs, and natural gas prices had several consequences for us (although, as noted, we are seeing improvements). Below are some of those consequences:
We incurred non-cash ceiling test write-downs in the first nine months of 2016 of $161.6 million ($100.6 million net of tax). We had no write-downs during 2017. It is hardwarrants issued to predict with any reasonable certainty the need for or amount of any future impairments given the many factors that go into the ceiling test calculation including, future pricing, operating costs, drilling and completion costs, upward or downward oil and gas reserve revisions, oil and gas reserve additions, and tax attributes. Subject to these inherent uncertainties, if we hold these same factors constant as they existed at December 31, 2017, and only adjust the 12-month average price to an estimated first quarter ending average (holding February 2018 prices constant for the remaining one monthholders of the first quarter of 2018), our forward looking expectation iscompany’s Old Common Stock that we willdid not recognize an impairment in the first quarter of 2018. But commodity prices (and other factors) remain volatile and they could negatively affect the 12-month average price resulting in the potential for a future impairment.
The number of gross wells our oil and gas segment drilled in 2017 verses 2016 increased from 21 wells to 70 wells due to increased cash flow. For 2018, we plan to increase the number of gross wells drilled to 75-85 wells (depending on future commodity prices).
The decline in drilling by our customers reduced the average use of our drilling rig fleet. At December 31, 2015, we had 26 drilling rigs operating. In 2016, utilization continued downward bottoming out in May at 13 operating drilling rigs. After May commodity prices improved for the remainderopt-out of the yearreleases under the Plan and we exited 2016 with 21 active rigs. As of December 31, 2017, we had 31 drilling rigs operating. Operators have been increasing drilling, but the extent of further increases remains uncertain. As of December 31 2017, all ten of our BOSS drilling rigs were under contract.
Due to low ethane price, we continue to operate some of our mid-stream processing facilities in ethane rejection mode which reduces the liquids sold. If ethane price relative to natural gas price remains depressed, we expect to continue operating in ethane rejection mode at some of our processing facilities.
Also, as noted elsewhere, beginning on April 4, 2017, we began an at-the-market offering for the sale ofthat owned their shares of ourold common stock. The offering allows us to sell shares, from time to time, up to an aggregate of $100.0 million in gross proceeds. As of December 31, 2017, we sold 787,547 shares for $18.6 million, net of offering costs of $0.4 million. Approximately $81.0 million remain available for sale under the program. Net proceeds from the offering will fund (or offset costs of) acquisitions, future capital expenditures, repay amounts outstanding under our revolving credit facility, and general corporate purposes.stock through Direct Registration are outlined below:
On April 3, 2017, we closed an acquisition of certain oil and natural gas assets from an unrelated third party. The acquisition included approximately 47 proved developed producing wells and 8,300 net acres primarily in Grady and Caddo Counties in western Oklahoma. The final adjusted value of consideration given was $54.3 million. The effective date of this acquisition was January 1, 2017.
Executive Summary
Oil and Natural Gas
Fourth quarter 2017 production from our oil and natural gas segment was 4,310 MBoe, an increase of 6% over the third quarter of 2017 and an increase of 2% over the fourth quarter of 2016. The increases mostly came from acquired wells and new wells drilled in 2017. Oil and NGLs production during the fourth quarter of 2017 was 46% of our total production compared to 47% of our total production during the fourth quarter of 2016.
Fourth quarter 2017 oil and natural gas revenues increased 19% over the third quarter of 2017 and increased 15% over the fourth quarter of 2016. These increases were primarily due to higher oil and NGLs prices and higher oil and natural gas production volumes.
Our NGLs, oil, and natural gas prices for the fourth quarter of 2017 increased 19%, 15%, and 1%, respectively, compared to the third quarter of 2017. Our NGLs and oil prices increased 50% and 18%, respectively, compared to the fourth quarter of 2016, while our natural gas prices were essentially unchanged.
Direct profit (oil and natural gas revenues less oil and natural gas operating expense) increased 29% over the third quarter of 2017 and 10% over the fourth quarter of 2016. The increases were primarily due to higher revenues due to rising commodity prices and production volumes.
Operating cost per Boe produced for the fourth quarter of 2017 decreased 3% from the third quarter of 2017 and increased 24% over the fourth quarter of 2016. The decrease from the third quarter of 2017 was primarily due to higher production volumes. The increase over the fourth quarter of 2016 was primarily due to higher lease operating expenses (LOE), gross production taxes, general and administrative expenses offset partially by higher production.
At December 31, 2017, these non-designated hedges were outstanding:
|
| | | | | | | | |
TermIssuance Date | | Commodity | | Contracted Volume | | Weighted Average
Fixed Price for Swaps
| | Contracted MarketWarrants Issued |
Jan’18 – Dec’18December 21, 2020 | | Natural gas – swap | | 20,000 MMBtu/day | | $3.013 | | IF – NYMEX (HH) |
Apr'18 – Oct'18 | | Natural gas – swap | | 10,000 MMBtu/day | | $2.990 | | IF – NYMEX (HH) |
Jan’18 – Mar'18 | | Natural gas – basis swap | | 10,000 MMBtu/day | | $(0.208) | | IF – NYMEX (HH) |
Nov’18 – Dec'18 | | Natural gas – basis swap | | 10,000 MMBtu/day | | $(0.208) | | IF – NYMEX (HH) |
Jan’18 – Mar'18 | | Natural gas – three-way collar | | 60,000 MMBtu/day | | $3.29 - $2.63 - $4.07 | | IF – NYMEX (HH) |
Apr’18 – Dec'18 | | Natural gas – three-way collar | | 20,000 MMBtu/day | | $3.00 - $2.50 - $3.51 | | IF – NYMEX (HH) |
Jan’18 – Dec'18 | | Crude oil – swap | | 3,000 Bbl/day | | $51.36 | | WTI – NYMEX |
Jan’18 – Mar'18 | | Crude oil – collar | | 500 Bbl/day | | $55.00 - $59.50 | | WTI – NYMEX |
Jan’18 – Dec'18 | | Crude oil – three-way collar | | 2,000 Bbl/day | | $47.50 - $37.50 - $56.08 | | WTI – NYMEX |
Apr’18 – Sep'18 | | Liquids (Propane) – swap | | 1,000 Bbl/day | | $31.16 | | MONT BELVIEU |
After December 31, 2017, these non-designated hedges were entered into:
|
| | | | | | | 1,764,164 | |
TermFebruary 11, 2021 | 42,511 | Commodity | | Contracted Volume | | Weighted Average
Fixed Price for Swaps | | Contracted Market |
Apr’18 – Sep'18July 29, 2021 | 10,521 | Natural gas – swap | | 10,000 MMBtu/day | | $2.925 | | IF – NYMEX (HH) |
Apr’18 – Sep'18October 13, 2021 | 5,005 | Natural gas – collar | | 30,000 MMBtu/day | | $2.67 - $2.97 | | IF – NYMEX (HH) |
Feb’18 – Dec'18Total | 1,822,201 | Natural gas – basis swap | | 10,000 MMBtu/day | | $(0.678) | | PEPL |
Feb’18 – Dec'18 | | Natural gas – basis swap | | 10,000 MMBtu/day | | $(0.568) | | NGPL MIDCON |
Apr’18 – Oct'18 | | Natural gas – basis swap | | 10,000 MMBtu/day | | $(0.190) | | NGPL TEXOK |
Jan'19 – Dec'19 | | Natural gas – basis swap | | 10,000 MMBtu/day | | $(0.728) | | PEPL |
Jan'19 – Dec'19 | | Natural gas – basis swap | | 10,000 MMBtu/day | | $(0.625) | | NGPL MIDCON |
Jan'19 – Dec'19 | | Natural gas – basis swap | | 20,000 MMBtu/day | | $(0.273) | | NGPL TEXOK |
Jan'20 – Dec'20 | | Natural gas – basis swap | | 20,000 MMBtu/day | | $(0.280) | | NGPL TEXOK |
Apr'18 – Dec'18 | | Crude oil – swap | | 1,000 Bbl/day | | $60.00 | | WTI – NYMEX |
Apr’18 – Sep'18 | | Liquids – swap | | 500 Bbl/day | | $34.10 | | MONT BELVIEU |
During 2017, we participated in the drilling of 70 wells (25.71 net wells). For 2018, we plan to participate in the drilling of approximately 75 to 85 gross wells. Our 2018 production guidance is approximately 17.1 to 17.4 MMBoe, an increase of 7-9% over 2017, actual results will be subject to many factors. This segment’s capital budget for 2018 is approximately $272.0 million, a 26% increase over 2017, excluding acquisitions and ARO liability.
Contract Drilling
The average numbercompany expects to issue approximately 21,117 more Warrants to the holders of drilling rigs we operated in the fourth quarter was 31.2 comparedOld Common Stock that did not opt-out of the releases under the Plan and owned their shares through Direct Registration.
Superior MSA and LLC amendments
Effective March 1, 2022, the employees of the Operator were transferred to 34.6 and 19.5 in the third quarter of 2017 and fourth quarter of 2016, respectively. As of December 31, 2017, 31 of our drilling rigs were operating.
Revenue for the fourth quarter of 2017 decreased 10% from the third quarter of 2017 and increased 40% over the fourth quarter of 2016. The decrease from the third quarter of 2017 was primarily due to fewer drilling rigs operating offset slightly by higher dayrates. The increase over the fourth quarter of 2016 was primarily due to more drilling rigs operating partially offset by lower dayrates.
Dayrates for the fourth quarter of 2017 averaged $16,645, a 1% increase over the third quarter of 2017 and a 1% decrease from the fourth quarter of 2016. The increase over the third quarter of 2017 was primarily due to a labor increase that was passed through to contracted rigs. The decrease from the fourth quarter of 2016 was primarily due to downward pressure on dayrates due to lower demand as higher rate contracts were expiring.
Operating costs for the fourth quarter of 2017 decreased 10% from the third quarter of 2017 and increased 45% over the fourth quarter of 2016. The decrease from the third quarter of 2017 was primarily due to fewer drilling rigs operating while the increase over the fourth quarter of 2016 was primarily due to more drilling rigs operating.
Direct profit (contract drilling revenue less contract drilling operating expense) for the fourth quarter of 2017 decreased 9% from the third quarter of 2017 and increased 31% over the fourth quarter of 2016. The decrease from the third quarter of 2017 was primarily due to fewer drilling rigs operating while the increase over the fourth quarter of 2016 was primarily due to more drilling rigs operating.
Operating cost per day for the fourth quarter of 2017 was essentially unchanged from the third quarter of 2017 and decreased 9% from the fourth quarter of 2016. The decrease from the fourth quarter of 2016 was primarily due to an increase in drilling rigs operating.
During 2017, almost all of our working drilling rigs were drilling horizontal or directional wells for oil and NGLs. The future demand forSuperior and the availability of drilling rigsMSA was amended and restated to meet that demand will affect our future dayrates.
As of December 31, 2017, we had nine term drilling contracts with original terms ranging from six monthsremove the operating services the Operator was providing to two years. Eight of these contracts are up for renewal in 2018, (four in the first quarter, three in the second quarter, and one in the fourth quarter) and one is up for renewal in 2019. Term contracts may contain a fixed rate during the contract or provide for rate adjustments within a specific range from the existing rate. Some operators who had signed term contracts have opted to release the drilling rig and pay an early termination penalty for the remaining term of the contract. We recorded $0.8 million, $3.1 million, and $29.0 million in early termination fees in 2017, 2016, and 2015, respectively.
All ten of our existing BOSS drilling rigs are under contract.
Our anticipated 2018 capital expenditures for this segment are approximately $47.0 million, a 30% increase over 2017.
Mid-Stream
Fourth quarter 2017 liquids sold per day increased 10% and 9% over the third quarter of 2017 and the fourth quarter of 2016, respectively. The increases were due primarily to more processed volume due to connecting additional wells to our systems. For the fourth quarter of 2017, gas processed per day increased 6% and 5% over the third quarter of 2017 and the fourth quarter of 2016, respectively. The increases were due to connecting additional wells to our processing systems. For the fourth quarter of 2017, gas gathered per daySuperior. There was essentially unchanged from the third quarter of 2017 and decreased 10% from the fourth quarter of 2016. The decrease from the fourth quarter of 2016 was primarily due to declining volumes from the Appalachian region.
NGLs prices in the fourth quarter of 2017 increased 17% and 44% over the prices received in the third quarter of 2017 and the fourth quarter of 2016, respectively. Because certain of the contracts used by our mid-stream segment for NGLs transactions are commodity-based contracts – under which we receive a share of the proceeds from the sale of the NGLs – our revenues from those commodity-based contracts fluctuate based on NGLs prices.
Direct profit (mid-stream revenues less mid-stream operating expense) for the fourth quarter of 2017 decreased 2% and 11% from the third quarter of 2017 and fourth quarter of 2016, respectively. The decrease from the third quarter was primarily due to a demand fee expiring in the fourth quarter of 2017 at our Pittsburgh Mills facility. The decrease from the fourth quarter of 2016 was also primarily dueno change to the expiring demandmonthly service fee at our Pittsburgh Mills facility infor shared services. The power to direct the fourth quarter of 2017 along withactivities 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 short-fall fee that was recognized in the fourth quarter of 2016. Total operating cost for this segment for the fourth quarter of 2017 increased 14% over both the third quarter of 2017VIE subsequent to these amendments and the fourth quarter of 2016, respectively due primarily to the combination of the higher cost of gas purchased and increased purchase volumes.
At our Cashion processing facility in central Oklahoma, our total throughput volume for the fourth quarter of 2017 averaged approximately 37.3 MMcf per day and our total production of natural gas liquids increased to approximately 198,600 gallons per day. The total processing capacity at this facility is approximately 45 MMcf per day. During 2017, we connected 12 new wells to this system from three producers. We are continuing a pipeline extension project for a producer scheduled to actively drill in the Cashion area in 2018. We have already connected four new wells from this producer and anticipate connecting several more wells throughout 2018. As volume increases on this system, we will evaluateno longer consolidate the need to add additional processing capacity. If volume continues to increase, we may need to addfinancial position, operating results, and cash flows of Superior as of March 1, 2022. We will subsequently account for our investment in Superior as an additional processing plant inequity method investment under the Cashion area.HLBV method.
At our Hemphill processing facility in the Texas panhandle, our average gathered volume for the fourth quarter of 2017 was approximately 68.5 MMcf per day and our total production of natural gas liquids increased to 188,600 gallons per day. During 2017, we connected six new wells to this processing system with several more wells scheduled to be connected in the first part of 2018. We have completed construction of the pipeline to connect the next well pad and we are upgrading our compression facilities to handles the expected additional volume.
At our Bellmon processing facility in the Mississippian play in north central Oklahoma, during 2017 we connected 14 new wells to this system. Our total throughput volume for the fourth quarter of 2017 averaged approximately 27 MMcf per day. We have two processing skids available that provide total processing capacity of 90 MMcf per day.
At our Segno gathering facility in Southeast Texas, our average gathered volume for the fourth quarter of 2017 was approximately 86.4 MMcf per day. The gathering and dehydration capacity for this facility is approximately 120 MMcf per day. During 2017, we connected three new wells to this gathering system along with additional volume from recompletion activity in the area around our system.
In the Appalachian region, at our Pittsburgh Mills gathering system, we continue to connect new well pads to this system. During 2017, we connected one new well pad with five new wells to this gathering system. By adding these new wells our average gathered volume for the fourth quarter was approximately 117.2 MMcf per day. We are constructing a new pipeline to connect the next well pad to this system. Most of the preliminary environmental and permitting activities have been completed and right of way has been obtained. In the first quarter of 2018, we will start the construction of the pipeline with an expected completion date in the third quarter of 2018. This new well pad is expected to have seven wells drilled and we anticipate receiving gas from this pad at the end of 2018. This well pad is on the south end of our system and will be connected to our Kissick compressor station. And we have been notified by the producer they will drill seven infill wells on already existing pads in 2018.
Anticipated 2018 capital expenditures for this segment are approximately $32.0 million, a 44% increase over 2017.
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 assumptionassumptions been used. We evaluate our estimates and assumptions regularly. We base our estimates on historical experience and various other assumptions we believe are reasonable under the circumstances, the results of which support making judgments about the carrying values of assets and liabilities not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our financial statements. In this discussion we attempt to explain the nature of these estimates, assumptions and judgments, and the likelihood that materially different amounts would be reported in our financial statements under different conditions or using different assumptions.
This table lists the critical accounting policies, identifies the estimates and assumptions that can have a significant impact on applying of these accounting policies, and the financial statement accounts affected by these estimates and assumptions.
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| | | | |
Accounting Policies | | Estimates or Assumptions | | Accounts Affected |
Full cost method of accounting for oil, NGLs, and natural gas properties | | • Oil, NGLs, and natural gas reserves, estimates, and related present value of future net revenues
• Valuation of unproved properties
• Estimates of future development costs
| | • Oil and natural gas properties
• Accumulated depletion, depreciation and amortization
• Provision for depletion, depreciation and amortization
• Impairment of oil and natural gas properties
• Long-term debt and interest expense
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| | | | |
Accounting for ARO for oil, NGLs, and natural gas properties | | • Cost estimates related to the plugging and abandonment of wells
• Timing of cost incurred
• Credit adjusted risk free rate
| | • Oil and natural gas properties
• Accumulated depletion, depreciation and amortization
• Provision for depletion, depreciation and amortization
• Current and non-current liabilities
• Operating expense
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| | | | |
Accounting for impairment of long-lived assets | | • Forecast of undiscounted estimated future net operating cash flows
| | • Drilling and mid-stream property and equipment
• Accumulated depletion, depreciation and amortization
• Provision for depletion, depreciation and amortization
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| | | | |
Goodwill | | • Forecast of discounted estimated future net operating cash flows
• Terminal value
• Weighted average cost of capital
| | • Goodwill |
| | | | |
Accounting for value of stock compensation awards | | • Estimates of stock volatility
• Estimates of expected life of awards
granted
• Estimates of rates of forfeitures
• Estimates of performance shares
granted
| | • Oil and natural gas properties
• Shareholder’s equity
• Operating expenses
• General and administrative expenses
|
| | | | |
Accounting for derivative instruments | | • Derivatives measured at fair value | | • Current and non-current derivative assets and liabilities
• Gain (loss) on derivatives
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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. TheThat audit of our reserve wells or locations as of December 31, 20172021 covered those thatreserves we projected to comprise 83%85% of the total proved developed future net income discounted at 10% and 86% of the total proved discounted future net income (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.
As a rule, theThe accuracy of estimating oil, NGLs, and natural gas reserves varies with the reserve classification and the related accumulation of available data, as shown in this table:
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| | | | | | | | | | | | | |
| Type of Reserves | | 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 isare greater than the projected revenues from the oil, NGLs, and natural gas reserves). But more significantly, the estimated present value of the future cash flows from our oil, NGLs, and natural gas reserves is sensitive to prices and costs and may vary materially based on different assumptions. Companies, like ours, usingWe use full cost accounting usewhich factors in the unweighted arithmetic average of the commodity prices existing on the first day of each of the 12twelve months before the end of the reporting period to calculate discounted future revenues, unless prices were otherwise determined under contractual arrangements.
We compute DD&A on a units-of-production method. Each quarter, we use these formulas to compute the provision for DD&A for our producing properties:
•DD&A Rate = Unamortized Cost / End of Period Reserves Adjusted for Current Period Production
•Provision for DD&A = DD&A Rate x Current Period Production
Unamortized cost includes all capitalized costs, estimated future expenditures to be incurred in developing proved reserves and estimated dismantlement and abandonment costs, net of estimated salvage values less accumulated amortization, unproved properties, and equipment not placed in service.
Oil, NGLs, and natural gas reserve estimates have a significant impact on our DD&A rate. If future reserve estimates for a property or group of properties are revised downward, the DD&A rate will increase because of the revision. If reserve estimates are revised upward, the DD&A rate will decrease. Based on our 2017 production level of 16.0 MMBoe, a decrease in our 2017 oil, NGLs, and natural gas reserves by 5% would increase our DD&A rate by $0.36 per Boe and would decrease pre-tax income by $5.8 million annually. Conversely, an increase in our 2017 oil, NGLs, and natural gas reserves by 5% would decrease our DD&A rate by $0.30 per Boe and would increase pre-tax income by $4.8 million annually.
The DD&A expense on our oil and natural gas properties is calculated each quarter using period end reserve quantities adjusted for period production.
We account for our oil and natural gas exploration and development activities using the full cost method of accounting. Under this method, we capitalize all costs incurred in the acquisition, exploration, and development of oil and natural gas properties. At the end of each quarter, the net capitalized costs of our oil and natural gas properties are limited to that amount which is the lower of unamortized costs or a ceiling. The ceiling is defined as the sum of the present value (using a 10% discount rate) of the estimated future net revenues from our proved reserves (based on the unescalated 12-month average price on our oil, NGLs, and natural gas adjusted for any cash flow hedges), plus the cost of properties not being amortized, plus the lower of the cost or estimated fair value of unproved properties included in the costs being amortized, less related income taxes. If the net capitalized costs of our oil and natural gas properties exceed the ceiling, we are required to write-down the excess amount. A ceiling test write-down is a non-cash charge to earnings. If required, it reducesreducing earnings and impacts shareholders’ equity in the period of occurrence, and resultsresulting in lower DD&A expense in future periods. Once incurred, aA write-down cannot be reversed.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, 2017,2021, our reserves were calculated based on applying 12-month 20172021 average unescalated prices of $51.34$66.56 per barrel of oil, $31.83$44.22 per barrel of NGLs, and $2.98$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. We had no ceiling test write-down for 2017.
It is hard to predict with any reasonable certainty the need for or amount of any future impairments given the many factors that go into the ceiling test calculation including, but not limited to, future pricing, operating costs, drilling and completion costs, upward or downward oil and gas reserve revisions, oil and gas reserve additions, and tax attributes. Subject to these inherent uncertainties, if we hold these same factors constant as they existed at December 31, 2017 and only adjust the 12-month average price to an estimated first quarter ending average (holding February 2018 prices constant for the remaining one month of the first quarter of 2018), our forward looking expectation is that we will not recognize an impairment in the first quarter of 2018. But commodity prices (and other factors) remain volatile and they could negatively affect the 12-month average price resulting in the potential for an impairment in the first quarter.
We use the sales method for recording natural gas sales. This method allows for the recognition of revenue, which may be more or less than our share of pro-rata production from certain wells. Our policy is to expense our pro-rata share of lease operating costs from all wells as incurred. The expenses relating to the wells in which we have a production imbalance are not material.
Costs Withheld from Amortization. Costs associated with unproved properties are excluded from our amortization base until we have evaluated the properties. The costs associated with unevaluated leasehold acreage and related seismic data, wells drilling and capitalized interest are initially excluded from our amortization base. Leasehold costs are transferred to our amortization base with the costs of drilling a well on the lease or are assessed at least annually for possible impairment or reduction in value. Leasehold costs are transferred to our amortization base to the extent a reduction in value has occurred.
Our decision to withhold costs from amortization and the timing of transferring those costs into the amortization base involve significant judgment and may be subject to changes over time based on several factors, including our drilling plans, availability of capital, project economics and results of drilling on adjacent acreage. In December 2015, December 2016, and December 2017, we determined the value of certain unproved oil and gas properties were diminished (in part or in whole) based on an impairment evaluation and our anticipated future exploration plans. Those determinations resulted in $114.4 million, $7.6 million, and $10.5 million in 2015, 2016, and 2017, respectively of costs being added to the total of our capitalized costs being amortized. At December 31, 2017, we had approximately $296.8 million of costs excluded from the amortization base of our full cost pool.
Accounting for ARO for Oil, NGLs, and Natural Gas Properties. We record the fair value of liabilities associated with the future plugging and abandonment of wells. In our case, when the reserves in each of our oil or gas wells deplete or otherwise become uneconomical, we must incur costs to plug and abandon the wells. These costs are recorded in the period in which the liability is incurred (at the time the wells are drilled or acquired). We have no assets restricted to settle these ARO liabilities. Our engineering staff uses historical experience to determine the estimated plugging costs considering the type of well (either oil or natural gas), the depth of the well, the physical location of the well, and the ultimate productive life to determine the estimated plugging costs. A risk-adjusted discount rate and an inflation factor are used on these estimated costs to determine the current present value of this obligation. To the extent any change in these assumptions affect future revisions and impact the present value of the existing ARO, a corresponding adjustment is made to the full cost pool.
Accounting for Impairment of Long-Lived Assets. Drilling equipment, transportation equipment, gas gatheringOther Property and processing systems, and other property and equipment are carried at cost less accumulated depreciation. Renewals and enhancements are capitalized while repairs and maintenance are expensed.Equipment. We review the carrying amounts of long-lived assets for potential impairment annually, typically during the fourth quarter, or when events occur or changes in circumstances suggest these carrying amounts may not be recoverable. Changes that could prompt such an assessment may 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 amount of the 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 management’sour assumptions and judgments regarding
future industry conditions and their effect on future utilization levels, dayrates, and costs. Using different estimates and assumptions could causeresult in materially different carrying values of our assets.
On a periodic basis, we evaluate our fleetAsset Retirement Obligations. We are required to record the estimated fair value of drilling rigs for marketability based on the condition of inactive rigs, expenditures that would be necessary to bring them to working condition and the expected demand for drilling services by rig type. The components comprising inactive rigs are evaluated, and those components with continuing utilityliabilities relating to the Company’s other marketed rigsfuture retirement of our long-lived assets. Our oil and natural gas wells are transferredplugged and abandoned when the oil and natural gas reserves in those wells are depleted or the wells are no longer able to other rigsproduce. The estimated liabilities related to these future costs are recorded at the time the wells are drilled or acquired. We use historical experience to its yardsdetermine 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 be spare equipment. The remaining componentsestimate the present value of these rigsobligations. We depreciate the capitalized asset retirement cost and accrete the obligation over time. Revisions to the obligations and assets are retired. During 2015, we recordedrecognized at the appropriate risk-adjusted discount rate with a write-down on 31 of our drilling rigs and related equipment of approximately $8.3 million pre-tax based oncorresponding adjustment made to the estimated market value for similar equipment from auctions sales. We then sold all 31 of these drilling rigs and some other drilling equipment to unaffiliated third parties. The proceeds from the sale of those assets, less costs to sell, was less than the $11.3 million net book value resulting in a loss of $7.3 million pre-tax. No impairments were recorded in 2016 or 2017.
In 2015, ourfull cost pool. Our mid-stream segment incurred a $27.0 million pre-tax write-downhas property and equipment at locations leased or under right of its systems, Bruceton Mills, Spring Creek, and Midwell dueway agreements which may require asset removal or site restoration, however, we are not able to anticipated future cash flow and future development around these systems not being sufficient to support their carrying value. The estimated future cash flows were less than the carrying value on these systems. No impairments were recorded in 2016 or 2017.
Goodwill. Goodwill represents the excess of the cost of acquisitions overreasonably measure the fair value of the net assets acquired. Goodwill is not amortized, but an impairment test is performed at least annually to determine whetherobligations as the fair value has decreased and is performed additionally when events indicate an impairment may have occurred. For impairment testing, goodwill is evaluated at the reporting unit level. Our goodwill is all related to our contract drilling segment, and, the impairment test is generally based on the estimated discounted future net cash flowspotential settlement dates are indeterminable.
Warrant Liability. We recognize the fair value of the warrants as a derivative liability on our drilling segment. Inputsconsolidated balance sheets with changes in the liability reported as loss on change in fair value of warrants in our estimated discountedconsolidated 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 net cash flows include drilling rig utilization, day rates, gross margin percentages,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 terminal value. No goodwill impairment wasevents 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 at December 31, 2017, 2016, or 2015. Basedin reorganization items, net on our impairment test performedaccompanying 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 of December 31, 2017,determined under ASC 820, Fair Value Measurement, represents the fair value of our drilling segment exceeded its carryingthe 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 by 41%. A period of sustained reduced commodity prices resulting in further reductions inrepresents the number of our drilling rigs working and the rates we charge for them could cause a non-cash goodwill impairment in future periods.
Turnkey and Footage Drilling Contracts. Because our contract drilling operations do not bear the risk of completion of a well being drilled under a “daywork” contract, we recognize revenues and expense generated under “daywork” contracts as the services are performed. Under “footage” and “turnkey” contracts we bear the risk of completion of the well, so revenues and expenses are recognized when the well is substantially completed. Substantial completion is determined when the well bore reaches the depth specified in the contract. The entire amount of any loss is recorded when the loss can be reasonably determined, however, any profit is recorded only at the time the well is finished. The costs of drilling contracts uncompleted at the end of the reporting period (which includes expenses incurred on “footage” or “turnkey” contracts) are included in other current assets. We drilled no wells under turnkey or footage contracts in 2017, 2016, or 2015.
Accounting for Value of Stock Compensation Awards. To account for stock-based compensation, compensation cost is measured at the grant date based on theestimated fair value of an awardentity’s long-term debt and is recognized overequity. 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 service period,Effects of Reference Rate Reform on Financial Reporting. The FASB issued ASU 2020-04 and ASU 2021-01 which is usuallyprovide 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 vesting period.amendments prospectively through December 31, 2022. We have not yet elected to use the modified prospective method, which requires compensation expenseoptional guidance and continue to be recorded for all unvested stockevaluate the options provided by ASU 2020-04 and other equity-based compensation beginningASU 2021-01.
Debt—Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging— Contracts in the first quarter of adoption. Determining the fair value of an award requires significant estimates and subjective judgments regarding, among other things, the appropriate option pricing model, the expected life of the award and performance vesting criteria assumptions. As there are inherent uncertainties related to these factors and our judgment in applying them to the fair value determinations, there is risk that the recorded stock compensation may not accurately reflect the amount ultimately earned by the employee.
Entity’s Own Equity (Subtopic 815-40): Accounting for DerivativeConvertible Instruments and Hedging. All derivatives are recognized on the balance sheet and measured at fair value. Any changesContracts in our derivatives' fair value before their maturity (i.e., temporary fluctuations in value) along with any derivatives settled are reported in gain (loss) on derivatives in our Consolidated Statements of Operations.
New Accounting Standards
Compensation—Stock Compensation. an Entity’s Own Equity. The FASB issued ASU 2017-09,2020-06 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 clarifyqualify for the derivative scope exception and reduce both (i) diversitysimplifies the diluted earnings per share calculation in practicecertain 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 (ii) costsimplify GAAP for other areas of Topic 740 by clarifying and complexity when applying its guidance to changes in the terms of a share-based payment award.amending existing guidance. The amendment is effective for reporting periods beginning after December 15, 2017. This amendment will not have a material impact on our financial statements.
Intangibles—Goodwill and Other: Simplifying the Test for Goodwill Impairment. 2020. The FASB issued ASU 2017-04, to simplify the measurementadoption of goodwill. The amendment eliminates Step 2 from the goodwill impairment test. The amendment will be effective prospectively for reporting periods beginning after December 15, 2019, and early adoption is permitted. This amendment will not have a material impact on our financial statements.
Business Combinations; Clarifying the Definition of a Business. The FASB issued ASU 2017-01, clarifying the definition of a business. The amendment should help companies and other organizations evaluate whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. For public companies, the amendment is effective for annual periods beginning after December 15, 2017. This amendment will not have a material impact on our financial statements.
Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments. The FASB issued ASU 2016-15, to address diversity in how certain transactions are presented and classified in the statement of cash flows. The amendment will be effective retrospectively for reporting periods beginning after December 31, 2017, and early adoption is permitted. This amendment will not have a material impact on our financial statements.
Leases. The FASB has issued ASU 2016-02. The amendment will require lessees to recognize at the commencement date a lease liability, which is a lessee's obligation to make lease payments arising from a lease, measured on a discounted basis; and a right-of-use asset, which is an asset that represents the lessee's right to use a specified asset for the lease term. Lessor accounting is largely unchanged. For public companies, the amendment is effective for annual periods beginning after December 15, 2018, and interim periods within those annual periods. The standard will not apply to leases of mineral rights. We are evaluating the impact this amendment will have on our financial statements and currently evaluating a plan for implementation.
Revenue from Contracts with Customers. The FASB has issued ASU 2014-09. This standard affects any entity using U.S. GAAP that either contracts with customers to transfer goods or services or enters into contracts for transferring nonfinancial assets unless those contracts are within the scope of other standards (e.g., insurance contracts or lease contracts). The core principle of the amendments is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 has been amended several times pre-issuance, which is codified in the new Topic 606, effective January 1, 2018. The guidance in this update supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and most industry-specific guidance throughout the Industry Topics of the Codification. We adopted this standard January 1, 2018 using the modified retrospective approach, which resulted in a cumulative effect adjustment upon adoption for our mid-stream segment. This adjustment related to the timing of revenue on certain demand fees which was not material to the company. Both our oil and natural gas and contract drilling segments had no retained earnings adjustment.
The application of Topic 606 will not have a material effect on our statement of operations or our balance sheet, as the timing of revenue recognized will not be materially modified, but additional footnote disclosures are required with respect to revenue. In our oil and natural gas segment, the classification of certain costs as either a deduction from revenue or an expense will be determined based on when control of the commodity transfers to the customer, which would impact total revenue recognized, but will not affect gross profit.
Part of our review included evaluation of these issues:
Based on an analysis of whether the transportation of gas is a performance obligation that occurs at a point in time or over time, the timing of when we recognize certain revenue elements will change. Specifically related to our mid-stream segment, certain fees collectible during a contract will be recognized over the life of the contract because these fees are part of the single performance obligation associated with the contract.
Certain of our contracts include promises to deliver a minimum volume of commodity to the customer over a defined period. If we do not meet this commitment, a deficiency fee is payable to the customer. Topic 606 requires these arrangements represent variable consideration related to the sale of the commodity, and requires that we include an
estimate of any deficiency fees expected within revenue, rather than as operating costs. In addition, we will also be required to analyze fees that are billable for deficiencies in minimum volume commitments from customers for our mid-stream segment. In these instances, we will assess the likelihood of earning these fees each reporting period based on the customer’s performance and recognize variable revenue when it is not expected to be subject to a significant reversal.
Our internal control framework did not materially change, but the existing internal controls have been modified to consider our new revenue recognition policy effective January 1, 2018. As we implement the new standard, we have added internal controls to ensure that we adequately evaluate new contracts under the five-step model under ASU 2014-09.
Adopted Standards
Income Taxes: Balance Sheet Classification of Deferred Taxes. The FASB has issued ASU 2015-17. This changes how deferred taxes are classified on organizations' balance sheets. Organizations must classify all deferred tax assets and liabilities as noncurrent. The amendments apply to all organizations that present a classified balance sheet. For public companies, the amendments were effective for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. The amendment requires current deferred tax assets to be combined with noncurrent deferred tax assets. We have adopted this ASU during the first quarter of 2017 on a prospective basis. Previously, we had a net current deferred tax asset now netted with our noncurrent deferred tax liability. Prior periods were not retrospectively adjusted.
Compensation—Stock Compensation: Improvements to Employee Share-Based Payment Accounting. The FASB has issued ASU 2016-09. The amendment should improve the accounting for employee share-based payments and affect all organizations that issue share-based payment awards to their employees. Several aspects of the accounting for share-based payment award transactions are simplified, including: (a) income tax consequences; (b) classification of awards as either equity or liabilities; and (c) classification on the statement of cash flows. For public companies, the amendment was effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods. The amendment primarily affects classification within the statement of cash flows between financial and operating activities. This did not have a material impact onto our consolidated financial statements.
Financial Condition and Liquidity
Summary.Summary
Our financial condition and liquidity primarily dependsdepend on the cash flow from our operations and borrowings under our credit agreement.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 demand foruse of our drilling rigs and the dayrates we receive for ourthose drilling rigs; and
•the fees and margins we obtain from our natural gas gathering and processing contracts.
We believe we have sufficientcurrently expect that cash flow and liquidity to meet our obligationscash equivalents, cash generated from operations, and remain in compliance with our debt covenants foravailable funds under the next twelve months. Our ability to meet our debt covenants (under ourExit credit agreement and our Indenture) and our capacity to incur additional indebtedness will depend on our future performance, which in turn will be affected by financial, business, economic, regulatory, and other factors. For example, lower oil, natural gas, and NGLs prices since the last redetermination under ourSuperior credit agreement could cause a redetermination of the borrowing baseare adequate to a lower level and therefore reduce or limit our ability to borrow funds. We monitorcover our liquidity and capital resources, endeavor to anticipate potential covenant compliance issues and work withrequirements for at least the lenders under our credit agreement to address any of those issues ahead of time.next 12 months.
Below is a summary of certain financial information for the years ended December 31:periods indicated:
| | | | | | | | | | | | | | | Successor | | | Predecessor |
| | 2017 | | 2016 | | 2015 | | | Year Ended
December 31, 2021 | | Four Months Ended
December 31, 2020 | | | Eight Months Ended
August 31, 2020 | |
| | (In thousands) | | | | | (In thousands) |
| Net cash provided by operating activities | $ | 279,588 |
| | $ | 240,130 |
| | $ | 446,944 |
| | Net cash provided by operating activities | $ | 175,969 | | | $ | 29,807 | | | | $ | 44,956 | | |
| Net cash used in investing activities | (306,998 | ) | | (110,971 | ) | | (549,778 | ) | | |
| Net cash provided by (used in) investing activities | | Net cash provided by (used in) investing activities | 36,205 | | | (2,258) | | | | (20,139) | | |
| Net cash provided by (used in) financing activities | 27,218 |
| | (129,101 | ) | | 102,620 |
| | Net cash provided by (used in) financing activities | (160,748) | | | (47,775) | | | | 7,552 | | |
| Net increase (decrease) in cash and cash equivalents | $ | (192 | ) | | $ | 58 |
| | $ | (214 | ) | | |
| Net increase (decrease) cash, restricted cash, and cash equivalents | | Net increase (decrease) cash, restricted cash, and cash equivalents | $ | 51,426 | | | $ | (20,226) | | | | $ | 32,369 | | |
Cash flowsFlows from Operating Activities
Our operating cash flow is primarily influenced by the prices we receive for our oil, NGLs, and natural gas production, the quantity of oil, NGL, and natural gas we produce, settlements of derivative contracts, third-party demanduse 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 2017the year ended December 31, 2021 increased by $39.5$101.2 million from 2016 dueas compared to the year ended December 31, 2020 primarily to higher revenues due to higher commodity prices and higher drilling rig utilizationincreased 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 flowsFlows from Investing Activities
We dedicate and expect to continue to dedicatehave historically dedicated a substantial portion of our capital budgetbudgets to theour 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.
Cash flows used inNet cash provided by (used in) investing activities increased by $196.0$58.6 million in 2017during the year ended December 31, 2021 compared to 2016. The change wasthe year ended December 31, 2020 primarily due primarily to an increase in capital expenditures due to an oil and gas property acquisition, the restarting of our drilling program in 2017, the construction of a new BOSS drilling rig, and a decrease in the proceeds received from the disposition of assets. See additional information onour corporate headquarters building and land, an increase in proceeds received from the disposition of other non-core assets, and a decrease in capital expenditures below under Capital Requirements.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
Cash flowsNet cash provided by (used in) financing activities increaseddecreased by $156.3$120.5 million in 2017during the year ended December 31, 2021 compared to 2016. The increase wasthe year ended December 31, 2020 primarily due to proceeds fromhigher payments on our credit agreements, the ATMrepurchase of common stock, program coupled with an increase in net borrowing after paying down long-term debt in 2016.lower borrowings under our credit agreements, distributions made to non-controlling interests, and lower bank overdrafts.
AtAs of December 31, 2017,2021, we had unrestricted cash and cash equivalents totaling $0.7$64.1 million, and had borrowed $178.0which 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 $475.0 million we have availableSuperior credit agreement. Unit had no outstanding borrowings under ourthe Exit credit agreement.
Below, is a summary ofwe summarize certain financial information as of December 31, and for the years ended 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 | | | |
|
| | | | | | | | | | | | |
| | 2017 | | 2016 | | 2015 | |
| | (In thousands) | |
| Working capital | $ | (62,264 | ) | | $ | (43,719 | ) | | $ | (10,633 | ) | |
Long-term debt (1) | $ | 820,276 |
| | $ | 800,917 |
| | $ | 918,995 |
| |
Shareholders’ equity (2) | $ | 1,345,560 |
| | $ | 1,194,070 |
| | $ | 1,313,580 |
| |
Net income (loss) (2) | $ | 117,848 |
| | $ | (135,624 | ) | | $ | (1,037,361 | ) | |
_________________________
| |
(1) | Long-term debt is net of unamortized discount and debt issuance costs. |
| |
(2) | In 2016 and 2015, we incurred non-cash ceiling test write-downs of our oil and natural gas properties of $161.6 million, and $1.6 billion pre-tax ($100.6 million and $1.0 billion, net of tax), respectively. In 2015, we incurred a non-cash write-down associated with the removal of 31 drilling rigs from our fleet along with certain other equipment and drill pipe of $8.3 million pre-tax ($5.1 million, net of tax). In December 2015, we incurred a non-cash write-down associated with the reduction in the carrying value of three mid-stream segment gathering systems of $27.0 million pre-tax ($16.8 million, net of tax). The write-downs affected our shareholders’ equity, ratio of long-term debt to total capitalization, and net income (loss) for 2015. There was no impact on our compliance with the covenants in our credit agreement. |
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 negativepositive working capital of $62.3$5.8 million $43.7 million, and $10.6at December 31, 2021 compared to positive working capital of $2.6 million as of December 31, 2017, 2016, and 2015, respectively. This2020. The increase in working capital is primarily due to increasedhigher cash and cash equivalents and accounts payable due to increased activity in our drilling program and increased drilling rig utilization and the reclassification of the current deferred tax asset to long-term asset per ASU 2015-17receivable, partially offset by increasedhigher current derivative liabilities, warrant liability, and accounts receivable from increased revenuespayable. Both the Superior credit agreement and the change inExit credit agreement may be used for working capital. As of December 31, 2021, we had no outstanding borrowings under the valueExit credit agreement and $19.2 million of outstanding derivatives. Our credit agreement is used primarily for working capital and capital expenditures. At December 31, 2017, we had borrowed $178.0 million ofborrowings under the $475.0 million available to us under ourSuperior credit agreement. The effect of our derivatives decreased working capital by $7.1$40.9 million as of December 31, 2017,2021 and increaseddecreased working capital by $21.6 million and $10.2$1.0 million as of December 31, 20162020.
Credit Agreements
Exit Credit Agreement. On the Effective Date, under the terms of the Plan, the company entered into an amended and 2015, respectively.
This table summarizes certain operating informationrestated credit agreement (the Exit credit agreement), providing for the years ended December 31:
|
| | | | | | | | | | | | |
| | 2017 | | 2016 | | 2015 | |
| Oil and Natural Gas: | | | | | | |
| Oil production (MBbls) | 2,715 |
| | 2,974 |
| | 3,783 |
| |
| Natural gas liquids production (MBbls) | 4,737 |
| | 5,014 |
| | 5,274 |
| |
| Natural gas production (MMcf) | 51,260 |
| | 55,735 |
| | 65,546 |
| |
| Average oil price per barrel received | $ | 49.44 |
| | $ | 40.50 |
| | $ | 50.79 |
| |
| Average oil price per barrel received excluding derivatives | $ | 48.98 |
| | $ | 39.05 |
| | $ | 45.04 |
| |
| Average NGLs price per barrel received | $ | 18.35 |
| | $ | 11.26 |
| | $ | 10.12 |
| |
| Average NGLs price per barrel received excluding derivatives | $ | 18.35 |
| | $ | 11.26 |
| | $ | 10.12 |
| |
| Average natural gas price per mcf received | $ | 2.46 |
| | $ | 2.07 |
| | $ | 2.63 |
| |
| Average natural gas price per mcf received excluding derivatives | $ | 2.49 |
| | $ | 1.98 |
| | $ | 2.25 |
| |
| Contract Drilling: | | | | | | |
| Average number of our drilling rigs in use during the period | 30.0 |
| | 17.4 |
| | 34.7 |
| |
| Total drilling rigs available for use at the end of the period | 95 |
| | 94 |
| | 94 |
| |
| Average dayrate | $ | 16,256 |
| | $ | 17,784 |
| | $ | 19,455 |
| |
| Mid-Stream: | | | | | | |
| Gas gathered—Mcf/day | 385,209 |
| | 419,217 |
| | 353,771 |
| |
| Gas processed—Mcf/day | 137,625 |
| | 155,461 |
| | 182,684 |
| |
| Gas liquids sold—gallons/day | 534,140 |
| | 536,494 |
| | 577,513 |
| |
| Number of natural gas gathering systems | 24 |
| | 25 |
| | 25 |
| (1) |
| Number of processing plants | 13 |
| | 13 |
| | 13 |
| |
_________________________
| |
(1) | In 2015, our mid-stream segment transferred 11 natural gas gathering systems to our oil and natural gas segment. |
Oil and Natural Gas Operations
Any significant change in oil, NGLs, or natural gas prices has a material effect on our revenues, cash flow, and the value of our oil, NGLs, and natural gas reserves. Generally, prices and demand for domestic natural gas are influenced by weather conditions, supply imbalances, and by worldwide oil price levels. Domestic oil prices are primarily influenced by world oil market developments. These factors are beyond our control and we cannot predict nor measure their future influence on the prices we will receive.
Based on our 2017 production, a $0.10 per Mcf change in what we are paid for our natural gas production, without the effect of derivatives, would cause a corresponding $410,000 per month ($4.9$140.0 million annualized) change in our pre-tax operating cash flow. Our 2017 average natural gas price was $2.46 compared to an average natural gas price of $2.07 for 2016 and $2.63 for 2015. A $1.00 per barrel change in our oil price, without the effect of derivatives, would have a $217,000 per month ($2.6 million annualized) change in our pre-tax operating cash flowsenior secured revolving credit facility (RBL Facility) and a $1.00 per barrel change in our NGLs prices, without$40.0 million senior secured term loan facility, among (i) the effectcompany, UDC, and UPC (together, the Borrowers), (ii) the guarantors party thereto, including the company and all of derivatives, would have a $380,000 per month ($4.6 million annualized) change in our pre-tax operating cash flow based on our production in 2017. Our 2017 average oil price per barrel was $49.44 compared with an average oil price of $40.50 in 2016 and $50.79 in 2015, and our 2017 average NGLs price per barrel was $18.35 compared with an average NGLs price of $11.26 in 2016 and $10.12 in 2015.
Because commodity prices affect the value of our oil, NGLs, and natural gas reserves, declines in those prices can cause a decline in the carrying value of our oil and natural gas properties. At December 31, 2017, the 12-month average unescalated prices were $51.34 per barrel of oil, $31.83 per barrel of NGLs, and $2.98 per Mcf of natural gas, and then are adjusted for price differentials. We did not have to take a write down in 2017.
It is hard to predict with any reasonable certainty the need for or amount of any future impairments given the many factors that go into the ceiling test calculation including, but not limited to, future pricing, operating costs, drilling and completion costs, upward or downward oil and gas reserve revisions, oil and gas reserve additions, and tax attributes. Subject to these inherent uncertainties, if we hold these same factors constantits subsidiaries existing as they existed at December 31, 2017 and only adjust the 12-month average price to an estimated first quarter ending average (holding February 2018 prices constant for the remaining
one month of the first quarter of 2018)Effective Date (other than Superior Pipeline Company, L.L.C. and its subsidiaries), our forward looking expectation is that we will not recognize an impairment in(iii) the first quarter of 2018. Commodity prices remain volatile and they could negatively affect the 12-month average price and the potential for an impairment in the first quarter.
Our natural gas production is sold to intrastate and interstate pipelines, to independent marketing firms and gatherers under contracts with terms generally ranging from one month to five years. Our oil production is sold to independent marketing firms generally under six-month contracts.
Contract Drilling Operations
Many factors influence the number of drilling rigs we have working and the costs and revenues associated with that work. These factors include the demand for drilling rigs in our areas of operation, competition from other drilling contractors, the prevailing prices for oil, NGLs, and natural gas, availability and cost of labor to run our drilling rigs, and our ability to supply the equipment needed.
Competition to keep qualified labor continues. We increased compensation for some rig personnel in the third quarter of 2017 and again during the first quarter of 2018.
During 2017, almost all of our working drilling rigs were drilling horizontal or directional wells for oil and NGLs. The continuous fluctuations in commodity prices for oil and natural gas changes demand for drilling rigs. These factors ultimately affect the demand and mix of the type of drilling rigs used by our customers. The future demand for and the availability of drilling rigs to meet that demand will affect our future dayrates. For 2017, our average dayrate was $16,256 per day compared to $17,784 and $19,455 per day for 2016 and 2015, respectively. Our average number of drilling rigs used (utilization %) in 2017 was 30.0 (32%) compared with 17.4 (19%) and 34.7 (38%) in 2016 and 2015, respectively.Based on the average utilization of our drilling rigs during 2017, a $100 per day change in dayrates has a $3,000 per day ($1.1 million annualized) change in our pre-tax operating cash flow.
Our contract drilling segment provides drilling services for our exploration and production segment. Some of the drilling services we perform on our properties are, depending on the timing of those services, deemed associated with acquiring an ownership interest in the property. In those cases, revenues and expenses for those services are eliminated in our statement of operations, with any profit recognized as a reduction in our investment in our oil and natural gas properties. The contracts for these services are issued under the same conditions and rates as the contracts entered into with unrelated third parties. By providing drilling services for the oil and natural gas segment, we eliminated revenue of $13.4 million and $22.1 million during 2017 and 2015, respectively, from our contract drilling segment and eliminated the associated operating expense of $11.8 million and $18.3 million during 2017 and 2015, respectively, yielding $1.6 million and $3.8 million during 2017 and 2015, respectively, as a reduction to the carrying value of our oil and natural gas properties. We eliminated no revenue or expenses in our contract drilling segment during 2016.
Mid-Stream Operations
This segment is engaged primarily in the buying, selling, gathering, processing, and treating of natural gas. It operates three natural gas treatment plants, 13 processing plants, 24 gathering systems, and approximately 1,455 miles of pipeline. Its operations are in Oklahoma, Texas, Kansas, Pennsylvania, and West Virginia. This segment enhances our ability to gather and market not only our own natural gas and NGLs but also that owned by third parties and serves as a mechanism through which we can construct or acquire existing natural gas gathering and processing facilities. During 2017, 2016, and 2015 this segment purchased $63.2 million, $42.7 million, and $57.6 million, respectively, of our oil and natural gas segment's natural gas and NGLs production, and provided gathering and transportation services of $6.7 million, $9.2 million, and $7.6 million, respectively. Intercompany revenue from services and purchases of production between this business segment and our oil and natural gas segment has been eliminated in our consolidated financial statements.
Our mid-stream segment gathered an average of 385,209 Mcf per day in 2017 compared to 419,217 Mcf per day in 2016 and 353,771 Mcf per day in 2015. It processed an average of 137,625 Mcf per day in 2017 compared to 155,461 Mcf per day in 2016 and 182,684 Mcf per day in 2015, and sold NGLs of 534,140 gallons per day in 2017 compared to 536,494 gallons per day in 2016 and 577,513 gallons per day in 2015. Gas gathering volumes per day in 2017 decreased primarily due to lower volumes from our fee-based Appalachian systems. Volumes processed decreased primarily due to lower purchased volumes and fewer new wells connected to our processing systems in 2017. NGLs sold decreased primarily due to lower purchased volumes and continuing to operate most of our systems in ethane rejection mode.
At-the-Market (ATM) Common Stock Program
On April 4, 2017, we entered into a Distribution Agreement (the Agreement) with a sales agent, under which we may offer and sell,lenders party thereto from time to time through(Lenders), and (iv) BOKF, NA dba Bank of Oklahoma as administrative agent and collateral agent (in such capacity, the sales agent sharesAdministrative Agent). The maturity date of our common stock, par value $0.20 per share (the Shares), up to an aggregate offering price of $100.0 million. We intend to useborrowings under this Exit credit agreement is March 1, 2024.
Our Exit credit agreement is primarily used for working capital purposes as it limits the net proceeds from these sales to fund (or offset costs of) acquisitions,amount that can be borrowed for capital expenditures. These limitations restrict future capital expenditures, repay amounts outstanding under our revolving credit facility, and general corporate purposes.
Underprojects using the Agreement, the sales agent may sell the Shares by methods deemed to be an “at-the-market” offering as defined in Rule 415 promulgated under the Securities Act of 1933, as amended, including sales made directly on the NYSE, on any other existing trading market for the Shares or to or through a market maker. In addition, under the Agreement, the sales agent may sell the Shares by any other method permitted by law, including in privately negotiated transactions. Subject to the terms of the Agreement, the sales agent will use commercially reasonable efforts, consistent with its normal trading and sales practices and applicable state and federal law, rules and regulations and the rules of the NYSE, to sell the Shares from time to time, based on our instructions (including any price, time or size limits or other customary parameters or conditions we may impose).
We do not have to make any sales of the Shares under the Agreement. The offering of Shares under the Agreement will terminate on the earlier of (1) the sale of all of the Shares subject to the Agreement or (2) the termination of the Agreement by the sales agent or us. We will pay the sales agent a commission of 2.0% of the gross sales price per share sold and have agreed to provide the sales agent with customary indemnification and contribution rights.
Since entering into the Agreement through February 13, 2018, we have sold 787,547 shares of our common stock resulting in net proceeds of approximately $18.6 million. No shares were sold in the fourth quarter of 2017. Approximately $81.0 million remain available for sale under the program.
Our Credit Agreement and Senior Subordinated Notes
Credit Agreement. On April 8, 2016, we amended our Senior Credit Agreement (credit agreement) scheduled to mature on April 10, 2020. The amount we can borrow is the lesser of the amount we elect (from time to time) as the commitment amount or the value of the borrowing base as determined by the lenders, but in either event not to exceed the maximum credit agreement amount of $875.0 million. Our elected commitment amount is $475.0 million. Our borrowing base is $475.0 million. We are charged a commitment fee of 0.50% on the amount available but not borrowed. The fee varies based on the amount borrowed as a percentage of the total borrowing base. We paid $1.0 million in origination, agency, syndication, and other related fees. We are amortizing these fees over the life of theExit credit agreement. With the new amendment, we pledged the following collateral: (a) 85% of the proved developed producing (discounted as present worth at 8%) total value of our oil and gas properties and (b) 100% of our ownership interest in our mid-stream affiliate, Superior Pipeline Company, L.L.C.
The lenders under our credit agreement and their respective participation interests are:
|
| | |
Lender | Participation
Interest
|
BOK (BOKF, NA, dba Bank of Oklahoma) | 17 | % |
Compass Bank | 17 | % |
BMO Harris Financing, Inc. | 15 | % |
Bank of America, N.A. | 15 | % |
Comerica Bank | 8 | % |
Wells Fargo Bank, N.A. | 8 | % |
Canadian Imperial Bank of Commerce | 8 | % |
Toronto Dominion (New York), LLC | 8 | % |
The Bank of Nova Scotia | 4 | % |
| 100 | % |
The borrowing base amount–which is subject to redetermination by the lenders on April 1st and October 1st of each year, is based primarily on a percentage of the discounted future value of our oil and natural gas reserves and on our cash flows from our mid-stream segment. The October 2017 redetermination did not result in any changes. We or the lenders may request a
onetime special redetermination of the borrowing base between each scheduled redetermination. In addition, we may request a redetermination following the completion of an acquisition that meets the requirements in the credit agreement.
At our election, any part of the outstanding debt under the credit agreement may be fixed at a London Interbank Offered Rate (LIBOR). LIBOR interest is computed as the sum of the LIBOR base for the applicable term plus 2.00% to 3.00% depending on the level of debt as a percentage of the borrowing base and is payable at the end of each term, or every 90 days, whichever is less. Borrowings not under LIBOR bear interest at the prime rate specified in the credit agreement that cannot be less than LIBOR plus 1.00% plus a margin. Interest is payable at the end of each month and the principal may be repaid in whole or in part at any time, without a premium or penalty. At December 31, 2017 and February 13, 2018, we had $178.0 million and $173.8 million, respectively, outstanding borrowings under our credit agreement.
We can use borrowings for financing general working capital requirements for (a) exploration, development, production and acquisition of oil and gas properties, (b) acquisitions and operation of mid-stream assets, (c) issuance of standby letters of credit, (d) contract drilling services, and (e) general corporate purposes.
The credit agreement prohibits, among other things:
the payment of dividends (other than stock dividends) during any fiscal year over 30% of our consolidated net income for the preceding fiscal year;
the incurrence of additional debt with certain limited exceptions; and
the creation or existence of mortgages or liens, other than those in the ordinary course of business, on any of our properties, except for our lenders.
TheExit credit agreement also requires that we have atproceeds from the enddisposition of each quarter: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 current ratio (as definedreduction 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)agreement with cash generated from operations as well as from proceeds from divestitures of not less than 1 to 1.non-core assets. As of December 31, 2021, we had no outstanding long-term borrowings under the Exit credit agreement.
Through the quarter ending March 31, 2019,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 agreement also requires that we have at the end of each quarter:
a senior indebtedness ratio of senior indebtednessamount up to consolidated EBITDA (as defined in the credit agreement) for the most recently ended rolling four quarters of no greater than 2.75 to 1.
Beginning with the quarter ending June 30, 2019, and for each quarter ending thereafter, the credit agreement requires:
a leverage ratio of funded debt to consolidated EBITDA (as defined in the credit agreement) for the most recently ended rolling four fiscal quarters of no greater than 4 to 1.
As of December 31, 2017, we were in compliance with the covenants in the credit agreement.
6.625% Senior Subordinated Notes. We have an aggregate principal amount of $650.0$250.0 million, 6.625% senior subordinated notes (the Notes). Interest on the Notes is payable semi-annually (in arrears) on May 15 and November 15 of each year. The Notes will mature on May 15, 2021. In issuing the Notes, we incurred $14.7 million of fees that are being amortized as debt issuance cost over the life of the Notes.
The Notes are subject to an Indenture dated as of May 18, 2011, between us and Wilmington Trust, National Association (successor to Wilmington Trust FSB), as Trustee (the 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 and providing for issuing the Notes. The Guarantors are our direct and indirect subsidiaries. The discussion of the Notes in this report is qualified by and subject to the actual terms of the 2011 Indenture.
Unit, as the parent company, has no independent assets or operations. The guarantees by the Guarantors of the Notes (registered under registration statements) are full and unconditional, joint and several, subject to certain automatic customary releases, are subject to certain restrictions on the sale, disposition, or transfer of the capital stock or substantially all of the assets of a subsidiary guarantor, and other conditions and terms set out in the Indenture. Any of our subsidiaries that are not Guarantors are minor. There are no significant restrictions on our ability to receive funds from our subsidiaries through dividends, loans, advances or otherwise.
We may redeem all or, from time to time, a part of the Notes at certain redemption prices, plus accrued and unpaid interest. If a “change of control” occurs, subject to certain conditions we must offer to repurchase from each holder all or any part of that holder’s Notes at a purchase price in cash equal to 101% of the principal amount of the Notes plus accrued and unpaid interest, if any, to the(Superior credit agreement). The maturity date of purchase. The 2011 Indenture contains customary events of default. The 2011 Indenture also contains covenants that, among other things, limit our ability andborrowings under the ability of certain of our subsidiaries to incur or guarantee additional indebtedness; pay dividends on our capital stock or redeem capital stock or subordinated indebtedness; transfer or sell assets; make investments; incur liens; enter into transactions with our affiliates; and merge or consolidate with other companies. We were in compliance with all covenants of the Notes asSuperior credit agreement is March 10, 2023. As of December 31, 2017.2021, 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. Any decisionOur 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. We completed drilling 70 gross wells (25.71 net wells) in 2017 compared to 21 gross wells (9.67 net wells) in 2016, and 58 gross wells (34.99 net wells) in 2015.
On April 3, 2017, we closed an acquisition of certain oil and natural gas assets located primarily in Grady and Caddo Counties in western Oklahoma. The final adjusted value of consideration given was $54.3 million. As of January 1, 2017, the effective date of the acquisition, the estimated proved oil and gas reserves of the acquired properties were 3.2 million barrels of oil equivalent (MMBoe). The acquisition added approximately 8,300 net oil and gas leasehold acres to our core Hoxbar area in southwestern Oklahoma including approximately 47 proved developed producing wells. This acquisition included 13 potential horizontal drilling locations not otherwise included in our existing acreage. Of the acreage acquired, approximately 71% was held by production. We also received one gathering system as part of the transaction.
Capital expenditures for oil and gas properties on the full cost method for 2017the 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 $59.0$0.4 million infor acquisitions (including associated ARO), totaled $215.4 million$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 2016 capital expenditures of $119.9 million (excluding a $30.9 million reduction in the ARO liability and $0.6 million in acquisitions), and 2015 capital expenditures of $273.5 million (excluding an $5.7 million reduction in the ARO liability and $0.2 million in acquisitions).
For 2018, we plan to participate in drilling approximately 75 to 853 gross wells (0.30 net wells) drilled by other operators in which we participated during the four months ended December 31, 2020 and estimate our total capital expenditures (excluding any possible acquisitions) for our oil16 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 natural gas segment will be approximately $272.0 million. Whethersale agreement to which we drillagreed to sell substantially all of thoseour wells depends on several factors, many of which are beyond our control and include the availability of drilling rigs, availability of pressure pumping services, prices for oil, NGLs, and natural gas, demand for oil, NGLs, and natural gas, the cost to drill wells, the weather, and the effortsleases 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 outside industry partners.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, for $18.6 million, $67.2 million, and $1.9during the year ended December 31, 2021, compared to $0.4 million during 2017, 2016,the four months ended December 31, 2020, and 2015, respectively. Proceeds from those dispositions reduced$1.2 million during the net book value of our full cost pool with noeight months ended August 31, 2020. No gain or loss recognized.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. During 2015, we recorded a write-downCapital expenditures for 2021 were primarily related to maintenance capital on 31operating drilling rigs. We also pursued the disposal or sale of our drilling rigs and related equipment of approximately $8.3 million pre-tax based on the estimated market value for similar equipment from auctions sales. We then sold all 31 of these drilling rigs and some other drilling equipment to unaffiliated third parties. The proceeds from the sale of those assets, less costs to sell, was less than the $11.3 million net book value resulting in a loss of $7.3 million pre-tax.
During 2015, five BOSS drilling rigs were constructed and placed into service for third-party operators.
During December 2016, we sold annon-core, idle 1500 HP SCR drilling rig to an unaffiliated third party.fleet. We also fabricated and placed into service our ninth new BOSS drilling rig for a third party operator. This new BOSS rig was constructed using the long lead time components purchasedincurred $2.9 million in prior years.
During 2017, we built our tenth BOSS drilling rig and placed it into service for a third party operator under a long term contract. We also returned to service 14 SCR drilling rigs that had been previously stacked.
Our anticipated 2018 capital expenditures for this segment is approximately $47.0 million. We spent $36.1 million for capital expenditures during 2017the year ended December 31, 2021 compared to $19.1$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 2016,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 $84.8$1.4 million in 2015.during the eight months ended August 31, 2020.
Mid-Stream Dispositions, Acquisitions, and Capital Expenditures. At our Cashion processing facility in central Oklahoma, our total throughput volume forDuring the fourth quarter of 2017 averaged approximately 37.3 MMcf per day and our total production of natural gas liquids increased to approximately 198,600 gallons per day. The total processing capacity at this facility is approximately 45 MMcf per day. During 2017, we connected 12 new wells to this system from three producers. We are continuing a pipeline extension project for a producer scheduled to actively drill in the Cashion area in 2018. We have already connected four new wells from this producer and anticipate connecting several more wells throughout 2018. As volume increases on this system, we will evaluate the need to add additional processing capacity. If volume continues to increase, we may need to add an additional processing plant in the Cashion area.
At our Hemphill processing facility in the Texas panhandle, our average gathered volume for the fourth quarter of 2017 was approximately 68.5 MMcf per day and our total production of natural gas liquids increased to 188,600 gallons per day. During 2017, we connected six new wells to this processing system with several more wells scheduled to be connected in the first part of 2018. We have completed construction of the pipeline to connect the next well pad and we are upgrading our compression facilities to handles the expected additional volume.
At our Bellmon processing facility in the Mississippian play in north central Oklahoma, during 2017 we connected 14 new wells to this system. Our total throughput volume for the fourth quarter of 2017 averaged approximately 27 MMcf per day. We have two processing skids available that provide total processing capacity of 90 MMcf per day.
At our Segno gathering facility in Southeast Texas, our average gathered volume for the fourth quarter of 2017 was approximately 86.4 MMcf per day. The gathering and dehydration capacity for this facility is approximately 120 MMcf per day. During 2017, we connected three new wells to this gathering system along with additional volume from recompletion activity in the area around our system.
In the Appalachian region, at our Pittsburgh Mills gathering system, we continue to connect new well pads to this system. During 2017, we connected one new well pad with five new wells to this gathering system. By adding these new wells our average gathered volume for the fourth quarter was approximately 117.2 MMcf per day. We are constructing a new pipeline to connect the next well pad to this system. Most of the preliminary environmental and permitting activities have been completed and right of way has been obtained. In the first quarter of 2018, we will start the construction of the pipeline with an expected completion date in the third quarter of 2018. This new well pad is expected to have seven wells drilled and we anticipate receiving gas from this pad at the end of 2018. This well pad is on the south end of our system and will be connected to our Kissick compressor station. And we have been notified by the producer they will drill seven infill wells on already existing pads in 2018.
During 2017,year ended December 31, 2021, our mid-stream segment incurred $22.2$24.5 million in capital expenditures as(including the $13.0 million acquisition of a gathering and processing system in southern Kansas) compared to $16.8$1.3 million in 2016, and $63.5$9.3 million in 2015. For 2018, our estimated capital expenditures is approximately $32.0 million.during the four months ended December 31, 2020 and eight months ended August 31, 2020, respectively.
Contractual Commitments
AtWe had the following contractual commitments as of December 31, 2017, we had these contractual obligations:2021:
| | | | Payments Due by Period | | Payments Due by Period |
| | Total | | Less Than 1 Year | | 2-3 Years | | 4-5 Years | | After 5 Years | | Total | | Less Than 1 Year | | 2-3 Years | | 4-5 Years | | After 5 Years |
| | (In thousands) | | (In thousands) |
Long-term debt (1) | $ | 986,931 |
| | $ | 49,133 |
| | $ | 271,871 |
| | $ | 665,927 |
| | $ | — |
| Long-term debt (1) | $ | 19,200 | | | $ | — | | | $ | 19,200 | | | $ | — | | | $ | — | |
Operating leases (2) | 3,878 |
| | 2,717 |
| | 1,024 |
| | 137 |
| | — |
| Operating leases (2) | 14,001 | | | 4,382 | | | 6,004 | | | 3,565 | | | 50 | |
Capital lease interest and maintenance (3) | 7,048 |
| | 2,324 |
| | 4,172 |
| | 552 |
| | — |
| |
Drill pipe, drilling components, and equipment purchases (4) | 3,887 |
| | 3,887 |
| | — |
| | — |
| | — |
| |
Firm transportation commitments (3) | | Firm transportation commitments (3) | 880 | | | 880 | | | — | | | — | | | — | |
| Total contractual obligations | $ | 1,001,744 |
| | $ | 58,061 |
| | $ | 277,067 |
| | $ | 666,616 |
| | $ | — |
| Total contractual obligations | $ | 34,081 | | | $ | 5,262 | | | $ | 25,204 | | | $ | 3,565 | | | $ | 50 | |
_________________________
| |
(1) | See previous discussion in MD&A regarding our long-term debt. This obligation is presented under the Notes and credit agreement and includes interest calculated using our December 31, 2017 interest rates1.Represents outstanding borrowings as of 6.625% for the Notes and 3.4% for the credit agreement. |
| |
(2) | We lease office space or yards in Edmond and Oklahoma City, Oklahoma; Houston, Texas; Englewood, Colorado; Pinedale, Wyoming; and Canonsburg, Pennsylvania under the terms of operating leases expiring through December 2021. And, we have several equipment leases and lease space on short-term commitments to stack excess drilling rig equipment and production inventory. |
| |
(3) | Maintenance and interest payments are included in our capital lease agreements. The capital leases are discounted using annual rates of 4.0%. Total maintenance and interest remaining are $5.9 million and $1.2 million, respectively. |
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(4) | We have committed to purchase approximately $3.9 million of new drilling rig components over the next year. |
At December 31, 2017, we also had these2021 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 and contingencies that could create, increase or accelerateto transport our liabilities:natural gas from various systems.
|
| | | | | | | | | | | | | | | | | | | |
| | Estimated Amount of Commitment Expiration Per Period |
| Other Commitments | Total Accrued | | Less Than 1 Year | | 2-3 Years | | 4-5 Years | | After 5 Years |
| | (In thousands) |
Deferred compensation plan (1) | $ | 5,390 |
| | Unknown |
| | Unknown |
| | Unknown |
| | Unknown |
|
Separation benefit plans (2) | $ | 6,524 |
| | $ | 657 |
| | Unknown |
| | Unknown |
| | Unknown |
|
ARO liability (3) | $ | 69,444 |
| | $ | 1,726 |
| | $ | 42,409 |
| | $ | 3,908 |
| | $ | 21,401 |
|
Gas balancing liability (4) | $ | 3,283 |
| | Unknown |
| | Unknown |
| | Unknown |
| | Unknown |
|
Repurchase obligations (5) | $ | — |
| | Unknown |
| | Unknown |
| | Unknown |
| | Unknown |
|
Workers’ compensation liability (6) | $ | 13,340 |
| | $ | 6,775 |
| | $ | 1,712 |
| | $ | 917 |
| | $ | 3,936 |
|
Capital lease obligations (7) | $ | 15,224 |
| | $ | 3,844 |
| | $ | 8,164 |
| | $ | 3,216 |
| | $ | — |
|
| Derivative liabilities—commodity hedges | $ | 7,763 |
| | $ | 7,763 |
| | $ | — |
| | $ | — |
| | $ | — |
|
_________________________
| |
(1) | We provide a salary deferral plan which allows participants to defer the recognition of salary for income tax purposes until actual distribution of benefits, which occurs at either termination of employment, death or certain defined unforeseeable emergency hardships. We recognize payroll expense and record a liability, included in other long-term liabilities in our Consolidated Balance Sheets, at the time of deferral. |
| |
(2) | Effective January 1, 1997, we adopted a separation benefit plan (Separation Plan). The Separation Plan allows eligible employees whose employment with us is involuntarily terminated or with an employee who has completed 20 years of service, voluntarily or involuntarily terminated, to receive benefits equivalent to four weeks salary for every whole year of service completed with the company up to a maximum of 104 weeks. To receive payments the recipient must waive certain claims against us in exchange for receiving the separation benefits. On October 28, 1997, we adopted a Separation Benefit Plan for Senior Management (Senior Plan). The Senior Plan provides certain officers and key executives of the company with benefits generally equivalent to the Separation Plan. The Compensation Committee of the Board of Directors has absolute discretion in the selection of the individuals covered in this plan. On May 5, 2004 we also adopted the Special Separation Benefit Plan (Special Plan). This plan is identical to the Separation Benefit Plan with the exception that the benefits under the plan vest on the earliest of a participant’s reaching the age of 65 or serving 20 years with the company. |
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(3) | When a well is drilled or acquired, under ASC 410 “Accounting for Asset Retirement Obligations,” we record the fair value of liabilities associated with the retirement of long-lived assets (mainly plugging and abandonment costs for our depleted wells). |
| |
(4) | We have recorded a liability for those properties we believe do not have sufficient oil, NGLs, and natural gas reserves to allow the under-produced owners to recover their under-production from future production volumes. |
| |
(5) | We formed The Unit 1984 Oil and Gas Limited Partnership and the 1986 Energy Income Limited Partnership along with private limited partnerships (the Partnerships) with certain qualified employees, officers and directors from 1984 through 2011. One of our subsidiaries serves as the general partner of each of these programs. Effective December 31, 2014, the 1984 partnership was dissolved and effective December 31, 2016, the two 1986 partnerships were also dissolved. The Partnerships were formed to conduct oil and natural gas acquisition, drilling and development operations and serving as co-general partner with us in any additional limited partnerships formed during that year. The Partnerships participated on a proportionate basis with us in most drilling operations and most producing property acquisitions commenced by us for our own account during the period from the formation of the Partnership through December 31 of that year. These partnership agreements require, on the election of a limited partner, that we repurchase the limited partner’s interest at amounts to be determined by appraisal in the future. Repurchases in any one year are limited to 20% of the units outstanding. We made repurchases of approximately $2,900, $5,000, and $118,000 in 2017, 2016, and 2015, respectively. |
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(6) | We have recorded a liability for future estimated payments related to workers’ compensation claims primarily associated with our contract drilling segment. |
| |
(7) | This amount includes commitments under capital lease arrangements for compressors in our mid-stream segment. |
Derivative Activities
Periodically we enter into derivative transactions locking in the prices to be received for a portion of our oil, NGLs, and natural gas production. Any change in the fair value of all our derivatives are reflected in the statement of operations.
Commodity Derivatives. Our commodity derivatives shouldare 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, 2017,2021, based on our fourth quarter 20172021 average daily production, the approximated percentages of our production under derivative contracts are as follows:
| | | | Mark-to-Market | |
| | 2018 | | | | | | | | | | | | |
| | Q1 | | Q2 | | Q3 | | Q4 | | 2022 | | 2023 |
| Daily oil production | 70 | % | | 63 | % | | 63 | % | | 63 | % | Daily oil production | | 53% | | 24% |
| Daily natural gas production | 53 | % | | 33 | % | | 33 | % | | 29 | % | Daily natural gas production | | 50% | | 28% |
| Daily NGLs production | — | % | | 7 | % | | 7 | % | | — | % | |
Regarding the commodities subject to derivative contracts, those contracts limit the risk of adverse downward price movements. However, they also limit increases in future revenues that would otherwise result from price movements above the contracted prices.
Using derivative transactions hasinstruments involves the risk that the counterparties may notcannot meet theirthe financial obligations underterms of the transactions. Based onWe considered this non-performance risk regarding our evaluationcounterparties and our own non-performance risk in our derivative valuation at December 31, 2017, we believe the2021 and determined there was no material risk of non-performance by our counterparties is not material. At December 31, 2017, theat that time. The fair valuesvalue of the net assets (liabilities)liabilities we had with eachBank of Oklahoma, our only commodity derivative counterparty, was $58.7 million as of December 31, 2021.
Warrants
We recognize the fair value of the counterpartieswarrants 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 our commoditybe 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.
Below is the effect of derivative transactions are:instruments on the consolidated statements of operations for the periods indicated:
|
| | | |
| | December 31, 2017 |
| | (In millions) |
| Canadian Imperial Bank of Commerce | $ | 0.7 |
|
| Bank of America Merrill Lynch | (2.5 | ) |
| Bank of Montreal | (5.3 | ) |
| Total assets (liabilities) | $ | (7.1 | ) |
| | | | | | | | | | | | | | | | | | | | | | |
| 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 inon our Consolidated Balance Sheets. At December 31, 2017, we recorded theconsolidated balance sheets. The fair value of our commodity derivatives on our consolidated balance sheet as current derivative assets of $0.7 million andsheets were current derivative liabilities of $7.8 million. At$40.9 million and long-term derivative liabilities of $17.9 million as of December 31, 2016, we recorded the fair value2021 compared to current derivative liabilities of our commodity derivatives on our balance sheet as non-current derivative assets of $0.4$1.0 million and current and non-current derivative liabilities of $21.6$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 $0.4 million, respectively.
All derivatives are recognized on the balance sheet and measured at fair value. Any changes in our derivatives'361,418 stock options with an aggregate grant date fair value before their maturity (i.e., temporary fluctuations in value) are reported in gain (loss)of $4.1 million. Director RSU grants will 25% vest on derivatives in our Consolidated Statements of Operations.
These gains (losses) are as follows at December 31: |
| | | | | | | | | | | |
| | 2017 | | 2016 | | 2015 |
| | (In thousands) |
| Gain (loss) on derivatives, included are amounts settled during the period of $173, $9,658, and $46,615, respectively | $ | 14,732 |
| | $ | (22,813 | ) | | $ | 26,345 |
|
Stock and Incentive Compensation
During 2017, we granted awards covering 708,276 shares of restricted stock. These awards were granted as retention incentive awards. These stock awards had an estimated fair value aseach of the grant datefollowing 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 $17.4 million. Compensation expensethe following dates: November 21, 2022, October 1, 2023, and October 1, 2024. The stock option grants will be recognized overone-third vest on each of the awards' three year vesting period. During 2017, we recognized $7.0 million in additional compensation expensefollowing dates: October 1, 2022, October 1, 2023, and capitalized $1.1 million for these awards. During 2016, we granted awards covering 736,451 shares of restricted stock. These awards were granted as retention incentive awards and are being recognized over the awards' three year vesting period. During 2015, we granted awards covering 750,290 shares of restricted stock. These awards were granted as retention incentive awards and are being recognized over their two and three year vesting periods. No SAR awards were made during 2017, 2016, or 2015.
During 2017, weOctober 1, 2024. We recognized compensation expense of $13.3$0.8 million for our restricted stock grants and capitalized $1.8 million ofduring the year ended December 31, 2021. We did not capitalize any compensation cost forto oil and natural gas properties.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.
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.
Oil and Natural Gas Limited Partnerships
Oil and Other Entity Relationships.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.
We areOil and natural gas operating costs decreased $62.6 million or 43% during the general partneryear ended December 31, 2021 compared to the year ended December 31, 2020 primarily due to the absence of 13gains 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 partnerships formed privately or publicly. Each partnership’s revenues and costs are shared under formulas set out in that partnership’s agreement. The partnerships repay us for contract drilling, well supervision and general and administrative expense. Related party transactions for contract drilling and well supervision fees areproperties decreased $419.8 million during the related party’s share of such costs. These costs are billed the same as billings to unrelated third parties for similar services. General and administrative reimbursements consist of direct general and administrative expense incurred on the related party’s behalf and indirect expenses assignedyear ended December 31, 2021 compared to the related parties. Allocations are based onyear ended December 31, 2020 due to the related party’s levelabsence of activitythe ceiling test write-downs and are considered by us to be reasonable. During 2017, 2016,salt water disposal asset impairment recorded during the year ended December 31, 2020.
Depreciation, depletion, and 2015, the total we received for these fees was $0.2 million, $0.3 million, and $0.4 million, respectively. Our proportionate shareamortization of assets, liabilities, and net income relating to the oil and natural gas partnerships is includedproperties 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 consolidated financial statements.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.
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. Commodity prices also can affect our fracking and completion costs. 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. Due to increased demand for drilling rigs and the need to maintain qualified labor, we increased pay for some
Off-Balance Sheet Arrangements
We do not currently utilize any off-balance sheet arrangements with unconsolidated entities to enhance liquidity and capital resource positions, or for any other purpose. However, as is customary in the oil and gas industry, we are subject to various contractual commitments.
Results of Operations
2017 versus 2016
|
| | | | | | | | | | |
| | 2017 | | 2016 | | Percent Change (1) |
| | (In thousands unless otherwise specified) | | |
| Total operating revenue | $ | 739,640 |
| | $ | 602,177 |
| | 23 | % |
| Net income (loss) | $ | 117,848 |
| | $ | (135,624 | ) | | 187 | % |
| | | | | | |
| Oil and Natural Gas: | | | | | |
| Revenue | $ | 357,744 |
| | $ | 294,221 |
| | 22 | % |
| Operating costs excluding depreciation, depletion, amortization, and impairment | $ | 130,789 |
| | $ | 120,184 |
| | 9 | % |
| Depreciation, depletion, and amortization | $ | 101,911 |
| | $ | 113,811 |
| | (10 | )% |
| Impairment of oil and gas properties | $ | — |
| | $ | 161,563 |
| | (100 | )% |
| | | | | | |
| Average oil price received (Bbl) | $ | 49.44 |
| | $ | 40.50 |
| | 22 | % |
| Average NGL price received (Bbl) | $ | 18.35 |
| | $ | 11.26 |
| | 63 | % |
| Average natural gas price received (Mcf) | $ | 2.46 |
| | $ | 2.07 |
| | 19 | % |
| Oil production (MBbls) | 2,715 |
| | 2,974 |
| | (9 | )% |
| NGLs production (MBbls) | 4,737 |
| | 5,014 |
| | (6 | )% |
| Natural gas production (MMcf) | 51,260 |
| | 55,735 |
| | (8 | )% |
| Depreciation, depletion, and amortization rate (Boe) | $ | 6.00 |
| | $ | 6.24 |
| | (4 | )% |
| | | | | | |
| Contract Drilling: | | | | | |
| Revenue | $ | 174,720 |
| | $ | 122,086 |
| | 43 | % |
| Operating costs excluding depreciation | $ | 122,600 |
| | $ | 88,154 |
| | 39 | % |
| Depreciation | $ | 56,370 |
| | $ | 46,992 |
| | 20 | % |
| | | | | | |
| Percentage of revenue from daywork contracts | 100 | % | | 100 | % | | — | % |
| Average number of drilling rigs in use | 30.0 |
| | 17.4 |
| | 72 | % |
| Average dayrate on daywork contracts | $ | 16,256 |
| | $ | 17,784 |
| | (9 | )% |
| | | | | | |
| Mid-Stream: | | | | | |
| Revenue | $ | 207,176 |
| | $ | 185,870 |
| | 11 | % |
| Operating costs excluding depreciation and amortization | $ | 155,483 |
| | $ | 137,609 |
| | 13 | % |
| Depreciation and amortization | $ | 43,499 |
| | $ | 45,715 |
| | (5 | )% |
| | | | | | |
| Gas gathered—Mcf/day | 385,209 |
| | 419,217 |
| | (8 | )% |
| Gas processed—Mcf/day | 137,625 |
| | 155,461 |
| | (11 | )% |
| Gas liquids sold—gallons/day | 534,140 |
| | 536,494 |
| | — | % |
| | | | | | |
| Corporate and other: | | | | | |
| General and administrative expense | $ | 38,087 |
| | $ | 33,337 |
| | 14 | % |
| Other depreciation | $ | 7,477 |
| | $ | 1,835 |
| | NM |
|
| Gain on disposition of assets | $ | 327 |
| | $ | 2,540 |
| | (87 | )% |
| Other income (expense): | | | | | |
| Interest expense, net | $ | (38,334 | ) | | $ | (39,829 | ) | | (4 | )% |
| Gain (loss) on derivatives | $ | 14,732 |
| | $ | (22,813 | ) | | 165 | % |
| Other | $ | 21 |
| | $ | 307 |
| | (93 | )% |
| Income tax benefit | $ | (57,678 | ) | | $ | (71,194 | ) | | 19 | % |
| Average interest rate | 6.0 | % | | 5.7 | % | | 5 | % |
| Average long-term debt outstanding | $ | 810,734 |
| | $ | 868,332 |
| | (7 | )% |
_________________________ | |
(1) | NM – A percentage calculation is not meaningful due to a zero-value denominator or a percentage change greater than 200. |
Oil and Natural Gas
Oil and natural gas revenues increased $63.5 million or 22% in 2017 as compared to 2016 due primarily to higher commodity prices partially offset by a decrease in production. Oil production decreased 9%, NGLs production decreased 6%, and natural gas production decreased 8%. Average oil prices between the comparative years increased 22% to $49.44 per barrel, NGLs prices increased 63% to $18.35 per barrel, and natural gas prices increased 19% to $2.46 per Mcf.
Oil and natural gas operating costs increased $10.6 million or 9% between the comparative years of 2017 and 2016 primarily due to higher LOE and gross production taxes partially offset by lower saltwater disposal expense.
DD&A decreased $11.9 million or 10% primarily due to a 4% decrease in our DD&A rate and by the effect of a 7% decrease in equivalent production. The decrease in our DD&A rate in 2017 compared to 2016 resulted primarily from the effect of the ceiling test write-downs throughout 2016. Our DD&A expense on our oil and natural properties is calculated each quarter using period end reserve quantities adjusted for period production.
During 2016, we recorded non-cash ceiling test write-downs of our oil and natural gas properties totaling $161.6 million pre-tax ($100.6 million net of tax). We did not have a non-cash ceiling test write-down in 2017. The write-downs were due primarily from the reduction of the 12-month average commodity prices during 2016.
Contract Drilling
Drilling revenues increased $52.6 million or 43% in 2017 as compared to 2016. The increase was due primarily to a 72% increase in the average number of drilling rigs in use partially offset by a 9% decrease in the average dayrate compared to 2016. Average drilling rig utilization increased from 17.4 drilling rigs in 2016 to 30.0 drilling rigs in 2017.
Drilling operating costs increased $34.4 million or 39% in 2017 compared to 2016. The increase was due primarily to more drilling rigs operating. Contract drilling depreciation increased $9.4 million or 20% also due primarily to more drilling rigs operating.
Mid-Stream
Our mid-stream revenues increased $21.3 million or 11% in 2017 as compared to 2016 primarily due to increased NGLs and condensate sales. Gas processing volumes per day decreased 11% between the comparative years primarily due to fewer new well connections to our processing systems. Gas gathering volumes per day decreased 8% primarily due to declining volumes in the Appalachian region.
Operating costs increased $17.9 million or 13% in 2017 compared to 2016 primarily due to increased natural gas, NGLs, and condensate prices. Depreciation and amortization decreased $2.2 million or 5% primarily due to less capital expenditures this year while older assets became fully depreciated.
General and Administrative
General and administrative expenses increased $4.8 million or 14% in 2017 compared to 2016 primarily due to higher employee costs.
Other Depreciation
Other depreciation increased $5.6 million in 2017 compared to 2016 primarily due to the depreciation on the new ERP system and the corporate office facility.
Gain on Disposition of Assets
Gain on disposition of assets decreased $2.2 million in 2017 compared to 2016. The gain in 2017 was primarily for the sale of a corporate aircraft and vehicles, while the pre-tax gain of $3.2 million in 2016 was primarily for the sale of one drilling rig, various drilling rig components, vehicles, and other equipment somewhat offset by losses from our oil and natural gas and mid-stream segments in 2016.
Other Income (Expense)
Interest expense, net of capitalized interest, decreased $1.5 million between the comparative years of 2017 and 2016. We capitalized interest based on the net book value associated with unproved properties not being amortized, the construction of additional drilling rigs, and the construction of gas gathering systems. Capitalized interest for 2017 was $15.9 million compared to $15.3 million in 2016, and was netted against our gross interest of $54.2 million and $55.1 million for 2017 and 2016, respectively. Our average interest rate increased from 5.7% to 6.0% and our average debt outstanding was $57.6 million lower in 2017 as compared to 2016 primarily due to the decrease in our outstanding borrowings under our credit agreement over the comparative periods.
Gain (loss) on derivatives increased from a loss of $22.8 million in 2016 to a gain of $14.7 million in 2017 primarily due to fluctuations in forward prices used to estimate the fair value in mark-to-market accounting.
Income Tax Benefit
Income tax benefit decreased $13.5 million in 2017 compared to 2016 primarily. During the fourth quarter of 2017, the U.S. government enacted the Tax Cuts and Jobs Act (the Tax Act). Among other provisions, the Tax Act reduces the federal corporate tax rate from the existing maximum rate of 35% to 21%, effective January 1, 2018. As a result of the Tax Act, the Company recorded a tax benefit of $81.3 million due to a revaluation of our net deferred tax liability. Without this income tax benefit charge, income tax expense would have been $23.6 million in 2017 compared to an income tax benefit of $71.2 million in 2016 or an increase of $94.8 million which is commensurate with the increase in pre-tax income for 2017 compared to 2016.
Our effective tax rate was (95.9%) for 2017 compared to 34.4% for 2016. The effective tax rate for the current year was dramatically lower due to the Tax Act and revaluation of our net deferred tax liability. Without the $81.3 million income tax benefit, our effective tax rate for 2017 would have been 39.3% The rate change without consideration of deferred tax liability revaluation was primarily due to increased deferred income tax expense related to our restricted stock vestings in both years whereby the increase in 2017 increased our deferred income tax expense and the increase in 2016 decreased our income tax benefit. We did not pay any income taxes during 2017.
2016 versus 2015
|
| | | | | | | | | | |
| | 2016 | | 2015 | | Percent Change (1) |
| | (In thousands unless otherwise specified) | | |
| Total operating revenue | $ | 602,177 |
| | $ | 854,231 |
| | (30 | )% |
| Net loss | $ | (135,624 | ) | | $ | (1,037,361 | ) | | 87 | % |
| | | | | | |
| Oil and Natural Gas: | | | | | |
| Revenue | $ | 294,221 |
| | $ | 385,774 |
| | (24 | )% |
| Operating costs excluding depreciation, depletion, amortization, and impairment | $ | 120,184 |
| | $ | 166,046 |
| | (28 | )% |
| Depreciation, depletion, and amortization | $ | 113,811 |
| | $ | 251,944 |
| | (55 | )% |
| Impairment of oil and natural gas properties | $ | 161,563 |
| | $ | 1,599,348 |
| | (90 | )% |
| | | | | | |
| Average oil price received (Bbl) | $ | 40.50 |
| | $ | 50.79 |
| | (20 | )% |
| Average NGLs price received (Bbl) | $ | 11.26 |
| | $ | 10.12 |
| | 11 | % |
| Average natural gas price received (Mcf) | $ | 2.07 |
| | $ | 2.63 |
| | (21 | )% |
| Oil production (MBbls) | 2,974 |
| | 3,783 |
| | (21 | )% |
| NGLs production (MBbls) | 5,014 |
| | 5,274 |
| | (5 | )% |
| Natural gas production (MMcf) | 55,735 |
| | 65,546 |
| | (15 | )% |
| Depreciation, depletion, and amortization rate (Boe) | $ | 6.24 |
| | $ | 12.30 |
| | (49 | )% |
| | | | | | |
| Contract Drilling: | | | | | |
| Revenue | $ | 122,086 |
| | $ | 265,668 |
| | (54 | )% |
| Operating costs excluding depreciation and impairment | $ | 88,154 |
| | $ | 156,408 |
| | (44 | )% |
| Depreciation | $ | 46,992 |
| | $ | 56,135 |
| | (16 | )% |
| Impairment of contract drilling equipment | $ | — |
| | $ | 8,314 |
| | (100 | )% |
| | | | | | |
| Percentage of revenue from daywork contracts | 100 | % | | 100 | % | | — | % |
| Average number of drilling rigs in use | 17.4 |
| | 34.7 |
| | (50 | )% |
| Average dayrate on daywork contracts | $ | 17,784 |
| | $ | 19,455 |
| | (9 | )% |
| | | | | | |
| Mid-Stream: | | | | | |
| Revenue | $ | 185,870 |
| | $ | 202,789 |
| | (8 | )% |
| Operating costs excluding depreciation, amortization, and impairment | $ | 137,609 |
| | $ | 161,556 |
| | (15 | )% |
| Depreciation and amortization | $ | 45,715 |
| | $ | 43,676 |
| | 5 | % |
| Impairment of gas gathering and processing systems | $ | — |
| | $ | 26,966 |
| | (100 | )% |
| | | | | | |
| Gas gathered—Mcf/day | 419,217 |
| | 353,771 |
| | 18 | % |
| Gas processed—Mcf/day | 155,461 |
| | 182,684 |
| | (15 | )% |
| Gas liquids sold—gallons/day | 536,494 |
| | 577,513 |
| | (7 | )% |
| | | | | | |
| Corporate and other: | | | | | |
| General and administrative expense | $ | 33,337 |
| | $ | 34,358 |
| | (3 | )% |
| Other depreciation | $ | 1,835 |
| | $ | 987 |
| | 86 | % |
| Gain (loss) on disposition of assets | $ | 2,540 |
| | $ | (7,229 | ) | | 135 | % |
| Other income (expense): | | | | | |
| Interest expense, net | $ | (39,829 | ) | | $ | (31,963 | ) | | 25 | % |
| Gain (loss) on derivatives | $ | (22,813 | ) | | $ | 26,345 |
| | (187 | )% |
| Other | $ | 307 |
| | $ | 45 |
| | NM |
|
| Income tax benefit | $ | (71,194 | ) | | $ | (626,948 | ) | | 89 | % |
| Average interest rate | 5.7 | % | | 5.4 | % | | 6 | % |
| Average long-term debt outstanding | $ | 868,332 |
| | $ | 897,391 |
| | (3 | )% |
_________________________
| |
(1) | NM – A percentage calculation is not meaningful due to a zero-value denominator or a percentage change greater than 200. |
Oil and Natural Gas
Oil and natural gas revenues decreased $91.6 million or 24% in 2016 as compared to 2015 due primarily to lower oil and natural gas prices and a decrease in production. Oil production decreased 21%, NGLs production decreased 5%, and natural gas production decreased 15%. Average oil prices between the comparative years decreased 20% to $40.50 per barrel, NGLs prices increased 11% to $11.26 per barrel, and natural gas prices decreased 21% to $2.07 per Mcf.
Oil and natural gas operating costs decreased $45.9 million or 28% between the comparative years of 2016 and 2015 due to lower LOE, saltwater disposal, and general and administrative expense.
DD&A decreased $138.1 million or 55% primarily due to a 49% decrease in our DD&A rate and by the effect of a 14% decrease in equivalent production. The decrease in our DD&A rate in 2016 compared to 2015 resulted primarily from the effect of the ceiling test write-downs during 2015 and 2016. Our DD&A expense on our oil and natural properties is calculated each quarter using period end reserve quantities adjusted for period production.
During 2016, we recorded non-cash ceiling test write-downs of our oil and natural gas properties totaling $161.6 million pre-tax ($100.6 million, net of tax) compared to a non-cash ceiling test write-down of our oil and natural gas properties of $1.6 billion pre-tax ($1.0 billion net of tax) in 2015. These write-downs were due primarily from the reduction of the 12-month average commodity prices during each year.
Contract Drilling
Drilling revenues decreased $143.6 million or 54% in 2016 as compared to 2015. The decrease was due primarily to a 50% decrease in the average number of drilling rigs in use, a 9% decrease in the average dayrate, and $25.9 million less received for fees on contracts terminated early in 2016 compared to 2015. Average drilling rig utilization decreased from 34.7 drilling rigs in 2015 to 17.4 drilling rigs in 2016.
Drilling operating costs decreased $68.3 million or 44% in 2016 compared to 2015. The decrease was due primarily to fewer drilling rigs operating. Contract drilling depreciation decreased $9.1 million or 16% also due primarily to fewer drilling rigs operating. During the second quarter of 2015, we recorded an impairment of approximately $8.3 million on 31 drilling rigs and other equipment sold at auction during the third quarter.
Mid-Stream
Our mid-stream revenues decreased $16.9 million or 8% in 2016 as compared to 2015 due primarily to gas sold per day decreasing 16% and NGLs sold per day decreasing 7%. Gas processing volumes per day decreased 15% between the comparative years primarily from fewer well connections near our processing systems. Gas gathering volumes per day increased 18% primarily from new well connections in the Appalachian region.
Operating costs decreased $23.9 million or 15% in 2016 compared to 2015 primarily due to a 6% decrease in prices paid for natural gas purchased and a 15% decrease in purchase volumes. Depreciation and amortization increased $2.0 million or 5% primarily due to capital expenditures for upgrades and well connects.
In December 2015, our mid-stream segment had a $27.0 million pre-tax write-down of three of its systems, Bruceton Mills, Midwell, and Spring Creek due to anticipated future cash flow and future development around these systems not being sufficient to support their carrying value. The estimated future cash flows were less than the carrying value on these systems.
Due to continued depressed NGLs prices, we were operating most of our processing facilities in full ethane rejection mode which reduced the liquids sold throughout 2016. Our mid-stream segment also experienced a reduction in processed volumes in 2016 due to the low pricing environment and reduced drilling activity around our systems.
General and Administrative
General and administrative expenses decreased $1.0 million or 3% in 2016 compared to 2015 primarily due to lower employee costs.
Other Depreciation
Other depreciation increased $0.8 million or 86% in 2016 compared to 2015 primarily due to the depreciation on the corporate office facility.
Gain (loss) on Disposition of Assets
Gain (loss) on disposition of assets increased $9.8 million in 2016 compared to 2015 primarily due to the gain of $3.2 million pre-tax on the sale of one drilling rig, various drilling rig components, vehicles, and other equipment somewhat offset by losses from our oil and natural gas and mid-stream segments, compared to a loss of $7.3 million pre-tax on the sale of 31 drilling rigs and other drilling equipment somewhat offset by the gains on the sale of one gathering system, various drilling rig components, vehicles, and a drilling rig during 2015.
Other Income (Expense)
Interest expense, net of capitalized interest, increased $7.9 million between the comparative years of 2016 and 2015. We capitalized interest based on the net book value associated with unproved properties not being amortized, the construction of additional drilling rigs, and the construction of gas gathering systems. Capitalized interest for 2016 was $15.3 million compared to $21.7 million in 2015, and was netted against our gross interest of $55.1 million and $53.7 million for 2016 and 2015, respectively. Our average interest rate increased from 5.4% to 5.7% and our average debt outstanding was $29.1 million lower in 2016 as compared to 2015 primarily due to the decrease in our outstanding borrowings under our credit agreement over the comparative periods.
Gain (loss) on derivatives decreased from a gain of $26.3 million in 2015 to a loss of $22.8 million in 2016 primarily due to fluctuations in forward prices used to estimate the fair value in mark-to-market accounting.
Income Tax Benefit
Income tax benefit decreased $555.8 million in 2016 compared to 2015 primarily due to a lower pre-tax loss from a reduction in non-cash ceiling test write-downs in 2016 compared to 2015. Our effective tax rate was 34.4% for 2016 and 37.7% for 2015. This decrease was primarily due to increased deferred tax expense in 2016 related to our restricted stock vestings in 2016 after the exhaustion of our remaining accumulated excess tax benefits. The current income tax benefit was minimal in 2016 compared to a current income tax benefit of $20.6 million for 2015. The $20.6 million current income tax benefit in 2015 was primarily due to an anticipated alternative minimum tax (AMT) net operating loss (NOL) carryback refund claim. We paid $42,000 in income taxes during 2016.
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
Our operations are exposed to market risks primarily because of changes in the prices for natural gas and oil and interest rates.
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 20172021 production, a $0.10 per Mcf change in what we are paid for our natural gas production would cause a corresponding $410,000$250 per month ($4.93.0 million annualized) change in our pre-tax cash flow. A $1.00 per barrel change in our oil price would have a $217,000$130 per month ($2.61.6 million annualized) change in our pre-tax operating cash flow and a $1.00 per barrel change in our NGLs prices would have a $380,000$220 per month ($4.62.6 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, 2017,2021, these non-designated hedges were outstanding:
|
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Term | | Commodity | | Contracted Volume | | Weighted Average Fixed Price for Swaps | | Contracted Market |
Jan’18 – Dec’18Jan'22 - Dec'22 | | Natural gas –- swap | | 20,0005,000 MMBtu/day | | $3.0132.605 | | IF –- NYMEX (HH) |
Apr'18 – Oct'18Jan'23 - Dec'23 | | Natural gas –- swap | | 10,00022,000 MMBtu/day | | $2.9902.456 | | IF –- NYMEX (HH) |
Jan’18 – Mar'18Jan'22 - Dec'22 | | Natural gas – basis swap- collar | | 10,00035,000 MMBtu/day | | $(0.208)2.50 - $2.68 | | IF –- NYMEX (HH) |
Nov’18 – Dec'18Jan'22 - Jun'22 | | Natural gas – basisCrude oil - swap | | 10,000 MMBtu/986 Bbl/day | | $(0.208)70.3 | | IF –WTI - NYMEX (HH) |
Jan’18 – Mar'18Jan'22 - Dec'22 | | Natural gas – three-way collarCrude oil - swap | | 60,000 MMBtu/2,300 Bbl/day | | $3.2942.25 | | WTI - $2.63 - $4.07 | | IF – NYMEX (HH) |
Apr’18 – Dec'18Jan'23 - Dec'23 | | Natural gas – three-way collar | | 20,000 MMBtu/day | | $3.00 - $2.50 - $3.51 | | IF – NYMEX (HH) |
Jan’18 – Dec'18 | | Crude oil –- swap | | 3,0001,300 Bbl/day | | $51.3643.60 | | WTI –- NYMEX |
Jan’18 – Mar'18 | | Crude oil – collar | | 500 Bbl/day | | $55.00 - $59.50 | | WTI – NYMEX |
Jan’18 – Dec'18 | | Crude oil – three-way collar | | 2,000 Bbl/day | | $47.50 - $37.50 - $56.08 | | WTI – NYMEX |
Apr’18 – Sep'18 | | Liquids (Propane) – swap | | 1,000 Bbl/day | | $31.16 | | MONT BELVIEU |
After December 31, 2017, these non-designated hedges were entered into:
|
| | | | | | | | |
Term | | Commodity | | Contracted Volume | | Weighted Average
Fixed Price for Swaps | | Contracted Market |
Apr’18 – Sep'18 | | Natural gas – swap | | 10,000 MMBtu/day | | $2.925 | | IF – NYMEX (HH) |
Apr’18 – Sep'18 | | Natural gas – collar | | 30,000 MMBtu/day | | $2.67 - $2.97 | | IF – NYMEX (HH) |
Feb’18 – Dec'18 | | Natural gas – basis swap | | 10,000 MMBtu/day | | $(0.678) | | PEPL |
Feb’18 – Dec'18 | | Natural gas – basis swap | | 10,000 MMBtu/day | | $(0.568) | | NGPL MIDCON |
Apr’18 – Oct'18 | | Natural gas – basis swap | | 10,000 MMBtu/day | | $(0.190) | | NGPL TEXOK |
Jan'19 – Dec'19 | | Natural gas – basis swap | | 10,000 MMBtu/day | | $(0.728) | | PEPL |
Jan'19 – Dec'19 | | Natural gas – basis swap | | 10,000 MMBtu/day | | $(0.625) | | NGPL MIDCON |
Jan'19 – Dec'19 | | Natural gas – basis swap | | 20,000 MMBtu/day | | $(0.273) | | NGPL TEXOK |
Jan'20 – Dec'20 | | Natural gas – basis swap | | 20,000 MMBtu/day | | $(0.280) | | NGPL TEXOK |
Apr'18 – Dec'18 | | Crude oil – swap | | 1,000 Bbl/day | | $60.00 | | WTI – NYMEX |
Apr’18 – Sep'18 | | Liquids – swap | | 500 Bbl/day | | $34.10 | | MONT BELVIEU |
Interest Rate Risk. Our interest rate exposure relates to our long-term debt under our credit agreements. Borrowings under our Exit credit agreement and the Notes. TheSuperior credit agreement at our election bearsbear interest at variable rates based on the Prime Rate or the LIBOR Rate. At our election, borrowings under our credit agreement may be fixed at the LIBOR Rate for periods of up to 180 days.interest rates. Based on our average outstanding long-term debt subject to a variable rate in 2017,2021, a 1% increase in the floatinginterest rate on the outstanding borrowings under these facilities would reduce our annual pre-tax cash flow by approximately $1.6$0.5 million. Under our Notes, we pay a fixed rate
Item 8. Financial Statements and Supplementary Data
Index to Financial Statements
Unit Corporation and Subsidiaries
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| Consolidated Financial Statements: | Page |
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Management’s Report on Internal Control over Financial Reporting
Pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the company;
Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and
Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Internal control over financial reporting cannot provide absolute assurance of achieving financial reporting objectives because of its inherent limitations. Internal control over financial reporting is a process that involves human diligence and compliance and is subject to lapses in judgment and breakdowns resulting from human failures. Internal control over financial reporting also can be circumvented by collusion or improper management override. Because of such limitations, there is a risk that material misstatements may not be prevented or detected on a timely basis by internal control over financial reporting. However, these inherent limitations are known features of the financial reporting process. Therefore, it is possible to design into the process safeguards to reduce, though not eliminate, this risk.
The company’s management assessed the effectiveness of the company’s internal control over financial reporting as of December 31, 2017. In making this assessment, the company’s management used the criteria set forth in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on their assessment, the company’s management concluded that, as of December 31, 2017, the company’s internal control over financial reporting was effective based on those criteria.
The effectiveness of the company’s internal control over financial reporting as of December 31, 2017, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.
Report of Independent Registered Public Accounting Firm
To
Board of Directors and Shareholders of
Unit Corporation:Corporation
OpinionsOpinion on the Financial Statements and Internal Control over Financial Reportingfinancial statements
We have audited the accompanying consolidated balance sheets of Unit Corporation (a Delaware corporation) and its subsidiaries (the “Company”) as of December 31, 20172021 and 2016, and2020 (Successor), the related consolidated statements of operations, comprehensive income (loss), changes in shareholders’ equity, and cash flows for each of the three years in the periodyear ended December 31, 2017, including2021 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 and financial statement schedule listed in the index appearing under Item 15(a)(2) (collectively referred to as the “consolidated financial“financial statements”). We also have audited the Company's internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control - Integrated Framework(2013)issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
In our opinion, the consolidatedfinancial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 20172021 and 2016,2020, and the results of theirits operations and theirits cash flows for each of the three years in the periodyear ended December 31, 20172021 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. Also
Basis of presentation
As discussed in our opinion,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 maintained,emerged from bankruptcy on September 3, 2020. Accordingly, the accompanying financial statements have been prepared in all material respects, effective internal control over financial reportingconformity with FASB Accounting Standards Codification 852, Reorganizations, for the Successor as of December 31, 2017, based on criteria establisheda new entity with assets, liabilities and a capital structure having carrying amounts not comparable with prior periods, as described in Internal Control - Integrated Framework(2013)issued by the COSO.Note 25.
Basis for Opinionsopinion
The Company's management is responsible for these consolidatedThese financial statements for maintaining effective internal control over financial reporting, and for its assessmentare the responsibility of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control over Financial Reporting.Company’s management. Our responsibility is to express opinionsan opinion on the Company’s consolidatedfinancial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) ("PCAOB"(“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 auditsaudit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the auditsaudit to obtain reasonable assurance about whether the consolidatedfinancial statements are free of material misstatement, whether due to error or fraud, and whether effectivefraud. 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 was maintained in all material respects.
Our auditsbut not for the purpose of expressing an opinion on the effectiveness of the consolidatedCompany’s internal control over financial statementsreporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the consolidatedfinancial 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 consolidatedfinancial 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 consolidatedfinancial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.opinion.
Definition and Limitations of Internal Control over Financial ReportingCritical audit matter
A company’s internal control over financial reportingThe critical audit matter communicated below is a process designedmatter arising from the current period audit of the financial statements that was communicated or required to provide reasonable assurancebe 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.
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 reliabilityfinancial performance of financial reportingwells 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 preparationestimation of financial statementsproved 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 external purposesour determination that the estimation of proved reserves is a critical audit matter is that changes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policiescertain inputs and procedures that (i) pertainassumptions, which require a high degree of management subjectivity, necessary to estimate the maintenance of records that, in reasonable detail, accuratelyvolume and fairly reflect the transactions and dispositionsfuture revenues of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets thatCompany's proved reserves could have a material effectsignificant impact on the financial statements.measurement of depletion expense or impairment expense. In turn, auditing those inputs and assumptions required complex auditor judgment.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subjectOur audit procedures related to the riskestimation 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 controls may become inadequate because of changesincluded 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 conditions, or that the degree of compliance withreserve report to realized prices related to revenue transactions recorded in the policies orcurrent 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 may deteriorate.to the reserve report by comparing the reserve report to historical actual results and to the prior year reserve report.
/s/ PricewaterhouseCoopersGRANT THORNTON LLP
Tulsa, Oklahoma
February 27, 2018
We have served as the Company’sCompany's auditor since 1989.2020.
Tulsa, Oklahoma
March 31, 2022
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
| | | | | | | | | | | | | | |
| Successor | | | Successor |
| December 31, 2021 | | | December 31, 2020 |
| (In thousands except share and par value amounts) |
| ASSETS | | | | |
| Current assets: | | | | |
| Cash and cash equivalents | $ | 64,140 | | | | $ | 12,145 | |
| Restricted cash | — | | | | 569 | |
| Accounts receivable, net of allowance for credit losses of $2,511 and $3,783 at December 31, 2021 and December 31, 2020, respectively | 87,248 | | | | 57,846 | |
| | | | |
| | | | |
| Current income taxes receivable | — | | | | 1,150 | |
| | | | |
| Prepaid expenses and other | 5,542 | | | | 11,212 | |
| Total current assets | 156,930 | | | | 82,922 | |
| Property and equipment: | | | | |
| Oil and natural gas properties, on the full cost method: | | | | |
| Proved properties | 225,014 | | | | 238,581 | |
| Unproved properties not being amortized | 422 | | | | 1,591 | |
| Drilling equipment | 66,058 | | | | 63,687 | |
| Gas gathering and processing equipment | 274,748 | | | | 251,404 | |
| | | | |
| Corporate land and building | — | | | | 32,635 | |
| Transportation equipment | 4,550 | | | | 3,130 | |
| Other | 8,631 | | | | 9,961 | |
| 579,423 | | | | 600,989 | |
| Less accumulated depreciation, depletion, amortization, and impairment | 128,880 | | | | 54,189 | |
| Net property and equipment | 450,543 | | | | 546,800 | |
| Right of use asset (Note 19) | 12,445 | | | | 5,592 | |
| Other assets | 9,559 | | | | 14,389 | |
Total assets (1) | $ | 629,477 | | | | $ | 649,703 | |
_________________________ |
| | | | | | | |
| | As of December 31, |
| | 2017 | | 2016 |
| | (In thousands except share and par value amounts) |
| ASSETS | | | |
| Current assets: | | | |
| Cash and cash equivalents | $ | 701 |
| | $ | 893 |
|
| Accounts receivable (less allowance for doubtful accounts of $2,450 and $3,773 at December 31, 2017 and 2016, respectively) | 111,512 |
| | 83,954 |
|
| Materials and supplies | 505 |
| | 3,340 |
|
| Current derivative asset (Note 12) | 721 |
| | — |
|
| Current deferred tax asset (Note 8) | — |
| | 25,211 |
|
| Prepaid expenses and other | 6,233 |
| | 7,798 |
|
| Total current assets | 119,672 |
| | 121,196 |
|
| Property and equipment: | | | |
| Oil and natural gas properties, on the full cost method: | | | |
| Proved properties | 5,712,813 |
| | 5,446,305 |
|
| Unproved properties not being amortized | 296,764 |
| | 314,867 |
|
| Drilling equipment | 1,593,611 |
| | 1,565,268 |
|
| Gas gathering and processing equipment | 726,236 |
| | 705,859 |
|
| Saltwater disposal systems | 62,618 |
| | 60,638 |
|
| Corporate land and building | 59,080 |
| | 59,066 |
|
| Transportation equipment | 29,631 |
| | 32,842 |
|
| Other | 53,439 |
| | 48,590 |
|
| | 8,534,192 |
| | 8,233,435 |
|
| Less accumulated depreciation, depletion, amortization, and impairment | 6,151,450 |
| | 5,952,330 |
|
| Net property and equipment | 2,382,742 |
| | 2,281,105 |
|
| Goodwill (Note 2) | 62,808 |
| | 62,808 |
|
| Non-current derivative asset (Note 12) | — |
| | 377 |
|
| Other assets | 16,230 |
| | 13,817 |
|
| Total assets | $ | 2,581,452 |
| | $ | 2,479,303 |
|
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS - (Continued)
|
| | | | | | | |
| | As of December 31, |
| | 2017 | | 2016 |
| | (In thousands except share and par value amounts) |
| LIABILITIES AND SHAREHOLDERS’ EQUITY | | | |
| Current liabilities: | | | |
| Accounts payable | $ | 112,648 |
| | $ | 88,793 |
|
| Accrued liabilities (Note 5) | 48,523 |
| | 39,651 |
|
| Current derivative liabilities (Note 12) | 7,763 |
| | 21,564 |
|
| Current portion of other long-term liabilities (Note 6) | 13,002 |
| | 14,907 |
|
| Total current liabilities | 181,936 |
| | 164,915 |
|
| Long-term debt less unamortized discount and debt issuance costs (Note 6) | 820,276 |
| | 800,917 |
|
| Non-current derivative liabilities (Note 12) | — |
| | 415 |
|
| Other long-term liabilities (Note 6) | 100,203 |
| | 103,064 |
|
| Deferred income taxes (Note 8) | 133,477 |
| | 215,922 |
|
| Commitments and contingencies (Note 14) | — |
| | — |
|
| Shareholders’ equity: | | | |
| Preferred stock, $1.00 par value, 5,000,000 shares authorized, none issued | — |
| | — |
|
| Common stock, $0.20 par value, 175,000,000 shares authorized, 52,880,134 and 51,494,318 shares issued as of December 31, 2017 and 2016, respectively | 10,280 |
| | 10,016 |
|
| Capital in excess of par value | 535,815 |
| | 502,500 |
|
| Accumulated other comprehensive income (net of tax of $39 at December 31, 2017) (Note 15) | 63 |
| | — |
|
| Retained earnings | 799,402 |
| | 681,554 |
|
| Total shareholders’ equity | 1,345,560 |
| | 1,194,070 |
|
| Total liabilities and shareholders’ equity | $ | 2,581,452 |
| | $ | 2,479,303 |
|
The accompanying notes are an integral part of the consolidated financial statements.
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONSBALANCE SHEETS - (Continued)
| | | | | | | | | | | | | | |
| Successor | | | Successor |
| December 31, 2021 | | | December 31, 2020 |
| (In thousands except share and par value amounts) |
| LIABILITIES AND SHAREHOLDERS’ EQUITY | | | | |
| Current liabilities: | | | | |
| Accounts payable | $ | 58,625 | | | | $ | 40,829 | |
| Accrued liabilities (Note 9) | 22,450 | | | | 21,743 | |
| | | | |
| Current operating lease liability (Note 19) | 3,791 | | | | 4,075 | |
| Current portion of long-term debt (Note 10) | — | | | | 600 | |
| Current derivative liabilities (Note 17) | 40,876 | | | | 1,047 | |
| Warrant liability (Note 17) | 19,822 | | | | 885 | |
| Current portion of other long-term liabilities (Note 10) | 5,574 | | | | 11,168 | |
| Total current liabilities | 151,138 | | | | 80,347 | |
| Long-term debt (Note 10) | 19,200 | | | | 98,400 | |
| Non-current derivative liabilities (Note 17) | 17,855 | | | | 4,659 | |
| Operating lease liability (Note 19) | 8,677 | | | | 1,445 | |
| Other long-term liabilities (Note 10) | 32,939 | | | | 39,259 | |
| Deferred income taxes (Note 13) | — | | | | — | |
| Commitments and contingencies (Note 21) | 0 | | | 0 |
| Shareholders’ equity: | | | | |
Common stock, $0.01 par value, 25,000,000 shares authorized, 12,000,000 shares issued and 10,050,037 outstanding as of December 31, 2021, and 12,000,000 issued and outstanding as of December 31, 2020 | 120 | | | | 120 | |
| Treasury stock | (51,965) | | | | — | |
| Capital in excess of par value | 198,171 | | | | 197,242 | |
| Retained earnings (deficit) | 41,071 | | | | (18,140) | |
| Total shareholders' equity attributable to Unit Corporation | 187,397 | | | | 179,222 | |
| Non-controlling interests in consolidated subsidiaries | 212,271 | | | | 246,371 | |
| Total shareholders’ equity | 399,668 | | | | 425,593 | |
Total liabilities and shareholders’ equity (1) | $ | 629,477 | | | | $ | 649,703 | |
_________________________ |
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| | (In thousands except per share amounts) |
| Revenues: | | | | | |
| Oil and natural gas | $ | 357,744 |
| | $ | 294,221 |
| | $ | 385,774 |
|
| Contract drilling | 174,720 |
| | 122,086 |
| | 265,668 |
|
| Gas gathering and processing | 207,176 |
| | 185,870 |
| | 202,789 |
|
| Total revenues | 739,640 |
| | 602,177 |
| | 854,231 |
|
| Expenses: | | | | | |
| Operating costs: | | | | | |
| Oil and natural gas | 130,789 |
| | 120,184 |
| | 166,046 |
|
| Contract drilling | 122,600 |
| | 88,154 |
| | 156,408 |
|
| Gas gathering and processing | 155,483 |
| | 137,609 |
| | 161,556 |
|
| Total operating costs | 408,872 |
| | 345,947 |
| | 484,010 |
|
| | | | | | |
| Depreciation, depletion, and amortization | 209,257 |
| | 208,353 |
| | 352,742 |
|
| Impairments | — |
| | 161,563 |
| | 1,634,628 |
|
| General and administrative | 38,087 |
| | 33,337 |
| | 34,358 |
|
| (Gain) loss on disposition of assets | (327 | ) | | (2,540 | ) | | 7,229 |
|
| Total expenses | 655,889 |
| | 746,660 |
| | 2,512,967 |
|
| Income (loss) from operations | 83,751 |
| | (144,483 | ) | | (1,658,736 | ) |
| Other income (expense): | | | | | |
| Interest, net | (38,334 | ) | | (39,829 | ) | | (31,963 | ) |
| Gain (loss) on derivatives | 14,732 |
| | (22,813 | ) | | 26,345 |
|
| Other | 21 |
| | 307 |
| | 45 |
|
| Total other income (expense) | (23,581 | ) | | (62,335 | ) | | (5,573 | ) |
| Income (loss) before income taxes | 60,170 |
| | (206,818 | ) | | (1,664,309 | ) |
| Income tax expense (benefit): | | | | | |
| Current | 5 |
| | 15 |
| | (20,616 | ) |
| Deferred | (57,683 | ) | | (71,209 | ) | | (606,332 | ) |
| Total income taxes | (57,678 | ) | | (71,194 | ) | | (626,948 | ) |
| Net income (loss) | $ | 117,848 |
| | $ | (135,624 | ) | | $ | (1,037,361 | ) |
| Net income (loss) per common share: | | | | | |
| Basic | $ | 2.31 |
| | $ | (2.71 | ) | | $ | (21.12 | ) |
| Diluted | $ | 2.28 |
| | $ | (2.71 | ) | | $ | (21.12 | ) |
The accompanying notes are an integral part of the consolidated financial statements.
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)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) | | | |
|
| | | | | | | | | | | |
| | For Years Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| | (In thousands) |
| Net income (loss) | $ | 117,848 |
| | $ | (135,624 | ) | | $ | (1,037,361 | ) |
| Other comprehensive income, net of taxes: | | | | | |
| Unrealized appreciation on securities, net of tax of $39, $0, and $0 | 63 |
| | — |
| | — |
|
| Comprehensive income (loss) | $ | 117,911 |
| | $ | (135,624 | ) | | $ | (1,037,361 | ) |
The accompanying notes are an integral part of these
unaudited condensed consolidated financial statements.
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY
Year Ended December 31, 2015, 2016, and 2017
|
| | | | | | | | | | | | | | | | | | | |
| | Common Stock | | Capital In Excess of Par Value | | Accumulated Other Comprehensive Income | | Retained Earnings | | Total |
| | (In thousands except per share amounts) |
| Balances, January 1, 2015 | $ | 9,732 |
| | $ | 468,123 |
| | $ | — |
| | $ | 1,854,539 |
| | $ | 2,332,394 |
|
| Net loss | — |
| | — |
| | — |
| | (1,037,361 | ) | | (1,037,361 | ) |
| Activity in employee compensation plans (819,289 shares) | 99 |
| | 18,448 |
| | — |
| | — |
| | 18,547 |
|
| Balances, December 31, 2015 | 9,831 |
| | 486,571 |
| | — |
| | 817,178 |
| | 1,313,580 |
|
| Net loss | — |
| | — |
| | — |
| | (135,624 | ) | | (135,624 | ) |
| Activity in employee compensation plans (1,081,217 shares) | 185 |
| | 15,929 |
| | — |
| | — |
| | 16,114 |
|
| Balances, December 31, 2016 | 10,016 |
| | 502,500 |
| | — |
| | 681,554 |
| | 1,194,070 |
|
| Net income | — |
| | — |
| | — |
| | 117,848 |
| | 117,848 |
|
| Other comprehensive income (net of tax $39) | — |
| | — |
| | 63 |
| | — |
| | 63 |
|
| Total comprehensive income | | | | | | | | | 117,911 |
|
| Proceeds from sale of stock (787,547 shares) | 158 |
| | 18,465 |
| | — |
| | — |
| | 18,623 |
|
| Activity in employee compensation plans (598,269 shares) | 106 |
| | 14,850 |
| | — |
| | — |
| | 14,956 |
|
| Balances, December 31, 2017 | $ | 10,280 |
| | $ | 535,815 |
| | $ | 63 |
| | $ | 799,402 |
| | $ | 1,345,560 |
|
The accompanying notes are an integral part of the consolidated financial statements.
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWSCOMPREHENSIVE INCOME (LOSS)
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| | (In thousands) |
| OPERATING ACTIVITIES: | | | | | |
| Net income (loss) | $ | 117,848 |
| | $ | (135,624 | ) | | $ | (1,037,361 | ) |
| Adjustments to reconcile net income (loss) to net cash provided (used) by operating activities: | | | | | |
| Depreciation, depletion, and amortization | 209,257 |
| | 208,353 |
| | 352,742 |
|
| Impairments (Note 2) | — |
| | 161,563 |
| | 1,634,628 |
|
| Amortization of debt issuance costs and debt discount | 2,159 |
| | 2,122 |
| | 2,088 |
|
| (Gain) loss on derivatives | (14,732 | ) | | 22,813 |
| | (26,345 | ) |
| Cash receipts on derivatives settled | 173 |
| | 9,658 |
| | 46,615 |
|
| (Gain) loss on disposition of assets | (327 | ) | | (3,127 | ) | | 7,229 |
|
| Deferred tax benefit | (57,683 | ) | | (71,209 | ) | | (606,332 | ) |
| Employee stock compensation plans | 17,747 |
| | 13,812 |
| | 21,468 |
|
| Bad debt expense | 348 |
| | 785 |
| | 1,191 |
|
| ARO liability accretion | 2,886 |
| | 2,779 |
| | 3,453 |
|
| Other, net | (865 | ) | | (6,037 | ) | | (1,517 | ) |
| Changes in operating assets and liabilities increasing (decreasing) cash: | | | | | |
| Accounts receivable | (32,073 | ) | | (11,796 | ) | | 105,426 |
|
| Materials and supplies | 2,835 |
| | 225 |
| | 1,507 |
|
| Prepaid expenses and other | 1,527 |
| | 2,585 |
| | 7,134 |
|
| Accounts payable | 21,824 |
| | 27,400 |
| | (20,306 | ) |
| Accrued liabilities | 6,996 |
| | (4,388 | ) | | (22,920 | ) |
| Income taxes | 38 |
| | 20,903 |
| | (21,482 | ) |
| Contract advances | 1,630 |
| | (687 | ) | | (274 | ) |
| Net cash provided by operating activities | 279,588 |
| | 240,130 |
| | 446,944 |
|
| INVESTING ACTIVITIES: | | | | | |
| Capital expenditures | (269,185 | ) | | (186,149 | ) | | (561,453 | ) |
| Producing property and other acquisitions | (58,026 | ) | | (564 | ) | | (179 | ) |
| Proceeds from disposition of property and equipment | 21,713 |
| | 74,823 |
| | 11,854 |
|
| Other | (1,500 | ) | | 919 |
| | — |
|
| Net cash used in investing activities | (306,998 | ) | | (110,971 | ) | | (549,778 | ) |
| FINANCING ACTIVITIES: | | | | | |
| Borrowings under line of credit | 343,900 |
| | 251,398 |
| | 618,500 |
|
| Payments under line of credit | (326,700 | ) | | (371,600 | ) | | (503,500 | ) |
| Payments on capitalized leases | (3,694 | ) | | (3,694 | ) | | (3,549 | ) |
| Proceeds from common stock issued, net of issue costs (Note 15) | 18,623 |
| | — |
| | — |
|
| Tax expense from stock compensation | — |
| | (376 | ) | | (3,207 | ) |
| Decrease in book overdrafts (Note 2) | (4,911 | ) | | (4,829 | ) | | (5,624 | ) |
| Net cash provided by (used in) financing activities | 27,218 |
| | (129,101 | ) | | 102,620 |
|
| Net increase (decrease) in cash and cash equivalents | (192 | ) | | 58 |
| | (214 | ) |
| Cash and cash equivalents, beginning of year | 893 |
| | 835 |
| | 1,049 |
|
| Cash and cash equivalents, end of year | $ | 701 |
| | $ | 893 |
| | $ | 835 |
|
| Supplemental disclosure of cash flow information: | | | | | |
| Cash paid during the year for: | | | | | |
| Interest paid (net of capitalized) | $ | 33,931 |
| | $ | 35,690 |
| | $ | 30,910 |
|
| Income taxes | $ | — |
| | $ | 42 |
| | $ | 3,540 |
|
| Changes in accounts payable and accrued liabilities related to purchases of property, plant, and equipment | $ | (6,942 | ) | | $ | 21,190 |
| | $ | 105,157 |
|
| Non-cash reductions to oil and natural gas properties related to asset retirement obligations | $ | 3,613 |
| | $ | 30,897 |
| | $ | 5,694 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | |
| 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.
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.
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.
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 – ORGANIZATION AND BUSINESS
Unless the context clearly indicates otherwise, references in this report to “Unit”, “Company”“company”, “we”, “our”, “us”, or like terms refer to Unit Corporation andor, 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 exploration, 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 principallyall 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 explore, develop, acquire, and produce oil and natural gas properties for our own account. Our producing oil and natural gas properties, unproved properties, and related assets are mainly in Oklahoma and Texas, and to a lesser extent, in Arkansas, 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 our own account and for a wide range of other oil and natural gas companies.companies as well as for our own account. Our drilling operations are mainly in Oklahoma, Texas, New Mexico, Wyoming, and North Dakota, and to a lesser extent in Louisiana and Kansas.Dakota.
Mid-Stream. Carried out by our subsidiary, Superior, Pipeline Company, L.L.C. and its subsidiaries, 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;
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
•Each holder of an allowed general unsecured claim against UDC, 8200 Unit, Unit Drilling Colombia and Unit Drilling USA received payment or will receive payment in full for that claim in the ordinary course of business; and
•Each retained or former employee with a claim for vested severance benefits, who opted into a settlement, received or will receive cash payment(s) for the claim in lieu of an allocation of New Common Stock otherwise provided to holders of general unsecured claims.
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.
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 23 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
PrinciplesBasis of Consolidation. Presentation. The consolidated financial statements include the accounts of Unit Corporation and its subsidiaries. Our investmentWe 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 limited partnerships is accountedthe United States (U.S. GAAP), for on the proportionate consolidation method, whereby our shareeach of the partnerships’ assets, liabilities, revenues, and expenses are includedperiods presented in the appropriate classificationconsolidated financial statements. We have concluded that we are the primary beneficiary of the VIE, as defined in the accompanyingaccounting 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 financial statements.subsidiaries.
Certain amounts in the accompanying consolidated financial statementspresented for prior periods have been reclassified to conform to current year presentation. Certain financial statement captions were expanded or combined withThere was no impact from these reclassifications to consolidated net incomeincome/(loss) or shareholders' equity.
UNIT CORPORATION AND SUBSIDIARIES
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. The preparation of Preparing financial statements in conformity with generally accepted accounting principles (GAAP)U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities atdisclosures in the date of theconsolidated financial statements and the reported amounts of revenues and expenses during the reporting period.statements. Actual results could differ from those estimates. Significant estimates and assumptions include:
Drilling Contracts. We recognize revenues•oil and expenses generated from “daywork” drilling contracts as the services are performed, since we do not bear the riskgas reserves quantities and values;
•full cost ceiling test and impairment assessments for property and equipment;
•asset retirement obligations;
•fair value of completioncommodity derivative assets and liabilities;
•fair value of the well. Under “footage” and “turnkey” contracts, we bear the risk of completionwarrant liability;
•reorganization fair value as of the well; therefore, revenuesEffective Date,
•grant date fair value of stock-based compensation;
•workers' compensation liabilities;
•contingency, litigation, and expenses are recognized when the well is substantially completed. Under this method, substantial completion is determined when the well bore reaches the negotiated depth as stated in the contract. The entire amountenvironmental liabilities;
•and realizability of a loss, if any, is recorded when the loss is determinable. The costs of uncompleted drilling contracts include expenses incurred to date on “footage” or “turnkey” contracts, which are still in process at the end of the period,deferred tax assets;
Cash and are included in other current assets. Typically, any one of these three types of contracts can be used for the drilling of one well which can take from 10 to 90 days. At December 31, 2017, all of our contracts were daywork contracts of which nine were multi-well and had durations which ranged from six months to two years, eight of which expire in 2018 and one expiring in 2019. These longer term contracts may contain a fixed rate for the duration of the contract or provide for the periodic renegotiation of the rate within a specific range from the existing rate.
Cash Equivalents and Book Overdrafts.Equivalents. We include as cash and cash equivalents all cash on hand and on deposit, as well as highly liquid investments with maturities at date of purchase of three months or less which are readily convertible into known amounts of cash. BookThe financing section of our consolidated statements of cash flows reflects bank overdraft activity. Bank overdrafts are checks that
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
have been issued before the end of the period, but not presented to our bank for payment before the end of the period. AtThere were no bank overdrafts as of December 31, 20172021 and 2016, book overdrafts were $12.4$2.6 million and $17.3 million, respectively.as of December 31, 2020.
Accounts Receivable. Receivable, Net of Allowance for Credit Losses. Accounts receivable are carried on a gross basis, with no discounting, less an allowance for doubtful accounts.expected credit losses. We estimate the allowance for doubtful accountscredit 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 doubtful accountscredit losses only after all collection attempts have been unsuccessful.
Financial InstrumentsProperty and ConcentrationsEquipment.
Oil and Natural Gas Properties. We account for our oil and natural gas exploration and development activities using the full cost method of Credit Riskaccounting prescribed by the SEC under which we capitalize all productive and Non-performance Risk. Financial instruments, which potentially subject usnon-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.
UNIT CORPORATION AND SUBSIDIARIES
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 concentrationsbe incurred in developing proved reserves, and estimated dismantlement and abandonment costs, net of credit risk, consist primarilyestimated 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 trade receivablesoperations, with a varietyany 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 companies. We do not generally require collateral related to receivables. Our credit risk is considered to be limited due to the large number of customers comprising our customer base. Below are the third-party customers that accounted for more than 10% of our segment’s revenues:
|
| | | | | | | | |
| | 2017 | | 2016 | | 2015 |
| Oil and Natural Gas: | | | | | |
| Sunoco Logistics Partners L.P. | 10 | % | | 24 | % | | 19 | % |
| Valero Energy Corporation | 9 | % | | 11 | % | | 15 | % |
| Drilling: | | | | | |
| QEP Resources, Inc. | 26 | % | | 28 | % | | 25 | % |
| Whiting Petroleum Corp. (formerly Kodiak Oil and Gas Corp.) | 7 | % | | 18 | % | | 7 | % |
| Mid-Stream: | | | | | |
| ONEOK, Inc. | 36 | % | | 30 | % | | 29 | % |
| Range Resources Corporation | 9 | % | | 10 | % | | 5 | % |
| Koch Energy Services, LLC | 8 | % | | 11 | % | | 9 | % |
| Tenaska Resources, LLC | 6 | % | | 10 | % | | 18 | % |
| Laclede Group, Inc. | 1 | % | | 9 | % | | 12 | % |
We hadproperties unless it results in a concentration of cash of $11.4 million and $8.3 million at December 31, 2017 and 2016, respectively with one bank.
The use of derivative transactions also involves the risk that the counterparties will be unable to meet the financial terms of the transactions. We considered this non-performance risk with regardsignificant alteration to our counterparties and our own non-performance risk in our derivative valuation at December 31, 2017 and determined there was no material risk at that time. At December 31, 2017, the fair values of the net assets (liabilities) we had with each of the counterparties with respect to all of our commodity derivative transactions are listed in the table below:full cost pool.
|
| | | |
| | December 31, 2017 |
| | (In millions) |
| Canadian Imperial Bank of Commerce | $ | 0.7 |
|
| Bank of America Merrill Lynch | (2.5 | ) |
| Bank of Montreal | (5.3 | ) |
| Total assets (liabilities) | $ | (7.1 | ) |
Property and Equipment.Drilling equipment, transportation equipment, gas gathering and processing systems,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. DepreciationPrior to emergence from bankruptcy, we recorded depreciation of drilling equipment is recorded 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.idle, unless idle for greater than 48 months, then it was depreciated at the full active rate. We usealso used the composite method of depreciation for drill pipe and collars and calculate the depreciation by footage actually 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 iswas computed using the straight-line method over the estimated useful life of the asset for 39 years. Depreciation of other property and equipment is computed using the straight-line method over the estimated useful lives of the assets ranging from 3three to 15 years.
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Impairment and disposal. We review the carrying amounts of long-lived assets for potential impairment annually, typically during the fourth quarter, or when events occur or changes in circumstances suggest that these carrying amounts may not be recoverable. Changes that could prompt such an assessment may 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 amount of the 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 management’sour assumptions and judgments regarding future industry conditions and their effect on future utilization levels, dayrates, and costs. The use ofUsing different estimates and assumptions could causeresult in materially different carrying values of our assets.
On a periodic basis, we evaluate our fleet of drilling rigs for marketability based on the condition of inactive rigs, expenditures that would be necessary to bring them to working condition and the expected demand for drilling services by rig type. The components comprising inactive rigs are evaluated, and those components with continuing utility to the Company’s other marketed rigs are transferred to other rigs or to its yards to be used as spare equipment. The remaining components of these rigs are retired. During 2015, we recorded a write-down on 31 of our drilling rigs and related equipment of approximately $8.3 million pre-tax based on the estimated market value for similar equipment from auctions sales. We then sold all 31 of these drilling rigs and some other drilling equipment to unaffiliated third parties. The proceeds from the sale of those assets, less costs to sell, was less than the $11.3 million net book value resulting in a loss of $7.3 million pre-tax. 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. Our contract drilling segment had no impairments in either 2016 or 2017. 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.
In 2015, our mid-stream segment incurred a $27.0 million, pre-tax write-down of three of its systems, Bruceton Mills, Midwell, and Spring Creek due to anticipated future cash flow and future development around these systems not being sufficient to support their carrying value. The estimated future cash flows were less than the carrying value on these systems. Our mid-stream segment had no impairments in either 2016 or 2017.
We record an asset and a liability equal to the present value of the expected future AROCapitalized Interest. Interest costs associated with our oil and gas properties. The AROmajor asset is depreciated in a manner consistent with the depreciation of the underlying physical asset. We measure changes in the liability due to passage of time by accreting an interest charge. This amount is recognized as an increase in the carrying amount of the liability and as a corresponding accretion expense.
Capitalized Interest. During 2017, 2016, and 2015, interest of approximately $15.9 million, $15.3 million, and $21.7 million, respectively, wasadditions are capitalized based on the net book value associated with unproved properties not being amortized,during the construction of additional drilling rigs, and the construction of gas gathering systems. Interest is being capitalizedperiod using a weighted average interest rate based on our outstanding borrowings. We did not capitalize any interest costs in 2021 or 2020.
Goodwill. Goodwill represents the excess of the cost of acquisitions over the fair value of the net assets acquired. Goodwill is not amortized, but an impairment test is performed at least annually to determine whether the fair value has decreased and is performed additionally when events indicate an impairment may have occurred. For impairment testing, goodwill is evaluated at the reporting unit level. Our goodwill is all related to our contract drilling segment, and, the impairment test is generally based on the estimated discounted future net cash flows of our drilling segment, utilizing discount rates and other factors in determining the fair value of our drilling segment. Inputs in our estimated discounted future net cash flows include drilling rig utilization, day rates, gross margin percentages, and terminal value. No goodwill impairment was recorded for the years ended December 31, 2017, 2016, or 2015. There were no additions to goodwill in 2017, 2016, or 2015. Based on our impairment test performed as of December 31, 2017, the fair value of our drilling segment exceeded its carrying value by 41%. Goodwill of $0.7 million is deductible for tax purposes.
Oil and Natural Gas Operations. We account for our oil and natural gas exploration and development activities using the full cost method of accounting prescribed by the SEC. Accordingly, 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, are capitalized and amortized on a units-of-production method based
UNIT CORPORATION AND SUBSIDIARIES
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 proveda 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 reserves. Directly related overhead costs of $14.8 million, $15.4 million,wells are plugged and $19.2 million were capitalized in 2017, 2016, and 2015, respectively. Independent petroleum engineers annually audit our internal evaluation of our reserves. The average rates used for DD&A were $6.00, $6.24, and $12.30 per Boe in 2017, 2016, and 2015, respectively. 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. Our unproved properties and wells in progress totaling $296.8 million are excluded from the DD&A calculation.
No gains or losses are recognized on the sale, conveyance, or other disposition of oil and natural gas properties unless a significant reserve amount to our total reserves is involved.
Revenue from the sale of oil and natural gas is recognizedabandoned when title passes, net of royalties.
Under the full cost rules, at the end of each quarter, we review the carrying value of our oil and natural gas properties. The full cost ceiling is based principally on the estimated future discounted net cash flows from our oil and natural gas properties discounted at 10%. We 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. In the event the unamortized cost of oil and natural gas properties being amortized exceeds the full cost ceiling, as defined by the SEC, the excess is charged to expense in the period during which such excess occurs. Once incurred, a write-down of oil and natural gas properties is not reversible.
We determined the value of certain unproved oil and gas properties were diminished (in part or in whole) based on an impairment evaluation and our anticipated future exploration plans. Those determinations resulted in $114.4 million, $7.6 million, and $10.5 million in 2015, 2016, and 2017, respectively of costs being added to the total of our capitalized costs being amortized. In 2015, we incurred non-cash ceiling test write-downs of our oil and natural gas properties of $1.6 billion pre-tax ($1.0 billion net of tax) primarily due to the reduction of the 12-month average commodity prices during the year. In 2016, we incurred non-cash ceiling test write-downs of our oil and natural gas properties of $161.6 million pre-tax ($100.6 million net of tax) due to the reduction of the 12-month average commodity prices during the first three quarters of the year. We had no non-cash ceiling test write-downs during 2017.
Our contract drilling segment provides drilling services for our exploration and production segment. 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 the acquisition of 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. The contracts for these services are issued under the similar terms and rates as the contracts entered into with unrelated third parties. By providing drilling services for the oil and natural gas segment, we eliminated revenue of $13.4 million and $22.1 million during 2017 and 2015, respectively, from our contract drilling segment and eliminated the associated operating expense of $11.8 million and $18.3 million during 2017 and 2015, respectively, yielding $1.6 million and $3.8 million during 2017 and 2015, respectively, as a reduction to the carrying value of our oil and natural gas properties. We eliminated no revenue or expenses in our contract drilling segment during 2016.
ARO. We record the fair value of liabilities associated with the future plugging and abandonment of wells. In our case, when the reserves in each of our oilthose wells are depleted or gasthe wells deplete or otherwise become uneconomical, we must incur costsare no longer able to plug and abandon the wells. Theseproduce. The estimated liabilities related to these future costs are recorded in the period in which the liability is incurred (atat the time the wells are drilled or acquired).acquired. We have no assets restricted to settle these ARO liabilities. Our engineering staff usesuse historical experience to determine the estimated plugging costs considering the well's type, of well (either oil or natural gas), the depth, of the well, the physical location, of the well, and the ultimate productive life to determine the estimated plugging costs.life. A risk-adjusted discount rate and an inflation factor are used on these estimated costsapplied to determine the current present value of this obligation. To the extent any change in these assumptions affect future revisions and impactestimate the present value of these obligations. We depreciate the existing ARO,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 is 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.
Gas Gathering and Processing Revenue. Our gathering and processing segment recognizes revenue from the gathering and processing of natural gas and NGLs in the period the service is provided based on contractual terms.
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 in order to limit, to the extent feasible, per occurrence and aggregate
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
exposure to certain types of claims. There is no assurance that the insurance coverages we have will adequately protect us against liability from all potential consequences. If insurance coverage becomes more expensive, we may choose to self-insure, decrease our limits, raise our deductibles, or any combination of these rather than pay higher premiums.
Derivative Activities.Commodity Derivatives. All commodity derivatives are recognized on the consolidated balance sheet andsheets 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 exception of normal purchase and normal sales which are expectedsame counterparty if a legal right to resultset-off exists. Changes in physical delivery. Any changes in our derivatives'the fair value occurring before their maturity (i.e., temporary fluctuations in value)of our commodity derivatives and gains or losses on commodity derivative settlement are reported in gain (loss) on derivatives in our Consolidated Statementsconsolidated statements of Operations.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.
We document our risk management strategy and do not engage in derivative transactions for speculative purposes.
Limited Partnerships. Unit Petroleum Company is a general partner in 13 oil and natural gas limited partnerships sold privately and publicly. Some of our officers, directors, and employees own the interests in most of these partnerships. We share in each partnership’s revenues and costs in accordance with formulas set out in each of the limited partnership agreement. The partnerships also reimburse us for certain administrative costs incurred on behalf of the partnerships.
Income Taxes. During 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 fourth quarterend of 2017,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. government enactedGAAP requires the Tax Act. Among other provisions, the Tax Act reduces the federal corporate tax rate from the existing maximum raterecognition of 35% to 21%, effective January 1, 2018. The change in tax law required the Company to remeasure existing neta deferred tax liabilities usingasset for net operating loss carryforwards and tax credit carryforwards. We periodically assesses the lower rate inrealizability of the period of enactment resulting in the Company recording a tax benefit of $81.3 million in 2017 due to a revaluation of our net deferred tax liability. Measurement of net deferred tax liabilities is based on provisions of enacted tax law (including the Tax Act); the effects of future changes in tax laws or rates are not included in the measurement. Valuation allowances are established where necessary to reduce deferred tax assets by considering all available evidence (both positive and negative) to the amount expected to be realized. Income tax expensedetermine whether it is the tax payable for the year and the change duringmore likely than not that year inall or a portion of the deferred tax assets will not be realized and liabilities.a valuation allowance is required.
The accounting for uncertainty in income taxes prescribes
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
Natural Gas Balancing. When there are insufficient remaining reserves to offset a recognition threshold and measurement attributegas imbalance, we recognize an asset or a liability for the financial statement recognition and measurement of a tax position takenunder-produced or expected to be taken in a return. Guidance is also provided on de-recognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition.
Natural Gas Balancing. We use the sales method for recording natural gas sales. This method allows for recognition of revenue, which may be more or less than its share of pro-rata production from certain wells. We estimate our December 31, 2017 balancing position to be approximately 3.7 Bcf on under-produced properties and approximately 3.8 Bcf on over-produced properties.position. We have recorded a receivable of $2.4$0.6 million on certain wells where we estimate that insufficient reserves are available for us to recover theour under-production from future production volumes. We have also recordedvolumes and a liability of $3.3$1.1 million on certain properties where we believe there are insufficient reserves available to allow the under-produced owners to recover their under-production from future production volumes.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.
Employee and Director Stock BasedStock-Based Compensation. We recognize in our financial statements the cost of employee services received in exchange for awards of equity instrumentsstock-based compensation over the requisite service periods, which is generally the vesting period, based on the grant date fair value of those awards. The amount of our equity compensation cost relating to employees directly involved in exploration activities of our oilawards and natural gas segment is capitalized to our oil and natural gas properties. Amounts not capitalized to our oil and natural gas properties are recognized in general and administrative expense and operating costs of our business segments.account for forfeitures as they occur.
Warrant Liability. We utilize the Black-Scholes option pricing model to measurerecognize the fair value of stock options and SARs. Thethe 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 restricted stock grants is based onconsolidated statements of operations. The liability will continue to be adjusted to fair value at each reporting period until the closing stock price onwarrants meet the datedefinition 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 grants.
New Accounting Standards
Compensation—Stock Compensation. Effects of Reference Rate Reform on Financial Reporting. The FASB issued ASU 2017-09,2020-04 and ASU 2021-01 which provide and clarify optional expedients and exceptions for applying generally accepted accounting principles to clarifycontract 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 reduce both (i) diversityan 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 practiceEntity’s Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and (ii) costContracts 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 complexity when applying its guidancesimplifies 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 changeshave 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 the termsTopic 740. The amendments also improve consistent application of a share-based payment award.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, 2017. This amendment will2020. The adoption of this standard did not have a material impact onto our consolidated financial statements.
0Intangibles—GoodwillNOTE 4 - IMPAIRMENTS
Oil and Other: SimplifyingNatural Gas Properties
2021
There were no impairments recorded during the Testyear 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 Goodwill Impairment. The FASB issued ASU 2017-04, to simplify the measurementceiling test versus the forward prices used for our Fresh Start fair value estimates. These charges are included within impairments in our consolidated statements of goodwill. The amendment eliminates Step 2 from the goodwill impairment test. The amendmentoperations.
UNIT CORPORATION AND SUBSIDIARIES
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.
will be effective prospectively for reporting periods beginning after December 15, 2019,
In addition to the impairment evaluations of our proved and early adoption is permitted. This amendment will not have a material impactunproved 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 financial statements.
Business Combinations; Clarifyingrevised forecast, we determined that some were no longer expected to be used and wrote off the Definitionassets for total expense of a Business. The FASB issued ASU 2017-01, clarifying$17.6 million during the definition of a business. The amendment should help companies and other organizations evaluate whether transactions should be accounted for as acquisitions (or disposals)eight months ended August 31, 2020. These amounts are reported in loss on abandonment of assets or businesses. For public companies,in our consolidated statements of operations.
Contract Drilling
2021
There were no impairments recorded during the amendment is effective for annual periods beginning after December 15, 2017. This amendment will not have a material impact on our financial statements.
Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments. The FASB issued ASU 2016-15, to address diversity in how certain transactions are presented and classified in the statement of cash flows. The amendment will be effective retrospectively for reporting periods beginning afteryear ended December 31, 2017, and early adoption is permitted. This amendment will not have a material impact on our financial statements.2021.
Leases. The FASB has issued ASU 2016-02. The amendment will require lessees to recognize at2020
During the commencement date a lease liability, which is a lessee's obligation to make lease payments arising from a lease, measured on a discounted basis; and a right-of-use asset, which is an asset that represents the lessee's right to use a specified asset for the lease term. Lessor accounting is largely unchanged. For public companies, the amendment is effective for annual periods beginning after December 15, 2018, and interim periods within those annual periods. The standard will not apply to leaseseight months ended August 31, 2020, we recorded expense of mineral rights. We are evaluating the impact this amendment will have on our financial statements and currently evaluating a plan for implementation.
Revenue from Contracts with Customers. The FASB has issued ASU 2014-09. This standard affects any entity using U.S. GAAP that either contracts with customers to transfer goods or services or enters into contracts for transferring nonfinancial assets unless those contracts are within the scope of other standards (e.g., insurance contracts or lease contracts). The core principle of the amendments is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 has been amended several times pre-issuance, which is codified in the new Topic 606, effective January 1, 2018. The guidance in this update supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and most industry-specific guidance throughout the Industry Topics of the Codification. We adopted this standard January 1, 2018 using the modified retrospective approach, which resulted in a cumulative effect adjustment upon adoption for our mid-stream segment. This adjustment$1.1 million related to the timingwrite-down of revenuecertain equipment that we consider abandoned. These amounts are reported in loss on certain demand feesabandonment 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 materialrecoverable 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 company. Both our oil and natural gas andBOSS 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 segments hadrigs asset groups for potential impairment included forecasted utilization, gross margins, salvage values, discount rates, and terminal values. There were no retained earnings adjustment.additional triggering events identified during the eight months ended August 31, 2020 or four months ended December 31, 2020.
The applicationMid-Stream
2021
In December 2021, we determined that the carrying value of Topic 606 willa gathering system in Pennsylvania was not have a material effect on our statementrecoverable and exceeded its estimated fair value due to unfavorable forecasted economics. We recorded non-cash impairment charges of operations or our balance sheet, as the timing of revenue recognized will not be materially modified, but additional footnote disclosures are required with respect to revenue. In our oil and natural gas segment, the classification of certain costs as either a deduction from revenue or an expense will be determined based on when control of the commodity transfers to the customer, which would impact total revenue recognized, but will not affect gross profit.
Part of our review included evaluation of these issues:
Based on an analysis of whether the transportation of gas is a performance obligation that occurs at a point in time or over time, the timing of when we recognize certain revenue elements will change. Specifically related to our mid-stream segment, certain fees collectible during a contract will be recognized over the life of the contract because these fees are part of the single performance obligation associated with the contract.
Certain of our contracts include promises to deliver a minimum volume of commodity to the customer over a defined period. If we do not meet this commitment, a deficiency fee is payable to the customer. Topic 606 requires these arrangements represent variable consideration related to the sale of the commodity, and requires that we include an estimate of any deficiency fees expected within revenue, rather than as operating costs. In addition, we will also be required to analyze fees that are billable for deficiencies in minimum volume commitments from customers for our mid-stream segment. In these instances, we will assess the likelihood of earning these fees each reporting period$10.7 million based on the customer’s performanceestimated 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 recognize variable revenue when itcentral Oklahoma where lower pricing is not expected to be subject to a significant reversal.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.
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
NOTE 5 – REVENUE FROM CONTRACTS WITH CUSTOMERS
Our internalrevenue 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 framework didof 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 materially change,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 existing internal controlscontract 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.
UNIT CORPORATION AND SUBSIDIARIES
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 modifiedcompleted, the customer no longer has access to consider our new revenue recognition policy effective January 1, 2018. As we implement the new standard, we have added internal controls to ensure that we adequately evaluate new contracts undercontracted capacity, or the five-step model under ASU 2014-09.
Adopted Standards
Income Taxes: Balance Sheet Classification of Deferred Taxes. The FASB has issued ASU 2015-17. This changes how deferred taxes are classified on organizations' balance sheets. Organizations must classify all deferred tax assets and liabilities as noncurrent. The amendments apply to all organizations that present a classified balance sheet. For public companies, the amendments were effective for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. The amendment requires current deferred tax assets to be combined with noncurrent deferred tax assets. We have adopted this ASU during the first quarter of 2017 on a prospective basis. Previously, we had a net current deferred tax asset now netted with our noncurrent deferred tax liability. Prior periods were not retrospectively adjusted.
Compensation—Stock Compensation: Improvements to Employee Share-Based Payment Accounting. The FASB has issued ASU 2016-09. The amendment should improve the accounting for employee share-based payments and affect all organizations that issue share-based payment awards to their employees. Several aspectslikelihood of the accounting for share-based payment award transactionscustomer 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 simplified, including: (a) income tax consequences; (b) classificationprimarily 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 awardsthe contracts as either equity or liabilities; and (c) classification on the statement of cash flows. For public companies, the amendment was effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods. The amendment primarily affects classification within the statement of cash flows between financial and operating activities. This did not have a material impact on our financial statements.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 36 – ACQUISITIONS AND DIVESTITURES
AcquisitionsOil and Natural Gas
On April 3, 2017, we closed on anThere 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 certainproducing and other oil and natural gas assetsproperties 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 primarily in Gradynear the Oklahoma Panhandle for $5.0 million, subject to customary closing and Caddo Counties in western Oklahoma. The final adjusted value of consideration given was $54.3 million.
As of January 1, 2017, thepost-closing adjustments with an effective date of December 1, 2021. No gain or loss was recognized as the acquisition, the estimated proved oil and gas reservessale of these assets did not result in a significant alteration of the acquired properties were 3.2full 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, barrelssubject to customary closing and post-closing adjustments. No gain or loss was recognized as the sale of oil equivalent (MMBoe). The acquisition added approximately 8,300 net oil and gas leasehold acres to our core Hoxbar areathese assets did not result in southwestern Oklahoma including approximately 47 proved developed producing wells. Of the acreage acquired, approximately 71% was held by production. We also received one gathering system as parta significant alteration of the transaction.full cost pool.
We accounted for this acquisition using the acquisition method under ASC 805, Business Combinations, which requires that the acquired assets and liabilities be recorded at their fair values as of the acquisition date. The following table summarizes the final adjusted purchase price and the values of assets acquired and liabilities assumed.
|
| | | |
| Final Adjusted Purchase Price | |
| Total consideration given | $ | 54,332 |
|
| | |
| Final Adjusted Allocation of Purchase Price | |
| Oil and natural gas properties included in the full cost pool: | |
| Proved oil and natural gas properties | $ | 43,745 |
|
| Undeveloped oil and natural gas properties | 8,650 |
|
Total oil and natural gas properties included in the full cost pool (1) | 52,395 |
|
| Gas gathering equipment and other | 2,340 |
|
| Asset retirement obligation | (403 | ) |
| Fair value of net assets acquired | $ | 54,332 |
|
| |
(1) | We used a discounted cash flow model and made market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates, and risk adjusted discount rates. |
UNIT CORPORATION AND SUBSIDIARIES
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.
The pro forma effects of this acquired business are immaterial to the results of operations.
For 2017, we had approximately $4.7 million in other acquisitions.
Divestitures
Oil and Natural Gas
We hadalso sold $5.0 million of other non-core asset sales with proceeds,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 $18.6 million, $67.2 million, and $1.9 million,these assets did not result in 2017, 2016, and 2015, respectively. Proceeds from these dispositions reduced the net book valuea significant alteration of the full cost pool with no gain or loss recognized.pool.
Contract Drilling
During 2015,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 recordedclosed on an acquisition for $13.0 million, subject to customary closing and post-closing adjustments, that included a write-down on 31cryogenic processing plant, approximately 1,620 miles of our drilling rigslow-pressure gathering pipeline, and related equipment of approximately $8.3 million pre-tax based oncompressor stations located in southern Kansas. The transaction was accounted for as an asset acquisition.
There was no significant acquisition activity during the estimated market value for similar equipment from auctions sales. We then sold allyear ended December 31, of these drilling rigs2020.
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 some other drilling equipment to unaffiliated third parties. The proceeds fromOther
In September 2021, we closed the sale of those assets, less costs to sell, was less than the $11.3our corporate headquarters building and land for $35.0 million net book value resulting in a loss of $7.3 million pre-tax.
During December 2016, we sold one idle 1500 HP SCR drilling rig to an unaffiliated third party. The proceeds of this sale, less costs to sell, exceeded the $1.7 million net book value of the drilling rig, resulting in a gain of $1.6 million.$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.
We did not have any divestitures in 2017.
NOTE 47 – EARNINGS (LOSS) PER SHARECAPITAL 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 following data showsLenders 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 amounts used in computing earnings (loss) per share:
|
| | | | | | | | | | |
| | Income (Loss) (Numerator) | | Weighted Shares (Denominator) | | Per-Share Amount |
| | (In thousands except per share amounts) |
| For the year ended December 31, 2015: | | | | | |
| Basic loss per common share | $ | (1,037,361 | ) | | 49,110 |
| | $ | (21.12 | ) |
| Effect of dilutive stock options, restricted stock, and SARs | — |
| | — |
| | — |
|
| Diluted loss per common share | $ | (1,037,361 | ) | | 49,110 |
| | $ | (21.12 | ) |
| For the year ended December 31, 2016: | | | | | |
| Basic loss per common share | $ | (135,624 | ) | | 50,029 |
| | $ | (2.71 | ) |
| Effect of dilutive stock options, restricted stock, and SARs | — |
| | — |
| | — |
|
| Diluted loss per common share | $ | (135,624 | ) | | 50,029 |
| | $ | (2.71 | ) |
| For the year ended December 31, 2017: | | | | | |
| Basic earnings per common share | $ | 117,848 |
| | 51,113 |
| | $ | 2.31 |
|
| Effect of dilutive restricted stock | — |
| | 635 |
| | (0.03 | ) |
| Diluted earnings per common share | $ | 117,848 |
| | 51,748 |
| | $ | 2.28 |
|
Due to the net loss for the years endedconsolidated balance sheets as of December 31, 20162021.
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 2015, approximately 509,000 and 186,000, respectively, weightedmay 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 shares related to stock options, restricted stock, and SARs were antidilutive and were excluded fromshare price of $32.57 for an aggregate purchase price of $41.4 million under the earnings per share calculation above.repurchase program.
UNIT CORPORATION AND SUBSIDIARIES
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 and their average exercise prices 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 yearsyear ended December 31:31, 2021:
| | | | | | | |
| 2021 | | |
| Stock options | 361,418 | | | |
| Average exercise price | $ | 45.00 | | | |
|
| | | | | | | | | | | |
| | 2017 | | 2016 | | 2015 |
| Options and SARs | 87,500 |
| | 199,755 |
| | 261,270 |
|
| Average exercise price | $ | 51.34 |
| | $ | 48.79 |
| | $ | 50.34 |
|
NOTE 59 – 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 | |
|
| | | | | | | |
| | 2017 | | 2016 |
| | (In thousands) |
| Employee costs | $ | 19,521 |
| | $ | 15,394 |
|
| Lease operating expenses | 11,819 |
| | 10,075 |
|
| Interest payable | 6,745 |
| | 6,524 |
|
| Taxes | 3,404 |
| | 2,219 |
|
| Third-party credits | 2,240 |
| | 2,998 |
|
| Other | 4,794 |
| | 2,441 |
|
| Total accrued liabilities | $ | 48,523 |
| | $ | 39,651 |
|
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued) NOTE 610 – 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 | |
|
| | | | | | | |
| | 2017 | | 2016 |
| | (In thousands) |
| Credit agreement with average interest rates of 3.4% and 2.8% at December 31, 2017 and 2016, respectively | $ | 178,000 |
| | $ | 160,800 |
|
| 6.625% senior subordinated notes due 2021 | 650,000 |
| | 650,000 |
|
| Total principal amount | $ | 828,000 |
| | $ | 810,800 |
|
| Less: unamortized discount | (2,234 | ) | | (2,804 | ) |
| Less: debt issuance costs, net | (5,490 | ) | | (7,079 | ) |
| Total long-term debt | $ | 820,276 |
| | $ | 800,917 |
|
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 8, 2016, we amended our Senior Credit Agreement (credit agreement) scheduled6, 2021, the company finalized the first amendment to mature on April 10, 2020. The amount we can borrow is the lesserExit credit agreement. Under the first amendment, the company reaffirmed its borrowing base of $140.0 million of the amount we elect (from timeRBL Facility, amended certain financial covenants, and received less restrictive terms, among others, as it relates to time)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 commitment amount oruse of proceeds from the valuedisposition of certain assets, while also amending certain financial covenants.
On March 30, 2022, the RBL Facility borrowing base of $80.0 million was reaffirmed.
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 borrowing baselast 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 determined byof the lenders, butlast day of any fiscal quarter to be less than 1.00 to 1.00 or (b) permit the Interest Coverage Ratio (as defined in either event notthe Exit credit agreement) as of the last day of any fiscal quarter to exceed the maximumbe less than 2.50 to 1.00. The Exit credit agreement amountalso 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 $875.0 million. Our elected commitment amounteach 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 $475.0 million. Our borrowing base is $475.0 million. 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 arehad 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 0.50%0.375% on the amount available but not borrowed. TheThat fee variesvaried based on the amount borrowed as a percentage of the amount of the total borrowing base. We paid $1.0Total amendment fees of $3.3 million in origination, agency, syndication, and other related fees. We are amortizing these fees were being amortized over the life of the Unit credit agreement. WithDue to the new amendment,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 the following collateral: (a) 85%as collateral 80% of the proved developed producing (discounted as present worth at 8%) total value of our oil and gas properties and (b) 100% of our ownership interest in our mid-stream affiliate, Superior Pipeline Company, L.L.C.
The borrowing base amount–which is subject to redetermination byproperties. Under the lenders on April 1st and October 1st of each year, is based primarily on a percentage of the discounted future value of ourmortgages covering those oil and natural gas reserves and on our cash flows from our mid-stream segment. The October 2017 redetermination did not cause any changes. We orproperties, UPC also pledged certain items of its personal property.
Before filing the lenders may request a onetime special redetermination of the borrowing base between each scheduled redetermination. In addition, we may request a redetermination following the completion of an acquisition that meets the requirements set forth in the credit agreement.
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
At our election,Chapter 11 Cases, any part of the outstanding debt under the Unit credit agreement maycould be fixed at a London Interbank Offered Rate (LIBOR). LIBOR interest iswas computed as the sum of the LIBOR base for the applicable term plus 2.00%1.50% to 3.00%2.50% depending on the level of debt as a percentage of the borrowing base and iswas payable at the end of each term, or every 90 days,, whichever is less. Borrowings not under LIBOR bear interest atequal to the higher of the prime rate specified in the Unit credit agreement that cannotand 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.margin. Interest iswas 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. At December 31, 2017, we had $178.0
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.
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 outstanding borrowingssenior 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 ourthe Superior credit agreement.
We can use borrowings for financing general working capital requirements foragreement bear annual interest at a rate, at Superior’s option, equal to (a) exploration, development, productionLIBOR 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 acquisition(iii) the Thirty-Day LIBOR Rate (as defined in the Superior credit agreement)) plus the applicable margin of oil1.00% to 2.25%. The obligations under the Superior credit agreement are secured by mortgage liens on certain of Superior’s processing plants and gas properties, (b) acquisitions and operation of mid-stream assets, (c) issuance of standby letters of credit, (d) contract drilling services, and (e) general corporate purposes.
gathering systems. The credit agreement prohibits, among other things:
provides that if ICE Benchmark Administration no longer reports the payment of dividends (other than stock dividends) during any fiscal year over 30% of our consolidated net income forLIBOR or Administrative Agent determines in good faith that the preceding fiscal year;
rate so reported no longer accurately reflects the incurrence of additional debt with certain limited exceptions; and
the creation or existence of mortgages or liens, other than thoserate available to Lender in the ordinary courseLondon 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 business,0.375% on anythe amount available but not borrowed which varies based on the amount borrowed as a percentage of our properties, except for our lenders.
the total borrowing base.
The Superior credit agreement also requires that we have at the end of each quarter:
Superior maintain a currentConsolidated EBITDA to interest expense ratio (as defined in the credit agreement) of not less than 1 to 1.
Through the quarter ending March 31, 2019, the credit agreement also requires that we have at the end of each quarter:
a senior indebtedness ratio of senior indebtedness to consolidated EBITDA (as defined in theSuperior credit agreement) for the most recentlymost-recently ended rolling four quarters of no greater than 2.75at least 2.50 to 1.
Beginning with the quarter ending June 30, 2019,1.00, and for each quarter ending thereafter, the credit agreement requires:
a leverage ratio of funded debt to consolidatedConsolidated EBITDA ratio (as defined in the Superior credit agreement) for the most recently ended rolling four fiscal quarters of nonot greater than 44.00 to 1.
As1.00. 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 December 31, 2017, we wereassets. 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 covenants containedSuperior 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.agreement was not affected by Unit's bankruptcy.
Predecessor 6.625% Senior Subordinated Notes.We have an aggregate principal amount of $650.0 million, The Predecessor 6.625% senior subordinated notes (theNotes (Predecessor Notes). Interest on the Notes is payable semi-annually (in arrears) on May 15 and November 15 of each year. The Notes will mature on May 15, 2021. In connection with the issuance of the Notes, we incurred $14.7 million of fees that are being amortized as debt issuance cost over the life of the Notes.
The Notes are subject to were issued under an Indenture dated as of May 18, 2011, between usthe company and Wilmington Trust, National Association (successor to Wilmington Trust FSB), as Trustee (the 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. The Guarantors are
As a result of Unit's emergence from bankruptcy, the Predecessor Notes were cancelled and our direct and indirect subsidiaries. The discussionliability under the Predecessor Notes was discharged as of the Effective Date. Holders of the Predecessor Notes were issued shares of New Common Stock in this report is qualifiedaccordance 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 actual terms ofDIP Credit Agreement and the 2011 Indenture.bankruptcy court’s orders.
Unit, as the parent company, has no independent assets or operations. The guarantees by the Guarantors of the Notes (registered under registration statements) are full and unconditional, joint and several, subject to certain automatic customary releases, are subject to certain restrictions on the sale, disposition, or transfer of the capital stock or substantially all of the assets of a subsidiary guarantor, and other conditions and terms set out in the Indenture. Any of our subsidiaries that are not Guarantors are minor. There are no significant restrictions on our ability to receive funds from our subsidiaries through dividends, loans, advances or otherwise.
We may redeem all or, from time to time, a part of the Notes at certain redemption prices, plus accrued and unpaid interest. If a “change of control” occurs, subject to certain conditions, we must offer to repurchase from each holder all or any
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
partOn the Effective Date, the DIP credit facility was paid in full and terminated, and each holder of that holder’s Notes at a purchase price in cashan 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 101%5% of the principal amountNew Common Stock (subject to dilution by shares reserved for issuance under a management incentive plan and on exercise of the Notes plus accrued and unpaid interest, if any, toWarrants).
For further information about the date of purchase. The 2011 Indenture contains customary events of default. The 2011 Indenture also contains covenants that, among other things, limit our ability and the ability of certain of our subsidiaries to incur or guarantee additional indebtedness; pay dividends on our capital stock or redeem capital stock or subordinated indebtedness; transfer or sell assets; make investments; incur liens; enter into transactions with our affiliates; and merge or consolidate with other companies. We were in compliance with all covenants of the Notes as of December 31, 2017.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 | |
|
| | | | | | | |
| | 2017 | | 2016 |
| | (In thousands) |
| ARO liability | $ | 69,444 |
| | $ | 70,170 |
|
| Capital lease obligations | 15,224 |
| | 18,918 |
|
| Workers’ compensation | 13,340 |
| | 15,163 |
|
| Separation benefit plans | 6,524 |
| | 4,943 |
|
| Deferred compensation plan | 5,390 |
| | 4,578 |
|
| Gas balancing liability | 3,283 |
| | 3,789 |
|
| Other | — |
| | 410 |
|
| | 113,205 |
| | 117,971 |
|
| Less current portion | 13,002 |
| | 14,907 |
|
| Total other long-term liabilities | $ | 100,203 |
| | $ | 103,064 |
|
Estimated annual principal payments under the terms of debt and other long-term liabilities from 2018 through 2022 are $13.0 million, $45.6 million, $184.7 million, $655.9 million, and $2.1 million, respectively.
Capital Leases
During 2014, our mid-stream segment entered into capital lease agreements for twenty compressors with initial terms of seven years. The underlying assets are included in gas gathering and processing equipment. The current portion of our capital lease obligations of $3.8 million is included in current portion of other long-term liabilities and the non-current portion of $11.4 million is included in other long-term liabilities in the accompanying Consolidated Balance Sheets as of December 31, 2017. These capital leases are discounted using annual rates of 4.0%. Total maintenance and interest remaining related to these leases are $5.9 million and $1.2 million, respectively at December 31, 2017. Annual payments, net of maintenance and interest, average $4.2 million annually through 2021. At the end of the term, our mid-stream segment has the option to purchase the assets at 10% of the fair market value of the assets at that time.
Future payments required under the capital leases at December 31, 2017 are as follows:
|
| | | | |
| | | Amount |
| Ending December 31, | | (In thousands) |
| 2018 | | $ | 6,168 |
|
| 2019 | | 6,168 |
|
| 2020 | | 6,168 |
|
| 2021 | | 3,768 |
|
| Total future payments | | 22,272 |
|
| Less payments related to: | | |
| Maintenance | | 5,874 |
|
| Interest | | 1,174 |
|
| Present value of future minimum payments | | $ | 15,224 |
|
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
NOTE 711 – ASSET RETIREMENT OBLIGATIONS
We are required to record the estimated fair value of the liabilities relating to the future retirement of our long-lived assets (AROs). Our oil and natural gas wells are plugged and abandoned when the oil and natural gas reserves in those wells are depleted or the wells are no longer able to produce. The plugging and abandonment liability for a well is recorded in the period in which the obligation is incurred (at the time the well is drilled or acquired). None of our assets are restricted for purposes of settling these AROs. All of our AROs relate to plugging costs associated with our oil and gas wells.
The following table shows certain information aboutsummarizes activity for our estimated AROs for the periods indicated:
|
| | | | | | | |
| | 2017 | | 2016 |
| | (In thousands) |
| ARO liability, January 1: | $ | 70,170 |
| | $ | 98,297 |
|
| Accretion of discount | 2,886 |
| | 2,779 |
|
| Liability incurred | 1,948 |
| | 584 |
|
| Liability settled | (2,694 | ) | | (1,215 | ) |
| Liability sold | (1,735 | ) | | (10,882 | ) |
Revision of estimates (1) | (1,131 | ) | | (19,393 | ) |
| ARO liability, December 31: | 69,444 |
| | 70,170 |
|
| Less current portion | 1,726 |
| | 2,906 |
|
| Total long-term ARO liability | $ | 67,718 |
| | $ | 67,264 |
|
_________________________
| |
(1) | Plugging liability estimates were revised in both 2017 and 2016 for updates in the cost of services used to plug wells over the preceding year. We had various upward and downward adjustments and changes in estimated timing of cash flows. |
NOTE 8 – INCOME TAXES
During the fourth quarter of 2017, the U.S. government enacted the Tax Act. Among its many provisions, the Tax Act reduces the federal corporate tax rate from 35% to 21%, effective January 1, 2018. The change in tax law required the Company to revalue its existing net deferred tax liability using the lower rate in the period of enactment resulting in the recognition of an income tax benefit of $81.3 million forduring the year ended December 31, 2017 related2021 (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 that revaluation. As a result,plug wells over the Company recognized an overall income tax benefit of $57.7 million for thepreceding year ended December 31, 2017.and estimated dates to be plugged.
Also during the fourth quarter of 2017, the SEC issued Staff Accounting Bulletin 118 (SAB 118), which provides guidance on accounting for tax effects of the Tax Act. SAB 118 provides a measurement period that should not extend beyond one year from the Tax Act enactment date for companies to complete the accounting under ASC 740. In accordance with SAB 118, a company must reflect the income tax effects of those aspects of the Act for which the accounting under ASC 740 is complete. While we were able to make reasonable estimates of the impact of the reduction in corporate rate, bonus depreciation expensing provisions, and impact of Sec 162(m) to our existing restricted stock grants, the final impact of the Tax Act may differ from these estimates, due to, among other things, changes in our interpretations and assumptions, additional guidance that may be issued by the IRS, and actions we may take.
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
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 | |
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
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.
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
A reconciliation of income tax expense (benefit), computed by applying the federal statutory rate to pre-tax income (loss) to our effective income tax expense (benefit) during the periods indicated is as follows:
| | | | | | | | | | Successor | | | Predecessor |
| | 2017 | | 2016 | | 2015 | | Year Ended
December 31, 2021 | | Four Months Ended
December 31, 2020 | | | Eight Months Ended
August 31, 2020 | |
| | (In thousands) | | (In thousands) |
| Income tax expense (benefit) computed by applying the statutory rate | $ | 21,059 |
| | $ | (72,386 | ) | | $ | (582,508 | ) | 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 | 1,655 |
| | (5,687 | ) | | (45,768 | ) | State income tax expense (benefit), net of federal benefit | 2,129 | | | (500) | | | | (31,684) | | |
Deferred tax liability revaluation (1) | (81,307 | ) | | — |
| | — |
| |
| Warrant liability revaluation | | Warrant liability revaluation | 4,640 | | | — | | | | — | | |
| Restricted stock shortfall | 1,867 |
| | 5,465 |
| | — |
| Restricted stock shortfall | — | | | — | | | | 7,404 | | |
| Non-controlling interest in Superior | | Non-controlling interest in Superior | (3,046) | | | (1,017) | | | | 7,504 | | |
| Goodwill impairment | | Goodwill impairment | — | | | — | | | | — | | |
| Valuation allowance | | Valuation allowance | (16,612) | | | 4,047 | | | | 177,284 | | |
| Reorganization adjustments | | Reorganization adjustments | — | | | — | | | | 14,152 | | |
| Statutory depletion and other | (952 | ) | | 1,414 |
| | 1,328 |
| Statutory depletion and other | 290 | | | 169 | | | | 813 | | |
| Income tax benefit | $ | (57,678 | ) | | $ | (71,194 | ) | | $ | (626,948 | ) | |
| Income tax expense (benefit) | | Income tax expense (benefit) | $ | 173 | | | $ | (302) | | | | $ | (14,630) | | |
__________________________
| |
(1) | In 2017, the revaluation from the Tax Act. |
For the periods indicated, theThe company's total provision for income taxes consisted of the following:following during the periods indicated:
| | | | | | | | | | Successor | | | Predecessor |
| | 2017 | | 2016 | | 2015 | | Year Ended
December 31, 2021 | | Four Months Ended
December 31, 2020 | | | Eight Months Ended
August 31, 2020 | |
| | (In thousands) | | (In thousands) |
| Current taxes: | | | | | | Current taxes: | | | | |
| Federal | $ | — |
| | $ | — |
| | $ | (20,612 | ) | Federal | $ | — | | | $ | — | | | | $ | (917) | | |
| State | 5 |
| | 15 |
| | (4 | ) | State | 173 | | | (302) | | | | — | | |
| | 5 |
| | 15 |
| | (20,616 | ) | | 173 | | | (302) | | | | (917) | | |
| Deferred taxes: | | | | | | Deferred taxes: | | | | | | | |
| Federal | (62,788 | ) | | (62,923 | ) | | (535,691 | ) | Federal | — | | | — | | | | (16,663) | | |
| State | 5,105 |
| | (8,286 | ) | | (70,641 | ) | State | — | | | — | | | | 2,950 | | |
| | (57,683 | ) | | (71,209 | ) | | (606,332 | ) | | — | | | — | | | | (13,713) | | |
| Total provision | $ | (57,678 | ) | | $ | (71,194 | ) | | $ | (626,948 | ) | |
| Total provision for income taxes | | Total provision for income taxes | $ | 173 | | | $ | (302) | | | | $ | (14,630) | | |
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
Net deferred tax assets and liabilities are comprised of the following atas of December 31:
| | | | | | | | Successor | | Successor |
| | 2017 | | 2016 | | 2021 | | 2020 |
| | (In thousands) | | (In thousands) |
| Deferred tax assets: | | | | Deferred tax assets: | |
| Allowance for losses and nondeductible accruals | $ | 32,242 |
| | $ | 53,967 |
| Allowance for losses and nondeductible accruals | $ | 23,819 | | | $ | 22,051 | |
| Net operating loss carryforward | 153,746 |
| | 190,603 |
| Net operating loss carryforward | 94,441 | | | 100,236 | |
| Depreciation, depletion, amortization, and impairment | | Depreciation, depletion, amortization, and impairment | 68,001 | | | 80,947 | |
| Alternative minimum tax and research and development tax credit carryforward | 5,409 |
| | 5,409 |
| Alternative minimum tax and research and development tax credit carryforward | 1,738 | | | 1,738 | |
| | 191,397 |
| | 249,979 |
| | 187,999 | | | 204,972 | |
| Deferred tax liability: | | | | Deferred tax liability: | |
| Depreciation, depletion, amortization, and impairment | (324,874 | ) | | (440,690 | ) | |
| Net deferred tax liability | (133,477 | ) | | (190,711 | ) | |
| Current deferred tax asset | — |
| | 25,211 |
| |
| | Investment in Superior | | Investment in Superior | (3,626) | | | (3,987) | |
| Net deferred tax asset | | Net deferred tax asset | 184,373 | | | 200,985 | |
| Valuation allowance | | Valuation allowance | (184,373) | | | (200,985) | |
| Non-current—deferred tax liability | $ | (133,477 | ) | | $ | (215,922 | ) | Non-current—deferred tax liability | $ | — | | | $ | — | |
Realization of the deferred tax assets are dependent on generating sufficient future taxable income. Although realization is not assured, management believesWe concluded that it is more likely than not that the net deferred tax asset will not be realized. The amount ofrealized and has recorded a full valuation allowance, reducing the net deferred tax asset considered realizable, however, could be reduced in the near-term if estimatesto zero. The company has maintained this conclusion as of future taxable income are reduced. At December 31, 2017, we2021 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 federal net operating loss carryforwards of approximately $587.9 million which expire from 2021 to 2037.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 20162017 or state income tax examinations by state taxing authorities for years before 2014. During 2014, we recognized a tax benefit relating to a research and development tax credit carryforward in conjunction with our BOSS
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
drilling rig activities. Due to the nature and subjectivity surrounding the research and development credit and historical challenges by the IRS against companies who claim the credit, it was our belief that the full amount of the credit may not have been eventually allowed by the IRS once we were no longer in an AMT tax paying position. During 2017, our U.S federal tax returns for 2013, 2014, and 2015 were examined by the IRS and no additional tax was found to be due and the research and development tax credit carryforward was allowed in full. Accordingly, we no longer have any unrecognized tax benefits as2016. As of December 31, 2017.2021, 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 914 – EMPLOYEE BENEFIT PLANS
Under our 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.
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. Employees who meet specified service requirements may contribute a percentage of their total compensation, up to a specified maximum, to the plan.401(k) Employee Thrift Plan. We may match each employee’s contribution, up to a specified maximum, in full or on a partial basis. Webasis with cash or common stock. The 2019 and 2020 plan year matching contributions were made discretionary contributions under the plan of 155,822, 630,039, and 235,104 shares of common stock and recognizedin cash. Total 401(k) employer matching expense of $4.4was $1.6 million, $4.0$0.7 million, and $6.2$1.4 million in 2017, 2016,the year ended December 31, 2021, four months ended December 31, 2020, and 2015,eight months ended August 31, 2020, respectively.
Salary Deferral Plan. We provideprovided a salary deferral plan for our executives (Deferral Plan) during the eight months ended August 31, 2020 which allowsallowed participants to defer the recognition of salary for income tax purposes until actual distribution of benefits which occursoccurred at either termination of employment, death, or certain defined unforeseeable emergency hardships. The liability recorded underAs of December 31, 2020, investments held in the Deferral Plan at December 31, 2017 and 2016 was $5.4 million and $4.6 million, respectively. We recognized payroll expense and recorded a liability at the time of deferral.
Effective January 1, 1997, we adopted a separation benefithad been paid out to plan (Separation Plan). The Separation Plan allows eligible employees whose employment is involuntarily terminated or, in the case of an employee who has completed 20 years of service, voluntarily or involuntarily terminated, to receive benefits equivalent to four weeks salary for every whole year of service completed up to a maximum of 104 weeks. To receive payments, the recipient must waive any claims against us in exchange for receiving the separation benefits. On October 28, 1997, we adopted a Separation Benefit Plan for Senior Management (Senior Plan). The Senior Plan provides certain officers and key executives of Unit with benefits generally equivalent to the Separation Plan. The Compensation Committee of the Board of Directors has absolute discretion in the selection of the individuals covered in this plan. On May 5, 2004 we also adopted the Special Separation Benefit Plan (Special Plan). This plan is identical to the Separation Benefit Plan with the exception that the benefits under the plan vest on the earliest of a participant’s reaching the age of 65 or serving 20 years with the company.
On December 31, 2008, we amended all three Plans to be in compliance with Section 409A of the Internal Revenue Code of 1986, as amended. The key amendments to the Plans address, among other things, when distributions may be made, the timing of payments,participants and the circumstances under which employees become eligible to receive benefits. On December 8, 2015, we amended the Plans to change the calculation for determining the payouts at the time of a Separation of Service under the Plans. None of the amendments materially increase the benefits, grants or awards issuable under the Plans. We recognized expense of $2.7 million, $3.1 million, and $3.0 million in 2017, 2016, and 2015, respectively, for benefits associated with anticipated payments from these separation plans.Deferral Plan was terminated.
We have entered into key employee change of control contracts with three of our current executive officers. These severance contracts have an initial three-year term that is automatically extended for one year on each anniversary, unless a notice not to extend is given by us. If a change of control of the company, as defined in the contracts, occurs during the term of the severance contract, then the contract becomes operative for a fixed three-year period. The severance contracts generally provide that the executive’s terms and conditions for employment (including position, work location, compensation, and benefits) will not be adversely changed during the three-year period after a change of control. If the executive’s employment is terminated (other than for cause, death, or disability), the executive terminates for good reason during such three-year period, or the executive terminates employment for any reason during the 30-day period following the first anniversary of the change of control, and on certain terminations prior to a change of control or in connection with or in anticipation of a change of control, the executive is generally entitled to receive, in addition to certain other benefits, any earned but unpaid compensation; up to 2.9 times the executive’s base salary plus annual bonus (based on historic annual bonus); and the company matching contributions that would have been made had the executive continued to participate in the company’s 401(k) plan for up to an additional three years.
The severance contract provides that the executive is entitled to receive a payment in an amount sufficient to make the executive whole for any excise tax on excess parachute payments imposed under Section 4999 of the Code. As a condition to receipt of these severance benefits, the executive must remain in the employ of the company prior to change of control and render services commensurate with his position.
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
NOTE 1015 – TRANSACTIONS WITH RELATED PARTIES
Unit Petroleum CompanyOne current director, Robert Anderson, also serves as the general partner of 13 oilan executive with GBK Corporation, a holding company with numerous energy and gas limited partnerships (the employee partnerships) which were formed to allow certain of our qualified employeesindustry subsidiaries and our directors to participate in Unit Petroleum’s oilaffiliates, including Kaiser Francis Oil Company and gas exploration and production operations. Employee partnerships were formed for each year beginning with 1984 and ending with 2011. Previously, there were three non-employee partnerships, one that was formed in 1984 and two formed in 1986 (investments by third parties). Effective December 31, 2014, the 1984 partnership was dissolved and effective December 31, 2016, the two 1986 partnerships were also dissolved.
Cactus Drilling Company. The employee partnerships formed in 1984 through 1990 were consolidated into a single consolidating partnership in 1993 and the employee partnerships formed in 1991 through 1999 were also consolidated into the consolidating partnership in 2002. The consolidation of the 1991 through the 1999 employee partnerships was done by the general partners under the authority containedcompany in the respective partnership agreementsordinary course of business, made payments for working interests, joint interest billings, drilling services, and did not involve any vote, consent or approval by the limited partners. The employee partnerships have each had a set percentage (rangingproduct purchases to, and received payments for working interests, joint interest billings, and contract drilling services from, 1%Kaiser Francis Oil Company and Cactus Drilling Company. Payments made to 15%) of our interest in most of the oilKaiser Francis Oil Company totaled $5.7 million, $0.5 million, and natural gas wells we drill or acquire for our own account$1.8 million while payments received totaled $6.2 million, $0.3 million, and $1.6 million during the particular year for which the partnership was formed. The total interest the employees have in our oil and natural gas wells by participating in these partnerships does not exceed one percent.
Amounts received in the years ended December 31, from both public and private Partnerships for which Unit is a general partner are as follows:
|
| | | | | | | | | | | |
| | 2017 | | 2016 | | 2015 |
| | (In thousands) |
| Well supervision and other fees | $ | 172 |
| | $ | 254 |
| | $ | 423 |
|
| General and administrative expense reimbursement | — |
| | 6 |
| | 18 |
|
Related party transactions for contract drilling and well supervision fees are the related party’s share of such costs. These costs are billed to related parties on the same basis as billings to unrelated parties for such services. General and administrative reimbursements are both direct general and administrative expense incurred on the related party’s behalf and indirect expenses allocated to the related parties. Such allocations are based on the related party’s level of activity and are considered by management to be reasonable.
As of2021, four months ended December 31, 2016, John Nikkel retired as director2020, and chairman of Unit's board and is no longer considered a related party. As of 2016, Mr. Nikkel was a 25.8% owner of Rampart Holdings, Inc. which owned 100% of Toklan Oil and Gaseight months ended August 31, 2020, respectively. Payments made to Cactus Drilling Company (Toklan), an oil and gas exploration and production company located in Tulsa, Oklahoma. Mr. Nikkel's son, Robert Nikkel is Toklan's President, and he owned 20.0% oftotaled $0.8 million during the company. In 2015, there was one well drilled for Toklan with no activity in 2016. Under its usual standard dayrate contract terms available generally to all similarly-situated customers at that time and in the same general drilling area, the Company recognized revenue from Toklan of approximately $0.5 million in 2015. During 2015, we received payments of $0.9 million with no accounts receivable balance atyear ended December 31, 2015. There were no material revenues in 2016. There were no material royalties to disclose for 2015 or 2016. Also in 2015, Toklan paid $0.5 million for the North Custer Gathering System, an inactive (since 2009) gathering system owned by our mid-stream segment. We determined that the capital required to re-activate that system would not provide adequate returns based on future cash flow potential. Toklan operates the North Custer Gathering System under its affiliate, West Thomas Field Services, LLC (West Thomas), a company in which Mr. John Nikkel held an approximate 25.0% ownership interest and in which Mr. Robert Nikkel held ownership interest of approximately 20.0%. West Thomas entered into a gas purchase agreement with our exploration and production segment in November of 2015. Payments from West Thomas under that contract amounted to $0.4 million and $0.1 million for 2016 and 2015 volumes purchased, respectively. Additionally, on March 10, 2016, Mr. Nikkel purchased in the open market $0.4 million in aggregate principal amount of our outstanding 6.625% senior subordinated notes due 2021. The notes pay interest semi-annually in cash in arrears on May 15 and November 15 of each year. For 2016, interest payments for May and November were approximately $4,800 and $13,250, respectively.
One of our directors,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 the Texas and Oklahoma Panhandles.several states. The Companycompany 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, in some cases,sometimes, as lessee, with respect toregarding certain wells in which Mr. Peyton, members of Mr. Peyton's
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
family, and Peyton Royalties, LP have an interest. Such payments totaled approximately $0.7 million, $0.5$0.4 million and $0.8$0.2 million during 2017, 2016,year ended December 31, 2021 and 2015,the eight months ended August 31, 2020, respectively.
Our Audit Committee and the board, in accordance with our related party transaction policy, have determined that these arrangements are in the best interest
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued) NOTE 1116 – STOCK-BASED COMPENSATION
ForUnit 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, we had: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.
|
| | | | | | | | | | | |
| | 2017 | | 2016 | | 2015 |
| | (In millions) |
| Recognized stock compensation expense | $ | 13.3 |
| | $ | 9.6 |
| | $ | 15.3 |
|
| Capitalized stock compensation cost for our oil and natural gas properties | 1.8 |
| | 2.1 |
| | 3.5 |
|
| Tax benefit on stock based compensation | 5.0 |
| | 3.6 |
| | 5.8 |
|
The remaining unrecognized compensation cost related to unvested awards at December 31, 2017 is approximately $12.8 million of which $1.3 million is anticipated to be capitalized. The weighted average period of time over which this cost will be recognized is 0.7 of a year.
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 amendedAmended plan) allowsallowed us to grant stock-based and cash-based compensation to our employees (including employees of subsidiaries) and to non-employee directors. A totalWe recognized a reversal of 7,230,000 shares of the company's common stock is authorized for issuance to eligible participants under the amended plan with 2.0 million shares being the maximum number of shares that can be issued as “incentive stock options.” Awards under this plan may be granted in any one or a combination of the following:
incentive stock options under Section 422 of the Internal Revenue Code;
non-qualified stock options;
performance shares;
performance units;
restricted stock;
restricted stock units;
stock appreciation rights;
cash based awards; and
other stock-based awards.
This plan also contains various limits as to the amount of awards that can be given to an employee in any fiscal year. All awards are generally subject to the minimum vesting periods, as determined by our Compensation Committee and included in the award agreement.
Expected volatilities are based on the historical volatility of our stock. We use historical data to estimate option exercise and termination rates within the model and aggregate groups that have similar historical exercise behavior for valuation purposes. To date, we have not paid dividends on our stock. The risk free interest rate is computed from the United States Treasury Strips rate using the term over which it is anticipated the grant will be exercised.
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
SARs
Activity pertaining to SARs granted under the amended plan is as follows:
|
| | | | | | |
| | Number of Shares | | Weighted Average Price |
| Outstanding at January 1, 2015 | 131,770 |
| | $ | 46.60 |
|
| Granted | — |
| | — |
|
| Exercised | — |
| | — |
|
| Forfeited | — |
| | — |
|
| Outstanding at December 31, 2015 | 131,770 |
| | 46.60 |
|
| Granted | — |
| | — |
|
| Exercised | — |
| | — |
|
| Forfeited | (40,515 | ) | | 51.76 |
|
| Outstanding at December 31, 2016 | 91,255 |
| | 44.31 |
|
| Granted | — |
| | — |
|
| Exercised | — |
| | — |
|
| Forfeited | (91,255 | ) | | 44.31 |
|
| Outstanding at December 31, 2017 | — |
| | $ | — |
|
There were no SARs granted or vested during 2017, 2016, or 2015. There were no SARs exercised in 2017. The SARs expired after 10 years from the date of the grant, and there were no outstanding shares at December 31, 2017.
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Restricted Stock
Activity pertaining to restricted stock awards granted under the amended plan is as follows:
|
| | | | | | | | | | | | |
| Employees | Number of Time Vested Shares | | Number of Performance Vested Shares | | Total Number of Shares | | Weighted Average Price |
| Nonvested at January 1, 2015 | 724,766 |
| | 175,520 |
| | 900,286 |
| | $ | 50.81 |
|
| Granted | 576,361 |
| | 148,081 |
| | 724,442 |
| | 34.06 |
|
| Vested | (343,657 | ) | | (39,245 | ) | | (382,902 | ) | | 49.69 |
|
| Forfeited | (20,808 | ) | | (7,196 | ) | | (28,004 | ) | | 45.33 |
|
| Nonvested at December 31, 2015 | 936,662 |
| | 277,160 |
| | 1,213,822 |
| | 41.29 |
|
| Granted | 494,078 |
| | 152,373 |
| | 646,451 |
| | 5.62 |
|
| Vested | (425,195 | ) | | — |
| | (425,195 | ) | | 43.47 |
|
| Forfeited | (75,808 | ) | | (57,405 | ) | | (133,213 | ) | | 36.87 |
|
| Nonvested at December 31, 2016 | 929,737 |
| | 372,128 |
| | 1,301,865 |
| | 23.32 |
|
| Granted | 485,799 |
| | 173,373 |
| | 659,172 |
| | 26.07 |
|
| Vested | (455,570 | ) | | (62,119 | ) | | (517,689 | ) | | 29.87 |
|
| Forfeited | (44,408 | ) | | (34,953 | ) | | (79,361 | ) | | 38.87 |
|
| Nonvested at December 31, 2017 | 915,558 |
| | 448,429 |
| | 1,363,987 |
| | $ | 21.25 |
|
|
| | | | | | |
| Non-Employee Directors | Number of Shares | | Weighted Average Price |
| Nonvested at January 1, 2015 | 35,136 |
| | $ | 50.08 |
|
| Granted | 25,848 |
| | 34.04 |
|
| Vested | (18,920 | ) | | 46.51 |
|
| Forfeited | — |
| | — |
|
| Nonvested at December 31, 2015 | 42,064 |
| | $ | 41.83 |
|
| Granted | 90,000 |
| | 12.02 |
|
| Vested | (20,248 | ) | | 43.46 |
|
| Forfeited | — |
| | — |
|
| Nonvested at December 31, 2016 | 111,816 |
| | $ | 17.21 |
|
| Granted | 49,104 |
| | 17.92 |
|
| Vested | (43,206 | ) | | 21.24 |
|
| Forfeited | — |
| | — |
|
| Nonvested at December 31, 2017 | 117,714 |
| | $ | 16.03 |
|
The time vested restricted stock awards granted are being recognized over a three year vesting period. During 2016, there were two different performance vested restricted stock awards granted to certain executive officers. The first will cliff vest three years from the grant date based on the company's achievement of certain stock performance measures at the end of the term and will range from 0% to 200% of the restricted shares granted as performance shares. The second will vest, one-third each year, over a three year vesting period based on the company's achievement of cash flow to total assets (CFTA) performance measurement each year and will range from 0% to 200%. Based on a probability assessment of the selected performance criteria at December 31, 2017, the participants are estimated to receive 82% of the 2017, 159% of the 2016, and 100% of the 2015 performance based shares. The CFTA performance measurement at December 31, 2017expense previously recorded for the one-third vesting in 2018 was assessed to vest at 131%. The CFTA performance measurementunvested awards of $2.2 million for future years was assessed to vest at target or 100%.these awards upon cancellation.
The fair value of the restricted stock granted in 2017, 2016, and 2015 at the grant date was $17.4 million, $4.5 million, and $24.5 million, respectively. The aggregate intrinsic value of the 560,895 shares of restricted stock that vested in 2017 on
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
their vesting date was $12.3 million. The aggregate intrinsic value of the 1,481,701 shares of restricted stock outstanding subject to vesting at December 31, 2017 was $32.6 million with a weighted average remaining life of 0.9 of a year.
Employee Stock Option Plan
The Stock Option Plan, provided the granting of options for up to 2,700,000 shares of common stock to officers and employees. The option plan permitted the issuance of qualified or nonqualified stock options. Options granted typically became exercisable at the rate of 20% per year one year after being granted and expire after 10 years from the original grant date. The exercise price for options granted under this plan was the fair market value of the common stock on the date of the grant. In 2006, as a result of the approval of the adoption of the Unit Corporation Stock and Incentive Compensation Plan, no further awards were made under this plan. During 2015, the remaining options expired.
Activity pertaining to the Stock Option Plan is as follows:
|
| | | | | | |
| | Number of Shares | | Weighted Average Exercise Price |
| Outstanding at January 1, 2015 | 9,500 |
| | $ | 37.69 |
|
| Granted | — |
| | — |
|
| Exercised | — |
| | — |
|
| Forfeited | (9,500 | ) | | 37.69 |
|
| Outstanding at December 31, 2015 | — |
| | — |
|
| Granted | — |
| | — |
|
| Exercised | — |
| | — |
|
| Forfeited | — |
| | — |
|
| Outstanding at December 31, 2016 | — |
| | — |
|
| Granted | — |
| | — |
|
| Exercised | — |
| | — |
|
| Forfeited | — |
| | — |
|
| Outstanding at December 31, 2017 | — |
| | $ | — |
|
As of December 31, 2015, there were no further options outstanding or exercisable in this plan.
Non-Employee Directors' Stock Option Plan
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 of Directors and who was not then an employee of the company or any of its subsidiaries was granted an option to purchase 3,500 shares of common stock.
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 option price for eachcancellations resulted in an acceleration of unrecorded stock option wascompensation expense during the fair market valueeight 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 common stockEffective 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 dateEffective Date, we immediately recognized the stock options were granted. The termexpense for the cancelled awards of each option is 10 years and cannot be increased and no stock options were to be exercised during the first six months of its term except in case of death. On May 2, 2012, our stockholders approved the amended plan which succeeds this plan, the remaining available shares were transferred over to the new plan and no further awards were made under the non-employee director option plan.$1.4 million as reorganization costs.
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
ActivitySuccessor Period activity pertaining to nonvested RSUs under the Directors’ PlanLTIP is as follows:
|
| | | | | | |
| | Number of Shares | | Weighted Average Exercise Price |
| Outstanding at January 1, 2015 | 150,500 |
| | $ | 54.18 |
|
| Granted | — |
| | — |
|
| Exercised | — |
| | — |
|
| Forfeited | (21,000 | ) | | 54.35 |
|
| Outstanding at December 31, 2015 | 129,500 |
| | 54.15 |
|
| Granted | — |
| | — |
|
| Exercised | — |
| | — |
|
| Forfeited | (21,000 | ) | | 62.40 |
|
| Outstanding at December 31, 2016 | 108,500 |
| | 52.56 |
|
| Granted | — |
| | — |
|
| Exercised | — |
| | — |
|
| Forfeited | (21,000 | ) | | 57.63 |
|
| Outstanding at December 31, 2017 | 87,500 |
| | $ | 51.34 |
|
| | | | | | | | | | | |
| 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 | |
_______________________
There were no options exercised in 2017.
|
| | | | | | | | |
| | Outstanding and Exercisable
Options at December 31, 2017 |
| Weighted Average Exercise Price | Number of Shares | | Weighted Average Remaining
Contractual Life | | Weighted Average
Exercise Price |
| $31.30 - $41.21 | 38,500 |
| | 1.9 years | | $ | 37.58 |
|
| $53.81 - $73.26 | 49,000 |
| | 2.1 years | | $ | 62.15 |
|
1.There was no activity during the four months ended December 31, 2020.
2.The grants had an aggregate intrinsicgrant date fair value of $8.4 million. Director grants will vest 25% on each of the shares outstanding subjectfollowing 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 options atnonvested RSUs not yet recognized as of December 31, 2017. 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 remaininggrants 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 2.0 years.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) | — | | | — | | | — | | | $ | — | |
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
| | | | | | | | | | | |
| 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 1217 – 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.conditions as well as certain requirements stipulated in the Exit credit agreement. As of December 31, 2017,2021, 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.
Basis 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 swaps to hedge the price risk between NYMEX and its physical delivery points.
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
•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.
Three-way collars. A three-way collar contains a fixed floor price (long put), fixed subfloor price (short put) and a fixed ceiling price (short call). If the market price exceeds the ceiling strike price, we receive the ceiling strike price and pay the market price. If the market price is between the ceiling and the floor strike price, no payments are due from either party. If the market price is below the floor price but above the subfloor price, we receive the floor strike price and pay the market price. If the market price is below the subfloor price, we receive the market price plus the difference between the floor and subfloor strike prices and pay the market price.
We have documented policies and procedures to monitor and control the use of derivative instruments. We do not engage in derivative transactions for speculative purposes. All derivativesWe are recognized on the balance sheetnot required to post any cash collateral with our counterparties and measured at fair value. Any changes in our derivatives' fair value occurring before their maturity (i.e., temporary fluctuations in value) are reported in gain (loss) on derivatives in our Consolidated Statementsno collateral has been posted as of Operations.
At December 31, 2017, the2021.
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
The following non-designated hedges were outstanding:outstanding as of December 31, 2021:
|
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Term | | Commodity | | Contracted Volume | | Weighted Average Fixed Price for Swaps | | Contracted Market |
Jan’18 – Dec’18Jan'22 - Dec'22 | | Natural gas –- swap | | 20,0005,000 MMBtu/day | | $3.0132.61 | | IF –- NYMEX (HH) |
Apr'18 – Oct'18Jan'23 - Dec'23 | | Natural gas –- swap | | 10,00022,000 MMBtu/day | | $2.9902.46 | | IF –- NYMEX (HH) |
Jan’18 – Mar'18Jan'22 - Dec'22 | | Natural gas – basis swap- collar | | 10,00035,000 MMBtu/day | | $(0.208)2.50 - $2.68 | | IF –- NYMEX (HH) |
Nov’18 – Dec'18Jan'22 - Jun'22 | | Natural gas – basisCrude oil - swap | | 10,000 MMBtu/986 Bbl/day | | $(0.208)70.30 | | IF –WTI - NYMEX (HH) |
Jan’18 – Mar'18Jan'22 - Dec'22 | | Natural gas – three-way collarCrude oil - swap | | 60,000 MMBtu/2,300 Bbl/day | | $3.2942.25 | | WTI - $2.63 - $4.07 | | IF – NYMEX (HH) |
Apr’18 – Dec'18Jan'23 - Dec'23 | | Natural gas – three-way collar | | 20,000 MMBtu/day | | $3.00 - $2.50 - $3.51 | | IF – NYMEX (HH) |
Jan’18 – Dec'18 | | Crude oil –- swap | | 3,0001,300 Bbl/day | | $51.3643.60 | | WTI –- NYMEX |
Jan’18 – Mar'18 | | Crude oil – collar | | 500 Bbl/day | | $55.00 - $59.50 | | WTI – NYMEX |
Jan’18 – Dec'18 | | Crude oil – three-way collar | | 2,000 Bbl/day | | $47.50 - $37.50 - $56.08 | | WTI – NYMEX |
Apr’18 – Sep'18 | | Liquids (Propane) – swap | | 1,000 Bbl/day | | $31.16 | | MONT BELVIEU |
After December 31, 2017,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 non-designated hedges were entered into: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 | |
|
| | | | | | | | |
Term | | Commodity | | Contracted Volume | | Weighted Average
Fixed Price for Swaps | | Contracted Market |
Apr’18 – Sep'18 | | Natural gas – swap | | 10,000 MMBtu/day | | $2.925 | | IF – NYMEX (HH) |
Apr’18 – Sep'18 | | Natural gas – collar | | 30,000 MMBtu/day | | $2.67 - $2.97 | | IF – NYMEX (HH) |
Feb’18 – Dec'18 | | Natural gas – basis swap | | 10,000 MMBtu/day | | $(0.678) | | PEPL |
Feb’18 – Dec'18 | | Natural gas – basis swap | | 10,000 MMBtu/day | | $(0.568) | | NGPL MIDCON |
Apr’18 – Oct'18 | | Natural gas – basis swap | | 10,000 MMBtu/day | | $(0.190) | | NGPL TEXOK |
Jan'19 – Dec'19 | | Natural gas – basis swap | | 10,000 MMBtu/day | | $(0.728) | | PEPL |
Jan'19 – Dec'19 | | Natural gas – basis swap | | 10,000 MMBtu/day | | $(0.625) | | NGPL MIDCON |
Jan'19 – Dec'19 | | Natural gas – basis swap | | 20,000 MMBtu/day | | $(0.273) | | NGPL TEXOK |
Jan'20 – Dec'20 | | Natural gas – basis swap | | 20,000 MMBtu/day | | $(0.280) | | NGPL TEXOK |
Apr'18 – Dec'18 | | Crude oil – swap | | 1,000 Bbl/day | | $60.00 | | WTI – NYMEX |
Apr’18 – Sep'18 | | Liquids – swap | | 500 Bbl/day | | $34.10 | | MONT BELVIEU |
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
The following tables presenttable shows the fair values and locations of the derivative transactions recorded in our Consolidated Balance Sheets at December 31:
|
| | | | | | | | | | |
| | | | | Derivative Assets Fair Value |
| | | Balance Sheet Location | | 2017 | | 2016 |
| | | | | (In thousands) |
| Commodity derivatives: | | | | | | |
| Current | | Current derivative assets | | $ | 721 |
| | $ | — |
|
| Long-term | | Non-current derivative assets | | — |
| | 377 |
|
| Total derivative assets | | | | $ | 721 |
| | $ | 377 |
|
|
| | | | | | | | | | |
| | | | | Derivative Liabilities Fair Value |
| | | Balance Sheet Location | | 2017 | | 2016 |
| | | | | (In thousands) |
| Commodity derivatives: | | | | | | |
| Current | | Current derivative liabilities | | $ | 7,763 |
| | $ | 21,564 |
|
| Long-term | | Non-current derivative liabilities | | — |
| | 415 |
|
| Total derivative liabilities | | | | $ | 7,763 |
| | $ | 21,979 |
|
If a legal right of set-off exists, we net the value of the derivative transactions we have with the same counterparty in our Consolidated Balance Sheets.
Effect ofactivity related to derivative instruments onin the Consolidated Statementsconsolidated statements of Operationsoperations for the year ended December 31: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) | | | $ | — | | | | $ | — | | | |
|
| | | | | | | | | | |
| Derivatives Instruments | | Location of Gain or (Loss) Recognized in Income on Derivative | | Amount of Gain or (Loss) Recognized in Income on Derivative |
| | | 2017 | | 2016 |
| | | | | (In thousands) |
| Commodity derivatives | | Gain (loss) on derivatives (1) | | $ | 14,732 |
| | $ | (22,813 | ) |
| Total | | | | $ | 14,732 |
| | $ | (22,813 | ) |
_________________________
| |
(1)
| Amount settled during the period are gains of $173 and $9,658, respectively. |
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
NOTE 1318 – FAIR VALUE MEASUREMENTS
The estimatedinputs available determine the valuation technique that we use to measure the fair value of the assets and liabilities presented in our available-for-sale securities, reflectedconsolidated financial statements. Fair value measurements are categorized into one of three different levels depending on our Unaudited Condensed Consolidated Balance Sheets as Non-current other assets, is based on market quotes. The following is a summary of available-for-sale securities:
|
| | | | | | | | | | | | | | | | |
| | | Cost | | Gross Unrealized Gains | | Gross Unrealized Losses | | Estimated Fair Value |
| | | (In thousands) |
| Equity Securities: | | |
| December 31, 2017 | | $ | 830 |
| | $ | 102 |
| | $ | — |
| | $ | 932 |
|
| December 31, 2016 | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
During the second quarter of 2017, we received available-for-sale securities for early termination fees associated with a long-term drilling contract. We will evaluate the marketable equity securities to determine if any decline in fair value below cost is other-than-temporary. If a decline in fair value below cost is determined to be other-than-temporary, an impairment charge will be recorded and a new cost basis established. We will review several factors to determine whether a loss is other-than-temporary. These factors include, but are not limited to, (i) the length of time a security is in an unrealized loss position, (ii) the extent to which fair value is less than cost, (iii) the financial condition and near-term prospectsobservability of the issuer, and (iv) our intent and ability to holdinputs used in the security for a period of time sufficient to allow for any anticipated recovery in fair value. These securities would be classified as Level 2.
Fair value is defined as the amount that would be received from the sale of an asset or paid for the transfer of a liability in an orderly transaction between market participants (in either case, an exit price). To estimate an exit price, a three-level hierarchy is used prioritizing the valuation techniques used to measure fair value into three levels with the highest priority given to Level 1 and the lowest priority given to Level 3.measurement. The levels are summarized as follows:
•Level 1—unadjustedobservable inputs such as quoted prices in active markets for identical assets and liabilities.
•Level 2—significantother observable pricing inputs, other thansuch as quoted prices included within level 1in inactive markets, or other inputs that are either directly or indirectly observable as of the reporting date. Essentially,date, including inputs (variables used in the pricing models) that are derived principally from or corroborated by observable market data.
•Level 3—generally unobservable inputs which are developed based on the best information available and may include our own internal data.data or estimates about how market participants would value such assets and liabilities.
The inputs available to us determine the valuation technique we use to measure the fair values of our financial instruments.Recurring Fair Value Measurements
The following tables set forthpresent our recurring fair value measurements: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) | |
|
| | | | | | | | | | | | | | | |
| | December 31, 2017 |
| | Level 2 | | Level 3 | | Effect of Netting | | Total |
| | (In thousands) |
| Financial assets (liabilities): | | | | | | | |
| Commodity derivatives: | | | | | | | |
| Assets | $ | 2,137 |
| | $ | 3,344 |
| | $ | (4,760 | ) | | $ | 721 |
|
| Liabilities | (8,973 | ) | | (3,550 | ) | | 4,760 |
| | (7,763 | ) |
| | $ | (6,836 | ) | | $ | (206 | ) | | $ | — |
| | $ | (7,042 | ) |
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
|
| | | | | | | | | | | | | | | |
| | December 31, 2016 |
| | Level 2 | | Level 3 | | Effect of Netting | | Total |
| | (In thousands) |
| Financial assets (liabilities): | | | | | | | |
| Commodity derivatives: | | | | | | | |
| Assets | $ | 878 |
| | $ | 43 |
| | $ | (544 | ) | | $ | 377 |
|
| Liabilities | (15,358 | ) | | (7,165 | ) | | 544 |
| | (21,979 | ) |
| | $ | (14,480 | ) | | $ | (7,122 | ) | | $ | — |
| | $ | (21,602 | ) |
All of our counterparties are subject to master netting arrangements. If a legal right of set-off exists, we net the value of the derivative transactions we have with the same counterparty. We are not required to post any cash collateral with our counterparties and no collateral has been posted as of December 31, 2017.
The following methods and assumptions were used to estimate the fair values of the assets and liabilities in the table above. There were no transfers between Level 2 and Level 3 financial assets (liabilities).
Level 2 Fair Value Measurements
Commodity Derivatives. We measure the fair values of our crude oil and natural gas swaps and collars using estimated internal 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.
Level 3 Fair Value Measurements
Commodity Derivatives. TheWe measure the fair values of our natural gas and crude oil three-way collars areusing estimated using internal discounted cash flow calculations based on forward price curves, quotes obtained from brokers for contracts with similar terms, or quotes obtained from counterparties to the agreements.
The following tables are reconciliations of our level We consider this a Level 3 measurement within the fair value measurements:hierarchy as the calculation uses certain generally unobservable inputs.
|
| | | | | | | |
| | Net Derivatives |
| | For the Year Ended, |
| | December 31, 2017 | | December 31, 2016 |
| | (In thousands) |
| Beginning of period | $ | (7,122 | ) | | $ | 9,094 |
|
| Total gains or losses: | | | |
Included in earnings (1) | 7,791 |
| | (9,042 | ) |
| Settlements | (875 | ) | | (7,174 | ) |
| End of period | $ | (206 | ) | | $ | (7,122 | ) |
| Total gains (losses) for the period included in earnings attributable to the change in unrealized loss relating to assets still held at end of period | $ | 6,916 |
| | $ | (16,216 | ) |
_________________________
| |
(1) | Commodity derivatives are reported in the Consolidated Statements of Operations in gain (loss) on derivatives. |
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
The following table provides quantitative information about our Level 3 unobservable inputs at December 31, 2017:
|
| | | | | | |
Commodity (1) | Fair Value | Valuation Technique | Unobservable Input | Range |
| | (In thousands) | | | |
| Oil collars | $ | (77 | ) | Discounted cash flow | Forward commodity price curve | $0.00 - $2.48 |
| Oil three-way collar | (3,473 | ) | Discounted cash flow | Forward commodity price curve | $0.00 - $5.96 |
| Natural gas three-way collar | 3,344 |
| Discounted cash flow | Forward commodity price curve | $0.00 - $0.68 |
_________________________
| |
(1) | The commodity contracts detailed in this category include non-exchange-traded crude oil collars and crude and natural gas three-way collars that are valued based on NYMEX. The forward pricing range represents the low and high price expected to be received within the settlement period. |
Based on our valuation at December 31, 2017, weWe determined that the non-performance risk with regard toregarding our commodity derivative counterparties was immaterial.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
The following disclosure of the estimated fair value of financial instruments is made in accordance with accounting guidance for financial instruments. We have determined the estimated fair values of other financial instruments by using available market information and valuation methodologies. Considerable judgment is required in interpreting market data to develop the estimates of fair value. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.
At December 31, 2017, theThe carrying values on the consolidated balance sheets for cash and cash equivalents, (classified as Level 1), accounts receivable, accounts payable, other current assets, and current liabilities approximate their fair value because of their short termshort-term nature.
Based on the borrowing rates currently available to us for credit agreement debt with similar terms and maturities and also considering the risk of our non-performance, long-term debt under our credit agreementagreements at December 31, 2017 approximates2021 would approximate its fair value. This debt would beis classified as Level 2.
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
Fair Value of Non-Financial Instruments
ARO. The initial measurement of AROsARO at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with property plant, and equipment. Significant Level 3 inputs used in the calculation of AROs include plugging costs and remaining reserve lives. A reconciliationsummary of the Company’s AROscompany’s ARO activity is presented in Note 711 – 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. During 2016 and 2015, weWe recorded non-cash impairment charges as discussed further in Note 23 – Summary of Significant Accounting Policies.Impairments. The valuationfair value measurement of these assets requiresis categorized as a Level 3 measurement as the discounted cash flow models require the use of significant unobservable inputs classifiedinputs.
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 Level 3. 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.
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 | |
| Finance lease right of use assets | | 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 | |
| Finance lease liabilities | | 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 | |
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
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 | | | $ | — | | | | $ | — | |
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.
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
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.
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
NOTE 1421 – COMMITMENTS AND CONTINGENCIES
Commitments
We lease office space or yards in Edmond and Oklahoma City, Oklahoma; Houston, Texas; Englewood, Colorado; Pinedale, Wyoming; and Canonsburg, Pennsylvania under the terms of operating leases expiring through December 2021. Additionally, we have several compressor rentals, equipment leases, and lease space on short-termfirm transportation commitments to stack excess drilling rig equipment and production inventory.Future minimum rental payments undertransport our natural gas from various systems for approximately $0.9 million over the terms of the leases are approximately $2.7 million, $0.6 million, $0.4 million, and $0.1 million in 2018 through 2021, respectively. Total rent expense incurred was $8.8 million, $11.1 million, and $12.9 million in 2017, 2016, and 2015, respectively.next twelve months.
Environmental
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
During 2014, our mid-stream segment entered into capital lease agreements for twenty compressors with initial terms of seven years. Future capital lease payments under the terms are approximately $6.2 million each year through 2020 and approximately $3.8 million in 2021. Total maintenance and interest remaining related to these leases are $5.9 million and $1.2 million, respectively at December 31, 2017. Annual payments, net of maintenance and interest, average $4.2 million annually through 2021. At the end of the term, our mid-stream segment has the option to purchase the assets at 10% of the fair market value of the assets at that time.
The employee oil and gas limited partnerships require, on the election of a limited partner, that we repurchase the limited partner’s interest at amounts to be determined by appraisal in the future. These repurchases in any one year are limited to 20% of the units outstanding. We made repurchases of approximately $2,900, $5,000, $118,000 in 2017, 2016, and 2015, respectively.
We manage our exposure to environmental liabilities on properties to be acquired by identifying existing problems and assessing the potential liability. We also conduct periodic reviews, on a company-wide basis, to identify changes in our environmental risk profile. These reviews evaluate whether there is a probable liability, its amount, and the likelihood that the liability will be incurred. The amount of anyAny potential liability is determined by considering, among other matters, incremental direct costs of any likely remediation and the proportionate cost of employees who are expected to devote a significant amount of time directly to any possible remediation effort. As it relates to evaluations of purchased properties, depending on the extent of an identified environmental problem, we may exclude a property from the acquisition, require the seller to remediate the property to our satisfaction, or agree to assume liability for the remediation of the property.
We have not historically experienced anysignificant 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 have beenwere resolved while the drilling rig iswas on the location and the cost has been includedlocation. Those costs were in the direct cost of drilling the well.
For 2018, we have committedLitigation
The company is subject to purchase approximately $3.9 million of new drilling rig components.
We are a party to various litigation matters and claims that have arisen in the normal course of our operations. While the results of litigation and claims cannot be predicted with certainty, we believe the reasonably possible losses from such matter, individually andarising in the aggregate,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 not material. Additionally, we believeinsured against various risks, there is no assurance that the probable final outcomenature and amount of such mattersthat insurance will not havebe adequate, in every case, to indemnify us against liabilities arising from future legal proceedings.
In February 2021, UPC finalized a material adverse effect on our resultssettlement agreement for $2.1 million related to a well drilled in Beaver County, Oklahoma during 2013. Certain operational issues arose and one of operations, financial position, or cash flows.the working interest owners in the well filed a lawsuit claiming that UPC’s actions violated its duties under the joint operating agreement and caused damages to the owners in the well. The case went to trial in January 2019 and the jury issued a verdict in favor of the working interest owner, awarding $2.4 million in damages, including pre- and post-judgment interest. UPC appealed the verdict and finalized the settlement agreement while the case was pending review in the Oklahoma Court of Civil Appeals.
NOTE 15 – EQUITY
At-the-Market (ATM) Common Stock Program
On April 4, 2017, we entered into a Distribution Agreement (the Agreement) with a sales agent,May 22, 2020, the Debtors filed petitions for relief under which we may offerChapter 11 of the Bankruptcy Code. The commencement of the Chapter 11 Cases automatically stayed all the proceedings and sell,actions against the Debtors (other than certain regulatory enforcement matters). The Debtors emerged from time to time, through the sales agent shares of our common stock, par value $0.20 per share (the Shares), up to an aggregate offering price of $100.0 million. We intend to use the net proceeds from these sales to fund (or offset costs of) acquisitions, future capital expenditures, repay amounts outstanding under our revolving credit facility, and general corporate purposes.
Under the Agreement, the sales agent may sell the Shares by methods deemed to be an “at-the-market” offering as defined in Rule 415 promulgated under the Securities Act of 1933, as amended, including sales made directlyChapter 11 Cases on the NYSE, on any other existing trading market forEffective Date. On the Shares or to or through a market maker. In addition, underEffective Date, the Agreement,automatic stay was terminated and replaced with the sales agent may sellinjunction provisions in the Shares by any other method permitted by law, including in privately negotiated transactions. Subject toConfirmation Order and the terms and conditionsPlan.
The commencement of the Agreement,Chapter 11 Cases also automatically stayed all proceedings and actions against the sales agent will use commercially reasonable efforts, consistentPredecessor company (other than certain regulatory enforcement matters). Effective at emergence from the Chapter 11 Cases, the automatic stay was terminated and replaced with its normal trading and sales practices and applicable state and federal law, rules and regulationsthe injunction provisions in the Confirmation Order and the rules of the NYSE, to sell the Shares from time to time, based on our instructions (including any price, time or size limits or other customary parameters or conditions that we may impose).Plan.
We are not obligated to make any sales of the Shares under the Agreement. The offering of Shares under the Agreement will terminate on the earlier of (1) the sale of all of the Shares subject to the Agreement or (2) the termination of the Agreement by the sales agent or us. We will pay the sales agent a commission of 2.0% of the gross sales price per share sold and have agreed to provide the sales agent with customary indemnification and contribution rights.
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.
As
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.
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, 2017, we sold 787,547 shares2021 and 2020, respectively, as well as a concentration of our common stock resultingcash equivalents of $27.0 million in net proceedsa money market fund comprised of approximately $18.6 million. No shares were sold in the fourth quarterU.S. Government and U.S. Treasury securities as of 2017.
Accumulated Other Comprehensive Income
Components of accumulated other comprehensive income were as follows for the years ended December 31:
|
| | | | | | | | | | | |
| | 2017 | | 2016 | | 2015 |
| | (In thousands) |
| Unrealized appreciation on securities, before tax | $ | 102 |
| | $ | — |
| | $ | — |
|
| Tax expense | (39 | ) | | — |
| | — |
|
| Unrealized appreciation on securities, net of tax | $ | 63 |
| | $ | — |
| | $ | — |
|
Changes in accumulated other comprehensive income by component, net of tax, for the years ended December 31, are as follows: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.
|
| | | | | | | | | | | |
| | Net Gains on Equity Securities |
| | 2017 | | 2016 | | 2015 |
| | (In thousands) |
| Balance at January 1: | $ | — |
| | $ | — |
| | $ | — |
|
| Unrealized appreciation before reclassifications | 63 |
| | — |
| | — |
|
| Amounts reclassified from accumulated other comprehensive income | — |
| | — |
| | — |
|
| Net current-period other comprehensive income | 63 |
| | — |
| | — |
|
| Balance at December 31: | $ | 63 |
| | $ | — |
| | $ | — |
|
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
NOTE 1623 – INDUSTRY SEGMENT INFORMATION
We have three main business segments offering different products and services:
•Oil and natural gas,
•Contract drilling, and
Mid-stream•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. Our oil and natural gas production outside the United States is not significant.
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
The following table providestables provide certain information about the operations ofand 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 | | | — | | | — | | | 0 | | 76,107 | |
| Gas gathering and processing | | — | | | 0 | | 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.
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, 2017 |
| | | Oil and Natural Gas | | Contract Drilling | | Mid-stream | | Other | | Eliminations | | Total Consolidated |
| | | (In thousands) |
| Revenues: | | | | | | | | | | | | |
| Oil and natural gas | | $ | 357,744 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 357,744 |
|
| Contract drilling | | — |
| | 188,172 |
| | — |
| | — |
| | (13,452 | ) | | 174,720 |
|
| Gas gathering and processing | | — |
| | — |
| | 277,049 |
| | — |
| | (69,873 | ) | | 207,176 |
|
| Total revenues | | 357,744 |
| | 188,172 |
| | 277,049 |
| | — |
| | (83,325 | ) | | 739,640 |
|
| Expenses: | | | | | | | | | | | | |
| Operating costs: | | | | | | | | | | | | |
| Oil and natural gas | | 135,532 |
| | — |
| | — |
| | — |
| | (4,743 | ) | | 130,789 |
|
| Contract drilling | | — |
| | 134,432 |
| | — |
| | — |
| | (11,832 | ) | | 122,600 |
|
| Gas gathering and processing | | — |
| | — |
| | 220,613 |
| | — |
| | (65,130 | ) | | 155,483 |
|
| Total operating costs | | 135,532 |
| | 134,432 |
| | 220,613 |
| | — |
| | (81,705 | ) | | 408,872 |
|
| Depreciation, depletion, and amortization | | 101,911 |
| | 56,370 |
| | 43,499 |
| | 7,477 |
| | — |
| | 209,257 |
|
| Total expenses | | 237,443 |
| | 190,802 |
| | 264,112 |
| | 7,477 |
| | (81,705 | ) | | 618,129 |
|
Total operating income (loss) (1) | | 120,301 |
| | (2,630 | ) | | 12,937 |
| | (7,477 | ) | | (1,620 | ) | | |
| General and administrative expense | | — |
| | — |
| | — |
| | (38,087 | ) | | — |
| | (38,087 | ) |
| Gain (loss) on disposition of assets | | 228 |
| | (776 | ) | | 25 |
| | 850 |
| | — |
| | 327 |
|
| Gain on derivatives | | — |
| | — |
| | — |
| | 14,732 |
| | — |
| | 14,732 |
|
| Interest expense, net | | — |
| | — |
| | — |
| | (38,334 | ) | | — |
| | (38,334 | ) |
| Other | | — |
| | — |
| | — |
| | 21 |
| | — |
| | 21 |
|
| Income (loss) before income taxes | | $ | 120,529 |
| | $ | (3,406 | ) | | $ | 12,962 |
| | $ | (68,295 | ) | | $ | (1,620 | ) | | $ | 60,170 |
|
| | | | | | | | | | | | | |
| Identifiable assets: | | | | | | | | | | | | |
Oil and natural gas (2) | | $ | 1,127,900 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 1,127,900 |
|
| Contract drilling | | — |
| | 933,063 |
| | — |
| | — |
| | — |
| | 933,063 |
|
| Gas gathering and processing | | — |
| | — |
| | 438,571 |
| | — |
| | — |
| | 438,571 |
|
Total identifiable assets (3) | | 1,127,900 |
| | 933,063 |
| | 438,571 |
| | — |
| | — |
| | 2,499,534 |
|
| Corporate land and building | | — |
| | — |
| | — |
| | 56,854 |
| | — |
| | 56,854 |
|
Other corporate assets (4) | | — |
| | — |
| | — |
| | 25,064 |
| | — |
| | 25,064 |
|
| Total assets | | $ | 1,127,900 |
| | $ | 933,063 |
| | $ | 438,571 |
| | $ | 81,918 |
| | $ | — |
| | $ | 2,581,452 |
|
| | | | | | | | | | | | | |
| Capital expenditures: | | $ | 270,443 |
| | $ | 36,148 |
| | $ | 22,168 |
| | $ | 3,521 |
| | $ | — |
| | $ | 332,280 |
|
_______________________
| |
(1) | Operating income (loss) is total operating revenues less operating expenses, depreciation, depletion, and amortization and does not include general corporate expenses, gain (loss) on disposition of assets, gain on derivatives, interest expense, other income, or income taxes. |
| |
(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) | Corporate assets are principally cash and cash equivalents, short-term investments, transportation equipment, furniture, and equipment. |
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 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.
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, 2016 |
| | | Oil and Natural Gas | | Contract Drilling | | Mid-stream | | Other | | Eliminations | | Total Consolidated |
| | | (In thousands) |
| Revenues: | | | | | | | | | | | | |
| Oil and natural gas | | $ | 294,221 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 294,221 |
|
| Contract drilling | | — |
| | 122,086 |
| | — |
| | — |
| | — |
| | 122,086 |
|
| Gas gathering and processing | | — |
| | — |
| | 237,785 |
| | — |
| | (51,915 | ) | | 185,870 |
|
| Total revenues | | 294,221 |
| | 122,086 |
| | 237,785 |
| | — |
| | (51,915 | ) | | 602,177 |
|
| Expenses: | | | | | | | | | | | | |
| Operating costs: | | | | | | | | | | | | |
| Oil and natural gas | | 126,739 |
| | — |
| | — |
| | — |
| | (6,555 | ) | | 120,184 |
|
| Contract drilling | | — |
| | 88,154 |
| | — |
| | — |
| | — |
| | 88,154 |
|
| Gas gathering and processing | | — |
| | — |
| | 182,969 |
| | — |
| | (45,360 | ) | | 137,609 |
|
| Total operating costs | | 126,739 |
| | 88,154 |
| | 182,969 |
| | — |
| | (51,915 | ) | | 345,947 |
|
| Depreciation, depletion and amortization | | 113,811 |
| | 46,992 |
| | 45,715 |
| | 1,835 |
| | — |
| | 208,353 |
|
Impairments (1) | | 161,563 |
| | — |
| | — |
| | — |
| | — |
| | 161,563 |
|
| Total expenses | | 402,113 |
| | 135,146 |
| | 228,684 |
| | 1,835 |
| | (51,915 | ) | | 715,863 |
|
Total operating income (loss) (2) | | (107,892 | ) | | (13,060 | ) | | 9,101 |
| | (1,835 | ) | | — |
| | |
| General and administrative expense | | — |
| | — |
| | — |
| | (33,337 | ) | | — |
| | (33,337 | ) |
| Gain (loss) on disposition of assets | | (324 | ) | | 3,184 |
| | (302 | ) | | (18 | ) | | — |
| | 2,540 |
|
| Loss on derivatives | | — |
| | — |
| | — |
| | (22,813 | ) | | — |
| | (22,813 | ) |
| Interest expense, net | | — |
| | — |
| | — |
| | (39,829 | ) | | — |
| | (39,829 | ) |
| Other | | — |
| | — |
| | — |
| | 307 |
| | — |
| | 307 |
|
| Income (loss) before income taxes | | $ | (108,216 | ) | | $ | (9,876 | ) | | $ | 8,799 |
| | $ | (97,525 | ) | | $ | — |
| | $ | (206,818 | ) |
| | | | | | | | | | | | | |
| Identifiable assets: | | | | | | | | | | | | |
Oil and natural gas (3) | | $ | 965,159 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 965,159 |
|
| Contract drilling | | — |
| | 941,676 |
| | — |
| | — |
| | — |
| | 941,676 |
|
| Gas gathering and processing | | — |
| | — |
| | 461,600 |
| | — |
| | — |
| | 461,600 |
|
Total identifiable assets (4) | | 965,159 |
| | 941,676 |
| | 461,600 |
| | — |
| | — |
| | 2,368,435 |
|
| Corporate land and building | | — |
| | — |
| | — |
| | 58,188 |
| | — |
| | 58,188 |
|
Other corporate assets (5) | | — |
| | — |
| | — |
| | 52,680 |
| | — |
| | 52,680 |
|
| Total assets | | $ | 965,159 |
| | $ | 941,676 |
| | $ | 461,600 |
| | $ | 110,868 |
| | $ | — |
| | $ | 2,479,303 |
|
| | | | | | | | | | | | | |
| Capital expenditures: | | $ | 89,562 |
| | $ | 19,134 |
| | $ | 16,796 |
| | $ | 16,663 |
| | $ | — |
| | $ | 142,155 |
|
_______________________
| |
(1) | We incurred non-cash ceiling test write-down of our oil and natural gas properties of $161.6 million pre-tax ($100.6 million, net of tax). |
| |
(2) | Operating income (loss) is total operating revenues less operating expenses, depreciation, depletion, amortization, and impairment and does not include general corporate expenses, gain (loss) on disposition of assets, loss on derivatives, interest expense, other income (loss), or income taxes. |
| |
(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) | Corporate assets are principally cash and cash equivalents, short-term investments, transportation equipment, furniture, and equipment. |
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
| | | | | | | | | | | | | | | | Predecessor |
| | | Year Ended December 31, 2015 | | Eight Months Ended August 31, 2020 |
| | | Oil and Natural Gas | | Contract Drilling | | Mid-stream | | Other | | Eliminations | | Total Consolidated | | Oil and Natural Gas | | Contract Drilling | | Mid-Stream | | Corporate and Other | | Eliminations | | Total Consolidated |
| | | (In thousands) | | (In thousands) |
| Revenues: | | | | | | | | | | | | | Revenues: | |
| Oil and natural gas | | $ | 385,774 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 385,774 |
| Oil and natural gas | | $ | 103,443 | | | $ | — | | | $ | — | | | $ | — | | | $ | (4) | | | $ | 103,439 | |
| Contract drilling | | — |
| | 287,767 |
| | — |
| | — |
| | (22,099 | ) | | 265,668 |
| Contract drilling | | — | | | 73,519 | | | — | | | — | | | — | | | 73,519 | |
| Gas gathering and processing | | — |
| | — |
| | 268,012 |
| | — |
| | (65,223 | ) | | 202,789 |
| Gas gathering and processing | | — | | | — | | | 114,531 | | | — | | | (14,532) | | | 99,999 | |
Total revenues | | 385,774 |
| | 287,767 |
| | 268,012 |
| | — |
| | (87,322 | ) | | 854,231 |
| | 103,443 | | | 73,519 | | | 114,531 | | | — | | | (14,536) | | | 276,957 | |
| Expenses: | | | | | | | | | | | | | Expenses: | | | | | | | | | | | | |
| Operating costs: | | | | | | | | | | | | | Operating costs: | |
| Oil and natural gas | | 170,831 |
| | — |
| | — |
| | — |
| | (4,785 | ) | | 166,046 |
| Oil and natural gas | | 119,664 | | | — | | | — | | | — | | | (1,973) | | | 117,691 | |
| Contract drilling | | — |
| | 174,757 |
| | — |
| | — |
| | (18,349 | ) | | 156,408 |
| Contract drilling | | — | | | 51,811 | | | — | | | — | | | (1) | | | 51,810 | |
| Gas gathering and processing | | — |
| | — |
| | 221,994 |
| | — |
| | (60,438 | ) | | 161,556 |
| Gas gathering and processing | | — | | | — | | | 80,607 | | | — | | | (12,562) | | | 68,045 | |
| Total operating costs | | 170,831 |
| | 174,757 |
| | 221,994 |
| | — |
| | (83,572 | ) | | 484,010 |
| Total operating costs | | 119,664 | | | 51,811 | | | 80,607 | | | — | | | (14,536) | | | 237,546 | |
| Depreciation, depletion and amortization | | 251,944 |
| | 56,135 |
| | 43,676 |
| | 987 |
| | — |
| | 352,742 |
| |
| Depreciation, depletion, and amortization | | Depreciation, depletion, and amortization | | 68,762 | | | 15,544 | | | 29,371 | | | 1,819 | | | — | | | 115,496 | |
Impairments (1)(2) | | 1,599,348 |
| | 8,314 |
| | 26,966 |
| | — |
| | — |
| | 1,634,628 |
| | 393,726 | | | 410,126 | | | 63,962 | | | — | | | — | | | 867,814 | |
| Total expenses | | 2,022,123 |
| | 239,206 |
| | 292,636 |
| | 987 |
| | (83,572 | ) | | 2,471,380 |
| Total expenses | | 582,152 | | | 477,481 | | | 173,940 | | | 1,819 | | | (14,536) | | | 1,220,856 | |
Total operating income (loss) (2) | | (1,636,349 | ) | | 48,561 |
| | (24,624 | ) | | (987 | ) | | (3,750 | ) | | | |
| General and administrative expense | | — |
| | — |
| | — |
| | (34,358 | ) | | — |
| | (34,358 | ) | |
| Gain (loss) on disposition of assets | | (147 | ) | | (7,516 | ) | | 465 |
| | (31 | ) | | — |
| | (7,229 | ) | |
| Gain on derivatives | | — |
| | — |
| | — |
| | 26,345 |
| | — |
| | 26,345 |
| |
| Interest expense, net | | — |
| | — |
| | — |
| | (31,963 | ) | | — |
| | (31,963 | ) | |
| Loss on abandonment of assets | | Loss on abandonment of assets | | 17,641 | | | 1,092 | | | — | | | — | | | — | | | 18,733 | |
| General and administrative | | General and administrative | | — | | | — | | | — | | | 42,766 | | | — | | | 42,766 | |
| (Gain) loss on disposition of assets | | (Gain) loss on disposition of assets | | (160) | | | (1,390) | | | (18) | | | 1,479 | | | — | | | (89) | |
| Loss from operations | | Loss from operations | | (496,190) | | | (403,664) | | | (59,391) | | | (46,064) | | | — | | | (1,005,309) | |
| Loss on derivatives | | Loss on derivatives | | — | | | — | | | — | | | (10,704) | | | — | | | (10,704) | |
| Write-off of debt issuance costs | | Write-off of debt issuance costs | | — | | | — | | | — | | | (2,426) | | | — | | | (2,426) | |
| Reorganization items, net | | Reorganization items, net | | 15,504 | | | (183,664) | | | (71,016) | | | 373,151 | | | — | | | 133,975 | |
| Interest, net | | Interest, net | | — | | | — | | | (1,888) | | | (20,936) | | | — | | | (22,824) | |
| Other | | — |
| | — |
| | — |
| | 45 |
| | — |
| | 45 |
| Other | | 458 | | | 1,449 | | | 50 | | | 77 | | | — | | | 2,034 | |
| Income (loss) before income taxes | | $ | (1,636,496 | ) | | $ | 41,045 |
| | $ | (24,159 | ) | | $ | (40,949 | ) | | $ | (3,750 | ) | | $ | (1,664,309 | ) | Income (loss) before income taxes | | $ | (480,228) | | | $ | (585,879) | | | $ | (132,245) | | | $ | 293,098 | | | $ | — | | | $ | (905,254) | |
| | | | | | | | | | | | | | |
| Identifiable assets: | | | | | | | | | | | | | |
Oil and natural gas (3) | | $ | 1,218,036 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 1,218,036 |
| |
| Contract drilling | | — |
| | 993,015 |
| | — |
| | — |
| | — |
| | 993,015 |
| |
| Gas gathering and processing | | — |
| | — |
| | 478,661 |
| | — |
| | — |
| | 478,661 |
| |
Total identifiable assets (4) | | 1,218,036 |
| | 993,015 |
| | 478,661 |
| | — |
| | — |
| | 2,689,712 |
| |
| Corporate land and building | | — |
| | — |
| | — |
| | 49,890 |
| | — |
| | 49,890 |
| |
Other corporate assets (5) | | — |
| | — |
| | — |
| | 60,240 |
| |
|
| | 60,240 |
| |
| Total assets | | $ | 1,218,036 |
| | $ | 993,015 |
| | $ | 478,661 |
| | $ | 110,130 |
| | $ | — |
| | $ | 2,799,842 |
| |
| | | | | | | | | | | | | | |
| Capital expenditures: | | $ | 267,944 |
| | $ | 84,802 |
| | $ | 63,476 |
| | $ | 38,065 |
| | $ | — |
| | $ | 454,287 |
| Capital expenditures: | | $ | 5,350 | | | $ | 2,438 | | | $ | 9,342 | | | $ | 83 | | | $ | — | | | $ | 17,213 | |
_______________________
| |
(1) | We incurred non-cash ceiling test write-down of our oil and natural gas properties of $1.6 billion pre-tax ($1.0 billion, net of tax). Impairment for contract drilling equipment includes an $8.3 million pre-tax write-down for 30 drilling rigs and other drilling equipment. Impairment for gas gathering and processing systems includes $27.0 million pre-tax write-down for three of our systems, Bruceton Mills, Midwell, and Spring Creek. |
| |
(2) | Operating income (loss) is total operating revenues less operating expenses, depreciation, depletion, amortization, and impairment and does not include general corporate expenses, gain (loss) on disposition of assets, gain on derivatives, interest expense, other income (loss), or income taxes. |
| |
(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) | Corporate assets are principally cash and cash equivalents, short-term investments, transportation equipment, furniture, and equipment. |
____________________
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.
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
NOTE 1724 – SELECTED QUARTERLYSUPPLEMENTAL CONDENSED CONSOLIDATING FINANCIAL INFORMATION
Summarized unaudited quarterlyThe 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 as follows: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.
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
|
| | | | | | | | | | | | | | | | |
| | Three Months Ended | |
| | March 31 | | June 30 | | September 30 | | December 31 | |
| | (In thousands except per share amounts) | |
| 2016 | | | | | | | | |
| Revenues | $ | 136,184 |
| | $ | 138,305 |
| | $ | 153,408 |
| | $ | 174,280 |
| |
Gross income (loss) (1) | $ | (49,745 | ) | | $ | (73,830 | ) | | $ | (26,893 | ) | | $ | 36,782 |
| |
| Net income (loss) | $ | (41,149 | ) | | $ | (72,136 | ) | | $ | (24,022 | ) | | $ | 1,683 |
| |
| Net income (loss) per common share: | | | | | | | | |
Basic (2) | $ | (0.83 | ) | | $ | (1.44 | ) | | $ | (0.48 | ) | | $ | 0.03 |
| |
Diluted (2) | $ | (0.83 | ) | | $ | (1.44 | ) | | $ | (0.48 | ) | | $ | 0.03 |
| |
| 2017 | | | | | | | | |
| Revenues | $ | 175,724 |
| | $ | 170,581 |
| | $ | 188,488 |
| | $ | 204,847 |
| |
Gross income (1) | $ | 32,657 |
| | $ | 24,462 |
| | $ | 27,181 |
| | $ | 37,211 |
| |
| Net income | $ | 15,929 |
| | $ | 9,059 |
| | $ | 3,705 |
| | $ | 89,155 |
| |
| Net income per common share: | | | | | | | | |
| Basic | $ | 0.32 |
| | $ | 0.18 |
| | $ | 0.07 |
| | $ | 1.74 |
| |
Diluted (2) | $ | 0.31 |
| | $ | 0.17 |
| | $ | 0.07 |
| | $ | 1.71 |
| |
_________________________ | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Predecessor |
| Eight Months Ended August 31, 2020 |
| Parent | | Combined Guarantor Subsidiaries | | Combined Non-Guarantor Subsidiaries | | Consolidating Adjustments | | Total Consolidated |
| (In thousands) |
| Revenues | $ | — | | | $ | 176,962 | | | $ | 114,531 | | | $ | (14,536) | | | $ | 276,957 | |
| Expenses: | | | | | | | | | |
| Operating costs | — | | | 171,476 | | | 80,607 | | | (14,537) | | | 237,546 | |
| Depreciation, depletion, and amortization | 1,819 | | | 84,306 | | | 29,371 | | | — | | | 115,496 | |
| Impairments | — | | | 803,852 | | | 63,962 | | | — | | | 867,814 | |
| Loss on abandonment of assets | — | | | 18,733 | | | — | | | — | | | 18,733 | |
| General and administrative | — | | | 42,766 | | | — | | | — | | | 42,766 | |
| (Gain) loss on disposition of assets | 1,479 | | | (1,550) | | | (18) | | | — | | | (89) | |
| Total operating costs | 3,298 | | | 1,119,583 | | | 173,922 | | | (14,537) | | | 1,282,266 | |
| Income (loss) from operations | (3,298) | | | (942,621) | | | (59,391) | | | 1 | | | (1,005,309) | |
| Interest, net | (20,936) | | | — | | | (1,888) | | | — | | | (22,824) | |
| Write-off of debt issuance costs | (2,426) | | | — | | | — | | | — | | | (2,426) | |
| Loss on derivatives | (10,704) | | | — | | | — | | | — | | | (10,704) | |
| Reorganization items | 373,151 | | | (168,160) | | | (71,016) | | | — | | | 133,975 | |
| Other, net | 79 | | | 1,906 | | | 49 | | | — | | | 2,034 | |
| Income (loss) before income taxes | 335,866 | | | (1,108,875) | | | (132,246) | | | 1 | | | (905,254) | |
| Income tax benefit | (14,630) | | | — | | | — | | | — | | | (14,630) | |
| Equity in net earnings from investment in subsidiaries, net of taxes | (1,241,120) | | | — | | | — | | | 1,241,120 | | | — | |
| Net loss | (890,624) | | | (1,108,875) | | | (132,246) | | | 1,241,121 | | | (890,624) | |
| Less: net income attributable to non-controlling interest | 40,388 | | | — | | | 40,388 | | | (40,388) | | | 40,388 | |
| Net loss attributable to Unit Corporation | $ | (931,012) | | | $ | (1,108,875) | | | $ | (172,634) | | | $ | 1,281,509 | | | $ | (931,012) | |
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
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) | |
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
Condensed Consolidating Statements of Cash Flows | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Predecessor |
| Eight Months Ended August 31, 2020 |
| | Parent | | Combined Guarantor Subsidiaries | | Combined Non-Guarantor Subsidiaries | | Consolidating Adjustments | | Total Consolidated |
| | (In thousands) |
| OPERATING ACTIVITIES: | | | | | | | | | |
| Net cash provided by (used in) operating activities | $ | (207,593) | | | $ | 82,769 | | | $ | 32,922 | | | $ | 136,858 | | | $ | 44,956 | |
| INVESTING ACTIVITIES: | | | | | | | | | |
| Capital expenditures | (986) | | | (14,585) | | | (10,204) | | | — | | | (25,775) | |
| Producing properties and other acquisitions | — | | | (382) | | | — | | | — | | | (382) | |
| Proceeds from disposition of assets | 1,169 | | | 4,772 | | | 77 | | | — | | | 6,018 | |
| Net cash provided by (used in) investing activities | 183 | | | (10,195) | | | (10,127) | | | — | | | (20,139) | |
| FINANCING ACTIVITIES: | | | | | | | | | |
| Borrowings under credit agreement, including borrowings under DIP credit facility | 55,300 | | | — | | | 32,100 | | | — | | | 87,400 | |
| Payments under credit agreement | (31,500) | | | — | | | (32,600) | | | — | | | (64,100) | |
| DIP financing costs | (990) | | | — | | | — | | | — | | | (990) | |
| Exit facility financing costs | (3,225) | | | — | | | — | | | — | | | (3,225) | |
| Intercompany borrowings (advances), net | 210,398 | | | (72,642) | | | (898) | | | (136,858) | | | — | |
| Payments on finance leases | — | | | — | | | (2,757) | | | — | | | (2,757) | |
| Employee taxes paid by withholding shares | (43) | | | — | | | — | | | — | | | (43) | |
| Bank overdrafts | (7,269) | | | — | | | (1,464) | | | — | | | (8,733) | |
| Net cash provided by (used in) financing activities | 222,671 | | | (72,642) | | | (5,619) | | | (136,858) | | | 7,552 | |
| Net increase (decrease) in cash and cash equivalents | 15,261 | | | (68) | | | 17,176 | | | — | | | 32,369 | |
| Cash and cash equivalents, beginning of period | 503 | | | 68 | | | — | | | — | | | 571 | |
| Cash and cash equivalents, end of period | $ | 15,764 | | | $ | — | | | $ | 17,176 | | | $ | — | | | $ | 32,940 | |
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
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 $726.3 million at the Effective Date, as reconciled below.
We estimated the enterprise value of the Successor using three valuation methods: net asset value (NAV), comparable public company analysis, and discounted cash flow (DCF). The NAV is a looking forward methodology under which future cash flows are discounted using various discount rates depending on reserve category. Similarly, DCF projects future cash flows which are discounted at rates above and below the company’s estimated weighted average cost of capital. The comparable public company analysis is based on the enterprise values of selected public companies with operating and financial characteristics comparable to the company. Under this methodology, certain financial multiples that measure financial performance and value are calculated for each selected company and then applied to imply an estimated enterprise value of the company.
The following table reconciles the enterprise value to the estimated fair value of the Successor's equity at the Effective Date (in thousands):
| | | | | |
(1)Enterprise value | Gross income (loss) excludes general$ | 559,205 | |
| Less: Fair value of noncontrolling interest | (242,200) | |
| Enterprise value of Unit interests | 317,005 | |
Plus: Cash and administrative expense, interest expense, (gain) loss on dispositioncash equivalents | 25,482 | |
| Plus: Restricted cash | 7,458 | |
Less: Fair value of assets, gain (loss) on derivatives, income taxes, and other income (loss).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):
| | | | | |
(2)Enterprise value | The earnings (loss) per share for$ | 559,205 | |
| Plus: Cash and cash equivalents | 25,482 | |
| Plus: Restricted cash | 7,458 | |
Plus: Current liabilities (excluding the year's four quarters does not equal annual income (loss) per share.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 | |
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.
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | As of September 1, 2020 |
| | Predecessor | | Reorganization Adjustments (1) | | Fresh Start Adjustments (11) | | Successor |
| ASSETS | | (In thousands) |
| Current assets: | | | | | | | | |
| Cash and cash equivalents | | $ | 32,280 | | | $ | (6,798) | | (2) | $ | — | | | $ | 25,482 | |
| Restricted cash | | — | | | 7,458 | | (3) | — | | | 7,458 | |
| Accounts receivable, net | | 50,621 | | | — | | | — | | | 50,621 | |
| Materials and supplies | | 64 | | | — | | | (64) | | (12) | | — | |
| Current income tax receivable | | 850 | | | — | | | — | | | 850 | |
| Prepaid expenses and other | | 13,692 | | | 6,382 | | (4) | (990) | | (13) | | 19,084 | |
| Total current assets | | 97,507 | | | 7,042 | | | (1,054) | | | 103,495 | |
| Property and equipment: | | | | | | | | |
| Oil and natural gas properties, on the full cost method: | | | | | | | | |
| Proved properties | | 6,539,816 | | | — | | | (6,301,532) | | (14) | | 238,284 | |
| Unproved properties not being amortized | | 30,205 | | | — | | | (30,205) | | (14) | | — | |
| Drilling equipment | | 1,285,024 | | | — | | | (1,221,566) | | (15) | | 63,458 | |
| Gas gathering and processing equipment | | 833,788 | | | — | | | (583,690) | | (15) | | 250,098 | |
| Saltwater disposal systems | | 43,541 | | | — | | | (43,541) | | (15) | | — | |
| Land and building | | 59,080 | | | — | | | (26,445) | | (15) | | 32,635 | |
| Transportation equipment | | 15,577 | | | — | | | (12,263) | | (15) | | 3,314 | |
| Other | | 57,427 | | | — | | | (47,469) | | (15) | | 9,958 | |
| | 8,864,458 | | | — | | | (8,266,711) | | | 597,747 | |
| Less accumulated depreciation, depletion, amortization, and impairment | | 7,923,868 | | | — | | | (7,923,868) | | (14) (15) | — | |
| Net property and equipment | | 940,590 | | | — | | | (342,843) | | | 597,747 | |
| Right of use asset | | 7,476 | | | — | | | (659) | | (16) | | 6,817 | |
| Other assets | | 24,666 | | | (6,382) | | (4) | — | | | 18,284 | |
| Total assets | | $ | 1,070,239 | | | $ | 660 | | | $ | (344,556) | | | $ | 726,343 | |
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 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 | | 0 | | 0 | | 0 | | 0 |
| Shareholders’ equity: | | | | | | | | |
| Predecessor preferred stock, $1.00 par value, 5,000,000 shares authorized, none issued at December 31, 2019 | | — | | | — | | | — | | | — | |
| Predecessor common stock, $0.20 par value, 175,000,000 shares authorized, 55,443,393 shares issued as of December 31, 2019 | | 10,704 | | | (10,704) | | (9) | — | | | — | |
| Predecessor capital in excess of par value | | 650,153 | | | (650,153) | | (9) | — | | | — | |
| Successor preferred stock, $0.01 par value, 1,000,000 shares authorized, none issued at September 1, 2020 | | — | | | — | | | — | | | — | |
| Successor common stock, $0.01 par value, 25,000,000 authorized, 12,000,000 issued at September 1, 2020 | | — | | | 120 | | (8) | — | | | 120 | |
| Successor capital in excess of par value | | — | | | 197,203 | | (8) | — | | | 197,203 | |
| Retained earnings (deficit) | | (818,679) | | | 1,215,619 | | (10) | (396,940) | | (20) | | — | |
| Total shareholders’ equity attributable to Unit Corporation | | (157,822) | | | 752,085 | | | (396,940) | | | 197,323 | |
| Non-controlling interests in consolidated subsidiaries | | 171,184 | | | — | | | 71,016 | | (21) | | 242,200 | |
| Total shareholders' equity | | 13,362 | | | 752,085 | | | (325,924) | | | 439,523 | |
| Total liabilities and shareholders’ equity | | $ | 1,070,239 | | | $ | 660 | | | $ | (344,556) | | | $ | 726,343 | |
Reorganization Adjustments
(1)Reflects accounts recorded as of the Effective Date, including among other items, settlement of the Predecessor's liabilities subject to compromise, cancellation of the Predecessor's equity, issuance of the New Common Stock and the Warrants, repayment of certain of Predecessor's liabilities and settlement with holders of the Notes.
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
(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):
| | | | | |
| Liabilities subject to compromise before the Effective Date: | |
| 6.625% senior subordinated notes due 2021 (including accrued interest as of the petition date) | $ | 672,369 | |
| Accounts payable | 1,179 | |
| Employee separation benefit plan obligations | 23,394 | |
| Litigation settlements | 45,000 | |
| Royalty suspense accounts payable | 20,273 | |
| Total liabilities subject to compromise | 762,215 | |
| Separation settlement treatment | (6,905) | |
Successor Common Stock and APIC(1) issued to allowed claim holders | (175,521) | |
| Successor Common Stock and APIC for disputed claims reserve | (11,936) | |
| Gain on settlement of liabilities subject to compromise | $ | 567,853 | |
(1) Balance excludes the Successor Common Stock and APIC of $9.9 million to the 5% Equity Facility which was not a liability subject to compromise.
(9)Represents the cancellation of Old Common Stock.
(10)Represents the cumulative impact to Predecessor retained earnings of the reorganization adjustments described above.
Fresh Start Adjustments
(11)Reflects accounts recorded as of the Effective Date for the fresh start adjustments based on the methodologies noted below.
(12)Represents the reclassification of materials and supplies to proved properties.
(13)Represents the write off of the Predecessor's unamortized debt fees related to the DIP facility.
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
(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.
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) | |
SUPPLEMENTAL OIL AND GAS DISCLOSURES
(UNAUDITED)
The supplemental data presented herein reflects information for all our oil and natural gas producing activities. Our oil and gas operations are substantially located in the United States.
Capitalized Costs
The capitalized costs at year endas of December 31, 2021 and costs incurred during the year2020 were as follows:
|
| | | | | | | | | | | |
| | 2017 | | 2016 | | 2015 |
| | (In thousands) |
| Capitalized costs: | | | | | |
| Proved properties | $ | 5,712,813 |
| | $ | 5,446,305 |
| | $ | 5,401,618 |
|
| Unproved properties | 296,764 |
| | 314,867 |
| | 337,099 |
|
| | 6,009,577 |
| | 5,761,172 |
| | 5,738,717 |
|
| Accumulated depreciation, depletion, amortization, and impairment | (4,996,696 | ) | | (4,900,304 | ) | | (4,631,404 | ) |
| Net capitalized costs | $ | 1,012,881 |
| | $ | 860,868 |
| | $ | 1,107,313 |
|
| Cost incurred: | | | | | |
| Unproved properties acquired | $ | 47,029 |
| | $ | 21,675 |
| | $ | 41,777 |
|
| Proved properties acquired | 47,638 |
| | 564 |
| | 179 |
|
| Exploration | 14,811 |
| | 17,325 |
| | 19,222 |
|
| Development | 160,941 |
| | 80,582 |
| | 208,845 |
|
| Asset retirement obligation | (3,613 | ) | | (30,906 | ) | | (5,693 | ) |
| Total costs incurred | $ | 266,806 |
| | $ | 89,240 |
| | $ | 264,330 |
|
| | | | | | | | | | | | | | |
| 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 shows a summary of thesets forth costs incurred related to our oil and natural gas property costs not being amortized at December 31, 2017, byactivities for the year in which such costs were incurred:periods indicated:
|
| | | | | | | | | | | | | | | | | | | |
| | 2017 | | 2016 | | 2015 | | 2014 and Prior | | Total |
| | (In thousands) |
| Unproved properties acquired and wells in progress | $ | 50,447 |
| | $ | 22,092 |
| | $ | 40,254 |
| | $ | 183,971 |
| | $ | 296,764 |
|
| | | | | | | | | | | | | | | | | | | | |
| 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.
The results of operations for producing activities are as follows:
| | | | | | | | | | Successor | | Successor | | | Predecessor |
| | 2017 | | 2016 | | 2015 | | Year Ended
December 31, 2021 | | Four Months Ended
December 31, 2020 | | | Eight Months Ended
August 31, 2020 | |
| | (In thousands) | | (In thousands) |
| Revenues | $ | 347,285 |
| | $ | 282,742 |
| | $ | 371,335 |
| Revenues | $ | 223,681 | | | $ | 55,272 | | | | $ | 96,033 | | |
| Production costs | (107,332 | ) | | (108,822 | ) | | (152,560 | ) | Production costs | (62,443) | | | (20,510) | | | | (46,633) | | |
| Depreciation, depletion, amortization, and impairment | (96,392 | ) | | (268,901 | ) | | (1,844,726 | ) | Depreciation, depletion, amortization, and impairment | (24,261) | | | (40,840) | | | | (461,901) | | |
| | 143,561 |
| | (94,981 | ) | | (1,625,951 | ) | | 136,977 | | | (6,078) | | | | (412,501) | | |
| Income tax (expense) benefit | (56,376 | ) | | 32,696 |
| | 612,496 |
| Income tax (expense) benefit | 168 | | | 128 | | | | 6,698 | | |
| Results of operations for producing activities (excluding corporate overhead and financing costs) | $ | 87,185 |
| | $ | (62,285 | ) | | $ | (1,013,455 | ) | 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 Bbls | | NGLs Bbls | | Natural Gas Mcf | | Total MBoe |
| | (In thousands) |
| 2015 | | | | | | | |
| Proved developed and undeveloped reserves: | | | | | | | |
| Beginning of year | 22,667 |
| | 48,529 |
| | 646,961 |
| | 179,023 |
|
Revision of previous estimates (1) | (3,954 | ) | | (9,367 | ) | | (139,514 | ) | | (36,573 | ) |
| Extensions and discoveries | 1,208 |
| | 1,948 |
| | 20,974 |
| | 6,651 |
|
| Infill reserves in existing proved fields | 670 |
| | 1,861 |
| | 22,641 |
| | 6,304 |
|
| Purchases of minerals in place | — |
| | — |
| | — |
| | — |
|
| Production | (3,783 | ) | | (5,274 | ) | | (65,546 | ) | | (19,981 | ) |
| Sales | (73 | ) | | (10 | ) | | (648 | ) | | (191 | ) |
| End of year | 16,735 |
| | 37,687 |
| | 484,868 |
| | 135,233 |
|
| Proved developed reserves: | | | | | | | |
| Beginning of year | 17,448 |
| | 35,850 |
| | 500,950 |
| | 136,790 |
|
| End of year | 14,679 |
| | 31,218 |
| | 416,395 |
| | 115,296 |
|
| Proved undeveloped reserves: | | | | | | | |
| Beginning of year | 5,219 |
| | 12,679 |
| | 146,011 |
| | 42,233 |
|
| End of year | 2,056 |
| | 6,469 |
| | 68,473 |
| | 19,937 |
|
| 2016 | | | | | | | |
| Proved developed and undeveloped reserves: | | | | | | | |
| Beginning of year | 16,735 |
| | 37,687 |
| | 484,868 |
| | 135,233 |
|
Revision of previous estimates (1) | (549 | ) | | (2,473 | ) | | (31,670 | ) | | (8,300 | ) |
| Extensions and discoveries | 1,816 |
| | 1,588 |
| | 13,720 |
| | 5,690 |
|
| Infill reserves in existing proved fields | 663 |
| | 2,724 |
| | 24,704 |
| | 7,504 |
|
| Purchases of minerals in place | 114 |
| | 43 |
| | 630 |
| | 262 |
|
| Production | (2,974 | ) | | (5,014 | ) | | (55,735 | ) | | (17,277 | ) |
| Sales | (109 | ) | | (73 | ) | | (30,938 | ) | | (5,338 | ) |
| End of year | 15,696 |
| | 34,482 |
| | 405,579 |
| | 117,774 |
|
| Proved developed reserves: | | | | | | | |
| Beginning of year | 14,679 |
| | 31,218 |
| | 416,395 |
| | 115,296 |
|
| End of year | 12,724 |
| | 28,502 |
| | 347,121 |
| | 99,079 |
|
| Proved undeveloped reserves: | | | | | | | |
| Beginning of year | 2,056 |
| | 6,469 |
| | 68,473 |
| | 19,937 |
|
| End of year | 2,972 |
| | 5,980 |
| | 58,458 |
| | 18,695 |
|
| 2017 | | | | | | | |
| Proved developed and undeveloped reserves: | | | | | | | |
| Beginning of year | 15,696 |
| | 34,482 |
| | 405,579 |
| | 117,774 |
|
| Revision of previous estimates | 730 |
| | 4,325 |
| | 38,330 |
| | 11,444 |
|
| Extensions and discoveries | 2,235 |
| | 4,520 |
| | 49,321 |
| | 14,975 |
|
| Infill reserves in existing proved fields | 1,632 |
| | 5,779 |
| | 52,270 |
| | 16,123 |
|
| Purchases of minerals in place | 2,019 |
| | 1,197 |
| | 15,313 |
| | 5,768 |
|
| Production | (2,715 | ) | | (4,737 | ) | | (51,260 | ) | | (15,996 | ) |
| Sales | (84 | ) | | (80 | ) | | (903 | ) | | (314 | ) |
| End of year | 19,513 |
| | 45,486 |
| | 508,650 |
| | 149,774 |
|
| Proved developed reserves: | | | | | | | |
| Beginning of year | 12,724 |
| | 28,502 |
| | 347,121 |
| | 99,079 |
|
| End of year | 14,862 |
| | 33,358 |
| | 388,446 |
| | 112,961 |
|
| Proved undeveloped reserves: | | | | | | | |
| Beginning of year | 2,972 |
| | 5,980 |
| | 58,458 |
| | 18,695 |
|
| End of year | 4,651 |
| | 12,128 |
| | 120,204 |
| | 36,813 |
|
_________________________ | |
(1) | Natural gas revisions of previous estimates decreased primarily due to a decline in natural gas prices. |
| | | | | | | | | | | | | | | | | | | | | | | |
| 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.
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 |
| | 2017 | | 2016 | | 2015 | | 2021 | | 2020 | |
| | (In thousands) | | (In thousands) |
| Future cash flows | $ | 3,347,396 |
| | $ | 2,030,925 |
| | $ | 2,475,898 |
| Future cash flows | $ | 1,977,529 | | | $ | 698,685 | | |
| Future production costs | (1,308,244 | ) | | (861,625 | ) | | (1,017,777 | ) | Future production costs | (835,430) | | | (416,095) | | |
| Future development costs | (369,560 | ) | | (173,446 | ) | | (228,445 | ) | Future development costs | — | | | — | | |
| Future income tax expenses | (234,152 | ) | | (141,752 | ) | | (230,544 | ) | Future income tax expenses | (87,117) | | | (39) | | |
| Future net cash flows | 1,435,440 |
| | 854,102 |
| | 999,132 |
| Future net cash flows | 1,054,982 | | | 282,551 | | |
| 10% annual discount for estimated timing of cash flows | (628,270 | ) | | (335,892 | ) | | (409,646 | ) | 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 | $ | 807,170 |
| | $ | 518,210 |
| | $ | 589,486 |
| 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:
| | | | 2017 | | 2016 | | 2015 | | 2021 | | 2020 | |
| | (In thousands) | | (In thousands) |
| Sales and transfers of oil and natural gas produced, net of production costs | $ | (239,953 | ) | | $ | (173,920 | ) | | $ | (218,115 | ) | Sales and transfers of oil and natural gas produced, net of production costs | $ | (161,238) | | | $ | (84,163) | | |
| Net changes in prices and production costs | 236,126 |
| | (94,026 | ) | | (1,356,333 | ) | Net changes in prices and production costs | 334,291 | | | (165,978) | | |
| Revisions in quantity estimates and changes in production timing | 87,239 |
| | (51,979 | ) | | (213,945 | ) | Revisions in quantity estimates and changes in production timing | 320,774 | | | (50,979) | | |
| Extensions, discoveries, and improved recovery, less related costs | 102,965 |
| | 84,738 |
| | 95,671 |
| Extensions, discoveries, and improved recovery, less related costs | 45,019 | | | 2,827 | | |
| Changes in estimated future development costs | (5,194 | ) | | 70,976 |
| | 227,857 |
| Changes in estimated future development costs | — | | | — | | |
| Previously estimated cost incurred during the period | 36,044 |
| | 16,602 |
| | 59,117 |
| Previously estimated cost incurred during the period | — | | | — | | |
| Purchases of minerals in place | 51,686 |
| | 2,652 |
| | — |
| Purchases of minerals in place | — | | | 852 | | |
| Sales of minerals in place | (1,447 | ) | | (17,248 | ) | | (3,338 | ) | Sales of minerals in place | (4,161) | | | (46) | | |
| Accretion of discount | 57,517 |
| | 69,069 |
| | 209,979 |
| Accretion of discount | 19,306 | | | 46,203 | | |
| Net change in income taxes | (33,389 | ) | | 44,241 |
| | 562,838 |
| Net change in income taxes | (87,078) | | | 282 | | |
| Other—net | (2,634 | ) | | (22,381 | ) | | (209,989 | ) | |
| Changes in timing and other | | Changes in timing and other | (88,791) | | | (17,686) | | |
| Net change | 288,960 |
| | (71,276 | ) | | (846,258 | ) | Net change | 378,123 | | | (268,688) | | |
| Beginning of year | 518,210 |
| | 589,486 |
| | 1,435,744 |
| Beginning of year | 193,021 | | | 461,709 | | |
| End of year | $ | 807,170 |
| | $ | 518,210 |
| | $ | 589,486 |
| 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.
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, 2017,2021 future cash flows were computed by applying the unescalated 12-month average prices of $51.34$66.56 per barrel for oil, $31.83$44.22 per barrel for NGLs, and $2.98$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
| |
(a) | Evaluation of Disclosure Controls and Procedures |
We maintain “disclosureOur management, including our Chief Executive Officer (CEO) and Chief Financial Officer (CFO), does not expect that our disclosure controls and procedures” as that term is (as defined in Rule 13a-15(e)Rules 13a - 15(e) and Rule 15d-15(e) under15d - 15(e) of the Securities Exchange Act of 1934, as amended (the Exchange Act), that are designed to ensure that information required to be disclosed) (Disclosure Controls) or our internal control over financial reporting (as defined in reports we file or submit underRules 13a - 15(f) and 15d - 15(f) of the Exchange Act is recorded, processed, summarized,Act) will prevent or detect all errors and reported within the time periods specified in SEC rules and forms, and that such information is collected and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating our disclosure controls and procedures, our management recognized thatall fraud. A control system, no matter how well conceiveddesigned and operated, disclosure controls and procedures can provide only reasonable, not absolute, assurance that the objectives of the disclosure controls and procedurescontrol system are met. Our disclosureFurther, 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 proceduresinstances of fraud, if any, within the company have been designeddetected. 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 meet,an error or fraud may occur and not be detected. We monitor our management believesDisclosure Controls and internal control over financial reporting and make modifications as necessary; our intent in this regard is that they meet, reasonable assurance standards. Based on their evaluationthe 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.
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 our Chief Executive Officerfor 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 Chief Financial Officernon-routine transactions. Effectively designed management review controls must also have concludedan established process that allows senior accounting personnel having the appropriate knowledge of the subject matter to the limitations noted above, the company’shave 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.effective at December 31, 2020.
| |
(b) | Management’s Report on Internal Control Over Financial Reporting |
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 Chief Executive OfficerCEO and Chief Financial Officer,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, 2017.2021.
The effectiveness of the company’sChanges in Internal Control Over Financial Reporting
Except as described above, there were no changes in internal control over financial reporting as of December 31, 2017, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears in this report.
| |
(c) | Changes in Internal Control Over Financial Reporting |
In January 2017, we implemented a new ERP accounting and reporting system designed to upgrade our technology and improve the timeliness and quality of our financial and operational information. This new ERP system was not implemented in response to any material weakness in our internal control over financial reporting (ICFR). The implementation of the ERP system has affected the processes that constitute part of our ICFR and requires ongoing testing for effectiveness. The adoption of this new ERP system has not materially affected our ICFR. There were no changes in ICFR during the quarter ended December 31, 2017,2021, that materially affected, our ICFR or are reasonably likely to materially affect, it.our internal control over financial reporting.
Item 9B. Other Information
None.
Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections
Not applicable.
PART III
Item 10. Directors, Executive Officers, and Corporate Governance
In accordance with Instruction G(3) of Form 10-K, the information required by this item is incorporated in this report by reference to the Proxy Statement, except for the information regarding our executive officers which is presented below. The Proxy Statement will be filed before our annual shareholders’ meeting scheduled to be held on May 2, 2018.
Information About Our Code of Ethics and Business Conduct applies to all directors, officers, and employees, including our Chief Executive Officer, our Chief Financial Officer, and our Controller. You can find our Code of Ethics and Business Conduct on our internet website, www.unitcorp.com. We will post any amendments to the Code of Ethics and Business Conduct, and any waivers that are required to be disclosed by the rules of either the SEC or the NYSE, on our internet website.
Because our common stock is listed on the NYSE, our Chief Executive Officer was required to make, and he has made, an annual certification to the NYSE stating that he was not aware of any violation by us of the NYSE corporate governance listing standards. Our Chief Executive Officer made his annual certification to that effect to the NYSE as of May 5, 2017. In addition, we have filed, as exhibits to this Annual Report on Form 10-K, the certifications of our Chief Executive Officer and Chief Financial Officer required under Section 302 of the Sarbanes-Oxley Act of 2002 to be filed with the SEC regarding the quality of our public disclosure.
Executive Officers
The table below and accompanying text sets forth certain information as of February 13, 2018 concerningMarch 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.
|
| | | | | | | | | | | | | |
NAMEName | | AGEAge | | POSITION HELDPositions Held |
Larry D. PinkstonPhilip B. Smith | | 6370 |
| | Director since September 3, 2020, Chairman since September 8, 2020, President and Chief Executive Officer since April 1, 2005, Director since January 15, 2004, President since August 1, 2003, Chief Operating Officer from February 24, 2004 to August 28, 2017, Vice President and Chief Financial Officer from May 1989 to February 24, 2004October 22, 2020 |
Mark E. SchellDavid P. Dunham | | 6042 |
| | Senior Vice President since December 2002, General Counsel and Corporate Secretary since January 1987 |
David T. Merrill | | 57 |
| | Chief Operating Officer since August 28, 2017, Senior Vice President from May 2, 2012 to November 27, 2017, Chief Financial Officer and Treasurer from February 24, 2004 to November 27, 2017, Vice President of Finance from August 2003 to February 24, 2004 |
Les Austin | | 52 |
| | Senior Vice President and Chief FinancialOperating Officer since November 27, 2017 |
David P. Dunham | | 38 |
| | October 22, 2020, Senior Vice President of Business Development sincefrom August 28, 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 |
John CromlingAndrew E. Harding | | 7044 |
| 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 | Executive Vice | 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 April 15, 2005 |
Robert Parks | | 63 |
| | Manager and President, Superior Pipeline Company, L.L.C. since June 1996 |
Frank Young | | 48 |
| | Senior Vice President Exploration and Production Midcontinent of Unit Petroleum Company since 2012, Vice President - Central Division from June 2007, when he joined Unit Company, until 2012.November 9, 2020 |
Mr. Pinkston joinedSmith was named to the companyBoard 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 December 1981. He had1999, 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 Budget Director and Assistant Controller before being appointed Controller in February, 1985.Planning. In December, 1986January 2012, he was elected Treasurer of the company and was electedpromoted to the position of Vice President and Chief Financial Officer in May, 1989. In August, 2003, he was elected to the position of President. He was elected a director of the company by the Board in January, 2004. In February, 2004, in addition to his position as President, he was elected to the office of Chief Operating Officer. In April 2005, he also began serving as Chief Executive Officer. Mr. Pinkston holds the offices of President and Chief Executive Officer. He holds a Bachelor of Science Degree in Accounting from East Central University of Oklahoma.
Mr. Schell joined the company in January 1987, as its Secretary and General Counsel. In 2003, he was promoted to Senior Vice President. From 1979 until joining Unit Corporation, Mr. Schell was Counsel, Vice President, and a member of the Board of Directors of C & S Exploration Inc. He received a Bachelor of Science degree in Political Science from Arizona State University and his Juris Doctorate degree from the University of Tulsa College of Law. He is a member of the Oklahoma Bar Association. Mr. Schell is a director of the Oklahoma Oil and Gas Association. In addition, he is the Chairman and a director of the Oklahoma Injury Benefit Coalition, an Oklahoma non-profit association advocating for improvements to Oklahoma's Workers' Compensation system. He is also a member of the State Chamber of Oklahoma board of directors and serves on the board of advisors for the Greater Oklahoma City Chamber.
Mr. Merrill joined the company in August 2003 and served as its Vice President of Finance until February 2004 when he was elected to the position of Chief Financial Officer and Treasurer. In May 2012, he was promoted to Senior Vice President, a position he held until November 2017. In August 2017, he was promoted to Chief Operating Officer. From May 1999 through August 2003, Mr. Merrill served as Senior Vice President, Finance with TV Guide Networks, Inc. From July 1996 through May 1999 he was a Senior Manager with Deloitte & Touche LLP. From July 1994 through July 1996 he was Director of Financial Reporting and Special Projects for MAPCO, Inc. He began his career as an auditor with Deloitte, Haskins & Sells in 1983. Mr. Merrill received a Bachelor of Business Administration Degree in Accounting from the University of Oklahoma and is a Certified Public Accountant.
Mr. Austin joined the company in November 2017 as Senior Vice President and Chief Financial Officer of the company. Prior to coming to Unit, he served as Senior Vice President and Chief Financial Officer of Cypress Energy Partners, L.P.. From 2008 to 2011, he was the Senior Vice President and Chief Financial Officer of Ram Energy Resources, Inc. In 2011, he was promoted to Chief Operating Officer where he served until its sale in 2012. Before joining Ram Energy Resources, Inc., Mr. Austin was the Vice President of Finance and Chief Financial Officer of Matrix Service Company. He has also held various managerial and financial positions at Flint Energy Construction Co. and Ernst & Young, LLP. Mr. Austin has a bachelor's degree in accounting from Oklahoma State University and is a Certified Public Accountant.
Mr. Dunham joined the company in November 2007 as its Director of Corporate Planning. He was promoted to Vice President of Corporate Planning in January 2012. In August 2017, he was promoted to Senior Vice President of Business Development. From 2004In October 2020, he was promoted to November 2007, Mr. Dunham worked forSenior Vice President and Chief Operating Officer. Prior to Unit, he held positions of increasing responsibility at Williams Power, serving as Manager of Structured
Products. He worked for Leggett & Platt, from 2003 to 2004, serving as a Mergersand Williams Energy Marketing & Acquisitions Analyst. HeTrading. Mr. Dunham received his Bachelor of Arts degree in Psychology from Northwestern University, his Master of Science in Finance degree from theThe University of Tulsa and his MBAMaster of Business Administration from theThe Wharton School of the University of Pennsylvania.
Mr. CromlingHarding joined Unit Drilling Company in 1997August 2004 as a Vice-President and Division Manager.Staff Attorney. In AprilMarch 2005, he was promoted to the position of Executive Vice-PresidentAssociate General Counsel. In October 2020, he was promoted to Vice President, General Counsel, and Secretary. Mr. Harding received his Bachelor of DrillingBusiness 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.
Mr. Menefee was appointed President of Unit Drilling Company. In 1980,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 formed Cromlingspent 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 managedis a major domestic contract drilling company, serving on numerous private boards including Summit ESP which was acquired by Halliburton in 2017. Between 2002 and operated drilling rigs until 1987. From 19872010 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 1997, Cromling Drilling Company provided engineering consulting services and generated and drilled oil and natural gas prospects.Chesapeake Energy in 2002. During his time with Sapient, Mr. Anderson was also actively involved on the IPAA's Capital Markets Committee. Prior to this,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 employed by Big Chief DrillingManaging 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 11 yearsthe 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 Vice-President. 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.
Mr. Cromling graduatedFrohlich 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 with a degree in Petroleum Engineering.
Mr. Parks founded Superior Pipeline Company, L.L.C. in 1996. When Superior was acquired by the company in July 2004, he continued with Superior as one of its managers and as its President. From April 1992 through April 1996 Mr. Parks served as Vice-President—Gathering and Processing for Cimarron Gas Companies. From December 1986 through March 1992, he served as Vice-President—Business Development for American Central Gas Companies. Mr. Parks began his career as1976, an engineer with Cities Service Company in 1978. He received a Bachelor of Science degree in Chemical Engineering from Rice University and his M.B.A. fromat the University of Texas at Austin.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. YoungHildebrand 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 Unit Petroleum CompanyThrifty Rent-A-Car System, Inc. in June 20071987 as Vice President - Central Division. In 2012,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 was promoted to Seniorheld several positions including Controller and Vice President of ExplorationFinance. 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 Production over Unit’s Midcontinent assets. Before joining Unit, 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. YoungSmith'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 employed by Anadarko Petroleum Corporation. He beganwith 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 Anadarkoa degree in 1991Economics. 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 Production Engineer and, in 1994, began working as a Reservoir Engineer. In 1996,director for the public company Lonestar Resources US Inc., where he was promoted to a Senior Asset Engineering role responsible for delineation and development of Anadarko’s North African oil fields. In 1999, he was moved into a Senior Completions / Operations Engineering role responsible for development of gas fields in East Texas. In 2000, he was promoted to Division Engineer responsible for operations within Anadarko’s Permian Division in West Texas. In 2002, he was promoted to Planning Manager for North America. In 2004, he was promoted to General Manager of Central Gulf of Mexico responsible for delineation and development of various Deepwater fields. Mr. Young holds a Bachelor of Science degree in Petroleum Engineering from Texas Tech Universitythe Audit Chair and a Mastermember 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 Administration degreeConduct and Ethics is available at https://unitcorp.com/investor-relations/#governanceand a copy may also be obtained, without charge, on request, from Texas A&M University.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.
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
InDirectors' 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 Instruction G(3)FASB ASC Topic 718 "Stock Compensation," which excludes the effect of Form 10-K,estimated forfeitures. The amount is based on the information requiredclosing sales
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 this Item is incorporated into this report by referenceour 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 $12,000 per year beginning in June 2021, which salary was determined in order to allow him to participate in our health insurance plan. Restricted stock unit awards ("RSUs") and stock option awards were granted to the Proxy Statement (see Item 10 above).named executive officers ("NEOs") under the LTIP in October 2021, and annual bonuses were determined in December 2021.
Summary Compensation Table for 2021
The following table sets forth information regarding the compensation paid, distributed, or earned by or for our NEOs for the stated fiscal years.
| | | | | | | | | | | | | | | | | | | | | | | |
| Summary Compensation Table |
| Name and Principal Position | Year | Salary (1) ($) | 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" ($) |
| Philip B. Smith | 80,000 | — | — | — | — | 80,000 |
| David P. Dunham | — | 5,246 | 11,600 | 6,000 | 10,852 | 33,698 |
| Christopher K. Menefee | — | 1,801 | 11,600 | — | 11,227 | 24,628 |
a. Reflects fees earned or paid in cash for service as a member of our board of directors and its chair.
b. Match was made in cash.
Outstanding Equity Awards at End of 2021
The following table sets forth information about our NEOs' outstanding equity awards at the end of 2021:
| | | | | | | | | | | | | | | | | | | | |
| Outstanding Equity Awards at Fiscal Year-End |
| Options Awards | Stock Awards |
| Name | Number of securities underlying unexercised options - exercisable
(#) | Number of securities underlying unexercised options - unexercisable (1) (#) | Option exercise price
($) | 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.
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 following tablepurpose 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 information for all equity compensation plansthe 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.
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 fiscal year ended December 31, 2017,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 equity securities were authorizedstock 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 issuance: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.
|
| | | | | | | | | | |
| Plan Category | Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights (a) | | Weighted Average
Exercise Price of
Outstanding
Options,
Warrants and Rights
(b) | | Number of Securities
Remaining
Available for
Future Issuance Under Equity
Compensation
Plans (Excluding Securities Reflected in Column (a)) (c) | |
Equity compensation plans approved by security holders (1) | 87,500 |
| (2) | $ | 51.34 |
| | 3,641,494 |
| (3) |
| Equity compensation plans not approved by security holders | — |
| | — |
| | — |
| |
| Total | 87,500 |
| | $ | 51.34 |
| | 3,641,494 |
| |
_________________________
| |
(1) | Shares awarded under all above plans may be newly issued, from our treasury, or acquired in the open market. |
| |
(2) | This number includes 87,500 stock options outstanding under the Non-Employee Directors’ Stock Option Plan. |
| |
(3) | This number reflects the shares available for issuance under the Second Amended and Restated Unit Corporation Stock and Incentive Compensation Plan effective May 6, 2015 (the amended plan). The amended plan allows us to grant stock-based compensation to our employees and non-employee directors. A total of 7,230,000 shares of the company's common stock is authorized for issuance to eligible participants under the amended plan. No more than 2,000,000 of the shares available under the amended plan may be issued as “incentive stock options” and all of the shares available under this plan may be issued as restricted stock. In addition, shares related to grants that are forfeited, terminated, canceled, expire unexercised, or settled in such manner that all or some of the shares are not issued to a participant shall immediately become available for issuance. |
In accordance•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 Instruction G(3)value and payment contingent on performance of Form 10-K, the information requiredcompany or other factors determined by this Item is incorporated into this reportthe compensation committee, and awards valued by reference to the Proxy Statement (see Item 10 above).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:
•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
In accordanceCertain Transactions Between the Company and Its Officers, Directors, and Their Associates
One current director, Robert Anderson, also serves as an executive with Instruction G(3)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 Form 10-K,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 information required by this Item is incorporated into this report by referencecompany. Under the terms of the consulting contract, Mr. Anderson agreed to provide advisory consulting services related to the Proxy Statement (see Item 10 above).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.
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 AccountingAccountant 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 accordance with Instruction G(3)recognition of Form 10-K,this responsibility, the information requiredaudit committee has established a policy to pre-approve all audit and permissible non-audit services provided by this Item is incorporated into this report by referencethe independent registered public accounting firm.
Before incurring the following, management will submit to the Proxy Statement (see Item 10 above).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.
(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, 20172021 and 20162020
Consolidated Statements of Operations for the yearsyear ended December 31, 2017, 2016,2021, four months ended December 31, 2020, and 2015eight months ended August 31, 2020
Consolidated Statements of Comprehensive Income (Loss) for the yearsyear ended December 31, 2017, 2016,2021, four months ended December 31, 2020, and 2015eight months ended August 31, 2020
Consolidated Statements of Changes in Shareholders’Shareholders' Equity for the yearsyear ended December 31, 2015, 2016,2021, four months ended December 31, 2020, and 2017eight months ended August 31, 2020
Consolidated Statements of Cash Flows for the yearsyear ended December 31, 2017, 2016,2021, four months ended December 31, 2020, and 2015eight 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, 2017, 2016,2021 and 2015:2020:
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.
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.
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| 2.1 | | |
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| 3.1 | | |
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3.1.2 | | |
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3.2 | | |
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4.13.2 | | |
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4.510.1† | | |
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4.610.2† | | First Supplemental Indenture (including formForm of note) dated as of May 18, 2011, byStock Option Grant Notice and among the Company, as issuer, the Subsidiary Guarantors (as defined therein), as guarantors and Wilmington Trust FSB as trusteeAward Agreement (filed as Exhibit 4.210.3 to Unit’s Form 8-K10-Q, dated May 18, 2011,November 12, 2021, which is incorporated herein by reference)reference herein). |
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4.710.3† | | Second Supplemental Indenture (including formForm of note) dated as of January 7, 2013, byRestricted Stock Unit (RSU) Grant Notice and among the Registrant, as issuer, the Subsidiary Guarantors (as defined therein), as guarantors and Wilmington Trust, National Association as trusteeAward Agreement (filed as Exhibit 4.1010.2 to Unit’s Post-Effective Amendment No.1 to the Registration Statement on Form S-310-Q, dated February 16, 2016,May 12, 2021, which is incorporated herein by reference)reference herein). |
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10.1.2*10.4† | | |
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| 10.5 | | |
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| 10.6 | | |
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| 10.7† | | |
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10.1.3* | | |
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10.1.410.8† | | |
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| 10.9† | | |
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| 10.10 | | |
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| 10.11 | | Amended and Restated Credit Agreement, dated August 19, 2008as of September 3, 2020, among Unit Corporation, Unit Drilling Company, Unit Petroleum Company, the lenders party thereto from time to time, the guarantors party thereto and BOKF, NA dba Bank of Oklahoma as administrative agent and collateral agent (filed as Exhibit 10.1 to Unit’s Form 8-K, dated August 25, 2008,September 10, 2020, which is incorporated herein by reference)reference herein). |
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10.1.510.12 | | |
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| 10.13 | | |
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| 10.14 | | |
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| 10.15 | | Credit Agreement dated May 10, 2018, by and among theSuperior Pipeline Company, L.L.C. and the subsidiaries named therein (as borrowers), BOKF, NA DBA Bank of Oklahoma, as Administrative Agent, and the institutions named therein (as lenders) (filed as Exhibit 10.1 to Unit’s Form 8-K dated September 13, 2011,May 16, 2018, which is incorporated herein by reference)reference herein). |
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10.1.610.16 | | |
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10.1.7 | | First Amendment and Consent, dated September 5, 2012, to the Senior Credit Agreement by and among the Company and the subsidiaries named therein (as borrowers), BOKF, NA DBAdba Bank of Oklahoma, as Administrative Agent, and the institutions named therein (as lenders) (filed as exhibit 10.1Exhibit 10.1(b) to Unit'sUnit’s Form 8-K10-Q, dated September 5, 2012,August 9, 2018, which is incorporated herein by reference)reference herein). |
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10.1.8*10.17 | | |
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10.1.9 | | |
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10.1.10 | | |
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10.2.1 | | Unit 1979 Oil and Gas Program Agreement of Limited Partnership (filed as Exhibit I to Unit Drilling and Exploration Company’s Registration Statement on Form S-1 as S.E.C. File No. 2-66347, which is incorporated herein by reference). |
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10.2.3* | | |
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10.2.4* | | |
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10.2.5* | | Unit Corporation Employees’ Thrift Plan (filed as an Exhibit to Form S-8 as S.E.C. File No. 33-53542, which is incorporated herein by reference). |
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10.2.6 | | Unit Consolidated Employee Oil and Gas Limited Partnership Agreement (filed as an Exhibit to Unit’s Annual Report under cover of Form 10-K for the year ended December 31, 1993, which is incorporated herein by reference). |
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10.2.7* | | |
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10.2.8* | | |
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10.2.9*10.18 | | |
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10.2.10 | | |
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10.2.11* | | |
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10.2.12 | | |
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10.2.13 | | |
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10.2.14 | | |
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10.2.15 | | | | | | | | |
| 10.19 | | |
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10.2.16 | | |
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10.2.17* | | |
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10.2.18*10.20 | | |
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10.2.19 | | |
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10.2.20 | | |
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10.2.21* | | |
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10.2.2210.21 | | |
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10.2.23*10.22 | | Annual Bonus Performance Plan entered into October 21, 2008Purchase and Sale Agreement, dated March 28, 2018, by and between Unit Corporation and SP Investor Holdings, LLC (filed as Exhibit 10.1 to Unit’s Form 8-K10-Q, dated October 23, 2008,May 3, 2018, which is incorporated herein by reference)reference herein). |
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10.2.24* | | |
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10.2.25* | | |
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10.2.26* | | |
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10.2.27* | | |
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10.2.28 | | |
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10.2.29* | | |
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10.2.30 | | |
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10.2.31 | | |
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10.2.32 | | |
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10.2.33* | | |
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10.2.34* | | |
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10.2.35 | | |
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10.2.36 | | |
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1221 | | |
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21 | | |
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| 23.1 | | |
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23.2 | | |
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| 31.1 | | |
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| 31.2 | | |
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| 32 | | |
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| 99.1 | | |
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| 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. |
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| 101.SCH | | XBRL Taxonomy Extension Schema Document. |
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| 101.CAL | | XBRL Taxonomy Extension Calculation Linkbase Document. |
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| 101.DEF | | XBRL Taxonomy Extension Definition Linkbase Document. |
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| 101.LAB | | XBRL Taxonomy Extension Labels Linkbase Document. |
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| 101.PRE | | XBRL Taxonomy Extension Presentation Linkbase Document. |
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| 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 Doubtful Accounts: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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| 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, 2017 | $ | 3,773 |
| | $ | 348 |
| | $ | (1,671 | ) | | $ | 2,450 |
|
| Year ended December 31, 2016 | $ | 5,199 |
| | $ | 785 |
| | $ | (2,211 | ) | | $ | 3,773 |
|
| Year ended December 31, 2015 | $ | 5,039 |
| | $ | 1,191 |
| | $ | (1,031 | ) | | $ | 5,199 |
|
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.
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| | | UNIT CORPORATION |
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| DATE: | March 31, 2022 | | UNIT CORPORATION |
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DATE: | February 27, 2018 | By: | /s/ LARRY D. PINKSTON PHILIP B. SMITH |
| | | LARRY D. PINKSTONPHILIP 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 27th31st day of February, 2018. March, 2022. | | | | | | | | |
| Name | | Title |
| | |
| /s/ PHILIP B. SMITH | | President and Chief Executive Officer and Chairman of the Board (Principal Executive Officer) |
| Philip B. Smith | |
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Name | | Title |
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/s/ J. MICHAEL ADCOCK THOMAS D. SELL | | Chairman of the Board and Director |
J. Michael Adcock | |
| | |
/s/ LARRY D. PINKSTON
| | President and Chief Executive Officer and Director
(Principal Executive Officer)
|
Larry D. Pinkston | |
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/s/ LES AUSTIN
| | Senior Vice President, Chief Financial Officer (Principaland Chief Accounting Officer(Principal Financial Officer) |
Les Austin | |
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/s/ DON A. HAYES
| | Vice President, Controller
(Principaland Accounting Officer)
|
Don A. HayesThomas D. Sell | |
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/s/ GARY CHRISTOPHER ROBERT ANDERSON | | Director |
Gary ChristopherRobert Anderson | | |
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/s/ ALAN J. CARR | | Director |
| Alan J. Carr | | |
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| /s/ PHIL FROHLICH | | Director |
| Phil Frohlich | | |
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/s/ STEVEN B. HILDEBRAND | | Director |
| Steven B. Hildebrand | | |
| | |
/s/ CARLA S. MASHINSKI ANDREI VERONA | | Director |
Carla S. MashinskiAndrei Verona | | |
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/s/ WILLIAM B. MORGAN
| | Director |
William B. Morgan | | |
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/s/ LARRY C. PAYNE
| | Director |
Larry C. Payne | | |
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/s/ G. BAILEY PEYTON IV
| | Director |
G. Bailey Peyton IV | | |
| | |
/s/ ROBERT SULLIVAN, JR.
| | Director |
Robert Sullivan, Jr. | | |
