Unit Corporation Reports 2015 Second Quarter Results

Unit Corporation (NYSE: UNT) today reported its financial and
operational results for the second quarter of 2015. Highlights for the
quarter include:

Total production of 5.1 million barrels of oil equivalent (MMBoe), a
9% increase over the second quarter of 2014
Oil and natural gas liquids (NGLs) production increased 8% over the
second quarter of 2014
Placed three BOSS drilling rigs into service during the quarter
Gas gathered and gas processed volumes per day increased 11% and 15%,
respectively, over the second quarter of 2014

SECOND QUARTER AND FIRST SIX MONTHS 2015 RESULTS

Because of significantly lower commodity prices, Unit’s second quarter
of 2015 results include the following pre-tax non-cash write downs:
$410.5 million ceiling test write down in the carrying value of the
company’s oil and natural gas properties and an $8.3 million pre-tax
write down for the decline in the carrying value of certain drilling
rigs and other assets removed from service. As a result, Unit recorded a
net loss of $274.4 million, or $5.58 per share, compared to net income
of $54.4 million, or $1.11 per diluted share, for the second quarter of
2014. Adjusted net loss for the quarter (which excludes the effect of
non-cash commodity derivatives and the effects of the write-downs) was
$5.9 million, or $0.12 per diluted share (see Non-GAAP Financial
Measures below). Total revenues for the quarter were $214.4 million (50%
oil and natural gas, 26% contract drilling, and 24% mid-stream),
compared to $405.4 million (49% oil and natural gas, 28% contract
drilling, and 23% mid-stream) for the second quarter of 2014.

For the first six months of 2015, Unit recorded an $811.1 million
pre-tax non-cash ceiling test write down in the carrying value of the
company’s oil and natural gas properties and an $8.3 million pre-tax
write down for the drilling rigs and other assets discussed above. As a
result, Unit recorded a net loss of $522.7 million, or $10.66 per share,
compared to net income of $111.3 million, or $2.27 per diluted share,
for the first six months of 2014. Adjusted net loss for the first six
months (which excludes the effect of non-cash commodity derivatives and
the effects of the write-downs) was $2.2 million, or $0.05 per diluted
share (see Non-GAAP Financial Measures below). Total revenues for the
first six months were $469.5 million (45% oil and natural gas, 32%
contract drilling, and 23% mid-stream), compared to $793.4 million (49%
oil and natural gas, 28% contract drilling, and 23% mid-stream) for the
first six months of 2014.

OIL AND NATURAL GAS SEGMENT INFORMATION

Total equivalent production for the quarter was 5.1 million barrels of
oil equivalent (MMBoe), an increase of 9% over the second quarter of
2014 and a 1% decrease from the first quarter of 2015. Liquids (oil and
NGLs) production represented 45% of total equivalent production for the
quarter. Oil production for the quarter was 10,418 barrels per day,
essentially unchanged from the second quarter of 2014 and a decrease of
15% from the first quarter of 2015. NGLs production for the quarter was
14,599 barrels per day, an increase of 14% over the second quarter of
2014 and an increase of 2% over the first quarter of 2015. Natural gas
production for the quarter was 183,135 thousand cubic feet (Mcf) per
day, an increase of 11% over the second quarter of 2014 and an increase
of 1% over the first quarter of 2015. Total production for the first six
months of 2015 was 10.2 MMBoe.

Unit’s average realized per barrel equivalent price for the second
quarter was $22.38, a decrease of 44% from the second quarter of 2014
and a 2% increase from the first quarter of 2015. Unit’s average natural
gas price for the second quarter of 2015 was $2.67 per Mcf, a decrease
of 34% from the second quarter of 2014 and a 9% decrease from the first
quarter of 2015. Unit’s average oil price for the quarter was $55.52 per
barrel, a decrease of 41% from the second quarter of 2014 and an
increase of 15% over the first quarter of 2015. Unit’s average NGLs
price for the quarter was $12.05 per barrel, a 60% decrease from the
second quarter of 2014 and an increase of 39% over the first quarter of
2015. All prices in this paragraph include the effects of derivative
contracts.

The following table summarizes this segment’s outstanding derivative
contracts.


Crude
	Swap Volume	Collar Volume	Weighted Average	Weighted Average	Weighted Average
Period	Bbl/Day	Bbl/Day	Swap Price	Floor Price	Ceiling Price
Q3 2015	1,000	2,000	$95.00	$58.00	$64.40
Q4 2015	1,000	2,000	$95.00	$58.00	$64.40
Natural Gas
	Swap Volume	Collar Volume	Weighted Average	Weighted Average	Weighted Average
Period	MMBtu/Day	MMBtu/Day	Swap Price	Floor Price	Ceiling Price
Q3 2015	40,000	30,000	$3.98	$2.58	$3.04
Q4 2015	40,000	—	$3.98	—	—
2016	10,000	—	$3.25	—	—

The following table illustrates this segment’s comparative production,
realized prices, and operating profit for the periods indicated:


	Three Months Ended						Three Months Ended						Six Months Ended
	June 30, 2015		June 30, 2014		Change		June 30, 2015		Mar. 31, 2015		Change		June 30, 2015		June 30, 2014		Change
Oil and NGLs Production, MBbl		2,277		2,113	8	%		2,277		2,384	(4	)%		4,661		3,989	17	%
Natural Gas Production, Bcf		16.7		15.0	11	%		16.7		16.4	2	%		33.1		28.9	14	%
Production, MBoe		5,054		4,618	9	%		5,054		5,117	(1	)%		10,171		8,802	16	%
Production, MBoe/day		55.5		50.7	9	%		55.5		56.9	(2	)%		56.2		48.6	16	%
Avg. Realized Natural Gas Price, Mcf ⁽¹⁾	$	2.67	$	4.05	(34	)%	$	2.67	$	2.94	(9	)%	$	2.80	$	4.14	(32	)%
Avg. Realized NGL Price, Bbl ⁽¹⁾	$	12.05	$	29.99	(60	)%	$	12.05	$	8.65	39	%	$	10.37	$	34.57	(70	)%
Avg. Realized Oil Price, Bbl ⁽¹⁾	$	55.52	$	94.17	(41	)%	$	55.52	$	48.47	15	%	$	51.73	$	92.95	(44	)%
Realized Price / Boe ⁽¹⁾	$	22.38	$	40.10	(44	)%	$	22.38	$	21.99	2	%	$	22.18	$	40.93	(46	)%
Operating Profit Before Depreciation, Depletion, & Amortization (MM) ⁽²⁾	$	61.3	$	153.8	(60	)%	$	61.3	$	60.9	1	%	$	122.1	$	301.6	(60	)%

(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.

Currently, two Unit drilling rigs are operating for this segment. One is
operating in the Southern Oklahoma Hoxbar Oil Trend (SOHOT) and one is
drilling in the Wilcox play, located in southeast Texas. The current
plan is to have two Unit drilling rigs operating through the end of the
third quarter at which time adjustments may be made depending on factors
such as commodity pricing, service costs and/or well results. Unit’s
expectations are to be at the top end of the production guidance of 2%
to 4%. Well service cost reductions and operating efficiencies are
resulting in current AFE’s being approximately 28% lower as compared to
2014.

In the SOHOT area, production increased 5% during the quarter as
compared to the first quarter of 2015. During the first half of 2015,
three horizontal operated Hoxbar wells were completed in the first
quarter and five horizontal Hoxbar wells were completed in the second
quarter for a total of eight wells. Six of the eight new wells were
completed in the Medrano member of the Hoxbar and two wells in the
Marchand member. The 30 day initial production rate for the six Medrano
wells averaged 7 MMcfe per day of which approximately 32% consisted of
liquids. The two Marchand wells had a 30 day average initial production
rate of approximately 1,571 Boe per day with 84% of the production mix
being oil. The current plan for 2015 is to utilize one to two Unit rigs
drilling in the prospect for the remainder of 2015, which should equate
to approximately 12 to 14 new horizontal Hoxbar completions.

In the Wilcox area, production was essentially unchanged during the
quarter as compared to the first quarter 2015 after accounting for a
reduction of 0.75 Bcfe due to a third party processing plant being shut
in for maintenance. Without the reduction, Wilcox production would have
increased approximately 11% for the quarter. For the first half 2015,
three Wilcox wells were completed in the first quarter and five Wilcox
wells were completed in the second quarter for a total of eight wells
(five vertical and three horizontal). Because of a lack of sufficient
production history and pending lease acquisition opportunities, we have
elected not to discuss the performance of the horizontal wells at this
time. Two additional horizontal wells are scheduled to be drilled late
in the fourth quarter of 2015. Development of the Gilly Downthrown fault
block is progressing favorably. Four vertical Wilcox wells have been
drilled and logged an average of approximately 200 feet of potential oil
and gas pay from multiple Wilcox sands. Completion operations have begun
on all four wells and current plans are to drill two to three additional
vertical delineation wells this year. The preliminary field size based
on the four wells is estimated at approximately 1,000 acres. In the
Wilcox project, the current plan is to utilize one to two Unit drilling
rigs in 2015, which should result in approximately 11 vertical and five
horizontal Wilcox completions.

In the Granite Wash, a horizontal “C1” well was completed with an
extended lateral of approximately 6,600 feet. The well, which is the
first extended lateral drilled in this sand, had an average IP 30 rate
of 10.7 MMcfe per day consisting of 42% natural gas, 35% oil, and 23%
NGLs production. This was a 39% increase in the IP 30 rate over the
typical “C1” well with a lateral length of 4,600 feet.

Larry Pinkston, Unit’s Chief Executive Officer and President, said: “Due
to the unexpected shut in of some of the production in East Texas
because of maintenance of a third party processing facility, production
for the quarter was negatively impacted by approximately 125,000 Boe. We
have reduced our drilling activities during the quarter because of the
continued lower commodity prices. Despite the slowdown, we are pleased
with the quality of the wells that we are drilling and completing. In
the two core areas where we are allocating capital we have a multi-year
inventory of potential drilling locations that can meet or exceed our
profitability hurdles in this challenging commodity price environment.”

CONTRACT DRILLING SEGMENT INFORMATION

The average number of drilling rigs used in the quarter was 30.7, a
decrease of 58% from the second quarter of 2014, and a decrease of 39%
from the first quarter of 2015. Per day drilling rig rates for the
quarter averaged $19,881, essentially unchanged from the second quarter
of 2014 and a 1% decrease from the first quarter of 2015. Average per
day operating margin for the quarter was $6,821 (before elimination of
intercompany drilling rig profit and bad debt expense of $0.5 million).
This compares to $8,317 (before elimination of intercompany drilling rig
profit and bad debt expense of $7.8 million) for the second quarter of
2014, a decrease of 18%, or $1,496. As compared to $10,253 (before
elimination of intercompany drilling rig profit and bad debt expense of
$2.9 million) for the first quarter of 2015, second quarter 2015
operating margin decreased 33% or $3,432 (in each case regarding
eliminating intercompany drilling rig profit and bad debt expense – see
Non-GAAP Financial Measures below). Average operating margins for the
second quarter of 2015 included early termination fees of approximately
$1.6 million, or $594 per day, from the cancellation of certain
long-term contracts, compared to no early termination fees during the
second quarter of 2014 and $12.7 million for the first quarter of 2015.

Larry Pinkston said: “Drilling rig demand continued to decline during
the second quarter because of the significant decrease in commodity
prices. During the quarter, our sixth, seventh, and eighth BOSS drilling
rigs began operating. With adding these three BOSS drilling rigs, our
current drilling rig fleet now totals 94 drilling rigs, of which 32 are
now working under contract. We have recently been notified of a
customer’s intent to terminate early the contracts on two BOSS drilling
rigs both of which are under term contracts that contain early
termination penalties. Long-term contracts (contracts with original
terms ranging from six months to two years in length) are in place for
14 of the 32 drilling rigs. Of the 14 long-term contracts, three are up
for renewal during the third quarter, one in the fourth quarter, seven
in 2016 and three in 2017.”

The following table illustrates certain comparative results from this
segment’s operations for the periods indicated:


	Three Months Ended						Three Months Ended						Six Months Ended
	June 30, 2015		June 30, 2014		Change		June 30, 2015		Mar. 31, 2015		Change		June 30, 2015		June 30, 2014		Change
Rigs Utilized		30.7		73.5	(58	)%		30.7		50.1	(39	)%		40.4		70.7	(43	)%
Operating Profit Before Depreciation, Depletion, & Amortization (MM) ⁽¹⁾	$	18.5	$	47.8	(61	)%	$	18.5	$	43.3	(57	)%	$	61.9	$	90.6	(32	)%

(1) Operating profit before depreciation is calculated by taking
operating revenues for this segment less operating expenses excluding
depreciation and impairment.

MID-STREAM SEGMENT INFORMATION

For the quarter, per day gas gathered and gas processed volumes
increased 11% and 15%, respectively, while liquids sold volumes
decreased 21% as compared to the second quarter of 2014. Compared to the
first quarter of 2015, gas gathered and liquids sold volumes per day
increased 9% and 5%, respectively, while gas processed volumes per day
decreased 2%. Operating profit (as defined in the footnote below) for
the quarter was $11.6 million, a decrease of 17% from the second quarter
of 2014 and an increase of 18% over the first quarter of 2015.

For the first six months, per day gas gathered and gas processed volumes
increased 11% and 20%, respectively, while liquids sold volumes per day
decreased 21% as compared to the first six months of 2014. Operating
profit (as defined in the footnote below) for the first six months was
$21.4 million, a decrease of 18% from the first six months of 2014.

The following table illustrates certain comparative results from this
segment’s operations for the periods indicated:


	Three Months Ended						Three Months Ended						Six Months Ended
	June 30, 2015		June 30, 2014		Change		June 30, 2015		Mar. 31, 2015		Change		June 30, 2015		June 30, 2014		Change
Gas Gathering, Mcf/day		362,896		326,028	11	%		362,896		334,278	9	%		348,666		315,116	11	%
Gas Processing, Mcf/day		186,041		161,509	15	%		186,041		189,160	(2	)%		187,592		155,807	20	%
Liquids Sold, Gallons/day		599,732		762,205	(21	)%		599,732		568,876	5	%		584,389		737,353	(21	)%
Operating Profit Before Depreciation, Depletion, & Amortization (MM) ⁽¹⁾	$	11.6	$	14.0	(17	)%	$	11.6	$	9.8	18	%	$	21.4	$	26.2	(18	)%

(1) Operating profit before depreciation is calculated by taking
operating revenues for this segment less operating expenses excluding
depreciation, amortization, and impairment.

Larry Pinkston said: “We continue to operate in full ethane rejection
mode due to the decline in liquids prices that have adversely impacted
our liquids sold volumes. Gathering volumes continue to increase through
the second quarter as our facilities are positioned well to take
advantage of operator activity. Progress continues to be made on the
Snowshoe project in Centre County, Pennsylvania with the completion
expected to be by the end of 2015.”

FINANCIAL INFORMATION

Unit ended the quarter with long-term debt of $926.9 million (consisting
of $646.4 million of senior subordinated notes net of unamortized
discount and $280.5 million of borrowings under its credit agreement).
Unit’s credit agreement provides that the amount Unit can borrow is the
lesser of the amount it elects as the commitment amount (currently $500
million) or the value of its borrowing base as determined by the lenders
(currently $725 million), but in either event not to exceed $900
million. The credit agreement was amended during the second quarter to
provide for a new maturity date of April 2020 and establish the current
borrowing base amount noted above.

WEBCAST

Unit will webcast its second quarter earnings conference call live over
the Internet on August 4, 2015 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 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 the productive
capabilities of the company’s wells, future demand for oil and natural
gas, future drilling rig utilization and dayrates, projected growth of
the company’s oil and natural gas production, oil and gas reserve
information, and its ability to meet its future reserve replacement
goals, anticipated gas gathering and processing rates and throughput
volumes, the prospective capabilities of the reserves associated with
the company’s inventory of future drilling sites, anticipated oil and
natural gas prices, the number of wells to be drilled by the company’s
oil and natural gas segment, development, operational, implementation,
and opportunity risks, possible delays caused by limited availability of
third party services needed in its operations, possibility of future
growth opportunities, 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,
	2015			2014			2015			2014
Statement of Operations:
Revenues:
Oil and natural gas	$	107,256		$	198,498		$	213,325		$	386,705
Contract drilling		55,015			114,278			150,092			220,878
Gas gathering and processing		52,176			92,655			106,129			185,836
Total revenues		214,447			405,431			469,546			793,419
Expenses:
Oil and natural gas:
Operating costs		45,972			44,723			91,183			85,138
Depreciation, depletion, and amortization		68,101			71,245			145,219			130,925
Impairment of oil and natural gas properties		410,536			–			811,129			–
Contract drilling:
Operating costs		36,485			66,494			88,231			130,298
Depreciation		13,265			20,239			28,278			38,634
Impairment of contract drilling equipment		8,314			–			8,314			–
Gas gathering and processing:
Operating costs		40,592			78,648			84,767			159,608
Depreciation and amortization		10,848			10,109			21,542			19,700
General and administrative		9,624			10,600			18,994			20,237
Gain on disposition of assets		(415	)		(195	)		(960	)		(9,621	)
Total operating expenses		643,322			301,863			1,296,697			574,919

Income (loss) from operations		(428,875	)		103,568			(827,151	)		218,500

Other income (expense):
Interest, net		(7,956	)		(4,131	)		(15,196	)		(7,921	)
Gain (loss) on derivatives not designated as hedges		(1,919	)		(10,709	)		4,667			(29,075	)
Other		24			(49	)		22			71
Total other income (expense)		(9,851	)		(14,889	)		(10,507	)		(36,925	)

Income (loss) before income taxes		(438,726	)		88,679			(837,658	)		181,575

Income tax expense (benefit):
Current		803			8,475			868			18,270
Deferred		(165,140	)		25,844			(315,783	)		52,000
Total income taxes		(164,337	)		34,319			(314,915	)		70,270

Net income (loss)	$	(274,389	)	$	54,360		$	(522,743	)	$	111,305

Net income (loss) per common share:
Basic	$	(5.58	)	$	1.12		$	(10.66	)	$	2.29
Diluted	$	(5.58	)	$	1.11		$	(10.66	)	$	2.27

Weighted average shares outstanding:
Basic		49,148			48,642			49,063			48,568
Diluted		49,148			49,116			49,063			49,010


	June 30,		December 31,
	2015		2014
Balance Sheet Data:
Current assets	$	166,534	$	252,491
Total assets	$	3,629,993	$	4,473,728
Current liabilities	$	177,900	$	304,171
Long-term debt	$	926,908	$	812,163
Other long-term liabilities	$	141,153	$	148,785
Deferred income taxes	$	560,432	$	876,215
Shareholders’ equity	$	1,823,600	$	2,332,394


	Six Months Ended June 30,
	2015			2014
Statement of Cash Flows Data:
Cash flow from operations before changes in operating assets and liabilities	$	207,221		$	370,348
Net change in operating assets and liabilities		50,385			(44,820	)
Net cash provided by operating activities	$	257,606		$	325,528
Net cash used in investing activities	$	(366,442	)	$	(379,107	)
Net cash provided by financing activities	$	108,626		$	36,064

Non-GAAP Financial Measures

Unit Corporation reports its financial results in accordance with
generally accepted accounting principles (“GAAP”). The Company believes
certain non-GAAP performance 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 and earnings per share including
impairment adjustments and the effect of the cash settled commodity
derivatives, its drilling segment’s average daily operating margin
before elimination of intercompany drilling rig profit and bad debt
expense, and its cash flow from operations before changes in operating
assets and liabilities.

Below is a reconciliation of GAAP financial measures to non-GAAP
financial measures for the three and six months ended June 30, 2015 and
2014. Non-GAAP financial measures should not be considered by themselves
or a substitute for results reported in accordance with GAAP.


Unit Corporation
Reconciliation of Adjusted Net Income and Adjusted Diluted Earnings per Share

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2015			2014			2015			2014
	(In thousands except earnings per share)
Adjusted net income:
Net income (loss)	$	(274,389	)	$	54,360		$	(522,743	)	$	111,305
Impairment adjustment (net of income tax)		260,734			–			510,103			–
(Gain) loss on derivatives not designated as hedges (net of income tax)		1,238			6,564			(2,786	)		17,822
Settlements during the period of matured derivative contracts (net of income tax)		6,495			(5,567	)		13,223			(11,005	)
Adjusted net income (loss)	$	(5,922	)	$	55,357		$	(2,203	)	$	118,122

Adjusted diluted earnings per share:
Diluted earnings (loss) per share	$	(5.58	)	$	1.11		$	(10.66	)	$	2.27
Diluted earnings per share from the impairments		5.31			–			10.40			–
Diluted earnings per share from the (gain) loss on derivatives		0.02			0.13			(0.06	)		0.37
Diluted earnings (loss) per share from the settlements of matured derivative contracts		0.13			(0.11	)		0.27			(0.23	)
Adjusted diluted earnings (loss) per share	$	(0.12	)	$	1.13		$	(0.05	)	$	2.41

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 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,
	2015		2015		2014		2015		2014
	(In thousands except for operating days and operating margins)
Contract drilling revenue	$	95,077	$	55,015	$	114,278	$	150,092	$	220,878
Contract drilling operating cost		51,746		36,485		66,494		88,231		130,298
Operating profit from contract drilling		43,331		18,530		47,784		61,861		90,580
Add:
Elimination of intercompany rig profit and bad debt expense		2,910		537		7,808		3,447		13,121
Operating profit from contract drilling before elimination of intercompany rig profit and bad debt expense		46,241		19,067		55,592		65,308		103,701
Contract drilling operating days		4,510		2,795		6,684		7,305		12,797
Average daily operating margin before elimination of intercompany rig profit and bad debt expense	$	10,253	$	6,821	$	8,317	$	8,940	$	8,104

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,
	2015			2014
	(In thousands)
Net cash provided by operating activities	$	257,606		$	325,528
Net change in operating assets and liabilities		(50,385	)		44,820
Cash flow from operations before changes in operating assets and liabilities	$	207,221		$	370,348

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.

View source version on businesswire.com: http://www.businesswire.com/news/home/20150804005488/en/

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

Unit Corporation Reports 2015 Second Quarter Results

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