Bronco Drilling 10-Q 2006 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 June 30, 2006

OR

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

For the transition period from            to            

Commission File Number 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 is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer  ¨ Accelerated filer  ¨ Non-accelerated filer  x

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act.):    Yes  ¨    No  x

The number of shares outstanding of the registrant’s common stock, par value $.01 per share, as of the close of business on August 10, 2006, was 24,937,939.

BRONCO DRILLING COMPANY, INC.

INDEX

		Page
PART I—FINANCIAL INFORMATION
Item 1.	Financial Statements
Bronco Drilling Company, Inc.:
	Consolidated Balance Sheets as of June 30, 2006 (unaudited) and December 31, 2005	3
	Consolidated Statements of Operations for the three months and six months ended June 30, 2006 and 2005 (unaudited)	4
	Consolidated Statement of Shareholders’ Equity for the six months ended June 30, 2006 (unaudited)	5
	Consolidated Statements of Cash Flows for the six months ended June 30, 2006 and 2005 (unaudited)	6
	Notes to Consolidated Financial Statements (unaudited)	7
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	16
Item 3.	Quantitative and Qualitative Disclosures about Market Risks	27
Item 4.	Controls and Procedures	27
PART II—OTHER INFORMATION
Item 1.	Legal Proceedings	28
Item 1A.	Risk Factors	28
Item 2.	Unregistered Sale of Equity Securities and Use of Proceeds	28
Item 3.	Defaults Upon Senior Securities	28
Item 4.	Submission of Matters to Vote of Security Holders	28
Item 5.	Other Information	29
Item 6.	Exhibits	30
Signatures		31

2

Bronco Drilling Company, Inc. and Subsidiaries

CONSOLIDATED BALANCE SHEETS

(Amounts in thousands except share par value)

	June 30, 2006		December 31, 2005
	(Unaudited)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	2,511	$	17,039
Receivables Trade, net of allowance for doubtful accounts of $364 and $330 in 2006 and 2005, respectively		49,756		35,078
Contract drilling in progress		1,920		1,226
Current deferred income taxes		137		125
Prepaid expenses		888		485
Total current assets		55,212		53,953
PROPERTY AND EQUIPMENT - AT COST
Drilling rigs and related equipment		342,257		252,709
Transportation, office and other equipment		23,403		14,149
		365,660		266,858
Less accumulated depreciation		28,233		15,965
		337,427		250,893
OTHER ASSETS
Goodwill		21,280		20,774
Restricted cash		1,666		2,184
Intangibles, net, and other		3,685		2,716
		26,631		25,674
	$	419,270	$	330,520
LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable	$	16,461	$	10,847
Accrued liabilities
Payroll related		5,796		2,737
Deferred revenue and other		4,415		3,062
Income tax payable		2,205		1,372
Note payable		—		7,503
Current maturities of long-term debt		445		8,012
Total current liabilities		29,322		33,533
LONG-TERM DEBT, less current maturities		56,950		36,310
DEFERRED INCOME TAXES		28,201		21,341
COMMITMENTS AND CONTINGENCIES (Notes 5 and 7)
SHAREHOLDERS’ EQUITY
Common stock, $.01 par value, 100,000 shares authorized; 24,938 and 23,165 shares issued and outstanding at June 30, 2006 and December 31, 2005		250		232
Additional paid-in capital		277,925		238,557
Retained earnings		26,622		547
Total shareholders’ equity		304,797		239,336
	$	419,270	$	330,520

The accompanying notes are an integral part of these statements.

3

Bronco Drilling Company, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF OPERATIONS

(Amounts in thousands, except per share amounts)

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2006			2005			2006			2005
REVENUES
Contract drilling revenues	$	67,110		$	11,652		$	123,497		$	20,269
EXPENSES
Contract drilling		33,171			7,003			60,895			12,870
Depreciation and amortization		6,805			1,490			12,742			2,851
General and administrative		3,576			504			7,050			1,123
		43,552			8,997			80,687			16,844
Income from operations		23,558			2,655			42,810			3,425
OTHER INCOME (EXPENSE)
Interest expense		(280	)		(251	)		(365	)		(309	)
Loss from early extinguishment of debt		—			—			(1,000	)		—
Interest income		77			8			123			12
Other		121			—			170			—
		(82	)		(243	)		(1,072	)		(297	)
Income before income taxes		23,476			2,412			41,738			3,128
Income tax expense (benefit)		8,747			(116	)		15,663			(231	)
NET INCOME	$	14,729		$	2,528		$	26,075		$	3,359
Income per common share-Basic	$	0.59					$	1.08
Income per common share-Diluted	$	0.59					$	1.08
Weighted average number of shares outstanding-Basic		24,938						24,227
Weighted average number of shares outstanding-Diluted		24,958						24,252
Pro Forma C-Corporation Information (unaudited):
Historical income from operations before income taxes				$	2,412					$	3,128
Pro forma provision for income taxes					909						1,181
Pro forma income from operations				$	1,503					$	1,947
Pro forma income per common share-Basic and Diluted				$	0.11					$	0.15
Weighted average number of shares outstanding-Basic and Diluted					13,360						13,360

The accompanying notes are an integral part of these statements.

4

Bronco Drilling Company, Inc. and Subsidiaries

CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY

(Amounts in thousands)

For the six-months ended June 30, 2006

(Unaudited)

	Common Shares		Common Amount		Additional Paid In Capital		Retained Earnings		Total Shareholders’ Equity
Balance as of January 1, 2006		23,165	$	232	$	238,557	$	547	$	239,336
Stock issued in acquisition		73		1		1,815		—		1,816
Issuance of common stock in follow-on offering; net of related expenses of $577		1,700		17		36,212		—		36,229
Net income		—		—		—		26,075		26,075
Stock compensation		—		—		1,341		—		1,341
Balance as of June 30, 2006	$	24,938	$	250	$	277,925	$	26,622	$	304,797

The accompanying notes are an integral part of these statements.

5

Bronco Drilling Company, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Amounts in thousands)

	Six Months Ended June 30,
	2006			2005
	(Unaudited)
Cash flows from operating activities:
Net income	$	26,075		$	3,359
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation and amortization		12,986			2,881
Change in allowance for doubtful accounts		34			—
Gain on sale of asset		(946	)		—
Write off of debt issue costs		267			—
Stock compensation		1,341			—
Change in deferred income taxes		6,848			(231	)
Changes in current assets and liabilities:
Receivables		(14,711	)		(2,502	)
Contract drilling in progress		(694	)		—
Prepaid expenses		(403	)		(392	)
Other assets		203			(217	)
Accounts payable		(5,609	)		(319	)
Accrued expenses		4,412			318
Income taxes payable		833			—
Net cash provided by operating activities		30,636			2,897
Cash flows from investing activities:
Restricted cash account		518			(1,515	)
Business acquisitions		(16,028	)		—
Proceeds from sale of asset		950			—
Purchase of property and equipment		(67,548	)		(12,170	)
Net cash used in investing activities		(82,108	)		(13,685	)
Cash flows from financing activities:
Proceeds from borrowings ($18,000 from affiliate in 2005)		37,000			23,700
Payments of debt		(34,620	)		(1,800	)
Debt issue costs		(1,665	)		(143	)
Capital contributions		—			1,515
Proceeds from sale of common stock, net of offering costs of $577		36,229			—
Net cash provided by financing activities		36,944			23,272
Net decrease in cash and cash equivalents		(14,528	)		12,484
Beginning cash and cash equivalents		17,039			1,139
Ending cash and cash equivalents	$	2,511		$	13,623
Supplemental Disclosure:
Common stock issued for acquisition	$	1,816		$	—
Interest paid, net of amount capitalized		—			189
Income taxes paid		7,983			—
Notes issued for acquisition of cranes		3,190			—

The accompanying notes are an integral part of these statements.

6

Bronco Drilling Company and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(Amounts in thousands, except per share amounts)

1. Organization and Summary of Significant Accounting Policies

Business and Principles of Consolidation

Bronco Drilling Company, Inc. (the “Company”) provides contract land drilling services to oil and natural gas exploration and production companies, primarily in Oklahoma and Texas. 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, shareholders’ 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 June 30, 2006, the related results of operations and cash flows of the Company for the three and six months ended June 30, 2006 and 2005.

The results of operations for the three and six months ended June 30, 2006 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. 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 rigs and related equipment are three to 15 years. The depreciable life of other equipment is three years. Depreciation is not commenced until acquired or refurbished 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 $68,382 and $47,655 as of June 30, 2006 and December 31, 2005, respectively.

The Company capitalizes interest as a component of the cost of drilling rigs constructed for its own use. For the six months ended June 30, 2006 and year-ended 2005, the Company capitalized $2,031 and $1,207, respectively, of interest costs incurred during the construction periods of certain drilling rigs. Gains and losses on dispositions of fixed assets are included in operating revenues. Due to immateriality, most amounts are included in contract drilling revenue.

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.

In April 2006, the Company entered into an agreement to purchase an approximately 18,100 square foot building located in Oklahoma City, Oklahoma for a total purchase price of $3.0 million, less an amount equal to one-half of the principal reduction on the seller’s loan secured by the property between the effective date of the purchase agreement and the closing. The transaction remains subject to customary closing conditions, but the Company expects to close on January 2, 2007. At that time, the Company would pay $1.4 million in cash and assume existing debt of $1.6 million. The Company is currently subleasing a total of 9,050 square feet of the building from its current tenants until the closing date for a monthly rental of $8.

7

Income Taxes

Pursuant to 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 34% and effective state tax rate of 3.7% (net of Federal income tax effects) were used for the enacted tax rate for all periods.

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 in based primarily on the classification of the assets and liabilities generating the difference.

Pro Forma Income Taxes (unaudited)

Our predecessor, a limited liability company, was classified as a partnership for income tax purposes. Accordingly, income taxes on net earnings were payable by the members and are not reflected in historical financial statements, prior to our IPO on August 15, 2005 except for tax expense (benefit) associated with a taxable subsidiary. Pro forma adjustments are reflected to provide for income taxes in accordance with SFAS No. 109. For unaudited pro forma income tax calculations, deferred tax assets and liabilities were recognized for the future tax consequences attributable to differences between the assets and liabilities and 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 34% and effective state tax rate of 3.7% (net of Federal income tax effects) were used for the pro forma enacted tax rate for all periods. The pro forma tax effects are based upon currently available information and assume the Company had been a taxable entity in the periods presented. Management believes that these assumptions provide a reasonable basis for presenting the pro forma tax effects.

Net Income Per Common Share

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

Pro Forma Income Per Share (unaudited)

Pro forma income per basic and diluted common share is computed based on weighted average pro forma number of basic and diluted shares assumed to be outstanding during the periods prior to our IPO on August 15, 2005. Pro forma basic and diluted income per share is presented for the predecessor’s three and six months ended June 30, 2005 on the basis of 13,360 shares issued to our founder in the merger immediately prior to our initial public offering in August 2005.

Stock-based Compensation

The Company adopted SFAS No. 123(R), “Share-Based Payment” upon granting its 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. Compensation expense was $811 and $1,341 for the three and six months ended June 30, 2006.

Recent Accounting Pronouncements

In June 2006, the Financial Accounting Standards Board (“FASB”) issued FASB Interpretation No. 48 (“FIN 48”),Accounting For Uncertainty in Income Taxes. This Interpretation clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with SFAS No. 109,“Accounting for Income Taxes.”This Interpretation 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. This Interpretation also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. This Interpretation is effective for fiscal years beginning after December 15, 2006. We do not expect the adoption of FIN 48 to have a material impact on our financial position or results of operation and financial condition.

8

2. Acquisitions

In July 2005, the Company acquired all the membership interests in Strata Drilling, L.L.C. and Strata Property, L.L.C. (collectively “Strata”) and a related rig yard. Included in these acquisitions were two operating rigs, one rig that was being refurbished, related structures, equipment and components and a 16 acre yard in Oklahoma City, Oklahoma used for equipment storage and refurbishment of inventoried rigs. The aggregate purchase price was $20,000, of which $13,000 was paid in cash and $7,000 was paid in the form of promissory notes issued to the sellers. The Company funded the cash portion of the purchase price with a $13,000 loan from Theta Investors, LLC, formerly Alpha Investors LLC, an entity controlled by Wexford Capital, LLC (“Wexford”), the Company’s equity sponsor. The outstanding principal balance of the Alpha loan was paid in full on August 22, 2005 with proceeds from our initial public offering. This purchase was accounted for as an acquisition of a business, and the results of operations of the acquired business have been included in our statement of operations since the date of acquisition. We allocated the purchase price to property and equipment and related assets based on their relative fair values at the date of acquisition.

The $7,000 original aggregate outstanding principal balance of the promissory notes issued to the sellers was automatically reduced by the amount of any costs and expenses the Company paid in connection with the refurbishment of one of the rigs it acquired from the sellers. The Company granted the sellers a security interest in this rig to secure its obligations under the notes. The outstanding principal balance on these notes did not bear any interest other than default interest in the event of a default. In January 2006, the rig was completed to the satisfaction of the Company and title passed at such point. Upon acceptance of the rig the outstanding balance of the note was paid in full (see Note 3).

In September 2005, the Company acquired all the outstanding common stock of Hays Trucking, Inc. for $3,000 in cash, which includes the repayment of $1,900 of debt owed by Hays Trucking, and the issuance of 65 shares of common stock with a fair value of $1,274 based on the closing stock price at the date of acquisition. In this acquisition, the Company acquired 18 trucks used to mobilize rigs to contracted drilling locations as well as other ancillary equipment. Approximately $286 of the purchase price was allocated to customer lists and is included in intangibles on the balance sheets at June 30, 2006 and December 31, 2005. Customer lists are being amortized over an expected life of four years.

In October 2005, the Company purchased 12 land drilling rigs from Eagle Drilling, L.L.C., and two of its affiliates (“Eagle”). This acquisition involved five operating rigs, seven inventoried rigs and rig equipment and parts for a purchase price of approximately $50,528. In connection with this acquisition, the Company leased the use of an additional rig refurbishment yard for a two-year term. The purchase price of $50,528, which includes approximately $528 of related transaction costs, was funded with a $7,528 from cash on hand and a $43,000 loan from Merrill Lynch Business Financial Services, Inc., as lender (see Note 4). The purchase price has been allocated to property and equipment totaling $33,838, goodwill of $16,037 and customer lists and relationships of $653. Goodwill decreased by $295 during the three months ended June 30, 2006 due to purchase price adjustments. Customer lists are being amortized over an expected life of four years. The entire amount allocated to goodwill is considered deductible for tax purposes.

In October 2005, the Company purchased 13 land drilling rigs from Thomas Drilling Company. (“Thomas”). This acquisition involved nine operating rigs, two rigs being refurbished, two inventoried rigs and rig equipment and parts for a purchase price of approximately $70,737, which includes approximately $2,737 of related transaction costs. In connection with this acquisition, the Company leased the use of an additional rig refurbishment yard for a six-month term, with the right to extend the term for an additional three years, and obtained an option to purchase the yard for $175. The purchase price was partially funded through a $50,000 loan from Theta Investors LLC, an entity controlled by Wexford. This loan was repaid in full on November 3, 2005 with a portion of the proceeds from the Company’s follow-on common stock offering which closed on November 2, 2005. The purchase price has been allocated to property and equipment totaling $64,708, goodwill of $4,863 and customer lists of $1,166. Goodwill increased by $7 during the three months ended June, 2006 due to purchase price adjustments. Customer lists are being amortized over an expected life of four years. The entire amount allocated to goodwill is considered deductible for tax purposes.

On January 18, 2006, the Company completed the acquisition of six land drilling rigs and certain other assets, including heavy haul trucks and excess rig equipment and inventory, from Big A Drilling, L.L.C. (“Big A”). The results of Big A’s operations have been included in the consolidated financial statements since that date. The purchase price for the assets consisted of $16,028 in cash and 73 shares of our common stock with a fair market value of $1,816. At closing, the Company also entered into a lease agreement with an affiliate of Big A under which it leased a rig refurbishment yard located in Woodward, Oklahoma. The lease had an initial term of six months, and the Company has the option to extend the initial term for a period of three years following the expiration of the initial term. The lease was extended through an amendment to December 31, 2006. The Company has the option to purchase the leased premises at any time during the term of the lease for $200. The purchase price has been allocated to property and equipment totaling $17,077, goodwill of $380 and customer lists of $387. Customer lists are being amortized over an expected life of four years. The entire amount allocated to goodwill is considered deductible for tax purposes.

9

The following table summarizes the allocation of purchase price to the Company’s acquisition of Big A:

Assets acquired:
Drilling equipment	$	16,724
Vehicles		353
Customer lists		387
Goodwill		380
	$	17,844

The following pro forma information gives effect to the Big A acquisition as though it was effective at the beginning of each year presented. It also gives effect to the Strata, Eagle and Thomas acquisitions as though they were effective at the beginning of 2005. Pro forma adjustments primarily relate to additional depreciation, amortization and interest costs. The information reflects the Company’s historical data and historical data from the acquired business for the periods indicated. The pro forma data may not be indicative of the results the Company would have achieved had it completed the acquisition at the beginning of each year presented, or that it may achieve in the future. The pro forma financial information should be read in conjunction with the accompanying historical financial statements. Pro forma income per basic and diluted common share is computed based on the weighted average pro forma number of basic and diluted shares assumed to be outstanding during the period. Pro forma per share information is presented for the three months ended June 30, 2006 on the basis of 24,938 and 24,958 weighted average shares issued basic and diluted. Pro forma per share information is presented for the six months ended June 30, 2006 on the basis of 24,227 and 24,252 weighted average shares issued basic and diluted. Pro forma per share information is presented for the three and six months ended June 30, 2005 on the basis of 13,360 shares issued to the Company’s founder, Wexford, and 73 shares issued in the Big A aquisition. Dilutive pro forma effect is given to shares which are issuable upon the exercise of outstanding options under the Company’s employee stock option plan.

	Three Months Ended June 30,				Six Months Ended June 30,
	2006		2005		2006		2005
Total revenues	$	67,110	$	27,871	$	124,322	$	52,366
Net income (loss)	$	14,729	$	1,762	$	25,308	$	1,827
Net income (loss) per common share:
Basic	$	0.59	$	0.13	$	1.04	$	0.14
Diluted	$	0.59	$	0.13	$	1.04	$	0.14

3. Notes Payable

Notes payable at December 31, 2005 consisted of advances under a $3,000 revolving line of credit with a bank (“Bank Note Payable”) and $7,000 original aggregate principal amount of notes payable to the sellers in the Strata acquisition (“Strata Note”). The Bank Note Payable bears interest based on JPMorgan Chase prime. Interest on the Bank Note Payable is due monthly with outstanding principal due November 1, 2006 and is collateralized by the Company’s accounts receivable. The Bank Note Payable was paid in full in January 2006 (See Note 4).

The $7,000 original aggregate principal balance of the Strata Note issued to the sellers was automatically reduced by the amount of any costs and expenses the Company paid in connection with the refurbishment of one of the rigs it acquired from the sellers. Payment of the outstanding balance of the Strata Note was due and payable upon satisfactory completion of the refurbishment of this rig. The Company granted the sellers a security interest in this rig to secure its obligations under the Strata Note. The outstanding aggregate principal balance on the Strata Note did not bear any interest other than default interest in the event of a default. The amount due on the Strata Note, net of costs and expenses of $2,497 paid by the Company, was $4,503 at December 31, 2005. The Strata Note was paid in full in January 2006 (See Note 2).

10

4. Long-term Debt

Long-term debt consists of the following:

	June 30, 2006		December 31, 2005
Note payable to Merrill Lynch Capital, collateralized by the Company’s assets, payable in sixty monthly installments equal to one sixtieth of the outstanding principal on January 1, 2006 plus interest at a floating rate equal to LIBOR plus 2.71%. Paid off on January 13, 2006 (1)	$	—	$	43,000
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%, with various due dates (2)		4,395		1,322
Revolving credit facility with Fortis Capital, collateralized by the Company’s assets, and matures on January 13, 2009. Loans under the revolving credit facility bear interest at variable rates as defined in the credit agreement (3)		53,000		—
		57,395		44,322
Less current installments		445		8,012
	$	56,950	$	36,310

(1) On September 19, 2005, the Company entered into a Term Loan and Security Agreement with Merrill Lynch Capital, a division of Merrill Lynch Business Financial Services, Inc., as lender (“Merrill Lynch” or the “lender”). The term loan provided for a term installment loan in an aggregate amount not to exceed $50,000 and provided for a commitment by Merrill Lynch to advance funds from time to time until December 31, 2005. The outstanding balance under the term loan could not exceed 60% of the net orderly liquidation value of the Company’s operating land drilling rigs. Proceeds of the term loan were to be used to replenish working capital for general business purposes, finance improvements to and the refurbishment of land drilling rigs, and to acquire additional land drilling rigs.

The term loan bore interest on the outstanding principal balance at a variable per annum rate equal to LIBOR plus 271 basis points. For the period from September 19, 2005 to January 1, 2006, interest only was payable monthly on the outstanding principal balance. Commencing February 1, 2006, the outstanding principal and interest on the term loan was to be payable in sixty consecutive monthly installments, each in an amount equal to one sixtieth of the outstanding principal balance on January 1, 2006 plus accrued interest on the outstanding principal balance. Any outstanding principal and accrued but unpaid interest would have become immediately due and payable in full on January 1, 2011. The Company’s obligations under the term loan were collateralized by a first lien and security interest on substantially all of the Company’s assets and were guaranteed by each of the Company’s principal subsidiaries. The term loan included usual and customary restrictive negative covenants and requires the Company to meet certain financial covenants, including maintaining (1) a minimum “Fixed Charge Coverage Ratio” and (2) a maximum “Total Debt to EBITDA Ratio” as defined in the agreement. The Company was in compliance with all covenants at December 31, 2005. In January 2006, all borrowings were repaid in full and the term loan and security agreements were terminated at such time.

(2) 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 term loans provide for term installment loans in an aggregate amount not to exceed $4,512. The proceeds of the term loans were used to purchase four cranes.

(3) On January 13, 2006, the Company entered into a $150,000 revolving credit facility with Fortis Capital Corp., as administrative agent, lead arranger and sole bookrunner, and a syndicate of lenders, which included The Royal Bank of Scotland plc, The CIT Group/Business Credit, Inc., Calyon Corporate and Investment Bank, Merrill Lynch Capital, Comerica Bank and Caterpillar Financial Services Corporation. The revolving credit facility matures on January 13, 2009. Loans under the revolving credit facility bear interest at 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 the agreement. The Company’s obligations under the term loan were collateralized by substantially all of the Company’s assets. Our initial borrowings under this revolving credit facility were used to fund a portion of the Big A acquisition, and to repay in full borrowings under our term loan with Merrill Lynch Capital and our revolving line of credit with International Bank of Commerce.

The revolving credit facility contains customary covenants for facilities of such type, including among other things covenants that restrict our ability to make capital expenditures, 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 1.75 to 1.00 and a maximum total leverage ratio of 2.00 to 1.00. The Company was in compliance with all covenants at June 30, 2006.

Long-term debt maturing each year subsequent to June 30, 2006 is as follows:

2007	$	445
2008		477
2009		53,512
2010		548
2011		560
2011 and thereafter		1,853
	$	57,395

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5. Workers’ Compensation

The Company is insured under a large deductible workers’ compensation insurance policy. The policy generally provides for a $250 deductible per covered accident. Due to the high deductible, the policy requires the Company to maintain a letter of credit with a bank. At June 30, 2006 and December 31, 2005, the Company had deposits of $1,666 and $2,184, respectively, with a bank collateralizing the letter of credits. The deposits are reflected in restricted cash.

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 $50 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 June 30, 2006 and December 31, 2005 included approximately $308 and $170, respectively, for our estimate of incurred but not reported costs related to the self-insurance portion of our health insurance.

6. Transactions with Affiliates

Effective April 1, 2005, the Company entered into an administrative services agreement with its affiliate Gulfport Energy Corporation (“Gulfport”). Under this agreement, Gulfport agreed to provide certain services to the Company, including accounting, human resources, legal and technical support services. In return for the services, the Company agreed to pay Gulfport an annual fee of approximately $414 payable in equal monthly installments during the term of this agreement. In addition, the Company leased approximately 1,200 square feet of office space from Gulfport for the Company’s headquarters for an annual rent of $21 payable in equal monthly installments. The services the Company receives under the administrative services agreement and the fees for such services can be amended by mutual agreement of the parties. In January 2006, the Company reduced the level of administrative services being provided by Gulfport and increased its office space to approximately 2,500 square feet. As a result, the Company’s annual fee for administrative services was reduced to approximately $150 and its annual rental was increased to approximately $44. The administrative services agreement has a three-year term, and upon expiration of that term the agreement will continue on a month-to-month basis until cancelled by either party with at least 30 days prior written notice. The administrative services agreement is terminable (1) by the Company at any time with at least 30 days prior written notice to Gulfport and (2) by either party if the other party is in material breach of the agreement and such breach has not been cured within 30 days of receipt of written notice of such breach. The Company terminated the administrative services agreement effective April 1, 2006. The Company paid Gulfport approximately $0 and $49 in consideration for these services during the three and six months ended June 30, 2006, respectively. At June 30, 2006 and December 31, 2005, approximately $49 and $47, respectively, was owed to Gulfport and included in accounts payable. Prior to entry into this administrative services agreement, the Company reimbursed Gulfport for its dedicated employee time, office space and general and administrative costs based upon the pro rata share of time its employees spent performing service for the Company.

Additionally, the Company provided contract drilling services totaling $3,082 and $5,821 to affiliated entities during the three and six months ended June 30, 2006, respectively. Certain borrowings for acquisitions (see Note 2) were from affiliates.

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7. Commitments and Contingencies

The Company currently has a lawsuit pending in which the Company sued the defendant, an oil and gas operating company, for approximately $942 as a result of the defendant’s refusal to make payment pursuant to the terms of its drilling contract. The defendant has countersued for damages in excess of $2,800, alleging breach of contract, negligence, gross negligence and breach of warranties. The trial date has been set for November 13, 2006. The Company is vigorously prosecuting its claims and defending against the counterclaims in this matter, and will continue to file appropriate responses, motions and documents as necessary. At this time, it is not possible to predict the outcome of this matter. An allowance of $146 has been provided for a portion of the amounts receivable under the drilling contract. No amounts have been accrued for damages sought in the counterclaim. Should the amounts ultimately not be collected or if any amounts are due under the counterclaims then additional expenses will be recorded.

Various other 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.

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 June 30, 2006		Six Months Ended June 30, 2006
Basic:
Net income	$	14,729	$	26,075
Weighted average shares		24,938		24,227
Earnings per share	$	0.59	$	1.08
Diluted:
Net income	$	14,729	$	26,075
Weighted average shares:
Outstanding		24,938		24,227
Options		20		25
		24,958		24,252
Income per share	$	0.59	$	1.08

The weighted average number of diluted shares excludes 99,260 and 100,459 shares for the three and six months ended June 30, 2006 for options due to their antidilutive effects.

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9. Equity Transactions

Effective January 18, 2006, the Company issued 73 shares of common stock to the equity owners of Big A in connection with the Company’s acquisition of the assets of Big A . (See Note 2).

In March 2006, the Company closed a public offering of 3,450 shares of common stock at a price of $22.75 per share. In the offering, a total of 1,700 shares were sold by the Company and 1,750 shares were sold by the selling stockholder. The offering included a total of 450 shares purchased pursuant to the underwriters’ overallotment option granted by the selling stockholder, which was exercised in full on March 27, 2006. The offering resulted in net proceeds to the Company of approximately $36,229, excluding offering expenses of $577. The Company did not receive any proceeds from the sale of shares by the selling stockholder.

10. Stock Options and Stock Option Plan

The Company’s 2005 Stock Incentive Plan was adopted on July 20, 2005 and amended on November 16, 2005 (the “2005 Plan”) which is described below. The compensation cost that has been charged against income before taxes was $811 and $1,341 for the three and six months ended June 30, 2006, respectively. The total income tax benefit recognized in the income statement for share-based compensation arrangements was $306 and $506 for the three and six months ended June 30, 2006. These options are reported as equity instruments and their fair value is amortized to expense using the straight line method over the vesting period. The shares of stock issued once the options are exercised will be from authorized but unissued common stock.

The purpose of the 2005 Plan was to enable the Company, and any of its affiliates, to attract and retain the services of the types of employees, consultants and directors who will contribute to its long-range success and to provide incentives which are linked directly to increases in share value which will inure to the benefit of the Company’s stockholders. The 2005 Plan provided a means by which eligible recipients of awards may be given an opportunity to benefit from increases in value of the Company’s common stock through the granting of incentive stock options and nonstatutory stock options. Eligible award recipients under the 2005 Plan were employees, consultants and directors of the Company and its affiliates. Incentive stock options under the 2005 Plan could be granted only to employees. Awards other than incentive stock options under the 2005 Plan could be granted to employees, consultants and directors. The shares that may be issued upon exercise of the options will be from authorized but unissued common stock, and the maximum aggregate amount of such common stock which could be issued upon exercise of all awards under the plan, including incentive stock options, could not exceed 1,000,000 shares, subject to adjustment to reflect certain corporate transactions or changes in the Company’s capital structure.

The fair value of each option award is estimated on the date of grant using a Black Scholes valuation model that uses the assumptions noted in the following table. Expected volatilities are based on the historical volatility of a selected peer and other factors. The majority of the Company’s options are held by employees that make up one group with similar expected exercise behavior for valuation purposes. The expected term of options granted is estimated based on an average of the vesting period and the contractual period. The risk-free rate for periods within the contractual life of the option is based on the U.S. Treasury yield curve in effect at the time of the grant.

Under the 2005 Stock Incentive Plan, employee stock options become exercisable in equal monthly installments over a three-year period, and all options generally expire ten years after the date of grant. The 2005 Plan provides that all options must have an exercise price not less than the fair market value of the Company’s common stock on the date of the grant. The following table provides information relating to outstanding stock options for the six months ended June 30, 2006:

	June 30, 2006
Weighted average expected volatility	49	%
Weighted average expected life in years	5.77
Weighted average risk free interest rate	4.65	%

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The Company has not declared dividends since it became a public company and does not intend to do so in the foreseeable future, and thus did not use a dividend yield. In each case, the actual value that will be realized, if any, will depend on the future performance of the common stock and overall stock market conditions. There is no assurance that the value an optionee actually realizes will be at or near the value estimated using the Black–Scholes model. The following table provides information relating to activity in the 2005 Plan during the six months ended June 30, 2006:

	Shares	Weighted Average Exercise Price per Share		Weighted Average Remaining Contractual Life	Aggregate Intrinsic Value
Options outstanding at December 31, 2005	574	$	18.91
Granted	426		23.59
Exercised	—		—
Forfeited/expired	30		19.21
Options outstanding at June 30, 2006	970	$	20.46	9.40	$	417
Options fully vested and exercisable at June 30, 2006	207	$	19.50	9.30	$	288

	Shares	Weighted Average Grant Date Fair Value		Aggregate Grant Date Fair Value
Options nonvested at December 31, 2005	511	$	9.77		4,998
Granted	426		12.04	$	5,122
Vested	144		10.37		1,497
Forfeited/expired	30		9.88		296
Options nonvested at June 30, 2006	763	$	10.61	$	8,092

As of June 30, 2006, there was $8,092 of total unrecognized compensation cost related to nonvested share-based compensation arrangements granted under the 2005 Plan. That cost is expected to be recognized over a weighted-average period of 1.82 years.

The Company’s board of directors and a majority of the Company’s stockholders approved the Company’s 2006 Stock Incentive Plan (the “2006 Plan”) effective April 20, 2006. No further awards will be made under the 2005 Plan. The purpose of the 2006 Plan provides a means by which eligible recipients of awards may be given an opportunity to benefit from increases in value of the Company’s common stock through the granting of one or more of the following awards: (1) incentive stock options, (2) nonstatutory stock options, (3) restricted awards, (4) performance awards and (5) stock appreciation rights. The maximum aggregate amount of the Company’s common stock which may be issued upon exercise of all awards under the 2006 Plan, may not exceed 2,500,000 shares, less 1,000,000 shares underlying options granted to employees under the 2005 Plan prior to the adoption of the 2006 Plan. As of June 30, 2006, no awards had been granted under the 2006 Plan.

11. Employee Benefit Plans

The Company implemented a new 401(k) retirement plan for its eligible employees during 2006. 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 and six months ended June 30, 2006 were $202 and $274, respectively.

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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 (the “SEC”) on March 7, 2006 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 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 services to oil and natural gas exploration and production companies. We currently own a fleet of 64 land drilling rigs, of which 47 are operating, four are in the process of being refurbished and 13 are held in inventory. In addition to the four rigs in the process of being refurbished, we plan on refurbishing one additional rig from our current inventory during 2006. We continue to focus our refurbishment program on our more powerful rigs, with 1,000 to 2,000 horsepower, which are capable of drilling to depths between 15,000 and 25,000 feet. We also own a fleet of 60 trucks used to transport our rigs.

We commenced operations in 2001 with the purchase of one stacked 650-horsepower rig that we refurbished and deployed. We subsequently made selective acquisitions of both operational and inventoried rigs, as well as ancillary equipment. Our most recent acquisition was completed in January 2006 when we purchased six land drilling rigs and certain other assets, including heavy haul trucks and excess equipment, from Big A Drilling Company, L.C. for $16.3 million in cash and 72,571 shares of our common stock. In October 2005, we purchased 12 land drilling rigs from Eagle Drilling, L.L.C. for approximately $50.0 million and 13 land drilling rigs from Thomas Drilling Co. for approximately $68.0 million. These transactions not only increased the size of our rig fleet, but also expanded our operations to the Barnett Shale trend in North Texas and the Palo Duro Basin in West Texas. In July 2005, we completed a transaction with Strata Drilling, L.L.C. and Strata Property, L.L.C. in which we acquired, among other assets, three land drilling rigs and a 16 acre storage and refurbishment yard for $20.0 million.

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 18 inventoried drilling rigs since November 2003. Upon completion of refurbishment, the rigs either met or exceeded our operating expectations. 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 four rig refurbishment yards, significantly reduces our reliance on outside machine shops and the attendant risk of third-party delays in our rig refurbishment program.

We currently operate in Oklahoma, Kansas, the Barnett Shale and Cotton Valley trends and Palo Duro Basin in Texas, the Williston Basin in North Dakota and the Piceance Basin in Colorado. A majority of the wells we have drilled for our customers have been drilled in search of natural gas reserves. Natural gas is often found in deep and complex geologic formations that generally require higher horsepower, premium rigs and experienced crews to reach targeted depths. Our current fleet of 64 rigs includes 37 rigs ranging from 950 to 2,500 horsepower. Accordingly, such rigs can, or in the case of inventoried rigs upon refurbishment will be able to, reach the depths required to explore for deep natural gas reserves. Our higher horsepower rigs can also drill horizontal wells, which are increasing as a percentage of total wells drilled in North America. We believe our premium rig fleet, rig inventory and experienced crews position us to benefit from the strong natural gas drilling activity in our core operating areas. The following table sets forth information regarding our drilling fleet as of August 10, 2006:

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Rig	Design	Approximate Drilling Depth (ft)	Type	Horsepower
Working Rigs
19	Mid Continent U-1220 EB	25,000	Electric	2,500
18	Gardner Denver 1500E	25,000	Electric	2,000
17	Skytop Brewster NE-95	20,000	Electric	1,700
12	Gardner Denver 1100E	18,000	Electric	1,500
25	Mid Continent U-914	18,000	Electric	1,500
16	Oilwell840E	18,000	Electric	1,400
20	Mid Continent U-914-EC	18,000	Electric	1,400
21	Mid Continent U-914-EC	18,000	Electric	1,400
15	Mid Continent U-712-EA	16,000	Electric	1,200
14	Mid Continent U-712-EA	16,000	Electric	1,200
77	Ideco 711	16,000	Mechanical	1,200
78	Seaco 1200	12,000	Mechanical	1,200
56	BDW 800 MI	16,500	Mechanical	1,100
60	Skytop Brewster N46	14,000	Mechanical	1,100
57	Continental Emsco D-3	15,000	Mechanical	1,100
11	Gardner Denver 800E	15,000	Electric	1,000
10	Gardner Denver 800E	15,000	Electric	1,000
43	National 80B	15,000	Mechanical	1,000
8	National 80-UE	15,000	Electric	1,000
23	Continental Emsco D-3	15,000	Electric	1,000
3	Cabot 900	10,000	Mechanical	950
4	Skytop Brewster N46	14,000	Mechanical	950
51	Skytop Brewster N42	12,000	Mechanical	850
52	Continental Emsco G-500	11,000	Mechanical	850
53	Skytop Brewster N42	12,000	Mechanical	850
54	Skytop Brewster N46	13,000	Mechanical	850
55	National 50-A	12,000	Mechanical	850
59	Skytop Brewster N46	13,000	Mechanical	850
61	National 50-A	11,500	Mechanical	850
41	Skytop-Brester N-46	13,500	Mechanical	800
58	National N55	12,000	Mechanical	800
72	Skytop Brewster N45	10,000	Mechanical	750
75	Ideco 750	14,000	Mechanical	750
76	National N55	12,000	Mechanical	700
42	Gardner Denver 500	12,000	Mechanical	650
94	Skytop Brewster N45	9,000	Mechanical	650
95	Unit U-15	8,000	Mechanical	650
9	Gardner Denver 500	11,000	Mechanical	650
7	Mid Con U36A	12,000	Mechanical	650
6	Mid Con U36A	12,000	Mechanical	650
5	Mid Con U36A	12,000	Mechanical	650
92	Weiss 45	8,000	Mechanical	450
70	National T32	6,000	Mechanical	450
2	Cardwell L-350	6,000	Mechanical	400
91	Ideco H-35	8,000	Mechanical	400
96	Ideco H-35	8,000	Mechanical	400
93	Ideco H-30	8,000	Mechanical	350
Rigs Being Refurbished
74	National 1320	20,000	Electric	2,000
27	Mid Continent U-914	18,000	Electric	1,500
22	Continental Emsco D-3	15,000	Electric	1,000
62	Brewster N-75	12,000	Mechanical	1,000
Rigs In Inventory
24	Skytop Brewster N-12	25,000	Electric	2,000
73	Ideco Super 7-11	18,000	Mechanical	2,000
29	Mid Continent U-914	18,000	Electric	1,500
36	Continental Emsco C-1	18,000	Electric	1,500
26	Ideco 1200E	14,000	Electric	1,200
28	Ideco 1200E	14,000	Electric	1,200
31	National 80 UE	14,000	Electric	1,000
30	Mid Continent U-914	18,000	Electric	1,500
32	Mid Continent U-914	18,000	Electric	1,500
33	Continental Emsco D-3	15,000	Electric	1,000
35	Supboz 7-11	12,000	Electric	1,000
34	Ideco 900E	12,000	Electric	1,000
97	Brewster N-42	12,000	Mechanical	700
Excess Rig Inventory
79	Oilwell 500	10,000	Mechanical	500
80	Mac 400	6,000	Mechanical	400
81	Mid Continent U34B	6,000	Mechanical	400
82	Ideco H-35 Hydrair	6,000	Mechanical	400

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We earn our contract drilling revenues by drilling oil and natural gas wells for our customers. 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 26 of our rigs operating under agreements with 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 in our industry is operating rig utilization. We compute operating 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 earn a fixed amount of revenue based on the mobilization rate stated in the contract. We begin earning our contracted daywork rate when we begin drilling the well. Occasionally, in periods of increased demand, we will receive a percentage of the contracted dayrate during the mobilization period. We account for these revenues as mobilization fees.

For the three and six-months ended June 30, 2006 and 2005 and years ended December 31, 2005, 2004 and 2003, our rig utilization rates, revenue days and average number of operating rigs were as follows:

	Three Months Ended June 30,				Six Months Ended June 30,				Years Ended December 31,
	2006		2005		2006		2005		2005		2004		2003
Average number of operating rigs	43		12		41		12		17		9		7
Revenue days	3,631		1,039		6,985		1,967		5,781		2,733		1,898
Utilization Rates	92	%	95	%	94	%	94	%	95	%	81	%	76	%

The annual increases in the number of revenue days in each of 2005, 2004 and 2003 and the period-to-period increase in the three and six months ended June 30, 2006 as compared to the same periods in 2005 are attributable to the increases in the size of our operating rig fleet. Based on our plan to refurbish and deploy our inventoried rigs and current market conditions, we anticipate continued growth in revenue days and stable utilization rates for the balance of 2006.

We devote substantial resources to maintaining, upgrading and expanding our rig fleet. We have completed the refurbishment of seven rigs to date in 2006 and plan on completing the refurbishment of five additional inventoried rigs by the end of 2006. We plan on refurbishing twelve inventoried rigs during 2007.

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Market Conditions in Our Industry

The United States contract land drilling services industry is highly cyclical. Volatility in oil and natural gas prices can produce wide swings in the levels of overall drilling activity in the markets we serve and affect the demand for our drilling services and the dayrates we can charge for our 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 number of wells oil and natural gas exploration and production companies decide to drill.

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 June 30,		At December 31,
	2006		2005		2004		2003
Crude oil (Bbl)	$	73.93	$	61.04	$	43.45	$	32.52
Natural gas (Mmbtu)	$	6.10	$	11.23	$	6.15	$	6.19
U.S. Land Rig Count		1,577		1,391		1,138		1,022

We believe capital spent on incremental natural gas production will be driven by an increase in hydrocarbon demand as well as shortages in supply of natural gas. The Energy Information Administration (EIA) has estimated that U.S. consumption of natural gas exceeded domestic production by 21% in 2005 and forecasts that U.S. consumption of natural gas will exceed U.S. domestic production by 26% in 2010. The EIA also predicts that “lower 48 production of unconventional natural gas is expected to be a major contributor to growth in U.S. natural gas supplies.” However, “LNG imports, Alaskan natural gas production, and lower 48 production from unconventional sources are not expected to increase sufficiently to offset the impacts of resource depletion and increased demand.” In addition, a study published by the National Petroleum Council in September 2003 concluded from drilling and production data over the preceding ten years that average “initial production rates from new wells have been sustained through the use of advanced technology; however, production declines from these initial rates have increased significantly; and recoverable volumes from new wells drilled in mature producing basins have declined over time.” The report went on to state that “without the benefit of new drilling, indigenous supplies have reached a point at which U.S. production declines by 25% to 30% each year” and predicted that in ten years 80% of gas production “will be from wells yet to be drilled.” We believe all of these factors tend to support a higher natural gas price environment, which should create strong incentives for oil and natural gas exploration and production companies to increase drilling activity in the U.S. Consequently, these factors may result in higher rig dayrates and rig utilization.

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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 our management to make estimates and judgments that affect the reported amounts of our 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—We earn our 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 we believe 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 operation, 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. During 2005, we experienced no losses on the five footage contracts we completed. We did not drill any wells pursuant to footage contracts during the six months ended June 30, 2006. We are more likely to encounter losses on footage contracts in years in which revenue rates are lower for all types of contracts.

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 June 30, 2006 or December 31, 2005. At June 30, 2006 and December 31, 2005, our contract drilling in progress totaled $1.9 million and $1.2 million, respectively, all of which relates to the revenue recognized but not yet billed or costs deferred on daywork contracts in progress at June 30, 2006 and December 31, 2005, respectively.

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.

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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 and have not extended payment terms beyond 60 days for any of our contracts in the last three years. Our allowance for doubtful accounts was $364,000 and $330,000 at June 30, 2006 and December 31, 2005, 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 assess the impairment of property and equipment, intangible assets and goodwill whenever events or circumstances indicate that the carrying value 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, intangible assets and goodwill 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, intangible assets and goodwill to its fair market value. A one percent write-down in the cost of our drilling equipment, intangible assets and goodwill, at June 30, 2006, would have resulted in a corresponding decrease in our net income of approximately $2.3 million.

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 15 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 rigs refurbished for our own use. During the six months ended June 30, 2006 and year ended December 31, 2005, we capitalized approximately $2.0 million and $1.2 million, respectively.

Deferred Taxes—We primarily provide deferred taxes for the basis difference in our property and equipment 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 June 30, 2006 and December 31, 2005 included accruals of approximately $1.1 million and $16,000, respectively, for costs under our workers’ compensation insurance. We have a deductible of $250,000 per covered accident under our workers’ compensation insurance. Our insurance policy requires us to maintain a letter of credit to cover payments by us of that deductible. As of June 30, 2006 and December 31, 2005, we had a $1.7 million and $2.2 million letter of credit for which we have a deposit account collateralizing the letter 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.

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Recent Highlights

The following are highlights that impacted our liquidity or results of operations for the six months ended June 30, 2006:

• 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 bookrunner, and a syndicate of lenders, which include The Royal Bank of Scotland plc, The CIT Group/Business Credit, Inc., Calyon Corporate and Investment Bank, Merrill Lynch Capital, Comerica Bank and Caterpillar Financial Services Corporation. The revolving credit facility matures on January 13, 2009.

• On January 18, 2006, we completed the acquisition of six land drilling rigs and certain other assets, including heavy haul trucks and excess rig equipment and inventory, from Big A Drilling.

• On March 29, 2006, we closed a public offering of a total of 3,450,000 shares of our common stock at a price of $22.75 per share. In the offering a total of 1,700,000 shares were sold by us and 1,750,000 shares were sold by Bronco Drilling Holdings, L.L.C., an entity controlled by Wexford. We received net proceeds of approximately $36.2 million from the offering, after underwriting discounts and commissions and before offering expenses.

Results of Operations

Three Months Ended June 30, 2006 Compared to Three Months Ended June 30, 2005

Contract Drilling Revenue. For the three months ended June 30, 2006, we reported contract drilling revenues of $67.1 million, a 476% increase from revenues of $11.7 million for the same period in 2005. The increase is primarily due to an increase in dayrates, revenue days and average number of rigs working for the three months ended June 30, 2006 as compared to the same period in 2005, partially offset by a decrease in utilization rates. Average dayrates for our drilling services increased $5,910, or 53%, to $17,147 for the three months ended June 30, 2006 from $11,237 in the same period in 2005. Revenue days increased 249% to 3,631 days for the three months ended June 30, 2006 from 1,039 days during the same period in 2005. Our average number of operating rigs increased to 43 from 12, or 260%, for the three months ended June 30, 2006 as compared to the same period in 2005. The increase in the number of revenue days for the three months ended June 30, 2006 as compared to the same period in 2005 is attributable to the increase in the size of our operating rig fleet due to acquisitions and refurbishments. Utilization for the second quarter decreased from the same period in 2005 due to upgrades performed on five active rigs during the quarter. Based on our plans to refurbish and deploy our inventoried rigs and current market conditions, we anticipate continued growth in revenue days and stable utilization rates for the balance of 2006.

Contract Drilling Expense. Direct rig cost increased $26.2 million to $33.2 million for the three months ended June 30, 2006 from $7.0 million for the same period in 2005. This 374% increase is primarily due to the increase in revenue days and the increase in average number of operating rigs in our fleett for the three months ended June 30, 2006 as compared to the same period in 2005, partially offset by a decrease in utilization rates. As a percentage of contract drilling revenue, drilling expense decreased to 49% for the three-month period ended June 30, 2006 from 60% for the same period in 2005 due primarily to the escalation in dayrates.

Depreciation Expense. Depreciation expense increased $5.3 million to $6.8 million for the three months ended June 30, 2006 from $1.5 million for the same period in 2005. The increase is primarily due to the 257% increase in fixed assets, including the deployment of nine additional rigs from our inventory and the Strata, Eagle, Thomas and Big A acquisitions, as well as incremental increases in ancillary equipment, all of which occurred after the same period in 2005.

General and Administrative Expense. General and administrative expense increased $3.1 million to $3.6 million for the three months ended June 30, 2006 from $500,000 for the same period in 2005. The increase is the result of an increase in yard expense of $411,000, an increase in filing and printing fees of $125,000, an increase in stock compensation expense of $811,000, an increase in payroll costs of $946,000, and an increase in rent expense of $84,000. The increase in payroll is primarily due to our increased employee count due both to organic growth and acquisitions as well as selected wage increases.

Interest Expense. Interest expense increased $29,000 to $280,000 for the three months ended June 30, 2006 from $251,000 for the same period in 2005. The increase is due to an increase in the average debt outstanding for the quarter, partially offset by an increase in capitalization of interest expense related to our rig refurbishment program. We capitalized $902,000 of interest for the three months ended June 30, 2006 as compared to $264,000 for the same period in 2005 as part of our rig refurbishment program.

Tax Expense (Benefit). We recorded a tax expense of $8.7 million for the three months ended June 30, 2006, of which $3.5 million is deferred tax expense. This compares to a deferred tax benefit of $116,000 for the three months ended June 30, 2005. This increase is due primarily to our conversion from an LLC to a taxable entity in August 2005 in connection with our initial public offering and an increase in pre-tax net income.

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Six Months Ended June 30, 2006 Compared to Six Months Ended June 30, 2005

Contract Drilling Revenue. For the six months ended June 30, 2006, we reported contract drilling revenues of $123.5 million, a 509% increase from revenues of $20.3 million for the same period in 2005. The increase is primarily due to an increase in dayrates, revenue days and average number of rigs working for the six months ended June 30, 2006 as compared to the same period in 2005. Average dayrates for our drilling services increased $5,823, or 55%, to $16,413 for the six months ended June 30, 2006 from $10,590 in the same period in 2005. Revenue days increased 255% to 6,985 days for the six months ended June 30, 2006 from 1,967 days during the same period in 2005. Our average number of operating rigs increased to 41 from 12, or 255%, for the six months ended June 30, 2006 as compared to the same period in 2005. The increase in the number of revenue days for the six months ended June 30, 2006 as compared to the same period in 2005 is attributable to the increase in the size of our operating rig fleet due to acquisitions and refurbishments.

Contract Drilling Expense. Direct rig cost increased $48.0 million to $60.9 million for the six months ended June 30, 2006 from $12.9 million for the same period in 2005. This 373% increase is primarily due to the increase in revenue days and the increase in average number of operating rigs in our fleet for the six months ended June 30, 2006 as compared to the same period in 2005. As a percentage of contract drilling revenue, drilling expense decreased to 49% for the six-month period ended June 30, 2006 from 63% for the same period in 2005 due primarily to the escalation in dayrates.

Depreciation Expense. Depreciation expense increased $9.8 million to $12.7 million for the six months ended June 30, 2006 from $2.9 million for the same period in 2005. The increase is primarily due to the 257% increase in fixed assets, including the deployment of nine additional rigs from our inventory and the Strata, Eagle, Thomas and Big A acquisitions, as well as incremental increases in ancillary equipment, all of which occurred after the 2005 period.

General and Administrative Expense. General and administrative expense increased $6.0 million to $7.1 million for the six months ended June 30, 2006 from $1.1 for the same period in 2005. The increase is the result of an increase in yard expense of $735,000, an increase in filing and printing fees of $157,000, an increase in stock compensation expense of $1.3 million, an increase in payroll costs of $2.0 million, an increase in accounting fees of $252,000 and an increase in rent expense of $206,000. The increase in payroll is primarily due to our increased employee count due both to organic growth and acquisitions as well as selected wage increases.

Interest Expense. Interest expense increased $57,000 to $366,000 for the six months ended June 30, 2006 from $309,000 for the same period in 2005. The increase is due to an increase in the average debt outstanding for the quarter, partially offset by an increase in capitalization of interest expense related to our rig refurbishment program. We capitalized $2.0 million of interest for the six months ended June 30, 2006 as compared to $547,000 for the same period in 2005 as part of our rig refurbishment program.

Tax Expense (Benefit). We recorded a tax expense of $15.7 million for the six months ended June 30, 2006, of which $6.7 million is deferred tax expense. This compares to a deferred tax benefit of $231,000 for the six months ended June 30, 2005. This increase is due primarily to our conversion from an LLC to a taxable entity in August 2005 in connection with our initial public offering and an increase in pre-tax net income.

Liquidity and Capital Resources

Operating Activities. Net cash provided by operating activities was $30.6 million for the six months ended June 30, 2006 as compared to $2.9 million in 2005. The increase of $27.7 million from 2006 to 2005 was primarily due to increased cash receipts from customers, partially offset by higher cash payments to employees and 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 for investing activities was $82.1 million for the six-months ended June 30, 2006 as compared to $13.7 million for the same period in 2005. During the 2006 period, $16.2 million related to the Big A acquisition and $67.4 million was used to refurbish drilling rigs. These amounts were partially offset by $518,000 received from a restricted account that is used as security for a letter of credit issued to our workers’ compensation insurance carrier and $950,000 of proceeds received from sale of asset. For the six months ended June 30, 2005, we used $12.2 million to refurbish our drilling rigs and $1.5 million was placed in the restricted account relating to our workers’ compensation.

Financing Activities. Our cash flows provided by financing activities were $37.0 million for the six months ended June 30, 2006 as compared to $23.3 million for the same period in 2005. Our net cash provided by financing activities for the six months ended June 30, 2006 related primarily to net proceeds of approximately $36.2 million from our March 2006 public offering of common stock, borrowings of $37.0 million under our credit facility with Fortis Capital, partially offset by principal payments of $30.0 million under our credit facility with Fortis Capital and $4.6 million on a promissory note given in connection with our Strata acquisition. For the six months ended June 30, 2005, our net cash provided by financing activities related to borrowings of $5.7 from International Bank of Commerce, borrowings of $18.0 million from entities controlled by Wexford Capital LLC, or Wexford, principal payments on borrowings of $1.8 million to International Bank of Commerce, and capital contributions of $1.5 million from entities controlled by Wexford.

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

Debt Financing. On December 26, 2003, we entered into a credit facility with GECC which provided for term loan advances of up to $12.0 million. At September 24, 2004 and April 22, 2005, we amended our credit facility with GECC to increase the maximum amount of the terms loans to $18.0 million and then to $25.5 million, respectively. Borrowings under this facility bore interest at a rate equal to LIBOR plus 5.0% and were secured by substantially all of our property and assets, including our drilling rigs and associated equipment, and ownership interests in our subsidiaries, but excluding cash and accounts receivable.

Draws on the facility were required to be in $2.5 million increments each with a five-year term. Payments of principal and accrued but unpaid interest were due on the first day of each month. This credit facility, which was to mature on October 1, 2010, was repaid in full on August 29, 2005 with a portion of the proceeds from our initial public offering and the credit facility was terminated.

On July 1, 2004, we entered into a revolving line of credit with International Bank of Commerce with a borrowing base of the lesser of $2.0 million or 80% of current receivables. Borrowings under this line bore interest at a rate equal to the greater of 4.0% or JPMorgan Chase prime (effective rate of 7.25% at December 31, 2005). Accrued but unpaid interest was payable monthly. On January 1, 2005, we amended our line of credit with International Bank of Commerce to increase the borrowing base to the lesser of $3.0 million or 80% of current receivables. The line of credit had a maturity date of November 1, 2006. It was repaid in full in January 2006 with a portion of the proceeds from our new revolving credit facility and then terminated.

On February 15, 2005, we entered into a $5.0 million revolving credit facility with Solitair LLC, an entity controlled by Wexford. Borrowings under this facility bore interest at a rate equal to LIBOR plus 5.0%. Payment of principal and accrued but unpaid interest were due on the maturity date of the credit facility which was the later of (1) six months after the actual maturity date of our credit facility with GECC and (2) December 1, 2010. We repaid this facility in full on August 22, 2005 with a portion of the proceeds from our initial public offering and the facility was terminated.

In July 2005, we acquired all of the membership interests in Strata Drilling, L.L.C. and Strata Property, L.L.C. and a related rig yard for an aggregate of $20.0 million, of which $13.0 million was paid in cash and $7.0 million paid in the form of promissory notes issued to the sellers. We funded the cash portion of the purchase price with a $13.0 million loan from Alpha Investors LLC, an entity controlled by Wexford. The outstanding principal balance of the loan plus accrued but unpaid interest was due in full upon the earlier to occur of the completion of our initial public offering and the maturity of the loan on July 1, 2006. We repaid this loan in full on August 22, 2005 with a portion of the proceeds from our initial public offering. Borrowings under our loan with Alpha bore interest at a rate equal to LIBOR plus 5% until September 30, 2005, and thereafter were to bear interest at a rate equal to LIBOR plus 7.5%. The $7.0 million original aggregate principal balance of the promissory notes issued to the sellers was automatically reduced by the amount of any costs and expenses we paid in connection with the refurbishment of one of the rigs we acquired from the sellers. The amount due on these notes, net of costs and expenses paid by us, was $4.5 million at December 31, 2005. The outstanding balance of the loan was paid in full on January 5, 2006 upon completion of the refurbishment of this rig.

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On September 19, 2005, we entered into a term loan and security agreement with Merrill Lynch Capital, a division of Merrill Lynch Business Financial Services, Inc. The term loan provided for a term installment loan in an aggregate amount not to exceed $50.0 million and provided for a commitment by Merrill Lynch to advance funds from time to time until December 31, 2005. The outstanding balance under the term loan could not exceed 60% of the net orderly liquidation value of our operating land drilling rigs. On September 19, 2005, we borrowed $43.0 million under the term loan. A portion of these borrowings, together with proceeds from our initial public offering, were used to fund the Eagle acquisition. The term loan bore interest on the outstanding principal balance at a variable per annum rate equal to LIBOR plus 271 basis points (7.1% at December 31, 2005). For the period from September 19, 2005 to January 1, 2006, interest only was payable monthly on the outstanding principal balance. Commencing February 1, 2006, the outstanding principal and interest on the term loan were payable in 60 consecutive monthly installments, each in an amount equal to one sixtieth of the outstanding principal balance on January 1, 2006 plus accrued interest on the outstanding principal balance. The maturity date was January 1, 2011. Our obligations under the term loan were secured by a first lien and security interest on substantially all of our assets and were guaranteed by each of our principal subsidiaries. The term loan included usual and customary negative covenants and events of default for loan agreements of this type. The term loan also required us to meet certain financial covenants, including maintaining a minimum Fixed Charge Coverage Ratio and a maximum Total Debt to EBITDA Ratio. This term loan was repaid in full in January 2006 with a portion of the proceeds from our new revolving credit facility and the term loan was terminated.

On October 14, 2005, we entered into a loan agreement with Theta Investors, LLC, an entity controlled by Wexford, for purposes of funding a portion of the purchase price for the Thomas acquisition. The Theta loan provided maximum aggregate borrowings of up to $60.0 million, which borrowings bore interest at a rate equal to LIBOR plus 400 basis points until December 15, 2005 and, thereafter, at a rate equal to LIBOR plus 600 basis points. Payment of principal and accrued but unpaid interest was due on October 15, 2006. Our obligations under the Theta loan were guaranteed by each of our principal subsidiaries. We borrowed $50.0 million under this loan on October 14, 2005. We repaid this facility in full on November 3, 2005 with a portion of the proceeds from our follow-on public offering, which closed November 2, 2005.

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 bookrunner, and a syndicate of lenders, which include The Royal Bank of Scotland plc, The CIT Group/Business Credit, Inc., Calyon Corporate and Investment Bank, Merrill Lynch Capital, Comerica Bank and Caterpillar Financial Services Corporation. The revolving credit facility matures on January 13, 2009. Loans under the revolving credit facility bear interest at 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 the credit agreement. Our borrowings under this revolving credit facility were used to fund a portion of the Big A Drilling acquisition and to repay in full all outstanding borrowings under our term loan with Merrill Lynch Capital and our revolving line of credit with International Bank of Commerce.

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. Our 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 shares of capital stock of our direct and indirect subsidiaries.

The revolving credit facility contains customary covenants for facilities of such type, including among other things covenants that restrict our ability to make capital expenditures, 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 1.75 to 1.00 and a maximum total leverage ratio of 2.00 to 1.00. The revolving credit facility provides for mandatory prepayments under certain circumstances as more fully discussed in the revolving credit facility. The revolving credit facility contains various events of default, including failure to pay principal and interest when due, breach of covenants, materially incorrect representations, default under certain other agreements, bankruptcy or insolvency, the occurrence of specified ERISA events, entry of enforceable judgments against us in excess of $3.0 million not stayed, and the occurrence of a change of control. If an event of default occurs, all commitments under the revolving credit facility may be terminated and all of our obligations under the revolving credit facility could be accelerated by the lenders, causing all loans outstanding (including accrued interest and fees payable thereunder) to be declared immediately due and payable.

We are 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 2014 and have an weighted average annual interest rate of approximately 6.9%. The proceeds from these term loans were used to purchase cranes.

Issuances of Equity.In March 2006, we closed a public offering of 3,450,000 shares of our common stock at a price of $22.75 per share. In the offering, a total of 1,700,000 shares were sold by us and 1,750,000 shares were sold by the selling stockholder. The offering resulted in net proceeds to us of approximately $36.2 million, excluding offering expenses of $577,000. We did not receive any proceeds from the sale of shares by the selling stockholder.

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Capital Expenditures.

During 2005, we completed the refurbishment of four rigs, ranging from 950 to 2,500 horsepower. We incurred aggregate refurbishment costs of $21.9 million, ranging from $4.5 million to $6.6 million per rig, which were funded with borrowings under our various credit facilities and proceeds from our initial public offering.

In January 2006, we completed the refurbishment of a 1,700-horsepower electric drilling rig, which we designated Rig No. 17. We incurred approximately $6.0 million in refurbishment costs for this rig which we funded with proceeds from our November 2005 follow-on offering. We mobilized Rig No. 17 to West Oklahoma in January 2006.

In January 2006, we completed the refurbishment of a 1,200-horsepower electric drilling rig, which we designated Rig No. 15. We incurred approximately $6.4 million in refurbishment costs for this rig which we funded with proceeds from our November 2005 follow-on offering. We mobilized Rig No. 15 to East Texas in January 2006.

In January 2006, the refurbishment of a 1,000-horsepower mechanical rig was completed pursuant to a $7.0 million seller’s note incurred in the Strata acquisition. We designated this Rig No. 43 and repaid the note with proceeds from our November 2005 follow-on offering. We mobilized Rig No. 43 to East Texas in January 2006.

On January 18, 2006, we purchased six operating rigs and certain other assets, including heavy haul trucks and excess rig equipment and inventory, from Big A Drilling, L.C. The purchase price for the assets consisted of $16.3 million paid in cash and 72,571 shares of our common stock.

In March 2006, we completed the refurbishment of a 1,100-horsepower mechanical drilling rig, which we designated Rig No. 57. We incurred approximately $2.3 million in refurbishment costs for this rig which we funded with proceeds from our November 2005 follow-on offering. We mobilized Rig No. 57 to Eastern Oklahoma in March 2006.

In April 2006, we completed the refurbishment of a 1,400-horsepower electric drilling rig, which we designated Rig No. 20. We incurred approximately $7.8 million in refurbishment costs for this rig which we funded with proceeds from our November 2005 follow-on offering. We mobilized Rig No. 20 to East Texas in April 2006.

In May 2006, we completed the refurbishment of a 450-horsepower mechanical drilling rig, which we designated Rig No. 70. We incurred approximately $544,000 in refurbishment costs for this rig which we funded with proceeds from our November 2005 follow-on offering. We mobilized Rig No. 70 to West Oklahoma in May 2006.

In May 2006, we completed the refurbishment of a 1,400-horsepower electric drilling rig, which we designated Rig No. 21. We incurred approximately $7.0 million in refurbishment costs for this rig. We mobilized Rig No. 21 to Eastern Oklahoma in May 2006.

In June 2006, we completed the refurbishment of a 800-horsepower mechanical drilling rig, which we designated Rig No. 58. We incurred approximately $4.3 million in refurbishment costs for this rig. We mobilized Rig No. 58 to East Texas in June 2006.

In July 2006, we completed the refurbishment of a 1,000-horsepower electric drilling rig, which we designated Rig No. 23. We incurred approximately $7.2 million in refurbishment costs for this rig. We mobilized Rig No. 23 to Colorado in July 2006.

In July 2006, we completed the refurbishment of a 2,000-horsepower electric drilling rig, which we designated Rig No. 25. We incurred approximately $7.9 in refurbishment costs for this rig. We mobilized Rig No. 25 to Eastern Oklahoma in July 2006.

In April 2006, we entered into an agreement to purchase an approximately 18,100 square foot building located in Oklahoma City, Oklahoma for a total purchase price of $3.0 million, less an amount equal to one-half of the principal reduction on the seller’s loan secured by the property between the effective date of the purchase agreement and the closing. The transaction remains subject to customary closing conditions, but we expect to close on January 2, 2007. At that time, we would pay $1.4 million in cash and assume existing debt of $1.6 million. We intend to sublease a total of 9,050 square feet of the building from its current tenants commencing during the second quarter of 2006 and continuing until the closing date for a monthly rental of $8,341.

We intend to refurbish five additional inventoried rigs during the third and fourth quarters of 2006 at estimated costs (including drill pipe) ranging from $2.2 million to $7.3 million per rig. We continue to focus our refurbishment program on our more powerful rigs, generally with 1,000 to 2,000 horsepower, which are capable of drilling to depths between 15,000 and 25,000 feet. We plan on refurbishing twelve additional rigs in 2007. The timing of these refurbishments will depend upon market conditions and other factors, including our estimation of existing and anticipated demand and dayrates, our success in bidding for domestic contracts, including term contracts, and the expected time needed to complete the refurbishments. The actual cost of refurbishing our rigs will depend upon such factors as the availability of equipment, unforeseen engineering problems, work stoppages, weather interference, unanticipated cost increases, inability to obtain necessary certifications and approvals, shortages of skilled labor and the specific customer requirements.

We believe that cash flow from our operations and borrowings under our revolving credit facility will be sufficient to fund our operations for at least the next 12 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.

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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 new 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. An increase or decrease of 1% in the interest rate would have a corresponding decrease or increase in our net income (loss) of approximately $330,000 annually, based on the $53,000 million outstanding in the aggregate under our credit facility as of June 30, 2006.

Item 4. Controls and Procedures

Evaluation of Disclosure Control and Procedures. Under the direction of the Chief Executive Officer and the Chief Financial Officer, we have established disclosure controls and procedures that are designed to ensure that information required to be disclosed in the reports that we file or submit 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. The disclosure controls and procedures are also intended to ensure that such information is accumulated and communicated to our management, including the Chief Executive Officer and the Vice President and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosures.

As of June 30, 2006, an evaluation was performed under the supervision and with the participation of our management, including the Chairman and Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15 under the Securities Exchange Act of 1934. Based upon their evaluation, the Chairman and Chief Executive Officer and Chief Financial Officer have concluded that as of June 30, 2006, our disclosure controls and procedures are effective.

Changes in Internal Control over Financial Reporting. There have not been any changes in our internal control over financial reporting that occurred during the last fiscal quarter that have materially affected, or are reasonably likely to materially affect, internal control over financial reporting.

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PART II: OTHER INFORMATION

Item 1. Legal Proceedings

Due to the nature of our business, we are, from time to time, involved in routine litigation or subject to disputes or claims related to our business activities, including workers’ compensation claims and employment related disputes. In the opinion of our management, with the exception of the matters previously disclosed, none of the pending litigation, disputes or claims against us, if decided adversely, will have a material adverse effect on our financial condition or results of operations.

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, 2005 and our Registration Statement on Form S-1, File No. 333-134322, filed with the SEC on May 19, 2006.

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

None, except as previously disclosed.

Item 3. Defaults Upon Senior Securities

None.

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

On June 9, 2006, our annual meeting of stockholders was held at our corporate headquarters in Oklahoma City, Oklahoma. A total of 23,447,245 of our shares of common stock were present or represented by proxy at the annual meeting. This represented more than 94% of our shares outstanding on the record date. Two management proposals were voted upon at our annual meeting and each was approved. Each of Mike Liddell, D. Frank Harrison, David L. Houston, Phillip G. Lancaster and William R. Snipes was re-elected as a director to serve until our next annual meeting of stockholders and until his successor is duly elected and qualified, and the 2006 Stock Incentive Plan was approved and adopted by the stockholders.

The results of the tabulation of the votes cast at our annual meeting are as follows:

	For (#)	Withhold (#)
Proposal 1 – Election of Directors:
Mike Liddell	19,849,939	3,597,306
D. Frank Harrison	19,899,899	3,547,346
David L. Houston	22,825,470	621,775
Phillip G. Lancaster	22,825,140	622,105
William R. Snipes	22,822,810	564,435

	For (#)	Against (#)	Abstain (#)	No Vote (#)
Proposal 2 – Approval and adoption of 2006 Stock Incentive Plan	13,437,550	6,066,510	14,359	3,928,826

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Item 5. Other Information

Termination of Administrative Services Agreement

Effective April 1, 2006, we terminated our administrative services agreement with Gulfport. Under this agreement, Gulfport provided certain services to us, including accounting, human resources, legal and technical support services. In return for these services, we paid Gulfport an annual fee of approximately $414,000. In addition, we leased approximately 1,200 square feet of office space from Gulfport for our headquarters located in Oklahoma City, Oklahoma for which we paid Gulfport annual rent of $20,880. In January 2006, we reduced the level of administrative services being provided by Gulfport and increased our office space to approximately 2,500 square feet. As a result, our annual fee for administrative services was reduced to approximately $150,000 and our annual rental was increased to approximately $44,000.

Employment Agreements

Effective as of August8, 2006, we entered into employment agreements with each of D. Frank Harrison, our Chief Executive Officer, Zachary M. Graves, our Chief Financial Officer, and Mark Dubberstein, our General Counsel. The agreements each have a three year term and provide for a base salary of $450,000 per year for Mr. Harrison and $200,000 per year for each of Mr. Dubberstein and Mr. Graves. Under their respective agreements, Mr. Dubberstein and Mr. Graves will be eligible to receive an annual bonus as established by our board of directors (or the compensation committee of the board of directors) and Mr. Harrison will be eligible to receive an annual bonus in an amount not less than 66.7% of his annual base salary. If we terminate any of these employment agreements without cause, the executive is entitled to severance pay in an amount equal to: (1) the base salary earned and unpaid through the date of such termination plus the executive’s base salary for the remainder of the term of his agreement; provided, however, that such amount may not be less than twice the base salary in effect on the date of the termination, plus (2) the greater of any target bonus for the year of termination or the average of the two immediately preceding years’ annual incentive bonuses; plus (3) any vacation pay accrued through the date of the termination. If, within two years following a change of control or following a potential change of control which is followed within one year by a change of control, we terminate the employment of any of these executives without cause or such executive resigns for good reason, such executive would be entitled to a severance payment, payable in a lump sum in cash following such executive’s termination, in an amount equal to three times his base salary for the twelve calendar months immediately preceding the date of termination plus an amount equal to the average of his preceding three years’ annual bonuses. The agreements provide that each executive may not, during the term of his employment with us and for a period extending one year from the date of the termination of his employment with us, disclose any confidential information regarding our company or use any such confidential information for any purpose other than the performance of his employment with us. Each executive is also prohibited, during the term of his employment with us and for a period of six months following the termination of his employment with us for any reason other than without cause, from soliciting, inducing, enticing or attempting to entice any employee, contractor, customer, vendor or subcontractor to terminate or breach any relationship with us or any of our subsidiaries or affiliates.

Resignation and Appointment of Director

Phillip G. Lancaster has notified us of his intention to become the Chief Executive Officer of one of our affiliates. The Nasdaq rules require that a majority of our board of directors consist of independent directors and that the audit committee of our board of directors be comprised of three independent directors. As a result, effective August11, 2006, Phillip G. Lancaster resigned from his positions as a member of our board of directors and a member of the audit committee of our board of directors. To fill the resulting vacancies, effective August11, 2006, our board of directors acted by unanimous written consent to appoint Gary C. Hill to serve on our board of directors and on the audit committee of our board of directors. There are no agreements or understandings pursuant to which Mr. Hill was appointed as a member of our board of directors. After giving effect to this change, the audit committee of our board of directors consists of three independent directors, Mr. Houston, Mr. Snipes and Mr. Hill.

Resignation of Karl W. Benzer

Karl Benzer, former Chief Operating Officer, will be leaving the Company this month to pursue other business opportunities.

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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).
+10.1	Bronco Drilling Company, Inc. 2006 Stock Incentive Plan (incorporated by reference to Appendix B to the Company’s Proxy Statement, filed by the Company with the SEC on April 28, 2006).
+10.2	Form of Restricted Stock Award Agreement (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K, File No. 000-51571, field by the Company with the SEC on June 15, 2006).
+10.3	Form of Stock Option Agreement (incorporated by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K, File No. 000-51571, field by the Company with the SEC on June 15, 2006).
+*10.4	Employment Agreement, datedeffective as of August 8, 2006, by and between the Company and D. Frank Harrison.
+*10.5	Employment Agreement, datedeffective as of August 8, 2006, by and between the Company and Zachary M. Graves.
+*10.6	Employment Agreement, datedeffective as of August 8, 2006, by and between the Company and Mark Dubberstein.
*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.

+ Management contract, compensatory plan or arrangement.

* 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: August 10, 2006	BRONCO DRILLING COMPANY, INC.
	By:	/s/ Zachary M. Graves
		Zachary M. Graves
		Chief Financial Officer
		(Principal Accounting and Financial Officer)
Dated: August 10, 2006	By:	/s/ D. Frank Harrison
		D. Frank Harrison
		Chief Executive Officer
		(Authorized Officer and Principal Executive Officer)

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