Parker Drilling (PKDC) 10-Q 2012 Q2 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)

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

For The Quarterly Period Ended June 30, 2012

OR

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

For the transition period from                      to                     

Commission File Number 1-7573

PARKER DRILLING COMPANY

(Exact name of registrant as specified in its charter)

Delaware	73-0618660
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
5 Greenway Plaza, Suite 100, Houston, Texas	77046
(Address of principal executive offices)	(Zip code)

(281) 406-2000

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files.    Yes  x    No  ¨

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

Large accelerated filer	¨	Accelerated filer	x
Non-accelerated filer	¨  (Do not check if a smaller reporting company)	Smaller reporting company	¨

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

As of August 1, 2012, there were 118,049,935 common shares outstanding.

TABLE OF CONTENTS

	Page
Part I. Financial Information		3
Item 1. Financial Statements		3
Consolidated Condensed Balance Sheets June 30, 2012 (Unaudited) and December 31, 2011		3
Consolidated Condensed Statements of Operations (Unaudited) Three and Six Months Ended June  30, 2012 and 2011		4
Consolidated Condensed Statements of Cash Flows (Unaudited) Six Months Ended June 30, 2012 and 2011		5
Notes to the Unaudited Consolidated Condensed Financial Statements		6
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		27
Item 3. Quantitative and Qualitative Disclosures about Market Risk		41
Item 4. Controls and Procedures		41
Part II. Other Information		43
Item 1. Legal Proceedings		43
Item 1A. Risk Factors		43
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		43
Item 6. Exhibits		44
Signatures		45
EX-10.1
EX-31.1
EX-31.2
EX-32.1
EX-32.2
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT

2

PART I.FINANCIAL INFORMATION

ITEM 1.FINANCIAL STATEMENTS

PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATED CONDENSED BALANCE SHEETS

(Dollars in Thousands)

	June 30, 2012			December 31, 2011
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	77,467		$	97,869
Accounts and notes receivable, net of allowance for bad debts of $2,561 and $1,544 at June 30, 2012 and December 31, 2011		176,190			183,923
Rig materials and supplies		24,246			29,947
Deferred costs		2,859			3,249
Deferred income taxes		6,380			6,650
Other tax assets		34,517			25,358
Assets held for sale		5,312			5,315
Other current assets		12,363			15,302
Total current assets		339,334			367,613
Property, plant and equipment less accumulated depreciation and amortization of $1,016,353 and $970,276 at June 30, 2012 and December 31, 2011		770,761			719,809
Deferred income taxes		99,622			108,311
Other noncurrent assets		27,649			20,513
Total assets	$	1,237,366		$	1,216,246
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current portion of long-term debt	$	51,136		$	145,723
Accounts payable and accrued liabilities		107,461			135,250
Accrued income taxes		5,271			4,837
Total current liabilities		163,868			285,810
Long-term debt		429,888			337,000
Other long-term liabilities		29,535			33,452
Long-term deferred tax liability		17,830			15,934
Contingencies (Note 11)		—			—
Stockholders’ equity:
Common stock		19,696			19,508
Capital in excess of par value		642,616			637,042
Accumulated deficit		(65,469	)		(111,944	)
Total controlling interest stockholders’ equity		596,843			544,606
Noncontrolling interest		(598	)		(556	)
Total equity		596,245			544,050
Total liabilities and stockholders’ equity	$	1,237,366		$	1,216,246

See accompanying notes to the unaudited consolidated condensed financial statements.

3

PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS

(Dollars in Thousands, Except Per Share and Weighted Average Shares Outstanding)

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
Revenues	$	178,925		$	172,812		$	355,494		$	328,991
Expenses:
Operating expenses		104,526			104,683			199,458			212,059
Depreciation and amortization		27,959			27,332			55,578			54,931
		132,485			132,015			255,036			266,990
Total operating gross margin		46,440			40,797			100,458			62,001
General and administration expense		(7,420	)		(7,948	)		(12,917	)		(14,752	)
Gain on disposition of assets, net		1,368			366			1,860			1,370
Total operating income		40,388			33,215			89,401			48,619
Other income and (expense):
Interest expense		(8,925	)		(5,755	)		(16,962	)		(11,616	)
Interest income		53			133			79			179
Loss on extinguishment of debt		(1,649	)		—			(1,649	)		—
Change in fair value of derivative positions		38			(137	)		(11	)		(137	)
Other		20			123			36			134
Total other expense		(10,463	)		(5,636	)		(18,507	)		(11,440	)
Income before income taxes		29,925			27,579			70,894			37,179
Income tax expense		9,817			13,464			24,460			18,303
Net income		20,108			14,115			46,434			18,876
Less: Net income (loss) attributable to noncontrolling interest		25			(58	)		(41	)		(125	)
Net income attributable to controlling interest	$	20,083		$	14,173		$	46,475		$	19,001
Basic earnings per share	$	0.17		$	0.12		$	0.40		$	0.16
Diluted earnings per share	$	0.17		$	0.12		$	0.39		$	0.16
Number of common shares used in computing earnings per share:
Basic		117,410,212			116,144,818			117,129,364			115,634,881
Diluted		118,526,879			117,253,588			118,623,037			116,750,717

See accompanying notes to the unaudited consolidated condensed financial statements.

4

PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)

(Unaudited)

	Six months ended June 30,
	2012			2011
Cash flows from operating activities:
Net income	$	46,434		$	18,876
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization		55,578			54,931
Loss on extinguishment of debt		1,649			—
Gain on disposition of assets		(1,860	)		(1,370	)
Deferred income tax expense		10,432			7,194
Expenses not requiring cash		11,789			8,355
Change in accounts receivable		9,161			(12,063	)
Change in other assets		(7,138	)		48,938
Change in accrued income taxes		923			—
Change in liabilities		(31,437	)		(28,962	)
Net cash provided by operating activities		95,531			95,899
Cash flows from investing activities:
Capital expenditures		(109,531	)		(99,377	)
Proceeds from the sale of assets		2,340			2,353
Proceeds from insurance settlements		—			250
Net cash used in investing activities		(107,191	)		(96,774	)
Cash flows from financing activities:
Proceeds from issuance of debt		130,000			50,000
Repayment of senior notes		(122,852	)		—
Repayments of term loan		(12,000	)		(9,000	)
Repayments of revolver		—			(25,000	)
Payments of debt issuance costs		(3,537	)		(504	)
Payments of debt extinguishment costs		(402	)		—
Proceeds from stock options exercised		—			183
Excess tax benefit from stock based compensation		49			1,260
Net cash provided by (used in) financing activities		(8,742	)		16,939
Net increase (decrease) in cash and cash equivalents		(20,402	)		16,064
Cash and cash equivalents, beginning of year		97,869			51,431
Cash and cash equivalents, end of period	$	77,467		$	67,495
Supplemental cash flow information:
Interest paid	$	16,989		$	16,328
Income taxes paid	$	28,307		$	4,926

See accompanying notes to the unaudited consolidated condensed financial statements.

5

PARKER DRILLING COMPANY AND SUBSIDIARIES

NOTES TO THE UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

1. General

In the opinion of the management of Parker Drilling Company (Parker Drilling), the accompanying unaudited consolidated condensed financial statements reflect all adjustments of a normally recurring nature which are necessary for a fair presentation of: (1) Parker Drilling’s financial position as of June 30, 2012 and December 31, 2011, (2) Parker Drilling’s results of operations for the three and six month periods ended June 30, 2012 and 2011, and (3) Parker Drilling’s cash flows for the six-month periods ended June 30, 2012 and 2011. Results for the six-month period ended June 30, 2012 are not necessarily indicative of the results that will be realized for the year ending December 31, 2012. The financial statements should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2011.

Nature of Operations — Parker Drilling, together with its subsidiaries (the Company), is a provider of contract drilling and drilling-related services. Our rental tools business specializes in providing equipment such as drill pipe, tubing, high-torque connections, blowout preventers (BOPs) and drill collars for use in drilling, work-over and production applications.

We have extensive experience and expertise in drilling geologically difficult wells and in managing the logistical and technological challenges of operating in remote, harsh and ecologically sensitive areas both internationally and within North America. Additionally, our international drilling business provides project management services, such as labor, maintenance, and logistics for operators who own their own drilling rigs, but choose Parker Drilling to operate the rigs for them. At June 30, 2012, our combined U.S. and international marketable rig fleet consisted of 15 barge drilling rigs and 25 land rigs located in the United States, Latin America, and certain Eastern Hemisphere regions. Our Technical Services business includes engineering and related project services during the concept development, pre-FEED (Front End Engineering and Design), and FEED phases of our customer-owned drilling facility projects. As these projects mature, we strive to continue providing the same services during the Engineering, Procurement, Construction and Installation (EPCI) phase.

Segment Reporting— As of December 31, 2011, we re-aligned our reporting segments to be consistent with recent changes to our organization. We have six distinct operating segments:

• Rental Tools

• U.S. Barge Drilling

• U.S. Drilling

• International Drilling

• Technical Services

• Construction Contract

As of December 31, 2011, we added the U.S. Drilling segment, represented primarily by our two Arctic Alaska Drilling Units (AADU) rigs in Alaska. Our U.S. Barge Drilling segment, previously referred to as the U.S. Drilling segment, represents our U.S. Gulf of Mexico barge business and remains unchanged. We aligned our international operations more closely with the management structure. Our previous three international geographic regions (Americas, CIS/AME, and Asia Pacific) are now two – Latin America and Eastern Hemisphere. Each region includes all drilling-related operations, whether conducted using a Parker-owned rig or a customer-owned rig pursuant to an Operations and Maintenance (O&M) contract. Our technical services activities, which primarily include our engagement in engineering support initiatives,

6

pre-FEED, FEED and EPCI projects that have the potential to evolve into future O&M opportunities, are now reported as an individual segment. Our Rental Tools and Construction Contract segments remain unchanged. Certain amounts presented in this Form 10-Q for the three and six-month periods ended June 30, 2011 have been revised to conform to the current period presentation.

Consolidation — The consolidated condensed financial statements include the accounts of Parker Drilling and subsidiaries over which we exercise control or in which have a controlling financial interest, including entities, if any, in which the Company is allocated a majority of the entity’s losses or returns, regardless of ownership percentage. If a subsidiary of Parker Drilling has a 50 percent interest in an entity but Parker Drilling’s interest in the subsidiary or the entity does not meet the consolidation criteria described above, then that interest is accounted for under the equity method.

Reclassifications — Certain reclassifications have been made to prior period amounts to conform with the current period presentation. These reclassifications did not have a material effect on our consolidated condensed statements of operations, consolidated condensed balance sheets or consolidated condensed statements of cash flows.

Use of Estimates — The preparation of financial statements in accordance with accounting policies generally accepted in the United States (U.S. GAAP) requires us to make estimates and assumptions that affect our reported amounts of assets and liabilities, our disclosure of contingent assets and liabilities at the date of the financial statements, and our revenue and expenses during the periods reported. Estimates are typically used when accounting for certain significant items, such as allowance for doubtful accounts, legal or contractual liability accruals, mobilization and deferred mobilization, revenue and cost accounting for projects that follow the percentage of completion method, self-insured medical/dental plans, income taxes and valuation allowance, and other items requiring the use of estimates. Estimates are based on a number of variables which may include third party valuations, historical experience and assumptions that we believe are reasonable under the circumstances. Due to the inherent uncertainty involved with estimates, actual results may differ from management estimates.

Revenue Recognition — We recognize revenues and expenses on dayrate contracts as drilling progresses. Revenues from rental activities are recognized ratably over the rental term. Mobilization fees received and related mobilization costs incurred are deferred and amortized over the term of the contract period. Construction contract revenues and costs are recognized on a percentage of completion basis utilizing the cost-to-cost method.

Reimbursable Costs — We recognize reimbursements received for out-of-pocket expenses as revenues and account for out-of-pocket expenses as direct operating costs. Such amounts totaled $10.1 million, and $20.8 million during the second quarters of 2012 and 2011, respectively, and $17.7 million and $35.0 million for the six months ended June 30, 2012 and 2011, respectively.

Concentrations of Credit Risk — Financial instruments, which potentially subject us to concentrations of credit risk, consist primarily of trade receivables. We generally do not require collateral on our trade receivables.

At June 30, 2012 and December 31, 2011, we had deposits in domestic banks in excess of federally insured limits of approximately $15.3 million and $10.2 million, respectively. In addition, as of June 30, 2012 and December 31, 2011, we had deposits in foreign banks which were not insured of $38.6 million and $38.4 million, respectively.

Our customer base consists primarily of major, independent, national and international oil and gas companies and integrated service providers. We depend on a limited number of customers. Our two largest customers constituted 9.9 percent and 9.5 percent, respectively, of our total year-to-date revenues as of

7

June 30, 2012. Each of our segments depends on a limited number of key customers and the loss of any one or more key customers could have a material adverse effect on a segment.

Construction Contract — For the periods reported, our construction contract business included only the Liberty drilling rig construction project for BP. In November 2010, BP, informed us that it was suspending construction on the project to review the rig’s engineering and design, including its safety systems. The Liberty rig construction contract was a fixed fee and reimbursable contract accounted for on a percentage of completion basis. As of December 31, 2011, we had recognized $335.5 million in revenues and $11.7 million of margin on the contract.

The Liberty rig construction contract expired on February 8, 2011 prior to completion of the rig. Before expiration of the construction contract, BP identified several areas of concern relating to design, construction and invoicing for which it asked us to provide explanations and documentation, and we did so. Although we provided BP with the requested information, we do not know when or how these issues will be resolved with our client.

After expiration of the construction contract, the Company and BP continued activities to preserve and maintain the rig under the “pre-operations” phase of our operations contract, which was entered into in August 2009 and expired on July 1, 2011. A new consulting services agreement was reached between us and BP effective July 1, 2011. Under the consulting services agreement, we assisted BP with technical support in a review of the rig’s design, the creation of a new statement of requirements for the rig, and the transition of documentation and materials to BP. All work under the consulting agreement has been completed and we are engaged with BP on construction contract close-out resolution. In June 2012, BP publicly announced that it had made the decision to suspend the Liberty project indefinitely. We do not know whether or how that decision may impact our discussions with BP related to contract close-out.

Capitalized Interest — Interest from external borrowings is capitalized on major projects until the assets are ready for their intended use. Capitalized interest is added to the cost of the underlying assets and is amortized over the useful lives of the assets in the same manner as the underlying assets. Capitalized interest reduces net interest expense in the consolidated condensed statements of operations. We capitalized interest costs primarily related to the construction of the two new AADU rigs of $3.0 million and $4.7 million during the second quarters of 2012 and 2011, respectively, and $5.4 million and $9.2 million for the six months ended June 30, 2012 and 2011, respectively.

2. Asset Impairment

During the fourth quarter of 2011, we evaluated the present value of the future cash flows related to our AADU rigs in accordance with the impairment or disposal of long-lived assets subsections of ASC 360-10, Property, Plant and Equipment. As a result, we recorded a non-cash pre-tax impairment charge of $170.0 million ($109.1 million after tax) due to the extended construction and commissioning schedule and related costs. The AADU rigs are reported as part of the U.S. Drilling segment.

8

3. Earnings per share (EPS)

	Three Months Ended June 30, 2012
	Income (Numerator)		Shares (Denominator)		Per-Share Amount
Basic EPS	$	20,083,000		117,410,212	$	0.17
Effect of dilutive securities:
Stock options and restricted stock				1,116,667	$	—
Diluted EPS	$	20,083,000		118,526,879	$	0.17
	Six Months Ended June 30, 2012
	Income (Numerator)		Shares (Denominator)		Per-Share Amount
Basic EPS	$	46,475,000		117,129,364	$	0.40
Effect of dilutive securities:
Stock options and restricted stock				1,493,673	$	(0.01	)
Diluted EPS	$	46,475,000		118,623,037	$	0.39
	Three Months Ended June 30, 2011
	Income (Numerator)		Shares (Denominator)		Per-Share Amount
Basic EPS	$	14,173,000		116,144,818	$	0.12
Effect of dilutive securities:
Stock options and restricted stock				1,108,770	$	—
Diluted EPS	$	14,173,000		117,253,588	$	0.12
	Six Months Ended June 30, 2011
	Income (Numerator)		Shares (Denominator)		Per-Share Amount
Basic EPS	$	19,001,000		115,634,881	$	0.16
Effect of dilutive securities:
Stock options and restricted stock				1,115,836	$	—
Diluted EPS	$	19,001,000		116,750,717	$	0.16

There were no options outstanding during the three and six month periods ended June 30, 2012. All options outstanding during the three months ended June 30, 2011 were included in the computation of diluted EPS as the options’ exercise prices were less than the average market price of the common shares. For the six months ended June 30, 2011, options to purchase 15,000 shares at an exercise price of $5.91 were excluded from the calculation of diluted EPS because the options’ exercise prices were greater than the average market price of the common shares for the six month period and therefore would have been anti-dilutive.

9

4. Reportable Segments

We report our business activities in six business segments: (1) Rental Tools, (2) U.S. Barge Drilling, (3) U.S. Drilling, (4) International Drilling, (5) Technical Services, and (6) Construction Contract. We eliminate inter-segment revenues and expenses. The following table represents the results of operations by reportable segment:

	Three Months Ended June 30,						Six Months Ended June 30,
Operations by Reportable Industry Segment	2012			2011			2012			2011
	(Dollars in Thousands)						(Dollars in Thousands)
Revenues:
Rental Tools	$	65,002		$	58,490		$	131,286		$	110,809
U.S. Barge Drilling		33,292			26,060			61,127			41,980
U.S. Drilling(2)		—			—			—			—
International Drilling		76,923			79,725			155,673			149,661
Technical Services		3,708			8,537			7,408			16,903
Construction Contract		—			—			—			9,638
Total revenues		178,925			172,812			355,494			328,991
Operating gross margin:
Rental Tools(1)		31,251			30,566			64,853			54,664
U.S. Barge Drilling(1)		11,014			4,451			18,171			1,769
U.S. Drilling(1)		(1,623	)		(340	)		(3,170	)		(681	)
International Drilling(1)		6,056			2,816			20,615			2,123
Technical Services(1)		(258	)		1,789			(11	)		3,355
Construction Contract(1)		—			1,515			—			771
Total operating gross margin		46,440			40,797			100,458			62,001
General and administrative expense		(7,420	)		(7,948	)		(12,917	)		(14,752	)
Gain on disposition of assets, net		1,368			366			1,860			1,370
Total operating income		40,388			33,215			89,401			48,619
Interest expense		(8,925	)		(5,755	)		(16,962	)		(11,616	)
Interest income		53			133			79			179
Loss on extinguishment of debt		(1,649	)		—			(1,649	)		—
Changes in fair value of derivative positions		38			(137	)		(11	)		(137	)
Other		20			123			36			134
Income before income taxes	$	29,925		$	27,579		$	70,894		$	37,179

(1) Operating gross margin is calculated as revenues less direct operating expenses, including depreciation and amortization expense.

(2) As of June 30, 2012, this segment had not begun generating revenue.

5. Assets Held for Sale

Assets held for sale of $5.3 million as of June 30, 2012 was comprised of the net book value of three land rigs and related inventory. We have received a down payment on these assets and associated inventories and consummation of the sales is targeted for 2012. The three rigs are part of our Eastern Hemisphere fleet, and prior to being classified as assets held for sale, were included in the international drilling segment. We expect the carrying amount of the assets, less costs to sell, will be fully recoverable through sale of the assets.

6. Accounting for Uncertainty in Income Taxes

We apply the accounting guidance related to accounting for uncertainty in income taxes. This guidance prescribes a recognition threshold and a measurement attribute for the financial statement recognition and

10

measurement of tax positions taken or expected to be taken in a tax return. For those benefits to be recognized, a tax position must be more likely than not to be sustained upon examination by taxing authorities. At June 30, 2012, we had a liability for unrecognized tax benefits of $14.8 million (which includes $6.9 million of benefits which would favorably impact our effective tax rate upon recognition). As of June 30, 2011, we had a liability for unrecognized tax benefits of $16.2 million ($5.8 million of which, if recognized, would favorably impact our effective tax rate) primarily related to foreign operations. In addition, we recognize interest and penalties that could be applied to uncertain tax positions in periodic income tax expense. As of June 30, 2012 and December 31, 2011, we had approximately $8.1 million and $8.4 million, respectively, of accrued interest and penalties related to uncertain tax positions.

7. Income Tax Benefit/Expense

Income tax expense was $9.8 million for the second quarter of 2012, as compared to $13.5 million for the second quarter of 2011. The decrease was driven primarily by utilization of net operating losses during the second quarter of 2012 that were not present during 2011 and release of reserves due to expiration of the statute of limitations associated with uncertain tax positions taken on returns in Latin America.

8. Long-Term Debt

The following table illustrates the Company’s debt portfolio as of June 30, 2012 and December 31, 2011:

	June 30, 2012		December 31, 2011
	(Dollars in Thousands)
9.125% Senior Notes, due April 2018 (Issued March 22, 2010)	$	300,000	$	300,000
9.125% Senior Notes, due April 2018 (Issued April 25, 2012)		129,888		—
2.125% Convertible Senior Notes, due July 2012		2,136		121,723
Term Note		49,000		61,000
Total debt		481,024		482,723
Less current portion		51,136		145,723
Total long-term debt	$	429,888	$	337,000

9.125% Senior Notes, due April 2018

On March 22, 2010, we issued $300.0 million aggregate principal amount of 9.125% Senior Notes (9.125% Notes) pursuant to an Indenture between the Company and The Bank of New York Mellon Trust Company, N.A., as trustee. Net proceeds from the 9.125% Notes offering were primarily used to redeem the $225.0 million aggregate principal amount of our 9.625% Senior Notes due 2013 and to repay $42.0 million of borrowings under our senior secured revolving credit facility (Revolver).

On April 25, 2012, we issued an additional $125.0 million aggregate principal amount of 9.125% Notes at a price of 104.0% of par, resulting in gross proceeds of $130.0 million. Substantially all of the net proceeds from the offering were utilized to repurchase $122.9 million aggregate principal amount of the 2.125% Convertible Senior Notes due July 2012 (2.125% Notes) tendered pursuant to a tender offer on May 9, 2012.

The 9.125% Notes are general unsecured obligations of the Company and rank equal in right of payment with all of our existing and future senior unsecured indebtedness. The 9.125% Notes are jointly and severally guaranteed by substantially all of our direct and indirect domestic subsidiaries other than immaterial subsidiaries and subsidiaries generating revenue primarily outside the United States. Interest on the 9.125% Notes is payable on April 1 and October 1 of each year.

11

At any time prior to April 1, 2013, we may redeem up to 35 percent of the aggregate principal amount of the 9.125% Notes at a redemption price of 109.125 percent of the principal amount, plus accrued and unpaid interest to the redemption date, with the net cash proceeds of certain equity offerings by us. On and after April 1, 2014, we may redeem all or a part of the 9.125% Notes upon appropriate notice, at a redemption price of 104.563 percent of the principal amount, and at redemption prices decreasing each year thereafter to par beginning April 1, 2016. If we experience certain changes in control, we must offer to repurchase the 9.125% Notes at 101.0 percent of the aggregate principal amount, plus accrued and unpaid interest and additional interest, if any, to the date of repurchase.

The Indenture restricts our ability and the ability of certain subsidiaries to: (i) sell assets, (ii) pay dividends or make other distributions on capital stock or redeem or repurchase capital stock or subordinated indebtedness, (iii) make investments, (iv) incur or guarantee additional indebtedness; (v) create or incur liens; (vi) enter into sale and leaseback transactions; (vii) incur dividend or other payment restrictions affecting subsidiaries, (viii) merge or consolidate with other entities, (ix) enter into transactions with affiliates, and (x) engage in certain business activities. Additionally, the Indenture contains certain restrictive covenants designating certain events as Events of Default. These covenants are subject to a number of important exceptions and qualifications.

2.125% Convertible Senior Notes, due July 2012

On July 5, 2007, we issued $125.0 million aggregate principal amount of 2.125% Notes. As noted above, May 9, 2012, we repurchased $122.9 million aggregate principal amount of the 2.125% Notes pursuant to a tender offer. The tender offer price was $1,003.27 for each $1,000 principal amount of 2.125% Notes, plus accrued and unpaid interest. This repurchase resulted in the recording of debt extinguishment costs of $1.6 million related to the write-down of previously recorded debt costs and debt discount associated with the 2.125% Notes. The $2.1 million aggregate principal amount of non-tendered 2.125% Notes was subsequently paid off at their stated maturity on July 15, 2012.

Concurrently with the issuance of the 2.125% Notes, we purchased a convertible note hedge (note hedge) and sold warrants in private transactions with counterparties that were different than the ultimate holders of the 2.125% Notes. The note hedge allowed us to receive shares of our common stock from the counterparties to the transaction equal to the amount of common stock related to the excess conversion value that we would issue and/or pay to the holders of the 2.125% Notes upon conversion. The warrants allow us to sell 9,027,713 common shares at a strike price of $18.29 per share. The note hedge expired on July 15, 2012, the maturity date of the 2.125% Notes. The warrants begin expiring on October 15, 2012 by expiring ratably over the following 90 business days, until the final warrants expire on February 22, 2013.

The aggregate principal amount of remaining non-tendered 2.125% Notes at June 30, 2012 were classified as current debt in our consolidated condensed balance sheets. Because we had the choice of settling the call options and the warrants in cash or shares of our common stock and these contracts met all of the applicable criteria for equity classification, the cost of the call options and proceeds from the sale of the warrants were classified in stockholders’ equity in the consolidated condensed balance sheets. In addition, because both of these contracts are classified in stockholders’ equity and are indexed solely to our common stock, they are not accounted for as derivatives.

Debt issuance costs related to the 2.125% Notes of approximately $3.6 million were amortized over the five year term of the 2.125% Notes using the effective interest method. As of June 30, 2012, the unamortized debt issuance costs were nominal.

Credit Agreement:

On May 15, 2008, we entered into a credit agreement (Credit Agreement) consisting of the Revolver of $80.0 million and senior secured term loan facility (Term Loan) of up to $50.0 million. The Credit Agreement provides that, subject to certain conditions, including the approval of the Administrative Agent

12

and the lenders’ acceptance (or additional lenders being joined as new lenders), the amount of the Term Loan or Revolver could be increased by an additional $50.0 million, so long as after giving effect to such increase, the Aggregate Commitments shall not be in excess of $180.0 million. On April 1, 2011, the Company exercised the additional $50.0 million accordion feature and entered into an amendment to the Credit Agreement that increased the Aggregate Commitments under the Credit Agreement to $159.0 million, and borrowed an additional $50.0 million in a Term Loan. When the facility was increased, all other terms of the Credit Agreement remained the same, including covenants and Applicable Rates (as defined in the Credit Agreement).

Our obligations under the Credit Agreement are guaranteed by substantially all of our domestic subsidiaries, except for domestic subsidiaries owned by foreign subsidiaries and certain immaterial subsidiaries, each of which has executed guaranty agreements. The Credit Agreement contains customary affirmative and negative covenants with which we were in compliance as of June 30, 2012 and December 31, 2011. The Credit Agreement terminates and must be repaid on May 14, 2013. All associated obligations related to the Credit Agreement have been recorded as current liabilities in our financial statements as of June 30, 2012. Based on the current amortization schedule, the balance of the Term Loan to be repaid at maturity would be $31.0 million. Although, we believe we could repay the Term Loan at the time of maturity utilizing existing cash and cash generated from operations, it is our intention to enter into a new Credit Facility prior to maturity.

Revolver:

Our Revolver is available for general corporate purposes and to support letters of credit. Interest on Revolver loans accrues at a Base Rate (as defined in the Credit Agreement) plus an Applicable Rate or LIBOR plus an Applicable Rate. The Applicable Rate varies from a rate per annum ranging from 2.75 percent to 3.25 percent for LIBOR rate loans and 1.75 percent to 2.25 percent for base rate loans, determined by reference to the consolidated leverage ratio (as defined in the Credit Agreement). Revolving loans are available subject to a borrowing base calculation based on a percentage of eligible accounts receivable, certain specified barge drilling rigs and rental equipment of the Company and its subsidiary guarantors. There were no revolving loans outstanding at June 30, 2012 or December 31, 2011. Letters of credit outstanding totaled $2.6 million and $2.7 million as of June 30, 2012 and December 31, 2011, respectively.

Term Loan:

The Term Loan originated at $50.0 million. Interest on the Term Loan accrues at either a Base Rate plus 2.25 percent or LIBOR plus 3.25 percent. On April 1, 2011, the company expanded its Term Loan by $50.0 million. Funding was provided by certain current lenders and Barclays Bank PLC, which joined as a lender under the Credit Agreement. We used the proceeds from the additional Term Loan to repay the $25.0 million outstanding on the Revolver, purchase additional rental tool inventory, and for general corporate purposes. The Term Loan requires quarterly principal payments of $6.0 million per quarter with the remaining loan balance payable upon maturity. The outstanding balance on the Term Loan at June 30, 2012 and December 31, 2011 was $49.0 million and $61.0 million, respectively.

9. Derivative Financial Instruments

We entered into two variable-to-fixed interest rate swap agreements as a strategy to manage the floating rate risk on the Term Loan borrowings under the Credit Agreement. The two agreements fix the interest rate on a notional amount of $73.0 million of borrowings at 3.878% for the period beginning June 27, 2011 and terminating May 14, 2013. The notional amount of the swap agreements will decrease correspondingly with amortization of the Term Loan. We do not apply hedge accounting to the agreements and, accordingly, we report the mark-to-market change in the fair value of the interest rate swaps in

13

earnings. For the three months ended June 30, 2012, we recognized in earnings a nominal gain relating to these agreements compared to a $0.1 million loss for the quarter ended June 30, 2011. For the six months ended June 30, 2012 and 2011, we recognized in earnings a nominal loss relating to these agreements.

10. Fair Value of Financial Instruments

Certain of our assets and liabilities are required to be measured at fair value on a recurring basis. For purposes of recording fair value adjustments for certain financial and non-financial assets and liabilities, and determining fair value disclosures, we estimate fair value at a price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants in the principal market for the asset or liability.

The fair value measurement and disclosure requirements of FASB Accounting Standards Codification Topic No. 820,Fair Value Measurement and Disclosures (ASC 820) requires inputs that we categorize using a three-level hierarchy, from highest to lowest level of observable inputs, as follows:

• Level 1 — Unadjusted quoted prices for identical assets or liabilities in active markets;

• Level 2 — Direct or indirect observable inputs, including quoted prices or other market data, for similar assets or liabilities in active markets or identical assets or liabilities in less active markets;

• Level 3 — Unobservable inputs that require significant judgment for which there is little or no market data.

When multiple input levels are required for a valuation, we categorize the entire fair value measurement according to the lowest level of input that is significant to the measurement even though we may have also utilized significant inputs that are more readily observable.

The amounts reported in our consolidated condensed balance sheets for cash and cash equivalents, accounts receivable, and accounts payable approximate fair value. Fair values and related carrying values of our debt instruments are as follows:

	June 30, 2012				December 31, 2011
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(in thousands)
Long-term Debt
9.125% Notes	$	300,000	$	317,250	$	300,000	$	315,000
9.125% Notes		125,000	$	132,188		—		—
2.125% Notes		2,148		2,136		125,000		123,204
Total	$	427,148	$	451,573	$	425,000	$	438,204

The carrying amount of our interest rate swap agreements represents the estimated fair value, measured using Level 2 inputs. The carrying amount of our interest rate swap agreements was $0.1 million as of both June 30, 2012 and December 31, 2011. As of June 30, 2012 the carrying amount of the agreements is classified as current and is recorded in accounts payable and accrued liabilities. As of December 31, 2011 the agreements were classified as long-term and recorded in other long-term liabilities on our consolidated condensed balance sheets.

As discussed in Note 2, in accordance with the impairment or disposal of long-lived assets subsections of ASC 360-10, Property, Plant and Equipment, during the fourth quarter of 2011, we recorded a non-cash pre-tax impairment charge of $170.0 million ($109.1 million, after tax) related to the AADU rigs in order to record them at their fair value of $169.5 million. The fair value of the AADU rigs was based on expected future cash flows using Level 3 inputs discounted at a 10 percent rate of interest.

14

Market conditions could cause an instrument to be reclassified from Level 1 to Level 2, or Level 2 to Level 3. There were no transfers between levels of the fair value hierarchy or any changes in the valuation techniques used during the three months ended June 30, 2012.

11. Contingencies

Asbestos-Related Claims

We are from time to time a party to various lawsuits in the ordinary course that are incidental to our operations in which the claimants seek an unspecified amount of monetary damages for personal injury, including injuries purportedly resulting from exposure to asbestos on drilling rigs and associated facilities. At June 30, 2012, there were approximately 15 of these lawsuits in which we are one of many defendants. These lawsuits have been filed in the United States in the State of Mississippi.

The subsidiaries named in these asbestos-related lawsuits intend to defend themselves vigorously and, based on the information available to us at this time, we do not expect the outcome to have a material adverse effect on our financial condition, results of operations or cash flows. However, we are unable to predict the ultimate outcome of these lawsuits. No amounts were accrued at June 30, 2012.

Gulfco Site

In 2003, we received an information request under the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) designating Parker Drilling Offshore Corporation, a subsidiary of Parker Drilling, as a potentially responsible party with respect to the Gulfco Marine Maintenance, Inc. Superfund Site in Freeport, Texas (EPA No. TX 055144539). We responded to this request and in January 2008 received an administrative order to participate in an investigation of the site and a study of the remediation needs and alternatives. The EPA alleges that our subsidiary is a successor to a party who owned the Gulfco site during the time when chemical releases took place there. In December 2010, we entered into an agreement with two other potentially responsible parties, pursuant to which we agreed to pay 20 percent of past and future costs to study and remediate the site. To date, we believe that all required activity for removal and remediation has been completed, except for ongoing monitoring costs, and we are awaiting a Notice of Completion from the EPA. The EPA has issued notice letters to several other parties who may also participate in funding the site remediation costs. As of June 30, 2012, the Company had made certain participating payments and had accrued $0.6 million for our portion of certain unreimbursed past costs and the estimated future cost of remediation.

Customs Agent and Foreign Corrupt Practices Act (FCPA) Investigation

As previously disclosed, we received requests from the United States Department of Justice (DOJ) in July 2007 and the United States Securities and Exchange Commission (SEC) in January 2008 relating to our utilization of the services of a customs agent. The DOJ and the SEC are conducting parallel investigations into possible violations of U.S. law, including the FCPA, by us. In particular, the DOJ and the SEC are investigating certain of our operations relating to countries in which we currently operate or formerly operated, including Kazakhstan and Nigeria. We are fully cooperating with the DOJ and SEC investigations and conducted an internal investigation into potential customs and other issues in Kazakhstan and Nigeria. The internal investigation has identified issues relating to potential non-compliance with applicable laws and regulations, including the FCPA, with respect to operations in Kazakhstan and Nigeria. At this point, we are unable to predict the duration, scope or result of the DOJ or the SEC investigation or whether either agency will commence any legal action. We are currently in continuing discussions with the DOJ and SEC regarding a potential settlement of this matter, but no agreement has been reached with either agency. We cannot predict or estimate whether or when a resolution with each will occur, or the terms, conditions, or other parameters of any such resolution (including the size of any monetary penalties or disgorgement).

15

Therefore, we have not made any accrual in our consolidated financial statements as of June 30, 2012, with respect to the investigations.

The DOJ and the SEC have a broad range of civil and criminal sanctions under the FCPA and other laws and regulations, which they may seek to impose against corporations and individuals in appropriate circumstances including, but not limited to, injunctive relief, disgorgement, fines, penalties and modifications to business practices and compliance programs. These authorities have entered into agreements with, and obtained a range of sanctions against, several public corporations and individuals arising from allegations of improper payments and deficiencies in books and records and internal controls, whereby civil and criminal penalties were imposed. Recent civil and criminal settlements have included multi-million dollar fines, deferred prosecution agreements, guilty pleas, and other sanctions, including the requirement that the relevant corporation retain a monitor to oversee its compliance with the FCPA. In addition, corporations may have to end or modify existing business relationships. Any of these remedial measures, if applicable to us, could have a material adverse impact on our business, results of operations, financial condition and liquidity.

We have taken certain steps to enhance our anti-bribery compliance efforts, including retaining a full-time Chief Compliance Officer who reports to the Chief Executive Officer and Audit Committee; adopting revised FCPA policies, procedures, and controls; increasing training and testing requirements; strengthening contractual provisions for our service providers that interface with foreign government officials; improving due diligence and continuing oversight procedures for the review and selection of such service providers; and implementing a compliance awareness improvement initiative that includes issuance of periodic anti-bribery compliance alerts.

Demand Letter and Derivative Litigation

In April 2010, we received a demand letter from a law firm representing Ernest Maresca. The letter states that Mr. Maresca is one of our stockholders and that he believes that certain of our current and former officers and directors violated their fiduciary duties related to the issues described above under “Customs Agent and Foreign Corrupt Practices Act (FCPA) Investigation.” The letter requests that our Board of Directors take action against the individuals in question. In response to this letter, the Board formed a special committee to evaluate the issues raised by the letter and determine a course of action for the Company. On August 25, 2010, Mr. Maresca filed a derivative action in the United States District Court for the Southern District of Texas against our current directors, select officers, and the Company as a nominal defendant. The lawsuit, like the demand letter, alleged that the individual defendants breached their fiduciary duties to the Company related to the issues described above under “Customs Agent and Foreign Corrupt Practices Act (FCPA) Investigation.” The lawsuit sought damages in an unspecified amount, along with various other forms of relief and an award of attorney fees, other costs, and expenses to the plaintiff. The lawsuit was voluntarily dismissed by the plaintiff in December 2010.

On June 3, 2010, Mohamed Kassamali, a purported stockholder of the Company, filed a derivative action in the state court of Harris County, Texas against our current directors and the Company as a nominal defendant. The lawsuit alleges that the individual defendants breached their fiduciary duties to the Company related to the issues described above under “Customs Agent and Foreign Corrupt Practices Act (FCPA) Investigation.” On June 22, 2010, the Fuchs Family Trust, a purported stockholder of the Company, filed a substantially similar lawsuit in the state court of Harris County, Texas. On June 23, 2010, Kenneth Flacks, a purported stockholder of the Company, also filed a substantially similar lawsuit in the state court of Harris County, Texas. The lawsuits seek damages related to the alleged breaches of duty, unjust enrichment, abuse of control, gross mismanagement and waste of corporate assets. The damages sought include both compensatory and exemplary damages in an unspecified amount, along with various other forms of relief and an award of attorney fees, other costs, and expenses to the plaintiffs. All defendants have retained counsel, and on October 15, 2010, the three cases pending in the state court of Harris County, Texas were

16

consolidated under the Kassamali case number and restyled as In re Parker Drilling Derivative Litigation. Plaintiffs filed a consolidated amended petition on April 7, 2011. On May 23, 2011, the Company, joined by the other defendants filed special exceptions to that petition, which were fully briefed as of August 8, 2011. On May 4, 2012, following an oral hearing on the Company’s special exceptions, the Court ordered the plaintiffs to replead the lawsuit. The plaintiffs filed an amended petition on June 13, 2012. On June 27, 2012, the Company (again joined by the other defendants) filed a motion to dismiss the amended petition, which was fully briefed as of July 11, 2012. A hearing on the motion to dismiss occurred on July 13, 2012, and the Court dismissed the matter without prejudice on July 23, 2012.

On August 31, 2010, Douglas Freuler, a purported stockholder of the Company, filed a derivative action in the United States District Court for the Southern District of Texas against our current directors, select officers, and the Company as a nominal defendant. The lawsuit was substantially similar to those filed in the state court of Harris County, Texas, and alleges breach of fiduciary duties to the Company related to the issues described above under “Customs Agent and Foreign Corrupt Practices Act (FCPA) Investigation,” as well as abuse of control, gross mismanagement, waste of corporate assets, and unjust enrichment. The damages sought included both compensatory and exemplary damages in an unspecified amount, along with various other forms of relief and an award of attorney fees, other costs, and expenses to the plaintiffs. Defendants’ motions to dismiss the amended complaint were granted on June 30, 2011, and plaintiff was given thirty days to replead. Mr. Freuler filed his second amended complaint on July 20, 2011. Defendants’ motions to dismiss the second amended complaint were granted on March 14, 2012. On April 12, 2012, Mr. Freuler filed a notice of appeal to the U.S. Court of Appeals for the Fifth Circuit.

Economic Sanctions Compliance

We are subject to laws and regulations restricting our international operations, including activities involving restricted countries, organizations, entities and persons that have been identified as unlawful actors or that are subject to U.S. economic sanctions. As previously reported, we conducted an internal review and identified certain shipments of equipment and supplies between 2003 and 2009 that were routed through Iran as well as other activities, including drilling activities, which may have violated applicable U.S. laws and regulations. Also as previously reported, we voluntarily disclosed the results of our review to the U.S. government. The U.S. Treasury Department’s Office of Foreign Assets Control has since provided a final response to our disclosure through the issuance of a cautionary letter, which stated that these shipments appear to have violated the regulations that it administers. No civil or criminal penalties were assessed in connection with this matter.

12. Recent Accounting Pronouncements

Comprehensive Income — FASB ASU No. 2011-05, Presentation of Comprehensive Income, as amended by FASB ASU No. 2011-12, Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05, revises FASB ASC Topic 220, Comprehensive Income, to require that a registrant report comprehensive income in a single continuous financial statement or in two separate but consecutive financial statements. The ASUs eliminate the option to present the components of other comprehensive income (OCI) as part of the statement of changes in stockholders’ equity. Public entities are required to comply with the new reporting requirements for fiscal years beginning after December 15, 2011 and interim periods within those years. Calendar year-end companies must adopt the requirements for the quarter ended March 31, 2012. The adoption of this update did not have a material impact on our financial position, results of operations, cash flows, or disclosures.

Fair value measurements — Effective January 1, 2012, we adopted the accounting standards update that changes the wording used to describe many of the requirements in U.S. GAAP for measuring fair value and for disclosing information about fair value measurements. Some of the amendments included in this

17

update are intended to clarify the applications of existing fair value measurement requirements. The update is effective for annual periods beginning after December 15, 2011. Our adoption did not have a material effect on the disclosures contained in our notes to the consolidated financial statements.

13. Parent, Guarantor, Non-Guarantor Unaudited Consolidating Condensed Financial Statements

Set forth on the following pages are the consolidating condensed financial statements of Parker Drilling. Our 9.125% Notes are guaranteed by substantially all of its direct and indirect domestic subsidiaries other than immaterial subsidiaries generating revenue primarily outside the United States. There are currently no restrictions on the ability of the guarantor subsidiaries to transfer funds to Parker Drilling in the form of cash dividends, loans or advances. Parker Drilling is a holding company with no operations, other than through its subsidiaries. Separate financial statements for each guarantor company are not provided as we comply with the exception to Rule 3-10(a)(1) of Regulation S-X, set forth in sub-paragraph (f) of such rule. All guarantor subsidiaries are owned 100 percent by Parker Drilling, all guarantees are full and unconditional and all guarantees are joint and several.

We are providing consolidating condensed financial information of the parent, Parker Drilling, the guarantor subsidiaries, and the non-guarantor subsidiaries as of June 30, 2012 and December 31, 2011 and for the three and six months ended June 30, 2012 and 2011. The consolidating condensed financial statements present investments in both consolidated and unconsolidated subsidiaries using the equity method of accounting.

18

PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATING CONDENSED BALANCE SHEET

(Dollars in Thousands)

(Unaudited)

	June 30, 2012
	Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	28,231		$	10,266		$	38,970		$	—		$	77,467
Accounts and notes receivable, net		289,720			107,730			282,476			(503,736	)		176,190
Rig materials and supplies		—			(1,044	)		25,290			—			24,246
Deferred costs		—			—			2,859			—			2,859
Deferred income taxes		—			4,940			1,440			—			6,380
Other tax assets		77,635			(47,411	)		4,293			—			34,517
Assets held for sale		—			—			5,312			—			5,312
Other current assets		722			5,144			6,497			—			12,363
Total current assets		396,308			79,625			367,137			(503,736	)		339,334
Property, plant and equipment, net		60			544,681			226,020			(0	)		770,761
Investment in subsidiaries and intercompany advances		776,638			(257,178	)		1,384,083			(1,903,543	)		—
Other noncurrent assets		40,616			68,171			18,484			—			127,271
Total assets	$	1,213,622		$	435,299		$	1,995,724		$	(2,407,279	)	$	1,237,366
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current portion of long-term debt	$	51,136		$	—		$	—		$	—		$	51,136
Accounts payable and accrued liabilities		63,599			71,396			190,474			(218,008	)		107,461
Accrued income taxes		(920	)		1,444			4,747			—			5,271
Total current liabilities		113,815			72,840			195,221			(218,008	)		163,868
Long-term debt		429,888			—			—			—			429,888
Other long-term liabilities		8,263			6,912			14,360			—			29,535
Long-term deferred tax liability		2,229			27,870			(12,269	)		—			17,830
Intercompany payables		62,584			43,657			103,625			(209,866	)		—
Contingencies		—			—			—			—			—
Stockholders’ equity:
Common stock		19,696			18,049			43,003			(61,052	)		19,696
Capital in excess of par value		642,616			733,112			1,449,633			(2,182,745	)		642,616
Retained earnings (accumulated deficit)		(65,469	)		(467,141	)		202,749			264,392			(65,469	)
Total controlling interest stockholders’ equity		596,843			284,020			1,695,385			(1,979,405	)		596,843
Noncontrolling interest		—			—			(598	)		—			(598	)
Total Equity		596,843			284,020			1,694,787			(1,979,405	)		596,245
Total liabilities and stockholders’ equity	$	1,213,622		$	435,299		$	1,995,724		$	(2,407,279	)	$	1,237,366

19

PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATING CONDENSED BALANCE SHEET

(Dollars in Thousands)

(Unaudited)

	December 31, 2011
	Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	55,670		$	4,212		$	37,987		$	—		$	97,869
Accounts and notes receivable, net		289,512			94,748			285,326			(485,663	)		183,923
Rig materials and supplies		—			762			29,185			—			29,947
Deferred costs		—			—			3,249			—			3,249
Deferred income taxes		—			5,311			853			486			6,650
Other tax assets		47,834			(25,218	)		2,742			—			25,358
Assets held for sale		—			—			5,315			—			5,315
Other current assets		788			6,381			8,133			—			15,302
Total current assets		393,804			86,196			372,790			(485,177	)		367,613
Property, plant and equipment, net		79			474,942			244,787			1			719,809
Investment in subsidiaries and intercompany advances		720,214			(212,883	)		1,347,719			(1,855,050	)		—
Other noncurrent assets		44,962			66,660			16,839			363			128,824
Total assets	$	1,159,059		$	414,915		$	1,982,135		$	(2,339,863	)	$	1,216,246
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current portion of long-term debt	$	145,723		$	—		$	—		$	—		$	145,723
Accounts payable and accrued liabilities		60,120			94,056			181,010			(199,936	)		135,250
Accrued income taxes		(205	)		921			4,121			—			4,837
Total current liabilities		205,638			94,977			185,131			(199,936	)		285,810
Long-term debt		337,000			—			—			—			337,000
Other long-term liabilities		8,081			9,474			15,897			—			33,452
Long-term deferred tax liability		1,151			25,232			(11,296	)		847			15,934
Intercompany payables		62,583			43,657			111,619			(217,859	)		—
Contingencies		—			—			—			—			—
Stockholders’ equity:
Common stock		19,508			18,049			43,003			(61,052	)		19,508
Capital in excess of par value		637,042			733,120			1,444,091			(2,177,211	)		637,042
Retained earnings (accumulated deficit)		(111,944	)		(509,594	)		194,246			315,348			(111,944	)
Total controlling interest stockholders’ equity		544,606			241,575			1,681,340			(1,922,915	)		544,606
Noncontrolling interest		—			—			(556	)		—			(556	)
Total Equity		544,606			241,575			1,680,784			(1,922,915	)		544,050
Total liabilities and stockholders’ equity	$	1,159,059		$	414,915		$	1,982,135		$	(2,339,863	)	$	1,216,246

20

PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATING CONDENSED STATEMENT OF OPERATIONS

(Dollars in Thousands)

(Unaudited)

	Three months ended June 30, 2012
	Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated
Total revenues	$	—		$	104,767		$	98,036		$	(23,878	)	$	178,925
Operating expenses		—			47,632			80,772			(23,878	)		104,526
Depreciation and amortization		—			15,665			12,294			—			27,959
Total operating gross margin		—			41,470			4,970			—			46,440
General and administration expense(1)		(44	)		(7,078	)		(298	)		—			(7,420	)
Gain on disposition of assets, net		—			197			1,171			—			1,368
Total operating income (loss)		(44	)		34,589			5,843			—			40,388
Other income and (expense):
Interest expense		(9,817	)		(35	)		(2,023	)		2,950			(8,925	)
Interest income		8,504			4,537			34,070			(47,058	)		53
Loss on extinguishment of debt		(1,649	)		—			—			—			(1,649	)
Changes in fair value of derivative positions		38			—			—			—			38
Other		—			23			(3	)		—			20
Equity in net earnings of subsidiaries		19,057			—			—			(19,057	)		—
Total other income (expense)		16,133			4,525			32,044			(63,165	)		(10,463	)
Income (benefit) before income taxes		16,089			39,114			37,887			(63,165	)		29,925
Income tax expense (benefit)		(3,994	)		13,668			143			—			9,817
Net income (loss)		20,083			25,446			37,744			(63,165	)		20,108
Less: Net income attributable to noncontrolling interest		—			—			25			—			25
Net income (loss) attributable to controlling interest	$	20,083		$	25,446		$	37,719		$	(63,165	)	$	20,083

(1) General and administration expenses for field operations are included in operating expenses.

21

PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATING CONDENSED STATEMENT OF OPERATIONS

(Dollars in Thousands)

(Unaudited)

	Three months ended June 30, 2011
	Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated
Total revenues	$	—		$	95,435		$	100,323		$	(22,946	)	$	172,812
Operating expenses		—			41,224			86,405			(22,946	)		104,683
Depreciation and amortization		—			15,387			11,945			—			27,332
Total operating gross margin		—			38,824			1,973			—			40,797
General and administration expense(1)		(83	)		(7,798	)		(67	)		—			(7,948	)
Gain on disposition of assets, net		—			94			272			—			366
Total operating income (loss)		(83	)		31,120			2,178			—			33,215
Other income and (expense):
Interest expense		(6,746	)		(8,909	)		(2,159	)		12,059			(5,755	)
Interest income		8,971			190			3,031			(12,059	)		133
Change in fair value of derivative position		(137	)		—			—			—			(137	)
Other		—			120			3			—			123
Equity in net earnings of subsidiaries		36,794			—			—			(36,794	)		—
Total other income and (expense)		38,882			(8,599	)		875			(36,794	)		(5,636	)
Income (benefit) before income taxes		38,799			22,521			3,053			(36,794	)		27,579
Income tax expense (benefit)		24,625			7,680			(18,841	)		—			13,464
Net income (loss)		14,174			14,841			21,894			(36,794	)		14,115
Less: Net (loss) attributable to noncontrolling interest		—			—			(58	)		—			(58	)
Net income (loss) attributable to controlling interest	$	14,174		$	14,841		$	21,952		$	(36,794	)	$	14,173

(1) General and administration expenses for field operations are included in operating expenses.

22

PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATING CONDENSED STATEMENT OF OPERATIONS

(Dollars in Thousands)

(Unaudited)

	Six months ended June 30, 2012
	Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated
Total revenues	$	—		$	203,924		$	201,061		$	(49,491	)	$	355,494
Operating expenses		—			90,999			157,950			(49,491	)		199,458
Depreciation and amortization		—			31,261			24,317			—			55,578
Total operating gross margin		—			81,664			18,794			—			100,458
General and administration expense(1)		(90	)		(12,450	)		(377	)		—			(12,917	)
Gain on disposition of assets, net		—			615			1,245			—			1,860
Total operating income (loss)		(90	)		69,829			19,662			—			89,401
Other income and (expense):
Interest expense		(18,818	)		(71	)		(3,972	)		5,899			(16,962	)
Interest income		8,600			4,715			36,771			(50,007	)		79
Loss on extinguishment of debt		(1,649	)		—			—			—			(1,649	)
Changes in fair value of derivative positions		(11	)		—			—			—			(11	)
Other		—			36			—			—			36
Equity in net earnings of subsidiaries		50,957			—			—			(50,957	)		—
Total other income (expense)		39,079			4,680			32,799			(95,065	)		(18,507	)
Income (benefit) before income taxes		38,989			74,509			52,461			(95,065	)		70,894
Income tax expense (benefit)		(7,486	)		27,698			4,248			—			24,460
Net income (loss)		46,475			46,811			48,213			(95,065	)		46,434
Less: Net (loss) attributable to noncontrolling interest		—			—			(41	)		—			(41	)
Net income (loss) attributable to controlling interest	$	46,475		$	46,811		$	48,254		$	(95,065	)	$	46,475

(1) General and administration expenses for field operations are included in operating expenses.

23

PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATING CONDENSED STATEMENT OF OPERATIONS

(Dollars in Thousands)

(Unaudited)

	Six months ended June 30, 2011
	Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated
Total revenues	$	—			182,840		$	208,414		$	(62,263	)	$	328,991
Operating expenses		—			91,628			182,694			(62,263	)		212,059
Depreciation and amortization		—			30,597			24,334			—			54,931
Total operating gross margin		—			60,615			1,386			—			62,001
General and administration expense(1)		(128	)		(14,495	)		(129	)		—			(14,752	)
Gain on disposition of assets, net		—			904			466			—			1,370
Total operating income (loss)		(128	)		47,024			1,723			—			48,619
Other income and (expense):
Interest expense		(13,598	)		(17,819	)		(3,887	)		23,688			(11,616	)
Interest income		17,941			380			5,546			(23,688	)		179
Change in fair value of derivative positions		(137	)		—			—			—			(137	)
Other		—			120			14			—			134
Equity in net earnings of subsidiaries		40,759			—			—			(40,759	)		—
Total other income and (expense)		44,965			(17,319	)		1,673			(40,759	)		(11,440	)
Income (benefit) before income taxes		44,837			29,705			3,396			(40,759	)		37,179
Income tax expense (benefit)		25,836			8,053			(15,586	)		—			18,303
Net income (loss)		19,001			21,652			18,982			(40,759	)		18,876
Less: Net (loss) attributable to noncontrolling interest		—			—			(125	)		—			(125	)
Net income (loss) attributable to controlling interest	$	19,001		$	21,652		$	19,107		$	(40,759	)	$	19,001

(1) General and administration expenses for field operations are included in operating expenses.

24

PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)

(Unaudited)

	Six Months Ended June 30, 2012
	Parent			Guarantor			Non—  Guarantor			Eliminations			Consolidated
Cash flows from operating activities:
Net income (loss)	$	46,475		$	46,811		$	48,213		$	(95,065	)	$	46,434
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization		—			31,261			24,317			—			55,578
Loss on extinguishment of debt		1,649			—			—			—			1,649
Gain on disposition of assets		—			(615	)		(1,245	)		—			(1,860	)
Deferred income tax expense		7,025			3,832			(425	)		—			10,432
Expenses not requiring cash		10,737			716			336			—			11,789
Equity in net earnings of subsidiaries		(50,957	)		—			—			50,957			—
Change in accounts receivable		(208	)		(11,248	)		20,617			—			9,161
Change in other assets		(29,586	)		22,490			(42	)		—			(7,138	)
Change in accrued income taxes		(766	)		1,042			647			—			923
Change in liabilities		2,402			(25,239	)		(8,600	)		—			(31,437	)
Net cash provided by (used in) operating activities		(13,229	)		69,050			83,818			(44,108	)		95,531
Cash flows from investing activities:
Capital expenditures		—			(103,855	)		(5,676	)		—			(109,531	)
Proceeds from the sale of assets		—			906			1,434			—			2,340
Intercompany dividend payment		(8,387	)		(4,357	)		(31,364	)		44,108			—
Net cash (used in) investing activities		(8,387	)		(107,306	)		(35,606	)		44,108			(107,191	)
Cash flows from financing activities:
Proceeds from debt issuance		130,000			—			—			—			130,000
Paydown on senior notes		(122,852	)		—			—			—			(122,852	)
Paydown on term note		(12,000	)		—			—			—			(12,000	)
Payment of debt issuance costs		(3,537	)		—			—			—			(3,537	)
Payment of debt extinguishment costs		(402	)		—			—			—			(402	)
Excess tax benefit from stock-based compensation		49			—			—			—			49
Intercompany advances, net		2,919			44,310			(47,229	)		—			—
Net cash provided by (used in) financing activities		(5,823	)		44,310			(47,229	)		—			(8,742	)
Net change in cash and cash equivalents		(27,439	)		6,054			983			—			(20,402	)
Cash and cash equivalents at beginning of year		55,670			4,212			37,987			—			97,869
Cash and cash equivalents at end of year	$	28,231		$	10,266		$	38,970		$	—		$	77,467

25

PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)

(Unaudited)

	Six Months Ended June 30, 2011
	Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated
Cash flows from operating activities:
Net income (loss)	$	19,001		$	21,652		$	18,982		$	(40,759	)	$	18,876
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization		—			30,597			24,334			—			54,931
Gain on disposition of assets		—			(904	)		(466	)		—			(1,370	)
Deferred income tax expense		33,718			(1,715	)		(24,809	)		—			7,194
Expenses not requiring cash		8,661			—			(306	)		—			8,355
Equity in net earnings of subsidiaries		(40,759	)		—			—			40,759			—
Change in accounts receivable		258,051			(211,818	)		(58,296	)		—			(12,063	)
Change in other assets		67,376			(21,355	)		2,917			—			48,938
Change in liabilities		(11,797	)		(73,099	)		55,934			—			(28,962	)
Net cash provided by (used in) operating activities		334,251			(256,642	)		18,290			—			95,899
Cash flows from investing activities:
Capital expenditures		—			(92,606	)		(6,771	)		—			(99,377	)
Proceeds from the sale of assets		—			1,590			763			—			2,353
Proceeds from insurance settlements		—			250			—			—			250
Net cash used in investing activities		—			(90,766	)		(6,008	)		—			(96,774	)
Cash flows from financing activities:
Proceeds from issuance of debt		50,000			—			—			—			50,000
Repayments of term loan		(9,000	)		—			—			—			(9,000	)
Repayments on revolver		(25,000	)		—			—			—			(25,000	)
Payment of debt issuance costs		(504	)		—			—			—			(504	)
Proceeds from stock options exercised		183			—			—			—			183
Excess tax benefit from stock-based compensation		1,260			—			—			—			1,260
Intercompany advances, net		(334,186	)		353,012			(18,826	)		—			—
Net cash provided by (used in) financing activities		(317,247	)		353,012			(18,826	)		—			16,939
Net change in cash and cash equivalents		17,004			5,604			(6,544	)		—			16,064
Cash and cash equivalents at beginning of period		13,835			2,317			35,279			—			51,431
Cash and cash equivalents at end of period	$	30,839		$	7,921		$	28,735		$	—		$	67,495

26

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

DISCLOSURE NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Form 10-Q contains statements that are “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (Securities Act), and Section 21E of the Securities Exchange Act of 1934, as amended (Exchange Act). All statements contained in this Form 10-Q, other than statements of historical facts, are forward-looking statements for purposes of these provisions, including any statements regarding:

• stability of prices and demand for oil and natural gas;

• levels of oil and natural gas exploration and production activities;

• demand for contract drilling and drilling-related services and demand for rental tools;

• our future operating results and profitability;

• our future rig utilization, dayrates and rental tools activity;

• entering into new, or extending existing, drilling contracts and our expectations concerning when our rigs will commence operations under such contracts;

• growth through acquisitions of companies or assets;

• organic growth of our operations;

• construction or upgrades of rigs and expectations regarding when these rigs will commence operations;

• capital expenditures for acquisition of rigs, construction of new rigs or major upgrades to existing rigs;

• scheduled delivery, commissioning and subsequent operation of our AADU rigs under the terms of our agreement with BP Exploration (Alaska) Inc.;

• entering into joint venture agreements;

• the outcome of pending or future legal proceedings, investigations, tax assessments and other claims;

• the availability of insurance coverage for pending or future claims;

• the enforceability of contractual indemnification in relation to pending or future claims;

• our future liquidity;

• availability and sources of funds to refinance our debt and expectations of when debt will be reduced; and

• compliance with covenants under our debt agreements.

In some cases, you can identify these statements by forward-looking words such as “anticipate,” “believe,” “could,” “estimate,” “expect,” “intend,” “outlook,” “may,” “should,” “will” and “would” or similar words. Forward-looking statements are based on certain assumptions and analyses made by our management in light of their experience and perception of historical trends, current conditions, expected future developments and other factors they believe are relevant. Although our management believes that their assumptions are reasonable based on information currently available, those assumptions are subject to significant risks and uncertainties, many of which are outside of our control.

27

The following factors, as well as those factors set forth in Item 1A, “Risk Factors”, in our Annual Report on Form 10-K for the year ended December 31, 2011, and any other cautionary language included in this Form 10-Q, provide examples of risks, uncertainties and events that may cause our actual results to differ materially from the expectations we describe in our forward-looking statements:

• worldwide economic and business conditions that adversely affect market conditions and/or the cost of doing business including Euro country failures and downgrades;

• our inability to access the credit or bond markets;

• U.S. credit market volatility resulting from the U.S. national debt and potential further downgrades of the U.S. credit rating;

• the U.S. economy and the demand for natural gas;

• low U.S. natural gas prices could adversely affect U.S. drilling and our barge rig and rental tools businesses;

• worldwide demand for oil;

• fluctuations in the market prices of oil and natural gas, including the inability or unwillingness of our customers to fund drilling programs in low price cycles;

• imposition of unanticipated trade restrictions;

• unanticipated operating hazards and uninsured risks;

• political instability, terrorism or war;

• governmental regulations, including changes in accounting rules or tax laws that may impact our ability to remit funds to the U.S., that adversely affect the cost of doing business;

• changes in the tax laws that would allow double taxation on foreign sourced income;

• the outcome of our investigation and the parallel investigations by the SEC and DOJ into possible violations of U.S. law, including the FCPA;

• adverse environmental events;

• adverse weather conditions;

• global health concerns;

• changes in the concentration of customer and supplier relationships;

• ability of our customers and suppliers to obtain financing for their operations;

• ability of our customers to fund drilling plans with low commodity prices;

• unexpected cost increases for new construction and upgrade and refurbishment projects;

• delays in obtaining components for capital projects and in ongoing operational maintenance and equipment certifications;

• shortages of skilled labor;

• unanticipated cancellation of contracts by customers or operators;

• breakdown of equipment;

• other operational problems including delays in start-up or commissioning of rigs;

• changes in competition;

• the effect of litigation and contingencies; and

• other similar factors, some of which are discussed in our Annual Report on Form 10-K, elsewhere in this Form 10-Q and in our other reports and filings with the SEC.

28

Each forward-looking statement speaks only as of the date of this Form 10-Q, and we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. Before you decide to invest in our securities, you should be aware that the occurrence of the events described in these risk factors and elsewhere in this Form 10-Q could have a material adverse effect on our business, results of operations, financial condition and cash flows.

29

OVERVIEW AND OUTLOOK

Overview

Parker’s operating results for the 2012 second quarter, reflect year-to-year increases in revenues, net income and earnings per share. We achieved growth in our Rental Tools and U.S. Barge Drilling segments, driven primarily by increased activity in the U.S. land and shallow water Gulf of Mexico drilling markets. Though International Drilling revenues and earnings declined due to reduced contributions from our Operations and Maintenance contracts (O&M), we realized improved utilization and higher average dayrates for the Parker-owned drilling rig fleet. In addition, we made progress toward the completion of our two Arctic Alaska Drilling Unit (AADU) rigs.

Outlook

Shifting trends in U.S. drilling and the market’s current uncertainty about future prices for oil and natural gas have begun to lead to slower growth in some U.S. land markets and has us alert for changing conditions that may further impact our business. We believe that our competitive position, geographic and market diversity, and other strategic strengths, position us to face these market challenges and take advantage of competitive opportunities to produce relatively resilient operating results.

We expect market conditions for rental tools to reflect the recent slower growth in U.S. land drilling and a more typical competitive environment. Nevertheless, the broadening application of lateral drilling and the trend toward more complex well designs should continue to lead to demand for premium rental tools and premier customer service. In addition, the growing fleet of deepwater drilling vessels in the Gulf of Mexico (GOM) is expected to be an expanded source of business opportunity for our Rental Tools segment.

Each of our AADU rigs will be presented for acceptance testing at separate times during the second half of the year, at which point the assets will be substantially complete and ready for their intended use. At this time, the Company will begin incurring operating costs and depreciation and will cease capitalizing interest costs. We expect there will be some months ahead in which we will have no or little revenues from these rigs. Revenues will be generated after the rigs have been accepted by the customer, moved to location and begun operations. As a result, the U.S. Drilling segment’s gross margin is likely to reflect losses during the remainder of the year.

Drilling remains active in the GOM barge drilling market with oil and liquids-rich natural gas targets being the predominant focus. If market prices for these commodities remain around current levels, there should be good support for continued drilling in the shallow waters of the GOM. Further interest in developing deep gas plays in this area could provide additional growth opportunities.

The Parker-owned international rig fleet is expected to experience declining utilization in the near-term. As current drilling contracts expire, not all of them are expected to be renewed. Deployment opportunities for our international rig fleet and additional contracts for our O&M portfolio take time to develop. Though there appears to be a growing interest among international operators to expand land drilling in several of our focus regions these are longer term developments. Any tender awards or contract wins in the next few months are most likely to have their greatest impact in 2013.

Our O&M contracts on Sakhalin Island, Russia expired in the third quarter. We were successful in winning a new contract that adds a third rig management project to the two projects we managed previously under the expired contracts. The new consolidated contract replaces a significant portion, but not all, of the financial contribution of the expired contracts.

We have substantially completed several of the Technical Services segment projects that were contributors to segment revenues and earnings during the first six months of 2012 and expect to maintain this lower level of activity for the near-term. There are some early-stage engineering and development projects in which we are engaged that could transform into more expansive involvement in the future.

30

RESULTS OF OPERATIONS

Three Months Ended June 30, 2012 Compared with Three Months Ended June 30, 2011

Revenues increased $6.1 million, or 3.5% to $178.9 million for the three months ended June 30, 2012 compared with revenues of $172.8 million for the comparable 2011 period. Operating gross margin increased $5.6 million, or 13.8% to $46.4 million for the three months ended June 30, 2012, compared with operating gross margin of $40.8 million for the three months ended June 30, 2011. We recorded net income attributable to controlling interest of $20.1 million for the three months ended June 30, 2012, compared with $14.2 million for the three months ended June 30, 2011.

The following is an analysis of our operating results for the comparable quarters:

	Three Months Ended June 30,
	2012					2011
	(Dollars in Thousands)
Revenues:
Rental Tools	$	65,002		36	%	$	58,490		34	%
U.S. Barge Drilling		33,292		19	%		26,060		15	%
U.S. Drilling		—		0	%		—		0	%
International Drilling		76,923		43	%		79,725		46	%
Technical Services		3,708		2	%		8,537		5	%
Construction Contract		—		0	%		—		0	%
Total revenues		178,925		100	%		172,812		100	%
Operating gross margin:
Rental Tools gross margin excluding depreciation and amortization		42,450		65	%		40,771		70	%
U.S Barge Drilling gross margin excluding depreciation and amortization		14,500		44	%		9,054		35	%
U.S. Drilling gross margin excluding depreciation and amortization		(533	)	n/a			(212	)	n/a
International Drilling gross margin excluding depreciation and amortization		18,240		24	%		15,212		19	%
Technical Services gross margin		(258	)	-7	%		1,789		21	%
Construction Contract gross margin		—		n/a			1,515		n/a
Total operating gross margin excluding depreciation and amortization		74,399		42	%		68,129		39	%
Depreciation and amortization		(27,959	)				(27,332	)
Total operating gross margin		46,440					40,797
General and administrative expense		(7,420	)				(7,948	)
Gain on disposition of assets, net		1,368					366
Total operating income	$	40,388				$	33,215

31

Segment operating gross margins excluding depreciation and amortization, are computed as revenues less direct operating expenses, excluding depreciation and amortization expense, where applicable; segment operating gross margin percentages are computed as operating gross margin as a percent of revenues. The operating gross margin amounts and operating gross margin percentages should not be used as a substitute for those amounts reported under U.S. GAAP. However, we monitor our business segments based on several criteria, including operating gross margin. Management believes that this information is useful to our investors because it more accurately reflects cash generated by segment. Such operating gross margin amounts are reconciled to our most comparable U.S. GAAP measure as follows:

	Rental Tools		U.S. Barge Drilling		U.S. Drilling			International Drilling		Technical Services(2)			Construction Contract(2)
Three Months Ended June, 2012	(Dollars in Thousands)
Operating gross margin(1)	$	31,251	$	11,014	$	(1,623	)	$	6,056	$	(258	)	$	—
Depreciation and amortization		11,199		3,486		1,090			12,184		—			—
Operating gross margin excluding depreciation and amortization	$	42,450	$	14,500	$	(533	)	$	18,240	$	(258	)	$	—
Three Months Ended June 30, 2011
Operating gross margin(1)	$	30,566	$	4,451	$	(340	)	$	2,816	$	1,789		$	1,515
Depreciation and amortization		10,205		4,603		128			12,396		—			—
Operating gross margin excluding depreciation and amortization	$	40,771	$	9,054	$	(212	)	$	15,212	$	1,789		$	1,515

(1) Operating gross margin is calculated as revenues less direct operating expenses, including depreciation and amortization expense.

(2) The Technical Services segment and the Construction Contract segment do not incur depreciation and amortization.

Rental Tools

Rental Tools segment revenues increased $6.5 million, or 11.1%, to $65.0 million for the second quarter of 2012 compared with $58.5 million for the second quarter of 2011. The increase was driven primarily by growth in demand for rental tools and improved pricing of our services. This segment benefitted from the expanded use of lateral drilling and the trend toward more complex well designs in the U.S. land market and renewed growth in Gulf of Mexico drilling.

Rental Tools segment operating gross margin, excluding depreciation and amortization, increased $1.7 million, or 4.1%, to $42.5 million for the second quarter of 2012, compared with $40.8 million for the second quarter of 2011. This was primarily due to increased revenues and cost management.

U.S. Barge Drilling

U.S. Barge Drilling segment revenues increased $7.2 million, or 27.8%, to $33.3 million for the second quarter of 2012 compared with $26.1 million for the second quarter of 2011. The increase in revenues was primarily due to increased utilization and a higher average dayrate for the U.S. barge rig fleet.

The U.S. Barge Drilling segment’s operating gross margin, excluding depreciation and amortization, increased $5.4 million, or 60.1% to $14.5 million for the second quarter of 2012 compared with $9.1 million for the second quarter of 2011. The increase in operating gross margin was mostly driven by an increase in average dayrates along with an increase in utilization for the U.S. barge rig fleet.

32

U.S. Drilling

As of June 30, 2012, the U.S. Drilling segment had not begun generating revenue. This segment is expected to begin generating revenue upon commencement of the drilling contract with our customer. Operating gross margin, excluding depreciation and amortization, was a loss of $0.5 million and $0.2 million for the three-month periods ended June 30, 2012 and 2011, respectively, and includes expenditures associated with re-entering the Alaskan market. The start-up costs include salaries and employee hiring-related expenditures, training and rental of facilities in Alaska to support our operations.

International Drilling

International Drilling segment revenues decreased $2.8 million, or 3.5%, to $76.9 million for the second quarter of 2012 compared with $79.7 million for the second quarter of 2011. The lower revenues are primarily due to a decline in reimbursable revenues from O&M contracts, offset by an increase in drilling revenue generated by the operation of rigs that we own.

O&M revenues declined $12.5 million, or 33.8%, to $24.5 million for the second quarter of 2012 compared with $37.0 million for the second quarter of 2011, primarily due to a decline in reimbursable expenses related to a drilling rig relocation project which commenced during the first quarter of 2011 and was completed prior to December 31, 2011. The decrease in revenues was partially offset by an increase in revenues for two O&M contracts that transitioned during the second quarter of 2012 to more active status from idle or minimal activity during the second quarter of 2011. O&M projects included approximately $6.1 million and $17.6 million of reimbursable costs for the three-month periods ended June 30, 2012 and 2011, respectively, which added to revenues but had little impact on operating margins.

Revenues related to Parker-owned rigs increased $9.7 million, or 22.7%, to $52.4 million for the second quarter of 2012 compared with $42.7 million for the second quarter of 2011. Increases were realized in both the Latin America and Eastern Hemisphere regions due to increased utilization in those regions. Additionally, the Latin America region recognized an increase in demobilization revenues as contracts for two rigs ended during the second quarter of 2012. The increase in revenues in the Eastern Hemisphere was partially offset by a decrease in revenues for our arctic-class barge rig located in the Caspian Sea.

International Drilling operating gross margin, excluding depreciation and amortization, increased $3.0 million, or 19.7%, to $18.2 million during the second quarter of 2012, compared with $15.2 million for the second quarter of 2011. The increase in operating gross margin for the second quarter of 2012 was primarily due to increased margins generated by higher dayrates and increased utilization of our rigs and the inclusion in the second quarter of 2011 of $2.3 million of expense related to a non-cash charge to write-off certain value added tax (VAT) assets in the Eastern Hemisphere region. This was partially offset by lower margins on O&M contracts resulting from a decrease in reimbursable expenses as described above.

Technical Services

Technical Services segment revenues decreased $4.8 million, or 56.6%, to $3.7 million for the second quarter of 2012 compared with $8.5 million for the second quarter of 2011. More than half of the decrease was due to expiration at the end of the second quarter of 2011 of the “pre-operations” phase of the Liberty project and transition of the Berkut platform project (previously described as the “Arkutun Dagi” project) from its engineering phase to a less revenue-intensive construction oversight and assistance phase.

Operating gross margin for this segment decreased to a loss of $0.3 million for the second quarter of 2012 compared with income of $1.8 million for the second quarter of 2011. The decrease is primarily the result of decreased operating gross margins on the Berkut project and completion or near completion of other pre-FEED engineering efforts that were ongoing during the year. The Technical Services segment does not incur depreciation and amortization.

33

Construction Contract

The Construction Contract segment includes only the Liberty extended-reach drilling rig construction project for BP. The Construction Contract segment had no revenues for the three months ended June 30, 2012 and June 30, 2011. This segment reported zero operating gross margin for the second quarter of 2012 compared with operating gross margin of $1.5 million for the second quarter of 2011. The operating gross margin generated during the second quarter of 2011 was based upon management’s evaluation and the adjustment of estimated liabilities to close out all remaining activities between us and BP related to the construction contract. The Construction Contract segment does not incur depreciation and amortization.

The Liberty rig construction contract was a fixed fee and reimbursable contract accounted for on a percentage of completion basis. As of December 31, 2011, we had recognized $335.5 million in project-to-date revenues. Over the life of the contract, we recognized $11.7 million of margin on the contract.

In November 2010, BP informed us that it was suspending construction on the project to review the rig’s engineering and design, including its safety systems. The Liberty rig construction contract expired on February 8, 2011 prior to completion of the rig. Before expiration of the construction contract, BP identified several areas of concern relating to design, construction and invoicing for which it asked us to provide explanations and documentation, and we did so. Although we provided BP with the requested information, we do not know when or how these issues will be resolved with our client.

After expiration of the construction contract, the Company and BP continued activities to preserve and maintain the rig under the “pre-operations” phase of an O&M contract, which was entered into in August 2009 and expired on July 1, 2011. A new consulting services agreement was reached between us and BP effective July 1, 2011. Under the consulting services agreement, we assisted BP in a review of the rig’s design, the creation of a new statement of requirements for the rig, and the transition of documentation and materials to BP. All work under the consulting agreement has been completed and we are engaged with BP on construction contract close-out resolution. In June 2012, BP publicly announced that it had made the decision to suspend the Liberty project indefinitely. We do not know whether or how that decision may impact our discussions with BP related to contract close-out.

Other Financial Data

Gains on asset dispositions for the second quarter of 2012 and 2011 were $1.4 million and $0.4 million, respectively, and were primarily the result of gains on various asset sales during each period. We periodically sell equipment deemed to be excess, obsolete, or not currently required for operations.

Interest expense increased $3.2 million for the second quarter of 2012 compared with the second quarter of 2011 due to a $1.1 million increase in interest expense resulting from higher interest on the additional $125 million of 9.125% Notes, which have a higher interest rate than our 2.125% Notes. We incurred interest on both notes issuances during the tender period. Additionally, we incurred a $1.7 million decrease in interest capitalized on major projects, primarily resulting from a reduction in the value of the AADUs following an impairment charge recorded during the fourth quarter of 2011. The remainder of the increase was due to an increase in amortization of debt fees attributable to the issuance of an additional $125.0 million of 9.125% Notes in April 2012. Interest income was not significant during each quarter.

We incurred a loss on extinguishment of debt of $1.6 million during the second quarter of 2012. This loss resulted from the repurchase of $122.9 million of 2.125% Notes pursuant to a tender offer which was funded on May 9, 2012. The loss included $0.4 million of premium paid to tender the 2.125% Notes prior to maturity and $1.2 million of accelerated amortization of the related debt discount and debt issuance costs.

34

General and administration expense decreased $0.5 million for the second quarter of 2012 compared with the second quarter of 2011 due primarily to a decrease in legal fees associated with the SEC and DOJ investigations (see further discussion in Note 11 in the Notes to Company financial statements), partially offset by an increase in employee recruitment costs and professional fees.

Income tax expense was $9.8 million for the second quarter of 2012, compared with $13.5 million for the second quarter of 2011. The decrease in current quarter tax expense was driven primarily by utilization of net operating losses during the second quarter of 2012 that were not present during 2011 and release of reserves due to expiration of the statute of limitations for uncertain tax positions taken on returns in Latin America.

Six Months Ended June 30, 2012 Compared with Six Months Ended June 30, 2011

Revenues increased $26.5 million, or 8.1%, to $355.5 million for the six months ended June 30, 2012, compared with revenues of $329.0 million for the comparable 2011 period. Operating gross margin increased $38.5 million, or 62.0%, to $100.5 million for the six months ended June 30, 2012, compared with operating gross margin of $62.0 million for the comparable 2011 period. We recorded net income attributable to controlling interest of $46.5 million for the six months ended June 30, 2012, as compared with $19.0 million for the six months ended June 30, 2011.

The following is an analysis of our operating results for the comparable periods:

	Six Months Ended June 30,
	2012					2011
	(Dollars in Thousands)
Revenues:
Rental Tools	$	131,286		37	%	$	110,809		34	%
U.S. Barge Drilling		61,127		17	%		41,980		13	%
U.S. Drilling		—		0	%		—		0	%
International Drilling		155,673		44	%		149,661		45	%
Technical Services		7,408		2	%		16,903		5	%
Construction Contract		—		0	%		9,638		3	%
Total revenues		355,494		100	%		328,991		100	%
Operating gross margin:
Rental Tools gross margin excluding depreciation and amortization		87,104		66	%		74,953		68	%
U.S Barge Drilling gross margin excluding depreciation and amortization		25,195		41	%		10,872		26	%
U.S. Drilling gross margin excluding depreciation and amortization		(999	)	n/a			(425	)	n/a
International Drilling gross margin excluding depreciation and amortization		44,747		29	%		27,406		18	%
Technical Services gross margin		(11	)	0	%		3,355		20	%
Construction Contract gross margin		—		n/a			771		8	%
Total operating gross margin excluding depreciation and amortization		156,036		44	%		116,932		36	%
Depreciation and amortization		(55,578	)				(54,931	)
Total operating gross margin		100,458					62,001
General and administrative expense		(12,917	)				(14,752	)
Gain on disposition of assets, net		1,860					1,370
Total operating income	$	89,401				$	48,619

35

Segment gross margins, excluding depreciation and amortization, are computed as revenues less direct operating expenses, and less depreciation and amortization expense, where applicable; segment operating gross margin percentages are computed as operating gross margin as a percent of revenues. The operating gross margin amounts and operating gross margin percentages should not be used as a substitute for those amounts reported under U.S. GAAP. However, we monitor our business segments based on several criteria, including operating gross margin. Management believes that this information is useful to our investors because it more accurately reflects cash generated by segment. Such operating gross margin amounts are reconciled to our most comparable U.S. GAAP measure as follows:

	Rental Tools		U.S. Barge Drilling		U.S. Drilling			International Drilling		Technical Services(2)			Construction Contract(2)
Six Months Ended June 30, 2012	(Dollars in Thousands)
Operating gross margin(1)	$	64,853	$	18,171	$	(3,170	)	$	20,615	$	(11	)	$	—
Depreciation and amortization		22,251		7,024		2,171			24,132		—			—
Operating gross margin excluding depreciation and amortization	$	87,104	$	25,195	$	(999	)	$	44,747	$	(11	)	$	—
Six Months Ended June 30, 2011
Operating gross margin(1)	$	54,664	$	1,769	$	(681	)	$	2,123	$	3,355		$	771
Depreciation and amortization		20,289		9,103		256			25,283		—			—
Operating gross margin excluding depreciation and amortization	$	74,953	$	10,872	$	(425	)	$	27,406	$	3,355		$	771

(1) Operating gross margin is calculated as revenues less direct operating expenses, including depreciation and amortization expense.

(2) The Technical Services segment and the Construction Contract segment do not incur depreciation and amortization.

Rental Tools

Rental Tools segment revenues increased $20.5 million, or 18.5%, to $131.3 million during the six months ended June 30, 2012 compared with $110.8 million for the six months ended June 30, 2011. The increase was primarily due to the increased demand for rental tools and higher utilization. This segment benefitted from the expanded use of lateral drilling and the trend toward more complex well designs in the U.S. land market and renewed growth in Gulf of Mexico drilling.

Rental Tools segment operating gross margin, excluding depreciation and amortization, increased $12.1 million, or 16.1%, to $87.1 million during the six months ended June 30, 2012, compared with $75.0 million for the six months ended June 30, 2011, primarily due to higher revenues, and cost management.

U.S. Barge Drilling

U.S. Barge Drilling segment revenues increased $19.1 million, or 45.6%, to $61.1 million for the six months ended June 30, 2012, compared with $42.0 million for the six months ended June 30, 2011. The increase in revenues was primarily due to overall increased utilization and a higher average dayrate for the U.S. barge rig fleet.

U.S. Barge Drilling segment operating gross margin, excluding depreciation and amortization, increased $14.3 million, or 131.7%, to $25.2 million for the six months ended June 30, 2012, compared with $10.9 million for the six months ended June 30, 2011, primarily due to the increase in utilization and average dayrates mentioned above.

36

U.S. Drilling

As of June 30, 2012, the U.S. Drilling segment had not begun generating revenues. Operating gross margin, excluding depreciation and amortization, was a loss of $1.0 million and $0.4 million for the six-month periods ended June 30, 2012 and 2011, respectively, and includes expenditures associated with re-entering the Alaskan market. The start-up costs include salaries and employee hiring-related expenditures, training and rental of facilities in Alaska to support our operations.

International Drilling

International Drilling segment revenues increased $6.0 million, or 4.0%, to $155.7 million for the six-months ended June 30, 2012 compared with $149.7 million for the six-months ended June 30, 2011. The higher revenues are primarily due to an increase in drilling revenues generated by the operation of rigs that we own partially offset by a decline in reimbursable revenues from O&M contracts.

Revenues related to Parker-owned rigs increased $24.5 million, or 28.9%, to $109.3 million for the six-months ended June 30, 2012 compared with $84.8 million for the six-months ended June 30, 2011, due to increases in revenue in both the Latin America and Eastern Hemisphere regions, primarily resulting from increased utilization. Both regions had rigs active during the first half of 2012 that had been idle for some or all of the comparable period in 2011. Revenues in the Eastern Hemisphere also increased as a result of higher dayrates and increased amortization of revenues related to customer-funded reimbursable rig upgrades.

O&M revenues declined $18.5 million, or 28.5%, to $46.4 million for the six-months ended June 30, 2012, compared with $64.9 million for the six-months ended June 30, 2011. The decrease in revenues from our O&M contracts was primarily due to a decrease in reimbursable expenses related to a drilling rig relocation project which commenced during the first quarter of 2011 and was completed prior to December 31, 2011. The decrease in revenues was partially offset by an increase in revenues for an O&M contract related to a shipyard refurbishment project that was on standby or operational rate during the entire first half of 2012 where it had generated minimal revenues in the first half of 2011. O&M projects included approximately $10.5 million and $28.7 million of reimbursable costs for the six-month periods ended June 30, 2012 and 2011, respectively, which added to revenues but had little impact on operating margins.

International Drilling operating gross margin, excluding depreciation and amortization, increased $17.3 million, or 63.3%, to $44.7 million during the six-months ended June 30, 2012, compared with $27.4 million for the six-months ended June 30, 2011. The increase in operating gross margin for the six-months ended June 30, 2012 was primarily due to higher dayrates and increased utilization and the inclusion in the first six months of 2011 of $3.6 million of expense related to a non-cash charge to write-off certain VAT assets in the Eastern Hemisphere region and $1.9 million of expense related to equity tax assessments in Latin America.

Technical Services

Technical Services segment revenues decreased $9.5 million, or 56.2%, to $7.4 million for the six months ended June 30, 2012, compared with $16.9 million for the six months ended June 30, 2011. More than half of the decrease was due to expiration at the end of the second quarter of 2011 of the “pre-operations” phase of the Liberty project and transition of the Berkut platform project (previously described as the “Arkutun Dagi” project) from its engineering phase to a less revenue-intensive construction oversight and assistance phase. The decline in revenues was partially offset by revenues from two FEED projects.

Operating gross margin for this segment was nominal for the six-months ended June 30, 2012, compared with $3.4 million for the six-months ended June 30, 2011. The decrease is primarily the result of decreased operating gross margins on the Berkut platform project and completion or near completion of other pre-FEED engineering efforts that were ongoing during the year. The Technical Services segment does not incur depreciation and amortization.

37

Construction Contract

This segment includes only the Liberty extended-reach drilling rig construction project. Construction Contract segment revenues were zero for the six months ended June 30, 2012 compared with $9.6 million for the six-months ended June 30, 2011. This segment reported zero and $0.8 million operating gross margin for the six months ended June 30, 2012 and 2011, respectively. The operating gross margin generated during the six-months ended June 30, 2011 was due to the preliminary close-out of the Liberty project and recognition of percentage of completion revenues. The Construction Contract segment does not incur depreciation and amortization.

The Liberty rig construction contract was a fixed fee and reimbursable contract accounted for on a percentage of completion basis. As of December 31, 2011, we had recognized $335.5 million in project-to-date revenues. Over the life of the contract, we recognized $11.7 million of margin on the contract.

In November 2010, BP informed us that it was suspending construction on the project to review the rig’s engineering and design, including its safety systems. The Liberty rig construction contract expired on February 8, 2011 prior to completion of the rig. Before expiration of the construction contract, BP identified several areas of concern relating to design, construction and invoicing for which it asked us to provide explanations and documentation, and we did so. Although we provided BP with the requested information, we do not know when or how these issues will be resolved with our client.

After expiration of the construction contract, the Company and BP continued activities to preserve and maintain the rig under the “pre-operations” phase of an O&M contract, which was entered into in August 2009 and expired on July 1, 2011. A new consulting services agreement was reached between the Company and BP effective July 1, 2011. Under the consulting services agreement, we assisted BP in a review of the rig’s design, the creation of a new statement of requirements for the rig, and the transition of documentation and materials to BP. All work under the consulting agreement has been completed and we are engaged with BP on construction contract close-out resolution. In June 2012, BP publicly announced that it had made the decision to suspend the Liberty project indefinitely. We do not know whether or how that decision may impact our discussions with BP related to contract close-out.

Other Financial Data

Gain on asset dispositions for the six months ended June 30, 2012 and 2011 was $1.9 million and $1.4 million, respectively, and was primarily a result of gains on various asset sales during each period. We periodically sell equipment deemed to be excess, obsolete, or not currently required for operations.

Interest expense increased $5.3 million for the six months ended June 30, 2012 compared with the six months ended June 30, 2011, due to an increase in debt-related interest expense of $1.1 million resulting from higher interest on the additional $125 million of 9.125% Notes, which have a higher interest rate than our 2.125% Notes. We incurred interest on both notes issuances during the tender period. Additionally, we incurred a $0.4 million increase in amortization of debt issuance costs attributable to the issuance of an additional $125.0 million of 9.125% Notes in April 2012, and a $3.8 million decrease in capitalized interest on major projects, primarily resulting from a reduction in the value of the AADU rigs following an impairment charge recorded during the fourth quarter of 2011. Interest income was minimal in each quarter.

We incurred a loss on extinguishment of debt of $1.6 million during the six months ended June 30, 2012. This loss resulted from the repurchase of $122.9 million of the 2.125% Notes pursuant to a tender offer on May 9, 2012. The loss included $0.4 million premium paid to repurchase the 2.125% Notes prior to maturity and $1.2 million accelerated amortization of the related debt discount and debt issuance costs.

General and administration expense decreased $1.8 million for the six months ended June 30, 2012 compared with the six months ended June 30, 2011 due primarily to a decrease in legal fees associated with the SEC and DOJ investigations (see further discussion in Note 11 in the Notes to Company financial statements) partially offset by an increase in employee recruitment costs and professional fees.

38

Income tax expense was $24.5 million for the six months ended June 30, 2012, as compared to $18.3 million for the six months ended June 30, 2011. The increase in 2012 period tax expense is driven primarily by an increase in income before income taxes, differences in the mix of our domestic and international pre-tax earnings and losses, as well as the mix of international tax jurisdictions in which we operate.

LIQUIDITY AND CAPITAL RESOURCES

We periodically evaluate our liability requirements, capital needs and availability of resources in view of inventory levels, expansion plans, debt service requirements and other operational cash needs. To meet our short and long term liquidity requirements, including payment of operating expenses and repaying debt, we rely primarily on cash from operations. However, we have recently, as well as in the past sought, and may in the future seek, to raise additional capital. We expect that, for the foreseeable future, cash generated from operations will be sufficient to provide us the ability to fund our operations, provide the working capital necessary to support our strategy and fund planned capital expenditures.

Our Credit Facility matures on May 14, 2013. As a result, the $49.0 million Term Loan borrowed under the facility is classified as a current obligation on our consolidated balance sheet at June 30, 2012. Based on the current amortization schedule, the balance of the Term Loan to be repaid at maturity would be $31.0 million. Although, we believe we could repay the Term Loan at the time of maturity utilizing existing cash and cash generated from operations, it is our intention to enter into a new Credit Facility prior to maturity.

On April 25, 2012, we issued an additional $125.0 million aggregate principal amount of our existing 9.125% Notes at a price of 104.0% of par, resulting in gross proceeds of $130.0 million. Substantially all of the net proceeds from the offering of $124.1 million were utilized to repurchase $122.9 million aggregate principal amount of 2.125% Notes pursuant to a tender offer on May 9, 2012. The tender offer price was $1,003.27 for each $1,000 principal amount of 2.125% Notes, plus accrued and unpaid interest. As a result of the repurchase, we recorded debt extinguishment costs of $1.6 million during the second quarter of 2012. The $2.1 million aggregate principal amount of remaining non-tendered 2.125% Notes were subsequently paid off at their stated maturity, July 15, 2012.

Cash Flows

As of June 30, 2012, we had cash and cash equivalents of $77.5 million, a decrease of $20.4 million from December 31, 2011. The primary uses of cash for the six-month period ended June 30, 2012 as reflected on the consolidated condensed statements of cash flows were $122.9 million for the repurchase of 2.125% Notes, $109.5 million for capital expenditures, a $12.0 million payment on our Term Loan, and $3.5 million of debt issuance costs attributable to the issuance of an additional $125.0 million of 9.125% Notes in April 2012. Major capital expenditures for the first six months of 2012 included $48.5 million on the construction of two new rigs for work in Alaska and $41.6 million for tubular and other rental tools for our Rental Tools segment. The primary source of cash for the second quarter of 2012 was $130 million from the issuance of $125 million additional 9.125% Notes at 104.0% of par and $95.5 million from operating activities.

As of June 30, 2011, we had cash and cash equivalents of $67.5 million, an increase of $16.1 million from December 31, 2010. The primary source of cash for the six-month period ended June 30, 2011 was $95.9 million from operating activities and $16.9 million from financing activities, which included a $50.0 million draw on the accordion feature of our Credit Agreement in the form of a Term Loan, offset by the repayment of the $25.0 million outstanding balance on our Revolver and $9.0 million payments against our Term Loans. The primary use of cash was $99.4 million for capital expenditures. Major capital expenditures for the first six months of 2011 included $55.5 million on the construction of two new rigs for work in Alaska and $29.4 million for tubulars and other rental tools for our Rental Tools segment.

39

Financing Activity

On May 15, 2008, we entered into the Credit Agreement with a five-year senior secured $80.0 million Revolver and a Term Loan of up to $50.0 million. Our obligations under the Credit Agreement are guaranteed by substantially all of our domestic subsidiaries, except for domestic subsidiaries owned by foreign subsidiaries and certain immaterial subsidiaries, each of which has executed a guaranty. The Credit Agreement contains customary affirmative and negative covenants, such as minimum ratios for consolidated leverage, consolidated interest coverage and consolidated senior secured leverage, which we were in compliance at June 30, 2012 and December 31, 2011.

Borrowings under the Credit Agreement are available for general corporate purposes and to fund reimbursement obligations under letters of credit the banks issue on our behalf pursuant to this facility. Loans are available under the Revolver subject to a borrowing base calculation based on a percentage of eligible accounts receivable, certain specified barge drilling rigs and eligible rental equipment of the Company and its subsidiary guarantors.

On April 1, 2011, we exercised the accordion feature under the Credit Agreement and entered into an amendment to the Credit Agreement that increased the aggregate current commitment under the Credit Agreement to $159.0 million, and borrowed an additional $50.0 million under a Term Loan. Funding was provided by certain current lenders and Barclays Bank PLC, which joined as a lender under the Credit Agreement. Use of proceeds included repayment of the $25.0 million outstanding on the Revolver, purchases of additional rental tool inventory and general corporate purposes. The Term Loan requires quarterly principal amortization to $6.0 million with the remaining loan balance payable upon maturity.

As of June 30, 2012, there was $49.0 million outstanding on the Term Loan, and $2.6 million in letters of credit outstanding. There were no amounts outstanding under the Revolver.

On March 22, 2010, we issued $300 million aggregate principal amount of 9.125% Notes and on April 25, 2012 we issued an additional $125 million aggregate principal amount of 9.125% Notes. Interest is payable on the 9.125% Notes on April 1 and October 1.

We had total long-term debt, including current portion, of $481.0 million as of June 30, 2012, which consisted of:

• $2.1 million aggregate principal amount of 2.125% Notes less a nominal amount of unamortized debt discount, all of which is classified as short term;

• $425.0 million aggregate principal amount of 9.125% Notes, plus an associated $4.9 million in unamortized debt premium; and

• $49.0 million drawn against our 2008 credit facility, consisting of no borrowings under our Revolver and $49.0 million under our Term Loan, all of which is classified as current.

As of June 30, 2012, we had approximately $154.9 million of liquidity which consisted of $77.5 million of cash and cash equivalents on hand and $77.4 million of availability under our Revolver.

40

Contractual Obligations

The following table summarizes our future contractual cash obligations as of June 30, 2012:

	Total		Less than 1 Year		Years 1-3		Years 3-5		More than 5 Years
	(Dollars in Thousands)
Contractual cash obligations:
Long-term debt — principal(1)	$	476,148	$	51,148	$	—	$	—	$	425,000
Long-term debt — interest(1)	$	234,284	$	40,377	$	77,563	$	77,563	$	38,781
Operating leases(2)	$	26,564	$	7,125	$	6,947	$	4,369	$	8,123
Purchase commitments(3)	$	11,468	$	11,468	$	—	$	—	$	—
Total contractual obligations	$	748,464	$	110,118	$	84,510	$	81,932	$	471,904
Commercial commitments:
Long-term debt — standby Revolving credit facility	$	—	$	—	$	—	$	—	$	—
Standby letters of credit(4)		2,603		2,603		—		—		—
Total commercial commitments	$	2,603	$	2,603	$	—	$	—	$	—

(1) Long-term debt includes the principal and interest cash obligations of the 9.125% Notes, the 2.125% Notes, and the Term Loan. The remaining unamortized premium of $4.9 million on the 9.125% Notes and the nominal unamortized discount on the 2.125% Notes are not included in the contractual cash obligations schedule.

(2) Operating leases consist of lease agreements in excess of one year for office space, equipment, vehicles and personal property.

(3) Purchase commitments outstanding as of June 30, 2012 are primarily related to rig upgrade projects and new rig construction.

(4) We have an $80.0 million revolving credit facility. As of June 30, 2012, we had no borrowings under the Revolver and $2.6 million of availability has been used to support letters of credit that have been issued, resulting in $77.4 million of availability. The Revolver expires May 14, 2013.

Off-Balance Sheet Arrangements

We do not have any unconsolidated special-purpose entities, off-balance sheet financing arrangements or guarantees of third-party financial obligations. We have no energy or commodity contracts.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

There has been no material change in the market risk faced by us from that reported in our 2011 Annual Report on Form 10-K filed with the SEC on March 6, 2012. For more information on market risk, see Part II, Item 7A in our 2011 Annual Report on Form 10-K.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures — In accordance with the Securities Exchange Act of 1934 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, as defined in the Exchange Act Rules 13a-15 and 15d-15, were effective, as of June 30, 2012, to provide reasonable assurance that information required to be disclosed in

41

our reports filed or submitted under the Exchange Act is (1) accumulated and communicated to our management, including our Chief Executive Officer and our Chief Financial Officer, to allow timely decisions regarding required disclosure and (2) recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms.

Changes in Internal Control Over Financial Reporting— There have been no changes in our internal control over financial reporting during the quarter ended June 30, 2012 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

42

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

For information regarding legal proceedings, see Note 11, “Contingencies,” in Item 1 of Part I of this quarterly report on Form 10-Q, which information is incorporated herein by reference into this item.

ITEM 1A. RISK FACTORS

Other than disclosed below, there have been no material changes from the risk factors disclosed in Item 1A. Risk Factors of our annual report on Form 10-K for the year ended December 31, 2011.

We are not fully insured against all risks associated with our business.

We ordinarily maintain insurance against certain losses and liabilities arising from our operations. However, we do not insure against all operational risks in the course of our business. Due to the significant premium, high self-insured retention and limited coverage, we decided not to purchase windstorm insurance for our inland barges in the Gulf of Mexico. Accordingly, we have retained the risk for loss or damage in the Gulf of Mexico arising out of windstorm damage. The occurrence of an event that is not fully covered by insurance could have a material adverse impact on our business activities, financial position and results of operations.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

The Company currently has no active share repurchase programs. Periodically, the Company purchases shares on the open market to meet our employer matching requirements under our 401 (k) Retirement Savings Plan (formerly known as our Stock Bonus Plan). Additionally, when restricted stock awarded by the Company becomes taxable compensation to personnel, shares may be withheld to satisfy the associated withholding tax liabilities. Information on our purchases of equity securities by means of such share withholdings is provided in the table below:

Issuer Purchases of Equity Securities

Period	Total Number of Shares Purchased		Average Price Paid Per Share
April 1-30, 2012		61,251	$	5.37
May 1-31, 2012		8,134	$	5.17
June 1-30, 2012		4,837	$	4.57
Total		74,222	$	5.29

43

ITEM 6. EXHIBITS

(a) Exhibits: The following exhibits are filed or furnished as a part of this report:

Exhibit Number		DESCRIPTION
10.1	—	Form of supplement to Restricted Stock Unit Incentive Agreement.
31.1	—	Robert L. Parker, Jr., Chairman, President and Chief Executive Officer, Rule 13a-14(a)/15d-14(a) Certification.
31.2	—	W. Kirk Brassfield, Senior Vice President and Chief Financial Officer, Rule 13a-14(a)/15d- 14(a) Certification.
32.1	—	Robert L. Parker, Jr., Chairman, President and Chief Executive Officer, Section 1350 Certification.
32.2	—	W. Kirk Brassfield, Senior Vice President and Chief Financial Officer, Section 1350 Certification.

44

SIGNATURES

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

	PARKER DRILLING COMPANY
Date: August 3, 2012	By:	/s/ Robert L. Parker, Jr.
		Robert L. Parker, Jr. Chairman, President, and Chief Executive Officer
	By:	/s/ W. Kirk Brassfield
		W. Kirk Brassfield Senior Vice President and Chief Financial Officer

45

INDEX TO EXHIBITS

Exhibit Number		DESCRIPTION
10.1	—	Form of supplement to Restricted Stock Unit Incentive Agreement.
31.1	—	Robert L. Parker, Jr., Chairman, President and Chief Executive Officer, Rule 13a-14(a)/15d-14(a) Certification.
31.2	—	W. Kirk Brassfield, Senior Vice President and Chief Financial Officer, Rule 13a-14(a)/15d- 14(a) Certification.
32.1	—	Robert L. Parker, Jr., Chairman, President and Chief Executive Officer, Section 1350 Certification.
32.2	—	W. Kirk Brassfield, Senior Vice President and Chief Financial Officer, Section 1350 Certification.

46