Edgar Filing: CNOOC LTD

Form 6-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 6-K

Report of Foreign Private Issuer

Pursuant to Rule 13a-16 or 15d-16

of the Securities Exchange Act of 1934

For the month of April 2014

Commission File Number 1-14966

CNOOC Limited

(Translation of registrant’s name into English)

65th Floor

Bank of China Tower

One Garden Road

Central, Hong Kong

(Address of principal executive offices)

Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or Form 40-F.

Form 20-F x Form 40-F ¨

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1): ¨

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7): ¨

Indicate by check mark whether by furnishing the information contained in this Form, the registrant is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934.

Yes ¨ No x

If “Yes” is marked, indicate below the file number assigned to the registrant in connection with Rule 12g3-2(b): Not applicable

THIS REPORT ON FORM 6-K SHALL BE DEEMED TO BE INCORPORATED BY REFERENCE IN THE REGISTRATION STATEMENT ON FORM F-3 (FILE NO. 333-188261) OF CNOOC LIMITED AND TO BE A PART THEREOF FROM THE DATE ON WHICH THIS REPORT IS FILED, TO THE EXTENT NOT SUPERSEDED BY DOCUMENTS OR REPORTS SUBSEQUENTLY FILED OR FURNISHED.

Signature

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


		CNOOC Limited

By:		/s/ Hua Zhong
Name:		Hua Zhong
Title:		Joint Company Secretary

Dated: April 22, 2014

EXHIBIT INDEX


Exhibit No.		Description

99.1		Extract from Nexen Inc. Consolidated Financial Statements for the Year Ended December 31, 2012 and 2011.

99.2		Consent of Deloitte LLP

99.3		Unaudited Pro Forma Consolidated Financial Information.

Exhibit 99.1

LOGO

NEXEN INC.

CONSOLIDATED FINANCIAL STATEMENTS

For the Year Ended December 31, 2012

NEXEN INC.

REPORTS OF INDEPENDENT REGISTERED CHARTERED ACCOUNTANTS

To the Board of Directors and Shareholders of Nexen Inc.

We have audited the accompanying consolidated financial statements of Nexen Inc. and subsidiaries (the “Company”), which comprise the consolidated balance sheet as at December 31, 2012 and 2011, and the consolidated statements of income, comprehensive income, cash flows and changes in equity for the years then ended, and the notes to the consolidated financial statements.

MANAGEMENT’S RESPONSIBILITY FOR THE CONSOLIDATED FINANCIAL STATEMENTS

Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board, and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

AUDITOR’S RESPONSIBILITY

Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we comply with ethical requirements and plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.

We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a basis for our audit opinion.

OPINION

In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of Nexen Inc. and subsidiaries as at December 31, 2012 and 2011, and their financial performance and cash flows for the years then ended in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board.

(signed) “Deloitte LLP”

Independent Registered Chartered Accountants

February 24, 2013

Calgary, Canada

NEXEN INC.

CONSOLIDATED BALANCE SHEET

As at December 31


(Cdn$ millions)	2012		2011

ASSETS
Current Assets
Cash and Cash Equivalents		1,174		845
Restricted Cash		21		45
Accounts Receivable (Note 3)		1,849		2,247
Derivative Contracts (Note 8)		80		119
Inventories and Supplies (Note 4)		354		320
Other Current Assets		90		115

Total Current Assets		3,568		3,691

Non-Current Assets
Property, Plant and Equipment (Note 5)		15,947		15,571
Goodwill (Note 6)		285		291
Deferred Income Tax Assets (Note 21)		648		338
Derivative Contracts (Note 8)		3		25
Other Long-Term Assets (Note 7)		86		152


TOTAL ASSETS		20,537		20,068


LIABILITIES
Current Liabilities
Accounts Payable and Accrued Liabilities (Note 10)		2,689		2,867
Current Income Taxes Payable		430		458
Derivative Contracts (Note 8)		37		103

Total Current Liabilities		3,156		3,428

Non-Current Liabilities
Long-Term Debt (Note 11)		4,288		4,383
Deferred Income Tax Liabilities (Note 21)		1,616		1,488
Asset Retirement Obligations (Note 14)		2,269		2,010
Derivative Contracts (Note 8)		3		24
Other Long-Term Liabilities (Note 15)		400		362

EQUITY (Note 18)
Share Capital
Common Shares		1,195		1,157
Preferred Shares		195		—
Retained Earnings		7,397		7,211
Cumulative Translation Adjustment		18		5

Total Equity		8,805		8,373


TOTAL LIABILITIES AND EQUITY		20,537		20,068

See accompanying notes to the Consolidated Financial Statements.

Approved on behalf of the Board:


(signed) “Kevin J. Reinhart”				(signed) “S. Barry Jackson”
Director				Director

NEXEN INC.

CONSOLIDATED STATEMENT OF INCOME

For the Years Ended December 31


(Cdn$ millions, except per-share amounts)	2012			2011

Revenues and Other Income
Net Sales		6,430			6,169
Marketing and Other Income (Note 20)		281			295

		6,711			6,464
Expenses
Operating		1,497			1,431
Depreciation, Depletion, Amortization and Impairment (Note 5)		1,951			1,913
Transportation and Other		482			425
General and Administrative		591			300
Exploration		429			368
Finance (Note 12)		301			251
Loss on Debt Redemption and Repurchase (Note 11)		—			91
Net Gain from Dispositions (Note 23)		(194	)		(38	)

		5,057			4,741

Income from Continuing Operations before Provision for Income Taxes		1,654			1,723

Provision for (Recovery of) Income Taxes (Note 21)
Current		1,460			1,584
Deferred		(139	)		(256	)

		1,321			1,328

Net Income from Continuing Operations		333			395
Net Income from Discontinued Operations, Net of Tax (Note 23)		—			302

Net Income Attributable to Nexen Inc. Shareholders		333			697


Earnings Per Common Share from Continuing Operations ($/share) (Note 22)
Basic		0.61			0.75
Diluted		0.61			0.69

Earnings Per Common Share ($/share) (Note 22)
Basic		0.61			1.32
Diluted		0.61			1.24

See accompanying notes to the Consolidated Financial Statements.

NEXEN INC.

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

For the Years Ended December 31


(Cdn$ millions)	2012			2011

Net Income Attributable to Nexen Inc. Shareholders		333			697

Other Comprehensive Income (Loss):
Currency Translation Adjustment
Net Translation Gains (Losses) of Foreign Operations		(93	)		109
Net Translation Gains (Losses) on US-Denominated Debt Hedging Foreign Operations ¹		81			(76	)

Total Currency Translation Adjustment		(12	)		33

Actuarial Losses of Defined Benefit Pension Plans ²		(33	)		(73	)

Other Comprehensive Loss		(45	)		(40	)


Total Comprehensive Income		288			657

1	Net of income tax expense for the year ended December 31, 2012 of $13 million (2011—$11 million recovery).

2	Net of income tax recovery for the year ended December 31, 2012 of $12 million (2011—$24 million recovery).

See accompanying notes to the Consolidated Financial Statements.

NEXEN INC.

CONSOLIDATED STATEMENT OF CASH FLOWS

For the Years Ended December 31


(Cdn$ millions)	2012			2011

Operating Activities
Net Income from Continuing Operations		333			395
Net Income from Discontinued Operations		—			302
Charges and Credits to Income not Involving Cash (Note 24)		1,937			1,335
Exploration Expense		429			368
Changes in Non-Cash Working Capital (Note 24)		(86	)		255
Other		(162	)		(158	)

		2,451			2,497

Financing Activities
Repayment of Long-Term Debt (Note 11)		—			(871	)
Dividends Paid on Common and Preferred Shares (Note 18)		(114	)		(105	)
Issue of Common Shares (Note 18)		37			46
Issue of Preferred Shares (Note 18)		195			—
Other		(6	)		(2	)

		112			(932	)

Investing Activities
Capital Expenditures
Exploration, Evaluation and Development		(3,023	)		(2,431	)
Corporate and Other		(101	)		(93	)
Proceeds from Dispositions		884			518
Changes in Restricted Cash		24			(4	)
Changes in Non-Cash Working Capital (Note 24)		1			321
Other		(5	)		(68	)

		(2,220	)		(1,757	)

Effect of Exchange Rate Changes on Cash and Cash Equivalents		(14	)		32


Increase (Decrease) in Cash and Cash Equivalents		329			(160	)


Cash and Cash Equivalents, Beginning of Year		845			1,005


Cash and Cash Equivalents, End of Year ¹		1,174			845

1	Cash and cash equivalents at December 31, 2012 consists of cash of $483 million (2011—$283 million) and short-term investments of $691 million (2011—$562 million).

See accompanying notes to the Consolidated Financial Statements.

NEXEN INC.

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

For the Years Ended December 31


(Cdn$ millions)	2012			2011

Share Capital (Note 18)
Common Shares, Beginning of Year		1,157			1,111
Issue of Common Shares		37			45
Accrued Liability Relating to Tandem Options Exercised for Common Shares		1			1

Balance at End of Year		1,195			1,157


Preferred Shares, Beginning of Year		—			—
Issue of Preferred Shares		195			—

Balance at End of Year		195			—


Retained Earnings, Beginning of Year		7,211			6,692
Net Income Attributable to Nexen Inc. Shareholders		333			697
Actuarial Losses of Defined Benefit Pension Plans		(33	)		(73	)
Dividends on Common and Preferred Shares		(114	)		(105	)

Balance at End of Year		7,397			7,211


Cumulative Translation Adjustment, Beginning of Year		5			(37	)
Currency Translation Adjustment		(12	)		33
Realized Translation Adjustments ¹		25			9

Balance at End of Year		18			5


Canexus Non-Controlling Interests, Beginning of Year		—			48
Net Income Attributable to Non-Controlling Interests		—			1
Disposition of Canexus (Note 23)		—			(49	)

Balance at End of Year		—			—

1	Net of income tax recovery for the year ended December 31, 2012 of $13 million (2011—$18 million expense).

See accompanying notes to the Consolidated Financial Statements.

NEXEN INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Cdn$ millions, except as noted

1. BASIS OF PRESENTATION

Nexen Inc. (Nexen, we or our) is an independent, global energy company with operations in the North Sea, Canada, Gulf of Mexico, Nigeria, Yemen and Colombia. Nexen is incorporated and domiciled in Canada and our head office is located at 801—7th Avenue SW, Calgary, Alberta, Canada. Nexen’s common shares are publicly traded on both the Toronto Stock Exchange and the New York Stock Exchange.

These Consolidated Financial Statements have been prepared in accordance with International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB).

CNOOC Acquisition of Nexen

On July 23, 2012, Nexen entered into an Arrangement Agreement in which CNOOC Limited (CNOOC) proposed to acquire all of the outstanding common and preferred shares of Nexen Inc. for approximately US$15 billion in cash. The transaction was approved by the common and preferred shareholders on September 20, 2012 and all regulatory approvals have been received. The transaction is expected to close the week of February 25, 2013.

The Consolidated Financial Statements were authorized by the board of directors for issue on February 24, 2013.

2. ACCOUNTING POLICIES

(A) CONSOLIDATION

The Consolidated Financial Statements include the accounts of Nexen and our subsidiary companies. All subsidiary companies are wholly owned. All intercompany balances, transactions and profit or loss are eliminated upon consolidation.

In February 2011, we completed the sale of our 62.7% interest in Canexus. Prior to the sale, all assets, liabilities and results of operations of Canexus were consolidated and included in our Consolidated Financial Statements. Non-Nexen ownership interests in Canexus were presented as non-controlling interests. The operating results of Canexus until the sale in February 2011 have been included in discontinued operations (see Note 23).

We proportionately consolidate our undivided interests in oil and gas exploration, development and production activities conducted under joint venture arrangements. While the joint ventures under which these activities are carried out do not comprise distinct legal entities, they are operating entities. The significant operating policies are, by contractual arrangement, jointly controlled by all working interest parties.

(B) USE OF ESTIMATES AND JUDGMENTS

The preparation of financial statements in accordance with IFRS requires management to make judgments, estimates and assumptions that affect the application of accounting policies and the reported amounts within the Consolidated Financial Statements. Judgments, estimates and underlying assumptions are reviewed on a continuous basis and are based on management’s experience and other factors, including expectations of future events that are believed to be reasonable under the circumstances.

In preparing our financial statements, we make judgments regarding the application of IFRS for our accounting policies. Significant judgments relate to the capitalization and depletion of oil and gas exploration and development costs, determination of functional currency for subsidiaries, recognition of tax assets, application of tax rules and regulations, interpretation of contracts and regulations as to what constitutes removal and remediation activities, and the identification of cash-generating units.

The financial statement areas that require significant estimates and assumptions are set out in the following paragraphs:

Oil and Gas Accounting—Reserves Determination

The process of estimating reserves is complex. It requires significant estimates based on available geological, geophysical, engineering and economic data. To estimate the economically recoverable crude oil and natural gas reserves and related future net cash flows, we incorporate many factors and assumptions including the expected reservoir characteristics, future commodity prices and costs and assumed effects of regulation by governmental agencies. Reserves are used to calculate the depletion of the capitalized oil and gas costs and for impairment purposes as described in Note 2(G).

Property, Plant and Equipment

We evaluate our long-lived assets (oil and gas properties and goodwill) for impairment if indicators exist. Cash flow estimates for our impairment assessments require assumptions and estimates about the following primary elements—future prices, future operating and development costs, remaining recoverable reserves and discount rates. In assessing the carrying values of our unproved properties, we make assumptions about our future plans for those properties, the remaining terms of the leases and any other factors that may be indicators of potential impairment.

Asset Retirement Obligations

In estimating our future asset retirement obligations, we make assumptions about activities that occur many years into the future including the cost and timing of such activities. The ultimate financial impact is not clearly known as asset removal and remediation techniques and costs are constantly changing, as are legal, regulatory, environmental, political, safety and other such considerations. In arriving at amounts recorded, numerous assumptions and estimates are made on ultimate settlement amounts, inflation factors, discount rates, timing and expected changes in legal, regulatory, environmental, political and safety environments.

Contingencies

By their nature, contingencies will only be resolved when one or more future events transpire. The assessment of contingencies inherently involves estimating the outcome of future events.

Income Taxes

We carry on business in several countries and as a result, are subject to income taxes in numerous jurisdictions. The determination of income tax is inherently complex and we are required to make certain estimates and assumptions about future events. While income tax filings are subject to audits and reassessments, we believe we have adequately provided for all income tax obligations. However, changes in facts and circumstances as a result of income tax audits, reassessments, jurisprudence and any new legislation may result in an increase or decrease in our provision for income taxes.

Derivatives and Fair Value Measurements

The fair value of derivative contracts is estimated wherever possible, based on quoted market prices, and if not available, on estimates from third-party brokers. Determining the fair value of derivatives also requires assumptions about market data or other information that market participants would use when pricing the asset or liability, including assumptions about risk. The actual settlement of derivatives could differ materially from the fair value recorded and could impact future results.

Cash and cash equivalents includes short-term, highly liquid investments that mature within three months of their purchase.

(D) RESTRICTED CASH

Restricted cash includes margin deposits relating to our exchange-traded derivative contracts used in our energy marketing business.

(E) ACCOUNTS RECEIVABLE

Accounts receivable are recorded based on our revenue recognition policy (see Note 2(N)). Our allowance for doubtful accounts provides for specific doubtful receivables, as well as general counterparty credit risk evaluated using observable market information and internal assessments.

(F) INVENTORIES AND SUPPLIES

Inventories and supplies, other than inventory held for trading purposes by our energy marketing group, are stated at the lower of cost and net realizable value. Cost is determined using the first-in, first-out method. Inventory costs include expenditures and other costs, including depletion and depreciation, directly or indirectly incurred in bringing the inventory to its location and existing condition.

Commodity inventories in our energy marketing operations that are held for trading purposes are carried at fair value, less any costs to sell. Any changes in fair value are included as gains or losses in marketing and other income during the period of change.

(G) PROPERTY, PLANT AND EQUIPMENT (PP&E)

PP&E includes capitalized costs related to our exploration and evaluation expenditures, assets under construction and producing oil and gas properties.

Exploration and Evaluation (E&E) Expenditures

Pre-License Expenditures

Pre-license expenditures are expensed in the period in which they are incurred.

License and Property Acquisition Expenditures

Exploration license and leasehold property acquisition expenditures are intangible assets that are capitalized as E&E costs in PP&E and are reviewed periodically for indications of potential impairment. This review includes confirming that exploration drilling is under way, firmly planned or that it has been determined or work is under way to determine, that the discovery is economically viable based on a range of technical and commercial considerations, and sufficient progress is being made to establish development plans and timing. If no future activity is planned, the remaining capitalized license and property acquisition costs are expensed. Licenses are amortized on a straight-line basis over the estimated period of exploration. Once proved reserves are discovered, technical feasibility and commercial viability are established and we decide to proceed with development, the remaining capitalized expenditure is transferred to either assets under construction or producing oil and gas properties.

Other Exploration and Evaluation Expenditures

Other exploration and evaluation costs, including drilling costs directly attributable to an identifiable exploration or appraisal well, are initially capitalized as an intangible asset until evaluation activities of the exploration play are completed. If hydrocarbons are not found, or not found in commercial quantities, the costs are expensed. If hydrocarbons are found and are likely to be capable of commercial development, the costs continue to be capitalized. These costs are reviewed periodically for indications of potential impairment. Capitalized costs are transferred to assets under construction or producing oil and gas properties after assessing the estimated fair value of the property and recognizing any potential impairment loss. Geological and geophysical costs and annual lease rental costs are expensed as incurred.

Producing Oil and Gas Properties

Producing oil and gas properties are carried at cost less accumulated depletion, depreciation, amortization, and impairment losses. The cost of an asset includes the initial purchase price and directly attributable expenditures to find, develop, construct and complete the asset. This includes installation or completion of infrastructure facilities such as platforms, pipelines and the drilling of development wells, including unsuccessful development or delineation wells. Any costs directly attributable to bringing the asset to the location and condition necessary to operate as intended by management and which result in an identifiable future benefit are also capitalized. This includes the estimate of any asset retirement obligation and, for qualifying assets, capitalized interest. Improvements that increase capacity or extend the useful lives of the related assets are capitalized. Major spare parts and standby equipment whose useful life is expected to last longer than one year are included in capitalized costs.

Major Maintenance and Repairs

Expenditures on major maintenance of our producing assets include the cost of replacement assets or parts of assets, inspection costs or overhaul costs. Where an asset, or part of an asset that was separately depreciated, is replaced and it is probable that there are future economic benefits associated with the item, the expenditure is capitalized and the carrying amount of the replaced item is derecognized. Inspection costs associated with major maintenance programs and necessary for continued operation of the asset are capitalized and amortized over the period to the next inspection. All other maintenance costs are expensed as incurred.

Research and Development

We engage in research and development activities to develop or improve processing techniques to extract crude oil and natural gas. Research involves investigations to gain new knowledge. Development involves translating that knowledge into a new technology or process. Research costs are expensed as incurred. Development costs are deferred once technical feasibility is established and we intend to proceed with development. We defer these costs in PP&E until the asset is substantially complete and ready for productive use. Otherwise, development costs are expensed as incurred.

Depreciation, Depletion, Amortization and Impairment (DD&A)

Unproved property costs and major projects under construction or development are not depreciated or depleted until commercial production commences. We amortize unproved land acquisition costs over the remaining lease term.

We review the useful lives of capitalized costs for producing oil and gas properties to determine the appropriate method of amortization. We deplete oil and gas capitalized costs using the unit-of-production method. Development drilling, equipping costs and other facility costs are depleted over remaining proved developed reserves and proved property acquisition costs are depleted over remaining proved reserves. Other facilities, plant and equipment which have significantly different useful lives than the associated proved reserves are depreciated in accordance with the asset’s future use which range from two to 40 years. Depletion is considered a cost of inventory when the oil and gas is produced. When the inventory is sold, the depletion is charged to DD&A expense.

Depreciation methods, useful lives and residual values are reviewed annually, with any amendments considered to be a change in estimate and accounted for prospectively.

Impairment

Each reporting date, we assess whether there is an indication that an asset may be impaired. If any indication exists, we estimate the asset’s recoverable amount. An asset’s recoverable amount is the higher of an asset’s or cash-generating unit’s (CGU) fair value less any costs to sell or value-in-use. Where an asset does not generate separately identifiable cash flows, we perform an impairment test on CGUs, which are the smallest grouping of assets that generate independent, identifiable cash inflows. Where the carrying amount of an asset or CGU exceeds its recoverable amount, the asset is considered impaired and written down to its recoverable amount. In assessing value-in-use, the estimated future cash flows are discounted to their present value using a discount rate that reflects current market assessments of the time value of money and the risks specific to the asset. In determining fair value less costs to sell, an appropriate valuation model is used. These calculations are corroborated by external valuation metrics or other available fair value indicators wherever possible.

In assessing the carrying values of our unproved properties, we take into account future plans for those properties, the remaining terms of the leases and any other factors that may be indicators of potential impairment.

For assets excluding goodwill, an assessment is made each reporting date as to whether there is an indication that previously recognized impairment losses no longer exist or have decreased. If such indication exists, an estimate of the asset’s or CGU’s recoverable amount is reviewed. A previously recognized impairment loss is reversed to the extent that the events or circumstances that triggered the original impairment have changed. The reversal is limited so that the carrying amount of the asset does not exceed its recoverable amount, nor exceed the carrying amount that would have been determined, net of DD&A, had no impairment loss been recognized for the asset in prior periods.

(H) CAPITALIZED BORROWING COSTS

We capitalize interest on major development projects until construction is complete using the weighted-average interest rate on all of our borrowings. Capitalized interest cannot exceed the actual interest incurred.

(I) CARRIED INTEREST

We conduct certain international operations jointly with foreign governments in accordance with production-sharing agreements pursuant to which proved reserves are recognized using the economic interest method. Under these agreements, we pay both our share and the government’s share of operating and capital costs. We recover the government’s share of these costs from future revenues or production over several years. The government’s share of operating costs is included in operating expense when incurred, and capital costs are included in PP&E and expensed to DD&A in the year recovered. All recoveries are recorded as revenue in the year of recovery.

(J) GOODWILL

Goodwill acquired in a business combination is initially recorded at cost, and for impairment testing purposes, is allocated to each of the CGUs that are expected to benefit from the expenditure. After initial recognition, goodwill is measured at cost less any accumulated impairment losses. We test goodwill for impairment at least annually as at December 31, or more frequently if events or circumstances indicate that goodwill may be impaired. We base our test on the assessment of the recoverable amount of the CGU. Where the recoverable amount of the CGU is less than the carrying amount, we reduce the carrying value to the estimated recoverable amount and a goodwill impairment loss is included in net income.

(K) FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES

All financial assets and liabilities are recognized on the balance sheet initially at fair value when we become a party to the contractual provisions of the instrument. Subsequent measurement of the financial instruments is based on their classification. We classify each financial instrument into one of the following categories: financial assets and liabilities at fair value through profit or loss, loans or receivables, financial assets held to maturity, financial assets available for sale and other financial liabilities. The classification depends on the characteristics and the purpose for which the financial instruments were acquired. Except in limited circumstances, the classification of financial instruments is not subsequently changed.

Financial instruments carried at fair value on our balance sheet include cash and cash equivalents, restricted cash and derivatives. Realized and unrealized gains and losses from financial assets and liabilities carried at fair value are recognized in net income in the period such gains and losses arise. Transaction costs related to these financial assets and liabilities are included in net income when incurred.

Financial instruments carried at cost or amortized cost include our accounts receivable, accounts payable and accrued liabilities and long-term debt. The transaction costs are included with the initial fair value, and the instruments are carried at amortized cost using the effective interest rate method. Gains and losses on financial assets and liabilities carried at cost or amortized cost are recognized in net income when these assets and liabilities settle.

Derivatives

We use derivative instruments such as physical purchase and sales contracts, exchange-traded futures and options, and non-exchange traded forwards, swaps and options for marketing crude oil and natural gas and to manage fluctuations in commodity prices, foreign currency exchange rates and interest rates. We record these instruments at fair value at each reporting date and changes in fair value are included in marketing and other income during the period of change unless the requirements for hedge accounting are met.

Hedge accounting

Hedge accounting is allowed when there is a high degree of correlation between price movements in the derivative instruments and the items designated as being hedged. Nexen formally documents all hedges and the risk management objectives at the inception of the hedge. Derivative instruments that have been designated and qualify for hedge accounting are classified as either cash flow or fair value hedges.

For cash flow hedges, changes in the fair value of a financial instrument designated as a cash flow hedge are recognized in net income in the same period as the hedged item. Any fair value change in the financial instrument before that period is recognized on the balance sheet. The effective portion of this fair value change is recognized in other comprehensive income, with any ineffectiveness recognized in net income during the period of change.

For fair value hedges, both the financial instrument designated as a fair value hedge and the underlying commitment are recognized on the balance sheet at fair value. Changes in the fair value of both are reflected in net income.

For hedges of net investments, gains and losses resulting from foreign exchange translation of our net investments in foreign operations and the effective portion of the hedging items are recorded in other comprehensive income. Amounts included in cumulative translation adjustment are reclassified to net income when realized.

(L) PROVISIONS AND CONTINGENCIES

Provisions are recognized when we have a present obligation (legal or constructive) as a result of a past event, it is probable that an outflow of resources will be required to settle the obligation and a reliable estimate can be made of the amount of the obligation. Where appropriate, the future cash flow estimates are adjusted to reflect the risks specific to the liability.

If the effect of the time value of money is material, provisions are determined by discounting the expected future cash flows at a discount rate that reflects current market assessments of the time value of money. Where discounting is used, the accretion of the provision due to the passage of time is recognized within finance costs.

Contingent liabilities are possible obligations which will be confirmed by future events that are not necessarily within our control, or are present obligations where the obligation cannot be measured reliably or it is not probable that settlement will be required. Contingent liabilities are disclosed only if the possibility of settlement is greater than remote. Contingent liabilities are not recorded in the financial statements.

Asset Retirement Obligations and Environmental Expenditures

We provide for asset retirement obligations (ARO) on our resource properties, facilities, production platforms, pipelines and other facilities based on estimates established by current legislation and industry practices. ARO is initially measured at fair value and capitalized to PP&E as an asset retirement cost. The liability is estimated by discounting expected future cash flows required to settle the liability using a risk-free rate. The estimated future asset retirement costs may be adjusted for risks such as project, physical, regulatory and timing. The estimates are reviewed periodically. Changes in the provision as a result of changes in the estimated future costs or discount rates are added to or deducted from the cost of the PP&E in the period of the change. The liability accretes for the effect of time value of money until it is expected to settle. The asset retirement cost is amortized through DD&A over the life of the related asset. Actual asset retirement expenditures are recorded against the obligation when incurred. Any difference between the accrued liability and the actual expenditures incurred is recorded as a gain or loss in the settlement period.

Liabilities for environmental costs are recognized when a clean-up is probable and the associated costs can be reliably estimated. Environmental expenditures that relate to current or future revenues are expensed or capitalized as appropriate.

(M) PENSION AND OTHER POST-RETIREMENT BENEFITS

Our employee post-retirement benefit programs consist of defined benefit and defined contribution pension plans, as well as other post-retirement benefit programs.

For our defined benefit plans, we provide retirement benefits to employees based on their length of service and final average earnings. The cost of pension benefits earned by employees in our defined benefit pension plans is actuarially determined using the projected-benefit method prorated on service and our best estimate of the plans’ investment performance, salary escalations and retirement ages of employees. To calculate the plans’ expected returns, assets are measured at fair value. Fair value measurement of the defined benefit assets is limited to the sum of any recognized net actuarial losses and past service costs, and the net present value of any economic benefit available in the form of surplus refunds to the plan or reductions in future contributions to the plan. Vested past service costs arising from plan amendments are recognized in other comprehensive income (OCI) immediately. Unvested past service costs are amortized over the expected average service life until they become vested. Net actuarial gains and losses are included in OCI as incurred with immediate recognition in retained earnings. Benefits paid out of Nexen’s defined benefit plan are indexed to 75% of the annual rate of inflation less 1% to a maximum increase of 5%. The measurement date for our defined benefit plans is December 31.

Our defined contribution pension plan benefits are based on plan contributions. Company contributions to the defined contribution plan are expensed as incurred.

Other post-retirement benefits include group life and supplemental health insurance for eligible employees and their dependants. Costs are accrued as compensation in the period employees work; however, these future obligations are not funded.

(N) REVENUE RECOGNITION

Revenue from the production of oil and gas is recognized when title passes to the customer. In Canada and the US, our customers primarily take title when the oil or gas reaches the end of the pipeline. For our other international operations, our customers generally take title when the crude oil is loaded onto tankers. When we sell more or less crude oil or natural gas than we produce, production overlifts and underlifts occur. We record overlifts as liabilities at fair value and underlifts as assets at cost. We settle these over time as liftings are equalized or in cash when production ends.

Revenue represents Nexen’s share and is recorded net of royalty obligations to governments and other mineral interest owners. For our international operations, all government interests, except for income taxes, are considered royalty obligations. Our revenue also includes the recovery of carried interest costs paid on behalf of foreign governments in accordance with production sharing contracts in certain international locations.

(O) FOREIGN CURRENCY TRANSLATION

Our foreign operations are translated from their functional currency into Canadian dollars at the balance sheet date exchange rate for assets and liabilities and at the monthly average exchange rate for revenues and expenses. Gains and losses resulting from this translation are included in other comprehensive income.

We have designated our US-dollar debt as a hedge against our net investment in US-dollar foreign operations. Gains and losses resulting from the translation of the designated US-dollar debt are included in other comprehensive income. If our US-dollar debt, net of income taxes, exceeds our US-dollar investment in foreign operations, then the translation gains or losses attributable to such excess are included in net income.

Monetary balance sheet amounts denominated in a currency other than a functional currency are translated into the functional currency using exchange rates at the balance sheet dates. Gains and losses arising from this translation are included in net income. Non—monetary balance sheet amounts denominated in a currency other than a functional currency are translated using historical exchange rates at the time of the transaction.

(P) TRANSPORTATION

We pay to transport the oil and gas products that we have sold and often bill our customers for the transportation cost. This transportation cost is included in transportation and other expense. Amounts billed to our customers are presented within marketing and other income.

(Q) LEASES

We classify leases entered into as either finance or operating leases. Leases that transfer substantially all of the risks and benefits of ownership to us are capitalized as finance leases within PP&E and other liabilities. All other leases are recorded as operating leases and expensed as incurred within operating expenses.

(R) SHARE-BASED COMPENSATION

Our share-based compensation programs consist of tandem option (TOPs), stock appreciation right (STARs), restricted share unit (RSUs) and deferred share unit (DSUs) plans.

TOPs to purchase common shares are granted to officers and employees at the discretion of the board of directors. Each TOP gives the holder a right to either purchase one Nexen common share at the exercise price or to receive a cash payment equal to the excess of the market price of the common share over the exercise price. TOPs granted vest over three years and are exercisable on a cumulative basis over five years. At the time of the grant, the exercise price equals the market price of the common share. Certain TOPs granted contain a performance vesting condition.

We record obligations for the outstanding TOPs using the fair-value method of accounting and recognize compensation expense in net income. Obligations are accrued on a graded vesting basis and revalued each reporting period based on the change in the estimated fair value of the options outstanding. We reduce the liability when the options are surrendered for cash. When the options are exercised for shares, the accrued liability is transferred to share capital.

Under our STARs plan, employees are entitled to cash payments equal to the excess of market price of the common share over the exercise price of the right. The vesting period and other terms of the plan are similar to the TOPs plan and include a performance vesting condition for certain awards. At the time of grant, the exercise price equals the market price of the common share. We account for STARs to employees on the same basis as our TOPs. Obligations are accrued as compensation expense over the graded vesting period of the STARs.

The fair value of each TOP and STAR is estimated using a Black-Scholes option pricing methodology, which takes into account share performance, market conditions, and other terms and conditions. For those awards that contain a performance vesting condition, we use the Monte Carlo option pricing model to simulate expected returns and estimate the fair value. This is applied to the reward criteria of the performance TOPs and STARs to give an expected value each measurement date.

Under our RSU plan, employees are entitled to receive a cash payment equal to the average closing market price of one common share for the 20 days prior to the vesting date for each RSU granted. All RSUs vest evenly over three years and are exercised and paid automatically when they vest. The liability for RSUs is revalued each period based on the market price of our common shares and the number of graded vested RSUs outstanding. Certain RSUs granted contain a performance vesting condition.

For employees eligible to retire during the vesting period, the compensation expense is recognized over the period from the grant date to the retirement eligibility date on a graded vesting basis. In instances where an employee is eligible to retire on the grant date of the share-based award, compensation expense is recognized in full at that date.

DSUs are equity-based awards granted to directors. The units accumulate over a director’s term of service and automatically vest when the director leaves the board. Payments may be made in cash or in Nexen common shares purchased on the open market at the company’s discretion. At the time of grant, the exercise price equals the market value of Nexen common shares.

(S) INCOME TAXES

The provision for income taxes comprises current and deferred tax provisions. The provision for income taxes is recognized in net income except to the extent that it relates to items recognized directly in equity.

Current tax is the expected tax payable on the taxable income for the year, using tax rates enacted or substantively enacted at the reporting date, and any adjustment to taxes payable in respect of previous years. Current tax assets and liabilities are offset to the extent the entity has the legal right to settle on a net basis.

Deferred tax assets and liabilities are recognized for temporary differences between reported amounts for financial statement and tax purposes. Deferred tax is not recognized for the following temporary differences: i) initial recognition of tax assets or liabilities in a transaction that is not a business combination and that affects neither accounting nor taxable profit or loss, ii) differences relating to investments in subsidiaries to the extent that it is probable that they will not reverse in the foreseeable future, and iii) the initial recognition of goodwill. Deferred tax assets are only recognized for temporary differences, unused tax losses and unused tax credits if it is probable that future tax amounts will arise to utilize those amounts.

Deferred tax assets and liabilities are measured at tax rates that are expected to be applied to temporary differences when they reverse, based on the tax rates and laws that have been enacted or substantively enacted by the reporting date. Deferred tax assets and tax liabilities are offset to the extent there is a legal right to settle on a net basis.

We do not provide for foreign withholding taxes on the undistributed earnings of our foreign subsidiaries, as we intend to invest such earnings in the respective foreign operations.

(T) CHANGES IN ACCOUNTING POLICIES

We have adopted all IFRS accounting standards in effect on December 31, 2012.

The following standards and interpretations have not been adopted as they apply to future periods. They may result in future changes to our existing accounting policies and other note disclosures. We are evaluating the impacts that these standards may have on our results of operations, financial position and disclosure.

•

IFRS 7 Financial Instruments: Disclosures—in December 2011, the IASB issued final amendments to the disclosure requirements for the offsetting of a financial asset and financial liabilities when offsetting is permitted under IFRS. The disclosure amendments are required to be adopted retrospectively for periods beginning January 1, 2013. Adoption of this standard will result in additional disclosures in our Consolidated Financial Statements.

•

IFRS 9 Financial Instruments—in November 2009, the IASB issued IFRS 9 to address classification and measurement of financial assets. In October 2010, the IASB issued additions to the standard to include financial liabilities. The standard is required to be adopted for periods beginning January 1, 2015. Portions of the standard remain in development and the full impact of the standard will not be known until the project is complete.

•

IFRS 10 Consolidated Financial Statements—in May 2011, the IASB issued IFRS 10 which provides additional guidance to determine whether an investee should be consolidated and establishes a new control model which applies to all entities including special purpose entities. The standard replaces the consolidation guidance in IAS 27 and is required to be adopted for periods beginning January 1, 2013. Adoption of IFRS 10 is not expected to have a significant impact on the Consolidated Financial Statements.

•

IFRS 11 Joint Arrangements—in May 2011, the IASB issued IFRS 11 which presents a new model for determining whether joint arrangements should be accounted for as a joint operation or as a joint venture. Joint operations are accounted for by recording an entity’s relevant share of assets, liabilities, revenues and expenses. Under IFRS 11, an entity will follow the substance of the joint arrangement rather than legal form and will no longer have a choice of the accounting method to apply. In conjunction with this new standard, amendments to IAS 28 have been made to specify that joint ventures are accounted for using the equity method. Both IFRS 11 and the amendments to IAS 28 are required to be adopted for periods beginning January 1, 2013. Adoption of IFRS 11 is not expected to have a significant impact on our Consolidated Financial Statements.

•

IFRS 12 Disclosure of Interests in Other Entities—in May 2011, the IASB issued IFRS 12 which aggregates and amends disclosure requirements included within other standards. The standard requires companies to provide disclosures about subsidiaries, joint arrangements, associates and unconsolidated structured entities. The standard is required to be adopted for periods beginning January 1, 2013. Adoption of this standard will result in additional disclosures in our Consolidated Financial Statements.

•

IFRS 13 Fair Value Measurement—in May 2011, the IASB issued IFRS 13 to provide comprehensive guidance for instances where IFRS requires fair value to be used. The standard provides guidance on determining fair value and requires disclosures about those measurements. The standard is required to be adopted for periods beginning January 1, 2013. We do not expect a material impact on our Consolidated Financial Statements from the adoption of this standard; however, additional disclosures will be required.

•

IAS 1 Presentation of Items of Other Comprehensive Income—in June 2011, the IASB issued amendments to IAS 1 Presentation of Financial Statements to separate items of other comprehensive income (OCI) between those that are reclassed to income and those that do not. The standard is required to be adopted for periods beginning on or after July 1, 2012. Adoption of this standard is not expected to have a significant impact on the Consolidated Financial Statements.

•

IAS 19 Employee Benefits—in June 2011, the IASB issued amendments to IAS 19 to revise certain aspects of the accounting for pension plans and other benefits. The amendments eliminate the corridor method of accounting for defined benefit plans, change the recognition pattern of gains and losses and require additional disclosures. The standard is required to be adopted for periods beginning on or after January 1, 2013. Adoption of this standard is not expected to have a significant impact on the Consolidated Financial Statements.

•

IAS 32 Financial Instruments: Presentation—in December 2011, the IASB issued amendments to clarify certain of the criteria required to be met in order to permit the offsetting of financial assets and financial liabilities. The standard is required to be adopted retrospectively for periods beginning January 1, 2014. Adoption of this standard is not expected to have a significant impact on the Consolidated Financial Statements.

3. ACCOUNTS RECEIVABLE


	December 31 2012			December 31 2011
Trade
Energy Marketing		585			1,146
Oil and Gas		1,223			1,040

		1,808			2,186
Non-Trade		53			73

		1,861			2,259
Allowance for Doubtful Receivables ¹		(12	)		(12	)


Total		1,849			2,247

1	Includes a general provision of $1 million and a specific provision against certain accounts.

Receivables terms are generally 30 days and were current as of December 31, 2012 and 2011.

4. INVENTORIES AND SUPPLIES


	December 31 2012		December 31 2011
Finished Products
Energy Marketing		240		230
Oil and Gas		14		36

		254		266
Work in Process		5		6
Field Supplies		95		48


Total		354		320

5. PROPERTY, PLANT AND EQUIPMENT

(A) CARRYING AMOUNT OF PP&E


	Exploration and Evaluation			Assets Under Construction			Producing Oil & Gas Properties			Corporate and Other			Total
Cost
As at December 31, 2010		2,990			1,748			18,887			757			24,382
Additions		1,056			734			693			92			2,575
Disposals/Derecognitions		(303	)		—			(2,004	)		(18	)		(2,325	)
Transfers		(1,253	)		(216	)		1,469			—			—
Exploration Expense		(368	)		—			—			—			(368	)
Other		65			31			493			—			589
Effect of Changes in Exchange Rate		19			50			294			6			369

As at December 31, 2011		2,206			2,347			19,832			837			25,222

Additions		765			849			1,409			101			3,124
Disposals/Derecognitions		(296	)		—			(944	)		(116	)		(1,356	)
Transfers ¹		—			(1,862	)		1,862			—			—
Exploration Expense		(429	)		—			—			—			(429	)
Other		15			19			461			14			509
Effect of Changes in Exchange Rate		(54	)		(33	)		(174	)		(15	)		(276	)

As at December 31, 2012		2,207			1,320			22,446			821			26,794


Accumulated Depreciation, Depletion & Amortization (DD&A)
As at December 31, 2010		331			—			9,054			418			9,803
DD&A		50			—			1,210			78			1,338
Disposals/Derecognitions		(12	)		—			(2,001	)		(12	)		(2,025	)
Impairments		—			—			322			—			322
Other		(6	)		—			(8	)		—			(14	)
Effect of Changes in Exchange Rate		5			—			220			2			227

As at December 31, 2011		368			—			8,797			486			9,651

DD&A		62			—			1,565			87			1,714
Disposals/Derecognitions		(125	)		—			(322	)		(116	)		(563	)
Impairments		—			—			237			—			237
Other		—			—			(40	)		17			(23	)
Effect of Changes in Exchange Rate		(3	)		—			(166	)		—			(169	)

As at December 31, 2012		302			—			10,071			474			10,847


Net Book Value
As at December 31, 2011		1,838			2,347			11,035			351			15,571

As at December 31, 2012		1,905			1,320			12,375			347			15,947

1	Includes PP&E costs related to our Usan development, offshore Nigeria which came on-stream February 2012.

Exploration and evaluation assets are mainly comprised of unproved properties and capitalized exploration drilling costs. Assets under construction at December 31, 2012 primarily include developments in the UK North Sea, Long Lake and Syncrude.

(B) IMPAIRMENT

In the fourth quarter of 2012, lower estimated future North American natural gas prices and increases in future abandonment costs resulted in a $237 million non-cash impairment charge for natural gas properties in North America. These assets are included in our Conventional North America segment.

DD&A expense for 2011 includes non-cash impairment charges of $322 million for our oil and gas properties in our Conventional North America segment. Canadian natural gas assets were impaired $234 million in the second half of 2011 due to lower estimated future natural gas prices and performance-related negative reserve revisions. In the fourth quarter of 2011, lower estimated future natural gas prices and higher estimated future abandonment costs resulted in an $88 million impairment of mature Gulf of Mexico properties.

The properties were written down to the higher amount of value-in-use and estimated fair value less costs to sell. We estimated fair value based on discounted future net cash flows using estimated future prices, a discount rate of 9% and management’s estimate of future production, capital and operating expenditures.

Nexen’s original strategy for future oil sands development was to build duplicates of the existing Long Lake SAGD facilities and upgrader. In 2011, we revised our strategy to focus on smaller, phased, SAGD-only projects. As a result, previously capitalized design and engineering costs of $253 million on the future phases were expensed in 2011.

6. GOODWILL

(A) CARRYING AMOUNT OF GOODWILL

Goodwill


As at December 31, 2010	286
Effect of Changes in Exchange Rate	7
Dispositions	(2	)

As at December 31, 2011	291
Effect of Changes in Exchange Rate	(6	)

As at December 31, 2012	285


	December 31 2012		December 31 2011
UK Conventional		277		284
Corporate and Other		8		7

Total		285		291

(B) IMPAIRMENT TESTING OF GOODWILL

Goodwill is attributable to our UK Conventional and Corporate and Other segments which have been allocated for impairment testing purposes to the cash-generating units that reflect the lowest level at which goodwill is attributable.

UK Conventional

The recoverable amount of the UK group was based on cash flow projections discounted at a rate of 9%. The significant assumptions used in the cash flow projections are:

Commodity prices: these assumptions are based on estimated market-based future prices, the global supply-demand balance for each commodity, other macroeconomic factors, historical trends and variability.

Discount rates: the rates used in the calculation are based on an industry-specific discount rate, adjusted to take into consideration country and project risks specific to the cash-generating unit.

Production volumes, capital investment and operating costs: estimated future operational activities and costs are based on current estimated asset development plans, past experience and available knowledge about costs and reservoir performance.

7. OTHER LONG-TERM ASSETS


	December 31 2012		December 31 2011
Long-Term Investments		36		41
Long-Term Capital Prepayments		1		46
Other		49		65

Total		86		152

8. FINANCIAL INSTRUMENTS

Financial instruments carried at fair value include cash and cash equivalents, restricted cash and derivatives used for trading and non-trading purposes. Our other financial instruments, including accounts receivable, accounts payable and accrued liabilities and long-term debt, are carried at cost or amortized cost. The carrying value of our short-term receivables and payables approximates fair value because the instruments are near maturity.

(A) DERIVATIVES

In our energy marketing group, we enter into contracts to purchase and sell crude oil, natural gas and other energy commodities, and use derivative contracts, including futures, forwards, swaps and options for hedging and trading purposes (collectively derivative contracts). We also use derivatives to manage commodity price risk and foreign currency risk for non-trading purposes. We categorize our derivative instruments between trading and non-trading activities and carry the instruments at fair value on our balance sheet. The fair values are included in derivative contracts and are classified as long-term or short-term based on anticipated settlement date and, where applicable, are presented net on the balance sheet in accordance with netting arrangements. Any change in fair value is included in marketing and other income in the period of change. Related amounts posted as margin for exchange-traded positions are recorded in restricted cash.

Total carrying value of derivative contracts

The fair value and carrying amounts related to derivative contracts are as follows:


	December 31 2012		December 31 2011
Commodity Contracts		80		119

Derivative Contracts—Current		80		119

Commodity Contracts		3		25

Derivative Contracts—Long-Term ¹		3		25

Total Derivative Assets		83		144


Commodity Contracts		37		103

Derivative Contracts—Current		37		103

Commodity Contracts		3		24

Derivative Contracts—Long-Term ¹		3		24


Total Derivative Liabilities		40		127


Total Net Derivative Contracts		43		17

1	These derivative contracts settle beyond 12 months and are considered non-current.

Derivative contracts related to trading

Our energy marketing group primarily focuses on crude oil marketing activities in North American and international markets.

Trading revenues generated by our energy marketing group include gains and losses on derivative instruments and non-derivative instruments such as physical inventory. During the years ended December 31, 2012 and 2011, the following revenues were recognized in marketing and other income:


	2012			2011
Commodity		315			200
Foreign Exchange		(1	)		(5	)

Marketing Revenue, Net		314			195

Derivative contracts related to non-trading activities

In 2011, we purchased crude oil put options on 100,000 bbls/d of our 2012 crude oil production for $52 million. These options established a monthly Dated Brent floor price of US$65/bbl on 60,000 bbls/d and an annual Dated Brent floor price of US$75/bbl on 40,000 bbls/d. The options settle monthly or annually and unexpired options are recorded at fair value throughout their term. As a result, changes in forward crude oil prices created gains or losses on these options at each reporting period. At December 31, 2011, higher crude oil prices reduced the fair value of the options to approximately $38 million, and we recorded a fair value loss during the period of $14 million in marketing and other income. Strengthening crude prices in 2012 reduced the fair value of these options to nil and we recorded a fair value loss of $38 million in 2012.

(B) FAIR VALUE OF FINANCIAL INSTRUMENTS

Fair value of derivatives

For purposes of estimating the fair value of our derivative contracts, wherever possible, we utilize quoted market prices and, if not available, estimates from third-party brokers. These broker estimates are corroborated with multiple sources and/or other observable market data utilizing assumptions that market participants would use when pricing the asset or liability, including assumptions about risk and market liquidity. Inputs may be readily observable, market-corroborated or generally unobservable. We utilize valuation techniques that seek to maximize the use of observable inputs and minimize the use of unobservable inputs. To value longer-term transactions and transactions in less active markets for which pricing information is not generally available, unobservable inputs may be used.

We classify financial instruments carried at fair value according to the following hierarchy based on the amount of observable inputs used to value the instruments.

Level 1—Quoted prices are available in active markets for identical assets or liabilities as at the reporting date. Active markets are those in which transactions occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 consists of financial instruments such as exchange-traded derivatives, and we use information from markets such as the New York Mercantile Exchange.

Level 2—Pricing inputs are other than quoted prices in active markets. Prices in Level 2 are either directly or indirectly observable as at the reporting date. Level 2 valuations are based on inputs, including quoted forward prices for commodities, time value, volatility factors and broker quotations, which can be substantially observed or corroborated in the marketplace. Instruments in this category include non-exchange traded derivatives such as over-the-counter physical forwards and options, including those that have prices similar to quoted market prices. We obtain information from sources such as the Natural Gas Exchange, independent price publications and over-the-counter broker quotes.

Level 3—Valuations in this level are those with inputs that are less observable, unavailable or where the observable data does not support the majority of the instrument’s fair value. Level 3 instruments may include items based on pricing services or broker quotes where we are unable to verify the observability of inputs into their prices. Level 3 instruments include longer-term transactions, transactions in less active markets or transactions at locations for which pricing information is not available. In these instances, internally developed methodologies are used to determine fair value, which primarily includes extrapolation of observable future prices to similar locations, similar instruments or later time periods.

Cash and cash equivalents and restricted cash are valued using Level 1 inputs. The following tables include derivatives carried at fair value for our trading and non-trading activities as at December 31, 2012 and 2011. Financial assets and liabilities are classified in the fair value hierarchy in their entirety based on the lowest level of input that is significant to the fair value measurement. Assessment of the significance of a particular input to the fair value measurement requires judgment and may affect placement within the fair value hierarchy levels.


Net Derivatives at December 31, 2012	Level 1		Level 2			Level 3		Total
Trading Derivatives		1		(3	)		45		43

Total		1		(3	)		45		43


Net Derivatives at December 31, 2011	Level 1			Level 2			Level 3			Total
Trading Derivatives		(17	)		(1	)		(3	)		(21	)
Non-Trading Derivatives		—			38			—			38

Total		(17	)		37			(3	)		17

A reconciliation of changes in the fair value of our derivatives classified as Level 3 for the years ended December 31, 2012 and 2011 is provided below:


	2012			2011
Level 3 Net Derivatives at January 1		(3	)		17
Realized and Unrealized Gains (Losses)		202			(34	)
Settlements		(154	)		14

Level 3 Net Derivatives at December 31		45			(3	)

Unsettled Gains (Losses) Relating to Instruments Still Held as of December 31		45			(3	)

Items classified in Level 3 are generally economically hedged such that gains or losses on positions classified in Level 3 are often offset by gains or losses on positions classified in Level 1 or 2. We performed a sensitivity analysis of inputs used to calculate the fair value of Level 3 instruments. Using reasonably possible alternative assumptions, the fair value of Level 3 instruments at December 31, 2012 could change by $5 million.

Fair value of long-term debt

We carry our long-term debt at amortized cost using the effective interest method. At December 31, 2012, the estimated fair value of our long-term debt was $5,643 million (2011—$4,848 million) as compared to the carrying value of $4,288 million (2011—$4,383 million). The fair value of long-term debt is estimated based on prices provided by quoted markets and third-party brokers.

9. RISK MANAGEMENT

(A) MARKET RISK

We invest in significant capital projects, purchase and sell commodities, issue short-term borrowings and long-term debt, and invest in foreign operations. These activities expose us to market risks from changes in commodity prices, foreign currency rates and interest rates, which could affect our earnings and the value of the financial instruments we hold. We use derivatives as part of our overall risk management policy to manage these market exposures.

The following market risk discussion focuses on the commodity price risk and foreign currency risk related to our financial instruments as our exposure to interest rate risk is immaterial given that the majority of our debt is fixed rate.

Commodity price risk

We are exposed to commodity price movements as part of our normal oil and gas operations, particularly in relation to the prices received for our crude oil and natural gas. Commodity price risk related to crude oil prices is our most significant market risk exposure. Crude oil and natural gas prices are sensitive to numerous worldwide factors, many of which are beyond our control, and are generally sold at contract or posted prices. Changes in the global supply and demand fundamentals in the crude oil market and geopolitical events can significantly affect crude oil prices. Changes in crude oil and natural gas prices may significantly affect our results of operations and cash generated from operating activities. Consequently, these changes may also affect the value of our oil and gas properties, our level of spending for exploration and development, and our ability to meet our obligations as they come due.

The majority of our oil and gas production is sold under short-term contracts, exposing us to the risk of price movements. Other energy contracts we enter into also expose us to commodity price risk between the time we purchase and sell contracted volumes. We actively manage these risks by using derivative contracts such as commodity put options.

We market and trade physical energy commodities, including crude oil, natural gas and other commodities in selected regions of the world. We accomplish this by buying and selling physical commodities, by acquiring and holding rights to physical transportation and storage assets for these commodities, and by building relationships with our customers and suppliers. In order to manage the commodity and foreign exchange price risks that come from this physical business, we use financial derivative contracts including energy-related futures, forwards, swaps and options, as well as foreign currency swaps or forwards.

Our risk management activities make use of tools such as Value-at-Risk (VaR) and stress testing. VaR is a statistical estimate of the expected profit or loss of a portfolio of positions assuming normal market conditions. We use a 95% confidence interval and an assumed five-day holding period in our measure, although actual results can differ from this estimate in abnormal market conditions, or if positions are held longer than five days based on market views or a lack of market liquidity to exit them. We estimate VaR primarily by using the Variance-Covariance method based on historical commodity price volatility and correlation inputs where available, and by historical simulation in other situations. Our estimate is based upon the following key assumptions:

•

changes in commodity prices are either normally or “T” distributed;

•

price volatility is comparable to prior periods; and

•

price correlation relationships remain stable.

We have defined VaR limits for different segments of our energy marketing business. These limits are calculated on an economic basis and include physical and financial derivatives, as well as physical transportation and storage capacity contracts accounted for as executory contracts in our financial statements. We monitor our positions against these VaR limits daily. Our year-end, annual high, annual low and average VaR amounts are as follows:


Value-at-Risk (Cdn$ millions)	2012		2011
Year-End		5		7
High		11		17
Low		1		2
Average		4		9

If a significant market shock occurred, the key assumptions underlying our VaR estimate could be exceeded and the potential loss could be greater than our estimate. We perform stress tests on a regular basis to complement VaR and assess the impact of abnormal changes in prices on our positions.

Foreign currency risk

Foreign currency risk is created by fluctuations in the fair values or cash flows of financial instruments due to changes in foreign exchange rates. A substantial portion of our activities are transacted in or referenced to US dollars including:

•

sales of crude oil and natural gas products;

•

capital spending and expenses in our oil and gas activities;

•

commodity derivative contracts used primarily by our energy marketing group; and

•

short-term borrowings and long-term debt.

We manage our exposure to fluctuations between the US and Canadian dollar by matching our expected net cash flows and borrowings in the same currency. Cash flows generated by our foreign operations and borrowings on our US-dollar debt facilities are generally used to fund US-dollar capital expenditures and debt repayments. We maintain revolving Canadian and US-dollar borrowing facilities that can be drawn upon or repaid depending on expected new cash flows.

We designate most of our US-dollar borrowings as a hedge against our US-dollar net investment in our foreign operations. The accumulated foreign exchange gains or losses related to the effective portion of our designated US-dollar debt are included in cumulative translation adjustment in shareholders’ equity. Our net investment in foreign operations and our designated US-dollar debt at December 31, 2012 and 2011 are as follows:


(US$ millions)	December 31 2012		December 31 2011
Net Investment in Foreign Operations		4,908		4,191
Designated US-Dollar Debt, After Tax		3,595		3,673

A one-cent change in the US dollar to Canadian dollar exchange rate would increase or decrease our cumulative translation adjustment by approximately $13 million (2011—$5 million), net of income tax, and would not have a material impact on our net income.

We also have exposures to currencies other than the US dollar, including a portion of our UK operating expenses, capital spending and future asset retirement obligations, which are denominated in British Pounds and Euros. We do not have any material exposure to highly inflationary foreign currencies. Our energy marketing group enters into transactions in various currencies including Canadian and US dollars, British Pounds and Euros. We may actively manage significant currency exposures using forward contracts and swaps.

Our sensitivities to the US/Canadian dollar exchange rate and the expected impact of a one-cent change on our 2013 cash flow from operating activities, net income, capital expenditures and long-term debt are as follows:


(Cdn$ millions)	Cash Flow		Net Income		Capital Expenditures		Long-Term Debt
$0.01 Change in US to Cdn		25		11		20		44

(B) CREDIT RISK

Credit risk affects our oil and gas operations and our energy marketing activities, and is the risk of loss if counterparties do not fulfill their contractual obligations. Most of our credit exposures are with counterparties in the energy industry, including integrated oil companies, refiners and utilities, and are subject to normal industry credit risk. Over 78% of our exposure is with these large energy companies. This concentration of risk within the energy industry is reduced because of our broad base of domestic and international counterparties. We take the following measures to reduce this risk:

•

assess the financial strength of our counterparties through a credit analysis process;

•

limit the total exposure extended to individual counterparties, and may require collateral from some counterparties;

•

routinely monitor credit risk exposures, including sector, geographic and corporate concentrations of credit, and report these to management and the board of directors;

•

set and regularly review counterparty credit limits based on rating agency credit ratings and internal assessments of company and industry analysis; and

•

use standard agreements where possible that allow for the netting of exposures associated with a single counterparty.

We believe these measures minimize our overall credit risk; however, there can be no assurance that these processes will protect us against all losses from non-performance.

At December 31, 2012, only two counterparties individually made up more than 10% of our credit exposure. These counterparties are major integrated oil companies with strong investment-grade credit ratings.

The following table illustrates the composition of credit exposure by credit rating:


Credit Rating	December 31 2012			December 31 2011
A or higher		47	%		60	%
BBB		43	%		31	%
Non-Investment Grade		10	%		9	%

Total		100	%		100	%

Our maximum counterparty credit exposure at the balance sheet date consists primarily of the carrying amounts of non-derivative financial assets such as cash and cash equivalents, restricted cash, accounts receivable, as well as the fair value of derivative financial assets.

Collateral received from customers at December 31, 2012 includes $299 million of letters of credit. The cash received is included in accounts payable and accrued liabilities.

Liquidity risk is the risk that we will not be able to meet our financial obligations when they fall due. We require liquidity specifically to fund capital requirements, satisfy financial obligations as they become due, and to operate our energy marketing business. We generally rely on operating cash flows to provide liquidity as well as maintain significant undrawn committed credit facilities. At December 31, 2012, we had approximately $4.5 billion of cash and available committed lines of credit. This includes $1.2 billion of cash and cash equivalents on hand and undrawn term credit facilities of $3.5 billion, of which $223 million was supporting letters of credit at December 31, 2012. Of these term credit facilities, $3.0 billion is available until 2017, with the remainder available until 2014. We also had $389 million of uncommitted, unsecured credit facilities, of which $20 million was supporting letters of credit outstanding at December 31, 2012. Of these uncommitted facilities, $209 million is available exclusively for supporting letters of credit.

The following table details the contractual maturities for our non-derivative financial liabilities, including both the principal and interest cash flows at December 31, 2012:


(Cdn$ millions)	Total		< 1 Year		1-3 Years		4-5 Years		> 5 Years
Long-Term Debt		4,365		—		125		61		4,179
Cumulative Interest on Long-Term Debt ¹		6,532		294		583		573		5,082

Total		10,897		294		708		634		9,261

1	At December 31, 2012, none of our variable interest rate debt was drawn.

The following table details contractual maturities for our derivative financial liabilities at December 31, 2012. The consolidated balance sheet amounts for derivative financial liabilities included below are not materially different from the contractual amounts due on maturity.


(Cdn$ millions)	Total		< 1 Year		1-3 Years		4-5 Years		> 5 Years
Derivative Contracts (Note 8)		40		37		3		—		—

At December 31, 2012, collateral posted with counterparties includes $243 million of letters of credit. Cash posted is included with accounts receivable. Cash collateral is not normally applied to contract settlement. Once a contract has been settled, the collateral amounts are refunded. If there is a default, the cash is retained.

The commercial agreements our energy marketing group enter into often include financial assurance provisions that allow us and our counterparties to effectively manage credit risk. The agreements normally require collateral to be posted if an adverse credit-related event occurs, such as a drop in credit ratings to non-investment grade. Based on the derivative contracts in place and commodity prices at December 31, 2012, we could be required to post collateral of approximately $424 million if we were downgraded to non-investment grade. These obligations are reflected on our balance sheet and the posting of collateral merely secures the payment of such amounts. We have significant undrawn credit facilities and cash to fund these potential collateral requirements.

Our exchange-traded derivative contracts are also subject to margin requirements. We have margin deposits at December 31, 2012 of $21 million (2011—$45 million), which have been included in restricted cash.

10. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES


	December 31 2012		December 31 2011
Accrued Payables		1,196		1,035
Energy Marketing Payables		696		1,287
Trade Payables		349		288
Share-Based Compensation		159		31
Accrued Interest Payable		80		78
Dividends Payable		27		26
Other		182		122

Total		2,689		2,867

11. LONG-TERM DEBT


	December 31 2012			December 31 2011
Term Credit Facilities (A)		—			—
Notes, due 2015 (US$126 million) (B)		125			128
Notes, due 2017 (US$62 million) (C)		61			63
Notes, due 2019 (US$300 million) (D)		299			305
Notes, due 2028 (US$200 million) (E)		199			203
Notes, due 2032 (US$500 million) (F)		497			509
Notes, due 2035 (US$790 million) (G)		786			804
Notes, due 2037 (US$1,250 million) (H)		1,244			1,271
Notes, due 2039 (US$700 million) (I)		696			712
Subordinated Debentures, due 2043 (US$460 million) (J)		458			468

		4,365			4,463
Unamortized Debt Issue Costs		(77	)		(80	)

Total		4,288			4,383

(A) TERM CREDIT FACILITIES

We have committed unsecured term credit facilities of $3.5 billion (US$3.5 billion), which were not drawn at either December 31, 2012 or December 31, 2011. Of these facilities, $530 million is available until 2014 and $3.0 billion is available until 2017. Borrowings are available as Canadian bankers’ acceptances, LIBOR-based loans, Canadian prime rate loans, US-dollar base rate loans or British pound call-rate loans. Interest is payable at floating rates. At December 31, 2012, $223 million of these facilities were utilized to support outstanding letters of credit (2011—$367 million). During the year, we borrowed and repaid $254 million on our term credit facilities.

(B) NOTES, DUE 2015

During March 2005, we issued US$250 million of notes. Interest is payable semi-annually at a rate of 5.2% and the principal is to be repaid in March 2015. In 2011, we repurchased and cancelled US$124 million of principal of these notes. We paid $135 million for the repurchase and recorded a $14 million loss in 2011 as the difference between the carrying value and the redemption price. At December 31, 2012, US$126 million of notes remain outstanding. We may redeem part or all of the notes at any time. The redemption price will be the greater of par and an amount that provides the same yield as a US Treasury security having a term-to-maturity equal to the remaining term of the notes plus 0.15%.

During May 2007, we issued US$250 million of notes. Interest is payable semi-annually at a rate of 5.65% and the principal is to be repaid in May 2017. In 2011, we repurchased and cancelled US$188 million of principal of these notes. We paid $211 million for the repurchase and recorded a $25 million loss in 2011 as the difference between the carrying value and the redemption price. At December 31, 2012, US$62 million of notes remain outstanding. We may redeem part or all of the notes at any time. The redemption price will be the greater of par and an amount that provides the same yield as a US Treasury security having a term-to maturity equal to the remaining term of the notes plus 0.20%.

(D) NOTES, DUE 2019

During July 2009, we issued US$300 million of notes. Interest is payable semi-annually at a rate of 6.2% and the principal is to be repaid in July 2019. We may redeem part or all of the notes at any time. The redemption price will be the greater of par and an amount that provides the same yield as a US Treasury security having a term-to-maturity equal to the remaining term of the notes plus 0.40%.

(E) NOTES, DUE 2028

During April 1998, we issued US$200 million of notes. Interest is payable semi-annually at a rate of 7.4% and the principal is to be repaid in May 2028. We may redeem part or all of the notes at any time. The redemption price will be the greater of par and an amount that provides the same yield as a US Treasury security having a term-to-maturity equal to the remaining term of the notes plus 0.25%.

(F) NOTES, DUE 2032

During March 2002, we issued US$500 million of notes. Interest is payable semi-annually at a rate of 7.875% and the principal is to be repaid in March 2032. We may redeem part or all of the notes at any time. The redemption price will be the greater of par and an amount that provides the same yield as a US Treasury security having a term-to-maturity equal to the remaining term of the notes plus 0.375%.

(G) NOTES, DUE 2035

During March 2005, we issued US$790 million of notes. Interest is payable semi-annually at a rate of 5.875% and the principal is to be repaid in March 2035. We may redeem part or all of the notes at any time. The redemption price will be the greater of par and an amount that provides the same yield as a US Treasury security having a term-to-maturity equal to the remaining term of the notes plus 0.20%.

(H) NOTES, DUE 2037

During May 2007, we issued US$1,250 million of notes. Interest is payable semi-annually at a rate of 6.4% and the principal is to be repaid in May 2037. We may redeem part or all of the notes at any time. The redemption price will be the greater of par and an amount that provides the same yield as a US Treasury security having a term-to-maturity equal to the remaining term of the notes plus 0.35%.

(I) NOTES, DUE 2039

During July 2009, we issued US$700 million of notes. Interest is payable semi-annually at a rate of 7.5% and the principal is to be repaid in July 2039. We may redeem part or all of the notes at any time. The redemption price will be the greater of par and an amount that provides the same yield as a US Treasury security having a term-to-maturity equal to the remaining term of the notes plus 0.45%.

(J) SUBORDINATED DEBENTURES, DUE 2043

During November 2003, we issued US$460 million of unsecured subordinated debentures. Interest is payable quarterly at a rate of 7.35%, and the principal is to be repaid in November 2043. We may redeem part or all of the debentures at any time. The redemption price is equal to the par value of the principal amount plus any accrued and unpaid interest to the redemption date.

(K) LONG-TERM DEBT REPAYMENTS

The following schedule outlines the required timetable of debt repayments and does not preclude earlier repayments as per the provisions of the respective notes.


(Cdn$ millions)	Total		2013		2014		2015		2016		2017		Thereafter
Long-Term Debt		4,365		—		—		125		—		61		4,179

(L) DEBT COVENANTS

Some of our debt instruments contain covenants with respect to certain financial ratios and our ability to grant security. We are required to maintain a debt to EBITDA ratio of less than 3.5. EBITDA is defined as net income plus interest expense, income tax expense, DD&A, exploration expense, equity loss, extraordinary and non-recurring losses and other non-cash expenses less equity income, income tax recoveries and extraordinary and non-recurring income and gains. For the year ended December 31, 2012, this ratio was 0.89 times (2011—0.95). At December 31, 2012 and 2011 we were in compliance with all covenants.

(M) CREDIT FACILITIES

Nexen has uncommitted, unsecured credit facilities of approximately $180 million (US$180 million), none of which were drawn at either December 31, 2012 or 2011. We utilized $4 million of these facilities to support outstanding letters of credit at December 31, 2012 (2011—$17 million). Interest is payable at floating rates.

Nexen has uncommitted, unsecured credit facilities exclusive to letters of credit of approximately $209 million (US$210 million). We utilized $16 million of these facilities to support outstanding letters of credit at December 31, 2012 (2011—$4 million).

(N) OTHER

We recorded $94 million (2011—$87 million net gain) of unrealized foreign exchange net gains on long-term debt in OCI.

12. FINANCE EXPENSE


	2012			2011
Long-Term Debt Interest Expense		296			304
Accretion Expense Related to Asset Retirement Obligations		52			44
Other Interest and Fees		25			27

Total		373			375
Less: Capitalized at 6.7% (2011—6.7%)		(72	)		(124	)

Total ¹		301			251

1	Excludes finance expense related to our chemical operations (see Note 23).

Capitalized interest relates to and is included as part of the cost of our oil and gas properties. The capitalization rates are based on our weighted-average cost of borrowings.

13. CAPITAL MANAGEMENT

Our objective for managing our capital structure is to ensure that we have the financial capacity, liquidity and flexibility to fund our investment in full-cycle exploration and development of conventional and unconventional resources and for our energy marketing activities. We generally rely on operating cash flows to fund capital investments. However, given the long cycle-time of some of our development projects, which require significant capital investment prior to cash flow generation, and volatile commodity prices, it is not unusual for capital expenditures to exceed our cash flow from operating activities in any given period. As such, our financing needs depend on the timing of expected net cash flows in a particular development or commodity cycle. This requires us to maintain financial flexibility and liquidity. Our capital management policies are aimed at:

•

maintaining an appropriate balance between short-term borrowings, long-term debt and equity;

•

maintaining sufficient undrawn committed credit capacity to provide liquidity;

•

ensuring ample covenant room permitting us to draw on credit lines as required; and

•

ensuring we maintain a credit rating that is appropriate for our circumstances.

We have the ability to change our capital structure by issuing additional equity or debt, returning cash to shareholders and making adjustments to our capital investment programs. Our capital consists of equity, short-term borrowings, long-term debt and cash and cash equivalents as follows:


Net Debt ¹	December 31 2012			December 31 2011
Long-Term Debt		4,288			4,383
Less: Cash and Cash Equivalents		(1,174	)		(845	)

Total		3,114			3,538

Equity ²		8,805			8,373

1	Includes all of our borrowings and is calculated as long-term debt and short-term borrowings less cash and cash equivalents.

2	Equity is the historical issue of equity and accumulated retained earnings.

We monitor the leverage in our capital structure and the strength of our balance sheet by reviewing the ratio of net debt to adjusted cash flow (cash flow from operating activities before changes in non-cash working capital and other).

Net debt and adjusted cash flow are non-GAAP measures that are unlikely to be comparable to similar measures presented by others. We calculate net debt using the GAAP measures of long-term debt and short-term borrowings less cash and cash equivalents (excluding restricted cash).

For the twelve months ended December 31, 2012, the net debt to adjusted cash flow was 1.2 times compared to 1.5 times at December 31, 2011. While we typically expect the target ratio to fluctuate between 1.0 and 2.0 times under normalized commodity prices, this can be higher or lower depending on commodity price volatility, where we are in the investment cycle, or when we pursue strategic opportunities requiring additional investment. Whenever we exceed our target ratio, we assess whether we need to develop a strategy to reduce our leverage and lower this ratio back to target levels over time. Our objectives for managing our capital structure or targets have not changed from last year.

14. ASSET RETIREMENT OBLIGATIONS

Changes in carrying amounts of our ARO provision are as follows:


	2012			2011
ARO, Beginning of Year		2,076			1,571
Obligations Incurred with Development Activities		84			69
Changes in Estimates		121			320
Change in Discount Rate		221			130
Obligations Related to Dispositions		(60	)		(9	)
Obligations Settled		(109	)		(72	)
Accretion		52			44
Effects of Changes in Foreign Exchange Rates		10			23

Balance at End of Year		2,395			2,076

Of which:
Due Within Twelve Months ¹		126			66
Due After Twelve Months		2,269			2,010

1	Included in accounts payable and accrued liabilities.

ARO represents the present value of estimated remediation and reclamation costs associated with our PP&E. We discounted the estimated ARO using a weighted-average risk-free rate of 2.1% (2011—2.6%). While the provision for abandonment is based on our best estimates of future costs and the economic lives of the assets involved, there is uncertainty regarding both the amount and timing of incurring these costs. We expect approximately $341 million included in our ARO will be settled over the next five years with the balance settling beyond that. We expect to fund ARO from future cash flow from operations.

15. OTHER LONG-TERM LIABILITIES


	December 31 2012		December 31 2011
Defined Benefit Pension Obligations (Note 16)		167		208
Long-Term Insurance Payable		50		54
Finance Lease Obligations		40		41
Other		143		59

Total		400		362

16. PENSION AND OTHER POST-RETIREMENT BENEFITS

Nexen has defined benefit and defined contribution pension plans, as well as other post-retirement benefit programs, which cover substantially all employees. Syncrude has a defined benefit plan for its employees, and we disclose only our proportionate share of this plan.

(A) DEFINED BENEFIT PENSION PLANS

The cost of pension benefits earned by employees is determined using the projected-benefit method prorated on employment services and is expensed as services are rendered. We fund these plans according to federal and provincial government regulations by contributing to trust funds administered by an independent trustee. These funds are invested primarily in equities and bonds.


	2012
	Nexen
	Registered			Supplemental¹			Total			Syncrude			Total
Benefit Obligations
Beginning of Year		344			120			464			189			653
Service Cost		25			8			33			8			41
Interest Cost		16			5			21			8			29
Plan Participants’ Contributions		7			—			7			1			8
Actuarial Loss		35			10			45			8			53
Benefits Paid		(25	)		(7	)		(32	)		(7	)		(39	)

End of Year ¹		402			136			538			207			745


Plan Assets
Beginning of Year		328			—			328			98			426
Expected Return		20			—			20			7			27
Employer’s Contributions		31			57			88			20			108
Plan Participants’ Contributions		7			—			7			1			8
Actuarial Gain		11			—			11			2			13
Benefits Paid		(25	)		(7	)		(32	)		(7	)		(39	)

End of Year		372			50			422			121			543

Net Pension Liability		(30	)		(86	)		(116	)		(86	)		(202	)


Pension Liability
Accounts Payable and Accrued Liabilities		(16	)		(4	)		(20	)		(15	)		(35	)
Other Long-Term Liabilities (Note 15)		(14	)		(82	)		(96	)		(71	)		(167	)

Net Pension Liability		(30	)		(86	)		(116	)		(86	)		(202	)


Assumptions (%)
Accrued Benefit Obligation at December 31 Discount Rate								4.00			4.00
Long-Term Rate of Employee Compensation Increase								4.00			4.56
Inflation Rate								2.00			5.00
Benefit Cost for Year Ended December 31 Discount Rate								4.50			4.00
Long-Term Annual Rate of Return on Plan Assets ²								6.25			6.50

1	Includes obligations for supplemental benefits to the extent that the benefit is limited by statutory guidelines. The obligations for supplemental benefits are backed by irrevocable letters of credit and cash.

2	The long-term annual rate of return on plan assets assumption is based on a mix of historical market returns for debt and equity securities.


	2011
	Nexen
	Registered			Supplemental¹			Total			Syncrude			Total
Benefit Obligations
Beginning of Year		291			97			388			151			539
Service Cost		21			5			26			6			32
Interest Cost		16			5			21			8			29
Plan Participants’ Contributions		6			—			6			1			7
Actuarial Loss		25			16			41			29			70
Benefits Paid		(15	)		(3	)		(18	)		(6	)		(24	)

End of Year ¹		344			120			464			189			653


Plan Assets
Beginning of Year		312			—			312			87			399
Expected Return		21			—			21			7			28
Employer’s Contributions		26			3			29			13			42
Plan Participants’ Contributions		6			—			6			1			7
Actuarial Loss		(22	)		—			(22	)		(5	)		(27	)
Benefits Paid		(15	)		(3	)		(18	)		(5	)		(23	)

End of Year		328			—			328			98			426

Net Pension Liability		(16	)		(120	)		(136	)		(91	)		(227	)


Pension Liability
Accounts Payable and Accrued Liabilities		(6	)		(4	)		(10	)		(9	)		(19	)
Other Long-Term Liabilities (Note 15)		(10	)		(116	)		(126	)		(82	)		(208	)

Net Pension Liability		(16	)		(120	)		(136	)		(91	)		(227	)


Assumptions *(%)*
Accrued Benefit Obligation at December 31 Discount Rate								4.50			4.25
Long-Term Rate of Employee Compensation Increase								4.00			4.50
Inflation Rate								2.00			5.00
Benefit Cost for Year Ended December 31 Discount Rate								5.25			4.25
Long-Term Annual Rate of Return on Plan Assets ²								6.75			7.30

1	Includes obligations for supplemental benefits to the extent that the benefit is limited by statutory guidelines. The obligations for supplemental benefits are backed by irrevocable letters of credit.

2	The long-term annual rate of return on plan assets assumption is based on a mix of historical market returns for debt and equity securities.


History of Surplus (Deficit) and of Experience Gains and Losses	2012			2011			2010
Benefit Obligation at December 31		745			653			539
Fair Value of Plan Assets at December 31		543			426			399

Surplus (Deficit)		(202	)		(227	)		(140	)


Experience Gains (Losses) on Plan Liabilities		(4	)		(5	)		—
Actuarial Gain (Loss) on Plan Assets		13			(27	)		10
Actual Return on Plan Assets		40			1			36


Defined Benefit Pension Plan Expense	2012			2011
Nexen
Cost of Benefits Earned by Employees		33			26
Interest Cost on Benefits Earned		21			21
Expected Return on Plan Assets ¹		(20	)		(21	)

Net Pension Expense		34			26


Syncrude ²
Cost of Benefit Earned by Employees		8			6
Interest Cost on Benefits Earned		8			8
Expected Return on Plan Assets ³		(7	)		(7	)

Net Pension Expense		9			7


Total Net Pension Expense ⁴		43			33

1	Actual gain on Nexen plan assets was $31 million (2011—$1 million loss).

2	Nexen’s share of Syncrude’s employee pension plans.

3	Actual gain on Syncrude plan assets was $9 million (2011—$2 million gain).

4	Net pension expense is reported principally within operating expense and general and administrative expense in the Consolidated Statement of Income.

(B) PLAN ASSET ALLOCATION AT DECEMBER 31

Our investment goal for the assets in our defined benefit pension plans is to preserve capital and earn a long-term rate of return on assets, net of all management expenses, in excess of the inflation rate. Investment funds are managed by external fund managers based on policies approved by the board of directors and pension management committee of Nexen. Nexen’s investment strategy is to diversify plan assets between debt and equity securities of Canadian and non-Canadian corporations that are traded on recognized stock exchanges. Allowable and prohibited investment types are also prescribed in Nexen’s investment policies.

Nexen’s investment strategy is to ensure appropriate diversification between and within asset classes in order to optimize the return/risk trade-off. Nexen’s policy allows investment in equities, fixed income, cash and real estate assets. Derivative instruments can be utilized as deemed appropriate by the pension management committee. Nexen’s expected long-term annual rate of return on plan assets assumption is based on a mix of historical market returns for debt and equity securities. The returns that are used as the basis for future expectations are derived from the major asset categories that Nexen is currently invested in.

The target allocations for plan assets are identified in the table below. Equity securities primarily include investments in large-cap companies, both Canadian and foreign, and debt securities primarily include corporate bonds of companies from diversified industries and Canadian treasury issuances. The Canadian fixed income pooled funds invest in low-cost fixed income index funds that track the DEX Universe Bond Index. The Canadian equity pooled funds invest in low-cost equity funds that track the S&P/TSX Composite Index. The foreign equity pooled funds invest in low-cost equity index funds that track the S&P 500 and MSCI EAFE Indexes.

Nexen also has an unregistered employer-funded supplemental defined benefit pension plan that covers obligations that are limited by statutory guidelines. Syncrude’s pension plan is governed and administered separately from ours. Syncrude’s plan assets are subject to similar investment goals, policies and strategies.


Plan Asset Allocation (%)	Expected 2013		2012		2011
Nexen
Equity Securities		65		66		65
Debt Securities		35		34		35

Total		100		100		100

Syncrude
Equity Securities		60		60		60
Debt Securities		40		40		40

Total		100		100		100

i) The fair value of Nexen’s defined benefit pension plan assets at December 31, 2012 by asset category are as follows:


	Fair Value Measurements at December 31, 2012
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
Asset Category
Cash		51		—		—		51
Pooled Funds
Canadian Fixed Income		—		125		—		125
Canadian Equity		—		93		—		93
Foreign Equity		—		153		—		153

Total		51		371		—		422

ii) The fair value of Nexen’s defined benefit pension plan assets at December 31, 2011 by asset category are as follows:


	Fair Value Measurements at December 31, 2011
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
Asset Category
Cash		2		—		—		2
Pooled Funds
Canadian Fixed Income		—		114		—		114
Canadian Equity		—		80		—		80
Foreign Equity		—		132		—		132

Total		2		326		—		328

iii) The fair value of Syncrude’s defined benefit pension plan assets at December 31, 2012 by asset category are as follows:


	Fair Value Measurements at December 31, 2012
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
Asset Category
Cash		1		—		—		1
Pooled Funds
Canadian Fixed Income		—		46		—		46
Canadian Equity		—		30		—		30
Foreign Equity		—		43		—		43
Other Types of Investments
Other		—		—		1		1

Total		1		119		1		121

iv) The fair value of Syncrude’s defined benefit pension plan assets at December 31, 2011 by asset category are as follows:


	Fair Value Measurements at December 31, 2011
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
Asset Category
Cash		1		—		—		1
Pooled Funds
Canadian Fixed Income		—		38		—		38
Canadian Equity		—		25		—		25
Foreign Equity		—		33		—		33
Other Types of Investments
Other		—		—		1		1

Total		1		96		1		98

Under these plans, pension benefits are based on plan contributions. During 2012, Canadian pension expense for these plans was $6 million (2011—$7 million). During 2012, US pension expense for these plans was $6 million (2011—$6 million) and UK pension expense for these plans was $8 million (2011—$6 million).

(D) POST-RETIREMENT BENEFITS

Nexen provides certain post-retirement benefits, including group life and supplemental health insurance, to eligible employees and their dependents. The present value of Nexen employees’ future post-retirement benefits at December 31, 2012 was $22 million (2011—$18 million).

(E) EMPLOYER FUNDING CONTRIBUTIONS AND BENEFIT PAYMENTS

Canadian regulators have prescribed funding requirements for our defined benefit plans. Our funding contributions over the last three years have met these requirements and also included additional discretionary contributions permitted by law to ensure the plans are adequately funded in light of potential future changes in assumptions. For our defined contribution pension plans, we make contributions on behalf of our employees and no further obligation exists. Our funding contributions for our defined benefit plans are:


	Expected 2013		2012		2011
Nexen		40		88		29
Syncrude		20		20		13

Total Defined Benefit Contribution		60		108		42

Our most recent funding valuation was prepared as of June 30, 2012. Our next funding valuation is required by June 30, 2015. Syncrude’s most recent funding valuation was prepared as of December 31, 2011, and their next funding valuation is required by December 31, 2014.

Our total benefit payments to participants in 2012 were $32 million for Nexen (2011—$18 million). Our share of Syncrude’s total benefit payments in 2012 was $7 million (2011—$6 million).

17. RELATED PARTY DISCLOSURES

(A) MAJOR SUBSIDIARIES

The Consolidated Financial Statements include the financial statements of Nexen Inc. and our subsidiaries as at December 31, 2012. The following is a list of the major subsidiaries of our operations. Transactions between subsidiaries are eliminated on consolidation. Nexen did not have any material related party transactions with entities outside the consolidated group in the years ended December 31, 2012 and 2011.

Major Subsidiaries

Jurisdiction
of
Incorporation

Principal
Activities

Ownership

Nexen Petroleum UK Limited

England & Wales

Oil & Gas

100

Nexen Petroleum Nigeria Limited

Nigeria

Oil & Gas

100

Nexen Petroleum Offshore USA Inc.

Delaware

Oil & Gas

100

Nexen Marketing

Alberta

Marketing

100

Nexen Oil Sands Partnership

Alberta

Oil & Gas

100

(B) KEY MANAGEMENT PERSONNEL COMPENSATION

Key management personnel compensation includes all compensation related to executive management and members of the board of directors of Nexen Inc. during the year.


	2012		2011
Short-Term Benefits ¹		8		9
Post Employment Benefits ²		3		3
Share-Based Compensation ³		24		(11	)

Total Compensation		35		1

1	Includes executives’ salaries, directors’ fees and non-equity incentive plan compensation and other short-term compensation.

2	Represents the pension costs.

3	Share-based compensation computed for executive management and the board of directors as described in Note 18 including the change in fair value of outstanding awards.

18. EQUITY

(A) AUTHORIZED CAPITAL

Authorized share capital consists of an unlimited number of common shares of no par value and an unlimited number of Class A preferred shares of no par value, issuable in series.

Common Shares

At December 31, 2012, there were 530,036,892 common shares outstanding (2011—527,892,635). The rights, privileges, restrictions and conditions attached to common shares include a vote at all meetings of shareholders they are invited to, the receipt of any dividend declared by the board of directors on the common shares, and receipt of all remaining property of Nexen upon dissolution.

Preferred Shares

At December 31, 2012, there were 8,000,000 Cumulative Redeemable Class A Rate Reset Preferred Shares, Series 2 (Series 2 Shares) outstanding (2011—nil). The holders of the Series 2 Shares are entitled to receive a fixed cumulative dividend at an annual rate of $1.25 per share, payable quarterly.

On September 20, 2012, the Arrangement Agreement was approved by the common and preferred shareholders of Nexen Inc. as described in Note 1.

(B) ISSUED COMMON SHARES AND DIVIDENDS

We paid dividends of $0.20 per common share for the year ended December 31, 2012 (2011—$0.20).

We paid dividends of $1.0178 per preferred share for the year ended December 31, 2012 (2011—nil).

Dividends paid to holders of common and preferred shares have been designated as “eligible dividends” for Canadian tax purposes.


(thousands of shares)	2012		2011
Issued Common Shares, Beginning of Year		527,893		525,706
Issue of Common Shares for Cash
Exercise of Tandem Options		139		59
Dividend Reinvestment Plan		1,478		1,542
Employee Flow-Through Shares		527		586

Balance at End of Year		530,037		527,893


Cash Consideration (Cdn$ millions)
Exercise of Tandem Options		3		1
Dividend Reinvestment Plan		24		30
Employee Flow-Through Shares		10		15

Total		37		46

During the year, 1,478,421 common shares were issued under the Dividend Reinvestment Plan and a balance of 1,601,043 common shares (2011—3,079,464) was reserved for issuance at December 31, 2012.

Tandem and performance tandem options to purchase common shares are awarded to officers and employees. Each option permits the holder the right to either purchase one Nexen common share at the exercise price or receive a cash payment equal to the excess of market price over the exercise price. The following tandem options have been granted:


	2012					2011
(thousands of shares)	Options (thousands)			Weighted Average Exercise Price ($/option)		Options (thousands)			Weighted Average Exercise Price ($/option)
Outstanding TOPs, Beginning of Year		14,854			23		18,435			25
Granted		1,368			20		1,582			17
Exercised for Shares		(139	)		21		(59	)		16
Surrendered for Cash		(769	)		21		(394	)		20
Cancelled		(2,116	)		25		(1,248	)		25
Expired		(1,482	)		29		(3,462	)		31

Balance at End of Year		11,716	¹		22		14,854			23


TOPs Exercisable at End of Year		8,082			22		8,878			24
Weighted Average Share Price During Year		21.41					20.80

1	Approximately 8% of TOPs outstanding at December 31, 2012 contain performance vesting conditions.

The range of exercise prices of options outstanding at December 31, 2012 is as follows:


	Outstanding Tandem and Performance Tandem Options
	Number of Options (thousands)		Weighted Average Exercise Price ($/option)		Weighted Average Years to Expiry (years)
$15.00 to $19.99		4,251		19		3
$20.00 to $24.99		7,409		23		2
$25.00 to $29.99		51		26		2
$30.00 to $34.99		—		—		—
$35.00 to $39.99		—		—		—
$40.00 to $44.99		5		40		—

Total		11,716

Fair values and associated details for tandem and performance tandem options granted during the year:


	2012			2011
Option Pricing Model Used for TOPs		Black-Scholes			Black-Scholes
Weighted Average Fair Value ($/option)		9.75			3.86
Expected Volatility		40	%		40	%
Weighted-Average Expected Life (years)		2.52			3.14
Expected Annual Dividends per Common Share ($/share)		0.20			0.20
Risk-Free Interest Rate		1.41	%		1.21	%
Expected Annual Forfeiture Rate		4	%		4	%

These assumptions are based on multiple factors, including: i) historical exercise patterns of employees in relatively homogenous groups with respect to exercise and post-vesting employment termination behaviors; ii) expected future exercising patterns for those same homogenous groups; iii) the implied volatility of our share price (based on the prior three years historic volatility); iv) our expected future dividend levels; and v) the interest rate for Government of Canada bonds.

The total share-based compensation expense arising from tandem options for the year ended December 31, 2012 was $63 million (2011—$39 million recovery). The total carrying value of liabilities arising from tandem options at December 31, 2012 amounted to $73 million (2011—$15 million). The total intrinsic value of all vested tandem options at December 31, 2012 amounted to $37 million (2011—nil).

(D) STOCK APPRECIATION RIGHTS

STARs and performance STARs are awarded to eligible employees. They permit the holder to receive a cash payment equal to the excess of the market price of the common shares over the exercise price of the right. The following STARs have been granted:


	2012					2011
(thousands of shares)	STARs (thousands)			Weighted Average Exercise Price ($/STAR)		STARs (thousands)			Weighted Average Exercise Price ($/STAR)
Outstanding STARs, Beginning of Year		14,407			23		18,993			25
Granted		339			20		377			18
Exercised for Cash		(1,249	)		20		(578	)		18
Cancelled		(1,630	)		25		(1,163	)		24
Expired		(2,414	)		29		(3,222	)		31

End of Year		9,453	¹		22		14,407			23


STARs Exercisable at End of Year		7,993			22		10,512			24
Weighted Average Share Price During Year		21.41					20.80

1	Approximately 2% of STARs outstanding at December 31, 2012 contain performance vesting conditions.

The range of exercise prices of STARs outstanding at December 31, 2012 is as follows:


	Outstanding STARs and Performance STARs
	Number of Options (thousands)		Weighted Average Exercise Price ($/STAR)		Weighted Average Years to Expiry (years)
$ 10.00 to $14.99		16		14		1
$ 15.00 to $19.99		2,978		19		2
$ 20.00 to $24.99		6,388		24		2
$ 25.00 to $29.99		40		27		1
$ 30.00 to $34.99		10		32		—
$ 35.00 to $39.99		20		37		—
$ 40.00 to $44.99		1		40		—

Total		9,453

Fair values and associated details for STARs and performance STARs granted during the year:


(thousands of shares)	2012			2011
Option Pricing Model Used for STARs		Black-Scholes			Black-Scholes
Weighted Average Fair Value ($/STAR)		9.58			3.48
Expected Volatility		40	%		40	%
Weighted-Average Expected Life (years)		2.26			2.84
Expected Annual Dividends per Common Share ($/share)		0.20			0.20
Risk-Free Interest Rate		1.41	%		1.21	%
Expected Annual Forfeiture Rate		5	%		5	%

The total share-based compensation expense arising from STARs for the year ended December 31, 2012 was $53 million (2011—$45 million recovery). The total carrying value of liabilities arising from STARs at December 31, 2012 amounted to $58 million (2011—$12 million). The total intrinsic value of all vested STARs at December 31, 2012 amounted to $36 million (2011—nil).

(E) SHARE UNIT PLANS

Restricted Share Units (RSUs) are awarded to eligible employees and permit the holder to receive a cash payment equal to the market value of the share on the vesting date. Performance Share Units (PSUs) are RSUs with a performance-vesting condition. Deferred Share Units (DSUs) are awarded to directors. The following RSUs, PSUs and DSUs have been granted:


(thousands of units)	RSU			PSU			DSU
Outstanding December 31, 2010		925			—			576

Granted		1,458			390			143
Redeemed for Cash		(302	)		—			—
Cancelled		(56	)		—			—

Outstanding December 31, 2011		2,025			390			719

Granted		1,943			318			87
Redeemed for Cash		(705	)		(98	)		(54	)
Cancelled		(306	)		(120	)		—

Outstanding December 31, 2012		2,957			490			752

Weighted Average Fair Value per Unit ($/unit)		26.70			26.07			26.60
Liability ($ millions)		41			8			20
Weighted Average Remaining Time to Expiry (years)		1.18			1.20

For the year ended December 31, 2012, we recognized share-based compensation expense related to RSUs and PSUs in the amount of $61 million (2011—$10 million expense). RSUs and PSUs are paid immediately on vesting. We recognized a share-based compensation expense related to DSUs in the amount of $8 million (2011—$1 million recovery).

19. COMMITMENTS, CONTINGENCIES AND GUARANTEES

We assume various contractual obligations and commitments in the normal course of our operations. Our operating leases, transportation, processing and storage commitments, finance leases, and drilling rig commitments as at December 31, 2012 are comprised of the following:


	2013		2014		2015		2016		2017		Thereafter
Operating Leases		76		56		27		25		13		79
Transportation, Processing and Storage Commitments		118		111		80		76		62		427
Drilling Rig Commitments ¹		387		88		24		3		1		—
Finance Leases		4		4		4		4		4		58

1	Total drilling rig commitments are disclosed net of $119 million of subleases.

During 2012, total rental expense under operating leases was $76 million (2011—$53 million).

We have a number of lawsuits and claims pending, including tax audits, the ultimate results of which cannot be ascertained at this time. We record costs as they are incurred or become determinable.

From time to time, we enter into contracts that require us to indemnify parties against certain types of possible third-party claims, particularly when these contracts relate to divestiture transactions. On occasion, we may provide routine indemnifications. The terms of such obligations vary and, generally, a maximum is not explicitly stated. Because the obligations in these agreements are often not explicitly stated, the overall maximum of the obligations cannot be reasonably estimated. Historically, we have not been obligated to make significant payments for these obligations. We believe that payments, if any, related to existing indemnities would not have a material adverse effect on our liquidity, financial condition or results of operations.

20. MARKETING AND OTHER INCOME


	2012			2011
Marketing Revenue, Net		314			195
Interest Income		24			4
Insurance Proceeds		—			26
Change in Fair Value of Crude Oil Put Options		(38	)		(23	)
Foreign Exchange Gains (Losses)		(67	)		36
Other		48			57

Total		281			295

21. INCOME TAXES

(A) PROVISION FOR (RECOVERY OF) INCOME TAXES


	2012			2011
Current Tax
Charge for Year		1,460			1,584
Deferred Tax
Temporary Differences in the Current Year		(202	)		(526	)
Impact of Changes in Tax Rates and Laws		63			270

Total Income Tax Expense Recognized in Net Income		1,321			1,328

(B) DEFERRED INCOME TAX


	Consolidated Statement of Income						Consolidated Balance Sheet
	2012			2011			2012			2011
Property, Plant and Equipment and Other		215			(25	)		3,046			3,027
Tax Losses and Credits ¹		(366	)		(215	)		(2,199	)		(1,985	)
Foreign-Denominated Debt		12			(16	)		121			108

Net Deferred Income Tax		(139	)		(256	)		968			1,150

1	Deferred tax assets have been recognized as it is probable there will be sufficient future taxable profits.


Net Deferred Income Tax Liability	2012			2011
Balance, Beginning of Year		1,150			1,327
Annual Recovery in Net Income		(139	)		(256	)
Provision (Recovery) in Other Comprehensive Income		1			(35	)
Provision (Recovery) in Equity		(13	)		18
Discontinued Operations		—			51
Effects of changes in Foreign Exchange Rates		(31	)		35
Other		—			10

Balance, End of Year		968			1,150


	2012			2011
Income before Provision for Income Taxes		1,654			1,723
Provision for Income Taxes Computed at the Canadian Statutory Rate		413			431
Add (Deduct) the Tax Effect of:
Foreign Tax Rate Differential		860			701
Effect of Changes in Tax Rates ¹		63			270
Lower Tax Rates on Capital (Gains) Losses		(12	)		16
Recognition of Previously Unrecognized Tax Assets		(16	)		(70	)
Share-Based Compensation		16			(10	)
Non-Deductible Expenses and Other		(3	)		(10	)

Provision for Income Taxes		1,321			1,328

Effective Tax Rate		80	%		77	%

Effective March 21, 2012, the UK government enacted a rate restriction of 50% on decommissioning charges. This increased our deferred tax liability and resulted in a one-time charge of $63 million to deferred tax expense. Effective March 24, 2011, the UK government enacted an increase to the supplementary charge tax rate on our North Sea oil and gas activities of 12%, which increased the statutory oil and gas income tax rate to 62%. This rate change increased our deferred tax liabilities, resulting in a one-time charge of $270 million to deferred tax expense.

(D) UNRECOGNIZED DEFERRED TAX ASSETS

At December 31, 2012, we had unrecognized deferred tax assets related to unused tax credits totaling $1,046 million (2011—$977 million). This includes $908 million (2011—$871 million) of Nigeria investment tax credits with no fixed expiry date. The remainder expires between 2015 and 2031.

We had no significant unrecognized deferred tax assets related to tax losses or other deductible temporary differences as at December 31, 2012.

(E) INCOME TAX AUDITS

Nexen’s income tax filings are subject to audit by taxation authorities in numerous jurisdictions. There are audits in progress and items under review, some of which may increase our tax liability. In addition, we have filed appeals and have disputed certain issues. While the results of these items cannot be ascertained at this time, we believe we have an adequate provision for income taxes based on available information.

22. EARNINGS PER COMMON SHARE

We calculate basic earnings per common share using net income attributable to Nexen Inc. shareholders adjusted for preferred share dividends and divided by the weighted-average number of common shares outstanding. We calculate diluted earnings per common share in the same manner as basic, except we adjust basic earnings for the potential conversion of the subordinated debentures and potential exercise of outstanding tandem options for shares, and use the weighted-average number of diluted common shares outstanding in the denominator.


(Cdn$ millions)	2012			2011
Net Income Attributable to Nexen Inc. Shareholders		333			697
Preferred Share Dividends		(8	)		—

Net Income Attributable to Nexen Inc. Shareholders, Basic		325			697
Potential Tandem Options Exercises		—			(40	)
Potential Conversion of Subordinated Debentures		—			25

Net Income Attributable to Nexen Inc. Shareholders, Diluted		325			682


(millions of shares)
Weighted Average Number of Common Shares Outstanding, Basic		529.5			527.2
Shares Issuable Pursuant to Tandem Options		—			2.5
Shares Notionally Purchased from Proceeds of Tandem Options		—			(2.3	)
Common Shares Issuable Pursuant to Potential Conversion of Subordinated Debentures		—			21.5

Weighted Average Number of Common Shares Outstanding, Diluted		529.5			548.9

In calculating the weighted-average number of diluted common shares outstanding and related earnings adjustments for the year ended December 31, 2012, we excluded 11,129,646 tandem options (2011—14,596,971) because their exercise price was greater than the average common share market price in the year. In 2012, there were no dilutive instruments. In 2011, the potential conversion of tandem options and subordinated debentures were the only potential dilutive instruments.

23. DISPOSITIONS

(A) DISCONTINUED OPERATIONS

In February 2011, we completed the sale of our 62.7% investment in Canexus, which operates a chemicals business, for net proceeds of $458 million and we realized a gain on disposition of $348 million in the first quarter. The gain on sale and results of our chemicals business have been presented as discontinued operations.


	2011 Chemicals
Revenues and Other Income
Net Sales		42
Other		(1	)
Gain on Disposition		348

		389

Expenses
Operating		25
Depreciation, Depletion, Amortization and Impairment		4
Transportation and Other		2
General and Administrative		2
Finance		2

		35

Income before Provision for Income Taxes		354
Less: Provision for Deferred Income Taxes		51

Income before Non-Controlling Interests		303
Less: Non-Controlling Interests		1

Net Income from Discontinued Operations, Net of Tax		302


Earnings Per Common Share
Basic		0.57
Diluted		0.55

There were no assets or liabilities related to our chemical operations at December 31, 2012 and 2011.

(B) ASSET DISPOSITIONS

Asset Dispositions

Canadian Shale Gas Joint Venture

During the third quarter of 2012, we closed the sale of a 40% working interest in our northeast British Columbia shale gas operations to INPEX Gas British Columbia Ltd. (IGBC). Upon closing we received $821 million in cash, comprised of the initial cash payment, the carry associated with Nexen’s capital and IGBC’s share of costs since the July 1, 2011 effective date of the transaction. We recorded a pre-tax gain on sale of $142 million on closing.

Canadian Undeveloped Leases

During the second quarter of 2012, we sold non-core leases in Canada for proceeds of $46 million and recognized a gain of $45 million.

UK North Sea

During the fourth quarter of 2011, we sold our non-operated working interest in the Duart field for proceeds of $38 million. The sale closed in December 2011 and we recognized a gain on sale of $38 million in the fourth quarter of 2011.

24. CASH FLOWS

(A) CHARGES AND CREDITS TO INCOME NOT INVOLVING CASH


	2012			2011
Depreciation, Depletion, Amortization and Impairment		1,951			1,913
Share-Based Compensation (Recovery)		157			(85	)
Change in Fair Value of Crude Oil Put Options		38			23
Loss on Debt Redemption and Repurchase		—			91
Net Gain on Dispositions		(194	)		(38	)
Non-Cash Items Included in Discontinued Operations		—			(290	)
Provision for Deferred Income Taxes		(139	)		(256	)
Foreign Exchange		58			(33	)
Other		66			10

Total		1,937			1,335

(B) CHANGES IN NON-CASH WORKING CAPITAL


	2012			2011
Accounts Receivable		441			(381	)
Inventories and Supplies		(71	)		208
Other Current Assets		27			26
Accounts Payable and Accrued Liabilities		(420	)		594
Current Income Taxes Payable		(62	)		129

Total		(85	)		576


Relating to:
Operating Activities		(86	)		255
Investing Activities		1			321

Total		(85	)		576


	2012		2011
Interest Paid		294		305
Income Taxes Paid		1,455		1,448

25. OPERATING SEGMENTS AND RELATED INFORMATION

We report our segments to align with our key growth areas, specifically, Conventional Oil and Gas, Oil Sands and Shale Gas.

Nexen has the following operating segments:

Conventional Oil and Gas: We explore for, develop and produce crude oil and natural gas from conventional sources around the world. Our operations are focused on the UK, North America (Canada and US) and other countries (Nigeria, Colombia and Yemen).

Oil Sands: We develop and produce synthetic crude oil from the Athabasca oil sands in northern Alberta. We produce bitumen using in situ and mining technologies and upgrade it into synthetic crude oil before ultimate sale. Our in situ activities are comprised of our operations at Long Lake and future development phases. Our mining activities are conducted through our 7.23% ownership of the Syncrude Joint Venture.

Shale Gas: We explore for and produce unconventional gas from shale formations in northeastern British Columbia. Production and results of operations are included within Conventional Oil and Gas until they become significant.

Corporate and Other includes energy marketing, unallocated items and the results of Canexus prior to its sale in February 2011. The results of Canexus have been presented as discontinued operations.

The accounting policies of our operating segments are the same as those described in Note 2. Net income (loss) of our operating segments excludes interest income, interest expense, unallocated corporate expenses and foreign exchange gains and losses. Identifiable assets are those used in the operations of the segments.

Segmented Net Income for the Year Ended December 31, 2012


	Conventional									Oil sands
(Cdn$ millions)	United Kingdom			North America			Other Countries¹			In Situ			Syncrude		Corporate and Other			Total
Net Sales		3,889			400			703	²		726			666		46			6,430
Marketing and Other Income		35			11			1			—			1		233			281

		3,924			411			704			726			667		279			6,711

Less: Expenses
Operating		439			171			134			466	³		264		23			1,497
Depreciation, Depletion, Amortization and Impairment		752			514	⁴		371			192			66		56			1,951
Transportation and Other		3			41			—			271			25		142			482
General and Administrative		28			119			58			45			1		340	⁵		591
Exploration		117			283			28	⁶		1			—		—			429
Finance		24			15			1			3			8		250			301
Net Gain from Dispositions		(2	)		(153	)		(7	)		(32	)		—		—			(194	)

Income (Loss) before Income Taxes		2,563			(579	)		119			(220	)		303		(532	)		1,654
Less: Provision for (Recovery of) Income Taxes																			1,321	⁷

Net Income (Loss)																			333

Capital Expenditures		1,022			701			455	⁸		690			204		52			3,124

1	Includes results of operations in Nigeria, Yemen and Colombia.

2	Includes net sales in Nigeria of $559 million.

3	Includes Long Lake turnaround costs of $49 million.

4	Includes non-cash impairment charges of $237 million.

5	Includes non-cash share-based compensation expense of $157 million.

6	Includes exploration activities primarily in Colombia and Poland, and recovery of previously expensed exploration costs in Norway.

7	Includes UK current tax expense of $1,433 million.

8	Includes capital expenditures in Nigeria of $336 million.

Segmented Net Income for the Year Ended December 31, 2011


	Conventional									Oil Sands
(Cdn$ millions)	United Kingdom			North America			Other Countries^1,2			In Situ			Syncrude		Corporate and Other			Total
Net Sales		3,432			499			781			688			713		56			6,169
Marketing and Other Income		21			39			21			—			3		211			295

		3,453			538			802			688			716		267			6,464

Less: Expenses
Operating		353			156			164			439			287		32			1,431
Depreciation, Depletion, Amortization and Impairment		631			708	³		76			384	⁴		60		54			1,913
Transportation and Other		7			35			28			220			23		112			425
General and Administrative		(8	)		74			31			19			1		183			300
Exploration		84			148			134	⁵		2			—		—			368
Finance		17			16			2			3			6		207			251
Net Loss on Debt Redemption		—			—			—			—			—		91			91
Net Gain from Dispositions		(38	)		—			—			—			—		—			(38	)

Income (Loss) from Continuing Operations before Income Taxes		2,407			(599	)		367			(379	)		339		(412	)		1,723
Less: Provision for (Recovery of) Income Taxes																			1,328	⁶
Income from Continuing Operations																			395
Add: Net Income from Discontinued Operations																			302

Net Income																			697

Capital Expenditures		583			694			718	⁷		397			124		59			2,575

1	Includes results of operations in Yemen and Colombia.

2	Includes Masila net sales of $588 million and net income of $161 million.

3	Includes non-cash impairment charges of $322 million.

4	Includes non-cash expenses of $253 million related to previously capitalized engineering and design costs.

5	Includes exploration activities primarily in Nigeria, Norway, Colombia and Poland.

6	Includes UK current tax expense of $1,436 million.

7	Includes capital expenditures in Nigeria of $542 million.

Segmented Assets as at December 31, 2012

Conventional

Oil Sands

(Cdn$ millions)

United
Kingdom

North
America

Other
Countries

In Situ

Syncrude

Corporate
and Other

Total

Total Assets

5,330

2,779

2,299

6,409

1,596

2,124

20,537

Property, Plant and Equipment

Cost

7,925

6,701

2,949

6,633

1,981

605

26,794

Less: Accumulated DD&A

4,200

4,441

1,008

384

469

345

10,847

Net Book Value

3,725

2,260

1,941

6,249

⁴

1,512

260

15,947

1	Includes cash of $674 million and Energy Marketing accounts receivable and inventory of $918 million.

2	Includes capitalized costs of $872 million associated with our Canadian shale gas operations and $1,185 million associated with our US operations.

3	Includes $1,773 million related to our Usan development, offshore Nigeria.

4	Includes net book value of $5,254 million for Long Lake Phase 1 and $995 million for future phases of our in situ oil sands projects.

Segmented Assets as at December 31, 2011

Conventional

Oil Sands

(Cdn$ millions)

United
Kingdom

North
America

Other
Countries

In Situ

Syncrude

Corporate
and Other

Total

Total Assets

4,817

3,403

2,138

5,881

1,423

2,406

20,068

Property, Plant and Equipment

Cost

7,103

7,256

2,566

5,915

1,733

649

25,222

Less: Accumulated DD&A

3,707

4,299

648

205

411

381

9,651

Net Book Value

3,396

2,957

1,918

5,710

⁴

1,322

268

15,571

1	Includes cash of $453 million and Energy Marketing accounts receivable and inventory of $1,449 million.

2	Includes capitalized costs of $1,293 million associated with our Canadian shale gas operations and $1,260 associated with our US operations.

3	Includes $1,821 million related to our Usan development, offshore Nigeria.

4	Includes net book value of $5,050 million for Long Lake Phase 1 and $660 million for future phases of our in situ oil sands projects.

Exhibit 99.2

CONSENT OF INDEPENDENT REGISTERED CHARTERED ACCOUNTANTS

We consent to the incorporation by reference in Registration Statement No. 333-188261 on Form F-3 of CNOOC Limited of our report dated February 24, 2013, relating to the consolidated financial statements of Nexen Inc. and subsidiaries appearing in this current Report on Form 6-K dated April 22, 2014.

/s/ Deloitte LLP

Independent Registered Chartered Accountants

Calgary, Canada

April 22, 2014

Exhibit 99.3

UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL INFORMATION

On July 23, 2012, CNOOC Limited (the “Company”), CNOOC Canada Holding Ltd. and Nexen Inc. (“Nexen”) entered into an arrangement agreement in relation to the Company’s proposed acquisition (through its wholly-owned subsidiary, CNOOC Canada Holding Ltd.) of all the Nexen common shares and preferred shares, pursuant to a plan of arrangement under the Canada Business Corporations Act.

The acquisition of Nexen was completed on February 26, 2013 (Beijing time). The consideration of the acquisition was approximately US$14.8 billion (approximately RMB92.8 billion), and was paid in cash. The consideration is related to acquisition of common shares and preferred shares. As a result of the acquisition, an additional amount of approximately US$275 million was paid by Nexen to settle its long-term incentive plans. The indebtedness of Nexen at the acquisition date remains outstanding except for the US$460 million of subordinated debt that was repaid subsequently in 2013.

The unaudited pro forma consolidated statement of profit or loss of the Company for the year ended December 31, 2013 gives effect to the Company’s acquisition of Nexen as if it had occurred on January 1, 2013. The unaudited pro forma consolidated statement of profit or loss does not purport to represent what the Company’s consolidated results of operations would have been if the Nexen acquisition had occurred on January 1, 2013, or what those results will be for any future periods. The unaudited pro forma financial information should be read in conjunction with the notes accompanying the unaudited pro forma consolidated financial information and with the audited consolidated financial statements and the related notes in the Company’s Annual Report on Form 20-F for the year ended December 31, 2013 filed with the U.S. Securities and Exchange Commission on April 17, 2014.

UNAUDITED PRO FORMA CONSOLIDATED STATEMENT OF PROFIT OR LOSS

YEAR ENDED DECEMBER 31, 2013

(All amounts expressed in millions of Renminbi, except per share data)


	Historical			Inclusion of Nexen’s results prior to acquisition			Fair Value Adjustments			Pro forma
				(a)			(b)
REVENUE
Oil and gas sales		226,445			6,504			—			232,949
Marketing revenues		55,495			551			—			56,046
Other income		3,917			559			—			4,476
		285,857			7,614			—			293,471
EXPENSES
Operating expenses		(30,014	)		(1,580	)		—			(31,594	)
Taxes other than income tax		(15,937	)		—			—			(15,937	)
Exploration expenses		(17,120	)		(164	)		(61	)		(17,345	)
Depreciation, depletion and amortisation		(56,456	)		(1,940	)		(907	)		(59,303	)
Special oil gain levy		(23,421	)		—			—			(23,421	)
Impairment and provision		45			(17	)		—			28
Crude oil and product purchases		(53,386	)		—			—			(53,386	)
Selling and administrative expenses		(7,859	)		(1,434	)		—			(9,293	)
Others		(3,206	)		(603	)		—			(3,809	)
		(207,354	)		(5,738	)		(968	)		(214,060	)
PROFIT FROM OPERATING ACTIVITIES		78,503			1,876			(968	)		79,411
Interest income		1,092			4			—			1,096
Finance costs		(3,457	)		(304	)		31			(3,730	)
Exchange gains, net		873			226			—			1,099
Investment income		2,611			—			—			2,611
Share of profits of associates		133			—			—			133
Share of profit of a joint venture		762			—			—			762
Non-operating income, net		334			—			—			334
PROFIT BEFORE TAX		80,851			1,802			(937	)		81,716
Income tax expense		(24,390	)		(1,474	)		577			(25,287	)
PROFIT FOR THE YEAR ATTRIBUTABLE TO OWNERS OF THE PARENT		56,461			328			(360	)		56,429

EARNINGS PER SHARE ATTRIBUTABLE TO ORDINARY EQUITY HOLDERS OF THE PARENT
Basic (RMB Yuan)		1.26									1.26
Diluted (RMB Yuan)		1.26									1.26

NOTES TO UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL INFORMATION

Pro Forma Adjustments and Assumptions

Basis of Presentation

The unaudited pro forma consolidated statement of profit or loss was compiled based on (i) the historical financial information of the Company for the year ended December 31, 2013, (ii) the Nexen historical financial information for the period from January 1, 2013 through February 26, 2013, and (iii) certain adjustments which the Company believes are reasonable to give effect to the acquisition as if it had occurred on January 1, 2013. The unaudited pro forma financial information has been compiled in a manner consistent with the accounting policies of the Company, which are in accordance with International Financial Reporting Standards issued by the International Accounting Standards Board, and Hong Kong Financial Reporting Standards issued by the Hong Kong Institute of Certified Public Accountants.

The unaudited pro forma consolidated statement of profit or loss gives pro forma effect to the following items:

(a) To include the results of Nexen from January 1, 2013 to February 26, 2013 as if the acquisition had taken place on January 1, 2013.

(b) Adjustments to depreciation, depletion and amortization of property, plant and equipment and intangible assets; exploration expenses; finance costs and deferred income tax expenses from January 1, 2013 to February 26, 2013 based on the basis of the fair value arising from the initial accounting for business combination rather than the carrying amounts recognized in the pre-acquisition financial statements of Nexen. The details of the fair values of the identifiable assets and liabilities of Nexen were disclosed in Note 4 to the consolidated financial statements of the Company for the year ended December 31, 2013 on Form 20-F filed with the U.S. Securities and Exchange Commission on April 17, 2014.

No pro forma adjustment to the transaction costs related to the Nexen acquisition in the pro forma consolidated financial information.