Exhibit

EX-99.1 2 a2q16991pressrelease.htm PRESS RELEASE Exhibit



News	UNIT CORPORATION
	8200 South Unit Drive, Tulsa, Oklahoma 74132
	Telephone 918 493-7700, Fax 918 493-7714



Contact:	Michael D. Earl
	Vice President, Investor Relations
	(918) 493-7700
	www.unitcorp.com

For Immediate Release…

August 4, 2016

UNIT CORPORATION REPORTS 2016 SECOND QUARTER RESULTS

Tulsa, Oklahoma . . . Unit Corporation (NYSE - UNT) today reported its financial and operational results for the second quarter 2016. Highlights include:


•	Record production of approximately 97 million cubic feet equivalent (MMcfe) per day in its Wilcox play, representing a 25% increase over the second quarter of 2015 and a 9% increase over the first quarter of 2016.


•	Seven of its eight BOSS drilling rigs currently operating under contract, compared to six during the first quarter of 2016.


•	Midstream segment's gas gathered and liquids sold volumes per day increased 15% and 2%, respectively, compared to the first quarter of 2016.


•	Midstream segment connected additional well pads to its Pittsburgh Mills gathering system in Butler County, Pennsylvania and its new Snow Shoe gathering system in Centre County, Pennsylvania.

SECOND QUARTER AND FIRST SIX MONTHS 2016 FINANCIAL RESULTS

Unit recorded a net loss of $72.1 million for the quarter, or $1.44 per share, compared to a net loss of $274.4 million, or $5.58 per share, for the second quarter of 2015. For the second quarter of 2016 and 2015, Unit incurred pre-tax non-cash ceiling test write-downs of $74.3 million and $410.5 million, respectively, in the carrying value of its oil and natural gas properties. These non-cash ceiling test write-downs have resulted from continued lower commodity prices. Adjusted net loss (which excludes the effect of non-cash commodity derivatives and the effect of the non-cash write-down) for the quarter was $7.4 million, or $0.15 per share (see Non-GAAP financial measures below). Total revenues were $138.3 million (50% oil and natural gas, 18% contract drilling, and 32% mid-stream), compared to $214.4 million (50% oil and natural gas, 26% contract drilling, and 24% mid-stream) for the second quarter of 2015. Adjusted EBITDA was $54.1 million, or $1.07 per diluted share (see Non-GAAP financial measures below).

For the first six months of 2016, Unit recorded a net loss of $113.3 million, or $2.27 per share, compared to a net loss of $522.7 million, or $10.66 per share, for the first six months of 2015. Unit incurred pre-tax non-cash ceiling test write-downs of $112.1 million and $811.1 million in the carrying value of its oil and natural gas properties during the first six months of 2016 and 2015, respectively. Unit recorded an adjusted net loss (which excludes the effect of non-cash commodity derivatives and the effect of the non-cash write-down) of $27.7 million, or $0.55 per share (see Non-GAAP financial measures below). Total revenues for the first six months were $274.5 million (46% oil and natural gas, 23% contract drilling, and 31% mid-stream), compared to $469.5 million (45% oil and natural gas, 32% contract drilling, and 23% mid-stream) for the first six months of 2015. Adjusted EBITDA for the first six months was $102.5 million, or $2.04 per diluted share (see Non-GAAP financial measures below).

OIL AND NATURAL GAS SEGMENT INFORMATION

For the quarter, total production was 4.4 million barrels of oil equivalent (MMBoe), a decrease of 14% from the second quarter of 2015 and a 3% decrease from the first quarter of 2016. The decrease in production resulted primarily from Unit's previous decision to reduce its new well drilling plans because of low commodity prices. Liquids (oil and NGLs) production represented 45% of total equivalent production. Oil production was 8,309 barrels per day, a decrease of 20% from the second quarter of 2015 and a decrease of 6% from the first quarter of 2016. NGLs production was 13,120 barrels per day, a decrease of 10% from the second quarter of 2015 and an 8% decrease from the first quarter of 2016. Natural gas production was 158,844 thousand cubic feet (Mcf) per day, a decrease of 13% from the second quarter of 2015 and essentially flat with the first quarter of 2016. Total production for the first six months of 2016 was 8.9 MMBoe.

Unit’s average realized per barrel equivalent price was $16.27, a decrease of 27% from the second quarter of 2015 and a 19% increase over the first quarter of 2016. Unit’s average natural gas price was $1.80 per Mcf, a decrease of 33% from the second quarter of 2015 and a decrease of 4% from the first quarter of 2016. Unit’s average oil price was $41.52 per barrel, a decrease of 25% from the second quarter of 2015 and an increase of 28% over the first quarter of 2016. Unit’s average NGLs price was $11.38 per barrel, a 6% decrease from the second quarter of 2015 and an increase of 73% over the first quarter of 2016. All prices in this paragraph include the effects of derivative contracts.

For the quarter, Unit achieved record production of approximately 97 MMcfe per day from its Wilcox play, representing a 25% increase over the second quarter of 2015 and a 9% increase over the first quarter of 2016. This production growth is attributed to first oil and natural gas sales from new horizontal wells and behind pipe recompletions that occurred primarily in the first quarter of 2016. Through the end of the second quarter, the company completed new behind pipe Wilcox intervals in four existing wells that are producing 17 MMcfe per day. These same four wells were producing approximately 700 Mcfe per day before the recompletions. Unit anticipates recompleting approximately four to six new behind pipe zones during the second half of the year.

In the Southern Oklahoma Hoxbar Oil Trend (SOHOT), Unit completed one new well during the quarter with an average 30 day IP rate of approximately 720 barrels of oil equivalent (Boe) per day. Unit anticipates resuming drilling Marchand oil wells during the fourth quarter, using a Unit drilling rig.

In the Buffalo Wallow field in the Granite Wash play, a horizontal “C1” well was completed with an extended lateral of approximately 7,500 feet. The well, which is Unit's first extended lateral drilled in this field, is currently producing approximately 12.1 MMcfe per day consisting of 43% natural gas, 15% oil, and 42% NGLs. Unit anticipates beginning a one or two drilling rig extended lateral development program in the Buffalo Wallow field late in the fourth quarter of 2016 or early 2017.

Larry Pinkston, Unit’s Chief Executive Officer and President, said: “We are pleased with the results of the wells that were completed during the first half of the year as well as the results of our behind pipe recompletions. We continue to increase our leasehold in our core areas and identify additional potential drilling locations. Depending on commodity prices, our plan will be to resume our drilling program in the latter part of the year."

This table illustrates certain comparative production, realized prices, and operating profit for the periods indicated:



	Three Months Ended					Three Months Ended					Six Months Ended
	June 30, 2016		June 30, 2015		Change	June 30, 2016		Mar. 31, 2016		Change	June 30, 2016		June 30, 2015		Change
Oil and NGLs Production, MBbl	1,950		2,277		(14)%	1,950		2,094		(7)%	4,044		4,661		(13)%
Natural Gas Production, Bcf	14.5		16.7		(13)%	14.5		14.5		—%	29.0		33.1		(12)%
Production, MBoe	4,359		5,054		(14)%	4,359		4,514		(3)%	8,873		10,171		(13)%
Production, MBoe/day	47.9		55.5		(14)%	47.9		49.6		(3)%	48.8		56.2		(13)%
Avg. Realized Natural Gas Price, Mcf ⁽¹⁾	$	1.80	$	2.67	(33)%	$	1.80	$	1.87	(4)%	$	1.83	$	2.80	(35)%
Avg. Realized NGL Price, Bbl ⁽¹⁾	$	11.38	$	12.05	(6)%	$	11.38	$	6.59	73%	$	8.90	$	10.37	(14)%
Avg. Realized Oil Price, Bbl ⁽¹⁾	$	41.52	$	55.52	(25)%	$	41.52	$	32.50	28%	$	36.88	$	51.73	(29)%
Realized Price / Boe ⁽¹⁾	$	16.27	$	22.38	(27)%	$	16.27	$	13.67	19%	$	14.95	$	22.18	(33)%
Operating Profit Before Depreciation, Depletion, & Amortization (MM) ⁽²⁾	$	35.9	$	61.3	(42)%	$	35.9	$	24.9	44%	$	60.8	$	122.1	(50)%


(1)	Realized price includes oil, natural gas liquids, natural gas, and associated derivatives.


(2)	Operating profit before depreciation is calculated by taking operating revenues for this segment less operating expenses excluding depreciation, depletion, amortization, and impairment. (See non-GAAP financial measures below.)

This table summarizes the outstanding derivative contracts.



	Crude
Period	Structure	Volume Bbl/Day	Weighted Average Fixed Price	Weighted Average Floor Price	Weighted Average Subfloor Price	Weighted Average Ceiling Price
Jul'16 - Sep'16	Swap	1,000	$48.45
Jul'16 - Sep'16	Collar	2,450		$44.44		$52.46
Oct'16 - Dec'16	Collar	1,450		$47.50		$56.40
Jul'16 - Dec'16	3-Way Collar	700		$46.50	$35.00	$57.00
Jul'16 - Dec'16	3-Way Collar ⁽¹⁾	700		$47.50	$35.00	$63.50
Jan'17 - Dec'17	3-Way Collar	750		$50.00	$37.50	$63.90
	Natural Gas
Period	Structure	Volume MMBtu/Day	Weighted Average Fixed Price	Weighted Average Floor Price	Weighted Average Subfloor Price	Weighted Average Ceiling Price
Jul'16 - Dec'16	Swap	45,000	$2.596
Jan'17 - Dec'17	Swap	60,000	$2.960
Jan'18 - Dec'18	Swap	10,000	$3.025
Jan'17 - Dec'17	Basis Swap	20,000	$(0.215)
Jan'18 - Dec'18	Basis Swap	10,000	$(0.208)
Jul'16 - Dec'16	Collar	42,000		$2.40		$2.88
Jan-17 - Oct'17	Collar	20,000		$2.88		$3.10
Jul'16 - Dec'16	3-Way Collar	13,500		$2.70	$2.20	$3.26
Jan'17 - Dec'17	3-Way Collar	15,000		$2.50	$2.00	$3.32


(1)	Unit pays its counterparty a premium, which can be and is being deferred until settlement.

CONTRACT DRILLING SEGMENT INFORMATION

The average number of Unit's drilling rigs working during the quarter was 13.5, a decrease of 56% from the second quarter of 2015 and a decrease of 34% from the first quarter of 2016. Per day drilling rig rates averaged $18,585, a decrease of 7% from the second quarter of 2015 and a 1% increase over the first quarter of 2016. For the first six months of 2016, per day

drilling rig rates averaged $18,468, an 8% decrease from the first six months of 2015. Average per day operating margin for the quarter was $4,259 (before elimination of intercompany drilling rig profit and bad debt expense of $0.2 million). This compares to second quarter 2015 average operating margin of $6,821 (before elimination of intercompany drilling rig profit and bad debt expense of $0.5 million), a decrease of 38%, or $2,562. Second quarter 2016 average operating margin decreased 25%, or $1,392, as compared to that of $5,651 for the first quarter of 2016 (in each case regarding eliminating intercompany drilling rig profit and bad debt expense - see Non-GAAP financial measures below). Average operating margins for the quarter included early termination fees of approximately $0.4 million, or $342 per day, from the cancellation of certain long-term contracts, compared to early termination fees of $1.6 million, or $594 per day, during the second quarter of 2015 and $2.6 million, or $1,410 per day, for the first quarter of 2016.

Pinkston said: “Although we saw a slight increase in commodity prices during the quarter, operators remain cautious about contracting new drilling rigs, resulting in our average utilization rate continuing to fall quarter over quarter. Currently, we have seven of our eight BOSS drilling rigs under contract. Our drilling rig fleet totals 94 drilling rigs, of which 16 are working under contract after rebounding from a low of 13 drilling rigs during the second quarter. Long-term contracts (contracts with original terms ranging from six months to two years in length) are in place for five of our drilling rigs. Of the five, one is up for renewal during the fourth quarter, and four in 2017.”

This table illustrates certain comparative results for the periods indicated:



	Three Months Ended					Three Months Ended					Six Months Ended
	June 30, 2016		June 30, 2015		Change	June 30, 2016		Mar. 31, 2016		Change	June 30, 2016		June 30, 2015		Change
Rigs Utilized	13.5		30.7		(56)%	13.5		20.6		(34)%	17.1		40.4		(58)%
Operating Profit Before Depreciation, Depletion, & Amortization (MM) ⁽¹⁾	$	5.0	$	18.5	(73)%	$	5.0	$	10.6	(53)%	$	15.6	$	61.9	(75)%


(1)	Operating profit before depreciation is calculated by taking operating revenues for this segment less operating expenses excluding depreciation and impairment. (See non-GAAP financial measures below.)

MID-STREAM SEGMENT INFORMATION

For the quarter, per day gas gathered volumes increased 21%, while gas processed and liquids sold volumes decreased 13% and 11%, respectively, as compared to the second quarter of 2015. Compared to the first quarter of 2016, gas gathered and liquids sold volumes per day increased 15% and 2%, respectively, while gas processed volumes per day decreased 3%. Operating profit (as defined in the footnote below) for the quarter was $12.5 million, an increase of 8% over the second quarter of 2015 and an increase of 53% over the first quarter of 2016.

For the first six months of 2016, per day gas gathered volumes increased 18%, while gas processed and liquids sold volumes per day decreased 12% and 10%, respectively, as compared to the first six months of 2015. Operating profit (as defined in the footnote below) for the first six months of 2016 was $20.6 million, a decrease of 4% from the first six months of 2015.

This table illustrates certain comparative results for the periods indicated:



	Three Months Ended					Three Months Ended					Six Months Ended
	June 30, 2016		June 30, 2015		Change	June 30, 2016		Mar. 31, 2016		Change	June 30, 2016		June 30, 2015		Change
Gas Gathering, Mcf/day	439,937		362,896		21%	439,937		383,405		15%	411,671		348,666		18%
Gas Processing, Mcf/day	161,619		186,041		(13)%	161,619		167,048		(3)%	164,333		187,592		(12)%
Liquids Sold, Gallons/day	532,215		599,732		(11)%	532,215		519,433		2%	525,824		584,389		(10)%
Operating Profit Before Depreciation, Depletion, & Amortization (MM) ⁽¹⁾	$	12.5	$	11.6	8%	$	12.5	$	8.1	53%	$	20.6	$	21.4	(4)%


(1)	Operating profit before depreciation is calculated by taking operating revenues for this segment less operating expenses excluding depreciation, amortization, and impairment. (See non-GAAP financial measures below.)

Pinkston said: “In the Wilcox in southeast Texas, our Segno system connected three new wells since the beginning of 2016. The Segno system's average daily gathered volume increased nearly 7% quarter over quarter to more than 90 MMcf per day. In the Marcellus, we connected an additional well pad during the quarter which included two new wells to our Pittsburgh Mills system in Butler County, Pennsylvania. This connection increased average daily gathered volume to 142 MMcf per day, a 54% increase over the first quarter of 2016. We connected a new well pad with three wells to our new Snow Shoe system in Centre County, Pennsylvania. Gathered volumes for this facility continue to increase, averaging 14 MMcf per day in the second quarter. Due to low liquids prices, our midstream segment remained in full ethane rejection mode for most of the quarter at our various gas processing facilities in the Mid-Continent.”

FINANCIAL INFORMATION

Unit ended the quarter with long-term debt of $875.1 million (a reduction of $23.6 million from the end of the first quarter), consisting of $639.1 million of senior subordinated notes net of unamortized discount and debt issuance costs and $236.0 million of borrowings under its credit agreement. Under the credit agreement, the amount Unit can borrow is the lesser of the amount it elects as the commitment amount ($475 million) or the value of its borrowing base as determined by the lenders ($475 million), but in either event not to exceed $875 million. The credit agreement was amended during the quarter to provide, in part, for a borrowing base of $475 million.

WEBCAST

Unit will webcast its second quarter earnings conference call live over the Internet on August 4, 2016 at 10:00 a.m. Central Time (11:00 a.m. Eastern). To listen to the live call, please go to http://www.unitcorp.com/investor/calendar.htm at least fifteen minutes prior to the start of the call to download and install any necessary audio software. For those who are not available to listen to the live webcast, a replay will be available shortly after the call and will remain on the site for 90 days.

_____________________________________________________

Unit Corporation is a Tulsa-based, publicly held energy company engaged through its subsidiaries in oil and gas exploration, production, contract drilling, and gas gathering and processing. Unit’s Common Stock is on the New York Stock Exchange under the symbol UNT. For more information about Unit Corporation, visit its website at http://www.unitcorp.com.

FORWARD-LOOKING STATEMENT

This news release contains forward-looking statements within the meaning of the private Securities Litigation Reform Act. All statements, other than statements of historical facts, included in this release that address activities, events, or developments that the Company expects, believes, or anticipates will or may occur in the future are forward-looking statements. Several risks and uncertainties could cause actual results to differ materially from these statements, including changes in commodity prices, the productive capabilities of the Company’s wells, future demand for oil and natural gas, future drilling rig utilization and dayrates, projected rate of the Company’s oil and natural gas production, the amount available to the Company for borrowings, its anticipated borrowing needs under its credit agreement, the number of wells to be drilled by the Company’s oil and natural gas segment, and other factors described from time to time in the Company’s publicly available SEC reports. The Company assumes no obligation to update publicly such forward-looking statements, whether because of new information, future events, or otherwise.

Unit Corporation

Selected Financial Highlights

(In thousands except per share amounts)



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2016			2015			2016			2015
Statement of Operations:
Revenues:
Oil and natural gas	$	69,190		$	107,256		$	127,464		$	213,325
Contract drilling	24,257			55,015			62,967			150,092
Gas gathering and processing	44,858			52,176			84,058			106,129
Total revenues	138,305			214,447			274,489			469,546
Expenses:
Oil and natural gas:
Operating costs	33,331			45,972			66,677			91,183
Depreciation, depletion, and amortization	30,411			68,101			62,243			145,219
Impairment of oil and natural gas properties	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	—			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
General and administrative	8,382			9,624			17,097			18,994
Gain on disposition of assets	(477		)	(415		)	(669		)	(960		)
Total operating expenses	220,006			643,322			414,354			1,296,697

Loss from operations	(81,701		)	(428,875		)	(139,865		)	(827,151		)

Other income (expense):
Interest, net	(10,606		)	(7,956		)	(20,223		)	(15,196		)
Gain (loss) on derivatives	(22,672		)	(1,919		)	(11,743		)	4,667
Other	1			24			(14		)	22
Total other income (expense)	(33,277		)	(9,851		)	(31,980		)	(10,507		)

Loss before income taxes	(114,978		)	(438,726		)	(171,845		)	(837,658		)

Income tax expense (benefit):
Current	—			803			—			868
Deferred	(42,842		)	(165,140		)	(58,560		)	(315,783		)
Total income taxes	(42,842		)	(164,337		)	(58,560		)	(314,915		)

Net loss	$	(72,136	)	$	(274,389	)	$	(113,285	)	$	(522,743	)

Net loss per common share:
Basic	$	(1.44	)	$	(5.58	)	$	(2.27	)	$	(10.66	)
Diluted	$	(1.44	)	$	(5.58	)	$	(2.27	)	$	(10.66	)

Weighted average shares outstanding:
Basic	50,074			49,148			49,977			49,063
Diluted	50,074			49,148			49,977			49,063



	June 30,		December 31,
	2016		2015
Balance Sheet Data:
Current assets	$	89,294	$	140,258
Total assets	$	2,552,096	$	2,799,842
Current liabilities	$	146,757	$	150,891
Long-term debt	$	875,051	$	918,995
Other long-term liabilities	$	103,926	$	140,341
Deferred income taxes	$	211,721	$	275,750
Shareholders’ equity	$	1,211,221	$	1,313,580



	Six Months Ended June 30,
	2016			2015
Statement of Cash Flows Data:
Cash flow from operations before changes in operating assets and liabilities	$	77,734		$	207,221
Net change in operating assets and liabilities	54,982			50,385
Net cash provided by operating activities	$	132,716		$	257,606
Net cash used in investing activities	$	(77,386	)	$	(366,442	)
Net cash (used in) provided by financing activities	$	(55,191	)	$	108,626

Non-GAAP Financial Measures

Unit Corporation reports its financial results in accordance with generally accepted accounting principles (“GAAP”). The Company believes certain non-GAAP measures provide users of its financial information and its management additional meaningful information to evaluate the performance of the company.

This press release includes net income (loss) and earnings (loss) per share excluding impairment adjustments and the effect of the cash settled commodity derivatives, its reconciliation of segment operating profit, its drilling segment’s average daily operating margin before elimination of intercompany drilling rig profit and bad debt expense, its cash flow from operations before changes in operating assets and liabilities, and its reconciliation of net income (loss) to adjusted EBITDA.

Below is a reconciliation of GAAP financial measures to non-GAAP financial measures for the three and six months ended June 30, 2016 and 2015. Non-GAAP financial measures should not be considered by themselves or a substitute for results reported in accordance with GAAP. This non-GAAP information should be considered by the reader in addition to, but not instead of, the financial statements prepared in accordance with GAAP. The non-GAAP financial information presented may be determined or calculated differently by other companies and may not be comparable to similarly titled measures.

Unit Corporation

Reconciliation of Adjusted Net Income and Adjusted Diluted Earnings per Share



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2016			2015			2016			2015
	(In thousands except earnings per share)
Adjusted net income:
Net loss	$	(72,136	)	$	(274,389	)	$	(113,285	)	$	(522,743	)
Impairment (net of income tax)	46,246			260,734			69,795			510,103
(Gain) loss on derivatives not designated as hedges (net of income tax)	15,650			1,238			7,742			(2,786		)
Settlements during the period of matured derivative contracts (net of income tax)	2,870			6,495			8,037			13,223
Adjusted net loss	$	(7,370	)	$	(5,922	)	$	(27,711	)	$	(2,203	)

Adjusted diluted earnings per share:
Diluted loss per share	$	(1.44	)	$	(5.58	)	$	(2.27	)	$	(10.66	)
Diluted earnings per share from impairments	0.92			5.31			1.40			10.40
Diluted earnings per share from (gain) loss on derivatives	0.31			0.02			0.16			(0.06		)
Diluted earnings (loss) per share from settlements of matured derivative contracts	0.06			0.13			0.16			0.27
Adjusted diluted loss per share	$	(0.15	)	$	(0.12	)	$	(0.55	)	$	(0.05	)

________________

The Company has included the net income and diluted earnings per share including only the cash settled commodity derivatives because:


•	It uses the adjusted net income to evaluate the operational performance of the company.


•	The adjusted net income is more comparable to earnings estimates provided by securities analysts.

Unit Corporation

Reconciliation of Segment Operating Profit



	Three Months Ended									Six Months Ended
	March 31,			June 30,						June 30,
	2016			2016			2015			2016			2015
	(In thousands)
Oil and natural gas	$	24,928		$	35,859		$	61,284		$	60,787		$	122,142
Contract drilling	10,612			5,003			18,530			15,615			61,861
Gas gathering and processing	8,134			12,477			11,584			20,611			21,362
Total operating profit	43,674			53,339			91,398			97,013			205,365
Depreciation, depletion and amortization	(55,486		)	(52,844		)	(92,214		)	(108,330		)	(195,039		)
Impairments	(37,829		)	(74,291		)	(418,850		)	(112,120		)	(819,443		)
Total operating loss	(49,641		)	(73,796		)	(419,666		)	(123,437		)	(809,117		)
General and administrative	(8,715		)	(8,382		)	(9,624		)	(17,097		)	(18,994		)
Gain on disposition of assets	192			477			415			669			960
Interest, net	(9,617		)	(10,606		)	(7,956		)	(20,223		)	(15,196		)
Gain (loss) on derivatives	10,929			(22,672		)	(1,919		)	(11,743		)	4,667
Other	(15		)	1			24			(14		)	22
Loss before income taxes	$	(56,867	)	$	(114,978	)	$	(438,726	)	$	(171,845	)	$	(837,658	)

________________

The Company has included segment operating profit because:


•	It considers segment operating profit to be an important supplemental measure of operating performance for presenting trends in its core businesses.


•	Segment operating profit is useful to investors because it provides a means to evaluate the operating performance of the segments and Company on an ongoing basis using criteria that is used by management.

Unit Corporation

Reconciliation of Average Daily Operating Margin Before Elimination of Intercompany Rig Profit and Bad Debt Expense



	Three Months Ended						Six Months Ended
	March 31,		June 30,				June 30,
	2016		2016		2015		2016		2015
	(In thousands except for operating days and operating margins)
Contract drilling revenue	$	38,710	$	24,257	$	55,015	$	62,967	$	150,092
Contract drilling operating cost	28,098		19,254		36,485		47,352		88,231
Operating profit from contract drilling	10,612		5,003		18,530		15,615		61,861
Add:
Elimination of intercompany rig profit and bad debt expense	—		235		537		235		3,447
Operating profit from contract drilling before elimination of intercompany rig profit and bad debt expense	10,612		5,238		19,067		15,850		65,308
Contract drilling operating days	1,878		1,230		2,795		3,108		7,305
Average daily operating margin before elimination of intercompany rig profit and bad debt expense	$	5,651	$	4,259	$	6,821	$	5,100	$	8,940

________________

The Company has included the average daily operating margin before elimination of intercompany rig profit and bad debt expense because:


•	Its management uses the measurement to evaluate the cash flow performance of its contract drilling segment and to evaluate the performance of contract drilling management.


•	It is used by investors and financial analysts to evaluate the performance of the company.

Unit Corporation

Reconciliation of Cash Flow From Operations Before Changes in Operating Assets and Liabilities



	Six Months Ended June 30,
	2016			2015
	(In thousands)
Net cash provided by operating activities	$	132,716		$	257,606
Net change in operating assets and liabilities	(54,982		)	(50,385		)
Cash flow from operations before changes in operating assets and liabilities	$	77,734		$	207,221

________________

The Company has included the cash flow from operations before changes in operating assets and liabilities because:


•	It is an accepted financial indicator used by its management and companies in the industry to measure the company’s ability to generate cash which is used to internally fund its business activities.


•	It is used by investors and financial analysts to evaluate the performance of the company.

Unit Corporation

Reconciliation of Adjusted EBITDA and Adjusted EBITDA per Diluted Share



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2016			2015			2016			2015
	(In thousands except earnings per share)

Net loss	$	(72,136	)	$	(274,389	)	$	(113,285	)	$	(522,743	)
Income taxes	(42,842		)	(164,337		)	(58,560		)	(314,915		)
Depreciation, depletion and amortization	53,406			92,986			109,522			196,576
Impairment	74,291			418,850			112,120			819,443
Interest expense	10,606			7,956			20,223			15,196
(Gain) loss on derivatives	22,672			1,919			11,743			(4,667		)
Settlements during the period of matured derivative contracts	5,052			10,070			12,192			21,082
Stock compensation plans	2,905			6,466			7,703			12,329
Other non-cash items	634			825			1,513			1,786
Gain on disposition of assets	(477		)	(415		)	(669		)	(960		)
Adjusted EBITDA	$	54,111		$	99,931		$	102,502		$	223,127

Diluted loss per share	$	(1.44	)	$	(5.58	)	$	(2.27	)	$	(10.66	)
Diluted earnings per share from income taxes	(0.86		)	(3.34		)	(1.17		)	(6.42		)
Diluted earnings per share from depreciation, depletion and amortization	1.06			1.88			2.18			3.99
Diluted earnings per share from impairments	1.49			8.52			2.25			16.71
Diluted earnings per share from interest expense	0.21			0.16			0.40			0.31
Diluted earnings per share from (gain) loss on derivatives	0.45			0.04			0.23			(0.09		)
Diluted earnings per share from settlements during the period of matured derivative contracts	0.10			0.20			0.25			0.42
Diluted earnings per share from stock compensation plans	0.06			0.13			0.15			0.25
Diluted earnings per share from other non-cash items	0.01			0.02			0.03			0.04
Diluted earnings per share from gain on disposition of assets	(0.01		)	(0.01		)	(0.01		)	(0.02		)
Adjusted EBITDA per diluted share	$	1.07		$	2.02		$	2.04		$	4.53

________________

The Company has included the adjusted EBITDA excluding gain or loss on disposition of assets and including only the cash settled commodity derivatives because:


•	It uses the adjusted EBITDA to evaluate the operational performance of the Company.


•	The adjusted EBITDA is more comparable to estimates provided by securities analysts.


•	It provides a means to assess the ability of the Company to generate cash sufficient to pay interest on its indebtedness.