Annual Report (foreign Private Issuer) (40-f)

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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
PSC TM	=	Premium Synthetic Crude TM	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 PSC™ 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 H 2 S 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 PSC™ 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 OrCrude™ technology to upgrade the bitumen to PSC™. SAGD operations at Long Lake started in 2008 and we began producing PSC™ 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 OrCrude™ 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 OrCrude™ process with hydrocracking and gasification technologies, the sour crude oil is upgraded to light (39° API) PSC™ 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 OrCrude™ 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 PSC™. 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 PSC™ 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 PSC™. PSC™ 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

 

(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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Table of Contents

 

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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