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 3, 2010

UNIT CORPORATION REPORTS 2010 SECOND QUARTER RESULTS

Tulsa, Oklahoma . . . Unit Corporation (NYSE - UNT) reported today its net income of $32.2 million, or $0.68 per diluted share, for the three months ended June 30, 2010, compared to net income of $32.0 million, or $0.68 per diluted share, for the three months ended June 30, 2009. Total revenues for the second quarter of 2010 were $204.6 million (35% contract drilling, 45% oil and natural gas, and 18% mid-stream), compared to total revenues for the second quarter of 2009 of $164.1 million (30% contract drilling, 55% oil and natural gas, and 14% mid-stream).

For the first six months of 2010, Unit reported net income of $68.3 million, or $1.43 per diluted share, compared to a net loss of $115.5 million, or $2.46 per diluted share, for the six months ended June 30, 2009. Included in the 2009 results was a noncash ceiling test write down of $281.2 million ($175.1 million after tax, or $3.72 per diluted share) that occurred in the first quarter. The ceiling test write down was required to reduce the carrying value of the company’s oil and natural gas properties because of significantly lower commodity prices at the end of the first quarter 2009. If the ceiling test write down had not been required, net income for the first six mont hs of 2009 would have been $59.6 million, or $1.26 per diluted share (see Non-GAAP Financial Measures below). Total revenues for the first six months of 2010 were $411.2 million (32% contract drilling, 46% oil and natural gas, and 19% mid-stream), compared to $365.1 million (38% contract drilling, 49% oil and natural gas, and 12% mid-stream) for the first six months of 2009.

CONTRACT DRILLING SEGMENT INFORMATION

The average number of drilling rigs used in the second quarter of 2010 was 58.1, an increase of 84% from the second quarter of 2009, and an increase of 14% from the first quarter of 2010. Contract drilling per day rig rates for the second quarter of 2010 averaged $14,915, down 14%, or $2,420, from the second quarter of 2009, and up 6%, or $788, from the first quarter of 2010. Average per day operating margins for the second quarter of 2010 were $5,101 (before elimination of intercompany drilling rig profit of $1.5 million) as compared to $7,138 (before elimination of intercompany drilling rig profit of $0.4 million) for the second quarter of 2009, down 29%, and compared to $4,435 (before elimination of intercompany drilling rig profit and bad debt expense of $0.4 million) for the first quarter 2010, up 15% or $666 (in each case with regard to the elimination of intercompany drilling rig profit see Non-GAAP Financial Measures below). Included in the average operating margin amounts for the second quarter 2010, the second quarter 2009, and first quarter 2010 was an approximate per day amount of $6, $163, and $28, respectively, resulting from early termination fees associated with the cancellation of long-term contracts. Excluding these early termination fees, average per day operating margins for the second quarter of 2010 were $5,095, an increase of $688 per day or 16% as compared to $4,407 for the first quarter of 2010.

For the first six months of 2010, Unit averaged 54.5 drilling rigs working, up 29% from 42.1 drilling rigs working during the first six months of 2009. Average per day operating margins for the first six months of 2010 were $4,791 (before elimination of intercompany drilling rig profit of $1.8 million) as compared to $7,807 (before elimination of intercompany drilling rig profit of $1.1 million) for the first six months of 2009, a decrease of 39% (in each case with regard to the elimination of intercompany drilling rig profit see Non-GAAP Financial Measures below). Included in the average operating margin amounts for the first six months of 2010 and 2009 was an approximate per day amount of $15 and $61, respectively, resulting from early termination fees associated with the cancel lation of long-term contracts. Excluding early termination fees, average operating margins for the first six months of 2010 were $4,776 per day, a decrease of $2,970 per day or 38% as compared to $7,746 per day for the first six months of 2009.

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

	2nd Qtr 10	1st Qtr 10	4th Qtr 09	3rd Qtr 09	2nd Qtr 09	1st Qtr 09	4th Qtr 08	3rd Qtr 08	2nd Qtr 08
Rigs	123	125	130	130	131	131	132	131	131
Utilization	47%	40%	28%	26%	24%	40%	74%	85%	80%

Larry Pinkston, Unit's Chief Executive Officer and President, said: “During the second quarter, we experienced an increase in the demand for our drilling rigs and dayrates, especially on drilling rigs drilling horizontal wells. We completed the previously announced sale of eight of our idle mechanical drilling rigs. We are using the sales proceeds to refurbish and upgrade certain drilling rigs in our fleet that we intend to target toward horizontal drilling activity. With the completed sale, our drilling rig fleet now totals 123. Currently, 71 of the 123 drilling rigs are under contract. Long-term contracts for which the original terms ranged from six months to two years in l ength are in place for 42 of the 71 drilling rigs currently under contract for work. Thirteen of these contracts are up for renewal during 2010, 28 are up for renewal during 2011 and one is up for renewal in 2012.”

OIL AND NATURAL GAS SEGMENT INFORMATION

·	Drilled 39 and 66 gross wells during the 2010 second quarter and first six months, respectively.

·	Completed a property acquisition that includes approximately 45,000 net acres and 11 producing oil wells.

·	Sold a natural gas pipeline of which we owned 60%.

·	Approximately 68% of anticipated natural gas production and 65% of anticipated crude oil production for 2010 is hedged.

·	Plan to drill 175 wells during 2010 with a revised production estimate of 62.0 to 63.0 Bcfe.

Second quarter 2010 production was 321,000 barrels of oil, in comparison to 348,000 barrels of oil in the second quarter of 2009, down 8%. Natural gas liquids (NGLs) production during the second quarter of 2010 was 388,000 barrels in comparison to 391,000 barrels in the second quarter of 2009, down 1%. Second quarter 2010 natural gas production was down 12% to 9.7 billion cubic feet (Bcf) compared to 11.0 Bcf for the comparable quarter of 2009. Second quarter 2010 equivalent production totaled 14.0 Bcfe, down 10% from the second quarter of 2009. Total production for the first six months of 2010 was 28.1 Bcfe, down 12% over the 31.7 Bcfe produced during the first six months of 2009.

Unit’s average natural gas price, including the effects of hedges, for the second quarter of 2010 increased 2% to $5.62 per thousand cubic feet (Mcf) as compared to $5.49 per Mcf for the second quarter of 2009. Unit’s average oil price, including the effects of hedges, for the second quarter of 2010 was $66.93 per barrel compared to $54.84 per barrel for the second quarter of 2009, up 22%, and Unit’s average NGLs price, including the effects of hedges, for the second quarter of 2010 was $33.37 per barrel compared to $23.88 per barrel for the second quarter of 2009, up 40%. For the first six months of 2010, Unit’s average natural gas price, including the effects of hedges, increased 6% to $5.79 per Mcf as compared to $5.47 per Mcf for the first six mo nths of 2009. Unit’s average oil price, including the effects of hedges, for the first six months of 2010 was $67.12 per barrel compared to $52.69 per barrel during the first six months of 2009, a 27% increase. Unit’s average NGLs price, including the effects of hedges, for the first six months of 2010 was $38.01 per barrel compared to $21.29 per barrel during the first six months of 2009, a 79% increase.

For 2010, approximately 68% of the company’s anticipated average daily natural gas production is hedged, 65% of its anticipated daily oil production is hedged, and 11% of its anticipated daily natural gas liquids production is hedged. The natural gas production is hedged under swap contracts at a comparable average NYMEX price of $6.95. The average basis differential for the swaps is ($0.66). Of the oil hedges, 60% are under swap contracts at an average price of $61.36 per barrel and 40% are under a collar contract with a floor of $67.50 per barrel and a ceiling of $81.53 per barrel. The natural gas liquids production is hedged under swap contracts at an average price of $41.12 per barrel.

For 2011, 15,000 MMBtu per day of the company’s natural gas production is hedged, 2,500 Bbls per day of its oil production is hedged and 504 Bbls per day of its natural gas liquids production is hedged. The natural gas production is hedged under swap contracts at a comparable average NYMEX price of $5.56. The average basis differential for the swaps is ($0.14). The oil production is hedged under swap contracts at an average price of $80.32 per barrel. The natural gas liquids production is hedged under swap contracts at an average price of $40.74 per barrel.

For 2012, approximately 15,000 MMBtu per day of the company’s natural gas production is hedged and 1,500 Bbls per day of its oil production is hedged. The natural gas production is hedged under swap contracts at a comparable average NYMEX price of $5.90. The average basis differential for the swaps is ($0.28). The oil production is hedged under swap contracts at an average price of $82.49 per barrel.

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

	2nd Qtr 10	1st Qtr 10	4th Qtr 09	3rd Qtr 09	2nd Qtr 09	1st Qtr 09	4th Qtr 08	3rd Qtr 08	2nd Qtr 08
Production, Bcfe	14.0	14.1	14.3	14.7	15.4	16.3	16.8	15.9	16.0
Production, MMcfe/day	153.3	156.8	155.8	159.4	169.6	180.9	182.6	172.4	175.3
Realized Price, Mcfe (1)	$6.37	$6.82	$6.12	$5.92	$5.75	$5.48	$6.21	$9.49	$10.19
Wells Drilled (gross)	39	27	37	21	16	21	67	82	72
Success Rate	92%	96%	92%	90%	100%	90%	90%	89%	90%

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

During the second quarter of 2010, this segment drilled 39 wells with a success rate of 92% compared to 16 wells with a 100% success rate during the second quarter of 2009.

In the Bakken play in North Dakota, Unit owns a 25% working interest in the Marty #1-20 which is currently flowing back after fracture stimulation at rates of approximately 1,500 barrels of oil per day and 1.6 MMcf per day. The well was drilled with a 5,736’ lateral and fracture stimulated in 15 stages. This is the second high volume oil well in the Williams County, ND Stockyard Creek Prospect where Unit owns approximately 11,500 gross (2,700 net) acres and expects to have one drilling rig operating during the remainder of 2010. In McKenzie County, ND, Unit owns a 16% working interest in the Dodge #4-6/7 HR which was recently completed at rates of approximately 2,465 barrels of oil per day and 1.6 MMcf per day. The well was drilled with an 8,846’ lateral and fracture stimulate d in 24 stages. Unit owns approximately 27,000 gross (5,400 net) acres in the Antelope Prospect and anticipates one rig drilling for the rest of this year.

In the Haynesville Shale play in Shelby County, TX, Unit owns a 55% working interest in the Smith #1H which was recently completed flowing at rates of 3.5 MMcf per day with 5,800 pounds of flowing tubing pressure. The well is being curtailed due to current pipeline constraints which are expected to be resolved in September. The well was drilled with a lateral of 3,300’ and fracture stimulated with eight stages. Unit owns approximately 16,000 gross (11,000 net) acres in the prospect area and anticipates drilling two additional wells in 2010.

In June, this segment closed the acquisition of oil and natural gas properties from certain unaffiliated third parties for approximately $75.0 million in cash, subject to post-closing adjustments. The acquisition includes approximately 45,000 net acres and 11 producing oil wells and is focused on the Marmaton horizontal oil play located primarily in Beaver County, Oklahoma. This acquisition, along with Unit’s existing leasehold position in this Marmaton play, provides Unit with more than 56,000 net undeveloped leasehold acres in this play. Proved developed producing (PDP) net reserves associated with the 11 acquired producing wells is approximately 900,000 barrels of oil equivalent (Boe) — consisting of 600,000 barrels of oil, 200,000 barrels of natural gas liquids (NGLs), and 700 million cubi c feet (MMcf) of natural gas. Net production from these wells in April 2010 averaged approximately 850 barrels of oil per day and 1.0 MMcf of natural gas per day.

Pinkston said: “This acquisition complements the presence that we already have in the Anadarko Basin, one of our core areas of operations. It also adds oil production and reserves to our existing portfolio and is in line with our focus on oil and rich gas opportunities. We anticipate working two to three drilling rigs in this play in which we have identified approximately 300 potential well locations with expected average reserves per well of 120,000 barrels of oil equivalent. Projected average completed well costs for wells in this play are approximately $2.0 million. Also during the second quarter, we sold a gas pipeline, located in the Haynesville Shale play in Shelby County, Texas, for $17 million, of which we owned 60%.”

“The first half of 2010 has been a challenging period for us in establishing the momentum planned for our 2010 drilling program. During the first and second quarters of 2010, we drilled 27 wells and 39 wells, respectively. Our first quarter 2010 drilling activity was slowed down by unusually wet weather, especially in the Texas Panhandle Granite Wash play, and operational delays as we transition to drilling primarily horizontal wells. While the number of wells drilled increased 44% from the first quarter to the second quarter, 46% of the wells drilled have not come online. The delays in getting wells online are primarily due to delays in fracture stimulation services and connections to gathering systems. Currently, we anticipate these delays will continue throughout the year due to limited availability of these services. As a result, we are revising our 2010 production guidance to approximately 62.0 to 63.0 Bcfe, with actual results subject to the timing of third party services. The number of wells we plan to participate in drilling and the level of capital expenditures remains unchanged for 2010 at 175 wells and $365 million, respectively.”

MID-STREAM SEGMENT INFORMATION

·	Increased second quarter 2010 liquids sold per day volumes and processing volumes per day by 17% and 10%, respectively, over second quarter of 2009.

·	In the process of adding two new processing plants to existing gathering systems.

Second quarter of 2010 per day processing volumes were 82,699 MMBtu while liquids sold volumes were 279,736 gallons per day, an increase of 10% and 17%, respectively, over second quarter of 2009. Second quarter 2010 per day gathering volumes were 183,858 MMBtu, down 2% over the second quarter of 2009. Operating profit (as defined in the Selected Financial and Operational Highlights) for the second quarter was $7.4 million, an increase of $3.4 million from the second quarter of 2009, due primarily to increased liquids prices, which resulted in increased processing margins.

For the first six months of 2010, processing volumes of 79,623 MMBtu per day and liquids sold volumes of 266,793 gallons per day increased 7% and 17%, respectively, from the first six months of 2009. Gathering volumes for the first six months of 2010 were 181,998 MMBtu per day, a 4% decrease from the first six months of 2009.

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

	2nd Qtr 10	1st Qtr 10	4th Qtr 09	3rd Qtr 09	2nd Qtr 09	1st Qtr 09	4th Qtr 08	3rd Qtr 08	2nd Qtr 08
Gas gathered MMBtu/day	183,858	180,117	177,145	179,047	187,666	192,320	187,585	195,914	205,397
Gas processed MMBtu/day	82,699	76,513	77,501	77,923	75,481	72,650	72,491	71,260	67,545
Liquids sold Gallons/day	279,736	253,707	263,668	251,830	239,121	218,762	197,428	199,805	202,130

Unit’s mid-stream segment operates three natural gas treatment plants, owns and operates eight processing plants, 33 active gathering systems and approximately 846 miles of pipeline.

Pinkston said: “Gas processed volumes, liquids sold volumes as well as gas gathered volumes all continued to increase and remained strong in the second quarter. We are in the process of adding two new processing plants to existing gathering systems. Construction on the 50.0 MMcf per day processing plant at our Hemphill facility in the Texas Panhandle is proceeding as planned with a completion date scheduled for the fourth quarter of this year. We are also in the process of adding a second processing plant, a 6.0 MMcf per day plant, at our Remington gathering facility in Osage County, Oklahoma. That plant should be completed and placed in service du ring the third quarter of 2010. We are continuing our activities in the Appalachian Basin with several existing projects moving forward as well as exploring various new opportunities that arise in the area.”

FINANCIAL INFORMATION

Unit ended the second quarter of 2010 with working capital of $47.2 million, long-term debt of $130.0 million, and a debt to capitalization ratio of 7%. Under the company’s credit facility, the amount 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 under the credit facility (currently $500 million), but in either event not to exceed the maximum credit facility amount of $400 million.

MANAGEMENT COMMENT

Larry Pinkston said: “The challenges to our industry remain, yet we are experiencing and benefitting from the increases in demand for drilling by exploration and production companies and are continuing to refurbish and upgrade certain drilling rigs in our

fleet. As evidenced by our recent oil and natural gas property acquisition, our focus continues to be on developing areas of oil or rich gas. While our 2010 exploration activities have started slower than we would like, we believe the results of our efforts will be evident throughout the second half of the year and carry into 2011.”

WEBCAST

Unit will webcast its second quarter earnings conference call live over the Internet on August 3, 2010 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 twelve months.

_____________________________________________________

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 natur al 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, availability and timing of obtaining third party services used in the drilling or completion of its oil and gas wells, 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 up date 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,
	2010		2009		2010		2009
Statement of Operations:
Revenues:
Contract drilling	$	72,061	$	49,883	$	132,915	$	138,582
Oil and natural gas		91,136		89,601		190,189		178,505
Gas gathering and processing		36,344		23,233		77,479		45,376
Other		5,062		1,357		10,570		2,673
Total revenues		204,603		164,074		411,153		365,136

Expenses:
Contract drilling:
Operating costs		46,541		29,779		87,441		80,109
Depreciation		16,445		10,261		30,231		22,880
Oil and natural gas:
Operating costs		23,817		17,249		48,851		42,065
Depreciation, depletion
and amortization		26,319		26,149		51,655		64,155
Impairment of oil and natural gas properties		---		---		---		281,241
Gas gathering and processing:
Operating costs		28,938		19,199		61,664		39,876
Depreciation
and amortization		3,982		4,110		7,923		8,171
General and administrative		6,456		5,493		12,735		11,582
Interest, net		---		61		---		538
Total expenses		152,498		112,301		300,500		550,617
Income (Loss) Before Income Taxes		52,105		51,773		110,653		(185,481	)

Income Tax Expense (Benefit):
Current		3,825		1,247		6,065		1,247
Deferred		16,105		18,495		36,260		(71,266	)
Total income taxes		19,930		19,742		42,325		(70,019	)

Net Income (Loss)	$	32,175	$	32,031	$	68,328	$	(115,462	)

Net Income (Loss) per Common Share:
Basic	$	0.68	$	0.68	$	1.45	$	(2.46	)
Diluted	$	0.68	$	0.68	$	1.43	$	(2.46	)
Weighted Average Common
Shares Outstanding:
Basic		47,171		47,008		47,146		46,965
Diluted		47,656		47,358		47,671		46,965

	June 30,		December 31,
	2010		2009
Balance Sheet Data:
Current assets	$	156,391	$	128,095
Total assets	$	2,461,706	$	2,228,399
Current liabilities	$	109,241	$	105,147
Long-term debt	$	130,000	$	30,000
Other long-term liabilities	$	82,234	$	81,126
Deferred income taxes	$	484,058	$	446,316
Shareholders’ equity	$	1,656,173	$	1,565,810

	Six Months Ended June 30,
	2010			2009
Statement of Cash Flows Data:
Cash Flow From Operations before Changes
in Operating Assets and Liabilities (1)	$	191,814		$	198,208
Net Change in Operating Assets and Liabilities		(14,047	)		110,634
Net Cash Provided by Operating Activities	$	177,767		$	308,842
Net Cash Used in Investing Activities	$	(277,265	)	$	(181,965	)
Net Cash Provided by (Used in) Financing Activities	$	100,119		$	(126,504	)

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2010		2009		2010		2009
Contract Drilling Operations Data:
Rigs Utilized		58.1		31.6		54.5		42.1
Operating Margins (2)		35%		40%		34%		42%
Operating Profit Before Depreciation (2) ($MM)	$	25.5	$	20.1	$	45.5	$	58.5

Oil and Natural Gas Operations Data:
Production:
Oil – MBbls		321		348		623		691
Natural Gas Liquids - MBbls		388		391		765		784
Natural Gas - MMcf		9,701		10,999		19,735		22,861
Average Prices:
Oil price per barrel received Oil price per barrel received, excluding hedges	$ $	66.93 74.49	$ $	54.84 53.61	$ $	67.12 75.08	$ $	52.69 46.11
NGLs price per barrel received NGLs price per barrel received, excluding hedges	$ $	33.37 33.10	$ $	23.88 23.88	$ $	38.01 37.88	$ $	21.29 21.29
Natural Gas price per Mcf received Natural Gas price per Mcf received, excluding hedges	$ $	5.62 3.72	$ $	5.49 2.71	$ $	5.79 4.44	$ $	5.47 3.11
Operating Profit Before DD&A and
Impairment (2) ($MM)	$	67.3	$	72.4	$	141.3	$	136.4

Mid-Stream Operations Data:
Gas Gathering - MMBtu/day		183,858		187,666		181,998		189,980
Gas Processing - MMBtu/day		82,699		75,481		79,623		74,074
Liquids Sold – Gallons/day		279,736		239,121		266,793		228,998
Operating Profit Before Depreciation
and Amortization (2) ($MM)	$	7.4	$	4.0	$	15.8	$	5.5

_____________

(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 and impairment, 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 net income excluding the effect of the impairment of our oil and natural gas properties, earnings per share excluding the effect of the impairment of our oil and natural gas properties, cash flow from operations before changes in working capital and our drilling segment’s average daily operating margin before elimination of 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, 2010 and 2009. 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 Net Income and Earnings per Share

Excluding the Effect of Impairment of Oil and Natural Gas Properties

	Three Months Ended					Six Months Ended
	June 30,					June 30,
		2010		2009		2010		2009
	(In thousands)
Net income excluding impairment of oil and
natural gas properties:
Net income (loss)	$	32,175	$	32,031	$	68,328	$	(115,462	)
Add:
Impairment of oil and natural gas properties
(net of income tax)		---		---		---		175,072
Net income excluding impairment of oil and
natural gas properties	$	32,175	$	32,031	$	68,328	$	59,610

Diluted earnings per share excluding
impairment of oil and natural gas properties:
Diluted earnings per share Add: Diluted earnings per share from impairment	$	0.68	$	0.68	$	1.43	$	(2.46	)
of oil and natural gas properties		---		---		---		3.72
Diluted earnings per share excluding
impairment of oil and natural gas properties	$	0.68	$	0.68	$	1.43	$	1.26

________________

We have included the net income excluding impairment of oil and natural gas properties and diluted earnings per share excluding impairment of oil and natural gas properties 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.

·	The impairment of oil and natural gas properties does not occur on a recurring basis and the amount and timing of impairments cannot be reasonably estimated for budgeting purposes and is therefore typically not included for forecasting operating results.

Unit Corporation

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

	Six Months Ended June 30,
		2010			2009
	(In thousands)
Net cash provided by operating activities	$	177,767		$	308,842
Subtract:
Net change in operating assets and liabilities		(14,047	)		110,634
Cash flow from operations before changes
in operating assets and liabilities	$	191,814		$	198,208

________________

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 Rig Profit

	Three Months Ended					Six Months Ended
	June 30,					June 30,
		2010		2009		2010		2009
		(In thousands)
Contract drilling revenue	$	72,061	$	49,883	$	132,915	$	138,582
Contract drilling operating cost		46,541		29,779		87,441		80,109
Operating profit from contract drilling		25,520		20,104		45,474		58,473
Add: Elimination of intercompany rig profit and bad debt expense		1,453		440		1,829		1,065
Operating profit from contract drilling
before elimination of intercompany
rig profit		26,973		20,544		47,303		59,538
Contract drilling operating days		5,288		2,878		9,873		7,626
Average daily operating margin before
elimination of rig profit	$	5,101	$	7,138	$	4,791	$	7,807

________________

We have included the average daily operating margin before elimination of 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.

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 3, 2010	By:	/s/ David T. Merrill
		David T. Merrill Chief Financial Officer and Treasurer