Unassociated Document

News	UNIT CORPORATION
	7130 South Lewis Avenue, Suite 1000, Tulsa, Oklahoma 74136
	Telephone 918 493-7700, Fax 918 493-7714

Contact:	David T. Merrill
	Chief Financial Officer
	and Treasurer
	(918) 493-7700 www.unitcorp.com

For Immediate Release…

August 2, 2011

UNIT CORPORATION REPORTS 2011 SECOND QUARTER RESULTS

Tulsa, Oklahoma . . . Unit Corporation (NYSE - UNT) reported net income of $49.8 million, or $1.04 per diluted share, for the three months ended June 30, 2011. For the same period in 2010, net income was $32.2 million, or $0.68 per diluted share. Total revenues for the second quarter of 2011 were $291.5 million (40% contract drilling, 45% oil and natural gas, and 15% mid-stream), compared to $204.6 million (35% contract drilling, 45% oil and natural gas, and 18% mid-stream) for the second quarter of 2010.

For the first six months of 2011, Unit reported net income of $90.8 million, or $1.89 per diluted share. For the same period in 2010, net income was $68.3 million, or $1.43 per diluted share. Total revenues for the first six months of 2011 were $538.9 million (40% contract drilling, 45% oil and natural gas, and 15% mid-stream), compared to $411.2 million (32% contract drilling, 46% oil and natural gas, and 19% mid-stream) for the first six months of 2010.

CONTRACT DRILLING SEGMENT INFORMATION

The average number of drilling rigs used in the second quarter of 2011 was 73.1, an increase of 26% from the second quarter of 2010, and an increase of 4% from the first quarter of 2011. Per day drilling rig rates for the second quarter of 2011 averaged $18,861, up 26%, or $3,946, from the second quarter of 2010, and up 7%, or $1,157 from the first quarter of 2011. Average per day operating margin for the second quarter of 2011 was $8,370 (before elimination of intercompany drilling rig profit of $5.1 million). This compares to $5,101 (before elimination of intercompany drilling rig profit of $1.5 million) for the second quarter of 2010, an increase of 64% or $3,269. As compared to the first quarter of 2011 ($8,077 before elimination of intercompany drilling rig profit of $5.0 million) second quarter 2011 operating margin increased 4% or $293 - in each case with regard to the elimination of intercompany drilling rig profit see Non-GAAP Financial Measures below.

For the first six months of 2011, Unit averaged 71.6 drilling rigs working, up 31% from 54.5 drilling rigs working during the first six months of 2010. Average per day operating margin for the first six months of 2011 was $8,229 (before elimination of intercompany drilling rig profit of $10.1 million) as compared to $4,791 (before elimination of intercompany drilling rig profit of $1.8 million) for the first six months of 2010, an increase of 72% (in each case with regard to the elimination of intercompany drilling rig profit see Non-GAAP Financial Measures below).

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

	2nd Qtr 11	1st Qtr 11	4th Qtr 10	3rd Qtr 10	2nd Qtr 10	1st Qtr 10	4th Qtr 09	3rd Qtr 09	2nd Qtr 09
Rigs	123	122	121	123	123	125	130	130	131
Utilization	60%	58%	59%	54%	47%	40%	28%	26%	24%

Larry Pinkston, Unit's Chief Executive Officer and President, said: “During the second quarter, our utilization rate increased and we obtained an increase in drilling rig day rates over the first quarter of 2011. Our fleet went through a transition in 2010 to accommodate the growing industry focus on drilling horizontal or directional wells. We refurbished and upgraded 30 drilling rigs in 2010 in order that they could undertake this type of drilling. Approximately 81% of our drilling rigs working today are drilling for oil or natural gas liquids and approximately 96% are drilling horizontal or directional wells. We have recently been awarded two additional new build rig contracts. Both contracts have an initial term of three years and are for 1,500 horsepower diesel-electric drilling rigs. Delivery of these two rigs is anticipated during the fourth quarter of 2011. We had previously announced that during 2011 we will add five new 1,500 horsepower diesel-electric drilling rigs to our fleet. Three of those drilling rigs are now completed and are working in the Bakken shale. The remaining two are expected to be completed late in the third quarter. Each of these five new drilling rigs will initially be working under a two-year drilling contract. Currently, 80 of our 124 drilling rigs are under contract. Term contracts (contracts with original terms ranging from six months to three years in length) are in place for 41 of the 80 contracted drilling rigs. Of these contracts 5 are up for renewal during the third quarter of 2011, 15 during the fourth quarter of 2011, and 21 after 2011. These contracts do not include the term contracts for the four new drilling rigs we are currently building and that will be added to our fleet later this year.”

OIL AND NATURAL GAS SEGMENT INFORMATION

·	Completed 45 and 79 gross wells during the 2011 second quarter and first six months, respectively.

·	39% of second quarter 2011 production was oil and natural gas liquids compared to 30% for the second quarter of 2010.

·	Increased estimated capital expenditures for 2011 from $415 million to $435 million.

·	Increased anticipated 2011 production to 11.3 to 11.6 MMBoe.

Second quarter 2011 oil production was 591,000 barrels, in comparison to 321,000 barrels for the same period of 2010, up 84%. Natural gas liquids (NGLs) production during the second quarter of 2011 was 567,000 barrels, an increase of 46% when compared to 388,000 barrels for the same period of 2010. Second quarter 2011 natural gas production increased 13% to10.9 billion cubic feet (Bcf) compared to 9.7 Bcf for the comparable quarter of 2010. Second quarter 2011 equivalent production averaged 32.8 MBoe per day, up 28% over the second quarter of 2010 and up 8% over the first quarter of 2011. Total production for the first six months of 2011 was 5.7 MMBoe.

Unit’s average natural gas price, including the effects of hedges, for the second quarter of 2011 decreased 23% to $4.30 per thousand cubic feet (Mcf) as compared to $5.62 per Mcf for the second quarter of 2010. Unit’s average oil price, including the effects of hedges, for the second quarter of 2011 was $89.77 per barrel compared to $66.93 per barrel for the second quarter of 2010, up 34%, and Unit’s average NGLs price, including the effects of hedges, for the second quarter of 2011 was $45.49 per barrel compared to $33.37 per barrel for the second quarter of 2010, up 36%. For the first six months of 2011, Unit’s average natural gas price, including the effects of hedges, decreased 26% to $4.29 per Mcf as compared to $5.79 per Mcf for the first six months of 2010. Unit’s average oil price, including the effects of hedges, for the first six months of 2011 was $87.14 per barrel compared to $67.12 per barrel during the first six months of 2010, a 30% increase. Unit’s average NGLs price, including the effects of hedges, for the first six months of 2011 was $42.80 per barrel compared to $38.01 per barrel during the first six months of 2010, a 13% increase.

Currently for 2011, Unit has hedged 80,000 MMBtu per day of its natural gas production, 4,000 Bbls per day of its oil production and 504 Bbls per day of its NGLs production. The natural gas production is hedged under swap contracts at a comparable average NYMEX price of $4.85. The average basis differential for the swaps is ($0.19). The oil production is hedged under swap contracts at an average price of $84.28 per barrel. The NGLs production is hedged under swap contracts at an average price of $40.67 per barrel.

For 2012, Unit has to date hedged 45,000 MMBtu per day of its natural gas production and 4,500 Bbls per day of its oil production. The natural gas production is hedged under swap contracts at a comparable average NYMEX price of $5.33. The oil production is hedged under swap contracts at an average price of $95.91 per barrel.

For 2013, Unit has to date hedged 2,000 Bbls per day of its oil production. The oil production is hedged under swap contracts at an average price of $102.05 per barrel.

The following table illustrates certain results for the periods indicated:

	2nd Qtr 11	1st Qtr 11	4th Qtr 10	3rd Qtr 10	2nd Qtr 10	1st Qtr 10	4th Qtr 09	3rd Qtr 09	2nd Qtr 09
Oil and NGL Production, MBo	1,158.6	1,034.0	925.5	756.5	708.6	679.4	641.0	658.2	738.7
Natural Gas Production, Bcf	10.9	10.2	10.6	10.4	9.7	10.0	10.5	10.7	11.0
Production, MBoe	2,983	2,739	2,698	2,478	2,325	2,352	2,389	2,444	2,572
Production, MBoe/day	32.8	30.4	29.3	27.0	25.6	26.1	26.0	26.6	28.3
Realized Price, Boe (1)	$42.23	$40.00	$41.58	$38.16	$38.22	$40.92	$36.72	$35.52	$34.50

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

In the Marmaton horizontal oil play located in Beaver County, Oklahoma, for the first half 2011, Unit had first sales on a total of 18 wells with an overall 30-day average rate of 208 Boe per day and an average working interest of approximately 91%. The average ultimate recovery for a Marmaton well is estimated at 130 MBoe comprised of 76% oil, 14% NGLs and 10% natural gas, with an average cost per well of $2.7 million. Unit has two rigs drilling in the Marmaton which should result in completing approximately 36 gross wells during the year at a total net cost of $60 million. Unit currently has leases on approximately 70,000 net acres in the play.

In the Granite Wash (GW) play located in the Texas Panhandle, Unit had first sales on four horizontal wells during the second quarter. Unit’s average working interest in these wells is 64%. Of the four new wells, one well was completed in the GW “A”, two in the GW “B” and one in the GW “C” zone. The average 30-day rate of production for these four wells was 6.0 MMcfe per day. For the first half of 2011, Unit had first sales on nine new GW horizontal wells with an average 30-day production rate of 6.2 MMcfe per day. The average ultimate recovery for a GW horizontal well is estimated at 4.3 Bcfe comprised of 8% oil, 39% NGLs and 53% natural gas with an average cost per well of $5.4 million. Unit plans to work three to four Unit rigs drilling Granite Wash horizontal wells in 2011 which should result in completing approximately 20 operated GW wells during the year with a projected total net cost of $85 million.

On July 20, 2011, Unit acquired certain producing properties from an unaffiliated seller for approximately $12.3 million in cash, subject to post-closing adjustments, consisting of 30 operated wells and 59 non-operated well interests located in Beaver, Harper and Ellis Counties in Oklahoma and Lipscomb County, Texas. The purchase price allocation was $8.4 million for proved properties and $3.9 million for acreage. The net proved developed reserves associated with the acquisition are estimated at 6.6 Bcfe (91% natural gas) with production of 1.7 MMcfe per day. The acquisition also included in excess of 12,000 net held by production acres in the area for future development.

On July 28, 2011, Unit entered into a purchase and sale agreement with an unaffiliated seller to acquire certain producing properties for $30.5 million in cash, subject to closing adjustments. The acquisition consists of more than 500 wells located principally in the Oklahoma Arkoma Woodford and Hartshorne Coal plays along with other properties located throughout Oklahoma and Texas. Unit’s preliminary proved reserves associated with the acquisition are approximately 31.2 Bcfe (99% natural gas), 83% of which is proved developed, with current production of approximately 7.8 MMcfe per day. The acquisition also includes approximately 55,000 net acres of which 96% is held by production. Closing of this acquisition, subject to customary due diligence, is expected to occur before the end of the third quarter.

Pinkston said: “We are pleased with the second quarter results from our drilling activity. This quarter marks the fourth consecutive quarter that production has increased. Our strategy of focusing on oil or NGLs rich prospects is evident in our second quarter 2011 production results of which 39% was oil and NGLs as compared to 30% in the second quarter of 2010 and 38% in the first quarter of 2011. For the second quarter, we completed 45 gross wells with a success rate of 93% compared to 39 gross wells with a 92% success rate during the second quarter of 2010. We are increasing our estimated capital expenditures for 2011 from $415 million to $435 million with the increase primarily being associated with acquiring acreage both within our existing core plays and in

areas outside of our core plays. For the year, we continue to plan to drill 180 gross wells; however, we are increasing our anticipated annual production guidance to 11.3 to 11.6 MMBoe from our previous guidance of 11.0 to 11.3 MMBoe, due primarily to favorable results associated with our activity during the first half of 2011.”

MID-STREAM SEGMENT INFORMATION

·	Increased second quarter 2011 liquids sold per day volumes, processing volumes per day, and gathering volumes per day by 27%, 10% and 4%, respectively, over the second quarter of 2010.

·	Construction of 16-mile pipeline and related compressor station in Preston County, West Virginia is on schedule to be operational during the third quarter of 2011.

·	Began construction activities for a gathering system and a compressor station in Tioga and Potter Counties, Pennsylvania.

·	Signed a letter of intent to construct a 7-mile, 16” pipeline in Allegheny and Butler Counties, Pennsylvania.

·	Increased estimated capital expenditures for 2011 from $47 million to $86 million.

Second quarter of 2011 per day processing volumes were 90,737 MMBtu while liquids sold volumes were 356,484 gallons per day, an increase of 10% and 27%, respectively, over the second quarter of 2010. Second quarter 2011 per day gathering volumes was 190,921 MMBtu, up 4% over the second quarter of 2010. Operating profit (as defined in the Selected Financial and Operational Highlights) for the second quarter was $7.6 million, an increase of $0.2 million from the second quarter of 2010 as increased revenue was offset by increased cost for gas purchased. As compared to the first quarter of 2011 operating profit decreased $3.1 million primarily due to the renegotiated contracts (effective April 1, 2011) with producers supplying gas to one of our processing plants that we had previously discussed during the first quarter.

For the first six months of 2011, processing volumes of 88,603 MMBtu per day and liquids sold volumes of 342,486 gallons per day increased 11% and 28%, respectively, from the first six months of 2010. Gathering volumes for the first six months of 2011 were 188,340 MMBtu per day, a 3% increase from the first six months of 2010.

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

	2nd Qtr 11	1st Qtr 11	4th Qtr 10	3rd Qtr 10	2nd Qtr 10	1st Qtr 10	4th Qtr 09	3rd Qtr 09	2nd Qtr 09
Gas gathered MMBtu/day	190,921	185,730	188,252	183,161	183,858	180,117	177,145	179,047	187,666
Gas processed MMBtu/day	90,737	86,445	85,195	84,175	82,699	76,513	77,501	77,923	75,481
Liquids sold Gallons/day	356,484	328,333	291,186	260,519	279,736	253,707	263,668	251,830	239,121

Pinkston said: “Processing and liquids sold volumes continue to increase and gas gathered volumes remain strong. In our Mid-continent operations, we are in the process of installing a high-efficiency processing plant at our Cashion system, located in Logan, Canadian, Oklahoma and Kingfisher Counties in Oklahoma, which will improve liquids recovery capability compared to our existing plant which it is replacing. In Grant County, Oklahoma, we have begun construction of a new gathering system, which will include a processing plant, and is anticipated to be completed during the third quarter of 2011. In connection with our Appalachian operations, we are in the final stages of constructing a 16-mile, 16" pipeline and a compressor station in Preston County, West Virginia, which will have a capacity of approximately 220.0 MMcf per day. We anticipate this pipeline will be operational during the third quarter of 2011. In addition to the Preston County pipeline, we began construction activities for a gathering system and a compressor station in Tioga and Potter Counties, Pennsylvania. This system will deliver gas to Dominion Transmission pipeline and is scheduled to be completed in the fourth quarter of this year or first quarter of 2012. We recently signed a letter of intent with a third party to construct a pipeline in Allegheny and Butler Counties of Pennsylvania. Land and survey work associated with the first phase, which consists of a 7-mile, 16” pipeline, has begun and construction is anticipated to be completed during the first half of 2012.”

FINANCIAL INFORMATION

Unit ended the second quarter of 2011 with working capital of $43.7 million, long-term debt of $250.0 million, and a debt to capitalization ratio of 12%. In May 2011, Unit completed an underwritten public offering of $250 million aggregate principal amount of senior subordinated notes due 2021, which bears interest at a rate of 6.625 percent per year. The notes were sold at 100 percent of par and Unit used the net proceeds primarily to repay its then outstanding borrowings under its credit facility. As of June 30, 2011, the company had no borrowings outstanding under its credit facility. The amount of the credit facility available to be borrowed is the lesser of the amount the company elects as the commitment amount (currently $325 million) or the value of the borrowing base as determined by the lenders (currently $532.5 million), but in either event, not to exceed the maximum credit facility amount of $400 million. We are in the process of renegotiating our credit facility to extend the maturity date past May 2012.

MANAGEMENT COMMENT

Larry Pinkston said: “We are pleased with the operating results of the second quarter and first half of 2011. For the remainder of the year, we will continue to focus our exploration efforts on our oil and natural gas liquids rich plays such as the Granite Wash and Marmaton and our contract drilling operations will continue responding to the demand for horizontal drilling by our customers by refurbishing and upgrading our existing rigs and, where appropriate, adding new drilling rigs to our fleet. Our mid-stream segment is always exploring for additional opportunities to grow its operations as is evident by the new projects in the Mid-continent and Appalachia areas. We are optimistic about the remainder of 2011 and we are well positioned, especially given the recent financing arrangements we have completed, to take advantage of growth opportunities that may arise in all three of our business segments.”

WEBCAST

Unit will webcast its second quarter earnings conference call live over the Internet on August 2, 2011 at 10:00 a.m. Central Time (11:00 a.m. Eastern). To listen to the live call, please go to www.unitcorp.com 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 listed on the New York Stock Exchange under the symbol UNT. For more information about Unit Corporation, visit its website at http://www.unitcorp.com.

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. A number of risks and uncertainties could cause actual results to differ materially from these statements, including the impact that the current decline in wells being drilled will have on production and drilling rig utilization, 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, as well as 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 the course of 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 as a result 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				Six Months Ended
	June 30,				June 30,
	2011		2010		2011		2010
Statement of Operations:
Revenues:
Contract drilling	$	115,183	$	72,061	$	213,171	$	132,915
Oil and natural gas		131,662		91,136		241,496		190,189
Gas gathering and processing		44,368		36,344		84,132		77,479
Other, net		282		5,062		101		10,570
Total revenues		291,495		204,603		538,900		411,153

Expenses:
Contract drilling:
Operating costs		64,238		46,541		117,082		87,441
Depreciation		19,218		16,445		36,515		30,231
Oil and natural gas:
Operating costs		33,417		23,817		64,198		48,851
Depreciation, depletion
and amortization		44,550		26,319		84,818		51,655
Gas gathering and processing:
Operating costs		36,789		28,938		65,844		61,664
Depreciation
and amortization		3,837		3,982		7,610		7,923
General and administrative		7,496		6,456		14,388		12,735
Interest, net		673		---		727		---
Total expenses		210,218		152,498		391,182		300,500
Income Before Income Taxes		81,277		52,105		147,718		110,653

Income Tax Expense:
Current		---		3,825		---		6,065
Deferred		31,458		16,105		56,872		36,260
Total income taxes		31,458		19,930		56,872		42,325

Net Income	$	49,819	$	32,175	$	90,846	$	68,328

Net Income per Common Share:
Basic	$	1.05	$	0.68	$	1.91	$	1.45
Diluted	$	1.04	$	0.68	$	1.89	$	1.43

Weighted Average Common
Shares Outstanding:
Basic		47,655		47,171		47,620		47,146
Diluted		47,983		47,656		47,944		47,671

	June 30,		December 31,
	2011		2010
Balance Sheet Data:
Current assets	$	189,831	$	188,180
Total assets	$	2,917,502	$	2,669,240
Current liabilities	$	146,133	$	147,128
Long-term debt	$	250,000	$	163,000
Other long-term liabilities	$	94,635	$	92,389
Deferred income taxes	$	613,476	$	556,106
Shareholders’ equity	$	1,813,258	$	1,710,617

	Six Months Ended June 30,
	2011			2010
Statement of Cash Flows Data:
Cash Flow From Operations before Changes
in Operating Assets and Liabilities (1)	$	284,726		$	191,814
Net Change in Operating Assets and Liabilities		(25,216	)		(14,047	)
Net Cash Provided by Operating Activities	$	259,510		$	177,767
Net Cash Used in Investing Activities	$	(351,942	)	$	(277,265	)
Net Cash Provided by Financing Activities	$	92,296		$	100,119

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2011		2010		2011		2010
Contract Drilling Operations Data:
Rigs Utilized		73.1		58.1		71.6		54.5
Operating Margins (2)		44%		35%		45%		34%
Operating Profit Before Depreciation (2) ($MM)	$	50.9	$	25.5	$	96.1	$	45.5

Oil and Natural Gas Operations Data:
Production:
Oil – MBbls		591		321		1,147		623
Natural Gas Liquids - MBbls		567		388		1,046		765
Natural Gas - MMcf		10,946		9,701		21,178		19,735
Average Prices:
Oil price per barrel received Oil price per barrel received, excluding hedges	$ $	89.77 101.02	$ $	66.93 74.49	$ $	87.14 96.06	$ $	67.12 75.08
NGLs price per barrel received NGLs price per barrel received, excluding hedges	$ $	45.49 46.58	$ $	33.37 33.10	$ $	42.80 43.72	$ $	38.01 37.88
Natural Gas price per Mcf received Natural Gas price per Mcf received, excluding hedges	$ $	4.30 3.97	$ $	5.62 3.72	$ $	4.29 3.91	$ $	5.79 4.44
Operating Profit Before DD&A (2) ($MM)	$	98.2	$	67.3	$	177.3	$	141.3

Mid-Stream Operations Data:
Gas Gathering - MMBtu/day		190,921		183,858		188,340		181,998
Gas Processing - MMBtu/day		90,737		82,699		88,603		79,623
Liquids Sold – Gallons/day		356,484		279,736		342,486		266,793
Operating Profit Before Depreciation
and Amortization (2) ($MM)	$	7.6	$	7.4	$	18.3	$	15.8

_____________

(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 account 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 and our drilling segment’s average daily operating margin before elimination of intercompany drilling rig profit.

Below is a reconciliation of GAAP financial measures to non-GAAP financial measures for the three and six months ended June 30, 2011 and 2010. 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

	Six Months Ended June 30,
		2011			2010
	(In thousands)
Net cash provided by operating activities	$	259,510		$	177,767
Subtract:
Net change in operating assets and liabilities		(25,216	)		(14,047	)
Cash flow from operations before changes
in operating assets and liabilities	$	284,726		$	191,814

________________

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						Six Months Ended
	March 31,		June 30,				June 30,
	2011		2011		2010		2011		2010
	(In thousands)
Contract drilling revenue	$	97,988	$	115,183	$	72,061	$	213,171	$	132,915
Contract drilling operating cost		52,844		64,238		46,541		117,082		87,441
Operating profit from contract drilling		45,144		50,945		25,520		96,089		45,474
Add: Elimination of intercompany rig profit		5,044		5,092		1,453		10,136		1,829
Operating profit from contract drilling
before elimination of intercompany
rig profit		50,188		56,037		26,973		106,225		47,303
Contract drilling operating days		6,214		6,695		5,288		12,909		9,873
Average daily operating margin before
elimination of intercompany rig profit	$	8,077	$	8,370	$	5,101	$	8,229	$	4,791

________________

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 of 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.

Delaware		1-9260		73-1283193
(State or other jurisdiction of incorporation)		(Commission File Number)		(I.R.S. Employer Identification No.)

7130 South Lewis, Suite 1000, Tulsa, Oklahoma		74136
(Address of principal executive offices)		(Zip Code)

	Unit Corporation


Date: August 2, 2011	By:	/s/ David T. Merrill
		David T. Merrill Chief Financial Officer and Treasurer