Unit Corporation Reports 2016 Third Quarter Results

Unit Corporation (NYSE: UNT) today reported its financial and
operational results for the third quarter 2016. Third quarter and recent
highlights include:

To date, the contract drilling segment increased the number of
drilling rigs in service from a low of 13 to 20, a 54% increase.
Average drilling rig utilization increased 19% quarter over quarter.
Unit also was awarded a term contract for its ninth BOSS drilling rig,
with completion expected in January 2017.
After the quarter, the oil and natural gas segment put one drilling
rig back into service in the Southern Oklahoma Hoxbar Oil Trend
(SOHOT) play and is planning to put into service a second drilling rig
in the Granite Wash play later in the fourth quarter.
Midstream segment connected six new wells to its Pittsburgh Mills
gathering system in Butler County, Pennsylvania, increasing the
average daily throughput volume to approximately 151 million cubic
feet (MMcf) per day, a 6% increase over the second quarter of 2016.
Reduced long-term debt by $21 million from the end of the second
quarter, bringing the total year-to-date reduction to $64 million.
October redetermination of Unit’s borrowing base amount was maintained
at $475 million.

THIRD QUARTER AND FIRST NINE MONTHS 2016 FINANCIAL RESULTS

Unit recorded a net loss of $24.0 million for the quarter, or $0.48 per
share, compared to a net loss of $205.3 million, or $4.18 per share, for
the third quarter of 2015. For the third quarter of 2016 and 2015, Unit
incurred pre-tax non-cash ceiling test write-downs of $49.4 million and
$329.9 million, respectively, in the carrying value of its oil and
natural gas properties. These non-cash ceiling test write-downs resulted
from continued lower commodity prices. Adjusted net income (which
excludes the effect of non-cash commodity derivatives and the effect of
the non-cash write-down) for the quarter was $1.7 million, or $0.04 per
share (see Non-GAAP financial measures below). Total revenues were
$153.4 million (51% oil and natural gas, 17% contract drilling, and 32%
midstream), compared to $212.4 million (45% oil and natural gas, 31%
contract drilling, and 24% midstream) for the third quarter of 2015.
Adjusted EBITDA for the quarter was $67.3 million, or $1.33 per diluted
share (see Non-GAAP financial measures below).

For the first nine months of 2016, Unit recorded a net loss of $137.3
million, or $2.75 per share, compared to a net loss of $728.0 million,
or $14.83 per share, for the first nine months of 2015. Unit incurred
pre-tax non-cash ceiling test write-downs of $161.6 million and $1.1
billion in the carrying value of its oil and natural gas properties
during the first nine 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
$26.0 million, or $0.52 per share, for the first nine months of 2016
(see Non-GAAP financial measures below). Total revenues for the first
nine months were $427.9 million (48% oil and natural gas, 21% contract
drilling, and 31% midstream), compared to $681.9 million (45% oil and
natural gas, 32% contract drilling, and 23% midstream) for the first
nine months of 2015. Adjusted EBITDA for the first nine months was
$169.8 million, or $3.37 per diluted share (see Non-GAAP financial
measures below).

OIL AND NATURAL GAS SEGMENT INFORMATION

For the quarter, total production was 4.2 million barrels of oil
equivalent (MMBoe), a decrease of 17% from the third quarter of 2015 and
a 4% decrease from the second quarter of 2016. The decrease from the
second quarter of 2016 was due primarily to approximately 0.6 billion
cubic feet equivalent (Bcfe) of production in the Wilcox play being shut
in for six days during the third quarter because of maintenance on a
third-party operated processing plant. Liquids (oil and NGLs) production
represented 47% of total equivalent production. Oil production was 7,618
barrels per day, a decrease of 26% from the third quarter of 2015 and a
decrease of 8% from the second quarter of 2016. NGLs production was
13,698 barrels per day, a decrease of 6% from the third quarter of 2015
and a 4% increase over the second quarter of 2016. Natural gas
production was 145,642 thousand cubic feet (Mcf) per day, a decrease of
19% from the third quarter of 2015 and a decrease of 8% from the second
quarter of 2016. Total production for the first nine months of 2016 was
13.1 MMBoe.

Unit’s average realized per barrel equivalent price was $18.29, a
decrease of 11% from the third quarter of 2015 and a 12% increase over
the second quarter of 2016. Unit’s average natural gas price was $2.29
per Mcf, a decrease of 14% from the third quarter of 2015 and an
increase of 27% over the second quarter of 2016. Unit’s average oil
price was $42.79 per barrel, a decrease of 16% from the third quarter of
2015 and an increase of 3% over the second quarter of 2016. Unit’s
average NGLs price was $12.68 per barrel, a 45% increase over the third
quarter of 2015 and an increase of 11% over the second quarter of 2016.
All prices in this paragraph include the effects of derivative contracts.

In the SOHOT area, Unit’s production per day for the quarter decreased
from the second quarter of 2016 in line with its expectations, due to
natural decline rates and because no new wells were completed in the
third quarter. Unit was able to increase its leasehold in the core area
of the play by 2% during the third quarter to over 19,700 net acres. As
planned, the company added a Unit drilling rig in late October to drill
two horizontal Marchand oil wells within the SOHOT area in the fourth
quarter of this year. After drilling these two wells, the drilling rig
will be released for three to four months as performance of the two
wells is monitored before resuming drilling for the remainder of 2017.

In the Wilcox area, production for the third quarter of 2016 averaged 90
MMcfe per day, which is a 7% decrease as compared to the second quarter
of 2016. The decrease in quarter over quarter production was a result of
maintenance on a third-party operated processing plant which caused
production to be shut in for six days during the quarter. The processing
plant was back to full operational capability by early August, and
September production averaged 100 MMcfe per day. During the third
quarter, Unit completed six new behind pipe Wilcox recompletions and
three workovers, which resulted in natural gas and oil production from
these nine wells increasing from 1,300 Mcf per day to 15,400 Mcf per day
and 140 barrels of oil per day to 850 barrels of oil per day,
respectively, from the beginning of the quarter to the end of the
quarter.

In the Texas Panhandle, Unit’s Granite Wash play operational results for
the third quarter exceeded its expectations as production per day
increased 3% as compared to the prior quarter. The increase was due to
the Dixon extended lateral well continuing to outperform expectations as
well as production increases from several recompletions and workovers
that helped offset the natural decline of existing wells. In December,
the company will add a Unit drilling rig and initiate an extended
lateral Granite Wash drilling program in the Buffalo Wallow field.
Current plans are to run this drilling rig for all of 2017.

Larry Pinkston, Unit’s Chief Executive Officer and President, said: “Our
Wilcox vertical behind pipe recompletion activity continues to produce
strong results. In the Granite Wash, our extended lateral Dixon well is
outperforming our type curve. Following two quarters of no new drilling
activity, we recommenced our drilling program primarily in the SOHOT and
Granite Wash plays. We are continuing our plan of maintaining a capital
expenditure level within cash flow. While it is our intention to keep at
least a two drilling rig program going for the foreseeable future, such
action will be dependent on prevailing conditions.”

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

	Three Months Ended						Three Months Ended						Nine Months Ended
	Sept. 30, 2016		Sept. 30, 2015		Change		Sept. 30, 2016		June 30, 2016		Change		Sept. 30, 2016		Sept. 30, 2015		Change
Oil and NGLs Production, MBbl		1,961		2,289	(14	)%		1,961		1,950	1	%		6,005		6,950	(14	)%
Natural Gas Production, Bcf		13.4		16.6	(19	)%		13.4		14.5	(7	)%		42.4		49.6	(15	)%
Production, MBoe		4,194		5,053	(17	)%		4,194		4,359	(4	)%		13,068		15,225	(14	)%
Production, MBoe/day		45.6		54.9	(17	)%		45.6		47.9	(5	)%		47.7		55.8	(14	)%
Avg. Realized Natural Gas Price, Mcf ⁽¹⁾	$	2.29	$	2.66	14	%	$	2.29	$	1.80	27	%	$	1.98	$	2.76	(28	)%
Avg. Realized NGL Price, Bbl ⁽¹⁾	$	12.68	$	8.74	45	%	$	12.68	$	11.38	11	%	$	10.16	$	9.83	3	%
Avg. Realized Oil Price, Bbl ⁽¹⁾	$	42.79	$	50.87	16	%	$	42.79	$	41.52	3	%	$	38.71	$	51.46	(25	)%
Realized Price / Boe ⁽¹⁾	$	18.29	$	20.61	(11	)%	$	18.29	$	16.27	12	%	$	16.02	$	21.66	(26	)%
Operating Profit Before Depreciation, Depletion, & Amortization (MM) ⁽²⁾	$	52.8	$	57.9	(9	)%	$	52.8	$	35.9	47	%	$	113.6	$	180.1	(37	)%

(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
Oct’16 – Dec’16	Collar	3,450		$47.79		$54.52
Oct’16 – Dec’16	3-Way Collar	700		$46.50	$35.00	$57.00
Oct’16 – Dec’16	3-Way Collar ⁽¹⁾	700		$47.50	$35.00	$63.50
Jan’17 – Dec’17	3-Way Collar	3,750		$49.79	$39.58	$60.98

	Natural Gas
Period	Structure	Volume MMBtu/Day	Weighted Average Fixed Price	Weighted Average Floor Price	Weighted Average Subfloor Price	Weighted Average Ceiling Price
Oct’16 – Dec’16	Swap	45,000	$2.596
Jan’17 – Mar’17	Swap	10,000	$3.550
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)
Oct’16 – Dec’16	Collar	42,000		$2.40		$2.88
Jan’17 – Oct’17	Collar	20,000		$2.88		$3.10
Oct’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 16.0, a decrease of 49% from the third quarter of 2015 and an
increase of 19% over the second quarter of 2016. Per day drilling rig
rates averaged $17,479, a decrease of 7% from the third quarter of 2015
and a 6% decrease from the second quarter of 2016. For the first nine
months of 2016, per day drilling rig rates averaged $18,147, an 8%
decrease from the first nine months of 2015. Average per day operating
margin for the quarter was $4,546 (with no elimination of intercompany
drilling rig profit and bad debt expense). This compares to third
quarter 2015 average operating margin of $10,368 (before elimination of
intercompany drilling rig profit and bad debt expense of $0.2 million),
a decrease of 56%, or $5,822. Third quarter 2016 average operating
margin increased 7%, or $287, as compared to that of $4,259 for the
second 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 no
early termination fees from the cancellation of certain long-term
contracts, compared to early termination fees of $11.4 million, or
$3,958 per day, during the third quarter of 2015 and $0.4 million, or
$342 per day, for the second quarter of 2016.

Pinkston said: “Commodity prices continued to increase during the
quarter, and we have seen an uptick in operator inquiries to contract
drilling rigs, resulting in an increase in our average utilization rate
over the previous quarter. After the end of the quarter, we contracted
our remaining BOSS drilling rig, bringing all eight of our BOSS drilling
rigs under contract. Additionally, we were awarded a term contract for a
ninth BOSS drilling rig with construction expected to be completed in
January 2017. Our drilling rig fleet totals 94 drilling rigs, of which
20 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 nine of our drilling rigs. Of the nine, one is up for renewal
during the fourth quarter, seven in 2017 and one in 2018.”

This table illustrates certain comparative results for the periods
indicated:

	Three Months Ended						Three Months Ended						Nine Months Ended
	Sept. 30, 2016		Sept. 30, 2015		Change		Sept. 30, 2016		June 30, 2016		Change		Sept. 30, 2016		Sept. 30, 2015		Change
Rigs Utilized		16.0		31.2	(49	)%		16.0		13.5	19	%		16.7		37.3	(55	)%
Operating Profit Before Depreciation, Depletion, & Amortization (MM) ⁽¹⁾	$	6.7	$	29.5	(77	)%	$	6.7	$	5.0	34	%	$	22.3	$	91.4	(76	)%

(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.)

MIDSTREAM SEGMENT INFORMATION

For the quarter, per day gas gathered volumes increased 20%, while gas
processed and liquids sold volumes decreased 18% and 4%, respectively,
as compared to the third quarter of 2015. Compared to the second quarter
of 2016, liquids sold volumes per day increased 5%, while gas gathered
and gas processed volumes per day decreased 2% and 6%, respectively.
Operating profit (as defined in the footnote below) for the quarter was
$13.0 million, an increase of 25% over the third quarter of 2015 and an
increase of 4% over the second quarter of 2016.

For the first nine months of 2016, per day gas gathered volumes
increased 19%, while gas processed and liquids sold volumes per day
decreased 14% and 8%, respectively, as compared to the first nine months
of 2015. Operating profit (as defined in the footnote below) for the
first nine months of 2016 was $33.6 million, an increase of 6% over the
first nine months of 2015.

This table illustrates certain comparative results for the periods
indicated:

	Three Months Ended						Three Months Ended						Nine Months Ended
	Sept. 30, 2016		Sept. 30, 2015		Change		Sept. 30, 2016		June 30, 2016		Change		Sept. 30, 2016		Sept. 30, 2015		Change
Gas Gathering, Mcf/day		429,693		357,427	20	%		429,693		439,937	(2	)%		417,722		351,619	19	%
Gas Processing, Mcf/day		152,651		185,625	(18	)%		152,651		161,619	(6	)%		160,411		186,929	(14	)%
Liquids Sold, Gallons/day		558,843		579,556	(4	)%		558,843		532,215	5	%		536,911		582,760	(8	)%
Operating Profit Before Depreciation, Depletion, & Amortization (MM) ⁽¹⁾	$	13.0	$	10.4	25	%	$	13.0	$	12.5	4	%	$	33.6	$	31.8	6	%

(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 Marcellus, additional well connections to our
Pittsburgh Mills system in Butler County, Pennsylvania have increased
average daily throughput volume to approximately 151 MMcf per day, a 6%
increase over the second quarter of 2016. Due to low liquids prices, our
midstream segment remained in 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 $854.6 million (a
reduction of $20.5 million from the end of the second quarter and $64.4
million from the end of 2015). Long-term debt consisted of $639.6
million of senior subordinated notes net of unamortized discount and
debt issuance costs and $215.0 million of borrowings under its credit
agreement. Recently, Unit’s borrowing base was redetermined with no
change to availability. 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.

WEBCAST

Unit will webcast its third quarter earnings conference call live over
the Internet on November 3, 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						Nine Months Ended
	September 30,						September 30,
	2016			2015			2016			2015
Statement of Operations:
Revenues:
Oil and natural gas	$	78,854		$	96,619		$	206,318		$	309,944
Contract drilling		25,819			65,022			88,786			215,114
Gas gathering and processing		48,735			50,752			132,793			156,881
Total revenues		153,408			212,393			427,897			681,939
Expenses:
Oil and natural gas:
Operating costs		26,014			38,688			92,691			129,871
Depreciation, depletion, and amortization		27,135			57,159			89,378			202,378
Impairment of oil and natural gas properties		49,443			329,924			161,563			1,141,053
Contract drilling:
Operating costs		19,137			35,486			66,489			123,717
Depreciation		11,318			14,255			34,431			42,533
Impairment of contract drilling equipment		–			–			–			8,314
Gas gathering and processing:
Operating costs		35,738			40,314			99,185			125,081
Depreciation and amortization		11,436			10,976			34,410			32,518
General and administrative		8,932			7,643			26,029			26,637
(Gain) loss on disposition of assets		(154	)		7,230			(823	)		6,270
Total operating expenses		188,999			541,675			603,353			1,838,372

Loss from operations		(35,591	)		(329,282	)		(175,456	)		(1,156,433	)

Other income (expense):
Interest, net		(10,002	)		(8,286	)		(30,225	)		(23,482	)
Gain (loss) on derivatives		6,969			8,250			(4,774	)		12,917
Other		3			16			(11	)		38
Total other income (expense)		(3,030	)		(20	)		(35,010	)		(10,527	)

Loss before income taxes		(38,621	)		(329,302	)		(210,466	)		(1,166,960	)

Income tax expense (benefit):
Current		–			(2,584	)		–			(1,716	)
Deferred		(14,599	)		(121,437	)		(73,159	)		(437,220	)
Total income taxes		(14,599	)		(124,021	)		(73,159	)		(438,936	)

Net loss	$	(24,022	)	$	(205,281	)	$	(137,307	)	$	(728,024	)

Net loss per common share:
Basic	$	(0.48	)	$	(4.18	)	$	(2.75	)	$	(14.83	)
Diluted	$	(0.48	)	$	(4.18	)	$	(2.75	)	$	(14.83	)

Weighted average shares outstanding:
Basic		50,081			49,155			50,012			49,094
Diluted		50,081			49,155			50,012			49,094


	September 30,			December 31,
	2016			2015
Balance Sheet Data:
Current assets	$	93,646		$	140,258
Total assets	$	2,481,191		$	2,799,842
Current liabilities	$	135,988		$	150,891
Long-term debt	$	854,583		$	918,995
Other long-term liabilities and non-current derivative liability	$	103,922		$	140,626
Deferred income taxes	$	197,122		$	275,750
Shareholders’ equity	$	1,189,576		$	1,313,580


	Nine Months Ended September 30,
	2016			2015
Statement of Cash Flows Data:
Cash flow from operations before changes in operating assets and liabilities	$	134,138		$	303,719
Net change in operating assets and liabilities		63,624			77,763
Net cash provided by operating activities	$	197,762		$	381,482
Net cash used in investing activities	$	(107,509	)	$	(474,190	)
Net cash (used in) provided by financing activities	$	(90,175	)	$	92,553

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 nine months ended September 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						Nine Months Ended
	September 30,						September 30,
	2016			2015			2016			2015
	(In thousands except earnings per share)
Adjusted net income:
Net loss	$	(24,022	)	$	(205,281	)	$	(137,307	)	$	(728,024	)
Impairment (net of income tax)		30,778			205,378			100,573			715,481
(Gain) loss on derivatives (net of income tax)		(4,627	)		(5,272	)		3,115			(8,058	)
Settlements during the period of matured derivative contracts (net of income tax)		(381	)		6,837			7,656			20,060
Adjusted net income (loss)	$	1,748		$	1,662		$	(25,963	)	$	(541	)

Adjusted diluted earnings per share:
Diluted loss per share	$	(0.48	)	$	(4.18	)	$	(2.75	)	$	(14.83	)
Diluted earnings per share from impairments		0.61			4.18			2.01			14.57
Diluted earnings per share from (gain) loss on derivatives		(0.09	)		(0.11	)		0.06			(0.16	)
Diluted earnings (loss) per share from settlements of matured derivative contracts		–			0.14			0.16			0.41
Adjusted diluted income (loss) per share	$	0.04		$	0.03		$	(0.52	)	$	(0.01	)

________________

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									Nine Months Ended
	June 30,			September 30,						September 30,
	2016			2016			2015			2016			2015
	(In thousands)
Oil and natural gas	$	35,859		$	52,840		$	57,931		$	113,627		$	180,073
Contract drilling		5,003			6,682			29,536			22,297			91,397
Gas gathering and processing		12,477			12,997			10,438			33,608			31,800
Total operating profit		53,339			72,519			97,905			169,532			303,270
Depreciation, depletion and amortization		(52,844	)		(49,889	)		(82,390	)		(158,219	)		(277,429	)
Impairments		(74,291	)		(49,443	)		(329,924	)		(161,563	)		(1,149,367	)
Total operating loss		(73,796	)		(26,813	)		(314,409	)		(150,250	)		(1,123,526	)
General and administrative		(8,382	)		(8,932	)		(7,643	)		(26,029	)		(26,637	)
Gain (loss) on disposition of assets		477			154			(7,230	)		823			(6,270	)
Interest, net		(10,606	)		(10,002	)		(8,286	)		(30,225	)		(23,482	)
Gain (loss) on derivatives		(22,672	)		6,969			8,250			(4,774	)		12,917
Other		1			3			16			(11	)		38
Loss before income taxes	$	(114,978	)	$	(38,621	)	$	(329,302	)	$	(210,466	)	$	(1,166,960	)

________________

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						Nine Months Ended
	June 30,		September 30,				September 30,
	2016		2016		2015		2016		2015
	(In thousands except for operating days and operating margins)
Contract drilling revenue	$	24,257	$	25,819	$	65,022	$	88,786	$	215,114
Contract drilling operating cost		19,254		19,137		35,486		66,489		123,717
Operating profit from contract drilling		5,003		6,682		29,536		22,297		91,397
Add:
Elimination of intercompany rig profit and bad debt expense		235		–		219		235		3,666
Operating profit from contract drilling before elimination of intercompany rig profit and bad debt expense		5,238		6,682		29,755		22,532		95,063
Contract drilling operating days		1,230		1,470		2,870		4,578		10,175
Average daily operating margin before elimination of intercompany rig profit and bad debt expense	$	4,259	$	4,546	$	10,368	$	4,922	$	9,343

________________

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

	Nine Months Ended September 30,
	2016			2015
	(In thousands)
Net cash provided by operating activities	$	197,762		$	381,482
Net change in operating assets and liabilities		(63,624	)		(77,763	)
Cash flow from operations before changes in operating assets and liabilities	$	134,138		$	303,719

________________

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						Nine Months Ended
	September 30,						September 30,
	2016			2015			2016			2015
	(In thousands except earnings per share)

Net loss	$	(24,022	)	$	(205,281	)	$	(137,307	)	$	(728,024	)
Income taxes		(14,599	)		(124,021	)		(73,159	)		(438,936	)
Depreciation, depletion and amortization		50,501			83,163			160,023			279,739
Impairment		49,443			329,924			161,563			1,149,367
Interest expense		10,002			8,286			30,225			23,482
(Gain) loss on derivatives		(6,969	)		(8,250	)		4,774			(12,917	)
Settlements during the period of matured derivative contracts		(457	)		11,074			11,735			32,156
Stock compensation plans		2,961			185			10,664			12,514
Other non-cash items		634			843			2,147			2,629
Gain on disposition of assets		(154	)		7,230			(823	)		6,270
Adjusted EBITDA	$	67,340		$	103,153		$	169,842		$	326,280

Diluted loss per share	$	(0.48	)	$	(4.18	)	$	(2.75	)	$	(14.83	)
Diluted earnings per share from income taxes		(0.29	)		(2.52	)		(1.46	)		(8.94	)
Diluted earnings per share from depreciation, depletion and amortization		1.00			1.68			3.17			5.67
Diluted earnings per share from impairments		0.98			6.71			3.24			23.41
Diluted earnings per share from interest expense		0.20			0.17			0.60			0.48
Diluted earnings per share from (gain) loss on derivatives		(0.14	)		(0.17	)		0.09			(0.26	)
Diluted earnings per share from settlements during the period of matured derivative contracts		(0.01	)		0.23			0.25			0.66
Diluted earnings per share from stock compensation plans		0.06			–			0.21			0.25
Diluted earnings per share from other non-cash items		0.01			0.02			0.04			0.05
Diluted earnings per share from gain on disposition of assets		–			0.15			(0.02	)		0.13
Adjusted EBITDA per diluted share	$	1.33		$	2.09		$	3.37		$	6.62

________________

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/20161103005369/en/

Unit Corporation
Michael D. Earl, 918-493-7700
Vice President,
Investor Relations
www.unitcorp.com

Unit Corporation Reports 2016 Third Quarter Results

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