PIONEER ENERGY SERVICES CORP - FORM 10-Q

PIONEER ENERGY SERVICES CORP - FORM 10-Q - August 5, 2010

Attached files

Attached files

PIONEER ENERGY SERVICES CORP Reports

file	filename
EX-31.2 - CERTIFICATION - EXECUTIVE VICE PRESIDENT AND CHIEF FINANCIAL OFFICER - PIONEER ENERGY SERVICES CORP	dex312.htm
EX-10.4 - 2007 INCENTIVE PLAN FORM OF RESTRICTED STOCK UNIT AGREEMENT - PIONEER ENERGY SERVICES CORP	dex104.htm
EX-10.3 - 2007 INCENTIVE PLAN FORM OF LONG-TERM INCENTIVE RESTRICTED STOCK AWARD AGREEMENT - PIONEER ENERGY SERVICES CORP	dex103.htm
EX-31.1 - CERTIFICATION - PRESIDENT AND CHIEF EXECUTIVE OFFICER - PIONEER ENERGY SERVICES CORP	dex311.htm
EX-32.1 - CERTIFICATION OF CEO PURSUANT TO SECTION 906 - PIONEER ENERGY SERVICES CORP	dex321.htm
EX-10.2 - 2007 INCENTIVE PLAN FORM OF LONG-TERM INCENTIVE CASH AWARD AGREEMENT - PIONEER ENERGY SERVICES CORP	dex102.htm
EX-10.1 - 2007 INCENTIVE PLAN FORM OF LONG-TERM INCENTIVE CASH AWARD AGREEMENT - PIONEER ENERGY SERVICES CORP	dex101.htm
EX-32.2 - CERTIFICATION OF CFO PURSUANT TO SECTION 906 - PIONEER ENERGY SERVICES CORP	dex322.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2010

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

For the transition period from ___________ to ____________

Commission File Number 1-8182

PIONEER DRILLING COMPANY

(Exact name of registrant as specified in its charter)


TEXAS		74-2088619
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification Number)

1250 N.E. Loop 410, Suite 1000, San Antonio, Texas		78209
(Address of principal executive offices)		(Zip Code)

210-828-7689

(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 þ No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ¨ No ¨

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

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

As of July 23, 2010 there were 54,175,370 shares of common stock, par value $0.10 per share, of the registrant issued and outstanding.

PART I. FINANCIAL INFORMATION

ITEM 1.

FINANCIAL STATEMENTS

PIONEER DRILLING COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS


	June 30, 2010			December 31, 2009
	(unaudited)			(audited)
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	17,348		$	40,379
Receivables:
Trade, net of allowance for doubtful accounts		56,562			26,648
Unbilled		23,371			8,586
Insurance recoveries		4,794			5,107
Income taxes		2,795			41,126
Deferred income taxes		9,400			5,560
Inventory		7,832			5,535
Prepaid expenses and other current assets		7,994			6,199

Total current assets		130,096			139,140

Property and equipment, at cost		1,049,652			967,893
Less accumulated depreciation		385,434			330,871

Net property and equipment		664,218			637,022
Intangible assets, net of amortization		24,269			25,393
Noncurrent deferred income taxes		1,572			2,339
Other long-term assets		27,345			21,061


Total assets	$	847,500		$	824,955


LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	45,303		$	15,324
Current portion of long-term debt		1,897			4,041
Prepaid drilling contracts		3,679			408
Accrued expenses:
Payroll and related employee costs		12,527			7,740
Insurance premiums and deductibles		9,105			8,615
Insurance claims and settlements		4,599			5,042
Other		14,875			7,634

Total current liabilities		91,985			48,804
Long-term debt, less current portion		264,497			258,073
Other long-term liabilities		9,836			6,457
Deferred income taxes		81,306			90,173

Total liabilities		447,624			403,507

Commitments and contingencies
Shareholders’ equity:
Preferred stock, 10,000,000 shares authorized; none issued and outstanding		—			—
Common stock $.10 par value; 100,000,000 shares authorized; 54,176,070 shares and 54,120,852 shares issued and outstanding at June 30, 2010 and December 31, 2009, respectively		5,419			5,413
Additional paid-in capital		335,850			332,534
Treasury stock, at cost; 17,380 shares and 5,174 shares at June 30, 2010 and December 31, 2009, respectively		(117	)		(31	)
Accumulated earnings		60,536			85,225
Accumulated other comprehensive loss		(1,812	)		(1,693	)

Total shareholders’ equity		399,876			421,448

Total liabilities and shareholders’ equity	$	847,500		$	824,955

See accompanying notes to condensed consolidated financial statements.

PIONEER DRILLING COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)


	Three Months Ended June 30,						Six Months Ended June 30,
	2010			2009			2010			2009
	(In thousands, except per share data)
Revenues:
Drilling services	$	76,096		$	45,720		$	131,913		$	117,086
Production services		40,931			23,400			71,135			52,874

Total revenue		117,027			69,120			203,048			169,960


Costs and expenses:
Drilling services		58,549			28,437			104,452			72,565
Production services		24,527			14,906			44,492			33,622
Depreciation and amortization		29,557			26,069			58,428			51,515
Selling, general and administrative		12,257			8,951			23,730			18,978
Bad debt (recovery) expense		(7	)		30			(82	)		(304	)

Total costs and expenses		124,883			78,393			231,020			176,376


Loss from operations		(7,856	)		(9,273	)		(27,972	)		(6,416	)


Other (expense) income:
Interest expense		(7,121	)		(1,728	)		(11,215	)		(3,716	)
Interest income		22			55			42			139
Other		315			1,140			799			625

Total other (expense) income		(6,784	)		(533	)		(10,374	)		(2,952	)


Loss before income taxes		(14,640	)		(9,806	)		(38,346	)		(9,368	)
Income tax benefit		4,498			3,547			13,657			3,727


Net loss	$	(10,142	)	$	(6,259	)	$	(24,689	)	$	(5,641	)


Loss per common share - Basic	$	(0.19	)	$	(0.13	)	$	(0.46	)	$	(0.11	)


Loss per common share - Diluted	$	(0.19	)	$	(0.13	)	$	(0.46	)	$	(0.11	)


Weighted average number of shares outstanding—Basic		53,781			49,826			53,750			49,825


Weighted average number of shares outstanding—Diluted		53,781			49,826			53,750			49,825

See accompanying notes to condensed consolidated financial statements.

PIONEER DRILLING COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Six Months Ended June 30,
	2010			2009
	(In thousands)
Cash flows from operating activities:
Net loss	$	(24,689	)	$	(5,641	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation and amortization		58,428			51,515
Allowance for doubtful accounts		(54	)		96
(Gain) loss on dispositions of property and equipment		(716	)		91
Stock-based compensation expense		3,432			3,889
Amortization of debt issuance costs and discount		1,142			332
Deferred income taxes		(11,958	)		3,414
Change in other assets		(2,609	)		575
Change in non-current liabilities		3,375			(991	)
Changes in current assets and liabilities:
Receivables		(6,442	)		40,711
Inventory		(2,297	)		(775	)
Prepaid expenses & other current assets		(1,796	)		4,707
Accounts payable		10,963			(7,153	)
Prepaid drilling contracts		3,271			(1,171	)
Accrued expenses		12,518			(8,922	)

Net cash provided by operating activities		42,568			80,677

Cash flows from investing activities:
Acquisition of Tiger Wireline, Inc.		(1,340	)		—
Purchases of property and equipment		(63,817	)		(47,677	)
Proceeds from sale of property and equipment		1,003			261
Proceeds from insurance recoveries		—			36

Net cash used in investing activities		(64,154	)		(47,380	)

Cash flows from financing activities:
Debt repayments		(245,951	)		(16,418	)
Proceeds from issuance of debt		249,375			—
Debt issuance costs		(4,795	)		—
Proceeds from exercise of options		12			—
Purchase of treasury stock		(86	)		—

Net cash (used in) provided by financing activities		(1,445	)		(16,418	)

Net increase (decrease) in cash and cash equivalents		(23,031	)		16,879
Beginning cash and cash equivalents		40,379			26,821

Ending cash and cash equivalents	$	17,348		$	43,700

Supplementary disclosure:
Interest paid	$	3,138		$	3,730
Income tax (refunded) paid	$	(40,514	)	$	(2,963	)

See accompanying notes to condensed consolidated financial statements.

PIONEER DRILLING COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. Nature of Operations and Summary of Significant Accounting Policies

Business and Basis of Presentation

Pioneer Drilling Company and subsidiaries provide drilling and production services to our customers in select oil and natural gas exploration and production regions in the United States and Colombia. Our Drilling Services Division provides contract land drilling services with its fleet of 71 drilling rigs in the following locations:


Drilling Division Locations		Rig Count

South Texas		19
East Texas		15
North Dakota		8
North Texas		4
Utah		4
Oklahoma		6
Appalachian		7
Colombia		8

As of July 23, 2010, 44 drilling rigs are operating under drilling contracts. We have 21 drilling rigs that are idle and six drilling rigs have been placed in storage or “cold stacked” in our Oklahoma drilling division location due to low demand for drilling rigs in that region. We are actively marketing all our idle drilling rigs. During the second quarter of 2009, we established our Appalachian drilling division location and now have six drilling rigs operating in the Marcellus Shale. We are currently upgrading a seventh rig that will begin operating in the Marcellus Shale in September 2010. We have eight drilling rigs operating under drilling contracts in Colombia. In addition to our drilling rigs, we provide the drilling crews and most of the ancillary equipment needed to operate our drilling rigs. 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, turnkey or footage basis. Contract terms 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.

Our Production Services Division provides a range of well services to oil and gas drilling and producing companies, including workover services, wireline services, and fishing and rental services. Our production services operations are managed through locations concentrated in the major United States onshore oil and gas producing regions in the Gulf Coast, Mid-Continent, Rocky Mountain and Appalachian states. We have a premium fleet of 74 workover rigs consisting of sixty-nine 550 horsepower rigs, four 600 horsepower rigs and one 400 horsepower rig. As of July 23, 2010, 72 workover rigs are operating and two workover rigs are idle with no crews assigned. We provide wireline services with a fleet of 78 wireline units and rental services with approximately $13.1 million of fishing and rental tools.

The accompanying unaudited condensed consolidated financial statements include the accounts of Pioneer Drilling Company and its wholly owned subsidiaries. All intercompany balances and transactions have been eliminated in consolidation. The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America for interim financial information and with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by generally accepted accounting principles for complete financial statements. In the opinion of our management, all adjustments (consisting of normal, recurring accruals) necessary for a fair presentation have been included. In preparing the accompanying unaudited condensed consolidated financial statements, we make various estimates and assumptions that affect the amounts of assets and liabilities we report as of the dates of the balance sheets and income and expenses we report for the periods shown in the income statements and statements of cash flows. Our actual results could differ significantly from those estimates. Material estimates that are particularly susceptible to significant changes in the near term relate to our recognition of revenues and costs for turnkey contracts, our estimate of the allowance for doubtful accounts, our estimate of the liability relating to the self-insurance portion of our health and workers’ compensation insurance, our estimate of asset impairments, our estimate of deferred taxes and our determination of depreciation and amortization expense. The condensed consolidated balance sheet as of December 31, 2009 has been derived from our audited financial statements. We suggest that you read these condensed consolidated financial statements together with the consolidated financial statements and the related notes included in our annual report on Form 10-K for the fiscal year ended December 31, 2009.

In preparing the accompanying unaudited condensed consolidated financial statements, we have reviewed events that have occurred after June 30, 2010, through the filing of this Form 10-Q, for inclusion as necessary.

Recently Issued Accounting Standards

Multiple Deliverable Revenue Arrangements. In October 2009, the FASB issued Accounting Standards update, 2009-13, Revenue Recognition (Topic 605) Multiple Deliverable Revenue Arrangements – A Consensus of the FASB Emerging Issues Task Force. This update provides application guidance on whether multiple deliverables exist, how the deliverables should be separated and how the consideration should be allocated to one or more units of accounting. This update establishes a selling price hierarchy for determining the selling price of a deliverable. The selling price used for each deliverable will be based on vendor-specific objective evidence, if available, third-party evidence if vendor-specific objective evidence is not available, or estimated selling price if neither vendor-specific or third-party evidence is available. We will be required to apply this guidance prospectively for revenue arrangements entered into or materially modified after January 1, 2011; however, earlier application is permitted. We do not expect the adoption of this new guidance to have a material impact on our financial position or results of operations.

Drilling Contracts

Our drilling contracts generally provide for compensation on either a daywork, turnkey or footage basis. Contract terms 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. Generally, our contracts provide for the drilling of a single well and typically permit the customer to terminate on short notice. However, we have entered into more longer-term drilling contracts during periods of high rig demand. In addition, we have entered into longer-term drilling contracts for our newly constructed rigs. As of July 23, 2010, we had 27 contracts with terms of six months to three years in duration, of which 16 will expire by January 23, 2011, three will expire by July 23, 2011, one will expire by January 23, 2012, and seven have a remaining term in excess of 18 months.

Foreign Currencies

Our functional currency for our foreign subsidiary in Colombia is the U.S. dollar. Nonmonetary assets and liabilities are translated at historical rates and monetary assets and liabilities are translated at exchange rates in effect at the end of the period. Income statement accounts are translated at average rates for the period. Gains and losses from remeasurement of foreign currency financial statements into U.S. dollars and from foreign currency transactions are included in other income or expense.

Restricted Cash

As of June 30, 2010, we had restricted cash in the amount of $2.0 million held in an escrow account to be used for future payments in connection with the acquisition of Prairie Investors d/b/a Competition Wireline (“Competition”). The former owner of Competition will receive annual installments of $0.7 million payable over the remaining three years from the escrow account. Restricted cash of $0.7 million and $1.3 million is recorded in other current assets and other long-term assets, respectively. The associated obligation of $0.7 million and $1.3 million is recorded in accrued expenses and other long-term liabilities, respectively.

Inventories

Inventories primarily consist of drilling rig replacement parts and supplies held for use by our Drilling Services Division’s operations and supplies held for use by our Production Services Division’s operations. Inventories are valued at the lower of cost (first in, first out or actual) or market value.

Investments

Other long-term assets include investments in tax exempt, auction rate preferred securities (ARPS). Our ARPSs are classified with other long-term assets on our condensed consolidated balance sheet as of June 30, 2010 because of our inability to determine the recovery period of our investments.

At June 30, 2010, we held $15.9 million (par value) of ARPSs, which are variable-rate preferred securities and have a long-term maturity with the interest rate being reset through “Dutch auctions” that are held every 7 days. The ARPSs had historically traded at par because of the frequent interest rate resets and because they are callable at par at the option of the issuer. Interest is paid at the end of each auction period. Our ARPSs are AAA/Aaa rated securities, collateralized by municipal bonds and backed by assets that are equal to or greater than 200% of the liquidation preference. Until February 2008, the auction rate securities market was highly liquid. Beginning mid-February 2008, we experienced several “failed” auctions, meaning that there was not enough demand to sell all of the securities that holders desired to sell at auction. The immediate effect of a failed auction is that such holders cannot sell the securities at auction and the interest rate on the security resets to a maximum auction rate. We have continued to receive interest payments on our ARPSs in accordance with their terms. We may not be able to access the funds we invested in our ARPSs without a

loss of principal, unless a future auction is successful or the issuer calls the security pursuant to redemption prior to maturity. We have no reason to believe that any of the underlying municipal securities that collateralize our ARPSs are presently at risk of default. We believe we will ultimately recover the par value of the ARPSs without a loss, primarily due to the collateral securing the ARPSs and our estimate of the discounted cash flows that we expect to collect. We do not currently intend to sell our ARPSs at a loss. Also, we believe it is more-likely-than-not that we will not have to sell our ARPSs prior to recovery, as our liquidity needs are expected to be met with cash flows from operating activities and our senior secured revolving credit facility. See Note 3 “Long-term Debt” below regarding compliance with the covenants in our credit agreement.

Our ARPSs are reported at amounts that reflect our estimate of fair value. ASC Topic 820 (formerly SFAS No. 157), provides a hierarchal framework associated with the level of subjectivity used in measuring assets and liabilities at fair value. To estimate the fair values of our ARPSs, we used inputs defined by ASC Topic 820 as level 3 inputs which are unobservable for the asset or liability and are developed based on the best information available in the circumstances. We estimate the fair value of our ARPSs based on discounted cash flow models and secondary market comparisons of similar securities. In addition, during the quarter ended June 30, 2009, we adopted the new accounting guidance under ASC Topic 320 when we evaluated the fair value of our ARPSs and evaluated whether the fair value discount represented an other-than-temporary impairment.

Our ARPSs are designated as available-for-sale and are reported at fair market value with the related unrealized gains or losses included in accumulated other comprehensive income (loss), net of tax, a component of shareholders’ equity. The estimated fair value of our ARPSs at June 30, 2010 was $13.0 million compared with a par value of $15.9 million. The $2.9 million difference represents a fair value discount due to the current lack of liquidity which is considered temporary and has been recorded as an unrealized loss, net of tax, in accumulated other comprehensive income (loss). As of March 31, 2010, we had recorded a total fair value discount of $3.0 million, of which $2.7 million of this fair value discount was recognized during 2009 and 2008. During the three months ended June 30, 2010 we recorded an unrealized gain of $0.1 million. There was no portion of the fair value discount attributable to credit losses. We would recognize an impairment charge in our statement of operations if the fair value of our investments falls below the cost basis and is judged to be other-than-temporary.

Income Taxes

Pursuant to ASC Topic 740 (formerly SFAS No. 109), we follow the asset and liability method of accounting for income taxes, under which we recognize 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 basis. We measure our deferred tax assets and liabilities by using the enacted tax rates we expect to apply to taxable income in the years in which we expect to recover or settle those temporary differences. Under ASC Topic 740, we reflect in income the effect of a change in tax rates on deferred tax assets and liabilities in the period during which the change occurs.

Comprehensive Income (Loss)

Comprehensive loss is comprised of net loss and other comprehensive income (loss). Other comprehensive income (loss) includes the change in the fair value of our ARPSs, net of tax, for the three and six months ended June 30, 2010 and 2009. The following table sets forth the components of comprehensive loss:


	Three Months Ended June 30,						Six Months Ended June 30,
	2010			2009			2010			2009
Net loss	$	(10,142	)	$	(6,259	)	$	(24,689	)	$	(5,641	)
Other comprehensive income (loss)—unrealized gain (loss) on ARPS securities		77			1,088			(119	)		(769	)


Comprehensive loss	$	(10,065	)	$	(5,171	)	$	(24,808	)	$	(6,410	)

Stock-based Compensation

Prior to 2010, we granted stock-based compensation in the form of stock option awards and restricted stock awards with vesting based solely on time of service conditions. In 2010, we continued to grant stock option awards with vesting based on time of service conditions and we began granting restricted stock unit awards with vesting based on time of service conditions, and in certain cases, performance conditions. We recognize compensation cost for stock option, restricted stock and restricted stock unit awards based on the grant-date fair value estimated in accordance with ASC Topic 718 (formerly SFAS No. 123R), and utilizing the graded vesting method.

Stock Options

We grant stock option awards which generally become exercisable over three- to five-year periods, and expire 10 years after the date of grant. Our stock-based compensation plans provide that all stock option awards must have an exercise price not less than the fair market value of our common stock on the date of grant. We issue shares of our common stock when vested stock option awards are exercised.

We estimate the fair value of each option grant on the date of grant using a Black-Scholes options-pricing model. The following table summarizes the assumptions used in the Black-Scholes option-pricing model for stock option awards granted during the three and six months ended June 30, 2010 and 2009:


	Three Months Ended June 30,						Six Months Ended June 30,
	2010			2009			2010			2009
Weighted average expected volatility		63	%		59	%		62	%		57	%
Weighted-average risk-free interest rates		2.6	%		2.1	%		2.6	%		2.1	%
Weighted-average expected life in years		5.00			5.00			5.65			5.50
Options granted		3,000			11,000			734,200			1,488,300
Weighted-average grant-date fair value	$	4.09		$	2.86		$	5.03		$	2.07

The assumptions above are based on multiple factors, including historical exercise patterns of homogeneous groups with respect to exercise and post-vesting employment termination behaviors, expected future exercising patterns for these same homogeneous groups and volatility of our stock price. As we have not declared dividends since we became a public company, we 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 our common stock and overall stock market conditions. There is no assurance the value an optionee actually realizes will be at or near the value we have estimated using the Black-Scholes options-pricing model.

During the three and six months ended June 30, 2010, 800 and 3,100 options were exercised, respectively. There were no stock options exercised during the six months ended June 30, 2009. We receive a tax deduction for certain stock option exercises during the period the options are exercised, generally for the excess of the fair market value of our stock on the date of exercise over the exercise price of the options. In accordance with ASC Topic 718, we reported all excess tax benefits resulting from the exercise of stock options as financing cash flows in our consolidated statement of cash flows.

The following table summarizes the compensation expense recognized for stock option awards during the three and six months ended June 30, 2010 and 2009 (amounts in thousands):


	Three Months Ended June 30,				Six Months Ended June 30,
	2010		2009		2010		2009
Selling, general and administrative expense	$	1,050	$	1,254	$	2,123	$	2,301
Operating costs		148		319		291		591

	$	1,198	$	1,573	$	2,414	$	2,892

Restricted Stock

We grant restricted stock awards that vest over a three-year period with a fair value based on the closing price of our common stock on the date of the grant. When restricted stock awards are granted, shares of our common stock are considered issued, but subject to certain restrictions.

We granted 66,224 restricted stock awards during the three months ended June 30, 2010, with a weighted-average grant date price of $6.04. There were no restricted stock awards granted during the three months ended March 31, 2010. During the three and six months ended June 30, 2009, we granted 71,048 and 326,748 restricted stock awards with a weighted-average grant date price of $5.63 and $4.23, respectively.

The following table summarizes the compensation expense recognized for restricted stock awards during the three and six months ended June 30, 2010 and 2009 (amounts in thousands):


	Three Months Ended June 30,				Six Months Ended June 30,
	2010		2009		2010		2009
Selling, general and administrative expense	$	264	$	460	$	591	$	827
Operating costs		32		87		76		170

	$	296	$	547	$	667	$	997

Restricted Stock Units

We grant restricted stock unit awards with vesting based on time of service conditions only, and we grant restricted stock unit awards with vesting based on time of service and performance conditions. Shares of our common stock are issued to recipients of restricted stock units only when they have satisfied the applicable vesting conditions.

During the six months ended June 30, 2010, we granted restricted stock unit awards with vesting based on time of service conditions. These restricted stock unit awards vest over a three-year period and represent 72,120 shares of common stock. The fair value of these restricted stock unit awards is based on the closing price of our common stock on the date of grant.

During the six months ended June 30, 2010, we also granted restricted stock unit awards with vesting based on time of service and performance conditions. These restricted stock unit awards vest over a three-year period and represent 136,276 estimated shares of our common stock. The fair value of these restricted stock unit awards is computed based on the closing price of our common stock on the date of grant and the estimated number of shares of common stock. The estimated number of shares of common stock will be adjusted based on our actual achievement levels that are measured against predetermined performance conditions. Compensation cost ultimately recognized is equal to the fair value of the restricted stock unit award based on the actual outcome of the service and performance conditions.

There were no restricted stock unit awards granted during the three months ended June 30, 2010. The restricted stock units awarded during the six months ended June 30, 2010 represented common stock with a weighted-average grant date price of $8.86. We did not grant any restricted stock unit awards prior to 2010.

The following table summarizes the compensation expense recognized for restricted stock unit awards during the three and six months ended June 30, 2010 and 2009 (amounts in thousands):


	Three Months Ended June 30, 2010		Six Months Ended June 30, 2010
Selling, general and administrative expense	$	152	$	304
Operating costs		26		47

	$	178	$	351

Related-Party Transactions

Our Chief Executive Officer, President of Drilling Services Division, Senior Vice President of Drilling Services Division—Marketing, and a Vice President of Drilling Services Division—Operations occasionally own a 1% to 5% working interest in oil and gas wells that we drill for one of our customers. These individuals did not own a working interest in any wells that we drilled for this customer during either of the six month periods ended June 30, 2010 and 2009.

In connection with the acquisitions of the production services businesses from WEDGE Group Incorporated (“WEDGE”) and Competition on March 1, 2008, we have leases for various operating and office facilities with entities that are owned by former WEDGE employees and Competition employees that are now employees of our company. Rent expense for the six months ended June 30, 2010 and 2009 was approximately $0.4 million and $0.3 million, respectively, for these related party leases.

We also have non-compete agreements with several former WEDGE and Tiger Wireline, Inc. employees that are now employees of our company. These non-compete agreements are recorded as intangible assets with a cost, net of accumulated amortization, of $0.5 million and $0.7 million as of June 30, 2010 and December 31, 2009, respectively.

We had aggregate purchases of $0.5 million and $0.1 million of goods and services during the six months ended June 30, 2010 and 2009, respectively, from seven vendors that are owned by company employees or family members of company employees.

Reclassifications

Certain amounts in the financial statements for the prior years have been reclassified to conform to the current year’s presentation.

2. Acquisitions

On April 1, 2010, we acquired Tiger Wireline Services, Inc., which provided wireline services with two wireline units through its facilities in Kansas. The aggregate purchase price was approximately $1.9 million, which we financed with $1.3 million in cash and a seller’s note of $0.6 million. The identifiable assets recorded in connection with this acquisition include fixed assets of $0.8 million and intangible assets of $1.1 million representing customer relationships and a non-competition agreement. We did not recognize any goodwill in conjunction with the acquisition and no contingent assets or liabilities were assumed. Our acquisition of Tiger Wireline Services, Inc. has been accounted for as an acquisition of a business in accordance with ASC Topic 805, Business Combinations.

3. Long-term Debt

Long-term debt as of June 30, 2010 and December 31, 2009 consists of the following (amounts in thousands):


	June 30, 2010			December 31, 2009
Senior secured revolving credit facility	$	22,750		$	257,500
Senior notes		239,630			—
Subordinated notes payable		3,862			4,387
Other		152			227

		266,394			262,114
Less current portion		(1,897	)		(4,041	)

	$	264,497		$	258,073

Senior Secured Revolving Credit Facility

We have a credit agreement, as amended, with Wells Fargo Bank, N.A. and a syndicate of lenders which provides for a senior secured revolving credit facility, with sub-limits for letters of credit and swing-line loans, of up to an aggregate principal amount of $225 million, all of which matures on August 31, 2012 (the “Revolving Credit Facility”). The Revolving Credit Facility contains customary mandatory prepayments in respect of asset dispositions, debt incurrence and equity issuances, which are applied to reduce outstanding revolving and swing-line loans and letter of credit exposure, but in no event will reduce the borrowing availability under the Revolving Credit Facility to less than $225 million. Borrowings under the Revolving Credit Facility bear interest, at our option, at the LIBOR rate or at the bank prime rate, plus an applicable per annum margin that ranges from 3.50% to 6.00% and 2.50% to 5.00%, respectively. The LIBOR margin and bank prime rate margin in effect at July 23, 2010 are 5.5% and 4.5%, respectively. The Revolving Credit Facility requires a commitment fee due quarterly based on the average daily unused amount of the commitments of the lenders, a fronting fee due for each letter of credit issued, and a quarterly letter of credit fee due based on the average undrawn amount of letters of credit outstanding during such period. Our obligations under the Revolving Credit Facility are secured by substantially all of our domestic assets (including equity interests in Pioneer Global Holdings, Inc. and 65% of the outstanding equity interests of any first-tier foreign subsidiaries owned by Pioneer Global Holdings, Inc., but excluding any equity interest in, and any assets of, Pioneer Services Holdings, LLC) and are guaranteed by certain of our domestic subsidiaries, including Pioneer Global Holdings, Inc. Borrowings under the Revolving Credit Facility are available for acquisitions, working capital and other general corporate purposes.

In March 2010, we made a payment of $234.8 million to reduce the outstanding debt balance under the Revolving Credit Facility, using the net proceeds from the issuance of our Senior Notes which is described below. We may choose to make additional principal payments to reduce the outstanding debt balance prior to maturity on August 31, 2012 when cash and working capital is sufficient. At July 23, 2010, we had $22.8 million outstanding under our Revolving Credit Facility and $9.2 million in committed letters of credit, which results in borrowing availability of $193.0 million under our Revolving Credit Facility. There are no limitations on our ability to access this borrowing capacity other than maintaining compliance with the covenants under the Revolving Credit Facility. At June 30, 2010, we were in compliance with our financial covenants. Our total consolidated leverage ratio was 4.25 to 1.0, our senior consolidated leverage ratio was 0.48 to 1.0, and our interest coverage ratio was 4.04 to 1.0. In order to remain in compliance with our financial covenants, our borrowing availability under the Revolving Credit Facility was limited to an additional $50.4 million as of June 30, 2010. The financial covenants contained in our Revolving Credit Facility include the following:

•

A maximum total consolidated leverage ratio that cannot exceed:

•

5.00 to 1.00 as of the end of any fiscal quarter ending June 30, 2010 through June 30, 2011;

•

4.75 to 1.00 as of the end of the fiscal quarter ending September 30, 2011;

•

4.50 to 1.00 as of the end of the fiscal quarter ending December 31, 2011;

•

4.25 to 1.00 as of the end of the fiscal quarter ending March 31, 2012; and

•

4.00 to 1.00 as of the end of any fiscal quarter ending June 30, 2012 and thereafter.

•

A maximum senior consolidated leverage ratio, which excludes unsecured and subordinated debt, that cannot exceed:

•

5.00 to 1.00 as of the end of the fiscal quarters ending June 30, 2010;

•

4.75 to 1.00 as of the end of the fiscal quarter ending September 30, 2010;

•

4.50 to 1.00 as of the end of the fiscal quarter ending December 31, 2010;

•

4.25 to 1.00 as of the end of the fiscal quarter ending March 31, 2011;

•

4.00 to 1.00 as of the end of the fiscal quarter ending June 30, 2011;

•

3.75 to 1.00 as of the end of the fiscal quarter ending September 30, 2011;

•

3.50 to 1.00 as of the end of the fiscal quarter ending December 31, 2011;

•

3.25 to 1.00 as of the end of the fiscal quarter ending March 31, 2012; and

•

3.00 to 1.00 as of the end of any fiscal quarter ended June 30, 2012 and thereafter.

•

A minimum interest coverage ratio that cannot be less than:

•

2.00 to 1.00 as of the end of any fiscal quarter ending June 30, 2010 through December 31, 2011; and

•

3.00 to 1.00 as of the end of any fiscal quarter ending March 31, 2012 and thereafter.

•

If our senior consolidated leverage ratio is greater than 2.25 to 1.00 at the end of any fiscal quarter, a minimum asset coverage ratio that cannot be less than 1.00 to 1.00 for any fiscal quarter ending on or before December 31, 2011, and 1.10 to 1.00 for any fiscal quarter ending March 31, 2012 and thereafter (as provided in the Revolving Credit Facility). If our senior consolidated leverage ratio is greater than 2.25 to 1.00 and our asset coverage ratio is less than 1.00 to 1.00, then borrowings outstanding under the Revolving Credit Facility will be limited to the sum of 80% of eligible accounts receivable, 80% of the orderly liquidation value of eligible equipment and 40% of the net book value of certain other fixed assets.

The Revolving Credit Facility restricts capital expenditures unless (a) after giving effect to such capital expenditure, no event of default would exist under the Revolving Credit Facility and availability under the Revolving Credit Facility would be equal to or greater than $25 million and (b) if the senior consolidated leverage ratio as of the last day of the most recent reported fiscal quarter was equal to or greater than 2.50 to 1.00, such capital expenditure would not cause the sum of all capital expenditures to exceed:

•

$65 million for fiscal year 2010; and

•

$80 million for each fiscal year thereafter.

The capital expenditure thresholds for each period noted above may be increased by:

•

the first $25 million of any aggregate equity issuance proceeds received during such period and 25% of any equity issuance proceeds received in excess of $25 million during such period; and

•

25% of any debt incurrence proceeds received during such period.

In addition, any unused portion of the capital expenditure threshold up to $30 million can be carried over from the immediate preceding fiscal year.

At June 30, 2010, our senior consolidated leverage ratio was not greater than 2.50 to 1.00 and therefore, we were not subject to the capital expenditure threshold restrictions listed above.

The Revolving Credit Facility has additional restrictive covenants that, among other things, limit the incurrence of additional debt, investments, liens, dividends, acquisitions, redemptions of capital stock, prepayments of indebtedness, asset dispositions, mergers and consolidations, transactions with affiliates, hedging contracts, sale leasebacks and other matters customarily restricted in such agreements. In addition, the Revolving Credit Facility contains customary events of default, including without limitation, payment defaults, breaches of representations and warranties, covenant defaults, cross-defaults to certain other material indebtedness in excess of specified amounts, certain events of bankruptcy and insolvency, judgment defaults in excess of specified amounts, failure of any guaranty or security document supporting the credit agreement and change of control.

Senior Notes

On March 11, 2010, we issued $250 million of Senior Notes with a coupon interest rate of 9.875% that are due in 2018 (the “Senior Notes”). The Senior Notes were sold with an original issue discount of $10.6 million that was based on 95.75% of their face value, which will result in an effective yield to maturity of approximately 10.677%. On March 11, 2010, we received $234.8 million of net proceeds from the issuance of the Senior Notes after deductions were made for the $10.6 million of original issue discount and $4.6 million for underwriters’ fees and other debt offering costs. The net proceeds were used to repay a portion of the borrowings outstanding under our Revolving Credit Facility. The Senior Notes are reflected on our condensed consolidated balance sheet at June 30, 2010 with a carrying value of $239.6 million, which represents the $250 million face value net of the $10.4 million unamortized portion of original issue discount. The original issue discount is being amortized over the term of the Senior Notes based on the effective interest method.

The Senior Notes will mature on March 15, 2018 with interest due semi-annually in arrears on March 15 and September 15 of each year, commencing on September 15, 2010. We have the option to redeem the Senior Notes, in whole or in part, at any time on or after March 15, 2014 in each case at the redemption price specified in the Indenture dated March 11, 2010 (the “Indenture”) together with any accrued and unpaid interest to the date of redemption. Prior to March 15, 2014, we may also redeem the Senior Notes, in whole or in part, at a “make-whole” redemption price specified in the Indenture, together with any accrued and unpaid interest to the date of redemption. In addition, prior to March 15, 2013, we may, on one or more occasions, redeem up to 35% of the aggregate principal amount of the Senior Notes at a redemption price of 109.875% of the principal amount, plus any accrued and unpaid interest to the redemption date, with the net proceeds of certain equity offerings, if at least 65% of the aggregate principal amount of the Senior Notes remains outstanding after such redemption and the redemption occurs within 120 days of the closing of the equity offering.

Upon the occurrence of a change of control, holders of the Senior Notes will have the right to require us to purchase all or a portion of the Senior Notes at a price equal to 101% of the principal amount of each Senior Note, together with any accrued and unpaid interest to the date of purchase. Under certain circumstances in connection with asset dispositions, we will be required to use the excess proceeds of asset dispositions to make an offer to purchase the Senior Notes at a price equal to 100% of the principal amount of each Senior Note, together with any accrued and unpaid interest to the date of purchase.

The Indenture contains certain restrictions on our and certain of our subsidiaries’ ability to:

•

pay dividends on stock;

•

repurchase stock or redeem subordinated debt or make other restricted payments;

•

incur, assume or guarantee additional indebtedness or issue disqualified stock;

•

create liens on our assets;

•

enter into sale and leaseback transactions;

•

restrict dividends, loans or other asset transfers from certain of our subsidiaries;

•

consolidate with or merge with or into, or sell all or substantially all of our properties to another person;

•

enter into transactions with affiliates; and

•

enter into new lines of business.

These covenants are subject to important exceptions and qualifications. We were in compliance with these covenants as of June 30, 2010. The Senior Notes are not subject to any sinking fund requirements. The Senior Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by certain of our existing domestic subsidiaries and by certain of our future domestic subsidiaries (see Note 9 “Guarantor/Non-Guarantor Condensed Consolidated Financial Statements”).

Subordinated Notes Payable and Other

In addition to amounts outstanding under our Revolving Credit Facility and Senior Notes, long-term debt includes subordinated notes payable to certain employees that are former shareholders of the production services businesses that were acquired by WEDGE prior to our acquisition of WEDGE on March 1, 2008, a subordinated note payable to an employee that is a former shareholder of Competition and three subordinated notes payable to certain employees that are former shareholders of Paltec, Inc., Pettus Well Service and Tiger Wireline, Inc. These subordinated notes payable have interest rates ranging from 5.4% to 14%, require quarterly or annual payments of principal and interest and have final maturity dates ranging from November 2010 to April 2013. The aggregate outstanding balance of these subordinated notes payable was $3.9 million as of June 30, 2010.

Other debt represents a financing arrangement for computer software with an outstanding balance of $0.2 million at June 30, 2010.

Debt Issuance Costs

Costs incurred in connection with our Revolving Credit Facility were capitalized and are being amortized using the straight-line method over the term of the Revolving Credit Facility which matures in August 2012. Costs incurred in connection with the issuance of our Senior Notes were capitalized and are being amortized using the straight-line method over the term of the Senior Notes which mature in March 2018. Capitalized debt costs related to the issuance of our long-term debt were approximately $7.7 million and $3.8 million as of June 30, 2010 and December 31, 2009, respectively. We recognized approximately $0.9 million and $0.3 million of associated amortization during the six months ended June 30, 2010 and 2009, respectively.

4. Fair Value of Financial Instruments

Our financial instruments consist primarily of cash, trade receivables, trade payables and long-term debt. The carrying value of cash, trade receivables and trade payables are considered to be representative of their respective fair values due to the short-term nature of these instruments. The fair value of our long-term debt is estimated using a discounted cash flow analysis, based on rates that we believe we would currently pay for similar types of debt instruments. This discounted cash flow analysis based on observable inputs for similar types of debt instruments represents level 2 inputs as defined by ASC Topic 820 (formerly SFAS No. 157). The following table presents the supplemental fair value information about long-term debt at June 30, 2010 and December 31, 2009 (amounts in thousands):


	June 30, 2010				December 31, 2009
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Total debt	$	266,394	$	269,505	$	262,114	$	262,429

5. Commitments and Contingencies

In connection with our expansion into international markets, our foreign subsidiaries have obtained bonds for bidding on drilling contracts, performing under drilling contracts, and remitting customs and importation duties. We have guaranteed payments of $52.7 million relating to our performance under these bonds.

Due to the nature of our business, we are, from time to time, involved in litigation or subject to disputes or claims related to our business activities, including workers’ compensation claims and employment-related disputes. Legal costs relating to these matters are expensed as incurred. In the opinion of our management, none of the pending litigation, disputes or claims against us will have a material adverse effect on our financial condition, results of operations or cash flow from operations.

6. Earnings (Loss) Per Common Share

The following table presents a reconciliation of the numerators and denominators of the basic loss per share and diluted loss per share computations (amounts in thousands, except per share data):


	Three Months Ended June 30,						Six Months Ended June 30,
	2010			2009			2010			2009
Basic
Net loss	$	(10,142	)	$	(6,259	)		(24,689	)	$	(5,641	)

Weighted average shares		53,781			49,826			53,750			49,825

Loss per share	$	(0.19	)	$	(0.13	)	$	(0.46	)	$	(0.11	)


	Three Months Ended June 30,						Six Months Ended June 30,
	2010			2009			2010			2009
Diluted
Net loss	$	(10,142	)	$	(6,259	)	$	(24,689	)	$	(5,641	)
Weighted average shares:
Outstanding		53,781			49,826			53,750			49,825
Diluted effect of stock options		—			—			—			—

		53,781			49,826			53,750			49,825

Loss per share	$	(0.19	)	$	(0.13	)	$	(0.46	)	$	(0.11	)

Outstanding stock options, restricted stock and restricted stock unit awards representing 653,877 and 788,900 shares of common stock were excluded from the diluted loss per share calculations for the three and six month periods ended June 30, 2010, because the effect of their inclusion would be antidilutive. Outstanding stock options and restricted stock awards representing 230,050 and 156,731 shares of common stock were excluded from the diluted loss per share calculations for the three and six month periods ended June 30, 2009, because the effect of their inclusion would be antidilutive.

7. Equity Transactions

Our employees exercised stock options at a weighted-average exercise price of $3.84 per share for the purchase of 800 and 3,100 shares of common stock during the three and six month periods ended June 30, 2010, respectively. There were no stock options exercised during the six month period ended June 30, 2009.

8. Segment Information

At June 30, 2010, we had two operating segments referred to as the Drilling Services Division and the Production Services Division which is the basis management uses for making operating decisions and assessing performance.

Drilling Services Division – Our Drilling Services Division provides contract land drilling services with its fleet of 71 drilling rigs that are assigned to the following locations:


Drilling Division Locations		Rig Count

South Texas		19
East Texas		15
North Dakota		8
North Texas		4
Utah		4
Oklahoma		6
Appalachian		7
Colombia		8

Production Services Division—Our Production Services Division provides a range of well services to oil and gas drilling and producing companies, including workover services, wireline services, and fishing and rental services. Our production services operations are managed through locations concentrated in the major United States onshore oil and gas producing regions in the Gulf Coast, Mid-Continent, Rocky Mountain and Appalachian states. We have a premium fleet of 74 workover rigs consisting of sixty-nine 550 horsepower rigs, four 600 horsepower rigs and one 400 horsepower rig. We provide wireline services with a fleet of 78 wireline units and rental services with approximately $13.1 million of fishing and rental tools.

The following tables set forth certain financial information for our two operating segments and corporate for the three months ended June 30, 2010 and 2009 (amounts in thousands):


	As of and for the Three Months Ended June 30, 2010
	Drilling Services Division		Production Services Division		Corporate		Total
Identifiable assets	$	580,174	$	241,455	$	25,871	$	847,500

Revenues	$	76,096	$	40,931	$	—	$	117,027
Operating costs		58,549		24,527		—		83,076

Segment margin	$	17,547	$	16,404	$	—	$	33,951


Depreciation and amortization	$	22,755	$	6,453	$	349	$	29,557
Capital expenditures	$	40,580	$	6,849	$	133	$	47,562


	As of and for the Three Months Ended June 30, 2009
	Drilling Services Division		Production Services Division		Corporate		Total
Identifiable assets	$	552,916	$	226,816	$	21,873	$	801,605

Revenues	$	45,720	$	23,400	$	—	$	69,120
Operating costs		28,437		14,906		—		43,343

Segment margin	$	17,283	$	8,494	$	—	$	25,777


Depreciation and amortization	$	19,788	$	5,902	$	379	$	26,069
Capital expenditures	$	17,108	$	1,359	$	15	$	18,482

The following tables set forth certain financial information for our two operating segments and corporate for the six months ended June 30, 2010 and 2009 (amounts in thousands):


	As of and for the Six Months Ended June 30, 2010
	Drilling Services Division		Production Services Division		Corporate		Total
Identifiable assets	$	580,174	$	241,455	$	25,871	$	847,500

Revenues	$	131,913	$	71,135	$	—	$	203,048
Operating costs		104,452		44,492		—		148,944

Segment margin	$	27,461	$	26,643	$	—	$	54,104


Depreciation and amortization	$	45,048	$	12,689	$	691	$	58,428
Capital expenditures	$	70,466	$	13,001	$	164	$	83,631


	As of and for the Six Months Ended June 30, 2009
	Drilling Services Division		Production Services Division		Corporate		Total
Identifiable assets	$	552,916	$	226,816	$	21,873	$	801,605
Revenues	$	117,086	$	52,874	$	—	$	169,960
Operating costs		72,565		33,622		—		106,187
Segment margin	$	44,521	$	19,252	$	—	$	63,773


Depreciation and amortization	$	39,126	$	11,626	$	763	$	51,515
Capital expenditures	$	36,991	$	7,632	$	597	$	45,220

The following table reconciles the segment profits reported above to loss from operations as reported on the condensed consolidated statements of operations (amounts in thousands):


	Three Months Ended June 30,						Six Months Ended June 30,
	2010			2009			2010			2009
Segment margin	$	33,951		$	25,777		$	54,104		$	63,773
Depreciation and amortization		(29,557	)		(26,069	)		(58,428	)		(51,515	)
Selling, general and administrative		(12,257	)		(8,951	)		(23,730	)		(18,978	)
Bad debt recovery (expense)		7			(30	)		82			304

Loss from operations	$	(7,856	)	$	(9,273	)	$	(27,972	)	$	(6,416	)

The following table sets forth certain financial information for our international operations in Colombia which is included in our Drilling Services Division (amounts in thousands):


	As of and for the				As of and for the
	Three Months Ended June 30,				Six Months Ended June 30,
	2010		2009		2010		2009
Identifiable assets	$	161,255	$	109,364	$	161,255	$	109,364

Revenues	$	20,322	$	10,179	$	36,066	$	24,796

Identifiable assets as of June 30, 2010 include three drilling rigs that are owned by one of our domestic subsidiaries and leased to our Colombia subsidiary.

9. Guarantor/Non-Guarantor Condensed Consolidated Financial Statements

Our Senior Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by our existing domestic subsidiaries, except for Pioneer Services Holdings, LLC, and certain of our future domestic subsidiaries. The subsidiaries that generally operate our non-U.S. business concentrated in Colombia do not guarantee our Senior Notes. The non-guarantor subsidiaries do not have any payment obligations under the Senior Notes, the guarantees or the Indenture. In the event of a bankruptcy, liquidation or reorganization of any non-guarantor subsidiary, such non-guarantor subsidiary will pay the holders of its debt and other liabilities, including its trade creditors, before it will be able to distribute any of its assets to us. In the future, any non-U.S. subsidiaries, immaterial subsidiaries and subsidiaries that we designate as unrestricted subsidiaries under the Indenture will not guarantee the Senior Notes. As of June 30, 2010, there were no restrictions on the ability of subsidiary guarantors to transfer funds to the parent company.

As a result of the guarantee arrangements, we are presenting the following condensed consolidated financial statements of the issuer, the guarantor subsidiaries and the non-guarantor subsidiaries.

CONDENSED CONSOLIDATED BALANCE SHEET

(Unaudited)


	June 30, 2010
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
*ASSEST*
Current assets:
Cash and cash equivalents	$	52,335		$	(36,231	)	$	1,244		$	—		$	17,348
Receivables		—			62,684			25,367			(529	)		87,522
Intercompany receivable (payable)		(115,711	)		123,938			(8,218	)		(9	)		—
Deferred income taxes		—			5,115			4,285			—			9,400
Inventory		—			2,223			5,609			—			7,832
Prepaid expenses and other current assets		1,199			3,204			3,591			—			7,994

Total current assets		(62,177	)		160,933			31,878			(538	)		130,096

Net property and equipment		1,662			568,844			94,462			(750	)		664,218
Investment in subsidiaries		708,744			113,301			—			(822,045	)		—
Intangible assets, net of amortization		701			23,568			—			—			24,269
Noncurrent deferred income taxes		1,051			—			1,572			(1,051	)		1,572
Other long-term assets		22,024			1,577			3,744			—			27,345

Total assets	$	672,005		$	868,223		$	131,656		$	(824,384	)	$	847,500

*LIABILITIES AND SHAREHOLDERS’ EQUITY*
Current liabilities:
Accounts payable	$	446		$	38,031		$	6,826		$	—		$	45,303
Current portion of long-term debt		151			1,746			—			—			1,897
Prepaid drilling contracts		—			899			2,780			—			3,679
Accrued expenses		8,402			28,674			4,568			(538	)		41,106

Total current liabilities		8,999			69,350			14,174			(538	)		91,985
Long-term debt, less current portion		262,380			2,117			—			—			264,497
Other long-term liabilities		—			5,655			4,181			—			9,836
Deferred income taxes		—			82,357			—			(1,051	)		81,306

Total liabilities		271,379			159,479			18,355			(1,589	)		447,624

Total shareholders’ equity		400,626			708,744			113,301			(822,795	)		399,876

Total liabilities and shareholders’ equity	$	672,005		$	868,223		$	131,656		$	(824,384	)	$	847,500

CONDENSED CONSOLIDATED BALANCE SHEET

(Unaudited)


	December 31, 2009
	Parent			Guarantor Subsidiaries		Non-Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
*ASSETS*
Current assets:
Cash and cash equivalents	$	9,958		$	20,678	$	9,743		$	—		$	40,379
Receivables		—			76,490		4,977			—			81,467
Intercompany receivable (payable)		(66,076	)		66,297		(221	)		—			—
Deferred income taxes		—			3,909		1,651			—			5,560
Inventory		—			1,791		3,744			—			5,535
Prepaid expenses and other current assets		874			3,358		1,967			—			6,199

Total current assets		(55,244	)		172,523		21,861			—			139,140

Net property and equipment		1,898			550,730		85,143			(749	)		637,022
Investment in subsidiaries		712,983			104,256		—			(817,239	)		—
Intangible assets, net of amortization		863			24,530		—			—			25,393
Noncurrent deferred income taxes		980			—		2,339			(980	)		2,339
Other long-term assets		18,957			1,611		493			—			21,061

Total assets	$	680,437		$	853,650	$	109,836		$	(818,968	)	$	824,955

*LIABILITIES AND SHAREHOLDERS’ EQUITY*
Current liabilities:
Accounts payable	$	286		$	12,277	$	2,761		$	—		$	15,324
Current portion of long-term debt		2,100			1,941		—			—			4,041
Prepaid drilling contracts		—			324		84			—			408
Accrued expenses		226			26,070		2,735			—			29,031

Total current liabilities		2,612			40,612		5,580			—			48,804
Long-term debt, less current portion		255,628			2,445		—			—			258,073
Other long-term liabilities		—			6,457		—			—			6,457
Deferred income taxes		—			91,153		—			(980	)		90,173

Total liabilities		258,240			140,667		5,580			(980	)		403,507

Total shareholders’ equity		422,197			712,983		104,256			(817,988	)		421,448

Total liabilities and shareholders’ equity	$	680,437		$	853,650	$	109,836		$	(818,968	)	$	824,955

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)


	Three Months Ended June 30, 2010
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenues:	$	—		$	96,705		$	20,322		$	—		$	117,027

Costs and expenses:
Operating costs		—			66,492			16,584			—			83,076
Depreciation and amortization		348			26,905			2,304			—			29,557
Selling, general and administrative		3,078			8,557			712			(90	)		12,257
Intercompany leasing		—			(1,125	)		1,125			—			—
Bad debt recovery		—			(7	)		—			—			(7	)

Total costs and expenses		3,426			100,822			20,725			(90	)		124,883

Income (loss) from operations		(3,426	)		(4,117	)		(403	)		90			(7,856	)

Other income (expense):
Equity in earnings of subsidiaries		296			(80	)		—			(216	)		—
Interest expense		(7,012	)		(101	)		(8	)		—			(7,121	)
Interest income		—			17			5			—			22
Other		—			203			202			(90	)		315

Total other income (expense)		(6,716	)		39			199			(306	)		(6,784	)

Loss before income taxes		(10,142	)		(4,078	)		(204	)		(216	)		(14,640	)
Income tax benefit (expense)		—			4,374			124			—			4,498

Net earnings (loss)	$	(10,142	)	$	296		$	(80	)	$	(216	)	$	(10,142	)


	Three Months Ended June 30, 2009
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenues:	$	—		$	58,941		$	10,179		$	—		$	69,120

Costs and expenses:
Operating costs		—			36,320			7,118			(95	)		43,343
Depreciation and amortization		371			23,776			1,922			—			26,069
Selling, general and administrative		3,227			5,808			270			(354	)		8,951
Bad debt recovery		—			30			—			—			30

Total costs and expenses		3,598			65,934			9,310			(449	)		78,393

Income (loss) from operations		(3,598	)		(6,993	)		869			449			(9,273	)

Other income (expense):
Equity in earnings of subsidiaries		(1,337	)		1,666			—			(329	)		—
Interest expense		(1,589	)		(139	)		—			—			(1,728	)
Interest income		—			27			28			—			55
Other		265			372			952			(449	)		1,140

Total other income (expense)		(2,661	)		1,926			980			(778	)		(533	)

Income (loss) before income taxes		(6,259	)		(5,067	)		1,849			(329	)		(9,806	)
Income tax benefit (expense)		—			3,730			(183	)		—			3,547

Net earnings (loss)	$	(6,259	)	$	(1,337	)	$	1,666		$	(329	)	$	(6,259	)

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)


	Six Months Ended June 30, 2010
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenues:	$	—		$	166,982		$	36,066		$	—		$	203,048

Costs and expenses:
Operating costs		—			119,117			29,827			—			148,944
Depreciation and amortization		690			53,188			4,550			—			58,428
Selling, general and administrative		7,103			15,434			1,373			(180	)		23,730
Intercompany leasing		—			(1,880	)		1,880			—			—
Bad debt recovery		—			(82	)		—			—			(82	)

Total costs and expenses		7,793			185,777			37,630			(180	)		231,020

Income (loss) from operations		(7,793	)		(18,795	)		(1,564	)		180			(27,972	)

Other income (expense):
Equity in earnings of subsidiaries		(5,912	)		94			—			5,818			—
Interest expense		(10,984	)		(213	)		(18	)		—			(11,215	)
Interest income		—			32			10			—			42
Other		—			381			598			(180	)		799

Total other income (expense)		(16,896	)		294			590			5,638			(10,374	)

Income (loss) before income taxes		(24,689	)		(18,501	)		(974	)		5,818			(38,346	)
Income tax benefit (expense)		—			12,589			1,068			—			13,657

Net earnings (loss)	$	(24,689	)	$	(5,912	)	$	94		$	5,818		$	(24,689	)


	Six Months Ended June 30, 2009
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenues:	$	—		$	145,164		$	24,796		$	—		$	169,960

Costs and expenses:
Operating costs		—			89,307			17,067			(187	)		106,187
Depreciation and amortization		748			46,933			3,834			—			51,515
Selling, general and administrative		6,350			12,766			570			(708	)		18,978
Bad debt recovery		—			(304	)		—			—			(304	)

Total costs and expenses		7,098			148,702			21,471			(895	)		176,376

Income (loss) from operations		(7,098	)		(3,538	)		3,325			895			(6,416	)

Other income (expense):
Equity in earnings of subsidiaries		4,347			3,190			—			(7,537	)		—
Interest expense		(3,419	)		(297	)		—			—			(3,716	)
Interest income		1			71			67			—			139
Other		528			731			261			(895	)		625

Total other income (expense)		1,457			3,695			328			(8,432	)		(2,952	)

Income (loss) before income taxes		(5,641	)		157			3,653			(7,537	)		(9,368	)
Income tax benefit (expense)		—			4,190			(463	)		—			3,727

Net earnings (loss)	$	(5,641	)	$	4,347		$	3,190		$	(7,537	)	$	(5,641	)

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Six Months Ended June 30, 2010
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations		Consolidated
	(In thousands)
Cash flows from operating activities:	$	42,861		$	(4,947	)	$	4,654		$	—	$	42,568

Cash flows from investing activities:
Acquisition of Tiger Wireline, Inc.		—			(1,340	)		—			—		(1,340	)
Purchases of property and equipment		(164	)		(50,454	)		(13,199	)		—		(63,817	)
Proceeds from sale of property and equipment		—			957			46			—		1,003

		(164	)		(50,837	)		(13,153	)		—		(64,154	)

Cash flows from financing activities:
Payments of debt		(244,826	)		(1,125	)		—			—		(245,951	)
Proceeds from issuance of debt		249,375			—			—			—		249,375
Debt issuance costs		(4,795	)		—			—			—		(4,795	)
Proceeds from exercise of options		12			—			—			—		12
Purchase of treasury stock		(86	)		—			—			—		(86	)

		(320	)		(1,125	)		—			—		(1,445	)

Net increase (decrease) in cash and cash equivalents		42,377			(56,909	)		(8,499	)		—		(23,031	)
Beginning cash and cash equivalents		9,958			20,678			9,743			—		40,379

Ending cash and cash equivalents	$	52,335		$	(36,231	)	$	1,244		$	—	$	17,348


	Six Months Ended June 30, 2009
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations		Consolidated
	(In thousands)
Cash flows from operating activities:	$	7,048		$	71,973		$	1,656		$	—	$	80,677

Cash flows from investing activities:
Purchases of property and equipment		(597	)		(44,058	)		(3,022	)		—		(47,677	)
Proceeds from sale of property and equipment		—			261			—			—		261
Proceeds from insurance recoveries		—			36			—			—		36

		(597	)		(43,761	)		(3,022	)		—		(47,380	)

Cash flows from financing activities:
Payments of debt		(15,089	)		(1,329	)		—			—		(16,418	)

		(15,089	)		(1,329	)		—			—		(16,418	)

Net increase (decrease) in cash and cash equivalents		(8,638	)		26,883			(1,366	)		—		16,879
Beginning cash and cash equivalents		858			13,896			12,067			—		26,821

Ending cash and cash equivalents	$	(7,780	)	$	40,779		$	10,701		$	—	$	43,700

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Statements we make in the following discussion that express a belief, expectation or intention, as well as those that are not historical fact, are forward-looking statements that are subject to risks, uncertainties and assumptions. Our actual results, performance or achievements, or industry results, could differ materially from those we express in the following discussion as a result of a variety of factors, including general economic and business conditions and industry trends, the continued strength or weakness of the contract land drilling industry in the geographic areas in which we operate, decisions about onshore exploration and development projects to be made by oil and gas companies, the highly competitive nature of our business, the availability, terms and deployment of capital, future compliance with covenants under our senior secured revolving credit facility and our senior notes, the availability of qualified personnel, and changes in, or our failure or inability to comply with, government regulations, including those relating to the environment. We have discussed many of these factors in more detail elsewhere in this report and in our Annual Report on Form 10-K for the year ended December 31, 2009 and in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2010. These factors are not necessarily all the important factors that could affect us. Unpredictable or unknown factors we have not discussed in this report or in our Annual Report on Form 10-K for the year ended December 31, 2009 or in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2010 could also have a material adverse effect on actual results of matters that are the subject of our forward-looking statements. All forward-looking statements speak only as the date on which they are made and we undertake no duty to update or revise any forward-looking statements. We advise our shareholders that they should (1) be aware that important factors not referred to above could affect the accuracy of our forward-looking statements and (2) use caution and common sense when considering our forward-looking statements.

Company Overview

Pioneer Drilling Company provides drilling services and production services to independent and major oil and gas exploration and production companies throughout much of the onshore oil and gas producing regions of the United States and internationally in Colombia. Pioneer Drilling Company was incorporated under the laws of the State of Texas in 1979 as the successor to a business that had been operating since 1968. Our business has grown through acquisitions and through organic growth. Over the last 10 years, we have significantly expanded our drilling rig fleet by adding 35 rigs through acquisitions and by adding 31 rigs through the construction of rigs from new and used components. We significantly expanded our service offerings in March 2008, when we acquired the production services businesses of WEDGE Group Incorporated (“WEDGE”) and Prairie Investors d/b/a Competition Wireline (“Competition”), which provide well services, wireline services and fishing and rental services. Drilling services and production services are fundamental to establishing and maintaining the flow of oil and natural gas throughout the productive life of a well site and enable us to meet multiple needs of our customers.

Business Segments

We currently conduct our operations through two operating segments: our Drilling Services Division and our Production Services Division. The following is a description of these two operating segments. Financial information about our operating segments is included in Note 8, Segment Information, of the Notes to Condensed Consolidated Financial Statements, included in Part I Item 1, Financial Statements, of this Quarterly Report on Form 10-Q.

•

Drilling Services Division—Our Drilling Services Division provides contract land drilling services with its fleet of 71 drilling rigs in the following locations:


Drilling Division Locations		Rig Count

South Texas		19
East Texas		15
North Dakota		8
North Texas		4
Utah		4
Oklahoma		6
Appalachian		7
Colombia		8

drilling contracts in Colombia. In addition to our drilling rigs, we provide the drilling crews and most of the ancillary equipment needed to operate our drilling rigs. 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, turnkey or footage basis. Contract terms 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.

•

Production Services Division—Our Production Services Division provides a range of well services to oil and gas drilling and producing companies, including workover services, wireline services, and fishing and rental services. Our production services operations are managed through locations concentrated in the major United States onshore oil and gas producing regions in the Gulf Coast, Mid-Continent, Rocky Mountain and Appalachian states. We provide our services to a diverse group of oil and gas companies. The primary production services we offer are the following:

•

Well Services. Existing and newly-drilled wells require a range of services to establish and maintain production over their useful lives. We use our fleet of 74 workover rigs in eight locations to provide these required services, including maintenance of existing wells, workover of existing wells, completion of newly-drilled wells, and plugging and abandonment of wells at the end of their useful lives. We have a premium workover rig fleet consisting of sixty-nine 550 horsepower rigs, four 600 horsepower rigs and one 400 horsepower rig. As of July 23, 2010, 72 workover rigs have crews assigned and are either operating or are being actively marketed. The remaining two workover rigs in our fleet are idle with no crews assigned.

•

Wireline Services. In order for oil and gas companies to better understand the reservoirs they are drilling or producing, they require logging services to accurately characterize reservoir rocks and fluids. When a producing well is completed, they also must perforate the production casing to establish a flow path between the reservoir and the wellbore. We use our fleet of wireline units to provide these important logging and perforating services. We provide both open and cased-hole logging services, including the latest pulsed-neutron technology. In addition, we provide services which allow oil and gas companies to evaluate the integrity of wellbore casing, recover pipe, or install bridge plugs. During the current year, we have acquired 12 additional wireline units, for a total of 78 wireline units in 20 locations, as of July 23, 2010.

•

Fishing and Rental Services. During drilling operations, oil and gas companies frequently need to rent unique equipment such as power swivels, foam circulating units, blow-out preventers, air drilling equipment, pumps, tanks, pipe, tubing, and fishing tools. We provide rental services out of four locations in Texas and Oklahoma. As of June 30, 2010 our fishing and rental tools have a gross book value of $13.1 million.

Pioneer Drilling Company’s corporate office is located at 1250 N.E. Loop 410, Suite 1000, San Antonio, Texas 78209. Our phone number is (210) 828-7689 and our website address is www.pioneerdrlg.com. We make available free of charge though our website our Annual Reports on our Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and all amendments to those reports as soon as reasonably practicable after such material is electronically filed with the Securities and Exchange Commission (the “SEC”). Information on our website is not incorporated into this report or otherwise made part of this report.

Market Conditions in Our Industry

Since late 2008, there has been substantial volatility and a decline in oil and natural gas prices due to the downturn in the global economic environment. In addition, there has been uncertainty in the capital markets and access to financing has been limited. These conditions have adversely affected our business environment. Our customers have curtailed their drilling programs and reduced their production activities, which has resulted in a decrease in demand for drilling and production services and a reduction in day rates and utilization. In addition, certain of our customers could experience an inability to pay suppliers in the event they are unable to access the capital markets to fund their business operations.

Demand for oilfield services offered by our industry is a function of our customers’ willingness to make operating and capital expenditures to explore for, develop and produce hydrocarbons, which in turn is affected by current and expected levels of oil and natural gas prices. From 2004 through 2008, domestic exploration and production spending increased as oil and natural gas prices increased. In response to the significant decline in oil and natural gas prices and the downturn in the global economic environment in late 2008, exploration and production companies announced cuts in their exploration budgets for 2009. These reductions in oil and gas exploration budgets resulted in a reduction in our rig utilization and revenue rates on new contracts during 2009. Exploration and production companies have modestly increased their exploration budgets for 2010 as compared to 2009.

Industry rig utilization and revenue rates showed modest improvements in the first half of 2010 and we expect modest increases for the remainder of 2010 as compared to 2009. For additional information concerning the effects of the volatility in oil and gas prices and uncertainty in capital markets, see Item 1A—“Risk Factors” in Part II of our Annual Report on Form 10-K for the year ended December 31, 2009.

On July 23, 2010, the spot price for West Texas Intermediate crude oil was $78.73, the spot price for Henry Hub natural gas was $4.69 and the Baker Hughes land rig count was 1,557, a 73% increase from 899 on July 24, 2009. The average weekly spot prices of West Texas Intermediate crude oil and Henry Hub natural gas, the average weekly domestic land rig count per the Baker Hughes land rig count, and the average monthly domestic workover rig count for the six months ended June 30, 2010 and the years ended June 30, 2010, 2009, 2008, 2007, and 2006 were:


	Six Months Ended June 30, 2010		Years ended June 30,
	Six Months Ended June 30, 2010		2010		2009		2008		2007		2006
Oil (West Texas Intermediate)	$	78.03	$	74.89	$	70.04	$	97.54	$	63.49	$	64.33

Natural Gas (Henry Hub)	$	4.70	$	4.15	$	5.86	$	8.24	$	6.79	$	8.98

U.S. Land Rig Count		1,363		1,177		1,466		1,716		1,624		1,402

U.S. Workover Rig Count		1,780		1,569		2,176		2,449		2,378		2,306

Increased expenditures for exploration and production activities generally lead to increased demand for our drilling services and production services. Between 2005 and late 2008, rising oil and natural gas prices and the corresponding increase in onshore oil and natural gas exploration and production spending led to expanded drilling and well service activity as reflected by the increases in the U.S. land rig counts and U.S. workover rig counts. The decline in oil and natural gas prices from late 2008 to late 2009 led to decreased oil and natural gas exploration and production spending and a corresponding decrease in drilling and well services activities as reflected by the decrease in the U.S. land rig counts and the U.S. workover rig counts. Since late 2009, increases in oil and natural gas prices have modestly increased exploration and production spending and a corresponding increase in drilling and well services activities as reflected by the increase in the U.S. land rig counts and the U.S. workover rig counts as noted in the table above.

Our business is influenced substantially by both operating and capital expenditures by exploration and production companies. Exploration and production spending is generally categorized as either a capital expenditure or operating expenditure.

Capital expenditures by oil and gas companies tend to be relatively sensitive to volatility in oil or natural gas prices because project decisions are tied to a return on investment spanning a number of years. As such, capital expenditure economics often require the use of commodity price forecasts which may prove inaccurate in the amount of time required to plan and execute a capital expenditure project (such as the drilling of a deep well). When commodity prices are depressed for long periods of time, capital expenditure projects are routinely deferred until prices return to an acceptable level.

In contrast, both mandatory and discretionary operating expenditures are more stable than capital expenditures for exploration. Mandatory operating expenditure projects involve activities that cannot be avoided in the short term, such as regulatory compliance, safety, contractual obligations and certain projects to maintain the well and related infrastructure in operating condition. Discretionary operating expenditure projects may not be critical to the short-term viability of a lease or field, but these projects are less sensitive to commodity price volatility as compared to capital expenditures for exploration. Discretionary operating expenditure work is evaluated according to a simple short-term payout criterion which is far less dependent on commodity price forecasts.

Because existing oil and natural gas wells require ongoing spending to maintain production, expenditures by exploration and production companies for the maintenance of existing wells are relatively stable and predictable. In contrast, capital expenditures by exploration and production companies for exploration and drilling are more directly influenced by current and expected oil and natural gas prices and generally reflect the volatility of commodity prices.

In our continuing effort to monitor market conditions and industry developments, we are evaluating the impact of the recent oil spill incident in the U.S. Gulf of Mexico involving BP. At this time, we cannot predict the full impact of the incident on our customers or on the continuing demand for our services. In addition, we cannot predict how our customers and government regulatory agencies will respond to the incident. Any changes to laws and regulations that may result from the oil spill incident would more likely be directed primarily at offshore drilling operations, but could impact our land drilling and production services operations as well.

Strategy

In past years, our strategy was to become a premier land drilling and production services company through steady and disciplined growth. We executed this strategy by acquiring and building a high quality drilling rig fleet and production services business that operates in active drilling markets in the United States and Colombia. Our long-term strategy is to maintain and leverage our position as a leading land drilling and production services company, continue to expand our relationships with existing customers, acquire new customers in the areas in which we currently operate and further enhance our geographic diversification through selective international expansion. The key elements of this long-term strategy include:

•

Further Strengthen our Competitive Position in the Most Attractive Domestic Markets. Shale plays are expected to become increasingly important to domestic hydrocarbon production in the coming years and not all drilling rigs are capable of successfully drilling shale play opportunities. We estimate that more than 75% of our rigs are currently capable of shale drilling, and we intend to further develop our rig fleet to take advantage of the expected increase in shale activity, including furthering our investment in top drives and winterizing additional rigs in our fleet for markets such as the Marcellus Shale in the northeastern United States and the Bakken Shale in the upper mid-west United States. We also plan to invest in additional safety equipment, such as the installation of iron roughnecks on certain of our rigs. We also intend to selectively add capacity to our wireline and well servicing product offerings, which are well positioned to capitalize on increased shale development.

•

Increase our Exposure to Oil-Driven Drilling Activity. We have intentionally increased our exposure to oil-related activities by redeploying certain of our assets into predominately oil-producing regions and actively seeking contracts with oil-focused producers. We currently have 64% of our working drilling rigs and 66% of our workover rigs operating on wells that are targeting or producing oil. We believe that by targeting a balanced mix of oil and natural gas oriented activities over time, we can lessen our exposure to fluctuations in capital spending associated with changes in any single commodity price. We believe that our flexible rig fleet and production services assets allow us to target both natural gas- and oil-focused opportunities.

•

Selectively Expand our International Operations. In early 2007, we announced our intention to selectively expand internationally and began a relationship with Ecopetrol S.A. in Colombia after a comprehensive review of international opportunities wherein we determined that Colombia offered an attractive mix of favorable business conditions, political stability, and a long-term commitment to expanding national oil and gas production. We have eight drilling rigs operating under drilling contracts in Colombia. We are continuously evaluating additional international expansion opportunities and intend to target international markets that share the favorable characteristics of our Colombian operations and which would allow us to deploy with sufficient scale to minimize management costs.

•

Continue Growth with Select Capital Deployment. We intend to invest in the growth of our business by continuing to strategically upgrade our existing assets, selectively engaging in new-build opportunities, and potentially making selective acquisitions. Our capital investment decisions are determined by an analysis of the projected return on capital employed. For significant capital expenditures, we have customarily identified the incremental revenue associated with the opportunity and secured use of the asset through contracts whenever possible. In addition to analyzing return on capital employed, we also require expenditures to be consistent with our strategic objectives. For example, we established our Appalachian drilling division location in 2009 to supply drilling rigs to the rapidly growing demand in the Marcellus Shale and began our operations in Colombia in 2007 to diversify our operations into the international market.

Liquidity and Capital Resources

Sources of Capital Resources

Our principal liquidity requirements have been for working capital needs, capital expenditures and acquisitions. Our principal sources of liquidity consist of: (i) cash and cash equivalents (which equaled $17.3 million as of June 30, 2010); (ii) cash generated from operations; and (iii) the unused portion of our senior secured revolving credit facility (the “Revolving Credit Facility”). Our Revolving Credit Facility provides for a senior secured revolving credit facility, with sub-limits for letters of credit and swing-line loans, of up to an aggregate principal amount of $225 million, all of which matures on August 31, 2012. At July 23, 2010, we had $22.8 million outstanding under our Revolving Credit Facility and $9.2 million in committed letters of credit, which results in borrowing availability of $193.0 million under our Revolving Credit Facility. There are no limitations on our ability to access the full borrowing availability under the Revolving Credit Facility other than maintaining compliance with the covenants in the

Revolving Credit Facility. In order to remain in compliance with our financial covenants, our borrowing availability under the Revolving Credit Facility was limited to an additional $50.4 million as of June 30, 2010. Additional information regarding these covenants is provided in the Debt Requirements section below. Borrowings under the Revolving Credit Facility are available for acquisitions, working capital and other general corporate purposes. We presently expect that cash and cash equivalents, cash generated from operations and available borrowings under our Revolving Credit Facility are adequate to cover our liquidity requirements for at least the next 12 months.

On March 11, 2010, we issued $250 million of senior notes (“Senior Notes”), and received $234.8 million net proceeds, after deducting the original issue discount, underwriters’ fees and other debt offering costs, which were used to reduce the outstanding debt balance under our Revolving Credit Facility. In July 2009, we filed a shelf registration statement that permits us to sell equity or debt in one or more offerings up to a total dollar amount of $300 million. In November 2009, we obtained $24.0 million in net proceeds when we sold 3,820,000 shares of our common stock at $6.75 per share, less underwriters’ commissions, pursuant to a public offering under the $300 million shelf registration statement. The remaining availability under the $300 million shelf registration statement for equity or debt offerings is $274.2 million as of July 23, 2010. In the future, we may consider equity or debt offerings, as appropriate, to meet our liquidity needs.

At June 30, 2010, we held $15.9 million (par value) of investments comprised of tax exempt, auction rate preferred securities (ARPS), which are variable-rate preferred securities and have a long-term maturity with the interest rate being reset through “Dutch auctions” that are held every 7 days. The ARPSs had historically traded at par because of the frequent interest rate resets and because they are callable at par at the option of the issuer. Interest is paid at the end of each auction period. Our ARPSs are AAA/Aaa rated securities, collateralized by municipal bonds and backed by assets that are equal to or greater than 200% of the liquidation preference. Until February 2008, the auction rate securities market was highly liquid. Beginning mid-February 2008, we experienced several “failed” auctions, meaning that there was not enough demand to sell all of the securities that holders desired to sell at auction. The immediate effect of a failed auction is that such holders cannot sell the securities at auction and the interest rate on the security resets to a maximum auction rate. We have continued to receive interest payments on our ARPSs in accordance with their terms. Unless a future auction is successful or the issuer calls the security pursuant to redemption prior to maturity, we may not be able to access the funds we invested in our ARPSs without a loss of principal. We have no reason to believe that any of the underlying municipal securities that collateralize our ARPSs are presently at risk of default. We believe we will ultimately recover the par value of the ARPSs without loss, primarily due to the collateral securing the ARPSs and our estimate of the discounted cash flows that we expect to collect. We do not currently intend to sell our ARPSs at a loss. Also, we believe it is more-likely-than-not that we will not have to sell our ARPSs prior to recovery, as our liquidity needs are expected to be met with cash flows from operating activities and borrowings under our Revolving Credit Facility. Our ARPSs are designated as available-for-sale and are reported at fair market value with the related unrealized gains or losses, included in accumulated other comprehensive income (loss), net of tax, a component of shareholders’ equity. The estimated fair value of our ARPSs at June 30, 2010 was $13.0 million compared with a par value of $15.9 million. The $2.9 million difference represents a fair value discount due to the current lack of liquidity which is considered temporary and has been recorded as an unrealized loss, net of tax, in accumulated other comprehensive income (loss). There was no portion of the fair value discount attributable to credit losses. We would recognize an impairment charge in our statement of operations if the fair value of our investments falls below the cost basis and is judged to be other-than-temporary. Our ARPSs are classified with other long-term assets on our condensed consolidated balance sheet as of June 30, 2010 because of our inability to determine the recovery period of our investments.

Uses of Capital Resources

For the six months ended June 30, 2010, we had $83.6 million of additions to our property and equipment. For the remainder of fiscal year 2010, our budgeted capital expenditures are approximately $62.0 million, comprised of new equipment expenditures of approximately $3.1 million, routine capital expenditures of approximately $20.8 million, non-routine capital expenditures of approximately $37.3 million and approximately $0.8 million for previously approved capital expenditures from 2009. We expect to fund these capital expenditures primarily from operating cash flow in excess of our working capital and other normal cash flow requirements and availability under our Revolving Credit Facility. In addition, as appropriate, we may consider equity or debt offerings to meet our liquidity needs. Based on our near-term strategy to maintain adequate liquidity, budgeted capital expenditures for 2010 represent routine capital expenditures necessary to keep our equipment in safe and efficient working order and discretionary capital expenditures for new equipment or upgrades of existing equipment when necessary to obtain new contracts.

Working Capital

Our working capital was $38.1 million at June 30, 2010, compared to $90.3 million at December 31, 2009. Our current ratio, which we calculate by dividing our current assets by our current liabilities, was 1.4 at June 30, 2010 compared to 2.9 at December 31, 2009.

Our operations have historically generated cash flows sufficient to meet our requirements for debt service and normal capital expenditures. However, during periods when higher percentages of our drilling contracts are turnkey and footage contracts, our short-term working capital needs could increase.

The changes in the components of our working capital were as follows:


	June 30, 2010		December 31, 2009		Change
Cash and cash equivalents	$	17,348	$	40,379	$	(23,031	)
Receivables
Trade, net		56,562		26,648		29,914
Unbilled		23,371		8,586		14,785
Insurance recoveries		4,794		5,107		(313	)
Income taxes		2,795		41,126		(38,331	)
Deferred income taxes		9,400		5,560		3,840
Inventory		7,832		5,535		2,297
Prepaid expenses and other current		7,994		6,199		1,795


Current assets		130,096		139,140		(9,044	)


Accounts payable		45,303		15,324		29,979
Current portion of long-term debt		1,897		4,041		(2,144	)
Prepaid drilling contracts		3,679		408		3,271
Accrued expenses:
Employee related employee costs		12,527		7,740		4,787
Insurance premiums and deductibles		9,105		8,615		490
Insurance claims and settlements		4,599		5,042		(443	)
Other		14,875		7,634		7,241


Current liabilities		91,985		48,804		43,181


Working capital	$	38,111	$	90,336	$	(52,225	)

The decrease in cash and cash equivalents was primarily due to $63.8 million used for purchases of property and equipment, offset by cash provided by operations of $42.6 million during the six months ended June 30, 2010.

The increases in our trade receivables and unbilled revenues as of June 30, 2010 as compared to December 31, 2009 were due to the increase in revenues of $35.8 million, or 44%, for the quarter ended June 30, 2010 as compared to the quarter ended December 31, 2009, and due to the timing of the billing and collection cycles for new long-term drilling contracts that began during the six months ended June 30, 2010 in Colombia.

Income taxes receivable as of December 31, 2009 primarily related to net operating losses recognized during 2009. We applied our net operating losses against taxable income that we recognized in prior years which resulted in a federal tax refund. Our income taxes receivable decreased at June 30, 2010, as we received a federal income tax refund of $40.6 million in April 2010 primarily related to the carry-back of our 2009 net operating losses.

The increase in deferred income taxes is due to the movement of our deferred tax assets related to net operating losses for our Colombian operations from long-term to current, as we now expect to realize them in the short-term due to the increase in our foreign operations through 2010.

The increase in inventory at June 30, 2010 as compared to December 31, 2009 was primarily due to the expansion of our operations in Colombia. We exported our seventh and eighth drilling rigs to Colombia during the six months ended June 30, 2010. We maintain inventories of replacement parts and supplies for our drilling rigs operating in Colombia to ensure efficient operations in geographically remote areas.

The increase in prepaid expenses and other current assets at June 30, 2010 as compared to December 31, 2009 is primarily due to an increase in deferred mobilization costs for drilling rigs that began new long-term drilling contracts during the six months ended June 30, 2010. These deferred mobilization costs will be amortized over the contract term. The overall increase in prepaid expenses and other current assets was partially offset by a decrease in prepaid insurance. We renew and prepay most of our insurance premiums in late October of each year and some in April of each year. As of June 30, 2010, we had amortization of eight months of these October insurance premiums, as compared to two months of amortization as of December 31, 2009.

The increase in accounts payable at June 30, 2010 as compared to December 31, 2009 is due to the overall increase in the demand for drilling, workover, wireline and fishing and rental services during the quarter ended June 30, 2010 as compared to the quarter ended December 31, 2009. Our operating costs increased $25.9 million, or 45%, during the second quarter of 2010 as compared to the fourth quarter of 2009. In addition, our capital expenditures increased for the quarter ended June 30, 2010 as compared to the quarter ended December 31, 2009, accounting for $19.0 million of the increase in accounts payable. Both the increase in the demand for our services and the increase in capital expenditures led to an increase in purchases from our vendors.

The current portion of long-term debt at June 30, 2010 relates to $1.9 million of debt payments under our subordinated notes payable and other debt that are due within the next year.

Prepaid drilling contracts represent amounts billed for mobilization revenues in excess of revenue recognized for certain drilling contracts. Mobilization billings, and costs incurred for the mobilization, are deferred and recognized over the term of the related drilling contracts. The increase in prepaid drilling contracts at June 30, 2010 as compared to December 31, 2009 is primarily due to an increase in deferred mobilization revenues for four drilling rigs in Colombia that began new long-term drilling contracts during the six months ended June 30, 2010.

The increase in accrued payroll and related employee costs was primarily due to workforce additions that occurred as the result of higher demand for drilling, workover, wireline and fishing and rental services during the six months ended June 30, 2010 as compared to the quarter ended December 31, 2009. Our employee count increased by approximately 650 people, or 38%, as of June 30, 2010 as compared to December 31, 2009.

The increase in accrued expenses – other is primarily due to an increase in accrued interest, which increased from $0.3 million at December 31, 2009 to $7.6 million at June 30, 2010. Accrued interest at June 30, 2010 primarily relates to the outstanding debt balance for our Senior Notes, while accrued interest at December 31, 2009 primarily related to the outstanding debt balance under our Revolving Credit Facility. On March 11, 2010, we issued $250 million of Senior Notes with a coupon interest rate of 9.875%. The Senior Notes were sold with an original issue discount that will result in an effective yield to maturity of approximately 10.677%. The proceeds from the issuance of the Senior Notes were immediately used to make a payment of $234.8 million to reduce the outstanding debt balance under the Revolving Credit Facility. The Revolving Credit Facility had an interest rate of 3.74% as of December 31, 2009 which was based on the LIBOR rate plus a per annum margin, with interest payments due monthly. The Senior Notes have a higher interest rate as compared to the Revolving Credit Facility, with interest payments due semi-annually, which resulted in an increase in accrued interest as of June 30, 2010.

Long-Term Debt and Other Contractual Obligations

The following table includes all our contractual obligations of the types specified below at June 30, 2010 (amounts in thousands):


	Payments Due by Period
Contractual Obligations	Total		Less than 1 year		2-3 years		4-5 years		More than 5 years
Long-term debt	$	276,763	$	1,897	$	24,866	$	—	$	250,000
Interest on long-term debt		201,250		26,621		51,191		49,375		74,063
Purchase obligations		14,842		14,842		—		—		—
Operating leases		7,049		2,393		3,372		1,284		—
Restricted cash obligation		1,950		650		1,300		—		—


Total	$	501,854	$	46,403	$	80,729	$	50,659	$	324,063

Long-term debt consists of $22.8 million outstanding under our Revolving Credit Facility, $250 million face amount outstanding under our Senior Notes, $3.9 million outstanding under subordinated notes payable to certain employees that are former shareholders of previously acquired production services businesses, and other debt of $0.2 million. The outstanding balance under our Revolving Credit Facility is not due until maturity on August 31, 2012. However, we may make principal payments to reduce the outstanding debt balance prior to maturity when cash and working capital is sufficient. The outstanding balance under our Senior

Notes has a carrying value of $239.6 million, which represents the $250 million face value net of the $10.4 million of original issue discount, net of amortization. The discount is being amortized over the term of the Senior Notes based on the effective interest method. The Senior Notes will mature on March 15, 2018. Our subordinated notes payable have final maturity dates ranging from November 2010 to April 2013.

Interest payment obligations on our Revolving Credit Facility are estimated based on (1) the 5.85% interest rate that was in effect on July 23, 2010 and (2) the remaining principal balance of $22.8 million to be paid at maturity in August 2012. Interest payment obligations on our Senior Notes are calculated based on the coupon interest rate of 9.875% due semi-annually in arrears on March 15 and September 15 of each year, commencing on September 15, 2010, through maturity. Interest payment obligations on our subordinated notes payable are based on interest rates ranging from 5.4% to 14%, with either quarterly or annual payments of principal and interest through maturity.

Purchase obligations primarily relate to equipment upgrades and purchases of new equipment.

Operating leases consist of lease agreements with terms in excess of one year for office space, operating facilities, equipment and personal property.

As of June 30, 2010, we had restricted cash in the amount of $2.0 million held in an escrow account to be used for future payments in connection with the acquisition of Competition. The former owner of Competition will receive annual installments of $0.7 million payable over the remaining three years from the escrow account.

Debt Requirements

The Revolving Credit Facility contains customary mandatory prepayments in respect of asset dispositions, debt incurrence and equity issuances, which are applied to reduce outstanding revolving and swing-line loans and letter of credit exposure. There are no limitations on our ability to access the $225 million borrowing capacity under the Revolving Credit Facility other than maintaining compliance with the covenants. At June 30, 2010, we were in compliance with our financial covenants. Our total consolidated leverage ratio was 4.25 to 1.0, our senior consolidated leverage ratio was 0.48 to 1.0, and our interest coverage ratio was 4.04 to 1.0. In order to remain in compliance with our financial covenants, our borrowing availability under the Revolving Credit Facility was limited to an additional $50.4 million as of June 30, 2010.

The financial covenants contained in our Revolving Credit Facility include the following:

•

A maximum total consolidated leverage ratio that cannot exceed:

•

5.00 to 1.00 as of the end of any fiscal quarter ending June 30, 2010 through June 30, 2011;

•

4.75 to 1.00 as of the end of the fiscal quarter ending September 30, 2011;

•

4.50 to 1.00 as of the end of the fiscal quarter ending December 31, 2011;

•

4.25 to 1.00 as of the end of the fiscal quarter ending March 31, 2012; and

•

4.00 to 1.00 as of the end of any fiscal quarter ending June 30, 2012 and thereafter.

•

A maximum senior consolidated leverage ratio, which excludes unsecured and subordinated debt, that cannot exceed:

•

5.00 to 1.00 as of the end of the fiscal quarters ending June 30, 2010;

•

4.75 to 1.00 as of the end of the fiscal quarter ending September 30, 2010;

•

4.50 to 1.00 as of the end of the fiscal quarter ending December 31, 2010;

•

4.25 to 1.00 as of the end of the fiscal quarter ending March 31, 2011;

•

4.00 to 1.00 as of the end of the fiscal quarter ending June 30, 2011;

•

3.75 to 1.00 as of the end of the fiscal quarter ending September 30, 2011;

•

3.50 to 1.00 as of the end of the fiscal quarter ending December 31, 2011;

•

3.25 to 1.00 as of the end of the fiscal quarter ending March 31, 2012; and

•

3.00 to 1.00 as of the end of any fiscal quarter ended June 30, 2012 and thereafter.

•

A minimum interest coverage ratio that cannot be less than:

•

2.00 to 1.00 as of the end of any fiscal quarter ending June 30, 2010 through December 31, 2011; and

•

3.00 to 1.00 as of the end of any fiscal quarter ending March 31, 2012 and thereafter.

•

$65 million for fiscal year 2010; and

•

$80 million for each fiscal year thereafter.

The capital expenditure thresholds for each period noted above may be increased by:

•

the first $25 million of any aggregate equity issuance proceeds received during such period and 25% of any equity issuance proceeds received in excess of $25 million during such period; and

•

25% of any debt incurrence proceeds received during such period.

In addition, any unused portion of the capital expenditure threshold up to $30 million can be carried over from the immediate preceding fiscal year.

At June 30, 2010, our senior consolidated leverage ratio was not greater than 2.50 to 1.00 and therefore, we were not subject to the capital expenditure threshold restrictions listed above.

Our obligations under the Revolving Credit Facility are secured by substantially all of our domestic assets (including equity interests in Pioneer Global Holdings, Inc. and 65% of the outstanding equity interests of any first-tier foreign subsidiaries owned by Pioneer Global Holdings, Inc., but excluding any equity interest in, and any assets of, Pioneer Services Holdings, LLC) and are guaranteed by certain of our domestic subsidiaries, including Pioneer Global Holdings, Inc.

In addition to the financial covenants under our Revolving Credit Facility, the Indenture Agreement for our Senior Notes contains certain restrictions on our ability to:

•

pay dividends on stock;

•

repurchase stock or redeem subordinated debt or make other restricted payments;

•

incur, assume or guarantee additional indebtedness or issue disqualified stock;

•

create liens on our assets;

•

enter into sale and leaseback transactions;

•

restrict dividends, loans or other asset transfers from certain of our subsidiaries;

•

consolidate with or merge with or into, or sell all or substantially all of our properties to another person;

•

enter into transactions with affiliates; and

•

enter into new lines of business.

These covenants are subject to important exceptions and qualifications.

Our Senior Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by our existing domestic subsidiaries, except for Pioneer Services Holdings, LLC, and by certain of our future domestic subsidiaries. The subsidiaries that generally operate our non-U.S. business concentrated in Colombia do not guarantee our Senior Notes. The non-guarantor subsidiaries do not have any payment obligations under the Senior Notes, the guarantees or the Indenture. In the event of a bankruptcy, liquidation or reorganization of any non-guarantor subsidiary, such non-guarantor subsidiary will pay the holders of its debt and other liabilities, including its trade creditors, before it will be able to distribute any of its assets to us. In the future, any non-U.S. subsidiaries, immaterial subsidiaries and subsidiaries that we designate as unrestricted subsidiaries under the Indenture will not guarantee the Senior Notes.

Our Senior Notes are not subject to any sinking fund requirements. As of June 30, 2010, there were no restrictions on the ability of subsidiary guarantors to transfer funds to the parent company, and we were in compliance with all covenants pertaining to our Senior Notes.

Results of Operations

Statement of Operations Analysis

The following table provides information for our operations for the three and six months ended June 30, 2010 and 2009 (amounts in thousands, except average number of drilling rigs, utilization rate and revenue day information):


	Three Months Ended June 30,						Six Months Ended June 30,
	2010			2009			2010			2009
Drilling Services Division:
Revenues	$	76,096		$	45,720		$	131,913		$	117,086
Operating costs		58,549			28,437			104,452			72,565

Drilling Services Division margin	$	17,547		$	17,283		$	27,461		$	44,521


Average number of drilling rigs		71.0			70.7			71.0			70.3
Utilization rate		58	%		35	%		54	%		44	%
Revenue days		3,775			2,238			6,927			5,534

Average revenues per day	$	20,158		$	20,429		$	19,043		$	21,158
Average operating costs per day		15,510			12,706			15,079			13,113


Drilling Services Division margin per day	$	4,648		$	7,723		$	3,964		$	8,045


Production Services Division:
Revenues	$	40,931		$	23,400		$	71,135		$	52,874
Operating costs		24,527			14,906			44,492			33,622

Production Services Division margin	$	16,404		$	8,494		$	26,643		$	19,252


Combined
Revenues	$	117,027		$	69,120		$	203,048		$	169,960
Operating costs		83,076			43,343			148,944			106,187

Combined margin	$	33,951		$	25,777		$	54,104		$	63,773


EBITDA	$	22,016		$	17,936		$	31,255		$	45,724

We present Drilling Services Division margin, Production Services Division margin, combined margin and earnings before interest, taxes, depreciation and amortization (EBITDA) information because we believe it provides investors and our management additional information to assist them in assessing our business and performance in comparison to other companies in our industry.

Since Drilling Services Division margin, Production Services Division margin, combined margin and EBITDA are “non-GAAP” financial measure under the rules and regulations of the SEC, we are providing the following reconciliation of combined margin and EBITDA to net (loss) earnings, which is the nearest comparable GAAP financial measure.


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
	(amounts in thousands)
Reconciliation of combined margin and EBITDA to net loss:
Combined margin	$	33,951		$	25,777		$	54,104		$	63,773

Selling, general and administrative		(12,257	)		(8,951	)		(23,730	)		(18,978	)
Bad debt recovery		7			(30	)		82			304
Other (expense) income		315			1,140			799			625

EBITDA		22,016			17,936			31,255			45,724

Depreciation and amortization		(29,557	)		(26,069	)		(58,428	)		(51,515	)
Interest expense, net		(7,099	)		(1,673	)		(11,173	)		(3,577	)
Income tax benefit		4,498			3,547			13,657			3,727

Net loss	$	(10,142	)	$	(6,259	)	$	(24,689	)	$	(5,641	)

Our Drilling Services Division’s revenues increased by $30.4 million, or 66%, for the quarter ended June 30, 2010, as compared to the corresponding quarter in 2009, due to a 69% increase in revenue days that resulted from an increase in our rig utilization rate from 35% to 58%. For the six months ended June 30, 2010, our Drilling Services Division’s revenues increased by $14.8 million, or 13%, as compared to the corresponding period in 2009, due to a 25% increase in revenue days that resulted from an increase in our rig utilization rate from 44% to 54%. We have experienced an increase in the demand for drilling services in 2010 as our industry begins to recover from the downturn that bottomed in late 2009. Consequently, utilization rates and drilling revenue rates have improved in 2010 as compared to 2009. However, our Drilling Services Division’s average revenues decreased by $271 per day, or 1%, during the three months ended June 30, 2010, and decreased by $2,115 per day, or 10%, during the six months ended June 30, 2010, when compared to the corresponding periods in 2009. During 2009, a significant portion of our drilling rigs were still operating or were on standby under long-term drilling contracts that were entered into when drilling rig demand was high and drilling revenues per day were at historically high levels. The positive impact of the higher revenue rates for these long-term contracts had a diminishing affect on our average revenues per day as the contracts expired ratably during 2009. The overall decreases in our average drilling revenues per day during 2010 as compared to 2009 was partially offset by higher average revenues per day due to a larger proportion of our Drilling Services Division’s revenues attributable to our Colombian operations during 2010, as drilling contracts in Colombia have higher revenue rates per day when compared to domestic drilling contracts.

Demand for drilling rigs influences the types of drilling contracts we are able to obtain. As demand for drilling rigs decreases, daywork rates move down and we may switch to performing more turnkey drilling contracts to maintain higher utilization rates and improve our Drilling Services Division’s margins. We completed two and six turnkey drilling contracts during the three and six months ended June 30, 2010, respectively, as compared to two and three turnkey drilling contracts completed during the three and six months ended June 30, 2009. The following table provides percentages of our drilling revenues by drilling contract type for the three and six months ended June 30, 2010 and 2009:


	Three Months Ended June 30,				Six Months Ended June 30,
	2010		2009		2010		2009
Daywork drilling contracts	89	%	92	%	90	%	96	%
Turnkey drilling contracts	11	%	8	%	10	%	4	%
Footage drilling contracts	—		—		—		—

Our Drilling Services Division’s operating costs increased by $30.1 million, or 106%, for the quarter ended June 30, 2010, as compared to the corresponding quarter in 2009, primarily due to the increase in utilization, and the increase in our average operating costs of $2,804 per day, or 22%. For the six months ended June 30, 2010, our Drilling Services Division’s operating costs increased $31.9 million, or 44%, as compared to the corresponding period in 2009, primarily due to the increase in utilization and the increase in our operating costs of $1,966 per day, or 15%. The increase in operating costs per day is due to higher average drilling

costs per day for our domestic operations, as well as the increased proportion of our operations in Colombia during 2010 as compared to 2009, where we have a higher average cost per day, as compared to our domestic operations. During 2010, we have seen an increase in the demand for our services as our industry begins to recover from the downturn that bottomed in late 2009. As utilization rates began to increase in 2010, average operating costs per day increased due to higher wage rates and repair and maintenance expenses as drilling rigs come out of storage and begin operations. In addition, average operating costs per day in 2009 were lower due to a significant portion of our drilling rigs earning standby revenue rates under longer-term drilling contracts and incurring reduced operating costs. A shift to more turnkey contracts during the three and six months ended June 30, 2010 as compared to the same period in 2009 also contributed to the increase in average operating costs per day.

Our Production Services Division’s revenues increased by $17.5 million, or 75%, while operating costs increased $9.6 million, or 65%, for the quarter ended June 30, 2010, as compared to the corresponding quarter in 2009. For the six months ended June 30, 2010, our Production Services Division’s revenue increased by $18.3 million, or 35%, while operating costs increased by $10.9 million, or 32%, as compared to the corresponding period in 2009. Our Production Services Division experienced increases in its revenue and operating cost due to higher demand for our wireline services, well services and fishing and rental services during the three and six months ended June 30, 2010, as compared to the corresponding periods in 2009. The increase in our Production Services Division’s revenues is due primarily to higher utilization rates, especially in the wireline services operations, and partially offset by lower revenue rates charged for these services as revenue rates have remained at lower levels during the first half of 2010, as compared to the corresponding period in 2009.

For the three and six months ended June 30, 2010, our selling, general and administrative expense increased by approximately $3.3 million and $4.8 million, or 37% and 25%, respectively, as compared to the corresponding periods in 2009. The increase is primarily due to increases in compensation related expenses. With the industry downturn during 2009, we experienced a decrease in the demand for our services and we responded with workforce reductions, elimination of wage rate increases and reduced bonus compensation. During the first and second quarters of 2010, we have seen an increase in the demand for our services as our industry begins to recover from the industry downturn in 2009. Compensation related expenses increased during the three and six months ended June 30, 2010 as compared to the corresponding quarters in 2009 as we have added employees in our corporate office and have accrued for potential higher bonuses anticipated for 2010.

Our other income decreased by $0.8 million for the quarter ended June 30, 2010, as compared to the corresponding quarter in 2009, primarily due to the decrease in foreign currency translation gains in excess of losses recognized in relation to our operations in Colombia. We recorded foreign currency translation gains of $0.2 million for the three months ended June 30, 2010, and foreign currency translation gains of $1.0 million for the three months ended June 30, 2009. For the six months ended June 30, 2010, our other income increased by $0.2 million, as compared to the corresponding period in 2009, primarily due to an increase in the foreign currency translation gains recognized in relation to our operations in Colombia. We recorded foreign currency translation gains of $0.6 million for the six months ended June 30, 2010, and foreign currency translation gains of $0.2 million for the six months ended June 30, 2009.

For the three and six months ended June 30, 2010, our depreciation and amortization expenses increased by $3.5 million and $6.9 million respectively, or 13%, as compared to the corresponding periods in 2009. This increase resulted from capital expenditures made to upgrade certain drilling rigs to meet the needs of our customers and obtain new contracts as well as capital expenditures for the acquisition of new wireline units.

Interest expense for the three and six months ended June 30, 2010 primarily related to the outstanding debt balance for our Senior Notes, while interest expense for the three and six months ended June 30, 2009 primarily related to the outstanding debt balance under our Revolving Credit Facility. On March 11, 2010, we issued $250 million of Senior Notes with a coupon interest rate of 9.875%. The Senior Notes were sold with an original issue discount that will result in an effective yield to maturity of approximately 10.677%. The proceeds from the issuance of the Senior Notes were immediately used to make a payment of $234.8 million to reduce the outstanding debt balance under the Revolving Credit Facility. The Revolving Credit Facility had a relatively low interest rate of 2.28% and 2.07% as of March 31, 2009 and June 30, 2009, respectively, which was based on the LIBOR rate plus a per annum margin. The Senior Notes have a higher interest rate when compared to the Revolving Credit Facility, which resulted in the increase in interest expense for the three and six months ended June 30, 2010. The increase in interest expense is slightly offset by the related increase in capitalized interest during 2010. We recognized $0.4 million and $0.5 million of capitalized interest during the three and six months ended June 30, 2010, as compared to $0.1 and $0.2 million during the three and six months ended June 30, 2009.

Our effective income tax rates for the three and six month periods ended June 30, 2010 differ from the federal statutory rate in the United States of 35% primarily due to a lower effective tax rate in foreign jurisdictions, state income taxes and other permanent differences.

Inflation

Wage rates for our operations personnel are impacted by inflationary pressures when the demand for drilling and production services increases and the availability of personnel is scarce. From early 2005 to late 2008, the increased rig count in each of our market areas resulted in increased wage rates for our drilling rig personnel. We were able to pass these wage rate increases on to our customers based on contract terms. Beginning in late 2008 and through late 2009, as the rig count in our market areas decreased, we reduced wage rates for drilling rig personnel. With the recent increase in rig counts, beginning in late 2009, we again saw a decreased availability of personnel to operate our rigs and therefore we had additional wage rate increases for drilling rig personnel of approximately 18% and 16% in February and July 2010, respectively.

During the fiscal years ended December 31, 2007 and 2008, we experienced increases in costs for rig repairs and maintenance and costs of rig upgrades and new rig construction, due to the increased industry-wide demand for equipment, supplies and service. We estimate these costs increased by 10% to 15% during the fiscal years ended December 31, 2007 and 2008. We have not experienced similar cost increases during 2009; however we expect a modest increase of less than 5% during 2010.

Off Balance Sheet Arrangements

We do not currently have any off balance sheet arrangements.

Critical Accounting Policies and Estimates

Revenue and cost recognition—Our Drilling Services Division earns revenues by drilling oil and gas wells for our customers under daywork, turnkey 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. We recognize revenues from our turnkey and footage contracts on the percentage-of-completion method based on our estimate of the number of days to complete each contract. Individual contracts are usually completed in less than 60 days. The risks to us under a turnkey contract and, to a lesser extent, under footage contracts, are substantially greater than on a contract drilled on a daywork basis. Under a turnkey contract, we assume most of the risks associated with drilling operations that are generally assumed by the operator in a daywork contract, including the risks of blowout, loss of hole, stuck drill pipe, machinery breakdowns and abnormal drilling conditions, as well as risks associated with subcontractors’ services, supplies, cost escalations and personnel operations.

Our management has determined that it is appropriate to use the percentage-of-completion method, as defined in the Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) Topic 605 (formerly American Institute of Certified Public Accountants’ Statement of Position 81-1), to recognize revenue on our turnkey and footage contracts. Although our turnkey and 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-on 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 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-on depth in breach of the applicable contract. However, in the event we were unable to drill to the agreed-on depth in breach of the contract, ultimate recovery of that value would be subject to negotiations with the customer and the possibility of litigation.

If a customer defaults on its payment obligation to us under a turnkey or footage contract, we would need to rely on applicable law to enforce our lien rights, because our turnkey and 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 also would 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 turnkey or footage contract.

We accrue estimated contract costs on turnkey and 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, operating overhead allocations and allocations of depreciation and amortization expense. In addition, the occurrence of uninsured or under-insured losses or operating cost overruns on our turnkey and footage contracts could have a material adverse effect on our financial position and results of operations. Therefore, our actual results for a contract could differ significantly if our cost estimates for that contract are later revised from our original cost estimates for a contract in progress at the end of a reporting period which was not completed prior to the release of our financial statements.

With most drilling contracts, we receive payments contractually designated for the mobilization of rigs and other equipment. Payments received, and costs incurred for the mobilization services are deferred and recognized on a straight line basis over the contract term of certain drilling contracts. Costs incurred to relocate rigs and other drilling equipment to areas in which a contract has not been secured are expensed as incurred. Reimbursements that we receive for out-of-pocket expenses are recorded as revenue and the out-of-pocket expenses for which they relate are recorded as operating costs.

The asset “unbilled receivables” represents revenues we have recognized in excess of amounts billed on drilling contracts and production services in progress. The assets “prepaid expenses and other current assets” and “other long-term assets” include the current and long-term portions of deferred mobilization costs for certain drilling contracts. The liabilities “prepaid drilling contracts” and “other long-term liabilities” include the current and long-term portions of deferred mobilization revenues for certain drilling contracts and amounts collected on contracts in excess of revenues recognized.

Our Production Services Division earns revenues for well services, wireline services and fishing and rental services pursuant to master services agreements based on purchase orders, contracts or other persuasive evidence of an arrangement with the customer that include fixed or determinable prices. Production service revenue is recognized when the service has been rendered and collectability is reasonably assured.

Long-lived Assets and Intangible Assets—We evaluate for potential impairment of long-lived assets and intangible assets subject to amortization when indicators of impairment are present, as defined in ASC Topic 360 (formerly SFAS No. 144). Circumstances that could indicate a potential impairment include significant adverse changes in industry trends, economic climate, legal factors, and an adverse action or assessment by a regulator. More specifically, significant adverse changes in industry trends include significant declines in revenue rates, utilization rates, oil and natural gas market prices and industry rig counts for drilling rigs and workover rigs. In performing the impairment evaluation, we estimate the future undiscounted net cash flows relating to long-lived assets and intangible assets grouped at the lowest level that cash flows can be identified. For our Production Services Division, our long-lived assets and intangible assets are grouped at the reporting unit level which is one level below the operating segment level. For our Drilling Services Division, we perform an impairment evaluation and estimate future undiscounted cash flows for individual drilling rig assets. If the sum of the estimated future undiscounted net cash flows is less than the carrying amount of the long-lived assets and intangible assets for these asset grouping levels, then we would recognize an impairment charge. The amount of an impairment charge would be measured as the difference between the carrying amount and the fair value of these assets. The assumptions used in the impairment evaluation for long-lived assets and intangible assets are inherently uncertain and require management judgment.

Goodwill—Goodwill results from business acquisitions and represents the excess of acquisition costs over the fair value of the net assets acquired. We account for goodwill and other intangible assets under the provisions of ASC Topic 350 (formerly SFAS No. 142), Goodwill and Other Intangible Assets. Goodwill is tested for impairment annually as of December 31 or more frequently if events or changes in circumstances indicate that the asset might be impaired. Circumstances that could indicate a potential impairment include a significant adverse change in the economic or business climate, a significant adverse change in legal factors, an adverse action or assessment by a regulator, unanticipated competition, loss of key personnel and the likelihood that a reporting unit or significant portion of a reporting unit will be sold or otherwise disposed of. These circumstances could lead to our net book value exceeding our market capitalization which is another indicator of a potential impairment in goodwill. ASC Topic 350 requires a two-step process for testing impairment. First, the fair value of each reporting unit is compared to its carrying value to determine whether an indication of impairment exists. Second, if impairment is indicated, then the fair value of the reporting unit's goodwill is determined by allocating the unit's fair value to its assets and liabilities (including any unrecognized intangible assets) as if the reporting unit had been acquired in a business combination on the impairment test date. The amount of impairment for goodwill is measured as the excess of the carrying value of the reporting unit over its fair value. Goodwill of $118.6 million was initially recorded in connection with the acquisitions of the production services businesses from WEDGE, Competition, Pettus and Paltec, all of which occurred between March 1, 2008 and October 1, 2008, and was allocated to the three reporting units for our Production Services Division which are well services, wireline services and fishing and rental services. We recorded a full impairment of this goodwill during the year ended December 31, 2008. We had no goodwill additions during the year ended December 31, 2009, or during the six months ended June 30, 2010.

Deferred taxes—We provide deferred taxes for the basis differences in our property and equipment between financial reporting and tax reporting purposes and other costs such as compensation, net operating loss carryforwards, employee benefit and other accrued liabilities which are deducted in different periods for 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 an entity rather than just its assets. For financial reporting purposes, we depreciate the various components of our drilling rigs, workover rigs and wireline units over 2 to 25 years and refurbishments over 3 to 5 years, while federal income tax rules require that we depreciate drilling rigs, workover rigs and wireline units over 5 years. Therefore, in the first 5 years of our ownership of a drilling rig, workover rig or wireline unit, our tax depreciation exceeds our financial reporting depreciation, resulting in our providing deferred taxes on this depreciation difference. After 5 years, financial reporting depreciation exceeds tax depreciation, and the deferred tax liability begins to reverse.

Accounting estimates—We consider the recognition of revenues and costs on turnkey and footage contracts to be critical accounting estimates. On these types of contracts, we are required to estimate the number of days needed for us to complete the contract and our total cost to complete the contract. Our actual costs could substantially exceed our estimated costs if we encounter problems such as lost circulation, stuck drill pipe or an underground blowout on contracts still in progress subsequent to the release of the financial statements. We receive payment under turnkey and 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 more shallow depth. Since 1995, we have completed all our turnkey or footage contracts. Although our initial cost estimates for turnkey and footage contracts do not include cost estimates for risks such as stuck drill pipe or loss of circulation, we believe that our experienced management team, our knowledge of geologic formations in our areas of operations, the condition of our drilling equipment and our experienced crews have previously enabled us to make reasonable 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 turnkey and 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 increase our cost estimate to complete the contract. 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 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 the six months ended June 30, 2010, we experienced a loss of $0.2 million on one turnkey contract. During the year ended December 31, 2009, we did not experience a loss on any turnkey or footage contracts completed. We are more likely to encounter losses on turnkey and footage contracts in periods in which revenue rates are lower for all types of contracts. During periods of reduced demand for drilling rigs, our overall profitability on turnkey and footage contracts has historically exceeded our profitability on daywork contracts.

Revenues and costs during a reporting period could be affected for contracts in progress at the end of a reporting period which have not been completed before our financial statements for that period are released. We had two turnkey and no footage contracts in progress at June 30, 2010, both of which were completed prior to the release of the financial statements included in this report. Our unbilled receivables totaled $23.4 million at June 30, 2010. Of that amount accrued, turnkey drilling contract revenues were $4.8 million. The remaining balance of unbilled receivables related to $17.4 million of the revenue recognized but not yet billed on daywork drilling contracts in progress at June 30, 2010 and $1.2 million related to unbilled receivables for our Production Services Division.

As of June 30, 2010, we had $20.4 million deferred tax assets relating to domestic and foreign net operating losses available to reduce future taxable income. In assessing the realizability of our deferred tax assets, we only recognize a tax benefit to the extent of taxable income that we expect to earn in the jurisdiction in future periods. We estimate that our operations will result in taxable income in excess of our net operating losses and we expect to apply the net operating losses against the current year taxable income and taxable income that we have estimated in future periods. Therefore, as of June 30, 2010, we have not recorded a valuation allowance.

We estimate an allowance for doubtful accounts based on the creditworthiness of our customers as well as general economic conditions. We evaluate the creditworthiness of our customers based on commercial credit reports, trade references, bank references, financial information, production information and any past experience we have with the customer. Consequently, any 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 15-day intervals during the performance of daywork contracts and upon completion of the daywork contract. Turnkey and 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 90 days for any of our contracts in the last three fiscal years. We had an allowance for doubtful accounts of $0.2 million at June 30, 2010 and $0.3 million at December 31, 2009.

Our determination of the useful lives of our depreciable assets, which directly affects our determination of depreciation expense and deferred taxes is also a critical accounting estimate. A decrease in the useful life of our property and equipment would increase depreciation expense and reduce deferred taxes. We provide for depreciation of our drilling, production, transportation and other equipment on a straight-line method over useful lives that we have estimated and that range from 2 to 25 years. We record the same depreciation expense whether a drilling rig, workover rig or wireline unit is idle or working. Our estimates of the useful lives of our drilling, production, transportation and other equipment are based on our more than 35 years of experience in the oilfield services industry with similar equipment.

Our accrued insurance premiums and deductibles as of June 30, 2010 include accruals for costs incurred under the self-insurance portion of our health insurance of approximately $1.1 million and our workers’ compensation, general liability and auto liability insurance of approximately $7.2 million. We have a deductible of $125,000 per covered individual per year under the health insurance. We have a deductible of $500,000 per occurrence under our workers’ compensation insurance, except in North Dakota, where we have a $100,000 deductible. We have deductibles of $250,000 and $100,000 per occurrence under our general liability insurance and auto liability insurance, respectively. We accrue for these costs as claims are incurred based on historical claim development data, and we accrue the costs of administrative services associated with claims processing. We also evaluate our workers’ compensation claim cost estimates based on estimates provided by a professional actuary.

Recently Issued Accounting Standards

ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Interest Rate Risk

We are subject to interest rate market risk on our variable rate debt. As of June 30, 2010, we had $22.8 million outstanding under our Revolving Credit Facility subject to variable interest rate risk. The impact of a 1% increase in interest rates on this amount of debt would result in increased interest expense of approximately $57,000 and a decrease in net income of approximately $37,000 during a quarterly period.

At June 30, 2010, we held $15.9 million (par value) of investments comprised of tax exempt, auction rate preferred securities (ARPS), which are variable-rate preferred securities and have a long-term maturity with the interest rate being reset through “Dutch auctions” that are held every 7 days. The ARPSs had historically traded at par because of the frequent interest rate resets and because they are callable at par at the option of the issuer. Interest is paid at the end of each auction period. Our ARPSs are AAA/Aaa rated securities, collateralized by municipal bonds and backed by assets that are equal to or greater than 200% of the liquidation preference. Until February 2008, the auction rate securities market was highly liquid. Beginning mid-February 2008, we experienced several “failed” auctions, meaning that there was not enough demand to sell all of the securities that holders desired to sell at auction. The immediate effect of a failed auction is that such holders cannot sell the securities at auction and the interest rate on the security resets to a maximum auction rate. We have continued to receive interest payments on our ARPSs in accordance with their terms. Unless a future auction is successful or the issuer calls the security pursuant to redemption prior to maturity, we may not be able to access the funds we invested in our ARPSs without a loss of principal. We have no reason to believe that any of the underlying municipal securities that collateralize our ARPSs are presently at risk of default. We believe we will ultimately recover the par value of the ARPSs without a loss, primarily due to the collateral securing the ARPSs and our estimate of the discounted cash flows that we expect to collect. We do not currently intend to sell our ARPSs at a loss. Also, we believe it is more-likely-than-not that we will not have to sell our ARPSs prior to recovery, as our liquidity needs are expected to be met with cash flows from operating activities and our Revolving Credit Facility. Our ARPSs are designated as available-for-sale and are reported at fair market value with the related unrealized gains or losses, included in accumulated other comprehensive income (loss), net of tax, a component of shareholders’ equity. The estimated fair value of our ARPSs at June 30, 2010 was $13.0 million compared with a par value of $15.9 million. The $2.9 million difference represents a fair value discount due to the current lack of liquidity which is considered temporary and has been recorded as an unrealized loss, net of tax, in accumulated other comprehensive income (loss). There was no portion of the fair value discount attributable to credit losses. We would recognize an impairment charge in our statement of operations if the fair value of our investments falls below the cost basis and is judged to be other-than-temporary. Our ARPSs are classified with other long-term assets on our condensed consolidated balance sheet as of June 30, 2010 because of our inability to determine the recovery period of our investments.

Foreign Currency Risk

While the U.S. dollar is the functional currency for reporting purposes for our Colombian operations, we enter into transactions denominated in Colombian pesos. Nonmonetary assets and liabilities are translated at historical rates and monetary assets and liabilities are translated at exchange rates in effect at the end of the period. Income statement accounts are translated at average rates for the period. As a result, Colombian Peso denominated transactions are affected by changes in exchange rates. We generally accept the exposure to exchange rate movements without using derivative financial instruments to manage this risk. Therefore, both positive and negative movements in the Colombian Peso currency exchange rate against the U.S. dollar has and will continue to affect the reported amount of revenues, expenses, profit, and assets and liabilities in our consolidated financial statements.

ITEM 4.

CONTROLS AND PROCEDURES

In accordance with Exchange Act Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of June 30, 2010 to ensure that information required to be disclosed in our reports filed or submitted under the Exchange Act is (1) recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms and (2) accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

There has been no change in our internal control over financial reporting that occurred during the three months ended June 30, 2010 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1.

Legal Proceedings

We are involved in litigation arising in the ordinary course of our business. Although the amount of any liability that could arise with respect to these actions cannot be accurately predicted, in management’s opinion, any such liability will not have a material adverse effect on our business, financial condition or operating results.

ITEM 1A.

Risk Factors

Not applicable.

ITEM 2.

Unregistered Sales of Equity Securities and Use of Proceeds

We did not make any unregistered sales of equity securities during the six months ended June 30, 2010, nor did we repurchase any shares of our common stock during the quarter ended June 30, 2010.

ITEM 3.

Defaults Upon Senior Securities

Not applicable.

ITEM 5.

Other Information

Not applicable.

ITEM 6.

EXHIBITS

The following exhibits are filed as part of this report or incorporated by reference herein:


Exhibit Number		Description

2.1*	-	Securities Purchase Agreement, dated January 31, 2008, by and among Pioneer Drilling Company, WEDGE Group Incorporated, WEDGE Energy Holdings, L.L.C., WEDGE Oil & Gas Services, L.L.C., Timothy Daley, John Patterson and Patrick Grissom (Form 8-K dated February 1, 2008 (File No. 1-8182, Exhibit 2.1)).

2.2*	-	Letter Agreement, dated February 29, 2008, amending the Securities Purchase Agreement, dated January 31, 2008, by and among Pioneer Drilling Company, WEDGE Group Incorporated, WEDGE Energy Holdings, L.L.C., WEDGE Oil & Gas Services, L.L.C., Timothy Daley, John Patterson and Patrick Grissom (Form 8-K dated March 3, 2008 (File No. 1-8182, Exhibit 2.1)).

3.1*	-	Restated Articles of Incorporation of Pioneer Drilling Company (Form 10-K for the year ended December 31, 2008 (File No. 1-8182, Exhibit 3.1)).

3.2*	-	Amended and Restated Bylaws of Pioneer Drilling Company (Form 8-K dated December 15, 2008 (File No. 1-8182, Exhibit 3.1)).

4.1*	-	Form of Certificate representing Common Stock of Pioneer Drilling Company (Form S-8 filed November 18, 2003 (Reg. No. 333-110569, Exhibit 4.3)).

4.2*	-	Indenture, dated March 11, 2010, by and among Pioneer Drilling Company, the subsidiary guarantors party thereto and Wells Fargo Bank, National Association, as trustee (Form 8-K dated March 12, 2010, (File No. 1-8182, Exhibit 4.1)).

4.3*	-	Registration Rights Agreement, dated March 11, 2010, by and among Pioneer Drilling Company, the subsidiary guarantors party thereto and the initial purchasers party thereto (Form 8-K dated March 12, 2010, (File No. 1-8182, Exhibit 4.2)).

10.1**	-	Pioneer Drilling Company 2007 Incentive Plan Form of Long-Term Incentive Cash Award Agreement

10.2**	-	Pioneer Drilling Company 2007 Incentive Plan Form of Long-Term Incentive Cash Award Agreement

10.3**	-	Pioneer Drilling Company 2007 Incentive Plan Form of Long-Term Incentive Restricted Stock Award Agreement

10.4**	-	Pioneer Drilling Company 2007 Incentive Plan Form of Restricted Stock Unit Agreement

31.1**	-	Certification by Wm. Stacy Locke, President and Chief Executive Officer, pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934.

31.2**	-	Certification by Lorne E. Phillips, Executive Vice President and Chief Financial Officer, pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934.

32.1#	-	Certification by Wm. Stacy Locke, President and Chief Executive Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code).

32.2#	-	Certification by Lorne E. Phillips, Executive Vice President and Chief Financial Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code).

*	Incorporated by reference to the filing indicated.

**	Filed herewith.

#	Furnished herewith.

+	Management contract or compensatory plan or arrangement.

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

PIONEER DRILLING COMPANY

/s/ Lorne E. Phillips

Lorne E. Phillips

Executive Vice President and Chief Financial Officer

(Principal Financial Officer and Duly Authorized Representative)

Dated: August 5, 2010

Index to Exhibits


Exhibit Number		Description

2.1*	-	Securities Purchase Agreement, dated January 31, 2008, by and among Pioneer Drilling Company, WEDGE Group Incorporated, WEDGE Energy Holdings, L.L.C., WEDGE Oil & Gas Services, L.L.C., Timothy Daley, John Patterson and Patrick Grissom (Form 8-K dated February 1, 2008 (File No. 1-8182, Exhibit 2.1)).

2.2*	-	Letter Agreement, dated February 29, 2008, amending the Securities Purchase Agreement, dated January 31, 2008, by and among Pioneer Drilling Company, WEDGE Group Incorporated, WEDGE Energy Holdings, L.L.C., WEDGE Oil & Gas Services, L.L.C., Timothy Daley, John Patterson and Patrick Grissom (Form 8-K dated March 3, 2008 (File No. 1-8182, Exhibit 2.1)).

3.1*	-	Restated Articles of Incorporation of Pioneer Drilling Company (Form 10-K for the year ended December 31, 2008 (File No. 1-8182, Exhibit 3.1)).

3.2*	-	Amended and Restated Bylaws of Pioneer Drilling Company (Form 8-K dated December 15, 2008 (File No. 1-8182, Exhibit 3.1)).

4.1*	-	Form of Certificate representing Common Stock of Pioneer Drilling Company (Form S-8 filed November 18, 2003 (Reg. No. 333-110569, Exhibit 4.3)).

4.2*	-	Indenture, dated March 11, 2010, by and among Pioneer Drilling Company, the subsidiary guarantors party thereto and Wells Fargo Bank, National Association, as trustee (Form 8-K dated March 12, 2010 (File No. 1-8182, Exhibit 4.1)).

4.3*	-	Registration Rights Agreement, dated March 11, 2010, by and among Pioneer Drilling Company, the subsidiary guarantors party thereto and the initial purchasers party thereto (Form 8-K dated March 12, 2010 (File No. 1-8182, Exhibit 4.2)).

10.1**	-	Pioneer Drilling Company 2007 Incentive Plan Form of Long-Term Incentive Cash Award Agreement

10.2**	-	Pioneer Drilling Company 2007 Incentive Plan Form of Long-Term Incentive Cash Award Agreement

10.3**	-	Pioneer Drilling Company 2007 Incentive Plan Form of Long-Term Incentive Restricted Stock Award Agreement

10.4**	-	Pioneer Drilling Company 2007 Incentive Plan Form of Restricted Stock Unit Agreement

31.1**	-	Certification by Wm. Stacy Locke, President and Chief Executive Officer, pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934.

31.2**	-	Certification by Lorne E. Phillips, Executive Vice President and Chief Financial Officer, pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934.

32.1#	-	Certification by Wm. Stacy Locke, President and Chief Executive Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code).

32.2#	-	Certification by Lorne E. Phillips, Executive Vice President and Chief Financial Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code).

*	Incorporated by reference to the filing indicated.

**	Filed herewith.

#	Furnished herewith.

+	Management contract or compensatory plan or arrangement.

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company