10-Q

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

[x] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2011

OR

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from              to             

[Commission File Number 1-9260]

UNIT CORPORATION

(Exact name of registrant as specified in its charter)

Delaware	73-1283193
(State or other jurisdiction of incorporation)	(I.R.S. Employer Identification No.)

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

(918) 493-7700

(Registrant’s telephone number, including area code)

None

(Former name, former address and former fiscal year,

if changed since last report)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes [x]            No [  ]                                                     

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes [x]            No [  ]                                                     

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer [x]                 Accelerated filer [  ]                 Non-accelerated filer [  ]                 Smaller reporting company [  ]

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes [  ]            No [x]                                                     

As of October 24, 2011, 48,150,732 shares of the issuer’s common stock were outstanding.

FORM 10-Q

UNIT CORPORATION

TABLE OF CONTENTS

		Page Number
	PART I. Financial Information
Item 1.	Financial Statements (Unaudited)
	Condensed Consolidated Balance Sheets September 30, 2011 and December 31, 2010		3
	Condensed Consolidated Statements of Income Three and Nine Months Ended September 30, 2011 and 2010		5
	Condensed Consolidated Statements of Cash Flows Nine Months Ended September 30, 2011 and 2010		6
	Condensed Consolidated Statements of Comprehensive Income Three and Nine Months Ended September 30, 2011 and 2010		7
	Notes to Condensed Consolidated Financial Statements		8
	Report of Independent Registered Public Accounting Firm		25
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		26
Item 3.	Quantitative and Qualitative Disclosure About Market Risk		48
Item 4.	Controls and Procedures		49
	PART II. Other Information
Item 1.	Legal Proceedings		50
Item 1A.	Risk Factors		50
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		50
Item 3.	Defaults Upon Senior Securities		50
Item 4.	Reserved and Removed		50
Item 5.	Other Information		50
Item 6.	Exhibits		51
Signatures			52

1

Forward-Looking Statements

This document contains “forward-looking statements” – meaning, statements related to future, not past, events within the meaning of Section 27A of the Securities Act of 1933, as amended and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, included or incorporated by reference in this document which address activities, events or developments which we expect or anticipate will or may occur in the future, are forward-looking statements. The words “believes,” “intends,” “expects,” “anticipates,” “projects,” “estimates,” “predicts” and similar expressions are used to identify forward-looking statements.

These forward-looking statements include, among others, such things as:

• the amount and nature of our future capital expenditures and how we expect to fund our capital expenditures;

• the number of wells we plan to drill or rework;

• prices for oil, NGLs and natural gas;

• demand for oil, NGLs and natural gas;

• our exploration and drilling prospects;

• the estimates of our proved oil, NGLs and natural gas reserves;

• oil, NGLs and natural gas reserve potential;

• development and infill drilling potential;

• expansion and other development trends of the oil and natural gas industry;

• our business strategy;

• production of oil, NGLs and natural gas;

• the number of gathering systems and processing plants we plan to construct or acquire;

• volumes and prices for natural gas gathered and processed;

• expansion and growth of our business and operations;

• demand for our drilling rigs and drilling rig rates;

• our belief that the final outcome of our legal proceedings will not materially affect our financial results;

• our ability to timely secure third party services used in completing our wells; and

• our ability to transport or convey our oil or natural gas production to established pipeline systems.

These statements are based on certain assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions and expected future developments as well as other factors we believe are appropriate in the circumstances. However, whether actual results and developments will conform to our expectations and predictions is subject to a number of risks and uncertainties which could cause our actual results to differ materially from our expectations, including:

• the risk factors discussed in this document and in the documents we incorporate by reference;

• general economic, market or business conditions;

• the availability of and nature or lack of business opportunities that we pursue;

• demand for our land drilling services;

• changes in laws or regulations;

• decreases or increases in commodity prices; and

• other factors, most of which are beyond our control.

You should not place undue reliance on any of these forward-looking statements. Except as required by law, we disclaim any current intention to update forward-looking information and to release publicly the results of any future revisions we may make to forward-looking statements to reflect events or circumstances after the date of this document to reflect the occurrence of unanticipated events.

2

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

UNIT CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

	September 30, 2011		December 31, 2010
	(In thousands except share amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	1,160	$	1,359
Accounts receivable, net of allowance for doubtful accounts of $5,083 at both September 30, 2011 and at December 31, 2010		153,827		130,142
Materials and supplies		8,096		6,316
Current derivative assets (Note 10)		41,257		5,568
Current income tax receivable		11,868		25,211
Current deferred tax asset		10,013		13,537
Prepaid expenses and other		9,749		6,047
Total current assets		235,970		188,180
Property and equipment:
Drilling equipment		1,386,388		1,273,861
Oil and natural gas properties on the full cost method:
Proved properties		3,166,022		2,738,093
Undeveloped leasehold not being amortized		184,540		175,065
Gas gathering and processing equipment		258,854		199,564
Transportation equipment		33,749		31,688
Other		35,607		28,511
		5,065,160		4,446,782
Less accumulated depreciation, depletion, amortization and impairment		2,242,812		2,047,031
Net property and equipment		2,822,348		2,399,751
Deferred financing costs, net		5,815		0
Goodwill		62,808		62,808
Other intangible assets, net		2,168		3,022
Non-current derivative assets (Note 10)		23,989		2,537
Other assets		12,153		12,942
Total assets	$	3,165,251	$	2,669,240

The accompanying notes are an integral part of these

condensed consolidated financial statements.

3

UNIT CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED) - CONTINUED

	September  30, 2011		December  31, 2010
	(In thousands except share amounts)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	105,493	$	89,885
Accrued liabilities (Note 5)		60,588		30,093
Contract advances		1,392		2,582
Current derivative liabilities (Note 10)		552		14,446
Current portion of other long-term liabilities (Note 6)		10,031		10,122
Total current liabilities		178,056		147,128
Long-term debt (Note 6)		305,400		163,000
Non-current derivative liabilities (Note 10)		0		4,359
Other long-term liabilities (Note 6)		112,701		88,030
Deferred income taxes		658,659		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, 48,150,732 and 47,910,431 shares issued, respectively		9,540		9,493
Capital in excess of par value		404,892		393,501
Accumulated other comprehensive gain (loss)		37,323		(6,851	)
Retained earnings		1,458,680		1,314,474
Total shareholders’ equity		1,910,435		1,710,617
Total liabilities and shareholders’ equity	$	3,165,251	$	2,669,240

The accompanying notes are an integral part of these

condensed consolidated financial statements.

4

UNIT CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
	(In thousands except per share amounts)
Revenues:
Contract drilling	$	128,927		$	85,004		$	342,098		$	217,919
Oil and natural gas		134,897			96,562			376,393			286,751
Gas gathering and processing		60,688			37,429			144,820			114,908
Other income (loss), net		(667	)		(879	)		(566	)		9,691
Total revenues		323,845			218,116			862,745			629,269
Expenses:
Contract drilling:
Operating costs		73,004			45,406			190,086			132,847
Depreciation		20,818			18,469			57,333			48,700
Oil and natural gas:
Operating costs		29,598			27,092			93,796			75,943
Depreciation, depletion and amortization		47,195			30,091			132,013			81,746
Gas gathering and processing:
Operating costs		53,299			30,743			119,143			92,407
Depreciation and amortization		4,017			3,823			11,627			11,746
General and administrative		7,800			6,637			22,188			19,372
Interest, net		1,351			0			2,078			0
Total operating expenses		237,082			162,261			628,264			462,761
Income before income taxes		86,763			55,855			234,481			166,508
Income tax expense (benefit):
Current		(3,949	)		(8,553	)		(3,949	)		(2,488	)
Deferred		37,352			29,917			94,224			66,177
Total income taxes		33,403			21,364			90,275			63,689
Net income	$	53,360		$	34,491		$	144,206		$	102,819
Net income per common share:
Basic	$	1.12		$	0.73		$	3.03		$	2.18
Diluted	$	1.11		$	0.73		$	3.01		$	2.17

The accompanying notes are an integral part of these

condensed consolidated financial statements.

5

UNIT CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

	Nine Months Ended September 30,
	2011			2010
	(In thousands)
OPERATING ACTIVITIES:
Net income	$	144,206		$	102,819
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		201,924			142,930
Unrealized gain on derivatives		(3,611	)		(1,202	)
Deferred tax expense		94,224			66,177
(Gain) loss on disposition of assets		462			(9,579	)
Stock compensation plans		10,780			6,603
Other		2,740			2,113
Changes in operating assets and liabilities increasing (decreasing) cash:
Accounts receivable		(26,118	)		(35,863	)
Accounts payable		(30,439	)		(7,924	)
Material and supplies inventory		(1,780	)		346
Accrued liabilities		13,487			5,121
Contract advances		(1,190	)		720
Other - net		13,166			11,635
Net cash provided by operating activities		417,851			283,896
INVESTING ACTIVITIES:
Capital expenditures		(541,044	)		(335,821	)
Producing property and other acquisitions		(50,525	)		(92,642	)
Proceeds from disposition of assets		7,779			34,335
Other - net		0			324
Net cash used in investing activities		(583,790	)		(393,804	)
FINANCING ACTIVITIES:
Borrowings under line of credit		334,100			205,000
Payments under line of credit		(441,700	)		(100,000	)
Proceeds from issuance of senior subordinated notes, net of offering costs		243,950			0
Proceeds from exercise of stock options		644			122
Book overdrafts		28,746			4,779
Net cash provided by financing activities		165,740			109,901
Net decrease in cash and cash equivalents		(199	)		(7	)
Cash and cash equivalents, beginning of period		1,359			1,140
Cash and cash equivalents, end of period	$	1,160		$	1,133

The accompanying notes are an integral part of these

condensed consolidated financial statements.

6

UNIT CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
	(In thousands)
Net income	$	53,360		$	34,491		$	144,206		$	102,819
Other comprehensive income (loss), net of taxes:
Change in value of derivative instruments used as cash flow hedges, net of tax of $27,015, $2,753, $28,201 and $18,780		43,154			4,148			45,123			30,014
Reclassification - derivative settlements, net of tax of ($771), ($5,646), $1,008 and ($13,708)		(1,232	)		(8,816	)		1,608			(21,832	)
Ineffective portion of derivatives, net of tax of ($899), ($67), ($1,601) and ($231)		(1,437	)		(109	)		(2,557	)		(374	)
Comprehensive income	$	93,845		$	29,714		$	188,380		$	110,627

The accompanying notes are an integral part of these

condensed consolidated financial statements.

7

UNIT CORPORATION AND SUBSIDIARIES

NOTES TO THE UNAUDITED 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 along 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 our management’s opinion, the accompanying condensed consolidated financial statements contain all normal recurring adjustments (including the elimination of all intercompany transactions) necessary to fairly state our:

• Balance Sheets at September 30, 2011 and December 31, 2010;

• Statements of Income for the three and nine months ended September 30, 2011 and 2010;

• Cash Flows for the nine months ended September 30, 2011 and 2010; and

• Statements of Comprehensive Income for the three and nine months ended September 30, 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 unaudited condensed consolidated financial statements and accompanying notes. Actual results may differ from those estimates. Results for the three and nine months ended September 30, 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 and nine month periods ended September 30, 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 November 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.

8

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. Once incurred, a write-down of oil and natural gas properties is not reversible.

At September 30, 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 at September 30, 2011, consisted of swaps covering 1.8 MMBoe in 2011, 4.7 MMBoe in 2012 and 0.7 MMBoe in 2013. The effect of those hedges on the September 30, 2011 ceiling test was a $13.7 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 Unaudited 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 closing 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. This acquisition targeted 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 consisting of approximately 32,000 net acres of undeveloped oil and gas leasehold located in Southwest Oklahoma and North Texas for approximately $17.6 million.

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

On August 31, 2011, we acquired certain producing oil and gas properties for $30.5 million in cash, subject to closing adjustments, from an unaffiliated seller. Included in the acquisition were more than 500 wells located principally in the Oklahoma Arkoma Woodford and Hartshorne Coal plays along with other properties located throughout Oklahoma and Texas. The proved reserves associated with the acquisition are approximately 31.2 Bcfe (99% natural gas), 83% of which is proved developed. The acquisition also included approximately 55,000 net acres of which 96% is held by production.

9

NOTE 4 – EARNINGS PER SHARE

Information related to the calculation of earnings per share follows:

	Income (Numerator)		Weighted Shares (Denominator)		Per-Share Amount
	(In thousands except per share amounts)
For the three months ended September 30, 2011:
Basic earnings per common share	$	53,360		47,687	$	1.12
Effect of dilutive stock options, restricted stock and stock appreciation rights (SARs)		0		281		(0.01	)
Diluted earnings per common share	$	53,360		47,968	$	1.11
For the three months ended September 30, 2010:
Basic earnings per common share	$	34,491		47,358	$	0.73
Effect of dilutive stock options, restricted stock and SARs		0		137		0.00
Diluted earnings per common share	$	34,491		47,495	$	0.73

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 September 30,
	2011		2010
Stock options and SARs		149,665		361,421
Average Exercise Price	$	58.41	$	48.05

10

	Income (Numerator)		Weighted Shares (Denominator)		Per-Share Amount
	(In thousands except per share amounts)
For the nine months ended September 30, 2011:
Basic earnings per common share	$	144,206		47,642	$	3.03
Effect of dilutive stock options, restricted stock and SARs		0		290		(0.02	)
Diluted earnings per common share	$	144,206		47,932	$	3.01
For the nine months ended September 30, 2010:
Basic earnings per common share	$	102,819		47,217	$	2.18
Effect of dilutive stock options, restricted stock and SARs		0		167		(0.01	)
Diluted earnings per common share	$	102,819		47,384	$	2.17

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:

	Nine Months Ended September 30,
	2011		2010
Stock options and SARs		73,500		233,401
Average Exercise Price	$	64.43	$	53.12

NOTE 5 – ACCRUED LIABILITIES

Accrued liabilities consisted of the following:

	September 30, 2011		December 31, 2010
	(In thousands)
Employee costs	$	16,487	$	16,499
Lease operating expense		6,875		6,214
Taxes		24,804		1,310
Interest payable		7,010		667
Hedge settlements		524		1,634
Other		4,888		3,769
Total accrued liabilities	$	60,588	$	30,093

11

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:

	September 30, 2011		December 31, 2010
	(In thousands)
Credit agreement with average interest rates, of 2.2% and 3.5% at September 30, 2011 and December 31, 2010, respectively	$	55,400	$	163,000
6.625% senior subordinated notes due 2021		250,000		0
Total long-term debt	$	305,400	$	163,000

Credit Agreement. On September 13, 2011, we entered into a Senior Credit Agreement (credit agreement) that replaces our previous credit agreement which was scheduled to mature on May 24, 2012. The credit agreement has a maturity date of September 13, 2016. The amount available to be borrowed is the lesser of the amount we elect as the commitment amount (currently $250.0 million) or the value of the borrowing base as determined by the lenders (currently $600.0 million), but in either event, not to exceed the maximum credit agreement amount of $750.0 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, in connection with this new credit agreement, we paid $1.6 million in origination, agency, syndication and other related fees. We are amortizing these fees over the life of the credit agreement.

The amount of the borrowing base, which is subject to redetermination on April 1st and October 1st of each year, is based primarily on a percentage of the discounted future value of our oil and natural gas reserves. 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 agreement.

At our election, any part of the outstanding debt under the credit agreement may be fixed at a London Interbank Offered Rate (LIBOR). LIBOR interest is computed as the sum of the LIBOR base for the applicable term 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 term, or every 90 days, whichever is less. Borrowings not under LIBOR bear interest at the 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 September 30, 2011, $50.0 million of our $55.4 million in outstanding borrowings were subject to LIBOR.

We used borrowings under the credit agreement to pay off the commitments issued under our previous credit agreement. In addition, we can use borrowings for financing general working capital requirements for (a) exploration, development, production and acquisition of oil and gas properties, (b) acquisitions and operation of midstream assets, (c) issuance of standby letters of credit, (d) contract drilling services, and (e) general corporate purposes of the Borrowers.

The credit agreement prohibits, among other things:

• the payment of dividends (other than stock dividends) during any fiscal year in excess of 30% 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.

12

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

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

• a leverage ratio of funded debt to consolidated EBITDA (as defined in the credit agreement) for the most recently ended rolling four fiscal quarters of no greater than 4 to 1.

As of September 30, 2011, we were in compliance with the covenants contained in the credit agreement.

6.625% Senior Subordinated Notes. On May 18, 2011, we completed the sale of $250.0 million aggregate principal amount of our 6.625% Senior Subordinated Notes due 2021 (the Notes). The Notes were issued at par and mature on May 15, 2021. We received net proceeds of approximately $244.0 million after deducting fees of approximately $6.0 million. Those fees are being amortized as deferred financing costs over the life of the Notes. We used the net proceeds to repay outstanding borrowings under our credit agreement, which was $220.3 million on May 18, 2011. The remaining proceeds were used for general working capital purposes.

The Notes are guaranteed by our wholly-owned domestic direct and indirect subsidiaries (the Guarantors). 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. Any subsidiaries of Unit other than the Guarantors are minor. There are no significant restrictions on the ability of Unit to receive funds from its subsidiaries through dividends, loans, advances or otherwise.

The Notes were issued under an Indenture dated as of May 18, 2011, between us and Wilmington Trust FSB, as Trustee (the Trustee), as supplemented by the First Supplemental Indenture dated as of May 18, 2011, between us, the Guarantors and the Trustee, establishing the terms and providing for the issuance of the Notes (the Supplemental Indenture). The discussion of the Notes in this quarterly report is qualified by and subject to the actual terms of the Indenture and the First Supplemental Indenture.

The Notes bear interest at a rate of 6.625% per year (payable semi-annually in arrears on May 15 and November 15 of each year, beginning on November 15, 2011), and will mature on May 15, 2021.

On and after May 15, 2016, we may redeem all or, from time to time, a part of the Notes at certain redemption prices, plus accrued and unpaid interest. Before May 15, 2014, we may on any one or more occasions redeem up to 35% of the original principal amount of the Notes with the net cash proceeds of one or more equity offerings at a redemption price of 106.625% of the principal amount, plus accrued and unpaid interest, if any, to the redemption date, provided that at least 65% of the original principal amount of the Notes remains outstanding after each redemption. In addition, at any time before May 15, 2016, we may redeem the Notes, in whole or in part, at a redemption price equal to 100% of the principal amount plus a “make whole” premium, plus accrued and unpaid interest, if any, to the redemption date. If a “change of control” occurs, subject to certain conditions, we must offer to repurchase from each holder all or any part of that holder’s Notes at a purchase price in cash equal to 101% of the principal amount of the Notes plus accrued and unpaid interest, if any, to the date of purchase. The Indenture and the Supplemental Indenture contain customary events of default. The Indenture governing the Notes contains covenants that, among other things, limit our ability and the ability of certain of our subsidiaries to incur or guarantee additional indebtedness; pay dividends on our capital stock or redeem capital stock or subordinated indebtedness; transfer or sell assets; make investments; incur liens; enter into transactions with our affiliates; and merge or consolidate with other companies. We were in compliance with all covenants of the Notes as of September 30, 2011.

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Other Long-Term Liabilities

Other long-term liabilities consisted of the following:

	September 30, 2011		December 31, 2010
	(In thousands)
Asset retirement obligations	$	92,802	$	69,265
Workers’ compensation		17,921		17,566
Separation benefit plans		6,480		5,690
Gas balancing		3,263		3,263
Deferred compensation plan		2,266		2,368
		122,732		98,152
Less current portion		10,031		10,122
Total other long-term liabilities	$	112,701	$	88,030

The estimated annual payments due under the terms of our other long-term liabilities during each of the five successive twelve month periods beginning October 1, 2011 (and through 2016) are $10.0 million, $16.9 million, $3.7 million, $3.0 million and $57.8 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 (AROs). 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 plugging costs associated with our oil and gas wells.

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

	Nine Months Ended September 30,
	2011			2010
	(In thousands)
ARO liability, January 1:	$	69,265		$	56,404
Accretion of discount		2,598			2,138
Liability incurred (1)		12,674			2,901
Liability settled		(831	)		(622	)
Revision of estimates (2)		9,096			3,822
ARO liability, September 30:		92,802			64,643
Less current portion		2,074			1,617
Total long-term ARO liability	$	90,728		$	63,026

(1) Liability incurred in 2011 includes estimates for new wells acquired.

(2) Plugging liability estimates were revised upward in both 2011 and 2010 due to increases in the cost of services used to plug wells over the preceding years.

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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.

Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and International Financial Reporting Standards (IFRS). In May 2011, the FASB issued ASU 2011-04 Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS. ASU 2011-4 is intended to improve the comparability of fair value measurements presented and disclosed in financial statements prepared in accordance with U.S. GAAP and IFRS. The amendments are of two types: (i) those that clarify the Board’s intent about the application of existing fair value measurement and disclosure requirements and (ii) those that change a particular principle or requirement for measuring fair value or for disclosing information about fair value measurements. The update is effective for annual periods beginning after December 15, 2011. We are in the process of evaluating the impact, if any, the adoption of this update will have on our financial statements.

Presentation of Comprehensive Income. In June 2011, the FASB issued ASU 2011-05 – Presentation of Comprehensive Income. This ASU amends the Codification to allow an entity the option to present the total of comprehensive income, the components of net income, and the components of other comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive statements. In both choices, an entity is required to present each component of net income along with total net income, each component of other comprehensive income along with a total for other comprehensive income, and a total amount for comprehensive income. ASU 2011-05 eliminates the option to present the components of other comprehensive income as part of the statement of changes in stockholders’ equity. The amendments to the Codification in the ASU do not change the items that must be reported in other comprehensive income or when an item of other comprehensive income must be reclassified to net income.

ASU 2011-05 should be applied retrospectively. The amendments are effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. We are in the process of evaluating the option we will choose to present comprehensive income and the impact it will have on our financial statements.

Testing Goodwill for Impairment. In September 2011, the FASB issued ASU 2011-08 – Intangibles-Goodwill and Other (ASC 350): Testing Goodwill for Impairment. This ASU is intended to simplify how entities, both public and nonpublic, test goodwill for impairment. ASU 2011-08 permits an entity to first assess qualitative factors to determine whether it is “more likely than not” that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test described in ASC 350, Intangibles-Goodwill and Other. The more-likely-than-not threshold is defined as having a likelihood of more than 50%.

ASU 2011-08 is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011.

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NOTE 9 – STOCK-BASED COMPENSATION

For the three and nine months ended September 30, 2011, we recognized stock compensation expense for restricted stock awards, stock options and stock settled SARs of $2.7 million and $7.7 million, respectively. We also capitalized for the same periods stock compensation cost for oil and natural gas properties of $0.6 million and $1.9 million, respectively. For these same periods, the tax benefit related to this stock based compensation was $1.1 million and $3.0 million, respectively. For the three and nine months ended September 30, 2010, we recognized stock compensation expense for restricted stock awards, stock options and stock settled SARs of $2.8 million and $8.3 million, respectively, and capitalized stock compensation cost for oil and natural gas properties of $0.7 million and $2.0 million, respectively. For these same periods, the tax benefit related to this stock based compensation was $1.1 million and $3.2 million, respectively. The remaining unrecognized compensation cost related to unvested awards at September 30, 2011 is approximately $11.2 million of which $2.2 million is anticipated to be capitalized. The weighted average period of time over which this cost will be recognized is 0.8 years.

We did not grant any SARs or stock options (other than the non-employee director options discussed below) during either of the three or nine month periods ending September 30, 2011 and 2010.

The table below shows the estimates of the fair value of the stock options granted to our non-employee directors under the Unit Corporation 2000 Non-employee Directors Stock Option Plan during the periods using the Black-Scholes model and applying the estimated values also presented in the table:

	Nine Months Ended September 30,
	2011			2010
Options granted (1)		31,500			52,504
Estimated fair value (in millions)	$	0.7		$	0.8
Estimate of stock volatility		0.48			0.45
Estimated dividend yield		0	%		0	%
Risk free interest rate		2	%		2	%
Expected annual life based on prior experience		5			5
Forfeiture rate		0	%		0	%

(1) On May 29, 2009, eight of our directors were each issued 3,063 options contingent on shareholder approval, which was received at the May 5, 2010 annual shareholders’ meeting. These 24,504 options granted and vested simultaneously with that approval.

Expected volatilities are based on the historical volatility of our stock. Within the model, we use historical data to estimate stock option exercise and termination rates and aggregate groups that have similar historical exercise behavior for valuation purposes. To date, we have not paid dividends on our stock. The risk free interest rate is computed from the LIBOR rate using the term over which it is anticipated the grant will be exercised. The stock options granted in the second quarter of 2011 increased stock compensation expense for the third quarter and first nine months of 2011 by $0.4 million and $0.6 million, respectively.

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
Shares granted		12,402			192,272			209,150			440,655
Estimated fair value (in millions)	$	0.6		$	6.0		$	10.9		$	16.6
Percentage of shares granted expected to be distributed		95	%		89	%		93	%		91	%

The restricted stock awards granted during the first three and nine months of 2011 will be recognized over a two- and three-year vesting period, except for a portion of those granted to certain executive officers in the first quarter of 2011. Thirty percent of the shares granted to the designated executive officers, or 20,062 shares (the performance shares), will cliff vest in the first half of 2014. The actual number of performance shares that vest in 2014 will be based on the company’s achievement of certain performance criteria over a three-year period, and will range from 50% to 150% of the 20,062 restricted shares granted as performance shares. Total 2011 awards increased the stock compensation expense and the capitalized cost related to oil and natural gas properties for the first nine months of 2011 by an aggregate of $3.5 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 agreement. 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. In May 2011, in association with the repayment of outstanding borrowings under our credit agreement, we terminated our two outstanding interest rate swaps that were previously accounted for as cash flow hedges, resulting in an increase of approximately $1.5 million in interest expense. Approximately $1.1 million of that expense was capitalized and will be amortized over the life of the assets.

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 September 30, 2011, our derivative transactions consisted of the following types of hedges:

• 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 September 30, 2011, the following cash flow hedges were outstanding:

Term	Commodity	Hedged Volume	Weighted Average Fixed Price for Swaps	Hedged Market
Oct’11 – Dec’11	Crude oil – swap	4,000 Bbl/day	$84.28	WTI – NYMEX
Jan’12 – Dec’12	Crude oil – swap	4,500 Bbl/day	$95.91	WTI – NYMEX
Jan’13 – Dec’13	Crude oil – swap	2,000 Bbl/day	$102.05	WTI – NYMEX
Oct’11 – Dec’11	Natural gas – swap	10,000 MMBtu/day	$4.43	CEGT
Oct’11 – Dec’11	Natural gas – swap	70,000 MMBtu/day	$4.87	IF – NYMEX (HH)
Oct’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	30,000 MMBtu/day	$5.05	IF – NYMEX (HH)
Jan’12 – Dec’12	Natural gas – swap	15,000 MMBtu/day	$5.62	IF – PEPL
Oct’11 – Dec’11	Liquids – swap (1)	2,024,418 Gal/mo	$1.07	OPIS – Conway
Oct’11 – Dec’11	Liquids – swap (1)	1,240,068 Gal/mo	$1.00	OPIS – Mont Belvieu
Jan’12 – Mar’12	Liquids – swap (1)	1,350,014 Gal/mo	$1.10	OPIS – Conway
Jan’12 – Mar’12	Liquids – swap (1)	1,155,018 Gal/mo	$0.91	OPIS – Mont Belvieu
Apr’12 – Dec’12	Liquids – swap (2)	180,006 Gal/mo	$2.11	OPIS – Conway
Apr’12 – Jun’12	Liquids – swap (3)	690,028 Gal/mo	$0.79	OPIS – Mont Belvieu

(1) Types of liquids involved are natural gasoline, ethane, propane, isobutane and normal butane.

(2) Types of liquids involved are natural gasoline.

(3) Types of liquids involved are natural gasoline and ethane.

At September 30, 2011, the following non-qualifying cash flow derivatives were outstanding:

Term	Commodity	Hedged Volume	Basis Differential	Hedged Market
Oct’11 – Dec’11	Natural gas – basis differential swap	15,000 MMBtu/day	($0.14)	Tenn Zone 0 – NYMEX
Oct’11 – Dec’11	Natural gas – basis differential swap	10,000 MMBtu/day	($0.21)	CEGT – NYMEX
Oct’11 – Dec’11	Natural gas – basis differential swap	10,000 MMBtu/day	($0.23)	PEPL – NYMEX

The following tables present the fair values of our derivative transactions and the location within our balance sheets where those values are recorded:

		Derivative Assets
		Fair Value
	Balance Sheet Location	September 30, 2011		December 31, 2010
		(In thousands)
Derivatives designated as hedging instruments
Commodity derivatives:
Current	Current derivative assets	$	41,257	$	5,091
Long-term	Non-current derivative assets		23,989		2,537
Total derivatives designated as hedging instruments			65,246		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		$	65,246	$	8,105

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		Derivative Liabilities
		Fair Value
	Balance Sheet Location	September 30, 2011		December 31, 2010
		(In thousands)
Derivatives designated as hedging instruments
Interest rate swaps:
Current	Current derivative liabilities	$	0	$	1,139
Long-term	Non-current derivative liabilities		0		475
Commodity derivatives:
Current	Current derivative liabilities		342		13,166
Long-term	Non-current derivative liabilities		0		3,884
Total derivatives designated as hedging instruments			342		18,664
Derivatives not designated as hedging instruments
Commodity derivatives (basis swaps):
Current	Current derivative liabilities		210		141
Total derivatives not designated as hedging instruments			210		141
Total derivative liabilities		$	552	$	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 September 30, 2011 and 2010, we had a gain of $37.3 million and $12.3 million, net of tax, respectively, in accumulated OCI.

Based on market prices at September 30, 2011, we expect to transfer a gain of approximately $25.0 million, net of tax, included in accumulated OCI during the next 12 months in the related month of settlement. The commodity derivative instruments existing as of September 30, 2011 are expected to mature by December 2013.

Certain derivatives do not qualify as cash flow hedges. Currently, three of our basis swaps do not qualify as cash flow hedges. For these derivatives, any changes in their fair value occurring before their maturity (i.e., temporary fluctuations in value) are reported in oil and natural gas revenues in our unaudited condensed consolidated statements of income. Changes in the fair value of derivatives 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 Unaudited Condensed Consolidated Statement of Income (cash flow hedges) for the nine months ended September 30:

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	$	0	$	(1,193	)
Commodity derivatives		37,323		13,459
Total	$	37,323	$	12,266

(1) Net of taxes.

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Effect of Derivative Instruments on the Unaudited Condensed Consolidated Statement of Income (cash flow hedges) for the three months ended September 30:

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	$	2,003	$	14,760		$	2,336	$	176
Interest rate swaps	Interest, net		0		(298	)		0		0
	Total	$	2,003	$	14,462		$	2,336	$	176

(1) Effective portion of gain (loss).

(2) Ineffective portion of gain (loss).

Effect of Derivative Instruments on the Unaudited Condensed Consolidated Statement of Income (derivatives not designated as hedging instruments) for the three months ended September 30:

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	$	(61	)	$	(427	)
Total		$	(61	)	$	(427	)

Effect of Derivative Instruments on the Unaudited Condensed Consolidated Statement of Income (cash flow hedges) for the nine months ended September 30:

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	$	(882	)	$	36,447		$	4,158	$	605
Interest rate swaps	Interest, net		(1,734	)		(907	)		0		0
	Total	$	(2,616	)	$	35,540		$	4,158	$	605

(1) Effective portion of gain (loss).

(2) Ineffective portion of gain (loss).

Effect of Derivative Instruments on the Unaudited Condensed Consolidated Statement of Income (derivatives not designated as hedging instruments) for the nine months ended September 30:

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	$	(1,008	)	$	597
Total		$	(1,008	)	$	597

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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.

The following tables set forth our recurring fair value measurements:

	September 30, 2011
	Level 2		Level 3		Total
	(In thousands)
Financial assets:
Commodity derivatives	$	39,565	$	25,129	$	64,694

	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, NGLs 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 reconcile our level 3 fair value measurements:

	Net Derivatives
	For the Three Months Ended September 30, 2011					For the Nine Months  Ended September 30, 2011
	Interest Rate Swaps		Commodity Swaps			Interest Rate Swaps			Commodity Swaps
	(In thousands)
Beginning of period	$	0	$	11,749		$	(1,614	)	$	10,868
Total gains or (losses) (realized and unrealized):
Included in earnings (1)		0		4,046			(1,734	)		11,923
Included in other comprehensive income		0		13,182			1,614			13,264
Settlements		0		(3,848	)		1,734			(10,926	)
End of period	$	0	$	25,129		$	0		$	25,129
Total gains for the period included in earnings attributable to the change in unrealized gains relating to assets still held at end of period	$	0	$	198		$	0		$	997

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

	Net Derivatives
	For the Three Months Ended September 30, 2010						For the Nine Months  Ended September 30, 2010
	Interest Rate Swaps			Commodity Swaps and Collars			Interest Rate Swaps			Commodity Swaps and Collars
	(In thousands)
Beginning of period	$	(1,971	)	$	33,313		$	(1,948	)	$	19,948
Total gains or (losses) (realized and unrealized):
Included in earnings (2)		(298	)		16,558			(907	)		44,322
Included in other comprehensive income (loss)		39			(1,266	)		16			10,646
Purchases, issuance and settlements		298			(16,809	)		907			(43,120	)
End of period	$	(1,932	)	$	31,796		$	(1,932	)	$	31,796
Total gains (losses) for the period included in earnings attributable to the change in unrealized gains relating to assets still held at end of period	$	0		$	(251	)	$	0		$	1,202

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

Based on our valuation at September 30, 2011, we determined that the non-performance risk with regard to our counterparties was immaterial.

Fair Value of Other Financial Instruments

The following disclosure of the estimated fair value of financial instruments is made in accordance with accounting guidance for financial instruments. We have determined the estimated fair values by using available market information and valuation methodologies. Considerable judgment is required in interpreting market data to develop the estimates of fair value. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.

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At September 30, 2011, the carrying values on the unaudited condensed 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.

Based on the borrowing rates currently available to us for credit agreement debt with similar terms and maturities and consideration of our non-performance risk, long-term debt associated with our credit agreement at September 30, 2011 approximates its fair value.

The carrying amount of long-term debt associated with the Notes reported in the consolidated balance sheet as of September 30, 2011 was $250.0 million. We estimate the fair value of these Notes using quoted marked prices at September 30, 2011 was $249.4 million.

NOTE 12 – INDUSTRY SEGMENT INFORMATION

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

• Contract drilling,

• Oil and natural gas and

• Midstream

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 midstream 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 oil and natural gas production outside the United States is not significant.

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
	(In thousands)
Revenues:
Contract drilling	$	140,193		$	96,705		$	381,982		$	246,252
Elimination of inter-segment revenue		(11,266	)		(11,701	)		(39,884	)		(28,333	)
Contract drilling net of inter-segment revenue		128,927			85,004			342,098			217,919
Oil and natural gas		134,897			96,562			376,393			286,751
Gas gathering and processing		79,919			47,864			200,821			148,606
Elimination of inter-segment revenue		(19,231	)		(10,435	)		(56,001	)		(33,698	)
Gas gathering and processing net of inter-segment revenue		60,688			37,429			144,820			114,908
Other, net		(667	)		(879	)		(566	)		9,691
Total revenues	$	323,845		$	218,116		$	862,745		$	629,269
Operating income:
Contract drilling	$	35,105		$	21,129		$	94,679		$	36,372
Oil and natural gas		58,104			39,379			150,584			129,062
Gas gathering and processing		3,372			2,863			14,050			10,755
Total operating income (1)		96,581			63,371			259,313			176,189
General and administrative expense		(7,800	)		(6,637	)		(22,188	)		(19,372	)
Interest expense, net		(1,351	)		0			(2,078	)		0
Other income (loss), net		(667	)		(879	)		(566	)		9,691
Income before income taxes	$	86,763		$	55,855		$	234,481		$	166,508

(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 unaudited condensed consolidated balance sheet of Unit Corporation and its subsidiaries as of September 30, 2011, and the related unaudited condensed consolidated statements of income and comprehensive income for the three and nine-month periods ended September 30, 2011 and 2010 and the unaudited condensed consolidated statements of cash flows for the nine-month periods ended September 30, 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 unaudited 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 income, 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

November 3, 2011

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Management’s Discussion and Analysis (MD&A) provides an understanding of our operating results and financial condition by focusing on changes in certain key measures from year to year. We have organized MD&A into the following sections:

• General

• Business Outlook

• Executive Summary

• Financial Condition and Liquidity

• New Accounting Pronouncements

• Results of Operations

Please read the following discussion and our unaudited condensed consolidated financial statements and related notes with the information contained in our most recent Annual Report on Form 10-K.

Unless otherwise indicated or required by the content, when used in this report the terms “company,” “Unit,” “us,” “our,” “we” and “its” refer to Unit Corporation or, as appropriate, one or more of its subsidiaries.

General

We operate, manage and analyze our results of operations through our three principal business segments:

• Contract Drilling – carried out by our subsidiary Unit Drilling Company and its subsidiaries. This segment contracts to drill onshore oil and natural gas wells for others and for our own account.

• Oil and Natural Gas – carried out by our subsidiary Unit Petroleum Company. This segment explores, develops, acquires and produces oil and natural gas properties for our own account.

• Midstream – carried out by our subsidiary Superior Pipeline Company, L.L.C. and its subsidiaries. This segment buys, sells, gathers, processes and treats natural gas for third parties and for our own account.

Business Outlook

As discussed in other parts of this quarterly report, the success of our consolidated business, as well as that of each of our three operating segments depends, to a large extent, on: the prices we receive for our natural gas, NGLs and oil production; the demand for oil and natural gas; and the demand for our drilling rigs which, in turn, influences the amounts we can charge for the use of those drilling rigs. Although all of our current operations (with the exception of a minor amount of production in Canada) are located within the United States, events outside the United States can and do have an impact on us and our industry.

In addition to their direct impact on us, low commodity prices-if sustained for a long period of time-could impact the liquidity of some of our industry partners and customers which, in turn, could limit their ability to meet their financial obligations to us.

In developing our initial overall operating budget for 2011, we used average oil and natural gas prices of $82.00 per Bbl and $4.60 per Mcf. Our 2011 operating budget will be funded using internally generated cash flow, borrowings under our credit agreement and the remaining proceeds from the Notes.

Executive Summary

Contract Drilling

The rate at which our drilling rigs were used (“our utilization rate”) for the third quarter 2011 was 63%, compared to 60% and 54% for the second quarter of 2011 and the third quarter of 2010, respectively.

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Dayrates for the third quarter of 2011 averaged $19,309, an increase of 2% from the second quarter of 2011 and an increase of 22% from the third quarter of 2010. These increases were primarily the result of increased use of drilling rigs in the 1,000 to 1,500 horsepower range that are used for horizontal drilling and also provide for higher rates.

Direct profit (contract drilling revenue less contract drilling operating expense) for the third quarter of 2011 increased 10% over the second quarter of 2011 and 41% over the third quarter of 2010. The increases were primarily due to increases in dayrates and utilization over the comparative periods as discussed above.

Operating cost per day for the third quarter of 2011 increased 5% over the second quarter of 2011 and increased 34% over the third quarter of 2010. The increase over the second quarter 2011 and the third quarter of 2010 is primarily due to increases in direct expenses due to pay increases for rig personnel and to a lesser extent from increases in rig servicing costs.

Historically, our contract drilling segment has experienced a greater demand for natural gas drilling as opposed to drilling for oil and NGLs. With the current weakened natural gas market, operators are focusing on drilling for oil and NGLs. Approximately 79% of our drilling rigs working today are drilling for oil or NGLs. Of those, approximately 95% are drilling horizontal or directional wells.

At the end of 2010, we began constructing five new 1,500 horsepower, diesel-electric drilling rigs. All of these drilling rigs are now completed and are working in the Bakken shale. Each of these five new drilling rigs is initially working under a two-year drilling contract. During the third quarter of 2011,we were awarded two additional new build rig contracts for 1,500 horsepower, diesel-electric drilling rigs. These new build rigs will initially be working under three year contracts. Delivery of the two rigs is scheduled for the fourth quarter of 2011. Both drilling rigs will be for our Rocky Mountain division operations. On completion of the additional drilling rigs, we will have 128 drilling rigs in our fleet.

Our anticipated 2011 capital expenditures for this segment are $174.0 million.

As of October 19, 2011, we had 61 term drilling contracts with original terms ranging from six months to three years. Nine of these contracts are up for renewal in 2011 and 52 are up for renewal in 2012 and later. These contracts include all seven term contracts for the new drilling rigs discussed above. Term contracts may contain a fixed rate for the duration of the contract or provide for rate adjustments within a specific range from the existing rate.

Oil and Natural Gas

During the second quarter of 2010 we completed an acquisition of oil and natural gas properties from certain unaffiliated parties. The properties were purchased for approximately $73.7 million in cash. The acquisition included approximately 45,000 net leasehold acres and 10 producing oil wells. This acquisition targeted the Marmaton horizontal oil play located mainly in Beaver County, Oklahoma. Proved developed producing net reserves associated with the 10 acquired producing wells is approximately 762,000 barrels of oil equivalent — consisting of 511,000 barrels of oil, 155,000 barrels of NGLs and 573 MMcf of natural gas.

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

On August 31, 2011, we acquired certain producing oil and gas properties for $30.5 million in cash, subject to closing adjustments, from an unaffiliated seller. Included in the acquisition were more than 500 wells located principally in the Oklahoma Arkoma Woodford and Hartshorne Coal plays along with other properties located throughout Oklahoma and Texas. The proved reserves associated with the acquisition are approximately 31.2 Bcfe (99% natural gas), 83% of which is proved developed. The acquisition also included approximately 55,000 net acres of which 96% is held by production.

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Third quarter 2011 production was 3,123,000 barrels of oil equivalent (Boe) per day, a 5% increase over the second quarter of 2011 and a 26% increase over the third quarter of 2010. The increase in production came primarily from oil and NGL rich prospects where we completed and brought new wells online and, to a lesser extent, from production associated with the acquisitions discussed above. Third quarter 2011 oil and NGL production was 38% of our total production compared to 30% of our total production over the third quarter of 2010. Our production in 2010 was hindered by delays in securing third party fracture stimulation services and delays associated with connecting wells to gathering systems. In addition, our 2010 production was curtailed because of the unexpected shut-in of some of our production from operational issues experienced at a third party facility that processes our Segno field production.

Third quarter 2011 oil and natural gas revenues increased 2% over the second quarter of 2011 and increased 40% over the third quarter of 2010. These increases were primarily due to increased production and for the increase over the third quarter of 2010, also increased oil and liquid prices.

Our oil and NGL prices for the third quarter of 2011 decreased 4% and remained unchanged, respectively, over the second quarter of 2011 and increased 29% and 43%, respectively, over the third quarter of 2010. Natural gas prices for the third quarter of 2011 increased 2% compared to second quarter 2011 and decreased 21% compared to the third quarter of 2010.

Direct profit (oil and natural gas revenues less oil and natural gas operating expense) increased 7% over the second quarter of 2011 and increased 52% over the third quarter of 2010. The increases were primarily attributable to increased production and a $4.5 million decrease in gross production taxes in the third quarter of 2011, due to refunds of production taxes attributable to high-cost gas wells, partially offset by increases in lease operating expenses.

Operating cost per Boe produced for the third quarter of 2011 decreased 15% from the second quarter of 2011 and decreased 13% from the third quarter of 2010. The decreases were primarily due to the gross production tax refund received in the third quarter of 2011 for high cost gas tax credits, partially offset by increases in lease operating expenses (LOE) due to increased workover expense and higher saltwater disposal fees.

For 2011, we currently have hedged approximately 59% of our anticipated daily oil production, approximately 58% of our anticipated natural gas production and approximately 40% of our anticipated NGLs production (percentages based on our third quarter 2011 production).

Currently for 2012 we have hedged 4,500 Bbls per day of oil production and 45,000 Mmbtu per day of natural gas production. The oil production is hedged under swap contracts at an average price of $95.91 per barrel. The natural gas production is hedged under swap contracts at a comparable average NYMEX price of $5.33. The average basis differential for the applicable swaps is ($0.28). We have NGL hedges of 1,988 Bbls per day in the first quarter, 683 Bbls per day in the second quarter, 140 Bbls per day in the third quarter, and 140 Bbls per day in the fourth quarter. The NGLs are hedged under swap contracts at an average price of $42.53 per barrel in the first quarter, $44.47 per barrel in the second quarter, $88.41 per barrel in the third quarter, and $88.41 per barrel in the fourth quarter.

Currently for 2013 we have hedged 2,000 Bbls per day of oil production. The oil production is hedged under swap contracts at an average price of $102.05 per barrel.

During the first nine months of 2011, we drilled 119 gross wells (62.20 net wells). During the second quarter, we increased our estimated capital expenditures for 2011 from $415.0 million to $435.0 million with the increase primarily being associated with the purchase of acreage both within our existing core plays and in areas outside of our core plays. For the year, we plan to drill 160 gross wells and we are also increasing our anticipated annual production guidance to a range between 11.8 to 12.1 MMBoe from our previous guidance of 11.3 to 11.6 MMBoe.

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Midstream

Third quarter 2011 liquids sold per day increased 26% over the second quarter of 2011 and increased 73% over the third quarter of 2010. The increases resulted from upgrades and expansions to existing plants and the connection of new wells. For the third quarter of 2011, gas processed per day increased 43% over the second quarter of 2011 and 54% over the third quarter of 2010. In 2010, we upgraded several of our existing processing facilities and added processing plants which was the primary reason for increased volumes. For the third quarter of 2011, gas gathered per day increased 20% over the second quarter of 2011 and increased 25% over the third quarter of 2010 primarily from well connects throughout 2011.

NGL prices in the third quarter of 2011 decreased 1% over the price received in the second quarter of 2011 and increased 29% over the price received in the third quarter of 2010. The price of NGLs as compared to natural gas affects the revenue in our midstream operations and determines the fractionation spread which is the difference in the value received for the NGLs recovered from natural gas in comparison to the amount received for the equivalent MMBtu’s of natural gas if unprocessed.

Direct profit (midstream revenues less midstream operating expense) for the third quarter of 2011 decreased 3% from the second quarter of 2011 and increased 11% over the third quarter of 2010. The decrease from second quarter of 2011 resulted primarily because of the lower amounts we now receive under certain contracts that we were required to renegotiate during the first quarter when the original term of those contracts expired. The increase over the third quarter of 2010 was primarily due to increases in volumes gathered, processed and liquids sold, partially offset by increased cost for gas purchased.

Total operating cost for our midstream segment for the third quarter of 2011 increased 45% over the second quarter of 2011 and 73% over the third quarter of 2010 due primarily to the increase in gas purchased due to increased volumes.

During the fourth quarter of 2010, we completed the installation and start up of a 50.0 MMcf per day turbo-expander natural gas processing plant at our Hemphill facility in Canadian, Texas. With the expansion of this plant, the total processing capacity at our Hemphill facility has increased to approximately 100.0 MMcf per day. During the third quarter of 2011, we increased the capacity of this plant by 20 MMcf per day by replacing the turbo expander center section.

In our Mid-continent operations, we are in the process of replacing the existing plant on our Cashion system with a high-efficiency gas processing plant. The new plant is expected to be operational during the first quarter of 2012. It will increase our processing capacity and will improve our liquids recovery capability by 12 to 15%. The Cashion plant gathers gas across Logan, Canadian, Oklahoma and Kingfisher Counties in Oklahoma. In the Mississippi Lime play in Grant County, Oklahoma, our new gathering system and processing plant became operational in October. One well is online and three more wells are in the process of being connected. We anticipate an additional 25 to 30 wells to be connected during 2012 due to active drilling by multiple producers in the area around the plant. This is our entrance into the Mississippi Lime play.

In our Appalachian operations, we are in the final stages of completing a 16-mile, 16” pipeline and a compressor station in Preston County, West Virginia, which will have a capacity of approximately 220.0 MMcf per day. Currently, we have four wells connected with an expected total initial flow volume in the 8 to 10 MMcf per day range. Three additional wells have been drilled and are waiting on completion prior to being connected. We anticipate this pipeline will be operational during the fourth quarter of 2011. In addition to the Preston County pipeline, we recently signed a letter of intent with a third party to construct a pipeline in Allegheny and Butler Counties of Pennsylvania. First flow of gas from this new system is expected to occur in the fourth quarter of 2011. Expectations are that the first well will flow up to 10 MMcf per day, and we anticipate four more wells to be drilled and connected during the first half of 2012.

Our anticipated capital expenditures for 2011 are $86.0 million.

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Financial Condition and Liquidity

Summary

Our financial condition and liquidity depends on the cash flow from our operations and, when necessary, borrowings under our credit agreement. The principal factors determining the amount of our cash flow are:

• the demand for and the dayrates we receive for our drilling rigs;

• the quantity of natural gas, oil and NGLs we produce;

• the prices we receive for our oil, NGL and natural gas production; and

• the margins we obtain from our natural gas gathering and processing contracts.

The following is a summary of certain financial information as of September 30, 2011 and 2010 and for the nine months ended September 30, 2011 and 2010:

	September 30,						% Change
	2011			2010
	(In thousands except percentages)
Working capital	$	57,914		$	35,480			63	%
Long-term debt	$	305,400		$	135,000			126	%
Shareholders’ equity	$	1,910,435		$	1,682,868			14	%
Ratio of long-term debt to total capitalization		14	%		7	%		100	%
Net income	$	144,206		$	102,819			40	%
Net cash provided by operating activities	$	417,851		$	283,896			47	%
Net cash used in investing activities	$	(583,790	)	$	(393,804	)		48	%
Net cash provided by financing activities	$	165,740		$	109,901			51	%

The following table summarizes certain operating information:

	Nine Months Ended September 30,				% Change
	2011		2010
Contract Drilling:
Average number of our drilling rigs in use during the period		74		58.2		27	%
Total number of drilling rigs owned at the end of the period		126		123		2	%
Average dayrate	$	18,663	$	15,037		24	%
Oil and Natural Gas:
Oil production (MBbls)		1,767		1,002		76	%
Natural gas liquids production (MBbls)		1,623		1,143		42	%
Natural gas production (MMcf)		32,730		30,121		9	%
Average oil price per barrel received	$	86.80	$	67.05		29	%
Average oil price per barrel received excluding hedges	$	93.75	$	74.11		27	%
Average NGL price per barrel received	$	43.72	$	35.91		22	%
Average NGL price per barrel received excluding hedges	$	44.65	$	35.70		25	%
Average natural gas price per mcf received	$	4.33	$	5.71		(24	)%
Average natural gas price per mcf received excluding hedges	$	3.94	$	4.27		(8	)%
Midstream:
Gas gathered—MMBtu/day		201,788		182,390		11	%
Gas processed—MMBtu/day		102,493		81,157		26	%
Gas liquids sold—gallons/day		378,585		264,679		43	%
Number of natural gas gathering systems		34		34		0	%
Number of processing plants		10		8		25	%

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At September 30, 2011, we had unrestricted cash totaling $1.2 million and had borrowed $55.4 million of the $250.0 million we had elected to have currently available under our credit agreement. Our credit agreement is used primarily for working capital and capital expenditures.

On May 18, 2011, we completed the sale of $250.0 million aggregate principal amount of 6.625% Senior Subordinated Notes due 2021. The Notes were issued at par and mature on May 15, 2021. The net proceeds were used to repay outstanding borrowings under our credit agreement, which had approximately $220.3 million outstanding as of May 18, 2011. The remaining proceeds were used for general working capital purposes.

Working Capital

Typically, our working capital balance fluctuates. This is because of the timing of our trade accounts receivable and accounts payable and from the fluctuation in current assets and liabilities associated with the mark to market value of our hedging activity. We had working capital of $57.9 million and $35.5 million as of September 30, 2011 and 2010, respectively. The effect of our hedging activity increased working capital by $25.0 million as of September 30, 2011 and increased working capital by $11.4 million as of September 30, 2010.

Contract Drilling

Many factors influence the number of drilling rigs we are working at any one time as well as the costs and revenues associated with that work. These factors include the demand for drilling rigs in our areas of operation, competition from other drilling contractors, the prevailing prices for oil, NGLs and natural gas, availability and cost of labor to run our drilling rigs and our ability to supply the equipment needed.

As activity has increased over last year’s levels, competition to keep qualified labor has also increased. In the third quarter 2010, we increased compensation for drilling personnel in Oklahoma, Texas and Louisiana and again at the end of the first quarter of 2011 for drilling personnel in all our divisions.

Over the past year, as more of our customers shift to drilling horizontal wells, demand for drilling rigs in the 1,000 to 1,500 horsepower range has increased as those drilling rigs have the horsepower ideally suited for horizontal drilling. The future demand for and the availability of drilling rigs to meet that demand will have an impact on our future dayrates. For the first nine months of 2011, our average dayrate was $18,663 per day compared to $15,037 per day for the first nine months of 2010. The average number of our drilling rigs used in the first nine months of 2011 was 74.0 drilling rigs (60%) compared with 58.2 drilling rigs (47%) in the first nine months of 2010. Based on the average utilization of our drilling rigs during the first nine months of 2011, a $100 per day change in dayrates has a $7,400 per day ($2.7 million annualized) change in our pre-tax operating cash flow.

Our contract drilling segment provides drilling services for our oil and natural gas segment. Depending on the timing of those services, some of the drilling services we perform on our properties are deemed to be associated with the acquisition of an ownership interest in the property. Accordingly, revenues and expenses for those drilling services are eliminated in our income statement, with any profit recognized as a reduction in our investment in our oil and natural gas properties. The contracts for these services are issued under the same conditions and rates as the contracts entered into with unrelated third parties. We eliminated revenue of $39.9 million and $28.3 million for the nine months of 2011 and 2010, respectively, from our contract drilling segment and eliminated the associated operating expense of $24.9 million and $23.6 million during the nine months of 2011 and 2010, respectively, yielding $15.0 million and $4.7 million during the nine months of 2011 and 2010, respectively, as a reduction to the carrying value of our oil and natural gas properties.

Impact of Prices for Our Oil, NGLs and Natural Gas

Any significant change in oil or natural gas prices has a material effect on our revenues, cash flow and the value of our oil, NGLs and natural gas reserves. Generally, prices and demand for domestic natural gas are influenced by weather conditions, supply imbalances and by worldwide oil price levels. Domestic oil prices are primarily influenced by world oil market developments. All of these factors are beyond our control and we cannot predict nor measure their future influence on the prices we will receive.

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Based on our first nine months of 2011 production, a $0.10 per Mcf change in what we are paid for our natural gas production, without the effect of hedging, would result in a corresponding $355,000 per month ($4.3 million annualized) change in our pre-tax operating cash flow. The average price we received for our natural gas production, including the effect of hedging, during the first nine months of 2011 was $4.33 compared to $5.71 for the first nine months of 2010. Based on our first nine months of 2011 production, a $1.00 per barrel change in our oil price, without the effect of hedging, would have a $185,000 per month ($2.2 million annualized) change in our pre-tax operating cash flow and a $1.00 per barrel change in our NGL prices, without the effect of hedging, would have a $170,000 per month ($2.0 million annualized) change in our pre-tax operating cash flow. In the first nine months of 2011, our average oil price per barrel received, including the effect of hedging, was $86.80 compared with an average oil price, including the effect of hedging, of $67.05 in the first nine months of 2010 and our first nine months of 2011 average NGLs price per barrel received was $43.72 compared with an average NGL price per barrel of $35.91 in the first nine months of 2010.

Because commodity prices have an effect on the value of our oil, NGLs and natural gas reserves, declines in those prices can result in a decline in the carrying value of our oil and natural gas properties. Price declines can also adversely affect the semi-annual determination of the amount available for us to borrow under our credit agreement since that determination is based mainly on the value of our oil, NGLs and natural gas reserves. A reduction could limit our ability to carry out our planned capital projects.

Our natural gas production is sold to intrastate and interstate pipelines, to independent marketing firms and gatherers under contracts with terms generally ranging anywhere from one month to five years. Our oil production is sold to independent marketing firms generally in nine month increments.

Midstream Operations

This segment is engaged primarily in the buying, selling, gathering, processing and treating of natural gas and operates three natural gas treatment plants, 10 processing plants, 34 gathering systems and 910 miles of pipeline. Our operations are located in Oklahoma, Texas, Kansas, Pennsylvania and West Virginia. This segment enhances our ability to gather and market not only our own natural gas but also that owned by third parties and serves as a mechanism through which we can construct or acquire existing natural gas gathering and processing facilities. During the first nine months of 2011 and 2010, this segment purchased $52.5 million and $30.5 million, respectively, of our oil and natural gas segment’s production and provided gathering and transportation services to our oil and natural gas segment of $3.5 million and $3.2 million, respectively. Intercompany revenue from services and purchases of production between our midstream segment and our oil and natural gas segment have been eliminated in our unaudited condensed consolidated financial statements.

Our midstream segment gathered an average of 201,788 MMBtu per day in the first nine months of 2011 compared to 182,390 MMBtu per day in the first nine months of 2010. Processed volumes were 102,493 MMBtu per day in the first nine months of 2011 compared to 81,157 MMBtu per day in the first nine months of 2010. The amount of NGLs we sold was 378,585 gallons per day in the first nine months of 2011 compared to 264,679 gallons per day in the first nine months of 2010. Gas gathering volumes per day in the first nine months of 2011 increased 11% compared to the first nine months of 2010 primarily from wells connected to our systems throughout 2011. Processed volumes increased 26% over the comparative nine months and NGLs sold also increased 43% over the comparative period primarily due to the addition of wells connected, recent upgrades to several of our processing systems and the doubling in size of our Hemphill facility in the Texas Panhandle.

Our Credit Agreement and Senior Subordinated Notes

In May 2011, we used proceeds from the Notes offering to repay $220.3 million in outstanding debt under our credit agreement. We also terminated two $15.0 million interest rate swaps associated with that debt with a settlement cost to us of $1.5 million.

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On September 13, 2011, we entered into a Senior Credit Agreement (credit agreement) that replaces our previous credit agreement which was scheduled to mature on May 24, 2012. The credit agreement has a maturity date of September 13, 2016. The amount available to be borrowed is the lesser of the amount we elect as the commitment amount (currently $250.0 million) or the value of the borrowing base as determined by the lenders (currently $600.0 million), but in either event, not to exceed the maximum credit agreement amount of $750.0 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, in connection with this new credit agreement, we paid $1.6 million in origination, agency, syndication and other related fees. We are amortizing these fees over the life of the credit agreement. At September 30, 2011 and October 24, 2011, borrowings were $55.4 million and $72.4 million, respectively.

The lenders under our credit agreement and their respective participation interests are as follows:

Lender	Participation Interest
BOK (BOKF, NA, dba Bank of Oklahoma)		20.00%
BBVA Compass Bank		20.00%
BMO		16.80%
Bank of America, N.A.		16.80%
Comerica Bank		8.80%
Crédit Agricole		8.80%
BNP Paribas		8.80%
		100.00%

The amount of the borrowing base, which is subject to redetermination on April 1st and October 1st of each year, is based primarily on a percentage of the discounted future value of our oil and natural gas reserves. 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 agreement.

At our election, any part of the outstanding debt under the credit agreement may be fixed at a London Interbank Offered Rate (LIBOR). LIBOR interest is computed as the sum of the LIBOR base for the applicable term 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 term, or every 90 days, whichever is less. Borrowings not under LIBOR bear interest at the 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 September 30, 2011, $50.0 million of our $55.4 million in outstanding borrowings were subject to LIBOR.

We used borrowings under the credit agreement to pay off the commitments issued under our previous credit agreement. In addition, we can use borrowings for financing general working capital requirements for (a) exploration, development, production and acquisition of oil and gas properties, (b) acquisitions and operation of midstream assets, (c) issuance of standby letters of credit, (d) contract drilling services, and (e) general corporate purposes of the Borrowers.

The credit agreement prohibits, among other things:

• the payment of dividends (other than stock dividends) during any fiscal year in excess of 30% 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 agreement also requires that we have at the end of each quarter:

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

• a leverage ratio of funded debt to consolidated EBITDA (as defined in the credit agreement) for the most recently ended rolling four fiscal quarters of no greater than 4 to 1.

As of September 30, 2011, we were in compliance with the covenants contained in the credit agreement.

6.625% Senior Subordinated Notes

During the second quarter of 2011, we issued $250.0 million of 6.625% Senior Subordinated Notes due May 15, 2021. We used the net proceeds of approximately $244.0 million from the offering to repay our then outstanding debt under our revolving credit agreement and the remaining amount was used for general working capital purposes.

Capital Requirements

Drilling Dispositions, Acquisitions and Capital Expenditures. During the first half of 2010, we sold eight of our idle mechanical drilling rigs to an unaffiliated party. These drilling rigs ranged in horsepower from 800 to 1,000. Proceeds from this sale were $23.9 million resulting in a gain of $5.7 million which we recorded in the first quarter of 2010. The proceeds were used to refurbish and upgrade additional drilling rigs in our fleet allowing those drilling rigs to be used in horizontal drilling operations. We also placed into service in our Rocky Mountain division a 1,500 horsepower, diesel-electric drilling rig that previously had been placed on hold during 2009 by our customer.

In September 2010, we entered into a contract with an unaffiliated party under which we conveyed three of our idle mechanical drilling rigs and, in exchange, received a 1,200 horsepower electric drilling rig and $5.3 million. The three drilling rigs sold ranged in horsepower from 650 to 1,000. The transaction was closed in October and resulted in a gain of $3.5 million.

At the end of 2010, we began constructing five new 1,500 horsepower, diesel-electric drilling rigs. All of these drilling rigs are now completed and are working in the Bakken shale. Each of these five new drilling rigs is initially working under a two-year drilling contract. During the third quarter of 2011, we were awarded two additional new build rig contracts for 1,500 horsepower, diesel-electric drilling rigs. These new build rigs will initially be working under three year contracts. Delivery of the two rigs is scheduled for the fourth quarter of 2011. Both drilling rigs will be for our Rocky Mountain division operations. On completion of the additional drilling rigs, we will have 128 drilling rigs in our fleet.

Our anticipated 2011 capital expenditures for this segment are $174.0 million. At September 30, 2011, we had commitments to purchase approximately $5.3 million for drill pipe, top drives and related equipment over the next twelve months. We have spent $122.3 million for capital expenditures during the first nine months of 2011 compared to $85.7 million in the first nine months of 2010.

Oil and Natural Gas Acquisitions and Capital Expenditures. Most of our capital expenditures for this segment are discretionary and directed toward future growth. Our decision to increase our oil, NGLs and natural gas reserves through acquisitions or through drilling depends on the prevailing or expected market conditions, potential return on investment, future drilling potential and opportunities to obtain financing under the circumstances involved, all of which provide us with a large degree of flexibility in deciding when and if to incur these costs. We completed drilling 119 gross wells (62.20 net wells) in the first nine months of 2011 compared to 105 gross wells (57.33 net wells) in the first nine months of 2010. Total capital expenditures for the first nine months of 2011 by this segment, excluding a $20.9 million ARO liability, and $50.5 million for acquisitions, totaled $370.5 million. Currently we plan to participate in drilling approximately 160 gross wells in 2011 and estimate our total capital expenditures (excluding acquisitions) for this segment are anticipated to be approximately $435.0 million. Whether we are able to drill the full number of wells planned is dependent on a number of factors, many of which are beyond our control, including the availability of drilling rigs, availability of pressure pumping services, prices for oil, NGLs and natural gas, demand for oil, NGLs and natural gas, the cost to drill wells, the weather and the efforts of outside industry partners.

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In June 2010, we completed an acquisition of oil and natural gas properties from certain unaffiliated parties. The properties were purchased for approximately $73.7 million in cash, after post closing adjustments. After these adjustments, the acquisition included approximately 45,000 net leasehold acres and 10 producing oil wells. This acquisition targeted 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 consisting of approximately 32,000 net acres of undeveloped oil and gas leasehold located in Southwest Oklahoma and North Texas for approximately $17.6 million from an unaffiliated party.

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

On August 31, 2011, we acquired certain producing oil and gas properties for $30.5 million in cash, subject to closing adjustments, from an unaffiliated seller. Included in the acquisition were more than 500 wells located principally in the Oklahoma Arkoma Woodford and Hartshorne Coal plays along with other properties located throughout Oklahoma and Texas. The proved reserves associated with the acquisition are approximately 31.2 Bcfe (99% natural gas), 83% of which is proved developed. The acquisition also included approximately 55,000 net acres of which 96% is held by production.

Midstream Acquisitions and Capital Expenditures. During the fourth quarter of 2010, we completed the installation and start up of a 50.0 MMcf per day turbo-expander natural gas processing plant at our Hemphill facility in Canadian, Texas. With the expansion of this plant, the total processing capacity at our Hemphill facility has increased to approximately 100.0 MMcf per day. During the third quarter of 2011, we increased the capacity of this plant by 20 MMcf per day by replacing the turbo expander center section.

In our Mid-continent operations, we are in the process of replacing the existing plant on our Cashion system with a high-efficiency gas processing plant. The new plant is expected to be operational during the first quarter of 2012. It will increase our processing capacity and will improve our liquids recovery capability by 12 to 15%. The Cashion plant gathers gas across Logan, Canadian, Oklahoma and Kingfisher Counties in Oklahoma. In the Mississippi Lime play in Grant County, Oklahoma, our new gathering system and processing plant became operational in October. One well is online and three more wells are in the process of being connected. We anticipate an additional 25 to 30 wells to be connected during 2012 due to active drilling by multiple producers in the area around the plant. This is our entrance into the Mississippi Lime play.

In our Appalachian operations, we are in the final stages of completing a 16-mile, 16” pipeline and a compressor station in Preston County, West Virginia, which will have a capacity of approximately 220.0 MMcf per day. Currently, we have four wells connected with an expected total initial flow volume in the 8 to 10 MMcf per day range. Three additional wells have been drilled and are waiting on completion prior to being connected. We anticipate this pipeline will be operational during the fourth quarter of 2011. In addition to the Preston County pipeline, we recently signed a letter of intent with a third party to construct a pipeline in Allegheny and Butler Counties of Pennsylvania. First flow of gas from this new system is expected to occur in the fourth quarter of 2011. Expectations are that the first well will flow up to 10 MMcf per day, and we anticipate four more wells to be drilled and connected during the first half of 2012.

During the first nine months of 2011, our midstream segment incurred $59.3 million in capital expenditures as compared to $19.7 million in the first nine months of 2010. For 2011, we have budgeted capital expenditures of approximately $86.0 million.

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Contractual Commitments

At September 30, 2011, we had certain contractual obligations including the following:

	Payments Due by Period
	Total		Less Than 1 Year		2-3 Years		4-5 Years		After 5 Years
	(In thousands)
Long-term debt (1)	$	477,034	$	17,764	$	35,529	$	90,929	$	332,812
Operating leases (2)		4,779		1,615		2,677		487		0
Drill pipe, drilling components and equipment purchases (3)		5,338		5,338		0		0		0
Total contractual obligations	$	487,151	$	24,717	$	38,206	$	91,416	$	332,812

(1) See previous discussion in MD&A regarding our long-term debt. This obligation is presented in accordance with the terms of the Notes and credit agreement and includes interest calculated using our September 30, 2011 interest rates of 6.625% for the Notes and 2.2% for the credit agreement.

(2) We lease office space or yards in Elmwood, Elk City, Oklahoma City, Quinton and Tulsa, Oklahoma; Canadian and Houston, Texas; Denver and Englewood, Colorado; Pinedale, Wyoming; and Pittsburgh, Pennsylvania under the terms of operating leases expiring through January, 2015. Additionally, we have several equipment leases and lease space on short-term commitments to stack excess drilling rig equipment and production inventory.

(3) We have committed to purchase approximately $5.3 million of new drilling rig components, drill pipe, drill collars and related equipment over the next twelve months.

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At September 30, 2011, we also had the following commitments and contingencies that could create, increase or accelerate our liabilities:

	Estimated Amount of Commitment Expiration Per Period
Other Commitments	Total Accrued		Less Than 1 Year		2-3 Years		4-5 Years		After 5 Years
	(In thousands)
Deferred compensation plan (1)	$	2,266		Unknown		Unknown		Unknown		Unknown
Separation benefit plans (2)	$	6,480	$	831		Unknown		Unknown		Unknown
Derivative liabilities – commodity hedges	$	552	$	552	$	0	$	0	$	0
Asset retirement liability (3)	$	92,802	$	2,074	$	16,840	$	4,156	$	69,732
Gas balancing liability (4)	$	3,263		Unknown		Unknown		Unknown		Unknown
Repurchase obligations (5)	$	0		Unknown		Unknown		Unknown		Unknown
Workers’ compensation liability (6)	$	17,921	$	7,126	$	3,767	$	1,296	$	5,732

(1) We provide a salary deferral plan which allows participants to defer the recognition of salary for income tax purposes until actual distribution of benefits, which occurs at either termination of employment, death or certain defined unforeseeable emergency hardships. We recognize payroll expense and record a liability, included in other long-term liabilities in our Unaudited Condensed Consolidated Balance Sheets, at the time of deferral.

(2) Effective January 1, 1997, we adopted a separation benefit plan (“Separation Plan”). The Separation Plan allows eligible employees whose employment with us is involuntarily terminated or, in the case of an employee who has completed 20 years of service, voluntarily or involuntarily terminated, to receive benefits equivalent to four weeks salary for every whole year of service completed with the company up to a maximum of 104 weeks. To receive payments the recipient must waive certain claims against us in exchange for receiving the separation benefits. On October 28, 1997, we adopted a Separation Benefit Plan for Senior Management (“Senior Plan”). The Senior Plan provides certain officers and key executives of the company with benefits generally equivalent to the Separation Plan. The Compensation Committee of the Board of Directors has absolute discretion in the selection of the individuals covered in this plan. On May 5, 2004 we also adopted the Special Separation Benefit Plan (“Special Plan”). This plan is identical to the Separation Benefit Plan with the exception that the benefits under the plan vest on the earliest of a participant’s reaching the age of 65 or serving 20 years with the company. On December 31, 2008, all these plans were amended to bring the plans into compliance with Section 409A of the Internal Revenue Code of 1986, as amended.

(3) When a well is drilled or acquired, under “Accounting for Asset Retirement Obligations,” we record the fair value of liabilities associated with the retirement of long-lived assets (mainly plugging and abandonment costs for our depleted wells).

(4) We have recorded a liability for those properties we believe do not have sufficient oil, NGLs and natural gas reserves to allow the under-produced owners to recover their under-production from future production volumes.

(5) We formed The Unit 1984 Oil and Gas Limited Partnership and the 1986 Energy Income Limited Partnership along with private limited partnerships (the “Partnerships”) with certain qualified employees, officers and directors from 1984 through 2011, with a subsidiary of ours serving as general partner. The Partnerships were formed for the purpose of conducting oil and natural gas acquisition, drilling and development operations and serving as co-general partner with us in any additional limited partnerships formed during that year. The Partnerships participated on a proportionate basis with us in most drilling operations and most producing property acquisitions commenced by us for our own account during the period from the formation of the Partnership through December 31 of that year. These partnership agreements require, on the election of a limited partner, that we repurchase the limited partner’s interest at amounts to be determined by appraisal in the future. Repurchases in any one year are limited to 20% of the units outstanding. We made repurchases of $22,000 in 2011, $22,000 in 2010 and $1,000 in 2009.

(6) We have recorded a liability for future estimated payments related to workers’ compensation claims primarily associated with our contract drilling segment.

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Derivative Activities

Periodically we enter into hedge transactions covering part of the interest rate payable under our credit agreement as well as the prices to be received for a portion of our oil, NGLs and natural gas production.

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 agreement. Under these transactions we swap the variable interest rate we would otherwise incur on a portion of our bank debt for a fixed rate of interest. In May 2011, in association with the repayment of outstanding borrowings under our credit agreement, we terminated our two outstanding interest rate swaps that were previously accounted for as cash flow hedges, resulting in an increase of approximately $1.5 million in interest expense. Approximately $1.1 million of that expense was capitalized and is being amortized over the life of the assets.

Commodity Hedges. Our commodity hedging is intended to reduce our exposure to price volatility and manage price risks. Our decision on the type and quantity of our production and the price(s) of our hedge(s) is based, in part, on our view of current and future market conditions. Based on our third quarter 2011 average daily production, as of September 30, 2011, the approximated percentages of our production that we have hedged are as follows:

Oil and Natural Gas Segment:

	Q4’11			Q1’12			Q2’12			Q3’12			Q4’12			2013
Daily oil production		59	%		67	%		67	%		67	%		67	%		30	%
Daily natural gas production		58	%		33	%		33	%		33	%		33	%		0	%
Natural gas liquids production		40	%		31	%		11	%		2	%		2	%		0	%

With respect to the commodities subject to our hedges, the use of hedging limits the risk of adverse downward price movements, however it also limits increases in future revenues that would otherwise result from price movements above the hedged prices.

The use of derivative transactions carries with it the risk that the counterparties will not be able to meet their financial obligations under the transactions. Based on our evaluation at September 30, 2011, we determined that there was no material risk of non-performance by our counterparties. At September 30, 2011, the fair values of the net assets (liabilities) we had with each of the counterparties to our commodity derivative transactions are as follows:

	September 30, 2011
	(In millions)
Bank of Montreal	$	27.8
BNP Paribas		11.8
Crédit Agricole Corporate and Investment Bank, London Branch		11.0
Comerica Bank		6.1
Bank of America, N.A.		4.1
BBVA Compass Bank		3.7
Macquarie Bank		0.4
BP Corporation		0.3
Barclays Capital		(0.5	)
Total assets (liabilities)	$	64.7

If a legal right of set-off exists, we net the value of the derivative arrangements we have with the same counterparty in our consolidated balance sheets. At September 30, 2011, we recorded the fair value of our commodity derivatives on our balance sheet as current and non-current derivative assets of $41.3 million and $24.0 million, respectively, and current derivative liabilities of $0.6 million. At September 30, 2010, we recorded the fair

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value of our commodity derivatives on our balance sheet as current and non-current derivative assets of $19.4 million and $5.7 million, respectively, and current and non-current derivative liabilities of $0.1 million and $2.6 million, respectively.

We recognize in accumulated 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 September 30, 2011, we had a gain of $37.3 million, net of tax from our oil and natural gas segment derivatives in accumulated OCI.

Based on market prices at September 30, 2011, we expect to transfer to earnings a gain of approximately $25.0 million, net of tax, of the loss included in accumulated OCI during the next 12 months in the related month of production. The commodity derivative instruments existing as of September 30, 2011 are expected to mature by December 2013.

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 currently in the consolidated statements of income as unrealized gains (losses) 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 currently in our oil and natural gas revenues as unrealized gains (losses). The effect of these realized and unrealized gains and losses on our revenues and expenses were as follows at September 30:

	Three Months Ended September 30,					Nine Months Ended September 30,
	2011		2010			2011			2010
	(In thousands)
Oil and natural gas revenue:
Realized gains (losses) on oil and natural gas derivatives	$	1,814	$	14,760		$	(1,343	)	$	36,447
Unrealized gains (losses) on ineffectiveness of cash flow hedges		2,336		176			4,158			605
Unrealized gains (losses) on non-qualifying oil and natural gas derivatives		128		(427	)		(547	)		597
Impact on pre-tax earnings	$	4,278	$	14,509		$	2,268		$	37,649

Stock and Incentive Compensation

During the first nine months of 2011, we granted awards covering 209,150 shares of restricted stock. These awards were granted as retention incentive awards. These stock awards had an estimated fair value as of the grant date of $10.9 million. Compensation expense will be recognized over their two and three year vesting periods, and during the first nine months of 2011, we recognized $2.8 million in additional compensation expense and capitalized $0.7 million for these awards. During the first nine months of 2011, we recognized compensation expense of $7.7 million for all of our restricted stock, stock options and SAR grants and capitalized $1.9 million of compensation cost for oil and natural gas properties.

Insurance

We are self-insured for certain losses relating to workers’ compensation, control of well and employee medical benefits. Insured policies for other coverage contain deductibles or retentions per occurrence that range from $50,000 to $1.0 million. We have purchased stop-loss coverage in order to limit, to the extent feasible, per occurrence and aggregate exposure to certain types of claims. However, there is no assurance that the insurance coverage will adequately protect us against liability from all potential consequences. We have elected to use an ERISA governed occupational injury benefit plan to cover all Texas drilling operations in lieu of covering them under Texas Workers’ Compensation. If insurance coverage becomes more expensive, we may choose to self-insure, decrease our limits, raise our deductibles or any combination of these rather than pay higher premiums.

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Oil and Natural Gas Limited Partnerships and Other Entity Relationships

We are the general partner of 16 oil and natural gas partnerships which were formed privately or publicly. Each partnership’s revenues and costs are shared under formulas set out in that partnership’s agreement. The partnerships repay us for contract drilling, well supervision and general and administrative expense. Related party transactions for contract drilling and well supervision fees are the related party’s share of such costs. These costs are billed on the same basis as billings to unrelated third parties for similar services. General and administrative reimbursements consist of direct general and administrative expense incurred on the related party’s behalf as well as indirect expenses assigned to the related parties. Allocations are based on the related party’s level of activity and are considered by us to be reasonable. For the first nine months of 2011 and 2010, the total we received for all of these fees was $2.4 million and $1.8 million, respectively. Our proportionate share of assets, liabilities and net income relating to the oil and natural gas partnerships is included in our unaudited condensed consolidated financial statements.

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.

Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and International Financial Reporting Standards (IFRS). In May 2011, the FASB issued ASU 2011-04 Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS. ASU 2011-4 is intended to improve the comparability of fair value measurements presented and disclosed in financial statements prepared in accordance with U.S. GAAP and IFRS. The amendments are of two types: (i) those that clarify the Board’s intent about the application of existing fair value measurement and disclosure requirements and (ii) those that change a particular principle or requirement for measuring fair value or for disclosing information about fair value measurements. The update is effective for annual periods beginning after December 15, 2011. We are in the process of evaluating the impact, if any, the adoption of this update will have on our financial statements.

Presentation of Comprehensive Income. In June 2011, the FASB issued ASU 2011-05 – Presentation of Comprehensive Income. This ASU amends the Codification to allow an entity the option to present the total of comprehensive income, the components of net income, and the components of other comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive statements. In both choices, an entity is required to present each component of net income along with total net income, each component of other comprehensive income along with a total for other comprehensive income, and a total amount for comprehensive income. ASU 2011-05 eliminates the option to present the components of other comprehensive income as part of the statement of changes in stockholders’ equity. The amendments to the Codification in the ASU do not change the items that must be reported in other comprehensive income or when an item of other comprehensive income must be reclassified to net income.

ASU 2011-05 should be applied retrospectively. The amendments are effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. We are in the process of evaluating the option we will choose to present comprehensive income and the impact it will have on our financial statements.

Testing Goodwill for Impairment. In September 2011, the FASB issued ASU 2011-08 – Intangibles-Goodwill and Other (ASC 350): Testing Goodwill for Impairment. This ASU is intended to simplify how entities, both public and

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nonpublic, test goodwill for impairment. ASU 2011-08 permits an entity to first assess qualitative factors to determine whether it is “more likely than not” that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test described in ASC 350, Intangibles-Goodwill and Other. The more-likely-than-not threshold is defined as having a likelihood of more than 50%.

ASU 2011-08 is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011.

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Results of Operations

Quarter Ended September 30, 2011 versus Quarter Ended September 30, 2010

Provided below is a comparison of selected operating and financial data:

	Quarter Ended September 30,						Percent Change
	2011			2010
Total revenue	$	323,845,000		$	218,116,000			48	%
Net income	$	53,360,000		$	34,491,000			55	%
Contract Drilling:
Revenue	$	128,927,000		$	85,004,000			52	%
Operating costs excluding depreciation	$	73,004,000		$	45,406,000			61	%
Percentage of revenue from daywork contracts		100	%		100	%		0	%
Average number of drilling rigs in use		78.9			65.4			21	%
Average dayrate on daywork contracts	$	19,309		$	15,814			22	%
Depreciation	$	20,818,000		$	18,469,000			13	%
Oil and Natural Gas:
Revenue	$	134,897,000		$	96,562,000			40	%
Operating costs excluding depreciation, depletion and amortization	$	29,598,000		$	27,092,000			9	%
Average oil price (Bbl)	$	86.19		$	66.94			29	%
Average NGL price (Bbl)	$	45.40		$	31.67			43	%
Average natural gas price (Mcf)	$	4.39		$	5.55			(21	)%
Oil production (Bbl)		620,000			379,000			64	%
NGL production (Bbl)		578,000			378,000			53	%
Natural gas production (Mcf)		11,553,000			10,385,000			11	%
Depreciation, depletion and amortization rate (Boe)	$	15.00		$	12.00			25	%
Depreciation, depletion and amortization	$	47,195,000		$	30,091,000			57	%
Midstream Operations:
Revenue	$	60,688,000		$	37,429,000			62	%
Operating costs excluding depreciation and amortization	$	53,299,000		$	30,743,000			73	%
Depreciation and amortization	$	4,017,000		$	3,823,000			5	%
Gas gathered—MMBtu/day		228,247			183,161			25	%
Gas processed—MMBtu/day		129,820			84,175			54	%
Gas liquids sold—gallons/day		449,604			260,519			73	%
General and administrative expense	$	7,800,000		$	6,637,000			18	%
Interest expense, net	$	1,351,000		$	0			NM
Income tax expense	$	33,403,000		$	21,364,000			56	%
Average interest rate		6.1	%		3.1	%		97	%
Average long-term debt outstanding	$	288,014,000		$	133,559,000			116	%

(1) NM – A percentage calculation is not meaningful due to a zero-value denominator or a percentage change greater than 200.

Contract Drilling

Drilling revenues increased $43.9 million or 52% in the third quarter of 2011 versus the third quarter of 2010 primarily due to a 21% increase in the average number of drilling rigs in use during the third quarter of 2011 compared to the third quarter of 2010 and a 22% higher average dayrate in the third quarter of 2011 compared to the third quarter of 2010. Average drilling rig utilization increased from 65.4 drilling rigs in the third quarter of 2010 to 78.9 drilling rigs in the third quarter of 2011. Oil prices improved in the third quarter of 2011 compared to the third quarter of 2010, creating increased demand for drilling rigs.

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Drilling operating costs increased $27.6 million or 61% between the comparative third quarters of 2011 and 2010 primarily due to increased utilization and increased direct cost due to higher personnel cost. Due to an increase in activity over last year’s levels, competition to keep qualified labor has increased. Contract drilling depreciation increased $2.3 million or 13% primarily due to increased utilization and from capital expenditures for upgrades to existing drilling rigs in our fleet.

Oil and Natural Gas

Oil and natural gas revenues increased $38.3 million or 40% in the third quarter of 2011 as compared to the third quarter of 2010 primarily due to an increase in equivalent production volumes of 26% and an increase in oil and NGL prices partially offset by decreases in prices for natural gas. Average oil and NGL prices between the comparative quarters increased 29% to $86.19 per barrel and 43% to $45.40 per barrel, respectively, and natural gas prices decreased 21% to $4.39 per Mcf. In the third quarter of 2011, as compared to the third quarter of 2010, oil production increased 64%, NGL production increased 53% and natural gas production increased 11%. Production for third quarter 2010 was negatively impacted by an unexpected shut-in of some of our production from operational issues experienced at a third party facility that processes our Segno field production and production growth was hampered by the lack of availability of fracing services to complete wells.

Oil and natural gas operating costs increased $2.5 million or 9% between the comparative third quarters of 2011 and 2010 due to the increase in total wells and increased production between quarters partially offset by refunds of production taxes attributable to high-cost gas wells received during the third quarter of 2011. Lease operating expenses per Boe decreased 7% to $6.56.

Depreciation, depletion and amortization (“DD&A”) increased $17.1 million or 57% primarily due to a 25% increase in our DD&A rate and a 26% increase in equivalent production. The increase in our DD&A rate in the third quarter of 2011 compared to the third quarter of 2010 resulted primarily from increases throughout 2010 and the first nine months of 2011 from increased net book value on new reserves added. Our DD&A expense on our oil and natural gas properties is calculated each quarter utilizing period end reserve quantities adjusted for current period production.

Midstream

Our midstream revenues were $23.3 million or 62% higher for the third quarter of 2011 as compared to the third quarter of 2010 primarily due to higher NGL prices and higher volumes. The average price for NGLs sold increased 29% Gas processing volumes per day increased 54% between the comparative quarters and NGLs sold per day increased 73% between the comparative quarters. The increase in volumes processed per day is primarily attributable to the volumes added from new wells connected to existing systems and increased capacity of processing facilities. NGLs sold volumes per day increased due to both an increase in volumes processed, upgrades to several of our processing facilities and the doubling in size of our Hemphill facility in the Texas Panhandle. Gas gathering volumes per day increased 25% primarily from new well connections.

Operating costs increased $22.6 million or 73% in the third quarter of 2011 compared to the third quarter of 2010 primarily due to a 25% increase in prices paid for natural gas purchased and increased volumes from new connects. Depreciation and amortization increased $0.2 million, or 5%, primarily due to increased capital investment for system improvements and well connects. For 2011, we increased well connections over 2010 due to increased drilling activity by operators in the areas of our existing gathering systems along with the benefit of the additional processing capacity from the Hemphill facility completed during the fourth quarter of 2010.

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Other

General and administrative expenses increased $1.2 million or 18% in the third quarter of 2011 compared to the third quarter of 2010 primarily due to increases in employee costs.

Interest expense, net of capitalized interest, increased $1.4 million between the comparative third quarters of 2011 and 2010. We capitalized interest based on the net book value associated with undeveloped leasehold not being amortized, the construction of additional drilling rigs and the construction of gas gathering systems. Our average interest rate increased by 97% due to the Notes issued during the second quarter of 2011 and our average debt outstanding was $154.5 million higher in the third quarter of 2011 as compared to the third quarter of 2010 due to the drilling of developmental wells and construction of new rigs in 2011.

Income tax expense increased $12.0 million or 56% in the third quarter of 2011 compared to the third quarter of 2010 primarily due to increased income. Our effective tax rate was 38.5% for the third quarter of 2011 and 38.3% for the third quarter of 2010. Current income tax benefit for the third quarter of 2011 was $3.9 million due to a larger than expected net operating loss carryback recognized in the third quarter of 2011 compared to $8.6 million of total income tax benefit in the third quarter of 2010 due to expected bonus depreciation for 2010. We paid $0.6 million in income taxes during the third quarter of 2011.

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Nine Months Ended September 30, 2011 versus Nine Months Ended September 30, 2010

Provided below is a comparison of selected operating and financial data:

	Nine Months Ended September 30,						Percent Change
	2011			2010
Total revenue	$	862,745,000		$	629,269,000			37	%
Net income	$	144,206,000		$	102,819,000			40	%
Contract Drilling:
Revenue	$	342,098,000		$	217,919,000			57	%
Operating costs excluding depreciation	$	190,086,000		$	132,847,000			43	%
Percentage of revenue from daywork contracts		100	%		99	%		1	%
Average number of drilling rigs in use		74.0			58.2			27	%
Average dayrate on daywork contracts	$	18,663		$	15,037			24	%
Depreciation	$	57,333,000		$	48,700,000			18	%
Oil and Natural Gas:
Revenue	$	376,393,000		$	286,751,000			31	%
Operating costs excluding depreciation, depletion and amortization	$	93,796,000		$	75,943,000			24	%
Average oil price (Bbl)	$	86.80		$	67.05			29	%
Average NGL price (Bbl)	$	43.72		$	35.91			22	%
Average natural gas price (Mcf)	$	4.33		$	5.71			(24	)%
Oil production (Bbl)		1,767,000			1,002,000			76	%
NGL production (Bbl)		1,623,000			1,143,000			42	%
Natural gas production (Mcf)		32,730,000			30,121,000			9	%
Depreciation, depletion and amortization rate (Boe)	$	14.82		$	11.34			31	%
Depreciation, depletion and amortization	$	132,013,000		$	81,746,000			61	%
Midstream Operations:
Revenue	$	144,820,000		$	114,908,000			26	%
Operating costs excluding depreciation and amortization	$	119,143,000		$	92,407,000			29	%
Depreciation and amortization	$	11,627,000		$	11,746,000			(1	) %
Gas gathered—MMBtu/day		201,788			182,390			11	%
Gas processed—MMBtu/day		102,493			81,157			26	%
Gas liquids sold—gallons/day		378,585			264,679			43	%
General and administrative expense	$	22,188,000		$	19,372,000			15	%
Interest expense, net	$	2,078,000		$	0			NM
Income tax expense	$	90,275,000		$	63,689,000			42	%
Average interest rate		5.6	%		3.8	%		47	%
Average long-term debt outstanding	$	231,559,000		$	78,988,000			193	%

(1) NM – A percentage calculation is not meaningful due to a zero-value denominator or a percentage change greater than 200.

Contract Drilling

Drilling revenues increased $124.2 million or 57% in the first nine months of 2011 versus the first nine months of 2010 primarily due to a 27% increase in the average number of drilling rigs in use during the first nine months of 2011 compared to the first nine months of 2010 and a 24% higher average dayrate in the first nine months of 2011 compared to the first nine months of 2010. Average drilling rig utilization increased from 58.2 drilling rigs in the first nine months of 2010 to 74.0 drilling rigs in the first nine months of 2011. Oil prices improved in the first nine months of 2011 compared to the first nine months of 2010, creating increased demand for drilling rigs.

45

Drilling operating costs increased $57.2 million or 43% between the comparative nine month periods of 2011 and 2010 primarily due to increased utilization and increased direct cost due to higher personnel cost. Due to an increase in activity over last year’s levels, competition to keep qualified labor has increased. Starting in the third quarter 2010, we increased compensation for drilling personnel in Oklahoma, Texas and Louisiana and again at the end of the first quarter for drilling personnel in all divisions. Contract drilling depreciation increased $8.6 million or 18% primarily due to increased utilization and from capital expenditures for upgrades to existing drilling rigs in our fleet.

Oil and Natural Gas

Oil and natural gas revenues increased $89.6 million or 31% in the first nine months of 2011 as compared to the first nine months of 2010 primarily due to an increase in equivalent production volumes of 23% and an increase in oil and NGL prices partially offset by decreases in prices for natural gas. Average oil and NGL prices between the comparative quarters increased 29% to $86.80 per barrel and 22% to $43.72 per barrel, respectively, while natural gas prices decreased 24% to $4.33 per Mcf. In the first nine months of 2011, as compared to the first nine months of 2010, oil production increased 76%, NGL production increased 42% and natural gas production increased 9%. Oil production increased from our drilling program and from wells acquired over the last twelve months while gas production for the first nine months of 2010 was negatively impacted by an unexpected shut-in of some of our production from operational issues experienced at a third party facility that processes our Segno field production and production growth was hampered by the lack of availability of fracing services to complete wells.

Oil and natural gas operating costs increased $17.9 million or 24% between the comparative nine months of 2011 and 2010 due to increases in lease operating expenses due to increased well servicing costs and higher saltwater disposal fees and higher gross production taxes due to higher oil prices and revenue from increased production between quarters partially offset by refunds of production taxes attributable to high-cost gas wells received during the third quarter of 2011. Lease operating expenses per Boe decreased 1% to $6.64.

Depreciation, depletion and amortization (“DD&A”) increased $50.3 million or 61% primarily due to a 31% increase in our DD&A rate and a 23% increase in equivalent production. The increase in our DD&A rate in the first nine months of 2011 compared to the first nine months of 2010 resulted primarily from increased net book value from new reserves added throughout 2010 and in the first nine months of 2011. Our DD&A expense on our oil and natural gas properties is calculated each quarter utilizing period end reserve quantities adjusted for current period production.

Midstream

Our midstream revenues were $29.9 million or 26% higher for in the first nine months of 2011 as compared to the first nine months of 2010 primarily due to higher NGL volumes and prices. The average price for NGLs sold increased 19%. Gas processing volumes per day increased 26% between the comparative nine months and NGLs sold per day increased 43% between the comparative periods. The increase in volumes processed per day is primarily attributable to the volumes added from new wells connected to existing systems and increased capacity of processing facilities. NGLs sold volumes per day increased due to an increase in volumes processed, upgrades to several of our processing facilities and the doubling in size of our Hemphill facility in the Texas Panhandle. Gas gathering volumes per day increased 11% primarily from new well connections.

Operating costs increased $26.7 million or 29% in the first nine months of 2011 compared to the first nine months of 2010 primarily due to a 13% increase in prices paid for natural gas purchased and a 26% increase in gas purchased per day. Depreciation and amortization decreased $0.1 million, or 1%, primarily due to decreased amortization on our intangible asset. For 2011, we increased well connections over 2010 due to increased drilling activity by operators in the areas of our existing gathering systems along with the benefit of the additional processing capacity from the Hemphill facility completed during the fourth quarter of 2010.

46

Other

Other revenue of $9.7 million for the first nine months of 2010 was primarily attributable to the sale of eight mechanical drilling rigs and the sale of a gas pipeline in which we owned a 60% interest.

General and administrative expenses increased $2.8 million or 15% in the first nine months of 2011 compared to the first nine months of 2010 primarily due to increases in employee costs.

Interest expense, net of capitalized interest, increased $2.1 million between the comparative nine months of 2011 and 2010. We capitalized interest based on the net book value associated with undeveloped leasehold not being amortized, the construction of additional drilling rigs and the construction of gas gathering systems. Our average interest rate increased by 47% and our average debt outstanding was $152.6 million higher in the first nine months of 2011 as compared to the first nine months of 2010 due to the drilling of developmental wells and construction of new rigs in 2011.

Income tax expense increased $26.6 million or 42% in the first nine months of 2011 compared to the first nine months of 2010 primarily due to increased income. Our effective tax rate was 38.5% for the first nine months of 2011 and 38.3% for the first nine months of 2010. Current income tax benefit for the first nine months of 2011 was $3.9 million due to a larger than expected net operating loss carryback recognized in the third quarter of 2011 compared with $2.5 million of total income tax benefit for the first nine months of 2010 due to expected bonus depreciation for 2010. We paid $0.6 million in income taxes during the first nine months of 2011.

Safe Harbor Statement

This report, including information included in, or incorporated by reference from, future filings by us with the SEC, as well as information contained in written material, press releases and oral statements issued by or on our behalf, contain, or may contain, certain statements that are “forward-looking statements” within the meaning of federal securities laws. All statements, other than statements of historical facts, included or incorporated by reference in this report, which address activities, events or developments which we expect or anticipate will or may occur in the future are forward-looking statements. The words “believes,” “intends,” “expects,” “anticipates,” “projects,” “estimates,” “predicts” and similar expressions are used to identify forward-looking statements.

These forward-looking statements include, among others, such things as:

• the amount and nature of our future capital expenditures and how we expect to fund our capital expenditures;

• the number of wells to be drilled or reworked;

• prices for oil, NGLs and natural gas;

• demand for oil, NGLs and natural gas;

• our exploration and drilling prospects;

• the estimates of our proved oil, NGLs and natural gas reserves;

• oil, NGLs and natural gas reserve potential;

• development and infill drilling potential;

• expansion and other development trends of the oil and natural gas industry;

• our business strategy;

• production of oil, NGLs and natural gas reserves;

• the number of gathering systems and processing plants we plan to construct or acquire;

• volumes and prices for natural gas gathered and processed;

• expansion and growth of our business and operations;

• demand for our drilling rigs and drilling rig rates;

• our belief that the final outcome of our legal proceedings will not materially affect our financial results;

• our ability to timely secure third party services used in completing our wells; and

• our ability to transport or convey our oil and natural gas production to established pipeline systems.

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These statements are based on certain assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions and expected future developments as well as other factors we believe are appropriate in the circumstances. However, whether actual results and developments will conform to our expectations and predictions is subject to a number of risks and uncertainties which could cause actual results to differ materially from our expectations, including:

• the risk factors discussed in this report and in the documents we incorporate by reference;

• general economic, market or business conditions;

• the availability of and nature or lack of business opportunities that we pursue;

• demand for our land drilling services;

• changes in laws or regulations;

• decreases or increases in commodity prices; and

• other factors, most of which are beyond our control.

You should not place undue reliance on any of these forward-looking statements. Except as required by law, we disclaim any current intention to update forward-looking information and to release publicly the results of any future revisions we may make to forward-looking statements to reflect events or circumstances after the date of this report to reflect the occurrence of unanticipated events.

A more thorough discussion of forward-looking statements with the possible impact of some of these risks and uncertainties is provided in our Annual Report on Form 10-K filed with the SEC. We encourage you to get and read that document.

Item 3. Quantitative and Qualitative Disclosure About Market Risk

Our operations are exposed to market risks primarily because of changes in commodity prices and interest rates.

Commodity Price Risk. Our major market risk exposure is in the price we receive for our oil, NGLs and natural gas production. These prices are primarily driven by the prevailing worldwide price for crude oil and market prices applicable to our natural gas production. Historically, the prices we received for our oil and natural gas production have fluctuated and we expect these prices to continue to fluctuate. The price of oil, NGLs and natural gas also affects both the demand for our drilling rigs and the amount we can charge for the use of our drilling rigs. Based on our first nine months 2011 production, a $0.10 per Mcf change in what we are paid for our natural gas production, without the effect of hedging, would result in a corresponding $355,000 per month ($4.3 million annualized) change in our pre-tax operating cash flow. A $1.00 per barrel change in our oil price, without the effect of hedging, would have a $185,000 per month ($2.2 million annualized) change in our pre-tax operating cash flow and a $1.00 per barrel change in our NGL prices, without the effect of hedging, would have a $170,000 per month ($2.0 million annualized) change in our pre-tax operating cash flow.

We use hedging transactions to manage the risk associated with price volatility. Our decisions regarding the amount and prices at which we choose to hedge certain of our products is based, in part, on our view of current and future market conditions. The transactions we use include financial price swaps under which we will receive a fixed price for our production and pay a variable market price to the contract counterparty. Currently, we also have three basis swaps that do not qualify as cash flow hedges. These financial derivatives are intended to support oil and gas prices at targeted levels and to manage our exposure to oil and gas price fluctuations. We do not hold or issue derivative instruments for speculative trading purposes.

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Oil and Natural Gas Segment:

At September 30, 2011, the following cash flow hedges were outstanding:

Term	Commodity	Hedged Volume	Weighted Average Fixed Price for Swaps	Hedged Market
Oct’11 – Dec’11	Crude oil – swap	4,000 Bbl/day	$84.28	WTI – NYMEX
Jan’12 – Dec’12	Crude oil – swap	4,500 Bbl/day	$95.91	WTI – NYMEX
Jan’13 – Dec’13	Crude oil – swap	2,000 Bbl/day	$102.05	WTI – NYMEX
Oct’11 – Dec’11	Natural gas – swap	10,000 MMBtu/day	$4.43	CEGT
Oct’11 – Dec’11	Natural gas – swap	70,000 MMBtu/day	$4.87	IF – NYMEX (HH)
Oct’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	30,000 MMBtu/day	$5.05	IF – NYMEX (HH)
Jan’12 – Dec’12	Natural gas – swap	15,000 MMBtu/day	$5.62	IF – PEPL
Oct’11 – Dec’11	Liquids – swap (1)	2,024,418 Gal/mo	$1.07	OPIS – Conway
Oct’11 – Dec’11	Liquids – swap (1)	1,240,068 Gal/mo	$1.00	OPIS – Mont Belvieu
Jan’12 – Mar’12	Liquids – swap (1)	1,350,014 Gal/mo	$1.10	OPIS – Conway
Jan’12 – Mar’12	Liquids – swap (1)	1,155,018 Gal/mo	$0.91	OPIS – Mont Belvieu
Apr’12 – Dec’12	Liquids – swap (1)	180,006 Gal/mo	$2.11	OPIS – Conway
Apr’12 – Jun’12	Liquids – swap (1)	690,028 Gal/mo	$0.79	OPIS – Mont Belvieu

(1) Types of liquids involved are natural gasoline, ethane, propane, isobutane and normal butane.

(2) Types of liquids involved are natural gasoline.

(3) Types of liquids involved are natural gasoline and ethane.

At September 30, 2011, the following non-qualifying cash flow derivatives were outstanding:

Term	Commodity	Hedged Volume	Basis Differential	Hedged Market
Oct’11 – Dec’11	Natural gas – basis differential swap	15,000 MMBtu/day	($0.14)	Tenn Zone 0 – NYMEX
Oct’11 – Dec’11	Natural gas – basis differential swap	10,000 MMBtu/day	($0.21)	CEGT – NYMEX
Oct’11 – Dec’11	Natural gas – basis differential swap	10,000 MMBtu/day	($0.23)	PEPL – NYMEX

Interest Rate Risk. Our interest rate exposure relates to our long-term debt under our credit agreement and the Notes. The credit agreement debt, at our election bears interest at variable rates based on the Prime Rate or the LIBOR Rate. At our election, borrowings under our credit agreement may be fixed at the LIBOR Rate for periods of up to 180 days. Based on our average outstanding long-term debt subject to a variable rate in the first nine months of 2011, a 1% increase in the floating rate would reduce our annual pre-tax cash flow by approximately $2.9 million. Under our Notes payable, we pay a fixed rate of interest of 6.625% per year (payable semi-annually in arrears on May 15 and November 15 of each year, beginning on November 15, 2011).

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures. As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures under Exchange Act Rule 13a-15. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures are effective as of September 30, 2011 in ensuring the appropriate information is recorded, processed, summarized and reported in our periodic SEC filings relating to the company (including its consolidated subsidiaries) and is accumulated and communicated to the Chief Executive Officer, Chief Financial Officer and management to allow timely decisions.

Changes in Internal Controls. There were no changes in our internal controls over financial reporting during the nine months ended September 30, 2011 that have materially affected or are reasonably likely to materially affect our internal control over financial reporting, as defined in Rule 13a – 15(f) under the Exchange Act.

49

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

For information regarding legal proceedings, see Item 3 of our Form 10-K for the fiscal year ended December 31, 2010. There have been no significant changes to what was disclosed in the Form 10-K.

Item 1A. Risk Factors

In addition to the other information set forth in this report, you should carefully consider the factors discussed below, if any, and in Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2010, which could materially affect our business, financial condition or future results. The risks described in our Annual Report on Form 10-K are not the only risks facing our company. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition and/or operating results.

There have been no material changes to the risk factors disclosed in Item 1A in our Form 10-K for the year ended December 31, 2010.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

The following table provides information relating to our repurchase of common stock for the three months ended September 30, 2011:

Period	(a) Total Number  of Shares Purchased (1)		(b) Average Price Paid Per Share (2)		(c) Total Number of Shares Purchased As Part of Publicly Announced Plans or Programs (1)		(d) Maximum Number (or Approximate Dollar Value) of Shares That May Yet Be Purchased Under the Plans or Programs
July 1, 2011 to July 31, 2011		1,428	$	61.66		1,428		0
August 1, 2011 to August 31, 2011		19,634		44.32		19,634		0
September 1, 2011 to September 30, 2011		0		0		0		0
Total		21,062	$	45.50		21,062		0

(1) The shares were repurchased to remit withholding of taxes on the value of stock distributed with the third quarter 2011 vesting distribution for grants previously made from our “Unit Corporation Stock and Incentive Compensation Plan” adopted May 3, 2006.

(2) The price paid per common share represents the closing sales price of a share of our common stock as reported by the NYSE on the day that the stock was acquired by us.

Item 3. Defaults Upon Senior Securities

Not applicable.

Item 4. Reserved and Removed

Item 5. Other Information

Not applicable.

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Item 6. Exhibits

Exhibits:

10.1	Restricted Stock Award Agreement Form.
15	Letter re: Unaudited Interim Financial Information.
31.1	Certification of Chief Executive Officer under Rule 13a – 14(a) of the Exchange Act.
31.2	Certification of Chief Financial Officer under Rule 13a – 14(a) of the Exchange Act.
32	Certification of Chief Executive Officer and Chief Financial Officer under Rule 13a – 14(a) of the Exchange Act and 18 U.S.C. Section 1350, as adopted under Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS	XBRL Instance Document.
101.SCH	XBRL Taxonomy Extension Schema Document.
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB	XBRL Taxonomy Extension Labels Linkbase Document.
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	Unit Corporation
Date: November 3, 2011	By: /s/ Larry D. Pinkston
	LARRY D. PINKSTON
	Chief Executive Officer and Director
Date: November 3, 2011	By: /s/ David T. Merrill
	DAVID T. MERRILL
	Chief Financial Officer and
	Treasurer

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EX-10.1

Exhibit 10.1

UNIT CORPORATION

RESTRICTED STOCK AWARD AGREEMENT

PERSONAL AND CONFIDENTIAL

[DATE]

Participant name	[	]
Date of grant	[	]
Number of shares of restricted stock subject to this award	[	]

We are pleased to inform you that as an employee of Unit Corporation (“Unit”) or one of its Affiliates, you have been granted an award of shares of restricted stock under the Unit Corporation Stock and Incentive Compensation Plan (the “Plan”). This agreement memorializes the terms of that award. This award is subject to the terms and conditions that follow in this agreement.

The date of the award evidenced by this agreement (the “date of grant”) is set forth above.

Capitalized terms used but not defined in this agreement have the meaning given to them in the Plan.

1. Acceptance of award. This award can be accepted by signing your name in the space provided on the enclosed copy of this agreement and returning it to the Secretary of Unit, 7130 South Lewis Avenue, Suite 1000, Tulsa, Oklahoma 74136. Your signing and delivering a copy of this agreement will evidence your acceptance on the terms and conditions stated in this agreement.

2. Award. Unit hereby grants to you a restricted stock award consisting of [                    ] shares of restricted stock (the “Total Restricted Stock Award”), subject to the terms and conditions of this agreement.

3. Vesting and delivery of shares. Unless previously forfeited, Unit will deliver to you, or your designated beneficiary, or if none, to your devisees in the event of death, shares of Unit common stock (in lieu of the shares of restricted stock) as follows:

A. Time Vested Shares. Seventy percent of the Total Restricted Stock Award will constitute (the “Time Vested Shares”) and will vest in the amounts and on the dates set forth in the following schedule:

(i)	[             ]% of the Time Vested Shares will vest on [DATE];
(ii)	an additional [            ]% of the Time Vested Shares will vest on [DATE]; and
(iii)	the remaining [            ]% of the Time Vested Shares will vest on [DATE].

Each share of Time Vested Shares represents the right to receive one share of Unit common stock.

B. Performance Shares. The remaining [    ]% of the Total Restricted Stock Award (the “Performance Shares”), will vest based on Unit’s Total Stockholder Return compared to the Total Stockholder Return of the Peer Group during the Performance Period.

(a) The calculation of the exact number of shares to be issued to you based on the Performance Shares will be determined as follows:

Page 1 of 8

Performance criteria for purposes of this award will be based on the “Total Shareholder Return” for Unit and each company in the Peer Group (which will include dividends paid) and will be determined as follows:

“Total Stockholder  Return” = Change in Stock Price+Dividends Paid Beginning Stock Price

•     Beginning Stock Price	=	means the average closing sale price as reported on the New York Stock Exchange (or any other applicable trading market index) of one (1) share of common stock for the 15 day period ending on [DATE]. The Beginning Stock Price will be appropriately adjusted to reflect any stock splits, reverse stock splits or stock dividends during the Performance Period.
•     Change in Stock Price	=	means the difference between the Ending Stock Price and the Beginning Stock Price.
•     Dividends Paid	=	means the total of all cash and in-kind dividends paid on one (1) share of common stock during the Performance Period, if any.
•     Ending Stock Price	=	means the average closing sale price of one (1) share of common stock for the 15 trading days immediately ending on [DATE] as reported on the New York Stock Exchange (or any other applicable trading market index).
•     Performance Period	=	means the period starting [DATE] and ending [DATE].
•     Peer Group	=	means:

[                                         ]	[                                         ]
[                                         ]	[                                         ]
[                                         ]	[                                         ]
[                                         ]	[                                         ]
[                                         ]	[                                         ]
[                                         ]	[                                         ]
[                                         ]	[                                         ]
Note: If any member of the Peer Group ceases to have publicly traded common stock, the Committee may select a replacement company which will then be included in the above definition of Peer Group as of January 1, 2011 instead of the replaced member.

(b) Not later than ninety (90) days after the conclusion of the Performance Period, the Committee will determine and certify the extent to which the performance criteria have been achieved. The Performance Shares will vest on the date of the Committee’s certification, and the value of the shares will be based on the closing price of Unit’s stock on the NYSE on that date.

After the Total Stockholder Return Formula is applied to Unit and each of the companies in the Peer Group, Unit’s rank within the Peer Group will be determined and a “Performance Percentile Rank” will be assigned to Unit to reflect its performance relative to the Peer Group.

Finally, the number of shares of common stock to be distributed to you as Performance Shares will then be calculated by multiplying the maximum number of shares designated as Performance Shares (30% of the Total Restricted Stock Award) by the percentage multiplier corresponding to Unit’s relative Performance Percentile Rank, as set forth in the following chart:

Unit’s Performance Percentile Rank	Percentage Multiplier
(Unit TSR vs. peer TSR)	(% shares that will be received)
___	___
___	___
___	___
___	___
___	___
___	___

Interpolation will be used in the vesting calculation for percentile ranks that fall in between those stated above.

Page 2 of 8

(c) The Committee may adjust application of the Total Stockholder Return Formula as the performance criteria for the Performance Shares as required to recognize special or non-recurring situations or circumstances with respect to Unit or any company in the Peer Group for any year during the Performance Period arising from the acquisition or disposition of assets, costs associated with exit or disposal activities, or material impairments that are reported on a Form 8-K filed with the Securities and Exchange Commission.

C. Any distribution of shares to you under this award is subject to and conditioned on the requirement that you be actively employed with Unit or one of its Affiliates on the date the shares vest in accordance with this Agreement.

4. Issuance of restricted stock.

A. Unless you are advised otherwise by Unit, your unvested shares of restricted stock will be held in book entry form. You agree that Unit may give stop transfer instructions to the depository to ensure compliance with the provisions of this agreement. You hereby (i) acknowledge that your unvested shares of restricted stock will be held in book entry form on the books of Unit’s depository (or another institution specified by Unit), and irrevocably authorize Unit to take whatever action may be necessary or appropriate to effectuate a transfer of the record ownership of any such shares that are unvested and forfeited, (ii) agree to deliver to Unit, as a precondition to the issuance of any certificate or certificates with respect to unvested shares of restricted stock, one or more stock powers, endorsed in blank, with respect to those shares, and (iii) agree to take any other action as Unit may reasonably request to accomplish the transfer or forfeiture of any unvested shares of restricted stock that are forfeited under this agreement.

B. In the event the Secretary of Unit advises you that your unvested shares of restricted stock will be represented by a certificate, then, subject to the provisions of this agreement, Unit will issue and register on its books and records in your name a certificate (or certificates) in the amount of the shares of restricted stock subject to this award as set forth above. Each certificate will bear a legend, substantially in the following form:

“The sale or other transfer of the Shares of stock represented by this certificate, whether voluntary, involuntary, or by operation of law, is subject to certain restrictions on transfer as set forth in the Unit Corporation Stock and Incentive Compensation Plan, and in the associated Award Agreement. A copy of this Plan and such Award Agreement may be obtained from Unit Corporation.”

The certificate(s) will be retained by Unit (or its designee) until the time that all restrictions or conditions applicable to the shares have been satisfied or lapsed.

5. Restrictions. In addition to the other terms contained in this agreement or the Plan, the shares of restricted stock subject to this Agreement will be subject to the following restrictions:

A. Neither (i) the shares of restricted stock, (ii) the right to vote the shares of restricted stock, (iii) the right to receive dividends on the shares of restricted stock, or (iv) any other rights under this agreement may be sold, transferred, donated, exchanged, pledged, assigned, or otherwise alienated or encumbered until (and then only to the extent of) the shares of restricted stock are delivered to you.

B. You will have, with respect to the shares of restricted stock, all of the rights of a holder of shares, including the right to vote the shares and to receive any cash dividends thereon. The Committee, however, may determine that cash dividends will be automatically reinvested in additional shares which will become shares of restricted stock and will be subject to the same restrictions and other terms of this award. Unless otherwise determined by the Committee, dividends payable in shares will be treated as additional shares of restricted stock subject to the same restrictions and other terms of this award and you will deliver a stock power, duly endorsed in blank, relating to the additional shares of restricted stock on payment of any the dividend.

Page 3 of 8

C. During your lifetime the shares delivered under this agreement will only be delivered to you. Any shares of restricted stock transferred in accordance with this agreement will continue to be subject to the terms and conditions of this agreement, including, without limitation, the provisions of this Section 5. Any transfer permitted under this agreement will be promptly reported in writing to Unit’s Secretary.

6. Affect of death or disability. Despite what is provided for in Section 5, if your employment with Unit or one of its Affiliates terminates before you have vested in all or any shares of restricted stock by reason of your death or disability (as determined by the Committee in its sole discretion), the vesting requirements will be accelerated and all shares of restricted stock that have not vested will vest 100% as of the date of such death or disability.

7. Affect of other causes of termination of employment.

A. On termination of your employment with Unit or any of its Affiliates for any reason (except (i) in the event of death or disability under Section 6, (ii) as a result of a Change of Control subject to Section 10, or (iii) unless the Committee determines otherwise in the case of your retirement), you will forfeit all shares of restricted stock (or all shares of common stock) that have not been previously delivered to you.

B. For the purposes of this agreement, your employment by an Affiliate of Unit will be considered terminated on the date that the company by which you are employed is no longer an Affiliate of Unit.

8. Transfer of employment; leave of absence. A transfer of your employment from Unit to an Affiliate or vice versa, or from one Affiliate to another, without an intervening period, will not be deemed a termination of employment. If you are granted an authorized leave of absence, you will be deemed to have remained in the employ of the company by which you are employed during such leave of absence.

9. Adjustments in shares of restricted stock.

A. The existence of this agreement and the shares of restricted stock will not affect or restrict in any way the right or power of the board of directors or the stockholders of Unit (or any of its Affiliates) to make or authorize any reorganization or other change in its capital or business structure, any merger or consolidation, any issue of bonds, debentures, preferred or prior preference stock ahead of or affecting the shares or the shares of restricted stock, the dissolution or liquidation of the company or any sale or transfer of all or any part of its (or their) assets or business.

B. In the event of any corporate event or transaction that is subject to the provisions of Section 4.2 of the Plan, the Committee may make adjustments or amendments to the terms of this award as it deems appropriate under the circumstances, in its sole discretion. Any adjustments or amendments may include, but are not limited to, (i) changes in the number and kind of shares of restricted stock set forth above, (ii) changes in the grant price per share, and (iii) accelerating the delivery of the shares of restricted stock. The determination by the Committee as to the terms of any amendments or adjustments will be conclusive and binding.

10. Change of Control. Article 14 of the Plan will apply to the terms of this award in the event a Change of Control occurs, except that for purposes of this agreement, Section 14.2 will be deemed to be amended by deleting the following language from the first sentence: “if the Committee reasonably determines in good faith before the occurrence of a Change of Control” and replacing it with this language: “if a majority of the Committee members in place prior to the Change of Control reasonably determines in good faith, either before or after the Change of Control”. If you are an employee of an Affiliate of the Company the following will generally constitute a Change of Control: the stockholders or members, as the case may be, of the Affiliate approve a reorganization, merger or consolidation or sale or other disposition of all or substantially all of the assets of that Affiliate (an “Affiliate Transaction”); excluding, however, an Affiliate Transaction under which (i) all or substantially all of the individuals or entities who are the owners of the Affiliate immediately before the Affiliate Transaction will beneficially own, directly or indirectly, more than 70% of the outstanding securities of

Page 4 of 8

the entity resulting from the Affiliate Transaction, (ii) no Person (other than: the Company; the entity resulting from the Affiliate Transaction; and any Person which beneficially owned, immediately before the Affiliate Transaction, directly or indirectly, 25% or more of the outstanding securities of the Affiliate) will beneficially own, directly or indirectly, 25% or more of the outstanding equity of the entity resulting from the Affiliate Transaction and (iii) individuals who were members of the incumbent board of directors (or managers, as the case may be) of the Affiliate will constitute a majority of the members of the board of directors (or managers, as the case may be) of the entity resulting from the Affiliate Transaction.

11. Tax matters.

A. Federal income and employment tax withholding (and state and local income tax withholding, if applicable) may be required in respect of taxes on income realized when restrictions are removed from the shares of restricted stock. You are required to deliver to Unit the amounts that it determines should be withheld, provided, however, that you may pay a portion or all of the withholding taxes by electing to have (i) Unit withhold a portion of the shares that would otherwise be delivered to you or (ii) you can deliver to Unit shares that you have owned for at least six months, in either case, having a Fair Market Value (as of the date that the amount of taxes is to be withheld) in the amount to be withheld, and provided further that your election will be irrevocable. Unless otherwise required under applicable law, for purposes of this Section 11, Fair Market Value means the closing price of the shares on the NYSE on the date the restrictions are removed.

B. You acknowledge that you have reviewed with your own tax advisor(s) the federal, state, and local tax consequences of accepting the shares of restricted stock and the other transactions contemplated by this agreement. You are relying solely on such advisor(s) and not on any statements or representations of the Company or any of its agents. You understand and agree that you, and not the Company, will be responsible for your own tax liability that may arise as a result of the transactions contemplated by this agreement. You understand that Section 83 of the Code taxes as ordinary income the difference between the purchase price, if any, for the shares of restricted stock and the Fair Market Value of the shares of restricted stock as of the date any restrictions on the shares of restricted stock terminate or lapse. In this context, “restrictions” includes the restrictions pursuant to Section 3 of this agreement. You understand that you may elect to be taxed at the time the shares of restricted stock are granted, rather than when and as the restrictions terminate or lapse (if ever), by filing an election under Section 83(b) of the Code with the Internal Revenue Service within thirty (30) days from the grant date. YOU ACKNOWLEDGE THAT IT IS YOUR SOLE RESPONSIBILITY (AND NOT THE COMPANY’S) TO FILE TIMELY THE ELECTION UNDER SECTION 83(B), EVEN IF YOU REQUEST THE COMPANY OR ITS REPRESENTATIVES TO MAKE THAT FILING ON YOUR BEHALF.

12. Employment. Nothing contained in this agreement or the Plan will confer on you any right to continue in the employ or other service of Unit or any of its Affiliates or limit in any way the right of your employer to change your compensation or other benefits or to terminate your employment or other service with or without Cause.

13. Short-swing trading. An executive officer of Unit who receives an award of restricted stock must report the transaction on a Form 4 Statement of Changes in Beneficial Ownership filed within two trading days with the EDGAR database of the Securities and Exchange Commission. While the General Counsel of Unit will draft the Form 4 on your request, the filing is your personal responsibility. Further, executive officers should review Unit Corporation’s Statement of Company Trading Policy before making arrangements for the sale of shares.

14. Forfeiture of award. If at any time during your employment by Unit or one of its Affiliates the Committee determines that you have engaged in any activity in competition with any activity of Unit or its Affiliates, or activity or conduct that is inimical, contrary or harmful to the interests of Unit or its Affiliates, including but not limited to:

A. conduct relating to your employment for which either criminal or civil penalties against you may be sought;

Page 5 of 8

B. conduct or activity that results in the termination of your employment because of your: (i) failure to abide by your employer’s rules and regulations governing the transaction of its business, including without limitation, its Code of Business Ethics and Conduct; (ii) inattention to duties, or the commission of acts while employed with your employer amounting to negligence or misconduct; (iii) misappropriation of funds or property of Unit or any of its Affiliates or committing any fraud against Unit or any of its Affiliates or against any other person or entity in the course of employment with Unit or any of its Affiliates; (iv) misappropriation of any corporate opportunity, or otherwise obtaining personal profit from any transaction which is adverse to the interests of Unit or any of its Affiliates or to the benefits of which Unit or any of its Affiliates is entitled; or (v) the commission of a felony or other crime involving moral turpitude;

C. accepting employment with, acquiring a 5% or more equity or participation interest in, serving as a consultant, advisor, director or agent of, directly or indirectly soliciting or recruiting any employee of Unit or any of its Affiliates who was employed at any time during your tenure with Unit of an of its Affiliates, or otherwise assisting in any other capacity or manner any company or enterprise that is directly or indirectly in competition with or acting against the interests of Unit or any of its Affiliates (a “competitor”), except for (i) any isolated, sporadic accommodation or assistance provided to a competitor, at its request, by you during your tenure with Unit or any of its Affiliates, but only if provided in the good faith and reasonable belief that such action would benefit Unit or any of its Affiliates by promoting good business relations with the competitor and would not harm Unit or any of its Affiliates interests in any substantial manner or (ii) any other service or assistance that is provided at the request or with the written permission of Unit or any of its Affiliates;

D. disclosing or misusing any confidential information or material concerning Unit or any of its Affiliates; or

E. making any statement or disclosing any information to any customers, suppliers, lessors, lessees, licensors, licensees, regulators, employees or others with whom Unit or any of its Affiliates engages in business that is defamatory or derogatory with respect to the business, operations, technology, management, or other employees of Unit or any of its Affiliates, or taking any other action that could reasonably be expected to injure Unit or any of its Affiliates in its business relationships with any of the foregoing parties or result in any other detrimental effect on Unit or any of its Affiliates;

then this award of shares of restricted stock will automatically terminate and be forfeited effective on the date on which you breached this Section 14 as determined by the Committee and (i) all shares acquired by you under this agreement (or other securities into which those shares have been converted or exchanged) will be returned to Unit or, if no longer held by you, you will pay to Unit, without interest, all cash, securities or other assets received by you on the sale or transfer of such stock or securities, and (ii) all unvested shares of restricted stock will be forfeited.

F. If you owe any amount under the above subsections of this Section 14, you acknowledge that your employer may, to the fullest extent permitted by applicable law, deduct such amount from any amounts your employer owes you from time to time for any reason (including without limitation amounts owed to you as salary, wages, reimbursements or other compensation, fringe benefits, retirement benefits or vacation pay). Whether or not your employer elects to make any such set-off in whole or in part, if your employer does not recover by means of set-off the full amount you owe it, you hereby agree to pay immediately the unpaid balance to your employer.

15. Listing; securities considerations. Despite anything else in this agreement, if at any time Unit determines, in its sole discretion, that the listing, registration or qualification (or any updating of any such document) of the shares issuable under this agreement is necessary on any securities exchange or under any federal or state securities or blue sky law, or that the consent or approval of any governmental regulatory body is necessary or desirable as a condition of, or in connection with the issuance of the shares of restricted stock, or the removal of any restrictions imposed on such shares, such shares will not be issued, in whole or in part, or the restrictions on the shares removed, unless such listing, registration, qualification, consent or approval will have been effected or obtained free of any conditions not acceptable to Unit.

Page 6 of 8

16. Binding effect. This agreement will inure to the benefit of and be binding on the parties to this agreement and their respective heirs, executors, administrators, legal representatives and successors. Without limiting the generality of the foregoing, whenever the term “you” is used in any provision of this agreement under circumstances where the provision appropriately applies to the heirs, executors, administrators or legal representatives to whom this award may be transferred as provided for in this agreement, the term “you” will be deemed to include that person or persons.

17. Plan provisions govern.

A. This award is subject to the terms, conditions, restrictions and other provisions of the Plan as fully as if all those provisions were set forth in their entirety in this agreement. If any provision of this agreement conflicts with a provision of the Plan, the Plan provision will control.

B. You acknowledge that a copy of the Plan and a prospectus summarizing the Plan was distributed or made available to you and that you were advised to review that material before entering into this agreement. You waive the right to claim that the provisions of the Plan are not binding on you and your heirs, executors, administrators, legal representatives and successors.

C. By your signature below, you represent that you are familiar with the terms and provisions of the Plan, and hereby accept this agreement subject to all of the terms and provisions of the Plan. You have reviewed the Plan and this agreement in their entirety and fully understand all provisions of this agreement. You agree to accept as binding, conclusive and final all decisions or interpretations of the Committee on any questions arising under the Plan or this agreement.

18. Governing law. This agreement will be governed by and construed in accordance with the laws of the State of Oklahoma despite any laws of the State of Oklahoma that would apply the laws of a different State.

19. Severability. If any term or provision of this agreement, or the application of this agreement to any person or circumstance, will at any time or to any extent be invalid, illegal or unenforceable in any respect as written, both parties intend for any court construing this agreement to modify or limit that provision so as to render it valid and enforceable to the fullest extent allowed by law. Any provision that is not susceptible of reformation will be ignored so as to not affect any other term or provision of this agreement, and the remainder of this agreement, or the application of that term or provision to persons or circumstances other than those as to which it is held invalid, illegal or unenforceable, will not be affected thereby and each term and provision of this agreement will be valid and enforced to the fullest extent permitted by law.

20. Consent to electronic delivery; electronic signature. In lieu of receiving documents in paper format, you agree, to the fullest extent permitted by law, to accept electronic delivery of any documents that may be required to be deliver to you (including, but not limited to, prospectuses, prospectus supplements, grant or award notifications and agreements, account statements, annual and quarterly reports, and all other forms of communications) in connection with this and any other award made or offered by Unit. Electronic delivery may be via electronic mail system or by reference to a location on a company intranet to which you have access. You hereby consent to any and all procedures Unit has established or may establish for an electronic signature system for delivery and acceptance of any such documents that may be required to be delivered to you, and agrees that your electronic signature is the same as, and will have the same force and effect as, your manual signature.

21. Entire agreement; modification. The Plan and this agreement contain the entire agreement between the parties with respect to the subject matter contained in this agreement and may not be modified except as provided in the Plan, as it may be amended from time to time in the manner provided in the Plan (or in this agreement), or as it may be amended from time to time by a written document signed by each of the parties to this agreement. Any oral or written agreements, representations, warranties, written inducements, or other communications with respect to the subject matter contained in this agreement made before the signing of this agreement will be void and ineffective for all purposes.

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22. Counterparts. This agreement may be signed in duplicate counterparts, each of which will be deemed to be an original.

UNIT CORPORATION:		PARTICIPANT:
By:	Mark E. Schell	[                                     ]
Title:	Senior Vice President

************************************************************************************************************

DESIGNATION OF BENEFICIARY

UNIT CORPORATION STOCK AND INCENTIVE COMPENSATION PLAN

I, [                                                     ] xxx-xx-[            ]             , hereby declare that in the event

                             Name                     Social Security No. (last 4 digits REQUIRED)

of my death while I am employed by the Company                                                                                                                           

                                                                      Name                     Social Security No. (last 4 digits REQUIRED)

(the “Beneficiary”) of                                                                                                                                                                                 ,

                                             Street Address                     City                         State                             Zip Code

who is my                                                                              , will be entitled to receive my undelivered shares of restricted stock

                                 Relationship to [                        ]

that are subject to this award having a date of grant of February 15, 2011.

It is understood that this Designation of Beneficiary is made under the Unit Corporation Stock and Incentive Compensation Plan and is subject to the terms and conditions stated in the plan, including the Beneficiary’s survival of my death. If any of those conditions are not satisfied, those rights will transfer according to my will or the laws of descent and distribution.

It is further understood that all prior Designations of Beneficiary made by me under the plan, if any, with regard to this Restricted Stock Award Agreement are hereby revoked. I reserve the right to change (revoke) this Designation of Beneficiary. Any change of this Designation of Beneficiary must be in writing, signed by me and filed with the Company before my death.

[                                     ] Date

Page 8 of 8

EX-15

Exhibit 15

November 3, 2011

Securities and Exchange Commission

100 F. Street, N.W.

Washington, D.C. 20549

Commissioners:

We are aware that our report dated November 3, 2011 on our review of interim financial information of Unit Corporation for the three and nine month periods ended September 30, 2011 and 2010 and included in the Company’s quarterly report on Form 10-Q for the quarter ended September 30, 2011 is incorporated by reference in its Registration Statements on Form S-3 (File No. 333-173884-02) and Form S-8 (File No.’s 33-19652, 33-44103, 33-49724, 33-64323, 33-53542, 333-38166, 333-39584, 333-135194, 333-137857 and 333-166605).

Very truly yours,

/s/ PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP

Tulsa, Oklahoma

EX-31.1

Exhibit 31.1

302 CERTIFICATIONS

I, Larry D. Pinkston, certify that:

1. I have reviewed this quarterly report on form 10-Q of Unit Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 3, 2011

/s/ Larry D. Pinkston

LARRY D. PINKSTON

Chief Executive Officer

and Director

EX-31.2

Exhibit 31.2

302 CERTIFICATIONS

I, David T. Merrill, certify that:

1. I have reviewed this quarterly report on form 10-Q of Unit Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 3, 2011

/s/    David T. Merrill

DAVID T. MERRILL

Chief Financial Officer

and Treasurer

EX-32

Exhibit 32

CERTIFICATION

PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

(SUBSECTIONS (A) AND (B) OF SECTION 1350, CHAPTER 63 OF TITLE 18, UNITED STATES CODE)

Pursuant to section 906 of the Sarbanes-Oxley Act of 2002 (subsections (a) and (b) of section 1350, chapter 63 of title 18, United States Code), each of the undersigned officers of Unit Corporation a Delaware corporation (the “Company”), does hereby certify, to such officer’s knowledge, that:

The Quarterly Report on Form 10-Q for the quarter ended September 30, 2011 (the “Form 10-Q”) of the Company fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934 and information contained in the Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of the Company as of September 30, 2011 and December 31, 2010 and for the three and nine month periods ended September 30, 2011 and 2010.

Dated: November 3, 2011

By:	/s/    Larry D. Pinkston
	Larry D. Pinkston
	Chief Executive Officer and Director

Dated: November 3, 2011

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

The foregoing certification is being furnished solely pursuant to section 906 of the Sarbanes-Oxley Act of 2002 (subsections (a) and (b) of section 1350, chapter 63 of title 18, United States Code) and is not being filed as part of the Form 10-Q or as a separate disclosure document.

A signed original of this written statement required by Section 906 of the Sarbanes-Oxley Act of 2002 has been provided to Unit Corporation and will be retained by Unit Corporation and furnished to the Securities and Exchange Commission or its staff on request.

XML

Industry Segment Information (Revenue From Different Segments) (Details) (USD $) In Thousands	3 Months Ended				9 Months Ended
	Sep. 30, 2011		Sep. 30, 2010		Sep. 30, 2011		Sep. 30, 2010
Industry Segment Information
Contract drilling	$ 140,193		$ 96,705		$ 381,982		$ 246,252
Elimination of inter-segment revenue	(11,266)		(11,701)		(39,884)		(28,333)
Contract drilling net of inter-segment revenue	128,927		85,004		342,098		217,919
Oil and natural gas	134,897		96,562		376,393		286,751
Gas gathering and processing	79,919		47,864		200,821		148,606
Elimination of inter-segment revenue	(19,231)		(10,435)		(56,001)		(33,698)
Gas gathering and processing net of inter-segment revenue	60,688		37,429		144,820		114,908
Other, net	(667)		(879)		(566)		9,691
Total revenues	323,845		218,116		862,745		629,269
Contract drilling	35,105		21,129		94,679		36,372
Oil and natural gas	58,104		39,379		150,584		129,062
Gas gathering and processing	3,372		2,863		14,050		10,755
Total operating income	96,581	[1]	63,371	[1]	259,313	[1]	176,189	[1]
General and administrative expense	(7,800)		(6,637)		(22,188)		(19,372)
Interest expense, net	(1,351)		0		(2,078)		0
Other income (loss), net	(667)		(879)		(566)		9,691
Income before income taxes	$ 86,763		$ 55,855		$ 234,481		$ 166,508

[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.

XML

Condensed Consolidated Balance Sheets (Parenthetical) (USD $) In Thousands, except Share data	Sep. 30, 2011	Dec. 31, 2010
Condensed Consolidated Balance Sheets
Accounts receivable, allowance for doubtful accounts	$ 5,083	$ 5,083
Preferred stock, par value	$ 1	$ 1
Preferred stock, shares authorized	5,000,000	5,000,000
Preferred stock, issued	0	0
Common stock, par value	$ 0.2	$ 0.2
Common stock, shares authorized	175,000,000	175,000,000
Common stock, shares issued	48,150,732	47,910,431

XML

Condensed Consolidated Statements Of Income (USD $) In Thousands, except Per Share data	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Revenues:
Contract drilling	$ 128,927	$ 85,004	$ 342,098	$ 217,919
Oil and natural gas	134,897	96,562	376,393	286,751
Gas gathering and processing	60,688	37,429	144,820	114,908
Other income (loss), net	(667)	(879)	(566)	9,691
Total revenues	323,845	218,116	862,745	629,269
Contract drilling:
Operating costs	73,004	45,406	190,086	132,847
Depreciation	20,818	18,469	57,333	48,700
Oil and natural gas:
Operating costs	29,598	27,092	93,796	75,943
Depreciation, depletion and amortization	47,195	30,091	132,013	81,746
Gas gathering and processing:
Operating costs	53,299	30,743	119,143	92,407
Depreciation and amortization	4,017	3,823	11,627	11,746
General and administrative	7,800	6,637	22,188	19,372
Interest, net	1,351	0	2,078	0
Total operating expenses	237,082	162,261	628,264	462,761
Income before income taxes	86,763	55,855	234,481	166,508
Income tax expense (benefit):
Current	(3,949)	(8,553)	(3,949)	(2,488)
Deferred	37,352	29,917	94,224	66,177
Total income taxes	33,403	21,364	90,275	63,689
Net income	$ 53,360	$ 34,491	$ 144,206	$ 102,819
Net income per common share:
Basic	$ 1.12	$ 0.73	$ 3.03	$ 2.18
Diluted	$ 1.11	$ 0.73	$ 3.01	$ 2.17

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Asset Retirement Obligations (Tables)

9 Months Ended

Sep. 30, 2011

Asset Retirement Obligations

Asset Retirement Obligations

	Nine Months Ended September 30,
	2011			2010
	(In thousands)
ARO liability, January 1:	$	69,265		$	56,404
Accretion of discount		2,598			2,138
Liability incurred (1)		12,674			2,901
Liability settled		(831	)		(622	)
Revision of estimates (2)		9,096			3,822
ARO liability, September 30:		92,802			64,643
Less current portion		2,074			1,617
Total long-term ARO liability	$	90,728		$	63,026

(1) Liability incurred in 2011 includes estimates for new wells acquired.

(2) Plugging liability estimates were revised upward in both 2011 and 2010 due to increases in the cost of services used to plug wells over the preceding years.

XML

Document And Entity Information	9 Months Ended
	Sep. 30, 2011	Oct. 24, 2011
Document And Entity Information
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2011
Document Fiscal Year Focus	2011
Document Fiscal Period Focus	Q3
Trading Symbol	unt
Entity Registrant Name	UNIT CORP
Entity Central Index Key	0000798949
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		48,150,732

XML

Fair Value Measurements (Recurring Fair Value Measurements) (Details) (USD $) In Thousands	Sep. 30, 2011	Dec. 31, 2010
Commodity Derivatives [Member]
Financial assets (liabilities)	$ 64,694	$ (9,086)
Commodity Derivatives [Member] | Level 2 [Member]
Financial assets (liabilities)	39,565	(19,954)
Commodity Derivatives [Member] | Level 3 [Member]
Financial assets (liabilities)	25,129	10,868
Interest Rate Swaps [Member] | Swap [Member]
Financial assets (liabilities)		(1,614)
Interest Rate Swaps [Member] | Swap [Member] | Level 2 [Member]
Financial assets (liabilities)		0
Interest Rate Swaps [Member] | Swap [Member] | Level 3 [Member]
Financial assets (liabilities)		$ (1,614)

XML

Fair Value Measurements (Tables)

9 Months Ended

Sep. 30, 2011

Fair Value Measurements

Recurring Fair Value Measurements

	September 30, 2011
	Level 2		Level 3		Total
	(In thousands)
Financial assets:
Commodity derivatives	$	39,565	$	25,129	$	64,694

	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	)

Reconciliations Of Level 3 Fair Value Measurements

	Net Derivatives
	For the Three Months Ended September 30, 2011					For the Nine Months Ended September 30, 2011
	Interest Rate Swaps		Commodity Swaps			Interest Rate Swaps			Commodity Swaps
	(In thousands)
Beginning of period	$	0	$	11,749		$	(1,614	)	$	10,868
Total gains or (losses) (realized and unrealized):
Included in earnings (1)		0		4,046			(1,734	)		11,923
Included in other comprehensive income		0		13,182			1,614			13,264
Settlements		0		(3,848	)		1,734			(10,926	)
End of period	$	0	$	25,129		$	0		$	25,129
Total gains for the period included in earnings attributable to the change in unrealized gains relating to assets still held at end of period	$	0	$	198		$	0		$	997

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

	Net Derivatives
	For the Three Months Ended September 30, 2010						For the Nine Months Ended September 30, 2010
	Interest Rate Swaps			Commodity Swaps and Collars			Interest Rate Swaps			Commodity Swaps and Collars
	(In thousands)
Beginning of period	$	(1,971	)	$	33,313		$	(1,948	)	$	19,948
Total gains or (losses) (realized and unrealized):
Included in earnings (1)		(298	)		16,558			(907	)		44,322
Included in other comprehensive income (loss)		39			(1,266	)		16			10,646
Purchases, issuance and settlements		298			(16,809	)		907			(43,120	)
End of period	$	(1,932	)	$	31,796		$	(1,932	)	$	31,796
Total gains (losses) for the period included in earnings attributable to the change in unrealized gains relating to assets still held at end of period	$	0		$	(251	)	$	0		$	1,202

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

XML

Fair Value Measurements (Narrative) (Details) (USD $) In Millions	Sep. 30, 2011
Fair Value Measurements
Carrying amount of long-term debt	$ 250.0
Estimated fair value of long-term debt	$ 249.4

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Accrued Liabilities

9 Months Ended

Sep. 30, 2011

Accrued Liabilities

Accrued Liabilities

NOTE 5 – ACCRUED LIABILITIES

Accrued liabilities consisted of the following:

	September 30, 2011		December 31, 2010
	(In thousands)
Employee costs	$	16,487	$	16,499
Lease operating expense		6,875		6,214
Taxes		24,804		1,310
Interest payable		7,010		667
Hedge settlements		524		1,634
Other		4,888		3,769
Total accrued liabilities	$	60,588	$	30,093

XML

Industry Segment Information (Tables)

9 Months Ended

Sep. 30, 2011

Industry Segment Information

Revenues From Different Segments

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
	(In thousands)
Revenues:
Contract drilling	$	140,193		$	96,705		$	381,982		$	246,252
Elimination of inter-segment revenue		(11,266	)		(11,701	)		(39,884	)		(28,333	)
Contract drilling net of inter-segment revenue		128,927			85,004			342,098			217,919
Oil and natural gas		134,897			96,562			376,393			286,751
Gas gathering and processing		79,919			47,864			200,821			148,606
Elimination of inter-segment revenue		(19,231	)		(10,435	)		(56,001	)		(33,698	)
Gas gathering and processing net of inter-segment revenue		60,688			37,429			144,820			114,908
Other, net		(667	)		(879	)		(566	)		9,691
Total revenues	$	323,845		$	218,116		$	862,745		$	629,269
Operating income:
Contract drilling	$	35,105		$	21,129		$	94,679		$	36,372
Oil and natural gas		58,104			39,379			150,584			129,062
Gas gathering and processing		3,372			2,863			14,050			10,755
Total operating income (1)		96,581			63,371			259,313			176,189
General and administrative expense		(7,800	)		(6,637	)		(22,188	)		(19,372	)
Interest expense, net		(1,351	)		0			(2,078	)		0
Other income (loss), net		(667	)		(879	)		(566	)		9,691
Income before income taxes	$	86,763		$	55,855		$	234,481		$	166,508

(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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Derivatives (Fair Value Of Derivative Instruments And Locations In Balance Sheets) (Details) (USD $) In Thousands	Sep. 30, 2011	Dec. 31, 2010
Current derivative assets	$ 41,257	$ 5,568
Non-current derivative assets	23,989	2,537
Total derivatives assets	65,246	8,105
Current derivative liabilities	552	14,446
Non-current derivative liabilities	0	4,359
Total derivative liabilities	552	18,805
Interest Rate Swaps [Member] | Designated As Hedging Instrument [Member]
Current derivative liabilities	0	1,139
Non-current derivative liabilities	0	475
Designated As Hedging Instrument [Member]
Total derivatives assets	65,246	7,628
Total derivative liabilities	342	18,664
Designated As Hedging Instrument [Member] | Commodity Contract [Member]
Current derivative assets	41,257	5,091
Non-current derivative assets	23,989	2,537
Current derivative liabilities	342	13,166
Non-current derivative liabilities	0	3,884
Not Designated As Hedging Instrument [Member]
Total derivatives assets	0	477
Total derivative liabilities	210	141
Not Designated As Hedging Instrument [Member] | Commodity Contract [Member]
Current derivative assets	0	477
Not Designated As Hedging Instrument [Member] | Commodity Basis Swap [Member]
Current derivative liabilities	$ 210	$ 141

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Stock-Based Compensation (Estimated Fair Value Of The Stock Options Granted) (Details) (USD $) In Millions, except Share data, unless otherwise specified	0 Months Ended	9 Months Ended
	May 05, 2010	Sep. 30, 2011 Stock Option [Member]		Sep. 30, 2010 Stock Option [Member]
Options granted	24,504	31,500	[1]	52,504	[1]
Estimated fair value		$ 0.7		$ 0.8
Estimate of stock volatility		0.48		0.45
Estimated dividend yield		0.00%		0.00%
Risk free interest rate		2.00%		2.00%
Expected annual life based on prior experience, years		5		5
Forfeiture rate		0.00%		0.00%
Contingent options	3,063
Number of directors receiving options	8

[1] On May 29, 2009, eight of our directors were each issued 3,063 options contingent on shareholder approval, which was received at the May 5, 2010 annual shareholders' meeting. These 24,504 options granted and vested simultaneously with that approval.

XML

Derivatives (Tables)

9 Months Ended

Sep. 30, 2011

Derivatives

Cash Flow Hedges Outstanding

Term	Commodity	Hedged Volume	Weighted Average Fixed Price for Swaps	Hedged Market
Oct'11– Dec'11	Crude oil – swap	4,000 Bbl/day	$84.28	WTI – NYMEX
Jan'12– Dec'12	Crude oil – swap	4,500 Bbl/day	$95.91	WTI – NYMEX
Jan'13 – Dec'13	Crude oil – swap	2,000 Bbl/day	$102.05	WTI – NYMEX
Oct'11 – Dec'11	Natural gas – swap	10,000 MMBtu/day	$4.43	CEGT
Oct'11– Dec'11	Natural gas – swap	70,000 MMBtu/day	$4.87	IF – NYMEX (HH)
Oct'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	30,000 MMBtu/day	$5.05	IF – NYMEX (HH)
Jan'12– Dec'12	Natural gas – swap	15,000 MMBtu/day	$5.62	IF – PEPL
Oct'11– Dec'11	Liquids – swap (1)	2,024,418 Gal/mo	$1.07	OPIS – Conway
Oct'11– Dec'11	Liquids – swap (1)	1,240,068 Gal/mo	$1.00	OPIS – Mont Belvieu
Jan'12– Mar'12	Liquids – swap (1)	1,350,014 Gal/mo	$1.10	OPIS – Conway
Jan'12– Mar'12	Liquids – swap (1)	1,155,018 Gal/mo	$0.91	OPIS – Mont Belvieu
Apr'12 – Dec'12	Liquids – swap (2)	180,006 Gal/mo	$2.11	OPIS – Conway
Apr'12– Jun'12	Liquids – swap (3)	690,028 Gal/mo	$0.79	OPIS – Mont Belvieu

(1) Types of liquids involved are natural gasoline, ethane, propane, isobutane and normal butane.

(2) Types of liquids involved are natural gasoline.

(3) Types of liquids involved are natural gasoline and ethane.

Non-qualifying Cash Flow Derivatives Outstanding

Term	Commodity	Hedged Volume	Basis Differential	Hedged Market
Oct'11– Dec'11	Natural gas – basis differential swap	15,000 MMBtu/day	($0.14)	Tenn Zone 0 – NYMEX
Oct'11– Dec'11	Natural gas – basis differential swap	10,000 MMBtu/day	($0.21)	CEGT – NYMEX
Oct'11– Dec'11	Natural gas – basis differential swap	10,000 MMBtu/day	($0.23)	PEPL – NYMEX

Fair Value Of Derivative Instruments And Locations In Balance Sheets

		Derivative Assets
		Fair Value
	Balance Sheet Location	September 30, 2011		December 31, 2010
		(In thousands)
Derivatives designated as hedging instruments
Commodity derivatives:
Current	Current derivative assets	$	41,257	$	5,091
Long-term	Non-current derivative assets		23,989		2,537
Total derivatives designated as hedging instruments			65,246		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		$	65,246	$	8,105

		Derivative Liabilities
		Fair Value
	Balance Sheet Location	September 30, 2011		December 31, 2010
		(In thousands)
Derivatives designated as hedging instruments
Interest rate swaps:
Current	Current derivative liabilities	$	0	$	1,139
Long-term	Non-current derivative liabilities		0		475
Commodity derivatives:
Current	Current derivative liabilities		342		13,166
Long-term	Non-current derivative liabilities		0		3,884
Total derivatives designated as hedging instruments			342		18,664
Derivatives not designated as hedging instruments
Commodity derivatives (basis swaps):
Current	Current derivative liabilities		210		141
Total derivatives not designated as hedging instruments			210		141
Total derivative liabilities		$	552	$	18,805

Amount Of Gain Or (Loss) Recognized In Accumulated OCI On Derivative

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	$	0	$	(1,193	)
Commodity derivatives		37,323		13,459
Total	$	37,323	$	12,266

Gain Or Loss Of Reclassified Accumulated Other Comprehensive Income And Recognized Income

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	$	2,003	$	14,760		$	2,336	$	176
Interest rate swaps	Interest, net		0		(298	)		0		0
	Total	$	2,003	$	14,462		$	2,336	$	176

(1) Effective portion of gain (loss).

(2) Ineffective portion of gain (loss).  

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	$	(882	)	$	36,447		$	4,158	$	605
Interest rate swaps	Interest, net		(1,734	)		(907	)		0		0
	Total	$	(2,616	)	$	35,540		$	4,158	$	605

(1) Effective portion of gain (loss).

(2) Ineffective portion of gain (loss).

Amount Of Gain (Loss) Recognized In Income On Derivative

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	$	(61	)	$	(427	)
Total		$	(61	)	$	(427	)

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	$	(1,008	)	$	597
Total		$	(1,008	)	$	597

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Derivatives

9 Months Ended

Sep. 30, 2011

Derivatives

Derivatives

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 agreement. 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. In May 2011, in association with the repayment of outstanding borrowings under our credit agreement, we terminated our two outstanding interest rate swaps that were previously accounted for as cash flow hedges, resulting in an increase of approximately $1.5 million in interest expense. Approximately $1.1 million of that expense was capitalized and will be amortized over the life of the assets.

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 September 30, 2011, our derivative transactions consisted of the following types of hedges:

• 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.

Oil and Natural Gas Segment:

At September 30, 2011, the following cash flow hedges were outstanding:

Term	Commodity	Hedged Volume	Weighted Average Fixed Price for Swaps	Hedged Market
Oct'11– Dec'11	Crude oil – swap	4,000 Bbl/day	$84.28	WTI – NYMEX
Jan'12– Dec'12	Crude oil – swap	4,500 Bbl/day	$95.91	WTI – NYMEX
Jan'13 – Dec'13	Crude oil – swap	2,000 Bbl/day	$102.05	WTI – NYMEX
Oct'11 – Dec'11	Natural gas – swap	10,000 MMBtu/day	$4.43	CEGT
Oct'11– Dec'11	Natural gas – swap	70,000 MMBtu/day	$4.87	IF – NYMEX (HH)
Oct'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	30,000 MMBtu/day	$5.05	IF – NYMEX (HH)
Jan'12– Dec'12	Natural gas – swap	15,000 MMBtu/day	$5.62	IF – PEPL
Oct'11– Dec'11	Liquids – swap (1)	2,024,418 Gal/mo	$1.07	OPIS – Conway
Oct'11– Dec'11	Liquids – swap (1)	1,240,068 Gal/mo	$1.00	OPIS – Mont Belvieu
Jan'12– Mar'12	Liquids – swap (1)	1,350,014 Gal/mo	$1.10	OPIS – Conway
Jan'12– Mar'12	Liquids – swap (1)	1,155,018 Gal/mo	$0.91	OPIS – Mont Belvieu
Apr'12 – Dec'12	Liquids – swap (2)	180,006 Gal/mo	$2.11	OPIS – Conway
Apr'12– Jun'12	Liquids – swap (3)	690,028 Gal/mo	$0.79	OPIS – Mont Belvieu

(1) Types of liquids involved are natural gasoline, ethane, propane, isobutane and normal butane.

(2) Types of liquids involved are natural gasoline.

(3) Types of liquids involved are natural gasoline and ethane.

At September 30, 2011, the following non-qualifying cash flow derivatives were outstanding:

Term	Commodity	Hedged Volume	Basis Differential	Hedged Market
Oct'11– Dec'11	Natural gas – basis differential swap	15,000 MMBtu/day	($0.14)	Tenn Zone 0 – NYMEX
Oct'11– Dec'11	Natural gas – basis differential swap	10,000 MMBtu/day	($0.21)	CEGT – NYMEX
Oct'11– Dec'11	Natural gas – basis differential swap	10,000 MMBtu/day	($0.23)	PEPL – NYMEX

The following tables present the fair values of our derivative transactions and the location within our balance sheets where those values are recorded:

		Derivative Assets
		Fair Value
	Balance Sheet Location	September 30, 2011		December 31, 2010
		(In thousands)
Derivatives designated as hedging instruments
Commodity derivatives:
Current	Current derivative assets	$	41,257	$	5,091
Long-term	Non-current derivative assets		23,989		2,537
Total derivatives designated as hedging instruments			65,246		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		$	65,246	$	8,105

		Derivative Liabilities
		Fair Value
	Balance Sheet Location	September 30, 2011		December 31, 2010
		(In thousands)
Derivatives designated as hedging instruments
Interest rate swaps:
Current	Current derivative liabilities	$	0	$	1,139
Long-term	Non-current derivative liabilities		0		475
Commodity derivatives:
Current	Current derivative liabilities		342		13,166
Long-term	Non-current derivative liabilities		0		3,884
Total derivatives designated as hedging instruments			342		18,664
Derivatives not designated as hedging instruments
Commodity derivatives (basis swaps):
Current	Current derivative liabilities		210		141
Total derivatives not designated as hedging instruments			210		141
Total derivative liabilities		$	552	$	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 September 30, 2011 and 2010, we had a gain of $37.3 million and $12.3 million, net of tax, respectively, in accumulated OCI.

Based on market prices at September 30, 2011, we expect to transfer a gain of approximately $25.0 million, net of tax, included in accumulated OCI during the next 12 months in the related month of settlement. The commodity derivative instruments existing as of September 30, 2011 are expected to mature by December 2013.

Certain derivatives do not qualify as cash flow hedges. Currently, three of our basis swaps do not qualify as cash flow hedges. For these derivatives, any changes in their fair value occurring before their maturity (i.e., temporary fluctuations in value) are reported in oil and natural gas revenues in our unaudited condensed consolidated statements of income. Changes in the fair value of derivatives 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 Unaudited Condensed Consolidated Statement of Income (cash flow hedges) for the nine months ended September 30:

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	$	0	$	(1,193	)
Commodity derivatives		37,323		13,459
Total	$	37,323	$	12,266

              (1) Net of taxes. 

Effect of Derivative Instruments on the Unaudited Condensed Consolidated Statement of Income (cash flow hedges) for the three months ended September 30:

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	$	2,003	$	14,760		$	2,336	$	176
Interest rate swaps	Interest, net		0		(298	)		0		0
	Total	$	2,003	$	14,462		$	2,336	$	176

(1) Effective portion of gain (loss).

(2) Ineffective portion of gain (loss).

Effect of Derivative Instruments on the Unaudited Condensed Consolidated Statement of Income (derivatives not designated as hedging instruments) for the three months ended September 30:

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	$	(61	)	$	(427	)
Total		$	(61	)	$	(427	)

Effect of Derivative Instruments on the Unaudited Condensed Consolidated Statement of Income (cash flow hedges) for the nine months ended September 30:

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	$	(882	)	$	36,447		$	4,158	$	605
Interest rate swaps	Interest, net		(1,734	)		(907	)		0		0
	Total	$	(2,616	)	$	35,540		$	4,158	$	605

(1) Effective portion of gain (loss).

(2) Ineffective portion of gain (loss).

Effect of Derivative Instruments on the Unaudited Condensed Consolidated Statement of Income (derivatives not designated as hedging instruments) for the nine months ended September 30:

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	$	(1,008	)	$	597
Total		$	(1,008	)	$	597

XML

Basis Of Preparation And Presentation

9 Months Ended

Sep. 30, 2011

Basis Of Preparation And Presentation

Basis Of Preparation And Presentation

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 along 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 our management's opinion, the accompanying condensed consolidated financial statements contain all normal recurring adjustments (including the elimination of all intercompany transactions) necessary to fairly state our:

• Balance Sheets at September 30, 2011 and December 31, 2010;

• Statements of Income for the three and nine months ended September 30, 2011 and 2010;

• Cash Flows for the nine months ended September 30, 2011 and 2010; and

• Statements of Comprehensive Income for the three and nine months ended September 30, 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 unaudited condensed consolidated financial statements and accompanying notes. Actual results may differ from those estimates. Results for the three and nine months ended September 30, 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 and nine month periods ended September 30, 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 November 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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Long-Term Debt And Other Long-Term Liabilities (Other Long-Term Liabilities) (Details) (USD $) In Thousands	Sep. 30, 2011	Dec. 31, 2010	Sep. 30, 2010	Dec. 31, 2009
Long-Term Debt And Other Long-Term Liabilities
Asset retirement obligations	$ 92,802	$ 69,265	$ 64,643	$ 56,404
Workers' compensation	17,921	17,566
Separation benefit plans	6,480	5,690
Gas balancing	3,263	3,263
Deferred compensation plan	2,266	2,368
Other liabilities	122,732	98,152
Less current portion	10,031	10,122
Total other long-term liabilities	$ 112,701	$ 88,030

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Asset Retirement Obligations

9 Months Ended

Sep. 30, 2011

Asset Retirement Obligations

Asset Retirement Obligations

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 (AROs). 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 plugging costs associated with our oil and gas wells.

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

	Nine Months Ended September 30,
	2011			2010
	(In thousands)
ARO liability, January 1:	$	69,265		$	56,404
Accretion of discount		2,598			2,138
Liability incurred (1)		12,674			2,901
Liability settled		(831	)		(622	)
Revision of estimates (2)		9,096			3,822
ARO liability, September 30:		92,802			64,643
Less current portion		2,074			1,617
Total long-term ARO liability	$	90,728		$	63,026

(1) Liability incurred in 2011 includes estimates for new wells acquired.

(2) Plugging liability estimates were revised upward in both 2011 and 2010 due to increases in the cost of services used to plug wells over the preceding years.

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Industry Segment Information

9 Months Ended

Sep. 30, 2011

Industry Segment Information

Industry Segment Information

NOTE 12 – INDUSTRY SEGMENT INFORMATION

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

• Contract drilling,

• Oil and natural gas and

• Midstream

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 midstream segment is engaged in the buying, selling, gathering, processing and treating of natural gas.

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 oil and natural gas production outside the United States is not significant.

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
	(In thousands)
Revenues:
Contract drilling	$	140,193		$	96,705		$	381,982		$	246,252
Elimination of inter-segment revenue		(11,266	)		(11,701	)		(39,884	)		(28,333	)
Contract drilling net of inter-segment revenue		128,927			85,004			342,098			217,919
Oil and natural gas		134,897			96,562			376,393			286,751
Gas gathering and processing		79,919			47,864			200,821			148,606
Elimination of inter-segment revenue		(19,231	)		(10,435	)		(56,001	)		(33,698	)
Gas gathering and processing net of inter-segment revenue		60,688			37,429			144,820			114,908
Other, net		(667	)		(879	)		(566	)		9,691
Total revenues	$	323,845		$	218,116		$	862,745		$	629,269
Operating income:
Contract drilling	$	35,105		$	21,129		$	94,679		$	36,372
Oil and natural gas		58,104			39,379			150,584			129,062
Gas gathering and processing		3,372			2,863			14,050			10,755
Total operating income (1)		96,581			63,371			259,313			176,189
General and administrative expense		(7,800	)		(6,637	)		(22,188	)		(19,372	)
Interest expense, net		(1,351	)		0			(2,078	)		0
Other income (loss), net		(667	)		(879	)		(566	)		9,691
Income before income taxes	$	86,763		$	55,855		$	234,481		$	166,508

(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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New Accounting Pronouncements

9 Months Ended

Sep. 30, 2011

New Accounting Pronouncements

New Accounting Pronouncements

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.

Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and International Financial Reporting Standards (IFRS). In May 2011, the FASB issued ASU 2011-04 Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS. ASU 2011-4 is intended to improve the comparability of fair value measurements presented and disclosed in financial statements prepared in accordance with U.S. GAAP and IFRS. The amendments are of two types: (i) those that clarify the Board's intent about the application of existing fair value measurement and disclosure requirements and (ii) those that change a particular principle or requirement for measuring fair value or for disclosing information about fair value measurements. The update is effective for annual periods beginning after December 15, 2011. We are in the process of evaluating the impact, if any, the adoption of this update will have on our financial statements.

Presentation of Comprehensive Income. In June 2011, the FASB issued ASU 2011-05 – Presentation of Comprehensive Income. This ASU amends the Codification to allow an entity the option to present the total of comprehensive income, the components of net income, and the components of other comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive statements. In both choices, an entity is required to present each component of net income along with total net income, each component of other comprehensive income along with a total for other comprehensive income, and a total amount for comprehensive income. ASU 2011-05 eliminates the option to present the components of other comprehensive income as part of the statement of changes in stockholders' equity. The amendments to the Codification in the ASU do not change the items that must be reported in other comprehensive income or when an item of other comprehensive income must be reclassified to net income.

ASU 2011-05 should be applied retrospectively. The amendments are effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. We are in the process of evaluating the option we will choose to present comprehensive income and the impact it will have on our financial statements.

Testing Goodwill for Impairment. In September 2011, the FASB issued ASU 2011-08 – Intangibles-Goodwill and Other (ASC 350): Testing Goodwill for Impairment. This ASU is intended to simplify how entities, both public and nonpublic, test goodwill for impairment. ASU 2011-08 permits an entity to first assess qualitative factors to determine whether it is "more likely than not" that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test described in ASC 350, Intangibles-Goodwill and Other. The more-likely-than-not threshold is defined as having a likelihood of more than 50%.

ASU 2011-08 is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011.

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Accrued Liabilities (Consisted Of Accrued Liabilities) (Details) (USD $) In Thousands	Sep. 30, 2011	Dec. 31, 2010
Accrued Liabilities
Employee costs	$ 16,487	$ 16,499
Lease operating expense	6,875	6,214
Taxes	24,804	1,310
Interest payable	7,010	667
Hedge settlements	524	1,634
Other	4,888	3,769
Total accrued liabilities	$ 60,588	$ 30,093

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Long-Term Debt And Other Long-Term Liabilities

9 Months Ended

Sep. 30, 2011

Long-Term Debt And Other Long-Term Liabilities

Long-Term Debt And Other Long-Term Liabilities

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:

	September 30, 2011		December 31, 2010
	(In thousands)
Credit agreement with average interest rates, of 2.2% and 3.5% at September 30, 2011 and December 31, 2010, respectively	$	55,400	$	163,000
6.625% senior subordinated notes due 2021		250,000		0
Total long-term debt	$	305,400	$	163,000

Credit Agreement. On September 13, 2011, we entered into a Senior Credit Agreement (credit agreement) that replaces our previous credit agreement which was scheduled to mature on May 24, 2012. The credit agreement has a maturity date of September 13, 2016. The amount available to be borrowed is the lesser of the amount we elect as the commitment amount (currently $250.0 million) or the value of the borrowing base as determined by the lenders (currently $600.0 million), but in either event, not to exceed the maximum credit agreement amount of $750.0 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, in connection with this new credit agreement, we paid $1.6 million in origination, agency, syndication and other related fees. We are amortizing these fees over the life of the credit agreement.

The amount of the borrowing base, which is subject to redetermination on April 1st and October 1st of each year, is based primarily on a percentage of the discounted future value of our oil and natural gas reserves. 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 agreement.

At our election, any part of the outstanding debt under the credit agreement may be fixed at a London Interbank Offered Rate (LIBOR). LIBOR interest is computed as the sum of the LIBOR base for the applicable term 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 term, or every 90 days, whichever is less. Borrowings not under LIBOR bear interest at the 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 September 30, 2011, $50.0 million of our $55.4 million in outstanding borrowings were subject to LIBOR.

We used borrowings under the credit agreement to pay off the commitments issued under our previous credit agreement. In addition, we can use borrowings for financing general working capital requirements for (a) exploration, development, production and acquisition of oil and gas properties, (b) acquisitions and operation of midstream assets, (c) issuance of standby letters of credit, (d) contract drilling services, and (e) general corporate purposes of the Borrowers.

The credit agreement prohibits, among other things:

• the payment of dividends (other than stock dividends) during any fiscal year in excess of 30% 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.

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

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

• a leverage ratio of funded debt to consolidated EBITDA (as defined in the credit agreement) for the most recently ended rolling four fiscal quarters of no greater than 4 to 1.

As of September 30, 2011, we were in compliance with the contained  in the credit agreement.

6.625% Senior Subordinated Notes. On May 18, 2011, we completed the sale of $250.0 million aggregate principal amount of our 6.625% Senior Subordinated Notes due 2021 (the Notes). The Notes were issued at par and mature on May 15, 2021. We received net proceeds of approximately $244.0 million after deducting fees of approximately $6.0 million. Those fees are being amortized as deferred financing costs over the life of the Notes. We used the net proceeds to repay outstanding borrowings under our credit agreement, which was $220.3 million on May 18, 2011. The remaining proceeds were used for general working capital purposes.

The Notes are guaranteed by our wholly-owned domestic direct and indirect subsidiaries (the Guarantors). 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. Any subsidiaries of Unit other than the Guarantors are minor. There are no significant restrictions on the ability of Unit to receive funds from its subsidiaries through dividends, loans, advances or otherwise.

The Notes were issued under an Indenture dated as of May 18, 2011, between us and Wilmington Trust FSB, as Trustee (the Trustee), as supplemented by the First Supplemental Indenture dated as of May 18, 2011, between us, the Guarantors and the Trustee, establishing the terms and providing for the issuance of the Notes (the Supplemental Indenture). The discussion of the Notes in this quarterly report is qualified by and subject to the actual terms of the Indenture and the First Supplemental Indenture.

The Notes bear interest at a rate of 6.625% per year (payable semi-annually in arrears on May 15 and November 15 of each year, beginning on November 15, 2011), and will mature on May 15, 2021.

On and after May 15, 2016, we may redeem all or, from time to time, a part of the Notes at certain redemption prices, plus accrued and unpaid interest. Before May 15, 2014, we may on any one or more occasions redeem up to 35% of the original principal amount of the Notes with the net cash proceeds of one or more equity offerings at a redemption price of 106.625% of the principal amount, plus accrued and unpaid interest, if any, to the redemption date, provided that at least 65% of the original principal amount of the Notes remains outstanding after each redemption. In addition, at any time before May 15, 2016, we may redeem the Notes, in whole or in part, at a redemption price equal to 100% of the principal amount plus a "make whole" premium, plus accrued and unpaid interest, if any, to the redemption date. If a "change of control" occurs, subject to certain conditions, we must offer to repurchase from each holder all or any part of that holder's Notes at a purchase price in cash equal to 101% of the principal amount of the Notes plus accrued and unpaid interest, if any, to the date of purchase. The Indenture and the Supplemental Indenture contain customary events of default. The Indenture governing the Notes contains covenants that, among other things, limit our ability and the ability of certain of our subsidiaries to incur or guarantee additional indebtedness; pay dividends on our capital stock or redeem capital stock or subordinated indebtedness; transfer or sell assets; make investments; incur liens; enter into transactions with our affiliates; and merge or consolidate with other companies. We were in compliance with all covenants of the Notes as of September 30, 2011.

Other Long-Term Liabilities

Other long-term liabilities consisted of the following:

	September 30, 2011		December 31, 2010
	(In thousands)
Asset retirement obligations	$	92,802	$	69,265
Workers' compensation		17,921		17,566
Separation benefit plans		6,480		5,690
Gas balancing		3,263		3,263
Deferred compensation plan		2,266		2,368
		122,732		98,152
Less current portion		10,031		10,122
Total other long-term liabilities	$	112,701	$	88,030

The estimated annual payments due under the terms of our other long-term liabilities during each of the five successive twelve month periods beginning October 1, 2011 (and through 2016) are $10.0 million, $16.9 million, $3.7 million, $3.0 million and $57.8 million, respectively.

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Condensed Consolidated Statements Of Comprehensive Income (USD $) In Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Condensed Consolidated Statements Of Comprehensive Income
Net income	$ 53,360	$ 34,491	$ 144,206	$ 102,819
Other comprehensive income (loss), net of taxes:
Change in value of derivative instruments used as cash flow hedges, net of tax of $27,015, $2,753, $28,201 and $18,780	43,154	4,148	45,123	30,014
Reclassification - derivative settlements, net of tax of ($771), ($5,646), $1,008 and ($13,708)	(1,232)	(8,816)	1,608	(21,832)
Ineffective portion of derivatives, net of tax of ($899), ($67), ($1,601) and ($231)	(1,437)	(109)	(2,557)	(374)
Comprehensive income	$ 93,845	$ 29,714	$ 188,380	$ 110,627

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Oil And Natural Gas Properties

9 Months Ended

Sep. 30, 2011

Oil And Natural Gas Properties

Oil And Natural Gas Properties

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. Once incurred, a write-down of oil and natural gas properties is not reversible.

At September 30, 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 at September 30, 2011, consisted of swaps covering 1.8 MMBoe in 2011, 4.7 MMBoe in 2012 and 0.7 MMBoe in 2013. The effect of those hedges on the September 30, 2011 ceiling test was a $13.7 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 Unaudited Condensed Consolidated Financial Statements.

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Derivatives (Narrative) (Details) (USD $) In Millions	1 Months Ended	9 Months Ended
	May 31, 2011	Sep. 30, 2011	Sep. 30, 2010
Number of outstanding interest rate swaps terminated	two
Accumulated OCI gain (loss) net of tax		$ 37.3	$ 12.3
Expected earnings transfer		25.0
Period over which gain included in AOCI will be transferred to earnings, months		12
Interest Rate Swaps [Member] | Cash Flow Hedging [Member]
Increase in interest expenses	1.5
Expense capitalized	1.1

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Earnings Per Share (Schedule Of Antidilutive Securities Excluded From Computation Of Earnings Per Share) (Details) (Derivative [Member], USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Derivative [Member]
Stock options and SARs	149,665	361,421	73,500	233,401
Average Exercise Price	$ 58.41	$ 48.05	$ 64.43	$ 53.12

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Acquisitions

9 Months Ended

Sep. 30, 2011

Acquisitions

Acquisitions

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 closing 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. This acquisition targeted 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 consisting of approximately 32,000 net acres of undeveloped oil and gas leasehold located in Southwest Oklahoma and North Texas for approximately $17.6 million.

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

On August 31, 2011, we acquired certain producing oil and gas properties for $30.5 million in cash, subject to closing adjustments, from an unaffiliated seller. Included in the acquisition were more than 500 wells located principally in the Oklahoma Arkoma Woodford and Hartshorne Coal plays along with other properties located throughout Oklahoma and Texas. The proved reserves associated with the acquisition are approximately 31.2 Bcfe (99% natural gas), 83% of which is proved developed. The acquisition also included approximately 55,000 net acres of which 96% is held by production.

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Derivatives (Non-Qualifying Cash Flow Derivatives Outstanding) (Details) (Basis Swap [Member], Natural Gas [Member], Oct'11 - Dec'11 [Member], USD $)	9 Months Ended
	Sep. 30, 2011
CEGT - NYMEX [Member]
Hedged Volume (MMBtu/day)	10,000
Basis Differential	$ (0.21)
CEGT - NYMEX [Member] | Start [Member]
Commodity Derivatives Term	Oct'11
CEGT - NYMEX [Member] | End [Member]
Commodity Derivatives Term	Dec'11
PEPL - NYMEX [Member]
Hedged Volume (MMBtu/day)	10,000
Basis Differential	(0.23)
PEPL - NYMEX [Member] | Start [Member]
Commodity Derivatives Term	Oct'11
PEPL - NYMEX [Member] | End [Member]
Commodity Derivatives Term	Dec'11
Tenn Zone - NYMEX [Member]
Hedged Volume (MMBtu/day)	15,000
Basis Differential	$ (0.14)
Tenn Zone - NYMEX [Member] | Start [Member]
Commodity Derivatives Term	Oct'11
Tenn Zone - NYMEX [Member] | End [Member]
Commodity Derivatives Term	Dec'11

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Oil And Natural Gas Properties (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2011
Effects of cash flow hedges	$ 13.7
Jan'12 - Dec'12 [Member]
Oil and gas production volume covered by hedges that affect ceiling determination (in MMBoe)	4.7
Jan'13 - Dec'13 [Member]
Oil and gas production volume covered by hedges that affect ceiling determination (in MMBoe)	0.7
Oct'11 - Dec'11 [Member]
Oil and gas production volume covered by hedges that affect ceiling determination (in MMBoe)	1.8

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Long-Term Debt And Other Long-Term Liabilities (Narrative) (Details) (USD $)	0 Months Ended	9 Months Ended
	Sep. 13, 2011	Sep. 30, 2011	Sep. 30, 2010	Dec. 31, 2010
Credit facility maximum credit amount		$ 750,000,000
Credit facility maturity date		May 24, 2012
Commitment fee under credit facility standard	1.00%
Origination, agency and syndication fees		1,600,000
LIBOR interest rate plus one percent		LIBOR plus 1.00%
Outstanding borrowings		55,400,000		163,000,000
Outstanding borrowings subject to LIBOR		50,000,000
Payments of dividends exceeding percentage		30.00%
Current ratio of credit facility		1 to 1
Leverage ratio of long-term debt		4 to 1
6.625% senior subordinated notes due 2021		250,000,000		0
Interest percentage of senior subordinated notes		6.625%
Aggregate principal amount of debt		305,400,000		163,000,000
Debt instrument maturity date		2021
Proceeds from issuance of senior subordinated notes		243,950,000	0
Deducting fees for debt issuance		6,000,000
Repayment of outstanding borrowings under unsecured credit facility		220,300,000
Significant restrictions on received funds from subsidiaries		0
Percentage of maximum, aggregate principal equity amount		35.00%
Proceed from equity offerings redemption price percentage		106.625%
Minimum redemption percentage of debt outstanding		65.00%
Equal redemption price percentage of principal amount of debt		100.00%
Senior notes repurchase price in percentage		101.00%
2011		10,000,000
2012		16,900,000
2013		3,700,000
2014		3,000,000
2015		57,800,000
Line of credit facility lender determined amount [Member]
Credit facility current credit amount		600,000,000
Line of credit facility commitment amount [Member]
Credit facility current credit amount		$ 250,000,000
Senior Unsecured Credit Facility [Member]
Credit facility maturity date		September 13, 2016
Minimum [Member]
Commitment fee percentage under credit facility	0.375%
LIBOR plus interest rate		1.75%
Maximum [Member]
Commitment fee percentage under credit facility	0.50%
LIBOR plus interest rate		2.50%

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Derivatives (Cash Flow Hedges Outstanding) (Details)	9 Months Ended
	Sep. 30, 2011 bbl
Swap [Member] | WTI - NYMEX [Member] | Crude Oil [Member] | Oct'11 - Dec'11 [Member]
Hedged Volume (in Bbl/day)	4,000
Weighted Average Fixed Price for Swaps	84.28
Swap [Member] | WTI - NYMEX [Member] | Crude Oil [Member] | Oct'11 - Dec'11 [Member] | Start [Member]
Commodity Derivatives Term	Oct'11
Swap [Member] | WTI - NYMEX [Member] | Crude Oil [Member] | Oct'11 - Dec'11 [Member] | End [Member]
Commodity Derivatives Term	Dec'11
Swap [Member] | WTI - NYMEX [Member] | Crude Oil [Member] | Jan'12 - Dec'12 [Member]
Hedged Volume (in Bbl/day)	4,500
Weighted Average Fixed Price for Swaps	95.91
Swap [Member] | WTI - NYMEX [Member] | Crude Oil [Member] | Jan'12 - Dec'12 [Member] | Start [Member]
Commodity Derivatives Term	Jan'12
Swap [Member] | WTI - NYMEX [Member] | Crude Oil [Member] | Jan'12 - Dec'12 [Member] | End [Member]
Commodity Derivatives Term	Dec'12
Swap [Member] | WTI - NYMEX [Member] | Crude Oil [Member] | Jan'13 - Dec'13 [Member]
Hedged Volume (in Bbl/day)	2,000
Weighted Average Fixed Price for Swaps	102.05
Swap [Member] | WTI - NYMEX [Member] | Crude Oil [Member] | Jan'13 - Dec'13 [Member] | Start [Member]
Commodity Derivatives Term	Jan'13
Swap [Member] | WTI - NYMEX [Member] | Crude Oil [Member] | Jan'13 - Dec'13 [Member] | End [Member]
Commodity Derivatives Term	Dec'13
Swap [Member] | CEGT - NYMEX [Member] | Natural Gas [Member] | Oct'11 - Dec'11 [Member]
Hedged Volume (MMBtu/day)	10,000
Weighted Average Fixed Price for Swaps	4.43
Swap [Member] | CEGT - NYMEX [Member] | Natural Gas [Member] | Oct'11 - Dec'11 [Member] | Start [Member]
Commodity Derivatives Term	Oct'11
Swap [Member] | CEGT - NYMEX [Member] | Natural Gas [Member] | Oct'11 - Dec'11 [Member] | End [Member]
Commodity Derivatives Term	Dec'11
Swap [Member] | IF - NYMEX (HH) [Member] | Natural Gas [Member] | Oct'11 - Dec'11 [Member]
Hedged Volume (MMBtu/day)	70,000
Weighted Average Fixed Price for Swaps	4.87
Swap [Member] | IF - NYMEX (HH) [Member] | Natural Gas [Member] | Oct'11 - Dec'11 [Member] | Start [Member]
Commodity Derivatives Term	Oct'11
Swap [Member] | IF - NYMEX (HH) [Member] | Natural Gas [Member] | Oct'11 - Dec'11 [Member] | End [Member]
Commodity Derivatives Term	Dec'11
Swap [Member] | IF - NYMEX (HH) [Member] | Natural Gas [Member] | Jan'12 - Dec'12 [Member]
Hedged Volume (MMBtu/day)	30,000
Weighted Average Fixed Price for Swaps	5.05
Swap [Member] | IF - NYMEX (HH) [Member] | Natural Gas [Member] | Jan'12 - Dec'12 [Member] | Start [Member]
Commodity Derivatives Term	Jan'12
Swap [Member] | IF - NYMEX (HH) [Member] | Natural Gas [Member] | Jan'12 - Dec'12 [Member] | End [Member]
Commodity Derivatives Term	Dec'12
Swap [Member] | IF - PEPL [Member] | Natural Gas [Member] | Jan'12 - Dec'12 [Member]
Hedged Volume (MMBtu/day)	15,000
Weighted Average Fixed Price for Swaps	5.62
Swap [Member] | IF - PEPL [Member] | Natural Gas [Member] | Jan'12 - Dec'12 [Member] | Start [Member]
Commodity Derivatives Term	Jan'12
Swap [Member] | IF - PEPL [Member] | Natural Gas [Member] | Jan'12 - Dec'12 [Member] | End [Member]
Commodity Derivatives Term	Dec'12
Swap [Member] | OPIS - Conway [Member] | Liquids [Member] | Oct'11 - Dec'11 [Member]
Hedged Volume (Gal/mo)	2,024,418	[1]
Weighted Average Fixed Price for Swaps	1.07	[1]
Swap [Member] | OPIS - Conway [Member] | Liquids [Member] | Oct'11 - Dec'11 [Member] | Start [Member]
Commodity Derivatives Term	Oct'11
Swap [Member] | OPIS - Conway [Member] | Liquids [Member] | Oct'11 - Dec'11 [Member] | End [Member]
Commodity Derivatives Term	Dec'11
Swap [Member] | OPIS - Conway [Member] | Liquids [Member] | Jan'12 - Mar'12 [Member]
Hedged Volume (Gal/mo)	1,350,014	[1]
Weighted Average Fixed Price for Swaps	1.10	[1]
Swap [Member] | OPIS - Conway [Member] | Liquids [Member] | Jan'12 - Mar'12 [Member] | Start [Member]
Commodity Derivatives Term	Jan'12
Swap [Member] | OPIS - Conway [Member] | Liquids [Member] | Jan'12 - Mar'12 [Member] | End [Member]
Commodity Derivatives Term	Mar'12
Swap [Member] | OPIS - Conway [Member] | Liquids [Member] | Apr'12 - Dec'12 [Member]
Hedged Volume (Gal/mo)	180,006	[2]
Weighted Average Fixed Price for Swaps	2.11	[2]
Swap [Member] | OPIS - Conway [Member] | Liquids [Member] | Apr'12 - Dec'12 [Member] | Start [Member]
Commodity Derivatives Term	Apr'12
Swap [Member] | OPIS - Conway [Member] | Liquids [Member] | Apr'12 - Dec'12 [Member] | End [Member]
Commodity Derivatives Term	Dec'12
Swap [Member] | OPIS - Mont Belvieu [Member] | Liquids [Member] | Oct'11 - Dec'11 [Member]
Hedged Volume (Gal/mo)	1,240,068	[1]
Weighted Average Fixed Price for Swaps	1.00	[1]
Swap [Member] | OPIS - Mont Belvieu [Member] | Liquids [Member] | Oct'11 - Dec'11 [Member] | Start [Member]
Commodity Derivatives Term	Oct'11
Swap [Member] | OPIS - Mont Belvieu [Member] | Liquids [Member] | Oct'11 - Dec'11 [Member] | End [Member]
Commodity Derivatives Term	Dec'11
Swap [Member] | OPIS - Mont Belvieu [Member] | Liquids [Member] | Jan'12 - Mar'12 [Member]
Hedged Volume (Gal/mo)	1,155,018	[1]
Weighted Average Fixed Price for Swaps	0.91	[1]
Swap [Member] | OPIS - Mont Belvieu [Member] | Liquids [Member] | Jan'12 - Mar'12 [Member] | Start [Member]
Commodity Derivatives Term	Jan'12
Swap [Member] | OPIS - Mont Belvieu [Member] | Liquids [Member] | Jan'12 - Mar'12 [Member] | End [Member]
Commodity Derivatives Term	Mar'12
Swap [Member] | OPIS - Mont Belvieu [Member] | Liquids [Member] | Apr'12 - Jun'12 [Member]
Hedged Volume (Gal/mo)	690,028	[3]
Weighted Average Fixed Price for Swaps	0.79	[3]
Swap [Member] | OPIS - Mont Belvieu [Member] | Liquids [Member] | Apr'12 - Jun'12 [Member] | Start [Member]
Commodity Derivatives Term	Apr'12
Swap [Member] | OPIS - Mont Belvieu [Member] | Liquids [Member] | Apr'12 - Jun'12 [Member] | End [Member]
Commodity Derivatives Term	Jun'12
Basis Swap [Member] | CEGT - NYMEX [Member] | Natural Gas [Member] | Oct'11 - Dec'11 [Member] | Start [Member]
Commodity Derivatives Term	Oct'11
Basis Swap [Member] | CEGT - NYMEX [Member] | Natural Gas [Member] | Oct'11 - Dec'11 [Member] | End [Member]
Commodity Derivatives Term	Dec'11
Basis Swap [Member] | Tenn Zone - NYMEX [Member] | Natural Gas [Member] | Oct'11 - Dec'11 [Member]
Hedged Volume (MMBtu/day)	15,000
Weighted Average Fixed Price for Swaps	(0.14)
Basis Swap [Member] | Tenn Zone - NYMEX [Member] | Natural Gas [Member] | Oct'11 - Dec'11 [Member] | Start [Member]
Commodity Derivatives Term	Oct'11
Basis Swap [Member] | Tenn Zone - NYMEX [Member] | Natural Gas [Member] | Oct'11 - Dec'11 [Member] | End [Member]
Commodity Derivatives Term	Dec'11

[1] Types of liquids involved are natural gasoline, ethane, propane, isobutane and normal butane.

[2] Types of liquids involved are natural gasoline.

[3] Types of liquids involved are natural gasoline and ethane.

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Earnings Per Share (Earnings (Loss) Per Share) (Details) (USD $) In Thousands, except Per Share data	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Earnings Per Share
Income/(loss) of basic earnings per common share	$ 53,360	$ 34,491	$ 144,206	$ 102,819
Income/(loss) of effect of dilutive stock options, restricted stock and stock appreciation rights (SARs)	0	0	0	0
Income/(loss) of diluted earnings per common share	$ 53,360	$ 34,491	$ 144,206	$ 102,819
Weighted shares of basic earnings per common share	47,687	47,358	47,642	47,217
Weighted shares of effect of dilutive stock options, restricted stock and stock appreciation rights (SARs)	281	137	290	167
Weighted shares of diluted earnings per common share	47,968	47,495	47,932	47,384
Per-share amount of basic earnings per common share	$ 1.12	$ 0.73	$ 3.03	$ 2.18
Per-share amount of effect of dilutive stock options, restricted stock and stock appreciation rights (SARs)	$ (0.01)	$ 0.00	$ (0.02)	$ (0.01)
Per-share amount of diluted earnings per common share	$ 1.11	$ 0.73	$ 3.01	$ 2.17

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Fair Value Measurements

9 Months Ended

Sep. 30, 2011

Fair Value Measurements

Fair Value Measurements

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.

The following tables set forth our recurring fair value measurements:

	September 30, 2011
	Level 2		Level 3		Total
	(In thousands)
Financial assets:
Commodity derivatives	$	39,565	$	25,129	$	64,694

	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, NGLs 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.

The following tables reconcile our level 3 fair value measurements:

	Net Derivatives
	For the Three Months Ended September 30, 2011					For the Nine Months Ended September 30, 2011
	Interest Rate Swaps		Commodity Swaps			Interest Rate Swaps			Commodity Swaps
	(In thousands)
Beginning of period	$	0	$	11,749		$	(1,614	)	$	10,868
Total gains or (losses) (realized and unrealized):
Included in earnings (1)		0		4,046			(1,734	)		11,923
Included in other comprehensive income		0		13,182			1,614			13,264
Settlements		0		(3,848	)		1,734			(10,926	)
End of period	$	0	$	25,129		$	0		$	25,129
Total gains for the period included in earnings attributable to the change in unrealized gains relating to assets still held at end of period	$	0	$	198		$	0		$	997

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

	Net Derivatives
	For the Three Months Ended September 30, 2010						For the Nine Months Ended September 30, 2010
	Interest Rate Swaps			Commodity Swaps and Collars			Interest Rate Swaps			Commodity Swaps and Collars
	(In thousands)
Beginning of period	$	(1,971	)	$	33,313		$	(1,948	)	$	19,948
Total gains or (losses) (realized and unrealized):
Included in earnings (1)		(298	)		16,558			(907	)		44,322
Included in other comprehensive income (loss)		39			(1,266	)		16			10,646
Purchases, issuance and settlements		298			(16,809	)		907			(43,120	)
End of period	$	(1,932	)	$	31,796		$	(1,932	)	$	31,796
Total gains (losses) for the period included in earnings attributable to the change in unrealized gains relating to assets still held at end of period	$	0		$	(251	)	$	0		$	1,202

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

Based on our valuation at September 30, 2011, we determined that the non-performance risk with regard to our counterparties was immaterial.

Fair Value of Other Financial Instruments

The following disclosure of the estimated fair value of financial instruments is made in accordance with accounting guidance for financial instruments. We have determined the estimated fair values by using available market information and valuation methodologies. Considerable judgment is required in interpreting market data to develop the estimates of fair value. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.

At September 30, 2011, the carrying values on the unaudited condensed 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.

Based on the borrowing rates currently available to us for credit agreement debt with similar terms and maturities and consideration of our non-performance risk, long-term debt associated with our credit agreement at September 30, 2011 approximates its fair value.

The carrying amount of long-term debt associated with the Notes reported in the consolidated balance sheet as of September 30, 2011 was $250.0 million. We estimate the fair value of these Notes using quoted marked prices at September 30, 2011 was $249.4 million.

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Earnings Per Share

9 Months Ended

Sep. 30, 2011

Earnings Per Share

Earnings Per Share

NOTE 4 – EARNINGS PER SHARE

Information related to the calculation of earnings per share follows:

	Income (Numerator)		Weighted Shares (Denominator)		Per-Share Amount
	(In thousands except per share amounts)
For the three months ended September 30, 2011:
Basic earnings per common share	$	53,360		47,687	$	1.12
Effect of dilutive stock options, restricted stock and stock appreciation rights (SARs)		0		281		(0.01	)
Diluted earnings per common share	$	53,360		47,968	$	1.11
For the three months ended September 30, 2010:
Basic earnings per common share	$	34,491		47,358	$	0.73
Effect of dilutive stock options, restricted stock and SARs		0		137		0.00
Diluted earnings per common share	$	34,491		47,495	$	0.73

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 September 30,
	2011		2010
Stock options and SARs		149,665		361,421
Average Exercise Price	$	58.41	$	48.05

	Income (Numerator)		Weighted Shares (Denominator)		Per-Share Amount
	(In thousands except per share amounts)
For the nine months ended September 30, 2011:
Basic earnings per common share	$	144,206		47,642	$	3.03
Effect of dilutive stock options, restricted stock and SARs		0		290		(0.02	)
Diluted earnings per common share	$	144,206		47,932	$	3.01
For the nine months ended September 30, 2010:
Basic earnings per common share	$	102,819		47,217	$	2.18
Effect of dilutive stock options, restricted stock and SARs		0		167		(0.01	)
Diluted earnings per common share	$	102,819		47,384	$	2.17

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:

	Nine Months Ended September 30,
	2011		2010
Stock options and SARs		73,500		233,401
Average Exercise Price	$	64.43	$	53.12

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Accrued Liabilities (Tables)

9 Months Ended

Sep. 30, 2011

Accrued Liabilities

Accrued Liabilities

	September 30, 2011		December 31, 2010
	(In thousands)
Employee costs	$	16,487	$	16,499
Lease operating expense		6,875		6,214
Taxes		24,804		1,310
Interest payable		7,010		667
Hedge settlements		524		1,634
Other		4,888		3,769
Total accrued liabilities	$	60,588	$	30,093

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Stock-Based Compensation (Fair Value Of The Restricted Stock Awards Granted During The Periods) (Details) (USD $) In Millions, except Share data, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Shares granted	0	0	0	0
Restricted Stock [Member]
Shares granted	12,402	192,272	209,150	440,655
Estimated fair value	$ 0.6	$ 6.0	$ 10.9	$ 16.6
Percentage of shares granted expected to be distributed	95.00%	89.00%	93.00%	91.00%

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Acquisitions (Details) (USD $) In Millions, unless otherwise specified	1 Months Ended		1 Months Ended	0 Months Ended		1 Months Ended
	Jun. 30, 2010	Jun. 02, 2010 Boe A	Jun. 30, 2010 Southwest Oklahoma And North Texas [Member]	Jul. 20, 2011 Oklahoma And Lipscomb [Member]	Jul. 20, 2011 Oklahoma And Lipscomb [Member] Natural Gas Reserves [Member]	Aug. 31, 2011 Oklahoma Arkoma Woodford And Hartshorne Coal [Member] A	Aug. 31, 2011 Oklahoma Arkoma Woodford And Hartshorne Coal [Member] Natural Gas [Member]	Jun. 02, 2010 Oil Reserves [Member] bbl	Jun. 02, 2010 Natural Gas Liquids Reserves [Member]	Jun. 02, 2010 Natural Gas Reserves [Member] MMcf
Payments to acquire oil and gas property	$ 73.7		$ 17.6	$ 12.3		$ 30.5
Purchase price allocation for proved properties	48.7			8.4
Undeveloped leasehold	$ 25.0			$ 3.9
Gas and oil acreage, developed and undeveloped, net		45,000				55,000
Operating number of wells		10		30
Operating and non-operating number of wells						500
Non-operating number of wells				59
Proved developed reserves (BOE)		762,000
Proved developed reserves (volume)								511,000		573
Proved developed reserves (volume) per day, MMcfe					1.7
Proved developed reserves of NGL, barrels									155,000
Preliminary proved reserves, cubic feet					6,600,000,000		31,200,000,000
Percentage of proved developed reserves							83.00%
Net undeveloped acres			32,000	12,000
Percentage of acre held for production						96.00%

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Condensed Consolidated Statements Of Cash Flows (USD $) In Thousands	9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010
OPERATING ACTIVITIES:
Net income	$ 144,206	$ 102,819
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	201,924	142,930
Unrealized gain on derivatives	(3,611)	(1,202)
Deferred tax expense	94,224	66,177
(Gain) loss on disposition of assets	462	(9,579)
Stock compensation plans	10,780	6,603
Other	2,740	2,113
Changes in operating assets and liabilities increasing (decreasing) cash:
Accounts receivable	(26,118)	(35,863)
Accounts payable	(30,439)	(7,924)
Material and supplies inventory	(1,780)	346
Accrued liabilities	13,487	5,121
Contract advances	(1,190)	720
Other - net	13,166	11,635
Net cash provided by operating activities	417,851	283,896
INVESTING ACTIVITIES:
Capital expenditures	(541,044)	(335,821)
Producing property and other acquisitions	(50,525)	(92,642)
Proceeds from disposition of assets	7,779	34,335
Other - net	0	324
Net cash used in investing activities	(583,790)	(393,804)
FINANCING ACTIVITIES:
Borrowings under line of credit	334,100	205,000
Payments under line of credit	(441,700)	(100,000)
Proceeds from issuance of senior subordinated notes, net of offering costs	243,950	0
Proceeds from exercise of stock options	644	122
Book overdrafts	28,746	4,779
Net cash provided by financing activities	165,740	109,901
Net decrease in cash and cash equivalents	(199)	(7)
Cash and cash equivalents, beginning of period	1,359	1,140
Cash and cash equivalents, end of period	$ 1,160	$ 1,133

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Long-Term Debt And Other Long-Term Liabilities (Tables)

9 Months Ended

Sep. 30, 2011

Long-Term Debt And Other Long-Term Liabilities

Long-Term Debt

	September 30, 2011		December 31, 2010
	(In thousands)
Credit agreement with average interest rates, of 2.2% and 3.5% at September 30, 2011 and December 31, 2010, respectively	$	55,400	$	163,000
6.625% senior subordinated notes due 2021		250,000		0
Total long-term debt	$	305,400	$	163,000

Other Long-Term Liabilities

	September 30, 2011		December 31, 2010
	(In thousands)
Asset retirement obligations	$	92,802	$	69,265
Workers' compensation		17,921		17,566
Separation benefit plans		6,480		5,690
Gas balancing		3,263		3,263
Deferred compensation plan		2,266		2,368
		122,732		98,152
Less current portion		10,031		10,122
Total other long-term liabilities	$	112,701	$	88,030

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Derivatives (Amount Of Gain Or (Loss) Recognized In Accumulated OCI On Derivative) (Details) (USD $) In Thousands	9 Months Ended
	Sep. 30, 2011		Sep. 30, 2010
Amount of Gain or (Loss) Recognized in Accumulated OCI on Derivative	$ 37,323	[1]	$ 12,266	[1]
Interest Rate Swaps [Member]
Amount of Gain or (Loss) Recognized in Accumulated OCI on Derivative	0	[1]	(1,193)	[1]
Commodity Derivatives [Member]
Amount of Gain or (Loss) Recognized in Accumulated OCI on Derivative	$ 37,323	[1]	$ 13,459	[1]

[1] Net of taxes.

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Stock-Based Compensation (Tables)

9 Months Ended

Sep. 30, 2011

Stock-Based Compensation

Estimated Fair Value Of The Stock Options Granted

	Nine Months Ended September 30,
	2011			2010
Options granted (1)		31,500			52,504
Estimated fair value (in millions)	$	0.7		$	0.8
Estimate of stock volatility		0.48			0.45
Estimated dividend yield		0	%		0	%
Risk free interest rate		2	%		2	%
Expected annual life based on prior experience		5			5
Forfeiture rate		0	%		0	%

(1)  On May 29, 2009, eight of our directors were each issued 3,063 options contingent on shareholder approval, which was received at the May 5, 2010 annual shareholders' meeting. These 24,504 options granted and vested simultaneously with that approval.

Fair Value Of The Restricted Stock Awards Granted During The Periods

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
Shares granted		12,402			192,272			209,150			440,655
Estimated fair value (in millions)	$	0.6		$	6.0		$	10.9		$	16.6
Percentage of shares granted expected to be distributed		95	%		89	%		93	%		91	%

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Condensed Consolidated Statements Of Comprehensive Income (Parenthetical) (USD $) In Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Condensed Consolidated Statements Of Comprehensive Income
Change in value of derivative instruments used as cash flow hedges, tax	$ 27,015	$ 2,753	$ 28,201	$ 18,780
Reclassification - derivative settlements, tax	(771)	(5,646)	1,008	(13,708)
Ineffective portion of derivatives, tax	$ (899)	$ (67)	$ (1,601)	$ (231)

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Stock-Based Compensation

9 Months Ended

Sep. 30, 2011

Stock-Based Compensation

Stock-Based Compensation

NOTE 9 – STOCK-BASED COMPENSATION

For the three and nine months ended September 30, 2011, we recognized stock compensation expense for restricted stock awards, stock options and stock settled SARs of $2.7 million and $7.7 million, respectively. We also capitalized for the same periods stock compensation cost for oil and natural gas properties of $0.6 million and $1.9 million, respectively. For these same periods, the tax benefit related to this stock based compensation was $1.1 million and $3.0 million, respectively. For the three and nine months ended September 30, 2010, we recognized stock compensation expense for restricted stock awards, stock options and stock settled SARs of $2.8 million and $8.3 million, respectively, and capitalized stock compensation cost for oil and natural gas properties of $0.7 million and $2.0 million, respectively. For these same periods, the tax benefit related to this stock based compensation was $1.1 million and $3.2 million, respectively. The remaining unrecognized compensation cost related to unvested awards at September 30, 2011 is approximately $11.2 million of which $2.2 million is anticipated to be capitalized. The weighted average period of time over which this cost will be recognized is 0.8 years.

We did not grant any SARs or stock options (other than the non-employee director options discussed below) during either of the three or nine month periods ending September 30, 2011 and 2010.

The table below shows the estimates of the fair value of the stock options granted to our non-employee directors under the Unit Corporation 2000 Non-employee Directors Stock Option Plan during the periods using the Black-Scholes model and applying the estimated values also presented in the table:

	Nine Months Ended September 30,
	2011			2010
Options granted (1)		31,500			52,504
Estimated fair value (in millions)	$	0.7		$	0.8
Estimate of stock volatility		0.48			0.45
Estimated dividend yield		0	%		0	%
Risk free interest rate		2	%		2	%
Expected annual life based on prior experience		5			5
Forfeiture rate		0	%		0	%

(1)  On May 29, 2009, eight of our directors were each issued 3,063 options contingent on shareholder approval, which was received at the May 5, 2010 annual shareholders' meeting. These 24,504 options granted and vested simultaneously with that approval.

Expected volatilities are based on the historical volatility of our stock. Within the model, we use historical data to estimate stock option exercise and termination rates and aggregate groups that have similar historical exercise behavior for valuation purposes. To date, we have not paid dividends on our stock. The risk free interest rate is computed from the LIBOR rate using the term over which it is anticipated the grant will be exercised. The stock options granted in the second quarter of 2011 increased stock compensation expense for the third quarter and first nine months of 2011 by $0.4 million and $0.6 million, respectively.

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
Shares granted		12,402			192,272			209,150			440,655
Estimated fair value (in millions)	$	0.6		$	6.0		$	10.9		$	16.6
Percentage of shares granted expected to be distributed		95	%		89	%		93	%		91	%

The restricted stock awards granted during the first three and nine months of 2011 will be recognized over a two- and three-year vesting period, except for a portion of those granted to certain executive officers in the first quarter of 2011. Thirty percent of the shares granted to the designated executive officers, or 20,062 shares (the performance shares), will cliff vest in the first half of 2014. The actual number of performance shares that vest in 2014 will be based on the company's achievement of certain performance criteria over a three-year period, and will range from 50% to 150% of the 20,062 restricted shares granted as performance shares. Total 2011 awards increased the stock compensation expense and the capitalized cost related to oil and natural gas properties for the first nine months of 2011 by an aggregate of $3.5 million.

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Long-Term Debt And Other Long-Term Liabilities (Long-Term Debt) (Details) (USD $) In Thousands, unless otherwise specified	9 Months Ended
	Sep. 30, 2011	Dec. 31, 2010
Long-Term Debt And Other Long-Term Liabilities
Credit agreement with average interest rates, of 2.2% and 3.5% at September 30, 2011 and December 31, 2010, respectively	$ 55,400	$ 163,000
6.625% senior subordinated notes due 2021	250,000	0
Total long-term debt	$ 305,400	$ 163,000
Revolving credit facility interest rate including the effect of hedging	2.20%	3.50%
Interest percentage of senior subordinated notes	6.625%
Debt instrument maturity date	2021

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Earnings Per Share (Tables)

3 Months Ended

9 Months Ended

Sep. 30, 2011

Sep. 30, 2011

Earnings Per Share

Earnings (Loss) Per Share

	Income (Numerator)		Weighted Shares (Denominator)		Per-Share Amount
	(In thousands except per share amounts)
For the three months ended September 30, 2011:
Basic earnings per common share	$	53,360		47,687	$	1.12
Effect of dilutive stock options, restricted stock and stock appreciation rights (SARs)		0		281		(0.01	)
Diluted earnings per common share	$	53,360		47,968	$	1.11
For the three months ended September 30, 2010:
Basic earnings per common share	$	34,491		47,358	$	0.73
Effect of dilutive stock options, restricted stock and SARs		0		137		0.00
Diluted earnings per common share	$	34,491		47,495	$	0.73

	Income (Numerator)		Weighted Shares (Denominator)		Per-Share Amount
	(In thousands except per share amounts)
For the nine months ended September 30, 2011:
Basic earnings per common share	$	144,206		47,642	$	3.03
Effect of dilutive stock options, restricted stock and SARs		0		290		(0.02	)
Diluted earnings per common share	$	144,206		47,932	$	3.01
For the nine months ended September 30, 2010:
Basic earnings per common share	$	102,819		47,217	$	2.18
Effect of dilutive stock options, restricted stock and SARs		0		167		(0.01	)
Diluted earnings per common share	$	102,819		47,384	$	2.17

Schedule Of Antidilutive Securities Excluded From Computation Of Earnings Per Share

	Three Months Ended September 30,
	2011		2010
Stock options and SARs		149,665		361,421
Average Exercise Price	$	58.41	$	48.05

	Nine Months Ended September 30,
	2011		2010
Stock options and SARs		73,500		233,401
Average Exercise Price	$	64.43	$	53.12

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Condensed Consolidated Balance Sheets (USD $) In Thousands	Sep. 30, 2011	Dec. 31, 2010
Current assets:
Cash and cash equivalents	$ 1,160	$ 1,359
Accounts receivable, net of allowance for doubtful accounts of $5,083 at both September 30, 2011 and at December 31, 2010	153,827	130,142
Materials and supplies	8,096	6,316
Current derivative assets (Note 10)	41,257	5,568
Current income tax receivable	11,868	25,211
Current deferred tax asset	10,013	13,537
Prepaid expenses and other	9,749	6,047
Total current assets	235,970	188,180
Property and equipment:
Drilling equipment	1,386,388	1,273,861
Oil and natural gas properties on the full cost method:
Proved properties	3,166,022	2,738,093
Undeveloped leasehold not being amortized	184,540	175,065
Gas gathering and processing equipment	258,854	199,564
Transportation equipment	33,749	31,688
Other	35,607	28,511
Property, plant and equipment, gross, total	5,065,160	4,446,782
Less accumulated depreciation, depletion, amortization and impairment	2,242,812	2,047,031
Net property and equipment	2,822,348	2,399,751
Deferred financing costs, net	5,815	0
Goodwill	62,808	62,808
Other intangible assets, net	2,168	3,022
Non-current derivative assets (Note 10)	23,989	2,537
Other assets	12,153	12,942
Total assets	3,165,251	2,669,240
Current liabilities:
Accounts payable	105,493	89,885
Accrued liabilities (Note 5)	60,588	30,093
Contract advances	1,392	2,582
Current derivative liabilities (Note 10)	552	14,446
Current portion of other long-term liabilities (Note 6)	10,031	10,122
Total current liabilities	178,056	147,128
Long-term debt (Note 6)	305,400	163,000
Non-current derivative liabilities (Note 10)	0	4,359
Other long-term liabilities (Note 6)	112,701	88,030
Deferred income taxes	658,659	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, 48,150,732 and 47,910,431 shares issued, respectively	9,540	9,493
Capital in excess of par value	404,892	393,501
Accumulated other comprehensive gain (loss)	37,323	(6,851)
Retained earnings	1,458,680	1,314,474
Total shareholders' equity	1,910,435	1,710,617
Total liabilities and shareholders' equity	$ 3,165,251	$ 2,669,240

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Asset Retirement Obligations (Asset Retirement Obligations) (Details) (USD $) In Thousands	9 Months Ended
	Sep. 30, 2011		Sep. 30, 2010
Asset Retirement Obligations
ARO liability, January 1:	$ 69,265		$ 56,404
Accretion of discount	2,598		2,138
Liability incurred	12,674	[1]	2,901	[1]
Liability settled	(831)		(622)
Revision of estimates	9,096	[2]	3,822	[2]
ARO liability, September 30:	92,802		64,643
Less current portion	2,074		1,617
Total long-term ARO liability	$ 90,728		$ 63,026

[1] Liability incurred in 2011 includes estimates for new wells acquired.

[2] Plugging liability estimates were revised upward in both 2011 and 2010 due to increases in the cost of services used to plug wells over the preceding years.

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Fair Value Measurements (Reconciliations Of Level 3 Fair Value Measurements) (Details) (USD $) In Thousands	3 Months Ended				9 Months Ended
	Sep. 30, 2011		Sep. 30, 2010		Sep. 30, 2011		Sep. 30, 2010
Commodity Swap [Member]
Beginning of period	$ 11,749				$ 10,868
Included in earnings (loss)	4,046	[1]			11,923	[1]
Included in other comprehensive income (loss)	13,182				13,264
Purchases, issuance and settlements	(3,848)				(10,926)
End of period	25,129				25,129
Total gains for the period included in earnings attributable to the change in unrealized gains relating to assets still held at end of period	198				997
Commodity Swaps And Collars [Member]
Beginning of period			33,313				19,948
Included in earnings (loss)			16,558	[2]			44,322	[2]
Included in other comprehensive income (loss)			(1,266)				10,646
Purchases, issuance and settlements			(16,809)				(43,120)
End of period			31,796				31,796
Total gains for the period included in earnings attributable to the change in unrealized gains relating to assets still held at end of period			(251)				1,202
Interest Rate Swaps [Member]
Beginning of period	0		(1,971)		(1,614)		(1,948)
Included in earnings (loss)	0	[1]	(298)	[2]	(1,734)	[1]	(907)	[2]
Included in other comprehensive income (loss)	0		39		1,614		16
Purchases, issuance and settlements	0		298		1,734		907
End of period	0		(1,932)		0		(1,932)
Total gains for the period included in earnings attributable to the change in unrealized gains relating to assets still held at end of period	$ 0		$ 0		$ 0		$ 0

[1] Interest rate swaps and commodity swaps are reported in the unaudited condensed consolidated statements of income in interest, net and revenues, respectively.

[2] Interest rate swaps and commodity swaps and collars are reported in the unaudited condensed consolidated statements of income in interest, net and revenues, respectively.

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Derivatives (Gain Or Loss Of Reclassified Accumulated Other Comprehensive Income And Recognized Income) (Details) (USD $) In Thousands	3 Months Ended				9 Months Ended
	Sep. 30, 2011		Sep. 30, 2010		Sep. 30, 2011		Sep. 30, 2010
Amount of Gain or (Loss) Reclassified from Accumulated OCI into Income	$ 2,003	[1]	$ 14,462	[1]	$ (2,616)	[1]	$ 35,540	[1]
Amount of Gain or (Loss) Recognized in Income	2,336	[2]	176	[2]	4,158	[2]	605	[2]
Interest Rate Swaps [Member] | Interest [Member]
Amount of Gain or (Loss) Reclassified from Accumulated OCI into Income	0	[1]	(298)	[1]	(1,734)	[1]	(907)	[1]
Amount of Gain or (Loss) Recognized in Income	0	[2]	0	[2]	0	[2]	0	[2]
Oil And Natural Gas Revenue [Member] | Commodity Derivatives [Member]
Amount of Gain or (Loss) Reclassified from Accumulated OCI into Income	2,003	[1]	14,760	[1]	(882)	[1]	36,447	[1]
Amount of Gain or (Loss) Recognized in Income	$ 2,336	[2]	$ 176	[2]	$ 4,158	[2]	$ 605	[2]

[1] Effective portion of gain (loss).

[2] Ineffective portion of gain (loss).

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Derivatives (Amount Of Loss Recognized In Income On Derivative) (Details) (USD $) In Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Amount of Loss Recognized in Income on Derivative	$ (61)	$ (427)	$ (1,008)	$ 597
Oil And Natural Gas Revenue [Member] | Commodity Derivatives [Member]
Amount of Loss Recognized in Income on Derivative	$ (61)	$ (427)	$ (1,008)	$ 597

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Stock-Based Compensation (Narrative) (Details) (USD $) In Millions, except Share data, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Stock compensation expense	$ 2.7	$ 2.8	$ 7.7	$ 8.3
Capitalized stock compensation cost	0.6	0.7	1.9	2.0
Tax benefit related to stock based compensation	1.1	1.1	3.0	3.2
Unrecognized compensation cost related to unvested awards	11.2		11.2
Unrecognized compensation cost, expect to be capitalized	2.2		2.2
Weighted average years over which this cost will be recognized			0.8
SARs, shares granted	0	0	0	0
Increase in stock compensation expense due to the stock options granted	0.4		0.6
Increase in stock compensation expense due to the restricted stock awards granted			$ 3.5
Minimum [Member] | First Half Of 2014 [Member]
Performance percentage criteria			50.00%
Maximum [Member] | First Half Of 2014 [Member]
Performance percentage criteria			150.00%
First Half Of 2014 [Member]
Restricted stock awards granted to designated executive officers			20,062
Restricted stock awards to be vested			30.00%