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…

July 31, 2012

UNIT CORPORATION REPORTS 2012 SECOND QUARTER AND FIRST SIX MONTHS RESULTS

Tulsa, Oklahoma . . . Unit Corporation (NYSE - UNT) reported a net loss of $19.3 million, or $0.40 per diluted share, for the three months ended June 30, 2012, compared to net income of $49.8 million, or $1.04 per diluted share for the second quarter of 2011. Included in the second quarter 2012 results was a non-cash ceiling test write down of $115.9 million ($72.1 million after tax, or $1.50 per diluted share). The ceiling test write down was required to reduce the carrying value of the company’s oil and natural gas properties resulting from significantly lower commodity prices during the second quarter of 2012. Excluding the ceiling test write down, net income for the second quarter of 2012 would have been $52.8 million, or $1.10 per diluted share, a 6% increase over the second quarter 2011 (see Non-GAAP Financial Measures below). Total revenues for the second quarter of 2012 were $329.9 million (45% contract drilling, 40% oil and natural gas, and 15% mid-stream), compared to $291.5 million (40% contract drilling, 45% oil and natural gas, and 15% mid-stream) for the second quarter of 2011.

For the first six months of 2012, Unit reported net income of $33.1 million, or $0.69 per diluted share. For the same period in 2011, net income was $90.8 million, or $1.89 per diluted share. Excluding the effect of the second quarter 2012 ceiling test write down, net income for the first six months would have been $105.3 million, or $2.19 per diluted share, an increase of 16% over the same period in 2011 (see Non-GAAP Financial Measures below). Total revenues for the first six months of 2012 were $662.3 million (43% contract drilling, 40% oil and natural gas, and 16% mid-stream), compared to $538.9 million (40% contract drilling, 45% oil and natural gas, and 15% mid-stream) for the first six months of 2011.

CONTRACT DRILLING SEGMENT INFORMATION

The average number of drilling rigs used in the second quarter of 2012 was 76.7, an increase of 5% over the second quarter of 2011, and a decrease of 6% from the first quarter of 2012. Per day drilling rig rates for the second quarter of 2012 averaged $20,128, an increase of 7%, or $1,267, from the second quarter of 2011, and an increase of 1%, or $290, from the first quarter of 2012. Average per day operating margin for the second quarter of 2012 was $11,130 (before elimination of intercompany drilling rig profit of $4.7 million). This compares to $8,370 (before elimination of intercompany drilling rig profit of $5.1 million) for the second quarter of 2011, an increase of 33%, or $2,760. As compared to the first quarter of 2012 ($9,414 before elimination of intercompany drilling rig profit of $4.3 million), second quarter 2012 operating margin increased 18% or $1,716 ( in each case with regard to the elimination of intercompany drilling rig profit see Non-GAAP Financial Measures below). Approximately $2,188 per day of the second quarter 2012 average operating margin was the result of early termination fees resulting from the cancellation of certain long-term contracts.

For the first six months of 2012, Unit averaged 79.1 drilling rigs working, up 10% from 71.6 drilling rigs working during the first six months of 2011. Average per day operating margin for the first six months of 2012 was $10,246 (before elimination of intercompany drilling rig profit of $9.0 million) as compared to $8,229 (before elimination of intercompany drilling rig profit of $10.1 million) for the first six months of 2011, an increase of 25% (in each case with regard to the elimination of intercompany drilling rig profit see Non-GAAP Financial Measures below). Approximately $1,109 per day of the first six months of 2012 average operating margin was the result of early termination fees resulting from the cancellation of certain long-term contracts.

Larry Pinkston, Unit’s Chief Executive Officer and President, said: “We are pleased with the results that our contract drilling segment has been able to attain. As the industry has continued to transition to drilling horizontal or directional wells, we have been able to respond to that demand by refurbishing our existing drilling rigs or adding new drilling rigs. Approximately 97% of our drilling rigs working today are drilling for oil or natural gas liquids (NGLs) and approximately 96% are drilling horizontal or directional wells. During the second quarter of 2012, we placed a new 1,500 horsepower, diesel-electric drilling rig in North Dakota under a three-year contract. Currently, we have 128 drilling rigs in our fleet, of which 73 are under contract. Long-term contracts (contracts with original terms ranging from six months to two years in length) are in place for 39 of those 73 drilling rigs. Of these contracts, 13 are up for renewal during the third quarter of 2012, nine during the fourth quarter of 2012, and 17 in 2013 and beyond. During the quarter, we had three drilling rigs that were under long-term contracts that were terminated early by the operator. The early termination fees associated with those contracts are approximately $15 million.”

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

	2nd Qtr 12	1st Qtr 12	4th Qtr 11	3rd Qtr 11	2nd Qtr 11	1st Qtr 11	4th Qtr 10	3rd Qtr 10	2nd Qtr 10
Rigs	128	127	127	126	123	122	121	123	123
Utilization	60%	64%	65%	63%	60%	58%	59%	54%	47%

OIL AND NATURAL GAS SEGMENT INFORMATION

·	Second quarter 2012 production was 3.3 MMBoe, an increase of 12% over the second quarter 2011.

·	44% of second quarter 2012 production was oil and NGLs compared to 39% for the second quarter of 2011.

·	Production guidance for 2012, excluding the impact of acquisitions, is 13.2 to 13.5 MMBoe, an increase of 9% to 12% over 2011.

·	Unit has drilled a significant multi-zone, deeper Wilcox field discovery located in Polk County, Texas.

The second quarter marks the tenth consecutive quarter that liquids (oil and NGLs) production has increased. Unit’s strategy of drilling oil or NGLs rich wells is evident in its production results. Liquids production represented 44% and 42% of total equivalent production during the second and first quarters of 2012, respectively. Second quarter 2012 total equivalent production increased 12% to 3.3 MMBoe over the second quarter of 2011, while total liquids production for the second quarter of 2012 increased 26% over the comparable quarter of 2011. Second quarter 2012 oil production was 786,000 barrels, in comparison to 591,000 barrels for the same period of 2011, an increase of 33%. NGLs production during the second quarter of 2012 was 674,000 barrels, an increase of 19% when compared to 567,000 barrels for the same period of 2011. Second quarter 2012 natural gas production increased 3% to 11.3 billion cubic feet (Bcf) compared to 10.9 Bcf for the comparable quarter of 2011. Total production for the first six months of 2012 was 6.6 MMBoe.

Unit’s average natural gas price, including the effects of its hedges, for the second quarter of 2012 decreased 30% to $3.03 per thousand cubic feet (Mcf) as compared to $4.30 per Mcf for the second quarter of 2011. Unit’s average oil price, including the effects of its hedges, for the second quarter of 2012 increased 3% to $92.43 per barrel compared to $89.77 per barrel for the second quarter of 2011. Unit’s average NGLs price, including the effects of its hedges, for the second quarter of 2012 was $32.34 per barrel compared to $45.49 per barrel for the second quarter of 2011, a decrease of 29%. For the first six months of 2012, Unit’s average natural gas price, including the effects of its hedges, decreased 26% to $3.19 per Mcf as compared to $4.29 per Mcf for the first six months of 2011. Unit’s average oil price, including the effects of its hedges, for the first six months of 2012 was $94.04 per barrel compared to $87.14 per barrel during the first six months of 2011, an 8% increase. Unit’s average NGLs price, including the effects of its hedges, for the first six months of 2012 was $35.53 per barrel compared to $42.80 per barrel during the first six months of 2011, a 17% decrease.

For 2012, Unit hedged approximately 6,100 Bbls per day of oil production and approximately 50,000 MMBtu per day of natural gas production. The oil production is hedged under swap contracts at an average price of $97.55 per barrel. The natural gas production is hedged under swap contracts at a comparable average NYMEX price of $5.09. The average basis differential for the applicable swap is ($0.28). For 2012, Unit hedged NGLs of 1,966 Bbls per day in the first quarter, 926 Bbls per day in the second quarter, and 380 Bbls per day in the third and fourth quarters. The NGLs are hedged under swap contracts at an average price of

$42.53 per barrel in the first quarter, $41.15 per barrel in the second quarter, $51.28 per barrel in the third quarter, and $50.28 per barrel in the fourth quarter.

For 2013, Unit has hedged 5,000 Bbls per day of its oil production and 80,000 MMBtu per day of natural gas production. The oil production is hedged under swap contracts at an average price of $100.19 per barrel. Of the natural gas production, 60,000 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 $3.56. The collar transaction was done at a comparable average NYMEX floor price of $3.25 and ceiling price of $3.72.

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

	2nd Qtr 12	1st Qtr 12	4th Qtr 11	3rd Qtr 11	2nd Qtr 11	1st Qtr 11	4th Qtr 10	3rd Qtr 10	2nd Qtr 10
Oil and NGL Production, MBbl	1,460.2	1,375.2	1,359.9	1,197.5	1,158.6	1,034.0	925.5	756.5	708.6
Natural Gas Production, Bcf	11.3	11.4	11.4	11.6	10.9	10.2	10.6	10.4	9.7
Production, MBoe	3,341	3,275	3,255	3,123	2,983	2,739	2,698	2,478	2,325
Production, MBoe/day	36.7	36.0	35.4	33.9	32.8	30.4	29.3	27.0	25.6
Realized Price, Boe (1)	$38.49	$40.51	$42.65	$41.75	$42.23	$40.00	$41.58	$38.16	$38.22

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

In Polk County, Texas, Unit has drilled a significant multi-zone, deeper Wilcox field discovery. To date, Unit has drilled four wells on the prospect averaging 226 feet of potential net pay with an average working interest of approximately 94%. First production in the new discovery started in July 2011 and currently three wells are producing at a combined approximate rate of 9.7 MMcf per day, 260 barrels of oil per day and 1,090 barrels of NGLs per day, or an equivalent rate of 17.8 MMcfe per day from an average of 26 feet of perforations per well. The fourth well, which is approximately 5,200 feet away from the other three wells, is currently being completed for production. Unit’s estimated total net resource potential for this prospect area is estimated at approximately 159 Bcfe, consisting of approximately 2.2 million barrels of oil, 9.2 million barrels of NGLs, and 90.4 Bcf of natural gas, of which approximately 16% is currently proved reserves. Unit plans to drill two additional step-out wells in this prospect in 2012 and anticipates drilling four infill development wells in 2013.

On July 10, 2012, Unit entered into an agreement to acquire certain oil and natural gas assets from Noble Energy, Inc. for $617.1 million in cash, subject to certain possible adjustments. The properties include approximately 84,000 net acres primarily in the Granite Wash, Cleveland, and Marmaton plays in western Oklahoma and the Texas Panhandle. The effective date of this acquisition is April 1, 2012, and closing is anticipated to be in September 2012, subject to customary closing conditions. As of the effective date, the estimated proved reserves of the subject properties is 44.0 MMBoe, and the estimated average daily net production is 10.0 MBoe. The acquisition will add approximately 25,000 net acres to Unit’s Granite Wash core area in the Texas Panhandle with significant resource potential, including 617 potential horizontal drilling locations. The acreage is characterized by high working interest and operatorship, and 95% of the acreage is held by production. Unit will also receive two natural gas gathering systems as part of the transaction.

Pinkston said: “We are excited about the Noble acquisition and the growth opportunities that it will provide us. This acquisition will more than double our acreage in our Granite Wash Texas Panhandle core area. It will also provide us with additional inventory of drilling opportunities that will allow us to significantly grow our production in the Anadarko Basin focused on oil- and liquids-rich gas targets. Our Wilcox play continues to deliver very exciting results. The significance of the multi-zone, deeper field discovery further confirms our commitment to the Wilcox play. Unit’s annual production guidance for 2012, excluding the impact of the Noble acquisition, is approximately 13.2 to 13.5 MMBoe, an increase of 9% to 12% over 2011. Including the anticipated fourth quarter production from the Noble acquisition, Unit estimates its annual production guidance for 2012 to be 14.1 to 14.4 MMBoe, an increase of 17% to 19% over 2011. ”

MID-STREAM SEGMENT INFORMATION

·	Increased second quarter 2012 liquids sold per day volumes, processed volumes per day, and gathered volumes per day by 77%, 96% and 57%, respectively, over the second quarter of 2011.

·	A new gas gathering system and processing plant in Noble and Kay counties in Oklahoma, known as the Bellmon system, was completed and began operating late in the second quarter.

Second quarter of 2012 per day processed volumes were 177,407 MMBtu while liquids sold volumes were 629,350 gallons per day, an increase of 96% and 77%, respectively, over the second quarter of 2011. Second quarter 2012 per day gathered volumes were 300,602 MMBtu, an increase of 57% over the second quarter of 2011. Operating profit (as defined in the Selected Financial and Operational Highlights) for the second quarter was $7.4 million, a decrease of 3% from the second quarter of 2011 and a decrease of 24% from the first quarter of 2012. The decreases were primarily due to decreases in the average price for natural gas and natural gas liquids.

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

	2nd Qtr 12	1st Qtr 12	4th Qtr 11	3rd Qtr 11	2nd Qtr 11	1st Qtr 11	4th Qtr 10	3rd Qtr 10	2nd Qtr 10
Gas gathered MMBtu/day	300,602	251,276	257,398	228,247	190,921	185,730	188,252	183,161	183,858
Gas processed MMBtu/day	177,407	154,825	156,721	129,820	90,737	86,445	85,195	84,175	82,699
Liquids sold Gallons/day	629,350	522,829	511,410	449,604	356,484	328,333	291,186	260,519	279,736

Pinkston said: “Our operating profit decreased 24% in the second quarter compared to the first quarter of 2012 due to a significant decline in the average price for natural gas liquids. NGLs prices in the second quarter of 2012 decreased 28% from the price received in the first quarter of 2012. We are still experiencing strong volume growth in our operations due to the number of well connects and upgrades and expansions to our processing plants. We have completed the installation of our fifth processing plant in our Hemphill County, Texas facility. We now have the capacity to process 160 MMcf per day of our own and third party Granite Wash natural gas production. In the Mississippian play in north central Oklahoma, a new gas gathering system and processing plant in Noble and Kay counties, known as the Bellmon system, was completed and began operating late in the second quarter. This system initially consists of approximately 10 miles of 12” and 16” pipe with a 10 MMcf per day gas processing plant that will be upgraded to a 30 MMcf per day gas processing plant in the fourth quarter of 2012. We are also planning to connect our existing Remington gathering system to the new Bellmon system. Connecting these two systems will require laying approximately 26 miles of pipeline and installing related compression which is scheduled to be completed by the end of this year. Also at our new Bellmon system, we are planning to extend the system approximately 14 miles to connect to a third-party producer. We anticipate this extension will be completed in the fourth quarter of 2012.”

“We are continuing to expand operations in the Appalachian region. Construction continues on our gathering facility in Allegheny and Butler counties, Pennsylvania, known as the Pittsburgh Mills system. The first phase of this project consists of approximately seven miles of gathering pipeline and a compressor station. Five wells were brought on during the second quarter of 2012. The current gathered volumes are 23 MMcf per day from six wells connected to this system. Construction activity for expansion of this pipeline continues as the producer is maintaining its drilling activity.”

FINANCIAL INFORMATION

Unit ended the second quarter of 2012 with working capital of $41.5 million, long-term debt of $332.9 million, and a debt to capitalization ratio of 14%. On July 24, 2012, Unit completed a private offering to eligible purchasers of $400 million aggregate principal amount of senior subordinated notes due 2021, with an interest rate of 6.625% per year. The notes were sold at 98.75% of par plus accrued interest from May 15, 2012. Unit intends to use the net proceeds to partially finance the pending acquisition from Noble. Also in conjunction with the acquisition, Unit intends to increase commitments under its existing credit facility from $250 million ($600 million borrowing base) up to $750 million ($800 million borrowing base).

MANAGEMENT COMMENT

Larry Pinkston said: “We are pleased with the operating results of the second quarter and first half of 2012. We believe the Noble acquisition is an important growth step for Unit and represents a unique opportunity that benefits all three of our business segments. For our upstream business segment, it will more than double our acreage in the Granite Wash Texas Panhandle core area, a highly prolific liquids-rich fairway in the Anadarko Basin. We plan to accelerate the drilling activity in the acquired properties over

the next 12 to 18 months using seven rigs from our contract drilling segment, and we plan to operate the acquired gathering systems and, as appropriate, replace existing third party processing contracts beginning in 2015. We anticipate that this acquisition will immediately be accretive to cash flow and to earnings beginning in 2013. We are optimistic about the remainder of 2012 and we are well positioned, especially given the recent financing arrangements we have completed, to take advantage of growth opportunities that may arise for our business segments.”

WEBCAST

Unit will webcast its second quarter earnings conference call live over the Internet on July 31, 2012 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 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 potential that the acquisition discussed in this release may not close, 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,
	2012			2011		2012			2011
Statement of Operations:
Revenues:
Contract drilling	$	146,872		$	115,183	$	287,778		$	213,171
Oil and natural gas		132,553			131,662		266,325			241,496
Gas gathering and processing		49,747			44,368		107,042			84,132
Other, net		720			282		1,175			101
Total revenues		329,892			291,495		662,320			538,900


Expenses:
Contract drilling:
Operating costs		74,819			64,238		150,992			117,082
Depreciation		21,238			19,218		42,566			36,515
Oil and natural gas:
Operating costs		33,279			33,417		68,888			64,198
Depreciation, depletion
and amortization		57,153			44,550		109,350			84,818
Impairment of oil and natural gas properties		115,874			—		115,874			—
Gas gathering and processing:
Operating costs		42,363			36,789		89,976			65,844
Depreciation
and amortization		5,312			3,837		10,446			7,610
General and administrative		8,376			7,496		15,380			14,388
Interest, net		2,542			673		4,368			727
Total expenses		360,956			210,218		607,840			391,182
Income (Loss) Before Income Taxes		(31,064	)		81,277		54,480			147,718

Income Tax Expense (Benefit):
Current		(2,066	)		---		(2,066	)		---
Deferred		(9,696	)		31,458		23,409			56,872
Total income taxes		(11,762	)		31,458		21,343			56,872

Net Income (Loss)	$	(19,302	)	$	49,819	$	33,137		$	90,846

Net Income (Loss) per Common Share:
Basic	$	(0.40	)	$	1.05	$	0.69		$	1.91
Diluted	$	(0.40	)	$	1.04	$	0.69		$	1.89

Weighted Average Common
Shares Outstanding:
Basic		47,906			47,655		47,868			47,620
Diluted		47,906			47,983		48,113			47,944

	June 30,		December 31,
	2012		2011
Balance Sheet Data:
Current assets	$	236,871	$	228,465
Total assets	$	3,353,437	$	3,256,720
Current liabilities	$	195,333	$	212,750
Long-term debt	$	332,900	$	300,000
Other long-term liabilities	$	116,362	$	113,830
Deferred income taxes	$	708,464	$	683,123
Shareholders’ equity	$	2,000,378	$	1,947,017

	Six Months Ended June 30,
	2012			2011
Statement of Cash Flows Data:
Cash Flow From Operations before Changes
in Operating Assets and Liabilities (1)	$	345,123		$	284,726
Net Change in Operating Assets and Liabilities		(30,091	)		(25,216	)
Net Cash Provided by Operating Activities	$	315,032		$	259,510
Net Cash Used in Investing Activities	$	(367,608	)	$	(351,942	)
Net Cash Provided by Financing Activities	$	52,826		$	92,296

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2012		2011		2012		2011
Contract Drilling Operations Data:
Rigs Utilized		76.7		73.1		79.1		71.6
Operating Margins (2)		49%		44%		48%		45%
Operating Profit Before Depreciation (2) ($MM)	$	72.1	$	50.9	$	136.8	$	96.1

Oil and Natural Gas Operations Data:
Production:
Oil – MBbls		786		591		1,506		1,147
Natural Gas Liquids - MBbls		674		567		1,330		1,046
Natural Gas - MMcf		11,287		10,946		22,688		21,178
Average Prices:
Oil price per barrel received Oil price per barrel received, excluding hedges	$ $	92.43 89.38	$ $	89.77 101.02	$ $	94.04 94.53	$ $	87.14 96.06
NGLs price per barrel received NGLs price per barrel received, excluding hedges	$ $	32.34 31.12	$ $	45.49 46.58	$ $	35.53 34.19	$ $	42.80 43.72
Natural Gas price per Mcf received Natural Gas price per Mcf received, excluding hedges	$ $	3.03 1.91	$ $	4.30 3.97	$ $	3.19 2.18	$ $	4.29 3.91
Operating Profit Before DD&A and impairment (2) ($MM)	$	99.3	$	98.2	$	197.4	$	177.3

Mid-Stream Operations Data:
Gas Gathering - MMBtu/day		300,602		190,921		275,939		188,340
Gas Processing - MMBtu/day		177,407		90,737		166,116		88,603
Liquids Sold – Gallons/day		629,350		356,484		576,089		342,486
Operating Profit Before Depreciation
and Amortization (2) ($MM)	$	7.4	$	7.6	$	17.1	$	18.3

(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, 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 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 net income excluding the effect of the impairment of our oil and natural gas properties, diluted earnings per share excluding the effect of the impairment of our oil and natural gas properties, 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, 2012 and 2011. 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 Diluted Earnings per Share

Excluding the Effect of Impairment of Oil and Natural Gas Properties

	Three Months Ended						Six Months Ended
	June 30,						June 30,
		2012			2011		2012		2011
	(In thousands)
Net income excluding impairment of oil and
natural gas properties:
Net income (loss)	$	(19,302	)	$	49,819	$	33,137	$	90,846
Add:
Impairment of oil and natural gas properties
(net of income tax)		72,132			---		72,132		---
Net income excluding impairment of oil and
natural gas properties	$	52,830		$	49,819	$	105,269	$	90,846

Diluted earnings per share excluding
impairment of oil and natural gas properties:
Diluted earnings per share Add: Diluted earnings per share from impairment	$	(0.40	)	$	1.04	$	0.69	$	1.89
of oil and natural gas properties		1.50			---		1.50		---
Diluted earnings per share excluding
impairment of oil and natural gas properties	$	1.10		$	1.04	$	2.19	$	1.89

________________

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.

Non-GAAP Financial Measures (continued)

Unit Corporation

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

	Six Months Ended June 30,
		2012			2011
	(In thousands)
Net cash provided by operating activities	$	315,032		$	259,510
Subtract:
Net change in operating assets and liabilities		(30,091	)		(25,216	)
Cash flow from operations before changes
in operating assets and liabilities	$	345,123		$	284,726

________________

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,
	2012		2012		2011		2012		2011
	(In thousands)
Contract drilling revenue	$	140,906	$	146,872	$	115,183	$	287,778	$	213,171
Contract drilling operating cost		76,173		74,819		64,238		150,992		117,082
Operating profit from contract drilling		64,733		72,053		50,945		136,786		96,089
Add: Elimination of intercompany rig profit		4,284		4,669		5,092		8,953		10,136
Operating profit from contract drilling
before elimination of intercompany
rig profit		69,017		76,722		56,037		145,739		106,225
Contract drilling operating days		7,331		6,893		6,695		14,224		12,909
Average daily operating margin before
elimination of intercompany rig profit	$	9,414	$	11,130	$	8,370	$	10,246	$	8,229

________________

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: July 31, 2012	By:	/s/ David T. Merrill
		David T. Merrill Chief Financial Officer and Treasurer