Note 1 — Summary of Significant Accounting Policies

Nature of Operations — Parker Drilling, together with its subsidiaries (the Company), is a worldwide provider of contract drilling and drilling-related services. Our rental tools subsidiary specializes in oil and gas drilling rental tools providing high-quality, reliable equipment, such as drill pipe, heavy-weight drill pipe, tubing, high-torque connections, BOPs and drill collars used for drilling, workover and production applications.

Our U.S. barge drilling business operates barge rigs in the shallow waters in and along the inland waterways of Louisiana and Texas. Our barge rigs drill for natural gas, oil, and a combination of oil and natural gas. Our international drilling business provides 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. Additionally, our international drilling business includes operations and maintenance and other 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 December 31, 2011, our marketable rig fleet consisted of 15 barge drilling rigs and 25 land rigs located in the United States, Latin America and the Eastern Hemisphere regions. Our Technical services business includes engineering and related project services during the concept development, pre-FEED, and FEED (Front End Engineering Design) phases of our customer owned drilling facility projects. As these projects mature, we continue providing the same services during the Engineering, Procurement, Construction and Installation (EPCI) phase.

Segment Reporting — As of December 31, 2011, the Company has re-aligned its reporting segments to be consistent with recent changes to improve our drilling organization. The Company is aligned in six distinct operating segments:

We have expanded our segments by one, adding a U.S. Drilling segment, represented primarily by our two AADU rigs in Alaska. Our U.S. Barge Drilling segment, previously referred to as the U.S. Drilling segment, represents our GOM barge business and remains unchanged. We have aligned our international operations more closely with the management structure we now have in place. Our previous three geographic regions (Americas, CIS/AME, and Asia Pacific) are now two – Latin America and Eastern Hemisphere. Each region includes all drilling-related operations, whether done using a Parker-owned rig or a customer-owned rig on an O&M contract. Our technical services activities, which primarily include our engagement in engineering support initiatives, pre-FEED, FEED and EPC/EPCI projects that have the potential to evolve into future O&M opportunities, is now reported as an individual segment. Our Rental Tools segment remains unchanged. We have reclassified revenues, expenses and related overhead amounts between the segments as of December 31, 2011 to reflect this alignment. Amounts presented throughout this document for the years ended December 31, 2010 and 2009 have been revised to conform to current period presentation.

Consolidation — The consolidated financial statements include the accounts of the Company and subsidiaries in which we exercise control or 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.

Noncontrolling Interest — We apply the accounting standards related to noncontrolling interests for ownership interests in our subsidiaries held by parties other than Parker Drilling. The entities that comprise the noncontrolling interest include Parker SMNG Drilling Limited Liability Company and Primorsky Drill Rig Services B.V. We report noncontrolling interest as equity on the consolidated balance sheets and report net income (loss) attributable to controlling interest and to noncontrolling interest separately on the consolidated statements of operations.

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 statements of operations, consolidated balance sheets or statements of cash flows.

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 — The Company recognizes reimbursements received for out-of-pocket expenses incurred as revenues and accounts for out-of-pocket expenses as direct operating costs. Such amounts totaled $64.2 million, $40.1 million, and $43.9 million during the years ended December 31, 2011, 2010, and 2009, respectively.

Use of Estimates — The preparation of financial statements in accordance with 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 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, and other items requiring the use of estimates. Estimates are based on a number of variables which may include third party valuations, historical experience, where applicable, 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.

During the third quarter of 2010, we corrected an accounting error relating to value added taxes (VAT) in our Western Kazakhstan branch (PDKBV). In Kazakhstan, companies are permitted to elect the use of either the proportional or separate method for filing periodic VAT returns. PDKBV utilized the proportional method which can limit future recoverability of VAT derived from vendor purchases and rig importation against VAT derived from customer invoicing activities. On the erroneous belief that certain VAT amounts would be recoverable in future periods, PDKBV recorded VAT assets in connection with several transactions occurring during the period 2007 through 2008. However, due to a customer having VAT exempt status, the recoverability of a portion of the VAT assets created was limited, and certain amounts should have been expensed during the periods in which the original transactions occurred. The cumulative effect of the error and related foreign currency translation impact overstated net income and retained earnings by $6.4 million over the period 2007 through 2009. The impact of the error was determined not to be material to our results of operations and financial position for any previously reported periods. Consequently, during the third quarter of 2010, the cumulative effect of this correction was recorded in operating expenses and is reflected in year to date operating expenses for the year ended December 31, 2010.

Cash and Cash Equivalents — For purposes of the consolidated balance sheets and the consolidated statements of cash flows, the Company considers cash equivalents to be highly liquid debt instruments that have a remaining maturity of three months or less at the date of purchase.

Accounts Receivable and Allowance for Doubtful Accounts — Trade accounts receivable are recorded at the invoice amount and generally do not bear interest. The allowance for doubtful accounts is our best estimate for losses that may occur resulting from disputed amounts and the inability of our customers to pay amounts owed. We estimate the allowance based on historical write-off experience and information about specific customers. We review individually, for collectability, all balances over 90 days past due as well as balances due from any customer with respect to which we have information leading us to believe that a risk exits for potential collection.

Account balances are charged off against the allowance when we believe it is probable the receivable will not be recovered. We do not have any off-balance-sheet credit exposure related to customers.

Property, Plant and Equipment — We account for depreciation of property, plant and equipment on the straight line method over the estimated useful lives of the assets after provision for salvage value. Depreciation, for tax purposes, utilizes several methods of accelerated depreciation. Depreciable lives for different categories of property, plant and equipment are as follows:

When assets are retired or otherwise disposed of, the related cost and accumulated depreciation are removed from the accounts and any resulting gain or loss is included within the statement of operations. In the first quarter of 2009, we implemented a change in accounting estimate to more accurately reflect the useful life of certain of the long-lived assets in our U.S. barge drilling and international drilling segments. This resulted in an approximate $16.0 million reduction in the depreciation expense in the year ended December 31, 2009, or $0.14 per share. We extended the useful lives of these long-lived assets based on our review of their service lives, technological improvements in the assets and recent changes to our refurbishment and maintenance practices which helped to extend the lives. Maintenance and repairs are charged to operating expense as incurred.

Annual Impairment Review — We review the carrying amounts of long-lived assets for potential impairment annually, typically during the fourth quarter, or when events occur or circumstances change that indicate the carrying value of such assets may not be recoverable. We determine recoverability by evaluating the undiscounted estimated future net cash flows. When impairment is indicated, we measure the impairment as the amount by which the assets’ carrying value exceeds its fair value. Management considers a number of factors such as estimated future cash flows from the assets, appraisals and current market value analysis in determining fair value. Assets are written down to fair value if the concluded current fair value is below the net carrying value.

During the fourth quarter of 2011, we evaluated the present value of our future cash flows related to our Arctic Alaska Drilling Units (AADU) as a result of their extended construction and commissioning schedule and the related increase in costs. The current estimated cost of the two rigs combined is approximately $385.0 million, which includes estimated total capitalized interest of approximately $50.7 million. Based on this evaluation, the Company determined the rigs were impaired because their carrying value of $339.5 million exceeded their fair value of $169.5 million. As a result, we recorded a pretax, non-cash charge of $170.0 million, with an after-tax impact on net income of $109.1 million. Fair value was based on expected future cash flows using Level 3 inputs under the fair value measurement requirements of U.S. GAAP. The cash flows are those expected to be generated by the market participants, discounted at the 10 percent rate of interest.

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 asset and is amortized over the useful lives of the assets in the same manner as the underlying assets. Capitalized interest costs reduce net interest expense in the consolidated statements of operations. During 2011, 2010 and 2009, we capitalized interest costs related to the construction of rigs of $19.3 million, $13.5 million and $6.0 million, respectively.

Assets held for sale — We classify an asset as held for sale when the facts and circumstances meet the criteria for such classification, including the following: (a) we have committed to a plan to sell the asset, (b) the asset is available for immediate sale, (c) we have initiated actions to complete the sale, including locating a buyer, (d) the sale is expected to be completed within one year, (e) the asset is being actively marketed at a price that is reasonable relative to its fair value, and (f) the plan to sell is unlikely to be subject to significant changes or termination. At December 31, 2011, we have net assets held for sale, included in current assets, in the amount of $5.3 million. For further information, see Note 4.

Goodwill — Goodwill, when recorded upon the result of a qualifying event, is assessed for impairment on at least an annual basis. As of December 31, 2011 there was no existing goodwill.

Rig Materials and Supplies — Because our international drilling generally occurs in remote locations, making timely outside delivery of spare parts uncertain, a complement of parts and supplies is maintained either at the drilling site or in warehouses close to the operation. During periods of high rig utilization, these parts are generally consumed and replenished within a one-year period. During a period of lower rig utilization in a particular location, the parts, like the related idle rigs, are generally not transferred to other international locations until new contracts are obtained because of the significant transportation costs, that would result from such transfers. We classify those parts which are not expected to be utilized in the following year as long-term assets. Rig materials and supplies are valued at the lower of cost or market value.

Deferred Costs — We defer costs related to rig mobilization and amortize such costs over the term of the related contract. The costs to be amortized within twelve months are classified as current.

Debt Issuance Costs — We typically defer costs associated with debt financings and refinancing, and amortize those costs over the term of the related debt.

Income Taxes — Income taxes have been provided based upon tax laws and rates in effect in the countries in which operations are conducted and income is earned. There is little or no expected relationship between the provision for or benefit from income taxes and income or loss before income taxes because the countries in which we operate have taxation regimes that vary not only with respect to nominal rate, but also in terms of the availability of deductions, credits and other benefits. Deferred tax liabilities and assets are determined based on the difference between the financial statement treatment and tax basis treatment of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse. Valuation allowances are recognized against deferred tax assets unless it is “more likely than not” that the Company can realize the benefit of the net operating loss (NOL) and foreign tax credit (FTC) carryforwards and deferred tax assets in future periods.

Earnings (Loss) Per Share (EPS) — Basic earnings (loss) per share is computed by dividing net income by the weighted average number of common shares outstanding during the period. The effects of dilutive securities, stock options, unvested restricted stock and convertible debt are included in the diluted EPS calculation, when applicable.

Concentrations of Credit Risk — Financial instruments, that potentially subject the Company to concentrations of credit risk consist primarily of trade receivables with a variety of national and international oil and gas companies. We generally do not require collateral on our trade receivables.

At December 31, 2011 and 2010, we had deposits in domestic banks in excess of federally insured limits of approximately $10.2 million and $25.9 million respectively. In addition, we had deposits in foreign banks, which were not insured at December 31, 2011 and 2010 of $38.4 million and $31.1 million, respectively.

Our customer base consists of major, independent and national oil and gas companies and integrated service providers. We depend on a limited number of significant customers. Our largest customer, Exxon Neftegas Limited (ENL), constituted $109.2 million or 15.9 percent of our year-to-date revenues as of December 31, 2011. Included in the total revenue for ENL is $48.0 million of reimbursable costs which increase revenues but have little direct impact on operating margins.

Construction Contract — For the periods reported, our construction contract business included only the Liberty drilling rig construction project for BP. In November 2010, our customer, 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 and 2010 we had recognized $335.5 million and $325.9 million in project-to-date revenues, respectively. We have recognized the entire $11.7 million fixed fee 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 have done 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 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, the Company 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 discussions.

Fair value measurements — 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. Our valuation technique requires inputs that we categorize using a three-level hierarchy, from highest to lowest level of observable inputs, as follows: (1) unadjusted quoted prices for identical assets or liabilities in active markets (Level 1), (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 2) and (3) unobservable inputs that require significant judgment for which there is little or no market data (Level 3). 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.

Derivative Financial Instruments — We use derivative instruments to manage risks associated with interest rate fluctuations in connection with our Credit Agreement (see Note 7). These derivative instruments, which consist of variable-to-fixed interest rate swaps, are not designated as hedges. Accordingly, the change in the fair value of the interest rate swaps is recognized in earnings at each reporting period.

Stock-Based Compensation — Under our long term incentive plans, we grant restricted stock awards (RSA), restricted stock units (RSU) and performance units (PU). For service-based awards and performance-based awards with graded vesting conditions, we recognize compensation expense on a straight-line basis over the service period for each separately vesting portion of the award as if the award was, in substance, multiple awards. For market-based awards that vest at the end of the service period, we recognize compensation expense on a straight-line basis through the end of the service period. Share-based awards generally vest over three years. Share-based compensation expense is recognized, net of an estimated forfeiture rate, which is based on historical experience and adjusted, if necessary, in subsequent periods based on actual forfeitures. The fair value of nonvested RSA’s and RSU’s is determined based on the closing trading price of the company’s shares on the grant date. Our RSA’s and RSU’s are settled in stock upon vesting. Our PU awards can be settled in cash or stock at the discretion of the compensation committee of the board of directors and are, therefore, accounted for as liability awards under the stock compensation rules of U.S. GAAP.

We utilize the Black-Scholes option-pricing model to estimate the fair value of our stock options. Expected volatility is determined by using historical volatilities based on historical stock prices for a period that matches the expected term. The expected term of options represents the period of time that options granted are expected to be outstanding and typically falls between the options’ vesting and contractual expiration dates. The expected term assumption is developed by using historical exercise data adjusted as appropriate for future expectations. The risk-free rate is based on the yield at the date of grant of a zero-coupon U.S. Treasury bond whose maturity period equals the option’s expected term. The fair value of each option is estimated on the date of grant. There were no option grants during any of the three-years ended December 31, 2011 and as of December 31, 2011 all previously existing options has been exercised or forfeited.

We recognize share-based compensation expense in the same financial statement line item as cash compensation paid to the respective employees. Tax deduction benefits for awards in excess of recognized compensation costs are reported as a financing cash flow.