Bronco Drilling 10-Q 2009 Q2 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2009

OR

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period fromto

Commission File Number 000-51471

BRONCO DRILLING COMPANY, INC.

(Exact name of registrant as specified in its charter)

Delaware	20-2902156
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

16217 North May Avenue

Edmond, OK 73013

(Address of principal executive offices) (Zip Code)

(405) 242-4444

(Registrant’s telephone number, including area code)

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 during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).   Yes ¨     No  ¨

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

Large Accelerated Filer   ¨  Accelerated Filer  x     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 April 30, 2009, 27,217,459 shares of common stock were outstanding.

 BRONCO DRILLING COMPANY, INC.

INDEX

		Page
PART I—FINANCIAL INFORMATION
Item 1.	Financial Statements	3
Bronco Drilling Company, Inc.:
	Consolidated Balance Sheets as of March 31, 2009 (unaudited) and December 31, 2008	3
	Consolidated Statements of Operations for the three months ended March 31, 2009 and 2008 (unaudited)	4
	Consolidated Statement of Stockholders’ Equity for the three months ended March 31,  2009 (unaudited)	5
	Consolidated Statements of Cash Flows for the three months ended March 31, 2009 and 2008 (unaudited)	6
	Notes to Consolidated Financial Statements (unaudited)	7
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	11
Item 3.	Quantitative and Qualitative Disclosures about Market Risks	16
Item 4.	Controls and Procedures	16
PART II—OTHER INFORMATION
Item 1.	Legal Proceedings	17
Item 1A.	Risk Factors	17
Item 2.	Unregistered Sale of Equity Securities and Use of Proceeds	17
Item 3.	Defaults Upon Senior Securities	17
Item 4.	Submission of Matters to Vote of Security Holders	17
Item 5.	Other Information	17
Item 6.	Exhibits	18
Signatures		19

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Bronco Drilling Company, Inc. and Subsidiaries
CONSOLIDATED BALANCE SHEETS
(Amounts in thousands, except share par value)
	March 31,		December 31,
	2009		2008
	(Unaudited)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	39,228	$	26,676
Receivables
Trade and other, net of allowance for doubtful accounts of
$4,110 and $3,830 in 2009 and 2008, respectively		39,583		65,817
Unbilled receivables		1,845		2,940
Income tax receivable		2,046		2,072
Current deferred income taxes		2,592		2,844
Current maturities of note receivable from affiliate		7,785		6,900
Prepaid expenses		1,418		572
Total current assets		94,497		107,821
PROPERTY AND EQUIPMENT - AT COST
Drilling rigs and related equipment		516,421		512,158
Transportation, office and other equipment		43,449		43,912
		559,870		556,070
Less accumulated depreciation		135,778		123,915
		424,092		432,155
OTHER ASSETS
Note receivable from affiliate, less current maturities		2,615		3,451
Investment in Challenger		63,287		62,875
Intangibles, net, and other		5,182		6,052
		71,084		72,378
	$	589,673	$	612,354
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable	$	5,958	$	18,473
Accrued liabilities		12,355		16,249
Current maturities of long-term debt		85		1,464
Total current liabilities		18,398		36,186
LONG-TERM DEBT,  less current maturities		112,437		116,083
DEFERRED INCOME TAXES		65,785		66,074
COMMITMENTS AND CONTINGENCIES (Note 6)
STOCKHOLDERS' EQUITY
Common stock, $.01 par value, 100,000
shares authorized; 26,657 and 26,346 shares
issued and outstanding at March 31, 2009 and December 31, 2008		267		267
Additional paid-in capital		304,766		304,015
Retained earnings		88,020		89,729
Total stockholders' equity		393,053		394,011
	$	589,673	$	612,354
The accompanying notes are an integral part of these statements.

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Bronco Drilling Company, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF OPERATIONS
(Amounts in thousands, except per share amounts)
	Three Months Ended March 31,
	2009			2008
	(Unaudited)
REVENUES
Contract drilling revenues	$	47,826		$	54,073
Well service		2,779			8,223
Gain on Challenger transactions		-			4,707
		50,605			67,003
EXPENSES
Contract drilling		29,844			33,190
Well service		2,315			4,943
Depreciation and amortization		12,526			11,925
General and administrative		5,188			5,739
		49,873			55,797
Income from operations		732			11,206
OTHER INCOME (EXPENSE)
Interest expense		(2,299	)		(1,226	)
Interest income		1			734
Equity in income of Challenger		412			1,845
Other		(566	)		141
		(2,452	)		1,494
Income (loss) before income taxes		(1,720	)		12,700
Income tax expense (benefit)		(11	)		4,552
NET INCOME (LOSS)	$	(1,709	)	$	8,148
Income (loss) per common share-Basic	$	(0.06	)	$	0.31
Income (loss) per common share-Diluted	$	(0.06	)	$	0.31
Weighted average number of shares outstanding-Basic		26,589			26,265
Weighted average number of shares outstanding-Diluted		26,589			26,287
The accompanying notes are an integral part of these statements.

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Bronco Drilling Company Inc. and Subsidiaries
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
(Amounts in thousands)
For the three months ended March 31, 2009
(Unaudited)
					Additional					Total
	Common		Common		Paid In		Retained			Stockholders'
	Shares		Amount		Capital		Earnings			Equity
Balance as of January 1, 2009		26,346	$	267	$	304,015	$	89,729		$	394,011
Net loss		-		-		-		(1,709	)		(1,709	)
Stock compensation		311		-		751		-			751
Balance as of March 31, 2009		26,657	$	267	$	304,766	$	88,020		$	393,053
The accompanying notes are an integral part of these statements.

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Bronco Drilling Company, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Amounts in thousands)
	Three Months Ended March 31,
	2009			2008
	(Unaudited)
Cash flows from operating activities:
Net income (loss)	$	(1,709	)	$	8,148
Adjustments to reconcile net income (loss) to net cash
provided by operating activities:
Depreciation and amortization		12,731			12,071
Bad debt expense		635			343
Loss (gain) on sale of assets		(166	)		293
Gain on Challenger transactions		-			(4,707	)
Equity in income of Challenger		(412	)		(1,845	)
Stock compensation		751			1,150
Provision for deferred income taxes		(37	)		4,553
Changes in current assets and liabilities:
Receivables		25,550			6,340
Unbilled receivables		1,095			(511	)
Prepaid expenses		(846	)		(835	)
Other assets		442			(152	)
Accounts payable		(13,948	)		(7,863	)
Accrued expenses		(3,894	)		(2,065	)
Income taxes receivable		26			-
Net cash provided by operating activities		20,218			14,920
Cash flows from investing activities:
Restricted cash account		-			57
Business acquisitions, net of cash acquired		-			(5,063	)
Proceeds from sale of assets		489			2,634
Purchase of property and equipment		(3,130	)		(18,528	)
Net cash used in investing activities		(2,641	)		(20,900	)
Cash flows from financing activities:
Proceeds from borrowings		-			5,000
Payments of debt		(5,025	)		(1,707	)
Net cash provided by (used in) financing activities		(5,025	)		3,293
Net increase (decrease) in cash and cash equivalents		12,552			(2,687	)
Beginning cash and cash equivalents		26,676			5,721
Ending cash and cash equivalents	$	39,228		$	3,034
Supplementary disclosure of cash flow information:
Interest paid, net of amount capitalized	$	2,256		$	1,393
Supplementary disclosure of non-cash investing and financing:
Assets exchanged/sold for equity interest and note receivable		-			70,381
Purchase of property and equipment in accounts payable		1,433			-
The accompanying notes are an integral part of these statements.

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Bronco Drilling Company, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

($ Amounts in thousands, except per share amounts)

Unless the context requires otherwise, a reference in this quarterly report to “Bronco,” the “Company,” “we,” “us,” and “our” are to Bronco Drilling Company, Inc., a Delaware corporation, and its consolidated subsidiaries.

1. Organization and Summary of Significant Accounting Policies

Business and Principles of Consolidation

 Bronco Drilling Company, Inc. (the “Company”) provides contract land drilling and workover services to oil and natural gas exploration and production companies. The accompanying consolidated financial statements include the Company’s accounts and the accounts of its wholly owned subsidiaries. All intercompany accounts and transactions have been eliminated in consolidation.

 The Company has prepared the accompanying unaudited consolidated financial statements and related notes in accordance with accounting principles generally accepted in the United States of America for interim financial information and with the instructions of Form 10-Q and Regulation S-X. In preparing the financial statements, the Company made various estimates and assumptions that affect the amounts of assets and liabilities the Company reports as of the dates of the balance sheets and amounts the Company reports for the periods shown in the consolidated statements of operations, stockholders’ equity and cash flows. The Company’s actual results could differ significantly from those estimates. Material estimates that are particularly susceptible to significant changes in the near term relate to the Company’s recognition of revenues and accrued expenses, estimate of the allowance for doubtful accounts, estimate of asset impairments, estimate of deferred taxes and determination of depreciation and amortization expense.

 In management’s opinion, the accompanying unaudited consolidated financial statements contain all adjustments (consisting of normal recurring accruals) necessary to present fairly the financial position of the Company as of March 31, 2009, the related results of operations for the three months ended March 31, 2009 and 2008 and the cash flows for the three months ended March 31, 2009 and 2008.  The information included in this Quarterly Report on Form 10-Q should be read in conjunction with the Company’s Annual Report on Form 10-K for the year ended December 31, 2008.

 The results of operations for the three months ended March 31, 2009 are not necessarily an indication of the results expected for the full year.

 A summary of the significant accounting policies consistently applied in the preparation of the accompanying consolidated financial statements follows.

Cash and Cash Equivalents

 The Company considers all highly liquid debt instruments purchased with a maturity of three months or less and money market mutual funds to be cash equivalents.

 The Company maintains its cash and cash equivalents in accounts and instruments which may not be federally insured beyond certain limits. The Company has not experienced any losses in such accounts and believes it is not exposed to any significant credit risks on cash and cash equivalents.

Property and Equipment

 Property and equipment, including renewals and betterments, are capitalized and stated at cost, while maintenance and repairs are expensed currently. Assets are depreciated on a straight-line basis. The depreciable lives of drilling and workover rigs and related equipment are three to 15 years. The depreciable life of other equipment is three years. Depreciation is not commenced until acquired rigs are placed in service. Once placed in service, depreciation continues when rigs are being repaired, refurbished or between periods of deployment. Assets not placed in service and not being depreciated were $34,784 and $34,293 as of March 31, 2009 and December 31, 2008, respectively.  Due to immateriality, gains and losses on dispositions, with the exception of the Challenger Limited transactions, are included in contract drilling and well service revenues.

 The Company capitalizes interest as a component of the cost of drilling and workover rigs constructed for its own use. For the three months ended March 31, 2009 and 2008, the Company capitalized $0 and $382, respectively, of interest costs incurred during the construction periods of certain drilling and workover rigs.

 The Company reviews long-lived assets to be held and used for impairment whenever events or changes in circumstances indicate that the carrying amount of the assets may not be recoverable. If the sum of the undiscounted expected future cash flows is less than the carrying amount of the assets, the Company recognizes an impairment loss based upon fair value of the asset.

Income Taxes

 Pursuant to Statement of Financial Accounting Standards (“SFAS”) No. 109, “Accounting for Income Taxes,” the Company follows the asset and liability method of accounting for income taxes, under which the Company recognizes deferred tax assets and liabilities for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases.  Deferred tax assets and liabilities were measured using enacted tax rates expected to apply to taxable income in the years in which the Company expects to recover or settle those temporary differences.  A statutory Federal tax rate of 35% and effective state tax rate of 3.7% (net of Federal income tax effects) were used for the enacted tax rates for all periods.  The Company’s effective income tax rate during the three months ended March 31, 2009 is higher than what would be expected if the federal statutory rate were applied to income before income taxes primarily because of certain stock compensation expenses recorded for financial reporting purposes that are not deductible for tax purposes.

 As changes in tax laws or rates are enacted, deferred income tax assets and liabilities are adjusted through the provision for income taxes.  Deferred tax assets are reduced by a valuation allowance if, based on available evidence, it is more likely than not that some portion or all of the deferred tax assets will not be realized.  The classification of current and noncurrent deferred tax assets and liabilities is based primarily on the classification of the assets and liabilities generating the difference.

 The Company applies the provisions of FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes — an interpretation of FASB Statement No. 109 (“FIN 48”), which addresses the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements and prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The Company recognizes interest and/or penalties related to income tax matters as income tax expense. As of March 31, 2009, the tax years ended December 31, 2005 through December 31, 2007 are open for examination by U.S. taxing authorities.

Net Income (Loss) Per Common Share

 The Company computes and presents net income (loss) per common share in accordance with SFAS No. 128, “Earnings per Share.” This standard requires dual presentation of basic and diluted net income (loss) per share on the face of the Company’s statement of operations. Basic net income (loss) per common share is computed by dividing net income or loss attributable to common stock by the weighted average number of common shares outstanding for the period. Diluted net income (loss) per common share reflects the potential dilution that could occur if options or other contracts to issue common stock were exercised or converted into common stock.

Stock-based Compensation

 The Company accounts for stock-based compensation in accordance with SFAS No. 123(R), “Share-Based Payment”. SFAS No. 123(R) requires a public entity to measure the costs of employee services received in exchange for an award of equity or liability instruments based on the grant-date fair value of the award. That cost will be recognized over the periods during which an employee is required to provide service in exchange for the award.

Recent Accounting Pronouncements

 In September 2006, the FASB issued SFAS No. 157 (“SFAS 157”), “Fair Value Measurements.”  This Statement defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles (“GAAP”), and expands disclosures about fair value measurements. This Statement applies under other accounting pronouncements that require or permit fair value measurements, the FASB having previously concluded in those accounting pronouncements that fair value is the relevant measurement attribute. Accordingly, this Statement does not require any new fair value measurements. This Statement is effective for fiscal years beginning after November 15, 2007; however, on February 12, 2008, the FASB issued FSP FAS No. 157-2, Effective Dates of FASB Statement No. 157, which delays the effective date of SFAS 157 to fiscal years beginning after November 15, 2008 for all nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis.  The adoption of the provisions of SFAS 157 did not have a material impact on the Company’s financial statements.

-7-

 In December 2007, the FASB issued SFAS No. 141 (revised 2007) “Business Combinations” (“SFAS 141R”). SFAS 141R establishes principles and requirements for how the acquirer of a business recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree. SFAS 141R also provides guidance for recognizing and measuring the goodwill acquired in the business combination and determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. SFAS No. 141R applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. The adoption of the provisions of SFAS 141R did not have an immediate impact on the Company’s consolidated financial statements.

 In December 2007, the FASB issued SFAS No. 160 (“SFAS 160”), “Noncontrolling Interests in Consolidated Financial Statements — an amendment of ARB No. 51.” SFAS 160 establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. SFAS 160 requires retroactive adoption of the presentation and disclosure requirements for existing minority interests. All other requirements of SFAS 160 shall be applied prospectively. SFAS 160 is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008.  The adoption of the provisions of SFAS 160 did not have a material impact on the Company’s consolidated financial statements.

 In March 2008, the FASB issued SFAS No. 161 (“SFAS 161”), “Disclosures about Derivative Instruments and Hedging Activities – an amendment of FASB Statement No. 133.”  SFAS 161 requires enhanced disclosures for derivative instruments and hedging activities that include how and why an entity uses derivatives, how instruments and the related hedged items are accounted for under FAS 133 and related interpretations, and how derivative instruments and related hedged items affect the entity’s financial position, results of operations and cash flows.  SFAS 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. The adoption of the provisions of SFAS 161 did not have a material impact on the Company’s financial statements.

 In June 2008, the FASB issued FSP No. EITF 03-6-1, Determining Whether Instruments Granted in Share-Based Payment Transactions are Participating Securities.  This FSP provides that unvested share-based payment awards that contain nonforfeitable rights to dividends are participating securities and shall be included in the computation of earnings per share pursuant to the two class method.  This FSP is effective for financial statements issued for fiscal years beginning after December 15, 2008 and interim periods within those years.  The adoption of this FSP did not have a material impact on our financial position or results of operation.

 In September 2008, the FASB issued EITF 08-6, Equity Method Investment Accounting Considerations.  The purpose of this issue is to resolve several accounting issues that arise in applying the equity method of accounting. Most of these issues arise or become more prevalent upon the effective date of FASB Statement No. 141 (Revised 2007), Business Combinations, and (or) FASB Statement No. 160, Noncontrolling Interests in Consolidated Financial Statements. This is because the literature that is being replaced or amended by Statements 141R and 160 has been used by analogy in addressing certain aspects of applying the equity method of accounting.  The EITF concluded that the effective date for this issue should coincide with the effective date of Statements 141R and 160 and that it should be applied prospectively. As such, the guidance in this issue applies to transactions that occur in fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008.  The adoption of the provisions EITF 08-6 did not have a material impact on the Company’s financial condition or results of operations.

2. Investment in Challenger

 On January 4, 2008, we acquired a 25% equity interest in Challenger Limited (“Challenger”), in exchange for six drilling rigs valued at $72,937 and $5,063 in cash.  The Company’s 25% interest at March 31, 2009 was based on 64,957,265 shares outstanding.  The Company recorded equity in income of investment of $412 and $1,845 for the three months ended March 31, 2009 and 2008, respectively, related to its equity investment in Challenger.  Challenger is an international provider of contract land drilling and workover services to oil and natural gas companies with its principal operations in Libya.  Five of the contributed drilling rigs were from our existing marketed fleet and one was a newly constructed rig.  The general specifications of the contributed rigs are as follows:

		Approximate
		Drilling
Rig	Design	Depth (ft)	Type	Horsepower
3	Cabot 900	10,000	Mechanical	950
18	Gardner Denver 1500E	25,000	Electric	2,000
19	Mid Continent U-1220 EB	25,000	Electric	2,000
38	National 1320	25,000	Electric	2,000
93	National T-32	8,000	Mechanical	500
96	Ideco H-35	8,000	Mechanical	400

 The Company also sold to Challenger four drilling rigs and ancillary equipment.  The sales price of $12,990 consisted of $1,950 in cash, installment receivable of $1,500 and a term note of $9,540.  The term note bears interest at 8.5%.  Interest and principal payments of $909 on the note are due quarterly until maturity at December 31, 2010.  The note receivable is collateralized by the assets sold to Challenger.  The note receivable from Challenger at March 31, 2009 was $10,400, of which $7,785 was classified as current and $2,615 was classified as long-term.

 The Company recorded a net gain of $4,707 for the three months ended March 31, 2008 relating to the exchange and sale of rigs and equipment to Challenger.  The transactions were completed on January 4, 2008.  Prior to these transactions, Challenger owned a fleet of 23 rigs.

 On February 20, 2008, the Company entered into a Management Services Agreement and Master Services Agreement with Challenger.  The Company agreed to make available to Challenger certain available employees of the Company for the purpose of providing land drilling services, certain business consulting services and managerial support to Challenger.  The Company invoices Challenger monthly for the services provided.  The Company had accounts receivable from Challenger of $3,689 and $3,387 at March 31, 2009 and December 31, 2008, respectively, related to these services provided.

 At March 31, 2009, the book value of the Company's ordinary share investment in Challenger was $63,287.  The Company’s 25% share of the net assets of Challenger was estimated to be $37,771.  The basis difference between the Company’s ordinary share investment in Challenger and the Company’s 25% share of the net assets of Challenger partially consists of certain property, plant and equipment in the amount of $5,004 and amortizable intangibles including customer lists and trade name in the amount of $9,770 and $1,313, respectively.  These amounts are being amortized against the Company’s share of Challenger’s net income over the useful lives of the assets including 15 years for the property, plant and equipment, 11 years for customer lists and 20 years for trade name.  Amortization recorded during the three months ended March 31, 2009 was $322. The remaining excess of $9,751 is accounted for as equity method goodwill.

 Summarized financial information of Challenger is presented below:

	Three Months Ended March 31,
	2009		2008
Condensed statement of operations:
Revenues	$	19,850	$	18,524
Gross margin	$	9,515	$	10,195
Net Income	$	2,937	$	6,554
	March 31,		December 31,
	2009		2008
Condensed balance sheet:
Current assets	$	58,236	$	50,837
Noncurrent assets		139,634		141,558
Total assets	$	197,870	$	192,395
Current liabilities	$	29,032	$	26,944
Noncurrent liabilities		17,754		17,304
Equity		151,084		148,147
Total liabilities and equity	$	197,870	$	192,395

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3. Long-term Debt

 Long-term debt consists of the following:

	March 31,		December 31,
	2009		2008
Notes payable to De Lage Landen Financial Services, collateralized by cranes,
payable in ninety-six monthly principal and interest installments of $61
Interest on the notes ranges from 6.74% - 7.07%, repaid in March, 2009. (1)	$	-	$	3,234
Revolving credit facility with Fortis Capital Corp., collateralized by the Company's assets,
and matures on September 29, 2013.  Loans under the revolving credit facility
bear interest at variable rates as defined in the credit agreement. (2)		111,100		111,100
Note payable to Ameritas Life Insurance Corp., collateralized by the building, payable in principal and interest installments of $14, interest on the note is 6.0%, maturity date of January 1, 2021. (3)		1,422		1,442
Notes payable to General Motors Acceptance Corporation, collateralized by trucks, payable in monthly principal and interest installments of $65, repaid in March, 2009. (4)		-		1,623
Note payable to John Deere Construction & Forestry Company, collaterized by forklifts, payable  in thirty-six monthly installments of $11, repaid in March, 2009 (5)		-		124
Note payable to Ford Motor Credit, collateralized by truck, payable in principal and interest
installments of $1.  Interest on the note is 2.9%, repaid in March, 2009. (6)		-		24
		112,522		117,547
Less current installments		85		1,464
	$	112,437	$	116,083

(1) On December 7, 2005, January 4, 2006, and June 12, 2006, the Company entered into Term Loan and Security Agreements with De Lage Landen Financial Services, Inc. The loans provide for term installments in an aggregate amount not to exceed $4,512. The proceeds of the term loans were used to purchase four cranes.  The term loans were repaid in full on March 30, 2009.

(2) On January 13, 2006, the Company entered into a $150.0 million revolving credit facility with Fortis Capital Corp., as administrative agent, lead arranger and sole book runner, and a syndicate of lenders.  On September 29, 2008, the Company amended and restated this revolving credit facility.  This $150.0 million amended and restated credit facility is with Fortis Bank SA/NV, New York Branch, as administrative agent, joint lead arranger and sole bookrunner, and a syndicate of lenders, which include The Royal Bank of Scotland plc, The CIT Group/Business Credit, Inc., The Prudential Insurance Company of America, Legacy Bank, Natixis and Caterpillar Financial Services Corporation. The revolving credit facility matures on September 29, 2013.  Loans under the revolving credit facility bear interest at LIBOR plus a 4.0% margin or, at our option, the prime rate plus a 3.0% margin.   The Company incurred $3,501 in debt issue costs related to the amended and restated credit facility.   The revolving credit facility also provides for a quarterly commitment fee of 0.5% per annum of the unused portion of the revolving credit facility, and fees for each letter of credit issued under the facility. Commitment fees expense for the three months ended March 31, 2009 and 2008 were $146 and $59, respectively.  The Company’s domestic subsidiaries have guaranteed the loans and other obligations under the revolving credit facility. The obligations under the revolving credit facility and the related guarantees are secured by a first priority security interest in substantially all of our assets, as well as the equity interests of our direct and indirect subsidiaries.   The revolving credit facility contains customary covenants for facilities of this type, including among other things, covenants that restrict the Company’s ability to incur indebtedness, incur liens, dispose of property, repay debt, pay dividends, repurchase shares and make certain acquisitions. The financial covenants are a minimum fixed charge coverage ratio of 1.05 to 1.00 for the four consecutive quarters ending March 31, 2009, 1.10 to 1.00 for the four consecutive quarters ending June 30, 2009 and 1.15 to 1.00 for the four consecutive quarters ending September 30, 2009 and each quarter thereafter and a maximum total leverage ratio of 2.00 to 1.00. The Company was in compliance with all covenants at March 31, 2009.  If oil and gas commodity prices remain at low levels causing demand for our services to continue to decline, the Company could be in violation of our revolving credit facility covenants during 2009, unless ratios are amended or the Company receives an infusion of capital.  The revolving credit facility provides for mandatory prepayments under certain circumstances.

(3) On January 2, 2007, the Company assumed a term loan agreement with Ameritas Life Insurance Corp. related to the acquisition of a building.  The loan provides for term installments in an aggregate not to exceed $1,590.

(4) On various dates during 2007 and 2008, the Company entered into term loan agreements with General Motors Acceptance Corporation.  The loans provide for term installments in an aggregate not to exceed $2,282.  The proceeds of the term loans were used to purchase 57 trucks.  The term loans were repaid in full on March 16, 2009.

(5) On November 21, 2006, the Company entered into term loan agreements with John Deere Credit.  The loans provide for term installments in an aggregate not to exceed $403.  The proceeds of the term loans were used to purchase two forklifts.  The term loans were repaid in full on March 19, 2009.

(6) On November 9, 2007, the Company entered into a term loan agreement with Ford Credit.  The loan provides for a term installment in an aggregate not to exceed $36.  The proceeds of the term loan were used to purchase a truck.  The term loan was repaid in full on March 24, 2009.

 Long-term debt maturing each year subsequent to March 31, 2009 is as follows:

2010	$	85
2011		91
2012		96
2013		102
2014		111,208
2015 and thereafter		940
	$	112,522

4. Workers’ Compensation and Health Insurance

 The Company is insured under a large deductible workers’ compensation insurance policy. The policy generally provides for a $1,000 deductible per covered accident. The Company maintains letters of credit in the aggregate amount of $11,560 for the benefit of various insurance companies as collateral for retrospective premiums and retained losses which may become payable under the terms of the underlying insurance contracts.  The letters of credit are typically renewed annually.  No amounts have been drawn under the letters of credit. Accrued expenses at March 31, 2009 and December 31, 2008 included approximately $3,931 and $4,288, respectively, for estimated incurred but not reported costs and premium accruals related to our workers’ compensation insurance.

 On November 1, 2005, the Company initiated a self-insurance program for major medical, hospitalization and dental coverage for employees and their dependents, which is partially funded by payroll deductions. The Company provided for both reported and incurred but not reported medical costs in the accompanying consolidated balance sheets. We have a maximum liability of $100 per employee/dependent per year. Amounts in excess of the stated maximum are covered under a separate policy provided by an insurance company. Accrued expenses at March 31, 2009 and December 31, 2008 included approximately $1,957 and $1,773, respectively, for our estimate of incurred but not reported costs related to the self-insurance portion of our health insurance.

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5. Transactions with Affiliates

 The Company has six operating leases with affiliated entities.  Related rent expense was approximately $143 and $70 for the three months ended March 31, 2009 and 2008.

 The Company provided workover services totaling $0 and $16 to affiliated entities during the three months ended March 31, 2009 and 2008.

 The Company had receivables from affiliates of $3,689 and $3,387 at March 31, 2009 and December 31, 2008, respectively.

 Additional information about our transactions with affiliates is included in Note 2, Investment in Challenger.

6. Commitments and Contingencies

 Various claims and lawsuits, incidental to the ordinary course of business, are pending against the Company. In the opinion of management, all matters are adequately covered by insurance or, if not covered, are not expected to have a material effect on the Company’s consolidated financial position, results of operations or cash flows.

7. Business Segments

 The Company’s reportable business segments are contract land drilling and well servicing.  The contract land drilling segment utilizes a fleet of land drilling rigs to provide contract drilling services to oil and natural gas exploration and production companies.  During the three months ended March 31, 2009, our drilling rigs operated in Oklahoma, Texas, Colorado, Utah, North Dakota, Louisiana, and Mexico.  The Company had revenues of $3,010 from drilling rigs operating in Mexico for the three months ended March 31, 2009. The well servicing segment encompasses a full range of services performed with a mobile well servicing rig, including the installation and removal of downhole equipment and elimination of obstructions in the well bore to facilitate the flow of oil and gas. During the three months ended March 31, 2009, our workover rigs operated in Oklahoma, Texas, Kansas, Colorado, Arkansas, and New Mexico.  The accounting policies of the segments are the same as those described in the summary of significant accounting policies.  The Company’s reportable segments are strategic business units that offer different products and services.

 The following table sets forth certain financial information with respect to the Company’s reportable segments:

	Contract land drilling			Well servicing			Total
Three Months Ended March 31, 2009
Operating Revenues	$	47,826		$	2,779		$	50,605
Direct operating costs		(29,844	)		(2,315	)	$	(32,159	)
Segment profits	$	17,982		$	464		$	18,446
Depreciation and amortization	$	10,842		$	1,684		$	12,526
Capital expenditures	$	2,908		$	222		$	3,130
Identifiable assets	$	532,318		$	57,355		$	589,673
Three Months Ended March 31, 2008
Operating Revenues	$	54,073		$	8,223		$	62,296
Direct operating costs		(33,190	)		(4,943	)	$	(38,133	)
Segment profits	$	20,883		$	3,280		$	24,163
Depreciation and amortization	$	10,623		$	1,302		$	11,925
Capital expenditures	$	15,340		$	3,188		$	18,528
Identifiable assets	$	523,710		$	62,142		$	585,852

 The following table reconciles the segment profits above to the operating income as reported in the consolidated statements of operations:

	Three Months Ended			Three Months Ended
	March 31, 2009			March 31, 2008
Segment profits	$	18,446		$	24,163
General and administrative expenses		(5,188	)		(5,739	)
Depreciation and amortization		(12,526	)		(11,925	)
Gain on Challenger transaction		-			4,707
Operating income	$	732		$	11,206

8. Net Income Per Common Share

 The following table presents a reconciliation of the numerators and denominators of the basic and diluted earnings per share (“EPS”) and diluted EPS comparisons as required by SFAS No. 128:

	Three Months Ended
	March 31,
	2009			2008
Basic:
Net income (loss)	$	(1,709	)	$	8,148
Weighted average shares		26,589			26,265
Earnings (loss) per share	$	(0.06	)	$	0.31
Diluted:
Net income (loss)	$	(1,709	)	$	8,148
Weighted average shares:
Outstanding (thousands)		26,589			26,265
Restricted Stock and Options (thousands)		-			22
		26,589			26,287
Income (loss) per share	$	(0.06	)	$	0.31

 The weighted average number of diluted shares excludes 19,857 and 9,865 shares for the three months ended March 31, 2009 and 2008, respectively, subject to restricted stock awards due to their antidilutive effects. 

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9. Restricted Stock

 Under all restricted stock awards to date, shares were issued when granted and nonvested shares are subject to forfeiture for failure to fulfill service conditions.  Restricted stock awards are valued at the grant date market value of the underlying common stock and are being amortized to operations over the respective vesting period.  Compensation expense for the three months ended March 31, 2009 and 2008, related to shares of restricted stock was $751 and $1,150, respectively.  Restricted stock activity for the three months ended March 31, 2009 was as follows:

			Weighted Average
			Grant Date
	Shares		Fair Value
Outstanding at December 31, 2008		463,680	$	15.22
Granted		415,955		5.28
Vested		(318,965)		15.59
Forfeited/expired		-		-
Outstanding at March 31, 2009		560,670	$	7.73

 There was $3,761 of total unrecognized compensation cost related to nonvested restricted stock awards to be recognized over a weighted-average period of 1.24 years as of March 31, 2009.

10. Employee Benefit Plans

 The Company implemented a new 401(k) retirement plan for its eligible employees during 2007. Under the plan, the Company matches 100% of employees’ contributions up to 5% of eligible compensation. Employee and employer contributions vest immediately. The Company’s contributions for the three months ended March 31, 2009 and 2008 were $204 and $258, respectively.

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

 The following discussion and analysis should be read in conjunction with the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section and audited consolidated financial statements and related notes thereto included in our Annual Report on Form 10-K, filed with the Securities and Exchange Commission, or SEC, on March 16, 2009 and with the unaudited consolidated financial statements and related notes thereto presented in this Quarterly Report on Form 10-Q.

Disclosure Regarding Forward-Looking Statements

 Our disclosure and analysis in this Form 10-Q may include forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, or the Securities Act, Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act, and the Private Securities Litigation Reform Act of 1995, that are subject to risks and uncertainties. Forward-looking statements give our current expectations and projections relating to our financial condition, results of operations, plans, objectives, future performance and business. You can identify these statements by the fact that they do not relate strictly to historical or current facts. These statements may include words such as “anticipate,” “estimate,” “expect,” “project,” “intend,” “plan,” “believe” and other words and terms of similar meaning in connection with any discussion of the timing or nature of future operating or financial performance or other events. All statements other than statements of historical facts included in this Form 10-Q that address activities, events or developments that we expect, believe or anticipate will or may occur in the future are forward-looking statements.

 These forward-looking statements are largely based on our expectations and beliefs concerning future events, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors relating to our operations and business environment, all of which are difficult to predict and many of which are beyond our control.

 Although we believe our estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, management’s assumptions about future events may prove to be inaccurate. Management cautions all readers that the forward-looking statements contained in this Form 10-Q are not guarantees of future performance, and we cannot assure any reader that those statements will be realized or the forward-looking events and circumstances will occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to the factors listed in the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Risk Factors” sections of this Quarterly Report on Form 10-Q and our most recent Annual Report on Form 10-K. All forward-looking statements speak only as of the date of this Form 10-Q. We do not intend to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise, except as required by law. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

Overview

 We provide contract land drilling and workover services to independent and major oil and natural gas exploration and production companies throughout the United States and internationally in Mexico. As of April 30, 2009, we owned a fleet of 56 land drilling rigs, of which 45 were marketed and 11 were held in inventory. We also owned a fleet of 61 workover rigs, of which 52 were marketed and nine were held in inventory. As of April 30, 2009, we also owned a fleet of 60 trucks used to transport our rigs.

 We commenced operations in 2001 with the purchase of one stacked 650-horsepower drilling rig that we refurbished and deployed. We subsequently made selective acquisitions of both operational and inventoried drilling rigs, as well as ancillary equipment. Our management team has significant experience not only with acquiring rigs, but also with refurbishing and deploying inventoried rigs. We have successfully refurbished and brought into operation 25 inventoried drilling rigs during the period from November 2003 through December 2008. In addition, we have a 41,000 square foot machine shop in Oklahoma City, which allows us to refurbish and repair our rigs and equipment in-house. This facility, which complements our three drilling rig refurbishment yards, significantly reduces our reliance on outside machine shops and the attendant risk of third-party delays in our rig refurbishment program.

Business Segments

 We currently conduct our operations through two operating segments: our Contract Land Drilling segment and our Well Servicing segment.  The following is a description of these two operating segments.  Financial information about our operating segments is included in Note 10, Business Segments and Concentrations, of the Notes to Consolidated Financial Statements.

 Contract Land Drilling - We obtain our contracts for drilling oil and natural gas wells either through competitive bidding or through direct negotiations with customers. Our drilling contracts generally provide for compensation on either a daywork or footage basis. We have not historically entered into turnkey contracts and do not intend to enter into any turnkey contracts, subject to changes in market conditions, although it is possible that we may acquire such contracts in connection with future acquisitions. Contract terms we offer generally depend on the complexity and risk of operations, the on-site drilling conditions, the type of equipment used and the anticipated duration of the work to be performed. Although, we currently have 11 of our drilling rigs operating under agreements with initial terms ranging from one to two years, our contracts generally provide for the drilling of a single well and typically permit the customer to terminate on short notice.

 A significant performance measurement that we use to evaluate this segment is operating rig utilization. We compute operating drilling rig utilization rates by dividing revenue days by total available days during a period. Total available days are the number of calendar days during the period that we have owned the operating rig. Revenue days for each operating rig are days when the rig is earning revenues under a contract, i.e. when the rig begins moving to the drilling location until the rig is released from the contract. On daywork contracts, during the mobilization period we typically receive a fixed amount of revenue based on the mobilization rate stated in the contract. We begin earning our contracted daywork rate and mobilization revenue when we begin drilling the well. Generally, we will receive a percentage of the contracted dayrate during the mobilization period. We account for these revenues as mobilization fees.

 For the three months ended March 31, 2009 and 2008 and years ended December 31, 2008, 2007 and 2006, our rig utilization rates, revenue days and average number of operating rigs were as follows:

	Three Months Ended
	March 31,						Years Ended December 31,
	2009			2008			2008			2007			2006
Average number of operating rigs		45			45			44			51			45
Revenue days		2,362			2,848			12,712			14,245			15,202
Utilization Rates		58	%		69	%		79	%		76	%		93	%

 The decrease in the number of revenue days in the three month-period ended March 31, 2009 as compared to the same period in 2008 is attributable to a decrease in our rig utilization rate.

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 Well Servicing – Our well servicing segment provides a broad range of well services to oil and gas drilling and producing companies, including maintenance, workover, new well completion and plugging and abandonment.  We provide maintenance-related services as part of the normal, periodic upkeep of producing oil and gas wells. Maintenance-related services represent a relatively consistent component of our business. Workover and completion services generate more revenue per hour than maintenance work due to the use of auxiliary equipment, but demand for workover and completion services fluctuates more with the overall activity level in the industry.

 The Company earns well servicing revenue based on purchase orders, contracts or other persuasive evidence of an arrangement with the customer, such as a master service agreement, that include fixed or determinable prices.  We generally charge our customers an hourly rate for these services, which varies based on a number of considerations including market conditions in each region, the type of rig and ancillary equipment required, and the necessary personnel.

 Our well servicing rig fleet has increased from a weighted average number of 24 rigs in the first quarter of 2007 to 61 in the fourth quarter of 2008 due to newbuild purchases.  We gauge activity levels in our well servicing rig operations based on rig utilization rate. We compute operating workover rig utilization rates by dividing revenue hours by total available hours during a period. Total available hours are the number of hours during the period that we have owned the operating workover rig based on a 50-hour work week per rig.

 For the three months ended March 31, 2009 and 2008 and years ended December 31, 2008 and 2007, our workover rig utilization rates, revenue hours and average number of operating workover rigs were as follows:

	Three Months Ended
	March 31,						Years Ended December 31,
	2009			2008			2008			2007
Average number of operating workover rigs		52			48			52			33
Revenue hours		8,012			23,865			91,591			63,746
Utilization Rates		24	%		77	%		68	%		78	%

Market Conditions in Our Industry

 The United States contract land drilling and well servicing industry is highly cyclical. Volatility in oil and natural gas prices can produce wide swings in the levels of overall drilling and well servicing activity in the markets we serve and affect the demand for our drilling and workover services and the revenue rates we can charge for our drilling and workover rigs. The availability of financing sources, past trends in oil and natural gas prices and the outlook for future oil and natural gas prices strongly influence the capital expenditure budgets of exploration and production companies.

 Our business environment has been adversely affected by the recent volatility and decline in oil and natural gas prices and the deteriorating global economic environment.  As part of this deterioration, there has been significant uncertainty in the capital markets and access to financing has been reduced.  As a result of these conditions, our customers have curtailed their exploration budgets, which is resulting in a significant decrease in demand for our services, a reduction in revenue rates and utilization.  During the first quarter of 2009, the Company recorded $3.1 million of contract drilling revenue related to terminated contracts.  Due to the current economic environment, certain customers may not be able to pay suppliers, including us, if they are not able to access capital to fund their business operations.

 The following table depicts the prices for near month delivery contracts for crude oil and natural gas as traded on the NYMEX, as well as the most recent Baker Hughes domestic land rig count, on the dates indicated:

	At March 31,		At December 31,
	2009		2008		2007		2006
Crude oil (Bbl)	$	49.66	$	44.60	$	95.98	$	61.05
Natural gas (Mmbtu)	$	3.78	$	5.62	$	7.48	$	6.30
U.S. Land Rig Count		1,039		1,653		1,719		1,626

 Increased expenditures for exploration and production activities generally leads to increased demand for our services. Over the past several years, rising oil and natural gas prices and the corresponding increase in onshore oil and natural gas exploration and production spending led to expanded drilling and well service activity as reflected by the increases in the U.S. land rig counts and U.S. workover rig counts over the previous five years. Falling commodity prices and the oversupply of rigs, similar to what we are currently experiencing, generally leads to lower demand for our services.

 The recent decline in oil and natural gas prices and the deteriorating global economic environment will lead to reductions in our rig utilization and revenue rates in 2009.  Our near-term strategy is to maintain a strong balance sheet and ample liquidity. Management has initiated certain cost reduction measures including workforce and wage rate reductions that will reduce operating expenses during the downturn in the industry. Budgeted capital expenditures for 2009 represent a substantial reduction from historical levels and consist of routine capital expenditures necessary to maintain our equipment in safe and efficient working order and limited discretionary capital expenditures of new equipment or upgrades of existing equipment.

Critical Accounting Policies and Estimates

 Our discussion and analysis of our financial condition and results of operations is based upon our consolidated financial statements, which have been prepared in accordance with accounting policies that are described in the notes to our consolidated financial statements. The preparation of the consolidated financial statements requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. We continually evaluate our judgments and estimates in determining our financial condition and operating results. Estimates are based upon information available as of the date of the financial statements and, accordingly, actual results could differ from these estimates, sometimes materially. Critical accounting policies and estimates are defined as those that are both most important to the portrayal of our financial condition and operating results and require management’s most subjective judgments. The most critical accounting policies and estimates are described below.

 Revenue and Cost Recognition—Our Contract Land Drilling segment earns revenues by drilling oil and natural gas wells for our customers under daywork or footage contracts, which usually provide for the drilling of a single well. We recognize revenues on daywork contracts for the days completed based on the dayrate each contract specifies. Mobilization revenues and costs are deferred and recognized over the drilling days of the related drilling contract. Individual contracts are usually completed in less than 120 days. We follow the percentage-of-completion method of accounting for footage contract drilling arrangements. Under this method, drilling revenues and costs related to a well in progress are recognized proportionately over the time it takes to drill the well. Percentage of completion is determined based upon the amount of expenses incurred through the measurement date as compared to total estimated expenses to be incurred drilling the well. Mobilization costs are not included in costs incurred for percentage-of-completion calculations. Mobilization costs on footage contracts and daywork contracts are deferred and recognized over the days of actual drilling. Under the percentage-of-completion method, management estimates are relied upon in the determination of the total estimated expenses to be incurred drilling the well. When estimates of revenues and expenses indicate a loss on a contract, the total estimated loss is accrued.

 Our management has determined that it is appropriate to use the percentage-of-completion method to recognize revenue on our footage contracts, which is the predominant practice in the industry. Although our footage contracts do not have express terms that provide us with rights to receive payment for the work that we perform prior to drilling wells to the agreed upon depth, we use this method because, as provided in applicable accounting literature, we believe we achieve a continuous sale for our work-in-progress and we believe, under applicable state law, we ultimately could recover the fair value of our work-in-progress even in the event we were unable to drill to the agreed upon depth in breach of the applicable contract. However, ultimate recovery of that value, in the event we were unable to drill to the agreed upon depth in breach of the contract, would be subject to negotiations with the customer and the possibility of litigation.

 We are entitled to receive payment under footage contracts when we deliver to our customer a well completed to the depth specified in the contract, unless the customer authorizes us to drill to a shallower depth. Since inception, we have completed all our footage contracts. Although our initial cost estimates for footage contracts do not include cost estimates for risks such as stuck drill pipe or loss of circulation, we believe that our experienced management team, our knowledge of geologic formations in our areas of operations, the condition of our drilling equipment and our experienced crews enable us to make reasonably dependable cost estimates and complete contracts according to our drilling plan. While we do bear the risk of loss for cost overruns and other events that are not specifically provided for in our initial cost estimates, our pricing of footage contracts takes such risks into consideration. When we encounter, during the course of our drilling operations, conditions unforeseen in the preparation of our original cost estimate, we immediately adjust our cost estimate for the additional costs to complete the contracts. If we anticipate a loss on a contract in progress at the end of a reporting period due to a change in our cost estimate, we immediately accrue the entire amount of the estimated loss, including all costs that are included in our revised estimated cost to complete that contract, in our consolidated statement of operations for that reporting period.  We are more likely to encounter losses on footage contracts in years in which revenue rates are lower for all types of contracts.

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 Revenues and costs during a reporting period could be affected by contracts in progress at the end of a reporting period that have not been completed before our financial statements for that period are released. We had no footage contracts in progress at March 31, 2009 and December 31, 2008. At March 31, 2009 and December 31, 2008, our unbilled receivables totaled $1.8 million and $2.9 million, respectively, all of which relates to the revenue recognized but not yet billed or costs deferred on daywork contracts in progress.

 We accrue estimated contract costs on footage contracts for each day of work completed based on our estimate of the total costs to complete the contract divided by our estimate of the number of days to complete the contract. Contract costs include labor, materials, supplies, repairs and maintenance and operating overhead allocations. In addition, the occurrence of uninsured or under-insured losses or operating cost overruns on our footage contracts could have a material adverse effect on our financial position and results of operations. Therefore, our actual results could differ significantly if our cost estimates are later revised from our original estimates for contracts in progress at the end of a reporting period that were not completed prior to the release of our financial statements.

 Accounts Receivable—We evaluate the creditworthiness of our customers based on their financial information, if available, information obtained from major industry suppliers, current prices of oil and natural gas and any past experience we have with the customer. Consequently, an adverse change in those factors could affect our estimate of our allowance for doubtful accounts. In some instances, we require new customers to establish escrow accounts or make prepayments. We typically invoice our customers at 30-day intervals during the performance of daywork contracts and upon completion of the daywork contract. Footage contracts are invoiced upon completion of the contract. Our typical contract provides for payment of invoices in 10 to 30 days. We generally do not extend payment terms beyond 30 days. We are currently involved in legal actions to collect various overdue accounts receivable.  Our allowance for doubtful accounts was $4.1 million and $3.8 million at March 31, 2009 and December 31, 2008, respectively. Any allowance established is subject to judgment and estimates made by management. We determine our allowance by considering a number of factors, including the length of time trade accounts receivable are past due, our previous loss history, our customer’s current ability to pay its obligation to us and the condition of the general economy and the industry as a whole. We write off specific accounts receivable when they become uncollectible and payments subsequently received on such receivables reduce the allowance for doubtful accounts.

 If a customer defaults on its payment obligation to us under a footage contract, we would need to rely on applicable law to enforce our lien rights, because our footage contracts do not expressly grant to us a security interest in the work we have completed under the contract and we have no ownership rights in the work-in-progress or completed drilling work, except any rights arising under the applicable lien statute on foreclosure. If we were unable to drill to the agreed on depth in breach of the contract, we might also need to rely on equitable remedies outside of the contract, including quantum meruit, available in applicable courts to recover the fair value of our work-in-progress under a footage contract.

 Asset Impairment and Depreciation—We review long-lived assets to be held and used for impairment whenever events or changes in circumstances indicate that the carrying amount of the assets may not be recoverable.  Factors that we consider important and could trigger an impairment review would be our customers’ financial condition and any significant negative industry or economic trends. More specifically, among other things, we consider our contract revenue rates, our rig utilization rates, cash flows from our drilling rigs, current oil and natural gas prices, industry analysts’ outlook for the industry and their view of our customers’ access to debt or equity and the trends in the price of used drilling equipment observed by our management. If a review of our drilling rigs and intangible assets indicate that our carrying value exceeds the estimated undiscounted future cash flows, we are required under applicable accounting standards to write down the drilling equipment and intangible assets to its fair market value.  A one percent write-down in the cost of our drilling equipment and intangible assets as of March 31, 2009, would have resulted in a corresponding increase in our net loss by approximately $2.6 million.

 During the first quarter of 2009, demand for our services continued to decline and general economic conditions worsened.  We considered this a triggering event that required us to perform an assessment with respect to impairment of long-lived assets, including property and equipment and intangible assets, in our contract land drilling and well servicing segments.  We estimated future undiscounted cash flows over the expected life of the long-lived assets and determined that expected cash flows exceeded the carrying value of the long-lived assets.  Based on the analysis performed, no impairment was indicated.

 Our determination of the estimated useful lives of our depreciable assets, directly affects our determination of depreciation expense and deferred taxes. A decrease in the useful life of our drilling equipment would increase depreciation expense and reduce deferred taxes. We provide for depreciation of our drilling rigs, transportation and other equipment on a straight-line method over useful lives that we have estimated and that range from three to fifteen years after the rig was placed into service. We record the same depreciation expense whether an operating rig is idle or working. Depreciation is not recorded on an inventoried rig until placed in service. Our estimates of the useful lives of our drilling, transportation and other equipment are based on our experience in the drilling industry with similar equipment.

 We capitalize interest cost as a component of drilling and workover rigs refurbished for our own use. During the three months ended March 31, 2009 and 2008, we capitalized approximately $0 and $382,000, respectively.

 Stock Based Compensation--- We have adopted SFAS No. 123(R), “Share-Based Payment” upon granting our first stock options on August 16, 2005. SFAS No. 123(R) requires a public entity to measure the costs of employee services received in exchange for an award of equity or liability instruments based on the grant-date fair value of the award. That cost will be recognized over the periods during which an employee is required to provide service in exchange for the award.  Stock compensation expense was $751,000 and $1.1 million for the three months ended March 31, 2009 and 2008, respectively.

 Deferred Income Taxes—We provide deferred income taxes for the basis difference in our property and equipment, stock compensation expense and other items between financial reporting and tax reporting purposes. For property and equipment, basis differences arise from differences in depreciation periods and methods and the value of assets acquired in a business acquisition where we acquire the stock in an entity rather than just its assets. For financial reporting purposes, we depreciate the various components of our drilling rigs and refurbishments over fifteen years, while federal income tax rules require that we depreciate drilling rigs and refurbishments over five years. Therefore, in the first five years of our ownership of a drilling rig, our tax depreciation exceeds our financial reporting depreciation, resulting in our providing deferred taxes on this depreciation difference. After five years, financial reporting depreciation exceeds tax depreciation, and the deferred tax liability begins to reverse.

 Other Accounting Estimates—Our other accrued expenses as of March 31, 2009 and December 31, 2008 included accruals of approximately $3.9 million and $4.3 million, respectively, for costs under our workers’ compensation insurance. We have a deductible of $1.0 million per covered accident under our workers’ compensation insurance. We maintain letters of credit in the aggregate amount of $11.6 million for the benefit of various insurance companies as collateral for retrospective premiums and retained losses which may become payable under the terms of the underlying insurance contracts.  The letters of credit are typically renewed annually.  No amounts have been drawn under the letters of credit. We accrue for these costs as claims are incurred based on cost estimates established for each claim by the insurance companies providing the administrative services for processing the claims, including an estimate for incurred but not reported claims, estimates for claims paid directly by us, our estimate of the administrative costs associated with these claims and our historical experience with these types of claims.  We also have a self-insurance program for major medical, hospitalization and dental coverage for employees and their dependents.  We recognize both reported and incurred but not reported costs related to the self-insurance portion of our health insurance.  Since the accrual is based on estimates of expenses for claims, the ultimate amount paid may differ from accrued amounts.

 Recent Accounting Pronouncements—In September 2006, the FASB issued SFAS No. 157, or SFAS 157, “Fair Value Measurements.”  This Statement defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, or GAAP, and expands disclosures about fair value measurements. This Statement applies under other accounting pronouncements that require or permit fair value measurements, the FASB having previously concluded in those accounting pronouncements that fair value is the relevant measurement attribute. Accordingly, this Statement does not require any new fair value measurements. This Statement is effective for fiscal years beginning after November 15, 2007; however, on February 12, 2008, the FASB issued FSP FAS No. 157-2, Effective Dates of FASB Statement No. 157, which delays the effective date of SFAS 157 to fiscal years beginning after November 15, 2008 for all nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis.  The adoption of the provisions of SFAS 157 did not have a material impact on our financial statements.

 In December 2007, the FASB issued SFAS No. 141 (revised 2007) “Business Combinations”, or SFAS 141R. SFAS 141R establishes principles and requirements for how the acquirer of a business recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree. SFAS 141R also provides guidance for recognizing and measuring the goodwill acquired in the business combination and determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. SFAS No. 141R applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008.  The adoption of the provisions of SFAS 141R did not have an immediate impact on our consolidated financial statements.

 In December 2007, the FASB issued SFAS No. 160, or SFAS 160, “Noncontrolling Interests in Consolidated Financial Statements — an amendment of ARB No. 51.” SFAS 160 establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. SFAS 160 requires retroactive adoption of the presentation and disclosure requirements for existing minority interests. All other requirements of SFAS 160 shall be applied prospectively. SFAS 160 is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008.  The adoption of the provisions of SFAS 141R did not have a material impact on our consolidated financial statements.

 In March 2008, the FASB issued SFAS No. 161, or SFAS 161, “Disclosures about Derivative Instruments and Hedging Activities – an amendment of FASB Statement No. 133.”  SFAS 161 requires enhanced disclosures for derivative instruments and hedging activities that include how and why an entity uses derivatives, how instruments and the related hedged items are accounted for under FAS 133 and related interpretations, and how derivative instruments and related hedged items affect the entity’s financial position, results of operations and cash flows.  SFAS 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. The adoption of the provisions of SFAS 161 did not have a material impact on our financial position or results of operations.

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 In June 2008, the FASB issued FSP No. EITF 03-6-1, Determining Whether Instruments Granted in Share-Based Payment Transactions are Participating Securities.  This FSP provides that unvested share-based payment awards that contain nonforfeitable rights to dividends are participating securities and shall be included in the computation of earnings per share pursuant to the two class method.  This FSP is effective for financial statements issued for fiscal years beginning after December 15, 2008 and interim periods within those years.  The adoption of this FSP did not have a material impact on our financial position or results of operation.

 In September 2008, the FASB issued EITF 08-6, Equity Method Investment Accounting Considerations.  The purpose of this issue is to resolve several accounting issues that arise in applying the equity method of accounting. Most of these issues arise or become more prevalent upon the effective date of FASB Statement No. 141 (Revised 2007), Business Combinations, and (or) FASB Statement No. 160, Noncontrolling Interests in Consolidated Financial Statements. This is because the literature that is being replaced or amended by Statements 141R and 160 has been used by analogy in addressing certain aspects of applying the equity method of accounting.  The EITF concluded that the effective date for this issue should coincide with the effective date of Statements 141R and 160 and that it should be applied prospectively. As such, the guidance in this issue applies to transactions that occur in fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008.  The adoption of EITF 08-6 did not have a material impact on our consolidated financial statements.

Recent Highlights

 Recent events, both within the United States and the world, have brought about significant and immediate changes in the global financial markets which in turn are affecting the United States economy, our industry and us.  In the United States, these events and others have had a significant impact on the prices for oil and natural gas as reflected in the following table:

		Natural Gas Price
		per Mcf				Oil Price per Bbl
Quarter		High		Low		High		Low
2009:
	First	$	6.07	$	3.63	$	54.34	$	33.98
2008:
	Fourth	$	7.73	$	5.29	$	98.53	$	33.87
	Third	$	13.58	$	7.22	$	145.29	$	95.71
	Second	$	13.35	$	9.32	$	140.21	$	100.98
	First	$	10.23	$	7.62	$	110.33	$	86.99
2007:
	Fourth	$	6.45	$	5.84	$	91.96	$	83.13
	Third	$	6.07	$	5.21	$	76.09	$	69.88
	Second	$	7.02	$	6.44	$	65.23	$	60.73
	First	$	6.88	$	5.80	$	58.69	$	50.79
2006:
	Fourth	$	6.72	$	4.50	$	58.23	$	56.15
	Third	$	6.74	$	5.55	$	72.49	$	61.56
	Second	$	6.06	$	5.46	$	69.67	$	67.26
	First	$	7.99	$	6.13	$	62.39	$	57.58

 As noted in the table, oil and natural gas prices have declined significantly during recent months in a deteriorating national and global economic environment.  The current economic environment and the recent decline in commodity prices is causing exploration and production companies to reduce their overall level of drilling activity and spending.  When drilling activity and spending decline for any sustained period of time our dayrates and utilization rates also tend to decline.  In addition, lower commodity prices for any sustained period of time could impact the liquidity condition of some of our customers, which, in turn, might limit their ability to meet their financial obligations to us.

 The impact on our business and financial results as a consequence of the recent volatility in oil and natural gas prices and the global economic crisis is uncertain in the long term, but in the short term, it has had a number of consequences for us, including the following:

·   In December 2008, we incurred goodwill impairment of our contract land drilling and well servicing segments of $24.3 million due to the fair value of the segments being less than their carrying value.

·   In December 2008, we incurred an impairment charge to our investment in Challenger of $14.4 million due to the fair value of the investment being less than its carrying value.

·   We have significantly reduced our total 2009 estimated capital expenditures for our business segments compared to 2008, excluding acquisitions, in order to focus on keeping our capital expenditures within anticipated internally generated cash flow.

·   Due to declining commodity prices of oil and natural gas, several of our customers have significantly reduced their drilling budgets for 2009, resulting in a significant reduction in the average utilization of our drilling and workover rig fleet.  Our average utilization was approximately 83% for the three months ended December 31, 2008, 76% for the month of January, 55% for the month of February and 44% for the month of March 2009.

Results of Operations

Three Months Ended March 31, 2009 Compared to Three Months Ended March 31, 2008

 Contract Drilling Revenue. For the three months ended March 31, 2009, we reported contract drilling revenues of $47.8 million, a 12% decrease from revenues of $54.1 million for the same period in 2008. The decrease is primarily due to a decrease in average dayrates and total revenue days for the three months ended March 31, 2009 as compared to the same period in 2008. Average dayrates for our drilling services decreased $393, or 2%, to $16,708 for the three months ended March 31, 2009 from $17,101 in the same period in 2008. Revenue days decreased 17% to 2,362 days for the three months ended March 31, 2009 from 2,848 days during the same period in 2008. The decrease in the number of revenue days for the three months ended March 31, 2009 as compared to the same period in 2008 is primarily due to a decrease in the utilization rate for the same period.  Utilization decreased to 58% for the three months ended March 31, 2009 from 69% for the same period in 2008.  During the first quarter of 2009, the Company recorded $3.1 million of contract drilling revenue related to terminated contracts.

 Well Service Revenue.  For the three months ended March 31, 2009, we reported well service revenues of approximately $2.8 million, a 66% decrease from revenues of $8.2 million for the same period in 2008.  The decrease is primarily due to a decrease in revenue hours.  Revenue hours decreased 66% to 8,012 hours for the three months ended March 31, 2009 from 23,865 hours during the same period in 2008.  The decrease in revenue hours for the three months ended March 31, 2009 compared to the same period in 2008 is due to a decrease in the utilization rate for the same time period partially offset by an increase in the average operating rigs for the same time period.  Utilization decreased to 24% for the three months ended March 31, 2009 from 77% for the same period in 2008.  The average operating rigs increased 8%, or 4 rigs, from 48 for the three months ended March 31, 2008 to 52 for the same period in 2009.

 Equity in Income of Challenger.  Equity in income of Challenger was $412,000 for the three months ended March 31, 2009 related to our investment in Challenger compared to $1.8 million for the three months ended March 31, 2008.  The equity in income of Challenger represents our 25% share of Challenger’s income.  For the three months ended March 31, 2009, Challenger had operating revenues of $19.8 million and operating costs of $10.3 million compared to $18.5 million and $8.3 million for the three months ended March 31, 2008.

 Contract Drilling Expense. Direct rig cost decreased $3.4 million to $29.8 million for the three months ended March 31, 2009 from $33.2 million for the same period in 2008. This 10% decrease is primarily due to the decrease in revenue days for the three months ended March 31, 2009 as compared to the same period in 2008.  As a percentage of contract drilling revenue, drilling expense increased to 62% for the three-month period ended March 31, 2009 from 61% for the same period in 2008 due primarily to a general increase in the cost of supplies and materials.

 Well Service Expense. Well service expense decreased $2.6 million to $2.3 million for the three months ended March 31, 2009 from $4.9 million for the same period in 2008.  This 53% decrease is primarily due to the decrease in revenue hours for the three months ended March 31, 2009 as compared to the same period in 2008.

 Depreciation and Amortization Expense. Depreciation expense increased $600,000 to $12.5 million for the three months ended March 31, 2009 from $11.9 million for the same period in 2008. The increase is primarily due to the 13% increase in fixed assets.

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 General and Administrative Expense. General and administrative expense decreased $551,000 to $5.2 million for the three months ended March 31, 2009 from $5.7 million for the same period in 2008. The decrease is the result of a decrease in stock compensation expense of $398,000 and a decrease in yard expense of $244,000.  The decrease in stock compensation expense is primarily due to stock grants with higher grant date fair values becoming fully amortized.  The decrease in yard expense is primarily due to decreased activity in the yards as a result of the slowdown of our rig refurbishment program.  These decreases were partially offset by an increase in accounts receivable write-offs of $291,000.

 Interest Expense. Interest expense increased $1.1 million to $2.3 million for the three months ended March 31, 2009 from $1.2 million for the same period in 2008. The increase is due to an increase in the average outstanding balance under our revolving credit facility and a decrease in the capitalization of interest expense related to our rig refurbishment program.  We capitalized $0 of interest for the three months ended March 31, 2009 compared to $382,000 of interest for the same period in 2008.

 Income Tax Expense. We recorded an income tax benefit of $11,000 for the three months ended March 31, 2009. This compares to an income tax expense of $4.6 million for the three months ended March 31, 2008.  This decrease is primarily due to a $14.4 million decrease in pre-tax income to a pre-tax loss of $1.7 million for the three months ended March 31, 2009 from pre-tax income of $12.7 million for the three months ended March 31, 2008.  The Company’s effective income tax rate is higher than what would be expected if the federal statutory rate were applied to income before income taxes primarily because of certain stock compensation expenses recorded for financial reporting purposes that are not deductible for tax purposes.

Liquidity and Capital Resources

 Operating Activities. Net cash provided by operating activities was $20.2 million for the three months ended March 31, 2009 as compared to $14.9 million in 2008. The increase of $5.3 million from 2008 to 2009 was primarily due to an increase in cash receipts from customers, partially offset by cash payments to suppliers.

 Investing Activities. We use a significant portion of our cash flows from operations and financing activities for acquisitions and the refurbishment of our rigs. Cash used in investing activities was $2.6 million for the three months ended March 31, 2009 as compared to $20.9 million for the same period in 2008.   For the three months ended March 31, 2009, we used $3.1 million to purchase fixed assets.  This amount was partially offset by $489,000 of proceeds received from the sale of assets.  For the three months ended March 31, 2008, we used $18.5 million to purchase fixed assets and $5.1 million to purchase an equity interest in Challenger.  These amounts were partially offset by $2.6 million of proceeds received from the sale of assets.

 Financing Activities. Our cash flows used in financing activities were $5.0 million for the three months ended March 31, 2009 as compared to $3.3 million provided by financing activities for the same period in 2008.  For the three months ended March 31, 2009 our net cash used in financing activities related to principal payments of $5.0 million to various lenders.  For the three months ended March 31, 2008, our net cash provided by financing activities related to borrowings of $5.0 million under our credit facility with Fortis Capital Corp., partially offset by principal payments of $1.7 million to various lenders.

 Sources of Liquidity. Our primary sources of liquidity are cash from operations and debt and equity financing.

 Debt Financing.  On January 13, 2006, we entered into a $150.0 million revolving credit facility with Fortis Capital Corp., as administrative agent, lead arranger and sole book runner, and a syndicate of lenders.  On September 29, 2008, we amended and restated this revolving credit facility.  This $150.0 million amended and restated credit facility is with Fortis Bank SA/NV, New York Branch, as administrative agent, joint lead arranger and sole bookrunner, and a syndicate of lenders, which include The Royal Bank of Scotland plc, The CIT Group/Business Credit, Inc., The Prudential Insurance Company of America, Legacy Bank, Natixis and Caterpillar Financial Services Corporation. The revolving credit facility matures on September 29, 2013.  Loans under the revolving credit facility bear interest at LIBOR plus a 4.0% margin or, at our option, the prime rate plus a 3.0% margin.  The Company had $111.1 million borrowed against the facility at March 31, 2009.

 The revolving credit facility also provides for a quarterly commitment fee of 0.5% per annum of the unused portion of the revolving credit facility, and fees for each letter of credit issued under the facility. Commitment fees expense for the three months ended March 31, 2009 and 2008 were $146,000 and $59,000, respectively.  Our domestic subsidiaries have guaranteed the loans and other obligations under the revolving credit facility. The obligations under the revolving credit facility and the related guarantees are secured by a first priority security interest in substantially all of our assets, as well as the equity interests of our direct and indirect subsidiaries.

 The revolving credit facility contains customary covenants for facilities of this type, including among other things, covenants that restrict our ability to incur indebtedness, incur liens, dispose of property, repay debt, pay dividends, repurchase shares and make certain acquisitions. The financial covenants are a minimum fixed charge coverage ratio of 1.05 to 1.00 for the four consecutive quarters ending March 31, 2009, 1.10 to 1.00 for the four consecutive quarters ending June 30, 2009 and 1.15 to 1.00 for the four consecutive quarters ending September 30, 2009 and each quarter thereafter and a maximum total leverage ratio of 2.00 to 1.00. We are in compliance with all covenants at March 31, 2009.  If oil and gas commodity prices remain at low levels causing demand for our services to continue to decline, we could be in violation of our revolving credit facility covenants during 2009, unless ratios are amended or we receive an infusion of capital. The revolving credit facility provides for mandatory prepayments under certain circumstances including the following:

·   Asset dispositions

·   Reduction of revolving commitments

·   Deficiency

·   Equity issuance

·   Debt incurrence; and

·   Event of default

 At December 31, 2008 we were party to term installment loans for an aggregate principal amount of approximately $4.5 million. These term loans are payable in 96 monthly installments, mature in 2013 and 2015 and have a weighted average annual interest rate of 6.93%. The proceeds from these term loans were used to purchase cranes.  These loans were paid in full in March of 2009.

 We are party to a term loan agreement with Ameritas Life Insurance Corp. for an aggregate principal amount of approximately $1.4 million related to the acquisition of a building. This term loan is payable in 166 monthly installments, matures in 2021 and has an interest rate of 6%.

 Working Capital.  Our working capital was $76.1 million at March 31, 2009 compared to $71.6 million at December 31, 2008.  Our current ratio, which we calculate by dividing our current assets by our current liabilities, was 5.1 at March 31, 2009 compared to 3.0 at December 31, 2008.

 We believe that the liquidity shown on our balance sheet as of March 31, 2009, which includes approximately $76.1 million in working capital (including $39.2 million in cash) and availability under our $150.0 million credit facility with $111.1 million outstanding at March 31, 2009, together with cash expected to be generated from operations, provides us with sufficient ability to fund our operations for at least the next twelve months.  However, additional capital may be required for future rig acquisitions.  While we would expect to fund such acquisitions with additional borrowings and the issuance of debt and equity securities, we cannot assure you that such funding will be available or, if available, that it will be on terms acceptable to us.  The changes in the components of our working capital were as follows (amounts in thousands):

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	March 31,		December 31,
	2009		2008		Change
Cash and cash equivalents	$	39,228	$	26,676	$	12,552
Trade and other receivables		39,583		65,817		(26,234	)
Unbilled receivables		1,845		2,940		(1,095	)
Income tax receivable		2,046		2,072		(26	)
Current deferred income taxes		2,592		2,844		(252	)
Current maturities of note receivable		7,785		6,900		885
Prepaid expenses		1,418		572		846
Current assets		94,497		107,821		(13,324	)
Current debt		85		1,464		(1,379	)
Accounts Payable		5,958		18,473		(12,515	)
Accrued liabilities and deferred revenues		12,355		16,249		(3,894	)
Current liabilities		18,398		36,186		(17,788	)
Working capital	$	76,099	$	71,635	$	4,464

The increase in cash and cash equivalents was primarily due to the reduction in trade and other receivables of $26.2 million, partially offset by the reduction in current debt and accounts payable of $1.4 million and $12.5 million, respectively.

 The decrease in trade receivables and other receivables as well as accounts payable at March 31, 2009 as compared to December 31, 2008 was due to a continued reduction in revenue days and utilization rates during the first quarter of 2009 compared to 2008.  Utilization for the first quarter of 2009 was 58% compared to 79% for 2008.

 The decrease in accrued liabilities was due to a decrease in deferred revenue of approximately $1.9 million due to the reduction in the deferral of mobilization revenue and prepayments from operators and a $1.3 million reduction in property taxes payable.  The decrease in our deferral of mobilization revenue is due to the reduction in revenue days and utilization rates during the first quarter of 2009.

Item 3. Quantitative and Qualitative Disclosures About Market Risks

 We are subject to market risk exposure related to changes in interest rates on our outstanding floating rate debt. Borrowings under our revolving credit facility bear interest at a floating rate equal to LIBOR plus a margin that can range from 2.0% to 3.0% or, at our option, the prime rate plus a margin that can range from 1.0% to 2.0%, depending on the ratio of our outstanding senior debt to Adjusted EBITDA, as defined in our credit agreement with Fortis Capital Corp. An increase or decrease of 1% in the interest rate would have a corresponding decrease or increase in our net income (loss) of approximately $681,000 annually, based on the $111.1 million outstanding in the aggregate under our credit facility as of March 31, 2009.

Item 4. Controls and Procedures

 Evaluation of Disclosure Control and Procedures.

 As of the end of the period covered by this Quarterly Report on Form 10−Q, our management, under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a−15(e) or 15d−15(e) under the Securities Exchange Act of 1934, as amended). Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that as of March 31, 2009 our disclosure controls and procedures are effective.

 Disclosure controls and procedures are controls and procedures designed to ensure that information required to be disclosed in our reports filed or submitted under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms; and include controls and procedures designed to ensure that information is accumulated and communicated to our management, and made known to our Chief Executive Officer and Chief Financial Officer, particularly during the period when this Quarterly Report on Form 10−Q was prepared, as appropriate to allow timely decision regarding the required disclosure.

 Changes in Internal Control over Financial Reporting.

 There were no changes in our internal control over financial reporting that occurred during the first quarter of 2009 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II: OTHER INFORMATION

Item 1. Legal Proceedings

Various claims and lawsuits, incidental to the ordinary course of business, are pending against the Company. In the opinion of management, all matters are adequately covered by insurance or, if not covered, are not expected to have a material effect on the Company’s consolidated financial position, results of operations or cash flows.

Item 1A. Risk Factors

There have been no material changes to the Risk Factors previously disclosed in our Annual Report on Form 10-K for the year ended December 31, 2008 filed with the SEC on March 16, 2009.

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

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Submission of Matters to a Vote of Security Holders

None.

Item 5. Other Information

None.

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Item 6. Exhibits

Exhibits:

Exhibit No.	Description
2.1	Merger Agreement, dated as of August 11, 2005, by and among Bronco Drilling Holdings, L.L.C, Bronco Drilling Company, L.L.C. and Bronco Drilling Company, Inc. (incorporated by reference to Exhibit 2.1 to the Registration Statement on Form S-1, File No. 333-128861, filed by the Company with the SEC on October 6, 2005).
3.1	Amended and Restated Certificate of Incorporation of the Company, dated August 11, 2005 (incorporated by reference to Exhibit 2.1 to the Registration Statement on Form S-1, File No. 333-128861, filed by the Company with the SEC on October 6, 2005).
3.2	Bylaws of the Company (incorporated by reference to Exhibit 3.2 to Amendment No. 1 to the Registration Statement on Form S-1, File No. 333-125405, filed by the Company with the SEC on July 14, 2005).
4.1	Form of Common Stock certificate (incorporated by reference to Exhibit 4.1 to Amendment No. 2 to the Registration Statement on Form S-1, File No. 333-125405, filed by the Company with the SEC on August 2, 2005).
*31.1	Certification of Chief Executive Officer of Bronco Drilling Company, Inc. pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended.
*31.2	Certification of Chief Financial Officer of Bronco Drilling Company, Inc. pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended
*32.1	Certification of Chief Executive Officer of Bronco Drilling Company, Inc. pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of Title 18 of the United States Code.
*32.2	Certification of Chief Financial Officer of Bronco Drilling Company, Inc. pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of Title 18 of the United States Code.

               * Filed herewith.

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SIGNATURE

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

Dated: May 8, 2009	BRONCO DRILLING COMPANY, INC.
	By:	/s/ Zachary M. Graves
		Zachary M. Graves
		Chief Financial Officer
		(Principal Accounting and Financial Officer)
Dated: May 8, 2009	By:	/s/ D. Frank Harrison
		D. Frank Harrison
		Chief Executive Officer
		(Authorized Officer and Principal Executive Officer)

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