Unit Corporation Reports 2016 Second Quarter Results

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.

View source version on businesswire.com: http://www.businesswire.com/news/home/20160804005325/en/

Source: Business Wire
(August 4, 2016 - 8:00 AM EDT)

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