NOTE 69 – LONG-TERM DEBT AND OTHER LONG-TERM LIABILITIES

Long-Term Debt

~~Our~~As of the date indicated, our long-term debt consisted of the following:


	June 30, 2021		December 31, 2020
	(In thousands)
Current portion of long-term debt:
Exit credit agreement with an average interest rate of 6.7% and 6.6% at June 30, 2021 and December 31, 2020, respectively	$	0	$	600
Long-term debt:
Exit credit agreement with an average interest rate of 6.7% and 6.6% at June 30, 2021 and December 31, 2020, respectively	$	35,000	$	98,400

Exit Credit Agreement. On the Effective Date, under the terms of the Plan, the company entered into an amended and restated credit agreement (the Exit credit agreement), providing for a $140.0 million senior secured revolving credit facility (RBL Facility) and a $40.0 million senior secured term loan facility, among (i) the company, UDC, and UPC (together, the Borrowers), (ii) the guarantors party thereto, including the company and all of its subsidiaries existing as of the ~~dates indicated consisted~~Effective Date (other than Superior Pipeline Company, L.L.C. and its subsidiaries), (iii) the lenders party thereto from time to time (Lenders), and (iv) BOKF, NA dba Bank of Oklahoma as administrative agent and collateral agent (in such capacity, the Administrative Agent).

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

On April 6, 2021, the company finalized the first amendment to the Exit credit agreement. Under the first amendment, the company reaffirmed its borrowing base of $140.0 million of the ~~following:~~

September 30,
2017 December 31,
2016
(In thousands)
Credit agreement with an average interest rate of 3.3% and 2.8% at September 30, 2017 and December 31, 2016, respectively $ 162,100
$ 160,800
6.625% senior subordinated notes due 2021 650,000
650,000
Total principal amount 812,100
810,800
Less: unamortized discount (2,380 ) (2,804 )
Less: debt issuance costs, net (5,887 ) (7,079 )
Total long-term debt $ 803,833
$ 800,917

~~Credit Agreement.~~ ~~Our Senior Credit Agreement (credit agreement) is scheduled~~RBL, amended certain financial covenants, and received less restrictive terms, among others, as it relates to ~~mature on April 10, 2020.~~the disposition of assets and the use of proceeds from those dispositions. On July 27, 2021, the company finalized the second amendment to the Exit credit agreement. Under the second amendment, the company obtained confirmation that the Term Loan had been paid in full prior to the amendment date and received one-time waivers related to the disposition of assets.

The Exit credit agreement requires the ~~amount we can borrow is~~company to comply with certain financial ratios, including a covenant that the ~~lesser~~company will not permit the Net Leverage Ratio (as defined in the Exit credit agreement) as of the ~~amount we elect as the commitment amount or the value~~last day of the ~~borrowing~~fiscal quarters ended (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 ended December 31, 2020, the company may not (a) permit the Current Ratio (as defined in the Exit credit agreement) as of the last day of any fiscal quarter to be less than 1.00 to 1.00 or (b) permit the Interest Coverage Ratio (as defined in the Exit credit agreement) as of the last day of any fiscal quarter to be less than 2.50 to 1.00. The Exit credit agreement also contains provisions, among others, that limit certain capital expenditures, and require certain hedging activities. The Exit credit agreement further requires the company provide quarterly financial statements within 45 days after the end of each of the first three quarters of each fiscal year and annual financial statements within 90 days after the end of each fiscal year. As of June 30, 2021, Unit was in compliance with these covenants.

The Exit credit agreement is secured by first-priority liens on substantially all of the personal and real property assets of the Borrowers and the Guarantors, including the company’s ownership interests in Superior.

At June 30, 2021, we had $35.0 million of long-term borrowings and $2.8 million of letters of credit outstanding under the Exit credit agreement.

Table of Contents

Superior Credit Agreement. On May 10, 2018, Superior signed a five-year, $200.0 million senior secured revolving credit facility with an option to increase the credit amount up to $250.0 million, subject to certain conditions (Superior credit agreement). The maturity date of borrowings under the Superior credit agreement is March 10, 2023. 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 ~~as determined~~rate (greater of (i) the federal funds rate plus 0.5%, (ii) the prime rate, and (iii) the Thirty-Day LIBOR Rate (as defined in the Superior credit agreement)) plus the applicable margin of 1.00% to 2.25%. The obligations under the Superior credit agreement are secured by mortgage liens on certain of Superior’s processing plants and gathering systems. The Superior credit agreement provides that if ICE Benchmark Administration no longer reports the ~~lenders, but~~LIBOR or Administrative Agent determines in ~~either event not~~good faith that the rate so reported no longer accurately reflects the rate available in the London Interbank Market or if such index no longer exists or accurately reflects the rate available to ~~exceed $875.0 million. Our borrowing base and elected commitment~~the Administrative Agent in the London Interbank Market, the Administrative Agent may select a replacement index.

Superior is ~~$475.0 million. We are~~ charged a commitment fee of ~~0.50%~~0.375% on the amount available but not ~~borrowed. That fee~~borrowed which varies based on the amount borrowed as a percentage of the total borrowing base. ~~We paid $1.0 million in origination, agency, syndication, and other related fees. We are amortizing these fees over the life of the credit agreement. Under the~~

The Superior credit agreement ~~we pledged the following collateral: (a) 85% of the proved developed producing (discounted as present worth at 8%) total value of our oil and gas properties and (b) 100% of our ownership~~requires that Superior maintain a Consolidated EBITDA to interest ~~in our mid-stream affiliate, Superior Pipeline Company, L.L.C.~~

The borrowing base amount–which is subject to redetermination by the lenders on April 1st and October 1st of each year–is based primarily on a percentage of the discounted future value of our oil and natural gas reserves. The October 2017 redetermination did not result in any changes. We or the lenders may request a onetime special redetermination of the borrowing base between each scheduled redetermination. In addition, we may request a redetermination following the completion of an acquisition that meets the requirements in the credit agreement.

~~At our election, any part of the outstanding debt under the credit agreement may be fixed at a London Interbank Offered Rate (LIBOR). LIBOR interest is computed as the LIBOR base~~expense ratio for the term plus 2.00% to 3.00% depending on the level of debt as a percentage of the borrowing base and is payable at the end of each term, or every 90 days, whichever is less. Borrowings not under LIBOR bear interest at the prime rate specified in the credit agreement that cannot be less than ~~LIBOR plus 1.00%~~. Interest is payable at the end of each month and the principal may be repaid in whole or in part at any time, without a premium or penalty. At September 30, 2017, we had $162.1 million of outstanding borrowings under our credit agreement.

We can use borrowings for financing general working capital requirements for (a) exploration, development, production, and acquisition of oil and gas properties, (b) acquisitions and operation of mid-stream assets, (c) issuance of standby letters of credit, (d) contract drilling services and acquisition of contract drilling equipment, and (e) general corporate purposes.

~~The credit agreement prohibits, among other things:~~

~~the payment of dividends (other than stock dividends) during any fiscal year over 30% of our consolidated net income for the preceding fiscal year;~~

~~the incurrence of additional debt with certain limited exceptions; and~~

~~the creation or existence of mortgages or liens, other than those in the ordinary course of business and with certain limited exceptions, on any of our properties, except in favor of our lenders.~~

~~The credit agreement also requires that we have at the end of each quarter:~~

~~a current ratio (as defined in the credit agreement) of not less than 1 to 1.~~

~~Through the quarter ending March 31, 2019, the credit agreement also requires that we have at the end of each quarter:~~

~~a senior indebtedness ratio of senior indebtedness to consolidated EBITDA (as defined in the credit agreement) for the most recently~~most-recently ended rolling four quarters of ~~no greater than~~ ~~2.75~~at least 2.50 to 1.

~~Beginning with the quarter ending June 30, 2019,~~1.00, and ~~for each following quarter, the credit agreement requires:~~

a ~~leverage ratio of~~ funded debt to ~~consolidated~~Consolidated EBITDA ~~(as defined in the credit agreement) for the most recently ended rolling four fiscal quarters~~ratio of nonot greater than 44.00 to 1.

1.00. The agreement also contains several customary covenants that restrict (subject to certain exceptions) Superior’s ability to incur additional indebtedness, create additional liens on its assets, make investments, pay distributions, sign sale and leaseback transactions, engage in certain transactions with affiliates, engage in mergers or consolidations, sign hedging arrangements, and acquire or dispose of assets. As of ~~September~~June 30, ~~2017, we were~~2021, Superior was in compliance with ~~the~~these covenants.

The Superior credit agreement ~~covenants.~~is used to fund capital expenditures and acquisitions and provide general working capital and letters of credit. As of June 30, 2021, we had no borrowings and $1.4 million of letters of credit outstanding under the Superior credit agreement.

~~6.625% Senior Subordinated Notes.~~ ~~We have an aggregate principal amount of $650.0 million,~~ ~~6.625%~~ ~~senior subordinated notes (the Notes) outstanding. Interest on the Notes is payable semi-annually (in arrears) on May 15 and November 15 of each year. The Notes mature on~~ ~~May 15, 2021. In issuing the Notes, we incurred fees of $14.7 million that are being amortized as debt issuance cost over the life of the Notes.~~

The Notes are subject to an Indenture dated as of May 18, 2011, between us and Wilmington Trust, National Association (successor to Wilmington Trust FSB), as Trustee (the Trustee), as supplemented by the First Supplemental Indenture dated as of May 18, 2011, between us, the Guarantors, and the Trustee, and as further supplemented by the Second Supplemental Indenture dated as of January 7, 2013, between us, the Guarantors, and the Trustee (as supplemented, the 2011 Indenture), establishing the terms of and providing for issuing the Notes. The Guarantors are most of our direct and indirect subsidiaries. The discussion of the Notes in this report is qualified by and subject to the actual terms of the 2011 Indenture.

Unit ~~as the parent company, has no independent assets or operations. The guarantees by the Guarantors of the Notes~~is not a party to and does not guarantee Superior's credit agreement.

(registered under registration statements) are full and unconditional, joint and several, subject to certain automatic customary releases, are subject to certain restrictions on the sale, disposition, or transfer of the capital stock or substantially all of the assets of a subsidiary guarantor, and other conditions and terms set out in the 2011 Indenture. Any of our subsidiaries that are not Guarantors are minor. There are no significant restrictions on our ability to receive funds from any of our subsidiaries through dividends, loans, advances, or otherwise.

We may redeem all or, occasionally, a part of the Notes at certain redemption prices, plus accrued and unpaid interest. If a “change of control” occurs, subject to certain conditions, we must offer to repurchase from each holder all or any part of that holder’s Notes at a purchase price in cash equal to ~~101%~~ of the principal amount of the Notes plus accrued and unpaid interest to the date of purchase. The 2011 Indenture contains customary events of default. The 2011 Indenture also contains covenants including those that limit our ability and the ability of certain of our subsidiaries to incur or guarantee additional indebtedness; pay dividends on our capital stock or redeem capital stock or subordinated indebtedness; transfer or sell assets; make investments; incur liens; enter into transactions with our affiliates; and merge or consolidate with other companies. We were in compliance with all covenants of the Notes as of ~~September 30, 2017~~.

Other Long-Term Liabilities

Other long-term liabilities consisted of the following:



	June 30, 2021		December 31, 2020
	(In thousands)
Asset retirement obligation (ARO) liability	$	23,172	$	23,356
Workers’ compensation	11,730		10,164
Finance lease obligations	0		3,216
Contract liability	2,724		4,172
Separation benefit plans	3,237		4,201
Gas balancing liability	4,238		3,997
Other long-term liability	1,321		1,321
	46,422		50,427
Less current portion	7,551		11,168
Total other long-term liabilities	$	38,871	$	39,259

Table of default. The 2011 Indenture also contains covenants including those that limit our ability and the ability of certain of our subsidiaries to incur or guarantee additional indebtedness; pay dividends on our capital stock or redeem capital stock or subordinated indebtedness; transfer or sell assets; make investments; incur liens; enter into transactions with our affiliates; and merge or consolidate with other companies. We were in compliance with all covenants of the Notes as of September 30, 2017.Contents

Capital Requirements

Oil and Natural Gas Segment Dispositions, Acquisitions, and Capital Expenditures. Most of our capital expenditures for this segment are discretionary and directed toward ~~future~~ growth. Our decisions to increase our oil, NGLs, and natural gas reserves through acquisitions or through drilling depends on the prevailing or expected market conditions, potential return on investment, future drilling potential, and opportunities to obtain financing, ~~under the circumstances~~ which provide us ~~with~~ flexibility in deciding when and if to incur these costs. We ~~completed drilling 43~~participated in the completion of 10 gross wells ~~(15.10~~(0.77 net wells) drilled by other operators in the first ~~nine~~six months of ~~2017~~2021 compared to 1527 gross wells ~~(7.77~~(6.16 net wells) drilled by other operators in which we participated in the first ~~nine~~six months of ~~2016.~~2020.

On April 3, 2017, we closed an acquisition of certain oil and natural gas assets located primarily in Grady and Caddo Counties in western Oklahoma. The final adjusted value of consideration given was $54.3 million. As of January 1, 2017, the effective date of the acquisition, the estimated proved oil and gas reserves of the acquired properties were 3.2 million barrels of oil equivalent (MMBoe). The acquisition added approximately 8,300 net oil and gas leasehold acres to our core Hoxbar area in southwestern Oklahoma including approximately 47 proved developed producing wells. This acquisition included 13 potential horizontal drilling locations not otherwise included in our existing acreage. Of the acreage acquired, approximately 71% was held by production. We also received one gathering system as part of the transaction.

Capital expenditures for oil and gas properties on the full cost method for the first ~~nine~~six months of ~~2017~~2021 by this segment, excluding ~~$56.4 million for acquisitions and~~ a ~~$2.8 million in the ARO liability, totaled $143.7 million. Capital expenditures for the first nine months of 2016, excluding a $29.4~~$1.1 million reduction in the ARO liability, totaled ~~$91.9~~$5.9 million. Capital expenditures for the first six months of 2020, excluding $0.2 million for acquisitions and a $3.4 million reduction in the ARO liability, totaled $9.9 million.

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

On June 25, 2021, the company entered into a purchase and sale agreement to which we agreed to sell substantially all of our wells and the leases related thereto located near Oklahoma City, Oklahoma for $19.5 million, subject to customary closing and post-closing adjustments. The divestiture closed on August 16, 2021, with an effective date of May 1, 2021. The sale of these assets will not result in a significant alteration of the full cost pool, and therefore no gain or loss will be recognized.

On March 30, 2021, the company entered into a purchase and sale agreement to which we agreed to sell substantially all of our wells and the leases related thereto located in Reno and Stafford Counties, Kansas for $7.1 million, subject to customary closing and post-closing adjustments. This divestiture closed on May 6, 2021, with an effective date of February 1, 2021. The sale of these assets did not result in a significant alteration of the full cost pool and therefore, no gain or loss was recognized.

We plan to participate in drilling approximately 60 to 65 gross wells in 2017 and our total estimated capital expenditures (excluding any possible acquisitions) for this segment are approximately $216.0 million. Whether we can drill the full numbersold $4.4 million of ~~wells planned depends on several factors, many of which are beyond our control, including the availability of drilling rigs, availability of pressure pumping services, prices for~~additional non-core oil ~~NGLs,~~ and natural gas ~~demand for oil, NGLs, and natural gas,~~assets, net of related expenses, during the first six months of 2021, compared to $0.9 million during the first six months of 2020. These proceeds reduced the net book value of our full cost ~~to drill wells, the weather, and the efforts of outside industry partners.~~pool with no gain or loss recognized.

Contract Drilling Segment Dispositions, Acquisitions, and Capital Expenditures. ~~During~~For 2021, capital expenditures are expected to primarily be for maintenance capital on operating drilling rigs. We also plan to pursue the disposal or sale of our non-core, idle drilling rig fleet. We incurred $0.5 million in capital expenditures during the first ~~quarter~~six months of ~~2017, we were awarded a term contract~~2021, compared to ~~build our tenth BOSS rig. Construction was completed and the drilling rig was placed into service late in the second quarter.~~

Our estimated 2017 capital expenditures for this segment are approximately $38.0 million. At September 30, 2017, we had commitments to purchase approximately $3.9 million for drilling equipment over the next year. We have spent $30.0$2.8 million for capital expenditures during the first ~~nine~~six months of ~~2017,~~2020.

We sold non-core contract drilling assets for proceeds of $3.9 million, net of related expenses, during the six months ended June 30, 2021, compared to ~~$7.2~~proceeds of $2.8 million ~~for capital expenditures~~ during the ~~first nine~~six months ended June 30, 2020. These proceeds resulted in net gains of ~~2016.~~$2.1 million during the six months ended June 30, 2021, compared to $0.1 million during the six months ended June 30, 2020.

Mid-Stream Dispositions, Acquisitions, and Capital Expenditures. In the Appalachian region, our Pittsburgh Mills gathering system, in Allegheny and Butler counties, continues to produce consistent financial results. Our average gathered volume for the third quarter of 2017 is approximately 128.5 MMcf per day. We connected the new Allen well pad in May and it included five new wells. We did not connect any new wells in the third quarter. We are constructing a pipeline to connect the Miller well pad, which will be the next pad connected to our system. The Miller pad will include seven new wells and we anticipate it will be ready to flow in the third quarter of 2018. Also, we anticipate several in-fill wells to be drilled and connected to our system in the second half of 2018.

At our Hemphill Texas system, our total throughput volume averaged 60.8 MMcf per day for the third quarter of 2017 and our total production of natural gas liquids was approximately 164,000 gallons per day. During the third quarter, we connected two new wells and since the beginning of 2017, we connected four new wells to this processing facility. Our oil and gas segment continues to operate a rig and we anticipate connecting two more wells in the fourth quarter.

At our Cashion processing facility in central Oklahoma, our total throughput volume for the third quarter of 2017 averaged approximately 38.4 MMcf per day and our total production of natural gas liquids was approximately 196,000 gallons per day. Total processing capacity for this facility remains at approximately 45 MMcf per day. We connected four new wells to this system in the third quarter for a total of six new wells connected in 2017. We completed a construction project that allows us to bring additional gas to this processing plant from a third party producer. This new producer will deliver fee-based volume to us for five years or will pay a shortfall fee settled annually. We are in the process of constructing a new pipeline extension which will allow us to connect a new producer to our system. We have connected one well from this producer and plan to connect two more wells in the fourth quarter.

At our Bellmon processing facility in the Mississippian play in north central Oklahoma, we connected two new wells in the third quarter of 2017 and since the beginning of 2017, we connected nine new wells to this processing facility. Our total throughput volume averaged approximately 27.5 MMcf per day. Total natural gas liquids averaged approximately 131,000 gallons per day while operating in ethane recovery mode at this facility. Total processing capacity at this system is approximately 90 MMcf per day.

At our Segno gathering facility in Southeast Texas, gathered volume for the third quarter of 2017 averaged approximately 81.5 MMcf per day. At this facility, we have increased our gathering and dehydration capacity to approximately 120 MMcf per day. We have connected two new wells to this system in 2017.

During the first ~~nine~~six months of ~~2017,~~2021, our mid-stream segment incurred ~~$10.1~~$4.1 million in capital expenditures as compared to ~~$11.1~~$9.0 million in the first ~~nine~~six months of ~~2016.~~2020. For ~~2017, our estimated~~2021, we estimate total capital expenditures ~~are~~of approximately ~~$18.9 million.~~$15.0 million, primarily for the maintenance and operation of our assets and connection of new wells.

~~Contractual Commitments~~

~~At September 30, 2017, we had certain contractual obligations including:~~

Payments Due by Period
Total
Less
Than
1 Year

2-3
Years

4-5
Years

After
5 Years
(In thousands)
Long-term debt ⁽¹⁾
$ 981,786
$ 48,443
$ 256,444
$ 676,899
$ —
Operating leases ⁽²⁾
4,698
3,209
1,200
289
—
Capital lease interest and maintenance⁽³⁾
7,653
2,362
4,254
1,037
—
Drill pipe, drilling components, and equipment purchases ⁽⁴⁾
3,887
3,887
—
—
—
Total contractual obligations $ 998,024
$ 57,901
$ 261,898
$ 678,225
$ —

~~_______________________~~


~~(1)~~	See previous discussion in MD&A regarding our long-term debt. This obligation is presented in accordance with the terms of the Notes and credit agreement and includes interest calculated using our September 30, 2017 interest rates of 6.625% for the Notes and 3.3% for the credit agreement. Our credit agreement has a maturity date of April 10, 2020.


~~(2)~~	We lease office space or yards in Edmond and Oklahoma City, Oklahoma; Houston, Texas; Englewood, Colorado; Pinedale, Wyoming; and Canonsburg, Pennsylvania under the terms of operating leases expiring through December 2021. 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 capital lease agreements. The capital leases are discounted using annual rates of 4.00%. Total maintenance and interest remaining are $6.3 million and $1.3 million, respectively.


~~(4)~~	~~We have committed to pay $3.9 million for drilling rig components, drill pipe, and related equipment over the year.~~

~~At September 30, 2017, we also had the following commitments and contingencies that could create, increase, or accelerate our liabilities:~~

Estimated Amount of Commitment Expiration Per Period
Other Commitments
Total
Accrued

Less
Than 1
Year

2-3
Years

4-5
Years

After 5
Years
(In thousands)
Deferred compensation plan ⁽¹⁾
$ 5,287
Unknown
Unknown
Unknown
Unknown
Separation benefit plans ⁽²⁾
$ 6,020
$ 775
Unknown
Unknown
Unknown
Asset retirement liability ⁽³⁾
$ 75,485
$ 2,947
$ 48,778
$ 4,247
$ 19,513
Gas balancing liability ⁽⁴⁾
$ 3,322
Unknown
Unknown
Unknown
Unknown
Repurchase obligations ⁽⁵⁾
$ —
Unknown
Unknown
Unknown
Unknown
Workers’ compensation liability ⁽⁶⁾
$ 13,420
$ 6,699
$ 1,699
$ 937
$ 4,085
Capital leases obligations ⁽⁷⁾
$ 16,161
$ 3,806
$ 8,083
$ 4,272
$ —
Other $ —
Unknown
$ —
Unknown
Unknown

~~_______________________~~

~~(1)~~

We provide a salary deferral plan which allows participants to defer the recognition of salary for income tax purposes until actual distribution of benefits, which occurs at either termination of employment, death, or certain defined unforeseeable emergency hardships. We recognize payroll expense and record a liability, included in other long-term liabilities in our Unaudited Condensed Consolidated Balance Sheets, at the time of deferral.

~~(2)~~

Effective January 1, 1997, we adopted a separation benefit plan (“Separation Plan”). The Separation Plan allows eligible employees whose employment is involuntarily terminated or, in the case of an employee who has completed 20 years of service, voluntarily or involuntarily terminated, to receive benefits equivalent to four weeks salary for every whole year of service completed with the company up to a maximum of 104 weeks. To receive payments the recipient must waive certain claims against us in exchange for receiving the separation benefits. On October 28, 1997, we adopted a Separation Benefit Plan for Senior Management (“Senior Plan”). The Senior Plan provides certain officers and key executives of the company with benefits generally equivalent to the Separation Plan. The Compensation Committee of the Board of Directors has absolute discretion in the selection of the individuals covered in this plan. Currently there are no participants in the Senior Plan. On May 5, 2004 we also adopted the Special Separation Benefit Plan (“Special Plan”). This plan is identical to the Separation Benefit Plan with the exception that the benefits under the plan vest on the earliest of a participant’s reaching the age of 65 or serving 20 years with the company.


~~(3)~~	When a well is drilled or acquired, under ASC 410 “Accounting for Asset Retirement Obligations,” we record the discounted fair value of liabilities associated with the retirement of long-lived assets (mainly plugging and abandonment costs for our depleted wells).


~~(4)~~	We have recorded a liability for those properties we believe do not have sufficient oil, NGLs, and natural gas reserves to allow the under-produced owners to recover their under-production from future production volumes.

~~(5)~~

We formed The Unit 1984 Oil and Gas Limited Partnership and the 1986 Energy Income Limited Partnership along with private limited partnerships (the “Partnerships”) with certain qualified employees, officers and directors from 1984 through 2011. One of our subsidiaries serves as the general partner of each of these programs. Effective December 31, 2014, The Unit 1984 Oil and Gas Limited Partnership dissolved and effective December 31, 2016, the two 1986 partnerships were dissolved. The Partnerships were formed for the purpose of conducting oil and natural gas acquisition, drilling and development operations and serving as co-general partner with us in any additional limited partnerships formed during that year. The Partnerships participated on a proportionate basis with us in most drilling operations and most producing property acquisitions commenced by us for our own account during the period from the formation of the Partnership through December 31 of that year. These partnership agreements require, on the election of a limited partner, that we repurchase the limited partner’s interest at amounts to be determined by appraisal in the future. Repurchases in any one year are limited to 20% of the units outstanding. We had no repurchases in the first nine months of 2016. We made repurchases of approximately $2,900 during the first nine months of 2017.


~~(6)~~	~~We have recorded a liability for future estimated payments related to workers’ compensation claims primarily associated with our contract drilling segment.~~


~~(7)~~	~~The amount includes commitments under capital lease arrangements for compressors in our mid-stream segment.~~

Derivative Activities

Periodically we enter into derivative transactions locking in the prices to be received for a portion of our oil, NGLs, and natural gas production.

Table of Contents

Commodity Derivatives. Our commodity derivatives are intended to 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. At ~~September~~June 30, ~~2017,~~2021, based on our ~~third~~second quarter ~~2017~~2021 average daily production, the approximated percentages of our production under derivative contracts are as follows:


	2021		2022		2023
Daily oil production	76	%	54	%	31	%
Daily natural gas production	59	%	48	%	27	%

Q3 Q4 Q1 Q2 Q3 Q4
2017 2018
Daily oil production 54 % 54 % 58 % 58 % 58 % 58 %
Daily natural gas production 74 % 64 % 56 % 28 % 28 % 28 %

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

The use of derivative transactions carries with it the risk that the counterparties may not be able to meet their financial obligations under the transactions. Based on our ~~September~~June 30, ~~2017~~2021 evaluation, we believe the risk of non-performance by our counterparties is not material. At ~~September~~June 30, ~~2017,~~2021, the fair values of the net ~~assets (liabilities)~~liabilities we had with each of the counterparties to our commodity derivative transactions are as follows:


	June 30, 2021
	(In thousands)
Bank of Oklahoma	$	(60,369)
Bank of Montreal	(861)
Total net liabilities	$	(61,230)

September 30, 2017
(In millions)
Bank of Montreal $ 0.9
Scotiabank (0.1 )
Canadian Imperial Bank of Commerce (0.3 )
Bank of America (0.4 )
Total assets $ 0.1

~~If a legal right~~Below is the effect of ~~set-off exists, we net the value of the~~ derivative transactions we have with the same counterparty in our Unaudited Condensed Consolidated Balance Sheets. At September 30, 2017, we recorded the fair value of our commodity derivatives on our balance sheet as current derivative assets of $1.0 million, and current and non-current derivative liabilities of $0.6 million and $0.3 million, respectively. At December 31, 2016, we recorded the fair value of our commodity derivatives on our balance sheet as non-current derivative assets of $0.4 million, and current and non-current derivative liabilities of $21.6 million and $0.4 million, respectively.

For our economic hedges any changes in their fair value occurring before their maturity (i.e., temporary fluctuations in value) are reported in gain (loss) on derivatives in our Unaudited Condensed Consolidated Statements of Operations. These gains (losses) at September 30 are as follows:

Three Months Ended Nine Months Ended
September 30, September 30,
2017 2016 2017 2016
(In thousands)
Gain (loss) on derivatives:
Gain (loss) on derivatives, included are amounts settled during the period of $840, ($457), ($729) and $11,735, respectively $ (2,614 ) $ 6,969
$ 21,019
$ (4,774 )
$ (2,614 ) $ 6,969
$ 21,019
$ (4,774 )

~~Stock and Incentive Compensation~~

~~During the first~~ ~~nine~~ ~~months of~~ ~~2017~~, we granted awards covering 698,276 shares of restricted stock. These awards had an estimated fair value as of their grant date of $17.2 million. Compensation expense will be recognized over the three year vesting periods, and during the nine months of 2017, we recognized $5.0 million in compensation expense and capitalized $0.8 million for these awards. During the first nine months of 2017, we recognized compensation expense of $9.0 million for all of

~~our restricted stock, stock options, and SAR grants and capitalized $1.3 million of compensation cost for oil and natural gas properties.~~

~~During the first~~ ~~nine~~ months of 2016, we granted awards covering 728,951 shares of restricted stock. These awards had an estimated fair value as of their grant date of $4.3 million. Compensation expense will be recognized over the three year vesting periods, and during the ~~nine~~ months of 2016, we recognized $1.1 million in compensation expense and capitalized $0.2 million for these awards. During the first nine months of 2016, we recognized compensation expense of $7.2 million for all of our restricted stock, stock options, and SAR grants and capitalized $1.6 million of compensation cost for oil and natural gas properties.

~~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 in order 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 are the general partner of 13 oil and natural gas partnerships which were formed privately or publicly. Each partnership’s revenues and costs are shared under formulas set out in that partnership’s agreement. The partnerships repay us for contract drilling, well supervision, and general and administrative expense. Related party transactions for contract drilling and well supervision fees are the related party’s share of such costs. These costs are billedinstruments on the same basis as billings to unrelated third parties for similar services. General and administrative reimbursements consist of direct general and administrative expense incurred on the related party’s behalf as well as indirect expenses assigned to the related parties. Allocations are based on the related party’s level of activity and are considered by us to be reasonable. For the first nine months of 2017 and 2016, the total we received for all of these fees was $0.1 million and $0.2 million, respectively. Our proportionate share of assets, liabilities, and net income (loss) relating to the oil and natural gas partnerships is included in our unaudited condensed consolidated ~~financial statements.~~

~~New Accounting Pronouncements~~

~~Compensation—Stock Compensation.~~ ~~The FASB issued ASU 2017-09, to clarify and reduce both (i) diversity in practice and (ii) cost and complexity when applying its guidance to changes in the terms and conditions~~statements of a share-based payment award. The amendments are effective for reporting periods beginning after December 15, 2017. We do not believe these amendments will have a material impact on our financial statements.

~~Intangibles—Goodwill and Other: Simplifying the Test for Goodwill Impairment.~~ The FASB issued ASU 2017-04, to simplify the subsequent measurement of goodwill. The amendments eliminate Step 2 from the goodwill impairment test. The amendments will be effective prospectively for reporting periods beginning after December 31, 2019, and early adoption is permitted. We do not believe these amendments will have a material impact on our financial statements.

~~Business Combinations; Clarifying the Definition of a Business.~~ The FASB issued ASU 2017-01, clarifying the definition of a business. The amendments are intended to help companies and other organizations evaluate whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. For public companies, the amendments are effective for annual periods beginning after December 15, 2017. We do not believe these amendments will have a material impact on our financial statements.

~~Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments.~~ The FASB issued ASU 2016-15, to address diversity in how certain transactions are presented and classified in the statement of cash flows. The amendments will be effective retrospectively for reporting periods beginning after December 31, 2017, and early adoption is permitted. We do not believe these amendments will have a material impact on our financial statements.

~~Leases.~~ The FASB has issued ASU 2016-02. The amendments will require lessees to recognize at the commencement date a lease liability, which is a lessee's obligation to make lease payments arising from a lease, measured on a discounted basis; and a right-of-use asset, which is an asset that represents the lessee's right to use a specified assetoperations for the ~~lease term. Lessor~~periods indicated:


	Successor		Predecessor		Successor		Predecessor
	Three Months Ended June 30, 2021		Three Months Ended June 30, 2020		Six Months Ended June 30, 2021		Six Months Ended June 30, 2020
	(In thousands)
Loss on derivatives:
Loss on derivatives, included are amounts settled during the period of ($6,403), ($1,243), ($9,707), and ($691), respectively	$	(42,400)	$	(6,937)	$	(65,231)	$	(6,454)
	$	(42,400)	$	(6,937)	$	(65,231)	$	(6,454)

accounting is largely unchanged. For public companies, the amendments are effective for annual periods beginning after December 15, 2018, and interim periods within those annual periods. The standard will not apply to leases

Table of ~~mineral rights. We are in the process of evaluating the impact these amendments will have on our financial statements.~~Contents

~~Revenue from Contracts with Customers.~~ The FASB has issued ASU 2014-09. These amendments affect any entity using U.S. GAAP that either enters into contracts with customers to transfer goods or services or enters into contracts for the transfer of nonfinancial assets unless those contracts are within the scope of other standards (e.g., insurance contracts or lease contracts). The core principle of the amendments is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 has been amended several times pre-issuance, which will be codified in the new Topic 606, and it is effective January 1. 2018. The guidance in this update supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and most industry-specific guidance throughout the Industry Topics of the Codification. We will adopt these amendments January 1, 2018.

The new revenue standard provides a five-step analysis of transactions to determine the amount and timing of revenue recognition. Entities can choose to apply Topic 606 using either the full retrospective approach or a modified retrospective approach. We plan to adopt using the modified retrospective approach, which will result in a cumulative effect adjustment upon adoption.

Currently, management believes the effect of adoption will not have a material effect on our statement of operations or our balance sheet, as the timing of revenue recognized will not be materially modified, but the adoption will result in more robust footnote disclosures in regards to revenue. We anticipate a cumulative effect of applying the new revenue standard as an adjustment to the opening balance of retained earnings at the beginning of 2018 in relation to certain mid-stream segment and contract drilling segment contracts that include adjustments to the timing of revenue recognition of certain demand fee and mobilization/demobilization expenses and revenue, respectively. We believe this adjustment will not be material due to the short-term nature of the majority of our current contract drilling segment contracts and the limited number of mid-stream segment contracts with demand fees that we anticipate to be in place at the adoption date. Part of our review included evaluation of the following issues:

Based on an analysis of whether the transportation of gas is a performance obligation that occurs at a point in time or over time, the timing of when we recognize certain revenue elements will change. Specifically related to our mid-stream segment, certain fees that are collectible in the early stages of a contract will be recognized over the life of the contract because these fees are part of the single performance obligation associated with the contract.

Certain of our contracts include promises to deliver a minimum volume of commodity to the customer over a defined period of time. If we do not meet this commitment, a deficiency fee is payable to the customer. Topic 606 requires that these types of arrangements represent variable consideration related to the sale of the commodity, and requires that we include an estimate of any deficiency fees expected within revenue, rather than as operating costs. In addition, we will also be required to analyze fees that are billable for deficiencies in minimum volume commitments from customers for our mid-stream segment. In these instances, we will assess the likelihood of earning these fees each reporting period based on the customer’s performance and recognize variable revenue at the time it is not expected to be subject to a significant reversal.

~~Adopted Standards~~

~~Income Taxes: Balance Sheet Classification of Deferred Taxes.~~ The FASB has issued ASU 2015-17. This changes how deferred taxes are classified on organizations' balance sheets. Organizations are required to classify all deferred tax assets and liabilities as noncurrent. The amendments apply to all organizations that present a classified balance sheet. For public companies, the amendments were effective for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. The amendments require current deferred tax assets to be combined with noncurrent deferred tax assets. We have adopted this ASU during the first quarter of 2017 on a prospective basis. Previously, we had a net current deferred tax asset which is now netted with our noncurrent deferred tax liability. Prior periods were not retrospectively adjusted.

~~Compensation—Stock Compensation: Improvements to Employee Share-Based Payment Accounting.~~ The FASB has issued ASU 2016-09. The amendments are intended to improve the accounting for employee share-based payments and affect all organizations that issue share-based payment awards to their employees. Several aspects of the accounting for share-based payment award transactions are simplified, including: (a) income tax consequences; (b) classification of awards as either equity or liabilities; and (c) classification on the statement of cash flows. For public companies, the amendments were effective for

annual periods beginning after December 15, 2016, and interim periods within those annual periods. The amendments primarily impact classification within the statement of cash flows between financial and operating activities. This did not have a material impact on our financial statements.

Results of Operations

Quarter Ended ~~September~~June 30, ~~2017~~2021 versus Quarter Ended ~~September~~June 30, ~~2016~~2020

Provided below is a comparison of selected operating and financial data:


	Successor			Predecessor			Percent Change (1)
	Quarter Ended June 30, 2021			Quarter Ended June 30, 2020
	(In thousands unless otherwise specified)
Total revenue, before inter-segment eliminations	$	144,160		$	93,878		54	%
Total revenue, after inter-segment eliminations	$	134,057		$	89,007		51	%
Net loss	$	(10,115)		$	(215,565)		95	%
Net income attributable to non-controlling interest	$	2,879		$	84		NM
Net loss attributable to Unit Corporation	$	(12,994)		$	(215,649)		94	%

Oil and Natural Gas:
Revenue, before inter-segment eliminations	$	59,776		$	26,957		122	%
Operating costs, before inter-segment eliminations	$	16,350		$	72,354		(77)	%
Average oil price (Bbl)	$	48.38		$	18.14		167	%
Average oil price per barrel received excluding derivatives	$	64.38		$	20.98		NM
Average NGLs price (Bbl)	$	17.95		$	4.11		NM
Average NGLs price per barrel received excluding derivatives	$	17.95		$	4.11		NM
Average natural gas price (Mcf)	$	2.98		$	1.08		176	%
Average natural gas price per Mcf received excluding derivatives	$	3.00		$	1.05		186	%
Oil production (MBbls)	389			546			(29)	%
NGL production (MBbls)	662			862			(23)	%
Natural gas production (MMcf)	7,543			9,576			(21)	%


Contract Drilling:
Revenue, before inter-segment eliminations	$	18,061		$	29,202		(38)	%
Operating costs, before inter-segment eliminations	$	14,080		20,951			(33)	%



Average number of drilling rigs in use	10.0			9.1			10	%
Total drilling rigs available for use at the end of the period	21.0			58.0			(64)	%
Average dayrate on daywork contracts	$	18,269		$	18,340		—	%

Mid-Stream:
Revenue, before inter-segment eliminations	$	66,323		$	37,719		76	%
Operating costs, before inter-segment eliminations	$	55,176		$	26,669		107	%


Gas gathered--Mcf/day	293,220			404,831			(28)	%
Gas processed--Mcf/day	127,399			155,555			(18)	%
Gas liquids sold--gallons/day	441,369			637,420			(31)	%
Number of natural gas gathering systems	17			18			(6)	%
Number of processing plants	11			11			—	%

Corporate and Other:

General and administrative expense, before inter-segment eliminations	$	4,871		$	25,814		(81)	%


Other income (expense):

Interest expense, net	$	(487)		$	(7,666)		(94)	%
Write-off of debt issuance costs	$	—		$	(2,426)		(100)	%
Reorganization items, net	$	(1,852)		$	(7,027)		(74)	%
Loss on derivatives	$	(42,400)		$	(6,937)		NM
Loss on change in fair value of warrants	$	(3,574)		$	—		—	%

Income tax benefit	$	—		$	(6,455)		100	%
Average interest rate	6.5		%	6.1		%	7	%
Average long-term debt outstanding	$	62,646		$	410,593		(85)	%

_________________________

1.NM – A percentage calculation is not meaningful due to a zero-value denominator or a percentage change greater than 200.

Quarter Ended September 30,
Percent
Change ⁽¹⁾
2017 2016
(In thousands unless otherwise specified)
Total revenue $ 188,488
$ 153,408
23 %
Net income (loss) $ 3,705
$ (24,022 ) 115 %

Oil and Natural Gas:
Revenue $ 85,470
$ 78,854
8 %
Operating costs excluding depreciation, depletion, amortization, and impairment $ 33,911
$ 26,014
30 %
Depreciation, depletion, and amortization $ 26,460
$ 27,135
(2 )%
Impairment of oil and natural gas properties $ —
$ 49,443
(100 )%

Average oil price received (Bbl) $ 47.29
$ 42.79
11 %
Average NGLs price received (Bbl) $ 18.35
$ 12.68
45 %
Average natural gas price received (Mcf) $ 2.36
$ 2.29
3 %
Oil production (Bbl) 633,000
701,000
(10 )%
NGLs production (Bbl) 1,243,000
1,260,000
(1 )%
Natural gas production (Mcf) 13,085,000
13,399,000
(2 )%
Depreciation, depletion, and amortization rate (Boe) $ 6.18
$ 6.06
2 %

Contract Drilling:
Revenue $ 51,619
$ 25,819
100 %
Operating costs excluding depreciation $ 34,747
$ 19,137
82 %
Depreciation $ 15,280
$ 11,318
35 %

Percentage of revenue from daywork contracts 100 % 100 % — %
Average number of drilling rigs in use 34.6
16.0
116 %
Average dayrate on daywork contracts $ 16,454
$ 17,479
(6 )%

Mid-Stream:
Revenue $ 51,399
$ 48,735
5 %
Operating costs excluding depreciation and amortization $ 38,116
$ 35,738
7 %
Depreciation and amortization $ 10,880
$ 11,436
(5 )%

Gas gathered—Mcf/day 383,787
429,693
(11 )%
Gas processed—Mcf/day 140,246
152,651
(8 )%
Gas liquids sold—gallons/day 530,028
558,843
(5 )%

Corporate and other:
General and administrative expense $ 9,235
$ 8,852
4 %
Other depreciation $ 1,913
$ 80
NM
Gain on disposition of assets $ 81
$ 154
(47 )%
Other income (expense):
Interest expense, net $ (9,944 ) $ (10,002 ) (1 )%
Gain (loss) on derivatives $ (2,614 ) $ 6,969
(138 )%
Other $ 5
$ 3
67 %
Income tax expense (benefit) $ 1,769
$ (14,599 ) 112 %
Average long-term debt outstanding $ 804,617
$ 866,249
(7 )%
Average interest rate 6.0 % 5.7 % 5 %

~~_________________________~~


~~(1)~~	~~NM – A percentage calculation is not meaningful due to a zero-value denominator or a percentage change greater than 200.~~

Table of Contents

Oil and Natural Gas

Oil and natural gas revenues increased ~~$6.6~~$32.8 million or 8%122% in the ~~third~~second quarter of ~~2017~~2021 as compared to the ~~third~~second quarter of ~~2016~~2020 primarily due to higher commodity prices, partially offset ~~from reduced~~by lower production volumes. In the ~~third~~second quarter of ~~2017,~~2021, as compared to the ~~third~~second quarter of ~~2016,~~2020, oil production decreased ~~10%~~29%, natural gas production decreased 2%21%, and NGLs production decreased 1%23%. ~~Average~~Including derivatives settled, average oil prices increased ~~11%~~167% to ~~$47.29~~$48.38 per barrel, average natural gas prices increased 3%176% to ~~$2.36~~$2.98 per Mcf, and NGLs prices increased ~~45%~~over 200% to ~~$18.35~~$17.95 per barrel.

Oil and natural gas operating costs ~~increased $7.9~~decreased $56.0 million or ~~30%~~77% between the comparative ~~third~~second quarters of ~~2017~~2021 and ~~2016~~2020 primarily due to ~~higher LOE and production taxes partially offset by lower saltwater disposal expenses.~~the settlement of Predecessor Period liabilities subject to compromise under the Plan.

Depreciation, depletion, and amortization (“DD&A”) decreased $0.7 million or 2% due primarily to a 3% decrease in equivalent production partially offset by a 2% increase in the DD&A rate. The increase in our DD&A rate in the third quarter of 2017 compared to the third quarter of 2016 resulted primarily from the cost of wells drilled in the first nine months of 2017.

~~During the third quarter of 2016, we recorded a non-cash ceiling test write-down of $49.4 million pre-tax ($30.8 million, net of tax). We did not have a write-down for the third quarter of 2017.~~

Contract Drilling

Drilling revenues ~~increased $25.8~~decreased $11.1 million or ~~100%~~38% in the ~~third~~second quarter of ~~2017~~2021 versus the ~~third~~second quarter of ~~2016.~~2020. The ~~increase~~decrease was ~~due~~driven primarily ~~to a 116% increase in~~by the ~~average number~~absence of ~~drilling rigs in use partially offset by a 6% decrease in~~early termination fees. During the ~~average dayrate. Average drilling rig utilization increased from 16.0 drilling rigs in the third~~second quarter of ~~2016~~2021, we recorded no early termination fees compared to ~~34.6 drilling rigs~~$9.2 million of early termination fees recorded in ~~the third~~second quarter of ~~2017.~~2020.

Drilling operating costs ~~increased $15.6~~decreased $6.9 million or ~~82%~~33% between the comparative ~~third~~second quarters of ~~2017~~2021 and ~~2016.~~2020. The ~~increase~~change was primarily due ~~primarily~~ to ~~more drilling rigs operating. Contract drilling depreciation increased $4.0 million or 35% also due primarily to more drilling rigs operating.~~a decrease in incurred separation benefit expenses recognized in the Predecessor Period.

Mid-Stream

Our mid-stream revenues increased ~~$2.7~~$28.6 million or 5%76% in the ~~third~~second quarter of ~~2017~~2021 as compared to the ~~third~~second quarter of ~~2016~~2020 primarily due ~~primarily~~ to ~~increases in~~higher gas, NGLs, and condensate ~~prices.~~prices, partially offset by lower volumes. Gas processed volumes per day decreased 8%18% between the comparative quarters primarily due to ~~declines in existing volumes,~~connecting fewer new wells ~~connected to~~and declining volumes on most of our major processing ~~systems, and no offload volume at our Hemphill facility in 2017.~~systems. Gas gathered volumes per day decreased ~~11%~~28% between the comparative quarters ~~primarily~~ due to declining ~~gathered~~ volumes ~~on our Appalachian systems.~~and fewer new well connections.

Operating costs increased ~~$2.4~~$28.5 million or 7%107% in the ~~third~~second quarter of ~~2017~~2021 compared to the ~~third~~second quarter of ~~2016~~2020 primarily due to ~~26%~~ higher gas, ~~purchase~~NGLs, and condensate prices, partially offset by ~~a 9% decrease in~~lower purchase volumes. ~~Depreciation and amortization decreased $0.6 million, or 5%, primarily due to certain assets being fully depreciated in 2017.~~

~~Other Depreciation~~

~~During the third quarter of 2017, we had $1.9 million of other depreciation primarily due to our new ERP accounting and reporting system that was implemented during the first quarter of 2017.~~

General and Administrative

Corporate general and administrative expenses ~~increased $0.4~~decreased $20.9 million or 4%81% in the ~~third~~second quarter of ~~2017~~2021 as compared to the ~~third~~second quarter of ~~2016~~2020 primarily due to reduced consulting and outside legal fees. We incurred $16.5 million in advisory and restructuring fees in the second quarter of 2020.

Other Income (Expense)

Interest expense decreased $7.2 million between the comparative second quarters of 2021 and 2020 primarily due to an ~~increase in employee costs.~~

~~Other Income (Expense)~~

~~Interest expense, net of capitalized interest, decreased $0.1 million between the comparative third quarters of 2017 and 2016 due primarily to a 7%~~85% decrease in average long-term debt outstanding, ~~in the third quarter of 2017 and an increase in interest capitalized~~ partially offset by a higher average interest rate. We capitalized interest based on the net book value associated with undeveloped leasehold not being amortized, the construction of additional drilling rigs, and the construction of gas gathering systems. Capitalized interest for the third quarter of 2017 was $4.0 million compared to $3.6 million in the third quarter of 2016, and was netted against our gross interest of $14.0 million and $13.6 million for the third quarters of 2017 and

~~2016, respectively.~~ Our average interest rate increased from ~~5.7%~~6.1% in the ~~third~~second quarter of ~~2016~~2020 to ~~6.0%~~6.5% in the ~~third~~second quarter of ~~2017~~2021 and our average debt outstanding ~~was $61.6~~decreased $347.9 million ~~lower~~ in the ~~third~~second quarter of ~~2017 as~~2021 compared to the ~~third~~second quarter of ~~2016~~2020 primarily due to the ~~decrease in outstanding borrowings~~settlement of the Notes under ~~our~~the Plan and payments made under the Exit credit agreement.

Write-off of Debt Issuance Costs

Due to the termination of the remaining commitments of the Predecessor Period Unit credit agreement, ~~over~~unamortized debt issuance costs of $2.4 million were written off during the ~~comparative periods.~~second quarter of 2020.

~~Gain (Loss)~~Reorganization Items, Net

Reorganization items, net represent any of the expenses, gains, and losses incurred subsequent to and as a direct result of the Chapter 11 proceedings.

Loss on Derivatives

~~Gain (loss)~~Loss on derivatives increased ~~$9.6~~by $35.5 million primarily due to fluctuations in forward prices used to estimate the fair value in mark-to-market accounting.

Table of Contents

Loss on Change in Fair Value of Warrants

Loss on change in fair value of warrants increased by $3.6 million primarily due to changes in the underlying assumptions used to estimate the fair value, including estimated strike price, entity value, duration to exercise and other inputs.

Income Tax ~~Expense (Benefit)~~Benefit

~~Income~~We did not record an income tax ~~expense increased $16.4~~benefit in the second quarter of 2021 compared to $6.5 million ~~between~~in the ~~comparative third quarters~~second quarter of ~~2017 and 2016 primarily~~2020 due to ~~increased pre-tax income.~~the company's full valuation allowance against our net deferred tax asset. Our effective tax rate was ~~32.3%~~0% for the ~~third~~second quarter of ~~2017~~2021 compared to ~~37.8%~~2.91% for the ~~third~~second quarter of ~~2016. The rate change was primarily~~2020 due to the ~~recognition of~~adjustment to our ~~Uncertain Tax Position associated with a research and development tax credit of $0.4 million. There was no current~~total valuation allowance for the income tax ~~expense or~~ benefit inthat was generated during the ~~third quarter of 2017 or 2016.~~period. We ~~did not pay any~~paid no income taxes in the ~~third~~second quarter of ~~2017.~~2021.

~~Nine~~

Table of Contents

Results of Operations

Six Months Ended ~~September~~June 30, ~~2017~~2021 versus ~~Nine~~Six Months Ended ~~September~~June 30, ~~2016~~2020

Provided below is a comparison of selected operating and financial data:


	Successor			Predecessor			Percent Change (1)
	Six Months Ended June 30, 2021			Six Months Ended June 30, 2020
	(In thousands unless otherwise specified)
Total revenue, before inter-segment eliminations	$	274,468		$	221,714		24��	%
Total revenue, after inter-segment eliminations	$	254,954		$	211,383		21	%
Net loss	$	(10,706)		$	(1,019,239)		99	%
Net income (loss) attributable to non-controlling interest	$	4,225		$	(33,096)		113	%
Net loss attributable to Unit Corporation	$	(14,931)		$	(986,143)		99	%

Oil and Natural Gas:
Revenue, before inter-segment eliminations	$	114,801		$	75,481		52	%
Operating costs, before inter-segment eliminations	$	36,343		$	103,769		(65)	%


Average oil price (Bbl)	$	47.82		$	32.93		45	%
Average oil price per barrel received excluding derivatives	$	60.12		$	34.20		76	%
Average NGLs price (Bbl)	$	17.95		$	3.67		NM
Average NGLs price per barrel received excluding derivatives	$	17.95		$	3.67		NM
Average natural gas price (Mcf)	$	2.87		$	1.16		147	%
Average natural gas price per Mcf received excluding derivatives	$	2.86		$	1.12		155	%
Oil production (MBbls)	801			1,220			(34)	%
NGLs production (MBbls)	1,303			1,827			(29)	%
Natural gas production (MMcf)	14,946			20,378			(27)	%


Contract Drilling:
Revenue, before inter-segment eliminations	$	33,735		$	65,834		(49)	%
Operating costs, before inter-segment eliminations	$	25,951		$	46,400		(44)	%




Average number of drilling rigs in use	9.7			13.9			(30)	%
Total drilling rigs available for use at the end of the period	21			58			(64)	%
Average dayrate on daywork contracts	$	18,200		$	19,165		(5)	%

Mid-Stream:
Revenue, before inter-segment eliminations	$	125,932		$	80,399		57	%
Operating costs, before inter-segment eliminations	$	104,286		$	58,988		77	%


Gas gathered--Mcf/day	296,396			397,037			(25)	%
Gas processed--Mcf/day	124,285			160,943			(23)	%
Gas liquids sold--gallons/day	425,277			582,546			(27)	%
Number of natural gas gathering systems	17			18			(6)	%
Number of processing plants	11			11			—	%

Corporate and Other:

General and administrative expense, before inter-segment eliminations	$	11,160		$	37,367		(70)	%


Other income (expense):

Interest expense, net	$	(2,777)		$	(20,923)		(87)	%
Write-off of debt issuance costs	$	—		$	(2,426)		(100)	%
Reorganization items, net	$	(2,988)		$	(7,027)		58	%
Loss on derivatives	$	(65,231)		$	(6,454)		NM

Loss on change in fair value of warrants	$	(3,574)		$	—		—	%
Income tax benefit	$	—		$	(9,880)		100	%
Average interest rate	6.7		%	6.2		%	7	%
Average long-term debt outstanding	$	77,852		$	586,048		(87)	%

_________________________

1.NM – A percentage calculation is not meaningful due to a zero-value denominator or a percentage change greater than 200.

Nine Months Ended September 30,
Percent
Change
2017 2016
(In thousands unless otherwise specified)
Total revenue $ 534,793
$ 427,897
25 %
Net income (loss) $ 28,693
$ (137,307 ) 121 %

Oil and Natural Gas:
Revenue $ 256,241
$ 206,318
24 %
Operating costs excluding depreciation, depletion, amortization, and impairment $ 95,873
$ 92,691
3 %
Depreciation, depletion, and amortization $ 71,544
$ 89,378
(20 )%
Impairment of oil and natural gas properties $ —
$ 161,563
(100 )%

Average oil price received (Bbl) $ 47.62
$ 38.71
23 %
Average NGLs price received (Bbl) $ 17.05
$ 10.16
68 %
Average natural gas price received (Mcf) $ 2.50
$ 1.98
26 %
Oil production (Bbl) 1,990,000
2,260,000
(12 )%
NGLs production (Bbl) 3,476,000
3,745,000
(7 )%
Natural gas production (Mcf) 37,317,000
42,376,000
(12 )%
Depreciation, depletion, and amortization rate (Boe) $ 5.76
$ 6.48
(11 )%

Contract Drilling:
Revenue $ 128,059
$ 88,786
44 %
Operating costs excluding depreciation $ 91,213
$ 66,489
37 %
Depreciation $ 41,896
$ 34,431
22 %

Percentage of revenue from daywork contracts 100 % 100 % — %
Average number of drilling rigs in use 29.7
16.7
78 %
Average dayrate on daywork contracts $ 16,120
$ 18,147
(11 )%

Mid-Stream:
Revenue $ 150,493
$ 132,793
13 %
Operating costs excluding depreciation and amortization $ 111,862
$ 99,185
13 %
Depreciation and amortization $ 32,547
$ 34,410
(5 )%

Gas gathered—Mcf/day 385,846
417,722
(8 )%
Gas processed—Mcf/day 133,986
160,411
(16 )%
Gas liquids sold—gallons/day 518,054
536,911
(4 )%

Corporate and other:
General and administrative expense $ 26,902
$ 25,811
4 %
Other depreciation $ 5,558
$ 218
NM
Gain on disposition of assets $ 1,153
$ 823
40 %
Other income (expense):
Interest expense, net $ (28,807 ) $ (30,225 ) (5 )%
Gain (loss) on derivatives $ 21,019
$ (4,774 ) NM
Other $ 14
$ (11 ) NM
Income tax expense (benefit) $ 22,084
$ (73,159 ) 130 %
Average long-term debt outstanding $ 811,159
$ 882,330
(8 )%
Average interest rate 6.0 % 5.6 % 7 %

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Oil and Natural Gas

Oil and natural gas revenues increased ~~$49.9~~$39.3 million or ~~24%~~52% in the first ~~nine~~six months ~~2017~~of 2021 as compared to the first ~~nine~~six months of ~~2016~~2020 primarily due to higher commodity prices partially offset by lower production volumes. ~~In the first nine months of 2017, as compared~~The decline in volumes was due to ~~the first nine months of 2016, oil~~normal well production decreased 12%, natural gas production decreased 12%, and NGLs production decreased 7%. Average oil prices increased 23% to $47.62 per barrel, average natural gas prices increased 26% to $2.50 per Mcf, and NGLs prices increased 68% to $17.05 per barrel.declines which have not been offset by new drilling or acquisitions.

Oil and natural gas operating costs ~~increased $3.2~~decreased $67.4 million or 3%65% between the comparative first ~~nine~~six months of ~~2017~~2021 and ~~2016~~2020 primarily due to ~~higher LOE and gross production tax partially offset by lower saltwater disposal expense.~~the settlement of Predecessor Period liabilities subject to compromise under the Plan.

~~DD&A~~Contract Drilling

Drilling revenues decreased ~~$17.8~~$32.1 million or ~~20% due primarily to a 11% decrease in our DD&A rate and a 11% decrease in equivalent production. The decrease in our DD&A rate~~49% in the first ~~nine~~six months of ~~2017 compared to the first nine months of 2016 resulted primarily from the effect of the ceiling test write-downs throughout 2016.~~

~~During the first nine months of 2016, we recorded non-cash ceiling test write-downs of $161.6 million pre-tax ($100.6 million, net of tax). We did not have a write-down for 2017.~~

~~Contract Drilling~~

~~Drilling revenues increased $39.3 million or 44% in the first nine months of 2017~~2021 versus the first ~~nine~~six months of ~~2016.~~2020. The ~~increase~~decrease was due primarily to a ~~78% increase~~30% decrease in the average number of drilling rigs in use ~~partially offset by~~and a ~~11%~~5% decrease in the average dayrate. Average drilling rig utilization ~~increased~~decreased from ~~16.7~~13.9 drilling rigs in the first ~~nine~~six months of ~~2016~~2020 to ~~29.7~~9.7 drilling rigs in the first ~~nine~~six months of ~~2017. We recorded $0.8 million in early termination revenue in the first nine months of 2017 compared to $3.1 million in the first nine months of 2016.~~2021.

Drilling operating costs ~~increased $24.7~~decreased $20.4 million or ~~37%~~44% between the comparative first ~~nine~~six months of ~~2017~~2021 and ~~2016.~~2020. The ~~increase~~decrease was due primarily to ~~more drilling rigs operating. Contract drilling depreciation increased $7.5 million or 22% also due primarily to more~~the reduced number of drilling rigs operating.

During the first six months of 2021, management reduced the number of drilling rigs available for use to 21 compared to 58 at December 31, 2020. The decrease corresponds with the company's strategy to focus on the utilization of our 14 BOSS rigs and certain SCR rigs that are either currently under contract or candidates for future upgrades. Of the 21 rigs available for use, 11 are currently working, 6 are actively being marketed, and the remaining 4 will be considered for upgrade and marketing as future conditions warrant. The company will continue its efforts to sell or scrap those other rigs that are not considered part of our available fleet.

Mid-Stream

Our mid-stream revenues increased ~~$17.7~~$45.5 million or ~~13%~~57% in the first ~~nine~~six months of ~~2017~~2021 as compared to the first ~~nine~~six months of ~~2016~~2020 primarily due to higher prices, partially offset by lower volumes. Gas processed volumes per day decreased 23% between the comparative periods primarily due to declining volumes and fewer new wells connected to our processing systems. Gas gathered volumes per day decreased 25% between the comparative periods also due to declining volumes and fewer new wells connected to our gathering systems. We also experienced overall lower volumes due to the February 2021 winter storm.

Operating costs increased $45.3 million or 77% in the first six months of 2021 compared to the first six months of 2020 primarily due to higher gas, NGLs, and condensate prices, partially offset by ~~a decrease in gas processed~~lower purchase volumes. Gas processed volumes per day decreased 16% between the comparative periods primarily due to declines in existing volumes, fewer new wells connected, and no offload volume at our Hemphill facility in 2017. Gas gathered volumes per day decreased 8% between the comparative periods primarily due declines in existing volumes, fewer new wells connected, and no offload volume at our Hemphill facility in 2017.

Operating costs increased $12.7 million or 13% in the first nine months of 2017 compared to the first nine months of 2016 primarily due to increased purchase prices partially offset by a decrease in gas purchased volumes. Depreciation and amortization decreased $1.9 million, or 5%, primarily due to certain assets being fully depreciated in 2017.

~~Other Depreciation~~

During the first nine months of 2017, we had $5.6 million of other depreciation primarily due to our new ERP accounting and reporting system that was implemented during the first quarter of 2017 as well as depreciation on our corporate building.

General and Administrative

Corporate general and administrative expenses ~~increased $1.1~~decreased $26.2 million or 4%70% in the first ~~nine~~six months of ~~2017~~2021 as compared to the first ~~nine~~six months of ~~2016~~2020 primarily due to ~~higher employee costs.~~reduction in consulting and legal fees paid prior to filing for bankruptcy.

~~Gain on Disposition of Assets~~

There was an $1.2 million gain on disposition of assets in the first nine months of 2017 primarily due to the sale of a corporate aircraft and vehicles, compared to a gain of $0.8 million for the disposition of assets in the first nine months of 2016 primarily due to the sale of various rig components (including three top drives and power units), vehicles, and a drilling yard.

Other Income (Expense)

Interest expense ~~net of capitalized interest,~~ decreased ~~$1.4~~$18.1 million between the comparative first ~~nine~~six months of ~~2017~~2021 and ~~2016~~2020 primarily due ~~primarily~~ to a ~~8% decrease~~reduction in ~~the~~ average long-term debt outstanding, ~~and increase interest capitalized~~ partially offset by a higher average interest rate. We capitalized interest based on the net book value associated with undeveloped leasehold not being amortized, the construction of additional drilling rigs, and the construction of gas gathering systems. Capitalized interest for the first nine months of 2017 was $11.9 million compared to $11.2 million in the first nine months of 2016, and was netted against our gross interest of $40.7 million and $41.4 million for the first nine months of 2017 and 2016, respectively. Our average interest rate increased from ~~5.6%~~6.2% in the first six months of 2020 to ~~6.0%~~6.7% in the first six months of 2021 and our average debt outstanding ~~was $71.2~~decreased $508.2 million ~~lower~~ in the first ~~nine~~six months of ~~2017 as~~2021 compared to the first ~~nine~~six months of ~~2016~~2020 primarily due to the ~~decrease in outstanding borrowings~~Notes being settled with the Plan and payments made under ~~our~~the Exit credit agreement.

Write-off of Debt Issuance Costs

~~Gain (Loss)~~

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Reorganization Items, Net

Reorganization items, net represent any of the expenses, gains, and losses incurred subsequent to and as a direct result of the Chapter 11 proceedings.

Loss on Derivatives

~~Gain (loss)~~Loss on derivatives increased ~~$25.8~~by $58.8 million primarily due to fluctuations in forward prices used to estimate the fair value in mark-to-market accounting.

Loss on Change in Fair Value of Warrants

Income Tax ~~Expense (Benefit)~~Benefit

~~Income~~We did not record an income tax ~~expense increased $95.2 million between~~benefit in the ~~comparative~~ first ~~nine~~six months of ~~2017 and 2016 primarily~~2021 compared to $9.9 million in the first six months of 2020 due to ~~increased pre-tax income.~~the company's full valuation allowance against our net deferred tax asset. Our effective tax rate was ~~43.5%~~0% for the first ~~nine~~six months of ~~2017~~2021 compared to ~~34.8%~~0.96% for the first ~~nine~~six months of ~~2016. The increase was primarily~~2020 due to ~~increased deferred tax expense related~~the adjustment to our ~~restricted stock vestings in both comparative periods. There was no current~~total valuation allowance for the income tax ~~expense or~~ benefit inthat was generated during the ~~first nine months of 2017 or 2016.~~period. We ~~did not pay any~~paid no income taxes in the first ~~nine~~six months of ~~2017.~~2021.

~~Safe Harbor Statement~~

This report, including information included in, or incorporated by reference from, future filings by us with the SEC, as well as information contained in written material, press releases, and oral statements issued by or on our behalf, contain, or may contain, certain statements that are “forward-looking statements” within the meaning of federal securities laws. All statements, other than statements of historical facts, included or incorporated by reference in this report, which address activities, events, or developments which we expect or anticipate will or may occur, are forward-looking statements. The words “believes,” “intends,” “expects,” “anticipates,” “projects,” “estimates,” “predicts,” and similar expressions are used to identify forward-looking statements.

~~These forward-looking statements include, among others, things as:~~

~~the amount and nature of our future capital expenditures and how we expect to fund our capital expenditures;~~

~~prices for oil, NGLs, and natural gas;~~

~~demand for oil, NGLs, and natural gas;~~

~~our exploration and drilling prospects;~~

~~the estimates of our proved oil, NGLs, and natural gas reserves;~~

~~oil, NGLs, and natural gas reserve potential;~~

~~development and infill drilling potential;~~

~~expansion and other development trends of the oil and natural gas industry;~~

~~our business strategy;~~

~~our plans to maintain or increase production of oil, NGLs, and natural gas;~~

~~the number of gathering systems and processing plants we plan to construct or acquire;~~

~~volumes and prices for natural gas gathered and processed;~~

~~expansion and growth of our business and operations;~~

~~demand for our drilling rigs and drilling rig rates;~~

~~our belief that the final outcome of legal proceedings involving us will not materially affect our financial results;~~

~~our ability to timely secure third-party services used in completing our wells;~~

~~our ability to transport or convey our oil or natural gas production to established pipeline systems;~~

impact of federal and state legislative and regulatory initiatives relating to hydrocarbon fracturing impacting our costs and increasing operating restrictions or delays as well as other adverse impacts on our business;

~~our projected production guidelines for the year;~~

~~our anticipated capital budgets;~~

~~our financial condition and liquidity;~~

~~the number of wells our oil and natural gas segment plans to drill or rework during the year; and~~

~~our estimates of the amounts of any ceiling test write-downs or other potential asset impairments we may have to record in future periods.~~

These statements are based on certain assumptions and analyses made by us based on our experience and our perception of historical trends, current conditions, and expected future developments as well as other factors we believe are appropriate in the circumstances. However, whether actual results and developments will conform to our expectations and predictions is subject to a number of risks and uncertainties which could cause actual results to differ materially from our expectations, including:

~~the risk factors discussed in this report and in the documents we incorporate by reference;~~

~~general economic, market, or business conditions;~~

~~the availability of and nature of (or lack of) business opportunities that we pursue;~~

~~demand for our land drilling services;~~

~~changes in laws or regulations;~~

~~changes in the current geopolitical situation;~~

~~risks relating to financing, including restrictions in our debt agreements and availability and cost of credit;~~

~~risks associated with future weather conditions;~~

~~decreases or increases in commodity prices;~~

~~putative class action lawsuits that may result in substantial expenditures and divert management's attention; and~~

~~other factors, most of which are beyond our control.~~

You should not place undue reliance on these forward-looking statements. Except as required by law, we disclaim any intention to update forward-looking information and to release publicly the results of any future revisions we may make to forward-looking statements to reflect events or circumstances after the date of this report to reflect the occurrence of unanticipated events.

A more thorough discussion of forward-looking statements with the possible impact of some of these risks and uncertainties is provided in our Annual Report on Form 10-K filed with the SEC. We encourage you to get and read that document.

Item 3. Quantitative and Qualitative ~~Disclosure~~Disclosures About Market Risk

Our operations are exposed to market risks primarily because of changes in commodity prices and interest rates.

Commodity Price Risk. Our major market risk exposure is in the prices we receive for our oil, NGLs, and natural gas production. These prices are primarily driven by the prevailing worldwide price for crude oil and market prices applicable to our NGLs and natural gas production. Historically, these prices have fluctuated and we expect this to continue. The prices for oil, NGLs, and natural gas also affect the demand for our drilling rigs and the amount we can charge for the use of our drilling rigs. Based on our first ~~nine~~six months ~~2017~~2021 production, a $0.10 per Mcf change in what we are paid for our natural gas production, without the effect of hedging, would result in a corresponding ~~$398,000~~$250,000 per month ($~~4.8~~3.0 million annualized)

change in our pre-tax operating cash flow. A $1.00 per barrel change in our oil price, without the effect of hedging, would have a ~~$212,000~~$130,000 per month ($~~2.5~~1.6 million annualized) change in our pre-tax operating cash flow and a $1.00 per barrel change in our NGLs prices, without the effect of hedging, would have a ~~$372,000~~$220,000 per month ($~~4.5~~2.6 million annualized) change in our pre-tax operating cash flow.

We use derivative transactions to manage the risk associated with price volatility. Our decisions regarding the amount and prices at which we choose to enter into a contract for certain of our products is based, in part, on our view of current and future market conditions. The transactions we use include financial price swaps under which we will receive a fixed price for our production and pay a variable market price to the contract counterparty. We do not hold or issue derivative instruments for speculative trading purposes.

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At ~~September~~June 30, ~~2017, the following~~2021, these derivatives were outstanding:

Term

Commodity

Contracted Volume

Weighted Average

Fixed Price

Contracted Market

~~Oct'17~~Jul'21 - Dec'21

Natural gas –- basis swap

~~70,000~~30,000 MMBtu/day

$~~3.038~~(0.215)

NGPL TEXOK

Jul'21 - Oct'21

Natural gas - swap

50,000 MMBtu/day

$2.818

IF –- NYMEX (HH)

~~Nov’17 – Dec'17~~Nov'21 - Dec'21

Natural gas –- swap

~~60,000~~45,000 MMBtu/day

$~~2.960~~2.900

IF –- NYMEX (HH)

~~Jan’18 – Dec'18~~Jan'22 - Dec'22

Natural gas –- swap

~~20,000~~5,000 MMBtu/day

$~~3.013~~2.605

IF –- NYMEX (HH)

~~Nov’17 – Dec'17~~Jan'23 - Dec'23

Natural gas ~~– basis~~- swap

~~20,000~~22,000 MMBtu/day

$~~(0.215)~~2.456

IF –- NYMEX (HH)

~~Jan’18 – Mar'18~~Jan'22 - Dec'22

Natural gas ~~– basis swap~~- collar

~~10,000~~35,000 MMBtu/day

~~$(0.208)~~

~~IF – NYMEX (HH)~~

~~Nov’18 – Dec'18~~

~~Natural gas – basis swap~~

~~10,000 MMBtu/day~~

~~$(0.208)~~

~~IF – NYMEX (HH)~~

~~Oct'17~~

~~Natural gas – collar~~

~~20,000 MMBtu/day~~

~~$2.88 - $3.10~~

~~IF – NYMEX (HH)~~

~~Oct'17~~

~~Natural gas – three-way collar~~

~~15,000 MMBtu/day~~

$2.50 - ~~$2.00~~$2.68

IF - ~~$3.32~~

~~IF –~~ NYMEX (HH)

~~Nov’17 – Dec'17~~Jul'21 - Dec'21

~~Natural gas – three-way collar~~Crude oil - swap

~~25,000 MMBtu/~~3,373 Bbl/day

$~~2.90~~45.57

WTI - ~~$2.30 - $3.59~~

~~IF –~~ NYMEX ~~(HH)~~

~~Jan'18 – Mar'18~~Jan'22 - Dec'22

~~Natural gas – three-way collar~~Crude oil - swap

~~60,000 MMBtu/~~2,300 Bbl/day

$~~3.29~~42.25

WTI - ~~$2.63 - $4.07~~

~~IF –~~ NYMEX ~~(HH)~~

~~Apr'18 – Dec'18~~Jan'23 - Dec'23

~~Natural gas – three-way collar~~

~~20,000 MMBtu/day~~

~~$3.00 - $2.50 - $3.51~~

~~IF – NYMEX (HH)~~

~~Oct’17 – Dec'17~~

Crude oil ~~– three-way collar~~- swap

~~3,750~~1,300 Bbl/day

$~~49.79~~43.60

WTI - ~~$39.58 - $60.98~~

~~WTI –~~ NYMEX

~~Jan'18 – Dec'18~~

~~Crude oil – three-way collar~~

~~2,000 Bbl/day~~

~~$47.50 - $37.50 - $56.08~~

~~WTI – NYMEX~~

~~Jan'18 – Dec'18~~

~~Crude oil – swap~~

~~2,000 Bbl/day~~

~~$50.140~~

~~WTI – NYMEX~~

~~After September 30, 2017, the following derivative was entered into:~~



~~Term~~	~~Commodity~~	~~Contracted Volume~~	~~Weighted Average~~ ~~Fixed Price~~	~~Contracted Market~~
~~Apr'18 – Oct'18~~	~~Natural gas – swap~~	~~10,000 MMBtu/day~~	~~$2.990~~	~~IF – NYMEX (HH)~~
~~Apr'18 – Sep'18~~	~~Liquids – swap~~ ⁽¹⁾	~~1,000 Bbl/day~~	~~$31.164~~	~~OPIS – Mont Belvieu~~

~~_______________________~~

~~(1) Type of liquid involved is propane.~~

Interest Rate Risk. Our interest rate exposure relates to our long-term debt under our Exit credit agreement and ~~the Notes. The~~Superior credit agreement. Borrowings under our Exit credit agreement ~~at our election bears interest at variable rates based on the Prime Rate or the LIBOR Rate. At our election, borrowings under our~~and Superior credit agreement ~~may be fixed at the LIBOR Rate for periods of up to 180 days. Based on our average outstanding long-term debt subject to a~~carry variable ~~rate in the first nine months of 2017, a~~interest rates. A 1% increase in the ~~floating rate~~interest rates on the outstanding borrowings under these facilities at June 30, 2021 would reduce our annual pre-tax cash flow by approximately ~~$1.6~~$0.4 million. ~~Under our Notes, we pay a fixed rate of interest of 6.625% per year (payable semi-annually in arrears on May 15~~For further information, see Note 9 – Long-Term Debt and ~~November 15 of each year).~~Other Long-Term Liabilities.

Item 4. Controls and Procedures

Our management, including our Chief Executive Officer (CEO) and Interim Chief Financial Officer (Interim CFO), does not expect that our disclosure controls and procedures (as defined in Rules 13a - 15(e) and 15d - 15(e) of the Securities Exchange Act of 1934, as amended (the Exchange Act)) (Disclosure Controls) or our internal control over financial reporting (ICFR) (as defined in Rules 13a - 15(f) and 15d - 15(f) of the Exchange Act) will prevent or detect all errors and all fraud. A control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of a simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the controls. The design of any system of controls also is based in part on certain assumptions about the likelihood of future events, and there is no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of the inherent limitations in a cost-effective control system, misstatements due to an error or fraud may occur and not be detected. We monitor our Disclosure Controls and ICFR and make modifications as necessary; our intent in this regard is that the Disclosure Controls and ICFR will be modified as systems change, and conditions warrant.

Evaluation of Disclosure Controls and Procedures.As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with the participation of our management, including our ~~Chief Executive Officer~~CEO and ~~Chief Financial Officer,~~Interim CFO, of the effectiveness of the design and operation of our disclosure controls and procedures under Exchange Act Rule 13a-15. Based on that evaluation, our ~~Chief Executive Officer~~CEO and ~~Chief Financial Officer~~Interim CFO concluded that our disclosure controls and procedures ~~are~~were not effective as of ~~September~~June 30, ~~2017~~2021 due to a material weakness in ~~ensuring~~ICFR described below.

Material Weakness in ICFR. A material weakness is a deficiency, or combination of deficiencies, in ICFR resulting in a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis.

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As previously disclosed in our Quarterly Report on Form 10-Q for the period ended June 30, 2020, in preparing our interim financial statements for the quarterly period ended June 30, 2020, we determined that a material weakness related to management review controls over complex accounting matters was present. Key elements of effectively designed management review controls include the establishment of documentation standards for process owners to document the substance of their work related to critical accounting estimates, complex accounting matters, and non-routine transactions. Effectively designed management review controls must also have an established process that allows senior accounting personnel having the appropriate ~~information is recorded, processed, summarized~~knowledge of the subject matter to have enough time to perform effective reviews. Necessary elements for effectively designed management review controls were either not present at June 30, 2020 or not present for a sufficient period of time in order to conclude our disclosure controls and ~~reported in our periodic SEC filings relating~~procedures were effective at June 30, 2020. This continued to be the ~~company (including its consolidated subsidiaries)~~case at June 30, 2021.

Plan for Remediation of the Material Weakness. We continue to address the underlying cause of the material weakness, including a redesign of certain management review controls related to complex accounting matters, the establishment of documentation standards, assessing the structure of the accounting organization, providing additional training for employees responsible for performing important management review controls, and ~~is accumulated~~supplementing internal resources with external expertise when appropriate.

We have also hired new personnel and ~~communicated~~re-assigned certain existing personnel into key positions. And we are conducting process improvement sessions with third party experts to enhance and augment business processes and utilization of system capabilities for greater effectiveness, efficiency, and scalability.

Our management believes the ~~Chief Executive Officer, Chief Financial Officer, and management to allow timely decisions.~~

~~Changes in Internal Controls.~~ ~~In January 2017, we implemented a new ERP accounting and reporting system designed to upgrade our technology~~measures described above will remediate this material weakness and improve the ~~timeliness~~overall effectiveness of internal control over financial reporting. As management continues to evaluate and ~~quality of our financial and operational information. This new ERP system was not implemented in response to any material weakness in our~~improve internal control over financial reporting, ~~(ICFR). The implementation~~we may decide to take additional measures to address this control deficiency or determine to modify, or in appropriate circumstances not to complete, certain of the ~~ERP system~~remediation measures. However, this material weakness will not be considered remediated until the applicable controls operate for a sufficient period of time and management has ~~affected~~tested the ~~processes that constitute part~~effectiveness of ~~our ICFR~~those controls. Management expects these remedial actions and ~~requires ongoing testing for effectiveness. The adoption of this new ERP system has not materially affected our ICFR.~~any other remedial actions related to the material weakness to be effectively implemented in 2021.

Changes in Internal Controls. There were no other changes in our ICFR during the quarter ended ~~September~~June 30, ~~2017,~~2021, that materially affected our ICFR or are reasonably likely to materially affect it, as defined in Rule 13a – 15(f) under the Exchange Act.

Table of Contents

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

~~Panola Independent School District No. 4, et al~~. ~~v. Unit Petroleum Company, No. CJ-07-215, District Court of Latimer County, Oklahoma.~~For further information about the outstanding legal proceedings, please see Note 15 – Commitments And Contingencies.

Panola Independent School District No. 4, Michael Kilpatrick, Gwen Grego, Carla Lessel, Thelma Christine Pate, Juanita Golightly, Melody Culberson, and Charlotte Abernathy are the Plaintiffs in this case and are royalty owners in oil and gas drilling and spacing units for which the company’s exploration segment distributes royalty. The Plaintiffs’ central allegation is that the company’s exploration segment has underpaid royalty obligations by deducting post-production costs or marketing related fees. Plaintiffs sought to pursue the case as a class action on behalf of persons who receive royalty from us for our Oklahoma production. We have asserted several defenses including that the deductions are permitted under Oklahoma law. We have also asserted that the case should not be tried as a class action due to the materially different circumstances that determine what, if any, deductions are taken for each lease. On December 16, 2009, the trial court entered its order certifying the class. On May 11, 2012 the court of civil appeals reversed the trial court’s order certifying the class. The Plaintiffs petitioned the supreme court for certiorari and on October 8, 2012, the Plaintiff’s petition was denied. On January 22, 2013, the Plaintiffs filed a second request to certify a class of royalty owners that was slightly smaller than their first attempt. Since then, the Plaintiffs have further amended their proposed class to just include royalty owners entitled to royalties under certain leases located in Latimer, Le Flore, and Pittsburg Counties, Oklahoma. In July 2014, a second class certification hearing was held where, in addition to the defenses described above, we argued that the amended class definition is still deficient under the court of civil appeals opinion reversing the initial class certification. Closing arguments were held on December 2, 2014. There is no timetable for when the court will issue its ruling. The merits of Plaintiffs’ claims will remain stayed while class certification issues are pending.

~~Cockerell Oil Properties, Ltd., v. Unit Petroleum Company, No. 16-cv-135-JHP, United States District Court for the Eastern District of Oklahoma.~~

~~On March 11, 2016, a putative class action lawsuit was filed against Unit Petroleum Company styled~~ ~~Cockerell Oil Properties, Ltd., v. Unit Petroleum Company~~ in LeFlore County, Oklahoma. We removed the case to federal court in the Eastern District of Oklahoma. The plaintiff alleges that Unit Petroleum wrongfully failed to pay interest with respect to untimely royalty payments under Oklahoma’s Production Revenue Standards Act. The lawsuit seeks actual and punitive damages, an accounting, disgorgement, injunctive relief, and attorney’s fees. Plaintiff is seeking relief on behalf of royalty owners in our Oklahoma wells. We have asserted several defenses including that the case cannot be properly certified as a class action because of the wide variety of circumstances that determine whether a royalty payment was timely made or has accrued interest under Oklahoma law. At this point, the court has not taken any action on the issue of class certification.

We continue to vigorously defend against each of the pending claims. At this time we are unable to express an opinion with respect to the likelihood of an unfavorable outcome or provide an estimate of potential losses, if any.

Item 1A. Risk Factors

In addition to the other information set forth in this quarterly report, you should carefully consider the factors discussed below, if any, and in Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, ~~2016,~~2020, which could materially affect our business, financial condition, or future results. The risks described in our Annual Report on Form 10-K are not the only risks facing our company. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition, and/or operating results.

~~Except as set forth below, there~~There have been no material changes to the risk factors disclosed in Item 1A in our Form 10-K for the year ended December 31, ~~2016.~~2020.

~~We are the subject of putative class action lawsuits that may result in substantial expenditures and divert management's attention.~~

We are the subject of putative class action lawsuits in Oklahoma with respect to the alleged failure to pay interest with on untimely royalty payments and with respect to the alleged underpayment of royalties. These lawsuits seek various remedies, including damages, injunctive relief, and attorney’s fees. For additional information on these lawsuits, see Item 1 Legal Proceedings in this Quarterly Report on Form 10-Q.

Although we believe that the allegations in these lawsuits are without merit and intend to defend such litigation vigorously, litigation is subject to inherent uncertainties, and an adverse result in one of these lawsuits or other matters that may arise from time to time could have a material adverse effect on our business, results of operations and financial condition. Defending the lawsuits may be costly and, further, could require significant involvement of our senior management and may divert management's attention from our business and operations.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

~~The following table provides information relating to our repurchase~~On June 16, 2021, the company repurchased an aggregate of 600,000 shares of its common stock from the Lenders (as defined in Note 9 - Long-Term Debt and Other Long-Term Liabilities) which received these shares as an exit fee during the company’s reorganization. The Lenders were paid $15.00 per share for their respective shares, for an aggregate cash purchase price of $9.0 million. The cash purchase price and direct acquisition costs are reflected as treasury stock on the ~~three months ended September~~condensed consolidated balance sheets as of June 30, ~~2017:~~2021.

In June 2021, the Board authorized repurchasing up to $25.0 million of the company’s outstanding common stock. The repurchases will be made through open market purchases, privately negotiated transactions, or other available means. The company has no obligation to repurchase any shares under the repurchase program and may suspend or discontinue it at any time without prior notice. As of June 30, 2021, no repurchases have been made under the share repurchase program.

Item 3. Defaults Upon Senior Securities

Not applicable.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

Not applicable.

Table of Contents

Item 6. Exhibits

Exhibits:



~~Period~~		3.1	~~(a)~~ ~~Total Number~~Amended and Restated Certificate of ~~Shares Purchased~~Incorporation.			~~(b)~~ ~~Average Price Paid~~ ~~Per Share~~		~~(c)~~ ~~Total Number of Shares Purchased As Part of Publicly Announced Plans or Programs~~	~~(d)~~ ~~Maximum Number (or Approximate Dollar Value) of Shares That May Yet Be Purchased Under the Plans or Programs~~
~~July 1, 2017 to July 31, 2017~~	—			$	—		—	—
~~August 1, 2017 to August 31, 2017~~	—			—			—	—
~~September 1, 2017 to September 30, 2017~~	—			—			—	—
~~Total~~	—			$	—		—	—

~~Item 3. Defaults Upon Senior Securities~~

~~Not applicable.~~

~~Item 4. Mine Safety Disclosures~~

~~Not applicable.~~

~~Item 5. Other Information~~

~~Not applicable.~~

~~Item 6. Exhibits~~

~~Exhibits:~~



~~31.1~~10.1			Second Amendment to Amended and Restated Credit Agreement effective July 26, 2021.

31.1			Certification of Chief Executive Officer under Rule 13a – 14(a) of the Exchange Act.

31.2			Certification of Chief Financial Officer under Rule 13a – 14(a) of the Exchange Act.

32			Certification of Chief Executive Officer and Chief Financial Officer under Rule 13a – 14(a) of the Exchange Act and 18 U.S.C. Section 1350, as adopted under Section 906 of the Sarbanes-Oxley Act of 2002.

101.INS			XBRL Instance Document.

101.SCH			XBRL Taxonomy Extension Schema Document.

101.CAL			XBRL Taxonomy Extension Calculation Linkbase Document.

101.DEF			XBRL Taxonomy Extension Definition Linkbase Document.

101.LAB			XBRL Taxonomy Extension Labels Linkbase Document.

101.PRE			XBRL Taxonomy Extension Presentation Linkbase Document.

104			Cover Page Interactive Data File. The cover page interactive data file does not appear in the interactive data file because its XBRL tags are embedded within the inline XBRL document (contained in Exhibit 101)

Table of Contents

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


				Unit Corporation

Date:				~~Unit Corporation~~

~~Date:~~	~~November 2, 2017~~August 16, 2021	By: /s/ ~~Larry D. Pinkston~~Philip B. Smith
				~~LARRY D. PINKSTON~~PHILIP B. SMITH
				President and Chief Executive Officer ~~and Director~~

Date:			~~November 2, 2017~~August 16, 2021	By: /s/ ~~David T. Merrill~~Thomas D. Sell
				~~DAVID T. MERRILL~~THOMAS D. SELL
				~~Chief Operating Officer,~~ Chief Financial Officer ~~and Treasurer~~



Delaware			73-1283193
(State or other jurisdiction of incorporation)			(I.R.S. Employer Identification No.)


Title of each class	Trading Symbol(s)	Name of each exchange on which registered
N/A	N/A	N/A


					Page Number
			PART I. Financial Information

			Item 1.	~~Page~~ ~~Number~~
	~~PART I. Financial Information~~

~~Item 1.~~	Financial Statements (Unaudited)

	~~Unaudited Condensed Consolidated Balance Sheets~~ ~~September 30, 2017 and December 31, 2016~~	34

			~~Unaudited Condensed Consolidated Statements of Operations~~ ~~Three and Nine Months Ended September 30, 2017 and 2016~~		5

			~~Unaudited Condensed Consolidated Statements of Comprehensive Income (Loss)~~ ~~Three and Nine Months Ended September 30, 2017 and 2016~~		6

			~~Unaudited Condensed Consolidated Statements of Cash Flows~~ ~~Nine Months Ended September 30, 2017 and 2016~~		7





			Notes to Unaudited Condensed Consolidated Financial Statements		911

Item 2.			Management’s Discussion and Analysis of Financial Condition and Results of Operations		3032

Item 3.			Quantitative and Qualitative Disclosure s About Market Risk		5439

Item 4.			Controls and Procedures		5640

			PART II. Other Information

Item 1.			Legal Proceedings		5642

Item 1A.			Risk Factors		5742

Item 2.			Unregistered Sales of Equity Securities and Use of Proceeds		5742

Item 3.			Defaults ~~Upon~~Upo n Senior Securities		5742

Item 4.			Mine Safety Disclosures		5742

Item 5.			Other Information		5842

Item 6.			Exhibits		5942

Signatures					6042


	June 30, 2021		December 31, 2020
	(In thousands except share amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	6,989	$	12,145
Restricted cash	0		569
Accounts receivable, net of allowance for credit losses of $4,265 and $3,783 at June 30, 2021 and December 31, 2020, respectively	63,879		57,846



Current income tax receivable	34		1,150

Prepaid expenses and other	6,212		11,212
Total current assets	77,114		82,922
Property and equipment:
Oil and natural gas properties, on the full cost method:
Proved properties	233,004		238,581
Unproved properties not being amortized	487		1,591
Drilling equipment	64,056		63,687
Gas gathering and processing equipment	255,338		251,404
Land and building	32,635		32,635
Transportation equipment	3,486		3,130
Other	8,935		9,961
	597,941		600,989
Less accumulated depreciation, depletion, amortization, and impairment	88,416		54,189
Net property and equipment	509,525		546,800


Right of use asset (Note 14)	6,406		5,592
Other assets	16,111		14,389
Total assets (1)	$	609,156	$	649,703



	September 30, 2017		December 31, 2016
	(In thousands except share amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	822	$	893
Accounts receivable, net of allowance for doubtful accounts of $2,393 and $3,773 at September 30, 2017 and December 31, 2016, respectively	116,292		83,954
Materials and supplies	3,323		3,340
Current derivative asset (Note 10)	1,064		—
Current income tax receivable	114		99
Current deferred tax asset (Note 8)	—		25,211
Prepaid expenses and other	7,351		7,699
Total current assets	128,966		121,196
Property and equipment:
Oil and natural gas properties on the full cost method:
Proved properties	5,605,974		5,446,305
Unproved properties not being amortized	337,064		314,867
Drilling equipment	1,593,835		1,565,268
Gas gathering and processing equipment	715,864		705,859
Saltwater disposal systems	62,387		60,638
Corporate land and building	59,079		59,066
Transportation equipment	29,731		32,842
Other	53,308		48,590
	8,457,242		8,233,435
Less accumulated depreciation, depletion, amortization, and impairment	6,099,229		5,952,330
Net property and equipment	2,358,013		2,281,105
Goodwill	62,808		62,808
Non-current derivative asset (Note 10)	—		377
Other assets	16,085		13,817
Total assets	$	2,565,872	$	2,479,303



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2017			2016			2017			2016
	(In thousands except per share amounts)
Revenues:
Oil and natural gas	$	85,470		$	78,854		$	256,241		$	206,318
Contract drilling	51,619			25,819			128,059			88,786
Gas gathering and processing	51,399			48,735			150,493			132,793
Total revenues	188,488			153,408			534,793			427,897
Expenses:
Operating costs:
Oil and natural gas	33,911			26,014			95,873			92,691
Contract drilling	34,747			19,137			91,213			66,489
Gas gathering and processing	38,116			35,738			111,862			99,185
Total operating costs	106,774			80,889			298,948			258,365
Depreciation, depletion, and amortization	54,533			49,969			151,545			158,437
Impairments (Note 2)	—			49,443			—			161,563
General and administrative	9,235			8,852			26,902			25,811
Gain on disposition of assets	(81		)	(154		)	(1,153		)	(823		)
Total operating expenses	170,461			188,999			476,242			603,353
Income (loss) from operations	18,027			(35,591		)	58,551			(175,456		)
Other income (expense):
Interest, net	(9,944		)	(10,002		)	(28,807		)	(30,225		)
Gain (loss) on derivatives	(2,614		)	6,969			21,019			(4,774		)
Other, net	5			3			14			(11		)
Total other income (expense)	(12,553		)	(3,030		)	(7,774		)	(35,010		)
Income (loss) before income taxes	5,474			(38,621		)	50,777			(210,466		)
Income tax expense (benefit):
Deferred	1,769			(14,599		)	22,084			(73,159		)
Total income taxes	1,769			(14,599		)	22,084			(73,159		)
Net income (loss)	$	3,705		$	(24,022	)	$	28,693		$	(137,307	)
Net income (loss) per common share:
Basic	$	0.07		$	(0.48	)	$	0.56		$	(2.75	)
Diluted	$	0.07		$	(0.48	)	$	0.56		$	(2.75	)


	Three Months Ended June 30, 2021
	Shareholders' Equity Attributable to Unit Corporation
	Common Stock		Treasury Stock		Capital in Excess of Par Value		Retained Earnings (Deficit)		Non-controlling Interest in Consolidated Subsidiaries		Total
	(In thousands except per share amounts)
Balances, March 31, 2021 (Successor)	$	120	$	0	$	197,316	$	(20,077)	$	247,733	$	425,092
Net income (loss)	0		0		0		(12,994)		2,879		(10,115)

Activity in stock-based compensation plans	0		0		245		0		15		260
Distributions to non-controlling interests	0		0		0		0		(12,344)		(12,344)
Repurchase of common stock	0		(9,048)		0		0		0		(9,048)
Balances, June 30, 2021 (Successor)	$	120	$	(9,048)	$	197,561	$	(33,071)	$	238,283	$	393,845



Supplemental disclosure of cash flow information:
Cash paid during the year for:
Interest paid (net of capitalized)	14,601		16,650
Income taxes	—		—
Changes in accounts payable and accrued liabilities related to purchases of property, plant, and equipment	(20,122	)	36,934
Non-cash (addition) reduction to oil and natural gas properties related to asset retirement obligations	(3,203	)	29,423



	Classification on the unaudited condensed consolidated balance sheets	June 30, 2021		December 31, 2020		Change
		(In thousands)
Assets
Current contract assets	Prepaid expenses and other	$	3,226	$	6,084	$	(2,858)
Non-current contract assets	Other assets	0		173		(173)
Total contract assets		$	3,226	$	6,257	$	(3,031)

Liabilities
Current contract liabilities	Current portion of other long-term liabilities	$	2,098	$	2,583	$	(485)
Non-current contract liabilities	Other long-term liabilities	626		1,589		(963)
Total contract liabilities		2,724		4,172		(1,448)
Contract assets (liabilities), net		$	502	$	2,085	$	(1,583)


Contract	Remaining Term of Contract	2021		2022		2023 and beyond		Total Remaining Impact to Revenue
		(In thousands)
Demand fee contracts	4 - 16 months	$	(1,876)	$	1,374	$	0	$	(502)



Adjusted Purchase Price
Total consideration given	$	54,332

Adjusted Allocation of Purchase Price
Oil and natural gas properties included in the full cost pool:
Proved oil and natural gas properties	$	43,745
Undeveloped oil and natural gas properties	8,650
Total oil and natural gas properties included in the full cost pool ⁽¹⁾	52,395
Gas gathering equipment and other	2,340
Asset retirement obligation	(403		)
Fair value of net assets acquired	$	54,332


	Earnings (Loss) (Numerator)		Weighted Shares (Denominator)	Per-Share Amount
	(In thousands except per share amounts)
For the three months ended June 30, 2021 (Successor)
Basic loss attributable to Unit Corporation per common share	$	(12,994)	11,901	$	(1.09)
Effect of dilutive stock options and restricted stock	0		0	0
Diluted loss attributable to Unit Corporation per common share	$	(12,994)	11,901	$	(1.09)
For the three months ended June 30, 2020 (Predecessor)
Basic loss attributable to Unit Corporation per common share	$	(215,649)	53,503	$	(4.03)
Effect of dilutive stock options and restricted stock	0		0	0
Diluted loss attributable to Unit Corporation per common share	$	(215,649)	53,503	$	(4.03)


	Earnings (Loss) (Numerator)		Weighted Shares (Denominator)	Per-Share Amount
	(In thousands except per share amounts)
For the six months ended June 30, 2021 (Successor)
Basic loss attributable to Unit Corporation per common share	$	(14,931)	11,950	$	(1.25)
Effect of dilutive stock options and restricted stock	0		0	0
Diluted loss attributable to Unit Corporation per common share	$	(14,931)	11,950	$	(1.25)
For the six months ended June 30, 2020 (Predecessor)
Basic loss attributable to Unit Corporation per common share	$	(986,143)	53,317	$	(18.50)
Effect of dilutive stock options and restricted stock	0		0	0
Diluted loss attributable to Unit Corporation per common share	$	(986,143)	53,317	$	(18.50)



	Amount
Beginning October 1,	(In thousands)
2017	$	6,168
2018	6,168
2019	6,168
2020	5,310
Total future payments	23,814
Less payments related to:
Maintenance	6,320
Interest	1,333
Present value of future minimum payments	$	16,161


~~(1)~~	~~We sold our interest in a number of non-core wells to unaffiliated third-parties during the first nine months of 2017 and 2016, respectively.~~



	September 30, 2017		December 31, 2016
	(In thousands)
Interest payable	$	17,480	$	6,524
Employee costs	14,526		15,394
Lease operating expenses	12,686		10,075
Taxes	9,982		2,219
Third-party credits	2,184		2,998
Other	3,274		2,441
Total accrued liabilities	$	60,132	$	39,651


~~(2)~~	~~Plugging liability estimates were revised in both 2017 and 2016~~ 1.Plugging liability estimates were revised in 2020 for updates ~~in the cost of services used to plug wells over the preceding year. We had various upward and downward adjustments.~~



	Nine Months Ended						Nine Months Ended
	September 30, 2017						September 30, 2016
	Time Vested			Performance Vested			Time Vested			Performance Vested
Shares granted:
Employees	475,799			173,373			486,578			152,373
Non-employee directors	49,104			—			90,000			—
	524,903			173,373			576,578			152,373
Estimated fair value (in millions):⁽¹⁾
Employees	$	11.8		$	4.5		$	2.6		$	0.8
Non-employee directors	0.9			—			0.9			—
	$	12.7		$	4.5		$	3.5		$	0.8
Percentage of shares granted expected to be distributed:
Employees	95		%	91		%	94		%	89		%
Non-employee directors	100		%	N/A			100		%	N/A


~~(1)~~	~~Represents 100% of the grant date fair value. (We recognize the grant date fair value minus estimated forfeitures.)~~


		Derivative Liabilities
		Fair Value

	Classification on the unaudited condensed consolidated balance sheets	June 30, 2021		December 31, 2020
		(In thousands)
Commodity derivatives:
Current	Current derivative liability	$	37,960	$	1,047
Long-term	Non-current derivative liability	23,270		4,659
Total derivative liabilities		$	61,230	$	5,706



		Derivative Assets
		Fair Value
	Balance Sheet Location	September 30, 2017		December 31, 2016
		(In thousands)
Commodity derivatives:
Current	Current derivative asset	$	1,064	$	—
Long-term	Non-current derivative asset	—		377
Total derivative assets		$	1,064	$	377



Derivatives Instruments	Location of Gain (Loss) Recognized in Income on Derivative	Amount of Gain (Loss) Recognized in Income on Derivative
		2017			2016
		(In thousands)
Commodity derivatives	Gain (loss) on derivatives ⁽¹⁾	$	(2,614	)	$	6,969
Total		$	(2,614	)	$	6,969


~~(1)~~	~~Amounts settled during the 2017 and 2016 periods include net proceeds of $0.8 million and net payments of $0.5 million, respectively.~~



Derivatives Instruments	Location of Gain (Loss) Recognized in Income on Derivative	Amount of Gain (Loss) Recognized in Income on Derivative
		2017		2016
		(In thousands)
Commodity derivatives	Gain (loss) on derivatives ⁽¹⁾	$	21,019	$	(4,774	)
Total		$	21,019	$	(4,774	)



	Cost		Gross Unrealized Gains		Gross Unrealized Losses		Estimated Fair Value
	(In thousands)
Equity Securities:
September 30, 2017	$	830	$	85	$	—	$	915
December 31, 2016	$	—	$	—	$	—	$	—



	June 30, 2021
	Level 2		Level 3		Effect of Netting		Net Amounts Presented
	(In thousands)
Financial assets (liabilities):
Commodity derivatives:
Assets	$	0	$	0	$	0	$	0
Liabilities	(61,230)		0		0		(61,230)
Total commodity derivatives	$	(61,230)	$	0	$	0	$	(61,230)


	September 30, 2017															December 31, 2020
	Level 1		Level 2			Level 3			Effect of Netting			Net Amounts Presented				Level 2		Level 3		Effect of Netting		Net Amounts Presented
	(In thousands)															(In thousands)
Financial assets (liabilities):															Financial assets (liabilities):
Commodity derivatives:															Commodity derivatives:
Assets	$	—	$	662		$	1,964		$	(1,562	)	$	1,064		Assets	$	3,436	$	0	$	(3,436)	$	0
Liabilities	—		(2,002		)	(478		)	1,562			(918		)	Liabilities	(9,142)		0		3,436		(5,706)
Total commodity derivatives	—		(1,340		)	1,486			—			146			Total commodity derivatives	$	(5,706)	0		0		(5,706)
Equity securities	915		—			—			—			915
	$	915	$	(1,340	)	$	1,486		$	—		$	1,061


	Net Derivatives
	Successor		Predecessor		Successor		Predecessor
	Three Months Ended June 30, 2021		Three Months Ended June 30, 2020		Six Months Ended June 30, 2021		Six Months Ended June 30, 2020

	(In thousands)
Beginning of period	$	0	$	948	$	0	$	1,204
Total gains or losses (realized and unrealized):
Included in earnings (1)	0		714		0		1,277
Settlements	0		(819)		0		(1,638)
End of period	$	0	$	843	$	0	$	843
Total losses for the period included in earnings attributable to the change in unrealized gain (loss) relating to assets still held at end of period	$	0	$	(105)	$	0	$	(361)


~~(1)~~	~~Commodity derivatives are reported in the Unaudited Condensed Consolidated Statements of Operations in gain (loss) on derivatives.~~



Commodity ⁽¹⁾	Fair Value			Valuation Technique	Unobservable Input	Range
	(In thousands)
Oil three-way collars	$	(9	)	Discounted cash flow	Forward commodity price curve	($3.65) - $5.02
Natural gas collar	$	25		Discounted cash flow	Forward commodity price curve	($0.11) - $0.06
Natural gas three-way collars	$	1,470		Discounted cash flow	Forward commodity price curve	($0.34) - $0.54


~~(1)~~	The commodity contracts detailed in this category include non-exchange-traded crude oil and natural gas collars and three-way collars that are valued based on NYMEX. The forward pricing range represents the low and high price expected to be paid or received within the settlement period.


	Amount
	(In thousands)
Ending June 30,
2022	$	3,686
2023	1,528
2024	1,271
2025	86
2026	12
2027 and beyond	57
Total future payments	6,640
Less: Interest	269
Present value of future minimum operating lease payments	6,371
Less: Current portion	3,515
Total long-term operating lease payments	$	2,856



	Net Gains on Equity Securities
	2017		2016
	(In thousands)
Balance at July 1:	$	20	$	—
Unrealized appreciation before reclassifications	33		—
Amounts reclassified from accumulated other comprehensive income	—		—
Net current-period other comprehensive income	33		—
Balance at September 30:	$	53	$	—



	Three Months Ended September 30, 2017
	Oil and Natural Gas			Contract Drilling		Mid-stream		Other			Eliminations			Total Consolidated
	(In thousands)
Revenues:
Oil and natural gas	$	85,470		$	—	$	—	$	—		$	—		$	85,470
Contract drilling	—			55,588		—		—			(3,969		)	51,619
Gas gathering and processing	—			—		69,057		—			(17,658		)	51,399
Total revenues	85,470			55,588		69,057		—			(21,627		)	188,488
Expenses:
Operating costs:
Oil and natural gas	35,082			—		—		—			(1,171		)	33,911
Contract drilling	—			38,115		—		—			(3,368		)	34,747
Gas gathering and processing	—			—		54,602		—			(16,486		)	38,116
Total operating costs	35,082			38,115		54,602		—			(21,025		)	106,774
Depreciation, depletion, and amortization	26,460			15,280		10,880		1,913			—			54,533
Total expenses	61,542			53,395		65,482		1,913			(21,025		)	161,307
Total operating income (loss) ⁽¹⁾	23,928			2,193		3,575		(1,913		)	(602		)
General and administrative expense	—			—		—		(9,235		)	—			(9,235		)
Gain (loss) on disposition of assets	(1		)	68		14		—			—			81
Loss on derivatives	—			—		—		(2,614		)	—			(2,614		)
Interest expense, net	—			—		—		(9,944		)	—			(9,944		)
Other	—			—		—		5			—			5
Income (loss) before income taxes	$	23,927		$	2,261	$	3,589	$	(23,701	)	$	(602	)	$	5,474


~~(1)~~	Operating income (loss) is total operating revenues less operating expenses, depreciation, depletion, and amortization and does not include general corporate expenses, gain (loss) on disposition of assets, loss on derivatives, interest expense, other income (loss), or income taxes.


																			Successor
	Three Months Ended September 30, 2016																		Three Months Ended June 30, 2021
	Oil and Natural Gas			Contract Drilling			Mid-stream		Other			Eliminations			Total Consolidated				Oil and Natural Gas (2)		Contract Drilling		Mid-Stream		Corporate and Other		Eliminations (3)		Total Consolidated
	(In thousands)																		(In thousands)
Revenues:(1)
Oil and natural gas	$	78,854		$	—		$	—	$	—		$	—		$	78,854		Oil and natural gas	$	59,776	$	0	$	0	$	0	$	(17,806)	$	41,970
Contract drilling	—			25,819			—		—			—			25,819			Contract drilling	0		18,061		0		0		0		18,061
Gas gathering and processing	—			—			63,090		—			(14,355		)	48,735			Gas gathering and processing	0		0		66,323		0		7,703		74,026
Total revenues	78,854			25,819			63,090		—			(14,355		)	153,408			Total revenues	59,776		18,061		66,323		0		(10,103)		134,057
Expenses:																		Expenses:
Operating costs:																		Operating costs:
Oil and natural gas	27,710			—			—		—			(1,696		)	26,014			Oil and natural gas	16,350		0		0		0		(863)		15,487
Contract drilling	—			19,137			—		—			—			19,137			Contract drilling	0		14,080		0		0		0		14,080
Gas gathering and processing	—			—			48,397		—			(12,659		)	35,738			Gas gathering and processing	0		0		55,176		0		(10,120)		45,056
Total operating costs	27,710			19,137			48,397		—			(14,355		)	80,889			Total operating costs	16,350		14,080		55,176		0		(10,983)		74,623
Depreciation, depletion, and amortization	27,135			11,318			11,436		80			—			49,969			Depreciation, depletion, and amortization	6,476		1,570		8,064		254		0		16,364
Impairments	49,443			—			—		—			—			49,443

Total expenses	104,288			30,455			59,833		80			(14,355		)	180,301			Total expenses	22,826		15,650		63,240		254		(10,983)		90,987
Total operating income (loss)⁽¹⁾	(25,434		)	(4,636		)	3,257		(80		)	—
General and administrative expense	—			—			—		(8,852		)	—			(8,852		)

General and administrative																		General and administrative	0		0		0		4,871		880		5,751
Gain on disposition of assets	—			151			—		3			—			154			Gain on disposition of assets	(67)		(1,618)		0		(25)		0		(1,710)
Gain on derivatives	—			—			—		6,969			—			6,969
Interest expense, net	—			—			—		(10,002		)	—			(10,002		)
Income (loss) from operations																		Income (loss) from operations	37,017		4,029		3,083		(5,100)		0		39,029
Loss on derivatives																		Loss on derivatives	0		0		0		(42,400)		0		(42,400)
Loss on change in fair value of warrants																		Loss on change in fair value of warrants	0		0		0		(3,574)		0		(3,574)

Reorganization items, net																		Reorganization items, net	0		0		0		(1,852)		0		(1,852)
Interest, net																		Interest, net	0		0		641		(1,128)		0		(487)
Other	—			—			—		3			—			3			Other	34		11		(850)		(26)		0		(831)
Income (loss) before income taxes	$	(25,434	)	$	(4,485	)	$	3,257	$	(11,959	)	$	—		$	(38,621	)	Income (loss) before income taxes	$	37,051	$	4,040	$	2,874	$	(54,080)	$	0	$	(10,115)