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**UNITED STATES**

**SECURITIES AND EXCHANGE COMMISSION**

**WASHINGTON, D.C. 20549**

 

**FORM 40-F**

 

**[Check one]**

 
| **o**      | ** ** | **REGISTRATION   STATEMENT PURSUANT TO SECTION 12 OF THE SECURITIES EXCHANGE ACT OF 1934**      |
|------------|------------|-------------------------------------------------------------------------------------------------|
| ** ** | ** ** | ** **                                                                                      |
| **OR**     |
|       |       |                                                                                            |
| **x**      | ** ** | **ANNUAL   REPORT PURSUANT TO SECTION 13(a) or 15(d) OF THE SECURITIES EXCHANGE ACT OF   1934** |

 

**For the fiscal year ended: December 31, 2012      Commission File Number:  1-6702**

 

**NEXEN INC.**

(Exact name of Registrant as specified in its charter)

 

**Not applicable**

(Translation of Registrant’s name into English (if applicable))

 

**Canada**

(Province or other jurisdiction of incorporation or organization)

 

**1311**

(Primary Standard Industrial

Classification Code Number (if applicable))

 

**98-600202**

(I.R.S. Employer

Identification Number (if applicable))

 

**801 - 7th Avenue S.W. Calgary, Alberta, Canada T2P 3P7 (403) 699-4000 Website: www.nexeninc.com**

(Address and telephone number of Registrant’s principal executive offices)

 

**Nexen Petroleum U.S.A. Inc. 945 Bunker Hill Road Suite 1400 Houston, Texas 77024**

**(832) 714-5000**

(Name, address (including zip code) and telephone number (including area code)

of agent for service in the United States)

 

Securities registered or to be registered pursuant to Section 12(b) of the Act.

 

| **Title of each class**               | ** ** | **Name of each exchange on which registered**                |
|---------------------------------------|------------|--------------------------------------------------------------|
|                                  |       |                                                         |
| **Common shares, no par value**       |       | **The New York Stock Exchange   The Toronto Stock Exchange** |
| ** **                            |       | ** **                                                   |
| **Subordinated Securities, due 2043** |       | **The New York Stock Exchange   The Toronto Stock Exchange** |

 

Securities registered or to be registered pursuant to Section 12(g) of the Act.

 

**None**

(Title of Class)

 

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act.

 

**None**

(Title of Class)

 

For Annual Reports indicate by check mark the information filed with this Form:

 

x Annual information form      x Audited annual financial statements

 

Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report:

** **

**530,036,892**

 

Indicate by check mark whether the Registrant (1) has filed all reports to be filed by Section 13 or 15(d) of the Exchange Act during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports) and (2) has been subject to filing requirements for the past 90 days.

 

Yes  x  No o

 

Indicate by check mark whether the Registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the Registrant was required to submit and post such files).

 

Yes o   No o

 

The Annual Report on Form 40-F shall be incorporated by reference into or as an exhibit to, as applicable, each of the Registrant’s Registration Statements under the Securities Act of 1933:  Form S-8 (File No.’s 333-119276, 333-118019 and 333-13574) and Form F-3 (File No.’s 333- 172612, 333-142670, 333-142652 and 333-84786).

 

 

 

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** **

**Principal Documents**

 

The following documents have been filed as part of this Annual Report on Form 40-F, beginning on the following page:

 

(a)                                 Annual Information Form of Nexen Inc. for the fiscal year ended December 31, 2012.

 

(b)                                 Management’s Discussion and Analysis of Nexen Inc. for the fiscal year ended December 31, 2012.

 

(c)                                  Consolidated Financial Statements of Nexen Inc. for the fiscal year ended December 31, 2012.

 

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*NEXEN INC.*

*ANNUAL INFORMATION FORM*

 

 

*For the Year Ended December 31, 2012*

 

 

*February 24, 2013*

 

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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. Following close of the transaction, future activities of the Company will be directed by CNOOC.

 

**ANNUAL INFORMATION FORM (AIF)**

 
| General   Information                                                                                         | 2  |
|---------------------------------------------------------------------------------------------------------------|----|
| Corporate   Structure                                                                                         | 4  |
| Business   Overview                                                                                           | 4  |
| Oil and Gas                                                                                                   | 6  |
| Understanding the Oil and Gas Industry                                                                        | 7  |
| Conventional   Oil and Gas                                                                                    | 8  |
| Oil Sands                                                                                                     | 11 |
| Shale Gas                                                                                                     | 13 |
| Energy   Marketing                                                                                            | 14 |
| Reserves, Production and Related Information                                                                  | 14 |
| Environmental and Regulatory Matters                                                                          | 33 |
| Employees                                                                                                     | 37 |
| Risk   Factors                                                                                                | 37 |
| Capital   Structure                                                                                           | 46 |
| Market   for Securities                                                                                       | 49 |
| Directors                                                                                                     | 51 |
| Audit Committee Information                                                                                   | 53 |
| Independent Registered Chartered Accountants (IRCA)   Fees                                                    | 54 |
| Executive   Officers                                                                                          | 55 |
| Other                                                                                                         | 56 |
| APPENDIX A—Audit and Conduct Review Committee Mandate                                                    | 59 |
| APPENDIX B—Reserves Estimates and Supplementary Data   Under SEC Requirements                            | 64 |
| APPENDIX   C—Form 51-101F2 Report on Reserves Data by Internal Qualified Reserves   Evaluator       | 78 |
| APPENDIX   D—Form 51-101F3 Report of Management and Directors on NI 51-101 Oil and   Gas Disclosure | 79 |

 

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*ANNUAL INFORMATION FORM (AIF)*

 

Below is a list of terms specific to the oil and gas industry. They are used throughout this AIF.

 
| /d     | = | per   day                                         | boe           | = | barrel   of oil equivalent on the basis of 1 bbl to 6 mcf of natural gas |
|--------|---|---------------------------------------------------|---------------|---|-------------------------------------------------------------------------------|
| bbl    | = | barrel                                            | mboe          | = | thousand   barrels of oil equivalent                                          |
| mbbls  | = | thousand   barrels                                | mmboe         | = | million   barrels of oil equivalent                                           |
| mmbbls | = | million   barrels                                 | mcf           | = | thousand   cubic feet                                                         |
| mmbtu  | = | million   British thermal units                   | mmcf          | = | million   cubic feet                                                          |
| km     | = | kilometre                                         | bcf           | = | billion   cubic feet                                                          |
| MW     | = | megawatt                                          | WTI           | = | West   Texas Intermediate                                                     |
| GWh    | = | gigawatt   hours                                  | Brent         | = | Dated   Brent                                                                 |
| GJ     | = | gigajoules                                        | NGL           | = | natural   gas liquid                                                          |
| PSCTM  | = | Premium   Synthetic CrudeTM                       | NYMEX         | = | New   York Mercantile Exchange                                                |
| AECO   | = | natural   gas storage facility located in Alberta | $000s   or $M | = | thousands   of dollars                                                        |
| $MM    | = | millions   of dollars                             | US$           | = | United   States dollars                                                       |

 

**GENERAL INFORMATION**

 

In this Annual Information Form (AIF), references to “we”, “our”, “us”, “Nexen” or the “Company” mean Nexen Inc., our subsidiaries and partnerships. Unless we indicate otherwise, all dollar amounts ($) are in millions of Canadian dollars (Cdn$), and oil and gas volumes, reserves and related performance measures are presented on a working interest before-royalties basis. Where appropriate, information on a working interest after-royalties basis is provided. The information contained in this AIF is dated December 31, 2012, unless otherwise indicated. The date of this discussion is February 24, 2013.

 

Conversions of gas volumes to boe in this AIF were made on the basis of 1 boe to 6 mcf of natural gas. A boe conversion ratio of 6 mcf:1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Disclosure provided herein in respect of boe may be misleading, particularly if used in isolation. Using the 2012 average prices applied to our reserves estimates, the boe conversion ratio based on wellhead value is approximately 35 mcf:1 bbl.

 

*Non-GAAP Measures*

 

Certain financial measures referred to in this AIF, namely “cash flow from operations” and “net debt” do not have a standardized meaning prescribed by GAAP and are therefore unlikely to be comparable to similar measures presented by others. These non-GAAP measures are included to assist investors in analyzing Nexen’s operating performance, leverage and liquidity. Reconciliations of these non-GAAP measures to their nearest GAAP equivalent are included in our Management’s Discussion and Analysis (MD&A) for the year ended December 31, 2012.

 

*Foreign Exchange*

 

The noon-day Canadian to US dollar exchange rates for Cdn$1.00, as reported by the Bank of Canada, were:

 
| **(US$)** | ** ** | **December 31** | ** ** | **Average** | ** ** | **High** | ** ** | **Low** | ** ** |
|-----------|------------|----------------------|------------|-------------|------------|----------|------------|---------|------------|
| 2010      |       | 1.0054               |       | 0.9709      |       | 1.0054   |       | 0.9278  |       |
| 2011      |       | 0.9833               |       | 1.0117      |       | 1.0583   |       | 0.9430  |       |
| 2012      |       | 1.0051               |       | 1.0004      |       | 1.0299   |       | 0.9599  |       |

 

On January 31, 2013, the noon-day exchange rate was US$0.9992 for Cdn$1.00.

 

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**FORWARD-LOOKING STATEMENTS**

 

Certain statements in this AIF constitute “forward-looking statements” (within the meaning of the *United States Private Securities Litigation Reform Act of 1995*, as amended) or “forward-looking information” (within the meaning of applicable Canadian securities legislation). Such statements or information (together “forward-looking statements”) are generally identifiable by the forward-looking terminology used such as “anticipate”, “believe”, “intend”, “plan”, “expect”, “estimate”, “budget”, “outlook”, “forecast” or other similar words and include statements relating to, or associated with, individual wells, regions or projects. Any statements as to possible future crude oil or natural gas prices; future production levels; future royalties and tax levels; future capital expenditures, their timing and their allocation to exploration and development activities; future earnings; future asset acquisitions or dispositions; future sources of funding for our capital program; future debt levels; availability of committed credit facilities; possible commerciality of our projects; development plans or capacity expansions; the expectation that we have the ability to substantially grow production at our oil sands facilities through controlled expansions; the expectation of achieving the production design rates from our oil sands facilities; the expectation that our oil sands production facilities continue to develop better and more sustainable practices; the expectation of cheaper and more technologically advanced operations; the expected design size of our facilities; the expected timing and associated production impact of facility turnarounds and maintenance; the expectation that we can continue to operate our offshore exploration, development and production facilities safely and profitably; future ability to execute dispositions of assets or businesses; future sources of liquidity, cash flows and their uses; future drilling of new wells; ultimate recoverability of current and long-term assets; ultimate recoverability of reserves or resources; expected finding and development costs; expected operating costs; future cost recovery of oil revenues from our Yemen operations; the expectation of our ability to comply with the new safety and environmental rules at a minimal incremental cost, and of receiving necessary drilling permits for our US offshore operations; estimates on a per share basis; future foreign currency exchange rates; future expenditures and future allowances relating to environmental matters and our ability to comply with them; dates by which certain areas will be developed, come on stream or reach expected operating capacity; and changes in any of the foregoing are forward-looking statements.

 

Statements relating to “reserves” or “resources” are forward-looking statements, as they involve the implied assessment, based on estimates and assumptions that the reserves and resources described exist in the quantities predicted or estimated and can be economically produced in the future.

 

All of the forward-looking statements in this AIF are qualified by the assumptions that are stated or inherent in such forward-looking statements. Although we believe that these assumptions are reasonable based on the information available to us on the date such assumptions were made, this list is not exhaustive of the factors that may affect any of the forward-looking statements and the reader should not place an undue reliance on these assumptions and such forward-looking statements. The key assumptions that have been made in connection with the forward-looking statements include the following: that we will conduct our operations and achieve results of operations as anticipated; that our development plans will achieve the expected results; the general continuance of current or, where applicable, assumed industry conditions; the continuation of assumed tax, royalty and regulatory regimes; the accuracy of the estimates of our reserve volumes; commodity price and cost assumptions; the continued availability of adequate cash flow and debt and/or equity financing to fund our capital and operating requirements as needed; the operations and capital expenditure plans of Nexen following the completion of the transaction; and the extent of our liabilities. We believe the material factors, expectations and assumptions reflected in the forward-looking statements are reasonable, but no assurance can be given that these factors, expectations and assumptions will prove to be correct.

 

Forward-looking statements are subject to known and unknown risks and uncertainties and other factors, many of which are beyond our control and each of which contributes to the possibility that our forward-looking statements will not occur or that actual results, levels of activity and achievements may differ materially from those expressed or implied by such statements. Such factors include, but are not limited to: market prices for oil and gas; our ability to explore, develop, produce, upgrade and transport crude oil and natural gas to markets; ultimate effectiveness of design or design modifications to facilities; the results of exploration and development drilling and related activities; the cumulative impact of oil sands development on the environment; the impact of technology on operations and processes and how new complex technology may not perform as expected; the availability of pipeline and global refining capacity; risks inherent to the operations of any large, complex refinery units, especially the integration between production operations and an upgrader facility; availability of third-party bitumen for use in our oil sands production facilities; labour and material shortages; risks related to accidents, blowouts and spills in connection with our offshore exploration, development and production activities, particularly our deep-water activities; direct and indirect risks related to the imposition of moratoriums, suspensions or cancellations of our offshore exploration, development and production operations, particularly our deep-water activities; the impact of severe weather on our offshore exploration, development and production activities, particularly our deep-water activities; the effectiveness and reliability of our technology in harsh and unpredictable environments; risks related to the actions and financial circumstances of our agents, contractors, counterparties and joint–venture partners; volatility in energy trading markets; foreign currency exchange rates; economic conditions in the countries and regions in which we carry on business; governmental actions including changes to taxes or royalties, changes in environmental and other laws and regulations including without limitation, those related to our offshore exploration, development and production activities; renegotiations of contracts; results of litigation, arbitration or regulatory proceedings; political uncertainty, including actions by terrorists, insurgent or other groups, or other armed conflict, including conflict between states; and other factors, many of which are beyond our control. These risks, uncertainties and other factors and their possible impact are discussed more fully in the sections titled “Risk Factors” in this AIF and “Quantitative and Qualitative Disclosures About Market Risk” in our MD&A. The impact of any one risk, uncertainty or factor on a particular forward-looking statement is not determinable with certainty as these factors are interdependent, and management’s future course of action would depend on our assessment of all information at that time.

 

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Although we believe that the expectations conveyed by the forward-looking statements are reasonable based on information available to us on the date such forward-looking statements were made, no assurances can be given as to future results, levels of activity and achievements. Undue reliance should not be placed on the forward-looking statements contained herein, which are made as of the date hereof as the plans, intentions, assumptions or expectations upon which they are based might not occur or come to fruition. Except as required by applicable securities laws, Nexen undertakes no obligation to update publicly or revise any forward-looking statements, whether as a result of new information, future events or otherwise. Included herein is information that may be considered financial outlook and/or future-oriented financial information. Its purpose is to indicate the potential results of our intentions and may not be appropriate for other purposes. The forward-looking statements contained herein are expressly qualified by this cautionary statement.

 

**CORPORATE STRUCTURE**

 

Nexen Inc. is incorporated under the Canada Business Corporations Act. Our registered and head office is located at 801 — 7th Avenue S.W., Calgary, Alberta, Canada T2P 3P7.

 

Our material operating subsidiaries owned directly or indirectly and their jurisdictions of incorporation as at December 31, 2012 are as follows:

 
| **Name of Subsidiary**    | ** ** | **Jurisdiction of Incorporation/********Formation/Continuation** |
|-------------------------------------|------------|----------------------------------------------------------------------------|
| Nexen   Petroleum UK Limited        |       | England & Wales                                                        |
| Nexen   Petroleum Nigeria Limited   |       | Nigeria                                                                    |
| Nexen   Petroleum Offshore USA Inc. |       | Delaware                                                                   |
| Nexen   Marketing                   |       | Alberta                                                                    |
| Nexen   Oil Sands Partnership       |       | Alberta                                                                    |

 

All material operating subsidiaries are 100% beneficially owned, controlled or directed by Nexen.

 

**BUSINESS OVERVIEW**

 

Nexen Inc. is a Canadian-based, global energy company. We were formed in Canada in 1971 as Canadian Occidental Petroleum Ltd. when Occidental Petroleum Corporation combined their Canadian crude oil, natural gas, sulphur and chemical operations into one company.

 

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CONVENTIONAL OIL AND GAS

 

Our conventional oil and gas assets are comprised mainly of large acreage positions in select basins including the UK North Sea, deep-water US Gulf of Mexico and offshore Nigeria. Strategically, we focus on these basins due to: i) past successes; ii) existing infrastructure in place; iii) significant potential in remaining resource; and/or iv) attractive fiscal terms. We assess our global portfolio of opportunities to identify prospects that we believe will generate the highest value in our selected basins.

 

In the UK North Sea, we are a significant regional player with concentrated assets, infrastructure and exploration potential for future growth. In addition to other producing properties, we operate the Buzzard field and platform, which is the largest field to come on production in the UK North Sea in over a decade. Other recent discoveries such as Golden Eagle and Rochelle are currently under development and are expected to provide new sources of production in the short-term. We actively explore the UK North Sea basin including relatively under-explored areas such as west of the Shetland Islands.

 

In the US Gulf of Mexico, we hold deep-water and shelf assets as well as several undeveloped deep-water discoveries including Appomattox, Vicksburg and Stampede (formerly Knotty Head-Pony). We are a significant leaseholder in the Gulf. The deep-water Gulf of Mexico has significant infrastructure and is near continental US markets.

 

Offshore Nigeria, our assets include Usan as well as several undeveloped discoveries. Oil production from Usan started in February 2012 on block OML-138 and eleven production wells are currently on stream. We continue to actively explore the basin.

 

OIL SANDS

 

Our oil sands investments include interests in the Long Lake project, the Syncrude joint venture and 621,000 undeveloped in situ oil sands acreage (gross) in northern Alberta. Our oil sands strategy is to generate steady and predictable cash flow for decades. While the cost to produce from the Athabasca oil sands is higher relative to conventional oil deposits, the significant discovered resource base and stable fiscal jurisdiction make this a key source of future oil development.

 

We first entered the oil sands by acquiring an interest in the Syncrude joint venture. Syncrude produces synthetic crude oil from mined bitumen-saturated sands.

 

We have interests in a number of in situ leases. Our first in situ oil sands project at Long Lake produces and upgrades bitumen in the Athabasca oil sands. Steam-assisted-gravity-drainage (SAGD) bitumen production began in 2008 and production of PSCTM from the upgrader began in 2009. Our near-term plans include SAGD development of the Kinosis lease at K1A.

 

SHALE GAS

 

Shale gas balances our corporate portfolio, which consists predominantly of large-scale, capital-intensive and long cycle-time projects. It provides natural gas exposure and short cycle-time projects where we control the scale and pace of development depending on the current price environment.

 

Our shale gas strategy is currently focused primarily in northeast British Columbia on the Horn River basin. The Horn River basin is a significant shale gas play with high resource density and strong well productivity. Additional evaluation activities of potential shale gas resource are underway in the Liard and Cordova basins in British Columbia. During the second half of 2012, we closed the sale of a 40% non-operated working interest in our shale gas lands in northeast British Columbia to INPEX Gas British Columbia Ltd. (IGBC). We have approximately 300,000 gross acres (180,000 net to us) of shale gas lands in the Horn River, Cordova and Liard basins.

 

We’ve expanded our shale gas portfolio by acquiring a non-operated shale gas exploration interest in Poland and by testing shale gas opportunities in Colombia.

 

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Three-Year Overview

 
| **2010**                 | ·    Generated cash flow   from operations of $2.2 billion and net income of $1.1 billion

·    Discovered the Appomattox field in the deep-water Gulf of   Mexico

·    Disposed of non-core, heavy oil properties in Western Canada   for $939 million

·    Divested non-core marketing businesses including North American   natural gas marketing

·    Doubled bitumen production at Long Lake with improved steam   reliability

·    More than doubled our British Columbia shale gas acreage,   adding lands in the Cordova and Liard basins                                                                                                                                                                                                                                                                                 |
|--------------------------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| ** **               |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |
| **2011**                 | ·    Generated cash flow   from operations of $2.4 billion and net income of $697 million

·    Completed a non-core asset disposition program with the sale of   our interest in Canexus for $458 million

·    Repaid approximately $800 million of long-term debt

·    Developed action plans to increase production at Long Lake and   fill the upgrader; ramped-up pad 11, drilled pads 12 and 13

·    Commissioned the Buzzard fourth platform to handle higher   levels of H2S from the   field

·    Achieved first oil at our Blackbird field in the UK North Sea

·    Received government approval and sanctioned the Golden Eagle   development in the UK

·    Brought a nine-well pad on stream at Horn River                                                                 |
| ** **               |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |
| **2012**

 

  | ·    Generated cash flow   from operations of $2.7 billion and net income of $333 million

·    Achieved first oil at Usan, offshore Nigeria

·    Completed major turnarounds and regulatory inspections at Scott,   Buzzard and Long Lake

·    Achieved first oil at Long Lake pads 12 and 13, and received   regulatory and partner approval for pads 14, 15 and Kinosis K1A

·    Closed the joint venture agreement in our northeast British   Columbia shale gas operations and received $821 million of cash upon closing

·    Completed our shale gas 18-well pad in northeast British   Columbia

·    Issued $200 million of preferred shares

·    Entered into an Arrangement Agreement with CNOOC Limited for   the acquisition of our outstanding common and preferred shares |

 

**OIL AND GAS**

 

In this AIF, we provide estimates of remaining quantities of proved and probable crude oil, synthetic oil, bitumen, coalbed methane (CBM), shale gas and natural gas reserves (oil and gas reserves) for our various properties as at December 31, 2012. These reserves estimates and related disclosures have been prepared in accordance with National Instrument 51-101—*Standards of Disclosure for Oil and Gas Activities*(NI 51-101). We have also prepared reserves estimates and disclosures in accordance with SEC requirements, which are included in Appendix B of this AIF. Reserves estimates and disclosures prepared in accordance with NI 51-101 requirements differ from reserves estimates prepared in accordance with SEC requirements. Significant qualitative differences between NI 51-101 and SEC reserves estimates and disclosures are described in the section entitled “Special Note to Investors” on page 33.

 

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Our proved and probable reserve estimates have been internally prepared. For our reserves estimates prepared in accordance with NI 51-101 requirements, we had 97% of our proved reserves assessed (either evaluated or audited as described on pages 30 to 31) by independent reserves consultants. Their assessment of the proved reserves is performed at varying levels of property aggregation, and we work with them to reconcile any difference on the portfolio of properties to within 10% in the aggregate. Estimates pertaining to individual properties within the portfolio may differ by more than 10% either positively or negatively, however, we believe such differences are not material relative to our total proved reserves.

 

We also had 98% of our NI 51-101 proved plus probable oil and gas reserves estimates assessed by independent reserves consultants. By definition, proved reserves must be determined together with probable reserves (see definition on page 31). As such, the independent reserves consultants’ assessments are prepared on a combined proved plus probable basis. Like proved reserves, their assessment of the proved plus probable reserves is performed at varying levels of property aggregation, and we work with them to reconcile any difference on the portfolio of properties to within 10% in the aggregate. Estimates pertaining to individual properties within the portfolio may differ by more than 10% either positively or negatively, however, we believe such differences are not material relative to our total proved plus probable reserves.

 

Refer to the section on Basis of Reserves Estimates on pages 14 to 16 for a description of our internal reserves process and the nature and scope of the independent assessments performed on our proved and probable reserves estimates and the results thereof.

 

**UNDERSTANDING THE OIL AND GAS INDUSTRY**

 

The oil and gas industry is highly competitive. With strong global demand for energy and limited exploration opportunities, there is intense competition to find and develop new sources of supply. Yet, barrels from different reservoirs around the world do not have equal value. Their value depends on the costs to find, develop and produce the oil or gas, the fiscal terms of the host regime and the price that products attract based on quality, location and marketing efforts. We captured an inventory of opportunities in our core growth areas, and our goal is to extract the maximum value from each barrel of oil equivalent so that every dollar of capital we invest generates an attractive return.

 

Numerous factors can affect this. Changes in crude oil and natural gas prices can significantly affect our net income and cash flow generated from operations. Consequently, these prices may also affect the carrying value of our oil and gas properties and how much we invest in oil and gas exploration and development. We attempt to reduce these impacts by investing in projects we believe will generate positive returns at relatively low commodity prices, and we maintain liquidity that provides us with the ability to sustain capital investment in high-quality projects during periods of low commodity prices.

 

The prices we receive for our oil and gas products are determined by global crude oil and regional natural gas markets, all of which can be volatile. With many alternative customers, the loss of any one customer is not expected to have a materially adverse effect on the price of our products or revenues. Oil and gas producing operations are generally not seasonal. However, demand for some of our products such as natural gas can fluctuate season to season, which can impact price. We manage our operations on a country-by-country basis, reflecting differences in the regulatory regime, competitive environments and risk factors associated with each country. Presentation of our oil and gas operations is separated between conventional oil and gas activities, and oil sands activities. Our conventional operations include our oil and gas operations in the UK North Sea, North America (excluding oil sands) and other countries (Yemen, offshore Nigeria, Colombia and other). Our oil sands activities are segregated between in situ oil sands operations (primarily at Long Lake) and our interest in Syncrude. Our shale gas results are included in the North America segment.

 

Production, revenues, net income, cash flows, capital expenditures and identifiable assets for these segments appear in Note 25 to the Consolidated Financial Statements and in our MD&A.

 

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**CONVENTIONAL OIL AND GAS**

 

UNITED KINGDOM (UK) — NORTH SEA

 

The UK North Sea is a key producing area for Nexen. Our primary assets, which we operate, include a 43.2% interest in the Buzzard field and facilities, a 41.9% interest in the Scott field and production platform, an 80.4% interest in the Telford field, a 79.7% interest in the Ettrick field and a 90.6% interest in the Blackbird field, along with interests in several undeveloped discoveries and exploration acreage. We are a significant regional player with concentrated assets, infrastructure and exploration potential for future growth. Our UK North Sea operations complement our global portfolio with significant cash flow generation and the opportunity for shorter cycle-time production growth.

 

Our UK strategy is to grow our existing North Sea production and identify new sources of production. To do this, we identify exploration and exploitation opportunities near existing infrastructure that can be tied-in economically in a relatively short time period. We also seek to establish new core areas through exploration in relatively unexplored areas of the basin (e.g. west of Shetlands, the Central Graben and the northern North Sea). We target oil-focused assets that are early life which generate stronger cash margins.

 

*Buzzard*

 

The Buzzard field is located about 60 miles northeast of Aberdeen in the Outer Moray Firth, central North Sea, in 317 feet of water. It was discovered in 2001 and came on stream in early 2007. The Buzzard development was initially comprised of three platforms capable of processing at least 200,000 bbls/d of oil and 60 mmcf/d of gas. A fourth platform with production-sweetening facilities to handle higher levels of hydrogen sulphide was completed in 2011. Oil from Buzzard is exported via the Forties pipeline to the Kinneil Terminal in Scotland. Gas is exported via the Frigg system to the St. Fergus Gas Terminal in northeast Scotland. Our share of production in 2012 was 69,300 boe/d.

 

*Scott/Telford*

 

The Scott field began producing in 1993, while Telford was tied back to the Scott platform and came on stream in 1996. Telford production is produced through subsea wells tied back to the Scott platform. Oil is delivered to the third-party Kinneil Terminal in Scotland via the Forties pipeline, while gas is exported via the SAGE pipeline to the St. Fergus Gas Terminal in northeast Scotland. The TAC Telford development well was tied into the Scott platform in 2012. The nearby Rochelle gas field is planned to be tied back to the Scott platform in 2013. Scott/Telford produced 13,800 boe/d (net to us) in 2012.

 

*Ettrick/Blackbird*

 

Ettrick is a producing field originally discovered in 1981 and brought on stream in 2009. Oil and gas from Ettrick is produced through subsea wells tied back to a leased FPSO. The FPSO is designed to handle 30,000 bbls/d of oil and 35 mmcf/d of gas. The produced oil is offloaded from the FPSO onto tankers and typically delivered to ports in the North Sea. Gas is exported via the SAGE pipeline to the St. Fergus Gas Terminal in northeast Scotland. Production from the nearby Blackbird field came on stream late in 2011 and is produced through the Ettrick FPSO. Our share of production from Ettrick/Blackbird in 2012 was 15,900 boe/d.

 

*Golden Eagle*

 

In 2007, we made a discovery at Golden Eagle, followed by Peregrine (formerly Pink) in 2008 and Hobby in 2009. We refer to these three discoveries as the Golden Eagle area and hold a 36.5% operated interest. Since the original discovery, we successfully completed a comprehensive appraisal program, which included drilling nine appraisal wells, two drill-stem tests and one injection test. In 2011, we completed the appraisal work, sanctioned the development plan and received government approval. The Golden Eagle development will include a two-platform stand-alone facility with production capacity of about 70,000 boe/d (26,000 boe/d net to us) at full rates. In 2012, we progressed platform fabrication and construction is on-time and on-budget. Development drilling in the field is expected to start in late 2013.

 

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*Exploration*

 

We hold approximately 70 blocks in the UK North Sea. We continue to actively explore the basin and hold several undeveloped discoveries on operated blocks near the Scott and Buzzard facilities as follows:

 
| **Field**  | ** ** | **Interest ****(%)** | ** ** | **Operator Status** | ** ** | **Comments**                                                  |
|------------|------------|---------------------------|------------|--------------------------|------------|---------------------------------------------------------------|
| Blackhorse |       | 50                        |       | operated                 |       | discovery   near Scott; evaluating development alternatives   |
| Bright     |       | 80                        |       | operated                 |       | discovery   near Buzzard; evaluating development alternatives |
| Bugle      |       | 100                       |       | operated                 |       | discovery   near Scott; evaluating development alternatives   |
| Polecat    |       | 80                        |       | operated                 |       | discovery   near Buzzard; evaluating development alternatives |

 

UNITED STATES (US) — GULF OF MEXICO

 

Existing production infrastructure, the potential for material discoveries and attractive fiscal terms make the deep-water Gulf of Mexico one of the world’s most prospective basins for oil and gas. While costs of deep-water exploration are typically higher, prospects generally have multiple sands and higher production rates — factors that can enhance economics. The deep-water Gulf has significant infrastructure and is near continental US markets, so discoveries can be brought on stream in reasonable time frames relative to less developed or more remote areas of the world.

 

Our existing Gulf of Mexico production and reserves are primarily concentrated in six deep-water and three shallow-water (shelf) areas. Our oil and natural gas production is transported to the continental US for sale via third-party pipelines and infrastructure. Our share of production in the Gulf of Mexico in 2012 was 15,600 boe/d.

 

*Deep Water*

 

Most of our deep-water production comes from our 25% non-operated Longhorn field, our 100% operated Green Canyon 6/137 fields and Aspen field, and our 30% non-operated Gunnison field. Our share of 2012 deep-water production before royalties was 10,300 boe/d.

 

Our Longhorn property is on Mississippi Canyon Blocks 502 and 546 in 2,400 feet of water. The project is a non-operated four-well subsea tie-back to the third-party Corral platform located 19 miles north of the field. Longhorn came on stream in 2009.

 

Aspen is on Green Canyon Block 243 in 3,150 feet of water. The project was developed using four subsea oil wells tied back to the third-party Bullwinkle platform 16 miles away. The field began production in 2002.

 

Our Green Canyon field includes wells on Green Canyon 6 and Green Canyon 137 in water depths of 650 and 1,170 feet, respectively. Production from this field was suspended in September 2008 as the third-party platform that processed our oil and gas was destroyed by Hurricane Ike. Production was re-established in 2012 through a tie-back to another third-party host platform.

 

Gunnison is in 3,100 feet of water and includes Garden Banks blocks 667, 668 and 669. Gunnison began production in 2003 through a truss SPAR platform that can handle 40,000 bbls/d of oil and 200 mmcf/d of gas.

 

*Shelf*

 

Our shelf producing assets are offshore Louisiana, primarily in three 100%-owned field areas: Eugene Island 255/257, Eugene Island 258/259 and Eugene Island 295.

 

*Exploration*

 

We hold approximately 190 blocks in the US Gulf of Mexico. Our undeveloped deep-water discoveries include:

 
| **Well**   | ** ** | **Interest ****(%)** | ** ** | **Operator Status** | ** ** | **Comments**                                                          |
|------------|------------|---------------------------|------------|--------------------------|------------|-----------------------------------------------------------------------|
| Appomattox |       | 20                        |       | non-operated             |       | discovery;   continued appraisal while evaluating development options |
| Stampede   |       | 20                        |       | non-operated             |       | discovery;   currently progressing development plans                  |
| Vicksburg  |       | 25                        |       | non-operated             |       | discovery;   continued appraisal                                      |

 

In 2010, we discovered Appomattox, approximately six miles west of our Vicksburg discovery. Preliminary results indicated a significant oil discovery with the potential to extend the discovery. In 2011, results of appraisal drilling and commencement of development planning allowed us to recognize 65 mmboe of probable reserves on the south fault block, net to Nexen. 

 

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In 2012, we further appraised the south fault block and encountered oil in the northeast fault block, which added 42 mmboe of probable reserves, net to Nexen.

 

In 2012, we concluded negotiations with our joint venture partners for potential development of the Stampede field (formerly Knotty Head-Pony). Each partner has a 20% working interest in the project and we are progressing development plans.

 

**OTHER INTERNATIONAL**

 

OFFSHORE NIGERIA

 

In 1998, we acquired a 20% non-operated interest in Block OPL-222, which covers 448,000 acres approximately 80 km offshore Nigeria in water depths ranging from 200 to 1,200 metres. In 1998, we discovered the Ukot field and in 2002, the Usan field was discovered with seven wells confirming the presence of significant hydrocarbon accumulations. In 2007, OPL- 222 was converted to two Oil Mining Leases, OML-138 and 139. The Usan development is within OML-138.

 

The Usan field achieved first oil in early 2012 and produced an average of 80,500 bbls/d (16,100 net to Nexen) since start-up. Production from Usan is processed through a FPSO which has capacity of 180,000 bbls/d (36,000 bbls/d, net to us). The FPSO can store up to two million barrels of oil before being offloaded onto tankers for delivery to customers. We are actively exploring the OPL-223 Block in Nigeria, in which we hold a 20% equity interest.

 

As is typical in many jurisdictions, the Nigerian government is reviewing its existing petroleum fiscal terms, including those applicable to our interests, the impact of which could negatively affect the economics of our projects.

 

YEMEN

 

In Yemen, production first began at Masila on Block 14 in 1993. We operated Masila, the country’s largest oil project, for 18 years and developed strong relationships with the government and local communities. The Masila production sharing agreement (PSA) expired in 2011 and production, operations, central processing facility, main oil pipeline and export facilities were transferred to the Yemen Government. We continue to operate the East Al Hajr facility (Block 51).

 

The first successful exploratory well at Block 51 was drilled in 2003 and development of the block began in 2004, which included a central processing facility (CPF), gathering system and a 22 km tie-back to an oil export pipeline. Production commenced in late 2004 and approximately 69 wells are currently on stream. Oil is delivered to customers via tankers in the Gulf of Aden.

 

We operate Block 51, which is governed by the Block 51 PSA between the Government of Yemen and the East Al Hajr partners; The Yemen Company (TYCO) (12.5% carried working interest) and Nexen (87.5% working interest). Under the PSA, TYCO has no obligation to fund the capital or operating expenditures and, therefore, our effective interest is 100%. For purposes of accounting and reserves recognition, we treat TYCO’s 12.5% participating interest as a royalty interest. The Block 51 PSA expires in 2023.

 

Our production in Yemen in 2012 was 4,500 bbls/d (2,500 bbls/d after royalties).

 

COLOMBIA

 

We currently hold interests in six exploration and production blocks in the Upper Magdalena Basin and the Eastern Cordillera area. In the Upper Magdalena Basin, we hold a 10% interest in the Boqueron block and a 50% non-operating interest in the Villarrica Norte Block. In the Eastern Cordillera area, we hold a 100% interest in the Chiquinquira, Sueva, Barbosa and Garagoa exploration and production blocks.

 

In 2000, we made a discovery at Guando on the 20% non-operated Boqueron Block, and production from the Guando field began in 2001. Boqueron is in the Upper Magdalena Basin of central Colombia, approximately 100 km southwest of Bogota. Under the terms of our licence, our working interest in Guando decreased from 20% to 10% in 2009 when cumulative oil production from the field reached 60 million barrels. Our share of production in Colombia in 2012 was 1,500 bbls/d (1,400 bbls/d after royalties).

 

We are in the early stages of shale gas exploration in Colombia. We are currently drilling a shale gas exploration well at Karupa and results are expected in 2013.

 

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**OIL SANDS**

 

The Athabasca oil sands deposit in northeast Alberta is a key growth area for us. We have a 7.23% investment in the Syncrude oil sands mining and upgrading operation. Our operated project at Long Lake involves integrating SAGD bitumen production with upgrading technology to produce PSCTM for sale and synthetic gas, which significantly reduces our need to purchase natural gas for SAGD operations. We also hold significant undeveloped in situ acreage.

 

In Situ Oil Sands

 

In 2001, we formed a joint venture with OPTI Canada Inc. (OPTI) to develop the Long Lake oil sands lease and several other joint venture leases using SAGD for bitumen production and proprietary OrCrudeTM technology to upgrade the bitumen to PSCTM. SAGD operations at Long Lake started in 2008 and we began producing PSCTM from the upgrader in 2009. Early in 2009, we acquired an additional 15% interest in the Long Lake project and other joint venture lands from OPTI, increasing our ownership level to 65%. Following the acquisition, we became operator of the entire project.

 

In 2011, CNOOC acquired OPTI, which included the 35% non-operated interest in the Long Lake project and joint venture lands.

 

SAGD AND UPGRADER INTEGRATION

 

The SAGD process involves drilling two parallel horizontal wells about 16 feet apart, with horizontal portions generally between 2,300 and 3,300 feet long. Steam is injected into the shallower well (the injector) where it heats the bitumen that then flows by gravity to the deeper producing well (the producer). Once the bitumen reaches the surface, the SAGD facilities remove water and add diluent to allow the bitumen to flow more easily.

 

At Long Lake, the OrCrudeTM technology, using conventional distillation, solvent de-asphalting and thermal cracking, separates the produced bitumen into partially upgraded sour crude oil and liquid asphaltenes. By coupling the OrCrudeTM process with hydrocracking and gasification technologies, the sour crude oil is upgraded to light (39° API) PSCTM and the asphaltenes are converted to a low-energy, synthetic fuel gas. This gas is used as a low-cost fuel for generating steam in the SAGD facilities and as a source of hydrogen for the hydrocracking process in the upgrader. The gas is also consumed in an 85 MW unit cogeneration plant to produce electricity for on-site use and sale to the provincial electricity grid. The energy conversion efficiency for our Long Lake upgrader is about 90%, compared to 75% for a typical bitumen-fed coker-based plant.

 

LONG LAKE PROJECT

 

The Long Lake project is located approximately 40 km southeast of Fort McMurray, Alberta and operations include steam generation and water treatment facilities, cogeneration plant, SAGD operations and an upgrader. Bitumen is produced from the McMurray reservoir using 99 well pairs located on 13 pads. Steam is generated from six once-through steam boilers and two cogeneration units.

 

The first several months of steam injection into a well pair largely involve heating the reservoir, followed by a ramp-up of bitumen production to peak rates over 12 to 24 months. At the start of production, steam-to-oil ratios (SORs) are high but are expected to decline as bitumen production ramps up to target rates. We expect the SOR at Long Lake will be in the range of three to four over the long term.

 

Initially, we expected to fill the upgrader from the first 11 pads; however, we underestimated the impact that reservoir quality would have on production rates and steam-oil ratio (SOR). We better understand the correlation between reservoir characteristics, production and SOR, based on the range of well performance we’ve experienced in the initial wells. This understanding allows us to target development in the best quality resource. It also confirms that our oil sands lands, including undeveloped areas on the Long Lake lease, contain attractive resource.

 

In 2012, we continued to progress our oil sands resource development strategy to accelerate increasing bitumen production for filling the Long Lake facilities. Our progress in 2012 included:

 

·                  maintain production from the initial 10 pads;

·                  ramp-up of pad 11;

·                  earlier than expected production at pads 12 and 13;

·                  regulatory approval for development on pads 14 and 15 and Kinosis K1A project;

·                  began drilling pads 14 and 15 at Long Lake and Kinosis K1A; and

·                  continue to process third-party sourced bitumen in the interim to enhance returns.

 

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We expect to maintain bitumen production over the project’s life, estimated in excess of 50 years, by drilling sustaining SAGD well pairs. In 2012, we began the early stages of developing future pads in the southwest area of the Long Lake lease.

 

The upgrader consists of the OrCrudeTM unit, air separation unit, hydro-cracker, sulphur recovery facilities and gasifier. Production design capacity for the Long Lake upgrader is approximately 60,000 bbls/d (39,000 bbls/d net to us) of PSCTM. We are progressing projects to increase the operating independence between our SAGD facilities and upgrader while maintaining the benefits of integration. The facilities are currently able to import between 10,000 and 15,000 bbls/d of third-party bitumen to process into PSCTM through the upgrader when it makes sense to do so. This capacity will be reduced as our proprietary production ramps up.

 

In 2012, we processed about 31,100 bbls/d gross (20,200 bbls/d net to us) of proprietary and third-party bitumen through the upgrader, producing 22,900 bbls/d gross (14,900 bbls/d net to us) of PSCTM. PSCTM is transported via the Athabasca Pipeline to Hardisty and sold to customers in Canada and the US.

 

OTHER PROJECTS

 

To further evaluate our Long Lake, Kinosis, Leismer and Cottonwood leases for future development, a three-year winter drilling program was initiated in 2012. This program supports our sustaining development activities to keep the Long Lake facilities full and to begin developing our other in situ leases.

 

Syncrude

 

We hold a 7.23% participating interest in the Syncrude joint venture. This joint venture was established in 1975 to mine shallow oil sand deposits using open-pit mining methods, extract the bitumen and upgrade it to a high-quality, light (32° API), sweet, synthetic crude oil.

 

Syncrude exploits a portion of the Athabasca oil sands that contains bitumen in the unconsolidated sands of the McMurray formation. Ore bodies are buried beneath 50 to 150 feet of over-burden, have bitumen grades ranging from 4 to 14% by weight and ore-bearing sand thickness of 100 to 160 feet. Syncrude’s operations are on eight leases (10, 12, 17, 22, 29, 30, 31 and 34) covering 248,300 acres, 40 km north of Fort McMurray in northeast Alberta. Syncrude currently mines oil sands at two mines: Mildred Lake North and Aurora North. Trucks and shovels are used to collect the oil sands in the open-pit mines. The oil sands are transferred for processing using a hydro-transport system.

 

The extraction facilities, which separate bitumen from oil sands, are capable of processing more than 310 million tons of oil sands per year and between 140 and 160 million barrels of bitumen per year depending on the average bitumen ore grade. To extract bitumen, the oil sands are mixed with water to form a slurry. Air and chemicals are added to separate bitumen from the sand grains. The process at the Mildred Lake North Mine uses hot water, steam and caustic soda to create a slurry, while at the Aurora North Mine, the oil sands are mixed with warm water. Close to 90% of the water used in operations is recycled from the upgrader and mine sites. Incremental water is drawn from the Athabasca River in accordance with existing licences.

 

The extracted bitumen is fed into a vacuum distillation tower and three cokers for primary upgrading, which ultimately become light, sweet, synthetic crude oil. Sulphur and coke, which are by-products of the process, are stockpiled for possible future sale.

 

The high quality of Syncrude’s synthetic crude oil allows it to be sold at prices approximating WTI. In 2012, about 45% of the synthetic crude oil was sold to refineries in Eastern Canada, 40% to those in the mid-western United States and the remaining 15% was sold to refineries in the Edmonton area. Electricity is provided to Syncrude from two generating plants on site: a 270 MW plant and an 80 MW plant.

 

Since operations started in 1978, Syncrude has shipped more than two billion barrels of synthetic crude oil to Edmonton by Alberta Oil Sands Pipeline Ltd. The pipeline was expanded in 2004 and 2009 to accommodate increased Syncrude production.

 

In 1999, the Alberta Energy and Utilities Board (AEUB) extended Syncrude’s operating licence for the eight oil sands leases through to 2035. The licence permits Syncrude to mine oil sands and produce synthetic crude oil from approved development areas on the oil sands leases. The leases are automatically renewable as long as oil sands operations are ongoing or the leases are part of an approved development plan. All eight leases are included in a development plan approved by the AEUB. There were no known commercial operations on these leases prior to the start-up of operations in 1978.

 

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In 1999, the AEUB approved an increase in Syncrude’s production capacity to 465,700 bbls/d. At the end of 2001, Syncrude increased its synthetic crude oil capacity to 246,500 bbls/d with the development of the Aurora North Mine, which involved extending mining operations to a new location about 40 km north of the main Syncrude site. The next expansion of Syncrude came on stream in 2006, increasing capacity to 360,000 bbls/d with the completion of the Stage 3 project.

 

Syncrude pays royalties to the Alberta government. Effective January 1, 2009, and consistent with other oil sands producers, Syncrude began paying royalties based on bitumen, rather than paying royalties calculated on fully upgraded synthetic crude oil. As a part of this conversion, the Alberta government will recapture royalties related to upgrader capital expenses of about $5 billion (gross) that were deducted against prior royalties from future production over a 25-year period. In connection with the transition to the revised Alberta royalty framework, Syncrude will continue to pay base royalty rates (being the greater of 25% of net bitumen-based revenues, or 1% of gross bitumen-based revenues) plus an incremental royalty of up to $975 million (our share $70.5 million) until December 31, 2015. The incremental royalty is subject to certain minimum bitumen production thresholds and is to be paid in six annual payments. This agreement is in lieu of the Syncrude owners converting to the Province of Alberta’s new royalty framework that became effective January 1, 2009. After January 1, 2016, the rates under the new Alberta royalty framework will apply to the Syncrude project.

 

**SHALE GAS**

 

As part of our growth strategy in unconventional Canadian resource plays, we have accumulated over 300,000 gross acres (180,000 net to us) of prospective shale gas lands in northeast British Columbia. Shale gas is natural gas produced from reservoirs composed of organic shale. The gas is stored in pore spaces and fractures, or absorbed into organic matter. Recent advances in drilling and completion technology have allowed companies to access this considerable potential resource.

 

Our shale gas resource allows us to take advantage of emerging markets such as growing oil sands demand and potential liquid natural gas (LNG) export opportunities off the west coast. Shale gas complements our corporate oil and gas portfolio with natural gas exposure and relatively short cycle-time projects where we control the scale and pace of development of the resource. We can match the pace of drilling and field development to forecasted economic conditions.

 

Our Canadian production (excluding the Athabasca oil sands) is comprised of unconventional shale gas assets in northeast British Columbia and conventional producing natural gas and coalbed methane (CBM) properties in Alberta and Saskatchewan.

 

Northeast British Columbia

 

We hold approximately 300,000 gross acres (180,000 net to us) in the Horn River, Cordova and Liard basins in northeast British Columbia. These basins are significant shale gas plays with high resource density and excellent well productivity. In August 2012, we closed a joint venture agreement to sell a 40% interest in our northeast British Columbia shale gas assets.

 

Our production is currently generated in the Horn River basin. In addition to our eight-well pad completed in 2010 and nine-well pad completed in 2011, we completed an 18-well pad with first production coming on stream mid-2012. Field processing capacity was expanded in 2012 from approximately 50 to 175 mmcf/d. Current operations are produced from 40 horizontal wells via pad developments, which minimize surface disturbances. Natural gas is compressed and dehydrated with in-field facilities before export to final treating facilities via pipelines. We hold long-term take or pay capacity on the third-party pipelines and facilities.

 

Primary tenure in the Horn River basin is four years and drilling activity and extensions can increase this up to 18 years. Our drilling activity to date has secured tenure for 10 years on all of our Horn River lands with extensions available of up to another three years. With the tenure secured, we are able to control the pace of field development during periods of low gas prices.

 

We are conducting exploration drilling programs on our leases in the Cordova and Liard basins.

 

Limited gas pipeline infrastructure and processing capacity in northeast British Columbia could potentially constrain early development of the play. To ensure sufficient gathering, processing and transportation capacity for our development programs, we contracted gas pipeline capacity and associated treating capacity at the Spectra-operated Fort Nelson plant. We also entered into additional agreements that allow us to participate in regional infrastructure expansion projects.

 

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Other Canada

 

Conventional natural gas properties in Alberta and Saskatchewan account for 31% of our 2012 Canadian natural gas production. This production is primarily generated from our Medicine Hat/Hatton conventional fields. These properties are mature but have low decline rates and numerous infill drilling opportunities. Our future investment here is limited as a result of low natural gas prices.

 

Approximately 26% of our 2012 Canadian natural gas was produced from our CBM developments in the Fort Assiniboine area of central Alberta. We began commercial operations in the Upper Mannville coals in 2005 and progressively developed opportunities on our land base with horizontal well technology. We have limited activity planned here for the future as a result of low natural gas prices.

 

Other International

 

During 2011, we entered into a joint venture agreement to explore ten concessions in Poland’s Paleozoic shale play. We acquired a 40% non-operated working interest in the concessions, which encompass more than two million acres. This opportunity provides potential shale gas exploration exposure close to European gas markets where prices are higher than in North America.

** **

**ENERGY MARKETING**

 

Our energy marketing group’s primary focus is to market Nexen’s proprietary crude oil and natural gas production. We also engage in market optimization activities including the purchase and sale of third-party production which provides us with additional market intelligence and opportunities in order to obtain competitive pricing for our proprietary volumes. Our team leverages regional knowledge and holds capacity on key North American infrastructure, including the Trans Mountain pipeline system to the west coast in Canada. In addition to physical marketing, we take advantage of quality, time and location spreads to generate returns. We also use financial contracts, including futures, forwards, swaps and options to manage our business. Results of these activities are included in Corporate and Other.

** **

**RESERVES, PRODUCTION AND RELATED INFORMATION**

 

Nexen prepares and discloses reserves estimates and other information in accordance with National Instrument 51-101—*Standards of Disclosure for Oil and Gas Activities*(NI 51-101) based on its current expectations of the future. Assuming closing of the transaction, as described on page 1, future activities of the Company will be directed by CNOOC.

 

In order to provide comparability to non-Canadian oil and gas companies, we also prepared reserves estimates and related information in accordance with SEC requirements, which are included in Appendix B of this AIF. Refer to the Special Note to Investors on page 33 for an explanation of differences between reserves estimates prepared under NI 51-101 and SEC requirements.

 

Nexen has not filed with nor included in reports to any Canadian or United States federal authority or agency any estimates of its total proved oil or gas reserves since the beginning of 2012.

 

Basis of Reserves Estimates

 

The process of estimating reserves requires complex judgments and decision-making based on available geological, geophysical, engineering and economic data. To estimate the economically recoverable oil and gas reserves and related future net cash flows, we consider many factors and make various assumptions including:

 

·                  expected reservoir characteristics based on geological, geophysical and engineering assessments;

·                  future production rates based on historical performance and expected future operating and investment activities;

·                  future oil and gas prices and quality differentials;

·                  assumed effects of regulation by governmental agencies; and

·                  future development and operating costs.

 

We believe these factors and assumptions are reasonable based on the information available to us at the time we prepared our estimates. However, there is no guarantee that the estimated reserves will be recovered and these estimates may change substantially as additional data from ongoing development activities and production performance becomes available and as economic conditions impacting oil and gas prices and costs change. For more information as to the risks involved in the recovery of oil and gas, see “Risk Factors” on pages 37 to 46 of this AIF.

 

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Our estimates of reserves and future net revenue are based on internal evaluations. Reserves estimates for each property are prepared at least annually by the property’s reservoir engineer and geoscientists, and by divisional management familiar with the property. Our internal reserves evaluation staff consists of over 180 individuals in multifunctional teams with relevant experience in reserves evaluation, engineering and geoscience, and over 135 of these individuals are qualified reserves evaluators for the purposes of NI 51-101. These individuals are dedicated to the development and operations of the properties evaluated and have a thorough knowledge of them. We support the technical staff with up-to-date tools for geological mapping, seismic interpretation, reservoir simulation and other technical analysis. Our reserves processes are designed to use all available information to provide accurate estimates for internal business needs and external reporting requirements. Due to the extent and expertise of our internal reserves evaluation resources, our staff’s familiarity with our properties and the controls applied to the evaluation process, we believe the reliability of our internally generated estimates of reserves and future net revenue is not materially less than would be generated by an independent qualified reserves evaluator.

 

Our internal qualified reserves evaluator (IQRE) is responsible for the reserves data and related disclosures. This position, required under NI 51-101, was appointed by the board in December 2003. The IQRE is a professional engineer and meets all professional and statutory requirements in regards to experience, education and professional membership associated with the role. With over 30 years of experience, the IQRE has an in-depth knowledge of reserves estimation techniques and professional guidelines, and with Canadian and SEC reserves regulations and related reporting requirements. The IQRE’s primary duty includes assessing whether the reserves estimates and related disclosures have been prepared in accordance with applicable regulatory requirements.

 

Although we have received an exemption from the NI 51-101 requirements to have our reserves estimates independently assessed, our policy is to have at least 80% of our NI 51-101 reserves estimates either evaluated or audited annually by independent qualified reserves consultants. The section entitled “Independent Reserves Evaluation” on pages 30 to 31 of the AIF describes the nature and scope of the work performed by the independent consultants and their opinions from performing this work.

 

An Executive Reserves Committee, including our CEO, CFO and IQRE, meet with divisional reserves personnel to review the estimates and any changes from previous estimates. The board of directors has a Reserves Review Committee (Reserves Committee) to assist the board and the Audit and Conduct Review Committee to oversee the annual review of our oil and gas reserves and related disclosures. The Reserves Committee is comprised of three or more directors, the majority of whom are independent and familiar with estimating oil and gas reserves and disclosure requirements. The Reserves Committee meets with management periodically to review the reserves process, the portfolio of properties selected by management for independent assessment, results and related disclosures. The Reserves Committee appoints and meets with the IQRE and independent qualified reserves consultants to review the scope of their work, whether they have had access to sufficient information, the nature and satisfactory resolution of any material differences of opinion, and in the case of the independent qualified reserves consultants, their independence. In the event of a proposed change to the areas of responsibility of either an independent qualified reserves consultant or the IQRE, the Reserves Committee inquires whether there have been disputes between the respective party and management.

 

The Reserves Committee has reviewed our procedures for preparing the reserves estimates and related disclosures, and the properties selected by management for independent assessment. The Committee reviewed the information with management and met with the IQRE and the independent qualified reserves consultants. As a result, the Reserves Committee is satisfied that the internally generated reserves estimates are reliable and free of material misstatement. Based on the recommendation of the Reserves Committee, the board has approved the reserves estimates and related disclosures in this AIF.

 

We have adopted a corporate policy that prescribes the procedures and standards to be followed in the evaluation of our reserves. This policy is reviewed and amended annually as required to conform to changes in law or industry accepted evaluation practices. A copy can be found on our corporate website at www.nexeninc.com.

 

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Reserves Estimates

 

The reserves data set forth on the following pages summarizes our crude oil and natural gas reserves and the net present value of the future net revenue for the reserves using forecast prices and costs. The information has been prepared in accordance with the requirements of NI 51-101. The estimates and other information has an effective date of December 31, 2012 and was prepared on February 24, 2013.

 

Readers should review the definitions and information contained in the “Definitions” section on pages 31 to 32 in conjunction with the following tables and notes.

 

Figures in this statement have been rounded to the nearest 1 mmbbls or 1 bcf. As a result, some columns may not add due to rounding.

 

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SUMMARY OF OIL AND GAS RESERVES AS AT DECEMBER 31, 2012

*Forecast prices and Costs*

 
| ** **                        | ** ** | **Total**   | ** ** | **Synthetic Oil** | ** ** | **Bitumen**  | ** ** | **Light and   Medium Oil** | ** ** | **Natural Gas** | ** ** | **CBM**    | ** ** | **Shale Gas** | ** ** |
|-----------------------------------|------------|-------------|------------|------------------------|------------|--------------|------------|--------------------------------------|------------|----------------------|------------|------------|------------|--------------------|------------|
| ** **                        | ** ** | **(mmboe)** | ** ** | **(mmbbls)**           | ** ** | **(mmbbls)** | ** ** | **(mmbbls)**                         | ** ** | **(bcf)**            | ** ** | **(bcf)**  | ** ** | **(bcf)**          | ** ** |
| ** **                        | ** ** | **Gross**   | ** ** | **Net**                | ** ** | **Gross**    | ** ** | **Net**                              | ** ** | **Gross**            | ** ** | **Net**    | ** ** | **Gross**          | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
| **Canada**                        |       |        |       |                   |       |         |       |                                 |       |                 |       |       |       |               |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Proved   Developed Producing      |       | 253         |       | 222                    |       | 214          |       | 186                                  |       | —               |       | —     |       | —             |       | — |   | 77 |   | 72 |   | 36 |   | 33 |   | 118 |   | 114 |   |
| Proved   Developed Non-Producing  |       | 6           |       | 6                      |       | 4            |       | 4                                    |       | —               |       | —     |       | —             |       | — |   | 11 |   | 10 |   | — |   | — |   | — |   | — |   |
| Proved   Undeveloped              |       | 428         |       | 374                    |       | 416          |       | 362                                  |       | —               |       | —     |       | —             |       | — |   | — |   | — |   | — |   | — |   | 71 |   | 69 |   |
| **Total Proved**                  | ** ** | **687**     | ** ** | **602**                | ** ** | **634**      | ** ** | **552**                              | ** ** | **—**           | ** ** | **—** | ** ** | **—**         | ** ** | **—** | ** ** | **88** | ** ** | **82** | ** ** | **36** | ** ** | **33** | ** ** | **189** | ** ** | **183** | ** ** |
| Probable                          |       | 987         |       | 807                    |       | 296          |       | 241                                  |       | 609                  |       | 490        |       | —             |       | — |   | 23 |   | 21 |   | 12 |   | 11 |   | 452 |   | 427 |   |
| **Total Proved Plus****Probable** | ** ** | **1,674**   | ** ** | **1,409**              | ** ** | **930**      | ** ** | **793**                              | ** ** | **609**              | ** ** | **490**    | ** ** | **—**         | ** ** | **—** | ** ** | **111** | ** ** | **103** | ** ** | **48** | ** ** | **44** | ** ** | **641** | ** ** | **610** | ** ** |
|                              |       |        |       |                   |       |         |       |                                 |       |                 |       |       |       |               |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| **United Kingdom**                |       |        |       |                   |       |         |       |                                 |       |                 |       |       |       |               |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Proved   Developed Producing      |       | 134         |       | 134                    |       | —       |       | —                               |       | —               |       | —     |       | 130                |       | 130 |   | 31 |   | 31 |   | — |   | — |   | — |   | — |   |
| Proved   Developed Non-Producing  |       | 1           |       | 1                      |       | —       |       | —                               |       | —               |       | —     |       | 1                  |       | 1 |   | — |   | — |   | — |   | — |   | — |   | — |   |
| Proved   Undeveloped              |       | 52          |       | 52                     |       | —       |       | —                               |       | —               |       | —     |       | 46                 |       | 46 |   | 35 |   | 35 |   | — |   | — |   | — |   | — |   |
| **Total Proved**                  | ** ** | **187**     | ** ** | **187**                | ** ** | **—**   | ** ** | **—**                           | ** ** | **—**           | ** ** | **—** | ** ** | **177**            | ** ** | **177** | ** ** | **66** | ** ** | **66** | ** ** | **—** | ** ** | **—** | ** ** | **—** | ** ** | **—** | ** ** |
| Probable                          |       | 93          |       | 93                     |       | —       |       | —                               |       | —               |       | —     |       | 86                 |       | 86 |   | 39 |   | 39 |   | — |   | — |   | — |   | — |   |
| **Total Proved Plus****Probable** | ** ** | **280**     | ** ** | **280**                | ** ** | **—**   | ** ** | **—**                           | ** ** | **—**           | ** ** | **—** | ** ** | **263**            | ** ** | **263** | ** ** | **105** | ** ** | **105** | ** ** | **—** | ** ** | **—** | ** ** | **—** | ** ** | **—** | ** ** |
|                              |       |        |       |                   |       |         |       |                                 |       |                 |       |       |       |               |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| **United States**                 |       |        |       |                   |       |         |       |                                 |       |                 |       |       |       |               |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Proved   Developed Producing      |       | 12          |       | 11                     |       | —       |       | —                               |       | —               |       | —     |       | 6                  |       | 6 |   | 34 |   | 28 |   | — |   | — |   | — |   | — |   |
| Proved   Developed Non-Producing  |       | 5           |       | 5                      |       | —       |       | —                               |       | —               |       | —     |       | 4                  |       | 4 |   | 8 |   | 7 |   | — |   | — |   | — |   | — |   |
| Proved   Undeveloped              |       | 7           |       | 6                      |       | —       |       | —                               |       | —               |       | —     |       | 3                  |       | 2 |   | 23 |   | 22 |   | — |   | — |   | — |   | — |   |
| **Total Proved**                  | ** ** | **24**      | ** ** | **22**                 | ** ** | **—**   | ** ** | **—**                           | ** ** | **—**           | ** ** | **—** | ** ** | **13**             | ** ** | **12** | ** ** | **65** | ** ** | **57** | ** ** | **—** | ** ** | **—** | ** ** | **—** | ** ** | **—** | ** ** |
| Probable                          |       | 181         |       | 157                    |       | —       |       | —                               |       | —               |       | —     |       | 166                |       | 143 |   | 95 |   | 83 |   | — |   | — |   | — |   | — |   |
| **Total Proved Plus****Probable** | ** ** | **205**     | ** ** | **179**                | ** ** | **—**   | ** ** | **—**                           | ** ** | **—**           | ** ** | **—** | ** ** | **179**            | ** ** | **155** | ** ** | **160** | ** ** | **140** | ** ** | **—** | ** ** | **—** | ** ** | **—** | ** ** | **—** | ** ** |
|                              |       |        |       |                   |       |         |       |                                 |       |                 |       |       |       |               |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| **Other****1**                    |       |        |       |                   |       |         |       |                                 |       |                 |       |       |       |               |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Proved   Developed Producing      |       | 21          |       | 18                     |       | —       |       | —                               |       | —               |       | —     |       | 21                 |       | 18 |   | — |   | — |   | — |   | — |   | — |   | — |   |
| Proved   Developed Non-Producing  |       | —      |       | —                 |       | —       |       | —                               |       | —               |       | —     |       | —             |       | — |   | — |   | — |   | — |   | — |   | — |   | — |   |
| Proved   Undeveloped              |       | 15          |       | 13                     |       | —       |       | —                               |       | —               |       | —     |       | 15                 |       | 13 |   | — |   | — |   | — |   | — |   | — |   | — |   |
| **Total Proved**                  | ** ** | **36**      | ** ** | **31**                 | ** ** | **—**   | ** ** | **—**                           | ** ** | **—**           | ** ** | **—** | ** ** | **36**             | ** ** | **31** | ** ** | **—** | ** ** | **—** | ** ** | **—** | ** ** | **—** | ** ** | **—** | ** ** | **—** | ** ** |
| Probable                          |       | 31          |       | 26                     |       | —       |       | —                               |       | —               |       | —     |       | 31                 |       | 26 |   | — |   | — |   | — |   | — |   | — |   | — |   |
| **Total Proved Plus****Probable** | ** ** | **67**      | ** ** | **57**                 | ** ** | **—**   | ** ** | **—**                           | ** ** | **—**           | ** ** | **—** | ** ** | **67**             | ** ** | **57** | ** ** | **—** | ** ** | **—** | ** ** | **—** | ** ** | **—** | ** ** | **—** | ** ** | **—** | ** ** |
|                              |       |        |       |                   |       |         |       |                                 |       |                 |       |       |       |               |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| **Total Company**                 |       |        |       |                   |       |         |       |                                 |       |                 |       |       |       |               |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Proved   Developed Producing      |       | 420         |       | 385                    |       | 214          |       | 186                                  |       | —               |       | —     |       | 157                |       | 154 |   | 142 |   | 131 |   | 36 |   | 33 |   | 118 |   | 114 |   |
| Proved   Developed Non-Producing  |       | 12          |       | 12                     |       | 4            |       | 4                                    |       | —               |       | —     |       | 5                  |       | 5 |   | 19 |   | 17 |   | — |   | — |   | — |   | — |   |
| Proved   Undeveloped              |       | 502         |       | 445                    |       | 416          |       | 362                                  |       | —               |       | —     |       | 64                 |       | 61 |   | 58 |   | 57 |   | — |   | — |   | 71 |   | 69 |   |
| **Total Proved**                  | ** ** | **934**     | ** ** | **842**                | ** ** | **634**      | ** ** | **552**                              | ** ** | **—**           | ** ** | **—** | ** ** | **226**            | ** ** | **220** | ** ** | **219** | ** ** | **205** | ** ** | **36** | ** ** | **33** | ** ** | **189** | ** ** | **183** | ** ** |
| Probable                          |       | 1,292       |       | 1,083                  |       | 296          |       | 241                                  |       | 609                  |       | 490        |       | 283                |       | 255 |   | 157 |   | 143 |   | 12 |   | 11 |   | 452 |   | 427 |   |
| **Total Proved Plus****Probable** | ** ** | **2,226**   | ** ** | **1,925**              | ** ** | **930**      | ** ** | **793**                              | ** ** | **609**              | ** ** | **490**    | ** ** | **509**            | ** ** | **475** | ** ** | **376** | ** ** | **348** | ** ** | **48** | ** ** | **44** | ** ** | **641** | ** ** | **610** | ** ** |

 

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*(1)   Other includes Yemen, Nigeria and Colombia.*

 

At December 31, 2012, our proved plus probable reserves estimates were approximately 2.2 billion boe, of which 0.9 billion boe are proved and 1.3 billion boe are probable.

 

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About 70% of our proved plus probable reserves relate to our Canadian oil sands properties. The synthetic oil reserves relate to our Long Lake and Kinosis K1A projects (referred to as Long Lake/K1A) and our non-operated interest in Syncrude. These reserves reflect bitumen which is upgraded on site into synthetic oil and are expected to be developed and produced through the existing upgrader facilities over the next 50 years. Our Kinosis K1A lands, a subset of the original Kinosis lease, will be developed in conjunction with Long Lake. The bitumen reserves relate to the remaining Kinosis lands (referred to as Kinosis) and the Hangingstone property. Project planning at Kinosis and Hangingstone is underway.

 

The remainder of our reserves are widely distributed throughout our oil and gas properties around the world. Our light and medium oil reserves relate to our offshore oil and gas operations in the UK North Sea, US Gulf of Mexico, Nigeria, and onshore Colombia. Our natural gas reserves relate to our properties in the US Gulf of Mexico, UK North Sea, and southern Alberta. Our CBM reserves are located primarily in central Alberta and our shale gas reserves are located in the Horn River basin in northeast British Columbia.

 

RECONCILIATION OF CHANGES IN RESERVES

 

The following table provides a reconciliation of Nexen’s total proved, probable and proved plus probable reserves (before royalties) for the year ended December 31, 2012 using forecast prices and costs.

 

GROSS RESERVES (NEXEN RESERVES BEFORE ROYALTIES)

 
| ** **                                | ** ** | **Total**   | ** ** | **Canada**                               | ** ** |
|-------------------------------------------|------------|-------------|------------|------------------------------------------|------------|
| ** **                                | ** ** | ** **  | ** ** | **Synthetic********Oil********Syncrude** | ** ** | **Synthetic********Oil********In Situ** | ** ** | **Bitumen ****1********In Situ** | ** ** | **Natural********Gas** | ** ** | **CBM** | ** ** | **Shale********Gas** | ** ** |
| **(Before Royalties)**               | ** ** | **(mmboe)** | ** ** | **(mmbbls)**                             | ** ** | **(mmbbls)** | ** ** | **(mmbbls)** | ** ** | **(bcf)** | ** ** | **(bcf)** | ** ** | **(bcf)** | ** ** |
| **Total Proved Reserves**                 |       |        |       |                                     |       |   |   |   |   |   |   |   |   |   |   |
| December 31, 2011                    |       | 1,008       |       | 324                                      |       | 319 |   | — |   | 128 |   | 69 |   | 319 |   |
| Discoveries                               |       | 1           |       | —                                   |       | — |   | — |   | — |   | — |   | — |   |
| Extensions and Improved   Recovery        |       | 22          |       | 8                                        |       | 7 |   | — |   | — |   | — |   | — |   |
| Technical Revisions                       |       | 2           |       | —                                   |       | (10 | ) | — |   | (19 | ) | (11 | ) | 13 |   |
| Economic Factors                          |       | (8          | )          | —                                   |       | — |   | — |   | (7 | ) | (11 | ) | (2 | ) |
| Dispositions                              |       | (20         | )          | —                                   |       | — |   | — |   | — |   | — |   | (122 | ) |
| Production                                |       | (71         | )          | (8                                       | )          | (6 | ) | — |   | (14 | ) | (11 | ) | (19 | ) |
| **December 31, 2012**                | ** ** | **934**     | ** ** | **324**                                  | ** ** | **310** | ** ** | **—** | ** ** | **88** | ** ** | **36** | ** ** | **189** | ** ** |
| **Total Probable Reserves**               |       |        |       |                                     |       |   |   |   |   |   |   |   |   |   |   |
| December 31, 2011                    |       | 1,298       |       | 46                                       |       | 231 |   | 661 |   | 33 |   | 24 |   | 742 |   |
| Discoveries                               |       | 102         |       | —                                   |       | — |   | — |   | — |   | — |   | — |   |
| Extensions and Improved   Recovery        |       | 55          |       | 8                                        |       | 41 |   | — |   | — |   | — |   | — |   |
| Technical Revisions                       |       | (37         | )          | —                                   |       | (30 | ) | (3 | ) | (6 | ) | (8 | ) | (5 | ) |
| Conversions 3                             |       | (35         | )          | (8                                       | )          | — |   | — |   | — |   | — |   | (13 | ) |
| Economic Factors                          |       | (42         | )          | —                                   |       | 8 |   | (49 | ) | (4 | ) | (4 | ) | 24 |   |
| Dispositions                              |       | (49         | )          | —                                   |       | — |   | — |   | — |   | — |   | (296 | ) |
| **December 31, 2012**                | ** ** | **1,292**   | ** ** | **46**                                   | ** ** | **250** | ** ** | **609** | ** ** | **23** | ** ** | **12** | ** ** | **452** | ** ** |
| **Total Proved Plus Probable   Reserves** |       |        |       |                                     |       |   |   |   |   |   |   |   |   |   |   |
| December 31, 2011                    |       | 2,306       |       | 370                                      |       | 550 |   | 661 |   | 161 |   | 93 |   | 1,061 |   |
| Discoveries                               |       | 103         |       | —                                   |       | — |   | — |   | — |   | — |   | — |   |
| Extensions and Improved   Recovery        |       | 77          |       | 16                                       |       | 48 |   | — |   | — |   | — |   | — |   |
| Technical Revisions                       |       | (35         | )          | —                                   |       | (40 | ) | (3 | ) | (24 | ) | (19 | ) | 8 |   |
| Conversions 3                             |       | (35         | )          | (8                                       | )          | — |   | — |   | — |   | — |   | (13 | ) |
| Economic Factors                          |       | (50         | )          | —                                   |       | 8 |   | (49 | ) | (12 | ) | (15 | ) | 22 |   |
| Dispositions                              |       | (69         | )          | —                                   |       | — |   | — |   | — |   | — |   | (418 | ) |
| Production                                |       | (71         | )          | (8                                       | )          | (6 | ) | — |   | (14 | ) | (11 | ) | (19 | ) |
| **December 31, 2012**                | ** ** | **2,226**   | ** ** | **370**                                  | ** ** | **560** | ** ** | **609** | ** ** | **111** | ** ** | **48** | ** ** | **641** | ** ** |

 

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Table of Contents

 

GROSS RESERVES (NEXEN RESERVES BEFORE ROYALTIES) continued

 
| ** **                                | ** ** | **United Kingdom**                     | ** ** | **United States** | ** ** | **Other ****2**                        | ** ** |
|-------------------------------------------|------------|---------------------------------------------|------------|------------------------|------------|---------------------------------------------|------------|
| ** **                                | ** ** | **Light and********Medium********Oil** | ** ** | **Natural********Gas** | ** ** | **Light and********Medium********Oil** | ** ** | **Natural********Gas** | ** ** | **Light and********Medium********Oil** | ** ** |
| **(Before Royalties)**               | ** ** | **(mmbbls)**                                | ** ** | **(bcf)**              | ** ** | **(mmbbls)**                                | ** ** | **(bcf)** | ** ** | **(mmbbls)** | ** ** |
| **Total Proved Reserves**                 |       |                                        |       |                   |       |                                        |       |   |   |   |   |
| December 31, 2011                    |       | 191                                         |       | 65                     |       | 16                                          |       | 106 |   | 43 |   |
| Discoveries                               |       | 1                                           |       | —                 |       | —                                      |       | — |   | — |   |
| Extensions and Improved   Recovery        |       | 3                                           |       | 1                      |       | —                                      |       | — |   | 4 |   |
| Technical Revisions                       |       | 18                                          |       | 14                     |       | —                                      |       | (12 | ) | (3 | ) |
| Economic Factors                          |       | (3                                          | )          | —                 |       | —                                      |       | (12 | ) | — |   |
| Dispositions                              |       | —                                      |       | —                 |       | —                                      |       | — |   | — |   |
| Production                                |       | (33                                         | )          | (14                    | )          | (3                                          | )          | (17 | ) | (8 | ) |
| **December 31, 2012**                | ** ** | **177**                                     | ** ** | **66**                 | ** ** | **13**                                      | ** ** | **65** | ** ** | **36** | ** ** |
| **Total Probable Reserves**               |       |                                        |       |                   |       |                                        |       |   |   |   |   |
| December 31, 2011                    |       | 98                                          |       | 41                     |       | 65                                          |       | 101 |   | 39 |   |
| Discoveries                               |       | —                                      |       | —                 |       | 101                                         |       | 7 |   | — |   |
| Extensions and Improved   Recovery        |       | 6                                           |       | 1                      |       | —                                      |       | — |   | — |   |
| Technical Revisions                       |       | —                                      |       | 9                      |       | —                                      |       | 2 |   | (2 | ) |
| Conversions 3                             |       | (18                                         | )          | (12                    | )          | —                                      |       | (10 | ) | (4 | ) |
| Economic Factors                          |       | —                                      |       | —                 |       | —                                      |       | (5 | ) | (2 | ) |
| Dispositions                              |       | —                                      |       | —                 |       | —                                      |       | — |   | — |   |
| **December 31, 2012**                | ** ** | **86**                                      | ** ** | **39**                 | ** ** | **166**                                     | ** ** | **95** | ** ** | **31** | ** ** |
| **Total Proved Plus Probable   Reserves** |       |                                        |       |                   |       |                                        |       |   |   |   |   |
| December 31, 2011                    |       | 289                                         |       | 106                    |       | 81                                          |       | 207 |   | 82 |   |
| Discoveries                               |       | 1                                           |       | —                 |       | 101                                         |       | 7 |   | — |   |
| Extensions and Improved   Recovery        |       | 9                                           |       | 1                      |       | —                                      |       | — |   | 4 |   |
| Technical Revisions                       |       | 17                                          |       | 23                     |       | —                                      |       | (10 | ) | (5 | ) |
| Conversions 3                             |       | (17                                         | )          | (12                    | )          | —                                      |       | (10 | ) | (4 | ) |
| Economic Factors                          |       | (3                                          | )          | 1                      |       | —                                      |       | (17 | ) | (2 | ) |
| Dispositions                              |       | —                                      |       | —                 |       | —                                      |       | — |   | — |   |
| Production                                |       | (33                                         | )          | (14                    | )          | (3                                          | )          | (17 | ) | (8 | ) |
| **December 31, 2012**                | ** ** | **263**                                     | ** ** | **105**                | ** ** | **179**                                     | ** ** | **160** | ** ** | **67** | ** ** |

 

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*(1)**        **Includes reserves for which there are no definitive plans for upgrading at this time.*

*(2)**        **Other includes Yemen, Nigeria and Colombia.*

*(3)**        **Technical revisions.*

 

PROVED RESERVES

 

During the year, proved reserves decreased 74 mmboe primarily as a result of production. Net additions and revisions were largely offset by the sale of Canadian shale gas reserves.

 

Extensions and improved recovery primarily relate to additions at Syncrude, recognition of additional Long Lake acreage delineated through core hole drilling, additional Buzzard well locations and extension of the Usan reservoir using demonstrated seismic-based technology.

 

Technical revisions resulted in a 2 mmboe net addition. The additions are primarily related to positive performance at our properties in the UK North Sea, and Block 51 in Yemen. These additions were partially offset by negative revisions at Long Lake/K1A primarily related to mapping updates as a result of our core hole drilling program. At Usan and US deep-water, the negative revisions are performance-related. At our Canada gas properties, negative revisions are caused by reduced well maintenance programs as a result of low gas prices.

 

Economic factors were primarily caused by lower future gas prices and operating cost increases.

 

Dispositions relate to the sale of a 40% interest through a joint venture arrangement in our Canadian shale gas properties in northeast British Columbia.

 

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PROBABLE RESERVES

 

Probable reserves were consistent with last year. The sale of Canadian shale gas reserves and conversions to proved reserves were offset by additions related to projects in the US Gulf of Mexico and changes to oil sands reserves.

 

Discoveries of 102 mmboe primarily relate to probable reserve additions in the US Gulf of Mexico.

 

Extensions and improved recovery of 55 mmboe primarily relate to additional delineation work for our Long Lake/K1A leases.

 

Technical revisions reduced probable reserves 37 mmboe and primarily reflect reduced oil-in-place expectations from the core hole drilling program at Long Lake/K1A.

 

Conversions reflect probable reserves that were converted to proved reserves as a result of increased expectations of producing the reserves based on advancement of development plans, positive production performance and/or drilling results.

 

Economic factors relate almost entirely to Kinosis where delays in our future development plans for bitumen projects reduced the amount of bitumen expected to be produced over a 50-year production period.

 

Dispositions relate to the sale of a 40% interest in our Canadian shale gas assets in northeast British Columbia.

 

UNDEVELOPED RESERVES

 

The following table discloses volumes of proved undeveloped and probable undeveloped reserves that were first attributed in the last three years.

 
| ** **                               | ** ** | **Proved Undeveloped (Before Royalties)** | ** ** |
|------------------------------------------|------------|----------------------------------------------------------|------------|
| ** **                               | ** ** | **2010 ****1**                                      | ** ** | **2011** | ** ** | **2012** | ** ** |
| ** **                               | ** ** | **First   Attributed**                                   | ** ** | **Booked at   Year-End** | ** ** | **First   Attributed** | ** ** | **Booked at   Year-End** | ** ** | **First   Attributed** | ** ** | **Booked at   Year-End** | ** ** |
| Synthetic Oil — In Situ *(mmbbls)*  |       | 3                                                        |       | 266 |   | 93 |   | 284 |   | 7 |   | 279 |   |
| Synthetic Oil — Syncrude *(mmbbls)* |       | 7                                                        |       | 123 |   | 8 |   | 131 |   | 8 |   | 137 |   |
| Bitumen *(mmbbls)*                       |       | —                                                   |       | — |   | — |   | — |   | — |   | — |   |
| Light and Medium Oil *(mmbbls)*          |       | 38                                                       |       | 100 |   | 1 |   | 70 |   | 7 |   | 64 |   |
| Shale Gas *(bcf)*                        |       | 103                                                      |       | 103 |   | 129 |   | 225 |   | — |   | 71 |   |
| Natural Gas *(bcf)*                      |       | 32                                                       |       | 81 |   | 7 |   | 57 |   | 1 |   | 58 |   |
| CBM *(bcf)*                              |       | 12                                                       |       | 13 |   | — |   | 7 |   | — |   | — |   |
| **Total***(mmboe)*                       | ** ** | **73**                                                   | ** ** | **522** | ** ** | **125** | ** ** | **533** | ** ** | **22** | ** ** | **502** | ** ** |

* *
| ** **                               | ** ** | **Probable Undeveloped (Before Royalties)** | ** ** |
|------------------------------------------|------------|------------------------------------------------------------|------------|
| ** **                               | ** ** | **2010****1**                                              | ** ** | **2011** | ** ** | **2012** | ** ** |
| ** **                               | ** ** | **First   Attributed**                                     | ** ** | **Booked at   Year-End** | ** ** | **First   Attributed** | ** ** | **Booked at   Year-End** | ** ** | **First   Attributed** | ** ** | **Booked at   Year-End** | ** ** |
| Synthetic Oil — In Situ *(mmbbls)*  |       | —                                                     |       | 861 |   | — |   | 221 |   | 41 |   | 235 |   |
| Synthetic Oil — Syncrude *(mmbbls)* |       | 17                                                         |       | 46 |   | 8 |   | 46 |   | 8 |   | 46 |   |
| Bitumen *(mmbbls)*                       |       | —                                                     |       | — |   | 49 |   | 661 |   | — |   | 609 |   |
| Light and Medium Oil *(mmbbls)*          |       | 7                                                          |       | 89 |   | 67 |   | 121 |   | 108 |   | 211 |   |
| Shale Gas *(bcf)*                        |       | 19                                                         |       | 19 |   | 656 |   | 695 |   | — |   | 404 |   |
| Natural Gas *(bcf)*                      |       | 20                                                         |       | 61 |   | 43 |   | 74 |   | 8 |   | 68 |   |
| CBM *(bcf)*                              |       | 3                                                          |       | 3 |   | — |   | 2 |   | — |   | — |   |
| **Total***(mmboe)*                       | ** ** | **31**                                                     | ** ** | **1,010** | ** ** | **241** | ** ** | **1,178** | ** ** | **158** | ** ** | **1,180** | ** ** |

 

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*(1) Reserves data is unavailable prior to 2010 when Nexen received an exemption from certain requirements of NI 51-101.*

 

Approximately half of our proved reserves are undeveloped at December 31, 2012. More than 80% of these proved undeveloped reserves (PUDs) are located on our oil sands properties at Long Lake/K1A and Syncrude which will be developed as we need bitumen feedstock to supply the upgraders during their expected lives. Other PUDs relate to ongoing development activity in the UK North Sea at Buzzard, Golden Eagle, Rochelle and Telford, in Canada at our Horn River shale gas properties, in Nigeria at Usan, and in the US Gulf of Mexico.

 

The synthetic oil in situ PUDs relate to reserves needed to supply the Long Lake upgrader over its expected life. They are expected to be converted to proved developed reserves over the next 29 years as we drill additional SAGD wells at Long Lake/K1A to offset declines from the initial wells. These wells were part of the initial field development plan and included in the project investment decision. The Syncrude synthetic oil PUDs relate to Syncrude’s Aurora South mine. The mine is included in the Syncrude development plan and was contemplated in the project investment decision relating to the Stage 3 expansion completed in 2005. 

 

20

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We do not consider this mine to be developed as the extraction equipment required to access the reserves has not yet been moved to the mine site. We are proceeding with planning for the development of the mine and other mining leases and expect to commence construction in five to six years. The Aurora South mine PUDs of 137 mmbbls are expected to be converted to proved developed reserves in eight to ten years.

 

Our light and medium oil PUDs are primarily located in the UK North Sea, offshore Nigeria and the US Gulf of Mexico. In the UK North Sea, 46 mmbbls of light and medium oil PUDs primarily relate to development projects underway at Golden Eagle, Rochelle, Solitaire and Peregrine, and ongoing development of the Buzzard and Ettrick fields. We have 15 mmbbls of PUDs at our offshore Nigeria property, which are expected to be converted to proved developed reserves over the next three years as development drilling is completed. The remaining PUDs are located in the US Gulf of Mexico.

 

Our shale gas PUDs are reserves related to development of one 20-well pad we are currently drilling at Horn River in northeast British Columbia.

 

Our natural gas PUDs are located in the UK North Sea and US Gulf of Mexico, and connected to our light and medium oil projects.

 

We expect to convert all of our PUDs to proved developed in the next four years except at Long Lake/K1A and Syncrude, which are expected to be converted to developed as required to keep the upgraders full for the next 35 years.

 

We expect our ongoing exploration and development activities will continue to add new PUDs.

 

The majority of our probable reserves are undeveloped and primarily reflect incremental synthetic oil reserves related to future drilling to keep the Long Lake upgrader full for 50 years, expected SAGD development of the bitumen resource at Kinosis and Hangingstone, and extension of the plant life and expected higher future yields at Syncrude. The remaining probable undeveloped reserves relate to ongoing pad development of Horn River, discoveries in the Gulf of Mexico, discoveries offshore Nigeria and other projects. These probable reserves will typically be developed in conjunction with proved reserves, but can take longer periods to develop. We expect these remaining probable undeveloped reserves will be developed over the next ten years.

 

Our oil sands projects are large-scale developments with significantly longer production lives than conventional oil and gas projects. The proved and probable reserves associated with these projects are developed over a period of decades within the limits of facility capacity.

 

Net Present Value of Future Net Revenue

 

The estimates of future net revenues presented in the following tables do not represent the fair market value of the reserves. There is no assurance that the forecast prices and costs assumptions will be attained and variances could be material.

 

Future net revenue includes estimated future abandonment costs related to wells and production facilities required to produce the reserves which have been developed or are anticipated to be developed.

 

21

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NET PRESENT VALUE OF FUTURE NET REVENUE BEFORE INCOME TAXES

AS AT DECEMBER 31, 2012

*Forecast Prices and Costs*

 
| ** **                     | ** ** | **Before Income Taxes Discounted at (%/Year)   (Cdn$ millions)** | ** ** | **Unit Value   Before Tax****1****Discounted   at 10%** | ** ** |
|--------------------------------|------------|------------------------------------------------------------------------------------------------|------------|------------------------------------------------------------------------|------------|
| ** **                     | ** ** | **0%**                                                                                         | ** ** | **5%**                                                                 | ** ** | **10%** | ** ** | **15%** | ** ** | **20%** | ** ** | **($/boe)** | ** ** |
| **Proved**                     |       |                                                                                           |       |                                                                   |       |   |   |   |   |   |   |   |   |
| Canada                         |       |                                                                                           |       |                                                                   |       |   |   |   |   |   |   |   |   |
| Proved Developed Producing     |       | 8,726                                                                                          |       | 5,037                                                                  |       | 3,321 |   | 2,413 |   | 1,878 |   | 14.92 |   |
| Proved Developed Non-Producing |       | 68                                                                                             |       | 51                                                                     |       | 31 |   | 13 |   | (2 | ) | 5.19 |   |
| Proved Undeveloped             |       | 14,025                                                                                         |       | 4,457                                                                  |       | 1,349 |   | 146 |   | (389 | ) | 3.61 |   |
|                           | ** ** | **22,819**                                                                                     | ** ** | **9,545**                                                              | ** ** | **4,701** | ** ** | **2,572** | ** ** | **1,487** | ** ** | **7.80** | ** ** |
| United Kingdom                 |       |                                                                                           |       |                                                                   |       |   |   |   |   |   |   |   |   |
| Proved Developed Producing     |       | 8,832                                                                                          |       | 7,828                                                                  |       | 7,018 |   | 6,371 |   | 5,849 |   | 52.37 |   |
| Proved Developed Non-Producing |       | 73                                                                                             |       | 58                                                                     |       | 48 |   | 41 |   | 37 |   | 55.00 |   |
| Proved Undeveloped             |       | 2,210                                                                                          |       | 1,884                                                                  |       | 1,548 |   | 1,265 |   | 1,036 |   | 29.76 |   |
| ** **                     | ** ** | **11,115**                                                                                     | ** ** | **9,770**                                                              | ** ** | **8,614** | ** ** | **7,677** | ** ** | **6,922** | ** ** | **46.09** | ** ** |
| United States                  |       |                                                                                           |       |                                                                   |       |   |   |   |   |   |   |   |   |
| Proved Developed Producing     |       | (153                                                                                           | )          | (75                                                                    | )          | (25 | ) | 7 |   | 29 |   | (2.40 | ) |
| Proved Developed Non-Producing |       | 253                                                                                            |       | 207                                                                    |       | 172 |   | 145 |   | 123 |   | 37.29 |   |
| Proved Undeveloped             |       | 171                                                                                            |       | 131                                                                    |       | 101 |   | 79 |   | 63 |   | 16.56 |   |
|                           | ** ** | **271**                                                                                        | ** ** | **263**                                                                | ** ** | **248** | ** ** | **231** | ** ** | **215** | ** ** | **11.61** | ** ** |
| Other Countries 2              |       |                                                                                           |       |                                                                   |       |   |   |   |   |   |   |   |   |
| Proved Developed Producing     |       | 1,020                                                                                          |       | 957                                                                    |       | 899 |   | 847 |   | 800 |   | 49.85 |   |
| Proved Developed Non-Producing |       | —                                                                                         |       | —                                                                 |       | — |   | — |   | — |   | — |   |
| Proved Undeveloped             |       | 935                                                                                            |       | 805                                                                    |       | 698 |   | 609 |   | 533 |   | 54.78 |   |
|                           | ** ** | **1,955**                                                                                      | ** ** | **1,762**                                                              | ** ** | **1,597** | ** ** | **1,456** | ** ** | **1,333** | ** ** | **51.89** | ** ** |
| Total Company                  |       |                                                                                           |       |                                                                   |       |   |   |   |   |   |   |   |   |
| Proved Developed Producing     |       | 18,425                                                                                         |       | 13,747                                                                 |       | 11,213 |   | 9,638 |   | 8,556 |   | 29.10 |   |
| Proved Developed Non-Producing |       | 394                                                                                            |       | 316                                                                    |       | 251 |   | 199 |   | 158 |   | 21.96 |   |
| Proved Undeveloped             |       | 17,341                                                                                         |       | 7,277                                                                  |       | 3,696 |   | 2,099 |   | 1,243 |   | 8.31 |   |
| **Total Proved**               | ** ** | **36,160**                                                                                     | ** ** | **21,340**                                                             | ** ** | **15,160** | ** ** | **11,936** | ** ** | **9,957** | ** ** | **18.02** | ** ** |
|                           |       |                                                                                           |       |                                                                   |       |   |   |   |   |   |   |   |   |
| **Probable**                   |       |                                                                                           |       |                                                                   |       |   |   |   |   |   |   |   |   |
| Canada                         |       | 34,181                                                                                         |       | 9,515                                                                  |       | 3,468 |   | 1,417 |   | 538 |   | 4.29 |   |
| United Kingdom                 |       | 7,740                                                                                          |       | 5,873                                                                  |       | 4,640 |   | 3,801 |   | 3,203 |   | 50.13 |   |
| United States                  |       | 10,627                                                                                         |       | 5,469                                                                  |       | 2,908 |   | 1,557 |   | 806 |   | 18.52 |   |
| Other Countries 2              |       | 1,175                                                                                          |       | 788                                                                    |       | 550 |   | 396 |   | 293 |   | 21.27 |   |
| **Total Probable**             | ** ** | **53,723**                                                                                     | ** ** | **21,645**                                                             | ** ** | **11,566** | ** ** | **7,171** | ** ** | **4,840** | ** ** | **10.68** | ** ** |
|                           |       |                                                                                           |       |                                                                   |       |   |   |   |   |   |   |   |   |
| **Proved Plus Probable**       |       |                                                                                           |       |                                                                   |       |   |   |   |   |   |   |   |   |
| Canada                         |       | 57,001                                                                                         |       | 19,060                                                                 |       | 8,169 |   | 3,989 |   | 2,025 |   | 5.79 |   |
| United Kingdom                 |       | 18,854                                                                                         |       | 15,643                                                                 |       | 13,255 |   | 11,478 |   | 10,125 |   | 47.42 |   |
| United States                  |       | 10,897                                                                                         |       | 5,732                                                                  |       | 3,156 |   | 1,788 |   | 1,021 |   | 17.69 |   |
| Other Countries 2              |       | 3,131                                                                                          |       | 2,550                                                                  |       | 2,146 |   | 1,851 |   | 1,626 |   | 37.91 |   |
| **Total Proved Plus Probable** | ** ** | **89,883**                                                                                     | ** ** | **42,985**                                                             | ** ** | **26,726** | ** ** | **19,106** | ** ** | **14,797** | ** ** | **13.88** | ** ** |

 

----

*(1)   The unit values are based on net reserve volumes.*

*(2)   Represents reserves in Yemen, Nigeria and Colombia.*

 

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NET PRESENT VALUE OF FUTURE NET REVENUE AFTER INCOME TAXES

AS AT DECEMBER 31, 2012

*Forecast Prices and Costs*

 
| ** **                     | ** ** | **After Income Taxes Discounted at (%/Year) ****1****(Cdn$ millions)** | ** ** |
|--------------------------------|------------|-----------------------------------------------------------------------------------------------------------|------------|
| ** **                     | ** ** | **0%**                                                                                                    | ** ** | **5%** | ** ** | **10%** | ** ** | **15%** | ** ** | **20%** | ** ** |
| **Proved**                     |       |                                                                                                      |       |   |   |   |   |   |   |   |   |
| Canada                         |       |                                                                                                      |       |   |   |   |   |   |   |   |   |
| Proved Developed Producing     |       | 8,726                                                                                                     |       | 5,037 |   | 3,321 |   | 2,413 |   | 1,878 |   |
| Proved Developed Non-Producing |       | 68                                                                                                        |       | 51 |   | 31 |   | 13 |   | (2 | ) |
| Proved Undeveloped             |       | 10,800                                                                                                    |       | 3,482 |   | 1,020 |   | 25 |   | (437 | ) |
|                           | ** ** | **19,594**                                                                                                | ** ** | **8,570** | ** ** | **4,372** | ** ** | **2,451** | ** ** | **1,439** | ** ** |
| United Kingdom                 |       |                                                                                                      |       |   |   |   |   |   |   |   |   |
| Proved Developed Producing     |       | 3,201                                                                                                     |       | 2,880 |   | 2,603 |   | 2,374 |   | 2,187 |   |
| Proved Developed Non-Producing |       | 27                                                                                                        |       | 22 |   | 18 |   | 15 |   | 14 |   |
| Proved Undeveloped             |       | 798                                                                                                       |       | 701 |   | 583 |   | 480 |   | 394 |   |
|                           | ** ** | **4,026**                                                                                                 | ** ** | **3,603** | ** ** | **3,204** | ** ** | **2,869** | ** ** | **2,595** | ** ** |
| United States                  |       |                                                                                                      |       |   |   |   |   |   |   |   |   |
| Proved Developed Producing     |       | (153                                                                                                      | )          | (75 | ) | (25 | ) | 7 |   | 29 |   |
| Proved Developed Non-Producing |       | 253                                                                                                       |       | 207 |   | 172 |   | 145 |   | 123 |   |
| Proved Undeveloped             |       | 171                                                                                                       |       | 130 |   | 101 |   | 79 |   | 63 |   |
|                           | ** ** | **271**                                                                                                   | ** ** | **262** | ** ** | **248** | ** ** | **231** | ** ** | **215** | ** ** |
| Other Countries 2              |       |                                                                                                      |       |   |   |   |   |   |   |   |   |
| Proved Developed Producing     |       | 999                                                                                                       |       | 937 |   | 881 |   | 829 |   | 783 |   |
| Proved Developed Non-Producing |       | —                                                                                                    |       | — |   | — |   | — |   | — |   |
| Proved Undeveloped             |       | 935                                                                                                       |       | 805 |   | 697 |   | 609 |   | 533 |   |
|                           | ** ** | **1,934**                                                                                                 | ** ** | **1,742** | ** ** | **1,578** | ** ** | **1,438** | ** ** | **1,316** | ** ** |
| Total Company                  |       |                                                                                                      |       |   |   |   |   |   |   |   |   |
| Proved Developed Producing     |       | 12,773                                                                                                    |       | 8,779 |   | 6,780 |   | 5,623 |   | 4,877 |   |
| Proved Developed Non-Producing |       | 348                                                                                                       |       | 280 |   | 221 |   | 173 |   | 135 |   |
| Proved Undeveloped             |       | 12,704                                                                                                    |       | 5,118 |   | 2,401 |   | 1,193 |   | 553 |   |
| **Total Proved**               | ** ** | **25,825**                                                                                                | ** ** | **14,177** | ** ** | **9,402** | ** ** | **6,989** | ** ** | **5,565** | ** ** |
|                           |       |                                                                                                      |       |   |   |   |   |   |   |   |   |
| **Probable**                   |       |                                                                                                      |       |   |   |   |   |   |   |   |   |
| Canada                         |       | 25,369                                                                                                    |       | 7,057 |   | 2,568 |   | 1,022 |   | 344 |   |
| United Kingdom                 |       | 2,921                                                                                                     |       | 2,240 |   | 1,776 |   | 1,457 |   | 1,229 |   |
| United States                  |       | 7,101                                                                                                     |       | 3,719 |   | 1,963 |   | 1,013 |   | 477 |   |
| Other Countries 2              |       | 1,079                                                                                                     |       | 725 |   | 505 |   | 364 |   | 268 |   |
| **Total Probable**             | ** ** | **36,470**                                                                                                | ** ** | **13,741** | ** ** | **6,812** | ** ** | **3,856** | ** ** | **2,318** | ** ** |
|                           |       |                                                                                                      |       |   |   |   |   |   |   |   |   |
| **Proved Plus Probable**       |       |                                                                                                      |       |   |   |   |   |   |   |   |   |
| Canada                         |       | 44,963                                                                                                    |       | 15,627 |   | 6,939 |   | 3,473 |   | 1,783 |   |
| United Kingdom                 |       | 6,948                                                                                                     |       | 5,843 |   | 4,981 |   | 4,326 |   | 3,824 |   |
| United States                  |       | 7,372                                                                                                     |       | 3,982 |   | 2,211 |   | 1,244 |   | 692 |   |
| Other Countries 2              |       | 3,012                                                                                                     |       | 2,467 |   | 2,083 |   | 1,801 |   | 1,584 |   |
| **Total Proved Plus Probable** | ** ** | **62,295**                                                                                                | ** ** | **27,919** | ** ** | **16,214** | ** ** | **10,844** | ** ** | **7,883** | ** ** |

 

----

*(1)**        **We have estimated the after-tax net present value after including the existing tax positions at a corporate level of aggregation. As a result, our after tax economics are not estimated on a project stand-alone basis and therefore the valuation of individual properties on a stand-alone basis may differ significantly from our estimates. We also have not included costs related to corporate activities such as financing and corporate G&A associated with administration and planning activities.*

*(2)   Represents reserves in Yemen, Nigeria and Colombia.*

 

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TOTAL FUTURE NET REVENUE (UNDISCOUNTED) AS AT DECEMBER 31, 2012

*Forecast Prices and Costs*

 
| **(Cdn$ millions)**            | ** ** | **Revenue** | ** ** | **Royalties** | ** ** | **Operating****Costs** | ** ** | **Development****Costs** | ** ** | **Abandonment****and Reclamation Costs** | ** ** | **Future****Net Revenue Before Income Taxes** | ** ** | **Income****Taxes** | ** ** | **Future****Net Revenue After Income Taxes** | ** ** |
|-------------------------------------|------------|-------------|------------|---------------|------------|------------------------|------------|--------------------------|------------|------------------------------------------|------------|-----------------------------------------------|------------|---------------------|------------|----------------------------------------------|------------|
| **Proved   Reserves**               |       |        |       |          |       |                   |       |                     |       |                                     |       |                                          |       |                |       |                                         |       |
| Canada                              |       | 85,568      |       | 11,612        |       | 43,882                 |       | 6,455                    |       | 800                                      |       | 22,819                                        |       | 3,225               |       | 19,594                                       |       |
| United Kingdom                      |       | 19,455      |       | 18            |       | 5,486                  |       | 1,192                    |       | 1,644                                    |       | 11,115                                        |       | 7,089               |       | 4,026                                        |       |
| United States                       |       | 1,621       |       | 178           |       | 407                    |       | 214                      |       | 551                                      |       | 271                                           |       | —              |       | 271                                          |       |
| Other 1                             |       | 3,674       |       | 513           |       | 822                    |       | 243                      |       | 141                                      |       | 1,955                                         |       | 21                  |       | 1,934                                        |       |
| **Total**                           | ** ** | **110,318** | ** ** | **12,321**    | ** ** | **50,597**             | ** ** | **8,104**                | ** ** | **3,136**                                | ** ** | **36,160**                                    | ** ** | **10,335**          | ** ** | **25,825**                                   | ** ** |
| **Proved   Plus Probable Reserves** | ** ** | ** **  | ** ** | ** **    | ** ** | ** **             | ** ** | ** **               | ** ** | ** **                               | ** ** | ** **                                    | ** ** | ** **          | ** ** | ** **                                   | ** ** |
| Canada                              |       | 206,410     |       | 34,069        |       | 91,863                 |       | 22,017                   |       | 1,460                                    |       | 57,001                                        |       | 12,038              |       | 44,963                                       |       |
| United Kingdom                      |       | 29,506      |       | 31            |       | 7,465                  |       | 1,347                    |       | 1,809                                    |       | 18,854                                        |       | 11,906              |       | 6,948                                        |       |
| United States                       |       | 21,926      |       | 3,032         |       | 2,990                  |       | 3,709                    |       | 1,298                                    |       | 10,897                                        |       | 3,525               |       | 7,372                                        |       |
| Other 1                             |       | 7,207       |       | 1,222         |       | 1,134                  |       | 1,469                    |       | 251                                      |       | 3,131                                         |       | 119                 |       | 3,012                                        |       |
| **Total**                           | ** ** | **265,049** | ** ** | **38,354**    | ** ** | **103,452**            | ** ** | **28,542**               | ** ** | **4,818**                                | ** ** | **89,883**                                    | ** ** | **27,588**          | ** ** | **62,295**                                   | ** ** |

 

----

*(1)   Represents reserves in Yemen, Nigeria and Colombia.*

 

TOTAL FUTURE NET REVENUE BY PRODUCT GROUP AS AT DECEMBER 31, 2012

*Forecast Prices and Costs*

 
| ** **                        | ** ** | **Future Net Revenue   Before Income Taxes   (discounted at   10%/year)** | ** ** | **Unit Value   Before Income Taxes ****1****(discounted at   10%/year)** | ** ** |
|-----------------------------------|------------|----------------------------------------------------------------------------------------------------|------------|---------------------------------------------------------------------------------------------------|------------|
| ** **                        | ** ** | **(Cdn$ millions)**                                                                           | ** ** | **($/bbl)**                                                                                       | ** ** | **($/mcf)** | ** ** |
| **Proved Reserves**               |       |                                                                                               |       |                                                                                              |       |   |   |
| Light and Medium Oil 2            |       | 10,234                                                                                             |       | 44.60                                                                                             |       | — |   |
| Synthetic Oil                     |       | 4,597                                                                                              |       | 8.32                                                                                              |       | — |   |
| Natural Gas                       |       | 235                                                                                                |       | —                                                                                            |       | 1.69 |   |
| Shale Gas                         |       | 70                                                                                                 |       | —                                                                                            |       | 0.38 |   |
| CBM                               |       | 24                                                                                                 |       | —                                                                                            |       | 0.73 |   |
| **Proved Plus Probable Reserves** |       |                                                                                               |       |                                                                                              |       |   |   |
| Light and Medium Oil 2            |       | 18,072                                                                                             |       | 36.79                                                                                             |       | — |   |
| Synthetic Oil                     |       | 6,635                                                                                              |       | 8.35                                                                                              |       | — |   |
| Bitumen                           |       | 1,343                                                                                              |       | 13.54                                                                                             |       | — |   |
| Natural Gas                       |       | 531                                                                                                |       | —                                                                                            |       | 2.18 |   |
| Shale Gas                         |       | 107                                                                                                |       | —                                                                                            |       | 0.18 |   |
| CBM                               |       | 38                                                                                                 |       | —                                                                                            |       | 0.87 |   |

 

----

*(1)   Unit values are based upon net reserves volumes.*

*(2)   Including solution gas and other by-products.*

 

FORECAST PRICES AND COSTS USED IN ESTIMATES

 

NI 51-101 requires that the forecast prices and costs used in preparation of the reserves estimates represent a reasonable outlook of the future. The pricing and cost assumptions were determined with reference to benchmark and inflationary forecasts obtained from a number of qualified reserves evaluation firms and other information sources. Field pricing was estimated by applying typical adjustments such as quality and transportation costs to a benchmark price.

 

24

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PRICING AND INFLATION RATE ASSUMPTIONS AS AT DECEMBER 31, 2012

*Forecast Prices and Costs*

 
| ** ** | ** ** | **Light and Medium Oil** | ** ** | **Synthetic   Crude Oil** | ** ** | **Natural Gas** | ** ** | **Inflation   Rates** | ** ** | **Exchange   Rate**                 | ** ** |
|------------|------------|-----------------------------------------|------------|--------------------------------|------------|----------------------|------------|-----------------------|------------|-------------------------------------|------------|
| ** ** | ** ** | **WTI Cushing   Oklahoma**         | ** ** | **Brent**                      | ** ** | **Vasconia**         | ** ** | **MSW   Edmonton**    | ** ** | **Henry Hub   Gas Price** | ** ** | **National   Balancing Pt** | ** ** | **AECO Gas   Price** | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Year**   | ** ** | **(US$/bbl)**                           | ** ** | **(US$/bbl)**                  | ** ** | **(US$/bbl)**        | ** ** | **(Cdn$/bbl)**        | ** ** | **(US$/mmbtu)**                     | ** ** | **(£/therm)** | ** ** | **(Cdn$/GJ)** | ** ** | **%/Year** | ** ** | **(US$/Cdn$)** | ** ** |
| Historical |       |                                    |       |                           |       |                 |       |                  |       |                                |       |   |   |   |   |   |   |   |   |
| 2012       |       | 94.20                                   |       | 111.99                         |       | 106.29               |       | 86.98                 |       | 2.82                                |       | 0.59 |   | 2.28 |   | n/a |   | 1.00 |   |
| Forecast   |       |                                    |       |                           |       |                 |       |                  |       |                                |       |   |   |   |   |   |   |   |   |
| 2013       |       | 91                                      |       | 107                            |       | 103                  |       | 90                    |       | 4.00                                |       | 0.60 |   | 3.40 |   | 2.0 |   | 1.00 |   |
| 2014       |       | 92                                      |       | 104                            |       | 100                  |       | 91                    |       | 4.35                                |       | 0.65 |   | 3.75 |   | 2.0 |   | 1.00 |   |
| 2015       |       | 94                                      |       | 102                            |       | 98                   |       | 93                    |       | 4.75                                |       | 0.65 |   | 4.15 |   | 2.0 |   | 1.00 |   |
| 2016       |       | 99                                      |       | 104                            |       | 100                  |       | 99                    |       | 5.30                                |       | 0.70 |   | 4.60 |   | 2.0 |   | 1.00 |   |
| 2017       |       | 102                                     |       | 104                            |       | 100                  |       | 101                   |       | 5.75                                |       | 0.70 |   | 5.00 |   | 2.0 |   | 1.00 |   |
| Thereafter |       | 2% infl.                                |       | 2% infl.                       |       | 2% infl.             |       | 2% infl.              |       | 2% infl.                            |       | 2% infl. |   | 2% infl. |   | 2% infl. |   | 1.00 |   |

 

The forecast price and cost assumptions assume the continuance of current laws and regulations. There is no assurance that the forecast prices and costs assumptions will be attained and variances could be material. These assumptions may differ from internal assumptions that are used for project economics and planning purposes.

 

Weighted average realized prices for the year ended December 31, 2012 are summarized in the section entitled Production History on pages 29 to 30.

 

SUMMARY OF OIL AND GAS FUTURE DEVELOPMENT COSTS AS AT DECEMBER 31, 2012

 

*Forecast Prices and Costs*

 
| ** **             | ** ** | **Total Proved Reserves** | ** ** | **Total Proved Plus Probable Reserves** | ** ** |
|------------------------|------------|-------------------------------------|------------|-------------------------------------------------------------|------------|
| **Cdn$ millions** | ** ** | **Canada**                          | ** ** | **United   Kingdom**                                        | ** ** | **United   States** | ** ** | **Other** | ** ** | **Total** | ** ** | **Canada** | ** ** | **United   Kingdom** | ** ** | **United   States** | ** ** | **Other** | ** ** | **Total** | ** ** |
| 2013                   |       | 816                                 |       | 572                                                         |       | 7 |   | 232 | ** ** | **1,627** |   | 975 |   | 638 |   | 78 |   | 301 | ** ** | **1,992** | ** ** |
| 2014                   |       | 418                                 |       | 425                                                         |       | 44 |   | 5 | ** ** | **892** |   | 1,025 |   | 513 |   | 356 |   | 175 | ** ** | **2,069** | ** ** |
| 2015                   |       | 376                                 |       | 138                                                         |       | 1 |   | 3 | ** ** | **518** |   | 1,263 |   | 138 |   | 477 |   | 151 | ** ** | **2,029** | ** ** |
| 2016                   |       | 248                                 |       | 57                                                          |       | 157 |   | 3 | ** ** | **465** |   | 877 |   | 58 |   | 781 |   | 108 | ** ** | **1,824** | ** ** |
| 2017                   |       | 279                                 |       | —                                                      |       | 1 |   | — | ** ** | **280** |   | 619 |   | — |   | 672 |   | 48 | ** ** | **1,339** | ** ** |
| Thereafter             |       | 4,318                               |       | —                                                      |       | 4 |   | — | ** ** | **4,322** |   | 17,258 |   | — |   | 1,345 |   | 686 | ** ** | **19,289** | ** ** |
| Total (undiscounted)   | ** ** | **6,455**                           | ** ** | **1,192**                                                   | ** ** | **214** | ** ** | **243** | ** ** | **8,104** | ** ** | **22,017** | ** ** | **1,347** | ** ** | **3,709** | ** ** | **1,469** | ** ** | **28,542** | ** ** |

 

We believe internally generated cash flow from operations, supplemented if required by existing credit facilities, access to debt and equity markets, and future asset dispositions, are sufficient to fund future growth plans. There can be no guarantee that funds will be available in the future or that we will allocate funding to develop all of the reserves. Failure to develop those reserves would have a negative impact on future production and cash flow and could result in negative revisions to our reserves.

 

Interest and other costs of external funding requirements are not included in the future net revenue estimates. Since our investment decisions are based on expected returns on investment, interest or other funding costs do not directly affect the reserves estimates. We do not expect that interest or other costs of external funding would make the development of any property uneconomic.

 

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Other Oil and Gas Information

PRODUCING AND NON-PRODUCING WELLS

 

The following table sets forth the number and status of wells in which we had a working interest as at December 31, 2012.

 
| ** **                      | ** ** | **Oil**   | ** ** | **Gas** | ** ** | **Total** | ** ** |
|---------------------------------|------------|-----------|------------|---------|------------|-----------|------------|
| **(number of wells)** | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
| **Producing Wells**             |       |      |       |    |       |      |       |   |   |   |   |   |   |
| United Kingdom                  |       | 67        |       | 34      |       | —    |       | — |   | 67 |   | 34 |   |
| Canada — Alberta           |       | 19        |       | 8       |       | 1,265     |       | 1,059 |   | 1,284 |   | 1,067 |   |
| Canada — British Columbia  |       | —    |       | —  |       | 46        |       | 27 |   | 46 |   | 27 |   |
| Canada — Saskatchewan      |       | —    |       | —  |       | 1,280     |       | 1,218 |   | 1,280 |   | 1,218 |   |
| Canada — Oil Sands         |       | 103       |       | 66      |       | —    |       | — |   | 103 |   | 66 |   |
| US — Louisiana             |       | 34        |       | 31      |       | 23        |       | 20 |   | 57 |   | 51 |   |
| US — Texas                 |       | 23        |       | 3       |       | 7         |       | 1 |   | 30 |   | 4 |   |
| Yemen                           |       | 54        |       | 54      |       | —    |       | — |   | 54 |   | 54 |   |
| Colombia                        |       | 113       |       | 11      |       | —    |       | — |   | 113 |   | 11 |   |
| Nigeria                         |       | 10        |       | 2       |       | —    |       | — |   | 10 |   | 2 |   |
| **Total**                       | ** ** | **423**   | ** ** | **209** | ** ** | **2,621** | ** ** | **2,325** | ** ** | **3,044** | ** ** | **2,534** | ** ** |
| **Non-Producing Wells**         |       |      |       |    |       |      |       |   |   |   |   |   |   |
| United Kingdom                  |       | 12        |       | 6       |       | —    |       | — |   | 12 |   | 6 |   |
| Canada — Alberta           |       | 1         |       | 1       |       | 469       |       | 335 |   | 470 |   | 336 |   |
| Canada — British Columbia  |       | —    |       | —  |       | 22        |       | 13 |   | 22 |   | 13 |   |
| Canada — Saskatchewan      |       | —    |       | —  |       | 48        |       | 46 |   | 48 |   | 46 |   |
| Canada — Oil Sands         |       | 16        |       | 10      |       | 21        |       | 14 |   | 37 |   | 24 |   |
| US — Louisiana             |       | 68        |       | 62      |       | 54        |       | 48 |   | 122 |   | 110 |   |
| US — Texas                 |       | 20        |       | 1       |       | 27        |       | 2 |   | 47 |   | 3 |   |
| Yemen                           |       | 46        |       | 46      |       | 1         |       | 1 |   | 47 |   | 47 |   |
| Nigeria                         |       | 25        |       | 5       |       | —    |       | — |   | 25 |   | 5 |   |
| **Total**                       | ** ** | **188**   | ** ** | **132** | ** ** | **644**   | ** ** | **461** | ** ** | **832** | ** ** | **592** | ** ** |

 

PROPERTIES WITH NO ATTRIBUTED RESERVES

 

The following table sets out the unproved properties in which we have an interest for which we have no attributed reserves, as at December 31, 2012.

 
| **(thousands of acres)** | ** ** | **Gross** | ** ** | **Net**   | ** ** | **To Expire Within   One Year ****1** | ** ** |
|------------------------------------|------------|-----------|------------|-----------|------------|-----------------------------------------------------------|------------|
| United Kingdom                     |       | 1,563     |       | 960       |       | 272                                                       |       |
| Canada                             |       | 1,612     |       | 733       |       | 31                                                        |       |
| United States                      |       | 1,167     |       | 520       |       | 56                                                        |       |
| Yemen 2                            |       | 511       |       | 511       |       | —                                                    |       |
| Colombia 3                         |       | 1,617     |       | 1,531     |       | —                                                    |       |
| Nigeria 2, 4                       |       | 230       |       | 46        |       | —                                                    |       |
| Poland                             |       | 2,258     |       | 903       |       | 798                                                       |       |
| **Total**                          | ** ** | **8,958** | ** ** | **5,203** | ** ** | **1,157**                                                 | ** ** |

 

----

*(1)**        **Net acres of unproved properties for which we expect our rights to explore, develop and exploit to expire within one year.*

*(2)   The acreage is covered by production sharing contracts.*

*(3)   The acreage is covered by an association contract.*

*(4)   The acreage is covered by joint venture agreements.*

 

Our properties with no attributed reserves are geographically and technically diverse and require a variety of capital investment activities ranging from seismic acquisition to drilling and development in order to explore and potentially prove-up reserves. Some properties are in the early evaluation stages of exploration while others have discovered hydrocarbons. Our property portfolio is continuously reviewed on the basis of prospectivity, risk, and economics to prioritize the opportunities we choose to invest in and develop. As a result, some properties are prioritized for capital investment, while others are held as inactive pending the results of future reviews, or sold, traded, relinquished, or allowed to expire.

 

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The practice of requiring companies to pledge to carry out work commitments such as seismic acquisition, geophysical studies or exploration drilling in exchange for property exploration and development rights is common particularly in undeveloped or unexplored areas. We estimate work commitments of about $180 million to retain the related properties located in offshore UK, offshore USA and Colombia over the next three years. We continue to assess and, if warranted, explore these lands prior to their expiry. There are no significant factors or uncertainties associated with the economic viability and development of these properties other than those discussed generally in the “Risk Factors” section on pages 37 to 46 of this AIF.

 

ADDITIONAL INFORMATION CONCERNING ABANDONMENT AND RECLAMATION COSTS

 

We are required to remove or remedy the effect of our activities at our present and future operating sites by dismantling and removing production facilities and remediating the related damage. In estimating our future abandonment and reclamation costs (A&R costs), we make estimates and judgments on activities that will occur many years from now. In estimating A&R costs, we consider many factors including existing contracts, regulations, A&R techniques, industry conditions and past experience. As such, factors are constantly changing and our estimates are uncertain.

 

As of December 31, 2012, our expected undiscounted A&R costs are $3,136 million ($1,731 million, discounted at 10%) for proved reserves, including $232 million of costs to be incurred within the next three financial years. These costs relate to approximately 3,126 existing net wells and additional wells planned to be drilled in the future to access proved reserves.

 

The total amount of A&R costs in our proved reserves estimate is higher than the asset retirement obligation on our balance sheet primarily due to retirement costs related to planned future capital expenditures. These future obligations are relevant for determining the economic viability of our reserves but do not constitute an existing liability in our financial statements as the wells or facilities potentially giving rise to these costs have not yet been constructed.

 

TAX HORIZON

 

We are currently cash taxable in the UK, Yemen and Colombia. In Canada, the US and Nigeria, our estimated tax horizon is beyond five years.

 

COSTS INCURRED

 

The following table summarizes the costs incurred in our oil and gas activities for the year ended December 31, 2012.

 
| ** **                              | ** ** | ** **                        | ** ** | **Oil and Gas** | ** ** |
|-----------------------------------------|------------|-----------------------------------|------------|---------------------------|------------|
| **(Cdn$ millions)**                | ** ** | **Total Oil   and Gas** | ** ** | **Canada**                | ** ** | **United   Kingdom** | ** ** | **United   States** | ** ** | **Other ****1** | ** ** |
| **Year Ended December 31,   2012** |       |                              |       |                      |       |   |   |   |   |   |   |
| Property Acquisition Costs              |       |                              |       |                      |       |   |   |   |   |   |   |
| Proved                                  |       | —                            |       | —                    |       | — |   | — |   | — |   |
| Unproved                                |       | 12                                |       | —                    |       | — |   | 12 |   | — |   |
| Exploration Costs                       |       | 752                               |       | 153                       |       | 202 |   | 255 |   | 142 |   |
| Development Costs                       |       | 2,732                             |       | 1,229                     |       | 1,003 |   | 156 |   | 344 |   |
| **Total Costs Incurred****2**           | ** ** | **3,496**                         | ** ** | **1,382**                 | ** ** | **1,205** | ** ** | **423** | ** ** | **486** | ** ** |

 

----

*(1)   Represents costs incurred in Yemen, Nigeria, Poland and Colombia, and recovery of previously expensed exploration costs in Norway.*

*(2)**        **Total costs incurred include asset retirement costs of $424 million and excludes costs related to energy marketing, corporate and other of $52 million.*

 

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EXPLORATION AND DEVELOPMENT ACTIVITIES

 

The following table sets forth the gross and net exploratory and development wells that were completed during 2012.

 
| ** **     | ** ** | **Exploratory Wells** | ** ** |
|----------------|------------|----------------------------|------------|
| ** **     | ** ** | **Oil Wells**         | ** ** | **Gas Wells** | ** ** | **Service Wells ****1** | ** ** | **Stratigraphic   Wells** | ** ** | **Dry Holes** | ** ** | **Total** | ** ** |
| ** **     | ** ** | **Gross**                  | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
| United Kingdom |       | —                     |       | — |   | — |   | — |   | — |   | — |   | — |   | — |   | 4.0 |   | 2.3 |   | 4.0 |   | 2.3 |   |
| Canada         |       | —                     |       | — |   | 1.0 |   | 1.0 |   | — |   | — |   | — |   | — |   | — |   | — |   | 1.0 |   | 1.0 |   |
| United States  |       | 2.0                        |       | 0.4 |   | — |   | — |   | — |   | — |   | — |   | — |   | 1.0 |   | 0.5 |   | 3.0 |   | 0.9 |   |
| Other 2        |       | 2.0                        |       | 0.3 |   | 7.0 |   | 4.0 |   | — |   | — |   | — |   | — |   | — |   | — |   | 9.0 |   | 4.3 |   |
| **Total**      | ** ** | **4.0**                    | ** ** | **0.7** | ** ** | **8.0** | ** ** | **5.0** |   | — |   | — |   | — |   | — | ** ** | **5.0** | ** ** | **2.9** | ** ** | **17.0** | ** ** | **8.6** | ** ** |

 
| ** **     | ** ** | **Development Wells** | ** ** |
|----------------|------------|----------------------------|------------|
| ** **     | ** ** | **Oil Wells**         | ** ** | **Gas Wells** | ** ** | **Service Wells ****1** | ** ** | **Stratigraphic   Wells** | ** ** | **Dry Holes** | ** ** | **Total** | ** ** |
| ** **     | ** ** | **Gross**                  | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
| United Kingdom |       | 2.0                        |       | 0.9 |   | — |   | — |   | 2.0 |   | 1.7 |   | — |   | — |   | 1.0 |   | 0.4 |   | 5.0 |   | 3.0 |   |
| Canada         |       | 11.0                       |       | 7.1 |   | 18.0 |   | 10.8 |   | 48.0 |   | 29.6 |   | 199.0 |   | 117.3 |   | — |   | — |   | 276.0 |   | 164.9 |   |
| United States  |       | —                     |       | — |   | — |   | — |   | — |   | — |   | — |   | — |   | — |   | — |   | — |   | — |   |
| Other 2        |       | 4.0                        |       | 0.7 |   | — |   | — |   | 6.0 |   | 1.2 |   | — |   | — |   | — |   | — |   | 10.0 |   | 1.8 |   |
| **Total**      | ** ** | **17.0**                   | ** ** | **8.7** | ** ** | **18.0** | ** ** | **10.8** | ** ** | **56.0** | ** ** | **32.5** | ** ** | **199.0** | ** ** | **117.3** | ** ** | **1.0** | ** ** | **0.4** | ** ** | **291.0** | ** ** | **169.7** | ** ** |

** **
| ** **     | ** ** | **Total Wells** | ** ** |
|----------------|------------|----------------------|------------|
| ** **     | ** ** | **Oil Wells**   | ** ** | **Gas Wells** | ** ** | **Service Wells ****1** | ** ** | **Stratigraphic   Wells** | ** ** | **Dry Holes** | ** ** | **Total** | ** ** |
| ** **     | ** ** | **Gross**            | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
| United Kingdom |       | 2.0                  |       | 0.9 |   | — |   | — |   | 2.0 |   | 1.7 |   | — |   | — |   | 5.0 |   | 2.8 |   | 9.0 |   | 5.3 |   |
| Canada         |       | 11.0                 |       | 7.2 |   | 19.0 |   | 11.8 |   | 48.0 |   | 29.6 |   | 199.0 |   | 117.3 |   | — |   | — |   | 277.0 |   | 165.9 |   |
| United States  |       | 2.0                  |       | 0.4 |   | — |   | — |   | — |   | — |   | — |   | — |   | 1.0 |   | 0.5 |   | 3.0 |   | 0.9 |   |
| Other 2        |       | 6.0                  |       | 1.0 |   | 7.0 |   | 4.0 |   | 6.0 |   | 1.2 |   | — |   | — |   | — |   | — |   | 19.0 |   | 6.2 |   |
| **Total**      | ** ** | **21.0**             | ** ** | **9.4** | ** ** | **26.0** | ** ** | **15.8** | ** ** | **56.0** | ** ** | **32.5** | ** ** | **199.0** | ** ** | **117.3** | ** ** | **6.0** | ** ** | **3.3** | ** ** | **308.0** | ** ** | **178.3** | ** ** |

 

----

*(1)   Service wells include injector wells, waste water wells and other wells not intended to produce oil and gas.*

*(2)   Represents activity in Yemen, Nigeria, Norway and Colombia.*

 

PRODUCTION ESTIMATES

 

The following table sets out our estimated production for 2013 from our estimates of gross proved reserves and gross probable reserves.

 
| ** **                  | ** ** | **Total**   | ** ** | **Synthetic   Oil** | ** ** | **Light and Medium Oil** | ** ** | **Natural Gas** | ** ** | **CBM**              | ** ** | **Shale   Gas** | ** ** |
|-----------------------------|------------|-------------|------------|---------------------|------------|-----------------------------------------|------------|----------------------|------------|----------------------|------------|-----------------|------------|
| ** **                  | ** ** | **(mmboe)** | ** ** | **(mmbbls)**        | ** ** | **(mmbbls)**                            | ** ** | **(bcf)**            | ** ** | **(bcf)**            | ** ** | **(bcf)**       | ** ** |
| **(Before Royalties)** | ** ** | **Company** | ** ** | **Canada**          | ** ** | **United   Kingdom**                    | ** ** | **United   States**  | ** ** | **Other ****1** | ** ** | **Total**       | ** ** | **Canada** | ** ** | **United   Kingdom** | ** ** | **United   States** | ** ** | **Total** | ** ** | **Canada** | ** ** | **Canada** | ** ** |
| Total Proved                |       | 69          |       | 14                  |       | 31                                      |       | 3                    |       | 8                    |       | 42              |       | 12 |   | 20 |   | 14 |   | 46 |   | 9 |   | 20 |   |
| Total Probable              |       | 11          |       | 1                   |       | 7                                       |       | —               |       | 1                    |       | 8               |       | — |   | 2 |   | 4 |   | 6 |   | — |   | 5 |   |
| Total Proved Plus Probable  |       | 80          |       | 15                  |       | 38                                      |       | 3                    |       | 9                    |       | 50              |       | 12 |   | 22 |   | 18 |   | 52 |   | 9 |   | 25 |   |

 

----

*(1)   Represents production in Yemen and Colombia.*

 

Our Buzzard field in the UK is the only field that accounts for more than 20% of our estimated 2013 production volumes. Our reserves analysis estimates the field will produce 30 mmboe of primarily light and medium oil on a proved plus probable basis for the year ended December 31, 2013.

 

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PRODUCTION HISTORY

 

The following table summarizes certain information in respect of our production, prices received, royalties paid, production costs and resulting netback for the two years ended December 31, 2012 and 2011.

 
| ** **                                                                  | ** ** | **Quarters — 2012** | ** ** | **Total   Year** | ** ** |
|-----------------------------------------------------------------------------|------------|------------------------------------|------------|------------------|------------|
| **(all dollar amounts in Cdn$ unless noted)** | ** ** | **1****st**                        | ** ** | **2****nd**      | ** ** | **3****rd** | ** ** | **4****th** | ** ** | **2012** | ** ** |
| **PRICES:**                                                                 |       |                               |       |             |       |   |   |   |   |   |   |
| Brent Crude   Oil (US$/bbl)                                                 |       | 119.13                             |       | 108.66           |       | 110.13 |   | 110.05 |   | 111.99 |   |
| WTI Crude Oil   (US$/bbl)                                                   |       | 102.93                             |       | 93.49            |       | 92.22 |   | 88.18 |   | 94.20 |   |
| Nexen Average — Oil (Cdn$/bbl)                                         |       | 111.62                             |       | 102.21           |       | 103.43 |   | 101.48 |   | 104.64 |   |
| NYMEX Natural Gas (US$/mmbtu)                                               |       | 2.51                               |       | 2.35             |       | 2.90 |   | 3.54 |   | 2.82 |   |
| AECO Natural Gas (Cdn$/mcf)                                                 |       | 2.39                               |       | 1.74             |       | 2.08 |   | 2.90 |   | 2.28 |   |
| Nexen Average — Gas (Cdn$/mcf)                                         |       | 3.13                               |       | 2.58             |       | 3.19 |   | 4.40 |   | 3.38 |   |
| **NETBACKS****1****:**                                                      |       |                               |       |             |       |   |   |   |   |   |   |
| **United Kingdom**                                                          |       |                               |       |             |       |   |   |   |   |   |   |
| Crude Oil:                                                                  |       |                               |       |             |       |   |   |   |   |   |   |
| Sales (mbbls/d)                                                             |       | 106.9                              |       | 105.3            |       | 82.1 |   | 83.8 |   | 94.4 |   |
| Price Received ($/bbl)                                                      |       | 118.12                             |       | 105.82           |       | 108.39 |   | 106.43 |   | 109.98 |   |
| Natural Gas:                                                                |       |                               |       |             |       |   |   |   |   |   |   |
| Sales (mmcf/d)                                                              |       | 33                                 |       | 31               |       | 31 |   | 57 |   | 38 |   |
| Price Received ($/mcf)                                                      |       | 7.83                               |       | 6.64             |       | 7.43 |   | 8.76 |   | 7.86 |   |
| Total Sales Volume (mboe/d)                                                 |       | 112.3                              |       | 110.4            |       | 87.3 |   | 93.3 |   | 100.8 |   |
|                                                                        |       |                               |       |             |       |   |   |   |   |   |   |
| Price Received ($/boe)                                                      |       | 114.65                             |       | 102.74           |       | 104.57 |   | 100.98 |   | 106.03 |   |
| Royalties & Other                                                  |       | 0.51                               |       | 0.55             |       | 0.71 |   | 0.69 |   | 0.61 |   |
| Operating Costs                                                             |       | 10.14                              |       | 10.90            |       | 13.78 |   | 13.38 |   | 11.89 |   |
| In-country Taxes                                                            |       | 45.41                              |       | 38.84            |       | 32.04 |   | 34.40 |   | 38.15 |   |
| Netback                                                                     |       | 58.59                              |       | 52.45            |       | 58.04 |   | 52.51 |   | 55.38 |   |
| **Oil Sands — In Situ****2**                                           |       |                               |       |             |       |   |   |   |   |   |   |
| Sales (mbbls/d)                                                             |       | 17.8                               |       | 16.5             |       | 11.2 |   | 16.2 |   | 15.4 |   |
|                                                                        |       |                               |       |             |       |   |   |   |   |   |   |
| Price Received ($/bbl)                                                      |       | 94.45                              |       | 86.58            |       | 80.13 |   | 82.47 |   | 86.57 |   |
| Royalties & Other                                                  |       | 4.79                               |       | 6.10             |       | 3.22 |   | 3.96 |   | 4.63 |   |
| Operating Costs                                                             |       | 68.89                              |       | 69.95            |       | 77.36 | 3 | 73.24 |   | 71.87 |   |
| Netback                                                                     |       | 20.77                              |       | 10.53            |       | (0.45 | ) | 5.27 |   | 10.07 |   |
| **Oil Sands — Syncrude**                                               |       |                               |       |             |       |   |   |   |   |   |   |
| Sales (mbbls/d)                                                             |       | 21.3                               |       | 17.2             |       | 22.7 |   | 21.6 |   | 20.7 |   |
|                                                                        |       |                               |       |             |       |   |   |   |   |   |   |
| Price Received ($/bbl)                                                      |       | 92.54                              |       | 89.85            |       | 91.48 |   | 90.78 |   | 91.23 |   |
| Royalties & Other                                                  |       | 11.25                              |       | (3.03            | )          | 1.84 |   | 2.54 |   | 3.42 |   |
| Operating Costs                                                             |       | 31.36                              |       | 44.96            |       | 35.93 |   | 29.20 |   | 34.86 |   |
| Netback                                                                     |       | 49.93                              |       | 47.92            |       | 53.71 |   | 59.04 |   | 52.95 |   |
| **United States**                                                           |       |                               |       |             |       |   |   |   |   |   |   |
| Crude Oil:                                                                  |       |                               |       |             |       |   |   |   |   |   |   |
| Sales (mbbls/d)                                                             |       | 8.0                                |       | 7.3              |       | 7.4 |   | 8.8 |   | 7.9 |   |
| Price Received ($/bbl)                                                      |       | 108.40                             |       | 102.19           |       | 99.04 |   | 98.95 |   | 102.10 |   |
| Natural Gas:                                                                |       |                               |       |             |       |   |   |   |   |   |   |
| Sales (mmcf/d)                                                              |       | 50                                 |       | 41               |       | 43 |   | 52 |   | 46 |   |
| Price Received ($/mcf)                                                      |       | 2.67                               |       | 2.19             |       | 2.89 |   | 3.35 |   | 2.81 |   |
| Total Sales Volume (mboe/d)                                                 |       | 16.3                               |       | 14.1             |       | 14.5 |   | 17.5 |   | 15.6 |   |
|                                                                        |       |                               |       |             |       |   |   |   |   |   |   |
| Price Received ($/boe)                                                      |       | 61.33                              |       | 58.84            |       | 58.91 |   | 59.79 |   | 59.77 |   |
| Royalties & Other                                                  |       | 6.02                               |       | 6.12             |       | 6.50 |   | 7.15 |   | 6.47 |   |
| Operating Costs                                                             |       | 17.29                              |       | 17.87            |       | 19.37 |   | 15.92 |   | 17.52 |   |
| Netback                                                                     |       | 38.02                              |       | 34.85            |       | 33.04 |   | 36.72 |   | 35.78 |   |

 

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*(1)**        **Netbacks are defined**average sales price less royalties, other operating costs and in-country taxes.*

*(2)**        **Excludes activities related to third-party bitumen purchased, processed and sold.*

*(3)**        **Excludes costs related to turnaround activities.*

 

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* *
| ** **                                                                  | ** ** | **Quarters — 2012** | ** ** | **Total   Year** | ** ** |
|-----------------------------------------------------------------------------|------------|------------------------------------|------------|------------------|------------|
| **(all dollar amounts in Cdn$ unless noted)** | ** ** | **1****st**                        | ** ** | **2****nd**      | ** ** | **3****rd** | ** ** | **4****th** | ** ** | **2012** | ** ** |
| **Canada — Natural Gas****2**                                          |       |                               |       |             |       |   |   |   |   |   |   |
| Sales (mmcf/d)                                                              |       | 131                                |       | 120              |       | 105 |   | 127 |   | 121 |   |
|                                                                        |       |                               |       |             |       |   |   |   |   |   |   |
| Price Received ($/mcf)                                                      |       | 2.12                               |       | 1.67             |       | 2.05 |   | 2.89 |   | 2.20 |   |
| Royalties & Other                                                  |       | 0.08                               |       | (0.05            | )          | 0.06 |   | 0.11 |   | 0.05 |   |
| Operating Costs                                                             |       | 1.58                               |       | 1.62             |       | 1.72 |   | 1.57 |   | 1.62 |   |
| Netback                                                                     |       | 0.46                               |       | 0.10             |       | 0.27 |   | 1.21 |   | 0.53 |   |
| **Other Countries****3**                                                    |       |                               |       |             |       |   |   |   |   |   |   |
| Sales (mbbls/d)                                                             |       | 5.4                                |       | 27.0             |       | 27.4 |   | 27.0 |   | 21.7 |   |
|                                                                        |       |                               |       |             |       |   |   |   |   |   |   |
| Price Received ($/bbl)                                                      |       | 119.61                             |       | 105.59           |       | 109.24 |   | 107.02 |   | 108.06 |   |
| Royalties & Other                                                  |       | 48.76                              |       | 17.27            |       | 18.44 |   | 17.60 |   | 19.69 |   |
| Operating Costs                                                             |       | 13.02                              |       | 17.70            |       | 14.42 |   | 18.14 |   | 16.40 |   |
| In-country Taxes                                                            |       | 9.31                               |       | 2.50             |       | 1.94 |   | 1.16 |   | 2.33 |   |
| Netback                                                                     |       | 48.52                              |       | 68.12            |       | 74.44 |   | 70.12 |   | 69.64 |   |
| **Company-Wide**                                                            |       |                               |       |             |       |   |   |   |   |   |   |
| Oil and Gas Sales (mboe/d)                                                  |       | 195.0                              |       | 205.2            |       | 180.6 |   | 196.8 |   | 194.4 |   |
|                                                                        |       |                               |       |             |       |   |   |   |   |   |   |
| Price Received ($/boe)                                                      |       | 94.67                              |       | 88.65            |       | 89.52 |   | 86.5 |   | 89.81 |   |
| Royalties & Other                                                  |       | 3.87                               |       | 3.19             |       | 4.12 |   | 4.05 |   | 3.80 |   |
| Operating Costs                                                             |       | 18.56                              |       | 19.74            |       | 20.71 | 4 | 20.49 |   | 19.86 |   |
| In-country Taxes                                                            |       | 26.43                              |       | 21.21            |       | 15.79 |   | 16.46 |   | 20.04 |   |
| Netback                                                                     |       | 45.81                              |       | 44.51            |       | 48.90 |   | 45.50 |   | 46.11 |   |

 

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*(1)     Netbacks are defined as average sales price less royalties and other, operating costs, and in-country taxes.*

*(2)     Includes Canadian conventional, CBM and shale gas activities. Shale gas was included beginning in the fourth quarter of 2011 when it became commercial.*

*(3)     Includes Yemen, Colombia and Nigeria.*

*(4)     Excludes costs related to turnaround activities.*

 

INDEPENDENT RESERVES EVALUATIONS

 

The following provides an overview of the nature and scope of the independent evaluations and audits that we have had performed on our reserves estimates. An independent evaluation is a process whereby we request a third-party engineering firm to prepare an estimate of our proved and probable reserves by assessing and interpreting all available data on a reservoir. An independent audit is a process whereby we request a third-party engineering firm to prepare an estimate of our reserves by reviewing our estimates, supporting working papers and other data as they feel is necessary. The primary difference is that an evaluator uses the reservoir data to prepare their own estimate, whereas an auditor reviews our work and estimate in preparing their estimate.

 

We have at least 80% of our NI 51-101 reserves estimates either evaluated or audited annually by independent qualified reserves consultants using applicable NI 51-101 requirements. Given that reserves estimates are based on numerous assumptions, interpretations and judgments, differences frequently arise between the estimates prepared by different qualified estimators. When the initial estimate of proved reserves on the portfolio of properties differs by greater than 10%, we work with the independent reserves consultant to reconcile the difference to within 10%. Estimates pertaining to individual properties within the portfolio may differ by more than 10%, either positively or negatively. We do not attempt to resolve each property to within 10% as it would be time and cost prohibitive given the number of wells in which we have an interest. We follow a similar process in connection with our probable reserves estimates whereby we reconcile any differences on a proved plus probable basis to be within 10%, and as such, probable reserves for individual properties within the portfolio may differ significantly.

 

In each case, we request their estimates to be prepared using standard geological and engineering methods generally accepted by the petroleum industry and in accordance with NI 51-101 requirements. Generally recognized methods for estimating reserves include volumetric calculations, material balance techniques, production decline curves and pressure transient analysis, analogy with similar reservoirs and reservoir simulation. The method or combination of methods used is based on their professional judgment and experience. In preparing their estimates, they obtain information from us with respect to property interests, production from such properties, current costs of operations, expected future development and abandonment costs, current prices for production, agreements relating to current and future operations and sale of production, and various other information and data. 

 

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They may rely on the information without independent verification. However, if in the course of their evaluation they question the validity or sufficiency of any information, we request that they not rely on such information until they satisfactorily resolve their questions or independently verify such information.

 

We do not place any limitations on the work to be performed. Upon completion of their work, the independent reserves consultant issues an opinion as to whether our estimates of the proved and probable reserves for that portfolio of properties is, in aggregate, reasonable relative to the criteria set forth in NI 51-101.

 

For our reserves estimates prepared in accordance with NI 51-101 requirements, we engaged three independent reserves consultants to evaluate or audit our properties:

 

·                  We engaged DeGolyer and MacNaughton (D&M) to evaluate 100% of our proved and proved plus probable reserves in the UK North Sea, Nigeria, and our Canadian shale gas properties. D&M provided an opinion that the proved and proved plus probable reserves for the reviewed properties are reasonable because, in aggregate, they are within 10% of their estimates.

·                  We engaged McDaniel & Associates Consultants Ltd. (McDaniel) to evaluate approximately 100% of our proved and our proved plus probable reserves for our in situ oil sands properties. McDaniel provided an opinion that the proved and proved plus probable reserves for the reviewed properties are reasonable because, in aggregate, they are within 10% of their estimates.

·                  We also engaged McDaniel to audit 100% of our proved and proved plus probable reserves for our Syncrude interest. McDaniel provided an opinion that the proved and proved plus probable reserves estimates for our Syncrude property are reasonable because they expect it would be within 10% of their own estimate were they to perform their own detailed evaluation of the property for Nexen.

·                  We engaged Ryder Scott Company (Ryder Scott) to evaluate 93% of our proved and 99% of our proved plus probable US Gulf of Mexico properties. Ryder Scott provided an opinion that the proved and proved plus probable reserves for the reviewed properties are reasonable because, in aggregate, they are within 10% of their estimates.

 

In aggregate our independent reserves consultants evaluated or audited 97% of our proved and 98% of our proved plus probable reserves.

 

For each opinion, an opinion letter has been prepared, which summarizes the work undertaken, the assumptions, data, methods and procedures they used and concludes with their opinion. These reports have been filed on SEDAR at www.sedar.com.

 

DEFINITIONS

 

In the foregoing reserves discussion the following definitions and notes are applicable:

 

1. “Gross” means:

 

a)        in relation to our interest in production or reserves, our “company gross reserves”, which are our working interest (operating and non-operating) share before deduction of royalties and without including any royalty interest to us;

b)         in relation to wells, the total number of wells in which we have an interest; and

c)         in relation to properties, the total area of properties in which we have an interest.

 

2. “Net” means:

 

a)        in relation to our interest in production or reserves, our working interest (operating and non-operating) share after deduction of royalties obligations, plus our royalty interests in production or reserves;

b)        in relation to our interest in wells, the number of wells obtained by aggregating our working interest in each of our gross wells; and

c)         in relation to our interest in a property, the total area in which we have an interest multiplied by the working interest we owned. The crude oil, natural gas liquids and natural gas reserves estimates presented in this Statement are based on the definitions and guidelines contained in the COGE Handbook. A summary of those definitions are set forth below:

 

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3. Reserves Categories

 

Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, as of a given date, based on:

 

a)        analysis of drilling, geological, geophysical and engineering data;

b)         the use of established technology; and

c)         specified economic conditions, which are generally accepted as being reasonable.

 

Reserves are classified according to the degree of certainty associated with the estimates.

 

a)        Proved reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.

b)        Probable reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.

 

Other criteria that must also be met for the classification of reserves are provided in the Canadian Oil and Gas Evaluation (COGE) Handbook.

 

4. Development and Production Status

 

Each of the reserves categories (proved and probable) may be divided into developed and undeveloped categories.

 

a)        Developed reserves are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (for example, when compared to the cost of drilling a well) to put the reserves on production. The developed category may be subdivided into producing and non-producing.

 

Developed producing reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty.

 

Developed non-producing reserves are those reserves that either have not been on production, or have previously been on production, but are shut-in and the date of resumption of production is unknown.

 

b)        Undeveloped reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (for example, when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves category (proved, probable) to which they are assigned.

 

In multi-well pools, it may be appropriate to allocate total pool reserves between the developed and undeveloped categories or to subdivide the developed reserves for the pool between developed producing and developed non-producing. This allocation should be based on the estimator’s assessment as to the reserves that will be recovered from specific wells, facilities and completion intervals in the pool and their respective development and production status.

 

LEVELS OF CERTAINTY FOR REPORTED RESERVES

 

The qualitative certainty levels referred to in the definitions above are applicable to individual reserve entities (which refers to the lowest level at which reserves calculations are performed) and to reported reserves (which refers to the highest level sum of individual entity estimates for which reserves estimates are presented). Reported reserves should target the following levels of certainty under a specific set of economic conditions:

 

a)        at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimated proved reserves; and

b)        at least a 50 percent probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus probable reserves.

 

A quantitative measure of the certainty levels pertaining to estimates prepared for the various reserves categories is desirable to provide a clearer understanding of the associated risks and uncertainties. However, the majority of reserves estimates are prepared using deterministic methods that do not provide a mathematically derived quantitative measure of probability. In principle, there should be no difference between estimates prepared using probabilistic or deterministic methods.

 

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Additional clarification of certainty levels associated with reserves estimates and the effect of aggregation is provided in the COGE Handbook.

 

Special Note to Investors

 

Investors should note the following fundamental differences between reserves estimates and related disclosures prepared in accordance with SEC requirements and those prepared in accordance with NI 51-101:

 

·                  SEC reserves estimates are based upon different reserves definitions and are prepared in accordance with generally recognized industry practices in the US, whereas NI 51-101 reserves are based on definitions and standards promulgated by the COGE Handbook and generally recognized industry practices in Canada;

·                  SEC reserves definitions differ from NI 51-101 in areas such as the use of reliable technology, areal extent around a drilled location, quantities below the lowest known oil and quantities across an undrilled fault block;

·                  the SEC mandates disclosure of proved reserves and the Standardized Measure of Discounted Future Net Cash Flows and Changes Therein calculated using the year’s monthly average prices and costs held constant, whereas NI 51-101 requires disclosure of reserves and related future net revenues using forecast prices and costs;

·                  the SEC mandates disclosure of reserves by geographic area, whereas NI 51-101 requires disclosure of reserves by additional categories and product types;

·                  the SEC does not require the disclosure of future net revenue of proved and proved plus probable reserves using forecast pricing at various discount rates;

·                  the SEC requires future development costs to be estimated using existing conditions held constant, whereas NI 51-101 requires estimation using forecast conditions;

·                  the SEC does not require the validation of reserves estimates by independent qualified reserves evaluators or auditors, whereas, without an exemption, NI 51-101 requires issuers to engage such evaluators or auditors to evaluate, audit or review their reserves and related future net revenue; and

·                  the SEC does not allow proved and probable reserves estimates to be aggregated, whereas NI 51-101 requires issuers to aggregate the estimates.

 

The foregoing is a general description of the principal differences only. The differences between SEC requirements and NI 51-101 may be material for certain properties.

 

**ENVIRONMENTAL AND REGULATORY MATTERS**

 

Government and Environmental Regulations

 

Our operations are subject to various levels of government controls and regulations in the countries where we operate. These laws and regulations include matters relating to exploration, production practices, occupational health and safety, environmental protection, midstream and marketing activities. These laws and regulations may increase the cost of doing business and, accordingly, affect profitability. We participate in many industry and professional associations through which our interests in new regulations and legislation are represented, and we monitor the progress of proposed regulatory and legislative amendments.

 

Laws and regulations change frequently and sometimes unpredictably. Regulatory complexity and stringency has increased over the past several years, as has the cost of compliance. Based on this trend, it is reasonably likely that the costs of compliance will continue to increase. We consider compliance with these regulations a necessary and manageable part of our business. We have been able to plan for and manage the increasing regulatory requirements without materially changing our business strategies or incurring significant or unreimbursed expenditures, though we are unable to predict the impact of future changes in compliance requirements on costs. We do not expect that the effect of these laws and regulations on our operations will be materially different than they would for any other oil and gas company of similar size and financial strength. We believe our operations comply, in all material respects, with applicable laws and regulations in the various jurisdictions where we operate.

 

The types of laws and regulations that affect our business most significantly fall into two categories: i) Operational and ii) Health, Safety and Environmental.

 

OPERATIONAL REGULATIONS

 

Our oil and gas exploration and production activities are subject to various international, federal, state, provincial, territorial and local laws and regulations. Those laws and regulations affect a number of operational activities, including:

 

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·                  land access;

·                  acquisition of seismic data;

·                  location of wells;

·                  drilling, completion and well servicing;

·                  transportation, storage and disposal of waste products arising from oil and gas operations;

·                  land restoration and well abandonment;

·                  pricing policies;

·                  royalties;

·                  various taxes and levies including income tax; and

·                  foreign trade and investment.

 

The implications of these laws and regulations to our business include direct costs in the form of tariffs, fees, taxes, rent and royalties and other direct charges measured by the type, region or intensity of activity. Indirect costs also arise from restricted access to certain areas of operation; restrictions on the type, frequency or conduct of permitted oilfield operations; limitations on production rates from certain oil and gas wells; forced pooling of oil and gas interests with third parties; changes in drill spacing units or well densities; infrastructure development; satisfaction of local content obligations for international projects; carried government participation in certain projects; and community consultation.

 

*US Gulf of Mexico*

 

Since the tragic explosion and sinking of the Deepwater Horizon drilling rig in 2010, the US Government has reviewed its enforcement of environmental and regulatory matters in the US Gulf of Mexico. Oversight of these matters, which had previously been through the Minerals Management Service of the US Department of the Interior, has now been split between to newly created agencies, the Bureau of Ocean Energy Management, Regulation and Enforcement and the Bureau of Safety and Environmental Enforcement. These new agencies have oversight of new regulations governing oil and gas drilling activities in the Gulf of Mexico. These regulations contain, among other things, increased requirements for wellbore integrity, blow-out prevention, well control equipment, personnel training, implementation of certain safety and environmental requirements governing how operations and work are performed offshore, rig safety, and spill response. We believe that the rigorous health, safety and environmental processes that we apply to our offshore operating activities enable us to satisfy these new regulatory obligations. Despite our ability to meet the new regulations, the new processes implemented to administer these regulations have delayed the permitting process, which could add to costs and longer cycle times for our Gulf of Mexico exploration and development activities.

 

HEALTH, SAFETY AND ENVIRONMENTAL REGULATIONS

 

Our oil and gas operations are subject to various international, federal, state, provincial, territorial and local laws and regulations designed to regulate the impact of human activity on the natural environment and the safety of our worksites. These laws and regulations relate to:

 

·                  the types and quantities of substances and waste materials that can be released into the environment;

·                  use or removal of natural resources (such as water and timber) in exploration and production activities;

·                  abandonment, reclamation and remediation of worksites (including sites of former operations);

·                  development of emergency and community response plans; and

·                  implementation of safe work practices for employees and contractors.

 

We are committed to operating within these laws and regulations and to conducting business in a safe and environmentally responsible manner.

 

Environmental regulations continue to evolve and are becoming more complex. To reduce our risk of noncompliance with these laws, we apply internal tools and processes, and industry standards and best practices that meet or exceed our legal obligations. Where regulations do not exist, or where we consider them to be insufficiently developed, we observe Canadian standards or internationally accepted industry environmental management practices.

 

Our Health, Safety, Environment and Social Responsibility group (HSE&SR) helps ensure our worldwide operations are conducted in a safe, ethical and socially responsible manner. Our HSE&SR practices are reported to our board of directors throughout the year. Nexen’s overall HSE&SR program is guided by our corporate HSE&SR management system that incorporates the continual improvement model of Plan, Do, Check, Act and our own 12 guiding elements for divisional performance. 

 

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For more information on Nexen’s HSE&SR governance model, refer to the Responsible Development section of our website as well as our sustainability report, both available at www.nexeninc.com.

 

Environmental and Social Responsibilities

 

Environmental and social responsibility has become an increasingly significant measurement of corporate performance by governments, investors and the public. The oil and gas industry is being challenged to improve its response to the effects of climate change, embrace responsible operating practices, including the preservation of water, land, air and biodiversity, and consult and invest in the communities it relies upon to do business. The level of regulation associated with these issues varies considerably throughout the jurisdictions in which we operate. Based on the current trend, it is reasonably likely that our regulatory obligations and the associated cost of compliance will increase. Due to the uncertainty surrounding the future implementation of regulations, we are unable to estimate our costs of compliance in the future. We do, however, look at a range of regulatory scenarios to try to determine the possible compliance costs.

 

As a result of our commitment to responsible operating practices and social responsibility, we believe we are well positioned to meet the challenges of increasing environmental regulation and social expectations that have become a significant component of sustainable resource development. We have built a corporate culture of integrity and respect for the communities and environments in which we operate and have developed policies and practices for continuing compliance with all applicable laws and regulations.

 

CLIMATE CHANGE AND AIR EMISSIONS

 

Nexen believes that climate change and the transition to a low carbon energy system are important issues. For the past decade, Nexen has been active in planning and preparing for carbon regulation and continues to be engaged in public discussions on this matter in the jurisdictions where we operate. We have also participated in carbon markets, renewable energy initiatives and a range of carbon offset/crediting projects. The Canadian Federal Government has yet to pass climate change legislation. In the US, there has been no material progress to date on comprehensive climate/energy legislation.

 

Any required reductions in the greenhouse gases (GHGs) emitted from our operations could result in increases to our capital or operating expense.

 

We currently have compliance obligations in the UK North Sea, Alberta and British Columbia. Alberta became the first jurisdiction in Canada to enact and implement binding industrial sector emission reductions (a one-time from base, 12% reduction in carbon intensity vs. a 2003—2005 baseline) on facilities annually emitting more than 100,000 tonnes of CO2 equivalent. Facilities unable to achieve internal reductions have an unlimited ability to achieve compliance through payment into a technology fund at the rate of $15 per tonne of CO2 equivalent or through the purchase of eligible Alberta-based emission offset credits.

 

British Columbia enacted legislation in November 2007 titled the *Greenhouse Gas Reduction Targets Act*, which targets a 33% reduction in current provincial GHG emissions by 2020. British Columbia has been actively engaged in the Western Climate Initiative and recently enacted a GHG reporting regulation. For oil and gas operations, the facility emission reporting threshold is 25,000 tonnes CO2 equivalent with the proviso that once a company exceeds that threshold all assets must report regardless of size. The province also applied an economy-wide carbon tax on all hydrocarbon fuels sold in the province. The tax started at $10/tonne of CO2 in 2008 and increased by $5 per year until it reached $30 per tonne in July of 2012.

 

In 2008, the European Union (EU) introduced Phase II of the Emissions Trading Scheme (ETS), which ran until the end of 2012. Under Phase II of the ETS, member states were required to establish a national allocation plan approved by the EU. The system covers CO2 from certain combustion and flaring activities, and member states are allowed to manage allocation across their industrial base as they see fit. Installations have the ability under the ETS to purchase allowances or other eligible instruments to ensure compliance. Phase III, scheduled to run from 2013 to 2020, may include a transition from the gratis allocation of allowances to the use of auctioning. Post-2012 auctioning of allowances for all electricity generation activities and phased reduction of free allocation of allowances for other activities, as well as phased reduction of allowance availability in general, are expected to increase our annual cost of compliance for our UK North Sea operations. Proposals to increase the EU reduction obligation from 20 to 30%, if implemented, could also increase our annual cost of compliance.

 

In 2009, the US Environmental Protection Agency (EPA) announced its findings that GHGs pose a threat to public health. In the absence of other federal programs to regulate GHGs, the EPA has initiated regulatory activity under the authority of the *Clean Air Act*. 

 

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The facility threshold for this action is currently set at 25,000 tonnes per year, a level that none of our operated US facilities currently emits. The impact of EPA activity in the area of GHG regulation is expected to be minimal on our current operations in the Gulf of Mexico.

 

To comply with our current and projected GHG emissions obligations, we rely on:

 

·                  reductions of direct GHG emissions at our existing facilities;

·                  incorporating new energy efficiency designs and/or technology in new facilities;

·                  generating carbon credits from wind power;

·                  payments into available technology funds; and

·                  access carbon markets as required.

 

The Canadian Council of Ministers of the Environment (comprised of the federal and provincial ministers) are pursuing a federal air quality management system for the regulation of air pollutant emissions and ambient air quality. Work on equipment performance standards and ambient air quality objectives progressed through 2011 and 2012. Draft regulations are expected in 2013 with implementation beginning in 2014. While we could face technical challenges in meeting minimum emission standards for certain pollutants, we are currently unable to estimate the cost of compliance and impact on our operations.

 

WATER

 

We developed a water strategy designed to minimize water use in our exploration and production operations. This strategy is embodied by the following four principles:

 

·                  optimize water use efficiency;

·                  minimize our impacts on ecosystem functions and ensure public health and safety are not affected by our activities;

·                  engage with stakeholders to promote responsible watershed management and evaluate opportunities to provide water management benefits to stakeholders; and

·                  measure and communicate our water management performance.

 

This strategy was implemented in 2009 with an emphasis on compliance and early adoption of best practices, incorporating water assessment in our investment decision-making process and developing water management systems to enhance water tracking and reporting.

 

LAND AND BIODIVERSITY

 

Our land use practices are based upon principles of minimal disturbance and a legal commitment to return the land to a natural state after responsibly producing oil and gas resources. We also recognize that our ability to effectively access land is directly linked to the way in which we manage the potential environmental impacts and in how we engage with local communities, stakeholders, regulators and other industries to reduce the cumulative effects of our projects throughout their lifecycle.

 

For many stakeholders, a company’s ability to meet environmental expectations is a significant criterion upon which their decision to invest or conduct business is based. A failure to meet those expectations can limit access to exploration, development and partnership opportunities. Therefore, we believe that environmental and social responsibility performance is directly linked to economic performance.

 

Our environmental practices and policies are disclosed in our sustainability report, available on our website at www.nexeninc.com.

 

Environmental Provisions and Expenditures

 

Meeting the challenges of environmental regulation and our commitment to sustainable resource development affects all stages of our operations and generally increases their cost. Environmental commitments and regulation can increase the operating or capital cost of operations, delay requisite permits or approvals from issuing authorities and could result in unprofitable operating conditions. During 2012, we incurred both capital and operating expenses, including expenses related to environmental control facilities. Those costs were not material and did not impair our ability to execute our business or operating strategy. We will continue to incur these costs in the future and expect they will be manageable. At December 31, 2012, $2,395 million ($3,731 million undiscounted, adjusted for inflation) has been provided in our Consolidated Financial Statements for future asset retirement obligations.

 

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**EMPLOYEES**

 

We had 3,228 employees on December 31, 2012.

 

**RISK FACTORS**

 

Our operations are exposed to various risks, some of which are common to other operations in the oil and gas industry and some of which are unique to our operations. Certain risks set out below constitute “forward-looking statements” and the reader should refer to the special note regarding “Forward-Looking Statements” set out on page 3 of this AIF.

 

Our profitability and liquidity are highly dependent on the price of crude oil and natural gas.

 

Our financial performance depends significantly on the price of crude oil and natural gas we receive for our production. Extended periods of lower commodity prices may reduce our level of spending for oil and gas exploration and development, and may have a material adverse effect on our results of operations. Lower realized commodity prices could also have a material adverse effect on our estimates of proved reserves, the carrying value of our oil and gas properties, the level of planned drilling activities and future growth. Crude oil and natural gas are commodities that are price-sensitive to numerous worldwide factors, many of which are beyond our control. These factors include, but are not limited to:

 

·                  global and regional supply and demand for crude oil, natural gas, and natural gas liquids;

·                  the costs of exploring for, developing, producing and transporting crude oil, natural gas and natural gas liquids;

·                  weather conditions;

·                  the effect of energy conservation efforts;

·                  limits on transportation capacity to alternative energy markets;

·                  the pricing and availability of alternative fuels and energy;

·                  production quotas set by the Organization of Petroleum Exporting Countries (OPEC), and their ability to meet those quotas;

·                  worldwide geopolitical events, armed conflict and acts of terrorism;

·                  domestic and foreign government regulations and taxes; and

·                  the overall economic environment worldwide.

 

Exploration, development and production activities may not be successful and carry a risk of loss.

 

Acquiring, exploring and developing crude oil and natural gas involves many risks. There is a risk that we will not encounter commercially productive oil or gas reservoirs and that the wells we drill may not be productive or not sufficiently productive to recover a portion or all of our investment. We may not achieve production targets should reservoir production decline sooner than expected. Seismic data and other exploration technologies we use do not provide conclusive proof prior to drilling a well that crude oil or natural gas is present or may be produced economically. The costs of drilling, completing and operating wells are often uncertain, and drilling operations may be extended, curtailed, delayed or cancelled as a result of a variety of factors, including:

 

·                  encountering unexpected formations or pressures;

·                  blowouts, wellbore collapse, equipment failures and other accidents;

·                  craterings and sour gas releases;

·                  accidents and equipment failures;

·                  uncontrollable flows of oil, natural gas or well fluids; and

·                  environmental risks.

 

These occurrences may also result in damage to or destruction of wells, facilities or other property, pollution, injury to persons or loss of life. We may not be fully insured against all of these risks, and insurance may not be available for certain risks, such as named wind storms. Our contractual allocation of risk amongst joint-operating partners and service providers may not operate as intended. Losses resulting from the occurrence of these risks may materially impact our operational activities and financial results.

 

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We operate in harsh and unpredictable climates and locations where our access is regulated, which could adversely impact our operations.

 

Some of our facilities are located in harsh and unpredictable climates and locations that can experience extreme weather conditions and natural disasters, such as sustained ambient temperatures above 40°C or below -35°C, flooding, droughts, wind and dust storms, difficult terrain, high seas, monsoons and hurricanes. These conditions are difficult to anticipate and cannot be controlled. In these conditions, operations can become difficult or unsafe and are often suspended. Some of our facilities and those that our facilities rely upon (such as pipelines, power, communication and oil field equipment) are vulnerable to these types of extreme weather conditions and may suffer extensive or catastrophic damage as a result. If any such extreme weather were to occur, our ability to operate certain facilities and proceed with exploration or development programs could be seriously or completely impaired or destroyed and could have a material adverse effect on our business, financial condition and results of operations. The insurance we maintain may not be adequate to cover our losses resulting from disasters or other business interruptions.

 

In some areas of the world, access and operations can only be conducted during limited times of the year due to weather or government regulation. These adverse conditions can limit our ability to operate in those areas and can intensify competition during these periods for oil field equipment, services and qualified personnel, which may lead to periodic shortages. These constraints and the resulting shortages or high costs could delay our operations and materially increase our operating and capital costs and could have a material adverse effect on our business, financial condition and results of operations. Changing weather patterns may increase the frequency, intensity or duration of these weather conditions and accordingly, exacerbate their impact on our operations.

 

Deep-water operations involve additional risk.

 

Our deep-water operations take place in difficult and unpredictable environments and are subject to certain risks including blowouts and other catastrophic events (collectively Catastrophic Events) that could result in suspension of operations, damage to equipment, harm to individuals and/or damage to the environment. While various precautions are taken to reduce the risk, these efforts cannot eliminate the risk that such events may occur. The consequences of Catastrophic Events occurring in deep-water operations can be more difficult and time-consuming to remedy. As well, the remedy may be made more difficult or uncertain by the water depths, pressures and cold temperatures encountered in deep-water operations, shortages of equipment and specialists required to work under these conditions, or the absence of appropriate means to effectively remedy such consequences. Emergency response plans that we have in place to address the environmental impact of Catastrophic Events arising out of our operations may not be entirely effective to mitigate the consequences of such Catastrophic Events. Our deep-water operations could also be affected by the actions of our contractors and agents, which could give rise to liability for us, damage to our equipment, harm to individuals, force a shutdown of our facilities or operations, or result in a shortage of appropriate equipment or specialists required to perform our planned operations. It is possible that the allocation of liabilities and risk of loss arising from deep-water operations and associated insurance coverage will not be sufficient to cover the costs arising out of such events.

 

Our costs associated with a Catastrophic Event could be material and we may not maintain sufficient insurance to cover such costs. As it pertains to these types of deep-water risks, we maintain insurance for costs relating to property damage to our facilities, control of well including drilling relief wells, removal of wreck, pollution clean—up, liability for bodily injury and property damage to third parties, including our contractors, and liability for damage to natural resources. For property damage to our facilities, we are covered for amounts up to the replacement cost of those facilities. For control of well, pollution clean—up, liability for bodily injury and property damage to third parties caused by pollution, we are insured for amounts up to US$400 million. We have separate, additional insurance covering liability for bodily injury and property damage to third parties of up to US$465 million, which responds whether the liability arises from pollution or from other causes. Where we are the operator of a well or a facility in the Gulf of Mexico, we are insured for our working interest share up to US$35 million of coverage relating to our obligations under Section 1001 of the US *Oil Pollution Act*of 1990, which includes liability for damage to natural resources. For declared deep-water wells, we are insured for our working interest share of up to US$750 million for costs related to control of the well. Our insurance for “pollution clean—up” covers: i) reasonable and necessary expenses incurred; ii) liability to any governmental entity for clean-up and removal costs and expenses; and iii) liability for costs and expenses of governmental action. In each case, such coverage is reasonable in that it allows us to take action to minimize, remediate or prevent further injuries to persons or loss or damage to the property of others arising out of seepage, pollution or contamination. Our insurance for “liability for damage to natural resources” includes coverage for damages for which we may be liable as a result of loss of or damage to, including loss of use of, “natural resources” arising out of seepage, pollution or contamination. “Natural resources” include land, fish, wildlife, plantlife, air, water, ground water, drinking water supplies and other such resources.

 

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Following the explosion and sinking of the Deepwater Horizon drilling rig, the offshore drilling industry is under increased scrutiny from governments, environmental groups, investors and the general public. The resultant increase in regulation of deep-water operations has increased our costs of compliance, though not presently to such extent that our current or proposed drilling activities have become uneconomic. A risk also exists that liability limits under existing regulations could be increased substantially by the US Government, which would increase our potential liability in the event of a blowout or other catastrophic event. We also may not be able to access sufficient pooled liability funds set up in the US Gulf of Mexico for costs of a blowout or other catastrophic event.

 

Catastrophic Events in connection with our deep-water operations, such as blowouts and oil spills, could result in material costs and reputational damage, and could have a material adverse effect on our credit rating, our ability to raise capital, or the cost of such capital.

 

Competitive forces may limit our access to natural resources and create labour and equipment shortages.

 

The oil and gas industry is highly competitive, particularly in the following areas:

 

·                  gaining access to areas or countries known to have available resources;

·                  searching for and developing new sources of crude oil and natural gas reserves;

·                  hiring the equipment and expertise required to safely and cost-effectively develop resources;

·                  constructing and operating crude oil and natural gas pipelines and facilities; and

·                  transporting and marketing crude oil, natural gas and other petroleum products.

 

Our competitors include national oil companies, major integrated oil and gas companies and various other independent oil and gas companies. The petroleum industry also competes with other industries in supplying energy, fuel and related products to customers. Key success factors in each of these markets are price, product quality, logistics and reliability of supply.

 

Competitive forces may result in shortages of: i) prospects to drill; ii) labour; iii) drilling rigs and other equipment to carry out exploration, development or operating activities; and/or iv) shortages of infrastructure to produce and transport production. It may also result in an oversupply of crude oil and natural gas. Each of these factors could negatively impact our costs and prices and, therefore, our financial results.

 

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Some of our production is concentrated in a few producing assets.

 

A significant portion of our current and future production is generated from highly productive wells or central production facilities. Examples include:

 

·                  our Buzzard, Scott and Ettrick production facilities in the UK North Sea;

·                  our Usan project, offshore Nigeria;

·                  our Long Lake project in the Athabasca oil sands; and

·                  upgrading facilities at Syncrude in the Athabasca oil sands.

 

As significant production is generated from each asset, any single event that interrupts one of these operations could result in the loss of production.

 

We operate in countries with political, economic and security risks.

 

We operate in numerous countries, some of which may be considered politically and economically unstable. A portion of our revenue is derived from operations in these countries. As a result, our financial condition and operating results could be significantly affected by risks associated with international activities, including:

 

·                  civil unrest and general strikes;

·                  political instability, the risk of war and acts of terrorism;

·                  taxation policies, including royalty and tax increases, retroactive tax claims and investment restrictions;

·                  expropriation or forced renegotiation or modification of existing contracts;

·                  exchange controls, currency fluctuations, devaluation or other activities that limit or disrupt markets and restrict payments or the movement of funds;

·                  the possibility of being subject to exclusive jurisdiction of foreign courts in connection with legal disputes relating to licences to operate and concession rights in countries where we currently operate; and

·                  difficulties in enforcing our rights against a governmental agency because of the doctrine of sovereign immunity and foreign sovereignty over international operations.

 

The impact that future potential terrorist attacks or regional hostilities may have on the oil and gas industry, and on our operations in particular, is not known at this time. Uncertainty surrounding military strikes or a sustained military campaign may affect operations in unpredictable ways, including disruptions of fuel supplies and markets, particularly crude oil, and the possibility that infrastructure facilities, including pipelines, production facilities, processing plants and refineries, could be direct targets of, or indirect casualties of, an act of terror or war. We may be required to incur significant costs in the future to safeguard our assets against terrorist activities or to remediate potential damage to our facilities. There can be no assurance that we will be successful in protecting ourselves against these risks and the related financial consequences.

 

We are required to obtain regulatory approvals in order to operate.

 

Our oil and gas operations are subject to various international, federal, state, provincial, territorial and local laws and regulations designed to regulate the conduct of oil and gas exploration, development and production activities. Those laws and regulations govern, amongst other things:

 

·                  the types and quantities of substances and waste materials that may be discharged into the surface and sub-surface environment;

·                  the use or removal of natural resources (such as water and timber) in exploration and production activities;

·                  the release of greenhouse gases, such as carbon dioxide and methane, into the atmosphere;

·                  the protection of endangered species;

·                  the abandonment, reclamation and remediation of worksites (including sites of former operations);

·                  the issuance of permits and other regulatory approvals in connection with exploration, drilling and production activities, the construction of roads, pipelines and other regional transportation infrastructure; and

·                  marketing and pricing policies, royalties, various taxes and levies including income tax, and foreign trade and investment.

 

These laws and regulations may impose significant liabilities on a failure to comply with their requirements including the possibility of administrative, civil and criminal penalties, cancellation or suspension of permits or authorizations, investigations or other proceedings. Significant changes to the environmental laws and regulations governing our current operations, including many of the proposed initiatives to regulate greenhouse gas emissions, may have a material adverse effect on the oil and gas industry, including our company. The cost of meeting new environmental and climate change regulations may have a material adverse effect on the viability of future projects, our results of operations, cash flows and financial condition.

 

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Our oil sands projects face additional risks compared to conventional oil and gas production.

 

Oil sands developments are large and capital intensive projects which rely on specialized production technologies such as SAGD. Our Long Lake development is a fully integrated production, upgrading and cogeneration facility that relies on specialized upgrading technology. Given the initial investment and operating costs to produce bitumen, the payout period for these projects is longer and the economic return is lower than a conventional light oil project with an equal volume of reserves.

 

Risks associated with oil sands projects include the following:

 

*SAGD BITUMEN PRODUCTION MAY NOT ACHIEVE OUR EXPECTATIONS*

 

Our estimates of performance and recoverable volumes for oil sands projects are based primarily on sample reservoir data, the results of pilot projects, our experience with the Long Lake project and industry performance from SAGD operations in similar reservoirs in the McMurray formation in the Athabasca oil sands. While some of the wells will achieve the performance expectations established prior to project sanction, there can be no certainty that these wells will maintain these levels or that our overall SAGD operation will produce bitumen at the expected levels or steam-to-oil ratio. If the assumed production rates or steam-to-oil ratio are not achieved for reasons which could be related to one or all of design, facility or reservoir performance, or the presence of problematic geological features in the reservoir such as shales or pockets of water, we might have to drill additional wells to maintain optimal production levels, construct additional steam generating capacity, or reconfigure, redesign or construct additional facilities. These could have an adverse impact on the future activities and economic return of the project.

 

*APPLICATION OF A NEW BITUMEN UPGRADING PROCESS AT LONG LAKE*

 

The proprietary OrCrudeTM process we are using at Long Lake to upgrade bitumen to synthetic crude is the first commercial application of this process. Although the commercial upgrader at Long Lake has been operating since January 2009, there is no certainty that it will sustain or achieve the results that are now being seen or forecast for reasons which could be related to multiple factors, some of which may be related to one or all of design, facility performance or integration of our facilities. As a result, we may be required to reconfigure, redesign or construct additional facilities. If we are unable to continue to upgrade the bitumen for any reason, we may decide to sell the bitumen directly to third parties without upgrading, which would expose us to the following risks:

 

·                  the market for bitumen may be limited;

·                  additional costs would be incurred to purchase diluent for blending and transporting bitumen;

·                  there could be a shortfall in the supply of diluent, which may cause its price to increase;

·                  the market price for bitumen is generally lower than for PSCTM, reflecting its quality differential; and

·                  additional costs would be incurred to purchase natural gas for use in generating steam for the SAGD process since we would not be producing synthetic gas from the upgrading process.

 

If any of these factors arise, our operating costs would increase or our revenues would decrease from what we have assumed. This would materially decrease expected earnings from the project and the project may not be profitable under these conditions.

 

*INTEGRATION OF A SAGD FACILITY AND AN UPGRADING FACILITY AT LONG LAKE*

 

The combination of a SAGD facility with the OrCrudeTM upgrading facility at Long Lake is a unique, patented combination of equipment. Although this integrated facility is expected to achieve lower operating costs and has demonstrated that the combination of technologies works, the complexity and degree of interdependency of the facilities creates conditions for interruptions and limitations to operations impacting the entire operation of the facilities. This could require future reconfigurations and modifications to improve the reliability, durability and efficiency of operation initially contemplated by its design. There is no certainty that any such changes will successfully resolve the problems experienced or that we may experience in the future, which would expose us to additional costs and associated downtime of one or both of the SAGD production and upgrader facilities, and the potential for increased maintenance requirements.

 

These factors could have a significant adverse impact on the future activities and economic returns of the Long Lake project.

 

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*DEPENDENCE UPON PROPRIETARY TECHNOLOGY AT LONG LAKE*

 

The success of the Long Lake project and our investment depends on the proprietary technology of Ormat Industries Ltd. (Ormat) and proprietary technology of third parties that has been, or is required to be, licensed for the project.

 

Ormat and Nexen rely on intellectual property rights and other contractual or proprietary rights, including (without limitation) copyright, trademark laws, trade secrets, confidentiality procedures, contractual provisions, licences and patents, to secure the rights to utilize Ormat’s proprietary technology and the proprietary technology of third parties. Ormat and Nexen may have to engage in litigation to protect the validity of its patents or other intellectual property rights, or to determine the validity or scope of patents or proprietary rights of third parties. Litigation can be time-consuming and expensive, whether successful or not. The process of seeking patent protection can itself be long and expensive. There is no assurance that any pending or future patent applications of Ormat or such third parties will actually result in issued patents or that, if patents are issued, they will be of sufficient scope or strength to provide meaningful protection or any commercial advantage to Ormat. Others may develop technologies that are similar or superior to: i) the technology of Ormat or third parties; or ii) the design around the patents owned by Ormat and/or third parties.

 

*OPERATIONAL HAZARDS*

 

Our oil sands projects are designed to process large volumes of hydrocarbons at high-pressure and temperatures and also handle large volumes of high-pressure steam. Equipment failures could result in damage to the project facilities and liability to third parties against which we may not be able to fully insure or may elect not to insure because of costs or for other reasons.

 

Certain components of the Long Lake facilities produce sour gas, which is gas containing hydrogen sulphide and carbon monoxide. Sour gas is a colourless, corrosive gas that is toxic at relatively low levels to plants and animals, including humans. Carbon monoxide is a colourless, odorless and tasteless gas that is toxic at relatively low levels to humans and animals. The project includes integrated facilities for handling and treating the sour gas and for consuming the carbon monoxide as a fuel, including the use of gas-sweetening units, sulphur recovery systems and emergency flaring systems. Failures or leaks from these systems or other exposure to sour gas produced as part of the project could result in damage to other equipment, liability to third parties, adverse effect to humans, animals and the environment, or the shutdown of operations.

 

The Long Lake project is susceptible to loss of production, slowdowns or restrictions on its ability to produce higher-value products due to the interdependence of its component systems. Severe climatic conditions can cause reduced production and, in some situations, result in higher costs. SAGD bitumen recovery facilities and development and expansion of production can entail significant capital outlays. The costs associated with synthetic crude oil production are largely fixed and, as a result, per unit operating costs depend largely on production levels.

 

Unconventional gas resource plays carry additional risks and uncertainties.

 

Shale gas and CBM are unconventional gas resources which are produced through the application of relatively new technologies, such as hydraulic fracing. Some of the uncertainties associated with development of unconventional gas resources are as follows:

 

·                  shales are typically less permeable than conventional gas reservoirs and can therefore require more extensive, and expensive, completion technologies, which can increase costs or which may not be successful;

·                  seasonal access to certain areas may limit activities or increase competition for equipment and/or qualified personnel;

·                  global demand for the specialized equipment and personnel required to develop and produce unconventional gas resources is strong, and access to the equipment may become more expensive and possibly limited;

·                  some unconventional gas resources are located in areas of the world with limited access to regional infrastructure for the sale of production;

·                  limitations on local water availability may limit our ability to develop shale gas, which generally requires more water to develop and produce than conventional resources;

·                  some jurisdictions have banned hydraulic fracturing activities pending further review of the practice amidst public concern and allegations it causes contamination of drinking water aquifers and other subsurface damage; and

·                  regulatory approval is required to drill more than one well per section, and as a result, the timing of drilling programs and land development can be uncertain.

 

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Without reserve additions, our reserves and production will decline over time and we require capital to produce remaining reserves.

 

Our future crude oil and natural gas reserves and production, and therefore our future operating cash flows and results of operations, are highly dependent upon our success in exploiting our current reserves and acquiring or discovering additional reserves in the future. Without reserve additions through exploration, development or acquisitions, our reserves and production will decline over time as reserves are produced. The business of exploring for, developing or acquiring reserves is capital intensive. To the extent cash flow from operations is insufficient and external sources of capital become limited or unavailable, our ability to make the necessary capital investments to maintain and expand our oil and natural gas reserves and production may be reduced.

 

Discovered oil and natural gas accumulations are generally only produced when they are economically recoverable. As such, oil and gas prices, and capital and operating costs have an impact on whether accumulations will ultimately be produced.

 

Our reserves include undeveloped properties that require additional capital to bring them on stream.

 

Proved and probable oil and gas reserves include undeveloped reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is still required before such wells begin production. Reserves may be recognized when plans are in place to make the required investments to convert these undeveloped reserves to producing. Circumstances such as a sustained decline in commodity prices or poorer than expected results from initial activities could cause a change in the investment or development plans, which could result in a material change in our reserves estimates.

 

Projects may not be completed on time or within budget.

 

We are involved with a variety of projects at any given time, including exploration and development projects, and the construction and expansion of facilities and pipelines. Project delays may adversely affect expected revenues and cost overruns may adversely affect project economics. Our ability to complete projects on time and on budget depends on many factors beyond our control, including the availability of equipment and personnel, land access, weather, accidents, equipment breakdown, the need for government and regulatory approvals, unexpected or uncontrollable increases in the costs of materials or labor and access to pipeline and processing capacity.

 

Pipeline and export infrastructure in North America is limited.

 

An increase in the supply of crude oil and natural gas from unconventional sources in North America has reduced commodity prices relative to many foreign markets. The increased supply in North America is expected to fill existing North American pipeline infrastructure. Without new transportation and export infrastructure, the current transportation network may not be able to accommodate the increased volumes of crude oil and natural gas expected from the development of unconventional oil and gas, including oil and gas produced from our oil sands and shale gas properties in western Canada. This, in turn, could delay the development of our oil and gas reserves in western Canada. In addition, North America has limited export infrastructure and without new export infrastructure, we may be required to sell our production into the North American markets at lower prices than are available in other foreign markets, which could materially and adversely affect our financial performance.

 

Negative public perception of oil and gas development, oil sands and shale gas hydraulic fracing may harm our corporate reputation and profitability.

 

The development of the oil sands and shale gas figures prominently in political, media and activist commentary on the subjects of greenhouse gas emissions, water usage, hydraulic fracing and potential for environmental damage. Concerns over greenhouse gas emissions, land use and water contamination may directly or indirectly harm the profitability of our current oil sands and shale gas projects and the viability of future projects in a number of ways, including:

 

·                  creating significant regulatory uncertainty that could challenge the economic modeling of future projects and delay sanctioning;

·                  motivating extraordinary environmental regulation of those projects by governmental authorities that could result in changes to facility design and operating requirements, thereby increasing the cost of construction, operation and abandonment; and

 

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·                  compelling legislation or policy that could limit the purchase of crude oil produced from the Athabasca oil sands by governments or other institutional consumers that, in turn, limits the market for this crude oil and reduces its price.

 

Concerns over these issues may also harm our corporate reputation and limit our ability to access land and joint venture opportunities in certain jurisdictions throughout the world.

 

Our lands could be subject to aboriginal claims.

 

Aboriginal peoples have claimed aboriginal title and rights to a substantial portion of western Canada. Certain aboriginal peoples have filed a claim against the Government of Canada, the Province of Alberta, the Province of British Columbia and certain governmental entities. They are claiming, among other things, aboriginal title to large areas of lands surrounding Fort McMurray, Alberta and Fort Nelson, British Columbia, including the lands on which our shale gas and oil sands interests, and those of most other oil sands and shale gas operators in Alberta and British Columbia, are located. As a result, aboriginal consultation on surface activities is required and may result in timing uncertainties or delays of future development activities. Such claims, if successful, could have a significant adverse effect on our oil sands and shale gas developments.

 

Our energy marketing operations expose us to the risk of trading losses and liquidity constraints.

 

Our energy marketing operations expose us to the risk of financial losses from various sources, which may have a material adverse effect on our financial performance. Our energy marketing team maintains a portfolio comprised of long and short physical and financial positions, which may be significant in size or number at any time. This portfolio of positions is managed based on a trading thesis for expected future pricing levels and trends in forward or regional markets. Unanticipated volatility in commodity price levels and trends upon which those positions are based may cause a position to decrease in value. The transportation and storage assets and contracts undertaken by our energy marketing business may decrease in value due to changes in temporal and regional commodity pricing.

 

Significant changes in commodity and financial markets could require us to provide additional liquidity if collateral is required to be placed with counterparties. We may also be required to reduce some of our energy marketing activities. Adverse credit-related events such as a downgrade of our credit rating to non-investment grade could require additional collateral to be placed with counterparties. Adverse, broad-based, industry credit-related events could also negatively affect trading counterparties who fail to fulfill their contractual obligations.

 

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Use of marine transportation may expose us to the risk of financial loss and damaged reputation.

 

From time to time, we may choose to charter marine vessels for the transportation of crude oil. This may expose us to the risk of financial loss and damaged reputation in the event of oil spills. Marine transportation is subject to hazards such as capsizing, collision, acts of piracy and damage or loss from severe weather conditions. These hazards could result in serious personal injury or loss of human life, significant damage to property and equipment, environmental pollution, impairment of operations, risk of financial loss and damaged reputation in the event of oil spills. We may not be insured against all of these risks and uninsured losses and liabilities arising from these hazards could reduce the funds available to us for capital, exploration and investment spending, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

 

Our debt and other financial commitments may limit our financial and operating flexibility.

 

As of December 31, 2012 our long-term debt was approximately $4.3 billion. We also have commitments under leases, drilling rig contracts, transportation and storage contracts, and purchase obligations for services and products. Our debt levels and financial commitments could have significant and adverse consequences to our business, including:

 

·                  an increased sensitivity to adverse economic and industry conditions;

·                  a limited ability to fund future working capital and capital expenditures, engage in future acquisitions or development activities, or to otherwise fully realize the value of assets or opportunities, because a substantial portion of our cash flows are required to service debt and other obligations;

·                  a limited ability to plan for, or react to, industry trends; and

·                  an uncompetitive position relative to our competitors whose debt and financial commitment levels are lower.

 

The inability of counterparties and joint operating partners to fulfill their obligations to us could adversely impact our results of operations.

 

Credit risk arises from the sale of our production, the sale of products our energy marketing group buys for resale, financial contracts we acquire for hedging and trading purposes, and from our joint venture partners for their share of capital and operating costs. There is the risk of loss and additional burden for amounts in excess of available remedies if counterparties or joint venture partners do not or cannot fulfill their contractual obligations.

 

A downgrade in our credit rating could increase our cost of capital and limit access to capital.

 

Rating agencies regularly evaluate Nexen and their ratings of our long-term and short-term debt are based on a number of factors. This includes their perception of our financial strength as well as other factors not entirely within our control, including conditions affecting the oil and gas industry generally, and the wider state of the economy. We cannot be assured that one or more of our credit ratings will not be downgraded. Our borrowing costs and ability to raise funds are directly impacted by our credit ratings.

 

In addition, credit ratings may be important to customers or counterparties when we compete in certain markets and when we seek to engage in certain transactions including transactions involving over-the-counter derivatives.

 

It is our objective to maintain high-quality credit ratings appropriate for our business activities. A credit-rating downgrade could potentially limit our access to private and public credit markets and increase the costs of borrowing under existing facilities. A reduction in our credit ratings could also have a significant impact on certain trading revenues, particularly in those businesses where counterparty creditworthiness is critical. A reduction could trigger collateralization requirements related to physical and financial derivative liabilities with certain marketing counterparties and pursuant to certain facility construction contracts. The occurrence of any of the foregoing could adversely affect our ability to execute portions of our business strategy and could have a material adverse effect on our liquidity and capital position. In connection with certain over-the-counter derivatives contracts and other trading agreements, we could be required to provide additional collateral or to terminate transactions with certain counterparties in the event of a downgrade of our credit ratings. The amount of additional collateral required depends on the terms of the contract and is usually a fixed incremental amount and/or the market value of the exposure.

 

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Fluctuations in foreign exchange rates may have a material adverse effect on our results of operations.

 

Our operations are sensitive to fluctuations in foreign currency exchange rates, particularly between the Canadian dollar, the US dollar and the British Pound. A substantial portion of our activities are transacted in, or referenced to, US dollars, including sales of crude oil and natural gas, capital spending and expenses for our oil and gas operations, and short-term and long-term borrowings. As a result, changes in exchange rates could materially and adversely affect our results of operations.

** **

**CAPITAL STRUCTURE**

 

Authorized Capital

 

Our authorized capital consists of an unlimited number of common shares without nominal or par value and an unlimited number of Class A preferred shares without nominal or par value, issuable in series. As at December 31, 2012, 530,036,892 common shares and 8,000,000 Cumulative Redeemable Class A Rate Reset Preferred Shares, Series 2 (Series 2 Shares) were issued and outstanding.

 

Common Shares

 

Each common share entitles the holder to receive notice of, attend and one vote at all meetings of our shareholders, other than meetings at which only the holders of a specified class or series of shares are entitled to vote. The holders of common shares are entitled, subject to the rights, privileges, restrictions and conditions attached to other classes of shares of Nexen, to receive any common share dividend declared by the board and to receive the remaining property of Nexen upon dissolution of the company. There are no pre-emptive or conversion rights attached to the common shares and the common shares are not subject to redemption. All common shares currently outstanding, and potentially outstanding upon the exercise of outstanding options, are, or will be, fully paid and non-assessable.

 

Preferred Shares

 

Preferred shares may be issued in one or more series. Each series consists of such number of shares and with the designation, rights, restrictions, conditions and limitations as determined by our board of directors.

 

Holders of preferred shares are not entitled to receive notice of, attend or vote at our shareholder meetings, unless payments of four quarterly preferred share dividends of any series remain outstanding and unpaid. As long as any preferred share dividend of any series remains in arrears, the holders of preferred shares are entitled to receive notice of and to attend all meetings of our shareholders and are entitled to one vote in respect of each preferred share held. In these circumstances, holders of preferred shares will be entitled, voting separately and exclusively as a class, to elect two directors to our board. Issued preferred shares will have priority over the common shares in payment of dividends and in the distribution of assets in the event of liquidation, dissolution or winding-up of Nexen. Each series of preferred shares rank in parity with preferred shares of every other series with respect to priority in payment of dividends and in the distribution of assets.

 

Series 2 Preferred Shares

 

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 to but excluding March 31, 2017, as and when declared by Nexen’s Board of Directors. Thereafter, the dividend rate will be reset every five years at a rate equal to the then current five-year Government of Canada bond yield plus 3.59%. The Series 2 Shares are redeemable at our option on March 31, 2017, and on March 31 of every fifth year thereafter.

 

The holders of the Series 2 Shares will have the right, at their option, to convert their shares to Cumulative Redeemable Class A Floating Rate Preferred Shares, Series 3 (Series 3 Shares), subject to certain conditions, on March 31, 2017 and on March 31 of every fifth year thereafter. The holders of the Series 3 Shares will be entitled to receive quarterly floating rate cumulative dividends, if declared, at a rate equal to the sum of the then current 90-day Government of Canada treasury bill rate plus 3.59%.

 

In the event of liquidation, dissolution or winding-up of Nexen, the holders of the Series 2 Shares will be entitled to receive $25 per share as well as all accrued unpaid dividends before any amounts will be paid or any assets will be 

 

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distributed to the holders of any other shares ranking junior to the preferred shares. The holders of the preferred shares will not be entitled to share in any further distribution of the assets of Nexen.

 

CNOOC Acquisition of Nexen Inc.

 

At a special meeting held on September 20, 2012, the holders of common and Series 2 Shares approved the Plan of Arrangement, pursuant to the Arrangement Agreement entered into on July 23, 2012, in connection with the proposed acquisition of Nexen Inc. by CNOOC Limited through CNOOC Canada Holding Ltd. The Arrangement Agreement proposed to acquire all outstanding common shares for US$27.50/share and all outstanding preferred shares of Cdn$26.00/share. Closing of the arrangement remains subject to the satisfaction or waiver of the remaining customary closing conditions. The transaction is expected to close the week of February 25, 2013.

 

Shareholder Rights Plan

 

A shareholder rights plan (the Plan) exists for holders of common shares of Nexen. The Plan creates a right for each present and future outstanding common share, entitling the holder to acquire additional common shares during the term of the right. Rights created under the Plan, which can only be exercised when a person acquires 20% or more of our common shares, entitle each common shareholder, other than the 20% buyer, to acquire additional common shares at one-half of the market price at the time of exercise. Prior to the separation date, the rights are not separable from the common shares and no separate certificates are issued. The separation date would typically occur at the time of an unsolicited takeover bid, but our board can defer the separation date. The Plan was reapproved by common shareholders at our annual general meeting in 2011 and will remain in force until the earlier of the date that the Plan is terminated by its terms and the termination of our annual general meeting in 2014. On closing of the Arrangement Agreement with CNOOC Limited, the Plan will terminate and all rights pursuant to the Plan will be cancelled with no payment. Otherwise, the Plan will remain in place until it is approved by common shareholders at or before our annual general meeting in 2014. A copy of the Plan is available on our website at www.nexeninc.com.

 

Credit Ratings

 

The following information relating to our credit ratings is provided as it relates to Nexen’s financing costs, liquidity and operations. Specifically, credit ratings affect our ability to obtain short-term and long-term financing and the cost of such financing. Additionally, our ability to engage in certain collateralized business activities on a cost-effective basis depends on Nexen’s credit ratings. A reduction in the current rating on our debt by rating agencies, particularly a downgrade below current ratings, or a negative change in the ratings outlook could adversely affect our cost of financing and our future access to sources of liquidity and capital. In addition, changes in credit ratings may affect our ability to, and the associated costs of: i) entering into ordinary course derivative or hedging transactions and may require posting additional collateral under certain contracts; and ii) entering into and maintaining ordinary course contracts with customers and suppliers on acceptable terms.

 

The table below details our current credit ratings and outlooks for our senior unsecured debt issued by credit rating agencies as of December 31, 2012. A credit rating is an independent measure intended to give an indication of a company’s ability to meet its financial commitments under the rated securities. Ratings are not recommendations to buy, hold or sell the debt and may be subject to revisions or withdrawal at any time by the rating agency.

 
| ** **                        | ** ** | **Standard & Poor’s   Rating Service   (S&P)** | ** ** | **Moody’s   Investors   Service   (Moody’s)** | ** ** | **DBRS   Limited   (DBRS)** | ** ** |
|-----------------------------------|------------|----------------------------------------------------------------------------|------------|---------------------------------------------------------|------------|-----------------------------|------------|
| Senior Unsecured/Long-Term Rating |       | BBB-                                                                       |       | Baa3                                                    |       | BBB                         |       |
| Outlook                           |       | Stable                                                                     |       | Negative                                                |       | Stable                      |       |

 

S&P’s credit ratings are on a long-term debt rating scale that ranges from AAA to D, representing the range from highest to lowest quality of such securities rated. The ratings from AA to CCC may be modified by the addition of a plus (+) or minus (-) sign to show relative standing within the major rating categories. According to S&P’s rating system, an obligation rated ‘BBB’ exhibits adequate protection parameters. However, adverse economic conditions or changing circumstances are more likely to lead to a weakened capacity of the obligor to meet its financial commitment on the obligation. Debt securities rated ‘BBB-’ are at the lowest end of these investment grade securities.

 

Moody’s credit ratings are on a long-term debt rating scale that ranges from Aaa to C, representing the range from highest to lowest quality of such securities rated. Moody’s applies numerical modifiers 1, 2 and 3 to each generic rating 

 

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classification from Aa through Caa in its long-term debt rating system. The modifier 1 indicates that the obligation ranks in the higher end of its generic rating category, the modifier 2 indicates a mid-range ranking and the modifier 3 indicates that the issue ranks in the lower end of that generic rating category. According to the Moody’s rating system, debt securities rated ‘Baa3’ are subject to moderate credit risk, considered medium grade and may possess certain speculative characteristics.

 

DBRS’ credit ratings are on a long-term debt rating scale that ranges from AAA to D, representing the range from highest to lowest quality of such securities rated. Each rating category between AA and C can be modified by the designations “high” and “low”, which indicate the relative standing of a rating within a particular rating category. The absence of either a “high” or “low” designation indicates that the rating is in the “middle” of the category. According to DBRS’ rating system, long-term debt securities rated ‘BBB’ are of adequate credit quality. The capacity for the payment of financial obligations is considered acceptable, however, it may be vulnerable to future events.

 

Risks and uncertainties related to our credit ratings and their possible impacts are discussed more fully in the section titled “Risk Factors” under the section titled “A downgrade in our credit rating could increase our cost of capital and limit access to capital”.

 

Quarterly Dividends Declared on Common and Preferred Shares

 

**Common Shares**

 
| **(Cdn$/share)** | ** ** | **First********Quarter** | ** ** | **Second********Quarter** | ** ** | **Third********Quarter** | ** ** | **Fourth********Quarter** | ** ** |
|------------------|------------|--------------------------|------------|---------------------------|------------|--------------------------|------------|---------------------------|------------|
| 2012             |       | 0.05                     |       | 0.05                      |       | 0.05                     |       | 0.05                      |       |
| 2011             |       | 0.05                     |       | 0.05                      |       | 0.05                     |       | 0.05                      |       |
| 2010             |       | 0.05                     |       | 0.05                      |       | 0.05                     |       | 0.05                      |       |

 

Subject to applicable law, our board of directors determines if and when dividends are declared on our common shares. Historically, dividends have been declared quarterly and paid on the first business day of the subsequent quarter. All dividends paid to holders of common shares have been designated as “eligible dividends” for Canadian tax purposes. This designation will apply to all such dividends paid in the future unless otherwise notified by us.

 

**Preferred Shares**

 
| **(Cdn$/share)** | ** ** | **First********Quarter** | ** ** | **Second********Quarter** | ** ** | **Third********Quarter** | ** ** | **Fourth********Quarter** | ** ** |
|------------------|------------|--------------------------|------------|---------------------------|------------|--------------------------|------------|---------------------------|------------|
| 2012             |       | —                   |       | 0.3928                    |       | 0.3125                   |       | 0.3125                    |       |

 

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, until March 31, 2017, as and when declared by Nexen’s Board of Directors. Thereafter, the dividend rate will be reset every five years at a rate equal to the then current five-year Government of Canada bond yield plus 3.59%. The Series 2 Shares are redeemable at our option on March 31, 2017, and on March 31 of every fifth year thereafter.

 

The Income Tax Act (Canada) requires us to deduct a withholding tax from all dividends remitted to non-residents. According to the Canada-US Tax Treaty, we deducted a withholding tax of 15% on dividends paid to residents of the United States, except in the case of a company that owns at least 10% of the voting stock, where the withholding tax is 5%.

 

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**MARKET FOR SECURITIES**

 

Common Shares

 

Our outstanding common shares are listed and traded on the TSX and NYSE under the trading symbol “NXY”. The following table provides the market price ranges and the aggregate volume of trading of the common shares on the TSX and NYSE for the periods indicated:

 
| ** ** | ** ** | **Toronto Stock Exchange   Cdn$** | ** ** | **New York Stock Exchange   US$** | ** ** |
|------------|------------|---------------------------------------------|------------|--------------------------------------------------|------------|
| **2012**   | ** ** | **High**                                    | ** ** | **Low**                                          | ** ** | **Close** | ** ** | **Volume** | ** ** | **High** | ** ** | **Low** | ** ** | **Close** | ** ** | **Volume** | ** ** |
| January    |       | 18.68                                       |       | 16.34                                            |       | 17.97 |   | 45,155,201 |   | 18.58 |   | 16.18 |   | 17.92 |   | 56,585,453 |   |
| February   |       | 21.53                                       |       | 17.33                                            |       | 20.17 |   | 37,358,099 |   | 21.59 |   | 17.37 |   | 20.38 |   | 48,817,376 |   |
| March      |       | 20.65                                       |       | 17.46                                            |       | 18.29 |   | 34,685,685 |   | 20.94 |   | 17.44 |   | 18.35 |   | 45,168,303 |   |
| April      |       | 19.38                                       |       | 16.94                                            |       | 19.09 |   | 45,116,630 |   | 19.61 |   | 16.86 |   | 19.35 |   | 58,203,303 |   |
| May        |       | 19.20                                       |       | 15.95                                            |       | 16.20 |   | 33,488,016 |   | 19.48 |   | 15.43 |   | 15.63 |   | 55,930,034 |   |
| June       |       | 17.76                                       |       | 15.18                                            |       | 17.24 |   | 42,417,825 |   | 17.42 |   | 14.63 |   | 16.89 |   | 47,823,068 |   |
| July       |       | 26.70                                       |       | 16.13                                            |       | 25.48 |   | 121,473,180 |   | 26.21 |   | 15.81 |   | 25.40 |   | 382,588,499 |   |
| August     |       | 25.75                                       |       | 24.78                                            |       | 24.78 |   | 26,713,142 |   | 25.92 |   | 25.09 |   | 25.21 |   | 117,740,382 |   |
| September  |       | 25.24                                       |       | 24.47                                            |       | 24.90 |   | 27,020,332 |   | 25.82 |   | 24.64 |   | 25.34 |   | 108,923,981 |   |
| October    |       | 25.51                                       |       | 23.01                                            |       | 23.85 |   | 36,956,026 |   | 25.87 |   | 23.08 |   | 23.90 |   | 185,396,913 |   |
| November   |       | 25.99                                       |       | 23.12                                            |       | 24.39 |   | 18,436,506 |   | 25.95 |   | 23.29 |   | 24.36 |   | 162,216,498 |   |
| December   |       | 26.83                                       |       | 21.35                                            |       | 26.57 |   | 33,977,333 |   | 26.99 |   | 21.07 |   | 26.94 |   | 309,388,484 |   |

 

Series 2 Preferred Shares

 

Our outstanding Series 2 preferred shares are listed and traded on the TSX under the trading symbol “NXY.PR.A”. The following table provides the market price ranges and the aggregate volume of trading of the Series 2 Shares on the TSX for the periods indicated:

 
| ** ** | ** ** | **Toronto Stock Exchange   Cdn$** | ** ** |
|------------|------------|---------------------------------------------|------------|
| **2012**   | ** ** | **High**                                    | ** ** | **Low** | ** ** | **Close** | ** ** | **Volume** | ** ** |
| January    |       | —                                      |       | — |   | — |   | — |   |
| February   |       | —                                      |       | — |   | — |   | — |   |
| March      |       | 25.25                                       |       | 25.00 |   | 25.18 |   | 1,426,857 |   |
| April      |       | 25.91                                       |       | 25.18 |   | 25.87 |   | 682,647 |   |
| May        |       | 25.75                                       |       | 25.10 |   | 25.26 |   | 182,086 |   |
| June       |       | 25.45                                       |       | 24.75 |   | 25.38 |   | 162,401 |   |
| July       |       | 26.15                                       |       | 25.22 |   | 25.88 |   | 765,159 |   |
| August     |       | 26.00                                       |       | 25.71 |   | 25.95 |   | 221,290 |   |
| September  |       | 25.99                                       |       | 25.34 |   | 25.78 |   | 309,287 |   |
| October    |       | 25.92                                       |       | 25.00 |   | 25.85 |   | 150,078 |   |
| November   |       | 26.00                                       |       | 25.66 |   | 25.76 |   | 161,243 |   |
| December   |       | 26.23                                       |       | 25.63 |   | 25.82 |   | 302,413 |   |

 

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Subordinated Notes

 

Our 7.35% subordinated notes due 2043 (7.35% Notes) are listed and traded on the TSX under the trading symbol “NXY.PR.U” and on the NYSE under the trading symbol “NXYPRB”. The following table provides the market price ranges and the aggregate volume of trading of the 7.35% Notes on the TSX and NYSE for the periods indicated:

 
| ** ** | ** ** | **Toronto Stock Exchange   Cdn$** | ** ** | **New York Stock Exchange   US$** | ** ** |
|------------|------------|---------------------------------------------|------------|--------------------------------------------------|------------|
| **2012**   | ** ** | **High**                                    | ** ** | **Low**                                          | ** ** | **Close** | ** ** | **Volume** | ** ** | **High** | ** ** | **Low** | ** ** | **Close** | ** ** | **Volume** | ** ** |
| January    |       | 25.80                                       |       | 25.10                                            |       | 25.77 |   | 17,056 |   | 25.66 |   | 25.20 |   | 25.35 |   | 206,454 |   |
| February   |       | 25.64                                       |       | 25.11                                            |       | 25.30 |   | 43,419 |   | 25.45 |   | 25.16 |   | 25.27 |   | 887,566 |   |
| March      |       | 25.65                                       |       | 25.25                                            |       | 25.42 |   | 45,568 |   | 25.44 |   | 25.12 |   | 25.30 |   | 3,706,735 |   |
| April      |       | 25.48                                       |       | 25.15                                            |       | 25.27 |   | 18,349 |   | 25.60 |   | 25.05 |   | 25.34 |   | 274,220 |   |
| May        |       | 25.45                                       |       | 25.08                                            |       | 25.17 |   | 19,847 |   | 25.38 |   | 25.10 |   | 25.15 |   | 391,797 |   |
| June       |       | 25.50                                       |       | 25.14                                            |       | 25.30 |   | 16,038 |   | 25.54 |   | 25.08 |   | 25.47 |   | 211,401 |   |
| July       |       | 25.60                                       |       | 25.25                                            |       | 25.32 |   | 24,888 |   | 25.60 |   | 25.14 |   | 25.30 |   | 308,504 |   |
| August     |       | 25.75                                       |       | 25.31                                            |       | 25.49 |   | 13,585 |   | 25.71 |   | 25.28 |   | 25.60 |   | 156,067 |   |
| September  |       | 25.65                                       |       | 25.36                                            |       | 25.50 |   | 13,547 |   | 25.60 |   | 25.39 |   | 25.43 |   | 138,909 |   |
| October    |       | 25.75                                       |       | 25.30                                            |       | 25.45 |   | 31,566 |   | 25.80 |   | 25.21 |   | 25.48 |   | 122,703 |   |
| November   |       | 25.60                                       |       | 25.31                                            |       | 25.60 |   | 9,961 |   | 25.56 |   | 25.30 |   | 25.45 |   | 164,986 |   |
| December   |       | 25.50                                       |       | 25.31                                            |       | 25.35 |   | 18,990 |   | 25.49 |   | 25.24 |   | 25.46 |   | 270,691 |   |

 

Prior Sales

 

For information in respect of share issuances related to the exercise of stock options and our dividend reinvestment plan, see Note 18 to our annual Consolidated Financial Statements for the year ended December 31, 2012, which are incorporated by reference into this AIF.

 

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**DIRECTORS**

 

According to our Articles, Nexen must have between three and 15 directors. Our By-Laws provide that directors will be elected at the annual general meeting (AGM) each year and will hold office until the following AGM when their successors are elected. The following is a list of our directors as at February 24, 2013.

 
| **Name ****(Age)**                 | ** ** | **Residence**                       | ** ** | **Principal Occupation ****1**                                                                                                                                                                                                                                                                                                        | ** ** | **Other Directorships**                                                                  | ** ** | **Nexen   Director   Since** |
|-----------------------------------------|------------|-------------------------------------|------------|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|-----------------------------------------------------------------------------------------------|------------|------------------------------|
| William B. Berry 3 (60)            |       | Houston, Texas

United States       |       | Retired oil and gas executive

Formerly: Executive Vice President of   ConocoPhillips                                                                                                                                                                                                                                                           |       | Teekay Corporation

Willbros Group, Inc.                                                 |       | 2008                         |
| Robert G. Bertram, O.C.3 (68)      |       | Aurora, Ontario

Canada             |       | Retired pension investment executive

Formerly: Executive Vice President of Ontario   Teachers’ Pension Plan Board                                                                                                                                                                                                                         |       | Strathbridge Asset Management Inc. 2                                                          |       | 2009                         |
| Thomas W. Ebbern 3 (54)            |       | Calgary, Alberta

Canada            |       | CFO of Northwest Upgrading Inc.

Formerly: Managing director of Macquarie Capital   Markets Canada Ltd.                                                                                                                                                                                                                                         |       | HRT Participacoes em Petroleo S.A.                                                            |       | 2011                         |
| S. Barry Jackson (60)                   |       | Calgary, Alberta

Canada            |       | Corporate director

Retired oil and gas executive                                                                                                                                                                                                                                                                                               |       | TransCanada Corporation (Chair)

TransCanada PipeLines Limited (Chair)

WestJet Airlines Ltd. |       | 2001                         |
| Kevin J. Jenkins (56)                   |       | Windsor, Berkshire

United Kingdom  |       | President and Chief Executive Officer of World   Vision International

Formerly: Managing Director of TriWest Capital   Partners                                                                                                                                                                                                                |       | —                                                                                        |       | 1996                         |
| A. Anne McLellan, P.C., O.C. (62)       |       | Edmonton, Alberta

Canada           |       | Counsel with Bennett Jones LLP, Barristers and Solicitors,   and Distinguished Scholar in Resident at the University of Alberta in the   Institute for United States Policy Studies

Formerly: Member of Parliament for Edmonton   Centre, Deputy Prime Minister, Minister of Public Safety and Emergency   Preparedness and Minister of Health |       | Agrium Inc.

Cameco Corporation                                                               |       | 2006                         |
| Eric P. Newell, O.C. (68)               |       | Edmonton, Alberta

Canada           |       | Retired oil executive                                                                                                                                                                                                                                                                                                                           |       | —                                                                                        |       | 2004                         |
| Thomas C. O’Neill 3 (67)      |       | Toronto, Ontario

Canada            |       | Retired chartered accountant                                                                                                                                                                                                                                                                                                                    |       | Adecco S.A.

BCE Inc. (Chair)

Loblaw Companies Limited

The Bank of Nova Scotia              |       | 2002                         |
| Kevin J. Reinhart (54)                  |       | Calgary, Alberta

Canada            |       | Interim President and CEO of Nexen

Formerly: Executive Vice President and CFO; Senior   VP and CFO; Senior VP, Corporate Planning and Business Development                                                                                                                                                                                     |       | —                                                                                        |       | 2012                         |
| Francis M. Saville, Q.C. (74)           |       | Calgary, Alberta

Canada            |       | Former Chair of Nexen

Formerly: Counsel with Fraser Milner Casgrain LLP,   Barristers and Solicitors                                                                                                                                                                                                                                           |       | —                                                                                        |       | 1994                         |
| Arthur R.A. Scace C.M., Q.C.3 (74) |       | Toronto, Ontario

Canada            |       | Retired lawyer

Formerly: Partner and Chair of McCarthy Tetrault   and Chair of Bank of Nova Scotia                                                                                                                                                                                                                                             |       | Fiera Capital Corporation

WestJet Airlines Ltd.                                              |       | 2011                         |
| John M. Willson (73)                    |       | Vancouver, British Columbia, Canada |       | Retired mining executive                                                                                                                                                                                                                                                                                                                        |       | —                                                                                        |       | 1996                         |
| Victor J. Zaleschuk 4 (69)         |       | Calgary, Alberta

Canada            |       | Retired oil and gas executive                                                                                                                                                                                                                                                                                                                   |       | Agrium Inc. (Chair)

Cameco Corporation (Chair)                                               |       | 1997                         |

 

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*(1)**        **Current and within the past five years.*

*(2)**        **An investment management fund organization managing a series of closed-end funds listed on the TSX. Mr. Bertram is a board member and participates in the audit committee function for five exchange-listed funds.*

*(3)**        **Audit committee financial expert under US regulatory requirements.*

*(4)**        **Mr. Zaleschuk was President and CEO of Nexen from 1997 to 2001.*

 

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Previous Directorships

 

The following table details the previous directorships held by our directors over the last five years at public and registered investment companies.

 
| **Name** | ** ** | **Company**                                                                                                            |
|----------|------------|------------------------------------------------------------------------------------------------------------------------|
| Jackson  |       | Cordero Energy Inc.                                                                                                    |
| Reinhart |       | Canexus                                                                                                                |
| Scace    |       | Garbell Holdings Limited, Gerdau AmeriSteel   Corporation, Sceptre Investment Counsel Limited, The Bank of Nova Scotia |
| Willson  |       | Finning International Inc., Harry Winston Diamond   Corp., Pan American Silver Corp.                                   |

 

Conflicts of Interest

 

As described on page 51, certain of Nexen’s directors are associated with other issuers engaged in the oil and gas industry and the interests of these directors could come into conflict with the interests they hold in these other issuers. In the event of a conflict of interest, Canadian legislation requires the director to disclose to Nexen the nature and extent of any interest they have in a material contract or material transaction, if the director is a party to the contract or transaction in question, if the director is a director or an officer of a party to the contract or transaction in question or has a material interest in a party to the contract or transaction. Nexen’s Integrity Guide also sets forth a detailed process for dealing with conflicts of interest.

 

Board Committees 1

 
| ** **                                    | ** ** | **Audit ****2** | ** ** | **Compensation** | ** ** | **Governance** | ** ** | **Finance** | ** ** | **HSE & SR** | ** ** | **Reserves** |
|-----------------------------------------------|------------|----------------------|------------|------------------|------------|----------------|------------|-------------|------------|----------------------------|------------|--------------|
| **Executive Director — Not Independent** |       |                 |       |             |       |           |       |        |       |                       |       |         |
| Kevin J. Reinhart                             |       |                 |       |             |       |           |       |        |       |                       |       |         |
| **Independent Outside Directors**             |       |                 |       |             |       |           |       |        |       |                       |       |         |
| William B. Berry 3                            |       | ·               |       | ·           |       |           |       |        |       |                       |       | Chair        |
| Robert G. Bertram, O.C. 3, 4                  |       | ·               |       |             |       | ·         |       | ·      |       |                       |       |         |
| Thomas W. Ebbern 3                            |       | ·               |       |             |       |           |       | ·      |       |                       |       | ·       |
| S. Barry Jackson (Board   Chair)              |       |                 |       | ·           |       | ·         |       | ·      |       |                       |       |         |
| Kevin J. Jenkins                              |       |                 |       | Chair            |       | ·         |       |        |       |                       |       |         |
| A. Anne McLellan, P.C.,   O.C.                |       |                 |       |             |       |           |       | ·      |       | ·                     |       |         |
| Eric P. Newell, O.C.                          |       |                 |       |             |       |           |       |        |       | Chair                      |       | ·       |
| Thomas C. O’Neill 3                      |       | Chair                |       | ·           |       |           |       |        |       |                       |       |         |
| Francis M. Saville, Q.C.                      |       |                 |       |             |       | Chair          |       |        |       | ·                     |       |         |
| Arthur R.A. Scace, C.M.,   Q.C. 3             |       | ·               |       | ·           |       | ·         |       |        |       |                       |       |         |
| John M. Willson                               |       |                 |       |             |       |           |       |        |       | ·                     |       | ·       |
| Victor J. Zaleschuk                           |       |                 |       |             |       |           |       | Chair       |       | ·                     |       | ·       |
| **Total Members**                             | ** ** | **5**                | ** ** | **5**            | ** ** | **5**          | ** ** | **5**       | ** ** | **5**                      | ** ** | **5**        |

 

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*(1)   All committee members are independent. Mr. Reinhart does not serve on any board committees for Nexen.*

*(2)**        **All Audit Committee members are independent and financially literate under additional regulatory requirements applicable to them. Experience of the members of the Audit Committee that indicates an understanding of the accounting principles we use to prepare our financial statements is shown on page 53.*

*(3)**        **Audit Committee financial expert under US regulatory requirements.*

*(4)**        **Mr. Bertram is a board member and participates in the audit committee function for five exchange-listed funds. The funds are related managed entities and limited in business purpose as investment funds. They are restricted to a mandate of a limited number of specific securities and dealt with as a group, making preparation and review time significantly less than would be associated with a single full-operating business. The board has considered and determined that Mr. Bertram’s participation in these funds does not impede his ability to fully carry out his duties as a director and committee member of Nexen.*

 

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**AUDIT COMMITTEE INFORMATION**

 

Each member of the Audit Committee has a thorough understanding of accounting principles and has the ability to assess the application of accounting principles in connection with the preparation of financial statements and the accounting for estimates, accruals and reserves. Audit Committee members have an understanding of internal controls and procedures for financial reporting and have experience preparing, auditing, analyzing or evaluating financial statements or actively supervising individuals engaged in such activities. In 2012, there were changes in Audit Committee membership. Mr. Jenkins and Mr. Newell left the committee in January 2012 and Mr. Flanagan retired in April 2012. Below is a description of each current Audit Committee member’s education and experience.

 

Audit Committee Education and Experience

 
| **Name**         | ** ** | **Experience**                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 |
|------------------|------------|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| ** **       |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           |
| **Berry**        |       | William   Berry is a retired oil and gas executive. From 2003 to 2008, he was Executive   Vice President of ConocoPhillips. He also held other senior executive   positions with Phillips Petroleum Co., including Senior Vice President,   Exploration and Production. His career in the oil and gas industry began in   1976 and includes experience working in Africa, the North Sea, Asia, Russia,   the Caspian Sea and North America.

 

Mr. Berry   has Bachelor and Masters of Science degrees in Petroleum Engineering from   Mississippi State University. He was responsible for understanding the   financial reporting of exploration and production at ConocoPhillips and   finance managers reporting directly to him on a functional basis. He held   various management roles, including Manager, Corporate Planning and   Budgeting.                                                                                                                                              |
| ** **       |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           |
| **Bertram**      |       | Robert   Bertram is a retired pension investment executive. He was the Executive Vice   President of Ontario Teachers’ Pension Plan Board (Teachers) from 1990 to   2008. He led Teachers’ investment program and oversaw the pension fund’s   growth from $19 billion when it was established in 1990 to $108.5 billion.   Prior to that, he spent 18 years at Telus Corporation, formerly Alberta   Government Telephones, where his responsibilities included investment   management, capital procurement, corporate risk management, tax and   compliance. Before leaving Telus, he was Assistant Vice President and   Treasurer.

 

Mr. Bertram   has a Bachelor of Arts degree in history from the University of Calgary and a   Master of Business Administration from the University of Alberta. He is a   Chartered Financial Analyst (CFA) charter holder.                                                                                                                |
| ** **       |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           |
| **Ebbern**       |       | Tom   Ebbern is the Chief Financial Officer of North West Upgrading Inc. He was   formerly Managing Director, Investment Banking, of Macquarie Capital   Markets Canada Ltd., a subsidiary of Macquarie Group Limited. Prior to that,   he was Managing Director of Tristone Capital Inc., an energy advisory firm   that was acquired by Macquarie. Mr. Ebbern’s various positions have   provided him with years of energy experience in exploration, business   development, and oil and gas investment banking and research.

 

Mr. Ebbern   has a Bachelor of Science degree in Geological Engineering from Queen’s   University and a Masters of Business Administration degree from the Richard   Ivey School of Business at the University of Western Ontario.                                                                                                                                                                                                          |
| ** **       |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           |
| **O’Neill** |       | Tom   O’Neill is the retired Chair of PwC Consulting. He was formerly CEO of PwC   Consulting; COO of PricewaterhouseCoopers LLP, Global; CEO of   PricewaterhouseCoopers LLP, Canada and Chair and CEO of Price Waterhouse   Canada. He worked in Brussels in 1975 to broaden his international experience   and from 1975 to 1985 was lead partner for numerous multinational companies,   specializing in dual Canadian and US listed companies.

 

Mr. O’Neill   has a Bachelor of Commerce Degree from Queen’s University. He received his   Chartered Accountant designation in 1970 and was made a Fellow (FCA) of the   Institute of Chartered Accountants of Ontario in 1988. Mr. O’Neill   lectured on Political Economics at the University of Toronto, taught courses   in commerce and finance, and has been actively involved in a number of   associations, including various committees of the Canadian and Ontario   Institutes of Chartered Accountants. |
| ** **       |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           |
| **Scace**        |       | Arthur   Scace is a retired lawyer. He was formerly Partner and Chair of McCarthy Tetrault   LLP, Barristers and Solicitors in Toronto. He was also formerly Chair of The   Bank of Nova Scotia. Specializing in tax law, Mr. Scace has provided   advice in many domestic and international commercial transactions,   co-authored The Income Tax Law of Canada, headed up tax law courses and   lectured at various schools and universities.

 

Mr. Scace   holds his Bachelor of Arts degrees from the University of Toronto and Oxford   University, a Master of Arts degree from Harvard University and a Bachelor of   Laws degree from Osgoode Hall Law School.                                                                                                                                                                                                                                                                                                                        |

 

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The Audit Committee mandate is included in Appendix A of this AIF.

 

All Committee mandates, including those for the Audit, Compensation and Governance Committees, our code of ethics and our corporate governance policy and categorical standards are available at www.nexeninc.com. Shareholders wishing to receive a copy of these documents may write to the Governance Office by mail at Nexen Inc., 801 — 7th Avenue SW, Calgary, Alberta, Canada T2P 3P7, Attention: Governance Office or by email at governance@nexeninc.com.

 

**INDEPENDENT REGISTERED CHARTERED ACCOUNTANTS (IRCA) FEES**

 

Pre-Approval Policies and Procedures

 

Nexen has adopted policies and procedures with respect to the pre-approval of audit and permitted non-audit services to be provided by the IRCA. The Audit Committee approves all services provided by the IRCA and the related fees. The services are sufficiently detailed to ensure that: i) the Audit Committee understands the services it is being asked to pre-approve; and ii) Nexen’s management does not need to make a judgement as to whether a proposed service fits within the pre-approved services. The pre-approval policies are further described in the Audit Committee mandate included in Appendix A of this AIF.

 

IRCA services that arise that were not pre-approved by the Audit Committee must be pre–approved by the Audit Committee chair between committee meetings. The Audit Committee is informed of the services at the following meeting. Nexen did not rely on the de minimus exemption provided by Section (c)(7)(i)(C) of Rule 2-01 of SEC Regulation S-X in either 2012 or 2011.

 

IRCA Fees Billed

 

The following table provides information about the fees billed to Nexen for professional services rendered by the IRCA during 2012 and 2011.

 
| **Type of Fee** | ** ** | **Billed in 2011 ****1** | ** ** | **Billed in 2012** | ** ** | **Percentage of Total********Fees Billed in 2012** | ** ** |
|---------------------------|------------|-----------------------------------------|------------|------------------------------|------------|-----------------------------------------------------------------------------|------------|
| Audit Fees 2              |       | 2,678,492                               |       | 2,867,976                    |       | 63                                                                          | %          |
| Audit-Related Fees 3      |       | 702,332                                 |       | 1,106,638                    |       | 24                                                                          | %          |
| Tax Fees 4                |       | 69,291                                  |       | 60,138                       |       | 1                                                                           | %          |
| All Other Fees 5          |       | 555,078                                 |       | 537,269                      |       | 12                                                                          | %          |
| **Total Annual Fees**     | ** ** | **4,005,193**                           | ** ** | **4,572,021**                | ** ** | **100**                                                                     | **%**      |

 

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*(1)**        **Fees billed in 2011 exclude fees related to Canexus as our remaining interest was sold in early 2011.*

*(2)**        **Audit fees were paid to the IRCA for the audit of annual financial statements or services provided in connection with statutory and regulatory filings or engagements.*

*(3)**        **Audit-related fees consist of fees for assurance and related services that are reasonably related to the performance of the audit or review of subsidiary financial statements and are not reported as Audit Fees.*

*(4)**        **Tax fees were paid to the IRCA for tax compliance services and tax-related consultation.*

*(5)**        **Other fees were paid to the IRCA for subscriptions to auditor-provided and supported tools.*

 

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**EXECUTIVE OFFICERS**

 

The board determines the term of office for each executive officer. Below are Nexen’s executive officers as at February 24, 2013, including prior offices and non-executive positions for each of them during the past five years. Start dates with Nexen are indicated for officer positions.

 
| **Name ****(Age)**  | ** ** | **Residence**            | ** ** | **Principal Occupation ****1**                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    | ** ** | **Effective Date of   Current Position** | ** ** | **Executive   Officer   Since** |
|--------------------------|------------|--------------------------|------------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|---------------------------------------------------------|------------|---------------------------------|
| ** **               | ** ** | ** **               | ** ** | ** **                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                  | ** ** | ** **                                              | ** ** | ** **                      |
| Kevin J. Reinhart (54)   |       | Calgary, Alberta Canada  |       | Interim   President and CEO and a director.

 

Formerly:   Executive VP and CFO since April 27, 2010; Senior VP and CFO since   January 1, 2009; Senior VP, Corporate Planning and Business Development   since November 1, 2007.                                                                                                                                                                                                                                                                                      |       | January 9, 2012                                    |       | 1994                            |
|                     |       |                     |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        |       |                                                    |       |                            |
| Una M. Power (48)        |       | Calgary, Alberta, Canada |       | Interim   CFO and Senior VP, Corporate Planning and Business Development.

 

Formerly:   Senior VP Corporate Planning and Business Development since April 27,   2010; VP, Corporate Planning and Business Development since January 16,   2009; Treasurer since July 11, 2002.                                                                                                                                                                                                                                        |       | January 9, 2012                                    |       | 1998                            |
|                     |       |                     |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        |       |                                                    |       |                            |
| Catherine J. Hughes (50) |       | Calgary, Alberta, Canada |       | Executive   VP, International Oil and Gas.

 

Formerly:   Interim Executive VP, International and VP Operational Services and   Technology since November 28, 2011; VP, Operational Services, Technology   and Human Resources since February 17, 2010; Division VP, Operational   Services, Technology and Human Resources since December 1, 2009;   Division VP, Operational Services and Technology since September 1,   2009; VP Oil Sands at Husky Oil Operations Ltd. since October 1, 2007. |       | January 23, 2012                                   |       | 2010                            |
|                     |       |                     |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        |       |                                                    |       |                            |
| James T. Arnold (53)     |       | Calgary, Alberta, Canada |       | Senior   VP, Oil Sands.

 

Formerly:   Senior VP, Synthetic Crude since July 16, 2009; Division VP Operations   and Projects, Synthetic Oil since February 1, 2009; Chief Operating   Officer at OPTI Canada Inc. since October 13, 2005.                                                                                                                                                                                                                                                                              |       | February 15, 2012                                  |       | 2009                            |
|                     |       |                     |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        |       |                                                    |       |                            |
| Ronald W. Bailey (48)    |       | Calgary, Alberta, Canada |       | Senior   VP, Natural Gas Canada and Operational Services and Technology.

 

Formerly:   Senior VP, Canada since February 15, 2012; Division VP, Natural   Gas-Canada since November 1, 2011; Division VP, Shale Gas-Canada since   December 1, 2010; GM, Gas-Shale Exploration and Development since   February 1, 2009; GM, Gas-CBM/Conventional since August 1, 2005.                                                                                                                                      |       | April 25, 2012                                     |       | 2012                            |
|                     |       |                     |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        |       |                                                    |       |                            |
| Alan O’Brien (55)   |       | Calgary, Alberta, Canada |       | Senior   VP, General Counsel and Secretary.

 

Formerly:   Interim Senior VP, General Counsel and Secretary since December 2, 2011;   Division VP, Chief Legal Counsel, International since November 30,   2010; Division VP, Chief Legal Counsel, NPUL since July 1, 2006.                                                                                                                                                                                                                                       |       | January 23, 2012                                   |       | 2012                            |
|                     |       |                     |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        |       |                                                    |       |                            |
| Kim D. McKenzie (64)     |       | Calgary, Alberta, Canada |       | VP   and Chief Information Officer.

 

Formerly:   Division VP, Information Technology since January 1, 1992.                                                                                                                                                                                                                                                                                                                                                                                                               |       | November 1, 2007                                   |       | 2007                            |
|                     |       |                     |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        |       |                                                    |       |                            |
| Kevin J. McLachlan (49)  |       | Calgary, Alberta, Canada |       | VP,   Global Exploration.

 

Formerly:   Division VP, Global Exploration since July 1, 2009; Division   VP, International Exploration since August 1, 2008; Manager,   Exploration, since January 1, 2006.                                                                                                                                                                                                                                                                                                        |       | February 17, 2010                                  |       | 2010                            |
|                     |       |                     |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        |       |                                                    |       |                            |
| Quinn E. Wilson (43)     |       | Calgary, Alberta, Canada |       | VP,   Human Resources and Corporate Services.

 

Formerly:   Division VP, Global Human Resources since January 1, 2011; Division VP   Human Resources, International since August 16, 2010; VP, HR Global   Business Partners at Flextronics since August 1, 2007.                                                                                                                                                                                                                                                |       | November 28, 2011                                  |       | 2011                            |
|                     |       |                     |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        |       |                                                    |       |                            |
| Brendon T. Muller (44)   |       | Calgary, Alberta, Canada |       | Controller   and VP, Insurance.

 

Formerly:   Controller since April 9, 2007.                                                                                                                                                                                                                                                                                                                                                                                                                                              |       | April 27, 2011                                     |       | 2007                            |
|                     |       |                     |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        |       |                                                    |       |                            |
| J. Michael Backus (42)   |       | Calgary, Alberta, Canada |       | Treasurer.

 

Formerly:   Manager, Planning, Synthetic Crude since January 1, 2009; Project   Planner — Phase 2 Long Lake, Synthetic Crude since April 1, 2005.                                                                                                                                                                                                                                                                                                                                                        |       | February 16, 2009                                  |       | 2009                            |

 

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**OTHER**

 

Legal Proceedings and Regulatory Actions

 

Nexen is party to various legal proceedings, both as a claimant and as a defendant, the ultimate results of which cannot be ascertained at this time. Management is of the opinion that any amounts awarded to us or assessed against us would not have a material effect on our consolidated financial position or results of operations. In any event, there are no legal proceedings to which we are a party or which our property is the subject of, nor are there any proceedings known by us to be contemplated that involves a claim for damages exceeding 10% of our current assets. We believe we have made adequate provisions for such lawsuits and claims.

 

Certain of our US oil and gas operations have received, over the years, notices and demands from the US EPA, state environmental agencies and certain third parties for certain sites seeking to require investigation and remediation under federal or state environmental statutes. In addition, notices, demands and lawsuits have been received for certain sites related to historical operations and activities in the US. Although no assurances can be made, we believe that certain assumption and indemnification agreements protect our US operations from any present or future material liabilities that may arise from these particular sites.

 

During the year ended December 31, 2012, there have been no: i) penalties or sanctions imposed against Nexen or its subsidiaries by a court relating to securities legislation or by a securities regulatory authority; or ii) settlement agreements entered into by Nexen or its subsidiaries before a court relating to securities legislation or with a securities regulatory authority. There have been no penalties or sanctions imposed by a court or regulatory body relating to any other legislation against Nexen or its subsidiaries that would likely be considered important to a reasonable investor in making an investment decision.

 

Interests of Management and Others in Material Transactions

 

No director or executive officer of Nexen or its subsidiaries, or any person or company that beneficially owns or controls or directs, directly or indirectly, more than 10% of Nexen’s outstanding voting securities or any associate or affiliate of these persons currently has, or has had, any material interests in any transaction or any proposed transaction that has materially affected or is reasonably expected to materially affect Nexen or any of Nexen’s subsidiaries, within the three most recently completed financial years or during the current financial year.

 

Shareholdings of Directors and Executive Officers

 

At December 31, 2012, Nexen’s directors and executive officers as a group beneficially own, directly or indirectly, or exercise control or direction over, less than 1% of Nexen’s issued and outstanding common shares.

 

Cease Trade Orders, Bankruptcies, Penalties or Sanctions

 

As of the date of this AIF, we confirm that, to the best of our knowledge:

 

a)             in the last 10 years, no director or executive officer of Nexen is or has been a director, chief executive officer or chief financial officer of another company or has owned a personal holding company that:

 

i.                                          was subject to a cease trade order or an order similar to a cease trade order or an order that denied the relevant company access to any exemption under securities legislation that was in effect for a period of more than 30 consecutive days (an order) while the director or executive officer was acting as a director, chief executive officer or chief financial officer; or

ii.                                       was subject to an order after the director or executive officer ceased to be a director, chief executive officer or chief financial officer in the company and which resulted from an event that occurred while that person was acting in the capacity as a director, chief executive officer or chief financial officer.

 

b)             in the last 10 years, no director or executive officer of Nexen has been a director or executive officer of a company that became bankrupt or made a proposal under any legislation relating to bankruptcy or insolvency or was subject to or instituted any proceedings, arrangement or compromise with creditors or had a receiver, receiver manager or trustee appointed to hold its assets while the director or executive officer was acting as a director or executive officer of such company or within a year of ceasing to act in that capacity;

 

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c)              no director or executive officer of Nexen nor any personal holding company controlled by such person has become bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency or become subject to or instituted any proceedings, arrangement or compromise with creditors, or had a receiver, receiver manager or trustee appointed to hold the assets of the director or executive officer; and

 

d)             no director or executive officer of Nexen has been subject to:

 

i.                                    any penalties or sanctions imposed by a court relating to securities legislation or by a securities regulatory authority or has entered into a settlement agreement with a securities regulatory authority; or

ii.                                 any other penalties or sanctions imposed by a court or regulatory body that would likely be considered important to a reasonable investor in making an investment decision.

 

Transfer Agents and Trustees

 

In Canada, CIBC Mellon Trust Company (CIBC Mellon) is our transfer agent and registrar of Nexen’s common shares, and Series 2 Shares. Canadian Stock Transfer Company Inc. acts as the administrative agent for CIBC Mellon. They are located at:

 

CIBC Mellon Trust Company

c/o Canadian Stock Transfer Company Inc.

320 Bay Street

Toronto, ON M5H 4A6

 

In the United States, Computershare Shareowner Services is our co-transfer agent of Nexen’s common shares. They are located at:

 

Computershare Shareowner Services

480 Washington Blvd., 27th Fl.

Jersey City, NJ 07310

 

Deutsche Bank Trust Company Americas, 60 Wall Street, 27th Floor, Mailstop NYC 60-2710, New York, New York 10005-2858, acts as trustee for the 7.35% Notes listed on the TSX and NYSE.

 

Material Contracts

 

*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 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.

 

Interest of Experts

 

Deloitte LLP is our Independent Registered Chartered Accountant and are independent with respect to Nexen within the meaning of the Rules of Professional Conduct of the Institute of Chartered Accountants of Alberta and the rules and standards of the Public Company Accounting Oversight Board (United States) and the securities laws and regulations administered by the SEC.

 

Information related to reserves in this AIF was reviewed by McDaniel & Associates Consultants Ltd., Ryder Scott Company LP and DeGolyer and MacNaughton, each of which is an independent qualified reserves evaluator.

 

As of the date hereof, none of the partners, principals, employees or consultants of McDaniel & Associates Consultants Ltd., Ryder Scott Company LP or DeGolyer and MacNaughton, through registered or beneficial interests, directly or indirectly, held, or are entitled to receive more than 1% of any class of Nexen’s outstanding securities, including the securities of our associates and affiliates.

 

The information relating to the Company’s NI 51-101 reserves as at December 31, 2012 incorporated by reference in this AIF has been compiled by the Company based on the report dated February 24, 2013 prepared by Mr. Ian R. McDonald, an employee of Nexen, in his capacity as the Company’s Internal Qualified Reserves Evaluator. Mr. McDonald beneficially owns, directly or indirectly, less than 1% of any class of the Company’s securities.

 

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Additional Information

 

Nexen is a Canadian issuer that is registered with the Canadian securities commissions and the SEC and trades on both the TSX and NYSE. Additional information relating to the Company can be found on the SEDAR website at www.sedar.com and on EDGAR at www.sec.gov.

 

Additional information including directors’ and officers’ remuneration and indebtedness, director nominees standing for re-election, principal holders of the Company’s securities, and securities authorised for issuance under the Company’s equity compensation plans, is contained in the Company’s Proxy Circular for the 2012 Annual General Meeting of Shareholders.

 

Additional financial information is provided in our MD&A and Consolidated Financial Statements for the most recently completed financial year.

 

Copies of our annual report may be obtained free of charge from Nexen’s website at www.nexeninc.com or upon request from:

 

Investor Relations

Nexen Inc.

701 – 8th Avenue S.W.

Calgary, Alberta T2P 3P7

(403) 699-5454

 

Information located on or accessible through Nexen’s website does not form part of this AIF and is not incorporated by reference herein, unless specifically otherwise stated.

 

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**APPENDIX A — AUDIT AND CONDUCT REVIEW COMMITTEE MANDATE**

 

Audit and Conduct Review Committee Mandate

 

The Audit and Conduct Review Committee (Committee) of the board of directors (board) of Nexen Inc. (Nexen) has the oversight responsibility and specific duties described below.

 

**COMPOSITION**

 

The Committee will be comprised of at least three directors. All Committee members will be independent under the Categorical Standards for Director Independence (Categorical Standards) adopted by the board and applicable law. Any Committee member who, for any reason, is no longer independent under the Categorical Standards or applicable law immediately ceases to be a Committee member.

 

All Committee members will be “financially literate” under the definition adopted by the board. At least one Committee member shall be designated as an “audit committee financial expert” under applicable law.

 

Committee members may not serve on the audit committees of more than two additional public companies without the approval of the board.

 

Committee members will be appointed and removed by the board. The Committee Chair will be appointed by the board.

 

**RESPONSIBILITY**

 

The Committee’s primary purpose is to assist the board in fulfilling its oversight responsibilities with respect to (i) the integrity of annual and quarterly financial statements to be provided to shareholders and regulatory bodies; (ii) compliance with accounting and finance based legal and regulatory requirements; (iii) the independent auditor’s qualifications and independence; (iv) the system of internal accounting and financial reporting controls that Management has established; (v) performance of the internal and external audit process and of the independent auditor; and, (vi) implementation and effectiveness of How We Work: Our Integrity Guide (Our Integrity Guide), which constitutes our code of ethics and the compliance programs.

 

**SPECIFIC DUTIES**

 

The Committee will:

 

*Audit and Conduct Review Leadership*

 

1.                                      Have a clear understanding with the independent auditor that it must maintain an open and transparent relationship with the Committee, and that the ultimate accountability of the independent auditor is to the Committee, as representatives of the shareholders.

 

2.                                      Provide an avenue for communication between each of internal audit (Corporate Audit), the independent auditor, financial and senior Management and the board.

 

3.                                      Review and, in the Committee’s discretion, approve and recommend to the board for consideration Our Integrity Guide, including procedures for (i) the receipt, retention, and treatment of complaints received by Nexen regarding accounting, internal accounting and financial reporting controls, or auditing matters; (ii) the confidential, anonymous submission by employees of concerns regarding questionable accounting or auditing matters; and, (iii) addressing a reporting attorney’s report of a material breach of securities law, material breach of fiduciary duty or similar material violation.

 

4.                                      Take all reasonable steps to oversee the implementation of Our Integrity Guide, including reviewing with Management Our Integrity Guide and the implementation and effectiveness of compliance programs under Our Integrity Guide.

 

5.                                      Take all reasonable steps to oversee conduct review by receiving an annual report summarizing the statements of compliance completed by employees pursuant to the Integrity Program, the Conflict of Interest Policy and the Prevention of Improper Payments Policy and make any resulting inquiries the Committee decides is needed.

 

6.                                      With the board and the board Chair, respond to potential conflict of interest situations.

 

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*Independent Auditor Qualifications and Selection*

 

7.                                       Subject to required shareholder approval of auditors, be solely responsible for selecting, retaining, compensating, overseeing and, where necessary, terminating the independent auditor. The independent auditor will be a “Registered Public Accounting Firm” and a “Participating Audit Firm”, each as defined under applicable law and will report directly to the Committee. The Committee is entitled to adequate funding from Nexen to compensate the independent auditor for completing an audit and audit report or performing other audit, review or attest services.

 

8.                                      Evaluate the independent auditor’s qualifications, performance and independence. As part of that evaluation, at least annually review a report by the independent auditor describing: the firm’s (auditor’s) internal quality control systems and procedures; any material issues, defects, restrictions or sanctions raised or imposed by the most recent internal quality control review, or peer review, of the firm, or by any inquiry or investigation by governmental or professional authorities or board, within the preceding five years, respecting one or more independent audits carried out by the firm or otherwise arising, and any steps taken to deal with any such issues, defects, restrictions or sanctions; and, (to assess the auditor’s independence) all relationships between the independent auditor and Nexen. Take all reasonable steps to satisfy itself that the independent auditor does not provide non-audit services that would disqualify it as independent under applicable law.

 

9.                                      Review the experience and qualifications of the senior members of the independent audit team and the quality control procedures of the independent auditor. Take all reasonable steps to satisfy itself that the lead audit partner of the independent auditor is replaced periodically, according to applicable law. Take all reasonable steps to satisfy itself of the continuing independence of the independent audit firm. Present the Committee’s conclusions on auditor independence to the board.

 

10.                               Recommend guidelines for Nexen’s hiring of partners and employees and former partners and employees of the current and any former independent auditor who were engaged on Nexen’s account to the board for consideration.

 

*Independent Audit Process*

 

11.                               Pre-approve all audit services (which may include comfort letters in connection with securities underwritings). In the discretion of the Committee, annually delegate to the Committee Chair the authority to grant pre-approvals for certain audit services to expedite the hiring of the independent auditor for minor, time-sensitive audit services provided that those pre-approvals are presented in writing to the Committee at the next regularly scheduled meeting. The Committee Chair’s pre-approval authority is limited to audit services required to start before the next regularly scheduled Committee meeting. The Committee Chair will not pre-approve audit services related to Nexen’s integrated audit.

 

12.                               Pre-approve and disclose, as required, the retention of the independent auditor for non-audit services permitted under applicable law. In the discretion of the Committee, annually delegate to one or more of its members the authority to grant pre-approvals for non-audit services provided that those pre-approvals are presented in writing to the Committee at the next regularly scheduled meeting.

 

13.                               Meet with the independent auditor prior to the audit to review the scope and general extent of the independent auditor’s annual audit including (i) the planning and staffing of the audit; and, (ii) an explanation from the independent auditor of the factors considered in determining the audit scope, including the major risk factors.

 

14.                               Require the independent auditor to provide a timely report setting out (i) all critical accounting policies, significant accounting judgments and practices to be used; (ii) all alternative treatments of financial information within Generally Accepted Accounting Principles (GAAP) that have been discussed with Management, ramifications of the use of such alternative disclosures and treatments and the treatment preferred by the independent auditor; and, (iii) other material written communications between the independent auditor and Management.

 

15.                               Take all reasonable steps to satisfy itself that officers and directors or persons acting under their direction are aware that they are prohibited from coercing, manipulating, misleading or fraudulently influencing the independent auditor when the person knew or should have known that the action could result in rendering the financial statements materially misleading.

 

16.                               Upon completion of the annual audit, review the following with Management and the independent auditor:

 

·                                          The annual financial statements, including related footnotes, the MD&A (Management’s Discussion and Analysis of Financial Condition and Results of Operations) and the Annual Information Form (AIF), to be included in Nexen’s Annual Report filed with Canadian and US regulatory agencies.

 

·                                          The significant accounting judgements and reporting principles, practices and procedures applied by Nexen in preparing its financial statements, including any newly adopted accounting policies and the reasons for their adoption.

 

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·                                          Any transactions accounted for by Nexen where Management has obtained opinion letters providing that hypothetical transactions accounted for in a similar manner are accounted for in accordance with GAAP (letters issued in accordance with Statement of Auditing Standards 50 - “Reports on the Application of Accounting Principles”).

 

·                                          The results of the combined audit of the financial statements and internal control over financial reporting; the related audit reports on the financial statements and internal control over financial reporting; and, whether any limitations were placed on the scope or nature of the audit procedures.

 

·                                          Significant changes to the audit plan, if any, and any serious disputes or difficulties with Management encountered during the audit, including any problems or disagreements with Management which, if not satisfactorily resolved, would have caused the independent auditor to issue a non standard report on Nexen’s financial statements.

 

·                                          The co-operation received by the independent auditor during its audit, including access to all requested records, data and information.

 

·                                          Any other matters not described above that are required to be communicated by the independent auditor to the Committee pursuant to auditing standards, rules or regulations in effect at the time.

 

*Risk Management*

 

17.                               Discuss guidelines and policies with respect to risk assessment and risk management, including the processes Management uses to assess and manage Nexen’s risk. Receive reports from Management and the Finance Committee with respect to risk assessment, risk management and major financial risk exposures. Discuss major financial risk exposures and steps Management has taken to monitor and manage such exposures.

 

*Financial Statements and Disclosure*

 

18.                               At least annually, as part of the review of the annual or quarterly financial statements, receive an oral report from Nexen’s general counsel concerning legal and regulatory matters that may have a material impact on the financial statements.

 

19.                               Based on discussions with Management and the independent auditor, in the Committee’s discretion, recommend to the board whether the annual financial statements should be approved for inclusion in Nexen’s Annual Report filed with Canadian and US regulatory agencies.

 

20.                               Review with Management and the independent auditor the quarterly financial statements and MD&A and, subject to delegation by the board to the Committee and in the Committee’s discretion, approve and/or recommend to the board for consideration the quarterly results, financial statements, MD&A, related reports and all earnings news releases prior to filing them with or furnishing them to the applicable securities regulators and prior to any public announcement of financial results for the periods covered, including the results of the independent auditor’s reviews of the quarterly financial statements, significant adjustments, new accounting policies, any disagreements between the independent auditor and Management and the impact on the financial statements of significant events, transactions or changes in accounting principles or estimates that potentially affect the quality of financial reporting.

 

21.                               Review the general types and presentation format of information that it is appropriate for Nexen to disclose in quarterly or annual earnings news releases and annual cashflow or production guidance. Annual production and cashflow guidance is approved through the board’s approval of the Annual Operating Plan. If such guidance is required to be updated during the year, the Committee Chair shall review and approve the updates and report any such change to the Committee at the next Committee meeting.

 

22.                               Receive reports, from time to time, as required, from the Chair or other representative of each of the Finance Committee and the Reserves Review Committee and discuss with them issues of relevance to both the Committee and each of the Finance Committee and the Reserves Review Committee.

 

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*Internal Control Process*

 

23.                         Review with Management, Corporate Audit and the independent auditor, Nexen’s internal control over financial reporting, any significant deficiencies or material weaknesses in their design or operation, any proposed major changes to them and any fraud involving Management or other employees who have a significant role in Nexen’s internal control over financial reporting.

 

24.                         Review the independent auditor’s annual attestation of the internal control over financial reporting structure and procedures.

 

25.                         Review the performance and independence of the Corporate Audit function and whether Corporate Audit has had full access to Nexen’s books, records and personnel.

 

26.                         Review and approve the proposed annual Corporate Audit Plan including assessment of major risks, areas of focus, responsibilities and objectives, and staffing.

 

27.                         Receive periodic reports from Corporate Audit addressing (i) progress on the Corporate Audit Plan, including any significant changes to it; (ii) significant internal audit findings, including issues as to the adequacy of internal control over financial reporting and any procedures implemented in light of significant control deficiencies; and, (iii) any significant internal fraud issues.

 

28.                         Review with Management, the Chief Financial Officer, the Chief Legal Officer, Corporate Audit and the independent auditor the methods used to establish and monitor Nexen’s policies with respect to unethical or illegal activities by employees that may have a material impact on the financial statements.

 

29.                         Meet with Management, Corporate Audit and the independent auditor to discuss any relevant significant recommendations that the independent auditor may have, particularly those characterized as “material” or “serious”. (Typically, such recommendations will be presented by the independent auditor in the form of a Letter of Comments and Recommendations to the Committee.) Review responses of Management to the Letter of Comments and Recommendations from the independent auditor and receive follow up reports on action taken concerning the recommendations.

 

30.                         Receive a report, at least annually, from the Reserves Review Committee on Nexen’s oil and gas reserves, and on the findings of any independent qualified reserves consultants.

 

31.                         Review any appointment or dismissal of the senior internal audit executive (VP, Corporate Audit).

 

32.                         Review with Management and the independent auditor any correspondence with regulators or government agencies and any employee complaints or published reports which raise material issues regarding Nexen’s financial statements or accounting policies.

 

33.                         Review with Management and the independent auditor any off-balance sheet financing mechanisms, transactions or obligations of Nexen.

 

34.                         Regularly review with Management and the independent auditor any related party transactions.

 

35.                         Review with the independent auditor the quality of Nexen’s accounting personnel. Review with Management the responsiveness of the independent auditor to Nexen’s needs.

 

36.                         Receive a report, at least annually, from Management on Nexen’s community investment budget and Nexen and employee donations.

 

*Compliance*

 

37.                         Prepare a letter for the annual report to shareholders and the Annual Report filed with Canadian and US regulatory agencies, disclosing whether or not, with respect to the prior fiscal year (i) Management has reviewed the audited financial statements with the Committee, including a discussion of the quality of the accounting principles as applied and significant judgments affecting Nexen’s financial statements; (ii) the independent auditor has discussed with the Committee the independent auditor’s judgments of the quality of those principles as applied and judgments referenced in (i) above under the circumstances; (iii) the members of the Committee have discussed among themselves, without Management or the independent auditor present, the information disclosed to the Committee described in (i) and (ii) above; and, (iv) the Committee, in reliance on the review and discussions conducted with Management and the independent auditor pursuant to (i) and (ii) above, believes that Nexen’s financial statements are fairly presented in conformity with Canadian GAAP in all material respects and that any reconciliation of Nexen’s financial statements to US GAAP complies with the requirements of the Securities Exchange Act of 1934 (1934 Act).

 

38.                         Receive reports, as required, from Management, Nexen’s VP, Corporate Audit or, to the best of their knowledge, the independent auditor that Nexen’s subsidiary/foreign affiliated entities are in conformity with applicable legal requirements and Our Integrity Guide, including disclosures of insider and affiliated party transactions.

 

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39.                         Review with the independent auditor any reports required to be submitted to the Committee under Section 10A of the 1934 Act (regarding the detection of illegal acts, the identification of related party transactions and the evaluation of whether there is substantial doubt about the ability of Nexen to continue as a going concern).

 

*Committee Reporting*

 

40.                         Following each meeting of the Committee, report to the board on the activities, findings and any recommendations of the Committee.

 

41.                         Report regularly to the board and review with the board any issues that arise with respect to the quality or integrity of Nexen’s financial statements, Nexen’s compliance with applicable law, the performance and independence of Nexen’s independent auditor, and the performance of the Corporate Audit function.

 

42.                         Annually review and approve the Committee’s report for inclusion in the Proxy Circular.

 

43.                         Prepare any reports required to be prepared by the Committee under applicable law.

 

*Committee Meetings*

 

44.                         Meet at least four times annually and as many additional times as needed to carry out its duties effectively. The Committee may, on occasion and in appropriate circumstances, hold a meeting by telephone conference call.

 

45.                         Meet in separate, non-management, closed sessions with the VP, Corporate Audit at each regularly scheduled meeting.

 

46.                         Meet in separate, non-management, closed sessions with the independent auditor at each regularly scheduled meeting.

 

47.                         Meet in separate, non-management, in camera sessions at each regularly scheduled meeting.

 

48.                         Meet in separate, non-management, closed sessions with any other internal personnel or outside advisors, as needed or appropriate.

 

*Committee Governance*

 

49.                         Once or more annually, as the Corporate Governance and Nominating Committee (CGN Committee) decides, receive for consideration that Committee’s evaluation of this Mandate and any recommended changes. Review and assess the CGN Committee’s recommended changes and make recommendations to the board for consideration.

 

*Advisors/Resources*

 

50.                         Have the sole authority to retain, oversee, compensate and terminate independent advisors who assist the Committee in its activities.

 

51.                         Receive adequate funding from Nexen for independent advisors and ordinary administrative expenses that are needed or appropriate for the Committee to carry out its duties.

 

*Other*

 

52.                         Carry out any other appropriate duties and responsibilities assigned by the board.

 

53.                         To honour the spirit and intent of applicable law as it evolves, authority to make minor technical amendments to this Mandate is delegated to the Secretary, who will report any amendments to the CGN Committee at its next meeting.

 

Approved: December 3, 2012

 

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**APPENDIX B— RESERVES ESTIMATES AND SUPPLEMENTARY DATA UNDER SEC REQUIREMENTS**

 

The following reserves estimates have been prepared in accordance with the requirements of the US Securities and Exchange Commission (SEC). We are providing this additional reserves disclosure to enhance comparability to non-Canadian oil and gas companies. The primary differences between SEC requirements and NI 51-101 requirements are set out under the heading “Special Note to Investors” on page 33 of this AIF.

 

All reserves are after-royalty values unless otherwise noted.

 

These estimates are internally prepared. For more information on our reserves evaluation process refer to the section entitled “Basis of Reserves Estimates” on pages 14 to 16 of this AIF.

 

Nexen has not filed with nor included in reports to any Canadian or United States federal authority or agency, any estimates of its total proved oil or gas reserves since the beginning of 2012.

 

Figures in this statement have been rounded to the nearest 1 mmbbls or 1 bcf. As a result, some columns may not add due to rounding.

 

Oil and Gas Reserves Estimates

 

At December 31, 2012, estimated proved reserves were 900 mmboe before royalties and 837 mmboe after royalties. Our probable estimated reserves were 1,217 mmboe before royalties and 1,046 mmboe after royalties. The following is a summary of our proved and probable reserves as at December 31, 2012:

 
| ** **         | ** ** | **Before Royalties**      | ** ** | **After Royalties** | ** ** |
|--------------------|------------|--------------------------------|------------|--------------------------|------------|
| ** **         | ** ** | **Synthetic   Oil   (mmbbls)** | ** ** | **Bitumen   (mmbbls)**   | ** ** | **Oil   (mmbbls)** | ** ** | **Gas   (bcf)** | ** ** | **Synthetic   Oil   (mmbbls)** | ** ** | **Bitumen   (mmbbls)** | ** ** | **Oil   (mmbbls)** | ** ** | **Gas   (bcf)** | ** ** |
| Developed          |       | 219                            |       | —                   |       | 167 |   | 148 |   | 196 |   | — |   | 164 |   | 139 |   |
| Undeveloped        |       | 416                            |       | —                   |       | 64 |   | 58 |   | 385 |   | — |   | 60 |   | 57 |   |
| **Total Proved**   | ** ** | **635**                        | ** ** | **—**               | ** ** | **231** | ** ** | **206** | ** ** | **581** | ** ** | **—** | ** ** | **224** | ** ** | **196** | ** ** |
| Developed          |       | 15                             |       | —                   |       | 74 |   | 115 |   | 12 |   | — |   | 73 |   | 108 |   |
| Undeveloped        |       | 281                            |       | 608                      |       | 208 |   | 67 |   | 242 |   | 510 |   | 180 |   | 61 |   |
| **Total Probable** | ** ** | **296**                        | ** ** | **608**                  | ** ** | **282** | ** ** | **182** | ** ** | **254** | ** ** | **510** | ** ** | **253** | ** ** | **169** | ** ** |

 

About 70% of our proved plus probable reserves relate to our Canadian oil sands properties. The synthetic oil reserves relate to our Long Lake and Kinosis K1A projects (referred to as Long Lake/K1A) and our non-operated interest in Syncrude. These reserves reflect bitumen which is upgraded on site into synthetic oil and are expected to be developed and produced through the existing facilities over the next 50 years. Our Kinosis K1A lands, a subset of the original Kinosis lease, will be developed in conjunction with Long Lake. The bitumen reserves relate to the remaining Kinosis lands (referred to as Kinosis) and the Hangingstone property. Project planning at Kinosis and Hangingstone is underway.

 

The remainder of our reserves are widely distributed throughout our oil and gas properties around the world in our offshore oil and gas operations in the UK North Sea, US Gulf of Mexico, Nigeria and onshore Canada and Colombia.

 

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Proved Reserves

 

The following table provides a summary of the changes in our proved oil and gas reserves after royalties during 2012.

 
| ** **                        | ** ** | **Canada**                     | ** ** | ** **                              | ** ** | ** ** | ** ** | ** **           | ** ** | ** **          | ** ** |
|-----------------------------------|------------|--------------------------------|------------|-----------------------------------------|------------|------------|------------|----------------------|------------|---------------------|------------|
| ** **                        | ** ** | **Oil Sands**             | ** ** | ** **                              | ** ** | ** ** | ** ** | ** **           | ** ** | ** **          | ** ** | ** ** | ** ** |
| **(mmboe)**                       | ** ** | **Syncrude   Synthetic   Oil** | ** ** | **In Situ   Synthetic   Oil****1** | ** ** | **Gas**    | ** ** | **United   Kingdom** | ** ** | **United   States** | ** ** | **Other   Countries ****2** | ** ** | **Total** | ** ** |
| December 31, 2011            |       | 282                            |       | 295                                     |       | 55         |       | 203                  |       | 29                  |       | 36 |   | 900 |   |
| Extensions & Discoveries |       | 7                              |       | 7                                       |       | —     |       | 4                    |       | —              |       | 3 |   | 21 |   |
| Revisions – Technical        |       | —                         |       | (9                                      | )          | (2         | )          | 19                   |       | (1                  | )          | (2 | ) | 5 |   |
| Revisions – Economic         |       | 7                              |       | 4                                       |       | (22        | )          | 1                    |       | (2                  | )          | 1 |   | (11 | ) |
| Divestments                       |       | —                         |       | —                                  |       | (11        | )          | —               |       | —              |       | — |   | (11 | ) |
| Production                        |       | (7                             | )          | (5                                      | )          | (7         | )          | (36                  | )          | (5                  | )          | (7 | ) | (67 | ) |
| **December 31, 2012**        | ** ** | **289**                        | ** ** | **292**                                 | ** ** | **13**     | ** ** | **191**              | ** ** | **21**              | ** ** | **31** | ** ** | **837** | ** ** |

 

----

*(1)   Represents reserves at Long Lake/K1A.*

*(2)   Represents reserves in Yemen, Nigeria and Colombia.*

 

During the year, proved reserves decreased by 63 mmboe primarily as a result of production. Net additions and revisions were largely offset by the sale of Canadian shale gas reserves.

 

Extensions and discoveries primarily relate to additions at Syncrude, the recognition of additional Long Lake acreage delineated through core hole drilling, additional Buzzard well locations and the extension of the Usan reservoir using demonstrated seismic-based technology.

 

Technical revisions resulted in a 5 mmboe net addition. The additions are primarily related to positive performance at our properties in the UK North Sea, and Block 51 in Yemen. These additions were partially offset by negative revisions at Long Lake/K1A primarily related to mapping updates as a result of our core hole drilling program. At Usan and US deep-water, the negative revisions are performance-related. At our Canada gas properties negative revisions are caused by reduced well maintenance programs as a result of low gas prices.

 

Economic revisions were primarily caused by negative revisions from lower North American natural gas prices and operating cost increases partially offset by positive revisions for oil sands properties.

 

Divestments relate to the sale of a 40% interest through a joint venture agreement in our Canadian shale gas assets in northeast British Columbia.

 

Proved Developed and Undeveloped Reserves

 

The following tables provide proved undeveloped reserves (PUDs) at December 31, 2012 and the changes during 2012:

 
| ** **                        | ** ** | **Canada**                     | ** ** | ** **                                    | ** ** | ** ** | ** ** | ** **           | ** ** | ** **          | ** ** |
|-----------------------------------|------------|--------------------------------|------------|-----------------------------------------------|------------|------------|------------|----------------------|------------|---------------------|------------|
| ** **                        | ** ** | **Oil Sands**             | ** ** | ** **                                    | ** ** | ** ** | ** ** | ** **           | ** ** | ** **          | ** ** | ** ** | ** ** |
| **(mmboe)**                       | ** ** | **Syncrude   Synthetic   Oil** | ** ** | **In Situ   Synthetic   Oil ****1** | ** ** | **Gas**    | ** ** | **United   Kingdom** | ** ** | **United   States** | ** ** | **Other   Countries**** 2** | ** ** | **Total** | ** ** |
| December 31, 2011            |       | 116                            |       | 261                                           |       | 16         |       | 49                   |       | 8                   |       | 16 |   | 466 |   |
| Extensions & Discoveries |       | 7                              |       | 7                                             |       | —     |       | 3                    |       | —              |       | 3 |   | 20 |   |
| Revisions – Technical        |       | (1                             | )          | (7                                            | )          | —     |       | 4                    |       | 3                   |       | (3 | ) | (4 | ) |
| Conversions 3                     |       | —                         |       | (5                                            | )          | (2         | )          | (6                   | )          | (5                  | )          | (6 | ) | (24 | ) |
| Revisions – Economic         |       | 2                              |       | 5                                             |       | (8         | )          | —               |       | —              |       | 3 |   | 2 |   |
| Divestments                       |       | —                         |       | —                                        |       | (6         | )          | —               |       | —              |       | — |   | (6 | ) |
| **December 31, 2012**        | ** ** | **124**                        | ** ** | **261**                                       |       | —     | ** ** | **50**               | ** ** | **6**               | ** ** | **13** | ** ** | **454** | ** ** |
| PUD % 4                           |       | 43                             | %          | 89                                            | %          | 0          | %          | 26                   | %          | 29                  | %          | 42 | % | 54 | % |

 

----

*(1)   Represents reserves at Long Lake/K1A.*

*(2)   Represents reserves in Yemen, Nigeria and Colombia.*

*(3)   Technical Revisions.*

*(4)   Determined as a percentage of total proved reserves for that area.*

 

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In 2012, our PUDs decreased by 12 mmboe. Extensions and discoveries relate to Long Lake/K1A where we added reserves as a result of a delineation program, Syncrude where we added an additional year of production, additional wells at Buzzard, Ettrick and Solitaire in the UK and the recognition of additional reservoir at Usan using seismic-based technology. Negative technical revisions relate primarily to remapping at Long Lake/K1A, negative performance revisions at Usan which were partially offset by positive performance revisions in the US and UK. Economic revisions are primarily related to increases at oil sands properties where lower oil prices reduce royalty obligations and reductions from lower North American natural gas prices.

 

Approximately half of our proved reserves are undeveloped at December 31, 2012. More than 80% of these PUDs are located on our Canadian oil sand properties at Long Lake/K1A and Syncrude, which will be developed as we need bitumen feedstock to supply the upgraders during their expected lives. The in situ synthetic oil PUDs relate to reserves needed to supply the Long Lake upgrader over its expected life. They are expected to be converted to proved developed reserves over the next 29 years as we drill additional SAGD wells at Long Lake/K1A to offset declines from the initial wells. These wells were part of the initial field development plan and included in the project investment decision. The Syncrude synthetic oil PUDs relate to Syncrude’s Aurora South mine. The Aurora South mine is included in the Syncrude development plan and was contemplated in the project investment decision relating to the Stage 3 expansion completed in 2005. We do not consider this mine to be developed as the extraction equipment required to access the reserves has not yet been moved to the mine site. We are proceeding with planning for the development of the mine and other mining leases and expect to commence construction in five to six years. The Aurora South mine PUDs of 124 mmboe are expected to be converted to proved developed reserves in eight to ten years.

 

In Canada Gas, we have no remaining PUDs as the existing gas price is insufficient to support economic development of additional dry gas reserves.

 

In the UK North Sea, we have 50 mmboe of PUDs that relate primarily to development projects underway at Golden Eagle, Rochelle, Peregrine and Solitaire, and ongoing development of the Buzzard and Ettrick fields. All of these PUDs are expected to be converted within the next three years.

 

In our other international operations, 13 mmboe of PUDs relate primarily to Usan, offshore Nigeria. They will be converted over the next three years as additional wells are drilled and tied into the production facilities.

 

In 2012, we spent $1.5 billion on developing PUDs to proved developed reserves.

 

During the year, we converted 24 mmboe or about 5% of our PUDs that existed at the end of last year. The conversion rate in 2012 is low because about 85% of the PUDs relate to our oil sand projects at Long Lake/K1A where conversions take place over 29 years as the wells are needed to keep the Long Lake upgrader at capacity, and Syncrude where conversion will occur when the long cycle—time Aurora South mine is completed. Excluding these oil sand projects, we converted 21% of our 2011 PUDs to developed in 2012 and more than 80% of our PUDs over the last three years. We anticipate that our PUD conversion rate will vary considerably from year to year due to the stage and nature of projects associated with our oil and gas assets. The low conversion rate in 2012 is not necessarily indicative of future PUD conversion rates.

 

Excluding Long Lake/K1A and Syncrude, we expect to convert all of our PUDs to developed in the next four years. We have reviewed our PUDs and determined there are no material amounts in individual fields which have remained undeveloped for five years or more after they were initially recognized as proved reserves. We expect our ongoing exploration and development activities to continue to add new PUDs.

 

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Following is a summary of our developed and undeveloped proved oil and gas reserves by country and product at December 31, 2012:

 
| ** **        | ** ** | **Synthetic   Oil   (mmbbls)** | ** ** | **Oil   (mmbbls)** | ** ** | **Gas   (bcf)** | ** ** |
|-------------------|------------|--------------------------------|------------|--------------------|------------|-----------------|------------|
| Canada            |       | 196                            |       | —             |       | 74              |       |
| United Kingdom    |       | —                         |       | 136                |       | 31              |       |
| United States     |       | —                         |       | 10                 |       | 34              |       |
| Other Countries 1 |       | —                         |       | 18                 |       | —          |       |
| **Developed**     | ** ** | **196**                        | ** ** | **164**            | ** ** | **139**         | ** ** |
| Canada            |       | 385                            |       | —             |       | —          |       |
| United Kingdom    |       | —                         |       | 45                 |       | 35              |       |
| United States     |       | —                         |       | 2                  |       | 22              |       |
| Other Countries 1 |       | —                         |       | 13                 |       | —          |       |
| **Undeveloped**   | ** ** | **385**                        | ** ** | **60**             | ** ** | **57**          | ** ** |
|              |       |                           |       |               |       |            |       |
| **Total Proved**  | ** ** | **581**                        | ** ** | **224**            | ** ** | **196**         | ** ** |

 

----

*(1)   Represents reserves in Yemen, Nigeria and Colombia.*

 

Probable Reserves

 

Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. Therefore, probable reserves have a higher degree of uncertainty than proved reserves.

 

At December 31, 2012, we had 1,046 mmboe of probable reserves. During the year, our probable reserves decreased by 76 mmboe. The sale of Canadian shale gas reserves, conversions to proved and economic revisions were partially offset by additions related to projects in the US, oil sands and the UK.

 

The following provides a summary of the changes in our probable oil and gas reserves during 2012:

 
| ** **                        | ** ** | **Canada**                     | ** ** | ** **                         | ** ** | ** **                            | ** ** | ** ** | ** ** | ** **           | ** ** | ** **          | ** ** |
|-----------------------------------|------------|--------------------------------|------------|------------------------------------|------------|---------------------------------------|------------|------------|------------|----------------------|------------|---------------------|------------|
| ** **                        | ** ** | **Oil Sands**             | ** ** | ** **                         | ** ** | ** **                            | ** ** | ** ** | ** ** | ** **           | ** ** | ** **          | ** ** | ** ** | ** ** |
| **(mmboe)**                       | ** ** | **Syncrude   Synthetic   Oil** | ** ** | **In Situ   Synthetic   Oil** | ** ** | **In Situ   Bitumen ****1** | ** ** | **Gas**    | ** ** | **United   Kingdom** | ** ** | **United   States** | ** ** | **Other   Countries ****2** | ** ** | **Total** | ** ** |
| December 31, 2011            |       | 41                             |       | 192                                |       | 540                                   |       | 146        |       | 107                  |       | 69                  |       | 27 |   | 1,122 |   |
| Extensions & Discoveries |       | 7                              |       | 37                                 |       | —                                |       | —     |       | 7                    |       | 89                  |       | — |   | 140 |   |
| Revisions — Technical        |       | —                         |       | (26                                | )          | (1                                    | )          | (7         | )          | 5                    |       | 1                   |       | (1 | ) | (29 | ) |
| Conversions 3                     |       | (7                             | )          | —                             |       | —                                |       | —     |       | (19                  | )          | (2                  | )          | (3 | ) | (31 | ) |
| Revisions — Economic         |       | 1                              |       | 9                                  |       | (29                                   | )          | (75        | )          | (5                   | )          | (1                  | )          | (1 | ) | (101 | ) |
| Divestments                       |       | —                         |       | —                             |       | —                                |       | (55        | )          | —               |       | —              |       | — |   | (55 | ) |
| **December 31, 2012**        | ** ** | **42**                         | ** ** | **212**                            | ** ** | **510**                               | ** ** | **9**      | ** ** | **95**               | ** ** | **156**             | ** ** | **22** | ** ** | **1,046** | ** ** |

 

----

*(1)   Includes reserves for which there are no definitive plans for upgrading at this time.*

*(2)   Represents reserves in Yemen, Nigeria and Colombia.*

*(3)   Technical Revisions.*

 

Extensions and discoveries of 140 mmboe primarily relate to discoveries in the US Gulf of Mexico and additional delineation work for our Long Lake/K1A leases.

 

Technical revisions reduced probable reserves 29 mmboe and primarily reflect reduced oil in place expectations from the core hole drilling program at Long Lake/K1A.

 

Conversions reflect probable reserves that were converted to proved reserves as a result of increased expectations of producing the reserves based on advancement of development plans, positive production performance and/or drilling results.

 

Economic revisions primarily relate to lower North American natural gas prices and delays in our future development plans for bitumen projects. These delays reduced the amount of bitumen expected to be produced over a 50-year production period.

 

Divestments relate to the sale of a 40% interest in our Canadian shale gas assets in northeast British Columbia.

 

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Probable Developed and Undeveloped Reserves

 

Following is a summary of our developed and undeveloped probable oil and gas reserves by country and product at December 31, 2012:

 
| ** **         | ** ** | **Synthetic   Oil   (mmbbls)** | ** ** | **Bitumen   (mmbbls)** | ** ** | **Oil   (mmbbls)** | ** ** | **Gas   (bcf)** | ** ** |
|--------------------|------------|--------------------------------|------------|------------------------|------------|--------------------|------------|-----------------|------------|
| Canada             |       | 12                             |       | —                 |       | —             |       | 49              |       |
| United Kingdom     |       | —                         |       | —                 |       | 64                 |       | 23              |       |
| United States      |       | —                         |       | —                 |       | 4                  |       | 36              |       |
| Other Countries 1  |       | —                         |       | —                 |       | 5                  |       | —          |       |
| **Developed**      | ** ** | **12**                         | ** ** | **—**             | ** ** | **73**             | ** ** | **108**         | ** ** |
| Canada             |       | 242                            |       | 510                    |       | —             |       | —          |       |
| United Kingdom     |       | —                         |       | —                 |       | 24                 |       | 16              |       |
| United States      |       | —                         |       | —                 |       | 139                |       | 45              |       |
| Other Countries 1  |       | —                         |       | —                 |       | 17                 |       | —          |       |
| **Undeveloped**    | ** ** | **242**                        | ** ** | **510**                | ** ** | **180**            | ** ** | **61**          | ** ** |
|               |       |                           |       |                   |       |               |       |            |       |
| **Total Probable** | ** ** | **254**                        | ** ** | **510**                | ** ** | **253**            | ** ** | **169**         | ** ** |

 

----

*(1)   Represents reserves in Yemen, Nigeria and Colombia.*

 

Developed probable reserves typically reflect increased recovery factors and recompletions of other zones on producing wells. Undeveloped probable reserves reflect reserves that have not yet been drilled or the production facilities completed. They can also represent the reserves associated with higher recovery in proved undeveloped areas.

 

The majority of our probable reserves are undeveloped and primarily reflects incremental synthetic oil reserves related to future drilling required to keep the Long Lake upgrader full for 50 years, expected SAGD development of the bitumen resource at Kinosis and Hangingstone, and extension of the plant life and expected higher future yields at Syncrude. These probable reserves will typically be developed in conjunction with proved reserves, but can take longer periods to develop. The remaining probable undeveloped reserves relate to ongoing pad development of Horn River, discoveries in the Gulf of Mexico and discoveries offshore Nigeria. We expect these remaining probable undeveloped reserves will be developed over the next ten years.

 

Our oil sands projects are large scale developments with significantly longer production lives than conventional oil and gas projects. The proved and probable reserves associated with these projects are developed over a period of decades within the limits of facility capacity.

 

Net Sales by Product from Oil and Gas Operations

 
| **(Cdn$ millions)**                                | ** ** | **2012**  | ** ** | **2011**  | ** ** | **2010 ****1** | ** ** |
|---------------------------------------------------------|------------|-----------|------------|-----------|------------|---------------------|------------|
| Conventional Crude Oil and Natural Gas Liquids   (NGLs) |       | 4,718     |       | 4,344     |       | 4,124               |       |
| Synthetic Crude Oil                                     |       | 1,407     |       | 1,449     |       | 1,062               |       |
| Natural Gas                                             |       | 262       |       | 327       |       | 410                 |       |
| **Total**                                               | ** ** | **6,387** | ** ** | **6,120** | ** ** | **5,596**           | ** ** |

 

----

*(1)   Includes results of discontinued operations (see Note 23 of our Consolidated Financial Statements).*

 

Crude oil (including synthetic crude oil) and NGLs represent approximately 96% of our oil and gas net sales, while natural gas represents the remaining 4%.

 

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Sales Prices and Production Costs

 
| ** **                                            | ** ** | **Average Sales Price ****1** | ** ** | **Average Production Cost ****1** |       |
|-------------------------------------------------------|------------|----------------------------------------------|------------|--------------------------------------------------|------------|
| ** **                                            | ** ** | **2012**                                     | ** ** | **2011**                                         | ** ** | **2010** | ** ** | **2012** | ** ** | **2011** | ** ** | **2010** | ** ** |
| **Crude Oil and NGLs (Cdn$/bbl)** | ** ** | ** **                                   | ** ** | ** **                                       | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Oil Sands – Syncrude                             |       | 91.23                                        |       | 101.73                                           |       | 81.23 |   | 36.22 |   | 40.94 |   | 37.18 |   |
| Oil Sands – In Situ                              |       | 86.57                                        |       | 98.33                                            |       | 77.07 |   | 77.19 |   | 90.22 |   | 105.25 |   |
| Canada – Other                                   |       | —                                       |       | —                                           |       | 61.39 |   | — |   | — |   | 20.97 |   |
| United Kingdom                                        |       | 109.98                                       |       | 106.76                                           |       | 79.02 |   | 11.96 |   | 10.64 |   | 8.28 |   |
| United States                                         |       | 102.10                                       |       | 99.65                                            |       | 76.73 |   | 19.82 |   | 13.22 |   | 10.76 |   |
| Other Countries 2                                |       | 108.06                                       |       | 107.85                                           |       | 81.63 |   | 19.90 |   | 22.53 |   | 17.83 |   |
| **Natural Gas***(Cdn$/mcf)*                           |       |                                         |       |                                             |       |   |   |   |   |   |   |   |   |
| Canada                                                |       | 2.20                                         |       | 3.44                                             |       | 3.94 |   | 1.65 |   | 1.78 |   | 1.93 |   |
| United Kingdom                                        |       | 7.86                                         |       | 7.42                                             |       | 5.28 |   | 1.99 |   | 1.77 |   | 1.38 |   |
| United States                                         |       | 2.81                                         |       | 4.21                                             |       | 4.97 |   | 3.30 |   | 2.20 |   | 1.79 |   |
| **Corporate Average***(Cdn$/boe)*                     | ** ** | **89.81**                                    | ** ** | **91.46**                                        | ** ** | **70.11** | ** ** | **20.77** | ** ** | **21.30** | ** ** | **17.40** | ** ** |

 

----

*(1)   Sales prices and unit production costs are calculated using our working interest production after royalties.*

*(2)**        **Includes Yemen, Nigeria and Colombia.*

 

Oil and Gas Acreage

 
| ** **                         | ** ** | **Developed** | ** ** | **Undeveloped ****1** | ** ** | **Total** | ** ** |
|------------------------------------|------------|---------------|------------|----------------------------|------------|-----------|------------|
| **(thousands of acres)** | ** ** | **Gross**     | ** ** | **Net**                    | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
| Oil Sands – In Situ           |       | 14            |       | 9                          |       | 621       |       | 270 |   | 636 |   | 279 |   |
| Oil Sands – Syncrude          |       | 117           |       | 8                          |       | 131       |       | 10 |   | 248 |   | 18 |   |
| Canada – Other 2              |       | 593           |       | 446                        |       | 911       |       | 461 |   | 1,504 |   | 907 |   |
| United Kingdom                     |       | 74            |       | 40                         |       | 1,640     |       | 991 |   | 1,714 |   | 1,032 |   |
| United States                      |       | 125           |       | 63                         |       | 1,167     |       | 520 |   | 1,292 |   | 583 |   |
| Yemen 3                            |       | 4             |       | 4                          |       | 511       |       | 511 |   | 515 |   | 515 |   |
| Colombia 4                         |       | 2             |       | —                     |       | 1,617     |       | 1,531 |   | 1,619 |   | 1,531 |   |
| Nigeria 2, 3                       |       | 7             |       | 2                          |       | 671       |       | 134 |   | 678 |   | 136 |   |
| Poland 2                           |       | —        |       | —                     |       | 2,258     |       | 903 |   | 2,258 |   | 903 |   |
| **Total****5**                     | ** ** | **936**       | ** ** | **572**                    | ** ** | **9,528** | ** ** | **5,332** | ** ** | **10,464** | ** ** | **5,904** | ** ** |

 

----

*(1)**        **Undeveloped acreage is considered to be those acres on which wells have not been drilled or completed to a point that would permit production of commercial quantities of crude oil and natural gas regardless of whether or not such acreage contains proved reserves.*

*(2)   The acreage is covered by joint venture agreements.*

*(3)   The acreage is covered by production-sharing contracts.*

*(4)   The acreage is covered by an association contract.*

*(5)**        **Approximately 21% of our net oil and gas acreage is scheduled to expire within three years if production is not established or we take no other action to extend the terms. We plan to continue the terms of many of these licences.*

 

Producing Oil and Gas Wells

 
| ** **                      | ** ** | **Oil**              | ** ** | **Gas**            | ** ** | **Total**            | ** ** |
|---------------------------------|------------|----------------------|------------|--------------------|------------|----------------------|------------|
| **(number of wells)** | ** ** | **Gross**** 1** | ** ** | **Net ****2** | ** ** | **Gross**** 1** | ** ** | **Net ****2** | ** ** | **Gross**** 1** | ** ** | **Net ****2** | ** ** |
| Canada                          |       | 131                  |       | 81                 |       | 2,544                |       | 2,278 |   | 2,675 |   | 2,359 |   |
| United Kingdom                  |       | 67                   |       | 34                 |       | —               |       | — |   | 67 |   | 34 |   |
| United States                   |       | 57                   |       | 34                 |       | 30                   |       | 21 |   | 87 |   | 55 |   |
| Yemen                           |       | 54                   |       | 54                 |       | —               |       | — |   | 54 |   | 54 |   |
| Colombia                        |       | 112                  |       | 11                 |       | —               |       | — |   | 112 |   | 11 |   |
| Nigeria                         |       | 10                   |       | 2                  |       | —               |       | — |   | 10 |   | 2 |   |
| **Total**                       | ** ** | **431**              | ** ** | **216**            | ** ** | **2,574**            | ** ** | **2,299** | ** ** | **3,005** | ** ** | **2,515** | ** ** |

 

----

*(1)   Gross wells are the total number of wells in which we own an interest.*

*(2)   Net wells are the sum of fractional interests owned in gross wells.*

 

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Drilling Activity

 
| ** **                      | ** ** | **2012**                 | ** ** |
|---------------------------------|------------|--------------------------|------------|
| ** **                      | ** ** | **Net Exploratory** | ** ** | **Net Development** | ** ** | **Total** | ** ** |
| **(number of wells)** | ** ** | **Productive**           | ** ** | **Dry Holes** | ** ** | **Total** | ** ** | **Productive** | ** ** | **Dry Holes** | ** ** | **Total** | ** ** | ** ** | ** ** |
| Canada                          |       | 1.0                      |       | — |   | 1.0 |   | 18.0 |   | — |   | 18.0 |   | 19.0 |   |
| United Kingdom                  |       | —                   |       | 2.3 |   | 2.3 |   | 0.9 |   | 0.4 |   | 1.3 |   | 3.6 |   |
| United States                   |       | 0.4                      |       | 0.5 |   | 0.9 |   | — |   | — |   | — |   | 0.9 |   |
| Other Countries                 |       | 3.3                      |  1    | — |   | 3.3 |   | 1.9 |   | — |   | 1.9 |   | 5.2 |   |
| **Total**                       | ** ** | **4.7**                  | ** ** | **2.8** | ** ** | **7.5** | ** ** | **20.8** | ** ** | **0.4** | ** ** | **21.2** | ** ** | **28.7** | ** ** |

 
| ** **                      | ** ** | **2011**                 | ** ** |
|---------------------------------|------------|--------------------------|------------|
| ** **                      | ** ** | **Net Exploratory** | ** ** | **Net Development** | ** ** | **Total** | ** ** |
| **(number of wells)** | ** ** | **Productive**           | ** ** | **Dry Holes** | ** ** | **Total** | ** ** | **Productive** | ** ** | **Dry Holes** | ** ** | **Total** | ** ** | ** ** | ** ** |
| Canada                          |       | 13.0                     |       | — |   | 13.0 |   | 28.5 |   | — |   | 28.5 |   | 41.5 |   |
| United Kingdom                  |       | —                   |       | 3.9 |   | 3.9 |   | 1.7 |   | 0.9 |   | 2.6 |   | 6.5 |   |
| United States                   |       | —                   |       | — |   | — |   | — |   | — |   | — |   | — |   |
| Other Countries                 |       | —                   |       | 0.5 |   | 0.5 |   | 5.6 |   | — |   | 5.6 |   | 6.1 |   |
| **Total**                       | ** ** | **13.0**                 | ** ** | **4.4** | ** ** | **17.4** | ** ** | **35.8** | ** ** | **0.9** | ** ** | **36.7** | ** ** | **54.1** | ** ** |

 
| ** **                      | ** ** | **2010**                 | ** ** |
|---------------------------------|------------|--------------------------|------------|
| ** **                      | ** ** | **Net Exploratory** | ** ** | **Net Development** | ** ** | **Total** | ** ** |
| **(number of wells)** | ** ** | **Productive**           | ** ** | **Dry Holes** | ** ** | **Total** | ** ** | **Productive** | ** ** | **Dry Holes** | ** ** | **Total** | ** ** | ** ** | ** ** |
| Canada                          |       | 9.0                      |       | — |   | 9.0 |   | 21.5 |   | — |   | 21.5 |   | 30.5 |   |
| United Kingdom                  |       | 2.0                      |       | 1.3 |   | 3.3 |   | 5.3 |   | 0.4 |   | 5.7 |   | 9.0 |   |
| United States                   |       | 0.5                      |       | — |   | 0.5 |   | 0.8 |   | — |   | 0.8 |   | 1.3 |   |
| Other Countries                 |       | —                   |       | 0.7 |   | 0.7 |   | 12.6 |   | 0.5 |   | 13.1 |   | 13.8 |   |
| **Total**                       | ** ** | **11.5**                 | ** ** | **2.0** | ** ** | **13.5** | ** ** | **40.2** | ** ** | **0.9** | ** ** | **41.1** | ** ** | **54.6** | ** ** |

 

----

*(1)**        **Includes six shale gas exploration wells (3.0 net) drilled and technical analysis to establish productivity has yet to be concluded.*

 

Present Activities

 

At December 31, 2012, we were drilling seven wells in the United Kingdom (3.3 net), seventeen wells in Canada (11.0 net), two wells in Colombia (2.0 net) and one well in Nigeria (0.2 net).

 

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**SUPPLEMENTARY DATA**

 

Oil and Gas Producing Activities

 

The following oil and gas information is provided in accordance with the Financial Accounting Standards Board (FASB) Topic 932 *Extractive Activities — Oil and Gas*.

 

(A) RESERVE QUANTITY INFORMATION

 

The net proved reserves represent management’s estimate of remaining proved oil and gas reserves after royalties. Every year, reserve estimates for each property are internally prepared. Our estimates of proved oil and gas reserves are determined through analysis of geological and engineering data, and demonstrate reasonable certainty that they are recoverable from known reservoirs under existing economic and operating conditions based on the 12-month average prices. See Basis of Reserves Estimates on pages 14 to 16 for a description of our oil and gas reserves estimation process.

 
| ** **                          | ** ** | ** **                                 | ** ** | ** **                               | ** ** | ** **                  | ** ** | ** **              | ** ** | ** **           | ** ** | **Canada**                                               | ** ** |
|-------------------------------------|------------|--------------------------------------------|------------|------------------------------------------|------------|-----------------------------|------------|-------------------------|------------|----------------------|------------|----------------------------------------------------------|------------|
| ** **                          | ** ** | **Total – By Product** | ** ** | **Oil Sands**                       | ** ** | ** **                  | ** ** | ** **              | ** ** |
| ** **                          | ** ** | **Total********(mmboe)**                   | ** ** | **Synthetic********Oil********(mmbbls)** | ** ** | **Bitumen********(mmbbls)** | ** ** | **Oil********(mmbbls)** | ** ** | **Gas********(bcf)** | ** ** | **Syncrude********Synthetic********Oil********(mmbbls)** | ** ** | **In Situ********Synthetic********Oil********(mmbbls)** | ** ** | **In Situ********Bitumen********(mmbbls)** | ** ** | **Oil********(mmbbls)** | ** ** | **Gas********(bcf)** | ** ** |
| **Proved Reserves after Royalties** | ** ** | ** **                                 | ** ** | ** **                               | ** ** | ** **                  | ** ** | ** **              | ** ** | ** **           | ** ** | ** **                                               | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| **December 31, 2009**          | ** ** | **920**                                    | ** ** | **579**                                  | ** ** | **—**                  | ** ** | **272**                 | ** ** | **411**              | ** ** | **288**                                                  | ** ** | **291** | ** ** | **—** | ** ** | **31** | ** ** | **244** | ** ** |
| Extensions and Discoveries          |       | 66                                         |       | 10                                       |       | —                      |       | 36                      |       | 121                  |       | 7                                                        |       | 3 |   | — |   | — |   | 90 |   |
| Revisions – Technical          |       | 27                                         |       | (3                                       | )          | —                      |       | 27                      |       | 21                   |       | —                                                   |       | (3 | ) | — |   | — |   | (16 | ) |
| Revisions – Economic           |       | 13                                         |       | 12                                       |       | —                      |       | 1                       |       | 1                    |       | 8                                                        |       | 4 |   | — |   | — |   | 7 |   |
| Acquisitions                        |       | 1                                          |       | —                                   |       | —                      |       | 1                       |       | 3                    |       | —                                                   |       | — |   | — |   | — |   | — |   |
| Divestments                         |       | (30                                        | )          | —                                   |       | —                      |       | (29                     | )          | (8                   | )          | —                                                   |       | — |   | — |   | (29 | ) | (8 | ) |
| Production                          |       | (79                                        | )          | (11                                      | )          | —                      |       | (53                     | )          | (90                  | )          | (7                                                       | )          | (4 | ) | — |   | (2 | ) | (42 | ) |
| **December 31, 2010**          | ** ** | **918**                                    | ** ** | **587**                                  | ** ** | **—**                  | ** ** | **255**                 | ** ** | **459**              | ** ** | **296**                                                  | ** ** | **291** | ** ** | **—** | ** ** | **—** | ** ** | **275** | ** ** |
| Extensions and Discoveries          |       | 107                                        |       | 86                                       |       | —                      |       | 1                       |       | 124                  |       | 7                                                        |       | 79 |   | — |   | — |   | 116 |   |
| Revisions – Technical          |       | (34                                        | )          | (59                                      | )          | —                      |       | 24                      |       | 8                    |       | —                                                   |       | (59 | ) | — |   | — |   | 3 |   |
| Revisions – Economic           |       | (23                                        | )          | (25                                      | )          | —                      |       | 6                       |       | (27                  | )          | (14                                                      | )          | (11 | ) | — |   | — |   | (26 | ) |
| Acquisitions                        |       | —                                     |       | —                                   |       | —                      |       | —                  |       | —               |       | —                                                   |       | — |   | — |   | — |   | — |   |
| Divestments                         |       | —                                     |       | —                                   |       | —                      |       | —                  |       | —               |       | —                                                   |       | — |   | — |   | — |   | — |   |
| Production                          |       | (68                                        | )          | (12                                      | )          | —                      |       | (43                     | )          | (82                  | )          | (7                                                       | )          | (5 | ) | — |   | — |   | (43 | ) |
| **December 31, 2011**          | ** ** | **900**                                    | ** ** | **577**                                  | ** ** | **—**                  | ** ** | **243**                 | ** ** | **482**              | ** ** | **282**                                                  | ** ** | **295** | ** ** | **—** | ** ** | **—** | ** ** | **325** | ** ** |
| Extensions and Discoveries          |       | 21                                         |       | 14                                       |       | —                      |       | 7                       |       | 1                    |       | 7                                                        |       | 7 |   | — |   | — |   | — |   |
| Revisions – Technical          |       | 5                                          |       | (9                                       | )          | —                      |       | 16                      |       | (7                   | )          | —                                                   |       | (9 | ) | — |   | — |   | (9 | ) |
| Revisions – Economic           |       | (11                                        | )          | 11                                       |       | —                      |       | 1                       |       | (139                 | )          | 7                                                        |       | 4 |   | — |   | — |   | (130 | ) |
| Acquisitions                        |       | —                                     |       | —                                   |       | —                      |       | —                  |       | —               |       | —                                                   |       | — |   | — |   | — |   | — |   |
| Divestments                         |       | (11                                        | )          | —                                   |       | —                      |       | —                  |       | (69                  | )          | —                                                   |       | — |   | — |   | — |   | (69 | ) |
| Production                          |       | (67                                        | )          | (12                                      | )          | —                      |       | (43                     | )          | (72                  | )          | (7                                                       | )          | (5 | ) | — |   | — |   | (43 | ) |
| **December 31, 2012**          | ** ** | **837**                                    | ** ** | **581**                                  | ** ** | **—**                  | ** ** | **224**                 | ** ** | **196**              | ** ** | **289**                                                  | ** ** | **292** | ** ** | **—** | ** ** | **—** | ** ** | **74** | ** ** |
|                                |       |                                       |       |                                     |       |                        |       |                    |       |                 |       |                                                     |       |   |   |   |   |   |   |   |   |
| **Proved Undeveloped**              |       |                                       |       |                                     |       |                        |       |                    |       |                 |       |                                                     |       |   |   |   |   |   |   |   |   |
| December 31, 2010              |       | 472                                        |       | 358                                      |       | —                      |       | 94                      |       | 122                  |       | 114                                                      |       | 244 |   | — |   | — |   | 44 |   |
| December 31, 2011              |       | 466                                        |       | 377                                      |       | —                      |       | 64                      |       | 154                  |       | 116                                                      |       | 261 |   | — |   | — |   | 99 |   |
| **December 31, 2012**          | ** ** | **454**                                    | ** ** | **385**                                  | ** ** | **—**                  | ** ** | **60**                  | ** ** | **57**               | ** ** | **124**                                                  | ** ** | **261** | ** ** | **—** | ** ** | **—** | ** ** | **—** | ** ** |
| ** **                          | ** ** | ** **                                 | ** ** | ** **                               | ** ** | ** **                  | ** ** | ** **              | ** ** | ** **           | ** ** | ** **                                               | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Proved Developed****3**           | ** ** | ** **                                 | ** ** | ** **                               | ** ** | ** **                  | ** ** | ** **              | ** ** | ** **           | ** ** | ** **                                               | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| December 31, 2010              |       | 446                                        |       | 229                                      |       | —                      |       | 161                     |       | 337                  |       | 182                                                      |       | 47 |   | — |   | — |   | 231 |   |
| December 31, 2011              |       | 434                                        |       | 200                                      |       | —                      |       | 179                     |       | 328                  |       | 166                                                      |       | 34 |   | — |   | — |   | 226 |   |
| **December 31, 2012**          | ** ** | **383**                                    | ** ** | **196**                                  | ** ** | **—**                  | ** ** | **164**                 | ** ** | **139**              | ** ** | **165**                                                  | ** ** | **31** | ** ** | **—** | ** ** | **—** | ** ** | **74** | ** ** |

 

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| ** **                          | ** ** | **United Kingdom** | ** ** | **United States** | ** ** | **Other********Countries ****1, 2** | ** ** |
|-------------------------------------|------------|-------------------------|------------|------------------------|------------|-----------------------------------------------|------------|
| ** **                          | ** ** | **Oil********(mmbbls)** | ** ** | **Gas********(bcf)**   | ** ** | **Oil********(mmbbls)**                       | ** ** | **Gas********(bcf)** | ** ** | **Oil********(mmbbls)** | ** ** |
| **Proved Reserves after Royalties** | ** ** | ** **              | ** ** | ** **             | ** ** | ** **                                    | ** ** | ** ** | ** ** | ** ** | ** ** |
| **December 31, 2009**          | ** ** | **169**                 | ** ** | **17**                 | ** ** | **19**                                        | ** ** | **150** | ** ** | **53** | ** ** |
| Extensions and   Discoveries        |       | 35                      |       | 29                     |       | —                                        |       | 2 |   | 1 |   |
| Revisions — Technical          |       | 25                      |       | 32                     |       | 1                                             |       | 5 |   | 1 |   |
| Revisions — Economic           |       | 1                       |       | —                 |       | —                                        |       | (6 | ) | — |   |
| Acquisitions                        |       | 1                       |       | 3                      |       | —                                        |       | — |   | — |   |
| Divestments                         |       | —                  |       | —                 |       | —                                        |       | — |   | — |   |
| Production                          |       | (38                     | )          | (14                    | )          | (3                                            | )          | (34 | ) | (10 | ) |
| **December 31, 2010**          | ** ** | **193**                 | ** ** | **67**                 | ** ** | **17**                                        | ** ** | **117** | ** ** | **45** | ** ** |
| Extensions and   Discoveries        |       | 1                       |       | 7                      |       | —                                        |       | 1 |   | — |   |
| Revisions — Technical          |       | 24                      |       | 3                      |       | —                                        |       | 2 |   | — |   |
| Revisions — Economic           |       | 7                       |       | (1                     | )          | —                                        |       | — |   | (1 | ) |
| Acquisitions                        |       | —                  |       | —                 |       | —                                        |       | — |   | — |   |
| Divestments                         |       | —                  |       | —                 |       | —                                        |       | — |   | — |   |
| Production                          |       | (32                     | )          | (10                    | )          | (3                                            | )          | (29 | ) | (8 | ) |
| **December 31, 2011**          | ** ** | **193**                 | ** ** | **66**                 | ** ** | **14**                                        | ** ** | **91** | ** ** | **36** | ** ** |
| Extensions and   Discoveries        |       | 4                       |       | 1                      |       | —                                        |       | — |   | 3 |   |
| Revisions — Technical          |       | 17                      |       | 13                     |       | 1                                             |       | (11 | ) | (2 | ) |
| Revisions — Economic           |       | 1                       |       | —                 |       | (1                                            | )          | (9 | ) | 1 |   |
| Acquisitions                        |       | —                  |       | —                 |       | —                                        |       | — |   | — |   |
| Divestments                         |       | —                  |       | —                 |       | —                                        |       | — |   | — |   |
| Production                          |       | (34                     | )          | (14                    | )          | (2                                            | )          | (15 | ) | (7 | ) |
| **December 31, 2012**          | ** ** | **181**                 | ** ** | **66**                 | ** ** | **12**                                        | ** ** | **56** | ** ** | **31** | ** ** |
|                                |       |                    |       |                   |       |                                          |       |   |   |   |   |
| **Proved Undeveloped**              |       |                    |       |                   |       |                                          |       |   |   |   |   |
| December 31, 2010              |       | 55                      |       | 55                     |       | 5                                             |       | 23 |   | 34 |   |
| December 31, 2011              |       | 44                      |       | 34                     |       | 4                                             |       | 21 |   | 16 |   |
| **December 31, 2012**          | ** ** | **45**                  | ** ** | **35**                 | ** ** | **2**                                         | ** ** | **22** | ** ** | **13** | ** ** |
|                                |       |                    |       |                   |       |                                          |       |   |   |   |   |
| **Proved Developed****3**           |       |                    |       |                   |       |                                          |       |   |   |   |   |
| December 31, 2010              |       | 138                     |       | 12                     |       | 12                                            |       | 94 |   | 11 |   |
| December 31, 2011              |       | 149                     |       | 32                     |       | 10                                            |       | 70 |   | 20 |   |
| **December 31, 2012**          | ** ** | **136**                 | ** ** | **31**                 | ** ** | **10**                                        | ** ** | **34** | ** ** | **18** | ** ** |

 

----

*(1)**        **Proved developed oil and gas reserves are expected to be recovered through existing wells with existing equipment and operating methods.*

*(2)**        **Under the terms of the Masila and the Block 51 production sharing contracts, production was divided into cost recovery oil and profit oil. The Government’s share of profit oil represents its royalty interest and an amount for income taxes payable in Yemen. Yemen’s net proved reserves were determined using the economic interest method and include our share of future cost recovery and profit oil after the Government’s royalty interest, but before reserves relating to income taxes payable. Under this method, reported reserves increased as oil prices decreased (and vice versa) as the barrels necessary to achieve cost recovery change with prevailing oil prices. Production included volumes used for fuel.*

*(3)**        **Represents reserves in Yemen, Nigeria and Colombia.*

 

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(B) CAPITALIZED COSTS

 
| **(Cdn$ millions)**      | ** ** | **Proved********Properties** | ** ** | **Unproved********Properties** | ** ** | **Accumulated********DD&A** | ** ** | **Capitalized********Costs** | ** ** |
|-------------------------------|------------|------------------------------|------------|--------------------------------|------------|---------------------------------|------------|------------------------------|------------|
| **December 31,   2012**  |       |                         |       |                           |       |                            |       |                         |       |
| United Kingdom                |       | 6,406                        |       | 1,519                          |       | (4,200                          | )          | 3,725                        |       |
| Canada                        |       | 2,236                        |       | 260                            |       | (1,421                          | )          | 1,075                        |       |
| Oil Sands In Situ             |       | 5,921                        |       | 712                            |       | (384                            | )          | 6,249                        |       |
| Oil Sands Syncrude            |       | 1,981                        |       | —                         |       | (469                            | )          | 1,512                        |       |
| United States                 |       | 3,936                        |       | 269                            |       | (3,020                          | )          | 1,185                        |       |
| Other Countries               |       | 2,774                        |       | 175                            |       | (1,008                          | )          | 1,941                        |       |
| **Total   Capitalized Costs** | ** ** | **23,254**                   | ** ** | **2,935**                      | ** ** | **(10,502**                     | **)**      | **15,687**                   | ** ** |
| **December 31,   2011**  |       |                         |       |                           |       |                            |       |                         |       |
| United Kingdom                |       | 5,967                        |       | 1,136                          |       | (3,707                          | )          | 3,396                        |       |
| Canada                        |       | 2,451                        |       | 476                            |       | (1,230                          | )          | 1,697                        |       |
| Oil Sands In Situ             |       | 5,304                        |       | 611                            |       | (205                            | )          | 5,710                        |       |
| Oil Sands Syncrude            |       | 1,733                        |       | —                         |       | (411                            | )          | 1,322                        |       |
| United States                 |       | 4,066                        |       | 263                            |       | (3,069                          | )          | 1,260                        |       |
| Other Countries               |       | 2,483                        |       | 83                             |       | (648                            | )          | 1,918                        |       |
| **Total   Capitalized Costs** | ** ** | **22,004**                   | ** ** | **2,569**                      | ** ** | **(9,270**                      | **)**      | **15,303**                   | ** ** |
| **December 31,   2010**  |       |                         |       |                           |       |                            |       |                         |       |
| United Kingdom                |       | 5,412                        |       | 977                            |       | (3,055                          | )          | 3,334                        |       |
| Canada                        |       | 1,909                        |       | 589                            |       | (870                            | )          | 1,628                        |       |
| Oil Sands In Situ             |       | 4,957                        |       | 799                            |       | (91                             | )          | 5,665                        |       |
| Oil Sands Syncrude            |       | 1,519                        |       | —                         |       | (359                            | )          | 1,160                        |       |
| United States                 |       | 3,666                        |       | 258                            |       | (2,727                          | )          | 1,197                        |       |
| Other Countries               |       | 3,647                        |       | 53                             |       | (2,370                          | )          | 1,330                        |       |
| **Total   Capitalized Costs** | ** ** | **21,110**                   | ** ** | **2,676**                      | ** ** | **(9,472**                      | **)**      | **14,314**                   | ** ** |

 

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(C) COSTS INCURRED

 
| **(Cdn $millions)**                | ** ** | **Total Oil   and Gas** | ** ** | **United   Kingdom** | ** ** | **Canada   Gas** | ** ** | **Oil Sands   In Situ** | ** ** | **Oil Sands   Syncrude** | ** ** | **United   States** | ** ** | **Other   Countries** | ** ** |
|-----------------------------------------|------------|-----------------------------------|------------|----------------------|------------|------------------|------------|-----------------------------------|------------|-------------------------------|------------|---------------------|------------|-----------------------|------------|
| **Year Ended December 31,   2012** |       |                              |       |                 |       |             |       |                              |       |                          |       |                |       |                  |       |
| Property Acquistion Costs               |       |                              |       |                 |       |             |       |                              |       |                          |       |                |       |                  |       |
| Proved                                  |       | —                            |       | —               |       | —           |       | —                            |       | —                        |       | —              |       | —                |       |
| Unproved                                |       | 12                                |       | —               |       | —           |       | —                            |       | —                        |       | 12                  |       | —                |       |
| Exploration Costs                       |       | 752                               |       | 202                  |       | 53               |       | 100                               |       | —                        |       | 255                 |       | 142                   |       |
| Development Costs                       |       | 2,732                             |       | 1,003                |       | 355              |       | 618                               |       | 256                           |       | 156                 |       | 344                   |       |
| **Total Costs Incurred**                | ** ** | **3,496**                         | ** ** | **1,205**            | ** ** | **408**          | ** ** | **718**                           | ** ** | **256**                       | ** ** | **423**             | ** ** | **486**               | ** ** |
| **Year Ended December 31,   2011** |       |                              |       |                 |       |             |       |                              |       |                          |       |                |       |                  |       |
| Property Acquistion Costs               |       |                              |       |                 |       |             |       |                              |       |                          |       |                |       |                  |       |
| Proved                                  |       | —                            |       | —               |       | —           |       | —                            |       | —                        |       | —              |       | —                |       |
| Unproved                                |       | 17                                |       | 12                   |       | 3                |       | —                            |       | —                        |       | 2                   |       | —                |       |
| Exploration Costs                       |       | 902                               |       | 87                   |       | 391              |       | 114                               |       | —                        |       | 154                 |       | 156                   |       |
| Development Costs                       |       | 2,123                             |       | 644                  |       | 135              |       | 299                               |       | 222                           |       | 229                 |       | 594                   |       |
| **Total Costs Incurred**                | ** ** | **3,042**                         | ** ** | **743**              | ** ** | **529**          | ** ** | **413**                           | ** ** | **222**                       | ** ** | **385**             | ** ** | **750**               | ** ** |
| **Year Ended December 31,   2010** |       |                              |       |                 |       |             |       |                              |       |                          |       |                |       |                  |       |
| Property Acquistion Costs               |       |                              |       |                 |       |             |       |                              |       |                          |       |                |       |                  |       |
| Proved                                  |       | 79                                |       | 79                   |       | —           |       | —                            |       | —                        |       | —              |       | —                |       |
| Unproved                                |       | 552                               |       | 176                  |       | 315              |       | —                            |       | —                        |       | 61                  |       | —                |       |
| Exploration Costs                       |       | 540                               |       | 35                   |       | 222              |       | 60                                |       | —                        |       | 120                 |       | 103                   |       |
| Development Costs                       |       | 1,758                             |       | 658                  |       | 66               |       | 175                               |       | 142                           |       | 152                 |       | 565                   |       |
| **Total Costs Incurred**                | ** ** | **2,929**                         | ** ** | **948**              | ** ** | **603**          | ** ** | **235**                           | ** ** | **142**                       | ** ** | **333**             | ** ** | **668**               | ** ** |

 

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(D) RESULTS OF OPERATIONS FOR PRODUCING ACTIVITIES

 
| **(Cdn$ millions)**                             | ** ** | **Total Oil********and Gas** | ** ** | **United********Kingdom** | ** ** | **Canada********Gas ****1** | ** ** | **Oil Sands********In Situ** | ** ** | **Oil Sands********Syncrude** | ** ** | **United********States** | ** ** | **Other   Countries ****2** | ** ** |
|------------------------------------------------------|------------|----------------------------------------|------------|---------------------------|------------|----------------------------------|------------|----------------------------------------|------------|------------------------------------|------------|--------------------------|------------|----------------------------------|------------|
| **Year Ended**                                       |       |                                   |       |                      |       |                             |       |                                   |       |                               |       |                     |       |                             |       |
| **December 31, 2012**                           |       |                                   |       |                      |       |                             |       |                                   |       |                               |       |                     |       |                             |       |
| Net Sales                                            |       | 6,384                                  |       | 3,889                     |       | 97                               |       | 726                                    |       | 666                                |       | 303                      |       | 703                              |       |
| Production Costs                                     |       | 1,474                                  |       | 439                       |       | 71                               |       | 466                                    |       | 264                                |       | 100                      |       | 134                              |       |
| Exploration Expense                                  |       | 429                                    |       | 117                       |       | 79                               |       | 1                                      |       | —                             |       | 204                      |       | 28                               |       |
| Depreciation, Depletion, Amortization and Impairment |       | 1,895                                  |       | 752                       |       | 245                              |       | 192                                    |       | 66                                 |       | 269                      |       | 371                              |       |
| Other Expenses (Income)                              |       | 400                                    |       | 18                        |       | (100                             | )          | 287                                    |       | 33                                 |       | 111                      |       | 51                               |       |
| **Results of****Operations before Income Taxes**     | ** ** | **2,186**                              | ** ** | **2,563**                 | ** ** | **(198**                         | **)**      | **(220**                               | **)**      | **303**                            | ** ** | **(381**                 | **)**      | **119**                          | ** ** |
| **Year Ended**                                       |       |                                   |       |                      |       |                             |       |                                   |       |                               |       |                     |       |                             |       |
| **December 31, 2011**                           |       |                                   |       |                      |       |                             |       |                                   |       |                               |       |                     |       |                             |       |
| Net Sales                                            |       | 6,113                                  |       | 3,432                     |       | 111                              |       | 688                                    |       | 713                                |       | 388                      |       | 781                              |       |
| Production Costs                                     |       | 1,399                                  |       | 353                       |       | 57                               |       | 439                                    |       | 287                                |       | 99                       |       | 164                              |       |
| Exploration Expense                                  |       | 368                                    |       | 84                        |       | 43                               |       | 2                                      |       | —                             |       | 105                      |       | 134                              |       |
| Depreciation, Depletion, Amortization and Impairment |       | 1,859                                  |       | 631                       |       | 417                              |       | 384                                    |       | 60                                 |       | 291                      |       | 76                               |       |
| Other Expenses (Income)                              |       | 352                                    |       | (43                       | )          | 53                               |       | 242                                    |       | 27                                 |       | 33                       |       | 40                               |       |
| **Results of****Operations before Income Taxes**     | ** ** | **2,135**                              | ** ** | **2,407**                 | ** ** | **(459**                         | **)**      | **(379**                               | **)**      | **339**                            | ** ** | **(140**                 | **)**      | **367**                          | ** ** |
| **Year Ended**                                       |       |                                   |       |                      |       |                             |       |                                   |       |                               |       |                     |       |                             |       |
| **December 31, 2010**                           |       |                                   |       |                      |       |                             |       |                                   |       |                               |       |                     |       |                             |       |
| Net Sales                                            |       | 5,595                                  |       | 3,115                     |       | 283                              |       | 443                                    |       | 580                                |       | 424                      |       | 750                              |       |
| Production Costs                                     |       | 1,354                                  |       | 337                       |       | 119                              |       | 373                                    |       | 265                                |       | 97                       |       | 163                              |       |
| Exploration Expense                                  |       | 328                                    |       | 67                        |       | 41                               |       | 1                                      |       | —                             |       | 115                      |       | 104                              |       |
| Depreciation, Depletion, Amortization and Impairment |       | 1,589                                  |       | 783                       |       | 205                              |       | 94                                     |       | 53                                 |       | 334                      |       | 120                              |       |
| Other Expenses (Income)                              |       | (465                                   | )          | 7                         |       | (723                             | )          | 118                                    |       | 21                                 |       | 72                       |       | 40                               |       |
| **Results of****Operations before Income Taxes**     | ** ** | **2,789**                              | ** ** | **1,921**                 | ** ** | **641**                          | ** ** | **(143**                               | **)**      | **241**                            | ** ** | **(194**                 | **)**      | **323**                          | ** ** |

 

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*(1)   Includes the results of discontinued operations.*

*(2)   Includes results of operations for Nigeria, Colombia and Yemen.*

 

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(E) STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS AND CHANGES THEREIN

 

The following disclosure is based on estimates of net proved reserves and the period during which they are expected to be produced. Future cash inflows are computed by applying average annual prices to our after royalty share of estimated annual future production from proved oil and gas reserves. Future cash inflows were computed using the average first-day-of-the-month prices for the year held constant. Future development, production and abandonment costs to be incurred in producing and further developing the proved reserves are based on existing cost indicators. Future income taxes are computed by applying year-end statutory tax rates. These rates reflect allowable deductions and tax credits, and are applied to the estimated pre-tax future net cash flows.

 

Discounted future net cash flows are calculated using 10% mid-period discount factors. The calculations assume the continuation of existing economic, operating and contractual conditions. However, such arbitrary assumptions have not proved to be the case in the past. Other assumptions could give rise to substantially different results.

 

We believe this information does not reflect the current economic value of our oil and gas producing properties or the present value of their estimated future cash flows as:

 

·                  no economic value is attributed to probable and possible reserves;

·                  use of a 10% discount rate is arbitrary; and

·                  prices change constantly from the prices used.

 
| ** **                                        | ** ** | ** ** | ** ** | **Canada**                               | ** ** | ** **                                   | ** ** | ** ** | ** ** | ** **                | ** ** |
|---------------------------------------------------|------------|------------|------------|------------------------------------------|------------|----------------------------------------------|------------|------------|------------|---------------------------|------------|
| ** **                                        | ** ** | ** ** | ** ** | **Oil Sands**                       | ** ** | ** **                                   | ** ** | ** ** | ** ** | ** **                | ** ** | ** ** | ** ** |
| **(Cdn$ millions)**                          | ** ** | **Total**  | ** ** | **Syncrude********Synthetic********Oil** | ** ** | **In Situ********Synthetic********Oil** | ** ** | **Gas**    | ** ** | **United********Kingdom** | ** ** | **United********States** | ** ** | **Other********Countries** | ** ** |
| **December 31, 2012**                        |       |       |       |                                     |       |                                         |       |       |       |                      |       |   |   |   |   |
| Future Cash Inflows                               |       | 78,680     |       | 27,030                                   |       | 26,321                                       |       | 158        |       | 20,342                    |       | 1,408 |   | 3,421 |   |
| Future Production Costs                           |       | 36,997     |       | 15,275                                   |       | 15,286                                       |       | 146        |       | 5,035                     |       | 412 |   | 843 |   |
| Future Development Costs                          |       | 6,733      |       | 831                                      |       | 4,265                                        |       | 9          |       | 1,182                     |       | 203 |   | 243 |   |
| Future Dismantlement and   Site Restoration Costs |       | 2,404      |       | 175                                      |       | 167                                          |       | 175        |       | 1,261                     |       | 506 |   | 120 |   |
| Future Income Tax                                 |       | 9,891      |       | 1,227                                    |       | 510                                          |       | —     |       | 8,127                     |       | — |   | 27 |   |
| Future Net Cash Flows                             |       | 22,655     |       | 9,522                                    |       | 6,093                                        |       | (172       | )          | 4,737                     |       | 287 |   | 2,188 |   |
| 10% Discounted Factor                             |       | 13,476     |       | 6,884                                    |       | 5,049                                        |       | (46        | )          | 1,129                     |       | 35 |   | 425 |   |
| **Standardized Measure**                          | ** ** | **9,179**  | ** ** | **2,638**                                | ** ** | **1,044**                                    | ** ** | **(126**   | **)**      | **3,608**                 | ** ** | **252** | ** ** | **1,763** | ** ** |
| **December 31, 2011**                        |       |       |       |                                     |       |                                         |       |       |       |                      |       |   |   |   |   |
| Future Cash Inflows                               |       | 87,256     |       | 29,058                                   |       | 30,189                                       |       | 1,141      |       | 21,199                    |       | 1,838 |   | 3,831 |   |
| Future Production Costs                           |       | 37,688     |       | 14,312                                   |       | 17,076                                       |       | 808        |       | 4,364                     |       | 378 |   | 750 |   |
| Future Development Costs                          |       | 7,688      |       | 1,433                                    |       | 3,853                                        |       | 201        |       | 1,485                     |       | 196 |   | 520 |   |
| Future Dismantlement and   Site Restoration Costs |       | 2,281      |       | 175                                      |       | 187                                          |       | 194        |       | 1,108                     |       | 508 |   | 109 |   |
| Future Income Tax                                 |       | 12,223     |       | 1,941                                    |       | 1,242                                        |       | —     |       | 8,978                     |       | — |   | 62 |   |
| Future Net Cash Flows                             |       | 27,376     |       | 11,197                                   |       | 7,831                                        |       | (62        | )          | 5,264                     |       | 756 |   | 2,390 |   |
| 10% Discounted Factor                             |       | 15,984     |       | 7,855                                    |       | 6,037                                        |       | (60        | )          | 1,353                     |       | 160 |   | 639 |   |
| **Standardized Measure**                          | ** ** | **11,392** | ** ** | **3,342**                                | ** ** | **1,794**                                    | ** ** | **(2**     | **)**      | **3,911**                 | ** ** | **596** | ** ** | **1,751** | ** ** |
| **December 31, 2010**                        |       |       |       |                                     |       |                                         |       |       |       |                      |       |   |   |   |   |
| Future Cash Inflows                               |       | 69,323     |       | 23,998                                   |       | 23,293                                       |       | 1,049      |       | 15,594                    |       | 1,831 |   | 3,558 |   |
| Future Production Costs                           |       | 33,631     |       | 14,002                                   |       | 13,200                                       |       | 706        |       | 4,437                     |       | 449 |   | 837 |   |
| Future Development Costs                          |       | 6,875      |       | 1,061                                    |       | 3,142                                        |       | 95         |       | 1,608                     |       | 253 |   | 716 |   |
| Future Dismantlement and   Site Restoration Costs |       | 2,226      |       | 182                                      |       | 147                                          |       | 242        |       | 1,094                     |       | 432 |   | 129 |   |
| Future Income Tax                                 |       | 6,251      |       | 1,241                                    |       | 416                                          |       | —     |       | 4,433                     |       | — |   | 161 |   |
| Future Net Cash Flows                             |       | 20,340     |       | 7,512                                    |       | 6,388                                        |       | 6          |       | 4,022                     |       | 697 |   | 1,715 |   |
| 10% Discounted Factor                             |       | 11,875     |       | 5,579                                    |       | 4,665                                        |       | (65        | )          | 985                       |       | 126 |   | 585 |   |
| **Standardized Measure**                          | ** ** | **8,465**  | ** ** | **1,933**                                | ** ** | **1,723**                                    | ** ** | **71**     | ** ** | **3,037**                 | ** ** | **571** | ** ** | **1,130** | ** ** |

 

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CHANGES IN THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS

 

The following are the principal sources of change in the standardized measure of discounted future net cash flows:

 
| **(Cdn$ millions)**                                                                   | ** ** | **2012**   | ** ** | **2011**   | ** ** | **2010**  | ** ** |
|--------------------------------------------------------------------------------------------|------------|------------|------------|------------|------------|-----------|------------|
| **Beginning of Year**                                                                      | ** ** | **11,392** | ** ** | **8,465**  | ** ** | **6,293** | ** ** |
| Sales and Transfers of Oil and Gas Produced, Net   of Production Costs                     |       | (4,664     | )          | (3,244     | )          | (3,018    | )          |
| Net Changes in Prices and Production Costs Related   to Future Production                  |       | (2,249     | )          | 5,554      |       | 3,364     |       |
| Extensions, Discoveries and Improved Recovery,   Less Related Costs                        |       | 460        |       | 537        |       | 373       |       |
| Changes in Estimated Future Development and   Dismantlement Costs                          |       | (373       | )          | (939       | )          | (580      | )          |
| Previous Estimated Future Development and   Dismantlement Costs Incurred During the Period |       | 1,515      |       | 1,300      |       | 782       |       |
| Revisions of Previous Quantity Estimates                                                   |       | 758        |       | 1,930      |       | 1,245     |       |
| Accretion of Discount                                                                      |       | 1,814      |       | 1,183      |       | 901       |       |
| Purchase of Reserves in Place                                                              |       | 8          |       | (3         | )          | 51        |       |
| Sales of Reserves in Place                                                                 |       | (22        | )          | (10        | )          | (301      | )          |
| Net Change in Income Taxes                                                                 |       | 540        |       | (3,381     | )          | (645      | )          |
| **End of Year**                                                                            | ** ** | **9,179**  | ** ** | **11,392** | ** ** | **8,465** | ** ** |

 

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**APPENDIX C— FORM 51-101F2**

 

**REPORT ON RESERVES DATA BY INTERNAL QUALIFIED RESERVES EVALUATOR**

 

To the board of directors of Nexen Inc. (the Company):

 

1.              The Company’s staff and I have evaluated 100% of the Company’s reserves data as at December 31, 2012. The reserves data are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2012, estimated using forecast prices and costs in accordance with National Instrument 51-101—*Standards of Disclosure for Oil and Gas Activities* (the Reserves Data).

 

2.              The Reserves Data are the responsibility of the Company’s management. My responsibility is to express an opinion on the Reserves Data based on my evaluation. The Company’s staff and I carried out an evaluation in accordance with standards set out in the Canadian Oil and Gas Evaluation Handbook (the COGE Handbook) prepared jointly by the Society of Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum Society).

 

3.              Those standards require that the evaluation is planned and performed to obtain reasonable assurance as to whether the Reserves Data are free of material misstatement. An evaluation also includes assessing whether the Reserves Data are in accordance with principles and definitions presented in the COGE Handbook.

 

4.              The following table sets forth the estimated future net revenue (before deduction of income taxes) attributed to proved plus probable reserves, estimated using forecast prices and costs and calculated using a discount rate of 10 percent, included in the Reserves Data:

 
| **Location of Reserves   (country or foreign geographic region)** | ** ** | **Net Present Value of   Future Net Revenue of Reserves   Evaluated (before income   taxes, 10% discount rate)   (Cdn $millions)** | ** ** |
|-------------------------------------------------------------------------------------------------|------------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|
| United Kingdom                                                                                  |       | 13,255                                                                                                                                                                                              |       |
| Canada                                                                                          |       | 8,169                                                                                                                                                                                               |       |
| United States                                                                                   |       | 3,156                                                                                                                                                                                               |       |
| Other                                                                                           |       | 2,146                                                                                                                                                                                               |       |
| Total Company                                                                                   |       | 26,726                                                                                                                                                                                              |       |

 

5.              Among other things, with respect to matters regarding royalties, operating costs, development plans and costs, abandonment plans and costs, and income taxes (where applicable), I have placed reasonable reliance on the information and decisions of others in their areas of authority, responsibility and expertise within the Company.

 

6.              I am not independent of the Company, within the meaning of the term “independent” under National Instrument 51-101—*Standards of Disclosure for Oil and Gas Activities*.

 

7.              In my opinion, the Reserves Data has, in all material respects, been determined and are in accordance with the COGE Handbook, consistently applied.

 

8.              I have no responsibility to update this opinion for events and circumstances occurring after their respective preparation dates.

 

9.              Because the Reserves Data are based on judgments regarding future events, actual results will vary and the variations may be material.

 

10.       I have signed this form in my capacity as an employee of Nexen Inc. and not in my personal capacity.

 

DATED as of this 24th day of February, 2013.

 

 
| (signed)   Ian R. McDonald              |   |
|-----------------------------------------|--------|
| **Ian R. McDonald, P. Eng.**            |   |
| Nexen   Inc.                            |   |
| Internal   Qualified Reserves Evaluator |   |
| Calgary,   Alberta                      |   |

 

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**APPENDIX D— FORM 51-101F3**

** **

**REPORT OF MANAGEMENT AND DIRECTORS ON NI 51-101 OIL AND GAS DISCLOSURE**

 

Management of Nexen Inc. (the Company) is responsible for the preparation and disclosure of information with respect to the Company’s oil and gas activities in accordance with securities regulatory requirements. This information includes reserves data, which are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2012 estimated using forecast prices and costs in accordance with National Instrument 51-101 (the Reserves Data).

 

The Company’s reserves evaluation staff, including our Internal Qualified Reserves Evaluator (the IQRE) who is an employee of the Company, have evaluated the Company’s Reserves Data. The report of the IQRE accompanies this report.

 

The Reserves Committee of the board of directors of the Company has

 

a)             reviewed the Company’s procedures used by the IQRE and other internal qualified reserves evaluators to prepare the Reserves Data;

b)             met with the IQRE to determine whether any restrictions affected the ability of the IQRE to report without reservation; and

c)              reviewed the Reserves Data with management and the IQRE.

 

The Reserves Committee of the board of directors has reviewed the Company’s procedures for assembling and reporting other information associated with oil and gas activities and has reviewed that information with management. The board of directors has, on the recommendation of the Reserves Committee, approved

 

a)             the content and filing with securities regulatory authorities of Form 51-101F1 containing the Reserves Data and other oil and gas information;

b)             the filing of a report on the Reserves Data by the IQRE; and

c)              the content and filing of this report.

 

Because the Reserves Data are based on judgments regarding future events, actual results will vary and the variations may be material.

 

DATED as of this 24th day of February, 2013.

 

 
| (signed)   Kevin J. Reinhart |       | (signed)   Una M. Power           |
|------------------------------|------------|-----------------------------------|
| **Kevin J. Reinhart**        | ** ** | **Una M. Power**                  |
| Interim   President and      |       | Interim   Chief Financial Officer |
| Chief   Executive Officer    |       |                              |
|                         |       |                              |
|                         |       |                              |
| (signed)   William B. Berry  |       | (signed)   S. Barry Jackson       |
| **William B. Berry**         | ** ** | **S. Barry Jackson**              |
| Director                     |       | Director                          |

 

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* *

*NEXEN INC.*

 

*MANAGEMENT’S DISCUSSION AND ANALYSIS*

 

*For the Year Ended December 31, 2012*

 

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**MANAGEMENT’S DISCUSSION AND ANALYSIS (MD&A)**

 

*The following should be read in conjunction with the Consolidated Financial Statements of Nexen Inc. as at and for the year ended December 31, 2012. The Consolidated Financial Statements have been prepared in accordance with International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB). The date of this discussion is February 24, 2013. Unless otherwise noted, tabular amounts are in millions of Canadian dollars. Oil and gas volumes, reserves and related performance measures are presented on a working-interest before-royalties basis. We measure our performance in this manner consistent with other Canadian oil and gas companies. Where appropriate, we have provided information on an after-royalty basis.*

 

*Investors should read the “Forward-Looking Statements” on page 105.*

 

*Proved and probable reserves estimates included in this MD&A have been prepared in accordance with National Instrument 51-101—Standards of Disclosure for Oil and Gas Activities (NI 51-101). We have also prepared reserves estimates and disclosures in accordance with SEC requirements, which are included in Appendix B of our 2012 Annual Information Form (AIF).*

 

*Our AIF is available from our public filings with the Canadian Securities Administrators at www.sedar.com or from our website www.nexeninc.com. Investors should read the “Special Note to Investors” on page 33 in our 2012 AIF for a qualitative description of the differences between NI 51-101 and SEC reserve estimates and disclosures.*

 

**EXECUTIVE SUMMARY**

 
| **(Cdn$ millions, except otherwise indicated)**  | ** ** | **2012** | ** ** | **2011** | ** ** | **2010** | ** ** |
|-------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Production before   Royalties 1*(mboe/d)*             |       | 198      |       | 207      |       | 246      |       |
| Production after   Royalties *(mboe/d)*               |       | 189      |       | 186      |       | 220      |       |
|                                                  |       |     |       |     |       |     |       |
| Total Revenue and Other   Income                      |       | 6,711    |       | 6,853    |       | 7,266    |       |
| Cash Flow from   Operations 2, 3                      |       | 2,651    |       | 2,368    |       | 2,150    |       |
| Net Income 2                                          |       | 333      |       | 697      |       | 1,127    |       |
| Earnings per Common   Share, Basic 2 *($/share)* |       | 0.61     |       | 1.32     |       | 2.15     |       |
| Earnings per Common   Share, Diluted 2 *($/share)*    |       | 0.61     |       | 1.24     |       | 2.09     |       |
| Dividends per Common   Share *($/share)*              |       | 0.20     |       | 0.20     |       | 0.20     |       |
| Dividends per Preferred   Share *($/share)*           |       | 1.0178   |       | —   |       | —   |       |
| Total Assets                                          |       | 20,537   |       | 20,068   |       | 19,647   |       |
| Net Debt 4                                            |       | 3,114    |       | 3,538    |       | 4,085    |       |

 

----

*1**           **Production before royalties reflects our working interest before royalties. We have presented our working interest before royalties as we measure our performance on this basis consistent with other Canadian oil and gas companies. At Long Lake, we report bitumen as production.*

*2**           **Includes results of discontinued operations in 2011 and 2010 (see Note 23 of our Consolidated Financial Statements).*

*3**           **Cash flow from operations is a non-GAAP measure and is reconciled to the nearest GAAP measure on page 104.*

*4**           **Net debt is a non-GAAP measure and is reconciled to the nearest GAAP measure on page 104.*

 

Cash flow from operations increased 12% from 2011. Production before royalties averaged 197,900 boe/d in 2012, 4% lower than 2011. Production after royalties increased 2% as lower-royalty production at Usan, offshore Nigeria, offset the expiry of the Yemen Masila contract. Our weighting to crude oil prices, in particular to Brent crude oil, allowed us to realize a cash netback of $46.11/boe in 2012, 15% higher than last year.

 

Net income was 52% lower than the prior year. This primarily reflects the impact of higher share-based compensation expense as a result of the increase in our share price in part due to the proposed CNOOC Limited (CNOOC) acquisition, and lower gains from asset dispositions. Last year, net income included pre-tax gains of $386 million from asset dispositions compared to $194 million in 2012.

 

Our financial position remained strong and we continued to reduce net debt in 2012. We used proceeds from our joint venture sale and the issuance of $200 million of preferred shares to strengthen our balance sheet.

 

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**CORPORATE UPDATE**

 

CNOOC Acquisition of Nexen

 

On July 23, 2012, Nexen entered into an Arrangement Agreement in which CNOOC proposed to acquire all of the outstanding 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. Following close of the transaction, future activities of the Company will be directed by CNOOC.

 

**CAPITAL INVESTMENT**

 

In 2012, we continued to focus on key investment areas including Athabasca oil sands, Canadian shale gas and conventional offshore opportunities in the North Sea, deep-water Gulf of Mexico, and offshore Nigeria. We invested $3,072 million in oil and gas activities and increased our proved plus probable reserves by 60 mmboe. Additional information on our oil and gas reserves can be found in Reserves, Production and Related Information on page 14 of our 2012 AIF.

 
| ** **               | ** ** | **Capital   Investment   (Cdn$ millions)** | ** ** | **Production****1****(mmboe)** | ** ** | **Proved   Reserve   Increase****1,3****(mmboe)** | ** ** | **Probable   Reserve   Increase****1,3****(mmboe)** | ** ** |
|--------------------------|------------|-------------------------------------------------|------------|--------------------------------|------------|---------------------------------------------------|------------|-----------------------------------------------------|------------|
| Conventional Oil and Gas |       | 1,740                                           |       | 54                             |       | 10                                                |       | 75                                                  |       |
| Oil Sands                |       | 894                                             |       | 15                             |       | 5                                                 |       | (33                                                 | )          |
| Shale Gas                |       | 438                                             | 2          | 3                              |       | 2                                                 |       | 1                                                   |       |
| **Total Oil and Gas**    | ** ** | **3,072**                                       | ** ** | **72**                         | ** ** | **17**                                            | ** ** | **43**                                              | ** ** |

 

----

*1**           **Before royalties.*

*2**           **Approximately $264 million was recovered on closing of the sale of a 40% working interest in our Canadian shale gas development.*

*3**           **Before production and dispositions.*

 

Our 2012 proved reserve additions are not necessarily indicative of future annual additions which will be dependent on such factors as oil and gas prices, capital allocations, nature of our drilling programs, exploration success and expected timing of proceeding with development of reserves discovered. A significant portion of our properties involve large-scale, multi-year development projects and as a result, we review this over the longer term.

 

Our investment details in 2012 are highlighted below:

 
| **(Cdn$ millions)**               | ** ** | **2012**   | ** ** | **2011**   | ** ** |
|----------------------------------------|------------|------------|------------|------------|------------|
| **Conventional   Oil & Gas**       |       |       |       |       |       |
| UK North Sea                           |       | 1,022      |       | 583        |       |
| Nigeria                                |       | 336        |       | 543        |       |
| US Gulf of Mexico                      |       | 344        |       | 216        |       |
| Other                                  |       | 38         |       | 183        |       |
| ** **                             | ** ** | **1,740**  | ** ** | **1,525**  | ** ** |
| **Oil   Sands**                        |       |       |       |       |       |
| Long Lake, Kinosis and   Other In Situ |       | 690        |       | 397        |       |
| Syncrude                               |       | 204        |       | 124        |       |
| ** **                             | ** ** | **894**    | ** ** | **521**    | ** ** |
| **Shale   Gas**                        | ** ** | ** ** | ** ** | ** ** | ** ** |
| Northeast British   Columbia           |       | 346        | 1          | 398        |       |
| Other                                  |       | 92         |       | 72         |       |
|                                   | ** ** | **438**    | ** ** | **470**    | ** ** |
| ** **                             | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Total   Oil and Gas**                | ** ** | **3,072**  | ** ** | **2,516**  | ** ** |
| Corporate and Other                    |       | 52         |       | 59         |       |
| **Total   Capital**                    | ** ** | **3,124**  | ** ** | **2,575**  | ** ** |

 

----

*1**           **Approximately $264 million was recovered on closing of the sale of a 40% working interest in our Canadian shale gas development.*

 

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**Conventional Oil and Gas**

 

United Kingdom

 

The Golden Eagle development is progressing towards first oil in late 2014. Fabrication of the platform facilities is well underway and construction is on time and on budget. The facility will have a capacity of 70,000 boe/d (26,000 boe/d net to Nexen). We’ve received regulatory approval to proceed with development of the Solitaire field, a satellite field which will be tied back to the Golden Eagle facility.

 

We continue to progress other development projects in the North Sea. The Telford TAC well came on-stream in 2012. Development work is currently underway on the Rochelle field, which is expected to be tied into our Scott platform and come on stream in 2013.

 

We maintain an active UK exploration program. Drilling continues on our North Uist exploration prospect, which is located west of the Shetland Islands. Results are expected in 2013.

 

North America

 

Our priority in the Gulf of Mexico is focused on continuing our exploration and appraisal program in the Norphlet play, including the Appomattox structure. At Appomattox, we have booked approximately 106 million barrels of probable reserves (net to Nexen) in the northeast and south fault block structures to date. We have five more exploration and appraisal targets in the Norphlet play that we plan to test over the next twelve months. Results from these wells will allow us to progress a proposed development plan for the Appomattox area.

 

During 2012, we concluded negotiations around the Knotty Head-Pony field unitization. Nexen was the operator of the Knotty Head portion of the field and had a 25% working interest. Under the new equity agreement, Hess Corporation is the operator of the expanded Knotty Head-Pony project and all parties have a 20% working interest. The project has been renamed Stampede.

 

Other Countries

 

Oil production from Usan, offshore Nigeria started in February 2012. Since then, we have brought eleven wells on-stream and rates are approximately 120,000 bbls/d (24,000 bbls/d net to Nexen).

 

**Oil Sands**

 

Long Lake

 

At Long Lake, our focus is on advancing the 60 additional wells to fill the upgrader. This year, we brought pads 12 and 13 on stream. These 18 wells are expected to continue to ramp up in 2013. Earlier in the year, we received regulatory and partner approvals for pads 14, 15 and Kinosis K1A and began drilling operations there in the third quarter.

 

A significant turnaround was completed at Long Lake in 2012. During the turnaround, we carried out all required regulatory inspections, scheduled maintenance and preliminary preparation for future pads as planned without encountering any significant issues.

 

**Shale Gas**

 

Northeast British Columbia

 

Our previously announced joint venture agreement with INPEX Gas British Columbia Ltd. (IGBC) closed in August. We received $821 million of cash comprised of the cash consideration, reimbursement of IGBC’s share of costs since July 1, 2011 (effective date) and IGBC’s carry component of our costs since July 1, 2011.

 

We completed and brought on-stream another 18-well pad during the year. Production from this pad came on-stream in late September, ahead of schedule. We also began drilling a 10-well pad in the Horn River late in the year. Lease earning activities are underway on our Liard acreage.

 

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**FINANCIAL RESULTS**

 

Year-to-Year Change in Net Income

 
| **(Cdn$ millions)**                                                     | ** ** | **2012 vs 2011** | ** ** |
|------------------------------------------------------------------------------|------------|------------------|------------|
| **Net   Income for 2011****1**                                               | ** ** | **697**          | ** ** |
| Favourable   (Unfavourable) Variances 2                                      |       |             |       |
| Production Volumes,   After Royalties                                        |       |             |       |
| Crude Oil                                                                    |       | 291              |       |
| Natural Gas                                                                  |       | (33              | )          |
| Change in Crude Oil   Inventory for Sale                                     |       | 94               |       |
| Total Volume Variance                                                        |       | 352              |       |
| Realized Commodity   Prices                                                  |       |             |       |
| Crude Oil                                                                    |       | (12              | )          |
| Natural Gas                                                                  |       | (68              | )          |
| Total Price Variance                                                         |       | (80              | )          |
| Oil & Gas Operating   Expense                                            |       | (75              | )          |
| Oil & Gas   Depreciation, Depletion, Amortization and Impairment         |       | (36              | )          |
| Exploration Expense                                                          |       | (61              | )          |
| Corporate Expense 3                                                          |       | 27               |       |
| Share-based   Compensation                                                   |       | (262             | )          |
| Income Taxes                                                                 |       | (149             | )          |
| Foreign Exchange                                                             |       | (85              | )          |
| Non-recurring Events                                                         |       |             |       |
| Pre-tax Gain on Shale   Gas Joint Venture                                    |       | 142              |       |
| Prior Year Gains on   Disposition and Loss on Debt Redemption and Repurchase |       | (295             | )          |
| UK Income Tax Rate   Change                                                  |       | 207              |       |
| Other                                                                        |       | (49              | )          |
| **Net   Income for 2012**                                                    | ** ** | **333**          | ** ** |

 

----

*1**           **Includes results of discontinued operations (see Note 23 of our Consolidated Financial Statements).*

*2**           **All amounts are presented before provision for income taxes.*

*3**           **Includes general & administrative expense, finance costs and energy marketing results.*

 

Significant variances in net income are explained in the sections that follow.

 

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** **

**OIL & GAS**

 

Production

 
| ** **                             | ** ** | **2012**                    | ** ** | **2011**              | ** ** |
|----------------------------------------|------------|-----------------------------|------------|-----------------------|------------|
| ** **                             | ** ** | **Before   Royalties****1** | ** ** | **After   Royalties** | ** ** | **Before   Royalties****1** | ** ** | **After   Royalties** | ** ** |
|                                   |       |                        |       |                  |       |   |   |   |   |
| **Conventional Oil and Gas***(mboe/d)* |       |                        |       |                  |       |   |   |   |   |
| United Kingdom                         |       | 99.0                        |       | 98.5                  |       | 90.0 |   | 89.7 |   |
| North America 2                        |       | 35.9                        |       | 33.6                  |       | 43.1 |   | 39.9 |   |
| Other Countries 3                      |       | 22.1                        |       | 18.4                  |       | 34.5 |   | 19.7 |   |
| **Oil Sands**                          |       |                        |       |                  |       |   |   |   |   |
| Long Lake Bitumen 4                    |       | 20.2                        |       | 19.0                  |       | 18.6 |   | 17.3 |   |
| Syncrude                               |       | 20.7                        |       | 19.9                  |       | 20.9 |   | 19.2 |   |
| **Total Production**                   | ** ** | **197.9**                   | ** ** | **189.4**             | ** ** | **207.1** | ** ** | **185.8** | ** ** |
|                                   |       |                        |       |                  |       |   |   |   |   |
| Total Crude Oil and Liquids *(mboe/d)* |       | 163.3                       |       | 156.4                 |       | 167.3 |   | 148.3 |   |
| Total Natural Gas *(mmcf/d)*           |       | 207                         |       | 198                   |       | 239 |   | 225 |   |

 

----

*1**           **We have presented production volumes before royalties as we measure our performance on this basis consistent with other Canadian oil and gas companies.*

*2**           **Includes shale gas production in Canada.*

*3**           **Includes Nigeria, Yemen and Colombia.*

*4**           **We report Long Lake bitumen as production.*

 

2012 VS 2011 — HIGHER VOLUMES INCREASED NET INCOME $352 MILLION

 

Production before royalties averaged 197,900 boe/d in 2012, 4% lower than 2011; whereas production after royalties increased 2% as lower-royalty production at Usan, offshore Nigeria, offset production lost from the expiry of the Yemen Masila contract. During 2012, production increased at Long Lake and in the UK North Sea, despite major facility turnarounds.

 

The following table summarizes our production changes year-over-year:

 
| **(mboe/d)**                         | ** ** | **Before****Royalties** | ** ** | **After****Royalties** | ** ** |
|--------------------------------------|------------|-------------------------|------------|------------------------|------------|
| 2011 Production                      |       | 207                     |       | 186                    |       |
| Production Changes                   |       |                    |       |                   |       |
| Nigeria                              |       | 16                      |       | 14                     |       |
| United Kingdom                       |       | 9                       |       | 9                      |       |
| Oil Sands — Long Lake   Bitumen |       | 2                       |       | 2                      |       |
| North America                        |       | (7                      | )          | (6                     | )          |
| Yemen                                |       | (29                     | )          | (16                    | )          |
| **2012   Production**                | ** ** | **198**                 | ** ** | **189**                | ** ** |

 

Production in the fourth quarter of 2012 averaged 195,800 boe/d (187,100 boe/d after royalties), 15,300 boe/d higher than the previous quarter. Scheduled major turnarounds in the UK North Sea and at Long Lake were completed early in the fourth quarter of 2012, which allowed the fields to resume normal operations. Compared to the fourth quarter of 2011, production decreased 12,300 boe/d primarily as a result of the expiry of the Masila contract in Yemen and scheduled major turnarounds in the UK North Sea. These shortfalls were partially offset by improved production at Syncrude.

 

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**Conventional Oil and Gas**

 

United Kingdom

 

UK production increased 10% over last year to average 99,000 boe/d, despite downtime for scheduled turnarounds on the Buzzard and Scott/Telford platforms.

 

Improved uptime at Buzzard resulted in an 11% increase in production to 69,300 boe/d in 2012. The scheduled major turnaround at Buzzard was completed in the fourth quarter with no significant issues encountered. Our production efficiency rate at Buzzard was 85% before planned shutdowns.

 

Production from the Ettrick/Blackbird field contributed 15,900 boe/d to our annual volumes, a 9% increase over last year. This increase reflects a full year of production from the Blackbird field that came on-stream in November 2011.

 

Scott/Telford averaged 13,800 boe/d, 6% higher than 2011 primarily as a result of improved operating efficiencies and the tie-in of the Telford TAC well. This was partially offset by natural declines in the Scott field and a scheduled turnaround on the Scott platform. Tie-in of the Telford TAC development well was completed in the first quarter of 2012.

 

North America

 

Production in North America decreased 17% from last year to average 35,900 boe/d, primarily due to declines in mature conventional fields in the US Gulf of Mexico and Canada. These declines were partially offset by increases from shale gas in northeast British Columbia.

 

Production in Canada increased in 2012 despite the sale of a 40% working interest in our northeast British Columbia shale gas operations in August. Shale gas production at Horn River averaged 53 mmcf/d for the year, 38% higher than the previous year. This increase reflects a full year of production from our nine-well pad that came on-stream in October 2011 and new production from our 18-well pad that came on-stream in September 2012. Production from our conventional gas and CBM properties in western Canada declined 19% from the same period last year as a result of natural declines from limited capital investment in a weak natural gas price environment.

 

Production in the Gulf of Mexico averaged 15,600 boe/d in 2012, 31% lower than 2011. Higher water content in the Longhorn field and extended third-party facility maintenance at Wrigley contributed to the reduction. This was partially offset by restoring production at the Green Canyon 6/137 fields in the third quarter, which have been off-line since Hurricane Ike in 2008.

 

Other Countries

 

First oil at Usan, offshore Nigeria, was achieved in February 2012. Eleven wells are now on-stream and production averaged 80,500 bbls/d (16,100 net to Nexen) in 2012. Fourth quarter production averaged 109,000 bbls/d (21,800 bbls/d net to us).

 

Our Masila contract with the Yemen government expired in December 2011. We continue to operate Block 51 in Yemen and current production is approximately 4,300 bbls/d. Production from Colombia decreased 12% from last year to average 1,500 bbls/d in 2012.

 

**Oil Sands**

 

Long Lake

 

Long Lake production averaged 31,100 bbls/d (20,200 bbls/d net to us) during the year, an increase of 2,500 bbls/d (1,600 bbls/d net to us) despite the scheduled major facility turnaround in the third quarter of 2012. The increase reflects continued ramp-up of pad 11 and well optimization activities on the first ten pads. Additionally, first oil from pads 12 and 13 began during the second half of the year.

 

Syncrude

 

Syncrude production averaged 20,700 bbls/d for the year, which is comparable to 2011 production rates. Turnarounds on coker 8-1 and 8-3, as well as other maintenance activities, were completed during the year.

 

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Commodity Prices

 
| ** **                                                        | ** ** | **2012**   | ** ** | **2011**   | ** ** |
|-------------------------------------------------------------------|------------|------------|------------|------------|------------|
| **Crude   Oil**                                                   |       |       |       |       |       |
| Dated Brent (Brent) *(US$/bbl)*                                   |       | 111.99     |       | 111.28     |       |
| West Texas Intermediate   (WTI) *(US$/bbl)*                       |       | 94.20      |       | 95.12      |       |
|                                                              |       |       |       |       |       |
| Realized Prices from   Producing Assets *(Cdn$/bbl)*              |       |       |       |       |       |
| United Kingdom                                                    |       | 109.98     |       | 106.76     |       |
| North America                                                     |       | 101.91     |       | 99.56      |       |
| Other Countries 1                                                 |       | 108.06     |       | 107.49     |       |
| Oil Sands — Long Lake                                        |       | 86.57      |       | 98.33      |       |
| Oil Sands — Syncrude                                         |       | 91.23      |       | 101.73     |       |
|                                                              |       |       |       |       |       |
| Corporate Average *(Cdn$/bbl)*                                    |       | 104.64     |       | 105.21     |       |
| **Natural   Gas**                                                 |       |       |       |       |       |
| New York Mercantile   Exchange (NYMEX) *(US$/mmbtu)*              |       | 2.82       |       | 4.03       |       |
| AECO *(Cdn$/mcf)*                                                 |       | 2.28       |       | 3.48       |       |
| Realized Prices from   Producing Assets *(Cdn$/mcf)*              |       |       |       |       |       |
| United Kingdom                                                    |       | 7.86       |       | 7.42       |       |
| North America                                                     |       | 2.37       |       | 3.81       |       |
|                                                              |       |       |       |       |       |
| Corporate Average *(Cdn$/mcf)*                                    |       | 3.38       |       | 4.31       |       |
| **Nexen’s   Average Realized Oil and Gas Price***(Cdn$/boe)* | ** ** | **89.81**  | ** ** | **91.46**  | ** ** |
| ** **                                                        | ** ** | ** ** | ** ** | ** ** | ** ** |
| Average Foreign   Exchange Rate — Canadian to US Dollar      |       | 1.0004     |       | 1.0117     |       |

 

----

*1**           **Includes Nigeria, Yemen and Colombia.*

 

2012 VS 2011 — LOWER REALIZED COMMODITY PRICES REDUCED NET INCOME BY $80 MILLION

 

Crude oil prices in 2012 were relatively consistent with 2011. The Brent benchmark price averaged US$111.99/bbl in 2012. WTI was slightly lower than 2011, averaging US$94.20/bbl. This contributed to a realized average crude oil price of $104.64/bbl as approximately 75% of our crude oil production is sold based on the Brent benchmark. On average, synthetic crude prices decreased from 2011 as higher production in Canada and the US further congested pipelines and storage systems. We receive synthetic crude oil prices for our Long Lake Premium Synthetic CrudeTM (PSCTM) and Syncrude sales.

 

In North America, NYMEX and AECO natural gas prices decreased 30% and 34% from the prior year, respectively. Our realized natural gas price decreased 22% to average $3.38/mcf, as a portion of our natural gas production is located in the UK North Sea where prices are higher.

 

The Canadian/US exchange rate averaged close to par during 2012, a decrease of 1 cent relative to 2011. This change increased sales by approximately $69 million.

 

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Operating Expenses

 
| **(Cdn$ millions)**                                 | ** ** | **2012**   | ** ** | **2011**   | ** ** |
|----------------------------------------------------------|------------|------------|------------|------------|------------|
| **Conventional   Oil and Gas**                           |       |       |       |       |       |
| United Kingdom                                           |       | 439        |       | 353        |       |
| North America                                            |       | 171        |       | 156        |       |
| Other Countries 1                                        |       | 134        |       | 164        |       |
| **Oil   Sands**                                          |       |       |       |       |       |
| Long Lake 2                                              |       | 466        |       | 439        |       |
| Syncrude                                                 |       | 264        |       | 287        |       |
| **Total   Oil and Gas Operating Expense**                | ** ** | **1,474**  | ** ** | **1,399**  | ** ** |
|                                                     |       |       |       |       |       |
| **(Cdn$/boe)**                                           | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Conventional   Oil and Gas**                           |       |       |       |       |       |
| United Kingdom                                           |       | 11.89      |       | 10.60      |       |
| North America                                            |       | 13.09      |       | 11.15      |       |
| Other Countries 1                                        |       | 16.84      |       | 12.73      |       |
| **Oil   Sands**                                          |       |       |       |       |       |
| Long Lake 2                                              |       | 71.87      | 3          | 83.44      |       |
| Syncrude                                                 |       | 34.86      |       | 37.78      |       |
| **Average   Oil and Gas Operating Expense per boe****4** | ** ** | **19.86**  | ** ** | **19.00**  | ** ** |

 

----

*1**           **Includes Nigeria, Yemen and Colombia.*

*2**           **Excludes activities related to third-party bitumen purchased, processed and sold.*

*3**           **Excludes costs related to turnaround activities.*

*4**           **Operating expenses per boe are total oil and gas operating costs divided by working interest sales, before royalties.*

 

2012 VS 2011 — HIGHER OIL AND GAS OPERATING EXPENSES REDUCED NET INCOME BY $75 MILLION

 

Oil and gas operating costs increased $75 million. This increased our corporate average per-unit operating costs by $0.86/boe.

 

Per-unit operating costs in the UK North Sea increased 12% during the year primarily due to the costs related to the turnarounds being completed at Scott/Telford and Buzzard. At Ettrick and Scott/Telford, per unit costs were also impacted by additional sub-sea maintenance, diesel consumption and volume-related tariff increases.

 

In North America, reduced production volumes combined with relatively fixed costs, increased our average per-unit operating costs. In other countries, the expiration of the Masila contract in Yemen and new production at Usan, offshore Nigeria increased our corporate average.

 

Long Lake per-unit operating expenses exclude costs directly related to the scheduled turnaround activity in the third quarter. For 2012, operating costs per boe at Long Lake were 14% lower due to higher production volumes. As the majority of the operating costs at Long Lake are fixed, higher production volumes have a significant impact on per-unit operating costs.

 

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

 
| **(Cdn$ millions)**                        | ** ** | **2012**   | ** ** | **2011**   | ** ** |
|-------------------------------------------------|------------|------------|------------|------------|------------|
| **Conventional   Oil and Gas**                  |       |       |       |       |       |
| United Kingdom                                  |       | 752        |       | 631        |       |
| North America                                   |       | 277        |       | 386        |       |
| Other Countries 1                               |       | 371        |       | 76         |       |
| **Oil   Sands**                                 |       |       |       |       |       |
| Long Lake                                       |       | 192        |       | 131        |       |
| Syncrude                                        |       | 66         |       | 60         |       |
| Impairment                                      |       | 237        |       | 322        |       |
| Derecognition of Oil   Sands Costs              |       | —     |       | 253        |       |
| **Total   Oil and Gas DD&A**                | ** ** | **1,895**  | ** ** | **1,859**  | ** ** |
|                                            |       |       |       |       |       |
| **(Cdn$/boe)**                                  | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Conventional   Oil and Gas**                  |       |       |       |       |       |
| United Kingdom                                  |       | 20.46      |       | 18.92      |       |
| North America                                   |       | 21.15      |       | 23.72      |       |
| Other Countries 1                               |       | 46.63      |       | 5.99       |       |
| **Oil   Sands**                                 |       |       |       |       |       |
| Long Lake                                       |       | 28.16      |       | 18.36      |       |
| Syncrude                                        |       | 8.73       |       | 7.85       |       |
| **Average   Oil and Gas DD&A per boe****2** | ** ** | **22.91**  | ** ** | **16.39**  | ** ** |

 

----

*1**           **Includes**Nigeria, Yemen and Colombia.*

*2**           **DD&A per boe is our DD&A for oil and gas operations divided by our working interest sales, before royalties and excludes impairment charges and derecognition of oil sands costs described in Note 5 of our Consolidated Financial Statements.*

 

2012 VS 2011 — HIGHER OIL AND GAS DD&A DECREASED NET INCOME BY $36 MILLION

 

DD&A expense increased by $36 million. Lower estimated future natural gas prices and revisions to abandonment costs resulted in a $237 million non-cash impairment charge for mature conventional gas properties in North America in 2012. DD&A in 2011 includes non-cash impairment charges of $322 million for oil and gas properties in North America and $253 million of previously capitalized design and engineering costs for future phases at Long Lake.

 

On a per-unit basis, average DD&A rates increased in 2012 with new higher-cost developments such as Usan coming on-stream. While the Usan DD&A rate is initially high, we expect this rate will decrease as ongoing development activities convert proved undeveloped reserves to proved developed reserves, which are used for DD&A calculations.

 

In the UK, depletion rates at Blackbird, which came on-stream in November 2011, increased our DD&A per boe. The initial Blackbird depletion rate was high as a portion of the proved reserves were classified as undeveloped and not used to deplete capitalized costs.

 

At Long Lake, the depletion rate increased as a result of lower proved producing reserves used for depletion calculations. This decrease in reserves for depletion purposes was a result of 2011 reserve revisions, where we reclassified some producing area reserves from proved to probable.

 

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Exploration Expense

 
| **(Cdn$ millions)**        | ** ** | **2012** | ** ** | **2011** | ** ** |
|---------------------------------|------------|----------|------------|----------|------------|
| Unsuccessful Drilling           |       | 227      |       | 65       |       |
| Seismic                         |       | 71       |       | 74       |       |
| Other 1                         |       | 131      |       | 229      |       |
| **Total   Exploration Expense** | ** ** | **429**  | ** ** | **368**  | ** ** |

 

----

*1**           **Consists of unutilized drilling costs, exploration support costs, lease rental expenses and pre-license expenditures.*

 

2012 VS 2011 — INCREASED EXPLORATION COSTS DECREASED NET INCOME BY $61 MILLION

 

Our exploration program is primarily focused on opportunities in the deep-water US Gulf of Mexico, the UK North Sea, offshore Nigeria and Canada. In 2012, we drilled 15 exploration and appraisal wells. Exploration and appraisal drilling activity included Kakuna and Appomattox in the US Gulf of Mexico, North Uist in the UK North Sea and Owowo West offshore Nigeria.

 

Unsuccessful drilling costs were $162 million higher in 2012 primarily due to expensing $126 million of exploration costs related to the Kakuna exploration well in the US Gulf of Mexico.

 

Other exploration costs were $98 million lower than the prior year. In 2011, other exploration expense included non-recurring lease rental expenses and unutilized drilling rig costs in the US Gulf of Mexico and the Norwegian North Sea.

 

**OIL & GAS CASH NETBACKS**

 

Cash netbacks are the cash margins we receive for every equivalent barrel sold before general and administrative expenses.

 

The UK, Nigeria, Syncrude and deep-water Gulf of Mexico assets have strong cash netbacks and generate 74% of our production. US Shelf and Canadian gas assets continue to have positive operating cash netbacks despite low gas prices. The in-situ cash netback for the year was $10.07/bbl. The netback was slightly higher this year despite lower realized prices. This is a result of higher volumes on relatively fixed costs.

 

The following table includes the sales prices, per-unit costs and netbacks for our producing assets, calculated using our working interest production before and after royalties.

 

Before Royalties 1

 
| ** **            | ** ** | **2012**                  | ** ** |
|-----------------------|------------|---------------------------|------------|
| ** **            | ** ** | **Conventional**          | ** ** | **Oil Sands** | ** ** | ** ** | ** ** |
| **(Cdn$/boe)**        | ** ** | **United********Kingdom** | ** ** | **North********America** | ** ** | **Other********Countries****2** | ** ** | **In Situ** | ** ** | **Syncrude** | ** ** | **Total Oil********and Gas** | ** ** |
| Price Received        |       | 106.03                    |       | 33.63 |   | 108.06 |   | 86.57 |   | 91.23 |   | 89.81 |   |
| Royalties and Other   |       | (0.61                     | )          | (2.99 | ) | (19.69 | ) | (4.63 | ) | (3.42 | ) | (3.80 | ) |
| Operating Expenses    |       | (11.89                    | )          | (13.09 | ) | (16.40 | ) | (71.87 | )3 | (34.86 | ) | (19.86 | ) |
| In-country Cash Taxes |       | (38.15                    | )          | — |   | (2.33 | ) | — |   | — |   | (20.04 | ) |
| **Cash Netback**      | ** ** | **55.38**                 | ** ** | **17.55** | ** ** | **69.64** | ** ** | **10.07** | ** ** | **52.95** | ** ** | **46.11** | ** ** |

 

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| ** **            | ** ** | **2011**                  | ** ** |
|-----------------------|------------|---------------------------|------------|
| ** **            | ** ** | **Conventional**          | ** ** | **Oil Sands** | ** ** | ** ** | ** ** |
| **(Cdn$/boe)**        | ** ** | **United********Kingdom** | ** ** | **North********America** | ** ** | **Other********Countries****2** | ** ** | **In Situ** | ** ** | **Syncrude** | ** ** | **Total Oil********and Gas** | ** ** |
| Price Received        |       | 103.32                    |       | 39.41 |   | 107.85 |   | 98.33 |   | 101.73 |   | 91.46 |   |
| Royalties and Other   |       | (0.36                     | )          | (3.72 | ) | (46.92 | ) | (5.05 | ) | (8.10 | ) | (10.34 | ) |
| Operating Expenses    |       | (10.60                    | )          | (11.15 | ) | (12.73 | ) | (83.44 | ) | (37.78 | ) | (19.00 | ) |
| In-country Cash Taxes |       | (42.41                    | )          | — |   | (14.17 | ) | — |   | — |   | (21.92 | ) |
| **Cash Netback**      | ** ** | **49.95**                 | ** ** | **24.54** | ** ** | **34.03** | ** ** | **9.84** | ** ** | **55.85** | ** ** | **40.20** | ** ** |

 

After Royalties 1

 
| ** **            | ** ** | **2012**                  | ** ** |
|-----------------------|------------|---------------------------|------------|
| ** **            | ** ** | **Conventional**          | ** ** | **Oil Sands** | ** ** | ** ** | ** ** |
| **(Cdn$/boe)**        | ** ** | **United********Kingdom** | ** ** | **North********America** | ** ** | **Other********Countries****2** | ** ** | **In Situ** | ** ** | **Syncrude** | ** ** | **Total Oil********and Gas** | ** ** |
| Price Received        |       | 106.03                    |       | 33.63 |   | 108.06 |   | 86.57 |   | 91.23 |   | 89.81 |   |
| Operating Expenses    |       | (11.96                    | )          | (13.99 | ) | (19.90 | ) | (77.18 | )3 | (36.22 | ) | (20.77 | ) |
| In-country Cash Taxes |       | (38.36                    | )          | — |   | (2.82 | ) | — |   | — |   | (20.96 | ) |
| **Cash Netback**      | ** ** | **55.71**                 | ** ** | **19.64** | ** ** | **85.34** | ** ** | **9.39** | ** ** | **55.01** | ** ** | **48.08** | ** ** |

** **
| ** **            | ** ** | **2011**                  | ** ** |
|-----------------------|------------|---------------------------|------------|
| ** **            | ** ** | **Conventional**          | ** ** | **Oil Sands** | ** ** | ** ** | ** ** |
| **(Cdn$/boe)**        | ** ** | **United********Kingdom** | ** ** | **North********America** | ** ** | **Other********Countries****2** | ** ** | **In Situ** | ** ** | **Syncrude** | ** ** | **Total Oil********and Gas** | ** ** |
| Price Received        |       | 103.32                    |       | 39.41 |   | 107.85 |   | 98.33 |   | 101.73 |   | 91.46 |   |
| Operating Expenses    |       | (10.64                    | )          | (12.20 | ) | (22.54 | ) | (90.22 | ) | (40.94 | ) | (21.30 | ) |
| In-country Cash Taxes |       | (42.56                    | )          | — |   | (25.07 | ) | — |   | — |   | (24.58 | ) |
| **Cash Netback**      | ** ** | **50.12**                 | ** ** | **27.21** | ** ** | **60.24** | ** ** | **8.11** | ** ** | **60.79** | ** ** | **45.58** | ** ** |

 

----

*1**           **Before-royalty cash netbacks are calculated by dividing sales, royalties and other, operating expenses and in-country taxes by production before royalties. After-royalty cash netbacks are calculated by dividing sales, operating expenses and in-country taxes by production after royalties.*

*2**           **Includes results of conventional crude oil operations in Nigeria, Yemen and Colombia.*

*3**           **Excludes costs related to turnaround activities.*

 

**CORPORATE**

 

General and Administrative (G&A) Expense 1

 
| **(Cdn$ millions)**                                             | ** ** | **2012** | ** ** | **2011** | ** ** |
|----------------------------------------------------------------------|------------|----------|------------|----------|------------|
| General and   Administrative Expense before Share-Based Compensation |       | 404      |       | 377      |       |
| Share-Based   Compensation (Recovery) 2                              |       | 187      |       | (75      | )          |
| **Total**                                                            | ** ** | **591**  | ** ** | **302**  | ** ** |

 

----

*1**           **Includes results of discontinued operations (see Note 23 of our Consolidated Financial Statements).*

*2**           **Includes cash and non-cash expenses (recoveries) related to our tandem option plan, stock appreciation rights plan, restricted share unit plan, deferred share unit plan and performance share unit plan.*

 

2012 VS 2011 — HIGHER G&A COSTS DECREASED NET INCOME BY $289 MILLION

 

G&A costs increased $289 million from 2011, primarily due to higher share-based compensation expense which was mostly related to the increase in our share price in 2012, in part due to the proposed acquisition by CNOOC. Changes in our share price create volatility in our net income as we account for share-based compensation using the fair-value method. During the year, we expensed non-cash share-based compensation costs of $157 million as our share price ended the year at $26.57/share, compared to the previous year when it closed at $16.21/share. In addition, cash payments for share-based compensation programs of $30 million were higher than the $11 million paid in 2011.

 

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Finance Expense

 
| **(Cdn$ millions)**                                    | ** ** | **2012** | ** ** | **2011** | ** ** |
|-------------------------------------------------------------|------------|----------|------------|----------|------------|
| Long-Term Debt Interest   Expense                           |       | 296      |       | 306      |       |
| Accretion Expense   Related to Asset Retirement Obligations |       | 52       |       | 44       |       |
| Other Interest and Fees                                     |       | 25       |       | 27       |       |
| Less: Capitalized   Borrowing Costs                         |       | (72      | )          | (124     | )          |
| **Total**                                                   | ** ** | **301**  | ** ** | **253**  | **1**      |
| Effective Interest Rate                                     |       | 6.7      | %          | 6.7      | %          |

 

----

*1**           **Includes results of discontinued operations (see Note 23 of our Consolidated Financial Statements).*

 

2012 VS 2011 — HIGHER FINANCE COSTS DECREASED NET INCOME BY $48 MILLION

 

Finance costs increased by 19% compared to 2011, primarily due to lower capitalized interest. Capitalized borrowing costs were $52 million lower than last year as we ceased capitalization on the Usan project when it came on-stream in February 2012. Currently, we are capitalizing interest on our Golden Eagle project in the UK North Sea and in-situ oil sands development projects.

 

Income Tax Expense

 
| **(Cdn$ millions)**               | ** ** | **2012**  | ** ** | **2011**  | ** ** |
|----------------------------------------|------------|-----------|------------|-----------|------------|
| Current                                |       | 1,460     |       | 1,584     |       |
| Deferred                               |       | (139      | )          | (205      | )1         |
| **Total   Provision for Income Taxes** | ** ** | **1,321** | ** ** | **1,379** | ** ** |

 

----

*1**           **Includes $51 million of deferred tax expense related to discontinued operations (see Note 23 of our Consolidated Financial Statements).*

 

2012 VS 2011 — LOWER TAXES INCREASED NET INCOME BY $58 MILLION

 

Our income tax provision includes current taxes in the UK, Yemen and Colombia. On July 17, 2012, UK government legislation was enacted to restrict relief for decommissioning expenses incurred after March 21, 2012 to the previous 50% income tax rate. This resulted in a one-time non-cash deferred income tax charge of $63 million.

 

In the first quarter of 2011, we recorded a one-time, non-cash deferred income tax charge of $270 million related to the increase in the UK statutory income tax rate on North Sea oil and gas activities from 50% to 62%.

 

Energy Marketing

 

2012 VS 2011 — HIGHER MARKETING CONTRIBUTION INCREASED NET INCOME BY $125 MILLION

 

Our energy marketing business generated solid results in 2012. In the first quarter of 2012, in Canada we secured 18,000 bbls/d of long-term pipeline capacity to the west coast on the Trans Mountain pipeline. This has allowed us to capture approximately $145 million of additional cash flow as we are able to realize Brent-linked pricing for otherwise heavily discounted Canadian crude oil.

 

COMPOSITION OF MARKETING ACTIVITIES

 
| **(Cdn$ millions)**                      | ** ** | **2012** | ** ** | **2011** | ** ** |
|-----------------------------------------------|------------|----------|------------|----------|------------|
| Trading Activities   (Physical and Financial) |       | 191      |       | 64       |       |
| Other Activities                              |       | 23       |       | 25       |       |
| **Total**                                     | ** ** | **214**  | ** ** | **89**   | ** ** |

 

TRADING ACTIVITIES

 

In our energy marketing group, we enter into contracts to purchase and sell energy commodities, primarily crude oil. We also use financial and derivative contracts, including futures, forwards, swaps and options for hedging and trading purposes. We account for all derivative contracts and commodity trading inventory using fair value accounting and record the net gain or loss from their revaluation in marketing and other income.

 

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OTHER ACTIVITIES

 

We enter into fee-for-service contracts related to transportation and storage of third-party oil and gas. In addition, we earn income from our power generation facilities at Balzac and Soderglen.

 

Other 1

 
| **(Cdn$ millions)**                          | ** ** | **2012** | ** ** | **2011** | ** ** |
|---------------------------------------------------|------------|----------|------------|----------|------------|
| Gain on Dispositions                              |       | 194      |       | 386      |       |
| Decrease in Fair Value   of Crude Oil Put Options |       | (38      | )          | (23      | )          |
| Loss on Debt Redemption   and Repurchase          |       | —   |       | (91      | )          |

 

----

*1**           **Includes results of discontinued operations (see Note 23 of our Consolidated Financial Statements).*

 

In 2012, we closed the sale of a 40% working interest in our northeast British Columbia shale gas operations to a consortium led by INPEX Gas British Columbia Ltd. (IGBC). Upon closing, we received $821 million in proceeds. We recorded a pre-tax gain on sale of $142 million on closing. We also disposed non-core leases in Canada in 2012, realizing a gain of $45 million.

 

In 2011, we realized net gains of $386 million on the disposition of non-core assets. We sold our 62.7% investment in Canexus for net proceeds of $458 million, realizing a gain of $348 million. We also sold our interest in the Duart field in the UK North Sea for proceeds of $38 million, realizing a gain of $38 million.

 

Crude oil put options are purchased to provide a base level of price protection without limiting our upside to higher prices. These options settle monthly or annually and unexpired options are recorded at fair value. As a result, changes in forward crude oil prices create gains or losses on the options at each period end. In 2012, we recorded a fair value loss of $38 million on crude oil put options (2011—$23 million loss).

 

During 2011, we paid $525 million to redeem the US$500 million notes due in 2013. We incurred a $52 million loss on the transaction being the difference between carrying cost and the redemption price. We also paid $346 million to repurchase and cancel US$312 million of notes due in 2015 and 2017. We incurred a $39 million loss on the repurchase.

 

Segmented Cash Flow from Operations 1

 
| **(Cdn$ millions)**                      | ** ** | **2012**   | ** ** | **2011**   | ** ** |
|-----------------------------------------------|------------|------------|------------|------------|------------|
| **Conventional Oil and Gas**                  |       |       |       |       |       |
| United Kingdom                                |       | 3,475      |       | 3,085      |       |
| North America                                 |       | 109        |       | 252        |       |
| Other Countries 2                             |       | 534        |       | 390        |       |
| **Oil Sands**                                 | ** ** | ** ** | ** ** | ** ** | ** ** |
| Long Lake                                     |       | (41        | )          | 5          |       |
| Syncrude                                      |       | 377        |       | 405        |       |
|                                          |       | 4,454      |       | 4,137      |       |
| Interest, Marketing and Other Corporate Items |       | (343       | )          | (367       | )3         |
| Current Income Taxes                          |       | (1,460     | )          | (1,402     | )          |
| **Total Cash Flow From Operations**           | ** ** | **2,651**  | ** ** | **2,368**  | ** ** |

 

----

1              Cash flow from operations is a non-GAAP measure and is reconciled to the nearest GAAP measure on page 104.

2              Includes Nigeria, Yemen and Colombia.

3              Includes results of discontinued operations. See Note 23 of our Consolidated Financial Statements.

 

Compared to 2011, cash flow from operations increased 12%, driven by strong performance in the UK and first cash flow from Nigeria. These increases were partially offset by low North American natural gas prices, the expiry of the Masila contract in Yemen and additional costs related to the scheduled turnaround at Long Lake.

 

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**SUMMARY OF QUARTERLY RESULTS**

 
| ** **                                                                          | ** ** | **2011**   | ** ** | **2012**   | ** ** |
|-------------------------------------------------------------------------------------|------------|------------|------------|------------|------------|
| **(Cdn$ millions, except per share amounts)**                                  | ** ** | **Mar**    | ** ** | **Jun**    | ** ** | **Sep** | ** ** | **Dec** | ** ** | **Mar** | ** ** | **Jun** | ** ** | **Sep** | ** ** | **Dec** | ** ** |
| Net   Sales from Continuing Operations                                              |       | 1,598      |       | 1,507      |       | 1,399 |   | 1,665 |   | 1,696 |   | 1,659 |   | 1,495 |   | 1,580 |   |
| Net   Income (Loss) from Continuing Operations before Income Taxes is Comprised of: |       |       |       |       |       |   |   |   |   |   |   |   |   |   |   |   |   |
| Oil   and Gas                                                                       |       | 677        |       | 660        |       | 501 |   | 297 |   | 771 |   | 571 |   | 586 |   | 258 |   |
| Corporate   and Other                                                               |       | (228       | )          | (76        | )          | 7 |   | (115 | ) | (151 | ) | (59 | ) | (240 | ) | (82 | ) |
|                                                                                | ** ** | **449**    | ** ** | **584**    | ** ** | **508** | ** ** | **182** | ** ** | **620** | ** ** | **512** | ** ** | **346** | ** ** | **176** | ** ** |
|                                                                                |       |       |       |       |       |   |   |   |   |   |   |   |   |   |   |   |   |
| **Net   Income (Loss) from Continuing****Operations**                               | ** ** | **(100**   | **)**      | **252**    | ** ** | **200** | ** ** | **43** | ** ** | **171** | ** ** | **109** | ** ** | **59** | ** ** | **(6** | **)** |
| ** **                                                                          | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Net   Income (Loss)**                                                             | ** ** | **202**    | ** ** | **252**    | ** ** | **200** | ** ** | **43** | ** ** | **171** | ** ** | **109** | ** ** | **59** | ** ** | **(6** | **)** |
|                                                                                |       |       |       |       |       |   |   |   |   |   |   |   |   |   |   |   |   |
| **Earnings   (Loss) per Common Share****from Continuing Operations***($/share)*     |       |       |       |       |       |   |   |   |   |   |   |   |   |   |   |   |   |
| Basic                                                                               |       | (0.19      | )          | 0.48       |       | 0.38 |   | 0.08 |   | 0.32 |   | 0.20 |   | 0.11 |   | (0.02 | ) |
| Diluted                                                                             |       | (0.19      | )          | 0.45       |       | 0.32 |   | 0.08 |   | 0.32 |   | 0.19 |   | 0.11 |   | (0.02 | ) |
|                                                                                |       |       |       |       |       |   |   |   |   |   |   |   |   |   |   |   |   |
| **Earnings   per Common Share***($/share)*                                          |       |       |       |       |       |   |   |   |   |   |   |   |   |   |   |   |   |
| Basic                                                                               |       | 0.38       |       | 0.48       |       | 0.38 |   | 0.08 |   | 0.32 |   | 0.20 |   | 0.11 |   | (0.02 | ) |
| Diluted                                                                             |       | 0.38       |       | 0.45       |       | 0.32 |   | 0.08 |   | 0.32 |   | 0.19 |   | 0.11 |   | (0.02 | ) |
|                                                                                |       |       |       |       |       |   |   |   |   |   |   |   |   |   |   |   |   |
| **Dividends   Declared***($/share)*                                                 |       |       |       |       |       |   |   |   |   |   |   |   |   |   |   |   |   |
| Common   Shares                                                                     |       | 0.050      |       | 0.050      |       | 0.050 |   | 0.050 |   | 0.050 |   | 0.050 |   | 0.050 |   | 0.050 |   |
| Preferred   Shares                                                                  |       | —     |       | —     |       | — |   | — |   | — |   | 0.3928 |   | 0.3125 |   | 0.3125 |   |
|                                                                                |       |       |       |       |       |   |   |   |   |   |   |   |   |   |   |   |   |
| **Common   Share Price***($/share)*                                                 |       |       |       |       |       |   |   |   |   |   |   |   |   |   |   |   |   |
| Toronto   Stock Exchange — High                                                |       | 27.11      |       | 25.47      |       | 23.67 |   | 18.00 |   | 21.53 |   | 19.38 |   | 26.70 |   | 26.83 |   |
| Toronto   Stock Exchange — Low                                                 |       | 21.57      |       | 19.22      |       | 15.67 |   | 14.20 |   | 16.34 |   | 15.18 |   | 16.13 |   | 21.35 |   |
| New   York Stock Exchange — High *(US$)*                                       |       | 27.94      |       | 26.82      |       | 24.99 |   | 17.72 |   | 21.59 |   | 19.61 |   | 26.96 |   | 26.99 |   |
| New   York Stock Exchange — Low *(US$)*                                        |       | 21.71      |       | 19.43      |       | 15.13 |   | 13.63 |   | 16.18 |   | 14.63 |   | 15.81 |   | 21.07 |   |

 

Quarterly variances in net income are largely driven by fluctuations in commodity prices, changes in production volumes and non-recurring items. The following discussion describes the non-recurring items during the periods.

 

In the fourth quarter of 2012, lower estimated future North American natural gas prices along with revisions to abandonment costs resulted in a $237 million non-cash impairment charge for mature conventional properties in North America.

 

We closed our northeast British Columbia shale gas joint venture agreement during the third quarter of 2012, recognizing a pre-tax gain of $142 million. This was offset by share-based compensation expenses, deferred income tax expense caused by changes to UK income tax legislation and turnaround costs at Long Lake.

 

Net income in the second quarter of 2012 includes $126 million of pre-tax dry hole costs for the unsuccessful Kakuna exploration well in the US Gulf of Mexico.

 

We completed the sale of our interest in Canexus in the first quarter of 2011, realizing a pre-tax gain of $348 million in discontinued operations. Changes to UK tax rates resulted in a non-cash deferred tax expense of $270 million in the first quarter 2011.

 

Net income for the third quarter of 2011 includes non-cash impairment charges of $141 million for our Canadian coalbed methane and conventional gas assets.

 

In the fourth quarter of 2011, net income was reduced by Canadian and US natural gas property impairments and by expensing preliminary engineering and design costs for future oil sands phases at Long Lake.

 

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**LIQUIDITY AND CAPITAL RESOURCES**

 

Capital Structure

 
| ** **                        | ** ** | **December 31** | ** ** | **December 31** | ** ** |
|-----------------------------------|------------|-----------------|------------|-----------------|------------|
| **(Cdn$ millions)**          | ** ** | **2012**        | ** ** | **2011**        | ** ** |
| **Net   Debt****1**               | ** ** | ** **      | ** ** | ** **      | ** ** |
| Public Senior Notes               |       | 3,843           |       | 3,929           |       |
| Subordinated Debt                 |       | 445             |       | 454             |       |
| **Total   Debt**                  | ** ** | **4,288**       | ** ** | **4,383**       | ** ** |
| Less: Cash and Cash   Equivalents |       | (1,174          | )          | (845            | )          |
| **Total   Net Debt**              | ** ** | **3,114**       | ** ** | **3,538**       | ** ** |
| **Equity   at Book Value**        | ** ** | **8,805**       | ** ** | **8,373**       | ** ** |

 

----

*1**           **Includes all of our debt and is calculated as long-term debt and short-term borrowings less cash and cash equivalents. Net debt is a non-GAAP measure and is reconciled to the nearest GAAP measure on page 104.*

 

Net Debt

 

Our net debt levels are directly related to our operating cash flows, capital expenditures and acquisition and divestiture activity. We ended the year with net debt of $3,114 million, $424 million lower than December 31, 2011. Over the last two years, we have reduced net debt by nearly $1 billion as we used proceeds from the sale of assets to repay debt and fund future growth. The year-over-year change in our net debt results from:

 
| **(Cdn$ millions)**                                  | ** ** | **2012**   | ** ** | **2011**   | ** ** |
|-----------------------------------------------------------|------------|------------|------------|------------|------------|
| Capital Investment                                        |       | (3,124     | )          | (2,575     | )          |
| Cash Flow from   Operations                               |       | 2,651      |       | 2,368      |       |
| Net Cash Flow Used                                        |       | (473       | )          | (207       | )          |
| ** **                                                | ** ** | ** ** | ** ** | ** ** | ** ** |
| Proceeds from Asset   Dispositions                        |       | 884        |       | 518        |       |
| Issue of Preferred   Shares, Net of Expenses              |       | 195        |       | —     |       |
| Issue of Common Shares                                    |       | 37         |       | 46         |       |
| Dividends on Common and   Preferred Shares                |       | (114       | )          | (105       | )          |
| Debt Repayment Costs                                      |       | —     |       | (91        | )          |
| Foreign Exchange   Translation of US-dollar Debt and Cash |       | 83         |       | (17        | )          |
| Net Change in Working   Capital                           |       | (85        | )          | 576        |       |
| Other                                                     |       | (103       | )          | (173       | )          |
| **Decrease   in Net Debt**                                | ** ** | **424**    | ** ** | **547**    | ** ** |

 

During 2012, our net debt decreased primarily as a result of proceeds from asset dispositions and preferred share issuance.

 

The reduction in net debt reduced our leverage in 2012 as reflected in the following ratios:

 
| **(times)**                               | ** ** | **2012** | ** ** | **2011** | ** ** |
|-------------------------------------------|------------|----------|------------|----------|------------|
| Net Debt to Cash Flow   from Operations 1 |       | 1.2      |       | 1.5      |       |
| Interest Coverage 2                       |       | 13.7     |       | 12.7     |       |

 

----

*1**           **For purposes of this calculation, cash flow from operating activities before changes in non-cash working capital and other.*

*2**           **Net income before interest, taxes, DD&A, exploration and other non-cash expenses, divided by interest expense (before capitalized interest).*

 

For the year ended December 31, 2012, our net debt to cash flow from operations ratio was 1.2 times compared to 1.5 times for the year ended 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 levels and our capital investment program. 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.

 

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Liquidity

 

We generally rely on operating cash flows to fund capital requirements and provide liquidity. Given the long cycle-time of some of our development projects and volatile commodity prices, it is not unusual for capital expenditures to exceed our cash flow in any given year. We also require liquidity to support our energy marketing business. We believe that maintaining strong liquidity is critical during periods of uncertain global economic markets.

 

In addition to managing capital investment levels, we monitor our asset portfolio on an ongoing basis to determine whether to sell our ownership interest or acquire additional working interests. In the last two years, we sold assets such as our interest in Canexus and undeveloped leases in Canada, and entered into joint venture agreements in northeast British Columbia and the US Gulf of Mexico.

 

The following table shows how we financed our business activities over the last five years. When our operating cash flows exceed our investment requirements, we generally pre-fund future capital commitments, pay down debt or return cash to shareholders. We borrow money or may issue equity to fund investment requirements that exceed our operating cash flow.

 
| **(Cdn$ millions)**              | ** ** | **2012** | ** ** | **2011** | ** ** | **2010** | ** ** | **2009****1** | ** ** | **2008****1** | ** ** |
|---------------------------------------|------------|----------|------------|----------|------------|----------|------------|---------------|------------|---------------|------------|
| Cash Flow from   Operating Activities |       | 2,451    |       | 2,497    |       | 2,392    |       | 1,886         |       | 4,354         |       |
| Cash Flow from   Investing Activities |       | (2,220   | )          | (1,757   | )          | (1,465   | )          | (3,743        | )          | (3,189        | )          |
| Surplus (Deficiency)                  |       | 231      |       | 740      |       | 927      |       | (1,857        | )          | 1,165         |       |
| Cash Flow from   Financing Activities |       | 112      |       | (932     | )          | (1,506   | )          | 1,821         |       | 322           |       |
| **Net   Cash Generated (Used)**       | ** ** | **343**  | ** ** | **(192** | **)**      | **(579** | **)**      | **(36**       | **)**      | **1,487**     | ** ** |

 

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*1**           **Prior to 2011, our financial statements were prepared in accordance with previous Canadian GAAP. In the first quarter of 2011, we adopted IFRS with an effective date as at January 1, 2010 and restated the 2010 financial results to be in accordance with IFRS. Further details regarding our transition to IFRS are included in Note 26 of the 2011 Consolidated Financial Statements. As such, amounts prior to 2010 are presented in accordance with previous Canadian GAAP and have not been restated.*

 

Over the last three years, our asset disposition program raised nearly $2.7 billion of proceeds. In 2012, we closed the sale of a 40% working interest in a shale gas joint venture with IGBC for proceeds of $821 million and issued $200 million of preferred shares. In 2011, we repurchased and cancelled US$812 million of long-term debt using cash on hand. In 2010, we repaid $1.5 billion of term credit facilities using proceeds from our non-core asset disposition program.

 

Our energy marketing business requires liquidity to support its activities. We require liquidity for working capital and cash or credit lines to fund collateral requirements and to absorb unexpected market or credit losses. The commercial agreements our marketing business enters into often include financial assurance provisions that allow Nexen and our counterparties to effectively manage credit risk. These agreements can require collateral to be posted if adverse credit-related events, such as reduced credit rating to noninvestment grade, occur. We have developed mitigation strategies to significantly reduce our overall exposure if such a downgrade were to occur. We believe our current liquidity is sufficient to fund this exposure, if necessary. Additionally, our exchange-traded contracts require that we provide margin based on daily fluctuations in the value of our contracts. The largest single-day margin call we received during 2012 was $16 million. In evaluating our liquidity requirements, we consider the current requirements of our marketing business as well as additional collateral or other payments that could be required if our credit ratings were reduced.

 

Future Liquidity

 

Our future liquidity depends upon cash flow generated from our operations and existing committed credit facilities. We continue to monitor economic conditions and commodity prices and expect to adjust our capital investment program if we feel it is appropriate.

 

At December 31, 2012, we had $1,174 million in cash, US$3.5 billion of undrawn committed credit facilities and US$389 million of undrawn uncommitted credit facilities. The only debt maturity in the next five years is US$126 and US$62 million notes, which mature in March 2015 and May 2017, respectively. Following close of the transaction, as described on page 82, future activities of the Company will be directed by CNOOC.

 

We are well positioned with our current debt structure. Our only financial debt covenant requires us to maintain a debt to EBITDA ratio of less than 3.5. At December 31, 2012, this ratio was approximately 0.89 times. We do not expect to exceed 3.5 based on our current debt levels and planned operations.

 

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The board declared common share dividends of $0.20/share and preferred share dividends of $1.0178/share during 2012.

 

Financial Assurance Provisions in Commercial Contracts

 

The commercial agreements our energy marketing group enters into often include financial assurance provisions that allow Nexen and our counterparties to effectively manage credit risk. The agreements can 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 derivative contracts in place and commodity prices at December 31, 2012, we would 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. The posting of collateral simply secures the payment of such amounts. Just as we may be required to post collateral in the case of an adverse credit—related event, we have similar provisions in many of our contracts that allow us to demand certain counterparties post collateral for amounts they owe us in similar circumstances.

 

Contractual Obligations, Commitments and Guarantees

 

We assume various contractual obligations and commitments in the normal course of our operations and financing activities. They include:

 
| ** **                                               | ** ** | **Payments** | ** ** |
|----------------------------------------------------------|------------|--------------|------------|
| **(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                  |       | 6,532        |       | 294 |   | 583 |   | 573 |   | 5,082 |   |
| Operating Leases 1                                       |       | 276          |       | 76 |   | 83 |   | 38 |   | 79 |   |
| Finance Leases                                           |       | 78           |       | 4 |   | 8 |   | 8 |   | 58 |   |
| Energy Commodity   Contracts                             |       | 40           |       | 37 |   | 3 |   | — |   | — |   |
| Transportation,   Processing and Storage Commitments   1 |       | 874          |       | 118 |   | 191 |   | 138 |   | 427 |   |
| Work Commitments and   Purchase Obligations 2            |       | 1,193        |       | 916 |   | 180 |   | 23 |   | 74 |   |
| Asset Retirement   Obligations                           |       | 3,731        |       | 129 |   | 121 |   | 91 |   | 3,390 |   |
| **Total**                                                | ** ** | **17,089**   | ** ** | **1,574** | ** ** | **1,294** | ** ** | **932** | ** ** | **13,289** | ** ** |

 

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*1**           **Payments for operating leases and transportation, processing, and storage commitments are deducted from our cash flow from operating activities.*

*2**          **Some of these payments relate to work commitments that we can cancel without penalties or additional fees. Drilling rig commitments are disclosed net of $119 million of subleases.*

 

Contractual obligations can be financial or non-financial. Financial obligations are known future cash payments that we must make under existing contracts, such as debt and lease arrangements. Non-financial obligations are contractual obligations to perform specified activities such as work commitments. Commercial commitments are contingent obligations that become payable only if certain pre-defined events occur. With respect to information in the table above:

 

·                  Long-term debt amounts are included on our December 31, 2012 Consolidated Balance Sheet.

 

·                  Operating leases include the minimum lease payment obligations associated with leases for office space, rail cars, vehicles and processing agreements that allow our production to flow through third-party processing facilities.

 

·                  Finance leases include pipeline commitments primarily related to production at Long Lake.

 

·                  Work commitments include non-discretionary capital spending for drilling, seismic, facilities construction and other development commitments in our operations, including commitments for the Golden Eagle development in the UK North Sea. Since the timing of certain payments is difficult to determine with certainty, the table was prepared using our best estimates.

 

·                  We have included $503 million in work commitments for drilling rigs we have contracted in Canada, UK North Sea, Offshore Nigeria and the US Gulf of Mexico over the next five years.

 

·                  We have $3,731 million of undiscounted asset retirement obligations after inflation. As of December 31, 2012, the discounted value ($2,395 million) of these estimated obligations was provided for in our Consolidated Financial Statements. Since timing of payments is difficult to determine with certainty, the table was prepared using our best estimates.

 

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·                  We have a net pension liability of $202 million for our defined benefit pension plan. This includes a $30 million net obligation for the defined benefit plan, $86 million for our share of Syncrude’s net pension obligation and $86 million for supplemental pension benefits. These obligations are included in the December 31, 2012 Consolidated Balance Sheet.

 

·                  We have excluded our normal purchase arrangements as they are discretionary and are reflected in our expected cash flow from operating activities and capital expenditures for 2013.

 

·                  We have excluded our deferred income tax liabilities as the amount and timing of any cash payment for income taxes is based on taxable income for each fiscal year in the various jurisdictions where we operate. We have also excluded deferred income tax liabilities as they relate to uncertain tax positions, as we cannot provide a reasonable estimate as to if, or when, future payments would be required.

 

From time to time, we enter into contracts that require us to indemnify parties against certain possible claims, particularly when these contracts relate to the sale of assets. On occasion, we provide indemnifications to the purchaser. Generally, a maximum obligation is not stated; therefore, the overall maximum amount cannot be reasonably estimated. We have not made any significant payments related to these indemnifications. We believe existing indemnifications would not have a material adverse effect on our liquidity, financial condition or results of operations.

 

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**CRITICAL ACCOUNTING ESTIMATES**

 

We make estimates and assumptions that affect: i) the reported amounts of our assets and liabilities; ii) the disclosure of contingent assets and liabilities at the date of the Consolidated Financial Statements; and iii) our revenues and expenses during the reporting period. Our management reviews these estimates, including those related to accruals, litigation, environmental and asset retirement obligations, recoverability of assets, income taxes, fair values of commodity trading inventories, fair values of derivative assets and liabilities, capital adequacy and the estimation of reserves on an ongoing basis. Changes in facts and circumstances may result in revised estimates and actual results may differ from these estimates. Our critical accounting estimates are discussed below.

 

Oil and Gas Accounting — Reserves Determination

 

We deplete our oil and gas costs using the unit-of-production method, as described in Note 2 to our Consolidated Financial Statements. This accounting methodology depends on the estimated remaining reserves. The process of estimating reserves requires complex judgments and decision-making based on available geological, geophysical, engineering and economic data. To estimate the economically recoverable oil and gas reserves and related future net cash flows, we consider many factors and make various assumptions. Refer to the Basis of Reserves Estimates on pages 14 to 16 in our 2012 AIF for a description of our process for estimating reserves.

 

Reserves estimates are critical to many of our accounting estimates, including:

 

·                  determining whether or not an exploratory well has found economically producible reserves. If successful, we capitalize the costs of the well, and, if not, we expense the costs immediately. In 2012, we spent $412 million on exploration drilling and expensed $227 million. If all of our exploration drilling was successful in 2012, our net income would have increased by $138 million, net of income tax;

 

·                  calculating our unit-of-production depletion rates. Both proved and proved developed reserves estimates are used to determine rates that are applied to each unit-of production in calculating our depletion expense. Proved reserves are used where a property is acquired, and proved developed reserves are used where a property is drilled and developed. In 2012, oil and gas depletion of $1,658 million was recorded in depletion, depreciation, amortization and impairment expense. If our proved reserves estimates changed by 10%, our depletion, depreciation, amortization and impairment expense would have changed by approximately $166 million, assuming no other changes to our reserves profiles or impairments as described below; and

 

·                  assessing, when necessary, our oil and gas assets for impairment. Estimated future discounted cash flows are determined using proved and probable reserves. The critical estimates used to assess impairment, including the impact of changes in reserves estimates, are discussed below.

 

Impairments

 

PROPERTY, PLANT AND EQUIPMENT

 

We evaluate our long-lived assets for impairment when there is an indication that the assets may be impaired. Among other things, these indicators might include falling oil and gas prices, a significant negative revision to our reserve estimates, changes in operating and capital costs or significant or adverse political or regulatory changes. If an indication exists, we assess the asset’s recoverable amount to determine if it is impaired. If the recoverable amount of the asset is less than the carrying amount of that asset, impairment is recorded.

 

Cash flow estimates for our impairment assessments require assumptions about the following primary elements: future prices, future costs, reserves and discount rates. Our estimates of future cash flows are based on our assumptions of long-term prices and operating and development costs and require significant judgments about highly uncertain future events. Historically, oil and gas prices have exhibited significant volatility — over the last five years, prices for Dated Brent and WTI have ranged from US$36/bbl to US$148/bbl and US$32/bbl to US$147/bbl, respectively. Prices for NYMEX gas have ranged from US$1.90/mmbtu to US$13.69/mmbtu. Our forecasts for oil and gas revenues are based on prices derived from a consensus of future price forecasts amongst industry analysts, our own assessments and existing market future prices. Our estimates of discount rates include consideration of the marketplace and risk of the asset. Given the significant assumptions required and the possibility that actual conditions will differ, we consider the assessments of impairment to be a critical accounting estimate.

 

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The relationship between our reserve estimates and the estimated cash flows, and the nature of the property-by-property impairment test is complex. As a result, we are unable to provide a reasonable sensitivity analysis of the impact that a change in reserve estimates would have on our assessment of impairment.

 

GOODWILL

 

Goodwill, for impairment testing purposes, is allocated to each of the cash-generating units (CGU) that are expected to benefit from the expenditure. We test goodwill for impairment at least annually or whenever an event or circumstance indicates that goodwill may be impaired. Our goodwill impairment test is based on the assessment of the recoverable amount of the CGU. If the carrying amount of the CGU is greater than its recoverable amount, a goodwill impairment expense equal to the excess is included in net income.

 

The process of assessing goodwill for impairment requires us to estimate the recoverable amount of our assets using one or more valuation techniques, including present-value calculations of estimated future cash flows. This process involves making various assumptions and judgments about future commodity prices, future activity levels, operating costs and discount rates. Changes in any of these assumptions or judgments could result in an impairment of all or a portion of the remaining goodwill.

 

Asset Retirement Obligations

 

We are required to remove or remedy the effect of our activities on the environment at our present and former operating sites by dismantling and removing production facilities and remediating the related damage caused by our operations. In estimating our future asset retirement obligations, we must make estimates and judgments on activities that will occur in the future. Additionally, contracts and regulations are often vague and unclear as to what constitutes removal and remediation. Furthermore, the ultimate financial impact is not always clearly known and cannot be reasonably estimated as asset removal and remediation techniques and costs are constantly changing, as are legal, regulatory, environmental, political, safety and other such considerations.

 

We record asset retirement obligations in our Consolidated Financial Statements by discounting the future value of the estimated retirement obligations associated with our oil and gas wells and facilities and other assets. In arriving at amounts recorded, numerous assumptions and judgments are made on ultimate settlement amounts, inflation factors, discount rates, timing of settlement and expected changes in legal, regulatory, environmental, political and safety environments. The asset retirement obligations we record increase the carrying amount of our property, plant and equipment and accrete with the passage of time.

 

A change in any one of our assumptions could impact asset retirement obligations, finance expense, the carrying amount of property, plant and equipment and DD&A expense.

 

Income Taxes

 

We follow the liability method of accounting for income taxes whereby deferred income tax assets and liabilities are recognized based on temporary differences in reported amounts for financial statement and income tax purposes. We carry on business in several countries and, as a result, we are subject to income taxes in numerous jurisdictions. The determination of current income tax is inherently complex, interpretations will vary, and we are required to make certain judgments. Our income tax filings are subject to audits and reassessments and we believe we have adequately provided for all income tax obligations. However, changes in facts, circumstances and interpretations as a result of income tax audits, reassessments, jurisprudence and any new legislation may result in an increase or decrease to our provision for income taxes.

 

Derivatives and Fair Value Measurements

 

We enter into contracts to purchase and sell energy commodities (primarily crude oil) and use derivative contracts, including futures, forwards, swaps and options, for hedging and trading purposes (collectively, derivatives). We also use derivatives to manage commodity price risk and foreign currency risk for non-trading purposes. We also carry commodity trading inventory held for trading purposes at fair value.

 

The fair value of derivative contracts and commodity trading inventories is estimated. Wherever possible, this estimate is based on quoted market prices and, if not available, on estimates from third-party brokers. We classify the fair value of our derivatives according to a three-level hierarchy based on the amount of observable inputs used to value the instruments. Inputs may be: i) readily observable; ii) market corroborated; or iii) generally unobservable. We utilize valuation techniques that maximize the use of observable inputs wherever possible and minimize the use of unobservable inputs. Determining the fair value of derivatives also requires assumptions about market data or information that market participants would use when pricing the asset or liability, including assumptions about risk.

 

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Our assessment of the significance of a particular input to the fair value measurement may affect the valuation of fair value within the hierarchy. Also for derivative contracts, the time between inception and settlement of the contract may affect fair value. The actual settlement of derivatives could differ materially from the fair value recorded and could impact future operating results. We performed a sensitivity analysis of inputs used to calculate the fair value of the instruments that are based on unobservable inputs. Using reasonably possible alternative assumptions, the fair value of these instruments would change by $5 million (before tax) at December 31, 2012.

 

**NEW ACCOUNTING PRONOUNCEMENTS**

 

IFRS Pronouncements

 

We have adopted all IFRS accounting standards in effect on December 31, 2012. See Note 2 of our Consolidated Financial Statements for future IFRS pronouncements and the potential impact on our results of operations, financial position and disclosure.

 

**QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK**

 

We are exposed to normal market risks inherent in the oil and gas business, including commodity price risk, foreign currency rate risk, interest rate risk and credit risk. We recognize these risks and manage our operations to minimize our exposures to the extent practical.

 

COMMODITY PRICE RISK

 

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 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, gas properties, our level of spending for exploration and development, and our ability to meet our obligations as they become due.

 

Our realized crude oil prices are based on various reference prices, primarily Brent and WTI and other prices that generally track the movement of Brent and WTI. Actual prices realized differ from the reference prices to reflect quality differentials and transportation. Brent, WTI and other international reference prices are affected by numerous and complex worldwide factors such as supply and demand fundamentals, economic outlooks, production quotas set by the Organization of Petroleum Exporting Countries and political events. Quality differentials are affected by local supply and demand factors.

 

We are also exposed to natural gas price movements. Natural gas prices are generally influenced by regional supply and demand fundamentals and, to a lesser extent, local market conditions and oil prices.

 

In 2012, WTI averaged US$94.20/bbl, reaching a high of US$111/bbl and a low of US$77/bbl. Dated Brent, on which approximately 75% of our crude oil production is priced, averaged US$111.99/bbl, reaching a high of US$128/bbl and a low of US$88/bbl. NYMEX natural gas prices averaged US$2.82/mmbtu in 2012, reaching a high of US$3.93/mmbtu and a low of US$1.90/mmbtu.

 

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 monitor these risks and manage accordingly.

 

Our energy marketing group’s primary focus is to market proprietary crude oil and natural gas production. We also buy and sell third-party production. In order to manage the commodity and foreign exchange price risks that come from this activity, we use financial derivative contracts, including energy-related futures, forwards, swaps and options, as well as 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:

 

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·                  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.

 

The US/Canadian dollar exchange rate averaged $1.0004 in 2012, ranging from a low of $0.9599 to a high of $1.0299.

 

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 net cash flows. We designate most of our US-dollar borrowings as a hedge against our US-dollar net investment in our foreign operations.

 

We do not have any material exposure to highly inflationary foreign currencies.

 

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INTEREST RATE RISK

 

We are exposed to changes in interest payments on any floating-rate debt as interest rates fluctuate. Our only floating-rate debt is our term credit facilities which are expected to be used minimally and, therefore, we expect our sensitivity to changes in interest rates to be immaterial.

 

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 and refiners, 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 ratings. Six counterparties made up more than 5% of our credit exposure. The following table illustrates the composition of credit exposure by credit rating:

 
| ** **             | ** ** | **December 31** | ** ** | **December 31** | ** ** |
|------------------------|------------|----------------------|------------|----------------------|------------|
| **Credit Rating** | ** ** | **2012**             | ** ** | **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. We have provided a general allowance of $1 million for credit risk with our counterparties.

 

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**OTHER**

 

Non-GAAP Measures

 

CASH FLOW FROM OPERATIONS

 

Cash flow from operations is a non-GAAP measure defined as cash flow from operating activities before changes in non-cash working capital and other, and excludes items of a non-recurring nature. We evaluate our performance and that of our business segments based on earnings and cash flow from operations. We consider it a key measure as it demonstrates our ability and the ability of our business segments to generate the cash flow necessary to fund future growth through capital investment and repay debt. Cash flow from operations is unlikely to be comparable with the calculation of similar measures for other companies.

 
| ** **                               | ** ** | **December 31** | ** ** | **December 31** | ** ** |
|------------------------------------------|------------|----------------------|------------|----------------------|------------|
| **(Cdn$ millions)**                 | ** ** | **2012**             | ** ** | **2011**             | ** ** |
| Cash Flow from   Operating Activities    |       | 2,451                |       | 2,497                |       |
| Changes in Non-Cash   Working Capital    |       | 86                   |       | (255                 | )          |
| Other                                    |       | 162                  |       | 158                  |       |
| Impact of Annual Crude   Oil Put Options |       | (48                  | )          | (32                  | )          |
| **Cash   Flow from Operations**          | ** ** | **2,651**            | ** ** | **2,368**            | ** ** |

 

NET DEBT

 

Net debt is a non-GAAP measure defined as long-term debt and short-term borrowings less cash and cash equivalents. We use net debt as a key indicator of our leverage and to monitor the strength of our balance sheet. Net debt is directly tied to our operating cash flows and capital investment. Net debt is unlikely to be comparable with the calculation of similar measures for other companies.

 
| ** **                        | ** ** | **December 31** | ** ** | **December 31** | ** ** |
|-----------------------------------|------------|----------------------|------------|----------------------|------------|
| **(Cdn$ millions)**          | ** ** | **2012**             | ** ** | **2011**             | ** ** |
| Public Senior Notes               |       | 3,843                |       | 3,929                |       |
| Subordinated Debt                 |       | 445                  |       | 454                  |       |
| **Total   Debt**                  | ** ** | **4,288**            | ** ** | **4,383**            | ** ** |
| Less: Cash and Cash   Equivalents |       | (1,174               | )          | (845                 | )          |
| **Total   Net Debt**              | ** ** | **3,114**            | ** ** | **3,538**            | ** ** |

 

Off-Balance Sheet Arrangements

 

We have no off-balance sheet arrangements at December 31, 2012 and 2011 that would have a material adverse effect on our liquidity, consolidated financial position or results of operations. We use operating leases in the normal course of business as disclosed in Commitments, Contingencies and Guarantees in Note 19 to the Consolidated Financial Statements, which is incorporated herein by reference.

 

At December 31, 2012, we had outstanding letters of credit supported by $223 million of unsecured term credit facilities and $20 million of uncommitted unsecured credit facilities. The related obligations are recorded on our consolidated balance sheet.

 

Transactions with Related Parties

 

As a Canadian foreign private issuer, Nexen provides the disclosure required under Item 1.9 of *National Instrument 51-102—Continuous Disclosure Obligations (NI 51-102F1)* dealing with “transactions between related parties”. Nexen did not have any material related party transactions in 2012. Certain other transactions involving Nexen and certain directors were entered into in 2012 and are described under “Interest of Management and Others in Material Transactions” in our AIF. These are not related party transactions.

 

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Additional Information

 

Additional information, including our AIF and our Consolidated Financial Statements, is available from our public filings with the Canadian Securities Administrators and the SEC at www.sedar.com and www.sec.gov, respectively, or from our website www.nexeninc.com.

 

On January 31, 2013, there were 530,036,892 common shares issued and outstanding.

 

**FORWARD-LOOKING STATEMENTS**

 

Certain statements in this MD&A constitute “forward-looking statements” (within the meaning of the *United States Private Securities Litigation Reform Act of 1995, as amended*) or “forward-looking information” (within the meaning of applicable Canadian securities legislation). Such statements or information (together “forward-looking statements”) are generally identifiable by the forward-looking terminology used such as “anticipate”, “believe”, “intend”, “plan”, “expect”, “estimate”, “budget”, “outlook”, “forecast” or other similar words and include statements relating to or associated with individual wells, regions or projects. Any statements as to possible future crude oil or natural gas prices; future production levels; future royalties and tax levels; future capital expenditures, their timing and their allocation to exploration and development activities; future earnings; future asset acquisitions or dispositions; future sources of funding for our capital program; future debt levels; availability of committed credit facilities; possible commerciality of our projects; development plans or capacity expansions; the expectation that we have the ability to substantially grow production at our oil sands facilities through controlled expansions; the expectation of achieving the production design rates from our oil sands facilities; the expectation that our oil sands production facilities continue to develop better and more sustainable practices; the expectation of cheaper and more technologically advanced operations; the expected design size of our facilities; the expected timing and associated production impact of facility turnarounds and maintenance; the expectation that we can continue to operate our offshore exploration, development and production facilities safely and profitably; future ability to execute dispositions of assets or businesses; future sources of liquidity, cash flows and their uses; future drilling of new wells; ultimate recoverability of current and long-term assets; ultimate recoverability of reserves or resources; expected finding and development costs; expected operating costs; future cost recovery oil revenues from our Yemen operations; the expectation of our ability to comply with the new safety and environmental rules enacted in the US at a minimal incremental cost, and of receiving necessary drilling permits for our US offshore operations; estimates on a per share basis; future foreign currency exchange rates; future expenditures and future allowances relating to environmental matters and our ability to comply with these; dates by which certain areas will be developed, come on-stream or reach expected operating capacity; and changes in any of the foregoing are forward-looking statements.

 

Statements relating to “reserves” or “resources” are forward-looking statements, as they involve the implied assessment, based on estimates and assumptions that the reserves and resources described exist in the quantities predicted or estimated and can be profitably produced in the future.

 

All of the forward-looking statements in this MD&A are qualified by the assumptions that are stated or inherent in such forward-looking statements. Although we believe that these assumptions are reasonable based on the information available to us on the date such assumptions were made, this list is not exhaustive of the factors that may affect any of the forward-looking statements and the reader should not place an undue reliance on these assumptions and such forward-looking statements. The key assumptions that have been made in connection with the forward-looking statements include the following: that we will conduct our operations and achieve results of operations as anticipated; that our development plans will achieve the expected results; the general continuance of current or, where applicable, assumed industry conditions; the continuation of assumed tax, royalty and regulatory regimes; the accuracy of the estimates of our reserve volumes; commodity price and cost assumptions; the continued availability of adequate cash flow and debt and/or equity financing to fund our capital and operating requirements as needed; the operations and capital expenditure plans of Nexen following the completion of the transaction; and the extent of our liabilities. We believe the material factors, expectations and assumptions reflected in the forward-looking statements are reasonable, but no assurance can be given that these factors, expectations and assumptions will prove to be correct.

 

Forward-looking statements are subject to known and unknown risks and uncertainties and other factors, many of which are beyond our control and each of which contributes to the possibility that our forward-looking statements will not occur or that actual results, levels of activity and achievements may differ materially from those expressed or implied by such statements. 

 

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Such factors include, among others: market prices for oil and gas; our ability to explore, develop, produce, upgrade and transport crude oil and natural gas to markets; ultimate effectiveness of design or design modifications to facilities; the results of exploration and development drilling and related activities; the cumulative impact of oil sands development on the environment; the impact of technology on operations and processes and how new complex technology may not perform as expected; the availability of pipeline and global refining capacity; risks inherent to the operations of any large, complex refinery units, especially the integration between production operations and an upgrader facility; availability of third-party bitumen for use in our oil sands production facilities; labour and material shortages; risks related to accidents, blowouts and spills in connection with our offshore exploration, development and production activities, particularly our deep-water activities; direct and indirect risks related to the imposition of moratoriums, suspensions or cancellations of our offshore exploration, development and production operations, particularly our deep-water activities; the impact of severe weather on our offshore exploration, development and production activities, particularly our deep-water activities; the effectiveness and reliability of our technology in harsh and unpredictable environments; risks related to the actions and financial circumstances of our agents and contractors, counterparties and joint venture partners; volatility in energy trading markets; foreign currency exchange rates; economic conditions in the countries and regions in which we carry on business; governmental actions including changes to taxes or royalties, changes in environmental and other laws and regulations including without limitation, those related to our offshore exploration, development and production activities; renegotiations of contracts; results of litigation, arbitration or regulatory proceedings; political uncertainty, including actions by terrorists, insurgent or other groups, or other armed conflict, including conflict between states; and other factors, many of which are beyond our control. These risks, uncertainties and other factors and their possible impact are discussed more fully in the sections titled “Risk Factors” in our AIF and “Quantitative and Qualitative Disclosures About Market Risk” in this MD&A. The impact of any one risk, uncertainty or factor on a particular forward-looking statement is not determinable with certainty as these factors are interdependent, and management’s future course of action would depend on our assessment of all information at that time.

 

Although we believe that the expectations conveyed by the forward-looking statements are reasonable based on information available to us on the date such forward-looking statements were made, no assurances can be given as to future results, levels of activity and achievements. Undue reliance should not be placed on the forward-looking statements contained herein, which are made as of the date hereof as the plans, intentions, assumptions or expectations upon which they are based might not occur or come to fruition. Except as required by applicable securities laws, Nexen undertakes no obligation to update publicly or revise any forward-looking statements, whether as a result of new information, future events or otherwise. Included herein is information that may be considered financial outlook and/or future-oriented financial information. Its purpose is to indicate the potential results of our intentions and may not be appropriate for other purposes. The forward-looking statements contained herein are expressly qualified by this cautionary statement.

 

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*NEXEN INC.*

 

*CONSOLIDATED FINANCIAL STATEMENTS*

* *

 

*For the Year Ended December 31, 2012*

 

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**NEXEN INC.**

** **

**CONSOLIDATED FINANCIAL STATEMENTS**

** **

**REPORT OF MANAGEMENT**

 

February 24, 2013

 

To the Shareholders of Nexen Inc.

 

We are responsible for the preparation and fair presentation of the Consolidated Financial Statements, as well as the financial reporting process that gives rise to such Consolidated Financial Statements. This responsibility requires us to make significant accounting judgments and estimates. For example, we are required to choose accounting principles and methods that are appropriate to the company’s circumstances, and we are required to make estimates and assumptions that affect amounts reported. Fulfilling this responsibility requires the preparation and presentation of our Consolidated Financial Statements in accordance with International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB).

 

We are responsible for developing and implementing internal controls over the financial reporting process. These controls are designed to provide reasonable assurance that relevant and reliable financial information is produced. To gather and control financial data, we established accounting and reporting systems supported by internal controls over financial reporting and an internal audit program. We believe that our internal controls over financial reporting provide reasonable assurance that our assets are safeguarded against loss from unauthorized use or disposition, that receipts and expenditures of the company are made only in accordance with authorization of management and directors of the company and that our records are reliable for preparing our Consolidated Financial Statements and other financial information in accordance with IFRS and in accordance with applicable securities rules and regulations. All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

 

We established disclosure controls and procedures, internal controls over financial reporting and corporate-wide policies to ensure that Nexen’s consolidated financial position, results of operations and cash flows are presented fairly. Our disclosure controls and procedures are designed to ensure timely disclosure and communication of all material information required by regulators. We oversee, with assistance from our Disclosure Review Committee, these controls and procedures and all required regulatory disclosures.

 

To ensure the integrity of our financial statements, we carefully select and train qualified personnel. We also ensure our organizational structure provides appropriate delegation of authority and division of responsibilities. Our policies and procedures are communicated throughout the organization and include a written ethics and integrity policy that applies to all employees, including the Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer or Controller.

 

Our board of directors is responsible for reviewing and approving the Consolidated Financial Statements and for overseeing management’s performance of its financial reporting responsibilities. Their financial statement-related responsibilities are fulfilled mainly through the Audit and Conduct Review Committee (Audit Committee), with assistance from the Reserves Review Committee regarding the annual review of our crude oil and natural gas reserves, and the Finance Committee regarding the assessment and mitigation of financial risk. The Audit Committee is composed entirely of independent directors and includes five directors with financial expertise. The Audit Committee meets regularly with management, the internal auditors and the independent registered Chartered Accountants to review accounting policies, financial reporting and internal control issues and to ensure each party is properly discharging its responsibilities. The Audit Committee is responsible for the appointment and compensation of the independent registered Chartered Accountants and also ensures their independence, reviews their fees and (subject to applicable securities laws) pre-approves their retention for any permitted non-audit services. The internal auditors and independent registered Chartered Accountants have full and unlimited access to the Audit Committee, with and without the presence of management.

 

| (signed)   “Kevin J. Reinhart”        |   | (signed)   “Una M. Power” |
|-------------------------------------------------|--------|-------------------------------------|
| Interim   President and Chief Executive Officer |   | Interim   Chief Financial Officer   |

 

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**MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING**

 

Our management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Exchange Act Rules 13(a)—15(f)). Under the supervision and with the participation of our management, including our principal executive officer (CEO) and principal financial officer (CFO), we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the *Internal Control — Integrated Framework*issued by the *Committee of Sponsoring Organizations of the Treadway Commission*. Based on our evaluation, we concluded that our internal control over financial reporting is effective as of December 31, 2012. We have documented this assessment and made this assessment available to our independent registered Chartered Accountants. We recognize that all internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Deloitte LLP audited our Consolidated Financial Statements as stated in their report and has provided an attestation report on our internal control over financial reporting.

 

**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.

 

OTHER MATTER

 

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2012, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 24, 2013 expressed an unqualified opinion on the Company’s internal control over financial reporting.

 

(signed) “Deloitte LLP”

Independent Registered Chartered Accountants

February 24, 2013

Calgary, Canada

 

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To the Board of Directors and Shareholders of Nexen Inc.

 

We have audited the internal control over financial reporting of Nexen Inc. and subsidiaries (the “Company”) as of December 31, 2012, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.  The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting.  Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

 

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.  Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances.  We believe that our audit provides a reasonable basis for our opinion.

 

A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with International Financial Reporting Standards.  A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with International Financial Reporting Standards, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

 

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis.  Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

 

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

 

We have also audited, in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2012 of the Company and our report dated February 24, 2013 expressed an unqualified opinion on those financial statements.

 

(signed) “Deloitte LLP”

Independent Registered Chartered Accountants

February 24, 2013

Calgary, Canada

 

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**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                                |

 

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**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.*

 

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**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**  | ** ** |

 

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*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.*

 

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**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**    | ** ** |

 

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*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.*

 

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**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**                                                 | ** ** | **—** | ** ** | **—** | ** ** |

 

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*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.*

 

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**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.

 

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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.

 

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(C) CASH AND CASH EQUIVALENTS

 

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.

 

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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 mortization. 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.

 

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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.

 

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(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.

 

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*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.

 

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(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.

 

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(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.

 

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(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.

 

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·                        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.

 

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**3. ACCOUNTS RECEIVABLE**

 
| ** **                           | ** ** | **December 31** | ** ** | **December 31** | ** ** |
|--------------------------------------|------------|----------------------|------------|----------------------|------------|
| ** **                           | ** ** | **2012**             | ** ** | **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**            | ** ** |

 

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*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** | ** ** | **December 31** | ** ** |
|-------------------|------------|----------------------|------------|----------------------|------------|
| ** **        | ** ** | **2012**             | ** ** | **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**              | ** ** |

 

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**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.

 

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(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.

 

(C) ASSET DERECOGNITIONS

 

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** | ** ** | **December 31** | ** ** |
|---------------------|------------|----------------------|------------|----------------------|------------|
| ** **          | ** ** | **2012**             | ** ** | **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.

 

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**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** | ** ** | **December 31** | ** ** |
|-------------------------------|------------|----------------------|------------|----------------------|------------|
| ** **                    | ** ** | **2012**             | ** ** | **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** | ** ** | **December 31** | ** ** |
|-----------------------------------------|------------|----------------------|------------|----------------------|------------|
| ** **                              | ** ** | **2012**             | ** ** | **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.*

 

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*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.

 

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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.

 

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**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        |       |

 

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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                   |       |

 

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(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.

 

(C) LIQUIDITY RISK

 

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.

 

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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** | ** ** | **December 31** | ** ** |
|---------------------------|------------|----------------------|------------|----------------------|------------|
| ** **                | ** ** | **2012**             | ** ** | **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**            | ** ** |

 

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**11. LONG-TERM DEBT**

 
| ** **                                               | ** ** | **December 31** | ** ** | **December 31** | ** ** |
|----------------------------------------------------------|------------|----------------------|------------|----------------------|------------|
| ** **                                               | ** ** | **2012**             | ** ** | **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%.

 

(C) NOTES, DUE 2017

 

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%.

 

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(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.

 

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(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:

 
| ** **                      | ** ** | **December 31** | ** ** | **December 31** | ** ** |
|---------------------------------|------------|----------------------|------------|----------------------|------------|
| **Net Debt ****1**    | ** ** | **2012**             | ** ** | **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**            | ** ** |

 

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*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.*

 

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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**                     | ** ** |

 

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**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** | ** ** | **Supplemental ****1** | ** ** | **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 |   |   |   |

 

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| *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.*                                                                        |

 

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| ** **                                                     | ** ** | **2011**       | ** ** |
|----------------------------------------------------------------|------------|----------------|------------|
| ** **                                                     | ** ** | **Nexen**      | ** ** | ** ** | ** ** | ** ** | ** ** |
| ** **                                                     | ** ** | **Registered** | ** ** | **Supplemental****1** | ** ** | **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       |       |

 

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| **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.

 

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| **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** | ** ** |

 

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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** | ** ** |

 

(C) DEFINED CONTRIBUTION PENSION PLANS

 

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).

 

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(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 & Wale               | s          |                       | 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.*

 

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**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.

 

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(C) TANDEM OPTIONS (TOPs)

 

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%            |       |

 

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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**                                                    | ** ** | ** ** | ** ** | ** ** | ** ** |

 

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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%            |       |

 

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 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).

 

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**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**  | ** ** |

 

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**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** | ** ** |

 

(C) RECONCILIATION OF EFFECTIVE TAX RATE TO THE CANADIAN STATUTORY TAX RATE

 
| ** **                                                           | ** ** | **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        | %          |

 

----

*1**                                        **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.*

 

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(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.

 

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**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.

 

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**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**  | ** ** |

 

(C) OTHER CASH FLOW INFORMATION

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

 

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**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   Countries****1** | ** ** | **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.*

 

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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** | ** ** |

 

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*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.*

 

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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** | **1** | **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**           | **2**      | **1,941**             | **3**      | **6,249**        | ** 4** | **1,512** | ** ** | **260** | ** ** | **15,947** | ** ** |

 

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*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** | **1** | **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**           | **2**      | **1,918**             | **3**      | **5,710**        | **4**      | **1,322** | ** ** | **268** | ** ** | **15,571** | ** ** |

 

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*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.*

 

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**FORWARD-LOOKING INFORMATION**

 

Certain statements in this report constitute “forward-looking statements” (within the meaning of the *United States Private Securities Litigation Reform Act of 1995*, as amended) or “forward-looking information” (within the meaning of applicable Canadian securities legislation). Such statements or information (together “forward-looking statements”) are generally identifiable by the forward-looking terminology used such as “anticipate”, “believe”, “intend”, “plan”, “expect”, “estimate”, “budget”, “outlook”, “forecast” or other similar words and include statements relating to, or associated with, individual wells, regions or projects. Any statements as to possible future crude oil or natural gas prices; future production levels; future royalties and tax levels; future capital expenditures, their timing and their allocation to exploration and development activities; future earnings; future asset acquisitions or dispositions; future sources of funding for our capital program; future debt levels; availability of committed credit facilities; possible commerciality of our projects; development plans or capacity expansions; the expectation that we have the ability to substantially grow production at our oil sands facilities through controlled expansions; the expectation of achieving the production design rates from our oil sands facilities; the expectation that our oil sands production facilities continue to develop better and more sustainable practices; the expectation of cheaper and more technologically advanced operations; the expected design size of our facilities; the expected timing and associated production impact of facility turnarounds and maintenance; the expectation that we can continue to operate our offshore exploration, development and production facilities safely and profitably; future ability to execute dispositions of assets or businesses; future sources of liquidity, cash flows and their uses; future drilling of new wells; ultimate recoverability of current and long-term assets; ultimate recoverability of reserves or resources; expected finding and development costs; expected operating costs; future cost recovery of oil revenues from our Yemen operations; the expectation of our ability to comply with the new safety and environmental rules at a minimal incremental cost, and of receiving necessary drilling permits for our US offshore operations; estimates on a per share basis; future foreign currency exchange rates; future expenditures and future allowances relating to environmental matters and our ability to comply with them; dates by which certain areas will be developed, come on-stream or reach expected operating capacity; and changes in any of the foregoing are forward-looking statements.

 

Statements relating to “reserves” or “resources” are forward-looking statements, as they involve the implied assessment, based on estimates and assumptions that the reserves and resources described exist in the quantities predicted or estimated and can be economically produced in the future.

 

All of the forward-looking statements in this report are qualified by the assumptions that are stated or inherent in such forward-looking statements. Although we believe that these assumptions are reasonable based on the information available to us on the date such assumptions were made, this list is not exhaustive of the factors that may affect any of the forward-looking statements and the reader should not place an undue reliance on these assumptions and such forward-looking statements. The key assumptions that have been made in connection with the forward-looking statements include the following: that we will conduct our operations and achieve results of operations as anticipated; that our development plans will achieve the expected results; the general continuance of current or, where applicable, assumed industry conditions; the continuation of assumed tax, royalty and regulatory regimes; the accuracy of the estimates of our reserve volumes; commodity price and cost assumptions; the continued availability of adequate cash flow and debt and/or equity financing to fund our capital and operating requirements as needed; the operations and capital expenditure plans of Nexen following the completion of the transaction; and the extent of our liabilities. We believe the material factors, expectations and assumptions reflected in the forward-looking statements are reasonable, but no assurance can be given that these factors, expectations and assumptions will prove to be correct.

 

Forward-looking statements are subject to known and unknown risks and uncertainties and other factors, many of which are beyond our control and each of which contributes to the possibility that our forward-looking statements will not occur or that actual results, levels of activity and achievements may differ materially from those expressed or implied by such statements. Such factors include, but are not limited to: market prices for oil and gas; our ability to explore, develop, produce, upgrade and transport crude oil and natural gas to markets; ultimate effectiveness of design or design modifications to facilities; the results of exploration and development drilling and related activities; the cumulative impact of oil sands development on the environment; the impact of technology on operations and processes and how new complex technology may not perform as expected; the availability of pipeline and global refining capacity; risks inherent to the operations of any large, complex refinery units, especially the integration between production operations and an upgrader facility; availability of third-party bitumen for use in our oil sands production facilities; labour and material shortages; risks related to accidents, blowouts and spills in connection with our offshore exploration, development and production activities, particularly our deep-water activities; direct and indirect risks related to the imposition of moratoriums, suspensions or cancellations of our offshore exploration, development and production operations, particularly our deep-water activities; the impact of severe weather on our offshore exploration, development and production activities, particularly our deep-water activities; the effectiveness and reliability of our technology in harsh and unpredictable environments; risks related to the actions and financial circumstances of our agents, contractors,

 

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counterparties and joint-venture partners; volatility in energy trading markets; foreign currency exchange rates; economic conditions in the countries and regions in which we carry on business; governmental actions including changes to taxes or royalties, changes in environmental and other laws and regulations including without limitation, those related to our offshore exploration, development and production activities; renegotiations of contracts; results of litigation, arbitration or regulatory proceedings; political uncertainty, including actions by terrorists, insurgent or other groups, or other armed conflict, including conflict between states; and other factors, many of which are beyond our control.

 

These risks, uncertainties and other factors and their possible impact are discussed more fully in the sections titled “Risk Factors” in our AIF and “Quantitative and Qualitative Disclosures About Market Risk” in our Management’s Discussion & Analysis (MD&A). The impact of any one risk, uncertainty or factor on a particular forward-looking statement is not determinable with certainty as these factors are interdependent, and management’s future course of action would depend on our assessment of all information at that time.

 

Although we believe that the expectations conveyed by the forward-looking statements are reasonable based on information available to us on the date such forward-looking statements were made, no assurances can be given as to future results, levels of activity and achievements. Undue reliance should not be placed on the forward-looking statements contained herein, which are made as of the date hereof as the plans, intentions, assumptions or expectations upon which they are based might not occur or come to fruition. Except as required by applicable securities laws, Nexen undertakes no obligation to update publicly or revise any forward-looking statements, whether as a result of new information, future events or otherwise. Included herein is information that may be considered financial outlook and/or future-oriented financial information. Its purpose is to indicate the potential results of our intentions and may not be appropriate for other purposes. The forward-looking statements contained herein are expressly qualified by this cautionary statement.

 

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**ADDITIONAL DISCLOSURE**

 

**Certifications and Disclosure Regarding Controls and Procedures.**

 

(a)                                 Certifications.  See Exhibits 99.1, 99.2, 99.3 and 99.4 to this Annual Report on Form 40-F.

 

(b)                                 Disclosure Controls and Procedures.  The registrant’s principal executive officer and principal financial officer have designed disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)), or caused such disclosure controls and procedures to be designed under their supervision, to ensure that material information relating to the registrant is made known to them, particularly during the period in which this report is prepared. They have evaluated the effectiveness of such disclosure controls and procedures for the fiscal year ended December 31, 2012 (the “Evaluation Date”). Based upon that evaluation, the registrant’s principal executive officer and principal financial officer concluded that, as of the Evaluation Date, the registrant’s disclosure controls and procedures are effective to ensure that information required to be disclosed by the registrant in reports that it files or submits under the Exchange Act is (i) recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission rules and forms; and (ii)  accumulated and communicated to the registrant’s management, including its principal executive officer and principal financial officer, to allow timely decisions regarding required disclosures.

 

The registrant’s management, including its principal executive officer and principal financial officer, does not expect that the registrant’s disclosure controls and procedures or internal controls will prevent all possible error and fraud.  The registrant’s disclosure controls and procedures are, however, designed to provide reasonable assurance of achieving their objectives, and the registrant’s principal executive officer and principal financial officer have concluded that the registrant’s financial controls and procedures are effective at that reasonable assurance level.

 

(c)                                  Management’s Annual Report on Internal Control Over Financial Reporting.  The required disclosure is included in the “Mangement’s Report on Internal Control Over Financial Reporting” that accompanies the registrant’s Consolidated Financial Statements for the fiscal year ended December 31, 2012, filed as part of this Annual Report on Form 40-F.

 

(d)                                 Attestation Report of the Registered Public Accounting Firm.  The required disclosure is included in the “Report of Independent Registered Chartered Accountants” that accompanies the registrant’s Consolidated Financial Statements for the fiscal year ended December 31, 2012, filed as part of this Annual Report on Form 40-F.

 

(e)                                  Changes in Internal Control over Financial Reporting.  During the fiscal year ended December 31, 2012, there was no change in the registrant’s internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting.

 

**Notices Pursuant to Regulation BTR.**

 

None.

 

**Audit Committee Financial Expert.**

 

The registrant’s board of directors has determined that each of William B. Berry, Robert G. Bertram, Thomas W. Ebbern, Thomas C. O’Neill, and Arthur R.A. Scace each a member of the registrant’s audit committee, qualifies as an “audit committee financial expert” (as such term is defined in paragraph 8(b) of General Instruction B to Form 40-F), and is “independent” as that term is defined in the rules of the New York Stock Exchange.  A description of Mr. Berry’s, Mr. Bertram’s, Mr. Ebbern’s, Mr. O’Neill’s and Mr. Scace’s experience relating to financial matters is set forth in the section “Audit Committee Education and Experience” of the Annual Information Form of Nexen Inc. for the fiscal year ended December 31, 2012, filed as part of this Annual Report on Form 40-F.

 

**NYSE Corporate Governance Rules Compliance.**

 

The registrant operates under corporate governance practices that are consistent with the requirements followed by U.S. domestic companies under the NYSE corporate governance listing standards. The registrant, as a foreign private issuer in the United States, is not required to comply with most of the NYSE corporate governance standards and may instead comply with Canadian corporate governance standards. The registrant is, however, required to disclose any significant differences between its corporate governance practices and those NYSE corporate governance standards required to be followed by U.S. domestic companies. The registrant has two deferred share unit (DSU) plans for non-executive directors, as described in the registrant’s management proxy circular. The registrant follows the Toronto Stock Exchange’s rules which, unlike NYSE rules, exempt DSU plans from shareholder approval where the common shares issued under

 

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the DSU plans are purchased on the open market, rather than by issuing new common shares. Other than this, the registrant’s corporate governance practices do not differ in any significant way from the NYSE corporate governance listing standards applicable to U.S. companies. A summary of the registrant’s corporate governance practices is contained in the registrant’s most recent management proxy circular and can also be found on the registrant’s website at www.nexeninc.com.

 

**Code of Ethics.**

 

The registrant has adopted a “code of ethics” (as that term is defined in paragraph 9(b) of General Instruction B to Form 40-F), entitled “How We Work: Our Integrity Guide” (the “Code of Ethics”), that applies to all of its directors, officers and employees, including its principal executive officer, principal financial officer, principal accounting officer or controller, and persons performing similar functions.

 

The Code of Ethics provides improved communication regarding expected behaviors and uses simplified language, real-life examples and questions and answers. It also includes an overview of the registrant’s 22 integrity-related policies, provides guidance for making ethical decisions and lists options for reporting concerns about business conduct.

 

Since the adoption of the Code of Ethics, there have not been any amendments or waivers, including implicit waivers, granted from any provision of the Code of Ethics.

 

Under the Code of Ethics, all directors, officers and employees must demonstrate ethical business practices in all business relationships, within and outside of the registrant. Employees are not permitted to commit an unethical, dishonest or illegal act or to instruct other employees to do so.

 

The Code of Ethics is available for viewing on the registrant’s website at www.nexeninc.com. If the registrant amends or waives any provision of the Code of Ethics, the registrant will disclose such amendment or waiver online. The registrant also files the Code of Ethics and any amendments to it on SEDAR at www.sedar.com. Requests for copies of the Code of Ethics should be made by contacting the registrant’s Integrity Resource Centre by emailing integrity@nexeninc.com or by calling (403) 699-6789.

 

**Principal Accountant Fees and Services.**

 

The required disclosure is included under the heading “Independent Registered Chartered Accountants (IRCA) Fees-IRCA Fees Billed” in the registrant’s Annual Information Form for the fiscal year ended December 31, 2012, filed as part of this Annual Report on Form 40-F.

 

**Pre-Approval Policies and Procedures.**

 

The required disclosure is included under the heading “Independent Registered Chartered Accountants (IRCA) Fees-Pre-Approval Policies and Procedures” in the registrant’s Annual Information Form for the fiscal year ended December 31, 2012, filed as part of this Annual Report on Form 40-F.

 

**Off-Balance Sheet Arrangements.**

 

The registrant does not have any off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on its financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.

 

**Tabular Disclosure of Contractual Obligations.**

 

The required disclosure is included under the heading “Contractual Obligations, Commitments and Guarantees” in the registrant’s Management’s Discussion and Analysis for the fiscal year ended December 31, 2012, filed as part of this Annual Report on Form 40-F.

 

**Identification of the Audit Committee.**

 

The registrant has a separately-designated standing audit committee established in accordance with Section 3(a)(58)(A) of the Exchange Act.  The members of the audit committee are:  William B. Berry, Robert G. Bertram, Thomas W. Ebbern, Thomas C. O’Neill and Arthur R.A. Scace.

 

**Mine Safety Disclosure.**

 

Not Applicable.

 

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**UNDERTAKING****AND CONSENT TO SERVICE OF PROCESS**

 

**A.  Undertaking.**

 

The registrant undertakes to make available, in person or by telephone, representatives to respond to inquiries made by the Commission staff, and to furnish promptly, when requested to do so by the Commission staff, information relating to: the securities registered pursuant to Form 40-F; the securities in relation to which the obligation to file an annual report on Form 40-F arises; or transactions in said securities.

 

**B.  Consent to Service of Process.**

 

(1)                                 The registrant has, together with this Form 40-F, filed a Form F-X in connection with the class of securities in relation to which the obligation to file this report arises.

 

(2)                                 Any change to the name or address of the agent for service of process of the registrant shall be communicated promptly to the Commission by an amendment to the Form F-X referencing the file number of the registrant.

 

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**SIGNATURES**

 

Pursuant to the requirements of the Exchange Act, the registrant certifies that it meets all of the requirements for filing on Form 40-F and has duly caused this Annual Report to be signed on its behalf by the undersigned, thereunto duly authorized.

 

 
| Date:   February 25, 2013 | **NEXEN INC.** |
|---------------------------|----------------|
|                      |           |   |
|                      |           |   |
|                      | By:            | /s/   Alan O’Brien |
|                      |           | Name: | Alan   O’Brien |
|                      |           | Title: | Senior   Vice-President, General Counsel and Secretary |

 

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**EXHIBIT INDEX**

 
| **Exhibits** | ** ** | **Documents**                                                                                                            |
|--------------|------------|--------------------------------------------------------------------------------------------------------------------------|
|         |       |                                                                                                                     |
| 99.1         |       | Certification   of Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14 of the   Securities Exchange Act of 1934 |
|         |       |                                                                                                                     |
| 99.2         |       | Certification   of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14 of the   Securities Exchange Act of 1934 |
|         |       |                                                                                                                     |
| 99.3         |       | Certification   of Chief Executive Officer pursuant to 18 U.S.C. Section 1350                                            |
|         |       |                                                                                                                     |
| 99.4         |       | Certification   of Chief Financial Officer pursuant to 18 U.S.C. Section 1350                                            |
|         |       |                                                                                                                     |
| 99.5         |       | Consent   of Independent Registered Chartered Accountants                                                                |
|         |       |                                                                                                                     |
| 99.6         |       | Consent   of Ian R. McDonald                                                                                             |
|         |       |                                                                                                                     |
| 99.7         |       | Consent   of Ryder Scott Company, L.P.                                                                                   |
|         |       |                                                                                                                     |
| 99.8         |       | Consent   of DeGolyer and MacNaughton                                                                                    |
|         |       |                                                                                                                     |
| 99.9         |       | Consent   of McDaniel & Associates Consultants Ltd.                                                                  |

 

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