Unit Corporation Reports 2013 First Quarter Results

Unit Corporation (NYSE: UNT) today reported its financial and
operational results for the first quarter of 2013. Highlights for the
quarter include:

Adjusted non-GAAP net income for the first quarter was $44.5 million,
or $0.92 per diluted share (see Non-GAAP Financial Measures below).
Total production for first quarter was 4.0 million barrels of oil
equivalent (MMBoe), an increase of 21% over the first quarter of 2012.
Total liquids (oil and natural gas liquids) production for the first
quarter of 2013 increased 16% over the comparable quarter of 2012.
Average number of drilling rigs utilized during the first quarter of
2013 increased 4% over the fourth quarter of 2012.
Mid-stream increased first quarter of 2013 gathered volumes per day
and processed volumes per day by 27% and 5%, respectively, over the
first quarter of 2012.

Net income for the three months ended March 31, 2013 was $40.2 million,
or $0.83 per diluted share, compared to $52.4 million, or $1.09 per
diluted share, for the three months ended March 31, 2012. Net income
included the effect of a $7.0 million ($4.3 million after tax) reduction
in earnings from the unrealized value of commodity derivatives. Without
this reduction, net income for the first quarter would have been $44.5
million, or $0.92 per diluted share (see Non-GAAP Financial Measures
below). Total revenues for the first quarter of 2013 were $318.5 million
(48% oil and natural gas, 34% contract drilling, and 18% mid-stream),
compared to $334.0 million (41% oil and natural gas, 42% contract
drilling, and 17% mid-stream) for the first quarter of 2012.

OIL AND NATURAL GAS SEGMENT INFORMATION

Unit’s strategy of drilling oil or natural gas liquids (NGLs) rich wells
is evident in its production results. Liquids production represented 40%
of total equivalent production during the first quarter of 2013. First
quarter of 2013 total equivalent production increased 21% over the first
quarter of 2012 to 4.0 MMBoe, while total liquids production for the
first quarter of 2013 increased 16% over the comparable quarter of 2012.
Liquids production for the first quarter of 2013 has increased 117%
since the first quarter of 2009 when Unit began focusing on increasing
its liquids production. First quarter 2013 oil production was 797,000
barrels, in comparison to 720,000 barrels for the same period of 2012,
an increase of 11%. NGLs production during the first quarter of 2013 was
804,000 barrels, an increase of 23% when compared to 656,000 barrels for
the same period of 2012. First quarter 2013 natural gas production
increased 25% to 14.2 billion cubic feet (Bcf) compared to 11.4 Bcf for
the comparable quarter of 2012. Total production for the first quarter
2013 was 4.0 MMBoe, an increase of 21% over the 3.3 MMBoe produced
during the first quarter of 2012.

Unit’s average natural gas price for the first quarter of 2013 decreased
2% to $3.30 per thousand cubic feet (Mcf) as compared to $3.36 per Mcf
for the first quarter of 2012. Unit’s average oil price for the first
quarter of 2013 decreased 1% to $95.23 per barrel compared to $95.81 per
barrel for the first quarter of 2012. Unit’s average NGLs price for the
first quarter of 2013 was $34.99 per barrel compared to $38.81 per
barrel for the first quarter of 2012, a decrease of 10%. All prices
reflected in this paragraph include the effects of hedges.

For 2013, Unit has hedged 8,330 Bbls per day of its oil production and
100,000 MMBtu per day of natural gas production. The oil production is
hedged under swap contracts at an average price of $97.94 per barrel. Of
the natural gas production, 80,000 MMBtu per day is hedged with swaps
and 20,000 MMBtu per day is hedged with a collar. The swap transactions
were done at a comparable average NYMEX price of $3.65. The collar
transaction was done at a comparable average NYMEX floor price of $3.25
and ceiling price of $3.72.

Currently for 2014, Unit has hedged 4,000 Bbls per day of its oil
production and 50,000 MMBtu per day of natural gas production. Of the
oil production, 2,000 Bbls per day is hedged with swaps and 2,000 Bbls
per day is hedged with collars. The swap transactions were done at an
average price of $91.40. The collar transactions were done at an average
floor price of $90.00 and ceiling price of $95.00. The natural gas
production is hedged under swap contracts at a comparable average NYMEX
price of $4.24 per MMBtu.

The following table illustrates Unit’s production and certain results
for the periods indicated:

	1^st Qtr 13	4^th Qtr 12	3^rd Qtr 12	2^nd Qtr 12	1^st Qtr 12	4^th Qtr 11	3^rd Qtr 11	2^nd Qtr 11	1^st Qtr 11
Oil and NGL Production, MBbl	1,600.6	1,694.1	1,545.8	1,460.2	1,375.2	1,359.9	1,197.5	1,158.6	1,034.0
Natural Gas Production, Bcf	14.2	14.5	11.7	11.3	11.4	11.4	11.6	10.9	10.2
Production, MBoe	3,971	4,115	3,498	3,341	3,275	3,255	3,123	2,983	2,739
Production, MBoe/day	44.1	44.7	38.0	36.7	36.0	35.4	33.9	32.8	30.4
Realized Price, Boe (1)	$37.73	$39.56	$37.99	$38.49	$40.51	$42.65	$41.75	$42.23	$40.00

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

The development of the “Gilly” Lower Wilcox field located in southeast
Texas with estimated gross resource reserves of 262 Bcfe (168 Bcfe net)
is continuing as planned with one new field well completed during the
first quarter. There have been six wells completed in the field with
plans to drill up to four additional field wells this year, including
Unit’s first horizontal well in one of the lower Wilcox sands.
Production from the “Gilly” field started in June 2011, and during the
first quarter of 2013, the field averaged approximately 370 barrels of
oil per day, 1,210 barrels of NGL’s per day, and 14 MMcf per day, or an
equivalent rate of approximately 23 MMcfe per day. During this early
phase of field development we are allowing sufficient time for testing
multiple sands and drilling new wells to determine the most cost
effective way to develop the reserves. Approximately one mile north of
the Gilly Field, Unit has discovered a new productive fault block with
the completion of two recent wells. Further testing and additional
drilling is scheduled for later this year to delineate the potential of
the discovery. For 2013, Unit plans to run one to two Unit drilling
rigs, drilling approximately 12 wells with an estimated working interest
of 90% at an approximate net cost of $60 million.

In Unit’s Mississippian play, located primarily in south central Kansas,
the installation of the pipeline and processing infrastructure is
currently underway and is estimated to be completed during the third
quarter of 2013. Current plans are to resume drilling in the prospect
during the third quarter and continue to work one or two drilling rigs
for the remainder of 2013. Unit’s initial Mississippian well had first
production in May 2012 with an average 30 day peak rate of approximately
350 Boe per day consisting of approximately 92% oil and NGLs. Unit’s
second well was drilled approximately two miles from the initial well
and came on line at the very end of 2012 with a 30 day peak rate of
approximately 130 Boe per day consisting of approximately 86% oil and
NGLs. The Mississippian interval in both wells appear similar in
character and shows; however, the second well had a smaller fracture
stimulation design, which does not appear to have been as effective as
the larger fracture stimulation design on the initial well. Based on the
production profile from both of these wells, the reserve range estimate
remains at 125 MBoe to 180 MBoe. Unit currently has approximately
110,000 net acres in the Mississippian play and plans to spend
approximately $40 million drilling and completing approximately 13 wells
during 2013.

In the Marmaton horizontal oil play located in Beaver County, Oklahoma,
Unit completed 10 wells during the first quarter with an average working
interest of 74%. The average 30 day peak rate for first quarter wells
was approximately 390 Boe, which is similar to 2012 results and in line
with expectations. Development of the field is continuing on one well
per 640 acre spacing and estimated ultimate reserves is unchanged from
previous estimates of 120 MBoe to 130 MBoe per well. Unit currently has
leases on approximately 113,000 net acres in this play with
approximately 47% of the leasehold held by production. For 2013, Unit
anticipates running a two to three drilling rig program in this play
that should result in approximately 40 gross wells at an approximate net
cost of $90 million.

In its Granite Wash (GW) play located in the Texas Panhandle, Unit
started 2013 with two Unit drilling rigs drilling and added a third and
fourth drilling rig during the first quarter with current plans to add a
fifth drilling rig in the third quarter and potentially a sixth drilling
rig in the fourth quarter. Drilling operations on Unit’s first
horizontal GW well from the recent Noble acquisition began in March, and
we expect to drill and test several different GW sands across the
leasehold this year. For the first quarter 2013, Unit had first sales on
four horizontal wells with a peak 30 day IP rate of 4.7 MMcfe per day at
an average working interest of 97%. For 2013, Unit anticipates
completing approximately 30 horizontal wells at an approximate net cost
of $140 million.

Larry Pinkston, Unit’s Chief Executive Officer and President, said: “We
are pleased with the results from our exploration operations, and we are
excited about our opportunities for growth. Production was down slightly
during the first quarter of 2013 from the fourth quarter of 2012 due
principally to weather related issues and reducing the number of company
operated drilling rigs to six during the fourth quarter of 2012. We
began ramping up our drilling program during the first quarter of 2013.
We are currently operating eight drilling rigs and plan to increase this
number throughout 2013 depending on market conditions. Unit’s annual
production guidance for 2013 is approximately 16.0 to 16.5 MMBoe, an
increase of 13% to 16% over 2012.”

CONTRACT DRILLING SEGMENT INFORMATION

The average number of drilling rigs used in the first quarter of 2013
was 66.3, a decrease of 19% from the first quarter of 2012, and an
increase of 4% from the fourth quarter of 2012. Per day drilling rig
rates for the first quarter of 2013 averaged $19,580, a decrease of 1%,
or $258, from the first quarter of 2012, and a 1% decrease, or $248,
from the fourth quarter of 2012. Average per day operating margin for
the first quarter of 2013 was $7,534 (before elimination of intercompany
drilling rig profit of $3.4 million). This compares to $9,414 (before
elimination of intercompany drilling rig profit of $4.3 million) for the
first quarter of 2012, a decrease of 20%, or $1,880. As compared to the
fourth quarter of 2012 ($7,838 before elimination of intercompany
drilling rig profit of $2.6 million), first quarter 2013 operating
margin decreased 4% or $304 (in each case regarding the elimination of
intercompany drilling rig profit see Non-GAAP Financial Measures below).
For the first quarter and fourth quarter of 2012 average operating
margins included early termination fees of approximately $95 per day and
$24 per day, respectively, from the cancellation of certain long-term
contracts.

Larry Pinkston said: “Drilling activity began to improve during the
first quarter of 2013 as we’ve seen a slight increase in demand for our
drilling rigs. We believe that operators are continuing to focus on
shallower oil plays and liquids rich plays which provided the
opportunity to put more of our 750 to 1,000 horsepower drilling rigs to
work. Approximately 99% of our drilling rigs working today are drilling
for oil or NGLs. Currently, we have 127 drilling rigs in our fleet, of
which 66 are under contract. Long-term contracts (contracts with
original terms ranging from six months to two years in length) are in
place for 27 of those 66 drilling rigs. Of these contracts, four are up
for renewal during the second quarter of 2013, ten during the third
quarter of 2013, two during the fourth quarter of 2013, and 11 in 2014
and beyond. During 2013, the drilling segment will be constructing a new
prototype 1,500 horsepower AC electric drilling rig of proprietary
design. The drilling rig will operate initially for our oil and natural
gas segment when completed.”

The following table illustrates Unit’s drilling rig count at the end of
each period and average utilization rate during the period:

	1^st Qtr 13	4^th Qtr 12	3^rd Qtr 12	2^nd Qtr 12	1^st Qtr 12	4^th Qtr 11	3^rd Qtr 11	2^nd Qtr 11	1^st Qtr 11
Rigs	127	127	127	128	127	127	126	123	122
Utilization	52%	50%	58%	60%	64%	65%	63%	60%	58%

MID-STREAM SEGMENT INFORMATION

First quarter of 2013 per day gathered volumes were 318,834 MMBtu while
per day processed volumes were 162,287 MMBtu, an increase of 27% and 5%,
respectively, over the first quarter of 2012. Per day gathered and
processed volumes decreased 2% and 1%, respectively, as compared to the
fourth quarter of 2012. First quarter 2013 liquids sold volumes were
420,291 gallons per day, a decrease of 5% from the fourth quarter of
2012 and a decrease of 20% from first quarter 2012 primarily due to
operating in ethane rejection mode and wells shut in during a snow storm
in the first quarter of 2013. Operating profit (as defined in the
Selected Financial and Operational Highlights) for the first quarter of
2013 was $8.0 million, a decrease of 18% from the first quarter of 2012
and an increase of 24% from the fourth quarter of 2012.

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

	1^st Qtr 13	4^th Qtr 12	3^rd Qtr 12	2^nd Qtr 12	1^st Qtr 12	4^th Qtr 11	3^rd Qtr 11	2^nd Qtr 11	1^st Qtr 11
Gas gathered MMBtu/day	318,834	325,231	277,806	300,602	251,276	257,398	228,247	190,921	185,730
Gas processed MMBtu/day	162,287	163,173	166,652	177,407	154,825	156,721	129,820	90,737	86,445
Liquids sold Gallons/day	420,291	441,973	576,889	629,350	522,829	511,410	449,604	356,484	328,333

Larry Pinkston said: “In the Mississippian play in north central
Oklahoma, we are continuing to expand our Bellmon system. In the first
quarter of 2013, we added approximately 54 miles of gathering pipeline,
which increases the total miles of pipeline to 136 for this system. Also
during the first quarter of 2013, we completed the installation of our
second processing plant at the Bellmon facility. With the installation
of this new processing plant, our total processing capacity at this
facility increased to 55 MMcf per day. At our Hemphill facility located
in Hemphill County, Texas, we now have the capacity to process 140 MMcf
per day of our own and third party Granite Wash natural gas production.
Also at this facility, we are completing two pipeline extension projects
for a total capital cost of approximately $5.7 million, which will allow
us to connect additional production to our system from new areas. In
Reno County, Kansas, we are in the process of constructing a new
gathering system and processing plant. This facility is currently under
construction and will consist initially of 35 miles of gathering
pipeline and two processing plants, an 8 MMcf per day refrigeration
plant and a 20 MMcf per day turbo expander plant. This system is
designed to gather and process our gas as well as third party production
in the area.

“In the Appalachian area, we are continuing to expand our Pittsburgh
Mills gathering system which is located in Allegheny County,
Pennsylvania. We have completed the 1^st phase of this project
which consists of approximately seven miles of gathering pipeline and
the related compressor station at which we have installed four rental
compressors. We are continuing to connect third party wells to this
system. We have 14 wells connected to this system with four additional
wells scheduled to be connected in the second quarter of 2013. The total
gathered volume from the wells currently connected to our system is
approximately 50 MMcf per day. Construction activity for expansion of
this gathering system continues as the producer is maintaining its level
of drilling activity.”

FINANCIAL INFORMATION

Unit ended the first quarter with long-term debt of $715.4 million
($645.4 million of senior subordinated notes and $70.0 million under its
credit agreement), and a debt to capitalization ratio of 26%. Under its
credit agreement, the amount available for Unit to borrow is the lesser
of the amount Unit elects as the commitment amount (currently $500
million) or the value of its borrowing base as determined by the lenders
(currently $800 million), but in either event not to exceed the maximum
amount of $900 million.

MANAGEMENT COMMENT

Larry Pinkston said: “We are pleased with the results of our operations
in all three segments and are excited about the growth opportunities for
2013. The recent acquisition from Noble was an important growth step for
us going forward. We plan to accelerate the drilling activity in the
acquired properties and our other Granite Wash acreage over the next 12
to 18 months using up to six rigs from our contract drilling segment,
and we plan to operate the acquired gathering systems and replace
existing third party processing contracts beginning in 2015. Unit
continues to maintain a conservative financial profile. As a result, we
are well positioned to take advantage of growth opportunities that may
arise for our business segments.”

WEBCAST

Unit will webcast its first quarter earnings conference call live over
the Internet on May 7, 2013 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
exploration 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 and Operations Highlights
(In thousands except per share and operations data)

	Three Months Ended
	March 31,
	2013			2012
Statement of Operations:
Revenues:
Oil and natural gas	$	153,609		$	135,765
Contract drilling		107,528			140,906
Gas gathering and processing		57,395			57,295
Total revenues		318,532			333,966

Expenses:
Oil and natural gas:
Operating costs		43,038			35,609
Depreciation, depletion, and amortization		51,983			52,197
Contract drilling:
Operating costs		66,002			76,173
Depreciation		17,260			21,328
Gas gathering and processing:
Operating costs		49,410			47,613
Depreciation and amortization		7,156			5,134
General and administrative		8,673			7,004
Total operating expenses		243,522			245,058

Income from operations		75,010			88,908

Other income (expense):
Interest, net		(3,561	)		(1,826	)
Loss on derivatives		(5,924	)		(1,993	)
Other		(150	)		455
Total other income (expense)		(9,635	)		(3,364	)

Income before income taxes		65,375			85,544

Income tax expense:
Current		2,517			—
Deferred		22,652			33,105
Total income taxes		25,169			33,105

Net income	$	40,206		$	52,439

Net income per common share:
Basic	$	0.84		$	1.10
Diluted	$	0.83		$	1.09

Weighted average shares outstanding:
Basic		48,117			47,829
Diluted		48,412			48,126


	March 31,			December 31,
	2013			2012
Balance Sheet Data:
Current assets	$	189,575		$	195,644
Total assets	$	3,814,840		$	3,761,120
Current liabilities	$	212,454		$	207,139
Long-term debt	$	715,365		$	716,359
Other long-term liabilities	$	158,510		$	167,545
Deferred income taxes	$	718,498		$	695,776
Shareholders’ equity	$	2,010,013		$	1,974,301


	Three Months Ended March 31,
	2013			2012
Statement of Cash Flows Data:
Cash flow from operations before changes in operating assets and liabilities (1)	$	153,314		$	170,876
Net change in operating assets and liabilities		26,346			(22,929	)
Net cash provided by operating activities	$	179,660		$	147,947
Net cash used in investing activities	$	(191,471	)	$	(189,419	)
Net cash provided by financing activities	$	11,990		$	41,832


	Three Months Ended
	March 31,
	2013			2012
Oil and Natural Gas Operations Data:
Production:
Oil – MBbls		797			720
NGLs – MBbls		804			656
Natural gas – MMcf		14,220			11,400
Average Prices:
Oil price per barrel received	$	95.23		$	95.81
Oil price per barrel received, excluding hedges	$	91.94		$	100.16
NGLs price per barrel received	$	34.99		$	38.81
NGLs price per barrel received, excluding hedges	$	34.99		$	37.38
Natural gas price per Mcf received	$	3.30		$	3.36
Natural gas price per Mcf received, excluding hedges	$	3.14		$	2.45
Operating profit before depreciation, depletion, and amortization (2) ($MM)	$	110.6		$	98.2

Contract Drilling Operations Data:
Rigs utilized		66.3			81.5
Operating margins (2)		39	%		46	%
Operating profit before depreciation (2) ($MM)	$	41.5		$	64.7

Mid-Stream Operations Data:
Gas gathering – MMBtu/day		318,834			251,276
Gas processing – MMBtu/day		162,287			154,825
Liquids sold – gallons/day		420,291			522,829
Operating profit before depreciation and amortization (2) ($MM)	$	8.0		$	9.7

(1) The company considers its cash flow from operations before changes
in operating assets and liabilities an important measure in meeting the
performance goals of the company (see Non-GAAP Financial Measures below).

(2) Operating profit before depreciation is calculated by taking
operating revenues by segment less operating expenses excluding
depreciation, depletion, amortization, general and administrative and
interest expense. Operating margins are calculated by dividing operating
profit by segment revenue.

Non-GAAP Financial Measures

We report our financial results in accordance with generally accepted
accounting principles (“GAAP”). We believe certain non-GAAP performance
measures provide users of our financial information and our management
additional meaningful information to evaluate the performance of our
company.

This press release includes cash flow from operations before changes in
operating assets and liabilities, our drilling segment’s average daily
operating margin before elimination of intercompany drilling rig profit,
and net income and earnings per share excluding the effect of the
unrealized value of commodity derivatives.

Below is a reconciliation of GAAP financial measures to non-GAAP
financial measures for the three months ended March 31, 2013 and 2012.
Non-GAAP financial measures should not be considered by themselves or a
substitute for our results reported in accordance with GAAP.


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

	Three Months Ended
	March 31,
	2013			2012
	(In thousands)
Net cash provided by operating activities	$	179,660		$	147,947
Net change in operating assets and liabilities		(26,346	)		22,929
Cash flow from operations before changes in operating assets and liabilities	$	153,314		$	170,876

____________

We have included the cash flow from operations before changes in
operating assets and liabilities because:

It is an accepted financial indicator used by our management and
companies in our industry to measure the company’s ability to generate
cash which is used to internally fund our business activities.
It is used by investors and financial analysts to evaluate the
performance of our company.


Unit Corporation
Reconciliation of Average Daily Operating Margin Before Elimination of Intercompany Rig Profit

	Three Months Ended
	March 31,				December 31,
	2013		2012		2012
	(In thousands except operating days and operating margins)
Contract drilling revenue	$	107,528	$	140,906	$	108,521
Contract drilling operating cost		66,002		76,173		65,544
Operating profit from contract drilling		41,526		64,733		42,977
Add:
Elimination of intercompany rig profit		3,409		4,284		2,647
Operating profit from contract drilling before elimination of intercompany rig profit		44,935		69,017		45,624
Contract drilling operating days		5,964		7,331		5,821
Average daily operating margin before elimination of intercompany rig profit	$	7,534	$	9,414	$	7,838

____________

We have included the average daily operating margin before elimination
of intercompany rig profit because:

Our management uses the measurement to evaluate the cash flow
performance or our 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 our company.


Unit Corporation
Reconciliation of Net Income (Loss) and Diluted Earnings per Share
Excluding the Effect of the Unrealized Value of Commodity Derivatives

	Three Months Ended
	March 31,
	2013		2012
	(In thousands except earnings per share)
Net income excluding the unrealized value of commodity derivatives:
Net income	$	40,206	$	52,439
Add:
Unrealized value of commodity derivatives (net of income tax)		4,283		1,222
Net income excluding the unrealized value of commodity derivatives	$	44,489	$	53,661

Diluted earnings per share excluding the unrealized value of commodity derivatives:
Diluted earnings per share	$	0.83	$	1.09
Add:
Diluted earnings per share from the unrealized value of commodity derivatives		0.09		0.03
Diluted earnings per share excluding the unrealized value of commodity derivatives	$	0.92	$	1.12

____________

We have included the net income excluding the unrealized value of
commodity derivatives and diluted earnings per share excluding the
unrealized value of commodity derivatives because:

We use 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 analyst.

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

Unit Corporation Reports 2013 First Quarter Results

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