UNIT CORP - FORM 10-Q - November 4, 2010

Attached files

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EXCEL - IDEA: XBRL DOCUMENT - UNIT CORP	Financial_Report.xls
EX-15 - LETTER RE: UNAUDITED INTERIM FINANCIAL INFORMATION - UNIT CORP	dex15.htm
EX-31.2 - CERTIFICATION OF CFO UNDER RULE 13A-14(A) - UNIT CORP	dex312.htm
EX-31.1 - CERTIFICATION OF CEO UNDER RULE 13A-14(A) - UNIT CORP	dex311.htm
EX-32 - CERTIFICATION OF CEO AND CFO UNDER RULE 13A-14(A) AND SECTION 1350 - UNIT CORP	dex32.htm

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, 2010

[ ] 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 29, 2010, 47,893,360 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, 2010 and December 31, 2009		3

	Condensed Consolidated Statements of Operations Three and Nine Months Ended September 30, 2010 and 2009		5

	Condensed Consolidated Statements of Cash Flows Nine Months Ended September 30, 2010 and 2009		6

	Condensed Consolidated Statements of Comprehensive Income (Loss) Three and Nine Months Ended September 30, 2010 and 2009		7

	Notes to Condensed Consolidated Financial Statements		8

	Report of Independent Registered Public Accounting Firm		23

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		24

Item 3.	Quantitative and Qualitative Disclosure About Market Risk		45

Item 4.	Controls and Procedures		46

	PART II. Other Information

Item 1.	Legal Proceedings		47

Item 1A.	Risk Factors		47

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		48

Item 3.	Defaults Upon Senior Securities		48

Item 4.	Reserved and Removed		48

Item 5.	Other Information		48

Item 6.	Exhibits		49

Signatures			50

Forward-Looking Statements

This document contains “forward-looking statements” – meaning, statements related to future, not past, events. In this context, forward-looking statements often address our expected future business and financial performance, and often contain words such as “expect,” “anticipate,” “intend,” “plan,” “believe,” “seek,” or “will.” Forward-looking statements by their nature address matters that are, to different degrees, uncertain. For us, some of the particular uncertainties that could adversely or positively affect our future results include: our belief regarding our liquidity; our expectation on how we intend to fund our capital expenditures; changes in the demand for and the prices of oil and natural gas; the availability of services to complete wells; the uncertainty related to declines and fluctuations in production volumes; the liquidity of our customers; the behavior of financial markets, including fluctuations in interest, commodity, and equity prices; strategic actions, including acquisitions and dispositions; future integration of acquired businesses; future financial performance of industries which we serve, including, without limitation, the energy industries; impact on us and the economy of recently enacted legislation; our belief that the final outcome of our legal proceedings will not materially affect our financial results; and numerous other matters of a national, regional and global scale, including those of a political, economic, business, legislative and competitive nature. These uncertainties may cause our actual future results to be materially different than those expressed in our forward-looking statements. We do not undertake to update our forward-looking statements.

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

UNIT CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)


	September 30, 2010		December 31, 2009
	(In thousands except share amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	1,133	$	1,140
Restricted cash		20		20
Accounts receivable, net of allowance for doubtful accounts of $5,184 at September 30, 2010 and $5,186 at December 31, 2009		107,040		74,382
Materials and supplies		6,568		6,914
Derivative assets (Note 10)		19,400		9,945
Income tax receivable		5,944		15,236
Deferred tax asset		12,484		14,423
Prepaid expenses and other		5,571		6,035

Total current assets		158,160		128,095


Property and equipment:
Drilling equipment		1,255,107		1,217,361
Oil and natural gas properties using the full cost method:
Proved properties		2,591,644		2,309,193
Undeveloped leasehold not being amortized		194,774		140,129
Gas gathering and processing equipment		191,943		172,549
Transportation equipment		32,067		30,726
Other		24,831		22,747

		4,290,366		3,892,705

Less accumulated depreciation, depletion, amortization and impairment		1,992,520		1,879,112

Net property and equipment		2,297,846		2,013,593


Goodwill		62,808		62,808
Other intangible assets, net		3,303		5,633
Non-current derivative assets (Note 10)		5,694		0
Other assets		17,074		18,270

Total assets	$	2,544,885	$	2,228,399

The accompanying notes are an integral part of these

condensed consolidated financial statements.

UNIT CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED) - CONTINUED


	September 30, 2010		December 31, 2009
	(In thousands except share amounts)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	65,681	$	55,880
Accrued liabilities (Note 5)		42,387		34,571
Contract advances		3,844		3,124
Derivative liabilities (Note 10)		1,278		2,230
Other liabilities (Note 6)		9,490		9,342

Total current liabilities		122,680		105,147


Long-term debt (Note 6)		135,000		30,000

Long-term derivative liabilities (Note 10)		3,392		1,142

Other long-term liabilities (Note 6)		87,382		79,984

Deferred income taxes		513,563		446,316


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, 47,899,300 and 47,530,669 shares issued, respectively		9,490		9,405
Capital in excess of par value		390,303		383,957
Accumulated other comprehensive income		12,266		4,458
Retained earnings		1,270,809		1,167,990

Total shareholders’ equity		1,682,868		1,565,810

Total liabilities and shareholders’ equity	$	2,544,885	$	2,228,399

The accompanying notes are an integral part of these

condensed consolidated financial statements.

UNIT CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)


	Three Months Ended September 30,					Nine Months Ended September 30,
	2010			2009		2010			2009
	(In thousands except per share amounts)
Revenues:
Contract drilling	$	85,004		$	49,801	$	217,919		$	188,383
Oil and natural gas		96,562			88,894		286,751			267,399
Gas gathering and processing		37,429			26,228		114,908			71,604
Other income (loss), net		(879	)		2,507		9,691			5,180

Total revenues		218,116			167,430		629,269			532,566


Expenses:
Contract drilling:
Operating costs		45,406			29,456		132,847			109,565
Depreciation		18,469			10,923		48,700			33,803
Oil and natural gas:
Operating costs		27,092			20,781		75,943			62,846
Depreciation, depletion and amortization		30,091			25,645		81,746			89,800
Impairment of oil and natural gas properties (Note 2)		0			0		0			281,241
Gas gathering and processing:
Operating costs		30,743			20,012		92,407			59,888
Depreciation and amortization		3,823			3,995		11,746			12,166
General and administrative		6,637			5,506		19,372			17,088
Interest, net		0			1		0			539

Total operating expenses		162,261			116,319		462,761			666,936

Income (loss) before income taxes		55,855			51,111		166,508			(134,370	)


Income tax expense (benefit):
Current		(8,553	)		8,571		(2,488	)		9,818
Deferred		29,917			11,091		66,177			(60,175	)

Total income taxes		21,364			19,662		63,689			(50,357	)


Net income (loss)	$	34,491		$	31,449	$	102,819		$	(84,013	)


Net income (loss) per common share:
Basic	$	0.73		$	0.67	$	2.18		$	(1.79	)


Diluted	$	0.73		$	0.66	$	2.17		$	(1.79	)

The accompanying notes are an integral part of these

condensed consolidated financial statements.

UNIT CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)


	Nine Months Ended September 30,
	2010			2009
	(In thousands)
OPERATING ACTIVITIES:
Net income (loss)	$	102,819		$	(84,013	)
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		142,930			136,569
Impairment of oil and natural gas properties (Note 2)		0			281,241
Unrealized (gain) loss on derivatives		(1,202	)		2,935
Deferred tax expense (benefit)		66,177			(60,175	)
Gain on disposition of assets		(9,579	)		(4,469	)
Stock compensation plans		6,603			8,449
Other		2,113			1,723
Changes in operating assets and liabilities increasing (decreasing) cash:
Accounts receivable		(35,863	)		130,339
Accounts payable		(7,924	)		(2,137	)
Material and supplies inventory		346			206
Accrued liabilities		5,121			(13,226	)
Contract advances		720			(1,810	)
Other – net		11,635			26,938

Net cash provided by operating activities		283,896			422,570


INVESTING ACTIVITIES:
Capital expenditures		(335,821	)		(246,300	)
Acquisitions		(92,642	)		0
Proceeds from disposition of assets		34,335			41,663
Other - net		324			0

Net cash used in investing activities		(393,804	)		(204,637	)


FINANCING ACTIVITIES:
Borrowings under line of credit		205,000			95,600
Payments under line of credit		(100,000	)		(265,100	)
Proceeds from exercise of stock options		122			100
Book overdrafts		4,779			(47,971	)

Net cash provided by (used in) financing activities		109,901			(217,371	)


Net increase (decrease) in cash and cash equivalents		(7	)		562

Cash and cash equivalents, beginning of period		1,140			584

Cash and cash equivalents, end of period	$	1,133		$	1,146

The accompanying notes are an integral part of these

condensed consolidated financial statements.

UNIT CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(UNAUDITED)


	Three Months Ended September 30,						Nine Months Ended September 30,
	2010			2009			2010			2009
	(In thousands)
Net income (loss)	$	34,491		$	31,449		$	102,819		$	(84,013	)
Other comprehensive income (loss), net of taxes:
Change in value of derivative instruments used as cash flow hedges, net of tax of $2,753, ($2,562), $18,780 and $18,806		4,148			(4,178	)		30,014			29,774
Reclassification - derivative settlements, net of tax of ($5,646), ($10,441), ($13,708) and ($32,142)		(8,816	)		(17,033	)		(21,832	)		(52,928	)
Ineffective portion of derivatives, net of tax of ($67), $96, ($231) and $139		(109	)		157			(374	)		233

Comprehensive income (loss)	$	29,714		$	10,395		$	110,627		$	(106,934	)

The accompanying notes are an integral part of these

condensed consolidated financial statements.

UNIT CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

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 its subsidiaries and affiliates, except as otherwise clearly indicated or as the context otherwise requires.

The accompanying condensed consolidated financial statements are unaudited and do not include all the notes in our annual financial statements. This quarterly report should be read in conjunction with the audited consolidated financial statements and notes included in our Form 10-K, filed February 23, 2010, for the year ended December 31, 2009.

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

• Balance Sheets at September 30, 2010 and December 31, 2009;

• Statements of Operations for the three and nine months ended September 30, 2010 and 2009;

• Cash Flows for the nine months ended September 30, 2010 and 2009; and

• Statements of Comprehensive Income (Loss) for the three and nine months ended September 30, 2010 and 2009.

Our financial statements are prepared in conformity with generally accepted accounting principles in the United States (GAAP). GAAP requires us to make certain estimates and assumptions that may affect the amounts reported in our condensed consolidated financial statements and accompanying notes. Actual results may differ from those estimates. Results for the three and nine months ended September 30, 2010 and 2009 are not necessarily indicative of the results to be realized for the full year in the case of 2010, or that we realized for the full year of 2009.

With respect to the unaudited financial information for the three and nine month periods ended September 30, 2010 and 2009, 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 4, 2010, 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 of that information 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.

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, NGLs and natural gas adjusted for any cash flow hedges, plus the cost of properties not being amortized, plus the lower of cost or estimated fair value of unproved properties included in the costs being amortized, less related income taxes. In the event the unamortized cost of the amortized oil and natural gas properties exceeds the full cost ceiling, the excess amount is charged to expense in the period during which the excess occurs, even if prices are depressed for only a short period of time. Once incurred, a write-down of oil and natural gas properties is not reversible.

Starting December 31, 2009, companies using full cost accounting moved from using the commodity prices existing on the last day of the period to that of the unweighted arithmetic average of the commodity prices existing on the first day of each of the 12 months before the end of the reporting period to calculate discounted future revenues, unless prices were otherwise determined under contractual arrangements.

We recorded a non-cash ceiling test write-down of $281.2 million pre-tax ($175.1 million, net of tax) during the quarter ending March 31, 2009. This write-down resulted from the reduction in commodity prices existing at the end of the first quarter of 2009 as compared to at the end of 2008. Derivative instruments qualifying as cash flow hedges were included in determining the limitation on the capitalized costs in our March 31, 2009 ceiling test calculation. The effect of including those hedges was a $197.9 million pre-tax increase in the discounted net cash flow of our oil and natural gas properties. Our qualifying cash flow hedges as of March 31, 2009, which consisted of swaps and collars, covered 2009 production of 30.3 Billion cubic feet of natural gas equivalent (Bcfe) and 2010 production of 33.2 Bcfe.

At September 30, 2010, using the existing 12-month average commodity prices, including the discounted value of our commodity hedges, we were not required to record a ceiling test write-down. However, if there are declines in the 12-month average prices, including the discounted value of our commodity hedges, we may be required to record a write-down in future periods. Our qualifying cash flow hedges used in the ceiling test determination as of September 30, 2010, consisted of swaps and collars covering 9.5 Bcfe in 2010, 12.1 Bcfe in 2011 and 8.8 Bcfe in 2012. The effect of those hedges on the September 30, 2010 ceiling test was a $29.5 million pre-tax increase in the discounted net cash flows of our oil and natural gas properties. Even without the impact of those hedges, we would not have been required to take a write-down for the quarter. Our oil and natural gas hedging is discussed in Note 10 of the Notes to our Condensed Consolidated Financial Statements.

NOTE 3 –ACQUISITIONS

During the second quarter of 2010 we completed an acquisition of oil and natural gas properties from certain unaffiliated third parties. The properties were purchased for approximately $73.7 million in cash after giving effect to certain post-closing adjustments. This transaction is reflected in oil and gas properties on the condensed consolidated balance sheets. After post-closing adjustments, the acquisition included approximately 45,000 net leasehold acres and 10 producing oil wells and is focused on 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.

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

NOTE 4 - EARNINGS PER SHARE

Information related to the calculation of earnings (loss) per share follows:


	Income (Numerator)		Weighted Shares (Denominator)		Per-Share Amount
	(In thousands except per share amounts)
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 stock appreciation rights (SARs)		0		137		0

Diluted earnings per common share	$	34,491		47,495	$	0.73


For the three months ended September 30, 2009:
Basic earnings per common share	$	31,449		47,011	$	0.67
Effect of dilutive stock options, restricted stock and SARs		0		408		(0.01	)

Diluted earnings per common share	$	31,449		47,419	$	0.66

The number of stock options and SARs (and their average exercise price) not included in the above computation because their exercise prices were greater than the average market price of our common stock was:


	Three Months Ended September 30,
	2010		2009

Stock options and SARs		361,421		358,021


Average Exercise Price	$	48.05	$	47.87


	Income/(Loss) (Numerator)			Weighted Shares (Denominator)		Per-Share Amount
	(In thousands except per share amounts)
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


For the nine months ended September 30, 2009:
Basic loss per common share	$	(84,013	)		46,980	$	(1.79	)
Effect of dilutive stock options, restricted stock and SARs		0			0		0

Diluted loss per common share	$	(84,013	)		46,980	$	(1.79	)

Because we had a net loss for the nine months ended September 30, 2009, approximately 300,000 weighted average shares related to stock options and SARs were antidilutive and not included in the calculation of earnings per share above. 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,
	2010		2009

Stock options and SARs		233,401		362,517


Average Exercise Price	$	53.12	$	47.67

NOTE 5 – ACCRUED LIABILITIES

Accrued liabilities consisted of the following:


	September 30, 2010		December 31, 2009
	(In thousands)

Taxes	$	14,804	$	5,085
Employee costs		11,717		13,307
Lease operating expenses		5,536		6,244
Deposit on rig sale		4,300		0
Other		6,030		9,935

Total accrued liabilities	$	42,387	$	34,571

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

Long-Term Debt

Currently, all of our long-term debt consists of borrowings under our bank credit agreement (Credit Facility). As of the dates in the table, long-term debt consisted of the following:


	September 30, 2010		December 31, 2009
	(In thousands)
Revolving credit facility with interest, including the effect of hedging, of 3.8% at September 30, 2010 and 4.3% at December 31, 2009	$	135,000	$	30,000
Less current portion		0		0

Total long-term debt	$	135,000	$	30,000

Our Credit Facility has a maximum credit amount of $400.0 million and matures on May 24, 2012. The lenders’ commitment under the Credit Facility is $325.0 million. Our borrowings are limited to the commitment amount that we elect. As of September 30, 2010, the commitment amount was $325.0 million. We are charged a commitment fee ranging from 0.375 to 0.50 of 1% on the amount available but not borrowed. The rate varies based on the amount borrowed as a percentage of the amount of the total borrowing base. To date we have paid $1.2 million in origination, agency and syndication fees under the Credit Facility. We are amortizing these fees over the life of the agreement.

The lenders’ aggregate commitment is limited to the lesser of the amount of the borrowing base or $400.0 million. The amount of the borrowing base, which is subject to redetermination on April 1 and October 1 of each year, is based primarily on a percentage of the discounted future value of our oil and natural gas reserves and, to a lesser extent, the loan value the lenders reasonably attribute to the cash flow (as defined in the Credit Facility) of our mid-stream segment. The October 1, 2010 redetermination maintained the borrowing base at $500.0 million. We or the lenders may request a onetime special redetermination of the amount of the borrowing base between each scheduled redetermination. In addition, we may request a redetermination following the completion of an acquisition that meets the requirements set forth in the Credit Facility.

At our election, any part of the outstanding debt under the Credit Facility may be fixed at a London Interbank Offered Rate (LIBOR) for a 30, 60, 90 or 180 day period. During any LIBOR funding period, the outstanding principal balance of the promissory note to which the LIBOR option applies may be repaid after three days prior notice to the administrative agent and on payment of any applicable funding indemnification amounts. LIBOR interest is computed as the sum of the LIBOR base for the applicable 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 BOK Financial Corporation (BOKF) National Prime Rate, which cannot be less than LIBOR plus 1.00%, and is payable at the end of each month and the principal borrowed may be paid at any time, in part or in whole, without a premium or penalty. At September 30, 2010, all of our $135.0 million in outstanding borrowings were subject to LIBOR.

The Credit Facility prohibits:

•

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

•

the incurrence of additional debt with certain limited exceptions; and

•

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

The Credit Facility also requires that we have at the end of each quarter:

•

consolidated net worth of at least $900 million;

•

a current ratio (as defined in the Credit Facility) of not less than 1 to 1; and

•

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

As of September 30, 2010, we were in compliance with our Credit Facility’s covenants.

Based on the borrowing rates currently available to us for debt with similar terms and maturities and consideration of our non-performance risk, long-term debt at September 30, 2010 approximates its fair value.

At September 30, 2010, the carrying values on the 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.

Other Long-Term Liabilities

Other long-term liabilities consisted of the following:


	September 30, 2010		December 31, 2009
	(In thousands)
Asset retirement obligations (ARO)	$	64,643	$	56,404
Workers’ compensation		21,666		22,974
Separation benefit plans		5,107		4,681
Gas balancing		3,263		3,263
Deferred compensation plan		2,193		2,004

		96,872		89,326
Less current portion		9,490		9,342

Total other long-term liabilities	$	87,382	$	79,984

Estimated annual payments due under the terms of debt and other long-term liabilities during each of the five successive twelve month periods beginning October 1, 2010 (and through 2015) are $9.5 million, $152.5 million, $3.4 million, $2.9 million and $2.8 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. 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 expense 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.

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


	Nine Months Ended September 30,
	2010			2009
	(In thousands)

ARO liability, January 1:	$	56,404		$	49,230
Accretion of discount		2,138			1,927
Liability incurred		2,901			2,485
Liability settled		(622	)		(2,226	)
Revision of estimates ⁽¹⁾		3,822			2,897

ARO liability, September 30:		64,643			54,313
Less current portion		1,617			1,149

Total long-term plugging liability	$	63,026		$	53,164

(1) Plugging liability estimates were revised upward in both 2010 and 2009 due to increases in the cost of services used to plug wells over the preceding years.

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 is 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 is required for annual reporting periods beginning after December 15, 2010 and for interim reporting periods within those years. This statement did not and will not have a significant impact on us due to it only requiring enhanced disclosures.

NOTE 9 – STOCK-BASED COMPENSATION

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, 2010 is approximately $11.9 million, $2.4 million of which we expect to capitalize. The weighted average period of time over which this cost will be recognized is 0.8 years.

For the three and nine months ended September 30, 2009, we recognized stock compensation expense for restricted stock awards, stock options and stock settled SARs of $1.7 million and $5.4 million, respectively, and capitalized stock compensation cost for oil and natural gas properties of $0.5 million and $1.6 million, respectively. The tax benefit related to this stock based compensation was $0.6 million and $2.0 million, respectively.

The following table shows the estimated fair value of the stock options granted to our non-employee directors during the periods indicated using the Black-Scholes model and applying the estimated values presented in the table:


	Nine Months Ended
	September 30,
	2010			2009

Options granted ⁽¹⁾		52,504			3,496
Estimated fair value (in millions)	$	0.8		$	0.1
Estimate of stock volatility		0.45			0.41
Estimated dividend yield		0	%		0	%
Risk free interest rate		2	%		2	%
Expected annual life based on prior experience		5			5
Forfeiture rate		0	%		5	%
(1) On May 29, 2009, eight of our directors were each awarded 3,063 options contingent on shareholder approval, which was received at the May 5, 2010 annual shareholder’s meeting. These 24,504 options granted and vested simultaneously with that approval. On May 6, 2010, eight of our directors each received 3,500 options which vest on November 6, 2010.

Estimated 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. We have not paid dividends on our stock. The risk free interest rate is calculated using the LIBOR rate over the term we anticipate the grant will be exercised. The stock options granted in the first nine months of 2010 increased stock compensation expense for the third quarter and first nine months of 2010 by $0.2 million and $0.7 million, respectively.

This table shows the fair value of the restricted stock awards granted during the periods indicated:


	Three Months Ended September 30,						Nine Months Ended September 30,
	Three Months Ended September 30,						Nine Months Ended September 30,
	2010			2009			2010			2009

Shares granted		192,272			0			440,655			0

Estimated fair value (in millions)	$	6.0		$	0		$	16.6		$	0

Percentage of shares expected to be distributed		89	%		0	%		91	%		0	%

The restricted stock awards granted during the first nine months of 2010 will be recognized over their two and three year vesting periods. These awards increased stock compensation expense and the capitalized cost related to our oil and natural gas properties for the third quarter and the first nine months of 2010 by $2.0 million and $5.1 million, respectively.

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 these transactions we swap the variable interest rate we would otherwise pay on a portion of our bank debt for a fixed interest rate. As of September 30, 2010, we had two outstanding interest rate swaps; both were cash flow hedges. There was no material amount of ineffectiveness. This table provides certain information about those interest rate swaps:


Term	Amount		Fixed Rate			Floating Rate
October 2010 – May 2012	$	15,000,000		4.53	%	3 month LIBOR
October 2010 – May 2012	$	15,000,000		4.16	%	3 month LIBOR

Commodity Derivatives

We have entered into various types of derivative instruments covering some of our projected natural gas, natural gas liquids 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, 2010, our derivative instruments consisted of the following types of swaps and collars:

•

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

•

Collars. A collar contains a fixed floor price (put) and a ceiling price (call). If the market price exceeds the call strike price or falls below the put strike price, we receive the fixed price and pay the market price. If the market price is between the call and the put strike price, no payments are due from either party.

•

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, 2010, the following cash flow hedges were outstanding:

Term	Commodity	Hedged Volume	Weighted Average Fixed Price for Swaps	Hedged Market
Oct’10 – Dec’10	Crude oil - collar	1,000 Bbl/day	$67.50 put & $81.53 call	WTI – NYMEX
Oct’10 – Dec’10	Crude oil – swap	1,500 Bbl/day	$61.36	WTI – NYMEX
Jan’11 – Dec’11	Crude oil – swap	2,500 Bbl/day	$80.32	WTI – NYMEX
Jan’12 – Dec’12	Crude oil – swap	1,500 Bbl/day	$82.49	WTI – NYMEX

Oct’10 – Dec’10	Natural gas – swap	15,000 MMBtu/day	$7.20	IF – NYMEX (HH)
Oct’10 – Dec’10	Natural gas – swap	20,000 MMBtu/day	$6.89	IF – Tenn Zone 0
Oct’10 – Dec’10	Natural gas – swap	30,000 MMBtu/day	$6.12	IF – CEGT
Oct’10 – Dec’10	Natural gas – swap	20,000 MMBtu/day	$5.67	IF – PEPL

Oct’10 – Dec’10	Natural gas – basis differential swap	10,000 MMBtu/day	($0.79)	PEPL – NYMEX
Jan’11 – Dec’11	Natural gas – swap	15,000 MMBtu/day	$5.56	IF – NYMEX (HH)

Jan’11 – Dec’11	Natural gas – basis differential swap	15,000 MMBtu/day	($0.14)	Tenn Zone 0 – NYMEX
Jan’12 – Dec’12	Natural gas – swap	15,000 MMBtu/day	$5.62	IF – PEPL

Oct’10 – Dec’11	Liquids – swap (1)	644,406 Gal/mo	$0.98	OPIS – Conway

(1) Types of liquids involved are natural gasoline, ethane, propane, isobutane and normal butane. At September 30, 2010, the following non-qualifying cash flow derivatives were outstanding:

Term	Commodity	Hedged Volume	Basis Differential	Hedged Market
Jan’11 – Dec’11	Natural gas – basis differential swap	15,000 MMBtu/day	($0.14)	Tenn Zone 0 – NYMEX
Jan’11 – Dec’11	Natural gas – basis differential swap	10,000 MMBtu/day	($0.21)	CEGT – NYMEX
Jan’11 – Dec’11	Natural gas – basis differential swap	10,000 MMBtu/day	($0.23)	PEPL – NYMEX
The following two tables present the fair values and locations where these derivative instruments are recorded in our balance sheets:


		Derivative Assets
		Fair Value
		September 30,		December 31,
	Balance Sheet Location	2010		2009
		(In thousands)
Derivatives designated as hedging instruments

Commodity derivatives:
Current	Current derivative assets	$	18,833	$	9,945
Long-term	Non-current derivative assets		5,505		0

Total derivatives designated as hedging instruments			24,338		9,945


Derivatives not designated as hedging instruments

Commodity derivatives (basis swaps):
Current	Current derivative assets		567		0
Long-term	Non-current derivative assets		189		0

Total derivatives not designated as hedging instruments			756		0


Total derivative assets		$	25,094	$	9,945


	Balance Sheet Location	Derivative Liabilities
		Fair Value
		September 30, 2010		December 31, 2009
		(In thousands)
Derivatives designated as hedging instruments

Interest rate swaps:
Current	Current portion of derivative liabilities	$	1,159	$	806
Long-term	Long-term derivative liabilities		773		1,142
Commodity derivatives:
Current	Current portion of derivative liabilities		0		1,424
Long-term	Long-term derivative liabilities		2,579		0

Total derivatives designated as hedging instruments			4,511		3,372


Derivatives not designated as hedging instruments

Commodity derivatives (basis swaps):
Current	Current derivative liabilities		119		0
Long-term	Long-term derivative liabilities		40		0

Total derivatives not designated as hedging instruments			159		0


Total derivative liabilities		$	4,670	$	3,372

If a legal right of set-off exists, we net the value of the derivative arrangements we have with the same counterparty on 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 on the purchases to expense as each of the underlying transactions are settled. As of September 30, 2010 and 2009, we had a gain of $12.3 million and $10.4 million, net of tax, respectively, in accumulated OCI.

Based on market prices at September 30, 2010, we expect to transfer to earnings approximately $11.4 million, net of tax, of the gain included in accumulated OCI over the next 12 months as the various transactions are settled. The interest rate swaps and the commodity derivative instruments existing as of September 30, 2010 are expected to mature by May 2012 and December 2012, respectively.

Certain derivatives do not qualify as cash flow hedges. Currently, we have three basis swaps that do not qualify as cash flow hedges. For these, any changes in their fair value that occurs before their maturity (i.e., temporary fluctuations in value) are reported in the condensed consolidated statements of operations within our oil and natural gas revenues. Any 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 our 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 cash flow hedges on our Condensed Consolidated Statement of Operations:


Derivatives in Cash Flow Hedging Relationships	Amount of Gain or (Loss) Recognized in Accumulated OCI on Derivative (Effective Portion) ⁽¹⁾
	Nine Months Ended September 30,
	2010			2009
	(In thousands)
Interest rate swaps	$	(1,193	)	$	(1,336	)
Commodity derivatives		13,459			11,699

Total	$	12,266		$	10,363

(1)Net of taxes.

Effect of cash flow hedges on our Condensed Consolidated Statement of Operations:


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⁾

		Three Months Ended September 30,						Three Months Ended September 30,
		2010			2009			2010		2009
		(In thousands)
Commodity derivatives	Oil and natural gas revenue	$	14,760		$	27,765		$	176	$	(253	)
Interest rate swaps	Interest, net		(298	)		(291	)		0		0

	Total	$	14,462		$	27,474		$	176	$	(253	)

(1)

Effective portion of gain (loss).

(2)

Ineffective portion of gain (loss).

Effect of derivatives not designated as hedging instruments on our Condensed Consolidated Statement of Operations:


Derivatives Not Designated as Hedging Instruments	Location of Loss Recognized in Income on Derivative	Amount of Loss Recognized in Income on Derivative
		Three Months Ended September 30,
		2010			2009
		(In thousands)

Commodity derivatives (basis swaps)	Oil and natural gas revenue	$	(427	)	$	(869	)

Total		$	(427	)	$	(869	)

Effect of cash flow hedges on our Condensed Consolidated Statement of Operations:


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⁾

		Nine Months Ended September 30,						Nine Months Ended September 30,
		2010			2009			2010		2009
		(In thousands)
Commodity derivatives	Oil and natural gas revenue	$	36,447		$	85,798		$	605	$	(372	)
Interest rate swaps	Interest, net		(907	)		(728	)		0		0

	Total	$	35,540		$	85,070		$	605	$	(372	)

(1)

Effective portion of gain (loss).

(2)

Ineffective portion of gain (loss).

Effect of derivatives not designated as hedging instruments on our Condensed Consolidated Statement of Operations:


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
		Nine Months Ended September 30,
		2010		2009
		(In thousands)

Commodity derivatives (basis swaps)	Oil and natural gas revenue	$	597	$	(3,260	)

Total		$	597	$	(3,260	)

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). Exit price is estimated using a three-level hierarchy that prioritizes 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.

The following tables show our recurring fair value measurements:


	September 30, 2010
	Level 1		Level 2			Level 3			Total
	(In thousands)
Financial assets (liabilities):
Interest rate swaps	$	0	$	0		$	(1,932	)	$	(1,932	)
Commodity derivatives	$	0	$	(9,440	)	$	31,796		$	22,356


	December 31, 2009
	Level 1		Level 2			Level 3			Total
	(In thousands)
Financial assets (liabilities):
Interest rate swaps	$	0	$	0		$	(1,948	)	$	(1,948	)
Commodity derivatives	$	0	$	(11,427	)	$	19,948		$	8,521

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. Our crude oil swaps are measured using estimated internal discounted cash flow calculations based on the NYMEX futures index.

Level 3 Fair Value Measurements:

Interest Rate Swaps. 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. Our natural gas and natural gas liquids swaps, basis swaps and crude oil and natural gas collars 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 show the reconciliations of our level 3 fair value measurements:


	Net Derivatives
	Three Months Ended September 30, 2010						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 (loss) ⁽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 gain (loss) 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 condensed consolidated statements of operations in interest, net and revenues, respectively.


	Net Derivatives
	Three Months Ended September 30, 2009						Nine Months Ended September 30, 2009
	Interest Rate Swaps			Commodity Swaps and Collars			Interest Rate Swaps			Commodity Swaps and Collars
	(In thousands)
Beginning of period	$	(1,969	)	$	49,193		$	(2,516	)	$	58,508
Total gains or losses (realized and unrealized):
Included in earnings (loss) ⁽¹⁾		(291	)		29,665			(728	)		81,791
Included in other comprehensive income (loss)		(185	)		(21,358	)		362			(27,733	)
Purchases, issuance and settlements		291			(29,660	)		728			(84,726	)

End of period	$	(2,154	)	$	27,840		$	(2,154	)	$	27,840


Total gains (losses) for the period included in earnings attributable to the change in unrealized gain (loss) relating to assets still held at end of period	$	0		$	5		$	0		$	(2,935	)

(1)

Interest rate swaps and commodity sales swaps and collars are reported in the condensed consolidated statements of operations in interest, net and revenues, respectively.

Based on our valuation at September 30, 2010, we determined that the non-performance risk with regard to our counterparties was immaterial.

NOTE 12 - INDUSTRY SEGMENT INFORMATION

Our three main business segments and the different products and services they offer are:


Segment		Services or Products
Contract drilling		Land contract drilling of oil and natural gas wells
Oil and natural gas		Development, acquisition and production of oil and natural gas properties
Mid-stream		Buying, selling, gathering, processing and treating of natural gas

Each segment’s performance is evaluated based on its operating income (loss) which is defined as its operating revenues less operating expenses and depreciation, depletion, amortization and impairment.

Although we have some production in Canada, it is not significant and therefore not split out below.

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


	Three Months Ended September 30,						Nine Months Ended September 30,
	2010			2009			2010			2009
	(In thousands)
Revenues:
Contract drilling	$	96,705		$	53,476		$	246,252		$	197,924
Elimination of inter-segment revenue		(11,701	)		(3,675	)		(28,333	)		(9,541	)

Contract drilling net of inter-segment revenue		85,004			49,801			217,919			188,383


Oil and natural gas		96,562			88,894			286,751			267,399


Gas gathering and processing		47,864			33,951			148,606			94,910
Elimination of inter-segment revenue		(10,435	)		(7,723	)		(33,698	)		(23,306	)

Gas gathering and processing net of inter-segment revenue		37,429			26,228			114,908			71,604


Other, net		(879	)		2,507			9,691			5,180

Total revenues	$	218,116		$	167,430		$	629,269		$	532,566


Operating income (loss): ⁽¹⁾
Contract drilling	$	21,129		$	9,422		$	36,372		$	45,015
Oil and natural gas ⁽²⁾		39,379			42,468			129,062			(166,488	)
Gas gathering and processing		2,863			2,221			10,755			(450	)

Total operating income (loss)		63,371			54,111			176,189			(121,923	)
General and administrative expense		(6,637	)		(5,506	)		(19,372	)		(17,088	)
Interest expense, net		0			(1	)		0			(539	)
Other income (loss), net		(879	)		2,507			9,691			5,180

Income (loss) before income taxes	$	55,855		$	51,111		$	166,508		$	(134,370	)

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

(2)	In March 2009, we incurred a $281.2 million pre-tax ($175.1 million net of tax) non-cash write-down of our oil and natural gas properties due to low commodity prices existing at the end of the first quarter 2009.

NOTE 13 - SUBSEQUENT EVENT

In September 2010, our contract drilling segment entered into a contract with an unaffiliated third-party under which we conveyed three of our idle mechanical drilling rigs and, in exchange, we 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 an estimated gain of $3.5 million. As a result of this transaction, our drilling rig fleet now totals 121.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders

Unit Corporation

We have reviewed the accompanying condensed consolidated balance sheet of Unit Corporation and its subsidiaries as of September 30, 2010, and the related condensed consolidated statements of operations and comprehensive income (loss) for the three and nine-month periods ended September 30, 2010 and 2009 and the condensed consolidated statements of cash flows for the nine-month periods ended September 30, 2010 and 2009. These interim financial statements are the responsibility of the company’s management.

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

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

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2009, and the related consolidated statements of operations, shareholders’ equity and of cash flows for the year then ended (not presented herein), and in our report dated February 23, 2010, 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, 2009, 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 4, 2010

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

MD&A should be read in combination with the unaudited condensed consolidated financial statements and related notes included in this quarterly report and 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.

•

Gas Gathering and Processing (Mid-Stream) – 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 each of our three operating segments depends, to a large extent, on: the prices received for our natural gas, natural gas liquids 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. While to-date all of our 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 impact 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.

The slowdown in the United States and world economies starting in late 2008 resulted in less demand for oil and natural gas products by those industries and consumers that use those products in their businesses. The long-term impact on our business and financial results as a consequence of the volatility in oil and natural gas prices and the global economic downturn is uncertain.

In developing our initial operating budget for 2010, we used average oil and natural gas prices of $72.00 per Bbl and $5.30 per Mcf. Our 2010 operating budget has been funded to date using internally generated cash flow and to a lesser extent from borrowings under our credit facility.

Executive Summary

Contract Drilling

Our utilization rate for the third quarter 2010 was 54%, compared to 47% and 26% from the second quarter of 2010 and the third quarter 2009, respectively.

Dayrates for the third quarter of 2010 averaged $15,814, an increase of 6% from the second quarter of 2010 and an increase of 3% from the third quarter of 2009. These increases were due primarily to increased demand for drilling rigs in the 1,000 to 1,500 horse power range.

Direct profit (contract drilling revenue less contract drilling operating expense) increased 55% from the second quarter of 2010 and 95% from the third quarter of 2009. The increase was primarily due to the increase in utilization over the comparative periods.

Operating cost per day decreased 14% from the second quarter of 2010 and decreased 19% from the third quarter of 2009. The decreases were primarily due to decreased per day indirect cost and decreases in workers’ compensation costs and fixed cost spread over more days due to increased utilization.

Historically, our contract drilling segment has experienced a greater demand for natural gas drilling as opposed to drilling for oil and NGLs. Today with the weakened demand and price for natural gas, operators are primarily focusing on drilling for oil and NGLs. Approximately 67% of our drilling rigs working today are drilling for oil or NGLs and approximately 88% are drilling horizontal or directional wells.

During the first half of 2010, our contract drilling segment sold eight of its idle mechanical drilling rigs to an unaffiliated third party. These drilling rigs ranged in horse power from 800 to 1,000. Proceeds from the sale of those drilling rigs were $23.9 million with a gain of $5.7 million. These proceeds are being 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 third-party under which we conveyed three of our idle mechanical drilling rigs and, in exchange, we 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 an estimated gain of $3.5 million. As a result of this transaction, our drilling rig fleet now totals 121.

Our anticipated 2010 capital expenditures for this segment are $130.0 million.

As of September 30, 2010, we had 43 long-term drilling contracts with original terms ranging from six months to two years. Eight of these contracts are up for renewals during the remainder of 2010, 34 are up for renewals during 2011 and one is up for renewal in 2012. These longer term contracts may contain a fixed rate for the duration of the contract or provide for the periodic renegotiation of the rate 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 third parties. The properties were purchased for approximately $73.7 million in cash after giving effect to certain post-closing adjustments. After these adjustments, the acquisition included approximately 45,000 net leasehold acres and 10 producing oil wells and is focused on 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.

Third quarter 2010 production from our oil and natural gas segment was 162,000 Mcfe per day, a 6% increase over the second quarter of 2010 and a 2% increase over the third quarter of 2009. The increase in production is primarily due to new wells being completed and coming online and, to a lesser extent, production associated with the acquisition discussed above. Our production for the second and third quarters of 2010 was negatively impacted by delays in securing third party fracture stimulation services and delays associated with connecting gathering systems. In addition, we also experienced loss of production due to the unexpected shut-in of some of our production from operational issues experienced at a third party facility that processes our Segno field production. Excluding the impact of the third quarter of 2010 Segno field production shut-in, third quarter 2010 production would have increased 8% over the second quarter of 2010 and 4% over the third quarter of 2009.

Third quarter 2010 oil and natural gas revenues increased 6% from the second quarter of 2010 and increased 9% from the third quarter of 2009.

Our natural gas and NGL prices in the third quarter of 2010 decreased 1% and 5%, respectively, from the second quarter of 2010 while oil prices remained flat over the two periods. Our oil and NGL prices increased 12% and 38%, respectively, from the third quarter of 2009 while natural gas prices decreased 2%.

Direct profit (oil and natural gas revenues less oil and natural gas operating expense) increased 3% from the second quarter of 2010 and increased 2% from the third quarter of 2009. The increases from the second quarter 2010 were primarily attributable to increases in production. The increases from the third quarter 2009 were primarily attributable to increases in prices.

Operating cost per Mcfe produced increased 6% from the second quarter of 2010 and increased 28% from the third quarter of 2009. The increase from the third quarter 2009 was primarily due to the increase in lease operating expense (LOE) and an increase in production taxes. Production taxes increased due to commodity price increases between the periods.

For 2010, we hedged approximately 61% of our average daily oil production, approximately 73% of our average natural gas production and approximately 12% of our average natural gas liquids production (percentages based on our third quarter 2010 production) to help manage our cash flow and capital expenditure requirements. Of the oil hedges, 60% are under swap contracts at an average price of $61.36 per barrel and 40% are under collar contracts with a floor of $67.50 per barrel and a ceiling of $81.53 per barrel. The natural gas production is hedged under swap contracts at a comparable average NYMEX price of $6.95. The average basis differential for the swaps is ($0.66). The natural gas liquids production is hedged under swap contracts at an average price of $41.13 per barrel.

Currently for 2011 we hedged approximately 61% of our average daily oil production, approximately 13% of our average natural gas production and approximately 12% of our average natural gas liquids production (percentages based on our third quarter 2010 production). The oil production is hedged under swap contracts at an average price of $80.32 per barrel. The natural gas production is hedged under swap contracts at a comparable average NYMEX price of $5.56. The average basis differential for the swaps is ($0.14). The natural gas liquids production is hedged under swap contracts at an average price of $40.76 per barrel.

Currently for 2012 we hedged approximately 36% of our average daily oil production, approximately and 13% of our average natural gas production (percentages based on our third quarter 2010 production). The oil production is hedged under swap contracts at an average price of $82.49 per barrel. The natural gas production is hedged under swap contracts at a comparable average NYMEX price of $5.90. The average basis differential for the swaps is ($0.28).

In March 2009, we incurred a non-cash ceiling test write-down of our oil and natural gas properties of $281.2 million pre-tax ($175.1 million net of tax) due to low commodity prices at the end of the first quarter. At September 30, 2010, the 12-month average of commodity prices, including the discounted value of our commodity hedges, were at levels that did not require us to record a write-down of our oil and natural gas properties. Prior to December 31, 2009, the price was based on the single-day period-end price. Effective December 31, 2009, reserve reporting rules require the use of a 12-month average price. The revision to the 12-month average price was made to reduce the affect of short-term volatility and seasonality that previously occurred with single-day pricing. Using the 12-month average may or may not result in write-downs that would have been required had the single-day period-end

price been used. Should the 12-month average for commodity prices decline below those existing at the period-end, including the discounted value of our commodity hedges, a write-down of the carrying value of our oil and natural gas properties could be required in future periods.

During the first, second and third quarters of 2010, we completed 27 wells, 39 wells and 39 wells, respectively. Our first quarter 2010 drilling activity was slowed down by unusually wet weather, especially in the Texas Panhandle Granite Wash play, and operational delays as we shifted to drilling primarily horizontal wells. The delays in getting wells online are primarily due to delays in securing fracture stimulation services and connections to gathering systems. During the third quarter, we undertook steps that we now feel will allow us to obtain these required services so that by the end of the year we should have eliminated the unusually large backlog of our well completions, especially in the Granite Wash and Marmaton plays. Additionally, we have scheduled fracture stimulation services for all of 2011 for all the wells we currently anticipate drilling in the Granite Wash play. As a result, we are revising our 2010 production guidance to approximately 59.0 to 60.0 Bcfe, although actual results will continue to be subject to the timing of third party services. The number of wells we plan to participate in drilling and the level of capital expenditures for 2010 is 160 wells and $344 million, respectively.

Mid-Stream

Third quarter 2010 liquids sold per day decreased 7% from the second quarter of 2010 and increased 3% from the third quarter of 2009. The decrease over the second quarter of 2010 was primarily due to reduced liquid recoveries from gas processed. The increase over the third quarter of 2009 was primarily as the result of upgrades and expansions to existing plants and the connection of new wells. Gas processed per day increased 2% from the second quarter of 2010 and 8% from the third quarter of 2009. In 2009, we upgraded several of our existing processing facilities and added three processing plants which was the primary reason for increased volumes. Gas gathered per day remained unchanged from the second quarter of 2010 and increased 2% from the third quarter of 2009 primarily from increased well connects throughout 2010, slightly offset by well production declines associated with the wells gathered from two of our gathering systems located in Southeast Texas.

NGL prices in the third quarter of 2010 increased 1% from the price received in the second quarter of 2010 and 28% from the price received in the third quarter of 2009. The price of liquids as compared to natural gas affects the revenue in our mid-stream 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. We currently do not have any fractionation spread hedges in place for 2010 and beyond.

Direct profit (mid-stream revenues less mid-stream operating expense) decreased 10% from the second quarter of 2010 and increased 8% from the third quarter of 2009. The decrease from the second quarter 2010 was due to a decrease in liquids sold and the increase from the third quarter 2009 resulted primarily from increased liquids sold and gas processed volumes and commodity prices. Total operating cost for our mid-stream segment increased 6% from the second quarter of 2010 and increased 54% from the third quarter of 2009 due primarily to the increase in gas purchases over the second quarter 2010 and the fluctuation in the price paid for the purchase of natural gas over the third quarter 2009.

We are in the final stages of completing a 50.0 MMcf per day turbo-expander natural gas processing plant at our Hemphill facility in Canadian, Texas. This gas processing plant should be completed and operational in the fourth quarter of 2010. Upon completion of this new natural gas processing plant, the total processing capacity at our Hemphill facility will increase to approximately 100.0 MMcf per day. In connection with our Appalachian operations, we recently committed to build a 16-mile, 16" pipeline and a compressor station in Preston County, West Virginia, which will have a capacity of approximately 200 MMcf per day. Preliminary right-of-way and environmental work is nearing completion and construction is scheduled to begin during the first quarter of 2011 with the facility being operational by mid-2011. We have signed an agreement to transport gas on this system for an unaffiliated third party.

Our anticipated capital expenditures for 2010 are $40.0 million.

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 Facility. 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, natural gas and NGL 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, 2010 and 2009 and for the nine months ended September 30, 2010 and 2009:


	September 30,						% Change ⁽²⁾
	2010			2009			% Change ⁽²⁾
	(In thousands except percentages)
Working capital	$	35,480		$	16,424			116	%
Long-term debt	$	135,000		$	30,000			NM	%
Shareholders’ equity ⁽¹⁾	$	1,682,868		$	1,541,017			9	%
Ratio of long-term debt to total capitalization ⁽¹⁾		7	%		2	%		NM	%
Net income (loss) ⁽¹⁾	$	102,819		$	(84,013	)		NM	%
Net cash provided by operating activities	$	283,896		$	422,570			(33	)%
Net cash used in investing activities	$	(393,804	)	$	(204,637	)		92	%
Net cash provided by (used in) financing activities	$	109,901		$	(217,371	)		151	%

(1)

In March 2009, we incurred a $281.2 million pre-tax ($175.1 million net of tax) non-cash ceiling test write-down of our oil and natural gas properties due to low commodity prices at quarter-end. The write-down impacted our 2009 shareholders’ equity, ratio of long-term debt to total capitalization and net income. The write-down did not impact our compliance with the covenants contained in our Credit Facility.

(2)

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

The following table summarizes certain operating information:


	Nine Months Ended September 30,				% Change
	2010		2009		% Change
Contract Drilling:
Average number of our drilling rigs in use during the period		58.2		39.6		47	%
Total number of drilling rigs owned at the end of the period		123		130		(5	)%
Average dayrate	$	15,037	$	17,335		(13	)%
Oil and Natural Gas:
Oil production (MBbls)		1,002		991		1	%
Natural gas liquids production (MBbls)		1,143		1,142		0	%
Natural gas production (MMcf)		30,121		33,575		(10	)%
Average oil price per barrel received	$	67.05	$	54.77		22	%
Average oil price per barrel received excluding hedges	$	74.11	$	51.76		43	%
Average NGL price per barrel received	$	35.91	$	21.80		65	%
Average NGL price per barrel received excluding hedges	$	35.70	$	22.51		59	%
Average natural gas price per mcf received	$	5.71	$	5.53		3	%
Average natural gas price per mcf received excluding hedges	$	4.27	$	3.06		40	%
Mid-Stream:
Gas gathered—MMBtu/day		182,390		186,296		(2	)%
Gas processed—MMBtu/day		81,157		75,371		8	%
Gas liquids sold — gallons/day		264,679		236,692		12	%
Number of natural gas gathering systems		34		34		0	%
Number of processing plants		8		8		0	%

At September 30, 2010, we had unrestricted cash totaling $1.1 million and we had borrowed $135.0 million of the $325.0 million we had elected to have available under our Credit Facility. Our Credit Facility is used for working capital and capital expenditures. Most of our capital expenditures were discretionary and directed toward future growth. Beginning in the fourth quarter of 2008 and continuing through 2009, we significantly reduced our capital expenditures because of the uncertain economic environment. For 2010, we have increased our capital expenditures, focusing on growth and funded mainly through internally generated cash flow and from borrowings under the credit facility.

Working Capital

Typically, our working capital balance varies primarily 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 $35.5 million and $16.4 million as of September 30, 2010 and 2009, respectively. The effect of our hedging activity increased working capital by $11.4 million and $8.8 million as of September 30, 2010 and 2009, respectively.

Contract Drilling

Many factors influence the number of drilling rigs we have working 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 natural gas and oil, availability and cost of labor to run our drilling rigs and our ability to supply the equipment needed.

During 2009, competition to keep and attract qualified employees to meet our requirements did not materially affect us due to the depressed conditions within our industry. With the increased utilization over last year’s levels, competition to keep qualified labor has increased so starting in the third quarter 2010; we increased compensation for drilling personnel in Oklahoma, Texas and Louisiana. Further increases in utilization beyond third quarter 2010 levels could also be hampered by limited availability of personnel.

Demand for drilling rigs in the 1,000 to 1,500 horsepower range has increased over the past year as more of our customers shift to drilling horizontal wells, which are suited for this horsepower range. Availability of drilling rigs in this range will also have a larger impact on dayrates in the future. For the first nine months of 2010, our average dayrate was $15,037 per day compared to $17,335 per day for the first nine months of 2009. The average number of our drilling rigs used in the first nine months of 2010 was 58.2 drilling rigs (47%) compared with 39.6 drilling rigs (30%) in the first nine months of 2009. Based on the average utilization of our drilling rigs during the first nine months of 2010, a $100 per day change in dayrates has a $5,820 per day ($2.1 million annualized) change in our pre-tax operating cash flow.

Our contract drilling segment provides drilling services for our exploration and production segment. Depending on their timing some of the drilling services performed on our properties are also deemed to be associated with the acquisition of an ownership interest in the property. Revenues and expenses for such 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 $28.3 million and $9.5 million for the nine months of 2010 and 2009, respectively from our contract drilling segment and eliminated the associated operating expense of $23.6 million and $8.3 million during the nine months of 2010 and 2009, respectively, yielding $4.7 million and $1.2 million during the nine months of 2010 and 2009, 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

As of December 31, 2009, natural gas comprised 73% of our oil, NGLs and natural gas reserves. Any significant change in 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, economic conditions, supply imbalances worldwide oil price levels and the value of the U.S. dollar. 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.

Based on our first nine months of 2010 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 $316,000 per month ($3.8 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 2010 was $5.71 compared to $5.53 for the first nine months of 2009. Based on our first nine months of 2010 production, a $1.00 per barrel change in our oil price, without the effect of hedging, would have a $105,000 per month ($1.3 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 $121,000 per month ($1.5 million annualized) change in our pre-tax operating cash flow. In the first nine months of 2010, our average oil price per barrel received, including the effect of hedging, was $67.05 compared with an average oil price, including the effect of hedging, of $54.77 in the first nine months of 2009 and our first nine months of 2010 average NGLs price per barrel received was $35.91 compared with an average NGL price per barrel of $21.80 in the first nine months of 2009.

Because prices have such a significant 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 bank credit facility since that determination is based mainly on the value of our oil, NGLs and natural gas reserves. Such a reduction could limit our ability to carry out our planned capital projects.

Most of our natural gas production is sold to third parties under month-to-month contracts.

Mid-Stream Operations

Our mid-stream operations are conducted through Superior Pipeline Company, L.L.C. and its subsidiaries. Superior is a mid-stream company engaged primarily in the buying, selling, gathering, processing and treating of natural gas and operates three natural gas treatment plants, eight processing plants, 34 gathering systems and 853

miles of pipeline. Superior operates in Oklahoma, Texas, Kansas, Pennsylvania and West Virginia and has been in business since 1996. 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 2010 and 2009, our mid-stream operations purchased $30.5 million and $19.7 million, respectively, of our oil and natural gas segment’s production and provided gathering and transportation services to it of $3.2 million and $3.6 million, respectively. Intercompany revenue from services and purchases of production between our mid-stream segment and our oil and natural gas exploration segment has been eliminated in our condensed consolidated financial statements.

Our mid-stream segment gathered an average of 182,390 MMBtu per day in the first nine months of 2010 compared to 186,296 MMBtu per day in the first nine months of 2009, processed volumes were 81,157 MMBtu per day in the first nine months of 2010 compared to 75,371 MMBtu per day in the first nine months of 2009 and the amount of NGLs sold were 264,679 gallons per day in the first nine months of 2010 compared to 236,692 gallons per day in the first nine months of 2009. Gas gathering volumes per day in the first nine months of 2010 decreased 2% compared to the first nine months of 2009 primarily due to a volumetric decline in gathering systems due to natural production declines associated with the connected wells. Processed volumes increased 8% over the comparative nine months and NGLs sold also increased 12% over the comparative period primarily due to the addition of wells connected and recent upgrades to several of our processing systems.

Our Credit Facility

Our existing Credit Facility has a maximum credit amount of $400.0 million and matures on May 24, 2012. The lenders’ current commitment under the Credit Facility is $325.0 million. Our borrowings are limited to the commitment amount that we elect. As of September 30, 2010, the commitment amount was $325.0 million. We are charged a commitment fee ranging from 0.375 to 0.50 of 1% on the amount available but not borrowed. The rate varies based on the amount borrowed as a percentage of the amount of the total borrowing base. To date we have paid $1.2 million in origination, agency and syndication fees under the Credit Facility. We are amortizing these fees over the life of the agreement. The average interest rate for both the first nine months of 2010 and the first nine months of 2009, which includes the effect of our two interest rate swaps, was 3.8%. At September 30, 2010 and October 29, 2010, borrowings were $135.0 million.

The lenders under our Credit Facility and their respective participation interests are as follows:


Lender	Participation Interest
Bank of Oklahoma, N.A.		18.75%
Bank of America, N.A.		18.75%
BMO Capital Markets Financing, Inc.		18.75%
BBVA Compass Bank		17.50%
Comerica Bank		08.75%
BNP Paribas		08.75%
Crédit Agricole Corporate and Investment Bank		08.75%

		100.00%

principal balance of the promissory note to which the LIBOR option applies may be repaid after three days prior notice to the administrative agent and on payment of any applicable funding indemnification amounts. LIBOR interest is computed as the sum of the LIBOR base for the applicable 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 BOK Financial Corporation (BOKF) National Prime Rate, which cannot be less than LIBOR plus 1.00%, and is payable at the end of each month and the principal borrowed may be paid at any time, in part or in whole, without a premium or penalty. At September 30, 2010, all of our $135.0 million in outstanding borrowings were subject to LIBOR.

The Credit Facility prohibits:

•

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

•

the incurrence of additional debt with certain very 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 Facility also requires that we have at the end of each quarter:

•

a consolidated net worth of at least $900.0 million;

•

a current ratio (as defined in the Credit Facility) of not less than 1 to 1; and

•

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

As of September 30, 2010, we were in compliance with the Credit Facility’s covenants.

We entered into the following interest rate swaps to manage our exposure to possible future interest rate increases. Under these transactions we swapped the variable interest rate we would otherwise incur on a portion of our bank debt for a fixed rate of interest:


Term	Amount		Fixed Rate			Floating Rate

October 2010 – May 2012	$	15,000,000		4.53	%	3 month LIBOR
October 2010 – May 2012	$	15,000,000		4.16	%	3 month LIBOR

Capital Requirements

Contract Drilling Acquisitions, Dispositions and Capital Expenditures. During the first half of 2010, our contract drilling segment sold eight of its idle mechanical drilling rigs to an unaffiliated third party. These drilling rigs ranged in horse power from 800 to 1,000. Proceeds from the sale of those drilling rigs were $23.9 million with a gain of $5.7 million which was booked in the first quarter 2010. These proceeds are being 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.

Recently we signed two year contracts for each of the four new 1,500 horse power drilling rigs which will be deployed in the Bakken play. We are currently building these rigs, two of which will be delivered during the first quarter of 2011 and the remaining two during the third quarter of 2011. Our anticipated 2010 capital expenditures for this segment have been revised from $76.0 million to $130.0 million due to refurbishments and new rig construction. At September 30, 2010, we had commitments to purchase approximately $10.2 million for drill pipe and top drives over the next year. We have spent $85.7 million in capital expenditures as of September 30, 2010 compared to $37.4 million as of September 30, 2009.

Oil and Natural Gas Segment Acquisitions and Capital Expenditures. Most of our capital expenditures 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 105 gross wells (57.33 net wells) in the first nine months of 2010 compared to 58 gross wells (24.83 net wells) in the first nine months of 2009. Total capital expenditures for the first nine months of 2010 by this segment, excluding a $6.1 million ARO liability and $92.6 million for acquisitions, totaled $238.4 million compared to $166.7 million at September 30, 2009. Currently we plan to participate in drilling an estimated 160 gross wells in 2010 and have reduced our estimate of total capital expenditures (excluding acquisitions) for our oil and natural gas segment from approximately $365.0 million to $344.0 million. Whether we are able to drill the full number of wells we are planning on drilling is dependent on a number of factors, many of which are beyond our control and include the availability of drilling rigs, availability of pressure pumping services, prices for oil, NGLs and natural gas, demand for oil and natural gas, the cost to drill wells, the weather and the efforts of outside industry partners.

In June 2010, we completed an acquisition of oil and natural gas properties from certain unaffiliated third parties. The properties were purchased for approximately $73.7 million in cash after giving effect to certain post-closing adjustments. After these adjustments, the acquisition included approximately 45,000 net leasehold acres and 10 producing oil wells and is focused on 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.

Mid-Stream Acquisitions and Capital Expenditures. During the first nine months of 2010, our mid-stream segment incurred $19.7 million in capital expenditures as compared to $7.8 million in the first nine months of 2009. For 2010, we revised our estimated capital expenditures from approximately $53.0 million to $40.0 million due to timing of construction projects in Appalachia.

As of December 31, 2008, we had commitments to purchase two new processing plants. After December 31, 2008, we cancelled the purchase of one of these plants due to nonperformance of contractual terms. We are seeking to recover the $2.8 million progress payments made toward the full purchase price before this contract was terminated. In March 2009, we cancelled our remaining commitment for the second plant and incurred a $1.3 million penalty. Approximately half of the penalty is being applied toward the purchase price of the plant we are constructing in 2010.

Contractual Commitments

At September 30, 2010, we had the following contractual obligations:


	Payments Due by Period
	Total		Less Than 1 Year		2-3 Years		4-5 Years		After 5 Years
	(In thousands)
Bank debt (1)	$	140,634	$	3,420	$	137,214	$	0	$	0
Operating leases (2)		6,306		1,703		2,844		1,759		0
Drill pipe, drilling components and equipment purchases (3)		11,235		11,235		0		0		0

Total contractual obligations	$	158,175	$	16,358	$	140,058	$	1,759	$	0

(1)	See previous discussion in MD&A regarding our Credit Facility. This obligation is presented in accordance with the terms of the Credit Facility and includes interest calculated using our September 30, 2010 interest rate of 3.8% which includes the effect of the interest rate swaps.

(2)

We lease office space or yards in Elk City, Oklahoma City and Tulsa, Oklahoma; Houston, Texas; Denver, 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)	For the next twelve months, we have committed to purchase approximately $10.2 million for drill pipe and top drives. Also in 2010, we will pay the remaining $1.0 million towards the purchase of a 50.0 MMcf per day gas plant.

At September 30, 2010, 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)	$	2,193		Unknown		Unknown		Unknown		Unknown
Separation benefit plans (2)	$	5,107	$	169		Unknown		Unknown		Unknown
Derivative liabilities – interest rate swaps	$	1,932	$	1,159	$	773	$	0	$	0
Derivative liabilities – commodities	$	2,738	$	119	$	2,619	$	0	$	0
Asset retirement liability (3)	$	64,643	$	1,617	$	18,107	$	4,597	$	40,322
Gas balancing liability (4)	$	3,263		Unknown		Unknown		Unknown		Unknown
Repurchase obligations (5)	$	0		Unknown		Unknown		Unknown		Unknown
Workers’ compensation liability (6)	$	21,666	$	7,704	$	2,779	$	1,141	$	10,042

(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 Condensed Consolidated Balance Sheet, 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 any 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 have recorded 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 2010, 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. Such repurchases in any one year are limited to 20% of the units outstanding. We made repurchases of $22,000 in 2010, $1,000 in 2009 and $241,000 in 2008.

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

Derivative Activities

Periodically we enter into hedge transactions covering part of the interest we incur under our Credit Facility as well as the prices to be received for a portion of our future 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 Facility. 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. As of September 30, 2010, we had two outstanding interest rate swaps; both were cash flow hedges. There was no material amount of ineffectiveness. Our September 30, 2010 balance sheet recognized the fair value of these swaps as current and non-current derivative liabilities and is presented in the table below:


Term	Amount		Fixed Rate			Floating Rate		Fair Value Asset (Liability)
($ in thousands)
October 2010 – May 2012	$	15,000		4.53	%		3 month LIBOR	$	(1,013	)
October 2010 – May 2012	$	15,000		4.16	%		3 month LIBOR		(919	)

								$	(1,932	)

Because of these interest rate swaps, interest expense increased by $0.3 million and $0.9 million for the three and nine months ended September 30, 2010, respectively. A loss of $1.2 million, net of tax, is reflected in accumulated other comprehensive income as of September 30, 2010. Interest expense increased by $0.3 million and $0.7 million for the three and nine months ended September 30, 2009.

Commodity Hedges. Our hedging is intended to reduce 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 2010 average daily production, as of September 30, 2010, the approximated percentages we have hedged are as follows:

Oil and Natural Gas Segment:


	October – December 2010		January – December 2011		January – December 2012
Daily oil production		61%		61%		36%
Daily natural gas production		73%		13%		13%
Natural gas liquids production		12%		12%		0%

With respect to the commodities subject to the hedge, 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 favorable price movements.

The use of derivative transactions also involves the risk that the counterparties will be unable to meet the financial terms of the transactions. Based on our valuation at September 30, 2010, we determined that the non-performance risk with regard to our counterparties was immaterial. At September 30, 2010, Bank of Montreal, Bank of America, N.A., Crédit Agricole Corporate and Investment Bank, London Branch, Comerica Bank, BBVA Compass Bank, Barclays Capital and ConocoPhillips were the counterparties with respect to all of our commodity derivative transactions. At September 30, 2010, the fair values of the net assets (liabilities) we had with each of these counterparties was $14.8 million, $4.6 million, ($1.2) million, $2.0 million, $0.6 million, $1.5 million and $0.1 million, respectively.

If a legal right of set-off exists, we net the value of the derivative arrangements we have with the same counterparty in our condensed consolidated balance sheets. At September 30, 2010, we recorded the fair 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. At September 30, 2009, we recorded the fair value of our commodity derivatives on our balance sheet as current and non-current derivative assets of $22.9 million and $2.2 million, respectively, and current and non-current derivative liabilities of $7.0 million and $0.9 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, 2010, we had a gain of $13.5 million, net of tax from our oil and natural gas segment derivatives and no gain or loss from our mid-stream segment derivatives in accumulated OCI.

Based on market prices at September 30, 2010, we expect to transfer to earnings approximately $11.4 million, net of tax, of the gain included in accumulated OCI during the next 12 months in the related month of production. The interest rate swaps and the commodity derivative instruments existing as of September 30, 2010 are expected to mature by May 2012 and December 2012, respectively.

Certain derivatives do not qualify as cash flow hedges. Currently, we have three basis swaps that do not qualify as cash flow hedges. For these types of derivatives, any changes in the fair value that occurs before their maturity (i.e., temporary fluctuations in value) are reported currently in the condensed consolidated statements of operations 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,
	2010			2009			2010		2009
	(In thousands)
Oil and natural gas revenue:
Realized gains on oil and natural gas derivatives	$	14,760		$	26,638		$	36,447	$	85,101
Unrealized gains (losses) on ineffectiveness of cash flow hedges		176			(253	)		605		(372	)
Unrealized gains (losses) on non-qualifying oil and natural gas derivatives		(427	)		258			597		(2,563	)


Impact on pre-tax earnings	$	14,509		$	26,643		$	37,649	$	82,166

Stock and Incentive Compensation

During the first nine months of 2010, we granted awards covering 440,655 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 $16.6 million. Compensation expense will be recognized over their two and three year vesting periods, and during the first nine months of 2010, we recognized $4.1 million in additional compensation expense and capitalized $1.0 million for these awards. During the first nine months of 2010, we recognized compensation expense of $8.3 million for all of our restricted stock, stock options and SAR grants and capitalized $2.0 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 for fiduciary liability to $1.0 million for drilling rig physical damage. 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.

Oil and Natural Gas Limited Partnerships and Other Entity Relationships

We are the general partner of 15 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 2010 and 2009, the total we received for all of these fees was $1.8 million and $1.1 million, respectively. Our proportionate share of assets, liabilities and net income relating to the oil and natural gas partnerships is included in our condensed consolidated financial statements.

New Accounting Pronouncements

Results of Operations

Quarter Ended September 30, 2010 versus Quarter Ended September 30, 2009

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


	Quarter Ended September 30,						Percent Change
	2010			2009			Percent Change
Total revenue	$	218,116,000		$	167,430,000			30	%
Net income	$	34,491,000		$	31,449,000			10	%
Contract Drilling:
Revenue	$	85,004,000		$	49,801,000			71	%
Operating costs excluding depreciation	$	45,406,000		$	29,456,000			54	%
Percentage of revenue from daywork contracts		100	%		100	%		0	%
Average number of drilling rigs in use		65.4			34.6			89	%
Average dayrate on daywork contracts	$	15,814		$	15,360			3	%
Depreciation	$	18,469,000		$	10,923,000			69	%
Oil and Natural Gas:
Revenue	$	96,562,000		$	88,894,000			9	%
Operating costs excluding depreciation, depletion, amortization and impairment	$	27,092,000		$	20,781,000			30	%
Average oil price (Bbl)	$	66.94		$	59.55			12	%
Average NGL price (Bbl)	$	31.67		$	22.99			38	%
Average natural gas price (Mcf)	$	5.55		$	5.67			(2	)%
Oil production (Bbl)		379,000			300,000			26	%
NGL production (Bbl)		378,000			358,000			6	%
Natural gas production (Mcf)		10,385,000			10,713,000			(3	)%
Depreciation, depletion and amortization rate (Mcfe)	$	2.00		$	1.73			16	%
Depreciation, depletion and amortization	$	30,091,000		$	25,645,000			6	%
Mid-Stream Operations:
Revenue	$	37,429,000		$	26,228,000			43	%
Operating costs excluding depreciation and amortization	$	30,743,000		$	20,012,000			54	%
Depreciation and amortization	$	3,823,000		$	3,995,000			(4	)%
Gas gathered—MMBtu/day		183,161			179,047			2	%
Gas processed—MMBtu/day		84,175			77,923			8	%
Gas liquids sold—gallons/day		260,519			251,830			3	%

General and administrative expense	$	6,637,000		$	5,506,000			21	%
Interest expense, net	$	0		$	1,000			NM
Income tax expense	$	21,364,000		$	19,662,000			9	%
Average interest rate		3.1	%		3.9	%		(21	)%
Average long-term debt outstanding	$	133,559,000		$	82,920,000			61	%

(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 $35.2 million or 71% in the third quarter of 2010 versus the third quarter of 2009 primarily due to an 89% increase in the average number of rigs in use during the third quarter of 2010 compared to the third quarter of 2009 and increased mobilization revenue between periods partially offset by reduced standby revenue and other revenue reimbursements for operating expenses. Average drilling rig utilization increased from 34.6 drilling rigs in the third quarter of 2009 to 65.4 drilling rigs in the third quarter of 2010.

Drilling operating costs increased $16.0 million or 54% between the comparative third quarters of 2010 and 2009 primarily due to increases in the number of drilling rigs used and to a lesser extent increases in per day direct cost. Total per day operating cost decreased 19% as indirect fixed costs were spread over more operating days due to higher utilization. During 2009, competition to keep and attract qualified employees to meet our requirements did not materially affect us due to the depressed conditions within our industry. Due to increased utilization over last year’s levels, competition to keep qualified labor has increased in 2010 so starting in the third quarter 2010; we increased compensation for drilling personnel in Oklahoma, Texas and Louisiana. Further increases in utilization beyond third quarter 2010 levels could also be hampered by limited availability of personnel. Contract drilling depreciation increased $7.5 million or 69% primarily due to an increase in the number of drilling rigs being utilized and an increase in capital expenditures for upgrades to existing drilling rigs in our fleet.

Oil and Natural Gas

Oil and natural gas revenues increased $7.7 million or 9% in the third quarter of 2010 as compared to the third quarter of 2009 primarily due to an increase in average oil and NGL prices and a slight increase in equivalent production volumes of 2%. Average oil prices between the comparative quarters increased 12% to $66.94 per barrel, NGL prices increased 38% to $31.67 per barrel and natural gas prices decreased 2% to $5.55 per Mcf. In the third quarter of 2010, as compared to the third quarter of 2009, oil production increased 26%, NGL production increased 6% and natural gas production decreased 3%. Production for the third quarter 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. The oil production increases are partially associated with the $73.7 million acquisition we completed during second quarter while NGL volumes came from the increase in our drilling activity.

Oil and natural gas operating costs increased $6.3 million or 30% between the comparative third quarters of 2010 and 2009 primarily due to the increase in LOE and increased gross production taxes. Production taxes increased due to commodity price increases between the periods. LOE per Mcfe increased 18% to $1.18 primarily due to more oil and NGL wells added which typically have higher LOE expense over adding natural gas wells.

Depreciation, depletion and amortization (“DD&A”) increased $4.4 million or 17% primarily due to a 16% increase in our DD&A rate. The increase in our DD&A rate in the third quarter of 2010 compared to the third quarter of 2009 resulted primarily from the average cost per Mcfe on reserves added in the quarter exceeding the previous average net book value per Mcfe for reserves previously discovered and acquired. Our DD&A expense on our oil and natural gas properties is calculated each quarter utilizing period end reserve quantities.

Mid-Stream

Our mid-stream revenues were $11.2 million or 43% higher for the third quarter of 2010 as compared to the third quarter of 2009 primarily due to higher NGL and natural gas prices and higher NGL volumes processed and sold. The average price for NGLs sold increased 28% and the average price for natural gas sold increased 38%. Gas processing volumes per day increased 8% between the comparative quarters and NGLs sold per day increased 3% 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 throughout 2009. NGLs sold volumes per day increased due to both an increase in volumes processed and upgrades to several of our processing facilities. Gas gathering volumes per day increased 2% primarily from increased well connects throughout 2010.

Operating costs increased $10.7 million or 54% in the third quarter of 2010 compared to the third quarter of 2009 primarily due to a 44% increase in prices paid for natural gas purchased and an 8% increase in purchase volumes. Depreciation and amortization decreased $0.2 million, or 4%, primarily due to decreased amortization on our intangible assets. For 2010, we anticipate an increase in well connections over 2009 due to anticipated drilling activity by operators in the areas of our existing gathering systems as well as adding an additional processing facility to accommodate the increased drilling activity of our oil and natural gas segment and other third parties.

Other

We recorded an $0.8 million loss on the sale of miscellaneous rig components in the third quarter of 2010.

Interest expense, net of capitalized interest, remained unchanged between the comparative quarters. We capitalized interest based on the net book value associated with our undeveloped oil and natural gas properties, the construction of additional drilling rigs and the construction of gas gathering systems. Our average interest rate was 21% lower and our average debt outstanding was 61% higher in the third quarter of 2010 as compared to the third quarter of 2009. Total interest incurred increased $0.3 million for both the third quarter of 2010 and the third quarter of 2009 due to interest rate swap settlements.

Income tax expense increased by $1.7 million, or 9% in the third quarter of 2010 compared to the third quarter of 2009 due to an increase in pre-tax income. Our effective tax rate was 38.3% and 38.5% for the third quarters of 2010 and 2009, respectively. The portion of our taxes reflected as a current income tax benefit for the third quarter of 2010 was $8.6 million as compared with an expense of $8.6 million or 44% of total income tax expense in the third quarter of 2009. The amount classified to current in 2010 is lower than 2009 primarily due to lower than expected alternative minimum tax for 2009 and to a lesser extent additional depreciation allowed on new capital expenditures in 2010. There were no income taxes paid in the third quarter of 2010.

Nine Months Ended September 30, 2010 versus Nine Months Ended September 30, 2009

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


	Nine Months Ended September 30,						Percent Change
	2010			2009			Percent Change
Total revenue	$	629,269,000		$	532,566,000			18	%
Net income (loss)	$	102,819,000		$	(84,013,000	)		NM	%
Contract Drilling:
Revenue	$	217,919,000		$	188,383,000			16	%
Operating costs excluding depreciation	$	132,847,000		$	109,565,000			21	%
Percentage of revenue from daywork contracts		99	%		100	%		(1	)%
Average number of drilling rigs in use		58.2			39.6			47	%
Average dayrate on daywork contracts	$	15,037		$	17,335			(13	)%
Depreciation	$	48,700,000		$	33,803,000			44	%
Oil and Natural Gas:
Revenue	$	286,751,000		$	267,399,000			7	%
Operating costs excluding depreciation, depletion, amortization and impairment	$	75,943,000		$	62,846,000			21	%
Average oil price (Bbl)	$	67.05		$	54.77			22	%
Average NGL price (Bbl)	$	35.91		$	21.80			65	%
Average natural gas price (Mcf)	$	5.71		$	5.53			3	%
Oil production (Bbl)		1,002,000			991,000			1	%
NGL production (Bbl)		1,143,000			1,142,000			0	%
Natural gas production (Mcf)		30,121,000			33,575,000			(10	)%
Depreciation, depletion and amortization rate (Mcfe)	$	1.89		$	1.92			(2	)%
Depreciation, depletion and amortization	$	81,746,000		$	89,800,000			(9	)%
Impairment of oil and natural gas properties	$	0		$	281,241,000			NM
Mid-Stream Operations:
Revenue	$	114,908,000		$	71,604,000			60	%
Operating costs excluding depreciation and amortization	$	92,407,000		$	59,888,000			54	%
Depreciation and amortization	$	11,746,000		$	12,166,000			(3	)%
Gas gathered—MMBtu/day		182,390			186,296			(2	)%
Gas processed—MMBtu/day		81,157			75,371			8	%
Gas liquids sold—gallons/day		264,679			236,692			12	%

General and administrative expense	$	19,372,000		$	17,088,000			13	%
Interest expense, net	$	0		$	539,000			NM
Income tax expense (benefit)	$	63,689,000		$	(50,357,000	)		NM
Average interest rate		3.8	%		3.8	%		0	%
Average long-term debt outstanding	$	78,988,000		$	139,377,000			(43	)%

(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 $29.5 million or 16% in the first nine months of 2010 versus the first nine months of 2009 primarily due to a 47% increase in the average number of rigs in use during the first nine months of 2010 compared to the first nine months of 2009 and increased mobilization revenue offset by a 13% lower average dayrate. Average drilling rig utilization increased from 39.6 drilling rigs in the first nine months of 2009 to 58.2 drilling rigs in the first nine months of 2010. Commodity prices have improved in the first nine months of 2010 compared to the first nine months of 2009.

Drilling operating costs increased $23.3 million or 21% between the comparative first nine months of 2010 and 2009 primarily due to increases in the number of drilling rigs used and increases in general and administrative expenses offset by decreases in worker’s compensation. During 2009, competition to keep and attract qualified employees to meet our requirements did not materially affect us due to the depressed conditions within our industry. Due to increased utilization over last year’s levels, competition to keep qualified labor has increased in 2010 so starting in the third quarter 2010; we increased compensation for drilling personnel in Oklahoma, Texas and Louisiana. Further increases in utilization beyond third quarter 2010 levels could also be hampered by limited availability of personnel. Contract drilling depreciation increased $14.9 million or 44% primarily due to an increase in the number of drilling rigs being utilized and an increase in capital expenditures for upgrades to existing drilling rigs in our fleet.

Oil and Natural Gas

Oil and natural gas revenues increased $19.4 million or 7% in the first nine months of 2010 as compared to the first nine months of 2009 primarily due to an increase in average oil, NGL and natural gas prices partially offset by a 7% decrease in equivalent production volumes. Average oil prices between the comparative quarters increased 22% to $67.05 per barrel, NGL prices increased 65% to $35.91 per barrel and natural gas prices increased 3% to $5.71 per Mcf. In the first nine months of 2010, as compared to the first nine months of 2009, oil production increased 1%, NGL production remained unchanged and natural gas production decreased 10%. Production for the third quarter 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.

Oil and natural gas operating costs increased $13.1 million or 21% between the comparative first nine months of 2010 and 2009 as reductions in lease operating expenses were offset by increased gross production taxes due to higher commodity prices between nine month periods. Production taxes in 2009 were also reduced by $5.8 million for production tax credits attributable to high-cost gas wells.

DD&A decreased $8.1 million or 9% primarily due to a 2% decrease in our DD&A rate and a 7% decrease in equivalent production. The decrease in our DD&A rate in the first nine months of 2010 compared to the first nine months of 2009 resulted primarily from the $281.2 million pre-tax non-cash ceiling test write-down of the carrying value of our oil and natural gas properties at the end of the first quarter in 2009 as a result of a decline in commodity prices partially offset by DD&A rate increases incurred in 2010 for 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.

Mid-Stream

Our mid-stream revenues were $43.3 million or 60% higher for the first nine months of 2010 as compared to the first nine months of 2009 primarily due to higher NGL and natural gas prices and higher NGL volumes processed and sold. The average price for NGLs sold increased 46% and the average price for natural gas sold increased 47%. Gas processing volumes per day increased 8% between the comparative periods and NGLs sold per day increased 12% 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 throughout 2010. NGLs sold volumes per day increased due to both an increase in volumes processed and upgrades to several of our processing facilities. Gas gathering volumes per day decreased 2% primarily from well production declines associated with the wells gathered from two of our gathering systems located in Southeast Texas.

Operating costs increased $32.5 million or 54% in the first nine months of 2010 compared to the first nine months of 2009 primarily due to a 56% increase in prices paid for natural gas purchased and a 8% increase in purchased volumes. Depreciation and amortization decreased $0.4 million, or 3%, primarily due to decreased amortization on our intangible assets. For 2010, we anticipate an increase in well connections over 2009 due to anticipated drilling activity by operators in the areas of our existing gathering systems as well as adding an additional processing facility to accommodate the increased drilling activity of our oil and natural gas segment and other third parties.

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, partially offset by an $0.8 million loss on the sale of miscellaneous rig components.

Interest expense, net of capitalized interest, decreased $0.5 million between the comparative quarters. We capitalized interest based on the net book value associated with our undeveloped oil and natural gas properties, the construction of additional drilling rigs and the construction of gas gathering systems. Our average interest rate remained unchanged at 3.8% and our average debt outstanding was 43% lower in the first nine months of 2010 as compared to the first nine months of 2009. Total interest incurred increased $0.9 million for the first nine months of 2010 and $0.7 million for the first nine months of 2009 due to interest rate swap settlements.

Income tax expense (benefit) changed from a benefit of $50.4 million in the first nine months of 2009 to an expense of $63.7 million in the first nine months of 2010 due to the non-cash ceiling test write-down of $281.2 million pre-tax ($175.1 million, net of tax) of our oil and natural gas properties during the quarter ended March 31, 2009. Our effective tax rate was 38.3% and 37.5% for the first nine months of 2010 and 2009, respectively. The portion of our taxes reflected as a current income tax benefit for the first nine months of 2010 was $2.5 million as compared to an expense of $9.8 million in the first nine months of 2009. Income taxes paid in the first nine months of 2010 were $3.1 million.

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 amount of wells to be drilled or reworked;

•

prices for oil and natural gas;

•

demand for oil and natural gas;

•

our exploration prospects;

•

estimates of our proved oil and natural gas reserves;

•

oil and natural gas reserve potential;

•

development and infill drilling potential;

•

our drilling prospects;

•

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

•

our business strategy;

•

production of oil and natural gas reserves;

•

growth potential for our mid-stream operations;

•

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; and

•

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.

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 nature or lack of business opportunities that we pursue;

•

demand for our land drilling services;

•

changes in laws or regulations;

•

the time period associated with the current decrease 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 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 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 2010 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 $316,000 per month ($3.8 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 $105,000 per month ($1.3 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 $121,000 per month ($1.5 million annualized) change in our pre-tax operating cash flow.

We use hedging transactions to reduce price volatility and manage price risks. 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, and collars that set a floor and ceiling price for the hedged production. If the applicable monthly price indices are outside of the ranges set by the floor and ceiling prices in the various collars, we will settle the difference with the counterparty to the collars. Currently, we also have one basis swap that does not qualify as cash flow hedge. 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.

Oil and Natural Gas Segment:

At September 30, 2010, the following cash flow hedges were outstanding:


Term	Commodity	Hedged Volume	Weighted Average Fixed Price for Swaps	Hedged Market
Oct’10 – Dec’10	Crude oil - collar	1,000 Bbl/day	$67.50 put & $81.53 call	WTI – NYMEX
Oct’10 – Dec’10	Crude oil – swap	1,500 Bbl/day	$61.36	WTI – NYMEX
Jan’11 – Dec’11	Crude oil – swap	2,500 Bbl/day	$80.32	WTI – NYMEX
Jan’12 – Dec’12	Crude oil – swap	1,500 Bbl/day	$82.49	WTI – NYMEX

Oct’10 – Dec’10	Natural gas – swap	15,000 MMBtu/day	$7.20	IF – NYMEX (HH)
Oct’10 – Dec’10	Natural gas – swap	20,000 MMBtu/day	$6.89	IF – Tenn Zone 0
Oct’10 – Dec’10	Natural gas – swap	30,000 MMBtu/day	$6.12	IF – CEGT
Oct’10 – Dec’10	Natural gas – swap	20,000 MMBtu/day	$5.67	IF – PEPL
Oct’10 – Dec’10	Natural gas – basis differential swap	10,000 MMBtu/day	($0.79)	PEPL – NYMEX
Jan’11 – Dec’11	Natural gas – swap	15,000 MMBtu/day	$5.56	IF – NYMEX (HH)
Jan’11 – Dec’11	Natural gas – basis differential swap	15,000 MMBtu/day	($0.14)	Tenn Zone 0 – NYMEX
Jan’12 – Dec’12	Natural gas – swap	15,000 MMBtu/day	$5.62	IF – PEPL

Oct’10 – Dec’11	Liquids – swap (1)	644,406 Gal/mo	$0.98	OPIS – Conway

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

At September 30, 2010, the following non-qualifying cash flow derivatives were outstanding:


Term	Commodity	Hedged Volume	Basis Differential	Hedged Market
Jan’11 – Dec’11	Natural gas – basis differential swap	15,000 MMBtu/day	($0.14)	Tenn Zone 0 – NYMEX
Jan’11 – Dec’11	Natural gas – basis differential swap	10,000 MMBtu/day	($0.21)	CEGT – NYMEX
Jan’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, all of which bears interest at variable rates based on the BOKF National Prime Rate or the LIBOR Rate. At our election, borrowings under our revolving Credit Facility may be fixed at the LIBOR Rate for periods of up to 180 days. To help manage our exposure to any future interest rate volatility, we currently have two $15.0 million interest rate swaps, one at a fixed rate of 4.53% and one at a fixed rate of 4.16%, both expiring in May 2012. Based on our average outstanding long-term debt subject to the floating rate in the first nine months of 2010, a 1% increase in the floating rate would reduce our annual pre-tax cash flow by $0.5 million.

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, 2010 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 quarter ended September 30, 2010 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.

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, 2009. 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 and in Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2009, 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.

Except as set forth below, 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, 2009.

New legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

The U.S. Environmental Protection Agency, or the EPA, has commenced a study of the potential environmental impacts of hydraulic fracturing, including the impact on drinking water sources and public health, and a committee of the U.S. House of Representatives is also conducting an investigation of hydraulic fracturing practices. Legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. In addition, some states have and others are considering adopting regulations that could restrict hydraulic fracturing in certain circumstances. Any new laws, regulation or permitting requirements regarding hydraulic fracturing could lead to operational delay, or increased operating costs or third party or governmental claims, and could result in additional burdens that could serve to delay or limit the drilling services we provide to third parties whose drilling operations could be impacted by these regulations or increase our costs of compliance and doing business as well as delay the development of unconventional gas resources from shale formations which are not commercial without the use of hydraulic fracturing. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce from our reserves.

Derivatives regulation included in current financial reform legislation could impede our ability to manage business and financial risks by restricting our use of derivative instruments as hedges against fluctuating commodity prices and interest rates.

In July 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act (the Act) was passed by Congress and signed into law. The Act contains significant derivatives regulation, including a requirement that certain transactions be cleared on exchanges and a requirement to post cash collateral (commonly referred to as “margin”) for such transactions. The Act provides for a potential exception from these clearing and cash collateral requirements for commercial end-users and it includes a number of defined terms that will be used in determining how this exception applies to particular derivative transactions and the parties to those transactions. The Act requires the Commodities Futures and Trading Commission (the CFTC) to promulgate rules to define these terms, but we do not know the definitions that the CFTC will actually promulgate nor how these definitions will apply to us.

We use crude oil and natural gas derivative instruments with respect to a portion of our expected production in order to reduce commodity price uncertainty and enhance the predictability of cash flows relating to the marketing of our crude oil and natural gas. We also use interest rate derivative instruments to minimize the impact of interest rate fluctuations associated with anticipated debt issuances. As commodity prices increase or interest rates decrease, our derivative liability positions increase; however, none of our current derivative contracts require the posting of margin or similar cash collateral when there are changes in the underlying commodity prices or interest rates that are referred to in these contracts.

Depending on the rules and definitions adopted by the CFTC, we could be required to post collateral with our dealer counterparties for our commodities and interest rate derivative transactions. Such a requirement could have a significant impact on our business by reducing our ability to execute derivative transactions to reduce commodity price and interest rate uncertainty and to protect cash flows. Requirements to post collateral would cause significant liquidity issues by reducing our ability to use cash for investment or other corporate purposes, or would require us to increase our level of debt. In addition, a requirement for our counterparties to post collateral would likely result in additional costs being passed on to us, thereby decreasing the effectiveness of our hedges and our profitability.

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, 2010:


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, 2010 to July 31, 2010		2,369	$	41.20		2,369		—
August 1, 2010 to August 31, 2010		125,760		35.14		125,760		—
September 1, 2010 to September 30, 2010		318		35.51		318		—

Total		128,447	$	35.25		128,447		—

(1)	The shares were repurchased to remit withholding of taxes on the value of stock distributed with the third quarter 2010 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.

Item 6. Exhibits

Exhibits:



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.

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 4, 2010		By: /s/ Larry D. Pinkston
		LARRY D. PINKSTON
		Chief Executive Officer and Director

Date: November 4, 2010		By: /s/ David T. Merrill
		DAVID T. MERRILL
		Chief Financial Officer and Treasurer

UNIT CORP - FORM 10-Q - November 4, 2010

Attached files

UNIT CORP Reports