Exhibit 99.2

Item 1. Financial Statements

UNIT CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

	March 31,		December 31,
	2011		2010
	(In thousands except share amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	1,236	$	1,359
Accounts receivable, net of allowance for doubtful accounts of $5,083 both at March 31, 2011 and at December 31, 2010		134,858		130,142
Materials and supplies		6,290		6,316
Current derivative assets (Note 10)		0		5,568
Current income tax receivable		19,316		25,211
Current deferred tax asset		19,757		13,537
Prepaid expenses and other		7,558		6,047
Total current assets		189,015		188,180
Property and equipment:
Drilling equipment		1,313,374		1,273,861
Oil and natural gas properties on the full cost method:
Proved properties		2,858,466		2,738,093
Undeveloped leasehold not being amortized		181,503		175,065
Gas gathering and processing equipment		208,610		199,564
Transportation equipment		33,266		31,688
Other		30,268		28,511
		4,625,487		4,446,782
Less accumulated depreciation, depletion, amortization and impairment		2,106,979		2,047,031
Net property and equipment		2,518,508		2,399,751
Goodwill		62,808		62,808
Other intangible assets, net		2,741		3,022
Non-current derivative assets (Note 10)		0		2,537
Other assets		12,972		12,942
Total assets	$	2,786,044	$	2,669,240

The accompanying notes are an integral part of these

condensed consolidated financial statements.

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UNIT CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED) - CONTINUED

	March 31,			December 31,
	2011			2010
	(In thousands except share amounts)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	108,495		$	89,885
Accrued liabilities (Note 5)		27,099			30,093
Contract advances		5,247			2,582
Current portion of derivative liabilities (Note 10)		25,558			14,446
Current portion of other long-term liabilities (Note 6)		9,875			10,122
Total current liabilities		176,274			147,128
Long-term debt (Note 6)		185,000			163,000
Long-term derivative liabilities (Note 10)		9,904			4,359
Other long-term liabilities (Note 6)		90,917			88,030
Deferred income taxes		579,085			556,106
Shareholders’ equity:
Preferred stock, $1.00 par value, 5,000,000 shares authorized, none issued		0			0
Common stock, $.20 par value, 175,000,000 shares authorized, 48,169,566 and 47,910,431 shares issued, respectively		9,524			9,493
Capital in excess of par value		400,543			393,501
Accumulated other comprehensive loss		(20,704	)		(6,851	)
Retained earnings		1,355,501			1,314,474
Total shareholders’ equity		1,744,864			1,710,617
Total liabilities and shareholders’ equity	$	2,786,044		$	2,669,240

The accompanying notes are an integral part of these

condensed consolidated financial statements.

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UNIT CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

	Three Months Ended
	March 31,
	2011			2010
	(In thousands)
Revenues:
Contract drilling	$	97,988		$	60,854
Oil and natural gas		109,834			99,053
Gas gathering and processing		39,764			41,135
Other		(181	)		5,508
Total revenues		247,405			206,550
Expenses:
Contract drilling:
Operating costs		52,844			40,900
Depreciation		17,297			13,786
Oil and natural gas:
Operating costs		30,781			25,034
Depreciation, depletion and amortization		40,268			25,336
Gas gathering and processing:
Operating costs		29,055			32,726
Depreciation and amortization		3,773			3,941
General and administrative		6,892			6,279
Interest, net		54			0
Total operating expenses		180,964			148,002
Income before income taxes		66,441			58,548
Income tax expense:
Current		0			2,240
Deferred		25,414			20,155
Total income taxes		25,414			22,395
Net income	$	41,027		$	36,153
Net income per common share:
Basic	$	0.86		$	0.77
Diluted	$	0.86		$	0.76

The accompanying notes are an integral part of these

condensed consolidated financial statements.

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UNIT CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

	Three Months Ended
	March 31,
	2011			2010
	(In thousands)
OPERATING ACTIVITIES:
Net income	$	41,027		$	36,153
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		61,577			43,313
Unrealized (gain) loss on derivatives		2,328			(1,148	)
Deferred tax expense		25,414			20,155
(Gain) loss on disposition of assets		170			(5,435	)
Stock compensation plans		3,286			3,316
Other		895			676
Changes in operating assets and liabilities increasing (decreasing) cash:
Accounts receivable		(4,716	)		(13,304	)
Accounts payable		(15,952	)		966
Material and supplies inventory		26			245
Accrued liabilities		101			(4,269	)
Contract advances		2,665			(1,537	)
Other - net		4,384			536
Net cash provided by operating activities		121,205			79,667
INVESTING ACTIVITIES:
Capital expenditures		(165,617	)		(105,269	)
Producing property and other acquisitions		(4,052	)		(294	)
Proceeds from disposition of assets		457			18,313
Other - net		0			324
Net cash used in investing activities		(169,212	)		(86,926	)
FINANCING ACTIVITIES:
Borrowings under line of credit		88,800			19,100
Payments under line of credit		(66,800	)		(19,100	)
Proceeds from exercise of stock options		513			246
Book overdrafts		25,371			6,912
Net cash provided by financing activities		47,884			7,158
Net decrease in cash and cash equivalents		(123	)		(101	)
Cash and cash equivalents, beginning of period		1,359			1,140
Cash and cash equivalents, end of period	$	1,236		$	1,039

The accompanying notes are an integral part of these

condensed consolidated financial statements.

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UNIT CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	Three Months Ended
	March 31,
	2011			2010
	(In thousands)
Net income	$	41,027		$	36,153
Other comprehensive income, net of taxes:
Change in value of derivative instruments used as cash flow hedges, net of tax of ($9,184) and $14,667		(14,827	)		23,672
Reclassification - derivative settlements, Net of tax of ($127) and ($2,014)		(205	)		(3,252	)
Ineffective portion of derivatives, net of tax of $730 and ($417)		1,179			(674	)
Comprehensive income	$	27,174		$	55,899

The accompanying notes are an integral part of these

condensed consolidated financial statements.

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UNIT CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 – BASIS OF PREPARATION AND PRESENTATION

The accompanying unaudited condensed consolidated financial statements in this quarterly report include the accounts of Unit Corporation and all its subsidiaries and affiliates and have been prepared under the rules and regulations of the SEC. The terms “company,” “Unit,” “we,” “our” and “us” refer to Unit Corporation, a Delaware corporation, and, as appropriate, one or more of its subsidiaries and affiliates, except as otherwise indicated or as the context otherwise requires.

The accompanying condensed consolidated financial statements are unaudited and do not include all the notes in our annual financial statements. This quarterly report should be read in conjunction with the audited consolidated financial statements and notes included in our Form 10-K, filed February 24, 2011, for the year ended December 31, 2010.

In the opinion of management, the accompanying unaudited condensed consolidated financial statements contain all normal recurring adjustments (including the elimination of all intercompany transactions) necessary to fairly state the following:

• Balance Sheets at March 31, 2011 and December 31, 2010;

• Statements of Income for the three months ended March 31, 2011 and 2010;

• Cash Flows for the three months ended March 31, 2011 and 2010; and

• Statements of Comprehensive Income for the three months ended March 31, 2011 and 2010.

Our financial statements are prepared in conformity with generally accepted accounting principles in the United States (GAAP). GAAP requires us to make certain estimates and assumptions that may affect the amounts reported in our condensed consolidated financial statements and accompanying notes. Actual results may differ from those estimates. Results for the three months ended March 31, 2011 and 2010 are not necessarily indicative of the results to be realized for the full year in the case of 2011, or that we realized for the full year of 2010.

With respect to the unaudited financial information for the three month periods ended March 31, 2011 and 2010, included in this quarterly report, PricewaterhouseCoopers LLP reported that it applied limited procedures in accordance with professional standards in reviewing that information. Its separate report, dated May 3, 2011, which is included in this quarterly report, states that it did not audit and it does not express an opinion on that unaudited financial information. Accordingly, the degree of reliance placed on its report should be restricted in light of the limited review procedures applied. PricewaterhouseCoopers LLP is not subject to the liability provisions of Section 11 of the Securities Act of 1933 (Act) for its report on the unaudited financial information because that report is not a “report” or a “part” of a registration statement prepared or certified by PricewaterhouseCoopers LLP within the meaning of Sections 7 and 11 of the Act.

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NOTE 2 – OIL AND NATURAL GAS PROPERTIES

Full cost accounting rules require us to review the carrying value of our oil and natural gas properties at the end of each quarter. Under those rules, the maximum amount allowed as the carrying value of those properties is referred to as the ceiling. The ceiling is the sum of the present value (using a 10% discount rate) of the estimated future net revenues from our proved reserves based on the unescalated 12-month average price on our oil, natural gas liquids (NGLs) and natural gas adjusted for any cash flow hedges, plus the cost of properties not being amortized, plus the lower of cost or estimated fair value of unproved properties included in the costs being amortized, less related income taxes. In the event the unamortized cost of the amortized oil and natural gas properties exceeds the full cost ceiling, the excess amount is charged to expense in the period during which the excess occurs, even if prices are depressed for only a short period of time. Once incurred, a write-down of oil and natural gas properties is not reversible.

At March 31, 2011, using the existing 12-month average commodity prices, including the discounted value of our commodity hedges, we were not required to record a ceiling test write-down. However, if there are declines in the 12-month average prices, including the discounted value of our commodity hedges, we may be required to record a write-down in future periods. Our qualifying cash flow hedges used in the ceiling test determination as of March 31, 2011, consisted of swaps covering 29.4 Bcfe in 2011, 17.6 Bcfe in 2012 and 2.2 Bcfe in 2013. The effect of those hedges on the March 31, 2011 ceiling test was a $40.9 million pre-tax increase in the discounted net cash flows of our oil and natural gas properties. Even without the impact of those hedges, we would not have been required to take a write-down for the quarter. Our oil and natural gas hedging is discussed in Note 10 of the Notes to our Condensed Consolidated Financial Statements.

NOTE 3 – ACQUISITIONS

On June 2, 2010, we completed an acquisition of oil and natural gas properties from certain unaffiliated parties in an effort to explore and develop more oil rich plays. The properties were purchased for approximately $73.7 million in cash, after post close adjustments. The purchase price allocation was $48.7 million for proved properties and $25.0 million for undeveloped leasehold not being amortized. The acquisition included approximately 45,000 net leasehold acres and 10 producing oil wells. These properties focused on the Marmaton horizontal oil play located mainly in Beaver County, Oklahoma. At the time of acquisition, proved developed producing net reserves associated with the 10 acquired producing wells was approximately 762,000 BOE – consisting of 511,000 barrels of oil, 155,000 barrels of NGLs and 573 MMcf of natural gas.

Also during the second quarter of 2010, we completed an acquisition from unaffiliated parties of approximately 32,000 net acres of undeveloped oil and gas leasehold located in Southwest Oklahoma and North Texas for approximately $17.6 million.

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NOTE 4 – EARNINGS PER SHARE

Information related to the calculation of earnings per share follows:

			Weighted
	Income		Shares		Per-Share
	(Numerator)		(Denominator)		Amount
	(In thousands except per share amounts)
For the three months ended
March 31, 2011:
Basic earnings per common share	$	41,027		47,584	$	0.86
Effect of dilutive stock options, restricted stock and stock appreciation rights (SARs)		0		321		0
Diluted earnings per common share	$	41,027		47,905	$	0.86
For the three months ended
March 31, 2010:
Basic earnings per common share	$	36,153		47,121	$	0.77
Effect of dilutive stock options, restricted stock and SARs		0		565		(0.01	)
Diluted earnings per common share	$	36,153		47,686	$	0.76

The following table shows the number of stock options and SARs (and their average exercise price) excluded because their option exercise prices were greater than the average market price of our common stock:

	Three Months Ended
	March 31,
	2011		2010
Stock options and SARs		73,500		132,165
Average Exercise Price	$	64.43	$	59.87

NOTE 5 – ACCRUED LIABILITIES

Accrued liabilities consisted of the following:

	March 31,		December 31,
	2011		2010
	(In thousands)
Employee costs	$	9,520	$	16,499
Lease operating expense accrual		6,064		6,214
Taxes		3,486		1,310
Hedge settlements		2,475		1,634
Other		5,554		4,436
Total accrued liabilities	$	27,099	$	30,093

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NOTE 6 – LONG-TERM DEBT AND OTHER LONG-TERM LIABILITIES

Long-Term Debt

As of the dates in the table, long-term debt consisted of the following:

	March 31,		December 31,
	2011		2010
	(In thousands)
Revolving credit facility with average interest rates, including the effect of hedging, of 2.8% at March 31, 2011 and 3.5% at December 31, 2010	$	185,000	$	163,000
Less current portion		0		0
Total long-term debt	$	185,000	$	163,000

Our credit facility has a maximum credit amount of $400.0 million and matures on May 24, 2012. The lenders’ current commitment under the credit facility is $325.0 million. Our borrowings are limited to the commitment amount that we from time to time elect. As of March 31, 2011, the commitment amount was $325.0 million. We are charged a commitment fee ranging from 0.375 to 0.50 of 1% on the amount available but not borrowed. The rate varies based on the amount borrowed as a percentage of the amount of the total borrowing base. To date we have paid $1.2 million in origination, agency and syndication fees under the credit facility. We are amortizing these fees over the life of the agreement.

The lenders’ aggregate commitment is limited to the lesser of the amount of the borrowing base or $400.0 million. The amount of the borrowing base, which is subject to redetermination on April 1 and October 1 of each year, is based primarily on a percentage of the discounted future value of our oil and natural gas reserves and, to a lesser extent, the loan value the lenders reasonably attribute to the cash flow (as defined in the credit facility) of our mid-stream segment. The April 1, 2011 redetermination increased the borrowing base to $600.0 million. We or the lenders may request a onetime special redetermination of the amount of the borrowing base between each scheduled redetermination. In addition, we may request a redetermination following the completion of an acquisition that meets the requirements set forth in the credit facility.

At our election, any part of the outstanding debt under the credit facility may be fixed at a London Interbank Offered Rate (LIBOR) for a 30, 60, 90 or 180 day period. During any LIBOR funding period, the outstanding principal balance of the promissory note to which the LIBOR option applies may be repaid after three days prior notice to the administrative agent and on payment of any applicable funding indemnification amounts. LIBOR interest is computed as the sum of the LIBOR base for the applicable period plus 1.75% to 2.50% depending on the level of debt as a percentage of the borrowing base and is payable at the end of each period, or every 90 days, whichever is less. Borrowings not under LIBOR bear interest at the BOK Financial Corporation (BOKF) National Prime Rate, which cannot be less than LIBOR plus 1.00%, and is payable at the end of each month and the principal borrowed may be paid at any time, in part or in whole, without a premium or penalty. At March 31, 2011, all of our $185.0 million in outstanding borrowings were subject to LIBOR.

The credit facility prohibits:

• the payment of dividends (other than stock dividends) during any fiscal year in excess of 25% of our consolidated net income for the preceding fiscal year;

• the incurrence of additional debt with certain limited exceptions; and

• the creation or existence of mortgages or liens, other than those in the ordinary course of business, on any of our properties, except in favor of our lenders.

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The credit facility also requires that we have at the end of each quarter:

• consolidated net worth of at least $900 million;

• a current ratio (as defined in the credit facility) of not less than 1 to 1; and

• a leverage ratio of long-term debt to consolidated EBITDA (as defined in the credit facility) for the most recently ended rolling four fiscal quarters of no greater than 3.50 to 1.0.

As of March 31 2011, we were in compliance with our credit facility’s covenants.

Based on the borrowing rates currently available to us for debt with similar terms and maturities and consideration of our non-performance risk, long-term debt at March 31, 2011 approximates its fair value.

At March 31, 2011, the carrying values on the consolidated balance sheets for cash and cash equivalents, accounts receivable, accounts payable, other current assets and current liabilities approximate their fair value because of their short term nature.

Securities being registered under the registration statement are debt securities guaranteed by our wholly-owned domestic direct and indirect subsidiaries. Unit Corporation (Unit), as the parent company, has no independent assets or operations. The guarantees registered under the registration statement are full and unconditional and joint and several, and subsidiaries of Unit other than the subsidiary guarantors are minor. There are no significant restrictions on the ability of our parent company to receive funds from our subsidiaries through dividends, loans, advances or otherwise.

Other Long-Term Liabilities

Other long-term liabilities consisted of the following:

	March 31, 2011		December 31, 2010
	(In thousands)
Asset retirement obligations (ARO) liability	$	71,338	$	69,265
Workers’ compensation		17,666		17,566
Separation benefit plans		5,953		5,690
Gas balancing liability		3,263		3,263
Deferred compensation plan		2,572		2,368
		100,792		98,152
Less current portion		9,875		10,122
Total other long-term liabilities	$	90,917	$	88,030

The estimated annual payments due under the terms of our debt and other long-term liabilities during each of the five successive twelve month periods beginning April 1, 2011 (and through 2016) are $9.9 million, $199.6 million, $3.3 million, $2.7 million and $2.1 million, respectively.

NOTE 7 – ASSET RETIREMENT OBLIGATIONS

We are required to record the estimated fair value of the liabilities relating to the future retirement of our long-lived assets. Our oil and natural gas wells are plugged and abandoned when the oil and natural gas reserves in those wells are depleted or the wells are no longer able to produce. The plugging and abandonment liability for a well is recorded in the period in which the obligation is incurred (at the time the well is drilled or acquired). None of our assets are restricted for purposes of settling these AROs. All of our AROs relate to the plugging costs associated with our oil and gas wells.

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The following table shows certain information about our AROs for the periods indicated:

	Three Months Ended March 31,
	2011			2010
	(In thousands)
ARO liability, January 1:	$	69,265		$	56,404
Accretion of discount		874			687
Liability incurred		1,559			472
Liability settled		(359	)		(270	)
Revision of estimates		(1	)		49
ARO liability, March 31:		71,338			57,342
Less current portion		1,836			1,632
Total long-term plugging liability	$	69,502		$	55,710

NOTE 8 – NEW ACCOUNTING PRONOUNCEMENTS

Improving Disclosures about Fair Value Measurements. In January 2010, the FASB issued ASU 2010-06 – Fair Value Measurements and Disclosures (ASC 820): Improving Disclosures about Fair Value Measurements, which provides additional guidance to improve disclosures regarding fair value measurements. The ASU amends ASC 820-10, Fair Value Measurements and Disclosures—Overall (formerly FAS 157, Fair Value Measurements) to add two new disclosures: (1) transfers in and out of Level 1 and 2 measurements and the reasons for the transfers, and (2) a gross presentation of activity within the Level 3 roll forward. The ASU also includes clarifications to existing disclosure requirements on the level of disaggregation and disclosures regarding inputs and valuation techniques. The ASU applies to all entities required to make disclosures about recurring and nonrecurring fair value measurements. The effective date of the ASU was the first interim or annual reporting period beginning after December 15, 2009 and was adopted January 1, 2010, except for the gross presentation of the Level 3 roll forward information, which was adopted January 1, 2011. Because it only includes enhanced disclosures, this statement did not have a significant impact on us.

NOTE 9 – STOCK-BASED COMPENSATION

For the three months ended March 31, 2011 and 2010, we recognized stock compensation expense for restricted stock awards, stock options and stock settled SARs of $2.3 million and $2.5 million, respectively, and capitalized stock compensation cost for oil and natural gas properties of $0.6 million and $0.5 million, respectively. For these same periods, the tax benefit related to this stock based compensation was $0.9 million each period. The remaining unrecognized compensation cost related to unvested awards at March 31, 2011 is approximately $16.3 million of which $3.1 million is anticipated to be capitalized. The weighted average period of time over which this cost will be recognized is 0.9 years.

We did not grant any stock options or SARs during either of the three month periods ending March 31, 2011 and 2010.

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The following table shows the fair value of any restricted stock awards granted during the periods indicated:

	Three Months Ended March 31,
	2011			2010
Shares granted		192,581			248,383
Estimated fair value (in millions)	$	10.0		$	10.6
Percentage of shares granted expected to be distributed		93	%		93	%

The restricted stock awards granted during the first three months of 2011 will be recognized over a three year vesting period except for certain designated executive officers. For grants to those executive offers covering 66,869 shares of the total granted, 70% will vest in equal one-third annual increments, the other 30% of the shares awarded will cliff vest in the first quarter of 2014, but only if certain performance criteria are met which could result in fewer or additional shares vesting. These awards increased the stock compensation expense and the capitalized cost related to oil and natural gas properties for the first quarter of 2011 by an aggregate of $0.5 million.

NOTE 10 – DERIVATIVES

Interest Rate Swaps

From time to time we enter into interest rate swaps to manage our exposure to possible future interest rate increases under our credit facility. Under these transactions we swap the variable interest rate we would otherwise pay on a portion of our bank debt for a fixed interest rate. As of March 31, 2011, we had two outstanding interest rate swaps; both were cash flow hedges. There was no material amount of ineffectiveness. This table provides certain information about those interest rate swaps:

Remaining Term	Amount		Fixed Rate			Floating Rate
April 2011 – May 2012	$	15,000,000		4.53	%		3 month LIBOR
April 2011 – May 2012	$	15,000,000		4.16	%		3 month LIBOR

Commodity Derivatives

We have entered into various types of derivative transactions covering some of our projected natural gas, NGLs and oil production. These transactions are intended to reduce our exposure to market price volatility by setting the price(s) we will receive for that production. Our decisions on the price(s), type and quantity of our production hedged is based, in part, on our view of current and future market conditions. As of March 31, 2011, our derivative transactions consisted of the following types of swaps:

• Swaps. We receive or pay a fixed price for the hedged commodity and pay or receive a floating market price to the counterparty. The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty.

• Basis Swaps. We receive or pay the NYMEX settlement value plus or minus a fixed delivery point price for the hedged commodity and pay or receive the published index price at the specified delivery point. We use basis swaps to hedge the price risk between NYMEX and its physical delivery points.

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Oil and Natural Gas Segment:

At March 31, 2011, the following cash flow hedges were outstanding:

Term	Commodity	Hedged Volume	Weighted Average Fixed Price for Swaps			Hedged Market
Apr’11 – Dec’11	Crude oil – swap	4,000 Bbl/day	$	84.28		WTI – NYMEX
Jan’12 – Dec’12	Crude oil – swap	3,000 Bbl/day	$	90.92		WTI – NYMEX
Jan’13 – Dec’13	Crude oil – swap	1,000 Bbl/day	$	101.08		WTI – NYMEX
Apr’11 – Dec’11	Natural gas – swap	10,000 MMBtu/day	$	4.43		CEGT
Apr’11 – Dec’11	Natural gas – swap	70,000 MMBtu/day	$	4.87		IF – NYMEX (HH)
Apr’11 – Dec’11	Natural gas – basis differential swap	15,000 MMBtu/day	($	0.14	)	Tenn Zone 0 – NYMEX
Jan’12 – Dec’12	Natural gas – swap	15,000 MMBtu/day	$	5.06		IF – NYMEX (HH)
Jan’12 – Dec’12	Natural gas – swap	15,000 MMBtu/day	$	5.62		IF – PEPL
Apr’11 – Dec’11	Liquids – swap (1)	644,406 Gal/mo	$	0.96		OPIS – Conway
(1)    Types of liquids involved are natural gasoline, ethane, propane, isobutane and normal butane.
At March 31, 2011, the following non-qualifying cash flow derivatives were outstanding:
Term	Commodity	Hedged Volume	Basis Differential			Hedged Market
Apr’11 – Dec’11	Natural gas – basis differential swap	15,000 MMBtu/day	($	0.14	)	Tenn Zone 0 –NYMEX
Apr’11 – Dec’11	Natural gas – basis differential swap	10,000 MMBtu/day	($	0.21	)	CEGT –NYMEX
Apr’11 – Dec’11	Natural gas – basis differential swap	10,000 MMBtu/day	($	0.23	)	PEPL – NYMEX
After March 31, 2011, we entered into the following cash flow hedges:
Term	Commodity	Hedged Volume	Weighted Average Fixed Price			Hedged Market
Jan’12 – Dec’12	Crude oil – swap	1,000 Bbl/day	$	107.31		WTI – NYMEX
Jan’13 – Dec’13	Crude oil – swap	500 Bbl/day	$	104.40		WTI – NYMEX

The following tables present the fair values and locations of the derivative transactions recorded in our balance sheets:

		Derivative Assets
		Fair Value
	Balance Sheet Location	March 31, 2011		December 31, 2010
		(In thousands)
Derivatives designated as hedging instruments
Commodity derivatives:
Current	Current derivative assets	$	0	$	5,091
Long-term	Non-current derivative assets		0		2,537
Total derivatives designated as hedging instruments			0		7,628
Derivatives not designated as hedging instruments
Commodity derivatives:
Current	Current derivative assets		0		477
Total derivatives not designated as hedging instruments			0		477
Total derivative assets		$	0	$	8,105

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		Derivative Liabilities
		Fair Value
	Balance Sheet Location	March 31, 2011		December 31, 2010
		(In thousands)
Derivatives designated as hedging instruments
Interest rate swaps:
Current	Current portion of derivative liabilities	$	1,167	$	1,139
Long-term	Long-term derivative liabilities		194		475
Commodity derivatives:
Current	Current portion of derivative liabilities		24,308		13,166
Long-term	Long-term derivative liabilities		9,710		3,884
Total derivatives designated as hedging instruments			35,379		18,664
Derivatives not designated as hedging instruments
Commodity derivatives (basis swaps):
Current	Current portion of derivative liabilities		83		141
Total derivatives not designated as hedging instruments			83		141
Total derivative liabilities		$	35,462	$	18,805

If a legal right of set-off exists, we net the value of the derivative transactions we have with the same counterparty in our balance sheets.

We recognize in accumulated other comprehensive income (OCI) the effective portion of any changes in fair value and reclassify the recognized gains (losses) on the sales to revenue and the purchases to expense as the underlying transactions are settled. As of March 31, 2011 and 2010, we had a loss of $20.7 million and a gain of $24.2 million, net of tax, respectively, in accumulated OCI.

Based on market prices at March 31, 2011, we expect to transfer a loss of approximately $15.9 million, net of tax, included in accumulated OCI during the next 12 months in the related month of settlement. The interest rate swaps and the commodity derivative instruments existing as of March 31, 2011 are expected to mature by May 2012 and December 2013, respectively.

Certain derivatives do not qualify as cash flow hedges. Currently, we have three basis swaps that do not qualify as cash flow hedges. For these types of derivatives, any changes in the fair value that occurs before their maturity (i.e., temporary fluctuations in value) are reported in the condensed consolidated statements of operations within our oil and natural gas revenues. Changes in the fair value of derivative instruments designated as cash flow hedges, to the extent they are effective in offsetting cash flows attributable to the hedged risk, are recorded in OCI until the hedged item is recognized into earnings. Any change in fair value resulting from ineffectiveness is recognized in our oil and natural gas revenues.

Effect of Derivative Instruments on the Condensed Consolidated Statement of Income (cash flow hedges) for the three months ended March 31:

Derivatives in Cash Flow Hedging Relationships	Amount of Gain or (Loss) Recognized in Accumulated OCI on  Derivative (Effective Portion) (1)
	2011			2010
	(In thousands)
Interest rate swaps	$	(840	)	$	(1,247	)
Commodity derivatives		(19,864	)		25,451
Total	$	(20,704	)	$	24,204

(1) Net of taxes.

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Effect of Derivative Instruments on the Condensed Consolidated Statement of Income (cash flow hedges) for the three months ended March 31:

Derivative Instrument	Location of Gain or (Loss) Reclassified from Accumulated OCI into Income &  Location of Gain or (Loss) Recognized in Income	Amount of Gain or (Loss) Reclassified from Accumulated OCI into Income (1)						Amount of Gain or (Loss) Recognized in Income (2)
		2011			2010			2011			2010
		(In thousands)
Commodity derivatives	Oil and natural gas revenue	$	635		$	5,573		$	(1,909	)	$	1,091
Interest rate swaps	Interest, net		(303	)		(307	)		0			0
	Total	$	332		$	5,266		$	(1,909	)	$	1,091

(1) Effective portion of gain (loss).

(2) Ineffective portion of gain (loss).

Effect of Derivative Instruments on the Condensed Consolidated Statement of Income (derivatives not designated as hedging instruments) for the three months ended March 31:

Derivatives Not Designated as Hedging Instruments	Location of Gain or (Loss) Recognized in Income on Derivative	Amount of Gain or (Loss) Recognized in Income on Derivative
		2011			2010
		(In thousands)
Commodity derivatives (basis swaps)	Oil and natural gas revenue	$	(601	)	$	57
Total		$	(601	)	$	57

NOTE 11 – FAIR VALUE MEASUREMENTS

Fair value is defined as the amount that would be received from the sale of an asset or paid for the transfer of a liability in an orderly transaction between market participants (in either case, an exit price). To estimate an exit price, a three-level hierarchy is used prioritizing the valuation techniques used to measure fair value into three levels with the highest priority given to Level 1 and the lowest priority given to Level 3. The levels are summarized as follows:

• Level 1 – unadjusted quoted prices in active markets for identical assets and liabilities.

• Level 2 – significant observable pricing inputs other than quoted prices included within level 1 that are either directly or indirectly observable as of the reporting date. Essentially, inputs (variables used in the pricing models) that are derived principally from or corroborated by observable market data.

• Level 3 – generally unobservable inputs which are developed based on the best information available and may include our own internal data.

The inputs available to us determine the valuation technique we use to measure the fair values of our financial instruments.

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The following tables set forth our recurring fair value measurements:

	March 31, 2011
	Level 2			Level 3			Total
	(In thousands)
Financial assets (liabilities):
Interest rate swaps	$	0		$	(1,361	)	$	(1,361	)
Commodity derivatives	$	(43,469	)	$	9,368		$	(34,101	)

	December 31, 2010
	Level 2			Level 3			Total
	(In thousands)
Financial assets (liabilities):
Interest rate swaps	$	0		$	(1,614	)	$	(1,614	)
Commodity derivatives	$	(19,954	)	$	10,868		$	(9,086	)

The following methods and assumptions were used to estimate the fair values of the assets and liabilities in the table above.

Level 2 Fair Value Measurements

Commodity Derivatives. We measure the fair values of our crude oil swaps using estimated internal discounted cash flow calculations based on the NYMEX futures index.

Level 3 Fair Value Measurements

Interest Rate Swaps. The fair values of our interest rate swaps are based on estimates provided by our respective counterparties and reviewed internally against established index prices and other sources.

Commodity Derivatives. The fair values of our natural gas, natural gas liquids and basis swaps are estimated using internal discounted cash flow calculations based on forward price curves, quotes obtained from brokers for contracts with similar terms, or quotes obtained from counterparties to the agreements.

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The following tables are reconciliations of our level 3 fair value measurements:

	Net Derivatives
	For the Three Months Ended March 31, 2011						For the Three Months Ended March 31, 2010
	Interest Rate Swaps			Commodity Swaps			Interest Rate Swaps			Commodity Swaps and Collars
	(In thousands)
Beginning of period	$	(1,614	)	$	10,868		$	(1,948	)	$	19,948
Total gains or losses (realized and unrealized):
Included in earnings (1)		(303	)		4,305			(307	)		9,074
Included in other comprehensive income (loss)		253			(1,765	)		(71	)		30,343
Settlements		303			(4,040	)		307			(7,926	)
End of period	$	(1,361	)	$	9,368		$	(2,019	)	$	51,439
Total gains for the period included in earnings attributable to the change in unrealized gain relating to assets still held at end of period	$	0		$	265		$	0		$	1,148

(1) Interest rate swaps and commodity swaps and collars are reported in the condensed consolidated statements of income in interest, net and revenues, respectively.

Based on our valuation at March 31, 2011, we determined that the non-performance risk with regard to our counterparties was immaterial.

NOTE 12 – INDUSTRY SEGMENT INFORMATION

We have three main business segments offering different products and services:

• Contract drilling,

• Oil and natural gas and

• Mid-stream

The contract drilling segment is engaged in the land contract drilling of oil and natural gas wells. The oil and natural gas segment is engaged in the development, acquisition and production of oil and natural gas properties and the mid-stream segment is engaged in the buying, selling, gathering, processing and treating of natural gas.

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We evaluate each segment’s performance based on its operating income, which is defined as operating revenues less operating expenses and depreciation, depletion, amortization and impairment. Our natural gas production in Canada is not significant.

The following table provides certain information about the operations of each of our segments:

	Three Months Ended March 31,
	2011			2010
	(In thousands)
Revenues:
Contract drilling	$	112,508		$	67,501
Elimination of inter-segment revenue		(14,520	)		(6,647	)
Contract drilling net of inter-segment revenue		97,988			60,854
Oil and natural gas		109,834			99,053
Gas gathering and processing		57,008			53,734
Elimination of inter-segment revenue		(17,244	)		(12,599	)
Gas gathering and processing net of inter-segment revenue		39,764			41,135
Other		(181	)		5,508
Total revenues	$	247,405		$	206,550
Operating income (1):
Contract drilling	$	27,847		$	6,168
Oil and natural gas		38,785			48,683
Gas gathering and processing		6,936			4,468
Total operating income		73,568			59,319
General and administrative expense		(6,892	)		(6,279	)
Interest expense, net		(54	)		0
Other		(181	)		5,508
Income before income taxes	$	66,441		$	58,548

(1) Operating income is total operating revenues less operating expenses, depreciation, depletion and amortization and does not include non-operating revenues, general corporate expenses, interest expense or income taxes.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders

Unit Corporation

We have reviewed the accompanying condensed consolidated balance sheet of Unit Corporation and its subsidiaries as of March 31, 2011, and the related condensed consolidated statements of income and comprehensive income for the three-month periods ended March 31, 2011 and 2010 and the condensed consolidated statements of cash flows for the three-month periods ended March 31, 2011 and 2010. These interim financial statements are the responsibility of the Company’s management.

We conducted our review in accordance with standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

Based on our review, we are not aware of any material modifications that should be made to the accompanying condensed consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2010, and the related consolidated statements of operations, shareholders’ equity and of cash flows for the year then ended (not presented herein), and in our report dated February 24, 2011, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2010, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

/s/ PricewaterhouseCoopers LLP

Tulsa, Oklahoma

May 3, 2011

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