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.

General

We were founded in 1963 as a contract drilling company. Today, we operate, manage and analyze our operating results across our three main lines of business:


•Oil and Natural Gas - carried out by our subsidiary Unit Petroleum Company.
This segment explores, develops, acquires, and produces oil and natural gas
properties for our own account.
•Contract Drilling - carried out by our subsidiary Unit Drilling Company. This
segment contracts to drill onshore oil and natural gas wells for others and for
our own account.
•Mid-Stream - carried out by our subsidiary Superior Pipeline Company, L.L.C.
and its subsidiaries. This segment buys, sells, gathers, processes, and treats
natural gas for third parties and for our own account. We own 50% of this
subsidiary.

Recent developments

Emergence of a voluntary reorganization under Chapter 11 of the Bankruptcy Code


On May 22, 2020, the Debtors filed petitions for reorganization under Chapter 11
of Title 11 of the United States Code 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) (Chapter 11 Cases). During the pendency of the Chapter 11
Cases, the Debtors operated their business as "debtors-in-possession" under the
authority of the bankruptcy court and under the Bankruptcy Code.

The Debtors filed their Plan and the related disclosure statement with the
bankruptcy court on June 9, 2020. On August 6, 2020, the bankruptcy court
entered the "Findings of Fact, Conclusions of Law, and Order (I) Approving the
Disclosure Statement on a Final Basis and (II) Confirming the Debtors' Amended
Joint Chapter 11 Plan of Reorganization" [Docket No. 340] (Confirmation Order)
confirming the Plan. On the Effective Date, the Debtors emerged from the Chapter
11 Cases. For more information regarding the Chapter 11 Cases and other related
matters, please read Note 2 - Emergence From Voluntary Reorganization Under
Chapter 11.

New start accounting


On the Effective Date, we qualified for and adopted fresh start accounting under
the provisions set forth in FASB Topic ASC 852 as (i) the reorganization value
of the company's assets immediately before the date of confirmation was less
than the post-petition liabilities and allowed claims, and (ii) the holders of
the existing voting shares of the Predecessor prior to emergence received less
than 50% of the voting shares of the emerging entity. As a result of the
application of fresh start accounting and the effects of the implementation of
the Plan, the Successor financial statements will not be comparable to the
financial statements prepared before the Effective Date.

Changes in accounting policies


On the Effective Date, we elected to change the accounting policies related to
depreciation of fixed assets of our Contract Drilling segment and the allocation
of earnings and losses between Unit and its partners in Superior.
•Regarding our Contract Drilling segment, we elected to depreciate all drilling
assets using the straight-line method over the useful lives of the assets
ranging from four to ten years.
•We elected to begin allocating earnings and losses between Unit and the
partners in Superior using the Hypothetical Liquidation at Book Value (HLBV)
method of accounting.

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Business Outlook

Strategy

Following our exit from bankruptcy, we are focused on increasing value through free cash flow generation, debt repayment and selective investments in each of our business lines. Investments are expected to be funded from free cash flow from operations, proceeds from the disposal of non-core assets and capacity available under the exit credit agreement, all subject to the various terms and conditions of the exit credit agreement as referenced in Note 9 – Long-term debt and other long-term liabilities.


In our oil and natural gas segment, we are optimizing production from our
existing reserves and converting non-producing reserves to producing, with no
exploratory drilling currently planned. We plan to divest non-core properties
and use those proceeds along with free cash flows to acquire producing
properties in our core areas.

In our contract drilling segment, we are focused on increasing the use of our
BOSS drilling rigs, as well as upgrading certain of our SCR drilling rigs. We
also plan to continue seeking opportunities to divest non-core, idle drilling
equipment.

In our mid-stream segment, we are focused on generating predictable free cash
flows with limited exposure to commodity prices. We also plan to continue
seeking business development opportunities in our core areas using the Superior
credit agreement (which Unit is not a party to nor guarantees) or other
financing sources that are available to it.

COVID-19 pandemic and the commodity price environment


As discussed in other parts of this report, among other things, our success
depends, to a large degree, on the prices we receive for our oil and natural gas
production, the demand for oil, natural gas, and NGLs, and the demand for our
drilling rigs which influences the amounts we can charge for those drilling
rigs. While our operations are all within the United States, events outside the
United States affect us and our industry.

We are continuously monitoring the current and potential impacts of the COVID-19
pandemic on our business. This includes how it has and may continue to impact
our operations, financial results, liquidity, customers, employees, and vendors.
In response to the pandemic, we have implemented various measures to ensure we
are conducting our business in a safe and secure manner. COVID-19 and the
response of governments around the world to contain the pandemic have
contributed to an economic downturn, reduced demand for oil and natural gas, and
together with a price war between Saudi Arabia and Russia, depressed oil and
natural gas prices in 2020. The global oil and natural gas supply and demand
imbalance continues to be uncertain, with possible on-going and future adverse
effects on the oil and gas industry.

During the last two years, commodity prices have been volatile. We reduced our
operated rig count in the first quarter of 2019 before getting as high as six
drilling rigs in the second quarter of 2019. Due to declining prices, we shut
down our own drilling program in July 2019 and used no drilling rigs for the
remainder of 2019 and 2020.

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The following chart reflects the significant fluctuations in the prices for oil
and natural gas:

[[Image Removed: unt-20201231_g2.jpg]]The following graph reflects the significant fluctuations in NGL prices:


[[Image Removed: unt-20201231_g3.jpg]]
_________________________
1.NGLs prices reflect a weighted-average, based on production, of Mont Belvieu
and Conway prices.



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Executive Summary

Oil and Natural Gas

Fourth quarter 2020 production from our oil and natural gas segment was 2,592
MBoe, a decrease of 9% and 38% from the third quarter of 2020 and the fourth
quarter of 2019, respectively. The decreases came from fewer net wells being
drilled in 2020 to replace the declines in existing drilled wells. Oil and NGLs
production during the fourth quarter of 2020 and the fourth quarter of 2019 were
each 48% of our total production.

Fourth quarter 2020 oil and natural gas revenues increased 6% over the third
quarter of 2020 and decreased 48% from the fourth quarter of 2019. The increase
over the third quarter of 2020 was primarily due an increase in commodity prices
partially offset by a decrease in equivalent production. The decrease from the
fourth quarter of 2019 was primarily due to a decrease in equivalent production
and oil and NGLs prices.

Our hedged natural gas prices for the fourth quarter of 2020 increased 56% over
third quarter of 2020 and increased 1% over fourth quarter of 2019. Our hedged
oil prices for the fourth quarter of 2020 increased 43% over the third quarter
of 2020 and decreased 29% from the fourth quarter of 2019, respectively. Our
hedged NGLs prices for the fourth quarter of 2020 increased 21% over the third
quarter of 2020 and decreased 24% from the fourth quarter of 2019.

Direct profit (oil and natural gas revenues less oil and natural gas operating
expense) increased 35% over the third quarter of 2020 and decreased 52% from the
fourth quarter of 2019. The increase over the third quarter of 2020 was
primarily due to an increase in commodity prices and a reduction in saltwater
disposal expense and G&A partially offset by a decrease in equivalent
production. The decrease from the fourth quarter of 2019 was primarily due to
lower revenues due to lower commodity prices and volumes partially offset by
lower LOE and G&A.

Operating cost per Boe produced for the fourth quarter of 2020 decreased 10%
from the third quarter of 2020 and decreased 3% from the fourth quarter of 2019.
The decrease from the third quarter of 2020 was primarily due to lower G&A and
saltwater disposal expense. The decrease from the fourth quarter of 2019 was
primarily due to lower LOE and G&A partially offset by no longer capitalizing
directly related overhead costs in 2020 due to the absence of drilling in 2020.

TO December 31, 2020, these unnamed covers were in progress:

                                                                                                          Weighted Average
         Term                            Commodity                       Contracted Volume              Fixed Price for Swaps              Contracted Market
Jan'21 - Dec'21              Natural gas - basis swap                30,000 MMBtu/day                $(0.215)                          NGPL TEXOK
Jan'21 - Oct'21              Natural gas - swap                      50,000 MMBtu/day                $2.82                             IF - NYMEX (HH)
Nov'21 - Dec'21              Natural gas - swap                      45,000 MMBtu/day                $2.90                             IF - NYMEX (HH)
Jan'22 - Dec'22              Natural gas - swap                      5,000 MMBtu/day                 $2.61                             IF - NYMEX (HH)
Jan'23 - Dec'23              Natural gas - swap                      22,000 MMBtu/day                $2.46                             IF - NYMEX (HH)
Jan'22 - Dec'22              Natural gas - collar                    35,000 MMBtu/day                $2.50 - $2.68                     IF - NYMEX (HH)
Jan'21 - Dec'21              Crude oil - swap                        3,000 Bbl/day                   $44.65                            WTI - NYMEX
Jan'22 - Dec'22              Crude oil - swap                        2,300 Bbl/day                   $42.25                            WTI - NYMEX
Jan'23 - Dec'23              Crude oil - swap                        1,300 Bbl/day                   $43.60                            WTI - NYMEX



In western Oklahoma, annual production averaged 73 MMcfe per day (31% oil, 22%
NGLs, 47% natural gas) which was a decrease of approximately 24% compared to
2019. During 2020, we did not drill any operated wells in this area and
participated in one net non-operated well.

In the Texas panhandle, annual production averaged 67 MMcfe per day (8% oil, 37%
NGLs, 55% natural gas) which was a decrease of approximately 27% compared to
2019. During 2020, we did not drill any operated wells in this area, nor did we
participate in any non-operated wells.

In our Wilcox play located primarily in Polk, Tyler, Hardin and Goliad Counties,
Texas, annual production averaged 45 MMcfe per day (9% oil, 29% NGL's, 62%
natural gas) which is a decrease of approximately 41% compared to 2019. During
2020, we did not drill any operated wells in this area, nor did we participate
in any non-operated wells.

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During the Successor Period and Predecessor Period of 2020, we participated in
the drilling of three wells (0.30 net wells) and 16 wells (0.35 net wells),
respectively.
Contract Drilling

The average number of drilling rigs we operated in the fourth quarter of 2020
was 7.6 compared to 5.1 and 18.3 in the third quarter of 2020 and fourth quarter
of 2019, respectively. As of December 31, 2020, nine of our drilling rigs were
operating.

Revenue for the fourth quarter of 2020 increased 24% over the third quarter of
2020 and decreased 59% from the fourth quarter of 2019. The increase over the
third quarter of 2020 was due to more drilling rigs operating and increasing
dayrates. The decrease from the fourth quarter of 2019 was due to less drilling
rigs operating and lower dayrates.

Dayrates for the fourth quarter of 2020 averaged $17,923, which was a 6%
increase over the third quarter of 2020 and a 7% decrease from the fourth
quarter of 2019. The increase over the third quarter of 2020 was primarily due
to more drilling rigs operating. The decrease from the fourth quarter of 2019
was primarily due to less drilling rigs operating.

Operating costs for the fourth quarter of 2020 increased 29% over the third
quarter of 2020 and decreased 59% from the fourth quarter of 2019. The increase
over the third quarter of 2020 was primarily due to more drilling rigs
operating. The decrease from the fourth quarter of 2020 was primarily due to
less drilling rigs operating. Operating cost per day for the fourth quarter of
2020 decreased 15% from the third quarter of 2020 and decreased 2% from the
fourth quarter of 2019. Revenue days for the fourth quarter of 2020 increased
51% over the third quarter of 2020 and decreased 58% from the fourth quarter of
2019.

Direct profit (contract drilling revenue less contract drilling operating
expense) for the fourth quarter of 2020 increased 13% over the third quarter of
2020 and decreased 59% from the fourth quarter of 2019. The increase over the
third quarter of 2020 was primarily due to more drilling rigs operating. The
decrease from the fourth quarter of 2019 was primarily due to less drilling rigs
operating.

The contract drilling segment has operations in Oklahoma, Texas, New Mexico,
Wyoming, and North Dakota. As of December 31, 2020, three drilling rigs were
working in Oklahoma, three in the Permian Basin of West Texas, two in Wyoming
and one drilling rig in the Bakken Shale of North Dakota.

During 2020, almost all our working drilling rigs were drilling horizontal or
directional wells for oil and NGLs. The future demand for and the availability
of drilling rigs to meet that demand will affect our future dayrates.

As of December 31, 2020, we had five term drilling contracts with original terms
ranging from two months to one year. Three of these contracts are up for renewal
in 2021, (two in the first quarter and one in the second quarter) and two are up
for renewal in 2022 and beyond. Term contracts may contain a fixed rate during
the contract or provide for rate adjustments within a specific range from the
existing rate. Some operators who had signed term contracts have opted to
release the drilling rig and pay an early termination penalty for the remaining
term of the contract. We recorded $9.2 million and $4.8 million in early
termination fees in 2020 and 2019, respectively.

Six of our 14 existing BOSS rigs were under contract to December 31, 2020.

All of our contracts are day contracts.


For 2021, capital expenditures for this segment are expected to primarily be for
maintenance capital on operating drilling rigs and the possible conversion of
certain SCR drilling rigs to AC drilling rigs if practicable. We also plan to
pursue the disposal or sale of our non-core, older drilling rig fleet.

Mid-stream


Fourth quarter 2020 liquids sold per day decreased 31% from the third quarter of
2020 and decreased 24% from the fourth quarter of 2019. The decreases were
primarily due to declining volumes and fewer wells connected to our major
systems resulting in lower liquids production. For the fourth quarter of 2020,
gas processed per day decreased 11% from the third quarter of 2020 and decreased
19% from the fourth quarter of 2019. The decreases were primarily due to
declining volumes and fewer wells connected to our major systems. For the fourth
quarter of 2020, gas gathered per day decreased 11% from the third
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quarter of 2020 and decreased 20% from the fourth quarter of 2019. The decreases
were primarily due to lower volumes from our major gathering and processing
systems resulting from fewer wells connected and declining wellhead volumes.

NGLs prices in the fourth quarter of 2020 increased 35% over the prices received
in the third quarter of 2020 and increased 5% over the prices received in the
fourth quarter of 2019. Because certain of the contracts used by our mid-stream
segment for NGLs transactions are commodity-based contracts - under which we
receive a share of the proceeds from the sale of the NGLs - our revenues from
those commodity-based contracts fluctuate based on NGLs prices.

Direct profit (mid-stream revenues less mid-stream operating expense) for the
fourth quarter of 2020 decreased 45% from the third quarter of 2020 and
decreased 12% from the fourth quarter of 2019, respectively. The decrease from
the third quarter of 2020 was primarily due to recognizing a shortfall fee in
the third quarter of 2020 in the amount of $5.3 million and due to declining
volumes on our major systems. The decrease from the fourth quarter of 2019 was
primarily due to lower volume on our major systems and lower condensate prices.
Total operating cost for this segment for the fourth quarter of 2020 increased
17% over the third quarter of 2020 and decreased 3% from the fourth quarter of
2019. The increase over the third quarter of 2020 was primarily due to an
increase in gas purchase cost due to higher purchase prices. The decrease from
the fourth quarter of 2019 was primarily due to declining wellhead volumes and
fewer wells connected resulting in lower purchased volumes.

At the Cashion processing facility in central Oklahoma, total throughput volume
for the fourth quarter of 2020 averaged approximately 64.2 MMcf per day and
total production of natural gas liquids averaged approximately 252,000 gallons
per day. For 2020, we continued to connect new wells to this system for third
party producers. Since the first of 2020, we connected 18 new wells to this
system from producers. The total processing capacity of the Cashion system is
105 MMcf per day.

In the Appalachian region, at the Pittsburgh Mills collection system, the average collected volume for the fourth quarter of 2020 was 131.7 MMcf per day and the average collected volume for 2020 was 152.3 MMcf per day. In 2020, we connected four new infill wells to an existing well pad.


Also, in the Appalachian area at our Snow Shoe gathering system, the average
gathering volume for the fourth quarter was 2.5 MMcf per day and the average
gathered volume for 2020 was 3.0 MMcf per day. In 2020, we did not connect any
new wells to this system. At Snow Shoe for 2020, we also charged a demand fee
based on a volume of 55 MMcf per day. This demand fee volume will be reduced in
2021 to 51 MMcf per day. Additionally, in 2020, we recognized a shortfall fee
from a producer on this system for $5.3 million. This fee will be invoiced in
the first quarter of 2021.

At the Hemphill processing facility located in the Texas panhandle, average
total throughput volume for the fourth quarter of 2020 was 46.6 MMcf per day and
average total throughput volume for 2020 was 51.3 MMcf per day. Total average
production of natural gas liquids for the fourth quarter of 2020 decreased to
approximately 110,000 gallons per day due to operating in ethane rejection.
Total production of natural gas liquids for 2020 averaged approximately 152,000
gallons per day. The total processing capacity of the Hemphill system is 135
MMcf per day. In 2020, we did not connect any new wells to this system.
Currently there are no active rigs in the area, and we do not anticipate any new
well connects for this system.

At the Segno gathering system located in East Texas, the average throughput
volume for the fourth quarter of 2020 decreased to approximately 31.0 MMcf per
day due to declining production volume along with no new drilling activity in
the area. For 2020, the average throughput volume for this system was
approximately 40 MMcf per day. During 2020, we did not connect any new wells to
this system.

The planned capital spending in 2021 for this segment will be approximately
$ 15.0 million, an increase of 61% compared to 2020.

Critical accounting conventions and estimates

Summary


In this section, we identify those critical accounting policies we follow in
preparing our financial statements and related disclosures. Many policies
require us to make difficult, subjective, and complex judgments while making
estimates of matters inherently imprecise. Some accounting policies involve
judgments and uncertainties to such an extent that there is a reasonable
likelihood that materially different amounts could have been reported under
different conditions, or had different assumptions been used. We evaluate our
estimates and assumptions regularly. We base our estimates on historical
experience and various other assumptions we believe are reasonable under the
circumstances, the results of which support making judgments about the carrying
values of assets and liabilities not readily apparent from other sources. Actual
results may differ from these estimates and assumptions used in preparation of
our financial statements. In this discussion we explain the nature of these
estimates,
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assumptions and judgments, and the likelihood that materially different amounts
would be reported in our financial statements under different conditions or
using different assumptions.

Significant estimates and assumptions


Full Cost Method of Accounting for Oil, NGLs, and Natural Gas Properties.
Determining our oil, NGLs, and natural gas reserves is a subjective process. It
entails estimating underground accumulations of oil, NGLs, and natural gas that
cannot be measured in an exact manner. Accuracy of these estimates depends on
several factors, including, the quality and availability of geological and
engineering data, the precision of the interpretations of that data, and
individual judgments. Each year, we hire an independent petroleum engineering
firm to audit our internal evaluation of our reserves. That audit as of
December 31, 2020 covered those reserves we projected to comprise 85% of the
total proved developed future net income discounted at 10% (based on the SEC's
unescalated pricing policy). Included in Part I, Item 1 of this report are the
qualifications of our independent petroleum engineering firm and our employees
responsible for preparing our reserve reports.

The accuracy of estimating oil, NGLs, and natural gas reserves varies with the
reserve classification and the related accumulation of available data, as shown
in this table:
Type of Reserves                         Nature of Available Data                             Degree of Accuracy

Proved undeveloped                       Data from offsetting wells, seismic data             Less accurate

Proved developed non-producing           The above and logs, core samples, 

test well,

                                         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. Companies,
like ours, using full cost accounting 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.

We calculate the DD&A on a production unit method. Each quarter, we use these formulas to calculate the DD&A allowance 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.

Depreciation and amortization costs for our oil and gas properties are calculated quarterly using end-of-period reserve quantities adjusted for production for the period.


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
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on our oil, NGLs, and natural gas adjusted for any cash flow hedges), plus the
cost of properties not being amortized, plus the lower of the cost or estimated
fair value of unproved properties included in the costs being amortized, less
related income taxes. If the net capitalized costs of our oil and natural gas
properties exceed the ceiling, we are required to write-down the excess amount.
A ceiling test write-down is a non-cash charge to earnings. If required, it
reduces earnings and impacts shareholders' equity in the period of occurrence
and results in lower DD&A expense in future periods. Once incurred, a write-down
cannot be reversed.

The risk we will be required to write-down the carrying value of our oil and
natural gas properties increases when the prices for oil, NGLs, and natural gas
are depressed or if we have large downward revisions in our estimated proved
oil, NGLs, and natural gas reserves. Application of these rules during periods
of relatively low prices, even if temporary, increases the chance of a ceiling
test write-down. At December 31, 2020, our reserves were calculated based on
applying 12-month 2020 average unescalated prices of $39.57 per barrel of oil,
$18.70 per barrel of NGLs, and $1.98 per Mcf of natural gas (then adjusted for
price differentials) over the estimated life of each of our oil and natural gas
properties.

Deficiency of the succession period


As of September 1, 2020, we adopted fresh start accounting and adjusted our
assets to fair value. Although under fresh start accounting we recorded our
assets at fair value on emergence, the application of the full cost accounting
rules resulted in non-cash ceiling test write-downs of $26.1 million pre-tax
during the Successor Period of 2020, primarily due to the use of average
12-month historical commodity prices for the ceiling test versus forward prices
for our Fresh Start fair value estimates.

Under full cost accounting rules we must review the carrying value of our oil
and natural gas properties at the end of each quarter. Under those rules, the
maximum amount allowed as the carrying value is called the ceiling. The ceiling
is the sum of the present value (using a 10% discount rate) of the estimated
future net revenues from our proved reserves (using the most recent unescalated
historical 12-month average price of our oil, NGLs, and natural gas), plus the
cost of properties not being amortized, plus the lower of cost or estimated fair
value of unproved properties in the costs being amortized, less related income
taxes. If the net book value of the oil, NGLs, and natural gas properties being
amortized exceeds the full cost ceiling, the excess amount is charged to expense
in the period during which the excess occurs, even if prices are depressed for
only a short while. Once incurred, a write-down of oil and natural gas
properties is not reversible.

We do not anticipate a non-cash ceiling test write-down in the first quarter of
2021 of our proved reserves. It is hard to predict with any certainty the need
for or amount of any future impairments given the many factors that go into the
ceiling test calculation including, but not limited to, future pricing,
operating costs, drilling and completion costs, upward or downward oil and gas
reserve revisions, oil and gas reserve additions, and tax attributes. Subject to
these inherent uncertainties, if we hold these same factors constant as they
existed at December 31, 2020, and only adjust the 12-month average price as of
March 2021, our forward-looking expectation is that we will not recognize an
impairment in the first quarter of 2021. Given the uncertainty associated with
the factors used in calculating our estimate of our future period ceiling test
write-down, these estimates should not necessarily be construed as indicative of
our future plans or financial results and the actual amount of any write-down
may vary significantly from this estimate depending on the final future
determination.

Impairments from the previous period


Oil and Natural Gas. During the Predecessor Period of 2020, we incurred non-cash
ceiling test write-downs of our oil and natural gas properties of $393.7 million
pre-tax ($346.6 million net of tax) due to the reduction in the 12-month average
commodity prices and the impairment of our unproved oil and gas properties
described below. In 2019, we incurred non-cash ceiling test write-downs of our
oil and natural gas properties of $559.4 million pre-tax ($422.4 million net of
tax) due to the reduction of the 12-month average commodity prices and the
removal of proved undeveloped reserves due to the uncertainty regarding our
ability to finance future capital expenditures.

In addition to the impairment evaluations of our proved and unproved oil and gas
properties in the first quarter of 2020, we also evaluated the carrying value of
our salt water disposal assets. Based on our revised forecast of asset
utilization, we determined certain assets were no longer expected to be used and
wrote off certain salt water disposal assets that we no longer considered
abandoned. We recorded expense of $17.6 million related to the write-down of our
salt water disposal assets in the first quarter of 2020.

Mid-stream. We determined that the carrying value of certain long-lived asset
groups in our mid-stream segment, where lower pricing is expected to impact
drilling and production levels, are not recoverable and exceeded their estimated
fair value.
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Table of contents Based on the estimated fair value of the groups of assets, we recognized non-cash impairment charges of $ 64.0 million. These charges are included in impairment charges in our Consolidated Statement of Income.


Contract Drilling. On a periodic basis, we evaluate our fleet of drilling rigs
for marketability based on the condition of inactive rigs, the expenditures
necessary to bring them into working condition and the expected demand for
drilling services by rig type. The components comprising inactive rigs are
evaluated, and those components with continuing utility to our other marketed
rigs are transferred to rigs or to our yards to be used as spare equipment. The
remaining components of these rigs are retired.

At March 31, 2020, due to market conditions, we performed impairment testing on
two asset groups which were comprised of our SCR diesel-electric drilling rigs
and our BOSS drilling rigs. We concluded that the net book value of the SCR
drilling rigs asset group was not recoverable through estimated undiscounted
cash flows and recorded a non-cash impairment charge of $407.1 million in the
first quarter of 2020. We also recorded an additional non-cash impairment
charges of $3.0 million for other miscellaneous drilling equipment.

We used the income approach to determine the fair value of the SCR drilling rigs
asset group. This approach uses significant assumptions including management's
best estimates of the expected future cash flows and the estimated useful life
of the asset group. Fair value determination requires a considerable amount of
judgement and is sensitive to changes in underlying assumptions and economic
factors. As a result, there is no assurance the fair value estimates made for
the impairment analysis will be accurate in the future.

We concluded that no impairment was needed on the BOSS drilling rigs asset group
as the undiscounted cash flows exceeded the carrying value of the asset group.
The carrying value of the asset group was approximately $242.5 million at March
31, 2020. The estimated undiscounted cash flows of the BOSS drilling rigs asset
group exceeded the carrying value by a relatively minor margin, which means
minor changes in certain key assumptions in future periods may result in
material impairment charges in future periods. Some of the more sensitive
assumptions used in evaluating the contract drilling rigs asset groups for
potential impairment include forecasted utilization, gross margins, salvage
values, discount rates, and terminal values.

We recorded expenses of $ 1.1 million related to the depreciation of certain equipment in the third quarter of 2020 that we consider to be abandoned.


Costs Withheld from Amortization. Costs associated with unproved properties are
excluded from our amortization base until we have evaluated the properties. The
costs associated with unevaluated leasehold acreage and related seismic data,
the drilling of wells, and capitalized interest are initially excluded from our
amortization base. Leasehold costs are transferred to our amortization base with
the costs of drilling a well on the lease or are assessed at least annually for
possible impairment or reduction in value. Leasehold costs are transferred to
our amortization base to the extent a reduction in value has occurred.

Our decision to withhold costs from amortization and the timing of transferring
those costs into the amortization base involve significant judgment
determinations which may change over time based on several factors, including
our drilling plans, availability of capital, project economics and results of
drilling on adjacent acreage. During the first quarter of 2020, we determined
that, because of the increased uncertainty in our business, our undeveloped
acreage would not be fully developed and thus certain unproved oil and gas
properties carrying values were not recoverable. This resulted in an impairment
of $226.5 million, which had a corresponding increase to our depletion base and
contributed to our full cost ceiling impairment recorded during the first
quarter of 2020. In 2019, we determined the value of certain unproved oil and
gas properties were diminished (in part or in whole) based on an impairment
evaluation and our anticipated future exploration plans. Those determinations
resulted in $73.9 million of costs being added to the total of our capitalized
costs being amortized. At December 31, 2020, we had approximately $1.6 million
of costs excluded from the amortization of our full cost pool.

Accounting for ARO for Oil, NGLs, and Natural Gas Properties. We record the fair
value of liabilities associated with the future plugging and abandonment of
wells. In our case, when the reserves in each of our oil or gas wells deplete or
the wells otherwise become uneconomical, we must incur costs to plug and abandon
the wells. These costs are recorded in the period in which the liability is
incurred (at the time the wells are drilled or acquired). We have no assets
restricted to settle these ARO liabilities. Our engineering staff uses
historical experience to determine the estimated plugging costs considering the
type of well (either oil, natural gas, or both), the depth of the well, the
physical location of the well, and the ultimate productive life to determine the
estimated plugging costs. A risk-adjusted discount rate and an inflation factor
are used on these estimated costs to
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determine the current present value of this obligation. To the extent any change
in these assumptions affect future revisions and impacts the present value of
the existing ARO, a corresponding adjustment is made to the full cost pool.

Drilling Contracts. The type of contract used determines our compensation. All
our contracts in 2020 and 2019 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 compensation is based on a negotiated
rate to be paid for each day the drilling rig is used.

Accounting for Value of Stock Compensation Awards. To account for stock-based
compensation, compensation cost is measured at the grant date based on the fair
value of an award and is recognized over the service period, which is usually
the vesting period. We elected to use the modified prospective method, which
requires compensation expense to be recorded for all unvested stock options and
other equity-based compensation beginning in the first quarter of adoption.
Determining the fair value of an award requires significant estimates and
subjective judgments regarding the appropriate option pricing model, the
expected life of the award and performance vesting criteria assumptions. As
there are inherent uncertainties related to these factors and our judgment in
applying them to the fair value determinations, there is risk that the recorded
stock compensation may not accurately reflect the amount ultimately earned by
the employee. All our previously reported awards were terminated because of our
Chapter 11 Cases and no awards were outstanding as of December 31, 2020.

Accounting for Derivative Instruments and Hedging. All derivatives are
recognized on the balance sheet and measured at fair value. Any changes in our
derivatives' fair value before their maturity (i.e., temporary fluctuations in
value) along with any derivatives settled are reported in gain (loss) on
derivatives in our Consolidated Statements of Operations.

Bankruptcy Reorganization. We have applied Accounting Standards Codification
(ASC) 852, Reorganizations (ASC 852) in preparing our consolidated financial
statements. ASC 852 requires that the financial statements, for periods
subsequent to the Chapter 11 Cases, distinguish transactions and events that are
directly associated with the reorganization from the ongoing operations of the
business. Accordingly, certain expenses, realized gains and losses and
provisions for losses that are realized or incurred in the bankruptcy
proceedings, are recorded in reorganization items, net on our accompanying
consolidated statements of operations.

Fresh Start. The company qualified for and adopted fresh start accounting under
the provisions of ASC 852. When applying ASC 852, an entity determines its
reorganization value and enterprise value. Reorganization value, as determined
under ASC 820, Fair Value Measurement, represents the fair value of the entity's
total assets before the consideration of liabilities and is intended to
approximate the amount a willing buyer would pay for the assets immediately
after a restructuring. The entity's enterprise value represents the estimated
fair value of an entity's long-term debt and equity. The assumptions used in
estimating these values are inherently uncertain and require significant
judgment.

New accounting standards


Reference Rate Reform (Topic 848)-Facilitation of the Effects of Reference Rate
Reform on Financial Reporting. The FASB issued ASU 2020-04 which provides
optional expedients and exceptions for applying generally accepted accounting
principles to contract modifications, subject to meeting certain criteria, that
reference LIBOR or another reference rate expected to be discontinued. The ASU
should help stakeholders during the global market-wide reference rate transition
period. The amendments within this ASU will be in effect for a limited time
beginning March 12, 2020, and an entity may elect to apply the amendments
prospectively through December 31, 2022. The amendments will not have a material
impact on our consolidated financial statements.

Income Taxes (Topic 740)-Simplifying the Accounting for Income Taxes. The FASB
issued ASU 2019-12 to simplify the accounting for income taxes by removing
certain exceptions to the general principles in Topic 740. The amendments also
improve consistent application of and simplify GAAP for other areas of Topic 740
by clarifying and amending existing guidance. The amendments will be effective
for reporting periods beginning after December 15, 2020. Early adoption is
permitted. This standard will not have a material impact on our consolidated
financial statements.

Adopted Standards

Measurement of Credit Losses on Financial Instruments (Topic 326). The FASB
issued ASU 2016-13 which replaces current methods for evaluating impairment of
financial instruments not measured at fair value, including trade accounts
receivable, and certain debt securities, with a current expected credit loss
model (CECL). The CECL model is expected to result
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in more timely recognition of credit losses. The amendment was effective for
reporting periods after December 15, 2019. The adoption of this guidance did not
have a material impact on our consolidated financial statements or related
disclosures.

Fair Value Measurement (Topic 820): Disclosure Framework-Changes to the
Disclosure Requirements for Fair Value Measurement. The FASB issued ASU 2018-13
to modify the disclosure requirements in Topic 820. Part of the disclosures were
removed or modified, and other disclosures were added. The amendment was
effective for reporting periods beginning after December 15, 2019. The adoption
of this guidance did not have a material impact on our consolidated financial
statements or related disclosures.

Financial situation and liquidity

Summary


Our financial condition and liquidity primarily depend on the cash flow from our
operations and borrowings under our credit agreements. The principal factors
determining our cash flow are:

•the amount of natural gas, oil, and NGLs we produce;
•the prices we receive for our natural gas, oil, and NGLs production;
•the use of our drilling rigs and the dayrates we receive for those drilling
rigs; and
•the fees and margins we obtain from our natural gas gathering and processing
contracts.

Our Chapter 11 Cases allowed us to significantly reduce our level of
indebtedness and our future cash interest obligations. We currently expect that
cash and cash equivalents, cash generated from operations, and available funds
under the Exit Credit Agreement and the Superior credit agreement are adequate
to cover our liquidity requirements for at least the next 12 months.

Below is a summary of certain financial information for the periods indicated:
                                                         Successor                           Predecessor
                                                           Period
                                                        September 1,                  Period
                                                            2020                    January 1,         For the Year
                                                          through                  2020 through            Ended
                                                        December 31,                August 31,         December 31,
                                                            2020                       2020                2019
                                                                              (In thousands)
Net cash provided by operating activities              $    29,807                $    44,956          $  269,396
Net cash used in investing activities                       (2,258)                   (20,139)           (394,563)

Net cash provided by (used in) financing activities (47,775)

             7,552             119,286
Net increase (decrease) cash, restricted cash, and
cash equivalents                                       $   (20,226)               $    32,369          $   (5,881)


Cash flow from operating activities


Our operating cash flow is primarily influenced by the prices we receive for our
oil, NGLs, and natural gas production, the oil, NGL, and natural gas we produce,
settlements of derivative contracts, third-party use for our drilling rigs and
mid-stream services, and the rates we can charge for those services. Our cash
flows from operating activities are also affected by changes in working capital.

Net cash provided by operating activities decreased by $194.6 million in 2020
compared to 2019 primarily due to lower revenues due to lower commodity prices
and lower drilling rig utilization partially offset by an increase in operating
assets and liabilities related to the timing of cash receipts and disbursements.

Cash flow from investing activities


We have historically dedicated a substantial portion of our capital budgets to
our exploration for and production of oil, NGLs, and natural gas. These
expenditures are necessary to off-set the inherent production declines typically
experienced in oil and gas wells. Although we curtailed our spending in 2020, we
expect that any future capital budgets would be focused on development or
acquisitions of producing oil and gas properties, but not exploration.

Cash flow used in investing activities decreased by $ 372.2 million in 2020 compared to 2019. The variation was due

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primarily to a decrease in capital expenditures due to a decrease in operated
wells drilled and a decrease in oil and gas property acquisitions partially
offset by a decrease in the proceeds received from the disposition of assets.
See additional information on capital expenditures below under Capital
Requirements.

Cash flow from financing activities

Cash flow generated by (used in) financing activities decreased by $ 159.5 million in 2020 compared to 2019. The decrease is mainly due to a decrease in net debt and a decrease in bank overdrafts.


At December 31, 2020, we had unrestricted cash and cash equivalents totaling
$12.1 million and had borrowed $99.0 million of the amounts available under the
Exit Credit Agreement. We did not have any outstanding borrowings under our
Superior credit agreement.

Below is a summary of certain financial information at the 31st of December:

                                                         Successor         Predecessor
                                                           2020               2019
                                                                (In thousands)
Working capital                                         $   2,575         $  (154,998)
Current portion of long-term debt                       $     600         $ 

108,200

Long-term debt (1)                                      $  98,400         $ 

663,216

Equity attributable to Unitary company $ 179,222 $

853 878

_________________________

1.Long-term debt is net of the unamortized discount and debt issuance costs for the prior period.


Working Capital

Typically, our working capital balance fluctuates, in part, because of the
timing of our trade accounts receivable and accounts payable and the fluctuation
in current assets and liabilities associated with the mark to market value of
our derivative activity. We had positive working capital of $2.6 million at
December 31, 2020 and negative working capital of $155.0 million as of December
31, 2019. The increase in working capital is primarily due to more cash and cash
equivalents and lower accounts payable and accrued liabilities from to the
settlement of the liabilities subject to compromise partially offset by lower
accounts receivable. Both the Superior credit agreement and the Exit Credit
Agreement are used for working capital. At December 31, 2020, we had borrowed
$99.0 million under the Exit Credit Agreement and we did not have any
outstanding borrowings under our Superior credit agreement. The effect of our
derivatives decreased working capital by $1.0 million as of December 31, 2020
and increased working capital by $0.6 million as of December 31, 2019.

Long-term debt


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 any proceeds from the disposition
of certain assets be used to repay amounts outstanding.

Oil and gas operations


Any significant change in oil, NGLs, or natural gas prices has a material effect
on our revenues, cash flow, and the value of our oil, NGLs, and natural gas
reserves. Generally, prices and demand for domestic natural gas are influenced
by weather conditions, supply imbalances, by worldwide oil price levels, and
recently by the worldwide economic impact from the coronavirus. Domestic oil
prices are primarily influenced by world oil market developments. These factors
are beyond our control and we cannot predict nor measure their future influence
on the prices we will receive.

Contract drilling operations


Many factors influence the number of drilling rigs we have working, and the
costs and revenues associated with that work. These factors include the demand
for drilling rigs in our areas of operation, competition from other drilling
contractors,
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the prevailing prices for oil, NGLs, and natural gas, availability and cost of
labor to run our drilling rigs, and our ability to supply the equipment needed.

Competition to keep qualified labor continues. Our drilling rig personnel are a
key component to the overall success of our drilling services. With the present
conditions in the drilling industry, we do not anticipate increases in the
compensation paid to those personnel in the near term.

During 2020, most of our working drilling rigs were drilling horizontal or
directional wells for oil and NGLs. The continuous fluctuations in commodity
prices for oil and natural gas changes demand for drilling rigs. These factors
ultimately affect the demand and mix of the type of drilling rigs used by our
customers. The future demand for and the availability of drilling rigs to meet
that demand will affect our future dayrates. For the Successor Period and
Predecessor Period of 2020, our average dayrate was $17,807 and $18,911 per day,
respectively, compared to $18,762 per day for 2019. Our average number of
drilling rigs used (utilization %) for the Successor Period and Predecessor
Period of 2020 were 7.2 (12%) and 11.5 (20%), respectively, compared with 24.6
(43%) in 2019. Based on the average utilization of our drilling rigs during
2020, a $100 per day change in dayrates has a $1,010 per day ($0.4 million
annualized) change in our pre-tax operating cash flow.

Our contract drilling segment provides drilling services for our exploration and
production segment. Some of the drilling services we perform on our properties
are, depending on the timing of those services, deemed associated with acquiring
an ownership interest in the property. In those cases, revenues and expenses for
those services are eliminated in our statement of operations, with any profit
recognized as a reduction in our investment in our oil and natural gas
properties. The contracts for these services are issued under the same
conditions and rates as the contracts entered into with unrelated third parties.
By providing drilling services for the oil and natural gas segment, we
eliminated revenue of $15.8 million during 2019 from our contract drilling
segment and eliminated the associated operating expense of $14.2 million
yielding $1.6 million as a reduction to the carrying value of our oil and
natural gas properties. We did not eliminate any revenue or expense in 2020.

No impairment trigger was identified during the 2020 succession period for our contract drilling assets.

Mid-term operations


This segment is engaged primarily in the buying, selling, gathering, processing,
and treating of natural gas. It operates three natural gas treatment plants, 11
processing plants, 17 gathering systems, and approximately 2,090 miles of
pipeline. Its operations are in Oklahoma, Texas, Kansas, Pennsylvania, and West
Virginia. This segment enhances our ability to gather and market not only our
own natural gas and NGLs but also natural gas and NGLs owned by third parties
and serves as a mechanism through which we can construct or acquire existing
natural gas gathering and processing facilities. During the Successor Period of
2020, Predecessor Period of 2020, and the year 2019, Superior purchased $10.6
million, $11.8 million, and $40.6 million, respectively, of our oil and natural
gas segment's natural gas and NGLs production, and provided gathering and
transportation services of $1.2 million, $2.8 million, and $6.9 million,
respectively. Intercompany revenue from services and purchases of production
between this business segment and our oil and natural gas segment has been
eliminated in our consolidated financial statements.

Our mid-stream segment gathered an average of 367,302 Mcf per day in 2020
compared to 435,646 Mcf per day in 2019. It processed an average of 150,559 Mcf
per day in 2020 compared to 164,482 Mcf per day in 2019, and sold NGLs of
555,454 gallons per day in 2020 compared to 625,873 gallons per day in 2019. Gas
gathering volumes per day in 2020 decreased primarily due to lower volumes from
most of our major gathering and processing systems resulting from declining
wellhead volumes and fewer wells connected except from the Cashion facility.
Volumes processed and NGLs sold in 2020 decreased mainly due to lower volumes
from our processing facility in the Texas panhandle resulting from declines and
not connecting any new wells in 2020.

Our predecessor credit and debt agreements


Exit Credit Agreement. On the Effective Date, under the Plan, we entered into an
amended and restated credit agreement (the Exit Credit Agreement), providing for
a $140.0 million senior secured revolving credit facility and a $40.0 million
senior secured term loan facility, among (i) the company, UDC, and UPC, (ii) the
guarantors, including the company and all its subsidiaries existing as of the
Effective Date (other than Superior Pipeline Company, L.L.C. and its
subsidiaries), (iii) the lenders under the agreement, and (iv) BOKF, NA dba Bank
of Oklahoma as administrative agent and collateral agent (the Administrative
Agent).

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The maturity date of borrowings under the Exit Credit Agreement is March 1,
2024. Revolving Loans and Term Loans (each as defined in the Exit Credit
Agreement) may be Eurodollar Loans or ABR Loans (each as defined in the Exit
Credit Agreement). Revolving loans that are Eurodollar Loans will bear interest
at a rate per annum equal to the Adjusted LIBO Rate (as defined in the Exit
Credit Agreement) for the applicable interest period plus 525 basis points.
Revolving Loans that are ABR Loans will bear interest at a rate per annum equal
to the Alternate Base Rate (as defined in the Exit Credit Agreement) plus 425
basis points. Term Loans that are Eurodollar Loans will bear interest at a rate
per annum equal to the Adjusted LIBO Rate for the applicable interest period
plus 625 basis points. Term Loans that are ABR Loans will bear interest at a
rate per annum equal to the Alternate Base Rate plus 525 basis points.

The Exit Credit Agreement requires that we comply with certain financial ratios,
including a covenant that we will not permit the Net Leverage Ratio (as defined
in the Exit Credit Agreement) as of the last day of the fiscal quarters ending
(i) December 31, 2020 and March 31, 2021, to be greater than 4.00 to 1.00, (ii)
June 30, 2021, September 30, 2021, December 31, 2021, March 31, 2022, and June
30, 2022, to be greater than 3.75 to 1.00, and (iii) September 30, 2022 and any
fiscal quarter thereafter, to be greater than 3.50 to 1.00. In addition,
beginning with the fiscal quarter ending December 31, 2020, we may not (a)
permit the Current Ratio (as defined in the Exit Credit Agreement) as of the
last day of any fiscal quarter to be less than 0.50 to 1.00 or (b) permit the
Interest Coverage Ratio (as defined in the Exit Credit Agreement) as of the last
day of any fiscal quarter to be less than 2.50 to 1.00. The Exit Credit
Agreement also contains provisions, among others, that limit certain capital
expenditures, restrict certain asset sales and the related use of proceeds, and
require certain hedging activities. The Exit Credit Agreement further requires
that we 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. For the quarter
ended September 30, 2020, the syndicate banks allowed for an extension.

The Exit Credit Agreement is secured by first-priority liens on substantially
all the personal and real property assets of the borrowers and the guarantors,
including our ownership interests in Superior Pipeline Company, L.L.C.

On the Effective Date, we had (i) $40.0 million in principal amount of Term
Loans outstanding, (ii) $92.0 million in principal amount of Revolving Loans
outstanding, and (iii) approximately $6.7 million of outstanding letters of
credit. At December 31, 2020, we had $0.6 million and $98.4 million outstanding
current and long-term borrowings, respectively, under the Exit Credit Agreement.

Predecessor's Credit Agreement. Before the filing of the Chapter 11 Cases, the
Unit credit agreement had a scheduled maturity date of October 18, 2023 that
would have accelerated to November 16, 2020 if, by that date, all the Notes were
not repurchased, redeemed, or refinanced with indebtedness having a maturity
date at least six months following October 18, 2023 (Credit Agreement Extension
Condition). The Debtors' filing of the Chapter 11 Cases constituted an event of
default that accelerated the Debtors' obligations under the Unit credit
agreement and the indenture governing the Notes. Due to the Credit Agreement
Extension Condition, our debt associated with the Unit credit agreement is
reflected as a current liability in our Consolidated Balance Sheets as of
December 31, 2019. The classification as a current liability due to the Credit
Agreement Extension Condition was based on the uncertainty regarding our ability
to repay or refinance the Notes before November 16, 2020. In addition, on May
22, 2020, the lenders' remaining commitments under the Unit credit agreement
were terminated.

Before filing the Chapter 11 Cases, we were charged a commitment fee of 0.375%
on the amount available but not borrowed. That fee varied based on the amount
borrowed as a percentage of the total borrowing base. Total amendment fees of
$3.3 million in origination, agency, syndication, and other related fees were
being amortized over the life of the Unit credit agreement. Due to the
termination of the remaining commitments of the lenders under the Unit credit
agreement, the unamortized debt issuance costs of $2.4 million were written off
during the second quarter of 2020. Under the Unit credit agreement, we pledged
as collateral 80% of the proved developed producing (discounted as present worth
at 8%) total value of our oil and gas properties. Under the mortgages covering
those oil and gas properties, UPC also pledged certain items of its personal
property.

Before filing the Chapter 11 Cases, any part of the outstanding debt under the
Unit credit agreement could be fixed at a London Interbank Offered Rate (LIBOR).
LIBOR interest was computed as the LIBOR base for the term plus 1.50% to 2.50%
depending on the level of debt as a percentage of the borrowing base and was
payable at the end of each term, or every 90 days, whichever is less. Borrowings
not under LIBOR bear interest equal to the higher of the prime rate specified in
the Unit credit agreement and the sum of the Federal Funds Effective Rate (as
defined in the Unit credit agreement) plus 0.50%, but in no event would the
interest on those borrowings be less than LIBOR plus 1.00% plus a margin.
Interest was payable at the end of each month or at the end of each LIBOR
contract and the principal may be repaid in whole or in part at any time,
without a premium or penalty.

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Filing the bankruptcy petitions on May 22, 2020 constituted an event of default
that accelerated our obligations under the Unit credit agreement, and the
lenders' rights of enforcement under the Unit credit agreement were
automatically stayed because of the Chapter 11 Cases.

On the Effective Date, each lender under the Unit credit agreement and the DIP
Credit Agreement received its pro rata share of revolving loans, term loans and
letter-of-credit participations under the Exit Credit Agreement, in exchange for
that lender's allowed claims under the Unit credit agreement or the DIP Credit
Agreement.

Superior Credit Agreement. On May 10, 2018, Superior entered into a five-year,
$200.0 million senior secured revolving credit facility with an option to
increase the credit amount up to $250.0 million, subject to certain conditions
(the Superior credit agreement). The amounts borrowed under the Superior credit
agreement bear annual interest at a rate, at Superior's option, equal to (a)
LIBOR plus the applicable margin of 2.00% to 3.25% or (b) the alternate base
rate (greater of (i) the federal funds rate plus 0.5%, (ii) the prime rate, and
(iii) third day LIBOR plus 1.00%) plus the applicable margin of 1.00% to 2.25%.
The obligations under the Superior credit agreement are secured by mortgage
liens on certain of Superior's processing plants and gathering systems. The
credit agreement provides that if ICE Benchmark Administration no longer reports
the LIBOR or Administrative Agent determines in good faith that the rate so
reported no longer accurately reflects the rate available to Lender in the
London Interbank Market or if that index no longer exists or accurately reflects
the rate available to the Administrative Agent in the London Interbank Market,
the Administrative Agent may select a replacement index.

Superior is charged a commitment fee of 0.375% on the amount available but not
borrowed which varies based on the amount borrowed as a percentage of the total
borrowing base. Superior paid $1.7 million in origination, agency, syndication,
and other related fees. These fees are being amortized over the life of the
Superior credit agreement.

The Superior credit agreement requires that Superior maintain a Consolidated
EBITDA to interest expense ratio for the most-recently ended rolling four
quarters of at least 2.50 to 1.00, and a funded debt to Consolidated EBITDA
ratio of not greater than 4.00 to 1.00. Additionally, the Superior credit
agreement contains several customary covenants that, among other things,
restrict (subject to certain exceptions) Superior's ability to incur additional
indebtedness, create additional liens on its assets, make investments, pay
distributions, enter into sale and leaseback transactions, engage in certain
transactions with affiliates, engage in mergers or consolidations, enter into
hedging arrangements, and acquire or dispose of assets. As of December 31, 2020,
Superior was in compliance with the Superior credit agreement covenants.

The borrowings from the Superior credit agreement will be used to finance capital expenditures and acquisitions, to provide general working capital and letters of credit for Superior.

Unit is not a party to and does not guarantee Superior’s credit agreement. Superior and its subsidiaries were not debtors in the Chapter 11 matters, and Superior’s credit agreement was not affected by Unit’s bankruptcy.


6.625% Senior Subordinated Notes. The Notes were issued under an Indenture dated
as of May 18, 2011, between the company and Wilmington Trust, National
Association (successor to Wilmington Trust FSB), as Trustee (Trustee), as
supplemented by the First Supplemental Indenture dated as of May 18, 2011,
between us, the Guarantors, and the Trustee, and as further supplemented by the
Second Supplemental Indenture dated as of January 7, 2013, between us, the
Guarantors, and the Trustee (as supplemented, the 2011 Indenture), establishing
the terms of and providing for issuing the Notes.

As a result of Unit's emergence from bankruptcy, the Notes were cancelled and
our liability under the Notes was discharged as of the Effective Date. Holders
of the Notes were issued shares of New Common Stock in accordance with the Plan.

DIP Credit Agreement. As contemplated by the Restructuring Support Agreement
between the company and certain of the Note holders and our lenders, the company
and the other Debtors entered into a Superpriority Senior Secured
Debtor-in-Possession Credit Agreement dated May 27, 2020 ( DIP credit
agreement), among the Debtors, the lenders under the facility (the DIP lenders),
and BOKF, NA dba Bank of Oklahoma, as administrative agent, under which the DIP
lenders agreed to provide us with the $36.0 million multiple-draw loan facility
(DIP credit facility). The bankruptcy court entered an interim order on May 26,
2020 approving the DIP credit facility, permitting the Debtors to borrow up to
$18.0 million on an interim basis. On June 19, 2020, the bankruptcy court
granted final approval of the DIP credit facility.

Before its repayment and termination on the Effective Date, borrowings under the
DIP credit facility matured on the earliest of (i) September 22, 2020 (subject
to a two-month extension to be approved by the DIP Lenders), (ii) the sale of
all or substantially all the assets of the Debtors under Section 363 of the
Bankruptcy Code or otherwise, (iii) the effective date of a
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plan of reorganization or liquidation in the Chapter 11 Cases, (iv) the entry of
an order by the bankruptcy court dismissing any of the Chapter 11 Cases or
converting such Chapter 11 Cases to a case under Chapter 7 of the Bankruptcy
Code and (v) the date of termination of the DIP lenders' commitments and the
acceleration of any outstanding extensions of credit, in each case, under the
DIP credit facility under and subject to the DIP Credit Agreement and the
bankruptcy court's orders.

On the Effective Date, the DIP credit facility was paid in full and terminated.
On the Effective Date, each holder of an allowed claim under the DIP credit
facility received its pro rata share of revolving loans, term loans, and
letter-of-credit participations under the Exit Credit Agreement. In addition,
each holder received (or was entitled to receive) its pro rata share of an
equity fee under the Exit Credit Agreement equal to 5% of the New Common Stock
(subject to dilution by shares reserved for issuance under a management
incentive plan and on exercise of the Warrants).

For more information on the DIP credit agreement, please see Note 2 – Exit from a voluntary reorganization in chapter 11.

Mandates


Each holder of the Old Common Stock outstanding before the Effective Date that
did not opt out of the release under the Plan, is entitled to receive its pro
rata share of seven-year warrants (Warrants) to purchase an aggregate of 12.5%
of the shares of New Common Stock, at an aggregate exercise price equal to the
$650.0 million principal amount of the Notes plus interest thereon to the May
15, 2021 maturity date of the Notes. On the Effective Date, we entered into a
Warrant Agreement (Warrant Agreement) with American Stock Transfer & Trust
Company, LLC. The Warrants expire on the earliest of (i) September 3, 2027, (ii)
consummation of a Cash Sale (as defined in the Warrant Agreement) or (iii) the
consummation of a liquidation, dissolutions or winding up of the company (such
earliest date, the Expiration Date). Each Warrant that is not exercised on or
before the Expiration Date will expire, and all rights under that Warrant and
the Warrant Agreement will cease on the Expiration Date. On December 21, 2020,
we issued approximately 1.8 million Warrants to the holders of the Old Common
Stock that did not opt out of the releases under the Plan and owned their shares
of Old Common Stock in street name through the facilities of the DTC. On
February 11, 2021, we issued 42,511 Warrants to certain holders of the Old
Common Stock that did not opt out of the releases under the Plan and owned their
shares through direct registration with the company's transfer agent (Direct
Registration). We expect to issue approximately 37,000 additional Warrants to
the holders of the Old Common Stock that did not opt out of the releases under
the Plan and owned their shares through Direct Registration. Under the Plan,
additional Warrants will be issued in book-entry form through the facilities of
the DTC, and each holder owning shares of Old Common Stock through Direct
Registration must provide that holder's brokerage account information to the
company to receive such holder's distribution of Warrants. Holders of shares of
the Old Common Stock that owned shares through Direct Registration should
contact Prime Clerk, LLC at (877) 720-6581 (Toll Free) or (646) 979-4412 (Local)
to obtain the forms necessary to receive their distribution. Any distribution
not made will be deemed forfeited at the first anniversary of the Effective
Date.

Capital required


Oil and Natural Gas Dispositions, Acquisitions, and Capital Expenditures. Most
of our capital expenditures in our oil and natural gas are discretionary and
directed toward growth. Any decision 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. During the Successor Period and
Predecessor Period of 2020, we participated in the drilling of three wells (0.30
net wells) and 16 wells (0.35 net wells), respectively, compared to 115 gross
wells (29.15 net wells) in 2019.

During the Successor Period of 2020, capital expenditures by this segment for
oil and gas properties on the full cost method, excluding a $1.7 million
reduction in the ARO liability and no acquisitions, totaled $4.0 million. During
the Predecessor Period of 2020, capital expenditures, excluding a $29.2 million
reduction in the ARO liability and $0.4 million in acquisitions (including
associated ARO), totaled $5.4 million compared to 2019 capital expenditures of
$264.9 million (excluding a $0.1 million reduction in the ARO liability and $3.7
million in acquisitions).

For 2021, we plan to focus our capital expenditures on the development of proven properties and the acquisition of proven and producing properties.


We sold non-core oil and natural gas assets, net of related expenses, for $0.4
million, $1.2 million and $21.8 million during the Successor Period, and
Predecessor Period of 2020, and the year 2019, respectively. Proceeds from those
dispositions
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The table of contents has reduced the net book value of our full cost pool without any gain or loss being recognized. We plan to pursue additional disposals of non-core assets in 2021.


Contract Drilling Dispositions, Acquisitions, and Capital Expenditures. During
2019, we completed construction and placed into service our 12th, 13th, and 14th
BOSS drilling rigs. These drilling rigs were subject to long-term contracts with
third party operators.

We have not built any new BOSS drilling rigs in 2020. We have no commitments or current plans to build additional BOSS drilling rigs in 2021.


For 2021, capital expenditures are expected to primarily be for maintenance
capital on operating drilling rigs and the possible conversion of certain SCR
drilling rigs to AC drilling rigs if practicable. We also plan to pursue the
disposal or sale of our non-core, idle drilling rig fleet. For 2020, we incurred
$0.6 million during the Successor Period and $2.4 million during the Predecessor
Period in capital expenditures, compared to $40.6 million in 2019.

Mid-Stream Dispositions, Acquisitions, and Capital Expenditures. At the Cashion
processing facility in central Oklahoma, total throughput volume for the fourth
quarter of 2020 averaged approximately 64.2 MMcf per day and total production of
natural gas liquids averaged approximately 252,000 gallons per day. For 2020, we
continued to connect new wells to this system for third party producers. Since
the first of 2020, we connected 18 new wells to this system from producers. The
total processing capacity of the Cashion system is 105 MMcf per day.

In the Appalachian region, at the Pittsburgh Mills collection system, the average collected volume for the fourth quarter of 2020 was 131.7 MMcf per day and the average collected volume for 2020 was 152.3 MMcf per day. In 2020, we connected four new infill wells to an existing well pad.


Also, in the Appalachian area at our Snow Shoe gathering system, the average
gathering volume for the fourth quarter was 2.5 MMcf per day and the average
gathered volume for 2020 was 3.0 MMcf per day. In 2020, we did not connect any
new wells to this system. At Snow Shoe for 2020, we also charged a demand fee
based on a volume of 55 MMcf per day. This demand fee volume will be reduced in
2021 to 51 MMcf per day. Additionally, in 2020, we recognized a shortfall fee
from a producer on this system for $5.3 million. This fee will be invoiced in
the first quarter of 2021.

At the Hemphill processing facility located in the Texas panhandle, average
total throughput volume for the fourth quarter of 2020 was 46.6 MMcf per day and
average total throughput volume for 2020 was 51.3 MMcf per day. Total average
production of natural gas liquids for the fourth quarter of 2020 decreased to
approximately 110,000 gallons per day due to operating in ethane rejection.
Total production of natural gas liquids for 2020 averaged approximately 152,000
gallons per day. The total processing capacity of the Hemphill system is 135
MMcf per day. In 2020, we did not connect any new wells to this system.
Currently there are no active rigs in the area, and we do not anticipate any new
well connects for this system.

At the Segno gathering system located in East Texas, the average throughput
volume for the fourth quarter of 2020 decreased to approximately 31.0 MMcf per
day due to declining production volume along with no new drilling activity in
the area. For 2020, the average throughput volume for this system was
approximately 40 MMcf per day. During 2020, we did not connect any new wells to
this system.

Our mid-stream segment incurred $1.3 million during the Successor Period and
$9.3 million during the Predecessor Period in capital expenditures as compared
to $64.4 million in 2019, which included $16.1 million for an acquisition. For
2021, our estimated capital expenditures will be approximately $15.0 million
which we expect to be primarily for the maintenance and operation of our assets
and connection of new wells.

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Contractual Commitments

TO December 31, 2020, we had these contractual obligations:

                                                                    Payments Due by Period
                                                       Less Than             2-3                4-5                After
                                     Total              1 Year              Years              Years              5 Years
                                                                        (In thousands)
Long-term debt (1)                $ 118,637          $    6,494          $  12,696          $  99,447          $        -
Operating leases (2)                  5,520               4,075              1,376                 16                  53
Finance lease interest and
maintenance (3)                         558                 558                  -                  -                   -
Firm transportation commitments
(4)                                   1,379               1,020                359                  -                   -
Total contractual obligations     $ 126,094          $   12,147          $  14,431          $  99,463          $       53


_________________________
1.See previous discussion in MD&A regarding our long-term debt. This obligation
is presented in accordance with the terms of the Exit Facility and includes
interest calculated using our December 31, 2020 interest rates of 6.6% for our
Exit Credit Agreement. The Exit Credit Agreement has a maturity date of March 1,
2024 and had an outstanding balance as of December 31, 2020 of $99.0 million
($0.6 million is reflected as a current liability in our Consolidated Balance
Sheets). The Superior credit agreement has a maturity date of May 10, 2023 and
had no outstanding balance as of December 31, 2020.
2.We lease certain office space, land, and equipment, including pipeline
equipment and office equipment under the terms of operating leases under ASC 842
expiring through March 2031. We also have short-term lease commitments of $0.2
million. This is lease office space or yards in Oklahoma City, Oklahoma; Houston
and Odessa, Texas; Englewood, Colorado; and Pinedale, Wyoming under the terms of
operating leases expiring through January 2022. Additionally, we have several
equipment leases and lease space on short-term commitments to stack excess
drilling rig equipment and production inventory.
3.Maintenance and interest payments are included in our finance lease
agreements. The finance leases are discounted using annual rates of 4.0%. Total
maintenance and interest remaining are $0.5 million and less than $0.1 million,
respectively.
4.We have firm transportation commitments to transport our natural gas from
various systems for approximately $1.0 million over the next twelve months and
$0.4 million for the one year thereafter.

During the second quarter of 2018, as part of the Superior transaction (see Note
19 - Variable Interest Entity Arrangements), we entered into a contractual
obligation committing us to spend $150.0 million to drill wells in the Granite
Wash/Buffalo Wallow area over three years starting January 1, 2019. For each
dollar of the $150.0 million we do not spend (over the three-year period), we
would forgo receiving $0.58 of future distributions from our ownership interest
in our consolidated mid-stream subsidiary. At December 31, 2020, if we elected
not to drill or spend any additional money in the designated area before
December 31, 2021, the maximum amount we could forgo from distributions would be
$72.6 million. The total amount spent towards the $150.0 million as of
December 31, 2020 was $24.8 million. We do not anticipate meeting the
contractual obligation over the remaining commitment period.

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At December 31, 2020, we also had these commitments and contingencies that could
create, increase or accelerate our liabilities:
                                                          Estimated Amount 

of commitment expiration per period

                                                                 Less
                                            Total               Than 1              2-3                4-5              After 5
Other Commitments                          Accrued               Year              Years              Years              Years
                                                                             (In thousands)

Separation benefit plans (1)           $      4,201          $   1,543               Unknown            Unknown            Unknown
ARO liability (2)                      $     23,356          $   2,121      

$ 3,240 $ 3,159 $ 14,836
Passive gas balancing (3)

            $      3,997               Unknown            Unknown            Unknown            Unknown

Civil liability for accidents at work (4) $ 10,164 $ 1705

          Unknown            Unknown            Unknown

Finance lease obligations (5) $ 3,216 $ 3,216

$ – $ – $ – Contractual liability (6)

                 $      4,172          $   2,583      

$ 1,560 $ 12 $ 18
Other long-term liabilities (7) $ 1,321 $ –

          $   1,321          $       -          $       -
Derivative liabilities-commodity
hedges                                 $      5,706          $   1,047          $   4,659          $       -          $       -


_________________________
1.As of the Effective Date, the Board adopted (i) the Amended and Restated
Separation Benefit Plan of Unit Corporation and Participating Subsidiaries
(Amended Separation Benefit Plan), (ii) the Amended and Restated Special
Separation Benefit Plan of Unit Corporation and Participating Subsidiaries
(Amended Special Separation Benefit Plan) and (iii) the Separation Benefit Plan
of Unit Corporation and Participating Subsidiaries (New Separation Benefit
Plan). In accordance with the Plan, the Amended Separation Benefit Plan and the
Amended Special Separation Benefit Plan allow former employees or retained
employees with vested severance benefits under either plan to receive certain
cash payments in full satisfaction for their allowed separation claim under the
Chapter 11 Cases. In accordance with the Plan, the New Separation Benefit Plan
is a comprehensive severance plan for retained employees, including retained
employees whose severance did not already vest under the Amended Separation
Benefit Plan or the Amended Special Separation Benefit Plan. The New Separation
Benefit Plan provides that eligible employees will be entitled to two weeks of
severance pay per year of service, with a minimum of four weeks and a maximum of
13 weeks of severance pay.
2.When a well is drilled or acquired, under ASC 410 "Accounting for Asset
Retirement Obligations," we record the fair value of liabilities associated with
the retirement of long-lived assets (mainly plugging and abandonment costs for
our depleted wells).
3.We have recorded a liability for those properties we believe do not have
sufficient oil, NGLs, and natural gas reserves to allow the under-produced
owners to recover their under-production from future production volumes.
4.We have recorded a liability for future estimated payments related to workers'
compensation claims primarily associated with our contract drilling segment.
5.This amount includes commitments under finance lease arrangements for
compressors in our mid-stream segment.
6.We have recorded a liability related to the timing of the revenue recognized
on certain demand fees in our mid-stream segment.
7.Due to the issuance of the Coronavirus Aid, Relief, and Economic Security Act
(CARES Act), we have deferred our FICA tax payment.

Derivative activities


Periodically we enter into derivative transactions locking in the prices to be
received for a portion of our oil, NGLs, or natural gas production. Any change
in the fair value of all our derivatives are reflected in our Consolidated
Statements of Operations.

Commodity Derivatives. Our commodity derivatives reduce our exposure to price
volatility and manage price risks. 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, 2020, based on our
fourth quarter 2020 average daily production, the approximated percentages of
our production under derivative contracts were as follows:

                                  2021      2022      2023
Daily oil production              66  %     46  %     26  %
Daily natural gas production      55  %     45  %     25  %



For commodities subject to derivative contracts, those contracts limit the risk
of downward price movements. But they also limit increases in future revenues
that would otherwise result from price movements above the contracted prices.

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Derivative transactions carry with them the risk that the counterparties may not
be able to meet their financial obligations under the transactions. Based on our
evaluation at December 31, 2020, we believe the risk of non-performance by our
counterparties is not material. At December 31, 2020, the fair values of the net
assets we had with each of the counterparties to our commodity derivative
transactions was:
                         December 31, 2020
                           (In millions)
Bank of Oklahoma        $             (5.4)
Bank of Montreal                      (0.3)
Total net liabilities   $             (5.7)



If a legal right of set-off exists, we net the value of the derivative
arrangements we have with the same counterparty in our Consolidated Balance
Sheets. At December 31, 2020, we recorded the fair value of our commodity
derivatives on our balance sheet as current derivative liabilities of $1.0
million and long-term derivative liabilities of $4.7 million. At December 31,
2019, we recorded the fair value of our commodity derivatives on our balance
sheet as current derivative assets of $0.6 million and long-term derivative
liabilities of less than $0.1 million.

 All derivatives are recognized on the balance sheet and measured at fair value.
Any changes in our derivatives' fair value before their maturity (i.e.,
temporary fluctuations in value) are reported in gain (loss) on derivatives in
our Consolidated Statements of Operations.
These gains (losses) as of the periods indicated were:
                                                               Successor                              Predecessor

                                                                                               Period
                                                                Period                       January 1,         For the Year
                                                           September 1, 2020                2020 through            Ended
                                                                through                      August 31,         December 31,
                                                           December 31, 2020                    2020                2019
                                                                           

(In thousands) Gain (loss) on derivatives, including amounts settled during the period of ($ 1,133), ($ 4,244), and $ 16,196, respectively

                                             $             (985)               $   (10,704)         $    4,225



Compensation in shares and incentives


During 2020, we did not grant any awards. We recognized compensation expense of
$6.1 million for all our prior restricted stock awards including the
acceleration of the unrecorded stock compensation expense. We did not capitalize
any compensation cost to oil and natural gas properties since we are currently
not drilling.

During 2019, we granted awards covering 1,500,213 shares of restricted stock.
These awards were granted as retention incentive awards and are being recognized
over the awards' three-year vesting period. These awards were granted as
retention incentive awards and are being recognized over their two- and
three-year vesting periods.

On the Effective Date, all equity-based awards that were outstanding immediately
before the Effective Date were cancelled. The cancellation of the awards
resulted in an acceleration of unrecorded stock compensation expense during the
Predecessor Period.

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.

Oil and natural gas limited partnerships and other entity relationships.


We were the general partner of 13 oil and natural gas partnerships formed
privately or publicly. Each partnership's revenues and costs were shared under
formulas set out in that partnership's agreement. The partnerships repaid us for
contract
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drilling, well supervision, and general and administrative expense. Related
party transactions for contract drilling and well supervision fees were the
related party's share of such costs. These costs were billed the same as
billings to unrelated third parties for similar services. General and
administrative reimbursements consisted of direct general and administrative
expense incurred on the related party's behalf and indirect expenses assigned to
the related parties. Allocations are based on the related party's level of
activity and were considered by us to be reasonable. Our proportionate share of
assets, liabilities, and net income relating to the oil and natural gas
partnerships is included in our consolidated financial statements for the years
prior to termination. The partnerships were terminated during the second quarter
of 2019 with an effective date of January 1, 2019 at a repurchase cost of $0.6
million, net of Unit's interest.

Effects of inflation


The effect of inflation in the oil and natural gas industry is primarily driven
by the prices for oil, NGLs, and natural gas. Increases in these prices increase
the demand for our contract drilling rigs and services. This increase in demand
affects the dayrates we can obtain for our contract drilling services. During
periods of higher demand for our drilling rigs we have experienced increases in
labor costs and the costs of services to support our drilling rigs.
Historically, during this same period, when oil, NGLs, and natural gas prices
declined, labor rates did not come back down to the levels existing before the
increases. If commodity prices increase substantially for a long period,
shortages in support equipment (like drill pipe, third party services, and
qualified labor) can cause additional increases in our material and labor costs.
Increases in dayrates for drilling rigs also increase the cost of drilling our
oil and natural gas properties. How inflation will affect us in the future will
depend on increases, if any, realized in our drilling rig rates, the prices we
receive for our oil, NGLs, and natural gas, and the rates we receive for
gathering and processing natural gas.

Off-balance sheet provisions


We do not currently utilize any off-balance sheet arrangements with
unconsolidated entities to enhance liquidity and capital resource positions, or
for any other purpose. However, as is customary in the oil and gas industry, we
are subject to various contractual commitments.

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Results of Operations
Provided below is a comparison of selected operating and financial data after
eliminations (in thousands unless otherwise specified):
                                                Successor                              Predecessor
                                                 Period                        Period
                                            September 1, 2020              January 1, 2020         Year Ended
                                                 through                       through            December 31,             Percent
                                            December 31, 2020              August 31, 2020            2019                Change (1)
Total revenue                              $        133,528                $    276,957          $   674,634                      (39) %
Net loss                                   $        (13,988)               $   (890,624)         $  (553,828)                     (63) %
Net income attributable to non-controlling
interest                                   $          4,152                $     40,388          $        51                          NM
Net loss attributable to Unit Corporation  $        (18,140)               $   (931,012)         $  (553,879)                     (71) %

Oil and Natural Gas:
Revenue                                    $         57,578                $    103,439          $   325,797                      (51) %
Operating costs excluding depreciation,
depletion, amortization, and impairment    $         25,256                $    117,691          $   135,124                        6  %
Depreciation, depletion, and amortization  $         14,869                $     68,762          $   168,651                      (50) %
Impairment of oil and natural gas
properties                                 $         26,063                $    393,726          $   559,867                      (25) %
Average oil price received (Bbl)           $          37.29                $      31.98          $     57.49                      (45) %
Average oil price per barrel received
excluding derivatives                      $          39.23                $      35.14          $     55.13                      (36) %
Average NGL price received (Bbl)           $           9.28                $       4.83          $     12.42                      (59) %
Average NGLs price per barrel received
excluding derivatives                      $           9.28                $       4.83          $     12.42                      (59) %
Average natural gas price received (Mcf)   $           1.92                $       1.14          $      2.04                      (41) %
Average natural gas price per mcf received
excluding derivatives                      $           1.91                $       1.11          $      1.88                      (38) %
Oil production (MBbls)                                  626                       1,562                3,208                      (32) %
NGLs production (MBbls)                               1,045                       2,399                4,773                      (28) %
Natural gas production (MMcf)                        11,006                      26,563               53,065                      (29) %
Depreciation, depletion, and amortization
rate (Boe)                                 $           4.21                $       7.77          $      9.66                      (30) %

Contract Drilling:
Revenue                                    $         19,413                $     73,519          $   168,383                      (45) %
Operating costs excluding depreciation     $         13,852                $     51,810          $   115,998                      (43) %
Depreciation                               $          2,102                $     15,544          $    51,552                      (66) %
Impairment of contract drilling equipment  $              -                $    410,126          $         -                        -  %
Impairment of goodwill                     $              -                $          -          $    62,809                     (100) %
Percentage of revenue from daywork
contracts                                               100  %                      100  %               100  %                     -  %
Average number of drilling rigs in use                  7.2                        11.5                 24.6                      (59) %
Total drilling rigs available for use at
the end of the period                                    58                          58                   58                        -  %
Average dayrate on daywork contracts       $         17,807                $     18,911          $    18,762                       (1) %


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                                                 Successor                              Predecessor

                                                                                Period
                                                  Period                      January 1,           Year Ended
                                             September 1, 2020               2020 through
                                                  through                     August 31,          December 31,             Percent
                                             December 31, 2020                   2020                 2019                Change (1)
Mid-Stream:
Revenue                                     $         56,537                $    99,999          $   180,454                      (13) %
Operating costs excluding depreciation and
amortization                                $         42,169                $    68,045          $   133,606                      (18) %
Depreciation and amortization               $         10,659                $    29,371          $    47,663                      (16) %
Impairment of gas gathering and processing
equipment and line fill                     $              -                $    63,962          $     3,040                          NM
Gas gathered-Mcf/day                                 324,892                    388,506              435,646                      (16) %
Gas processed-Mcf/day                                135,615                    158,031              164,482                       (8) %
Gas liquids sold-gallons/day                         441,761                    612,301              625,873                      (11) %
Number of natural gas gathering systems                   17                         18                   19                       (7) %
Number of processing plants                               11                         11                   11                        -  %

Corporate and other:
Loss on abandonment of assets               $              -                $    18,733          $         -                        -  %
General and administrative expense          $          6,702                $    42,766          $    38,246                       29  %
Other depreciation                          $            332                $     1,819          $     7,707                      (72) %
Gain (loss) on disposition of assets        $            619                $        89          $    (3,502)                     120  %
Other income (expense):
Interest income                             $              -                $        58          $        49                       18  %
Interest expense, net                       $         (3,275)               $   (22,882)         $   (37,061)                     (29) %
Reorganization costs, net                   $         (2,273)               $   133,975          $         -                        -  %
Write-off debt issuance costs               $              -                $    (2,426)         $         -                        -  %
Gain (loss) on derivatives                  $           (985)              
$   (10,704)         $     4,225                          NM
Other                                       $            100                $     2,034          $      (236)                         NM
Income tax benefit                          $           (302)               $   (14,630)         $  (132,326)                      89  %
Average interest rate                                    6.8  %                     5.5  %               6.4  %                   (14) %
Average long-term debt outstanding          $        121,740                $   526,167          $   744,978                      (35) %


_________________________

1.NM – A percentage calculation does not make sense due to a denominator of zero value or a percentage change greater than 200.

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Oil and Natural Gas

Oil and natural gas revenues decreased $164.8 million or 51% in 2020 as compared
to 2019 due primarily to lower commodity prices and production. Oil production
decreased 32%, NGLs production decreased 28%, and natural gas production
decreased 29%. Average oil prices between the comparative years decreased 45% to
$31.61 per barrel, NGLs prices decreased 59% to $5.10 per barrel, and natural
gas prices decreased 41% to $1.20 per Mcf.

Oil and natural gas operating costs increased $7.8 million or 6% between the
comparative years of 2020 and 2019 primarily due to higher G&A expenses from the
litigation settlements and no longer capitalizing directly related overhead
costs in 2020 partially offset by lower LOE and gross production taxes.

DD&A decreased $85.0 million or 50% primarily due to a 30% decrease in our DD&A
rate and a 29% decrease in equivalent production. The decrease in our DD&A rate
resulted primarily from the effect of the ceiling test write-downs during 2020.

During the Successor Period of 2020, we recorded non-cash ceiling test
write-downs of $26.1 million pre-tax primarily due to the use of average
12-month historical commodity prices for the ceiling test versus forward prices
for our Fresh Start fair value estimates. During the Predecessor Period of 2020,
we recorded non-cash ceiling test write-downs of $393.7 million, pre-tax ($346.6
million, net of tax) due to the reduction for the 12-month average commodity
prices and the impairment of our unproved oil and gas properties. We also
recorded an expense of $17.6 million related to the write-down of our salt water
disposal asset that we considered abandoned. During 2019, we recorded non-cash
ceiling test write-downs of $559.4 million, pre-tax ($422.4 million, net of tax)
due to the reduction of the 12-month average commodity prices and the removal of
proved undeveloped reserves due to the uncertainty regarding our ability to
finance future capital expenditures. We also recorded in 2019 a $0.5 million
impairment on gathering systems with wells no longer producing.

Contract drilling

Drilling revenues have declined $ 75.5 million or 45% in 2020 compared to 2019. The decrease is mainly due to a 59% decrease in the average number of rigs in service compared to 2019. Average use of rigs fell from 24.6 rigs in 2019 to 10.1 rigs in 2020.


Drilling operating costs decreased $50.3 million or 43% in 2020 compared to
2019. The decrease was due primarily to less drilling rigs operating. Contract
drilling depreciation decreased $33.9 million or 66% also due primarily to less
drilling rigs operating and from lower depreciable net book value due to
impairments recognized in the first half of 2020.

At March 31, 2020, due to market conditions, we performed impairment testing on
two asset groups which were comprised of the SCR diesel-electric drilling rigs
and the BOSS drilling rigs. We concluded that the net book value of the SCR
drilling rigs asset group was not recoverable through estimated undiscounted
cash flows and recorded a non-cash impairment charge of $407.1 million in the
first quarter of 2020. We also recorded an additional non-cash impairment charge
of $3.0 million for other drilling equipment. These charges are included within
impairment charges in our Consolidated Statements of Operations. No impairment
was needed on the BOSS drilling rigs asset group as the undiscounted cash flows
exceeded the carrying value of the asset group.

In 2019, we recognized goodwill impairment charges of $62.8 million, pre-tax
($59.8 million, net of tax) representing all our goodwill which is related to
our contract drilling segment.

Mid-stream


Our mid-stream revenues decreased $23.9 million or 13% in 2020 as compared to
2019 primarily due to decreased NGLs, gas, and condensate sales as a result of
lower prices and lower volumes resulting from fewer wells connected and
declining wellhead volumes. Gas processing volumes per day decreased 8% between
the comparative years primarily due to lower purchased volumes from our
processing facility in the Texas panhandle. Gas gathering volumes per day
decreased 16% primarily due to lower volumes from most of our major gathering
and processing systems resulting from fewer wells connected and declining
wellhead volumes except from the Cashion facility.

Operating costs decreased $23.4 million or 18% in 2020 compared to 2019
primarily due to a decrease in purchase prices. Depreciation and amortization
decreased $7.6 million or 16% primarily due to lower depreciable net book value
from the impairment recognized in the first quarter of 2020.
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During the first quarter of 2020, we determined that the carrying value of
certain long-lived asset groups located in southern Kansas and central Oklahoma,
where lower pricing is expected to impact drilling and production levels, are
not recoverable and exceeded their estimated fair value. Based on the estimated
fair value of the asset groups, we recorded non-cash impairment charges of $64.0
million. In 2019, we recorded a $3.0 million impairment due to decreased value
of line fill due to lower prices and from the retirement of two older systems.

Loss on abandonment of assets


During the first quarter of 2020, we evaluated the carrying value of our salt
water disposal assets. Based on our revised forecast of asset utilization, we
determined certain assets were no longer expected to be used and wrote off
certain salt water disposal assets that we now consider abandoned. We recorded
expense of $17.6 million related to the write-down of our salt water disposal
asset in the first quarter of 2020. In the third quarter of 2020, we recorded
expense of $1.2 million related to the write-down of our drilling line asset.

General and administrative


General and administrative expenses increased $11.2 million or 29% in 2020
compared to 2019 primarily due to consulting fees paid prior to filing for
bankruptcy and costs incurred for separation benefits provided to employees that
were part of our reduction in force in April 2020. We incurred $20.2 million in
advisory and restructuring fees.

Gain (loss) on disposal of assets


(Gain) loss on disposition of assets decreased $4.2 million in 2020 compared to
2019. The loss in 2020 was primarily related to the sale of vehicles, drilling
rigs, and other drilling equipment, while the gain in 2019 was primarily from
the retirement of old rig inventory.

Other income (expenses)


Interest expense, net of capitalized interest, decreased $10.9 million between
the comparative years of 2020 and 2019. We capitalized interest based on the net
book value associated with unproved properties not being amortized, the
construction of additional drilling rigs, and the construction of gas gathering
systems. Because we are not currently undergoing any capital projects, we had no
capitalized interest for 2020 compared to $16.2 million in 2019 that was netted
against our gross interest of $53.2 million for 2019. Our average interest rate
increased due to the new Exit Credit Agreement terms and our average debt
outstanding was decreased primarily due to the Notes being settled with the
Plan.

Elements of reorganization, net


Reorganization items, net represent any of the expenses, gains, and losses
incurred subsequent to and as a direct result of the Chapter 11 proceedings. For
more detail, see Note 2 - Emergence From Voluntary Reorganization Under Chapter
11.

Write-off of debt securities issuance costs


Due to the remaining commitments of the Unit credit agreement being terminated
by the lenders, the unamortized debt issuance costs of $2.4 million were written
off during the second quarter of 2020.

Gain (loss) on derivatives

Gain (loss) on derivatives decreased $ 15.9 million primarily due to fluctuations in futures prices used to estimate fair value in mark-to-market accounting.

Tax benefit


Income tax benefit decreased $117.4 million in 2020 compared to 2019. We
recognized an income tax benefit of $14.9 million in 2020 compared to an income
tax benefit of $132.6 million in 2019. The 2020 income tax benefit was lower
primarily due to the recognition of a full valuation allowance against our net
deferred tax assets due to our emergence from bankruptcy in 2020 and fresh start
accounting principles.

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Our effective tax rate was 1.6% for 2020 compared to 19.3% for 2019. The
effective tax rate for the current year was lower as compared to 2019 because of
the recognition of a full valuation allowance as described above. The increase
in our valuation allowance was due to determining it was more likely than not
that the net deferred tax assets would not be fully realizable. We paid no
federal or state income taxes during 2020.

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