---

---

•	factors related to the offshore drilling market, including changes in oil and gas prices and the state of the global economy on market outlook for our various geographical operating sectors and classes of rigs;

•	supply and demand for drilling units and competitive pressure on utilization rates and dayrates;

•	customer contracts, including contract backlog, contract commencements, contract terminations, contract option exercises, contract revenues, contract awards and rig mobilizations;

•	the repudiation, nullification, modification or renegotiation of contracts;

•	delays in payments by, or disputes with our customers under our drilling contracts;

•	fluctuations in the market value of our drilling units and the amount of debt we can incur under certain covenants in our debt financing agreements;

•	the liquidity and adequacy of cash flow for our obligations;

•	our ability to successfully employ our drilling units ;

•	our ability to procure or have access to financing;

•	our expected debt levels;

•	our ability to comply with certain covenants in our debt financing agreements;

•	credit risks of our key customers;

•	political and other uncertainties, including political unrest, risks of terrorist acts, war and civil disturbances, public health threats, piracy, corruption, significant governmental influence over many aspects of local economies, or the seizure, nationalization or expropriation of property or equipment;

•	the concentration of our revenues in certain jurisdictions;

•	limitations on insurance coverage, such as war risk coverage, in certain areas;

•	our inability to repatriate income or capital;

•	the operation and maintenance of our drilling units, including complications associated with repairing and replacing equipment in remote locations and maintenance costs incurred while idle;

•	newbuildings, upgrades, shipyard and other capital projects, including the completion, delivery and commencement of operation dates;

•	import-export quotas;

•	wage and price controls and the imposition of trade barriers;

•	recruitment and retention of personnel;

•	regulatory or financial requirements to comply with foreign bureaucratic actions, including potential limitations on drilling activity, changing taxation policies and other forms of government regulation and economic conditions that are beyond our control;

•	the level of expected capital expenditures, our expected financing of such capital expenditures and the timing and cost of completion of capital projects;

•	fluctuations in interest rates or exchange rates and currency devaluations relating to foreign or U.S. monetary policy;

---

•	tax matters, changes in tax laws, treaties and regulations, tax assessments and liabilities for tax issues, including those associated with our activities in Bermuda, Norway, the United Kingdom and Russia;

•	legal and regulatory matters, including the results and effects of legal proceedings, and the outcome and effects of internal and governmental investigations;

•	hazards inherent in the drilling industry and marine operations causing personal injury or loss of life, severe damage to or destruction of property and equipment, pollution or environmental damage, claims by third parties or customers and the suspension of operations;

•	customs and environmental matters; and

•	other important factors described from time to time in the reports filed or furnished by us with the Securities and Exchange Commission, or the Commission, and the New York Stock Exchange, or the NYSE.

---

---

PART I

ITEM 1.    IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS

Not applicable.

ITEM 2.    OFFER STATISTICS AND EXPECTED TIMETABLE

Not applicable.

ITEM 3.    KEY INFORMATION

Throughout this Annual Report, all references to “we,” “our,” “us,” "NADL" and the “Company” refer to North Atlantic Drilling Ltd. and its subsidiaries. Unless otherwise indicated, all references to “U.S. dollars,” “USD,” “dollars,” “US$” and “$” in this annual report are to the lawful currency of the United States of America and references to “Norwegian kroner” and “NOK” are to the lawful currency of Norway. References in this Annual Report to “Statoil,” “ConocoPhillips,” “Shell,” “Total,” “ExxonMobil,” “Centrica,” “KMNG,” “Jurong” and “Rosneft” refer to Statoil ASA, Conoco Phillips Company, Royal Dutch Shell, Total S.A., Exxon Mobil Corporation, Centrica PLC, Karmorneftegaz SARL, Jurong Shipyard Pte Ltd. and Rosneft Oil Company, respectively, and certain of each of their subsidiaries that are our current or former customers. References in this Annual Report to “ft” means “feet.”

References in this annual report to our common shares are adjusted to reflect the consolidation of our common shares through a one-for-ten reverse stock split, which became effective on December 31, 2015.

A.    Selected Financial Data

The selected statement of operations and other financial data of the Company with respect to the fiscal years ended December 31, 2015 , 2014 and 2013 and the selected balance sheet data of the Company with respect to the fiscal years ended December 31, 2015 and 2014 have been derived from the Company's Consolidated Financial Statements included in Item 18 of this Annual Report, which have been prepared in accordance with accounting principles generally accepted in the United States, or U.S. GAAP.

The selected statement of operations and other financial data for the fiscal years ended December 31, 2012 and 2011 and the selected balance sheet data with respect to the fiscal years ended December 31, 2013 , 2012 and 2011 have been derived from the Consolidated and Combined Consolidated Carve-Out Financial Statements of the Company and are not included herein.

The following financial data should be read in conjunction with “Item 5. Operating and Financial Review and Prospects” and our consolidated financial statements and the notes thereto, which are included herein. Our financial statements are maintained in U.S. dollars. We refer you to the notes to our consolidated financial statements for a discussion of the basis on which our consolidated financial statements are presented.

(in millions of U.S. dollars except common share and per share data)	Year ended December 31,
	2015		2014		2013		2012		2011
Statement of Operations Data
Total operating revenues	747.7		1,263.7		1,324.3		1,044.7		938.0
Net operating income/(loss)	97.5		(116.4	)	360.6		404.1		402.0
Net (loss)/income	(78.6	)	(320.5	)	235.6		181.7		246.7
(Loss)/Earnings per share, basic and diluted (1)	(3.93	)	(13.86	)	10.35		8.25		12.82
Dividends declared per share (1)	—		4.80		9.05		9.00		6.00
Weighted average common shares outstanding, in millions	24.1		24.0		22.8		22.0		19.2

6

---

(in millions of U.S. dollars except common share and per share data)	Year ended December 31,
	2015		2014		2013		2012		2011
Balance Sheet Data (at end of period):
Cash and cash equivalents (2)	150.9		116.2		84.1		98.4		147.4
Drilling rigs	2,738.0		2,923.5		2,377.8		2,416.2		2,006.8
Newbuildings	—		172.6		312.9		248.7		572.2
Goodwill	—		—		480.6		480.6		480.6
Total assets (3) (4)	3,255.1		3,651.0		3,679.0		3,916.8		3,580.5
Interest bearing debt (including current portion) (3)	2,434.9		2,706.8		2,427.6		2,430.8		2,599.8
Total shareholders’ equity	418.7		461.6		857.5		838.1		525.7
Common shares outstanding	2.4		1,205.7		1,138.1		1,138.1		988.1
Other Financial Data:
Net cash provided by continuing operations	339.9		199.1		425.2		254.2		334.6
Net cash used in investing activities from continuing operations	(39.0	)	(447.5	)	(103.9	)	(238.8	)	(390.4	)
Net cash (used in)/provided by financing activities from continuing operations	(264.1	)	271.2		(334.0	)	(64.6	)	199.6

____________________

(1)	As a result of the 1-for-10 reverse stock split and related reduction in authorized capital in 2015, the earnings per share and dividends declared per share have been retrospectively adjusted by a factor of 10. Please see " Note 17 –Common share capital" of the Notes to our Consolidated Financial Statements included herein for more information.

(2)	Excludes restricted cash.

(3)

During the year ended December 31, 2015, the Company adopted Accounting Standards Update (ASU) 2015-03, Interest–Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs , which requires the debt issuance costs related to a recognized debt liability to be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts and premiums. Accordingly the previous year's selected financial data have been represented to reflect the adoption of this ASU. The total amounts represented were $14.7 million as at December 31, 2015, $23.3 million as at December 31, 2014, $20.3 million as at December 31, 2013, $21.7 million as at December 31, 2012, and $26.9 million as at December 31, 2011. Please see " Note 2 –Accounting policies" of the Notes to our Financial Statements included herein for more information.

(4)

Historically, the Company presented balances due to or from Ship Finance International Limited (NYSE: "SFL"), or Ship Finance, on a gross basis. Beginning on June 30, 2015 the Company has elected to present this on a net basis, due to the fact that the right of offset is established in the long-term loan agreements, and the balances are intended to be settled on a net basis, providing a more appropriate description of the Company’s related party net debt position. Accordingly the Company has represented from amounts due from related parties (current assets) to offset against long-term debt due to related parties (non-current liabilities). The total amounts represented were $0 million as at December 31, 2015, $14.3 million as at December 31, 2014, $0 million as at December 31, 2013, $0 million as at December 31, 2012, and $0 million as at December 31, 2011.

B.    Capitalization and Indebtedness

Not applicable.

C.    Reasons for the Offer and Use of Proceeds

Not applicable.

D.    Risk Factors

Our assets are primarily engaged, or intended to engage, in offshore contract drilling for the oil and gas industry in harsh environments in the territorial waters and outer continental shelf jurisdiction of Norway, the United Kingdom, Ireland, Denmark, the Netherlands, the east coast of Greenland, Russia (west of the island of Diksonskiy) and all countries within the Baltic Sea and the Gulf of Bothnia, which we refer to as the "North Atlantic Region," including ultra-deepwater environments. The following risks relate principally to the industry in which we operate and our business in general. Other risks relate principally to the market and ownership of our securities. The occurrence of any of the events described in this section could materially and negatively affect our business, financial condition, operating results, cash available for the payment of dividends, or the trading price of our common shares. Unless otherwise indicated, all information concerning our business and our assets is as of December 31, 2015 . The risks and uncertainties described below are not the only ones we face. Additional risks and uncertainties not presently known to us or that we currently deem immaterial may also impair our business operations.

7

---

Risks Relating to Our Company

Our business in the offshore drilling sector depends on the level of activity in the offshore oil and gas industry, which is significantly affected by, among other things, volatile oil and gas prices and may be materially and adversely affected by a decline in the offshore oil and gas industry.

The offshore contract drilling industry is cyclical and volatile. Our business in the offshore drilling sector depends on the level of activity in oil and gas exploration, development and production in offshore areas worldwide. The availability of quality drilling prospects, exploration success, relative production costs, the stage of reservoir development and political and regulatory environments affect our customers’ drilling programs. Oil and gas prices and market expectations of potential changes in these prices also significantly affect the level of activity and demand for drilling units.

Oil and gas prices are extremely volatile and are affected by numerous factors beyond our control, including, but not limited to, the following:

•	worldwide production and demand for oil and gas and geographical dislocations in supply and demand;

•	the cost of exploring for, developing, producing and delivering oil and gas;

•	expectations regarding future energy prices and production;

•	advances in exploration, development and production technology;

•	the ability of the Organization of Petroleum Exporting Countries, or OPEC, to set and maintain levels and pricing;

•	the level of production in non-OPEC countries;

•	international sanctions on oil-producing countries, or the lifting of such sanctions;

•	government regulations, including restrictions on offshore transportation of oil and natural gas;

•	local and international political, economic and weather conditions;

•	domestic and foreign tax policies;

•	the development and exploitation of alternative fuels and unconventional hydrocarbon production, including shale;

•	worldwide economic and financial problems and the corresponding decline in the demand for oil and gas and, consequently, our services;

•	the policies of various governments regarding the exploration and development of their oil and gas reserves, accidents, severe weather, natural disasters and other similar incidents relating to the oil and gas industry; and

•	the worldwide political and military environment, including uncertainty or instability resulting from an escalation or additional outbreak of armed hostilities or other crises in the Middle East, eastern Europe or other geographic areas or further acts of terrorism in the United States, Europe or elsewhere.

In addition to oil and gas prices, the offshore drilling industry is influenced by additional factors, including:

•	the availability of competing offshore drilling units;

•	the availability of debt financing on reasonable terms;

•	the level of costs for associated offshore oilfield and construction services;

•	oil and gas transportation costs;

•	the level of rig operating costs, including crew and maintenance;

•	the discovery of new oil and gas reserves;

•	the political and military environment of oil and gas reserve jurisdictions; and

•	regulatory restrictions on offshore drilling.

Any of these factors could reduce demand for our services and adversely affect our business and results of operations.

The current downturn in activity in the oil and gas drilling industry has had and is likely to continue to have an adverse impact on our business and results of operations.

The oil and gas drilling industry is cyclical, and the industry is currently in a downcycle. The price of Brent crude has fallen from $115 per barrel in June 2014 to a low of $30 per barrel in January 2016. As of March 31, 2016 , the price of Brent crude was approximately $39.60 per barrel. The significant decrease in oil and natural gas prices is expected to continue to reduce many of our customers' demand for our services in 2016 due to significant decreases in budgeted expenditures for offshore drilling. Declines in capital spending levels, coupled with additional newbuild supply, have and are likely to continue to put significant pressure on dayrates and utilization. The decline and the perceived risk of a further decline in oil and/or gas prices could cause oil and gas companies to further reduce their overall level of activity or spending, in which case demand for our services may further decline and revenues may continue to be adversely affected through lower drilling unit utilization and/or lower dayrates.

Declines in oil and gas prices for an extended period of time, or market expectations of potential decreases in these prices, have affected and could continue to negatively affect our business in the offshore drilling sector. Sustained periods of low oil prices have resulted in reduced exploration and drilling because oil and gas companies’ capital expenditure budgets are subject to cash flow from such activities and are therefore sensitive to changes in energy prices. As a result of the low commodity prices, the majority of exploration and production companies have announced 2016 capital expenditure budgets with significant reductions in capital spending from prior years. These changes in commodity prices can have a dramatic effect on rig demand, and periods of low demand can cause excess rig supply and intensify the competition in the industry that often results in drilling units, particularly older

8

---

and less technologically advanced drilling units, being idle for long periods of time. We cannot predict the future level of demand for our services or future conditions in the oil and gas industry. In response to the recent decrease in the prices of oil and gas, a number of our oil and gas company customers have recently announced decreases in budgeted expenditures for offshore drilling. Any future decrease in exploration, development or production expenditures by oil and gas companies could reduce our revenues and materially harm our business and results of operations.

We may not be able to set profitable utilization and dayrates or delay entry of newbuild drilling units into our active fleet.

During the recent period of high utilization and high dayrates, which we believe ended in early 2014, industry participants increased the supply of drilling rigs by ordering new drilling rigs, particularly in the ultra-deepwater segment of the industry. Historically, this has resulted in an over-supply of drilling rigs and has caused a subsequent decline in utilization and dayrates when the drilling rigs have entered the market. The worldwide fleet of ultra-deepwater floaters consisted of 165 rigs ( 61 semi-submersibles and 104 drillships) as of March 31, 2016 . As of the same date, an additional 13 semi-submersibles and 43 ultra-deepwater drillships were under construction or on order, which would bring the total ultra-deepwater floater fleet to 221 rigs by January 2020, assuming no reduction in the total fleet size through the retirement of drilling units or otherwise.

Rigs, such as ours, operating in harsh environments, such as the North Sea, Barents Sea, West of Shetland, Greenland and other similar locations require specialized capabilities related to motion, wind resistance, insulation and heat tracing. As of March 31, 2016 , 78 floaters and 75 jack-ups were capable of operations in harsh environments with an additional 11 such harsh environment floaters and 31 jack-ups under construction or on order.

A relatively large number of the drilling rigs currently under construction, including ten harsh environment floaters and 26 harsh environment jack-ups, have not been contracted for future work, and a number of units in the existing worldwide fleet are currently off-contract. The supply of available uncontracted units is intensifying price competition as scheduled delivery and redelivery dates occur and additional contracts terminate without renewal, which will continue to reduce dayrates as the active fleet grows. Rig owners are bidding for available work extremely competitively with a focus on utilization over returns, which has driven rates down to or below cash breakeven levels. Any reductions in drilling activity by our customers may not be uniform across different geographic regions. Locations where costs of drilling and production are relatively higher, such as Arctic, harsh environment or deepwater locations where we operate, may be subject to greater reductions in activity. Such reductions in high cost regions may lead to the relocation of drilling units, increasing the supply of available drilling units in regions with relatively fewer reductions in activity. In addition, customers have requested and may in the future request the renegotiation of existing contracts to lower dayrates. In an over-supplied market, we may have limited bargaining power to renegotiate on more favorable terms. Lower utilization and dayrates have affected and will adversely affect our revenues and profitability.

We may not be able to renew or obtain new and favorable contracts for drilling rigs the contracts for which are expiring or are terminated, which could adversely affect our revenues and profitability.

As of March 31, 2016 , we had three contracts that are scheduled to expire in 2016, one contract that is scheduled to expire in 2017, and one contract that is scheduled to expire in 2019, excluding options granted to our customers to extend the term of their contracts. Our ability to renew expiring contracts or obtain new contracts will depend on the prevailing market conditions at the time, which may vary among different geographic regions, different types of drilling units, and specific customers. For example, the West Navigator , following the expiration of its previous drilling contract in December 2014, remained off-hire for the first quarter 2015, and the contract with Rosneft which had been secured for the West Navigator was terminated. If we are not able to obtain new contracts in direct continuation with existing contracts, or if new contracts are entered into at dayrates substantially below the existing dayrates or on terms otherwise less favorable compared to existing contracts terms, our revenues and profitability could be adversely affected. We may also be required to accept more risk in areas other than price to secure a contract which risk we may be unable to push down to other contractors, are unable or unwilling at competitive prices to insure against and which therefore have to be managed by applying other controls

The offshore drilling markets in which we compete experience fluctuations in the demand for drilling services, as measured by the level of exploration and development expenditures and supply of capable drilling equipment. The existing drilling contracts for our drilling rigs currently employed are scheduled to expire from July 2016 to May 2019 (excluding any potential future Rosneft contracts, and any options to extend) if such contracts are not earlier terminated. Upon the expiration or termination of their current contracts, we may not be able to obtain contracts for our drilling rigs currently employed and there may be a gap in employment of the rigs between current contracts and subsequent contracts. In particular, if, as is presently the case, oil and gas prices are low, or it is expected that such prices will decrease in the future, at a time when we are seeking to arrange contracts for our drilling rigs, we may not be able to obtain drilling contracts at attractive dayrates or at all.

If the dayrates that we receive for the reemployment of our current drilling rigs are less favorable, we will recognize less revenue from their operations. Our ability to meet our cash flow obligations will depend on our ability to consistently secure drilling contracts for our drilling rigs at sufficiently high dayrates. We cannot predict the future level of demand for our services or future conditions in the oil and gas industry. If oil and gas prices remain low and/or if companies do not continue to increase exploration, development and production expenditures, we may have difficulty securing drilling contracts, or we may be forced to enter into contracts at unattractive dayrates, which would have a material adverse effect on our financial position, results of operations, cash flow and our ability to pay dividends to our shareholders.

Our contract backlog for our fleet of drilling rigs may not be realized.

As of March 31, 2016 , our contract backlog was approximately $630 million . The contract backlog presented in this Annual Report and our other public disclosures is only an estimate. The actual amount of revenues earned and the actual periods during which revenues are earned will be different from the contract backlog projections due to various factors, including shipyard and maintenance projects, downtime and other events within or beyond our control. In addition, we or our customers may seek to cancel or renegotiate our contracts for various reasons, including adverse market conditions, such as the current environment, resulting in lower dayrates.

9

---

Compensation under our drilling contracts is based on daily performance and/or availability of each drilling rig in accordance with the requirements specified in the applicable drilling contract. For instance, when our drilling rigs are idle, but available for operation, our customers are generally entitled to pay a waiting rate lower than the operational rate.

Several factors could cause an interruption of operations, including:

•	breakdowns of equipment and other unforeseen engineering problems;

•	failure by our employees or contractors to operate critical equipment on the drilling rigs;

•	work stoppages, including labor strikes;

•	shortages of material and skilled labor;

•	delays in repairs by suppliers;

•	surveys by government and maritime authorities;

•	periodic classification surveys;

•	severe weather, strong ocean currents or harsh operating conditions; and

•	force majeure events.

In addition, if our drilling rigs are taken out of service for maintenance and repair for a period of time exceeding the scheduled maintenance periods set forth in our drilling contracts, we will not be entitled to payment of dayrates until the relevant rig is available for deployment. If the interruption of operations were to exceed a determined period due to an event of force majeure, our customers have the right to pay a rate (the “force majeure rate”) that is normally significantly lower than the waiting rate for a period of time, and, thereafter, may terminate the drilling contracts related to the subject rig. For more details on our drilling contracts, please see “Item 4. Information on the Company—B. Business Overview—Drilling Contracts.” Suspension of drilling contract payments, prolonged payment of reduced rates or termination of any drilling contract agreements as a result of an interruption of operations as described herein could materially adversely affect our financial condition, results of operations and ability to pay dividends to our shareholders.

The market value of our current drilling rigs and those we acquire in the future may decrease, which could cause us to record impairment losses, or incur realized losses if we decide to sell them following a decline in their market values.

During the year ended December 31, 2015, the estimated value of our drilling units, based on broker valuations, decreased by approximately 29% . If the offshore contract drilling industry continues to suffer adverse developments, the fair market value of our drilling rigs may decline further. The fair market value of the drilling rigs that we currently own, or may acquire in the future, may increase or decrease depending on a number of factors, including:

•	general economic and market conditions affecting the offshore contract drilling industry, including competition from other offshore contract drilling companies;

•	types, sizes and ages of drilling rigs;

•	supply and demand for drilling rigs;

•	costs of newbuildings;

•	prevailing level of drilling services contract dayrates;

•	governmental or other regulations; and

•	technological advances.

Additionally, if we sell one or more of our drilling rigs at a time when drilling rig prices have fallen and before we have recorded an impairment adjustment to our Consolidated Financial Statements, the sale price may be less than the drilling rig’s carrying value in our Consolidated Financial Statements, resulting in a loss and a reduction in earnings. Furthermore, if drilling unit values fall significantly, we may have to record an impairment adjustment in our Consolidated Financial Statements, which could adversely affect our financial results and condition. Please see “—The current downturn in activity in the oil and gas drilling industry has had and is likely to continue to have an adverse impact on our business and results of operations.”

The market value of our drilling units may fall, which may impact our ability to incur additional indebtedness. Please see "—We may not have sufficient liquidity to service our debt or flexibility to obtain additional financing and pursue other business opportunities, and Seadrill may not honor its guarantee of our debt." If the market value of our drilling units falls, we may also be required to, among other things, make prepayments on certain of our secured credit facilities, which may adversely impact our liquidity. Please see "—We may be unable to comply with covenants in our credit facilities or any future financial obligations that impose operating and financial restrictions on us, which could result in a default under the terms of these agreements, which could accelerate our repayment of funds that we have borrowed."

A reduction in the market value of our drilling units could lead to the recognition of further impairment charges on, among other things, our drilling units if future cash flow estimates, based on information available to management at the time, indicate that the carrying value of these drilling units or goodwill may not be recoverable. For example, as noted below, we have recognized an impairment loss of $82 million on the West Rigel for the year ended December 31, 2015. In addition, if the market value of our drilling units decreases, and we sell any drilling unit at a time when prices for drilling units have fallen, such a sale may result in a loss, which would negatively affect our results of operations. Please see "—The decreasing value of our drilling units could result in impairment charges or impact our ability to incur debt under our debt financing agreements" below.

10

---

The decreasing value of our drilling units could result in impairment charges or impact our ability to incur debt under our debt financing agreements.

During the year ended December 31, 2014, we recorded an impairment charge for goodwill of $480.6 million, due to declining dayrates and our future expectations for dayrates in the sector. Since recognizing this impairment charge, we no longer retain any goodwill on our balance sheet. In addition, we have recognized an impairment loss of $82 million on the West Rigel for the year ended December 31, 2015. In the future, we may be required to record additional impairment charges to other assets. Such impairment charges could have a material adverse effect on our financial performance or results of operations. In addition, such impairment charges could adversely impact our ability to comply with the restrictions and covenants in our debt agreements, including meeting financial ratios and tests in those agreements. If we are unable to comply with the restrictions and covenants in the agreements governing our indebtedness or in current or future debt financing agreements, a default could occur under the terms of those agreements.

We may not have sufficient liquidity to service our debt or flexibility to obtain additional financing and pursue other business opportunities, and Seadrill may not honor its guarantee of our debt.

As of December 31, 2015 , we had approximately $2.4 billion in interest-bearing debt at an average annual interest rate of 4.4% , of which $1.6 billion was secured by, among other things, liens on our drilling units. In addition, Seadrill guarantees our NOK 1,500 million senior unsecured bond, $2,000 million Senior Secured Credit Facility, and $475 million secured term loan. Our current and future indebtedness could also affect our future operations, as a portion of our cash flow from operations will be dedicated to the payment of interest and principal on such debt and will not be available for other purposes. Covenants contained in our debt agreements require Seadrill to meet certain financial tests and non-financial tests, which may affect our flexibility in planning for, and reacting to, changes in our business or economic conditions, may limit our ability to dispose of assets or place restrictions on the use of proceeds from such dispositions, withstand current or future economic or industry downturns and compete with others in our industry for strategic opportunities, and may limit our ability to obtain additional financing for working capital, capital expenditures, acquisitions, general corporate and other purposes.

Our business is capital intensive and, to the extent that we do not generate sufficient cash from operations, we may need to raise additional funds through public or private debt or equity financings to grow our business and to fund capital expenditures. Adequate sources of capital funding may not be available when needed or may not be available on favorable terms. If we raise additional funds by issuing additional equity securities, dilution to the holdings of existing shareholders may result. Our ability to meet our debt service obligations and to fund planned expenditures, including construction costs for our newbuilding projects, will be dependent upon our future performance, which will be subject to prevailing economic conditions, industry cycles and financial, business, regulatory and other factors affecting our operations, many of which are beyond our control. In addition, we are highly dependent on Seadrill and its affiliates to assist us in operating. Any inability of Seadrill or its associates to honor its guarantees of our debt or provide us with sufficient liquidity could negatively impact our business. Please see "—We are a holding company dependent on our subsidiaries and certain affiliates of Seadrill, including Seadrill Management AS, or Seadrill Management, to assist us in operating and satisfying our financial obligations" below. Our future cash flows may be insufficient to meet all of our debt obligations and contractual commitments, and any insufficiency could negatively impact our business. To the extent that we are unable to repay our indebtedness as it becomes due or at maturity, we may need to refinance our debt, raise new debt, sell assets or repay the debt with the proceeds from equity offerings. Additional indebtedness or equity financing may not be available to us in the future for the refinancing or repayment of existing indebtedness, and we may not be able to complete asset sales in a timely manner sufficient to make such repayments. Please see “Item 5. Operating and Financial Review and Prospects—B. Liquidity and Capital Resources.”

We are a holding company dependent on our subsidiaries and certain affiliates of Seadrill, including Seadrill Management Limited, or Seadrill Management, to assist us in operating and satisfying our financial obligations.

We are a holding company, and our subsidiaries, which are all directly and indirectly wholly-owned by us, conduct all of our operations and own all of our operating assets. As a result, our ability to satisfy our financial obligations in the future depends on the ability of our subsidiaries to generate profits available for distribution to us. Our ability to enter into new drilling contracts and expand our customer and supplier relationships also depends largely on our ability to leverage our relationship with Seadrill and its reputation and relationships in the offshore drilling industry. If Seadrill suffers material damage to its reputation or relationships, it may harm our ability to:

•	renew existing drilling contracts upon their expiration;

•	obtain new drilling contracts;

•	efficiently and productively carry out our drilling activities;

•	successfully interact with shipyards;

•	obtain financing and maintain insurance on commercially acceptable terms; or

•	maintain satisfactory relationships with suppliers and other third parties.

Pursuant to a services agreement between us and Seadrill Management, or the Services Agreement, Seadrill Management provides us with treasury and financial advisory services, insurance placement and building supervisory services. We also receive corporate, secretarial and certain other administrative services relating to the jurisdiction of Bermuda from Frontline Management (Bermuda) Ltd. under the Services Agreement with Seadrill Management. In addition, we receive management services from Seatankers Management Norway AS. In addition, pursuant to our cooperation agreement with Seadrill, or the Cooperation Agreement, we have the right of first refusal to participate in any business opportunity identified by Seadrill for drilling activities in the North Atlantic Region and have provided Seadrill with a right of first refusal to participate in any business opportunity identified by us for drilling activities outside the North Atlantic Region. Our operational success and ability to execute our growth strategy will depend significantly upon the satisfactory performance of these agreements. Our business will be harmed if Seadrill and its affiliates fail to perform satisfactorily under these agreements, if they cancel their agreements with us or if they stop providing these services to us. Please see “Item 7. Major Shareholders and Related Party Transactions—B. Related Party Transactions.”

11

---

Although Seadrill has historically provided us with significant financial resources, Seadrill may diminish or cease providing such financial resources in the future. If Seadrill were to reduce its ownership in us to a minority interest, we can provide no assurance that Seadrill would continue to provide support and management services to us, and we can provide no assurance that we would be able to replace Seadrill’s support and services with the support and services of a third party that would be of the same quality or at the same cost. If funding is insufficient at any time in the future, we may be unable to fund maintenance requirements, take advantage of business opportunities or respond to competitive pressures, any of which could adversely impact our financial condition and results of operations.

We may be unable to comply with covenants in our credit facilities or any future financial obligations that impose operating and financial restrictions on us, which could result in a default under the terms of these agreements, which could accelerate our repayment of funds that we have borrowed.

Our debt agreements impose operating and financial restrictions on us, which may prohibit or otherwise limit our ability to, among other things:

•	enter into other financing arrangements;

•	incur additional indebtedness;

•	create or permit liens on our assets;

•	sell our drilling rigs or the shares of our subsidiaries;

•	make investments;

•	change the general nature of our business;

•	pay dividends to our shareholders;

•	change the management and/or ownership of the drilling rigs;

•	make capital expenditures; and

•	compete effectively to the extent our competitors are subject to less onerous restrictions.

Therefore, we will need to seek permission from our lenders in order to engage in some corporate actions. Our lenders’ interests may be different from ours and we may not be able to obtain our lenders’ permission when needed. This may limit our long term ability to pay dividends to you, if we determine, and are able, to do so in the future, finance our future operations or capital requirements, make acquisitions or pursue business opportunities.

Our ability to comply with the restrictions and covenants, including financial ratios and tests, contained in our financing agreements is dependent on our future performance and may be affected by events beyond our control, including prevailing economic, financial and industry conditions. The financial covenants in our NOK 1,500 Million Senior Unsecured Bond, our $2,000 Million Senior Secured Credit Facility and our Sale and Leaseback Agreement with Ship Finance were amended replacing our independent financial covenants by the standard financial covenants of our majority shareholder, Seadrill, and to add Seadrill as guarantor of the debt. We or Seadrill may seek and obtain waivers or amendments from our lenders with respect to the restrictions and covenants contained in our debt agreements. If we or Seadrill were to fail to comply with any of the restrictions and covenants in our debt agreement and we or Seadrill, as applicable, are unable to obtain a waiver or amendment from our lender for such noncompliance, there could be a default under our financing agreements. We have no ability to control Seadrill's compliance with its financial covenants. In addition, if the market value of any of our drilling rigs declines, or if market or other economic conditions deteriorate, our ability and Seadrill's ability to comply with these covenants may be impaired. If we or Seadrill are unable to comply with the restrictions and covenants in the agreements governing our indebtedness or in current or future debt financing agreements, there could be a default under the terms of those agreements. If a default occurs under these agreements, lenders could terminate their commitments to lend and/or accelerate the outstanding loans and declare all amounts borrowed due and payable. We also pledge our drilling rigs as security for our indebtedness. If our lenders were to foreclose on our drilling rigs in the event of a default, this may adversely affect our ability to finance future operations or capital needs or to engage, expand or pursue our business activities. In addition, all of our loan agreements contain cross-default provisions, meaning that if we are in default under one of our loan agreements, amounts outstanding under our other loan agreements may also be accelerated and become due and payable. If any of these events occur, our assets may be insufficient to repay in full all of our outstanding indebtedness, and we may be unable to find alternative financing. Even if we could obtain alternative financing, that financing might not be on terms that we find are favorable or acceptable. Moreover, in connection with any further waivers of or amendments to our credit facilities that we may obtain, our lenders may impose additional operating and financial restrictions on us or modify the terms of our existing credit facilities. Any of these events may further restrict our ability to pay dividends, repurchase our common shares, make capital expenditures or incur additional indebtedness, including through the issuance of guarantees. Please see “Item 5. Operating and Financial Review and Prospects—B. Liquidity and Capital Resources” for more information on our liquidity outlook and financial covenants, including details of the covenant amendments obtained in April 2016.

Failure to comply with covenants and other provisions in our existing or future debt agreements, including the senior unsecured notes, could result in cross-defaults under our existing debt agreements, which would have a material adverse effect on us.

Our existing debt agreements contain cross-default provisions that may be triggered if we default under the terms of our existing or future financing agreements. Please see “Item 5. Operating and Financial Review and Prospects—B. Liquidity and Capital Resources.” In the event of a default by us under one of our debt agreements, the lenders under our existing debt agreements could determine that we are in default under our other financing agreements. This could result in the acceleration of the maturity of such debt under these agreements and the lenders thereunder may foreclose upon any collateral securing that debt, including our drilling rigs, even if we were to subsequently cure such default. In the event of such acceleration and foreclosure, we might not have sufficient funds or other assets to satisfy all of our obligations, which would have a material adverse effect on our business, results of operations and financial condition and would significantly reduce our ability, or make us unable, to pay dividends to our shareholders for so long as such default is continuing. In addition, we are subject to certain financial and restrictive covenants contained in the indenture relating to the $600 Million 6.25% Senior Unsecured Notes due 2019, or the Senior Unsecured Notes, which, among other things, restrict our ability to pay dividends, incur indebtedness, incur liens, and make certain investments. In addition, the indenture governing the senior unsecured notes contains other customary terms,

12

---

including certain events of default, upon the occurrence of which, the notes may be declared immediately due and payable. Additionally, we are a “restricted subsidiary” under the indentures relating to Seadrill’s $1,000 million 5  ⁵ / ₈ % Senior Notes due 2017 and $500 million 6  ¹ / ₈ % Senior Notes due 2020. While we are not a guarantor of the notes or a party to the indentures thereto, Seadrill has agreed to cause us to comport with the restrictions on “restricted subsidiaries” contained in the indentures. Accordingly, Seadrill may use its influence over us to restrict our ability, among other things, to incur additional debt, pay dividends or issue guarantees, if Seadrill is required to do so under the terms of the indentures for the notes. We also consolidate SFL Linus Ltd. into our financial statements as a variable interest entity, or VIE. SFL Linus Ltd. is a subsidiary of Ship Finance, which owns the West Linus . To the extent that SFL Linus Ltd. defaults under its indebtedness and is marked current in its financial statements, we would in turn mark such indebtedness current in our consolidated financial statements. The characterization of the indebtedness in our financial statements as current may adversely impact our compliance with the covenants contained in our existing and future debt agreements. In addition, the financial covenants in our NOK 1,500 Million Unsecured Bond due 2018, our $2,000 Million Senior Secured Credit Facility and our Sale and Leaseback Agreement with Ship Finance were recently amended to replace our independent financial covenants by the standard financial covenants of our majority shareholder, Seadrill, and to add Seadrill as guarantor of the debt. If Seadrill were to fail to comply with such financial covenants, there could be a default under our financing agreements. We have no ability to control Seadrill's compliance with its financial covenants.

We currently derive all of our revenue from four customers, and the loss of any of these customers could result in a significant loss of revenues and cash flow.

We currently derive all of our revenues and cash flow from four customers. Among our four customers for the year ending December 31, 2015 , Statoil accounted for 44% , ExxonMobil accounted for 25% , Conoco Phillips accounted for 18% and Total accounted for 13% of our total revenues. Among our six customers for the year ended December 31, 2014 , Statoil accounted for 38% , ExxonMobil accounted for 13% , Shell accounted for 12% , Total accounted for 12% , KMNG accounted for 11% , and Conoco Phillips accounted for 8% of our total revenues. All of our drilling contracts have fixed terms, but may be terminated early due to certain events or we may be unable to realize revenue under such contracts in the event of unanticipated developments, such as the deterioration in the general business or financial condition of a customer, resulting in its inability to meet its obligations under our contracts.

If any of our drilling contracts are terminated, we may be unable to re-deploy the drilling rig subject to such terminated contract on terms as favorable to us as our current drilling contracts. This may cause us to receive decreased revenues and cash flows than we would have otherwise earned. The loss of any customers, drilling contracts or drilling rigs, or a decline in payments under any of our drilling contracts, could have a material adverse effect on our business, results of operations, financial condition and ability to pay dividends to our shareholders.

In addition, our drilling contracts subject us to counterparty risks. The ability of each of our counterparties to perform its obligations under a contract with us will depend on a number of factors that are beyond our control and may include, among other things, general economic conditions, the condition of the offshore drilling industry, prevailing prices for oil and gas, the overall financial condition of the counterparty, the dayrates received for specific types of drilling rigs and the level of expenses necessary to maintain drilling activities. In addition, in depressed market conditions, our customers may no longer need a drilling rig that is currently under contract or may be able to obtain a comparable drilling rig at a lower dayrate. Should a counterparty fail to honor its obligations under an agreement with us, we could sustain losses, which could have a material adverse effect on our business, financial condition, results of operations and ability to pay dividends to our shareholders.

Our international operations in the offshore drilling sector involve additional risks, which could adversely affect our business.

We operate in various regions of the world. As a result of our international operations, we may be exposed to political and other uncertainties, including risks of:

•	terrorist acts, armed hostilities, war and civil disturbances;

•	acts of piracy, which have historically affected ocean-going vessels;

•	significant governmental influence over many aspects of local economies;

•	the seizure, nationalization or expropriation of property or equipment;

•	the repudiation, nullification, modification or renegotiation of contracts;

•	limitations on insurance coverage, such as war risk coverage, in certain areas;

•	political unrest;

•	foreign and U.S. monetary policy and foreign currency fluctuations and devaluations;

•	the inability to repatriate income or capital;

•	complications associated with repairing and replacing equipment in remote locations;

•	import-export quotas, wage and price controls, and the imposition of trade barriers;

•	U.S. and foreign sanctions or trade embargoes;

•	regulatory or financial requirements to comply with foreign bureaucratic actions;

•	changing taxation policies, including confiscatory taxation;

•	other forms of government regulation and economic conditions that are beyond our control; and

•	governmental corruption.

In addition, international contract drilling operations are subject to various laws and regulations of the countries in which we operate, including laws and regulations relating to:

13

---

•	the equipping and operation of drilling units;

•	the repatriation of foreign earnings and exchange controls;

•	oil and gas exploration and development;

•	the taxation of offshore earnings and the earnings of expatriate personnel; and

•	the use and compensation of local employees and suppliers by foreign contractors.

Some foreign governments favor or effectively require (i) the awarding of drilling contracts to local contractors or to drilling rigs owned by their own citizens, (ii) the use of a local agent or (iii) foreign contractors to employ citizens of, or purchase supplies from, a particular jurisdiction. These practices may adversely affect our ability to compete in those regions. It is difficult to predict what governmental regulations may be enacted in the future that could adversely affect the international drilling industry. The actions of foreign governments, including initiatives by OPEC, may adversely affect our ability to compete. Failure to comply with applicable laws and regulations, including those relating to sanctions and export restrictions, may subject us to criminal sanctions or civil remedies, including fines, denial of export privileges, injunctions or seizures of assets.

Newbuilding projects are subject to risks that could cause delays or cost overruns

We have entered into a construction contract for one semi-submersible rig, the  West Rigel . On December 2, 2015 we entered an agreement with Jurong Shipyard Pte Ltd., or Jurong, to, among other things, defer our taking delivery of the West Rigel for a period of six months, until June 2016, or the Deferral Period. During the Deferral Period, we will continue to market the rig for employment while the rig remains at the Jurong shipyard in Singapore. If the West Rigel is not contracted for employment on terms acceptable to us or otherwise sold to a third party prior to the expiration of the Deferral Period, NADL and Jurong have agreed to jointly own the rig. For additional information, please see "Item 4. Information on the Company - A. History and Development of the Company." In view of current market conditions, we believe that it is unlikely that we will be able to secure acceptable employment for the rig prior to the expiry of the Deferral Period, and as a result, we expect that the rig will be jointly owned with Jurong. Accordingly, we have classified the West Rigel as “Held for Sale” as of December 31, 2015. To the extent we delay taking delivery of, or are unable to take full delivery of, the West Rigel , we would be prevented from realising potential revenues from this rig, which would adversely affect our financial position, results of operations and cash flows.

Any limitation in the availability or operation of our seven drilling rigs could have a material adverse effect on our business, results of operations and financial condition.

Our fleet currently consists of three harsh environment semi-submersibles, one harsh environment deepwater drillship, and three harsh environment jack-up rigs. We also have a contract for the construction of one harsh environment semi-submersible rig, which has been classified as "Held for sale" in our Consolidated Financial Statements included herein. If any of our drilling rigs are unable to generate revenues as a result of the expiration or termination of its drilling contracts or sustained periods of downtime, our results of operations and financial condition could be materially adversely affected.

Some of our customers have the right to terminate their drilling contracts without cause upon the payment of an early termination fee. The general principle is that such early termination fee shall compensate us for lost revenues less operating expenses for the remaining contract period; however, in some cases, such payments may not fully compensate us for the loss of the drilling contract. Under certain circumstances our contracts may permit customers to terminate contracts early without the payment of any termination fees as a result of nonperformance, total loss of the rigs, extended periods of downtime or impaired performance caused by equipment or operational issues, or sustained periods of downtime due to force majeure events beyond our control. During periods of challenging market conditions, we may be subject to an increased risk of our customers seeking to repudiate their contracts, including through claims of non-performance. Our customers’ ability to perform their obligations under their drilling contracts may also be negatively impacted by the prevailing uncertainty surrounding the development of the world economy and the credit markets. If a customer cancels its contract and we are unable to secure a new contract on a timely basis and on substantially similar terms, or if a contract is suspended for an extended period of time or if a contract is renegotiated on different terms, these events could adversely affect our business, results of operations and financial condition and may reduce the amount of cash we have available to pay dividends to our shareholders. As of March 31, 2016 , we had two units stacked and uncontracted, the West Navigator and the West Venture . For more information regarding the termination provisions of our drilling contracts, see “Item 4. Information on the Company-B. Business Overview-Drilling Contracts.”

The provisions of our drilling contracts may not permit us to fully recoup our cost increases in the event of a rise in our expenses.

The average remaining contract length as of March 31, 2016 , was four months for our floaters and 19 months for our jack-up rigs. The majority of these contracts have dayrates that are fixed over the contract term. In order to mitigate the effects of inflation on revenues from term contracts, some of our drilling contracts include escalation provisions. These provisions allow us to adjust the dayrates based on certain published indices. These indices are designed to recompense us for certain cost increases, including wages, insurance and maintenance costs. However, actual cost increases may result from events or conditions that do not cause correlative changes to the applicable indices. Furthermore, certain indices are updated semi-annually, and therefore may be outdated at the time of adjustment. The adjustments are also typically performed on a semi-annual or annual basis. For these reasons, the timing and amount awarded as a result of such adjustments may differ from our actual cost increases, which could adversely affect our financial performance.

Our operating and maintenance costs will not necessarily fluctuate in proportion to changes in operating revenues.

Our operating expenses and maintenance costs depend on a variety of factors including crew costs, provisions, equipment, insurance, maintenance and repairs and shipyard costs, many of which are beyond our control and affect the entire offshore drilling industry. During periods after which a rig becomes idle, we may decide to “warm stack” the rig, which means the rig is kept fully operational and ready for redeployment, and maintains most of its crew. As a result, our operating expenses during a warm stacking will not be substantially different than those we would incur if the rig remained active. We

14

---

may also decide to “cold stack” the rig, which the means the rig is stored in a harbor, shipyard or a designated offshore area, and the crew is assigned to an active rig or dismissed. However, reductions in costs following the decision to cold stack a rig may not be immediate, as a portion of the crew may be required to prepare the rig for such storage. Moreover, as our drilling rigs are mobilized from one geographic location to another, the labor and other operating and maintenance costs can vary significantly. Operating and maintenance costs will not necessarily fluctuate in proportion to changes in operating revenues. Operating revenues may fluctuate as a function of changes in supply of offshore drilling rigs and demand for contract drilling services, which in turn, affect dayrates, and the economic utilization and performance of our fleet of drilling rigs. However, operating costs are generally related to the number of drilling rigs in operation and the cost level in each country or region where such drilling rigs are located. In addition, equipment maintenance costs fluctuate depending upon the type of activity that the drilling rig is performing and the age and condition of the equipment. Escalation provisions contained in our drilling contracts may not be adequate to substantially mitigate these increased operating and maintenance costs. In connection with new assignments, we might incur expenses relating to preparation for operations under a new contract. The expenses may vary based on the scope and length of such required preparations and the duration of the contractual period over which such expenditures are amortized. In situations where our drilling rigs incur idle time between assignments, the opportunity to reduce the size of our crews on those drilling rigs is limited as the crews will be engaged in preparing the drilling rig for its next contract. When a drilling rig faces longer idle periods, reductions in costs may not be immediate as some of the crew may be required to prepare drilling rigs for stacking and maintenance in the stacking period. Should drilling rigs be idle for a longer period, we may not be successful in redeploying crew members, who are not required to maintain the drilling rigs, and therefore may not be successful in reducing our costs in such cases.

Our future business depends on the level of oil and gas activity in the North Atlantic Region and our ability to operate outside of Norway and the United Kingdom.

Our future business depends significantly on the future level of oil and gas activity in the North Atlantic Region and our ability to expand into North Atlantic Region markets outside Norway and the United Kingdom. Expansion of our business outside Norway and the United Kingdom depends on our ability to operate in other areas of the North Atlantic Region. Any such expansion may be adversely affected by local regulations requiring us to award contracts to local operators and the number and location of new drilling concessions granted by foreign governments. Restrictions or requirements that may be imposed in the countries in which we operate could have a material adverse effect on our financial position, results of operations or cash flows. If we are unable to expand our operations within the geographic area where we currently operate, or gain contracts in the North Atlantic Region markets outside of Norway and the United Kingdom, our future business, financial condition and results of operations may be adversely affected.

We may not commence operations under the drilling contracts with Rosneft Oil Company, and we may not close the acquisition of the land drilling business from Rosneft Oil Company.

In July 2014, entered into six offshore drilling contracts with Rosneft. In August, 2014, we entered into an agreement to acquire a significant portion of Rosneft's land drilling fleet in Russia, along with new five-year contracts awarded by Rosneft for the land drilling units being acquired pursuant to a framework agreement, or the Framework Agreement. In November 2014, we and Rosneft agreed to delay to May 2015 the closing of these transactions that are contemplated in the Framework Agreement and on April 16, 2015, we mutually agreed to further extend the date of termination of the Framework Agreement until May 31, 2017, whereby both parties can effectively terminate the Framework Agreement and / or any offshore drilling contracts at any time prior to May 31, 2017 at no cost. In June 2015, the parties agreed to cancel any restrictions of business included within the terms of the Framework Agreement, and replaced this with a requirement for us, subject to applicable law, to inform Rosneft of any material developments affecting us. Due to recent and ongoing developments and events, we believe that it will be extremely unlikely to close these transactions on the same terms contemplated in the executed agreements.

Competition within the offshore drilling industry may adversely affect our results of operations and financial condition.

The offshore drilling industry is highly competitive and fragmented and includes several large companies, including Seadrill, that compete in many of the markets we serve, as well as numerous small companies that compete with us on a local basis. Offshore drilling contracts are generally awarded on a competitive bid basis or through privately negotiated transactions. In determining which qualified drilling contractor is awarded a contract, the key factors are pricing, rig availability, rig location, condition and integrity of equipment, its record of operating efficiency, including high operating uptime, technical specifications, safety performance record, crew experience, reputation, industry standing and customer relations. Our operations may be adversely affected if our current competitors or new market entrants introduce new drilling rigs with better features, performance, prices or other characteristics in comparison to our drilling rigs, or expand into service areas where we operate. In addition, mergers among oil and gas exploration and production companies have reduced, and may from time to time further reduce, the number of available customers, which would increase the ability of potential customers to achieve pricing terms favorable to them.

The offshore drilling industry has historically been cyclical and is impacted by oil and gas price levels and volatility. There have been periods of high demand, short rig supply and high dayrates, followed by periods of low demand, excess rig supply and low dayrates, such as the downturn that we are currently experiencing. Changes in commodity prices can have a dramatic effect on rig demand, and periods of excess rig supply may intensify competition in the industry and result in the idling of older and less technologically advanced equipment. We have idled rigs, and may in the future idle or stack additional rigs or enter into lower dayrate drilling contracts in response to market conditions. We cannot predict when or if any idled or stacked rigs will return to service. When idled or stacked, drilling units do not earn revenues, but continue to require cash expenditures for crews, fuel, insurance, berthing and associated items. As of March 31, 2016 , we had two units stacked, the West Navigator and the West Venture . If our lenders are not confident that we are able to employ our assets, we may be unable to secure additional financing on terms acceptable to us or at all for the remaining installment payments we are obligated to make before the delivery of our remaining newbuildings and our other capital requirements including principal repayments.

Competitive pressures or other factors may also result in significant price competition, particularly during industry downturns, which could have a material adverse effect on our financial position, results of operations, cash flows and ability to pay dividends to our shareholders.

15

---

An economic downturn could have a material adverse effect on our revenue, profitability and financial position.

We depend on our customers’ willingness and ability to fund operating and capital expenditures to explore, develop and produce oil and gas, and to purchase drilling and related equipment. There has historically been a strong link between the development of the world economy and demand for energy, including oil and gas. The world economy is currently facing a number of challenges, including the economic slowdown in China. Concerns persist regarding the debt burden of certain eurozone countries and their ability to meet future financial obligations and the overall stability of the euro. An extended period of adverse development in the outlook for European countries could reduce the overall demand for oil and natural gas and for our services. These potential developments, or market perceptions concerning these and related issues, could affect our financial position, results of operations and profitability, and may have a disproportionate impact on us because we currently operate exclusively offshore in Norway and the United Kingdom. This includes uncertainty surrounding the sovereign debt and credit crises in certain European countries and the continued economic slowdown in the Asia Pacific region, including Japan and China. In addition, turmoil and hostilities in Ukraine, Korea, the Middle East, North Africa and other geographic areas and countries are adding to overall risk.

In addition, worldwide financial and economic conditions could cause our ability to access the capital markets to be severely restricted at a time when we would like, or need, to access such markets, which could impact our ability to react to changing economic and business conditions. Worldwide economic conditions have in the past impacted, and could in the future impact, the lenders participating in our credit facilities and our customers, causing them to fail to meet their obligations to us. In addition, a portion of the credit under our credit facilities is provided by European banking institutions. If economic conditions in Europe preclude or limit financing from these banking institutions, we may not be able to obtain financing from other institutions on terms that are acceptable to us, or at all, even if conditions outside Europe remain favorable for lending.

An extended period of adverse development in the outlook for the world economy could reduce the overall demand for oil and gas and for our services. Such changes could adversely affect our financial condition, results of operations and cash flows.

Failure to obtain or retain highly skilled personnel could adversely affect our operations.

We require highly skilled personnel to operate and provide technical services and support for our business. Competition for skilled and other labor required for our drilling operations has increased in recent years as the number of drilling rigs activated or added to worldwide fleets has increased. If this expansion continues and is coupled with improved demand for drilling services in general, shortages of qualified personnel could further create and intensify upward pressure on wages and make it more difficult for us to staff and service our drilling rigs. Such developments could adversely affect our financial results and cash flow. Furthermore, as a result of any increased competition for people and risk for higher turnover, we may experience a reduction in the experience level of our personnel, which could lead to higher downtime and more operating incidents.

Our labor costs and the operating restrictions that apply to us could increase as a result of collective bargaining negotiations and changes in labor laws and regulations.

The majority of our employees are represented by collective bargaining agreements, mainly in Norway and the United Kingdom. As part of the legal obligations, we are required to contribute certain amounts to retirement funds and pension plans and are restricted in our ability to dismiss employees. In addition, many of these represented individuals are working under agreements that are subject to salary negotiation. These negotiations could result in higher personnel costs, other increased costs or increased operating restrictions that could adversely affect our financial performance.

An inability to obtain visas and work permits for our employees on a timely basis could hurt our operations and have an adverse effect on our business.

Our ability to operate in numerous countries depends on our ability to obtain the necessary visas and work permits for our personnel to travel in and out of, and to work in, the jurisdictions in which we operate. Governmental actions in some of the jurisdictions in which we operate may make it difficult for us to move our personnel in and out of these jurisdictions by delaying or withholding the approval of these permits. If we are not able to obtain visas and work permits for the employees we need for operating our rigs on a timely basis, or for third-party technicians needed for maintenance or repairs, we might not be able to perform our obligations under our drilling contracts, which could allow our customers to cancel the contracts. If our customers cancel some of our contracts, and we are unable to secure new contracts on a timely basis and on substantially similar terms, it could adversely affect our consolidated statement of financial position, results of operations or cash flows.

Interest rate fluctuations could affect our earnings and cash flow.

In order to finance our growth, we have incurred significant amounts of debt. As of March 31, 2016 , with the exception of the $600 Million 6.25% Senior Unsecured Notes due 2019 (issued in January 2014), and the $125 million related party loan to Ship Finance owed by SFL Linus Ltd, our consolidated variable interest entity, our debt arrangements have floating interest rates. As such, significant movements in interest rates could have an adverse effect on our earnings and cash flow. In order to manage our exposure to interest rate fluctuations, we use interest rate swaps to effectively fix a part of our floating rate debt obligations. The principal amount covered by interest rate swaps is evaluated continuously and determined based on our debt level, our expectations regarding future interest rates, our contract backlog and our overall financial risk exposure. As of December 31, 2015 , our net effective exposure to interest rate fluctuations on our outstanding debt was $171.2 million , and an increase or decrease in short-term interest rates of one percentage point would increase or decrease our net effective interest expense by approximately $1.7 million on an annual basis. For more information regarding our debt arrangements. Please see “Item 5. Operating Financial Review and Prospects—B. Liquidity and Capital Resources” and “Item 11. Quantitative and Qualitative Disclosures About Market Risk.”

Fluctuations in exchange rates and non-convertibility of currencies could result in losses to us.

16

---

We use the U.S. dollar as our functional currency because the majority of our revenues and expenses are denominated in U.S. dollars. Accordingly, our reporting currency is also U.S. dollars. However, as a result of our international operations, we are exposed to fluctuations in foreign exchange rates due to parts of our revenues being received and operating expenses paid in currencies other than U.S. dollars. Currently, such currencies include the Norwegian kroner, the British pound sterling, and the Russian ruble. Accordingly, we may experience currency exchange losses if we have not fully hedged our exposure to a foreign currency. For further details about our financial instruments, please see “Item 11. Quantitative and Qualitative Disclosures about Market Risk” and “ Note 22 –Risk Management and Financial Instruments” to our Consolidated Financial Statements included herein. Certain countries where we may operate, such as Russia, place certain controls over currency exchange and the repatriation of income or capital. To the extent that we undertake future operations in such countries or similar laws are enacted in the countries where we operate, we may be unable to collect revenues earned in such countries.

If one of our drilling rigs fails to maintain its class certification or fails any required survey, that drilling rig would be unable to operate, thereby reducing our revenues and profitability.

Every offshore drilling rig is a registered marine vessel and must be “classed” by a classification society. The classification society certifies that the drilling rig is “in-class,” signifying that such drilling rig has been built and maintained in accordance with the rules of the classification society and complies with applicable rules and regulations of the drilling rig’s country of registry and the international conventions of which that country is a member. In addition, where surveys are required by international conventions and corresponding laws and ordinances of a flag state, the classification society will undertake them on application or by official order, acting on behalf of the authorities concerned. Our drilling rigs are certified as being “in class” by Det Norske Veritas, or DNV, and the relevant national authorities in the countries where our drilling rigs operate. If any drilling rig does not maintain its class and/or fails any periodical survey or special survey, the drilling rig will be unable to carry on operations and will be unemployable and uninsurable, which could cause us to be in violation of certain covenants in our credit facilities. Any such inability to carry on operations or be employed could have a material adverse impact on our financial condition, results of operations, and ability to pay dividends to our shareholders.

The use of our drilling rigs may infringe the intellectual property rights of others.

The majority of the intellectual property rights relating to our drilling rigs and related equipment are owned by our suppliers. In the event that one of our suppliers becomes involved in a dispute over infringement of intellectual property rights relating to equipment owned by us, we may lose access to repair services, replacement parts, or could be required to cease use of some equipment. In addition, our competitors may assert claims for infringement of intellectual property rights related to certain equipment on our drilling rigs and we may be required to stop using such equipment and/or pay damages and royalties for the use of such equipment. The consequences of technology disputes involving our suppliers or competitors could adversely affect our financial results and operations. We have provisions in some of our supply contracts for suppliers to provide indemnity to us against intellectual property lawsuits. However, these suppliers may be unwilling or financially unable to honor their indemnity obligations, or the indemnities may not fully protect us from the adverse consequences of such technology disputes. We also have provisions in some of our client contracts to require the client to share some of these risks on a limited basis, but these provisions may not fully protect us from the adverse consequences of such technology disputes.

A change in tax laws of any country in which we operate could result in a higher tax expense or a higher effective tax rate on our earnings.

We conduct our operations through various subsidiaries in various countries. Tax laws, regulations and treaties are highly complex and subject to interpretation. Consequently, we may be subject to changing tax laws, regulations and treaties in and between countries in which we operate. Our income tax expense is based upon our interpretation of the tax laws in effect in various countries at the time that the expense was incurred. A change in these tax laws, regulations or treaties, or in the interpretation thereof, or in the valuation of our deferred tax assets, which such events are beyond our control, may result in a materially higher tax expense or a higher effective tax rate on our earnings.

United States tax authorities may treat us as a “passive foreign investment company” for United States federal income tax purposes, which may have adverse tax consequences to U.S. shareholders .

A foreign corporation will be treated as a “passive foreign investment company,” or PFIC, for United States federal income tax purposes if either (1) at least 75% of its gross income for any taxable year consists of certain types of “passive income” or (2) at least 50% of the average value of the corporation’s assets produce or are held for the production of those types of “passive income.” For purposes of these tests, “passive income” includes dividends, interest, and gains from the sale or exchange of investment property and rents and royalties other than rents and royalties which are received from unrelated parties in connection with the active conduct of a trade or business. For purposes of these tests, income derived from the performance of services does not constitute "passive income." U.S. shareholders of a PFIC are subject to a disadvantageous U.S. federal income tax regime with respect to the income derived by the PFIC, the distributions they receive from the PFIC and the gain, if any, they derive from the sale or other disposition of their shares in the PFIC.

Based on the current and anticipated valuation of our assets, including goodwill, and composition of our income and assets, we intend to take the position that we will not be treated as a PFIC for U.S. federal income tax purposes for our current taxable year or in the foreseeable future. Our position is based on valuations and projections provided regarding our assets and income. While we believe these valuations and projections to be accurate, such valuations and projections may not continue to be accurate. Moreover, as we have not sought a ruling from the Internal Revenue Service, or IRS, on this matter, the IRS or a court could disagree with our position. In addition, although we intend to conduct our affairs in a manner to avoid, to the extent possible, being classified as a PFIC with respect to any taxable year, the nature of our operations may change in the future, and if so, we may not be able to avoid PFIC status in the future.

If the IRS were to find that we are or have been a PFIC for any taxable year, our U.S. holders of our common shares will face adverse U.S. tax consequences. Under the PFIC rules, unless those holders make an election available under the Internal Revenue Code of 1986, as amended, (which election could itself have adverse consequences for such holders, as discussed below under “Item 10. Additional Information—E. Taxation”), such holders would be

17

---

liable to pay United States federal income tax at the then prevailing income tax rates on ordinary income plus interest upon excess distributions and upon any gain from the disposition of our common shares, as if the excess distribution or gain had been recognized ratably over the shareholder’s holding period of our common shares. See “Item 10. Additional Information—E. Taxation-United States Federal Income Taxation of U.S. Holders—Passive Foreign Investment Company” for a more comprehensive discussion of the United States federal income tax consequences to holders of our common shares if we are treated as a PFIC.

We depend on directors who are associated with affiliated companies, which may create conflicts of interest, and Seadrill and its affiliates may compete against us.

Our principal shareholder is Seadrill. Mrs. Kate Blankenship, Mr. Paul M. Leand Jr, Mr. Orjan Svanevik and Mrs. Georgina Sousa are also directors of Seadrill, and serve as directors of other related companies. The aforementioned directors owe fiduciary duties to both us and other related parties, and may have conflicts of interest in matters involving or affecting us and our customers. In addition, they may have conflicts of interest when faced with decisions that could have different implications for Seadrill or other related parties than they do for the Company. Such potential conflicts of interest may not be resolved in our favor.

Pursuant to our cooperation agreement, or the Cooperation Agreement, with Seadrill, we have the right of first refusal to participate in any business opportunity identified by Seadrill for drilling activities in the North Atlantic Region and Seadrill has a right of first refusal to participate in any business opportunity identified by us for drilling activities outside the North Atlantic Region. The Cooperation Agreement, however, contains significant exceptions that may allow Seadrill or any of its affiliates to compete with us, and in certain cases Seadrill has provided Seadrill Partners LLC, or Seadrill Partners, with the right to purchase any drilling rig in Seadrill’s fleet in the event that any such rig enters into a contract with a term of five years or more, which could restrict our growth prospects. Please see “Item 7. Major Shareholders and Related Party Transactions—B. Related Party Transactions.”

Currently, we operate exclusively offshore Norway and the United Kingdom, which have fields that are considered in the industry to be “mature” and as a result, overall activity may decline faster than anticipated.

Currently, we operate exclusively offshore Norway and the United Kingdom (excluding any potential future operations pursuant to the Rosneft contracts). Norway and the United Kingdom have fields that are considered in the industry to be “mature” and as a result, the overall activity in such fields may decline faster than anticipated. There are increased costs associated with retiring old North Sea oil and gas installations, which may threaten to slow the development of the region’s remaining resources. We will rely on work for our drilling rigs being available in the regions where we currently operate, or alternatively, expand our area of operations, to be able to secure new contracts for our drilling rigs when the existing drilling contracts expire.

We may be subject to litigation, arbitration and other proceedings that could have an adverse effect on our business and financial condition.

We are currently involved in various litigation matters and we anticipate that we will be involved in litigation matters from time to time in the future. The operating hazards inherent in the offshore drilling business expose us to litigation, including personal injury litigation, environmental litigation, contractual litigation with customers, intellectual property litigation, tax or securities litigation, and maritime lawsuits including the possible arrest of our drilling rigs. We cannot predict with certainty the outcome or effect of any claim or other litigation matter. If we are involved in any future litigation, or if our positions concerning current disputes are found to be incorrect, this may have an adverse effect on our business, financial position, results of operations and available cash, because of potential negative outcomes, the costs associated with asserting our claims or defending such lawsuits, and the diversion of management’s attention to these matters. For example, we are currently a defendant in a class action lawsuit alleging that we made certain materially false and misleading statements in our public disclosure, including, among other things, that Seadrill, the Company and certain of their respective executives made materially false and misleading statements in connection with the payment of dividends, the failure to disclose the risks to the Rosneft transaction as a result of various enacted government sanctions and the inclusion in backlog of $4.1 billion attributable to the Rosneft transaction. Although we are vigorously defending this action, we cannot predict the outcome of this case, nor can we estimate the amount of any possible loss. Accordingly, no loss contingency has been recognized in our Consolidated Financial Statements. For additional information on these, and other, litigation matters that we are currently involved in, please see “Item 8. Consolidated Statements and Other Financial Information—A. Legal Proceedings.”

Risks Relating to Our Industry

Our business and operations involve numerous operating hazards, and our insurance and indemnities from our customers may not be adequate to cover potential losses from our operations.

Our operations are subject to hazards inherent in the offshore drilling industry, such as blowouts, reservoir damage, loss of production, loss of well control, lost or stuck drill strings, equipment defects, punch-throughs, craterings, fires, explosions and pollution. Contract drilling requires the use of heavy equipment and exposure to hazardous conditions, which may subject us to liability claims by employees, customers and third parties. These hazards can cause personal injury or loss of life, severe damage to or destruction of property and equipment, pollution or environmental damage, claims by third parties or customers and suspension of operations. Our offshore fleet is also subject to hazards inherent in marine operations, either while on-site or during mobilization, such as capsizing, sinking, grounding, collision, piracy, damage from severe weather and marine life infestations. Operations may also be suspended because of machinery breakdowns, abnormal drilling conditions, failure of subcontractors to perform or supply goods or services or personnel shortages. We customarily obtain contract indemnities from our customers for claims that could be asserted by us relating to damage to or loss of our equipment, including rigs, and claims that could be asserted by us or our employees relating to personal injury or loss of life.

Damage to the environment could also result from our operations, particularly through spillage of hydrocarbons, fuel, lubricants or other chemicals and substances used in drilling operations, or extensive uncontrolled fires. We may also be subject to property damage, environmental indemnity and other claims by oil and gas companies. Our insurance policies and drilling contracts contain rights to indemnity that may not adequately cover our losses, and

18

---

we do not have insurance coverage or rights to indemnity for all risks. Consistent with standard industry practice, our customers generally assume, and indemnify us against, well control and subsurface risks under dayrate contracts. These are risks associated with the loss of control of a well, such as blowout or cratering, the cost to regain control of or re-drill the well and associated pollution. However, there can be no assurance that these customers will be willing or financially able to indemnify us against all these risks. In addition, a court may decide that certain indemnities in our current or future contracts are not enforceable. For example, in a 2012 case related to the fire and explosion that took place on the unaffiliated Deepwater Horizon Mobile Offshore Drilling Unit in the Gulf of Mexico in April 2010, or the Deepwater Horizon Incident (to which we were not a party), the U.S. District Court for the Eastern District of Louisiana invalidated certain contractual indemnities for punitive damages and for civil penalties under the U.S. Clean Water Act under a drilling contract governed by U.S. maritime law as a matter of public policy. In addition, pollution and environmental risks generally are not totally insurable. See “Item 4. Information on the Company—B.Business Overview-Risk of Loss and Insurance Coverage.”

If a significant accident or other event occurs that is not fully covered by our insurance or an enforceable or recoverable indemnity from a customer, the occurrence could adversely affect our financial position, results of operations or profitability. The amount of our insurance may also be less than the related impact on enterprise value after a loss. Our insurance coverage will not in all situations provide sufficient funds to protect us from all liabilities that could result from our drilling operations. Our coverage includes annual aggregate policy limits. As a result, we retain the risk for any losses in excess of these limits. Any such lack of reimbursement may cause us to incur substantial costs. In addition, we could decide to retain more risk in the future. This results in a higher risk of losses, which could be material, which are not covered by third-party insurance contracts. Moreover, we may not be able to maintain adequate insurance in the future at rates that we consider reasonable, or obtain insurance against certain risks.

Governmental laws and regulations, including environmental laws and regulations, may add to our costs, expose us to liability or limit our drilling activity.

Our business in the offshore drilling industry is affected by laws and regulations relating to the energy industry and the environment in the geographic areas where we operate, including international conventions and treaties, and regional, national, state and local laws and regulations (including those of the International Maritime Organization, European Union, the United Kingdom and Norway). The offshore drilling industry is dependent on demand for services from the oil and gas exploration and production industry, and, accordingly, we are directly affected by the adoption of laws and regulations that, for economic, environmental or other policy reasons, curtail exploration and development drilling for oil and gas. Compliance with such laws, regulations and standards, where applicable, may require us to make significant capital expenditures, such as installation of costly equipment or operational changes, and may affect the resale value or useful lifetime of our rigs. We may also incur additional costs in order to comply with other existing and future regulatory obligations, including, but not limited to, costs relating to air emissions, including greenhouse gases, the management of ballast waters, maintenance and inspection, development and implementation of emergency procedures and insurance coverage or other financial assurance of our ability to address pollution incidents. Further, our ability to compete in international offshore contract drilling markets may be limited by foreign governmental regulations that favor or require the awarding of contracts to local contractors or by regulations requiring foreign contractors to employ citizens of, or purchase supplies from, a particular jurisdiction. Governments in some countries are increasingly active in regulating and controlling the ownership of concessions, the exploration for oil and gas, and other aspects of the oil and gas industries. Offshore drilling in certain areas, including arctic areas, has been curtailed and, in certain cases, prohibited because of concerns over protection of the environment. These costs could have a material adverse effect on our business, results of operations, cash flows and financial condition. A failure to comply with applicable laws and regulations may result in administrative and civil penalties, criminal sanctions or the suspension or termination of our operations.

To the extent new laws are enacted or other governmental actions are taken that prohibit or restrict offshore drilling or impose additional environmental protection requirements that result in increased costs to the oil and gas industry, in general, or the offshore drilling industry, in particular, our business or prospects could be materially adversely affected. Environmental protection of arctic regions is a particularly sensitive issue in some countries, and may be subject to special additional new regulations. The operation of our drilling rigs will require certain governmental approvals. Depending on the jurisdiction, these governmental approvals may involve public hearings and costly undertakings on our part. We may not obtain such approvals or such approvals may not be obtained in a timely manner. If we fail to timely secure the necessary approvals or permits, our customers may have the right to terminate or seek to renegotiate their drilling contracts to our detriment. The amendment or modification of existing laws and regulations or the adoption of new laws and regulations curtailing or further regulating exploratory or development drilling and production of oil and gas could have a material adverse effect on our business, results of operations or financial condition. Future earnings may be negatively affected by compliance with any such new legislation or regulations.

As an operator of mobile drilling rigs, we may be liable for damages and costs incurred in connection with spills of oil and other chemicals and substances related to our operations, and we may also be subject to significant fines in connection with spills. For example, an oil spill could result in significant liability, including fines, penalties and criminal liability and remediation costs for natural resource damages under other international laws, as well as third-party damages, to the extent that the contractual indemnification provisions in our drilling contracts are not sufficient, or if our clients are unwilling or unable to contractually indemnify us from these risks. Additionally, we may not be able to obtain such indemnities in our future contracts and our clients may not have the financial capability to fulfill their contractual obligations to us. Also, these indemnities may be held to be unenforceable in certain jurisdictions, as a result of public policy or for other reasons. Laws and regulations protecting the environment have become more stringent in recent years, and may in some cases impose strict liability, rendering a person liable for environmental damage without regard to negligence. These laws and regulations may expose us to liability for the conduct of or conditions caused by others, or for acts that were in compliance with all applicable laws at the time when such acts were performed. The application of these requirements or the adoption of new requirements could have a material adverse effect on our financial position, results of operations or cash flows.

We are subject to complex environmental laws and regulations that can adversely affect the cost, manner or feasibility of doing business.

Our operations are subject to numerous international, national, state and local laws and regulations, treaties and conventions in force in international waters and the jurisdictions in which our drilling units operate or are registered, which can significantly affect the ownership and operation of our drilling

19

---

units. These requirements include, but are not limited to the United Nation's International Maritime Organization, IMO, the International Convention for the Prevention of Pollution from Ships of 1973, as from time to time amended and generally referred to as MARPOL, including the designation of Emission Control Areas, or ECAs thereunder, the IMO International Convention on Civil Liability for Oil Pollution Damage of 1969, as from time to time amended and generally referred to as CLC, the International Convention on Civil Liability for Bunker Oil Pollution Damage, or the Bunker Convention, the International Convention for the Safety of Life at Sea of 1974 as from time to time amended and generally referred to as SOLAS, the International Safety Management Code for the Safe Operation of Ships and for Pollution Prevention, or ISM Code, the IMO International Convention on Load Lines in 1966, as from time to time amended, the International Convention for the Control and Management of Ships’ Ballast Water and Sediments in February 2004, or the BWM Convention, and European Union, or EU, regulations. Compliance with such laws, regulations and standards, where applicable, may require installation of costly equipment or implementation of operational changes and may affect the resale value or useful lifetime of our drilling units. These costs could have a material adverse effect on our business, results of operations, cash flows and financial condition. A failure to comply with applicable laws and regulations may result in administrative and civil penalties, criminal sanctions or the suspension or termination of our operations. Because such conventions, laws, and regulations are often revised, we cannot predict the ultimate cost of complying with them or the impact thereof on the resale prices or useful lives of our rigs. Additional conventions, laws and regulations may be adopted which could limit our ability to do business or increase the cost of our doing business and which may materially adversely affect our operations.

Environmental laws often impose strict liability for remediation of spills and releases of oil and hazardous substances, which could subject us to liability without regard to whether we were negligent or at fault. Furthermore, the 2010 explosion of the Deepwater Horizon well and the subsequent release of oil into the Gulf of Mexico, or other similar events, may result in further regulation of the shipping industry, and modifications to statutory liability schemes, thus exposing us to further potential financial risk in the event of any such oil or chemical spill in the future.

We are required by various governmental and quasi-governmental agencies to obtain certain permits, licenses, and certificates with respect to our operations, and satisfy insurance and financial responsibility requirements for potential oil (including marine fuel) spills and other pollution incidents. Although we have arranged insurance to cover certain environmental risks, there can be no assurance that such insurance will be sufficient to cover all such risks or that any claims will not have a material adverse effect on our business, results of operations, cash flows, financial condition and our ability to pay dividends, if any, in the future.

Although our drilling units are separately owned by our subsidiaries, under certain circumstances a parent company and all of the unit-owning affiliates in a group under common control engaged in a joint venture could be held liable for damages or debts owed by one of the affiliates, including liabilities for oil spills under environmental laws. Therefore, it is possible that we could be subject to liability upon a judgment against us or any one of our subsidiaries.

Our drilling units could cause the release of oil or hazardous substances. Any releases may be large in quantity, above our permitted limits or occur in protected or sensitive areas where public interest groups or governmental authorities have special interests. Any releases of oil or hazardous substances could result in fines and other costs to us, such as costs to upgrade our drilling rigs, clean up the releases, and comply with more stringent requirements in our discharge permits. Moreover, these releases may result in our customers or governmental authorities suspending or terminating our operations in the affected area, which could have a material adverse effect on our business, results of operations and financial condition.

If we are able to obtain from our customers some degree of contractual indemnification against pollution and environmental damages in our contracts, such indemnification may not be enforceable in all instances or the customer may not be financially able to comply with its indemnity obligations in all cases, and we may not be able to obtain such indemnification agreements in the future. In addition, a court may decide that certain indemnities in our current or future contracts are not enforceable.

Our insurance coverage may not be available in the future, or we may not obtain certain insurance coverage. Even if insurance is available and we have obtained the coverage, it may not be adequate to cover our liabilities or our insurance underwriters may be unable to pay compensation if a significant claim should occur. Any of these scenarios could have a material adverse effect on our business, results of operations and financial condition.

Climate change and greenhouse gas restrictions may adversely impact our operations and markets.

Due to concerns over the risk of climate change, a number of countries and the United Nations’ International Maritime Organization, or IMO, have adopted, or are considering the adoption of, regulatory frameworks to reduce greenhouse gas emissions. Currently, the emissions of greenhouse gases from ships involved in international transport are not subject to the Kyoto Protocol to the United Nations Framework Convention on Climate Change, which entered into force in 2005 and pursuant to which adopting countries have been required to implement national programs to reduce greenhouse gas emissions. As of January 1, 2013, all ships (including rigs and drillships) must comply with mandatory requirements adopted by the IMO’s Maritime Environment Protection Committee, or the MEPC, in July 2011 relating to greenhouse gas emissions. These requirements could cause us to incur additional compliance costs. In addition, the European Union has indicated that it intends to propose an expansion of the existing European Union emissions trading scheme to include emissions of greenhouse gases from marine vessels.The 2015 United Nations Climate Change Conference in Paris did not result in an agreement that directly limits greenhouse gas emissions from ships.

All ships are required to follow the Ship Energy Efficiency Management Plans, or SEEMP, and minimum energy efficiency levels per capacity mile, outlined in the Energy Efficiency Design Index, or EEDI, applies to all new ships. These requirements could cause us to incur additional compliance costs. The IMO is planning to implement market-based mechanisms to reduce greenhouse gas emissions from ships at an upcoming MEPC session. In April 2013, the European Union Parliament rejected proposed changes to the European Union Emissions law regarding carbon trading. The measures would have limited the availability of permits that allow companies to emit greenhouse gases. The European Union is still considering an expansion of

20

---

the existing European Union emissions trading scheme to include emissions of greenhouse gases from marine vessels, including drilling units, and in June 2013, the European Commission issued a memorandum recommending a “gradual approach” starting with a program to monitor, report and verify such greenhouse gas emissions from ships. In April 2015, a regulation was adopted requiring that large ships (over 5,000 gross tons) calling at European Union ports from January 2018 collect and publish data on carbon dioxide emissions and other information. In the United States, the EPA has issued a finding that greenhouse gases endanger the public health and safety and has adopted regulations to limit greenhouse gas emissions from certain mobile sources and large stationary sources. Although the mobile source emissions regulations do not apply to greenhouse gas emissions from drilling units, such regulation of drilling units is foreseeable, and the EPA has in recent years received petitions from the California Attorney General and various environmental groups seeking such regulation.

Compliance with changes in laws, regulations and obligations relating to climate change could increase our costs related to operating and maintaining our assets, and might also require us to install new emission controls, acquire allowances or pay taxes related to our greenhouse gas emissions, or administer and manage a greenhouse gas emissions program. Any passage of climate control legislation or other regulatory initiatives by the IMO, European Union, the United States or other countries where we operate, or any treaty adopted at the international level to succeed the Kyoto Protocol, that restrict emissions of greenhouse gases could require us to make significant financial expenditures which we cannot predict with certainty at this time.

Additionally, adverse effects upon the oil and gas industry relating to climate change, including growing public concern about the environmental impact of climate change, may also adversely affect demand for our services. For example, increased regulation of greenhouse gases or other concerns relating to climate change may reduce the demand for oil and gas in the future or create greater incentives for use of alternative energy sources. Any long-term material adverse effect on the oil and gas industry could have a significant financial and operational adverse impact on our business. Please see “Item 4. Information on the Company—B. Business Overview—Environmental and Other Regulations.”

The Deepwater Horizon oil spill in the U.S. Gulf of Mexico has and may result in more stringent laws and regulations governing offshore drilling, which could have a material adverse effect on our business, results of operations or financial condition.

On April 20, 2010, there was an explosion and a related fire on the Deepwater Horizon, an ultra-deepwater semi-submersible drilling rig that is not connected to us, while it was servicing a well in the U.S. Gulf of Mexico. This catastrophic event resulted in the death of 11 workers and the total loss of that drilling rig, as well as the release of large amounts of oil into the U.S. Gulf of Mexico, impacting the environment and the region’s key industries. This event was investigated by several federal agencies, including the U.S. Department of Justice and by the U.S. Congress, and was also the subject of numerous lawsuits. On January 3, 2013, Transocean Deepwater Inc. agreed to plead guilty to violating the U.S. Clean Water Act and to pay $1.4 billion in civil and criminal fines and penalties for its conduct in relation to the incident. On May 30, 2010, the U.S. Department of the Interior issued a six-month moratorium on all deepwater drilling in the outer continental shelf regions of the U.S. Gulf of Mexico and the Pacific Ocean. On October 12, 2010, the U.S. government lifted the drilling moratorium, subject to compliance with enhanced safety requirements. All drilling in the U.S. Gulf of Mexico must comply with the Interim Final Rule to Enhance Safety Measures for Energy Development on the Outer Continental Shelf (Drilling Safety Rule), which took effect October 22, 2012, and the Workplace Safety Rule on Safety and Environmental Management Systems and various requirements imposed through Notices to Lessees and Operators, or SEMS. Operators were required to implement a SEMS program by November 15, 2011 and submit their first completed SEMS audit to BSEE by November 15, 2013. The original SEMS rule was later modified by the SEMS II final rule which became effective June 4, 2013. SEMS II enhanced and supplemented operators' SEMS programs with employee training, empowering field level personnel with safety management decisions and strengthening auditing procedures by requiring them to be completed by independent third parties. Operators had until June 4, 2014 to comply with SEMS II, except for certain auditing requirements. All SEMS audits had to comply with SEMS II by June 4, 2015. The U.S. Occupational Safety and Health Act (OSHA) imposes additional record keeping obligations concerning occupational injuries and illnesses for Mobile Offshore Drilling Units attached to the outer continental shelf.

While we do not currently operate any of our drilling rigs in the U.S. Gulf of Mexico, these developments could have a substantial impact on the offshore oil and gas industry worldwide. Governmental investigations and proceedings may result in significant changes to existing laws and regulations and substantially stricter governmental regulation of our drilling rigs. For example, Norway’s Petroleum Safety Authority is assessing the results of the investigations into the Deepwater Horizon oil spill and issued a preliminary report of its recommendations in June 2011, and Oil & Gas United Kingdom has established the Oil Spill Prevention and Response Advisory Group, which issued its final report on industry practices in the United Kingdom in September 2011. In addition, BP plc, a company not affiliated with us and the rig operator of the Deepwater Horizon, has reached an agreement with the U.S. government to establish a claims fund of $20 billion, which far exceeds the $75 million strict liability limit set forth under the U.S. Oil Pollution Act of 1990. Amendments to existing laws and regulations or the adoption of new laws and regulations curtailing or further regulating exploratory or development drilling and the production of oil and gas, may be highly restrictive and require costly compliance measures that could have a material adverse effect on our business, results of operations or financial condition. Future earnings may be negatively affected by compliance with any such amended or new legislation or regulations.

It is possible in the future for our drilling units to be located in countries that are subject to economic sanctions or other operating restrictions imposed by the United States or other governments, our reputation and the market for our common shares could be adversely affected.

In 2010, the U.S. enacted the Comprehensive Iran Sanctions Accountability and Divestment Act or CISADA, which expanded the scope of the former Iran Sanctions Act. Among other things, CISADA expands the application of the prohibitions to non-U.S. companies such as ours, and introduced limits on the ability of companies and persons to do business or trade with Iran when such activities relate to the investment, supply or export of refined petroleum or petroleum products. On August 10, 2012, the U.S. signed into law the Iran Threat Reduction and Syria Human Rights Act of 2012, or the Iran Threat Reduction Act, which places further restrictions on the ability of non-U.S. companies to do business or trade with Iran and Syria. Perhaps the most significant provision in the Iran Threat Reduction Act is that prohibitions in the existing Iran sanctions applicable to U.S. persons will now apply to any foreign entity owned or controlled by a U.S. person. These new sanctions were codified within the Iranian Transactions Regulations on or

21

---

about December 26, 2012. The other major provision in the Iran Threat Reduction Act is that issuers of securities must disclose to the Commission in their annual and quarterly reports filed after February 6, 2013 if the issuer or “any affiliate” has “knowingly” engaged in certain sanctioned activities involving Iran during the timeframe covered by the report. The disclosure must describe the nature and extent of the activity in detail and the Commission will publish the disclosure on its website. The President of the U.S. must then initiate an investigation and determine whether sanctions on the issuer or its affiliate will be imposed. Such negative publicity and the possibility that sanctions could be imposed would present a risk for any issuer that is knowingly engaged in sanctioned conduct or that has an affiliate that is knowingly engaged in such conduct. At this time, we are not aware of any violative activity, conducted by ourselves or by any affiliate, which is likely to trigger a Commission disclosure requirement.

Certain of our customers or other parties that we have entered into contracts with may be the subject of sanctions imposed by the United States, the European Union, Norway and / or other international bodies as a result of the annexation of Crimea by Russia in 2014 and the subsequent conflict in eastern Ukraine, or may be affiliated with persons or entities that are the subject of such sanctions. If we determine that such sanctions require us to terminate existing contracts or if we are found to be in violation of such applicable sanctions, our results of operations may be adversely affected or we may suffer reputational harm. In addition, such sanctions may prevent us from closing the previously announced transactions between us and Rosneft, or performing some or all of our obligations under the drilling contracts with Rosneft, which could impact our future revenue, contract backlog, and results of operations.

In addition, various U.S. sanctions have certain extraterritorial effects that need to be considered by non-U.S. companies. Moreover, any U.S. persons who serve as officers, directors or employees of our subsidiaries would be fully subject to U.S. sanctions. It should also be noted that other governments are more frequently implementing versions of U.S. sanctions. However, from time to time, we may enter into drilling contracts with countries or government-controlled entities that are subject to sanctions and embargoes imposed by the U.S. government and/or identified by the U.S. government as state sponsors of terrorism where entering into such contracts would not violate U.S. law, or may enter into drilling contracts involving operations in countries or with government-controlled entities that are subject to sanctions and embargoes imposed by the U.S government and/or identified by the U.S. government as state sponsors of terrorism. However, this could negatively affect our ability to obtain investors. In some cases, U.S. investors would be prohibited from investing in an arrangement in which the proceeds could directly or indirectly be transferred to or may benefit a sanctioned entity. Moreover, even in cases where the investment would not violate U.S. law, potential investors could view such drilling contracts negatively, which could adversely affect our reputation and the market for our shares. With the exception of certain drilling contracts between us and Rosneft, we do not currently have any drilling contracts or plans to initiate any drilling contracts involving operations in countries or with government-controlled entities that are subject to sanctions and embargoes imposed by the U.S. government and/or identified by the U.S. government as state sponsors of terrorism.

On November 24, 2013, the P5+1 (the United States, United Kingdom, Germany, France, Russia and China) entered into an interim agreement with Iran entitled the "Joint Plan of Action", or JPOA. Under the JPOA it was agreed that, in exchange for Iran taking certain voluntary measures to ensure that its nuclear program is only used for peaceful purposes, the United States and the European Union would voluntarily suspend certain sanctions for a period of six months. On January 20, 2014, the United States and the European Union indicated that they would begin implementing the temporary relief measures provided for under the JPOA. These measures include, among other things, the suspension of certain sanctions on the Iranian petrochemicals, precious metals and automotive industries from January 20, 2014 to July 20, 2014.

The JPOA was subsequently extended twice. On July 14, 2015, the P5+1 and the E.U. announced that they reached a landmark agreement with Iran titled the Joint Comprehensive Plan of Action Regarding the Islamic Republic of Iran’s Nuclear Program, or the JCPOA, which is intended to significantly restrict Iran’s ability to develop and produce nuclear weapons for 10 years while simultaneously easing sanctions directed toward non-U.S. persons for conduct involving Iran, but taking place outside of U.S. jurisdiction and does not involve U.S. persons. On January 16, 2016 (“Implementation Day”), the United States joined the E.U. and the U.N. in lifting a significant number of their nuclear-related sanctions on Iran following an announcement by the International Atomic Energy Agency, or the IAEA, that Iran had satisfied its respective obligations under the JCPOA.

U.S. sanctions prohibiting certain conduct that is now permitted under the JCPOA have not actually been repealed or permanently terminated at this time. Rather, the U.S. government has implemented changes to the sanctions regime by: (1) issuing waivers of certain statutory sanctions provisions; (2) committing to refrain from exercising certain discretionary sanctions authorities; (3) removing certain individuals and entities from OFAC's sanctions lists; and (4) revoking certain Executive Orders and specified sections of Executive Orders. These sanctions will not be permanently "lifted" until the earlier of “Transition Day,” set to occur on October 20, 2023, or upon a report from the IAEA stating that all nuclear material in Iran is being used for peaceful activities.

As stated above, we believe that we are in compliance with all applicable sanctions and embargo laws and regulations, and intend to maintain such compliance. However, there can be no assurance that we will be in compliance in the future, particularly as the scope of certain laws may be unclear and may be subject to changing interpretations. Any such violation could result in fines or other penalties and could result in some investors deciding, or being required, to divest their interest, or not to invest, in our shares. Additionally, some investors may decide to divest their interest, or not to invest, in our shares simply because we may do business with companies that do business in sanctioned countries. Moreover, our drilling contracts may violate applicable sanctions and embargo laws and regulations as a result of actions that do not involve us, or our drilling rigs, and those violations could in turn negatively affect our reputation. Investor perception of the value of our shares may also be adversely affected by the consequences of war, the effects of terrorism, civil unrest and governmental actions in these and surrounding countries.

Any failure to comply with the complex laws and regulations governing international trade could adversely affect our operations.

The shipment of goods, services and technology across international borders subjects our offshore drilling segment to extensive trade laws and regulations. Import activities are governed by unique customs laws and regulations in each of the countries of operation. Moreover, many countries, including the

22

---

United States, control the export and re-export of certain goods, services and technology and impose related export recordkeeping and reporting obligations. Governments also may impose economic sanctions against certain countries, persons and other entities that may restrict or prohibit transactions involving such countries, persons and entities. U.S. sanctions in particular are targeted against countries (such as Russia, Venezuela, Iran, Myanmar and Sudan, among others) that are heavily involved in the petroleum and petrochemical industries, which includes drilling activities.

The laws and regulations concerning import activity, export recordkeeping and reporting, export control and economic sanctions are complex and constantly changing. These laws and regulations may be enacted, amended, enforced or interpreted in a manner materially impacting our operations. Shipments can be delayed and denied export or entry for a variety of reasons, some of which are outside our control and some of which may result from failure to comply with existing legal and regulatory regimes. Shipping delays or denials could cause unscheduled operational downtime. Any failure to comply with applicable legal and regulatory trading obligations could also result in criminal and civil penalties and sanctions, such as fines, imprisonment, debarment from government contracts, seizure of shipments and loss of import and export privileges.

Failure to comply with the United States Foreign Corrupt Practices Act of 1977 or the Bribery Act 2010 of the United Kingdom could result in fines, criminal penalties, drilling contract terminations and an adverse effect on our business.

We operate our drilling rigs in a number of countries. Our business with national oil companies, as well as state or government-owned shipbuilding enterprises and financing agencies may put us in contact with persons who may be considered to be “foreign officials” under the Foreign Corrupt Practices Act, or FCPA, and the U.K. Bribery Act 2010 of the United Kingdom, or the U.K. Bribery Act. We are subject to the risk that we, our affiliated entities or our or their respective officers, directors, employees and agents may take actions determined to be in violation of anti-corruption laws, including the FCPA and the U.K. Bribery Act. Any such violation could result in substantial fines, sanctions, civil and/or criminal penalties, curtailment of operations in certain jurisdictions, and such violations or allegations of such violations might adversely affect our business, results of operations or financial condition. In addition, actual or alleged violations could damage our reputation and ability to do business. Furthermore, detecting, investigating and resolving actual or alleged violations is expensive and can consume significant time and attention of our senior management.

In order to effectively compete in some foreign jurisdictions, we may utilize local agents and/or establish entities with local operators or strategic partners. All of these activities may involve interaction by our agents with government officials. Even though some of our agents and partners may not themselves be subject to the FCPA, the U.K. Bribery Act or other anti-bribery laws to which we may be subject, if our agents or partners make improper payments to government officials or other persons in connection with engagements or partnerships with us, we could be investigated and potentially found liable for violation of such anti-bribery laws and could incur civil and criminal penalties and other sanctions, which could have a material adverse effect on our business and results of operation.

Consolidation and governmental regulation of suppliers may increase the cost of obtaining supplies or restrict our ability to obtain needed supplies, which may have a material adverse effect on our results of operations and financial condition.

We rely on certain third parties to provide supplies and services necessary for our offshore drilling operations, including drilling equipment suppliers, caterers and machinery suppliers. The number of available suppliers is limited, resulting in fewer alternatives for sourcing key supplies. With respect to certain items, such as blow-out preventers, or BOPs, we are generally dependent upon the original equipment manufacturer for repair and replacement of the item or its spare parts. Such consolidation, combined with a high volume of drilling rigs under construction, may result in a shortage of supplies and services thereby increasing the cost of supplies and/or potentially inhibiting the ability of suppliers to deliver on time. For instance, several drilling companies, including Seadrill, experienced significant interruption of operations in early 2013 as a result of a defective batch of connector bolts procured by a supplier of BOP equipment, and the only source of approved replacement bolts was that same supplier. Similar cost increases or delays could have a material adverse effect on our results of operations and result in rig downtime, and delays in the repair and maintenance of our drilling rigs. Furthermore, many of our suppliers are U.S. companies or non-U.S. subsidiaries owned or controlled by U.S. companies, which means that in the event a U.S. supplier was debarred or otherwise restricted by the U.S. government from delivering products, our ability to supply and service our operations could be materially impacted. In addition, through regulation and permitting, certain foreign governments effectively restrict the number of suppliers and technicians available to supply and service our operations in those jurisdictions, which could materially impact our operations.

Acts of terrorism, piracy and political and social unrest could affect the markets for drilling services, which may have a material adverse effect on our results of operations.

Acts of terrorism, piracy and political and social unrest, brought about by world political events or otherwise, have caused instability in the world’s financial and insurance markets in the past and may occur in the future. Such acts could be directed against companies such as ours or our customers. Our drilling operations could also be targeted by acts of piracy. In addition, acts of terrorism and social unrest could lead to increased volatility in prices for crude oil and gas and could affect the markets for drilling services and result in lower dayrates. Insurance premiums could also increase and coverage may be unavailable in the future. Increased insurance costs or increased cost of compliance with applicable regulations may have a material adverse effect on our results of operations.

A cyber-attack could materially disrupt our business.

We rely on information technology systems and networks in our operations and administration of our business. Our drilling operations or other business operations could be targeted by individuals or groups seeking to sabotage or disrupt our information technology systems and networks, or to steal data. A successful cyber-attack could materially disrupt our operations, including the safety of our operations, or lead to unauthorized release of information or alteration of information on our systems. Any such attack or other breach of our information technology systems could have a material adverse effect on our business and results of operations.

23

---

We may not be able to keep pace with the continual and rapid technological developments that characterize the market for our services, and our failure to do so may result in our loss of market share.

The market for our services is characterized by continual and rapid technological developments that have resulted in, and will likely continue to result in, substantial improvements in equipment functions and performance. As a result, our future success and profitability will be dependent in part upon our ability to keep pace with technological developments. If we are not successful in acquiring new equipment or upgrading our existing equipment in a timely and cost-effective manner in response to technological developments or changes in standards in our industry, we could lose business and profits. The cost of upgrading our equipment may increase as our fleet ages, which could adversely affect our financial performance. In addition, current competitors or new market entrants may develop new technologies, services or standards that could render some of our services or equipment obsolete, which could have a material adverse effect on our operations.

In addition, we currently operate in Norway and the United Kingdom. If we are unable to expand our operations and pursue harsh environment drilling operations in other locations in the North Atlantic Region, it could have a material adverse effect on our operations.

Public health threats could have an adverse effect on our operations and our financial results.

Public health threats, such as ebola, influenza, severe acute respiratory syndrome (SARS), the Zika Virus, and other highly communicable diseases or viruses, outbreaks of which have from time to time occurred in various parts of the world in which we operate, could adversely impact our operations, and the operations of our customers. In addition, public health threats in any area, including areas where we do not operate, could disrupt international transportation. Our crews generally work on a rotation basis, and as we expand outside operations in the U.K. and Norway, a substantial portion of our crews may begin to rely on international air transport for rotation. Any such disruptions could impact the cost of rotating our crews, and possibly impact our ability to maintain a full crew on all rigs at a given time. Any of these public health threats and related consequences could adversely affect our financial results.

Risks Relating to Our Common Shares

The market price of our common shares has recently declined significantly.  If the average closing price of our common shares declines to less than $1.00 over 30 consecutive trading days, our common shares could be delisted from the NYSE or trading could be suspended.

Our common shares are currently listed on the NYSE. In order for our common shares to continue to be listed on the NYSE, we are required to comply with various listing standards, including the maintenance of a minimum average closing price of at least $1.00 per share during a consecutive 30 trading-day period. For example, on August 20, 2015, we received notice from the New York Stock Exchange, or NYSE, that we were not in compliance with the NYSE’s continued listing standards because the average closing share price of our common stock for the consecutive 30 trading-day period ending on August 17, 2015 had fallen below the requirement to be at least $1.00 per share. This notice did not have an immediate effect on the NYSE listing of our common shares. Following our 1 for 10 reverse stock split and capital reduction, which was completed on December 30, 2015, we received notification from the NYSE on February 1, 2016, that we are now in compliance with the continued listing criterion.

A renewed or continued decline in the closing price of our common shares on the NYSE could result in a breach of these requirements. Although we would have an opportunity to take action to cure such a breach, if we did not succeed, the NYSE could commence suspension or delisting procedures in respect of our common shares. The commencement of suspension or delisting procedures by an exchange remains, at all times, at the discretion of such exchange and would be publicly announced by the exchange. If a suspension or delisting were to occur, there would be significantly less liquidity in the suspended or delisted securities. In addition, our ability to raise additional necessary capital through equity or debt financing would be greatly impaired. Furthermore, with respect to any suspended or delisted common shares, we would expect decreases in institutional and other investor demand, analyst coverage, market making activity and information available concerning trading prices and volume, and fewer broker-dealers would be willing to execute trades with respect to such common shares. A suspension or delisting would likely decrease the attractiveness of our common shares to investors and cause the trading volume of our common shares to decline, which could result in a further decline in the market price of our common shares.

Seadrill controls a substantial ownership stake in us and Seadrill’s interests could conflict with interest of our other shareholders.

As the date of this Annual Report, Seadrill owns approximately 70.4% of our outstanding common shares. As a result of this substantial ownership interest, Seadrill currently has the ability to exert significant influence over certain actions requiring shareholders’ approval, including, increasing or decreasing the authorized share capital, the election of directors, declaration of dividends, the appointment of management, and other policy decisions. While transactions with Seadrill could benefit us, the interests of Seadrill could at times conflict with the interests of our other shareholders. Conflicts of interest may arise between us and Seadrill or its affiliates, which may result in the conclusion of transactions on terms not determined by market forces. Any such conflicts of interest could adversely affect our business, financial condition and results of operations, and the trading price of our common shares.

Seadrill may reduce its ownership interest in us.

The potential transactions announced with Rosneft will, if consummated, result in a reduction in Seadrill's ownership interest in us. While it is contemplated that Seadrill will continue to hold a majority ownership interest in us upon closing of the Rosneft transactions, we can provide no assurance that Seadrill will not agree with Rosneft to further reduce its ownership in us, or negotiate another transaction to reduce its ownership in us. If Seadrill were to reduce its ownership in us to a minority interest, we can provide no assurance that Seadrill would continue to provide support or management services to us, and we can provide no assurance that we would be able to replace Seadrill’s support and services with the support and services of a third party that would be of the same quality or at the same cost.

Because we are a foreign corporation, you may not have the same rights that a shareholder in a U.S. corporation may have.

24

---

We are a Bermuda exempted company. Our memorandum of association and bye-laws and the Companies Act, 1981 of Bermuda, or the Companies Act, govern our affairs. The Companies Act does not as clearly establish your rights and the fiduciary responsibilities of our directors as do statutes and judicial precedent in some U.S. jurisdictions. Therefore, you may have more difficulty in protecting your interests as a shareholder in the face of actions by the management, directors or controlling shareholders than would shareholders of a corporation incorporated in a United States jurisdiction. There is a statutory remedy under Section 111 of the Companies Act which provides that a shareholder may seek redress in the courts as long as such shareholder can establish that our affairs are being conducted, or have been conducted, in a manner oppressive or prejudicial to the interests of some part of the shareholders, including such shareholder. However, you may not have the same rights that a shareholder in a U.S. corporation may have.

We are incorporated in Bermuda and it may not be possible for our investors to enforce U.S. judgments against us.

We are incorporated in Bermuda and substantially all of our assets are located outside the United States. In addition, most of our directors and some of our executive officers are non-residents of the United States. As a result, it may be difficult or impossible for U.S. investors to serve process in the United States upon us or our directors and executive officers, or to enforce a judgment against us for civil liabilities in U.S. courts.

In addition, you should not assume that courts in the countries in which we are incorporated or where our assets are located would enforce judgments of U.S. courts obtained in actions against us based upon the civil liability provisions of applicable U.S. federal and state securities laws or would enforce, in original actions, liabilities against us based on those laws.

Our costs of operating as a public company are and will be significant, and our management is and will be required to devote substantial time to complying with public company regulations.

We are subject to the reporting requirements of the Securities Exchange Act of 1934, as amended, or the Exchange Act, and the other rules and regulations of the Commission, including the Sarbanes-Oxley Act of 2002, or the Sarbanes-Oxley Act, and as such, we have, and will continue to have, significant legal, accounting and other expenses that we did not incur prior to our initial public offering in the United States. These reporting obligations impose various requirements on public companies, including changes in corporate governance practices, and these requirements may continue to evolve. We and our management personnel, and other personnel, if any, devote, and will need to continue to devote a substantial amount of time to comply with these requirements. Moreover, these rules and regulations increase our legal and financial compliance costs and make some activities more time-consuming and costly.

The Sarbanes-Oxley Act requires, among other things, that we maintain and periodically evaluate our internal control over financial reporting and disclosure controls and procedures. In particular, we need to perform system and process evaluation and testing of our internal control over financial reporting to allow management and our independent registered public accounting firm to report on the effectiveness of our internal control over financial reporting, as required by Section 404 of the Sarbanes-Oxley Act. Our compliance with Section 404 requires that we incur substantial accounting expenses and expend significant management efforts.

An active and liquid market for our common shares may not develop or be sustained and the price of our common shares may be highly volatile.

Our common shares have only traded on the NYSE since January 29, 2014 and on the Norwegian OTC List since February 24, 2011. Active, liquid trading markets generally result in lower bid ask spreads and more efficient execution of buy and sell orders for market participants. If an active trading market for the common shares does not develop, the price of the common shares may be more volatile and it may be more difficult and time consuming to complete a transaction in the common shares, which could have an adverse effect on the realized price of the common shares. We cannot predict the price at which our common shares will trade.

The market price of our common shares has fluctuated widely and may continue to do so in response to many factors, such as actual or anticipated fluctuations in our operating results, changes in financial estimates by securities analysts, economic and regulatory trends, general market conditions, rumors and other factors, many of which are beyond our control. Further, there may be no continuing active or liquid public market for our common shares. If an active trading market for our common shares does not continue, the price of our common shares may be more volatile and it may be more difficult and time consuming to complete a transaction in the common shares, which could have an adverse effect on the realized price of the common shares. An adverse development in the market price for our common shares could negatively affect our ability to issue new equity to fund our activities. For our share price history, please see “Item 9. The Offer and Listing—A. Offer and Listing Details.”

ITEM 4.    INFORMATION ON THE COMPANY

A.    History and Development of the Company

The Company

North Atlantic Drilling Ltd. was formed as an exempted company limited by shares under the laws of Bermuda on February 10, 2011, by our parent, Seadrill (NYSE: SDRL), as a new offshore drilling subsidiary focused on operations in the North Atlantic Region, which includes only the territorial waters and outer continental shelf jurisdiction of Norway, the United Kingdom, Ireland, Denmark, the Netherlands, the east coast of Greenland, Russia (west of the island of Diksonskiy), and all countries within the Baltic Sea and the Gulf of Bothnia. On February 17, 2011, we entered into an agreement with Seadrill to acquire six harsh environment drilling rigs, including all relevant contracts, spares, stores and offshore personnel related to the drilling rigs, which we refer to as the North Atlantic Restructuring. The North Atlantic Restructuring closed on March 31, 2011 and our business is a direct continuation of the North Atlantic business of Seadrill. We did not engage in any business or other activities prior to the North Atlantic Restructuring,

25

---

except in connection with our formation. The North Atlantic Restructuring was limited to entities that were under the control of Seadrill and its affiliates, and, as such, the North Atlantic Restructuring was accounted for as a transaction between entities under common control.

In February 2014, we completed our underwritten initial public offering of 13,513,514 common shares at $9.25 per share. We also completed our offer to exchange all of the unregistered common shares that we previously issued in our prior equity private placements (other than the common shares owned by affiliates of ours) for common shares that have been registered under the Securities Act of 1933, or the Securities Act, in which an aggregate of 53,068,404 common shares were validly tendered and exchanged. Our common shares trade on the NYSE and Norwegian OTC List under the symbol “NADL.”

On December 31, 2015, our shareholders, in a special general meeting, approved a capital reorganization including a 1-for- 10 reverse stock split of our issued and outstanding common shares and reducing par value from $5.00 to $0.10 . The high and low prices presented as at December 30, 2015 and prior to this have been re-presented to reflect the change from the 1-for- 10 reverse stock split.

Our principal executive offices are located at Par-la-Ville Place, 4th Floor, 14 Par-la-Ville Road, Hamilton HM 08, Bermuda and our telephone number is +1 (441) 295-6935.

Acquisitions, Disposals and Other Developments for the period from January 1, 2015 through and including December 31, 2015

Capital Expenditures

We had total capital expenditures of approximately $73.8 million in 2015 . Our capital expenditures relate primarily to our newbuild program, capital additions and equipment purchases to our existing drilling units and payments for long term maintenance.

Newbuilding deferral

On December 2, 2015, the Company signed an amendment with Jurong for the deferral of the delivery of the semi-submersible drilling unit, the West Rigel , or the Unit. The deferral period lasts until June 2016, following completion of which, the Company and Jurong have agreed to form a joint asset holding company for joint ownership of the Unit, to be owned 23% by the Company and 77% by Jurong, in the event no employment is secured for the Unit and no alternative transaction is completed. Until the end of the deferral period, the Company will continue to market the Unit for an acceptable drilling contract, and the Unit will remain at the Jurong Shipyard in Singapore. The Company and Jurong may also consider other commercial opportunities for the Unit during this period. However, based on current market conditions, management deems the most probable outcome to be that the Unit will be contributed to the joint asset holding company.

Drilling Contract Terminations

On March 13, 2015, we received a termination notice from Rosneft of the drilling contract for the  West Navigator.  The drillship was scheduled to commence operations under a five-year contract with Rosneft during the summer of 2015. The termination of the drilling contract for the  West Navigator  reduced our contract backlog by $1.0 billion . We will be marketing the West Navigator for alternative future opportunities; however, we remain in discussions with Rosneft to explore various alternatives for future co-operation.

Rosneft Framework Agreement Update

On April 16, 2015, we, along with Seadrill and Rosneft, mutually agreed to further extend the date of termination of the Framework Agreement until May 31, 2017, whereby both parties can effectively terminate the Framework Agreement and/or any offshore drilling contracts at any time prior to May 31, 2017 at no cost. The parties have agreed to use their reasonable endeavors to renegotiate, by no later than May 31, 2017, the terms of the transactions contemplated in the Framework Agreement, the characteristics of the transactions contemplated in the Framework Agreement, and the terms of the related offshore drilling contracts. During this time, we are permitted to market our offshore drilling rigs subject to existing drilling contracts with Rosneft, enter into binding contracts with third parties in respect of those rigs, delay the mobilization of those rigs under the Rosneft contracts in order to comply with the terms of any contracts with third parties, delay the construction or delivery of any of those rigs, and extend the construction period or shipyard stay of any of those rigs.

In June 2015, the parties agreed to cancel any restrictions of business included within the terms of the Framework Agreement, and replaced this with a requirement for us, subject to applicable law, to inform Rosneft of any material developments affecting us.

We can provide no assurances that we will be able to reach an agreement with Rosneft by May 31, 2017. Even if an agreement is reached, the terms of such agreement will likely differ materially from the terms contemplated in the original Framework Agreement as summarized below. Please see “—Acquisitions, Disposals and Other Developments for the period from January 1, 2014 through and including December 31, 2014—Rosneft Framework Agreement” below.

26

---

Acquisitions, Disposals, and Other Developments for the period from January 1, 2014 through and including December 31, 2014

Capital Expenditures

We had total capital expenditures of approximately $617.2 million in 2014 . Our capital expenditures relate primarily to our newbuild program, capital additions and equipment purchases to our existing drilling units and payments for long-term maintenance. In May 2014, we reclassified $589.1 million from newbuilds to drilling units relating to the delivery of the West Linus . We financed our capital expenditures through cash generated from operations and secured and unsecured debt arrangements.

Capital and Financing Transactions

On January 28, 2014, we completed the issuance of $600 million in aggregate principal amount of 6.25% Senior Unsecured Notes due 2019 in a private offering to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to certain persons in offshore transactions in reliance on Regulation S under the Securities Act. We used the gross proceeds of the senior unsecured notes issuance for the prepayment of indebtedness and transaction expenses and general corporate purposes. Seadrill purchased approximately 31.1% of the aggregate principal amount of the notes. The notes were listed on the Irish Stock Exchange on July 1, 2014.

On February 3, 2014, we completed our underwritten initial public offering in the United States of 13,513,514 common shares at $9.25 per share, resulting in gross proceeds to us of $125 million.

Rosneft Framework Agreement

On May 26, 2014, we entered into an investment and co-operation agreement, or the Investment and Co-Operation Agreement, with Seadrill and Rosneft to pursue onshore and offshore growth opportunities in the Russian market.

In connection with the Investment and Co-Operation Agreement, on August 20, 2014, we entered into a Framework Agreement with Seadrill and Rosneft, pursuant to which Rosneft agreed to sell, and we agreed to purchase, 100% of the capital of Rosneft’s Russian land drilling subsidiary, RN Burenie LLC, together with its subsidiaries, in exchange for such number of our newly issued common shares, based on an agreed share price of $9.25 per share, as payment of the agreed purchase price, subject to certain cash adjustments. As part of this transaction, Rosneft agreed to purchase additional shares at closing, at the same price, to increase its aggregate ownership interest in us to at least 30%. In addition, the Framework Agreement provides that Rosneft is entitled to receive our additional shares following the commencement of certain offshore drilling contracts awarded by Rosneft to us. The Framework Agreement also provides that we and Rosneft will enter into a shareholder agreement to reflect certain agreements relating to us and the shares owned by both us and Rosneft, including, among other things, certain restrictions on such stockholders’ rights to vote, standstill restrictions and certain rights of first refusal. The Framework Agreement also contains customary closing conditions, including the necessary corporate approvals from Rosneft and certain termination rights.

The Framework Agreement provides for a closing date of no earlier than November 10, 2014, and that the agreement would terminate if the transaction had not closed by December 31, 2014. On November 7, 2014, the parties mutually agreed to extend the date of termination of the Framework Agreement until May 31, 2015, and on April 16, 2015, the parties mutually agreed to further extend the date of termination until May 31, 2017. See “—Acquisitions, Disposals and Other Developments for the period from January 1, 2015 through and including December 31, 2015—Rosneft Framework Agreement Update” above.

Other Significant Developments

On November 26, 2014, our board of directors resolved to suspend dividend distributions until further notice.

Acquisitions, Disposals and Other Developments for the period from January 1, 2013 through and including December 31, 2013

Capital Expenditures

We had total capital expenditures of approximately $198.9 million in 2013 , relating primarily to our newbuilding program, capital additions and equipment purchases to our existing drilling units and payments for long-term maintenance.

Disposals

We sold the shares in two of our subsidiaries, Seadrill Norge Holding AS and Seadrill Norge AS, to Seadrill on June 28, 2013. Total consideration for the shares was $154.0 million, offset by a liability of $288.4 million that we had against these subsidiaries before the sales. In relation to the common control transaction, $2.3 million was recognized as contributed deficit as of December 31, 2013. The sales had no cash effect in the year ended December 31, 2013 and the net increased liability was treated as a drawdown on the increased revolving credit facility provided by Seadrill. The increased revolving facility was subsequently repaid.

B.    Business Overview

We are an offshore drilling contractor focused on operations in the North Atlantic Region. While we currently operate exclusively offshore Norway and the United Kingdom, we intend to grow our position in the North Atlantic Region by continuing to provide excellent service to our customers with our

27

---

modern, technologically advanced harsh environment fleet, together with our approximately 1,082 experienced and skilled employees. Our drilling rigs are under contracts with major oil companies such as Statoil, ConocoPhillips, Total and ExxonMobil, with an average remaining term of approximately 13 months as of March 31, 2016 .

Our Business Strategies

Our operations are focused on state-of-the-art offshore drilling units primarily in harsh environments and the North Atlantic Region. We believe we have one of the most capable fleets in this sector of the drilling industry and believe that by combining quality assets with experienced and skilled employees we will be able to provide our customers with safe and effective operations, and establish, develop and maintain a position as a preferred provider of harsh environment drilling services for our customers.

We intend to leverage the relationships, expertise and reputation of Seadrill to assist in re-contracting our fleet under long-term contracts. Seadrill is one of the world’s largest international offshore drilling contractors and owned 70.4% of our outstanding common shares as of the date of this Annual Report. We are highly dependent on Seadrill to provide liquidity and support our operations. Please see "Item 5. Operating and Financial Review and Prospects—B. Liquidity and Capital Resources" and "Item 3. Information on the Company—D. Risk Factors" for more information.

The key elements in our strategy are as follows:

•	commitment to provide customers with safe and effective operations;

•	combine state-of-the-art mobile drilling units with experienced and skilled employees; and

•	focus and develop our strong position in harsh environments.

Management of Our Business

Our Board of Directors has the authority to oversee and direct our operations, management and policies on an exclusive basis. Our Board of Directors has organized the provision of certain management and other services through North Atlantic Management, our wholly-owned subsidiary, and Seadrill Management, a wholly-owned subsidiary of Seadrill.

North Atlantic Management provides all day-to-day management functions to the Company and its subsidiaries in accordance with the terms of the general management agreement, or the General Management Agreement. North Atlantic Management is responsible for, among other things, corporate governance services, budgeting and accounting functions, the financing of our activities, commercial management including marketing of our drilling rigs, and the purchase and sale of assets.

North Atlantic Management employs our senior management, including our Chief Executive Officer. Our Chief Financial Officer has been seconded to North Atlantic Management from Sevan Drilling Management AS, a subsidiary of Seadrill and Sevan Drilling Limited, or Sevan Drilling. North Atlantic Management has contracted in certain other management services from Seadrill Management in accordance with the terms of the Services Agreement. In addition, the costs attributable to one of our directors is charged from Seatankers Management Norway AS. The agreement can be terminated by either party upon one month's notice. In consideration of the services provided, the Company will pay Seadrill a fee that includes the operating costs attributable to us plus a margin of 8%.

Our principal executive headquarters are at Par-la-Ville Place, 14 Par-la-Ville Road, Hamilton HM 08, Bermuda. Pursuant to the Services Agreement and the General Management Agreement (which is a general management agreement between us and North Atlantic Management AS, or North Atlantic Management, one of our subsidiaries), all day-to-day management functions are provided by Seadrill Management and North Atlantic Management. Seadrill Management’s offices are located at Building 11, 2 ^nd Floor, Chiswick Business Park, 566 Chiswick High Road, London W4 5YS, United Kingdom, and North Atlantic Management’s offices are located at Drammensveien 228, 0283 Oslo, P.O. Box 224, 1326 Lysaker, Norway. North Atlantic Management's telephone number at that address is +47 51 30 90 00. North Atlantic Management also has offices in Bergen and Stavanger, Norway and Aberdeen, United Kingdom.

Market Overview

We operate within the harsh environment segment of the offshore drilling market, which constitutes a part of the international oil and gas service industry. Our operating fleet of seven harsh environment offshore drilling rigs consists of one ultra-deepwater drillship, three semi-submersibles and three jack-up rigs. While we currently operate exclusively in Norway and the United Kingdom, we pursue harsh environment drilling operating in other locations in the North Atlantic Region. The North Atlantic Region has historically offered long-term contracts, high utilization and competitive dayrates compared to the international offshore drilling market for similar drilling rigs.

The Global Fleet of Drilling Units

The global fleet of offshore drilling units consists of drillships, semi-submersible rigs, jack-up rigs and tender rigs. The existing worldwide fleet as of March 31, 2016 totals 879 units including 121 drillships, 185 semi-submersible rigs, 536 jack-up rigs and 37 tender rigs. In addition, there are 46 drillships, 23 semi-submersible rigs, 122 jack-up rigs and eight tender rigs under construction. The water depth capabilities varies depending on type and design of the rigs. Jack-up rigs normally work in water depths up to 450ft while semi-submersible rigs and drillships can work in water depths up to 12,000ft. Tender rigs work in water depths up to 410ft for tender barges and up to 6,000ft for semi-tenders. All offshore rigs are capable of working in benign environment, but there are certain additional requirements for rigs to operate in harsh environments due to extreme marine and enviromental

28

---

conditions. The number of rigs outfitted for such operations are limited, and the present number of rigs operating in harsh environments in Norway and the United Kingdom total 54 rigs, of which there are 31 floaters and 23 jack-ups.

Seasonality

In general, seasonal factors do not have a significant direct effect on our business as typical drilling contracts are based on long-term demand from oil companies and the cyclical nature in the contract drilling market is normally multi-year. However, the weather conditions during parts of the year could adversely impact the operational utilization of the rigs and our ability to relocate rigs between drilling locations, and as such, limit contract opportunities in the short term. Such adverse weather could include the winter season offshore Norway and the United Kingdom.

Drilling Contracts

We provide drilling, combined drilling and production, and plug and abandonment services on a “dayrate” contract basis. We do not provide “turnkey” or other risk-based drilling services to the customer. Under dayrate contracts, the drilling contractor provides a drilling rig and rig crews and charges the customer a fixed amount per day regardless of the number of days needed to drill or service the well. The customer bears substantially all of the ancillary costs of constructing the well and supporting drilling operations, as well as the economic risk relative to the success of the well. In addition, dayrate contracts usually provide for a lump sum amount or dayrate for mobilizing the rig to the initial operating location, which is usually lower than the contractual dayrate for uptime services, and a reduced dayrate when drilling operations are interrupted or restricted by equipment breakdowns, adverse weather conditions or other conditions beyond the contractor’s control. A dayrate contract generally covers either the drilling or service to a single well or a number of wells or has a stated term regardless of the number of wells. These contracts may generally be terminated by the customer in the event the drilling rig is destroyed or lost or if drilling operations are suspended for an extended period of time as a result of a breakdown of equipment, “force majeure” events beyond the control of either party or upon the occurrence of other specified conditions. In some instances, the dayrate contract term may be extended by the customer exercising options for the drilling of additional wells or for an additional length of time at fixed or mutually agreed terms, including dayrates.

Our drilling contracts are the result of negotiations with our customers. Our existing drilling contracts generally contain, among other things, the following commercial terms:

•	contract duration extending over a specific period of time;

•	term extension options in favor of our customer, generally upon advance notice to us, at mutually agreed, indexed or fixed rates;

•	provisions permitting early termination of the contract if the drilling rig is lost or destroyed, if operations are suspended for an extended period of time due to breakdown of major rig equipment or “force majeure” events beyond our control and the control of the customer;

•	provisions allowing early termination of the contract by the customer without cause with a specified early termination fee or a reduced rate for a specified period of time;

•	payment of compensation to us (generally in U.S. dollars although some contracts require a portion of the compensation to be paid in local currency) on a dayrate basis (lower rates or no compensation generally apply during periods of equipment breakdown and repair or in the event operations are suspended or interrupted by other specified conditions, some of which may be beyond our control);

•	payment by us of the operating expenses of the drilling rig, including crew labor and incidental rig supply costs;

•	provisions entitling us to adjustments of dayrates in accordance with published indices or otherwise;

•	provisions requiring us or Seadrill to provide a performance guarantee;

•	indemnity provisions between us and our customers in respect of third-party claims and risk allocations between us and our customers relating to damages, claims or losses to us, our customers or third parties; and

•

provisions permitting the customer’s assignment to a third party with our prior consent, such consent not to be unreasonably withheld. Our indemnification provisions may not cover all damages, claims or losses to us or third parties, and the indemnifying party may not have sufficient resources to cover its indemnification obligations. In addition, our drilling contracts typically provide for situations where the drilling rig would operate at reduced operating dayrates.

Employment of Our Fleet

Our customers consist primarily of major integrated oil companies. We currently have contracts with Statoil, ExxonMobil, ConocoPhillips and Total.

Our contract backlog includes firm commitments only, which are represented by signed drilling contracts. As of March 31, 2016 , our contract backlog was approximately $630 million , and was attributable to revenues we expect to generate from all of our drilling rigs. We calculate our contract backlog by multiplying the contractual dayrate by the minimum expected number of days committed under the contracts (excluding options to extend), assuming full utilization. The actual amount of revenues earned and the actual periods during which revenues are earned may differ from the amounts and periods shown in the table below due to, for example, shipyard and maintenance projects, downtime and other factors that result in lower revenues than our average contract backlog per day.

The actual amount of revenues earned may also fluctuate due to parts of the dayrates being received in Norwegian kroner. Approximately 20% to 50% of the dayrates are payable in Norwegian kroner, which approximately corresponds to the amount of operational expenses paid in Norwegian kroner. As a result, our net operational profit measured in U.S. dollars is minimally affected by currency fluctuations on a historical basis even though operational expenses and revenues may be affected individually. Norwegian kroner elements of future contract revenue and dayrate information provided throughout this Annual Report have been converted into U.S. dollars using an exchange rate of USD $1 to NOK8.74 , as of December 31, 2015 , respectively. In

29

---

addition, we may enter into drilling contracts that contain bonus payments in excess of the stated dayrate if we meet certain agreed operational objectives under the applicable contract.

The firm commitments that comprise our contract backlog as of March 31, 2016 are as follows.

Drilling Rig	Contracted Location	Customer	Contractual Daily Rate   $'000s	Contract Start Date	Earliest Expiration Date
West Alpha	Norway	ExxonMobil	$501	January 1, 2014	July 1, 2016
West Elara	Norway	Statoil  (1)	$312	March 1, 2012	March 30, 2017
West Epsilon	Norway	Statoil	$242	December 28, 2010	December 1, 2016
West Linus	Norway	ConocoPhillips  (2)(3)	$327	May 1, 2014	May 1, 2019
West Navigator	Norway	Available  (4)	$—	—	—
West Phoenix	UK	Total	$280	April 1, 2016	September 1, 2016
West Venture	Norway	Available  (4)	$—	—	—

 

For our drilling rigs operating in Norway, the dayrates listed in the table above include adjustments, as applicable, effective from July 1, 2013, pursuant to the NR ( Norges Rederiforbund ) tariff, a Norwegian offshore industry tariff. The daily rate for the West Phoenix, which operates in the United Kingdom, is subject to annual rate revisions based on changes in indices derived from the U.S. Department of Labor, Bureau of Labor Statistics.

(1)	Statoil has the option to extend the contract until March 2019 on identical terms upon notice to us one and a half years before the expiration of the firm contract period.

(2)

ConocoPhillips has the option to extend the contract from five to seven years at the same dayrate upon notice to us which expires in May 2017. In addition, ConocoPhillips has the option to extend the contract for two additional two-year periods at a dayrate that is $10,000 less than the current dayrate for the extension periods upon 24 months’ notice to us prior to the expiration of the relevant period.

(3)	Excludes $12,430 per day which we receive in addition to the ordinary dayrate as compensation for additional capital expenditures we incur to provide the customer with additional equipment.

(4)	The West Navigator and West Venture are currently cold stacked.

Customers

Our customers are oil and gas exploration and production companies, including major integrated oil companies, independent oil and gas producers and government-owned oil and gas companies. The table below shows the percentage of our consolidated revenues attributable from each customer, including certain of their subsidiaries, for the years ended December 31, 2015 , 2014 and 2013 :

Contract revenue split by client:		Year ended December 31,
		2015			2014			2013
Statoil		44	%		38	%		57	%
ExxonMobil		25	%		13	%		12	%
Conoco Phillips		18	%		8	%		—	%
Total		13	%		12	%		13	%
Shell		—	%		12	%		14	%
KMNG		—	%		11	%		—	%
Other		—	%		6	%		4	%
Total		100	%		100	%		100	%

All of our drilling contracts have fixed terms, but may be terminated early due to certain events or we may be unable to realize revenue under these contracts in the event of unanticipated developments, such as the deterioration in the general business or financial condition of a customer, resulting in its inability to meet its obligations under our contracts.

In light of the current environment, we are encountering and may in the future encounter situations where counterparties request relief to contracted dayrates or seek early contract termination. In the event of early termination for the customer's convenience, an early termination amount is typically payable to us, in accordance with the terms of the drilling agreement. While we are confident that our contract terms are enforceable, we may be willing to engage in discussions to modify such contracts if there is a commercial agreement that is beneficial to both parties.

Competition

30

---

The offshore drilling industry is highly competitive, with market participants ranging from large multinational companies to smaller companies with fewer than five drilling rigs.

The demand for offshore drilling services is driven by oil and gas companies’ exploration and development drilling programs. These drilling programs are affected by oil and gas companies’ expectations regarding oil and gas prices, anticipated production levels, worldwide demand for oil and gas products and many other factors. The availability of quality drilling prospects, exploration success, availability of qualified rigs and operating personnel, relative production costs, availability and lead time requirements for drilling and production equipment, the stage of reservoir development and political and regulatory environments also affect customers’ drilling programs. Oil and gas prices are volatile, which has historically led to significant fluctuations in expenditures by customers for drilling services. Variations in market conditions impact us in different ways, depending primarily on the length of drilling contracts we have for our rigs. Short-term changes in these markets may have a minimal short-term impact on revenues and cash flows, unless the timing of contract renewals coincides with short-term movements in the market.

Offshore drilling contracts are generally awarded on a competitive bid basis or through privately negotiated transactions. In determining which qualified drilling contractor is awarded a contract, the key factors are pricing, rig availability, rig location, condition and integrity of equipment, its record of operating efficiency, including high operating uptime, technical specifications, safety performance record, crew experience, reputation, industry standing and client relations.

Competition for offshore drilling rigs is generally on a global basis, as rigs are highly mobile. However, the cost associated with mobilizing rigs between regions is sometimes substantial, as entering a new region could necessitate modifications of the drilling rig and its equipment to specific regional requirements. For example, drilling rigs operating in the North Atlantic Region and in other harsh environment drilling locations require specialized equipment and modifications, including without limitation, unique structuring of drilling rig hulls and protection from exposure to weather and low temperatures. Not all rigs can be modified to operate in harsh environment conditions. The large investment in specialized or modified drilling equipment required to operate in harsh environment conditions creates barriers to entry. In addition, Norway imposes added requirements for drilling facilities, including, among other things, strict standards relating to safety, drilling rig technical specifications, crew accommodations and certain other compliance measures, known as Acknowledgment of Compliance, or AOC, which must be satisfied in order to operate in the Norwegian Continental Shelf. All of our drilling rigs meet, or are being constructed to meet, AOC requirements.

We believe that the market for drilling contracts will continue to be highly competitive for the foreseeable future. While we believe that our fleet of well-maintained and technologically advanced drilling rigs provides us with a competitive advantage over competitors with older fleets, as our drilling rigs are generally better suited to meet the requirements of customers for drilling in harsh environments, certain competitors may have greater financial resources than we do, which may enable them to better withstand periods of low utilization, and compete more effectively on the basis of price.

For further information on current market conditions and global offshore drilling fleet, please refer to “Item 5. Operating and Financial Review and Prospects—D. Trend Information.”

Environmental and Other Regulations

Our operations are subject to numerous laws and regulations in the form of international treaties and maritime regimes, flag state requirements, national environmental laws and regulations, navigation and operating permit requirements, local content requirements, and other national, state and local laws and regulations in force in the jurisdictions in which our drilling units operate or are registered, which can significantly affect the ownership and operation of our drilling units. Please see "Item 3. Key Information—D. Risk Factors—Risks Relating to Our Industry—Governmental laws and regulations, including environmental laws and regulations, may add to our costs, expose us to liability, or limit our drilling activity.”

Flag State Requirements

All of our drilling units are subject to regulatory requirements of the flag state where the drilling unit is registered. These include engineering, safety and other requirements related to the drilling industry and to maritime vessels in general. In addition, each of our drilling units must be “classed” by a classification society. The classification society certifies that the drilling rig is “in-class,” signifying that such drilling rig has been built and maintained in accordance with the rules of the classification society and complies with applicable rules and regulations of the flag state and the international conventions of which that country is a member. Maintenance of class certification requires expenditure of substantial sums, and can require taking a drilling unit out of service from time to time for repairs or modifications to meet class requirements. Our drilling units must generally undergo a class survey once every five years.

International Maritime Regimes

These requirements include, but are not limited to, the IMO International Convention for the Prevention of Pollution from Ships of 1973, as from time to time amended, (MARPOL) and designation of Emission Control Areas (ECAs) thereunder, the International Convention on Civil Liability for Oil Pollution Damage of 1969 (CLC) the International Convention on Civil Liability for Bunker Oil Pollution Damage of 2001 (ratified in 2008) (Bunker Convention), the International Convention for the Safety of Life at Sea of 1974, or SOLAS, the International Safety Management Code for the Safe Operation of Ships and for Pollution Prevention (ISM Code), and the International Convention for the Control and Management of Ships’ Ballast Water and Sediments in February 2004, (BWM Convention). These various conventions regulate air emissions and other discharges to the environment from our drilling units worldwide, and we may incur costs to comply with these regimes and continue to comply to these regimes as they may be amended in the future. In addition, these conventions impose liability for certain discharges, including strict liability in some cases. Please see “Item 3. Key

31

---

information—D. Risk Factors—Risks Relating to Our Industry—Governmental laws and regulations, including environmental laws and regulations, may add to our costs, expose us to liability or limit our drilling activity.”

Environmental Laws and Regulations

These laws and regulations include the U.S. Oil Pollution Act of 1990, (OPA), the Comprehensive Environmental Response, Compensation and Liability Act, (CERCLA), the U.S. Clean Water Act (CWA), the U.S. Clean Air Act (CAA), the U.S. Outer Continental Shelf Lands Act, the U.S. Maritime Transportation Security Act of 2002, or the “MTSA, European Union regulations, and Brazil’s National Environmental Policy Law (6938/81), Environmental Crimes Law (9605/98) and Federal Law (9966/2000) relating to pollution in Brazilian waters. These laws govern the discharge of materials into the environment or otherwise relate to environmental protection.

In April 2016, the BSEE issued a final rule on well control regulations that set new and revised safety and operational standards for owners and operators of offshore wells and facilities.  Among other requirements, the new regulation sets standards for blow-out preventers that include baseline requirements for their design, manufacture, inspection and repair, requires third-party verification of the equipment, and calls for real-time monitoring of certain drilling activities, to name just a few of the many requirements.  These new regulations grow out of the findings made in connection with the Deepwater Horizon incident and include a number of requirements that will add to the costs of exploring for, developing and producing of oil and gas in offshore settings.  These new rules add new requirements and amend existing ones to, among other things, set new baseline standards for the design, manufacture, inspection, repair and maintenance of blow-out preventers including their inspection and the use of double shear rams.  These rules contain a number of other requirements including third-party verification and certifications, real-time monitoring of deepwater and certain other activities, and sets criteria for safe drilling margins. 

In certain circumstances, these laws may impose strict liability, rendering us liable for environmental and natural resource damages without regard to negligence or fault on our part. Implementation of new environmental laws or regulations that may apply to ultra deepwater drilling units may subject us to increased costs or limit the operational capabilities of our drilling units and could materially and adversely affect our operations and financial condition. Please see "Item 3 Key information—D. Risk Factors—Risks Relating to Our Industry—Governmental laws and regulations, including environmental laws and regulations, may add to our costs, expose us to liability or limit our drilling activity.”

Safety Requirements

Our operations are subject to special safety regulations relating to drilling and to the oil and gas industry in many of the countries where we operate. The United States undertook substantial revision of the safety regulations applicable to our industry following the Deepwater Horizon Incident, in which we were not involved, that led to the Macondo well blow out situation, in 2010. Other countries are also undertaking a review of their safety regulations related to our industry. These safety regulations may impact our operations and financial results. For instance, the revisions to the regulations in the United States have resulted in new requirements, such as specific requirements for maintenance and certification of BOP’s, which may cause us to incur cost and may result in additional downtime for our drilling units in the US Gulf of Mexico. Please see "Item 3. Key information—D. Risk Factors—Risks Relating to Our Industry—The Deepwater Horizon oil spill in the U.S. Gulf of Mexico has and may result in more stringent laws and regulations governing offshore drilling, which could have a material adverse effect on our business, operating results or financial condition.” Furthermore, in April 2015, it was announced that new regulations are expected to be imposed in the United States regarding offshore oil and gas drilling.

Navigation and Operating Permit Requirements

Numerous governmental agencies issue regulations to implement and enforce the laws of the applicable jurisdiction, which often involve lengthy permitting procedures, impose difficult and costly compliance measures, particularly in ecologically sensitive areas, and subject operators to substantial administrative, civil and criminal penalties or may result in injunctive relief for failure to comply. Some of these laws contain criminal sanctions in addition to civil penalties.

Local Content Requirements

Governments in some countries have become increasingly active in local content requirements on the ownership of drilling companies, local content requirements for equipment utilized in our operations, and other aspects of the oil and gas industries in their countries. These regulations include requirements for participation of local investors in our local operating subsidiaries in countries such as Angola and Nigeria, and local content requirements in relation to drilling unit construction contracts in which we are participating in Brazil. Although these requirements have not had material impact on our operations in the past, they could have a material impact on our earnings, operations and financial condition in the future.

Norwegian Regulation

Our drilling operations in Norway are governed by various regulations relating to environmental safety. The Norwegian Petroleum Act of November 29, 1996, or the Petroleum Act, gives Norway the exclusive right to award licenses for development, exploration and production projects in Norwegian fields. Such licenses are granted by the Norwegian Ministry on Petroleum and Energy, and as holders of such licenses, we are subject to strict liability for any pollution damage suffered as a result of a petroleum leak by facilities for which we hold licenses. Under the Petroleum Act, we are also subject to certain health, safety and environment regulations, which require us to conduct our operations with a reasonable standard of care, taking into consideration the safety of our employees and the environment. Other regulations proscribed by the Norwegian Ministry on Petroleum and Energy and the Norwegian Ministry of the Environment may also affect our operations.

The Norwegian Petroleum Safety Authority oversees technical and operational safety, emergency preparedness and the environment. Each drilling facility operating on the Norwegian Continental Shelf must obtain an Acknowledgement of Compliance, or AOC. The AOC is a government-issued

32

---

certificate that acknowledges compliance with Norway’s laws and regulations relating to safety and emergency preparedness, drilling rig technical specifications, crew accommodations, management systems, and other requirements. Such certificates are granted upon successful completion of an inspection by Petroleum Safety Authority, based on information that a company provides about its facility, as well as any information gathered by the Norwegian Petroleum Safety Authority in its follow-up review of a drilling facility. An AOC alone does not grant a company the right to begin operations on the Norwegian Continental Shelf, but it is mandatory for most petroleum operations in that location, including drilling, production, storage, and offloading facilities. All of our drilling rigs meet the specifications required by the Petroleum Safety Authority and we have obtained an AOC for each of our drilling rigs that are currently in operation.

United Kingdom Regulation

Drilling activities in the United Kingdom are subject to environmental regulations. Under the Petroleum Act 1998, oil and gas companies are required to obtain approval from the U.K. Department of Energy and Climate Change, or the DECC prior to the commencement of any drilling activity onshore or on the U.K. Continental Shelf.

Our activities in the United Kingdom must comply with the regulations adopted by the U.K. Health and Safety Executive, or the HSE, including the Offshore Installations Prevention of Fire and Explosion, and Emergency Response (PFEER) Regulations 1995. In order to comply with the U.K. Offshore Installations (Safety Case) Regulations 2005, we are also required to submit a periodic safety case report, or Safety Case, to the HSE as a measure of our ability to control risks and appropriately implement health and safety management systems for each of our rigs operating in the U.K. The Safety Cases are subject to revision every five years, however the HSE can require resubmission earlier particularly in the event any of the contents or assumptions of the original Safety Case materially changes during the five year period. The HSE also requires that we keep our operating risks “as low as reasonably practicable.”

As of the date of this annual report, two of our units, the West Phoenix  and the  West Navigator , have obtained acceptance of their Safety Cases for drilling operations in the United Kingdom.

Other Laws and Regulations

In addition to the requirements described above, our international operations in the offshore drilling segment are subject to various other international conventions and laws and regulations in countries in which we operate, including laws and regulations relating to the importation of and operation of drilling units and equipment, currency conversions and repatriation, oil and gas exploration and development, taxation of offshore earnings and earnings of expatriate personnel, the use of local employees and suppliers by foreign contractors and duties on the importation and exportation of drilling units and other equipment

Risk of Loss and Insurance Coverage

Our operations are subject to hazards inherent in the drilling of oil and gas wells, including blowouts and well fires, which could cause personal injury, suspend drilling operations, destroy the equipment involved or cause serious environmental damage. Offshore drilling contractors such as us are also subject to hazards particular to marine operations, including capsizing, grounding, collision and loss or damage from severe weather. Our marine insurance package policy provides insurance coverage for physical damage to our drilling rigs, loss of hire and third-party liability.

Our insurance claims are subject to a deductible, or non-recoverable, amount. We currently maintain a deductible per occurrence of up to $5 million related to physical damage to our drilling rigs. However, a total loss of, or a constructive total loss of, a drilling rig is recoverable without being subject to a deductible. For general and marine third-party liabilities, we generally maintain a deductible of up to $25,000 per occurrence on personal injury liability for crew claims, non-crew claims and third-party property damage including oil pollution from the drilling rigs. Furthermore, for some of our drilling rigs we purchase insurance to cover loss due to the drilling rig being wholly or partially deprived of income as a consequence of damage to the rig. The loss of hire insurance has a deductible period of 60 days after the occurrence of physical damage. Thereafter, coverage is limited to 210 days per event and in the annual aggregate. The daily indemnity or compensation is approximately 75% of the respective contract dayrate. If the repair period for any physical damage exceeds the number of days permitted under our loss of hire policy, we will be responsible for the costs in such period.

C.     Organizational Structure

North Atlantic Drilling Ltd. is a company organized under the laws of Bermuda. We are a majority owned subsidiary of Seadrill, which owns approximately 70.4% of our outstanding common shares as of the date of this Annual Report. We own our drilling rigs through separate wholly-owned subsidiaries that are incorporated in Bermuda.

Please see Exhibit 8.1 to this Annual Report for a list of our current subsidiaries.

33

---

D.    Property, Plants and Equipment

Our Fleet

Our fleet of seven harsh environment offshore drilling rigs consists of three semi-submersibles, one ultra-deepwater drillship and three jack-up rigs . The following table sets forth certain information regarding our drilling rigs as of the date of this Annual Report:

Drilling Rig	Generation / Type	Year Built	Water Depth Capacity (in feet)	Drilling Depth Capacity (in feet)	Contract	Month of contract expiry
Floaters
Semi-Submersibles
West Phoenix	6 th  - HE	2008	10,000	30,000	Total	September 2016
West Venture	5 th  - HE	2000	2,600	30,000	Available	Available
West Alpha	4 th  - HE	1986	2,000	23,000	ExxonMobil	July 2016
Drillship
West Navigator	Ultra-deepwater - HE	2000	7,500	35,000	Available	Available
Jack-ups
West Epsilon	HD - HE	1993	400	30,000	Statoil	December 2016
West Elara	HD - HE	2011	450	40,000	Statoil	March 2017
West Linus (1)	HD - HE	2014	450	40,000	ConocoPhillips	May 2019

  _____________

(1)

Pursuant to a sale and leaseback agreement, we sold the West Linus to Ship Finance, and the rig has been chartered back to us on a bareboat charter for a period of 15 years from its delivery date on February 18, 2014. In accordance with accounting principles generally accepted in the United States, or U.S. GAAP, we consolidate SFL Linus Ltd., the Ship Finance subsidiary that owns the rig, in our consolidated financial statements. See “Item 7. Major Shareholders and Related Party Transactions—B. Related Party Transactions.”

On December 2, 2015, the Company signed an amendment with Jurong for the deferral of the delivery of the semi-submersible drilling unit, the West Rigel (the "Unit"). The deferral period lasts until June 2016, following completion of which, the Company and Jurong have agreed to form a joint asset holding company for joint ownership of the Unit, to be owned 23% by the Company and 77% by Jurong, in the event no employment is secured for the Unit and no alternative transaction is completed. Until the end of the deferral period, the Company will continue to market the unit for an acceptable drilling contract, and the Unit will remain at the Jurong Shipyard in Singapore. The Company and Jurong may also consider other commercial opportunities for the Unit during this period. However, based on current market conditions, management deems the most probable outcome to be that the Unit will be contributed to the joint asset holding company. As a result of the above, the Company has concluded that the West Rigel should be classified as an asset held for sale as at December 31, 2015. Please see “ Note 12 –Asset held for sale” of the Notes to the Consolidated Financial Statements contained herein for further information.

ITEM 4A.    UNRESOLVED STAFF COMMENTS

Not applicable.

ITEM 5.    OPERATING AND FINANCIAL REVIEW AND PROSPECTS

Overview

The following presentation of management’s discussion and analysis of results of operations and financial condition should be read in conjunction with our Consolidated Financial Statements and accompanying Notes thereto, included herein. You should also carefully read the following discussion with the sections of this Annual Report entitled “Cautionary Statements Regarding Foreward-Looking Statements”, “Item 3. Key Information—A. Selected Financial Data,” “Item 3. Key Information—D. Risk Factors” and “Item 4. Information on the Company.” Our consolidated financial statements as of December 31, 2015 and 2014 and for the years ended December 31, 2015 , 2014 and 2013 , included herein, have been prepared in accordance with U.S. GAAP and are presented in U.S. dollars unless otherwise indicated.

Our Fleet

For certain information regarding our drilling units, please see “Item 4. Information on the Company—D. Property, Plants and Equipment—Our Fleet.”

Factors Affecting our Results of Operations

The principal factors which we believe have affected our results and are expected to affect our future results of operations and financial position include:

34

---

•	our ability to successfully employ our drilling units at economically attractive dayrates as long-term contracts expire or are otherwise terminated;

•	the ability to maintain good relationships with our existing customers and to increase the number of customer relationships;

•	the number and availability of our drilling units,

•	fluctuations and current decline in the price of oil and gas, which influence the demand for offshore drilling services;

•	the effective and efficient technical management of our drilling units;

•	our ability to obtain and maintain major oil and gas company approvals and to satisfy their quality, technical, health, safety and compliance standards;

•	economic, regulatory, political and governmental conditions that affect the offshore drilling industry;

•	accidents, natural disasters, adverse weather, equipment failure or other events outside of its control that may result in downtime;

•	mark-to-market changes in interest rate swaps;

•	foreign currency exchange gains and losses;

•	increases in crewing and insurance costs and other operating costs;

•	the level of debt and the related interest expense and amortization of principal;the impairment of goodwill, investments, drilling units and other assets;

•	gains on disposals of assets;

•	interest and other financial items;and

•	tax expenses.

Please see I“Item 3. Key Information—D. Risk Factors” for a discussion of certain risks inherent in the Company's business.

Important Financial Terms and Concepts

Revenues

In general, each of our drilling units is contracted for a period of time to an oil and gas company to provide offshore drilling services at an agreed daily rate. A unit will be stacked if it has no contract in place. Dayrates are volatile and can vary depending on the type of drilling unit and its capabilities, operating expenses, taxes and other factors. An important factor in determining the level of revenue is the technical utilization of the drilling rig. To the extent that our operations are interrupted due to equipment breakdown or operational failures, we do not generally receive dayrate compensation for the period of the interruption. Furthermore, our dayrates can be reduced in instances of interrupted or suspended service due to, among other things, repairs, upgrades, maintenance, force majeure or requested suspension of services by the client and other operating factors.

The terms and conditions of the contracts allow for compensation when factors beyond our control, including weather conditions, influence drilling operations and, in some cases, for compensation when we perform planned maintenance activities. In general, we are entitled to cost escalation to compensate for industry-specific cost increases as reflected in publicly available cost indices.

In addition to contracted daily revenue, customers may pay mobilization and demobilization fees for units before and after their drilling assignments, and may also pay reimbursement of costs incurred by us at their request for additional supplies, personnel and other services, not covered by the contractual dayrate.

Gain/Loss on disposal

From time to time we may sell, or otherwise dispose of, drilling units, businesses, and other fixed assets, to external parties or related parties. In addition assets may be classified as "held for sale" on our balance sheet when, among other things, we are committed to a plan to sell assets, and consider a sale probable within twelve months. We may recognize a gain/loss on disposal depending on whether the fair value of the consideration received is higher/lower than the carrying value of the asset.

Operating Expenses     

Our operating expenses consist primarily of vessel and rig operating expenses, reimbursable expenses, depreciation and amortization and general and administrative expenses.

•	Vessel and rig operating expenses are related to the drilling units we have in operation and include the remuneration of offshore crews, onshore rig supervision staff, expenses for repairs and maintenance, as well as other expenses specifically related to the drilling units.

•	Reimbursable expenses are incurred at the request of customers, and include supplies, personnel and other services.

•	Loss on impairment of goodwill and drilling units. Management reviews these assets for impairment at least once each year or more often if there are factors indicating that it is more likely than not that the fair value of these assets will be lower than their respective carrying value. Please see "—Critical Accounting Estimates" for further information.

•	Depreciation and amortization expenses are based on the historical cost of our drilling units and other equipment.

•	General and administrative expenses include the costs of our regional offices in various locations, as well as the remuneration and other compensation of the directors and employees engaged in our management and administration.

35

---

Financial items and other income/expense

Our financial items and other income/expense consist primarily of interest income, interest expense, gain/loss on derivative financial instruments, foreign exchange gain/loss and other non-operating income or expenses. See further discussion below in relation to these items:

•	The amount of interest expense recognized depends on the overall level of debt we have incurred and prevailing interest rates for our agreements. However, overall interest expense may be reduced as a consequence of capitalization of interest expense relating to drilling units under construction.

•	Gains/losses recognized on derivative financial instruments reflect various mark-to-market adjustments to the value of our interest rate and forward currency swap agreements and other derivative financial instruments, and the net settlement amount paid or received on swap agreements.

•	Foreign exchange gains/losses recognized generally relate to transactions and revaluation of balances carried in currencies other than the U.S. dollar.

•	Other non-operating income or expense relate to items which generally do not fall within any other categories listed above.

Income taxes

Income tax expense reflects current tax payable and deferred taxes related to our drilling unit owning and operating activities and may vary significantly depending on jurisdictions and contractual arrangements. In most cases the calculation of tax is based on net income or deemed income, the latter generally being a function of gross turnover.

Critical Accounting Estimates

The preparation of our Consolidated Financial Statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosures about contingent assets and liabilities. We base these estimates and assumptions on historical experience and on various other information and assumptions that we believe to be reasonable. Our critical accounting estimates are important to the portrayal of both our financial condition and results of operations and require us to make subjective or complex assumptions or estimates about matters that are uncertain. The basis of preparation and our significant accounting policies are discussed in "Note 1–General Information" and "Note 2–Accounting Policies" of the Notes to our Consolidated Financial Statements appearing elsewhere in this annual report. The following are what we believe to be the critical accounting estimates used in the preparation of the Consolidated Financial Statements. In addition, there are other items within the Consolidated Financial Statements that require estimation.

Drilling Units

Drilling units, vessels and equipment are recorded at historical cost less accumulated depreciation. The cost of these assets less estimated residual value is depreciated on a straight-line basis over their estimated remaining economic useful lives. The estimated economic useful life of our drilling units, when new, is approximately 30 years.

Significant investments are capitalized and depreciated in accordance with the nature of the investment. Significant investments that are deemed to increase an asset’s value for its remaining useful life, are capitalized and depreciated over the remaining life of the asset. We determine the carrying value of these assets based on policies that incorporate our estimates, assumptions and judgments relative to the carrying value, remaining useful lives and residual values. The assumptions and judgments we use in determining the estimated useful lives of our drilling units reflect both historical experience and expectations regarding future operations, utilization and performance. The use of different estimates, assumptions and judgments in establishing estimated useful lives could result in materially different net book values of our drilling units and results of operations.

The useful lives of units and related equipment are difficult to estimate due to a variety of factors, including technological advances that impact the methods or cost of oil and gas exploration and development, changes in market or economic conditions and changes in laws or regulations affecting the drilling industry. We re-evaluate the remaining useful lives of our drilling units as and when certain events occur which directly impact our assessment of their remaining useful lives and include changes in operating condition, functional capability and market and economic factors.

The carrying values of our long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may no longer be appropriate. We assess recoverability of the carrying value of the asset by estimating the undiscounted future net cash flows expected to result from the asset, including eventual disposition. If the undiscounted future net cash flows are less than the carrying value of the asset, an impairment loss is recorded equal to the difference between the asset’s carrying value and fair value. In general, impairment analyses are based on expected costs, utilization and dayrates for the estimated remaining useful lives of the asset or group of assets being assessed. An impairment loss is recorded in the period in which it is determined that the aggregate carrying amount is not recoverable. Asset impairment evaluations are, by nature, highly subjective. They involve expectations about future cash flows generated by our assets, and reflect management’s assumptions and judgments regarding future industry conditions and their effect on future utilization levels, dayrates and costs. The use of different estimates and assumptions could result in significantly different carrying values of our assets and could materially affect our results of operations.

With regard to older drilling units which have relatively short remaining estimate useful lives, the results of impairment tests are particularly sensitive to management's assumptions. These assumptions include the likelihood of the unit obtaining a contract upon the expiry of any current contract, and the Company's intention for the drilling unit should no contract be obtained, including warm / cold stacking or scrapping. The use of different assumptions in the future could potentially result in an impairment of drilling units, which could materially affect our results of operations. If market supply and

36

---

demand conditions in the ultra deepwater offshore drilling sector do not improve it is likely that the Company will be required to impair certain drilling units.

Income Taxes

We are a Bermuda company. We are not currently required to pay taxes in Bermuda on ordinary income or capital gains. We have received written assurance from the Minister of Finance in Bermuda that we will be exempt from taxation until March 31, 2035. Certain subsidiaries operate in other jurisdictions where taxes are imposed. Consequently, income taxes have been recorded in these jurisdictions when appropriate. Our income tax expense is based on our income, statutory tax rates and tax planning opportunities available to us in the various jurisdictions in which we operate. We provide for income taxes based on the tax laws and rates in effect in the countries in which operations are conducted and income is earned. The income tax rates and methods of computing taxable income vary substantially between jurisdictions. Our income tax expense is expected to fluctuate from year to year as our operations are conducted in different tax jurisdictions and the amount of pre-tax income fluctuates.

The determination and evaluation of our annual group income tax provision involves interpretation of tax laws in various jurisdictions in which we operate and requires significant judgment and use of estimates and assumptions regarding significant future events, such as amount, timing and character of income, deductions and tax credits. There are certain transactions for which the ultimate tax determination is unclear due to uncertainty in the ordinary course of business. We recognize tax liabilities based on our assessment of whether our tax positions are sustainable and on estimates of taxes that will ultimately be due. Changes in tax laws, regulations, agreements, treaties, foreign currency exchange restrictions or our levels of operations or profitability in each jurisdiction may impact our tax liability in any given year. While our annual tax provision is based on the information available to us at the time, a number of years may elapse before the ultimate tax liabilities in certain tax jurisdictions are determined. Current income tax expense reflects an estimate of our income tax liability for the current year, withholding taxes, changes in prior year tax estimates as tax returns are filed, or from tax audit adjustments. Our deferred tax expense or benefit represents the change in the balance of deferred tax assets or liabilities as reflected on the balance sheet. Valuation allowances are determined 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. To determine the amount of deferred tax assets and liabilities, as well as of the valuation allowances, we must make estimates and certain assumptions regarding future taxable income, including where our drilling units are expected to be deployed, as well as other assumptions related to our future tax position. A change in such estimates and assumptions, along with any changes in tax laws, could require us to adjust the deferred tax assets, liabilities, or valuation allowances.

Recent accounting pronouncements

Recently Adopted Accounting Standards

Please see "Note 2–Accounting Policies" of the Notes to our Consolidated Financial Statements included herein, for a list of recently adopted accounting standards.

Recently Issued Accounting Standards

The following is a summary of the recently issued accounting standards that we believe are most relevant to our Consolidated Financial Statements.

In May 2014, the Financial Accounting Standards Board, or the FASB, issued ASU 2014-09, Revenue from Contracts with Customers , which provides new authoritative guidance on the methods of revenue recognition and related disclosure requirements. In April 2015 the FASB proposed to defer the effective date of the guidance by one year. Based on this proposal, public entities would need to apply the new guidance for annual and interim periods beginning after December 15, 2017, and shall be applied, at the Company’s option, retrospectively to each period presented or as a cumulative-effect adjustment as of the date of adoption. Early adoption is not permitted until periods beginning after December 15, 2016. The Company is in the process of evaluating the impact of this updated standard on its consolidated financial statements and related disclosures.

In August 2014, the FASB issued ASU 2014-15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern , which provides new authoritative guidance with regards to management's responsibility to assess an entity's ability to continue as a going concern, and to provide related footnote disclosures in certain circumstances. The ASU will be effective for all entities in the first annual period ending after December 15, 2016 (December 31, 2016 for calendar year-end entities) and early adoption is permitted. The Company is in the process of evaluating the impact of this updated standard on its consolidated financial statements and related disclosures.

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) . The update requires lessees to put most leases on their balance sheets but recognize expenses on their income statements in a manner similar to today’s accounting. For lessors, the guidance modifies the classification criteria and the accounting for sales-type and direct financing leases. The guidance will be effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years and early adoption is permitted. The Company is in the process of evaluating the impact of this updated standard on its consolidated financial statements and related disclosures.

Please see "Note 2–Accounting Policies" of the Notes to our Consolidated Financial Statements included herein, for a list of recently issued accounting standards, that may impact the Company's consolidated financial statements and related disclosures when adopted.

37

---

A.    Results of Operations

Fiscal Year Ended December 31, 2015 compared to Fiscal Year Ended December 31, 2014

The following table sets forth our operating results for the years ended December 31, 2015 and 2014 .

(In millions of U.S. dollars)	Year ended December 31, 2015		Year ended December 31, 2014
Total operating revenues	747.7		1,263.7
Loss on disposal	(82.0	)	—
Total operating expenses	(568.2	)	(1,380.1	)
Operating (loss)/income	97.5		(116.4	)
Interest expense	(97.7	)	(103.8	)
Other financial items	(34.3	)	(70.7	)
Income/(loss) before taxes	(34.5	)	(290.9	)
Income taxes	(44.1	)	(29.6	)
Net income/(loss)	(78.6	)	(320.5	)

Total operating revenues

The following table sets forth our operating revenues for the years ended December 31, 2015 and 2014 .

(In millions of U.S. dollars)	Year ended December 31, 2015		Year ended December 31, 2014		Decrease
Total operating revenues	747.7		1,263.7		(40.8	)%

Total operating revenues for the year ended December 31, 2015 was $747.7 million , compared to $1,263.7 million for the year ended December 31, 2014 . Total operating revenues are predominantly contract revenues with additional amounts of reimbursable and related party revenue. The decrease in total operating revenues was primarily due to the West Navigator finishing its contract in January 2015, which has contributed to approximately $244.3 million of the decrease as compared to 2014. The West Venture also ended its contract in August 2015, which has contributed to approximately $53.9 million of the decrease as compared to 2014. Lower operating dayrates on the West Phoenix , West Epsilon and West Elara contributed to a decrease of approximately $46.5 million, $20.1 million and $15.7 million respectively as compared to 2014. In addition, lower reimbursable revenue on the West Alpha contributed to a fall of approximately $97.3 million as compared to 2014, due to completion of winterization projects for Kara Sea operations. The West Elara also had lower reimbursable revenue, contributing to a fall of approximately $20.3 million as compared to 2014. In 2014, we earned related party revenues of $44.0 million relating to our management of the West Hercules on behalf of Seadrill. No such revenue was earned in 2015. The fall in revenue was partly offset by the West Linus , which commenced operations in May 2014, and contributed to an increase of approximately $44.6 million in revenues for the year ended December 31, 2015 as compared to 2014. The remaining movements relate to variations in the operating performance of the drilling units.

Loss on disposals

As a result of the agreement with Jurong, we have concluded that the West Rigel drilling unit should be classified as “Held for Sale” as at December 31, 2015, and accordingly we have recognized an impairment loss of $82 million . Refer to Note 12 - "Asset held for sale" to our Consolidated Financial Statements included herein for more information.

Total operating expenses

The following table sets forth our operating expenses for the years ended December 31, 2015 and 2014 :

(In millions of U.S. dollars)	Year ended December 31, 2015		Year ended December 31, 2014		Decrease
Total operating expenses	(568.2	)	(1,380.1	)	(58.8	)%

Total operating expenses for the year ended December 31, 2015 was $(568.2) million , compared to $(1,380.1) million for the year ended December 31, 2014 . Total operating expenses consist of vessel and rig operating expenses, depreciation and amortization, impairment charges, general and administrative expenses and reimbursable expenses. Vessel and rig operating expenses decreased by $187.6 million , primarily due to the West Navigator and West Venture completing their contracts, as discussed in the revenues section above. The West Phoenix was also warm stacked for the fourth quarter of 2015, resulting in lower operating costs. In addition our cost-cutting initiatives have resulted in lower personnel and repairs and maintenance costs across all units. The weakening of the Norwegian kroner against the U.S. dollar has also caused reductions in operating expenses. The decrease in vessel and rig

38

---

operating expenses is partly offset by the West Linus , which commenced operations in May 2014. Reimbursable expenses decreased by a total of $134.6 million. This was mainly driven by the decrease in reimbursables on the West Alpha , which contributed to a fall of approximately $90.6 million as compared to 2014. Depreciation expenses increased by a total of $9.8 million, which was driven by the West Linus being available for operations commencing May 2014. The decrease in operating expenses was also primarily related to a loss on impairment relating to goodwill of $480.6 million in 2014, for which there was none of in 2015. General and administration expenses decreased by $18.8 million in 2015 as compared to 2014 due to the transaction fees and costs relating to our relocation to Oslo in 2014.

Interest expense

Interest expense for the year ended December 31, 2015 was $97.7 million , compared to $103.8 million for the year ended December 31, 2014 . The decrease was primarily due to a fall in the total outstanding interest bearing debt of $2,449.6 million as at December 31, 2015 compared to $2,730.1 million as at December 31, 2014 , which is due to repayments made on the outstanding principal.

Other financial items

Other financial items reported in the income statement include the following items:

(In millions of U.S. dollars)	Year ended December 31, 2015		Year ended December 31, 2014
Interest income	0.2		0.5
Loss on derivative financial instruments	(57.4	)	(86.2	)
Foreign exchange gain/(loss)	28.3		41.0
Other financial items	(5.4	)	(26.0	)
Total other financial items	(34.3	)	(70.7	)

The loss on derivative financial instruments relates to fair value adjustments and net settlements on our interest rate swaps, cross currency swaps and forward exchange contracts. During the year ended December 31, 2015 , the recognized loss from derivative financial instruments was $57.4 million , compared to a loss of $86.2 million for the year ended December 31, 2014 . These figures include realized net settlements on the derivative financial instruments of $37.1 million and $32.5 million for the the year ended December 31, 2015 and December 31, 2014 respectively. The unrealized losses were due to the falls in the fair market value of these derivative financial instruments.

Foreign exchange gain was $28.3 million for the year ended December 31, 2015 , compared to a gain of $41.0 million in the year ended December 31, 2014 . This was primarily due to the Norwegian kroner weakening against the U.S. dollar during 2015 and 2014, with gains recognized in respect of our NOK-denominated debt.

Income taxes

Income tax expense was $44.1 million for the year ended December 31, 2015 , compared to $29.6 million for the year ended December 31, 2014 . Our effective tax rate was approximately -127.8% for the year ended December 31, 2015 , as compared to -10.2% for the year ended December 31, 2014 . The increase in the negative effective tax rate is due to the loss on derivatives, which is recognized in a non-taxable jurisdiction. This means that we continue to pay tax on local operations but reported an overall a loss before tax inclusive of discrete items.  The negative rate reflects no tax relief on the impairments or the derivative loss. This is due to these items largely falling within the zero tax rate on Bermuda companies. In addition, the increase in the tax expense in 2015 in comparison to 2014 is mainly due to deferred tax liability recorded on unremitted earnings.

We may be taxable in more than one jurisdiction based on our drilling rig operations. A loss in one jurisdiction may not be offset against taxable income in another jurisdiction. Thus, we may pay tax within some jurisdictions even though it might have an overall loss at the consolidated level.

Significant amounts of our income and costs are reported in non-taxable jurisdictions such as Bermuda. The drilling rig operations are normally carried out in taxable jurisdictions. In the tax jurisdictions where we operate, the corporate income tax rates range from 20% to 27% for earned income. Further, losses in one tax jurisdiction may not be offset against taxable income in other jurisdictions. Accordingly, the effective tax rate may differ significantly from period to period depending on the level of activity in and mix of each of the tax jurisdictions in which our operations are conducted.

39

---

Fiscal Year Ended December 31, 2014 compared to Fiscal Year Ended December 31, 2013

The following table sets forth our operating results for the year ended December 31, 2014 and 2013 .

(In millions of U.S. dollars)	Year ended December 31, 2014		Year ended December 31, 2013
Total operating revenues	1,263.7		1,324.3
Total operating expenses	(1,380.1	)	(963.7	)
Operating income	(116.4	)	360.6
Interest expense	(103.8	)	(84.9	)
Other financial items	(70.7	)	(11.2	)
Income before taxes	(290.9	)	264.5
Income taxes	(29.6	)	(28.9	)
Net income	(320.5	)	235.6

Total operating revenues

The following table sets forth our total operating revenues for the year ended December 31, 2014 and 2013 .

(In millions of U.S. dollars)	Year ended December 31, 2014		Year ended December 31, 2013		Increase
Total operating revenues	1,263.7		1,324.3		(4.6	)%

Total operating revenues for the year ended December 31, 2014 was $1,263.7 million , compared to $1,324.3 million for the year ended December 31, 2013 . Total operating revenues are predominantly contract revenues with additional amounts of reimbursable and related party revenue. The decrease in total operating revenues was primarily due to West Hercules moving from a bareboat agreement to a management agreement in November 2013 resulting in revenue being billed from Seadrill. The West Hercules commenced operations in January 2013 and contributed $128.3 million of contract revenues in 2013 compared to nil in 2014. Similarly, reimbursable revenues decreased by $34.3 million due reimbursable work to winterize the West Hercules , in 2013 of $112.0 million offset by an increase of $74.5 million of reimbursable revenue from preparing the West Alpha for operations in the Kara Sea. Related party revenues were $44.9 million in 2014 compared to $12.1 million in 2013 due to the West Hercules management agreement in November 2013. In addition the West Linus commenced operations in May 2014, contributing $79.8 million of revenues in 2014.

Total operating expenses

The following table sets forth our total operating expenses for the year ended December 31, 2014 and 2013 .

(In millions of U.S. dollars)	Year ended December 31, 2013		Year ended December 31, 2012		Increase
Total operating expenses	(1,380.1	)	(963.7	)	43.2	%

Total operating expenses for the year ended December 31, 2014 was (1,380.1) million compared to (963.7) million for the year ended December 31, 2013 . Total operating expenses consist of vessel and rig operating expenses, depreciation and amortization, general and administrative expenses and reimbursable expenses. The increase in operating expenses was primarily related to a loss on impairment relating to goodwill of $480.6 million. West Hercules moving from a bareboat agreement to a management agreement led to decreased operating expenses of $78.0 million in 2014, mostly due to no bareboat fee of $58.5 million. This was offset by operating expenses for the West Linus commencing operations of $37.7 million. Reimbursable expenses decreased by $33.7 million, mainly related to the winterization work on West Hercules which was recharged to Statoil in 2013. There was also an increase in general and administrative expenses of $7.0 million in professional fees which includes transactions fees for the Rosneft transactions and $3.0 million for relocating offices to Oslo.

Interest expense

Interest expense for the year ended December 31, 2014 was $103.8 million, compared to $84.9 million for the year ended December 31, 2013. The increase was primarily due to an increase in interest bearing debt to $2,774.4 million for the year ended December 31, 2014 compared to $2,447.9 million in 2013. The main refinancing activity took place at the start of the year being the $600 million 6.25% Senior Unsecured Notes due 2019 in January 2014 and $475 million Credit Facility for the West Linus in February 2015.

40

---

Other financial items

Other financial items reported in the income statement include the following items:

(In millions of U.S. dollars)	Year ended December 31, 2013		Year ended December 31, 2012
Interest income	0.5		0.6
Loss on derivative financial instruments	(86.2	)	10.9
Foreign exchange (loss)/gain	41.0		10.9
Other financial items	(26	)	(6.5	)
Total other financial items	(70.7	)	15.9

 

The loss on derivative financial instruments relates to fair value adjustments to our interest rate swaps, cross currency swaps and forward exchange contracts. During the year ended December 31, 2014, the recognized loss from derivative financial instruments was $86.2 million, compared to a loss of $16.1 million for the year ended December 31, 2013. These losses were primarily due to adjustments for the fair market value of these derivative financial instruments.

Foreign exchange gain was $41.0 million for the year ended December 31, 2014, compared to a gain of $10.9 million in the year ended December 31, 2013. This was primarily due to the Norwegian kroner weakening against the U.S. dollar during 2014 and 2013 in respect of our NOK-denominated debt. The other financial items of $26.0 million are mostly related to $22.5 million termination fee for the $500 million 7.75% bond redeemed in February 2014.

Income taxes

Income tax expense was $29.6 million for the year ended December 31, 2014, compared to $28.9 million for the year ended December 31, 2013. Our effective tax rate was approximately (10.2%) for the year ended December 31, 2014, as compared to 10.9% for the year ended December 31, 2013. The negative effective tax rate results from the non-taxable loss on impairment of $480.6 million which was recognized during the year ended December 31, 2014. On April 1, 2014, there was a legislation change to the bareboat charter measure in the United Kingdom where a cap on the bareboat charter deduction was introduced. The impact on the tax expense for the year ended December 31, 2014 was an increase of $5.3 million.

Significant amounts of our income and costs are reported in non-taxable jurisdictions such as Bermuda. The drilling rig operations are normally carried out in taxable jurisdictions. In the tax jurisdictions where we operate, the corporate income tax rates range from 20% to 27% for earned income. Further, losses in one tax jurisdiction may not be offset against taxable income in other jurisdictions. Accordingly, the effective tax rate may differ significantly from period to period depending on the level of activity in and mix of each of the tax jurisdictions in which our operations are conducted.

B.    Liquidity and Capital Resources

Overview

We operate in a capital-intensive industry. Historically, our investment in newbuild drilling units, secondhand drilling units and our acquisition of other companies has been financed through cash generated from operations, and a combination of equity issuances, bond and convertible bond offerings, and borrowings from commercial banks and export credit agencies. Our liquidity requirements relate to servicing and repaying our debt, funding investment in drilling units, funding working capital requirements, funding potential dividend payments and maintaining adequate cash reserves to mitigate the effects of fluctuations in operating cash flows. Most of our contract and other revenues are received monthly in arrears, and most of our operating costs are paid on a monthly basis.

Our funding and treasury activities are conducted within corporate policies to maximize returns while maintaining appropriate liquidity for our operating requirements. Cash and cash equivalents are held mainly in U.S. dollars, with lesser amounts held in Norwegian Kroner and Brazilian Real.

This section discusses the most important factors affecting the liquidity and capital resources of the company, including:

•	summary of our borrowing activities;

•	liquidity outlook;

•	our newbuilding program;

•	key financial covenants contained in our borrowings; and

•	sources and uses of cash.

Summary of our borrowing activities

As of December 31, 2015 , we had total outstanding borrowings under our credit facilities of $2,449.6 million , compared to $2,730.1 million as at December 31, 2014 . This includes interest bearing debt under loan agreements with related parties of $321.0 million .

41

---

We have issued a variety of secured and unsecured borrowings. Total secured debt totaled $1,554.0 million as at December 31, 2015 . Generally the secured debt amortizes over a period of five to ten years, with a balloon payment at maturity. The debt is secured by, among other things, liens on our drilling units. In addition, all of our loan agreements contain cross-default provisions, meaning that if we are in default under one of our loan agreements, amounts outstanding under our other loan agreements may also be in default, accelerated and become due and payable.

In addition, we had unsecured bonds totaling $770.6 million . Our unsecured debt consists of bonds denominated primarily in U.S. dollars, but also in Norwegian kroner, at both fixed and floating rates of interest. For the floating bonds in Norwegian kroner, we have entered into cross-currency interest rate swaps to fix the interest and exchange rates to the U.S. dollar.

During the year ended December 31, 2015 we made external debt repayments of $305.1 million , compared to $430.5 million in 2014 . In 2015 this consisted of normal debt amortizations.

In 2014 we issued a bond (the Senior Unsecured Notes) with an aggregate principal of $600 million ,coupon rate of 6.25% , and maturity in 2019. We used the gross proceeds of the senior unsecured notes issuance for the prepayment of indebtedness and transaction expenses and general corporate purposes. Seadrill has purchased approximately 31.1% of the aggregate principal amount of the notes. In addition, in 2014, SFL Linus Ltd, which we consolidate as a variable interest entity, drew down on its $475 million secured term loan and revolving credit facility to fund the acquisition of West Linus .

As at December 31, 2015 we had a total of $50 million of undrawn borrowing capacity under our existing credit facilities. At the current time, however, we are restricted from drawing down on any of this capacity due to restrictions in our debt agreements.

The outstanding debt as of December 31, 2015 is repayable as follows:

(In millions of U.S. dollars)	Year ending December 31,
Year ended December 31, 2016	218.1
Year ended December 31, 2017	1,080.8
Year ended December 31, 2018	218.4
Year ended December 31, 2019	807.3
Year ended December 31, 2020	—
Year ended December 31, 2021 and thereafter	125.0
Total debt	2,449.6

Liquidity outlook

Our short-term liquidity requirements relate to servicing our debt amortizations, interest payments, and funding working capital requirements. Sources of liquidity include existing cash balances, and contract and other revenues. We have historically relied on our cash generated from operations to meet our working capital needs. In the past we have also relied on revolving credit facilities provided by Seadrill.

We anticipate that we will be required to obtain additional liquidity provided by Seadrill in order to fully meet our short term liquidity requirements over the next twelve months. Our previous $85m revolving credit facility with Seadrill expired in January 2015.  At the current point in time no revolving credit facility is in place.

Our long-term liquidity requirements include the repayment of long-term debt balances. On April 28, 2016 we entered into an amendment to defer the maturity our US$2 billion senior secured credit facility, which has a balloon payment of $950 million on maturity, from April 15, 2017 until June 30, 2017. We expect the need to refinance this facility with additional issuances of debt and/or new equity in order to meet our obligations as they become due. The Company's secured credit facilities and NOK 1,500 million bond are guaranteed by Seadrill, and cross default clauses exist between our secured credit facilities and bonds and Seadrill's other credit facilities.

We are currently working with our banks and advisers to evaluate financing alternatives in light of industry and capital market conditions. We aim to further communicate our financing plans later this year.

Covenants contained within our borrowings

Our credit facilities generally contain financial covenants. In February 2015, we received approval to amend the agreements for our NOK 1,500 million senior unsecured bond, $2,000 million Senior Secured Credit Facility, and $475 million secured term loan. Under the terms of each agreement, Seadrill provides guarantees for the bonds and credit facility in exchange for amendments to the covenant package, principally replacing the previous financial covenants with Seadrill's financial covenants, which are measured at the Seadrill consolidated level.

42

---

Please see " Note 14 –Long term debt" to our Consolidated Financial Statements included herein, for further information on the covenants contained within our credit facilities and bonds.

Please see "Item 3. Key Information—D. Risk Factors" for further information on the risks facing our Company and implications of a breach in financial covenants.

In February 2015, we received approval to amend the agreements for our NOK 1,500 million senior unsecured bond, $2,000 million Senior Secured Credit Facility, and $475 million secured term loan. Under the terms of each agreement, Seadrill provides guarantees for the bonds and credit facility in exchange for amendments to the covenant package, principally replacing the current financial covenants with Seadrill's financial covenants, which are measured at the Seadrill consolidated level.

In May 2015, Seadrill executed an amendment to the covenants contained in all of its secured credit facilities. Under the amended terms, the permitted leverage ratio has been amended to the following:

•	6.0:1, from and including the financial quarter starting on July 1, 2015 and including the financial quarter ending on September 30, 2016;

•	5.5:1, from and including the financial quarter starting on October 1, 2016 and including the financial quarter ending December 31, 2016;

•	4.5:1, from and including the financial quarter starting on January 1, 2017 until the final maturity date.

In connection with the amendment, effective from July 1, 2015, an additional margin may be payable on the senior secured credit facilities as follows:

•	.125 percent per annum if the leverage ratio is 4.50:1 up to and including 4.99:1;

•	.25 percent per annum if the leverage ratio is 5.00:1 up to and including 5.49:1; and

•	.75 percent per annum if the leverage ratio is 5.50:1 up to and including 6.00:1.

In addition, as part of the amendments to the covenants contained in the Company’s senior secured credit facilities in May 2015, the Company is restricted from making dividend distributions, and repurchasing its own shares during the amendment period until January 1, 2017.

On April 28, 2016, Seadrill and the Company executed amendment and waiver agreements in respect of all of their senior secured credit facilities. The maturity of our $2 billion senior secured credit facility has been extended to June 30, 2017. In addition, the key terms and conditions of these agreements are as follows:

•

Equity ratio : Seadrill is required to maintain a total equity to total assets ratio of at least 30.0% . Prior to the amendment, both total equity and total assets are adjusted for the difference between book and market values of drilling units, as determined by independent broker valuations. The amendment removes the need for the market value adjustment from the calculation of the equity ratio until June 30, 2017.

•	Leverage ratio : the Seadrill is required to maintain a ratio of net debt to EBITDA. Prior to the amendment the leverage ratio had to be no greater than 6.0 :1, falling to 5.5 :1 from October 1, 2016, and falling again to 4.5 :1 from January 1, 2017. The amendment retains the ratio at 6.0 :1 until December 31, 2016, and then increases to 6.5 :1 between January 1, 2017 and June 30, 2017.

•

Minimum-value-clauses : Seadrill's and the Company's secured bank credit facilities contain loan-to-value clauses, or minimum-value-clauses (“MVC”), which could require the Seadrill and the Company to post additional collateral or prepay a portion of the outstanding borrowings should the value of the drilling units securing borrowings under each of such agreements decrease below required levels. This covenant has been suspended until June 30, 2017.

•	Minimum Liquidity : The aggregated minimum liquidity requirement for the Seadrill Group to maintain cash and cash equivalents of at least $150 million has been increased to $250 million .

Additional undertakings:

•	Further process : Seadrill and the Company has agreed to consultation, information provision and certain processes in respect of further discussions with its lenders under its senior secured credit facilities. This includes agreements in respect of progress milestones towards the agreement of, and implementation plan in respect of, a comprehensive financing package.

•	Restrictive undertakings : Seadrill and the Company has agreed to additional near-term restrictive undertakings applicable during this process, including (without limitation) limitations in respect of:

◦	dividends, share capital repurchases and total return swaps;

◦	investments in, extensions of credit to or the provision of financial support for non-wholly owned subsidiaries;

◦	investments in, extensions of credit to or the provision of financial support for joint ventures or associated entities;

◦	acquisitions;

◦	dispositions;

◦	prepayment, repayment or repurchase of any debt obligations;

43

---

◦	granting security; and

◦	payments in respect of newbuild drilling units,

in each case, subject to limited exceptions.

•	Other changes and provisions:

◦	Undrawn availability : Seadrill and the Company has agreed to refrain from borrowing any undrawn commitments under its senior secured credit facilities.

◦	Fees : The Company has agreed to pay certain fees to its lenders in consideration of these extensions and amendments.

These extensions and amendments are designed to provide Seadrill and the Company and the banking group with a period of stability and certainty while a more comprehensive financing package is agreed. Seadrill and the Company intends to further communicate these financing plans this year.

The Seadrill and the Company expect to remain in compliance with the amended covenants in 2016.

Our Newbuilding Program

We have entered into a construction contract for one sixth-generation harsh environment semi-submersible, the West Rigel , with corresponding contractual commitments, including project management, operation preparations, and variation orders, totaling $717.5 million of which we have paid $204.3 million to date. The West Rigel was scheduled to be delivered to us in the fourth quarter of 2015.

On December 2, 2015, we signed an amendment with Jurong for the deferral of the delivery of the semi-submersible drilling unit, the West Rigel (the "Unit"). The deferral period lasts until June 2016, following completion of which, we and Jurong have agreed to form a joint asset holding company for joint ownership of the Unit, to be owned 23% by us and 77% by Jurong, in the event no employment is secured for the Unit and no alternative transaction is completed. Until the end of the deferral period, the Company will continue to market the unit for an acceptable drilling contract, and the Unit will remain at the Jurong Shipyard in Singapore. We and Jurong may also consider other commercial opportunities for the Unit during this period. However, based on current market conditions, management deems the most probable outcome to be that the Unit will be contributed to the joint asset holding company. As a result of the above, we have concluded that the West Rigel should be classified as an asset held for sale as at December 31, 2015. Please see “ Note 12 –Asset held for sale” of the Consolidated Financial Statements contained herein for further information.

Sources and Uses of Cash

At December 31, 2015 , we had cash and cash equivalents totaling $150.9 million , as compared to $116.2 million in 2014 .

In the year ended December 31, 2015 , we generated cash from operations of $339.9 million , used $39.0 million in investing activities, and cash outflows from financing activities were $264.1 million . In the year ended December 31, 2014 , we generated cash from operations of $199.1 million , used $447.5 million in investing activities, and raised $271.2 million from financing activities. In the year ended December 31, 2013 , we generated cash from operations of $425.2 million , used $103.9 million in investing activities, and outflows of $334.0 million from financing activities.

	Years Ended December 31,
	2015			2014			2013
Net cash provided by operating activities	339.9			199.1			425.2
Net cash used in investing activities	(39.0	)		(447.5	)		(103.9	)
Net cash (used in)/provided by financing activities	(264.1	)		271.2			(334.0	)
Effect of exchange rate changes on cash and cash equivalents	(2.1	)		9.3			(1.6	)
Net increase/(decrease) in cash and cash equivalents	34.7			32.1			(14.3	)
Cash and cash equivalents at beginning of the period	116.2			84.1			98.4
Cash and cash equivalents at the end of period	150.9			116.2			84.1

Net cash provided by operating activities

The net cash generated from operations increased in 2015 compared to 2014 primarily due to working capital improvements in the year, including improved collections of trade receivables and related party balances. Net changes in operating assets and liabilities were an inflow of $114.1 million in 2015 compared to an outflow of $58.8 million in 2014 . We also spent $30.3 million on long-term maintenance in 2015 compared to $155.4 million in 2014 , due to the implementation of our cost savings program. The increase in net cash generated from operations was partly offset by a reduction in underlying operating income.

Net cash used in Investing activities

44

---

The net cash used in investing activities was $39.0 million in 2015 , compared to net cash used in investing activities of $447.5 million in 2014 . In 2014 we paid the final yard installment for the West Linus which was completed in the first half of 2014. No newbuildings were completed in 2015.

Net cash used in Financing activities

he net cash used in financing activities was $264.1 million in 2015 , compared to cash provided by financing activities of $271.2 million in 2014 . During the year ended December 31, 2015 we made external debt repayments of $305.1 million , compared to $430.5 million in 2014 .

In 2014 we also raised $1,215.0 million in new debt, paid dividends of $171.1 million , and made net repayments of related party and shareholder loans of $445 million. In February 2014, we completed our underwritten initial public offering in the United States of 13,513,514 common shares at $9.25 per share, resulting in net proceeds to us of $114.1 million .

Dividends

For the year ended December 31, 2015, we did not pay any dividends, while for the same period in 2014 we paid $171.1 million in total cash dividends. On November 26, 2014, the Company suspended dividend distributions until further notice. As of May 2015, as part of the amendments to the covenants contained in the Company’s senior secured credit facilities, the Company is restricted from making dividend distributions during the waiver period until January 1 2017. In addition, in April 2016, as part of the amendments to the covenants contained in the Company’s senior secured credit facilities, the Company is restricted from making dividend distributions during the amendment period until June 30, 2017. Please see "Item 8. Financial Information—A. Consolidated Statements and Other Financial Information—Dividend Policy" for more information.

Restrictions

North Atlantic Drilling Ltd., as the parent company of its operating subsidiaries, is not a party to any drilling contracts directly and is therefore dependent on receiving cash distributions from its subsidiaries and other investments to meet its payment obligations. Cash dividend payments are regularly transferred by the various subsidiaries. Surplus funds are deposited to maximize returns while providing the Company with flexibility to meet all requirements for working capital and capital investments.

Hedging of market risk

We use financial instruments to reduce the risk associated with fluctuations in interest and foreign exchange rates. Most of these agreements do not qualify for hedge accounting and any changes in the fair values of the financial instruments are included in the Consolidated Statement of Operations under "gain/(loss) on derivative financial instruments."

Please see "Item 11–Quantitative and qualitative disclosures about market risk" for a more detailed discussion of how changes in the economic environment would affect the Company.

Please see " Note 22 –Risk management and financial instruments" to our Consolidated Financial Statements included herein, for further information on our loan facilities and bonds.

C.     Research and development, patents and licenses, etc.

We do not undertake any significant expenditure on research and development, and have no significant interests in patents or licenses.

D.     Trend information

As a result of the decline in oil prices and reductions in oil company expenditures, the offshore drilling market is currently entering its third year of a downturn. Rig owners are bidding for available work extremely competitively with a focus on utilization over returns, which will likely drive dayrates down to or below cash breakeven levels.

The harsh environment drilling market continues to be oversupplied with multiple drilling rigs chasing the few opportunities that are available and contracting activity is at the lowest levels since the 1980’s. Oil company capital expenditures are expected to decline further in 2016 following two consecutive years of decline. It is expected that the majority of rigs with contracts expiring in 2016 will be unable to find suitable follow on work and many are likely to be idle for a protracted period. Consequently, cold stacking and scrapping activity will likely accelerate.

Oil companies continue to work on managing their existing rig capacity. They are in many cases overcommitted based on reduced activity levels and there is very little appetite for adding new units. Near term budgetary constraints are the primary focus of many oil companies, with short term cash conservation ranking ahead of long term value generation. However, the near term cost cutting needed to support dividend payments can be expected to negatively impact the long term production profiles of existing development projects.

45

---

At today’s oil prices, the full cycle cost of many of the hydrocarbon provinces globally are uneconomic, including the harsh environment where costs historically have been higher due to required winterization of equipment and regional regulations. A supply response is inevitable, however it may take some time due to the high degree of sunk costs in producing projects. When also considering the eventual demand response to low prices a rebalancing in the oil markets is expected at some point. Offshore oil fields represent a material portion of most major oil company’s reserves and their production remains a cost competitive source of hydrocarbons.

Harsh environment floaters

It is likely that the majority of harsh environment floaters with contracts expiring in 2016 will be unable to find reasonable follow on work. It will be important to observe how rig owners react when faced with idle time on their units and face the choice to warm stack, cold stack or scrap units. For the most part, customer conversations remain focused on extending existing contracted assets or trade-offs between existing assets and newer assets rather than contracting new units for work.

As of March 31, 2016, there were 17 floaters operating in Norway and 14 in the United Kingdom. There are 20 rigs stacked in these markets, of which eight rigs are warm stacked, representing a 79% marketed utilization. There are nine harsh environment rigs scheduled for delivery in 2016-2017 that are capable of working in the North Atlantic Region and one additional newbuild unit is currently mobilizing to the U.K. shelf. With uncertain near-term activity levels, the Company expects further pressure on both dayrates and utilization.

Cold stacked units will generally require an improvement in dayrates sufficient to overcome reactivation costs before they are reintroduced into marketed supply. There are 15 floaters in the United Kingdom and Norway older than 30 years with contracts expiring in 2016 and in 2017. Additionally, there are nine rigs older than 30 years which are already idle. We expect a number of these older rigs to be cold stacked and ultimately retired, as the investment to reactivate will outweigh contract economics in this prolonged downturn. Significant cold stacking activity would represent a positive development in the market, effectively reducing marketed supply and helping to stabilize utilization and pricing until a more fundamental recovery is in place.

Harsh environment jack-ups

Tendering activity in the jack-up market during 2015 continued to decline and reached new low dayrate levels. Recent tenders reflect a lowered demand for drilling exploration and development activities in the near term, and interest has increased for alternative types of work. Oil companies are inquiring about rigs that can be used for combined drilling and production activities, as well as plug and abandonment of wells to decommission their fields. This represents a shift in the market as oil companies are rationalizing their investments in the offshore oil fields in the North Sea.

Currently 23 harsh environment jack-ups (+350 ft) are working in Norway and the United Kingdom out of a total marketed fleet of 25, representing a 93% marketed utilization. There are four idle rigs and an additional two rigs rolling off contract by the end of 2016 that are older than 30 years, which are prime candidates for retirement.

E.     Off Balance Sheet Arrangements

We had no off-balance sheet arrangements as of December 31, 2015 or 2014 , other than operating lease obligations and other commitments in the ordinary course of business that we are contractually obligated to fulfill with cash under certain circumstances. These commitments include guarantees in favor of banks, suppliers and variable interest entities and guarantees towards third parties such as surety performance guarantees towards customers as it relates to our drilling contracts, contract bidding, customs duties, tax appeals and other obligations in various jurisdictions. Obligations under these guarantees are not normally called, as we typically comply with the underlying performance requirement. As of December 31, 2015 , we had not been required to make collateral deposits with respect to these agreements.

The maximum potential future payments are summarized in " Note 23 –Commitments and contingencies" of the Notes to our Consolidated Financial Statements included herein.

46

---

F.     Contractual Obligations

At December 31, 2015 , we had the following contractual obligations and commitments:

(In millions of U.S. dollars)	Less than 1 year		1 - 3 years		3 - 5 years		More than 5 years		Total
$2,000 Million Senior Secured Credit Facility	166.7		1,033.3		—		—		1,200.0
$475 Million Credit Facility	51.4		95.0		207.6		—		354.0
$600 Million 6.25% Senior Unsecured Notes due 2019	—		—		600.0		—		600.0
NOK 1,500 Million Senior Unsecured Bond (1)	—		—		170.6		—		170.6
$125 Million related party loan	—		—		—		125.0		125.0
Total interest payments (2)	99.8		146.3		17.8		50.6		314.5
Financial Guarantee fee charged by Seadrill	4.8		3.0		0.2		—		8.0
Pension obligations  (3)	11.7		24.4		25.5		69.7		131.3
Leased premises	4.2		7.5		7.0		6.5		25.2
Total contractual cash obligations	338.6		1,309.5		1,028.7		251.8		2,928.6

(1)	This has been converted using an exchange rate of USD $1 to NOK8.75 as of December 31, 2015 . Please see “Item 11. Quantitative And Qualitative Disclosures About Market Risk” for details on cross currency swaps.

(2)	Interest payments are based on the assumption that all of our loans are fully drawn over the period. It is further assumed that no refinancing of existing loans takes place. Interest has been calculated using the U.S. Dollar Yield Curve published by Bloomberg, plus agreed margins for each loan facility. The effects of interest rate swaps have been included in the calculations.

(3)	Pension obligations are the forecasted employer's contributions to the Company's defined benefit plans, expected to be made over the next ten years.

G.     Safe Harbor

Forward-looking information discussed in this Item 5 includes assumptions, expectations, projections, intentions and beliefs about future events. These statements are intended as "forward-looking statements." We caution that assumptions, expectations, projections, intentions and beliefs about future events may and often do vary from actual results and the differences can be material. Please see "Cautionary Statement Regarding Forward-Looking Statements" in this Annual Report.

ITEM 6.    DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES

A.    Directors and Senior management

Set forth below are the names, ages and positions of our current directors and executive officers.

Name	Age	Position
Kate Blankenship	51	Director and Audit Committee Member
Paul M. Leand, Jr.	49	Director
Ørjan Svanevik	50	Director
Georgina Sousa	65	Director, Company Secretary
Bote de Vries	57	Director
Hunter Cochrane	61	Director
Alf Ragnar Løvdal	58	Chief Executive Officer of North Atlantic Management
Scott McReaken	37	Chief Financial Officer of North Atlantic Management

In May 2015, Ms. Cecilie Fredriksen and Mr. Harald Thorstein resigned as directors of the Company. On November 5, 2015 Jo Lunder resigned as a director of the Company. On August 17, 2015, Ragnvald Kavli resigned as our Chief Financial Officer and Mr. Scott McReaken was appointed as his replacement.

47

---

Biographical information concerning the directors and executive officers listed above is set forth below.

Kate Blankenship has served as a director of the Company since February 2011. Mrs. Blankenship has also served as a director of Frontline since 2003. Mrs. Blankenship joined Frontline Ltd. in 1994 and served as its Chief Accounting Officer and Company Secretary until October 2005. Mrs. Blankenship has been a director of Ship Finance since October 2003, Seadrill since its inception in May 2005, Seadrill Partners since June 2012, Independent Tankers Corporation Limited, since February 2008, Golden Ocean Group Limited since March 2015, Archer Ltd., or Archer, since its incorporation in 2007 and Avance Gas Holding Ltd since October 2013. Mrs. Blankenship served as a director of Golar LNG Limited from July 2003 until September 2015 and Golar LNG Partners from September 2007 until September 2015. She is a member of the Institute of Chartered Accountants in England and Wales.

Paul M. Leand, Jr.  has served as a director since February 2012. Mr. Leand has been the Chief Executive Officer and director of AMA Capital Partners LLC, or AMA, an investment bank specializing in the maritime industry since 2004. Mr. Leand has worked extensively in U.S. capital markets in connection with AMA’s restructuring and mergers and acquisitions practices. Mr. Leand currently serves as a member of the Investment Committee of AMA Shipping funds, a series of private equity funds formed and managed by AMA. From 1989 to 1998, Mr. Leand served at the First National Bank of Maryland where he managed the bank’s Railroad Division and its International Maritime Division. Mr. Leand has also served as a director of Ship Finance since 2003, Golar LNG Partners LP since 2011, Seadrill since April 2013 and Eagle Bulk Shipping Inc. since 2014.

Ørjan Svanevik has served as a director of the Company since May 2015, and as a director of Seadrill since October 2014. Mr. Svanevik joined the Seatankers Group in July 2014 and has a broad industry background, with special knowledge of oil and gas, maritime, shipbuilding, and engineering sectors. He has extensive experience in global operations, investment management and corporate finance. Mr. Svanevik was served as managing director for the investment advisory firm Oavik Capital from October 2008 to July 2014. From 2005 to 2008, Mr. Svanevik was the head of mergers and acquisitions and a partner and Aker ASA. From 2004 to 2005, he was the COO and EVP of Kværner ASA. From 1994 to 2001, Mr. Svanevik worked in corporate advisory and investment banking for the Arkwright Group. Mr. Svanevik began his career at Schlumberger, where he held various international financial management positions from 1991 to 1994. Mr. Svanevik has an AMP from Harvard Business School and a MBA from Thunderbird School of Global Management.

Georgina Sousa  has served as a director of the Company since September 2013, and as our Company Secretary since our inception in February 2011. She is currently a director of Ship Finance, a director and the Head of Corporate Administration for Frontline Ltd., and the Company Secretary of Seadrill, Seadrill Partners, and Archer. Until January 2007, she was Vice-President-Corporate Services of Consolidated Services Limited, a Bermuda Management Company, having joined the firm in 1993 as Manager of Corporate Administration. From 1976 to 1982, Mrs. Souza was employed by the Bermuda law firm of Appleby, Spurling & Kempe as a company secretary and from 1982 to 1993 she was employed by the Bermuda law firm of Cox & Wilkinson as senior company secretary.

Bote de Vries was appointed as a director of the Company in March 2016. Mr. de Vries has extensive legal, asset advisory and financial services experience, specifically in the shipping and maritime sectors. He is a board member of Artilium Plc, TBS Shipping Services Inc., Lloydsfonds AG, Metro Exploration Holding Corporation and Vallianz Holdings; and member of four supervisory boards in shipping, healthcare, banking and building societies in the Netherlands.

Hunter Cochrane was appointed as a director of the Company in March 2016. Mr. Cochrane has extensive experience in industrial distribution and the oil and gas industry. He is also a board member of Chloe Marine Corp Ltd. and Golden Close Marine Corp Ltd; and holds advisory positions with Bovaro Partners LLC, a merchant banking partnership.

Alf Ragnar Løvdal has served as Chief Executive Officer of North Atlantic Management since January 2013. Mr. Løvdal served as Senior Vice President for Seadrill in the Asia Pacific region from April 2009 until December 2012. Mr. Løvdal has also held several other senior positions at Seadrill, including as general manager of operations for its mobile units. Mr. Løvdal has 35 years of experience in the oil and gas industry, including ten years in the well services business of the drilling contractor Smedvig, which Seadrill acquired in early 2006. Prior to his employment with Smedvig and Seadrill, Mr. Løvdal held various positions in different oil service companies, including five years of offshore field experience with Schlumberger Limited and serving as the chief executive officer of Seawell Management AS. He has a degree in mechanical engineering from Horten Engineering Academy in Norway.

Scott McReaken has served as Chief Financial Officer of North Atlantic Management since August 2015. Mr. McReaken has also served as Chief Executive Officer of Sevan Drilling since November 2013. He was previously director of finance for Seadrill in the Americas region from July 2012 to November 2013. Mr. McReaken was Director Financial Planning and Analysis at Vantage Drilling Company from March 2010 to July 2012 and held various positions at Pride International from May 2005 to March 2010, including finance manager in West Africa and lead analyst for divestiture of the Latin American onshore drilling and oil field services division. From the onset of his career at Arthur Andersen LLP in 2001, Mr. McReaken worked in audit and advisory services for various companies until 2005. He has a degree in accounting from The University of Texas at Austin and is a Certified Public Accountant and Certified Internal Auditor. Mr. McReaken has served as the Treasurer and Secretary of the International Association of Drilling Contractors since January 2013.

48

---

B.    Compensation

For the year ended December 31, 2015 , we paid $0.4 million in total compensation to directors. None of the members of our Board of Directors or officers will receive any benefits upon termination of their directorships or officers positions.

All references in this Annual Report to “our officers” include those officers of North Atlantic Management and Sevan Drilling Management AS, who perform or performed, as the case may be, executive officer services for our benefit. For the year ending December 31, 2015 , the Chief Executive Officer of North Atlantic Management AS, our Principal Executive Officer, and the Chief Financial Officer of North Atlantic Management AS, our Principal Financial Officer, were paid total combined aggregate compensation of $1.8 million in relation to their services to us.

In addition to cash compensation, during 2015 we also recognized an expense of $0.6 million relating to restricted stock units granted to certain of our directors and executive officers. The fair values of awards are based on the market share price on grant date which was $96.50 for the restricted stock units were granted in 2013, $14.10 for the grants in May 2015 and $3.70 for the grants in December 2015.

C.    Board Practices

Each director holds office until his or her term expires at the next annual general meeting of shareholders or until his or her death, resignation, removal or the earlier termination of his or her term of office. All directors whose term expires are eligible for re-election. Officers are appointed from time to time by our Board of Directors and hold office until a successor is appointed or their employment is terminated.

Our Board of Directors currently consists of six members, of which four are considered independent according to Rule 10A-3 of the Securities Exchange Commission Act of 1934, as amended: Mrs. Kate Blankenship, Mr. Paul Leand Jr, Mr. Hunter Cochrane and Mr. Bote de Vries.

We do not maintain service contracts with any of our directors providing for benefits upon termination of employment .

Committees of the Board of Directors

Our Board of Directors has established an audit committee that consists of one director, Mrs. Kate Blankenship. Our audit committee is responsible for ensuring that we have an independent and effective internal and external audit system. Additionally, the audit committee supports the Board of Directors in the administration and exercise of its responsibility for supervisory oversight of financial reporting and internal control matters and maintains appropriate relationships with our auditors. Our Board of Directors has determined that Mrs. Blankenship qualifies as “independent” under Rule 10A-3 under the Exchange Act, and as an “audit committee financial expert” for purposes of the Commission's rules and regulations.

Our Board of Directors has also established a conflicts committee composed of at least two members of our Board of Directors to review all transactions that the Board of Directors believes may involve conflicts of interest, including without limitation, the exercise of the right of first refusal or any waiver of rights under the Cooperation Agreement, and will determine if such transaction and the resolution of the conflict of interest is fair and reasonable to us. At least 50% of the members of the conflicts committee may not be officers or employees of us or directors, officers or employees of Seadrill or its affiliates. Any matters approved by the conflicts committee will be conclusively deemed to be fair and reasonable to us, and not a breach by our directors of any duties any of them may owe us or our shareholders. The current members of the conflicts committee are Mr de Vries and Mr Cochrane.

Our Board of Directors may, in the future, establish such other committees as it determines from time to time.

D.    Employees

As of December 31, 2015 , we employed approximately 1,082 people, including contracted labor, in our offices in Stavanger, Oslo, Bergen, Bermuda and Aberdeen, including 65 onshore employees and 1,017 offshore employees. Some of our employees and our contracted labor, who work in Norway and the United Kingdom, are represented by collective bargaining agreements. As part of the legal obligations in some of these agreements, we are required to contribute certain amounts to retirement funds and pension plans and have restricted ability to dismiss employees. In addition, many of these represented individuals are working under agreements that are subject to salary negotiation. These negotiations could result in higher personnel costs, other increased costs or increased operating restrictions that could adversely affect our financial performance. We consider our relationships with the various unions as stable, productive and professional. At present, there are no ongoing negotiations or outstanding issues, other than as disclosed in " Note 23 –Commitments and contingencies" of the Notes to our Consolidated Financial Statements included herein.

E.    Share ownership

The common shares beneficially owned by our directors and our executive officers are disclosed in “Item 7. Major Shareholders and Related Party Transactions - A. Major Shareholders.”

49

---

Equity Compensation Plans

On February 14, 2011, our Board of Directors resolved to establish a share option based incentive plan for our employees and directors, approved a set of rules applicable to the plan and reserved 6,000,000 of our authorized, but unissued common shares for use to satisfy future exercises of options granted under the plan.

As a result of the 1-for-10 reverse stock split in December 2015, the number of authorized, but unissued, share options was adjusted to 600,000 .

No options have, to date, been granted under this plan.

Restricted Stock Units

On November 7, 2013, our Board of the Directors approved 278,778 awards under North Atlantic Drilling`s Restricted Stock Units (“RSU”) plan.  During 2015, our Board of the Directors approved a further 1,587,719 awards under our RSU plan. 

Under the terms of the plan, the holder of an award is entitled to receive a certain number of our common shares if still employed at the end of the three year vesting period.  There is no requirement for the holder to pay for the share on grant date or upon vesting of the award.  In addition the holder is entitled to receive an amount equal to the ordinary dividends declared and paid on our shares during the vesting period.

As a result of the 1-for-10 reverse stock split in December 2015, the number of RSUs has been adjusted by 1,571,251 units. The total outstanding RSUs as of December 31, 2015 were 174,583 .

The table below summarizes the outstanding Shares, Share Options and RSU's issued to or Directors and executive officers. The awards have been adjusted for the 1 for 10 stock split.

Director or Key Employee	Interest in Options and Restricted Stock Units (RSUs)
	Scheme		Total number			Number vested			Fair Value at Grant Date			Vest date
Alf Ragnar Løvdal	RSUs		7,185			—			96.50			December 2016
	RSUs		3,145			—			14.10			December 2017
	RSUs		28,310			—			3.70			December 2018
Scott McReaken	RSUs		9,660			—			3.70			December 2018

ITEM 7.    MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS.

A.    Major shareholders

The following table sets forth information regarding beneficial ownership of our common stock for (i) owners of more than five percent of our common stock and (ii) our directors and officers, of which we are aware as of the date of this annual report.

Name	Number of shares		Percentage
Seadrill Limited (1)	16,966,372		70.4	%
All directors and executive officers individually	*		*

*	Our officers and directors individually own less than 1% of our outstanding shares of common stock.

(1)

Hemen Holding Limited, a Cyprus holding company, and other related companies are collectively referred to herein as Hemen. Hemen is Seadrill’s principal shareholder and indirectly holds 119,097,583 of Seadrill's common shares, representing 24.2% of Seadrill’s total outstanding common shares. These shares are indirectly held in trusts established by Mr. John Fredriksen for the benefit of his immediate family. Mr. Fredriksen disclaims beneficial ownership of the 119,097,583 Seadrill common shares held by Hemen, except to the extent of his voting and dispositive interest in such shares of common stock. Mr. Fredriksen has no pecuniary interest in the shares held by Hemen. Hemen also owns 168,734 of our common shares. In addition, Hemen Holding has a total return swap agreement with underlying exposure to 353,000 of our common shares.

Our principal shareholder has the same voting rights as other holders of our shares of common stock. We are not aware of any arrangements the operation of which may at a subsequent date result in our change of control.

50

---

B.    Related party transactions

From time to time the Company has entered into agreements and has consummated transactions with certain related parties, and may continue to do so in the future.

Included below is a summary of certain of our related party transactions. Additional information regarding the related party transactions for the years ended December 31, 2015 , 2014 , and 2013 is presented in " Note 21 –Related Party Transactions" of the Notes to our Consolidated Financial Statements contained herein.

Significant transactions with Seadrill

We are a majority owned subsidiary of Seadrill, which owns approximately 70.4% of our outstanding common shares as of the date of this Annual Report. The following is a summary of the significant related party agreements we have with Seadrill.

Cooperation Agreement

At the closing of our initial public offering, we entered into a cooperation agreement, or the Cooperation Agreement, with Seadrill.

Right of First Refusal on Business Opportunities

Under the Cooperation Agreement, we received a right of first refusal to participate in any business opportunity, or a North Atlantic Business Opportunity, identified by Seadrill or its controlled affiliates for drilling activities in the North Atlantic Region, which includes only the territorial waters and outer continental shelf jurisdiction of (i) Norway, (ii) the United Kingdom, (iii) Ireland, (iv) Denmark, (v) the Netherlands, (vi) the east coast of Greenland, (vii) Russia (west of the island of Diksonskiy), and (viii) all countries within the Baltic Sea and the Gulf of Bothnia. We will generally have between thirty (30) and ninety (90) days to either accept or reject such opportunity. If we reject or do not timely accept the North Atlantic Business Opportunity, Seadrill or its controlled affiliates may pursue the North Atlantic Business Opportunity. Seadrill Partners LLC is expressly excluded from the Seadrill affiliates subject to the Cooperation Agreement.

We have provided Seadrill or its controlled affiliates (other than us or our subsidiaries) with a right of first refusal to participate in any business opportunity, or a Seadrill Business Opportunity, identified by us for drilling activities outside of the North Atlantic Region. Seadrill will generally have between thirty (30) and ninety (90) days to either accept or reject such opportunity. If Seadrill rejects or does not timely accept the Seadrill Business Opportunity, we may pursue the Seadrill Business Opportunity.

Conflicts Committee

Under the Cooperation Agreement, a conflicts committee has been established to review all transactions that the board of directors believes may involve conflicts of interest, including exercise of the right of first refusal described in the two preceding paragraphs, or any waiver of our rights under the Cooperation Agreement and will determine such transaction and the resolution of the conflict of interest is fair and reasonable to us. At least 50% of the members of the conflicts committee may not be officers or employees of us or directors, officers or employees of our controlling shareholder or its affiliates. Any matters approved by the conflicts committee will be conclusively deemed to be fair and reasonable to us, and not a breach by our directors of any duties any of them may owe us or our shareholders.

Term, Termination and Amendments

The Cooperation Agreement has a five year term and shall terminate with immediate effect in the event Seadrill ceases to beneficially own a majority of our outstanding common shares. The Cooperation Agreement may be amended or terminated at any time upon the written agreement of the parties.

Loans and financial guarantees provided by Seadrill

Financial covenants and debt guarantees

In February 2015, we amended the agreements for our NOK 1,500 million senior unsecured bond, $2,000 million Senior Secured Credit Facility, and $475 million secured term loan. Under the terms of each amended agreement, Seadrill guarantees our obligations thereunder in exchange for amendments to the covenant package, principally replacing the previous financial covenants with Seadrill's financial covenants, which are measured at the Seadrill consolidated level. For further information on the covenants contained in our debt agreements, please see " Note 14 –Long term debt" of the Notes to our Consolidated Financial Statements included herein. The guarantee fee charged by Seadrill is 0.3% per annum of the outstanding principal.

In April 2016, Seadrill and the Company executed an amendment to the extend certain maturities and modify certain covenants contained within its secured credit facilities. Please see "Item 5. Operating and financial prospects - B. Liquidity and capital resources" for more information.

$600 Million 6.25% Senior Unsecured Notes due 2019

Seadrill is the holder of 31.1% of our $600 Million 6.25% Senior Unsecured Notes due 2019, which amounts to $186.6 million .

NOK 1,500 Million Senior Unsecured Bond

51

---

Seadrill is the holder of 5.5% of our NOK 1,500 Million Senior Unsecured Bond, which amounts to $11 million .

Revolving Credit Facility

Seadrill provided us with an unsecured revolving shareholder loan of $85 million, which matured on January 30, 2015.

Management services

North Atlantic Management provides all day-to-day management functions to the Company and its subsidiaries in accordance with the terms of the General Management Agreement. North Atlantic Management has contracted in senior management services and corporate management services from Seadrill Management in accordance with the terms of the Management and Administrative Services Agreement. The agreement can be terminated by either party upon 90 days ' notice. In consideration of the services provided, the Company pay Seadrill a fee that includes the operating costs attributable to the Company plus a margin of 8% . For providing services pursuant to the services agreement, Seadrill Management had charged North Atlantic Management a fee of $25.0 million , $27.6 million and $32.4 million for providing the services under the Services Agreement for the years ended December 31, 2015 , 2014 and 2013 , respectively.

Performance guarantees provided by Seadrill

Seadrill provides performance guarantees in connection with the Company’s drilling contracts, and charges the Company an annual fee of 1% of the guaranteed amount to provide these guarantees. The total amount of such guarantees was $200 million at December 31, 2015 and $250 million at December 31, 2014 . The incurred fee was $2.1 million and $2.5 million or the years ended December 31, 2015 and 2014 respectively. In addition, the Company has agreed to reimburse Seadrill for all claims made against Seadrill under the performance guarantees.

Transactions with Frontline

Management services

We receive corporate secretarial and certain other administrative services applicable to the jurisdiction of Bermuda from Frontline Management (Bermuda) Ltd. The fee was $1.2 million , $1.3 million and $0.1 million for the years ended December 31, 2015 , 2014 and 2013 respectively. Frontline Management (Bermuda) Ltd. is a wholly owned subsidiary of Frontline Ltd., a company in which Hemen, Seadrill's principal shareholder, is a large shareholder.

Transactions with Seatankers

Management services

We receive corporate management services through Seatankers Management Norway AS, which is an affiliated company of Hemen, Seadrill's principal shareholder. The fee was $0.2 million , nil and nil for the years ended December 31, 2015 , 2014 and 2013 respectively.

Significant transactions with Ship Finance

Sale and leaseback agreement

In June 2013, we entered into sale and leaseback agreement with Ship Finance for the newbuilding jack-up rig, the West Linus , for total consideration of $600 million . We received $195 million upon signing of the agreement and the remaining balance of the purchase price was paid on the delivery of the rig. The West Linus is chartered back to us on a bareboat charter for a period of 15 years , pursuant to which we have been granted four purchase options. Ship Finance has an option to sell the rig back to us at the end of the charter period. The West Linus was delivered from the yard in February 2014. As of December 31, 2015 , we report the West Linus under "Drilling Units" in our balance sheet. Please see Note 24 to the Consolidated Financial Statements included herein for more information.

Unsecured Loan

Ship Finance granted the VIE company, SFL Linus Ltd., an unsecured loan of $195 million on June 28, 2013 to be repaid at the earlier of June 30, 2029 or date of sale of the West Linus rig. While the loan did not initially bear interest, Ship Finance reserved the right to charge interest after the rig is delivered from the yard. Commencing in February 2014, the loan bore interest of 4.5% per annum. SFL Linus repaid $70 million on this facility during the first quarter in 2014 and the outstanding balance at December 31, 2015 is $ 125 million ( December 31, 2014 : $125.0 million ). The proceeds of this loan were used to finance the acquisition of the West Linus .

$475 million Secured Credit Facility

On October 17, 2013, SFL Linus Ltd. entered into a $475 million secured term loan and revolving credit facility with a syndicate of banks to fund the acquisition of West Linus , which was pledged as security thereunder. The facility bears interest at LIBOR plus a margin of 2.75% and is repayable over a term of five years . The outstanding balance at December 31, 2015 was $354.0 million ( December 31, 2014 : $451.3 million ). In February 2015, this facility was amended, such that Seadrill provides a guarantee for the facility in exchange for amendments to the covenant package, principally replacing the Company's financial covenants with financial covenants within Seadrill's secured credit facilities. The guarantee fee charged by Seadrill is 0.3% per annum of the outstanding principal.

52

---

Transactions with Archer

Engineering Services

We receive certain technical engineering services from certain subsidiaries of Archer Limited. The charged amount was $1.9 million , $1.0 million and $4.0 million for the years ended December 31, 2015 , 2014 and 2013 , respectively. Archer Limited. is a company in which Seadrill, our principal shareholder, is a large shareholder.

C.    Interests of experts and counsel.

Not applicable.

ITEM 8.    FINANCIAL INFORMATION

A.    Consolidated Statements and Other Financial Information

See “Item 18. Financial Statements.”

Legal Proceedings

The Company is a party, as plaintiff or defendant, to some lawsuits in various jurisdictions for demurrage, damages, off-hire and other claims and commercial disputes arising from the construction or operation of its drilling units, in the ordinary course of business or in connection with its acquisition activities.  Other than as noted below the Company believes that the resolution of such claims will not have a material adverse effect on the Company's operations or financial condition either individually or in the aggregate. The Company's best estimate of the outcome of the various disputes has been reflected in the financial statements of the Company as of December 31, 2015 which is not material except as otherwise disclosed below.

In December 2014, a purported shareholder class action lawsuit, Fuchs et al. v. Seadrill Limited et al. , No. 14-cv-9642 (LGS)(KNF), was filed in U.S. District Court for the Southern District of New York, alleging, among other things, that Seadrill and certain of its executives made materially false and misleading statements in connection with the payment of dividends. In January 2015, a second purported shareholder class action lawsuit, Heron v. Seadrill Limited et al. , No. 15-cv-0429 (LGS)(KNF), was filed in the same court on similar grounds. In March 2015, a third purported shareholder class action lawsuit, Glow v. Seadrill Limited et al. , No. 15-cv-1770 (LGS)(KNF), was filed in the same court on similar grounds. On March 24, 2015, the court consolidated these complaints into a single action. On June 23, 2015 the court appointed co-lead plaintiffs and co-lead counsel and ordered the co-lead plaintiffs to file a single consolidated amended by complaint by July 23, 2015.

The amended complaint was filed on July 23, 2015 including North Atlantic Drilling as a defendant. It alleges, among other things, that Seadrill Limited, North Atlantic Drilling and certain of our and its executives made materially false and misleading statements in connection with the payment of dividends, the failure to disclose the risks to the Rosneft transaction as a result of various enacted government sanctions and the inclusion in backlog of $4.1 billion attributable to the Rosneft transaction.

Defendants filed their Motion to Dismiss the Complaint on October 13, 2015. The plaintiffs, in turn, filed their Opposition to the Motion to Dismiss on November 12, 2015 and the defendants filed their Reply Brief on December 4, 2015. Although we intend to vigorously defend this action, we cannot predict the outcome of this case, nor can we estimate the amount of any possible loss. Accordingly, no loss contingency has been recognized in the Company's financial statements.

In addition, the Company has received voluntary requests for information from the Commission concerning, among other things, statements in connection with its payment of dividends, inclusion of contracts in the Company's backlog and its contracts with Rosneft.

Other Matters

North Atlantic Drilling, and all other offshore contractors that are members of the Norwegian Shipowners’ Association, lost a Norwegian court case in July 2015 concerning the pension rights of night shift compensation for offshore workers. The case has been appealed to the Supreme Court of Norway by the members of the Norwegian Shipowners’ Association, and the hearings are expected to be held in June 2016. Due to the uncertainty of the appeal we cannot predict the outcome of this case, nor can we estimate the amount of any possible loss. Accordingly, no loss contingency has been recognized within the Company's financial statements as at December 31, 2015.

In February 2016, the Company was notified of customer claims that are potentially material to our financial statements. After an initial assessment including advice from external counsel, the Company fully refutes the validity of these claims and will take appropriate actions related to our position. The client has withheld amounts from invoice payments due in the first quarter of 2016, which total $36.2 million . No provision has been recognized in relation to these claims.

53

---

Dividend Policy

Generally, under our Bye-laws, our Board of Directors may declare cash dividends or distributions out of retained earnings and contributed surplus and may also pay a fixed cash dividend biannually or on other dates. However, our Board previously suspended the payment of dividends in the third quarter of 2014. Additionally, in May 2015, as part of the amendments to the covenants contained in Seadrill's senior secured credit facilities, we are restricted from making dividend distributions during the waiver period until January 1, 2017. We cannot assure you when we will resume paying dividends, if at all. Any dividends declared will be in the sole discretion of the Board of Directors and will depend upon earnings, restrictions in our debt agreements, market prospects, current capital expenditure programs and investment opportunities, the provisions of Bermuda law affecting the payment of distributions to shareholders and other factors. Under Bermuda law, the Board of Directors has no discretion to declare or pay a dividend if there are reasonable grounds for believing that (a) the company is, or would after the payment be, unable to pay its liabilities as they become due; or (b) the realizable value of the company’s assets would thereby be less than its liabilities.

Separately, since we are a holding company with no material assets other than the shares of our subsidiaries through which we conduct our operations, our ability to pay dividends will depend on our subsidiaries’ distributing to us their earnings and cash flows.

We have paid the following dividends per share since our inception in the first quarter of 2011 in respect of the periods set forth below:

Fourth quarter 2015	$	—
Third quarter 2015	$	—
Second quarter 2015	$	—
First quarter 2015	$	—
Fourth quarter 2014	$	—
Third quarter 2014	$	—
Second quarter 2014	$	0.240
First quarter 2014	$	0.240
Fourth quarter 2013	$	0.230
Third quarter 2013	$	0.225
Second quarter 2013	$	0.225
First quarter 2013	$	0.225

Our ability to pay dividends is also subject to our ability to satisfy financial covenants contained in our financing arrangements. See “Item 5. Operating and Financial Review and Prospects—B. Liquidity and Capital Resources.”

B.    Significant Changes

There have been no significant changes to our Consolidated Financial Statements included in this Annual Report, other than as described in “ Note 26 –Subsequent Events” to our Consolidated Financial Statements.

ITEM 9.    OFFER AND THE LISTING

A.    Offer and Listing Details

Our common shares have traded on the Norwegian OTC List since February 24, 2011 and on the NYSE, since January 29, 2014, under the symbol “NADL.”

The following tables set forth the high and low prices for our common shares as reported on the Norwegian OTC List for the periods listed below. Share prices are presented in U.S. dollars per common share based on the Bloomberg Composite Rate on each day of measurement. On March 31, 2016 , the exchange rate between the Norwegian kroner and the U.S. dollar was NOK8.29 to one U.S. dollar based on the Bloomberg Composite Rate in effect on that date.

On December 31, 2015, our shareholders, in a special general meeting, approved a capital reorganization including a 1-for- 10 reverse stock split of our issued and outstanding common shares and reducing par value from $5.00 to $0.10 . The high and low prices presented as at December 30, 2015 and prior to this have been re-presented to reflect the change from the 1-for- 10 reverse stock split.

54

---

The following table sets forth the fiscal years high and low prices of our common shares since they began trading on the Norwegian OTC list in February 2011 and on the NYSE in January 2014.

	NYSE				Norwegian OTC List
	High (US$)		Low (US$)		High (NOK)		Low (NOK)
For the Fiscal Year Ended
December 31, 2011 (1)	—		—		550.00		362.50
December 31, 2012	—		—		610.00		435.00
December 31, 2013	—		—		605.00		480.00
December 31, 2014 (2)	115.00		13.10		670.00		95.00
December 31, 2015	23.70		2.10		200.00		15.00

(1)	The high and low prices presented for the fiscal year ended December 31, 2011 for OTC listings are during the period from February 24, 2011 through and including December 31, 2011.

(2)	The high and low prices presented for the fiscal year ended December 31, 2014 for NYSE listings are during the period from January 28, 2014 though and including December 31, 2014.

The following table sets forth, for each full financial quarter for the two most fiscal years, the high and low prices of our common shares trading on the Norwegian OTC list and NYSE.

	NYSE				Norwegian OTC List
	High (US$)		Low (US$)		High (NOK)		Low (NOK)
For the Quarter ended
March 31, 2014 (3)	92.50		80.10		577.50		470.00
June 30, 2014	115.00		81.40		650.00		490.00
September 30, 2014	111.30		62.20		670.00		400.00
December 31, 2014	67.40		13.10		420.00		95.00
March 31, 2015	23.70		11.20		200.00		97.00
June 30, 2015	17.90		11.00		126.00		80.00
September 30, 2015	12.60		11.00		100.00		62.00
December 31, 2015	10.40		2.10		80.00		15.00
March 31, 2016	4.36		1.36		12.00		11.00

(3)	The high and low prices of our common shares on the NYSE are during the period from January 29, 2014 through and including March 31, 2014.

The following table sets forth, for the six most recent months, the high and low prices of our common shares trading on the Norwegian OTC list and NYSE:

	NYSE				Norwegian OTC List
	High (US$)		Low (US$)		High (NOK)		Low (NOK)
For the Month
October 2015	10.40		7.24		80.00		61.70
November 2015	9.30		4.50		80.00		60.00
December 2015	5.50		2.10		80.00		15.00
January 2016	2.67		1.36		12.00		11.00
February 2016 (4)	1.96		1.47		—		—
March 2016 (4)	4.36		1.73		—		—
April 2016 (5)	3.77		2.50		11.00		11.00

(4)	No trades on the Norwegian OTC were recorded as executed for the months of February and March 2016.

(5)	The high and low prices of our common shares on the NYSE are during the period from April 1, 2016 through and including April 27, 2016 .

B.    Plan of Distribution

Not applicable

55

---

C.    Markets

Our common shares have traded on the Norwegian OTC List since February 24, 2011 and on the NYSE since January 29, 2014, under the symbol “NADL.”

D.    Selling Shareholders

Not applicable.

E.    Dilution

Not applicable.

F.    Expenses of the Issue

Not applicable.

ITEM 10.    ADDITIONAL INFORMATION

A.    Share capital

Not applicable.

B.    Memorandum and Articles of Association

The following is a description of the material terms of our Memorandum of Association and Bye-laws currently in effect. Because the following is a summary, it does not contain all of the information that you may find useful. For more complete information, see our Memorandum of Association and Bye-laws, copies of which are attached as exhibits 3.1 and 3.3, respectively, to the Registration Statement on Form F-1 (Registration No. 333-185394), declared effective by the Commission on January 28, 2014, and are hereby incorporated by reference into this Annual Report.

Purpose

Our purpose, as stated in our Memorandum of Association, is to engage in any lawful act or activity for which companies may be organized under the Companies Act.

Authorized Capitalization

At our Special General Meeting of Shareholders held on December 28, 2015, our shareholders approved a resolution to effect a capital reorganization. As part of this capital reorganization, we effectuated a one-for-ten reverse stock split of our issued and outstanding common shares and reduced the par value per share from $5.00 to $0.10. It was also resolved that our issued and paid-up share capital be reduced, with effect from December 31, 2015, from $1,217,582,550.00 to $2,435,165.00, by cancelling the paid-up capital of $49.90 on each of the common shares in issue so that each of the 24,351,651 shares of par value $50.00 shall have a par value of $0.10. It was also resolved that our authorized share capital be reduced from $2,000,000,000 to $10,000,000, divided into 100,000,000 shares of par value $0.10 each. Currently, there are 24,351,651shares issued and outstanding.

Common Shares

Shareholder Rights

Shareholders are entitled to one vote for each share held of record on all matters submitted to a vote of our shareholders. Holders of common shares are entitled to receive, ratably, all dividends, if and when declared by our board of directors, out of funds legally available for dividends, subject to any preferred dividend right of holders of any preference shares. Holders of common shares do not have pre-emptive, subscription, redemption, conversion or sinking fund rights, and do not have any cumulative voting rights. The rights, preferences and privileges of holders of our common shares are subject to the rights of the holders of any preferred shares which we may issue in the future. Directors to be elected by shareholders require a simple majority of votes cast at a meeting at which a quorum is present. For all other matters, unless a different majority is required by law or our Bye-laws, resolutions to be approved by shareholders require approval by a simple majority of votes cast at a meeting at which a quorum is present.

Upon liquidation, dissolution or winding up of the Company, under Bermuda law, shareholders will be entitled to receive, ratably, our net assets available after the payment of all our debts and liabilities and any preference amount owed to any preference shareholders.

Other Rights

Special rights attaching to any class of our shares may be altered or abrogated with the consent, in writing, of not less than 75% of the issued shares of that class, or with the sanction of a resolution passed at a separate general meeting of the holders of such shares voting in person or by proxy.

Directors

56

---

Our Bye-laws currently provide that the number of directors shall be such number not less than two, or as the shareholders by ordinary resolution may from time to time determine. At the 2013 annual general meeting held on September 20, 2013, our shareholders set the maximum number of directors to eight. Our board of directors currently consists of six members. Directors shall serve until re-elected or their successors are appointed at the next annual general meeting of shareholders.

Under the Companies Act, subject to a company’s bye-laws, the shareholders of a company may, at a special general meeting called for that purpose, remove any director. Any director whose removal is to be considered at such a special general meeting is entitled to receive not less than 14 days’ notice and shall be entitled to be heard at the meeting. A vacancy created by the removal of a director at a special general meeting may be filled at that meeting by the election of another director or in the absence of such election, by the other directors.

Shareholder meetings

Under our Bye-laws, annual meetings of shareholders will be held at such times and places as our board of directors shall designate each calendar year. Special meetings of shareholders may be called by our board of directors at any time and, pursuant to Bermuda law, special meetings must be called at the request of shareholders holding at least 10% of our paid-up share capital carrying the right to vote at general meetings. Under our Bye-laws, at least five days’ notice of an annual meeting or any special meeting must be given to each shareholder entitled to vote at that meeting. Under Bermuda law, accidental failure to give notice will not invalidate proceedings at a meeting. Our board of directors may set a record date at any time before or after any date on which such notice is dispatched.

Dissenters’ Rights of Appraisal

Under Bermuda law, in the event of an amalgamation or merger of a Bermuda company with another company or corporation, a shareholder of the Bermuda company who did not vote in favor of the amalgamation and is not satisfied that fair value has been offered for such shareholder’s shares may, within one month of notice of the shareholders meeting, apply to the Supreme Court of Bermuda to appraise the fair value of those shares.

Shareholders’ Derivative Actions

Class actions and derivative actions are generally not available to shareholders under Bermuda law. Bermuda courts, however, would ordinarily be expected to permit a shareholder to commence an action in the name of a company to remedy a wrong to the company where the act complained of is alleged, to be beyond the corporate power of the company, or illegal, or would result in the violation of the company’s memorandum of association or bye-laws. Furthermore, consideration would be given by a Bermuda court to acts that are alleged to constitute a fraud against the minority shareholders or, for instance, where an act requires the approval of a greater percentage of the company’s shareholders than that which actually approved it. However, generally a derivative action will not be permitted where there is an alternative action available that would provide an adequate remedy. Any property or damages recovered by derivative action go to the company, not to the plaintiff shareholders. When the affairs of a company are being conducted in a manner which is oppressive or prejudicial to the interests of some part of the shareholders, one or more shareholders may apply to the Supreme Court of Bermuda, which may make such order as it sees fit, including an order regulating the conduct of the company’s affairs in the future or ordering the purchase of the shares of any shareholders by other shareholders or by the company or that the company be wound up.

A statutory right of action is conferred on subscribers to shares of a Bermuda company against persons (including directors and officers) responsible for the issue of a prospectus in respect of damage suffered by reason of an untrue statement contained in the prospectus, but this confers no right of action against the Bermuda company itself. In addition, subject to any limitations that may be contained in the company’s bye-laws a shareholder may bring a derivative action on behalf of the company to enforce a right of the company (as opposed to a right of its shareholders) against its officers (including directors) for breach of their statutory and fiduciary duty to act honestly and in good faith with a view to the best interests of the company.

Our Bye-laws contain provisions whereby each shareholder agrees that the liability of our officers shall be limited, and further agrees to waive any claim such shareholder may have, whether individually or derivatively, against our officers in respect of the officer’s performance of his or her duties, and to indemnify and hold harmless its officers in respect of any liability attaching to such officer incurred by him or her as an officer of the Company. The restrictions on liability, the indemnity and the waiver do not extend to any liability of an officer for fraud or dishonesty.

Limitations on Director Liability and Indemnification of Directors and Officers

Bermuda law permits the bye-laws of a Bermuda company to contain provisions excluding personal liability of a director, alternate director, officer, member of a committee authorized under the company’s bye-laws, resident representative or their respective heirs, executors or administrators to the company for any loss arising or liability attaching to him by virtue of any rule of law in respect of any negligence, default, breach of duty or breach of trust of which the officer or person may be guilty. Bermuda law also grants companies the power, generally, to indemnify directors, alternate directors and officers of the company and any member of a committee authorized under the company’s bye-laws, resident representatives or their respective heirs, executors or administrators if any such person was or is a party, or threatened to be made a party, to a threatened, pending or completed action, suit or proceeding by reason of the fact that he or she is or was a director, alternate director or officer of the company or member of a committee authorized under the company’s bye-laws, resident representative or their respective heirs, executors or administrators or was serving in a similar capacity for another entity at the company’s request.

Our Bye-laws provide that our current directors, officers, resident representative and members of our board committees shall be indemnified out of the funds of the Company from and against all civil liabilities, loss, damage or expense incurred or suffered by him or her as such director, officer, resident representative or committee member, and the indemnity extends to any person acting as a director, officer, resident representative or committee member

57

---

of the Company, in the reasonable belief that he or she has been so appointed or elected notwithstanding any defect in such appointment or election. Such indemnity shall not extend to any matter which would render it void pursuant to the Companies Act.

C.    Material contracts.

Attached as exhibits to this annual report are the contracts we consider to be both material and outside the ordinary course of business for the two-year period immediately preceding the date of this annual report. Please see “Item 5. Operating and Financial Review and Prospects—B. Liquidity and Capital Resources” and “Item 7. Major Shareholders and Related Party Transactions—B. Related Party Transactions” for a discussion of these agreements.

Other than as set forth above, there were no material contracts, other than contracts entered into in the ordinary course of business to which we were a party during the two-year period immediately preceding the date of this Annual Report.

D.    Exchange controls.

The Bermuda Monetary Authority, or the BMA, must give permission for all issuances and transfers of securities of a Bermuda exempted company like ours, unless the proposed transaction is exempted by the BMA’s written general permissions. We have obtained general permission from the BMA to issue any unissued common shares and for the free transferability of our common shares as long as our common shares are listed on an “appointed stock exchange.” The New York Stock Exchange is an “appointed stock exchange and our common shares are freely transferable among persons who are residents and non-residents of Bermuda.

Although we are incorporated in Bermuda, we are classified as a non-resident of Bermuda for exchange control purposes by the BMA. Other than transferring Bermuda Dollars out of Bermuda, there are no restrictions on our ability to transfer funds into and out of Bermuda or to pay dividends in currency other than Bermuda Dollars to U.S. residents (or other non-residents of Bermuda) who are holders of our common shares.

In accordance with Bermuda law, share certificates may be issued only in the names of corporations, individuals or legal persons. In the case of an applicant acting in a special capacity (for example, as an executor or trustee), certificates may, at the request of the applicant, record the capacity in which the applicant is acting. Notwithstanding the recording of any such special capacity, we are not bound to investigate or incur any responsibility in respect of the proper administration of any such estate or trust.

We will take no notice of any trust applicable to any of our shares or other securities whether or not we had notice of such trust.

E.      Taxation

The following is a discussion of the material Bermuda and U.S. federal income tax consequences to our Company and to a “U.S. Holder” and a “Non-U.S. Holder,” as each term is defined below. This discussion does not purport to deal with the tax consequences of owning common stock to all categories of investors, some of which, such as dealers in securities, investors whose functional currency is not the U.S. dollar and investors that own, actually or under applicable constructive ownership rules, 10% or more of our common stock, may be subject to special rules. This discussion deals only with shareholders who own the common stock as a capital asset. Moreover, this discussion is based upon laws, regulations and other authorities in effect as of the date hereof, all of which are subject to change, possibly with retroactive effect. You are encouraged to consult your own tax advisors concerning the overall tax consequences arising in your own particular situation under U.S. federal, state, local and foreign law of the ownership of shares of our common stock.

Bermuda and Other Non-United States Tax Considerations

As of the date of this Annual Report, whilst North Atlantic Drilling is resident in Bermuda, we are not subject to taxation under the laws of Bermuda. Distributions we receive from our subsidiaries also are not subject to any Bermuda tax. As of the date of this Annual Report, there is no Bermuda income, corporation or profits tax, withholding tax, capital gains tax, capital transfer tax, or estate duty or inheritance tax payable by non-residents of Bermuda in respect of capital gains realized on a disposition of our common stock or in respect of distributions they receive from us with respect to our common stock. This discussion does not, however, apply to the taxation of persons ordinarily resident in Bermuda. Bermuda shareholders should consult their own tax advisors regarding possible Bermuda taxes with respect to dispositions of, and distributions on, our common stock. We have received from the Minister of Finance under The Exempted Undertaking Tax Protection Act 1966, as amended, an assurance that, in the event that Bermuda enacts legislation imposing tax computed on profits, income, any capital asset, gain or appreciation, or any tax in the nature of estate duty or inheritance, the imposition of any such tax shall not be applicable to us or to any of our operations or shares, debentures or other obligations, until March 31, 2035. This assurance is subject to the proviso that it is not to be construed to prevent the application of any tax or duty to such persons as are ordinarily resident in Bermuda or to prevent the application of any tax payable in accordance with the provisions of the Land Tax Act 1967. The assurance does not exempt us from paying import duty on goods imported into Bermuda. In addition, all entities employing individuals in Bermuda are required to pay a payroll tax and there are other sundry taxes payable, directly or indirectly, to the Bermuda government. We and our subsidiaries incorporated in Bermuda pay annual government fees to the Bermuda government. Bermuda currently has no tax treaties in place with other countries in relation to double-taxation or for the withholding of tax for foreign tax authorities.

United States Federal Income Tax Considerations

In the opinion of Seward & Kissel LLP, our United States counsel, the following are the material United States federal income tax consequences to U.S. Holders and Non-U.S. Holders, each as defined below, of the ownership of our common shares. This discussion does not purport to deal with the tax consequences of owning common shares to all categories of investors, some of which, such as banks, insurance companies, real estate investment trusts, regulated investment companies, grantor trusts, tax-exempt organizations, dealers in securities or currencies, traders in securities that elect the mark-to-market method of accounting for their securities, investors whose functional currency is not the United States dollar, investors that are or own our common shares through partnerships or other pass-through entitles, investors that own, actually or under applicable constructive ownership rules, 10 percent or more of our common shares, persons that will hold the common shares as part of a hedging transaction, “straddle” or “conversion transaction,”

58

---

persons who are deemed to sell the common shares under constructive sale rules and persons who are liable for the alternative minimum tax may be subject to special rules. The following discussion of United States federal income tax matters is based on the United States Internal Revenue Code of 1986, as amended, or the Code, judicial decisions, administrative pronouncements, and existing and proposed regulations issued by the United States Department of the Treasury, or the Treasury Regulations, all of which are subject to change, possibly with retroactive effect. This discussion deals only with holders who hold the common shares as a capital asset. The discussion below is based, in part, on the description of our business as described herein and assumes that we conduct our business as described herein. Unless otherwise noted, references in the following discussion to the “Company,” “we” and “us” are to North Atlantic Drilling Ltd. and its subsidiaries on a consolidated basis.

United States Federal Income Taxation of U.S. Holders

As used herein, the term “U.S. Holder” means a beneficial owner of common shares that is a United States citizen or resident, United States corporation or other United States entity taxable as a corporation, an estate the income of which is subject to United States federal income taxation regardless of its source, or a trust if (i) a court within the United States is able to exercise primary supervision over the administration of the trust and one or more United States persons have the authority to control all substantial decisions of the trust or (ii) the trust has a valid election in effect to be treated as a United States person for United States federal income tax purposes.

If a partnership holds our common shares, the tax treatment of a partner will generally depend upon the status of the partner and upon the activities of the partnership. If you are a partner in a partnership holding our common shares, you are encouraged to consult your tax advisor.

Distributions

Subject to the discussion of passive foreign investment companies below, any distributions made by us with respect to our common shares to a U.S. Holder will generally constitute dividends, which may be taxable as ordinary income or “qualified dividend income” as described in more detail below, to the extent of our current and accumulated earnings and profits, as determined under United States federal income tax principles. Distributions in excess of our earnings and profits will be treated first as a nontaxable return of capital to the extent of the U.S. Holder’s tax basis in the holder’s common shares on a dollar-for-dollar basis and thereafter as capital gain. Because we are not a United States corporation, U.S. Holders that are corporations will not be entitled to claim a dividends received deduction with respect to any distributions they receive from us. Dividends paid with respect to our common shares will generally be treated as “passive category income” or, in the case of certain types of U.S. Holders, “general category income” for purposes of computing allowable foreign tax credits for United States foreign tax credit purposes.

Dividends paid on our common shares to a U.S. Holder who is an individual, trust or estate (a “U.S. Non-Corporate Holder”) will generally be treated as “qualified dividend income” that is taxable to such U.S. Non-Corporate Holders at preferential tax rates provided that (1) the common shares are readily tradable on an established securities market in the United States (such as the New York Stock Exchange, on which our common shares are listed); (2) we are not a passive foreign investment company for the taxable year during which the dividend is paid or the immediately preceding taxable year (as discussed below); (3) the U.S. Non-Corporate Holder has owned the common shares for more than 60 days in the 121-day period beginning 60 days before the date on which the common shares become ex-dividend (and has not entered into certain risk limiting transactions with respect to such common share); and (4) the U.S. Non-Corporate Holder is not under an obligation (whether pursuant to a short sale or otherwise) to make related payments with respect to positions in substantially similar related property. There is no assurance that any dividends paid on our common shares will be eligible for these preferential tax rates in the hands of a U.S. Non-Corporate Holder.

Special rules may apply to any “extraordinary dividend” generally, a dividend paid by us in an amount which is equal to or in excess of ten percent of a U.S. Non-Corporate Holder’s adjusted tax basis (or fair market value in certain circumstances) in a share of common shares paid by us. In addition, extraordinary dividends include dividends received within a one year period that, in the aggregate, equal or exceed 20% of a U.S. Non-Corporate Holder’s adjusted tax basis (or fair market value in certain circumstances). If we pay an “extraordinary dividend” on our common shares that is treated as “qualified dividend income,” then any loss derived by a U.S. Non-Corporate Holder from the sale or exchange of such common shares will be treated as long-term capital loss to the extent of such dividend.

Sale, Exchange or other Disposition of Common Shares

Subject to the discussion of passive foreign investment companies below, a U.S. Holder generally will recognize taxable gain or loss upon a sale, exchange or other disposition of our common shares in an amount equal to the difference between the amount realized by the U.S. Holder from such sale, exchange or other disposition and the U.S. Holder’s tax basis in such shares The U.S. Holder’s initial tax basis in its shares generally will be the U.S. Holder’s purchase price for the shares and that tax basis will be reduced (but no below zero) by the amount of any distributions on the shares that are treated as non-taxable returns of capital (as discussed above under “—United States Federal Income Taxation of U.S. Holders-Distributions”). Such gain or loss will be treated as long-term capital gain or loss if the U.S. Holder’s holding period is greater than one year at the time of the sale, exchange or other disposition. Such capital gain or loss will generally be treated as United States source income or loss, as applicable, for United States foreign tax credit purposes. A U.S. Holder’s ability to deduct capital losses is subject to certain limitations.

3.8% Tax on Net Investment Income

Certain U.S Holders, including individuals, estates and trusts, will be subject to an additional 3.8% tax on the lesser of (1) the U.S. Holder’s net investment income for the taxable year and (2) the excess of the U.S. Holder’s modified adjusted gross income for the taxable year over a certain threshold (which in the case of individuals is between $125,000 and $250,000). A U.S. Holder that is an estate or a trust will generally be subject to a 3.8% tax on the lesser of (1) the U.S. Holder’s undistributed net investment income for the taxable year and (2) the excess of the U.S. Holder’s adjusted gross income for the taxable year over the dollar amount at which the highest income tax bracket applicable to an estate or trust begins for the taxable year. A U.S.

59

---

Holder’s net investment income will generally include distributions made by us which constitute a dividend for U.S. federal income tax purposes and gain realized from the sale, exchange or other disposition of our shares. This tax is in addition to any income taxes due on such investment income.

If you are a U.S. Holder that is an individual, estate or trust, you are encouraged to consult your tax advisors regarding the applicability of the 3.8% tax on net investment income to the ownership and disposition of our common shares.

Passive Foreign Investment Company

Special United States federal income tax rules apply to a U.S. Holder that holds stock in a foreign corporation classified as a passive foreign investment company, or PFIC for United States federal income tax purposes. In general, a foreign corporation will be treated as a PFIC with respect to a United States shareholder in such foreign corporation, if, for any taxable year in which such shareholder holds stock in such foreign corporation, either:

•	at least 75 percent of the corporation’s gross income for such taxable year consists of passive income (e.g., dividends, interest, capital gains and rents derived other than in the active conduct of a rental business); or

•	at least 50 percent of the average value of the assets held by the corporation during such taxable year produce, or are held for the production of, passive income.

For purposes of determining whether a foreign corporation is a PFIC, it will be treated as earning and owning its proportionate share of the income and assets, respectively, of any of its subsidiary corporations in which it owns at least 25 percent of the value of the subsidiary’s stock.

Income earned by a foreign corporation in connection with the performance of services would not constitute passive income. By contrast, rental income would generally constitute “passive income” unless the foreign corporation is treated under specific rules as deriving its rental income in the active conduct of a trade or business or receiving the rental income from a related party.

Based on the current and anticipated valuation of our assets, including goodwill, and composition of our income and assets, we intend to take the position that, and our counsel Seward & Kissel LLP is of the opinion that, we will not be treated as a PFIC for U.S. federal income tax purposes for our current taxable year or in the foreseeable future. This opinion is based and its accuracy is conditioned on representations, valuations and projections provided by us regarding our assets and income to our counsel. While we believe these representations, valuations and projections to be accurate, no assurance can be given that they will continue to be accurate. Moreover, we have not sought, and we do not expect to seek, a ruling from the Internal Revenue Service, or the IRS, on this matter. As a result, the IRS or a court could disagree with our position. No assurance can be given that this result will not occur. In addition, although we intend to conduct our affairs in a manner to avoid, to the extent possible, being classified as a PFIC with respect to any taxable year, we cannot assure you that the nature of our operations will not change in the future, or that we can avoid PFIC status in the future.

As discussed more fully below, if we were to be treated as a PFIC for any taxable year, a U.S. Holder would be subject to different taxation rules depending on whether the U.S. Holder makes an election to treat us as a “Qualified Electing Fund,” which election we refer to as a “QEF election.” As an alternative to making a QEF election, a U.S. Holder should be able to make a “mark-to-market” election with respect to our common shares, as discussed below.

If we were to be treated as a PFIC for any taxable year, a U.S. Holder would be required to file IRS Form 8621 with the IRS for that year with respect to such U.S. Holder’s common shares.

Taxation of U.S. Holders Making a Timely QEF Election

If a U.S. Holder makes a timely QEF election, which U.S. Holder we refer to as an “Electing Holder,” the Electing Holder must report each year for United States federal income tax purposes his pro rata share of our ordinary earnings and our net capital gain, if any, for our taxable year that ends with or within the taxable year of the Electing Holder, regardless of whether or not distributions were received from us by the Electing Holder. The Electing Holder’s adjusted tax basis in the common shares will be increased to reflect taxed but undistributed earnings and profits. Distributions of earnings and profits that had been previously taxed will result in a corresponding reduction in the adjusted tax basis in the common shares and will not be taxed again once distributed. An Electing Holder would generally recognize capital gain or loss on the sale, exchange or other disposition of our common shares. A U.S. Holder would make a QEF election with respect to any year that our company is a PFIC by filing IRS Form 8621 with his United States federal income tax return. If we were aware that we or any of our subsidiaries were to be treated as a PFIC for any taxable year, we would, if possible, provide each U.S. Holder with all necessary information in order to make the QEF election described above. If we were to be treated as a PFIC, a U.S. Holder would be treated as owning his proportionate share of stock in each of our subsidiaries which is treated as a PFIC and such U.S. Holder would need to make a separate QEF election for any such subsidiaries. It should be noted that we may not be able to provide such information if we did not become aware of our status as a PFIC in a timely manner.

Taxation of U.S. Holders Making a “Mark-to-Market” Election

Alternatively, if we were to be treated as a PFIC for any taxable year and, as we anticipate, our shares are treated as “marketable stock,” a U.S. Holder would be allowed to make a “mark-to-market” election with respect to our common shares, provided the U.S. Holder completes and files IRS Form 8621 in accordance with the relevant instructions and related Treasury Regulations. The “mark-to-market” election will not be available for any of our subsidiaries. If that election is made, the U.S. Holder generally would include as ordinary income in each taxable year the excess, if any, of the fair market value of the common shares at the end of the taxable year over such holder’s adjusted tax basis in the common shares. The U.S. Holder would also be permitted an ordinary loss in respect of the excess, if any, of the U.S. Holder’s adjusted tax basis in the common shares over its fair market value at the end of the taxable year, but only to the extent of the net amount previously included in income as a result of the mark-to-market election. A U.S.

60

---

Holder’s tax basis in his common shares would be adjusted to reflect any such income or loss amount. Gain realized on the sale, exchange or other disposition of our common shares would be treated as ordinary income, and any loss realized on the sale, exchange or other disposition of the common shares would be treated as ordinary loss to the extent that such loss does not exceed the net mark-to-market gains previously included in income by the U.S. Holder. It should be noted that the mark-to-market election would likely not be available for any of our subsidiaries which are treated as PFICs.

Taxation of U.S. Holders Not Making a Timely QEF or Mark-to-Market Election

Finally, if we were to be treated as a PFIC for any taxable year, a U.S. Holder who does not make either a QEF election or a “mark-to-market” election for that year, whom we refer to as a “Non-Electing Holder,” would be subject to special rules with respect to (1) any excess distribution (i.e., the portion of any distributions received by the Non-Electing Holder on our common shares in a taxable year in excess of 125 percent of the average annual distributions received by the Non-Electing Holder in the three preceding taxable years, or, if shorter, the Non-Electing Holder’s holding period before the taxable year for the common shares), and (2) any gain realized on the sale, exchange or other disposition of our common shares. Under these special rules:

•	the excess distribution or gain would be allocated ratably over the Non-Electing Holders’ aggregate holding period for the common shares;

•	the amount allocated to the current taxable year and any taxable year before we became a PFIC would be taxed as ordinary income; and

•	the amount allocated to each of the other taxable years would be subject to tax at the highest rate of tax in effect for the applicable class of taxpayer for that year, and an interest charge for the deemed tax deferral benefit would be imposed with respect to the resulting tax attributable to each such other taxable year.

These rules would not apply to a pension or profit sharing trust or other tax-exempt organization that did not borrow funds or otherwise utilize leverage in connection with its acquisition of our common shares. If a Non-Electing Holder who is an individual dies while owning our common shares, such holder’s successor generally would not receive a step-up in tax basis with respect to such shares.

United States Federal Income Taxation of “Non-U.S. Holders”

A beneficial owner of our common shares that is not a U.S. Holder is referred to herein as a “Non-U.S. Holder.”

If a partnership holds our common shares, the tax treatment of a partner will generally depend upon the status of the partner and upon the activities of the partnership. If you are a partner in a partnership holding our common shares, your are encouraged to consult your tax advisor.

Dividends on Common Shares

Non-U.S. Holders generally will not be subject to United States federal income tax or withholding tax on dividends received from us with respect to our common shares, unless that income is effectively connected with the Non-U.S. Holder’s conduct of a trade or business in the United States. If the Non-U.S. Holder is entitled to the benefits of a United States income tax treaty with respect to those dividends, that income may be taxable only if it is also attributable to a permanent establishment maintained by the Non-U.S. Holder in the United States.

Sale, Exchange or Other Disposition of Common Shares

Non-U.S. Holders generally will not be subject to United States federal income tax or withholding tax on any gain realized upon the sale, exchange or other disposition of our common shares, unless:

•	the gain is effectively connected with the Non-U.S. Holder’s conduct of a trade or business in the United States. If the Non-U.S. Holder is entitled to the benefits of an income tax treaty with respect to that gain, that gain may be taxable only if it is also attributable to a permanent establishment maintained by the Non-U.S. Holder in the United States or

•	the Non-U.S. Holder is an individual who is present in the United States for 183 days or more during the taxable year of disposition and other conditions are met.

If the Non-U.S. Holder is engaged in a United States trade or business for United States federal income tax purposes, the income from the common shares, including dividends and the gain from the sale, exchange or other disposition of the common shares that are effectively connected with the conduct of that trade or business will generally be subject to regular United States federal income tax in the same manner as discussed in the previous section relating to the taxation of U.S. Holders. In addition, in the case of a corporate Non-U.S. Holder, its earnings and profits that are attributable to the effectively connected income, subject to certain adjustments, may be subject to an additional branch profits tax at a rate of 30 percent, or at a lower rate as may be specified by an applicable United States income tax treaty.

Backup Withholding and Information Reporting

In general, dividend payments, or other taxable distributions, made within the United States to you will be subject to information reporting requirements. Such payments will also be subject to backup withholding tax if paid to a non-corporate U.S. Holder who:

•	fails to provide an accurate taxpayer identification number;

•	is notified by the IRS that he has failed to report all interest or dividends required to be shown on his federal income tax returns; or

•	in certain circumstances, fails to comply with applicable certification requirements.

Non-U.S. Holders may be required to establish their exemption from information reporting and backup withholding by certifying their status on an applicable IRS Form W-8.

61

---

If a Non-U.S. Holder sells his common shares to or through a United States office of a broker, the payment of the proceeds is subject to both United States backup withholding and information reporting unless the Non-U.S. Holder certifies that he is a non-U.S. person, under penalties of perjury, or otherwise establishes an exemption. If a Non-U.S. Holder sells his common shares through a non-United States office of a non-United States broker and the sales proceeds are paid to the Non-U.S. Holder outside the United States then information reporting and backup withholding generally will not apply to that payment. However, United States information reporting requirements, but not backup withholding, will apply to a payment of sales proceeds, even if that payment is made to a Non-U.S. Holder outside the United States, if the Non-U.S. Holder sells common shares through a non-United States office of a broker that is a United States person or has some other contacts with the United States.

Backup withholding is not an additional tax. Rather, a taxpayer generally may obtain a refund of any amounts withheld under backup withholding rules that exceed the taxpayer’s income tax liability by filing a refund claim with the IRS.

Individuals who are U.S. Holders (and to the extent specified in applicable Treasury Regulations, certain individuals who are Non-U.S. Holders and certain United States entities) who hold “specified foreign financial assets” (as defined in Section 6038D of the Code) are required to file IRS Form 8938 with information relating to the asset for each taxable year in which the aggregate value of all such assets exceeds $75,000 at any time during the taxable year or $50,000 on the last day of the taxable year (or such higher dollar amount as prescribed by applicable Treasury Regulations). Specified foreign financial assets would include, among other assets, our common shares, unless the shares are held through an account maintained with a United States financial institution. Substantial penalties apply to any failure to timely file IRS Form 8938, unless the failure is shown to be due to reasonable cause and not due to willful neglect. Additionally, in the event an individual U.S. Holder (and to the extent specified in applicable Treasury Regulations, an individual Non-U.S. Holder or a United States entity) that is required to file IRS Form 8938 does not file such form, the statute of limitations on the assessment and collection of United States federal income taxes of such holder for the related tax year may not close until three years after the date that the required information is filed. U.S. Holders (including United States entities) and Non-U.S. Holders are encouraged consult their own tax advisors regarding their reporting obligations under this legislation.

Other Tax Considerations

In addition to the tax consequences discussed above, we may be subject to tax in one or more other jurisdictions where we conduct activities. The amount of any such tax imposed upon our operations may be material.

F.    Dividends and paying agents.

Not applicable.

G.    Statement by experts.

Not applicable.

H.    Documents on display.

We are subject to the informational requirements of the U.S. Securities Exchange Act of 1934, as amended, or the Exchange Act. In accordance with these requirements we file reports and other information with the Commission. These materials, including this Annual Report and the accompanying exhibits, may be inspected and copied at the public reference facilities maintained by the Commission at 100 F Street, N.E., Washington, D.C. 20549. You may obtain information on the operation of the public reference room by calling 1 (800) SEC-0330, and you may obtain copies at prescribed rates from the Public Reference Section of the Commission at its principal office in Washington, D.C. 20549. The Commission maintains a website (http://www.sec.gov) that contains reports, proxy and information statements and other information that we and other registrants have filed electronically with the Commission. Our filings are also available on our website at www.nadlcorp.com . This web address is provided as an inactive textual reference only. Information contained on our website does not constitute part of this Annual Report. In addition, documents referred to in this Annual Report may be inspected at our principle executive offices at Par-la-Ville Place, 14 Par-la-Ville Road, Hamilton HM 08, Bermuda.

I.    Subsidiary Information

Not applicable.

ITEM 11.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to various market risks, including foreign currency fluctuations, changes in interest rates and credit risk. Our policy is to hedge our exposure to these risks where possible, within boundaries deemed appropriate by management and the board of directors. We accomplish this by entering into appropriate derivative instruments and contracts to maintain the desired level of risk exposure. Our activities expose us primarily to the financial risks of changes in foreign currency exchange rates and interest rates as described below.

62

---

Interest rate risk

A significant portion of our debt obligations and surplus funds placed with financial institutions are subject to movements in interest rates. It is our policy to obtain the most favorable interest rates available without increasing our foreign currency exposure. Working capital is placed in bank accounts or fixed deposits with reputable financial institutions in order to maximize returns, while providing the Company with the flexibility to meet working capital and capital investments. We have no significant interest bearing assets other than cash and cash equivalents; therefore our income and operating cash flows are substantially independent of changes in market interest rates.

This section should be read in conjunction with Note 22 –Risk management and financial instruments of the Consolidated Financial Statements included herein.

We use interest rate swaps to manage our exposure to interest rate risks. Interest rate swaps are used to convert floating rate debt obligations to a fixed rate in order to achieve an overall desired position of fixed and floating rate debt. The extent to which interest rate swaps are used is determined by reference to our net debt exposure. Most of our interest rate swaps do not qualify for hedge accounting and movements in their fair values are reflected in the statement of operations under "gain/(loss) on derivative financial instruments". Interest rate swap agreements that have a positive fair value are recorded as "Other non-current assets", while swaps with a negative fair value are recorded as "Other current liabilities".

At December 31, 2015 , we had interest rate swap agreements with an outstanding principal amount of $1,300 million ( December 31, 2014 : $1,300 million ), including one contract of $200 million which was entered into in February 2014 with forward start in March 2016 . Interest rate swap contracts have maturity dates between January 2016 and March 2021.

We did not enter into any other new swap agreements, nor change any existing swap agreements, during the year ended December 31, 2015 .

Financial instruments

The following table summarizes the notional amounts and estimated fair values of our financial instruments as of December 31, 2015 ( December 31, 2014 : $39.9 million):

(In millions of U.S. dollars)	Notional amount			Fair value
Interest rate swaps - assets	$	200.0		1.5
Interest rate swaps - liabilities	$	1,100.0		(25.9	)

The fair value of interest rate swaps is the estimated amount that our counterparties would receive or pay to terminate the swap agreements at the reporting date. The valuation technique used to determine the fair value of interest rate swaps approximates the net present value of the swap contracts’ future cash flows.

In addition to the above interest rate swaps, SFL Linus Ltd., our fully-consolidated VIE has executed interest rate cash flow hedges in the form of interest rate swaps. Movements in their fair value are reflected in "Accumulated other comprehensive income (loss)," with their fair value recorded as "Other current assets" or "Other current liabilities." As of December 31, 2015 , the fully-consolidated VIE had entered into interest rate swap agreements with a combined outstanding principal amount of $199.9 million , as compared to $224.0 million in 2014 , at a rate of 1.77% to 2.01% per annum. The swap agreements mature between October and December 2018, and the fair value as of December 31, 2015 was a liability of $2.3 million ( December 31, 2014 : liability of $2.5 million ).

(In millions of U.S. dollars)	Notional amount			Fair value
Interest rate swaps - hedge accounted - liabilities	$	199.9		$	(2.3	)

As of December 31, 2015 we also had outstanding cross currency interest rate swaps with principal amount of $253.5 million ( December 31, 2014 : $253.5 million ) with maturity dates in October 2018 at fixed interest rates of 6.18% per annum. The fair value of our cross currency interest rate swap contracts as of December 31, 2015 ( December 31, 2014 : $13.1 million), was as follows:

(In millions of U.S. dollars)	Notional amount			Fair value
Cross currency swaps - liability	$	253.5		$	(98.6	)

As of December 31, 2015 , our net effective exposure to floating interest rate fluctuations on our outstanding debt was $171.2 million , based on our total net interest bearing debt including related party of $2,449.6 million less $725.0 million of fixed rate loans and bonds, less $1,553.4 million outstanding principal of our floating to fixed interest rate swaps and cross currency swaps. An increase or decrease in short-term interest rates of one percentage point would thus increase or decrease our effective interest expense by approximately $1.7 million on an annual basis as of December 31, 2015 .

63

---

Foreign currency risk management

We have U.S. dollars as our functional currency because the majority of our revenues and cash inflows are denominated in dollars. Accordingly, our reporting currency is also U.S. dollars. We do, however, earn some of our revenue and incur some of our expenses in other currencies (primarily Norwegian Kroner) and there is therefore a risk that currency fluctuations could have an adverse effect on our cash flows.

This section should be read in conjunction with " Note 22 –Risk management and financial instruments" to our Consolidated Financial Statements included herein.

Our foreign currency risk arises from the measurement of debt and other monetary assets and liabilities denominated in foreign currencies converted to U.S. dollars, with the resulting gain or loss recorded as “Other financial items” and the impact of fluctuations in exchange rates on the reported amounts of our revenues and expenses which are contracted in foreign currencies.

As at December 31, 2015 we did not have any outstanding forward currency contracts.

As of December 31, 2015 , we held cash denominated in Norwegian kroner of NOK 465.9 million . A 1% change in the exchange rate between the U.S. dollar and the bought forward currencies would result in an unrealized foreign currency translation or loss of $0.5 million that would be reflected in our consolidated statements of operations on an annual basis as of December 31, 2015 .

Concentration of credit risk

The market for our services is the offshore oil and gas industry, and our customers consist primarily of major integrated oil companies, independent oil and gas producers and government owned oil companies. We perform ongoing credit evaluations of our customers and generally do not require collateral in our business agreements. Reserves for potential credit losses are maintained when necessary.

The following table shows the customers which accounted for more than 10% of the Company’s consolidated revenues:

Contract revenue split by client:		Year ended December 31,
		2015			2014			2013
Statoil		44	%		38	%		57	%
ExxonMobil		25	%		13	%		12	%
Conoco Phillips		18	%		8	%		—	%
Total		13	%		12	%		13	%
Shell		—	%		12	%		14	%
KMNG		—	%		11	%		—	%
Other		—	%		6	%		4	%
Total		100	%		100	%		100	%

We may also face credit related losses in the event that counterparties to our derivative financial instrument contracts do not perform according to the terms of the contract. The credit risk arising from these counterparties relates to unrealized profits from foreign exchange forward contracts and interest rate swaps. We generally do not require collateral for our financial instrument contracts. We do, however, enter into master netting agreements with our counterparties to derivative financial instrument contracts to mitigate our exposure to counterparty credit risks. These agreements provide us with the legal right to discharge all or a portion of amounts owed to a counterparty by offsetting against them any amounts that the counterparty may owe us.

In the opinion of management, our counterparties are creditworthy financial institutions, and we do not expect any significant loss to result from their non-performance. The credit exposure of interest rate swap agreements, currency option contracts and foreign currency contracts is represented by the fair value of contracts with a positive fair value at the end of each period, reduced by the effects of master netting agreements.

ITEM 12.    DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES

A.	DEBT SECURITIES

 

Not applicable.

B.	WARRANTS AND RIGHTS

 

Not applicable.

64

---

C.	OTHER SECURITIES

 

Not applicable.

D.	AMERICAN DEPOSITORY SHARES

 

Not applicable.

65

---

PART II

ITEM 13.    DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES

None.

ITEM 14.    MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS

None.

ITEM 15.    CONTROLS AND PROCEDURES

(a)      Disclosure of controls and procedures.

Management assessed the effectiveness of the design and operation of the Company's disclosure controls and procedures pursuant to Rule 13a-15 (e) of the Exchange Act as of December 31, 2015 . Based upon that evaluation the Principal Executive Officer and Principal Financial Officer concluded that the Company's disclosure controls and procedures are effective as of the evaluation date.

(b)      Management's report on internal control over financial reporting.

The Company's management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15 (f) promulgated under the Exchange Act. Internal control over financial reporting is defined in Rule 13a-15(f) or 15d-15(f) promulgated under the Exchange Act as a process designed by, or under the supervision of, the Company's principal executive and principal financial officers and effected by the Company's Board of Directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles and includes those policies and procedures that:

•	Pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company;

•	Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that the Company's receipts and expenditures are being made only in accordance with authorizations of Company's management and directors; and

•	Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company's assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree or compliance with the policies or procedures may deteriorate.

Management conducted the evaluation of the effectiveness of the internal controls over financial reporting using the control criteria framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, or COSO, published in its report entitled Internal Control- Integrated Framework (2013).

The Company's management with the participation of the Company's Principal Executive Officer and Principal Financial Officer assessed the effectiveness of the design and operation of the Company's internal controls over financial reporting pursuant to Rule 13a-15 of the Exchange Act as of December 31, 2015 . Based upon that evaluation, management, including the Principal Executive Officer and Principal Financial Officer, concluded that the Company's internal controls over financial reporting are effective as of December 31, 2015 .

The effectiveness of the Company's internal control over financial reporting as of December 31, 2015 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.

(c)      Attestation report of the registered public accounting firm.

The independent registered public accounting firm that audited the Consolidated Financial Statements, PricewaterhouseCoopers LLP, has issued an attestation report on the effectiveness of the Company's internal control over financial reporting as of December 31, 2015 , appearing under Item 18, and such report is incorporated herein by reference.

(d)      Changes in internal control over financial reporting.

There were no changes in the Company's internal controls over financial reporting that occurred during the period covered by this annual report that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.

ITEM 16A.    AUDIT COMMITTEE FINANCIAL EXPERT

Our Board of Directors has determined that the sole member of the audit committee, Mrs. Kate Blankenship, is an independent director and is the audit committee financial expert.

66

---

ITEM 16B.    CODE OF ETHICS

We have adopted a code of conduct that applies to all entities controlled by the Company and its employees, directors, officers and agents. A copy of our code of ethics has been filed as an exhibit to our Registration Statement on Form F-1 (Registration No. 333-185394) and is also available on our website at www.nadlcorp.com . This web address is provided as an inactive textual reference only. Information contained on our website does not constitute part of this Annual Report. We will provide any person, free of charge, a copy of our Code of Ethics upon written request to our registered office.

ITEM 16C.    PRINCIPAL ACCOUNTING FEES AND SERVICES

Our principal accountants for the fiscal years ended December 31, 2015 was PricewaterhouseCoopers LLP (UK) and for December 31, 2014 was PricewaterhouseCoopers AS (Norway). The following table sets forth the fees related to audit and other services provided by PricewaterhouseCoopers LLP and PricewaterhouseCoopers AS.

(in U.S. dollars)	2015		2014
Audit fees (a)	644,000		1,457,990
Audit-related fees (b)	—		—
Taxation fees (c)	—		—
All other fees (d)	11,000		—
Total	655,000		1,457,990

a)	Audit Fees

Audit fees represent professional services rendered for the audit of our annual financial statements and services provided by the principal accountant in connection with statutory and regulatory filings or engagements.

b)	Audit-Related Fees

Audit-related fees consist of assurance and related services rendered by the principal accountant related to the performance of the audit or review of our financial statements which have not been reported under Audit fees above.

c)	Taxation Fees

Taxation fees represent fees for professional services rendered by the principal accountant for tax compliance, tax advice and tax planning.

d)	All Other Fees

All other fees include services other than audit fees, audit-related fees and taxation fees set forth above.

e)	Audit Committee’s Pre-Approval Policies and Procedures

Our Board of Directors has adopted pre-approval policies and procedures in compliance with paragraph (c)(7)(i) of Rule 2-01 of Regulation S-X that requires the Board to approve the appointment of our independent auditor before such auditor is engaged, and approve each of the audit and non-audit related services to be provided by such auditor under such engagement by the Company. All services provided by the principal auditor in 2015 and 2014 were approved by the Board pursuant to the pre-approval policy.

ITEM 16D.    EXEMPTIONS FROM LISTING STANDARDS FOR AUDIT COMMITTEES

None.

ITEM 16E.    PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PURCHASES

None.

ITEM 16F.    CHANGE IN REGISTRANT'S CERTIFYING ACCOUNTANT

Effective September 18, 2015 North Atlantic Drilling Ltd. (the “Company”) dismissed PricewaterhouseCoopers AS (“PwC Norway”) as the Company's independent registered public accounting firm, in connection with the relocation of its corporate accounting function to the United Kingdom. The Audit committee of the board of directors (the “Audit committee”) of the Company approved the dismissal of PwC Norway.

The reports of PwC Norway on the consolidated financial statements of the Company for the year ended December 31, 2014 and 2013 did not contain an adverse opinion or disclaimer of opinion and were not qualified or modified as to uncertainty, audit scope, or accounting principles.

67

---

During the years ended December 31, 2014 and 2013 and through September 18, 2015 there were no disagreements with PwC Norway on any matter of accounting principles or practices, financial statement disclosures, or auditing scope or procedure, which such disagreements, if not resolved to the satisfaction of PwC Norway, would have caused PwC Norway to make reference thereto in its reports on the financial statements of the Company for such years. During the years ended December 31, 2014 and 2013, and through the September 18, 2015, there were no “reportable events” as that term is described in paragraphs (A) through (D) of Item 16 F(a)(1)(v) of Form 20-F.

The Company provided PwC Norway with a copy of the disclosure it made in its Report of Foreign Private Issuer on Form 6-K (the “ Report”) dated October 13, 2015, and requested that PwC Norway furnish the Company with a letter addressed to the Securities and Exchange Commission (the “SEC”), pursuant to Item 16F(a)(3) of Form 20-F, stating whether PwC Norway agrees with the statements made by the Company in the Report, and if not, the respects in which PwC Norway does not agree. A copy of PwC Norway’s letter to the SEC dated October 13, 2015 is attached as exhibit to this Annual Report.

On September 18, 2015, in connection with the relocation of the Company’s corporate accounting functions to the United Kingdom, the Audit Committee approved the appointment of PricewaterhouseCoopers LLP (“PwC UK”), effective September 18, 2015, as the Company's new independent registered public accounting firm for the fiscal year ending December 31, 2015.

During the years ended December 31, 2014 and 2013, and through September 18, 2015, neither the Company, nor anyone on its behalf, consulted PwC UK regarding either (i) the application of accounting principles to a specified transaction, either completed or proposed, or the type of audit opinion that might be rendered with respect to the financial statements of the Company; or (ii) any matter that was either the subject of a “disagreement,” as that term is defined in Item 16F(a)(1)(iv) of Form 20-F and the related instructions to item 16F of form 20-F, or a “reportable event”, as that term is described in Item 16F(a)(1)(v) of Form 20-F.

ITEM 16G.    CORPORATE GOVERNANCE

Pursuant to an exception under the NYSE listing standards available to foreign private issuers, we are not required to comply with all of the corporate governance practices followed by U.S. companies under the NYSE listing standards, which are available at  www.nyse.com . Pursuant to Section 303.A.11 of the NYSE Listed Company Manual, we are required to list the significant differences between our corporate governance practices and the NYSE standards applicable to listed U.S. companies. Set forth below is a list of those differences.

•	Independence of Directors .  The NYSE requires that a U.S. listed company maintain a majority of independent directors. As permitted under Bermuda law and our Bye-laws, four of our six members of our Board of Directors are independent according to the NYSE’s standards for independence applicable to a foreign private issuer.

•

Compensation Committee and Nominating/Corporate Governance Committee .  The NYSE requires that a listed U.S. company have a compensation committee and a nominating/corporate governance committee of independent directors and a committee charter specifying the purpose, duties and evaluation procedures of the committee. As permitted under Bermuda law and our Bye-laws, we do not currently have a compensation committee or nominating or corporate governance committee.

•

Executive Sessions .  The NYSE requires that non-management directors meet regularly in executive sessions without management. The NYSE also requires that all independent directors meet in an executive session at least once a year. As permitted under Bermuda law and our Bye-laws, our non-management directors do not regularly hold executive sessions without management and we do not expect them to do so in the future.

•

Audit Committee.  The NYSE requires, among other things, that a listed U.S. company have an audit committee with a minimum of three members. As permitted by Rule 10A-3 under the Exchange Act, our audit committee consists of one independent member of our Board of Directors. Pursuant to our audit committee charter, the audit committee confers with our independent registered public accounting firm and reviews, evaluates and advises the Board of Directors concerning the adequacy of our accounting systems, our financial reporting practices, the maintenance of our books and records and our internal controls. In addition, the audit committee reviews the scope of the audit of our financial statements and results thereof.

•

Corporate Governance Guidelines .  The NYSE requires U.S. companies to adopt and disclose corporate governance guidelines. The guidelines must address, among other things: director qualification standards, director responsibilities, director access to management and independent advisers, director compensation, director orientation and continuing education, management succession and an annual performance evaluation. We are not required to adopt such guidelines under Bermuda law and we have not adopted such guidelines.

We believe that our established corporate governance practices satisfy the NYSE listing standards.

ITEM 16H.    MINE SAFETY DISCLOSURE

Not applicable.

68

---

PART III

ITEM 17.    FINANCIAL STATEMENTS

See “Item 18. Financial Statements.”

ITEM 18.    FINANCIAL STATEMENTS

The financial statements, together with the reports from PricewaterhouseCoopers LLP and PricewaterhouseCoopers AS thereon, beginning on page F-1, are filed as a part of this Annual Report.

69

---

ITEM 19.    EXHIBITS

Exhibit Number	Description
1.1	Memorandum of Association of North Atlantic Drilling Ltd.  (1)
1.2	Amended and Restated Bye-laws of North Atlantic Drilling Ltd. (2)
1.3	Certificate of Deposit of Memorandum of Reduction of Share Capital of North Atlantic Drilling Ltd. dated December 31, 2015, and Certificate of Deposit of Memorandum of Issued Share Capital of North Atlantic Drilling Ltd. dated December 31, 2015.
2.1	Form of Common Stock Certificate (5)
4.1	Equity Compensation Plan (2)
4.2	Restricted Stock Unit Plan (2)
4.3	General Management Agreement between North Atlantic Drilling Ltd. and North Atlantic Management AS (1)
4.4	Services Agreement between North Atlantic Management AS and Seadrill Management AS (1)
4.5	Cooperation Agreement (3)
4.6	$2,000 Million Senior Secured Credit Facility between North Atlantic Drilling Ltd. and a Syndicate of Banks, dated April 15, 2011  (1)
4.7	Amendment to the $2,000 Million Senior Secured Credit Facility between North Atlantic Drilling Ltd. and a Syndicate of Banks, dated April 28, 2016
4.8	$500 Million 7.75% Unsecured Bond (1)
4.9	Seadrill Revolving Credit Facility between North Atlantic Drilling Ltd. and Seadrill Limited, dated March 30, 2012 (1)
4.1	Amendment No. 1 to the Seadrill Revolving Credit Facility between North Atlantic Drilling Ltd. and Seadrill Limited, dated June 28, 2013 (1)
4.11	$195 Million Related Party Loan (2)
4.12	NOK 1,500 Million Senior Unsecured Bond (2)
4.13	Indenture relating to $600 Million 6.25% Senior Unsecured Notes due 2019 (3)
4.14	Framework agreement by and among Rosneft Oil Company, Seadrill Limited and North Atlantic Drilling Ltd., dated August 20, 2014, as amended by the first letter amendment dated November 7, 2014, and the second letter amendment dated April 15, 2015. (4) †
4.15	Framework agreement by and among Rosneft Oil Company, Seadrill Limited and North Atlantic Drilling Ltd., third letter amendment dated June 2015
4.16	Amendment No. 1 to the Agreement for the Construction of the West Rigel,  dated December 2, 2015, by and between Jurong Shipyard Pte. Ltd. and North Atlantic Rigel Ltd., including the Joint Asset Holding Agreement between Jurong Shipyard Pte. Ltd. and North Atlantic Drilling Ltd., included as Appendix 1 thereto †
8.1	List of Subsidiaries of North Atlantic Drilling Ltd.
11.1	Code of Conduct (1)
12.1	Certification of the Principal Executive Officer pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended.
12.2	Certification of the Principal Financial Officer pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended.
13.1	Certification of the Principal Executive Officer pursuant to 18 USC Section 1350, as adopted, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
13.2	Certification of the Principal Financial Officer pursuant to 18 USC Section 1350, as adopted, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
15.1	Copy of Letter from PricewaterhouseCoopers AS to SEC confirming their agreement with statements made by the company concerning their firm in its Form 6-K dated October 13, 2015
101.INS	XBRL Instance Document
101.SCH	XBRL Taxonomy Extension Schema
101.CAL	XBRL Taxonomy Extension Schema Calculation Linkbase
101.DEF	XBRL Taxonomy Extension Definition Linkbase
101.LAB	XBRL Taxonomy Extension Label Linkbase
101.PRE	XBRL Taxonomy Extension Presentation Linkbase

_____________

(1)	Incorporated by reference to the Company’s Registration Statement on Form F-1 (File No. 333-185394), filed with the Commission on December 12, 2012.

(2)	Incorporated by reference to Amendment No. 1 to the Company's Registration Statement on Form F-1 (File No. 333-185394), filed with the Commission on November 8, 2013.

(3)	Incorporated by reference to the Company`s Annual report on Form 20-F, filed with the Commission on April 22, 2014.

(4)	Incorporated by reference to the Company's Annual report on Form 20-F, filed with the Commission on April 22, 2015.

(5)	Incorporated by reference to the Company’s Registration Statement on Form 8-A12B, filed with the Commission on January 4, 2016

†	Certain portions have been omitted pursuant to a confidential treatment request. Omitted information has been filed separately with the Commission.

70

---

SIGNATURES

The registrant hereby certifies that it meets all of the requirements for filing on Form 20-F and that it has duly caused and authorized the undersigned to sign this annual report on its behalf.

NORTH ATLANTIC DRILLING LTD.
(Registrant)
Date: April 28, 2016
	By:	/s/ Alf Ragnar Løvdal
	Name:	Alf Ragnar Løvdal
	Title:	Chief Executive Officer of North Atlantic Management AS (Principal Executive Officer of North Atlantic Drilling Ltd.)

71

---

NORTH ATLANTIC DRILLING LTD.

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

Reports of Independent Registered Public Accounting Firms	F-3
Consolidated Statement of Operations for the years ended December 31, 2015, 2014 and 2013	F-4
Consolidated Statement of Comprehensive Income for the years ended December 31, 2015, 2014 and 2013	F-5
Consolidated Balance Sheet as of December 31, 2015 and 2014	F-6
Consolidated Statement of Cash Flows for the years ended December 31, 2015, 2014 and 2013	F-7
Consolidated Statement of Changes in Equity for the years ended December 31, 2015, 2014 and 2013	F-9
Notes to the Consolidated Financial Statements	F-10

F-1

---

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders of North Atlantic Drilling Limited

In our opinion, the accompanying consolidated balance sheet and the related consolidated statement of operations, of comprehensive income, of cash flows and of changes in equity present fairly, in all material respects, the financial position of North Atlantic Drilling Limited and its subsidiaries at December 31, 2015, and the results of their operations and their cash flows for the year ended December 31, 2015 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company's management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management's Report on Internal Control over Financial Reporting appearing under Item 15(b). Our responsibility is to express opinions on these financial statements and on the Company's internal control over financial reporting based on our integrated audit. We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audit of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP

Uxbridge, United Kingdom

April 28, 2016

F-2

---

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders of North Atlantic Drilling Limited

In our opinion, the accompanying consolidated balance sheet and the related consolidated statements of operations, of comprehensive income, of cash flows and of changes in equity present fairly, in all material respects, the financial position of North Atlantic Drilling Limited and its subsidiaries at December 31, 2014 and the results of their operations and their cash flows for each of the two years in the period ended December 31, 2014, in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers AS

Oslo, Norway

April 21, 2015 except with respect to our opinion on the consolidated financial statements as it relates to the effects of the 1-for-10 reverse stock split discussed in Note 1, the effects of the related party offsetting discussed in Note 1 and the effects of the change in the classification of deferred taxes and debt issuance costs discussed in Note 2, as to which the date is April 28, 2016 .

F-3

---

NORTH ATLANTIC DRILLING LTD.

Consolidated Statement of Operations for the years ended December 31, 2015 , 2014 and 2013

(In millions of U.S. dollars, except per share data)

	Years Ended December 31,
	2015			2014			2013
Operating revenues
Contract revenues	730.4			1,058.8			1,116.7
Reimbursables	17.3			160.0			195.3
Related party revenues *	—			44.9			12.1
Other revenues	—			—			0.2
Total operating revenues	747.7			1,263.7			1,324.3
Loss on disposal	(82.0	)		—			—
Operating expenses
Vessel and rig operating expenses *	270.8			458.4			527.1
Reimbursable expenses	15.4			150.0			183.7
Depreciation and amortization	221.9			212.2			188.0
Loss on impairment	—			480.6			—
General and administrative expenses *	60.1			78.9			64.9
Total operating expenses	568.2			1,380.1			963.7
Net operating (loss)/income	97.5			(116.4	)		360.6
Financial items
Interest income	0.2			0.5			0.5
Interest expense *	(97.7	)		(103.8	)		(84.9	)
Foreign exchange gain	28.3			41.0			10.9
Loss on derivative financial instruments	(57.4	)		(86.2	)		(16.1	)
Other financial items *	(5.4	)		(26.0	)		(6.5	)
Total financial items	(132.0	)		(174.5	)		(96.1	)
(Loss)/Income before income taxes	(34.5	)		(290.9	)		264.5
Income taxes	(44.1	)		(29.6	)		(28.9	)
Net (loss)/income	(78.6	)		(320.5	)		235.6
Net income to non-controlling interests	16.2			12.4			—
Net (loss)/income attributable to the shareholders of the Company	(94.8	)		(332.9	)		235.6
Basic earnings per share **	(3.93	)		(13.86	)		10.35
Diluted earnings per share **	(3.93	)		(13.86	)		10.35
Declared dividend per share	0.00			4.80			9.05

*	Includes transactions with related parties. Refer to Note 21 - Related Party Transactions.

**	As a result of the stock split and capital reduction, the earnings per share has been retrospectively adjusted. Refer to Note 17 for more information.

See accompanying notes that are an integral part of these Consolidated Financial Statements.

F-4

---

NORTH ATLANTIC DRILLING LTD.

Consolidated Statement of Comprehensive Income

for the years ended December 31, 2015 , 2014 and 2013

(In millions of U.S. dollars)

	Years Ended December 31,
	2015			2014			2013
Net (loss)/income	(78.6	)		(320.5	)		235.6
Other comprehensive gain / (loss), net of tax:
Change in actuarial gain / (loss) relating to pension	34.9			(19.2	)		(6.6	)
Change in unrealized gain / (loss) on interest rate swaps in VIE	0.2			—			(2.3	)
Other comprehensive income / (loss), net of tax	35.1			(19.2	)		(8.9	)
Total comprehensive (loss)/income for the year ended	(43.5	)		(339.7	)		226.7
Total comprehensive income/(loss) attributable to non-controlling interests	16.4			12.4			(2.3	)
Total comprehensive (loss)/income attributable to the shareholders	(59.9	)		(352.1	)		229.0

Note: All items of other comprehensive (loss)/income are stated net of tax

See accompanying notes that are an integral part of these Consolidated Financial Statements.

 

F-5

---

NORTH ATLANTIC DRILLING LTD.

Consolidated Balance Sheet as of December 31, 2015 and 2014

(In millions of U.S. dollars)

	December 31, 2015			December 31, 2014
ASSETS
Current assets
Cash and cash equivalents	150.9			116.2
Restricted cash	6.5			11.0
Accounts receivables, net	99.3			235.1
Amount due from related party	4.7			34.8
Other current assets	25.1			22.0
Total current assets	286.5			419.1
Non-current assets
Newbuildings	—			172.6
Drilling units	2,738.0			2,923.5
Non-current assets held for sale	128.4			—
Deferred tax assets	7.5			31.8
Other non-current assets	94.7			104.0
Total non-current assets	2,968.6			3,231.9
Total assets	3,255.1			3,651.0
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Current portion of long-term debt	210.4			210.2
Amount due to related party	39.8			17.0
Trade accounts payable	12.3			6.5
Tax payable	20.3			11.8
Other current liabilities	211.8			267.8
Total current liabilities	494.6			513.3
Non-current liabilities
Long-term interest bearing debt	1,903.5			2,188.2
Long term debt to related party	321.0			308.4
Deferred taxes	57.7			54.2
Pension liabilities	37.4			82.9
Other non-current liabilities	22.2			42.4
Total non-current liabilities	2,341.8			2,676.1
Shareholders’ equity
Common shares of par value US$0.10 per share: 24,114,232 shares outstanding at December 31, 2015 (December 31, 2014: US$5.00 per share, 241,142,651 shares outstanding)	2.4			1,205.7
Additional paid in capital	49.2			48.6
Contributed surplus	2,037.6			834.3
Contributed deficit	(1,188.4	)		(1,188.4	)
Accumulated other comprehensive loss	(23.7	)		(58.6	)
Accumulated deficit	(484.9	)		(390.1	)
Total shareholders’ equity	392.2			451.5
Non controlling interest	26.5			10.1
Total equity	418.7			461.6
Total liabilities and shareholders’ equity	3,255.1			3,651.0

---

NORTH ATLANTIC DRILLING LTD.

Consolidated Statement of Cash Flows for the years ended December 31, 2015 , 2014 and 2013

(In millions of U.S. dollars)

	Years Ended December 31,
	2015			2014			2013
Cash Flows from Operating Activities
Net (loss)/income	(78.6	)		(320.5	)		235.6
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	221.9			212.2			188.0
Amortization of deferred loan charges	8.2			8.4			6.2
Loss on impairment	—			480.6			—
Loss on disposal	82.0			—			—
Amortization of mobilization cost	—			—			7.1
Amortization of tax assets	8.8			9.1			9.1
Payments for long-term maintenance	(30.3	)		(155.4	)		(96.4	)
Unrealized loss/(gain) related to derivative financial instruments	20.3			53.7			(13.0	)
Unrealized foreign exchange gain on long-term interest bearing debt	(30.6	)		(43.0	)		(9.7	)
Share based payments expense	0.6			0.8			0.5
Deferred income tax expense	23.5			12.0			20.0
Gain on disposal of fixed assets	—			—			(0.2	)
Changes in operating assets and liabilities:
Trade accounts receivable	135.8			(13.4	)		(9.8	)
Trade accounts payable	5.8			(3.9	)		4.8
Change in short-term related party receivables and liabilities	67.1			(39.1	)		89.4
Other receivables and other assets	2.6			12.2			(13.0	)
Change in deferred revenue	(18.3	)		0.2			23.8
Other liabilities	(78.9	)		(14.8	)		(17.2	)
Net cash provided by operating activities	339.9			199.1			425.2

---

NORTH ATLANTIC DRILLING LTD.

Consolidated Statement of Cash Flows for the years ended December 31, 2015 , 2014 and 2013

(In millions of U.S. dollars)

	Years Ended December 31,
	2015			2014			2013
Cash Flows from Investing Activities
Additions to newbuilding	(37.8	)		(448.9	)		(64.2	)
Additions to rigs and equipment	(5.7	)		(12.9	)		(36.9	)
Additions to other fixed assets	—			—			(1.4	)
Proceeds from sale of other fixed assets	—			—			0.2
Change in restricted cash	4.5			14.3			(1.6	)
Net cash used in investing activities	(39.0	)		(447.5	)		(103.9	)
Cash Flows from Financing Activities
Repayments of debt	(305.1	)		(430.5	)		(246.7	)
Proceeds from debt	41.0			1,215.0			250.6
Repayments of shareholder loan	—			(517.0	)		(659.4	)
Proceeds from new shareholder loan	—			142.0			355.0
Proceeds from related party loan	—			40.0			193.5
Repayment of related party loan	—			(110.0	)		(21.6	)
Proceeds from issuance of equity, net of issuance cost	—			114.1			—
Debt fees paid	—			(11.3	)		—
Dividends paid	—			(171.1	)		(205.4	)
Net cash (used in)/provided by financing activities	(264.1	)		271.2			(334.0	)
Effect of exchange rate changes on cash and cash equivalents	(2.1	)		9.3			(1.6	)
Net increase/(decrease) in cash and cash equivalents	34.7			32.1			(14.3	)
Cash and cash equivalents at beginning of the period	116.2			84.1			98.4
Cash and cash equivalents at the end of period	150.9			116.2			84.1
Supplementary disclosure of cash flow information
Interest paid, net of capitalized interest	77.7			96.8			82.9
Income taxes paid	8.8			11.9			9.0

---

NORTH ATLANTIC DRILLING LTD.

Consolidated Statement of Changes in Equity for the years ended December 31, 2015 , 2014 , 2013

(In millions of U.S. dollars)

	Share Capital		Additional paid-in capital		Contributed surplus		Contributed deficit		Retained earnings		Other comprehensive loss		Total Shareholder's equity		NCI		Total equity
Balance at December 31, 2012	1,138.1		0.8		834.3		(1,186.1	)	83.8		(32.8	)	838.1		—		838.1
Stock options	—		0.5		—		—		—		—		0.5		—		0.5
Other comprehensive loss	—		—		—		—		—		(6.6	)	(6.6	)	(2.3	)	(8.9	)
Common control transaction	—		—		—		(2.3	)	—		—		(2.3	)	—		(2.3	)
Dividend paid	—		—		—		—		(205.5	)	—		(205.5	)	—		(205.5	)
Net income	—		—		—		—		235.6		—		235.6		—		235.6
Balance at December 31, 2013	1,138.1		1.3		834.3		(1,188.4	)	113.9		(39.4	)	859.8		(2.3	)	857.5
Issuance of common shares	67.6		46.5		—		—		—		—		114.1		—		114.1
Other comprehensive loss	—		—		—		—		—		(19.2	)	(19.2	)	—		(19.2	)
Stock options	—		0.8		—		—		—		—		0.8		—		0.8
Dividend paid	—		—		—		—		(171.1	)	—		(171.1	)	—		(171.1	)
Net (loss) / income	—		—		—		—		(332.9	)	—		(332.9	)	12.4		(320.5	)
Balance at December 31, 2014	1,205.7		48.6		834.3		(1,188.4	)	(390.1	)	(58.6	)	451.5		10.1		461.6
Stock options	—		0.6		—		—		—		—		0.6		—		0.6
Other comprehensive income	—		—		—		—		—		34.9		34.9		0.2		35.1
Net (loss)/income	—		—		—		—		(94.8	)	—		(94.8	)	16.2		(78.6	)
Reverse stock split and capital reduction	(1,203.3	)	—		1,203.3		—		—		—		—		—		—
Balance at December 31, 2015	2.4		49.2		2,037.6		(1,188.4	)	(484.9	)	(23.7	)	392.2		26.5		418.7

---

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1 - General information

As used herein, and unless otherwise required by the context, the terms “North Atlantic” and “North Atlantic Drilling” refer to North Atlantic Drilling Ltd. and the terms “Company”, “we”, “Group”, “us” and words of similar import refer to North Atlantic Drilling and its consolidated companies for the periods that are consolidated and the consolidated group for the periods that are consolidated. The use herein of such terms as group, organization, we, us, our and its, or references to specific entities, is not intended to be a precise description of corporate relationships. The Company was a Norwegian Over The Counter (N-OTC) listed company at December 31, 2013. On January 29, 2014 the Company was listed on the New York Stock Exchange. The Company was formed as a wholly owned subsidiary of Seadrill Limited (“Seadrill” or “the Parent”) on February 10, 2011, under the laws of Bermuda to acquire certain continuing businesses of Seadrill in the North Atlantic region. We were registered on the N-OTC list on February 24, 2011. Following the Initial Public offering on January 2014, seadrill owns 70.4% of The Company.

Through the acquisition of certain Seadrill subsidiaries and investment in newbuildings, the Company has developed into a leading offshore drilling contractor in the North Atlantic Area. As of December 31, 2015 , we owned seven offshore drilling rigs, consisting of one drillship, three jack-up rigs and three semi-submersible rigs, for operations in harsh environments. In addition, one semi-submersible rig under construction, the West Rigel, is classified as an asset held for sale as at December 31, 2015 .

Basis of presentation

Our Consolidated Financial Statements are prepared in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”). Investments in companies in which we directly or indirectly hold more than 50% of the voting control are consolidated in the financial statements. All inter-company balances and transactions are eliminated. The amounts are presented in United States dollars (“U.S. dollars”) rounded to the nearest one hundred thousand, unless otherwise stated.

Basis of consolidation

The consolidated financial statements include the assets and liabilities of the Company and its subsidiaries and variable interest entities ("VIE") in which the Company is deemed to be the primary beneficiary. The Consolidated Financial Statements include the assets and liabilities of the Company and its subsidiaries. All intercompany balances and transactions have been eliminated on consolidation.

A VIE is defined in ASC Topic 810 "Consolidation" ("ASC810") as a legal entity either (a) the total equity at risk is not sufficient to permit the entity that most significantly impact on its activities without additional subordinated support; (b) equity interests holders as a group lack either i) the power to direct the activities of the entity that most significantly impact on its economic success, ii) the obligation to absorb the expected losses of the entity, or iii) the right to receive the expected residual return of the entity; or (c) the voting rights of some investors in the entity are not proportional to their economic interests and the activities of the entity involve or are conducted on behalf of an investor with disproportionately small voting interests.

ASC 810 requires a variable interest entity to be consolidated by its primary beneficiary, being the interest holder, if any, which has both (1) the power to direct the activities of the entity which most significantly impact on the entity`s economic performance, and (2) the right to receive benefits or the obligation to absorb losses from the entity which could potentially be significant to the entity.

We evaluate a VIE, in order to determine whether we are the primary beneficiary of the entity, and where it is determined that we are the primary beneficiary we fully consolidate the entity.

Intercompany transactions and internal sales have been eliminated on consolidation. Unrealized gains and losses arising from transactions with associates are eliminated to the extent of the Company`s interest in the entity.

Reverse stock split and capital reduction

In December 2015 the shareholders in a special general meeting approved a capital reorganization including a 1-for- 10 reverse stock split of the Company's issued and outstanding common shares and reducing par value from $5.00 to $0.10 . In addition the total authorized share capital was reduced from $2,000.0 million to $10.0 million .

As a result of the capital restructuring the number of shares outstanding has fallen from 241,142,651 to 24,114,232 . As a result, the issued share capital of the Company has fallen from $1,205.7 million to $2.4 million and the contributed surplus has been increased by $1,203.3 million . Refer to Note 17 - Share Capital for more information.

F-10

---

Related party offsetting

Historically the Company presented balances due to/from Ship Finance on a gross basis. Beginning on June 30, 2015 the Company elected to represent this on a net basis, due to the fact that the right of offset is established in the long-term loan agreements, and the balances are intended to be settled on a net basis, providing a more appropriate description of the Company’s related party net debt position. Accordingly the Company has represented $14.3 million as at December 31, 2014, from Amounts due from related parties (current assets) and offset against long-term debt due to related parties (non-current liabilities). There is no corresponding offsetting impact as at December 31, 2015 as the short term trading balances are in a liability position of $23.2 million . Refer to Note 21 - Related party transactions and Note 24 - Variable Interest Entity.

Note 2 - Accounting policies

The accounting policies set out below have been applied consistently to all periods in these Consolidated Financial Statements.

Use of estimates

Preparation of financial statements in accordance with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Contract revenue

A substantial majority of the Company’s revenues are derived from dayrate based drilling contracts (which may include lump sum fees for mobilization and demobilization) and other service contracts. Both dayrate based and lump sum fee revenues are recognized ratably over the contract period as services are rendered. Under some contracts, the Company is entitled to additional payments for meeting or exceeding certain performance targets. Such additional payments are recognized when any uncertainties regarding achievements of such targets are resolved or upon completion of the drilling program.

In connection with drilling contracts, the Company may receive lump sum fees for the mobilization of equipment and personnel or for capital additions and upgrades prior to commencement of drilling services. These up-front fees are recognized as revenue over the original contract term, excluding any extension option periods.

In some cases, the Company may receive lump sum non-contingent fees or dayrate based fees from customers for demobilization upon completion of a drilling contract. Non-contingent demobilization fees are recognized as revenue over the original contract term, excluding any extension option periods. Contingent demobilization fees are recognized as earned upon completion of the drilling contract.

Fees received from customers under drilling contracts for capital upgrades are deferred and recognized over the remaining contract term, excluding any extension option periods.

In certain countries in which we operate, taxes such as sales, use, value-added, gross receipts and excise may be assessed by the local government on our revenues. We generally record our tax-assessed revenue transactions on a net basis in our consolidated statement of income.

Reimbursables

Reimbursements received for the purchases of supplies, personnel services and other services provided on behalf of and at the request of our customers in accordance with a contract or agreement are recorded as revenue. The related costs are recorded as reimbursable expenses in the same period.

 

Other revenues

In a business combination there may exist favorable and unfavorable drilling contracts which are recorded at fair value at the date of acquisition when the purchase price allocation is prepared. A favorable or unfavorable drilling contract is a contract that has a dayrate which differs from prevailing market rates at the time of acquisition. The net present value of such contracts is recorded as an asset or liability at the purchase date and subsequently recognized as revenue or reduction to revenue over the contract term.

Mobilization and demobilization expenses

Mobilization costs incurred as part of a contract are capitalized and recognized as expense over the original contract term, excluding any extension option periods. The costs of relocating drilling rigs that are not under contract are expensed as incurred.

Demobilization costs are costs related to the transfer of a vessel or drilling rig to a safe harbor or different geographic area and are expensed as incurred.

F-11

---

Vessel and Rig Operating Expenses

Vessel and rig operating expenses are costs associated with operating a drilling unit that is either in operation or stacked, and include the remuneration of offshore crews and related costs, supplies, insurance costs, expenses for repairs and maintenance as well as costs related to onshore personnel in various locations where we operate the drilling units and are expensed as incurred.

Repairs, maintenance and periodic surveys

Costs related to periodic surveys of drilling rigs are capitalized under drilling rigs and amortized over the anticipated period between overhauls, which is generally five years. These costs are primarily shipyard costs and the cost of employees directly involved in the work. Amortization costs for periodic surveys are included in depreciation and amortization expense. Costs for other repair and maintenance activities are included in vessel and rig operating expenses and expensed when the repairs and maintenance take place.

Foreign currencies

The Company and its subsidiaries use the U.S. dollar as their functional currency because the majority of their revenues and expenses are denominated in U.S. dollars. Accordingly, the Company’s reporting currency is also U.S. dollars.

Transactions in foreign currencies during a period are translated into U.S. dollar at the rates of exchange in effect on the date of the transaction. Foreign currency assets and liabilities are translated using rates of exchange at the balance sheet date. Gains and losses on foreign currency transactions are included in the Company’s consolidated statements of operations.

Current and non-current classification

Receivables and liabilities (excluding deferred taxes) are classified as current assets and liabilities, respectively, if their maturity is within one year of the balance sheet date. Otherwise, they are classified as non-current assets and liabilities.

In November 2015, the FASB issued ASU 2015-17, Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes, to simplify the presentation of deferred income taxes in a classified statement of financial position. The update require that deferred tax liabilities and assets be classified as non-current in a classified statement of financial position as opposed to the current requirement to separate these into current and non-current amounts. As permitted by ASU 2015-17, the Company early-adopted this standard as at December 31, 2015 and applied it retrospectively to all periods presented. As a result the Company has presented all deferred tax liabilities and assets, as well as any related valuation allowance, as non-current for all periods presented in this annual report. The adoption of this guidance did not have a material impact on Company's consolidated financial statements and related disclosures.

Cash and cash equivalents

Cash and cash equivalents consist of cash, bank deposits and highly liquid financial instruments with original maturities of three months or less.

Restricted cash

Restricted cash consists of bank deposits which have been pledged as collateral for certain guarantees issued by a bank or minimum deposits which must be maintained at all times in accordance with contractual arrangements. Restricted cash with maturity longer than one year are classified separately as non-current assets.

Receivables

Receivables, including accounts receivable, are recorded in the balance sheet at their nominal amount less an allowance for doubtful accounts. The Company establishes reserves for doubtful accounts on a case-by-case basis when it is unlikely that required payments of specific amounts will occur. In establishing these reserves, the Company considers the financial condition of the customer as well as specific circumstances related to the receivable, such as customer disputes. Receivable amounts determined as being unrecoverable are written off.

Newbuildings

The carrying value of rigs under construction ("Newbuildings") represents the accumulated costs at the balance sheet date. Cost components include payments for yard installments and variation orders, construction supervision, equipment, spare parts, capitalized interest, costs related to first time mobilization and commissioning costs. No charge for depreciation is made until commissioning of the newbuilding has been completed and it is ready for its intended use.

Capitalized interest

Interest expenses are capitalized during construction of newbuilds based on accumulated expenditures for the applicable project at the Company’s current rate of borrowing. The amount of interest expense capitalized in an accounting period shall be determined by applying an interest rate (“the capitalization rate”) to the average amount of accumulated expenditures for the asset during the period. The capitalization rates used in an accounting period are based on the rates applicable to borrowings outstanding during the period. The Company does not capitalize amounts beyond the actual interest expense incurred in the period.

F-12

---

If the Company’s financing plans associate a specific new borrowing with a qualifying asset, the Company uses the rate on that borrowing as the capitalization rate to be applied to that portion of the average accumulated expenditures for the asset that does not exceed the amount of that borrowing. If average accumulated expenditures for the asset exceed the amounts of specific new borrowings associated with the asset, the capitalization rate to be applied to such excess shall be a weighted average of the rates applicable to other borrowings of the Company.

Drilling rigs

Rigs, vessels and equipment are recorded at historical cost less accumulated depreciation. The cost of these assets, less estimated residual value is depreciated on a straight-line basis over their estimated remaining economic useful lives. The estimated economic useful life of the Company's drilling rigs, when new, is 30 years.

 

Significant investments are capitalized and depreciated in accordance with the nature of the investment. Significant investments that are deemed to increase an asset's value for its remaining useful life are capitalized and depreciated over the remaining life of the asset.

Cost of property and equipment sold or retired, with the related accumulated depreciation and write-downs are removed from the balance sheet, and resulting gains or losses are included in the consolidated statement of operations.

Assets held for sale

Assets are classified as held for sale when all of the following criteria are met: Management, having the authority to approve the action, commits to a plan to sell the asset (disposal group), the asset (disposal group) is available for immediate sale in its present condition subject only to terms that are usual and customary for sales of such assets (disposal groups), an active program to locate a buyer and other actions required to complete the plan to sell the asset (disposal group) have been initiated, the sale of the asset (disposal group) is probable, and transfer of the asset (disposal group) is expected to qualify for recognition as a completed sale, within 1 year. The term probable refers to a future sale that is likely to occur, the asset (disposal group) is being actively marketed for sale at a price that is reasonable in relation to its current fair value and actions required to complete the plan indicate that it is unlikely that significant changes to the plan will be made or that the plan will be withdrawn.

Other equipment

Other equipment is recorded at historical cost less accumulated depreciation and is depreciated over its estimated remaining useful life, which is between three and five years depending on the type of asset. Equipment is recorded within Other non-current assets on the balance sheet.

Impairment of Long-Lived Assets

The carrying value of long-lived assets that are held and used by the Company are reviewed for impairment whenever certain triggering events indicate that the carrying amount of an asset may no longer be appropriate. The Company assesses recoverability of the carrying value of the asset by estimating the undiscounted future net cash flows expected to result from the asset, including eventual disposition. If the undiscounted future net cash flows are less than the carrying value of the asset, an impairment loss is recorded equal to the difference between the asset’s carrying value and fair value.

Goodwill

The Company allocates the purchase price of acquired businesses to the identifiable tangible and intangible assets and liabilities acquired, with any remaining amount being capitalized as goodwill. Goodwill is tested for impairment at least annually at the reporting unit level, which is defined as an operating segment, or a component one level below an operating segment, that constitutes a business for which financial information is available and is regularly reviewed by management. The Company has one reporting unit.

The Company tests goodwill for impairment on an annual basis as of December 31 each year or when events or circumstances indicate that a potential impairment exists. The Company first assesses qualitative factors to determine whether it is more-likely-than-not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two step goodwill impairment test.

If the qualitative factors indicate possible impairment, the Company performs a quantitative assessment to estimate fair value of its reporting unit compared to their carrying value. In the event that the fair value is less than carrying value, the Company must perform an exercise similar to a purchase price allocation in a business combination in order to determine the amount of the impairment charge.The quantitative goodwill impairment test for a reporting unit is based on discounted cash flows. The Company uses estimated future cash flows applying contract dayrates during the firm contract periods and estimated forecasted dayrates for the periods after expiry of firm contract periods. Zero escalation of dayrates for the periods will be assumed. The estimated future cash flows will be based on remaining economic useful lives for the assets, and discounted using a weighted average cost of capital (WACC).

Defined benefit pension plans

The Company has defined benefit plans which provide retirement, death and early termination benefits. The Company's net obligation is calculated separately for each plan by estimating the amount of the future benefit that employees have earned in return for their cumulative service.

The aggregated projected future benefit obligation is discounted to a present value, and the aggregated fair value of any plan assets is deducted. The discount rate is the market yield at the balance sheet date on government bonds in the relevant currency and based on terms consistent with the post-

F-13

---

employment benefit obligations. The retirement benefits are generally a function of number of years of employment and amount of employees’ remuneration. The plans are primarily funded through payments to insurance companies. The Company records its pension costs in the period during which the services are rendered by the employees. Actuarial gains and losses are recognized in the consolidated statement of operations when the net cumulative unrecognized actuarial gains or losses for each individual plan at the end of the previous reporting year exceed 10% of the higher of the present value of the defined benefit obligation and the fair value of plan assets at that date. These gains and losses are recognized over the expected remaining working lives of the employees participating in the plans. Otherwise, recognition of actuarial gains and losses is included in other comprehensive income. Those amounts will be subsequently recognized as a component of net periodic pension cost on the same basis as the amounts recognized in accumulated other comprehensive income.

On retirement, or when an employee leaves the Company, the member's pension liability is transferred to the life insurance company administering the plan, and the pension plan no longer retains an obligation relating to the leaving member. This action is deemed to represent a settlement under US GAAP, as it represents the elimination of significant risks relating to the pension obligation and related assets. Under settlement accounting US GAAP requires a portion of the net unrealized actuarial gains/losses to be recognized through the statement of operations. The portion corresponds to the relative value of the obligation reduction as a result of the settlement. However settlement accounting is not required if the cost of all settlements in a year is not deemed to be significant in the context of the plan. The Company deems the settlement not to be significant when the cost of settlements in the year is less than the sum of service cost and interest cost in the year. In this case the difference between the reduction in benefit obligation and the plan assets transferred to the life insurance company is recognized within "other comprehensive income", rather than being recognized in the statement of operations.

Treasury shares

Treasury shares are recognized at cost as a separate component of shareholders' equity. The purchase of treasury shares reduces the Company's share capital by the nominal value of the acquired treasury shares. The amount paid in excess of the nominal value is treated as a reduction of additional paid-in capital.

Derivative Financial Instruments and Hedging Activities

The Company's derivative instruments include interest-rate swap agreements, cross currency swaps and forward exchange contracts which are recorded at fair value. Changes in the fair value of these derivatives, which have not been designated as hedging instruments, are recorded as a gain or loss as a separate line item within financial items in our consolidated statement of operations.

 

Changes in the fair value of any derivative instrument that we have formally designated as a hedge, are recognized in accumulated other comprehensive income/(loss) in the consolidated balance sheets. Any change in fair value relating to an ineffective portion of a designated hedge is recognized, in the consolidated statement of operations. When the hedged item affects the income statement, the gain or loss included in accumulated other comprehensive income is reported on the same line in the consolidated statements of operations as the hedged item.

Income taxes

North Atlantic is a Bermuda company that has a number of subsidiaries in various jurisdictions. Currently, the Company and its Bermudan subsidiaries are not required to pay taxes in Bermuda on ordinary income or capital gains as they qualify as exempt companies. The Company and its subsidiaries and have received written assurance from the Minister of Finance in Bermuda that it will be exempt from taxation until March 2035. Certain subsidiaries operate in other jurisdictions where taxes are imposed. Consequently income taxes have been recorded in these jurisdictions when appropriate. Our income tax expense is based on our income and statutory tax rates in the various jurisdictions in which we operate. We provide for income taxes based on the tax laws and rates in effect in the countries in which operations are conducted and income is earned.

The determination and evaluation of our annual group income tax provision involves interpretation of tax laws in various jurisdictions in which we operate and requires significant judgment and use of estimates and assumptions regarding significant future events, such as amounts, timing and character of income, deductions and tax credits. There are certain transactions for which the ultimate tax determination is unclear due to uncertainty in the ordinary course of business. We recognize tax liabilities based on our assessment of whether our tax positions are more likely than not sustainable, based solely on the technical merits and considerations of the relevant taxing authority's widely understood administrative practices and precedence. Changes in tax laws, regulations, agreements, treaties, foreign currency exchange restrictions or our levels of operations or profitability in each jurisdiction may impact our tax liability in any given year. While our annual tax provision is based on the information available to us at the time, a number of years may elapse before the ultimate tax liabilities in certain tax jurisdictions are determined. Current income tax expense reflects an estimate of our income tax liability for the current year, withholding taxes, changes in prior year tax estimates as tax returns are filed, or from tax audit adjustments.

Income tax expense consists of taxes currently payable and changes in deferred tax assets and liabilities calculated according to local tax rules.

Deferred tax assets and liabilities are based on temporary differences that arise between carrying values used for financial reporting purposes and amounts used for taxation purposes of assets and liabilities and the future tax benefits of tax loss carry forwards.

Our deferred tax expense or benefit represents the change in the balance of deferred tax assets or liabilities as reflected on the balance sheet. Valuation allowances are determined 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. To determine the amount of deferred tax assets and liabilities, as well as of the Valuation allowances, we must make estimates and certain assumptions regarding future taxable income, including where our drilling units are expected to be deployed, as well as other assumptions related to

F-14

---

our future tax position. A change in such estimates and assumptions, along with any changes in tax laws, could require us to adjust the deferred tax assets, liabilities, or valuation allowances. The amount of deferred tax provided is based upon the expected manner of settlement of the carrying amount of assets and liabilities, using tax rates enacted at the balance sheet date. The impact of tax law changes is recognized in periods when the change is enacted.

Deferred charges

Loan related costs, including debt issuance, arrangement fees and legal expenses, are capitalized and presented in the balance sheet as a direct deduction from the carrying amount of the related debt liability, and amortized over the term of the related loan and the amortization is included in interest expense.

Share-based compensation

North Atlantic has established a Restricted Stock Units (“RSU”) plan where the holder of an award is entitled to receive shares if still employed at the end of the three year vesting period. There is no requirement for the holder to pay for the share on grant or vesting of the award.

The fair value of the RSU award is calculated as the market share price on grant date. The fair value of the awards expected to vest is recognized as compensation cost straight-line over the vesting period.

Provisions

A provision is recognized in the balance sheet when the Company has a present legal or constructive obligation as a result of a past event, and it is probable that an outflow of economic benefits will be required to settle the obligation and a reliable estimate of the amount can be made. If the effect is material, provisions are determined by discounting the expected future cash flows at a pre-tax rate that reflects current market assessments of the time value of money and, where appropriate, the risks specific to the liability.

 

Related parties

Parties are related if one party has the ability, directly or indirectly, to control the other party or exercise significant influence over the other party in making financial and operating decisions. Parties are also related if they are subject to common control or common significant influence.

Earnings per share

Basic earnings per share ("EPS") is calculated based on the income (loss) for the period available to common stockholders divided by the weighted average number of shares outstanding for basic EPS for the period. Diluted EPS includes the effect of the assumed conversion of potentially dilutive instruments. The determination of dilutive earnings per share requires the Company to potentially make certain adjustments to net income and for the weighted average shares outstanding used to compute basic earnings per share unless anti-dilutive.

Recently Adopted Accounting Standards

In April 2015, the Financial Accounting Standards Board issued Accounting Standards Update (ASU) 2015-03, Interest - Imputation of Interest, (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs , which requires the debt issuance costs related to a recognized debt liability to be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts and premiums. This ASU is effective for the first interim period beginning after December 15, 2015 and early adoption is permitted. The Company has chosen to early adopt this ASU in the second quarter of 2015. As a result, the consolidated balance sheet as at December 31, 2014 has been re-presented to reflect this change in accounting principle. $7.9 million of debt issuance costs have been reclassified from Other current assets to a direct deduction from Current portion of long-term debt and $15.4 million of debt issuance costs have been reclassified from Other non-current assets to a direct deduction from Long-term debt. Similarly, as at December 31, 2015, $7.7 million of debt issuance costs have been presented as a direct deduction from the current portion of long-term debt and $7.0 million of debt issuance costs have been presented as a direct deduction from long-term debt. The company has disclosed this presentation in Note 14 - Long term interest bearing debt.

In April 2014, the Financial Accounting Standards Board ("FASB") issued ASU 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity , which amends the criteria for reporting discontinued operations to include only disposals representing a strategic shift in operations. The ASU also requires expanded disclosures regarding the assets, liabilities, income, and expenses of discontinued operations. The Company adopted this guidance in the period, which was effective for the discontinued operations occurring after January 1, 2015. The adoption of this guidance did not have a material impact on Company's consolidated financial statements and related disclosures.

In November 2015, the FASB issued ASU 2015-17, Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes, to simplify the presentation of deferred income taxes in a classified statement of financial position. The update requires that deferred tax liabilities and assets be classified as non-current in a classified statement of financial position as opposed to the current requirement to separate these into current and non current amounts. As permitted by ASU 2015-17, the Company early-adopted this standard effective December 31, 2015 and applied it retrospectively to all periods presented. As a result the Company has presented all deferred tax liabilities and assets, as well as any related valuation allowance, as non-current for all periods presented in this annual report. The adoption of this guidance did not have a material impact on Company's consolidated financial statements and related disclosures.

F-15

---

Recently Issued Accounting Standards

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers , which provides new authoritative guidance on the methods of revenue recognition and related disclosure requirements. In April 2015 the FASB proposed to defer the effective date of the guidance by one year. Based on this proposal, public entities would need to apply the new guidance for annual and interim periods beginning after December 15, 2017, and shall be applied, at the Company’s option, retrospectively to each period presented or as a cumulative-effect adjustment as of the date of adoption. Early adoption is not permitted until periods beginning after December 15, 2016. The Company is in the process of evaluating the impact of this standard update on its consolidated financial statements and related disclosures.

In August 2014, the FASB issued ASU 2014-15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern , which provides new authoritative guidance with regards to management's responsibility to assess an entity's ability to continue as a going concern, and to provide related footnote disclosures in certain circumstances. The ASU will be effective for all entities in the first annual period ending after December 15, 2016 (December 31, 2016 for calendar year-end entities) and early adoption is permitted. The Company is in the process of evaluating the impact of this standard update on its consolidated financial statements and related disclosures.

In February 2015, the FASB issued ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis , which made targeted amendments to the current consolidation guidance that could affect all industries. The FASB issued this guidance to respond to stakeholders’ concerns about the current accounting for consolidation of certain legal entities. Financial statement users asserted that in certain situations in which consolidation is ultimately required, deconsolidated financial statements are necessary to better analyze the reporting entity’s economic and operational results. Previously, the FASB issued an indefinite deferral for certain entities to partially address those concerns. However, the amendments in this guidance rescind that deferral and address those concerns by making changes to the consolidation guidance. The ASU will be effective for public entities in the first annual period, and for interim periods therein, beginning after December 15, 2015 and early adoption is permitted. The Company does not expect the adoption of this standard to have a material impact on its consolidated financial statements and related disclosures.

In April 2015, the FASB issued ASU 2015-05, Intangibles - Goodwill and Other - Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Fees Paid in a Cloud Computing Arrangement , which provides explicit guidance about a customer’s accounting for fees paid in a cloud computing arrangement. This ASU will be effective for the first interim period beginning after December 15, 2015 and early adoption is permitted. The Company does not expect the adoption of this standard to have a material impact on its consolidated financial statements and related disclosures.

In September 2015, the FASB issued ASU 2015-16, Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments . The amendments in this update require that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. The guidance further requires that the acquirer record, in the same period’s financial statements, the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date and present separately on the face of the income statement or disclose in the notes the portion of the amount recorded in current-period earnings by line item that would have been recorded in previous reporting periods if the adjustment to the provisional amounts had been recognized as of the acquisition date. The guidance will be effective for fiscal years beginning after December 15, 2015, including interim periods within those fiscal years and early adoption is permitted. The Company does not expect the adoption of this standard to have a material impact on its consolidated financial statements and related disclosures.

In January 2016, the FASB issued ASU 2016-01, Financial Instruments—Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities, which made targeted improvements to the recognition and measurement of financial assets and financial liabilities. The update changes how entities measure equity investments that do not result in consolidation and are not accounted for under the equity method and how they present changes in the fair value of financial liabilities measured under the fair value option that are attributable to their own credit. The new guidance also changes certain disclosure requirements and other aspects of current US GAAP. The guidance will be effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years and early adoption is permitted in some cases. The Company is in the process of evaluating the impact of this standard update on its consolidated financial statements and related disclosures.

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) . The update requires an entity to recognize right-of-use assets and lease liabilities on its balance sheet and disclose key information about leasing arrangements. It also offers specific accounting guidance for a lessee, a lessor and sale and leaseback transactions. Lessees and lessors are required to disclose qualitative and quantitative information about leasing arrangements to enable a user of the financial statements to assess the amount, timing and uncertainty of cash flows arising from leases. The guidance will be effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years and early adoption is permitted. The Company is in the process of evaluating the impact of this standard update on its consolidated financial statements and related disclosures.

In March 2016, the FASB issued ASU 2016-07, Investments-Equity Method and Joint Ventures (Topic 323): Simplifying the Transition to the Equity Method of Accounting. The update eliminates the requirement that an investor retrospectively apply equity method accounting when an investment that it had accounted for by another method initially qualifies for use of the equity method. The guidance will be effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years and early adoption is permitted. The Company does not expect the adoption of this standard to have a material impact on its consolidated financial statements and related disclosures.

In March 2016, the FASB issued ASU 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net). The update clarifies principal vs agent accounting of the new revenue standard. The guidance will be effective for annual and interim periods beginning after December 15, 2017, and shall be applied, at the Company’s option, retrospectively to each period presented or as a

F-16

---

cumulative-effect adjustment as of the date of adoption. Early adoption is not permitted until periods beginning after December 15, 2016. The Company is in the process of evaluating the impact of this standard update on its consolidated financial statements and related disclosures.

In March 2016, the FASB issued ASU 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting. The update simplifies the accounting for share based payment transactions. The guidance will be effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years and early adoption is permitted. The Company does not expect the adoption of this standard to have a material impact on its consolidated financial statements and related disclosures.

In April 2016, the FASB issued ASU 2016-10, Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing. The update provide more clarification about identifying performance obligations and licensing. The guidance will be effective for annual and interim periods beginning after December 15, 2017, and shall be applied, at the Company’s option, retrospectively to each period presented or as a cumulative-effect adjustment as of the date of adoption. Early adoption is not permitted until periods beginning after December 15, 2016. The Company is in the process of evaluating the impact of this standard update on its consolidated financial statements and related disclosures.

Note 3 – Segment information

Operating segments

We provide harsh environment offshore drilling services to the oil and gas industry. The Company’s performance is reviewed by the chief operating decision maker as one single business segment, mobile units.

Geographic segment data

Revenues are attributed to geographical segments based on the country of operations for drilling activities; that is, the country where the revenues are generated. The following presents the Company’s revenue by geographic area:

	Year ended December 31,
(In millions of U.S. dollars)	2015			2014			2013
Norway	648.6			1,056.8			1,121.7
United Kingdom	99.1			148.9			176.4
Russia	—			58.0			—
Ireland	—			—			26.2
Total	747.7			1,263.7			1,324.3

As of December 31, 2015 , one of the Company’s drilling rigs, with a net book value of $643.6 million , was located in the United Kingdom and all other rigs were located in Norway. At December 31, 2014 , one drilling rigs, with a net book value of $671.9 million , was located in United Kingdom and all other rigs were located in Norway. Asset location at the end of the period is not necessarily indicative of the geographic distribution of the revenues or operating profits generated by such assets during the period.

Major Customers

In the years ended December 31, 2015 , 2014 and 2013 , the Company had the following customers with contract revenues greater than 10% in any of the years presented:

		Year ended December 31,
Contract revenue split by client		2015			2014			2013
Statoil		44	%		38	%		57	%
ExxonMobil		25	%		13	%		12	%
Conoco Phillips		18	%		8	%		—	%
Total		13	%		12	%		13	%
Shell		—	%		12	%		14	%
KMNG		—	%		11	%		—	%
Other		—	%		6	%		4	%
Total		100	%		100	%		100	%

F-17

---

Note 4 – Taxation

Income taxes consist of the following:

	Year ended December 31,
(In millions of U.S. dollars)	2015			2014			2013
Current tax expense:
Bermuda	—			—			—
Foreign	19.5			8.2			(0.5	)
Deferred tax expense:
Bermuda	—			—			—
Foreign	15.5			12.3			20.3
Amortization of tax effect on internal sale of assets	9.1			9.1			9.1
Total provision	44.1			29.6			28.9
Effective tax rate	-127.8	%		-10.2	%		10.9	%

The effective tax rate for the year months ended December 31, 2015 and 2014 was -127.8% and -10.2% respectively. This means that we continue to pay tax on local operations but reported an overall a loss before tax inclusive of discrete items.  The negative rate reflects no tax relief on the impairments or the derivative loss. This is due to these items largely falling within the zero tax rate Bermuda companies. In addition, the increase in the tax expense in 2015 in comparison to 2014 is mainly due to deferred tax liability recorded on unremitted earnings.

The Company may be taxable in more than one jurisdiction based on its drilling rig operations. A loss in one jurisdiction may not be offset against taxable income in another jurisdiction. Thus, the Company may pay tax within some jurisdictions even though it might have an overall loss at the consolidated level.

    

The income taxes for the years ended December 31, 2015 and 2014 differed from the amount computed by applying the statutory income tax rate of 0% due to operations in foreign jurisdictions with different applicable tax rates as compared to Bermuda.

	Year ended December 31,
(In millions of U.S. dollars)	2015			2014			2013
Income taxes at statutory rate	—			—			—
Effect of amortization of tax on internal sale of assets	9.1			9.1			9.1
Effect of unremitted earnings of subsidiaries	21.4			—			—
Effect of taxable income in various countries	13.6			20.5			19.8
Total	44.1			29.6			28.9

Deferred Income Taxes

Deferred income taxes reflect the impact of temporary differences between the amount of assets and liabilities recognized for financial reporting purposes and such amounts recognized for tax purposes. The net deferred tax assets (liabilities) consist of the following:

Deferred Tax Assets:

(In millions of U.S. dollars)	December 31, 2015			December 31, 2014
Pension	5.4			21.7
Contracts and long term maintenance	—			3.6
Loss carry forward	2.5			6.5
Gross deferred tax asset	7.9			31.8
Valuation allowance related to net operating losses carried forward	(0.4	)		—
Net deferred tax asset	7.5			31.8

F-18

---

Deferred Tax Liability:

(In millions of U.S. dollars)	December 31, 2015			December 31, 2014
Long term maintenance	36.3			50.7
Unremitted Earnings of Subsidiaries	21.4			—
Tax depreciation	—			0.3
Pensions	—			3.2
Gross deferred tax liability	57.7			54.2
Net deferred tax liability	(50.2	)		(22.4	)

Net deferred taxes are classified as follows:

(In millions of U.S. dollars)	December 31, 2015			December 31, 2014
Short-term deferred tax asset	—			—
Long-term deferred tax asset	7.5			31.8
Short-term deferred tax liability	—			—
Long-term deferred tax liability	(57.7	)		(54.2	)
Net deferred tax liability	(50.2	)		(22.4	)

As of December 31, 2015 , deferred tax assets related to net operating loss ("NOL") carryforwards were $2.5 million , which can be used to offset future taxable income. NOL carryforwards were generated in UK and will not expire. As at December 31, 2015 , the valuation allowance of $0.4 million on the NOL carryforwards results where we do not expect to generate future taxable income ( 2014 : nil , 2013 : nil ).

The Company has reviewed its assertion of indefinite reinvestment of unremitted earnings of subsidiaries and determined that, due to the cash needs of the Company caused by the recent industry trend in the market, the Company no longer considers such earnings to be indefinitely reinvested. The Company has recognized a deferred tax liability of $21.4 million in 2015 .

In November 2015, the FASB issued ASU 2015-17, Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes, to simplify the presentation of deferred income taxes in a classified statement of financial position. The update requires that deferred tax liabilities and assets be classified as non-current in a classified statement of financial position as opposed to the current requirement to separate these into current and non-current amounts. As permitted by ASU 2015-17, the Company early-adopted this standard effective December 31, 2015 and applied it retrospectively to all periods presented. As a result the Company has presented all deferred tax liabilities and assets, as well as any related valuation allowance, as non-current for all periods presented in this annual report. The adoption of this guidance did not have a material impact on Company's consolidated financial statements and related disclosures.

North Atlantic is headquartered in Bermuda where we have been granted a tax exemption until 2035. Other jurisdictions in which the Company operates are taxable based on rig operations. A loss in one jurisdiction may not be offset against taxable income in another jurisdiction. Thus, the Company may pay tax within some jurisdictions even though it may have an overall loss at the consolidated level. The following table summarizes the earliest tax years that remain subject to examination by the major taxable jurisdictions in which the Company operates:

Jurisdiction	Earliest Open Year
United Kingdom	2011
Norway	2013
Faroe Islands *	2014
Russia	2014

* North Atlantic operated the West Hercules drilling unit while the unit was on a contract in the Faroe Islands, the contracting party for the period of operations in the Faroe Islands was Seadrill Offshore AS.

Note 5 - Interest expense

F-19

---

(In millions of U.S. dollars)	Years ended December 31
	2015			2014			2013
Gross interest expense	105.0			110.9			95.2
Capitalized interest	7.3			7.1			10.3
Net interest expense	97.7			103.8			84.9

Note 6 – Earnings per share

The computation of basic earnings per share (“EPS”) is based on the weighted average number of shares outstanding during the period. Diluted EPS includes the effect of the assumed conversion of potentially dilutive instruments.

The components of the numerator for the calculation of basic and diluted EPS are as follows:

(In millions of US$)	Year ended December 31,
	2015			2014			2013
Net loss attributable to shareholders	(94.8	)		(332.9	)		235.6
Effect of dilution	—			—			—
Diluted net income attributable to stockholders	(94.8	)		(332.9	)		235.6

The components of the denominator for the calculation of basic and diluted EPS are as follows:

(In millions of US$)	Year ended December 31,
	2015			2014			2013
				Restated*			Restated*
Basic loss per share:
Weighted average number of common shares outstanding	24.1			24.0			22.8
Diluted loss per share:
Weighted average number of common shares outstanding	24.1			24.0			22.8
Effect of dilution	—			—			—
Diluted numbers of shares	24.1			24.0			22.8
Basic loss per share (US$)	(3.93	)		(13.86	)		10.35
Diluted loss per share (US$)	(3.93	)		(13.86	)		10.35

* As a result of the 1 for 10 reverse stock split and capital reduction, the earnings per share has been retrospectively adjusted. Refer to Note 19 for more information.

Note 7 – Restricted cash

Short term restricted cash of $6.5 million and $11.0 million at December 31, 2015 and 2014 , respectively, mainly relates to tax withholding deposits.

Note 8 – Accounts receivable

Accounts receivable are presented net of allowances for doubtful accounts. The allowance for doubtful accounts receivables at December 31, 2015 was $12.1 million ( 2014 : $8.3 million , 2013 : $22.2 million ).

The Company did not recognize any bad debt expense in 2015 and 2014 , but has instead reduced contract revenue for any disputed amounts.

F-20

---

Note 9 – Other current assets

(In millions of U.S. dollars)	December 31, 2015			December 31, 2014
Reimbursable amounts due from customers	7.4			6.2
Prepaid expenses	5.3			0.9
Deferred  tax effect of  internal transfer of assets – current portion	9.1			9.1
VAT receivables	1.8			3.0
Other	1.5			2.8
Total other current assets	25.1			22.0

Note 10 – Newbuildings

(In millions of U.S. dollars)	December 31, 2015			December 31, 2014
Opening balance	172.6			312.9
Additions	30.5			441.7
Capitalized interest and loan related costs	7.3			7.1
Re-classified as Drilling rigs	—			(589.1	)
Re-classified as held for sale	(210.4	)		—
Closing balance	—			172.6

 

Additions in 2015 are related to the construction of the semi-submersible drilling rig West Rigel . Additions in 2014 are related to the construction of jack-up drilling rigs West Linus and the semi-submersible drilling rig West Rigel.

As of December 2, 2015, the West Rigel, with book value of $210.4 million , was reclassified as an asset held for sale. Refer to Note 12 for more information.

The reclassification to drilling units in 2014 is related to the West Linus which commenced operations in May 2014.

Note 11 – Drilling rigs

 

(In millions of U.S. dollars)	December 31, 2015			December 31, 2014
Cost	4,116.1			4,079.7
Accumulated depreciation	(1,378.1	)		(1,156.2	)
Net book value	2,738.0			2,923.5

Depreciation and amortization expense was $221.9 million , $212.2 million and $ 188.0 million for the years ended December 31, 2015 , 2014 and 2013 respectively.

Note 12 - Asset held for sale

On December 2, 2015, the Company signed an amendment with Jurong Shipyard ("Jurong") for the deferral of the delivery of the semi-submersible drilling unit, the West Rigel (the "Unit"). The deferral period lasts until June 2016, following completion of which, the Company and Jurong have agreed to form a Joint Asset Holding Company for joint ownership of the Unit, to be owned 23% by the Company and 77% by Jurong, in the event no employment is secured for the Unit and no alternative transaction is completed. Until the end of the deferral period, the Company will continue to market the unit for an acceptable drilling contract, and the Unit will remain at the Jurong Shipyard in Singapore. The Company and Jurong may also consider other commercial opportunities for the Unit during this period. However, based on current market conditions, management deems the most probable outcome to be that the Unit will be contributed to the Joint Asset Holding Company.

As a result, the Company has concluded that the West Rigel drilling unit should be classified as “Held for Sale” as at December 31, 2015. A loss has been recognized in the year of $82 million , which is the difference between the net book value of the unit of $210.4 million , compared to the expected

F-21

---

recoverable value of the Company’s investment in the Joint Asset Holding Company of $128.4 million . The loss has been recognized in "Loss on disposal" in the Statement of Operations.

(In millions of US$)	December 31, 2015
West Rigel newbuild investment, classified as held for sale	210.4
Loss on disposal	(82.0	)
Closing balance at the end of the period	128.4

Note 13 – Other non-current assets

(In millions of U.S. dollars)	December 31, 2015			December 31, 2014
Deferred tax effect of internal transfer of assets –long term portion	92.9			102.0
Other	1.8			2.0
Total other non-current assets	94.7			104.0

Note 14 – Long-term interest bearing debt

As of December 31, 2015 and December 31, 2014 , the Company had the following debt facilities:

(In millions of U.S. dollars)	December 31, 2015			December 31, 2014
Credit facilities:
US$2,000 facility	1,200.0			1,366.7
US $475 facility	354.0			451.3
Total credit facilities	1,554.0			1,818.0
Bonds:
NOK 1,500 bond	170.6			201.4
US$600 bond	600.0			600.0
Total bonds	770.6			801.4
Related Party Loans
Loan provided by related party	125.0			110.7
Total interest bearing debt	2,449.6			2,730.1
Less : current portion	(218.1	)		(218.1	)
Less : Related party share of long term debt	(321.0	)		(308.4	)
Long-term portion of interest bearing debt	1,910.5			2,203.6

* Seadrill is the owner of 5.5% of the bond, this portion is presented as a related party liability in the Company's consolidated balance sheet. Refer to Note 21 - Related party transactions.

** Seadrill is the owner of 31.1% of the bond, this portion is presented as a related party liability in the Company's consolidated balance sheet. Refer to Note 21 - Related party transactions.

The company has adopted Accounting Standards Update (ASU) 2015-03, Interest - Imputation of Interest, (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs as at June 30, 2015, which requires the debt issuance costs related to a recognized debt liability to be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts and premiums. This ASU is effective for the first interim period beginning after December 15, 2015 and early adoption is permitted. The Company has chosen to early adopt this ASU in the second quarter of 2015. As a result, the consolidated balance sheet as at December 31, 2014 has been represented to reflect this change in accounting principle. $7.9 million of debt issuance costs have been reclassified from Other current assets to a direct deduction from Current portion of long-term debt and $15.4 million of debt issuance costs have been reclassified from Other non-current assets to a direct deduction from Long-term debt. Similarly, as at

F-22

---

December 31, 2015, $7.7 million of debt issuance costs have been presented as a direct deduction from the current portion of long-term debt and $7.0 million of debt issuance costs have been presented as a direct deduction from long-term debt.

Outstanding debt as at December 31, 2015
(In $ millions)	Principal outstanding			Less: Debt Issuance Costs			Total Debt
Current portion of long-term debt	218.1			(7.7	)		210.4
Long-term portion of debt	1,910.5			(7.0	)		1,903.5
Total external debt	2,128.6			(14.7	)		2,113.9

Outstanding debt as at December 31, 2014
(In $ millions)	Principal outstanding			Less: Debt Issuance Costs			Total Debt
Current portion of long-term debt	218.1			(7.9	)		210.2
Long-term portion of debt	2,203.6			(15.4	)		2,188.2
Total external debt	2,421.7			(23.3	)		2,398.4

The outstanding debt as of December 31, 2015 is repayable as follows:

(In millions of U.S. dollars)	Year ending December 31,
Year ended December 31, 2016	218.1
Year ended December 31, 2017	1,080.8
Year ended December 31, 2018	218.4
Year ended December 31, 2019	807.3
Year ended December 31, 2020	—
Year ended December 31, 2021 and thereafter	125.0
Total debt	2,449.6

Credit facilities

$2,000 million senior secured credit facility

In April 2011, a $2,000 million senior secured credit facility was entered into with Seadrill to fund the Company’s acquisition of West Phoenix , West Navigator , West Alpha , West Epsilon , West Venture , and West Elara , which have been pledged as security . As at December 31, 2015 the net book value of units pledged as security was $2,178.9 million . The $2,000 million senior secured credit facility has a 6 year term payable quarterly with a balloon payment of $950 million at maturity. The loan bears interest of Libor plus 2.0%  per annum. As at December 31, 2015 , the outstanding balance under the facility was $1,200 million , compared to $1,366.7 million as at December 31, 2014 . We had $50 million undrawn under this facility as of December 31, 2015 , which bears a commitment fee of 40% of the margin. The Company is restricted from using this undrawn capacity, however, due to restrictive covenants within the indentures of Seadrill's USD bonds - refer to the section below "Covenants on credit facilities and bonds" for further information.

In February 2015, North Atlantic Drilling received approval to amend its $2,000 million Senior Secured Credit Facility. Under the terms of the agreement, Seadrill has provided a guarantee for the credit facility in exchange for amendments to the covenant package, principally replacing the existing financial covenants with financial covenants within Seadrill's secured credit facilities. The guarantee fee charged by Seadrill is 0.3% per annum of the outstanding principal.

$475 million secured term loan

In October 2013 , SFL Linus Ltd entered into a $475 million secured term loan and revolving credit facility with a syndicate of banks to fund the acquisition of West Linus , which has been pledged as security. As at December 31, 2015 the net book value of the West Linus pledged as security was $559.1 million . SFL Linus Ltd drew down on the loan at the delivery date of the rig in February 2014. The facility bears interest of LIBOR plus a margin of 2.75% and is repayable over a term of five years . A balloon of $192 million payable on maturity in June 2019 . SFL Linus Ltd. entered into interest swap arrangements in July, 2013, in order to mitigate exposure to variability in cash flows for future interest payments on this loan. Refer also to Note 22 - Risk management and financial instruments for additional details. During the year ended December 31, 2015 draw downs of $41.0 million were made from the revolving credit facility and the Company made repayments totaling $138.3 million . As at December 31, 2015 , the outstanding balance under the facility was $354.0 million , compared to $451.3 million as at December 31, 2014 . There is no undrawn capacity on this facility at December 31, 2015 .

F-23

---

In February 2015, North Atlantic Drilling received approval to amend its $475 million Credit Facility. Under the terms of the agreement, Seadrill provides a guarantee for the facility in exchange for amendments to the covenant package, principally replacing the Company's financial covenants with financial covenants within Seadrill's secured credit facilities. The guarantee fee charged by Seadrill is 0.3% per annum of the outstanding principal.

Unsecured Bonds

NOK 1,500 million Senior Unsecured Bond

On October 30, 2013, a NOK 1,500 million senior unsecured bond was issued with maturity date October 2018. The bond bears interest at 3-months NIBOR plus a margin of 4.40% . The bond was subsequently swapped to US$ with a fixed rate of 6.18% per annum until maturity. The net proceeds were used to repay the remaining outstanding amount under our Seadrill Revolving Credit Facility. During fourth quarter of 2014, Seadrill purchased in the open market a total of 5.5% ownership in the NOK 1,500 million Senior Unsecured Bond. As at December 31, 2015 , Seadrill is the holder of 5.5% of the bond, which amounts to $9.4 million ( December 31, 2014 : 5.5% or $11.0 million ).

In February 2015, the Company received approval from its Norwegian bondholders to amend the bond agreement for its NOK 1,500 million Senior Unsecured Bond maturing in 2018. Under the terms of the agreement, Seadrill has provided a guarantee for the bond issue in exchange for amendments to the covenant package, principally replacing the current financial covenants with the financial covenants within Seadrill's NOK bonds. The guarantee fee charged by Seadrill is 0.3% per annum of the outstanding principal.

$600 million 6.25% Senior Unsecured Notes due 2019

On January 31, 2014, a $600 million senior unsecured bond was issued with maturity date January 2019. The notes bear a fixed coupon of 6.25% . The notes were listed on the Irish Stock Exchange on July 1, 2014. The net proceeds of this offering have been used to repay the $500 million 7.7% Bond, including a settlement premium of $22.5 million . As of December 31, 2015 Seadrill held 31.1% of the bond, which amounts to $186.6 million ( December 31, 2014 : 31.1% or $186.6 million ).

The $600 million 6.25% Senior Unsecured Notes due 2019 are subject to certain financial and restrictive covenants contained in our indentures which restrict, among other things, our ability to pay dividends, incur indebtedness, incur liens, and make certain investments. In addition, these indentures contain other customary terms, including certain events of default, upon the occurrence of which, the bonds may be declared immediately due and payable.

In addition to the above, our bond indentures generally also contain restrictions which are customary for unsecured financings in this industry for similar unrated bonds, including limitations on indebtedness, payments, transactions with affiliates and restrictions on consolidation, merger and sale of assets.

Related party loans

$85 million Seadrill Revolving Credit Facility

Seadrill has provided North Atlantic an unsecured revolving shareholder loan of $85 million . The maturity date is set to January 30, 2015. The facility was increased from $200 million to $335 million on June 28, 2013, and then decreased to $85 million on November 20, 2013. The terms of the remaining facility of $85 million are the same as stated in the original agreement dated March 30, 2012. The interest is Libor plus 3.0%  per annum. Aggregate drawdowns and repayments on this facility during the year ended December 31, 2015 were $0 million and $0 million , respectively. The facility matured in January 30, 2015 .

SFL Linus Ltd

Ship Finance granted the VIE company, SF Linus Ltd, a loan of $195 million on June 28, 2013 to be repaid at the earlier of June 30, 2029 or date of sale of the West Linus rig. The loan did not bear interest until the rig was delivered from the yard. SFL Linus Ltd. repaid $70 million during the first quarter in 2014. The outstanding balance at December 31, 2015 is $125 million ( December 31, 2014 : $125 million ). The proceeds of this loan was used to finance the acquisition of the West Linus. The loan is presented as debt to related parties on our balance sheet on December 31, 2015 .

F-24

---

Covenants on credit facilities and unsecured bonds

Our credit facilities generally contain financial covenants as well as security provided to lenders in the form of pledged assets.

Bank Loans

In February 2015, we received approval to amend the agreements for our NOK 1,500 million senior unsecured bond, $2,000 million Senior Secured Credit Facility, and $475 million secured term loan. Under the terms of each agreement, Seadrill provides guarantees for the bonds and credit facility in exchange for amendments to the covenant package, principally replacing the current financial covenants with Seadrill's financial covenants, which are measured at the Seadrill consolidated level. In May 2015, Seadrill executed an amendment to the covenants contained in all of its secured credit facilities.

As such the main financial covenants contained in our credit facilities are as follows:

•	Aggregated minimum liquidity requirement for the Seadrill group: to maintain cash and cash equivalents of at least $150 million within the Seadrill group.

•	Interest coverage ratio: to maintain an EBITDA to interest expense ratio of at least 2.5 .

•	Current ratio: to maintain current assets to current liabilities ratio of at least 1 . Current assets are defined as book value less minimum liquidity, but including up to 20% of shares in listed companies owned 20% or more. Current liabilities are defined as book value less the current portion of long term debt.

•	Equity ratio: to maintain total equity to total assets ratio of at least 30% . Both equity and total assets are adjusted for the difference between book and market values of drilling units.

•	Leverage ratio: to maintain a ratio of net debt to EBITDA. Net debt is calculated as all interest bearing debt less cash and cash equivalents excluding minimum liquidity requirements.

◦	6.0 :1, from and including the financial quarter starting on July 1, 2015 and including the financial quarter ending on September 30, 2016;

◦	5.5 :1, from and including the financial quarter starting on October 1, 2016 and including the financial quarter ending December 31, 2016;

◦	4.5 :1, from and including the financial quarter starting on January 1, 2017 until the final maturity date.

In connection with the amendment made in May 2015, effective from July 1, 2015, an additional margin may be payable on the senior secured credit facilities as follows:

•	0.125% per annum if the leverage ratio is 4.50 :1 up to and including 4.99 :1;

•	0.25% per annum if the leverage ratio is 5.00 :1 up to and including 5.49 :1;

•	0.75% per annum if the leverage ratio is 5.50 :1 up to and including 6.00 :1

In addition, as part of the amendments to the covenants contained in the Company’s senior secured credit facilities in May 2015, the Company is restricted from making dividend distributions during the waiver period until January 1 2017.

On April 28, 2016, Seadrill and the Company executed amendment and waiver agreements in respect of all of its senior secured credit facilities. The maturity of our $2 billion senior secured credit facility has been extended to June 30, 2017. In addition, the key terms and conditions of these agreements are as follows:

•

Equity ratio : Seadrill is required to maintain a total equity to total assets ratio of at least 30.0% . Prior to the amendment, both total equity and total assets are adjusted for the difference between book and market values of drilling units, as determined by independent broker valuations. The amendment removes the need for the market value adjustment from the calculation of the equity ratio until June 30, 2017.

•	Leverage ratio : the Seadrill is required to maintain a ratio of net debt to EBITDA. Prior to the amendment the leverage ratio had to be no greater than 6.0 :1, falling to 5.5 :1 from October 1, 2016, and falling again to 4.5 :1 from January 1, 2017. The amendment retains the ratio at 6.0 :1 until December 31, 2016, and then increases to 6.5 :1 between January 1, 2017 and June 30, 2017.

•

Minimum-value-clauses : Seadrill's and the Company's secured bank credit facilities contain loan-to-value clauses, or minimum-value-clauses (“MVC”), which could require the Seadrill and the Company to post additional collateral or prepay a portion of the outstanding borrowings should the value of the drilling units securing borrowings under each of such agreements decrease below required levels. This covenant has been suspended until June 30, 2017.

•	Minimum Liquidity : The aggregated minimum liquidity requirement for the group to maintain cash and cash equivalents of at least $150 million has been increased to $250 million .

F-25

---

Additional undertakings:

•	Further process : Seadrill and the Company has agreed to consultation, information provision and certain processes in respect of further discussions with its lenders under its senior secured credit facilities.

•	Restrictive undertakings : Seadrill and the Company has agreed to additional near-term restrictive undertakings applicable during this process, including (without limitation) limitations in respect of:

◦	dividends, share capital repurchases and total return swaps;

◦	investments in, extensions of credit to or the provision of financial support for non-wholly owned subsidiaries;

◦	investments in, extensions of credit to or the provision of financial support for joint ventures or associated entities;

◦	acquisitions;

◦	dispositions;

◦	prepayment, repayment or repurchase of any debt obligations;

◦	granting security; and

◦	payments in respect of newbuild drilling units,

in each case, subject to limited exceptions.

•	Other changes and provisions:

◦	Undrawn availability : Seadrill and the Company has agreed to refrain from borrowing any undrawn commitments under its senior secured credit facilities.

◦	Fees : The Company has agreed to pay certain fees to its lenders in consideration of these extensions and amendments.

These extensions and amendments are designed to provide Seadrill and the Company and the banking group with a period of stability and certainty while a more comprehensive financing package is agreed. Seadrill and the Company intends to further communicate these financing plans this year.

For the purposes of the above tests, EBITDA is defined as the earnings before interest, taxes, depreciation and amortization on a consolidated basis and (ii) the cash distributions from investments, each for the previous period of twelve months as such term is defined in accordance with accounting principles consistently applied. However, in the event that Seadrill or a member of the group acquires rigs or rig owning entities with historical EBITDA available for the rigs' previous ownership, such EBITDA shall be included for covenant purposes in the relevant loan agreement, and if necessary, be annualized to represent a twelve (12) month historical EBITDA. In the event that Seadrill or a member of the group acquires rigs or rig owning companies without historical EBITDA available, Seadrill is entitled to base a twelve month historical EBITDA calculation on future projected EBITDA only subject to any such new rig having (i) a firm charter contract in place at the time of delivery of the rig, with a minimum duration of twelve months, and (ii) a firm charter contract in place at the time of such EBITDA calculation, provided Seadrill provides the agent bank with a detailed calculation of future projected EBITDA. Further, EBITDA shall include any realized gains and/or losses in respect of the disposal of rigs or the disposal of shares in rig owning companies.

Cash distributions from investments are defined as cash received by Seadrill, by way of dividends, in respect of its ownership interests in companies which Seadrill does not control but over which it exerts significant influence.

Our credit facilities and bonds contain customary restrictive covenants which that limit, among other things, our ability to:

•	incur additional indebtedness;

•	sell the mortgaged drilling rig, if applicable;

•	make additional investments or acquisitions;

•	pay dividends; and

•	effect a change of control in the Company.

A failure to comply with the covenants in our loan agreements could result in a default under those agreements and under other debt agreements containing cross-defaults provisions.

Our $2,000 million senior secured credit facility is secured by:

•	Guarantee provided by Seadrill Limited

•	Guarantees from the drilling rig owning subsidiaries and intra-group charterers (guarantors);

•	A first priority share charge over all of the shares issued by each of the guarantors;

•	A first priority mortgage in all collateral drilling units and any deed of covenant or general assignment thereto;

•	A first priority assignment of the earnings which arise out of the use of or operation of any of the collateral drilling units;

•	A first priority assignment of the bareboat charter contracts for the collateral drilling units;

•	A security interest in the earnings accounts; and

F-26

---

•	A first priority assignment of all of the insurance policies and contracts of insurance in respect of the collateral drilling units.

The $2,000 million senior secured credit facility also contains a loan-to-value clause, which could require the Company, at its option, to post additional collateral or prepay a portion of the outstanding borrowings should the value of the drilling units securing borrowings under each of such agreements decrease below required levels. The market value of the rigs must be at least 135% of the loan outstanding.

We were in compliance with all financial loan covenants as of December 31, 2015 .

Bonds

For the Company’s outstanding NOK 1,500 million Senior Unsecured Bond, the main financial covenant is for Seadrill to maintain a total equity to total assets ratio of at least 30.0% . Both equity and total assets are adjusted for the difference between book value and market values of drilling units.

For the Company’s outstanding $600 million Senior Unsecured Notes, we are subject to certain financial and restrictive covenants contained in our indentures which restrict, among other things, our ability to pay dividends, incur indebtedness, incur liens, and make certain investments. In addition, these indentures contain other customary terms, including certain events of default, upon the occurrence of which, the bonds may be declared immediately due and payable.

Additionally, we are a “restricted subsidiary” under the indenture relating to Seadrill’s 1,000 million 5  ⁵ / ₈ % Senior Notes due 2017 and 500 million 6  ¹ / ₈ % Senior Notes due 2020. While we are not a guarantor of the notes or a party to the indentures thereto, Seadrill has agreed to cause us to comport with the restrictions on “restricted subsidiaries” contained in the indenture. Accordingly, Seadrill may use its influence over us to restrict our ability, among other things, to incur additional debt, pay dividends or issue guarantees, if Seadrill is required to do so under the terms of the indenture for the notes.

The Company and Seadrill were in compliance with all financial and other covenants as included within the amended credit facilities and bond agreements as tested by reference to the financial statements as of December 31, 2015 .

Covenants contained in the credit facility of SFL Linus Ltd., our consolidated VIE

On October 17, 2013, SFL Linus Ltd. entered into a $475 million secured term loan and revolving credit facility with a syndicate of banks to fund the acquisition of the West Linus , which has been pledged as security. Seadrill Limited is the Charter Guarantor under this facility. While we are not, directly or indirectly, obligated to repay the borrowings under this facility, a breach of one or more of the covenants contained in this credit facility may have a material adverse affect on us. See “Item 3. Key Information-D. Factors-Failure to comply with covenants and other provisions in our existing or future debt agreements, including the senior unsecured notes, could result in cross-defaults under our existing debt agreements, which would have a material adverse affect on us.”

In February 2015, we received approval to amend the agreements for our $475 million credit facility. Under the terms of the agreement, Seadrill will provide a guarantee in exchange for amendments to the covenant package, principally replacing the current financial covenants with Seadrill's financial covenants. These covenants are the same as the NOK 1,500 million Senior Unsecured Bond and $2,000 million Senior Secured Credit Facility given above.

The Company, Seadrill and SFL Linus Ltd. complied with all financial and other covenants as included within the amended credit facility as tested by reference to the financial statements as of December 31, 2015 .

Note 15 – Other current liabilities

(In millions of U.S. dollars)	December 31, 2015			December 31, 2014
Derivative financial instruments 1	124.5			109.4
Accrued interest expense	17.9			19.5
Accrued expenses	22.5			65.6
Employee withheld taxes, social security and vacation payment	18.7			33.2
Withheld business taxes	6.6			20.2
Short term portion of deferred revenues	21.6			19.9
Total other current liabilities	211.8			267.8

(1)	Derivative financial instruments consist of unrealized losses on interest rate swaps, cross currency swaps and foreign exchange rate forwards. Additional disclosure has been provided in Note 22 .

F-27

---

Note 16 – Other non-current liabilities

(In millions of U.S. dollars)	December 31, 2015			December 31, 2014
Deferred revenue	19.9			39.9
Derivative financial instruments (1)	2.3			2.5
Total non-current liabilities	22.2			42.4

(1)	Derivative financial instruments consist of unrealized losses on interest rate swaps. Additional disclosure has been provided in Note 22 .

Note 17 – Common share capital

	December 31, 2015						December 31, 2014
	Common shares of par value $0.10						Common shares of par value $5.00
	Shares			US$ millions			Shares			US$ millions
Authorized share capital	100,000,000			10.0			400,000,000			2,000.0
Issued and fully paid share capital	24,351,618			2.4			243,516,514			1,217.6
Treasury shares held by Company	(237,386	)		0.0			(2,373,863	)		(11.9	)
Outstanding shares in issue	24,114,232			2.4			241,142,651			1,205.7

As of December 31, 2012, the Company's shares were listed on the Norwegian OTC list. On January 29, 2014, the Company completed its initial public offering in the United States. The total number of shares issued by the Company as of December 31, 2013 consisted of 3,000 shares issued upon formation of the Company, 50,000,000 shares issued to the general public in a private placement during February 2011, 150,000,000 shares issued to Seadrill as part of the consideration for the transfer of the business to the Company on March 31, 2011, 30,000,000 shares issued in a private placement during March 2012 and 13,513,514 shares issued when North Atlantic Drilling completed its initial public offering on the New York Stock Exchange on January 29, 2014.

 

After incorporation, the Company repurchased shares that may be canceled or held as treasury shares. As of December 31, 2015 and the Company held 237,386 common shares as treasury shares at cost ( December 31, 2014 : 2,373,863 treasury shares).

The Company’s shareholders passed a resolution at the annual general meeting held on September 21, 2012, authorizing the reduction of the Company’s share premium account from $834.3 million to $0 million and an increase in the Company’s contributed surplus account of $834.3 million , with immediate effect, the purpose of which was primarily to increase the ability of the Company to declare and distribute dividends to its shareholders.

The Company’s contributed deficit account originally amounted to $2,000.0 million and relates to the difference between the carrying value of net assets purchased and the consideration paid for the businesses acquired in the North Atlantic Restructuring. This account will not be netted against future earnings and does not restrict the Company’s ability to pay dividends. Following the recognition of certain common control transactions in 2011, 2012, and 2013, the contributed deficit has been reduced to $10.0 million .

Reverse stock split and capital reduction

In December 2015 the shareholders in a special general meeting approved a capital reorganization including a 1-for- 10 reverse stock split of the Company's issued and outstanding common shares and reducing par value from $5.00 to $0.10 . In addition the total authorized share capital was reduced from $2,000.0 million to $10.0 million .

As a result of the capital restructuring the number of shares outstanding has fallen from 241,142,651 to 24,114,232 . As a result, the issued share capital of the Company has fallen from $1,205.7 million to $2.4 million , and the contributed surplus has been increased by $1,203.3 million .

F-28

---

Note 18 – Accumulated Other Comprehensive Loss

(In millions of U.S. dollars)	December 31, 2015			December 31, 2014
Actuarial loss relating to pension	(23.7	)		(58.6	)
Total accumulated other comprehensive loss	(23.7	)		(58.6	)

For the actuarial loss related to pension, the accumulated applicable amount of income taxes related to companies domiciled in Norway, where the tax rate is 25% , amounted to $7.9 million at December 31, 2015 ( December 31, 2014 : tax rate of 27% , deferred tax asset of $21.7 million ).

Note 19 – Share based compensation

Share Option Plan

The Board resolved, in its meeting on February 14, 2011, to establish a share option based incentive scheme for the Company’s employees and directors, approved a set of rules applicable to the scheme and reserved 6,000,000 of its authorized, but unissued share for use to satisfy future exercises of options granted under the scheme.

Further, the Board resolved that options granted prior to the listing of the Company’s shares could be granted at an exercise price equal to the subscription price in the private placement. No options have been granted under the scheme in 2015 , 2014 or 2013 . However, the Company did recognize a charge for share options granted at the Seadrill Ltd level related to North Atlantic employees of $0.6 million , $0.8 million and $0.5 million in 2015 , 2014 and 2013 , respectively.

In December 2015 the shareholders of NADL in a special general meeting approved a capital reorganization including a 1-for- 10 reverse stock split of the Company's issued and outstanding common shares and reducing par value from $5.00 to $0.10 . As a result of the capital restructuring the number of authorized, but unissued, share options has been adjusted to 600,000 .

Restricted Stock Units

On November 7, 2013, the Board of the Company approved 278,778 awards under North Atlantic Drilling`s Restricted Stock Units (“RSU”) plan.  During 2015, the Board of the Company approved a further 1,587,719 awards under North Atlantic Drilling`s Restricted Stock Units (“RSU”) plan. 

Under the terms of the plan, the holder of an award is entitled to receive a share in the respective company if still employed at the end of the three year vesting period.  There is no requirement for the holder to pay for the share on grant date or upon vesting of the award.  In addition the holder is entitled to receive an amount equal to the ordinary dividends declared and paid on the Company's shares during the vesting period.

In December 2015 the shareholders of NADL in a special general meeting approved a capital reorganization including a 1-for- 10 reverse stock split of the Company's issued and outstanding common shares and reducing par value from $5.00 to $0.10 . As a result of the capital restructuring the number of RSUs has been adjusted by 1,571,251 units.

The fair value of the awards are calculated based on the market share price on grant date which was US$9.46 for the RSUs issued in 2013, US$1.33 for the RSUs granted in April 2015 and US$0.37 for the RSUs granted in December 2015.

The fair value of the awards expected to vest is recognized as compensation cost straight-line over the vesting period.  All awards are currently expected to vest. Compensation cost related to the RSU plans of $0.6 million has been recognized in 2015 , 2014 $0.8 million and 2013 $0.1 million . As of December 31, 2015 and December 31, 2014 there was $1.2 million and $1.7 million respectively of unrecognized compensation costs related to non-vested awards.

The following table summarizes RSU activity for the years ended December 31, 2015 , 2014 and 2013 :

Restricted Stock Units	2015			2014			2013
Outstanding at beginning of year	253,870			278,778			—
Granted	1,587,719			—			278,778
Forfeited	(95,755	)		(24,908	)		—
Adjustment *	(1,571,251	)		—			—
Outstanding at end of year	174,583			253,870			278,778

F-29

---

* Adjustment relates to the Company's 1 for 10 reverse stock split completed in December 2015.

Note 20 - Pension benefits

Defined benefit plans

The Company has several defined benefit pension plans covering substantially all Norwegian employees. All off the plans are administered by a life insurance company. Under these plans, the Company contributes to the employee’s pension plan amounts ranging between five to eight percent of the employee’s annual salary.

 

For onshore employees in Norway, continuing with the defined benefits plan, the primary benefits are retirement pension of approximately 66% of salary at retirement age of 67 years, together with a long-term disability pension. The retirement pension per employee is capped at an annual payment of 66% of the total of 12 times the Norwegian Social Security Base. Most employees in this group may choose to retire at 62 years of age on a pre-retirement pension. Offshore employees in Norway have retirement and long-term disability pension of approximately 60% of salary at retirement age of 67 . Offshore employees on mobile units may choose to retire at 60 years of age on a pre-retirement pension.

Annual pension cost

The expenses for our defined benefit pension plans for the years ended December 31, 2015 , 2014 and 2013 were as follows:

	Year ended December 31,
(In millions of U.S. dollars)	2015			2014			2013
Benefits earned during the year	12.2			16.6			14.9
Interest cost on prior years' benefit obligation	3.5			6.8			6.3
Gross pension cost for the year	15.7			23.4			21.2
Expected return on plan assets	(3.2	)		(5.8	)		(4.7	)
Administration charges	0.8			0.9			0.5
Net pension cost for the year	13.3			18.5			17.0
Social security cost	1.9			2.6			2.4
Amortization of actuarial gains/losses	3.4			2.2			1.5
Amortization of prior service cost	—			—			(0.4	)
Total net pension cost	18.6			23.3			20.5

The funded status of the defined benefit plan

(In millions of U.S. dollars)	December 31, 2015			December 31, 2014
Projected benefit obligations	129.8			186.5
Plan assets at market value	(97.0	)		(113.8	)
Accrued pension liability exclusive social security	32.8			72.7
Social security related to pension obligations	4.6			10.2
Accrued pension liabilities	37.4			82.9

Change in benefit obligations

(In millions of U.S. dollars)	December 31, 2015			December 31, 2014
Benefit obligations at beginning of year	186.5			176.1
Interest cost	3.5			6.8
Current service cost	12.2			14.0
Benefits paid	(1.9	)		(1.9	)
Change in unrecognized actuarial loss	(20.0	)		23.5
Settlement	(20.2	)		—
Foreign currency translations	(30.3	)		(32.0	)
Benefit obligations at end of year	129.8			186.5

F-30

---

Change in plan assets

(In millions of U.S. dollars)	December 31, 2015			December 31, 2014
Fair value of plan assets at beginning of year	113.8			125.8
Expected return on plan assets	3.2			4.9
Contribution by employer	11.7			16.9
Administration charges	(0.8	)		(0.9	)
Benefits paid	(1.9	)		(2.0	)
Change in unrecognized actuarial (loss) gain	—			(8.9	)
Settlement	(11.2	)		—
Foreign currency translations	(17.8	)		(22.0	)
Fair value of plan assets at end of year	97.0			113.8

The accumulated benefit obligation for all defined benefit pension plans was $101.1 million and $146.4 million at December 31, 2015 and 2014 , respectively.

Pension obligations are actuarially determined and are critically affected by the assumptions used, including the expected return on plan assets, discount rates, compensation increases and employee turnover rates. The Company periodically reviews the assumptions used, and adjusts them and the recorded liabilities as necessary.

During the year a number of employees left the Company and as a result the defined benefit scheme transferred the pension liability for these employees to the life insurance company administering the scheme. The difference between the reduction in benefit obligation and the plan assets transferred to the life insurance company has been recognized within "Other comprehensive income". The settlement is not deemed to be significant in the context of the overall scheme and as such net unrecognized actuarial losses have not been recycled as a result of the settlement.

The expected rate of return on plan assets and the discount rate applied to projected benefits are particularly important factors in calculating the Company's pension expense and liabilities. The Company evaluates assumptions regarding the estimated rate of return on plan assets based on historical experience and future expectations on investment returns, which are calculated utilizing the asset allocation classes held by the plan's portfolios. The discount rate is based on the covered bond rate in Norway. Changes in these and other assumptions used in the actuarial computations could impact the projected benefit obligations, pension liabilities, pension expense and other comprehensive income.

Assumptions used in calculation of pension obligations	2015			2014			2013
Rate of compensation increase at the end of year	2.50	%		2.75	%		3.75	%
Discount rate at the end of year	2.70	%		2.30	%		4.00	%
Prescribed pension index factor	1.20	%		1.20	%		1.40	%
Expected return on plan assets for the year	3.30	%		3.20	%		4.40	%
Employee turnover	4.00	%		4.00	%		4.00	%
Expected increases in Social Security Base	2.50	%		2.50	%		3.50	%

The weighted-average asset allocation of funds related to the Company's defined benefit plan at December 31, 2015 and 2014 was as follows:

Pension benefit plan assets	2015			2014
Equity securities	6.1	%		7.1	%
Debt securities	47.5	%		53.4	%
Real estate	14.7	%		15.0	%
Money market	25.2	%		22.4	%
Other	6.5	%		2.1	%
Total	100.0	%		100.0	%

F-31

---

The investment policies and strategies for the pension benefit plan funds do not use target allocations for the individual asset categories. The investment objectives are to maximize returns subject to specific risk management policies. The Company diversifies its allocation of plan assets by investing in both domestic and international fixed income securities and domestic and international equity securities. These investments are readily marketable and can be sold to fund benefit payment obligations as they become payable. The estimated yearly return on pension assets was 3.3% in 2015 and 3.2% in 2014 .

Cash flows - Contributions expected to be paid

The table below shows the Company's expected annual pension plan contributions under defined benefit plans for the years 2016 - 10 . The expected payments are based on the assumptions used to measure the Company's obligations at December 31, 2015 and include estimated future employee services.

(In millions of U.S. dollars)	Years ending December 31,
2016	11.7
2017	12.1
2018	12.3
2019	12.6
2020	12.9
2021 - 10.0	69.7
Total payments expected during the next 10 years	131.3

Defined contribution plans

In addition, the Company has defined contribution plans for all new onshore employees. Total payments to this plan were $0.5 million , $0.9 million and $1.2 million for the years ended December 31, 2015 , 2014 and 2013 , respectively.

Note 21 – Related party transactions

We are a majority owned subsidiary of Seadrill, which owns approximately 70.4% of our outstanding common shares as of the date of this Annual Report. The Company transacts business with the following related parties, being companies in which are affiliated with Seadrill and Seadrill's principal shareholder Hemen Holding Ltd (hereafter jointly referred to as "Hemen"):

•	Seadrill Limited

•	Ship Finance International Limited ("Ship Finance")

•	Metrogas Holdings Inc ("Metrogas")

•	Frontline Management (Bermuda) Limited ("Frontline")

•	Seatankers Management Norway AS ("Seatankers")

•	Archer Limited ("Archer")

•	Sevan Drilling Limited ("Sevan")

The Company has entered into the following significant agreements with related parties:

Transactions with Seadrill

$500 million 7.75% Bond

In April 2011 the Company issued a $500 million bond with a fixed coupon rate of 7.75% per annum, payable semi-annually in arrears. Seadrill was the holder of the entire bonds. The bond was repaid on January 31, 2014, including a settlement premium of $22.5 million , which was settled in cash.

$600 million 6.25% Senior Unsecured Notes due 2019

In January 2014 the Company issued a $600 million Senior Unsecured Notes with a fixed coupon of 6.25% per annum, and maturity in January 2019. As of December 31, 2015 Seadrill was the holder of 31.1% of the notes, which amounts to $186.6 million ( December 31, 2014 : 31.1% , or $186.6 million ). Interest due to Seadrill for the year ended December 31, 2015 was $11.7 million ( December 31, 2014 : $8.9 million ).

F-32

---

$85 million Seadrill Revolving Credit Facility

Seadrill provided the Company an unsecured revolving credit facility of $200 million in March 2012. The facility was increased from $200 million to $335 million on June 28, 2013, and then decreased to $85 million on November 20, 2013. The terms of the remaining facility of $85 million are the same as stated in the original agreement dated March 30, 2012. Aggregate draw downs and repayments on this facility during the year ended December 31, 2015 were $0 million and $0 million , respectively. The interest of the facility was Libor plus 3.00% per annum. Interest and commitment fee charged relating to the shareholder loan from Seadrill for the year ended December 31, 2015 amounted to $0.1 million ( December 31, 2014 : $1.0 million ). This credit facility matured on January 30, 2015.

NOK 1,500 million Senior Unsecured Bond

On October 30, 2013, the Company issued a NOK 1,500 million Senior Unsecured Bond with maturity date October 2018. The bond bears interest at 3-months NIBOR plus a margin of 4.40% . The net proceeds were used to repay the remaining outstanding amount under our $85 million Seadrill Revolving Credit Facility. During fourth quarter of 2014, Seadrill purchased in the open market an aggregate of 5.5% ownership in the NOK 1,500 million Senior Unsecured Bond equal to $11 million . As at December 31, 2015 , Seadrill is the holder of 5.5% of the bond, which amounts to $9.4 million ( December 31, 2014 : 5.5% or $11.0 million ). Interest due to Seadrill for the year ended December 31, 2015 was $0.4 million ( December 31, 2014 : nil ).

Financial covenants and debt guarantees

In February 2015, the Company received approval from its Norwegian Bondholders to amend the Bond Agreement for its NOK 1,500 million Norwegian Bond maturing in 2018. Under the terms of the agreement, Seadrill will provide a guarantee for the Bond Issue in exchange for amendments to the covenant package, principally replacing the current financial covenants with the financial covenants within Seadrill's NOK bonds. Additionally, the Company received approval to amend its $2,000 million credit facility and $475 million secured term loan and revolving credit facility. Under the terms of the agreements, Seadrill provides a guarantee for the credit facilities in exchange for amendments to the covenant package, principally replacing the Company's existing financial covenants with financial covenants within Seadrill's secured credit facilities. This amendment to the covenants was applicable to the period ended December 31, 2014. As such there are no longer separate financial covenants contained within the Company's credit facilities or bond agreements. The guarantee fees charged by Seadrill is 0.3% per annum of the outstanding principal. The total guarantee fee for the year months ended December 31, 2015 was $3.9 million ( December 31, 2014 : nil ). These fees are presented with "other financial items" in the statement of operations.

Performance guarantees

Seadrill provides performance guarantees in connection with the Company’s drilling contracts, and charges the Company an annual fee of 1% of the guaranteed amount to provide these guarantees. The total amount of such guarantees was $200 million at December 31, 2015 and $250 million at December 31, 2014 . The incurred fee was $2.1 million and $2.5 million or the years ended December 31, 2015 and 2014 respectively. In addition, the Company has agreed to reimburse Seadrill for all claims made against Seadrill under the performance guarantees. These fees are presented with "other financial items" in the statement of operations.

Operation and Management of the West Hercules

The West Hercules, a harsh environment, semi-submersible drilling rig, is owned by a wholly-owned subsidiary of Ship Finance, a related party, and is controlled by Seadrill through a bareboat charter agreement that expires in 2023. Until October 31, 2013, the company operated and managed this rig pursuant to an operational bareboat charter agreement that the Company entered into with Seadrill in July 2012. Subsequently the company entered into a management agreement with Seadrill which replaced the bareboat charter agreement effective from November 1, 2013, pursuant to which the Company operated and managed the West Hercules when it was employed under the drilling contract with Statoil.

The key terms of the agreement were:

•	Seadrill is obligated to pay North Atlantic a daily management fee.

•	North Atlantic is entitled to a potential bonus based on economical utilization of the operations.

•	All crew services shall be provided by North Atlantic and charged to Seadrill at cost plus a margin of 7% .

•	All direct costs related to the operations shall be charged to Seadrill at cost.

•	Operational risks are obligations of Seadrill.

•	Capital expenditures and long term maintenance associated with the rig are obligations of Seadrill.

•	North Atlantic is entitled to receive and keep all agreed mark-up fee for provision of additional services

under the Drilling Contract which are payable by the client.

Under the management agreement, North Atlantic Drilling has charged Seadrill a management fee of $7.1 million and crew costs of $37.8 million for the year ended December 31, 2014. In August 2014, the operation and management of the West Hercules was transferred to Seadrill.

Management services

North Atlantic Management provides all day-to-day management functions to the Company and its subsidiaries in accordance with the terms of the General Management Agreement. North Atlantic Management has contracted in senior management services from Seadrill Management in accordance with the terms of the Management and Administrative Services Agreement. The agreement can be terminated by either party at ninety days notice. In consideration of the services provided, the Company pay Seadrill a fee that includes the operating costs attributable to the Company plus a margin of 8% . Seadrill Management had charged North Atlantic Management a fee of $25.0 million , $27.6 million and $32.4 million for providing the services under the Services Agreement for the years ended December 31, 2015 , 2014 and 2013 respectively.

F-33

---

Newbuild construction services

The Company has contracted a subsidiary of Seadrill to provide construction and project management services for construction of the West Rigel drilling unit. In consideration of the services provided Seadrill has charged the Company a fee that includes the operating costs attributable to the Company plus a margin of 5% . The total amount charged was $12.4 million , $9.3 million and $3.4 million for the years ended December 31, 2015 , 2014 and 2013 respectively. As these costs are directly attributable to the construction of the drilling unit, they are capitalized and depreciated in accordance with the accounting policy for Drilling Units.

Transactions with Frontline

Management services

The Company receives corporate secretarial and certain other administrative services applicable to the jurisdiction of Bermuda from Frontline Management (Bermuda) Ltd. The fee was $1.2 million , $1.3 million and $0.1 million for the years ended December 31, 2015 , 2014 and 2013 respectively. Frontline Management (Bermuda) Ltd. is a wholly owned subsidiary of Frontline Ltd., a company in which Hemen is a large shareholder.

Transactions with Sevan Drilling

Management services

Pursuant to the secondment agreement with Seven Drilling our Chief Financial Officer has been seconded to North Atlantic Management from Sevan Drilling Management AS, a subsidiary of Seadrill and Sevan Drilling Limited The fee was $0.2 million, nil and nil for the years ended December 31, 2015 , 2014 and 2013 respectively.

Transactions with Seatankers

Management services

The Company receives corporate management and director services through Seatankers Management Norway AS. The fee was $0.2 million , nil and nil for the years ended December 31, 2015 , 2014 and 2013 respectively. Seatankers Management Norway AS a company which is an affiliate of Hemen.

Transactions with Ship Finance

Sale and leaseback agreement

In June 2013, the Company entered into sale and leaseback agreement with Ship Finance for the newbuilding jack-up rig, the West Linus for total consideration of $600 million . Upon the closing of the agreement, $195 million was paid to North Atlantic Drilling and the remaining balance of the purchase price was paid to North Atlantic Drilling upon the delivery of the rig. The West Linus is chartered back to North Atlantic Drilling on a bareboat charter for a period of 15 years , pursuant to which North Atlantic has been granted four purchase options. Ship Finance has an option to sell the rig back to North Atlantic Drilling at the end of the charter period. The West Linus was delivered from the yard in February 2014. At December 31, 2015 , the West Linus is reported under Drilling Units in the Company’s balance sheet. Additional disclosure about the VIE has been provided in Note 24 .

Seadrill provided a guarantee in the principal amount of up to $525 million issued in favor of Ship Finance, which was payable in the event that the West Linus was not unconditionally accepted by the charterer by June 30, 2014. The guarantee provided by Seadrill commenced on February 13, 2014 and expired in May 2014.

Related Party Loan Facility

Ship Finance granted the VIE company, SFL Linus Ltd., an unsecured loan of $195 million on June 28, 2013 to be repaid at the earlier of June 30, 2029 or date of sale of the West Linus rig. While the loan did not initially bear interest, Ship Finance reserved the right to charge interest after the rig is delivered from the shipyard. SFL Linus repaid $70 million during the first quarter in 2014 and the outstanding balance at December 31, 2015 is $ 125 million ( December 31, 2014 : $125.0 million ). Commencing in February 2014, the loan bore interest of 4.5% per annum. The proceeds of this loan were used to finance the acquisition of the West Linus . The loan was presented as long term debt to related party on our balance sheet on December 31, 2015 . Interest charged by Ship Finance for the year ended December 31, 2015 , was $5.6 million ( 2014 : $4.9 million ).

$475 million Secured Credit Facility

On October 17, 2013, SFL Linus Ltd. entered into a $475 million secured term loan and revolving credit facility with a syndicate of banks to fund the acquisition of West Linus , which was pledged as security thereunder. The facility bears interest at LIBOR plus a margin of 2.75% and is repayable over a term of five years . The outstanding balance at December 31, 2015 was $354.0 million ( December 31, 2014 : $451.3 million ). In February 2015, North Atlantic Drilling received approval to amend its $475 million Credit Facility. Under the terms of the agreement, Seadrill provides a guarantee for the facility in exchange for amendments to the covenant package, principally replacing the Company's financial covenants with financial covenants within Seadrill's secured credit facilities. The guarantee fee charged by Seadrill is 0.3% per annum of the outstanding principal.

Transactions with Archer

Engineering Services

We receive certain technical engineering services from subsidiaries of Archer Ltd. The charged amount was $1.9 million , $1.0 million and $4.0 million for the years ended December 31, 2015 , 2014 and 2013 , respectively. These amounts are included in vessel and rig operating expenses. Archer Ltd. is a company in which Seadrill is a large shareholder.

F-34

---

Related Party Balances

The following are the related party balances as at December 31, 2015 and December 31, 2014 :

(In millions of U.S. dollars)		December 31, 2015			December 31, 2014
Related party receivables:
Seadrill		4.7			34.8
Ship Finance International		—			—
Total related party receivables		4.7			34.8
Related party payables:
Seadrill		16.6			17.0
Ship Finance International		23.2			—
Total related party payables		39.8			17.0
Long term debt to related parties
US$600 Bond, Seadrill share 31.1%		186.6			186.6
NOK1,500 Senior Unsecured Bond, Seadrill share 5.5%		9.4			11.1
Non-current related party loan from Ship Finance *		125.0			110.7
Total long term debt to related party		321.0			308.4

Receivables and payables with related parties arise when the Company pays an invoice on behalf of a related party and vice versa. Receivables and payables are generally settled monthly in arrears.

Other than the loans specifically mentioned, the amounts due to and from Seadrill Limited and its subsidiaries under business operations are unsecured, interest-free and intended to be settled in the ordinary course of business.

* Historically the Company presented balances due to/from Ship Finance on a gross basis. From June 30, 2015 the Company has elected to represent this on a net basis, due to the fact that the right of offset is established in the long-term loan agreements, and the balances are intended to be settled on a net basis, providing a more appropriate description of the Company’s related party net debt position. Accordingly the Company has re-presented $14.3 million as at December 31, 2014, from Amounts due from related parties (Current assets) and offset against Long-term debt due to related parties (Non-current liabilities). There is no corresponding offsetting impact as at December 31, 2015 as the short term trading balances are in a liability position of $23.2 million .

Note 22 – Risk management and financial instruments

The majority of our gross earnings from the Company's drilling rigs are receivable in U.S. dollars and the majority of the Company's other transactions, assets and liabilities are denominated in U.S. dollars, the functional currency of the Company. The Company, however, has operations and assets in countries with currency other than U.S. dollars and incurs expenditures in other currencies, causing its results from operations to be affected by fluctuations in currency exchange rates, on primarily NOK denominated debt . The Company is also exposed to changes in interest rates on floating interest rate debt. There is thus a risk that currency and interest rate fluctuations will have a positive or negative effect on the value of the Company’s cash flows.

Interest rate risk management

The Company’s exposure to interest rate risk relates mainly to its floating interest rate debt and balances of surplus funds placed with financial institutions. This exposure is managed through the use of interest rate swaps. The Company's objective is to obtain the most favorable interest rate borrowings available without increasing its foreign currency exposure. Surplus funds are generally placed in fixed deposits with reputable financial institutions, yielding higher returns than are available on overnight deposits in banks. Such deposits generally have short-term maturities, in order to provide the Company with flexibility to meet all requirements for working capital and capital investments. The extent to which the Company utilizes interest rate swaps and other derivatives to manage its interest rate risk is determined by the net debt exposure.

Interest rate swap agreements not qualified as hedge accounting

As at December 31, 2015 , the Company had interest rate swap agreements with an outstanding principal amount of $1,300 million ( December 31, 2014 : $1,300 million ), including one contract of $200 million which was entered into in February 2014 with forward start in March 2016. Certain of these interest rate swaps are forward starting swaps as disclosed below. The agreements do not qualify for hedge accounting, and accordingly any changes

F-35

---

in the fair values of the swap agreements are included in the consolidated statement of operations under “gain/(loss) from derivative financial instruments”. The total fair value of the interest rate swaps outstanding at December 31, 2015 amounted to a gross and net liability of $25.9 million and an asset of $1.5 million ( December 31, 2014 : liability $39.0 million and asset $2.7 million ). The Company did not enter into any other new swap agreements, nor change any existing swap agreements, during the year ended December 31, 2015.

The Company’s interest rate swap agreements as of December 31, 2015 were as follows:

Outstanding principal	Receive rate	Pay rate	Length of contract
(In US$ millions)
400	3 month LIBOR	2.14%	May 2011 - Jan 2016
100	3 month LIBOR	2.74%	May 2012 - May 2017
200	3 month LIBOR	2.57%	June 2012 - June 2017
100	3 month LIBOR	2.56%	June 2012 - June 2017
200	3 month LIBOR	2.17%	Aug 2012 - Aug 2017
100	3 month LIBOR	1.15%	Dec 2012 - Dec 2019
200	3 month LIBOR	2.92%	Mar 2016 - Mar 2021

Interest rate hedge accounting

The Ship Finance subsidiary consolidated by the Company as a VIE (refer to " Note 24 - Variable Interest Entities") has entered into interest rate swap agreements in order to mitigate its exposure to variability in cash flows for future interest payments on the loan taken out to finance the acquisition of West Linus. These interest rate swaps qualify for hedge accounting and any changes in their fair value are included in "other comprehensive income". Below is a summary of the notional amount, fixed interest rate payable and duration of the interest rate swaps.

Outstanding principal	Receive rate	Pay rate	Length of contract
(in US$ Millions)
191.9	3 month LIBOR	1.77%	Dec 2013 - Dec 2018
4.0	2 month LIBOR	2.01%	Mar 2014 - Oct 2018
4.0	1 month LIBOR	2.01%	Mar 2014 - Nov 2018

The total fair value of the interest rate swaps outstanding at December 31, 2015 amounted to a liability of $2.3 million ( December 31, 2014 : a liability of $2.5 million ). In the year ended December 31, 2015 , the above VIE Ship Finance subsidiary has recorded fair value gains on interest rate swaps of $0.2 million ( December 31, 2014 : $0 million fair value gains or losses). Gain or loss is recorded by the VIE in "Other comprehensive income" but due to its ownership by Ship Finance this is allocated to "Non-controlling interest" in our statement of changes in equity. Any change in fair value resulting from hedge ineffectiveness is recognized immediately in earnings. The VIE, and therefore North Atlantic Drilling, did not recognize any gain or loss due to hedge ineffectiveness in the consolidated financial statements during the twelve month period ended December 31, 2015 and 2014 .

Cross currency interest rate swaps not qualified for hedge accounting

At December 31, 2015 we had outstanding cross currency interest rate swaps with a principal amount of $253.5 million ( December 31, 2014 : $253.5 million ). These agreements, entered into in October 2013, do not qualify for hedge accounting and accordingly any changes in the fair values of the swap agreements are included in the Consolidated Statement of Operations under " Gain/(loss) on derivative financial instruments." The total fair value of cross currency interest rate swaps outstanding at December 31, 2015 amounted to a liability of $98.6 million ( December 31, 2014 : a liability $64.4 million ). The fair value of the cross currency interest rate swaps are classified as other current liabilities in the balance sheet.

Foreign currency risk management

The Company uses foreign currency forward contracts and other derivatives to manage its exposure to foreign currency risk on certain assets, liabilities and future anticipated transactions. Such derivative contracts do not qualify for hedge accounting treatment and are recorded in the balance sheet under other current assets if the contracts have a net positive fair value, and under other short-term liabilities if the contracts have a net negative fair value. During the year ended December 31, 2015 , the Company's forward contracts to sell $40 million matured at exchange rates between NOK 7.9493 and NOK 7.9716 per US dollar. The total fair value of currency forward contracts outstanding as at December 31, 2015 amounted to $0.0 million liability ( December 31, 2014 : liability $8.4 million ).

F-36

---

The gains and losses of the derivatives recognized in the Statement of Operations for the period were as follows:

(In millions of U.S. dollars)		Years ended December 31,
		2015			2014			2013
Interest rate swaps		(12.2	)		(16.2	)		8.0
Ship Finance Linus Interest rate swaps		(3.1	)		(3.9	)		—
Cross currency interest rate swap agreements		(39.1	)		(52.4	)		(14.0	)
Foreign currency agreements		(3.0	)		(13.7	)		(10.1	)
Total Loss on Derivatives		(57.4	)		(86.2	)		(16.1	)

Fair values

The carrying value and estimated fair value of the Company’s financial instruments at December 31, 2015 and December 31, 2014 are as follows:

	December 31, 2015						December 31, 2014
(In millions of U.S. dollars)	Fair value			Carrying value			Fair value			Carrying value
Assets
Cash and cash equivalents	150.9			150.9			116.2			116.2
Restricted cash	6.5			6.5			11.0			11.0
External Loans
Current portion of long-term debt	218.1			218.1			218.1			218.1
Long-term interest bearing debt	1,335.9			1,335.9			1,599.9			1,599.9
$600 million fixed interest bond	222.7			413.4			270.3			413.4
NOK 1,500 million floating interest bond	84.5			161.2			123.8			190.3
Related party debt
$600 million fixed interest bond - owned by related party	100.6			186.6			122.0			186.6
NOK 1,500 million floating interest bond - owned by related party	4.8			9.4			6.6			11.1
Long term fixed interest loan to related party	125.0			125.0			125.0			125.0

Financial instruments that are measured at fair value on a recurring basis:

(In millions of U.S. dollars)			December 31, 2015						December 31, 2014
			Fair value			Carrying value			Fair value			Carrying value
Assets
Interest rate swap - non-current assets	Level 2		1.5			1.5			2.7			2.7
Liabilities
Currency forward contracts - current liabilities	Level 2		—			—			8.4			8.4
Interest rate swaps - current liabilities	Level 2		25.9			25.9			39.0			39.0
Interest rate swaps qualified for hedge accounting - non-current liabilities	Level 2		2.3			2.3			2.5			2.5
Cross Currency swap - current liabilities	Level 2		98.6			98.6			64.4			64.4

US GAAP emphasizes that fair value is a market-based measurement, not an entity-specific measurement, and should be determined based on the assumptions that market participants would use in pricing the asset or liability. As a basis for considering market participant assumptions in fair value measurements, US GAAP establishes a fair value hierarchy that distinguishes between market participant assumptions based on market data obtained from sources independent of the reporting entity (observable inputs that are classified within levels one and two of the hierarchy) and the reporting entity’s own assumptions about market participant assumptions (unobservable inputs classified within level three of the hierarchy).

Level one input utilizes unadjusted quoted prices in active markets for identical assets or liabilities that the Company has the ability to access. Level two inputs are inputs other than quoted prices included in level one that are observable for the asset or liability, either directly or indirectly. Level two inputs may include quoted prices for similar assets and liabilities in active markets, as well as inputs that are observable for the asset or liability, other than quoted prices, such as interest rates, foreign exchange rates and yield curves that are observable at commonly quoted intervals. Level three inputs are unobservable inputs for the asset or liability, which are typically based on an entity’s own assumptions, as there is little, if any, related market activity.

F-37

---

In instances where the determination of the fair value measurement is based on inputs from different levels of the fair value hierarchy, the level in the fair value hierarchy within which the entire fair value measurement falls is based on the lowest level input that is significant to the fair value measurement in its entirety. The Company’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment, and considers factors specific to the asset or liability.

Quoted market prices are used to estimate the fair value of marketable securities, which are valued at fair value on a recurring basis.

The fair values of interest rate swaps, cross currency swaps and forward exchange contracts are calculated using the income approach, discounting of future contracted cash flows on LIBOR and NIBOR interest rates. We have categorized these transactions as level 2 on the fair value measurement hierarchy.

As at December 31, 2015 and December 31, 2014 liabilities or assets related to financial and derivative instruments are presented at gross amounts and have not been presented net because we do not have the right of offset. The amounts are included in our fair value table above.

The carrying value of cash and cash equivalents and restricted cash, which are highly liquid, is a reasonable estimate of fair value and categorized at level 1 on the fair value measurement hierarchy.

The fair value of the current and long-term portion of floating rate debt is estimated to be equal to the carrying value since it bears variable interest rates, which are reset regularly and usually in the range between every one to six months. We have categorized this at level 2 on the fair value measurement hierarchy. We have based the table above on the total carrying value of principal outstanding debt, before capitalized loan fees are deducted. Refer to Note 14 - Long term debt for more information.

The fair value of the $600 million 6.25% Senior Unsecured Notes due 2019 and the NOK 1,500 million Senior Unsecured Bond at December 31, 2015 is based at the price it is trading at the year end. We have categorized this at level 1 on the fair value measurement hierarchy.

The remaining related party debt is categorized at level 2 in the fair value measurement hierarchy and amounts to $125 million as at December 31, 2015 .

Retained Risk

Physical Damage Insurance

The Parent purchases hull and machinery insurance to cover for physical damage to its drilling rigs and charges the Company for the cost related to the Company’s fleet.

The Company retains the risk for the deductibles relating to physical damage insurance on the Company’s rig fleet. The deductible is currently a maximum of $5 million per occurrence.

Loss of Hire Insurance

The Parent purchases insurance to cover for loss of revenue in the event of extensive downtime caused by physical damage to its drilling rigs, where such damage is covered under the Parent’s physical damage insurance, and charges the Company for the cost related to the Company’s fleet.

The loss of hire insurance has a deductible period of 60 days after the occurrence of physical damage. Thereafter, insurance policies according to which the Company is compensated for loss of revenue are limited to 210 days. The Company retains the risk related to loss of hire during the initial 60 day period, as well as any loss of hire exceeding the number of days permitted under insurance policy.

Protection and Indemnity Insurance

The Parent purchases protection and indemnity insurance and excess liability for personal injury liability for crew claims, non-crew claims and third-party property damage including oil pollution from the drilling rigs to cover claims of up to $250 million , per event and in the aggregate.  

The Company retains the risk for the deductible of up to $25 thousand per occurrence relating to protection and indemnity insurance.

F-38

---

Credit risk

The Company has financial assets, including cash and cash equivalents, restricted cash, other receivables and certain amounts receivable on derivative instruments, mainly forward exchange contracts and interest rate swaps. These assets expose the Company to credit risk arising from possible default by the counterparty. The Company considers the counterparties to be creditworthy financial institutions and does not expect any significant loss to result from non-performance by such counterparties. The Company, in the normal course of business, does not demand collateral. The credit exposure of interest rate swap agreements and foreign currency contracts is represented by the fair value of contracts with a positive fair value at the end of each period, reduced by the effects of master netting agreements. It is the Company’s policy to enter into master netting agreements with the counterparties to derivative financial instrument contracts, which give the Company the legal right to discharge all or a portion of amounts owed to a counterparty by offsetting them against amounts that the counterparty owes to the Company.

Concentration of risk

The Company has financial assets, including cash and cash equivalents, other receivables and certain derivative instrument receivable amounts. These other assets expose the Company to credit risk arising from possible default by the counterparty. There is also a concentration of credit risk with respect to cash and cash equivalents to the extent that most of the amounts are carried with Swedbank AB, Danske Bank A/S, ABN Amro and Nordea Bank Finland Plc. The Company considers these risks to be remote.

Revenues from the following customers accounted for more than 10% of the Company’s consolidated revenues:

Contract revenue split by client:		Year ended December 31,
		2015			2014			2013
Statoil		44	%		38	%		57	%
ExxonMobil		25	%		13	%		12	%
Conoco Phillips		18	%		8	%		—	%
Total		13	%		12	%		13	%
Shell		—	%		12	%		14	%
KMNG		—	%		11	%		—	%
Other		—	%		6	%		4	%
Total		100	%		100	%		100	%

Note 23 – Commitments and contingencies

Pledged assets

The book value of assets pledged under mortgages and overdraft facilities at December 31, 2015 was $2,738 million .

    

Newbuilding Commitments

As of December 31, 2015 , we no longer had any contractual commitments under newbuilding contracts. The West Rigel semi-submersible rig was reclassified as an asset held for sale as at December 31, 2015 due to the arrangements made with the shipyard. Refer to Note 12 for more information

Leased Premises Commitments

The related operating lease commitments are summarized in the table below:

(In millions of U.S. dollars)	2016		2017		2018		2019		2020		2021 and thereafter
Leased premises	4.2		3.9		3.6		3.5		3.5		6.5

Guarantees

The Company has not issued any guarantees in favor of third parties. Refer to Note 21 – Related party transactions for disclosure of the guarantees provided by Seadrill on behalf of the Company.

Legal Proceedings

From time to time we are a party, as plaintiff or defendant, to lawsuits in various jurisdictions for demurrage, damages, off-hire and other claims and commercial disputes arising from the construction or operation of our drilling units, in the ordinary course of business or in connection with our acquisition or disposal activities. Other than as disclosed below, we believe that the resolution of such claims will not have a material impact individually or in the aggregate on our operations or financial condition. Our best estimate of the outcome of the various disputes has been reflected in our financial statements as of December 31, 2015 .

F-39

---

In December 2014, a purported shareholder class action lawsuit, Fuchs et al. v. Seadrill Limited et al., No. 14-cv-9642 (LGS)(KNF), was filed in US Federal District Court in the Southern District of New York, alleging, among other things, that Seadrill and certain of its executives made materially false and misleading statements in connection with the payment of dividends. In January 2015, a second purported shareholder class action lawsuit, Heron v. Seadrill Limited et al., No. 15-cv-0429 (LGS)(KNF), was filed in the same court on similar grounds. In March 2015, a third purported shareholder class action lawsuit, Glow v. Seadrill Limited et al., No. 15-cv-1770 (LGS)(KNF), was filed in the same court on similar grounds. On March 24, 2015, the court consolidated these complaints into a single action. On June 23, 2015 the court appointed co-lead plaintiffs and co-lead counsel and ordered the co-lead plaintiffs to file a single consolidated amended by complaint by July 23, 2015.

The amended complaint was filed on July 23, 2015 including North Atlantic Drilling as a defendant. It alleges, among other things, that Seadrill Limited, North Atlantic Drilling and certain of our and its executives made materially false and misleading statements in connection with the payment of dividends, the failure to disclose the risks to the Rosneft transaction as a result of various enacted government sanctions and the inclusion in backlog of $4.1 billion attributable to the Rosneft transaction.

Defendants filed their Motion to Dismiss the Complaint on October 13, 2015. The plaintiffs, in turn, filed their Opposition to the Motion to Dismiss on November 12, 2015 and Defendants filed the Reply Brief on December 4, 2015. Although we intend to vigorously defend this action, we cannot predict the outcome of this case, nor can we estimate the amount of any possible loss. Accordingly, no loss contingency has been recognized within the Company's financial statements.

In addition, the Company has received voluntary requests for information from the U.S. Securities and Exchange Commission concerning, among other things, statements in connection with its payment of dividends, inclusion of contracts in the Company's backlog, and its contracts with Rosneft.

Other Matters

North Atlantic Drilling, and all other offshore contractors that are members of the Norwegian Shipowners’ Association, lost a Norwegian court case in July 2015 concerning the pension rights of night shift compensation for offshore workers. The case has been appealed to the Supreme Court of Norway by the members of the Norwegian Shipowners’ Association, and the hearings are expected to be held in June 2016. Due to the uncertainty of the appeal we cannot predict the outcome of this case, nor can we estimate the amount of any possible loss. Accordingly, no loss contingency has been recognized within the Company's financial statements as at December 31, 2015.

In February 2016 the Company was notified of customer claims that are potentially material to our financial statements. After an initial assessment including advice from external counsel, the Company fully refutes the validity of these claims and will take appropriate actions related to our position. The client has withheld amounts from invoice payments due in the first quarter of 2016, which total $36.2 million . No provision has been recognized in relation to these claims.

Note 24 - Variable Interest Entity (VIE)

As of December 31, 2015 , the Company leased a jack-up rig from a VIE under a finance lease. The shares in North Atlantic Linus Ltd, the company which owned the newbuild jack-up rig, were sold by the Company to SFL Linus Ltd, a Ship Finance company, on June 30, 2013, while the West Linus rig was simultaneously leased back by the Company on a bareboat charter contract for a term of 15 years. The Company has four options to repurchase the unit during the charter period, and Ship Finance has an option to sell the asset at the end of the 15 year lease period.

The Company has determined that the Ship Finance subsidiary, which owns the rig, is a VIE, and that North Atlantic Drilling is the primary beneficiary of the risks and rewards connected with the ownership of the rig and the charter contract. Accordingly, the VIE is consolidated in our financial statements. The Company did not record any gain or loss from the sale of the shares, as the assets and liabilities continued to be reported at its original cost in the Company's balance sheet at the time of the transaction. At December 31, 2015 , the asset is reported under Drilling unit in the Company’s balance sheet. Refer also to Note 21 - Related party transactions for additional details about the sales and leaseback contract.

The following table gives a summary of the sale and leaseback arrangement, as of December 31, 2015 :

Unit	Effective from	Sale value (in US$ millions)	First repurchase option (in US$ millions)	Month of first repurchase option	Last repurchase option (in US$ millions)	Month of last repurchase option
West Linus	June 30, 2013	600	370	On the 5 th  anniversary*	170	On the 15 th  anniversary*

* Anniversaries of the drilling contract commencement date

Ship Finance has a right to require North Atlantic to purchase the rig on the 15 ^th anniversary for the price of $100 million if North Atlantic doesn’t exercise the final repurchase option.

F-40

---

The bareboat charter rate is set on the basis of a Base LIBOR Interest Rate for the bareboat charter contract, and thereafter adjusted for differences between the LIBOR fixing each month and the Base LIBOR Interest Rate for the contract. A summary of the bareboat charter rate per day is given below. The amounts shown are based on the Base LIBOR Interest Rate. These lease costs are eliminated on consolidation.

		(In thousands of US$)
Unit	Base LIBOR interest rate	2016	2017	2018	2019	2020
West Linus	1%	222	222	222	172.6	140

The assets and liabilities in the accounts of the VIE as at December 31, 2015 and 2013 are as follows:

		December 31, 2015			December 31, 2014
(In millions of US$)		SFL Linus Ltd			SFL Linus Ltd
Investment in Finance Lease		530.4			574.5
Related party receivables		0.2			—
Total assets		530.6			574.5
Current position of long-term debt		51.4			51.5
Short-term related party liability		23.2			—
Total current liabilities		74.6			51.5
Interest bearing debt		302.3			399.7
Non-current related party liability		125.0			110.7
Derivative instruments - payable		2.3			2.5
Total non-current liabilities		429.6			512.9
Accumulated Other Comprehensive loss		(2.1	)		(2.3	)
Retained earnings		28.5			12.4
Total stockholders' equity		26.4			10.1
Total liabilities and stockholders' equity		530.6			574.5
Book value of the unit in the Company’s consolidated accounts		559.1			581.0

Historically the Company presented balances due to/from Ship Finance on a gross basis. From June 30, 2015 the Company have elected to represent this on a net basis, due to the fact that the right of offset is established in the long-term loan agreements, and the balances are intended to be settled on a net basis, providing a more appropriate description of the Company’s related party net debt position. Accordingly the Company has represented $14.3 million from Amounts due from related parties (Current assets) and offset against Long-term debt due to related parties (Non-current liabilities) as at December 31, 2014. There is no corresponding offsetting impact as at December 31, 2015 as the short term trading balances are in a liability position of 23.2 million .

Note 25 - Non-controlling interest

In 2013 the Company entered into a sale and leaseback arrangement for West Linus with Ship Finance, who incorporated subsidiary company for the sole purpose of owning and leasing the rig. The Company has recognized this subsidiary company as a VIE and concluded that North Atlantic Drilling is their primary beneficiary. Accordingly, this subsidiary company is included in the Company`s consolidated accounts, with the Ship Finance equity in this company included in non-controlling interest.

F-41

---

Changes in non-controlling interest in 2015 , 2014 and 2013 are as follows;

(In millions of U.S. dollars)	Ship Finance			Total
December 31, 2012	—			—
Other comprehensive income due to non-controlling interest	(2.3	)		(2.3	)
Net income due to non-controlling interest	—			—
December 31, 2013	(2.3	)		(2.3	)
Other comprehensive income due to non-controlling interest	—			—
Net income due to non-controlling interest	12.4			12.4
December 31, 2014	10.1			10.1
Other comprehensive income due to non-controlling interest	0.2			0.2
Net income due to non-controlling interest	16.2			16.2
December 31, 2015	26.5			26.5

Note 26 - Subsequent Events

Amendments to our secured credit facilities

On April 28, 2016 the Company executed an amendment to the covenants contained within its secured credit facilities. The amendment, among other things, amends the requirements and definitions of the equity ratio, leverage ratio, minimum-value-clauses, and minimum liquidity requirements. The covenant amendments are in place until July 1, 2017. In addition the maturity date of the $2,000 million senior secured credit facility has been amended from April 15, 2017 to June 30, 2017. Refer to " Note 14 . Long-term debt -Covenants contained within our debt facilities" for more information.

F-42