Nabors Industries (NBR) 8-K Other Events

Exhibit 99.3

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 to our consolidated financial statements.

     Nabors is the largest land drilling contractor in the world. 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. Nabors also is one of the largest land well-servicing and workover contractors in the United States and Canada and is a leading provider of offshore platform workover and drilling rigs in the United States and multiple international markets. To further supplement and complement our primary business, we 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 selected domestic and international markets. We offer logistics services for onshore drilling in Canada using helicopter and fixed-winged 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 worldwide.

     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 a category labeled Oil and Gas for segment reporting purposes. 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 a category labeled Other Operating Segments for segment reporting purposes.

     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 the degree of their cash flow and earnings which are largely determined 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)
	2008		2007		2006		2008 to 2007				2007 to 2006
Commodity prices:
Average Henry Hub natural gas spot price ($/million cubic feet (mcf))	$	8.89	$	6.97	$	6.73	$	1.92	28	%	$	0.24	4	%
Average West Texas intermediate crude oil spot price ($/barrel)	$	99.92	$	72.23	$	66.09	$	27.69	38	%	$	6.14	9	%

     Beginning in the second half of 2008, there has been a significant decrease in natural gas and oil prices. Natural gas prices, which averaged $10.03 per mcf during the first half of 2008, declined significantly, averaging only $7.74 per mcf during the second half of 2008 and $5.84 per mcf during December 2008. The decline has continued as natural gas prices have averaged $4.96 per mcf during the period January 1, 2009 through February 23, 2009.

     Oil prices also declined in the second half of 2008 with average prices of $111.14 per barrel during the first half of 2008, decreasing to average prices of $88.88 per barrel during the second half of 2008 and $41.44 per barrel during December 2008. Oil prices remain depressed and have averaged $40.22 per barrel during the period January 1, 2009 through February 23, 2009.

     This significant decline in commodity prices has, at least in part, been driven by the significant deterioration of the global economic environment including the extreme volatility in the capital and credit markets. All of these factors are having an adverse

effect on our customers’ spending plans for exploration, production and development activities which has had a significant negative impact on our operations beginning in December 2008.

     Operating revenues and Earnings from unconsolidated affiliates for the year ended December 31, 2008 totaled $5.3 billion, representing an increase of $325.5 million, or 7% as compared to the year ended December 31, 2007. Adjusted income derived from operating activities and net income for the year ended December 31, 2008 totaled $1.0 billion and $475.7 million ($1.65 per diluted share), respectively, representing decreases of 15% and 45%, respectively, compared to the year ended December 31, 2007. Operating revenues and Earnings from unconsolidated affiliates for the year ended December 31, 2007 totaled $5.0 billion, representing an increase of $228.7 million, or 5% as compared to the year ended December 31, 2006. Adjusted income derived from operating activities and net income for the year ended December 31, 2007 totaled $1.2 billion and $865.7 million ($3.00 per diluted share), respectively, representing decreases of 13% and 11%, respectively, compared to the year ended December 31, 2006.

     Our operating results were negatively impacted as a result of non-cash, pre-tax charges arising from oil and gas full cost ceiling test writedowns and goodwill and intangible asset impairments. Our Earnings (losses) from Unconsolidated Affiliates line in our income statement includes $228.3 million, representing our proportionate share of non-cash pre-tax full cost ceiling test writedowns from our U.S., international and Canadian joint ventures during the three months ended December 31, 2008. Additionally, we recorded non-cash pre-tax impairment charges of $21.5 million related to our wholly owned Ramshorn business unit under application of the successful efforts method of accounting related to oil and gas properties during the three months ended December 31, 2008. Charges from our U.S., international and Canadian joint ventures and our wholly owned Ramshorn business unit are included in our Oil and Gas operating segment results. Our Canada Well-servicing and Drilling operating segment and Nabors Blue Sky Ltd., one of our Canadian subsidiaries reported in our Other Operating Segments include $145.4 million and $4.6 million non-cash pre-tax goodwill and intangible asset impairment charges to reduce the carrying value of these assets to their estimated fair value due to the duration of the economic downturn in Canada and the lack of certainty regarding eventual recovery. Excluding these charges, our operating results were slightly higher primarily due to our U.S. Lower 48 Land Drilling, International Drilling and Other Operating segments resulting from higher average dayrates and activity levels resulting from sustained higher natural gas and oil prices throughout 2007 and the majority of 2008, partially offset by increased operating costs and higher depreciation expense due to our capital expenditures.

     The decrease in our adjusted income derived from operating activities from 2006 to 2007 related primarily to our U.S. Lower 48 Land Drilling, Canada Drilling and Well-servicing, and our U.S. Well-servicing operations, where activity levels decreased despite slightly higher natural gas prices and higher oil prices. Operating results were further negatively impacted by higher levels of depreciation expense due to our capital expenditures. Partially offsetting the decreases in our adjusted income derived from operating activities were the increases in operating results from our International operations and to a lesser extent by our Alaska operations, driven by high oil prices. In addition, our net income and earnings per share for 2007 has decreased compared to 2006 as a result of investment net losses during 2007 only partially offset by a lower effective tax rate and a lower number of average shares outstanding.

     Our operating results for 2009 are expected to decrease from levels realized during 2008 given our current expectation of the continuation of lower commodity prices during 2009 and the related impact on drilling and well-servicing activity and dayrates. The decrease in drilling activity and dayrates is expected to have a significant impact on our U.S. Lower 48 Land Drilling and our U.S. Land Well-servicing operations. In our U.S. Lower 48 Land Drilling operations, our rig count has decreased from its peak during October 2008 of 273 rigs to 162 rigs currently operating as of February 23, 2009. Our Well-servicing activity is down approximately 45% from its October 2008 peak of 105,872 hours when compared to estimated rig hours for February 2009. We expect our International operations to increase during 2009 resulting from the deployment of additional rigs under long-term contracts and the renewal of existing contracts at higher dayrates.

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

2

(In thousands, except percentages	Year Ended December 31,									Increase/(Decrease)
and rig activity)	2008			2007			2006			2008 to 2007					2007 to 2006
Reportable segments:
Operating revenues and Earnings (losses) from unconsolidated affiliates from continuing operations:(1)
Contract Drilling:(2)
U.S. Lower 48 Land Drilling	$	1,878,441		$	1,710,990		$	1,890,302		$	167,451		10	%	$	(179,312	)	(9	%)
U.S. Land Well-servicing		758,510			715,414			704,189			43,096		6	%		11,225		2	%
U.S. Offshore		252,529			212,160			221,676			40,369		19	%		(9,516	)	(4	%)
Alaska		184,243			152,490			110,718			31,753		21	%		41,772		38	%
Canada		502,695			545,035			686,889			(42,340	)	(8	%)		(141,854	)	(21	%)
International		1,372,168			1,094,802			746,460			277,366		25	%		348,342		47	%
Subtotal Contract Drilling(3)		4,948,586			4,430,891			4,360,234			517,695		12	%		70,657		2	%
Oil and Gas(4) (5)		(151,465	)		152,320			59,431			(303,785	)	(199	%)		92,889		156	%
Other Operating Segments(6)(7)		683,186			588,483			505,286			94,703		16	%		83,197		16	%
Other reconciling items(8)		(198,245	)		(215,122	)		(197,117	)		16,877		8	%		(18,005	)	(9	%)
Total	$	5,282,062		$	4,956,572		$	4,727,834		$	325,490		7	%	$	228,738		5	%
Adjusted income (loss) derived from operating activities from continuing operations:(1)(9)
Contract Drilling:
U.S. Lower 48 Land Drilling	$	628,579		$	596,302		$	821,821		$	32,277		5	%	$	(225,519	)	(27	%)
U.S. Land Well-servicing		148,626			156,243			199,944			(7,617	)	(5	%)		(43,701	)	(22	%)
U.S. Offshore		59,179			51,508			65,328			7,671		15	%		(13,820	)	(21	%)
Alaska		52,603			37,394			17,542			15,209		41	%		19,852		113	%
Canada		61,040			87,046			185,117			(26,006	)	(30	%)		(98,071	)	(53	%)
International		407,675			332,283			208,705			75,392		23	%		123,578		59	%
Subtotal Contract Drilling(3)		1,357,702			1,260,776			1,498,457			96,926		8	%		(237,681	)	(16	%)
Oil and Gas(4)(5)		(228,027	)		56,133			4,065			(284,160	)	(506	%)		52,068		n/m	(6)
Other Operating Segments(7)(8)		68,572			35,273			30,028			33,299		94	%		5,245		17	%
Other reconciling items(11)		(167,831	)		(138,302	)		(136,655	)		(29,529	)	(21	%)		(1,647	)	(1	%)
						��
Total		1,030,416			1,213,880			1,395,895			(183,464	)	(15	%)		(182,015	)	(13	%)
Interest expense		(196,718	)		(154,920	)		(120,507	)		(41,798	)	(27	%)		(34,413	)	(29	%)
Investment (loss) income		21,726			(15,891	)		102,007			37,617		237	%		(117,898	)	(116	%)
(Losses) gains on sales, retirements and impairments of long-lived assets and other income (expense), net		(18,954	)		(10,895	)		(24,118	)		(8,059	)	(74	%)		13,223		55	%
Goodwill and intangible asset impairment(12)		(154,586	)		—			—			(154,586	)	(100	%)		—		—
Income from continuing operations before income taxes	$	681,884		$	1,032,174		$	1,353,277		$	(350,290	)	(34	%)	$	(321,103	)	(24	%)
Rig activity:
Rig years:(13)
U.S. Lower 48 Land Drilling		247.9			229.4			255.5			18.5		8	%		(26.1	)	(10	%)
U.S. Offshore		17.6			15.8			16.4			1.8		11	%		(0.6	)	(4	%)
Alaska		10.9			8.7			8.6			2.2		25	%		0.1		1	%
Canada		35.5			36.7			53.3			(1.2	)	(3	%)		(16.6	)	(31	%)
International(14)		120.5			115.2			97.1			5.3		5	%		18.1		19	%
Total rig years		432.4			405.8			430.9			26.6		7	%		(25.1	)	(6	%)
Rig hours:(15)
U.S. Land Well-servicing		1,090,511			1,119,497			1,256,141			(28,986	)	(3	%)		(136,644	)	(11	%)
Canada Well-servicing		248,032			283,471			360,129			(35,439	)	(13	%)		(76,658	)	(21	%)
Total rig hours		1,338,543			1,402,968			1,616,270			(64,425	)	(5	%)		(213,302	)	(13	%)

(1)	All segment information excludes the Sea Mar business, which has been classified as a discontinued operation.
(2)	These segments include our drilling, workover and well-servicing operations, on land and offshore.

3

(3)	Includes earnings (losses), net from unconsolidated affiliates, accounted for by the equity method, of $5.8 million, $5.6 million and $4.0 million for the years ended December 31, 2008, 2007 and 2006, respectively.
(4)	Represents our oil and gas exploration, development and production operations. Includes $228.3 million, representing our proportionate share, of non-cash pre-tax full cost ceiling test writedowns from our U.S., international and Canadian joint ventures and non-cash pre-tax impairment charges of $21.5 million under application of the successful efforts method of accounting from our wholly owned Ramshorn business unit related to oil and gas properties.
(5)	Includes earnings (losses), net from unconsolidated affiliates, accounted for by the equity method, of $(241.4) million, $(3.9) million and $0 for the years ended December 31, 2008, 2007 and 2006, respectively.
(6)	The percentage is so large that it is not meaningful.
(7)	Includes our drilling technology and top drive manufacturing, directional drilling, rig instrumentation and software, and construction and logistics operations.
(8)	Includes earnings (losses), net from unconsolidated affiliates, accounted for by the equity method, of $5.8 million, $16.0 million and $16.5 million for the years ended December 31, 2008, 2007 and 2006, respectively.
(9)	Represents the elimination of inter-segment transactions.
(10)	Adjusted income derived from operating activities is computed by: subtracting direct costs, general and administrative expenses, depreciation and amortization, and depletion expense from Operating revenues and then adding Earnings from unconsolidated affiliates. Such amounts should not be used as a substitute to those amounts reported under GAAP. However, management evaluates the performance of our business units and the consolidated company based on several criteria, including adjusted income derived from operating activities, because it believes that this financial measure is an accurate reflection of the ongoing profitability of our Company. A reconciliation of this non-GAAP measure to income from continuing operations before income taxes, which is a GAAP measure, is provided within the above table.
(11)	Represents the elimination of inter-segment transactions and unallocated corporate expenses.
(12)	Represents non-cash pre-tax goodwill and intangible asset impairment charges recorded during the three months ended December 31, 2008, all of which related to our Canadian business units.
(13)	Excludes well-servicing rigs, which are measured in rig hours. Includes our equivalent percentage ownership of rigs owned by unconsolidated affiliates. Rig years represent a measure of the number of equivalent rigs operating during a given period. For example, one rig operating 182.5 days during a 365-day period represents 0.5 rig years.
(14)	International rig years include our equivalent percentage ownership of rigs owned by unconsolidated affiliates which totaled 3.5 years during the year ended December 31, 2008 and 4.0 years during the years ended December 31, 2007 and 2006, respectively.
(15)	Rig hours represents the number of hours that our well-servicing rig fleet operated during the year.

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)	2008		2007		2006		2008 to 2007				2007 to 2006
Operating revenues and Earnings from unconsolidated affiliates	$	1,878,441	$	1,710,990	$	1,890,302	$	167,451	10	%	$	(179,312	)	(9	%)
Adjusted income derived from operating activities	$	628,579	$	596,302	$	821,821	$	32,277	5	%	$	(225,519	)	(27	%)
Rig years		247.9		229.4		255.5		18.5	8	%		(26.1	)	(10	%)

4

     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.

     The decrease in operating results from 2006 to 2007 was a result of year-over-year decreases in drilling activity. Additionally, the decrease in operating results was due to higher drilling rig operating costs, including 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)	2008		2007		2006		2008 to 2007					2007 to 2006
Operating revenues and Earnings from unconsolidated affiliates	$	758,510	$	715,414	$	704,189	$	43,096		6	%	$	11,225		2	%
Adjusted income derived from operating activities	$	148,626	$	156,243	$	199,944	$	(7,617	)	(5	%)	$	(43,701	)	(22	%)
Rig hours		1,090,511		1,119,497		1,256,141		(28,986	)	(3	%)		(136,644	)	(11	%)

     Operating revenues and Earnings from unconsolidated affiliates increased from 2007 to 2008 and from 2006 to 2007 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 and from 2006 to 2007 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)	2008		2007		2006		2008 to 2007				2007 to 2006
Operating revenues and Earnings from unconsolidated affiliates	$	252,529	$	212,160	$	221,676	$	40,369	19	%	$	(9,516	)	(4	%)
Adjusted income derived from operating activities	$	59,179	$	51,508	$	65,328	$	7,671	15	%	$	(13,820	)	(21	%)
Rig years		17.6		15.8		16.4		1.8	11	%		(0.6	)	(4	%)

     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.

     The decrease in operating results from 2006 to 2007 primarily resulted from a decrease in average dayrates and utilization for our jack-up rigs, partially offset by the deployment of two new-built Barge and one Platform Workover Drilling rigs in early 2007. Operating results were further negatively impacted by increased depreciation expense relating to the new rigs added to the fleet.

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

(In thousands, except percentages	Year Ended December 31,						Increase
and rig activity)	2008		2007		2006		2008 to 2007				2007 to 2006
Operating revenues and Earnings from unconsolidated affiliates	$	184,243	$	152,490	$	110,718	$	31,753	21	%	$	41,772	38	%
Adjusted income derived from operating activities	$	52,603	$	37,394	$	17,542	$	15,209	41	%	$	19,852	113	%
Rig years		10.9		8.7		8.6		2.2	25	%		0.1	1	%

     The increase in operating results from 2007 to 2008 and from 2006 to 2007 is primarily due to year-over-year increases in average dayrates and drilling activity. Drilling activity levels have increased as a result of year-over-year increased customer demand, driven by higher oil prices throughout 2007 and most of 2008, and the deployment and utilization of additional rigs added in late 2007. These increases have been partially offset by higher operating costs and increased depreciation expense as well as increased labor and repairs and maintenance costs in 2008 and 2007 as compared to prior years.

5

     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)	2008		2007		2006		2008 to 2007					2007 to 2006
Operating revenues and Earnings from unconsolidated affiliates	$	502,695	$	545,035	$	686,889	$	(42,340	)	(8	%)	$	(141,854	)	(21	%)
Adjusted income derived from operating activities	$	61,040	$	87,046	$	185,117	$	(26,006	)	(30	%)	$	(98,071	)	(53	%)
Rig years — Drilling		35.5		36.7		53.3		(1.2	)	(3	%)		(16.6	)	(31	%)
Rig hours — Well-servicing		248,032		283,471		360,129		(35,439	)	(13	%)		(76,658	)	(21	%)

     The decrease in operating results from 2007 to 2008 and from 2006 to 2007 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 resulting in 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. Operating results exclude non-cash pre-tax goodwill and intangible asset impairment charges that are separately reflected in the Goodwill and Intangible Asset Impairment financial line in our consolidated statements of income.

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

(In thousands, except percentages	Year Ended December 31,						Increase
and rig activity)	2008		2007		2006		2008 to 2007				2007 to 2006
Operating revenues and Earnings from unconsolidated affiliates	$	1,372,168	$	1,094,802	$	746,460	$	277,366	25	%	$	348,342	47	%
Adjusted income derived from operating activities	$	407,675	$	332,283	$	208,705	$	75,392	23	%	$	123,578	59	%
Rig years		120.5		115.2		97.1		5.3	5	%		18.1	19	%

     The increase in operating results from 2007 to 2008 and from 2006 to 2007 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 and most of 2008. The increases in operating results during 2007 and 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 are 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

     This operating segment represents our oil and gas exploration, development and production operations. The results of operations for this reportable segment are as follows:

	Year Ended December 31,							Increase/(Decrease)
(In thousands, except percentages)	2008			2007		2006		2008 to 2007					2007 to 2006
Operating revenues and Earnings (losses) from unconsolidated affiliates	$	(151,465	)	$	152,320	$	59,431	$	(303,785	)	(199	%)	$	92,889	156	%
Adjusted income derived from operating activities	$	(228,027	)	$	56,133	$	4,065	$	(284,160	)	(506	%)	$	52,068	n/m	(1)

(1) The percentage is so large that it is not meaningful.

     Operating results decreased from 2007 to 2008 as a result of non-cash pre-tax impairment charges recorded during the fourth quarter of 2008 by our wholly owned Ramshorn business unit and our U.S., international and Canadian joint ventures. Because of the low natural gas prices at year end, we performed an impairment test on our oil and gas properties of our wholly owned Ramshorn business unit which follows the successful efforts method of accounting. As a result, we recorded a non-cash pre-tax impairment to oil and gas properties which totaled $21.5 million. Our joint ventures’ non-cash pre-tax full cost ceiling test writedowns, of which our proportionate share totaled $228.3 million, 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 is evaluated at the end of each quarter using quarter end prices of oil and

6

natural gas, adjusted for the impact of derivatives accounted for as cash flow hedges. Our U.S., international and Canadian joint ventures used a quarter end price of $5.63 per mcf for natural gas and $44.60 per barrel for oil which resulted in the ceiling test writedowns.

     Additionally, our proportionate share of losses from our 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 their forward contracts to minimize the volatility in reported earnings caused by market price fluctuations of the underlying hedged commodities. While our wholly owned Ramshorn business unit recorded approximately $21.5 million in non-cash pre-tax impairment charges to oil and gas properties, the charge was 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 certain leasehold interests in 2008.

     The increase in our operating results from 2006 to 2007 was primarily a result of year-over-year increases in income attributable to earnings related to production payment contracts and gains totaling $88 million recognized on the sale of certain properties during 2007. Additionally, operating results were higher year-over-year due to increases in production and increases in oil, gas and natural gas liquid prices. These increases to operating results were partially offset by a $33.6 million increase in depletion expense and approximately $3.9 million in net losses from our joint ventures which commenced operations in 2007, as well as higher seismic costs and workover expenses compared to the prior year. The higher depletion expense resulted from increased units-of-production depletion and impairment charges, related to higher costs and lower than expected performance of certain oil and gas developmental wells.

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
(In thousands, except percentages)	2008		2007		2006		2008 to 2007				2007 to 2006
Operating revenues and Earnings from unconsolidated affiliates	$	683,186	$	588,483	$	505,286	$	94,703	16	%	$	83,197	16	%
Adjusted income (loss) derived from operating activities	$	68,572	$	35,273	$	30,028	$	33,299	94	%	$	5,245	17	%

     The increase in operating results from 2007 to 2008 and from 2006 to 2007 primarily resulted from year-over-year increased third party sales and higher margins on top drives driven by the strengthening of the oil drilling market and increased equipment sales and increased market share in Canada and increased demand in the U.S. directional drilling market. Results for construction and logistics services increased from 2007 to 2008 due to increases in customer demand for our construction and logistics services in Alaska but decreased from 2006 to 2007 due to lower demand for our services.

Discontinued Operations

     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 of this business 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 Sea Mar business for the years ended December 31, 2008, 2007 and 2006 were as follows:

	Year Ended December 31,						Increase/(Decrease)
(In thousands, except percentages)	2008		2007		2006		2008 to 2007					2007 to 2006
Revenues	$	—	$	58,887	$	112,873	$	(58,887	)	(100	%)	$	(53,986	)	(48	%)
Income from discontinued operations, net of tax	$	—	$	35,024	$	27,727	$	(35,024	)	(100	%)	$	7,297		26	%

     The decrease in revenues from 2006 to 2007 resulted from seven months of operations before our sale of the Sea Mar business in August 2007. The increase in income, net of tax, from 2006 to 2007 resulted from the gain recognized on the sale.

7

OTHER FINANCIAL INFORMATION

General and administrative expenses

	Year Ended December 31,									Increase/(Decrease)
(In thousands, except percentages)	2008			2007			2006			2008 to 2007					2007 to 2006
General and administrative expenses	$	479,984		$	436,282		$	416,610		$	43,702		10	%	$	19,672		5	%
General and administrative expenses as a percentage of operating revenues		8.7	%		8.8	%		8.9	%		(.1	%)	(1	%)		(.1	%)	(1	%)

     General and administrative expenses increased from 2007 to 2008 and from 2006 to 2007 primarily as a result of increases in wages and burden for a majority of our operating segments compared to each prior year period, which resulted from an increase in the number of employees required to support the increase in activity levels and from higher wages, and increased corporate compensation expense, which primarily resulted from higher bonuses and non-cash compensation expenses recorded for restricted stock awards during each sequential year. During the fourth quarter of 2006 a non-recurring non-cash charge representing additional compensation expense of $51.6 million was recorded relating to the Company’s review of its employee stock option granting practices.

Depreciation and amortization, and depletion expense

	Year Ended December 31,						Increase/(Decrease)
(In thousands, except percentages)	2008		2007		2006		2008 to 2007					2007 to 2006
Depreciation and amortization expense	$	614,367	$	469,669	$	365,357	$	144,698		31	%	$	104,312	29	%
Depletion expense	$	46,979	$	72,182	$	38,580	$	(25,203	)	(35	%)	$	33,602	87	%

     Depreciation and amortization expense.Depreciation and amortization expense increased from 2007 to 2008 and from 2006 to 2007 as a result of capital expenditures made throughout 2006, 2007 and 2008 relating to our expanded capital expenditure program that commenced in early 2005.

     Depletion expense.The decrease in depletion expense from 2007 to 2008 primarily resulted from a decrease of non-cash impairment charges of $37.9 million during 2007 compared to $21.5 million during 2008.

     Depletion expense increased from 2006 to 2007 as a result of increased units-of-production depletion and impairment charges resulting from higher costs and lower than expected performance of certain oil and gas developmental wells.

Interest expense

	Year Ended December 31,						Increase
(In thousands, except percentages)	2008		2007		2006		2008 to 2007				2007 to 2006
Interest expense	$	196,718	$	154,920	$	120,507	$	41,798	27	%	$	34,413	29	%

     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.

     Interest expense increased from 2006 to 2007 as a result of the additional interest expense related to the May 2006 issuance of the $2.75 billion 0.94% senior exchangeable notes due 2011. This increase was partially offset by interest expense reductions resulting from the redemption of 93% or $769.8 million of our zero coupon convertible senior debentures due 2021 on February 6, 2006. These zero coupon notes accreted at a rate of 2.5% per annum.

Investment income (loss)

	Year Ended December 31,							Increase/(Decrease)
(In thousands, except percentages)	2008		2007			2006		2008 to 2007				2007 to 2006
Investment income (loss)	$	21,726	$	(15,891	)	$	102,007	$	37,617	237	%	$	(117,898	)	(116	%)

     Investment income during 2008 was $21.7 million compared to a net loss of $15.9 million during the prior year. The current year income 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.

8

     Investment income (loss) during 2007 was a net loss of $15.9 million compared to income of $102.0 million during the prior year. The loss during 2007 included a net loss of $61.4 million from the portion of our long-term investments comprised of actively managed funds inclusive of substantial gains from sales of our marketable equity securities. Investment income from our short-term investments was approximately $45.5 million.

     Investment income during 2006 included net unrealized gains of $3.1 million from our short-term investments, interest and dividend income of $55.7 million and gains of $43.2 million from our actively managed funds.

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

	Year Ended December 31,									Increase/(Decrease)
(In thousands, except percentages)	2008			2007			2006			2008 to 2007					2007 to 2006
Gains (losses) on sales, retirements and impairments of long-lived assets and other income (expense), net	$	(18,954	)	$	(10,895	)	$	(24,118	)	$	(8,059	)	(74	%)	$	13,223	55	%

     The amount of gains (losses) on sales, retirements and impairments of long-lived assets and other income (expense), net for 2008 represents a net loss of $19.0 million and includes: (1) 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, (2) losses on retirements and impairment charges 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 (3) losses resulting from increases to litigation reserves 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 our $2.75 billion 0.94% senior exchangeable notes due 2011.

     The amount of gains (losses) on sales, retirements and impairments of long-lived assets and other income (expense), net for 2007 represents a net loss of $10.9 million and includes: (1) losses on retirements and impairment charges on long-lived assets of approximately $40.0 million and (2) losses resulting from increases to litigation reserves 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.

Goodwill and intangible asset impairment

	Year Ended December 31,
(In thousands, except percentages)	2008		2007	2006
Goodwill and intangible asset impairment	$	154,586	—	—

     Our goodwill impairment for the year ended December 31, 2008 is comprised of $145.4 million and $4.6 million, respectively, relating to our Canada Well-servicing and Drilling operating segment and Nabors Blue Sky Ltd., one of our Canadian subsidiaries reported in our Other Operating Segments. The non-cash impairment charges were determined necessary due to the duration of the economic downturn in Canada and the lack of certainty regarding eventual recovery in valuing these operations. Additionally, we recorded a non-cash impairment to intangible assets of $4.6 million which related to certain rights and licenses for a helicopter by Blue Sky, Ltd. A prolonged period of lower oil and natural gas prices and its potential impact on our financial results could result in future goodwill impairment charges. See Critical Accounting Policies below and Note 2 (included under the caption “Goodwill”) in Part II, Item 8. — Financial Statements and Supplementary Data.

Income tax rate

	Year Ended December 31,
	2008			2007			2006
Effective income tax rate from continuing operations		30	%		20	%		30	%

     The increase in our effective income tax rate from 2007 to 2008 resulted from (1) our goodwill impairments that 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 taxable income being generated in the United States during 2008 which is generally taxed at a higher rate than in the international jurisdictions in which we operate.

     The decrease in our effective income tax rate from 2006 to 2007 is a direct result of (1) the reversal of certain tax reserves during 2007 in the amount of $25.5 million, (2) a decrease in tax expense of approximately $16.0 million resulting from a reduction in Canadian tax rates, and (3) a decrease in the proportion of income generated in the U.S. versus the international jurisdictions in which

9

we operate. During 2006, a tax expense relating to the redemption of common shares held by a foreign parent of a U.S. based Nabors’ subsidiary in the amount of $36.2 million increased taxes while a reduction in Canadian tax rates decreased tax expense in the amount of $20.5 million.

     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 which is reflected in our income tax provisions and accruals. Based on the results of an audit or litigation, a material effect on our financial position, income tax provision, net income, or cash flows in the period or periods for which that determination is made could result.

     Various bills have been introduced in Congress which 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 shall be treated as a domestic corporation for United States federal income tax purposes. Nabors’ reorganization was completed June 24, 2002. There has been and we expect that there may continue to be legislation proposed by Congress from time to time applicable to certain companies that completed such reorganizations on or after March 20, 2002 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 have an impact on our ability to realize the tax savings recorded to date as well as future tax savings resulting from our reorganization.

     We expect our effective tax rate during 2009 to be in the 25-28% range. We are subject to income taxes in the U.S. and numerous foreign jurisdictions. One of the most volatile factors in this determination is the relative proportion of our income being recognized in high versus low tax jurisdictions.

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, 2008 and 2007.

     Operating Activities.Net cash provided by operating activities totaled $1.5 billion during 2008 compared to net cash provided by operating activities of $1.4 billion during 2007. During 2008, net income was increased for non-cash items, such as depreciation and amortization, depletion, share-based compensation, deferred income taxes, our proportionate share of losses from unconsolidated affiliates and goodwill and intangible asset impairments and was reduced for changes in our working capital and other balance sheet accounts. During 2007, net income was increased for non-cash items, such as depreciation and amortization, depletion, share-based compensation and was reduced for deferred income taxes, changes in our working capital and other balance sheet accounts.

     Investing Activities.Net cash used for investing activities totaled $1.5 billion during 2008 compared to net cash used for investing activities of $1.5 billion during 2007. During 2008 and 2007, cash was used for capital expenditures totaling $1.5 billion and $2.0 billion, respectively, and investment in unconsolidated affiliates totaling $271.3 million and $278.1 million, respectively. During 2008 and 2007, cash was provided by sales of investments, net of purchases, totaling $251.6 million and $482.1 million, respectively. During 2007, cash was provided from the sale of long-lived assets and from the sale of our Sea Mar business totaling $162.1 million and $194.3 million, respectively.

     Financing Activities.Net cash used for financing activities totaled $89.2 million during 2008 compared to net cash used for financing activities of $78.9 million during 2007. During 2008, cash totaling $836.5 million was used to redeem our $700 million zero coupon senior exchangeable notes due 2023 and our $82.8 million zero coupon senior convertible debentures due 2021 and for the purchase of $100 million par value of our $2.75 billion 0.94% senior exchangeable notes due 2011 in the open market. During 2008 and 2007, cash was used to repurchase our common shares totaling $281.1 million and $102.5 million, respectively. During 2008, cash was provided by the receipt of $955.6 million in proceeds, net of debt issuance costs, from the February and July 2008 issuances of our $575 million and $400 million 6.15% senior notes due 2018, respectively. During 2008 and 2007, cash was provided

10

by our receipt of proceeds totaling $56.6 million and $61.6 million, respectively, from the exercise by our employees of options to acquire our common shares.

Future Cash Requirements

     As of December 31, 2008, we had long-term debt, including current maturities, of $3.8 billion and cash and cash equivalents and investments of $826.1 million, including $240.0 million of long-term investments and other receivables. Long-term investments and other receivables include $224.2 million in oil and gas financing receivables.

     Our $225 million 4.875% senior notes are coming due in August 2009 and have been reclassified from long-term debt to current portion of long-term debt in our balance sheet as of September 30, 2008. During January and through February 23, 2009, we repurchased $56.6 million par value of these senior notes for cash totaling $56.8 million.

     Our $2.75 billion 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 23, 2009, the market price for our shares closed at $9.14. 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, 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 that the price of our shares were to exceed $59.57 for the required period of time that 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.

     During the fourth quarter of 2008 we purchased $100 million par value of our $2.75 billion 0.94% senior exchangeable notes due 2011 in the open market, leaving $2.65 billion par value outstanding at December 31, 2008. In January and through February 23, 2009, we purchased an additional $427.7 million par value of our $2.75 billion 0.94% senior exchangeable notes due 2011 in the open market for cash totaling $370.6 million, leaving $2.22 billion par value outstanding.

     As of December 31, 2008, we had outstanding purchase commitments of approximately $685.3 million, primarily for rig-related enhancing, construction and sustaining capital expenditures and other operating expenses. Total capital expenditures over the next twelve months, including these outstanding purchase commitments, are currently expected to be approximately $1.0-1.2 billion, including currently planned rig-related enhancing, 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 or planned. These programs 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. Since expanding our capital expenditure program in 2005, we have added 168 new land drilling rigs, 15 offshore rigs and 116 newly built workover and well-servicing rigs to our fleet. Our expansion of our capital expenditure programs to build new state-of-the-art drilling rigs is expected to impact 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 issuance of 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 under Off-Balance Sheet Arrangements (Including Guarantees).

     The following table summarizes our contractual cash obligations as of December 31, 2008. This table does not include the issue of $1.125 billion 9.25% senior notes due 2019 on January 12, 2009 nor any open market purchases of any of our notes that have occurred since December 31, 2008.

11

	Payments due by Period
(In thousands)	Total		< 1 Year			1-3 Years			3-5 Years			Thereafter			Other
Contractual cash obligations:
Long-term debt:(1)
Principal	$	4,126,008	$	225,288	(2)	$	2,650,553	(3)	$	275,167	(4)	$	975,000	(5)	$	—
Interest		702,235		110,683			186,961			134,760			269,831			—
Operating leases(6)		46,254		20,209			16,869			4,887			4,289			—
Purchase commitments(7)		685,293		681,922			3,371			—			—			—
Employment contracts(6)		22,225		6,906			10,525			4,794			—			—
Pension funding obligations(8)		750		750			—			—			—			—
Tax reserves(9)		70,447		—			—			—			—			70,447
Total contractual cash obligations	$	5,653,212	$	1,045,758		$	2,868,279		$	419,608		$	1,249,120		$	70,447

(1)	See Note 10 in Part II, Item 8. — Financial Statements and Supplementary Data.
(2)	Represents Nabors Holdings’ $225 million 4.875% senior notes due August 2009. In January and through February 23, 2009, we repurchased $56.6 million par value of our $225 million principal amount of 4.875% senior notes due August 2009 in the open market for cash totaling $56.8 million.
(3)	Includes Nabors Delaware’s $2.75 billion 0.94% senior exchangeable notes due May 2011. In 2008 we purchased $100 million par value of these notes in the open market, leaving $2.65 billion par value outstanding at December 31, 2008. During January and through February 23, 2009, we purchased an additional $427.7 million par value of these notes in the open market for cash totaling $370.6 million.
(4)	Includes Nabors Delaware’s $275 million 5.375% senior notes due August 2012.
(5)	Represents Nabors Delaware’s aggregate $975 million 6.15% senior notes due February 2018.
(6)	See Note 15 in Part II, Item 8. — Financial Statements and Supplementary Data.
(7)	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.
(8)	See Note 13 in Part II, Item 8. — Financial Statements and Supplementary Data.
(9)	Tax reserves are included in Other due to the difficulty in making reasonably reliable estimates of the timing of cash settlements to taxing authorities. See Note 11 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, 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. This program supersedes and cancels our previous share repurchase program. Through December 31, 2008, $464.5 million of our common shares had been repurchased under this program. As of December 31, 2008, 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 15 in Part II, Item 8. — Financial Statements and Supplementary Data for discussion of commitments and contingencies relating to (i) employment contracts that could result in significant cash payments of $264 million and $90 million to Messrs. Isenberg and Petrello, respectively, by the Company if there are terminations of these executives in the event of death, disability, termination without cause or cash payments of $360 million and $122 million to Messrs. Isenberg and Petrello, respectively, by the Company if there are terminations of these executives in the event of a change in control, inclusive of gross up payments, and (ii) off-balance sheet arrangements (including guarantees).

12

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, 2008, we had cash and cash equivalents and investments of $826.1 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. 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. Long-term investments also consist of investments in overseas funds investing primarily in a variety of public and private U.S. and non-U.S. securities (including asset-backed securities and mortgage-backed securities, global structured asset securitizations, whole loan mortgages, and participations in whole loans and whole loan mortgages). These investments are classified as non-marketable, because they do not have published fair values. This compares to cash and cash equivalents and investments of $1.2 billion (including $359.5 million of long-term investments and other receivables, inclusive of $123.3 million in oil and gas financing receivables) and working capital of $711.0 million as of December 31, 2007.

     Our gross funded debt to capital ratio was 0.41:1 as of December 31, 2008 and 0.39:1 as of December 31, 2007. Our net funded debt to capital ratio was 0.35:1 as of December 31, 2008 and 0.30:1 as of December 31, 2007. The gross funded debt to capital ratio is calculated by dividing funded debt by funded debt plus deferred tax liabilities net of deferred tax assets plus capital. Funded debt is defined as the sum of (1) short-term borrowings, (2) current portion of long-term debt and (3) long-term debt. Capital is defined as shareholders’ equity. The net funded debt to capital ratio is calculated by dividing net funded debt by net funded debt plus deferred tax liabilities net of deferred tax assets plus capital. Net funded debt is defined as the sum of (1) short-term borrowings, (2) current portion of long-term debt and (3) long-term debt reduced by the sum of cash and cash equivalents and short-term and long-term investments and other receivables. Capital is defined as shareholders’ equity. Both of these ratios are a method for calculating the amount of leverage a company has in relation to its capital. The gross funded debt to capital ratio and the net funded debt to capital ratio are not measures of operating performance or liquidity defined by GAAP and therefore, they may not be comparable to similarly titled measures presented by other companies.

     Our interest coverage ratio from continuing operations was 20.7:1 as of December 31, 2008, compared to 32.5:1 as of December 31, 2007. The interest coverage ratio is a trailing twelve-month computation of the sum of income from continuing operations before income taxes, interest expense, depreciation and amortization, depletion expense, goodwill and intangible asset impairments and our proportionate share of non-cash pre-tax full cost ceiling writedowns from our oil and gas joint ventures less investment income and then dividing by interest expense. This ratio is a method for calculating the amount of operating cash flows available to cover interest expense. The interest coverage ratio from continuing operations 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 have four letter of credit facilities with various banks as of December 31, 2008. Availability and borrowings under our credit facilities as of December 31, 2008 are as follows:

(In thousands)
Credit available	$	295,045
Letters of credit outstanding		174,156
Remaining availability	$	120,889

     On January 12, 2009, Nabors Delaware completed a private placement of $1.125 billion aggregate principal amount of 9.25% senior notes due 2019 with registration rights, which are unsecured and are fully and unconditionally guaranteed by Nabors Bermuda. Nabors Delaware intends to use the proceeds from the offering for the repayment or repurchase of indebtedness and general corporate purposes.

     Our ability to access capital markets or to otherwise obtain sufficient financing is enhanced by our senior unsecured debt ratings as provided by DBRS, Fitch Ratings, Moody’s Investor Service and Standard & Poor’s, which are currently “BBB+”, “BBB+”, “Baa1” and “BBB+ (Negative Watch)”, respectively, and our historical ability to access those markets as needed. However, recent instability in the global financial markets has resulted in a significant reduction in the availability of funds from capital markets and other credit markets and as a result, our ability to access these markets at this time may be significantly reduced. In addition, Standard & Poor’s recently affirmed its BBB+ credit rating, but revised its outlook to negative from stable due primarily to worsening industry conditions. A credit downgrade by Standard & Poor’s may impact our ability to access credit markets.

     Our current cash and cash equivalents, investments and projected cash flows generated from current 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 on page 40.

13

Off-Balance Sheet Arrangements (Including Guarantees)

     We are a party to certain 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 in 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 to certain third parties which serve as guarantees. 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 and performance guarantees issued by Nabors:

	Maximum Amount
(In thousands)	2009		2010		2011		Thereafter		Total
Financial standby letters of credit and other financial surety instruments	$	143,444	$	12,277	$	965	$	—	$	156,686
Contingent consideration in acquisition		—		2,125		2,125		—		4,250
Total	$	143,444	$	14,402	$	3,090	$	—	$	160,936

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. We are currently evaluating the impact that the Stimulus Act may have on our consolidated financial statements.

     A court in Algeria has entered a judgment against the Company related to certain alleged customs infractions. The Company believes it did not receive proper notice of the judicial proceedings against it, and that the amount of the judgment is excessive. We intend to assert the lack of legally required notice as a basis for challenging the judgment on appeal. 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 of this matter, and the timing of such resolution, is 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 $20 million.

Recent Accounting Pronouncements

     In December 2007 the FASB issued Statement of Financial Accounting Standards (“SFAS”) No. 141(R), “Business Combinations.” This statement retains the fundamental requirements in SFAS No. 141, “Business Combinations” that the acquisition method of accounting be used for all business combinations and expands the same method of accounting 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. This statement replaces SFAS No. 141 by requiring measurement at the acquisition date of the fair value of assets acquired, liabilities assumed and any noncontrolling interest. Additionally, SFAS No. 141(R) requires that acquisition-related costs, including restructuring costs, be recognized as expense separately from the acquisition. SFAS No. 141(R) applies prospectively to business combinations for fiscal years beginning after December 15, 2008. We will adopt SFAS No. 141(R) beginning January 1, 2009 and apply to future acquisitions.

     In December 2007 the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51.” This statement establishes the accounting and reporting standards for a noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. This statement clarifies 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. SFAS No. 160 requires retroactive adoption of the presentation and disclosure requirements for existing minority interests and applies prospectively to business combinations for fiscal years beginning after December 15, 2008. We will adopt SFAS No. 160 beginning January 1, 2009. We are currently evaluating the impact that this pronouncement may have on our consolidated financial statements.

14

     In September 2006 the FASB issued SFAS No. 157, “Fair Value Measurements.” This statement defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles and expands disclosures about fair value measurements for financial assets and liabilities, as well as for any other assets and liabilities that are carried at fair value on a recurring basis in financial statements. SFAS No. 157 is effective with respect to financial assets and liabilities for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. SFAS No. 157 applies prospectively to financial assets and liabilities. There is a one year deferral for the implementation of SFAS No. 157 for nonfinancial assets and liabilities measured on a nonrecurring basis. Effective January 1, 2008, we adopted the provisions of SFAS No. 157 relating to financial assets and liabilities. The new disclosures regarding the level of pricing observability associated with financial instruments carried at fair value is provided in Note 3 in Part II, Item 8. Financial Statements and Supplementary Data. The adoption of SFAS No. 157 with respect to financial assets and liabilities did not have a material financial impact on our consolidated results of operations or financial condition. We are currently evaluating the impact of implementation with respect to nonfinancial assets and liabilities measured on a nonrecurring basis on our consolidated financial statements, which will be primarily limited to asset impairments including goodwill, intangible assets and other long-lived assets, assets acquired and liabilities assumed in a business combination and asset retirement obligations.

     In October 2008 the FASB issued Staff Position (“FSP”) SFAS No. 157-3, “Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active.” This FSP clarifies the application of SFAS No. 157 in an inactive market and provides an example to illustrate key considerations in determining the fair value of a financial asset when the market for that financial asset is not active. This FSP was effective October 10, 2008 and must be applied to prior periods for which financial statements have not been issued. The application of this FSP did not have a material impact on our consolidated financial statements.

     In February 2007 the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities — Including an amendment of FASB Statement No. 115.” This statement permits entities to choose to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value and establishes presentation and disclosure requirements designed to facilitate comparisons between entities that choose different measurement attributes for similar types of assets and liabilities. SFAS No. 159 is effective as of the beginning of an entity’s first fiscal year that begins after November 15, 2007, provided the entity also elects to apply the provisions of SFAS No. 157. The adoption of SFAS No. 159 did not have a material impact on our consolidated results of operations or financial condition as we have not elected to apply the provisions to our financial instruments or other eligible items that are not currently required to be measured at fair value.

     In March 2008 the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities, an Amendment to FASB Statement No. 133.” This statement is intended to improve financial reporting about derivative instruments and hedging activities by requiring enhanced qualitative and quantitative disclosures regarding derivative instruments, gains and losses on such instruments and their effects on an entity’s financial position, financial performance and cash flows. SFAS No. 161 is effective for financial statements issued for fiscal years beginning after November 15, 2008, and interim periods within those fiscal years. We are currently evaluating the impact that this pronouncement may have on our consolidated financial statements.

     In May 2008 the FASB issued FSP APB No. 14-1, “Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement).” The FSP clarifies that convertible debt instruments that may be settled in cash upon conversion (including partial cash settlement) are not addressed by paragraph 12 of APB Opinion No. 14, “Accounting for Convertible Debt and Debt Issued with Stock Purchase Warrants.” Effective January 1, 2009, we adopted the provisions of this FSP and applied them, on a retrospective basis, to our consolidated financial statements, including those presented herein. The impact of the FSP is provided in Notes 7, 9, 10, 11, 16, 17, 18, 20 and 21.

     In June 2008 the FASB issued FSP EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities.” This EITF provides 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. Effective January 1, 2009, we adopted the provisions of this EITF and applied them, on a retrospective basis, to our consolidated financial statements, including those presented herein. The impact of the EITF is provided in Notes 16 and 18.

     In December 2008 the SEC issued a Final Rule, “Modernization of Oil and Gas Reporting”. This Final Rule revises certain oil and gas reporting disclosure in Regulation S-K and Regulation S-X under the Securities Act and the Exchange Act, as well as Industry Guide 2. 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 a trailing twelve month average natural gas and oil price when performing the full cost ceiling test calculation which will impact the accounting by our oil and gas joint ventures. The disclosure requirements are effective for registration statements filed on or after January 1, 2009 and for annual financial statements filed on or after December 31, 2009. We are currently evaluating the impact that this Final Rule may have on our consolidated financial statements.

15

     In December 2008 the FASB issued FSP SFAS No. 140-4 and FIN 46(R)-8, “Disclosures by Public Entities (Enterprises) about Transfers of Financial Assets and Interests in Variable Interest Entities.” This FSP increases disclosure requirements for public companies by amending SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities” to require additional information about a transferors’ continuing involvement with transferred financial assets and amending FASB Interpretation No. 46(R) (“FIN 46(R)”), “Consolidation of Variable Interest Entities” to require additional disclosure about their involvement with variable interest entities. This FSP is effective for reporting periods that end after December 15, 2008. The new disclosures requirements did not have an impact on our financial statements.

     In January 2009 the FASB issued FSP EITF 99-20-a, “Amendments to the Impairment and Interest Income Measurement Guidance of EITF Issue No. 99-20.” This FSP amends EITF Issue No. 99-20, “Recognition of Interest Income and Impairment on Purchased Beneficial Interests and Beneficial Interests That Continue to Be Held by a Transferor in Securitized Financial Assets” and applies to the evaluation of impairment of beneficial interests in securitized financial assets. The amendment requires that other-than-temporary impairments be recognized when there has been a “probable” adverse change in estimated cash flows and removes the references to a market participant view of determining estimated cash flows. This FSP is effective for reporting periods that end after December 15, 2008. The adoption of this FSP did not have a significant impact on our financial statements.

Related-Party Transactions

     Pursuant to their employment agreements, Nabors and its Chairman and Chief Executive Officer, 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 certain instances, members of their families. Under these agreements, we are reimbursed for such premiums upon the occurrence of specified events, including the death of an insured individual. Any recovery of premiums paid by Nabors could potentially be limited to the cash surrender value of these 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 $11.2 million related to these policies. The cash surrender value of these policies of approximately $8.4 million and $10.5 million is included in other long-term assets in our consolidated balance sheets as of December 31, 2008 and 2007, 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 may be deemed to be prohibited loans by us to these individuals. We have paid no premiums related to our agreements with these individuals since the adoption of the Sarbanes-Oxley Act and have postponed premium payments related to our agreements with these individuals.

     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 $259.3 million, $153.4 million and $99.2 million for the years ended December 31, 2008, 2007 and 2006, respectively. Expenses from business transactions with these affiliated entities totaled $9.6 million, $6.6 million and $4.7 million for the years ended December 31, 2008, 2007 and 2006, respectively. Additionally, we had accounts receivable from these affiliated entities of $96.1 million and $62.3 million as of December 31, 2008 and 2007, respectively. We had accounts payable to these affiliated entities of $10.0 million and $14.7 million as of December 31, 2008 and 2007, respectively, and long-term payables with these affiliated entities of $7.8 million and $7.8 million as of December 31, 2008 and 2007, respectively, which is included in other long-term liabilities.

     During the fourth quarter of 2006, the Company entered into a transaction with Shona Energy Company, LLC (“Shona”), a company in which Mr. Payne, an outside director of the Company, is the Chairman and Chief Executive Officer. During the fourth quarter of 2008, the Company purchased 1.8 million common shares of Shona for $.9 million. Pursuant to these transactions, a subsidiary of the Company acquired and holds a minority interest of less than 20% of the issued and outstanding common 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 such 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

16

• 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 in Part II, Item 8. - Financial Statements and Supplementary Data.

     Financial Instruments.As defined in SFAS No. 157, fair value is the price that would be received to sell an asset or paid to transfer 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 utilize 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 in which there is little, if any, market activity for the asset or liability at the measurement date. We are able to classify fair value balances based on the observability of those inputs. SFAS No. 157 establishes a fair value hierarchy such that 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 which have been adjusted for effects of restrictions 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 SFAS No. 157, we did not have a transition adjustment to our retained earnings. Our enhanced disclosures are included in Note 3 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 70% of our total assets as of December 31, 2008, and depreciation constituted 13% of our total costs and other deductions for the year ended December 31, 2008.

     Depreciation for our primary operating assets, drilling and workover rigs is calculated based on the units-of-production method 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. When our drilling and workover rigs are not operating, a depreciation charge is provided using the straight-line method 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.

     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 lives do not continue to be appropriate. Accordingly, for the years ended December 31, 2008, 2007 and 2006, 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 industries are very capital intensive, which is evident in the fact that our property, plant and equipment represented 70% of our total assets as of December 31, 2008. We review our long-lived assets for impairment when events or changes in circumstances indicate that the carrying amounts of such assets may not be recoverable, as required by SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Asset.” An impairment loss is recorded in the period in which it is determined that the carrying amount of the long-lived asset is not recoverable. Such determination requires us to make judgments regarding long-term forecasts of future revenues and costs related to

17

the assets subject to review in order to determine the future cash flows associated with the assets. These long-term forecasts are uncertain in that 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 require a provision for impairment in a future period. 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, 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, 2008, 2007 and 2006, 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.

     Impairment of Goodwill and Intangible Assets.Other long-lived assets subject to impairment consist primarily of goodwill, which represented 1.7% of our total assets as of December 31, 2008. 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, as required by SFAS No. 142, “Goodwill and Other Intangible Assets.” 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 and four of our other operating segments: Canrig Drilling Technology Ltd., Epoch Well Services, Inc., Ryan Energy Technologies and Nabors Blue Sky Ltd. The impairment test involves comparing the estimated fair value of goodwill and intangible assets at each 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.

     The fair values calculated in these impairment tests are determined using discounted cash flow models involving assumptions based on our utilization of rigs, revenues, 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%.

     During the second quarter of 2008, we performed our annual goodwill impairment test and concluded that the carrying amounts of our goodwill and intangible assets did not exceed fair value. At June 30, 2008, the market price for our shares closed at $49.23 and our market capitalization value was $13.6 billion, based on the weighted average diluted share count of 277.1 million shares at June 30, 2008. Since June 30, 2008, several market factors have combined to cause a significant decrease in our stock price market capitalization. At December 31, 2008, the market price for our shares closed at $11.97 and our market capitalization value was $3.3 billion, based on the weighted average diluted share count of 278.4 million shares for the three months ended December 31, 2008. During the period June 30, 2008 to December 31, 2008, oil prices have decreased from $140.00 per barrel to $44.60 per barrel, while natural gas prices have declined from $13.18 per mcf to $5.63 per mcf. The S&P 500 index has decreased from $1,280 to $903 or 30%, while the oilfield services index (OSX) has declined from $354 to $121 or 65%. We believe that the decline in our stock price was principally driven by circumstances that occurred in the stock market as a whole primarily driven by the deteriorating global economic environment. These factors led us to believe a triggering event had occurred requiring a year end goodwill impairment test.

     Our year end impairment test of our goodwill and intangible assets required that for two of our ten reporting units that we perform the second step to measure the goodwill impairment loss. The results indicated a permanent impairment to our Canada Well-servicing and Drilling operating segment and Nabors Blue Sky Ltd., one of our Canadian subsidiaries reported in our Other Operating Segments. As such, we recorded $145.4 million and $4.6 million non-cash impairment charges to reduce the carrying value of these assets to their estimated fair value. Our Canada Well-servicing and Drilling operating segment included assets primarily related to acquisitions of Enserco Energy Services Company, Inc. in 2002 and Command Drilling Corporation in 2001. The non-cash impairment charges were determined necessary due to the duration of the economic downturn in Canada and the lack of certainty regarding eventual recovery in valuing this operation. The main factor that impacted our analysis of Nabors Blue Sky Ltd. is that the current downturn in the drilling market and reduced capital spending on the part of our customers has diminished demand for immediate access to remote drilling site by helicopter use. Additionally, we recorded $4.6 million non-cash impairment to certain intangible assets relating to rights and licenses for a helicopter. As part of our review of our goodwill assumptions, we

18

compared the sum of the our reporting units’ estimated fair value which included the fair value of non-operating assets and liabilities less debt to our market capitalization to assess the reasonableness of our estimated fair value. A prolonged period of lower oil and natural gas prices and its potential impact on our financial results could result in future goodwill impairment charges. For the years ended December 31, 2007 and 2006, 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. Proved oil and gas properties are reviewed when circumstances suggest the need for such a review and, if required, the proved properties are written down to their estimated fair value. Unproved properties are reviewed to determine if there has been impairment of the carrying value, with any such impairment charged to expense in that period. Because of the low natural gas prices at December 31, 2008, we performed an impairment test on our oil and gas properties of our wholly owned Ramshorn business unit. As a result, we recorded a non-cash pre-tax impairment to our oil and gas properties which totaled $21.5 million. We recorded impairment charges of approximately $21.9 million and $9.9 million during the years ended December 31, 2007 and 2006, respectively, related to our oil and gas properties. Estimated fair value includes the estimated present value of all reasonably expected future production, prices, and costs. 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 provision for depletion is based on the capitalized costs as determined above and is determined on a property-by-property basis using the units-of-production method, with costs being amortized over proved developed reserves.

     Our 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 unit-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. The full-cost ceiling is evaluated at the end of each quarter 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 have recorded non-cash pre-tax full cost ceiling test writedowns of which $228.3 million represents our proportionate share of the writedowns recorded during the three months ended December 31, 2008. There was no impairment recorded by our oil and gas joint ventures for the year ended December 31, 2007.

     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 SFAS No. 109, “Accounting for Income Taxes,” 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 shareholders’ 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 which 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. See Note 11 in Part II, Item 8. — Financial Statements and Supplementary Data for additional discussion.

19

     Effective January 1, 2007, we adopted the provisions of the FASB issued Interpretation No. 48 (“FIN 48”), “Accounting for Uncertainty in Income Taxes.” In connection with the adoption of FIN 48, we recognized increases to our tax reserves for uncertain tax positions and interest and penalties. See Note 11 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 which is reflected in historical income tax provisions and accruals. Based on the results of an audit or litigation, a material effect on our financial position, income tax provision, net income, or cash flows in the period or periods for which that determination is made could result. 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, 2008, our provision for income taxes from continuing operations was $206.1 million, consisting of $188.8 million of current tax expense and $17.3 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. Changes in these assumptions could potentially change the effective tax rate. A 1% change in the effective tax rate from 30.2% to 31.2% would increase the current year income tax provision by approximately $6.8 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, 2008, 2007 and 2006, no significant changes have been made to the methodology utilized to estimate insurance reserves. For purposes of earnings sensitivity analysis, if the December 31, 2008 reserves for insurance were adjusted (increased or decreased) by 10%, total costs and other deductions would have changed by $16.3 million, or 0.4%.

     Fair Value of Assets Acquired and Liabilities Assumed.We have completed a number of acquisitions in recent years as discussed in Note 5 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, which involved the use of 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

20

charges being recorded in our consolidated statements of income. 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 are 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, 2008, 2007 and 2006, 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.

     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 through the awarding of stock options and restricted stock. Based on the requirements of SFAS 123(R), which we adopted on January 1, 2006, we account for stock option and restricted stock awards in 2006, 2007 and 2008 using a fair-value based method, resulting in compensation expense for stock-based awards being recorded in our consolidated statements of income. 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 beginning in the first quarter of 2006, management believes that accounting estimates related to the valuation of stock options 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, 2008, 2007 and 2006, no significant changes have been made to the methodology utilized to determine the assumptions used in these calculations.

21