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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
☒ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2020
OR
☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from              to             
[Commission File Number 1-9260]
UNT-20200331_G1.JPG
UNIT CORPORATION
(Exact name of registrant as specified in its charter)
Delaware 73-1283193
(State or other jurisdiction of incorporation) (I.R.S. Employer Identification No.)
8200 South Unit Drive, Tulsa, Oklahoma 74132
(Address of principal executive offices) (Zip Code)
(918) 493-7700
(Registrant’s telephone number, including area code)
None
(Former name, former address and former fiscal year,
if changed since last report)

Securities registered pursuant to Section 12(b) of the Act:
Title of each class Trading Symbol(s) Name of each exchange on which registered
Common Stock UNTCQ *
* On May 26, 2020, the issuer’s common stock was suspended from trading on the NYSE. Effective May 27, 2020, trades in the issuer’s common stock began being quoted on the OTC Pink Marketplace under the symbol “UNTCQ.” On June 10, 2020, the NYSE filed a Form 25 to delist the issuer’s common stock and to remove it from registration under Section 12(b) of the Exchange Act.
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes ☒            No ☐ 

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).       Yes ☒            No ☐                                                   
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and "emerging growth company" in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer ☐    Accelerated filer ☒    Non-accelerated filer ☐
Smaller reporting company ☐   Emerging growth company ☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐        

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐            No ☒         
As of June 11, 2020, 54,622,664 shares of the issuer's common stock were outstanding.

EXPLANATORY NOTE

As previously disclosed in the Current Report on Form 8-K filed by Unit Corporation, a Delaware corporation (the company), with the U.S. Securities and Exchange Commission (SEC) on May 7, 2020, the filing of this report was delayed due to the circumstances related to the COVID-19 pandemic. The outbreak and spread of COVID-19 required the company’s employees to work remotely, which has resulted in a delay in the preparation and completion of the information in the 10-Q. The company’s headquarters, officers, corporate, legal, and accounting personnel are in Tulsa, Oklahoma, which had issued orders limiting the company’s ability to conduct its normal business operations, including orders to “shelter-in-place.” The disruptions in staffing, communications, and access to personnel resulted in delays, limited support, and insufficient time for preparation and review of this report. For the foregoing reasons, the company had not yet finalized its financial results for the quarterly period ended March 31, 2020. The company relied on the SEC’s Order Under Section 36 of the Securities Exchange Act of 1934 Modifying Exemptions From the Reporting and Proxy Delivery Requirements for Public Companies, dated March 25, 2020 (Release No. 34-88465) to delay the filing of this report on Form 10-Q.

2

TABLE OF CONTENTS
 
    Page
Number
Item 1.
Unaudited Condensed Consolidated Balance Sheets
March 31, 2020 and December 31, 2019
3
Unaudited Condensed Consolidated Statements of Operations
Three Months Ended March 31, 2020 and 2019
5
Unaudited Condensed Consolidated Statements of Comprehensive Loss
Three Months Ended March 31, 2020 and 2019
6
Unaudited Condensed Consolidated Statements of Changes in Shareholders' Equity
Three Months Ended March 31, 2020 and 2019
7
Unaudited Condensed Consolidated Statements of Cash Flows
Three Months Ended March 31, 2020 and 2019
8
10
Item 2.
40
Item 3.
59
Item 4.
60
Item 1.
62
Item 1A.
63
Item 2.
69
Item 3.
69
Item 4.
69
Item 5.
69
Item 6.
69
72

3
Forward-Looking Statements

This report contains “forward-looking statements” – meaning, statements related to future events within the meaning of Section 27A of the Securities Act of 1933, as amended and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, included or incorporated by reference in this document that addresses activities, events or developments 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. This report modifies and supersedes documents filed by us before this report. In addition, certain information we file with the SEC will automatically update and supersede information in this report.
These forward-looking statements include, among others, things such as:

•the amount and nature of our future capital expenditures and how we expect to fund our capital expenditures;
•prices for oil, natural gas liquids (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 actions affecting our costs and increasing operating restrictions or delays and other adverse impacts on our business;
•the possibility of security threats, including terrorist attacks and cybersecurity breaches, against, or otherwise affecting our facilities and systems;
•our projected production guidelines for the year;
•our anticipated capital budgets;
•our financial condition and liquidity (including our ability to refinance our senior subordinated notes);
•the number of wells our oil and natural gas segment plans to drill or rework during the year;
•our estimates of the amounts of any ceiling test write-downs or other potential asset impairments we may have to record in future periods; and
•our plans to restructure our debt and the costs related to those plans.
These statements are based on assumptions and analyses made by us based on our experience and our perception of historical trends, current conditions, and expected future developments, and other factors we believe are appropriate in the circumstances. Whether actual results and developments will conform to our expectations and predictions is subject to several risks and uncertainties, any one or combination of which could cause our actual results to differ materially from our expectations and predictions, including:
•the risk factors discussed in this document and in the documents (if any) we incorporate by reference;
•general economic, market, or business conditions;
•the availability of and nature of (or lack of) business opportunities we pursue;
•demand for our land drilling services;
•changes in laws or regulations;
•changes in the current geopolitical situation;
•risks relating to financing, including restrictions in our debt agreements and availability and cost of credit;
•risks associated with future weather conditions;
•decreases or increases in commodity prices;
•the amount and terms of our debt;
•future compliance with covenants under our debt agreements;
1
•our ability to confirm and consummate a plan of reorganization under Chapter 11 of Title 11 of the United States Code (Bankruptcy Code);
•our ability to obtain the approval of the United States Bankruptcy Court for the Southern District of Texas, Houston Division (Bankruptcy Court) regarding motions or other requests made to the Bankruptcy Court in the Chapter 11 Cases (as defined below), including maintaining strategic control as debtor-in-possession;
•Bankruptcy Court rulings in the Chapter 11 Cases and the outcome of the Chapter 11 Cases in general;
•the time that we will operate under Chapter 11 protection and the continued availability of operating capital during the pendency of the proceedings;
•risks associated with third party motions in the Chapter 11 Cases, which may interfere with our ability to confirm and consummate a plan of reorganization;
•the potential adverse effects of the Chapter 11 Cases on our liquidity and results of operations;
•increased advisory costs to execute a reorganization;
•the effects of the Bankruptcy Petitions (as defined below) on the interests of various constituencies, including holders of our common stock;
•inability to maintain relationship with suppliers, customers, employees and other third parties because of our Chapter 11 filing;
•ability to satisfy our short- or long-term liquidity needs, including ability to generate sufficient cash flow from operations or to obtain adequate financing to fund our capital expenditures and meet working capital needs and ability to continue as a going concern;
•our ability to continue as a going concern;
•putative class action lawsuits that may cause substantial expenditures and divert management's attention;
•the public health crisis related to a novel strain of coronavirus (COVID-19) and resulting impact on demand and supply for oil and natural gas;
•delays in the Chapter 11 Cases or interruptions or cessation of our business operations as a result of the COVID-19 pandemic;
•other risks related to the outbreak of COVID-19 and its impact on our business, suppliers, customers, employees and supply chains; 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 this document to reflect unanticipated events.
To help provide you with a more thorough understanding of the possible effects of these influences on any forward-looking statements made by us, this discussion outlines some (but not all) of the factors that could cause our consolidated results to differ materially from those that may be presented in any forward-looking statement made by us or on our behalf.
2
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements

UNIT CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
March 31,
2020 		December 31,
2019
  (In thousands except share amounts)
ASSETS
Current assets:
Cash and cash equivalents $ 40,994    $ 571   
Accounts receivable, net of allowance for doubtful accounts of $2,332 as of March 31, 2020 and December 31, 2019, respectively    54,379    82,656   
Materials and supplies 414    449   
Current derivative asset (Note 12) 661    633   
Current income tax receivable 2,673    1,756   
Assets held for sale (Note 5) —    5,908   
Prepaid expenses and other 13,754    13,078   
Total current assets 112,875    105,051   
Property and equipment:
Oil and natural gas properties, on the full cost method:
Proved properties 6,565,136    6,341,582   
Unproved properties not being amortized 31,538    252,874   
Drilling equipment 1,298,626    1,295,713   
Gas gathering and processing equipment 829,600    824,699   
Saltwater disposal systems 43,831    69,692   
Land and building 59,080    59,080   
Transportation equipment 27,515    29,723   
Other 58,039    57,992   
8,913,365    8,931,355   
Less accumulated depreciation, depletion, amortization, and impairment 7,768,310    6,978,669   
Net property and equipment 1,145,055    1,952,686   
Right of use asset (Note 14) 6,937    5,673   
Other assets 22,976    26,642   
Total assets (1)
$ 1,287,843    $ 2,090,052   

The accompanying notes are an integral part of these
unaudited condensed consolidated financial statements.
3
UNIT CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED) - CONTINUED

March 31,
2020 		December 31,
2019
  (In thousands except share amounts)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable $ 58,595    $ 84,481   
Accrued liabilities (Note 7) 41,830    46,562   
Current operating lease liability (Note 14) 4,128    3,430   
Current portion of long-term debt (Note 8)(1)
771,283    108,200   
Current portion of other long-term liabilities (Note 8) 18,317    17,376   
Total current liabilities 894,153    260,049   
Long-term debt less debt issuance costs (Note 8)(1)
37,000    663,216   
Non-current derivative liabilities (Note 12) 123    27   
Operating lease liability (Note 14) 2,639    2,071   
Other long-term liabilities (Note 8) 88,237    95,341   
Deferred income taxes 11,205    13,713   
Commitments and contingencies (Note 15)
Shareholders’ equity:
Preferred stock, $1.00 par value, 5,000,000 shares authorized, none issued —    —   
Common stock, $0.20 par value, 175,000,000 shares authorized, 54,746,727 and 55,443,393 shares issued as of March 31, 2020 and December 31, 2019, respectively 10,694    10,591   
Capital in excess of par value 646,543    644,152   
Retained earnings (deficit) (571,359)   199,135   
Total shareholders’ equity attributable to Unit Corporation 85,878    853,878   
Non-controlling interests in consolidated subsidiaries 168,608    201,757   
Total shareholders' equity 254,486    1,055,635   
Total liabilities(2) and shareholders’ equity
$ 1,287,843    $ 2,090,052   
_______________________
(1)As of March 31, 2020, the current portion of long-term debt is net of debt issuance costs. As of December 31, 2019, the long-term debt is net of debt issuance costs. See Note 8 – Long-Term Debt and Other Long-Term Liabilities.
(2)Unit Corporation's consolidated total assets as of March 31, 2020 include total current and long-term assets of its variable interest entity (VIE) (Superior Pipeline Company, L.L.C.) of $46.7 million and $360.7 million, respectively, which can only settle obligations of the VIE. Unit Corporation's consolidated total liabilities as of March 31, 2020 include total current and long-term liabilities of the VIE of $25.8 million and $42.9 million, respectively, for which the creditors of the VIE have no recourse to Unit Corporation. Unit Corporation's consolidated total assets as of December 31, 2019 include total current and long-term assets of the VIE of $28.8 million and $434.3 million, respectively, which can only settle obligations of the VIE. Unit Corporation's consolidated total liabilities as of December 31, 2019 include total current and long-term liabilities of the VIE of $32.2 million and $26.0 million, respectively, for which the creditors of the VIE have no recourse to Unit Corporation. See Note 16 – Variable Interest Entity Arrangements.


The accompanying notes are an integral part of these
unaudited condensed consolidated financial statements.
4



UNIT CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
 
Three Months Ended
  March 31,
  2020 2019
  (In thousands except per share amounts)
Revenues:
Oil and natural gas $ 48,522    $ 86,095   
Contract drilling 36,632    51,155   
Gas gathering and processing 37,222    52,441   
Total revenues 122,376    189,691   
Expenses:
Operating costs:
Oil and natural gas 30,663    32,714   
Contract drilling 25,449    31,401   
Gas gathering and processing 27,611    39,355   
Total operating costs 83,723    103,470   
Depreciation, depletion, and amortization 61,617    62,126   
Impairments (Note 3) 741,924    —   
Loss on abandonment of assets (Note 3) 17,554    —   
General and administrative 11,553    9,741   
Loss on disposition of assets 390    1,615   
Total operating expenses 916,761    176,952   
Income (loss) from operations (794,385)   12,739   
Other income (expense):
Interest, net (13,257)   (8,538)  
Gain (loss) on derivatives 483    (6,932)  
Other, net 60    5   
Total other income (expense) (12,714)   (15,465)  
Loss before income taxes (807,099)   (2,726)  
Income tax benefit:
Current (917)   —   
Deferred (2,508)   (444)  
Total income taxes (3,425)   (444)  
Net loss (803,674)   (2,282)  
Net income (loss) attributable to non-controlling interest (33,180)   1,222   
Net loss attributable to Unit Corporation (770,494)   (3,504)  
Net loss attributable to Unit Corporation per common share (Note 6):
Basic $ (14.50)   $ (0.07)  
Diluted $ (14.50)   $ (0.07)  

The accompanying notes are an integral part of these
unaudited condensed consolidated financial statements.

5


UNIT CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (UNAUDITED)
 
Three Months Ended
  March 31,
  2020 2019
  (In thousands)
Net loss (803,674)   (2,282)  
Other comprehensive income, net of taxes:   
Unrealized gain on securities, net of tax of $0 and $7 —    24   
Comprehensive loss    (803,674)   (2,258)  
Less: Comprehensive income (loss) attributable to non-controlling interest (33,180)   1,222   
Comprehensive loss attributable to Unit Corporation $ (770,494)   $ (3,480)  

The accompanying notes are an integral part of these
unaudited condensed consolidated financial statements.
6



UNIT CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY (UNAUDITED)

Three Months Ended March 31, 2020
Shareholders' Equity Attributable to Unit Corporation
Common
Stock 		Capital in Excess
of Par Value 		Accumulated Other Comprehensive Income Retained
Earnings (Deficit) 		Non-controlling Interest in Consolidated Subsidiaries Total
(In thousands except per share amounts)
Balances, December 31, 2019 $ 10,591    $ 644,152    $ —    $ 199,135    $ 201,757    $ 1,055,635   
Net loss —    —    —    (770,494)   (33,180)   (803,674)  
Activity in employee compensation plans 103    2,391    —    —    31    2,525   
Balances, March 31, 2020 $ 10,694    $ 646,543    $ —    $ (571,359)   $ 168,608    $ 254,486   

Three Months Ended March 31, 2019
Shareholders' Equity Attributable to Unit Corporation
Common
Stock 		Capital in Excess
of Par Value 		Accumulated Other Comprehensive Income (Loss) Retained
Earnings 		Non-controlling Interest in Consolidated Subsidiaries Total
(In thousands except per share amounts)
Balances, December 31, 2018 $ 10,414    $ 628,108    $ (481)   $ 752,840    $ 202,563    $ 1,593,444   
Cumulative effect adjustment for adoption of ASUs —    —    —    174    —    174   
Net income (loss) —    —    —    (3,504)   1,222    (2,282)  
Other comprehensive income (net of tax of $7) —    —    24    —    —    24   
Total comprehensive loss (2,258)  
Distributions to non-controlling interest —    —    —    —    (918)   (918)  
Activity in employee compensation plans 164    5,253    —    —    —    5,417   
Balances, March 31, 2019 $ 10,578    $ 633,361    $ (457)   $ 749,510    $ 202,867    $ 1,595,859   


The accompanying notes are an integral part of these
unaudited condensed consolidated financial statements.
7
UNIT CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
Three Months Ended
  March 31,
  2020 2019
  (In thousands)
OPERATING ACTIVITIES:
Net loss    $ (803,674)   $ (2,282)  
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization 61,617    62,126   
Impairments (Note 3)   741,924    —   
Loss on abandonment of assets (Note 3)   17,554    —   
Amortization of debt issuance costs and debt discount (Note 8)   567    556   
(Gain) loss on derivatives (Note 12)   (483)   6,932   
Cash receipts on derivatives settled (Note 12)   551    2,656   
Loss on disposition of assets    390    1,615   
Deferred tax benefit (2,508)   (444)  
Employee stock compensation plans 2,568    5,134   
ARO liability accretion (Note 9)   596    562   
Contract assets and liabilities, net (Note 4)   808    (700)  
Other, net (740)   11   
Changes in operating assets and liabilities increasing (decreasing) cash:
Accounts receivable 28,277    22,940   
Material and supplies 35    (22)  
Prepaid expenses and other 420    747   
Accounts payable (12,341)   (20,848)  
Accrued liabilities (4,840)   2,749   
Income taxes (917)   —   
Contract advances 108    (544)  
Net cash provided by operating activities    29,912    81,188   
INVESTING ACTIVITIES:
Capital expenditures (17,528)   (122,507)  
Producing properties and other acquisitions (210)   (1,580)  
Proceeds from disposition of property and equipment 1,751    3,190   
Net cash used in investing activities    (15,987)   (120,897)  
FINANCING ACTIVITIES:
Borrowings under line of credit 71,400    109,800   
Payments under line of credit (35,100)   (69,800)  
Net payments on finance leases (1,026)   (985)  
Employee taxes paid by withholding shares (43)   (4,110)  
Distributions to non-controlling interests —    (918)  
Bank overdrafts (8,733)   3,161   
Net cash provided by financing activities    26,498    37,148   
Net increase (decrease) in cash and cash equivalents   40,423    (2,561)  
Cash and cash equivalents, beginning of year 571    6,452   
Cash and cash equivalents, end of year $ 40,994    $ 3,891   

The accompanying notes are an integral part of these
unaudited condensed consolidated financial statements.
8



UNIT CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) - CONTINUED

Three Months Ended
  March 31,
  2020 2019
  (In thousands)
Supplemental disclosure of cash flow information:
Cash paid during the year for:
Interest paid (net of capitalized) $ 2,141    $ (3,307)  
Income taxes —    —   
Changes in accounts payable and accrued liabilities related to purchases of property, plant, and equipment 4,812    (641)  
Non-cash (additions) reductions to oil and natural gas properties related to asset retirement obligations 3,404    (3,070)  
Non-cash trade of property, plant, and equipment 548    —   

The accompanying notes are an integral part of these
unaudited condensed consolidated financial statements.
9
UNIT CORPORATION AND SUBSIDIARIES
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 – BASIS OF PREPARATION AND PRESENTATION

The unaudited condensed consolidated financial statements in this report include the accounts of Unit Corporation and all its subsidiaries and affiliates and have been prepared under the rules and regulations of the SEC. The terms “company,” “Unit,” “we,” “our,” “us,” or like terms refer to Unit Corporation, a Delaware corporation, and one or more of its subsidiaries and affiliates, except as otherwise indicated or as the context otherwise requires. We consolidate the activities of Superior Pipeline Company, L.L.C. (Superior), a 50/50 joint venture between Unit Corporation and SP Investor Holdings, LLC, (SP Investor) which qualifies as a Variable Interest Entity (VIE) under generally accepted accounting principles in the United States (GAAP). We have concluded that we are the primary beneficiary of the VIE, as defined in the accounting standards, since we have the power, through 50% ownership, to direct those activities that most significantly affect the economic performance of Superior as further described in Note 16 – Variable Interest Entity Arrangements.

The condensed consolidated financial statements are unaudited and do not include all the notes in our annual financial statements. This report should be read with the audited consolidated financial statements and notes in our Annual Report on Form 10-K for the year ended December 31, 2019, filed with the SEC March 16, 2020.

In the opinion of our management, the unaudited condensed consolidated financial statements contain all normal recurring adjustments (including the elimination of all intercompany transactions) necessary to fairly state:

•Balance Sheets as of March 31, 2020 and December 31, 2019;
•Statements of Operations for the three months ended March 31, 2020 and 2019;
•Statements of Comprehensive Income (Loss) for the three months ended March 31, 2020 and 2019;
•Statements of Changes in Shareholders' Equity for the three months ended March 31, 2020 and 2019; and
•Statements of Cash Flows for the three months ended March 31, 2020 and 2019.

Our financial statements are prepared in conformity with GAAP, which requires us to make certain estimates and assumptions that may affect the amounts reported in our unaudited condensed consolidated financial statements and notes. Actual results may differ from those estimates. Results for the three months ended March 31, 2020 and 2019 are not necessarily indicative of the results we may realize for the full year of 2020, or that we realized for the full year of 2019.

Certain amounts in this report for prior periods have been reclassified to conform to current year presentation. There was no impact to consolidated net loss or shareholders' equity.

NOTE 2 – CHAPTER 11 PROCEEDINGS, LIQUIDITY, AND ABILITY TO CONTINUE AS A GOING CONCERN

Voluntary Reorganization Under Chapter 11 of the Bankruptcy Code

On May 22, 2020 (Petition Date), Unit and its wholly owned subsidiaries Unit Drilling Company (UDC) Unit Petroleum Company (UPC), 8200 Unit Drive, L.L.C. (8200 Unit), Unit Drilling Colombia, L.L.C. (Unit Drilling Colombia) and Unit Drilling USA Colombia, L.L.C. (Unit Drilling USA, together with Unit, UPC, UDC, 8200 Unit and Unit Drilling Colombia, the Debtors) filed voluntary petitions (Bankruptcy Petitions) for reorganization under Chapter 11 of Title 11 of the United States Code (Bankruptcy Code) in the United States Bankruptcy Court for the Southern District of Texas, Houston Division (Bankruptcy Court). The Chapter 11 proceedings are being jointly administered under the caption In re Unit Corporation, et al., Case No. 20-32740 (DRJ) (Chapter 11 Cases). The Debtors are operating their business as "debtors-in-possession" under the jurisdiction of the Bankruptcy Court and under the provisions of the Bankruptcy Code and orders of the Bankruptcy Court.

On May 22, 2020, the Debtors entered into a Restructuring Support Agreement (RSA) with (i)holders of 100% of the aggregate principal amount of loans outstanding under the Senior Credit Agreement, dated as of September 13, 2011 (as amended, the Unit credit agreement, together with the loan facility, the Unit credit facility), by and among the company, UPC and UDC, as borrowers, the institutions named as lenders (RBL Lenders) and BOKF, NA dba Bank of Oklahoma, as administrative agent (RBL Agent) and (ii)holders of over 70% of the aggregate outstanding principal amount of the company’s 6.625% senior subordinated notes due 2021 (Notes). In accordance with the RSA, the Debtors filed a Chapter 11 plan of reorganization (including all exhibits and schedules attached thereto, and as may be amended, supplemented, or modified from
10
time to time, Plan) and the related disclosure statement with the Bankruptcy Court on June 9, 2020. Below is a summary of the treatment that the stakeholders of the Debtors would receive under the Plan:

•Each lender under the Unit credit facility and the DIP credit facility described below will receive its pro rata share of revolving loans, term loans and letter-of-credit participations under the Exit Facility described below, in exchange for that lender’s allowed claims under the Unit credit facility or DIP credit facility;
•Each holder of the Notes will receive its pro rata share of new common shares of reorganized Unit based on equity allocations at each of Unit, UDC and UPC in exchange for the holder’s allowed Notes claim;
•Each holder of an allowed general unsecured claim against Unit or UPC will receive its pro rata share of new common shares of reorganized Unit based on equity allocations at each of Unit and UPC, respectively;
•Each retained or former employee with a claim for vested severance benefits may opt-in to a settlement to receive a cash payment for that claim in lieu of an allocation of new common shares of reorganized Unit otherwise provided to holders of general unsecured claims;
•Each holder of an allowed unsecured claim against UDC, 8200 Unit, Unit Drilling Colombia and Unit Drilling USA will receive payment in full of that claim in the ordinary course of business; and
•Each holder of the company’s common stock that does not opt out of the releases under the Plan will receive its pro rata share of seven-year warrants to purchase an aggregate of 12.5% of the new common shares of reorganized Unit at an aggregate exercise price equal to the $650.0 million principal amount of the Notes plus interest thereon to the May 15, 2021 maturity date of the Notes.

As contemplated by the RSA and subject to the Bankruptcy Court’s approval, upon the Debtors’ emergence from the Chapter 11 Cases and to the extent any claims under the DIP credit facility have not otherwise been repaid, each holder of an allowed claim under the DIP credit facility will receive its pro rata share of (i) revolving loans, term loans and letter-of-credit participations under the Exit Facility and (ii) an equity fee under the Exit Facility equal to 5% of the new common shares of reorganized Unit (subject to dilution by shares reserved for issuance under a management incentive plan and exercise of the warrants described above).

As contemplated by the RSA, the company and the other Debtors entered into a Superpriority Senior Secured Debtor-in-Possession Credit Agreement dated May 27, 2020 (DIP credit agreement), by and among the Debtors, the RBL Lenders (in such capacity, the DIP Lenders) and BOKF, NA dba Bank of Oklahoma, as administrative agent, under which the DIP Lenders agreed to provide the company with a $36.0 million multi-draw loan facility ( DIP credit facility). On May 26, 2020, the Bankruptcy Court granted interim approval of the DIP credit facility, including the DIP credit agreement, permitting the Debtors to borrow up to $18.0 million on an interim basis. On June 19, 2020, the Bankruptcy Court granted final approval of the DIP credit facility.

Subject to certain exceptions, under the Bankruptcy Code, filing the Bankruptcy Petitions automatically enjoined, or stayed, the continuation of most judicial or administrative proceedings or filing of other actions against the Debtors or their property to recover, collect or secure a claim arising before the Petition Date. Accordingly, although filing the Bankruptcy Petitions triggered defaults on the Debtors’ debt obligations, creditors are stayed from taking any actions against the Debtors because of such defaults, subject to certain limited exceptions permitted by the Bankruptcy Code. Absent an order of the Bankruptcy Court, substantially all of the Debtors’ pre-petition liabilities are subject to settlement under the Bankruptcy Code (except for payments to UDC’s vendors and suppliers, which are not expected to be affected by the Chapter 11 Cases). Superior and its subsidiaries are not parties to the RSA and are not Debtors in the Chapter 11 Cases.

Subject to certain exceptions, under the Bankruptcy Code, the Debtors may assume, assign or reject certain executory contracts and unexpired leases subject to the approval of the Bankruptcy Court and certain other conditions. Generally, the rejection of an executory contract or unexpired lease is treated as a pre-petition breach of such executory contract or unexpired lease and, subject to certain exceptions, relieves the Debtors of performing their future obligations under such executory contract or unexpired lease but entitles the contract counterparty or lessor to a pre-petition general unsecured claim for damages caused by such deemed breach. Counterparties to such rejected contracts or leases may assert unsecured claims in the Bankruptcy Court against the applicable Debtors’ estate for such damages. Generally, the assumption of an executory contract or unexpired lease requires the Debtors to cure existing monetary defaults under such executory contract or unexpired lease and adequately assure future performance. Any description of an executory contract or unexpired lease with the Debtors in this report, including where applicable a quantification of a Debtor’s obligations under any such executory contract or unexpired lease with the Debtor is qualified by any rejection rights the Debtor has under the Bankruptcy Code. Further, nothing herein is or shall be deemed an admission regarding any claim amounts or calculations arising from the rejection of any executory
11
contract or unexpired lease and the Debtors expressly preserve all of their rights with respect thereto. The Debtors have not yet made any formal determinations regarding the assumption or rejection of any executory contracts or unexpired leases.

Events of Default

The Debtors’ filing of the Bankruptcy Petitions constituted an event of default that accelerated the Debtors' obligations under the Unit credit agreement and the indenture governing the Notes. Additionally, other events of default, including cross-defaults, exist under these debt agreements. As a result, the Unit credit facility and Notes have been classified as current as of March 31, 2020. Under the Bankruptcy Code, the creditors under these debt agreements are stayed from taking any action against the Debtors because of an event of default. Superior and its subsidiaries are not parties to the Chapter 11 Cases, and the Chapter 11 Cases did not result in an event of default under the Superior credit agreement (as defined below). In addition, the company’s filing of the Bankruptcy Petitions constituted a termination event regarding the company’s hedge agreements, which permits the counterparties to such hedge agreements to terminate the outstanding hedges, which termination events are not stayed under the Chapter 11 Cases.

On the Petition Date, the Debtors entered into a Continuation Agreement (Continuation Agreement) with Superior, SPC Midstream Operating, L.L.C. and SP Investor to continue the parties' contractual relationships during the course of the Chapter 11 Cases under the governance, operational and related agreements entered into by those parties in connection with the formation of Superior (the company’s midstream joint venture with SP Investor), notwithstanding certain provisions triggered by the filing of the Chapter 11 Cases.

Liquidity, Unit Credit Facility and Debtor-in-Possession Credit Agreement

The company has incurred significant losses and was in a negative working capital position as of March 31, 2020. The company’s cash balance as of March 31, 2020 was $41.0 million, [including $23.9 million of which related to Superior], and effective January 17, 2020, the company's borrowing base under the Unit credit facility was $200.0 million, of which $124.0 million had been drawn as of March 31, 2020. The Unit credit facility has a scheduled maturity date of October 18, 2023 that, absent the filing of the Chapter 11 Cases, would accelerate to November 16, 2020 if, by that date, all the Notes are not repurchased, redeemed, or refinanced with indebtedness having a maturity date at least six months following October 18, 2023 (Credit Agreement Extension Condition). In addition, filing the Chapter 11 Cases resulted in events of default under the Unit credit agreement and accelerated the Debtors' obligations under the Unit credit agreement. As a result of these circumstances, the company's debt associated with the Unit credit agreement is reflected as a current liability in its consolidated balance sheet as of March 31, 2020 and December 31, 2019. In addition, on May 22, 2020, the RBL Lenders' remaining commitments under the Unit credit facility were terminated.

To facilitate the negotiation of proposals regarding the company's capital structure and the Chapter 11 restructuring, the company, UPC, UDC, BOKF, NA dba Bank of Oklahoma, and the RBL Lenders entered into a Standstill and Amendment Agreement on March 11, 2020 regarding the Unit credit facility, which delayed the scheduled borrowing base redetermination for the facility until the expiration of a standstill period and under which the RBL Lenders agreed not to exercise certain of their rights and remedies under the Unit credit facility. The standstill period was set to expire on April 15, 2020 and was ultimately extended to May 22, 2020. On May 22, 2020, the parties to the Standstill and Amendment Agreement agreed that the company would draw an additional $8.0 million under the Unit credit facility and that, immediately following that borrowing, the remaining commitments of the RBL Lenders under the Unit credit facility were terminated.

In order to provide liquidity to fund its operations and the Chapter 11 Cases, the company and the other Debtors entered into the DIP credit agreement. Borrowings under the DIP credit facility mature on the earliest of (i) September 22, 2020 (subject to a two-month extension to be approved by the DIP Lenders), (ii) the sale of all or substantially all of the assets of the Debtors under Section 363 of the Bankruptcy Code or otherwise, (iii) the effective date of a plan of reorganization or liquidation in the Chapter 11 Cases, (iv) the entry of an order by the Bankruptcy Court dismissing any of the Chapter 11 Cases or converting such Chapter 11 Cases to a case under Chapter 7 of the Bankruptcy Code, and (v) the date of termination of the DIP Lenders’ commitments and the acceleration of any outstanding extensions of credit, in each case, under the DIP credit agreement and subject to the Bankruptcy Court’s orders.

The DIP credit agreement contains events of default customary for debtor-in-possession financings, including events related to the Chapter 11 proceedings, the occurrence of which could cause the acceleration of the Debtors’ obligation to repay borrowings outstanding under the DIP credit facility. The Debtors’ obligations under the DIP credit agreement are secured by a security interest in, and lien on, substantially all present and after-acquired property (whether tangible, intangible, real, personal
12
or mixed) of the Debtors, including a superpriority priming lien on the property of the company and certain of its subsidiaries that secure their obligations under the existing Unit credit facility.

On the Debtors’ emergence from the Chapter 11 Cases and to the extent any claims under the DIP credit facility have not otherwise been repaid, each holder of an allowed claim under the DIP credit facility will receive its pro rata share of (i) revolving loans, term loans and letter-of-credit participations under a new credit facility with reorganized Unit (Exit Facility) and (ii) an equity fee under the Exit Facility equal to 5% of the new common shares of reorganized Unit (subject to dilution by shares reserved for issuance under a management incentive plan and upon exercise of the warrants described above). The Exit Facility will be provided by the lenders under the Unit credit facility and the DIP credit facility to reorganized Unit in an aggregate principal amount of at least $180.0 million, consisting of (i) a $140.0 million reserve-based lending revolving loan and (ii) a $40.0 million term loan, each consistent with and subject to the RSA.

Going Concern

Besides entering into the RSA and the DIP credit agreement, the company is undertaking several actions to alleviate the conditions that cause substantial doubt about our ability to continue as a going concern, including (i) minimizing capital expenditures, (ii) aggressively managing working capital, (iii) further reducing recurring operating expenses, and (iv) exploring potential business transactions. We currently expect that the company’s cash flows, cash on hand and any financing it can obtain through the DIP credit facility should provide sufficient liquidity for the company during the Chapter 11 Cases. However, the significant risks and uncertainties related to the company’s liquidity and Chapter 11 Cases raise substantial doubt about the company’s ability to continue as a going concern. The outcome of the Chapter 11 Cases is subject to significant uncertainty and depends upon factors outside of the company’s control, including actions of the Bankruptcy Court and the company’s creditors. There can be no assurance that the company will confirm and consummate the plan as contemplated by the RSA or complete an alternative plan of reorganization. The company has therefore concluded there continues to be substantial doubt about the company’s ability to continue as a going concern.

The condensed consolidated financial statements have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets, and satisfaction of liabilities and commitments in the normal course of business. The condensed consolidated financial statements include no adjustments that might result from the outcome of the going concern uncertainty. If the company cannot continue as a going concern, adjustments to the carrying values and classification of its assets and liabilities and the reported amounts of income and expenses could be required and could be material.

NOTE 3 – IMPAIRMENTS

We review and evaluate our long-lived assets, including intangible assets, for impairment when events or changes in circumstances indicate that the related carrying amount of such assets may not be recoverable, and changes to our estimates could affect our assessment of asset recoverability.

During the first quarter of 2020, global commodity prices declined due to factors that significantly impacted both demand and supply. As the COVID-19 pandemic spread, causing travel and other restrictions to be implemented globally, the demand for crude oil declined. Additionally, the supply shock late in the first quarter from certain major oil producing nations increasing production further contributed to the sharp drop in crude oil prices. The sharp drop in crude oil prices has resulted in prompt reactions from a number of domestic producers, including significantly reducing capital budgets and resultant drilling activity and shutting-in production.

The above circumstances are a triggering event that requires long-lived assets to be evaluated for impairment. At March 31, 2020, we determined that indicators of impairment existed for certain asset groups within our operating segments. For each asset group for which undiscounted future net cash flows could not recover the net book value, fair value was determined through use of discounted estimated cash flows to measure the impairment loss.

The estimated cash flows used to assess recoverability of our long-lived assets and measure fair value of our asset groups are derived from current business plans, which are developed using near-term price and volume projections reflective of the current environment and estimated drilling rig utilization. Other key assumptions include volume projections, operating costs, timing of incurring such costs and using an appropriate discount rate. These key assumptions could change in the future that could result in additional impairment expense recorded on these asset groups. We believe our estimates and models used to determine fair value are similar to what a market participant would use and are appropriate in the circumstances. However, given the rate of change impacting the energy industry, it is reasonably possible that our estimates and models used in our
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impairment testing may change in the near term resulting in potentially material impairment expense in the future interim periods.

The fair value measurement of our long-lived assets was based, in part, on significant inputs not observable in the market (as discussed above) and thus represents a Level 3 measurement. The significant unobservable inputs used include forecasted revenues, gross margins, discount rates, and terminal value exit multiples. The weighted average discount rate and exit multiples reflect management’s best estimate of inputs a market participant would utilize.

Oil and Natural Gas Properties

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

We determined that, due to the increased uncertainty that our undeveloped acreage would be fully developed, certain unproved oil and gas properties carrying values were not recoverable, resulting in impairment of $226.5 million in the first quarter of 2020, which had a corresponding increase to our depletion base and contributed to our full cost ceiling impairment recorded during the first quarter of 2020. We recorded a non-cash full cost ceiling test write-down of $267.8 million pre-tax in the first quarter of 2020 due to the reduction for the 12-month average commodity prices and the impairment of our unproved oil and gas properties described above. We had no non-cash ceiling test write-downs in the first quarter of 2019.

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

Contract Drilling

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

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

Mid-stream

We determined that the carrying value of certain long-lived asset groups in southern Kansas, and central Oklahoma where lower pricing is expected to impact drilling and production levels, are not recoverable and exceeded their estimated fair value. Based on the estimated fair value of the asset groups, we recorded non-cash impairment charges of $64.0 million. These charges are included within impairment charges in our Unaudited Condensed Consolidated Statement of Operations.

NOTE 4 – REVENUE FROM CONTRACTS WITH CUSTOMERS

Our revenue streams are reported under three segments: oil and natural gas, contract drilling, and mid-stream. This is how we disaggregate our revenue and how we report our segment revenue (as reflected in Note 17 – Industry Segment Information).
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Revenue from the oil and natural gas segment is from sales of our oil and natural gas production. Revenue from the contract drilling segment comes from contracting with upstream companies to drill an agreed-on number of wells or provide drilling rigs and services over an agreed-on period. Revenue from the mid-stream segment is derived from gathering, transporting, and processing natural gas and NGLs and selling those commodities. We sell the hydrocarbons (from our oil and natural gas and mid-stream segments) to other mid-stream and downstream oil and gas companies.

Oil and Natural Gas Revenues

Certain costs—as either a deduction from revenue or as an expense—are determined based on when control of the commodity is transferred to our customer, which would affect our total revenue recognized, but will not affect gross profit. For example, gathering, processing, and transportation costs included as part of the contract price with the customer on transfer of control of the commodity are included in the transaction price, while costs incurred while we are in control of the commodity represent operating costs.

Contract Drilling Revenues

We have evaluated the mobilization and de-mobilization charges due under our outstanding drilling contracts. The impact of those charges to the financial statements was immaterial. As of March 31, 2020, we had six contract drilling contracts with terms ranging from two months to almost two years.

Most of our drilling contracts have an original term of less than one year. The remaining performance obligations under the contracts with a longer duration are not material.

Mid-stream Contracts Revenues

Revenues are generated from fees earned for gas gathering and processing services provided to a customer. The typical revenue contracts used by this segment are gas gathering and processing agreements. These tables show the changes in our mid-stream contract asset and contract liability balances during the three months ended March 31, 2020:


March 31,
2020 		December 31,
2019 		Change
(In thousands)
Contract assets $ 11,395    $ 12,921    $ (1,526)  
Contract liabilities 6,343    7,061    (718)  
Contract assets (liabilities), net $ 5,052    $ 5,860    $ (808)  
Included below is the fixed revenue we will earn over the remaining term of the contracts and excludes all variable consideration to be earned with the associated contract.
Contract Remaining Term of Contract April - December
2020 		2021 2022 2023 and beyond Total Remaining Impact to Revenue
(In thousands)
Demand fee contracts 3-9 years $ (2,967)   $ (3,501)   $ 1,380    $ 36    $ (5,052)  

NOTE 5 – DIVESTITURES

Oil and Natural Gas

We sold $0.6 million of non-core oil and natural gas assets, net of related expenses, during the first three months of 2020 and 2019. These proceeds reduced the net book value of our full cost pool with no gain or loss recognized.
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Contract Drilling

In December 2019, we determined that $10.8 million of the assets held for sale would not be sold in the next twelve months and were moved back to long-lived assets. Seven drilling rigs and equipment were to be marketed for sale throughout the next twelve months and remained classified as assets held for sale. The fair value of those assets was $5.9 million. During the first quarter of 2020, due to market conditions, it was determined these assets would not be sold in the next twelve months and were moved back to long-lived assets. We no longer have assets that meet the criteria to be classified as held for sale.

NOTE 6 – LOSS PER SHARE

Information related to the calculation of loss per share attributable to Unit Corporation is as follows:
Loss
(Numerator) 		Weighted
Shares
(Denominator) 		Per-Share
Amount
  (In thousands except per share amounts)
For the three months ended March 31, 2020
Basic loss attributable to Unit Corporation per common share $ (770,494)   53,131    $ (14.50)  
Effect of dilutive stock options and restricted stock
—    —    —   
Diluted loss attributable to Unit Corporation per common share $ (770,494)   53,131    $ (14.50)  
For the three months ended March 31, 2019
Basic loss attributable to Unit Corporation per common share $ (3,504)   52,557    $ (0.07)  
Effect of dilutive stock options and restricted stock
—    —    —   
Diluted loss attributable to Unit Corporation per common share $ (3,504)   52,557    $ (0.07)  



The following table shows the number of stock options (and their average exercise price) excluded because their option exercise prices were greater than the average market price of our common stock:
Three Months Ended
  March 31,
  2020 2019
Stock options 42,000    56,000   
Average exercise price $ 48.56    $ 44.73   

NOTE 7 – ACCRUED LIABILITIES

Accrued liabilities consisted of:
March 31,
2020 		December 31,
2019
  (In thousands)
Interest payable $ 17,171    $ 6,562   
Employee costs 8,093    17,832   
Lease operating expenses 8,127    9,200   
Taxes 3,141    3,450   
Third-party credits 2,292    3,691   
Other 3,006    5,827   
Total accrued liabilities $ 41,830    $ 46,562   
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NOTE 8 – LONG-TERM DEBT AND OTHER LONG-TERM LIABILITIES

Long-Term Debt

As of the date indicated, our long-term debt consisted of the following:
March 31,
2020 		December 31,
2019
  (In thousands)
Current portion of long-term debt:
Unit credit agreement with an average interest rate of 2.9% and 4.0% at March 31, 2020 and December 31, 2019, respectively $ 124,000    $ 108,200   
6.625% senior subordinated notes due 2021 650,000    —   
Total principal amount 774,000    108,200   
Less: unamortized discount (801)   —   
Less: debt issuance costs, net (1,916)   —   
Total current portion of long-term debt 771,283    108,200   
Long-term debt:
Superior credit agreement with an average interest rate of 2.7% and 3.9% at March 31, 2020 and December 31, 2019, respectively 37,000    16,500   
6.625% senior subordinated notes due 2021 —    650,000   
Total principal amount 37,000    666,500   
Less: unamortized discount —    (971)  
Less: debt issuance costs, net —    (2,313)  
Total long-term debt $ 37,000    $ 663,216   

Unit Credit Agreement. Before the filing of the Chapter 11 Cases, the Unit credit facility had a scheduled maturity date of October 18, 2023 that would accelerate to November 16, 2020 if, by that date, all the Notes are not repurchased, redeemed, or refinanced with indebtedness having a maturity date at least six months following October 18, 2023 (Credit Agreement Extension Condition). The Debtors' filing of the Bankruptcy Petitions constituted an event of default that accelerated the Debtors' obligations under the Unit credit agreement and the indenture governing the Notes. Due to the Credit Agreement Extension Condition and the acceleration of debt obligations resulting from filing the Chapter 11 Cases, the company's debt associated with the Unit credit agreement is reflected as a current liability in its consolidated balance sheet as of March 31, 2020 and December 31, 2019. The classification as a current liability due to the Credit Agreement Extension Condition is based on the uncertainty regarding the company's ability to repay or refinance the Notes before November 16, 2020. In addition, on May 22, 2020, the RBL Lenders' remaining commitments under the Unit credit facility were terminated.

As of March 31, 2020, our elected commitment amount and borrowing base were both $200.0 million. We were charged a commitment fee of 0.375% on the amount available but not borrowed. That fee varied based on the amount borrowed as a percentage of the total borrowing base. Total amendment fees of $3.3 million in origination, agency, syndication, and other related fees are being amortized over the life of the Unit credit agreement. Under the Unit credit agreement, we pledged as collateral 80%of the proved developed producing (discounted as present worth at 8%) total value of our oil and gas properties. Under the mortgages covering such oil and gas properties, UPC also pledged as collateral certain items of its personal property.

On May 2, 2018, we entered into a Pledge Agreement with BOKF, NA (dba Bank of Oklahoma), as administrative agent to benefit the secured parties, under which we granted a security interest in the limited liability membership interests and other equity interests we own in Superior (which as of this report is 50% of the aggregate outstanding equity interests of Superior) as additional collateral for our obligations under the Unit credit agreement.

At our election, any part of the outstanding debt under the Unit credit agreement can be fixed at a London Interbank Offered Rate (LIBOR). LIBOR interest is computed as the LIBOR base for the term plus 1.50% to 2.50% depending on the level of debt as a percentage of the borrowing base and 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 Unit credit agreement but in no event less than LIBOR plus 1.00% plus a margin. The Unit credit agreement provides that if ICE Benchmark Administration no longer reports the LIBOR or Administrative Agent determines in good faith that the rate so reported no longer accurately reflects the rate available to Lender in the London Interbank Market or if such index no longer exists or accurately reflects the rate available to
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Administrative Agent in the London Interbank Market, Administrative Agent may select a replacement index. Interest is payable at the end of each month or at the end of each LIBOR contract and the principal may be repaid in whole or in part at any time, without a premium or penalty.

Filing the Bankruptcy Petitions on May 22, 2020 constituted an event of default that accelerated the company’s obligations under the Unit credit agreement, and the lenders’ rights of enforcement regarding the Unit credit agreement were automatically stayed because of the Chapter 11 Cases.

To facilitate negotiations of proposals regarding credit matters and the Chapter 11 restructuring, the company, UPC, UDC, BOKF, NA dba Bank of Oklahoma, and the RBL Lenders entered into a Standstill and Amendment Agreement on March 11, 2020 regarding the Unit credit facility, which delayed the scheduled borrowing base redetermination for the facility until the expiration of a standstill period and under which the RBL Lenders agreed not to exercise certain of their rights and remedies under the Unit credit facility. The standstill period was set to expire on April 15, 2020 and was subsequently extended from time to time until May 22, 2020. On May 22, 2020, the parties entered into a Fifth Amendment to Standstill and Amendment Agreement under which they agreed to the terms of an $8.0 million borrowing by the company under the Unit credit agreement and that, immediately following that borrowing, the remaining commitments of the RBL Lenders under the Unit credit facility were terminated. Subject to approval of the Plan, each lender under the Unit credit facility and the DIP credit facility will receive its pro rata share of revolving loans, term loans and letter-of-credit participations under the Exit Facility, in exchange for that lender’s allowed claims under the Unit credit facility or the DIP credit facility.

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 amounts borrowed under the Superior credit agreement bear annual interest at a rate, at Superior’s option, equal to (a) LIBOR plus the applicable margin of 2.00% to 3.25% or (b) the alternate base rate (greater of (i) the federal funds rate plus 0.5%, (ii) the prime rate, and (iii) third day LIBOR plus 1.00%) plus the applicable margin of 1.00% to 2.25%. The obligations under the Superior credit agreement are secured by mortgage liens on certain of Superior’s processing plants and gathering systems. The Superior credit agreement provides that if ICE Benchmark Administration no longer reports the LIBOR or Administrative Agent determines in good faith that the rate so reported no longer accurately reflects the rate available to Lender in the London Interbank Market or if such index no longer exists or accurately reflects the rate available to Administrative Agent in the London Interbank Market, Administrative Agent may select a replacement index.

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

The Superior credit agreement requires that Superior maintain a Consolidated EBITDA to interest expense ratio for the most-recently ended rolling four quarters of at least 2.50 to 1.00, and a funded debt to Consolidated EBITDA ratio of not greater than 4.00 to 1.00. 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 March 31, 2020, Superior complied with these covenants.
 
The borrowings under the Superior credit agreement will fund capital expenditures and acquisitions, provide general working capital, and for letters of credit for Superior.

Superior's credit agreement is not guaranteed by Unit. Superior and its subsidiaries are not parties to the RSA and are not Debtors in the Chapter 11 Cases.

6.625% Senior Subordinated Notes. As of March 31, 2020, we had an aggregate principal amount of $650.0 million in 6.625% senior subordinated notes (Notes) outstanding. Interest on the Notes was payable semi-annually (in arrears) on May 15 and November 15 of each year. The Notes were scheduled to mature on May 15, 2021. In issuing the Notes, we incurred fees of $14.7 million that are being amortized as debt issuance cost until maturity.

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 (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.
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Unit, as the parent company, has no significant independent assets or operations. The guarantees by the Guarantors of the Notes (registered under registration statements) are full and unconditional, joint and several, subject to certain automatic customary releases, are subject to certain restrictions on the sale, disposition, or transfer of the capital stock or substantially all of the assets of a subsidiary guarantor, and other conditions and terms set out in the 2011 Indenture. Effective April 3, 2018, Superior is no longer a Guarantor of the Notes. Excluding Superior, any of our other subsidiaries that are not Guarantors are minor. There are no significant restrictions on our ability to receive funds from any subsidiary through dividends, loans, advances, or otherwise.

The company elected not to make the approximate $21.5 million semi-annual interest payment due on the Notes on May 15, 2020. The company was entitled to a 30-day grace period after the interest payment date before an event of default would occur because of such non-payment.

Filing of the Bankruptcy Petitions on May 22, 2020 constituted an event of default that accelerated the company’s obligations under the Notes. However, under the Bankruptcy Code, holders of the Notes are stayed from taking any action against the company or the other Debtors because of the default. Subject to confirmation of the Plan, each holder of the Notes will receive its pro rata share of new common shares of reorganized Unit based on equity allocations at each of Unit, UDC and UPC in exchange for the holder’s allowed Notes claim.

DIP Credit Agreement. As contemplated by the RSA, the company and the other Debtors entered into the DIP credit agreement under which the DIP Lenders agreed to provide the company with the $36.0 million multiple-draw loan facility, or the DIP credit facility. The Bankruptcy Court entered an interim order on May 26, 2020 approving the DIP credit facility, permitting the Debtors to borrow up to $18.0 million on an interim basis. On June 19, 2020, the Bankruptcy court entered a final order approving the DIP credit facility. For further information about the DIP credit agreement, please see Note 2 – Chapter 11 Proceedings, Liquidity, and Ability to Continue as a Going Concern.

Other Long-Term Liabilities

Other long-term liabilities consisted of the following:
March 31,
2020 		December 31,
2019
  (In thousands)
Asset retirement obligation (ARO) liability $ 63,819    $ 66,627   
Workers’ compensation 11,178    11,510   
Finance lease obligations 6,354    7,379   
Contract liability 6,343    7,061   
Separation benefit plans 9,719    10,122   
Deferred compensation plan 5,303    6,180   
Gas balancing liability 3,838    3,838   
106,554    112,717   
Less current portion 18,317    17,376   
Total other long-term liabilities $ 88,237    $ 95,341   

Estimated annual principal payments under the terms of our long-term debt and other long-term liabilities during the five successive twelve-month periods beginning April 1, 2020 (and through 2024) are $792.3 million, $5.1 million, $3.5 million, $39.5 million, and $2.4 million, respectively. The Debtors' filing of the Bankruptcy Petitions constituted an event of default that accelerated the Debtors' obligations under the Unit credit agreement and the indenture governing the Notes. The debt associated with both are reflected as current liabilities as of March 31, 2020.

NOTE 9 – ASSET RETIREMENT OBLIGATIONS

We are required to record the estimated fair value of the liabilities relating to the future retirement of our long-lived assets. Our oil and natural gas wells are plugged and abandoned when the oil and natural gas reserves in those wells are depleted or the wells are no longer able to produce. The plugging and abandonment liability for a well is recorded in the period in which the obligation is incurred (at the time the well is drilled or acquired). None of our assets are restricted for purposes of settling these AROs. All our AROs relate to the plugging costs associated with our oil and gas wells.
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The following table shows certain information about our estimated AROs for the periods indicated:
Three Months Ended
  March 31,
  2020 2019
  (In thousands)
ARO liability, January 1: $ 66,627    $ 64,208   
Accretion of discount 596    562   
Liability incurred 314    3,116   
Liability settled (319)   (1,636)  
Liability sold (15)   (549)  
Revision of estimates (1)
(3,384)   2,139   
ARO liability, March 31: 63,819    67,840   
Less current portion 1,470    1,742   
Total long-term ARO $ 62,349    $ 66,098   
_______________________ 
1.Plugging liability estimates were revised in both 2020 and 2019 for updates in the cost of services used to plug wells over the preceding year. We had various upward and downward adjustments.

NOTE 10 – NEW ACCOUNTING PRONOUNCEMENTS

Reference Rate Reform (Topic 848)—Facilitation of the Effects of Reference Rate Reform on Financial Reporting. The FASB issued 2020-04 which provides optional expedients and exceptions for applying generally accepted accounting principles to contract modifications, subject to meeting certain criteria, that reference LIBOR or another reference rate expected to be discontinued. The ASU is intended to help stakeholders during the global market-wide reference rate transition period. The amendment will be in effect for a limited time through December 31, 2022.

Adopted Standards

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

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

NOTE 11 – STOCK-BASED COMPENSATION

The Company has a significant amount of indebtedness that is senior to its existing common stock in its capital structure. As a result, the Company believes that it is highly likely that its existing common shares, including shares of its restricted stock, will be cancelled in its Chapter 11 proceedings and entitled to no recovery.

For restricted stock awards and stock options, we had:
Three Months Ended
March 31,
2020 2019
(In millions)
Recognized stock compensation expense $ 2.5    $ 3.8   
Capitalized stock compensation cost for our oil and natural gas properties
—    0.6   
Tax benefit on stock-based compensation 0.6    0.9   
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The remaining unrecognized compensation cost related to unvested awards at March 31, 2020 is approximately $8.2 million. The weighted average period over which this cost will be recognized is 1.3 of a year.

Our Second Amended and Restated Unit Corporation Stock and Incentive Compensation Plan effective May 6, 2015 (the amended plan) allows us to grant stock-based and cash-based compensation to our employees (including employees of subsidiaries) and to non-employee directors. There are 7,230,000 shares of the company's common stock authorized for issuance to eligible participants under the amended plan with 2,000,000 shares being the maximum number of shares that can be issued as "incentive stock options."

We did not grant any stock options during either of the three month periods ending March 31, 2020 or 2019. We did not grant any restricted stock awards during the three-month periods ending March 31, 2020. This table shows the fair value of restricted stock awards granted to employees and non-employee directors during the three months ended March 31, 2019:

Three Months Ended
March 31, 2019
  Time
Vested 		Performance Vested
Shares granted:
Employees 925,673    424,070   
Non-employee directors —    —   
925,673    424,070   
Estimated fair value (in millions): (1)
Employees $ 14.6    $ 7.1   
Non-employee directors —    —   
$ 14.6    $ 7.1   
Percentage of shares granted expected to be distributed:
Employees 95  % 64  %
Non-employee directors N/A    N/A   
_______________________
1.The performance shares represent 100% of the grant date fair value. (We recognize the grant date fair value minus estimated forfeitures.)

The time vested restricted stock awards granted during the first three months of 2019 are being recognized over a three-year vesting period. During the first quarter of 2019, two performance vested restricted stock awards were granted to certain executive officers. The first cliff vests three years from the grant date based on the company's achievement of certain stock performance measures (TSR) at the end of the term and will range from 0% to 200% of the restricted shares granted as performance shares. The second vests, one-third each year, over a three-year vesting period subject to the company's achievement of cash flow to total assets (CFTA) performance measurement each year and will range from 0% to 200%. Based on a probability assessment of the selected TSR performance criteria at March 31, 2020, the participants are estimated to receive 2% of the 2019 and 29% of the 2018 performance-based shares. We expense the CFTA performance award at target or 100%.

NOTE 12 – DERIVATIVES

Commodity Derivatives

We have signed various types of derivative transactions covering some of our projected natural gas and oil production. These transactions should reduce our exposure to market price volatility by setting the price(s) we will receive for that production. Our decisions on the price(s), type, and quantity of our production subject to a derivative contract are based, in part, on our view of current and future market conditions. As of March 31, 2020, these hedges made up our derivative transactions:

•Basis/Differential Swaps. We receive or pay the NYMEX settlement value plus or minus a fixed delivery point price for the commodity and pay or receive the published index price at the specified delivery point. We use basis/differential swaps to hedge the price risk between NYMEX and its physical delivery points.

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•Three-way collars. A three-way collar contains a fixed floor price (long put), fixed subfloor price (short put), and a fixed ceiling price (short call). If the market price exceeds the ceiling strike price, we receive the ceiling strike price and pay the market price. If the market price is between the ceiling and the floor strike price, no payments are due from either party. If the market price is below the floor price but above the subfloor price, we receive the floor strike price and pay the market price. If the market price is below the subfloor price, we receive the market price plus the difference between the floor and subfloor strike prices and pay the market price.

We have documented policies and procedures to monitor and control the use of derivative transactions. We do not engage in derivative transactions not otherwise tied to our projected production. Any changes in the fair value of our derivative transactions before maturity (i.e., temporary fluctuations in value) are reported in gain (loss) on derivatives in our Unaudited Condensed Consolidated Statements of Operations. As a result of the commencement of the Chapter 11 Cases, the Debtors' ability to enter into derivative transactions is limited.

At March 31, 2020, these derivatives were outstanding:
Term Commodity Contracted Volume Weighted Average 
Fixed Price 		Contracted Market
Apr'20 - Dec'20 Natural gas - basis swap 30,000 MMBtu/day $(0.275)   NGPL TEXOK
Apr'20 - Dec'20 Natural gas - basis swap 20,000 MMBtu/day $(0.455)   PEPL
Jan'21 - Dec'21 Natural gas - basis swap 30,000 MMBtu/day $(0.215)   NGPL TEXOK
Apr'20 - Dec'20 Natural gas - three-way collar 30,000 MMBtu/day $2.50 - $2.20 - $2.80    IF - NYMEX (HH)

The following tables present the fair values and locations of the derivative transactions recorded in our Unaudited Condensed Consolidated Balance Sheets:
    Derivative Assets
    Fair Value
  Balance Sheet Location March 31,
2020 		December 31,
2019
    (In thousands)
Commodity derivatives:
Current Current derivative asset $ 661    $ 633   
Long-term Non-current derivative asset —    —   
Total derivative assets $ 661    $ 633   

    Derivative Liabilities
    Fair Value
  Balance Sheet Location March 31,
2020 		December 31,
2019
    (In thousands)
Commodity derivatives:
Current Current derivative liability $ —    $ —   
Long-term Non-current derivative liability 123    27   
Total derivative liabilities $ 123    $ 27   

All our counterparties are subject to master netting arrangements. If we have a legal right of set-off, we net the value of the derivative transactions we have with the same counterparty in our Unaudited Condensed Consolidated Balance Sheets.

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Following is the effect of derivative instruments on the Unaudited Condensed Consolidated Statements of Operations for the periods indicated:
Three Months Ended
March 31,
2020 2019
  (In thousands)
Gain (loss) on derivatives:
Gain (loss) on derivatives, included are amounts settled during the period of $551 and $2,656, respectively $ 483    $ (6,932)  
$ 483    $ (6,932)  

The commencement of the Chapter 11 Cases constituted a termination event with respect of the company's derivative instruments, which permits the counterparties to such derivative instruments to terminated their outstanding hedges. Such terminations are not stayed under the Bankruptcy Code.

NOTE 13 – FAIR VALUE MEASUREMENTS

Fair value is defined as the amount that would be received from the sale of an asset or paid for transferring a liability in an orderly transaction between market participants (in either case, an exit price). To estimate an exit price, a three-level hierarchy is used prioritizing the valuation techniques used to measure fair value into three levels with the highest priority given to Level 1 and the lowest priority given to Level 3. The levels are summarized as follows:

•Level 1—unadjusted quoted prices in active markets for identical assets and liabilities.

•Level 2—significant observable pricing inputs other than quoted prices included within level 1 either directly or indirectly observable as of the reporting date. Essentially, inputs (variables used in the pricing models) that are derived principally from or corroborated by observable market data.

•Level 3—generally unobservable inputs developed based on the best information available and may include our own internal data.

The inputs available to us determine the valuation technique we use to measure the fair values of our financial instruments.

The following tables set forth our recurring fair value measurements:
  March 31, 2020
  Level 2 Level 3 Effect
of Netting 		Net Amounts Presented
 
Financial assets (liabilities):
Commodity derivatives:
Assets $ 189    $ 948    $ (476)   $ 661   
Liabilities (599)   —    476    (123)  
Total commodity derivatives $ (410)   $ 948    $ —    $ 538   

  December 31, 2019
  Level 2 Level 3 Effect
of Netting 		Net Amounts Presented
 
Financial assets (liabilities):
Commodity derivatives:
Assets $ 177    $ 1,204    $ (748)   $ 633   
Liabilities (775)   —    748    (27)  
Total commodity derivatives $ (598)   1,204    —    606   
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All our counterparties are subject to master netting arrangements. If a legal right of set-off exists, we net the value of the derivative transactions we have with the same counterparty. We are not required to post cash collateral with our counterparties and no collateral has been posted as of March 31, 2020.

We used the following methods and assumptions to estimate the fair values of the assets and liabilities in the table above. There were no transfers between Level 2 and Level 3 financial assets (liabilities).

Level 2 Fair Value Measurements

Commodity Derivatives. We measure the fair values of our crude oil and natural gas swaps using estimated internal discounted cash flow calculations based on the NYMEX futures index.

Level 3 Fair Value Measurements

Commodity Derivatives. The fair values of our natural gas and crude oil collars and three-way collars are estimated using internal discounted cash flow calculations based on forward price curves, quotes obtained from brokers for contracts with similar terms, or quotes obtained from counterparties to the agreements.

The following table is a reconciliation of our Level 3 fair value measurements:

  Net Derivatives
Three Months Ended
March 31,
  2020 2019
  (In thousands)
Beginning of period $ 1,204    $ 10,630   
Total gains or losses (realized and unrealized):
Included in earnings (1)
563    (5,434)  
Settlements (819)   (2,116)  
End of period $ 948    $ 3,080   
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 $ (256)   $ (7,550)  
_______________________
1.Commodity derivatives are reported in the Unaudited Condensed Consolidated Statements of Operations in gain (loss) on derivatives.

The following table provides quantitative information about our Level 3 unobservable inputs at March 31, 2020:
Commodity (1)
Fair Value Valuation Technique Unobservable Input Range
  (In thousands)      
Natural gas three-way collar $ 948    Discounted cash flow Forward commodity price curve $0.00 -$0.86
 _______________________
1.The commodity contracts detailed in this category include non-exchange-traded natural gas 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.

Our valuation at March 31, 2020 reflected that the risk of non-performance was immaterial.

Fair Value of Other Financial Instruments

This disclosure of the estimated fair value of financial instruments is made under accounting guidance for financial instruments. We have determined the estimated fair values by using market information and certain valuation methodologies. Considerable judgment is required in interpreting market data to develop the estimates of fair value. Using different market assumptions or valuation methodologies may have a material effect on our estimated fair value amounts.

At March 31, 2020, the carrying values on the Unaudited Condensed Consolidated Balance Sheets for cash and cash equivalents (composed of bank and money market accounts - classified as Level 1), accounts receivable, accounts payable, other current assets, and current liabilities approximate their fair value because of their short-term nature.
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The carrying amounts of long-term debt associated with the Notes, net of unamortized discount and debt issuance costs, reported in the Unaudited Condensed Consolidated Balance Sheets as of March 31, 2020 and December 31, 2019 were $647.3 million and $646.7 million, respectively. Filing the Bankruptcy Petitions on May 22, 2020 constituted an event of default that accelerated the company’s obligations under the Notes and they are classified as current in the Unaudited Condensed Balance Sheet as of March 31, 2020. The estimated fair value of the Notes using quoted market prices at March 31, 2020 and December 31, 2019 was $65.9 million and $357.5 million, respectively. The Notes would be classified as Level 2.

Fair Value of Non-Financial Instruments

The initial measurement of AROs at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with property, plant, and equipment. Significant Level 3 inputs used in the calculation of AROs include plugging costs and remaining reserve lives. A reconciliation of our AROs is presented in Note 9 – Asset Retirement Obligations.

NOTE 14 – LEASES

Operating Leases under ASC 840

We lease office space or yards in Edmond and Oklahoma City, Oklahoma; Houston, Texas; Englewood, Colorado; and Pinedale, Wyoming under the terms of operating leases expiring through December 2021. We own our corporate headquarters in Tulsa, Oklahoma. We also have several compressor rentals, equipment leases, and lease space on short-term commitments to stack excess drilling rig equipment and production inventory.

Operating Leases under ASC 842

Adoption of Accounting Standards Codification (“ASC”) Topic 842, “Leases." We adopted Topic 842 on January 1, 2019, using the modified retrospective method and the optional transition method to record the adoption impact through a cumulative adjustment to equity. Results for reporting periods beginning after January 1, 2019, are presented under Topic 842, while prior periods are not adjusted and continue to be reported under the accounting standards in effect for those periods.

We determine whether a contract is or contains a lease at inception of the contract based on whether an identified asset exists and whether we may obtain substantially all the benefit of the assets and to control its use over the full term of the agreement. When available, we use the rate implicit in the lease to discount lease payments to present value; however, most of our leases do not provide a readily determinable implicit rate. Therefore, we must estimate our incremental borrowing rate considering both the revolving credit rates and a credit notching approach to discount the lease payments based on information available at lease commencement. There are no material residual value guarantees and no restrictions or covenants in our lease agreements. Certain of our leases include provisions for variable payments. These variable payments are typically determined based on a measure of throughput or actual days or another measure of usage and are not included in the calculation of lease liabilities and right-of-use assets.

Related to our oil and natural gas segment, our short-term lease costs include those that are recognized in profit or loss during the period and those that are capitalized as part of the cost of another asset under other U.S. GAAP. As the costs related to our drilling and production activities are reflected at our net ownership consistent with the principals of proportional consolidation, and lease commitments are generally considered gross as the operator, the costs may not reasonably reflect the company’s short-term lease commitments. As of March 31, 2020, we had an average working interest of 95% in our operated properties.

Practical Expedients and Policies Elected. We elected the hindsight expedient, which allows us to use hindsight in assessing lease term; the package of practical expedients permitted under the guidance, which allowed us to carry forward the historical lease classification; and the land easement expedient, which allowed us to apply the guidance prospectively at adoption for land easements on existing agreements. We applied the short-term policy election, which allowed us to exclude from recognition on the balance sheet leases with an initial term of 12 months or less. We considered quantitative and qualitative factors when determining the application of the practical expedient that allowed us not to separate lease and non-lease components and are accounting for the agreements as a single lease component.

We routinely enter into related party agreements between our three segments. These agreements have been evaluated under the guidance of ASC 842. Routinely, our oil and natural gas segment contracts its drilling equipment from our drilling segment.
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We have determined that the contracting of our drilling segment's drilling rigs will be accounted for under ASC 606 as the service has been deemed the predominate component of the contract per the lessor practical expedient.

Adoption. Adoption of Topic 842 resulted in new operating lease assets and lease liabilities on our Unaudited Condensed Consolidated Balance Sheet of $3.7 million and $3.5 million, respectively, as of January 1, 2019, which represents non-cash operating activity. The immaterial difference between the lease assets and lease liabilities was recorded as an adjustment to the beginning balance of retained earnings, which represents the cumulative impact of adopting the standard. Our accounting for finance leases remained substantially unchanged.

Leases. We lease certain office space, land and equipment, including pipeline equipment and office equipment. Our lease payments are generally straight-line and exercising lease renewal options, which vary in term, is at our sole discretion. We include renewal periods in our lease term if we are reasonably certain to exercise renewal options. Our lease agreements do not include options to purchase the leased property.

The following table shows supplemental cash flow information related to leases for the three months of March 31, 2020 and 2019:
March 31,
2020 		March 31,
2019
(In thousands)
Cash paid for amounts in the measurement of lease liabilities:
Operating cash flows for operating leases $ 1,333    577
Financing cash flows for finance leases 1,025    985
Lease liabilities recognized in exchange for new operating lease right of use assets —    5

The following table shows information about our lease assets and liabilities in our Unaudited Condensed Consolidated Balance Sheet:
Classification on the Consolidated Balance Sheet March 31,
2020 		December 31,
2019
(In thousands)
Assets
Operating right of use assets Right of use assets $ 6,937    $ 5,673   
Finance right of use assets Property, plant, and equipment, net 16,926    17,396   
Total right of use assets $ 23,863    $ 23,069   
Liabilities
Current liabilities:
Operating lease liabilities Current operating lease liabilities $ 4,128    $ 3,430   
Finance lease liabilities Current portion of other long-term liabilities 5,852    4,164   
Non-current liabilities:
Operating lease liabilities Operating lease liabilities 2,639    2,071   
Finance lease liabilities Other long-term liabilities 502    3,215   
Total lease liabilities $ 13,121    $ 12,880   

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The following table shows certain information related to the lease costs for our finance and operating leases for the three months ended March 31, 2020:
March 31,
2020 		March 31,
2019
(In thousands)
Components of total lease cost:
Amortization of finance leased assets $ 1,025    $ 985   
Interest on finance lease liabilities 70    111   
Operating lease cost 1,244    598   
Short-term lease cost (1)
3,991    9,974   
Variable lease cost 82    106   
Total lease cost $ 6,412    $ 11,774   
_______________________
1.Short-term lease cost includes amounts capitalized related to our oil and natural gas segment of $1.0 million and $5.7 million for the first three months of 2020 and 2019, respectively.

The following table shows certain information related to the weighted average remaining lease terms and the weighted average discount rates for our operating and finance leases:
Weighted Average Remaining Lease Term
Weighted Average Discount
Rate (1)
(In years)
Operating leases 1.9 6.31%
Finance leases 1.4 4.00%
_______________________
1.Our weighted average discount rates represent the rate implicit in the lease or our incremental borrowing rate for a term equal to the remaining term of the lease.

The following table sets forth the maturity of our operating lease liabilities as of March 31, 2020:
Amount
(In thousands)
Ending April 1,
2021 $ 4,425   
2022 2,356   
2023 296   
2024 29   
2025 12   
2026 and beyond 72   
Total future payments 7,190   
Less: Interest 423   
Present value of future minimum operating lease payments 6,767   
Less: Current portion 4,128   
Total long-term operating lease payments $ 2,639   

Finance Leases

In 2014, Superior entered into finance lease agreements for 20 compressors with initial terms of seven years. The underlying assets are included in gas gathering and processing equipment. The $5.9 million current portion of the finance lease obligations is included in current portion of other long-term liabilities and the non-current portion of $0.5 million is included in other long-term liabilities in the Unaudited Condensed Consolidated Balance Sheets as of March 31, 2020. These finance leases are discounted using annual rates of 4.00%. Total maintenance and interest remaining related to these leases are $1.9 million
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and $0.2 million, respectively, at March 31, 2020. Annual payments, net of maintenance and interest, average $4.5 million annually through 2021. At the end of the term, Superior has the option to purchase the assets at 10% of their then fair market value.

The following table sets forth the maturity of our finance lease liabilities as of March 31, 2020:
Amount
Ending April 1, (In thousands)
2021 $ 7,841   
2022 579   
Total future payments 8,420   
Less payments related to:
Maintenance 1,884   
Interest 182   
Present value of future minimum finance lease payments 6,354   
Less: Current portion 5,852   
Total long-term finance lease payments $ 502   

NOTE 15 – COMMITMENTS AND CONTINGENCIES

On May 22, 2020, the Debtors filed the Bankruptcy Petitions seeking relief under the Bankruptcy Code. The commencement of the Chapter 11 Cases automatically stayed all of the proceedings and actions against the Debtors (other than certain regulatory enforcement matters). For further information on the Chapter 11 Cases, please see Note 2 – Chapter 11 Proceedings, Liquidity, and Ability to Continue as a Going Concern.

We manage our exposure to environmental liabilities on properties to be acquired by identifying existing problems and assessing the potential liability. We also conduct periodic reviews, on a company-wide basis, to identify changes in our environmental risk profile. These reviews evaluate whether there is a probable liability, its amount, and the likelihood that the liability will be incurred. Any potential liability is determined by considering, among other matters, incremental direct costs of any likely remediation and the proportionate cost of employees expected to devote significant time directly to any possible remediation effort. As it relates to evaluations of purchased properties, depending on the extent of an identified environmental problem, we may exclude a property from the acquisition, require the seller to remediate the property to our satisfaction, or agree to assume liability for the remediation of the property.

We have not historically experienced any environmental liability while being a contract driller since the greatest portion of that risk is borne by the operator. Any liabilities we have incurred have been small and were resolved while the drilling rig was on the location. Those costs were in the direct cost of drilling the well.

During the second quarter of 2018, as part of the Superior transaction, we entered into a contractual obligation that commits us to spend $150.0 million to drill wells in the Granite Wash/Buffalo Wallow area over three years starting January 1, 2019. This amount is included in our future drilling plans. For each dollar of the $150.0 million we do not spend (over the three-year period), we would forgo receiving $0.58 of future distributions from our 50% ownership interest in our consolidated mid-stream subsidiary. At March 31, 2020, if we elected not to drill or spend any additional money in the designated area before December 31, 2021, the maximum amount we could forgo from distributions would be $72.7 million. We have no plans to drill in 2020. Total spent towards the $150.0 million as of March 31, 2020 was $24.7 million.

We have firm transportation commitments to transport our natural gas from various systems for approximately $0.6 million over the next twelve months and $0.6 million for the two years thereafter.

NOTE 16 – VARIABLE INTEREST ENTITY ARRANGEMENTS

On April 3, 2018 we sold 50% of the ownership interest in Superior. The 50% interest in Superior we sold was acquired by SP Investor Holdings, LLC, a holding company jointly owned by OPTrust and funds managed and/or advised by Partners Group, a global private markets investment manager. Superior will be governed and managed under the Amended and Restated Limited Liability Company Agreement and a Management Services Agreement (MSA). The MSA is between our affiliate, SPC Midstream Operating, L.L.C. (Operator) and Superior. The Operator is a wholly owned subsidiary of Unit Corporation. Under the guidance in ASC 810, Consolidation, we have determined that Superior is a VIE. The two variable interests applicable to
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Unit include the 50% equity investment in Superior and the MSA. The MSA gives us the power to direct the activities that most significantly affect Superior's operating performance. The MSA is a separate variable interest. Unit through the MSA has the power to direct Superior’s most significant activities; reciprocally the equity investors lack the power to direct the activities that most affect the entity’s economic performance. Because of this, Unit is considered the primary beneficiary. There have been no changes to the primary beneficiary during the quarter ended March 31, 2020.

As the primary beneficiary of this VIE, we consolidate in our financial statements the financial position, results of operations, and cash flows of this VIE, and all intercompany balances and transactions between us and the VIE are eliminated in our consolidated financial statements. Cash distributions of income, net of agreed on expenses, and estimated expenses are allocated to the equity owners as specified in the relevant agreements.

On the sale or liquidation of Superior, distributions would occur in the order and priority specified in the relevant agreements.

As the Operator, we provide services, like operations and maintenance support, accounting, legal, and human resources to Superior for a monthly service fee of $260,560. Superior's creditors have no recourse to our general credit. Superior's credit agreement is not guaranteed by Unit. The obligations under Superior's credit agreement are secured by, among other things, mortgage liens on certain of Superior’s processing plants and gathering systems.

The carrying value of Superior's assets and liabilities, after eliminations of any intercompany transactions and balances, in the consolidated balance sheets were as follows:
March 31,
2020 		December 31,
2019
  (In thousands)
Current assets:
Cash and cash equivalents $ 23,900    $ —   
Accounts receivable    15,305    21,073   
Prepaid expenses and other 7,473    7,686   
Total current assets 46,678    28,759   
Property and equipment:
Gas gathering and processing equipment 829,600    824,699   
Transportation equipment 3,397    3,390   
832,997    828,089   
Less accumulated depreciation, depletion, amortization, and impairment 483,205    407,144   
Net property and equipment 349,792    420,945   
Right of use asset 3,227    3,948   
Other assets 7,651    9,442   
Total assets $ 407,348    $ 463,094   
Current liabilities:
Accounts payable $ 12,013    $ 18,511   
Accrued liabilities 3,064    4,198   
Current operating lease liability 1,961    2,407   
Current portion of other long-term liabilities 8,765    7,060   
Total current liabilities 25,803    32,176   
Long-term debt 37,000    16,500   
Operating lease liability 1,131    1,404   
Other long-term liabilities 4,782    8,126   
Total liabilities $ 68,716    $ 58,206   

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NOTE 17 – INDUSTRY SEGMENT INFORMATION

We have three main business segments offering different products and services within the energy industry:
 
•Oil and natural gas,
•Contract drilling, and
•Mid-stream

Our oil and natural gas segment is engaged in the acquisition, development, and production of oil, NGLs, and natural gas properties. The contract drilling segment is engaged in the land contract drilling of oil and natural gas wells and the mid-stream segment is engaged in the buying, selling, gathering, processing, and treating of natural gas and NGLs.

We evaluate each segment’s performance based on its operating income, which is defined as operating revenues less operating expenses and depreciation, depletion, amortization, and impairment. We have no oil and natural gas production outside the United States.

The following tables provide certain information about the operations of each of our segments:

Three Months Ended March 31, 2020
  Oil and Natural Gas Contract Drilling Mid-stream Corporate and Other Eliminations Total Consolidated
  (In thousands)
Revenues: (1)
Oil and natural gas $ 48,524    $ —    $ —    $ —    $ (2)   $ 48,522   
Contract drilling —    36,632    —    —    —    36,632   
Gas gathering and processing —    —    42,680    —    (5,458)   37,222   
Total revenues 48,524    36,632    42,680    —    (5,460)   122,376   
Expenses:
Operating costs:
Oil and natural gas 31,415    —    —    —    (752)   30,663   
Contract drilling —    25,449    —    —    —    25,449   
Gas gathering and processing —    —    32,319    —    (4,708)   27,611   
Total operating costs
31,415    25,449    32,319    —    (5,460)   83,723   
Depreciation, depletion, and amortization
36,728    11,745    12,273    871    —    61,617   
Impairments 267,836    410,126    63,962    —    —    741,924   
Total expenses 335,979    447,320    108,554    871    (5,460)   887,264   
Loss on abandonment of assets 17,554    —    —    —    —    17,554   
General and administrative
—    —    —    11,553    —    11,553   
(Gain) loss on disposition of assets (13)   409    (6)   —    —    390   
Loss from operations (304,996)   (411,097)   (65,868)   (12,424)   —    (794,385)  
Gain on derivatives —    —    —    483    —    483   
Interest, net —    —    (518)   (12,739)   —    (13,257)  
Other 18    17    18    7    —    60   
Loss before income taxes $ (304,978)   $ (411,080)   $ (66,368)   $ (24,673)   $ —    $ (807,099)  
_______________________
1.The revenues for oil and natural gas occur at a point in time. The revenues for contract drilling and gas gathering and processing occur over time.

30
Three Months Ended March 31, 2019
  Oil and Natural Gas Contract Drilling Mid-stream Corporate and Other Eliminations Total Consolidated
  (In thousands)
Revenues: (1)
Oil and natural gas $ 86,095    $ —    $ —    $ —    $ —    $ 86,095   
Contract drilling —    58,199    —    —    (7,044)   51,155   
Gas gathering and processing —    —    70,509    —    (18,068)   52,441   
Total revenues 86,095    58,199    70,509    —    (25,112)   189,691   
Expenses:
Operating costs:
Oil and natural gas 34,008    —    —    —    (1,294)   32,714   
Contract drilling —    37,385    —    —    (5,984)   31,401   
Gas gathering and processing —    —    56,129    —    (16,774)   39,355   
Total operating costs
34,008    37,385    56,129    —    (24,052)   103,470   
Depreciation, depletion, and amortization
35,767    12,699    11,726    1,934    —    62,126   
Total expenses 69,775    50,084    67,855    1,934    (24,052)   165,596   
General and administrative
—    —    —    9,741    —    9,741   
(Gain) loss on disposition of assets (79)   1,746    (42)   (10)   —    1,615   
Income (loss) from operations 16,399    6,369    2,696    (11,665)   (1,060)   12,739   
Loss on derivatives —    —    —    (6,932)   —    (6,932)  
Interest, net —    —    (336)   (8,202)   —    (8,538)  
Other —    —    —    5    —    5   
Income (loss) before income taxes $ 16,399    $ 6,369    $ 2,360    $ (26,794)   (1,060)   $ (2,726)  
_______________________
1.The revenues for oil and natural gas occur at a point in time. The revenues for contract drilling and gas gathering and processing occur over time.

NOTE 18 – SUPPLEMENTAL CONDENSED CONSOLIDATING FINANCIAL INFORMATION

We have no significant assets or operations other than our investments in our subsidiaries. Our wholly owned subsidiaries are the guarantors of our Notes. On April 3, 2018, we sold 50% of the ownership interest in our mid-stream segment, Superior and that company and its subsidiaries are no longer guarantors of the 2021 Notes. Instead of providing separate financial statements for each subsidiary issuer and guarantor, we have included the unaudited condensed consolidating financial statements based on Rule 3-10 of the SEC's Regulation S-X.

For the following footnote:

•we are called "Parent",
•the direct subsidiaries are 100% owned by the Parent and the guarantee is full and unconditional and joint and several and called "Combined Guarantor Subsidiaries", and
•Superior and its subsidiaries and the Operator are called "Non-Guarantor Subsidiaries."

The following unaudited supplemental condensed consolidating financial information reflects the Parent's separate accounts, the combined accounts of the Combined Guarantor Subsidiaries', the combined accounts of the Non-Guarantor Subsidiaries', the combined consolidating adjustments and eliminations, and the Parent's consolidated amounts for the periods indicated.






31
Condensed Consolidating Balance Sheets (Unaudited)
March 31, 2020
Parent Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Consolidating Adjustments Total Consolidated
(In thousands)
ASSETS
Current assets:
Cash and cash equivalents $ 17,008    $ 81    $ 23,905    $ —    $ 40,994   
Accounts receivable, net of allowance for doubtful accounts of $2,332 (Guarantor of $1,116 and Parent of $1,216)   1,670    40,119    17,395    (4,805)   54,379   
Materials and supplies 414    —    —    414   
Current derivative asset 661    —    —    —    661   
Income taxes receivable 2,673    —    —    —    2,673   
Prepaid expenses and other 3,138    3,143    7,473    —    13,754   
Total current assets 25,150    43,757    48,773    (4,805)   112,875   
Property and equipment:
Oil and natural gas properties on the full cost method:
Proved properties —    6,565,136    —    —    6,565,136   
Unproved properties not being amortized
—    31,538    —    —    31,538   
Drilling equipment —    1,298,626    —    —    1,298,626   
Gas gathering and processing equipment —    —    829,600    —    829,600   
Saltwater disposal systems —    43,831    —    —    43,831   
Corporate land and building —    59,080    —    —    59,080   
Transportation equipment 9,713    14,405    3,397    —    27,515   
Other 29,008    29,031    —    —    58,039   
38,721    8,041,647    832,997    —    8,913,365   
Less accumulated depreciation, depletion, amortization, and impairment
34,327    7,250,779    483,204    —    7,768,310   
Net property and equipment 4,394    790,868    349,793    —    1,145,055   
Intercompany receivable 973,769    —    —    (973,769)   —   
Investments 74,752    —    —    (74,752)   —   
Right of use asset 39    3,724    3,227    (53)   6,937   
Other assets 7,060    8,266    7,650    —    22,976   
Total assets $ 1,085,164    $ 846,615    $ 409,443    $ (1,053,379)   $ 1,287,843   

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March 31, 2020
Parent Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Consolidating Adjustments Total Consolidated
(In thousands)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable $ 3,121    $ 47,721    $ 12,014    $ (4,261)   $ 58,595   
Accrued liabilities 30,735    7,585    4,055    (545)   41,830   
Current operating lease liability 17    2,156    1,961    (6)   4,128   
Current portion of long-term debt less debt issuance costs 771,283    —    —    —    771,283   
Current portion of other long-term liabilities 3,020    6,533    8,764    —    18,317   
Total current liabilities 808,176    63,995    26,794    (4,812)   894,153   
Intercompany debt —    972,510    1,259    (973,769)   —   
Long-term debt —    —    37,000    —    37,000   
Non-current derivative liability 123    —    —    —    123   
Operating lease liability 20    1,533    1,132    (46)   2,639   
Other long-term liabilities 11,154    72,301    4,782    —    88,237   
Deferred income taxes 11,205    —    —    —    11,205   
Total shareholders' equity 254,486    (263,724)   338,476    (74,752)   254,486   
Total liabilities and shareholders’ equity $ 1,085,164    $ 846,615    $ 409,443    $ (1,053,379)   $ 1,287,843   

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December 31, 2019
Parent Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Consolidating Adjustments Total Consolidated
(In thousands)
ASSETS
Current assets:
Cash and cash equivalents $ 503    $ 68    $ —    $ —    $ 571   
Accounts receivable, net of allowance for doubtful accounts of $2,332 (Guarantor of $1,116 and Parent of $1,216)   2,645    64,805    24,653    (9,447)   82,656   
Materials and supplies —    449    —    —    449   
Current derivative asset 633    —    —    —    633   
Income tax receivable 1,756    —    —    —    1,756   
Assets held for sale —    5,908    —    —    5,908   
Prepaid expenses and other 2,019    3,373    7,686    —    13,078   
Total current assets 7,556    74,603    32,339    (9,447)   105,051   
Property and equipment:
Oil and natural gas properties on the full cost method:
Proved properties —    6,341,582    —    —    6,341,582   
Unproved properties not being amortized
—    252,874    —    —    252,874   
Drilling equipment —    1,295,713    —    —    1,295,713   
Gas gathering and processing equipment —    —    824,699    —    824,699   
Saltwater disposal systems —    69,692    —    —    69,692   
Corporate land and building —    59,080    —    —    59,080   
Transportation equipment 9,712    16,621    3,390    —    29,723   
Other 28,927    29,065    —    —    57,992   
38,639    8,064,627    828,089    —    8,931,355   
Less accumulated depreciation, depletion, amortization, and impairment
33,794    6,537,731    407,144    —    6,978,669   
Net property and equipment 4,845    1,526,896    420,945    —    1,952,686   
Intercompany receivable 1,048,785    —    —    (1,048,785)   —   
Investments 865,252    —    —    (865,252)   —   
Right of use asset 46    1,733    3,948    (54)   5,673   
Other assets 8,107    9,094    9,441    —    26,642   
Total assets $ 1,934,591    $ 1,612,326    $ 466,673    $ (1,923,538)   $ 2,090,052   

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December 31, 2019
Parent Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Consolidating Adjustments Total Consolidated
(In thousands)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable $ 12,259    $ 61,002    $ 18,511    $ (7,291)   $ 84,481   
Accrued liabilities 28,003    14,024    6,691    (2,156)   46,562   
Current operating lease liability 20    1,009    2,407    (6)   3,430   
Current portion of long-term debt 108,200    —    —    —    108,200   
Current portion of other long-term liabilities 3,003    7,313    7,060    —    17,376   
Total current liabilities 151,485    83,348    34,669    (9,453)   260,049   
Intercompany debt —    1,047,599    1,186    (1,048,785)   —   
Long-term debt less debt issuance costs 646,716    —    16,500    —    663,216   
Non-current derivative liability 27    —    —    —    27   
Operating lease liability 25    690    1,404    (48)   2,071   
Other long-term liabilities 12,553    74,662    8,126    —    95,341   
Deferred income taxes 68,150    (54,437)   —    —    13,713   
Total shareholders' equity 1,055,635    460,464    404,788    (865,252)   1,055,635   
Total liabilities and shareholders’ equity $ 1,934,591    $ 1,612,326    $ 466,673    $ (1,923,538)   $ 2,090,052   

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Condensed Consolidating Statements of Operations (Unaudited)

Three Months Ended March 31, 2020
  Parent Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Consolidating Adjustments Total Consolidated
  (In thousands)
Revenues $ —    $ 85,154    $ 42,680    $ (5,458)   $ 122,376   
Expenses:
Operating costs —    56,864    32,317    (5,458)   83,723   
Depreciation, depletion, and amortization 871    48,473    12,273    —    61,617   
Impairments —    677,962    63,962    —    741,924   
Loss on abandonment of assets —    17,554    —    —    17,554   
General and administrative —    11,553    —    —    11,553   
(Gain) loss on disposition of assets —    396    (6)   —    390   
Total operating costs 871    812,802    108,546    (5,458)   916,761   
Loss from operations (871)   (727,648)   (65,866)   —    (794,385)  
Interest, net (12,739)   —    (518)   —    (13,257)  
Gain on derivatives 483    —    —    —    483   
Other, net 7    35    18    —    60   
Loss before income taxes (13,120)   (727,613)   (66,366)   —    (807,099)  
Income tax benefit —    (3,425)   —    —    (3,425)  
Equity in net earnings from investment in subsidiaries, net of taxes
(790,554)   —    —    790,554    —   
Net loss (803,674)   (724,188)   (66,366)   790,554    (803,674)  
Less: net loss attributable to non-controlling interest (33,180)   —    (33,180)   33,180    (33,180)  
Net loss attributable to Unit Corporation $ (770,494)   $ (724,188)   $ (33,186)   $ 757,374    $ (770,494)  
Three Months Ended March 31, 2019
Parent Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Consolidating Adjustments Total Consolidated
  (In thousands)
Revenues $ —    $ 144,294    $ 70,509    $ (25,112)   $ 189,691   
Expenses:
Operating costs —    71,393    56,129    (24,052)   103,470   
Depreciation, depletion, and amortization 1,934    48,466    11,726    —    62,126   
General and administrative —    9,741    —    —    9,741   
(Gain) loss on disposition of assets (10)   1,667    (42)   —    1,615   
Total operating costs 1,924    131,267    67,813    (24,052)   176,952   
Income (loss) from operations (1,924)   13,027    2,696    (1,060)   12,739   
Interest, net (8,202)   —    (336)   —    (8,538)  
Loss on derivatives (6,932)   —    —    —    (6,932)  
Other, net 5    —    —    —    5   
Income (loss) before income taxes (17,053)   13,027    2,360    (1,060)   (2,726)  
Income tax expense (benefit) (3,699)   3,255    —    —    (444)  
Equity in net earnings from investment in subsidiaries, net of taxes
9,850    —    —    (9,850)   —   
Net income (loss) (3,504)   9,772    2,360    (10,910)   (2,282)  
Less: net income attributable to non-controlling interest —    —    1,222    —    1,222   
Net income (loss) attributable to Unit Corporation $ (3,504)   $ 9,772    $ 1,138    $ (10,910)   $ (3,504)  
        
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Condensed Consolidating Statements of Comprehensive Income (Loss) (Unaudited)
Three Months Ended March 31, 2020
  Parent Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Consolidating Adjustments Total Consolidated
  (In thousands)
Net loss $ (803,674)   $ (724,188)   $ (66,366)   $ 790,554    $ (803,674)  
Other comprehensive loss, net of taxes:
Unrealized gain on securities, net of tax of $0 —    —    —    —    —   
Comprehensive loss (803,674)   (724,188)   (66,366)   790,554    (803,674)  
Less: Comprehensive loss attributable to non-controlling interests (33,180)   —    (33,180)   33,180    (33,180)  
Comprehensive loss attributable to Unit Corporation $ (770,494)   $ (724,188)   $ (33,186)   $ 757,374    $ (770,494)  

Three Months Ended March 31, 2019
  Parent Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Consolidating Adjustments Total Consolidated
  (In thousands)
Net income (loss) $ (3,504)   $ 9,772    $ 2,360    $ (10,910)   $ (2,282)  
Other comprehensive income (loss), net of taxes:
Unrealized income on securities, net of tax of $7 —    24    —    —    24   
Comprehensive income (loss) (3,504)   9,796    2,360    (10,910)   (2,258)  
Less: Comprehensive income attributable to non-controlling interests —    —    1,222    —    1,222   
Comprehensive income (loss) attributable to Unit Corporation $ (3,504)   $ 9,796    $ 1,138    $ (10,910)   $ (3,480)  

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Condensed Consolidating Statements of Cash Flows (Unaudited)
Three Months Ended March 31, 2020
  Parent Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Consolidating Adjustments Total Consolidated
  (In thousands)
OPERATING ACTIVITIES:
Net cash provided by (used in) operating activities $ (66,578)   $ 86,663    $ 9,827    $ —    $ 29,912   
INVESTING ACTIVITIES:
Capital expenditures
(421)   (13,051)   (4,056)   —    (17,528)  
Producing properties and other acquisitions
—    (210)   —    —    (210)  
Proceeds from disposition of assets
—    1,700    51    —    1,751   
Net cash used in investing activities (421)   (11,561)   (4,005)   —    (15,987)  
FINANCING ACTIVITIES:
Borrowings under credit agreement
39,300    —    32,100    —    71,400   
Payments under credit agreement
(23,500)   —    (11,600)   —    (35,100)  
Intercompany borrowings (advances), net
75,016    (75,089)   73    —    —   
Net payments on finance leases
—    —    (1,026)   —    (1,026)  
Employee taxes paid by withholding shares (43)   —    —    —    (43)  
Bank overdrafts
(7,269)   —    (1,464)   —    (8,733)  
Net cash provided by (used in) financing activities 83,504    (75,089)   18,083    —    26,498   
Net increase in cash and cash equivalents 16,505    13    23,905    —    40,423   
Cash and cash equivalents, beginning of period
503    68    —    —    571   
Cash and cash equivalents, end of period
$ 17,008    $ 81    $ 23,905    $ —    $ 40,994   

Three Months Ended March 31, 2019
  Parent Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Consolidating Adjustments Total Consolidated
  (In thousands)
OPERATING ACTIVITIES:
Net cash provided by (used in) operating activities $ 3,548    $ 64,168    $ 13,506    $ (34)   $ 81,188   
INVESTING ACTIVITIES:
Capital expenditures
(321)   (110,089)   (12,097)   —    (122,507)  
Producing properties and other acquisitions
—    (1,580)   —    —    (1,580)  
Proceeds from disposition of assets
10    3,142    38    —    3,190   
Net cash used in investing activities (311)   (108,527)   (12,059)   —    (120,897)  
FINANCING ACTIVITIES:
Borrowings under credit agreement
106,900    —    2,900    —    109,800   
Payments under credit agreement
(66,900)   —    (2,900)   —    (69,800)  
Intercompany borrowings (advances), net
(43,103)   44,407    (1,338)   34    —   
Net payments on finance leases
—    —    (985)   —    (985)  
Employee taxes paid by withholding shares (4,110)   —    —    —    (4,110)  
Distributions to non-controlling interest 919    —    (1,837)   —    (918)  
Bank overdrafts
3,161    —    —    —    3,161   
Net cash provided by (used in) financing activities (3,133)   44,407    (4,160)   34    37,148   
Net increase (decrease) in cash and cash equivalents 104    48    (2,713)   —    (2,561)  
Cash and cash equivalents, beginning of period
403    208    5,841    —    6,452   
Cash and cash equivalents, end of period
$ 507    $ 256    $ 3,128    $ —    $ 3,891   


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NOTE 19 – SUBSEQUENT EVENTS

Delay of Filing

On May 7, 2020, we filed a Current Report on Form 8-K giving notice that we intended to delay the filing of our 10-Q for the fiscal quarter ended March 31, 2020. We relied on the SEC order (SEC Release 34-88465), to delay the filing of our 10-Q.

Standstill and Amendment Agreement

To facilitate the negotiation of proposals regarding the company's capital structure and the Chapter 11 restructuring, the company, UPC, UDC, BOKF, NA dba Bank of Oklahoma, and the RBL Lenders entered into a Standstill and Amendment Agreement on March 11, 2020 regarding the Unit credit facility, which delayed the scheduled borrowing base redetermination for the facility until the expiration of a standstill period and under which the RBL Lenders agreed not to exercise certain of their rights and remedies under the Unit credit facility. The standstill period was set to expire on April 15, 2020 and was ultimately extended to May 22, 2020. For further information, please see Note 2 – Chapter 11 Proceedings, Liquidity, and Ability to Continue as a Going Concern—Liquidity, Unit Credit Facility and Debtor-in-Possession Credit Agreement.

Voluntary Reorganization Under Chapter 11 of the Bankruptcy Code

On May 22, 2020, the Debtors filed the Bankruptcy Petitions seeking relief under the Bankruptcy Code. We expect to continue operations in the normal course during the pendency of the Chapter 11 Cases. For further information, please see Note 2 – Chapter 11 Proceedings, Liquidity, and Ability to Continue as a Going Concern—Voluntary Reorganization Under Chapter 11 of the Bankruptcy Code.

Debtor-in-Possession Credit Agreement

On May 27, 2020, the Debtors entered into the DIP credit agreement with the RBL Lenders (in such capacity, the DIP Lenders) and BOKF, NA dba Bank of Oklahoma, as administrative agent, under which the DIP Lenders agreed to provide the company with the $36.0 million multi-draw loan facility. On June 19, 2020, the the Bankruptcy Court granted final approval of the DIP credit facility. For further information, please see Note 2 – Chapter 11 Proceedings, Liquidity, and Ability to Continue as a Going Concern—Liquidity, Unit Credit Facility and Debtor-in-Possession Credit Agreement.

Interest Payment Deferral on the Notes

On May 15, 2020, the company elected not to make the approximate $21.5 million semi-annual interest payment due on the Notes. For further information, please see Note 8 – Long-Term Debt and Other Long-Term Liabilities—Long-Term Debt—6.625% Senior Subordinated Notes.

Reduction in Force

In April 2020, we initiated a plan to reduce the number of employees in our organization in an effort to lower operating costs and restructure our business. We announced and communicated a reduction in personnel in our corporate offices as well as certain field office locations. As a result, we expect to incur incremental costs for severance related to our former employees.

Delisting of Our Common Stock from the NYSE

On May 26, 2020, trading in our common stock on the New York Stock Exchange (NYSE) was suspended because of the Debtors’ filing of the Chapter 11 Cases. Effective May 27, 2020, trades in our common stock began being quoted on the OTC Pink Market under the symbol “UNTCQ”. On June 10, 2020, the NYSE filed a Form 25 to delist our common stock and to remove it from registration under Section 12(b) of the Exchange Act.


39
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Management’s Discussion and Analysis (MD&A) provides you with an understanding of our operating results and financial condition by focusing on changes in certain key measures from year to year or period to period. MD&A is organized into these sections: 

•General;
•Recent Developments;
•Business Outlook;
•Executive Summary;
•Financial Condition and Liquidity;
•New Accounting Pronouncements; and
•Results of Operations.

Please read the information in our most recent Annual Report on Form 10-K in conjunction with your review of the information below and our unaudited condensed consolidated financial statements and related notes.

Unless otherwise indicated or required by the content, when used in this report the terms “company,” “Unit,” “us,” “our,” “we,” and “its” refer to Unit Corporation or, as appropriate, one or more of its subsidiaries. References to our mid-stream segment refers to Superior Pipeline Company, L.L.C. of which we own 50%.

General

We operate, manage, and analyze the results of our operations through our three principal business segments: 

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

In addition to the companies identified above, our corporate headquarters is owned by our wholly owned subsidiary "8200 Unit Drive, L.L.C.".

Recent Developments

Voluntary Reorganization Under Chapter 11 of the Bankruptcy Code

As discussed in Note 2 – Chapter 11 Proceedings, Liquidity, and Ability to Continue as a Going Concern, on the Petition Date, the Debtors filed the Bankruptcy Petitions under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. The Chapter 11 Cases are being jointly administered under the caption In re Unit Corporation, et al., Case No. 20-32740 (DRJ). The Debtors will continue to operate as debtors-in-possession under the jurisdiction of the Bankruptcy Court and under the provisions of the Bankruptcy Code and an order of the Bankruptcy Court. The Debtors filed and were granted a series of first day motions with the Bankruptcy Court that allowed the Debtors to continue to conduct business without interruption. For more information regarding the Chapter 11 Cases, the RSA, DIP credit agreement and other related matters, please read Note 2 – Chapter 11 Proceedings, Liquidity, and Ability to Continue as a Going Concern.

Going Concern and Financial Reporting in Reorganization

Besides entering into the RSA and the DIP credit agreement, the company is undertaking several actions to alleviate the conditions that cause substantial doubt about our ability to continue as a going concern, including (i) minimizing capital expenditures, (ii) aggressively managing working capital, (iii) further reducing recurring operating expenses, and (iv) exploring potential business transactions. We expect that the company’s cash flows, cash on hand and any financing it can obtain through the DIP credit facility should provide sufficient liquidity for the company during the pendency of the Chapter 11 Cases.
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However, the significant risks and uncertainties related to the company’s liquidity and Chapter 11 Cases raise substantial doubt about the company’s ability to continue as a going concern. The outcome of the Chapter 11 Cases is subject to significant uncertainty and depends upon factors outside of the company’s control, including actions of the Bankruptcy Court and the company’s creditors. There can be no assurance that the company will confirm and consummate the plan as contemplated by the RSA or complete an alternative plan of reorganization. The company has concluded there continues to be substantial doubt about the company’s ability to continue as a going concern.

The condensed consolidated financial statements have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets, and satisfaction of liabilities and commitments in the normal course of business. The condensed consolidated financial statements include no adjustments that might result from the outcome of the going concern uncertainty. If the company cannot continue as a going concern, adjustments to the carrying values and classification of its assets and liabilities and the reported amounts of income and expenses could be required and could be material.

Delisting of Our Common Stock from the NYSE

On May 26, 2020, trading in our common stock on the New York Stock Exchange (NYSE) was suspended because of the Debtors’ filing of the Chapter 11 Cases. Effective May 27, 2020, trades in our common stock began being quoted on the OTC Pink Market under the symbol “UNTCQ”. On June 10, 2020, the NYSE filed a Form 25 to delist our common stock and to remove it from registration under Section 12(b) of the Exchange Act.

Business Outlook

COVID-19 Pandemic and Commodity Price Environment

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

On January 30, 2020, the World Health Organization (WHO) announced a global health emergency as COVID-19, continued to spread globally beyond its point of origin. In March 2020, WHO classified the COVID-19 outbreak as a pandemic based on the rapid increase in exposure globally and the risks posed to the international community. The global spread of COVID-19 has caused widespread illness and significant loss of life, leading governments across the world to impose severely stringent limitations on movement and human interaction. The response of governments throughout the world to address the spread of COVID-19, including, among other actions, imposing travel bans, quarantines and entry restrictions, has significantly slowed down the global economic activity and reduced the demand for oil and natural gas. We can neither predict the duration nor estimate the economic impact of the COVID-19 pandemic. Therefore, the company can give no assurances that the spread of COVID-19 will not have a material adverse effect on its financial position or results of operations in 2020 and beyond.

On March 9, 2020, the price of oil fell approximately 20% due to a dispute over production levels between Saudi Arabia and Russia. Saudi Arabia’s subsequent decision to dramatically increase its oil production and engage in a price war with Russia led to a massive oversupply of oil, which flooded the global markets. The confluence of the spread of COVID-19 and the oil price war has significantly impacted the oil and gas industry, causing an unprecedented drop in oil prices and ensuing reductions of exploration and production company capital and operating budgets. Though OPEC, Russia and other major oil and gas producing nations recently agreed to drastically cut oil production, the efforts to contain COVID-19 will continue to depress global economic activity in the near-term, and the supply and demand imbalance of oil and gas will likely continue for the foreseeable future, leading to sustained lower prices for the remainder of 2020 and possibly beyond.

During the last three years, commodity prices have been volatile. Our oil and natural gas segment used two to three drilling rigs throughout 2017. With improved commodity prices during the first quarter of 2018, our oil and natural gas segment put four of our drilling rigs to work and increased the number to six drilling rigs for a brief period during the third quarter of 2018. We reduced our operated rig count in the fourth quarter of 2018 and the first quarter of 2019 before getting as high as six drilling rigs again in the second quarter of 2019. Due to declining prices we shut down our drilling program in July and used no drilling rigs the remainder of 2019 or the first quarter of 2020.

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

UNT-20200331_G2.JPG
The following chart reflects the significant fluctuations in the prices for NGLs:

UNT-20200331_G3.JPG
_________________________
1.NGLs prices reflect a weighted-average, based on production, of Mont Belvieu and Conway prices.


Commodity prices continued to decline into the first quarter of 2020 and have continued to decline into the second quarter of 2020. As of June 11, 2020, crude oil WTI was $36.34 per BBl, natural gas Henry Hub was $1.81 per MMBtu, ethane was $3.60 per Bbl, propane was $8.51 per Bbl, and condensate was $12.72 per Bbl.
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For the three months ended March 31, 2020, we participated in completing 14 gross wells (3.07 net wells) drilled by other operators. For 2020, we do not currently have any plans to drill wells pending our ability to refinance our debt and the outcome of the Restructuring.

In the first quarter of 2020, we incurred a non-cash ceiling test write-down of our oil and natural gas properties of $267.8 million pre-tax ($220.8 million net of tax). We anticipate a non-cash ceiling test write-down in the second quarter of 2020. It is hard to predict with any reasonable certainty the need for or amount of any future impairments given the many factors that go into the ceiling test calculation including, but not limited to, future pricing, operating costs, drilling and completion costs, upward or downward oil and gas reserve revisions, oil and gas reserve additions, and tax attributes. Subject to these inherent uncertainties, if we hold these same factors constant as they existed at March 31, 2020, and only adjust the 12-month average price as of June 2020, our forward looking expectation is that we would recognize an impairment of $95 million pre-tax in the second quarter of 2020. Given the uncertainty associated with the factors used in calculating our estimate of both our future period ceiling test write-down and the decrease in our undeveloped reserves, these estimates should not necessarily be construed as indicative of our future development plans or financial results and the actual amount of any write-down may vary significantly from this estimate depending on the final future determination.

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

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

Within our mid-stream segment, we determined that the carrying value of certain long-lived asset groups in southern Kansas, and central Oklahoma where lower pricing is expected to impact drilling and production levels, are not recoverable and exceeded their estimated fair value. Based on the estimated fair value of the asset groups, we recorded non-cash impairment charges of $64.0 million. These charges are included within impairment charges in our Consolidated Statement of Operations.

Going Concern

Besides entering into the RSA and the DIP credit agreement the company is undertaking several actions to alleviate the conditions that cause substantial doubt about our ability to continue as a going concern, including (i) minimizing capital expenditures, (ii) aggressively managing working capital, (iii) further reducing recurring operating expenses, and (iv) exploring potential business transactions. We expect that the company’s cash flows, cash on hand and any financing it can obtain through the DIP credit facility should provide sufficient liquidity for the company during the pendency of the Chapter 11 Cases. However, the significant risks and uncertainties related to the company’s liquidity and Chapter 11 Cases raise substantial doubt about the company’s ability to continue as a going concern. The outcome of the Chapter 11 Cases is subject to high uncertainty and depends upon factors outside of the company’s control, including actions of the Bankruptcy Court and the company’s creditors. There can be no assurance that the company will confirm and consummate the plan as contemplated by the RSA or complete another plan of reorganization regarding the Chapter 11 Cases. The company has concluded there continues to be substantial doubt about the company’s ability to continue as a going concern.

Executive Summary

Oil and Natural Gas

First quarter 2020 production from our oil and natural gas segment was 3,440,000 barrels of oil equivalent (Boe), a decrease of 17% from the fourth quarter of 2019 and a decrease of 17% from the first quarter of 2019. The decreases came from fewer net wells being completed in the first quarter to replace declines in existing drilled wells.

First quarter 2020 oil and natural gas revenues decreased 42% from the fourth quarter of 2019 and decreased 44% from the first quarter of 2019. The decreases were primarily from a decrease in commodity prices and production.
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Our oil prices for the first quarter of 2020 decreased 22% from the fourth quarter of 2019 and decreased 20% from the first quarter of 2019. Our NGLs prices decreased 75% from the fourth quarter of 2019 and decreased 80% from the first quarter of 2019. Our natural gas prices decreased 38% from the fourth quarter of 2019 and decreased 51% from the first quarter of 2019.

Operating cost per Boe produced for the first quarter of 2020 increased 20% over the fourth quarter of 2019 and increased 12% over the first quarter of 2019. The increases were primarily due to lower production applied against fixed costs and no G&G cost capitalized in the first quarter of 2020.

At March 31, 2020, these derivatives were outstanding:
Term Commodity Contracted Volume Weighted Average 
Fixed Price 		Contracted Market
Apr'20 - Dec'20 Natural gas - basis swap 30,000 MMBtu/day $(0.275)   NGPL TEXOK
Apr'20 - Dec'20 Natural gas - basis swap 20,000 MMBtu/day $(0.455)   PEPL
Jan'21 - Dec'21 Natural gas - basis swap 30,000 MMBtu/day $(0.215)   NGPL TEXOK
Apr'20 - Dec'20 Natural gas - three-way collar 30,000 MMBtu/day $2.50 - $2.20 - $2.80    IF - NYMEX (HH)

After March 31, 2020, these derivatives were entered into:
Term Commodity Contracted Volume Weighted Average Fixed Price Contracted Market
May'20 - Sep'20 Crude oil - collar 112,000 Bbl/month $20.00 - $26.50    WTI - NYMEX

As a result of the commencement of the Chapter 11 Cases, our ability to enter into derivative transactions are limited.

For the three months ended March 31, 2020, we participated in the completion of 14 gross wells (3.07 net wells) drilled by other operators. For 2020, we do not currently have any plans to drill wells pending our ability to refinance our debt.

Contract Drilling

The average number of drilling rigs we operated in the first quarter of 2020 was 18.7 compared to 18.3 and 31.4 in the fourth quarter of 2019 and the first quarter of 2019, respectively. As of March 31, 2020, 17 of our drilling rigs were operating.

Revenue for the first quarter of 2020 was essentially unchanged from the fourth quarter of 2019 and decreased 28% from the first quarter of 2019. The decrease from the first quarter of 2019 was primarily due to less drilling rigs operating.

Dayrates for the first quarter of 2020 averaged $19,535, an 1% increase over the fourth quarter of 2019 and a 7% increase over the first quarter of 2019. The increases were primarily due to drilling rigs with lower dayrates being released and higher dayrate BOSS drilling rigs continuing to operate.

Operating costs for the first quarter of 2020 decreased 4% from the fourth quarter of 2019 and decreased 19% from the first quarter of 2019. The decreases were both primarily due to less drilling rigs operating.

We have four term drilling contracts with original terms ranging from six months to two years. They are up for renewal after 2020. Term contracts may contain a fixed rate during the contract or provide for rate adjustments within a specific range from the existing rate. Some operators who had signed term contracts have opted to release the drilling rig early and pay an early termination penalty for the remaining term of the contract. We recorded no early termination fees in the first quarter of 2020. We recorded $4.8 million in early termination fees in the first quarter of 2019.
Six of our 14 existing BOSS drilling rigs are under contract.

For 2020, we do not currently have an approved capital plan for this segment. Capital expenditures incurred would be within anticipated cash flows.

Mid-Stream

First quarter 2020 liquids sold per day decreased 8% from the fourth quarter of 2019 and decreased 19% from the first
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quarter of 2019, respectively. The decreases were due to lower plant recoveries while operating our processing facilities in ethane rejection mode resulting in lower liquids available for sale. For the first quarter of 2020, gas processed per day increased 2% over the fourth quarter of 2019 and increased 3% over the first quarter of 2019. The increases were primarily due to higher volumes from new well connects and adding the volume from a new acquisition to our Cashion processing facility. For the first quarter of 2020, gas gathered per day decreased 2% from the fourth quarter of 2019 and decreased 14% from the first quarter of 2019, respectively. The decrease from the fourth quarter of 2019 was primarily due to declining volume from the Appalachian region and to a lesser extent from declining volumes on several gathering systems in Oklahoma and Texas. The decrease over the first quarter of 2019 was due to declining volumes from most of our major systems in both the Appalachian region and the mid-continent area.

NGLs prices in the first quarter of 2020 decreased 32% from the prices received in the fourth quarter of 2019 and decreased 42% from the prices received in the first quarter of 2019. Because certain contracts used by our mid-stream segment for NGLs transactions are commodity-based contracts, under which we receive a share of the proceeds from the sale of the NGLs, our revenues from those commodity-based contracts fluctuate based on the price of NGLs.

Total operating cost for our mid-stream segment for the first quarter of 2020 decreased 17% from the fourth quarter of 2019 and decreased 30% from the first quarter of 2019. The decreases were both primarily due to lower purchase prices.

At the Cashion processing facility in central Oklahoma, total throughput volume for the first quarter of 2020 averaged approximately 81.5 MMcf per day and total production of natural gas liquids averaged approximately 315,000 gallons per day. Through the first quarter of 2020, we continued to connect new wells to this system for third party producers. Since the first of this year, we connected seven new wells to this system from producers. The new 60 MMcf per day Reeding processing facility is operational and we brought the recently acquired mid-continent production to this facility for processing beginning April 1, 2020. The total processing capacity on the Cashion system is 105 MMcf per day.

In the Appalachian region at the Pittsburgh Mills gathering system, average gathered volume for the first quarter of 2020 was 145.1 MMcf per day while the average gathered volume for March 2020 was approximately 149.9 MMcf per day. During the first quarter of 2020, we added three new infill wells to this system. One additional new infill well began flowing at the beginning of the second quarter. With these four new wells connected to the Pittsburgh Mills system, gathered volume has increase to approximately 190 MMcf per day.

At the Hemphill processing facility in the Texas panhandle, average total throughput volume for the first quarter of 2020 was 56.2 MMcf per day and total production of natural gas liquids declined to approximately 126,000 gallons per day due to lower wellhead volume and operating in full ethane rejection due to lower prices. We connected no new wells to this system in the first quarter of 2020.

At the Segno gathering system in East Texas, the average throughput volume for the first quarter of 2020 was 51.7 MMcf per day. During the first quarter of 2020, we connected no new wells to this system.

Anticipated 2020 capital expenditures for this segment will be approximately $28.0 million, a 57% decrease from 2019.

Financial Condition and Liquidity

Summary

Our financial condition and liquidity depend on the cash flow from our operations and borrowings under our credit agreements. Our cash flow is based primarily on:
 
•the amount of natural gas, oil, and NGLs we produce;
•the prices we receive for our natural gas, oil, and NGLs production;
•the demand for and the dayrates we receive for our drilling rigs; and
•the fees and margins we obtain from our natural gas gathering and processing contracts.

We expect that the company’s cash flows, cash on hand and any financing it can obtain through the DIP credit facility should provide sufficient liquidity for the company during the pendency of the Chapter 11 Cases. However, the significant risks and uncertainties related to the company’s liquidity and Chapter 11 Cases raise substantial doubt about the company’s ability to continue as a going concern. The outcome of the Chapter 11 Cases is subject to significant uncertainty and depends upon factors outside of the company’s control, including actions of the Bankruptcy Court and the company’s creditors. There can be no assurance that the company will confirm and consummate the plan as contemplated by the RSA or complete an alternative
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plan of reorganization. The company has therefore concluded there continues to be substantial doubt about the company’s ability to continue as a going concern.

Below is a summary of certain financial information for the periods indicated:
  Three Months Ended March 31, %
Change
  2020 2019
  (In thousands except percentages)
Net cash provided by operating activities 29,912    81,188    (63) %
Net cash used in investing activities (15,987)   (120,897)   87  %
Net cash provided by financing activities 26,498    37,148    (29) %
Net increase (decrease) in cash and cash equivalents $ 40,423    $ (2,561)  

Cash Flows from Operating Activities

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

Net cash provided by operating activities in the first three months of 2020 decreased by $51.3 million as compared to the first three months of 2019. The decrease was primarily due to lower revenues due to lower commodity prices and lower drilling rig utilization partially offset by an increase in changes in operating assets and liabilities related to the timing of cash receipts and disbursements.

Cash Flows from Investing Activities

We dedicate and expect to continue to dedicate a substantial portion of our capital budget to the exploration for and production of oil, NGLs, and natural gas. These expenditures are necessary to off-set the inherent production declines typically experienced in oil and gas wells.

Cash flows used in investing activities decreased by $104.9 million for the first three months of 2020 compared to the first three months of 2019. The change was due primarily to a decrease in capital expenditures due to decrease in wells drilled, oil and gas property acquisitions, and a decrease in the proceeds received from the disposition of assets. See additional information on capital expenditures below under Capital Requirements.

Cash Flows from Financing Activities

Cash flows provided by financing activities decreased by $10.7 million for the first three months of 2020 compared to the first three months of 2019. The decrease was primarily due to a decrease in the net borrowings under our credit agreements and a decrease in bank overdrafts.

At March 31, 2020, we had unrestricted cash and cash equivalents totaling $41.0 million and had borrowed $124.0 million and $37.0 million of the amounts available under the Unit and Superior credit agreements, respectively.

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Below, we summarize certain financial information as of March 31, 2020 and 2019 and for the three months ended March 31, 2020 and 2019:
  March 31,
%
Change (2)
  2020 2019
  (In thousands except percentages)
Working capital $ (781,278)   $ (66,651)   NM   
Current portion of long-term debt (1)
$ 771,283    $ —    NM   
Long-term debt (1)
$ 37,000    $ 685,031    (95) %
Shareholders’ equity attributable to Unit Corporation $ 85,878    $ 1,392,992    (94) %
Net loss attributable to Unit Corporation $ (770,494)   $ (3,504)   NM   
_________________________
1.In 2020, current portion of long-term debt is net of unamortized discount and debt issuance costs. In 2019, long-term debt is net of unamortized discount and debt issuance costs.
2.NM – A percentage calculation is not meaningful due to a zero-value denominator or a percentage change greater than 200.

Working Capital

Typically, our working capital balance fluctuates, in part, because of the timing of our trade accounts receivable and accounts payable and the fluctuation in current assets and liabilities associated with the mark to market value of our derivative activity. We had negative working capital of $781.3 million and $66.7 million as of March 31, 2020 and 2019, respectively. The decrease in working capital is primarily due to the springing maturity of the Unit credit agreement and the Notes and the determination to treat the borrowings as current liabilities and a decrease in accounts receivable due to lower revenues partially offset by reduction in accounts payable and an increase in cash and cash equivalents. The Superior credit agreement is used primarily for working capital and capital expenditures and the DIP facility is used to find the operation of the Debtors and the Chapter 11 Cases. At March 31, 2020, we had borrowed $124.0 million of the $200.0 million and $37.0 million of the $200.0 million available under the Unit and Superior credit agreements, respectively. As discussed below under “—Our Credit Agreements and Senior Subordinated Notes,” the RBL Lenders’ remaining commitments under the Unit credit agreement were terminated on May 22, 2020 under the Fifth Amendment to Standstill and Amendment Agreement. The effect of our derivative contracts increased working capital by $0.7 million as of March 31, 2020 and increased working capital by $3.5 million as of March 31, 2019.

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This table summarizes certain operating information:
Three Months Ended
  March 31, %
Change
  2020 2019
Oil and Natural Gas:
Oil production (MBbls) 674    688    (2) %
NGLs production (MBbls) 965    1,207    (20) %
Natural gas production (MMcf) 10,802    13,371    (19) %
Equivalent barrels (MBoe) 3,440    4,123    (17) %
Average oil price per barrel received $ 44.92    $ 56.29    (20) %
Average oil price per barrel received excluding derivatives $ 44.92    $ 53.14    (15) %
Average NGLs price per barrel received $ 3.27    $ 16.06    (80) %
Average NGLs price per barrel received excluding derivatives $ 3.27    $ 16.06    (80) %
Average natural gas price per Mcf received $ 1.23    $ 2.52    (51) %
Average natural gas price per Mcf received excluding derivatives $ 1.18    $ 2.49    (53) %
Contract Drilling:
Average number of our drilling rigs in use during the period 18.7    31.4    (40) %
Total drilling rigs available for service at the end of the period 58    57    2  %
Average dayrate $ 19,535    $ 18,339    7  %
Mid-Stream:
Gas gathered—Mcf/day 389,243    449,916    (13) %
Gas processed—Mcf/day 166,331    161,748    3  %
Gas liquids sold—gallons/day 527,673    650,614    (19) %
Number of natural gas gathering systems 19    22    (14) %
Number of processing plants 11    12    (8) %

Oil and Natural Gas Operations

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

Based on our first three months of 2020 production, a $0.10 per Mcf change in what we are paid for our natural gas production, without the effect of derivatives, would cause a corresponding $351,000 per month ($4.2 million annualized) change in our pre-tax operating cash flow. The average price we received for our natural gas production, including the effect of derivatives, during the first three months of 2020 was $1.23 compared to $2.52 for the first three months of 2019. Based on our first three months of 2020 production, a $1.00 per barrel change in our oil price, without the effect of derivatives, would have a $214,000 per month ($2.6 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 derivatives, would have a $310,000 per month ($3.7 million annualized) change in our pre-tax operating cash flow. In the first three months of 2020, our average oil price per barrel received, including the effect of derivatives, was $44.92 compared with an average oil price, including the effect of derivatives, of $56.29 in the first three months of 2019 and our first three months of 2020 average NGLs price per barrel received, including the effect of derivatives was $3.27 compared with an average NGLs price per barrel of $16.06 in the first three months of 2019.

Because commodity prices affect the value of our oil, NGLs, and natural gas reserves, declines in those prices can cause a decline in the carrying value of our oil and natural gas properties. Price declines can also hurt the semi-annual determination of the amount available for us to borrow under our Unit credit agreement since that determination is based mainly on the value of our oil, NGLs, and natural gas reserves. A reduction could limit our ability to carry out our planned capital projects. In the first quarter of 2020, the unamortized cost of our oil and gas properties exceeded the ceiling of our proved oil, NGLs, and natural gas reserves. As a result, we recorded a non-cash ceiling test write down of $267.8 million pre-tax ($220.8 million, net of tax).
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At March 31, 2020, the 12-month average unescalated prices were $55.77 per barrel of oil, $20.47 per barrel of NGLs, and $2.30 per Mcf of natural gas, and then are adjusted for price differentials.

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

We anticipate a non-cash ceiling test write-down in the second quarter of 2020. It is hard to predict with any reasonable certainty the need for or amount of any future impairments given the many factors that go into the ceiling test calculation including, but not limited to, future pricing, operating costs, drilling and completion costs, upward or downward oil and gas reserve revisions, oil and gas reserve additions, and tax attributes. Subject to these inherent uncertainties, if we hold these same factors constant as they existed at March 31, 2020, and only adjust the 12-month average price as of June 2020, our forward looking expectation is that we would recognize an impairment of $95 million pre-tax in the second quarter of 2020. Given the uncertainty associated with the factors used in calculating our estimate of both our future period ceiling test write-down and the decrease in our undeveloped reserves, these estimates should not necessarily be construed as indicative of our future development plans or financial results and the actual amount of any write-down may vary significantly from this estimate depending on the final future determination.

Our natural gas production is sold to intrastate and interstate pipelines and to independent marketing firms and gatherers under contracts with terms ranging from one month to five years. Our oil production is sold to independent marketing firms generally under six-month contracts.

Contract Drilling Operations

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

Most of our working drilling rigs are drilling horizontal or directional wells for oil and NGLs. The continuous fluctuations in commodity prices for oil and natural gas changes the demand for drilling rigs. These factors ultimately affect the demand and mix of the drilling rigs used by our customers. The future demand for and the availability of drilling rigs to meet that demand will affect our future dayrates. For the first three months of 2020, our average dayrate was $19,535 per day compared to $18,339 per day for the first three months of 2019. The average number of our drilling rigs used in the first three months of 2020 was 18.7 drilling rigs compared with 31.4 drilling rigs in the first three months of 2019. Based on the average utilization of our drilling rigs during the first three months of 2020, a $100 per day change in dayrates has a $1,870 per day ($0.7 million annualized) change in our pre-tax operating cash flow.

Our contract drilling segment provides drilling services for our exploration and production segment. Some of the drilling services we perform on our properties are, depending on the timing of those services, deemed associated with acquiring an ownership interest in the property. In those cases, revenues and expenses for those services are eliminated in our income statements, with any profit recognized as a reduction in our investment in our oil and natural gas properties. The contracts for these services are issued under the same conditions and rates as the contracts entered into with unrelated third parties. We eliminated revenue of $7.0 million for the first three months of 2019, from our contract drilling segment and eliminated the associated operating expense of $6.0 million during the first three months of 2019, yielding $1.1 million during the first three months of 2019, as a reduction to the carrying value of our oil and natural gas properties. We eliminated no revenue in our contract drilling segment for the first three months of 2020.

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

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

Our mid-stream segment is engaged primarily in the buying, selling, gathering, processing, and treating of natural gas. It operates three natural gas treatment plants, 11 processing plants, 19 gathering systems, and approximately 2,085 miles of pipeline. It operates in Oklahoma, Texas, Kansas, Pennsylvania, and West Virginia. Besides serving third parties, this segment also enhances our ability to gather and market our own natural gas and NGLs and serving as a mechanism through which we can construct or acquire existing natural gas gathering and processing facilities. During the first three months of 2020 and 2019, our mid-stream operations purchased $4.4 million and $16.3 million, respectively, of our natural gas production and NGLs, and provided gathering and transportation services of $1.1 million and $1.8 million, respectively. Intercompany revenue from services and purchases of production between this business segment and our oil and natural gas segment has been eliminated in our unaudited condensed consolidated financial statements.

This segment gathered an average of 389,243 Mcf per day in the first three months of 2020 compared to 449,916 Mcf per day in the first three months of 2019. It processed an average of 166,331 Mcf per day in the first three months of 2020 compared to 161,748 Mcf per day in the first three months of 2019. The NGLs sold was 527,673 gallons per day in the first three months of 2020 compared to 650,614 gallons per day in the first three months of 2019. Gas gathered volumes per day in the first three months of 2020 decreased 13% compared to the first three months of 2019 primarily due to declining volumes from most of our major systems partially offset by higher volumes on our Cashion system. Gas processed volumes for the first three months of 2020 increased 3% compared to the first three months of 2019 due to connecting new wells and adding the volume from a new acquisition at our Cashion processing facility. NGLs sold in the first three months of 2020 decreased 19% compared to the first three months of 2019 due to declining volumes on several major processing systems and operating several of our processing facilities in ethane rejection.

We determined that the carrying value of certain long-lived asset groups in southern Kansas, and central Oklahoma where lower pricing is expected to impact drilling and production levels, are not recoverable and exceeded their estimated fair value. Based on the estimated fair value of the asset groups, we recorded non-cash impairment charges of $64.0 million. These charges are included within impairment charges in our Consolidated Statement of Operations.

Our Credit Agreements and Senior Subordinated Notes

Unit Credit Agreement. Due to the Credit Agreement Extension Condition and acceleration of debt obligations resulting from filing the Chapter 11 Cases, the company's debt associated with the Unit credit agreement is reflected as a current liability in its consolidated balance sheets as of March 31, 2020 and December 31, 2019. The classification as a current liability due to the Credit Agreement Extension Condition is based on the uncertainty regarding the company's ability to repay or refinance the Notes before November 16, 2020. Filing the Bankruptcy Petitions on May 22, 2020 constituted an event of default that accelerated the company’s obligations under the Unit credit agreement, and the lenders’ rights of enforcement regarding the Unit credit agreement were automatically stayed because of the Chapter 11 Cases.

To facilitate negotiations of proposals regarding credit matters and the Chapter 11 restructuring, the company, UPC, UDC, BOKF, NA dba Bank of Oklahoma, and the RBL Lenders entered into a Standstill and Amendment Agreement on March 11, 2020 regarding the Unit credit facility, which delayed the scheduled borrowing base redetermination for the facility until the expiration of a standstill period and under which the RBL Lenders agreed not to exercise certain of their rights and remedies under the Unit credit facility. The standstill period was set to expire on April 15, 2020 and was subsequently extended from time to time until May 22, 2020. On May 22, 2020, the parties entered into a Fifth Amendment to Standstill and Amendment Agreement under which they agreed to the terms of an $8.0 million borrowing by the company under the Unit credit agreement and that, immediately following that borrowing, the remaining commitments of the RBL Lenders under the Unit credit facility were terminated. Subject to approval of the Plan, each lender under the Unit credit facility and the DIP credit facility will receive its pro rata share of revolving loans, term loans and letter-of-credit participations under the Exit Facility, in exchange for that lender’s allowed claims under the Unit credit facility or the DIP credit facility.

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 amounts borrowed under the Superior credit agreement bear annual interest at a rate, at Superior’s option, equal to (a) LIBOR plus the applicable margin of 2.00% to 3.25% or (b) the alternate base rate (greater of (i) the federal funds rate plus 0.5%, (ii) the prime rate, and (iii) third day LIBOR plus 1.00%) plus the applicable margin of 1.00% to 2.25%. The
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obligations under the Superior credit agreement are secured by, among other things, 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 LIBOR or Administrative Agent determines in good faith that the rate so reported no longer accurately reflects the rate available to Lender in the London Interbank Market or if such index no longer exists or accurately reflects the rate available to Administrative Agent in the London Interbank Market, Administrative Agent may select a replacement index.

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

The Superior credit agreement requires that Superior maintain a Consolidated EBITDA to interest expense ratio for the most-recently ended rolling four quarters of at least 2.50 to 1.00, and a funded debt to Consolidated EBITDA ratio of not greater than 4.00 to 1.00. 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 March 31, 2020, Superior complied with these covenants.
 
The borrowings under the Superior credit agreement will fund capital expenditures and acquisitions, provide general working capital, and for letters of credit for Superior.

Superior's credit agreement is not guaranteed by Unit. Superior and its subsidiaries are not parties to the RSA and are not Debtors in the Chapter 11 Cases.

The lenders under the Superior credit agreement and their respective participation interests are:
Lender Participation
Interest
BOK (BOKF, NA, dba Bank of Oklahoma) 17.50  %
Compass Bank 17.50  %
BMO Harris Financing, Inc. 13.75  %
Toronto Dominion (New York), LLC 13.75  %
Bank of America, N.A. 10.00  %
Branch Banking and Trust Company 10.00  %
Comerica Bank 10.00  %
Canadian Imperial Bank of Commerce 7.50  %
100.00  %

Subordinated Notes. As of March 31, 2020, we had an aggregate principal amount of $650.0 million in 6.625% senior subordinated notes (Notes) outstanding. Interest on the Notes was payable semi-annually (in arrears) on May 15 and November 15 of each year. The Notes were scheduled to mature on May 15, 2021. In issuing the Notes, we incurred fees of $14.7 million that are being amortized as debt issuance cost until maturity.

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 (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 significant independent assets or operations. The guarantees by the Guarantors of the Notes (registered under registration statements) are full and unconditional, joint and several, subject to certain automatic customary releases, are subject to certain restrictions on the sale, disposition, or transfer of the capital stock or substantially all of the assets of a subsidiary guarantor, and other conditions and terms set out in the 2011 Indenture. Effective April 3, 2018, Superior is no longer a Guarantor of the Notes. Excluding Superior, any of our other subsidiaries that are not Guarantors are minor. There are no significant restrictions on our ability to receive funds from any subsidiary through dividends, loans, advances, or otherwise.

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The company elected not to make the approximate $21.5 million semi-annual interest payment due on the Notes on May 15, 2020. The company was entitled to a 30-day grace period after the interest payment date before an event of default would occur because of such non-payment.

Filing the Bankruptcy Petitions on May 22, 2020 constituted an event of default that accelerated the company’s obligations under the Notes. However, under the Bankruptcy Code, holders of the Notes are stayed from taking any action against the company or the other Debtors because of the default. Subject to confirmation of the Plan, each holder of the Notes will receive its pro rata share of new common shares of reorganized Unit based on equity allocations at each of Unit, UDC and UPC in exchange for the holder’s allowed Notes claim.

DIP Credit Agreement. On May 26, 2020, the Bankruptcy Court granted interim approval of the DIP credit facility, including the DIP credit agreement, permitting the Debtors to borrow up to $18.0 million on an interim basis. On May 27, 2020 and as contemplated by the RSA, the company and the other Debtors entered into the DIP credit agreement under which the DIP Lenders agreed to provide the company with the $36.0 million multi-DIP credit facility. On June 19, 2020, the Bankruptcy Court granted final approval of the DIP credit facility.

Borrowings under the DIP credit facility mature on the earliest of (i) September 22, 2020 (subject to a two-month extension to be approved by the DIP Lenders), (ii) the sale of all or substantially all of the assets of the Debtors under Section 363 of the Bankruptcy Code or otherwise, (iii) the effective date of a plan of reorganization or liquidation in the Chapter 11 Cases, (iv) the entry of an order by the Bankruptcy Court dismissing any of the Chapter 11 Cases or converting such Chapter 11 Cases to a case under Chapter 7 of the Bankruptcy Code, and (v) the date of termination of the DIP Lenders’ commitments and the acceleration of any outstanding extensions of credit, in each case, under the DIP credit facility under and subject to the DIP credit agreement and the Bankruptcy Court’s orders.

The DIP credit agreement contains events of default customary for debtor-in-possession financings, including events related to the Chapter 11 proceedings, the occurrence of which could cause the acceleration of the Debtors’ obligation to repay borrowings outstanding under the DIP credit facility. The Debtors’ obligations under the DIP credit agreement are secured by a security interest in, and lien on, substantially all present and after-acquired property (whether tangible, intangible, real, personal or mixed) of the Debtors, including a superpriority priming lien on the property of the company and certain of its subsidiaries that secure their obligations under the existing Unit credit facility.

On the Debtors’ emergence from the Chapter 11 Cases and to the extent any claims under the DIP credit facility have not otherwise been repaid, each holder of an allowed claim under the DIP credit facility will receive its pro rata share of (i) revolving loans, term loans and letter-of-credit participations under a new credit facility with the reorganized Unit (Exit Facility) and (ii) an equity fee under the Exit Facility equal to 5% of the new common shares of reorganized Unit (subject to dilution by shares reserved for issuance under a management incentive plan and upon exercise of the warrants described above). The Exit Facility will be provided by the lenders under the Unit credit facility and the DIP credit facility to reorganized Unit in an aggregate principal amount of at least $180.0 million, consisting of (i) a $140.0 million reserve-based lending revolving loan and (ii) a $40.0 million term loan, each consistent with and subject to the RSA.

Capital Requirements

Oil and Natural Gas Segment Dispositions, Acquisitions, and Capital Expenditures. Most of our capital expenditures for this segment are discretionary and directed toward growth. 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 participated in the completion of 14 gross wells (3.07 net wells) drilled by other operators in the first three months of 2020 compared to 18 gross wells (5.57 net wells) drilled by Unit and other operators in which we participated in the first three months of 2019.

Capital expenditures for oil and gas properties on the full cost method for the first three months of 2020 by this segment, excluding $0.2 million for acquisitions and a $3.4 million reduction in the ARO liability, totaled $7.7 million. Capital expenditures for the first three months of 2019, excluding $1.6 million for acquisitions and an $4.7 million increase in the ARO liability, totaled $90.1 million.

For 2020, we do not currently have any plans to drill wells pending our ability to refinance or restructure our debt.

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Contract Drilling Segment Dispositions, Acquisitions, and Capital Expenditures. During the first quarter of 2019, we completed construction and placed into service our 12th and 13th BOSS drilling rigs. One was delivered to an existing third-party operator in Wyoming. Two additional BOSS drilling rigs under contract with the same customer were also extended. The other BOSS drilling rig was delivered to a new customer in the Permian Basin. This was following an early termination by the original third-party operator before the drilling rig’s completion. Our 14th BOSS drilling rig was completed and placed into service in December of 2019 for a third-party under a long term contract.

We have no commitments or plans to build any additional BOSS drilling rigs in 2020.

For 2020, we do not currently have an approved capital plan for this segment. Capital expenditures incurred would be within anticipated cash flows. We have spent $2.2 million for capital expenditures during the first three months of 2020, compared to $17.0 million for capital expenditures during the first three months of 2019.

Mid-Stream Dispositions, Acquisitions, and Capital Expenditures. At the Cashion processing facility in central Oklahoma, total throughput volume for the first quarter of 2020 averaged approximately 81.5 MMcf per day and total production of natural gas liquids averaged approximately 315,000 gallons per day. Through the first quarter of 2020, we continued to connect new wells to this system for third party producers. Since the first of this year, we connected seven new wells to this system from producers. The new 60 MMcf per day Reeding processing facility is operational and we brought the recently acquired mid-continent production to this facility for processing beginning April 1, 2020. The total processing capacity on the Cashion system is 105 MMcf per day.

In the Appalachian region at the Pittsburgh Mills gathering system, average gathered volume for the first quarter of 2020 was 145.1 MMcf per day while the average gathered volume for March 2020 was approximately 149.9 MMcf per day. During the first quarter of 2020, we added three new infill wells to this system. One additional new infill well began flowing at the beginning of the second quarter. With these four new wells connected to the Pittsburgh Mills system, gathered volume has increase to approximately 190 MMcf per day.

At the Hemphill processing facility in the Texas panhandle, average total throughput volume for the first quarter of 2020 was 56.2 MMcf per day and total production of natural gas liquids declined to approximately 126,000 gallons per day due to lower wellhead volume and operating in full ethane rejection due to lower prices. We connected no new wells to this system in the first quarter of 2020.

At the Segno gathering system in East Texas, the average throughput volume for the first quarter of 2020 was 51.7 MMcf per day. During the first quarter of 2020, we connected no new wells to this system.

During the first three months of 2020, our mid-stream segment incurred $5.0 million in capital expenditures as compared to $15.3 million in the first three months of 2019. For 2020, our estimated capital expenditures will be approximately $28.0 million.

Contractual Commitments

At March 31, 2020, 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)
$ 860,796    $ 821,660    $ 2,028    $ 37,108    $ —   
Operating leases (2)
6,767    4,128    2,548    32    59   
Finance lease interest and maintenance (3)
2,066    1,989    77    —    —   
Firm transportation commitments (4)
1,273    643    630    —    —   
Total contractual obligations $ 870,902    $ 828,420    $ 5,283    $ 37,140    $ 59   
_______________________ 
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 Unit credit agreement and includes interest calculated using our March 31, 2020 interest rates of 6.625% for the Notes and 2.9% for our Unit credit agreement and 2.7% for our Superior credit agreement. At March 31, 2020, our Unit credit agreement and the Notes are reflected as a current liability in our consolidated balance sheet due to the uncertainty regarding the company's ability to repay or refinance the Notes before November 16, 2020. The outstanding Unit
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credit agreement balance as of March 31, 2020 was $124.0 million. Our Superior credit agreement has a maturity date of May 10, 2023 and an outstanding balance of $37.0 million as of March 31, 2020.

2.We lease certain office space, land and equipment, including pipeline equipment and office equipment under the terms of operating leases under ASC 842 expiring through March 2032. We also have short-term lease commitments of $0.4 million. This is lease office space or yards in Edmond and Oklahoma City, Oklahoma; Houston, Texas; Englewood, Colorado; and Pinedale, Wyoming under the terms of operating leases expiring through October 2020. Additionally, we have several equipment leases and lease space on short-term commitments to stack excess drilling rig equipment and production inventory.

3.Maintenance and interest payments are included in our finance lease agreements. The finance leases are discounted using annual rates of 4.00%. Total maintenance and interest remaining are $1.9 million and $0.2 million, respectively.

4.We have firm transportation commitments to transport our natural gas from various systems for approximately $0.6 million over the next twelve months and $0.6 million for the two years thereafter.

During the second quarter of 2018, as part of the Superior transaction, we entered into a contractual obligation that commits us to spend $150.0 million to drill wells in the Granite Wash/Buffalo Wallow area over three years starting January 1, 2019. This amount is included in our future drilling plans. For each dollar of the $150.0 million we do not spend (over the three-year period), we would forgo receiving $0.58 of future distributions from our 50% ownership interest in our consolidated mid-stream subsidiary. At March 31, 2020, if we elected not to drill or spend any additional money in the designated area before December 31, 2021, the maximum amount we could forgo from distributions would be $72.7 million. We have no plans to drill in 2020. Total spent towards the $150.0 million as of March 31, 2020 was $24.7 million.

At March 31, 2020, 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)
$ 5,303    Unknown Unknown Unknown Unknown
Separation benefit plans (2)
$ 9,719    $ 3,051    Unknown Unknown Unknown
Asset retirement liability (3)
$ 63,819    $ 1,470    $ 3,319    $ 4,007    $ 55,023   
Gas balancing liability (4)
$ 3,838    Unknown Unknown Unknown Unknown
Workers’ compensation liability (5)
$ 11,178    $ 5,063    $ 1,350    $ 855    $ 3,910   
Finance lease obligations (6)
$ 6,354    $ 5,852    $ 502    $ —    $ —   
Contract liability (7)
$ 6,343    $ 2,881    $ 3,428    $ 12    $ 22   
_______________________ 
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 have recorded a liability for future estimated payments related to workers’ compensation claims primarily associated with our contract drilling segment.

6.The amount includes commitments under finance lease arrangements for compressors in Superior.

7.We have recorded a liability related to the timing of revenue recognized on certain demand fees for Superior.

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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.

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 March 31, 2020, based on our first quarter 2020 average daily production, the approximated percentages of our production under derivative contracts are as follows:
2020
Daily natural gas production 26  %

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 March 31, 2020 evaluation, we believe the risk of non-performance by our counterparties is not material. At March 31, 2020, the fair values of the net assets we had with each of the counterparties to our commodity derivative transactions are as follows:
  March 31, 2020
  (In millions)
Bank of Montreal $ 0.4   
Bank of America 0.2   
Total net assets $ 0.6   
If a legal right 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 March 31, 2020, we recorded the fair value of our commodity derivatives on our balance sheet as current derivative assets of $0.7 million and non-current derivative liabilities of $0.1 million. At December 31, 2019, we recorded the fair value of our commodity derivatives on our balance sheet as current derivative assets of $0.6 million and non-current derivative liabilities of less than $0.1 million.

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 March 31 are as follows:
Three Months Ended
March 31,
2020 2019
  (In thousands)
Gain (loss) on derivatives:
Gain (loss) on derivatives, included are amounts settled during the period of $551 and $2,656, respectively $ 483    $ (6,932)  
$ 483    $ (6,932)  

Stock and Incentive Compensation

During the first three months of 2020, we granted no shares of restricted stock. We recognized compensation expense of $2.5 million for all of our restricted stock. We did not capitalize any compensation cost to oil and natural gas properties since we are currently not drilling.

During the first three months of 2019, we granted awards covering 1,349,743 shares of restricted stock. These awards had an estimated fair value as of their grant date of $21.7 million. Compensation expense will be recognized over the three-year vesting periods, and during the three months of 2019, we recognized $0.9 million in compensation expense and capitalized $0.1
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million for these awards. During the first three months of 2019, we recognized compensation expense of $3.8 million for all of our restricted stock and stock options and capitalized $0.6 million of compensation cost to 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 to limit, to the extent feasible, per occurrence and aggregate exposure to certain types of claims. There is no assurance that the insurance coverage we have will protect us against liability from all potential consequences. If insurance coverage becomes more expensive, we may choose to self-insure, decrease our limits, raise our deductibles, or any combination of these rather than pay higher premiums.

Oil and Natural Gas Limited Partnerships and Other Entity Relationships

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

New Accounting Pronouncements

Reference Rate Reform (Topic 848)—Facilitation of the Effects of Reference Rate Reform on Financial Reporting. The FASB issued 2020-04 which provides optional expedients and exceptions for applying generally accepted accounting principles to contract modifications, subject to meeting certain criteria, that reference LIBOR or another reference rate expected to be discontinued. The ASU is intended to help stakeholders during the global market-wide reference rate transition period. The amendment will be in effect for a limited time through December 31, 2022.

Adopted Standards

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

Fair Value Measurement (Topic 820): Disclosure Framework—Changes to the Disclosure Requirements for Fair Value Measurement. The FASB issued ASU 2018-13 to modify the disclosure requirements in Topic 820. Part of the disclosures were removed or modified, and other disclosures were added. The amendment will be effective for reporting periods beginning after December 15, 2019. Early adoption is permitted. The adoption of this guidance did not have a material impact on our consolidated financial statements or related disclosures.
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Results of Operations
Quarter Ended March 31, 2020 versus Quarter Ended March 31, 2019
Provided below is a comparison of selected operating and financial data:
  Quarter Ended March 31,
Percent
Change (1)
  2020 2019
(In thousands unless otherwise specified)
Total revenue $ 122,376    $ 189,691    (35) %
Net loss $ (803,674)   $ (2,282)   NM   
Net income (loss) attributable to non-controlling interest $ (33,180)   $ 1,222    NM   
Net loss attributable to Unit Corporation $ (770,494)   $ (3,504)   NM   
Oil and Natural Gas:
Revenue $ 48,522    $ 86,095    (44) %
Operating costs excluding depreciation, depletion, and amortization $ 30,663    $ 32,714    (6) %
Depreciation, depletion, and amortization $ 36,728    $ 35,767    3  %
Impairment of oil and natural gas properties $ 267,836    $ —    —  %
Average oil price (Bbl) $ 44.92    $ 56.29    (20) %
Average NGLs price (Bbl) $ 3.27    $ 16.06    (80) %
Average natural gas price (Mcf) $ 1.23    $ 2.52    (51) %
Oil production (MBbls) 674    688    (2) %
NGL production (MBbls) 965    1,207    (20) %
Natural gas production (MMcf) 10,802    13,371    (19) %
Depreciation, depletion, and amortization rate (Boe) $ 10.20    $ 8.28    23  %
Contract Drilling:
Revenue $ 36,632    $ 51,155    (28) %
Operating costs excluding depreciation $ 25,449    31,401    (19) %
Depreciation $ 11,745    $ 12,699    (8) %
Impairment of contract drilling equipment $ 410,126    $ —    —  %
Percentage of revenue from daywork contracts 100  % 100  % —  %
Average number of drilling rigs in use 18.7    31.4    (40) %
Average dayrate on daywork contracts $ 19,535    $ 18,339    7  %
Mid-Stream:
Revenue $ 37,222    $ 52,441    (29) %
Operating costs excluding depreciation and amortization $ 27,611    $ 39,355    (30) %
Depreciation and amortization $ 12,273    $ 11,726    5  %
Impairment $ 63,962    $ —    —  %
Gas gathered--Mcf/day 389,243    449,916    (13) %
Gas processed--Mcf/day 166,331    161,748    3  %
Gas liquids sold--gallons/day 527,673    650,614    (19) %
Corporate and Other:
General and administrative expense $ 11,553    $ 9,741    19  %
Other depreciation $ 871    $ 1,934    (55) %
Loss on disposition of assets $ (390)   $ (1,615)   (75.9) %
Other income (expense):
Interest income $ —    $ 41    (100) %
Interest expense, net $ (13,257)   $ (8,579)   (55) %
Gain (loss) on derivatives $ 483    $ (6,932)   107  %
Other $ 60    $ 5    NM   
Income tax benefit $ (3,425)   $ (444)   NM   
Average interest rate 6.3  % 6.6  % (5) %
Average long-term debt outstanding $ 761,502    $ 689,659    10  %
_________________________
1.NM – A percentage calculation is not meaningful due to a zero-value denominator or a percentage change greater than 200.
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Oil and Natural Gas

Oil and natural gas revenues decreased $37.6 million or 44% in the first quarter of 2020 as compared to the first quarter of 2019 primarily due to lower commodity prices and volumes. In the first quarter of 2020, as compared to the first quarter of 2019, oil production decreased 2%, natural gas production decreased 19%, and NGLs production decreased 20%. Including derivatives settled, average oil prices decreased 20% to $44.92 per barrel, average natural gas prices decreased 51% to $1.23 per Mcf, and NGLs prices decreased 80% to $3.27 per barrel.

Oil and natural gas operating costs decreased $2.1 million or 6% between the comparative first quarters of 2020 and 2019 primarily due to lower lease operating expenses (LOE), gross production taxes, and general and administrative expense.

Depreciation, depletion, and amortization (DD&A) increased $1.0 million or 3% due primarily to a 23% increase in the DD&A rate partially offset by a 17% decrease in equivalent production. The increase in our DD&A rate in the first quarter of 2020 compared to the first quarter of 2019 resulted primarily from write off of undeveloped leasehold in the first quarter of 2020.

During the first quarter of 2020, we recorded a non-cash ceiling test write-down of $267.8 million pre-tax ($220.8 million, net of tax). We did not have a ceiling test write-down in the first quarter of 2019. We recorded expense of $17.6 million related to the write down of our salt water disposal asset that we consider abandoned in first quarter of 2020.

Contract Drilling

Drilling revenues decreased $14.5 million or 28% in the first quarter of 2020 versus the first quarter of 2019. The decrease was due primarily to a 40% decrease in the average number of drilling rigs in use partially offset by a 7% increase in the average dayrate. Average drilling rig utilization decreased from 31.4 drilling rigs in the first quarter of 2019 to 18.7 drilling rigs in the first quarter of 2020.

Drilling operating costs decreased $6.0 million or 19% between the comparative first quarters of 2020 and 2019. The decrease was due primarily to less drilling rigs operating. Contract drilling depreciation decreased $1.0 million or 8% in the first quarter of 2020 versus the first quarter of 2019 also due to less drilling rigs operating.

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

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

Mid-Stream

Our mid-stream revenues decreased $15.2 million or 29% in the first quarter of 2020 as compared to the first quarter of 2019 due primarily to lower gas, NGLs, and condensate prices and decreased liquids sales volumes. Gas processed volumes per day increased 3% between the comparative quarters primarily due to connecting new wells and adding the volume from a new acquisition to our Cashion gathering system. Gas gathered volumes per day decreased 13% between the comparative quarters due to declining volumes from most of our major systems offset by higher volume on our Cashion system.

Operating costs decreased $11.7 million or 30% in the first quarter of 2020 compared to the first quarter of 2019 primarily due to lower purchase prices. Depreciation and amortization increased $0.5 million, or 5%, primarily due to new capital assets placed in service including the new mid-continent acquisition.

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We determined that the carrying value of certain long-lived asset groups located in southern Kansas, and central Oklahoma where lower pricing is expected to impact drilling and production levels, are not recoverable and exceeded their estimated fair value. Based on the estimated fair value of the asset groups, we recorded non-cash impairment charges of $64.0 million.

General and Administrative

Corporate general and administrative expenses increased $1.8 million or 19% in the first quarter of 2020 as compared to the first quarter of 2019 primarily due to higher consulting and outside legal fees partially offset by lower employee costs. We paid $3.1 million in restructuring fees in the first quarter of 2020.

Loss on Disposition of Assets

There was a $0.4 million loss on disposition of assets in the first quarter of 2020 primarily related to due to the sale of drill pipe and other drilling equipment. For the first quarter of 2019, we had a loss of $1.6 million for the disposition of assets primarily due to the sale of three drilling rigs and other drilling rig components and vehicles.

Other Income (Expense)

Interest expense, net of capitalized interest, increased $4.7 million between the comparative first quarters of 2020 and 2019 due primarily to an 10% increase in average long-term debt outstanding and no capitalized interest in the first quarter of 2020 partially offset by a lower average interest rate. We capitalized interest based on the net book value associated with undeveloped leasehold not being amortized, constructing additional drilling rigs, and constructing gas gathering systems. Because we are not currently undergoing any capital projects, we had no capitalized interest for the first quarter of 2020 compared to $4.2 million for the first quarter of 2019 and was netted against our gross interest of $13.3 million and $12.8 million for the first quarters of 2020 and 2019, respectively. Our average interest rate decreased from 6.6% in the first quarter of 2019 to 6.3% in the first quarter of 2020 and our average debt outstanding increased $71.8 million in the first quarter of 2020 compared to the first quarter of 2019 primarily due to additional capital expenditures over the last 12 months.

Gain (Loss) on Derivatives

Gain (loss) on derivatives increased by $7.4 million primarily due to fluctuations in forward prices used to estimate the fair value in mark-to-market accounting.

Income Tax Benefit

Income tax benefit was a benefit of $3.4 million in the first quarter of a benefit of 2020 compared to $0.4 million in the first quarter of 2019 primarily due to decreased pre-tax income. Our effective tax rate was 0.42% for the first quarter of 2020 compared to 16.3% for the first quarter of 2019. The rate change was primarily due to our income tax benefit for the first quarter of 2020 being offset by a valuation allowance. Current income tax benefit was $0.9 million for the first quarter of 2020 which was related to the acceleration of our Alternative Minimum Tax (AMT) Minimum Credit under the Coronavirus Aid, Relief, and Economic Security Act (CARES Act). We did not have a current income tax benefit for the first quarter of 2019. We paid no income taxes in the first quarter of 2020.

Item 3. Quantitative and Qualitative Disclosure 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 three months 2020 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 $351,000 per month ($4.2 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 $214,000 per month ($2.6 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 $310,000 per month ($3.7 million annualized) change in our pre-tax operating cash flow.

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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. As a result of the commencement of the Chapter 11 Cases, our ability to enter into derivative transactions are limited.

At March 31, 2020, these derivatives were outstanding:
Term Commodity Contracted Volume Weighted Average 
Fixed Price 		Contracted Market
Apr'20 - Dec'20 Natural gas - basis swap 30,000 MMBtu/day $(0.275)   NGPL TEXOK
Apr'20 - Dec'20 Natural gas - basis swap 20,000 MMBtu/day $(0.455)   PEPL
Jan'21 - Dec'21 Natural gas - basis swap 30,000 MMBtu/day $(0.215)   NGPL TEXOK
Apr'20 - Dec'20 Natural gas - three-way collar 30,000 MMBtu/day $2.50 - $2.20 - $2.80    IF - NYMEX (HH)

After March 31, 2020, the following derivatives were entered into:
Term Commodity Contracted Volume Weighted Average Fixed Price Contracted Market
May'20 - Sep'20 Crude oil - collar 112,000 Bbl/month $20.00 - $26.50    WTI - NYMEX

Interest Rate Risk. Our interest rate exposure relates to our long-term debt under our credit agreements and the 2021 Notes. The 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 credit agreements 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 variable rate in the first three months of 2020, a 1% increase in the floating rate would reduce our annual pre-tax cash flow by approximately $1.3 million. Under our Notes, we pay a fixed rate of interest of 6.625% per year (payable semi-annually in arrears on May 15 and November 15 of each year). On May 15, 2020, the company elected not to make the approximate $21.5 million semi-annual interest payment due on the Notes. For further information, see Note 8 – Long-Term Debt and Other Long-Term Liabilities—Long-Term Debt—6.625% Senior Subordinated Notes.

Item 4. Controls and Procedures

Our management, including our Chief Executive Officer (CEO) and Chief Financial Officer (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 (Exchange Act)) (Disclosure Controls) 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 CEO and CFO, of the effectiveness of the design and operation of our disclosure controls and procedures under Exchange Act Rule 13a-15. Based on that evaluation, our CEO and CFO concluded that our disclosure controls and procedures are effective as of March 31, 2020 at a reasonable assurance level.

Changes in Internal Controls. There were no changes in our ICFR during the quarter ended March 31, 2020, that materially affected our ICFR or are reasonably likely to materially affect it, as defined in Rule 13a – 15(f) under the Exchange Act.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

Voluntary Petitions under Chapter 11 of the Bankruptcy Code

On May 22, 2020, the Debtors filed the Bankruptcy Petitions seeking relief under the Bankruptcy Code. The
commencement of the Chapter 11 Cases automatically stayed all of the proceedings and actions against the Debtors (other than
certain regulatory enforcement matters). For further information, please see Note 2 – Chapter 11 Proceedings, Liquidity, and Ability to Continue as a Going Concern—Voluntary Reorganization Under Chapter 11 of the Bankruptcy Code.

Panola Independent School District No. 4, et al. v. Unit Petroleum Company, No. CJ-07-215, District Court of Latimer County, Oklahoma.

Panola Independent School District No. 4, Michael Kilpatrick, Gwen Grego, Carla Lessel, Thelma Christine Pate, Juanita Golightly, Melody Culberson, and Charlotte Abernathy are the Plaintiffs and are royalty owners in oil and gas drilling and spacing units for which the company’s exploration segment distributes royalty. The Plaintiffs’ central allegation is that the company’s exploration segment has underpaid royalty obligations by deducting post-production costs or marketing related fees. Plaintiffs sought to pursue the case as a class action on behalf of persons who receive royalty from us for our Oklahoma production. We have asserted several defenses including that the deductions are permitted under Oklahoma law. We have also asserted that the case should not be tried as a class action due to the materially different circumstances that determine what, if any, deductions are taken for each lease. On December 16, 2009, the trial court entered its order certifying the class. On May 11, 2012 the Oklahoma 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, Plaintiffs filed a second request to certify a smaller class of royalty owners than their first attempt. Since then, the Plaintiffs have further amended their proposed class to just include royalty owners under certain leases in Latimer, Le Flore, and Pittsburg Counties, Oklahoma. On July 29, 2019, the trial court denied the Plaintiffs’ second motion for class certification. Plaintiffs are appealing the order denying class certification, which is now stayed due to the bankruptcy filing.

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 late paid oil and gas proceeds under Oklahoma’s Production Revenue Standards Act. The lawsuit seeks actual and punitive damages, an accounting, disgorgement, injunctive relief, and attorney fees. Plaintiff is seeking relief on behalf of royalty and working interest owners in our Oklahoma wells. 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. Further, Plaintiff’s requests for relief beyond payment of interest allegedly due are barred by statute. We filed a summary judgment motion as to named Plaintiff’s individual claims. On February 28, 2020, the Court granted us a summary judgment on several of the Plaintiff's individual claims, including standing, but found that some claims presented fact issues. the Plaintiff filed a motion with the Court asking it to reconsider its ruling. On May 4, 2020, the Court reversed its summary judgment ruling on our challenge to Plaintiff's standing and how interest should be calculated. Plaintiff subsequently filed its motion for class certifications, which is now stayed due to the bankruptcy filing.

Chieftain Royalty Company v. Unit Petroleum Company, No. CJ-16-230, District Court of LeFlore County, Oklahoma.

On November 3, 2016, a putative class action lawsuit was filed against Unit Petroleum Company styled Chieftain Royalty Company v. Unit Petroleum Company in LeFlore County, Oklahoma. Plaintiff alleges that Unit Petroleum breached its duty to pay royalties on natural gas used for fuel off the lease premises. The lawsuit seeks actual and punitive damages, an accounting, injunctive relief, and attorney’s fees. Plaintiff is seeking relief on behalf of Oklahoma citizens who are or were royalty owners in our Oklahoma wells. Unit has numerous defenses including that it has fulfilled its lease royalty obligations with respect to gas consumed as fuel. As to the propriety of class certification, we are defending on the grounds that the class involves thousands of different leases that have to be individually examined and construed, making class-wide liability determinations
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impossible. On June 26, 2019, Plaintiff moved for class certification. On February 6, 2020, the Court entered its order certifying the class. We have appealed the Court's order, which is now stayed due to the bankruptcy filing.

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, 2019, 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.

Other than as set forth below, 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, 2019.

The Chapter 11 Cases may have a material adverse impact on our business, financial condition, results of operations, and cash flows. In addition, the filing of the Chapter 11 Cases has had a material adverse impact on the trading price of our common stock and ultimately is expected to result in the cancellation of our common stock under the Plan.

In August 2019, we engaged an investment bank to advise the company in connection with an exchange offer with respect to the Notes and the consideration of other potential liability management transactions. Once it became evident that the exchange offer was not going to be successful and our other cost reduction and liquidity maximization efforts would be insufficient to solve the company’s liquidity and near-term maturity issues, we subsequently expanded the investment bank’s retention to explore various financial and restructuring alternatives, including a potential in-court or out-of-court restructuring, and engaged legal and restructuring advisors. These efforts led to the execution of the RSA and commencement of the Chapter 11 Cases on May 22, 2020.

The Chapter 11 Cases could have a material adverse effect on our business, financial condition, results of operations and liquidity. Bankruptcy Court protection also may make it more difficult to retain management and the key personnel necessary to our business. In addition, during the period of time we are involved in a bankruptcy proceeding, our clients and suppliers might lose confidence in our ability to reorganize our business successfully and may discontinue conducting business with us or seek to establish alternative commercial relationships.

Other significant risks include or relate to the following:
•our ability to obtain the Bankruptcy Court’s approval with respect to motions or other requests made to the Bankruptcy Court in the Chapter 11 Cases, including maintaining strategic control as debtor-in-possession;
•delays in the Chapter 11 Cases;
•our ability to consummate the Plan;
•our ability to achieve our stated goals and continue as a going concern;
•the effects of the filing of the Chapter 11 Cases on our business and the interest of various constituents, including our shareholders, customers, suppliers, service providers, and employees;
•the high costs of bankruptcy proceedings and related advisory costs to effect our reorganization;
•our ability to maintain relationships with customers, suppliers, employees and other third parties as a result of the Chapter 11 Cases;
•our ability to maintain contracts that are critical to our operations;
•our ability to fund and execute our business plan;
•our ability to obtain acceptable and appropriate financing;
•Bankruptcy Court rulings in the Chapter 11 Cases as well as the outcome of the Chapter 11 Cases in general;
•the length of time that we will operate with Chapter 11 protection and the continued availability of operating capital during the pendency of the Chapter 11 Cases;
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•our ability to confirm and consummate a plan of reorganization with respect to the Chapter 11 Cases, views and objections of creditors and other parties in interest that may make it difficult to consummate a plan in a timely manner;
•the ability of third parties to seek and obtain Bankruptcy Court approval to terminate or shorten the exclusivity period for us to propose and confirm a plan of reorganization, to appoint a U.S. trustee or to convert the Chapter 11 Cases to cases under Chapter 7 of the Bankruptcy Code (Chapter 7);
•third-party motions in the Chapter 11 Cases, which may interfere with our ability to consummate the Plan; and
•the potential adverse effects of the Chapter 11 Cases on our liquidity and results of operations.

Because of the risks and uncertainties associated with the Chapter 11 Cases, we cannot predict or quantify the ultimate impact that events occurring during the Chapter 11 Cases may have on our business, cash flows, liquidity, financial condition and results of operations, nor can we predict the ultimate impact that events occurring during the Chapter 11 Cases may have on our corporate or capital structure, although we expect such proceedings to result in the cancellation of our common stock.

The filing of the Chapter 11 Cases has had a material adverse effect on the trading price of our common stock. On May 26, 2020, we received notification from the NYSE that our common stock had been suspended from trading effective on that same day and that NYSE had determined to commence proceedings to delist our common stock. Our common stock began to be quoted on the OTC Pink Marketplace under the symbol “UNTCQ” on May 27, 2020. The closing price of our common stock was $0.05 per share on May 27, 2020, compared with $0.24 per share on May 22, 2020, the last trading day before we announced the filing of the Chapter 11 Cases. During the pendency of the Chapter 11 Cases, the trading price of our common stock could continue to fall.

Delays in the Chapter 11 Cases may increase the risks of our being unable to reorganize our business and emerge from bankruptcy and may increase our costs associated with the bankruptcy process.

The RSA contemplates the consummation of the Plan through an orderly pre-negotiated plan of reorganization, but there can be no assurance that we will be able to consummate the Plan. A prolonged Chapter 11 proceeding could adversely affect our relationships with customers, suppliers, service providers, and employees, among other third parties, which in turn could adversely affect our business, competitive position, financial condition, liquidity and results of operations and our ability to continue as a going concern. A weakening of our financial condition, liquidity and results of operations could adversely affect our ability to implement the Plan (or any other plan of reorganization). If we are unable to consummate the Plan, we may be forced to liquidate our assets.

In addition, the occurrence of the effective date of the Plan is subject to certain conditions and requirements that may not be satisfied or waived.

The Plan may not become effective.

The Plan may not become effective because it is subject to the satisfaction of certain conditions precedent, some of which are beyond our control. There can be no assurance that such conditions will be satisfied or waived and, therefore, that the Plan will become effective and that we will emerge from the Chapter 11 Cases as contemplated by the Plan. If the effective date of the Plan is delayed, we may not have sufficient cash available to operate our business. In that case, we may need new or additional post-petition financing, which may increase the cost of consummating the Plan. There is no assurance of the terms on which such financing may be available or if such financing will be available. If the transactions contemplated by the Plan are not completed, it may become necessary to amend the Plan. The terms of any such amendment are uncertain and could result in material additional expense and result in material delays to the Chapter 11 Cases.

We may not be able to obtain Bankruptcy Court confirmation of the Plan or may have to modify the terms of the Plan.

Even if the Plan is approved by each class of holders of claims and interests entitled to vote (a Voting Class), the Bankruptcy Court, which, as a court of equity, may exercise substantial discretion and may choose not to confirm the Plan. Section 1129 of the Bankruptcy Code requires, among other things, a showing that confirmation of a Chapter 11 plan will not be followed by liquidation or the need for further financial reorganization, and that the value of distributions to dissenting holders of claims and interests will not be less than the value such holders would receive if we, the debtors, liquidated under Chapter 7. Although we believe that the Plan will satisfy such tests, there can be no assurance that the Bankruptcy Court will reach the same conclusion.

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Confirmation of the Plan will also be subject to certain conditions. These conditions may not be met and there can be no assurance that the Majority Restructuring Support Parties (as defined in the Plan) will agree to modify or waive such conditions to the extent required by the RSA or Plan, as applicable. Further, changed circumstances may necessitate changes to the Plan. Any such modifications could result in less favorable treatment than the treatment currently anticipated to be included in the Plan based upon the agreed terms of the RSA. Such less favorable treatment could include a distribution of property (including the new common stock that would be issued upon our emergence from bankruptcy) to the class affected by the modification of a lesser value than currently anticipated to be included in the Plan or no distribution of property whatsoever under the Plan. Changes to the Plan may also delay the confirmation of the Plan and our emergence from bankruptcy, which could result in, among other things, incurred costs and expenses to the estates of the debtors.

Even if a Chapter 11 plan of reorganization is consummated, we may not be able to achieve our stated goals and continue as a going concern.

Even if the Plan, or any other plan of reorganization, is consummated, we may continue to face a number of risks, such as further deterioration or other changes in economic conditions, changes in our industry, changes in demand for our services and increasing expenses. Accordingly, we cannot guarantee that the Plan, or any other plan of reorganization, will achieve our stated goals.

Furthermore, even if our debts are reduced through a plan of reorganization, we may need to raise additional funds through public or private debt or equity financing or other various means to fund our business after the completion of the Chapter 11 Cases. Our access to additional financing may be limited, if it is available at all. Therefore, adequate funds may not be available when needed or may not be available on favorable terms.

The Plan or another plan of reorganization that we may implement will be based upon assumptions and analyses developed by us. If these assumptions and analyses prove to be incorrect, we may not be able to successfully execute such plan.

The Plan or any other plan of reorganization that we may implement will affect both our capital structure and the ownership, structure and operation of our business and will reflect assumptions and analyses based on our experience and perception of historical trends, current conditions and expected future developments, as well as other factors that we consider appropriate under the circumstances. Whether actual future results and developments will be consistent with our expectations and assumptions depends on a number of factors, including but not limited to (i) our ability to substantially change our capital structure; (ii) our ability to obtain adequate liquidity and financing sources; (iii) our ability to maintain customers’ confidence in our viability as a continuing entity and to attract and retain sufficient business from them; (iv) our ability to retain key employees, and (v) the overall strength and stability of general economic conditions and conditions of the our industry. The failure of any of these factors could materially adversely affect the successful reorganization of our business.

In addition, the Plan or any other plan of reorganization, will rely upon financial projections, including with respect to revenues, capital expenditures, debt service and cash flow. Financial forecasts are necessarily speculative, and it is possible that one or more of the assumptions and estimates that are the basis of these financial forecasts will not be accurate. In our case, the forecasts are even more speculative than normal, because they involve fundamental changes in the nature of our capital structure. Accordingly, we expect that our actual financial condition and results of operations may differ, perhaps materially, from what we have anticipated. Consequently, there can be no assurance that the results or developments contemplated by any plan of reorganization we may implement will occur or, even if they do occur, that they will have the anticipated effects on us or our business or operations. The failure of any such results or developments to materialize as anticipated could materially adversely affect the successful execution of the Plan or any other plan of reorganization.

Our cash flows may not provide sufficient liquidity during the Chapter 11 Cases. Our long-term liquidity requirements and the adequacy of our capital resources are difficult to predict at this time.

Our ability to fund our operations and our capital expenditures requires a significant amount of cash. Our current principal sources of liquidity include the available borrowing capacity under the DIP credit facility and cash flow generated from operations. If our cash flow from operations decreases, we may not have the ability to expend the capital necessary to maintain our current operations, negatively impacting our future revenues.

We face uncertainty regarding the adequacy of our liquidity and capital resources and have limited, if any, access to additional financing. In addition to the cash requirements necessary to fund ongoing operations, we have incurred significant professional fees and other costs in connection with preparation for the Chapter 11 proceedings and expect that we will continue to incur significant professional fees and costs throughout our Chapter 11 proceedings. As a result, we may not be able to comply with the covenants of the DIP credit facility, and our cash on hand and cash flow from operations may not be
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sufficient to continue to fund our operations and allow us to satisfy our obligations related to the Chapter 11 Cases until we are able to emerge from the Chapter 11 Cases.

Our liquidity, including our ability to meet our ongoing operational obligations, is dependent upon, among other things: (i) our ability to comply with the terms and conditions of the DIP credit agreement, (ii) our ability to comply with the terms and conditions of any cash collateral order that may be entered by the Bankruptcy Court in connection with the Chapter 11 Cases, (iii) our ability to maintain adequate cash on hand, (iv) our ability to generate cash flow from operations, (v) our ability to confirm and consummate the Plan or another alternative restructuring transaction and (vi) the cost, duration and outcome of the Chapter 11 Cases.

We may be unable to comply with restrictions or with budget, liquidity, or other covenants imposed by the agreements governing the DIP credit facility. Such non-compliance could result in an event of default under the terms of the DIP credit facility that, if not cured or waived, would have a material adverse effect on our business, financial condition and results of operations.

The DIP credit facility requires that we comply with general affirmative and negative covenants such as prohibiting us from incurring or permitting debt, investments, liens or dispositions unless specifically permitted. Our ability to comply with these provisions may be affected by events beyond our control and our failure to comply, or obtain a waiver in the event we cannot comply with a covenant, could result in an event of default under the DIP credit facility and permit the lenders thereunder to accelerate the loans and otherwise exercise remedies allowable by the agreements governing the DIP credit facility.

Competing plans of reorganization, which could have less favorable terms or result in significant litigation and expenses.

Parties in interest may seek to file alternative plans of reorganization. An alternative plan of reorganization could contemplate us continuing as a going concern, us being broken up, us or our assets being acquired by a third party, us being merged with a competitor, or some other proposal. There can be no assurances that recoveries under any such alternative plan would be as favorable to creditors as the Plan. In addition, the proposal of competing plans of reorganization may entail significant litigation and significantly increase the expenses of administration of the Chapter 11 Cases, which could deplete creditor recoveries under any plan.

As a result of the Chapter 11 Cases, our historical financial information may not be indicative of our future performance, which may be volatile.

During the Chapter 11 Cases, we expect our financial results to continue to be volatile as restructuring activities and expenses significantly impact our consolidated financial statements. As a result, our historical financial performance is likely not indicative of our financial performance after the date of the filing of the Chapter 11 Cases. In addition, if we emerge from Chapter 11, the amounts reported in subsequent consolidated financial statements may materially change relative to our historical consolidated financial statements, including as a result of revisions to our operating plans pursuant to the Plan. We expect that we will be required to adopt the fresh start accounting rules, in which case our assets and liabilities will be recorded at fair value as of the fresh start reporting date, which may differ materially from the recorded values of assets and liabilities on our consolidated balance sheets and our financial results after the application of fresh start accounting may be different from historical trends.

Trading in our securities during the pendency of the Chapter 11 Cases is highly speculative and poses substantial risks. The Plan will result in the cancellation of our common stock.

Under the Plan, all existing equity interests in the company will be extinguished. Each holder of our common stock that does not opt out of the releases under the Plan will receive its pro rata share of seven-year warrants to purchase an aggregate of 12.5% of the new common shares of reorganized Unit. Amounts invested by the holders of our common stock will not be recoverable and such securities will have no value other than the right to receive the warrants under the Plan. Trading prices for our common stock bear no relationship to the actual recovery, if any, by the holders thereof in the Chapter 11 Cases. Accordingly, we urge extreme caution with respect to existing and future investments in our existing common stock.

Our common stock is quoted on the OTC Pink, and thus may have a limited market and lack of liquidity.

Our common stock is quoted on the OTC Pink, which may have an unfavorable impact on our stock price and liquidity. The OTC Pink Marketplace is a significantly more limited market than the NYSE or The Nasdaq Stock Market. The quotation of our shares on such marketplace may result in a less liquid market available for existing and potential stockholders to trade
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shares of our common stock, could depress the trading price of our common stock, and could have a long-term adverse impact on our ability to raise capital in the future. There can be no assurance that there will be an active market for our shares of common stock, either now or in the future, or that stockholders will be able to liquidate their investment or liquidate it at a price that reflects the value of the business.

If the RSA is terminated, our ability to confirm and consummate the Plan could be materially and adversely affected.

The RSA contains a number of termination events, upon the occurrence of which certain parties to the RSA may terminate the agreement. If the RSA is terminated as to all parties thereto, each of the parties thereto will be released from its obligations in accordance with the terms of the RSA. Such termination may result in the loss of support for the Plan by the parties to the RSA, which could adversely affect our ability to confirm and consummate the Plan. If the Plan is not consummated, there can be no assurance that the Chapter 11 Cases would not be converted to Chapter 7 liquidation cases or that any new plan would be as favorable to holders of claims against the Debtors as contemplated by the RSA.

In certain instances, a Chapter 11 case may be converted to a case under Chapter 7 of the Bankruptcy Code.

Upon a showing of cause, the Bankruptcy Court may convert the Chapter 11 Cases to case(s) under Chapter 7. In such event, a Chapter 7 trustee would be appointed or elected to liquidate our assets for distribution in accordance with the priorities established by the Bankruptcy Code. We believe that liquidation under Chapter 7 would result in smaller distributions being made to our creditors than those provided for in the Plan because of (i) the likelihood that the assets would have to be sold or otherwise disposed of in a distressed fashion over a short period of time rather than in a controlled manner and as a going concern, (ii) additional administrative expenses involved in the appointment of a Chapter 7 trustee, and (iii) additional expenses and claims, some of which would be entitled to priority, that would be generated during the liquidation and from the rejection of executory contracts in connection with a cessation of operations.

We may be subject to claims that will not be discharged in the Chapter 11 Cases, which could have a material adverse effect on our financial condition and results of operations.

The Bankruptcy Code provides that the confirmation of a plan of reorganization discharges a debtor from substantially all debts arising before consummation of a plan of reorganization. With few exceptions, all claims that arose before May 22, 2020 or before consummation of the Plan (i) would be subject to compromise and/or treatment under the Plan and/or (ii) would be discharged in accordance with the Bankruptcy Code and the terms of the Plan. Any claims not ultimately discharged pursuant to the Plan could be asserted against the reorganized entities and may have an adverse effect on our financial condition and results of operations on a post-reorganization basis.

The Chapter 11 Cases limit the flexibility of our management team in running our business.

While we currently operate our business as debtors-in-possession under the supervision by the Bankruptcy Court, we may be required to obtain the approval of the Bankruptcy Court and, in some cases, the Majority Restructuring Support Parties, before engaging in activities or transactions outside the ordinary course of business. Bankruptcy Court approval of non-ordinary course activities entails preparation and filing of appropriate motions with the Bankruptcy Court, negotiation with the creditors’ committee (if any) and other parties-in-interest and one or more hearings. A creditors’ committee (if any) and other parties-in interest may be heard at any Bankruptcy Court hearing and may raise objections with respect to these motions.

This process may delay such-non ordinary course transactions and limit our ability to respond in a timely manner to adapt to changing market or industry conditions or to take advantage of certain opportunities. Furthermore, in the event the Bankruptcy Court does not approve a proposed activity or transaction, we would be prevented from engaging in activities and transactions that we believe to be beneficial to us.

The commencement of the Chapter 11 Cases has consumed and will continue to consume a substantial portion of the time and attention of our management and will impact how our business is conducted, which may have an adverse effect on our business and results of operations.

The requirements of the Chapter 11 Cases have consumed and will continue to consume a substantial portion of our management’s time and attention and leave them with less time to devote to the operation of our business. This diversion of attention may materially adversely affect the conduct of our business and, as a result, our financial condition and results of operations.

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We may experience employee attrition as a result of the Chapter 11 Cases.

As a result of the Chapter 11 Cases, we may experience employee attrition, and our employees may face considerable distraction and uncertainty. A loss of key personnel or material erosion of employee morale could adversely affect our business and results of operations. Our ability to engage, motivate and retain key employees or take other measures intended to motivate and incentivize key employees to remain with us through the pendency of the Chapter 11 Cases is limited by restrictions on implementation of incentive programs under the Bankruptcy Code. The loss of services of members of our senior management team could impair our ability to execute our strategy and implement operational initiatives, which could have a material adverse effect on our financial condition, liquidity and results of operations.

On the effective date of the Plan, the composition of our board of directors will change substantially.

Under the Plan, the composition of our board of directors will change substantially. Pursuant to the Plan, our new board of directors will consist of seven members, including (i) David T. Merrill, who will also serve as reorganized Unit’s CEO, (ii) one independent member mutually acceptable to the Debtors and the Majority Consenting Noteholders, and (iii) five members (including the chairman) selected by the Majority Consenting Noteholders. “Majority Consenting Noteholders” means holders of the Notes that are party to the RSA and hold a majority in dollar amount of the aggregate outstanding principal amount of the Notes held by all holders of Notes party to the RSA. Accordingly, almost all of our board members will be new to the company. Any new directors are likely to have different backgrounds, experiences and perspectives from those individuals who previously served on the board of directors and, thus, may have different views on the issues that will determine our future. As a result, our future strategy and plans may differ materially from those of the past.

Adverse publicity in connection with the Chapter 11 Cases or otherwise could negatively affect our business.

Adverse publicity or news coverage relating to us, including, but not limited to, publicity or news coverage in connection with the Chapter 11 Cases, may negatively impact our efforts to establish and promote name recognition and a positive image after emergence from the Chapter 11 Cases.

Public health events that are outside of our control, including pandemics, epidemics and infectious disease outbreaks, such as the recent global outbreak of COVID-19, have materially and adversely affected, and may further materially and adversely affect, our business.

We face risks related to epidemics, pandemics, outbreaks, or other public health events that are outside of our control, and could significantly disrupt our operations and adversely affect their financial condition. For example, the outbreak of the COVID-19 virus has spread across the globe and impacted financial markets and worldwide economic activity and may continue to adversely affect our operations or the health of our workforce by rendering employees or contractors unable to work or unable to access the our facilities for an indefinite period of time. In addition, the effects of COVID-19 and concerns regarding its global spread have negatively impacted the domestic and international demand for crude oil and natural gas, which has adversely affected crude oil prices and resulted in significant price volatility. As the duration and full impact from COVID-19 is difficult to predict, the extent to which it may negatively affect the our operating results or the duration of any potential business disruption is uncertain. Any potential impact will depend on future developments and new information that may emerge regarding the severity and duration of COVID-19 and the actions taken by authorities to contain it or treat its impact, all of which are beyond our control. These potential impacts, while uncertain, could adversely affect the our operating results.

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

The following table provides information relating to our repurchase of common stock for the three months ended March 31, 2020:
Period (a)
Total Number of Shares Purchased 		(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
January 1, 2020 to January 31, 2020 —    $ —    —    —   
February 1, 2020 to February 29, 2020 —    —    —    —   
March 1, 2020 to March 31, 2020 162,135    0.26    162,135    —   
Total 162,135    $ 0.26    162,135    —   

Item 3. Defaults Upon Senior Securities

Not applicable.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

Not applicable.


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Item 6. Exhibits

Exhibits: 
10.1    Standstill and Amendment Agreement, dated as of March 11, 2020, by and among Unit Corporation, Unit Drilling Company, Unit Petroleum Company, the Lenders party to the Existing Credit Agreement and BOKF, NA dba Bank of Oklahoma, as administrative agent for the Lenders (filed as Exhibit 10.1 to Unit’s Form 8-K dated March 16, 2020, which is incorporated herein by reference).
10.2    First Amendment to Standstill and Amendment Agreement, dated as of April 15, 2020, by and among Unit Corporation, Unit Drilling Company, Unit Petroleum Company, the lenders party thereto and BOKF, NA dba Bank of Oklahoma, as administrative agent for the lenders (filed as Exhibit 10.1 to Unit’s Form 8-K dated April 16, 2020, which is incorporated herein by reference).
10.3    Second Amendment to Standstill and Amendment Agreement, dated as of April 17, 2020, by and among Unit Corporation, Unit Drilling Company, Unit Petroleum Company, and BOKF, NA dba Bank of Oklahoma, as administrative agent on behalf of the lenders (filed as Exhibit 10.1 to Unit’s Form 8-K dated April 22, 2020, which is incorporated herein by reference).
10.4    Third Amendment to Standstill and Amendment Agreement, dated as of May 4, 2020, by and among Unit Corporation, Unit Drilling Company, Unit Petroleum Company, and BOKF, NA dba Bank of Oklahoma, as administrative agent on behalf of the lenders (filed as Exhibit 10.1 to Unit’s Form 8-K dated May 5, 2020, which is incorporated herein by reference).
10.5    Fourth Amendment to Standstill and Amendment Agreement, dated as of May 15, 2020, by and among Unit Corporation, Unit Drilling Company, Unit Petroleum Company, and BOKF, NA dba Bank of Oklahoma, as administrative agent on behalf of the lenders (filed as Exhibit 10.1 to Unit’s Form 8-K dated May 21, 2020, which is incorporated herein by reference).
10.6    Fifth Amendment to Standstill and Amendment Agreement, dated as of May 22, 2020, by and among Unit Corporation, Unit Drilling Company, Unit Petroleum Company, and BOKF, NA dba Bank of Oklahoma, as administrative agent on behalf of the lenders (filed as Exhibit 10.3 to Unit’s Form 8-K dated May 26, 2020, which is incorporated herein by reference).
10.7    Restructuring Support Agreement, dated as of May 22, 2020, by and among Unit Corporation, Unit Petroleum Company, Unit Drilling Company, 8200 Unit Drive, L.L.C., Unit Drilling USA Colombia, L.L.C., Unit Drilling USA Colombia, L.L.C., the Consenting RBL Lenders party thereto, BOKF, NA Bank of Oklahoma as RBL Agent, and the Consenting Noteholders party thereto (filed as Exhibit 10.1 to Unit’s Form 8-K dated May 26, 2020, which is incorporated herein by reference).
10.8    Superpriority Senior Secured Debtor-in-Possession Credit Agreement, dated as of May 27, 2020, by and among Unit Corporation, Unit Petroleum Company, Unit Drilling Company, 8200 Unit Drive, L.L.C., Unit Drilling USA Colombia, L.L.C., Unit Drilling Colombia L.L.C., the lenders party thereto and BOKF, NA dba Bank of Oklahoma as Administrative Agent (filed as Exhibit 10.1 to Unit’s Form 8-K dated June 1, 2020, which is incorporated herein by reference)
10.9    Continuation Agreement, dated as of May 22, 2020, by and among Superior Pipeline Company, L.L.C., Unit Corporation, SPC Midstream Operating, L.L.C., SP Investor Holdings, LLC, 8200 Unit Drive, L.L.C., Unit Drilling Colombia, L.L.C., Unit Drilling Company, Unit Drilling USA Colombia, L.L.C. and Unit Petroleum Company (filed as Exhibit 10.1 to Unit’s Form 8-K dated May 26, 2020, which is incorporated herein by reference).
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31.1   
31.2   
32   
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.
_______________________
*Certain schedules referenced in the agreement have been omitted in accordance with Item 601(b)(2) of Regulation S-K. A copy of any omitted schedule will be furnished supplementary to the U.S. Securities and Exchange Commission upon request.
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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: June 25, 2020
By: /s/ David T. Merrill
DAVID T. MERRILL
President and Chief Executive Officer
Date: June 25, 2020
By: /s/ Les Austin
LES AUSTIN
Senior Vice President and Chief Financial Officer

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