SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form ~~10-Q~~10-Q/A

(Amendment No. 1)

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

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended ~~June 30, 2017~~March 31, 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 and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted 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 and post 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 [ x ] Non-accelerated filer (Do not check if a smaller reporting company) [ ]

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 21, 2017, 52,886,592~~April 20, 2018, 54,046,361 shares of the issuer's common stock were outstanding.

TABLE OF CONTENTS



		Page Number
	PART I. Financial Information

Item 1.	Financial Statements (Unaudited)	4

	Unaudited Condensed Consolidated Balance Sheets ~~June 30, 2017~~March 31, 2018 and December 31, ~~2016~~2017	34

	Unaudited Condensed Consolidated Income Statements ~~of Operations~~ Three ~~and Six~~ Months Ended ~~June 30,~~March 31, 2018 and 2017 ~~and 2016~~	5

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

	Unaudited Condensed Consolidated Statements of ~~Cash Flows~~ ~~Six~~Comprehensive Income Three Months Ended ~~June 30,~~March 31, 2018 and 2017 ~~and 2016~~	7

	Unaudited Condensed Consolidated Statements of Cash Flows Three Months Ended March 31, 2018 and 2017	8

	Notes to Unaudited Condensed Consolidated Financial Statements	9

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	30

~~Item 3.~~	~~Quantitative and Qualitative Disclosure About Market Risk~~	5231

Item 4.	Controls and Procedures	5351

	PART II. Other Information

Item 1.	~~Legal Proceedings~~	54

~~Item 1A.~~	~~Risk Factors~~	54

~~Item 2.~~	~~Unregistered Sales of Equity Securities and Use of Proceeds~~	55

~~Item 3.~~	~~Defaults Upon Senior Securities~~	55

~~Item 4.~~	~~Mine Safety Disclosures~~	55

~~Item 5.~~	~~Other Information~~	55

~~Item~~ 6.	Exhibits	5653

Signatures		5754

Explanatory Note

We are filing this Amendment No. 1 on Form 10-Q/A (the Amended Filing or Form 10-Q/A) to our previously issued Quarterly Report on Form 10-Q for the quarter ended March 31, 2018, initially filed with the Securities and Exchange Commission on May 3, 2018 (the Original Filing). This Form 10-Q/A amends and restates Items 1, 2, and 4 of Part I of the Original Filing.

In the course of preparing our consolidated financial statements for the quarter ended June 30, 2018, we identified a misstatement as of March 31, 2018, of approximately $44.9 million within the operating activities and the investing activities sections of the statement of cash flows. Management reported the matter to the Audit Committee of the Company's Board of Directors.

The misstatement did not have any impact on revenues, net income, working capital, total assets, or shareholders' equity. Our financial statements have been restated to correctly reflect the noncash activity within our condensed consolidated statements of cash flows. We have restated Note 1, Basis of Preparation and Presentation to reflect the impacts of this correction to the statement of cash flows.

Correspondingly, this Form 10-Q/A amends and restates Item 2 of Part I, which includes our revised discussion of liquidity and capital resources to reflect the impact of the restatement to the statement of cash flows. Item 4 of Part I includes our revised assessment of the effectiveness of our disclosure controls and procedures. This restatement resulted from a material weakness in internal control over financial reporting. In addition, under the rules of the SEC, Item 6 of Part II of the Original Filing has been amended to contain currently-dated certifications from our Chief Executive Officer and Chief Financial Officer, as required by Sections 302 and 906 of the Sarbanes-Oxley Act of 2002.

This Form 10-Q/A has not been updated for events occurring after the filing of the Original Filing, except to reflect the foregoing.

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;

Table of Contents

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 midstream 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 ~~result in~~cause substantial expenditures and divert management's attention; and

other factors, most of which are beyond our control.

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

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

UNIT CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)


	June 30, 2017		December 31, 2016		March 31, 2018		December 31, 2017
	(In thousands except share amounts)				(In thousands except share amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	849	$	893	$	752	$	701
Accounts receivable, net of allowance for doubtful accounts of $2,888 and $3,773 at June 30, 2017 and December 31, 2016, respectively	94,998		83,954
Accounts receivable, net of allowance for doubtful accounts of $2,450 at both March 31, 2018 and December 31, 2017, respectively					98,506		111,512
Materials and supplies	3,291		3,340		455		505
Current derivative asset (Note 10)	3,948		—		537		721
Current income tax receivable	114		99		61		—
Current deferred tax asset (Note 8)	—		25,211
Prepaid expenses and other	6,304		7,699		7,724		6,233
Total current assets	109,504		121,196		108,035		119,672
Property and equipment:
Oil and natural gas properties on the full cost method:
Proved properties	5,540,086		5,446,305		5,762,069		5,712,813
Unproved properties not being amortized	337,190		314,867		305,621		296,764
Drilling equipment	1,587,096		1,565,268		1,601,777		1,593,611
Gas gathering and processing equipment	711,355		705,859		731,006		726,236
Saltwater disposal systems	62,191		60,638		63,124		62,618
Corporate land and building	59,075		59,066		59,080		59,080
Transportation equipment	29,704		32,842		29,908		29,631
Other	52,799		48,590		56,142		53,439
	8,379,496		8,233,435		8,608,727		8,534,192
Less accumulated depreciation, depletion, amortization, and impairment	6,044,966		5,952,330		6,207,449		6,151,450
Net property and equipment	2,334,530		2,281,105		2,401,278		2,382,742
Goodwill	62,808		62,808		62,808		62,808
Non-current derivative asset (Note 10)	689		377
Other assets	15,779		13,817		27,470		16,230
Total assets	$	2,523,310	$	2,479,303	$	2,599,591	$	2,581,452

The accompanying notes are an integral part of these

unaudited condensed consolidated financial statements.

UNIT CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED) - CONTINUED


	June 30, 2017		December 31, 2016		March 31, 2018			December 31, 2017
	(In thousands except share amounts)				(In thousands except share amounts)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	106,200	$	88,793	$	131,064		$	112,648
Accrued liabilities (Note 5)	39,092		39,651		52,964			48,523
Current derivative liability (Note 10)	1,036		21,564		12,104			7,763
Current portion of other long-term liabilities (Note 6)	14,593		14,907		14,587			13,002
Total current liabilities	160,921		164,915		210,719			181,936
Long-term debt less debt issuance costs (Note 6)	806,092		800,917		790,522			820,276
Non-current derivative liability (Note 10)	—		415		164			—
Other long-term liabilities (Note 6)	100,796		103,064		104,286			100,203
Deferred income taxes (Note 8)	211,038		215,922
Deferred income taxes					136,600			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, 52,889,118 and 51,494,318 shares issued as of June 30, 2017 and December 31, 2016, respectively	10,277		10,016
Common stock, $.20 par value, 175,000,000 shares authorized, 54,046,361 and 52,880,134 shares issued as of March 31, 2018 and December 31, 2017, respectively					10,403			10,280
Capital in excess of par value	527,624		502,500		541,004			535,815
Accumulated other comprehensive income (Note 13)	20		—		(100		)	63
Retained earnings	706,542		681,554		805,993			799,402
Total shareholders’ equity	1,244,463		1,194,070		1,357,300			1,345,560
Total liabilities and shareholders’ equity	$	2,523,310	$	2,479,303	$	2,599,591		$	2,581,452

The accompanying notes are an integral part of these

unaudited condensed consolidated financial statements.

UNIT CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED INCOME STATEMENTS ~~OF OPERATIONS~~ (UNAUDITED)


	Three Months Ended						Six Months Ended						Three Months Ended
	June 30,						June 30,						March 31,
	2017			2016			2017			2016			2018			2017
	(In thousands except per share amounts)												(In thousands except per share amounts)
Revenues:
Oil and natural gas	$	83,173		$	69,190		$	170,771		$	127,464		$	103,099		$	87,598
Contract drilling	39,255			24,257			76,440			62,967			45,989			37,185
Gas gathering and processing	48,153			44,858			99,094			84,058			56,044			50,941
Total revenues	170,581			138,305			346,305			274,489			205,132			175,724
Expenses:
Operating costs:
Oil and natural gas	32,758			33,331			61,962			66,677			35,962			29,204
Contract drilling	27,239			19,254			56,466			47,352			31,667			29,227
Gas gathering and processing	36,042			32,381			73,746			63,447			41,604			37,704
Total operating costs	96,039			84,966			192,174			177,476			109,233			96,135
Depreciation, depletion, and amortization	50,080			52,878			97,012			108,468			57,066			46,932
Impairments (Note 2)	—			74,291			—			112,120
General and administrative	8,713			8,348			17,667			16,959			10,762			8,954
Gain on disposition of assets	(248		)	(477		)	(1,072		)	(669		)	(161		)	(824		)
Total operating expenses	154,584			220,006			305,781			414,354			176,900			151,197
Income (loss) from operations	15,997			(81,701		)	40,524			(139,865		)
Income from operations													28,232			24,527
Other income (expense):
Interest, net	(9,467		)	(10,606		)	(18,863		)	(20,223		)	(10,004		)	(9,396		)
Gain (loss) on derivatives	8,902			(22,672		)	23,633			(11,743		)	(6,762		)	14,731
Other, net	6			1			9			(14		)	6			3
Total other income (expense)	(559		)	(33,277		)	4,779			(31,980		)	(16,760		)	5,338
Income (loss) before income taxes	15,438			(114,978		)	45,303			(171,845		)
Income tax expense (benefit):
Income before income taxes													11,472			29,865
Income tax expense:
Deferred	6,379			(42,842		)	20,315			(58,560		)	3,607			13,936
Total income taxes	6,379			(42,842		)	20,315			(58,560		)	3,607			13,936
Net income (loss)	$	9,059		$	(72,136	)	$	24,988		$	(113,285	)
Net income (loss) per common share:
Net income													$	7,865		$	15,929
Net income per common share:
Basic	$	0.18		$	(1.44	)	$	0.49		$	(2.27	)	$	0.15		$	0.32
Diluted	$	0.17		$	(1.44	)	$	0.49		$	(2.27	)	$	0.15		$	0.31

The accompanying notes are an integral part of these

unaudited condensed consolidated financial statements.

UNIT CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME ~~(LOSS)~~ (UNAUDITED)

Three Months Ended Six Months Ended
June 30, June 30,
2017 2016 2017 2016
(In thousands)
Net income (loss) $ 9,059
$ (72,136 ) $ 24,988
$ (113,285 )
Other comprehensive income, net of taxes:
Unrealized appreciation on securities, net of tax of $12, $0, $12, and $0 20
—
20
—
Comprehensive income (loss) $ 9,079
$ (72,136 ) $ 25,008
$ (113,285 )



	Three Months Ended
	March 31,
	2018			2017
	(In thousands)
Net income	$	7,865		$	15,929
Other comprehensive income, net of taxes:
Unrealized loss on securities, net of tax of ($58) and $0	(176		)	—
Comprehensive income	$	7,689		$	15,929

The accompanying notes are an integral part of these

unaudited condensed consolidated financial statements.

UNIT CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

Six Months Ended
June 30,
2017 2016
(In thousands)
OPERATING ACTIVITIES:
Net income (loss) $ 24,988
$ (113,285 )
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, and amortization 97,012
108,468
Impairments (Note 2) —
112,120
Amortization of debt issuance costs and debt discount 1,075
1,054
(Gain) loss on derivatives (23,633 ) 11,743
Cash (payments) receipts on derivatives settled (1,569 ) 12,192
Deferred tax expense (benefit) 20,315
(58,560 )
Gain on disposition of assets (1,072 ) (946 )
Employee stock compensation plans 8,066
7,703
Other, net 299
(2,755 )
Changes in operating assets and liabilities increasing (decreasing) cash:
Accounts receivable (15,087 ) 5,443
Accounts payable 3,724
24,077
Material and supplies 49
241
Accrued liabilities 756
3,411
Income taxes (15 ) 18,969
Other, net 2,147
2,841
Net cash provided by operating activities 117,055
132,716
INVESTING ACTIVITIES:
Capital expenditures (107,933 ) (124,182 )
Producing properties and other acquisitions (Note 3) (52,956 ) —
Proceeds from disposition of assets 19,556
46,627
Other (1,500 ) 169
Net cash used in investing activities (142,833 ) (77,386 )
FINANCING ACTIVITIES:
Borrowings under credit agreement 160,600
150,300
Payments under credit agreement (156,500 ) (195,300 )
Payments on capitalized leases (1,901 ) (1,828 )
Proceeds from common stock issued, net of issue costs (Note 13) 18,623
—
Tax benefit from stock compensation —
(376 )
Book overdrafts 4,912
(7,987 )
Net cash provided by (used in) financing activities 25,734
(55,191 )
Net increase (decrease) in cash and cash equivalents (44 ) 139
Cash and cash equivalents, beginning of period 893
835
Cash and cash equivalents, end of period $ 849
$ 974

Supplemental disclosure of cash flow information:
Cash paid during the year for:
Interest paid (net of capitalized) 16,813
19,830
Income taxes —
—
Changes in accounts payable and accrued liabilities related to purchases of property, plant, and equipment (8,771 ) 30,758
Non-cash reductions to oil and natural gas properties related to asset retirement obligations 1,579
28,884



	Three Months Ended
	March 31,
	As Restated
	2018			2017
	(In thousands)
OPERATING ACTIVITIES:
Net income	$	7,865		$	15,929
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, and amortization	57,066			46,932
Amortization of debt issuance costs and debt discount (Note 6)	546			536
(Gain) loss on derivatives	6,762			(14,731		)
Cash payments on derivatives settled, net	(2,073		)	(1,159		)
Deferred tax expense	3,607			13,936
Gain on disposition of assets	(161		)	(824		)
Stock compensation plans	6,609			3,704
Contract assets and liabilities, net (Note 2)	(1,192		)	—
Other, net	937			626
Changes in operating assets and liabilities increasing (decreasing) cash:
Accounts receivable	8,005			(1,900		)
Accounts payable	(10,716		)	(7,735		)
Material and supplies	50			73
Accrued liabilities	6,757			9,832
Other, net	(494		)	433
Net cash provided by operating activities	83,568			65,652
INVESTING ACTIVITIES:
Capital expenditures	(90,249		)	(37,636		)
Producing properties and other acquisitions	—			(7,508		)
Proceeds from disposition of assets	22,084			16,116
Net cash used in investing activities	(68,165		)	(29,028		)
FINANCING ACTIVITIES:
Borrowings under credit agreement	67,400			49,700
Payments under credit agreement	(97,700		)	(60,500		)
Payments on capitalized leases	(946		)	(946		)
Book overdrafts	15,894			(17,301		)
Net cash used in financing activities	(15,352		)	(29,047		)
Net increase in cash and cash equivalents	51			7,577
Cash and cash equivalents, beginning of period	701			893
Cash and cash equivalents, end of period	$	752		$	8,470



Supplemental disclosure of cash flow information:
Cash paid during the year for:
Interest paid (net of capitalized)	(1,731	)	(2,389	)
Income taxes	—		—
Changes in accounts payable and accrued liabilities related to purchases of property, plant, and equipment	(13,238	)	(11,401	)
Non-cash (addition) reduction to oil and natural gas properties related to asset retirement obligations	6,340		912

The accompanying notes are an integral part of these

unaudited condensed consolidated financial statements.

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.

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 ~~28, 2017,~~27, 2018, for the year ended December 31, ~~2016~~2017.

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 the following:~~state:

Balance Sheets at ~~June 30, 2017~~March 31, 2018 and December 31, ~~2016;~~2017;

Income Statements ~~of Operations~~ for the ~~three and~~ ~~six~~three months ended ~~June 30, 2017~~March 31, 2018 and ~~2016;~~2017;

Statements of Comprehensive Income ~~(Loss)~~ for the three ~~and~~ ~~six~~months ended ~~June 30, 2017~~March 31, 2018 and ~~2016;~~2017; and

Statements of Cash Flows for the ~~six~~three months ended ~~June 30, 2017~~March 31, 2018 and ~~2016~~2017.

Our financial statements are prepared in conformity with generally accepted accounting principles in the United States (GAAP). GAAP 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~~three months ended ~~June 30, 2017~~March 31, 2018 and ~~2016~~2017 are not necessarily indicative of the results to be realized for the full year of ~~2017~~2018, or that we realized for the full year of ~~2016~~2017.

~~Certain amounts in the~~Restatement of Unaudited Condensed Consolidated Statement of Cash Flows

We have restated our unaudited condensed consolidated financial statements to correct an error within our condensed consolidated statement of cash flows. In the course of preparing our consolidated financial statements for ~~prior periods have been reclassified~~the quarter ended June 30, 2018, we identified an error as of March 31, 2018, of approximately $44.9 million between the operating activities and the investing activities sections of the statement of cash flows. The following table presents the effect of the correction on the selected line items previously reported in the condensed consolidated cash flows statement for the three months ended March 31, 2018:



	Three Months Ended
	March 31,
	2018
	As Reported			Adjustment			As Restated
	(In thousands)
OPERATING ACTIVITIES:
Changes in operating assets and liabilities increasing (decreasing) cash:
Accounts payable	$	(55,638	)	$	44,922		$	(10,716	)
Net cash provided by operating activities	38,646			44,922			83,568

INVESTING ACTIVITIES:
Capital expenditures	(45,327		)	(44,922		)	(90,249		)
Net cash used in investing activities	(23,243		)	(44,922		)	(68,165		)

Supplemental disclosure of cash flow information:
Changes in accounts payable and accrued liabilities related to purchases of property, plant, and equipment	$	(58,160	)	$	44,922		$	(13,238	)

There were no impacts to ~~conform to current year presentation. There~~net cash provided by financing activities within our unaudited condensed consolidated statements of cash flows and there was no impact to ~~consolidated~~the net ~~income (loss) or shareholders' equity.~~increase (decrease) in cash and cash equivalents resulting from the restatement.

The impacts of the restatements have been reflected throughout these unaudited financial statements as appropriate.

Accounting Changes - Recent Accounting Pronouncements - Adopted

As of January 1, 2018, the company 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 did not have a 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 13 - Equity.

Also, as of January 1, 2018, the company adopted ASU 2014-09 Revenue from Contracts with Customers - Topic 606 (ASC 606) and all later amendments that modified ASC 606. The new revenue standard is explained further in Note 8 - New Accounting Pronouncements. The company has elected to apply the standard on the modified retrospective approach method to contracts not completed as of January 1, 2018, where the cumulative effect upon 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. 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 the ASU have been included in Note 2 – Revenue from Contracts with Customers.

NOTE 2 – ~~OIL AND NATURAL GAS PROPERTIES~~REVENUE FROM CONTRACTS WITH CUSTOMERS

~~Full cost accounting rules require us to review~~The company’s 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 14 - Industry Segment Information). Revenue from the ~~carrying value~~oil and natural gas segment is derived from sales of our oil and natural gas ~~properties~~production. Revenue from the contract drilling segment is derived by contracting with upstream companies to drill an agreed-on number of wells or provide drilling rigs and services over an agreed-on period of time. Revenue from the mid-stream segment is derived from gathering, transporting, and processing natural gas production and selling those commodities. The company sells its hydrocarbons (from the oil and natural gas and mid-stream segments) to midstream and downstream oil and gas companies.

We satisfy performance obligation for each contract 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 on a monthly basis. Per the contracts for all segments, customers pay for the services/goods received on a monthly basis 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.

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

Typical types of revenue contracts signed 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 single month to extended term contracts spanning a decade or more; some include evergreen provisions. Revenues from sales are recognized when the customer obtains control of the company’s product. For sales to other midstream 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. On adoption of the standard, no adjustment to opening retained earnings was required.

Certain costs as either a deduction from revenue or an expense is determined based on when control of the commodity transfers to the customer, which would affect our total revenue recognized, but will not affect gross profit. For example, gathering, processing and transportation costs that are included as part of the contract price with the customer upon 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 following table summarizes the impact of the adoption of ASC 606 on revenue and operating costs, as the change did not impact income from operations or net income for the three months ended March 31, 2018:



	As Reported		Adjustments due to ASC 606			Amounts without the Adoption of ASC 606
	(In thousands)
Oil and natural gas revenues	$	103,099	$	(3,169	)	$	106,268
Oil and natural gas operating costs	35,962		(3,169		)	39,131
Gross profit	$	67,137	$	—		$	67,137

Our performance obligation for all contracts is the delivery of oil and gas volumes to the customer. Typically the contract will establish a period of time (for example, a month or a year); however, each delivery can be considered separately identifiable as 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 obligation, we conclude this performance obligation is satisfied monthly. We typically receive payment within a set number of days following the end of the month and 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 final purchaser.

The majority of the consideration received 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 contract drilling contracts we use primarily are industry standard IADC contracts 2003 and 2013. Contract terms can range from six months to two or more years or can be based on terms to drill a specific number of wells. These allocation rules in ASC 606 are referred to as the series guidance which states 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. The company 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 driller promises to transfer represents a performance obligation that would meet the criteria for recognizing revenue over time, and 2) the driller 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 the new standard will allow the company to recognize revenues associated with contract 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. Such 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 contracts is to drill the agreed-on number of wells or drill over an agreed-on period of time as stated in the contract. Mobilization and demobilization activities associated with a drilling contract 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 received 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 includes payment for all services performed 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-upon depth or by a set date.

All consideration received for contract drilling contracts is variable, excluding termination fees, which we 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 per the contract 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 or not the variability is constrained does not affect accounting for revenue under ASC 606 as the variability is known prior to 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 financial statements was immaterial. As of March 31, 2018, we had 32 contract drilling contracts (six long-term) for a duration of two to fourteen months.

Per the new guidance in relation to disclosures regarding 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 contract drilling contracts have an original term of less than one year; however, there are a few contracts with a longer duration that 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. Typical types of revenue contracts signed are Gas Gathering and Processing agreements. Contract terms can range from single month to extended term contracts 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 following impact of these demand fees to the Unaudited Condensed Consolidated Balance Sheet on at March 31, 2018:



	As Reported		Adjustments due to ASC 606			Amounts without the Adoption of ASC 606
	(In thousands)
Assets:
Prepaid expenses and other	$	7,724	$	50		$	7,674
Other assets	27,470		11,397			16,073
Liabilities and shareholders' equity:
Current portion of other long-term liabilities	14,587		2,824			11,763
Other long-term liabilities	104,286		9,118			95,168
Deferred income taxes	136,600		(121		)	136,479
Retained earnings	805,993		(374		)	805,619

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 March 31, 2018:



	As Reported		Adjustments due to ASC 606		Amounts without the Adoption of ASC 606
	(In thousands)
Gas gathering and processing revenues	$	56,044	$	1,192	$	54,852
Deferred income tax expense	3,607		292		3,315
Net income	7,865		900		6,965

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 the company 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 2018		2019		2020			2021			2022		Total Remaining Impact to Revenue
		(In thousands)
Demand fee contracts	4-5 years	$	3,777	$	2,632	$	(3,781	)	$	(3,507	)	$	1,374	$	495

Before the implementation of ASC 606, we recognized the entire demand fee as the fee was payable the first five years after the effective date, not the entire term of the contract. However, as the demand fee does not specifically relate to a distinct performance obligation, the amount should be recognized over the life of the contract. Therefore, the demand fee already recognized for $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 consideration, recognition of the remaining portion will be stable. For the first three months of March 31, 2018, $1.2 million was recognized in revenue for these demand fees.

Besides the demand fee, there were no other contract assets or liabilities (see above for the balance sheet line items where they are reported.)



	March 31, 2018			January 1, 2018			Change
	(In thousands)
Contract assets	$	11,447		$	10,798		$	649
Contract liabilities	11,942			12,485			(543		)
Contract liabilities, net	$	(495	)	$	(1,687	)	$	1,192

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 set number of days following the end of the month and includes payment for all services performed that month. The company satisfies its overall performance obligation at the end of the contract term.

Most of the consideration received for 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 ~~quarter. Under those rules, the maximum amount allowed~~month as the ~~carrying value~~company will know the number of volumes serviced under each contract and payment is ~~referred~~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 ~~the ceiling. The ceiling is the sum~~ of the ~~present value (using a 10% discount rate)~~reporting date, due to the variable volumes an estimation and allocation of ~~the estimated~~transaction price and 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~~obligations are not being amortized, plus the lower of cost or estimated fair value of unproved properties included 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.

During the first and second quarter of 2016, we had a non-cash ceiling test write-down of $37.8 million pre-tax ($23.5 million, net of tax) and $74.3 million pre-tax ($46.3 million, net of tax), respectively. We had no non-cash ceiling test write-downs for the first or second quarter of 2017.required.

NOTE 3 – ~~ACQUISITIONS AND~~ DIVESTITURES

~~Acquisitions~~

~~On April 3, 2017, we closed on an acquisition of certain oil~~Oil and ~~natural gas assets located primarily in Grady and Caddo Counties in western Oklahoma. The preliminary adjusted value of consideration given was $54.0 million.~~

As of January 1, 2017, the effective date of the acquisition, the estimated proved oil and gas reserves of the acquired properties were 3.2 million barrels of oil equivalent (MMBoe). The acquisition adds approximately 8,300 net oil and gas

leasehold acres to our core Hoxbar area in southwestern Oklahoma including approximately 47 proved developed producing wells. Of the acreage acquired, approximately 71% is held by production. We also received one gathering system as part of the transaction.

~~We accounted for this acquisition using the acquisition method under ASC 805,~~ ~~Business Combinations~~, which requires that the acquired assets and liabilities be recorded at their fair values as of the acquisition date. The following table summarizes the preliminary purchase price and the preliminary estimated values of assets acquired and liabilities assumed. It is based on information available to us at the time these unaudited condensed consolidated financial statements were prepared. We believe these estimates are reasonable; however, the estimates are subject to change as additional information becomes available and is assessed by us (in thousands):

Preliminary Purchase Price
Total consideration given $ 54,000

Preliminary Allocation of Purchase Price
Oil and natural gas properties included in the full cost pool:
Proved oil and natural gas properties $ 43,413
Undeveloped oil and natural gas properties 8,650
Total oil and natural gas properties included in the full cost pool ⁽¹⁾
52,063
Gas gathering equipment and other 2,340
Asset retirement obligation (403 )
Fair value of net assets acquired $ 54,000

(1) We used a discounted cash flow model and made market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates, and risk adjusted discount rates.

~~The pro forma effects of this acquired business is immaterial to the results of operations.~~

~~Divestitures~~Natural Gas

We sold non-core oil and natural gas assets, net of related expenses, for ~~$17.8~~$21.7 million during the first ~~six~~three months of ~~2017,~~2018, compared to ~~$43.6~~$14.8 million during the first ~~six~~three months of ~~2016.~~2017. Proceeds from those sales reduced the net book value of our full cost pool with no gain or loss recognized.

NOTE 4 – EARNINGS ~~(LOSS)~~ PER SHARE

Information related to the calculation of earnings ~~(loss)~~ per share follows:

Earnings (Loss)
(Numerator)

Weighted
Shares
(Denominator)

Per-Share
Amount
(In thousands except per share amounts)
For the three months ended June 30, 2017
Basic earnings 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 per common share $ 9,059
51,944
$ 0.17
For the three months ended June 30, 2016
Basic loss per common share $ (72,136 ) 50,074
$ (1.44 )
Effect of dilutive stock options, restricted stock, and SARs —
—
—
Diluted loss per common share $ (72,136 ) 50,074
$ (1.44 )

Due to the net loss for the three months ended June 30, 2016, approximately 417,000 weighted average shares related to stock options, restricted stock, and SARs were antidilutive and excluded from the calculation above.



	Earnings (Numerator)		Weighted Shares (Denominator)	Per-Share Amount
	(In thousands except per share amounts)
For the three months ended March 31, 2018
Basic earnings per common share	$	7,865	51,730	$	0.15
Effect of dilutive stock options and restricted stock	—		542	—
Diluted earnings per common share	$	7,865	52,272	$	0.15
For the three months ended March 31, 2017
Basic earnings per common share	$	15,929	50,293	$	0.32
Effect of dilutive stock options, restricted stock, and stock appreciation rights (SARs)	—		568	(0.01		)
Diluted earnings per common share	$	15,929	50,861	$	0.31

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,
2017 2016
Stock options and SARs 178,755
240,270
Average exercise price $ 47.75
$ 49.29

Earnings (Loss)
(Numerator)
Weighted
Shares
(Denominator)

Per-Share
Amount
(In thousands except per share amounts)
For the six months ended June 30, 2017
Basic income per common share $ 24,988
50,832
$ 0.49
Effect of dilutive stock options, restricted stock, and SARs —
539
—
Diluted income per common share $ 24,988
51,371
$ 0.49
For the six months ended June 30, 2016
Basic loss per common share $ (113,285 ) 49,977
$ (2.27 )
Effect of dilutive stock options, restricted stock, and SARs —
—
—
Diluted loss per common share $ (113,285 ) 49,977
$ (2.27 )

Because of the net loss for the six months ended June 30, 2016, approximately 332,000 weighted average shares related to stock options, restricted stock, and SARs were antidilutive and excluded from the calculation above.


	Six Months Ended				Three Months Ended
	June 30,				March 31,
	2017		2016		2018		2017
Stock options and SARs	178,755		240,270		87,500		199,755
Average exercise price	$	47.75	$	49.29	$	51.34	$	48.79

NOTE 5 – ACCRUED LIABILITIES

Accrued liabilities consisted of:


	June 30, 2017		December 31, 2016		March 31, 2018		December 31, 2017
	(In thousands)				(In thousands)
Interest payable					$	17,560	$	6,745
Lease operating expenses					11,570		11,819
Employee costs	$	10,526	$	15,394	9,754		19,521
Lease operating expenses	10,047		10,075
Interest payable	6,684		6,524
Taxes	6,577		2,219		4,139		3,404
Third-party credits	2,149		2,998		2,051		2,240
Derivative settlements					1,527		—
Other	3,109		2,441		6,363		4,794
Total accrued liabilities	$	39,092	$	39,651	$	52,964	$	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, 2017			December 31, 2016			March 31, 2018			December 31, 2017
	(In thousands)						(In thousands)
Credit agreement with an average interest rate of 3.5% and 2.8% at June 30, 2017 and December 31, 2016, respectively	$	164,900		$	160,800
Credit agreement with an average interest rate of 3.8% and 3.4% at March 31, 2018 and December 31, 2017, respectively							$	147,700		$	178,000
6.625% senior subordinated notes due 2021	650,000			650,000			650,000			650,000
Total principal amount	814,900			810,800			797,700			828,000
Less: unamortized discount	(2,524		)	(2,804		)	(2,085		)	(2,234		)
Less: debt issuance costs, net	(6,284		)	(7,079		)	(5,093		)	(5,490		)
Total long-term debt	$	806,092		$	800,917		$	790,522		$	820,276

Credit Agreement. ~~Our~~On April 2, 2018, we amended our Senior Credit Agreement (credit agreement) is scheduled to mature on April 10, 2020. ~~Under~~The details of this amendment are discussed in Note 15 — Subsequent Events.

Before the ~~credit agreement,~~amendment and through March 31, 2018, the amount we ~~can~~could borrow iswas the lesser of the amount we elect as the commitment amount or the value of the borrowing base as determined by the lenders, but in either event not to exceed $875.0 million. Our borrowing base and elected commitment ~~amount is $475.0 million. Our borrowing base is~~was $475.0 million. We ~~are~~were charged a commitment fee of 0.50% on the amount available but not borrowed. That fee ~~varies~~varied based on the amount borrowed as a percentage of the total borrowing base. We paid $1.0 million in origination, agency, syndication, and other related fees. We are amortizing these fees over the life of the credit agreement. Under the credit agreement, we have pledged the following collateral: (a) 85% of the proved developed producing (discounted as present worth at 8%) total value of our oil and gas properties and (b) 100% of our ownership interest in our ~~midstream~~mid-stream affiliate, Superior Pipeline Company, L.L.C.

The borrowing base amount–which is subject to redetermination by the lenders on April 1st and October 1st of each year–is based primarily on a percentage of the discounted future value of our oil and natural gas reserves. We or the lenders may request a onetime special redetermination of the borrowing base between each scheduled redetermination. In addition, we may request a redetermination following the completion of an acquisition that meets the requirements in the credit agreement.

At our election, any part of the outstanding debt under the credit agreement ~~may~~could 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 credit agreement that cannot be 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, 2017,~~March 31, 2018, we had ~~$164.9~~$147.7 million of outstanding borrowings under our credit agreement.

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

The credit agreement prohibits, among other things:

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

the incurrence of additional debt with certain limited exceptions; and

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

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

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

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

a senior indebtedness ratio of senior indebtedness to consolidated EBITDA (as defined in the credit agreement) for the most recently 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 credit agreement requires:

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

As of ~~June 30, 2017~~March 31, 2018, we were in compliance with the credit agreement covenants.

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

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

Unit, as the parent company, has no independent assets or operations. The guarantees by the Guarantors of the Notes

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

We may redeem all or, occasionally, a part of the Notes at certain redemption prices, plus accrued and unpaid interest. If a “change of control” occurs, subject to certain conditions, we must offer to repurchase from each holder all or any part of that holder’s Notes at a purchase price in cash equal to 101% of the principal amount of the Notes plus accrued and unpaid interest to the date of purchase. The 2011 Indenture contains customary events of default. The 2011 Indenture also contains covenants including those that limit our ability and the ability of certain of our subsidiaries to incur or guarantee additional indebtedness; pay dividends on our capital stock or redeem capital stock or subordinated indebtedness; transfer or sell assets; make investments; incur liens; enter into transactions with our affiliates; and merge or consolidate with other companies. We were in compliance with all covenants of the Notes as of ~~June 30, 2017~~March 31, 2018.

Other Long-Term Liabilities

Other long-term liabilities consisted of the following:


	June 30, 2017		December 31, 2016		March 31, 2018		December 31, 2017
	(In thousands)				(In thousands)
Asset retirement obligation (ARO) liability	$	70,049	$	70,170	$	63,763	$	69,444
Capital lease obligations	17,089		18,918		14,277		15,224
Workers’ compensation	13,971		15,163		13,049		13,340
Contract liability					11,942		—
Separation benefit plans	5,456		4,943		7,087		6,524
Deferred compensation plan	5,092		4,578		5,472		5,390
Gas balancing liability	3,322		3,789		3,283		3,283
Other	410		410
	115,389		117,971		118,873		113,205
Less current portion	14,593		14,907		14,587		13,002
Total other long-term liabilities	$	100,796	$	103,064	$	104,286	$	100,203

Estimated annual principal payments under the terms of debt and other long-term liabilities during the five successive ~~twelve month~~twelve-month periods beginning ~~July~~April 1, ~~2017~~2018 (and through ~~2021)~~2023) are $14.6 million, ~~$45.6~~$41.9 million, ~~$173.6~~$156.1 million, ~~$659.6~~$653.2 million, and ~~$2.5~~$2.0 million, respectively.

Capital Leases

In 2014, our mid-stream segment 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 ~~$3.8~~$3.9 million current portion of our capital lease obligations is included in current portion of other long-term liabilities and the non-current portion of ~~$13.3~~$10.4 million is included in other long-term liabilities in the accompanying Unaudited Condensed Consolidated Balance Sheets as of ~~June 30, 2017~~March 31, 2018. These capital leases are discounted using annual rates of 4.00%. Total maintenance and interest remaining related to these leases are ~~$6.8~~$5.4 million and ~~$1.5~~$1.0 million, respectively, at ~~June 30, 2017~~March 31, 2018. Annual payments, net of maintenance and interest, average ~~$4.1~~$4.2 million annually through 2021. At the end of the term, our mid-stream segment 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, 2017:~~March 31, 2018:


	Amount		Amount
Beginning July 1,	(In thousands)
2017	$	6,168
Beginning April 1,			(In thousands)
2018	6,168		$	6,168
2019	6,168		6,168
2020	6,673		7,815
2021	179		579
Total future payments	25,356		20,730
Less payments related to:
Maintenance	6,767		5,428
Interest	1,500		1,025
Present value of future minimum payments	$	17,089	$	14,277

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						Three Months Ended
	June 30,						March 31,
	2017			2016			2018			2017
	(In thousands)						(In thousands)
ARO liability, January 1:	$	70,170		$	98,297		$	69,444		$	70,170
Accretion of discount	1,458			1,513			659			785
Liability incurred	1,018			212			118			658
Liability settled	(1,224		)	(605		)	(1,626		)	(630		)
Liability sold ⁽¹⁾	(1,412		)	(10,308		)	(81		)	(432		)
Revision of estimates ⁽²⁾⁽¹⁾	39			(18,183		)	(4,751		)	(508		)
ARO liability, June 30:	70,049			70,926
ARO liability, March 31:							63,763			70,043
Less current portion	2,825			3,523			1,477			3,243
Total long-term ARO	$	67,224		$	67,403		$	62,286		$	66,800

_______________________


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


~~(2)~~	Plugging liability estimates were revised in both ~~2017~~2018 and ~~2016~~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.~~ The FASB issued ASU 2017-09, to clarify and reduce both (i) diversity in practice and (ii) cost and complexity when applying its guidance to changes in the terms and conditions of a share-based payment award. The amendments are effective for reporting periods beginning after December 15, 2017. We are in the process of evaluating the impact these amendments will have on our financial statements.

Intangibles—Goodwill and Other: Simplifying the Test for Goodwill Impairment. The FASB issued ASU 2017-04, to simplify the ~~subsequent~~ measurement of goodwill. The ~~amendments eliminate~~amendment eliminates Step 2 from the goodwill impairment test. The ~~amendments~~amendment will be effective prospectively for reporting periods beginning after December ~~31,~~15, 2019, and early adoption is permitted. ~~We do~~This amendment will not ~~believe these amendments will have a material impact on our financial statements.~~

~~Business Combinations; Clarifying the Definition of a Business.~~ The FASB issued ASU 2017-01, clarifying the definition of a business. The amendments are intended to help companies and other organizations evaluate whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. For public companies, the amendments are effective for annual periods beginning after December 15, 2017. We are in the process of evaluating the impact these amendments will have on our financial statements.

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

December 15, 2018, and interim periods within those annual periods. ~~Early adoption~~The standard will not apply to leases of mineral rights. We have begun the identification of leases and impact assessment within the scope of the ~~amendments is permitted. We are in the process~~guidance. Our evaluation of ~~evaluating~~ the impact ~~these amendments will have~~of the new guidance on our financial statements in 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 did not have a 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 13 - Equity.

Revenue from Contracts with Customers. Effective January 1, 2018, the company adopted ASC 606. The ~~FASB has issued ASU 2014-09. These amendments affect any entity using U.S. GAAP that either enters into contracts with customers~~new revenue standard provides a five-step analysis of transactions to ~~transfer goods or services or enters into contracts for~~determine when and how revenue is recognized. The guidance in this update supersedes the ~~transfer of nonfinancial assets unless those contracts are within~~revenue recognition requirements in ASC 605, Revenue Recognition, and most industry-specific guidance throughout the ~~scope of other standards (e.g., insurance contracts or lease contracts). The core principle~~Industry Topics of the ~~amendments~~Codification. Under the standard, revenue is ~~that an entity should recognize revenue to depict the transfer~~recognized when a customer obtains control of promised goods or services ~~to customers~~ in an amount that reflects the consideration ~~to which~~ the entity expects to ~~be entitled~~receive in exchange for those goods or services. In ~~May 2016,~~addition, the ~~FASB issued~~standard requires disclosure of the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. The company applied the five step method outlined in the ASU ~~2016-12, "Narrow-Scope Improvements~~to all revenue streams in the scope of ASC 606 and ~~Practical Expedients," which provides clarifying guidance~~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 certain areas and adds some practical expedients. Also in May 2016, the FASB issued ASU 2016-11, "Rescission of SEC Guidance Because of Accounting Standards Updates 2014-09 and 2014-16 Pursuant to Staff Announcements at the March 3, 2016 EITF Meeting." This amendment rescinds SEC Staff Observer comments that are codified in Topic 605, Revenue Recognition, and Topic 932, Extractive Activities- Oil and Gas, effective on the adoption of Topic 606,Note 2 – Revenue from Contracts with Customers. ~~In April 2016,~~

Our internal control framework did not materially change, but the ~~FASB issued ASU 2016-10, "Identifying Performance Obligations and Licensing," which amends the~~existing internal controls have been modified to consider our new revenue guidance on identifying performance obligations and accounting for licenses of intellectual property. The FASB has issued 2015-14, which defers the effective date to annual reporting periods beginning after December 15, 2017, including interim reporting periods within that reporting period. We will adopt these amendmentsrecognition policy effective January 1, 2018. ~~We are utilizing a bottom-up approach to analyze the impact of~~As we implement the new standard, on our contracts by reviewing our current accounting policies and practices to identify potential differences that would result from applying the requirements of the new standard. We have an implementation team evaluating contracts for the various revenue streams of our business segments to address changes to business processes, systems, and controls. While we have ~~not identified any material differences in~~added internal controls to ensure that we adequately evaluate new contracts under the amount and timing of revenue recognition to date, our evaluation is not complete, and we have not reached a conclusion on the overall impacts of adopting Topic 606. Topic 606 provides for adoption either retrospectively to each prior reporting period presented or as a cumulative effect adjustment to retained earnings at the date of adoption. We plan to adopt using the cumulative effect method.five-step model under ASU 2014-09.

~~Adopted Standards~~

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

~~Compensation—Stock Compensation: Improvements to Employee Share-Based Payment Accounting.~~ The FASB has issued ASU 2016-09. The amendments are intended to improve the accounting for employee share-based payments and affect all organizations that issue share-based payment awards to their employees. Several aspects of the accounting for share-based payment award transactions are simplified, including: (a) income tax consequences; (b) classification of awards as either equity or liabilities; and (c) classification on the statement of cash flows. For public companies, the amendments were effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods. The amendments primarily impact classification within the statement of cash flows between financial and operating activities. This did not have a material impact on our financial statements.

NOTE 9 –STOCK-BASED COMPENSATION

For restricted stock awards and stock options, we had:


	Three Months Ended				Six Months Ended				Three Months Ended
	June 30,				June 30,				March 31,
	2017		2016		2017		2016		2018		2017
	(In millions)								(In millions)
Recognized stock compensation expense	$	3.2	$	2.0	$	5.8	$	5.3	$	4.6	$	2.6
Capitalized stock compensation cost for our oil and natural gas properties	0.4		0.4		0.8		1.2		1.3		0.4
Tax benefit on stock based compensation	1.2		0.7		2.2		2.0		1.1		1.0

The remaining unrecognized compensation cost related to unvested awards at ~~June 30, 2017~~March 31, 2018 is approximately ~~$17.4~~$27.4 million, of which ~~$2.1~~$3.5 million is anticipated to be capitalized. The weighted average period over which this cost will be recognized is one 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) ~~as well as~~and to non-employee directors. ~~A total of 7,000,000~~7,230,000 shares of the company's common stock isare 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~~granted no SARs or stock options during either of the three ~~or six month~~-month periods ending ~~June 30, 2017~~March 31, 2018 or ~~2016~~2017. ~~The following~~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, 2017 June 30, 2016

Time
Vested
Performance Vested
Time
Vested
Performance Vested
Shares granted:
Employees 14,000
21,000
—
—
Non-employee directors 49,104
—
90,000
—
63,104
21,000
90,000
—
Estimated fair value (in millions):⁽¹⁾

Employees $ 0.4
$ 0.5
$ —
$ —
Non-employee directors 0.9
—
0.9
—
$ 1.3
$ 0.5
$ 0.9
$ —
Percentage of shares granted expected to be distributed:
Employees 100 % 87 % N/A
N/A
Non-employee directors 100 % N/A
100 % N/A

~~_______________________~~


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


	Six Months Ended						Six Months Ended						Three Months Ended						Three Months Ended
	June 30, 2017						June 30, 2016						March 31, 2018						March 31, 2017
	Time Vested			Performance Vested			Time Vested			Performance Vested			Time Vested			Performance Vested			Time Vested			Performance Vested
Shares granted:
Employees	475,799			173,373			486,578			152,373			839,498			362,070			461,799			152,373
Non-employee directors	49,104			—			90,000			—			—			—			—			—
	524,903			173,373			576,578			152,373			839,498			362,070			461,799			152,373
Estimated fair value (in millions):⁽¹⁾
Employees	$	11.8		$	4.5		$	2.6		$	0.8		$	16.1		$	7.3		$	11.4		$	4.0
Non-employee directors	0.9			—			0.9			—			—			—			—			—
	$	12.7		$	4.5		$	3.5		$	0.8		$	16.1		$	7.3		$	11.4		$	4.0
Percentage of shares granted expected to be distributed:
Employees	95		%	87		%	94		%	70		%	95		%	63		%	94		%	105		%
Non-employee directors	100		%	N/A			100		%	N/A			N/A			N/A			N/A			N/A

_______________________


(1)	Represents 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~~three months of ~~2017~~2018 and ~~2016~~2017 are being recognized over a three-year vesting period. During the ~~first two quarters of 2017 and~~ the first quarter of ~~2016,~~2018 and 2017, there were two ~~different~~ performance vested restricted stock awards 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, 2017,~~March 31, 2018, the participants are estimated to receive ~~74%~~27% of the 2018, 93% of the 2017, ~~145%~~and 164% of the 2016 ~~and 34% of the 2015~~ performance based shares. The CFTA performance measurement at ~~June 30, 2017~~March 31, 2018 was assessed to vest at target or 100%. The total aggregate stock compensation expense and capitalized cost related to oil and natural gas properties for ~~2017~~2018 awards for the first ~~six~~three months of ~~2017~~2018 was ~~$3.4~~$1.1 million.

NOTE 10 – DERIVATIVES

Commodity Derivatives

We have ~~entered into~~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, 2017~~March 31, 2018, our derivative transactions ~~were~~ comprised ~~of the following~~these hedges:

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 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 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 for speculative purposes. Any changes in the fair value of our derivative transactions ~~occurring~~ before maturity (i.e., temporary fluctuations in value) are reported in gain (loss) on derivatives in our Unaudited Condensed Consolidated ~~Statements of Operations.~~Income Statements.

At ~~June 30, 2017, the following~~March 31, 2018, these derivatives were outstanding:



Term	Commodity	Contracted Volume	Weighted Average Fixed Price	Contracted Market
~~Jul’17~~Apr’18 – ~~Oct'17~~Sep'18	Natural gas – swap	~~70,000~~40,000 MMBtu/day	$~~3.038~~2.985	IF – NYMEX (HH)
~~Nov’17 – Dec'17~~Oct'18	Natural gas – swap	~~60,000~~30,000 MMBtu/day	$~~2.960~~3.005	IF – NYMEX (HH)
~~Jan’18~~Nov’18 – Dec'18	Natural gas – swap	20,000 MMBtu/day	$3.013	IF – NYMEX (HH)
~~Nov’17~~Apr'18 – ~~Dec'17~~	~~Natural gas – basis swap~~	~~20,000 MMBtu/day~~	~~$(0.215)~~	~~IF – NYMEX (HH)~~
~~Jan’18 – Mar'18~~Oct'18	Natural gas – basis swap	10,000 MMBtu/day	$~~(0.208)~~(0.190)	IFNGPL TEXOK
Apr'18 – ~~NYMEX (HH)~~Dec'18	Natural gas – basis swap	10,000 MMBtu/day	$(0.678)	PEPL
Apr’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)
~~Jul’17~~Jan'19 – ~~Oct'17~~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	20,000 MMBtu/day	$(0.280)	NGPL TEXOK
Apr'18 – Sep'18	Natural gas – collar	~~20,000~~30,000 MMBtu/day	$~~2.88~~2.67 - ~~$3.10~~	~~IF – NYMEX (HH)~~
~~Jul'17 – Oct'17~~	~~Natural gas – three-way collar~~	~~15,000 MMBtu/day~~	~~$2.50 - $2.00 - $3.32~~	~~IF – NYMEX (HH)~~
~~Nov’17 – Dec'17~~	~~Natural gas – three-way collar~~	~~25,000 MMBtu/day~~	~~$2.90 - $2.30 - $3.59~~	~~IF – NYMEX (HH)~~
~~Jan'18 – Mar'18~~	~~Natural gas – three-way collar~~	~~60,000 MMBtu/day~~	~~$3.29 - $2.63 - $4.07~~$2.97	IF – NYMEX (HH)
Apr'18 – Dec'18	Natural gas – three-way collar	20,000 MMBtu/day	$3.00 - $2.50 - $3.51	IF – NYMEX (HH)
~~Jul’17~~Apr'18 – ~~Dec'17~~Dec'18	Crude oil – ~~three-way collar~~swap	~~3,750~~4,000 Bbl/day	$~~49.79 - $39.58 - $60.98~~53.52	WTI – NYMEX
~~Jan'18~~Apr'18 – Dec'18	Crude oil – three-way collar	~~1,000~~2,000 Bbl/day	$~~50.00~~47.50 - ~~$40.00~~$37.50 - ~~$56.65~~$56.08	WTI – NYMEX
Apr'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, 2017,~~March 31, 2018, the following ~~derivatives were~~derivative was entered into:



Term	Commodity	Contracted Volume	Weighted Average Fixed Price	Contracted Market
~~Jan'18~~Jan'19 – ~~Dec'18~~	~~Crude oil – swap~~	~~500 Bbl/day~~	~~$50.00~~	~~WTI – NYMEX~~
~~Jan'18 – Dec'18~~Dec'19	Crude oil – three-way collar	1,000 Bbl/day	$~~45.00~~55.00 - ~~$35.00~~$45.00 - ~~$55.50~~$70.25	WTI – NYMEX
Jan'20 – Dec'20	Natural gas – basis swap	10,000 MMBtu/day	$(0.265)	NGPL TEXOK

The following tables present the fair values and locations of the derivative transactions recorded in our Unaudited Condensed Consolidated Balance Sheets:


		Derivative Assets					Derivative Assets
		Fair Value					Fair Value
	Balance Sheet Location	June 30, 2017		December 31, 2016		Balance Sheet Location	March 31, 2018		December 31, 2017
		(In thousands)					(In thousands)
Commodity derivatives:
Current	Current derivative asset	$	3,948	$	—	Current derivative asset	$	537	$	721
Long-term	Non-current derivative asset	689		377		Non-current derivative asset	—		—
Total derivative assets		$	4,637	$	377		$	537	$	721


		Derivative Liabilities					Derivative Liabilities
		Fair Value					Fair Value
	Balance Sheet Location	June 30, 2017		December 31, 2016		Balance Sheet Location	March 31, 2018		December 31, 2017
		(In thousands)					(In thousands)
Commodity derivatives:
Current	Current derivative liability	$	1,036	$	21,564	Current derivative liability	$	12,104	$	7,763
Long-term	Non-current derivative liability	—		415		Non-current derivative liability	164		—
Total derivative liabilities		$	1,036	$	21,979		$	12,268	$	7,763

All of 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 in our Unaudited Condensed Consolidated Balance Sheets.

Following is the effect of derivative instruments on the Unaudited Condensed Consolidated Income Statements ~~of Operations~~ for the three months ended ~~June 30~~March 31:


Derivatives Instruments	Location of Gain (Loss) Recognized in Income on Derivative	Amount of Gain (Loss) Recognized in Income on Derivative					Location of Gain (Loss) Recognized in Income on Derivative	Amount of Gain (Loss) Recognized in Income on Derivative
		2017		2016				2018			2017
		(In thousands)						(In thousands)
Commodity derivatives	Gain (loss) on derivatives ⁽¹⁾	$	8,902	$	(22,672	)	Gain (loss) on derivatives ⁽¹⁾	$	(6,762	)	$	14,731
Total		$	8,902	$	(22,672	)		$	(6,762	)	$	14,731

_______________________


(1)	Amounts settled during the ~~2017~~2018 and ~~2016~~2017 periods include ~~a loss~~net payments of ~~$0.4~~$2.1 million and ~~a gain of $5.1~~$1.2 million, respectively.

~~Following is the effect of derivative instruments on the Unaudited Condensed Consolidated Statements of Operations 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
2017 2016
(In thousands)
Commodity derivatives
Gain (loss) on derivatives ⁽¹⁾
$ 23,633
$ (11,743 )
Total $ 23,633
$ (11,743 )

~~_______________________~~


~~(1)~~	~~Amounts settled during the 2017 and 2016 periods include a loss of $1.6 million and a gain of $12.2 million, respectively.~~

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, 2017 $ 830
$ 32
$ —
$ 862
December 31, 2016 $ —
$ —
$ —
$ —



	Cost		Gross Unrealized Gains		Gross Unrealized Losses		Estimated Fair Value
	(In thousands)
Equity Securities:
March 31, 2018	$	830	$	—	$	132	$	698
December 31, 2017	$	830	$	102	$	—	$	932

During the second quarter of 2017, we received available-for-sale securities for early termination fees associated with a long-term drilling contract. We will evaluate the marketable of those equity securities to determine if any decline in fair value below cost is other-than-temporary. If a decline in fair value below cost is determined to be other-than-temporary, an impairment charge will be recorded, and a new cost basis established. We will review several factors to determine whether a loss is other-than-temporary. These factors include, but are not limited to, (i) the ~~length of~~ time a security is in an unrealized loss position, (ii) the extent to which fair value is less than cost, (iii) the financial condition and near-term prospects of the issuer, and (iv) our intent and ability to hold the security for a period of time sufficient to allow for any anticipated recovery in fair value.

Fair value is defined as the amount that would be received from the sale of an asset or paid for ~~the transfer of~~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 ~~which are~~ 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:


	June 30, 2017														March 31, 2018
	Level 1		Level 2			Level 3			Effect of Netting			Net Amounts Presented			Level 1		Level 2			Level 3			Effect of Netting			Net Amounts Presented
	(In thousands)														(In thousands)
Financial assets (liabilities):
Commodity derivatives:
Assets	$	—	$	1,010		$	4,656		$	(1,029	)	$	4,637		$	—	$	2,897		$	1,294		$	(3,654	)	$	537
Liabilities	—		(1,502		)	(563		)	1,029			(1,036		)	—		(11,422		)	(4,500		)	3,654			(12,268		)
Total commodity derivatives	—		(492		)	4,093			—			3,601			—		(8,525		)	(3,206		)	—			(11,731		)
Equity securities	862		—			—			—			862			698		—			—			—			698
	$	862	$	(492	)	$	4,093		$	—		$	4,463		$	698	$	(8,525	)	$	(3,206	)	$	—		$	(11,033	)


	December 31, 2016														December 31, 2017
	Level 1		Level 2			Level 3			Effect of Netting			Net Amounts Presented			Level 1		Level 2			Level 3			Effect of Netting			Net Amounts Presented
	(In thousands)														(In thousands)
Financial assets (liabilities):
Commodity derivatives:
Assets	$	—	$	878		$	43		$	(544	)	$	377		$	—	$	2,137		$	3,344		$	(4,760	)	$	721
Liabilities	—		(15,358		)	(7,165		)	544			(21,979		)	—		(8,973		)	(3,550		)	4,760			(7,763		)
Total commodity derivatives															$	—	$	(6,836	)	$	(206	)	$	—		$	(7,042	)
Equity securities															932		—			—			—			932
	$	—	$	(14,480	)	$	(7,122	)	$	—		$	(21,602	)	$	932	$	(6,836	)	$	(206	)	$	—		$	(6,110	)

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 ~~June 30, 2017.~~March 31, 2018.

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 1 Fair Value Measurements

Equity Securities. We measure the fair values of our available for sale securities based on market quotes.

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												Net Derivatives
	Three Months Ended						Six Months Ended						Three Months Ended
	June 30,						June 30,						March 31,
	2017			2016			2017			2016			2018			2017
	(In thousands)												(In thousands)
Beginning of period	$	(602	)	$	9,983		$	(7,122	)	$	9,094		$	(206	)	$	(7,122	)
Total gains or losses (realized and unrealized):
Included in earnings ⁽¹⁾	5,214			(12,322		)	11,117			(6,334		)	(3,919		)	5,903
Settlements	(519		)	(2,422		)	98			(7,521		)	919			617
End of period	$	4,093		$	(4,761	)	$	4,093		$	(4,761	)	$	(3,206	)	$	(602	)
Total gains (losses) for the period included in earnings attributable to the change in unrealized gain relating to assets still held at end of period	$	4,695		$	(14,744	)	$	11,215		$	(13,855	)	$	(3,000	)	$	6,520

_______________________


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

The following table provides quantitative information about our Level 3 unobservable inputs at ~~June 30, 2017:~~March 31, 2018:


Commodity ⁽¹⁾	Fair Value			Valuation Technique	Unobservable Input	Range	Fair Value			Valuation Technique	Unobservable Input	Range
	(In thousands)						(In thousands)
Oil three-way collars	$	3,340		Discounted cash flow	Forward commodity price curve	($3.23) - $6.94	$	(4,457	)	Discounted cash flow	Forward commodity price curve	$0 - $9.41
Natural gas collar	$	(180	)	Discounted cash flow	Forward commodity price curve	($0.32) - $0.16	$	(1	)	Discounted cash flow	Forward commodity price curve	$0.01 - $0.12
Natural gas three-way collars	$	933		Discounted cash flow	Forward commodity price curve	($0.42) - $0.60	$	1,252		Discounted cash flow	Forward commodity price curve	$0 - $0.28

_______________________


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

Our valuation at ~~June 30, 2017~~March 31, 2018 reflected that the risk of non-performance by our counterparties was immaterial.

Fair Value of Other Financial Instruments

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

At ~~June 30, 2017~~March 31, 2018, the carrying values on the Unaudited Condensed Consolidated Balance Sheets for cash and cash equivalents (classified as Level 1), accounts receivable, accounts payable, other current assets, and current liabilities approximate their fair value because of their short-term nature.

Based on the borrowing rates ~~currently~~ available to us for credit agreement debt with similar terms and maturities and considering the risk of our non-performance, long-term debt under our credit agreement approximates its fair value and at ~~June 30, 2017~~March 31, 2018 and December 31, ~~2016~~2017 was ~~$164.9~~$147.7 million and ~~$160.8~~$178.0 million, respectively. This debt would be classified as Level 2.

The carrying amounts of long-term debt associated with the Notes, net of unamortized discount and debt issuance costs, ~~associated with the Notes~~ reported in the Unaudited Condensed Consolidated Balance Sheets as of ~~June 30, 2017~~March 31, 2018 and December 31, ~~2016~~2017 were ~~$641.2~~$642.8 million and $~~640.1~~642.3 million, respectively. We estimate the fair value of the Notes using quoted marked prices at ~~June 30, 2017~~March 31, 2018 and December 31, ~~2016~~2017 was $~~627.9~~632.9 million and $~~649.9~~649.7 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 the ~~Company’s~~company’s AROs is presented in Note 7 – Asset Retirement Obligations.

NOTE 12 – COMMITMENTS AND CONTINGENCIES

We lease office space or yards in Edmond and Oklahoma City, Oklahoma; Houston, Texas; Englewood, Colorado; Pinedale, Wyoming; and Canonsburg, Pennsylvania under the terms of operating leases expiring through December 2021. We also have several compressor rentals, equipment leases, and lease space on short-term commitments to stack excess drilling rig equipment and production inventory. Future minimum rental payments under the terms of the leases are approximately ~~$3.5~~$2.7 million, ~~$1.1~~$0.9 million, $0.4 million, ~~$0.3 million,~~ and less than $0.1 million in ~~twelve month~~twelve-month periods beginning ~~July~~April 1, ~~2017~~2018 (and through ~~the end of~~ 2021), respectively. Total rent expense incurred was ~~$4.2~~$2.3 million and ~~$6.2~~$2.1 million for the first ~~six~~three months of ~~2017~~2018 and ~~2016,~~2017, respectively.

In 2014, our mid-stream segment ~~entered into~~signed capital lease agreements for 20 compressors with initial terms of seven years. Estimated annual capital lease payments under the terms during the ~~five~~four successive ~~twelve month~~twelve-month periods beginning ~~July~~April 1, ~~2017~~2018 (and through the end of 2021) are $6.2 million, $6.2 million, ~~$6.2 million, $6.7~~$7.8 million, and ~~$0.2~~$0.6 million. Total maintenance and interest remaining related to these leases are ~~$6.8~~$5.4 million and ~~$1.5~~$1.0 million, respectively at ~~June 30, 2017.~~March 31, 2018. Annual payments, net of maintenance and interest, average ~~$4.1~~$4.2 million annually through 2021. At the end of the term, our mid-stream segment has the option to purchase the assets at 10% of their then fair market value.

The employee oil and gas limited partnerships require, on the election of a limited partner, that we repurchase the limited partner’s interest at amounts to be determined by appraisal. In any one year, these repurchases are limited to 20% of the units outstanding. We had no repurchases in the first ~~six months~~quarter of ~~2017~~2018 or ~~2016.~~2017.

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 risk is borne by the operator. Any liabilities we have incurred have been small and have been resolved while the drilling rig is on the location and the cost has been included in the direct cost of drilling the well.

For the next twelve months, we have committed to purchase approximately ~~$3.9~~$3.4 million of new drilling rig components.

NOTE 13 – EQUITY

At-the-Market (ATM) Common Stock Program

On April 4, 2017, we ~~entered into~~signed a Distribution Agreement (the Agreement) with a sales agent, under which we may offer and sell, from time to time, through the sales agent shares of our common stock, par value $.20 per share (the Shares), up to an aggregate offering price of $100.0 million. We intend to use the net proceeds from these sales to fund (or offset costs of) acquisitions, future capital expenditures, repay amounts outstanding under our revolving credit facility, and general corporate purposes.

Under the Agreement, the sales agent may sell the Shares by methods deemed to be an “at-the-market” offering as defined in Rule 415 promulgated under the Securities Act of 1933, as amended, including sales made directly on the NYSE, on any other existing trading market for the Shares or to or through a market maker. In addition, under the Agreement, the sales agent may sell the Shares by any other method permitted by law, including in privately negotiated transactions. Subject to the terms ~~and conditions~~ of the Agreement, the sales agent will use commercially reasonable efforts, consistent with its normal trading and sales practices and applicable state and federal law, rules and regulations and the rules of the NYSE, to sell the Shares from

time to time, based on our instructions (including any price, time or size limits or other customary parameters or conditions ~~that~~ we may impose).

We ~~are~~do not ~~obligated~~have to make any sales of the Shares under the Agreement. The offering of Shares under the Agreement will terminate on the earlier of (1) the sale of all of the Shares subject to the Agreement or (2) the termination of the Agreement by the sales agent or us. We will pay the sales agent a commission of 2.0% of the gross sales price per share sold and have agreed to provide the sales agent with customary indemnification and contribution rights.

As of ~~June 30, 2017,~~March 31, 2018, we have sold 787,547 shares of our common stock resulting in net proceeds of approximately $18.6 million. No shares were sold in the first quarter of 2018. On May 2, 2018, we terminated this Agreement, the details are discussed in Note 15 — Subsequent Events.

Accumulated Other Comprehensive Income

Components of accumulated other comprehensive income were as follows for the three ~~and six~~ months ended ~~June 30:~~March 31:

2017 2016
(In thousands)
Unrealized appreciation on securities, before tax $ 32
$ —
Tax expense (12 ) —
Unrealized appreciation on securities, net of tax $ 20
$ —



	2018				2017
	(In thousands)
Unrealized loss on securities, before tax	$	(234	)		$	—
Tax expense	58			⁽¹⁾	—
Unrealized loss on securities, net of tax	$	(176	)		$	—

_______________________


(1)	Due to the implementation of ASU 2018-02, the tax rate changed from 37.75% to 24.5%.

Changes in accumulated other comprehensive income by component, net of tax, for the three ~~and six~~ months ended ~~June 30~~March 31 are as follows:

Net Gains on Equity Securities
2017 2016
(In thousands)
Beginning balance $ —
$ —
Other comprehensive gain before reclassifications 20
—
Amounts reclassified from accumulated other comprehensive income —
—
Net current-period other comprehensive income 20
—
Balance at June 30 $ 20
$ —



	Net Gains on Equity Securities
	2018				2017
	(In thousands)
Balance at December 31, 2017	$	63			$	—
Adjustment due to ASU 2018-02	13			⁽¹⁾	—
Balance at January 1:	76				—
Unrealized loss before reclassifications	(176		)	⁽¹⁾	—
Amounts reclassified from accumulated other comprehensive income	—				—
Net current-period other comprehensive income	(176		)		—
Balance at March 31:	$	(100	)		$	—

_______________________


(1)	Due to the implementation of ASU 2018-02, the tax rate changed from 37.75% to 24.5%.

NOTE 14 – 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 June 30, 2017																Three Months Ended March 31, 2018
	Oil and Natural Gas		Contract Drilling			Mid-stream		Other			Eliminations			Total Consolidated			Oil and Natural Gas		Contract Drilling		Mid-stream		Other			Eliminations			Total Consolidated
	(In thousands)																(In thousands)
Revenues:(1)
Oil and natural gas	$	83,173	$	—		$	—	$	—		$	—		$	83,173		$	103,099	$	—	$	—	$	—		$	—		$	103,099
Contract drilling	—		44,844			—		—			(5,589		)	39,255			—		50,710		—		—			(4,721		)	45,989
Gas gathering and processing	—		—			63,111		—			(14,958		)	48,153			—		—		74,650		—			(18,606		)	56,044
Total revenues	83,173		44,844			63,111		—			(20,547		)	170,581			103,099		50,710		74,650		—			(23,327		)	205,132
Expenses:
Operating costs:
Oil and natural gas	33,941		—			—		—			(1,183		)	32,758			37,152		—		—		—			(1,190		)	35,962
Contract drilling	—		32,452			—		—			(5,213		)	27,239			—		35,954		—		—			(4,287		)	31,667
Gas gathering and processing	—		—			49,817		—			(13,775		)	36,042			—		—		59,020		—			(17,416		)	41,604
Total operating costs	33,941		32,452			49,817		—			(20,171		)	96,039			37,152		35,954		59,020		—			(22,893		)	109,233
Depreciation, depletion, and amortization	23,558		13,769			10,849		1,904			—			50,080			30,783		13,312		11,053		1,918			—			57,066
Total expenses	57,499		46,221			60,666		1,904			(20,171		)	146,119			67,935		49,266		70,073		1,918			(22,893		)	166,299
Total operating income (loss) ⁽¹⁾⁽²⁾	25,674		(1,377		)	2,445		(1,904		)	(376		)				35,164		1,444		4,577		(1,918		)	(434		)
General and administrative expense	—		—			—		(8,713		)	—			(8,713		)	—		—		—		(10,762		)	—			(10,762		)
Gain on disposition of assets	168		31			44		5			—			248			71		26		34		30			—			161
Gain on derivatives	—		—			—		8,902			—			8,902
Loss on derivatives																	—		—		—		(6,762		)	—			(6,762		)
Interest expense, net	—		—			—		(9,467		)	—			(9,467		)	—		—		—		(10,004		)	—			(10,004		)
Other	—		—			—		6			—			6			—		—		—		6			—			6
Income (loss) before income taxes	$	25,842	$	(1,346	)	$	2,489	$	(11,171	)	$	(376	)	$	15,438		$	35,235	$	1,470	$	4,611	$	(29,410	)	$	(434	)	$	11,472

_______________________


(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.


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

Three Months Ended June 30, 2016
Oil and Natural Gas Contract Drilling Mid-stream Other Eliminations Total Consolidated
(In thousands)
Revenues:
Oil and natural gas $ 69,190
$ —
$ —
$ —
$ —
$ 69,190
Contract drilling —
24,257
—
—
—
24,257
Gas gathering and processing —
—
56,533
—
(11,675 ) 44,858
Total revenues 69,190
24,257
56,533
—
(11,675 ) 138,305
Expenses:
Operating costs:
Oil and natural gas 35,555
—
—
—
(2,224 ) 33,331
Contract drilling —
19,254
—
—
—
19,254
Gas gathering and processing —
—
41,832
—
(9,451 ) 32,381
Total operating costs 35,555
19,254
41,832
—
(11,675 ) 84,966
Depreciation, depletion, and amortization 30,411
10,918
11,515
34
—
52,878
Impairments 74,291
—
—
—
—
74,291
Total expenses 140,257
30,172
53,347
34
(11,675 ) 212,135
Total operating income (loss)⁽¹⁾
(71,067 ) (5,915 ) 3,186
(34 ) —

General and administrative expense —
—
—
(8,348 ) —
(8,348 )
Gain (loss) on disposition of assets (324 ) 815
—
(14 ) —
477
Loss on derivatives —
—
—
(22,672 ) —
(22,672 )
Interest expense, net —
—
—
(10,606 ) —
(10,606 )
Other —
—
—
1
—
1
Income (loss) before income taxes $ (71,391 ) $ (5,100 ) $ 3,186
$ (41,673 ) $ —
$ (114,978 )

~~_______________________~~


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


	Six Months Ended June 30, 2017																Three Months Ended March 31, 2017
	Oil and Natural Gas		Contract Drilling			Mid-stream		Other			Eliminations			Total Consolidated			Oil and Natural Gas		Contract Drilling			Mid-stream		Other			Eliminations			Total Consolidated
	(In thousands)																(In thousands)
Revenues:
Oil and natural gas	$	170,771	$	—		$	—	$	—		$	—		$	170,771		$	87,598	$	—		$	—	$	—		$	—		$	87,598
Contract drilling	—		82,029			—		—			(5,589		)	76,440			—		37,185			—		—			—			37,185
Gas gathering and processing	—		—			129,575		—			(30,481		)	99,094			—		—			66,464		—			(15,523		)	50,941
Total revenues	170,771		82,029			129,575		—			(36,070		)	346,305			87,598		37,185			66,464		—			(15,523		)	175,724
Expenses:
Operating costs:
Oil and natural gas	64,267		—			—		—			(2,305		)	61,962			30,326		—			—		—			(1,122		)	29,204
Contract drilling	—		61,679			—		—			(5,213		)	56,466			—		29,227			—		—			—			29,227
Gas gathering and processing	—		—			101,922		—			(28,176		)	73,746			—		—			52,105		—			(14,401		)	37,704
Total operating costs	64,267		61,679			101,922		—			(35,694		)	192,174			30,326		29,227			52,105		—			(15,523		)	96,135
Depreciation, depletion, and amortization	45,084		26,616			21,667		3,645			—			97,012			21,526		12,847			10,818		1,741			—			46,932
Total expenses	109,351		88,295			123,589		3,645			(35,694		)	289,186			51,852		42,074			62,923		1,741			(15,523		)	143,067
Total operating income (loss)⁽¹⁾	61,420		(6,266		)	5,986		(3,645		)	(376		)				35,746		(4,889		)	3,541		(1,741		)	—
General and administrative expense	—		—			—		(17,667		)	—			(17,667		)	—		—			—		(8,954		)	—			(8,954		)
Gain on disposition of assets	177		38			44		813			—			1,072			9		7			—		808			—			824
Gain on derivatives	—		—			—		23,633			—			23,633			—		—			—		14,731			—			14,731
Interest expense, net	—		—			—		(18,863		)	—			(18,863		)	—		—			—		(9,396		)	—			(9,396		)
Other	—		—			—		9			—			9			—		—			—		3			—			3
Income (loss) before income taxes	$	61,597	$	(6,228	)	$	6,030	$	(15,720	)	$	(376	)	$	45,303		$	35,755	$	(4,882	)	$	3,541	$	(4,549	)	$	—		$	29,865

_______________________


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

NOTE 15 – SUBSEQUENT EVENTS

On April 2, 2018, the company, including certain of its subsidiaries signed a Fourth Amendment to our Senior Credit Agreement (Fourth Amendment) with these lenders: BOKF, NA (dba Bank of Oklahoma); Compass Bank; BMO Harris Financing, Inc.; Bank of America, N.A.; Wells Fargo Bank, N.A.; Comerica Bank; Canadian Imperial Bank of Commerce, New York Branch; and Toronto Dominion (New York), LLC. BOKF, NA is serving as administrative agent for the other lenders under the Fourth Amendment.

Six Months Ended June 30, 2016
Oil and Natural Gas Contract Drilling Mid-stream Other Eliminations Total Consolidated
(In thousands)
Revenues:
Oil and natural gas $ 127,464
$ —
$ —
$ —
$ —
$ 127,464
Contract drilling —
62,967
—
—
—
62,967
Gas gathering and processing —
—
105,578
—
(21,520 ) 84,058
Total revenues 127,464
62,967
105,578
—
(21,520 ) 274,489
Expenses:
Operating costs:
Oil and natural gas 70,361
—
—
—
(3,684 ) 66,677
Contract drilling —
47,352
—
—
—
47,352
Gas gathering and processing —
—
81,283
—
(17,836 ) 63,447
Total operating costs 70,361
47,352
81,283
—
(21,520 ) 177,476
Depreciation, depletion, and amortization 62,243
23,113
22,974
138
—
108,468
Impairments 112,120
—
—
—
—
112,120
Total expenses 244,724
70,465
104,257
138
(21,520 ) 398,064
Total operating income (loss)⁽¹⁾
(117,260 ) (7,498 ) 1,321
(138 ) —

General and administrative expense —
—
—
(16,959 ) —
(16,959 )
Gain (loss) on disposition of assets (324 ) 1,316
(302 ) —
(21 ) —
669
Loss on derivatives —
—
—
(11,743 ) —
(11,743 )
Interest expense, net —
—
—
(20,223 ) —
(20,223 )
Other —
—
—
(14 ) —
(14 )
Income (loss) before income taxes $ (117,584 ) $ (6,182 ) $ 1,019
$ (49,098 ) $ —
$ (171,845 )

~~_______________________~~The Fourth Amendment was signed in connection with our sale of 50% of our ownership interest in our midstream segment, Superior Pipeline Company, L.L.C. One of the conditions of that sale was the release of Superior from the terms of the credit agreement. Since the Fourth Amendment needed to be signed before the closing of the Superior sale it was designed to account for the possibility the Superior sale might not close as anticipated. The Fourth Amendment provides, among other things, for a reduction of the maximum credit amount from $875.0 million to $475.0 million, and an increase in the borrowing base from $475.0 million to $525.0 million; provide that part of the proceeds from the sale be used to pay down the existing outstanding principal balance under the credit agreement. Once that payment was made on April 3, 2018-(i) the total commitment amount was reduced from $475.0 million to $425.0 million; (ii) the maximum credit amount was reduced from $475.0 million to $425.0 million and set as the amount that would otherwise be subject to redetermination in April; (iii) the borrowing base was reduced from $525.0 million to $425.0 million; and (iv) Superior and its subsidiaries (Superior), were fully released as a borrower and co-obligor under the credit agreement. The Superior sale closed on April 3, 2018 and the paydown under the credit agreement was made that same day.


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

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 (Purchaser), for

cash consideration of $300.0 million. The sale closed under the purchase and sale agreement (the Purchase Agreement) dated March 28, 2018 and closed on April 3, 2018. Part of the proceeds from the sale 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, the company and its board of directors took the necessary actions under the Indenture governing the company's outstanding senior subordinated notes to secure the ability to close the sale and to have Superior released from the Indenture.

Superior will be governed and managed by the Amended and Restated Limited Liability Company Agreement and Master Services and Operating Agreement, respectively, both of which are included as exhibits to the Purchase and Sale Agreement filed with this report.

On May 2, 2018, we terminated the Distribution Agreement dated April 4, 2017, as amended (the Distribution Agreement), between the company and Raymond James & Associates, Inc. (the Sales Agent). The Distribution Agreement was terminable at will on written notification by the company with no penalty. Under the Distribution Agreement, the company was entitled to issue and sell, from time to time, through or to the Sales Agent shares of its common stock, having an aggregate offering price of up to $100.0 million in an “at-the-market” offering program. As of the date of termination, the company sold 787,547 shares of its Common Stock under the Distribution Agreement. As a result of the termination, there will be no more sales of the our common stock under the Distribution Agreement.

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 ~~the following~~these sections:

General;

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 with your review of the information below ~~as well as~~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.

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 our subsidiary Superior Pipeline Company, L.L.C. and its subsidiaries. This segment buys, sells, gathers, processes, and treats natural gas for third parties and for our oil and natural gas segment.

Business Outlook

As discussed in other parts of this report, 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, ~~as well as,~~and the demand for our drilling rigs which ~~in turn,~~ influences the amounts we can charge for those drilling rigs. While our operations are ~~located~~ within the United States, events outside the United States affect us and our industry.

~~Deteriorating~~Fluctuating commodity prices worldwide during the past several years brought about significant and adverse changes to our industry and us. ~~As a result we reduced or stopped, for a period of time, our oil and natural gas segment's drilling activity.~~ Industry wide reductions in drilling activity and spending for extended periods ~~also tends to reduce~~reduces the rates for and the number of our drilling rigs ~~that~~ we can work. In addition, sustained lower commodity prices impact the liquidity condition of some of our industry partners and customers, which ~~in turn,~~ could limit their ability to meet their financial obligations to us.

~~During 2016,~~Recently, commodity prices ~~began to improve. In~~have improved. During the ~~fourth~~first quarter of ~~2016,~~2018, our oil and natural gas segment ~~began using two~~used four of our drilling rigs and ~~has continued using them~~used three to four during ~~the first six months of~~ 2017. Our contract drilling segment completed the construction and contracted ~~the ninth and~~our tenth BOSS drilling ~~rigs~~rig in ~~the fourth quarter of 2016 and~~ the second quarter of 2017, ~~respectively.~~and is constructing the eleventh. Our drilling rig segment's rig utilization increased from 16an average of 25.5 drilling rigs working asduring the first quarter of ~~June 30, 2016,~~2017 to 3331.7 average drilling rigs working ~~as of June 30, 2017. The extent and duration of this improvement remains uncertain.~~

~~The reduction in oil, NGLs, and natural gas prices had a number of consequences for us (although, as noted, we are starting to see some improvements). Below are some of those consequences:~~

~~We incurred non-cash ceiling test write-downs in~~during the first ~~nine months~~quarter of ~~2016 of $161.6 million ($100.6 million net of tax). We did not have a write-down~~2018. Rig utilization fluctuated over the past year due to commodity prices changing and budget constraints on operators in the fourth quarter of ~~2016 or~~2017. We expect this same trend to continue in 2018.

Other recent improvements:

We have not incurred a non-cash ceiling test write-down since 2016. We had no write-down in the first ~~two quarters~~quarter of 2018 nor the first quarter of 2017. 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 ~~June 30, 2017~~March 31, 2018, and only adjust the 12-month average price to an estimated ~~third~~second quarter ending average (holding ~~July 2017~~April 2018 prices constant for the remaining two months of the ~~third~~second quarter of ~~2017)~~2018), our forward looking expectation is that we will not recognize an impairment in the ~~third~~second quarter of ~~2017.~~2018. But commodity prices (and other factors) remain volatile and they could negatively ~~impact~~affect the 12-month average price resulting in the potential for ~~an impairment in the future.~~a future impairment.

We ~~reduced~~increased the number of gross wells our oil and natural gas segment ~~drilled~~plan to drill in ~~2016 by approximately 64% from the number drilled in 2015 due~~2018 to ~~our reduced cash flow. For~~75-85 wells (depending on future commodity prices). In 2017, we ~~plan to increase~~increased the number of gross wells drilled ~~by approximately 67-90% (depending on future commodity prices)~~to 70 from ~~the number of wells drilled~~21 in ~~2016.~~

~~The decline in drilling by our customers reduced the average utilization of our drilling rig fleet. At December 31, 2015, we had 26 drilling rigs operating. In~~ 2016 utilization continued downward bottoming out in May 2016 at 13 operating drilling rigs. After May commodity prices began improving for the remainder of the year and we exited 2016 with 21 active rigs. As of June 30, 2017, we had 33 drilling rigs operating (an improvement of 57% over the end of the year). Operators have been increasing drilling, but the extent of further increases remain uncertain. During the second quarter of 2017, we completed the construction of our tenth BOSS drilling rig and all of our BOSS drilling rigs are under contract.

~~Due~~due to low NGLs prices, we continue to operate most of our mid-stream processing facilities in ethane rejection mode which reduces the amount of liquids sold. As long as NGLs prices remain depressed, we expect to continue operating in ethane rejection mode.

Also, as noted elsewhere, beginning on April 4, 2017, we began an at-the-market offering for the sale of shares of our common stock. The offering allows us to sell shares, from time to time, up to an aggregate of $100 million in gross proceeds. As of June 30, 2017, we sold 787,547 shares for $18.6 million, net of offering costs of $0.4 million. Approximately $81.0 million remain available for sale under the program. Net proceeds from the offering will be used to fund (or offset costs of) acquisitions, future capital expenditures, repay amounts outstanding under our revolving credit facility, and general corporate purposes.increased cash flow.

On April 3, ~~2017, we closed~~2018, the company completed the sale of 50% of the ownership interests in Superior to 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, for cash consideration of $300 million. Part of the proceeds from the sale were used to pay down our bank debt and the balance 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.

The unaudited pro forma consolidated income statement for the quarter ended March 31, 2018, if presented, would contain an ~~acquisition~~adjustment to increase net income for $2.2 million resulting from the reduction in interest due to the payment of ~~certain oil~~bank debt and ~~natural gas assets~~the benefit from lower effective tax rate due to non-controlling interest. There is also an ~~unrelated third party. The acquisition includes approximately 47 proved developed producing wells and 8,300~~adjustment of $1.6 million of net ~~acres primarily in Grady and Caddo Counties in western Oklahoma. The preliminary adjusted value of consideration given was $54.0 million. This acquisition is subject~~income attributable to ~~certain post-closing adjustments. The effective date of this acquisition is January 1, 2017.~~the non-controlling interest.

The following unaudited pro forma consolidated balance sheet totals at March 31, 2018 set forth below gives effect to the Superior sale and the reduction of our bank debt as if it had occurred on that date. The unaudited pro forma balance sheet is provided for illustrative purposes only and does not purport to represent what our actual financial position would have been if the sale had occurred on the dates indicated, nor is it necessarily indicative of our future operating results or financial position.



	March 31, 2018
	As Reported		Adjustment				Pro Forma
	(In thousands except share and par value amounts)
Total assets	$	2,599,591	$	149,692		⁽¹⁾	$	2,749,283
Total liabilities	1,242,291		(122,475		)	⁽²⁾	1,119,816
Total shareholders' equity	1,357,300		272,167			⁽³⁾	1,629,467

_________________________


(1)	Represents $300.0 million cash consideration from SP Investor Holdings, LLC for 50% ownership interests in Superior less $2.6 million of transaction costs and $147.7 million of bank debt reduction.


(2)	Represents$147.7 million of bank debt reduction and all tax related effects of the transaction for $25.2 million based on the statutory rate of 24.5%.


(3)	Represents the $300.0 million cash consideration less $2.6 million of transaction costs, and $25.2 million of taxes.

Executive Summary

Oil and Natural Gas

~~Second~~First quarter~~2017~~ 2018 production from our oil and natural gas segment was ~~3,852,000~~4,181,000 barrels of oil equivalent (Boe), a decrease of 3% from the fourth quarter of 2017 and an increase of 2%11% over the first quarter of 2017, ~~and a~~ respectively. The decrease ~~of 12%~~ from the ~~second~~fourth quarter of ~~2016, respectively.~~2017 was due to delays in completing newer wells drilled. The increase over the first quarter of 2017 was primarily from acquired wells and new wells drilled ~~in the first six months of~~during 2017. The decrease from the second quarter of 2016 was primarily due to the continued production decline of existing wells and reduced drilling activity between the periods. Second quarter 2017 production was also negatively affected by approximately 94,000 Boe due to third party gas processing outages and the delay of several fracture stimulation jobs from early May until early June.

~~Second~~

First quarter ~~2017~~2018 oil and natural gas revenues ~~decreased 5% from~~increased 2% over the fourth quarter of 2017 and increased 18% over the first quarter of 2017. The increase over the fourth quarter of 2017 was due primarily to higher oil and natural gas prices and increased ~~20%~~oil volumes partially offset by lower NGLs and natural gas production volumes and lower NGLs prices. The increase over ~~the second quarter of 2016. The decrease from~~ the first quarter of 2017 was due primarily to ~~lower commodity~~higher oil and NGLs prices ~~partially offset by~~and higher production volumes. ~~The increase over the second quarter of 2016 was due primarily to higher commodity prices partially offset by lower production volumes.~~

Our oil prices for the ~~second~~first quarter of ~~2017 decreased 4% from~~2018 increased 1% over the ~~first~~fourth quarter of 2017 and increased 13% over the ~~second~~first quarter of ~~2016.~~2017. Our NGLs prices decreased ~~16%~~4% from the fourth quarter of 2017 and increased 18% over the first quarter of 2017. Our natural gas prices increased 10% over the fourth quarter of 2017 and decreased 2% from the first quarter of ~~2017 and increased 31% over the second~~

~~quarter of 2016. Our natural gas prices decreased 9% from the first quarter of 2017 and increased 36% over the second quarter of 2016.~~2017.

Operating cost per Boe produced for the ~~second~~first quarter of 2018 increased 6% over the fourth quarter of 2017 and increased ~~10% and~~ 11% over the first quarter of ~~2017 and~~2017. The increase over the ~~second~~fourth quarter of ~~2016, respectively.~~2017 was primarily due to higher lease operating expenses, saltwater disposal, and gross production tax expense, partially offset by lower production volumes. The increase over the first quarter of 2017 was primarily due to ~~an increase in~~higher lease operating expenses, production taxes, saltwater disposal expense, and ~~increased production taxes after receiving a higher amount of tax refunds. The increase over the second quarter of 2016 was primarily due to lower production volumes~~general and administrative expense partially offset by ~~lower lease operating expenses.~~higher production volumes.

At ~~June 30, 2017, we had~~March 31, 2018, these derivatives were outstanding:



Term	Commodity	Contracted Volume	Weighted Average Fixed Price	Contracted Market
~~Jul’17~~Apr’18 – ~~Oct'17~~Sep'18	Natural gas – swap	~~70,000~~40,000 MMBtu/day	$~~3.038~~2.985	IF – NYMEX (HH)
~~Nov’17 – Dec'17~~Oct'18	Natural gas – swap	~~60,000~~30,000 MMBtu/day	$~~2.960~~3.005	IF – NYMEX (HH)
~~Jan’18~~Nov’18 – Dec'18	Natural gas – swap	20,000 MMBtu/day	$3.013	IF – NYMEX (HH)
~~Nov’17~~Apr'18 – ~~Dec'17~~	~~Natural gas – basis swap~~	~~20,000 MMBtu/day~~	~~$(0.215)~~	~~IF – NYMEX (HH)~~
~~Jan’18 – Mar'18~~Oct'18	Natural gas – basis swap	10,000 MMBtu/day	$~~(0.208)~~(0.190)	IFNGPL TEXOK
Apr'18 – ~~NYMEX (HH)~~Dec'18	Natural gas – basis swap	10,000 MMBtu/day	$(0.678)	PEPL
Apr’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)
~~Jul’17~~Jan'19 – ~~Oct'17~~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	20,000 MMBtu/day	$(0.280)	NGPL TEXOK
Apr'18 – Sep'18	Natural gas – collar	~~20,000~~30,000 MMBtu/day	$~~2.88~~2.67 - ~~$3.10~~	~~IF – NYMEX (HH)~~
~~Jul'17 – Oct'17~~	~~Natural gas – three-way collar~~	~~15,000 MMBtu/day~~	~~$2.50 - $2.00 - $3.32~~	~~IF – NYMEX (HH)~~
~~Nov’17 – Dec'17~~	~~Natural gas – three-way collar~~	~~25,000 MMBtu/day~~	~~$2.90 - $2.30 - $3.59~~	~~IF – NYMEX (HH)~~
~~Jan'18 – Mar'18~~	~~Natural gas – three-way collar~~	~~60,000 MMBtu/day~~	~~$3.29 - $2.63 - $4.07~~$2.97	IF – NYMEX (HH)
Apr'18 – Dec'18	Natural gas – three-way collar	20,000 MMBtu/day	$3.00 - $2.50 - $3.51	IF – NYMEX (HH)
~~Jul’17~~Apr'18 – ~~Dec'17~~Dec'18	Crude oil – ~~three-way collar~~swap	~~3,750~~4,000 Bbl/day	$~~49.79 - $39.58 - $60.98~~53.52	WTI – NYMEX
~~Jan'18~~Apr'18 – Dec'18	Crude oil – three-way collar	~~1,000~~2,000 Bbl/day	$~~50.00~~47.50 - ~~$40.00~~$37.50 - ~~$56.65~~$56.08	WTI – NYMEX
Apr'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, 2017,~~March 31, 2018, the following ~~derivatives were~~derivative was entered into:



Term	Commodity	Contracted Volume	Weighted Average Fixed Price	Contracted Market
~~Jan'18~~Jan'19 – ~~Dec'18~~	~~Crude oil – swap~~	~~500 Bbl/day~~	~~$50.00~~	~~WTI – NYMEX~~
~~Jan'18 – Dec'18~~Dec'19	Crude oil – three-way collar	1,000 Bbl/day	$~~45.00~~55.00 - ~~$35.00~~$45.00 - ~~$55.50~~$70.25	WTI – NYMEX
Jan'20 – Dec'20	Natural gas – basis swap	10,000 MMBtu/day	$(0.265)	NGPL TEXOK

For the ~~six~~three months ended ~~June 30, 2017,~~March 31, 2018, we completed drilling 1915 gross wells ~~(8.21~~(5.40 net wells). For all of ~~2017,~~2018, we ~~plan to participate~~anticipate participating in the drilling of approximately 3575 to 4085 gross wells.Excluding acquisitions and ARO liability, our estimated ~~2017~~2018 capital expenditures for this segment are approximately ~~$197.0~~$272.0 million. Our current ~~2017~~2018 production guidance is approximately ~~16.0~~17.1 to ~~16.5~~17.4 MMBoe, ~~a decrease~~an increase of ~~4% to 7%~~7-9% from ~~2016,~~2017, although actual results continue to be subject to many factors.

Contract Drilling

The average number of drilling rigs we operated in the ~~second~~first quarter of 2018 was 31.7 compared to 31.2 and 25.5 in the fourth quarter of 2017 ~~was 28.8 compared to 25.5~~ and ~~13.5 in~~ the first quarter of 2017, ~~and the second quarter of 2016,~~ respectively. As of ~~June 30, 2017, 33~~March 31, 2018, 32 of our drilling rigs were operating.

Revenue for the ~~second~~first quarter of 2018 decreased 1% from the fourth quarter of 2017 and increased ~~6% and 62%~~24% over the first quarter of 2017, ~~and~~respectively. The decrease from the ~~second~~fourth quarter of ~~2016, respectively. The increases were~~2017 was primarily due to a decrease in mobilization and other revenues partially offset by an increase in drilling rigs operating ~~partially offset by lower dayrates between the second quarter of 2017~~ and ~~the second quarter of 2016.~~

~~Dayrates for the second quarter of 2017 averaged $15,962, a 1% increase over the first quarter of 2017 and a 14% decrease from the second quarter of 2016.~~dayrates. The increase over the first quarter of 2017 was primarily due to increased ~~demand. The decrease from the second quarter of 2016 was primarily due to downward pressure on dayrates due to lower demand.~~utilization and an increase in dayrates.

~~Operating costs~~Dayrates for ~~the second quarter of 2017 decreased 7% from~~ the first quarter of 2018 averaged $17,038, a 2% increase over the fourth quarter of 2017 and ~~increased 41%~~an 8% increase over the ~~second~~first quarter of ~~2016.~~2017. The ~~decrease from~~increase over the ~~first~~fourth quarter of 2017 was primarily due to ~~less new rig activation costs.~~a labor increase in the first quarter of 2018 passed through to contracted rigs. The

increase over the ~~second~~first quarter of ~~2016~~2017 was due to two labor increases passed through to contracted rigs and improving market dayrates.

Operating costs for the first quarter of 2018 increased 1% over the fourth quarter of 2017 and increased 8% over the first quarter of 2017. The increases were due primarily to more drilling rigs ~~operating partially offset by decreased per day cost.~~

Almost all of our working drilling rigs were drilling horizontal or directional wells for oil and NGLs. The improved commodity pricing for oil and natural gas that began during the second half of 2016 has increased demand for drilling rigs. Our drilling rig count bottomed out at 13 drilling rigs operating during the second quarter of 2016, but increased to 21 drilling rigs operating at the end of 2016. Our drilling rig count continued to increase during the first half of 2017 ending at 33 operating drilling rigs. The future demand for and the availability of drilling rigs to meet that demand will affect our future dayrates.operating.

We have 15six term drilling contracts with original terms ranging from six months to two years. ~~Seven are~~One is up for renewal in the second quarter of 2018, two in the third quarter of ~~2017, six~~2018, two in the fourth quarter of ~~2017, one is up for renewal in~~ 2018, and one in 2019. 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 with signed term contracts opted to release the drilling rig and pay an early termination penalty for the remaining term of the contract. During the first six months of 2017, we recorded $0.8 million of early termination fees compared to $3.0 million in the first six months of 2016.

All ten of our existing BOSS drilling rigs are under contract. Construction was completed on our tenth BOSS drilling rig and the rig was placed into service late in the second quarter. We also have contracted and placed into service three of our stacked SCR drilling rigs in our Mid-Continent division during the second quarter. One SCR drilling rig was upgraded, one was relocated from our Rocky Mountain division, and the third SCR rig required no modifications. We have two additional stacked SCR drilling rigs returning to service in the third quarter. Both in our Mid-Continent division. One is being relocated from our Rocky Mountain division. Our estimated ~~2017~~2018 capital expenditures for this segment are approximately ~~$28.0~~$47.0 million.

Competition to keep qualified labor continues to be an issue we face in this ~~segment.~~segment and in response, we implemented pay rate increases in certain areas in the first quarter of 2018. We do not believe this shortage of qualified labor will keep us from working additional drilling rigs, but it could cause some delays in the time to crew new drilling rigs. ~~Beginning in third quarter 2017, we increased compensation for certain drilling rig personnel.~~

Mid-Stream

~~Second~~First quarter ~~2017~~2018 liquids sold per day decreased 1% from the fourth quarter of 2017 and increased 6%16% over the first quarter of 2017, ~~and decreased 1%~~respectively. The decrease from the ~~second~~fourth quarter of ~~2016, respectively.~~2017 was due to lower recoveries at our processing facilities. The increase over the first quarter of 2017 was ~~due to increased volumes at our processing facilities. The decrease from the second quarter of 2016 was~~ primarily due to ~~less~~increased volume available to process at our ~~plants.~~plants due to additional well connects. For the ~~second~~first quarter of ~~2017,~~2018, gas processed per day increased 7%2% over the fourth quarter of 2017 and increased 19% over the first quarter of ~~2017 and decreased 16% from~~2017. The increase over the ~~second~~fourth quarter of ~~2016.~~2017 was primarily due to higher processed volumes from new wells at our Cashion facility and our Hemphill facility. The increase over the first quarter of 2017 was primarily due to higher ~~volumes at our Cashion facility~~volume from ~~an offload and more drilling activity at our Hemphill facility. The decrease from the second quarter of 2016 was primarily due to declines in existing volumes, fewer~~ new wells connected ~~and losing an offload volume~~ at our ~~Hemphill facility in mid-2016.~~processing facilities. For the ~~second~~first quarter of ~~2017,~~2018, gas gathered per day decreased 2%3% and ~~13%~~4% from the fourth quarter of 2017 and the first quarter of 2017, respectively. The decrease from the fourth quarter of 2017 and the ~~second~~first quarter of ~~2016, respectively. The decreases were~~2017 was primarily due to declining gathered volume on our Appalachian ~~systems and losing an offload volume at our Hemphill facility in mid-2016.~~gathering systems.

NGLs prices in the ~~second~~first quarter of 2018 decreased 9% from the prices received in the fourth quarter of 2017 ~~decreased 12% from~~and increased 19% over the prices received in the first quarter of ~~2017 and increased 9% over the prices received in the second quarter of 2016.~~2017. Because certain of the contracts used by our mid-stream segment for NGLs transactions are commodity-based contracts–under which we receive a share of the proceeds from the sale of the NGLs–our revenues from those commodity-based contracts fluctuate based on the price of NGLs.

Total operating cost for our mid-stream segment for the ~~second~~first quarter of ~~2017~~2018 decreased 4%5% from the ~~first~~fourth quarter of 2017 and increased ~~11%~~10% over the ~~second~~first quarter of ~~2016. Second~~2017. First quarter of ~~2017~~2018 costs were lower than the ~~first~~fourth quarter of 2017 primarily due to lower gas ~~purchase prices partially offset by increased purchase volumes.~~and NGLs prices. The increase over the ~~second~~first quarter of ~~2016~~2017 was primarily due to higher ~~gas purchase prices partially offset by lower purchase~~purchased volumes and ~~lower field direct expenses.~~

In the Appalachian region, our Pittsburgh Mills gathering system, in Allegheny and Butler counties, continues to produce consistent financial results. Our average gathered volume for the second quarter of 2017 is approximately 133 MMcf per day. We connected the new Allen well pad in May and it included five new wells. And we are constructing a pipeline to connect the Miller well pad, which will be the next pad connected to our system. The Miller pad will include seven new wells and we anticipate it will be ready to flow in the third quarter of 2018. Also, we anticipate several in-fill wells to be drilled and connected to our system in the first half of 2018.

higher NGLs prices.

At our Hemphill Texas system, our total throughput volume averaged ~~57.5~~67.5 MMcf per day for the ~~second~~first quarter of ~~2017~~2018 and our total production of natural gas liquids was approximately ~~142,000~~171,000 gallons ~~per day. Total processing capacity at this facility is 135 MMcf~~ per day. During the ~~second~~first quarter, we ~~connected one new well~~constructed pipelines to connect several wells in the Buffalo Wallow area and ~~since~~expect these will begin flowing in the ~~beginning of 2017, we connected two new wells to this processing facility.~~second quarter. Our oil and gas segment continues to operate a rig in the Buffalo Wallow area and we ~~anticipate connecting four more wells in the third quarter.~~ are completing a construction project that will expand our compression capacity at our Buffalo Wallow compressor station to accommodate additional volumes.

At our Cashion processing facility in central Oklahoma, our total throughput volume for the ~~second~~first quarter of ~~2017~~2018 averaged approximately ~~37.8~~42.6 MMcf per day and our total production of natural gas liquids increased to approximately ~~207,000~~224,700 gallons per day. Total processing capacity for this facility remains at approximately 45 MMcf per day. InWe connected three new wells to this system in the first ~~six months~~quarter of ~~2017, we connected one new well and~~2018. We completed a ~~construction~~pipe line extension project that allows us to ~~bring additional~~gather and process gas ~~to this processing plant~~ from a ~~third party~~third-party producer who is actively drilling in the area. We are continuing to lay laterals from this trunkline in order to connect additional wells from this producer. ~~This new~~In the first quarter, we continued to receive gas from the producer ~~will~~that is committed to deliver fee-based ~~volume~~volumes to us for five ~~years or~~years. If they fail to deliver the required volumes they will pay a shortfall fee ~~settled annually. And we are constructing a new pipeline extension~~ which will ~~allow us to connect a new producer to our system. Construction of this pipeline is underway and we expect to connect the first well to our system in the thrid quarter of this year.~~ be settled annually.

At our ~~Bellmon~~Minco processing facility, we completed an offload connection to a new producer in the ~~Mississippian play in north central Oklahoma, we connected six new wells in the second~~first quarter of ~~2017 and~~2018. With this offload connection our total throughput volume averaged approximately 279.1 MMcf per ~~day. Total~~day while natural gas liquids averaged approximately ~~137,700~~24,200 gallons per ~~day while operating in ethane recovery mode at this facility.~~day. Total processing capacity is approximately 12 MMcf per day at this ~~system is approximately 90 MMcf per day.~~facility.

At our Segno gathering facility in Southeast Texas, gathered volume for the ~~second~~first quarter of ~~2017~~2018 averaged approximately ~~79.2~~84.9 MMcf per day. At this facility, ~~we have increased~~ our gathering and dehydration capacity will allow us gather up to ~~approximately~~ 120 MMcf per day. We ~~have~~ connected one new well to this system in ~~2017.~~the first quarter of 2018 and the producer in this area is actively reworking and recompleting wells that are connected to our system which will continue to increase gathered volumes.

In the Appalachian region at our Pittsburgh Mills gathering system, our average gathered volume for the first quarter of 2018 is approximately 106.5 MMcf per day. We are currently constructing a new pipeline to connect the next well pad to our system. This pad will include seven new wells and we anticipate construction to be completed in the third quarter. Production from this new pad is expected to begin in the fourth quarter of 2018. Additionally, we are preparing to receive production from several infill wells that are currently being drilled on existing pads. These infill wells are expected to begin flow in the second quarter of this year.

Our estimated ~~2017~~2018 capital expenditures for this segment are approximately ~~$16.0~~$32.0 million.

Financial Condition and Liquidity

Summary

Our financial condition and liquidity depends on the cash flow from our operations and borrowings under our credit agreement. 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 believe we will have enough cash flow and liquidity to meet our obligations and remain in compliance with our debt covenants for the next twelve months. Our ability to meet our debt covenants (under our credit agreement and our 2011 Indenture) and our capacity to incur additional indebtedness will depend on our future performance, which will be affected by financial, business, economic, regulatory, and other factors. For example, if we experience lower oil, natural gas, and NGLs prices since the last borrowing base determination under our credit agreement, it could ~~cause a reduction of~~reduce the borrowing base and therefore reduce or limit our ability to incur indebtedness. We monitor our liquidity and capital resources, endeavor to anticipate potential covenant compliance issues, and work, where possible, with our lenders to address those issues ahead of time.


									Three Months Ended March 31,						% Change
	Six Months Ended June 30,						% Change		As Restated
	2017			2016			% Change		2018			2017
	(In thousands except percentages)								(In thousands except percentages)
Net cash provided by operating activities	$	117,055		$	132,716		(12	)%	$	83,568		$	65,652		27	%
Net cash used in investing activities	(142,833		)	(77,386		)	85	%	(68,165		)	(29,028		)	135	%
Net cash provided by (used in) financing activities	25,734			(55,191		)	147	%
Net increase (decrease) in cash and cash equivalents	$	(44	)	$	139
Net cash used in financing activities									(15,352		)	(29,047		)	(47	)%
Net increase in cash and cash equivalents									$	51		$	7,577

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 ~~impacted~~affected by changes in working capital.

Net cash provided by operating activities in the first ~~six~~three months of ~~2017 decreased~~2018 increased by ~~$15.7~~$17.9 million as compared to the first ~~six~~three months of ~~2016.~~2017. The ~~decrease was the result of~~increase resulted from changes in operating assets and liabilities related to the timing of cash receipts and disbursements ~~partially offset~~and by ~~higher profit margins~~the change in ~~all three segments.~~the value of outstanding derivatives.

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 increased by ~~$65.4~~$39.1 million for the first ~~six~~three months of ~~2017~~2018 compared to the first ~~six~~three months of ~~2016.~~2017. The change was due ~~primarily~~ to an increase in capital expenditures due to ~~an oil and gas property acquisition,~~increased drilling activity offset by the ~~restarting of our contract drilling program in 2017, the construction of two new BOSS drilling rigs, and a decrease~~increase 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~~used by financing activities ~~increased~~decreased by ~~$80.9~~$13.7 million for the first ~~six~~three months of ~~2017~~2018 compared to the first ~~six~~three months of ~~2016.~~2017. The ~~increase~~decrease was primarily due to ~~an increase~~a decrease in ~~borrowings under our credit agreement, proceeds from the ATM common stock program, and~~net borrowing after paying down long-term debt in 2018 partially offset by an increase in book ~~overdrafts in 2017 after we paid down debt in the first six months of 2016.~~overdrafts.

At ~~June 30, 2017~~March 31, 2018, we had unrestricted cash totaling $0.8 million and had borrowed ~~$164.9~~$147.7 million of the $475.0 million we had elected to then have available under our credit agreement. Our credit agreement is used primarily for working capital and capital expenditures. On April 3, 2018, we paid down the outstanding debt under our credit agreement.

~~The following is a summary of~~Below, we summarize certain financial information as of ~~June 30, 2017~~March 31, 2018 and ~~2016~~2017 and for the ~~six~~three months ended ~~June 30, 2017~~March 31, 2018 and ~~2016~~2017:


	June 30,						% Change		March 31,						% Change
	2017			2016			% Change		2018			2017			% Change
	(In thousands except percentages)								(In thousands except percentages)
Working capital	$	(51,417	)	$	(57,463	)	11	%	$	(102,684	)	$	(41,296	)	(149	)%
Long-term debt less debt issuance costs	$	806,092		$	875,051		(8	)%	$	790,522		$	790,653		—	%
Shareholders’ equity	$	1,244,463		$	1,211,221		3	%	$	1,357,300		$	1,213,046		12	%
Net income (loss)	$	24,988		$	(113,285	)	122	%
Net income									$	7,865		$	15,929		(51	)%

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 ~~$51.4~~$102.7 million and ~~$57.5~~$41.3 million as of ~~June 30,~~March 31, 2018 and 2017, ~~and 2016,~~ respectively. ~~This~~The increase in negative working capital is primarily ~~from an increase in accounts receivable~~ due to ~~higher revenues,~~increased accounts payable due to increased activity in our drilling program and increased drilling rig utilization and the change in the value of outstanding derivatives ~~the reclassification of current deferred tax asset to long-term asset per ASU 2015-17, and decreased accrued liabilities~~ partially offset by increased accounts ~~payable due to~~receivable from increased ~~drilling activity and more rigs operating.~~revenues. Our credit agreement is used primarily for working capital and capital expenditures. At ~~June 30, 2017,~~March 31, 2018, we had borrowed ~~$164.9~~$147.7 million of the $475.0 million available under our credit agreement. The effect of our derivative contracts ~~increased~~decreased working capital by ~~$2.9~~$11.6 million as of ~~June 30, 2017~~March 31, 2018 and decreased working capital by ~~$9.6~~$5.6 million as of ~~June 30, 2016.~~March 31, 2017.

~~The following~~This table summarizes certain operating information:


	Six Months Ended						Three Months Ended
	June 30,				% Change		March 31,					% Change
	2017		2016		% Change		2018			2017		% Change
Oil and Natural Gas:
Oil production (MBbls)	1,357		1,559		(13	)%	736			643		14	%
NGLs production (MBbls)	2,233		2,485		(10	)%	1,195			1,097		9	%
Natural gas production (MMcf)	24,232		28,977		(16	)%	13,499			12,225		10	%
Average oil price per barrel received	$	47.77	$	36.88	30	%	$	55.10		$	48.68	13	%
Average oil price per barrel received excluding derivatives	$	47.27	$	34.77	36	%	$	61.21		$	48.64	26	%
Average NGLs price per barrel received	$	16.34	$	8.90	84	%	$	21.08		$	17.81	18	%
Average NGLs price per barrel received excluding derivatives	$	16.34	$	8.90	84	%	$	21.08		$	17.81	18	%
Average natural gas price per Mcf received	$	2.57	$	1.83	40	%	$	2.62		$	2.68	(2	)%
Average natural gas price per Mcf received excluding derivatives	$	2.66	$	1.52	75	%	$	2.44		$	2.78	(12	)%
Contract Drilling:
Average number of our drilling rigs in use during the period	27.2		17.1		59	%	31.7			25.5		24	%
Total number of drilling rigs owned at the end of the period	95		94		1	%	95			94		1	%
Average dayrate	$	15,905	$	18,468	(14	)%	$	17,038		$	15,835	8	%
Mid-Stream:
Gas gathered—Mcf/day	386,893		411,671		(6	)%	372,862			390,384		(4	)%
Gas processed—Mcf/day	130,804		164,333		(20	)%	151,039			126,559		19	%
Gas liquids sold—gallons/day	511,969		525,824		(3	)%	577,560			497,862		16	%
Number of natural gas gathering systems	25		26		(4	)%	22		⁽¹⁾	25		(12	)%
Number of processing plants	13		14		(7	)%	13			13		—	%

_______________________

(1) In the first quarter of 2018, our mid-stream segment transferred two natural gas gathering systems to our oil and natural gas segment.

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 ~~six~~three months of ~~2017~~2018 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 ~~$392,000~~$436,000 per month ($~~4.7~~5.2 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 ~~six~~three months of ~~2017~~2018 was ~~$2.57~~$2.62 compared to ~~$1.83~~$2.68 for the first ~~six~~three months of ~~2016.~~2017. Based on our first ~~six~~three months of ~~2017~~2018 production, a $1.00 per barrel change in our oil price, without the effect of derivatives, would have a ~~$219,000~~$237,000 per month ($~~2.6~~2.8 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 ~~$362,000~~$388,000 per month ($~~4.3~~4.7 million annualized) change in our pre-tax operating cash flow. In the first ~~six~~three months of ~~2017,~~2018, our average oil price per barrel received, including the effect of derivatives, was ~~$47.77~~$55.10 compared with an average oil price, including the effect of derivatives, of ~~$36.88~~$48.68 in the first ~~six~~three months of ~~2016~~2017 and our first ~~six~~three months of ~~2017~~2018 average NGLs price per barrel received was ~~$16.34~~$21.08 compared with an average NGLs price per barrel of ~~$8.90~~$17.81 in the first ~~six~~three months of ~~2016.~~2017.

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. At ~~June 30, 2017,~~March 31, 2018, the 12-month average unescalated prices were ~~$48.95~~$53.49 per barrel of oil, ~~$24.97~~$33.18 per barrel of NGLs, and ~~$3.01~~$3.00 per Mcf of natural gas, asand then are adjusted for price differentials. We did not have to take a write down in the first ~~six~~three months of ~~2017.~~2018.

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 ~~June 30, 2017,~~March 31, 2018, and only adjust the 12-month average price to an estimated ~~third~~fourth quarter ending average (holding ~~July 2017~~April 2018 prices constant for the remaining two months of the ~~third~~second quarter of ~~2017)~~2018), our forward looking expectation is that we will not recognize an impairment in the ~~third~~second quarter of ~~2017.~~2018. But commodity prices (and other factors) remain volatile and they could negatively affect the 12-month average price resulting in the potential for ~~an impairment in the future.~~a future impairment.

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 inunder six month ~~increments.~~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 were drilling horizontal or directional wells for oil and NGLs. The ~~improved~~continuous fluctuations in commodity ~~pricing~~prices for oil and natural gas ~~that began during~~changes the ~~second half of 2016 has increased~~ demand for drilling rigs. These factors ultimately affect the demand and mix of the type of drilling rigs used by our customers. The future demand for and the availability of drilling rigs to meet that demand will affect our future dayrates. For the first ~~six~~three months of ~~2017~~2018, our average dayrate was ~~$15,905~~$17,038 per day compared to ~~$18,468~~$15,835 per day for the first ~~six~~three months of ~~2016.~~2017. The average number of our drilling rigs used in the first ~~six~~three months of ~~2017~~2018 was ~~27.2~~31.7 drilling rigs compared with ~~17.1~~25.5 drilling rigs in the first ~~six~~three months of ~~2016.~~2017. Based on the average utilization of our drilling rigs during the first ~~six~~three months of ~~2017~~2018, a $100 per day change in dayrates has a ~~$2,720~~$3,170 per day ($~~1.0~~1.2 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 to be associated with acquiring an ownership interest in the property. In those cases, revenues and expenses for those services are eliminated in our ~~statement of operations,~~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 ~~$5.6~~$4.7 million for the first ~~six~~three months of ~~2017~~2018 from our contract drilling segment and eliminated the associated operating expense of ~~$5.2~~$4.3 million yielding $0.4 million 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 ~~six~~three months of ~~2016.~~2017.

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, 13 processing plants, 2522 gathering systems, and approximately ~~1,470~~1,450 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 ~~six~~three months of ~~2017~~2018 and ~~2016~~2017, our mid-stream operations purchased ~~$27.3~~$16.9 million and ~~$16.4~~$13.9 million, respectively, of our natural gas production and NGLs, and provided gathering and transportation services of ~~$3.2~~$1.7 million and ~~$5.1~~$1.6 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 ~~386,893~~372,862 Mcf per day in the first ~~six~~three months of ~~2017~~2018 compared to ~~411,671~~390,384 Mcf per day in the first ~~six~~three months of ~~2016~~.2017. It processed an average of ~~130,804~~151,039 Mcf per day in the first ~~six~~three months of ~~2017~~2018 compared to ~~164,333~~126,559 Mcf per day in the first ~~six~~three months of ~~2016.~~2017. The ~~amount of~~ NGLs sold was ~~511,969~~577,560 gallons per day in the first ~~six~~three months of ~~2017~~2018 compared to ~~525,824~~497,862 gallons per day in the first ~~six~~three months of ~~2016.~~2017. Gas gathered volumes per day in the first ~~six~~three months of ~~2017~~2018 decreased 6%4% compared to the first ~~six~~three months of ~~2016~~2017 primarily due to ~~declines in existing~~declining volumes ~~fewer new wells connected, and losing an offload volume at~~on our ~~Hemphill facility in mid-2016.~~Appalachian systems. Gas processed volumes for the first ~~six~~three months of 2018 increased 19% over the first three months of 2017 ~~decreased 20% from the first six months of 2016~~ due to ~~declines in existing volumes, fewer new~~additional wells connected to our processing systems and ~~losing an~~higher offload ~~volume at our Hemphill facility in mid-2016.~~volumes. NGLs sold ~~decreased 3% from~~increased 16% over the comparative period due to ~~less~~higher volume available to process at our plants.

At-the-Market (ATM) Common Stock Program

On May 2, 2018, we terminated the Distribution Agreement dated April 4, 2017, ~~we entered into a~~as amended (the Distribution Agreement), between the company and Raymond James & Associates, Inc. (the Sales Agent). The Distribution Agreement ~~(the Agreement)~~was terminable at will on written notification by the company with ~~a sales agent, under which we may offer~~no penalty. Under the Distribution Agreement, the company was entitled to issue and sell, from time to time, through or to the ~~sales agent~~Sales Agent shares of ~~our~~its common stock, ~~par value $0.20 per share (the Shares), up to~~having an aggregate offering price of up to $100.0 million. We intend to use the net proceeds from these sales to fund (or offset costs of) acquisitions, future capital expenditures, repay amounts outstanding under our revolving credit facility, and general corporate purposes.

~~Under the Agreement, the sales agent may sell the Shares by methods deemed to be~~million in an “at-the-market” offering as defined in Rule 415 promulgated under the Securities Act of 1933, as amended, including sales made directly on the NYSE, on any other existing trading market for the Shares or to or through a market maker. In addition, under the Agreement, the sales agent may sell the Shares by any other method permitted by law, including in privately negotiated transactions. Subject to the termsprogram. As of the ~~Agreement,~~date of termination, the sales agent will use commercially reasonable efforts, consistent with its normal trading and sales practices and applicable state and federal law, rules and regulations and the rules of the NYSE, to sell the Shares from time to time, based on our instructions (including any price, time or size limits or other customary parameters or conditions we may impose).

We do not have to make any sales of the Shares under the Agreement. The offering of Shares under the Agreement will terminate on the earlier of (1) the sale of all of the Shares subject to the Agreement or (2) the termination of the Agreement by the sales agent or us. We will pay the sales agent a commission of 2.0% of the gross sales price per share sold and have agreed to provide the sales agent with customary indemnification and contribution rights.

~~As of July 21, 2017, we~~company sold 787,547 shares of its Common Stock under the Distribution Agreement. As a result of the termination, there will be no more sales of the our common stock ~~resulting in net proceeds of approximately $18.6 million.~~under the Distribution Agreement.

Our Credit Agreement and Senior Subordinated Notes

Credit Agreement. ~~Our~~On April 2, 2018, we amended our Senior Credit Agreement (credit agreement) is scheduled to mature on April 10, 2020. Under the credit agreement, the amount we can borrow is the lesser of the amount we elect as the commitment amount or the value of the borrowing base as determined by the lenders, but in either event not to exceed ~~$875.0 million. Our elected commitment amount is $475.0 million. Our borrowing base is $475.0 million.~~the maximum 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~~Previous amendment fees of $1.0 million in origination, agency, syndication, and other related ~~fees. We~~fees are ~~amortizing these fees~~being amortized over the life of the credit agreement. No new fees were incurred for the Fourth Amendment. Under the credit agreement, we have pledged the following collateral: (a) 85% of the proved developed producing (discounted as present worth at 8%) total value of our oil and gas properties and (b) 100% of our ownership interest in our ~~midstream~~mid-stream affiliate, Superior Pipeline Company, L.L.C.

The Fourth Amendment was signed in connection with our sale of 50% of our ownership interest in our midstream segment, Superior. One of the conditions of that sale was the release of Superior from the terms of the credit agreement. Under the Fourth Amendment the amount we can borrow is the lesser of the amount we elect as the commitment amount or the value of the borrowing base as determined by the lenders, but in either event not to exceed $425.0 million. Our borrowing base and elected commitment is $425.0 million. The Superior sale closed on April 3, 2018 and the paydown under the credit agreement was made that same day.

The current lenders under our credit agreement and their respective participation interests are:



Lender	Participation Interest
BOK (BOKF, NA, dba Bank of Oklahoma)	1718	%
Compass Bank	1718	%
BMO Harris Financing, Inc.	1516	%
Bank of America, N.A.	1516	%
Comerica Bank	8	%
Wells Fargo Bank, N.A.	8	%
Canadian Imperial Bank of Commerce	8	%
Toronto Dominion (New York), LLC	8	%
~~The Bank of Nova Scotia~~	4	%
	100	%

may request a onetime special redetermination of the borrowing base between each scheduled redetermination. In addition, we may request a redetermination following the completion of an acquisition that meets the requirements in the credit agreement.

At our election, any part of the outstanding debt under the credit agreement ~~may~~could 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 credit agreement that cannot be 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, 2017 and July 21, 2017,~~March 31, 2018, borrowings were ~~$164.9 million and $172.1 million, respectively.~~$147.7 million. The outstanding balance was paid down on April 3, 2018.