UNIT CORP - FORM 10-Q - August 9, 2018

Attached files

file	filename
EX-32 - CERTIFICATION OF CEO AND CFO UNDER RULE 13A -14(A) - UNIT CORP	unt-20180630xex32.htm
EX-31.2 - CERTIFICATION OF CFO UNDER RULE 13A -14(A) - UNIT CORP	unt-20180630xex312.htm
EX-31.1 - CERTIFICATION OF CEO UNDER RULE 13A -14(A) - UNIT CORP	unt-20180630xex311.htm
EX-10.1 (B) - FIRST AMENDMENT TO CREDIT AGREEMENT - UNIT CORP	exhibit101bfirstamendmentt.htm

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SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

[x] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2018

[ ] 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]

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)

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 [x] 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 [x] 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 [ x ] 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 [x]

As of July 20, 2018, 54,086,806 shares of the issuer's common stock were outstanding.

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TABLE OF CONTENTS



		Page Number
	PART I. Financial Information

Item 1.	Financial Statements (Unaudited)

	Unaudited Condensed Consolidated Balance Sheets June 30, 2018 and December 31, 2017	4

	Unaudited Condensed Consolidated Income Statements Three and Six Months Ended June 30, 2018 and 2017	6

	Unaudited Condensed Consolidated Statements of Comprehensive Income Three and Six Months Ended June 30, 2018 and 2017	7

	Unaudited Condensed Consolidated Statements of Changes in Shareholders' Equity Six Months Ended June 30, 2018 and 2017	8

	Unaudited Condensed Consolidated Statements of Cash Flows Six Months Ended June 30, 2018 and 2017	9

	Notes to Unaudited Condensed Consolidated Financial Statements	11

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	47

Item 3.	Quantitative and Qualitative Disclosure About Market Risk	71

Item 4.	Controls and Procedures	72

	PART II. Other Information

Item 1.	Legal Proceedings	73

Item 1A.	Risk Factors	74

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	74

Item 3.	Defaults On Senior Securities	74

Item 4.	Mine Safety Disclosures	74

Item 5.	Other Information	74

Item 6.	Exhibits	75

Signatures		76

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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 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;


•	our projected production guidelines for the year;


•	our anticipated capital budgets;


•	our financial condition and liquidity;


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


•	our intended use of the proceeds from the sale of 50% of the interest we owned in our mid-stream segment; and


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

These statements are based on 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;


•	putative class action lawsuits that may cause substantial expenditures and divert management's attention; and


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

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

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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

UNIT CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)



	June 30, 2018		December 31, 2017
	(In thousands except share amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	104,308	$	701
Accounts receivable, net of allowance for doubtful accounts of $2,450 at both June 30, 2018 and December 31, 2017, respectively	113,377		111,512
Materials and supplies	501		505
Current derivative asset (Note 10)	127		721
Prepaid expenses and other	8,731		6,233
Total current assets	227,044		119,672
Property and equipment:
Oil and natural gas properties on the full cost method:
Proved properties	5,809,850		5,712,813
Unproved properties not being amortized	325,595		296,764
Drilling equipment	1,612,817		1,593,611
Gas gathering and processing equipment	736,488		726,236
Saltwater disposal systems	65,218		62,618
Corporate land and building	59,081		59,080
Transportation equipment	29,918		29,631
Other	56,381		53,439
	8,695,348		8,534,192
Less accumulated depreciation, depletion, amortization, and impairment	6,263,504		6,151,450
Net property and equipment	2,431,844		2,382,742
Goodwill	62,808		62,808
Other assets	28,113		16,230
Total assets ⁽¹⁾	$	2,749,809	$	2,581,452

The accompanying notes are an integral part of these

unaudited condensed consolidated financial statements.

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UNIT CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED) - CONTINUED



	June 30, 2018			December 31, 2017
	(In thousands except share amounts)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	114,411		$	112,648
Accrued liabilities (Note 5)	49,064			48,523
Income taxes payable	4,648			—
Current derivative liability (Note 10)	18,555			7,763
Current portion of other long-term liabilities (Note 6)	14,036			13,002
Total current liabilities	200,714			181,936
Long-term debt less debt issuance costs (Note 6)	643,371			820,276
Non-current derivative liability (Note 10)	910			—
Other long-term liabilities (Note 6)	102,928			100,203
Deferred income taxes	158,232			133,477
Commitments and contingencies (Note 12)	—			—
Shareholders’ equity:
Preferred stock, $1.00 par value, 5,000,000 shares authorized, none issued	—			—
Common stock, $.20 par value, 175,000,000 shares authorized, 54,089,366 and 52,880,134 shares issued as of June 30, 2018 and December 31, 2017, respectively	10,414			10,280
Capital in excess of par value	622,120			535,815
Accumulated other comprehensive income (loss) (Note 14)	(65		)	63
Retained earnings	811,781			799,402
Total shareholders’ equity attributable to Unit Corporation	1,444,250			1,345,560
Non-controlling interests in consolidated subsidiaries	199,404			—
Total shareholders' equity	1,643,654			1,345,560
Total liabilities⁽¹⁾ and shareholders’ equity	$	2,749,809		$	2,581,452

_______________________

(1)

Unit Corporation's consolidated total assets as of June 30, 2018 include total current and long-term assets of the variable interest entity (VIE) of $38.4 million and $412.2 million, respectively, which can only be used to settle obligations of the VIE. Unit Corporation's consolidated total liabilities as of June 30, 2018 include total current and long-term liabilities of the VIE of $33.7 million and $17.9 million, respectively, for which the creditors of the VIE have no recourse to Unit Corporation. See Note 13, "Variable Interest Entity Arrangements."

The accompanying notes are an integral part of these

unaudited condensed consolidated financial statements.

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UNIT CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED INCOME STATEMENTS (UNAUDITED)



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2018			2017			2018			2017
	(In thousands except per share amounts)
Revenues:
Oil and natural gas	$	102,318		$	83,173		$	205,417		$	170,771
Contract drilling	46,926			39,255			92,915			76,440
Gas gathering and processing	54,059			48,153			110,103			99,094
Total revenues	203,303			170,581			408,435			346,305
Expenses:
Operating costs:
Oil and natural gas	32,418			32,758			68,380			61,962
Contract drilling	31,894			27,239			63,561			56,466
Gas gathering and processing	39,703			36,042			81,307			73,746
Total operating costs	104,015			96,039			213,248			192,174
Depreciation, depletion, and amortization	58,373			50,080			115,439			97,012
General and administrative	8,712			8,713			19,474			17,667
Gain on disposition of assets	(161		)	(248		)	(322		)	(1,072		)
Total operating expenses	170,939			154,584			347,839			305,781
Income from operations	32,364			15,997			60,596			40,524
Other income (expense):
Interest, net	(7,729		)	(9,467		)	(17,733		)	(18,863		)
Gain (loss) on derivatives	(14,461		)	8,902			(21,223		)	23,633
Other, net	5			6			11			9
Total other income (expense)	(22,185		)	(559		)	(38,945		)	4,779
Income before income taxes	10,179			15,438			21,651			45,303
Income tax expense:
Deferred	2,029			6,379			5,636			20,315
Total income taxes	2,029			6,379			5,636			20,315
Net income	8,150			9,059			16,015			24,988
Net income attributable to non-controlling interest	2,362			—			2,362			—
Net income attributable to Unit Corporation	5,788			9,059			13,653			24,988
Net income attributable to Unit Corporation per common share:
Basic	$	0.11		$	0.18		$	0.26		$	0.49
Diluted	$	0.11		$	0.17		$	0.26		$	0.49

The accompanying notes are an integral part of these

unaudited condensed consolidated financial statements.

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UNIT CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)



	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2018		2017		2018			2017
	(In thousands)
Net income	$	8,150	$	9,059	$	16,015		$	24,988
Other comprehensive income (loss), net of taxes:
Unrealized gain (loss) on securities, net of tax of $11, $12, ($47) and $12	35		20		(141		)	20
Comprehensive income	8,185		9,079		15,874			25,008
Less: Comprehensive income attributable to non-controlling interest	2,362		—		2,362			—
Comprehensive income attributable to Unit Corporation	$	5,823	$	9,079	$	13,512		$	25,008

The accompanying notes are an integral part of these

unaudited condensed consolidated financial statements.

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UNIT CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY (UNAUDITED)



	Shareholders' Equity Attributable to Unit Corporation
	Common Stock		Capital In Excess of Par Value			Accumulated Other Comprehensive Income			Retained Earnings			Non-controlling Interest in Consolidated Subsidiaries		Total
	(In thousands except per share amounts)
Balances, January 1, 2018	$	10,280	$	535,815		$	63		$	799,402		$	—	$	1,345,560
Cumulative effect adjustment for adoption of ASUs (Notes 1 and 2)	—		—			13			(1,274		)	—		(1,261		)
Net income	—		—			—			13,653			2,362		16,015
Other comprehensive loss (net of tax ($47))	—		—			(141		)	—			—		(141		)
Total comprehensive income														15,874
Contributions	—		102,958			—			—			197,042		300,000
Transaction costs associated with sale of non-controlling interest	—		(2,254		)	—			—			—		(2,254		)
Tax effect of the sale of non-controlling interest	—		(24,300		)	—			—			—		(24,300		)
Activity in employee compensation plans (1,209,232 shares)	134		9,901			—			—			—		10,035
Balances, June 30, 2018	$	10,414	$	622,120		$	(65	)	$	811,781		$	199,404	$	1,643,654



	Shareholders' Equity Attributable to Unit Corporation
	Common Stock		Capital In Excess of Par Value		Accumulated Other Comprehensive Income		Retained Earnings		Non-controlling Interest in Consolidated Subsidiaries		Total
	(In thousands except per share amounts)
Balances, January 1, 2017	$	10,016	$	502,500	$	—	$	681,554	$	—	$	1,194,070
Net income	—		—		—		24,988		—		24,988
Other comprehensive income (net of tax $12)	—		—		20		—		—		20
Total comprehensive income											25,008
Activity in employee compensation plans (1,349,800 shares)	261		25,124		—		—		—		25,385
Balances, June 30, 2017	$	10,277	$	527,624	$	20	$	706,542	$	—	$	1,244,463

The accompanying notes are an integral part of the consolidated financial statements.

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UNIT CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)



	Six Months Ended
	June 30,
	2018			2017
	(In thousands)
OPERATING ACTIVITIES:
Net income	$	16,015		$	24,988
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, and amortization	115,439			97,012
Amortization of debt issuance costs and debt discount (Note 6)	1,095			1,075
(Gain) loss on derivatives (Note 10)	21,223			(23,633		)
Cash payments on derivatives settled, net (Note 10)	(8,928		)	(1,569		)
Deferred tax expense	5,636			20,315
Gain on disposition of assets	(322		)	(1,072		)
Stock compensation plans	12,073			8,066
Contract assets and liabilities, net (Note 2)	(2,371		)	—
Other, net	1,998			299
Changes in operating assets and liabilities increasing (decreasing) cash:
Accounts receivable	(6,812		)	(15,087		)
Accounts payable	(403		)	3,724
Material and supplies	4			49
Income taxes	—			(15		)
Accrued liabilities	1,572			756
Other, net	(1,526		)	2,147
Net cash provided by operating activities	154,693			117,055
INVESTING ACTIVITIES:
Capital expenditures	(189,916		)	(107,933		)
Producing properties and other acquisitions	(962		)	(52,956		)
Proceeds from disposition of assets	23,528			19,556
Other	—			(1,500		)
Net cash used in investing activities	(167,350		)	(142,833		)
FINANCING ACTIVITIES:
Borrowings under credit agreement	71,200			160,600
Payments under credit agreement	(249,200		)	(156,500		)
Payments on capitalized leases	(1,901		)	(1,901		)
Proceeds from common stock issued, net of issue costs (Note 14)	—			18,623
Proceeds from investments of non-controlling interest	300,000			—
Transaction costs associated with sale of non-controlling interest	(2,254		)	—
Book overdrafts	(1,581		)	4,912
Net cash provided in financing activities	116,264			25,734
Net increase (decrease) in cash and cash equivalents	103,607			(44		)
Cash and cash equivalents, beginning of period	701			893
Cash and cash equivalents, end of period	$	104,308		$	849

The accompanying notes are an integral part of these

unaudited condensed consolidated financial statements.

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UNIT CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) - CONTINUED



	Six Months Ended
	June 30,
	2018		2017
	(In thousands)
Supplemental disclosure of cash flow information:
Cash paid during the year for:
Interest paid (net of capitalized)	(17,957	)	(16,813	)
Income taxes	—		—
Changes in accounts payable and accrued liabilities related to purchases of property, plant, and equipment	(3,747	)	(8,771	)
Non-cash (addition) reduction to oil and natural gas properties related to asset retirement obligations	7,854		1,579

The accompanying notes are an integral part of these

unaudited condensed consolidated financial statements.

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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, which qualifies as a 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 our 50% ownership, to direct those activities that most significantly impact the economic performance of Superior as further described in Note 13 – 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 Form 10-K, filed February 27, 2018, for the year ended December 31, 2017 as amended by our Form 10-K/A filed on August 6, 2018.

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 at June 30, 2018 and December 31, 2017;


•	Income Statements for the three and six months ended June 30, 2018 and 2017;


•	Statements of Comprehensive Income for the three and six months ended June 30, 2018 and 2017;


•	Statements of Changes in Shareholders' Equity for the six months ended June 30, 2018 and 2017; and


•	Statements of Cash Flows for the six months ended June 30, 2018 and 2017.

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 six months ended June 30, 2018 and 2017 are not necessarily indicative of the results we may realize for the full year of 2018, or that we realized for the full year of 2017.

Accounting Changes - Recent Accounting Pronouncements - Adopted

As of January 1, 2018, we adopted ASU 2018-02 Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income. This standard is explained further in Note 8 - New Accounting Pronouncements. We adopted this amendment early and it had no material effect to our financial statements. We previously used 37.75% to calculate the tax effect on AOCI and we now use 24.5%. This change is reflected in our Unaudited Condensed Consolidated Statements of Comprehensive Income and in Note 14 - Equity.

Also, as of January 1, 2018, we adopted ASU 2014-09 Revenue from Contracts with Customers - Topic 606 (ASC 606) and all later amendments that modified ASC 606. This new revenue standard is explained further in Note 8 - New Accounting Pronouncements. We elected to apply this standard on the modified retrospective approach method to contracts not completed as of January 1, 2018, where the cumulative effect on adoption, which only impacted our mid-stream segment, is recognized as an adjustment to opening retained earnings at January 1, 2018. This adjustment related to the timing of revenue recognition for certain demand fees. Our oil and natural gas and contract drilling segments had no retained earnings adjustment. Comparative prior periods have not been adjusted and continue to be reported under ASC 605.

The additional disclosures required by the ASU are included in Note 2 – Revenue from Contracts with Customers.

NOTE 2 – REVENUE FROM CONTRACTS WITH CUSTOMERS

Our revenue streams are reported under three segments: oil and natural gas, contract drilling, and mid-stream. This is our disaggregation of revenue and how our segment revenue is reported (as reflected in Note 15 - Industry Segment Information). Revenue from the oil and natural gas segment is derived from sales of our oil and natural gas production. Revenue from the contract drilling segment is derived by contracting with upstream companies to drill an agreed-on number of wells or provide

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drilling rigs and services over an agreed-on time period. Revenue from the mid-stream segment is derived from gathering, transporting, and processing natural gas production and selling those commodities. We sell the hydrocarbons (from the oil and natural gas and mid-stream segments) to mid-stream and downstream oil and gas companies.

We satisfy the performance obligation under each segment's contracts as follows: for the contract drilling and mid-stream contracts, we satisfy the performance obligation over the agreed-on time period within the contracts, and for oil and natural gas contracts, we satisfy the performance obligation with each delivery of volumes. For oil and natural gas contracts, as it is more feasible, we account for these deliveries monthly. Per the contracts for all segments, customers pay for the services/goods received monthly within an agreed on number of days following the end of the month. Besides the mid-stream demand fees discussed further below, there were no other contract assets or liabilities falling within the scope of this accounting pronouncement.

Oil and Natural Gas Contracts, Revenues, Implementation Impact to Retained Earnings, and Performance Obligations

Typical types of revenue contracts signed by our segments are Oil Sales Contracts, Gas Purchase Agreements, North American Energy Standards Board (NAESB) Contracts, Gas Gathering and Processing Agreements, and revenues earned as the non-operated party with the operator serving as an agent on our behalf under our Joint Operating Agreements. Contract term can range from a single month to a term spanning a decade or more; some may also include evergreen provisions. Revenues from sales we make are recognized when our customer obtains control of the sold product. For sales to other mid-stream and downstream oil and gas companies, this would occur at a point in time, typically on delivery to the customer. Sales generated from our non-operated interest are recorded based on the information obtained from the operator. Our adoption of this standard did not require an adjustment to opening retained earnings.

Certain costs—as either a deduction from revenue or as an expense—is 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. The impact of the adoption of ASC 606 did not impact income from operations or net income for the three or six months ended June 30, 2018. The following tables summarizes the impact of the adoption of ASC 606 on revenue and operating costs for the three months ended June 30, 2018:



	Three Months Ended June 30, 2018
	As Reported		Adjustments due to ASC 606			Amounts without the Adoption of ASC 606
	(In thousands)
Oil and natural gas revenues	$	102,318	$	(3,732	)	$	106,050
Oil and natural gas operating costs	32,418		(3,732		)	36,150
Gross profit	$	69,900	$	—		$	69,900

The following tables summarizes the impact of the adoption of ASC 606 on revenue and operating costs for the six months ended June 30, 2018:



	Six Months Ended June 30, 2018
	As Reported		Adjustments due to ASC 606			Amounts without the Adoption of ASC 606
	(In thousands)
Oil and natural gas revenues	$	205,417	$	(6,902	)	$	212,319
Oil and natural gas operating costs	68,380		(6,902		)	75,282
Gross profit	$	137,037	$	—		$	137,037

Our performance obligation for all commodity contracts is the delivery of oil and gas volumes to the customer. Typically, the contract is for a specified period of time (for example, a month or a year); however, each delivery under that contract can be considered separately identifiable since each delivery provides benefits to the customer on its own. For feasibility, as accounting for a monthly performance obligation is not materially different than identifying a more granular performance

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obligation, we conclude this performance obligation is satisfied monthly. We typically receive a payment within a set number of days following the end of the month which includes payment for all deliveries in that month. Depending on contract circumstances, judgment could be required to determine when the transfer of control occurs. Generally, depending of the facts and circumstances, we consider the transfer of control of the asset in a commodity sale to occur at the point the commodity transfers to our purchaser.

Most of the consideration received by us for oil and gas sales is variable. Most of our contracts state the consideration is calculated by multiplying a variable quantity by an agreed-on index price less deductions related to gathering, transportation, fractionation, and related fuel charges. There are also instances where the consideration is quantity multiplied by a weighted average sales price. These different pricing tools can change the perception of when control transfers; however, when analyzed with other control factors, typically the accounting conclusion is the same for both pricing methods. In these instances, the variable consideration is partially constrained. In addition, all variable consideration is settled at the end of the month; therefore, whether the variability is constrained does not affect accounting for revenue under ASC 606 as the variability is known prior to each reporting period. An estimation and allocation of transaction price and future obligations are not required.

Contract Drilling Contracts, Revenues, Implementation impact to retained earnings, and Performance Obligations

The contracts our drilling segment uses are primarily industry standard IADC contracts model year 2003 and 2013. Contract terms range from six months to two or more years or can be based on terms to drill a specific number of wells. The allocation rules in ASC 606 (referred to as the "series guidance") provide that a contract may contain a single performance obligation composed of a series of distinct goods or services if 1) each distinct good or service is substantially the same and would meet the criteria to be a performance obligation satisfied over time and 2) each distinct good or service is measured using the same method as it relates to the satisfaction of the overall performance obligation. We have determined that the delivery of drilling services is within the scope of the series guidance as both criteria noted above are met. Specifically, 1) each distinct increment of service (i.e. hour available to drill) that the drilling contractor promises to transfer represents a performance obligation that would meet the criteria for recognizing revenue over time, and 2) the drilling contractor would use the same method for measuring progress toward satisfaction of the performance obligation for each distinct increment of service in the series. At inception, the total transaction price will be estimated to include any applicable fixed consideration, unconstrained variable consideration (estimated day rate mobilization and demobilization revenue, estimated operating day rate revenue to be earned over the contract term, expected bonuses (if material and can be reasonably estimated without significant reversal), and penalties (if material and can be reasonably estimated without significant reversal)). Allocation rules under this new standard allow us to recognize revenues associated with our drilling contacts in materially the same manner as under the previous revenue accounting standard. A contract liability will be recorded for consideration received before the corresponding transfer of services. Those liabilities will generally only arise in relation to upfront mobilization fees which are paid in advance and are allocated/recognized over the entire performance obligation. Such balances will be amortized over the recognition period based on the same method of measure used for revenue. On adoption of the standard, no adjustment to opening retained earnings was required.

Our performance obligation for all drilling contracts is to drill the agreed-on number of wells or drill over an agreed-on period of time as stated in the applicable contract. Any mobilization and demobilization activities are not considered to be distinct within the context of the contract and therefore, any associated revenue is allocated to the overall performance obligation of drilling services and recognized ratably over the initial term of the related drilling contract. It typically takes from 10 to 90 days to complete drilling a well; therefore, depending on the number of wells under a contract, the contract term could be up to two years. Most of the drilling contracts are for less than one year. As the customer simultaneously receives and consumes the benefits provided by the company’s performance, and the company’s performance enhances an asset that the customer controls, the performance obligation to drill the well occurs over time. We typically receive payment within a set number of days following the end of the month and that payment includes payment for all services performed during that month (calculated on an hourly basis). The company satisfies its overall performance obligation when the well included in the contract is drilled to an agreed-on depth or by a set date.

All consideration received for contract drilling is variable, excluding termination fees, which we have concluded will not be applicable to our current contracts as of the reporting date. The consideration is calculated by multiplying a variable quantity (number of days/hours) by an agreed-on daily price (for the daily rate, mobilization and demobilization revenue). Other revenue items under the contract may include bonus/penalty revenue, reimbursable revenue, drilling fluid rates, and early termination fees. All variable consideration is not constrained but is settled at the end of the month; therefore, whether the variability is constrained or not does not affect accounting for revenue under ASC 606 as the variability is known before each reporting period excluding certain bonuses/penalties which might be based on activity that occurs over the entire term of the contract. We have evaluated the mobilization and de-mobilization charges on outstanding contracts, however, the impact to the

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financial statements was immaterial. As of June 30, 2018, we had 36 contract drilling contracts (12 of which are long-term) for a duration of two months to almost three years.

Under the guidance in relation to disclosures regarding the remaining performance obligations, there is a practical expedient for contracts that have an original expected duration of one year or less (ASC 606-10-50-14) and for contracts where the entity can recognize revenue as invoiced (ASC 606-10-55-18). The majority of our drilling contracts have an original term of less than one year; however, the remaining performance obligations under the contracts that do have a longer duration are not material.

Mid-stream Contracts Revenues, and Implementation impact to retained earnings, and Performance Obligations

Revenues are generated from the fees earned for gas gathering and processing services provided to a customer. The typical types of revenue contracts used by this segment are gas gathering and processing agreements. Contract terms range from a single month to terms spanning a decade or more, some include evergreen provisions. Fees for mid-stream services (gathering, transportation, processing) are performance obligations and meet the criteria of over time recognition which could be considered a series of distinct performance obligations that represents one overall performance obligation of gas gathering and processing services.

On adoption of the standard, an adjustment to opening retained earnings was made in the amount of $1.7 million ($1.3 million, net of tax). This adjustment related to the timing of revenue recognized on certain demand fees and had the following impact to the Unaudited Condensed Consolidated Balance Sheet:



	Balance at December 31, 2017		Adjustments due to ASC 606			Balance at January 1, 2018
	(In thousands)
Assets:
Other assets	$	16,230	$	10,798		$	27,028
Liabilities and shareholders' equity:
Current portion of other long-term liabilities	13,002		2,748			15,750
Other long-term liabilities	100,203		9,737			109,940
Deferred income taxes	133,477		(413		)	133,064
Retained earnings	799,402		(1,274		)	798,128

The impact of these demand fees to the Unaudited Condensed Consolidated Balance Sheet at June 30, 2018 was:



	As Reported		Adjustments due to ASC 606		Amounts without the Adoption of ASC 606
	(In thousands)
Assets:
Prepaid expenses and other	$	8,731	$	128	$	8,603
Other assets	28,113		11,887		16,226
Liabilities and shareholders' equity:
Current portion of other long-term liabilities	14,036		2,875		11,161
Other long-term liabilities	102,928		8,456		94,472
Deferred income taxes	158,232		168		158,064
Retained earnings	811,781		516		811,265

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This adjustment related to the timing of revenue recognized on certain demand fees and had the following impact to the Unaudited Condensed Consolidated Income Statement for the three months ended June 30, 2018:



	As Reported		Adjustments due to ASC 606		Amounts without the Adoption of ASC 606
	(In thousands)
Gas gathering and processing revenues	$	54,059	$	1,179	$	52,880
Deferred income tax expense	2,029		289		1,740
Net income	8,150		890		7,260



	As Reported		Adjustments due to ASC 606		Amounts without the Adoption of ASC 606
	(In thousands)
Gas gathering and processing revenues	$	110,103	$	2,371	$	107,732
Deferred income tax expense	5,636		581		5,055
Net income	16,015		1,790		14,225

The only fixed consideration related to mid-stream consideration is the demand fee which is calculated by multiplying an agreed-on price by a fixed number of volumes per month over a specified term in the contract.

Included below is the additional 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	July - December 2018		2019		2020			2021			2022		Total Remaining Impact to Revenue
		(In thousands)
Demand fee contracts	4-5 years	$	2,598	$	2,632	$	(3,781	)	$	(3,507	)	$	1,374	$	(684	)

Before the implementation of ASC 606, we immediately recognized the entire demand fee since the fee was payable within the first five years from the effective date of the contract and not over the entire term of the contract. However, as the demand fee does not specifically relate to a distinct performance obligation, under the new standard that amount should now be recognized over the life of the contract. Therefore, the demand fee previously recognized in the amount of $1.7 million ($1.3 million, net of tax) was adjusted to retained earnings as of January 1, 2018, and will be recognized over the remaining term of the contract. As this amount is fixed, recognition of the remaining portion will be stable. Besides the demand fee, there were no other contract assets or liabilities (see above for the balance sheet line items where they are reported). For the three and six months ended June 30, 2018, $1.2 million and $2.4 million, respectively, was recognized in revenue for these demand fees.



	June 30, 2018		January 1, 2018			Change
	(In thousands)
Contract assets	$	12,015	$	10,798		$	1,217
Contract liabilities	11,331		12,485			(1,154		)
Contract liabilities, net	$	684	$	(1,687	)	$	2,371

Our performance obligations for all contracts is to gather, transport, or process an agreed-on number of volumes as stated in the contract. Typically the contract will establish a period of time over which the company will perform the mid-stream services. Certain contracts also include an agreed-on quantity (or an agreed-on minimum quantity) of volumes that the company will deliver or service. The term under mid-stream service contracts is typically five to ten years. Under service contracts, as the customer simultaneously receives and consumes the benefits provided by the entity’s performance as the entity performs, the performance obligation to gather, transport, or process occurs over time. We typically receive payment within a

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set number of days following the end of the month and includes payment for all services performed that month. Our overall performance obligation is satisfied at the end of the contract term.

Most of the consideration received under mid-stream service contracts is variable. The consideration is calculated by multiplying a variable quantity (number of volumes) by an agreed-on price per MCF (commodity fee and the gathering fee). One fixed component of revenue is calculated by multiplying an agreed-on price by a certain volume commitment (MCF per day). Other revenue items may include shortfall fees. All variable consideration is settled at the end of the month; therefore, whether or not the variability is constrained does not affect accounting for revenue under ASC 606 as the variability is known before each reporting period. However, this excludes the shortfall fee as this fee could be based on a set number of volumes over the course of more than one month.

Per the new guidance related to disclosures for remaining performance obligations, there is a practical expedient for contracts that have an original expected duration of one year or less (ASC 606-10-50-14). There is also a practical expedient for “variable consideration [that] is allocated entirely to a wholly unsatisfied performance obligation… that forms part of a single performance obligation… for which the criteria in paragraph 606-10-32-40 have been met” (ASC 606-10-50-14A). As stated previously, the contract term for mid-stream services is typically longer than one year. However, based on the guidance at 606-10-32-40, we determined some of the variable payment in mid-stream service agreements specifically relates to the entity’s efforts to satisfy the performance obligation and that “allocating the variable amount entirely to the distinct good or service is consistent with the allocation objective in paragraph 606-10-32-28.” Therefore, the practical expedient relates to this variable consideration: the commodity fee and the gathering fee. The last time we received a shortfall fee was in 2016 and the amount was immaterial to total mid-stream revenues. These terms have historically been limited in our contracts.

We calculate revenue earned from the variable consideration related to mid-stream services by multiplying the number of volumes serviced times an agreed-on price. Therefore, the variable portion of this consideration is due to the change in volumes. This variability is resolved at the end of each month as the company will know the number of volumes serviced under each contract and payment is received monthly. The mid-stream gathering service contracts remaining are for a duration of less than one year to 15 years.

While long term service contracts are in place as of the reporting date, due to the variable volumes an estimation and allocation of transaction price and future obligations are not required.

NOTE 3 – DIVESTITURES

Divestitures

Oil and Natural Gas

We sold non-core oil and natural gas assets, net of related expenses, for $22.4 million during the first six months of 2018, compared to $17.8 million during the first six months of 2017. Proceeds from those sales reduced the net book value of our full cost pool with no gain or loss recognized.

Mid-Stream

On April 3, 2018, we sold 50% of the ownership interest in our mid-stream segment, Superior. The purchaser is 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. We received $300.0 million as a result of this sale. A portion of the proceeds were used to pay down our bank debt and the remainder will be used to accelerate the drilling program of our upstream subsidiary, Unit Petroleum Company, make additional capital investments in the jointly owned Superior, and for general working capital purposes. In connection with the sale of the interest in Superior, we took the necessary actions under the Indenture governing our outstanding senior subordinated notes to secure the ability to close the sale and have Superior released from the Indenture.

Superior will be governed and managed under its Amended and Restated Limited Liability Company Agreement and the Master Services and Operating Agreement (MSA) entered into by Superior and an affiliate of Unit, as both of those agreements may be amended from time to time. Further details are in Note 13 – Variable Interest Entity Arrangements.

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NOTE 4 – EARNINGS PER SHARE

Information related to the calculation of earnings per share attributable to Unit Corporation follows:



	Earnings (Numerator)		Weighted Shares (Denominator)	Per-Share Amount
	(In thousands except per share amounts)
For the three months ended June 30, 2018
Basic earnings attributable to Unit Corporation per common share	$	5,788	52,050	$	0.11
Effect of dilutive stock options and restricted stock	—		731	—
Diluted earnings attributable to Unit Corporation per common share	$	5,788	52,781	$	0.11
For the three months ended June 30, 2017
Basic earnings attributable to Unit Corporation per common share	$	9,059	51,366	$	0.18
Effect of dilutive stock options, restricted stock, and stock appreciation rights (SARs)	—		578	(0.01		)
Diluted earnings attributable to Unit Corporation per common share	$	9,059	51,944	$	0.17

The following table shows the number of stock options and SARs (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
	June 30,
	2018		2017
Stock options and SARs	66,500		178,755
Average exercise price	$	44.42	$	47.75



	Earnings (Loss) (Numerator)		Weighted Shares (Denominator)	Per-Share Amount
	(In thousands except per share amounts)
For the six months ended June 30, 2018
Basic earnings attributable to Unit Corporation per common share	$	13,653	51,891	$	0.26
Effect of dilutive stock options and restricted stock	—		651	—
Diluted earnings attributable to Unit Corporation per common share	$	13,653	52,542	$	0.26
For the six months ended June 30, 2017
Basic earnings attributable to Unit Corporation per common share	$	24,988	50,832	$	0.49
Effect of dilutive stock options, restricted stock, and SARs	—		539	—
Diluted earnings attributable to Unit Corporation per common share	$	24,988	51,371	$	0.49



	Six Months Ended
	June 30,
	2018		2017
Stock options and SARs	66,500		178,755
Average exercise price	$	44.42	$	47.75

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NOTE 5 – ACCRUED LIABILITIES

Accrued liabilities consisted of:



	June 30, 2018		December 31, 2017
	(In thousands)
Employee costs	$	12,359	$	19,521
Lease operating expenses	12,080		11,819
Taxes	6,997		3,404
Interest payable	6,581		6,745
Derivative settlements	2,550		—
Third-party credits	2,473		2,240
Other	6,024		4,794
Total accrued liabilities	$	49,064	$	48,523

NOTE 6 – LONG-TERM DEBT AND OTHER LONG-TERM LIABILITIES

Long-Term Debt

Our long-term debt as of the dates indicated consisted of the following:



	June 30, 2018			December 31, 2017
	(In thousands)
Unit credit agreement with an average interest rate of 3.4% at December 31, 2017	$	—		$	178,000
Superior credit agreement	—			—
6.625% senior subordinated notes due 2021	650,000			650,000
Total principal amount	650,000			828,000
Less: unamortized discount	(1,933		)	(2,234		)
Less: debt issuance costs, net	(4,696		)	(5,490		)
Total long-term debt	$	643,371		$	820,276

Unit Credit Agreement. On April 2, 2018, we signed a Fourth Amendment to our Senior Credit Agreement (Unit credit agreement) scheduled to mature on April 10, 2020. The Fourth Amendment provided, among other things, for a reduction of the maximum credit amount from $875.0 million to $425.0 million, a reduction in the borrowing base from $475.0 million to $425.0 million, a reduction in the total commitment amount from $475.0 million to $425.0 million; and the full release of Superior and its subsidiaries as a borrower and co-obligor under the Unit credit agreement. Under the amendment, once the sale of the interest in Superior was completed, we were required to use part of the proceeds to pay down the Unit credit agreement. The Superior sale closed on April 3, 2018 and the pay down was made that day.

On May 2, 2018, as contemplated under the Fourth Amendment to its credit agreement, the company entered into a Pledge Agreement with BOKF, NA (dba Bank of Oklahoma), as administrative agent for the benefit of 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 the date of this report is 50% of the aggregate outstanding equity interests of Superior) as additional collateral for our obligations under the Unit credit agreement.

We are charged a commitment fee of 0.50% on the amount available but not borrowed. That fee varies based on the amount borrowed as a percentage of the total borrowing base. We paid $1.0 million in previous origination, agency, syndication, and other related fees. We did not incur any additional fees related to the amendment. We are amortizing these fees over the life of the Unit credit agreement. Under the Unit credit agreement, we have pledged as collateral 85% of the proved developed producing (discounted as present worth at 8%) total value of our oil and gas properties.

The borrowing base amount which is subject to redetermination by the lenders on April 1st and October 1st of each year is based on a percentage of the discounted future value of our oil and natural gas reserves. We or the lenders may request a

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onetime special redetermination of the borrowing base between each scheduled redetermination. In addition, we may request a redetermination following the completion of an acquisition that meets the requirements in the 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 2.00% to 3.00% depending on the level of debt as a percentage of the borrowing base and is payable at the end of each term, or every 90 days, whichever is less. Borrowings not under LIBOR bear interest at the prime rate specified in the Unit credit agreement but in no event less than LIBOR plus 1.00% plus a margin. Interest is payable at the end of each month and the principal may be repaid in whole or in part at any time, without a premium or penalty. At June 30, 2018, we did not have any outstanding borrowings under our Unit credit agreement.

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

The Unit credit agreement prohibits, among other things:


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


•	the incurrence of additional debt with certain limited exceptions;


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


•	investments in Unrestricted Subsidiaries (as defined in the Unit credit agreement) in excess of $200.0 million.

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


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

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


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

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


•	a leverage ratio of funded debt to consolidated EBITDA (as defined in the Unit credit agreement) for the most recently ended rolling four fiscal quarters of no greater than 4 to 1.

As of June 30, 2018, we were in compliance with the Unit credit agreement covenants.

Superior Credit Agreement. On May 10, 2018, Superior entered into a five-year, $200.0 million senior secured revolving credit facility with an option to increase the credit amount up to $250.0 million, subject to certain conditions (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, among other things, mortgage liens on certain of Superior’s processing plants and gathering systems.

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

The Superior credit agreement requires that Superior maintain a Consolidated EBITDA to interest expense ratio for the most-recently ended rolling four quarters of at least 2.50 to 1.00, and a funded debt to Consolidated EBITDA ratio of not greater than 4.00 to 1.00. Additionally, the Superior credit agreement contains a number of customary covenants that, among

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other things, restrict (subject to certain exceptions) Superior’s ability to incur additional indebtedness, create additional liens on its assets, make investments, pay distributions, enter into sale and leaseback transactions, engage in certain transactions with affiliates, engage in mergers or consolidations, enter into hedging arrangements, and acquire or dispose of assets. As of June 30, 2018, we were in compliance with the Superior credit agreement covenants.

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

On June 27, 2018, Superior and the lenders amended the Superior credit agreement to revise certain definitions in the agreement.

Superior's credit agreement is not guaranteed by Unit.

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

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

Unit, as the parent company, has no 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. Any of our other subsidiaries that are not Guarantors are minor. There are no significant restrictions on our ability to receive funds from any of our subsidiaries through dividends, loans, advances, or otherwise.

We may redeem all or, occasionally, a part of the Notes at certain redemption prices, plus accrued and unpaid interest. If a “change of control” occurs, subject to certain conditions, we must offer to repurchase from each holder all or any part of that holder’s Notes at a purchase price in cash equal to 101% of the principal amount of the Notes plus accrued and unpaid interest to the date of purchase. The 2011 Indenture contains customary events of default. The 2011 Indenture also contains covenants including those that limit our ability and the ability of certain of our subsidiaries to incur or guarantee additional indebtedness; pay dividends on our capital stock or redeem capital stock or subordinated indebtedness; transfer or sell assets; make investments; incur liens; enter into transactions with our affiliates; and merge or consolidate with other companies. We were in compliance with all covenants of the Notes as of June 30, 2018.

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Other Long-Term Liabilities

Other long-term liabilities consisted of the following:



	June 30, 2018		December 31, 2017
	(In thousands)
Asset retirement obligation (ARO) liability	$	62,838	$	69,444
Capital lease obligations	13,321		15,224
Workers’ compensation	12,963		13,340
Contract liability	11,331		—
Separation benefit plans	7,607		6,524
Deferred compensation plan	5,621		5,390
Gas balancing liability	3,283		3,283
	116,964		113,205
Less current portion	14,036		13,002
Total other long-term liabilities	$	102,928	$	100,203

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 July 1, 2018 (and through 2023) are $14.0 million, $43.8 million, $660.6 million, $5.0 million, and $2.7 million, respectively.

Capital Leases

In 2014, Superior entered into capital lease agreements for 20 compressors with initial terms of seven years. The underlying assets are included in gas gathering and processing equipment. The $3.9 million current portion of the capital lease obligations is included in current portion of other long-term liabilities and the non-current portion of $9.4 million is included in other long-term liabilities in the accompanying Unaudited Condensed Consolidated Balance Sheets as of June 30, 2018. These capital leases are discounted using annual rates of 4.00%. Total maintenance and interest remaining related to these leases are $5.0 million and $0.9 million, respectively, at June 30, 2018. Annual payments, net of maintenance and interest, average $4.2 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.

Future payments required under the capital leases at June 30, 2018 are:



	Amount
Beginning July 1,	(In thousands)
2018	$	6,168
2019	6,168
2020	6,673
2021	179
Total future payments	19,188
Less payments related to:
Maintenance	4,981
Interest	886
Present value of future minimum payments	$	13,321

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NOTE 7 – 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.

The following table shows certain information about our AROs for the periods indicated:



	Six Months Ended
	June 30,
	2018			2017
	(In thousands)
ARO liability, January 1:	$	69,444		$	70,170
Accretion of discount	1,248			1,458
Liability incurred	211			1,018
Liability settled	(3,142		)	(1,224		)
Liability sold	(94		)	(1,412		)
Revision of estimates ⁽¹⁾	(4,829		)	39
ARO liability, June 30:	62,838			70,049
Less current portion	1,451			2,825
Total long-term ARO	$	61,387		$	67,224

_______________________


(1)	Plugging liability estimates were revised in both 2018 and 2017 for updates in the cost of services used to plug wells over the preceding year. We had various upward and downward adjustments.

NOTE 8 – NEW ACCOUNTING PRONOUNCEMENTS

Compensation—Stock Compensation: Improvements to Nonemployee Share-Based Payment Accounting. The FASB issued ASU 2018-07, to improve financial reporting for nonemployee share-based payments. The amendment expands the scope of Topic 718, Compensation—Stock Compensation to include share-based payments issued to nonemployees for goods or services. The amendment will be effective for years beginning after December 15, 2019, and interim periods within those years. This amendment will not have a material impact on our financial statements.

Income Taxes - Amendments to SEC Paragraphs Pursuant to SEC Staff Accounting Bulletin No. 118. In March 2018, the FASB issued ASU 2018-05 which updates the FASB’s Accounting Standards Codification to reflect the guidance in SAB 118, which adds Section EE, “Income Tax Accounting Implications of the Tax Cuts and Jobs Act,” to SAB Topic 5, “Miscellaneous Accounting.” SAB 118 also provides guidance on applying ASC 740, Income Taxes, if the accounting for certain income tax effects of the Tax Cuts and Jobs Act of 2017 is incomplete when the financial statements are issued for a reporting period.

Intangibles—Goodwill and Other: Simplifying the Test for Goodwill Impairment. The FASB issued ASU 2017-04, to simplify the measurement of goodwill. The amendment eliminates Step 2 from the goodwill impairment test. The amendment will be effective prospectively for reporting periods beginning after December 15, 2019, and early adoption is permitted. This amendment will not have a material impact on our financial statements.

Leases. The FASB has issued ASU 2016-02. The amendment will require lessees to recognize at the commencement date of a lease a lease liability which is the lessee's obligation to make lease payments arising from the lease, measured on a discounted basis; and a right-of-use asset, which represents the lessee's right to use a specified asset for the lease term. Lessor accounting is largely unchanged. In January 2018, the FASB issued ASU 2018-01, "Leases - Land Easement practical expedient for Transition to Topic 842", which provides clarifying guidance regarding land easements and adds practical expedients. Further amendments were issued under ASU 2018-10. In July 2018, the FASB issued ASU 2018-11, “Leases (Topic 842),” as an amendment to ASU 2016-02, “Leases (Topic 842) Targeted Improvements” which provides entities with an additional transition method in which an entity initially applies the new leases standard at the adoption date and recognizes a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. The amendment also provides a practical expedient for lessors. At this time, we are still evaluating these expedients. For public companies, these amendments are effective for annual periods beginning after December 15, 2018, and interim periods within those annual

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periods. The standard will not apply to leases of mineral rights. We have an implementation team working through the provisions of the new guidance including a review of different types of contracts to document our lease portfolio and assess the impact on our accounting, disclosures, processes, internal control over financial reporting, and the election of certain practical expedients. Our evaluation of the impact of the new guidance on our financial statements is on-going.

Adopted Standards

Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income. The FASB issued ASU 2018-02, an amendment which provides financial statement preparers with an option to reclassify stranded tax effects within AOCI to retained earnings caused by the Tax Cuts and Jobs Act of 2017. The amendment is effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years. Early adoption is permitted. Organizations should apply the proposed amendments either in the period of adoption or retrospectively to each period (or periods) in which the effect of the change in the U.S. federal corporate income tax rate in the Tax Cuts and Jobs Act is recognized. We adopted this amendment early and it had no material effect to our financial statements. We previously used 37.75% to calculate the tax effect on AOCI and now we are using 24.5%. The change is reflected in our Unaudited Condensed Consolidated Statements of Comprehensive Income and in Note 14 - Equity.

Revenue from Contracts with Customers. Effective January 1, 2018, we adopted ASC 606. This new revenue standard provides for a five-step analysis of transactions to determine when and how revenue is to be recognized. The guidance in this update supersedes the revenue recognition requirements in ASC 605, Revenue Recognition, and most industry-specific guidance throughout the Industry Topics of the Codification. Under the standard, revenue is recognized when a customer obtains control of promised goods or services in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. In addition, the standard requires disclosure of the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. We applied the five step method outlined in the ASU to all of our revenue streams in the scope of ASC 606 and elected the modified retrospective approach method. Under that approach the cumulative effect on adoption is recognized as an adjustment to opening retained earnings at January 1, 2018. Only our mid-stream segment was affected. This adjustment related to the timing of revenue on certain demand fees. Both our oil and natural gas and contract drilling segments had no retained earnings adjustment. Comparative prior periods have not been adjusted and continue to be reported under ASC 605.

The additional disclosures required by ASC 606 have been included in Note 2 – Revenue from Contracts with Customers.

Our internal control framework did not materially change as a result of this standard, but the existing internal controls have been modified to consider our new revenue recognition policy effective January 1, 2018. As we implement the new standard, we have added internal controls to ensure that we adequately evaluate new contracts under the five-step model under ASU 2014-09.

NOTE 9 – STOCK-BASED COMPENSATION

For restricted stock awards and stock options, we had:



	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2018		2017		2018		2017
	(In millions)
Recognized stock compensation expense	$	4.0	$	3.2	$	9.5	$	5.8
Capitalized stock compensation cost for our oil and natural gas properties	0.6		0.4		1.0		0.8
Tax benefit on stock-based compensation	1.0		1.2		2.3		2.2

The remaining unrecognized compensation cost related to unvested awards at June 30, 2018 is approximately $23.7 million, of which $3.0 million is anticipated to be capitalized. The weighted average period over which this cost will be recognized is 1.0 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. 7,230,000 shares of the company's common stock are authorized for issuance to

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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 granted no SARs or stock options during either of the three or six month periods ending June 30, 2018 or 2017. This table shows the fair value of restricted stock awards granted to employees and non-employee directors during the periods indicated:



	Three Months Ended					Three Months Ended
	June 30, 2018					June 30, 2017
	Time Vested			Performance Vested		Time Vested			Performance Vested
Shares granted:
Employees	5,000			—		14,000			21,000
Non-employee directors	44,312			—		49,104			—
	49,312			—		63,104			21,000
Estimated fair value (in millions):⁽¹⁾
Employees	$	0.1		$	—	$	0.4		$	0.5
Non-employee directors	0.9			—		0.9			—
	$	1.0		$	—	$	1.3		$	0.5
Percentage of shares granted expected to be distributed:
Employees	95		%	N/A		100		%	87		%
Non-employee directors	100		%	N/A		100		%	N/A

_______________________


(1)	The performance shares represent 100% of the grant date fair value. (We recognize the grant date fair value minus estimated forfeitures.)



	Six Months Ended						Six Months Ended
	June 30, 2018						June 30, 2017
	Time Vested			Performance Vested			Time Vested			Performance Vested
Shares granted:
Employees	844,498			362,070			475,799			173,373
Non-employee directors	44,312			—			49,104			—
	888,810			362,070			524,903			173,373
Estimated fair value (in millions):⁽¹⁾
Employees	$	16.2		$	7.3		$	11.8		$	4.5
Non-employee directors	0.9			—			0.9			—
	$	17.1		$	7.3		$	12.7		$	4.5
Percentage of shares granted expected to be distributed:
Employees	95		%	62		%	95		%	87		%
Non-employee directors	100		%	N/A			100		%	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 six months of 2018 and 2017 are being recognized over a three-year vesting period. During the first quarter of 2018 and 2017, two performance vested restricted stock awards were granted to certain executive officers. The first will cliff vest 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 will vest, 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 June 30, 2018, the participants are estimated to receive 25% of the 2018, 91% of the 2017, and 167% of the 2016 performance-based shares. The CFTA performance measurement at June 30, 2018 was assessed to vest at target or 100%. The total aggregate stock

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compensation expense and capitalized cost related to oil and natural gas properties for 2018 awards for the first six months of 2018 was $4.3 million.

NOTE 10 – DERIVATIVES

Commodity Derivatives

We have signed various types of derivative transactions covering some of our projected natural gas and oil production. These transactions are intended to reduce our exposure to market price volatility by setting the price(s) we will receive for that production. Our decisions on the price(s), type, and quantity of our production subject to a derivative contract are based, in part, on our view of current and future market conditions. As of June 30, 2018, these hedges made up our derivative transactions:


•	Swaps. We receive or pay a fixed price for the commodity and pay or receive a floating market price to the counterparty. The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty.


•	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.


•	Collars. A collar contains a fixed floor price (put) and a ceiling price (call). If the market price exceeds the call strike price or falls below the put strike price, we receive the fixed price and pay the market price. If the market price is between the call and the put strike price, no payments are due from either party.

•

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 Income Statements.

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At June 30, 2018, these derivatives were outstanding:



Term	Commodity	Contracted Volume	Weighted Average Fixed Price	Contracted Market
Jul'18 – Sep'18	Natural gas – swap	40,000 MMBtu/day	$2.985	IF – NYMEX (HH)
Oct'18	Natural gas – swap	30,000 MMBtu/day	$3.005	IF – NYMEX (HH)
Nov’18 – Dec'18	Natural gas – swap	20,000 MMBtu/day	$3.013	IF – NYMEX (HH)
Jan'19 – Dec'19	Natural gas – swap	10,000 MMBtu/day	$2.810	IF – NYMEX (HH)
Jul'18 – Oct'18	Natural gas – basis swap	10,000 MMBtu/day	$(0.190)	NGPL TEXOK
Jul'18 – Dec'18	Natural gas – basis swap	10,000 MMBtu/day	$(0.678)	PEPL
Jul'18 – Dec'18	Natural gas – basis swap	10,000 MMBtu/day	$(0.568)	NGPL MIDCON
Nov’18 – Dec'18	Natural gas – basis swap	10,000 MMBtu/day	$(0.208)	IF – NYMEX (HH)
Jan'19 – Dec'19	Natural gas – basis swap	10,000 MMBtu/day	$(0.728)	PEPL
Jan'19 – Dec'19	Natural gas – basis swap	10,000 MMBtu/day	$(0.625)	NGL MIDCON
Jan'19 – Dec'19	Natural gas – basis swap	30,000 MMBtu/day	$(0.265)	NGPL TEXOK
Jan'20 – Dec'20	Natural gas – basis swap	30,000 MMBtu/day	$(0.275)	NGPL TEXOK
Jul'18 – Sep'18	Natural gas – collar	30,000 MMBtu/day	$2.67 - $2.97	IF – NYMEX (HH)
Jul'18 – Dec'18	Natural gas – three-way collar	20,000 MMBtu/day	$3.00 - $2.50 - $3.51	IF – NYMEX (HH)
Jul'18 – Dec'18	Crude oil – swap	4,000 Bbl/day	$53.52	WTI – NYMEX
Jul'18 – Dec'18	Crude oil – price differential risk	500 Bbl/day	$7.00	LLS/WTI
Jul'18 – Dec'18	Crude oil – three-way collar	2,000 Bbl/day	$47.50 - $37.50 - $56.08	WTI – NYMEX
Jan'19 – Dec'19	Crude oil – three-way collar	2,000 Bbl/day	$57.50 - $47.50 - $71.90	WTI – NYMEX
Jul'18 – Sep'18	NGLs – swap ⁽¹⁾	1,500 Bbl/day	$32.14	OPIS – Mont Belvieu

_______________________


(1)	Type of NGLs involved is propane.

After June 30, 2018, the following derivative was entered into:



Term	Commodity	Contracted Volume	Weighted Average Fixed Price	Contracted Market
Jan'19 – Dec'19	Natural gas – basis swap	10,000 MMBtu/day	$(0.590)	PEPL

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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	June 30, 2018		December 31, 2017
		(In thousands)
Commodity derivatives:
Current	Current derivative asset	$	127	$	721
Long-term	Non-current derivative asset	—		—
Total derivative assets		$	127	$	721



		Derivative Liabilities
		Fair Value
	Balance Sheet Location	June 30, 2018		December 31, 2017
		(In thousands)
Commodity derivatives:
Current	Current derivative liability	$	18,555	$	7,763
Long-term	Non-current derivative liability	910		—
Total derivative liabilities		$	19,465	$	7,763

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.

Following is the effect of derivative instruments on the Unaudited Condensed Consolidated Income Statements for the three months ended June 30:



Derivatives Instruments	Location of Gain (Loss) Recognized in Income on Derivative	Amount of Gain (Loss) Recognized in Income on Derivative
		2018			2017
		(In thousands)
Commodity derivatives	Gain (loss) on derivatives ⁽¹⁾	$	(14,461	)	$	8,902
Total		$	(14,461	)	$	8,902

_______________________


(1)	Amounts settled during the 2018 and 2017 periods include net payments of $6.9 million and $0.4 million, respectively.

Following is the effect of derivative instruments on the Unaudited Condensed Consolidated Income Statements for the six months ended June 30:



Derivatives Instruments	Location of Gain (Loss) Recognized in Income on Derivative	Amount of Gain (Loss) Recognized in Income on Derivative
		2018			2017
		(In thousands)
Commodity derivatives	Gain (loss) on derivatives ⁽¹⁾	$	(21,223	)	$	23,633
Total		$	(21,223	)	$	23,633

_______________________


(1)	Amounts settled during the 2018 and 2017 periods include payments of $8.9 million and $1.6 million, respectively.

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NOTE 11 – FAIR VALUE MEASUREMENTS

The estimated fair value of our available-for-sale securities, reflected on our Unaudited Condensed Consolidated Balance Sheets as Non-current other assets, is based on market quotes. The following is a summary of available-for-sale securities:

Cost

Gross Unrealized Gains

Gross Unrealized Losses

Estimated Fair Value

(In thousands)

Equity Securities:

June 30, 2018

830

—