SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

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

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, ~~2016~~2017

[ ] 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, or a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated ~~filer” and~~filer,” “smaller reporting ~~company”~~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 ~~22, 2016, 51,503,672~~21, 2017, 52,886,592 shares of the issuer's common stock were outstanding.

~~Table of Contents~~

TABLE OF CONTENTS



		Page Number
	PART I. Financial Information

Item 1.	Financial Statements (Unaudited)

	Unaudited Condensed Consolidated Balance Sheets June 30, ~~2016~~2017 and December 31, ~~2015~~2016	43

	Unaudited Condensed Consolidated Statements of Operations Three and Six Months Ended June 30, ~~2016~~2017 and ~~2015~~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 Months Ended June 30, ~~2016~~2017 and ~~2015~~2016	7

	Notes to Unaudited Condensed Consolidated Financial Statements	89

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	2630

Item 3.	Quantitative and Qualitative Disclosure About Market Risk	4952

Item 4.	Controls and Procedures	5153

	PART II. Other Information

Item 1.	Legal Proceedings	5154

Item 1A.	Risk Factors	5154

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	5255

Item 3.	Defaults Upon Senior Securities	5255

Item 4.	Mine Safety Disclosures	5255

Item 5.	Other Information	5255

Item 6.	Exhibits	5356

Signatures		5457

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, ~~in the future,~~ 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 ~~in the future~~ 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 ~~our~~ legal proceedings involving us will not materially affect our financial results;

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

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

impact of federal and state legislative and regulatory actions affecting our costs and increasing operating restrictions or delays and other adverse impacts on our business;

our projected production guidelines for the year;

our anticipated capital budgets;

our financial condition and liquidity;

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

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

These statements are based on assumptions and analyses made by us ~~in light of~~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;

~~our ability to successfully implement our pending technology conversion process relating to our financial~~putative class action lawsuits that may result in substantial expenditures and ~~operational information systems;~~divert management's attention; and

other factors, most of which are beyond our control.

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, 2016		December 31, 2015		June 30, 2017		December 31, 2016
	(In thousands except share amounts)				(In thousands except share amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	974	$	835	$	849	$	893
Accounts receivable, net of allowance for doubtful accounts of $5,174 and $5,199 at June 30, 2016 and December 31, 2015, respectively	67,506		79,941
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
Materials and supplies	3,324		3,565		3,291		3,340
Current derivative asset (Note 10)	—		10,186		3,948		—
Current income tax receivable	2,033		21,002		114		99
Current deferred tax asset	8,598		14,206
Assets held for sale	—		615
Current deferred tax asset (Note 8)					—		25,211
Prepaid expenses and other	6,859		9,908		6,304		7,699
Total current assets	89,294		140,258		109,504		121,196
Property and equipment:
Oil and natural gas properties on the full cost method:
Proved properties	5,420,972		5,401,618		5,540,086		5,446,305
Unproved properties not being amortized	321,191		337,099		337,190		314,867
Drilling equipment	1,567,765		1,567,560		1,587,096		1,565,268
Gas gathering and processing equipment	697,573		689,063		711,355		705,859
Saltwater disposal systems	60,527		60,316		62,191		60,638
Corporate land and building	56,149		49,890		59,075		59,066
Transportation equipment	34,055		40,072		29,704		32,842
Other	45,777		45,489		52,799		48,590
	8,204,009		8,191,107		8,379,496		8,233,435
Less accumulated depreciation, depletion, amortization, and impairment	5,818,163		5,609,980		6,044,966		5,952,330
Net property and equipment	2,385,846		2,581,127		2,334,530		2,281,105
Goodwill	62,808		62,808		62,808		62,808
Non-current derivative asset (Note 10)	—		968		689		377
Other assets	14,148		14,681		15,779		13,817
Total assets	$	2,552,096	$	2,799,842	$	2,523,310	$	2,479,303

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, 2016		December 31, 2015		June 30, 2017		December 31, 2016
	(In thousands except share amounts)				(In thousands except share amounts)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	72,744	$	87,413	$	106,200	$	88,793
Accrued liabilities (Note 5)	46,368		46,918		39,092		39,651
Current derivative liability (Note 10)	9,646		—		1,036		21,564
Current portion of other long-term liabilities (Note 6)	17,999		16,560		14,593		14,907
Total current liabilities	146,757		150,891		160,921		164,915
Long-term debt less debt issuance costs (Note 6)	875,051		918,995		806,092		800,917
Non-current derivative liability (Note 10)	3,420		285		—		415
Other long-term liabilities (Note 6)	103,926		140,341		100,796		103,064
Deferred income taxes	211,721		275,750
Deferred income taxes (Note 8)					211,038		215,922
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, 51,504,959 and 50,413,101 shares issued as of June 30, 2016 and December 31, 2015, respectively	10,016		9,831
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
Capital in excess of par value	497,312		486,571		527,624		502,500
Accumulated other comprehensive income (Note 13)					20		—
Retained earnings	703,893		817,178		706,542		681,554
Total shareholders’ equity	1,211,221		1,313,580		1,244,463		1,194,070
Total liabilities and shareholders’ equity	$	2,552,096	$	2,799,842	$	2,523,310	$	2,479,303

The accompanying notes are an integral part of these

unaudited condensed consolidated financial statements.

UNIT CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)


	Three Months Ended						Six Months Ended						Three Months Ended						Six Months Ended
	June 30,						June 30,						June 30,						June 30,
	2016			2015			2016			2015			2017			2016			2017			2016
	(In thousands except per share amounts)												(In thousands except per share amounts)
Revenues:
Oil and natural gas	$	69,190		$	107,256		$	127,464		$	213,325		$	83,173		$	69,190		$	170,771		$	127,464
Contract drilling	24,257			55,015			62,967			150,092			39,255			24,257			76,440			62,967
Gas gathering and processing	44,858			52,176			84,058			106,129			48,153			44,858			99,094			84,058
Total revenues	138,305			214,447			274,489			469,546			170,581			138,305			346,305			274,489
Expenses:
Oil and natural gas:
Operating costs	33,331			45,972			66,677			91,183
Operating costs:
Oil and natural gas													32,758			33,331			61,962			66,677
Contract drilling													27,239			19,254			56,466			47,352
Gas gathering and processing													36,042			32,381			73,746			63,447
Total operating costs													96,039			84,966			192,174			177,476
Depreciation, depletion, and amortization	30,411			68,101			62,243			145,219			50,080			52,878			97,012			108,468
Impairment of oil and natural gas properties (Note 2)	74,291			410,536			112,120			811,129
Contract drilling:
Operating costs	19,254			36,485			47,352			88,231
Depreciation	10,918			13,265			23,113			28,278
Impairment of contract drilling equipment (Note 3)	—			8,314			—			8,314
Gas gathering and processing:
Operating costs	32,381			40,592			63,447			84,767
Depreciation and amortization	11,515			10,848			22,974			21,542
Impairments (Note 2)													—			74,291			—			112,120
General and administrative	8,382			9,624			17,097			18,994			8,713			8,348			17,667			16,959
Gain on disposition of assets	(477		)	(415		)	(669		)	(960		)	(248		)	(477		)	(1,072		)	(669		)
Total operating expenses	220,006			643,322			414,354			1,296,697			154,584			220,006			305,781			414,354
Loss from operations	(81,701		)	(428,875		)	(139,865		)	(827,151		)
Income (loss) from operations													15,997			(81,701		)	40,524			(139,865		)
Other income (expense):
Interest, net	(10,606		)	(7,956		)	(20,223		)	(15,196		)	(9,467		)	(10,606		)	(18,863		)	(20,223		)
Gain (loss) on derivatives	(22,672		)	(1,919		)	(11,743		)	4,667			8,902			(22,672		)	23,633			(11,743		)
Other	1			24			(14		)	22
Other, net													6			1			9			(14		)
Total other income (expense)	(33,277		)	(9,851		)	(31,980		)	(10,507		)	(559		)	(33,277		)	4,779			(31,980		)
Loss before income taxes	(114,978		)	(438,726		)	(171,845		)	(837,658		)
Income (loss) before income taxes													15,438			(114,978		)	45,303			(171,845		)
Income tax expense (benefit):
Current	—			803			—			868
Deferred	(42,842		)	(165,140		)	(58,560		)	(315,783		)	6,379			(42,842		)	20,315			(58,560		)
Total income taxes	(42,842		)	(164,337		)	(58,560		)	(314,915		)	6,379			(42,842		)	20,315			(58,560		)
Net loss	$	(72,136	)	$	(274,389	)	$	(113,285	)	$	(522,743	)
Net loss per common share:
Net income (loss)													$	9,059		$	(72,136	)	$	24,988		$	(113,285	)
Net income (loss) per common share:
Basic	$	(1.44	)	$	(5.58	)	$	(2.27	)	$	(10.66	)	$	0.18		$	(1.44	)	$	0.49		$	(2.27	)
Diluted	$	(1.44	)	$	(5.58	)	$	(2.27	)	$	(10.66	)	$	0.17		$	(1.44	)	$	0.49		$	(2.27	)

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	)

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						Six Months Ended
	June 30,						June 30,
	2016			2015			2017			2016
	(In thousands)						(In thousands)
OPERATING ACTIVITIES:
Net loss	$	(113,285	)	$	(522,743	)
Adjustments to reconcile net loss to net cash provided by 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	109,522			196,576			97,012			108,468
Impairments (Notes 2 and 3)	112,120			819,443
Impairments (Note 2)							—			112,120
Amortization of debt issuance costs and debt discount							1,075			1,054
(Gain) loss on derivatives	11,743			(4,667		)	(23,633		)	11,743
Cash receipts on derivatives settled	12,192			21,082
Deferred tax benefit	(58,560		)	(315,783		)
Cash (payments) receipts on derivatives settled							(1,569		)	12,192
Deferred tax expense (benefit)							20,315			(58,560		)
Gain on disposition of assets	(946		)	(960		)	(1,072		)	(946		)
Employee stock compensation plans	7,703			12,329			8,066			7,703
Other, net	(2,755		)	1,944			299			(2,755		)
Changes in operating assets and liabilities increasing (decreasing) cash:
Accounts receivable	5,443			77,894			(15,087		)	5,443
Accounts payable	24,077			(16,327		)	3,724			24,077
Material and supplies	241			(2,366		)	49			241
Accrued liabilities	3,411			(11,811		)	756			3,411
Income taxes	18,969			(1,845		)	(15		)	18,969
Other, net	2,841			4,840			2,147			2,841
Net cash provided by operating activities	132,716			257,606			117,055			132,716
INVESTING ACTIVITIES:
Capital expenditures	(124,182		)	(371,572		)	(107,933		)	(124,182		)
Producing properties and other acquisitions (Note 3)							(52,956		)	—
Proceeds from disposition of assets	46,627			5,130			19,556			46,627
Other	169			—			(1,500		)	169
Net cash used in investing activities	(77,386		)	(366,442		)	(142,833		)	(77,386		)
FINANCING ACTIVITIES:
Borrowings under credit agreement	150,300			396,000			160,600			150,300
Payments under credit agreement	(195,300		)	(281,500		)	(156,500		)	(195,300		)
Payments on capitalized leases	(1,828		)	(1,757		)	(1,901		)	(1,828		)
Tax (benefit) expense from stock compensation	(376		)	4
Proceeds from common stock issued, net of issue costs (Note 13)							18,623			—
Tax benefit from stock compensation							—			(376		)
Book overdrafts	(7,987		)	(4,121		)	4,912			(7,987		)
Net cash (used in) provided by financing activities	(55,191		)	108,626
Net cash provided by (used in) financing activities							25,734			(55,191		)
Net increase (decrease) in cash and cash equivalents	139			(210		)	(44		)	139
Cash and cash equivalents, beginning of period	835			1,049			893			835
Cash and cash equivalents, end of period	$	974		$	839		$	849		$	974


Supplemental disclosure of cash flow information:
Cash paid during the year for:
Interest paid (net of capitalized)	19,830	15,886	16,813		19,830
Income taxes	—	3,142	—		—
Changes in accounts payable and accrued liabilities related to purchases of property, plant, and equipment	30,758	92,743	(8,771	)	30,758
Non-cash reductions to oil and natural gas properties related to asset retirement obligations	28,884	5,956	1,579		28,884

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 ~~accompanying~~ 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 ~~accompanying~~ 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 ~~25, 2016,~~28, 2017, for the year ended December 31, ~~2015~~2016.

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

Balance Sheets at June 30, ~~2016~~2017 and December 31, ~~2015;~~2016;

Statements of Operations for the three and six months ended June 30, ~~2016~~2017 and ~~2015;~~2016;

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

Statements of Cash Flows for the six months ended June 30, ~~2016~~2017 and ~~2015~~2016.

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 ~~accompanying~~ notes. Actual results may differ from those estimates. Results for the six months ended June 30, ~~2016~~2017 and ~~2015~~2016 are not necessarily indicative of the results to be realized for the full year of ~~2016~~2017, or that we realized for the full year of ~~2015~~2016.

Certain amounts in the ~~accompanying~~ unaudited condensed consolidated financial statements for prior periods have been reclassified to conform to current year presentation. There was no impact to consolidated net income (loss) or shareholders' equity.

NOTE 2 – OIL AND NATURAL GAS PROPERTIES

Full cost accounting rules require us to review the carrying value of our oil and natural gas properties at the end of each quarter. Under those rules, the maximum amount allowed as the carrying value is referred to as the ceiling. The ceiling is the sum of the present value (using a 10% discount rate) of the estimated future net revenues from our proved reserves (using the unescalated 12-month average price of our oil, NGLs, and natural gas), plus the cost of properties not being amortized, plus the lower of cost or estimated fair value of unproved properties 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 ~~quarter of 2015, the 12-month average commodity prices decreased significantly, resulting in a non-cash ceiling test write-down of $400.6 million pre-tax ($249.4 million, net of tax). During the~~and second quarter of ~~2015, the 12-month average commodity prices decreased further, resulting in a non-cash ceiling test write-down of $410.5 million pre-tax ($255.6 million, net of tax).~~

~~During the first quarter of~~ 2016, ~~the 12-month average commodity prices continued to decrease, resulting in~~we had a non-cash ceiling test write-down of $37.8 million pre-tax ($23.5 million, net of tax)~~. For the second quarter of 2016, the 12-month average commodity prices decreased further, resulting in a non-cash ceiling test write-down of~~ 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.

NOTE 3 – ACQUISITIONS AND DIVESTITURES

~~Oil~~Acquisitions

On April 3, 2017, we closed on an acquisition of certain oil and ~~Natural Gas~~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

We sold non-core oil and natural gas assets, net of related expenses, for $17.8 million during the first six months of 2017, compared to $43.6 million during the first six months of ~~2016, compared to less than $0.1 million during the first six months of 2015.~~2016. Proceeds from those sales reduced the net book value of our full cost pool with no gain or loss recognized.

~~Contract Drilling~~

~~During the second quarter of 2015, we recorded a write-down of approximately~~ ~~$8.3 million~~ ~~pre-tax on drilling equipment that was being held for sale.~~

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

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


	Loss (Numerator)			Weighted Shares (Denominator)	Per-Share Amount			Earnings (Loss) (Numerator)			Weighted Shares (Denominator)	Per-Share Amount
	(In thousands except per share amounts)							(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 stock appreciation rights (SARs)	—			—	—
Diluted loss per common share	$	(72,136	)	50,074	$	(1.44	)
For the three months ended June 30, 2015
Basic loss per common share	$	(274,389	)	49,148	$	(5.58	)	$	(72,136	)	50,074	$	(1.44	)
Effect of dilutive stock options, restricted stock, and SARs	—			—	—			—			—	—
Diluted loss per common share	$	(274,389	)	49,148	$	(5.58	)	$	(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 ~~above earnings per share calculation. For the three months ended June 30, 2015, approximately 307,000 weighted average shares were excluded.~~calculation above.

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				Three Months Ended
	June 30,				June 30,
	2016		2015		2017		2016
Stock options and SARs	240,270		259,085		178,755		240,270
Average exercise price	$	49.29	$	50.50	$	47.75	$	49.29


	Loss (Numerator)			Weighted Shares (Denominator)	Per-Share Amount			Earnings (Loss) (Numerator)			Weighted Shares (Denominator)	Per-Share Amount
	(In thousands except per share amounts)							(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	)	$	(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	)	$	(113,285	)	49,977	$	(2.27	)
For the six months ended June 30, 2015
Basic loss per common share	$	(522,743	)	49,063	$	(10.66	)
Effect of dilutive stock options, restricted stock, and SARs	—			—	—
Diluted loss per common share	$	(522,743	)	49,063	$	(10.66	)

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 ~~above earnings per share calculation. For the six months ended June 30, 2015, approximately 206,000 weighted average shares were excluded.~~calculation above.


	Six Months Ended				Six Months Ended
	June 30,				June 30,
	2016		2015		2017		2016
Stock options and SARs	240,270		261,270		178,755		240,270
Average exercise price	$	49.29	$	50.34	$	47.75	$	49.29

NOTE 5 – ACCRUED LIABILITIES

Accrued liabilities consisted ~~of the following:~~of:


	June 30, 2016		December 31, 2015		June 30, 2017		December 31, 2016
	(In thousands)				(In thousands)
Employee costs					$	10,526	$	15,394
Lease operating expenses	$	19,157	$	17,220	10,047		10,075
Interest payable					6,684		6,524
Taxes	8,722		3,767		6,577		2,219
Employee costs	7,007		12,641
Interest payable	6,213		6,321
Third-party credits	2,954		3,326		2,149		2,998
Derivative settlements	278		—
Other	2,037		3,643		3,109		2,441
Total accrued liabilities	$	46,368	$	46,918	$	39,092	$	39,651

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

Long-Term Debt

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


	June 30, 2016			December 31, 2015			June 30, 2017			December 31, 2016
	(In thousands)						(In thousands)
Credit agreement with an average interest rate of 3.9% and 2.6% at June 30, 2016 and December 31, 2015, respectively	$	236,000		$	281,000
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
6.625% senior subordinated notes due 2021	650,000			650,000			650,000			650,000
Total principal amount	886,000			931,000			814,900			810,800
Less: unamortized discount	(3,076		)	(3,338		)	(2,524		)	(2,804		)
Less: debt issuance costs, net	(7,873		)	(8,667		)	(6,284		)	(7,079		)
Total long-term debt	$	875,051		$	918,995		$	806,092		$	800,917

Credit Agreement. ~~On April 8, 2016, we amended our~~Our Senior Credit Agreement (credit agreement) is scheduled to mature on April 10, 2020. ~~The~~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 ~~the maximum credit agreement amount of~~ $875.0 million. Our elected commitment amount is $475.0 million. Our borrowing base is $475.0 million. We are charged a commitment fee of 0.50% on the amount available but not borrowed. ~~The~~That fee varies based on the amount borrowed as a percentage ~~of the amount~~ 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. ~~With~~Under the ~~new amendment,~~credit agreement, we pledged the following collateral: (a) 85% of the proved developed producing (discounted as present worth at 8%) total value of our oil and gas properties and (b) 100% of our ownership interest in our midstream 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 be fixed at a London Interbank Offered Rate (LIBOR). LIBOR interest is computed as the ~~sum of the~~ LIBOR base for the ~~applicable~~ term plus 2.00% to 3.00% depending on the level of debt as a percentage of the borrowing base and is payable at the end of each term, or every 90 days, whichever is less. Borrowings not under LIBOR bear interest at the prime rate specified in the credit agreement that cannot be less than LIBOR plus 1.00%. Interest is payable at the end of each month and the principal may be repaid in whole or in part at any time, without a premium or penalty. At June 30, ~~2016,~~2017, we had ~~$236.0~~$164.9 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, ~~ending thereafter,~~ 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, ~~2016~~2017, we were in compliance with the ~~covenants in the~~ credit ~~agreement.~~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 ~~will~~ 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 ~~the issuance of~~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.

~~On and after May 15, 2016, we~~We may redeem all or, ~~from time to time,~~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 ~~if any,~~ to the date of purchase. The 2011 Indenture contains customary events of default. The 2011 Indenture also contains covenants including those that ~~among other things,~~ 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, ~~2016~~2017.

Other Long-Term Liabilities

Other long-term liabilities consisted of the following:


	June 30, 2016		December 31, 2015		June 30, 2017		December 31, 2016
	(In thousands)				(In thousands)
Asset retirement obligation (ARO) liability	$	70,926	$	98,297	$	70,049	$	70,170
Capital lease obligations	20,710		22,466		17,089		18,918
Workers’ compensation	15,258		16,551		13,971		15,163
Separation benefit plans	6,386		9,886		5,456		4,943
Deferred compensation plan	4,430		4,244		5,092		4,578
Gas balancing liability	3,805		5,047		3,322		3,789
Other	410		410		410		410
	121,925		156,901		115,389		117,971
Less current portion	17,999		16,560		14,593		14,907
Total other long-term liabilities	$	103,926	$	140,341	$	100,796	$	103,064

Estimated annual principal payments under the terms of debt and other long-term liabilities during ~~each of~~ the five successive twelve month periods beginning July 1, ~~2016~~2017 (and through 2021) are ~~$18.0~~$14.6 million, ~~$44.3~~$45.6 million, ~~$10.2~~$173.6 million, ~~$244.1~~$659.6 million, and ~~$658.7~~$2.5 million, respectively.

Capital Leases

~~During~~In 2014, our mid-stream segment entered into capital lease agreements for ~~twenty~~20 compressors with initial terms of seven years. The underlying assets are included in gas gathering and processing equipment. The $3.8 million current portion of our capital lease obligations ~~of $3.6 million~~ is included in current portion of other long-term liabilities and the non-current portion of ~~$17.1~~$13.3 million is included in other long-term liabilities in the accompanying Unaudited Condensed Consolidated Balance Sheets as of June 30, ~~2016~~2017. These capital leases are discounted using annual rates of 4.00%. Total maintenance and interest remaining related to these leases are ~~$8.6~~$6.8 million and ~~$2.3~~$1.5 million, respectively, at June 30, ~~2016~~2017. Annual payments, net of maintenance and interest, average ~~$4.0~~$4.1 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 at that time.~~value.

Future payments required under the capital leases at June 30, ~~2016:~~2017:


	Amount		Amount
Ending June 30,	(In thousands)
Beginning July 1,			(In thousands)
2017	$	6,168	$	6,168
2018	6,168		6,168
2019	6,168		6,168
2020	6,168		6,673
2021 and thereafter	6,853
2021			179
Total future payments	31,525		25,356
Less payments related to:
Maintenance	8,552		6,767
Interest	2,263		1,500
Present value of future minimum payments	$	20,710	$	17,089

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 of 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						Six Months Ended
	June 30,						June 30,
	2016			2015			2017			2016
	(In thousands)						(In thousands)
ARO liability, January 1:	$	98,297		$	100,567		$	70,170		$	98,297
Accretion of discount	1,513			1,757			1,458			1,513
Liability incurred	212			5,986			1,018			212
Liability settled	(605		)	(1,566		)	(1,224		)	(605		)
Liability sold ⁽¹⁾	(10,308		)	(246		)	(1,412		)	(10,308		)
Revision of estimates ⁽²⁾	(18,183		)	(10,130		)	39			(18,183		)
ARO liability, June 30:	70,926			96,368			70,049			70,926
Less current portion	3,523			3,277			2,825			3,523
Total long-term ARO	$	67,403		$	93,091		$	67,224		$	67,403

_______________________


(1)	We sold ~~approximately 1,150~~our interest in a number of non-core wells to unaffiliated third-parties during the first six months of ~~2016.~~2017 and 2016, respectively.


(2)	Plugging liability estimates were revised in both ~~2016~~2017 and ~~2015~~2016 for updates in the cost of services used to plug wells over the preceding year. We had various upward and downward adjustments.

NOTE 8 – NEW ACCOUNTING PRONOUNCEMENTS

Compensation—Stock ~~Compensation: Improvements to Employee Share-Based Payment Accounting.~~Compensation. The FASB ~~has~~ issued ASU ~~2016-09.~~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 Step 2 from the goodwill impairment test. The amendments will be effective prospectively for reporting periods beginning after December 31, 2019, and early adoption is permitted. We do not believe these amendments will have a material impact on our financial statements.

Business Combinations; Clarifying the Definition of a Business. The FASB issued ASU 2017-01, clarifying the definition of a business. The amendments are intended to ~~improve the accounting~~help companies and other organizations evaluate whether transactions should be accounted for ~~employee share-based payments and affect all organizations that issue share-based payment awards to their employees. Several aspects~~as acquisitions (or disposals) of ~~the accounting for share-based payment award transactions are simplified, including: (a) income tax consequences; (b) classification of awards as either equity~~assets or ~~liabilities; and (c) classification on the statement of cash flows.~~businesses. For public companies, the amendments are effective for annual periods beginning after December 15, ~~2016,~~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 ~~interim periods within those annual periods. Early adoption of the amendments is permitted.~~ Cash Payments. The ~~amendments primarily impact classification within~~FASB issued ASU 2016-15, to address diversity in how certain transactions are presented and classified in the statement of cash ~~flows between financial~~flows. The amendments will be effective retrospectively for reporting periods beginning after December 31, 2017, and ~~operating activities.~~early adoption is permitted. We do not believe ~~the~~these amendments will have a material impact on our financial statements.

Leases. The FASB has issued ASU 2016-02. ~~Under the new guidance,~~The amendments will require lessees ~~will be required~~ to recognize at the commencement date a lease liability, which is a lessee's obligation to make lease payments arising from a lease, measured on a discounted basis; and a right-of-use asset, which is an asset that represents the lessee's right to use a specified asset for the lease term. Lessor accounting is largely unchanged. For public companies, the amendments are effective for annual periods beginning after

December 15, 2018, and interim periods within those annual periods. Early adoption of the amendments is permitted. We are in the process of evaluating the impact itthese amendments will have on our financial statements.

~~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 will be 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 are effective for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Early adoption of the amendments is permitted. The amendments will require current deferred tax assets to be combined with noncurrent deferred tax assets. We do not believe the amendments will have a material impact on our financial statements.

~~Interest—Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs.~~ ~~The FASB has issued ASU 2015-03. The amendments in this ASU require that debt issuance costs related to a recognized debt liability be presented in the~~

balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The FASB has also issued ASU 2015-15. The amendments in this ASU allow an entity to defer and present debt issuance cost as an asset and subsequently amortize the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. We have maintained debt issuance costs associated with our credit agreement as an asset and amortize these fees over the life of the credit agreement. For public business entities, the amendments are effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. The amendments should be applied on a retrospective basis, wherein the balance sheet of each individual period presented should be adjusted to reflect the period-specific effects of applying the new guidance. We have adopted these amendments during the first quarter of 2016. Previously, debt issuance costs associated with the Notes was classified as a long-term asset on the balance sheet, but with ASU 2015-03, it is presented as a direct deduction from the carrying amount of the recognized debt liability.

Revenue from Contracts with Customers. The FASB has issued ASU 2014-09. ~~This affects~~These amendments affect any entity using U.S. GAAP that either enters into contracts with customers to transfer goods or services or enters into contracts for the transfer of nonfinancial assets unless those contracts are within the scope of other standards (e.g., insurance contracts or lease contracts). The core principle of the ~~guidance~~amendments is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. In May 2016, the FASB issued ASU 2016-12, "Narrow-Scope Improvements and Practical Expedients," which provides clarifying guidance 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 ~~ASU~~amendment rescinds SEC Staff Observer comments that are codified in Topic 605, Revenue Recognition, and Topic 932, Extractive ~~Activities—~~Activities- Oil and Gas, effective ~~upon~~on the adoption of Topic 606, Revenue from Contracts with Customers. In April 2016, the FASB issued ASU 2016-10, "Identifying Performance Obligations and Licensing," which amends the 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 amendments effective January 1, 2018. We are utilizing a bottom-up approach to analyze the impact of 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 the ~~process~~amount and timing of ~~evaluating~~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.

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 ~~it will~~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~~–STOCK-BASED COMPENSATION

For restricted stock awards and stock options, we had:


	Three Months Ended				Six Months Ended				Three Months Ended				Six Months Ended
	June 30,				June 30,				June 30,				June 30,
	2016		2015		2016		2015		2017		2016		2017		2016
	(In millions)								(In millions)
Recognized stock compensation expense	$	2.0	$	4.8	$	5.3	$	9.1	$	3.2	$	2.0	$	5.8	$	5.3
Capitalized stock compensation cost for our oil and natural gas properties	0.4		1.0		1.2		1.9		0.4		0.4		0.8		1.2
Tax benefit on stock based compensation	0.7		1.7		2.0		3.4		1.2		0.7		2.2		2.0

The remaining unrecognized compensation cost related to unvested awards at June 30, ~~2016~~2017 is approximately ~~$10.9~~$17.4 million, of which ~~$1.7~~$2.1 million is anticipated to be capitalized. The weighted average period ~~of time~~ over which this cost will be recognized is ~~0.7 of a~~one year.

~~The~~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 to non-employee directors. A total of ~~4,500,000~~7,000,000 shares of the company's common stock is 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 SARs or stock options during either of the three or six month periods ending June 30, ~~2016~~2017 ~~and~~or ~~2015~~2016. The following ~~tables show~~table shows the fair value of restricted stock awards granted to employees and non-employee directors during the periods ~~indicated.~~indicated:


	Three Months Ended					Three Months Ended					Three Months Ended						Three Months Ended
	June 30, 2016					June 30, 2015					June 30, 2017						June 30, 2016
	Time Vested			Performance Vested		Time Vested			Performance Vested		Time Vested			Performance Vested			Time Vested			Performance Vested
Shares granted:
Employees	—			—		—			—		14,000			21,000			—			—
Non-employee directors	90,000			—		25,848			—		49,104			—			90,000			—
	90,000			—		25,848			—		63,104			21,000			90,000			—
Estimated fair value (in millions):⁽¹⁾
Employees	$	—		$	—	$	—		$	—	$	0.4		$	0.5		$	—		$	—
Non-employee directors	0.9			—		0.9			—		0.9			—			0.9			—
	$	0.9		$	—	$	0.9		$	—	$	1.3		$	0.5		$	0.9		$	—
Percentage of shares granted expected to be distributed:
Employees	N/A			N/A		N/A			N/A		100		%	87		%	N/A			N/A
Non-employee directors	100		%	N/A		100		%	N/A		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						Six Months Ended						Six Months Ended
	June 30, 2016						June 30, 2015						June 30, 2017						June 30, 2016
	Time Vested			Performance Vested			Time Vested			Performance Vested			Time Vested			Performance Vested			Time Vested			Performance Vested
Shares granted:
Employees	486,578			152,373			576,361			148,081			475,799			173,373			486,578			152,373
Non-employee directors	90,000			—			25,848			—			49,104			—			90,000			—
	576,578			152,373			602,209			148,081			524,903			173,373			576,578			152,373
Estimated fair value (in millions):⁽¹⁾
Employees	$	2.6		$	0.8		$	18.5		$	5.1		$	11.8		$	4.5		$	2.6		$	0.8
Non-employee directors	0.9			—			0.9			—			0.9			—			0.9			—
	$	3.5		$	0.8		$	19.4		$	5.1		$	12.7		$	4.5		$	3.5		$	0.8
Percentage of shares granted expected to be distributed:
Employees	94		%	70		%	94		%	3		%	95		%	87		%	94		%	70		%
Non-employee directors	100		%	N/A			100		%	N/A			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.)

The time vested restricted stock awards granted during the first six months of ~~2016~~2017 and ~~2015~~2016 are being recognized over a ~~three year~~three-year vesting period. During the first two quarters of 2017 and the first quarter of 2016, 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 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~~three-year vesting period ~~based on~~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 performance criteria at June 30, 2017, the participants are estimated to receive 74% of the 2017, 145% of the 2016, and 34% of the 2015 performance based shares. The CFTA performance measurement at June 30, 2017 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 ~~2016~~2017 awards for the first six months of ~~2016~~2017 was ~~$0.7~~$3.4 million.

NOTE 10 – DERIVATIVES

Commodity Derivatives

We have entered into 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, ~~2016~~2017, our derivative transactions were comprised of the following 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. ~~For our economic hedges any~~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.

At June 30, ~~2016, we had~~2017, the following derivatives were outstanding:



Term	Commodity	Contracted Volume	Weighted Average Fixed Price	Contracted Market
~~Jul’16~~Jul’17 – ~~Dec’16~~Oct'17	Natural gas – swap	~~45,000~~70,000 MMBtu/day	$~~2.596~~3.038	IF – NYMEX (HH)
~~Jan’17~~Nov’17 – Dec'17	Natural gas – swap	60,000 MMBtu/day	$2.960	IF – NYMEX (HH)
Jan’18 – Dec'18	Natural gas – swap	~~10,000~~20,000 MMBtu/day	$~~3.025~~3.013	IF – NYMEX (HH)
~~Jan’17~~Nov’17 – Dec'17	Natural gas – basis swap	20,000 MMBtu/day	$(0.215)	IF – NYMEX (HH)
Jan’18 – Mar'18	Natural gas – basis swap	10,000 MMBtu/day	$(0.208)	IF – NYMEX (HH)
Nov’18 – Dec'18	Natural gas – basis swap	10,000 MMBtu/day	$(0.208)	IF – NYMEX (HH)
~~Jul’16 – Dec'16~~	~~Natural gas – collar~~	~~42,000 MMBtu/day~~	~~$2.40 - $2.88~~	~~IF – NYMEX (HH)~~
~~Jan’17~~Jul’17 – Oct'17	Natural gas – collar	~~10,000~~20,000 MMBtu/day	$~~2.75~~2.88 - ~~$2.95~~$3.10	IF – NYMEX (HH)
~~Jul’16~~Jul'17 – ~~Dec'16~~	~~Natural gas – three-way collar~~	~~13,500 MMBtu/day~~	~~$2.70 - $2.20 - $3.26~~	~~IF – NYMEX (HH)~~
~~Jan’17 – Dec'17~~Oct'17	Natural gas – three-way collar	15,000 MMBtu/day	$2.50 - $2.00 - $3.32	IF – NYMEX (HH)
~~Jul’16~~Nov’17 – ~~Sep'16~~Dec'17	~~Crude oil – swap~~	~~1,000 Bbl/day~~	~~$48.45~~	~~WTI – NYMEX~~
~~Jul’16 – Sep'16~~	~~Crude oil – collar~~	~~2,450 Bbl/day~~	~~$44.44 - $52.46~~	~~WTI – NYMEX~~
~~Oct’16 – Dec'16~~	~~Crude oil – collar~~	~~1,450 Bbl/day~~	~~$47.50 - $56.40~~	~~WTI – NYMEX~~
~~Jul’16 – Dec'16~~	~~Crude oil~~Natural gas – three-way collar	~~700 Bbl/~~25,000 MMBtu/day	$~~46.50~~2.90 - ~~$35.00~~$2.30 - ~~$57.00~~$3.59	~~WTI~~IF – NYMEX (HH)
~~Jul’16~~Jan'18 – ~~Dec'16~~Mar'18	~~Crude oil~~Natural gas – three-way collar⁽¹⁾	~~700 Bbl/~~60,000 MMBtu/day	$~~47.50~~3.29 - ~~$35.00~~$2.63 - ~~$63.50~~$4.07	~~WTI~~IF – NYMEX (HH)
~~Jan’17~~Apr'18 – Dec'18	Natural gas – three-way collar	20,000 MMBtu/day	$3.00 - $2.50 - $3.51	IF – NYMEX (HH)
Jul’17 – Dec'17	Crude oil – three-way collar	~~750~~3,750 Bbl/day	$49.79 - $39.58 - $60.98	WTI – NYMEX
Jan'18 – Dec'18	Crude oil – three-way collar	1,000 Bbl/day	$50.00 - ~~$37.50~~$40.00 - ~~$63.90~~$56.65	WTI – NYMEX

~~_______________________~~


~~(1)~~	~~We pay our counterparty a premium, which can be and is being deferred until settlement.~~

After June 30, ~~2016, we entered into~~2017, the following ~~derivatives:~~derivatives were entered into:



Term	Commodity	Contracted Volume	Weighted Average Fixed Price	Contracted Market
~~Jan’17~~Jan'18 – ~~Oct'17~~Dec'18	~~Natural gas~~Crude oil – swap	500 Bbl/day	$50.00	WTI – NYMEX
Jan'18 – Dec'18	Crude oil – three-way collar	~~10,000 MMBtu/~~1,000 Bbl/day	$~~3.00~~45.00 - ~~$3.24~~$35.00 - $55.50	IFWTI – NYMEX ~~(HH)~~

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


		Derivative Assets					Derivative Assets
		Fair Value					Fair Value
	Balance Sheet Location	June 30, 2016		December 31, 2015		Balance Sheet Location	June 30, 2017		December 31, 2016
		(In thousands)					(In thousands)
Commodity derivatives:
Current	Current derivative asset	$	—	$	10,186	Current derivative asset	$	3,948	$	—
Long-term	Non-current derivative asset	—		968		Non-current derivative asset	689		377
Total derivative assets		$	—	$	11,154		$	4,637	$	377


		Derivative Liabilities					Derivative Liabilities
		Fair Value					Fair Value
	Balance Sheet Location	June 30, 2016		December 31, 2015		Balance Sheet Location	June 30, 2017		December 31, 2016
		(In thousands)					(In thousands)
Commodity derivatives:
Current	Current derivative liability	$	9,646	$	—	Current derivative liability	$	1,036	$	21,564
Long-term	Non-current derivative liability	3,420		285		Non-current derivative liability	—		415
Total derivative liabilities		$	13,066	$	285		$	1,036	$	21,979

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.

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


Derivatives Instruments	Location of Loss Recognized in Income on Derivative	Amount of Loss Recognized in Income on Derivative						Location of Gain (Loss) Recognized in Income on Derivative	Amount of Gain (Loss) Recognized in Income on Derivative
		2016			2015				2017		2016
		(In thousands)							(In thousands)
Commodity derivatives	Gain (loss) on derivatives ⁽¹⁾	$	(22,672	)	$	(1,919	)	Gain (loss) on derivatives ⁽¹⁾	$	8,902	$	(22,672	)
Total		$	(22,672	)	$	(1,919	)		$	8,902	$	(22,672	)

_______________________


(1)	Amounts settled during the ~~2016~~2017 and ~~2015~~2016 periods include ~~gains~~a loss of ~~$5.1~~$0.4 million and ~~$10.1~~a gain of $5.1 million, respectively.

~~Effect~~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					Location of Gain (Loss) Recognized in Income on Derivative	Amount of Gain (Loss) Recognized in Income on Derivative
		2016			2015			2017		2016
		(In thousands)						(In thousands)
Commodity derivatives	Gain (loss) on derivatives ⁽¹⁾	$	(11,743	)	$	4,667	Gain (loss) on derivatives ⁽¹⁾	$	23,633	$	(11,743	)
Total		$	(11,743	)	$	4,667		$	23,633	$	(11,743	)

_______________________


(1)	Amounts settled during the ~~2016~~2017 and ~~2015~~2016 periods include ~~gains~~a loss of ~~$12.2~~$1.6 million and ~~$21.1~~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	$	—	$	—	$	—	$	—

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 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 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, 2016												June 30, 2017
	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	$	435		$	515		$	(950	)	$	—		$	—	$	1,010		$	4,656		$	(1,029	)	$	4,637
Liabilities	(8,740		)	(5,276		)	950			(13,066		)	—		(1,502		)	(563		)	1,029			(1,036		)
Total commodity derivatives													—		(492		)	4,093			—			3,601
Equity securities													862		—			—			—			862
	$	(8,305	)	$	(4,761	)	$	—		$	(13,066	)	$	862	$	(492	)	$	4,093		$	—		$	4,463


	December 31, 2015												December 31, 2016
	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	$	2,794		$	10,145		$	(1,785	)	$	11,154		$	—	$	878		$	43		$	(544	)	$	377
Liabilities	(1,019		)	(1,051		)	1,785			(285		)	—		(15,358		)	(7,165		)	544			(21,979		)
	$	1,775		$	9,094		$	—		$	10,869		$	—	$	(14,480	)	$	(7,122	)	$	—		$	(21,602	)

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. We are not required to post ~~any~~ cash collateral with our counterparties and no collateral has been posted as of June 30, ~~2016.~~2017.

~~The~~We used the following methods and assumptions ~~were used~~ to estimate the fair values of the assets and liabilities in the table above.

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 ~~tables are reconciliations~~table is a reconciliation of our level 3 fair value measurements:


	Net Derivatives												Net Derivatives
	Three Months Ended						Six Months Ended						Three Months Ended						Six Months Ended
	June 30,						June 30,						June 30,						June 30,
	2016			2015			2016			2015			2017			2016			2017			2016
	(In thousands)												(In thousands)
Beginning of period	$	9,983		$	857		$	9,094		$	3,355		$	(602	)	$	9,983		$	(7,122	)	$	9,094
Total gains or losses (realized and unrealized):
Included in earnings ⁽¹⁾	(12,322		)	111			(6,334		)	888			5,214			(12,322		)	11,117			(6,334		)
Settlements	(2,422		)	(761		)	(7,521		)	(4,036		)	(519		)	(2,422		)	98			(7,521		)
End of period	$	(4,761	)	$	207		$	(4,761	)	$	207		$	4,093		$	(4,761	)	$	4,093		$	(4,761	)
Total losses for the period included in earnings attributable to the change in unrealized gain (loss) relating to assets still held at end of period	$	(14,744	)	$	(650	)	$	(13,855	)	$	(3,148	)
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	)

_______________________


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

The following table provides quantitative information about our Level 3 unobservable inputs at June 30, ~~2016~~:2017:


Commodity ⁽¹⁾	Fair Value			Valuation Technique	Unobservable Input	Range	Fair Value			Valuation Technique	Unobservable Input	Range
	(In thousands)						(In thousands)
Oil collars	$	(151	)	Discounted cash flow	Forward commodity price curve	$0.07 - $5.31
Oil three-way collars	$	301		Discounted cash flow	Forward commodity price curve	$0.00 - $6.35	$	3,340		Discounted cash flow	Forward commodity price curve	($3.23) - $6.94
Natural gas collar	$	(3,253	)	Discounted cash flow	Forward commodity price curve	$0.00 - $0.90	$	(180	)	Discounted cash flow	Forward commodity price curve	($0.32) - $0.16
Natural gas three-way collars	$	(1,658	)	Discounted cash flow	Forward commodity price curve	$0.00 - $0.51	$	933		Discounted cash flow	Forward commodity price curve	($0.42) - $0.60

_______________________


(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.

~~Based on our~~Our valuation at June 30, ~~2016~~2017~~, we determined~~ reflected that the risk of non-performance by our counterparties was immaterial.

Fair Value of Other Financial Instruments

The following disclosure of the estimated fair value of financial instruments is made in accordance with 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 different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.

At June 30, ~~2016~~2017, 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~~short-term nature.

Based on the borrowing rates currently available to us for credit agreement debt with similar terms and maturities and ~~also~~ considering the risk of our non-performance, long-term debt under our credit agreement approximates its fair value and at June 30, ~~2016~~2017 and December 31, ~~2015~~2016 was ~~$236.0~~$164.9 million and ~~$281.0~~$160.8 million, respectively. This debt would be classified as Level 2.

The carrying amounts of long-term debt, net of unamortized discount and debt issuance costs, associated with the Notes reported in the Unaudited Condensed Consolidated Balance Sheets as of June 30, ~~2016~~2017 and December 31, ~~2015~~2016 were ~~$639.1~~$641.2 million and $~~638.0~~640.1 million, respectively. We estimate the fair value of ~~these~~the Notes using quoted marked prices at June 30, ~~2016~~2017 and December 31, ~~2015~~2016 ~~were~~was $~~505.4~~627.9 million and $~~455.5~~649.9 million, respectively. ~~These~~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 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 million, $1.1 million, $0.4 million, $0.3 million, and $0.1 million in twelve month periods beginning July 1, 2017 (and through the end of 2021), respectively. Total rent expense incurred was $4.2 million and $6.2 million for the first six months of 2017 and 2016, respectively.

In 2014, our mid-stream segment entered into capital lease agreements for 20 compressors with initial terms of seven years. Estimated annual capital lease payments under the terms during the five successive twelve month periods beginning July 1, 2017 (and through the end of 2021) are $6.2 million, $6.2 million, $6.2 million, $6.7 million, and $0.2 million. Total maintenance and interest remaining related to these leases are $6.8 million and $1.5 million, respectively at June 30, 2017. Annual payments, net of maintenance and interest, average $4.1 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 of 2017 or 2016.

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 million of new drilling rig components.

NOTE 13 – EQUITY

At-the-Market (ATM) Common Stock Program

On April 4, 2017, we entered into 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 not obligated 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, we sold 787,547 shares of our common stock resulting in net proceeds of approximately $18.6 million.

Accumulated Other Comprehensive Income

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



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

Changes in accumulated other comprehensive income by component, net of tax, for the three and six months ended June 30 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	$	—

NOTE 1214 – 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, ~~acquisition,~~ 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 ~~table provides~~tables provide certain information about the operations of each of our segments:



	Three Months Ended June 30, 2017
	Oil and Natural Gas		Contract Drilling			Mid-stream		Other			Eliminations			Total Consolidated
	(In thousands)
Revenues:
Oil and natural gas	$	83,173	$	—		$	—	$	—		$	—		$	83,173
Contract drilling	—		44,844			—		—			(5,589		)	39,255
Gas gathering and processing	—		—			63,111		—			(14,958		)	48,153
Total revenues	83,173		44,844			63,111		—			(20,547		)	170,581
Expenses:
Operating costs:
Oil and natural gas	33,941		—			—		—			(1,183		)	32,758
Contract drilling	—		32,452			—		—			(5,213		)	27,239
Gas gathering and processing	—		—			49,817		—			(13,775		)	36,042
Total operating costs	33,941		32,452			49,817		—			(20,171		)	96,039
Depreciation, depletion, and amortization	23,558		13,769			10,849		1,904			—			50,080
Total expenses	57,499		46,221			60,666		1,904			(20,171		)	146,119
Total operating income (loss) ⁽¹⁾	25,674		(1,377		)	2,445		(1,904		)	(376		)
General and administrative expense	—		—			—		(8,713		)	—			(8,713		)
Gain on disposition of assets	168		31			44		5			—			248
Gain on derivatives	—		—			—		8,902			—			8,902
Interest expense, net	—		—			—		(9,467		)	—			(9,467		)
Other	—		—			—		6			—			6
Income (loss) before income taxes	$	25,842	$	(1,346	)	$	2,489	$	(11,171	)	$	(376	)	$	15,438

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:
Oil and natural gas:
Operating costs 35,555
—
—
—
(2,224 ) 33,331
Depreciation, depletion, and amortization 30,411
—
—
—
—
30,411
Impairment of oil and natural gas properties 74,291
—
—
—
—
74,291
Contract drilling:
Operating costs —
19,254
—
—
—
19,254
Depreciation —
10,918
—
—
—
10,918
Gas gathering and processing:
Operating costs —
—
41,832
—
(9,451 ) 32,381
Depreciation and amortization —
—
11,515
—
—
11,515
Total expenses 140,257
30,172
53,347
—
(11,675 ) 212,101
Total operating income (loss) ⁽¹⁾
(71,067 ) (5,915 ) 3,186
—
—
(73,796 )
General and administrative expense —
—
—
(8,382 ) —
(8,382 )
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~~amortization and does not include general corporate expenses, ~~(gain) loss~~gain on disposition of assets, ~~loss~~gain on derivatives, interest expense, other income (loss), or income taxes.


	Three Months Ended June 30, 2015																	Three Months Ended June 30, 2016
	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	$	107,256		$	—		$	—	$	—		$	—		$	107,256		$	69,190		$	—		$	—	$	—		$	—		$	69,190
Contract drilling	—			60,813			—		—			(5,798		)	55,015			—			24,257			—		—			—			24,257
Gas gathering and processing	—			—			69,163		—			(16,987		)	52,176			—			—			56,533		—			(11,675		)	44,858
Total revenues	107,256			60,813			69,163		—			(22,785		)	214,447			69,190			24,257			56,533		—			(11,675		)	138,305
Expenses:
Oil and natural gas:
Operating costs	47,179			—			—		—			(1,207		)	45,972
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	68,101			—			—		—			—			68,101			30,411			10,918			11,515		34			—			52,878
Impairment of oil and natural gas properties	410,536			—			—		—			—			410,536
Contract drilling:
Operating costs	—			41,746			—		—			(5,261		)	36,485
Depreciation	—			13,265			—		—			—			13,265
Impairment of contract drilling properties	—			8,314			—		—			—			8,314
Gas gathering and processing:
Operating costs	—			—			56,372		—			(15,780		)	40,592
Depreciation and amortization	—			—			10,848		—			—			10,848
Impairments																		74,291			—			—		—			—			74,291
Total expenses	525,816			63,325			67,220		—			(22,248		)	634,113			140,257			30,172			53,347		34			(11,675		)	212,135
Total operating income (loss)⁽¹⁾	(418,560		)	(2,512		)	1,943		—			(537		)	(419,666		)	(71,067		)	(5,915		)	3,186		(34		)	—
General and administrative expense	—			—			—		(9,624		)	—			(9,624		)	—			—			—		(8,348		)	—			(8,348		)
Gain (loss) on disposition of assets	—			(50		)	465		—			—			415			(324		)	815			—		(14		)	—			477
Loss on derivatives	—			—			—		(1,919		)	—			(1,919		)	—			—			—		(22,672		)	—			(22,672		)
Interest expense, net	—			—			—		(7,956		)	—			(7,956		)	—			—			—		(10,606		)	—			(10,606		)
Other	—			—			—		24			—			24			—			—			—		1			—			1
Income (loss) before income taxes	$	(418,560	)	$	(2,562	)	$	2,408	$	(19,475	)	$	(537	)	$	(438,726	)	$	(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, 2016																		Six Months Ended June 30, 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	$	127,464		$	—		$	—		$	—		$	—		$	127,464		$	170,771	$	—		$	—	$	—		$	—		$	170,771
Contract drilling	—			62,967			—			—			—			62,967			—		82,029			—		—			(5,589		)	76,440
Gas gathering and processing	—			—			105,578			—			(21,520		)	84,058			—		—			129,575		—			(30,481		)	99,094
Total revenues	127,464			62,967			105,578			—			(21,520		)	274,489			170,771		82,029			129,575		—			(36,070		)	346,305
Expenses:
Oil and natural gas:
Operating costs	70,361			—			—			—			(3,684		)	66,677
Operating costs:
Oil and natural gas																			64,267		—			—		—			(2,305		)	61,962
Contract drilling																			—		61,679			—		—			(5,213		)	56,466
Gas gathering and processing																			—		—			101,922		—			(28,176		)	73,746
Total operating costs																			64,267		61,679			101,922		—			(35,694		)	192,174
Depreciation, depletion, and amortization	62,243			—			—			—			—			62,243			45,084		26,616			21,667		3,645			—			97,012
Impairment of oil and natural gas properties	112,120			—			—			—			—			112,120
Contract drilling:
Operating costs	—			47,352			—			—			—			47,352
Depreciation	—			23,113			—			—			—			23,113
Gas gathering and processing:
Operating costs	—			—			81,283			—			(17,836		)	63,447
Depreciation and amortization	—			—			22,974			—			—			22,974
Total expenses	244,724			70,465			104,257			—			(21,520		)	397,926			109,351		88,295			123,589		3,645			(35,694		)	289,186
Total operating income (loss)⁽¹⁾	(117,260		)	(7,498		)	1,321			—			—			(123,437		)	61,420		(6,266		)	5,986		(3,645		)	(376		)
General and administrative expense	—			—			—			(17,097		)	—			(17,097		)	—		—			—		(17,667		)	—			(17,667		)
Gain (loss) on disposition of assets	(324		)	1,316			(302		)	(21		)	—			669
Loss on derivatives	—			—			—			(11,743		)	—			(11,743		)
Gain on disposition of assets																			177		38			44		813			—			1,072
Gain on derivatives																			—		—			—		23,633			—			23,633
Interest expense, net	—			—			—			(20,223		)	—			(20,223		)	—		—			—		(18,863		)	—			(18,863		)
Other	—			—			—			(14		)	—			(14		)	—		—			—		9			—			9
Income (loss) before income taxes	$	(117,584	)	$	(6,182	)	$	1,019		$	(49,098	)	$	—		$	(171,845	)	$	61,597	$	(6,228	)	$	6,030	$	(15,720	)	$	(376	)	$	45,303

_______________________


(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.



	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	)

_______________________


(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, 2015
Oil and Natural Gas Contract Drilling Mid-stream Other Eliminations Total Consolidated
(In thousands)
Revenues:
Oil and natural gas $ 213,325
$ —
$ —
$ —
$ —
$ 213,325
Contract drilling —
165,751
—
—
(15,659 ) 150,092
Gas gathering and processing —
—
142,967
—
(36,838 ) 106,129
Total revenues 213,325
165,751
142,967
—
(52,497 ) 469,546
Expenses:
Oil and natural gas:
Operating costs 93,560
—
—
—
(2,377 ) 91,183
Depreciation, depletion, and amortization 145,219
—
—
—
—
145,219
Impairment of oil and natural gas properties 811,129
—
—
—
—
811,129
Contract drilling:
Operating costs —
100,443
—
—
(12,212 ) 88,231
Depreciation —
28,278
—
—
—
28,278
Impairment of contract drilling properties —
8,314
—
—
—
8,314
Gas gathering and processing:
Operating costs —
—
119,228
—
(34,461 ) 84,767
Depreciation and amortization —
—
21,542
—
—
21,542
Total expenses 1,049,908
137,035
140,770
—
(49,050 ) 1,278,663
Total operating income (loss) ⁽¹⁾
(836,583 ) 28,716
2,197
—
(3,447 ) (809,117 )
General and administrative expense —
—
—
(18,994 ) —
(18,994 )
Gain on disposition of assets —
495
465
—
—
960
Gain on derivatives —
—
—
4,667
—
4,667
Interest expense, net —
—
—
(15,196 ) —
(15,196 )
Other —
—
—
22
—
22
Income (loss) before income taxes $ (836,583 ) $ 29,211
$ 2,662
$ (29,501 ) $ (3,447 ) $ (837,658 )

~~_______________________~~


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

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. ~~We have~~MD&A is organized ~~MD&A~~ into the following 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 ~~in connection~~ with your review of the information below as well as 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 ~~that of~~ 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 ~~own account.~~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 ~~own account.~~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, ~~and~~ natural gas, and NGLs, as well as, 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 commodity prices worldwide during the past ~~20 or so months~~several years brought about significant and adverse changes ~~affecting~~to our industry and us. ~~These lower commodity prices caused us (and other~~As a result we reduced or stopped, for a period of time, our oil and natural gas ~~companies) to reduce (or even stop) our level of~~segment's drilling ~~activity and spending. When~~activity. Industry wide reductions in drilling activity and spending ~~decline~~ for extended periods ~~of time~~also tends to reduce the rates for and the number of our drilling rigs ~~working also tend to decline.~~that we can work. In addition, sustained lower commodity prices ~~can~~ 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.

~~It is uncertain how long the current depressed~~During 2016, commodity prices ~~will continue. As noted elsewhere~~began to improve. In the fourth quarter of 2016, our oil and natural gas segment began using two of our drilling rigs and has continued using them during the first six months of 2017. Our contract drilling segment completed the construction and contracted the ninth and tenth BOSS drilling rigs in the fourth quarter of 2016 and the second quarter of 2017, respectively. Our drilling rig segment's rig utilization increased from 16 drilling rigs working as of June 30, 2016, to 33 drilling rigs working as of June 30, 2017. The extent and duration of this ~~report, those prices are subject to a number of factors most of which we cannot control.~~improvement remains uncertain.

The ~~impact on our business and financial results from the~~ reduction in oil, NGLs, and natural gas prices ~~has~~ had a number of consequences for us ~~including:~~(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 the first ~~six~~nine months of 2016 of ~~$112.1~~$161.6 million ($~~69.8~~100.6 million net of tax). We did not have a write-down in the fourth quarter of 2016 or the first two quarters 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 ~~factors and~~ inherent ~~limitations,~~uncertainties, if we hold these same factors constant as they existed ~~on July 1, 2016~~at June 30, 2017 and only ~~adjusted~~adjust the 12-month average price to an estimated ~~second~~third quarter ending average (holding July ~~2016~~2017 prices constant for the remaining two months of the third quarter of ~~2016)~~2017), our forward looking expectation is that we ~~would~~will not ~~expect to~~ recognize an impairment in the third quarter of ~~2016. Commodity~~2017. But commodity prices (and other factors) remain volatile and ~~have recently trended downward and should that trend continue it~~they could negatively impact the 12-month average price ~~and~~resulting in the potential for an impairment in the ~~third quarter.~~future.

We ~~have~~ reduced the number of gross wells ~~we plan to drill~~our oil and natural gas segment drilled in 2016 by approximately ~~57-66%~~64% from the number drilled in 2015 due to our reduced cash ~~flow resulting~~flow. For 2017, we plan to increase the number of gross wells drilled by approximately 67-90% (depending on future commodity prices) from ~~lower commodity prices.~~the number of wells drilled in 2016.

~~Several of~~The decline in drilling by our ~~drilling rig~~ customers ~~significantly reduced their drilling budgets, which have~~ 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 ~~at July 22,~~we exited 2016 ~~that number was 16. We~~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 ~~starting to see a small increase in rig activity in the third quarter.~~under contract.

Due to ~~the~~ low NGLs prices, we ~~are operating~~continue to operate most of our mid-stream processing facilities in ~~full~~ ethane rejection mode which reduces the amount of liquids sold. As long as NGLs prices ~~continue to be~~remain depressed, we expect to continue operating in ~~full~~ ethane rejection mode. As low commodity prices continue, we expect the reductions in drilling activity around our systems will reduce the number of new wells available to connect to our systems thus resulting in lower processed volumes

Also, as ~~production from connected wells naturally decline.~~

~~Under the third amendment to our credit agreement entered into~~noted elsewhere, beginning on April ~~8, 2016,~~4, 2017, we began an at-the-market offering for the ~~lenders decreased~~sale of shares of our ~~borrowing base~~common stock. The offering allows us to sell shares, from ~~$550.0~~time to time, up to an aggregate of $100 million ~~to $475.0~~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. ~~Our commitment~~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 ~~agreement also decreased from $500.0 million to $475.0 million. At July 22, 2016, borrowings were $238.6 million. We believe our liquidity is adequate to carry out our 2016 capital plans.~~facility, and general corporate purposes.

~~We have reduced our total 2016 capital budget by a range~~On April 3, 2017, we closed an acquisition of approximately 59-65% as compared to 2015, excluding acquisitions and ARO liability. The budget is designed to keep our capital expenditures below our anticipated cash flow and proceeds from any non-core asset sales and is based on realized prices for the year of $34.57 per barrel of oil, $8.01 per barrel of NGLs, and $2.24 per Mcf of natural gas. We may periodically adjust our budget for various reasons including changes in commodity prices and industry conditions. Funding for the budget will come primarily from our cash flow, possible non-core asset sales, and, if necessary, borrowings under our credit agreement.

~~In response to lower commodity prices we did the following during the first six months of 2016:~~

~~Consolidated from five to two the number of divisions within our drilling segment further reducing the costs associated with operating the divisions.~~

Designed the higher end of our 2016 exploration and production segment budget so the majority of those proposed expenditures would be in the latter part of the year allowing us to take into account future commodity price movement before we actually incur those expenditures.

~~Implemented~~ certain ~~reductions in our office and field workforces to account for the reduction in our operating activities as well as reducing the compensation paid to drilling personnel.~~

~~Through June 30, 2016, we have sold non-core~~ oil and natural gas ~~properties for~~assets from an unrelated third party. The acquisition includes approximately ~~$43.6 million with most~~47 proved developed producing wells and 8,300 net acres primarily in Grady and Caddo Counties in western Oklahoma. The preliminary adjusted value of ~~the proceeds being used~~consideration given was $54.0 million. This acquisition is subject to ~~pay down borrowings under our bank credit agreement.~~certain post-closing adjustments. The effective date of this acquisition is January 1, 2017.

Executive Summary

Oil and Natural Gas

Second quarter ~~2016~~2017 production from our oil and natural gas segment was ~~4,359,000~~3,852,000 barrels of oil equivalent (Boe), an increase of 2% over the first quarter of 2017 and a decrease of 3%12% from the second quarter of 2016, respectively. The increase over the first quarter of 2017 was from acquired wells and ~~14%~~new wells drilled in the first six months of 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 quarter 2017 oil and natural gas revenues decreased 5% from the first quarter of ~~2016~~2017 and increased 20% over the second quarter of ~~2015, respectively. This~~2016. The decrease ~~was primarily due to natural declines in production with minimal replacement in production~~ from ~~new wells due to our reduced drilling activity resulting from lower commodity prices.~~

~~Second quarter 2016 oil and natural gas revenues increased 19% over~~ the first quarter of ~~2016~~ ~~and decreased 36% from the second quarter of 2015.~~2017 was due primarily to lower commodity prices partially offset by higher production volumes. The increase over ~~first~~the second quarter of 2016 was due primarily to higher ~~oil and NGLs prices offset partially from lower production volumes and lower natural gas prices. The decrease from the second quarter of 2015 was due primarily to lower~~ commodity prices ~~and to a lesser extent from~~partially offset by lower production volumes.

Our oil prices for the second quarter of 2016 increased 28% over the first quarter of 2016 and decreased 25% from the second quarter of 2015. Our NGLs prices increased 73% over the first quarter of 2016 and decreased 6% from the second quarter of 2015. Our natural gas prices2017 decreased 4% from the first quarter of ~~2016~~2017 and ~~decreased 33% from~~increased 13% over the second quarter of ~~2015.~~2016. Our NGLs prices decreased 16% 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.

Operating cost per Boe produced for the second quarter of ~~2016~~2017 increased 4%10% and 11% over the first quarter of ~~2016~~2017 and ~~decreased 16% from~~ the second quarter of ~~2015.~~2016, respectively. The increase over the first quarter of 2017 was primarily due to an increase in 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 ~~higher gross~~lower production ~~taxes due to fewer gross production tax credits. The decrease from the second quarter of 2015 was primarily due to~~volumes partially offset by lower lease operating ~~expenses, saltwater disposal expense, and general and administrative~~ expenses.

At June 30, ~~2016,~~2017, we had ~~the following~~these derivatives outstanding:



Term	Commodity	Contracted Volume	Weighted Average Fixed Price	Contracted Market
~~Jul’16~~Jul’17 – ~~Dec’16~~Oct'17	Natural gas – swap	~~45,000~~70,000 MMBtu/day	$~~2.596~~3.038	IF – NYMEX (HH)
~~Jan’17~~Nov’17 – Dec'17	Natural gas – swap	60,000 MMBtu/day	$2.960	IF – NYMEX (HH)
Jan’18 – Dec'18	Natural gas – swap	~~10,000~~20,000 MMBtu/day	$~~3.025~~3.013	IF – NYMEX (HH)
~~Jan’17~~Nov’17 – Dec'17	Natural gas – basis swap	20,000 MMBtu/day	$(0.215)	IF – NYMEX (HH)
Jan’18 – Mar'18	Natural gas – basis swap	10,000 MMBtu/day	$(0.208)	IF – NYMEX (HH)
Nov’18 – Dec'18	Natural gas – basis swap	10,000 MMBtu/day	$(0.208)	IF – NYMEX (HH)
~~Jul’16 – Dec'16~~	~~Natural gas – collar~~	~~42,000 MMBtu/day~~	~~$2.40 - $2.88~~	~~IF – NYMEX (HH)~~
~~Jan’17~~Jul’17 – Oct'17	Natural gas – collar	~~10,000~~20,000 MMBtu/day	$~~2.75~~2.88 - ~~$2.95~~$3.10	IF – NYMEX (HH)
~~Jul’16~~Jul'17 – ~~Dec'16~~	~~Natural gas – three-way collar~~	~~13,500 MMBtu/day~~	~~$2.70 - $2.20 - $3.26~~	~~IF – NYMEX (HH)~~
~~Jan’17 – Dec'17~~Oct'17	Natural gas – three-way collar	15,000 MMBtu/day	$2.50 - $2.00 - $3.32	IF – NYMEX (HH)
~~Jul’16~~Nov’17 – ~~Sep'16~~Dec'17	~~Crude oil – swap~~	~~1,000 Bbl/day~~	~~$48.45~~	~~WTI – NYMEX~~
~~Jul’16 – Sep'16~~	~~Crude oil – collar~~	~~2,450 Bbl/day~~	~~$44.44 - $52.46~~	~~WTI – NYMEX~~
~~Oct’16 – Dec'16~~	~~Crude oil – collar~~	~~1,450 Bbl/day~~	~~$47.50 - $56.40~~	~~WTI – NYMEX~~
~~Jul’16 – Dec'16~~	~~Crude oil~~Natural gas – three-way collar	~~700 Bbl/~~25,000 MMBtu/day	$~~46.50~~2.90 - ~~$35.00~~$2.30 - ~~$57.00~~$3.59	~~WTI~~IF – NYMEX (HH)
~~Jul’16~~Jan'18 – ~~Dec'16~~Mar'18	~~Crude oil~~Natural gas – three-way collar⁽¹⁾	~~700 Bbl/~~60,000 MMBtu/day	$~~47.50~~3.29 - ~~$35.00~~$2.63 - ~~$63.50~~$4.07	~~WTI~~IF – NYMEX (HH)
~~Jan’17~~Apr'18 – Dec'18	Natural gas – three-way collar	20,000 MMBtu/day	$3.00 - $2.50 - $3.51	IF – NYMEX (HH)
Jul’17 – Dec'17	Crude oil – three-way collar	~~750~~3,750 Bbl/day	$49.79 - $39.58 - $60.98	WTI – NYMEX
Jan'18 – Dec'18	Crude oil – three-way collar	1,000 Bbl/day	$50.00 - ~~$37.50~~$40.00 - ~~$63.90~~$56.65	WTI – NYMEX

~~_______________________~~


~~(1)~~	~~We pay our counterparty a premium, which can be and is being deferred until settlement.~~

After June 30, ~~2016, we entered into~~2017, the following ~~derivatives:~~derivatives were entered into:



Term	Commodity	Contracted Volume	Weighted Average Fixed Price	Contracted Market
~~Jan’17~~Jan'18 – ~~Oct'17~~Dec'18	~~Natural gas~~Crude oil – swap	500 Bbl/day	$50.00	WTI – NYMEX
Jan'18 – Dec'18	Crude oil – three-way collar	~~10,000 MMBtu/~~1,000 Bbl/day	$~~3.00~~45.00 - ~~$3.24~~$35.00 - $55.50	IFWTI – NYMEX ~~(HH)~~

For the six months ended June 30, ~~2016,~~2017, we completed drilling 1319 gross wells ~~(7.65~~(8.21 net wells). For all of ~~2016,~~2017, we plan to participate in the drilling of approximately ~~20-25~~35 to 40 gross wells. Excluding acquisitions and ARO liability, our estimated ~~2016~~2017 capital expenditures for this segment ~~range from $109.0 to $131.0~~are approximately $197.0 million. Our current ~~2016~~2017 production guidance is approximately ~~16.9~~16.0 to ~~17.4~~16.5 MMBoe, a decrease of ~~13%~~4% to ~~16%~~7% from ~~2015,~~2016, although actual results continue to be subject to many factors.

Contract Drilling

The average number of drilling rigs we operated in the second quarter of ~~2016~~2017 was ~~13.5~~28.8 compared to ~~20.6~~25.5 and ~~30.7~~13.5 in the first quarter of ~~2016~~2017 and the second quarter of ~~2015,~~2016, respectively. Late in the fourth quarter of 2014, the number of our drilling rigs operating started to decline and has continued to decline through the first six months of 2016 because of lower commodity prices and operators reducing their drilling budgets. As of June 30, ~~2016, 16~~2017, 33 of our drilling rigs were operating.

Revenue for the second quarter of ~~2016 decreased 37%~~2017 increased 6% and ~~56% from~~62% over the first quarter of ~~2016~~2017 and the second quarter of ~~2015,~~2016, respectively. The ~~decreases~~increases were primarily due ~~primarily~~ to ~~fewer~~an increase in drilling rigs ~~operating.~~operating partially offset by lower dayrates between the second quarter of 2017 and the second quarter of 2016.

Dayrates for the second quarter of ~~2016~~2017 averaged ~~$18,585,~~$15,962, a 1% increase over the first quarter of ~~2016~~2017 and a 7%14% decrease from the second quarter of ~~2015.~~2016. The increase over the first quarter of 2017 was primarily due to increased demand. The decrease from the second quarter of ~~2015~~2016 was primarily due to downward pressure on dayrates ~~from~~due to lower demand.

Operating costs for the second quarter of ~~2016~~2017 decreased ~~31% and 47%~~7% from the first quarter of ~~2016~~2017 and increased 41% over the second quarter of ~~2015, respectively.~~2016. The ~~decreases were~~decrease from the first quarter of 2017 was primarily due to less new rig activation costs. The

increase over the second quarter of 2016 was due primarily to ~~fewer~~more drilling rigs ~~operating.~~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 ~~continued low~~improved commodity ~~prices~~pricing for oil and natural gas that began during the second half of 2016 has ~~changed~~increased demand for drilling rigs. ~~These factors affect~~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 ~~mix of~~ the ~~type~~availability of drilling rigs ~~used by our customers and~~to meet that demand will ~~impact~~affect our future dayrates.

~~As of June 30, 2016, we had five~~We have 15 term drilling contracts with original terms ranging from six months to ~~three~~two years. ~~One~~Seven are up for renewal in the third quarter of ~~these contracts~~2017, six in the fourth quarter of 2017, one is up for renewal in ~~the fourth quarter of 2016~~2018, and ~~four are up for renewal~~one in ~~2017.~~2019. Term contracts may contain a fixed rate ~~for the duration of~~during the contract or provide for rate adjustments within a specific range from the existing rate. Some operators ~~who had~~with signed term contracts ~~have~~ opted to release the drilling rig and pay an early termination penalty for the remaining term of the contract. During the ~~second quarter~~first six months of ~~2016,~~2017, we recorded ~~$0.4~~$0.8 million inof early termination fees compared to ~~$2.6~~$3.0 million in the first ~~quarter~~six months of ~~2016~~2016.

All ten of our existing BOSS drilling rigs are under contract. Construction was completed on our tenth BOSS drilling rig and ~~$1.6 million~~the rig was placed into service late in the second ~~quarter of 2015.~~

~~As of June 30, 2016, seven~~quarter. We also have contracted and placed into service three of our ~~eight BOSS~~stacked SCR drilling rigs ~~were under contract. Currently, we do not~~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 ~~any contracts~~two additional stacked SCR drilling rigs returning to ~~build additional BOSS drilling rigs.~~service in the third quarter. Both in our Mid-Continent division. One is being relocated from our Rocky Mountain division. Our ~~anticipated 2016~~estimated 2017 capital expenditures for this segment ~~range~~are approximately $28.0 million.

Competition to keep qualified labor continues to be an issue we face in this segment. We do not believe this shortage of qualified labor will keep us from ~~$9.0 million~~working additional drilling rigs, but it could cause some delays in the time to ~~$11.0 million, an 87-89% decrease from 2015.~~crew new drilling rigs. Beginning in third quarter 2017, we increased compensation for certain drilling rig personnel.

Mid-Stream

Second quarter ~~2016~~2017 liquids sold per day increased 2%6% over the first quarter of ~~2016~~2017 and decreased ~~11%~~1% from the second quarter of ~~2015.~~2016, respectively. The increase over the first quarter of ~~2016~~2017 was due to ~~recovering more liquids~~increased volumes at ~~certain~~our processing facilities. The decrease from the second quarter of ~~2015~~2016 was primarily due to less volume available to process at our plants. For the second quarter of ~~2016,~~2017, gas processed per day ~~decreased 3% from~~increased 7% over the first quarter of ~~2016~~2017 and decreased ~~13%~~16% from the second quarter of ~~2015.~~2016. The ~~decreases were~~increase over the first quarter of 2017 was primarily due to higher volumes at our Cashion facility 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, ~~and~~ fewer new wells ~~connected.~~connected, and losing an offload volume at our Hemphill facility in mid-2016. For the second quarter of ~~2016,~~2017, gas gathered per day ~~increased 15% over~~decreased 2% and 13% from the first quarter of ~~2016~~2017 and ~~increased 21% over~~ the second quarter of ~~2015.~~2016, respectively. The ~~increases~~decreases were primarily ~~from additional wells added~~due to declining volume on our ~~Pittsburgh Mills gathering system.~~Appalachian systems and losing an offload volume at our Hemphill facility in mid-2016.

NGLs prices in the second quarter of ~~2016 increased 38% over~~2017 decreased 12% from the prices received in the first quarter of ~~2016~~2017 and ~~were essentially unchanged from~~increased 9% over the prices received in the second quarter of ~~2015.~~2016. 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 quarter of ~~2016 increased~~2017 decreased 4% ~~over~~from the first quarter of ~~2016~~2017 and ~~decreased 20% from~~increased 11% over the second quarter of ~~2015.~~2016. Second quarter of ~~2016~~2017 costs were ~~higher~~lower than the first quarter of 2017 primarily due to lower gas purchase prices partially offset by increased purchase volumes. The increase over the second quarter of 2016 was primarily due to higher gas purchase prices ~~while~~partially offset by lower purchase 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 ~~2016 versus second~~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 ~~2015 was lower due~~2018. Also, we anticipate several in-fill wells to ~~lower gas purchase prices~~be drilled and ~~lower purchase volumes along with lower general and administrative and field direct expenses.~~connected to our system in the first half of 2018.

At our Hemphill Texas system, our total throughput volume averaged 57.5 MMcf per day for the second quarter of ~~2016, our total throughput volume averaged 69.3 MMcf per day~~2017 and our total production of natural gas liquids was approximately ~~172,200~~142,000 gallons per day. ~~At this processing facility we have the capacity to process 135 MMcf per day through three processing skids. During the second quarter, we connected one new- long lateral well to this system.~~

increased our natural gas liquids volume to approximately 130,800 gallons per day. After minor modifications to our gathering system, we have been receiving additional volumes from third party producers since the first of this year. During the first six months of 2016, we connected 15 additional wells to this gathering system. At this processing facility we have two processing skids available that provide totalTotal processing capacity ~~of 90 MMcf per day.~~

~~At our Segno gathering~~at this facility located Southeast Texas, our average transported volume increased to over 90 MMcf per day for the second quarter of 2016. Since the first of this year, we connected three new wells to this gathering system. With the completion of the GAP pipeline extension project, our total gathering capacity has increased to 120 MMcf per day for this system.

In the Appalachian region, at our Pittsburgh Mills gathering system, our average throughput volume continues to increase. During the second quarter of 2016 the total throughput volume increased to approximately 142.5 MMcf per day. Since the beginning of this year we have connected three new well pads with a total of 12 new wells to this gathering system. In June, we connected the Thompson well pad which included two new wells. The Thompson well pad is located on the northern end of our system and delivers gas into NiSource’s Big Pine system. We have completed construction of a pipeline to connect our next well pad which is the Belo pad. There are six wells located on this pad and it was connected and began flowing gas in July.

Also in the Appalachian area at our Snow Shoe gathering system, since the first of this year, we have connected three well pads that have a total of six wells. Our average throughput volume for the second quarter of 2016 has increased to approximately 14135 MMcf per day. During the second quarter, we connected one new well ~~pad~~and since the beginning of 2017, we connected two new wells to this processing facility. Our oil and gas segment continues to operate a rig and we anticipate connecting four more wells in the third quarter.

At our Cashion processing facility in central Oklahoma, our total throughput volume for the second quarter of 2017 averaged approximately 37.8 MMcf per day and our total production of natural gas liquids increased to approximately 207,000 gallons per day. Total processing capacity for this facility remains at approximately 45 MMcf per day. In the first six months of 2017, we connected one new well and completed a construction project that ~~had three~~allows us to bring additional gas to this processing plant from a third party producer. This new producer will deliver fee-based volume to us for five years or will pay a shortfall fee settled annually. 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.

At our Bellmon processing facility in the Mississippian play in north central Oklahoma, we connected six new wells ~~which began flowing~~ in ~~April.~~the second quarter of 2017 and our total throughput volume averaged approximately 27 MMcf per day. Total natural gas liquids averaged approximately 137,700 gallons per day while operating in ethane recovery mode at this facility. Total processing capacity at this system is approximately 90 MMcf per day.

At our Segno gathering facility in Southeast Texas, gathered volume for the second quarter of 2017 averaged approximately 79.2 MMcf per day. At this facility, we have increased our gathering and dehydration capacity to approximately 120 MMcf per day. We have ~~completed preliminary construction of the Snow Shoe compressor station but we will not complete the compressor station until compression services are required.~~connected one new well to this system in 2017.

Our estimated ~~2016~~2017 capital expenditures for this segment ~~range from $22.0 million to $24.0~~are approximately $16.0 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. ~~The amount of our~~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 ~~currently~~ believe we will have ~~sufficient~~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 ~~as well as~~and our 2011 Indenture) and our capacity to incur additional indebtedness will depend on our future performance, which ~~in turn~~ 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 ~~result in~~cause a reduction of the borrowing base and therefore reduce or limit our ability to incur indebtedness. ~~As a result, we~~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 ~~if any,~~ ahead of time.

As part of our efforts to manage liquidity risks, we have lowered our capital expenditures budget, focused our drilling program on our highest return plays, and continue to explore opportunities to divest non-core assets and properties. During the first six months, we sold non-core oil and gas properties for approximately $43.6 million using most of the proceeds to pay down borrowings under our bank credit agreement. If necessary, we could sell other non-core assets and use the proceeds to further reduce our outstanding borrowings.


	Six Months Ended June 30,						% Change⁽¹⁾		Six Months Ended June 30,						% Change
	2016			2015			% Change⁽¹⁾		2017			2016			% Change
	(In thousands except percentages)								(In thousands except percentages)
Net cash provided by operating activities	$	132,716		$	257,606		(48	)%	$	117,055		$	132,716		(12	)%
Net cash used in investing activities	(77,386		)	(366,442		)	(79	)%	(142,833		)	(77,386		)	85	%
Net cash (used in) provided by financing activities	(55,191		)	108,626			(151	)%
Net cash provided by (used in) financing activities									25,734			(55,191		)	147	%
Net increase (decrease) in cash and cash equivalents	$	139		$	(210	)			$	(44	)	$	139

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 by changes in working capital.

Net cash provided by operating activities in the first six months of ~~2016~~2017 decreased by ~~$124.9~~$15.7 million ~~from~~as compared to the first six months of ~~2015.~~2016. The decrease was the result of ~~lower revenues resulting from lower commodity prices, lower drilling rig utilization, and by~~ changes in operating assets and liabilities related to the timing of cash receipts and ~~disbursements.~~disbursements partially offset by higher profit margins in all three segments.

Cash Flows from Investing Activities

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

Cash flows used in investing activities ~~decreased~~increased by ~~$289.1~~$65.4 million for the first six months of ~~2016~~2017 compared to the first six months of ~~2015.~~2016. The change was due primarily to ~~a decrease~~an increase in capital expenditures due to an oil and ~~an increase~~gas property acquisition, the restarting of our contract drilling program in 2017, the construction of two new BOSS drilling rigs, and a decrease in the proceeds received from the disposition of assets. See additional information on capital expenditures below under Capital Requirements.

Cash Flows from Financing Activities

Cash flows ~~(used in)~~ provided by financing activities ~~decreased~~increased by ~~$163.8~~$80.9 million for the first six months of ~~2016~~2017 compared to the first six months of ~~2015. This decrease~~2016. The increase was primarily due to ~~the payback of~~an increase in borrowings under our credit ~~agreement.~~agreement, proceeds from the ATM common stock program, and an increase in book overdrafts in 2017 after we paid down debt in the first six months of 2016.

At June 30, ~~2016~~2017, we had unrestricted cash totaling ~~$1.0~~$0.8 million and had borrowed ~~$236.0~~$164.9 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.

The following is a summary of certain financial information as of June 30, ~~2016~~2017 and ~~2015~~2016 and for the six months ended June 30, ~~2016~~2017 and ~~2015~~2016:

June 30,
%
Change⁽¹⁾
2016 2015
(In thousands except percentages)
Working capital $ (57,463 ) $ (11,366 ) NM
Long-term debt less debt issuance costs $ 875,051
$ 917,447
(5 )%
Shareholders’ equity $ 1,211,221
$ 1,823,600
(34 )%
Net loss $ (113,285 ) $ (522,743 ) (78 )%

~~_______________________~~


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

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

Six Months Ended
June 30,
%
Change
2016 2015
Oil and Natural Gas:
Oil production (MBbls) 1,559
2,046
(24 )%
NGLs production (MBbls) 2,485
2,615
(5 )%
Natural gas production (MMcf) 28,977
33,064
(12 )%
Average oil price per barrel received $ 36.88
$ 51.73
(29 )%
Average oil price per barrel received excluding derivatives $ 34.77
$ 48.13
(28 )%
Average NGLs price per barrel received $ 8.90
$ 10.37
(14 )%
Average NGLs price per barrel received excluding derivatives $ 8.90
$ 10.37
(14 )%
Average natural gas price per Mcf received $ 1.83
$ 2.80
(35 )%
Average natural gas price per Mcf received excluding derivatives $ 1.52
$ 2.39
(36 )%
Contract Drilling:
Average number of our drilling rigs in use during the period 17.1
40.4
(58 )%
Total number of drilling rigs owned at the end of the period 94
94
— %
Average dayrate $ 18,468
$ 20,032
(8 )%
Mid-Stream:
Gas gathered—Mcf/day 411,671
348,666
18 %
Gas processed—Mcf/day 164,333
187,592
(12 )%
Gas liquids sold—gallons/day 525,824
584,389
(10 )%
Number of natural gas gathering systems 26
27
(4 )%
Number of processing plants 14
13
8 %



	June 30,						% Change
	2017			2016			% Change
	(In thousands except percentages)
Working capital	$	(51,417	)	$	(57,463	)	11	%
Long-term debt less debt issuance costs	$	806,092		$	875,051		(8	)%
Shareholders’ equity	$	1,244,463		$	1,211,221		3	%
Net income (loss)	$	24,988		$	(113,285	)	122	%

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 ~~$57.5~~$51.4 million and ~~$11.4~~$57.5 million as of June 30, ~~2016~~2017 and ~~2015,~~2016, respectively. This is primarily from ~~the change~~an increase in ~~value of remaining derivatives outstanding and lower~~ accounts receivable due to ~~lower~~higher revenues, 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 ~~the timing of~~increased accounts payable ~~associated with our capital expenditures.~~due to increased drilling activity and more rigs operating. Our credit agreement is used primarily for working capital and capital expenditures. At June 30, ~~2016,~~2017, we had borrowed ~~$236.0~~$164.9 million of the $475.0 million available under our credit agreement. The effect of our derivative contracts increased working capital by $2.9 million as of June 30, 2017 and decreased working capital by $9.6 million as of June 30, ~~2016 and increased working capital by $14.6 million as of June 30, 2015.~~2016.

The following table summarizes certain operating information:



	Six Months Ended
	June 30,				% Change
	2017		2016		% Change
Oil and Natural Gas:
Oil production (MBbls)	1,357		1,559		(13	)%
NGLs production (MBbls)	2,233		2,485		(10	)%
Natural gas production (MMcf)	24,232		28,977		(16	)%
Average oil price per barrel received	$	47.77	$	36.88	30	%
Average oil price per barrel received excluding derivatives	$	47.27	$	34.77	36	%
Average NGLs price per barrel received	$	16.34	$	8.90	84	%
Average NGLs price per barrel received excluding derivatives	$	16.34	$	8.90	84	%
Average natural gas price per Mcf received	$	2.57	$	1.83	40	%
Average natural gas price per Mcf received excluding derivatives	$	2.66	$	1.52	75	%
Contract Drilling:
Average number of our drilling rigs in use during the period	27.2		17.1		59	%
Total number of drilling rigs owned at the end of the period	95		94		1	%
Average dayrate	$	15,905	$	18,468	(14	)%
Mid-Stream:
Gas gathered—Mcf/day	386,893		411,671		(6	)%
Gas processed—Mcf/day	130,804		164,333		(20	)%
Gas liquids sold—gallons/day	511,969		525,824		(3	)%
Number of natural gas gathering systems	25		26		(4	)%
Number of processing plants	13		14		(7	)%

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. ~~Domestic oil prices are primarily influenced by global~~Global oil market ~~developments. All of these~~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 months of ~~2016~~2017 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 ~~$464,000~~$392,000 per month ($~~5.6~~4.7 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 months of ~~2016~~2017 was ~~$1.83~~$2.57 compared to ~~$2.80~~$1.83 for the first six months of ~~2015.~~2016. Based on our first six months of ~~2016~~2017 production, a $1.00 per barrel change in our oil price, without the effect of derivatives, would have a ~~$252,000~~$219,000 per month ($~~3.0~~2.6 million annualized) change in our pre-tax operating cash flow and a $1.00 per barrel change in our NGLs prices, without the effect of derivatives, would have a ~~$399,000~~$362,000 per month ($~~4.8~~4.3 million annualized) change in our pre-tax operating cash flow. In the first six months of ~~2016,~~2017, our average oil price per barrel received, including the effect of derivatives, was ~~$36.88~~$47.77 compared with an average oil price, including the effect of derivatives, of ~~$51.73~~$36.88 in the first six months

of ~~2015~~2016 and our first six months of ~~2016~~2017 average NGLs price per barrel received was ~~$8.90~~$16.34 compared with an average NGLs price per barrel of ~~$10.37~~$8.90 in the first six months of ~~2015.~~2016.

Because commodity prices affect the value of our oil, NGLs, and natural gas reserves, declines in those prices can cause a decline in the carrying value of our oil and natural gas properties. Price declines can also adversely affect the semi-annual determination of the amount available for us to borrow under our credit agreement since that determination is based mainly on the value of our oil, NGLs, and natural gas reserves. A reduction could limit our ability to carry out our planned capital projects. In the first quarter of 2016, the unamortized cost of our oil and gas properties exceeded the ceiling of our proved oil, NGLs, and natural gas reserves. As a result, we recorded a non-cash ceiling test write down of $37.8 million pre-tax ($23.5 million, net of tax). During the second quarter of 2016, the 12-month average commodity prices decreased further, resulting in a non-cash ceiling test write-down of $74.3 million pre-tax ($46.3 million, net of tax). At June 30, ~~2016,~~2017, the 12-month average unescalated prices were ~~$43.12~~$48.95 per barrel of oil, ~~$17.79~~$24.97 per barrel of NGLs, and ~~$2.24~~$3.01 per Mcf of natural gas, ~~then~~as adjusted for price differentials. We did not have to take a write down in the first six months 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 ~~factors and~~ inherent ~~limitations,~~uncertainties, if we hold these same factors constant as they existed ~~on July 1, 2016~~at June 30, 2017, and only ~~adjusted~~adjust the 12-month average price to an estimated ~~second~~third quarter ending average (holding July ~~2016~~2017 prices constant for the remaining two months of the third quarter of ~~2016)~~2017), our forward looking expectation is that we ~~would~~will not ~~expect to~~ recognize an impairment in the third quarter of ~~2016. Commodity~~2017. But commodity prices (and other factors) remain volatile and ~~have recently trended downward and should that trend continue it~~they could negatively ~~impact~~affect the 12-month average price ~~and~~resulting in the potential for an impairment in the ~~third quarter.~~

Given the uncertainty associated with the factors used in calculating our estimate of both our future period ceiling test write-down and the decrease in our undeveloped reserves, these estimates should not necessarily be construed as indicative of our future development plans or financial results.

Price declines can also adversely affect future semi-annual determinations of the amount we can borrow under our credit agreement since that determination is based mainly on the value of our oil, NGLs, and natural gas reserves. Such a reduction could limit our ability to carry out our planned capital projects. Under the third amendment to our credit agreement entered into on April 8, 2016, the lenders decreased our borrowing base from $550.0 million to $475.0 million. Our commitment under the credit agreement decreased from $500.0 million to $475.0 million.future.

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 in six month increments.

Contract Drilling Operations

Many factors influence the number of drilling rigs we are working ~~at any given time as well as~~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.

Our drilling rig personnel are a key component to the overall success of our drilling services; however, due to the present conditions existing in the drilling industry, we reduced the compensation paid to all drilling personnel in April 2016.

~~Almost all~~Most of our working drilling rigs ~~are~~were drilling horizontal or directional wells for oil and NGLs. The ~~continued low~~improved commodity ~~price environment~~pricing for oil and natural gas that began during the second half of 2016 has ~~changed~~increased demand for drilling rigs. These factors ultimately affect the demand and mix of the type of drilling rigs used by our ~~customers~~customers. The future demand for and the availability of drilling rigs to meet that demand ~~will have an impact on~~affect our future dayrates. For the first six months of ~~2016~~2017, our average dayrate was ~~$18,468~~$15,905 per day compared to ~~$20,032~~$18,468 per day for the first six months of ~~2015.~~2016. The average number of our drilling rigs used in the first six months of ~~2016~~2017 was ~~17.1~~27.2 drilling rigs compared with ~~40.4~~17.1 drilling rigs in the first six months of ~~2015.~~2016. Based on the average utilization of our drilling rigs during the first six months of ~~2016~~2017, a $100 per day change in dayrates has a ~~$1,710~~$2,720 per day ($~~0.6~~1.0 million annualized) change in our pre-tax operating cash flow.

Our contract drilling segment ~~also~~ provides drilling services for our ~~oil~~exploration and ~~natural gas~~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 ~~drilling~~ services are eliminated in our

statement of operations, with any profit recognized as a reduction in our investment in our oil and natural gas properties. The contracts for these services are issued under the same conditions and rates as the contracts entered into with unrelated third parties. We ~~did not eliminate any~~eliminated revenue ~~in our contract drilling segment~~of $5.6 million for the first six months of 2016 and the oil and gas segment did not use any of our rigs in the second quarter. Our oil and natural gas segment to incur the majority of its drilling capital expenditures in the latter part of the year thus allowing us to take into account future commodity price movement before those expenditures are incurred. For the first six months of 2015, we eliminated revenue of $15.7 million2017 from our contract drilling segment and eliminated the associated operating expense of ~~$12.2~~$5.2 million yielding ~~$3.5~~$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 months of 2016.

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, 1413 processing plants, 2625 gathering systems, and approximately ~~1,450~~1,470 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 months of ~~2016~~2017 and ~~2015~~2016, our mid-stream operations purchased ~~$16.4~~$27.3 million and ~~$33.0~~$16.4 million,, respectively, of our natural gas production and NGLs, and provided gathering and transportation services of ~~$5.1~~$3.2 million and ~~$3.8~~$5.1 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 Mcf per day in the first six months of 2017 compared to 411,671 Mcf per day in the first six months of 2016 ~~compared to~~ ~~348,666~~. It processed an average of 130,804 Mcf per day in the first six months of ~~2015. It processed an average of~~2017 compared to 164,333 Mcf per day in the first six months of ~~2016 compared to 187,592 Mcf~~2016. The amount of NGLs sold was 511,969 gallons per day in the first six months of ~~2015. The amount of NGLs sold was~~2017 compared to 525,824 gallons per day in the first six months of ~~2016 compared to 584,389 gallons per day in the first six months of 2015.~~2016. Gas ~~gathering~~gathered volumes per day in the first six months of ~~2016 increased 18%~~2017 decreased 6% compared to the first six months of ~~2015~~2016 primarily ~~from additional~~due to declines in existing volumes, fewer new wells ~~added to~~connected, and losing an offload volume at our ~~Pittsburgh Mills gathering system. Processed~~Hemphill facility in mid-2016. Gas processed volumes for the first six months of ~~2016~~2017 decreased ~~12%~~20% from the first six months of ~~2015~~2016 due to declines in existing volumes, fewer new wells connected to our processing systems, and losing an offload volume at our Hemphill facility in ~~our systems where we process gas combined with few replacement wells due to decreased drilling activity by operators in those areas.~~mid-2016. NGLs sold decreased ~~10%~~3% from the comparative period due to less volume available to process at our plants.

At-the-Market (ATM) Common Stock Program

On April 4, 2017, we entered into 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 $0.20 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 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 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 sold 787,547 shares of our common stock resulting in net proceeds of approximately $18.6 million.

Our Credit Agreement and Senior Subordinated Notes

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



Lender	Participation Interest
BOK (BOKF, NA, dba Bank of Oklahoma)	17	%
Compass Bank	17	%
BMO Harris Financing, Inc.	15	%
Bank of America, N.A.	15	%
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	%

At our election, any part of the outstanding debt under the credit agreement may be fixed at a London Interbank Offered Rate (LIBOR). LIBOR interest is computed as the ~~sum of the~~ LIBOR base for the ~~applicable~~ term plus 2.00% to 3.00% depending on the level of debt as a percentage of the borrowing base and is payable at the end of each term, or every 90 days, whichever is less. Borrowings not under LIBOR bear interest at the prime rate specified in the credit agreement that cannot be less than LIBOR plus 1.00%. Interest is payable at the end of each month and the principal may be repaid in whole or in part at any time, without a premium or penalty. At June 30, ~~2016~~2017 and July ~~22, 2016,~~21, 2017, borrowings were ~~$236.0~~$164.9 million and ~~$238.6~~$172.1 million, respectively.