UNIT CORPORATION Please read this discussion of our financial condition and results of operations with the consolidated financial statements and related notes in Item 8 of this report. Introduction
We operate, manage, and analyze our results of operations through our three principal business segments:
•Oil and Natural Gas - carried out by our subsidiary
•Contract Drilling - carried out by our subsidiaryUnit Drilling Company . This segment contracts to drill onshore oil and natural gas wells for others and for our own account. •Mid-Stream - carried out by Superior and its subsidiaries. This segment buys, sells, gathers, processes, and treats natural gas for third parties and for our own account. We hold a 50% investment in Superior.
In our oil and natural gas segment, we are optimizing production and converting non-producing reserves to producing with selective drilling activities. We also anticipate continuing to hedge a portion of our future production depending on future market pricing among other factors.
Contract Drilling
In our contract drilling segment, we are focused on maintaining utilization of our drilling rigs in a safe and efficient manner. All 14 of our BOSS drilling rigs are currently operating. Most of our drilling rigs are contracted for periods of 12 months or less. During the fourth quarter of 2022, contracts on five BOSS drilling rigs repriced at higher dayrates. We expect that contracts on 11 BOSS drilling rigs will be up for change or renegotiation betweenDecember 31, 2022 andJune 30, 2023 . EffectiveDecember 31, 2022 , we reduced the number of total rigs available for use from 21 to 18, reflecting the current market outlook for utilization of SCR rigs.
Mid-Stream
In our mid-stream segment, Superior is focused on continuing to generate predictable free cash flows with limited exposure to commodity prices in addition to seeking business development opportunities in its core areas utilizing the Superior credit agreement (which Unit is not a party to and does not guarantee) or other financing sources that are available to it. We hold a 50% investment in Superior, and subsequent to the deconsolidation of Superior as ofMarch 1, 2022 , we report our ownership interest as an equity method investment. The following discussion of financial condition and results of operations pertaining to our mid-stream segment during the year endedDecember 31, 2022 relates to the two months of consolidated results prior to deconsolidation as ofMarch 1, 2022 .
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
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Oil, natural gas, and NGL pricing generally improved during 2021 and much of
2022 as demand recovered from the COVID-19 pandemic while oil supply was
negatively impacted by the conflict between Russia and Ukraine as well as
restrained production growth from OPEC+, among other factors. Prices generally
declined later in 2022 due to growing economic uncertainty and recession
concerns and improved supply, among other factors. Commodity prices have been
volatile in recent years and the outlook for future oil and gas prices remains
uncertain and subject to many factors. The following chart reflects the
significant fluctuations in the historical prices for oil and natural gas:
[[Image Removed: unt-20221231_g2.jpg]] The following chart reflects the significant fluctuations in the prices for NGLs(1):
[[Image Removed: unt-20221231_g3.jpg]]
1.NGL prices reflect the monthly average Mont Belvieu price.
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Common Stock Dividends
OnJanuary 5, 2023 , the Company announced the declaration of a special cash dividend of$10.00 per share and has approved a quarterly cash dividend policy beginning in the Company's second quarter. The special dividend was paid onJanuary 31, 2023 , to stockholders of record as of the close of business onJanuary 20, 2023 . The initial quarterly dividend will be$2.50 per share to be paid on a date in the Company's second quarter that is yet to be determined. Subsequent quarterly dividends will be issued on a variable rate per share basis as determined by the Company. The special and quarterly cash dividends will be funded by cash on the Company's balance sheet. 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.
Stock Repurchase Activity
The table below presents the common stock repurchase activity during the periods
indicated:
Shares Purchase Price Price per Share
(in thousands, except for per share amounts)
2022
Repurchase Program 522,429 $ 27,421 $ 52.49
Total Repurchases 522,429 $ 27,421 $ 52.49
2021
Repurchase Program 1,271,963 $ 41,430 $ 32.57
Lender Repurchases 600,000 $ 9,000 $ 15.00
Other Repurchases 78,000 $ 1,487 $ 19.07
Total Repurchases 1,949,963 $ 51,917 $ 26.62
As of
Warrants
Each holder of Unit common stock outstanding (Old Common Stock) before theSeptember 3, 2020 emergence from bankruptcy (Emergence Date) that did not opt out of the release under the Chapter 11 plan (as amended, supplemented and modified from time to time, the "Plan") of reorganization filed with the bankruptcy court onJune 9, 2020 is entitled to receive 0.03460447 warrants for every share of Old Common Stock owned. Each warrant is exercisable for one share of common stock, subject to adjustment as provided in the Warrant Agreement. The warrants expire on the earliest of (i)September 3, 2027 , (ii) consummation of a Cash Sale (as defined in the Warrant Agreement), or (iii) the consummation of a liquidation, dissolution or winding up of the Company. As ofDecember 31, 2022 , the Company had authorized 1,822,231 warrants and none had been exercised. Pursuant to the terms of the Warrant Agreement, the Company determined the initial exercise price of the warrants to be$63.74 . OnApril 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 aboutApril 25, 2022 , the warrants began trading over-the-counter under the symbol "UNTCW". 36 --------------------------------------------------------------------------------
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Superior MSA and LLC amendments
EffectiveMarch 1, 2022 , the employees of the Operator were transferred to Superior and the MSA was amended and restated to remove the operating services the Operator was providing to Superior. There was no change to the monthly service fee for shared services. We no longer consolidate the financial position, operating results, and cash flows of Superior as of, and subsequent to,March 1, 2022 . We recognized a$13.1 million loss on deconsolidation during the twelve months endedDecember 31, 2022 as the difference between the$1.7 million estimated fair value of our retained equity method investment in Superior as ofMarch 1, 2022 and Superior's net equity attributable to Unit's ownership interest prior to deconsolidation. We subsequently account for our investment in Superior as an equity method investment using the hypothetical liquidation book value (HLBV) method which is a balance sheet approach that calculates the change in the hypothetical amount Unit and SP Investor would be entitled to receive if Superior were liquidated at book value at the end of each period, adjusted for any contributions made and distributions received during the period. OnFebruary 21, 2023 , we entered into a letter agreement (the "Letter Agreement") with SP Investor under which the Company has agreed to sell all of its 50% ownership interest in Superior for$20.0 million . The Letter Agreement provides that SP Investor will pay Unit$12.0 million at closing and$8.0 million in deferred proceeds to be paid no later than 12 months from closing, subject to Unit's satisfaction of certain ongoing covenant obligations and other customary conditions.
Officer Departure and Appointments
OnFebruary 23, 2023 ,Philip B. Smith notified the Company's Board of Directors of his decision to step down as President and Chief Executive Officer of the Company effectiveMarch 31, 2023 . His decision to step down was due to his desire to spend more time working on his nonprofit projects and other endeavors.Mr. Smith will continue to serve as Chairman of the Board of Directors. In connection withMr. Smith stepping down as President and CEO, the Board of Directors has approved (i) a pro-rated vesting of his outstanding time-based equity awards scheduled to vest on the next applicable vesting date based on the number of days worked during the then-current vesting period, and (ii) extending the time thatMr. Smith can exercise his options to the expiration date set forth in his award agreement governing the options. To fill the vacancy created byMr. Smith's resignation, onFebruary 28, 2023 , the Board of Directors appointedPhil Frohlich as interim Chief Executive Officer, effectiveApril 1, 2023 , until the Board of Directors names a successor.Mr. Frohlich has been a member of the Board of Directors sinceSeptember 3, 2020 . Additional information aboutMr. Frohlich is contained in Part III of this Annual Report.
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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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, 2022 covered reserves that we projected to comprise 86% 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 I, Item 1 of this 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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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, 2022 , our reserves were calculated based on
applying 12-month 2022 average unescalated prices of $93.67 per barrel of oil
and $6.36 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.
Impairment of Other Property and Equipment. We review the carrying amounts of
long-lived assets for potential impairment when events occur or changes in
circumstances suggest these carrying amounts may not be recoverable. Changes
that could prompt an assessment include equipment obsolescence, changes in the
market demand for a specific asset, changes in commodity prices, periods of
relatively low drilling rig utilization, declining revenue per day, declining
cash margin per day, or overall changes in general market conditions. Assets are
determined to be impaired if a forecast of undiscounted estimated future net
operating cash flows directly related to the asset, including disposal value if
any, is less than the carrying amount of the asset. If any asset is determined
to be impaired, the loss is measured as the amount by which the carrying asset
exceeds its fair value. The estimate of fair value is based on the best
information available, including prices for similar assets. Changes in these
estimates could cause us to reduce the carrying value of property and equipment.
Asset impairment evaluations are, by nature, highly subjective. They involve
expectations about future cash flows generated by our assets and reflect our
assumptions and judgments regarding future industry conditions and their effect
on future utilization levels, dayrates, and costs. Using different estimates and
assumptions could result in materially different carrying values of our assets.
Asset Retirement Obligations. We are required to record the estimated fair value
of the liabilities relating to the future retirement of our long-lived assets.
Our oil and natural gas wells are plugged and abandoned when the oil and natural
gas reserves in those wells are depleted or the wells are no longer able to
produce. The estimated liabilities related to these future costs are recorded at
the time the wells are drilled or acquired. We use historical experience to
determine the estimated plugging costs considering the well's type, depth,
physical location, and ultimate productive life. A risk-adjusted discount rate
and an inflation factor are applied to estimate the present value of these
obligations. We depreciate the capitalized asset retirement cost and accrete the
obligation over time. Revisions to the obligations and assets are recognized at
the appropriate risk-adjusted discount rate with a corresponding adjustment made
to the full cost pool. Our mid-stream segment has property and equipment at
locations leased or under right of way agreements which may require asset
removal or site restoration, however, we are not able to reasonably measure the
fair value of the obligations as the potential settlement dates are
indeterminable.
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 those drilling rigs; and
•the fees and margins we obtain from our natural gas gathering and processing contracts.
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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The table below summarizes cash flow activity during the periods indicated:
Year Ended December 31, Percent
2022 2021 Change
(In thousands except percentages)
Net cash provided by operating activities $ 159,421 $ 175,969 (9) %
Net cash provided by investing activities 28,896 36,205 (20) %
Net cash used in financing activities (38,482) (160,748) (76) %
Net increase in cash and cash equivalents $ 149,835 $ 51,426
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 Superior's mid-stream services, and the rates charged for those drilling and mid-stream services. Our cash flows from operating activities are also affected by changes in working capital. Net cash provided by operating activities during the year endedDecember 31, 2022 decreased by$16.5 million as compared to the year endedDecember 31, 2021 primarily due to higher payments on derivative settlements and the absence of operating cash flows from Superior subsequent to theMarch 1, 2022 deconsolidation, partially offset by higher operating cash flows from our oil and natural gas and contract drilling segments.
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 investing activities decreased by$7.3 million during the year endedDecember 31, 2022 compared to the year endedDecember 31, 2021 primarily due to the deconsolidation of Superior's cash and cash equivalents and lower proceeds received from the disposition of non-core property and equipment, partially offset by lower capital expenditures. Capital expenditures decreased primarily due to lower spend from Superior due to itsMarch 1, 2022 deconsolidation and the absence of Superior's 2021 gathering and processing system acquisition, partially offset by higher capital spend in our contract drilling and oil and natural gas segments.
Cash Flows from Financing Activities
Net cash used in financing activities decreased by$122.3 million during the year endedDecember 31, 2022 compared to the year endedDecember 31, 2021 primarily due to the absence of net payments on credit agreements and finance leases, lower repurchases of common stock, and lower distributions made by Superior to non-controlling interests due to Superior'sMarch 1, 2022 deconsolidation. A portion of future cash flows and cash and cash equivalents may be used for future shareholder return activities, including stock repurchases and cash distributions.
As of
The following table summarizes certain financial condition and liquidity information as of the dates indicated:
Year Ended December 31,
2022 2021
(In thousands)
Working capital $ 207,237 $ 5,792
Current portion of long-term debt $ - $ -
Long-term debt $ - $ 19,200
Shareholders' equity attributable to Unit Corporation $ 362,626 $ 187,397
40-------------------------------------------------------------------------------- Table of Contents 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$207.2 million atDecember 31, 2022 compared to positive working capital of$5.8 million as ofDecember 31, 2021 . The increase in working capital is primarily due to higher cash and cash equivalents, lower accounts payable and accrued liabilities, lower current derivative liabilities, and the absence of the warrant liability, partially offset by lower accounts receivable. The Exit credit agreement may be used for working capital. Credit Agreements Exit Credit Agreement. On the Effective Date, under the terms of the Plan, the Company entered into an amended and restated credit agreement (the Exit credit agreement), providing for a$140.0 million senior secured revolving credit facility (RBL Facility) and a$40.0 million senior secured term loan facility, among (i) the Company, UDC, and UPC (together, the Borrowers), (ii) the guarantors party thereto, including the Company and all of its subsidiaries existing as of the Effective Date (other thanSuperior Pipeline Company, L.L.C. and its subsidiaries), (iii) the lenders party thereto from time to time (Lenders), and (iv)BOKF, NA dbaBank of Oklahoma as administrative agent and collateral agent (in such capacity, the Administrative Agent). The maturity date of borrowings under this Exit credit agreement isMarch 1, 2024 . Our Exit credit agreement is primarily used for working capital purposes as it limits the amount that can be borrowed for capital expenditures. These limitations restrict future capital projects using the Exit credit agreement. The Exit credit agreement also requires that proceeds from the disposition of certain assets be used to repay amounts outstanding. OnApril 6, 2021 , the Company finalized the first amendment to the Exit credit agreement. Under the first amendment, the Company reaffirmed its borrowing base of$140.0 million of the RBL, amended certain financial covenants, and received less restrictive terms as it relates to the disposition of assets and the use of proceeds from those dispositions. OnJuly 27, 2021 , the Company finalized the second amendment to the Exit credit agreement. Under the second amendment, the Company obtained confirmation that the Term Loan had been paid in full prior to the amendment date and received one-time waivers related to the disposition of assets. OnOctober 19, 2021 , the Company finalized the third amendment to the Exit credit agreement. Under the third amendment, the Company requested, and was granted, a reduction in the RBL borrowing base from$140.0 million to$80.0 million in addition to less restrictive terms as it relates to capital expenditures, required hedges, and the use of proceeds from the disposition of certain assets, while also amending certain financial covenants.
On
On
OnNovember 1, 2022 , the Company finalized the fourth amendment to the Exit credit agreement. Under the fourth amendment, (i) the RBL Facility borrowing base was increased to$35.0 million , (ii) the lenders party to the agreement were revised to onlyBOKF, NA dbaBank of Oklahoma , and (iii) the Eurodollar Loan borrowing option was amended to a secured overnight financing rate (SOFR) option. Subsequent to the fourth amendment, Revolving Loans are able to be SOFR Loans or ABR Loans (each as defined in the Exit credit agreement). Revolving Loans that are SOFR Loans bear interest at a rate per annum equal to the Adjusted Term SOFR Rate (as defined in the Exit credit agreement) for the applicable interest period plus 525 basis points while Revolving Loans that are ABR Loans bear interest at a rate per annum equal to the Alternate Base Rate plus 425 basis points. Superior Credit Agreement. OnMay 10, 2018 , Superior signed a five-year,$200.0 million senior secured revolving credit facility with an option to increase the credit amount up to$250.0 million , subject to certain conditions (Superior credit agreement). OnApril 29, 2022 , Superior entered into an Amended and Restated Credit Agreement for a four-year,$135.0 million senior secured revolving credit facility with an option to increase the credit amount up to$200.0 million , subject to certain conditions (Amended Superior credit agreement). 41 -------------------------------------------------------------------------------- Table of Contents 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. We participated in the completion of 27 gross wells (1.34 net wells) drilled by other operators during the first twelve months of 2022 compared to 12 gross wells (1.75 net wells) during the first twelve months of 2021. Oil and natural gas segment capital expenditures, including oil and gas properties on the full cost method, for the first twelve months of 2022 totaled$21.0 million , excluding a$4.3 million increase in the ARO liability, compared to$17.8 million , excluding a$0.5 million increase in the ARO liability, during the first twelve months of 2021. OnJuly 1, 2022 , the Company closed on the sale of certain wells and related leases near theTexas Gulf Coast for cash proceeds of$45.4 million , net of customary closing and post-closing adjustments based on an effective date ofApril 1, 2022 . These proceeds reduced the net book value of our full cost pool with no gain or loss recognized as the sale did not result in a significant alteration of the full cost pool. OnMarch 8, 2022 , the Company closed on the sale of certain non-core wells and related leases located near theOklahoma Panhandle for cash proceeds of$3.6 million , net of customary closing and post-closing adjustments based on an effective date ofDecember 1, 2021 . These proceeds reduced the net book value of our full cost pool with no gain or loss recognized as the sale did not result in a significant alteration of the full cost pool. OnAugust 16, 2021 , the Company closed on the sale of substantially all of our wells and related leases located nearOklahoma City, Oklahoma for cash proceeds of$16.1 million , net of customary closing and post-closing adjustments based on an effective date ofAugust 1, 2021 . These proceeds reduced the net book value of our full cost pool with no gain or loss recognized as the sale did not result in a significant alteration of the full cost pool. OnMay 6, 2021 , the Company closed on the sale of substantially all of our wells and the leases related thereto located inReno andStafford Counties,Kansas for cash proceeds of$7.3 million , net of customary closing and post-closing adjustments based on an effective date ofFebruary 1, 2021 . These proceeds reduced the net book value of our full cost pool with no gain or loss recognized as the sale did not result in a significant alteration of the full cost pool. Net proceeds for the sale of other non-core oil and natural gas assets totaled$7.7 million and$5.0 million during the twelve months endedDecember 31, 2022 and 2021, respectively. Contract Drilling Segment Dispositions, Acquisitions, and Capital Expenditures. Near term capital expenditures are expected to primarily be for maintenance capital on operating drilling rigs. We also continue to pursue the disposal or sale of our non-core, idle drilling rig fleet. Contract drilling capital expenditures totaled$11.1 million during the first twelve months of 2022 compared to$2.9 million during the first twelve months of 2021. Proceeds for the sale of non-core contract drilling assets totaled$12.8 million and$12.7 million during the twelve months endedDecember 31, 2022 and 2021, respectively. These proceeds resulted in net gains of$8.4 million and$10.1 million during the twelve months endedDecember 31, 2022 and 2021, respectively. The net gains are presented within gain on disposition of assets in the consolidated statements of operations. Mid-Stream Capital Expenditures and Acquisitions. Superior incurred$1.2 million and$24.5 million in consolidated capital expenditures during the two months prior to theMarch 1, 2022 deconsolidation and the year endedDecember 31, 2021 , respectively.
In
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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, 2022 , based on our fourth quarter 2022 average daily production,
the approximated percentages of our production under derivative contracts are as
follows:
2023 2024 and beyond
Daily oil production 48% -%
Daily natural gas production 45% -%
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, 2022 and determined there was no material
risk at that time. The fair value of the net liabilities we had with Bank of
Oklahoma , our only commodity derivative counterparty, was $23.6 million as of
December 31, 2022 .
Warrants. Prior to the determination of the initial exercise price, we
recognized the fair value of the warrants as a derivative liability on our
consolidated balance sheets with changes in the liability reported as loss on
change in fair value of warrants in our consolidated statements of operations.
On April 7, 2022 , the Company delivered notice of the initial $63.74 exercise
price resulting in the warrants meeting the definition of an equity instrument.
Accordingly, we recognized the change in the fair value of the warrant liability
in our unaudited condensed consolidated statements of operations and
reclassified the $49.1 million warrant liability to capital in excess of par
value on the unaudited condensed consolidated balance sheets as of April 7,
2022 . The warrants will continue to be reported as capital in excess of par
value and are no longer subject to future fair value adjustments.
Below is the effect of derivative instruments on the consolidated statements of operations for the periods indicated:
Year Ended December 31,
2022 2021
(In thousands)
Loss on derivatives $ (63,610) $ (97,615)
Cash settlements paid on commodity derivatives (98,775) (44,591)
Loss on derivatives less cash settlements paid on commodity derivatives
$ 35,165 $ (53,024) Loss on change in fair value of warrants$ (29,323) $ (18,937) If a legal right of set-off exists, we net the value of the derivative arrangements we have with the same counterparty on our consolidated balance sheets. The fair value of our commodity derivatives on our consolidated balance sheets were current derivative liabilities of$23.6 million as ofDecember 31, 2022 compared to current derivative liabilities of$40.9 million and non-current derivative liabilities of$17.9 million as ofDecember 31, 2021 .
Stock-Based Compensation
During the year endedDecember 31, 2022 , we granted 7,850 restricted stock units (RSU) with an aggregate grant date fair value of$0.2 million and 13,416 stock options with an aggregate grant date fair value of$0.1 million . The RSU grants were made inJanuary 2022 and vest equally each month for thirty months. The stock option grants were made inJanuary 2022 and 100% vest on the first anniversary of the grant date. We recognized stock-based compensation expense of$6.7 million during the year endedDecember 31, 2022 . 43 --------------------------------------------------------------------------------
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During the year endedDecember 31, 2021 , we granted 315,529 RSUs with an aggregate grant date fair value of$8.4 million and 361,418 stock options with an aggregate grant date fair value of$4.1 million . Director RSU grants will 25% vest on each of the following dates:May 27, 2022 ,September 3, 2022 ,September 3, 2023 , andSeptember 3, 2024 while employee RSU grants will one-third vest on each of the following dates:November 21, 2022 ,October 1, 2023 , andOctober 1, 2024 . The stock option grants will one-third vest on each of the following dates:October 1, 2022 ,October 1, 2023 , andOctober 1, 2024 . We recognized compensation expense of$0.8 million during the year endedDecember 31, 2021 . OnJanuary 6, 2023 , in accordance with the provisions allowed under the LTIP, the Compensation Committee adjusted the exercise price of all outstanding stock options to$35.00 per share effectiveJanuary 31, 2023 to account for the special dividend paid on that date.
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. 44 -------------------------------------------------------------------------------- Table of Contents Results of Operations Year EndedDecember 31, 2022 versus Year EndedDecember 31, 2021 Year Ended December 31, Percent 2022 2021 Change Change (1) (In thousands
except rig and day amounts, and as otherwise specified)
Total revenue, before inter-segment eliminations
$ 690,012 $ (132,836) (19) %
Total revenue, after inter-segment eliminations
$ 638,716 $ (93,191) (15) % Net income$ 142,541 $ 48,216 $ 94,325 196 %
Net loss attributable to non-controlling interest
$ (12,431) $ 6,603 (53) % Net income attributable to Unit Corporation$ 148,369 $ 60,647 $ 87,722 145 % Oil and Natural Gas: Revenue, before inter-segment eliminations$ 326,238 $ 272,231 $ 54,007 20 %
Operating costs, before inter-segment eliminations
$ 83,221 $ 10,638 13 % Average oil price ($/Bbl)$ 57.48 $ 50.03 $ 7.45 15 %
Average oil price excluding derivatives ($/Bbl)
$ 66.50 $ 27.78 42 % Average NGLs price ($/Bbl)$ 30.00 $ 23.41 $ 6.59 28 %
Average NGLs price excluding derivatives ($/Bbl)
$ 23.41 $ 6.59 28 % Average natural gas price ($/Mcf)$ 3.65 $ 2.93 $ 0.72 25 % Average natural gas price excluding derivatives ($/Mcf)$ 5.79 $ 3.55 $ 2.24 63 % Oil production (MBbls) 1,281 1,615 (334) (21) % NGL production (MBbls) 2,148 2,624 (476) (18) % Natural gas production (MMcf) 24,211 29,012 (4,801) (17) % Contract Drilling: Revenue, before inter-segment eliminations$ 147,740 $ 76,107 $ 71,633 94 %
Operating costs, before inter-segment eliminations
$ 60,973 $ 44,635 73 %
Total drilling rigs available for use at the end of the period
18 21 (3) (14) %
Average number of drilling rigs in use 16.4 10.9 5.5 50 %
Total revenue days 6,001 3,985 2,016 51 %
Average dayrate on daywork contracts ($/day)
$ 17,987 $ 5,145 29 % Average dayrate on daywork contracts - BOSS Rigs ($/day)$ 23,963 $ 19,503 $ 4,460 23 % Average dayrate on daywork contracts - SCR Rigs ($/day)$ 19,422 $ 13,981 $ 5,441 39 % Mid-Stream: (2) Revenue, before inter-segment eliminations$ 83,198 $ 341,674 $ (258,476) (76) %
Operating costs, before inter-segment eliminations
$ 286,199 $ (212,428) (74) % Gas gathered--Mcf/day 348,859 319,394 29,465 9 % Gas processed--Mcf/day 146,368 130,000 16,368 13 % Gas liquids sold--gallons/day 456,700 442,796 13,904 3 % Corporate and Other: General and administrative expense, before$ 24,033 $ 21,399 $ 2,634 12 % inter-segment eliminations Other income (expense): Interest income$ 2,642 $ 2 $ 2,640 NM Interest expense$ (447) $ (4,266) $ 3,819 (90) % Reorganization items$ (127) $ (4,294) $ 4,167 97 % Loss on derivatives$ (63,610) $ (97,615) $ 34,005 35 % Loss on change in fair value of warrants$ (29,323) $ (18,937) $ (10,386) 55 % Loss on deconsolidation of Superior$ (13,141) $ -$ (13,141) - % Income tax expense, net$ 333 $ 173 $ 160 92 % Average interest rate on long-term debt outstanding 2.2 % 6.4 % (4.2) % (66) % Average long-term debt outstanding$ 3,143 $ 46,222 $ (43,079) (93) %
1.NM - A percentage calculation is not meaningful due to a zero-value
denominator or a percentage change greater than 200.
2.Mid-Stream activity and metrics shown in this table for the year ended
45
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Oil and natural gas revenues increased$54.0 million or 20% during the year endedDecember 31, 2022 compared to the year endedDecember 31, 2021 primarily due to higher commodity prices, partially offset by lower production volumes. Including derivatives settled, average oil prices increased 15% to$57.48 per barrel, average natural gas prices increased 25% to$3.65 per Mcf, and NGLs prices increased 28% to$30.00 per barrel. Oil production decreased 21%, natural gas production decreased 17%, and NGLs production decreased 18%. The decrease in volumes was primarily due to normal well production declines and divestitures of producing properties which have not been offset by new drilling or acquisitions. Oil and natural gas operating costs increased$10.6 million or 13% during the year endedDecember 31, 2022 compared to the year endedDecember 31, 2021 primarily due to higher production tax expenses due to increased revenues, higher employee compensation and separation benefits, and higher lease operating expenses. Contract Drilling Contract drilling revenues increased$71.6 million or 94% during the year endedDecember 31, 2022 compared to the year endedDecember 31, 2021 primarily due to a 50% increase in the average number of drilling rigs in use to 16.4 during the year endedDecember 31, 2022 as well as increases to the average dayrates on daywork contracts of 23% and 39% on BOSS rigs and SCR rigs, respectively. Contract drilling operating costs increased$44.6 million or 73% during the year endedDecember 31, 2022 compared to the year endedDecember 31, 2021 primarily due to an increase in the average number of operating rigs, higher employee compensation, and$6.7 million of transportation and start up costs associated with bringing stacked rigs back into service.
Total rigs available for use was reduced from 21 to 18 as of
Mid-Stream
Mid-Stream revenues decreased$258.5 million or 76% during the year endedDecember 31 2022 compared to the year endedDecember 31, 2021 primarily due to the absence of activity subsequent toMarch 1, 2022 as a result of the deconsolidation of Superior, partially offset by higher gas, NGL, and condensate prices as well as higher volumes during the consolidated period. Gas processed volumes per day increased 13% while gas gathered volumes per day increased 9% between the comparative periods primarily due to connecting new wells as well as new volumes from the processing plant and gathering system acquired inNovember 2021 . Operating costs decreased$212.4 million or 74% during the year endedDecember 31, 2022 compared to the year endedDecember 31, 2021 primarily due to the absence of activity subsequent toMarch 1, 2022 as a result of the deconsolidation of Superior, partially offset by higher gas, NGL, and condensate prices as well as higher purchase volumes related to the processing plant and gathering system acquired inNovember 2021 .
General and Administrative
General and administrative expenses increased$2.6 million or 12% during the year endedDecember 31, 2022 compared to the year endedDecember 31, 2021 primarily due to an increase in stock-based compensation, partially offset by lower insurance expense. Interest Income Interest income increased$2.6 million during the year endedDecember 31, 2022 compared to the year endedDecember 31, 2021 primarily due to higher average cash equivalents held as well as higher average interest rates during the year endedDecember 31, 2022 compared to the year endedDecember 31, 2021 . 46 -------------------------------------------------------------------------------- Table of Contents Interest Expense Interest expense decreased$3.8 million during the year endedDecember 31, 2022 compared to the year endedDecember 31, 2021 primarily due to a 93% decrease in average long-term debt outstanding and a decrease in the average interest rate from 6.4% during the year endedDecember 31, 2021 to 2.2% during the year endedDecember 31, 2022 . Our average debt outstanding decreased$43.1 million during the year endedDecember 31, 2022 compared the year endedDecember 31, 2021 primarily due to payments made under the Exit credit agreement and the deconsolidation of Superior's outstanding long-term debt, partially offset by borrowings under the Superior credit agreement prior to deconsolidation.
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.
Loss on Derivatives
The$34.0 million favorable change in loss on derivatives between the comparative first twelve months of 2022 and 2021 is primarily due to favorable pricing changes on unsettled commodity derivative positions and new commodity derivative positions executed during the second quarter of 2022, partially offset by higher settlement payments driven by higher average pricing.
Loss on Change in Fair Value of Warrants
The$10.4 million unfavorable change in loss on change in fair value of warrants between the years endedDecember 31, 2022 and 2021 is primarily due to changes in the underlying assumptions used to estimate the fair value, including entity value, volatility, duration to exercise, and other inputs.
Loss on Deconsolidation of Superior
Loss on deconsolidation of
Income Tax Expense
Income tax expense was
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 generalUnited 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, during this same period, when oil, NGLs, and natural gas prices declined, labor rates did not come back down to the levels existing before the increases. If commodity prices increase substantially for a long period, shortages in support equipment (like drill pipe, third party services, and qualified labor) can cause additional increases in our material and labor costs. Increases in dayrates for drilling rigs also increase the cost of drilling our oil and natural gas properties. How inflation will affect us in the future will depend on increases, if any, realized in our drilling rig rates, the prices we receive for our oil, NGLs, and natural gas, and the rates we receive for gathering and processing natural gas. 47 --------------------------------------------------------------------------------
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