Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2011

Summary of Significant Accounting Policies [Abstract]

Principles of Consolidation

Principles of Consolidation

Our consolidated financial statements include the accounts of Nabors, as well as all majority owned and non-majority owned subsidiaries required to be consolidated under GAAP. Our consolidated financial statements exclude majority owned entities for which we do not have either (1) the ability to control the operating and financial decisions and policies of that entity or (2) a controlling financial interest in a variable interest entity. All significant intercompany accounts and transactions are eliminated in consolidation.

Investments in operating entities where we have the ability to exert significant influence, but where we do not control operating and financial policies, are accounted for using the equity method. Our share of the net income (loss) of these entities is recorded as earnings (losses) from unconsolidated affiliates in our consolidated statements of income (loss), and our investment in these entities is included as a single amount in our consolidated balance sheets. Investments in unconsolidated affiliates accounted for using the equity method totaled $371.0 million and $265.8 million as of December 31, 2011 and 2010, respectively. Investments in unconsolidated affiliates accounted for using the cost method totaled $1.9 million as of December 31, 2010. At December 31, 2011 and 2010, assets held for sale included investments in unconsolidated affiliates accounted for using the equity method totaling $13.7 million and $79.5 million, respectively. See Note 4 — Discontinued Operations for additional information.

We have investments in offshore funds, which are classified as long-term investments and are accounted for using the equity method of accounting based on our ownership interest in each fund. The carrying value of these investments totaled $5.9 million and $7.4 million as of December 31, 2011 and 2010, respectively.

Cash and Cash Equivalents

Cash and Cash Equivalents

Cash and cash equivalents include demand deposits and various other short-term investments with original maturities of three months or less.

Investments

Investments

Short-term investments

Short-term investments consist of equity securities, certificates of deposit, corporate debt securities, mortgage-backed debt securities and asset-backed debt securities. Securities classified as available-for-sale or trading are stated at fair value. Unrealized holding gains and temporary losses for available-for-sale securities are excluded from earnings and, until realized, are reported net of taxes in a separate component of equity. Unrealized holding losses are included in earnings during the period for which the loss is determined to be other-than-temporary. Gains and losses from changes in the market value of securities classified as trading are reported in earnings currently.

In computing realized gains and losses on the sale of equity securities, the specific-identification method is used. In accordance with this method, the cost of the equity securities sold is determined using the specific cost of the security when originally purchased.

Long-term investments and other receivables

We have investments in overseas funds that invest primarily in a variety of public and private U.S. and non-U.S. securities (including asset-backed and mortgage-backed securities, global structured-asset securitizations, whole-loan mortgages, and participations in whole loans and whole-loan mortgages). These investments are non-marketable and do not have published fair values. We account for these funds under the equity method of accounting based on our percentage ownership interest and recognize gains or losses as investment income (loss), currently based on changes in the net asset value of our investment during the current period.

Our oil and gas financing receivables, previously included in long-term investments, have been reclassified to assets held for sale. These receivables represent our financing agreements for certain production payment contracts in our Oil and Gas segment.

Inventory

Inventory

Inventory is stated at the lower of cost or market. Cost is determined using the first-in, first-out method and includes the cost of materials, labor and manufacturing overhead. Inventory included the following:

	December 31, 2011		December 31, 2010
	(In thousands)
Raw materials	$	133,480	$	81,308
Work-in-progress		50,951		23,629
Finished goods		88,421		53,899
	$	272,852	$	158,836

Property, Plant and Equipment

Property, Plant and Equipment

Property, plant and equipment, including renewals and betterments, are stated at cost, while maintenance and repairs are expensed currently. Interest costs applicable to the construction of qualifying assets are capitalized as a component of the cost of such assets. We provide for the depreciation of our drilling and workover rigs using the units-of-production method. For each day a rig is operating, we depreciate it over an approximate 4,900-day period, with the exception of our jackup rigs which are depreciated over an 8,030-day period, after provision for salvage value. For each day a rig asset is not operating, it is depreciated over an assumed depreciable life of 20 years, with the exception of our jackup rigs, where a 30-year depreciable life is used, after provision for salvage value.

Depreciation on our buildings, well-servicing rigs, oilfield hauling and mobile equipment, marine transportation and supply vessels, and other machinery and equipment is computed using the straight-line method over the estimated useful life of the asset after provision for salvage value (buildings — 10 to 30 years; well-servicing rigs — 3 to 15 years; marine transportation and supply vessels — 10 to 25 years; oilfield hauling and mobile equipment and other machinery and equipment — 3 to 10 years). Amortization of capitalized leases is included in depreciation and amortization expense. Upon retirement or other disposal of fixed assets, the cost and related accumulated depreciation are removed from the respective accounts and any gains or losses are included in our results of operations.

We review our assets for impairment annually or when events or changes in circumstances indicate that the carrying amounts of property, plant and equipment may not be recoverable. An impairment loss is recorded in the period in which it is determined that the sum of estimated future cash flows, on an undiscounted basis, is less than the carrying amount of the long-lived asset. Impairment charges are recorded using discounted cash flows which requires the estimation of dayrates and utilization, and such estimates can change based on market conditions, technological advances in the industry or changes in regulations governing the industry. Significant and unanticipated changes to the assumptions could result in future impairments. A significantly prolonged period of lower oil and natural gas prices could adversely affect the demand for and prices of our services, which could result in future impairment charges. As the determination of whether impairment charges should be recorded on our long-lived assets is subject to significant management judgment, and an impairment of these assets could result in a material charge on our consolidated statements of income (loss), management believes that accounting estimates related to impairment of long-lived assets are critical.

Oil and Gas Properties

Oil and Gas Properties

Our unconsolidated oil and gas joint ventures, which we account for under the equity method of accounting, utilize the full-cost method of accounting for costs related to oil and natural gas properties. Under this method, all such costs (for both productive and nonproductive properties) are capitalized and amortized on an aggregate basis over the estimated lives of the properties using the units-of-production method. However, these capitalized costs are subject to a ceiling test, which limits pooled costs to the aggregate of the present value of future net revenues attributable to proved oil and natural gas reserves, discounted at 10%, plus the lower of cost or market value of unproved properties. Future revenues for purposes of the ceiling test are valued using a 12-month average price, adjusted for the impact of derivatives accounted for as cash flow hedges as prescribed by the Securities and Exchange Commission (“SEC”) rules. During 2011 and 2009, our proportionate share of those ventures’ full-cost ceiling test writedowns was $15.6 million and $237.1 million, respectively. No full-cost ceiling test writedowns were recorded by our unconsolidated oil and gas joint ventures during 2010.

Our wholly owned oil and gas investment portfolio and our unconsolidated ownership interest in Remora is reflected in Assets held for sale in our consolidated balance sheet at December 31, 2011. We evaluate the carrying value of our assets held for sale to the fair value of the assets less costs to sale to determine whether impairment is indicated.

A significantly prolonged period of lower oil and natural gas prices or a reduction to the estimation of reserve quantities could continue to adversely affect the demand for and prices of our services, which could result in future impairment charges to our oil and gas properties.

Oil and Gas Reserves

Oil and Gas Reserves

Evaluations of oil and gas reserves are integral to making investment decisions about oil and gas properties such as whether development should proceed. Oil and gas reserve quantities are also used as the basis for calculating unit-of-production depreciation rates and for evaluating impairment. Oil and gas reserves include both proved and unproved reserves. Consistent with the definitions provided by the SEC, proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, known reservoirs, and under existing economic conditions. Unproved reserves are those with less than reasonable certainty of recoverability and include probable reserves. Probable reserves are reserves that are more likely to be recovered than not.

Estimation of proved reserves, which is based on the requirement of reasonable certainty, is an ongoing process involving rigorous technical evaluations, commercial and market assessment, and detailed analysis of well information such as flow rates and reservoir pressure declines. Although we are reasonably certain that proved reserves will be produced, the timing and amount recovered can be affected by a number of factors including completion of development projects, reservoir performance, regulatory approvals and significant changes in long-term oil and gas price levels.

Goodwill

Goodwill

Goodwill represents the cost in excess of fair value of the net assets of companies acquired. We review goodwill and intangible assets with indefinite lives for impairment annually or more frequently if events or changes in circumstances indicate that the carrying amount of the reporting unit exceeds its fair value. All our operating segment’s fair values were substantially in excess of their carrying value with the exception of the U.S. Land Well-servicing and International segments. These operating segments had an excess of fair value over carrying value of approximately 20%. As further discussed below in Recent Accounting Pronouncements, we changed the manner in which we initially assess goodwill for impairment during 2012. Under new guidance, we will assess qualitative factors to determine whether to perform the two-step quantitative goodwill impairment tests. A significantly prolonged period of lower oil and natural gas prices could adversely affect the demand for and prices of our services, which could result in future goodwill impairment charges for other reporting units due to the potential impact on our estimate of our future operating results. See Note 3 — Impairments and Other Charges for discussion of goodwill impairments.

The change in the carrying amount of goodwill for our various Contract Drilling segments, Pressure Pumping segment and Other Operating segments for the years ended December 31, 2011 and 2010 was as follows:

	Balance as of December 31, 2009		Acquisitions and Purchase Price Adjustments			Impairments			Cumulative Translation Adjustment		Balance as of December 31, 2010
	(In thousands)
Contract Drilling:
U.S. Lower 48 Land Drilling	$	30,154	$	—		$	—		$	—	$	30,154
U.S. Land Well-servicing		50,839		5,000	(1)		—			—		55,839
U.S. Offshore		18,003		—			(10,707	)(2)		—		7,296
Alaska		19,995		—			—			—		19,995
International		18,983		—			—			—		18,983
Subtotal Contract Drilling		137,974		5,000			(10,707	)		—		132,267
Pressure Pumping		—		334,992	(3)		—			—		334,992
Other Operating Segments		26,291		—			—			822		27,113
Total	$	164,265	$	339,992		$	(10,707	)	$	822	$	494,372

	Balance as of December 31, 2010		Acquisitions and Purchase Price Adjustments			Impairments		Cumulative Translation Adjustment			Balance as of December 31, 2011
	(In thousands)
Contract Drilling:
U.S. Lower 48 Land Drilling	$	30,154	$	—		$	—	$	—		$	30,154
U.S. Land Well-servicing		55,839		(767	)(1)		—		—			55,072
U.S. Offshore		7,296		—			—		—			7,296
Alaska		19,995		—			—		—			19,995
International		18,983		—			—		—			18,983
Subtotal Contract Drilling		132,267		(767	)		—		—			131,500
Pressure Pumping		334,992		—			—		—			334,992
Other Operating Segments		27,113		8,000	(4)		—		(347	)		34,766
Total	$	494,372	$	7,233		$	—	$	(347	)	$	501,258

(1) Represents the goodwill recorded in connection with our acquisition of Energy Contractors during 2010 and an adjustment to the goodwill recorded during 2011. See Note 5 — Acquisitions for additional discussion.

(2) Represents goodwill impairment associated with our U.S. Offshore operating segment. The impairment charge was deemed necessary due to the uncertainty of utilization of some of our rigs as a result of changes in our customers’ plans for future drilling operations in the Gulf of Mexico. See Note 3 — Impairments and Other Charges for additional information.

(3) Represents the goodwill recorded in connection with our acquisition of Superior. See Note 5 — Acquisitions for additional discussion.

(4) Represents goodwill recorded in connection with our acquisition of the remaining 50 percent equity interest of Peak. See Note 5 — Acquisitions for additional discussion.

Our Oil and Gas segment does not have any goodwill. Goodwill for the consolidated company, totaling approximately $12.9 million, is expected to be deductible for tax purposes.

Derivative Financial Instruments

Derivative Financial Instruments

We record derivative financial instruments (including certain derivative instruments embedded in other contracts) in our consolidated balance sheets at fair value as either assets or liabilities. The accounting for changes in the fair value of a derivative instrument depends on the intended use of the derivative and the resulting designation, which is established at the inception of a derivative. Accounting for derivatives qualifying as fair value hedges allows a derivative’s gains and losses to offset related results on the hedged item in the statement of income. For derivative instruments designated as cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. Hedge effectiveness is measured quarterly based on the relative cumulative changes in fair value between the derivative contract and the hedged item over time. Any change in fair value resulting from ineffectiveness is recognized immediately in earnings. Any change in fair value of derivative financial instruments that are speculative in nature and do not qualify for hedge accounting treatment is also recognized immediately in earnings. Proceeds received upon termination of derivative financial instruments qualifying as fair value hedges are deferred and amortized into income over the remaining life of the hedged item using the effective interest rate method.

Litigation and insurance reserves

Litigation and Insurance Reserves

We estimate our reserves related to litigation and insurance based on the facts and circumstances specific to the litigation and insurance claims and our past experience with similar claims. We maintain actuarially determined accruals in our consolidated balance sheets to cover self-insurance retentions. See Note 18 — Commitments and Contingencies regarding self-insurance accruals. We estimate the range of our liability related to pending litigation when we believe the amount and range of loss can reasonably be estimated. We record our best estimate of a loss when the loss is considered probable. When a liability is probable and there is a range of estimated loss with no best estimate in the range, we record the minimum estimated liability related to the lawsuits or claims. As additional information becomes available, we assess the potential liability related to our pending litigation and claims and revise our estimates. Due to uncertainties related to the resolution of lawsuits and claims, the ultimate outcome may differ from our estimates. For matters where an unfavorable outcome is reasonably possible and significant, we disclose the nature of the matter and a range of potential exposure, unless an estimate cannot be made at the time of disclosure.

Revenue Recognition

Revenue Recognition

We recognize revenues and costs on daywork contracts daily as the work progresses. For certain contracts, we receive lump-sum payments for the mobilization of rigs and other drilling equipment. We defer revenue related to mobilization periods and recognize the revenue over the term of the related drilling contract. Costs incurred related to a mobilization period for which a contract is secured are deferred and recognized over the term of the related drilling contract. Costs incurred to relocate rigs and other drilling equipment to areas in which a contract has not been secured are expensed as incurred. We defer recognition of revenue on amounts received from customers for prepayment of services until those services are provided.

We recognize revenue for top drives and instrumentation systems we manufacture when the earnings process is complete. This generally occurs when products have been shipped, title and risk of loss have been transferred, collectability is probable, and pricing is fixed and determinable.

In connection with the performance of our cementing services, we recognize product and service revenue when the products are delivered or services are provided to the customer and collectability is reasonably assured. Product sale prices are determined by published price lists provided to our customers.

We recognize, as operating revenue, proceeds from business interruption insurance claims in the period that the applicable proof of loss documentation is received. Proceeds from casualty insurance settlements in excess of the carrying value of damaged assets are recognized in losses (gains) on sales and retirements of long-lived assets and other expense (income), net in the period that the applicable proof of loss documentation is received. Proceeds from casualty insurance settlements that are expected to be less than the carrying value of damaged assets are recognized at the time the loss is incurred and recorded in losses (gains) on sales and retirements of long-lived assets and other expense (income), net.

We recognize reimbursements received for out-of-pocket expenses incurred as revenues and account for out-of-pocket expenses as direct costs.

We recognize revenue on our interests in oil and gas properties as production occurs and title passes. We apply the entitlement method of accounting for natural gas revenue. Under this method, revenues are recognized based on our revenue interest of production from our properties in which sales are disproportionately allocated to owners because of marketing or other contractual arrangements. Accordingly, revenue is not recognized for deliveries in excess of our net revenue interest, while revenue is recognized for any under delivered volumes. Production imbalances are generally recorded at estimated sales prices of the anticipated future settlements of the imbalances. Production volume is monitored to minimize these natural gas imbalances.

Share-Based Compensation

Share-Based Compensation

We record compensation expense for all share-based awards granted. The amount of compensation expense recognized is based on the grant-date fair value. See Note 8 — Share-Based Compensation for additional discussion.

Income Taxes

Income Taxes

We are a Bermuda exempted company and are not subject to income taxes in Bermuda. Consequently, income taxes have been provided based on the tax laws and rates in effect in the countries in which our operations are conducted and income is earned. The income taxes in these jurisdictions vary substantially. Our effective tax rate for financial statement purposes will continue to fluctuate from year to year because our operations are conducted in different taxing jurisdictions.

We recognize increases to our tax reserves for uncertain tax positions along with interest and penalties as an increase to other long-term liabilities.

For U.S. and other jurisdictional income tax purposes, we have net operating and other loss carryforwards that we are required to assess quarterly for potential valuation allowances. We consider the sufficiency of existing temporary differences and expected future earnings levels in determining the amount, if any, of valuation allowance required against such carryforwards and against deferred tax assets.

Nabors realizes an income tax benefit associated with certain awards issued under our stock plans. We recognize the benefits related to tax deductions up to the amount of the compensation expense recorded for the award in the consolidated statements of income (loss). Any excess tax benefit (i.e., tax deduction in excess of compensation expense) is reflected as an increase in capital in excess of par. Any shortfall is recorded as a reduction to capital in excess of par to the extent of our aggregate accumulated pool of windfall benefits, beyond which the shortfall would be recognized in the consolidated statements of income (loss).

Foreign Currency Translation

Foreign Currency Translation

For certain of our foreign subsidiaries, such as those in Canada and Argentina, the local currency is the functional currency, and therefore translation gains or losses associated with foreign-denominated monetary accounts are accumulated in a separate section of the consolidated statements of changes in equity. For our other international subsidiaries, the U.S. dollar is the functional currency, and therefore local currency transaction gains and losses, arising from remeasurement of payables and receivables denominated in local currency, are included in our consolidated statements of income (loss).

Cash flows

Cash Flows

We treat the redemption price, including accrued original issue discount, on our convertible debt instruments as a financing activity for purposes of reporting cash flows in our consolidated statements of cash flows.

Use of estimates

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make certain estimates and assumptions. These estimates and assumptions affect the reported amounts of assets and liabilities, the disclosures of contingent assets and liabilities at the balance sheet date and the amounts of revenues and expenses recognized during the reporting period. Actual results could differ from such estimates. Areas where critical accounting estimates are made by management include:

• financial instruments;

• depreciation of property, plant and equipment;

• impairment of long-lived assets;

• impairment of goodwill and intangible assets;

• impairment of oil and gas properties;

• valuation of oil and gas reserves;

• income taxes;

• litigation and self-insurance reserves;

• fair value of assets acquired and liabilities assumed; and

• share-based compensation.

Recent Accounting Pronouncements

Recent Accounting Pronouncements

In December 2008, the SEC issued a Final Rule, “Modernization of Oil and Gas Reporting.” This rule revised some of the oil and gas reporting disclosures in Regulation S-K and Regulation S-X under the Securities Act and the Exchange Act, as well as Industry Guide 2. Effective December 31, 2009, the Financial Accounting Standards Board (“FASB”) issued revised guidance that substantially aligned the oil and gas accounting disclosures with the SEC’s Final Rule. The standard requires that entities use 12-month average natural gas and oil prices when calculating the quantities of proved reserves and performing the full-cost ceiling test calculation. The standard also clarified that an entity’s equity-method investments must be considered in determining whether it has significant oil and gas activities. The disclosure requirements were effective for registration statements filed on or after January 1, 2010 and for annual financial statements filed on or after December 31, 2009. The FASB provided a one-year deferral of the disclosure requirements if an entity became subject to the requirements because of a change to the definition of significant oil and gas activities. When operating results from our wholly owned oil and gas activities were considered with operating results from our unconsolidated oil and gas joint ventures, which we account for under the equity method of accounting, we had significant oil and gas activities under the new definition. Our oil and gas disclosures for the years ended December 31, 2011 and 2010 are provided in Note 24 — Supplementary Information on Oil and Gas Exploration and Production Activities.

Effective January 1, 2010, we adopted the revised provisions relating to consolidation of variable interest entities within the Consolidations Topic of the FASB’s Accounting Standards Codification (“ASC”). The revised provisions replaced the quantitative approach to identify a variable interest entity with a qualitative approach that focuses on an entity’s control and ability to direct the variable interest entity’s activities. The application of these provisions did not have a material impact on our consolidated financial statements.

The FASB issued new guidance relating to revenue recognition for contractual arrangements with multiple revenue-generating activities. The ASC Topic for revenue recognition includes identification of a unit of accounting and how arrangement consideration should be allocated to separate the units of accounting, when applicable. The new guidance, including expanded disclosures, became applicable to us for contracts entered into after June 15, 2010. The adoption of these rules did not have a significant impact on our consolidated financial statements.

In May 2011, the FASB issued an Accounting Standards Update (“ASU”) to clarify the application of some of the existing fair value measurement and disclosure requirements. These changes are effective for interim and annual periods that begin after December 15, 2011. The disclosure requirements did not have a significant impact on our consolidated financial statements.

In June 2011, the FASB issued an ASU relating to the presentation of other comprehensive income (“OCI”). This ASU does not change the items that are reported in OCI, but does remove the option to present the components of OCI within the statement of changes in equity. In addition, this ASU will require OCI presentation on the face of the financial statements. These changes are effective for interim and annual periods that begin after December 15, 2011, and are applied retrospectively to all periods presented. Early adoption is permitted. We adopted the ASU beginning January 1, 2012 and it did not have an impact on our consolidated financial statements.

In September 2011, the FASB issued a revised ASU relating to goodwill impairment tests. An entity is allowed to first assess qualitative factors to determine whether it is necessary to perform the two-step quantitative goodwill impairment test. An entity is not required to calculate the fair value of a reporting unit unless the entity determines, based on its qualitative assessment, that it is more likely than not that the fair value is less than its carrying amount. The amendment is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011 and early adoption is permitted. We adopted the ASU beginning January 1, 2012 and will apply it to our goodwill impairment tests.