EXHIBIT 99.2

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Management Overview

     The following Management’s Discussion and Analysis of Financial Condition and Results of Operations is intended to help the reader understand the results of our operations and our financial condition. This information is provided as a supplement to, and should be read in conjunction with, our consolidated financial statements and the accompanying notes thereto.

     Nabors is the largest land drilling contractor in the world, with approximately 542 actively marketed land drilling rigs. We conduct oil, gas and geothermal land drilling operations in the U.S. Lower 48 states, Alaska, Canada, South America, Mexico, the Caribbean, the Middle East, the Far East, Russia and Africa. We are also one of the largest land well-servicing and workover contractors in the United States and Canada. We actively market approximately 558 rigs for land workover and well-servicing work in the United States, primarily in the southwestern and western United States, and approximately 172 rigs for land workover and well-servicing work in Canada. Nabors is a leading provider of offshore platform workover and drilling rigs, and actively markets 40 platform, 13 jack-up and 3 barge rigs in the United States and multiple international markets. These rigs provide well-servicing, workover and drilling services. We have a 51% ownership interest in a joint venture in Saudi Arabia, which owns and actively markets 9 rigs in addition to the rigs we lease to the joint venture. We also offer a wide range of ancillary well-site services, including engineering, transportation, construction, maintenance, well logging, directional drilling, rig instrumentation, data collection and other support services in select domestic and international markets. We provide logistics services for onshore drilling in Canada using helicopters and fixed-wing aircraft. We manufacture and lease or sell top drives for a broad range of drilling applications, directional drilling systems, rig instrumentation and data collection equipment, pipeline handling equipment and rig reporting software. We also invest in oil and gas exploration, development and production activities in the U.S., Canada and international areas through both our wholly owned subsidiaries and our separate joint venture entities. We hold a 50% ownership interest in our Canadian entity and 49.7% ownership interests in our U.S. and International entities. Each joint venture pursues development and exploration projects with our existing customers and with other operators in a variety of forms, including operated and non-operated working interests, joint ventures, farm-outs and acquisitions.

     The majority of our business is conducted through our various Contract Drilling operating segments, which include our drilling, workover and well-servicing operations, on land and offshore. Our oil and gas exploration, development and production operations are included in our Oil and Gas operating segment. Our operating segments engaged in drilling technology and top drive manufacturing, directional drilling, rig instrumentation and software, and construction and logistics operations are aggregated in our Other Operating Segments.

     Our businesses depend, to a large degree, on the level of spending by oil and gas companies for exploration, development and production activities. Therefore, a sustained increase or decrease in the price of natural gas or oil, which could have a material impact on exploration, development and production activities, could also materially affect our financial position, results of operations and cash flows.

     The magnitude of customer spending on new and existing wells is the primary driver of our business. The primary determinate of customer spending is their cash flow and earnings which are largely driven by natural gas prices in our U.S. Lower 48 Land Drilling and Canadian Drilling operations, while oil prices are the primary determinate in our Alaskan, International, U.S. Offshore (Gulf of Mexico), Canadian Well-servicing and U.S. Land Well-servicing operations. The following table sets forth natural gas and oil price data per Bloomberg for the last three years:

		Year Ended December 31,												Increase / (Decrease)
		2009				2008				2007				2009 to 2008								2008 to 2007
Commodity prices:
Average Henry Hub natural gas spot price ($/million cubic feet (mcf))		$	3.94			$	8.89			$	6.97			$	(4.95	)			(56	%)		$	1.92				28	%
Average West Texas intermediate crude oil spot price ($/barrel)		$	61.99			$	99.92			$	72.23			$	(37.93	)			(38	%)		$	27.69				38	%

     Beginning in the fourth quarter of 2008, there was a significant reduction in the demand for natural gas and oil that was caused, at least in part, by the significant deterioration of the global economic environment including the extreme volatility in the capital and credit markets. Weaker demand throughout 2009 has resulted in sustained lower natural gas and oil prices. The price of natural gas reached a low for 2009 of $1.83 per mcf during September and while showing improvement remains depressed, having averaged $3.77 per mcf during the second half of 2009. The significant drop in the price of oil reached a low for 2009 of $33.98 per barrel in February with continuous recovery throughout 2009, averaging $72.08 per barrel during the second half of 2009. These reduced prices for natural gas and oil have led to a sharp decline in the demand for drilling and workover services. Continued fluctuations in the demand for gas and oil, among other factors including supply, could contribute to continued price volatility which may continue to affect demand for our services and could materially affect our future financial results.

     Operating revenues and Earnings (losses) from unconsolidated affiliates for the year ended December 31, 2009 totaled $3.5 billion, representing a decrease of $1.8 billion, or 34% as compared to the year ended December 31, 2008. Adjusted income derived from operating activities and net income (loss) attributable to Nabors for the year ended December 31, 2009 totaled $421.9 million and $(85.5) million ($(.30) per diluted share), respectively, representing decreases of 62% and 118%, respectively, compared to the year ended December 31, 2008. Operating revenues and Earnings (losses) from unconsolidated affiliates for the year ended December 31, 2008 totaled $5.3 billion, representing an increase of $355.3 million, or 7% as compared to the year ended December 31, 2007. Adjusted income derived from operating activities and net income (loss) attributable to Nabors for the year ended December 31, 2008 totaled $1.1 billion and $475.7 million ($1.65 per diluted share), respectively, representing decreases of 13% and 45%, respectively, compared to the year ended December 31, 2007.

     During 2009 and 2008, our operating results were negatively impacted as a result of charges arising from oil and gas full-cost ceiling test writedowns and other impairments. Earnings (losses) from unconsolidated affiliates includes $(189.3) million and $(207.3) million, respectively, for the years ended December 31, 2009 and 2008, representing our proportionate share of full-cost ceiling test writedowns from our unconsolidated oil and gas joint ventures which utilize the full-cost method of accounting. During 2009, our joint ventures used a 12-month average price in the ceiling test calculation as required by the revised SEC rules whereas during 2008, the ceiling test calculation used the single-day, year-end commodity price that, at December 31, 2008, was near its low point for that year. The full-cost ceiling test writedowns are included in our Oil and Gas operating segment results.

     During 2009 and 2008, our operating results were also negatively impacted as a result of our impairments and other charges of $331.0 million and $176.1 million, respectively. During 2009, impairments and other charges included recognition of other-than-temporary impairments of $54.3 million relating to our available-for-sale securities, and impairments of $64.2 million to long-lived assets that were retired from our U.S. Offshore, Alaska, Canada and International contract drilling segments. Additionally, we recorded impairment charges of $197.7 million and $21.5 million, respectively, to our wholly owned Ramshorn business unit under application of the successful-efforts method of accounting for some of our oil and gas-related assets during the years ended December 31, 2009 and 2008. During 2008, impairments and other charges included goodwill and intangible asset impairments totaling $154.6 million recorded by our Canada Well-servicing and Drilling operating segment and Nabors Blue Sky Ltd., one of our Canadian subsidiaries reported in Other Operating Segments. We recognized these goodwill and intangible asset impairments to reduce the carrying value of these assets to their estimated fair value. We consider these writedowns necessary because of the duration of the industry downturn in Canada and the lack of certainty regarding eventual recovery. These impairments and other charges are reflected separately as impairments and other charges in our consolidated statements of income (loss) for the years ended December 31, 2009 and 2008.

     Excluding these charges, our operating results were lower than the previous year results primarily due to the continuing weak environment in our U.S. Lower 48 Land Drilling, U.S. Land Well-servicing, Canada and U.S. Offshore operations where activity levels and demand for our drilling rigs have decreased substantially in response to uncertainty in the financial markets and commodity price deterioration. Operating results have been further negatively impacted by higher levels of depreciation expense due to our increased capital expenditures in recent years.

     Our operating results for 2010 are expected to approximate levels realized during 2009 given our current expectation of the continuation of lower commodity prices during 2010 and the related impact on drilling and well-servicing activity and dayrates. We expect the decrease in drilling activity and dayrates to continue to adversely impact our U.S. Lower 48 Land Drilling and our U.S. Land Well-servicing operations for 2010, as compared to 2009, because the number of working rigs and average dayrates have declined. We expect our International operations to decrease slightly during 2010 as a result of lower drilling activity and utilization partially offset by the deployment of new and incremental rigs under long-term contracts and the renewal of multi-year contracts. Although rig count is expected to be lower overall, the reductions are primarily comprised of lower yielding assets, leaving higher margin contracts in place partially offset by certain contracts rolling over at lower current market rates. Our investments in new and upgraded rigs over the past five years have resulted in long-term contracts which we expect will enhance our competitive position when market conditions improve.

The following tables set forth certain information with respect to our reportable segments and rig activity:

(In thousands, except
percentages		Year Ended December 31,												Increase/(Decrease)
and rig activity)		2009				2008				2007				2009 to 2008								2008 to 2007
Reportable segments:
Operating revenues and Earnings (losses) from unconsolidated affiliates from continuing operations: (1)
Contract Drilling: (2)
U.S. Lower 48 Land Drilling		$	1,082,531			$	1,878,441			$	1,710,990			$	(795,910	)			(42	%)		$	167,451				10	%
U.S. Land Well-servicing			412,243				758,510				715,414				(346,267	)			(46	%)			43,096				6	%
U.S. Offshore			157,305				252,529				212,160				(95,224	)			(38	%)			40,369				19	%
Alaska			204,407				184,243				152,490				20,164				11	%			31,753				21	%
Canada			298,653				502,695				545,035				(204,042	)			(41	%)			(42,340	)			(8	%)
International			1,265,097				1,372,168				1,094,802				(107,071	)			(8	%)			277,366				25	%
Subtotal Contract Drilling (3)			3,420,236				4,948,586				4,430,891				(1,528,350	)			(31	%)			517,695				12	%
Oil and Gas (4) (5)			(158,780	)			(118,533	)			155,476				(40,247	)			(34	%)			(274,009	)			(176	%)
Other Operating Segments (6) (7)			446,282				683,186				588,483				(236,904	)			(35	%)			94,703				16	%
Other reconciling items (8)			(179,752	)			(198,245	)			(215,122	)			18,493				9	%			16,877				8	%
Total		$	3,527,986			$	5,314,994			$	4,959,728			$	(1,787,008	)			(34	%)		$	355,266				7	%
Adjusted income (loss) derived from operating activities from continuing operations: (1)(9)
Contract Drilling:
U.S. Lower 48 Land Drilling		$	294,679			$	628,579			$	596,302			$	(333,900	)			(53	%)		$	32,277				5	%
U.S. Land Well-servicing			28,950				148,626				156,243				(119,676	)			(81	%)			(7,617	)			(5	%)
U.S. Offshore			30,508				59,179				51,508				(28,671	)			(48	%)			7,671				15	%
Alaska			62,742				52,603				37,394				10,139				19	%			15,209				41	%
Canada			(7,019	)			61,040				87,046				(68,059	)			(111	%)			(26,006	)			(30	%)
International			365,566				407,675				332,283				(42,109	)			(10	%)			75,392				23	%
Subtotal Contract Drilling(3)			775,426				1,357,702				1,260,776				(582,276	)			(43	%)			96,926				8	%
Oil and Gas(4)(5)			(190,798	)			(159,931	)			101,672				(30,867	)			(19	%)			(261,603	)			(257	%)
Other Operating Segments (7)(8)			34,120				68,572				35,273				(34,452	)			(50	%)			33,299				94	%
Other reconciling items (10)			(196,844	)			(167,831	)			(138,302	)			(29,013	)			(17	%)			(29,529	)			(21	%)
Total		$	421,904			$	1,098,512			$	1,259,419			$	(676,608	)			(62	%)		$	(160,907	)			(13	%)

(In thousands, except
percentages		Year Ended December 31,												Increase/(Decrease)
and rig activity)		2009				2008				2007				2009 to 2008								2008 to 2007
Interest expense			(266,039	)			(196,718	)			(154,919	)			(69,231	)			(35	%)			(41,799	)			(27	%)
Investment income (loss)			25,599				21,412				(16,290	)			4,187				20	%			37,702				231	%
Gains (losses) on sales and retirements of long-lived assets and other income (expense), net			(12,559	)			(15,829	)			(11,777	)			3,270				21	%			(4,052	)			(34	%)
Impairments and other charges (11)			(330,976	)			(176,123	)			(41,017	)			(154,853	)			(88	%)			(135,106	)			(329	%)
Income (loss) from continuing operations before income taxes			(162,071	)			731,254				1,035,416				(893,325	)			(122	%)			(304,162	)			(29	%)
Income tax expense (benefit)			(133,803	)			209,660				201,896				(343,463	)			(164	%)			7,764				4	%
Income (loss) from continuing operations, net of tax			(28,268	)			521,594				833,520				(549,862	)			(105	%)			(311,926	)			(37	%)
Income from discontinued operations, net of tax			(57,620	)			(41,930	)			31,762				(15,690	)			(37	%)			(73,692	)			(232	%)
Net income (loss)			(85,888	)			479,664				865,282				(565,552	)			(118	%)			(385,618	)			(45	%)
Less: Net (income) loss attributable to noncontrolling interest			342				(3,927	)			420				4,269				109	%			(4,347	)			N/M	(15)
Net income (loss) attributable to Nabors		$	(85,546	)		$	475,737			$	865,702			$	(561,283	)			(118	%)		$	(389,965	)			(45	%)
Rig activity:
Rig years: (12)
U.S. Lower 48 Land Drilling			149.4				247.9				229.4				(98.5	)			(40	%)			18.5				8	%
U.S. Offshore			11.0				17.6				15.8				(6.6	)			(38	%)			1.8				11	%
Alaska			10.0				10.9				8.7				(0.9	)			(8	%)			2.2				25	%
Canada			19.7				35.5				36.7				(15.8	)			(45	%)			(1.2	)			(3	%)
International (13)			100.2				120.5				115.2				(20.3	)			(17	%)			5.3				5	%
Total rig years			290.3				432.4				405.8				(142.1	)			(33	%)			26.6				7	%
Rig hours: (14)
U.S. Land Well-servicing			590,878				1,090,511				1,119,497				(499,633	)			(46	%)			(28,986	)			(3	%)
Canada Well-servicing			143,824				248,032				283,471				(104,208	)			(42	%)			(35,439	)			(13	%)
Total rig hours			734,702				1,338,543				1,402,968				(603,841	)			(45	%)			(64,425	)			(5	%)

Segment Results of Operations

Contract Drilling

     Our Contract Drilling operating segments contain one or more of the following operations: drilling, workover and well-servicing, on land and offshore.

     U.S. Lower 48 Land Drilling. The results of operations for this reportable segment are as follows:

(In thousands, except percentages		Year Ended December 31,												Increase/(Decrease)
and rig activity)		2009				2008				2007				2009 to 2008								2008 to 2007
Operating revenues and Earnings from unconsolidated affiliates		$	1,082,531			$	1,878,441			$	1,710,990			$	(795,910	)			(42	%)		$	167,451				10	%
Adjusted income derived from operating activities		$	294,679			$	628,579			$	596,302			$	(333,900	)			(53	%)		$	32,277				5	%
Rig years			149.4				247.9				229.4				(98.5	)			(40	%)			18.5				8	%

     Operating results decreased from 2008 to 2009 primarily due to a decline in drilling activity, driven by lower natural gas prices beginning in the fourth quarter of 2008 and diminished demand as customers released rigs and delayed drilling projects in response to the significant drop in natural gas prices and the tightening of the credit markets. Operating results were further negatively impacted by higher depreciation expense related to capital expansion projects completed in recent years.

     The increase in operating results from 2007 to 2008 was due to overall year-over-year increases in rig activity and increases in average dayrates, driven by higher natural gas prices throughout 2007 and most of 2008. This increase was only partially offset by higher operating costs and an increase in depreciation expense related to capital expansion projects.

     U.S. Land Well-servicing. The results of operations for this reportable segment are as follows:

(In thousands, except percentages		Year Ended December 31,												Increase/(Decrease)
and rig activity)		2009				2008				2007				2009 to 2008								2008 to 2007
Operating revenues and Earnings from unconsolidated affiliates		$	412,243			$	758,510			$	715,414			$	(346,267	)			(46	%)		$	43,096				6	%
Adjusted income derived from operating activities		$	28,950			$	148,626			$	156,243			$	(119,676	)			(81	%)		$	(7,617	)			(5	%)
Rig hours			590,878				1,090,511				1,119,497				(499,633	)			(46	%)			(28,986	)			(3	%)

     Operating results decreased from 2008 to 2009 primarily due to lower rig utilization and price erosion, driven by lower customer demand for our services due to relatively lower oil prices caused by the U.S. economic recession and reduced end product demand. Operating results were further negatively impacted by higher depreciation expense related to capital expansion projects completed in recent years.

     Operating revenues and Earnings from unconsolidated affiliates increased from 2007 to 2008 primarily as a result of higher average dayrates year-over-year, driven by high oil prices during 2007 and the majority of 2008 as well as market expansion. Higher average dayrates were partially offset by lower rig utilization. Adjusted income derived from operating activities decreased from 2007 to 2008 despite higher revenues due primarily to higher depreciation expense related to capital expansion projects and, to a lesser extent, higher operating costs.

     U.S. Offshore. The results of operations for this reportable segment are as follows:

(In thousands, except percentages		Year Ended December 31,												Increase/(Decrease)
and rig activity)		2009				2008				2007				2009 to 2008								2008 to 2007
Operating revenues and Earnings from unconsolidated affiliates		$	157,305			$	252,529			$	212,160			$	(95,224	)			(38	%)		$	40,369				19	%
Adjusted income derived from operating activities		$	30,508			$	59,179			$	51,508			$	(28,671	)			(48	%)		$	7,671				15	%
Rig years			11.0				17.6				15.8				(6.6	)			(38	%)			1.8				11	%

     The decrease in operating results from 2008 to 2009 primarily resulted from lower average dayrates and utilization for the SuperSundowner^TM platform rigs, workover jack-up rigs, barge drilling and workover rigs, and Sundowner^® platform rigs, partially offset by higher utilization of our MODS^® rigs inclusive of a significant term contract for a MODS^® rig deployed in January 2009.

     The increase in operating results from 2007 to 2008 primarily resulted from higher average dayrates and increased drilling activity driven by high oil prices during the majority of 2008, especially in the Sundowner and Super Sundowner platform workover and re-drilling rigs and the MASE^® platform drilling rigs. The increase in 2008 was partially offset by higher operating costs and increased depreciation expense relating to new rigs added to the fleet in early 2007.

     Alaska. The results of operations for this reportable segment are as follows:

(In thousands, except percentages		Year Ended December 31,												Increase/(Decrease)
and rig activity)		2009				2008				2007				2009 to 2008								2008 to 2007
Operating revenues and Earnings from unconsolidated affiliates		$	204,407			$	184,243			$	152,490			$	20,164				11	%		$	31,753				21	%
Adjusted income derived from operating activities		$	62,742			$	52,603			$	37,394			$	10,139				19	%		$	15,209				41	%
Rig years			10.0				10.9				8.7				(0.9	)			(8	%)			2.2				25	%

     The increases in operating results from 2008 to 2009 and from 2007 to 2008 were primarily due to increases in average dayrates and drilling activity. Although drilling activity levels decreased slightly during 2009, operating results reflect the higher average margins as a result of the addition of some high specification rig work. Drilling activity levels increased in 2008 as a result of the deployment and utilization of rigs added to the fleet in late 2007 under long-term contracts. The increases during 2009 and 2008 have been partially offset by higher operating costs and increased depreciation expense as well as increased labor and repairs and maintenance costs in 2009 and 2008 as compared to prior years.

     Canada. The results of operations for this reportable segment are as follows:

(In thousands, except percentages		Year Ended December 31,												Increase/(Decrease)
and rig activity)		2009				2008				2007				2009 to 2008								2008 to 2007
Operating revenues and Earnings from unconsolidated affiliates		$	298,653			$	502,695			$	545,035			$	(204,042	)			(41	%)		$	(42,340	)			(8	%)
Adjusted income (loss) derived from operating activities		$	(7,019	)		$	61,040			$	87,046			$	(68,059	)			(111	%)		$	(26,006	)			(30	%)
Rig years — Drilling			19.7				35.5				36.7				(15.8	)			(45	%)			(1.2	)			(3	%)
Rig hours — Well-servicing			143,824				248,032				283,471				(104,208	)			(42	%)			(35,439	)			(13	%)

     Operating results decreased from 2008 to 2009 primarily as a result of an overall decrease in drilling and well-servicing activity due to lower natural gas prices driving a significant decline of customer demand for drilling and well-servicing operations. Our operating results for 2009 were further negatively impacted by the economic uncertainty in the Canadian drilling market and financial market instability. The Canadian dollar began 2009 in a

weak position versus the U.S. dollar, during a period of time when drilling and well-servicing activity was typically at its seasonal peak, which also had an overall negative impact on operating results. These decreases in operating results were partially offset by cost reductions in direct costs, general and administrative expenses and depreciation.

     The decrease in operating results from 2007 to 2008 resulted from year-over-year decreases in drilling and well-servicing activity and decreases in average dayrates for drilling and well-servicing operations as a result of economic uncertainty and Alberta’s tight labor market which led to a number of projects being delayed. Our operating results were further negatively impacted by proposed changes to the Alberta royalty and tax regime causing customers to assess the impact of such changes. The strengthening of the Canadian dollar versus the U.S. dollar during 2007 and throughout the majority of 2008 positively impacted operating results, but negatively impacted demand for our services as much of our customers’ revenue is denominated in U.S. dollars while their costs are denominated in Canadian dollars. Additionally, operating results were negatively impacted by increased operating expenses, including depreciation expense related to capital expansion projects.

     International. The results of operations for this reportable segment are as follows:

(In thousands, except percentages		Year Ended December 31,												Increase/(Decrease)
and rig activity)		2009				2008				2007				2009 to 2008								2008 to 2007
Operating revenues and Earnings from unconsolidated affiliates		$	1,265,097			$	1,372,168			$	1,094,802			$	(107,071	)			(8	%)		$	277,366				25	%
Adjusted income derived from operating activities		$	365,566			$	407,675			$	332,283			$	(42,109	)			(10	%)		$	75,392				23	%
Rig years			100.2				120.5				115.2				(20.3	)			(17	%)			5.3				5	%

     The decrease in operating results from 2008 to 2009 resulted primarily from year-over-year decreases in average dayrates and lower utilization of rigs in Mexico, Libya, Argentina and Colombia, driven by weakening customer demand for drilling services stemming from the drop in oil prices in the fourth quarter of 2008 which continued throughout 2009. Operating results were further negatively impacted by higher depreciation expense related to capital expansion projects completed in recent years. These decreases were partially offset by higher average dayrates from two jack-up rigs deployed in Saudi Arabia, increases in average dayrates for our new and incremental rigs added and deployed during 2008 and a start-up floating, drilling, production, storage and offloading vessel off the coast of the Republic of the Congo.

     The increase in operating results from 2007 to 2008 primarily resulted from year-over-year increases in average dayrates and drilling activities, reflecting strong customer demand for drilling services, stemming from sustained higher oil prices throughout 2007. Operating results during 2007 and most of 2008 were also positively impacted by an expansion of our rig fleet and continuing renewal of existing multi-year contracts at higher average dayrates. These increases were partially offset by increased operating expenses, including depreciation expense related to capital expenditures for new and refurbished rigs deployed throughout 2007 and 2008.

     Oil and Gas. The results of operations for this reportable segment are as follows:

		Year Ended December 31,												Increase/(Decrease)
(In thousands, except percentages)		2009				2008				2007				2009 to 2008								2008 to 2007
Operating revenues and Earnings (losses) from unconsolidated affiliates		$	(158,780	)		$	(118,533	)		$	155,476			$	(40,247	)			(34	%)		$	(274,009	)			(176	%)
Adjusted income (loss) derived from operating activities		$	(190,798	)		$	(159,931	)		$	101,672			$	(30,867	)			(19	%)		$	(261,603	)			(257	%)

     Our operating results decreased from 2008 to 2009 primarily as a result of full-cost ceiling test writedowns recorded during 2009 by our unconsolidated joint ventures. During 2009, our U.S. oil and gas joint venture recorded a full-cost ceiling test writedown, of which our proportionate share totaled $189.3 million. The writedown resulted from the application of the full-cost method of accounting for costs related to oil and natural gas properties. The full-cost ceiling test limits the carrying value of the capitalized cost of the properties to 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. The full-cost ceiling test was evaluated using the 12-month average commodity price as required by the revised SEC rules.

     Operating results further decreased from 2008 to 2009 due to declines in natural gas prices and production volumes from our Ramshorn and joint venture operations. Additionally, operating results for 2008 included a $12.3 million gain recorded on the sale of leasehold interests.

     Our operating results decreased from 2007 to 2008 as a result of a full-cost ceiling test writedown recorded during 2008 by our unconsolidated U.S. oil and gas joint venture. During 2008, our U.S. oil and gas joint venture recorded a full-cost ceiling test writedown, of which our proportionate share totaled $207.3 million. The full-cost ceiling test was determined using the single-day, year-end price as required by SEC rules at the time.

     Additionally during 2008, our proportionate share of losses from our unconsolidated oil and gas joint ventures included $10.0 million of depletion charges from lower-than-expected performance of certain oil and gas developmental wells and $5.8 million of mark-to-market unrealized losses from derivative instruments representing forward gas sales through swaps and price floor guarantees utilizing puts. Beginning in May 2008 our U.S. joint venture began to apply hedge accounting to its forward contracts to minimize the volatility in reported earnings caused by market price fluctuations of the underlying hedged commodities. These losses were partially offset by income from our production volumes and oil and gas production sales as a result of higher oil and natural gas prices throughout most of 2008 and a $12.3 million gain on the sale of leasehold interests in 2008.

Other Operating Segments

     These operations include our drilling technology and top-drive manufacturing, directional drilling, rig instrumentation and software, and construction and logistics operations. The results of operations for these operating segments are as follows:

		Year Ended December 31,												Increase/(Decrease)
(In thousands, except percentages)		2009				2008				2007				2009 to 2008								2008 to 2007
Operating revenues and Earnings from unconsolidated affiliates		$	446,282			$	683,186			$	588,483			$	(236,904	)			(35	%)		$	94,703				16	%
Adjusted income derived from operating activities		$	34,120			$	68,572			$	35,273			$	(34,452	)			(50	%)		$	33,299				94	%

     The decreases in operating results from 2008 to 2009 primarily resulted from (i) lower demand in the U.S. and Canadian drilling markets for rig instrumentation and data collection services from oil and gas exploration companies, (ii) decreases in customer demand for our construction and logistics services in Alaska and (iii) decreased capital equipment unit volumes and lower service and rental activity as a result of the slowdown in the oil and gas industry.

     The increase in operating results from 2007 to 2008 primarily resulted from year-over-year increases in third-party sales and higher margins on top drives occasioned by the strengthening of the oil drilling market, increased equipment sales, increased market share in Canada and increased demand in the U.S. directional drilling market. Results were also improved in 2008 due to increases in customer demand for our construction and logistics services in Alaska.

Discontinued Operations

     During 2010, we began actively marketing our oil and gas assets in the Horn River basin in Canada and in the Llanos basin in Colombia. These assets also include our 49.7% and 50.0% ownership interests in our investments of Remora and SMVP, respectively, which we account for using the equity method of accounting. All of these assets are included in our oil and gas operating segment. We determined that the plan of sale criteria in the ASC Topic relating to the Presentation of Financial Statements for Assets Sold or Held for Sale had been met during the third quarter of 2010. Accordingly, we reclassified these wholly owned oil and gas assets from our property, plant and equipment, net, as well as our investment balances for Remora and SMVP from investments in unconsolidated affiliates to assets held for sale in our consolidated balance sheet at September 30, 2010.

     During the third quarter of 2007 we sold our Sea Mar business which had previously been included in Other Operating Segments to an unrelated third party. The assets included 20 offshore supply vessels and certain related assets, including a right under a vessel construction contract. The operating results for the year ended December 31, 2007 include a gain, net of tax of $19.6 million, related to the sale of the Sea Mar business. We have not had any continuing involvement subsequent to the sale of this business.

     The operating results from these assets for all periods presented are retroactively presented and accounted for as discontinued operations in the accompanying audited consolidated statements of income. Our condensed statements of income from discontinued operations related to the oil and gas assets as well as our Sea Mar business for the years ended December 31, 2009, 2008 and 2007 were as follows:

		Year Ended December 31,												Increase/(Decrease)
(In thousands, except percentages)		2009				2008				2007				2009 to 2008								2008 to 2007
Revenues from oil and gas assets		$	8,937			$	4,354			$	100			$	4,583				105	%		$	4,254				n/m	(1)
Revenues from Sea Mar business		$	—			$	—			$	58,887			$	—				—			$	(58,887	)			(100	%)
Earnings (losses) from unconsolidated affiliates		$	(59,248	)		$	(37,286	)		$	(3,256	)		$	(21,962	)			(59	%)		$	(34,030	)			n/m	(1)
Income (loss) from discontinued operations, net of tax
Income (loss) from discontinued operations from oil and gas assets, net of tax		$	(57,620	)		$	(41,930	)		$	(3,262	)		$	(15,690	)			(37	%)		$	(38,668	)			n/m	(1)
Income (loss) from discontinued operations from Sea Mar business, net of tax			—				—				35,024				—				—				(35,024	)			(100	%)

OTHER FINANCIAL INFORMATION

General and administrative expenses

		Year Ended December 31,												Increase/(Decrease)
(In thousands, except percentages)		2009				2008				2007				2009 to 2008								2008 to 2007
General and administrative expenses		$	428,161			$	479,194			$	436,274			$	(51,033	)			(11	%)		$	42,920				10	%
General and administrative expenses as a percentage of operating revenues			11.6	%			8.7	%			8.8	%			2.9	%			33	%			(.1	%)			(1	%)

     General and administrative expenses decreased from 2008 to 2009 primarily as a result of significant decreases in wage-related expenses and other cost-reduction efforts across all business units, partially offset by an increase of approximately $61.2 million in stock compensation expense. During 2009, share-based compensation expense included $72.1 million of compensation expense related to previously granted restricted stock and option awards held by Messrs. Isenberg and Petrello that was unrecognized as of April 1, 2009. The recognition of this expense resulted from provisions of their respective new employment agreements that effectively eliminated the risk of forfeiture of such awards. There is no remaining unrecognized expense related to their outstanding restricted stock and option awards. General and administrative expenses as a percentage of operating revenues increased primarily due to lower revenues.

     General and administrative expenses increased from 2007 to 2008 primarily as a result of increases in wages and wage-related expenses for a majority of our operating segments compared to each prior year, which resulted from an increase in the number of employees required to support higher activity levels. The increase was also driven by higher compensation expense, primarily resulting from higher bonuses and non-cash compensation expenses recorded for restricted stock awards during 2007 and 2008.

Depreciation and amortization, and depletion expense

		Year Ended December 31,												Increase/(Decrease)
(In thousands, except percentages)		2009				2008				2007				2009 to 2008								2008 to 2007
Depreciation and amortization expense		$	667,100			$	614,367			$	469,669			$	52,733				9	%		$	144,698				31	%
Depletion expense		$	9,417			$	22,308			$	30,904			$	(12,891	)			(58	%)		$	(8,596	)			(28	%)

     Depreciation and amortization expense. Depreciation and amortization expense increased from 2008 to 2009 and from 2007 to 2008 primarily as a result of projects completed in recent years under our expanded capital expenditure program that commenced in early 2005.

     Depletion expense. Depletion expense decreased from 2008 to 2009 and from 2007 to 2008 primarily as a result of decreased natural gas production volumes during each year.

Interest expense

		Year Ended December 31,												Increase/(Decrease)
(In thousands, except percentages)		2009				2008				2007				2009 to 2008								2008 to 2007
Interest expense		$	266,039			$	196,718			$	154,919			$	69,321				(35	%)		$	41,799				(27	%)

     Interest expense increased from 2008 to 2009 as a result of the interest expense related to our January 2009 issuance of 9.25% senior notes due January 2019. The increase was partially offset by a reduction to interest expense due to our repurchases of approximately $1.1 billion par value of 0.94% senior exchangeable notes during 2008 and 2009.

     Interest expense increased from 2007 to 2008 as a result of the additional interest expense related to our February 2008 and July 2008 issuances of 6.15% senior notes due February 2018 in the amounts of $575 million and $400 million, respectively.

Investment income (loss)

		Year Ended December 31,												Increase/(Decrease)
(In thousands, except percentages)		2009				2008				2007				2009 to 2008								2008 to 2007
Investment income (loss)		$	25,599			$	21,412			$	(16,290	)		$	4,187				20	%		$	37,702				231	%

     Investment income during 2009 was $25.6 million compared to $21.4 million during the prior year. Investment income in 2009 included net unrealized gains of $9.8 million from our trading securities and interest and dividend income of $15.9 million from our cash, other short-term and long-term investments.

     Investment income during 2008 was $21.4 million compared to a net investment loss of $15.9 million during the prior year. Investment income in 2008 included net unrealized gains of $8.5 million from our trading securities and interest and dividend income of $40.5 million from our short-term and long-term investments, partially offset by losses of $27.4 million from our actively managed funds classified as long-term investments.

     Investment income (loss) during 2007 included a net loss of $61.4 million from our actively managed funds classified as long-term investments inclusive of substantial gains from sales of our marketable equity securities. This net loss was offset by interest and dividend income of $45.5 million from our short-term investments.

Gains (losses) on sales and retirements of long-lived assets and other income (expense), net

		Year Ended December 31,												Increase/(Decrease)
(In thousands, except percentages)		2009				2008				2007				2009 to 2008								2008 to 2007
Gains (losses) on sales and retirements of long-lived assets and other income (expense), net		$	(12,559	)		$	(15,829	)		$	(11,777	)		$	3,270				21	%		$	(4,052	)			(34	%)

     The amount of gains (losses) on sales and retirements of long-lived assets and other income (expense), net for 2009 represents a net loss of $12.6 million and includes: (i) foreign currency exchange losses of approximately $8.4 million, (ii) increases of litigation expenses of $11.5 million, and (iii) net losses on sales and retirements of long-lived assets of approximately $5.9 million. These losses were partially offset by pre-tax gains of $11.5 million recognized on purchases of $964.8 million par value of our 0.94% senior exchangeable notes due 2011.

     The amount of gains (losses) on sales and retirements of long-lived assets and other income (expense), net for 2008 represents a net loss of $15.8 million and includes: (i) losses on derivative instruments of approximately $14.6 million, including a $9.9 million loss on a three-month written put option and a $4.7 million loss on the fair value of our range-cap-and-floor derivative, (ii) losses on retirements on long-lived assets of approximately $13.2 million, inclusive of involuntary conversion losses on long-lived assets of approximately $12.0 million, net of insurance recoveries, related to damage sustained from Hurricanes Gustav and Ike during 2008, and (iii) increases of litigation expenses of $3.5 million. These losses were partially offset by a $12.2 million pre-tax gain recognized on our purchase of $100 million par value of 0.94% senior exchangeable notes due 2011.

     The amount of gains (losses) on sales and retirements of long-lived assets and other income (expense), net for 2007 represents a net loss of $11.8 million and includes: (i) losses on retirements and impairment charges on long-lived assets of approximately $40.0 million and (ii) increases of litigation expenses of $9.6 million. These losses were partially offset by the $38.6 million gain on the sale of three accommodation jack-up rigs in the second quarter of 2007.

Impairments and Other Charges

		Year Ended December 31,												Increase/(Decrease)
(In thousands, except percentages)		2009				2008				2007				2009 to 2008								2008 to 2007
Goodwill impairments		$	14,689			$	150,008			$	—			$	(135,319	)			(90	%)		$	150,008				100	%
Impairment of long-lived assets to be disposed of other than by sale			64,229				—				—				64,229				100	%			—				—
Impairment of other intangible assets			—				4,578				—				(4,578	)			(100	%)			4,578				100	%
Impairment of oil and gas- related assets			197,744				21,537				41,017				176,207				818	%			(19,480	)			(47	%)
Other-than-temporary impairment on securities			54,314				—				—				54,314				100	%			—				—
Total		$	330,976			$	176,123			$	41,017			$	154,853				88	%		$	135,106				329	%

     During the years ended December 31, 2009 and 2008, we recognized goodwill impairments of approximately $14.7 million and $150.0 million, respectively, related to our Canadian operations. During 2008, we impaired the entire goodwill balance of $145.4 million of our Canada Well-servicing and Drilling operating segment and recorded an impairment of $4.6 million to Nabors Blue Sky Ltd., one of our Canadian subsidiaries reported in our Other Operating segments. During 2009, we impaired the remaining goodwill balance of $14.7 million of Nabors Blue Sky Ltd. The impairment charges resulted from of our annual impairment tests on goodwill which compared the estimated fair value of each of our reporting units to its carrying value. The estimated fair value of these business units was determined using discounted cash flow models involving assumptions based on our utilization of rigs or aircraft, revenues and earnings from affiliates, as well as direct costs, general and administrative costs, depreciation, applicable income taxes, capital expenditures and working capital requirements. The impairment charges were deemed necessary due to the continued downturn in the oil and gas industry in Canada and the lack of certainty regarding eventual recovery in the value of these operations. This downturn has led to reduced capital spending by some of our customers and has diminished demand for our drilling services and for immediate access to remote drilling sites. 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 Critical Accounting Policies below and Note 2 — Summary of Significant Accounting Policies (included under the caption “Goodwill”) in Part II, Item 8. — Financial Statements and Supplementary Data.

     During the year ended December 31, 2009, we retired some rigs and rig components in our U.S. Offshore, Alaska, Canada and International Contract Drilling segments and reduced their aggregate carrying value from $69.0 million to their estimated aggregate salvage value, resulting in impairment charges of approximately $64.2 million. The retirements included inactive workover jack-up rigs in our U.S. Offshore and International operations, the structural frames of some incomplete coiled tubing rigs in our Canada operations and miscellaneous rig components in our Alaska operations. The impairment charges resulted from the continued deterioration and longer than expected downturn in the demand for oil and gas drilling activities. A prolonged period of lower natural gas and oil prices and its potential impact on our utilization and dayrates could result in the recognition of future impairment charges to additional assets if future cash flow estimates, based upon information then available to management, indicate that the carrying value of those assets may not be recoverable.

     Also in 2009, we recorded impairments totaling $197.7 million to some of the oil and gas-related assets of our wholly owned Ramshorn business unit. We recorded an impairment of $149.1 million to one of our oil and gas financing receivables, which reduced the carrying value of our oil and gas financing receivables recorded as long-term investments to $92.5 million. The impairment resulted primarily from commodity price deterioration and the lower price environment lasting longer than expected. This prolonged period of lower prices has significantly reduced demand for future gas production and development in the Barnett Shale area of north central Texas, which has influenced our decision not to expend capital to develop on some of the undeveloped acreage. The impairment was determined using discounted cash flow models involving assumptions based on estimated cash flows for proved and probable reserves, undeveloped acreage value, and current and expected natural gas prices. We believe the estimates used provide a reasonable estimate of current fair value. A further protraction or continued period of lower commodity prices could result in recognition of future impairment charges. During the years ended December

31, 2009, 2008 and 2007, our impairment tests on the oil and gas properties of our wholly owned Ramshorn business unit resulted in impairment charges of $48.6 million, $21.5 million and $41.0 million, respectively. The impairments recognized during 2009 were primarily the result of a write down of the carrying value of some acreage in the U.S. and Canada because we do not have future plans to develop. The impairments recognized during 2008 were primarily due to the significant decline in oil and natural gas prices at the end of 2008. The impairments recognized during 2007 were necessary from lower than expected performance of some oil and gas development wells. Additional discussion of our policy pertaining to the calculations of these impairments is set forth in “Oil and Gas Properties” under Critical Accounting Estimates below in this section or in Note 2 — Summary of Significant Accounting Policies in Part II Item 8. — Financial Statements and Supplementary Data.

     In 2009, we recorded other-than-temporary impairments to our available-for-sale securities totaling $54.3 million. Of this, $35.6 million was related to an investment in a corporate bond that was downgraded to non-investment grade level by Standard and Poor’s and Moody’s Investors Service during the year. Our determination that the impairment was other than temporary was based on a variety of factors, including the length of time and extent to which the market value had been less than cost, the financial condition of the issuer of the security, and the credit ratings and recent reorganization of the issuer. The remaining $18.7 million related to an equity security of a public company whose operations are driven in large measure by the price of oil and in which we invested approximately $46 million during the second and third quarters of 2008. During late 2008, demand for oil and gas began to diminish significantly as part of the general deterioration of the global economic environment, causing a broad decline in value of nearly all oil and gas-related equity securities. Because the trading price per share of this security remained below our cost basis for an extended period, we determined the investment was other than temporarily impaired and it was appropriate to write down the investment’s carrying value to its current estimated fair value of approximately $27.0 million at December 31, 2009.

Income tax rate

		Year Ended December 31,												Increase/(Decrease)
		2009				2008				2007				2009 to 2008								2008 to 2007
Effective income tax rate from continuing operations			83	%			29	%			19	%			54	%			186	%			10	%			53	%

     Our effective income tax rate for 2009 reflects the disparity between losses in our U.S. operations (attributable primarily to impairments) and income in our other operations primarily in lower tax jurisdictions. Because the U.S. income tax rate is higher than that of other jurisdictions, the tax benefit from our U.S. losses was not proportionately reduced by the tax expense from our other operations. The result is a net tax benefit that represents a significant percentage (82.5%) of our consolidated loss from continuing operations before income taxes. Because of the manner in which this number is derived, we do not believe it presents a meaningful basis for comparing our 2009 effective income tax rate to our 2008 effective income tax rate.

     The increase in our effective income tax rate from 2007 to 2008 resulted from (1) our goodwill impairments which had no associated tax benefit, (2) the reversal of certain tax reserves during 2007 in the amount of $25.5 million, (3) a decrease in 2007 tax expense of approximately $16.0 million resulting from a reduction in Canada’s tax rate, and (4) a higher proportion of our 2008 taxable income being generated in the United States, which generally imposes a higher tax rate than the other jurisdictions in which we operate.

     We are subject to income taxes in the U.S. and numerous other jurisdictions. Significant judgment is required in determining our worldwide provision for income taxes. One of the most volatile factors in this determination is the relative proportion of our income or loss being recognized in high versus low tax jurisdictions. In the ordinary course of our business, there are many transactions and calculations for which the ultimate tax determination is uncertain. We are regularly under audit by tax authorities. Although we believe our tax estimates are reasonable, the final outcome of tax audits and any related litigation could be materially different than what is reflected in our income tax provisions and accruals. The results of an audit or litigation could materially affect our financial position, income tax provision, net income, or cash flows.

     Various bills have been introduced in Congress that could reduce or eliminate the tax benefits associated with our reorganization as a Bermuda company. Legislation enacted by Congress in 2004 provides that a corporation that reorganized in a foreign jurisdiction on or after March 4, 2003 be treated as a domestic corporation for United States

federal income tax purposes. Nabors’ reorganization was completed June 24, 2002. There have been and we expect that there may continue to be legislation proposed by Congress from time to time which, if enacted, could limit or eliminate the tax benefits associated with our reorganization.

     Because we cannot predict whether legislation will ultimately be adopted, no assurance can be given that the tax benefits associated with our reorganization will ultimately accrue to the benefit of the Company and its shareholders. It is possible that future changes to the tax laws (including tax treaties) could impact on our ability to realize the tax savings recorded to date as well as future tax savings resulting from our reorganization.

Liquidity and Capital Resources

Cash Flows

     Our cash flows depend, to a large degree, on the level of spending by oil and gas companies for exploration, development and production activities. Sustained increases or decreases in the price of natural gas or oil could have a material impact on these activities, and could also materially affect our cash flows. Certain sources and uses of cash, such as the level of discretionary capital expenditures, purchases and sales of investments, issuances and repurchases of debt and of our common shares are within our control and are adjusted as necessary based on market conditions. The following is a discussion of our cash flows for the years ended December 31, 2009 and 2008.

     Operating Activities. Net cash provided by operating activities totaled $1.6 billion during 2009 compared to net cash provided by operating activities of $1.5 billion during 2008. Net cash provided by operating activities (“operating cash flows”) is our primary source of capital and liquidity. Factors affecting changes in operating cash flows are largely the same as those that affect net earnings, with the exception of non-cash expenses such as depreciation and amortization, depletion, impairments, share-based compensation, deferred income taxes and our proportionate share of earnings or losses from unconsolidated affiliates. Net income (loss) adjusted for non-cash components was approximately $1.1 billion and $1.7 billion for the years ended December 31, 2009 and 2008, respectively. Additionally, changes in working capital items such as collection of receivables can be a significant component of operating cash flows. Changes in working capital items provided $471.9 million in cash flows for the year ended December 31, 2009 and required $278.6 million in cash flows for the year ended December 31, 2008.

     Investing Activities. Net cash used for investing activities totaled $1.2 billion during 2009 compared to net cash used for investing activities of $1.5 billion during 2008. During 2009 and 2008, cash was used primarily for capital expenditures totaling $1.1 billion and $1.5 billion, respectively, and investments in unconsolidated affiliates totaling $125.1 million and $271.3 million, respectively. During 2009 and 2008, cash was derived from sales of investments, net of purchases, totaling $24.4 million and $251.6 million, respectively.

     Financing Activities. Net cash provided by financing activities totaled $19.4 million during 2009 compared to net cash used for financing activities of $89.2 million during 2008. During 2009, cash was derived from the receipt of $1.1 billion in proceeds, net of debt issuance costs, from the January 2009 issuance of 9.25% senior notes due 2019. Also during 2009, cash totaling $862.6 million was used to purchase $964.8 million par value of 0.94% senior exchangeable notes due 2011 and cash totaling $225.2 million was used to redeem the 4.875% senior notes. During 2008, cash totaling $836.5 million was used to redeem Nabors Delaware’s zero coupon senior exchangeable notes due 2023 and zero coupon senior convertible debentures due 2021 and for the purchase of $100 million par value of 0.94% senior exchangeable notes due 2011 in the open market. During 2008, cash was used to repurchase our common shares in the open market for $281.1 million. Also during 2008, cash was provided by the receipt of $955.6 million in net proceeds from the February and July 2008 issuances of the 6.15% senior notes due 2018, net of debt issuance costs. During 2009 and 2008, cash was provided by our receipt of proceeds totaling $11.2 million and $56.6 million, respectively, from the exercise by our employees of options to acquire our common shares.

Future Cash Requirements

     As of December 31, 2009, we had long-term debt, including current maturities, of $3.9 billion and cash and investments of $1.2 billion, including $100.9 million of long-term investments and other receivables. Long-term investments and other receivables include $92.5 million in oil and gas financing receivables.

     Our 0.94% senior exchangeable notes mature in May 2011. During 2008 and 2009 collectively, we purchased $1.1 billion par value of these notes in the open market for cash totaling $938.4 million, leaving approximately $1.7 billion par value outstanding. The balance of these notes will be reclassified to current debt in the second quarter of 2010. We believe our positive cash flow from operations in combination with our ability to access the capital markets will be sufficient to enable us to satisfy the payment obligation due in May 2011.

     Our 0.94% senior exchangeable notes due 2011 provide that upon an exchange of these notes, we will be required to pay holders of the notes cash up to the principal amount of the notes and our common shares for any amount that the exchange value of the notes exceeds the principal amount of the notes. The notes cannot be exchanged until the price of our shares exceeds approximately $59.57 for at least 20 trading days during the period of 30 consecutive trading days ending on the last trading day of the previous calendar quarter; or during the five business days immediately following any ten consecutive trading day period in which the trading price per note for each day of that period was less than 95% of the product of the sale price of Nabors’ common shares and the then applicable exchange rate for the notes; or upon the occurrence of specified corporate transactions set forth in the indenture. On February 24, 2010, the closing market price for our common stock was $21.92 per share. If any of the events described above were to occur and the notes were exchanged at a purchase price equal to 100% of the principal amount of the notes before maturity in May 2011, the required cash payment could have a significant impact on our level of cash and cash equivalents and investments available to meet our other cash obligations. Management believes that in the event the price of our shares were to exceed $59.57 for the required period of time, the holders of these notes would not be likely to exchange the notes as it would be more economically beneficial to them if they sold the notes to other investors on the open market. However, there can be no assurance that the holders would not exchange the notes.

     As of December 31, 2009, we had outstanding purchase commitments of approximately $152.4 million, primarily for rig-related enhancements, construction and sustaining capital expenditures and other operating expenses. Capital expenditures over the next twelve months, including these outstanding purchase commitments, are currently expected to total approximately $.6 — $.8 billion, including currently planned rig-related enhancements, construction and sustaining capital expenditures. This amount could change significantly based on market conditions and new business opportunities. The level of our outstanding purchase commitments and our expected level of capital expenditures over the next twelve months represent a number of capital programs that are currently underway. These programs, which are nearing an end, have resulted in an expansion in the number of drilling and well-servicing rigs that we own and operate and consist primarily of land drilling and well-servicing rigs. The expansion of our capital expenditure programs to build new state-of-the-art drilling rigs has impacted a majority of our operating segments, most significantly within our U.S. Lower 48 Land Drilling, U.S. Land Well-servicing, Alaska, Canada and International operations.

     We have historically completed a number of acquisitions and will continue to evaluate opportunities to acquire assets or businesses to enhance our operations. Several of our previous acquisitions were funded through issuances of our common shares. Future acquisitions may be paid for using existing cash or issuing debt or Nabors shares. Such capital expenditures and acquisitions will depend on our view of market conditions and other factors.

     See our discussion of guarantees issued by Nabors that could have a potential impact on our financial position, results of operations or cash flows in future periods included below under Off-Balance Sheet Arrangements (Including Guarantees).

     The following table summarizes our contractual cash obligations as of December 31, 2009:

		Payments due by Period
(In thousands)		Total				< 1 Year				1-3 Years				3-5 Years				Thereafter
Contractual cash obligations:
Long-term debt: (1)
Principal		$	4,061,255			$	163			$	1,961,002	(2)		$	90			$	2,100,000	(3)
Interest			1,566,550				194,679				365,645				328,076				678,150
Operating leases (4)			35,550				15,498				13,705				4,840				1,507
Purchase commitments (5)			152,387				151,097				1,290				—				—
Employment contracts (4)			35,442				10,723				21,330				3,389				—
Pension funding obligations (6)			450				450				—				—				—
Total contractual cash obligations		$	5,851,634			$	372,610			$	2,362,972			$	336,395			$	2,779,657

     The table above excludes liabilities for unrecognized tax benefits totaling $107.5 million as of December 31, 2009 because we are unable to make reasonably reliable estimates of the timing of cash settlements with the respective taxing authorities. Further details on the unrecognized tax benefits can be found in Note 12 — Income Taxes in Part II, Item 8. — Financial Statements and Supplementary Data.

(1)

See Note 11 — Debt in Part II, Item 8. — Financial Statements and Supplementary Data.

(2)

Includes the remaining portion of Nabors Delaware’s 0.94% senior exchangeable notes due May 2011 and 5.375% senior notes due August 2012.

(3)

Represents Nabors Delaware’s aggregate 6.15% senior notes due February 2018 and 9.25% senior notes due January 2019.

(4)

See Note 16 — Commitments and Contingencies in Part II, Item 8. — Financial Statements and Supplementary Data.

(5)

Purchase commitments include agreements to purchase goods or services that are enforceable and legally binding and that specify all significant terms, including fixed or minimum quantities to be purchased; fixed, minimum or variable pricing provisions; and the approximate timing of the transaction.

(6)

See Note 14 — Pension, Postretirement and Postemployment Benefits in Part II, Item 8. - Financial Statements and Supplementary Data.

     We may from time to time seek to retire or purchase our outstanding debt through cash purchases and/or exchanges for equity securities, both in open-market purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.

     In July 2006 our Board of Directors authorized a share repurchase program under which we may repurchase up to $500 million of our common shares in the open market or in privately negotiated transactions. Through December 31, 2009, $464.5 million of our common shares had been repurchased under this program. As of December 31, 2009, we had the capacity to repurchase up to an additional $35.5 million of our common shares under the July 2006 share repurchase program.

     See Note 16 — Commitments and Contingencies in Part II, Item 8. — Financial Statements and Supplementary Data for discussion of commitments and contingencies relating to (i) new employment agreements, effective April 1, 2009, that could result in significant cash payments of $100 million and $50 million to Messrs. Isenberg and Petrello, respectively, by the Company if their employment is terminated in the event of death or disability or cash payments of $100 million and $45 million to Messrs. Isenberg and Petrello, respectively, by the Company if their employment is terminated without cause or in the event of a change in control and (ii) off-balance sheet arrangements (including guarantees).

Financial Condition and Sources of Liquidity

     Our primary sources of liquidity are cash and cash equivalents, short-term and long-term investments and cash generated from operations. As of December 31, 2009, we had cash and investments of $1.2 billion (including $100.9 million of long-term investments and other receivables, inclusive of $92.5 million in oil and gas financing receivables) and working capital of $1.6 billion. Oil and gas financing receivables are classified as long-term investments. These receivables represent our financing agreements for certain production payment contracts in our Oil and Gas segment. This compares to cash and investments of $824.2 million (including $240.0 million of long-term investments and other receivables, inclusive of $224.2 million in oil and gas financing receivables) and working capital of $1.0 billion as of December 31, 2008.

     Our gross funded debt to capital ratio was 0.41:1 as of each December 31, 2009 and 2008. Our net funded debt to capital ratio was 0.33:1 as of December 31, 2009 and 0.35:1 as of December 31, 2008.

     The gross funded debt to capital ratio is calculated by dividing (x) funded debt by (y) funded debt plus deferred tax liabilities (net of deferred tax assets) plus capital. Funded debt is the sum of (1) short-term borrowings, (2) the current portion of long-term debt and (3) long-term debt. Capital is shareholders’ equity.

     The net funded debt to capital ratio is calculated by dividing (x) net funded debt by (y) net funded debt plus deferred tax liabilities (net of deferred tax assets) plus capital. Net funded debt is funded debt minus the sum of cash and cash equivalents and short-term and long-term investments and other receivables. Both of these ratios are used to calculate a company’s leverage in relation to its capital. Neither ratio measures operating performance or liquidity as defined by GAAP and, therefore, may not be comparable to similarly titled measures presented by other companies.

     Our interest coverage ratio was 6.3:1 as of December 31, 2009 and 21.0:1 as of December 31, 2008. The interest coverage ratio is a trailing 12-month quotient of the sum of income (loss) from continuing operations, net of tax, net income (loss) attributable to noncontrolling interest, interest expense, depreciation and amortization, depletion expense, impairments and other charges, income tax expense (benefit) and our proportionate share of writedowns from our unconsolidated oil and gas joint ventures less investment income (loss) divided by cash interest expense. This ratio is a method for calculating the amount of operating cash flows available to cover cash interest expense. The interest coverage ratio is not a measure of operating performance or liquidity defined by GAAP and may not be comparable to similarly titled measures presented by other companies.

     We had four letter of credit facilities with various banks as of December 31, 2009. Availability under our credit facilities as of December 31, 2009 was as follows:

(In thousands)
Credit available		$	245,442
Letters of credit outstanding, inclusive of financial and performance guarantees			(71,389	)
Remaining availability		$	174,053

     Our ability to access capital markets or to otherwise obtain sufficient financing is enhanced by our senior unsecured debt ratings as provided by Fitch Ratings, Moody’s Investors Service and Standard & Poor’s, which are currently “BBB+”, “Baa1” and “BBB+”, respectively, and our historical ability to access those markets as needed. While there can be no assurances that we will be able to access these markets in the future, we believe that we will be able to access capital markets or otherwise obtain financing in order to satisfy any payment obligation that might arise upon exchange or purchase of our notes and that any cash payment due of this magnitude, in addition to our other cash obligations, would not ultimately have a material adverse impact on our liquidity or financial position. In addition, Standard & Poor’s recently affirmed its BBB+ credit rating, but revised its outlook to negative from stable in early 2009 due primarily to worsening industry conditions. A credit downgrade may impact our ability to access credit markets.

     Our current cash and investments and projected cash flows from operations are expected to adequately finance our purchase commitments, our scheduled debt service requirements, and all other expected cash requirements for the next twelve months.

     See our discussion of the impact of changes in market conditions on our derivative financial instruments discussed under Item 7A. Quantitative and Qualitative Disclosures About Market Risk.

Off-Balance Sheet Arrangements (Including Guarantees)

     We are a party to some transactions, agreements or other contractual arrangements defined as “off-balance sheet arrangements” that could have a material future effect on our financial position, results of operations, liquidity and capital resources. The most significant of these off-balance sheet arrangements involve agreements and obligations under which we provide financial or performance assurance to third parties. Certain of these agreements serve as guarantees, including standby letters of credit issued on behalf of insurance carriers in conjunction with our workers’ compensation insurance program and other financial surety instruments such as bonds. We have also guaranteed payment of contingent consideration in conjunction with an acquisition in 2005. Potential contingent consideration is based on future operating results of the acquired business. In addition, we have provided indemnifications, which serve as guarantees, to some third parties. These guarantees include indemnification provided by Nabors to our share transfer agent and our insurance carriers. We are not able to estimate the potential future maximum payments that might be due under our indemnification guarantees.

     Management believes the likelihood that we would be required to perform or otherwise incur any material losses associated with any of these guarantees is remote. The following table summarizes the total maximum amount of financial guarantees issued by Nabors and guarantees representing contingent consideration in connection with a business combination:

		Maximum Amount
(In thousands)		2010				2011				2012				Thereafter				Total
Financial standby letters of credit and other financial surety instruments		$	66,182			$	10,808			$	277			$	—			$	77,267
Contingent consideration in acquisition			—				4,250				—				—				4,250
Total		$	66,182			$	15,058			$	277			$	—			$	81,517

Other Matters

     Recent Legislation and Actions

     In February 2009, Congress enacted the American Recovery and Reinvestment Act of 2009 (the “Stimulus Act”). The Stimulus Act is intended to provide a stimulus to the U.S. economy, including relief to companies related to income on debt repurchases and exchanges at a discount, expansion of unemployment benefits to former employees and other social welfare provisions. The Stimulus Act has not had a significant impact on our consolidated financial statements.

     A court in Algeria entered a judgment of approximately $19.7 million against us related to alleged customs infractions in 2009. We believe we did not receive proper notice of the judicial proceedings, and that the amount of the judgment is excessive. We have asserted the lack of legally required notice as a basis for challenging the judgment on appeal to the Algeria Supreme Court. Based upon our understanding of applicable law and precedent, we believe that this challenge will be successful. We do not believe that a loss is probable and have not accrued any amounts related to this matter. However, the ultimate resolution and the timing thereof are uncertain. If the Company is ultimately required to pay a fine or judgment related to this matter, the amount of the loss could range from approximately $140,000 to $19.7 million.

     Recent Accounting Pronouncements

     On July 1, 2009, the Financial Accounting Standards Board (“FASB”) released the Accounting Standards Codification (“ASC”). The ASC became the single source of authoritative nongovernmental GAAP. Rules and interpretive releases of the SEC under authority of federal securities laws are also sources of authoritative GAAP for SEC registrants. The ASC is not intended to change GAAP, but changes the approach by referencing authoritative literature by topic (each, a “Topic”) rather than by type of standard. Accordingly, references in the Notes to Consolidated Financial Statements to former FASB positions, statements, interpretations, opinions, bulletins or other pronouncements are now presented as references to the corresponding Topic in the ASC.

     Effective January 1, 2009, Nabors changed its method of accounting for certain of its convertible debt instruments in accordance with the revised provisions of the Debt with Conversions and Other Options Topic of the ASC. Additionally, Nabors changed its method for calculating its basic and diluted earnings per share using the two-class method in accordance with the revised provisions of the Earnings Per Share Topic of the ASC. As required by the Accounting Changes and Error Corrections Topic of the ASC, financial information and earnings per share calculations for prior periods have been adjusted to reflect retrospective application.

     The revised provisions of the Debt with Conversions and Other Options Topic clarify that convertible debt instruments that may be settled in cash upon conversion are accounted for with a liability component based on the fair value of a similar nonconvertible debt instrument and an equity component based on the excess of the initial proceeds from the convertible debt instrument over the liability component. Such excess represents proceeds related to the conversion option and is recorded as capital in excess of par value. The liability is recorded at a discount, which is then amortized as additional non-cash interest expense over the convertible debt instrument’s expected life. The retrospective application and impact of these provisions on our consolidated financial statements is described in Note 11 — Debt in Part II Item 8. — Financial Statements and Supplementary Data.

     The revised provisions relating to use of the two-class method for calculating earnings per share within the Earnings Per Share Topic provide that securities which are granted in share-based transactions are “participating securities” prior to vesting if they have a nonforfeitable right to participate in any dividends, and such securities therefore should be included in computing basic earnings per share. Our awards of restricted stock are considered participating securities under this definition. The retrospective application and impact of these provisions on our consolidated financial statements is set forth in Note 17 — Earnings (Losses) Per Share in Part II Item 8. — Financial Statements and Supplementary Data.

     Effective January 1, 2008, we adopted and applied the provisions of the Fair Value Measurements and Disclosures Topic of the ASC to our financial assets and liabilities and on January 1, 2009 applied the same provisions to our nonfinancial assets and liabilities. Effective April 1, 2009, we adopted the provisions of this Topic relating to fair value measures in inactive markets. The provisions provide additional guidance for determining whether a market for a financial asset is not active and a transaction is not distressed for fair value measurements. The application of these provisions did not have a material impact on our consolidated financial statements. Our fair value disclosures are provided in Note 5 — Fair Value Measurements in Part II Item 8. — Financial Statements and Supplementary Data.

     Effective January 1, 2009, we adopted the revised provisions of the Business Combinations Topic of the ASC and will apply those provisions on a prospective basis to acquisitions. The revised provisions retain the fundamental requirement that the acquisition method of accounting be used for all business combinations and expands the use of the acquisition method to all transactions and other events in which one entity obtains control over one or more other businesses or assets at the acquisition date and in subsequent periods. The revised provisions require measurement at the acquisition date of the fair value of assets acquired, liabilities assumed and any noncontrolling interests. Additionally, acquisition-related costs, including restructuring costs, are recognized as expense separately from the acquisition.

     Effective January 1, 2009, new provisions relating to noncontrolling interests of a subsidiary within the Identifiable Assets and Liabilities, and Any Noncontrolling Interest Topic of the ASC were released. The provisions establish the accounting and reporting standards for a noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. The provisions clarify that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. Our consolidated financial statements reflect the adoption and have been adjusted to reflect retrospective application. The application of these provisions did not have a material impact on our consolidated financial statements.

     Effective January 1, 2009, we adopted the revised provisions relating to expanded disclosures of derivatives within the Derivatives and Hedging Topic of the ASC. The revised provisions are intended to improve financial reporting about derivative instruments and hedging activities by requiring enhanced qualitative and quantitative disclosures regarding such instruments, gains and losses thereon and their effects on an entity’s financial position, financial performance and cash flows. The application of these provisions did not have a material impact on our consolidated financial statements.

     In December 2008, the SEC issued a Final Rule, “Modernization of Oil and Gas Reporting.” This rule revises 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 FASB issued revised guidance that substantially aligned the oil and gas accounting disclosures with the SEC’s Final Rule. The amendments are designed to modernize and update oil and gas disclosure requirements to align them with current practices and changes in technology. Additionally, this new accounting 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 new 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 are effective for registration statements filed on or after January 1, 2010 and for annual financial statements filed on or after January 1, 2010. 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 are considered with operating results from our unconsolidated oil and gas joint ventures, which we account for under the equity method of accounting, we have significant oil and gas activities under the new definition. In line with the one-year deferral, we will provide the oil and gas disclosures in annual periods beginning after December 31, 2009.

     Effective April 1, 2009, we adopted the provisions in the Investments of Debt and Equity Securities Topic of the ASC relating to recognition and presentation of other-than-temporary impairments to debt securities. The impact of these provisions is provided in Notes 3 — Impairments and Other Charges and 4 — Cash, Cash Equivalents and Investments in Part II Item 8. — Financial Statements and Supplementary Data.

     Effective June 30, 2009, we adopted the provisions in the Financial Instruments Topic of the ASC relating to quarterly disclosure of the fair value of financial instruments. The disclosures required by this Topic are provided in Note 5 — Fair Value Measurements in Part II Item 8. — Financial Statements and Supplementary Data.

     Effective June 30, 2009, we adopted the revised provisions in the Subsequent Events Topic of the ASC and evaluated subsequent events through the date of the release of our financial statements. The adoption of the Subsequent Events Topic of the ASC did not have any impact on our financial position, results of operations or cash flows.

Related-Party Transactions

     Nabors and its Chairman and Chief Executive Officer, its Deputy Chairman, President and Chief Operating Officer, and certain other key employees entered into split-dollar life insurance agreements, pursuant to which we paid a portion of the premiums under life insurance policies with respect to these individuals and, in some instances, members of their families. These agreements provide that we are reimbursed the premium payments upon the occurrence of specified events, including the death of an insured individual. Any recovery of premiums paid by Nabors could be limited to the cash surrender value of the policies under certain circumstances. As such, the values of these policies are recorded at their respective cash surrender values in our consolidated balance sheets. We have made premium payments to date totaling $11.7 million related to these policies. The cash surrender value of these policies of approximately $9.3 million and $8.4 million is included in other long-term assets in our consolidated balance sheets as of December 31, 2009 and 2008, respectively.

     Under the Sarbanes-Oxley Act of 2002, the payment of premiums by Nabors under the agreements with our Chairman and Chief Executive Officer and with our Deputy Chairman, President and Chief Operating Officer could be deemed to be prohibited loans by us to these individuals. Consequently, we have paid no premiums related to our agreements with these individuals since the adoption of the Sarbanes-Oxley Act.

     In the ordinary course of business, we enter into various rig leases, rig transportation and related oilfield services agreements with our unconsolidated affiliates at market prices. Revenues from business transactions with these affiliated entities totaled $327.3 million, $285.3 million and $153.4 million for the years ended December 31, 2009, 2008 and 2007, respectively. Expenses from business transactions with these affiliated entities totaled $9.8 million, $9.6 million and $6.6 million for the years ended December 31, 2009, 2008 and 2007, respectively. Additionally, we had accounts receivable from these affiliated entities of $104.2 million and $107.5 million as of December 31, 2009 and 2008, respectively. We had accounts payable to these affiliated entities of $14.8 million and $10.0 million as of

December 31, 2009 and 2008, respectively, and long-term payables with these affiliated entities of $.8 million and $7.8 million as of December 31, 2009 and 2008, respectively, which is included in other long-term liabilities.

     We own an interest in Shona Energy Company, LLC (“Shona”), a company of which Mr. Payne, an independent member of our Board of Directors, is the Chairman and Chief Executive Officer. During the fourth quarter of 2008, we purchased 1.8 million common shares of Shona for $.9 million. During the first quarter of 2010, we purchased shares of Shona’s preferred stock and warrants to purchase additional common shares for $.9 million. After these transactions, we hold a minority interest of approximately 11% of the issued and outstanding shares of Shona.

     Critical Accounting Estimates

     The preparation of our 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. We analyze our estimates based on our historical experience and various other assumptions that we believe to be reasonable under the circumstances. However, actual results could differ from our estimates. The following is a discussion of our critical accounting estimates. Management considers an accounting estimate to be critical if:

	•		it requires assumptions to be made that were uncertain at the time the estimate was made; and
	•		changes in the estimate or different estimates that could have been selected could have a material impact on our consolidated financial position or results of operations.

     For a summary of all of our significant accounting policies, see Note 2 — Summary of Significant Accounting Policies in Part II, Item 8. — Financial Statements and Supplementary Data.

     Financial Instruments. As defined in the ASC, fair value is the price that would be received upon a sale of an asset or paid upon a transfer of a liability in an orderly transaction between market participants at the measurement date (exit price). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market-corroborated, or generally unobservable. We primarily apply the market approach for recurring fair value measurements and endeavor to utilize the best information available. Accordingly, we employ valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The use of unobservable inputs is intended to allow for fair value determinations in situations where there is little, if any, market activity for the asset or liability at the measurement date. We are able to classify fair value balances utilizing a fair-value hierarchy based on the observability of those inputs. Under the fair-value hierarchy

	•		Level 1 measurements include unadjusted quoted market prices for identical assets or liabilities in an active market;
	•		Level 2 measurements include quoted market prices for identical assets or liabilities in an active market that have been adjusted for items such as effects of restrictions for transferability and those that are not quoted but are observable through corroboration with observable market data, including quoted market prices for similar assets; and
	•		Level 3 measurements include those that are unobservable and of a highly subjective measure.

     As part of adopting fair value measurement reporting on January 1, 2008, we did not have a transition adjustment to our retained earnings. Our enhanced disclosures are included in Note 5 — Fair Value Measurements in Part II, Item 8. — Financial Statements and Supplementary Data.

     Depreciation of Property, Plant and Equipment. The drilling, workover and well-servicing industries are very capital intensive. Property, plant and equipment represented 72% of our total assets as of December 31, 2009, and depreciation constituted 18% of our total costs and other deductions for the year ended December 31, 2009.

     Depreciation for our primary operating assets, drilling and workover rigs, is calculated based on 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 jack-up 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 jack-up rigs, where a 30-year depreciable life is typically used, after provision for salvage value.

     Depreciation on our buildings, well-servicing rigs, oilfield hauling and mobile equipment, marine transportation and supply vessels, aircraft equipment, 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; aircraft equipment — 5 to 20 years; oilfield hauling and mobile equipment and other machinery and equipment — 3 to 10 years).

     These depreciation periods and the salvage values of our property, plant and equipment were determined through an analysis of the useful lives of our assets and based on our experience with the salvage values of these assets. Periodically, we review our depreciation periods and salvage values for reasonableness given current conditions. Depreciation of property, plant and equipment is therefore based upon estimates of the useful lives and salvage value of those assets. Estimation of these items requires significant management judgment. Accordingly, management believes that accounting estimates related to depreciation expense recorded on property, plant and equipment are critical.

     There have been no factors related to the performance of our portfolio of assets, changes in technology or other factors that indicate that these estimates do not continue to be appropriate. Accordingly, for the years ended December 31, 2009, 2008 and 2007, no significant changes have been made to the depreciation rates applied to property, plant and equipment, the underlying assumptions related to estimates of depreciation, or the methodology applied. However, certain events could occur that would materially affect our estimates and assumptions related to depreciation. Unforeseen changes in operations or technology could substantially alter management’s assumptions regarding our ability to realize the return on our investment in operating assets and therefore affect the useful lives and salvage values of our assets.

     Impairment of Long-Lived Assets. As discussed above, the drilling, workover and well-servicing industry is very capital intensive. We review our assets for impairment 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. Such determination requires us to make judgments regarding long-term forecasts of future revenues and costs related to the assets subject to review in order to determine the future cash flows associated with the assets. These long-term forecasts are uncertain because they require assumptions about demand for our products and services, future market conditions, technological advances in the industry, and changes in regulations governing the industry. Significant and unanticipated changes to the assumptions could result in future impairments. 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.

     Assumptions made in the determination of future cash flows are made with the involvement of management personnel at the operational level where the most specific knowledge of market conditions and other operating factors exists. For the years ended December 31, 2009, 2008 and 2007, no significant changes have been made to the methodology utilized to determine future cash flows.

     Given the nature of the evaluation of future cash flows and the application to specific assets and specific times, it is not possible to reasonably quantify the impact of changes in these assumptions. A significantly prolonged period of lower oil and natural gas prices could continue to adversely affect the demand for and prices of our services, which could result in future impairment charges.

     Impairment of Goodwill and Intangible Assets. Goodwill represented 1.5% of our total assets as of December 31, 2009. 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 such goodwill and intangible assets exceed their fair value. We perform our impairment tests of goodwill and intangible assets for ten reporting units within our operating segments. These reporting units consist of our six contract drilling segments: U.S. Lower 48 Land Drilling, U.S. Land Well-servicing, U.S. Offshore, Alaska, Canada and International; our oil and gas segment; and three of our other operating segments: Canrig Drilling Technology Ltd., Ryan Energy Technologies

and Nabors Blue Sky Ltd. The impairment test involves comparing the estimated fair value of the reporting unit to its carrying amount. If the carrying amount of the reporting unit exceeds its fair value, a second step is required to measure the goodwill impairment loss. This second step compares the implied fair value of the reporting unit’s goodwill to the carrying amount of that goodwill. If the carrying amount of the reporting unit’s goodwill exceeds the implied fair value of the goodwill, an impairment loss is recognized in an amount equal to the excess. Our impairment test results required the second step measurement for one of our ten reporting units during 2009 and two of our ten reporting units during 2008.

     The fair values calculated in these impairment tests are determined using discounted cash flow models involving assumptions based on our utilization of rigs or aircraft, revenues and earnings from affiliates, as well as direct costs, general and administrative costs, depreciation, applicable income taxes, capital expenditures and working capital requirements. Our discounted cash flow projections for each reporting unit were based on financial forecasts. The future cash flows were discounted to present value using discount rates that are determined to be appropriate for each reporting unit. Terminal values for each reporting unit were calculated using a Gordon Growth methodology with a long-term growth rate of 3%. We believe the fair value estimated for purposes of these tests represent a Level 3 fair value measurement.

     During the years ended December 31, 2009 and 2008, we recognized goodwill impairments of approximately $14.7 million and $150.0 million, respectively, both related to our Canadian operations. During 2008, we impaired the entire goodwill balance of $145.4 million of our Canada Well-servicing and Drilling operating segment and recorded an impairment of $4.6 million to Nabors Blue Sky Ltd., one of our Canadian subsidiaries reported in our Other Operating segments. During 2009, we impaired the remaining goodwill balance of $14.7 million of Nabors Blue Sky Ltd. The impairment charges were deemed necessary due to the continued downturn in the oil and gas industry in Canada and the lack of certainty regarding eventual recovery in the value of these operations. This downturn has led to reduced capital spending by our customers and diminished demand for our drilling services and for immediate access to remote drilling sites. A significantly prolonged period of lower oil and natural gas prices could continue to 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.

     For the year ended December 31, 2007, our annual impairment test indicated the fair value of our reporting unit’s goodwill and intangible assets exceeded carrying amounts.

     Oil and Gas Properties. We follow the successful-efforts method of accounting for our consolidated subsidiaries’ oil and gas activities. Under the successful-efforts method, lease acquisition costs and all development costs are capitalized. Our provision for depletion is based on these capitalized costs and is determined on a property-by-property basis using the units-of-production method. Proved property acquisition costs are amortized over total proved reserves. Costs of wells and related equipment and facilities are amortized over the life of proved developed reserves. Estimated fair value of proved and unproved properties includes the estimated present value of all reasonably expected future production, prices, and costs. Proved oil and gas properties are reviewed when circumstances suggest the need for such a review and, are written down to their estimated fair value, if required. Unproved properties are reviewed to determine if there has been impairment of the carrying value and when circumstances suggest an impairment has occurred, are written down to their estimated fair value in that period. The estimated fair value of our proved reserves generally declines when there is a significant and sustained decline in oil and natural gas prices. For the years ended December 31, 2009, 2008 and 2007, our impairment tests on the oil and gas-related assets of our wholly owned Ramshorn business unit resulted in impairment charges of $197.7 million, $21.5 million and $41.0 million, respectively. As discussed above in Recent Accounting Pronouncements, we adopted new guidance relating to the manner in which our oil and gas reserves are estimated as of December 31, 2009.

     Exploratory drilling costs are capitalized until the results are determined. If proved reserves are not discovered, the exploratory drilling costs are expensed. Interest costs related to financing major oil and gas projects in progress are capitalized until the projects are evaluated or until the projects are substantially complete and ready for their intended use if the projects are evaluated as successful. Other exploratory costs are expensed as incurred.

     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 such 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. As discussed above in Recent Accounting Pronouncements and in relation to the full-cost ceiling test, our unconsolidated oil and gas joint ventures changed the manner in which their oil and gas reserves are estimated and the manner in which they calculate the ceiling limit on capitalized oil and gas costs as of December 31, 2009. Under the new guidance, 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 SEC rules. For the year ended December 31, 2009, our unconsolidated oil and gas joint ventures’ application of the full-cost ceiling test resulted in impairment charges, of which $189.3 million represented our proportionate share.

     For the years ended December 31, 2008 and 2007, our unconsolidated oil and gas joint ventures evaluated the full-cost ceiling using then-current prices for oil and natural gas, adjusted for the impact of derivatives accounted for as cash flow hedges. Our U.S., international and Canadian joint ventures’ application of the full-cost ceiling test resulted in impairment charges during 2008, of which $207.3 million represented our proportionate share. There were no ceiling test impairment charges recorded by our unconsolidated oil and gas joint ventures during 2007.

     A significantly prolonged period of lower oil and natural gas prices or reserve quantities could continue to adversely affect the demand for and prices of our services, which could result in future impairment charges due to the potential impact on our estimate of our future operating results.

     Income Taxes. Deferred taxes represent a substantial liability for Nabors. For financial reporting purposes, management determines our current tax liability as well as those taxes incurred as a result of current operations yet deferred until future periods. In accordance with the liability method of accounting for income taxes as specified in the Income Taxes Topic of the ASC, the provision for income taxes is the sum of income taxes both currently payable and deferred. Currently payable taxes represent the liability related to our income tax return for the current year while the net deferred tax expense or benefit represents the change in the balance of deferred tax assets or liabilities reported on our consolidated balance sheets. The tax effects of unrealized gains and losses on investments and derivative financial instruments are recorded through accumulated other comprehensive income (loss) within equity. The changes in deferred tax assets or liabilities are determined based upon changes in differences between the basis of assets and liabilities for financial reporting purposes and the basis of assets and liabilities for tax purposes as measured by the enacted tax rates that management estimates will be in effect when these differences reverse. Management must make certain assumptions regarding whether tax differences are permanent or temporary and must estimate the timing of their reversal, and whether taxable operating income in future periods will be sufficient to fully recognize any gross deferred tax assets. Valuation allowances are established to reduce deferred tax assets when it is more likely than not that some portion or all of the deferred tax assets will not be realized. In determining the need for valuation allowances, management has considered and made judgments and estimates regarding estimated future taxable income and ongoing prudent and feasible tax planning strategies. These judgments and estimates are made for each tax jurisdiction in which we operate as the calculation of deferred taxes is completed at that level. Further, under U.S. federal tax law, the amount and availability of loss carryforwards (and certain other tax attributes) are subject to a variety of interpretations and restrictive tests applicable to Nabors and our subsidiaries. The utilization of such carryforwards could be limited or effectively lost upon certain changes in ownership. Accordingly, although we believe substantial loss carryforwards are available to us, no assurance can be given concerning the realization of such loss carryforwards, or whether or not such loss carryforwards will be available in the future. These loss carryforwards are also considered in our calculation of taxes for each jurisdiction in which we operate. Additionally, we record reserves for uncertain tax positions that are subject to a significant level of management judgment related to the ultimate resolution of those tax positions. Accordingly, management believes that the estimate related to the provision for income taxes is critical to our results of operations. See Part I, Item 1A. — Risk Factors — We may have additional tax liabilities and Note 12 — Income Taxes in Part II, Item 8. — Financial Statements and Supplementary Data for additional discussion.

     Effective January 1, 2007, we adopted the revised provisions of the Income Taxes Topic in the ASC relating to uncertain tax positions. In connection with that adoption, we recognized increases to our tax reserves for uncertain tax positions along with interest and penalties as an increase to other long-term liabilities and as a reduction to retained earnings at January 1, 2007. See Note 12 — Income Taxes in Part II, Item 8. — Financial Statements and Supplementary Data for additional discussion.

     We are subject to income taxes in both the United States and numerous foreign jurisdictions. Significant judgment is required in determining our worldwide provision for income taxes. In the ordinary course of our business, there are many transactions and calculations where the ultimate tax determination is uncertain. We are regularly under audit by tax authorities. Although we believe our tax estimates are reasonable, the final determination of tax audits and any related litigation could be materially different than that reflected in historical income tax provisions and accruals. An audit or litigation could materially affect our financial position, income tax provision, net income, or cash flows in the period or periods challenged. However, certain events could occur that would materially affect management’s estimates and assumptions regarding the deferred portion of our income tax provision, including estimates of future tax rates applicable to the reversal of tax differences, the classification of timing differences as temporary or permanent, reserves recorded for uncertain tax positions, and any valuation allowance recorded as a reduction to our deferred tax assets. Management’s assumptions related to the preparation of our income tax provision have historically proved to be reasonable in light of the ultimate amount of tax liability due in all taxing jurisdictions.

     For the year ended December 31, 2009, our provision for income taxes from continuing operations was $(133.8) million, consisting of $69.5 million of current tax expense and $(203.3) million of deferred tax expense. Changes in management’s estimates and assumptions regarding the tax rate applied to deferred tax assets and liabilities, the ability to realize the value of deferred tax assets, or the timing of the reversal of tax basis differences could potentially impact the provision for income taxes and could potentially change the effective tax rate. A 1% change in the effective tax rate from 82.5% to 81.5% would increase the current year income tax provision by approximately $1.6 million.

     Self-Insurance Reserves. Our operations are subject to many hazards inherent in the drilling, workover and well-servicing industries, including blowouts, cratering, explosions, fires, loss of well control, loss of hole, damaged or lost drilling equipment and damage or loss from inclement weather or natural disasters. Any of these hazards could result in personal injury or death, damage to or destruction of equipment and facilities, suspension of operations, environmental damage and damage to the property of others. Generally, drilling contracts provide for the division of responsibilities between a drilling company and its customer, and we seek to obtain indemnification from our customers by contract for certain of these risks. To the extent that we are unable to transfer such risks to customers by contract or indemnification agreements, we seek protection through insurance. However, there is no assurance that such insurance or indemnification agreements will adequately protect us against liability from all of the consequences of the hazards described above. Moreover, our insurance coverage generally provides that we assume a portion of the risk in the form of a deductible or self-insured retention.

     Based on the risks discussed above, it is necessary for us to estimate the level of our liability related to insurance and record reserves for these amounts in our consolidated financial statements. Reserves related to self-insurance are based on the facts and circumstances specific to the claims and our past experience with similar claims. The actual outcome of self-insured claims could differ significantly from estimated amounts. We maintain actuarially determined accruals in our consolidated balance sheets to cover self-insurance retentions for workers’ compensation, employers’ liability, general liability and automobile liability claims. These accruals are based on certain assumptions developed utilizing historical data to project future losses. Loss estimates in the calculation of these accruals are adjusted based upon actual claim settlements and reported claims. These loss estimates and accruals recorded in our financial statements for claims have historically been reasonable in light of the actual amount of claims paid.

     Because the determination of our liability for self-insured claims is subject to significant management judgment and in certain instances is based on actuarially estimated and calculated amounts, and because such liabilities could be material in nature, management believes that accounting estimates related to self-insurance reserves are critical.

     For the years ended December 31, 2009, 2008 and 2007, no significant changes have been made to the methodology utilized to estimate insurance reserves. For purposes of earnings sensitivity analysis, if the December 31, 2009 reserves for insurance were adjusted (increased or decreased) by 10%, total costs and other deductions would change by $13.9 million, or .4%.

     Fair Value of Assets Acquired and Liabilities Assumed. We have completed a number of acquisitions in recent years as discussed in Note 5 — Fair Value Measurements in Part II, Item 8. — Financial Statements and

Supplementary Data. In conjunction with our accounting for these acquisitions, it was necessary for us to estimate the values of the assets acquired and liabilities assumed in the various business combinations using various assumptions. These estimates may be affected by such factors as changing market conditions, technological advances in the industry or changes in regulations governing the industry. The most significant assumptions, and the ones requiring the most judgment, involve the estimated fair values of property, plant and equipment, and the resulting amount of goodwill, if any. Unforeseen changes in operations or technology could substantially alter management’s assumptions and could result in lower estimates of values of acquired assets or of future cash flows. This could result in impairment charges being recorded in our consolidated statements of income (loss). As the determination of the fair value of assets acquired and liabilities assumed is subject to significant management judgment and a change in purchase price allocations could result in a material difference in amounts recorded in our consolidated financial statements, management believes that accounting estimates related to the valuation of assets acquired and liabilities assumed are critical.

     The determination of the fair value of assets and liabilities is based on the market for the assets and the settlement value of the liabilities. These estimates are made by management based on our experience with similar assets and liabilities. For the years ended December 31, 2009, 2008 and 2007, no significant changes have been made to the methodology utilized to value assets acquired or liabilities assumed. Our estimates of the fair values of assets acquired and liabilities assumed have proved to be reliable in the past.

     Given the nature of the evaluation of the fair value of assets acquired and liabilities assumed and the application to specific assets and liabilities, it is not possible to reasonably quantify the impact of changes in these assumptions.

     Share-Based Compensation. We have historically compensated our executives and employees, in part, with stock options and restricted stock. Based on the requirements of the Stock Compensation Topic of the ASC, we accounted for stock option and restricted stock awards in 2007, 2008 and 2009 using a fair-value based method, resulting in compensation expense for stock-based awards being recorded in our consolidated statements of income (loss). Determining the fair value of stock-based awards at the grant date requires judgment, including estimating the expected term of stock options, the expected volatility of our stock and expected dividends. In addition, judgment is required in estimating the amount of stock-based awards that are expected to be forfeited. Because the determination of these various assumptions is subject to significant management judgment and different assumptions could result in material differences in amounts recorded in our consolidated financial statements, management believes that accounting estimates related to the valuation of stock-based awards are critical.

     The assumptions used to estimate the fair market value of our stock options are based on historical and expected performance of our common shares in the open market, expectations with regard to the pattern with which our employees will exercise their options and the likelihood that dividends will be paid to holders of our common shares. For the years ended December 31, 2009, 2008 and 2007, no significant changes have been made to the methodology utilized to determine the assumptions used in these calculations.