UNIT CORPORATION
A Delaware Corporation
8200 South Unit Drive
Tulsa, OK 74132
_____________________
Telephone: (918) 493-7700
Email: ir@unitcorp.com
_____________________
Federal EIN: 73-1283193
NAICS: 211120, 211130, 213111
Issuer’s Annual Report
For the annual period ended December 31, 2024
(the "Reporting Period")
The number of shares outstanding of our common stock is 9,846,301 as of March 13, 2025.
The number of shares outstanding of our common stock was 9,718,588 as of September 30, 2024 (end of previous reporting
period).
Indicate by check mark whether the company is a shell company (as defined in Rule 405 of the Securities Act of 1933 and Rule
12b-2 of the Exchange Act of 1934):
Yes ☐ No ☒
Indicate by check mark whether the company’s shell status has changed since the previous reporting period:
Yes ☐ No ☒
Indicate by check mark whether a change in control of the company has occurred over this reporting period:
Yes ☐ No ☒
Table of Contents
UNIT CORPORATION
TABLE OF CONTENTS
Part A
General Company Information
1
Part B
Share Structure
1
Part C
Business Information
3
Part D
Management Structure and Financial Information
26
Part E
Issuance History
78
Part F
Exhibits
79
Page
Table of Contents
The following are explanations of some of the industry and general terms we use in this report:
ARO – Asset retirement obligations.
ASC – FASB Accounting Standards Codification.
ASU – Accounting Standards Update.
Bbl – Barrel, or 42 U.S. gallons liquid volume.
Boe – Barrel of oil equivalent. Determined using the ratio of six Mcf of natural gas to one barrel of crude oil or NGLs.
Btu – British thermal unit, used in gas volumes. Btu is used to refer to the natural gas required to raise the temperature of one
pound of water by one-degree Fahrenheit at one atmospheric pressure.
Development drilling – The drilling of a well within the proven area of an oil or gas reservoir to the depth of a stratigraphic
horizon known to be productive.
DD&A – Depreciation, depletion, and amortization.
FASB – Financial and Accounting Standards Board.
FERC – Federal Energy Regulatory Commission.
Finding and development costs – Costs associated with acquiring and developing proved natural gas and oil reserves
capitalized under generally accepted accounting principles, including any capitalized general and administrative expenses.
G&A – General and administrative expenses.
Gross acres or gross wells – The total acres or wells in which a working interest is owned.
IF – Inside FERC (U.S. Federal Energy Regulatory Commission).
LOE – Lease operating expense.
MBbls – Thousand barrels of crude oil or other liquid hydrocarbons.
Mcf – Thousand cubic feet of natural gas.
MBoe – Thousand barrels of oil equivalent.
MMBtu – Million Btu’s.
MMcf – Million cubic feet of natural gas.
MMcfe – Million cubic feet of natural gas equivalent. It is determined using the ratio of one barrel of crude oil or NGLs to six
Mcf of natural gas.
Net acres or net wells – The total fractional working interests owned in gross acres or gross wells.
NGLs – Natural gas liquids.
NYMEX – The New York Mercantile Exchange.
OPEC – The Organization of Petroleum Exporting Countries.
Play – A term applied by geologists and geophysicists identifying an area with potential oil and gas reserves.
Producing property – A natural gas or oil property with existing production.
Proved developed reserves – Reserves expected to be recovered through existing wells with existing equipment and operating
methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and through
installed extraction equipment and infrastructure operational at the time of the reserves estimate. For additional information, see
the SEC’s definition in Rule 4-10(a)(6) of Regulation S-X.
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Proved reserves – Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and
engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from
known reservoirs and under existing economic conditions, operating methods, and government regulations – prior to the time at
which the contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless
of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have
commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. For
additional information, see the SEC’s definition in Rule 4-10(a)(22)(i) through (v) of Regulation S-X.
Proved undeveloped reserves – Proved reserves expected to be recovered from new wells on undrilled acreage, or from existing
wells where a relatively major expenditure is required for recompletion. For additional information, see the SEC’s definition in
Rule 4-10(a)(431) of Regulation S-X.
Reasonable certainty (regarding reserves) – If deterministic methods are used, reasonable certainty means high confidence that
the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities
actually recovered will equal or exceed the estimate.
Reliable technology – A grouping of one or more technologies (including computational methods) that has been field tested and
has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated
or in an analogous formation.
Ryder Scott – Ryder Scott Company, L.P., independent petroleum consultants.
SEC – Securities and Exchange Commission.
SOFR - Secured Overnight Financing Rate.
Undeveloped acreage – Lease acreage on which wells have not been drilled or completed to the point that would permit the
production of economic quantities of natural gas or oil regardless of whether the acreage contains proved reserves.
The following are explanations of some of the terms we use that are specific to us:
BOKF – Bank of Oklahoma Financial Corporation.
BOSS Rig – Unit’s proprietary BOSS rig design are Tier 1, Super-Spec alternating current drilling rigs which are standard
equipped to handle multi-well pad drilling programs. Features include multi-directional walking systems, 800,000 pound static
hook load masts, pipe racking capacities ranging from 22,500 to 26,500 feet, 7,500 psi mud systems, including quintuplex mud
pumps, AC draw works, power generating system with dual fuel capability or high line power capability, high-torque top
drives, automated iron roughneck wrenches, and automated catwalks.
Chapter 11 Cases – The cases filed by the Debtors on May 22, 2020 under Chapter 11 of Title 11 of the United States Code in
the United States Bankruptcy Court for the Southern District of Texas, Houston Division. The Chapter 11 proceedings were
jointly administered under the caption In re Unit Corporation, et al. Case No. 20-32740 (DRJ). During the pendency of the
Chapter 11 Cases, the Debtors operated their business as "debtors-in-possession" under the authority of the bankruptcy court
and under the Bankruptcy Code. The Debtors emerged from bankruptcy on September 3, 2020.
Debtors – Unit and its wholly owned subsidiaries UDC, UPC, 8200 Unit, Unit Drilling Colombia, and Unit Drilling USA, all of
which were parties to the Chapter 11 Cases.
Emergence 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.
MSA – The Amended and Restated Master Services and Operating Agreement for Superior.
New Common Stock – The Company common stock at a par value of $0.01 issued under the Plan and following the Emergence
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.
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 Emergence Date.
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SCR Rig – Direct current electric rigs that are standard equipped to drill multi-well pad drilling programs. Features include
1,500 horsepower hoisting capability, 7,500 psi mud systems, top drives, iron roughnecks, and automated catwalks. These rigs
are equipped with either skidding or walking systems to move from well to well on a pad.
Superior – Superior Pipeline Company, L.L.C., and its subsidiaries.
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 to utilize the benefits of net operating losses and other deferred tax assets against potential future taxable
income;
•
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 position;
•
our ability to timely secure third-party services used in completing our wells;
•
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; and
•
our estimates of any ceiling test write-downs or other potential asset impairments we may have to record in future
periods.
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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;
•
our ability to pay dividends and make share repurchases;
•
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.
Table of Contents
UNIT CORPORATION
Annual Report
For The Year Ended December 31, 2024
Part A. General Company Information
The name of the issuer is Unit Corporation. Unless otherwise indicated or required by the context, the terms “Company,”
“Unit,” “us,” “our,” “we,” and “its” refer to Unit Corporation or, as appropriate, one or more of its subsidiaries. Unit was
founded in 1963 as an oil and natural gas contract drilling company and has since grown to include operations in exploration
and production. Unit Corporation is the name of both the successor entity that emerged from bankruptcy on September 3, 2020
and the predecessor entity prior to emergence. Unit is actively conducting operations as a Delaware corporation and is not a
"shell company" as defined in the OTCQX U.S. Disclosure Guidelines and the federal securities laws.
Our executive offices are located at 8200 South Unit Drive, Tulsa, Oklahoma 74132; our telephone number is (918)
493-7700. Our company website is at www.unitcorp.com and our investor relations contact is Rene Punch, Investor Relations
via mail or telephone as listed above or via email at ir@unitcorp.com.
Part B. Share Structure
Common Stock
Stockholders of the Company are entitled to dividends if declared by the Board of Directors. Each share of our common
stock entitles the holder thereof to one vote on all matters submitted to a vote of the stockholders. Our common stock has
certain stockholder consent rights related to, among other things, the nature of the Company’s business, liquidation and
dissolution, and tax treatment. Holders of common stock do not have preemptive rights, or rights to convert their common stock
into other securities.
The provisions of Unit Corporation’s articles of incorporation and bylaws that are summarized below may have an
antitakeover effect and may delay, defer or prevent a tender offer or takeover attempt that a stockholder might consider to be in
such stockholder's best interests, including those attempts that might result in a premium over the market price for the shares
held by stockholders:
•
the requirement that only stockholders owning at least 25% of the outstanding shares of our common stock may
call a special stockholders’ meeting;
•
our Board of Directors is classified in two groups, each serving staggered two-year terms; and
•
the prohibition of any stockholder that owns 4.75% or more of the outstanding shares of our common stock
acquiring additional shares without approval by the Board of Directors.
Under our certificate of incorporation, we may issue shares of preferred stock on terms that are unfavorable to the holders
of our common stock. The issuance of shares of preferred stock could also prevent or inhibit a third party from acquiring us.
The existence of these provisions could depress the price of our common stock, could delay or prevent a takeover attempt or
could prevent attempts to replace or remove incumbent management.
Our common stock was issued at a par value of $0.01 and trades on the OTCQX market under the symbol
"UNTC" (CUSIP Number: 909218406).
Warrants
Each holder of Unit common stock outstanding (Old Common Stock) before the Emergence Date that did not opt out of the
release under the Plan was entitled to receive 0.03460447 warrants for every share of Old Common Stock owned. Each warrant
is exercisable for one share of common stock, subject to adjustment as provided in the Warrant Agreement. The warrants expire
on the earliest of (i) September 3, 2027, (ii) consummation of a Cash Sale (as defined in the Warrant Agreement), or (iii) the
consummation of a liquidation, dissolution or winding up of the Company.
As of December 31, 2024, the Company had authorized 1,843,318 warrants of which 100,668 had been exercised or
canceled.
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1
Among other provisions, the Warrant Agreement outlines potential adjustments to the warrants if certain events occur,
including (i) stock dividends payable in shares of common stock or stock splits, (ii) reverse stock splits or similar combination
events, (iii) Liquidity Events (as defined in the Warrant Agreement), and (iv) other events not explicitly contemplated which
may have an adverse impact to the intent and purpose of the warrants as set forth in the Plan, provided, however, the warrants
will not be adjusted for (a) any issuances of securities in connection with a merger, share exchange, asset acquisition, stock
purchase, recapitalization, reorganization or other similar business combination, (b) the issuance of any securities by Unit on or
after September 3, 2020 (the "Emergence Date") pursuant to the Plan or upon the issuance of shares of common stock upon the
exercise of such securities, (c) the issuance of any shares of common stock pursuant to the exercise of the warrants, (d) the
issuance of shares of common stock pursuant to any management stock option incentive or similar plan, (e) a dividend or
distribution to holders of common stock of cash, property, or securities (other than common stock), and/or (f) any change in the
par value of the common stock.
Pursuant to the terms of the Warrant Agreement, the Company determined the initial exercise price of the warrants to be
$63.74. On April 7, 2022, the Company delivered notice of the initial exercise price to the Warrant Agent and the warrants
became exercisable for shares of the Company’s common stock. On or about April 25, 2022, the warrants began trading over-
the-counter under the symbol "UNTCW" (CUSIP Number: 909218125). On March 31, 2023, the warrants began trading on the
OTCQX Best Market.
The table below presents information about the securities authorized for issuance as of the dates indicated:
As of December 31,
2024
2023
Common Stock:
Number of shares authorized
25,000,000
25,000,000
Number of shares outstanding
9,747,725
9,760,142
Number of shares freely tradable (public float) (1)(2)
9,580,049
9,679,275
Total number of holders of record (3)
16
12
Preferred Stock:
Number of shares authorized
1,000,000
1,000,000
Number of shares outstanding
—
—
Number of shares freely tradable (public float)
—
—
Total number of holders of record
—
—
Warrants:
Number of shares authorized
1,843,318
1,843,318
Number of shares outstanding
1,721,563
1,744,953
Number of shares freely tradeable (public float)
—
—
Total number of holders of record
—
—
1.
The number of shares freely tradable includes shares held by Prescott Group Capital Management LLC and may include shares held by other stockholders
owning 10% or more of our common stock. These stockholders may be considered “affiliates” within the meaning of Rule 144, and their shares may be
“control shares” subject to the volume and manner of sale restrictions under Rule 144.
2.
The number of shares freely tradable excludes shares of our common stock held by our officers and directors as well as shares issued on the exercise of
options that had not yet reached the required holding period. These shares may be “control shares” and "restricted shares," respectively, subject to the
volume and manner of sale restrictions under Rule 144.
3.
The majority of common stock shares are held in street name.
Transfer Agent
Equiniti Trust Company, LLC
48 Wall Street, Floor 23
New York, New York 10005
Phone: (718) 921-8200
Equniti Trust Company, LLC (formerly American Stock Transfer and Trust Company, LLC) is registered under the
Securities Exchange Act of 1934, as amended. EQ’s procedures and transactions are regulated and audited by the Securities and
Exchange Commission.
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2
Part C. Business Information
We operate, manage, and analyze our results of operations through our two principal business segments:
•
Oil and Natural Gas – carried out by our subsidiary Unit Petroleum Company ("UPC"). 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 ("UDC"). This segment contracts to drill
onshore oil and natural gas wells for a wide range of other oil and natural gas companies.
Each company may conduct operations through subsidiaries of its own. We also have several other subsidiaries, none of
which conduct material operations.
The following table lists information about our consolidated oil and natural gas and contract drilling assets as of December
31, 2024:
Oil and Natural Gas
Total number of wells in which we own an interest
4,660
Contract Drilling
Total number of drilling rigs available for use
14
2024 SEGMENT OPERATIONS HIGHLIGHTS
Oil and Natural Gas
•
Revenues decreased by 36% from 2023 primarily due to lower production volumes from our sale of producing
properties in the Texas panhandle in December 2023.
•
Operating costs before eliminations decreased 32% from 2023 primarily due to lower production tax expenses on
reduced revenues and lower lease operating expenses from our divestiture of properties in the Texas panhandle in
December 2023.
•
Capital expenditures increased 145% from 2023 as we secured 2,600 acres of oil and gas leases for $7.1 million and
made prepayments on two gross wells for $2.5 million during the year ended December 31, 2024.
Contract Drilling
•
Revenues decreased 20% from 2023 primarily due to a 20% decrease in the average number of drilling rigs in use to
from 15.1 in 2023 to 12.1 during the year ended December 31, 2024. We also had a 3% decrease in our average
dayrate.
•
Operating costs decreased 8% from 2023 primarily due to a decrease in the average number of drilling rigs in use and
lower rig relocation expense, partially offset by higher average employee compensation.
FINANCIAL INFORMATION ABOUT SEGMENTS
See Note 22 - Industry Segment Information of our Notes to Consolidated Financial Statements in Part D of this report for
information about each of our segments' revenues, profits or losses, and total assets.
OIL AND NATURAL GAS
General. Our producing oil and natural gas properties, unproved properties, and related assets are primarily located in
Oklahoma and Texas. All of our oil and natural gas properties are located in the United States.
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3
The following table presents information regarding our oil and natural gas assets as of December 31, 2024 and production
activity during the year then ended:
Number of
Gross Wells
Number of
Net Wells
Number of
Gross Wells
in Process
Number of
Net Wells
in Process
2024 Average Net Daily Production
Natural Gas
(Mcf)
Oil
(Bbls)
NGLs
(Bbls)
Total
4,660
776
4
0.29
37,159
1,899
2,759
Acquisitions. During December 2024, the Company acquired approximately 1,000 acres of oil and gas leases for $3.0
million, of which $0.8 million consideration was paid at closing while $2.2 million was accrued for as of December 31, 2024.
In separate transactions, during 2024 the Company also acquired approximately 1,600 acres of oil and gas leases for $4.1
million and made prepayments of $2.5 million on two gross wells. All properties are located in Oklahoma. These amounts are
presented in unproved properties not being amortized on the consolidated balance sheets as of December 31, 2024.
Dispositions. On December 13, 2023, the Company closed on the sale of certain non-core wells and related leases in the
Texas Panhandle for cash proceeds of $50.7 million, after customary post-closing adjustments based on an effective date of
October 1, 2023. The sale represented a significant alteration to the full cost pool as reserves in excess of 25% were divested.
To determine the gain, the Company allocated the net book value of the full cost pool based on the relative fair value of the
properties retained versus those divested. A gain of $37.2 million was recognized within gain on disposition of assets in the
consolidated statements of operations.
Net proceeds for the sale of other non-core oil and natural gas assets totaled $2.9 million and $3.3 million during the years
ended December 31, 2024 and 2023, respectively. These proceeds reduced the net book value of our full cost pool with no gain
or loss recognized as the sales did not result in a significant alteration of the full cost pool.
Well and Leasehold Data. The following table presents the number of oil and natural gas exploratory and development
wells completed during the periods indicated:
Year Ended December 31,
2024
2023
Gross
Net
Gross
Net
Development:
Oil
3
0.004
6
0.37
Natural Gas
1
0.001
3
0.01
Dry
—
—
—
—
Total development
4
0.005
9
0.38
Exploratory:
Oil
6
0.24
5
0.02
Natural gas
11
1.36
10
0.85
Dry
—
—
—
—
Total exploratory
17
1.60
15
0.87
Total wells completed
21
1.60
24
1.25
The following table presents the number of wells producing, capable of producing or shut-in as of the dates indicated:
As of December 31,
2024
2023
Gross
Net
Gross
Net
Oil
2,136
166.0
2,094
168.3
Natural gas
2,524
610.0
2,529
619.4
Total
4,660
776.0
4,623
787.7
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4
We did not develop any previously booked proved undeveloped oil and natural gas reserves during the years ended
December 31, 2024 or 2023.
The following table presents our leasehold acreage as of December 31, 2024:
Developed
Undeveloped
Total
Gross
Net
Gross
Net (1)
Gross
Net
Total leasehold acreage
360,765
146,323
10,424
1,320
371,189
147,643
1.
Approximately 95% of the net undeveloped acres are covered by leases that will expire in the years 2025—2028 unless drilling or production extends
those leases.
Price and Production Data. The following tables present the average sales price and production volumes for our oil,
NGLs, and natural gas activities during the periods indicated:
Year Ended December 31,
2024
2023
Average sales price per barrel of oil produced:
Price before derivatives
$
74.51 $
75.57
Effect of derivatives
—
(14.96)
Price including derivatives
$
74.51 $
60.61
Average sales price per barrel of NGLs produced:
Price before derivatives
$
19.71 $
18.02
Effect of derivatives
—
—
Price including derivatives
$
19.71 $
18.02
Average sales price per Mcf of natural gas produced:
Price before derivatives
$
1.58 $
2.07
Effect of derivatives
—
0.21
Price including derivatives
$
1.58 $
2.28
Year Ended December 31,
2024
2023
Oil production (MBbls):
Anadarko basin
681
972
All other basins
12
13
Total oil production
693
984
NGLs production (MBbls):
Anadarko basin
1,004
1,633
All other basins
3
3
Total NGL production
1,007
1,636
Natural gas production (MMcf):
Anadarko basin
13,516
20,122
All other basins
47
73
Total natural gas production
13,563
20,195
Total production (MBoe):
Anadarko basin
3,938
5,958
All other basins
23
28
Total BOE production
3,961
5,986
The Anadarko basin contained 96% and 97% of our total proved reserves as of December 31, 2024 and 2023,
respectively, expressed on an oil-equivalent barrel basis. There are no other basins that accounted for more than 10% of our
proved reserves.
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5
Oil, NGLs, and Natural Gas Reserves. The table below presents our estimated proved developed and undeveloped oil,
NGLs, and natural gas reserves as of December 31, 2024:
Oil
(MBbls)
NGLs
(MBbls)
Natural Gas
(MMcf)
Total Proved
Reserves
(MBoe)
Proved developed
4,669
8,758
85,565
27,688
Proved undeveloped
—
—
—
—
Total proved
4,669
8,758
85,565
27,688
Oil, NGLs, and natural gas reserves cannot be measured exactly. Estimates of those reserves require extensive judgments
of reservoir engineering data and are generally less precise than other estimates made in financial disclosures.
Company Reserve Estimation and Technical Qualifications
Our Reservoir Engineering department is responsible for reserve determination for the wells in which we have an interest.
Their primary objective is to estimate the wells' future reserves and future net value to us. Data is incorporated from multiple
sources including geological, production engineering, marketing, production, land, and accounting departments. The engineers
review this information for accuracy as it is incorporated into the reservoir engineering database. Management reviews our
internal controls to help provide assurance all the data has been provided. New well reserve estimates are provided to
management and the respective operational divisions for additional scrutiny. Major reserve changes on existing wells are
reviewed regularly with the operational divisions to confirm completeness and accuracy. As the external audit is being
completed, the reservoir department reviews all properties for accuracy of forecasting.
Responsible for overseeing the preparation of our reserve report is our reservoir engineer Derek Smith.
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 promoted to Reservoir Manager. He has been a member of the Society of Petroleum Engineers (SPE) since 2000 and
joined the Society of Petroleum Evaluation Engineers (SPEE) in 2018.
As part of his continuing education Mr. Smith has attended various seminars and forums to enhance his 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 Annual Report. The
wells or locations for which reserve estimates were audited were taken from our reserve and income projections as of December
31, 2024, 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 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 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.
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Paradiso fulfills. Based on his educational background, professional training and over 41 years of practical experience in the
estimation and evaluation of petroleum reserves, Mr. Paradiso has attained the professional qualifications as a Reserves
Estimator and Reserves Auditor in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas
Reserves Information” promulgated by the SPE as of June 2019. For more information regarding Mr. Paradiso’s geographic
and job-specific experience, please refer to the Ryder Scott Company website at http://www.ryderscott.com/Company/
Employees.
Definitions and Other Proved Reserve Information.
For proved reserves, the area of the reservoir considered as "proved" includes:
•
The area identified by drilling and limited by any fluid contacts, and
•
Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with the
reservoir and to contain economically producible oil or gas based on available geosciences and engineering data.
Absent data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as incurred
in a well penetration unless geosciences, engineering, or performance data and reliable technology establish a lower contact
with reasonable certainty.
Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an
associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geosciences,
engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
Reserves which can be produced economically through application of improved recovery techniques (including, but not
limited to, fluid injection) are included in the proved classification when:
•
Successful testing by a pilot project in an area of the reservoir with properties no more favorable than the reservoir as
a whole;
•
The operation of an installed program in the reservoir or other evidence using reliable technology establishes
reasonable certainty of the engineering analysis on which the project or program was based; and
•
The project has been approved for development by all necessary parties and entities, including governmental entities.
Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be
determined. The price used is the average of the prices over the 12 months before the ending date of the period covered by the
report and is an unweighted arithmetic average of the first day of the month price for each month within the period, unless
prices are defined by contractual arrangements, excluding escalations based on future conditions.
Proved Undeveloped Reserves. As of December 31, 2024, we had not recorded any proved undeveloped reserves.
Our estimated proved reserves and the standardized measure of discounted future net cash flows of the proved reserves at
December 31, 2024 and 2023, the changes in quantities, and standardized measure of those reserves for the years then ended,
are shown in the Supplemental Oil and Gas Disclosures in 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
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. Three third-party customers accounted for 46% of our oil and natural gas revenues during the year ended
December 31, 2024 and no other company accounted for over 10% of our oil and natural gas revenues.
CONTRACT DRILLING
General. Our contract drilling business is conducted through Unit Drilling Company. We drill onshore oil and natural gas
wells for a wide range of other oil and natural gas companies as well as for our own account. Our drilling operations are located
in Oklahoma, Texas and New Mexico.
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The following table presents information about our contract drilling segment assets and operations as of and during the
periods indicated:
Year Ended December 31,
2024
2023
Number of drilling rigs available for use at end of period
14
14
Average number of drilling rigs utilized
12.1
15.1
Utilization rate (1)
87 %
95 %
Average revenue per day (2)
$
32,544
$
32,854
Total footage drilled (in thousands of feet)
4,477
5,449
Number of wells drilled
229
300
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 2023 reduction in drilling rigs available for use.
2.
Represents the total revenues from our contract drilling segment divided by the total days our drilling rigs were used during the year.
Description and Location of Our Drilling Rigs. An on-shore drilling rig is composed of major equipment components
like engines, drawworks or hoists, derrick or mast, substructure, mud pumps, blowout preventers, top drives, and drill pipe.
Because of the normal wear and tear from operating 24 hours a day, several of the major components, like engines, mud pumps,
top drives, and drill pipe, must be replaced or overhauled periodically. Other major components, like the substructure, mast, and
drawworks, can be used for extended periods with proper inspections and maintenance. We also own additional equipment used
in operating our drilling rigs, including iron roughnecks, automated catwalks, skidding systems, and other support equipment.
The majority of the wells we drill today are horizontal wells. Depending on our customers' well programs, we routinely drill
horizontal wells ranging from 15,000 to over 25,000 feet in length.
The following table presents the contractual status and capabilities of our drilling rigs as of December 31, 2024:
Contracted Rigs
Non-Contracted
Total Rigs
Average Rated
Drilling Depth
(ft)
BOSS rigs
12
2
14
20,000
Fluctuating commodity prices directly affect the number of drilling rigs we can put to work, both positively and
negatively. Generally, sustained higher commodity prices lead to greater demand for drilling rigs, while demand and rates tends
to fall as commodity prices decline for any extended period. The number of drilling rigs we can work also depends on several
conditions besides demand, including the availability of qualified labor as well as the availability of needed drilling supplies
and equipment.
The following table presents the average number of our drilling rigs working by quarter during the years indicated:
2024
2023
First quarter
13.7
16.8
Second quarter
11.9
15.6
Third quarter
11.1
14.1
Fourth quarter
11.9
13.9
Drilling Rig Fleet. Our rig fleet consists of 14 super-spec BOSS rigs. Total rigs available for use was reduced from 18 to
14 during 2023 to reflect the removal of the older generation SCR rigs from our fleet.
Dispositions. On May 18, 2023, the Company closed on the sale of two older generation SCR rigs and certain related
equipment for total proceeds of $5.8 million. Cash proceeds of $5.0 million were received at closing and deferred cash proceeds
of $0.8 million were received on January 25, 2024. The deferred proceeds are included in notes receivable on the consolidated
balance sheets. The total proceeds recognized during the year ended December 31, 2023 resulted in net gains of $4.4 million,
which are presented within gain on disposition of assets in the consolidated statements of operations.
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Proceeds for the sale of other non-core contract drilling assets totaled $2.9 million, and $13.6 million during the years
ended December 31, 2024, and 2023, respectively. These proceeds resulted in net gains of $1.8 million and $9.5 million during
the years ended December 31, 2024 and 2023. The net gains are presented within gain on disposition of assets in the
consolidated statements of operations.
Drilling Contracts. Our third-party drilling contracts are obtained through a competitive bidding process. Contract terms
and payment rates vary depending on the type of contract used, the duration of the work, the equipment and services supplied,
and other matters. We pay certain operating expenses, including the wages of our drilling rig personnel, maintenance expenses,
and incidental drilling rig supplies and equipment. The contracts are usually subject to early termination by the customer subject
to the payment of a fee. Our contracts also contain provisions regarding indemnification against certain types of claims
involving injury to persons, property, and for acts of pollution. The specific terms of these indemnifications are negotiated on a
contract-by-contract basis.
All of our drilling contracts during 2024 and 2023 were daywork contracts. Under a daywork contract, we provide the
drilling rig with the required personnel and the operator supervises the drilling of the well. Our daywork compensation is based
on a negotiated rate to be paid for each day the drilling rig is used.
Most of our contracts are term contracts, with the rest being either well-to-well or pad-to-pad contracts. Term contracts
can range from months to a year and the rates can either be fixed throughout the term or allow for periodic adjustments.
Customers. Four customers accounted for 94% of our contract drilling revenues during the year ended December 31,
2024. No other third-party customer accounted for 10% or more of our contract drilling revenues.
Our contract drilling segment may also provide drilling services for our oil and natural gas segment. 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. We did not have any eliminations during the years ended December 31, 2024 or 2023.
COMPETITION
All our businesses are highly competitive and price sensitive. Competition in the contract drilling business traditionally
involves factors such as demand, price, efficiency, the condition of equipment, availability of labor and equipment, reputation,
and customer relations.
Our oil and natural gas operations likewise encounter strong competition from other oil and natural gas companies. Many
competitors have greater financial, technical, and other resources than we do and have more experience than we do in the
exploration for and production of oil and natural gas. Our drilling success and the success of other activities integral to our
operations will depend, in part, on our ability to attract and retain experienced geologists, engineers, and other professionals
during times of increased competition as competition for these professionals can be intense.
HUMAN CAPITAL
We believe that our employees are critical to our future success, and seek to provide competitive compensation and
benefits to attract and retain a skilled workforce. We care about the well-being and development of our employees, and aim to
provide a culture of respect and collaboration by supporting employee training and development. We are also very focused on
maintaining a culture of continuous improvement in safety and environmental practices as safety and environmental
stewardship are at the forefront of everything that we do.
As of December 31, 2024, we had 516 employees, none of whom are members of a union or labor organization. Our
workforce includes 417 employees in our contract drilling segment, 70 employees in our oil and natural gas segment, and 29
employees in our general corporate group. We also periodically utilize the services of independent contractors. We have not
experienced any strikes or work-force stoppages.
GOVERNMENTAL REGULATIONS
General. Our business depends on the demand for oil, natural gas, and natural gas liquids, as well as the demand for
services from the oil and natural gas exploration and development industry. 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.
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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, FERC regulates the interstate transportation
and the sale in interstate commerce for resale of natural gas. FERC’s authority over interstate natural gas sales has been
substantially modified by the Natural Gas Policy Act under which FERC continued to regulate the maximum selling prices of
certain categories of gas sold in “first sales” in interstate and intrastate commerce. Effective January 1, 1993, however, the
Natural Gas Wellhead Decontrol Act (the Decontrol Act) deregulated natural gas prices for all “first sales” of natural gas.
Because “first sales” include typical wellhead sales by producers, all natural gas produced from our natural gas properties is
sold at market prices, subject to the terms of any private contracts which may be in effect. FERC’s authority over interstate
natural gas transportation is not affected by the Decontrol Act.
Our sales of natural gas are affected by intrastate and interstate gas transportation regulation. Beginning in 1985, FERC
adopted regulatory changes that have significantly altered the transportation and marketing of natural gas. These changes are
intended by FERC to foster competition by, among other things, transforming the role of interstate pipeline companies from
wholesale marketers of natural gas to the primary role of gas transporters. All natural gas marketing by the pipelines must
divest to a marketing affiliate, which operates separately from the transporter and in direct competition with all other merchants.
Because of the various omnibus rulemaking proceedings in the late 1980s and the later individual pipeline restructuring
proceedings of the early to mid-1990s, interstate pipelines must provide open and nondiscriminatory transportation and
transportation-related services to all producers, natural gas marketing companies, local distribution companies, industrial end
users, and other customers seeking service. Through similar orders affecting intrastate pipelines that provide similar interstate
services, FERC expanded the impact of open access regulations to certain aspects of intrastate commerce.
FERC has pursued other policy initiatives that affected natural gas marketing. Most notable are (1) the large-scale
divestiture of interstate pipeline-owned gas gathering facilities to affiliated or non-affiliated companies; (2) further development
of rules governing the relationship of the pipelines with their marketing affiliates; (3) the publication of standards relating to
using electronic bulletin boards and electronic data exchange by the pipelines to make available transportation information
timely and to enable transactions to occur on a purely electronic basis; (4) further review of the role of the secondary market for
released pipeline capacity and its relationship to open access service in the primary market; and (5) development of policy and
promulgation of orders pertaining to its authorization of market-based rates (rather than traditional cost-of-service based rates)
for transportation or transportation-related services on the pipeline’s demonstration of lack of market control in the relevant
service market.
Because of these changes, independent sellers and buyers of natural gas have gained direct access to the pipeline services
they need and can better conduct business with a larger number of counterparties. 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.
We may be indirectly exposed to certain risks in the U.S. LNG export markets. The LNG export industry is a highly
regulated and capital intensive industry that is subject to a number of risks. Many facilities remain under construction or are
expanding, and if these facilities are unable to obtain and maintain approvals and permits from governmental and regulatory
agencies, the U.S. LNG market may be materially and adversely impacted, which could reduce demand for U.S. natural gas and
have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and
prospects.
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
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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 Federal Water Pollution Control Act, or the Clean Water Act, and comparable state laws impose
restrictions and strict controls regarding the discharge of pollutants, including produced waters and other oil and natural gas
wastes, into federal and state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with
the terms of a permit issued by the U.S. Environmental Protection Agency (EPA) or a state equivalent agency. The discharge of
dredge and fill material in regulated waters, including wetlands, is also prohibited, unless authorized by a permit issued by the
U.S. Army Corps of Engineers (Corps). The scope of the Clean Water Act’s jurisdiction has been the subject of significant
uncertainty and litigation in recent years. For example, under the Obama Administration, the EPA and the U.S. Army Corp of
Engineers proposed a new expansive definition of the “waters of the United States,” known as the “Clean Water Rule.”
However, during the Trump Administration, the EPA and the Corps replaced the Clean Water Rule with the Navigable Waters
Protection Rule (NWPR), which narrows the definition of “waters of the United States” to four categories of jurisdictional
waters and includes twelve categories of exclusions, including groundwater; however, these rulemakings are currently subject
to litigation and it is possible that the Biden Administration could propose a broader definition for these regulated waters. Both
the Clean Water Rule and the NWPR are subject to ongoing litigation, with the Clean Water Rule in effect in certain states and
the NWPR in effect in others. In addition, in an April 2020 decision defining the scope of the Clean Water Act that was handed
down just days after the NWPR was published, the U.S. Supreme Court held that, in certain cases, discharges from a point
source to groundwater could fall within the scope of the Clean Water Act and require a permit. The Court rejected the EPA’s
and Corps’ assertion that groundwater should be totally excluded from the Clean Water Act. The Court’s decision is expected to
bolster challenges to the NWPR. As a result of these developments, the scope of jurisdiction under the Clean Water Act is
uncertain at this time.
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To the extent any rule expands the scope of the Clean Water Act’s jurisdiction in areas where we operate, we could face
increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas, which could delay the
development of our natural gas and oil projects. Similarly, any increased costs or delays for such permits may impact the
development of pipeline infrastructure, which may impact our ability to transport our products. Also, pursuant to these laws and
regulations, we may be required to obtain and maintain approvals or permits for the discharge of wastewater or storm water and
are required to develop and implement spill prevention, control and countermeasure plans, also referred to as “SPCC plans,” in
connection with on-site storage of significant quantities of oil. These laws and any implementing regulations provide for
administrative, civil and criminal penalties for any unauthorized discharges of oil and other substances in reportable quantities
and may impose substantial potential liability for the costs of removal, remediation and damages.
Hazardous Substances and Waste Management. RCRA and comparable state statutes regulate the generation,
transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Pursuant to rules issued by the
EPA, individual state governments administer some or all of the provisions of RCRA, sometimes in conjunction with their own,
more stringent requirements. Drilling fluids, produced waters and most of the other wastes associated with the exploration,
development and production of oil or natural gas are currently regulated under RCRA’s non-hazardous waste provisions.
However, it is possible that certain oil, natural gas, and drilling and production wastes now classified as non-hazardous could be
classified as hazardous wastes in the future.
CERCLA, also known as the Superfund law, imposes joint and several liability, without regard to fault or legality of
conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the
environment. These persons include the current and former owners and operators of the site where the release occurred and
anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, such persons
may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into
the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for
neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the
hazardous substances released into the environment. We generate materials during our operations that may be regulated as
hazardous substances. Despite the “petroleum exclusion” of CERCLA, which currently encompasses crude oil and natural gas,
we may nonetheless generate or handle hazardous substances within the meaning of CERCLA, or similar state statutes, in the
course of our ordinary operations and, as a result, may be jointly and severally liable under CERCLA for all or part of the costs
required to clean up sites at which these hazardous substances have been released into the environment. In addition, we
currently own, lease, or operate numerous properties that have been used for oil and natural gas exploration, production and
processing for many years. Although we believe that we have utilized operating and waste disposal practices that were standard
in the industry at the time, hazardous substances, wastes, or hydrocarbons may have been released on, under or from the
properties owned or leased by us, or on, under or from other locations, including off-site locations, where such substances have
been taken for disposal. Under such laws, we could be required to undertake investigatory, response, or corrective measures,
which could include soil and groundwater sampling, the removal of previously disposed substances and wastes, the cleanup of
contaminated property, or remedial plugging or pit closure operations to prevent future contamination, the costs of which could
be substantial.
Endangered Species Act. The federal Endangered Species Act (ESA) and analogous state laws regulate many activities,
including oil and gas development, which could have an adverse effect on species listed as threatened or endangered under the
ESA or their habitats. Designating previously unidentified endangered or threatened species could cause oil and natural gas
exploration and production operators and service companies to incur additional costs or become subject to operating delays,
restrictions or bans in affected areas, which impacts could adversely reduce drilling activities in affected areas. Both of our
business segments could be subject to the effect of one or more species being listed as threatened or endangered within the areas
of our operations. Numerous species have been listed or are under consideration for protected status under the ESA in areas in
which we provide or could undertake operations, such as the dunes sagebrush lizard, lesser prairie chicken, and greater sage
grouse. In addition, the Supreme Court held in 2018 that only the actual habitat of an endangered species can be designated
critical habitat, meaning that an uninhabited area that otherwise meets the definition of critical habitat should not be so
designated. Following this decision, the U.S. Fish and Wildlife Service (FWS) and the National Marine Fisheries Service
NMFS) issued joint regulations in December 2020 defining critical habitat to mean an area that currently or periodically
contains the resources and conditions necessary to support a species listed under the ESA. The Department of Interior (DOI)
also finalized rules in January 2021 under the Migratory Bird Treaty Act, which imposes similar restrictions and penalties as
those found under the ESA, that limit the imposition of criminal sanctions in instances where only an incidental take of
protected birds occurs. The Biden Administration has stated that it plans to review the FWS, NMFS, and DOI regulations and
has paused implementation of the DOI rules. The presence of protected species in areas where we provide contract drilling or
conduct exploration and production operations could impair our ability to timely complete or carry out those services and,
consequently, hurt our results of operations and financial position.
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Air Emissions. The federal Clean Air Act and comparable state laws restrict the emission of air pollutants from many
sources, such as tank batteries and compressor stations, through air emissions standards, construction and operating permitting
programs and the imposition of other compliance requirements. These laws and regulations may require us to obtain
preapproval for the construction or modification of certain projects or facilities expected to produce or significantly increase air
emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to
control emissions of certain pollutants. The EPA has also adopted rules under the Clean Air Act that require the reduction of
volatile organic compound emissions from certain fractured and refractured natural gas wells for which well completion
operations are conducted and further require that most wells use reduced emission completions, also known as “green
completions.” These regulations also establish specific new requirements regarding emissions from production-related wet seal
and reciprocating compressors and from pneumatic controllers and storage vessels. The EPA expanded on its emission
standards for volatile organic compounds in June 2016 with the issuance of first-time standards to address emissions of
methane from equipment and processes across oil and natural gas production, storage, processing and transmission sources,
including hydraulically fractured oil natural gas and well completions.
On August 16, 2022, President Biden signed a budget reconciliation measure commonly referred to as the “Inflation
Reduction Act of 2022” (IRA). The IRA contains incentives for the development of renewable energy, clean hydrogen, clean
fuels, electric vehicles and supporting infrastructure and carbon capture and sequestration, among other provisions. The IRA
also includes a charge on methane emissions which is the first ever federal fee on emissions through a methane emissions
charge. Facilities required to report their greenhouse gas (GHG) emissions to the EPA will be assessed a fee of $900 per metric
ton of methane in 2024, increasing to $1,500 per metric ton for 2026 and each year thereafter.
On December 2, 2023, the EPA issued a final rule of pollution reduction standards that address sources of methane and
other pollutants at oil and gas facilities, including methane that leaks or is vented from equipment and processes. The final rule
will phase in a requirement to eliminate routine flaring of natural gas that is produced by new oil wells, require comprehensive
monitoring for leaks of methane from well sites and compressor stations, while giving oil and gas companies flexibility to use
low-cost and innovative methane monitoring technologies, and establish standards that require reductions in emissions from
high-emitting equipment like controllers, pumps, and storage tanks.
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 GHGs. At the federal level, no comprehensive
climate change law or regulation has been implemented to date. The EPA has, however, adopted regulations that, among other
things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources, and
together with the U.S. Department of Transportation, implement GHG emissions limits on vehicles manufactured for operation
in the United States. The federal regulation of methane emissions from oil and gas facilities has been subject to controversy in
recent years. For more information, see our regulatory disclosure titled “Air Emissions.”
The adoption and implementation of new or more stringent international, federal or state legislation, regulations or other
regulatory initiatives that impose more stringent standards upon GHG emissions from the oil and natural gas sector could result
in increased costs of compliance. Concerns related to the impacts of climate change could also result in reduced demand for oil
and natural gas and adversely impact the value of reserves. In addition, increased financial scrutiny of climate risks could result
in restrictions on our access to capital. Moreover, there are increasing risks to operations resulting from the potential physical
impacts of climate change, such as drought, wildfires, damage to infrastructure and resources from flooding, storms, and other
natural disasters and other physical disruptions. One or more of these developments could have a material adverse effect on our
business, financial condition and results of operation.
Hydraulic Fracturing. Our oil and natural gas segment routinely apply hydraulic fracturing techniques to many of our oil
and natural gas properties. Hydraulic fracturing has been the subject of public scrutiny over the past several years. While states
typically have primary authority with respect to regulating oil and natural gas production activities, including hydraulic
fracturing, from time to time Congress has considered passing new laws to regulate this practice, and the U.S. Government has
asserted regulatory authority over certain aspects of hydraulic fracturing. In addition, certain states in which we operate,
including Texas and Oklahoma, have adopted, and other states and municipalities and other local governmental entities in some
states, have and others are considering adopting regulations and ordinances that could impose more stringent permitting, require
the public disclosure of chemicals in fracking fluids, flaring limitations, waste disposal, and well construction requirements on
these operations, and even restrict or ban hydraulic fracturing in certain circumstances.
In December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water
resources. The final report concluded that certain activities associated with hydraulic fracturing may impact drinking water
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resources under certain limited circumstances. Both the EPA and the United States Geological Survey (USGS) have made
statements indicating that the disposal of wastes associated with hydraulic fracturing via injection wells may result in induced
seismic events. Several states, including Texas and Oklahoma, have adopted measures limiting disposal well operations in areas
under certain circumstances.
At the state level, several states, including Texas, have adopted or are considering legal requirements that require oil and
natural gas operators to disclose chemical ingredients and water volumes used to hydraulically fracture wells, in addition to
more stringent well construction and monitoring requirements. Local governments may also adopt ordinances within their
jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular.
Any new laws, regulation, or permitting requirements regarding hydraulic fracturing could lead to operational delay, or
increased operating costs or third party or governmental claims, and could result in additional burdens that could delay or limit
the drilling services we provide to third parties whose drilling operations could be affected by these regulations or increase our
costs of compliance and doing business and delay the development of unconventional gas resources from shale formations
which are not commercial without using hydraulic fracturing. Restrictions on hydraulic fracturing could also reduce the oil and
natural gas we can ultimately produce from our reserves.
Other; Compliance Costs. We cannot predict future legislation or regulations. It is possible that some future laws,
regulations, and/or ordinances could increase our compliance costs and/or impose additional operating restrictions on us as well
as those of our customers. Such future developments also might curtail the demand for fossil fuels which could hurt the demand
for our services, which could hurt our future results of operations. Likewise, we cannot predict with any certainty whether any
changes to temperature, storm intensity or precipitation patterns because of climate change (or otherwise) will have a material
impact on our operations.
Compliance with applicable environmental requirements has not, to date, had a material effect on the cost of our
operations, earnings, or competitive position. However, as noted above in our discussion of the regulation of GHG and
hydraulic fracturing, compliance with amended, new, or more stringent requirements of existing environmental regulations or
requirements may cause us to incur additional costs or subject us to liabilities that may have a material adverse effect on our
results of operations and financial condition.
RISK FACTORS
RISKS CONCERNING COMMODITY PRICES
Our business is heavily affected by commodity prices. Oil, NGLs, and natural gas prices are volatile, and low prices have
hurt our financial results and could do so in the future.
Our revenues, operating results, cash flow, and growth depend on prevailing prices for oil, NGLs, and natural gas. Oil,
NGLs, and natural gas prices and markets have been volatile, and they are likely to remain volatile.
The prices we receive for our oil, NGLs, and natural gas production affect our revenues, profitability, cash flow, and
ability to meet our projected financial and operational goals. Prices also tend to influence third parties' use of our services.
Those prices are decided by many factors beyond our control, including:
•
the demand for and supply of oil, NGLs, and natural gas;
•
weather conditions in the continental United States (which can influence the demand and prices for natural gas);
•
the amount and timing of oil, natural gas, and liquefied petroleum gas imports and exports;
•
the ability of distribution systems in the United States to effectively meet the demand for oil, NGLs, and natural gas,
particularly in times of peak demand which may result because of adverse weather conditions;
•
the ability or willingness of OPEC+ to set and support production levels for oil;
•
oil and gas production levels by non-OPEC+ countries;
•
political and economic uncertainty and geopolitical activity, including military conflicts and perceived hostilities in oil
producing regions;
•
governmental policies and subsidies;
•
the costs of exploring for, producing, and delivering oil and natural gas;
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•
technological advances affecting energy consumption;
•
United States storage levels of oil, NGLs, and natural gas;
•
price, availability, and acceptance of alternative fuels;
•
volatility in ethane prices causing rejection of ethane as part of the liquids processed stream;
•
pandemics, epidemics, outbreaks, or other public health events;
•
worldwide economic conditions;
•
advancement in oil and gas technologies that impact the demand for energy;
•
the development and use of alternative energy sources; and
•
increased focus by the investment community on alternative energy resources.
Oil prices are sensitive to domestic and foreign influences based on political, social, or economic underpinnings, any of
which could have an immediate and significant effect on the price and supply of oil. Prices of oil, NGLs, and natural gas can
also be influenced by trading on the commodities markets which has increased the volatility associated with these prices,
causing large differences in prices on even a weekly and monthly basis.
Based on our production for the year ended December 31, 2024, a $0.10 per Mcf change in what we receive for our
natural gas production, without the effect of derivatives, would cause a corresponding $0.1 million per month ($1.3 million
annualized) change in our pre-tax operating cash flow. A $1.00 per barrel change in our oil price, without the effect of
derivatives, would result in a $0.1 million per month ($0.7 million annualized) change in our pre-tax operating cash flow and a
$1.00 per barrel change in our NGLs price, without the effect of derivatives, would result in a $0.1 million per month ($1.1
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 may use derivative
contracts like swaps and collars. Derivative contracts may expose us to risk of financial loss and limit the benefit to us due to
changes in market prices. Volumes not covered by derivative contracts are subject to market prices.
See Note 16 - Derivatives for additional information.
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 or the carrying value of our drilling rigs.
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 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.
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RISKS RELATED TO OIL, NGL, AND NATURAL GAS RESERVES
Many uncertainties are inherent in estimating quantities of oil, NGLs, and natural gas reserves and their values, including
factors beyond our control. Actual production, revenues, and expenditures regarding our oil, NGLs, and natural gas
reserves will likely vary from estimates, and those variances may be material.
Many uncertainties are inherent in estimating quantities of oil, NGLs, and natural gas reserves and their values, including
factors beyond our control. The oil, NGLs, and natural gas reserve information in this report is only an estimate of these
reserves. Oil, NGLs, and natural gas reservoir engineering is a subjective and inexact process of estimating underground
accumulations of oil, NGLs, and natural gas that cannot be measured precisely. Estimates of economically recoverable oil,
NGLs, and natural gas reserves depend on several variable factors, including historical production from the area compared with
production from other producing areas, and assumptions about: reservoir size; the effects of regulations by governmental
agencies; future oil, NGLs, and natural gas prices; future operating costs; severance and excise taxes; operational risks;
development costs; and workover and remedial costs.
Some or all these assumptions may vary considerably from actual results. For these and other reasons, estimates of the
economically recoverable quantities of oil, NGLs, and natural gas attributable to any group of properties, classifications of
those oil, NGLs, and natural gas reserves based on the risk of recovery, and estimates of the future net cash flows from oil,
NGLs, and natural gas reserves prepared by different engineers or by the same engineers but at different times may vary
substantially. Oil, NGLs, and natural gas reserve estimates may be subject to periodic downward or upward adjustments. Actual
production, revenues, and expenditures regarding our oil, NGLs, and natural gas reserves will likely vary from estimates, and
those variances may be material.
The information about discounted future net cash flows in this report is not necessarily the current market value of the
estimated oil, NGLs, and natural gas reserves attributable to our properties. Using full cost accounting requires us to use the
unweighted arithmetic average of the commodity prices existing on the first day of each of the 12 months before the end of the
reporting period to calculate discounted future revenues unless prices were otherwise determined under contractual
arrangements. Actual future prices and costs may be materially higher or lower. Actual future net cash flows are also affected
by these factors:
•
the amount and timing of oil, NGLs, and natural gas production;
•
supply and demand for oil, NGLs, and natural gas;
•
increases or decreases in consumption; and
•
changes in governmental regulations or taxation.
Although we are not a reporting company under the Exchange Act, we use the 10% discount factor required by the SEC
for calculating discounted future net cash flows for reporting purposes, which is not necessarily the most accurate discount
factor based on interest rates in effect from time to time and the risks associated with our operations or the oil and natural gas
industry.
Estimated quantities of oil, NGLs, and natural gas reserves and their values used to prepare our consolidated financial
statements and supplemental oil and gas disclosures may differ from estimates used in other strategic or economic purposes.
As described above, the information about discounted future net cash flows in this report is not necessarily the current
market value of the estimated oil, NGLs, and natural gas reserves attributable to our properties so estimates used by
management for strategic or economic purposes may differ.
RISKS RELATED TO FINANCING OUR BUSINESS
Our inability to satisfy our future debt obligations and covenants could result in our failure to meet our capital needs and
adversely affect our operations.
We may incur substantial capital expenditures in our operations. Historically, we have funded our capital needs through
internally generated cash flows. As of December 31, 2024, we had no outstanding borrowings under our credit agreement.
If we borrow under our credit agreement, the cash flow needed to satisfy that debt and the covenants in our bank credit
agreements could:
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•
limit funds otherwise available for financing our capital expenditures, our drilling program, or other activities or cause
us to curtail these activities;
•
limit our flexibility in planning for or reacting to changes in our business;
•
place us at a competitive disadvantage to those of our competitors less indebted than we are;
•
make us more vulnerable during periods of low oil, NGLs, and natural gas prices or if a downturn in our business
occurs; and
•
prevent us from obtaining more financing on acceptable terms or limit amounts available under our existing or future
credit facilities.
Our ability to meet any future debt obligations depends on our future performance. If such obligations are not satisfied, a
default could be deemed to occur, and our lenders could accelerate the payment of the outstanding indebtedness. See “Our long-
term liquidity requirements and the adequacy of our capital resources are difficult to predict” below.
Restrictive covenants in our credit facilities may limit our financial and operating flexibility and our ability to pursue our
business strategies.
As of December 31, 2024, we had no outstanding borrowings under our credit agreement. Our financing agreement
permits us to incur more indebtedness and other obligations. We may also seek amendments or waivers from our existing
lenders if we need to incur indebtedness above amounts permitted by our financing agreement.
Our credit facility contains certain restrictions, which may have adverse effects on our business, financial condition, cash
flows or results of operations, limiting our ability, among other things, to:
•
incur additional indebtedness;
•
incur additional liens;
•
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 facility also requires 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 lender(s) under our credit
facility may elect to declare all borrowings outstanding, together with accrued interest and other fees, to be immediately due.
The lender(s) would also have the right in that case to terminate any commitments they have to provide more borrowings. If we
cannot repay our indebtedness when due or declared due, the lenders may also proceed against the collateral pledged to secure
the indebtedness. If the indebtedness was accelerated, our assets might not fully repay our secured indebtedness.
Disruptions in the financial markets could affect our ability to obtain financing or refinance existing indebtedness on
reasonable terms and may have other adverse effects.
Commercial-credit and equity market disruptions may cause tight capital markets in the United States. Liquidity in the
global capital markets can be severely contracted by market disruptions making financing less attractive. In some cases, it leads
to the unavailability of certain types of financing. Because of credit and equity market turmoil, we may not obtain debt or equity
financing or refinance existing indebtedness on favorable terms, which could affect operations and financial performance.
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Our ability to declare and pay dividends and repurchase shares is subject to certain considerations.
Dividends and share repurchases are authorized and determined by our Board of Directors in its sole discretion and
depend upon a number of factors, including the Company’s financial results, cash requirements, and future prospects, as well as
other factors deemed relevant by our Board of Directors. We can provide no assurance that we will continue to pay dividends at
the current rate or at all or authorize share repurchases. Any elimination of, or reduction to, our dividend payout or share
repurchase program could have an adverse effect on the market price of our common stock.
RISKS RELATED TO OPERATING OUR BUSINESS
Increasing attention to environmental, social and governance (ESG) matters may adversely impact our business.
Organizations that provide information to investors on corporate governance and related matters have developed ratings
processes for evaluating companies on their approach to ESG matters. Such ratings are used by some investors to evaluate their
investment and voting decisions. Unfavorable ESG ratings may lead to increased negative investor sentiment toward us and to
the diversion of their investment away from the fossil fuel industry to other industries which could have a negative impact on
our stock price and our access to and costs of capital.
Public health events outside our control, including pandemics, epidemics, and infectious disease outbreaks may materially
hurt our business.
We face risks related to epidemics, pandemics, outbreaks, or other public health events outside our control that could
disrupt our operations and hurt our financial condition. It is difficult to predict the timing, frequency or severity of such events
or how such frequency or severity may change. Any such events could have a material adverse effect on our results of
operations or financial condition.
The industries in which we operate are highly competitive, and many of our competitors have resources more significant
than we do.
The drilling industry in which we operate is generally very competitive. Most drilling contracts are awarded based on
competitive bids, which may cause intense price competition. Some of our competitors in the contract drilling industry have
greater financial and human resources than we do. These resources may enable them to withstand periods of low drilling rig use
better, compete more effectively based on price and technology, build new drilling rigs, or acquire existing drilling rigs, and
provide drilling rigs more quickly than we do in periods of high drilling rig use.
The oil and natural gas industry is also highly competitive. We compete in property acquisitions and oil and natural gas
exploration, development, production, and marketing with major oil companies, other independent oil and natural gas concerns,
and individual producers and operators. Many of our competitors in the oil and natural gas industry have resources substantially
greater than we do.
Competition for experienced technical personnel may hurt our operations or financial results.
Our success will depend, in part, on our ability to attract and retain experienced geologists, engineers, drilling rig hands,
and other employees. Competition for these employees can be intense, particularly when the industry is experiencing favorable
conditions.
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Our operations are subject to inherent risks that, if material, could harm our results of operations.
Our contract drilling operations are subject to many hazards, including blowouts, cratering, explosions, fires, loss of well
control, loss of hole, damaged or lost drilling equipment, and damage or loss from inclement weather. Our exploration and
production operations are subject to these and similar risks. These events could cause personal injury or death, damage to or
destruction of equipment and facilities, suspension of operations, environmental damage, and damage to others’ property.
Generally, drilling contracts provide for the division of responsibilities between a drilling company and its customer. We seek
to obtain contractual indemnification from our drilling customers for some of these risks. If we cannot transfer these risks to
drilling customers by contract or indemnification agreements (or if we assume obligations of indemnity or assume liability for
certain risks under our drilling contracts), we seek protection from some of these risks through insurance. Still, some risks are
not covered by insurance. We cannot assure you that the insurance we have or the indemnification agreements we have will
adequately protect us against liability from the consequences of the hazards described above. An event not fully insured or
indemnified against, or a customer’s failure to meet its indemnification obligations, could cause substantial losses. We cannot
assure you that insurance will be available to cover any or all of these risks. Even if available, the insurance might not be
adequate to cover all of our losses, or we might decide against obtaining that insurance because of high premiums or other
costs.
Our exploration and development operations involve many risks that may cause dry holes, the failure to produce oil,
NGLs, and natural gas in commercial quantities, and the inability to fully produce discovered reserves. The cost of drilling,
completing, and operating wells is substantial and uncertain. Many of these factors are beyond our control and may cause the
curtailment, delay, or cancellation of drilling operations.
Exploratory drilling is a speculative activity. Success rates may decline. Also, we may not lease or drill the drilling
prospects we have identified or budgeted for. 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 operational risks for those wells and our
ability to influence those wells’ operations are less subject to our control and the operators of those wells may act in ways not in
our best interests.
Our oil and natural gas segment’s prospective drilling locations are in various evaluation stages, ranging from a prospect
ready to drill to a prospect that will require additional geological and engineering analysis. Based on many factors, including
future oil, NGLs, natural gas prices, the generation of additional seismic or geological information, and other factors, we may
decide not to drill one or more of these prospects. We may not increase or maintain our reserves or production, which could
hurt our business, financial position, and operating results. Although we are not a reporting company under the Exchange Act,
we still comply with the SEC’s reserve reporting rules requiring 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, 2024,
we had no proved undeveloped drilling locations.
New technologies may cause our exploration and drilling methods to become obsolete, causing an adverse effect on our
production.
Our industry is subject to rapid and significant technological advancements, including the introduction of new products
and services using new technologies. As competitors use or develop new technologies, we may be at a competitive
disadvantage, and competitive pressures may force us to implement new technologies at a substantial cost. In addition, our
competitors may have greater financial, technical, and personnel resources that allow them to enjoy technological advantages
and may allow them to implement new technologies before we can. We cannot be sure that we can implement technologies
timely or at an acceptable cost. One or more technologies we use or that we may implement may become obsolete or may not
work as we expected, and we may be hurt financially and operationally as a result.
Our operating results depend on our ability to transport oil, NGLs, and gas production to key markets.
The marketability of our oil, NGLs, and natural gas production depends in part on the availability, proximity, and
capacity of pipeline systems, refineries, and other transportation sources. The unavailability of or lack of capacity on these
systems and facilities could cause the shut-in of producing wells or the delay or discontinuance of development plans for
properties. Federal and state regulation of oil, NGLs, and natural gas production and transportation, tax, and energy policies,
changes in supply and demand, pipeline pressures, damage to or destruction of pipelines, and general economic conditions
could hurt our ability to produce, gather, and, transport oil, NGLs, and natural gas.
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Losing one or several of our larger customers could have a material adverse effect on our financial condition and results of
operations.
During the year ended December 31, 2024, three customers accounted for 46% of our oil and natural gas revenue and four
customers accounted for 94% of our contract drilling revenues. No other third-party customer accounted for 10% or more of
any of our segment revenues. Any customer may choose not to use our services or purchase oil, natural gas, or NGLs from us,
and losing one or several of our larger customers could have a material adverse effect on our financial condition and results of
operations if we could not find replacements.
We rely on management and other key employees.
We depend significantly on the efforts of our executive officers and other key employees to manage our operations. The
loss or unavailability of any of our executive officers or other key employees could have a material adverse effect on our
business.
We are subject to various claims and litigation that could ultimately be resolved against us, requiring material future cash
payments or future material charges against our operating income, and materially impairing our financial position.
The nature of our business makes us highly susceptible to claims and litigation. We are subject to various existing legal
claims and lawsuits, which could have a material adverse effect on our consolidated financial position, results of operations, or
cash flows. Even if indemnified or insured, any claims or litigation could hurt our reputation among our customers and the
public and make it harder for us to compete effectively or obtain adequate insurance in the future.
Demand for our contract drilling 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 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 greenhouse gases (GHGs) could result in
increased operating costs and reduced demand for the oil, natural gas and NGLs we produce.
Climate change continues to attract considerable public and scientific attention. As a result, numerous proposals have
been made and may continue to be made at the international, national, regional and state levels of government to monitor and
limit emissions of GHGs. These efforts have included consideration of cap-and-trade programs, carbon taxes, GHG reporting
and tracking programs, mandates for the production of renewable fuels, and regulations that directly limit GHG emissions from
certain sources. At the federal level, no comprehensive climate change legislation has been implemented to date. The EPA has,
however, adopted regulations that, among other things, establish construction and operating permit reviews for GHG emissions
from certain large stationary sources, and together with the U.S. Department of Transportation, implement GHG emissions
limits on vehicles manufactured for operation in the United States. For more information, see our regulatory disclosure titled
“Air Emissions.”
The adoption and implementation of new or more stringent international, federal or state legislation, regulations or other
regulatory initiatives that impose more stringent standards upon GHG emissions from the oil and natural gas sector could result
in increased costs of compliance. Concerns related to the impacts of climate change could also result in reduced demand for oil
and natural gas and adversely impact the value of reserves. In addition, increased financial scrutiny of climate risks could result
in restrictions on our access to capital. Moreover, there are increasing risks to operations resulting from the potential physical
impacts of climate change, such as drought, wildfires, damage to infrastructure and resources from flooding, storms, and other
natural disasters and other physical disruptions. One or more of these developments could have a material adverse effect on our
business, financial condition and results of operations.
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Geopolitical tensions may create market volatility or other disruptions which could negatively impact our ability to carry out
our business plan.
Although we have no direct transactional or supply chain exposure to current areas of conflict, 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.
Ineffective internal controls could affect the accuracy and timely reporting of our business and financial results.
Our internal controls 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.
Consolidation in our industry may impact our results.
The oil and gas industry has seen significant consolidation in recent years, with some of our largest contract drilling
clients merging and using leveraging their increased size and purchasing power to achieve cost efficiencies and negotiate lower
prices. Ongoing consolidation in the sector could lead to reduced capital spending by certain operators, potentially diminishing
the demand for our contract drilling services. The potential effects of industry consolidation on pricing, customer capital
expenditures, our competitive position, customer retention, and contract negotiations remain uncertain.
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 cash flows generated from
operations and available borrowing capacity. If our cash flows from operations decrease, 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 credit facility, (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.
The contract land drilling industry and the exploration and development 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. Growth from mergers or
acquisitions 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.
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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.
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 possible that third parties may claim that our BOSS
drilling rig design infringes on their intellectual property rights. In that event, we may resolve these claims by signing royalty
and licensing agreements, redesigning the drilling rig, or paying damages. These outcomes may cause operating margins to
decline. In addition to money damages, plaintiffs may seek injunctive relief in some jurisdictions that may limit or prevent
marketing and use of our drilling rigs if they are determined to be an infringement upon a third party's intellectual property
rights.
RISKS RELATED TO REGULATIONS
New laws, policies, regulations, rulemaking, and oversight, as well as changes to those currently in effect, could adversely
impact our earnings, cash flows, and operations.
Our business is subject to federal, state, and local laws and regulations on taxation, the exploration for and development,
production, and marketing of oil and natural gas, and safety matters. Many laws and regulations require drilling permits and
govern the spacing of wells, production rates, prevention of waste, unitization and pooling of properties, and other matters.
These laws and regulations have increased the costs of planning, designing, drilling, installing, operating, and abandoning our
oil and natural gas wells and other facilities. These laws and regulations, and any others passed by the jurisdictions where we
have production, could limit the number of wells drilled or the allowable production from successful wells, limiting our
revenues.
We are (or could become) subject to complex environmental laws and regulations adopted by the jurisdictions where we
own properties or operate. We could incur liability to governments or third parties for discharges of oil, natural gas, or other
pollutants into the air, soil, or water, including responsibility for remedial costs. We could discharge these materials into the
environment in many ways, including:
•
from a well or drilling equipment at a drill site;
•
from gathering systems, pipelines, transportation facilities, and storage tanks;
•
damage to oil and natural gas wells resulting from accidents during normal operations;
•
sabotage; and
•
blowouts, cratering, and explosions.
Because the requirements imposed by laws and regulations often change, we cannot assure you that future laws and
regulations, including changes to existing laws and regulations, will not have a material adverse effect on our business or results
of operations. The United States Congress and White House administration may impose more stringent environmental
requirements on our operations or change existing laws and regulations in a manner that could adversely impact our business.
Stricter standards, greater regulation, and more extensive permit requirements could increase our future risks and costs related
to environmental matters. Because we acquire interests in properties operated in the past by others, we may be liable for
environmental damage caused by the former operators, which liability could be material.
Emissions regulations or legislation, including the Inflation Reduction Act of 2022, could accelerate the transition away
from fossil fuels and increase the costs of our operations.
On August 16, 2022, President Biden signed a budget reconciliation measure commonly referred to as the “Inflation
Reduction Act of 2022” (IRA). The IRA contains incentives for the development of renewable energy, clean hydrogen, clean
fuels, electric vehicles and supporting infrastructure and carbon capture and sequestration, among other provisions. These
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incentives could accelerate the transition away from the use of fossil fuels, which could decrease demand for oil and natural gas
having an adverse impact on our business.
The IRA also includes a charge on methane emissions, which is the first ever federal fee on emissions through a methane
emissions charge. Facilities required to report their GHG emissions to the EPA, which includes our facilities, will be assessed a
fee of $900 per metric ton of methane in 2024, increasing to $1,500 per metric ton for 2026 and each year thereafter. These new
fees and the related compliance and monitoring costs could increase the costs of our operations.
Proposed federal and state legislative and regulatory initiatives relating to hydraulic fracturing could cause increased costs
and additional operating restrictions or delays.
Hydraulic fracturing is an essential and common practice in the oil and gas industry used to stimulate the production of
oil, natural gas, and associated liquids from dense subsurface rock formations. Our oil and natural gas segment routinely applies
hydraulic-fracturing techniques to many of our oil and natural gas properties, including our plays in Texas and Oklahoma.
Hydraulic-fracturing involves using water, sand, and certain chemicals to fracture the hydrocarbon-bearing rock formation to
allow hydrocarbons’ flow into the wellbore. State oil and natural gas commissions process typically regulate this process, but
the EPA has asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel under the Safe
Drinking Water Act and published permitting guidance addressing the performance of such activities. The EPA has also
finalized rules under the Clean Water Act in June 2016 that prohibit the discharge of wastewater from hydraulic fracturing
operations to publicly owned wastewater treatment plants. Separately, in December 2016, the EPA released its final report on
the potential impacts of hydraulic fracturing on drinking water resources. The final report concluded that certain activities
associated with hydraulic fracturing may impact drinking water resources under certain limited circumstances.
Some states where we operate, including Texas and Oklahoma, have adopted, and other states are considering adopting,
regulations that could impose more stringent permitting, public disclosure of fracking fluids, waste disposal, and well
construction requirements on hydraulic-fracturing operations or otherwise seek to ban fracturing activities altogether. Local
governments may also seek to restrict or prohibit well-drilling, hydraulic fracturing, or both. If state, local, or municipal legal
restrictions are adopted in areas where we are conducting or plan to conduct operations, we may incur added costs to comply
with such requirements that may be significant, experience delays or curtailment pursuing exploration, development, or
production activities, and perhaps even be precluded from the drilling and completion of wells.
In addition, our ability to produce crude oil, natural gas, and associated liquids economically and in commercial quantities
could be impaired if we cannot get adequate supplies of water for our drilling and completion operations or cannot dispose of or
recycle the water we use at a reasonable cost and under applicable environmental rules. Any new laws, regulation, or permitting
requirements regarding hydraulic fracturing could lead to operational delays, or increased operating costs or third party or
governmental claims, and could result in additional burdens that could delay or limit the drilling services we provide to third
parties whose drilling operations could be affected by these regulations or increase our costs of compliance and doing business
and delay the development of unconventional gas resources from shale formations which are not commercial without using
hydraulic fracturing. Restrictions on hydraulic fracturing could also reduce the oil and natural gas we can ultimately produce
from our reserves.
To our knowledge, there have been no citations, suits, or contamination of potable drinking water arising from our
fracturing operations. We do not have insurance policies in effect intended to supply coverage for losses solely related to
hydraulic fracturing operations, but our general liability and excess liability insurance policies might cover third-party claims
related to hydraulic fracturing operations and associated legal expenses depending on the specific nature of the claims, the
timing of the claims, and the specific terms of such policies.
The hydraulic fracturing process on which we depend to produce commercial quantities of crude oil, natural gas, and
associated NGLs from many reservoirs requires the use and disposal of significant water quantities.
Our inability to secure enough water or dispose of or recycle the water used in our oil and natural gas segment operations
could hurt our operations. Imposing new environmental initiatives and regulations could include restrictions on our ability to
conduct certain operations such as hydraulic fracturing or disposal of wastes, including, but not limited to, produced water,
drilling fluids, and other wastes associated with the exploration, development, or production of oil and natural gas.
Compliance with environmental regulations and permit requirements governing the withdrawal, storage and, use of
surface water or groundwater necessary for hydraulic fracturing of wells may increase our operating costs and cause delays,
interruptions, or termination of our operations, the extent of which cannot be predicted, all of which could hurt our operations
and financial condition.
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23
The potential listing of species as “endangered” under the federal Endangered Species Act could cause increased costs and
new operating restrictions or delays on our operations and of our customers, which could hurt our operations and financial
results.
The ESA and similar state laws regulate various activities, including oil and gas development, which could harm species
listed as threatened or endangered under the ESA or their habitats. Designating previously unidentified endangered or
threatened species could cause oil and natural gas exploration and production operators and service companies to incur added
costs or become subject to operating delays, restrictions, or bans in affected areas, which impacts could reduce drilling activities
in affected areas. All of our business segments could be subject to the effect of one or more species being listed as threatened or
endangered within the areas of our operations. Many species have been listed or are under consideration for protected status in
areas we operate or could undertake operations, such as the dunes sagebrush lizard, lesser prairie chicken, and greater sage
grouse.
RISKS RELATED TO TERRORIST ATTACKS OR CYBER-ATTACKS
Terrorist attacks or cyber-attacks could have a material adverse effect on our business, financial condition, or results of
operations.
Terrorist attacks or cyber-attacks may affect the energy industry and economic conditions, including our operations and
our customers, general economic conditions, consumer confidence and spending, and market liquidity. Strategic targets, such as
energy-related assets, may be at greater risk of future attacks than other United States targets. A cyber incident could cause
information theft, data corruption, operational disruption, and financial loss. Our insurance may not protect us against such
occurrences. It is possible that any of these occurrences, or a combination of them, could have a material adverse effect on our
business, financial condition, and results of operations.
We are increasingly dependent on digital technologies, including information systems, infrastructure, and cloud
applications and services, to operate our businesses, process and record financial and operating data, communicate with our
employees and business partners, analyze seismic and drilling information, estimate quantities of natural gas reserves, and
perform other activities related to our businesses. Our business partners, including vendors, service providers, and financial
institutions, also depend on digital technology.
As dependence on digital technologies has increased, cyber incidents, including deliberate attacks or unintentional events,
have also increased. A cyber-attack could include gaining unauthorized access to digital systems to misappropriate assets or
sensitive information, corrupting data, or causing operational disruption, or result in denial-of-service on websites.
Our technologies, systems, networks, and those of our business partners may become the target of cyber-attacks or
information security breaches that could cause the unauthorized release, gathering, monitoring, misuse, loss, or destruction of
proprietary and other information, or other disruption of our business operations. Some cyber incidents, like surveillance, may
remain undetected for a long time.
Deliberate attacks on our assets, or security breaches in our systems or infrastructure, the systems or infrastructure of
third-parties or the cloud could lead to corruption or loss of our proprietary data and potentially sensitive data, delays in
production or delivery, difficulty completing and settling transactions, challenges in maintaining our books and records,
environmental damage, communication interruptions, other operational disruptions, and third-party liability, including:
•
a cyber-attack on a vendor or service provider could cause supply chain disruptions, which could delay or halt the
development of more infrastructure, effectively delaying the start of cash flows from the project;
•
a cyber-attack on our facilities may cause equipment damage or failure;
•
a cyber-attack on mid-stream or downstream pipelines could prevent our products from being delivered, leading to
losing revenues;
•
a cyber-attack on a communications network or power grid could cause operational disruption resulting in loss of
revenues;
•
deliberate corruption of our financial or operational data could cause events of non-compliance leading to regulatory
fines or penalties; and
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24
•
business interruptions could cause expensive remediation efforts, the distraction of management, or damage to our
reputation.
Implementation of various controls and processes to monitor and mitigate security threats and increase security for our
information, facilities and infrastructure are costly and labor-intensive. There can be no assurance that such measures will
prevent security breaches from occurring. As cyber threats continue to evolve, we may have to spend significant additional
resources to modify or enhance our protective measures or investigate and remediate any information security vulnerabilities.
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 the
Depository Trust Company (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 OTCQX® Best Market 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.
Our New Common Stock is quoted on the OTCQX® Best Market, which 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 shareholders 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 shareholders can liquidate their investment or liquidate it
at a price that reflects the business’ value.
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25
Our charter and by-laws contain provisions that could delay or discourage a change in control transaction or prevent
shareholders 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 shareholders 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 of Directors, (ii)
undertaking any fundamental change to the nature of the business, or (iii) consummating a public offering of common
stock.
•
The Board of Directors is divided into two classes, Group I and Group II. The current Group I directors will serve until
the Company’s 2025 annual meeting of stockholders, and the current Group II directors will serve until the Company’s
2026 annual meeting of shareholders. 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 shareholders, 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 shareholders may only be called by the Board of Directors or by the secretary of the Company
at the written request of shareholders owning at least 25% of the voting stock.
•
The Board of Directors has the ability to authorize undesignated preferred stock. This ability makes it possible for our
Board of Directors 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 the remaining directors then in office, even if less than a quorum, or by a sole remaining director.
•
Advance notice requirements for nominations for election to the Board of Directors and business to be brought by
shareholders before any annual meeting of shareholders.
Part D. Management Structure and Financial Information
The Name of the Chief Executive Officer, Members of the Board of Directors, as well as Control Persons
A.
Officers and Directors
Information About Our Executive Officers
The table below and accompanying text sets forth certain information as of March 13, 2025, 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.
Table of Contents
26
Name
Age
Positions Held
Phil Frohlich
70
Director since September 3, 2020, Chief Executive Officer since April 1, 2023
Andrew E. Harding
47
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
60
Chief Financial Officer since June 23, 2021; Chief Accounting Officer from December 31, 2020 to
September 30, 2023; Interim Chief Financial Officer from October 22, 2020 to June 23, 2021
Christopher K.
Menefee
47
President - Unit Drilling Company since November 9, 2020
Karl Bode
66
Sr. Vice President, Business Development - Unit Petroleum Company since January 1, 2019
Mr. Frohlich was elected as a director in September 2020. He has served as interim Chief Executive Officer of the
Company since April 1, 2023. He founded Prescott Capital Management in 1992 and has been serving as Managing Partner
since. The Oklahoma-based hedge fund focuses on small and mid-cap stocks. Mr. Frohlich was formerly president of Tulsa-
based Siegfried Companies Inc. and a tax principal with what is now the international accounting firm Ernst & Young. He
received a B.B.A. in Economics from the University of Oklahoma in 1976, an M.B.A. at the University of Texas at Austin in
1980, and a J.D. from the University of Tulsa in 1993.
Mr. Harding joined Unit in August 2004 as a Staff Attorney. In March 2005, he was promoted to the position of
Associate General Counsel. In October 2020, he was promoted to Vice President, General Counsel, and Secretary. Mr. Harding
received his Bachelor of Business Administration from Baylor University in 2001, and his Juris Doctorate from the University
of Tulsa College of Law in 2004. He is a member of the Oklahoma Bar Association. He is also a member of the Petroleum
Alliance of Oklahoma board of directors and is chairman of the legal committee.
Mr. Sell joined Unit in October 2020 as Interim Chief Financial Officer. In December 2020, he also become Chief
Accounting Officer ("CAO"), and in June 2021 he became Chief Financial Officer, CAO and Controller. From March 2020 to
October 2020, he was the Chief Financial Officer for Montereau, Inc., a retirement community. From 2016 to March 2020, Mr.
Sell served as Chief Accounting Officer and Controller for SemGroup Corporation, a gathering, transportation, storage,
distribution, marketing and other midstream services company. From 1996 to 2016, Mr. Sell was with Williams Companies,
Inc., where he held several different management positions in finance and accounting. Mr. Sell was with Deloitte & Touche
from 1987 to 1996. Mr. Sell received his Bachelor of Science in Accounting from Oral Roberts University, where he graduated
magna cum laude. He is a certified public accountant.
Mr. Menefee was appointed President of Unit Drilling Company in November 2020. He most recently served as Senior
Vice President, Business Development at Independence Contract Drilling, Inc., an onshore oil and gas contract drilling services
company, from May 2012 to April 2020. Before that, he spent over 15 years at Rowan Companies, Inc. where he held many
operational and management roles, including the Director of Marketing from 2006 to 2012. Mr. Menefee graduated from The
University of Mississippi in Oxford with a Bachelor of Arts in Psychology. He holds a graduate certificate in corporate finance
from the Cox School of Business at Southern Methodist University.
Mr. Bode joined Unit in November 2012 as Manager of Non-Operated Properties. In 2014 he was promoted to Chief
Engineer. In 2017 he was promoted to the position of Vice-President and subsequently was promoted to position of Sr. Vice-
President in 2019. Mr. Bode received a Bachelor of Science degree in Petroleum Engineering from the University of Tulsa in
1981 and earned a Certified Public Accounting license in 1999. Prior to Unit, Mr. Bode held various engineering, accounting
and management positions at QEP Resources, Kaiser-Francis Oil Company, Samson Resources Company and Chevron, USA.
Information About Our Directors
The table below and accompanying text sets forth certain information as of March 13, 2025, concerning each member of
our Board of Directors (the "Board"). There is currently a vacancy in Group 1.
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27
Name
Age
Director
Since
Group
Committees of
the Board
Term
Expires
Primary Occupation
Robert R. Anderson
67
2020
II
2026
Executive, GBK Corporation, Tulsa,
Oklahoma
Alan J. Carr
54
2020
II
Compensation (Chair)
Strategic Transactions
2026
Chief Executive Officer, Drivetrain,
LLC, New York City, New York
Phil Frohlich
70
2020
II
Audit
2026
Managing Partner, Prescott Capital
Management, Tulsa, Oklahoma
Steven B. Hildebrand
70
2008
I
Audit (Chair)
Strategic Transactions
2025
Investments, Tulsa, Oklahoma
Philip B. Smith
73
2020
II
2026
President, Chief Executive Officer and
Chairman of the Board, Unit
Corporation, Tulsa, Oklahoma
Andrei Verona
46
2020
I
Strategic Transactions (Chair)
Audit, Compensation
2025
Spectrum Fund Portfolio Manager at
Saye Capital Management,
headquartered in Redondo Beach,
California
Mr. Anderson was elected as a director in September 2020. Since 2010 he has worked as an executive with GBK
Corporation, a holding company with numerous energy industry subsidiaries and affiliates, including Kaiser Francis Oil
Company, which has extensive domestic upstream oil & gas interests, and Cactus Drilling Company, which is a major domestic
contract drilling company, serving on numerous private boards including Summit ESP which was acquired by Halliburton in
2017. Between 2002 and 2010 Mr. Anderson engaged primarily in personal investing with a focus on oil & gas supply/demand
fundamentals while simultaneously serving on the University of Kansas Chemical & Petroleum Engineering Board of Advisors.
In 1998, he was co-founder and CEO of privately held Sapient Energy Corp which was subsequently sold to Chesapeake
Energy in 2002. During his time with Sapient, Mr. Anderson was also actively involved on the IPAA’s Capital Markets
Committee. Prior to establishing Sapient Energy, Mr. Anderson worked for Kaiser-Francis Oil Company in various roles of
increasing responsibilities from 1984 through 1997. After graduating from the University of Kansas in 1980 with a BS 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 was elected as a director in September 2020. Since September 2013 he has worked as the Managing Member and
Chief Executive Officer of Drivetrain, LLC, an independent fiduciary services firm. He has been a distressed investing and
turnaround professional, with 25 years of experience in principal investing, advisory mandates, and board of directors’ service,
including complex financial restructurings and reorganizations in the U.S. and Europe. From 2003 to 2013, Mr. Carr was
Managing Director at Strategic Value Partners, a global investment firm focused on distressed debt and private equity
opportunities. Mr. Carr started his career at Skadden, Arps, Slate, Meagher & Flom LLC and Ravin, Sarasohn, Baumgarten,
Fisch & Rosen in corporate restructuring advisory. He received a B.A. in Economics and Sociology from Brandeis University
in 1992 and earned a J.D. from Tulane Law School in 1995. Mr. Carr currently serves as a director for the following public
company: NewLake Capital Partners (since 2019). Public companies for which Mr. Carr no longer serves as director but on
which he served as a director in the last five years include: Sears Holdings Corporation; Enjoy Technology, Inc.; Atlas Iron
Limited; TEAC Corporation; Tidewater Inc.; Midstates Petroleum Company, Inc.; Verso Corporation; McDermott
International, Inc.; Basic Energy Services; 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. Frohlich biographical information is listed in the section above setting forth information about our officers. Attributes,
experience, and qualifications for board and committee service: executive and entrepreneurial experience; accounting,
investment, business and legal expertise.
Mr. Hildebrand was elected as a director in October 2008. Since March 2008, he has been engaged in personal
investments. He retired in 2008 from Dollar Thrifty Automotive Group, Inc., a car rental business, where he had served as
Executive Vice President and Chief Financial Officer since 1997. Prior to that, Mr. Hildebrand served as Executive Vice
President and Chief Financial Officer of Thrifty Rent-A-Car System, Inc., a subsidiary of Dollar Thrifty. Mr. Hildebrand
joined Thrifty Rent-A-Car System, Inc. in 1987 as Vice President and Treasurer and became Chief Financial Officer in 1989.
Mr. Hildebrand was with Franklin Supply Company, an oilfield supply business, from 1980 to 1987 where he held several
positions including Controller and Vice President of Finance. From 1976 to 1980, Mr. Hildebrand was with the accounting
firm Coopers & Lybrand, most recently as Audit Supervisor. Mr. Hildebrand earned a B.S.B.A. degree in accounting from
Oklahoma State University, and he is a retired status 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
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28
management, executive compensation, corporate compliance, internal audit, bank facilities, private placement debt transactions
and working with ratings agencies.
Mr. Smith was named to the Board of Directors on September 3, 2020, and became Chairman on September 8, 2020. He
served as President and Chief Executive Officer of the Company from October 2020 to March 2023. Before his appointment to
Unit’s Board, he was self-employed since 2002. Mr. Smith served on the Board of Directors of Eagle Rock Energy LP from
2007 to 2015. Mr. Smith was Chief Executive Officer and Chairman of Prize Energy Corp., which he co-founded with Natural
Gas Partners in 1999, until the company’s merger with Magnum Hunter Resources in 2002. Mr. Smith also served as Chief
Executive Officer of Tide West Oil Company until it was sold to HS Resources in 1996. He received a B.S. in Mechanical
Engineering from Oklahoma State University and a Master of Business Administration from the University of Tulsa.
Attributes, experience, and qualifications for board and committee service: executive leadership experience and industry
familiarity; entrepreneurial and business experience; and engineering background.
Mr. Verona was elected as a director in September 2020. He is an advisor to Saye Capital Management, an opportunistic
credit hedge fund headquartered in Rancho Palos Verdes, California, where he previously was a portfolio manager from 2013 to
2024. He helps manage the corporate portion of the portfolio, which invests primarily in high yield and distressed bonds with a
focus on restructurings and other event-driven opportunities. From 2009 to 2013, Mr. Verona was with Gleacher & Company's
Investment Banking Group, serving most recently as Vice President. At Gleacher he focused on middle market corporates,
advising clients on in-court and out-of-court restructurings, financings, and M&A transactions. Prior to Gleacher, he was a
Senior Associate in GSC Partners' Corporate Credit Group. Mr. Verona started his career in the convertible bond and
structured credit groups at Pacific Investment Management Company (PIMCO). He graduated cum laude from the University
of California Los Angeles with a degree in Economics. Mr. Verona is a director for Iracore International, a private company,
where he serves as the Audit Chair and Special Committee Chair. From November 2020 to October 2021, he served as a
director for the public company Lonestar Resources US Inc., where he was the Audit Chair and a member of the Compensation
Committee. Attributes, experience, and qualifications for board and committee service: complex investment and securitization
experience; financial analysis expertise; M&A expertise; restructuring experience; and director experience.
Compensation of Officers and Directors
Beneficial share ownership of Officers and Directors as of March 13, 2025:
Phil Frohlich 2
Chief Executive
Officer and
Director
18,168
—
—
18,168
Thomas D. Sell
Chief Financial
Officer
22,316
—
—
22,316
Andrew E. Harding
Vice President,
Secretary and
General Counsel
6,671
—
10,744
17,415
Chris Menefee
President – Unit
Drilling Company
26,303
—
—
26,303
Karl Bode
Senior Vice
President, Business
Development –
Unit Petroleum
Company
17,889
—
—
17,889
Robert R. Anderson Director
39,434
—
—
39,434
Alan J. Carr
Director
18,168
—
—
18,168
Steven B.
Hildebrand
Director
18,186
—
—
18,168
Philip B. Smith
Director and
Chairman of the
Board
55,063
—
—
55,063
Andrei Verona
Director
13,626
—
—
13,626
Name and Business
Address*
Position
Common Stock
Restricted Stock
units vesting within
60 days
Options
Exercisable within
60 days
Total Beneficially
Owned Shares 1
*All officers and directors may be contacted at Unit Corporation’s address.
1.
Beneficial share ownership includes vested restricted stock units, vested options, and restricted stock units and options scheduled to vest within 60
days of March 13, 2025.
2.
Mr. Frohlich manages Prescott Group Capital Management, which owns 3,517,707 shares of Unit Corporation’s common stock.
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29
The following tables set forth the aggregate compensation paid by Unit Corporation for services rendered by its Executive
Officers and Directors during the periods indicated:
Executive Officers
Name and Principal
Position
Year
Ended
Salary ($)
Cash Bonus
($)
Restricted
Stock Awards
($)
Performance
Restricted
Stock Awards
($)
Option
Awards ($)
Total ($)
Phil Frohlich, Chief
Executive Officer 1
2024 $
— $
— $
— $
— $
— $
—
2023 $
— $
— $
— $
— $
— $
—
Philip B. Smith,
Former President and
Chief Executive
Officer 2
2024 $
— $
— $
— $
— $
— $
—
2023 $
3,000 $
— $
— $
— $
— $
3,000
Thomas D. Sell, Chief
Financial Officer
2024 $
351,900 $
244,340 $
73,892 $
119,284 $
— $
789,416
2023 $
340,000 $
238,000 $
— $
— $
— $
578,000
Andrew E. Harding,
Vice President,
Secretary and General
Counsel
2024 $
299,115 $
148,349 $
44,883 $
72,414 $
— $
564,761
2023 $
289,000 $
144,500 $
— $
— $
— $
433,500
Chris Menefee,
President - Unit
Drilling Company
2024 $
330,000 $
229,134 $
69,295 $
111,864 $
— $
740,293
2023 $
300,035 $
200,000 $
— $
— $
— $
500,035
Karl Bode, Senior Vice
President, Business
Development - Unit
Petroleum Company
2024 $
300,000 $
148,788 $
44,992 $
72,641 $
— $
566,421
2023 $
275,000 $
137,500 $
— $
— $
— $
412,500
1.
Mr. Frohlich became the Company’s Chief Executive Officer on April 1, 2023.
2.
Mr. Smith stepped down as the Company’s President and Chief Executive Officer on March 31, 2023.
Directors
Our directors fees are structured as set forth in the table below:
Annual retainer
$65,000
Annual retainer for each committee a board member serves on
$10,000
Additional compensation for service as board chair
$15,000
Reimbursement for expenses incurred attending stockholder, board, and committee meetings
Yes
Table of Contents
30
Name
Year Ended
Director's Fees ($)
Restricted Stock
Awards ($)
Option Awards ($)
Total ($)
Robert R. Anderson
2024 $
65,000 $
195,471 $
— $
260,471
2023 $
65,000 $
159,023 $
— $
224,023
Alan J. Carr
2024 $
85,000 $
125,015 $
— $
210,015
2023 $
85,000 $
— $
— $
85,000
Phil Frohlich
2024 $
75,000 $
125,015 $
— $
200,015
2023 $
75,000 $
— $
— $
75,000
Steven B. Hildebrand
2024 $
85,000 $
125,015 $
— $
210,015
2023 $
85,000 $
— $
— $
85,000
Philip B. Smith
2024 $
80,000 $
125,015 $
— $
205,015
2023 $
80,000 $
— $
— $
80,000
Andrei Verona
2024 $
95,000 $
125,015 $
— $
220,015
2023 $
95,000 $
— $
— $
95,000
B. Other Control Persons
As of December 31, 2024, the following shareholders beneficially own 5% or more of Unit Corporation’s common stock:
Name
Address
Number of Shares Beneficially Owned
Prescott Group Capital Management, LLC
1924 South Utica Avenue, Suite 1120
Tulsa, Oklahoma 74104
3,517,707
NYL Investors LLC
51 Madison Avenue, 2nd Floor New
York, New York 10010
623,361
Unit Corporation is not aware of any additional beneficial stockholders owning 5% or more of our common stock. It is
possible that there are one or more additional beneficial holders of a significant percentage of our common stock, however the
federal securities laws do not require a beneficial stockholder of 5% or more of our common stock to disclose that information
publicly or to the Company. The table above is based on the best information available to the Company.
C. Legal/Disciplinary History
None of the officers, directors, promoters, or control persons of Unit has, in the past five years, been the subject of any of
the following:
•
A conviction in a criminal proceeding or named as a defendant in a pending criminal proceeding (excluding traffic
violations and other minor offenses);
•
The entry of an order, judgment or decree, not subsequently reversed, suspended or vacated, by a court of competent
jurisdiction that permanently or temporarily enjoined, barred, suspended, or otherwise limited such person’s
involvement in any type of business, securities, commodities, or banking activities;
•
A finding or judgment by a court of competent jurisdiction (in a civil action), the SEC or the Commodity Futures
Trading Commission, or a state securities regulator of a violation of federal or state securities or commodities law,
which finding or judgment has not been reversed, suspended, or vacated; or
•
The entry of an order by a self-regulatory organization that permanently or temporarily barred, suspended, or
otherwise limited such person’s involvement in any type of business or securities activities.
D. Disclosure of Family Relationships
None.
Table of Contents
31
E. Disclosure of Related Party Transactions
Certain Transactions Between the Company and Its Officers, Directors, and Their Associates
One current director, Robert Anderson, also serves as an executive with GBK Corporation, a holding company with
numerous energy and industry subsidiaries and affiliates, including Kaiser Francis Oil Company. The Company in the ordinary
course of business, made payments for working interests, joint interest billings, drilling services, and product purchases to, and
received payments for working interests, joint interest billings, and contract drilling services from, Kaiser Francis Oil Company.
Payments made to Kaiser Francis Oil Company totaled $0.9 million and $2.2 million during 2024 and 2023, respectively, while
payments received totaled $4.3 million and $6.2 million during 2024 and 2023, respectively. Additionally, on January 7, 2022
(the "grant date"), Mr. Anderson entered into a consulting contract with the Company. Under the terms of the consulting
contract, Mr. Anderson agreed to provide advisory consulting services related to the Company's sale of up to all of the assets of
its exploration and production segment in exchange for awards of 7,850 restricted stock units and 13,416 stock options having a
total estimated grant date fair value of $0.3 million. The restricted stock units vest in equal monthly installments beginning one
month from the grant date, and will be fully vested within thirty months of the grant date. The stock options became 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.
F. Disclosure of Conflicts of Interest
None.
The name, address, telephone number, and email address of each of the following outside providers that advise the
issuer on matters relating to operations, business development and disclosure:
1. Investment Banker:
None
2. Promoters:
None
3. Disclosure Counsel:
Conner & Winters, LLP
15 E. 5th St., Suite 4100
Tulsa, OK 74103
(918) 586-8600
https://www.cwlaw.com/
4. Auditor:
Grant Thornton LLP
6120 S. Yale Ave., Suite 1400
Tulsa, OK 74136
(918) 877-0800
https://www.grantthornton.com/
5. Public Relations Consultant:
None
6. Investor Relations Consultant:
None
7. Corporate Secretary:
Drew Harding, Vice President, General Counsel, and Secretary
8200 S. Unit Dr.
Tulsa, OK 74132
(918) 493-7700
drew.harding@unitcorp.com
8. Any Other Advisor:
None
Auditor Fees and Services
Preparation of the consolidated financial statements is the responsibility of Unit's management. Grant Thornton LLP is
responsible for expressing an opinion on the consolidated financial statements based on their audit procedures. Grant Thornton
LLP has confirmed to us that the firm is licensed to practice public accounting in the states in which we conduct our business
and is registered with the PCAOB.
The table below presents the fees for professional services paid to Grant Thornton LLP during the years indicated:
Table of Contents
32
Type of Service
2024
2023
Audit Fees
$550,000
$626,000
Audit-Related Fees (1)
$26,500
$25,200
Tax Fees (2)
$32,554
$55,670
All Other Fees
—
—
Total
$609,054
$706,870
1.
Audit-related fees include professional services for the audit of the Unit Corporation 401(k) Employee Thrift Plan's financial statements.
2.
Tax fees include professional services related to the review and assistance with selected income tax filings and various consulting projects.
Policy on Audit Committee Pre-Approval of Audit and Permissible Non-Audit Services of Independent Auditor
The audit committee has responsibility for appointing, setting compensation, and overseeing the work of the independent
certified public accounting firm. In recognition of this responsibility, the audit committee has established a policy to pre-
approve all audit and permissible non-audit services provided by the independent certified public accounting firm.
Before incurring the following, management will submit to the audit committee for approval a list of services and related
fees expected to be rendered by our independent certified 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 certified 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 certified
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 certified 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 certified public accounting firm's services within each category. The
fees are budgeted and the audit committee requires the independent certified 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 certified 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 certified 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.
Table of Contents
33
Index to the Consolidated Financial Statements
Unit Corporation and Subsidiaries
Page
Consolidated Financial Statements:
Report of Independent Certified Public Accounting Firm
35
Consolidated Balance Sheets as of December 31, 2024 and 2023
36
Consolidated Statements of Operations for the years ended December 31, 2024 and 2023
37
Consolidated Statements of Changes in Shareholders’ Equity for the years ended December 31, 2024 and 2023
38
Consolidated Statements of Cash Flows for the years ended December 31, 2024 and 2023
39
Notes to Consolidated Financial Statements
41
Table of Contents
34
Report of Independent Certified Public Accounting Firm
Board of Directors
Unit Corporation
Opinion
We have audited the consolidated financial statements of Unit Corporation (a Delaware corporation) and subsidiaries (the “Company”), which
comprise the consolidated balance sheets as of December 31, 2024 and 2023, and the related consolidated statements of operations, changes
in stockholders’ equity, and cash flows for the years then ended, and the related notes to the consolidated financial statements.
In our opinion, the accompanying consolidated financial statements present fairly, in all material respects, the financial position of the
Company as of December 31, 2024 and 2023, and the results of its operations and its cash flows for the years then ended in accordance with
accounting principles generally accepted in the United States of America.
Basis for opinion
We conducted our audits of the consolidated financial statements in accordance with auditing standards generally accepted in the United
States of America (US GAAS). Our responsibilities under those standards are further described in the Auditor’s Responsibilities for the Audit
of the Financial Statements section of our report. We are required to be independent of the Company and to meet our other ethical
responsibilities in accordance with the relevant ethical requirements relating to our audits. We believe that the audit evidence we have
obtained is sufficient and appropriate to provide a basis for our audit opinion.
Responsibilities of management for the financial statements
Management is responsible for the preparation and fair presentation of the consolidated financial statements in accordance with accounting
principles generally accepted in the United States of America, and for the design, implementation, and maintenance of internal control
relevant to the preparation and fair presentation of consolidated financial statements that are free from material misstatement, whether due to
fraud or error.
In preparing the consolidated financial statements, management is required to evaluate whether there are conditions or events, considered in
the aggregate, that raise substantial doubt about the Company’s ability to continue as a going concern for one year after the date the
consolidated financial statements are issued.
Auditor’s responsibilities for the audit of the financial statements
Our objectives are to obtain reasonable assurance about whether the consolidated financial statements as a whole are free from material
misstatement, whether due to fraud or error, and to issue an auditor’s report that includes our opinion. Reasonable assurance is a high level of
assurance but is not absolute assurance and therefore is not a guarantee that an audit conducted in accordance with US GAAS will always
detect a material misstatement when it exists. The risk of not detecting a material misstatement resulting from fraud is higher than for one
resulting from error, as fraud may involve collusion, forgery, intentional omissions, misrepresentations, or the override of internal control.
Misstatements are considered material if there is a substantial likelihood that, individually or in the aggregate, they would influence the
judgment made by a reasonable user based on the consolidated financial statements.
In performing an audit in accordance with US GAAS, we:
•
Exercise professional judgment and maintain professional skepticism throughout the audit.
•
Identify and assess the risks of material misstatement of the consolidated financial statements, whether due to fraud or error, and
design and perform audit procedures responsive to those risks. Such procedures include examining, on a test basis, evidence
regarding the amounts and disclosures in the consolidated financial statements.
•
Obtain an understanding of internal control relevant to the audit in order to design audit procedures that are appropriate in the
circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control.
Accordingly, no such opinion is expressed.
•
Evaluate the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by
management, as well as evaluate the overall presentation of the consolidated financial statements.
•
Conclude whether, in our judgment, there are conditions or events, considered in the aggregate, that raise substantial doubt about
the Company’s ability to continue as a going concern for a reasonable period of time.
We are required to communicate with those charged with governance regarding, among other matters, the planned scope and timing of the
audit, significant audit findings, and certain internal control-related matters that we identified during the audit.
/s/ GRANT THORNTON LLP
Tulsa, Oklahoma
March 13, 2025
Table of Contents
35
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
As of December 31,
2024
2023
(In thousands)
ASSETS
Current assets:
Cash and cash equivalents
$
48,884
$
60,779
Accounts receivable, net of allowance for credit losses of $2.9 million and $2.6 million at December 31, 2024
and December 31, 2023, respectively
37,554
45,382
Notes receivable (Notes 5 and 19)
—
8,619
Current derivative asset (Note 16)
534
—
Prepaid expenses and other
3,278
3,516
Total current assets
90,250
118,296
Property and equipment:
Oil and natural gas properties, on the full cost method:
Proved properties
167,347
161,391
Unproved properties not being amortized
10,655
1,173
Drilling equipment
95,292
85,609
Other
9,391
9,558
Property and equipment, gross
282,685
257,731
Less: accumulated depreciation, depletion, amortization, and impairment
130,890
115,826
Property and equipment, net
151,795
141,905
Deferred tax assets, net (Note 12)
32,979
47,085
Right of use asset (Note 18)
3,915
5,262
Other assets
10,304
10,172
Total assets
$
289,243
$
322,720
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable
$
11,718
$
19,448
Accrued liabilities (Note 8)
16,372
16,721
Current operating lease liability (Note 18)
2,436
1,985
Current portion of other long-term liabilities (Note 9)
1,942
4,245
Total current liabilities
32,468
42,399
Operating lease liability (Note 18)
1,589
3,392
Other long-term liabilities (Note 9)
22,665
22,803
Commitments and contingencies (Note 20)
Shareholders' equity:
Preferred stock, $0.01 par value, 1,000,000 shares authorized, none issued
—
—
Common stock, $0.01 par value, 25,000,000 shares authorized; 12,265,268 shares issued and 9,747,725
outstanding at December 31, 2024, and 12,248,992 shares issued and 9,760,142 outstanding at December 31,
2023
123
122
Treasury stock (Note 6)
(82,703)
(79,399)
Capital in excess of par value
267,670
263,555
Retained earnings
47,431
69,848
Total shareholders' equity
232,521
254,126
Total liabilities and shareholders' equity
$
289,243
$
322,720
The accompanying notes are an integral part of the consolidated financial statements.
Table of Contents
36
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
Year Ended December 31,
2024
2023
(In thousands except per share
amounts)
Revenues:
Oil and natural gas
$
93,248 $
146,237
Contract drilling
144,364
181,056
Total revenues
237,612
327,293
Expenses:
Operating costs:
Oil and natural gas
44,420
65,739
Contract drilling
99,655
108,035
Total operating costs
144,075
173,774
Depreciation, depletion, and amortization
15,646
17,724
General and administrative
22,497
22,577
Gain on disposition of assets
(1,667)
(49,950)
Total operating expenses
180,551
164,125
Income from operations
57,061
163,168
Other income (expense):
Interest income
4,104
9,734
Interest expense
(55)
(164)
Gain on derivatives (Note 16)
534
12,975
Gain on sale of Superior investment (Note 19)
—
17,812
Reorganization items, net
(84)
(299)
Other, net
59
203
Total other income
4,558
40,261
Income before income taxes
61,619
203,429
Income tax expense (benefit) (Note 12):
Current
267
1,575
Deferred
14,107
(47,085)
Total income tax expense (benefit)
14,374
(45,510)
Net income
$
47,245 $
248,939
Net income per common share (Note 7)
Basic
$
4.82 $
25.68
Diluted
$
4.75 $
25.32
The accompanying notes are an integral part of the consolidated financial statements.
Table of Contents
37
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)
Total
(In thousands)
Balances, December 31, 2022
$
121 $
(79,399) $
252,464
$
189,440
$
362,626
Net income
—
—
—
248,939
248,939
Dividends declared (Note 6)
—
—
—
(368,531)
(368,531)
Stock-based compensation
—
—
7,547
—
7,547
Vesting of restricted stock units, net of shares
withheld for employee taxes
—
—
(786)
—
(786)
Exercise of stock options, net of shares withheld for
taxes and exercise price
—
—
(400)
—
(400)
Exercise of warrants
1
—
4,730
—
4,731
Balances, December 31, 2023
$
122 $
(79,399) $
263,555
$
69,848
$
254,126
Net income
$
— $
—
$
—
47,245
47,245
Dividends declared (Note 6)
—
—
—
(69,662)
(69,662)
Stock-based compensation
—
—
4,597
—
4,597
Exercise of stock options, net of shares withheld for
taxes and exercise price
1
—
(486)
—
(485)
Exercise of warrants, net of shares withheld for
exercise price
—
—
4
—
4
Repurchases of common stock
—
(3,304)
—
—
(3,304)
Balances, December 31, 2024
$
123 $
(82,703) $
267,670
$
47,431
$
232,521
The accompanying notes are an integral part of the consolidated financial statements.
Table of Contents
38
UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
OPERATING ACTIVITIES:
Net income
$
47,245 $
248,939
Adjustments to reconcile net income operating activities:
Depreciation, depletion, and amortization
15,646
17,724
Gain on derivatives, net (Note 16)
(534)
(12,975)
Loss on derivatives settled (Note 16)
—
(10,591)
Gain on disposition of assets
(1,667)
(49,950)
Gain on sale of Superior investment (Note 15)
—
(17,812)
Deferred tax expense (benefit) (Note 12)
14,107
(47,085)
Stock-based compensation plans (Note 15)
4,597
7,547
ARO liability accretion (Note 10)
800
1,880
Other, net
(2,629)
(3,728)
Changes in operating assets and liabilities increasing (decreasing) cash:
Accounts receivable
7,289
12,066
Prepaid expenses and other
8
876
Accounts payable
(6,552)
(438)
Accrued liabilities
(3,094)
3,709
Net changes in operating assets and liabilities
$
(2,349) $
16,213
Net cash provided by operating activities
$
75,216 $
150,162
INVESTING ACTIVITIES:
Capital expenditures
(26,147)
(24,012)
Proceeds from sale of Superior investment (Note 15)
8,000
12,000
Proceeds from disposition of property and equipment
6,570
69,989
Net cash provided by (used in) investing activities
$
(11,577) $
57,977
FINANCING ACTIVITIES:
Dividend and dividend equivalent payments (Note 6)
(71,749)
(364,881)
Employee taxes paid by withholding shares
(486)
(1,187)
Proceeds from exercise of warrants (Note 6)
5
4,733
Repurchase of common stock (Note 6)
(3,304)
—
Net cash used in financing activities
$
(75,534) $
(361,335)
Net decrease in cash and cash equivalents
(11,895)
(153,196)
Cash and cash equivalents, beginning of period
60,779
213,975
Year Ended December 31,
2024
2023
(In thousands)
Table of Contents
The accompanying notes are an integral part of the consolidated financial statements.
39
Cash and cash equivalents, end of period
$
48,884 $
60,779
Supplemental disclosure of cash flow information:
Cash paid (received) for:
Interest paid (net of capitalized)
$
89 $
161
Income taxes
$
1,701 $
(335)
Reorganization items
$
(84) $
(299)
Changes in accounts payable and accrued liabilities related to purchases of property and
equipment
$
1,096 $
(5,953)
Changes in accrued liabilities related to dividend equivalent rights
$
(2,087) $
3,651
Non-cash reductions to oil and natural gas properties related to asset retirement obligations
$
487 $
787
Non-cash (additions) reductions to oil and natural gas properties related to net changes in asset
retirement obligations, accounts receivable, accounts payable, and accrued liabilities resulting
from divestitures
$
(587) $
13,632
Non-cash trade of property and equipment
$
(135) $
—
Year Ended December 31,
2024
2023
(In thousands)
The accompanying notes are an integral part of the consolidated financial statements.
Table of Contents
40
NOTE 1 – ORGANIZATION AND BUSINESS
Unless the context clearly indicates otherwise, references in this report to “Unit”, “Company”, “we”, “our”, “us”, or like
terms refer to Unit Corporation or, as appropriate, one or more of its subsidiaries. References to "Superior" refer to our 50%
ownership interest in Superior Pipeline Company, L.L.C. which we sold on April 24, 2023 as discussed in Note 19 - Superior
Investment.
We are primarily engaged in the development, acquisition, and production of oil and natural gas properties as well as
onshore contract drilling of natural gas and oil wells. Our operations are all located in the United States and are organized as the
following two reporting segments:
Oil and Natural Gas. Carried out by our subsidiary, Unit Petroleum Company (UPC), we develop, acquire, and produce
oil and natural gas properties for our own account. Our producing oil and natural gas properties, unproved properties, and
related assets are primarily located in Oklahoma and Texas.
Contract Drilling. Carried out by our subsidiary, Unit Drilling Company (UDC), we drill onshore oil and natural gas
wells for other oil and natural gas companies. Our drilling operations are primarily located in Oklahoma, Texas and New
Mexico.
NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation. The consolidated financial statements include the accounts of Unit Corporation and its wholly-
owned subsidiaries.
We evaluated our disclosure of subsequent events through March 13, 2025, the date the consolidated financial statements
were issued.
Accounting Estimates. Preparing financial statements in conformity with U.S. GAAP requires management to make
estimates and assumptions that affect the reported amounts and disclosures in the consolidated financial statements. Actual
results could differ from those estimates. Significant estimates and assumptions include:
•
oil and gas reserves quantities and values;
•
full cost ceiling test and impairment assessments for property and equipment;
•
asset retirement obligations (ARO);
•
fair value of commodity derivative assets and liabilities;
•
fair value of stock-based compensation grants or modifications;
•
workers' compensation liabilities;
•
contingency, litigation, and environmental liabilities; and
•
realizability of deferred tax assets.
Cash and Cash Equivalents. We include as cash and cash equivalents all cash on hand and on deposit, as well as highly
liquid investments with maturities of three months or less which are readily convertible into known amounts of cash. The
financing section of our consolidated statements of cash flows reflects bank overdraft activity. Bank overdrafts are checks
issued before the end of the period, but not presented to our bank for payment before the end of the period. There were no bank
overdrafts as of December 31, 2024 or December 31, 2023.
We had a concentration of cash with one bank of $1.8 million and $3.1 million as of December 31, 2024 and 2023,
respectively. We also had a concentration of cash equivalents of $25.1 million and $23.5 million in two separate money market
funds comprised of U.S. Government and U.S. Treasury securities as of December 31, 2024 compared to cash equivalents of
$32.9 million and $27.6 million in those funds as of December 31, 2023.
Accounts Receivable, Net of Allowance for Credit Losses. Accounts receivable are carried on a gross basis, with no
discounting, less an allowance for expected credit losses. We estimate the allowance for credit losses based on existing
economic conditions, the financial condition of our customers, and the amount and age of past due accounts. Receivables are
considered past due if full payment is not received by the contractual due date. Past due accounts are generally written off
against the allowance for credit losses only after all collection attempts have been unsuccessful.
Table of Contents
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
41
Notes Receivable. We record all future payments of principal and interest (whether stated or imputed) on notes as notes
receivable on the consolidated balance sheets, less the amount of any related unearned interest income and an allowance for
expected credit losses, if any. We estimate the allowance for credit losses based on collection experience and the collectability
of specifically identified borrowers. Notes are considered impaired when, based on current information and events, it is
probable that the Company will be unable to collect the scheduled payments when due. The related interest is recognized over
the term of the note.
Property and Equipment.
Oil and Natural Gas Properties. We account for our oil and natural gas exploration and development activities using the
full cost method of accounting prescribed by the SEC under which we capitalize all productive and non-productive costs
incurred in connection with the acquisition, exploration, and development of our oil, NGLs, and natural gas reserves, including
directly related overhead costs and related asset retirement costs. We did not capitalize any directly related overhead costs for
the years ended December 31, 2024 or 2023.
Capitalized costs are amortized on a units-of-production method based on proved oil and natural gas reserves. The
calculation of DD&A includes all capitalized costs, estimated future expenditures to be incurred in developing proved reserves,
and estimated dismantlement and abandonment costs, net of estimated salvage values less accumulated amortization, unproved
properties, and equipment not placed in service. The average rates used for DD&A were $1.97 and $1.45 per Boe for the years
ended December 31, 2024 and 2023, respectively.
Our contract drilling segment may provide drilling services for our oil and natural gas segment. Revenues and expenses
from these services are eliminated in our consolidated statements of operations, with any recognized profit reducing the cost of
our oil and natural gas properties. There were no intercompany drilling services provided for elimination during the years ended
December 31, 2024 or 2023.
No gains or losses are recognized on the sale, conveyance, or other disposition of oil and natural gas properties unless it
results in a significant alteration to our full cost pool.
Drilling equipment and other property and equipment. Drilling equipment and other property and equipment are carried
at cost less accumulated depreciation. Refurbishments and enhancements are capitalized while repairs and maintenance are
expensed. We depreciate all drilling assets utilizing the straight-line method over the estimated useful lives of the assets,
typically ranging from four to ten years. Depreciation of other property and equipment is computed using the straight-line
method over the estimated useful lives of the assets, typically ranging from 3 to 15 years.
Impairment and disposal. We review the carrying amounts of long-lived assets for potential impairment when events or
changes in circumstances suggest the carrying amounts may not be recoverable. Changes that could prompt an assessment
include equipment obsolescence, declines in the market demand for an asset, declines in commodity prices, periods of relatively
low drilling rig utilization, declining revenue or cash margin per day, or overall unfavorable changes in general market
conditions. Assets are determined to be impaired if the 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 our assumptions and
judgments regarding future industry conditions and their effect on future utilization levels, dayrates, and costs. Using different
estimates and assumptions could result in materially different carrying values of our assets.
When property and equipment components are disposed of, the cost and the related accumulated depreciation are
removed from the accounts and any resulting gain or loss is generally reflected in income from operations. For dispositions of
drill pipe and drill collars, an average cost for the appropriate feet of drill pipe and drill collars is removed from the asset
account and charged to accumulated depreciation. Any proceeds are credited to accumulated depreciation unless proceeds
would exceed remaining cost, in which case excess proceeds are recorded as a gain on disposition of assets.
Capitalized Interest. Interest costs associated with major asset additions are capitalized during the construction period
using a weighted average interest rate based on our outstanding borrowings. We did not capitalize any interest costs during the
years ended December 31, 2024 or 2023.
Table of Contents
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
42
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.
Expenses related to leases determined to be operating leases will be recognized on a straight-line basis over the lease
term including any reasonably certain renewal periods, while those determined to be finance leases will be recognized
following a front-loaded expense profile in which interest and amortization are presented separately in the consolidated
statements of operations. The determination of whether a lease is accounted for as a finance lease or an operating lease requires
management's estimates of the fair value of the underlying asset and its estimated economic useful life, among other
considerations.
ARO. We record the estimated fair value of the liabilities relating to the future retirement of our long-lived assets. Our oil
and natural gas wells are plugged and abandoned when the oil and natural gas reserves in those wells are depleted or the wells
are no longer able to produce. The estimated liabilities related to these future costs are recorded at the time the wells are drilled
or acquired. We use historical experience to determine the estimated plugging costs considering the well's type, depth, physical
location, and ultimate productive life. A risk-adjusted discount rate and an inflation factor are applied to estimate the present
value of these obligations. We depreciate the capitalized asset retirement cost and accrete the obligation over time. Revisions to
the obligations and assets are recognized at the appropriate risk-adjusted discount rate with a corresponding adjustment made to
the full cost pool.
Insurance. We are self-insured for certain losses relating to workers’ compensation, control of well, and employee
medical benefits. Insured policies for other coverage contain deductibles or retentions per occurrence that range from zero to
$1.0 million. We have purchased stop-loss coverage to limit, to the extent feasible, per occurrence and aggregate exposure to
certain types of claims. There is no assurance that the insurance coverages we have will adequately protect us against liability
from all potential consequences. If insurance coverage becomes more expensive, we may choose to self-insure, decrease our
limits, raise our deductibles, or any combination of these rather than pay higher premiums.
Commodity Derivatives. All commodity derivatives are recognized on the consolidated balance sheets as either an asset
or liability measured at fair value and our commodity derivative counterparty is subject to a master netting agreement. We net
the value of the derivative transactions with the same counterparty if a legal right to set-off exists. Changes in the fair value of
our commodity derivatives and gains or losses on commodity derivative settlements are reported in gain on derivatives in our
consolidated statements of operations. Cash settlements received or paid for matured, early-terminated, and/or modified
derivatives are reported in cash payments on derivatives settled in our consolidated statements of cash flows.
Income Taxes. Income taxes are recognized based on earnings reported for tax return purposes in addition to a provision
for deferred income taxes. Deferred income taxes are recognized at the end of each reporting period for the future tax
consequences of cumulative temporary differences between the tax basis of assets and liabilities and their reported amounts in
the Company’s consolidated financial statements based on existing tax laws and enacted statutory tax rates applicable to the
periods in which the temporary differences are expected to affect taxable income. U.S. GAAP requires the recognition of a
deferred tax asset for net operating loss carryforwards and tax credit carryforwards. We periodically assess the realizability of
the deferred tax assets by considering all available evidence (both positive and negative) to determine whether it is more likely
than not that all or a portion of the deferred tax assets will not be realized and a valuation allowance is required.
Natural Gas Balancing. When there are insufficient remaining reserves to offset a gas imbalance, we recognize an asset
or a liability for the under-produced or over-produced position. We have recorded a receivable of $4.6 million and a liability of
$3.1 million as of December 31, 2024 on certain properties where we estimate that insufficient reserves are available for us to
recover our under-production from future production volumes or insufficient reserves available to allow the under-produced
owners to recover their under-production from future production volumes, respectively. 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.
Table of Contents
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
43
Stock-Based Compensation. We recognize the cost of stock-based compensation over the requisite service periods, which
is generally the vesting period, based on the grant date fair value of those awards and account for forfeitures as they occur.
Revisions to the strike price of stock options by the Compensation Committee are accounted for as a modification to the
original award under ASC Topic 718, Compensation - Stock Compensation.
NOTE 3 - IMPAIRMENTS
Oil and Natural Gas Properties and Contract Drilling
There were no impairments recorded during the years ended December 31, 2024 or 2023.
NOTE 4 – REVENUE FROM CONTRACTS WITH CUSTOMERS
Our revenue streams are reported under two segments: oil and natural gas, and contract drilling which is consistent with
how we report our segment revenue in Note 22 – Industry Segment Information. Revenue from the oil and natural gas segment
is from sales of our oil and natural gas production. Revenue from the contract drilling segment comes from contracting with
upstream companies to drill an agreed-on number of wells or provide drilling rigs and services over an agreed-on period.
Oil and Natural Gas Revenue
Typical types of revenue contracts entered into by our oil and gas segment are Oil Sales Contracts, North American
Energy Standards Board (NAESB) Contracts, Gas Gathering and Processing Agreements, and revenues earned as the non-
operated party with the operator serving as an agent on our behalf under joint operating agreements. Consideration received is
variable and settled monthly while contract terms can range from a single month or evergreen to terms of a decade or more.
Revenue from oil and natural gas sales is recognized when the customer obtains control of the 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. This determination would affect our total revenue recognized, but will not affect
gross profit. For example, gathering, processing and transportation costs are deducted from oil and natural gas revenues when
control of the commodity is transferred to the customer, while costs incurred while we are in control of the commodity
represent operating costs.
Contract Drilling Revenue
Contract drilling revenues and expenses are primarily recognized as services are performed and collection is reasonably
assured. Revenue mobilization and demobilization is not tied to specific goods or services delivered under the contract. We
recognize mobilization and demobilization revenue when invoiced. Given their insignificance to our consolidated financial
statements, we do not defer these payments to recognize them over the life of the contract. Instead, we include them in our
revenue figures as they are billed. Costs related to moving rigs and drilling equipment to new locations, before securing a
contract for those areas, are recognized as expenses as incurred. Any reimbursements received for out-of-pocket relocation
expenses are recorded as revenues.
Most of our drilling contracts have a term of one year or less. The remaining performance obligations under contracts
without a fixed term are not material.
Table of Contents
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
44
Contract Assets and Liabilities
The table below presents the changes in our contract asset and contract liability balances during periods indicated:
December 31,
Classification on the
consolidated balance sheets
2024
2023
Change
(In thousands)
Assets
Current contract assets
Prepaid expenses and other
$
— $
—
$
—
Non-current contract assets
Other assets
—
—
—
Total contract assets
$
— $
—
$
—
Liabilities
Current contract liabilities
Current portion of other long-term liabilities
$
— $
16
$
(16)
Non-current contract liabilities
Other long-term liabilities
—
160
(160)
Total contract liabilities
—
176
(176)
Contract assets (liabilities), net
$
— $
(176) $
176
NOTE 5 – ACQUISITIONS AND DIVESTITURES
Oil and Natural Gas
During December 2024, the Company acquired approximately 1,000 acres of oil and gas leases for $3.0 million, of which
$0.8 million consideration was paid at closing while $2.2 million was accrued for as of December 31, 2024. In separate
transactions, during 2024 the Company also acquired approximately 1,600 acres of oil and gas leases for approximately $4.1
million and made prepayments of $2.5 million on two gross wells. All properties are located in Oklahoma. These amounts are
presented in unproved properties not being amortized on the consolidated balance sheets as of December 31, 2024.
On December 13, 2023, the Company closed on the sale of certain non-core wells and related leases in the Texas
Panhandle for cash proceeds of $50.7 million, after customary post-closing adjustments based on an effective date of October 1,
2023. The sale represented a significant alteration to the full cost pool as reserves in excess of 25% were divested. To determine
the gain, the Company allocated the net book value of the full cost pool based on the relative fair value of the properties
retained versus those divested. A gain of $37.2 million was recognized within gain on disposition of assets in the consolidated
statements of operations.
Net proceeds for the sale of other non-core oil and natural gas assets totaled $2.9 million and $3.3 million during the years
ended December 31, 2024 and 2023, respectively. These proceeds reduced the net book value of our full cost pool with no gain
or loss recognized as the sales did not result in a significant alteration of the full cost pool.
Contract Drilling
On May 18, 2023, the Company closed on the sale of two older generation SCR rigs and certain related equipment for
total proceeds of $5.8 million. Cash proceeds of $5.0 million were received at closing and deferred cash proceeds of $0.8
million were received on January 25, 2024. The deferred proceeds were included in notes receivable on the consolidated
balance sheets as of December 31, 2023. The total proceeds from the sale resulted in net gains of $4.4 million, which are
presented within gain on disposition of assets in the consolidated statements of operations for the year ended December 31,
2023.
Proceeds for the sale of other non-core contract drilling assets totaled $2.9 million and $13.6 million during the years
ended December 31, 2024 and 2023, respectively. These proceeds resulted in net gains of $1.8 million and $9.5 million during
the years ended December 31, 2024 and 2023, respectively. The net gains are presented within gain on disposition of assets in
the consolidated statements of operations.
Table of Contents
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
45
NOTE 6 – SHAREHOLDERS' EQUITY AND DIVIDENDS
Common Stock
On September 3, 2020 (Emergence Date), the Company emerged from Chapter 11 bankruptcy and issued a total of
12.0 million shares of New Common Stock to be subsequently distributed in accordance with the Plan. On February 21, 2023, a
final decree was approved to close the remaining Chapter 11 case and grant related relief. As a result, any shares of common
stock not yet claimed were deemed unclaimed property and have been treated as reductions to the number of shares of common
stock issued and outstanding as of February 21, 2023.
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 Company's 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.
Common Stock Repurchases
During the year ended December 31, 2024, the Company repurchased 97,354 shares under the repurchase program at an
average share price of $33.94 (unadjusted for dividends paid) for an aggregate purchase price of $3.3 million.
As of December 31, 2024, we had repurchased a total of 2,569,746 shares of common stock since emergence from
bankruptcy at an average share price of $32.16 (unadjusted for dividends paid) for an aggregate purchase cost of $82.7 million.
These repurchases were made through private and open market transactions made under the repurchase program authorized by
the Board of Directors in June 2021 (as amended), as well as other privately negotiated transactions. The purchase cost and any
direct acquisition costs are reflected as treasury stock on the consolidated balance sheets.
As of December 31, 2024, the remaining value of shares that may be purchased under the repurchase program
authorization was $27.8 million.
Dividends
The table below presents information about the dividends paid during the periods indicated:
Type
Dividend
per share
Total
Amount
Record Date
Payment Date
2023
(In thousands)
First quarter
Special
$
10.00 $
96,179
January 20, 2023
January 31, 2023
Second quarter
Quarterly
$
2.50 $
24,071
June 16, 2023
June 26, 2023
Third quarter
Quarterly
$
2.50 $
24,113 September 15, 2023 September 26, 2023
Fourth quarter
Quarterly
$
2.50 $
24,226 December 18, 2023
December 27, 2023
Fourth quarter
Special
$
15.00 $
145,353 December 18, 2023
December 27, 2023
Fourth quarter
Special
$
5.00 $
48,451 December 18, 2023
December 27, 2023
2024
First quarter
Quarterly
$
1.25 $
12,269
March 18, 2024
March 28, 2024
Second quarter
Quarterly
$
1.25 $
12,961
June 17, 2024
June 27, 2024
Third quarter
Quarterly
$
1.25 $
12,248 September 16, 2024 September 27, 2024
Fourth quarter
Quarterly
$
1.25 $
12,185 December 17, 2024
December 27, 2024
Fourth quarter
Special
$
2.00 $
19,495 December 17, 2024
December 27, 2024
The Company announced on March 7, 2025 that a quarterly cash dividend of $1.25 per share had been declared for the
first quarter of 2025, to be paid on March 28, 2025 to shareholders of record as of the close of business on March 18, 2025.
Table of Contents
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
46
The declaration and payment of any future dividend, whether fixed, special, or variable, will remain at the full discretion
of the Company’s Board of Directors and will depend upon the Company’s financial position, results of operations, cash flows,
capital requirements, business conditions, future expectations, the requirements of applicable law, and other factors that the
Company’s Board of Directors finds relevant at the time of considering any potential dividend declaration.
We have accrued liabilities for dividend equivalent payments to be made upon the vesting of restricted stock units
outstanding as of the dividend record date, but not yet vested. These amounts total $1.6 million and $3.7 million as of
December 31, 2024 and 2023, respectively, and are reported in current and other long-term liabilities on the consolidated
balance sheets.
Warrants
Each holder of Unit common stock outstanding (Old Common Stock) before the Emergence Date that did not opt out of
the release under the Plan was entitled to receive 0.03460447 warrants for every share of Old Common Stock owned. Each
warrant is exercisable for one share of common stock, subject to adjustment as provided in the Warrant Agreement. The
warrants expire on the earliest of (i) September 3, 2027, (ii) consummation of a Cash Sale (as defined in the Warrant
Agreement), or (iii) the consummation of a liquidation, dissolution or winding up of the Company.
As of December 31, 2024, the Company had authorized 1,843,318 warrants of which 100,668 had been exercised or
canceled.
Among other provisions, the Warrant Agreement outlines potential adjustments to the warrants if certain events occur,
including (i) stock dividends payable in shares of common stock or stock splits, (ii) reverse stock splits or similar combination
events, (iii) Liquidity Events (as defined in the Warrant Agreement), and (iv) other events not explicitly contemplated which
may have an adverse impact to the intent and purpose of the warrants as set forth in the Plan, provided, however, the warrants
will not be adjusted for (a) any issuances of securities in connection with a merger, share exchange, asset acquisition, stock
purchase, recapitalization, reorganization or other similar business combination, (b) the issuance of any securities by Unit on or
after September 3, 2020 (the "Emergence Date") pursuant to the Plan or upon the issuance of shares of common stock upon the
exercise of such securities, (c) the issuance of any shares of common stock pursuant to the exercise of the warrants, (d) the
issuance of shares of common stock pursuant to any management stock option incentive or similar plan, (e) a dividend or
distribution to holders of common stock of cash, property, or securities (other than common stock), and/or (f) any change in the
par value of the common stock.
Pursuant to the terms of the Warrant Agreement, the Company determined the initial exercise price of the warrants to be
$63.74. On April 7, 2022, the Company delivered notice of the initial exercise price to the Warrant Agent and the warrants
became exercisable for shares of the Company’s common stock. On or about April 25, 2022, the warrants began trading over-
the-counter under the symbol "UNTCW". On March 31, 2023, the warrants began trading on the OTCQX Best Market.
See Note 20 - Commitments And Contingencies for disclosure on litigation related to the warrants.
NOTE 7 – EARNINGS PER SHARE
The table below shows the calculation of earnings per share attributable to Unit Corporation using the treasury stock
method for the periods indicated:
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UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
47
Earnings (Loss)
(Numerator)
Weighted
Shares
(Denominator)
Per-Share
Amount
(In thousands except per share amounts)
Year ended December 31, 2024
Basic earnings attributable to Unit Corporation per common share
$
47,245
9,812
$
4.82
Effect of dilutive restricted stock units and stock options (1)
—
143
(0.07)
Diluted earnings attributable to Unit Corporation per common share
$
47,245
9,955
$
4.75
Year ended December 31, 2023
Basic earnings attributable to Unit Corporation per common share
$
248,939
9,695
$
25.68
Effect of dilutive stock options(2)
—
136
(0.36)
Diluted loss attributable to Unit Corporation per common share
$
248,939
9,831
$
25.32
1.
The diluted earnings per share calculation for the year ended December 31, 2024 excludes the effects related to 1,721,579 average warrants with a $63.74
exercise price and 2,979 average outstanding restricted stock units because their inclusion would be antidilutive.
2.
The diluted earnings per share calculation for the year ended December 31, 2023 excludes the effects related to 1,798,417 average warrants with a $63.74
exercise price because their inclusion would be antidilutive.
NOTE 8 – ACCRUED LIABILITIES
The table below presents the components of accrued liabilities:
As of December 31,
2024
2023
(In thousands)
Employee costs
$
9,004
$
10,088
Lease operating expenses
2,515
2,453
Capital expenditures
3,263
653
Taxes
501
2,152
Interest payable
8
43
Other
1,081
1,332
Total accrued liabilities
$
16,372
$
16,721
Accrued capital expenditures as of December 31, 2024 include the accrual of $2.2 million for acreage in Oklahoma
acquired in December 2024. See Note 5 - Acquisitions And Divestitures for additional information.
NOTE 9 – LONG-TERM DEBT AND OTHER LONG-TERM LIABILITIES
Long-Term Debt
The table below presents the individual components of long-term debt:
As of December 31,
2024
2023
(In thousands)
Long-term debt:
Second credit agreement
—
—
Second Amended and Restated Credit Agreement. On March 8, 2024, the Company entered into the Second Amended and
Restated Credit Agreement (the Second credit agreement), dated as of March 8, 2024 and effective as of March 1, 2024. This
agreement replaces the Exit credit agreement, which was set to mature on March 1, 2024. The Second credit agreement
provides a $10.0 million initial borrowing base, subject to semi-annual redetermination, with BOKF, NA dba Bank of
Oklahoma (BOKF). The Second credit agreement matures on March 8, 2027 and is collateralized by the Company's BOSS rigs
and upstream properties.
Table of Contents
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
48
The Second credit agreement requires the Company to comply with certain financial ratios, including: the Net Leverage
Ratio (as defined in the Second credit agreement) as of the last day of any fiscal quarter can not be greater than 3.00 to 1.00 and
the Current Ratio to be less than 1.00 to 1.00. The Second credit agreement also contains provisions, among others, that require
the Company to provide quarterly financial statements within 45 days after the end of each of the first three quarters of each
fiscal year and annual audited financial statements within 90 days after the end of each fiscal year. As of December 31, 2024,
the Company was in compliance with these covenants.
As of December 31, 2024, we had no long-term borrowings and $1.3 million of letters of credit outstanding under the
Second credit agreement.
Exit Credit Agreement. On the Emergence Date, the Company entered into an amended and restated credit agreement (the
Exit credit agreement), providing for a $140.0 million senior secured revolving credit facility (RBL Facility) and a
$40.0 million senior secured term loan facility, among (i) the Company, UDC, and UPC (together, the Borrowers), (ii) the
guarantors party thereto, including the Company and all of its subsidiaries existing as of the Emergence Date (other than
Superior and its subsidiaries), (iii) the lenders party thereto from time to time (Emergence 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 was March 1, 2024. The Exit credit agreement was secured by first-priority liens
on substantially all of the personal and real property assets of the Borrowers and the Guarantors, including the Company’s
ownership interests in Superior.
Since the Emergence Date, the Company and the Lenders had various amendments that reduced the borrowing base of the
Exit credit agreement. As of December 31, 2023, the Exit credit agreement had a borrowing base of $35.0 million.
The Exit credit agreement required the Company to comply with certain financial ratios, including: the Net Leverage
Ratio (as defined in the Exit credit agreement) as of the last day of any fiscal quarter could not be greater than 3.25 to 1.00, the
Current Ratio (as defined in the Exit credit agreement) as of the last day of any fiscal quarter could not be less than 1.00 to 1.00,
and the Interest Coverage Ratio (as defined in the Exit credit agreement) as of the last day of any fiscal quarter could not be less
than 2.50 to 1.00. The Exit credit agreement also contained provisions, among others, that limited certain capital expenditures,
and required certain hedging activities. The Exit credit agreement further required the Company to provide quarterly financial
statements within 45 days after the end of each of the first three quarters of each fiscal year and annual financial statements
within 90 days after the end of each fiscal year. As of December 31, 2023, the Company was in compliance with these
covenants.
Other Long-Term Liabilities
The table below presents the components of other long-term liabilities:
As of December 31,
2024
2023
(In thousands)
Asset retirement obligation (ARO) liability
$
11,214
$
10,901
Workers’ compensation
7,685
8,296
Contract liabilities
—
176
Separation benefit plans
1,063
1,009
Gas balancing liability
3,081
3,015
Dividend equivalents liability
1,564
3,651
24,607
27,048
Less: current portion
1,942
4,245
Total other long-term liabilities
$
22,665
$
22,803
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UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
49
NOTE 10 – ASSET RETIREMENT OBLIGATIONS
We are required to record the estimated fair value of the liabilities associated with the future retirement of our long-lived
assets. Our asset retirement obligations (AROs) primarily relate to the plugging and abandonment of our oil and natural gas
wells once the reserves are depleted or the wells can no longer produce.
The fair value of the plugging and abandonment liability is recognized when a well is drilled or acquired and the
obligation is incurred. This estimation is based on current costs, applicable regulations, and our historical experience, and it
incorporates assumptions about future inflation and discount rates.
None of our assets are restricted for the purpose of settling these AROs. All of our AROs relate to the plugging costs
associated with our oil and gas wells. We continually review and adjust these estimates as necessary to reflect changes in
regulations, technology, and market conditions.
The following table presents activity for our estimated AROs:
Year Ended December 31,
2024
2023
(In thousands)
ARO liability, beginning of period
$
10,901
$
23,440
Accretion of discount
800
1,880
Liability incurred
1
54
Liability settled
(201)
(1,608)
Liability sold
(127)
(13,632)
Revision of estimates (1)
(160)
767
ARO liability, end of period
11,214
10,901
Less: current portion
683
607
Long-term ARO liability
$
10,531
$
10,294
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 11 – WORKERS' COMPENSATION
We are liable for workers' compensation benefits for traumatic injuries through our self-insured program to provide
income replacement and medical treatment for work-related traumatic injury claims as required by applicable state laws.
Workers' compensation laws also compensate survivors of workers who suffer employment related deaths. Our liability for
traumatic injury claims is the estimated present value of current workers' compensation benefits, based on our actuarial
estimates. Our actuarial calculations are based on a blend of actuarial projection methods and numerous assumptions including
claim development patterns, mortality, medical costs and interest rates.
The following table presents activity for our workers' compensation liability during the periods indicated:
Year Ended December 31,
2024
2023
(In thousands)
Workers' compensation liability, beginning of period
$
8,296
$
8,345
Claims and valuation adjustments
(296)
524
Payments
(315)
(573)
Workers' compensation liability, end of period
7,685
8,296
Less: current portion
766
1,014
Long-term workers' compensation liability
$
6,919
$
7,282
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, 2024 and 2023 are
$5.0 million and $5.1 million, respectively, and are included in other assets on our consolidated balance sheets.
Table of Contents
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
50
NOTE 12 – INCOME TAXES
The following table presents a reconciliation between income tax expense computed by applying the federal statutory rate
to income before income taxes and our effective income tax expense during the periods indicated:
Year Ended December 31,
2024
2023
(In thousands)
Income tax expense at statutory rate
$
12,940 $
42,720
State income tax expense, net of federal benefit
1,807
6,661
Stock-based compensation windfall
77
(370)
Change in valuation allowance
(380)
(115,115)
Revaluation of deferred tax assets and liabilities due to state income tax rate change
—
5,699
Sale of Superior investment (Note 19)
—
14,416
Other permanent items
(70)
479
Income tax expense (benefit)
$
14,374 $
(45,510)
The Company reviews available positive and negative evidence to assess the need for a valuation allowance against the
Company's deferred tax assets. The Company determined that it is more likely than not that a portion of the net deferred tax
assets related to NOL carryforwards would be realized. Accordingly, the Company released a portion of its valuation allowance
contributing to a $94.7 million net change in the valuation allowance in the first quarter of 2023. A total net change of $115.1
million in the valuation allowance with a corresponding income tax benefit was recorded in our consolidated statements of
operations as of December 31, 2023 as the deferred tax assets on our allowance for losses and nondeductible accruals and non-
producing oil and gas properties continued to decrease throughout the year. The company also recognized a change in the
valuation allowance during the year ended December 31, 2024 attributable to changes in the deferred tax assets of certain non-
producing oil and gas properties and allowances for losses and nondeductible accruals.
Realizability of NOL carryforwards is dependent upon the Company's ability to produce future taxable income. Predicting
future earnings is uncertain as commodity prices are volatile. As the Company continues to assess the realizability of NOL
carryforwards going forward, changes in estimates of future taxable income could result in the need for a valuation allowance to
be applied in future periods.
The following table presents the Company's total provision for income taxes during the periods indicated:
Year Ended December 31,
2024
2023
(In thousands)
Current taxes:
Federal
$
— $
—
State
267
1,575
267
1,575
Deferred taxes:
Federal
12,606
(42,261)
State
1,501
(4,824)
14,107
(47,085)
Total provision for income taxes
$
14,374 $
(45,510)
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UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
51
The following table presents the components of net deferred tax assets and liabilities:
December 31,
2024
December 31,
2023
(In thousands)
Deferred tax assets:
Allowance for losses and nondeductible accruals
$
7,171 $
6,967
Net operating loss carryforward (1)
49,281
57,290
Non-producing oil and natural gas properties
18,699
19,283
Producing oil and natural gas properties
—
76
Alternative minimum tax and research and development tax credit carryforward
1,738
1,738
Gross deferred tax assets
76,889
85,354
Valuation allowance (2)
(25,870)
(26,250)
Total deferred tax assets
51,019
59,104
Deferred tax liabilities:
Contract drilling and other equipment
(12,930)
(12,019)
Producing oil and natural gas properties
(5,110)
—
Total deferred tax liabilities
(18,040)
(12,019)
Deferred tax assets, net
$
32,979 $
47,085
1. As of December 31, 2024, the Company had an expected federal net operating loss carryforward of $209.7 million of which $8.7 million is subject to
expiration in 2037.
2. The Company has retained a partial valuation allowance on its deferred tax assets as of December 31, 2024 primarily due to uncertainty in forecasting the
timing of future tax benefit recognition related to certain non-producing oil and gas properties and allowance for losses and nondeductible accruals.
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 2021 or state income tax examinations by state taxing authorities for years before 2020. As of
December 31, 2024, our tax basis in UPC's properties was approximately $145.2 million.
NOTE 13 – EMPLOYEE BENEFIT PLANS
Separation Benefit Plan. The Company provides benefits to employees who are involuntarily separated through the
Second Amended and Restated Separation Plan (Separation Plan). Benefits from the Separation Plan received by employees are
based on salary, years of service, and level within the organization. Payments may be paid in a lump sum or installments
ranging from two to 13 weeks. Under the Separation Plan, an employee vests in a 13 week severance benefit after 20 years of
service provided to the Company. This amount is payable upon voluntary separation. As of December 31, 2024 and 2023, the
Company had $1.1 million and $1.0 million payable for separation benefits, respectively. These amounts are included on the
consolidated balance sheets in other long-term liabilities.
We recognized expense for benefits associated with anticipated payments from these separation plans of $0.7 million and
$0.9 million during the years ended December 31, 2024 and 2023, respectively.
401(k) Employee Thrift Plan. Employees who meet specified service requirements may contribute a percentage of their
total compensation, up to a specified maximum, to the 401(k) Employee Thrift Plan. We may match each employee’s
contribution, up to a specified maximum, in full or on a partial basis with cash. The 2023 and 2024 plan year matching
contributions were made in cash. Total 401(k) employer matching expense was $1.2 million and $1.6 million during the years
ended December 31, 2024 and 2023, respectively.
NOTE 14 – TRANSACTIONS WITH RELATED PARTIES
One current director, Robert Anderson, also serves as an executive with GBK Corporation, a holding company with
numerous energy and industry subsidiaries and affiliates, including Kaiser Francis Oil Company. The Company in the ordinary
course of business, made payments for working interests, joint interest billings, drilling services, and product purchases to, and
received payments for working interests, joint interest billings, and contract drilling services from, Kaiser Francis Oil Company.
The table below presents the payment activity with these related parties during the periods indicated:
Table of Contents
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
52
Year Ended December 31,
2024
2023
(In thousands)
Payments made to:
Kaiser Francis Oil Company
$
942 $
2,205
Payments received from:
Kaiser Francis Oil Company
$
4,297 $
6,155
NOTE 15 – STOCK-BASED COMPENSATION
Unit Corporation Long Term Incentive Plan. On the Emergence 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 is administered by the Compensation Committee and provides for the grant, from time to time, at the discretion of the
Board or a committee thereof, of stock options, stock appreciation rights, restricted stock, restricted stock units, stock awards,
dividend equivalents, other stock-based awards, cash awards, performance awards, substitute awards or any combination of the
foregoing. Subject to adjustment in the event of certain transactions or changes of capitalization in accordance with the LTIP,
903,226 shares of New Common Stock were 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.
On July 1, 2024, 33,296 restricted stock units (RSUs) and 29,730 performance restricted stock units (PRSUs) were issued
to members of the Board and certain members of management pursuant to the LTIP. Vesting for the awards ranges between one
and three years and the underlying compensation will be recorded ratably over the vesting period.
The following table presents the stock-based compensation expense activity recognized during the periods indicated:
Year Ended December 31,
2024
2023
(In thousands)
Recognized stock compensation expense
$
4,597 $
7,547
Tax benefit on stock-based compensation
$
1,080 $
1,773
The tables below presents the activity pertaining to nonvested RSUs during the periods indicated:
Year Ended December 31,
2024
2023
Number
of Shares
Weighted
Average Grant
Date
Fair Value
Number
of Shares
Weighted
Average Grant
Date
Fair Value
Nonvested RSUs, beginning of period
91,635 $
31.24
170,313 $
27.15
Granted
33,296
36.49
23,700
47.88
Vested
(71,672)
27.31
(87,319)
27.29
Forfeited
(6,215)
39.85
(15,059)
34.00
Nonvested RSUs, end of period (1)
47,044 $
44.79
91,635 $
31.24
1.
The aggregate compensation cost related to nonvested RSUs not yet recognized as of December 31, 2024 was $1.4 million with a weighted average
remaining service period of 0.9 years.
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UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
53
The tables below summarizes activity pertaining to outstanding stock options during the periods indicated:
Year Ended December 31,
2024
2023
Number
of Shares
Weighted
Average
Exercise Price (2)
Number
of Shares
Weighted
Average
Exercise Price
Outstanding stock options, beginning of period
215,298 $
7.50
319,166 $
45.00
Granted
—
—
—
—
Exercised
(55,608)
7.22
(74,495)
34.80
Forfeited or expired
(6,291)
7.50
(29,373)
35.00
Outstanding stock options, end of period (1)
153,399 $
0.50
215,298 $
7.50
Exercisable stock options, end of period (1)
153,399 $
0.50
140,492 $
7.50
1.
Stock options outstanding and exercisable as of December 31, 2024 had a weighted average remaining contractual term of 1.81 years and an aggregate
intrinsic value of $4.6 million.
2.
In accordance with the provisions allowed under the LTIP, the Compensation Committee adjusted the exercise price of all outstanding stock options to
$0.50 per share effective December 27, 2024 to account for the quarterly dividends paid during 2024.
The table below summarizes activity pertaining to PRSUs during the periods indicated:
Year Ended December 31,
2024
2023
Number
of Shares
Weighted
Average Grant
Date
Fair Value
Number
of Shares
Weighted
Average Grant
Date
Fair Value
Nonvested PRSUs, beginning of period
— $
—
— $
—
Granted
29,730
25.24
—
—
Vested
—
—
—
—
Forfeited
—
—
—
—
Nonvested PRSUs, end of period (1)
29,730 $
25.24
— $
—
1.
The aggregate compensation cost related to nonvested PRSUs not yet recognized as of December 31, 2024 was $0.6 million with a weighted average
remaining service period of 2 years.
Vesting of the PRSUs occurs on December 31, 2026 only if the Company's total shareholder return (TSR) achieves certain
performance criteria set forth in the agreement.
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UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
54
NOTE 16 – DERIVATIVES
Commodity Derivatives
We have entered into various types of derivative transactions covering some of our projected natural gas, NGLs, and oil
production. These transactions are intended to reduce our exposure to market price volatility by setting the price(s) we will
receive for that production. Our decisions on the price(s), type, and quantity of our production subject to a derivative contract
are based, in part, on our view of current and future market conditions as well as certain requirements stipulated in the Second
credit agreement. For the years ended December 31, 2024 and 2023, 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.
We do not engage in derivative transactions for speculative purposes. We are not required to post any cash collateral with
our counterparties and no collateral has been posted as of December 31, 2024.
The following non-designated hedges were outstanding as of December 31, 2024:
Remaining Term
Commodity
Contracted Volume
Weighted Average
Fixed Price for Swaps
Contracted Market
Jan'25 - Dec'25
Natural gas - basis swap
Floating to fixed
10,000 MMBtu/day
$(0.30)
IF - PEPL - TX-OK
Jan'25 - Dec'25
Natural gas - basis swap
Floating to fixed
7,500 MMBtu/day
$(0.25)
IF - PEPL - TX-OK
Jan'25 - Dec'25
Natural gas - basis swap
Floating to fixed
5,000 MMBtu/day
$(0.25)
IF - PEPL - TX-OK
In March 2025, we entered into NYMEX (HH) natural gas - swap agreements averaging 15,000 MMBtu/day for April
2025 through December 2025 at a weighted average fixed price of $4.69 per MMBtu. In addition, we entered into NYMEX
(HH) natural gas - swap agreements averaging 5,000 MMBtu/day for January 2026 through December 2026 at a weighted
average fixed price of $4.22 per MMBtu.
The following table presents the recognized derivative assets on our consolidated balance sheets as of the date
identified:
Balances as of December 31, 2024
Balance Sheet Classification
Presented
Gross
Effects of
Netting
Presented
Net
(In thousands)
Assets:
Current commodity derivatives
Current derivative assets
$
1,691
$
(1,157) $
534
Long-term commodity derivatives
Non-current derivative assets
—
—
—
Total derivative assets
$
1,691
$
(1,157) $
534
Liabilities:
Current commodity derivatives
Current derivative liabilities
$
1,157
$
(1,157) $
—
Long-term commodity derivatives
Non-current derivative liabilities
—
—
—
Total derivative liabilities
$
1,157
$
(1,157) $
—
Table of Contents
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
55
There were no commodity derivatives outstanding as of December 31, 2023.
The following table presents the activity related to derivative instruments in the consolidated statements of operations
during the periods indicated:
Year Ended December 31,
2024
2023
(In thousands)
Gain on derivatives
$
534
$
12,975
Cash settlements paid on commodity derivatives
—
(10,591)
Gain on derivatives less cash settlements paid on commodity derivatives
$
534
$
23,566
NOTE 17 – FAIR VALUE MEASUREMENTS
We have determined the estimated fair values by using market information and certain valuation methodologies.
Considerable judgment is required in interpreting market data to develop the estimates of fair value. Using different market
assumptions or valuation methodologies may have a material effect on our estimated fair value amounts.
The inputs available determine the valuation technique that we use to measure the fair value of assets and liabilities
presented in our consolidated financial statements. Fair value measurements are categorized into one of three different levels
depending on the observability of the inputs used in the measurement. The levels are summarized as follows:
•
Level 1—observable inputs such as quoted prices in active markets for identical assets and liabilities.
•
Level 2—other observable pricing inputs, such as quoted prices in inactive markets, or other inputs that are either
directly or indirectly observable as of the reporting date, including inputs that are derived from or corroborated by
observable market data.
•
Level 3—generally unobservable inputs which are developed based on the best information available and may
include our own internal data or estimates about how market participants would value such assets and liabilities.
Recurring Fair Value Measurements
The following table presents our recurring fair value measurements as of the identified date:
Balances as of December 31, 2024
Level 1
Level 2
Level 3
Total
(In thousands)
Financial assets:
Commodity derivative assets
$
—
$
534
$
—
$
534
There were no recurring fair value assets or liabilities presented at fair value in our consolidated balance sheets as of
December 31, 2023.
The following methods and assumptions were used to estimate the fair values of the assets and liabilities in the table
above. There were no transfers between Level 2 and Level 3 financial liabilities.
Commodity Derivatives. We measure the fair values of our crude oil and natural gas swaps using estimated discounted
cash flow calculations based on the NYMEX futures index. We consider these Level 2 measurements within the fair value
hierarchy as the inputs in the model are substantially observable over the term of the commodity derivative contract and there is
a wide availability of quoted market prices for similar commodity derivative contracts.
We determined that the non-performance risk regarding our commodity derivative counterparties was immaterial based
on our valuation at December 31, 2024.
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UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
56
There were no commodity derivatives outstanding as of December 31, 2023.
There were no Level 3 fair value measurements during the years ended December 31, 2024 or 2023.
Fair Value of Other Financial Instruments
We have determined the estimated fair values of other financial instruments by using available market information and
valuation methodologies. Considerable judgment is required in interpreting market data to develop the estimates of fair value.
The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value
amounts.
The carrying values on the consolidated balance sheets for cash and cash equivalents, accounts receivable, accounts
payable, other current assets, and current liabilities approximate their fair values because of their short-term nature.
Fair Value of Non-Financial Instruments
ARO. The initial measurement of ARO at fair value is calculated using discounted cash flow techniques and based on
internal estimates of future retirement costs associated with property and equipment. Significant Level 3 inputs used in the
calculation of AROs include plugging costs and remaining reserve lives. A summary of the Company’s ARO activity is
presented in Note 10 – Asset Retirement Obligations.
Stock-Based Compensation. We use the Black-Scholes option pricing model to estimate the fair value of stock option
grants and modifications while the value of our restricted stock unit 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.
We used a Monte Carlo simulation to estimate the fair value of the PRSU grants during the year ended December 31,
2024. Key assumptions within the model include volatility, risk-free rate, and a simulation of stock prices during the
performance period. We consider these inputs to be a Level 3 measurement within the fair value hierarchy as estimated
volatility and simulated stock prices are unobservable and require management’s estimation.
Impairments. Non-recurring fair value measurements are also applied, when applicable, to determine the fair value of our
long-lived assets and goodwill. We recorded non-cash impairment charges as discussed further in Note 3 – Impairments. The
fair value measurement of these assets is categorized as a Level 3 measurement as the discounted cash flow models require the
use of significant unobservable inputs.
Table of Contents
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
57
NOTE 18 – LEASES
Operating Leases. We are a lessee through noncancellable lease agreements for property and equipment consisting
primarily of office space, land, vehicles, and equipment used in both our operations and administrative functions.
The following table presents the maturities, weighted average remaining lease term, and the weighted average discount
rate of our operating lease liabilities as of December 31, 2024:
Amount
(In thousands)
Ending December 31,
2025
$
2,638
2026
1,631
2027
—
2028
—
2029
—
2030 and beyond
—
Total future payments
4,269
Less: Interest
244
Present value of future minimum operating lease payments
4,025
Less: Current portion
2,436
Total long-term operating lease payments
$
1,589
Weighted average remaining lease term (years)
1.7
Weighted average discount rate (1)
7.02 %
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.
The following table presents the operating and finance lease assets and liabilities on our consolidated balance sheets:
Balance Sheet Classification
December 31,
2024
December 31,
2023
(In thousands)
Assets
Operating lease right of use assets
Right of use assets
$
3,915 $
5,262
Total lease right of use assets
$
3,915 $
5,262
Liabilities
Current liabilities:
Operating lease liabilities
Current operating lease liabilities
$
2,436 $
1,985
Non-current liabilities:
Operating lease liabilities
Operating lease liabilities
1,589
3,392
Total lease liabilities
$
4,025 $
5,377
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UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
58
The following table presents the components of total lease cost for our operating and finance leases during the periods
indicated:
Year Ended December 31,
2024
2023
(In thousands)
Components of total lease cost:
Short-term lease cost (1)
$
4,979 $
7,337
Operating lease cost
2,722
3,932
Total lease cost
$
7,701 $
11,269
1.
Short-term lease cost includes amounts capitalized related to our oil and natural gas segment of $0.4 million and $1.1 million for the years ended
December 31, 2024 and 2023, respectively.
The following table presents supplemental cash flow information related to our operating and finance leases during the
periods indicated:
Year Ended December 31,
2024
2023 (1)
(In thousands)
Cash payments made on operating leases
$
2,727 $
3,905
Lease liabilities recognized in exchange for new operating lease right of use assets
$
1,398 $
3,712
Termination of lease liabilities and operating lease right of use assets
$
(399) $
(1,631)
1.
Leases terminated as a results of the Texas Panhandle divestiture. See Note 5 - Acquisitions And Divestitures.
Table of Contents
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
59
NOTE 19 – SUPERIOR INVESTMENT
Sale Event. On April 24, 2023 (the "Superior Sale Date"), we entered into and closed a purchase and sale agreement with
SP Investor under which the Company sold its 50% ownership interest in Superior for $20.0 million. Unit received proceeds of
$12.0 million at closing and the remaining proceeds of $8.0 million were received on April 23, 2024. We recognized a $17.8
million gain on sale of Superior investment in the consolidated statements of operations for the year ended December 31, 2023.
Prior to the sale in 2023, we accounted for our investment in Superior as an equity method investment using the
hypothetical liquidation book value (HLBV) method. We recognized no equity earnings from our investment in Superior during
the year ended December 31, 2023.
Affiliate Activity. The table below presents the affiliate activity between UPC and Superior incurred prior to the Superior
Sale Date for the year ended December 31, 2023.
Oil and natural gas revenues
$
12,765
Oil and natural gas operating costs
$
683
NOTE 20 – COMMITMENTS AND CONTINGENCIES
Environmental
We manage our exposure to environmental liabilities on properties to be acquired by identifying existing problems and
assessing the potential liability. We also conduct periodic reviews, on a company-wide basis, to identify changes in our
environmental risk profile. These reviews evaluate whether there is a probable liability, its amount, and the likelihood that the
liability will be incurred. Any potential liability is determined by considering, among other matters, incremental direct costs of
any likely remediation and the proportionate cost of employees expected to devote significant time directly to any possible
remediation effort. As it relates to evaluations of purchased properties, depending on the extent of an identified environmental
problem, we may exclude a property from the acquisition, require the seller to remediate the property to our satisfaction, or
agree to assume liability for the remediation of the property.
We have not historically experienced significant environmental liability while being a contract driller since the greatest
portion of that risk is borne by the operator. Any liabilities we have incurred have been small and were resolved while the
drilling rig was on the location. Those costs were in the direct cost of drilling the well.
Litigation
The Company is subject to litigation and claims arising in the ordinary course of business which may include
environmental, health and safety matters, commercial disputes with customers, or more routine employment related claims. The
Company accrues for such items when a liability is both probable and the amount can be reasonably estimated. As new
information becomes available or because of legal or administrative rulings in similar matters or a change in applicable law, the
Company's conclusions regarding the probability of outcomes and the amount of estimated loss, if any, may change. Although
we are insured against various risks, there is no assurance that the nature and amount of that insurance will be adequate, in
every case, to indemnify us against liabilities arising from future legal proceedings.
On September 11, 2023, a group of plaintiffs filed an attempted class action lawsuit alleging that during the Company’s
Chapter 11 bankruptcy, it changed the anti-dilution language of the approved form of warrant agreement without seeking the
court’s approval under section 1127(b) of the Bankruptcy Code. The case was filed in the United States Federal District Court
for the Western District of Oklahoma (WDOK). On December 20, 2023, the Company filed a motion in the U.S. Bankruptcy
Court for the Southern District of Texas (the Court) asking it to enter an order that requires the plaintiffs to dismiss the lawsuit
in the WDOK because the claims asserted therein are barred by releases granted by the plaintiffs pursuant to the confirmation
order entered by the Court in connection with the Company’s Chapter 11 Cases, and an injunction enjoining the plaintiffs from
bringing any action subject to those releases. On October 4, 2024, the Court entered an order denying the Company’s motion
for an order enforcing the confirmation order. The Company has appealed the Court’s decision to the United States District
Court for the Southern District of Texas. The Company has also filed a motion with the WDOK asking it to stay proceedings
pending the appeal.
Table of Contents
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
60
NOTE 21 - 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.
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, 2024 and determined there was no material risk at that time. The fair value of the net derivative
assets with Bank of Oklahoma, our only commodity derivative counterparty, was $0.5 million of December 31, 2024.
We had no outstanding commodity derivatives as of December 31, 2023.
The following table presents third-party customers that accounted for over 10% of each of our segments' revenues:
Year Ended December 31,
2024
2023
Oil and Natural Gas:
CVR Energy, Inc.
19%
14%
Southwest Energy L.P.
16%
12%
Superior Pipeline Corporation, L.L.C. (1)
11%
19%
Drilling:
Coterra Energy, Inc.
33%
17%
Devon Energy Production Company, LP
28%
*
Continental Resources Inc.
17%
15%
Diamondback E&P, LLC
16%
23%
Earthstone Operating, LLC
*
14%
* Revenue accounted for less than 10% of the segment's revenues.
1.
See Note 19 - Superior Investment for information on affiliate activity with Superior.
NOTE 22 – INDUSTRY SEGMENT INFORMATION
We have two main business segments offering different products and services within the energy industry:
•
Oil and natural gas - the oil and natural gas segment is engaged in the acquisition, development, and production of
oil, NGLs, and natural gas properties.
•
Contract drilling - the contract drilling segment is engaged in the land contract drilling of oil and natural gas wells.
We evaluate each consolidated segment’s performance based on its operating income, which is defined as operating
revenues less operating expenses and depreciation, depletion, amortization, and impairment. We have no oil and natural gas
production or other operations outside the United States. The Company's chief operating decision maker (CODM) is the chief
executive officer. The significant expense categories and amounts included in the table below align with the segment-level
information that is regularly provided to the CODM.
Table of Contents
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
61
The following tables present information about the operations and assets for each of our segments:
Year Ended December 31, 2024
Oil and
Natural Gas
Contract
Drilling
Corporate and
Other
Eliminations
Total
Consolidated
(In thousands)
Revenues: (1)
Oil and natural gas
$
93,248
$
—
$
—
$
—
$
93,248
Contract drilling
—
144,364
—
—
144,364
Total revenues
93,248
144,364
—
—
237,612
Expenses:
Operating costs:
Oil and natural gas
44,420
—
—
—
44,420
Contract drilling
—
99,655
—
—
99,655
Total operating costs
44,420
99,655
—
—
144,075
Depreciation, depletion, and amortization
7,889
7,425
332
—
15,646
General and administrative
—
—
22,497
—
22,497
(Gain) loss on disposition of assets
114
(1,781)
—
—
(1,667)
Total operating expenses
52,423
105,299
22,829
—
180,551
Income (loss) from operations
40,825
39,065
(22,829)
—
57,061
Other income (expense):
Interest income
—
—
4,104
—
4,104
Interest expense
—
—
(55)
—
(55)
Gain on derivatives
—
—
534
—
534
Reorganization items, net
—
—
(84)
—
(84)
Other
134
350
(425)
—
59
Total other income (expense)
134
350
4,074
—
4,558
Income (loss) before income taxes
$
40,959
$
39,415
$
(18,755) $
—
$
61,619
Identifiable assets:
Oil and natural gas (2)
$
106,116
$
—
$
—
$
(148) $
105,968
Contract drilling
—
94,088
—
—
94,088
Total identifiable assets (3)
106,116
94,088
—
(148)
200,056
Other corporate assets (4)
—
—
56,208
—
56,208
Deferred tax assets
—
—
32,979
—
32,979
Total assets
$
106,116
$
94,088
$
89,187
$
(148) $
289,243
Capital expenditures:
$
16,444
$
10,673
$
126
$
—
$
27,243
1.
The revenues for oil and natural gas occur at a point in time. The revenues for contract drilling occur over time.
2.
Oil and natural gas assets include oil and natural gas properties, 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, short-term investments, transportation equipment, furniture, and equipment.
Table of Contents
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
62
Year Ended December 31, 2023
Oil and
Natural Gas
Contract
Drilling
Corporate and
Other
Eliminations
Total
Consolidated
(In thousands)
Revenues: (1)
Oil and natural gas
$
146,237
$
—
$
—
$
—
$
146,237
Contract drilling
—
181,056
—
—
181,056
Total revenues
146,237
181,056
—
—
327,293
Expenses:
Operating costs:
Oil and natural gas
65,739
—
—
—
65,739
Contract drilling
—
108,035
—
—
108,035
Total operating costs
65,739
108,035
—
—
173,774
Depreciation, depletion, and amortization
9,430
7,927
367
—
17,724
General and administrative
—
—
22,577
—
22,577
(Gain) loss on disposition of assets
(36,125)
(13,932)
107
—
(49,950)
Total operating expenses
39,044
102,030
23,051
—
164,125
Income (loss) from operations
107,193
79,026
(23,051)
—
163,168
Other income (expense):
Interest income
—
—
9,734
—
9,734
Interest expense
—
—
(164)
—
(164)
Gain on derivatives
—
—
12,975
—
12,975
Gain on Sale of Superior Investment
—
—
17,812
—
17,812
Reorganization items, net
—
—
(299)
—
(299)
Other
213
(258)
248
—
203
Total other income (expense)
213
(258)
40,306
—
40,261
Income (loss) before income taxes
$
107,406
$
78,768
$
17,255
$
—
$
203,429
Identifiable assets:
Oil and natural gas (2)
$
99,670
$
—
$
—
$
(148) $
99,522
Contract drilling
—
96,629
—
—
96,629
Total identifiable assets (3)
99,670
96,629
—
(148)
196,151
Other corporate assets (4)
—
—
79,483
—
79,483
Deferred tax assets
—
—
47,086
—
47,086
Total assets
$
99,670
$
96,629
$
126,569
$
(148) $
322,720
Capital expenditures:
$
6,706
$
11,249
$
104
$
—
$
18,059
1.
The revenues for oil and natural gas occur at a point in time. The revenues for contract drilling occur over time.
2.
Oil and natural gas assets include oil and natural gas properties, 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 primarily cash and cash equivalents, transportation equipment, furniture, and equipment.
Table of Contents
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
63
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 all located in the United States.
Capitalized Costs
The following table presents capitalized costs related to our oil and natural gas activities:
As of December 31,
2024
2023
(In thousands)
Proved properties (1)
$
167,495
$
161,539
Unproved properties (wells in progress)
10,655
1,173
178,150
162,712
Accumulated depreciation, depletion, amortization, and impairment
(92,023)
(84,747)
Net capitalized costs
$
86,127
$
77,965
1.
Presented gross of any inter-segment eliminations which reduce the consolidated capitalized costs. See Note 22 - Industry Segment Information for detail
on inter-segment eliminations.
Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration, and Development Activities
The following table presents costs incurred related to our oil and natural gas activities during the periods indicated:
Year Ended December 31,
2024
2023
(In thousands)
Unproved properties acquired
$
9,717 $
762
Proved properties acquired
—
—
Exploration
—
—
Development
6,307
5,730
Total costs incurred
$
16,024 $
6,492
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 following table presents results of operations for producing activities before inter-segment eliminations during the
periods indicated:
Year Ended December 31,
2024
2023
(In thousands)
Revenues from producing activities
$
92,902 $
145,743
Production costs
(31,890)
(52,272)
Depreciation, depletion, amortization, and impairment
(7,358)
(8,752)
53,654
84,719
Income tax expense (benefit)
9
(59,550)
Results of operations for producing activities (excluding corporate overhead and financing costs)
$
53,645 $
144,269
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64
The table below presents 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:
2023
Proved developed and undeveloped reserves:
Beginning of year
7,681
20,132
212,409
63,215
Revision of previous estimates (1)
(735)
(2,763)
(31,052)
(8,673)
Extensions and discoveries
20
24
1,909
362
Infill reserves in existing proved fields
60
26
291
135
Purchases of minerals in place
—
—
—
—
Production
(984)
(1,636)
(20,195)
(5,986)
Sales (3)
(996)
(5,917)
(63,476)
(17,493)
Net proved reserves at December 31, 2023
5,046
9,866
99,886
31,560
Proved developed reserves, December 31, 2023
5,046
9,866
99,886
31,560
Proved undeveloped reserves, December 31, 2023
—
—
—
—
2024
Proved developed and undeveloped reserves:
Beginning of year
5,046
9,866
99,886
31,560
Revision of previous estimates (2)
251
(110)
(4,670)
(637)
Extensions and discoveries
62
9
3,851
713
Infill reserves in existing proved fields
8
—
61
18
Purchases of minerals in place
—
—
—
—
Production
(693)
(1,007)
(13,563)
(3,961)
Sales
(5)
—
—
(5)
Net proved reserves at December 31, 2024
4,669
8,758
85,565
27,688
Proved developed reserves, December 31, 2024
4,669
8,758
85,565
27,688
Proved undeveloped reserves, December 31, 2024
—
—
—
—
Oil (MBbls)
NGL (MBbls)
Gas (Mcf)
Total (MBoe)
1.
Revisions of previous estimates increased primarily due to changes in the unescalated 12-month average product prices which decreased approximately
16% for oil and 58% for natural gas compared to the December 31, 2023 pricing.
2.
Revisions of previous estimates decreased primarily due to changes in the unescalated 12-month average product prices which decreased approximately
4% for oil and 19% for natural gas compared to the December 31, 2024 pricing.
3.
See Note 5 - Acquisitions And Divestitures for discussion of the assets divested during the year ended December 31, 2023.
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.
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65
The following table presents the components of the standardized measure of discounted future net cash flows:
As of December 31,
2024
2023
(In thousands)
Future cash inflows
$
708,020 $
850,979
Future production costs
(373,337)
(434,221)
Future development costs
(981)
(991)
Future income tax expenses
(21,583)
(11,714)
Future net cash flows
312,119
404,053
10% annual discount for estimated timing of cash flows
(136,943)
(166,872)
Standardized measure of discounted future net cash flows relating to proved oil, NGLs, and natural gas
reserves
$
175,176 $
237,181
The following table presents the principal sources of changes in the standardized measure of discounted future net cash
flows:
Year Ended December 31,
2024
2023
(In thousands)
Sales and transfers of oil and natural gas produced, net of production costs
$
(61,013) $
(93,472)
Net changes in prices and production costs
(12,123)
(410,475)
Revisions in quantity estimates and changes in production timing
(4,628)
(61,551)
Extensions, discoveries, and improved recovery, less related costs
5,439
6,339
Changes in estimated future development costs
10
658
Previously estimated cost incurred during the period
—
—
Purchases of minerals in place
—
—
Sales of minerals in place
(16)
(208,841)
Accretion of discount
24,889
95,656
Net change in income taxes
(9,869)
159,825
Changes in timing and other
(4,694)
(35,983)
Net change
(62,005)
(547,844)
Beginning of year
237,181
785,025
End of year
$
175,176 $
237,181
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, 2024 future cash flows were computed by applying the 12-month 2024 average unescalated prices of
$75.48 per barrel of oil and $2.13 per Mcf of natural gas, then adjusted for price differentials, over the estimated life of each of
our oil and natural gas properties. NGL pricing was estimated as a percentage of the pricing per barrel of oil. Future price
changes are considered only to the extent provided by contractual arrangements in existence at year-end.
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66
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.
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67
Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis presents management’s perspective of our business, financial condition and overall
performance. This information is intended to provide investors with an understanding of our past performance, current financial
condition and outlook for the future and should be read in conjunction with the consolidated financial statements and related
notes.
Introduction
We operate, manage, and analyze our results of operations through our three principal business segments:
•
Oil and Natural Gas – carried out by our subsidiary Unit Petroleum Company. This segment explores, develops,
acquires, and produces oil and natural gas properties for our own account.
•
Contract Drilling – carried out by our subsidiary Unit Drilling Company. This segment contracts to drill onshore oil
and natural gas wells for a wide range of other oil and natural gas companies.
Oil and Natural Gas
In our oil and natural gas segment, we are optimizing production and converting non-producing reserves to producing
with selective drilling activities. We evaluate future hedging of our production opportunistically depending on future market
pricing among other factors.
Contract Drilling
In our contract drilling segment, we are focused on maintaining utilization of our current fleet of 14 BOSS drilling rigs in
a safe and efficient manner. Generally, the contract periods for our rigs range from 3 to 12 months, but shorter terms are
possible in certain situations.
As of December 31, 2024, two of our 14 BOSS rigs were warm-stacked in our Odessa Yard. Subsequently, in February
2025, one of the two stacked rigs resumed operations. We are actively seeking new contract opportunities for the remaining
stacked rig, as well as continuing to manage the upcoming renewals for our operational fleet.
Recent Developments
Commodity Price Environment
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, are all significant drivers of our results.
While our operations are all within the United States, events outside the United States affect us and our industry, including
political and economic uncertainty and geopolitical activity.
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68
The following chart reflects the fluctuations in the historical prices for oil and natural gas:
$ per Bbl
$ per MMBtu
Natural Gas Henry Hub
Crude Oil WTI
Mar 2023
Jun 2023
Sep 2023
Dec 2023
Mar 2024
Jun 2024
Sep 2024
Dec 2024
$48.00
$60.00
$72.00
$84.00
$96.00
$—
$2.50
$5.00
$7.50
$10.00
The following chart reflects the significant fluctuations in the prices for NGLs(1):
$ per Bbl
Ethane
Propane
Condensate
Mar 2023
Jun 2023
Sep 2023
Dec 2023
Mar 2024
Jun 2024
Sep 2024
Dec 2024
$—
$20.00
$40.00
$60.00
$80.00
1.
NGL prices reflect the monthly average Mont Belvieu price.
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69
Common Stock Dividends
The table below presents information about the dividends paid during the periods indicated:
Type
Dividend
per share
Total
Amount
Record Date
Payment Date
2023
(In thousands)
First quarter
Special
$
10.00 $
96,179
January 20, 2023
January 31, 2023
Second quarter
Quarterly
$
2.50 $
24,071
June 16, 2023
June 26, 2023
Third quarter
Quarterly
$
2.50 $
24,113 September 15, 2023 September 26, 2023
Fourth quarter
Quarterly
$
2.50 $
24,226 December 18, 2023
December 27, 2023
Fourth quarter
Special
$
15.00 $
145,353 December 18, 2023
December 27, 2023
Fourth quarter
Special
$
5.00 $
48,451 December 18, 2023
December 27, 2023
2024
First quarter
Quarterly
$
1.25 $
12,269
March 18, 2024
March 28, 2024
Second quarter
Quarterly
$
1.25 $
12,961
June 17, 2024
June 27, 2024
Third quarter
Quarterly
$
1.25 $
12,248 September 16, 2024 September 27, 2024
Fourth quarter
Quarterly
$
1.25 $
12,185 December 17, 2024
December 27, 2024
Fourth quarter
Special
$
2.00 $
19,495 December 17, 2024
December 27, 2024
The Company announced on March 7, 2025 that a quarterly cash dividend of $1.25 per share had been declared for the
first quarter of 2025, to be paid on March 28, 2025 to shareholders of record as of the close of business on March 18, 2025.
The declaration and payment of any future dividend, whether fixed, special, or variable, will remain at the full discretion
of the Company’s Board of Directors and will depend upon the Company’s financial position, results of operations, cash flows,
capital requirements, business conditions, future expectations, the requirements of applicable law, and other factors that the
Company’s Board of Directors finds relevant at the time of considering any potential dividend declaration. Future dividends are
expected to be funded by cash on the Company's balance sheet.
Sale of Superior Investment
On April 24, 2023, we entered into a purchase and sale agreement (the "Superior PSA") with SP Investor under which the
Company closed on the sale of its 50% ownership interest in Superior for $20.0 million. Unit received proceeds of $12.0
million at closing and received $8.0 million of deferred proceeds in April 2024. We recognized a $17.8 million gain on sale of
Superior investment in the consolidated statements of operations for the year ended December 31, 2023.
Critical Accounting Policies and Estimates
Summary
This section identifies the critical accounting policies we follow in preparing our financial statements and related
disclosures. Certain policies require us to make difficult, subjective, and complex judgments while making estimates of matters
inherently imprecise. Some accounting policies involve judgments and uncertainties to such an extent that there is a reasonable
likelihood that materially different amounts could have been reported under different conditions, or had different assumptions
been used. We evaluate our estimates and assumptions regularly. We base our estimates on historical experience and various
other assumptions we believe are reasonable under the circumstances, the results of which support making judgments about the
carrying values of assets and liabilities not readily apparent from other sources. Actual results may differ from these estimates
and assumptions used in preparation of our financial statements.
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70
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. We hire an
independent petroleum engineering firm to audit our internal evaluation of our reserves on an annual basis. The audit as of
December 31, 2024 covered reserves that we projected to comprise 85% of the total proved developed future net income
discounted at 10% (based on the SEC's unescalated pricing policy). The qualifications of our independent petroleum
engineering firm and our employees responsible for preparing our reserve reports are included in Part C of this Annual Report.
The accuracy of estimating oil, NGLs, and natural gas reserves varies with the reserve classification and the related
accumulation of available data, as shown in this table:
Type of Reserves
Nature of Available Data
Degree of Accuracy
Proved undeveloped
Data from offsetting wells, seismic data
Less accurate
Proved developed non-producing
The above and logs, core samples, well tests, pressure data
More accurate
Proved developed producing
The above and production history, pressure data over time
Most accurate
Assumptions of future oil, NGLs, and natural gas prices and operating and capital costs also play a significant role in
estimating these reserves and the estimated present value of the cash flows to be received from the future production of those
reserves. Volumes of recoverable reserves are influenced by the assumed prices and costs due to the economic limit (that point
when the projected costs and expenses of producing recoverable oil, NGLs, and natural gas reserves are greater than the
projected revenues from the oil, NGLs, and natural gas reserves). But more significantly, the estimated present value of the
future cash flows from our oil, NGLs, and natural gas reserves is sensitive to prices and costs and may vary materially based on
different assumptions. We use full cost accounting which factors in the unweighted arithmetic average of the commodity prices
existing on the first day of each of the twelve months before the end of the reporting period to calculate discounted future
revenues, unless prices were otherwise determined under contractual arrangements.
We compute DD&A on a units-of-production method. Each quarter, we use these formulas to compute the provision for
DD&A for our producing properties:
•
DD&A Rate = Unamortized Cost / End of Period Reserves Adjusted for Current Period Production
•
Provision for DD&A = DD&A Rate x Current Period Production
Unamortized cost includes all capitalized costs, estimated future expenditures to be incurred in developing proved
reserves and estimated dismantlement and abandonment costs, net of estimated salvage values less accumulated amortization,
unproved properties, and equipment not placed in service.
Oil, NGLs, and natural gas reserve estimates have a significant impact on our DD&A rate. If future reserve estimates for
a property or group of properties are revised downward, the DD&A rate will increase because of the revision. If reserve
estimates are revised upward, the DD&A rate will decrease.
The DD&A expense on our oil and natural gas properties is calculated each quarter using period end reserve quantities
adjusted for period production.
We account for our oil and natural gas exploration and development activities using the full cost method of accounting.
Under this method, we capitalize all costs incurred in the acquisition, exploration, and development of oil and natural gas
properties. At the end of each quarter, the net capitalized costs of our oil and natural gas properties are limited to that amount
which is the lower of unamortized costs or a ceiling. The ceiling is defined as the sum of the present value (using a 10%
discount rate) of the estimated future net revenues from our proved reserves (based on the unescalated 12-month average price
on our oil, NGLs, and natural gas adjusted for any cash flow hedges), plus the cost of properties not being amortized, plus the
lower of the cost or estimated fair value of unproved properties included in the costs being amortized, less related income taxes.
If the net capitalized costs of our oil and natural gas properties exceed the ceiling, we are required to write-down the excess
amount. A ceiling test write-down is a non-cash charge reducing earnings and shareholders’ equity in the period of occurrence,
resulting in lower DD&A expense in future periods. A write-down cannot be reversed once incurred.
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71
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. As of December 31, 2024, our reserves were calculated based on applying 12-month 2024
average unescalated prices of $75.48 per barrel of oil and $2.13 per Mcf of natural gas, then adjusted for price differentials,
over the estimated life of each of our oil and natural gas properties. NGL pricing was estimated as a percentage of the pricing
per barrel of oil. We did not record a ceiling test write-down for the years ended December 31, 2024 or 2023.
Impairment of Other Property and Equipment. We review the carrying amounts of long-lived assets for potential
impairment when events occur or changes in circumstances suggest these carrying amounts may not be recoverable. Changes
that could prompt an assessment include equipment obsolescence, changes in the market demand for a specific asset, changes in
commodity prices, periods of relatively low drilling rig utilization, declining revenue per day, declining cash margin per day, or
overall changes in general market conditions. Assets are determined to be impaired if a forecast of undiscounted estimated
future net operating cash flows directly related to the asset, including disposal value if any, is less than the carrying amount of
the asset. If any asset is determined to be impaired, the loss is measured as the amount by which the carrying asset exceeds its
fair value. The estimate of fair value is based on the best information available, including prices for similar assets. Changes in
these estimates could cause us to reduce the carrying value of property and equipment. Asset impairment evaluations are, by
nature, highly subjective. They involve expectations about future cash flows generated by our assets and reflect our
assumptions and judgments regarding future industry conditions and their effect on future utilization levels, dayrates, and costs.
Using different estimates and assumptions could result in materially different carrying values of our assets.
Asset Retirement Obligations. We are required to record the estimated fair value of the liabilities relating to the future
retirement of our long-lived assets. Our oil and natural gas wells are plugged and abandoned when the oil and natural gas
reserves in those wells are depleted or the wells are no longer able to produce. The estimated liabilities related to these future
costs are recorded at the time the wells are drilled or acquired. We use historical experience to determine the estimated plugging
costs considering the well's type, depth, physical location, and ultimate productive life. A risk-adjusted discount rate and an
inflation factor are applied to estimate the present value of these obligations. We depreciate the capitalized asset retirement cost
and accrete the obligation over time. Revisions to the obligations and assets are recognized at the appropriate risk-adjusted
discount rate with a corresponding adjustment made to the full cost pool.
Financial Condition and Liquidity
Summary
Our near-term and long-term financial condition and liquidity primarily depend on the cash flow from our operations and
credit agreement borrowings. The principal factors determining our cash flow from operations are:
•
the volume of natural gas, oil, and NGLs we produce;
•
the prices we receive for our natural gas, oil, and NGLs production;
•
the utilization of our drilling rigs; and
•
the dayrates we receive for utilization of our drilling rigs.
We currently expect that cash and cash equivalents, cash generated from operations, and available funds under our credit
facility will be adequate to support our working capital, capital expenditures, dividend distributions, discretionary stock
repurchases, and other cash requirements for at least the next 12 months and we are not aware of any indications that they will
not be adequate for the foreseeable periods thereafter.
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72
The table below summarizes cash flow activity during the periods indicated:
Year Ended December 31,
Percent
Change
2024
2023
(In thousands except percentages)
Net cash provided by operating activities
$
75,216 $
150,162
(50) %
Net cash provided by (used in) investing activities
(11,577)
57,977
(120) %
Net cash used in financing activities
(75,534)
(361,335)
79 %
Net decrease in cash and cash equivalents
$
(11,895) $
(153,196)
Cash Flows from Operating Activities
Our operating cash flow is primarily influenced by the prices we receive for our oil, NGLs, and natural gas production,
the volume of oil, NGLs, and natural gas we produce, settlements of commodity derivative contracts, third-party utilization of
our drilling rigs, and the rates charged for those drilling services. Our cash flows from operating activities are also affected by
changes in working capital.
Net cash provided by operating activities during the year ended December 31, 2024 decreased by $74.9 million as
compared to the year ended December 31, 2023 primarily due to decreased income from operations and unfavorable changes in
net working capital.
Cash Flows from Investing Activities
We anticipate using a portion of our free cash flows for capital expenditures related to our development and production of
oil, NGLs, and natural gas as well as the maintenance of our existing drilling rig fleet.
Net cash provided by (used in) investing activities decreased by $69.6 million during the year ended December 31, 2024
compared to the year ended December 31, 2023 primarily due to lower proceeds from the disposition of property and
equipment.
Cash Flows from Financing Activities
Net cash used in financing activities decreased by $285.8 million during the year ended December 31, 2024 compared to
the year ended December 31, 2023 primarily due to lower dividends paid during the year ended December 31, 2024.
As of December 31, 2024, we had unrestricted cash and cash equivalents totaling $48.9 million and no outstanding
borrowings under the Second Credit Agreement.
The following table summarizes certain financial condition and liquidity information as of the dates indicated:
Year Ended December 31,
2024
2023
(In thousands)
Working capital
$
57,782
$
75,897
Current portion of long-term debt
$
—
$
—
Long-term debt
$
—
$
—
Shareholders' equity
$
232,521
$
254,126
Working Capital
Our working capital balance primarily fluctuates due to the increase or use of our cash and cash equivalents balances, and
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 commodity derivatives. We had positive working capital of $57.8 million at December 31,
2024 compared to positive working capital of $75.9 million as of December 31, 2023. The decrease in working capital is
primarily due to lower cash and cash equivalents and accounts receivable, partially offset by lower accounts payable.
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73
Credit Agreements
Second Amended and Restated Credit Agreement. On March 8, 2024, the Company entered into the Second Amended and
Restated Credit Agreement (the Second credit agreement), dated as of March 8, 2024 and effective as of March 1, 2024. This
agreement replaces the Exit credit agreement, which was set to mature on March 1, 2024. The Second credit agreement
provides a $10.0 million initial borrowing base, subject to semi-annual redetermination, with BOKF, NA dba Bank of
Oklahoma (BOKF). The Second credit agreement matures on March 8, 2027 and is collateralized by the Company's BOSS rigs
and upstream properties.
Exit Credit Agreement. On the Emergence Date, the Company entered into an amended and restated credit agreement (the
Exit credit agreement), providing for a $140.0 million senior secured revolving credit facility (RBL Facility) and a
$40.0 million senior secured term loan facility, among (i) the Company, UDC, and UPC (together, the Borrowers), (ii) the
guarantors party thereto, including the Company and all of its subsidiaries existing as of the Emergence Date (other than
Superior and its subsidiaries), (iii) the lenders party thereto from time to time (Emergence 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 was March 1, 2024. The Exit credit agreement was secured by first-priority liens
on substantially all of the personal and real property assets of the Borrowers and the Guarantors, including the Company’s
ownership interests in Superior.
Capital Requirements
Oil and Natural Gas Segment Acquisitions, Capital Expenditures, and Dispositions. Most of our capital expenditures for
this segment are discretionary and directed toward growth. Our decisions to increase our oil, NGLs, and natural gas reserves
through acquisitions or through drilling depends on the prevailing or expected market conditions, potential return on
investment, future drilling potential, and opportunities to obtain financing, which provide us flexibility in deciding when and if
to incur these costs.
Oil and natural gas segment capital expenditures, including oil and gas properties on the full cost method, for the year
ended 2024 totaled $16.4 million, excluding a $0.5 million increase in the ARO liability, compared to $6.7 million, excluding a
$14.4 million reduction in the ARO liability, during the year ended 2023. We participated in the completion of 20 gross wells
(0.60 net wells) drilled by other operators during the year ended December 31, 2024 compared to 24 gross wells (1.25 net
wells) during the year ended December 31, 2023. In addition, we secured 2,600 acres of oil and gas leases for $7.1 million and
made prepayments on two gross wells for $2.5 million during the year ended December 31, 2024.
On December 13, 2023, the Company closed on the sale of certain non-core wells and related leases in the Texas
Panhandle for cash proceeds of $50.7 million, after customary post-closing adjustments based on an effective date of October 1,
2023. A gain of $37.2 million was recognized within gain on disposition of assets in the consolidated statements of operations
for the year ended December 31, 2023.
Net proceeds for the sale of other non-core oil and natural gas assets totaled $2.9 million and $3.3 million during the years
ended December 31, 2024 and 2023, respectively. These proceeds reduced the net book value of our full cost pool with no gain
or loss recognized as the sales did not result in a significant alteration of the full cost pool.
Contract Drilling Segment Dispositions, Acquisitions, and Capital Expenditures. Near term capital expenditures are
expected to primarily be for maintenance capital on operating drilling rigs. Contract drilling capital expenditures totaled $10.7
million and $11.3 million during the years ended December 31, 2024 and 2023, respectively.
On May 18, 2023, the Company closed on the sale of two older generation SCR rigs and certain related equipment for
total proceeds of $5.8 million. Cash proceeds of $5.0 million were received at closing and deferred cash proceeds of $0.8
million were received on January 25, 2024. The deferred proceeds are included in notes receivable on the consolidated balance
sheets. The total proceeds resulted in net gains of $4.4 million, which are presented within gain on disposition of assets in the
consolidated statements of operations.
Proceeds from the sale of other non-core contract drilling assets totaled $2.9 million and $13.6 million during the years
ended December 31, 2024 and 2023, respectively. These proceeds resulted in net gains of $1.8 million and $9.5 million during
the years ended December 31, 2024 and 2023, respectively. The net gains are presented within gain on disposition of assets in
the consolidated statements of operations.
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74
Derivative Activities
Commodity Derivatives. Our commodity derivatives are intended to reduce our exposure to price volatility and manage
price risks. Those contracts limit the risk of downward price movements for commodities subject to derivative contracts, but
they also limit increases in future revenues that would otherwise result from price movements above the contracted prices. Our
decision on the type and quantity of our production and the price(s) of our derivative(s) is based, in part, on our view of current
and future market conditions. As of December 31, 2024, based on our fourth quarter 2024 average daily production, the
approximated percentages of our production under basis swaps are as follows:
2025
2026 and beyond
Daily natural gas production
54%
—%
In March 2025, we entered into NYMEX (HH) natural gas - swap agreements averaging 15,000 MMBtu/day for April
2025 through December 2025 at a weighted average fixed price of $4.69 per MMBtu. In addition, we entered into NYMEX
(HH) natural gas - swap agreements averaging 5,000 MMBtu/day for January 2026 through December 2026 at a weighted
average fixed price of $4.22 per MMBtu.
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, 2024 and determined there was no material risk at that time. The fair value of the net derivative
liabilities with Bank of Oklahoma, our only commodity derivative counterparty, was $0.5 million of December 31, 2024.
Below is the effect of derivative instruments on the consolidated statements of operations for the periods indicated:
Year Ended December 31,
2024
2023
(In thousands)
Gain on derivatives
$
534 $
12,975
Cash settlements paid on commodity derivatives
—
(10,591)
Gain on derivatives less cash settlements paid on commodity derivatives
$
534 $
23,566
If a legal right of set-off exists, we net the value of the derivative arrangements we have with the same counterparty on
our consolidated balance sheets.
Stock-Based Compensation
During the year ended December 31, 2024, we granted 33,296 restricted stock units (RSUs) with an aggregate grant date
fair value of $1.2 million. The RSU grants were made in July 2024 and vest equally each month for 36 months.
During the year ended December 31, 2024, we granted 29,730 performance restricted stock units (PRSUs) with an
aggregate grant date fair value of $0.8 million. The PRSU grants were made in July 2024 and vest on December 31, 2026.
We recognized stock-based compensation expense of $4.6 million during the year ended December 31, 2024.
During the year ended December 31, 2023, we granted 23,700 RSUs with an aggregate grant date fair value of $1.1
million. The RSU grants were made in July 2023 and vest equally each month for 36 months. We recognized stock-based
compensation expense of $7.5 million during the year ended December 31, 2023.
Insurance
We are self-insured for certain losses relating to workers’ compensation, general liability, control of well, and employee
medical benefits. Insured policies for other coverage contain deductibles or retentions per occurrence that range from zero to
$1.0 million. We have purchased stop-loss coverage to limit, to the extent feasible, per occurrence and aggregate exposure to
certain types of claims. There is no assurance that the insurance coverage we have will protect us against liability from all
potential consequences. If insurance coverage becomes more expensive, we may choose to self-insure, decrease our limits, raise
our deductibles, or any combination of these rather than pay higher premiums.
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75
Results of Operations
Year Ended December 31, 2024 versus Year Ended December 31, 2023
Year Ended December 31,
Change
Percent
Change (1)
2024
2023
(In thousands except rig and day amounts, and as otherwise specified)
Total revenue
$
237,612
$
327,293
$
(89,681)
(27) %
Net income
$
47,245
$
248,939
$
(201,694)
(81) %
Oil and Natural Gas:
Revenue
$
93,248
$
146,237
$
(52,989)
(36) %
Operating costs
$
44,420
$
65,739
$
(21,319)
(32) %
Average oil price ($/Bbl)
$
74.51
$
60.61
$
13.90
23 %
Average oil price excluding derivatives ($/Bbl)
$
74.51
$
75.57
$
(1.06)
(1) %
Average NGLs price ($/Bbl)
$
19.71
$
18.02
$
1.69
9 %
Average NGLs price excluding derivatives ($/Bbl)
$
19.71
$
18.02
$
1.69
9 %
Average natural gas price ($/Mcf)
$
1.58
$
2.28
$
(0.70)
(31) %
Average natural gas price excluding derivatives ($/Mcf)
$
1.58
$
2.07
$
(0.49)
(24) %
Oil production (MBbls)
693
984
(291)
(30) %
NGL production (MBbls)
1,007
1,636
(629)
(38) %
Natural gas production (MMcf)
13,563
20,195
(6,632)
(33) %
Total production (MBoe)
3,961
5,986
(2,025)
(34) %
Contract Drilling:
Revenue
$
144,364
$
181,056
$
(36,692)
(20) %
Operating costs
$
99,655
$
108,035
$
(8,380)
(8) %
Total drilling rigs available for use at the end of the period
14
14
—
— %
Average number of drilling rigs in use
12.1
15.1
(3.0)
(20) %
Average dayrate on daywork contracts ($/day)
$
30,357
$
31,225
$
(868)
(3) %
Corporate and Other:
General and administrative expense
$
22,497
$
22,577
$
(80)
— %
Other income (expense):
Interest income
$
4,104
$
9,734
$
(5,630)
(58) %
Interest expense
$
(55)
$
(164)
$
109
67 %
Reorganization items
$
(84)
$
(299)
$
215
72 %
Gain on derivatives
$
534
$
12,975
$
(12,441)
(96) %
Gain on sale of Superior investment
$
—
$
17,812
$
(17,812)
(100) %
Income tax expense (benefit), net
$
14,374
$
(45,510)
$
59,884
132 %
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 $53.0 million or 36% during the year ended December 31, 2024 compared to the
year ended December 31, 2023. This decline was due to lower production volumes due to the divestiture of producing
properties in the Texas Panhandle during the December of 2023, and normal well production declines. Excluding derivatives
settled, average oil prices decreased 1% to $74.51 per barrel, average natural gas prices decreased 24% to $1.58 per Mcf, and
NGLs prices increased 9% to $19.71 per barrel.
Oil and natural gas operating costs decreased $21.3 million or 32% during the year ended December 31, 2024 compared
to the year ended December 31, 2023. This decrease was primarily due to lower production taxes on reduced revenues and
lower lease operating expenses also due to the divestiture of producing properties in the Texas Panhandle during the December
of 2023.
Contract Drilling
Contract drilling revenues decreased $36.7 million or 20% during the year ended December 31, 2024 compared to the
year ended December 31, 2023 primarily due to a 20% decrease in the average number of rigs in use with an average of 12.1
rigs working in 2024 compared to 15.1 rigs working in 2023. We also had a 3% decrease in our average dayrate.
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76
Contract drilling operating costs decreased $8.4 million or 8% during the year ended December 31, 2024 compared to the
year ended December 31, 2023 primarily due to a decrease in the average number of drilling rigs in use and lower rig relocation
expense, partially offset by higher average employee compensation.
General and Administrative
Corporate general and administrative expenses decreased $0.1 million during the year ended December 31, 2024
compared to the year ended December 31, 2023. Excluding the $3.3 million service fee received from Superior during the year
ended December 31, 2023, general and administrative expenses decreased by $3.4 million, primarily due to lower headcount.
Interest Income
Interest income decreased $5.6 million during the year ended December 31, 2024 compared to the year ended December
31, 2023 primarily due to lower average cash equivalents held as well as lower average interest rates.
Interest Expense
Changes in interest expense between the comparative year ended 2024 and 2023 are primarily related to commitment fees
paid on the unused portion of the Second credit facility and the Exit credit facility. There were no borrowings outstanding on
either credit facility during the comparative years.
Reorganization Items
Reorganization items represent any of the expenses, gains, and losses incurred subsequent to and as a direct result of the
Chapter 11 proceedings.
Gain on Derivatives
The $12.4 million unfavorable change in gain on derivatives between the comparative years ended December 31, 2024
and 2023 is primarily due to timing of market pricing changes on outstanding commodity derivative positions and decreased
commodity derivative activity in 2024.
Gain on Sale of Superior Investment
The $17.8 million gain on sale of Superior investment represents the gain recognized on the April 2023 sale of our
investment in Superior.
Income Tax Expense (Benefit), Net
The $59.9 million unfavorable change in income tax expense (benefit), net during the year ended December 31, 2024
compared to the year ended December 31, 2023 is primarily due to the non-recurring $115.1 million release of the valuation
allowance in 2023, offset by the April 2023 sale of the Superior investment and lower pre-tax income for the year ended
December 31, 2024 as compared to the year ended December 31, 2023.
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,
as well as inflationary factors in the general United States economy. Increases in oil and gas 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 when oil, NGLs, and natural gas prices declined, labor rates did not come back down to
the levels existing before the increases. If commodity prices increase substantially for a long period, shortages in support
equipment (like drill pipe, third party services, and qualified labor) can cause additional increases in our material and labor
costs. Increases in dayrates for drilling rigs also increase the cost of drilling our oil and natural gas properties. How inflation
will affect us in the future will depend on increases, if any, realized in our drilling rig rates, the prices we receive for our oil,
NGLs, and natural gas, and the rates we receive for gathering and processing natural gas.
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77
Quantitative and Qualitative Disclosures about Market Risk
Commodity Price Risk. Our major market risk exposure is in the prices we receive for our oil, NGLs, and natural gas
production. Those prices are primarily driven by the prevailing worldwide price for crude oil and market prices applicable to
our natural gas production. Historically, these prices have fluctuated, and they will probably continue to do so. The price of oil,
NGLs, and natural gas also affects both the demand for our drilling rigs and the amount we can charge for our drilling rigs.
Based on our production for the year ended December 31, 2024, a $0.10 per Mcf change in what we receive for our natural gas
production, without the effect of derivatives, would cause a corresponding $0.1 million per month ($1.3 million annualized)
change in our pre-tax operating cash flow. A $1.00 per barrel change in our oil price, without the effect of derivatives, would
result in a $0.1 million per month ($0.7 million annualized) change in our pre-tax operating cash flow and a $1.00 per barrel
change in our NGLs price, without the effect of derivatives, would result in a $0.1 million per month ($1.1 million annualized)
change in our pre-tax operating 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.
See Note 16 - Derivatives for additional information.
Interest Rate Risk. Our interest rate exposure primarily relates to our cash equivalents held in money market funds
comprised of U.S. Government and U.S. Treasury securities and our long-term debt under our credit agreement. Our money
market fund holdings accrue interest at variable interest rates. Based on our average cash equivalents subject to a variable rate
during 2024, a 1% change in the average effective interest rate on these holdings during 2024 would change our annual pre-tax
cash flow by approximately $0.8 million. Borrowings under our Exit credit agreement also bear interest at variable interest
rates. We had no outstanding borrowings under this facility as of December 31, 2024.
Part E. Issuance History
The following table presents all shares or any other securities or options to acquire such securities issued for services
during the periods indicated below:
Month of Issuance
Issuance Type (1)
Shares Issued
Price at Issuance
Issuance Class
2023
July 2023
Restricted Stock (2)
23,700 $
47.88
Employee (3)
2024
July 2024
Restricted Stock (2)
33,296 $
36.49
Board (4) and
Employee (5)
July 2024
Performance
Restricted Stock (2)
29,730 $
25.24
Employee (6)
1.
All awards related to common stock and were issued pursuant to the Company's LTIP.
2.
Restricted stock award agreements contain a legend stating that the shares have not been registered under the Securities Act or any state securities
laws and setting forth or referring to the restrictions on transferability and sale of the shares under the Securities Act.
3.
During July 2023, the Company granted employee RSUs that one-third vest on each of the following dates: August 1, 2024, July 1, 2025, and July 1,
2026.
4.
During July 2024, the Company granted RSUs to Board members that vest on August 1, 2025.
5.
During July 2024, the Company granted employee RSUs that one-third vest on each of the following dates: July 1, 2025, July 1, 2026, and July 1,
2027.
6.
During July 2024, the Company granted employee PRSUs that vest on December 31, 2026 if certain performance criteria are met as set forth in the
PRSU agreement.
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78
Part F. Exhibits
2.1
Debtors' Amended Joint Chapter 11 Plan of Reorganization [Docket No. 320] (filed as Exhibit 2.1 to Unit's Form 8-
K, dated August 12, 2020, which is incorporated by reference herein).
3.1
Amended and Restated Certificate of Incorporation of Unit Corporation, dated as of September 3, 2020 (filed as
Exhibit 3.1 to Unit's Form 10-Q, dated August 16, 2021, which is incorporated by reference herein).
3.2
Amended and Restated Bylaws of Unit Corporation, dated as of September 3, 2020 (filed as Exhibit 3.2 to Unit's
Form 8-K, dated September 10, 2020, which is incorporated by reference herein).
10.1†
Unit Corporation Long Term Incentive Plan (filed as Exhibit 10.1 to Unit’s Form 8-K, dated September 10, 2020,
which is incorporated by reference herein).
10.2†
Form of Stock Option Grant Notice and Award Agreement (filed as Exhibit 10.3 to Unit’s Form 10-Q, dated
November 12, 2021, which is incorporated by reference herein).
10.3†
Form of Restricted Stock Unit (RSU) Grant Notice and Award Agreement (filed as Exhibit 10.2 to Unit’s Form 10-
Q, dated May 12, 2021, which is incorporated by reference herein).
10.4†
Form of Consulting Agreement with Robert Anderson (filed as Exhibit 10.4 to Unit's Form 10-K, dated March 31,
2022, which is incorporated by reference herein).
10.5
Form of Indemnification Agreement between Unit Corporation and its executive officers and directors (filed as
Exhibit 10.27 to Unit’s Form 10-K, dated March 31, 2021, which is incorporated by reference herein).
10.6
Form of Director Engagement Letter (filed as Exhibit 10.28 to Unit’s Form 10-K, dated March 31, 2021, which is
incorporated by reference herein).
10.7†
Employment Agreement, dated October 26, 2020, between Unit Corporation and Thomas Sell (filed as Exhibit 10.1
to Unit’s Form 8-K, dated December 11, 2020, which is incorporated by reference herein).
10.8†
Amended and Restated Separation Benefit Plan of Unit Corporation and Participating Subsidiaries (filed as Exhibit
10.8 to Unit's Form 10-K, dated March 31, 2022, which is incorporated by reference herein).
10.9†
Amendment No. 1 to Amended and Restated Separation Benefit Plan of Unit Corporation and Participating
Subsidiaries (filed as Exhibit 10.9 to Unit's Form 10-K, dated March 31, 2022, which is incorporated by reference
herein).
10.10
Amended and Restated Management Services and Operating Agreement between SPC Midstream Operating, L.L.C.
and Superior Pipeline Company, L.L.C. (filed as Exhibit 10.10 to Unit's Form 10-k, dated March 31, 2022, which is
incorporated by reference herein).
10.11
Amended and Restated Credit Agreement, dated as 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 September 10, 2020, which is incorporated by reference herein).
10.12
First Amendment to Amended and Restated Credit Agreement dated April 6, 2021 (filed as Exhibit 10.1 to Unit’s
Form 10-Q, dated May 12, 2021, which is incorporated by reference herein).
10.13
Second Amendment to Amended and Restated Credit Agreement effective July 26, 2021 (filed as Exhibit 10.1 to
Unit’s Form 10-Q, dated August 16, 2021, which is incorporated by reference herein).
10.14
Third Amendment to Amended and Restated Credit Agreement effective October 20, 2021 (filed as Exhibit 10.1 to
Unit’s Form 10-Q, dated November 12, 2021, which is incorporated by reference herein).
10.15
Fourth Amendment to Amended and Restated Credit Agreement effective November 1, 2022 (filed as Exhibit 10.1
to Unit’s Form 10-Q, dated November 10, 2022, which is incorporated by reference herein).
10.16
Credit Agreement dated May 10, 2018, by and among Superior Pipeline Company, L.L.C. and 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 May 16, 2018, which is incorporated by reference herein).
10.17
First Amendment to Credit Agreement, dated June 27, 2018, by and among Superior 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(b) to Unit’s Form 10-Q, dated August 9, 2018, which is
incorporated by reference herein).
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79
10.18
Amended and Restated Credit Agreement, dated April 29, 2022 by and among Superior Pipeline Company, L.L.C.
and 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 10-Q, dated May 12, 2022, which is incorporated by reference herein).
10.19
Warrant Agreement, dated as of September 3, 2020, by and between Unit Corporation and American Stock Transfer
& Trust Company, LLC (filed as Exhibit 10.2 to Unit’s Form 8-K, dated September 10, 2020, which is incorporated
by reference herein).
10.20
Registration Rights Agreement, dated as of September 9, 2020, by and between the Company and the holders party
thereto (filed as Exhibit 10.3 to Unit’s Form 8-K, dated September 10, 2020, which is incorporated by reference
herein).
10.21
Second Amended and Restated Limited Liability Company Agreement of Superior Pipeline Company, L.L.C., dated
as of July 1, 2019 (filed as Exhibit 10.1 to Unit’s Form 10-Q, dated October 21, 2020, which is incorporated by
reference herein).
10.22
Amendment No. 1 to Second Amended and Restated Limited Liability Company Agreement of Superior Pipeline
Company, L.L.C., dated as of July 1, 2019 (filed as Exhibit 10.2 to Unit’s Form 10-Q, dated October 21, 2020,
which is incorporated by reference herein).
10.23
Amendment No. 2 to Second Amended and Restated Limited Liability Company Agreement of Superior Pipeline
Company, L.L.C., dated as of March 1, 2022 (filed as Exhibit 10.21 to Unit's Form 10-K, dated March 31, 2022,
which is incorporated by reference herein).
10.24
Purchase 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 10-Q, dated May 3, 2018, which is incorporated by reference herein).
10.25
Second Amended and Restated Credit Agreement, dated March 8, 2024, effective March 1, 2024.
10.26†
Performance Restricted Stock Unit Grant Notice
31.1
Certification of Principal Executive Officer (filed herewith).
31.2
Certification of Principal Financial Officer (filed herewith).
99.1
Ryder Scott Company, L.P. Summary Report (filed herewith).
† Indicates a management contract or compensatory plan.
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UNIT CORPORATION
LONG TERM INCENTIVE PLAN
PERFORMANCE RESTRICTED STOCK UNIT GRANT NOTICE
Under the terms and conditions of the Unit Corporation Long Term Incentive Plan, as
amended from time to time (the “Plan”), Unit Corporation, a Delaware corporation
(the “Company”), hereby grants to the individual listed below (“you” or the “Participant”) the
number of performance-based Restricted Stock Units (the “PRSUs”) set forth below. This award
of PRSUs (this “Award”) is subject to the terms and conditions set forth herein, in the
Performance Restricted Stock Unit Agreement attached hereto as Exhibit A (the “Agreement”)
and the Plan, each of which is incorporated herein by reference. Capitalized terms used but not
defined herein shall have the meanings set forth in the Plan or the Agreement, as applicable.
Participant:
_____________________
Date of Grant:
_____________________ (the “Date of Grant”)
Award Type and
Description:
Your right to receive settlement of this Award in an amount ranging
from 0% to 150% of the Target PRSUs (as defined below) shall vest
and become earned and nonforfeitable upon (i) your satisfaction of
the continued employment requirements described below under
“Service Requirement” and (ii) the Committee’s certification of the
level of achievement of the Performance Goals (defined below).
Target Number of
PRSUs:
_____________________ (the “Target PRSUs”)
Performance Period:
January 1, 2024 (the “Performance Period Commencement Date”)
through December 31, 2026 (the “Performance Period End Date”)
Service Requirement:
Subject to the terms of the Plan and the Agreement, you must remain
continuously employed by the Company or an Affiliate from the
Date of Grant through the Performance Period End Date to be
eligible to vest in this Award (the “Service Requirement”), which is
further based on the level of achievement with respect to the
Performance Goals (as defined below).
Performance Goals:
The “Performance Goals” are based on the Company’s achievement
with respect to the performance goals described in Exhibit B attached
hereto.
By your signature below, you agree to be bound by the terms and conditions of the Plan,
the Agreement and this Grant Notice. You acknowledge that you have reviewed the Agreement,
the Plan and this Grant Notice in their entirety and fully understand all provisions of the
Agreement, the Plan and this Grant Notice. You hereby agree to accept as binding, conclusive
and final all decisions or interpretations of the Committee regarding any questions or
determinations that arise under the Agreement, the Plan or this Grant Notice. This Grant Notice
may be executed in one or more counterparts (including portable document format (.pdf) and
facsimile counterparts), each of which shall be deemed to be an original, but all of which
together shall constitute one and the same agreement.
[Signature Page Follows]
2
IN WITNESS WHEREOF, the Company has caused this Grant Notice to be executed by an
officer thereunto duly authorized, and the Participant has executed this Grant Notice, effective
for all purposes as provided above.
UNIT CORPORATION
By:
Name:
Title:
PARTICIPANT
Name:
Signature Page to
Performance Restricted Stock Unit Grant Notice
EXHIBIT A
PERFORMANCE RESTRICTED STOCK UNIT AGREEMENT
This Performance Restricted Stock Unit Agreement (this “Agreement”) is made as of the
Date of Grant by and between Unit Corporation, a Delaware corporation (the “Company”), and
_________ (the “Participant”). Capitalized terms used but not specifically defined herein shall
have the meanings specified in the Plan or the Grant Notice.
1.
Award. In consideration of the Participant’s past and/or continued employment
with the Company or an Affiliate and for other good and valuable consideration, the receipt and
sufficiency of which is hereby acknowledged, effective as of the Date of Grant, the Company
hereby grants to the Participant the number of Target PRSUs set forth in the Grant Notice on the
terms and conditions set forth in the Grant Notice, this Agreement and the Plan (which is
incorporated herein by reference as a part of this Agreement). If any inconsistency arises
between the Plan and this Agreement, the Plan shall control. Vesting and settlement of the
PRSUs shall occur at the times and subject to the terms and conditions set forth in the Grant
Notice, this Agreement and the Plan. Depending on the level of performance determined to be
attained with respect to the Performance Goals, the number of PRSUs granted hereunder that
become Earned PRSUs may range from 0% to 150% of the Target PRSUs. Unless the PRSUs
have become earned in the manner set forth in the Grant Notice and this Agreement, the
Participant will have no right to receive any cash or Stock in respect of the PRSUs. Prior to
settlement of this Award, the PRSUs and this Award represent an unsecured obligation of the
Company, payable only from the general assets of the Company.
2.
Earning of PRSUs. Except as otherwise set forth in Section 3 and the Plan, the
PRSUs shall vest and become earned (“Earned PRSUs”) in accordance with the Participant’s
satisfaction of the Service Requirement and the extent to which the Company has satisfied the
Performance Goals set forth in Exhibit B attached hereto, which shall be determined by the
Committee in its sole discretion following the end of the Performance Period (and any PRSUs
that do not become Earned PRSUs shall be automatically forfeited). Unless and until the PRSUs
have vested and become Earned PRSUs as described in the preceding sentence, the Participant
will have no right to receive any dividends or other distribution with respect to the PRSUs.
3.
Effect of Termination of Employment. Notwithstanding anything in the Grant
Notice, this Agreement, or the Plan to the contrary, a termination of the Participant’s
employment with the Company or an Affiliate will result in the following vesting rights or
forfeiture, as applicable, of the PRSUs.
(a)
Termination Without Cause. If the Participant’s employment with the
Company or an Affiliate is terminated by the Company or an Affiliate without Cause before the
Performance Period End Date, then (i) the Participant shall be deemed to have satisfied a portion
of the Service Requirement with respect to a portion of the PRSUs (“Partially Vested PRSUs”)
equal to (x ÷ y) times the number of Target PRSUs where “x” equals the number of days from
the Performance Period Commencement Date to the termination date and “y” equals the total
number of days in the Performance Period; (ii) such Partially Vested PRSUs shall remain
outstanding and, subject to the satisfaction of the Performance Goals, become Earned PRSUs at
the end of the Performance Period which shall be eligible for settlement at the time provided for
in, and otherwise in accordance with, Section 4; and (iii) the remaining PRSUs (and all rights
arising from such PRSUs and from being a holder thereof) will terminate automatically as of the
date of termination with no further action by the Company and will be forfeited without further
notice and at no cost to the Company.
Exhibit A
(b)
For example, if Participant’s employment with the Company or an Affiliate is terminated
by the Company or an Affiliate without Cause on December 31, 2024, and the number of Target
PRSUs is equal to 1,000, then the number of Partially Vested PRSUs would equal 333 [(365 ÷
1,095) X 1,000].
(c)
Change in Control. If the Participant’s employment with the Company or
an Affiliate is terminated before the end of the Performance Period End Date (i) by the Company
or an Affiliate without Cause during the Protection Period, or (ii) by the Participant for Good
Reason during the Protection Period, then the Participant shall be deemed to have satisfied the
Service Requirement with respect to all PRSUs, and such PRSUs shall remain outstanding and,
subject to the satisfaction of the Performance Goals, become Earned PRSUs at the end of the
Performance Period which shall be eligible for settlement at the time provided for in, and
otherwise in accordance with, Section 4.
(d)
Except as otherwise provided in Sections 3(a) and 3(b), in the event of the
termination of the Participant’s employment with the Company and its Affiliates for any reason,
any unvested PRSUs (and all rights arising from such PRSUs and from being a holder thereof)
will terminate automatically as of the date of termination with no further action by the Company
and will be forfeited without further notice and at no cost to the Company.
(e)
Certain Definitions. For this Agreement, these terms will have the
meanings specified below.
(i)
“Cause” means “cause” as defined under the Participant’s
employment agreement with the Company or, in the absence of such an agreement or definition,
shall mean the Committee’s determination (excluding the Participant) of misconduct by the
Participant that is or may be materially injurious to the Company or that results in the
Participant’s inability to substantially perform the Participant’s duties to the Company; provided,
however, that if the Participant’s actions or omissions are of such a nature that the Committee
(excluding the Participant) determines that they are curable by the Participant, such actions or
omissions must remain uncured for 30 days after the Company first provided the Participant
written notice of the obligation to cure such actions or omissions.
(ii)
“Change in Control” has the meaning given to it in the Plan,
provided, however, with respect to this Agreement and notwithstanding anything to the contrary
in the Plan, a Change in Control shall not be deemed to have occurred with respect to any
transaction that results in a change in the level of ownership of the Company attributable to
Prescott Group Capital Management, LLC.
(iii)
“Good Reason” means a (i) a material diminution in the
Participant’s annualized base salary, (ii) a material diminution in the Participant’s authority,
duties and responsibilities, taken as a whole, or (iii) the relocation of the geographic location of
the Participant’s principal place of employment by more than 50 miles from the location of the
Participant’s principal place of employment as of the Date of Grant; provided that, in the case of
the Participant’s assertion of Good Reason, (A) the condition described in the foregoing clauses
must have arisen without the Participant’s consent; (B) the Participant must provide written
notice to the Company of such condition in accordance with this Agreement within 30 days of
the initial existence of the condition; (C) the condition specified in such notice must remain
uncorrected for 30 days after receipt of such notice by the Company; and (D) the date of
termination of the Participant’s employment or other service relationship with the Company or
an Affiliate must occur within 90 days after such notice is received by the Company.
Exhibit A
(iv)
“Protection Period” means the period of time beginning on the
date of a Change in Control and ending on the first anniversary of the date of such Change in
Control.
4.
Settlement of PRSUs.
(a)
Timing of Settlement. Following PRSUs vesting and becoming Earned
PRSUs under Sections 2 or 3, the Company shall deliver to the Participant the number of shares
of Stock equal to the number of Earned PRSUs as soon as administratively practicable following
the Committee’s certification of the level of attainment of the Performance Goals, but in no event
later than March 15 of the calendar year following the Performance Period End Date.
(b)
Additional Settlement Details. Any fractional PRSU that becomes earned
hereunder shall be rounded down at the time shares of Stock are issued in settlement of such
PRSU. No fractional shares of Stock, nor the cash value of any fractional shares of Stock, shall
be issuable or payable to the Participant pursuant to this Agreement. All shares of Stock issued
hereunder shall be delivered either by delivering one or more certificates for shares to the
Participant or by entering such shares in book entry form, as determined by the Committee in its
sole discretion. The value of shares of Stock shall not bear any interest owing to the passage of
time. Neither this Section 4 nor any action taken pursuant to or in accordance with this
Agreement shall be construed to create a trust or a funded or secured obligation of any kind.
5.
Tax Withholding. To the extent that the receipt, vesting or settlement of this
Award results in compensation income or wages to the Participant for federal, state, local or
foreign tax purposes, the Participant shall make arrangements satisfactory to the Company for
the satisfaction of obligations for the payment of withholding taxes and other tax obligations
relating to this Award, which arrangements include the delivery of cash or cash equivalents,
Stock (including previously owned Stock, net settlement, a broker-assisted sale, or other cashless
withholding or reduction of the amount of shares otherwise issuable or delivered pursuant to this
Award), other property, or any other legal consideration the Committee deems appropriate. If
such tax obligations are satisfied through net settlement or the surrender of previously owned
Stock, the maximum number of shares of Stock that may be so withheld (or surrendered) shall be
the number of shares of Stock that have an aggregate Fair Market Value on the date of
withholding or surrender equal to the aggregate amount of such tax liabilities determined based
on the greatest withholding rates for federal, state, local or foreign tax purposes, including
payroll taxes, that may be utilized without creating adverse accounting treatment for the
Company with respect to this Award, as determined by the Committee. Any fraction of a share of
Stock required to satisfy such tax obligations shall be disregarded and the amount due shall be
paid instead in cash to the Participant. The Participant acknowledges that there may be adverse
tax consequences upon the receipt, vesting or settlement of this Award or disposition of the
underlying shares and that the Participant has been advised, and hereby is advised, to consult a
tax advisor. The Participant represents that the Participant is in no manner relying on the Board,
the Committee, the Company or any of its Affiliates or any of their respective managers,
directors, officers, employees or authorized representatives (including, without limitation,
attorneys, accountants, consultants, bankers, lenders, prospective lenders and financial
representatives) for tax advice or an assessment of such tax consequences.
6.
Non-Transferability. During the lifetime of the Participant, the PRSUs may not
be sold, pledged, assigned, or transferred other than by will or the laws of descent and
distribution, unless the shares of Stock underlying the PRSUs have been issued, and all
restrictions applicable to those shares have lapsed. Neither the PRSUs nor any interest or right
therein will be liable for the debts, contracts or engagements of the Participant or his or her
successors in interest or be subject to disposition by transfer, alienation, anticipation, pledge,
encumbrance, assignment or any other means, whether the disposition be voluntary or
Exhibit A
involuntary or by operation of law by judgment, levy, attachment, garnishment or any other legal
or equitable proceedings (including bankruptcy), and any attempted disposition thereof is null
and void and of no effect, except if the disposition is permitted by the preceding sentence.
7.
Compliance with Applicable Law. The issuance and transfer of shares of Stock
hereunder is subject to compliance by the Company and the Participant with all requirements of
federal and state securities laws and with all requirements of any stock exchange on which the
Company’s shares of Stock may be listed. No shares of Stock will be issued or transferred
unless any then applicable requirements of state and federal laws and regulatory agencies have
been complied with to the satisfaction of the Company and its counsel. The Participant
understands that the Company is under no obligation to register the shares of Stock with the
Securities and Exchange Commission, any state securities commission or any stock exchange to
effect such compliance.
8.
Rights as a Stockholder; Dividend Equivalents.
(a)
The Participant has no rights as a stockholder of the Company regarding
any shares of Stock that may become deliverable hereunder unless the Participant has become
the holder of record of such shares of Stock, and no adjustments shall be made for dividends in
cash or other property, distributions or other rights in respect of any such shares of Stock, except
as otherwise specifically provided for in the Plan or this Agreement. Any issuance or transfer of
shares of Stock or other property to the Participant or the Participant’s legal representative, heir,
legatee, or distributee, under this Agreement will be in full satisfaction of all claims of that
Person.
(b)
Each PRSU subject to this Award is granted in tandem with a
corresponding dividend equivalent right (“DER”), which DER remains outstanding from the
Date of Grant until the earlier of the settlement or forfeiture of the PRSU to which the DER
corresponds. Each vested DER entitles the Participant to receive payments, subject to and under
this Agreement, in an amount equal to any dividends paid by the Company regarding the share of
Stock underlying the PRSU to which such DER relates. The Company shall establish, regarding
each PRSU, a separate DER bookkeeping account for such PRSU (a “DER Account”), which
will be credited (without interest) on the applicable dividend payment dates with an amount
equal to any dividends paid while such PRSU remains outstanding regarding the share of Stock
underlying the PRSU to which such DER relates. Upon a PRSU vesting and becoming an
Earned PRSU, the DER (and the DER Account) regarding the Earned PRSU will become vested.
Similarly, on the forfeiture of a PRSU, the DER (and the DER Account) regarding the forfeited
PRSU will also be forfeited. DERs will not entitle the Participant to any payments relating to
dividends paid after the earlier to occur of the date that the Earned PRSU is settled under Section
4 or the forfeiture of the PRSU underlying such DER. Payments regarding vested DERs will be
made as soon as practicable following the applicable vesting date but within 60 days after such
vesting date. The Participant will not receive any interest regarding the payment of DERs. The
DERs and any amounts that may become payable in respect thereof will be treated separately
from the PRSUs for purposes of the Nonqualified Deferred Compensation Rules (including for
the designation of the time and form of payments required by the Nonqualified Deferred
Compensation Rules).
9.
No Right to Continued Employment or Awards. Nothing in the adoption of
the Plan, nor the grant of the PRSUs under the Grant Notice and this Agreement, will confer on
the Participant the right to continued employment or a service relationship with the Company or
affect the right of the Company to terminate such employment or service relationship. The grant
of the PRSUs is a one-time benefit and creates no contractual or other right to receive a grant of
Awards or benefits in lieu of Awards in the future. Any future Awards will be granted at the sole
discretion of the Company.
Exhibit A
10.
Notices. Notices hereunder will be mailed or delivered to the Company at its
principal place of business and will be mailed or delivered to the Participant at the address on file
with the Company or, in either case, at such other address as one party may furnish to the other
party in writing. Any notice delivered personally or by overnight courier or telecopier in the
manner provided will be deemed to have been duly given to the Participant when mailed by the
Company or, if such notice is not mailed to the Participant, on receipt by the Participant. Any
notice addressed and mailed in the manner herein provided will be conclusively presumed to
have been given to the party to whom it is addressed at the close of business, local time of the
recipient, on the fourth day after the day it is so placed in the mail.
11.
Consent to Electronic Delivery; Electronic Signature. In lieu of receiving
documents in paper format, the Participant agrees, to the fullest extent permitted by law, to
accept electronic delivery of any documents that the Company may have to deliver (including,
but not limited to, prospectuses, prospectus supplements, grant or award notifications and
agreements, account statements, annual and quarterly reports and all other forms of
communications) in connection with this and any other Award made or offered by the Company.
Electronic delivery may be via a Company electronic mail system or by reference to a location
on a Company intranet to which the Participant has access. The Participant consents to any
procedures the Company has established or may establish for an electronic signature system for
delivery and acceptance of any such documents that the Company may have to deliver, and
agrees that his or her electronic signature is the same as, and will have the same force and effect
as, his or her manual signature.
12.
Agreement to Furnish Information. The Participant agrees to furnish to the
Company all information requested by the Company to enable it to comply with any reporting or
other requirement imposed on the Company by or under any statute or regulation.
13.
Entire Agreement; Amendment. This Agreement constitutes the entire
agreement of the parties regarding the subject hereof, and contains all the covenants, promises,
representations, warranties and agreements between the parties regarding the granted PRSUs.
Without limiting the scope of the preceding sentence, except as provided herein, all prior
understandings and agreements among the parties relating to the subject hereof are hereby null
and void and of no further force and effect. The Participant acknowledges and agrees that this
Award supersedes and replaces in its entirety the option award described in that certain letter
agreement previously entered into between the Company and the Participant regarding the
engagement of the Participant as a member of the Board. The Committee may, in its sole
discretion, amend this Agreement from time to time in any manner that is not inconsistent with
the Plan; provided, however, that except as otherwise provided in the Plan or this Agreement,
any such amendment that materially reduces the rights of the Participant will be effective only if
it is in writing and signed by both the Participant and an authorized officer of the Company.
14.
Severability and Waiver. If a court of competent jurisdiction determines that
any provision of this Agreement is invalid or unenforceable, then the invalidity or
unenforceability of such provision shall not affect the validity or enforceability of any other
provision, and all other provisions will remain in full force and effect. Waiver by any party of
any breach of this Agreement or failure to exercise any right hereunder will not be deemed to be
a waiver of any other breach or right. The failure of any party to act by reason of such breach or
to exercise any such right will not deprive the party of the right to act at any time while or after
such breach or condition giving rise to such rights continues.
15.
Governing Law. THIS AGREEMENT WILL BE GOVERNED BY AND
CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE STATE OF DELAWARE
APPLICABLE TO CONTRACTS MADE AND TO BE PERFORMED THEREIN,
EXCLUSIVE OF THE CONFLICT OF LAWS PROVISIONS OF DELAWARE LAW.
Exhibit A
Regarding any claim or dispute related to or arising under this Agreement, Participant consents
to the exclusive jurisdiction, forum and venue of the state and federal courts (as applicable) in
Oklahoma. The parties waive, to the fullest extent permitted by law, any defenses to venue and
jurisdiction in Oklahoma.
16.
Successors and Assigns. The Company may assign any of its rights under this
Agreement without the Participant’s consent. This Agreement will be binding on and inure to
the benefit of the successors and assigns of the Company. Subject to the restrictions on transfer
set forth herein and in the Plan, this Agreement will be binding on the Participant and the
Participant’s beneficiaries, executors, administrators and the Person(s) to whom the PRSUs may
be transferred by will or the laws of descent or distribution.
17.
Headings. Headings are for convenience only and are not deemed part of this
Agreement.
18.
Counterparts. The Grant Notice may be executed in one or more counterparts,
each of which will be deemed an original and all of which together will constitute one
instrument. Delivery of an executed counterpart of the Grant Notice by facsimile or portable
document format (.pdf) attachment to electronic mail will be effective as delivery of a manually
executed counterpart of the Grant Notice.
19.
Section 409A. Notwithstanding anything herein or in the Plan to the contrary, the
PRSUs and the DERs granted under this Agreement are intended to comply with the
Nonqualified Deferred Compensation Rules or an exemption therefrom and will be limited,
construed and interpreted in accordance with such intent. Notwithstanding the foregoing, the
Company makes no representations that the PRSUs or the DERs provided under this Agreement
are exempt from or compliant with the Nonqualified Deferred Compensation Rules and the
Company will not or any of its Affiliates be liable for all or any portion of any taxes, penalties,
interest or other expenses that may be incurred by the Participant because of non-compliance
with the Nonqualified Deferred Compensation Rules. Each payment under this Agreement is
considered a separate payment for the Nonqualified Deferred Compensation Rules.
Exhibit A
EXHIBIT B
PERFORMANCE GOALS FOR PERFORMANCE RESTRICTED STOCK UNITS
The performance goals for (i) 50% of the Target PRSUs (the “Absolute TSR Portion”)
shall be based on the Company’s total stockholder return (“TSR”) during the Performance Period
(the “Absolute TSR PRSUs”) and (ii) 50% of the Target PRSUs (the “Relative TSR Portion”)
shall be based on the Company’s TSR relative to the Performance Peer Group (as defined below)
during the Performance Period (the “Relative TSR PRSUs”). The Committee, in its sole
discretion, shall have final authority to make factual determinations, interpret any ambiguities
and resolve any and all issues with respect to the Absolute TSR PRSUs, the Relative TSR
PRSUs and the Performance Goals.
Absolute TSR Performance Goal
For the Performance Period, the Committee, in its sole discretion, will review, analyze
and certify the Company’s TSR (expressed as a percentage) in order to determine the number of
Earned PRSUs with respect to the Absolute TSR Portion in accordance with the table below.
Performance Level
TSR (%) Earned PRSUs (% of Absolute TSR Portion)*
Below Threshold
<10%
0%
Threshold
10%
50%
Target
12.5%
100%
Maximum
15%
150%
*The Earned PRSUs for performance between two different performance levels shall be calculated using linear
interpolation.
Relative TSR Performance Goal
For the Performance Period, the Committee, in its sole discretion, will review, analyze and
certify the Company’s Relative TSR as compared to the Performance Peer Group in order to
determine the number of Earned PRSUs with respect to the Relative TSR Portion in accordance
with the table below.
Performance
Level
Relative TSR Percentile
Ranking
Earned PRSUs (% of Relative TSR
Portion)*
Below Threshold
<40th Percentile
0%
Threshold
40th Percentile
50%
Target
50th Percentile
100%
Maximum
65th Percentile
150%
*The Earned PRSUs for performance between two different performance levels shall be calculated using linear
interpolation.
To determine the Company’s Relative TSR percentile ranking for the Performance
Period, TSR will be calculated for the Company and each entity or fund in the Performance Peer
Exhibit B
Group as of the Performance Period End Date. The entities and funds in the Performance Peer
Group will be arranged by their respective TSR (highest to lowest) and the percentile ranking of
the Company within the Performance Peer Group will be determined.
Performance Peer Group
The following companies and funds will be deemed to be the Company’s “Performance
Peer Group” for purposes of the Relative TSR Portion:
Ticker Symbol
Company Name
AMPY
Amplify Energy Corp.
BRY
Berry Corporation
DEC
Diversified Energy Company PLC
HP
Helmerich & Payne, Inc.
ICD
Independence Contract Drilling, Inc.
MNR
Mach Natural Resources LP
NBR
Nabors Industries Ltd.
PTEN
Patterson-UTI Energy, Inc.
PDS
Precision Drilling Corporation
SD
SandRidge Energy, Inc.
Calculation of TSR
For purposes of this Exhibit B, TSR for the Company and each member of the
Performance Peer Group, as applicable, shall be equal to (“X” plus “Y”) divided by “Z”, where:
“X” is the difference between (i) the volume-weighted average closing price (the
“VWAP”) of the Company’s or such entity’s or fund’s common stock or other equity securities
for the 20 consecutive trading days immediately preceding the Performance Period End Date,
minus (ii) the VWAP of the Company’s or such entity’s or fund’s common stock or other equity
securities for the 20 consecutive trading days immediately following the Performance Period
Commencement Date;
“Y” is the cumulative amount of dividends and distributions (whether in the form of cash
or equity) paid in respect of the Company’s or such entity’s or fund’s common stock or other
equity securities during the Performance Period, assuming such dividends and distributions are
reinvested in additional shares of the Company’s or such entity’s common stock or other equity
securities; and
“Z” is the VWAP of the Company’s or such entity’s or fund’s common stock or other
equity securities for the 20 consecutive trading days immediately following the Performance
Period Commencement Date.
Exhibit B
Notwithstanding the foregoing, with respect to the Relative TSR Portion, the following
events shall be used to adjust the Performance Peer Group in response to changes in the
corporate structure of an entity in the Performance Peer Group:
1. If an entity in the Performance Peer Group spins-off a subsidiary, such spin-off
should be treated as a dividend.
2. If an entity in the Performance Peer Group is acquired prior to the first
anniversary of the Performance Period Commencement Date, the Committee shall
choose a replacement company to be added to the Performance Peer Group.
3. If an entity in the Performance Peer Group is acquired on or after the first
anniversary of the Performance Period Commencement Date, the TSR of such
entity shall be measured on the effective date of the consummation of such
acquisition.
4. In the event of a merger or other business combination of two Performance Peer
Group members (including, without limitation, the acquisition of one
Performance Peer Group member, or all or substantially all of its assets, by
another Performance Peer Group member), the surviving, resulting or successor
entity, as the case may be, shall continue to be treated as a member of the
Performance Peer Group, provided that the common stock (or similar equity
security) of such entity is listed or traded on a national securities exchange
through the last trading day of the Performance Period.
5. If an entity in the Performance Peer Group files for bankruptcy or liquidates due
to an insolvency or is delisted, the TSR of such entity shall be deemed to be
negative 100% (and if multiple members of the Performance Peer Group file for
bankruptcy or liquidate due to an insolvency or are delisted, such members shall
be ranked in order of when such bankruptcy or liquidation occurs, with earlier
bankruptcies, liquidations and delistings ranking lower than later bankruptcies,
liquidations and delistings).
6. Notwithstanding the foregoing, the Committee has discretion to make any
adjustments it deems necessary with respect to the Performance Peer Group.
Exhibit B
Exhibit 31.1 Certification of Principal Executive Officer
CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER
I, Phil Frohlich, Chief Executive Officer of Unit Corporation, certify that:
1.
I have reviewed this Annual Report of Unit Corporation;
2.
Based on my knowledge, this Annual Report does not contain any untrue statement of a material fact or omit to state a
material fact necessary to make the statements made, in light of the circumstances under which such statements were
made, not misleading with respect to the periods covered by this Annual Report; and
3.
Based on my knowledge, the financial statements, and other financial information included or incorporated by
reference in this Annual Report, fairly present in all material respects the financial condition, results of operations, and
cash flows of the issuer as of, and for, the periods presented in this Annual Report.
/s/ Phil Frohlich
Phil Frohlich
Chief Executive Officer
Date: March 13, 2025
Exhibit 31.2 Certification of Principal Financial Officer
CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER
I, Thomas D. Sell, Chief Financial Officer of Unit Corporation, certify that:
1.
I have reviewed this Annual Report of Unit Corporation;
2.
Based on my knowledge, this Annual Report does not contain any untrue statement of a material fact or omit to state a
material fact necessary to make the statements made, in light of the circumstances under which such statements were
made, not misleading with respect to the periods covered by this Annual Report; and
3.
Based on my knowledge, the financial statements, and other financial information included or incorporated by
reference in this Annual Report, fairly present in all material respects the financial condition, results of operations, and
cash flows of the issuer as of, and for, the periods presented in this Annual Report.
/s/ Thomas D. Sell
Thomas D. Sell
Chief Financial Officer
Date: March 13, 2025
UNIT CORPORATION
Estimated
Net Future Reserves
Attributable to Certain
Leasehold Interests
SEC Parameters
As of
December 31, 2024
/s/ Robert J. Paradiso
Robert J. Paradiso, P.E.
TBPELS License No. 111861
Senior Vice President
[SEAL]
RYDER SCOTT COMPANY, L.P.
TBPELS Firm Registration No. F-1580
TBPELS REGISTERED ENGINEERING FIRM F-1580
1100 LOUISIANA SUITE 4600
HOUSTON, TEXAS 77002-5294
TELEPHONE (713) 651-9191
January 27, 2025
Unit Corporation
8200 South Unit Drive
Tulsa, Oklahoma 74132
Ladies and Gentlemen:
At the request of Unit Corporation (Unit), Ryder Scott Company, L.P. (Ryder Scott) has
conducted a reserves audit of the estimates of the proved reserves as of December 31, 2024 prepared
by Unit’s engineering and geological staff based on the definitions and disclosure guidelines of the
United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal
Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the
Federal Register (SEC regulations). Our reserves audit, completed on January 27, 2025 and presented
herein, was prepared for public disclosure by Unit in filings made with the SEC in accordance with the
disclosure requirements set forth in the SEC regulations. The estimated reserves shown herein
represent Unit’s estimated net reserves attributable to the leasehold interests in certain properties
owned by Unit and the portion of those reserves reviewed by Ryder Scott, as of December 31, 2024.
The properties reviewed by Ryder Scott incorporate 253 reserves determinations and are located in the
states of Oklahoma and Texas. The wells for which estimates of reserves were audited by Ryder Scott
were selected by Unit. At Unit’s request, the reserves audit conducted by Ryder Scott addresses only
the proved developed producing reserves.
The properties reviewed by Ryder Scott account for a portion of Unit’s total net proved liquid
hydrocarbon and gas reserves as of December 31, 2024. Based on the estimates of total net proved
reserves prepared by Unit, the reserves audit conducted by Ryder Scott addresses approximately 81
percent of the total proved net reserves of Unit on a barrel of oil equivalent, BOE basis as of December
31, 2024.
The properties reviewed by Ryder Scott account for a portion of Unit’s total proved discounted
future net income using SEC hydrocarbon price parameters as of December 31, 2024. Based on the
reserves and income projections prepared by Unit, the audit conducted by Ryder Scott addresses
approximately 85 percent of the total proved discounted future net income at 10% of Unit as of
December 31, 2024.
As prescribed by the Society of Petroleum Engineers in Paragraph 2.2(f) of the Standards
Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (SPE auditing
PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES
Page 2
standards), a reserves audit is defined as “the process of reviewing certain of the pertinent facts
interpreted and assumptions made that have resulted in an estimate of reserves and/or Reserves
Information prepared by others and the rendering of an opinion about (1) the appropriateness of the
methodologies employed; (2) the adequacy and quality of the data relied upon; (3) the depth and
thoroughness of the reserves estimation process; (4) the classification of reserves appropriate to the
relevant definitions used; and (5) the reasonableness of the estimated reserves quantities and/or
Reserves Information.” Reserves Information may consist of various estimates pertaining to the extent
and value of petroleum properties.
Based on our review, including the data, technical processes and interpretations presented by
Unit, it is our opinion that the overall procedures and methodologies utilized by Unit in preparing their
estimates of the proved reserves as of December 31, 2024 comply with the current SEC regulations
and that the overall proved reserves for the reviewed properties as estimated by Unit are, in the
aggregate, reasonable within the established audit tolerance guidelines of 10 percent as set forth in the
SPE auditing standards.
The estimated reserves presented in this report are related to hydrocarbon prices. Unit has
informed us that in the preparation of their reserves and income projections, as of December 31, 2024,
they used average prices during the 12-month period prior to the “as of date” of this report, determined
as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each
month within such period, unless prices were defined by contractual arrangements, as required by the
SEC regulations. Unit has informed us they do not have any fixed price contractual arrangements.
Actual future prices may vary considerably from the prices required by SEC regulations. The reserves
volumes and the income attributable thereto have a direct relationship to the hydrocarbon prices
actually received; therefore, volumes of reserves actually recovered may differ significantly from the
estimated quantities presented in this report. The net reserves as estimated by Unit attributable to
Unit's interest in properties that we reviewed and for those that we did not review are summarized
below:
PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES
Page 3
SEC PARAMETERS
Estimated Net Reserves
Certain Leasehold Interests of
Unit Corporation
As of December 31, 2024
Total Proved
Developed
Producing
Net Reserves of Properties
Audited by Ryder Scott
Oil/Condensate – MBarrels
3,820
Plant Products – MBarrels
7,167
Gas – MMcf
68,090
MBOE
22,336
Net Reserves of Properties
Not Audited by Ryder Scott
Oil/Condensate – MBarrels
849
Plant Products – MBarrels
1,591
Gas – MMcf
17,475
MBOE
5,352
Total Net Reserves
Oil/Condensate – MBarrels
4,669
Plant Products – MBarrels
8,758
Gas – MMcf
85,565
MBOE
27,688
Liquid hydrocarbons are expressed in standard 42 U.S. gallon barrels and shown herein as
thousands of barrels (MBarrels). All gas volumes are reported on an “as sold basis” expressed in
millions of cubic feet (MMcf) at the official temperature and pressure bases of the areas in which the
gas reserves are located. The net reserves are also shown herein on an equivalent unit basis wherein
natural gas is converted to oil equivalent using a factor of 6,000 cubic feet of natural gas per one barrel
of oil equivalent. MBOE means thousand barrels of oil equivalent.
Reserves Included in This Report
In our opinion, the proved reserves presented in this report conform to the definition as set forth
in the Securities and Exchange Commission’s Regulations Part 210.4-10(a). An abridged version of the
SEC reserves definitions from 210.4-10(a) entitled “PETROLEUM RESERVES DEFINITIONS” is
included as an attachment to this report.
The various proved reserves status categories are defined in the attachment entitled
“PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES” in this report. No proved
developed non-producing or undeveloped reserves are included herein.
Reserves are “estimated remaining quantities of oil and gas and related substances anticipated
to be economically producible, as of a given date, by application of development projects to known
accumulations.” All reserves estimates involve an assessment of the uncertainty relating the likelihood
PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES
Page 4
that the actual remaining quantities recovered will be greater or less than the estimated quantities
determined as of the date the estimate is made. The uncertainty depends primarily on the amount of
reliable geologic and engineering data available at the time of the estimate and the interpretation of
these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two
principal categories, either proved or unproved. Unproved reserves are less certain to be recovered
than proved reserves and may be further sub-categorized as probable and possible reserves to denote
progressively increasing uncertainty in their recoverability. At Unit’s request, this report addresses only
the proved reserves attributable to the properties reviewed herein.
Proved oil and gas reserves are “those quantities of oil and gas which, by analysis of
geoscience and engineering data, can be estimated with reasonable certainty to be economically
producible from a given date forward.” The proved reserves included herein were estimated using
deterministic methods. The SEC has defined reasonable certainty for proved reserves, when based on
deterministic methods, as a “high degree of confidence that the quantities will be recovered.”
Proved reserves estimates will generally be revised only as additional geologic or engineering
data become available or as economic conditions change. For proved reserves, the SEC states that
“as changes due to increased availability of geoscience (geological, geophysical, and geochemical),
engineering, and economic data are made to the estimated ultimate recovery (EUR) with time,
reasonably certain EUR is much more likely to increase or remain constant than to decrease.”
Moreover, estimates of proved reserves may be revised as a result of future operations, effects of
regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved reserves
included in this report are estimates only and should not be construed as being exact quantities. They
may or may not be actually recovered, and if recovered, could be more or less than the estimated
amounts.
Audit Data, Methodology, Procedure and Assumptions
The estimation of reserves involves two distinct determinations. The first determination results
in the estimation of the quantities of recoverable oil and gas and the second determination results in the
estimation of the uncertainty associated with those estimated quantities in accordance with the
definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a). The
process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain
generally accepted analytical procedures. These analytical procedures fall into three broad categories
or methods: (1) performance-based methods; (2) volumetric-based methods; and (3) analogy. These
methods may be used individually or in combination by the reserves evaluator in the process of
estimating the quantities of reserves. Reserves evaluators must select the method or combination of
methods which in their professional judgment is most appropriate given the nature and amount of
reliable geoscience and engineering data available at the time of the estimate, the established or
anticipated performance characteristics of the reservoir being evaluated and the stage of development
or producing maturity of the property.
In many cases, the analysis of the available geoscience and engineering data and the
subsequent interpretation of this data may indicate a range of possible outcomes in an estimate,
irrespective of the method selected by the evaluator. When a range in the quantity of reserves is
identified, the evaluator must determine the uncertainty associated with the incremental quantities of
the reserves. If the reserves quantities are estimated using the deterministic incremental approach, the
uncertainty for each discrete incremental quantity of the reserves is addressed by the reserves category
assigned by the evaluator. Therefore, it is the categorization of reserves quantities as proved, probable
PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES
Page 5
and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For
proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities
actually recovered are much more likely to be achieved than not.” The SEC states that “probable
reserves are those additional reserves that are less certain to be recovered than proved reserves but
which, together with proved reserves, are as likely as not to be recovered.” The SEC states that
“possible reserves are those additional reserves that are less certain to be recovered than probable
reserves and the total quantities ultimately recovered from a project have a low probability of exceeding
proved plus probable plus possible reserves.” All quantities of reserves within the same reserves
category must meet the SEC definitions as noted above.
Estimates of reserves quantities and their associated reserves categories may be revised in the
future as additional geoscience or engineering data become available. Furthermore, estimates of
reserves quantities and their associated reserves categories may also be revised due to other factors
such as changes in economic conditions, results of future operations, effects of regulation by
governmental agencies or geopolitical or economic risks as previously noted herein.
The reserves prepared by Unit for the properties that we reviewed were estimated by
performance methods. These performance methods include, but may not be limited to, decline curve
analysis, which utilized extrapolations of historical production and pressure data available through
October 2024 in those cases where such data were considered to be definitive. The data used in these
analyses were furnished to Ryder Scott by Unit or obtained from public data sources and were
considered sufficient for the purpose thereof.
To estimate economically producible proved oil and gas reserves, many factors and
assumptions are considered including, but not limited to, the use of reservoir parameters derived from
geological, geophysical and engineering data which cannot be measured directly, economic criteria
based on current costs and SEC pricing requirements, and forecasts of future production rates. Under
the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be
economically producible from a given date forward based on existing economic conditions including the
prices and costs at which economic producibility from a reservoir is to be determined. While it may
reasonably be anticipated that the future prices received for the sale of production and the operating
costs and other costs relating to such production may increase or decrease from those under existing
economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from
consideration in conducting this review.
As stated previously, proved reserves must be anticipated to be economically producible from a
given date forward based on existing economic conditions including the prices and costs at which
economic producibility from a reservoir is to be determined. To confirm that the proved reserves
reviewed by us meet the SEC requirements to be economically producible, we have reviewed certain
primary economic data utilized by Unit relating to hydrocarbon prices and costs as noted herein.
The hydrocarbon prices furnished by Unit for the properties reviewed by us are based on SEC
price parameters using the average prices during the 12-month period prior to the “as of date” of this
report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-
month for each month within such period, unless prices were defined by contractual arrangements. For
hydrocarbon products sold under contract, the contract prices, including fixed and determinable
escalations exclusive of inflation adjustments, were used until expiration of the contract. Upon contract
expiration, the prices were adjusted to the 12-month unweighted arithmetic average as previously
described.
PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES
Page 6
The initial SEC hydrocarbon benchmark prices in effect on December 31, 2024 for the
properties reviewed by us were determined using the 12-month average first-day-of-the-month
benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These
benchmark prices are prior to the adjustments for differentials as described herein. The table below
summarizes the “benchmark prices” and “price reference” used by Unit for the geographic area
reviewed by us. The price reference and benchmark prices may be defined by contractual
arrangements.
The product prices that were actually used by Unit to determine the future gross revenue for
each property reviewed by us reflect adjustments to the benchmark prices for gravity, quality, local
conditions, and/or distance from market, referred to herein as “differentials.” The differentials used by
Unit were accepted as factual data and reviewed by us for their reasonableness; however, we have not
conducted an independent verification of the data used by Unit.
The table below summarizes Unit’s net volume weighted benchmark prices adjusted for
differentials for the properties reviewed by us and referred to herein as Unit’s “average realized prices.”
The average realized prices shown in the table below were determined from Unit’s estimate of the total
future gross revenue before production taxes for the properties reviewed by us and Unit’s estimate of
the total net reserves for the properties reviewed by us for the geographic area. The data shown in the
table below is presented in accordance with SEC disclosure requirements for the geographic area
reviewed by us.
Geographic Area
Product
Price
Reference
Average
Benchmark
Prices
Average
Realized
Prices
United States
Oil/Condensate
WTI Cushing
$75.48/bbl
$74.11/bbl
NGLs
WTI Cushing
$75.48/bbl
$23.11/bbl
Gas
Henry Hub
$2.13/MMBTU
$1.86/Mcf
The effects of derivative instruments designated as price hedges of oil and gas quantities are
not reflected in Unit’s individual property evaluations.
Accumulated gas production imbalances, if any, were not taken into account in the proved gas
reserves estimates reviewed. The proved gas volumes presented herein do not include volumes of gas
consumed in operations as reserves.
Operating costs furnished by Unit are based on the operating expense reports of Unit and
include only those costs directly applicable to the leases or wells for the properties reviewed by us. The
operating costs include a portion of general and administrative costs allocated directly to the leases and
wells. For operated properties, the operating costs include an appropriate level of corporate general
administrative and overhead costs. The operating costs for non-operated properties include the
COPAS overhead costs that are allocated directly to the leases and wells under terms of operating
agreements. Transportation fees are included as operating cost deductions. The operating costs
furnished by Unit were accepted as factual data and reviewed by us for their reasonableness using
information provided by Unit; however, we have not conducted an independent verification of the data
used by Unit. No deduction was made for loan repayments, interest expenses, or exploration and
development prepayments that were not charged directly to the leases or wells.
PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES
Page 7
Unit has informed us that abandonment costs are reported outside of this report; therefore, their
projection of future net income associated with the reserve projections does not reflect abandonment
costs.
Current costs used by Unit were held constant throughout the life of the properties.
Unit’s forecasts of future production rates are based on historical performance. If no production
decline trend has been established, future production rates were held constant until a decline in ability
to produce was anticipated. An estimated rate of decline was then applied until depletion of the
reserves. If a decline trend has been established, this trend was used as the basis for estimating future
production rates.
The future production rates may be more or less than estimated because of changes including,
but not limited to, reservoir performance, operating conditions related to surface facilities, compression
and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or
allowables or other constraints set by regulatory bodies.
Unit’s operations may be subject to various levels of governmental controls and regulations.
These controls and regulations may include, but may not be limited to, matters relating to land tenure
and leasing, the legal rights to produce hydrocarbons, drilling and production practices, environmental
protection, marketing and pricing policies, royalties, various taxes and levies including income tax and
are subject to change from time to time. Such changes in governmental regulations and policies may
cause volumes of proved reserves actually recovered and amounts of proved income actually received
to differ significantly from the estimated quantities.
The estimates of proved reserves presented herein were based upon a review of the properties
in which Unit owns an interest; however, we have not made any field examination of the properties. No
consideration was given in this report to potential environmental liabilities that may exist nor were any
costs included by Unit for potential liabilities to restore and clean up damages, if any, caused by past
operating practices.
Certain technical personnel of Unit are responsible for the preparation of reserves estimates on
new properties and for the preparation of revised estimates, when necessary, on old properties. These
personnel assembled the necessary data and maintained the data and workpapers in an orderly
manner. We consulted with these technical personnel and had access to their workpapers and
supporting data in the course of our audit.
Unit has informed us that they have furnished us all of the material accounts, records, geological
and engineering data, and reports and other data required for this investigation. In performing our audit
of Unit’s forecast of future proved production, we have relied upon data furnished by Unit with respect
to property interests owned, production and well tests from examined wells, normal direct costs of
operating the wells or leases, other costs such as transportation and/or processing fees, ad valorem
and production taxes, product prices based on the SEC regulations, adjustments or differentials to
product prices, and pressure measurements. Ryder Scott reviewed such factual data for its
reasonableness; however, we have not conducted an independent verification of the data furnished by
Unit. We consider the factual data furnished to us by Unit to be appropriate and sufficient for the
purpose of our review of Unit’s estimates of reserves. In summary, we consider the assumptions, data,
methods and analytical procedures used by Unit and as reviewed by us appropriate for the purpose
hereof, and we have used all such methods and procedures that we consider necessary and
appropriate under the circumstances to render the conclusions set forth herein.
PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES
Page 8
Audit Opinion
Based on our review, including the data, technical processes and interpretations presented by
Unit, it is our opinion that the overall procedures and methodologies utilized by Unit in preparing their
estimates of the proved reserves as of December 31, 2024 comply with the current SEC regulations
and that the overall proved reserves for the reviewed properties as estimated by Unit are, in the
aggregate, reasonable within the established audit tolerance guidelines of 10 percent as set forth in the
SPE auditing standards. Ryder Scott found the processes and controls used by Unit in their estimation
of proved reserves to be effective and, in the aggregate, we found no bias in the utilization and analysis
of data in estimates for these properties.
We were in reasonable agreement with Unit's estimates of proved reserves for the properties
which we reviewed; although in certain cases there was more than an acceptable variance between
Unit's estimates and our estimates due to a difference in interpretation of data or due to our having
access to data which were not available to Unit when its reserves estimates were prepared. However
notwithstanding, it is our opinion that on an aggregate basis the data presented herein for the properties
that we reviewed fairly reflects the estimated net reserves owned by Unit.
Other Properties
Other properties, as used herein, are those properties of Unit which we did not review. The
proved net reserves attributable to the other properties account for approximately 19 percent of the total
proved net liquid hydrocarbon and gas reserves of Unit on a barrel of oil equivalent, BOE basis, based
on estimates prepared by Unit as of December 31, 2024. The other properties represent approximately
15 percent of the total proved discounted future net income at 10% based on the unescalated pricing
policy of the SEC as taken from reserves and income projections prepared by Unit as of December 31,
2024.
The same technical personnel of Unit were responsible for the preparation of the reserves
estimates for the properties that we reviewed as well as for the properties not reviewed by Ryder Scott.
Standards of Independence and Professional Qualification
Ryder Scott is an independent petroleum engineering consulting firm that has been providing
petroleum consulting services throughout the world since 1937. Ryder Scott is employee-owned and
maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have
approximately eighty engineers and geoscientists on our permanent staff. By virtue of the size of our
firm and the large number of clients for which we provide services, no single client or job represents a
material portion of our annual revenue. We do not serve as officers or directors of any privately-owned
or publicly-traded oil and gas company and are separate and independent from the operating and
investment decision-making process of our clients. This allows us to bring the highest level of
independence and objectivity to each engagement for our services.
Ryder Scott actively participates in industry-related professional societies and organizes an
annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our
staff have authored or co-authored technical papers on the subject of reserves related topics. We
PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES
Page 9
encourage our staff to maintain and enhance their professional skills by actively participating in ongoing
continuing education.
Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and
geoscientists receive professional accreditation in the form of a registered or certified professional
engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent
thereof, from an appropriate governmental authority or a recognized self-regulating professional
organization. Regulating agencies require that, in order to maintain active status, a certain amount of
continuing education hours be completed annually, including an hour of ethics training. Ryder Scott
fully supports this technical and ethics training with our internal requirement mentioned above.
We are independent petroleum engineers with respect to Unit. Neither we nor any of our
employees have any financial interest in the subject properties, and neither the employment to do this
work nor the compensation is contingent on our estimates of reserves for the properties which were
reviewed.
The results of this audit, presented herein, are based on technical analyses conducted by teams
of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned,
the technical person primarily responsible for overseeing, reviewing and approving the review of the
reserves information discussed in this report, are included as an attachment to this letter.
Terms of Usage
The results of our third party audit, presented in report form herein, were prepared in
accordance with the disclosure requirements set forth in the SEC regulations and intended for public
disclosure as an exhibit in filings made with the SEC by Unit.
We have provided Unit with a digital version of the original signed copy of this report letter. In
the event there are any differences between the digital version included in filings made by Unit and the
original signed report letter, the original signed report letter shall control and supersede the digital
version.
PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES
Page 10
The data and work papers used in the preparation of this report are available for examination by
authorized parties in our offices. Please contact us if we can be of further service.
Very truly yours,
RYDER SCOTT COMPANY, L.P.
TBPELS Firm Registration No. F-1580
/s/ Robert J. Paradiso
Robert J. Paradiso, P.E.
TBPELS License No. 111861
Senior Vice President
[SEAL]
RJP (GR)/pl
PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES
Page 11
Professional Qualifications of Primary Technical Person
The conclusions presented in this report are the result of technical analysis conducted by teams of
geoscientists and engineers from Ryder Scott Company, L.P. Robert J. Paradiso was the primary
technical person responsible for overseeing the estimate of the reserves, future production and income
prepared by Ryder Scott presented herein.
Mr. Paradiso, an employee of Ryder Scott Company L.P. (Ryder Scott) since 2008, is a Senior Vice
President and also serves as Project Coordinator, responsible for coordinating and supervising staff
and consulting engineers of the company in ongoing reservoir evaluation studies worldwide. Before
joining Ryder Scott, Mr. Paradiso served in a number of 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. For
more information regarding Mr. Paradiso’s geographic and job specific experience, please refer to the
Ryder Scott Company website at https://ryderscott.com/employees.
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.
In addition to gaining experience and competency through prior work experience, the Texas Board of
Professional Engineers requires a minimum of fifteen hours of continuing education annually, including
at least one hour in the area of professional ethics, which Mr. Paradiso fulfills. As part of his 2024
continuing education hours, Mr. Paradiso attended 6 hours of formalized training during the 2024 RSC
Reserves Conference relating to the definitions and disclosure guidelines contained 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 43½ hours of formalized in-house training during 2024 covering such topics as
the SPE/WPC/AAPG/SPEE Petroleum Resources Management System, SEC comment letters, carbon
storage, geothermal energy, reservoir engineering, geoscience and petroleum economics evaluation
methods and procedures, and ethics for consultants.
Based on his educational background, professional training and more than 45 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 Society of Petroleum Engineers as of June 2019.
PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES
Page 12
PETROLEUM RESERVES DEFINITIONS
As Adapted From:
RULE 4-10(a) of REGULATION S-X PART 210
UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)
PREAMBLE
On January 14, 2009, the United States Securities and Exchange Commission (SEC) published
the “Modernization of Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives
and Records Administration (NARA). The “Modernization of Oil and Gas Reporting; Final Rule”
includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and
additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry
Guide 2 in Regulation S-K. The “Modernization of Oil and Gas Reporting; Final Rule”, including all
references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC
regulations”. The SEC regulations take effect for all filings made with the United States Securities and
Exchange Commission as of December 31, 2009, or after January 1, 2010. Reference should be made
to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for
the complete definitions (direct passages excerpted in part or wholly from the aforementioned SEC
document are denoted in italics herein).
Reserves are estimated remaining quantities of oil and gas and related substances anticipated
to be economically producible, as of a given date, by application of development projects to known
accumulations. All reserve estimates involve an assessment of the uncertainty relating the likelihood
that the actual remaining quantities recovered will be greater or less than the estimated quantities
determined as of the date the estimate is made. The uncertainty depends primarily on the amount of
reliable geologic and engineering data available at the time of the estimate and the interpretation of
these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two
principal categories, either proved or unproved. Unproved reserves are less certain to be recovered
than proved reserves and may be further sub-categorized as probable and possible reserves to denote
progressively increasing uncertainty in their recoverability. Under the SEC regulations as of
December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities
of probable or possible oil and gas reserves in documents publicly filed with the SEC. The SEC
regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and
any estimated values of such resources in any document publicly filed with the SEC unless such
information is required to be disclosed in the document by foreign or state law as noted in §229.1202
Instruction to Item 1202.
Reserves estimates will generally be revised only as additional geologic or engineering data
become available or as economic conditions change.
PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES
Page 13
Reserves may be attributed to either natural energy or improved recovery methods. Improved
recovery methods include all methods for supplementing natural energy or altering natural forces in the
reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, natural
gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible
displacement fluids. Other improved recovery methods may be developed in the future as petroleum
technology continues to evolve.
Reserves may be attributed to either conventional or unconventional petroleum accumulations.
Petroleum accumulations are considered as either conventional or unconventional based on the nature
of their in-place characteristics, extraction method applied, or degree of processing prior to sale.
Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/
CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These
unconventional accumulations may require specialized extraction technology and/or significant
processing prior to sale.
Reserves do not include quantities of petroleum being held in inventory.
Because of the differences in uncertainty, caution should be exercised when aggregating
quantities of petroleum from different reserves categories.
RESERVES (SEC DEFINITIONS)
Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as
follows:
Reserves. Reserves are estimated remaining quantities of oil and gas and related substances
anticipated to be economically producible, as of a given date, by application of development projects to
known accumulations. In addition, there must exist, or there must be a reasonable expectation that
there will exist, the legal right to produce or a revenue interest in the production, installed means of
delivering oil and gas or related substances to market, and all permits and financing required to
implement the project.
Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major,
potentially sealing, faults until those reservoirs are penetrated and evaluated as economically
producible. Reserves should not be assigned to areas that are clearly separated from a known
accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or
negative test results). Such areas may contain prospective resources (i.e., potentially recoverable
resources from undiscovered accumulations).
PROVED RESERVES (SEC DEFINITIONS)
Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and
gas reserves as follows:
Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which,
by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be
economically producible—from a given date forward, from known reservoirs, and under existing
economic conditions, operating methods, and government regulations—prior to the time at which
contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably
PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES
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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.
(i) The area of the reservoir considered as proved includes:
(A) The area identified by drilling and limited by fluid contacts, if any, and
(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be
judged to be continuous with it and to contain economically producible oil or gas on the
basis of available geoscience and engineering data.
(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the
lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience,
engineering, or performance data and reliable technology establishes a lower contact with
reasonable certainty.
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PROVED RESERVES (SEC DEFINITIONS) CONTINUED
(iii) Where direct observation from well penetrations has defined a highest known oil (HKO)
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 geoscience, engineering, or
performance data and reliable technology establish the higher contact with reasonable certainty.
(iv) 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:
(A) Successful testing by a pilot project in an area of the reservoir with properties no
more favorable than in the reservoir as a whole, the operation of an installed program in
the reservoir or an analogous reservoir, or other evidence using reliable technology
establishes the reasonable certainty of the engineering analysis on which the project or
program was based; and
(B) The project has been approved for development by all necessary parties and entities,
including governmental entities.
(v) Existing economic conditions include prices and costs at which economic producibility from a
reservoir is to be determined. The price shall be the average price during the 12-month period
prior to the ending date of the period covered by the report, determined as an unweighted
arithmetic average of the first-day-of-the-month price for each month within such period, unless
prices are defined by contractual arrangements, excluding escalations based upon future
conditions.
PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES
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PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES
As Adapted From:
RULE 4-10(a) of REGULATION S-X PART 210
UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)
and
2018 PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)
Sponsored and Approved by:
SOCIETY OF PETROLEUM ENGINEERS (SPE)
WORLD PETROLEUM COUNCIL (WPC)
AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)
SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)
SOCIETY OF EXPLORATION GEOPHYSICISTS (SEG)
SOCIETY OF PETROPHYSICISTS AND WELL LOG ANALYSTS (SPWLA)
EUROPEAN ASSOCIATION OF GEOSCIENTISTS & ENGINEERS (EAGE)
Reserves status categories define the development and producing status of wells and
reservoirs. Reference should be made to Title 17, Code of Federal Regulations, Regulation S-X Part
210, Rule 4-10(a) and the SPE-PRMS as the following reserves status definitions are based on
excerpts from the original documents (direct passages excerpted from the aforementioned SEC and
SPE-PRMS documents are denoted in italics herein).
DEVELOPED RESERVES (SEC DEFINITIONS)
Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil
and gas reserves as follows:
Developed oil and gas reserves are reserves of any category that can be expected to be
recovered:
(i) 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
(ii) Through installed extraction equipment and infrastructure operational at the time of
the reserves estimate if the extraction is by means not involving a well.
Developed Producing (SPE-PRMS Definitions)
While not a requirement for disclosure under the SEC regulations, developed oil and gas
reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as
Producing or Non-Producing.
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Developed Producing Reserves
Developed Producing Reserves are expected quantities to be recovered from completion
intervals that are open and producing at the effective date of the estimate.
Improved recovery reserves are considered producing only after the improved recovery project
is in operation.
Developed Non-Producing
Developed Non-Producing Reserves include shut-in and behind-pipe Reserves.
Shut-In
Shut-in Reserves are expected to be recovered from:
(1) completion intervals that are open at the time of the estimate but which have not yet
started producing;
(2) wells which were shut-in for market conditions or pipeline connections; or
(3) wells not capable of production for mechanical reasons.
Behind-Pipe
Behind-pipe Reserves are expected to be recovered from zones in existing wells that will require
additional completion work or future re-completion before start of production with minor cost to
access these reserves.
In all cases, production can be initiated or restored with relatively low expenditure compared to
the cost of drilling a new well.
UNDEVELOPED RESERVES (SEC DEFINITIONS)
Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil
and gas reserves as follows:
Undeveloped oil and gas reserves are reserves of any category that are expected to be
recovered from new wells on undrilled acreage, or from existing wells where a relatively major
expenditure is required for recompletion.
(i)
Reserves on undrilled acreage shall be limited to those directly offsetting
development spacing areas that are reasonably certain of production when drilled,
unless evidence using reliable technology exists that establishes reasonable certainty of
economic producibility at greater distances.
(ii) 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.
(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to
any acreage for which an application of fluid injection or other improved recovery
technique is contemplated, unless such techniques have been proved effective by actual
projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2)
of this section, or by other evidence using reliable technology establishing reasonable
certainty.
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