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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K/A
Amendment No. 1
ANNUAL REPORT PURSUANT TO SECTION 13 or 15(d) of
THE SECURITIES EXCHANGE ACT OF 1934
For the year ended December 31, 2006
Commission File Number 1-6702
NEXEN INC.
Incorporated under the Laws of Canada
98-6000202
(I.R.S. Employer Identification No.)
801 - 7th Avenue S.W.
Calgary, Alberta, Canada T2P 3P7
Telephone - (403) 699-4000
Web site - www.nexeninc.com
SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
TITLE EXCHANGE REGISTERED ON
---------------- ----------------------
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 PURSUANT TO SECTION 12(G) OF THE ACT: NONE.
Indicate by check mark if the registrant is a well-known seasoned issuer, as
defined in Rule 405 of the Securities Act.
Yes [X] No [_]
Indicate by check mark if the registrant is not required to file reports
pursuant to Section 13 or Section 15(d) of the Exchange Act.
Yes [_] No [X]
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months, and (2) has been subject to such filing
requirements for the past 90 days.
Yes [X] No [_]
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to
this Form 10-K. [X]
Indicate by check mark whether the registrant is a large accelerated filer, an
accelerated filer, or a non-accelerated filer.
Large accelerated filer [X] Accelerated filer [_] Non-accelerated filer [_]
Indicate by check mark whether the registrant is a shell company (as defined in
Rule 12b-2 of the Exchange Act).
Yes [_] No [X]
On June 30, 2006, the aggregate market value of the voting shares held by
non-affiliates of the registrant was approximately Cdn $16.5 billion based on
the Toronto Stock Exchange closing price on that date. On January 31, 2007,
there were 262,830,108 common shares issued and outstanding.
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EXPLANATORY NOTE
This Amendment No. 1 on Form 10-K/A (this "Amendment") amends the Annual Report
on Form 10-K for the year ended December 31, 2006 filed on February 26, 2007
(the "Original Filing"). Nexen, Inc. (the "Company") has filed this Amendment
to incorporate textual changes in Items 1 and 2, Business and Properties, and
in Item 7, Management's Discussion and Analysis of Financial Condition and
Results of Operations regarding the Company's reserves process. This Amendment
also includes a change in Item 8, Financial Statements and Supplementary Data
(Note 21 - Differences between Canadian and U.S. Generally Accepted Accounting
Principles) to remove the transitional impact of adopting FASB Statement 158
EMPLOYERS' ACCOUNTING FOR DEFINED BENEFIT PENSION AND OTHER RETIREMENT PLANS
from US GAAP Comprehensive Income for the year ended December 31, 2006. This
Amendment has no effect on the Consolidated Balance Sheets, Consolidated
Statements of Income, Consolidated Statement of Cash Flows, and Consolidated
Statements of Changes in Shareholders' Equity, and more specifically, does not
affect net income, earnings per share, total cash flows, current assets, total
assets, current liabilities, total shareholders' equity or other information as
presented in the Original Filing.
Other information contained herein has not been updated. Therefore, this
Amendment should be read together with other documents that the Company has
filed with the Securities and Exchange Commission subsequent to the filing of
the Original Filing. Information in such reports and documents updates and
supersedes certain information contained in this Amendment. The filing of this
Amendment shall not be deemed an admission that the Original Filing, when made,
included any known, untrue statement of material fact or knowingly omitted to
state a material fact necessary to make a statement not misleading.
TABLE OF CONTENTS
PART I PAGE
Items 1 & 2. Business and Properties .................................. 2
PART II
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations ......................29
Item 8. Financial Statments and Supplementary Data ...............68
PART IV
Item 15. Exhibits ................................................122
Unless we indicate otherwise, all dollar amounts ($) are in Canadian dollars,
and oil and gas volumes, reserves and related performance measures are
presented on a working interest before-royalties basis. Where appropriate,
information on an after-royalties basis is provided in tabular format. Volumes
and reserves include Syncrude operations unless otherwise stated.
Below is a list of terms specific to the oil and gas industry. They are
used throughout the Form 10-K.
/d = per day mboe = thousand barrels of oil equivalent
bbl = barrel mmboe = million barrels of oil equivalent
mbbls = thousand barrels mcf = thousand cubic feet
mmbbls = million barrels mmcf = million cubic feet
mmbtu = million British thermal units bcf = billion cubic feet
km = kilometre WTI = West Texas Intermediate
MW = megawatt NGL = natural gas liquid
In this 10-K, we refer to oil and gas in common units called barrel of oil
equivalent (boe). A boe is derived by converting six thousand cubic feet of gas
to one barrel of oil (6mcf/1bbl). This conversion may be misleading,
particularly if used in isolation, as the 6mcf/1bbl ratio is based on an energy
equivalency at the burner tip and does not represent the value equivalency at
the well head.
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
2002 0.6331 0.6369 0.6618 0.6199
2003 0.7738 0.7135 0.7738 0.6350
2004 0.8308 0.7683 0.8493 0.7159
2005 0.8577 0.8253 0.8690 0.7872
2006 0.8581 0.8818 0.9099 0.8528
On January 31, 2007, the noon-day exchange rate was US $0.8480 for Cdn
$1.00.
Electronic copies of our filings with the Securities Exchange Commission
(SEC) and the Ontario Securities Commission (OSC) (from November 8, 2002
onward) are available, free of charge, on our website (www.nexeninc.com).
Filings prior to November 8, 2002 are available free of charge, on request, by
contacting our investor relations department at 403.699.5931. As soon as
reasonably practicable, our filings are made available on our website once they
are electronically filed with the SEC and/or the OSC. Alternatively, the SEC
and the OSC each maintain a website (www.sec.gov and www.sedar.com) that
contains our reports, proxy and information statements and other published
information that have been filed or furnished with the SEC and the OSC.
PART I
ITEMS 1 AND 2. BUSINESS AND PROPERTIES
PAGE
----
ABOUT US 3
STRATEGY 4
UNDERSTANDING THE OIL AND GAS BUSINESS 4
OIL AND GAS OPERATIONS 5
North Sea--United Kingdom 5
Gulf of Mexico--United States 8
Canada 10
Middle East--Yemen 14
Offshore West Africa 17
Other International 18
RESERVES, PRODUCTION AND RELATED INFORMATION 18
SYNCRUDE MINING OPERATIONS 23
ENERGY MARKETING 25
CHEMICALS 27
GOVERNMENT REGULATIONS 28
ENVIRONMENTAL REGULATIONS 28
EMPLOYEES 28
2
ABOUT US
Nexen Inc. (Nexen, we or our) is an independent, Canadian-based, global
energy company. We were formed in Canada in 1971 by the combination of the
Canadian crude oil, natural gas, sulphur and chemical operations of two
subsidiaries of Occidental Petroleum Corporation (Occidental). We've grown from
producing 10,700 boe/d before royalties with revenues of $26 million in 1971,
to 211,700 boe/d before royalties (including Syncrude production) and revenues
of $3.9 billion in 2006. We achieved this growth through exploration success
and strategic acquisitions. In more than 30 years of operations, we have been
profitable every year, except one, and have been paying quarterly dividends
consecutively since 1975.
In the 1970s, we expanded our western Canadian assets and entered the US
Gulf of Mexico. We finished this decade with production of approximately 11,000
boe/d before royalties and revenues of $126 million.
In the 1980s, we continued to expand in western Canada by acquiring
Canada-Cities Service, Ltd. in 1983. This acquisition doubled our size and
included an interest in the Syncrude Joint Venture, our entry into the
Athabasca oil sands. Acquisitions of Cities Offshore Production Co. in 1984 and
Moore McCormack Energy, Inc. in 1988 established our presence in the Gulf of
Mexico. We finished this decade with production of approximately 68,600 boe/d
before royalties and revenues of $591 million.
In the 1990s, we had two defining events: discovering oil on the Masila
block in Yemen and acquiring Wascana Energy Inc. The first of 17 fields at
Masila was discovered in 1991, and Masila has produced more than 940 million
barrels since start up in 1993. Our 1997 purchase of Wascana Energy Inc. almost
tripled our Canadian production. In 1998, we entered Australia with an interest
in the offshore Buffalo field and Nigeria as the operator of the Ejulebe field.
Also in 1998, we discovered Ukot on Block OPL-222, offshore Nigeria, the first
of several discoveries to date on the block. We finished this decade with
production of approximately 239,200 boe/d before royalties and revenues of $1.7
billion.
So far in the 21st century, we have made a number of discoveries, two
strategic acquisitions and completed a non-core divestiture program. In 2000,
we discovered Gunnison in the deep-water Gulf of Mexico and Guando in Colombia.
We joined with Ontario Teachers' Pension Plan Board (Teachers) to acquire
Occidental's remaining 29% interest in us. Teachers purchased 20.2 million
common shares. We repurchased the remaining 20 million common shares for $605
million, which would have had a value of more than $2.6 billion at year-end
2006. We also exchanged our oil and gas operations in Ecuador for Occidental's
15% interest in our chemical operations and we changed our name to Nexen Inc.
from Canadian Occidental Petroleum Ltd. In 2001, we discovered Aspen in the
deep-water Gulf of Mexico and signed a joint venture agreement with OPTI Canada
Inc. to develop, produce and upgrade bitumen at Long Lake in the Athabasca oil
sands. In 2002, we discovered Usan, the second discovery on OPL-222, offshore
Nigeria. In late 2003, we discovered two fields on Block 51 in Yemen. In 2004,
we acquired properties in the UK North Sea, providing us with operatorship of
the Buzzard discovery, the producing Scott and Telford fields and 700,000
exploration acres.
WE'VE GROWN FROM PRODUCING 10,700 BOE/D IN 1971 TO
211,700 BOE/D IN 2006. IN 2007, WE EXPECT OUR NET PRODUCTION TO GROW BY 50%.
In 2005, we sold Canadian conventional oil and gas properties producing
approximately 18,300 boe/d before royalties and monetized 39% of our chemical
business through the initial public offering of the Canexus Income Fund. We
also made a potentially significant discovery in the Gulf of Mexico at Knotty
Head and commenced commercial development of our first coalbed methane (CBM)
project in the Fort Assiniboine area in western Canada. In 2006, we completed
our major development project at Buzzard on budget and made significant
construction progress at our Long Lake project in the Athabasca oil sands. In
early January 2007, Buzzard produced first oil. With Buzzard on stream,
followed by Long Lake later in the year, we expect our production after
royalties in 2007 to grow by more than 50%, net of declines. Our portfolio of
assets, combined with our talented people and an active exploration program,
are expected to provide future growth for our company.
For financial reporting purposes, we report on four main segments:
o oil and gas;
o Syncrude;
o energy marketing; and
o chemicals
Our oil and gas operations are broken down geographically into the UK North
Sea, US Gulf of Mexico, Canada,
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Yemen and Other International (currently Colombia and offshore West Africa).
Results from our Long Lake project are included in Canada. Syncrude is our
7.23% interest in the Syncrude Joint Venture. Energy marketing includes our
growing crude oil, natural gas, natural gas liquids, ethanol and power
marketing business in North America, Europe and southeast Asia. Chemicals
includes operations in North America and Brazil that manufacture, market and
distribute sodium chlorate, caustic soda and chlorine through the Canexus
Limited Partnership.
Production, revenues, net income, capital expenditures and identifiable
assets for these segments appear in Note 20 to the Consolidated Financial
Statements and in Management's Discussion and Analysis of Financial Condition
and Results of Operations (MD&A) in this report.
STRATEGY
Our goal is to grow long-term value for our shareholders. We define value
growth as increasing reserves, production, cash flow and net income over the
long term. We believe in developing our competitive advantage, which generates
opportunities for long-term success in our ever-evolving industry. As
conventional basins in North America mature, we have developed specific
capabilities in oil sands, coalbed methane (CBM), deep-water technology and
international locations. These enable us to focus on specific types of
projects, as we transition toward major projects in established basins,
exploration in less mature basins and exploitation of unconventional resources.
Today, we are building new sustainable businesses in western Canada, the
North Sea, Gulf of Mexico, and offshore West Africa, capitalizing on the
following corporate strengths:
o We are successful deep-water explorers with significant
discoveries at Knotty Head in the Gulf of Mexico and at Usan,
offshore Nigeria;
o We are skilled project managers with major development projects at
Buzzard in the North Sea, and Long Lake in Canada's Athabasca oil
sands. In 2006, Buzzard was completed on budget and just days
after the original projected start up date. At Long Lake,
construction is progressing well and we expect the SAGD production
operations to be on stream by the end of the first quarter in
2007, followed by the start up of the upgrader late in the year;
o We are innovative in our application of technology. Long Lake is
expected to be the first oil sands project to use gasification
technology to significantly reduce the cost of producing bitumen;
o We are an international operator with a proven track record of
successful business ventures in Yemen, the United Kingdom,
Nigeria, Colombia and Australia; and
o From time to time, we supplement our growth with acquisitions,
such as our strategic entry into the UK North Sea in 2004.
The location and scale of our operations often result in an extended
period of time from the capture of opportunities to first production and
non-linear year-over-year growth in reserves and production. Significant
up-front capital investment is often required prior to realizing production and
free cash flows. We fund this investment by maximizing cash flow from our
producing assets, issuing long-term debt and selling non-core assets into
attractive markets.
WE ARE BUILDING SUSTAINABLE BUSINESSES WITH MAJOR PROJECTS IN
ESTABLISHED BASINS, EXPLOITATION OF UNCONVENTIONAL RESOURCES AND EXPLORATION.
Our long-term strategy focuses on building capacity by ensuring we have a
sufficient inventory of opportunities for future growth. With Buzzard on
stream, followed by Long Lake later this year, we expect to deliver significant
production growth. In fact, in 2007 we expect our production after royalties to
grow by more than 50%, net of declines. However, the growth does not stop
there. Beyond 2007, we have a number of opportunities that are expected to
provide production growth and create shareholder value well into the next
decade. These opportunities include undeveloped discoveries at Knotty Head in
the Gulf of Mexico, Usan and Ukot offshore Nigeria, various discoveries in the
UK North Sea, together with development of our CBM and additional oil sands
leases in Canada.
In creating sustainable businesses, we are committed to good corporate
governance and social responsibility. We believe that over the long term,
companies that follow sustainable business practices outperform those with
narrower priorities. We foster dialogue with stakeholders about our operational
opportunities and challenges, from exploration to production to reclamation.
Our goal is to help stakeholders become engaged participants in a continuing
consultation process, while balancing their multiple, and sometimes conflicting
goals.
UNDERSTANDING THE OIL AND GAS BUSINESS
The oil and gas industry is highly competitive. With strong global demand
for energy, 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
4
the oil or gas, the fiscal terms of the host regime and the price products
command in the market based on quality and marketing efforts. Our goal is to
extract the maximum value from each barrel of oil equivalent, so 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 generated from
operating activities. 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.
Realized prices for our oil and gas products are mainly determined by
volatile global crude oil and natural gas markets. With many alternative
customers, the loss of any one customer is not expected to have a significant
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
can have a seasonal component that can impact price. In particular, heavy oil
is generally in higher demand in the summer for its use in road construction,
and natural gas is generally in higher demand in the winter for heating. We
manage our operations on a country-by-country basis, reflecting differences in
the regulatory and competitive environments and risk factors associated with
each country.
OIL AND GAS OPERATIONS
We have oil and gas operations in the UK North Sea, US Gulf of Mexico,
western Canada, Yemen, offshore West Africa and Colombia. We also have
operations in Canada's Athabasca oil sands which produce synthetic crude oil.
We operate most of our production and continue to develop new growth
opportunities in each area by actively exploring and applying technology.
In this Form 10-K/A, we provide estimates of remaining quantities of oil
and gas reserves for our various properties. Such estimates are internally
prepared. We had 97% of our oil and gas reserves before royalties (97% after
royalties) and 100% of our Syncrude reserves before royalties (100% after
royalties) assessed (either evaluated or audited as described on page 22) by
independent reserves consultants. Their assessments are performed at varying
levels of property aggregation, and we work with them to reconcile the
differences on the portfolio of properties to within 10% in the aggregate.
Estimates pertaining to individual properties within the portfolio often differ
by significantly more than 10%, either positively or negatively; however, we
believe such differences are not material relative to our total proved
reserves. Refer to the section on Critical Accounting Estimates - Oil and Gas
Accounting - Reserves Determination on page 62 for a description of our
reserves process, and to the section on Reserves, Production and Related
Information on page 18 for a description of the nature and scope of the
independent assessments performed and the results thereof.
NORTH SEA--UNITED KINGDOM (UK)
The UK is one of our key growth areas. In 2004, we acquired a 43.2%
operated interest in the Buzzard development, a 41% operated interest in the
Scott field, a 54.3% operated interest in the Telford field, the Scott
production platform, interests in several satellite discoveries and more than
700,000 net undeveloped exploration acres for US$2.1 billion. This acquisition
established us as a significant regional player with concentrated assets,
infrastructure and exploration and development potential for future growth. It
added high-margin reserves and production, diversified our worldwide portfolio
by adding strong assets in a stable jurisdiction, and complemented our other
longer cycle-time projects.
5
Our UK strategy is focused on exploration and exploitation opportunities
near existing infrastructure. We have a number of exploitation opportunities in
our existing fields and smaller satellite undeveloped discoveries near
infrastructure. Most of our unexplored acreage is near Scott/Telford, Buzzard
or Ettrick which is currently being developed. As a result, new discoveries
could be tied-in relatively quickly, upon success.
During the year, we produced 20,200 boe/d before royalties (20,200 after
royalties) in the UK, which was approximately 10% of Nexen's total production.
At year end, the UK had proved reserves of 182 mmboe before royalties (182
after royalties) representing about 17% of our total proved oil and gas and
Syncrude reserves.
BUZZARD DEVELOPMENT
The Buzzard field is located in the Outer Moray Firth, central North Sea,
about 60 miles northeast of Aberdeen, in 317 feet of water. The field was
discovered in 2001 and construction was completed in 2006, with production
commencing early January 2007. During the year, we installed the utilities and
production topsides, drilled the initial development wells and completed
hook-ups and project commissioning. The facilities have the capacity to process
up to 200,000 bbls/d of oil and 60 mmcf/d of gas, including the removal of
hydrogen sulphide. Based upon recent drilling results, we have experienced more
well-to-well variability in the concentration of hydrogen sulphide than
previously seen. We expect existing equipment and processes will allow us to
manage this variability for at least the first two to three years of
production. As we continue to produce and acquire additional reservoir
information, we will determine whether additional equipment will ultimately be
required. We anticipate the field will be produced through 27 production wells
and reservoir pressure will be maintained through an active water-flood
program. Buzzard is one of the largest discoveries in the UK North Sea in the
past ten years.
BUZZARD IS ON STREAM AND RAMPING UP
TO ESTIMATED PEAK RATES OF 85,000 BOE/D NET TO US.
ETTRICK DEVELOPMENT
We are progressing development of the Ettrick field which is expected to
begin producing in the first half of 2008, with our share expected to average
approximately 16,000 boe/d (before and after royalties). Development includes
drilling three production wells tied back to a leased floating production,
storage and off-loading vessel (FPSO) and is approximately 30% complete. Our
share of full-cycle development costs is estimated at $460 million. In 2007, we
plan to invest $235 million in subsea development including drilling three
development wells and one water injection well.
UK PRODUCTION
Buzzard began producing at the beginning of January 2007. We expect to
reach peak gross production rates of approximately 200,000 bbls/d of oil and
approximately 30 mmcf/d of gas, with our share about 85,000 boe/d (before and
after royalties) in the first half of 2007. Oil from Buzzard is exported via
the Forties pipeline to the Grangemouth refinery in Scotland. Gas is exported
via the Frigg system to the St. Fergus Gas Terminal in northeast Scotland. In
2007, we plan to invest approximately $130 million to pre-drill and complete 11
future production and injection wells.
Scott and Telford are producing fields with additional exploitation
opportunities. Scott, in which we have a 41% working interest, was discovered
in 1987 and began producing in September 1993. We have a 54.3% working interest
in Telford, which was discovered in 1991 and came on stream in 1996. In 2006,
our share of Scott and Telford royalty-free production approximated 16,000
boe/d, of which 80% was oil.
Oil and gas is produced through numerous subsea wells and platform wells.
Oil is delivered to the Grangemouth refinery in Scotland via the Forties
pipeline, while gas is exported via the SAGE pipeline to the St. Fergus Gas
Terminal in
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northeast Scotland. In 2005, the Scott platform underwent a significant
maintenance turnaround and facilities upgrade to improve reliability and extend
facility life. In 2006, the flare tip and flare tip supporting structure were
upgraded. In 2007, we plan to invest approximately $45 million to drill,
complete and tie-in three development wells.
Our 2004 UK acquisition included a non-operated interest in Farragon, a
small satellite discovery, which was brought on stream in November 2005. In
2006, our 20% share of royalty-free production from Farragon was 3,700 boe/d.
EXPLORATION AND UNDEVELOPED ASSETS
In early 2007, we completed drilling operations at our Golden Eagle
prospect and we encountered hydrocarbons. A successful sidetrack was drilled to
appraise the accumulation and we are currently evaluating development options.
We have a number of smaller discoveries on operated blocks near Scott, Buzzard
and third-party facilities as follows:
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FIELD INTEREST (%) OPERATOR STATUS COMMENTS
- -------------------------------------------------------------------------------------------------------------------------
Duart 50 non-operated discovery near Scott; first oil expected in late 2007
- -------------------------------------------------------------------------------------------------------------------------
Black Horse 40 operated discovery near Scott; evaluating development alternatives
- -------------------------------------------------------------------------------------------------------------------------
Bugle 82 operated discovery near Scott; well planned for 2007
- -------------------------------------------------------------------------------------------------------------------------
Dolphin 42 operated discovery near Scott; evaluating development alternatives
- -------------------------------------------------------------------------------------------------------------------------
Golden Eagle 34 operated discovery near Ettrick; evaluating development alternatives
- -------------------------------------------------------------------------------------------------------------------------
Perth 42 operated discovery near Scott; evaluating development alternatives
- -------------------------------------------------------------------------------------------------------------------------
Polecat 40 operated discovery near Buzzard; evaluating development alternatives
- -------------------------------------------------------------------------------------------------------------------------
Selkirk 38 operated appraisal well planned for 2007
- -------------------------------------------------------------------------------------------------------------------------
Yeoman 50 operated discovery near Scott; evaluating development alternatives
=========================================================================================================================
Development is progressing at Duart. In 2007, we plan to drill a
development well and bring the field on stream before year-end. The other
discoveries are in various stages of evaluation.
During 2006, we drilled unsuccessful exploration wells at Zanzibar and
Black Cat. These wells encountered non-commercial hydrocarbons and were
abandoned. In 2007, we expect to drill five exploration and appraisal wells.
The offshore drilling rig market is currently tight, however, we have secured
drilling rigs for most of our 2007 North Sea exploration and development
program.
COALBED METHANE (CBM)
In 2006, we acquired an 80% working interest at an emerging CBM
opportunity in the UK. CBM is commonly referred to as an unconventional form of
natural gas because it is primarily stored through adsorption by coal in coal
deposits rather than in the pore space of the rock like most conventional gas.
The gas is released in response to a drop in reservoir pressure. If the coal
deposit is water saturated, water generally needs to be extracted to reduce the
pressure and allow gas production to occur. If the coal does not produce water
and is "dry", gas will be produced from initial development. Water-producing
CBM wells in the United States generally show increasing gas production rates
for a period of approximately one to three years before gas rates begin to
decline.
During 2006, we drilled two exploratory wells at our UK CBM opportunity.
The wells encountered all the coal seams expected. In 2007, we plan to continue
assessing the potential of this investment by drilling additional wells and
production testing them.
FISCAL TERMS
UK fiscal terms are favourable. New discoveries pay no royalties and
result in cash netbacks that are higher than our company average. Scott is
subject to Petroleum Revenue Tax (PRT), although no PRT is payable until
available oil allowances have been fully utilized, which isn't expected before
2012. Once payable, PRT is levied at 50% of cash flow after capital
expenditures, operating costs and an oil allowance. PRT is applicable to fields
receiving development consent prior to March 1993. The Buzzard, Telford and
Farragon fields are not subject to PRT. PRT is deductible for corporate income
tax purposes. The UK corporate income tax rate is 30% of taxable income. Income
from oil and gas activities is also subject to a supplemental charge. The UK
government increased this charge from 10% to 20%, effective January 1, 2006.
The amount and timing of income taxes payable depends on many factors including
price, production, capital investment levels and available tax losses.
7
GULF OF MEXICO--UNITED STATES (US)
The Gulf of Mexico is an integral part of our growth strategy. Large
discoveries, relatively high success rates, production infrastructure and
attractive fiscal terms make the deep-water Gulf of Mexico one of the world's
most prospective sources for oil and gas. The deep-water prospects generally
have multiple sands and high production rates, factors which reduce risk and
improve economics. Technology to find, drill, and develop discoveries is
rapidly progressing and becoming more cost effective. The deep-water Gulf is
relatively near infrastructure and continental US markets, enabling discoveries
to be brought on stream in a reasonable period of time.
Our strategy in the Gulf is to explore for new reserves, exploit our
existing asset base and acquire assets with upside potential. We focus our
exploration program on three strategic play types:
o deep-shelf gas prospects;
o deep-water prospects near existing infrastructure; and
o deep-water, sub-salt plays with potential to become new core
areas.
These plays are relatively under-explored, hold potential for large
discoveries and have attractive fiscal terms. The shorter-cycle times for shelf
gas and deep-water prospects near infrastructure complement the longer-cycle
times for deep-water sub-salt plays. Although competition in the Gulf is
strong, we expect the availability of expiring acreage over the next few years
to provide us with access to additional exploration opportunities.
In 2006, we invested $595 million on exploration and development
activities in the Gulf. This resulted in discoveries at Alaminos Canyon Block
856 (Great White West) and Ringo. In 2007, we plan to invest approximately $585
million in the Gulf to further our strategy.
US PRODUCTION
2006 2005 2004
- ------------------------------------------------------------------------------------------------------------------------------
BEFORE AFTER BEFORE AFTER BEFORE AFTER
(mboe/d) ROYALTIES ROYALTIES ROYALTIES ROYALTIES ROYALTIES ROYALTIES
- ------------------------------------------------------------------------------------------------------------------------------
Deep-water 19.6 17.5 24.0 21.5 32.1 28.7
- ------------------------------------------------------------------------------------------------------------------------------
Shallow-water 15.9 13.2 17.6 14.6 22.6 18.8
- ------------------------------------------------------------------------------------------------------------------------------
Total 35.5 30.7 41.6 36.1 54.7 47.5
==============================================================================================================================
In 2006, we produced approximately 35,500 boe/d before royalties (30,700
after royalties), representing approximately 17% of Nexen's total production
including Syncrude. This was less than expected due to timing delays at Aspen
and weather-related disruptions. Weather is a risk in the Gulf of Mexico;
specifically, tropical storms and hurricanes can damage facilities, drilling
rigs and surrounding infrastructure, interrupt production, and delay
exploration and development programs. Storms in 2005 caused damage to
third-party infrastructure and as a result, approximately 4,000 boe/d of our
pre-storm production was shut-in for nine months of 2006. We carry property and
business interruption insurance to mitigate losses caused by adverse weather.
During 2006, we received $80 million of insurance proceeds relating to these
storms.
At year end, we had proved reserves of 73 mmboe before royalties (63 after
royalties) representing about 7% of Nexen's total proved oil and gas and
Syncrude reserves. Our production and reserves in the Gulf are primarily
concentrated in two deep-water and five shallow-water areas. We operate most of
this production.
8
DEEP-WATER PRODUCTION
The majority of our deep-water production comes from our 100%-operated
Aspen field and 30% non-operated Gunnison field. Aspen is on Green Canyon Block
243 in 3,150 feet of water. The project was developed using subsea wells tied
back to the Shell-operated Bullwinkle platform 16 miles away. Production began
in December 2002 and we achieved payout on our full investment in Aspen in
January 2005. Our share of 2006 production before royalties was approximately
8,900 boe/d (8,000 after royalties). In 2006, we drilled an additional
development well. This well came on stream in late December. Based on results
from this well, we see additional opportunities in the Aspen field and are
currently sidetracking the Aspen 1 well to exploit deeper sands. We expect our
2007 production from the Aspen field to average between 15,000 and 20,000
boe/d.
THE WRIGLEY DISCOVERY IS
EXPECTED TO BEGIN PRODUCING IN EARLY 2007.
Gunnison is in 3,100 feet of water and includes Garden Banks Blocks 667,
668 and 669. Gunnison began production in December 2003 through our truss SPAR
platform that can handle 40,000 bbls/d of oil and 200 mmcf/d of gas. We
achieved payout on Gunnison in December 2005, just two years after first
production. In 2006, our share of production before royalties was approximately
10,600 boe/d (9,300 after royalties). Our Gunnison SPAR production facility has
excess capacity, leaving room for growth from exploration and processing of
third-party volumes. In 2006, we completed the tie-in of our 15% non-operated
Dawson Deep discovery to the Gunnison SPAR.
SHALLOW-WATER PRODUCTION
Our shelf producing assets are offshore Louisiana, primarily in five
100%-owned field areas: Eugene Island 18, Eugene Island 255/257/258/259, Eugene
Island 295, Vermilion 302/321/339/340, and Vermilion 76 (consisting of Blocks
65, 66 and 67). We continue to exploit these assets and look for other
opportunities on the shelf. Most of our 2006 shelf activities focused on
development drilling at Eugene Island 258/259 and Eugene Island 295.
EXPLORATION AND UNDEVELOPED ASSETS
Our exploration program in the Gulf of Mexico continues to produce new
discoveries. In 2006, we had discoveries at Alaminos Canyon Block 856 (Great
White West) and Ringo. We are currently evaluating development options for both
of these discoveries. During the year, we also drilled a successful sidetrack
well on our 2005 Knotty Head discovery. We are currently proceeding with
facility and subsurface studies. Access to deep-water rigs remains limited and
we continue to work with partners to find a rig to complete the appraisal of
the field. Our undeveloped deep-water discoveries include:
- ---------------------------------------------------------------------------------------------------------------------------------
WELL INTEREST (%) OPERATOR STATUS COMMENTS
- ---------------------------------------------------------------------------------------------------------------------------------
Wrigley 50 non-operated development underway; expected to begin producing in early 2007
- ---------------------------------------------------------------------------------------------------------------------------------
Alaminos Canyon Block 856 30 non-operated evaluating development alternatives
- ---------------------------------------------------------------------------------------------------------------------------------
Tobago 10 non-operated development approved; expected to begin producing in 2009
- ---------------------------------------------------------------------------------------------------------------------------------
Knotty Head 25 operated further appraisal required
- ---------------------------------------------------------------------------------------------------------------------------------
Ringo 50 non-operated additional appraisal well to be drilled in 2007
=================================================================================================================================
During the year, we drilled dry holes at Pathfinder, West Cameron 135,
West Cameron 109, Eugene Island 19 and Vermilion 65. We increased our
deep-water undeveloped land position by 20 blocks to over 200 blocks and expect
this acreage and future exploration opportunities to position us well for
continued growth. In 2007, we plan to tie-in our Wrigley discovery to a
third-party facility. We also plan to drill nine exploration wells (four in the
deep water and five on the shelf) and have drilling rigs secured for more than
half of these wells. We are actively working with partners to find rigs for the
remainder. In 2005, we committed to a deep-water drilling contract, which
provides us with access to a new-build fifth generation dynamically positioned
semi-submersible drilling rig for two years over a three-and-a-half year
period. We expect this new rig to be available in mid 2009.
9
FISCAL TERMS
In 2006, royalty rates on our US production averaged 16.6% for
shallow-water volumes and 11.2% for deep-water volumes. The US government has
proposed to increase royalty rates from 12.5% to 16.7% for new deep-water
leases awarded after July 2007. We qualify for royalty relief at our deep-water
Aspen and Gunnison fields on the first 87.5 mmboe of production. However, we
may be subject to royalties at Gunnison if annual commodity prices are higher
than threshold prices set by the US Department of the Interior's Minerals
Management Service (MMS). The oil and gas industry is currently litigating the
enforceability of these price thresholds. In 2006, commodity prices exceeded
these thresholds, and we were assessed a royalty at Gunnison of 12.5% by the
MMS. If the litigation is not successful, royalties that we have accrued on our
Gunnison production will be payable. Our Aspen field is not subject to the
minimum price threshold, however, the US government has proposed legislation to
include minimum threshold prices for deep-water leases granted in 1998 and
1999. If the legislation is approved, our Aspen field could be subject to a
12.5% government royalty on production after October 1, 2006. US taxable income
is subject to federal income tax of 35% and state taxes ranging from 0% to 12%.
IN CANADA, WE ARE INCREASING OUR CAPACITY BY FOCUSING
ON UNCONVENTIONAL RESOURCES SUCH AS OIL SANDS, CBM AND ENHANCED OIL RECOVERY.
CANADA
Our strategy in Canada is to bring our new growth developments into
production while we maximize value from our established operations. In 2005, we
disposed of approximately 18,300 boe/d before royalties of production,
comprising approximately 60% oil and 40% gas. The assets we retained have
upside potential for continued conventional development and enhanced recovery
with advancements in extraction technology. During the year, we produced 38,000
boe/d before royalties (31,000 after royalties), which was approximately 18% of
Nexen's total production including Syncrude. At year end 2006, proved reserves
(including bitumen and excluding Syncrude) of 364 mmboe before royalties (319
after royalties) were approximately 35% of our total proved oil and gas and
Syncrude reserves.
Our remaining Canadian conventional assets comprise heavy oil production
in east-central Alberta and west-central Saskatchewan, and natural gas near
Calgary and in southern Alberta and Saskatchewan. We operate most of our
producing properties and hold 1.1 million net acres of undeveloped land across
western Canada. These assets provide predictable production volumes and
earnings while we advance the following initiatives for future growth:
o Athabasca oil sands--to produce and upgrade bitumen into synthetic
crude;
o enhanced oil recovery (EOR)--to increase recovery in our heavy oil
fields; and
o coalbed methane (CBM)--to extract natural gas primarily from Upper
Mannville coals.
In 2006, we invested $1,609 million in Canada; $1,416 million into these
growth initiatives. In 2007, we plan to invest approximately $1,070 million;
$944 million in these initiatives.
ATHABASCA OIL SANDS
The Athabasca oil sands in northeast Alberta is a key growth area for
Nexen. Our strategy is to economically develop our bitumen resource in phases
to provide low-risk, stable, future growth. Our Long Lake project involves
integrating steam-assisted-gravity-drainage (SAGD) bitumen production with
field upgrading technology to produce a premium synthetic crude oil that
significantly reduces our need to purchase natural gas. We also have a 7.23%
investment in the Syncrude oil sands mining operation.
10
Long Lake Project
In 2001, we formed a 50/50 joint venture with OPTI Canada Inc. (OPTI) to
develop the Long Lake property using SAGD for bitumen production and field
upgrading using the proprietary OrCrude(TM) process. OrCrude(TM) is a
technology to which OPTI has the exclusive Canadian license. We acquired the
exclusive right to use this technology with OPTI, within approximately 100
miles of Long Lake, and the right to use the technology independently elsewhere
in the world.
We operate the Long Lake lease bitumen extraction process and are
responsible for constructing, developing and operating the SAGD project. OPTI
is responsible for the design, construction and operation of the upgrader. We
share equally in all project reserves, production, operating and capital costs.
SAGD AND UPGRADER INTEGRATION
SAGD involves drilling two parallel horizontal wells, generally between
2,300 and 3,300 feet long, with about 16 feet of vertical separation. Steam is
injected into the shallower well, where it heats the bitumen that then flows by
gravity to the deeper producing well. The OrCrude(TM) 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(TM) process with commercially
available hydrocracking and gasification technologies, sour crude is upgraded
to light (39(degree) API) premium synthetic sweet crude oil, and the
asphaltenes are converted to a low-energy, synthetic fuel gas. This gas is
available as a low-cost fuel source, and as a source for hydrogen required in
the hydrocracker. The gas is also to be burned in a co-generation plant to
produce steam for the SAGD operations and for electricity to be used on-site
and sold 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, which we expect will provide us with an approximate $10/bbl
operating cost advantage.
OUR STRATEGIC ADVANTAGE
Our SAGD and upgrading integration enables us to overcome three main
economic hurdles of SAGD bitumen production: 1) the high cost of natural gas;
2) the cost and availability of diluent; and 3) the realized price of bitumen.
With synthetic gas from the asphaltenes as a fuel source, we have little need
to purchase additional natural gas. With the upgrading facilities on site,
expensive diluent is not required to transport the bitumen to market. And, by
upgrading the bitumen into a highly desirable refinery feedstock or diluent
supply, the end product commands light-sweet crude oil premium pricing.
WE EXPECT OUR INTEGRATED OIL SANDS STRATEGY WILL
PROVIDE US WITH AN APPROXIMATE $10/BBL OPERATING COST ADVANTAGE.
PROJECT MILESTONES AND COSTS
The Long Lake project received regulatory approval in 2003 and Nexen board
approval in 2004. Field construction on the SAGD and upgrader facilities began
in 2004. In 2006, we substantially completed module and site construction of
the SAGD facilities. Steam injection is expected to commence at the end of the
first quarter of 2007, with bitumen production expected to ramp up to peak
rates over a 12 to 24 month period. For the first six months of SAGD operation,
we will largely be heating the reservoir. During this period, steam to oil
ratios will be high but will decline with time as bitumen production ramps up
to our target rates. Depending on our actual start up date and the amount of
downtime at our facilities, we expect bitumen production before royalties to
reach between 35,000 and 45,000 bbls/d (between 17,500 and 22,500 bbls/d net to
our share) by the end of 2007, with a steam-to-oil
11
ratio of between 3.5 and 4.0. We expect the steam-to-oil ratio to average
approximately 3.0 over the long-term.
LONG LAKE IS ON TRACK FOR START UP IN 2007 AND EXPECTED TO REACH PEAK
PRODUCTION OF ABOUT 60,000 BBLS/D (30,000 BBLS/D NET) OF PREMIUM
SYNTHETIC CRUDE BY LATE 2008 OR EARLY 2009.
Upgrader module fabrication is largely complete and over 95% of the
modules are on site. Construction of the upgrader is approximately 80% complete
and start up is scheduled for late 2007. Peak output of premium synthetic crude
oil is expected within 6 to 18 months of upgrader start up and we expect to
exit 2007 with synthetic production rates of between 28,000 and 36,000 bbls/d
(between 14,000 and 18,000 bbls/d net to our share). Production capacity for
the first phase of Long Lake is approximately 60,000 bbls/d (30,000 bbls/d net
to our share) of premium synthetic crude, which we expect to reach by late 2008
or early 2009. We also expect production to be maintained over the project's
life, estimated at 40 years, by periodically drilling additional SAGD
well-pairs.
In 2006, we invested $1,050 million at Long Lake and expect to invest
approximately $500 million in 2007. The capital cost estimate when our board
sanctioned the project in February 2004 was $3.4 billion ($1.7 billion net). In
December 2004, we accelerated the drilling of an additional well pad consisting
of 13 well-pairs to ensure certainty and reliability of bitumen production at
the commencement of upgrader operations at a cost of $98 million ($49 million
net). In early 2006, we further modified the project design by adding steam
generation capacity and soot handling equipment at a cost of $360 million ($180
million net). These scope changes increased the estimated project cost to $3.8
billion ($1.9 billion net). While construction progress has been significant,
high activity in the oil sands is placing ongoing pressure on the costs of
labour and services. In addition, labour productivity has been lower than
anticipated, requiring a larger workforce to maintain progress. As a result,
the projected costs of Long Lake have increased from $3.8 billion to $4.6
billion ($1.9 billion to $2.3 billion net). Although we are seeing pressure on
capital costs, we expect to benefit from a significant operating cost
advantage. Combined SAGD, cogeneration and upgrading operating costs are
expected to average between $12/bbl and $14/bbl, substantially lower than
coking upgrading. We expect ongoing capital to average between $3/bbl and
$4/bbl. The capital costs of producing and upgrading bitumen using this
technology are comparable to those for surface mining and coking upgrading on a
barrel-of-daily production basis.
12
FUTURE PHASES
We have approximately 240,000 net acres of bitumen-prone lands in the
Athabasca region and plan to acquire more. We plan to continue developing our
bitumen lands in a phased manner using our integrated upgrading strategy. In
2005, we announced our plan to duplicate Long Lake by developing Phase 2. In
2006, we invested $119 million for future phases and in 2007, we plan to invest
approximately $170 million on land acquisition, additional drilling, seismic
and engineering to develop our leases and advance regulatory applications for
these phases. Phase 2 SAGD production is expected to be on stream by late 2011,
with upgrader start up by the second half of 2012, followed by additional
phases every two or three years. Each phase will leverage the knowledge and
experience gained from successfully developing Long Lake and subsequent
projects will be similar in size and design. By keeping the core team in place
and repeating and improving on existing designs and implementation plans, we
expect to gain efficiencies in engineering, modular fabrication and on-site
construction. We also anticipate enhanced operating efficiencies as we can
train and move people easily between the various plants.
PHASE 2 SAGD PRODUCTION IS EXPECTED TO BE ON
STREAM BY LATE 2011 FOLLOWED BY UPGRADER START UP IN 2012.
RESERVES RECOGNITION
Under SEC rules and regulations, we are required to recognize bitumen
reserves rather than the upgraded premium synthetic crude oil that we will
produce and sell. The economic recoverability of bitumen reserves is sensitive
to natural gas prices, diluent costs and light/heavy differentials, risks that
our integrated project has been designed to virtually eliminate. At December
31, 2006, we recognized proved bitumen reserves of 246 mmboe before royalties
(219 after royalties) for our Long Lake project, representing about 23% of
Nexen's total proved oil and gas and Syncrude reserves before royalties.
HEAVY OIL
Approximately 52% of our Canadian conventional production is heavy oil.
Heavy oil is characterized by high specific gravity or weight and high
viscosity or resistance to flow. Because of these features, heavy oil is more
difficult and expensive to extract, transport and refine than other types of
oil. Heavy oil also receives a lower price than light oil, as more expensive
and complex refineries are required to refine the heavy crude into higher-value
petroleum products.
Our heavy oil operations are in east-central Alberta and west-central
Saskatchewan. To maximize heavy oil returns, it is important to manage capital
and operating costs. Our large production base and existing infrastructure are
advantageous to us in managing these costs. In 2007, we plan to continue
exploiting our existing fields through drilling and optimizing operations.
ENHANCED OIL RECOVERY
Heavy oil reservoirs typically have lower recovery factors than
conventional oil reservoirs, leaving substantial amounts of oil in the ground.
This creates an opportunity to increase recovery factors by applying new
technology. We are continuing to research various technologies to increase our
heavy oil recoveries with several ongoing pilot projects in west-central
Saskatchewan.
NATURAL GAS
Approximately 48% of our Canadian production is natural gas extracted
primarily from shallow sweet reservoirs in southern Alberta and Saskatchewan
and from sour gas reservoirs near Calgary. In general, shallower gas targets
are cheaper to drill and develop, but have relatively smaller reserves and
lower productivity per well. Sour gas is natural gas that contains hydrogen
sulfide. We have been producing sour natural gas from our Balzac field
northeast of Calgary since 1961. This sour gas is processed through our
operated Balzac plant.
COALBED METHANE (CBM)
In 2005, we approved commercial CBM developments at Corbett, Doris and
Thunder in the Fort Assiniboine area. Our CBM pilot at Corbett in the Fort
Assiniboine area of central Alberta has established techniques to produce
natural gas from water saturated Upper Mannville coals. These coals are
generally deeper than the Horseshoe Canyon "dry coal" play, which is also being
commercially developed in Alberta. We established commerciality of CBM
production from the Upper Mannville coals in 2005 by applying horizontal well
technology. Commercial production rates and reduced de-watering time has
enabled us to confidently develop these coals.
13
In 2006, we invested approximately $237 million in exploration and
development activities. We have a long-term view of this business and plan to
increase our CBM production to at least 150 mmcf/d by 2011, more than doubling
our current Canadian natural gas production. At the end of 2006, we held more
than 700 net sections of land in Alberta with CBM potential, some of which
overlay existing conventional producing lands. We have also established
positions in other prospective CBM areas of Alberta. In 2007, we plan to invest
$200 million to develop 98 gross (41 net) sections using single and multi-leg
horizontal wells. In addition to our development at Fort Assiniboine, we will
continue to evaluate other Mannville and Horseshoe Canyon CBM prospects and
pursue new CBM opportunities in 2007.
SHALE GAS
As part of our growth strategy in unconventional Canadian resource plays,
we acquired over 100 sections of land in an emerging shale gas play in western
Canada in 2006. Shale gas is natural gas produced from reservoirs composed of
organic shale. The gas is stored in pore spaces, fractures or adsorbed into
organic matter. Currently, the United States is the largest producer of shale
gas. In 2007, we plan to initiate a drilling and evaluation program to
demonstrate the feasibility of this resource.
FISCAL TERMS
In Canada, we pay royalties ranging from 15% to 40% on production from
lands owned by the federal and provincial governments. Some provinces also
impose taxes on production from lands where they do not own the mineral rights.
The Saskatchewan government assesses a resource surcharge on gross Saskatchewan
resource sales that are subject to crown royalties of 3.3%, which is reduced to
1.85% for wells completed after October 1, 2002.
Profits earned in Canada from resource properties are subject to federal
and provincial income taxes. In 2006, legislation was passed to reduce the
federal corporate income tax rate on income from Canadian oil and gas
activities from 24% to 19% by 2010.
For our oil sands projects, we elected to pay royalties based on bitumen
production, which includes a 1% royalty on gross revenue until all costs have
been recovered, at which time the royalty changes to 25% on net revenue. With
the combination of low royalties, our expected operating cost advantage and a
premium product, our oil sands financial returns are expected to be attractive
relative to other oil sands projects.
MIDDLE EAST--YEMEN
Yemen has been our most significant international region since we first
began production at Masila in 1993. We operate the country's largest oil
project and have developed excellent relationships with the government and
local communities. Our success and reputation in Yemen opens doors elsewhere in
the Middle East and around the world.
ALTHOUGH OUR MASILA FIELDS HAVE MATURED,
WE EXPECT TO GENERATE APPROXIMATELY 20% OF THE TOTAL
PROJECT CASH FLOW FROM THE REMAINING PROVED RESOURCES.
Our strategy is to maximize the value from our existing blocks, while we
continue to search for new reservoirs in deeper horizons. We have two producing
blocks: Masila (Block 14) and East Al Hajr (Block 51). In 2006, we produced
92,900 bbls/d of oil before royalties (51,800 after royalties), representing
approximately 44% of Nexen's total production and 32% of 2006 cash flow. Proved
reserves of 66 mmboe before royalties (38 after royalties) comprise
approximately 6% of Nexen's total proved oil and gas and Syncrude reserves
before royalties.
14
MASILA BLOCK (BLOCK 14)
We have a 52% working interest in and operate the Masila project. Our
share of 2006 production was 70,300 bbls/d before royalties (35,500 after
royalties). After more than 10 years of growth, our Masila fields have matured,
but significant value still remains. As a result of the Production Sharing
Agreement (PSA) terms that govern Masila production, we still expect to
generate approximately 20% of the total project free cash flow from the
remaining proved reserves recoverable before the PSA expires in 2011.
The first successful Masila exploratory well was drilled at Sunah in 1990,
with additional discoveries quickly following at Heijah and Camaal. Initial
production began in July 1993, with the first lifting of oil in August 1993.
Masila Blend oil averages 32(degree) API at very low gas-oil ratios. Most of
the oil is produced from the Upper Qishn formation, but we also produce from
deeper formations including the Lower Qishn, Upper Saar, Saar, Madbi, Basal
Sand and Basement formations.
Production is collected at our Central Processing Facility (CPF) where
water is separated for reinjection and oil is pumped to the Ash Shihr export
terminal and shipped to customers primarily in Asia.
We are managing the pace of our drilling program to ensure we recover the
remaining reserves in the most efficient, cost-effective manner. In 2007, we
plan to invest approximately $55 million to drill 14 wells.
The PSA governing Masila production was signed in 1987 between the
Government of Yemen and the Masila joint venture partners (Masila Partners),
including Nexen. Under the PSA, we have the right to produce oil from Masila
into 2011 and to negotiate a five-year extension. Production is divided into
cost recovery oil and profit oil. Cost recovery oil provides for the recovery
of all exploration, development, and operating costs that are funded by the
Masila Partners. Costs are recovered from a maximum of 40% of production each
year, as follows:
--------------------------------------------------------------
COSTS RECOVERY
--------------------------------------------------------------
Operating 100% in year incurred
Exploration 25% per year for 4 years
Development 16.7% per year for 6 years
--------------------------------------------------------------
The remaining production is profit oil that is shared between the Masila
Partners and the Government and is calculated on a sliding scale based on
production. The Masila Partners' share of profit oil ranges from 20% to 33%.
The structure of the agreement moderates the impact on Masila Partners' cash
flows during periods of low prices, as we recover our costs first and then
share any remaining profit oil with the Government. At current production, the
Government is entitled to approximately 73% of the profit oil, which includes a
component for Yemen income taxes payable by the Masila Partners at a rate of
35%. In 2006, the Masila Partners' share of production, including recovery of
past costs, was approximately 37%.
15
EAST AL HAJR BLOCK (BLOCK 51)
We have an 87.5% working interest and operate Block 51. This block is
governed by a PSA between the Government of Yemen and the East Al Hajr partners
(EAH 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
capital or operating expenditures. Our effective interest is 100% and for
purposes of accounting and reserves recognition, we treat TYCO's 12.5%
participating interest as a royalty interest. We recognize both the
Government's share and TYCO's share of profit oil under the PSA as royalties
and taxes consistent with our treatment of our Masila operations. The PSA
expires in 2023, and we have the right to negotiate a five-year extension.
Under the terms of the PSA, the EAH Partners pay a royalty ranging from 3% to
10% to the Government depending on production volumes. The remaining production
is divided into cost recovery oil and profit oil. Cost recovery oil provides
for the recovery of all of the project's exploration, development and operating
costs, funded solely by Nexen. Costs are recovered from a maximum of 50% of
production each year after royalties, as follows:
--------------------------------------------------------------
COSTS RECOVERY
--------------------------------------------------------------
Operating 100% in year incurred
Exploration 75% per year, declining balance
Development 75% per year, declining balance
--------------------------------------------------------------
The remaining production is profit oil that is shared between the EAH
Partners and the Government on a sliding scale based on production rates. The
EAH Partners' share of profit oil ranges from 20% to 30%. The Government's
share of profit oil includes a component for Yemen income taxes payable by the
EAH Partners at a rate of 35%. In 2006, the EAH Partners' share of Block 51
production, including recovery of past costs, was approximately 61%.
The first successful exploratory well was drilled at BAK-A in 2003, with
BAK-B discovered shortly after. Block 51 development began in 2004 and includes
a CPF, gathering system and a 22-km tieback to our Masila export pipeline.
Production began in November 2004 and we achieved payout on the project in the
first quarter of 2006. During the year, production averaged 22,600 bbls/d
before royalties (16,300 after royalties).
WE ACHIEVED PAYOUT ON BLOCK 51 IN THE FIRST QUARTER OF 2006.
In 2006, we drilled three exploration wells on the block and two of these
wells were abandoned. In 2007, we plan to invest approximately $80 million to
drill nine development wells, construct additional facilities and continue
exploring with three exploration wells.
16
OFFSHORE WEST AFRICA
Offshore West Africa is a growing core area where we already have
discoveries. It offers prolific reservoirs and multiple opportunities to invest
in this oil-rich region. Our strategy here is to explore and develop our
portfolio for medium- to long-term growth.
NIGERIA
Block OPL-222
In 1998, we acquired a 20% non-operated interest in Block OPL-222, which
includes 448,000 acres and is approximately 50 miles offshore in water depths
ranging from 600 to 3,500 feet. The ongoing appraisal of the block indicates
significant hydrocarbon accumulations based on the drilling results outlined
below:
- -------------------------------------------------------------------------------------------------------------------------------
YEAR WELL LOCATION RESULTS
- -------------------------------------------------------------------------------------------------------------------------------
1998 Ukot-1 Ukot field encountered three oil-bearing intervals and flowed at restricted rate of 13,900
discovery well bbls/d from two intervals
- -------------------------------------------------------------------------------------------------------------------------------
2002 Usan-1 Usan field encountered several oil-bearing intervals and flowed at restricted rate of 5,000
discovery well bbls/d from one interval
- -------------------------------------------------------------------------------------------------------------------------------
2003 Usan-2 3 km west of appraised up-dip portion of the fault block
discovery
- -------------------------------------------------------------------------------------------------------------------------------
2003 Usan-3 2 km northwest of appraised separate fault block and flowed at restricted rate of 5,600 bbls/d from
discovery one interval
- -------------------------------------------------------------------------------------------------------------------------------
2003 Ukot-2 3.5 km south of encountered three oil-bearing intervals
discovery
- -------------------------------------------------------------------------------------------------------------------------------
2003 Usan-4 5 km south of flowed at restricted rate of 4,400 bbls/d from first interval and 6,300 bbls/d
discovery from second interval
- -------------------------------------------------------------------------------------------------------------------------------
2004 Usan-5 6 km west of sampled oil in several intervals
discovery
- -------------------------------------------------------------------------------------------------------------------------------
2004 Usan-6 4 km south of Usan-5 flowed at restricted rate of 5,800 bbls/d from one interval
- -------------------------------------------------------------------------------------------------------------------------------
9 km southwest of
2005 Usan-7 discovery confirmed an eastern extension of the field
- -------------------------------------------------------------------------------------------------------------------------------
2005 Usan-8 3 km southwest of confirmed an eastern extension of the field
discovery
===============================================================================================================================
Appraisal of this field is complete. The Nigerian authorities have
provisionally approved the preliminary Usan field development plan. We expect
the Usan development to be formally sanctioned in 2007, with first production
as early as 2010.
USAN IS EXPECTED TO BE PRODUCING
BY 2011, ADDING ABOUT 30,000 BBLS/D TO OUR PRODUCTION.
The development will include a FPSO with storage capacity of two million
barrels, capable of handling peak production rates of 160,000 bbls/d of oil. In
2007, we plan to invest approximately $140 million to progress development by
completing our cost estimate. We have a 20% interest in this development
program. Proved reserves of 30 mmboe before royalties (25 after royalties)
comprise approximately 3% of Nexen's total proved oil and gas and Syncrude
reserves.
In 2006, we drilled the deep-water Ukot South well. This well was
unsuccessful and the capital costs were expensed.
Block OML-115
We relinquished this block during the year.
Block OML-109--Ejulebe
In 2005, we sold our producing assets and terminated our contractual
interest in this block.
17
EQUATORIAL GUINEA--BLOCK K
We relinquished this block during the year.
OTHER INTERNATIONAL
COLOMBIA
Boqueron Block--Guando
In 2000, we made our first discovery at Guando on our 20% non-operated
Boqueron Block. Boqueron is in the Upper Magdalena Basin of central Colombia,
approximately 45 km southwest of Bogota. Our share of 2006 production averaged
6,300 bbls/d before royalties (5,700 after royalties), about 3% of Nexen's
total production including Syncrude.
Production from Guando is subject to a 5% to 25% royalty depending on
daily production. In 2006, legislation was introduced to reduce the corporate
income tax rate from 38.5% in 2006 to 34% in 2007, and to 33% in 2008 and
future years.
Exploration Blocks
We have interests in three exploration blocks in the Upper Magdalena
Basin. Villarrica was acquired in 2000, El Queso in 2003 and Boqueron Deep in
2003. In 2005, we relinquished the Villarrica Block and acquired the Villarrica
Norte Block under improved fiscal terms. In 2006, we drilled a well on the El
Queso block which we are currently evaluating. We are currently participating
in a well on Boqueron Deep and plan to drill a well on Villarrica Norte later
in 2007. In addition, we are assessing potential drilling opportunities in
other areas of the Upper Magdelena Basin.
NORWAY
As part of our growth strategy in the North Sea, we participated in the
2006 bid round for exploration rights offshore Norway and were awarded
interests in four licenses in early 2007. In 2007, we expect to invest
approximately $30 million in additional seismic and geologic studies there.
AUSTRALIA--BUFFALO
Field abandonment began in November 2004 and was completed in 2005.
RESERVES, PRODUCTION AND RELATED INFORMATION
In addition to the tables below, we refer you to the Supplementary Data in
Item 8 of this Form 10-K for information on our oil and gas producing
activities. Nexen has not filed with nor included in reports to any other
United States federal authority or agency, any estimates of total proved crude
oil or natural gas reserves since the beginning of the last fiscal year.
Oil and Gas Acreage
2006
------------------------------------------------------------------------------------------------------
DEVELOPED UNDEVELOPED (1) TOTAL
(thousands of acres) GROSS NET GROSS NET GROSS NET
- ------------------------------------------------------------------------------------------------------------------------------
Yemen (2) 50 29 756 628 806 657
- ------------------------------------------------------------------------------------------------------------------------------
Canada 781 578 2,081 1,095 2,862 1,673
- ------------------------------------------------------------------------------------------------------------------------------
United States 183 103 1,396 650 1,579 753
- ------------------------------------------------------------------------------------------------------------------------------
United Kingdom 83 27 1,822 1,031 1,905 1,058
- ------------------------------------------------------------------------------------------------------------------------------
Colombia (4) 1 - 604 463 605 463
- ------------------------------------------------------------------------------------------------------------------------------
Nigeria (2), (3) - - 448 90 448 90
- ------------------------------------------------------------------------------------------------------------------------------
TOTAL 1,098 737 7,107 3,957 8,205 4,694
==============================================================================================================================
NOTES:
(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 PRODUCTION SHARING CONTRACTS.
(3) THE ACREAGE IS COVERED BY A JOINT VENTURE AGREEMENT.
(4) THE ACREAGE IS COVERED BY AN ASSOCIATION CONTRACT.
18
Producing Oil and Gas Wells
2006
---------------------------------------------------------------------------------------------------------
OIL GAS TOTAL
(number of wells) GROSS (1) NET (2) GROSS (1) NET (2) GROSS (1) NET (2)
- -------------------------------------------------------------------------------------------------------------------------------
Yemen 428 249 - - 428 249
- -------------------------------------------------------------------------------------------------------------------------------
Canada 2,196 1,519 2,627 2,279 4,823 3,798
- -------------------------------------------------------------------------------------------------------------------------------
United States 191 91 199 138 390 229
- -------------------------------------------------------------------------------------------------------------------------------
United Kingdom 39 17 - - 39 17
- -------------------------------------------------------------------------------------------------------------------------------
Colombia 91 19 - - 91 19
- -------------------------------------------------------------------------------------------------------------------------------
TOTAL 2,945 1,895 2,826 2,417 5,771 4,312
===============================================================================================================================
NOTES:
(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.
Drilling Activity
2006
--------------------------------------------------------------------------------------------------------
NET EXPLORATORY NET DEVELOPMENT TOTAL
(number of net wells) PRODUCTIVE DRY HOLES TOTAL PRODUCTIVE DRY HOLES TOTAL
- -------------------------------------------------------------------------------------------------------------------------------
Yemen 3.0 5.5 8.5 36.0 1.0 37.0 45.5
- -------------------------------------------------------------------------------------------------------------------------------
Canada 35.4 2.2 37.6 214.3 0.7 215.0 252.6
- -------------------------------------------------------------------------------------------------------------------------------
United States 1.6 2.1 3.7 8.3 2.0 10.3 14.0
- -------------------------------------------------------------------------------------------------------------------------------
United Kingdom 0.8 1.7 2.5 5.5 - 5.5 8.0
- -------------------------------------------------------------------------------------------------------------------------------
Colombia - - - 2.0 - 2.0 2.0
- -------------------------------------------------------------------------------------------------------------------------------
Nigeria - 0.2 0.2 - - - 0.2
- -------------------------------------------------------------------------------------------------------------------------------
TOTAL 40.8 11.7 52.5 266.1 3.7 269.8 322.3
===============================================================================================================================
2005
--------------------------------------------------------------------------------------------------------
NET EXPLORATORY NET DEVELOPMENT TOTAL
(number of net wells) PRODUCTIVE DRY HOLES TOTAL PRODUCTIVE DRY HOLES TOTAL
- -------------------------------------------------------------------------------------------------------------------------------
Yemen 0.5 4.6 5.1 33.0 1.6 34.6 39.7
- -------------------------------------------------------------------------------------------------------------------------------
Canada 32.2 8.0 40.2 198.9 0.5 199.4 239.6
- -------------------------------------------------------------------------------------------------------------------------------
United States - 0.6 0.6 7.2 1.0 8.2 8.8
- -------------------------------------------------------------------------------------------------------------------------------
United Kingdom 0.5 2.1 2.6 1.5 - 1.5 4.1
- -------------------------------------------------------------------------------------------------------------------------------
Colombia - - - 1.8 - 1.8 1.8
- -------------------------------------------------------------------------------------------------------------------------------
Nigeria 0.4 0.2 0.6 - - - 0.6
- -------------------------------------------------------------------------------------------------------------------------------
Equatorial Guinea - 0.5 0.5 - - - 0.5
- -------------------------------------------------------------------------------------------------------------------------------
TOTAL 33.6 16.0 49.6 242.4 3.1 245.5 295.1
===============================================================================================================================
2004
--------------------------------------------------------------------------------------------------------
NET EXPLORATORY NET DEVELOPMENT TOTAL
(number of net wells) PRODUCTIVE DRY HOLES TOTAL PRODUCTIVE DRY HOLES TOTAL
- -------------------------------------------------------------------------------------------------------------------------------
Yemen - 2.0 2.0 37.3 0.5 37.8 39.8
- -------------------------------------------------------------------------------------------------------------------------------
Canada 13.4 1.0 14.4 202.9 - 202.9 217.3
- -------------------------------------------------------------------------------------------------------------------------------
United States 0.3 1.8 2.1 11.0 1.0 12.0 14.1
- -------------------------------------------------------------------------------------------------------------------------------
United Kingdom - - - - - - -
- -------------------------------------------------------------------------------------------------------------------------------
Colombia - - - 7.0 - 7.0 7.0
- -------------------------------------------------------------------------------------------------------------------------------
Nigeria 0.4 1.0 1.4 - - - 1.4
- -------------------------------------------------------------------------------------------------------------------------------
Equatorial Guinea - 0.5 0.5 - - - 0.5
- -------------------------------------------------------------------------------------------------------------------------------
TOTAL 14.1 6.3 20.4 258.2 1.5 259.7 280.1
===============================================================================================================================
Wells in Progress
At December 31, 2006, we were drilling 5 wells in Yemen (3.6 net), 5 wells
in Canada (5 net), 2 wells in the United States (1.6 net), 3 wells in the
United Kingdom (1.6 net), and 1 well in Colombia (0.5 net).
19
Net Sales by Product from Continuing Oil and Gas Operations (including Syncrude)
(Cdn$ millions) 2006 2005 2004
- -----------------------------------------------------------------------------------------------------------------
Conventional Crude Oil and Natural Gas Liquids (NGLs) 2,479 2,438 1,697
- -----------------------------------------------------------------------------------------------------------------
Synthetic Crude Oil 446 397 321
- -----------------------------------------------------------------------------------------------------------------
Natural Gas 553 671 534
- -----------------------------------------------------------------------------------------------------------------
TOTAL 3,478 3,506 2,552
=================================================================================================================
Crude oil (including synthetic crude oil) and natural gas liquids represent
approximately 84% of our oil and gas net sales, while natural gas represents the
remaining 16%.
Sales Prices and Production Costs (excluding Syncrude)
AVERAGE SALES PRICE (1) AVERAGE PRODUCTION COST (1)
2006 2005 2004 2006 2005 2004
- ---------------------------------------------------------------------------------------------------------
CRUDE OIL AND NGLS (Cdn$/bbl)
- ---------------------------------------------------------------------------------------------------------
Yemen 71.57 62.07 47.59 8.11 6.75 5.64
- ---------------------------------------------------------------------------------------------------------
Canada (2) 42.79 40.51 36.60 15.50 14.01 11.76
- ---------------------------------------------------------------------------------------------------------
United States 65.80 57.63 46.60 9.45 7.33 6.09
- ---------------------------------------------------------------------------------------------------------
United Kingdom 71.19 60.55 46.81 11.28 14.90 8.26
- ---------------------------------------------------------------------------------------------------------
Australia (2) - - 51.22 - - 35.73
- ---------------------------------------------------------------------------------------------------------
Other Countries 66.09 59.96 43.07 3.13 6.08 4.09
- ---------------------------------------------------------------------------------------------------------
NATURAL GAS (Cdn$/mcf)
- ---------------------------------------------------------------------------------------------------------
Canada (2) 6.49 7.51 5.76 1.65 0.95 0.85
- ---------------------------------------------------------------------------------------------------------
United States 7.86 10.56 7.89 1.58 1.22 1.02
- ---------------------------------------------------------------------------------------------------------
United Kingdom 7.43 7.86 8.28 1.88 2.48 -
=========================================================================================================
NOTES:
(1) SALES PRICES AND UNIT PRODUCTION COSTS ARE CALCULATED USING OUR WORKING
INTEREST PRODUCTION AFTER ROYALTIES.
(2) INCLUDES RESULTS OF DISCONTINUED OPERATIONS FOR 2005 AND 2004. (SEE NOTE
14 TO OUR CONSOLIDATED FINANCIAL STATEMENTS.)
PROVED RESERVES INCLUDING PROVED UNDEVELOPED RESERVES
At December 31, 2006, we had 725 mmboe of proved oil and gas reserves
before royalties (637 after royalties). This is a 55% increase over the prior
year (62% after royalties). Including Syncrude, our total proved oil and gas
and Syncrude reserves increased 34% to 1,049 mmboe (39% to 911 after
royalties).
The following table provides a summary of the changes in our proved oil
and gas reserves (before royalties) excluding our Syncrude reserves. Refer to
page 116 in our 2006 Form 10-K for proved reserves information on an
after-royalties basis.
UNITED UNITED OTHER
(mmboe) CANADA KINGDOM STATES YEMEN COUNTRIES TOTAL
- -----------------------------------------------------------------------------------------------------------------
December 31, 2005 117 145 90 105 11 468
- -----------------------------------------------------------------------------------------------------------------
Extension and Discoveries 11 25 7 4 30 77
- -----------------------------------------------------------------------------------------------------------------
Revisions 249 20 (11) (8) 1 251
- -----------------------------------------------------------------------------------------------------------------
Production (13) (8) (13) (35) (2) (71)
- -----------------------------------------------------------------------------------------------------------------
DECEMBER 31, 2006 364 182 73 66 40 725
=================================================================================================================
20
Extensions and discoveries contributed 77 mmboe (67 after royalties). The
majority of the increase results from new development projects at Usan,
offshore West Africa, the Ettrick and Duart fields in the North Sea, Ringo in
the Gulf of Mexico, and coalbed methane in Canada. Other increases relate to
ongoing exploitation activities in the North Sea, Yemen, the Gulf of Mexico and
Canada.
The revisions relate primarily to our Long Lake project. Under SEC rules,
we are required to recognize bitumen reserves rather than the upgraded
synthetic crude oil that we will produce and sell. As such, proved reserves
recognition depends on year end oil prices, light/heavy differentials, diluent
prices and natural gas prices. We initially recognized proved bitumen reserves
at Long Lake in early 2004 when we sanctioned development of the project. The
reserves were, however, written off at the end of the year due to wide
light/heavy differentials and high natural gas costs. At the end of 2006,
narrow light/heavy differentials and low natural gas costs allowed us to
recognize proved bitumen reserves of 246 mmboe (219 after royalties). In the
North Sea, the additions reflect increases at Buzzard as a result of
development drilling and an increase in the proved recovery factor. In Canada,
the additions relate primarily to our heavy oil properties where narrow
light/heavy differentials increased the amount of economically recoverable
reserves. Negative revisions occurred on Block 51 in Yemen and the Aspen field
in the Gulf of Mexico as a result of lower than expected production
performance.
PROVED UNDEVELOPED RESERVES
The following table provides a summary of our proved undeveloped reserves
(PUDs) for our oil and gas activities at December 31, 2006 and 2005:
BEFORE ROYALTIES % OF AFTER ROYALTIES % OF
(mmboe) PUDS TOTAL PROVED (1) TOTAL PUDS TOTAL PROVED (1) TOTAL
- --------------------------------------------------------------------------------------------------------------
Canada 216 364 59% 188 319 59%
- --------------------------------------------------------------------------------------------------------------
United Kingdom 50 182 27% 50 182 27%
- --------------------------------------------------------------------------------------------------------------
Yemen 9 66 14% 5 38 13%
- --------------------------------------------------------------------------------------------------------------
United States 9 73 12% 7 63 11%
- --------------------------------------------------------------------------------------------------------------
Other Countries 31 40 78% 25 35 71%
- --------------------------------------------------------------------------------------------------------------
DECEMBER 31, 2006 315 725 43% 275 637 43%
==============================================================================================================
Canada 13 117 11% 11 101 11%
- --------------------------------------------------------------------------------------------------------------
United Kingdom 128 145 88% 128 145 88%
- --------------------------------------------------------------------------------------------------------------
Yemen 23 105 22% 13 59 22%
- --------------------------------------------------------------------------------------------------------------
United States 15 90 17% 13 77 17%
- --------------------------------------------------------------------------------------------------------------
Other Countries 1 11 5% - 11 5%
- --------------------------------------------------------------------------------------------------------------
DECEMBER 31, 2005 180 468 38% 165 393 42%
==============================================================================================================
NOTE:
(1) EXCLUDES PROVED RESERVES FOR OUR SYNCRUDE OPERATIONS OF 324 MMBOE (274
AFTER ROYALTIES) IN 2006 AND 318 MMBOE (264 AFTER ROYALTIES) IN 2005.
In 2006, our PUDs increased by 135 mmboe (110 after royalties). We added
206 mmboe (179 after royalties) at Long Lake relating to proved reserves
outside of the initial 81 well-pair SAGD development area. We also added PUDs
from our new development projects at Usan, Ettrick, Ringo, Duart and CBM. We
converted 117 mmboe (112 after royalties) of PUDs to developed, with the
majority relating to the completion of the Buzzard development project. Other
small additions and conversions occurred from ongoing development activities at
Canada, the United States, Yemen, the United Kingdom and Colombia.
In Canada, our PUDs increased from 13 mmboe (11 after royalties) to 216
mmboe (188 after royalties). Substantially all of the increase relates to Long
Lake where we added 206 mmboe (179 after royalties). These PUDs are expected to
be converted to developed over the next 20 years as we drill additional wells
to provide feedstock to run the upgrader at capacity. The remaining PUDs relate
to infill drilling, recompletions or facilities enhancements on our various
heavy oil and natural gas fields. The majority of these PUDs are expected to be
converted to producing reserves in 2007 and 2008. Also, a small portion of the
PUDs relate to our CBM properties, which are expected to be converted to
producing by infill drilling and field development planned for 2007 and 2008.
21
In the United Kingdom, our PUDs decreased from 128 mmboe (128 after
royalties) to 50 mmboe (50 after royalties) primarily from completing the
Buzzard development, which converted 80% of the related PUDs to developed. The
remaining Buzzard PUDs are expected to be converted to proved over the next few
years as we drill additional wells to keep the platform operating at capacity.
PUDs were added by our Ettrick development, which we expect to convert to
producing in 2008.
In Yemen, the PUDs are split relatively equally between our Masila and
East Al Hajr Blocks. These reserves relate entirely to infill drilling, which
we plan to carry-out during 2007 and 2008.
In the United States, our PUDS decreased from ongoing development of our
Gulf of Mexico deep-water and shelf properties. In 2006, additions principally
relate to the Ringo and Tobago developments, which are expected to be producing
within the next two years.
In other countries, our PUDs increased by 30 mmboe (25 after royalties),
resulting from recognizing proved reserves associated with our Usan
development, offshore West Africa.
Excluding Long Lake and Usan, we expect to convert about 80% of our PUDs
to producing in 2007 and 2008. Usan will be converted by 2011 when it is
expected to come on stream. Long Lake PUDs will be converted over the next 20
years as initial SAGD wells deplete. At the same time, we expect our ongoing
exploration and development activities to continue to add new PUDs.
BASIS OF RESERVES ESTIMATES
Reserve estimates in this report are internally prepared. Refer to the
section on Critical Accounting Estimates - Oil and Gas Accounting - Reserves
Determination on page 62 for a description of our reserves process. As
described therein, we have at least 80% of our oil and gas reserve estimates
either evaluated or audited annually by independent qualified reserves
consultants. The nature and scope of the independent evaluations and audits is
determined by agreement between us and the engineering firm. Independent
assessments for other companies may, therefore, be different.
The following provides an overview of the nature and scope of the
independent evaluations and audits that we have performed. An independent
evaluation is a process whereby we request a third-party engineering firm to
prepare an estimate of our 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 auditor reviews our work and
estimate in preparing their estimate whereas an evaluator uses the reservoir
data to prepare their estimate.
In each case, we request their estimate to be prepared using standard
geological and engineering methods generally accepted by the petroleum
industry. Generally accepted methods for estimating reserves include volumetric
calculations, material balance techniques, production and pressure decline
curve analysis, analogy with similar reservoirs, and reservoir simulation. The
method or combination of methods used is based on their professional judgement
and experience. In preparing their estimates, they obtain information from us
with respect to property interests, production from such properties, current
costs of operations, future development and abandonment, current prices for
production, agreements relating to current and future operations and sale of
production, and various other information and data. 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 do 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 evaluator or auditor issues an opinion as to whether our
estimate of the proved reserves for that portfolio of properties is, in
aggregate, reasonable relative to the criteria set forth in SEC Rule 4-10(a)(2)
of Regulation S-X. These rules define proved reserves as the estimated
quantities of oil and gas which geological and engineering data demonstrate
with reasonable certainty to be recoverable in future years from known
reservoirs under existing economic and operating conditions.
Our estimate may differ from the independent evaluators and auditors as
they apply their professional judgement and experience, which may result in
applying different estimating methods or interpreting data differently than us.
We believe our estimate for a portfolio of properties is reasonable when it is,
in aggregate, within 10% of the independent evaluator or auditor.
We engaged DeGolyer and MacNaughton ("D&M") to evaluate 100% of our
reserves before royalties (100% after royalties) for the United Kingdom, Yemen
Masila, Yemen Block 51 and Nigeria. A separate opinion was provided on each of
these four areas. D&M provided an opinion on each of the areas that the proved
reserves estimate prepared by us is, in aggregate, reasonable when compared to
their estimate which was prepared in accordance with SEC Rules.
22
We engaged McDaniel & Associates Consultants Ltd. ("McDaniel") to evaluate
98% of our Canadian conventional, CBM and bitumen reserves before royalties
(98% after royalties) and to audit 100% of our Syncrude mining reserves before
royalties (100% after royalties). The properties were selected by management
and reviewed with the Reserves Review Committee of the Board. All material
properties were selected. McDaniel provided an opinion that the proved reserves
estimate prepared by us is, in aggregate, within 10% of their estimate which
was prepared in accordance with SEC Rules.
We engaged Ryder Scott Company ("Ryder Scott") to audit 82% of our U.S.
Gulf of Mexico shelf reserves before royalties (82% after royalties). The
properties were selected by management and reviewed with the Reserves Review
Committee of the Board. All material properties were selected. Ryder Scott
provided an opinion that the difference between their estimate and ours is
within the range of reasonable differences and that the estimates have been
prepared in accordance with SEC Rules.
We engaged William M. Cobb & Associates, Inc. ("Cobb") to audit 100% of
our U.S. Gulf of Mexico deep-water reserves before royalties (100% after
royalties). Cobb provided an opinion that the difference between their estimate
and ours is within the range of reasonable differences and that the estimates
have been prepared in accordance with SEC Rules.
SYNCRUDE MINING OPERATIONS
We hold a 7.23% participating interest in Syncrude Canada Ltd. (Syncrude).
This joint venture was established in 1975 to mine shallow oil sands deposits
using open-pit mining methods, extract the bitumen from the oil sands, and
upgrade the bitumen to produce a high-quality, light (32(degree) API), sweet,
synthetic crude oil.
The Syncrude operation exploits a portion of the Athabasca oil sands
deposit 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 percent 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 258,000 hectares, 40 km north of Fort McMurray in northeast
Alberta.
Syncrude mines oil sands at three mines: Base, North, and Aurora North.
These locations are readily accessible by public road. 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 270 million tons of oil sands per year and
about 160 mmbbls of bitumen per year. 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 Base Mine uses hot water,
steam, and caustic soda to create a slurry, while at the North Mine and the
Aurora North Mine, the oil sands are mixed with warm water to produce a slurry.
The extracted bitumen is fed into a vacuum distillation tower and three
cokers for primary upgrading. The resulting products are then separated into
naphtha, light gas oil, and heavy gas-oil streams. These streams are
hydrotreated to remove sulphur and nitrogen impurities to form 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 2006, about 40% of the synthetic crude oil was
sold to Edmonton area refineries, and the remaining 60% was sold to refineries
in Eastern Canada and the mid-western United States.
Electricity is provided to Syncrude from two generating plants on site: a
270 MW plant and an 80 MW plant.
23
Since operations started in 1978, Syncrude has shipped more than 1.7
billion barrels of synthetic crude oil to Edmonton, Alberta, by Alberta Oil
Sands Pipeline Ltd. The pipeline was expanded in 2004 to accommodate increased
Syncrude production.
At December 31, 2006, our total investment in the property, plant and
equipment, including surface mining facilities, transportation equipment, and
upgrading facilities, was approximately $1.3 billion. Based on development
plans, our share of future expansion and equipment replacement costs over the
next 35 years is expected to be more than $2.5 billion.
In 1999, the Alberta Energy and Utilities Board (AEUB) extended Syncrude's
operating license for the eight oil sands leases through to 2035. The license
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.
Syncrude pays a royalty to the Province of Alberta. Subsequent to 1987,
this royalty was equal to 50% of Syncrude's deemed net profits after deduction
of capital expenditures. In 1995, the Province of Alberta announced generic
royalty terms for new oil sands projects that provide for a royalty rate of 25%
on net revenues after all costs have been recovered, subject to a minimum 1%
gross royalty. In 1997, the Province of Alberta and the Syncrude owners agreed
to move to the generic royalty terms when the total of all allowed capital
costs incurred after December 31, 1995 equaled $2.8 billion (gross). That total
was surpassed at the end of 2001. In 2006, we realized full recovery of allowed
capital costs and, as a result, Syncrude royalties are assessed at 25% of net
revenues.
In 1999, the AEUB approved an increase in Syncrude's production capacity
to 465,700 bbls/d. At the end of 2001, Syncrude had 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 25
miles 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. Our share of capital spending in 2007 is expected to be
$50 million.
In 2006, Syncrude's production of marketable synthetic crude oil was
258,400 bbls/d. Nexen's share was 18,700 bbls/d before royalties (16,900 after
royalties).
The following table provides some operating statistics for Syncrude
operations:
2006 2005 2004
- ------------------------------------------------------------------------------
TOTAL MINED VOLUME (1)
- ------------------------------------------------------------------------------
Millions of Tons 428 353 389
- ------------------------------------------------------------------------------
Mined Volume to Oil Sands Ratio (1) 2.2 2.1 2.1
- ------------------------------------------------------------------------------
OIL SANDS PROCESSED
- ------------------------------------------------------------------------------
Millions of Tons 192 169 188
- ------------------------------------------------------------------------------
Average Bitumen Grade (weight %) 11.3 11.1 11.1
- ------------------------------------------------------------------------------
BITUMEN IN MINED OIL SANDS
- ------------------------------------------------------------------------------
Millions of Tons 22 19 21
- ------------------------------------------------------------------------------
Average Extraction Recovery (%) 90 89 87
- ------------------------------------------------------------------------------
BITUMEN PRODUCTION (2)
- ------------------------------------------------------------------------------
Millions of Barrels 112 94 103
- ------------------------------------------------------------------------------
Average Upgrading Yield (%) 85 85 86
- ------------------------------------------------------------------------------
GROSS SYNTHETIC CRUDE OIL SHIPPED (3)
- ------------------------------------------------------------------------------
Millions of Barrels 94 78 87
- ------------------------------------------------------------------------------
NEXEN'S SHARE OF MARKETABLE CRUDE OIL
- ------------------------------------------------------------------------------
Millions of Barrels Before Royalties 6.8 5.7 6.3
- ------------------------------------------------------------------------------
Millions of Barrels After Royalties 6.2 5.6 6.1
==============================================================================
NOTES:
(1) INCLUDES PRE-STRIPPING OF MINE AREAS.
(2) BITUMEN PRODUCTION IN BARRELS IS EQUAL TO BITUMEN IN MINED OIL SANDS
MULTIPLIED BY THE AVERAGE EXTRACTION RECOVERY AND THE APPROPRIATE
CONVERSION FACTOR.
(3) APPROXIMATELY 1.2% OF THE PRODUCED SYNTHETIC CRUDE OIL IS USED INTERNALLY,
PRIMARILY FOR DIESEL THAT FUELS THE TRUCKS AND SHOVELS AT SYNCRUDE. THE
REMAINING SYNTHETIC CRUDE OIL IS SOLD EXTERNALLY.
24
ENERGY MARKETING
Our marketing group sells proprietary and third-party natural gas, crude
oil, natural gas liquids, ethanol and power in certain regional global markets.
We have built a solid strategic presence within various North American regional
markets and extended our presence into certain global markets as well. We focus
on securing access to transportation, storage and facilities, as well as
commodities we produce or acquire. We optimize the margin on our base business
by physically and financially trading around our access to these physical
assets. We also trade financially for profit where we see opportunities in the
market. We use financial and derivative contracts, including futures, forwards,
swaps and options for hedging and trading purposes.
Our marketing strategy is to:
o obtain competitive pricing on the sale of our oil and gas
production;
o provide market intelligence in support of our oil and gas
operations;
o provide superior customer service to producers and consumers;
o capitalize on market opportunities through physical and financial
trading; and
o optimize physical assets or contracts to which we have access.
This strategy aligns with our corporate focus on extracting full value
from our assets and provides us with the market intelligence needed to deliver
current and future oil and gas production to market at competitive pricing.
NORTH AMERICAN GAS MARKETING
The marketing and trading of North American natural gas is our marketing
group's largest revenue source. We focus on key regional markets where we have
a strategic presence--solid customer relationships, in-depth understanding of
the market or established physical assets. We capture regional opportunities by
managing supply, transportation and storage assets for producers and end users.
In addition to the fee-for-service income we realize from managing these
assets, we generate further revenue by:
o capitalizing on location spreads (differences in prices between
locations) using our transportation assets;
o capitalizing on time spreads (differences in prices between summer
and winter) using our storage assets; and
o financial trading of location and time spreads.
We have offices in key regions including Calgary, Detroit and Houston. Our
Calgary office provides a variety of services, including supply, storage, and
transportation management as well as netback pool arrangements and other
customer services. Our customers include producers and consumers in western
Canada as well as consumers (including utilities) in eastern Canada, the
north-eastern United States and the US mid-continent. Our Detroit office works
closely with Calgary to provide services to our customers. Our presence in
Houston has established us in the Gulf Coast region where we have our own
production.
We use our access to transportation and storage facilities to optimize
returns for ourselves as well as our customers.
In 2003 and 2004, we grew our asset base by acquiring physical gas
purchase and sales contracts, as well as natural
25
gas transportation capacity, on favourable terms. This gives us access to new
third party gas supply until 2008, pipeline capacity to 2016 and new
relationships that have enabled us to negotiate new gas purchase and sales
contracts. In 2006, we continued to grow our storage and transportation
positions through acquisitions as well as bidding processes. Our position as a
physical marketer at multiple delivery points in key markets gives us the
flexibility to capitalize on time and location spreads. With pipeline capacity,
we can move gas from producing regions to take advantage of price differences.
At the end of 2006, we held 3.3 bcf/d of pipeline capacity, primarily between
western Canada and the eastern US, and we continue to expand our presence into
other markets within North America. We also use storage capacity to store
typically cheaper summer gas in the ground until the winter heating season
arrives. We had access to 50 bcf of natural gas storage facilities at the end
of the year.
WE USE OUR ACCESS TO TRANSPORTATION AND STORAGE FACILITIES
TO OPTIMIZE RETURNS, CAPITALIZING ON LOCATION AND TIME SPREADS.
In addition to transportation and storage assets, we hold financial
contracts that enable us to capture profits around time and location spreads.
The risks we assume on these contracts are based on fundamental analysis and
knowledge of regional markets. The risk is managed proactively by our product
group teams and monitored by our risk group, with regular reporting to
management and the board of directors.
INTERNATIONAL CRUDE OIL MARKETING
Our crude oil business focuses on marketing physical crude oil to end-use
refiners. The crude oil group markets our own production and more than 500,000
bbls/d of third-party field production to refiners from producing regions where
we operate. In addition to physical marketing, we take advantage of quality
differentials and time spreads.
Our North American operations focus on key regions supported by our
offices in Calgary, Houston and Denver. In western Canada, our producer
services group concentrates on the procurement of a diversified supply base,
while our trading team seeks to optimize the mix for sale to refiners.
Traditionally, the Chicago and Denver areas have been key markets for our
western Canadian crude, however, we continue to expand our presence into the US
Gulf Coast. Our deep-water Gulf of Mexico crude oil production has given us the
opportunity to expand our presence in that market through our Houston office.
At the end of 2006, we had access to 1.7 mmbbls of storage and over the course
of the year, moved approximately 705 mbbls per day.
In the last two years, we acquired two North American natural gas liquid
(NGL) and ethanol businesses that focus on buying and selling NGLs as well as
diesel, ethanol and natural gasoline. These businesses acquire and move NGLs
into the US midwest and Gulf Coast from Canada, as well as providing denaturant
for ethanol production and the marketing of finished ethanol in the US. At the
end of 2006, we had access to 550 mbbls of storage and over the course of the
year, moved approximately 25 mbbls per day of product.
Internationally, we focus on the physical marketing of our Yemen crude
oil. In order to meet customer needs, we may occasionally market other regional
crude types. In addition to our own crude, we market production for our
partners and third parties in the Yemen region. By locating our international
crude oil marketing office in Singapore, we are well positioned to serve both
the producing region and the Asian refining market. We established an office in
London, United Kingdom to maximize the value of our North Sea production. With
Buzzard crude on stream in early 2007, we expect to increase our presence in
various global markets, ensuring we maximize the value of this production.
Our crude oil marketing group also holds financial contracts intended to
capture trading profits around time, quality and location spreads. Like gas
marketing, the risks assumed are based on fundamental analysis and proprietary
knowledge of regional markets, and are monitored by our risk group.
NORTH AMERICAN POWER MARKETING
Our power marketing group is responsible for optimizing the use of our 50%
interest in a 100 MW gas-fired, combined-cycle power generation facility at
Balzac, Alberta, as well as our recently completed 70 MW Soderglen wind power
operation in southern Alberta. We also market power to larger commercial,
industrial and municipal clients in Alberta. With the 2005 acquisition of a
commercial/industrial marketing business in Alberta, we became the largest
supplier of power to the commercial and industrial sectors in the province. Our
Balzac facility began operations in 2001 and Soderglen in October 2006. We
expect to increase our power generation capacity with a 170 MW co-generation
facility at Long Lake in 2007. We have a 50% interest in this project.
26
EUROPEAN GAS AND POWER MARKETING
In 2006, we acquired a UK-based European gas and power marketing business
that focuses on UK gas and power as well as German power. In 2007, we expect to
increase our presence in both the UK and continental Europe gas and power
markets.
CHEMICALS
In 2005, we monetized part of our chemicals business through an initial
public offering of the Canexus Income Fund. We have retained a 61.4% interest
in our chemicals business, and we continue to fully consolidate chemicals in
our Consolidated Financial Statements.
Our chemicals business manufactures sodium chlorate and chlor-alkali
products (chlorine, caustic soda and muriatic acid) in Canada and Brazil. This
production is sold in North and South America, with some sodium chlorate
distributed in Asia. Our manufacturing facilities are modern, reliable and
strategically located to capitalize on competitive power costs or
transportation infrastructure to minimize production and delivery costs. This
enables us to have reliable supplies and low costs--key factors for marketing
bleaching chemicals.
Electricity is the most significant operating cost in producing sodium
chlorate and chlor-alkali products, making up over half our cash costs.
Therefore, our current facilities are strategically located to take advantage
of economic power sources. Our second highest cost is transportation. The
proximity of our manufacturing plants to major customers and competitive
freight rates minimize our transportation costs. Labour is also a significant
manufacturing cost. Approximately 50% of our workforce is unionized with
collective agreements in place at all of our unionized plants.
To grow value in our chemicals business, we focus on reducing our costs
while maintaining market share, building a sustainable North American customer
base and capturing new offshore opportunities.
Average Annual Production Capacity
(short tons) 2006 2005 2004
- ------------------------------------------------------------------------------
SODIUM CHLORATE
- ------------------------------------------------------------------------------
North America 446,208 446,208 446,617
- ------------------------------------------------------------------------------
Brazil 68,563 68,563 68,563
- ------------------------------------------------------------------------------
TOTAL 514,771 514,771 515,180
- ------------------------------------------------------------------------------
CHLOR-ALKALI
- ------------------------------------------------------------------------------
North America 356,002 356,002 356,002
- ------------------------------------------------------------------------------
Brazil 109,430 109,430 109,430
- ------------------------------------------------------------------------------
TOTAL 465,432 465,432 465,432
==============================================================================
NORTH AMERICA
The North American pulp and paper industry consumes approximately 95% of
the continent's sodium chlorate production. We market our sodium chlorate
production to numerous pulp and paper mills under multi-year contracts that
contain price and volume adjustment provisions. Approximately 32% of this
production is sold in Canada, 61% in the US, and the rest is marketed offshore.
We are the third-largest manufacturer of sodium chlorate in North America
with four Canadian facilities: Nanaimo, British Columbia; Bruderheim, Alberta;
Brandon, Manitoba; and Beauharnois, Quebec.
27
In October 2004, we completed an expansion of our plant in Brandon,
Manitoba increasing capacity to 260,000 tonnes per year. This expansion
replaced higher-cost capacity idled in 2002 at Taft, Louisiana. Brandon is the
world's largest sodium chlorate facility and has one of the lowest cost
structures in the industry, significantly enhancing our competitive position in
North America. In late 2006, we began another expansion of our plant in Brandon
which is expected to increase capacity by 32,300 tonnes per year, early in
2008.
Our chlor-alkali facility at North Vancouver, British Columbia,
manufactures caustic soda, chlorine and muriatic acid. Almost all of our
caustic soda is consumed by local pulp and paper mills, while our chlorine is
sold to various customers in the polyvinyl chloride, water purification and
petrochemicals industries, primarily in the United States.
BRAZIL
We entered Brazil in 1999 by acquiring a sodium chlorate plant and a
chlor-alkali plant from Aracruz Cellulose S.A. (Aracruz), the leading
manufacturer of pulp in Brazil. The majority of the sodium chlorate production
is sold to Aracruz under a long-term sales agreement that expires in 2024. This
agreement had an initial six-year take-or-pay component that ended in 2005.
Most of the chlorine and about 20% of the sodium chlorate production is sold in
the merchant market under shorter-term contractual arrangements. In 2002, we
completed an expansion at both facilities to meet Aracruz's growing needs. The
majority of our electricity needs are supplied by a long-term supply contract
in Brazil.
GOVERNMENT 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 land tenure, drilling, production practices,
environmental protection, marketing and pricing policies, royalties, various
taxes and levies including income tax, and foreign trade and investment, that
are subject to change from time to time. Current legislation is generally a
matter of public record, and we are unable to predict what additional
legislation or amendments may be proposed that will affect our operations or
when any such proposals, if enacted, might become effective. We participate in
many industry and professional associations and monitor the progress of
proposed legislation and regulatory amendments.
ENVIRONMENTAL REGULATIONS
Our oil and gas, Syncrude and chemical operations are subject to
government laws and regulations designed to protect and regulate the discharge
of materials into the environment in countries where we operate. We believe our
operations comply in all material respects with applicable environmental laws.
To reduce our exposure, we apply industry standards, codes and best practices
to meet or exceed these laws and regulations. Occasionally, we may conduct
activities in countries where environmental regulatory frameworks are in
various stages of evolution. Where regulations are lacking, we observe Canadian
standards where applicable, as well as internationally accepted industry
environmental management practices.
We have an active safety, environment and social responsibility group that
ensures our worldwide operations are conducted in a safe, ethical and socially
responsible manner. We have developed policies for continuing compliance with
environmental laws and regulations in the countries in which we operate.
ENVIRONMENTAL PROVISIONS AND EXPENDITURES
The ultimate financial impact of environmental laws and regulations is not
clearly known and cannot be reasonably estimated as new standards continue to
evolve in the countries in which we operate. We estimate our future
environmental costs based on past experience and current regulations. At
December 31, 2006, $704 million ($1,770 million, undiscounted) has been
provided in our Consolidated Financial Statements for asset retirement
obligations. In 2006, we increased our retirement obligations for future
dismantlement and site restoration by $75 million primarily from the
development of the Buzzard field in the North Sea.
In 2006, our capital expenditures for environmental-related matters,
including environment control facilities, were approximately $44 million. Our
operating expenditures for environmental-related matters were approximately $6
million. In 2007, we estimate these expenditures to be approximately $21
million.
EMPLOYEES
We had 3,687 employees on December 31, 2006, of which 266 were employed
under collective bargaining schemes. Information on our executive officers is
presented in Item 10 of this report.
28
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
The following should be read in conjunction with the Consolidated
Financial Statements included in this report. The Consolidated Financial
Statements have been prepared in accordance with generally accepted accounting
principles (GAAP) in Canada. The impact of significant differences between
Canadian and United States (US) accounting principles on the financial
statements is disclosed in Note 21 to the Consolidated Financial Statements.
The date of this discussion is February 9, 2007.
Unless otherwise noted, tabular amounts are in millions of Canadian
dollars. Our discussion and analysis of our oil and gas activities include our
Syncrude activities since the product produced from Syncrude competes in the
oil and gas market. 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 in tabular format.
Note: Canadian investors should read the Special Note to Canadian
Investors on page 81 in our 2006 Form 10-K, as filed with the Securities and
Exchange Commission on February 26, 2007, which highlights differences between
our reserve estimates and related disclosures that are otherwise required by
Canadian regulatory authorities.
PAGE
----
EXECUTIVE SUMMARY 30
CAPITAL INVESTMENT 31
FINANCIAL RESULTS
Year-to-Year Change in Net Income 35
Oil & Gas and Syncrude
Production 36
Commodity Prices 39
Operating Expenses 42
Depreciation, Depletion, Amortization and Impairment 43
Exploration Expense 45
Oil & Gas and Syncrude Netbacks 47
Energy Marketing 48
Chemicals 51
Corporate Expenses 52
OUTLOOK FOR 2007 55
LIQUIDITY AND CAPITAL RESOURCES 56
CRITICAL ACCOUNTING ESTIMATES 62
NEW ACCOUNTING PRONOUNCEMENTS 65
29
EXECUTIVE SUMMARY
2006 2005 2004
(Cdn$ millions)
- -------------------------------------------------------------------------------------------------------------
Net Income 601 1,140 793
- -------------------------------------------------------------------------------------------------------------
Earnings per Common Share, Basic ($/share) 2.29 4.38 3.08
- -------------------------------------------------------------------------------------------------------------
Cash Flow from Operating Activities 2,374 2,143 1,606
- -------------------------------------------------------------------------------------------------------------
Production before Royalties (mboe/d) (1) 212 242 250
- -------------------------------------------------------------------------------------------------------------
Production after Royalties (mboe/d) 156 173 174
- -------------------------------------------------------------------------------------------------------------
Capital Investment, including Acquisitions 3,408 2,638 4,264
- -------------------------------------------------------------------------------------------------------------
Net Debt (2) 4,730 3,639 4,285
- -------------------------------------------------------------------------------------------------------------
Average Foreign Exchange Rate (Canadian to US dollar) 0.88 0.83 0.77
- -------------------------------------------------------------------------------------------------------------
Proved Oil and Gas Reserves before Royalties (mmboe) (3) 725 468 542
- -------------------------------------------------------------------------------------------------------------
Proved Oil and Gas Reserves after Royalties (mmboe) (3) 637 393 451
- -------------------------------------------------------------------------------------------------------------
Proved Syncrude Reserves before Royalties (mmboe) (3) 324 318 301
- -------------------------------------------------------------------------------------------------------------
Proved Syncrude Reserves after Royalties (mmboe) (3) 274 264 255
=============================================================================================================
NOTES:
(1) PRODUCTION BEFORE ROYALTIES REFLECTS OUR WORKING INTEREST BEFORE ROYALTIES
AND INCLUDES PRODUCTION OF SYNTHETIC CRUDE OIL FROM SYNCRUDE. WE HAVE
PRESENTED OUR WORKING INTEREST BEFORE ROYALTIES AS WE MEASURE OUR
PERFORMANCE ON THIS BASIS CONSISTENT WITH OTHER CANADIAN OIL AND GAS
COMPANIES.
(2) LONG-TERM DEBT AND SHORT-TERM BORROWINGS LESS CASH AND CASH EQUIVALENTS.
(3) INCLUDES DEVELOPED AND UNDEVELOPED PROVED RESERVES AS AT DECEMBER 31.
Strong commodity prices and record results from our energy marketing group
contributed to net income and cash flow from operating activities. WTI reached
new trading highs during the year and our realized oil and gas price was
$62.92/boe, 9% above 2005. The marketing group contributed record results,
generating value from the optimization of storage and transportation capacity,
as well as financially trading price differences caused by location, product
quality and time. At the beginning of the year, the UK government increased the
supplementary tax on oil and gas activities in the North Sea. As a result, we
recorded $277 million of future income tax expense. Our 2006 income also
included $151 million of expense in connection with our Block 51 arbitration.
Last year, our net income included gains of $225 million from the sale of
Canadian oil and gas properties and a gain of $193 million on the sale of a
portion of our interest in our chemicals business.
Our combined oil & gas and Syncrude production was lower than 2005 levels
as we continue to transition from maturing production in Yemen and Canada to
new higher-return production in 2007, primarily in the North Sea and the Gulf
of Mexico. The 2005 sale of Canadian conventional oil and gas assets reduced
our 2006 volumes by 10,700 boe/d before royalties (8,100 boe/d after royalties)
as compared to last year. As expected, our Masila assets continued to mature
and production declined 16,800 boe/d (7,600 boe/d after royalties). Our ongoing
investment in Masila is to maximize the recovery of the remaining reserves
before our licence expires in 2011. With Buzzard on stream in early January
2007, our 2007 net production is expected to grow 50% to average between
230,000 boe/d and 260,000 boe/d, after royalties, and between 275,000 boe/d and
305,000 boe/d, before royalties.
In 2006, our largest annual capital program was focused on our major
development projects at Buzzard and at Long Lake. Development of Buzzard in the
North Sea was completed during the year and the field began producing on
January 7, 2007. Peak production rates of 85,000 boe/d, net to us, are expected
by mid 2007. At Long Lake, we invested over $1 billion on the SAGD component of
the project and on construction of the upgrader. We expect steam injection to
begin at the end of the first quarter of 2007, with upgrader start up scheduled
for late 2007. At its peak, we expect our share of synthetic crude oil from
phase 1 of Long Lake to be 30,000 bbls/d. At Syncrude, the Stage 3 expansion
was brought on stream in 2006, adding 8,000 bbls/d of production capacity. Late
in the year, we completed an additional development well at Aspen in the Gulf
of Mexico, and we expect 2007 Aspen production to average between 15,000 and
20,000 boe/d.
30
Our 2006 exploration program was focused on drilling 20 wells, primarily
in the Gulf of Mexico and the North Sea. We had successful results from
Alaminos Canyon Block 856 (Great White West) and Ringo in the Gulf of Mexico,
and Golden Eagle in the North Sea.
Our net debt increased from 2005 as a result of our investment in capital
projects, primarily at Buzzard and Long Lake. We drew upon our committed term
credit facilities during the year as our capital spending exceeded our cash
flow by approximately $1 billion.
Throughout 2006, the Canadian dollar continued to strengthen relative to
the US dollar. Our sales revenue is denominated in or referenced to US dollars.
As a result, our revenues decline as the US dollar weakens. On the other hand,
our US-dollar capital spending and operating costs are lower when translated to
Canadian dollars. Overall, the weaker US dollar reduced our 2006 cash flow from
operating activities and net income by $223 million and $98 million,
respectively.
During 2006, our proved oil and gas and Syncrude reserves additions
replaced more than 400% of our oil and gas and Syncrude production (500% after
royalties) as shown in the following table:
BEFORE AFTER
(mmboe) ROYALTIES ROYALTIES
- -------------------------------------------------------------------------------
PRODUCTION
- -------------------------------------------------------------------------------
Oil and Gas 71 51
- -------------------------------------------------------------------------------
Syncrude 7 6
- -------------------------------------------------------------------------------
TOTAL 78 57
- -------------------------------------------------------------------------------
EXTENSIONS, DISCOVERIES AND REVISIONS
- -------------------------------------------------------------------------------
Oil and Gas 328 295
- -------------------------------------------------------------------------------
Syncrude 13 16
- -------------------------------------------------------------------------------
TOTAL 341 311
===============================================================================
The majority of our 2006 additions came from our development projects at
Long Lake in the Athabasca oil sands, Ettrick in the North Sea and Usan,
offshore West Africa. We included 246 mmboe of bitumen (219 after royalties) at
Long Lake as a result of strong year-end bitumen prices and lower natural gas
costs. The Ettrick development was sanctioned during the year, contributing 18
mmboe of proved reserves (18 after royalties). At Usan, offshore West Africa,
we added 30 mmboe of proved reserves (25 after royalties). Reserves were also
added from ongoing activities in Canada, the Gulf of Mexico and the North Sea.
CAPITAL INVESTMENT
(Cdn$ millions) ESTIMATED 2007 2006 2005
- -------------------------------------------------------------------------------
Major Development 1,000 1,849 1,550
- -------------------------------------------------------------------------------
Early Stage Development 400 123 54
- -------------------------------------------------------------------------------
New Growth Exploration 700 491 456
- -------------------------------------------------------------------------------
Core Asset Development 700 748 524
- -------------------------------------------------------------------------------
Total Oil & Gas and Syncrude 2,800 3,211 2,584
- -------------------------------------------------------------------------------
Marketing, Corporate, Chemicals and Other 100 197 54
- -------------------------------------------------------------------------------
TOTAL CAPITAL 2,900 3,408 2,638
===============================================================================
31
Our strategy and capital programs are focused on growing long-term value
for our shareholders. To maximize value, we invest in:
o core assets for short-term production and free cash flow to fund
capital programs and repay debt;
o development projects that convert our discoveries into new
production and cash flow; and
o exploration projects for longer-term growth.
As conventional basins in North America mature, we have been transitioning
our operations toward less mature basins and unconventional resources. Our key
focus areas include the North Sea, Athabasca oil sands, Canadian coalbed
methane, Gulf of Mexico, offshore West Africa and the Middle East--areas we
believe have attractive fiscal terms and significant remaining opportunity, and
where we have some competitive advantage.
In 2006, we invested more than $3.4 billion in capital expenditures,
mostly in multi-year development projects and long cycle-time exploration. In
2007, we plan to invest $2.8 billion in our oil and gas and Syncrude assets.
About 34% of this is focused on multi-year development projects, 28% on core
assets to sustain production and provide cash flow, and 24% on drilling
high-impact exploration wells and building our acreage position. The rest will
be spent on early stage development activities.
2006 INVESTMENT PROGRAM
MAJOR EARLY STAGE NEW GROWTH CORE ASSET
(Cdn$ millions) DEVELOPMENT DEVELOPMENT EXPLORATION DEVELOPMENT TOTAL
- ------------------------------------------------------------------------------------------------------------------------
Oil and Gas
- ------------------------------------------------------------------------------------------------------------------------
Synthetic (mainly Long Lake) 1,050 74 45 - 1,169
- ------------------------------------------------------------------------------------------------------------------------
United Kingdom 552 14 62 31 659
- ------------------------------------------------------------------------------------------------------------------------
Yemen - - 37 145 182
- ------------------------------------------------------------------------------------------------------------------------
United States 31 - 177 387 595
- ------------------------------------------------------------------------------------------------------------------------
Canada 167 15 118 140 440
- ------------------------------------------------------------------------------------------------------------------------
Other Countries - 20 52 8 80
- ------------------------------------------------------------------------------------------------------------------------
Syncrude 49 - - 37 86
- ------------------------------------------------------------------------------------------------------------------------
1,849 123 491 748 3,211
- ------------------------------------------------------------------------------------------------------------------------
Marketing, Corporate and Other - - - 197 197
- ------------------------------------------------------------------------------------------------------------------------
TOTAL CAPITAL 1,849 123 491 945 3,408
- ------------------------------------------------------------------------------------------------------------------------
As a % of Total Capital 54% 4% 14% 28% 100%
========================================================================================================================
2007 ESTIMATED CAPITAL
MAJOR EARLY STAGE NEW GROWTH CORE ASSET
(Cdn$ millions) DEVELOPMENT DEVELOPMENT EXPLORATION DEVELOPMENT TOTAL
- ------------------------------------------------------------------------------------------------------------------------
Oil and Gas
- ------------------------------------------------------------------------------------------------------------------------
Synthetic (mainly Long Lake) 500 170 - - 670
- ------------------------------------------------------------------------------------------------------------------------
United Kingdom 300 - 125 200 625
- ------------------------------------------------------------------------------------------------------------------------
Yemen - - 50 100 150
- ------------------------------------------------------------------------------------------------------------------------
United States - 60 325 200 585
- ------------------------------------------------------------------------------------------------------------------------
Canada 200 - 50 150 400
- ------------------------------------------------------------------------------------------------------------------------
Other Countries - 170 150 - 320
- ------------------------------------------------------------------------------------------------------------------------
Syncrude - - - 50 50
- ------------------------------------------------------------------------------------------------------------------------
1,000 400 700 700 2,800
- ------------------------------------------------------------------------------------------------------------------------
Marketing, Corporate and Other - - - 100 100
- ------------------------------------------------------------------------------------------------------------------------
TOTAL CAPITAL 1,000 400 700 800 2,900
- ------------------------------------------------------------------------------------------------------------------------
As a % of Total Capital 34% 14% 24% 28% 100%
========================================================================================================================
32
MAJOR AND EARLY STAGE DEVELOPMENT PROJECTS
Approximately 58% of our 2006 capital was directed towards early stage and
major development projects including Buzzard, Long Lake, Syncrude Stage 3 and
CBM.
SYNTHETIC
In 2006, we invested approximately $1.2 billion to develop our insitu oil
sands resource. This included approximately $1.1 billion invested at our first
phase of Long Lake. The SAGD facilities are in the final stages of
commissioning and start up and we expect steam injection to commence at the end
of the first quarter of 2007, with bitumen production rates ramping up to peak
rates over a 12 to 24 month period. Upgrader module fabrication is largely
complete and over 95% of the modules are on site. Construction of the upgrader
is approximately 80% complete and start up is scheduled for late 2007.
Production capacity for the first phase of Long Lake is approximately 60,000
bbls/d (30,000 bbls/d net to us) of premium synthetic crude which we expect to
reach by late 2008 or early 2009.
WE HAVE A NUMBER OF MAJOR DEVELOPMENT
PROJECTS AT VARIOUS STAGES OF COMPLETION.
We are planning to increase synthetic crude oil production to 240,000
bbls/d (120,000 bbl/s net to us) over the next decade. We plan to sequentially
develop our oil sands leases with additional 60,000 bbls/d (30,000 bbls/d net
to us) phases using the same technology and design as Long Lake phase 1. We are
currently progressing phase 2 development. We have completed seismic and core
hole drilling programs and we have ordered several major vessels.
UNITED KINGDOM
At Buzzard, we installed the utilities and production topsides, drilled
the initial development wells and completed hook-ups and project commissioning.
Buzzard came on stream in early January 2007 and production is ramping up. The
facilities have the capacity to process up to 200,000 bbls/d of oil and 60
mmcf/d of gas, including the removal of hydrogen sulphide. Based upon recent
drilling results, we have experienced more well-to-well variability in the
concentration of hydrogen sulphide than previously seen. We expect existing
equipment and processes will allow us to manage this variability for at least
the first two or three years of production. As we continue to produce and
acquire reservoir information, we will determine whether additional equipment
will ultimately be required. We have a 43.2% interest in Buzzard and operate
the project.
Elsewhere in the North Sea, we are progressing the development of the
Ettrick field. Production at Ettrick is expected to commence in the first half
of 2008, with our share reaching approximately 16,000 boe/d. Development is
approximately 30% complete and includes drilling three production wells tied
back to a floating production, storage and off-loading vessel. We have an 80%
interest in Ettrick.
CANADA
In Canada, we are developing the first commercial CBM project from
Mannville coals in the Fort Assiniboine area of Alberta. In 2006, we invested
$237 million in exploration and development activities on our CBM lands, of
which $181 million was associated with development. We plan to increase our CBM
production to at least 150 mmcf/d by 2011.
During the year, we acquired over 100 sections of land in an emerging
shale gas play in western Canada. We plan to initiate a drilling and evaluation
program in 2007 to demonstrate the feasibility of this opportunity.
33
OTHER COUNTRIES
On Block OPL-222, offshore West Africa, Nigerian authorities have
provisionally approved the Usan Field Development Plan. Basic engineering of
the facilities is complete and tendering of contracts for all major components
is proceeding. The development plan includes a floating production, storage and
off-loading vessel with storage capacity of two million barrels, capable of
handling peak production rates of 160,000 bbls/d of oil. We expect the Usan
development to be formally sanctioned in 2007, with first production as early
as 2010. We have a 20% interest in the exploration and development of this
block.
SYNCRUDE
At Syncrude, we completed the Stage 3 expansion during the year. Start up
was initially delayed by the emission of odours from the flue gas desulphurizer
plant but modifications to eliminate the odours were completed and the
expansion started up in late August. The Stage 3 expansion increases our
production capacity by 8,000 bbls/d.
NEW GROWTH EXPLORATION
We invested approximately 14% of our 2006 capital in new growth
exploration, including seismic data acquisition. We had exploration success in
the Gulf of Mexico at Alaminos Canyon Block 856 (Great White West) and Ringo,
and at Golden Eagle in the UK North Sea.
At Alaminos Canyon 856, we are evaluating development options following a
two-well exploration drilling program earlier in the year. This block is
located approximately 240 miles south of Houston and is immediately west of the
Great White discovery. We have a 30% interest in this discovery.
At Ringo, we are evaluating a sub-sea tie-back to nearby facilities, which
could be on stream in late 2008. We have a 50% interest in this discovery.
We recently completed drilling operations at our Golden Eagle prospect in
the UK North Sea. The discovery well was drilled to a depth of approximately
7,500 feet and encountered hydrocarbons. A successful sidetrack well was
drilled to appraise the accumulation and we are currently evaluating
development options. We have a 34% operated interest in Golden Eagle.
OUR EXPLORATION PROGRAM CONTINUES
TO DELIVER RESULTS WITH NEW FINDS IN
THE GULF OF MEXICO AND NORTH SEA.
In 2006, we participated in the Norwegian exploration bid round and were
recently awarded four licenses. The licenses are in water depths from 1,000 to
1,300 feet and are located between 30 and 100 miles offshore Norway, situated
close to existing infrastructure. In 2007, we plan to invest in additional
seismic and geological studies in this region.
CORE ASSET DEVELOPMENT
We direct our capital investment in our maturing assets to extract maximum
value over the remaining life of the assets. In the Gulf of Mexico, we began
producing from an additional development well at Aspen in late December. Based
on results from this well, we see further opportunities in the Aspen field and
are currently sidetracking one of our existing Aspen wells to exploit deeper
sands. We have a 100% interest in Aspen.
During the year, we commenced power production from our Soderglen 70
megawatt wind farm in southern Alberta. The wind farm comprises 47 wind towers,
each with a 1.5 megawatt turbine. We have a 50% interest in this project.
34
FINANCIAL RESULTS
YEAR-TO-YEAR CHANGE IN NET INCOME
(Cdn$ millions) 2006 VS 2005 2005 VS 2004
- -------------------------------------------------------------------------------------------------------
NET INCOME FOR 2005 AND 2004 (1) 1,140 793
- -------------------------------------------------------------------------------------------------------
Favourable (unfavourable) variances: (2)
- -------------------------------------------------------------------------------------------------------
Production Volumes, After Royalties
- -------------------------------------------------------------------------------------------------------
Crude Oil (245) 39
- -------------------------------------------------------------------------------------------------------
Natural Gas (55) (55)
- -------------------------------------------------------------------------------------------------------
Change in Crude Oil Inventory (74) 4
- -------------------------------------------------------------------------------------------------------
Total Volume Variance (374) (12)
- -------------------------------------------------------------------------------------------------------
Realized Commodity Prices
- -------------------------------------------------------------------------------------------------------
Crude Oil 325 648
- -------------------------------------------------------------------------------------------------------
Natural Gas (133) 165
- -------------------------------------------------------------------------------------------------------
Total Price Variance 192 813
- -------------------------------------------------------------------------------------------------------
Oil and Gas Operating Expense
- -------------------------------------------------------------------------------------------------------
Conventional 13 (64)
- -------------------------------------------------------------------------------------------------------
Syncrude (35) (27)
- -------------------------------------------------------------------------------------------------------
Total Operating Expense Variance (22) (91)
- -------------------------------------------------------------------------------------------------------
Depreciation, Depletion, Amortization and Impairment
- -------------------------------------------------------------------------------------------------------
Oil & Gas and Syncrude (48) (308)
- -------------------------------------------------------------------------------------------------------
Other 4 (19)
- -------------------------------------------------------------------------------------------------------
Total Depreciation, Depletion, Amortization and Impairment
Impairment Variance (44) (327)
- -------------------------------------------------------------------------------------------------------
Exploration Expense (111) (5)
- -------------------------------------------------------------------------------------------------------
Energy Marketing Contribution 336 49
- -------------------------------------------------------------------------------------------------------
Chemicals Contribution (12) 31
- -------------------------------------------------------------------------------------------------------
General and Administrative Expense 254 (510)
- -------------------------------------------------------------------------------------------------------
Interest Expense 44 46
- -------------------------------------------------------------------------------------------------------
Current Income Taxes (29) (91)
- -------------------------------------------------------------------------------------------------------
Future Income Taxes (549) 353
- -------------------------------------------------------------------------------------------------------
Other
- -------------------------------------------------------------------------------------------------------
Block 51 Arbitration (151) -
- -------------------------------------------------------------------------------------------------------
Business Interruption Insurance Proceeds 152 (8)
- -------------------------------------------------------------------------------------------------------
Gains from Divestiture Programs (418) 418
- -------------------------------------------------------------------------------------------------------
Increase (Decrease) in Fair Value of Crude Oil Put Options 185 (252)
- -------------------------------------------------------------------------------------------------------
Other 8 (67)
- -------------------------------------------------------------------------------------------------------
NET INCOME FOR 2006 AND 2005 (1) 601 1,140
=======================================================================================================
NOTES:
(1) 2005 AND 2004 INCLUDES RESULTS OF DISCONTINUED OPERATIONS (SEE NOTE 14 TO
OUR CONSOLIDATED FINANCIAL STATEMENTS).
(2) ALL AMOUNTS ARE PRESENTED BEFORE PROVISION FOR INCOME TAXES.
Significant variances in net income are explained in the sections that follow.
35
OIL & GAS AND SYNCRUDE
PRODUCTION
2006 2005 2004
BEFORE AFTER BEFORE AFTER BEFORE AFTER
ROYALTIES (1) ROYALTIES ROAYLTIES (1) ROYALTIES ROYALTIES (1) ROYALTIES
- -------------------------------------------------------------------------------------------------------------------------------
OIL AND LIQUIDS (mbbls/d)
- -------------------------------------------------------------------------------------------------------------------------------
Yemen 92.9 51.8 112.7 60.6 107.3 53.5
- -------------------------------------------------------------------------------------------------------------------------------
Canada (2) 20.0 15.8 29.2 22.6 36.2 28.2
- -------------------------------------------------------------------------------------------------------------------------------
United States 17.0 15.0 22.2 19.6 30.0 26.5
- -------------------------------------------------------------------------------------------------------------------------------
United Kingdom 16.9 16.9 12.6 12.6 1.5 1.5
- -------------------------------------------------------------------------------------------------------------------------------
Australia (3) - - - - 2.7 2.5
- -------------------------------------------------------------------------------------------------------------------------------
Other Countries 6.3 5.7 5.6 5.1 5.3 4.7
- -------------------------------------------------------------------------------------------------------------------------------
Syncrude (mbbls/d) (4) 18.7 16.9 15.5 15.3 17.2 16.6
- -------------------------------------------------------------------------------------------------------------------------------
171.8 122.1 197.8 135.8 200.2 133.5
NATURAL GAS (mmcf/d)
- -------------------------------------------------------------------------------------------------------------------------------
Canada (2) 108 91 124 101 146 115
- -------------------------------------------------------------------------------------------------------------------------------
United States 111 94 116 99 148 126
- -------------------------------------------------------------------------------------------------------------------------------
United Kingdom 20 20 23 23 3 3
- -------------------------------------------------------------------------------------------------------------------------------
239 205 263 223 297 244
- -------------------------------------------------------------------------------------------------------------------------------
TOTAL (mboe/d) 212 156 242 173 250 174
===============================================================================================================================
NOTES:
(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 THE FOLLOWING PRODUCTION FROM DISCONTINUED OPERATIONS. SEE NOTE
14 TO OUR CONSOLIDATED FINANCIAL STATEMENTS.
2006 2005 2004
-------------------------------------------------------
Before Royalties
-------------------------------------------------------
Oil and Liquids (mbbls/d) - 6.7 11.7
-------------------------------------------------------
Natural Gas (mmcf/d) - 24 47
-------------------------------------------------------
After Royalties -
-------------------------------------------------------
Oil and Liquids (mbbls/d) - 5.3 9.0
-------------------------------------------------------
Natural Gas (mmcf/d) - 17 33
========================================================
(3) COMPRISES PRODUCTION FROM DISCONTINUED OPERATIONS. SEE NOTE 14 TO OUR
CONSOLIDATED FINANCIAL STATEMENTS.
(4) CONSIDERED A MINING OPERATION FOR US REPORTING PURPOSES.
2006 VS 2005--LOWER PRODUCTION DECREASED NET INCOME BY $374 MILLION
Production before royalties decreased 12% from 2005, while production
after royalties decreased 10%. Our 2006 production excludes volumes from our
Canadian oil and gas properties that were sold in the third quarter of 2005.
Removing the impact of these property dispositions, production before and after
royalties declined 8% and 5%, respectively.
The following table summarizes our production changes year over year:
BEFORE AFTER
(mboe/d) ROYALTIES ROYALTIES
- -----------------------------------------------------------------------------
2005 Production 242 173
- -----------------------------------------------------------------------------
Canada--Disposition of Properties (11) (8)
- -----------------------------------------------------------------------------
231 165
- -----------------------------------------------------------------------------
Production changes
- -----------------------------------------------------------------------------
Yemen (20) (9)
- -----------------------------------------------------------------------------
Canada (1) (1)
- -----------------------------------------------------------------------------
United States (6) (5)
- -----------------------------------------------------------------------------
United Kingdom 4 4
- -----------------------------------------------------------------------------
Colombia 1 1
- -----------------------------------------------------------------------------
Syncrude 3 1
- -----------------------------------------------------------------------------
2006 PRODUCTION 212 156
=============================================================================
36
In 2007, we expect to grow our annual production rate after royalties
approximately 50% compared to 2006 to between 230,000 and 260,000 boe/d after
royalties (275,000 and 305,000 boe/d before royalties). Increases are expected
to come from Buzzard in the North Sea (which commenced production January 7,
2007), from the Gulf of Mexico and a full year of production from the Stage 3
expansion at Syncrude. Also, steam injection at Long Lake is expected to begin
at the end of the first quarter in 2007, with bitumen production ramping up
until the upgrader is scheduled to commence synthetic crude oil production late
in 2007. Anticipated field declines in Yemen will partially offset these
expected increases.
OUR PRODUCTION AFTER ROYALTIES IS EXPECTED TO GROW
APPROXIMATELY 50% IN 2007, WITH INCREMENTAL VOLUMES FROM
BUZZARD, THE GULF OF MEXICO, SYNCRUDE STAGE 3 AND LONG LAKE.
Production volumes discussed in this section represent our working
interest before royalties.
YEMEN
Yemen production decreased 18% from 2005. Production from Masila decreased
19% reflecting the maturity of the field and the impact of a reduced
development drilling program. In 2006, we drilled 28 development wells, eight
fewer than in 2005. Strong initial rates from new wells, combined with well
optimizations, helped to minimize expected production declines. Base declines
at Masila are expected to continue as we maximize recovery of the remaining
reserves on the block prior to expiry of our license in 2011. We plan to drill
14 development wells and continue our well optimization program in 2007.
On Block 51, production from the East Al Hajr field declined 12%. In the
first quarter of 2006, we commissioned the permanent central processing
facilities on the block. Lower than expected initial rates on new wells and
higher than anticipated decline rates contributed to the decrease from 2005.
During the year, we drilled 24 development wells and nine development wells are
planned for 2007.
We expect our share of total production from Yemen to average between
60,000 and 75,000 bbls/d in 2007.
CANADA
Production in Canada decreased 24% from the previous year, primarily as a
result of the sale of conventional oil and gas properties in Alberta, British
Columbia and Saskatchewan. Removing the effect of the dispositions, production
decreased 3% from 2005. Natural field declines of 7,600 boe/d were offset by
capital investment in our heavy oil and natural gas assets, contributing 5,500
boe/d in new production. Gas production is increasing at our coalbed methane
projects in Alberta as existing wells continue to de-water and we bring more
wells on stream. In 2007, we expect to drill 165 infill wells, continue
optimization activities on our conventional assets and work on developing new
technologies to increase recoveries on our heavy oil properties.
We expect 2007 production to average between 45,000 and 50,000 boe/d in
Canada with the commencement of production of premium synthetic crude oil at
Long Lake and additional coalbed methane volumes.
UNITED STATES
Gulf of Mexico production declined 14%, or about 6,000 boe/d from 2005.
Lower production from Aspen due to natural declines contributed approximately
5,400 boe/d of the decrease. An additional Aspen development well was brought
on stream in December 2006. This well was expected to come on stream earlier in
the year but damage to the drilling rig from a work-boat accident delayed
completion of the well. We are currently side-tracking one of the wells and
expect it to be on stream by mid 2007. In 2007, we expect production from the
Aspen field to average between 15,000 and 20,000 boe/d. Gunnison production
remained strong, accounting for 30% of our production from the Gulf of Mexico.
Development of the Dawson Deep discovery was completed and tied-back to our
Gunnison SPAR in July. The Wrigley development was delayed by the tight rig
market in the Gulf, but completion is progressing and the development is
expected to come on stream in the first half of 2007, with production rates
anticipated of 3,200 boe/d.
37
The effects of Hurricanes Katrina and Rita continued to be felt in 2006 as
we slowly restored production from fields shut-in due to damage received in
2005. Production from Vermilion 321 was restored in September 2006. At year
end, Vermilion 340 remains shut-in from damage to the sub-surface pipeline
system. This production was restored in early 2007 (400 boe/d).
During the year, we received $80 million of business interruption
insurance proceeds related to the 2005 hurricanes.
In 2007, we expect production to average between 45,000 and 55,000 boe/d
in the Gulf of Mexico.
UNITED KINGDOM
Production in the UK increased 23%, or 3,800 boe/d from 2005, primarily as
a result of less downtime on the Scott platform and new production from our
non-operated Farragon field. In 2005, our production was reduced by two
generator failures on the Scott platform. During 2006, we received $74 million
in business interruption proceeds related to these failures. Our 2006
production was lower than we expected as planned maintenance work on the Scott
platform flare tip took longer than anticipated and operating capacity was
reduced by maintenance activities on the SAGE export pipeline.
WITH BUZZARD ON STREAM, WE EXPECT UK PRODUCTION
TO AVERAGE BETWEEN 90,000 AND 100,000 BOE/D IN 2007.
Final commissioning of the facilities at Buzzard was delayed by inclement
weather in the North Sea late in the year. Buzzard began production on January
7, 2007. The delay has no impact on our ramp-up plans and peak production of
85,000 boe/d is expected to be achieved in the second quarter of 2007.
In 2007, we plan to drill and complete eight production and three
injection wells at Buzzard and three development wells in the Scott/Telford
area. We expect our total year production from our North Sea assets to average
between 90,000 and 100,000 boe/d in 2007. This compares to the 19,000 boe/d
these assets produced when we purchased them in late 2004.
OTHER COUNTRIES
Production from the Guando field in Colombia was consistent with 2005. We
maintained production rates from two infill drilling programs, bringing 15
additional wells on stream during the year. We expect to maintain production
rates in Colombia in 2007.
SYNCRUDE
At Syncrude, production increased 21% from 2005, but was lower than
expected. The start-up of the Stage 3 expansion was delayed by emission of
odours from the flue gas desulphurizer plant. Production from the Stage 3
expansion began in early May and was approaching design capacity rates prior to
shutting in as a result of the odours. Modifications to eliminate the problem
were completed during the summer and the facilities were restarted in late
August. Late in the year, a turnaround on coker 8-2 reduced production by
approximately 6,000 bbls/d. The turnaround was completed early in 2007.
Strong realized prices on production have enabled us to fully recover
capital costs at Syncrude including costs associated with the Stage 3
expansion. Consequently, our Syncrude royalty in 2006 increased from a 1% gross
revenue royalty to a 25% net revenue royalty. As a result of the increased
royalty rate, we receive lower net production relative to our working interest
production volumes.
In 2007, we expect our total-year production from Syncrude to average
between 20,000 and 25,000 bbls/d.
2005 VS 2004--LOWER PRODUCTION DECREASED NET INCOME BY $12 MILLION
Production before royalties declined 3% during 2005, while production
after royalties remained consistent with 2004 levels. New royalty-free
production from the UK North Sea partially offset the sale of higher-royalty
production from Canada. We sold Canadian production during 2005 to reduce debt
that financed our acquisition of offshore oil and gas assets in the North Sea.
Production was lower as a result of hurricane activity in the Gulf of Mexico in
the second half of 2005. Removing the impact of the Canadian asset sales and
the lost volumes attributable to Hurricanes Katrina and Rita, our 2005
production before royalties would have increased 3% from 2004.
38
COMMODITY PRICES
2006 2005 2004
- -------------------------------------------------------------------------------
CRUDE OIL
- -------------------------------------------------------------------------------
West Texas Intermediate (WTI) (US$/bbl) 66.22 56.58 41.40
- -------------------------------------------------------------------------------
Differentials (1) (US$/bbl)
- -------------------------------------------------------------------------------
Heavy Oil - LLK 21.79 20.82 13.53
- -------------------------------------------------------------------------------
MARS 7.34 6.59 6.15
- -------------------------------------------------------------------------------
Masila 3.00 5.71 4.84
- -------------------------------------------------------------------------------
Dated Brent 1.08 2.20 -
- -------------------------------------------------------------------------------
Producing Assets (Cdn$/bbl)
- -------------------------------------------------------------------------------
Yemen 71.57 62.07 47.59
- -------------------------------------------------------------------------------
Canada 42.79 40.51 36.60
- -------------------------------------------------------------------------------
United States 65.80 57.63 46.60
- -------------------------------------------------------------------------------
United Kingdom 71.19 60.55 46.81
- -------------------------------------------------------------------------------
Australia - - 51.22
- -------------------------------------------------------------------------------
Other Countries 66.09 59.96 43.07
- -------------------------------------------------------------------------------
Syncrude 72.32 71.00 52.80
- -------------------------------------------------------------------------------
Corporate Average (Cdn$/bbl) 67.50 58.98 45.90
- -------------------------------------------------------------------------------
NATURAL GAS
- -------------------------------------------------------------------------------
New York Mercantile Exchange (US$/mmbtu) 6.99 8.99 6.19
- -------------------------------------------------------------------------------
AECO (Cdn$/mcf) 6.62 8.04 6.44
- -------------------------------------------------------------------------------
Producing Assets (Cdn$/mcf)
- -------------------------------------------------------------------------------
Canada 6.49 7.51 5.76
- -------------------------------------------------------------------------------
United States 7.86 10.56 7.89
- -------------------------------------------------------------------------------
United Kingdom 7.43 7.86 8.28
- -------------------------------------------------------------------------------
Corporate Average (Cdn$/mcf) 7.18 8.89 6.85
- -------------------------------------------------------------------------------
NEXEN'S AVERAGE REALIZED OIL AND GAS
PRICE (Cdn$/boe) 62.92 57.97 44.94
- -------------------------------------------------------------------------------
Average Foreign Exchange Rate-Canadian to
US Dollar 0.8818 0.8253 0.7683
===============================================================================
NOTE:
(1) THESE DIFFERENTIALS ARE A DISCOUNT TO WTI.
2006 VS 2005--HIGHER REALIZED PRICES INCREASED NET INCOME $192 MILLION
Average WTI was 17% higher from the prior year, increasing our average
realized crude oil price 14% to $67.50/bbl. Our realized natural gas price fell
19% from 2005, while NYMEX decreased 22% in the same period. The full impact of
the increase in WTI was not reflected in our higher realized crude oil price as
the Canadian dollar strengthened relative to the US dollar. The impact of the
weaker US dollar was offset by narrower crude oil differentials. The weaker US
dollar reduced net sales by approximately $250 million, and reduced our
realized crude oil and natural gas prices by approximately $4.85/bbl and
$0.50/mcf, respectively as compared to 2005.
39
CRUDE OIL REFERENCE PRICES
Crude oil prices remained strong for most of 2006, with WTI reaching new
highs in July before finishing the year at US$61.05/bbl, roughly where it
began. WTI traded at an average of US$66.22/bbl for the year, with a trading
range of between US$54.86/bbl and US$78.40/bbl, where it peaked on July 14. The
steady decline in crude prices from August to the end of the year was largely
driven by warm weather, above average crude oil inventories, concerns over the
US economy, the perceived reduction of geopolitical tensions in the Middle East
and institution-led sell offs in the crude oil markets.
Weather has become an increasingly significant factor in the pricing of
crude oil. In North America, a mild 2005/2006 winter followed by an uneventful
hurricane season in the Gulf of Mexico and a forecast for a warmer than normal
2006/2007 winter season due to the warming effect of El Nino have put downward
pressure on prices. The resulting reduced demand has helped push crude oil
inventories to levels higher than the five-year average. In addition, concerns
over a slowdown in the US economy due to the weakening of the US housing market
have depressed crude oil prices further.
WTI REACHED RECORD HIGHS DURING 2006,
INCREASING OUR REALIZED CRUDE OIL PRICES.
Geopolitical events were a dominant theme through the first eight months
of the year. Tensions in the Middle East as a result of Iran's uranium
enrichment program, on-going violence in Iraq, fighting between Israel and
Hezbollah militants in Lebanon, supply outages in Nigeria caused by continued
violence and the nationalization of Venezuela's energy industry contributed to
increased prices and greater market volatility. Towards the end of the year,
however, geopolitical tensions have been discounted by the market following an
end to the conflict in Lebanon and doubts the US will move against Iran.
A number of oil and gas producers have put option price protection
programs in place at WTI strike prices ranging from US$45 to US$60/bbl. With
falling crude oil prices, these programs get closer to being "in the money".
This caused a sell-off in the crude oil markets by various institutions that
wrote these options as they attempted to manage their option exposures. This
sell-off contributed to the downward pressure on crude prices.
To mitigate the bearish sentiments for crude oil, OPEC has shown a
commitment to its US$50 - $55/bbl basket price by agreeing to reduce production
by 1.2 million barrels a day from November 1 and by a further 500,000 barrels a
day from February 1, 2007. On the demand side, global oil demand growth remains
moderate and is expected to rise by 1.5 million barrels per day in 2007 to 86
million barrels a day. This growth comes mainly from China and India. We expect
this demand increase and the commitment from OPEC to lower production to
stabilize crude oil prices in the near term.
Since the beginning of 2007, WTI has dropped to a low of US$49.90/bbl, but
has since rebounded to approximately US$59/bbl in early February.
CRUDE OIL DIFFERENTIALS
In Canada, heavy crude oil differentials averaged US$21.79/bbl (33% of
WTI) for the year, compared to $20.82/bbl (37% of WTI) in 2005. Differentials
narrowed in the summer, as demand increased for heavy blends relative to light
blends. This reflected normal seasonal narrowing as we headed into the summer
asphalt season. Typically, heavy crude oil differentials widen going into the
fourth quarter but this year, they maintained their summer levels following the
late-year falloff in WTI. In addition, heavy crude oil differentials are
tighter than usual this winter since OPEC cuts tend to be heavy barrels. This
increases the value of heavy barrels relative to lighter barrels.
40
The US Gulf Coast Mars differential widened, averaging US$7.34/bbl in 2006
as compared to US$6.59/bbl in 2005. This was primarily due to higher WTI
prices, temporary declines in demand due to refinery maintenance schedules and
increased competition from Canadian heavy crude down the Spearhead pipeline
into Cushing, Oklahoma and the Pegasus pipeline into Nederland, Texas. Late in
the year, Mars differentials narrowed in response to falling WTI prices and
OPEC production quota cuts.
The Yemen Masila differential narrowed substantially relative to WTI
during 2006, averaging US$3.00/bbl compared to US$5.71/bbl last year. This
largely reflects the impact of stronger Brent pricing since Masila crude is
priced off Brent, coupled with continued strong Asian demand.
THE BRENT/WTI DIFFERENTIAL STRENGTHENED DURING 2006,
CREATING STRONG CRUDE OIL PRICING FOR OUR NORTH SEA BARRELS.
The Brent/WTI differential strengthened during 2006 averaging US$1.08/bbl
as compared to US$2.20/bbl in 2005, resulting in a solid crude oil price for
our North Sea barrels. The spread between WTI and Brent broke away from
historical norms where WTI usually trades at a premium of US$1.50/bbl to
US$2.00/bbl. Several times during the year, WTI traded at a discount to Brent.
This was caused by weak US demand during a heavier than usual maintenance
season, coupled with high US crude inventory levels as production from the US
Gulf Coast came back on stream following damage caused by Hurricanes Katrina
and Rita in 2005. On-going production outages in Nigeria also helped to push
Brent up relative to the North American WTI benchmark. Near the end of the
year, Brent gained more upside support due to the production quota cut from
OPEC. OPEC cuts have a more immediate impact on Brent relative to WTI given the
shorter transit time of Brent to world markets.
NATURAL GAS REFERENCE PRICES
Natural gas prices averaged US$6.99/mmbtu, 22% below 2005 levels. NYMEX
reached record price and volatility levels in late 2005, driven mainly by the
impact of hurricanes Katrina and Rita and speculation around the 2005/2006
North American winter season. In 2006, the mildest January temperatures on
record were experienced in several key North American natural gas consuming
regions which resulted in a weakening of NYMEX. This created a significant gas
storage overhang. Prices remained soft throughout the year reflecting high
storage levels, an uneventful hurricane season and a mild 2006/2007 winter
prediction due to the warming effect of El Nino. Lack of sustained cold
temperatures heading into 2007 will discourage storage withdrawals, which puts
further downward pressure on prices.
2005 VS 2004--HIGHER REALIZED PRICES ADDED $813 MILLION TO NET INCOME
Crude oil prices remained strong in 2005 reaching new highs and new levels
of volatility. While global demand was moderate and supply levels adequate, the
stability and security of long-term supply remained a concern, along with
tightening refining capacity worldwide.
Natural gas prices reached record highs and experienced increased
volatility. Prices early in the year were propped up by strong oil prices. The
disruptions caused by the hurricanes pushed North American gas prices to new
highs. The volatility did not end with the hurricane activity, but continued
into the winter, as markets speculated on the impact of a cold or mild winter
on tight supply. Prices peaked on December 13, 2005 with NYMEX gas settling at
US$15.38/mmbtu.
The full benefit of higher benchmark prices wasn't reflected in our
realized prices because of the weaker US dollar in 2005. All of our oil sales
and most of our gas sales are denominated in, or referenced to, US dollars. As
a result, the weaker US dollar decreased net sales for the year by
approximately $270 million, and reduced our realized crude oil and natural gas
prices by approximately $4.40/bbl and $0.65/mcf, respectively, compared to
2004.
41
OPERATING EXPENSES
2006 2005 2004
(Cdn$/boe) BEFORE AFTER BEFORE AFTER BEFORE AFTER
ROYALTIES (1) ROYALTIES ROYALTIES (1) ROYALTIES ROAYLTIES (1) ROYALTIES
- -------------------------------------------------------------------------------------------------------------------------------
CONVENTIONAL OIL AND GAS
- -------------------------------------------------------------------------------------------------------------------------------
Yemen 4.45 8.11 3.63 6.75 2.80 5.64
- -------------------------------------------------------------------------------------------------------------------------------
Canada 10.31 12.73 8.21 10.34 7.12 8.98
- -------------------------------------------------------------------------------------------------------------------------------
United States 8.17 9.45 6.35 7.33 5.30 6.12
- -------------------------------------------------------------------------------------------------------------------------------
United Kingdom 11.28 11.28 14.90 14.90 8.26 8.26
- -------------------------------------------------------------------------------------------------------------------------------
Australia - - - - 32.94 35.73
- -------------------------------------------------------------------------------------------------------------------------------
Other Countries 2.87 3.13 5.55 6.08 3.76 4.09
- -------------------------------------------------------------------------------------------------------------------------------
Average Conventional 6.95 9.69 6.03 8.70 5.13 7.59
- -------------------------------------------------------------------------------------------------------------------------------
SYNTHETIC CRUDE OIL
Syncrude 27.53 30.43 26.95 27.22 19.89 20.61
- -------------------------------------------------------------------------------------------------------------------------------
AVERAGE OIL AND GAS 8.77 11.96 7.36 10.34 6.15 8.83
===============================================================================================================================
NOTE:
(1) OPERATING EXPENSES PER BOE ARE OUR TOTAL OIL AND GAS OPERATING COSTS
DIVIDED BY OUR WORKING INTEREST PRODUCTION BEFORE ROYALTIES. WE USE
PRODUCTION BEFORE ROYALTIES TO MONITOR OUR PERFORMANCE CONSISTENT WITH
OTHER CANADIAN OIL AND GAS COMPANIES.
2006 VS 2005--HIGHER OPERATING EXPENSES DECREASED NET INCOME BY $22 MILLION
In Yemen, operating costs on a per-unit basis are increasing as fixed
costs from our central processing facilities, combined with increased water
handling costs, are spread over lower production volumes. At Masila, lower
production and increased service rig activity required to minimize production
declines, combined with the costs associated with the replacement of a single
point mooring system used to load oil onto tankers, increased our corporate
average by $0.20/boe. Block 51 operating costs increased our corporate average
by $0.22/boe, reflecting higher manpower costs, increased water handling costs
at the new facilities, maintenance costs associated with equipment repairs and
power outages, and increased fuel consumption and fuel prices. We expect Yemen
operating costs per barrel to continue to increase as our production declines.
Following the sale of Canadian conventional oil and gas properties in
2005, we have proportionately higher production from our heavy oil properties,
which have higher operating costs compared to the lighter oil production we
sold. Canadian operating costs increased our corporate average by $0.18/boe. We
are focused on increasing recovery rates from our heavy oil properties by
developing new technologies.
Operating costs in the Gulf of Mexico increased from last year due to
industry cost pressures caused by the strong commodity price environment and
the 2005 hurricane season. Lower production volumes and workovers on our shelf
properties at the start of the year increased our corporate average by
$0.39/boe.
With the sale of Canadian production in 2005, barrels from the North Sea
are contributing a higher percentage of our total production. As the North Sea
has higher operating costs than our average cost per barrel, the change in
production mix has increased our corporate average by $0.32/boe. This was
offset by lower operating costs relative to 2005, as operating expenses last
year included repair costs related to turbine failures. This reduced our
corporate average by $0.26/boe. We expect our North Sea operating costs to
decrease on a per-unit basis in 2007, with increased low-operating cost
production expected from Buzzard.
WE EXPECT 2007 OPERATING COSTS TO DECREASE ON A
PER-UNIT BASIS WITH INCREASED LOW-OPERATING COST PRODUCTION FROM BUZZARD.
Syncrude increased our corporate average operating costs by $0.72/boe as a
result of maintenance activities and the turnaround of a coker during the first
quarter of 2006, combined with costs related to start-up of the Stage 3
expansion.
The stronger Canadian dollar decreased our US-dollar denominated operating
costs, reducing our corporate average by $0.38/boe, compared to 2005.
42
2005 VS 2004--HIGHER OPERATING EXPENSES DECREASED NET INCOME BY $91 MILLION
In 2005, higher operating costs reflect the change in our profile as more
of our production came from higher-cost areas such as the North Sea and from
Canadian heavy oil following the Canadian property sales completed that year.
Operating costs were negatively impacted by storm-related costs and maintenance
activities. In addition, high levels of industry activity and higher energy
costs, driven by record commodity prices, increased our operating costs.
Our operations at Masila in Yemen reflect the maturing asset base and have
higher operating costs, mainly from increased service rig activity to minimize
production declines. These higher costs added $0.09/boe to our corporate
average. Block 51 operating costs were higher than Masila, reflecting the use
of temporary production facilities. Higher operating costs from Block 51
increased our corporate average by $0.53/boe.
Industry cost pressures and the sale of conventional production increased
our Canadian unit operating costs in 2005. Although we sold high-cost
production relative to our corporate average, we expect our overall Canadian
operating costs to increase as we have proportionately higher production from
our heavy oil properties. These properties have higher operating costs compared
to the lighter oil production that was sold.
In the Gulf of Mexico, lower volumes of higher-cost barrels at Aspen,
along with $12 million of Aspen-1 intervention costs expensed in 2004,
decreased our corporate average by $0.10/boe. Workovers on our shelf
properties, coupled with lower production and property damage costs not covered
by insurance, increased our corporate average by $0.05/boe from 2004.
Higher-cost North Sea production increased our corporate average unit
costs by $1.14/boe. Our North Sea operating costs were higher than anticipated
as a result of maintenance and repair work caused by generator failures in the
second quarter and major maintenance turnaround and facilities upgrading at the
Scott platform in the third quarter.
Our Australian operations ceased in late 2004 and the exclusion of these
high-cost, late-life barrels reduced our corporate average by $0.57/boe.
US-dollar denominated operating costs were lower when translated to Canadian
dollars as a result of the weak US dollar. Our corporate average was reduced by
$0.30/boe as a result.
Syncrude operating costs per boe were 35% higher than in 2004. Turnaround
and maintenance costs accounted for half of the increase, as we completed major
turnarounds on various upgrading units during the year. In addition, high
levels of industry activity in the oil sands have put upward pressure on costs.
When combined with higher energy costs required in the upgrading process, our
corporate average increased by $0.34/boe.
DEPRECIATION, DEPLETION, AMORTIZATION AND IMPAIRMENT (DD&A)
2006 2005 2004
ROYALTIES ROYALTIES ROYALTIES AFTER BEFORE AFTER
(Cdn$/boe) ROYALTIES (1) ROYALTIES ROYALTIES (1) ROYALTIES ROYALTIES (1) ROYALTIES
- ----------------------------------------------------------------------------------------------------------------------------------
CONVENTIONAL OIL AND GAS
- ----------------------------------------------------------------------------------------------------------------------------------
Yemen 9.67 17.61 8.56 15.93 4.35 8.77
- ----------------------------------------------------------------------------------------------------------------------------------
Canada 11.22 13.84 9.26 11.67 9.02 11.37
- ----------------------------------------------------------------------------------------------------------------------------------
United States (2) 16.28 18.84 15.39 17.77 12.93 14.93
- ----------------------------------------------------------------------------------------------------------------------------------
United Kingdom 30.22 30.22 33.25 33.25 22.44 22.44
- ----------------------------------------------------------------------------------------------------------------------------------
Australia - - - - 5.82 6.31
- ----------------------------------------------------------------------------------------------------------------------------------
Other Countries 4.30 4.69 6.20 6.79 9.90 10.77
- ----------------------------------------------------------------------------------------------------------------------------------
Average Conventional 13.12 18.30 11.78 17.00 7.87 11.64
- ----------------------------------------------------------------------------------------------------------------------------------
SYNTHETIC CRUDE OIL
- ----------------------------------------------------------------------------------------------------------------------------------
Syncrude 4.81 5.32 3.08 3.12 2.75 2.85
- ----------------------------------------------------------------------------------------------------------------------------------
AVERAGE OIL AND GAS 12.38 16.88 11.23 15.77 7.52 10.80
==================================================================================================================================
NOTES:
(1) DD&A PER BOE IS OUR DD&A FOR OIL AND GAS OPERATIONS DIVIDED BY OUR WORKING
INTEREST PRODUCTION BEFORE ROYALTIES. WE USE PRODUCTION BEFORE ROYALTIES
TO MONITOR OUR PERFORMANCE CONSISTENT WITH OTHER CANADIAN OIL AND GAS
COMPANIES.
(2) DD&A PER BOE EXCLUDES THE IMPAIRMENT CHARGE DESCRIBED IN NOTE 6 OF OUR
CONSOLIDATED FINANCIAL STATEMENTS.
43
2006 VS 2005--HIGHER OIL AND GAS DD&A DECREASED NET INCOME BY $48 MILLION
Our 2006 DD&A expense includes $93 million ($1.21/boe) of impairment
expense primarily related to two natural gas producing properties in the Gulf
of Mexico. The impairment was caused by disappointing development programs and
negative year-end reserve revisions. The carrying values of the impaired
properties have been reduced to their estimated fair value. In addition, our
2006 DD&A expense includes $15 million (2005 --$58 million) relating to the
write down of a portion of our purchase price allocation to unproved properties
purchased in the North Sea as a result of unsuccessful exploration activities.
Our 2006 average depletion rate excluding impairment charges is $12.38/boe, 10%
above our 2005 average.
In Yemen, we began depleting the permanent production facilities on Block
51 during the year. Strong crude oil prices allowed us to continue to maximize
the recovery of the costs we paid on behalf of the government. This increased
our corporate average by $0.64/boe.
THE STRONG CANADIAN DOLLAR REDUCED OUR
CORPORATE DD&A RATE BY $0.72/BOE FROM 2005.
The increased Canadian depletion rate reflects the depletion of costs
associated with our coalbed methane projects in central Alberta. Our corporate
average is higher by $0.35/boe as a result. We expect our depletion rate for
our coalbed methane projects to decline as the wells de-water and we are able
to recognize additional reserves. Depletion rates for our deep-water assets in
the Gulf of Mexico increased our average by $0.28/boe primarily as a result of
reserve revisions late in 2005.
Our depletion rate for our North Sea assets is higher than our average,
primarily from the allocation of the purchase price we paid for these assets in
2004. Our corporate average is increasing as the North Sea becomes a larger
proportion of our total production and from lower production in Canada
following the sale of conventional oil and gas assets in 2005. This change
increased our corporate average by $0.42/boe. We expect our corporate average
will continue to increase in 2007 as we begin to deplete Buzzard.
The Stage 3 expansion at Syncrude began producing during the year and we
started depleting these assets in 2006. This increased our corporate average by
$0.23/boe.
The strong Canadian dollar reduced our DD&A expense relative to 2005 as
the depletion of our international and US assets is denominated in US dollars.
This lowered our corporate average by $0.72/boe from last year.
2005 VS 2004--HIGHER OIL AND GAS DD&A DECREASED NET INCOME BY $308 MILLION
Strong production volumes, new production from our North Sea assets and
additional capital cost recovery from Block 51 in Yemen increased our oil and
gas DD&A compared with 2004 levels. We also expensed $58 million related to
unproved North Sea properties as a result of unsuccessful exploration
activities.
Block 51 production in Yemen increased our corporate unit depletion by
$2.21/boe from 2004 as a result of carried interest accounting for the recovery
of Block 51 capital costs. Strong production and higher realized oil prices
have resulted in faster recovery of capital costs we paid on behalf of the
government.
Our Canadian depletion rate per unit has increased slightly compared with
2004. Reserve revisions at the end of 2004 increased our 2005 heavy oil
depletion rate. This increase was somewhat offset when we stopped depleting our
Canadian assets held for sale in the second quarter, but continued to recognize
related production. The disposition of these assets in the third quarter
changed our asset mix and reduced our average annual corporate depletion rate
by $0.23/boe.
Depletion rates in the Gulf of Mexico increased following reserve
revisions in late 2004. Reduced volumes offset the increase in rates with
minimal impact on our overall unit rate.
44
North Sea depletion increased our corporate average by $2.37/boe in 2005.
The depletable carrying costs of our Scott, Telford and Farragon fields include
an allocation of the purchase price we paid for these assets. In addition, our
North Sea depletion includes $58 million relating to a partial write-off of our
purchase price allocation to unproved properties subject to unsuccessful
exploration activities.
The strengthening Canadian dollar offset these increases as the depletion
of our international and US assets is denominated in US dollars. This lowered
our corporate average by $0.70/boe compared with 2004.
EXPLORATION EXPENSE (1)
(Cdn$ millions) 2006 2005 2004
- ------------------------------------------------------------------------------
Seismic 128 53 73
- ------------------------------------------------------------------------------
Unsuccessful Drilling 169 143 125
- ------------------------------------------------------------------------------
Other 65 55 48
- ------------------------------------------------------------------------------
TOTAL EXPLORATION EXPENSE 362 251 246
- ------------------------------------------------------------------------------
New Growth Exploration 491 456 266
- ------------------------------------------------------------------------------
Geological and Geophysical Costs 128 53 73
- ------------------------------------------------------------------------------
TOTAL EXPLORATION EXPENDITURES 619 509 339
- ------------------------------------------------------------------------------
Exploration Expense as a % of Exploration Expenditures 58% 49% 73%
==============================================================================
NOTE:
(1) 2005 AND 2004 INCLUDES EXPLORATION EXPENSE FROM DISCONTINUED OPERATIONS.
SEE NOTE 14 TO OUR CONSOLIDATED FINANCIAL STATEMENTS.
2006 VS 2005--HIGHER EXPLORATION EXPENSE REDUCED NET INCOME BY $111 MILLION
Our 2006 exploration activities were focused on drilling 20 wells, mostly
in the Gulf of Mexico and the North Sea, and acquiring seismic data. We were
successful at Great White West and Ringo in the Gulf of Mexico. In early 2007,
we completed drilling operations at our Golden Eagle prospect on License P928
in the UK North Sea. The discovery well was drilled to a depth of approximately
7,500 feel and encountered hydrocarbons. A successful sidetrack well was
drilled to appraise the accumulation and we are currently evaluating
development options.
Our unsuccessful drilling results were primarily in the Gulf of Mexico,
where we expensed $135 million in dry hole costs. Early in the year, we
expensed $49 million for the Pathfinder well, which found non-commercial
quantities of hydrocarbons, after reaching a total depth of 31,196 feet.
Unsuccessful wells on the shelf in the Gulf of Mexico include West Cameron 135
and 109 ($23 million and $14 million respectively) and Vermilion 65 ($15
million). During the year, we also expensed $29 million of capitalized costs
related to Big Bend as it was determined that development was uneconomic and
the block was relinquished. In the North Sea, dry hole costs included
unsuccessful exploratory wells at Zanzibar ($10 million) and Black Cat ($7
million). Exploration expense also includes costs relating to Ukot South,
offshore Nigeria, which encountered wet sands and was plugged and abandoned,
and costs relating to three unsuccessful wells on Block 51 in Yemen.
45
Our geological and geophysical costs include $128 million of seismic data
acquired during the year of which half relates to the Gulf of Mexico. The
balance was spent on data relating to Canada, Norway, the North Sea, Nigeria
and other international targets.
We continue to focus on large unconventional resource opportunities in
Canada. In 2006, we acquired approximately 100 sections of prospective shale
gas acreage in northeast British Columbia for $50 million, which we intend to
evaluate in 2007.
WE CONTINUE TO GROW OUR UNCONVENTIONAL RESOURCE IN CANADA.
IN 2006, WE ACQUIRED A SIZEABLE SHALE GAS LAND POSITION IN NORTHEAST BC.
In 2007, we plan to invest approximately $700 million to drill up to 19
exploration wells and acquire seismic data and access to new exploratory
acreage. In the Gulf of Mexico we have four deep-water and five shelf-gas
prospects planned, while we anticipate drilling five exploration wells in the
North Sea. We expect to drill three exploration wells on Block 51 in Yemen, one
deep-water exploration well offshore West Africa and one exploration well in
Colombia.
2005 VS 2004--HIGHER EXPLORATION EXPENSE REDUCED NET INCOME BY $5 MILLION
Our 2005 exploration program was active, as we spent more than $500
million on 20 high-potential exploration wells in our key basins. In the Gulf
of Mexico, Knotty Head, drilled to a depth of 34,189 feet, encountered
hydrocarbons in multiple zones.
Our 2005 exploration expense includes costs associated with unsuccessful
wells in the Gulf of Mexico, North Sea, offshore West Africa and Yemen. In the
Gulf of Mexico, we expensed $44 million for the Vrede well. Vrede, a sub-salt
prospect drilled to a total depth of 32,600 feet, encountered non-commercial
quantities of hydrocarbons and was temporarily abandoned. We also wrote off
costs relating to our Castleton dry hole, together with trailing costs related
to the 2004 Crested Butte, Wind River and Fawkes wells. These wells, with the
exception of Wind River, were located in the deep water.
In the North Sea, exploration expense includes costs relating to Black
Horse, Polecat, Bennachie and Saracen. The Black Horse and Polecat wells
encountered hydrocarbons, but insufficient to warrant stand-alone development.
We will continue to evaluate these reservoirs in combination with other
potential development projects that may be sanctioned in the future. Bennachie
was abandoned after encountering no reservoir sands in the target zone. Saracen
was written off earlier in 2005 as an unsuccessful exploratory well.
Internationally, we expensed costs related to four unsuccessful wells on
Block 51 in Yemen and we abandoned our deep-water Efere well in Nigeria, as
well as our K-2 well on Block K in Equatorial Guinea.
46
OIL & GAS AND SYNCRUDE NETBACKS
Netbacks are the cash margins, before general and administrative expenses,
we receive for every equivalent barrel sold. The following table lists the
sales prices, per-unit costs and netbacks for our producing assets, calculated
using our working interest production before and after royalties.
BEFORE ROYALTIES
2006
($/boe) YEMEN CANADA US UK OTHER SYNCRUDE TOTAL
- -----------------------------------------------------------------------------------------------------------------------
Sales 71.57 40.98 56.12 66.81 66.09 72.32 62.92
- -----------------------------------------------------------------------------------------------------------------------
Royalties and Other (32.32) (7.80) (7.53) - (5.51) (6.93) (17.68)
- -----------------------------------------------------------------------------------------------------------------------
Operating Expenses (4.45) (10.31) (8.17) (11.28) (2.87) (27.53) (8.77)
- -----------------------------------------------------------------------------------------------------------------------
In-country Taxes (1) (8.45) - - - - - (3.72)
- -----------------------------------------------------------------------------------------------------------------------
CASH NETBACK 26.35 22.87 40.42 55.53 57.71 37.86 32.75
=======================================================================================================================
2005
($/boe) YEMEN CANADA US UK OTHER SYNCRUDE TOTAL
- -----------------------------------------------------------------------------------------------------------------------
Sales 62.07 42.42 60.26 57.83 59.96 71.00 57.97
- -----------------------------------------------------------------------------------------------------------------------
Royalties and Other (28.71) (8.75) (8.06) - (5.23) (0.71) (16.70)
- -----------------------------------------------------------------------------------------------------------------------
Operating Expenses (3.63) (8.21) (6.35) (14.90) (5.55) (26.95) (7.36)
- -----------------------------------------------------------------------------------------------------------------------
In-country Taxes (1) (7.17) - - - - - (3.34)
- -----------------------------------------------------------------------------------------------------------------------
CASH NETBACK 22.56 25.46 45.85 42.93 49.18 43.34 30.57
=======================================================================================================================
2004
($/boe) AUSTRALIA YEMEN CANADA US UK OTHER SYNCRUDE TOTAL
- -----------------------------------------------------------------------------------------------------------------------
Sales 51.22 47.59 35.76 46.94 47.45 43.07 52.80 44.94
- -----------------------------------------------------------------------------------------------------------------------
Royalties and Other (4.00) (23.98) (7.40) (6.29) - (3.49) (1.84) (13.65)
- -----------------------------------------------------------------------------------------------------------------------
Operating Expenses (32.94) (2.80) (7.12) (5.30) (8.26) (3.76) (19.89) (6.15)
- -----------------------------------------------------------------------------------------------------------------------
In-country Taxes (1) - (5.82) - - - - - (2.48)
- -----------------------------------------------------------------------------------------------------------------------
CASH NETBACK 14.28 14.99 21.24 35.35 39.19 35.82 31.07 22.66
=======================================================================================================================
AFTER ROYALTIES
2006
($/boe) YEMEN CANADA US UK OTHER SYNCRUDE TOTAL
- -----------------------------------------------------------------------------------------------------------------------
Sales 71.57 40.98 56.12 66.81 66.09 72.32 62.92
- -----------------------------------------------------------------------------------------------------------------------
Operating Expenses (8.11) (12.73) (9.45) (11.28) (3.13) (30.43) (11.96)
- -----------------------------------------------------------------------------------------------------------------------
In-country Taxes (1) (15.40) - - - - - (5.07)
- -----------------------------------------------------------------------------------------------------------------------
CASH NETBACK 48.06 28.25 46.67 55.53 62.96 41.89 45.89
- ----------------------------------------------------- --------- --------- ------- -------- ------- ----------- --------
2005
($/boe) YEMEN CANADA US UK OTHER SYNCRUDE TOTAL
- -----------------------------------------------------------------------------------------------------------------------
Sales 62.07 42.42 60.26 57.83 59.96 71.00 57.97
- -----------------------------------------------------------------------------------------------------------------------
Operating Expenses (6.75) (10.34) (7.33) (14.90) (6.08) (27.22) (10.34)
- -----------------------------------------------------------------------------------------------------------------------
In-country Taxes (1) (13.35) - - - - - (4.69)
- -----------------------------------------------------------------------------------------------------------------------
CASH NETBACK 41.97 32.08 52.93 42.93 53.88 43.78 42.94
=======================================================================================================================
2004
($/boe) AUSTRALIA YEMEN CANADA US UK OTHER SYNCRUDE TOTAL
- -----------------------------------------------------------------------------------------------------------------------
Sales 51.22 47.59 35.76 46.94 47.45 43.07 52.80 44.94
- -----------------------------------------------------------------------------------------------------------------------
Operating Expenses (35.73) (5.64) (8.98) (6.12) (8.26) (4.09) (20.61) (8.83)
- -----------------------------------------------------------------------------------------------------------------------
In-country Taxes (1) - (11.72) - - - - - (3.57)
- -----------------------------------------------------------------------------------------------------------------------
CASH NETBACK 15.49 30.23 26.78 40.82 39.19 38.98 32.19 32.54
=======================================================================================================================
NOTE:
(1) COMPRISES INCOME TAXES PAYABLE IN YEMEN THAT ARE INCLUDED IN THE
GOVERNMENT'S SHARE OF PROFIT OIL.
47
ENERGY MARKETING
(Cdn$ millions) 2006 2005 2004
- --------------------------------------------------------------------------------------------
Physical Sales (1) 40,920 37,873 28,554
- --------------------------------------------------------------------------------------------
Physical Purchases (1) (39,925) (36,988) (28,074)
- --------------------------------------------------------------------------------------------
Net Financial Transactions (1) 314 (38) 128
- --------------------------------------------------------------------------------------------
Net Revenue 1,309 847 608
- --------------------------------------------------------------------------------------------
Transportation Expense (789) (641) (451)
- --------------------------------------------------------------------------------------------
Other 20 (2) (2)
- --------------------------------------------------------------------------------------------
NET MARKETING REVENUE 540 204 155
- --------------------------------------------------------------------------------------------
CONTRIBUTION TO NET MARKETING REVENUE BY PRODUCT TYPE:
- --------------------------------------------------------------------------------------------
North American Natural Gas 390 117 93
- --------------------------------------------------------------------------------------------
International Crude Oil 114 70 52
- --------------------------------------------------------------------------------------------
North American Power 16 8 4
- --------------------------------------------------------------------------------------------
Other 20 9 6
- --------------------------------------------------------------------------------------------
NET MARKETING REVENUE 540 204 155
- --------------------------------------------------------------------------------------------
Depreciation, Depletion, Amortization and Impairment (12) (11) (10)
- --------------------------------------------------------------------------------------------
General and Administrative (112) (89) (58)
- --------------------------------------------------------------------------------------------
MARKETING CONTRIBUTION TO INCOME FROM CONTINUING
OPERATIONS BEFORE INCOME TAXES 416 104 87
- --------------------------------------------------------------------------------------------
NATURAL GAS
- --------------------------------------------------------------------------------------------
Physical Sales Volumes (2) (bcf/d) 5.4 4.9 4.9
- --------------------------------------------------------------------------------------------
Transportation Capacity (bcf/d) 3.3 4.0 3.5
- --------------------------------------------------------------------------------------------
Storage Capacity (bcf) 50 30 27
- --------------------------------------------------------------------------------------------
CRUDE OIL
- --------------------------------------------------------------------------------------------
Physical Sales Volumes (2) (mbbls/d) 705 510 465
- --------------------------------------------------------------------------------------------
Storage Capacity (mbbls) 1,749 580 408
- --------------------------------------------------------------------------------------------
POWER
- --------------------------------------------------------------------------------------------
Physical Sales Volumes - Power (2) (MW/d) 4,388 2,548 1,191
- --------------------------------------------------------------------------------------------
Generation Capacity (MW/hr) 87 53 53
- --------------------------------------------------------------------------------------------
VALUE-AT-RISK
- --------------------------------------------------------------------------------------------
Year End 26 24 21
- --------------------------------------------------------------------------------------------
High 33 28 42
- --------------------------------------------------------------------------------------------
Low 17 11 17
- --------------------------------------------------------------------------------------------
Average 23 21 29
============================================================================================
NOTES:
(1) MARKETING'S PHYSICAL SALES, PHYSICAL PURCHASES AND NET FINANCIAL
TRANSACTIONS ARE REPORTED NET ON THE CONSOLIDATED STATEMENT OF INCOME AS
MARKETING AND OTHER.
(2) EXCLUDES INTRA-SEGMENT TRANSACTIONS.
2006 VS 2005--NET MARKETING REVENUE INCREASED NET INCOME BY $336 MILLION
Marketing had record results in 2006, with all groups achieving new highs
or starting new businesses. The largest contribution continues to come from our
North American natural gas marketing group where we capitalized on our
asset-based trading strategy. Time and location spread trading generated most
of our gas gains but we were also successful in generating revenues through the
optimization of our transportation and storage capacity. Volatility within the
North American gas markets created market inefficiencies for us to capitalize
on. North American gas prices started 2006 at US$10.63/mcf and closed the year
at US$6.30/mcf. Storage overhang and speculation around weather and possible
hurricanes caused significant changes in prices during the year. We also took
advantage of opportunities late in the year to add to our storage capacity.
48
Our crude oil marketing group also generated record results by
successfully taking advantage of crude quality, location and time spreads. The
group generated physical and financial trading gains by taking advantage of the
contango (rising forward month prices) in the crude oil forward curve. In
addition, we captured profits around quality spreads by diverting crude oil, or
by blending to enhance the crude quality, and attract higher prices. While our
strategies remained largely the same in 2006, we executed more transactions and
added more capacity, particularly storage, during the year. With our newly
established marine transportation capabilities, this group is well positioned
to start marketing our Buzzard production in 2007.
Our power marketing group is the largest supplier of power to the
commercial and industrial sector in Alberta and net revenue contributions
exceeded expectations.
OUR POWER MARKETING GROUP IS THE LARGEST SUPPLIER OF
POWER TO THE COMMERCIAL AND INDUSTRIAL SECTOR IN ALBERTA.
We continued our expansion into new markets during the year with
acquisitions in the North American NGL trading business and a UK acquisition
which positioned us in the UK and European gas and power markets.
Results from our marketing group vary between periods and historical
results are not necessarily indicative of future results. Marketing results
depend on a variety of factors such as market volatility, changes in time and
location spreads, the manner in which we use our storage and transportation
assets and the change in value of the financial instruments we use to hedge
these assets.
2005 VS 2004--NET MARKETING REVENUE INCREASED NET INCOME BY $49 MILLION
Marketing delivered strong results in 2005, with net revenue of $204
million. Our gas marketing group grew their net revenue to $117 million. We
achieved these results through our continued focus on an asset-based trading
strategy, using our transportation and storage capacity to take advantage of
seasonal and locational pricing differences and market inefficiencies.
While 2005 was a profitable year, it was also volatile with hurricane
activity in the Gulf of Mexico disrupting gas supply and infrastructure. This
volatility caused us to recognize losses in the third quarter on financial
contracts hedging our physical assets. However, we were able to recognize gains
on our physical assets in the fourth quarter as we used our transportation
capacity and sold gas from storage. This allowed us to recoup our third quarter
losses and recognize $175 million of net revenue in the fourth quarter. We also
generated profits from financial contracts that captured time and location
spreads.
Our crude oil marketing group contributed $70 million of net revenue in
2005, an increase of 35% over 2004. Similar to prior years, we continued to
capitalize on forward prices, as well as differences in crude qualities. In
particular, in 2005, we took advantage of contango by successfully pricing our
purchases lower than our sales, and by financially trading calendar spreads. We
also captured profits around quality spreads by diverting crude oil, or by
blending to enhance the crude quality, and attract higher prices.
COMPOSITION OF NET MARKETING REVENUE
(Cdn$ millions) 2006 2005
- -------------------------------------------------------------------------------
Trading Activities 520 195
- -------------------------------------------------------------------------------
Non-Trading Activities 20 9
- -------------------------------------------------------------------------------
TOTAL NET MARKETING REVENUE 540 204
===============================================================================
49
TRADING ACTIVITIES
In marketing, we enter into contracts to purchase and sell crude oil and
natural gas. We also use financial and derivative contracts, including futures,
forwards, swaps and options for hedging and trading purposes. We account for
all derivative contracts not designated as hedges for accounting purposes using
mark-to-market accounting and record the net gain or loss from their
revaluation in marketing and other income. The fair value of these instruments
is included with accounts receivable or payable. They are classified as
long-term or short-term based on their anticipated settlement date.
We value derivative trading contracts daily using:
o actively quoted markets such as the New York Mercantile Exchange
and the International Petroleum Exchange; and
o other external sources such as the Natural Gas Exchange,
independent price publications and over-the-counter broker quotes.
FAIR VALUE OF DERIVATIVE CONTRACTS
At December 31, 2006, the fair value of our derivative contracts not
designated as hedges totalled $360 million (2005--$169 million). Below is a
breakdown of this fair value by valuation method and contract maturity.
LESS THAN MATURITY MORE THAN
(Cdn$ millions) 1 YEAR 1-3 YEARS 4-5 YEARS 5 YEARS TOTAL
- --------------------------------------------------------------------------------------------------------------------------------
Prices
- --------------------------------------------------------------------------------------------------------------------------------
Actively Quoted Markets 190 (26) (21) - 143
- --------------------------------------------------------------------------------------------------------------------------------
From Other External Sources 216 (6) 13 (6) 217
- --------------------------------------------------------------------------------------------------------------------------------
Based on Models and Other Valuation Methods - - - - -
- --------------------------------------------------------------------------------------------------------------------------------
TOTAL 406 (32) (8) (6) 360
================================================================================================================================
CHANGES IN FAIR VALUE OF DERIVATIVE CONTRACTS
(Cdn$ millions) TOTAL
- -------------------------------------------------------------------------------------------------------
Fair Value at December 31, 2005 169
- -------------------------------------------------------------------------------------------------------
Change in Fair Value of Contracts 576
- -------------------------------------------------------------------------------------------------------
Net Losses (Gains) on Contracts Closed (385)
- -------------------------------------------------------------------------------------------------------
Changes in Valuation Techniques and Assumptions (1) -
- -------------------------------------------------------------------------------------------------------
FAIR VALUE AT DECEMBER 31, 2006 360
- -------------------------------------------------------------------------------------------------------
Unrecognized Gains on Hedges of Future Sale of Gas Inventory at December 31, 2006 25
- -------------------------------------------------------------------------------------------------------
TOTAL OUTSTANDING AT DECEMBER 31, 2006 385
=======================================================================================================
NOTE:
(1) OUR VALUATION METHODOLOGY HAS BEEN APPLIED CONSISTENTLY YEAR-OVER-YEAR.
As a physical energy marketer, we match the contract months of our
derivative contracts with the contract months of our physical sales and
purchases. As a result, the fair value of our derivative contracts as at
December 31, 2006 includes amounts with no ongoing commodity price or foreign
currency exchange risk. Excluding these amounts, the fair value of our
derivative contracts at December 31, 2006 was $102 million.
The fair values of our derivative contracts will be realized over time as
the related contracts settle. Until then, the value of certain contracts will
vary with forward commodity prices and price differentials. While forward
prices vary, the value of the contracts only varies to the extent they are
economically exposed or unprotected. As most of our unrealized value is not
economically exposed, we expect to realize the majority of this fair value.
50
More than 113% of the unrealized fair value relates to contracts that
settle within 12 months. Contract maturities vary from a single day up to 12
years. Those maturing beyond one year primarily relate to North American
natural gas positions. The relatively short maturity of our contracts, the high
quality of our valuations from quoted markets and external sources and the
limited economic exposure combine to lower our portfolio risk.
As part of our gas marketing strategy, we hold physical transportation and
storage capacity contracts that allow us to take advantage of pricing
differences between locations (i.e. west vs. east) and time periods (i.e.
summer vs. winter). These capacity contracts have market value, similar to
financial commodity contracts, as future margins realized depend on future
prices and, more importantly, pricing differences. The market value of these
capacity contracts varies depending on the change in future prices and pricing
relationships. We routinely hedge the economic value of our capacity contracts
using various types of derivative contracts, thereby limiting volatility in our
economic results. Accounting rules, however, increase volatility in our
reported results since they require us to recognize the change in fair value of
derivative contracts hedging our capacity contracts, but do not allow us to
recognize the change in fair value of the capacity contracts themselves until
the contracts are used. As a result, when prices or pricing relationships
change, we may be required to include gains or losses in our reported results
in different periods even though our underlying economic results may be largely
unchanged. At the end of 2006, unrecognized future commitments related to our
transportation and storage capacity contracts was a loss of $81 million. This
amount has been included in our contractual obligations, commitments and
guarantees in the MD&A.
We have designated certain derivative contracts as accounting cash flow
hedges of the future sale of our gas in storage. Mark-to-market gains and
losses on these designated contracts are excluded from income until the
underlying inventory is sold. At December 31, 2006, we had $25 million of
unrecognized gains on these derivative contracts. These contracts have been
valued from actively quoted markets and will settle within 12 months. In late
2006, we de-designated certain futures contracts that had been designated as
cash flow hedges of future sales of our natural gas in storage. Gains of $65
million on the futures contracts have been deferred and are expected to be
recognized in net income in the first quarter of 2007.
NON-TRADING ACTIVITIES
We enter into fee-for-service contracts related to transportation and
storage of third-party oil and gas. We also earn income from our power
generation facilities at Balzac and Soderglen. We earned $20 million from our
non-trading activities in 2006 (2005--$9 million).
CHEMICALS
(Cdn$ millions) 2006 2005 2004
- -------------------------------------------------------------------------------
Net Sales 407 398 378
- -------------------------------------------------------------------------------
Sales Volumes (thousand short tons)
- -------------------------------------------------------------------------------
Sodium Chlorate 487 493 506
- -------------------------------------------------------------------------------
Chlor-alkali 451 450 403
- -------------------------------------------------------------------------------
Operating Profit (1) 124 136 105
- -------------------------------------------------------------------------------
Operating Margin (2) 30% 34% 28%
- -------------------------------------------------------------------------------
Chemicals Contribution to Income from Continuing
Operations Before Income Taxes 44 37 40
- -------------------------------------------------------------------------------
Capacity Utilization 95% 96% 95%
===============================================================================
NOTES:
(1) TOTAL REVENUES LESS OPERATING COSTS, TRANSPORTATION AND OTHER.
(2) OPERATING PROFIT DIVIDED BY NET SALES.
51
2006 VS 2005-- LOWER CHEMICALS OPERATING PROFIT DECREASED NET INCOME BY
$12 MILLION
Our investment in our chemicals business is held through our 61.4%
interest in the Canexus Limited Partnership. While North American prices for
sodium chlorate remained strong throughout 2006, sales volumes fell slightly
from last year as a result of pulp mill closures. Chlor-alkali volumes and
prices in North America remained steady. US-dollar denominated North American
sales were reduced $12 million from the stronger Canadian dollar during 2006.
Sales and operations from the Brazil plant remained solid as a result of strong
demand from Aracruz Cellulose, our primary customer, and from the merchant
market.
DURING THE YEAR, CANEXUS BEGAN AN EXPANSION OF THE
BRANDON, MANITOBA PLANT, WHICH BENEFITS FROM LOW ELECTRICITY RATES.
Late in the year, Canexus commenced an expansion of the Brandon, Manitoba
plant to increase capacity by 12% by early 2008. The Brandon plant benefits
from low electricity rates in the province of Manitoba, where the electricity
market is based on hydroelectric power and is regulated.
2005 VS 2004--HIGHER CHEMICALS OPERATING PROFIT INCREASED NET INCOME BY
$31 MILLION
In the third quarter of 2005, we monetized a portion of our chemicals
business by creating the Canexus Income Fund through an initial public offering
(IPO), which raised net proceeds of $301 million. Canexus Limited Partnership,
also raised US$167 million ($200 million) of bank debt. Canexus Limited
Partnership used the proceeds from Canexus Income Fund's IPO and the bank debt,
together with the issuance of 50.5 million exchangeable units of the Canexus
Limited Partnership to Nexen, to purchase our chemicals operations. We have
retained a 61.4% interest in the chemicals operations through our investment in
Canexus Limited Partnership, and we recorded a gain of $193 million on the
dilution of our interest.
Despite lower sales volumes, strong chlor-alkali prices and higher margins
generated strong results for the chemicals business. Sodium chlorate volumes
decreased compared with 2004 as a result of our decision in early 2005 to
forego low-margin business consistent with our restructuring effort and the
closure of our Amherstburg, Ontario plant. Sales and operations from the Brazil
plant remained strong as a result of continued strong demand from Aracruz
Cellulose, our primary customer in Brazil, and an expanded presence in the
merchant market.
The weaker US dollar put pressure on our US-dollar denominated sales,
reducing net sales by $13 million. During 2005, we purchased US-dollar foreign
currency call options to mitigate our exposure to the weakening dollar. We
generated $4 million of income as a result of these call options.
Our chemicals contribution was reduced by $12 million for an impairment
charge relating to our chemicals plant in Amherstburg, which was closed in the
third quarter of 2005.
CORPORATE EXPENSES
GENERAL AND ADMINISTRATIVE (G&A)
(Cdn$ millions) 2006 2005 2004
- ------------------------------------------------------------------------------------------------------
General and Administrative Expense before Stock-Based Compensation 345 302 206
- ------------------------------------------------------------------------------------------------------
Stock-Based Compensation (1) 210 507 93
- ------------------------------------------------------------------------------------------------------
TOTAL GENERAL AND ADMINISTRATIVE EXPENSE 555 809 299
======================================================================================================
NOTE:
(1) INCLUDES TANDEM OPTION PLAN, STOCK OPTIONS FOR OUR US-BASED EMPLOYEES AND
STOCK APPRECIATION RIGHTS PLAN.
52
2006 VS 2005--LOWER COSTS INCREASED NET INCOME BY $254 MILLION
Our G&A expense before stock-based compensation increased 14% primarily
from additional costs to expand our marketing operations into new markets.
Acquisitions during the year enabled us to increase our NGL business in North
America and to expand our European trading operations. Our G&A expense also
includes higher variable compensation stemming from our marketing group's
strong performance in 2006.
TOTAL G&A EXPENSE DECREASED 31% IN 2006
FROM LOWER STOCK-BASED COMPENSATION COSTS.
Changes in our share price creates volatility in our net income as we
account for stock-based compensation using the intrinsic-value method. This
method uses our share price at the end of the reporting period to determine our
stock-based compensation expense and related obligations. In 2006, our share
price increased 16% from $55.42 to $64.20, creating over $2.3 billion of
shareholder value. The expense represents approximately 9% of the increase in
shareholder value. Cash payments to employees for our stock-based compensation
programs were $119 million in 2006, a 61% increase over 2005.
2005 VS 2004--HIGHER COSTS REDUCED NET INCOME BY $510 MILLION
Our stock-based compensation expense in 2005 reflects the significant
increase in the price of our common shares. Our share price increased 128% from
$24.35 to $55.42, adding more than $8 billion of shareholder value.
Notwithstanding this increase in our share price, cash payments to employees
under our stock-based compensation programs only amounted to $74 million.
Our growing international presence and the expansion of our businesses
increased our G&A costs during the year. Costs reflect more employees,
additional travel, and higher compliance and governance costs, combined with
increased variable incentive compensation stemming from our record results. We
also incurred additional costs related to our disposition activities and the
integration of our North Sea operations acquired in late 2004.
INTEREST
(Cdn$ millions) 2006 2005 2004
- -------------------------------------------------------------------------------
Interest 294 275 194
- -------------------------------------------------------------------------------
Less: Capitalized (241) (178) (51)
- -------------------------------------------------------------------------------
NET INTEREST EXPENSE 53 97 143
- -------------------------------------------------------------------------------
Effective Rate 6.3% 6.4% 6.6%
===============================================================================
2006 VS 2005--LOWER NET INTEREST EXPENSE INCREASED NET INCOME BY $44 MILLION
Our financing costs have increased $19 million from 2005. Additional
borrowings to finance our 2006 capital program increased financing costs by
approximately $28 million. This was partially offset however, by the stronger
Canadian dollar which decreased our US-dollar denominated interest by $16
million. The Canexus debt, consolidated with our results, increased our
interest expense by $7 million.
The amount of interest we capitalized on our major development projects
grew by $63 million, primarily from increased investment in the North Sea
Buzzard project, at Long Lake and the Stage 3 expansion at Syncrude prior to
its start-up. We expect interest capitalized on projects to decrease in 2007 as
we ceased capitalizing interest on the Syncrude expansion in August 2006 and on
Buzzard in January 2007. We expect to continue to capitalize interest on our
Long Lake project prior to its completion in 2007. Our net interest expense is
expected to increase once these projects are completed.
2005 VS 2004--LOWER NET INTEREST EXPENSE INCREASED NET INCOME BY $46 MILLION
We acquired our North Sea assets in late 2004. We partially financed this
acquisition with US$1 billion of new long-term debt, increasing our interest
costs by $87 million in 2005. Interest expense also increased $3 million
relating to the Canexus debt consolidated with our results. However, the
stronger Canadian dollar lowered our US-dollar denominated interest by $12
million. During the last two years, we have taken advantage of declining
interest rates by replacing our higher-cost preferred securities with new
long-term debt at lower rates.
53
INCOME TAXES
(Cdn$ millions) 2006 2005 2004
- --------------------------------------------------------------------------------
Current 368 339 248
- --------------------------------------------------------------------------------
Future 315 (234) 119
- --------------------------------------------------------------------------------
TOTAL PROVISION FOR INCOME TAXES 683 105 367
- --------------------------------------------------------------------------------
Disclosed as:
- --------------------------------------------------------------------------------
Provision for Income Taxes--Continuing Operations 683 234 317
- --------------------------------------------------------------------------------
Provision for Income Taxes--Discontinued Operations (1) - (129) 50
- --------------------------------------------------------------------------------
TOTAL PROVISION FOR INCOME TAXES 683 105 367
- --------------------------------------------------------------------------------
Effective Rate 53% 8% 32%
================================================================================
NOTE:
(1) SEE NOTE 14 TO OUR CONSOLIDATED FINANCIAL STATEMENTS.
2006 VS 2005--EFFECTIVE TAX RATE INCREASES FROM 8% TO 53%
In early 2006, the UK government substantively enacted increases to the
supplementary tax rate on our North Sea oil and gas activities from 10% to 20%,
effective January 1, 2006. This increased our future income tax liabilities,
resulting in a charge of $277 million during the first quarter. During the
second quarter, federal and certain provincial governments in Canada reduced
corporate income tax rates. These rate reductions lowered our future income tax
liabilities by $32 million. Our effective tax rate excluding the effect of
these tax rate changes was 33%.
IN 2006, AN INCREASE IN THE UK SUPPLEMENTAL TAX RATE ON
OIL & GAS ACTIVITIES RESULTED IN A FUTURE INCOME TAX EXPENSE OF $277 MILLION.
Current income taxes include cash taxes in Yemen of $286 million (2005 -
$296 million; 2004 - $227 million). Our current income tax provision also
includes federal and state taxes in the US, cash taxes in Colombia and capital
taxes in Canada.
2005 VS 2004--EFFECTIVE TAX RATE DECREASES FROM 32% TO 8%
The recovery of future taxes payable of $234 million is attributable to
the disposition of our oil and gas producing properties in Canada and the sale
of our chemicals business to the Canexus Limited Partnership. As a result of
the dispositions, we revalued our future income tax liabilities for the change
in the underlying book and tax values. This revaluation resulted in the
reduction of our future income tax liabilities. In addition, the disposition
gains were taxed at lower capital gains tax rates. Removing the tax impact of
the dispositions, the effective tax rate for our continuing operations was 32%.
54
OTHER
(Cdn$ millions) 2006 2005 2004
- ------------------------------------------------------------------------------------------------------------------
Block 51 Arbitration (151) - -
- ------------------------------------------------------------------------------------------------------------------
Business Interruption Insurance Proceeds 154 2 10
- ------------------------------------------------------------------------------------------------------------------
Gain on Dilution of Interest in Chemicals Business - 193 -
- ------------------------------------------------------------------------------------------------------------------
Gain on Disposition of Oil and Gas Assets included as Discontinued Operations - 225 -
- ------------------------------------------------------------------------------------------------------------------
Increase (Decrease) in Fair Value of Crude Oil Put Options (11) (196) 56
==================================================================================================================
During the year, a court of arbitration concluded that we breached an Area
of Mutual Interest agreement with Occidental Petroleum Corporation
(Occidental). As a result, Occidental was entitled to monetary damages. In late
2006, we agreed to settle the arbitration by agreeing to pay Occidental US$135
million as monetary damages. No further amounts are expected to be payable
under the settlement.
In 2006, we received $154 million of business interruption insurance
proceeds related to production losses caused by Gulf of Mexico hurricanes in
2005 and by generator failures in our UK operations in 2005.
As a result of the sale of our chemicals business to the Canexus Limited
Partnership in 2005, we recorded a gain on the dilution of our interest from
100% to 61.4% of $193 million. Our gain on the 2005 sale of Canadian oil and
gas properties in Alberta, British Columbia and Saskatchewan was $225 million.
Following our North Sea acquisition in late 2004, we purchased put options
on 60,000 bbls/d of oil production for 2005 and 2006 to ensure base cash flow
in those years while we invest in our major development projects. These options
created an average floor price for this production of US$43.17/bbl in 2005 and
US$38.17/bbl in 2006. Accounting rules require that these options be recorded
at fair value throughout their term. As a result, changes in forward crude oil
prices cause gains or losses to be recorded on these options at each period
end. A gain of $56 million was recorded in the fourth quarter of 2004, bringing
the fair value of these options to $200 million. During 2005, a significant
increase in forward crude prices reduced the value of these options by $196
million. Strong WTI prices in 2006 reduced the market value of these remaining
options to nil and we expensed $4 million in 2006 as a result.
During 2006, we purchased put options on approximately 105,000 bbls/d of
our 2007 crude oil production. These options establish a WTI floor price of
US$50/bbl on these volumes, are settled annually and provide a base level of
price protection without limiting our upside to higher prices. The put options
were purchased for $26 million and are carried at fair value. We recorded a
loss of $7 million during the year for the decrease in fair value.
OUTLOOK FOR 2007
In 2007, we plan to invest $2.9 billion in capital projects. Approximately
34% of this capital will be invested in development projects, which include
Long Lake, coalbed methane in Canada, Ettrick in the North Sea, and Wrigley and
Tobago in the Gulf of Mexico. We are also directing 14% of our 2007 capital to
early-stage development projects expected to contribute production and cash
flow growth beyond 2007. These include Knotty Head, Alaminos Canyon Block 856
(Great White West) and Ringo in the Gulf of Mexico, additional phases of oil
sands in the Athabasca region and Block 222, offshore West Africa. We have
allocated 24% of our capital to exploration opportunities in our growth areas.
The remaining 28% of the 2007 capital will be invested to exploit potential in
our existing producing assets and in other corporate assets.
Details of our 2007 capital investment program are included in the Capital
Investment section of the MD&A.
DAILY PRODUCTION
We expect to grow annual production rates after royalties approximately
50% compared to 2006 to between 230,000 and 260,000 boe/d (275,000 and 305,000
boe/d before royalties). Our Buzzard development came on stream early January
2007 and we expect to achieve peak rates of 85,000 boe/d during the second
quarter of 2007. Other contributions to our expected growth in 2007 are from
the Gulf of Mexico, a full year of production from the Stage 3 expansion at
Syncrude and bitumen production from Long Lake. Our annual production for 2007
is expected to be:
55
2007 ESTIMATED PRODUCTION
2007 ESTIMATED PRODUCTION 2006 PRODUCTION
BEFORE AFTER BEFORE AFTER
(mboe/d) ROYALTIES ROYALTIES ROYALTIES ROYALTIES
- ----------------------------------------------------------------------------------------------------------
United States 45 - 55 38 - 48 36 31
- ----------------------------------------------------------------------------------------------------------
United Kingdom 90 - 100 90 - 100 20 20
- ----------------------------------------------------------------------------------------------------------
Yemen 60 - 75 35 - 45 93 52
- ----------------------------------------------------------------------------------------------------------
Canada 45 - 50 38 - 42 38 31
- ----------------------------------------------------------------------------------------------------------
Syncrude 20 - 25 18 - 20 19 17
- ----------------------------------------------------------------------------------------------------------
Other International 6 - 7 5 - 6 6 5
- ----------------------------------------------------------------------------------------------------------
TOTAL 275 - 305 230 - 260 212 156
==========================================================================================================
CASH FLOW AND SENSITIVITIES
We expect to generate more than $3.3 billion in cash flow from operating
activities in 2007 (before site restoration and geological and geophysical
expenditures), assuming the following:
- -------------------------------------------------------------------------------
WTI (US$/bbl) 50.00
- -------------------------------------------------------------------------------
NYMEX Natural Gas (US$/mmbtu) 6.00
- -------------------------------------------------------------------------------
Oil & Gas and Syncrude Operating Costs (Cdn$/boe) 8.00
- -------------------------------------------------------------------------------
US to Canadian Dollar Exchange Rate 0.88
===============================================================================
Changes in commodity prices and exchange rates impact our annual cash flow
from operating activities as follows:
(Cdn$ millions)
- -------------------------------------------------------------------------------
WTI--US$1/bbl Change above US$50 73
- -------------------------------------------------------------------------------
WTI--US$1/bbl Change below US$50 42
- -------------------------------------------------------------------------------
NYMEX Natural Gas--US $1.00/mcf Change 66
- -------------------------------------------------------------------------------
Exchange Rate--$0.01 Change 35
===============================================================================
LIQUIDITY AND CAPITAL RESOURCES
CAPITAL STRUCTURE
(Cdn$ millions) 2006 2005
- -------------------------------------------------------------------------------
NET DEBT (1)
- -------------------------------------------------------------------------------
Bank Debt 1,410 171
- -------------------------------------------------------------------------------
Public Senior Notes 2,885 2,980
- -------------------------------------------------------------------------------
Senior Debt 4,295 3,151
- -------------------------------------------------------------------------------
Subordinated Debt 536 536
- -------------------------------------------------------------------------------
Total Debt 4,831 3,687
- -------------------------------------------------------------------------------
Less: Cash and Cash Equivalents (101) (48)
- -------------------------------------------------------------------------------
TOTAL NET DEBT 4,730 3,639
===============================================================================
SHAREHOLDERS' EQUITY (2) 4,636 3,996
===============================================================================
NOTES:
(1) INCLUDES ALL OF OUR DEBT AND IS CALCULATED AS LONG-TERM DEBT AND
SHORT-TERM BORROWINGS LESS CASH AND CASH EQUIVALENTS.
(2) AT JANUARY 31, 2007, THERE WERE 262,830,108 COMMON SHARES AND US$460
MILLION OF UNSECURED SUBORDINATED SECURITIES OUTSTANDING. THESE
SUBORDINATED SECURITIES MAY BE REDEEMED BY ISSUING COMMON SHARES AT OUR
OPTION AFTER NOVEMBER 8, 2008. THE NUMBER OF SHARES ISSUABLE DEPENDS ON
THE COMMON SHARE PRICE ON THE REDEMPTION DATE.
56
NET DEBT
We use net debt as a key indicator of our leverage and to monitor the
strength of our balance sheet. Net debt is directly related to our operating
cash flows, capital investment activities and disposition programs. We ended
the year with net debt of $4.7 billion, an increase of $1.1 billion from 2005.
In 2006, we invested over $3.4 billion in capital projects, with more than 50%
of this at Long Lake and Buzzard. These major projects did not contribute to
cash flow in 2006 but will start to contribute in 2007 and beyond. We financed
our 2006 capital program with cash flow from operating activities and borrowed
US$925 million under our term credit facilities.
The year-over-year change in our net debt results from:
(Cdn$ millions) 2006 2005
- --------------------------------------------------------------------------------
Capital Investment 3,408 2,638
- --------------------------------------------------------------------------------
Cash Flow from Operating Activities (2,374) (2,143)
- --------------------------------------------------------------------------------
Excess of Capital Investment over Cash Flow 1,034 495
- --------------------------------------------------------------------------------
Net Proceeds on Disposition of Assets (27) (911)
- --------------------------------------------------------------------------------
Net Proceeds from Canexus Initial Public Offering - (301)
- --------------------------------------------------------------------------------
Dividends on Common Shares 52 52
- --------------------------------------------------------------------------------
Issue of Common Shares (48) (58)
- --------------------------------------------------------------------------------
Foreign Exchange Translation of US-dollar Debt and Cash 31 (113)
- --------------------------------------------------------------------------------
Other 49 190
- --------------------------------------------------------------------------------
INCREASE (DECREASE) IN NET DEBT 1,091 (646)
================================================================================
The change in our net debt has increased our leverage levels as reflected
in following ratios:
(times) 2006 2005 2004
- -------------------------------------------------------------------------------
Net Debt to Cash Flow from Operating Activities 2.0 1.7 2.7
- -------------------------------------------------------------------------------
Interest Coverage (1) 9.6 9.7 11.9
===============================================================================
NOTE:
(1) EARNINGS BEFORE INTEREST, TAXES, DD&A AND EXPLORATION EXPENSE DIVIDED BY
INTEREST EXPENSE (BEFORE CAPITALIZED INTEREST).
Our business strategy is focused on value-based growth through full-cycle
exploration and development, supplemented by strategic acquisitions when
appropriate. We have leveraged our balance sheet in the past to accomplish our
growth strategy, as most of our projects have long-cycle times, requiring
significant amounts of capital to be invested prior to generating cash flows.
Historically, we have been successful with this strategy as we used leverage
to:
o develop the Masila project in Yemen in 1993;
o acquire Wascana in 1997;
o repurchase 20 million common shares in 2000;
o acquire the remaining interest in Aspen in 2003;
o acquire the Buzzard project and other key assets in the North
Sea in 2004;
o build our first phase of Long Lake, scheduled to be on stream
in late 2007; and
o fund remaining development capital.
Each time, we exceeded our internal net debt to cash flow target band;
however, we successfully brought our leverage down through asset sales and
incremental cash flows. In 2006, we again increased our leverage levels as a
result of capital expenditures on our major development projects at Buzzard and
Long Lake. In 2007, we anticipate reducing our net debt to cash flow from
operating activities ratio using cash flows from our Buzzard operations, as
well as our Long Lake project, expected to come on stream in 2007.
57
CHANGE IN WORKING CAPITAL
INCREASE/
(Cdn$ millions) 2006 2005 (DECREASE)
- -------------------------------------------------------------------------------
Cash and Cash Equivalents 101 48 53
- -------------------------------------------------------------------------------
Restricted Cash and Margin Deposits 197 70 127
- -------------------------------------------------------------------------------
Accounts Receivable 2,951 3,151 (200)
- -------------------------------------------------------------------------------
Inventories and Supplies 786 504 282
- -------------------------------------------------------------------------------
Future Income Tax Assets 479 - 479
- -------------------------------------------------------------------------------
Accounts Payable and Accrued Liabilities (3,879) (3,727) (152)
- -------------------------------------------------------------------------------
Other (1) (17) 16
- -------------------------------------------------------------------------------
TOTAL 634 29 605
===============================================================================
Lower natural gas prices reduced our year end accruals for our marketing
accounts receivable and accounts payable. This has been offset by higher prices
in crude oil markets. We expanded our crude oil physical and financial trading
activities to capture market gains. This expanded activity increased our
marketing accounts receivable and accounts payable. We took advantage of lower
natural gas prices and expanded our gas storage inventories by 27 bcf during
the year. Volatile gas markets also increased the value of our derivative
contract assets and liabilities.
Our accounts payable and accrued liabilities have increased since 2005
from higher accrued stock-based compensation obligations as a result of our
strong share price, higher accruals related to our capital investment programs
and our accrual related to the Block 51 settlement. We have reclassed $479
million of future income tax assets to current assets. This represents tax loss
carry-forward balances in our UK operations that we expect to use in the next
twelve months now that Buzzard is on stream.
LIQUIDITY
We generally rely on operating cash flows to fund capital requirements and
provide liquidity. We build our opportunity portfolio to provide a balance of
short-term, mid-term, and longer-term growth. Given the long cycle-time of some
of our development projects and the volatility of commodity prices, it is not
unusual in any given year for capital expenditures to exceed our cash flow. In
addition, we require liquidity for our energy marketing business. Accordingly,
we maintain significant committed credit facilities. At December 31, 2006, we
had committed term credit facilities of $3.6 billion that are available until
2011. At year end, $1,078 million was drawn on these facilities and $294
million of these facilities were utilized to support letters of credit. We also
had $632 million of uncommitted, unsecured credit facilities, of which $158
million was drawn at year end and $252 million was utilized to support letters
of credit.
From time to time, we access the capital markets to meet our financing
needs. We also use various financial instruments to minimize our exposure to
fluctuations in commodity prices and foreign exchange. For example, we
purchased WTI put options for 2007 to mitigate cash flow volatility. Overall,
we manage our capital structure to maintain flexibility so we can fund our
capital programs throughout the highs and lows of the price cycles inherent in
the oil and gas business.
The following table shows how we finance our business activities. When our
operating cash flows exceed our investment requirements, we generally pay down
debt. We borrow or issue equity to fund investment requirements that exceed our
operating cash flow.
(Cdn$ millions) 2006 2005 2004 2003 2002
- --------------------------------------------------------------------------------
Cash Flow from Operating Activities 2,374 2,143 1,606 1,405 1,250
- --------------------------------------------------------------------------------
Cash Flow from Investing Activities (3,388) (1,864) (4,013) (1,219) (1,569)
- --------------------------------------------------------------------------------
Surplus (Deficiency) (1,014) 279 (2,407) 186 (319)
- --------------------------------------------------------------------------------
Cash Flow from Financing Activities 1,081 (274) 1,426 1,006 329
- --------------------------------------------------------------------------------
67 5 (981) 1,192 10
================================================================================
58
In 2002, we began to invest significantly in two deep-water Gulf of Mexico
projects (Aspen and Gunnison), our Syncrude expansion and our Long Lake
project. We accessed public debt markets in 2002 to fund these investments. In
2003, Aspen contributed significantly to our cash flow and in late 2003, we
pre-funded debt repayments by raising more than $1 billion in senior and
subordinated debt. We used these funds in 2004 to repay higher-cost debt, and
coupled with acquisition credit facilities, acquired the North Sea assets. In
2005, we used our cash flow and the proceeds from asset dispositions to fund
our capital program and repay debt. In 2006, we borrowed approximately $1
billion under our committed term credit facilities and used our cash flow from
operating activities to fund our capital program.
Our marketing business also requires liquidity to support its asset-based
trading strategy. We require liquidity for working capital, 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 typically require posting
of collateral when adverse credit-related events occur, such as a reduction in
credit ratings. 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 in the event of reductions in our
credit ratings.
FUTURE LIQUIDITY
Our future liquidity is primarily dependent on cash flows generated from
our operations, existing committed credit facilities and our ability to access
debt and equity markets. Assuming WTI of US$50/bbl, we expect our 2007 cash
flow to exceed our capital investment program and dividend requirements by more
than $300 million. In July 2007, we are required to repay $150 million of
medium term notes that become due, however, we plan to fund this with our term
credit facilities.
Our cash flow is sensitive to changes in commodity prices and exchange
rates. For 2007, we expect cash flow of approximately $3.3 billion (before
remediation and geological and geophysical expenditures) assuming:
- -------------------------------------------------------------------------------
WTI (US$/bbl) 50.00
- -------------------------------------------------------------------------------
NYMEX Natural Gas (US$/mmbtu) 6.00
- -------------------------------------------------------------------------------
US to Canadian Dollar Exchange Rate 0.88
===============================================================================
Changes in commodity prices and exchange rates will impact our cash flow
and borrowing requirements. The impact of a variance in any one of the above
assumptions on our cash flow is described in the Outlook for 2007 section on
page 55.
FOR 2007, WE EXPECT CASH FLOW OF
APPROXIMATELY $3.3 BILLION.
We are in the midst of a number of development projects that require
capital to bring them on stream. We anticipate that we will spend an additional
$500 million in 2007 to bring the first phase of Long Lake on stream. In
addition, we expect to spend $200 million in 2007 on furthering our coalbed
methane projects in central Alberta and $235 million to complete the Ettrick
development in the North Sea by mid 2008.
While these development projects lack exploration risk, they are subject
to other risks including higher than anticipated capital costs or delayed
start-up. We maintain undrawn committed credit facilities to manage this risk.
In addition to our operating cash flows and our undrawn committed credit
facilities, we have a US$1.5 billion shelf prospectus available in the US and
Canada.
At December 31, 2006, the average term to maturity of our long-term debt
was 16.6 years. We have the following short and long-term debt maturities
during the next five years:
(Cdn$ millions) 2007 2008 2009 2010 2011
- -------------------------------------------------------------------------------
Uncommitted Credit Facilities 158 - - - -
- -------------------------------------------------------------------------------
Term Credit Facilities (1) - - - - 1,078
- -------------------------------------------------------------------------------
Canexus LP Term Credit Facilities - - - 174 -
- -------------------------------------------------------------------------------
Debentures - - - - -
- -------------------------------------------------------------------------------
Medium Term Notes 150 125 - - -
- -------------------------------------------------------------------------------
TOTAL 308 125 - 174 1,078
===============================================================================
NOTE:
(1) $3.6 BILLION AVAILABLE UNTIL 2011.
59
With our expected cash flow streams, commodity price and hedging
strategies, current levels of liquidity, and access to debt and equity markets,
we expect to be able to fund our planned capital programs, dividend
requirements and debt repayments, or meet other obligations that may arise from
our oil and gas, chemicals and marketing operations.
In 2006 we declared common share dividends of $0.20 per share
(2005--$0.20, 2004--$0.20). We expect to declare common share dividends of
$0.20 per share in 2007.
CONTRACTUAL OBLIGATIONS, COMMITMENTS AND GUARANTEES
We assume various contractual obligations and commitments in the normal
course of our operations and financing activities. We have considered these
obligations and commitments in assessing our cash requirements, as noted in the
above discussion of future liquidity. They include:
LESS THAN PAYMENTS MORE THAN
(Cdn$ millions) TOTAL 1 YEAR 1-3 YEARS 4-5 YEARS 5 YEARS
- --------------------------------------------------------------------------------------------------------------------
Short-Term and Long-Term Debt 4,831 308 125 1,252 3,146
- --------------------------------------------------------------------------------------------------------------------
Interest on Long-Term Debt 4,859 215 406 403 3,835
- --------------------------------------------------------------------------------------------------------------------
Operating Leases (1) 752 44 236 240 232
- --------------------------------------------------------------------------------------------------------------------
Capital Leases 119 5 10 10 94
- --------------------------------------------------------------------------------------------------------------------
Energy Commodity Contract Liabilities 524 325 191 8 -
- --------------------------------------------------------------------------------------------------------------------
Transportation and Storage Commitments (1) 927 424 262 123 118
- --------------------------------------------------------------------------------------------------------------------
Work Commitments and Purchase Obligations (2) 1,460 663 419 218 160
- --------------------------------------------------------------------------------------------------------------------
Asset Retirement Obligations 1,770 21 42 34 1,673
- --------------------------------------------------------------------------------------------------------------------
TOTAL 15,242 2,005 1,691 2,288 9,258
====================================================================================================================
NOTES:
(1) PAYMENTS FOR OPERATING LEASES AND TRANSPORTATION AND STORAGE COMMITMENTS
ARE DEDUCTED FROM OUR CASH FLOW FROM OPERATING ACTIVITIES.
(2) SOME OF THESE PAYMENTS RELATE TO WORK COMMITMENTS CANCELLABLE AT OUR
OPTION WITHOUT PENALTIES OR ADDITIONAL FEES.
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.
o Short-term and long-term debt amounts are included on our December
31, 2006 Consolidated Balance Sheet.
o Operating leases include the minimum lease payment obligations
associated with leases for office space, rail cars, vehicles and
our processing agreement that allows our Aspen production to flow
through Shell's processing facilities at the Bullwinkle platform.
The terms of the processing agreement give Shell an annual option
to take payment in cash or in kind. For 2007, Shell has elected to
take payment in kind, so the 2007 obligation has been excluded
from this table. Instead, it is shown as a royalty and excluded
from reserves and production.
o Capital leases include pipeline commitments primarily related to
future production at Long Lake.
o Energy commodity contract liabilities include the purchase and
sale of physical quantities of oil and natural gas, and financial
derivatives used to manage our exposure to commodity prices. For
contracts where the price is based on an index, the amount is
based on forward market prices at December 31, 2006. For certain
contracts, we may net settle.
o Work commitments include non-discretionary capital spending
related to drilling, seismic, construction of facilities and other
development commitments in our international operations, and
includes Long Lake ($157 million) and the Ettrick development in
the North Sea ($233 million). The timing of certain payments is
difficult to determine with certainty. The table has been prepared
using our best estimates; the remainder of our 2007 capital
investment is discretionary.
o We also have included work commitments relating to drilling rigs,
which have been contracted to work for us in the North Sea and
Gulf of Mexico, totalling $414 million over the next five years.
60
o We have $1,770 million of undiscounted asset retirement
obligations after inflation. As of December 31, 2006, the
discounted value ($704 million) of these estimated obligations has
been provided for in our Consolidated Financial Statements
(including $21 million of current liabilities). The timing of any
payments is difficult to determine with certainty, and the table
has been prepared using our best estimates.
o We have unfunded obligations under our defined benefit pension
plans of $122 million (Nexen--$67 million; Canexus--$8 million;
Syncrude--$47 million). Our obligations for Nexen and Canexus
include $54 million that is unfunded as a result of statutory
limitations. These obligations are backed by irrevocable letters
of credit.
o We have excluded obligations on our tandem option and stock
appreciation rights programs as the amount and timing of cash
payments are indeterminable.
o We have excluded our normal purchase arrangements as they are
discretionary and are reflected in our expected cash flow from
operating activities and our expected capital expenditures for
2007.
o We have excluded our future income tax liabilities as the amount
and timing of any cash payments for income taxes are based
primarily on taxable income for each fiscal year in the various
jurisdictions in which we operate.
From time to time, we enter into contracts that require us to indemnify
parties against 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 these matters would not
have a material adverse effect on our liquidity, financial condition or results
of operations.
CREDIT RATINGS
Currently, our senior debt is rated Baa2 by Moody's Investor Service, Inc.
(Moody's), BBB by Dominion Bond Rating Service (DBRS) and BBB- by Standard &
Poor's (S&P). In addition, Moody's and DBRS currently rate our outlook as
stable while S&P has a positive outlook. Our strong financial results, ample
liquidity and financial flexibility continue to support our credit ratings.
FINANCIAL ASSURANCE PROVISIONS IN COMMERCIAL CONTRACTS
The commercial agreements our marketing group enters into often include
financial assurance provisions that allow Nexen and our counterparties to
effectively manage credit risk. The agreements normally require posting of
collateral when adverse credit-related events occur such as a reduction in
credit ratings. Based on the contracts in place and commodity prices at
December 31, 2006, we could be required to post collateral of up to $1,149
million if we were downgraded to non-investment grade. These obligations are
already reflected on our balance sheet. The posting of collateral merely
accelerates the payment of such amounts. Just as we may be required to post
collateral in the event of a downgrade below investment grade, we have similar
provisions in many of our contracts that allow us to demand certain
counterparties post collateral for amounts owing to us if they are downgraded
to non-investment grade.
OFF-BALANCE SHEET ARRANGEMENTS
We have no off-balance sheet arrangements 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 Contractual Obligations, Commitments and Guarantees on page 60 and
in Note 15 to the Consolidated Financial Statements in Item 8, which is
incorporated herein by reference. At December 31, 2006, we had outstanding
letters of credit amounting to $294 million and $252 million supported by our
committed term credit facilities and our uncommitted credit facilities,
respectively.
CONTINGENCIES
We have no contingencies that would have a material adverse effect on our
liquidity, consolidated financial position or results of operations. See Note
15 to the Consolidated Financial Statements in Item 8, which is incorporated
herein by reference for a discussion of our contingencies.
61
CRITICAL ACCOUNTING ESTIMATES
We make estimates and assumptions that affect the reported amounts of our
assets and liabilities and the disclosure of contingent assets and liabilities
at the date of the Consolidated Financial Statements and our revenues and
expenses during the reporting period. Our management reviews these estimates,
including those related to accruals, litigation, environmental and asset
retirement obligations, income taxes, derivative contract assets and
liabilities and the determination of proved 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 follow the successful efforts method of accounting for our oil and gas
activities, as described in Note 1 to our Consolidated Financial Statements.
Successful efforts accounting depends on the estimated reserves we believe are
recoverable from our oil and gas properties.
The process of estimating reserves is complex. It requires significant
judgments and decisions based on available geological, geophysical, engineering
and economic data. To estimate the economically recoverable oil and natural gas
reserves and related future net cash flows, we incorporate many factors and
assumptions including:
o expected reservoir characteristics based on geological,
geophysical and engineering assessments;
o future production rates based on historical performance and
expected future operating and investment activities;
o future oil and gas prices and quality differentials;
o assumed effects of regulation by governmental agencies; and
o future development and operating costs.
We believe these factors and assumptions are reasonable based on the
information available to us at the time we prepare our estimates. However,
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.
Management is responsible for estimating the quantities of proved oil and
natural gas reserves and for preparing related disclosures. Estimates and
related disclosures are prepared in accordance with SEC requirements, generally
accepted industry practices in the US and the standards of the Canadian Oil and
Gas Evaluation Handbook modified to reflect SEC requirements.
Reserve estimates for each property are internally prepared at least
annually by the property's reservoir engineer. They are reviewed by engineers
familiar with the property and by divisional management. An Executive Reserves
Committee, including our CEO, CFO and board-appointed internal qualified
reserves evaluator, meet with divisional reserves personnel to review the
estimates and any changes from previous estimates.
The internal qualified reserves evaluator assesses whether our reserves
estimates and the STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS AND
CHANGES THEREIN, included in the Supplementary Financial Information, have been
prepared in accordance with our reserve standards. His opinion stating that the
reserves information has, in all material respects, been prepared according to
our reserves standards is included in an exhibit to this Form 10-K.
Our reserves are based on internal estimates. To increase our confidence
in our estimates, we have at least 80% of our oil and gas and Syncrude reserves
either evaluated or audited annually by independent qualified reserves
consultants. Given that reserve estimates are based on numerous assumptions,
interpretations and judgments, differences frequently arise between the
estimates prepared by different qualified estimators. When the initial estimate
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 often differ
by significantly 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.
The nature and extent of the independent evaluations and audits, and the
results thereof, are provided in the section on Reserves, Production and
Related Information on page 18.
62
The board of directors has established 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 each being familiar with estimating
oil and gas reserves. 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 each of the internal qualified
reserves evaluator and independent reserves consultants, independent of
management, 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 reserves
consultants, their independence.
The Reserves Committee has reviewed Nexen's procedures for preparing the
reserves estimates and related disclosures. It has reviewed the information
with management, and met with the internal qualified reserves evaluator and the
independent qualified reserves consultants. As a result of this, the Reserves
Committee is satisfied that the internally-estimated reserves 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 the Form 10-K.
Reserves estimates are critical to many of our accounting estimates,
including:
o 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 2006, $169 million of our total $289 million spent on
exploration drilling was expensed. If none of our exploration
drilling had been successful, our net income would have decreased
by $120 million.
o 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 2006, oil and gas depletion
of $741 million was recorded in depletion, depreciation,
amortization and impairment expense. If our reserves estimates
changed by 10%, our depletion, depreciation, amortization and
impairment expense would have changed by approximately $74
million, assuming no other changes to our reserves profiles.
o Assessing, when necessary, our oil and gas assets for impairment.
Estimated future undiscounted cash flows are determined using
proved reserves. The critical estimates used to assess impairment,
including the impact of changes in reserves estimates, are
discussed below.
Since we do not have any loan covenants directly linked to reserves, it
would take a significant decrease in our proved reserves to limit our ability
to borrow money under our term credit facilities, as previously described in
the Liquidity section of the MD&A.
PROPERTY, PLANT AND EQUIPMENT--IMPAIRMENT
We evaluate our long-lived assets (oil and gas properties, Syncrude and
chemicals) for impairment if an adverse event or change occurs. Among other
things, this might include falling oil and gas prices, a significant negative
revision to our reserves estimates, changes in operating and capital costs, or
significant
63
or adverse political changes. If one of these occurs, we assess estimated
undiscounted future cash flows for affected properties to determine if they are
impaired. If the undiscounted future cash flows for a property are less than
the carrying amount of that property, we calculate its fair value using a
discounted cash flow approach. The property is then written down to its fair
value. We assessed our oil and gas assets for impairment at the end of 2006 and
recorded an impairment charge of $93 million, primarily related to two natural
gas producing properties in the Gulf of Mexico.
Cash flow estimates for our impairment assessments require assumptions
about two primary elements--future prices and reserves. Our estimates of future
prices require significant judgments about highly uncertain future events.
Historically, oil and gas prices have exhibited significant volatility--over
the last five years, prices for WTI and NYMEX gas have ranged from US$18/bbl to
US$79/bbl and US$2/mmbtu to US$16/mmbtu, respectively. Our forecasts for oil
and gas revenues are based on prices derived from a consensus of future price
forecasts amongst industry analysts and our own assessments. Our estimates of
future cash flows generally assume our long-term price forecast and forecast
operating and development costs. Given the significant assumptions required and
the possibility that actual conditions will differ, we consider the assessment
of impairment to be a critical accounting estimate. A change in these estimates
would impact all except our chemicals and energy marketing businesses.
It is difficult to determine and assess the impact of a decrease in our
proved reserves on our impairment tests. The relationship between the reserves
estimate and the estimated undiscounted 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 reserves
estimate decrease would have on our assessment of impairment.
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 any damage caused. Estimating
our future asset retirement obligations requires us to make estimates and
judgments with respect to activities that will occur many years into the
future. In addition, the ultimate financial impact of environmental laws and
regulations is not always clearly known and cannot be reasonably estimated as
standards evolve in the countries in which we operate.
We record asset retirement obligations in our Consolidated Financial
Statements by discounting the present value of the estimated retirement
obligations associated with our oil and gas wells and facilities, Syncrude
assets and chemical plants. In arriving at amounts recorded, numerous
assumptions and judgments are made with respect to ultimate settlement amounts,
inflation factors, credit-adjusted discount rates, timing of settlement and
expected changes in legal, regulatory, environmental and political
environments. The asset retirement obligations we have recorded result in an
increase to the carrying cost of our property, plant and equipment. The
obligations are accreted with the passage of time. A change in any one of our
assumptions could impact our asset retirement obligations, the carrying value
of our property, plant and equipment and our net income.
It is difficult to determine the impact of a change in any one of our
assumptions. As a result, we are unable to provide a reasonable sensitivity
analysis of the impact a change in our assumptions would have on our financial
results.
BUSINESS COMBINATION--PURCHASE PRICE ALLOCATION
During the fourth quarter of 2004, we acquired a company operating and
exploring oil and gas properties located in the North Sea. We accounted for
this acquisition using the purchase method of accounting. Under this method, we
were required to record on our Consolidated Balance Sheet the estimated fair
values of the acquired company's assets and liabilities at the acquisition
date. The excess of the purchase price over the fair values of the tangible and
intangible net assets acquired was recorded as goodwill.
We made various assumptions in determining the fair values of the acquired
company's assets and liabilities. The most significant assumptions and
judgments relate to the estimation of the fair value of the oil and gas
properties. To determine the fair value of these properties, we estimated (a)
oil and gas reserves in accordance with our reserve standards, (b) additional
reserves potential and (c) future prices of oil and gas.
Our reserve estimates were based on the work performed by our engineers
and outside consultants. The judgments associated with these estimated reserves
are described earlier in our critical accounting estimates discussion entitled
"Oil and Gas
64
Accounting--Reserves Determination". Our estimates of future prices were based
on prices derived from a consensus of future price forecasts amongst industry
analysts and our own assessments. The judgments associated with these estimates
are described earlier in our critical accounting estimates discussion entitled
"Oil and Gas Accounting--Impairment".
We applied our estimated future prices to the estimated reserves
quantities acquired, and we estimated future operating and development costs,
to arrive at estimated future net revenues for the properties acquired. For
proved properties, we discounted the future net revenues using after-tax
discount rates. The same principles were applied in arriving at the fair value
of unproved properties acquired. These unproved properties generally represent
the value of the probable and possible reserves. Because of their very nature,
probable and possible reserve estimates are more imprecise than those of proved
reserves. To compensate for the inherent risk of estimating and valuing
unproved reserves, an appropriate risk-weighting factor was applied to the
discounted future net revenues of the probable and possible reserves in each
particular instance.
If the fair value allocated to oil and gas properties acquired had been
decreased by $50 million, future income tax liabilities would have decreased by
$20 million and goodwill would have increased by $30 million.
FUTURE INCOME TAXES
We follow the liability method of accounting for income taxes whereby
future income tax assets and liabilities are recognized based on temporary
differences in reported amounts for financial statement and 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 our income tax
provision is inherently complex and we are required to interpret continually
changing regulations and make certain judgments. While income tax filings are
subject to audits and reassessments, we believe we have made adequate provision
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.
NEW ACCOUNTING PRONOUNCEMENTS
CANADIAN PRONOUNCEMENTS
In an effort to harmonize Canadian GAAP with US GAAP, the Canadian
Accounting Standards Board (AcSB) has issued sections:
o 1530, COMPREHENSIVE INCOME;
o 3855, FINANCIAL INSTRUMENTS--RECOGNITION AND MEASUREMENT; and
o 3865, HEDGES.
Under these new standards, all financial assets should be measured at fair
value with the exception of loans, receivables and investments that are
intended to be held to maturity and certain equity investments, which should be
measured at cost. Similarly, all financial liabilities should be measured at
fair value when they are held for trading or they are derivatives.
Gains and losses on financial instruments measured at fair value will be
recognized in the income statement in the periods they arise with the exception
of gains and losses arising from:
o financial assets held for sale, for which unrealized gains and
losses are deferred in other comprehensive income until sold or
impaired; and
o certain financial instruments that qualify for hedge accounting.
Sections 3855 and 3865 make use of "other comprehensive income". Other
comprehensive income comprises revenues, expenses, gains and losses that are
recognized in comprehensive income, but are excluded from net income.
Unrealized gains and losses on qualifying hedging instruments, translation of
self-sustaining foreign operations, and unrealized gains or losses on financial
instruments available for sale will be included in other comprehensive income
and reclassified to net income when realized. Comprehensive income and its
components will be a required disclosure under the new standard.
These new standards are effective for fiscal years beginning on or after
October 1, 2006 and early adoption is permitted. Adoption of these standards as
at December 31, 2006 would have the following impact on our Consolidated
Financial Statements:
INCREASE/
(Cdn$ millions) (DECREASE)
- --------------------------------------------------------------------------------
Accounts Receivable 25
- --------------------------------------------------------------------------------
Future Income Tax Liabilities 7
- --------------------------------------------------------------------------------
Cumulative Foreign Currency Translation Adjustment 161
- --------------------------------------------------------------------------------
Accumulated Other Comprehensive Income (143)
================================================================================
65
In March 2006, the CICA's Emerging Issues Committee (EIC) issued Abstract
160, STRIPPING COSTS INCURRED IN THE PRODUCTION PHASE OF A MINING OPERATION
(EIC-160). EIC-160 outlines accounting for overburden and mine waste materials
removed in the process of accessing mineral deposits according to the benefit
received by the entity. Generally, stripping costs should be accounted for as
variable production costs and included in the costs of inventory produced in
the period the stripping costs are incurred. If it can be shown that the
stripping was for betterment of the mineral property, stripping costs should be
capitalized. The standard outlines the requirement for amortization of
capitalized stripping costs as well as a reconciliation of stripping costs
incurred in the production phase. EIC-160 is effective for fiscal years
beginning on or after July 1, 2006. We do not expect the adoption of EIC-160
will have any material impact on our results of operations or financial
position.
In July 2006, the EIC issued Abstract 162, STOCK-BASED COMPENSATION FOR
EMPLOYEES ELIGIBLE TO RETIRE BEFORE THE VESTING DATE (EIC-162). EIC-162
provides that if an employee is eligible to retire on the grant date of a
stock-based award, related compensation expense is recognized in full at that
date as there is no ongoing service requirement to earn the award. In addition,
if the employee becomes eligible to retire during the vesting period, related
compensation expense is recognized over the period from the grant date to the
retirement eligibility date on a graded vesting basis. EIC-162 is effective for
interim and annual periods ending on or after December 31, 2006. We adopted
EIC-162 on a retroactive basis in the fourth quarter of 2006. For the year
ended December 31, 2006, the impact of adopting EIC-162 decreased general and
administrative expense by $9 million, increased provision for future income
taxes by $3 million, increased net income $6 million, and increased basic and
diluted earnings per share by $0.02/share. For the year ended December 31,
2005, the impact of adopting EIC-162 increased general and administrative
expense by $17 million, decreased provision for future income taxes by $5
million, reduced net income by $12 million, and reduced basic and diluted
earnings per share by $0.05/share. The impact on the year ended December 31,
2004 was immaterial.
In December 2006, the AcSB issued two new Sections in relation to
financial instruments: Section 3862, FINANCIAL INSTRUMENTS - DISCLOSURES, and
Section 3863, FINANCIAL INSTRUMENTS - PRESENTATION. Both sections will become
effective for annual and interim periods beginning on or after October 1, 2007
and will require increased disclosure of financial instruments.
In December 2006, the AcSB issued Section 1535, CAPITAL DISCLOSURES,
requiring disclosure of information about an entity's capital and the
objectives, policies, and processes for managing capital. The standard is
effective for annual periods beginning on or after October 1, 2007.
US PRONOUNCEMENTS
On January 1, 2006, we adopted FASB Statement 123 (revised), SHARE-BASED
PAYMENT (Statement 123(R)) using the modified-prospective approach and
graded-vesting amortization. Under Statement 123(R), our tandem options and
stock appreciation rights are considered liability-based stock compensation
plans. Under the modified-prospective approach, no amounts are restated in
prior periods. Upon adoption of Statement 123(R), we recorded a cumulative
effect of a change in accounting principle of $2 million. This amount was
recorded in general and administrative expenses during the first quarter of
2006 in our US GAAP Consolidated Statement of Income.
Prior to the adoption of Statement 123(R), we accounted for our
liability-based stock compensation plans in accordance with FASB Interpretation
28, ACCOUNTING FOR STOCK APPRECIATION RIGHTS AND OTHER VARIABLE STOCK OPTION OR
AWARD PLANS (the intrinsic-value method). Accordingly, obligations were accrued
on a graded-vesting basis and represented the difference between the market
value of our common shares and the exercise price of underlying options and
rights. Under Statement 123(R), obligations for liability-based stock
compensation plans are measured at their fair value, and are re-measured at
fair value in each subsequent reporting period.
Consistent with Statement 123(R), we account for any stock options that do
not include a cash feature (equity-based stock compensation plans), using the
fair-value method.
66
The impact of adopting Statement 123(R) on our results for the year ended
December 31, 2006 is as follows:
PRIOR TO AFTER
ADOPTION OF ADOPTION OF INCREASE/
(Cdn$ millions, except per share amounts) FAS 123(R) FAS 123(R) (DECREASE)
- --------------------------------------------------------------------------------------------------------------------------
Income from Continuing Operations before Income Taxes--US GAAP 1,306 1,264 (42)
- --------------------------------------------------------------------------------------------------------------------------
Net Income--US GAAP 608 579 (29)
- --------------------------------------------------------------------------------------------------------------------------
Basic Earnings per Common Share--US GAAP ($/share) 2.32 2.21 (0.11)
- --------------------------------------------------------------------------------------------------------------------------
Diluted Earnings per Common Share--US GAAP ($/share) 2.26 2.15 (0.11)
==========================================================================================================================
We recognize stock-based compensation expense for our retired and
retirement-eligible employees over an accelerated graded vesting period in
accordance with the provisions of Statement 123(R) for stock-based awards
granted to employees after December 31, 2005. For stock-based awards granted
prior to the adoption of Statement 123(R), stock-based compensation expense for
our retired and retirement-eligible employees is recognized over a graded
vesting period. If we applied the accelerated vesting provisions of Statement
123(R) to stock-based awards granted to our retired and retirement-eligible
employees prior to the adoption of Statement 123(R), there would be no material
change to our stock-based compensation expense for the three years ended
December 31, 2006.
In February 2006, the FASB issued Statement 155, ACCOUNTING FOR CERTAIN
HYBRID INSTRUMENTS, which amends Statement 133, ACCOUNTING FOR DERIVATIVE
INSTRUMENTS AND HEDGING ACTIVITIES, and Statement 140, ACCOUNTING FOR TRANSFERS
AND SERVICING OF FINANCIAL ASSETS AND EXTINGUISHMENTS OF LIABILITIES. Statement
155 permits fair value re-measurement of hybrid financial instruments that
contain an embedded derivative that otherwise would require bifurcation from
its host contract in accordance with Statement 133. Statement 155 also
clarifies and amends certain other provisions of Statement 133 and Statement
140. This statement is effective for all financial instruments acquired or
issued in fiscal years beginning after September 15, 2006. We do not expect the
adoption of this statement will have a material impact on our results of
operations or financial position.
In July 2006, FASB issued FIN 48 ACCOUNTING FOR UNCERTAINTY IN INCOME
TAXES with respect to FAS 109 ACCOUNTING FOR INCOME TAXES regarding accounting
for and disclosure of uncertain tax positions. FIN 48 seeks to reduce the
diversity in practice associated with certain aspects of the recognition and
measurement related to accounting for income taxes and is effective for fiscal
years beginning after December 15, 2006. Adoption of this standard is expected
to increase our future income tax liabilities by no more than $30 million and
decrease our retained earnings by a corresponding amount.
In September 2006, FASB issued Statement 157, FAIR VALUE MEASUREMENTS.
Statement 157 defines fair value, establishes a framework for measuring fair
value under US generally accepted accounting principles and expands disclosures
about fair value measurements. This statement is effective for fiscal years
beginning after November 15, 2007. We do not expect the adoption of this
statement will have a material impact on our results of operations or financial
position.
In September 2006, FASB issued Statement 158, EMPLOYERS' ACCOUNTING FOR
DEFINED BENEFIT PENSION AND OTHER POSTRETIREMENT PLANS. Statement 158 requires
an employer to recognize the over-funded or under-funded status of a defined
benefit post-retirement plan on the balance sheet as an asset or liability and
to recognize changes in funded status through comprehensive income. This
statement also requires measurement of the funded status of a plan as of the
balance sheet date. The recognition and disclosures under Statement 158 are
required for fiscal years ending after December 15, 2006 while the new
measurement date is effective for fiscal years ending after December 15, 2008.
We adopted the recognition and disclosure provisions at December 31, 2006 in
our US GAAP presentation. We do not expect the adoption of the change in
measurement date in 2008 to have a material impact on our results of operations
or financial position.
67
F I N A N C I A L S T A T E M E N T S
STRONG COMMODITY PRICES AND RECORD RESULTS FROM OUR
MARKETING GROUP RESULTED IN SOLID FINANCIAL RESULTS
FOR 2006. CASH FLOW FROM OPERATING ACTIVITIES WAS A RECORD
$2.4 BILLION, WHILE NET INCOME WAS $601 MILLION.
68
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
PAGE
REPORT OF MANAGEMENT .......................................................85
REPORT OF INDEPENDENT REGISTERED CHARTERED ACCOUNTANTS .....................86
CONSOLIDATED FINANCIAL STATEMENTS
Consolidated Statement of Income ......................................87
Consolidated Balance Sheet ............................................88
Consolidated Statement of Cash Flows ..................................89
Consolidated Statement of Shareholders' Equity ........................90
Notes To Consolidated Financial Statements ............................91
SUPPLEMENTARY DATA (UNAUDITED)
Quarterly Financial Data In Accordance with Canadian and US GAAP .....130
Oil And Gas Producing Activities and Syncrude Operations .............131
69
REPORT OF MANAGEMENT
February 9, 2007
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 generally accepted accounting
principles in Canada with a reconciliation to generally accepted accounting
principles in the US.
We also have responsibility for the preparation and fair presentation of
other financial information in this report and to ensure the consistency of
this information with the financial statements.
We are responsible for the development and implementation of 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 have 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 applicable generally accepted accounting
principles 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 have 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 (the 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 risk. The
Audit Committee is composed entirely of independent directors and includes four
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
considers their independence, reviews their fees and (subject to applicable
securities laws), pre-approves their retention for any permitted non-audit
services and their fee for such services. The internal auditors and independent
registered Chartered Accountants have full and unlimited access to the Audit
Committee, with or without the presence of management.
/s/ Charles W. Fischer /s/ Marvin F. Romanow
- ------------------------- -------------------------------
President and Chief Executive Executive Vice President and
Officer Chief Financial Officer
70
REPORT OF INDEPENDENT REGISTERED CHARTERED ACCOUNTANTS
To the Board of Directors and Shareholders of Nexen Inc.:
We have audited the accompanying consolidated balance sheets of Nexen Inc.
and subsidiaries (the "Company") as of December 31, 2006 and 2005 and the
consolidated statements of income, cash flows and shareholders' equity for each
of the three years in the period ended December 31, 2006. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with Canadian generally accepted
auditing standards and the standards of the Public Company Accounting Oversight
Board (United States). These standards require that we plan and perform the
audit to obtain reasonable assurance about whether the financial statements are
free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, such consolidated financial statements present fairly, in
all material respects, the financial position of Nexen Inc. and subsidiaries as
of December 31, 2006 and 2005 and the results of their operations and their
cash flows for each of the three years in the period ended December 31, 2006 in
conformity with Canadian generally accepted accounting principles.
We have also audited, in accordance with the standards of the Public
Company Accounting Oversight Board (United States), the effectiveness of the
Company's internal control over financial reporting as of December 31, 2006,
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 9, 2007 expressed an unqualified opinion on
management's assessment of the effectiveness of the Company's internal control
over financial reporting and an unqualified opinion on the effectiveness of the
Company's internal control over financial reporting.
Calgary, Canada /s/ DELOITTE & TOUCHE LLP
February 9, 2007 Independent Registered Chartered Accountants
COMMENTS BY INDEPENDENT REGISTERED CHARTERED ACCOUNTANTS ON CANADA-UNITED
STATES OF AMERICA REPORTING DIFFERENCE
The standards of the Public Company Accounting Oversight Board (United
States) require the addition of an explanatory paragraph when there are changes
in accounting principles that have a material effect on the comparability of
the Company's financial statements, such as the change described in Note 1(u)
to the consolidated financial statements. Our report to the board of directors
and shareholders on the consolidated financial statements of the Company dated
February 9, 2007, is expressed in accordance with Canadian reporting standards
which do not require a reference to such changes in accounting principles in
the auditors' report when the change is properly accounted for and adequately
disclosed in the financial statements.
Calgary, Canada /s/ DELOITTE & TOUCHE LLP
February 9, 2007 Independent Registered Chartered Accountants
71
NEXEN INC.
CONSOLIDATED STATEMENT OF INCOME
FOR THE THREE YEARS ENDED DECEMBER 31, 2006
Cdn$ millions, except per share amounts 2006 2005 2004
Note 1(u) Note 1(u)
- ----------------------------------------------------------------------------------------------------------------
Revenues and Other Income
- ----------------------------------------------------------------------------------------------------------------
Net Sales 3,936 3,932 2,944
- ----------------------------------------------------------------------------------------------------------------
Marketing and Other (Note 17) 1,450 702 713
- ----------------------------------------------------------------------------------------------------------------
Gain on Dilution of Interest in Chemicals Business (Note 2) - 193 -
- ----------------------------------------------------------------------------------------------------------------
5,386 4,827 3,657
- ----------------------------------------------------------------------------------------------------------------
Expenses
- ----------------------------------------------------------------------------------------------------------------
Operating 955 893 722
- ----------------------------------------------------------------------------------------------------------------
Depreciation, Depletion, Amortization and Impairment (Note 6) 1,124 1,052 674
- ----------------------------------------------------------------------------------------------------------------
Transportation and Other 1,041 796 549
- ----------------------------------------------------------------------------------------------------------------
General and Administrative 555 809 299
- ----------------------------------------------------------------------------------------------------------------
Exploration 362 250 243
- ----------------------------------------------------------------------------------------------------------------
Interest (Note 8) 53 97 143
- ----------------------------------------------------------------------------------------------------------------
4,090 3,897 2,630
- ----------------------------------------------------------------------------------------------------------------
Income from Continuing Operations before Income Taxes 1,296 930 1,027
- ----------------------------------------------------------------------------------------------------------------
Provision for Income Taxes (Note 18)
- ----------------------------------------------------------------------------------------------------------------
Current 368 339 248
- ----------------------------------------------------------------------------------------------------------------
Future 315 (105) 69
- ----------------------------------------------------------------------------------------------------------------
683 234 317
- ----------------------------------------------------------------------------------------------------------------
Net Income from Continuing Operations before Non-Controlling Interests 613 696 710
- ----------------------------------------------------------------------------------------------------------------
Net Income Attributable to Non-Controlling Interests 12 8 -
- ----------------------------------------------------------------------------------------------------------------
Net Income from Continuing Operations 601 688 710
- ----------------------------------------------------------------------------------------------------------------
Net Income from Discontinued Operations (Note 14) - 452 83
- ----------------------------------------------------------------------------------------------------------------
NET INCOME 601 1,140 793
- ----------------------------------------------------------------------------------------------------------------
EARNINGS PER COMMON SHARE FROM CONTINUING OPERATIONS ($/share)
- ----------------------------------------------------------------------------------------------------------------
Basic (Note 13) 2.29 2.64 2.76
- ----------------------------------------------------------------------------------------------------------------
Diluted (Note 13) 2.24 2.58 2.72
- ----------------------------------------------------------------------------------------------------------------
EARNINGS PER COMMON SHARE ($/share)
- ----------------------------------------------------------------------------------------------------------------
Basic (Note 13) 2.29 4.38 3.08
- ----------------------------------------------------------------------------------------------------------------
Diluted (Note 13) 2.24 4.28 3.04
================================================================================================================
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
72
NEXEN INC.
CONSOLIDATED BALANCE SHEET
DECEMBER 31, 2006 AND 2005
Cdn$ millions, except share amounts 2006 2005
- --------------------------------------------------------------------------------
Note 1(u)
- --------------------------------------------------------------------------------
ASSETS
- --------------------------------------------------------------------------------
Current Assets
- --------------------------------------------------------------------------------
Cash and Cash Equivalents 101 48
- --------------------------------------------------------------------------------
Restricted Cash and Margin Deposits 197 70
- --------------------------------------------------------------------------------
Accounts Receivable (Note 4) 2,951 3,151
- --------------------------------------------------------------------------------
Inventories and Supplies (Note 5) 786 504
- --------------------------------------------------------------------------------
Future Income Tax Assets (Note 18) 479 -
- --------------------------------------------------------------------------------
Other 67 51
- --------------------------------------------------------------------------------
Total Current Assets 4,581 3,824
- --------------------------------------------------------------------------------
Property, Plant and Equipment (Note 6) 11,739 9,594
- --------------------------------------------------------------------------------
Goodwill 377 364
- --------------------------------------------------------------------------------
Future Income Tax Assets (Note 18) 141 410
- --------------------------------------------------------------------------------
Deferred Charges and Other Assets (Note 10) 318 398
- --------------------------------------------------------------------------------
TOTAL ASSETS 17,156 14,590
- --------------------------------------------------------------------------------
LIABILITIES AND SHAREHOLDERS' EQUITY
- --------------------------------------------------------------------------------
Current Liabilities
- --------------------------------------------------------------------------------
Short-Term Borrowings (Note 8) 158 -
- --------------------------------------------------------------------------------
Accounts Payable and Accrued Liabilities 3,879 3,727
- --------------------------------------------------------------------------------
Accrued Interest Payable 55 55
- --------------------------------------------------------------------------------
Dividends Payable 13 13
- --------------------------------------------------------------------------------
Total Current Liabilities 4,105 3,795
- --------------------------------------------------------------------------------
Long-Term Debt (Note 8) 4,673 3,687
- --------------------------------------------------------------------------------
Future Income Tax Liabilities (Note 18) 2,468 1,955
- --------------------------------------------------------------------------------
Asset Retirement Obligations (Note 9) 683 590
- --------------------------------------------------------------------------------
Deferred Credits and Other Liabilities (Note 11) 516 479
- --------------------------------------------------------------------------------
Non-Controlling Interests (Note 2) 75 88
- --------------------------------------------------------------------------------
Shareholders' Equity (Note 12)
- --------------------------------------------------------------------------------
Common Shares, no par value
- --------------------------------------------------------------------------------
Authorized: Unlimited
- --------------------------------------------------------------------------------
Outstanding: 2006--262,513,206 shares 821 732
2005--261,140,571 shares
- --------------------------------------------------------------------------------
Contributed Surplus 4 2
- --------------------------------------------------------------------------------
Retained Earnings 3,972 3,423
- --------------------------------------------------------------------------------
Cumulative Foreign Currency Translation Adjustment (161) (161)
- --------------------------------------------------------------------------------
Total Shareholders' Equity 4,636 3,996
- --------------------------------------------------------------------------------
Commitments, Contingencies and Guarantees (Notes 15 and 18)
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY 17,156 14,590
================================================================================
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
Approved on behalf of the Board:
/s/ Charles W. Fischer /s/ Thomas C. O'Neill
- --------------------------- --------------------------
Director Director
73
NEXEN INC.
CONSOLIDATED STATEMENT OF CASH FLOWS
FOR THE THREE YEARS ENDED DECEMBER 31, 2006
Cdn$ millions 2006 2005 2004
- ------------------------------------------------------------------------------------------------------------------------------
Note 1(u) Note 1(u)
- ------------------------------------------------------------------------------------------------------------------------------
OPERATING ACTIVITIES
- ------------------------------------------------------------------------------------------------------------------------------
Net Income from Continuing Operations 601 688 710
- ------------------------------------------------------------------------------------------------------------------------------
Net Income from Discontinued Operations - 452 83
- ------------------------------------------------------------------------------------------------------------------------------
Charges and Credits to Income not Involving Cash (Note 19) 1,629 1,081 906
- ------------------------------------------------------------------------------------------------------------------------------
Exploration Expense 362 250 243
- ------------------------------------------------------------------------------------------------------------------------------
Changes in Non-Cash Working Capital (Note 19) (177) (195) (122)
- ------------------------------------------------------------------------------------------------------------------------------
Other (41) (133) (214)
- ------------------------------------------------------------------------------------------------------------------------------
2,374 2,143 1,606
- ------------------------------------------------------------------------------------------------------------------------------
FINANCING ACTIVITIES
- ------------------------------------------------------------------------------------------------------------------------------
Proceeds from Long-Term Notes and Debentures (Note 8) - 1,253 1,779
- ------------------------------------------------------------------------------------------------------------------------------
Repayment of Long-Term Notes and Debentures (Note 8) (93) (1,818) (300)
- ------------------------------------------------------------------------------------------------------------------------------
Proceeds from (Repayment of) Term Credit Facilities, Net 1,044 (66) 83
- ------------------------------------------------------------------------------------------------------------------------------
Proceeds from (Repayment of) Short-Term Borrowings, Net 160 (99) 101
- ------------------------------------------------------------------------------------------------------------------------------
Redemption of Preferred Securities - - (289)
- ------------------------------------------------------------------------------------------------------------------------------
Dividends on Common Shares (52) (52) (52)
- ------------------------------------------------------------------------------------------------------------------------------
Issue of Common Shares and Exercise of Options for Shares 48 58 124
- ------------------------------------------------------------------------------------------------------------------------------
Net Proceeds from Canexus Initial Public Offering (Note 2) - 301 -
- ------------------------------------------------------------------------------------------------------------------------------
Proceeds from Term Credit Facilities of Canexus, Net (Notes 2 and 8) 2 176 -
- ------------------------------------------------------------------------------------------------------------------------------
Other (28) (27) (20)
- ------------------------------------------------------------------------------------------------------------------------------
1,081 (274) 1,426
INVESTING ACTIVITIES
- ------------------------------------------------------------------------------------------------------------------------------
Business Acquisitions, Net of Cash Acquired (Note 3) (78) - (2,583)
- ------------------------------------------------------------------------------------------------------------------------------
Capital Expenditures
- ------------------------------------------------------------------------------------------------------------------------------
Exploration and Development (3,198) (2,564) (1,582)
- ------------------------------------------------------------------------------------------------------------------------------
Proved Property Acquisitions (13) (20) (4)
- ------------------------------------------------------------------------------------------------------------------------------
Chemicals, Corporate and Other (119) (54) (95)
- ------------------------------------------------------------------------------------------------------------------------------
Proceeds on Disposition of Assets 27 911 34
- ------------------------------------------------------------------------------------------------------------------------------
Changes in Non-Cash Working Capital (Note 19) 134 (54) 244
- ------------------------------------------------------------------------------------------------------------------------------
Changes in Restricted Cash and Margin Deposits (127) (70) -
- ------------------------------------------------------------------------------------------------------------------------------
Other (14) (13) (27)
- ------------------------------------------------------------------------------------------------------------------------------
(3,388) (1,864) (4,013)
- ------------------------------------------------------------------------------------------------------------------------------
Effect of Exchange Rate Changes on Cash and Cash Equivalents (14) (30) (33)
- ------------------------------------------------------------------------------------------------------------------------------
Increase (Decrease) in Cash and Cash Equivalents 53 (25) (1,014)
- ------------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents--Beginning of Year 48 73 1,087
- ------------------------------------------------------------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS--END OF YEAR 101 48 73
==============================================================================================================================
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
74
NEXEN INC.
CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY
FOR THE THREE YEARS ENDED DECEMBER 31, 2006
Cdn$ millions 2006 2005 2004
- -------------------------------------------------------------------------------------------------------------------------
Note 1(u) Note 1(u)
- -------------------------------------------------------------------------------------------------------------------------
COMMON SHARES (Note 12)
- -------------------------------------------------------------------------------------------------------------------------
Balance at Beginning of Year 732 637 513
- -------------------------------------------------------------------------------------------------------------------------
Issue of Common Shares 32 29 31
- -------------------------------------------------------------------------------------------------------------------------
Proceeds from Options Exercised for Shares 16 29 93
- -------------------------------------------------------------------------------------------------------------------------
Accrued Liability Relating to Options Exercised 41 37 -
- -------------------------------------------------------------------------------------------------------------------------
BALANCE AT END OF YEAR 821 732 637
- -------------------------------------------------------------------------------------------------------------------------
CONTRIBUTED SURPLUS
- -------------------------------------------------------------------------------------------------------------------------
Balance at Beginning of Year 2 - 1
- -------------------------------------------------------------------------------------------------------------------------
Stock-Based Compensation Expense (Note 12) 2 2 2
- -------------------------------------------------------------------------------------------------------------------------
Modification of Stock Option Plan to Tandem Option Plan (Note 12) - - (3)
- -------------------------------------------------------------------------------------------------------------------------
BALANCE AT END OF YEAR 4 2 -
- -------------------------------------------------------------------------------------------------------------------------
RETAINED EARNINGS
- -------------------------------------------------------------------------------------------------------------------------
Balance at Beginning of Year 3,423 2,335 1,594
- -------------------------------------------------------------------------------------------------------------------------
Net Income 601 1,140 793
- -------------------------------------------------------------------------------------------------------------------------
Dividends on Common Shares (52) (52) (52)
- -------------------------------------------------------------------------------------------------------------------------
BALANCE AT END OF YEAR 3,972 3,423 2,335
- -------------------------------------------------------------------------------------------------------------------------
CUMULATIVE FOREIGN CURRENCY TRANSLATION ADJUSTMENT
- -------------------------------------------------------------------------------------------------------------------------
Balance at Beginning of Year (161) (105) (33)
- -------------------------------------------------------------------------------------------------------------------------
Translation Adjustment, Net of Income Taxes - (56) (72)
- -------------------------------------------------------------------------------------------------------------------------
BALANCE AT END OF YEAR (161) (161) (105)
=========================================================================================================================
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
75
NEXEN INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Cdn$ millions, except as noted
1. ACCOUNTING POLICIES
Our Consolidated Financial Statements are prepared in accordance with
Canadian Generally Accepted Accounting Principles (GAAP). The impact of
significant differences between Canadian and United States (US) GAAP on the
Consolidated Financial Statements is disclosed in Note 21.
(a) USE OF ESTIMATES
We make estimates and assumptions that affect the reported amounts of
assets and liabilities and disclosure of contingent assets and liabilities at
the date of the Consolidated Financial Statements, and revenues and expenses
during the reporting period. Our management reviews these estimates, including
those related to accruals, litigation, environmental and asset retirement
obligations, income taxes, derivative contract assets and liabilities and the
determination of proved reserves on an ongoing basis. Changes in facts and
circumstances may result in revised estimates, and actual results may differ
from these estimates.
(b) PRINCIPLES OF CONSOLIDATION
The Consolidated Financial Statements include the accounts of Nexen Inc.
and our subsidiary companies (Nexen, we or our). All subsidiary companies, with
the exception of Canexus LP (see Note 2) and its subsidiaries, are wholly owned
and intercompany accounts and transactions have been eliminated. On August 18,
2005, we sold our chemicals operations to Canexus LP, but retained control of
these operations through our 61.4% interest in Canexus LP. All of the assets,
liabilities and results of operations of Canexus LP and its subsidiaries have
been included in our consolidated financial statements. The non-Nexen ownership
interests in Canexus LP and its subsidiaries are shown as non-controlling
interests. We proportionately consolidate our undivided interests in our oil
and gas exploration, development and production activities conducted under
joint venture arrangements. We also proportionately consolidate our 7.23%
undivided interest in the Syncrude joint venture, which is considered a mining
activity under US regulations. 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 of which are, by
contractual arrangement, jointly controlled by all working interest parties.
(c) ACCOUNTS RECEIVABLE
Accounts receivable are recorded based on our revenue recognition policy
(see Note 1(j)). Our allowance for doubtful accounts provides for specific
doubtful receivables.
(d) INVENTORIES AND SUPPLIES
Inventories and supplies for our oil and gas, marketing and chemicals
operations are stated at the lower of cost and net realizable value. Cost is
determined on the first-in, first-out method or average basis. Inventory costs
include expenditures and other costs, including depreciation, depletion and
amortization, directly or indirectly incurred in bringing the inventory to its
existing condition.
(e) PROPERTY, PLANT AND EQUIPMENT (PP&E)
Property, plant and equipment is recorded at cost and includes only
recoverable costs that directly result in an identifiable future benefit.
Unrecoverable costs, maintenance and turnaround costs are expensed as incurred.
Improvements that increase capacity or extend the useful lives of the related
assets are capitalized to PP&E.
We follow successful efforts accounting for our oil and gas business. All
property acquisition costs are initially capitalized to PP&E as unproved
property costs. Once proved reserves are discovered, the acquisition costs are
reclassified to proved property
76
acquisition costs. Exploration drilling costs are capitalized pending evaluation
as to whether sufficient quantities of reserves have been found to justify
commercial production. If commercial quantities of reserves are not found,
exploration drilling costs are expensed. All exploratory wells are evaluated for
commercial viability on a regular basis following completion of drilling.
Exploration drilling costs remain capitalized when a well has found a sufficient
quantity of reserves to justify its completion as a producing well and
sufficient progress is being made to assess the reserves and the economic and
operating viability of the well. All other exploration costs, including
geological and geophysical and annual lease rentals, are expensed to earnings as
incurred. All development costs are capitalized as proved property costs.
General and administrative costs that directly relate to acquisition,
exploration and development activities are capitalized to PP&E.
PP&E for our Syncrude operation is recorded at cost and includes only
recoverable costs that directly result in an identifiable future benefit.
Unrecoverable costs, maintenance and turnaround costs are expensed as incurred.
Improvements that increase capacity or extend the useful lives of the related
assets are capitalized to PP&E.
We engage in research and development activities to develop or improve
processes and techniques to extract oil and gas. Research involves
investigating 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
commencement of commercial operations or production. Otherwise, development
costs are expensed as incurred. Development costs include pre-operating
revenues and costs.
(f) DEPRECIATION, DEPLETION, AMORTIZATION AND IMPAIRMENT (DD&A)
Under successful efforts accounting, we deplete oil and gas capitalized
costs using the unit-of-production method. Development and exploration drilling
and equipping costs are depleted over remaining proved developed reserves and
proved property acquisition costs over remaining proved reserves. Depletion is
considered a cost of inventory when the oil and gas is produced. When this
inventory is sold, the depletion is charged to DD&A expense.
Our Syncrude PP&E is depleted using the unit-of-production method.
Capitalized costs are depleted over proved and probable reserves within
developed areas of interest.
We depreciate other plant and equipment costs, including our chemicals
facilities, using the straight-line method based on the estimated useful lives
of the assets, which range from 3 years to 30 years. Unproved property costs
and major projects that are under construction or development are not
depreciated, depleted or amortized.
We evaluate the carrying value of our PP&E whenever events or conditions
occur that indicate that the carrying value of properties on our balance sheet
may not be recoverable from future cash flows. These events or conditions occur
periodically. If carrying value exceeds the sum of undiscounted future cash
flows, the property's value is impaired. The property is then assigned a fair
value equal to its estimated total future cash flows, discounted for the time
value of money, and we expense the excess carrying value to depreciation,
depletion, amortization and impairment. Our cash flow estimates require
assumptions about future commodity prices, operating costs and other factors.
Actual results can differ from these estimates.
In assessing the carrying values of our unproved properties, we take into
account our future plans for these properties, the remaining terms of the
leases and any other factors that may be indicators of potential impairment.
(g) 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 are recorded in operating expense when incurred and capital costs are
recorded in PP&E and expensed to DD&A in the year recovered. All recoveries are
recorded as revenue in the year of recovery.
77
(h) ASSET RETIREMENT OBLIGATIONS
We provide for future asset retirement obligations on our resource
properties, facilities, production platforms, pipelines and chemicals
facilities based on estimates established by current legislation and industry
practices. The asset retirement obligation is initially measured at fair value
and capitalized to PP&E as an asset retirement cost. The asset retirement
obligation accretes until the time the retirement obligation is expected to
settle, while the asset retirement cost is amortized over the useful life of
the underlying PP&E. We periodically review our estimates for changes in
expected amounts or timing of cash flows.
The amortization of the asset retirement cost and the accretion of the
asset retirement obligation are included in depreciation, depletion,
amortization and impairment. Actual retirement costs are recorded against the
obligation when incurred. Any difference between the recorded asset retirement
obligation and the actual retirement costs incurred is recorded as a gain or
loss in the period of settlement.
(i) GOODWILL
Goodwill is recorded at cost and is not amortized. We test goodwill for
impairment annually based on estimated future cash flows of the reporting unit
to which the goodwill is attributable. In addition, we test goodwill for
impairment whenever an event or circumstance occurs that may reduce the fair
value of a reporting unit below its carrying amount. If our goodwill is
impaired, we write it down to its implied fair value, based on the fair value
of the assets and liabilities of the underlying reporting unit. Our goodwill is
attributable to our marketing and UK reporting units.
(j) REVENUE RECOGNITION
CRUDE OIL AND NATURAL GAS
Revenue from the production of crude oil and natural gas is recognized
when title passes to the customer. In Canada, the US and the UK, our customers
primarily take title when the crude oil and natural gas reaches the end of the
pipeline. For our other international operations, our customers take title when
the crude oil is loaded onto the tanker. When we produce or sell more or less
oil or natural gas than our share, production overlifts and underlifts occur.
We record overlifts as liabilities and underlifts as assets. 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 payments
to governments and other mineral interest owners. For our international
operations, all government interests, except for income taxes, are considered
royalty payments. Our revenue also includes the recovery of costs paid on
behalf of foreign governments in international locations. See Note 1(g).
CHEMICALS
Revenue from our chemicals operations is only recognized when our products
are delivered to our customers. Delivery only takes place when we have a sales
contract in place specifying delivery volumes and sales prices. We assess
customer credit worthiness before entering into sales contracts to minimize
collection risk.
MARKETING
Substantially all of the physical purchase and sales contracts entered
into by our marketing operation are considered to be derivative instruments.
Accordingly, financial and physical commodity contracts (collectively
derivative instruments) held by our marketing operation are stated at fair
value on the balance sheet unless the requirements for hedge accounting are met
(see Note 1(n)). We record any change in fair value as a gain or loss in
marketing and other.
Any margin realized by our marketing operation on the sale of our
proprietary oil and gas production is included in marketing and other. Sales of
our proprietary production are recorded at monthly market-based prices and
intercompany profits and losses between segments are eliminated. We assess
customer credit worthiness before entering into contracts and provide for
netting terms to minimize collection risk. Amounts are recorded on a net basis
where we have the legal right of offset.
78
(k) INCOME TAXES
We follow the liability method of accounting for income taxes (see Note
18). This method recognizes income tax assets and liabilities at current rates,
based on temporary differences in reported amounts for financial statement and
tax purposes. The effect of a change in income tax rates on future income tax
assets and future income tax liabilities is recognized in income when
substantively enacted.
We do not provide for foreign withholding taxes on the undistributed
earnings of our foreign subsidiaries, as we intend to invest such earnings
indefinitely in foreign operations.
(l) FOREIGN CURRENCY TRANSLATION
Our foreign operations, which are considered financially and operationally
independent, are translated from their functional currency into Canadian
dollars as follows:
o assets and liabilities using exchange rates at the balance sheet
dates; and
o revenues and expenses using average exchange rates throughout the
year.
Gains and losses resulting from this translation are included in the
cumulative foreign currency translation adjustment in shareholders' equity.
Monetary balances 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, except on our
designated US-dollar debt, are included in income. We have designated our
US-dollar debt as a hedge against our net investment in US-dollar based
self-sustaining foreign operations. Gains and losses resulting from the
translation of the designated US-dollar debt are included in the cumulative
foreign currency translation adjustment in shareholders' equity. If our
US-dollar debt, net of income taxes, exceeds our US-dollar investment in
foreign operations, then the gains or losses attributable to such excess are
included in marketing and other in the Consolidated Statement of Income.
(m) CAPITALIZED INTEREST
We capitalize interest on major development projects until the project is
substantially complete using the weighted-average interest rate on all of our
borrowings. Capitalized interest cannot exceed the actual interest incurred.
(n) DERIVATIVE INSTRUMENTS
NON-TRADING ACTIVITIES
We use derivative instruments such as physical purchase and sales
contracts, forwards, futures, swaps and options for non-trading purposes to
manage fluctuations in commodity prices, foreign currency exchange rates and
interest rates (see Note 7). We record these instruments at fair value at the
balance sheet date and record any change in fair value as a net gain or loss in
marketing and other during the period of change unless the requirements for
hedge accounting are met. Hedge accounting is used 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. We recognize gains
and losses on the derivative instruments designated as hedges in the same
period as the gains or losses on the hedged items are recognized. If effective
correlation ceases, hedge accounting is terminated, and future changes in the
market value of the derivative instrument are included as gains or losses in
marketing and other in the period of change.
TRADING ACTIVITIES
Our marketing operation uses derivative instruments for marketing and
trading crude oil and natural gas including:
o commodity contracts settled with physical delivery;
o exchange-traded futures and options; and
o non-exchange traded forwards, swaps and options.
We record these instruments at fair value at the balance sheet date and
record changes in fair value as net gains or losses in marketing and other
during the period of change. The fair value of these instruments is recorded as
accounts receivable or
79
payable if we anticipate settling the instruments within a year of the balance
sheet date. If we anticipate settling the instruments beyond 12 months, we
record them as deferred charges and other assets or deferred credits and other
liabilities.
(o) EMPLOYEE FUTURE BENEFITS
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. Past service costs arising
from plan amendments, and net actuarial gains and losses that exceed 10% of the
greater of the accrued benefit obligation and the fair value of plan assets,
are expensed in equal amounts over the expected average remaining service life
of the employee group. We measure the plan assets and the accrued benefit
obligation on October 31 each year.
(p) STOCK-BASED COMPENSATION
In 2003, we adopted the fair-value method of accounting for stock options
granted to employees and directors. We recorded stock-based compensation
expense in the Consolidated Statement of Income as general and administrative
expenses for all options granted on or after January 1, 2003, with a
corresponding increase to contributed surplus. Compensation expense for options
granted was based on estimated fair values at the time of grant and we
recognized the expense over the vesting period of the option.
In May 2004, we modified our stock option plan to a tandem option plan by
including a cash feature. The tandem options give the holders a right to either
purchase common shares at the exercise price or to receive cash payments equal
to the excess of the market value of the common shares over the exercise price.
As a result of the modification, we record obligations for the tandem options
using the intrinsic-value method of accounting and recognize compensation
expense. Obligations are accrued on a graded vesting basis and represent the
difference between the market value of our common shares and the exercise price
of the options. The obligations are revalued each reporting period based on the
change in the market value of our common shares and the number of graded vested
options outstanding. We reduce the liability when the options are surrendered
for cash. When the options are exercised for stock, the recorded liability
amount is transferred to share capital.
Stock options awarded to our US employees between December 1, 2004 and
December 1, 2005 do not include a cash feature and are not accounted for as
tandem options. Instead, we account for these options using the fair-value
method. Compensation expense is based on estimated fair values at the time of
grant and is recognized over the vesting period of the options. The expense is
included as general and administrative expense with a corresponding increase to
contributed surplus. Stock options awarded to our US employees after December
1, 2005 are accounted for as tandem options.
We provide stock appreciation rights to employees as described in Note 12,
and we account for these on the same basis as our tandem options. Obligations
are accrued as compensation expense over the graded vesting period of the stock
appreciation rights.
(q) CASH AND CASH EQUIVALENTS
Cash and cash equivalents include short-term, highly liquid investments
that mature within three months of their purchase. They are recorded at cost,
which approximates market value.
(r) RESTRICTED CASH AND MARGIN DEPOSITS
Restricted cash includes margin deposits relating to our exchange-traded
derivative contracts and other cash balances subject to regulatory
restrictions.
(s) LEASES
We classify leases entered into as either capital or operating leases.
Leases that transfer substantially all of the benefits and risks of ownership
to us are accounted for as capital leases and the related assets are included
with PP&E. These assets are depreciated on the same basis as other PP&E. Rental
payments under operating leases are expensed as incurred.
80
(t) TRANSPORTATION
We pay to transport the crude oil, natural gas and chemicals products that
we market, and then bill our customers for the transportation. This
transportation is presented in our Consolidated Financial Statements as a cost
to us and is recorded as transportation and other. Our marketing operation has
received cash payments in exchange for assuming certain transportation
obligations from third parties. These cash payments have been recorded as
deferred liabilities and are recognized in net income as the transportation is
used.
(u) CHANGES IN ACCOUNTING PRINCIPLES
STOCK-BASED COMPENSATION FOR EMPLOYEES ELIGIBLE TO RETIRE BEFORE THE VESTING
DATE
In the fourth quarter of 2006, we retroactively adopted EIC-162,
STOCK-BASED COMPENSATION FOR EMPLOYEES ELIGIBLE TO RETIRE BEFORE THE VESTING
DATE (EIC-162). EIC-162 provides that if an employee is eligible to retire on
the grant date of a stock-based award, related compensation expense is
recognized in full at that date as there is no ongoing service requirement to
earn the award. In addition, if an employee becomes eligible to retire during
the vesting period, related compensation expense is recognized over the period
from the grant date to the retirement eligibility date on a graded vesting
basis. Prior to the adoption of EIC-162, we did not consider the retirement
dates of our employees in the determination of our stock-based compensation
expense. EIC-162 is effective for interim and annual periods ending on or after
December 31, 2006 and is to be adopted on a retroactive basis. For the year
ended December 31, 2006, the impact of adopting EIC-162 decreased general and
administrative expense by $9 million, increased provision for future income
taxes by $3 million, increased net income by $6 million, and increased basic
and diluted earnings per share by $0.02/share. For the year ended December 31,
2005, the impact of adopting EIC-162 increased general and administrative
expense by $17 million, decreased provision for future income taxes by $5
million, reduced net income by $12 million, and reduced basic and diluted
earnings per share by $0.05/share. The impact on the year ended December 31,
2004 was immaterial.
2. CANEXUS INCOME FUND
In June 2005, our board of directors approved a plan to monetize our
chemicals operations through the creation of an income trust and the issuance
of trust units in an initial public offering. This initial public offering
closed on August 18, 2005, with Canexus Income Fund (Canexus) issuing 30
million units at a price of $10 per unit for gross proceeds of $300 million
($284 million, net of underwriters' commissions).
Concurrent with the closing of the offering, Canexus acquired a 36.5%
interest in Canexus Limited Partnership (Canexus LP) using the net proceeds
from the initial public offering. Canexus LP acquired Nexen's chemicals
business for approximately $1 billion, comprised of the net proceeds from
Canexus' initial public offering and $200 million (US$167 million) of bank
debt, plus the issuance of 52.3 million exchangeable limited partnership units
(Exchangeable LP Units) of Canexus LP. At that time, the Exchangeable LP Units
held by Nexen represented a 63.5% interest in Canexus LP.
The Exchangeable LP Units held by Nexen are exchangeable on a one-for-one
basis for trust units of Canexus. As a result, the Exchangeable LP Units owned
by Nexen were exchangeable into 52.3 million trust units which represented
63.5% of the outstanding trust units of Canexus assuming exchange of the
Exchangeable LP Units.
On September 16, 2005, the underwriters of the initial public offering
exercised a portion of their over-allotment option to purchase 1.75 million
trust units at $10 per unit for gross proceeds of $18 million ($17 million, net
of underwriters' commissions). As a result, Nexen exchanged 1.75 million of its
Exchangeable LP Units for $17 million in net proceeds. After this exchange,
Nexen has a 61.4% interest in Canexus LP represented by 50.5 million
Exchangeable LP Units. The initial public offering, together with the exercise
of the over-allotment, resulted in total net proceeds to Nexen of $301 million.
These transactions diluted our interest in our chemicals operations. As a
result of this dilution, we recorded a gain of $193 million during the third
quarter of 2005.
We have the right to nominate a majority of the members of the board of
Canexus Limited, the corporation with responsibility for the strategic
management and operational decisions of Canexus and Canexus LP. Nexen currently
has nominated two representatives to the 10-member board of Canexus Limited.
Since we have retained effective control of our chemicals business, the
81
results, assets and liabilities of this business have been included in these
financial statements. The non-Nexen ownership interests in our chemicals
business are shown as non-controlling interests.
During the year $28 million (2005 - $10 million) of distributions were
paid to non-Nexen ownership interests.
3. BUSINESS ACQUISITIONS
In 2006, we completed minor business acquisitions related to our marketing
group for $78 million, net of cash acquired. These acquisitions were accounted
for using the purchase method of accounting. The assets and liabilities
purchased were primarily working capital and we recorded goodwill of $12
million as a result of the acquisitions.
On December 1, 2004, we acquired 100% of the issued and outstanding share
capital of EnCana (UK) Limited (EnCana UK) from EnCana Corporation (EnCana) for
cash consideration of US$2.1 billion, subject to certain adjustments. EnCana UK
held all of EnCana's offshore oil and gas assets in the North Sea. We acquired
EnCana UK to establish a strategic presence in the North Sea by acquiring
operatorship of the Buzzard field development and operatorship of the producing
Scott and Telford fields. The acquisition also gave us access to interests in
several satellite discoveries and more than 700,000 net undeveloped exploration
acres. In addition, we acquired the management and technical teams that found
and are developing the Buzzard discovery. Goodwill paid was attributable to the
established North Sea presence acquired and the knowledge and business
relationships acquired through the management team and employees of EnCana UK.
The acquisition has been accounted for using the purchase method, and the
results of EnCana UK have been consolidated with the results of Nexen from
December 1, 2004. The following table shows the allocation of the purchase
price based on the estimated fair values of the assets and liabilities
acquired:
Purchase Price, Net of Cash Acquired:
- -------------------------------------------------------------------------------
Cash Paid 2,561
- -------------------------------------------------------------------------------
Transaction Costs 22
- -------------------------------------------------------------------------------
TOTAL PURCHASE PRICE 2,583
===============================================================================
Purchase Price Allocated as follows:
- -------------------------------------------------------------------------------
Accounts Receivable 310
- -------------------------------------------------------------------------------
Inventories and Supplies 11
- -------------------------------------------------------------------------------
Other Current Assets 2
- -------------------------------------------------------------------------------
Property, Plant and Equipment 3,395
- -------------------------------------------------------------------------------
Future Income Tax Assets 239
- -------------------------------------------------------------------------------
Goodwill (1) 334
- -------------------------------------------------------------------------------
Deferred Charges and Other Assets 12
- -------------------------------------------------------------------------------
Accounts Payable and Accrued Liabilities (289)
- -------------------------------------------------------------------------------
Asset Retirement Obligations (134)
- -------------------------------------------------------------------------------
Future Income Tax Liabilities (1,284)
- -------------------------------------------------------------------------------
Deferred Credits and Other Liabilities (13)
- -------------------------------------------------------------------------------
TOTAL PURCHASE PRICE ALLOCATED 2,583
===============================================================================
NOTE:
(1) THE AMOUNT OF GOODWILL DEDUCTIBLE FOR TAX PURPOSES IS NIL.
The unaudited pro forma results for the year ended December 31, 2004 are
shown below as if the acquisition had occurred on January 1, 2004. Pro forma
results are not necessarily indicative of actual results or future performance.
2004
- -------------------------------------------------------------------------------
Revenues 4,258
- -------------------------------------------------------------------------------
Net Income 841
- -------------------------------------------------------------------------------
Earnings Per Common Share--Basic ($/share) 3.27
- -------------------------------------------------------------------------------
Earnings Per Common Share--Diluted ($/share) 3.23
===============================================================================
82
4. ACCOUNTS RECEIVABLE
2006 2005
- ---------------------------------------------------------------------------------------------------------------
Trade
- ---------------------------------------------------------------------------------------------------------------
Marketing 2,226 2,400
- ---------------------------------------------------------------------------------------------------------------
Oil and Gas 600 614
- ---------------------------------------------------------------------------------------------------------------
Chemicals and Other 58 48
- ---------------------------------------------------------------------------------------------------------------
2,884 3,062
- ---------------------------------------------------------------------------------------------------------------
Non-Trade 80 96
- ---------------------------------------------------------------------------------------------------------------
2,964 3,158
- ---------------------------------------------------------------------------------------------------------------
Allowance for Doubtful Receivables (13) (7)
===============================================================================================================
TOTAL ACCOUNTS RECEIVABLE 2,951 3,151
- -------------------------------------------------------------------------------- ------------------------------
5. INVENTORIES AND SUPPLIES
2006 2005
- ---------------------------------------------------------------------------------------------------------------
Finished Products
- ---------------------------------------------------------------------------------------------------------------
Marketing 609 320
- ---------------------------------------------------------------------------------------------------------------
Oil and Gas 21 11
- ---------------------------------------------------------------------------------------------------------------
Chemicals and Other 14 15
- ---------------------------------------------------------------------------------------------------------------
644 346
- ---------------------------------------------------------------------------------------------------------------
Work in Process 5 6
- ---------------------------------------------------------------------------------------------------------------
Field Supplies 137 152
- ---------------------------------------------------------------------------------------------------------------
TOTAL INVENTORIES AND SUPPLIES 786 504
===============================================================================================================
6. PROPERTY, PLANT AND EQUIPMENT
2006 2005
ACCUMULATED NET BOOK ACCUMULATED NET BOOK
COST DD&A VALUE COST DD&A VALUE
- -----------------------------------------------------------------------------------------------------------------
Oil and Gas
- -----------------------------------------------------------------------------------------------------------------
Yemen 779 599 180 833 546 287
- -----------------------------------------------------------------------------------------------------------------
Yemen--Carried Interest 1,625 1,529 96 1,410 1,295 115
- -----------------------------------------------------------------------------------------------------------------
Canada 5,216 1,448 3,768 3,631 1,311 2,320
- -----------------------------------------------------------------------------------------------------------------
United States 2,889 1,445 1,444 2,437 1,159 1,278
- -----------------------------------------------------------------------------------------------------------------
United Kingdom 4,710 432 4,278 4,013 216 3,797
- -----------------------------------------------------------------------------------------------------------------
Other Countries 249 78 171 249 119 130
- -----------------------------------------------------------------------------------------------------------------
15,468 5,531 9,937 12,573 4,646 7,927
- -----------------------------------------------------------------------------------------------------------------
Marketing 226 47 179 177 72 105
- -----------------------------------------------------------------------------------------------------------------
Syncrude 1,304 179 1,125 1,240 171 1,069
- -----------------------------------------------------------------------------------------------------------------
Chemicals 854 494 360 827 456 371
- -----------------------------------------------------------------------------------------------------------------
Corporate and Other 286 148 138 245 123 122
- -----------------------------------------------------------------------------------------------------------------
TOTAL PP&E 18,138 6,399 11,739 15,062 5,468 9,594
=================================================================================================================
The above table includes capitalized costs of $6,708 million (2005--$5,211
million) relating to unproved properties and projects under construction or
development. These costs are not being depreciated, depleted or amortized.
These costs include $2,399 million related to our Buzzard project in the North
Sea that began operations in January 2007.
83
Our Syncrude operations are considered a mining operation for US reporting
purposes. PP&E at December 31, 2006 and 2005 includes mineral rights of $6
million.
DEPRECIATION, DEPLETION, AMORTIZATION AND IMPAIRMENT (DD&A)
Our 2006 DD&A expense includes $93 million of impairment expense,
primarily related to two natural gas producing properties in the Gulf of
Mexico. The impairment was caused by unsuccessful development programs and
negative year-end reserve revisions. The carrying values of the impaired
properties have been reduced to their estimated fair value. In addition, our
2006 DD&A expense includes $15 million (2005 - $58 million) relating to the
write down of a portion of our purchase price allocation to unproved properties
purchased in the North Sea as a result of unsuccessful exploration activities.
RESEARCH AND DEVELOPMENT
We incurred $53 million (2005--$54 million) in connection with research
and development activities related to developing new technologies for
increasing oil recoveries. Research costs of $50 million (2005--$44 million)
were included in other expense on the Consolidated Statement of Income. The
development costs have been deferred and are included in PP&E.
2006 2005
- ------------------------------------------------------------------------------------------------------
Development Costs Deferred, Beginning of Year 25 15
- ------------------------------------------------------------------------------------------------------
Deferred in the Year 3 10
- ------------------------------------------------------------------------------------------------------
Amortized in the Year - -
- ------------------------------------------------------------------------------------------------------
DEVELOPMENT COSTS DEFERRED, END OF YEAR 28 25
======================================================================================================
SUSPENDED WELL COSTS
The following table shows the changes in capitalized exploratory well
costs during the years ended December 31, 2006 and 2005, and does not include
amounts that were initially capitalized and subsequently expensed in the same
period.
2006 2005
- ------------------------------------------------------------------------------------------------------
Balance at Beginning of Year 252 116
- ------------------------------------------------------------------------------------------------------
Additions to Capitalized Exploratory Well Costs Pending the
Determination of Proved Reserves 129 174
- ------------------------------------------------------------------------------------------------------
Capitalized Exploratory Well Costs Charged to Expense (70) (27)
- ------------------------------------------------------------------------------------------------------
Transfers to Wells, Facilities and Equipment Based on Determination
of Proved Reserves (84) (3)
- ------------------------------------------------------------------------------------------------------
Effects of Foreign Exchange (1) (8)
- ------------------------------------------------------------------------------------------------------
BALANCE AT END OF YEAR 226 252
======================================================================================================
The following table provides an aging of capitalized exploratory well
costs based on the date drilling was completed and shows the number of projects
for which exploratory well costs have been capitalized for a period greater
than one year after the completion of drilling.
2006 2005
- -----------------------------------------------------------------------------------------------------
Capitalized for a Period of One Year or Less 179 165
- -----------------------------------------------------------------------------------------------------
Capitalized for a Period of Greater than One Year 47 87
- -----------------------------------------------------------------------------------------------------
BALANCE AT END OF YEAR 226 252
=====================================================================================================
Number of Projects that have Exploratory Well Costs Capitalized for a Period
Greater than One Year 4 3
=====================================================================================================
As at December 31, 2006, we have exploratory costs that have been
capitalized for more than one year relating to our interest in an exploratory
block, offshore Nigeria ($14 million), our interest in an exploratory block in
the Gulf of Mexico ($16 million), our coalbed methane exploratory activities in
Canada ($10 million) and an exploratory block in the North Sea ($7 million).
Our
84
capitalized costs in Nigeria include capital spending for four successful
wells. Development plans are currently being prepared for this area. We have
capitalized costs related to successful wells drilled in the Gulf of Mexico and
the North Sea. In Canada, we have capitalized exploratory costs relating to our
coalbed methane projects. We are assessing all of these wells and projects, and
we are working with our partners to prepare development plans.
7. DERIVATIVE INSTRUMENTS AND FINANCIAL RISK MANAGEMENT
(a) CARRYING VALUE AND ESTIMATED FAIR VALUE OF DERIVATIVE AND FINANCIAL
INSTRUMENTS
The carrying values, fair values and unrecognized gains or losses on our
outstanding derivatives and long-term financial assets and liabilities at
December 31 are:
2006 2005
CARRYING UNRECOGNIZED CARRYING UNRECOGNIZED
VALUE FAIR VALUE GAIN (LOSS) VALUE FAIR VALUE GAIN (LOSS)
- ------------------------------------------------------------------------------------------------------------------------------
COMMODITY PRICE RISK
- ------------------------------------------------------------------------------------------------------------------------------
Non-Trading Activities
- ------------------------------------------------------------------------------------------------------------------------------
Crude Oil Put Options 19 19 - 4 4 -
- ------------------------------------------------------------------------------------------------------------------------------
Fixed-Price Natural Gas
Contracts (96) (96) - (175) (175) -
- ------------------------------------------------------------------------------------------------------------------------------
Natural Gas Swaps (8) (8) - 29 29 -
- ------------------------------------------------------------------------------------------------------------------------------
Trading Activities
- ------------------------------------------------------------------------------------------------------------------------------
Crude Oil and Natural Gas 372 372 - 161 161 -
- ------------------------------------------------------------------------------------------------------------------------------
Future Sale of Gas
Inventory - 25 25 - (35) (35)
- ------------------------------------------------------------------------------------------------------------------------------
FOREIGN CURRENCY RISK
- ------------------------------------------------------------------------------------------------------------------------------
Non-Trading Activities - - - 14 14 -
- ------------------------------------------------------------------------------------------------------------------------------
Trading Activities (12) (12) - 8 8 -
- ------------------------------------------------------------------------------------------------------------------------------
TOTAL DERIVATIVES 275 300 25 41 6 (35)
==============================================================================================================================
FINANCIAL ASSETS AND LIABILITIES
Long-Term Debt (4,673) (4,728) (55) (3,687) (3,863) (176)
==============================================================================================================================
The estimated fair value of all derivative instruments is based on quoted
market prices and, if not available, on estimates from third-party brokers or
dealers. The carrying value of cash and cash equivalents, restricted cash,
margin deposits, amounts receivable and short-term obligations approximates
their fair value because the instruments are near maturity.
(b) COMMODITY PRICE RISK MANAGEMENT
NON-TRADING ACTIVITIES
We generally sell our crude oil and natural gas under short-term
market-based contracts.
Crude oil put options
In 2006, we purchased WTI crude oil put options to provide a base level of
price protection without limiting our upside to higher prices. These options
establish an annual average WTI floor price of US$50/bbl in 2007 on 105,000
bbls/d at a cost of $26 million. In 2004, we purchased WTI crude oil put
options to manage the commodity price risk exposure of a portion of our oil
production in 2006 and 2005. These options established an annual average WTI
floor price of US$38/bbl in 2006 and US$43/bbl in 2005 at a cost of $144
million. The 2006 and 2005 WTI crude oil put options were not used and have
expired. The 2007
85
WTI crude oil put options are stated at fair value and are included in deferred
charges and other assets as they settle beyond 12 months from December 31,
2006. Any change in fair value is included in marketing and other on the
Consolidated Statement of Income.
NOTIONAL AVERAGE
VOLUMES TERM PRICE (WTI) FAIR VALUE
(bbls/d) (US$/bbl) (Cdn$ millions)
- -----------------------------------------------------------------------------------------------------------
WTI Crude Oil Put Options 105,000 2007 50 19
===========================================================================================================
Fixed price natural gas contracts and natural gas swaps
In July and August 2005, we sold certain Canadian oil and gas properties,
and we retained fixed-price natural gas sales contracts that were previously
associated with those properties (see Note 14). Since these contracts are no
longer used in the normal course of our oil and gas operations, they have been
included in our Consolidated Balance Sheet at fair value. Any change in fair
value is included in marketing and other in the Consolidated Statement of
Income.
NOTIONAL
VOLUMES TERM PRICE FAIR VALUE
(Gj/d) ($/Gj) (Cdn$ millions)
- -----------------------------------------------------------------------------------------------------------
Fixed-Price Natural Gas Contracts 15,514 2007 2.46 (22)
- -----------------------------------------------------------------------------------------------------------
15,514 2008-2010 2.56-2.77 (74)
- -----------------------------------------------------------------------------------------------------------
(96)
===========================================================================================================
Following the sale of the Canadian oil and gas properties, we entered into
natural gas swaps to economically hedge our exposure to the fixed-price natural
gas contracts. Any change in fair value is included in marketing and other in
the Consolidated Statement of Income.
NOTIONAL
VOLUMES TERM PRICE FAIR VALUE
(Gj/d) ($/Gj) (Cdn$ millions)
- -----------------------------------------------------------------------------------------------------------
Natural Gas Swaps 15,514 2007 7.60 (6)
- -----------------------------------------------------------------------------------------------------------
15,514 2008-2010 7.60 (2)
- -----------------------------------------------------------------------------------------------------------
(8)
===========================================================================================================
TRADING ACTIVITIES
Crude oil and natural gas
We enter into physical purchase and sales contracts as well as financial
commodity contracts to enhance our price realizations and lock-in our margins.
The physical and financial commodity contracts (derivative contracts) are
stated at market value. The $372 million fair value of the commodity contracts
at December 31, 2006 is included in the Consolidated Balance Sheet and any
change in fair value is included in marketing and other in the Consolidated
Statement of Income.
Future sale of gas inventory
We have certain NYMEX futures contracts and swaps in place, which
effectively lock-in our margins on the future sale of our natural gas inventory
in storage. We have designated, in writing, some of these derivative contracts
as cash flow hedges of the
86
future sale of our storage inventory. As a result, gains and losses on these
designated futures contracts and swaps are recognized in net income when the
inventory in storage is sold. The principal terms of these outstanding
contracts and the unrecognized gains at December 31, 2006 are:
HEDGED AVERAGE UNRECOGNIZED
VOLUMES MONTH PRICE GAIN
(mmbtu) (US$/mcf) (Cdn$ millions)
- ----------------------------------------------------------------------------------------------------------
NYMEX Natural Gas Futures 5,580,000 January 2007 10.73 25
==========================================================================================================
In late 2006, we de-designated certain futures contracts that had been
designated as cash flow hedges of future sales of our natural gas in storage.
These contracts were de-designated since it became uncertain that the future
sales of natural gas would occur within the designated time frame. As it is
reasonably possible that the future sales may take place as designated at the
inception of the hedging relationship, gains of $65 million on the futures
contracts have been deferred and will be recognized in net income in 2007 in
the originally designated time frame.
(c) FOREIGN CURRENCY EXCHANGE RATE RISK MANAGEMENT
NON-TRADING ACTIVITIES
US dollar call options--Canexus
The operations of Canexus are exposed to changes in the US-dollar exchange
rate as a portion of its sales are denominated in US dollars. Canexus
periodically purchases US-dollar call options to reduce this exposure to
fluctuations in the Canadian-US dollar exchange rate. Under outstanding option
contracts at December 31, 2006, Canexus LP had the right to sell US$5 million
monthly and purchase Canadian dollars at an exchange rate of US$0.85 for the
period August 16, 2006 to January 10, 2007 and has the right to sell US$5
million monthly and purchase Canadian dollars at an exchange rate of US$0.87
for the period January 10, 2007 to July 11, 2007. The fair value of these
contracts at December 31, 2006 was immaterial and changes in fair value are
included in marketing and other in the Consolidated Statement of Income.
Foreign currency swap
We occasionally use derivative instruments to effectively convert cash
flows from Canadian to US dollars and vice versa. During the year, we held a
foreign currency derivative instrument that obligated us and the counterparty
to exchange principal and interest amounts. In November 2006, we paid US$37
million and received Cdn$50 million to settle the foreign currency swap (see
Note 8). The change in fair value was included in marketing and other in the
Consolidated Statement of Income.
Other
The foreign exchange gains or losses related to our designated debt are
included in the cumulative foreign currency translation adjustment in
shareholders' equity. Our net investment in self-sustaining foreign operations
and our designated US-dollar debt at December 31 are as follows:
(US$ millions) 2006 2005
- --------------------------------------------------------------------------------
Net Investment in Self-Sustaining Foreign Operations 4,534 4,357
- --------------------------------------------------------------------------------
US-Dollar Debt 3,761 2,700
================================================================================
We also have small exposures to currencies other than the US dollar. A
portion of our United Kingdom operating expenses, capital spending and future
asset retirement expenditures is denominated in British pounds and Euros. We do
not have any material exposure to highly inflationary foreign currencies.
87
TRADING ACTIVITIES
Our sales and purchases of crude oil and natural gas are generally
transacted in or referenced to the US dollar, as are most of the financial
commodity contracts used by our marketing group. However, we pay for many of
our purchases in Canadian dollars. We enter into US-dollar forward contracts
and swaps to manage this exposure. Losses of $12 million on our US-dollar
forward contracts and swaps at December 31, 2006 are included in the
Consolidated Balance Sheet, and any change in fair value is included in
marketing and other in the Consolidated Statement of Income.
(d) TOTAL CARRYING VALUE OF DERIVATIVE CONTRACTS RELATED TO TRADING
ACTIVITIES
Amounts related to derivative instruments held by our marketing operation
are equal to fair value as we use mark-to-market accounting, and are as follows
at December 31:
2006 2005
- --------------------------------------------------------------------------------
Accounts Receivable 731 382
- --------------------------------------------------------------------------------
Deferred Charges and Other Assets 1 (Note 10) 153 232
- --------------------------------------------------------------------------------
TOTAL DERIVATIVE CONTRACT ASSETS 884 614
===============================================================================
- --------------------------------------------------------------------------------
Accounts Payable and Accrued Liabilities 325 321
- --------------------------------------------------------------------------------
Deferred Credits and Other Liabilities 1 (Note 11) 199 124
- --------------------------------------------------------------------------------
TOTAL DERIVATIVE CONTRACT LIABILITIES 524 445
- --------------------------------------------------------------------------------
TOTAL DERIVATIVE CONTRACT NET ASSETS 2 360 169
===============================================================================
NOTES:
(1) THESE DERIVATIVE INSTRUMENTS SETTLE BEYOND 12 MONTHS AND ARE CONSIDERED
NON-CURRENT.
(2) COMPRISED OF $372 MILLION (2005--$161 MILLION) RELATED TO COMMODITY
CONTRACTS AND LOSSES OF $12 MILLION (2005--$8 MILLION) RELATED TO
US-DOLLAR FORWARD CONTRACTS AND SWAPS.
As a physical energy marketer, we match the contract months of our
derivative instruments with the contract months of our physical sales and
purchases. As a result, our disclosure with respect to derivative instruments
includes amounts with no ongoing commodity price or foreign currency risk as at
December 31, 2006. Excluding such amounts, derivative contracts included in
accounts receivable at December 31, 2006 amounted to $460 million (December 31,
2005 - $382 million) and derivative contracts included in accounts payable and
accrued liabilities amounted to $312 million (December 31, 2005 - $290
million).
Our exchange-traded derivative contracts are subject to margin deposit
requirements. We are required to advance cash to counterparties in order to
satisfy these requirements. We have margin deposits of $197 million (December
31, 2005--nil), which have been included in restricted cash and margin deposits
on our Consolidated Balance Sheet at December 31, 2006.
(e) INTEREST RATE RISK MANAGEMENT
We use fixed and floating rate debt to finance our operations. The
floating rate debt exposes us to changes in interest payments as interest rates
fluctuate. To manage this exposure, we maintain a combination of fixed and
floating rate borrowings and facilities. At December 31, 2006, fixed-rate
borrowings comprised 73% (2005--95%) of our long-term debt at an effective
average rate of 6.3% (2005--6.3%). During the year, we periodically drew on our
floating-rate, unsecured, committed term credit facilities. We had no interest
rate swaps outstanding in 2006 or 2005.
(f) CREDIT RISK MANAGEMENT
A substantial portion of our accounts receivable are with counterparties
in the energy industry and are subject to normal industry credit risk. This
concentration of risk within the energy industry is reduced because of our
broad base of domestic and international counterparties. We assess the
financial strength of our counterparties, including those involved in marketing
and other commodity arrangements, and we limit the total exposure to individual
counterparties. As well, a number of our contracts contain provisions that
allow us to demand the posting of collateral in the event downgrades to
non-investment grade credit ratings occur. Credit risk,
88
including credit concentrations, is routinely reported to our Risk Management
Committee. We also use standard agreements that allow for the netting of
exposures associated with a single counterparty. We believe this minimizes our
overall credit risk.
8. LONG-TERM DEBT AND SHORT-TERM BORROWINGS
2006 2005
- -------------------------------------------------------------------------------
Canexus LP Term Credit Facilities (US$149 million) (a) 174 171
- -------------------------------------------------------------------------------
Term Credit Facilities (US$925 million) (b) 1,078 -
- -------------------------------------------------------------------------------
Debentures, due 2006 (c) - 93
- -------------------------------------------------------------------------------
Medium-Term Notes, due 2007 (d) 150 150
- -------------------------------------------------------------------------------
Medium-Term Notes, due 2008 (e) 125 125
- -------------------------------------------------------------------------------
Notes, due 2013 (US$500 million) (f) 583 583
- -------------------------------------------------------------------------------
Notes, due 2015 (US$250 million) (g) 291 292
- -------------------------------------------------------------------------------
Notes, due 2028 (US$200 million) (h) 233 233
- -------------------------------------------------------------------------------
Notes, due 2032 (US$500 million) (i) 583 583
- -------------------------------------------------------------------------------
Notes, due 2035 (US$790 million) (j) 920 921
- -------------------------------------------------------------------------------
Subordinated Debentures, due 2043 (US$460 million) (k) 536 536
- -------------------------------------------------------------------------------
TOTAL 4,673 3,687
==============================================================================
(a) CANEXUS LP TERM CREDIT FACILITIES
Canexus LP has $350 million of committed, secured term credit facilities,
which are available until 2010. At December 31, 2006, $174 million (US$149
million) was drawn on these facilities (December 31, 2005--$171 million).
Borrowings are available as Canadian bankers' acceptances, LIBOR-based loans,
Canadian prime rate loans or US-dollar base rate loans. Interest is payable
monthly at floating rates. The term credit facilities are secured by a floating
charge debenture over all of Canexus LP's assets and by certain guarantees,
security interests and subordination agreements provided by certain affiliates
of Canexus LP (which do not include Nexen). During 2006, the weighted-average
interest rate on the Canexus LP term credit facilities was 5.9% (2005--4.8%).
(b) TERM CREDIT FACILITIES
We have committed, unsecured, term credit facilities of $3.6 billion,
which are available until 2011. At December 31, 2006, $1,078 million (US$925
million) was drawn on these facilities (December 31, 2005--nil). 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 monthly at floating rates. During 2006, the
weighted-average interest rate was 5.7% (2005--4.4%). At December 31, 2006,
$294 million of these facilities were utilized to support outstanding letters
of credit (December 31, 2005--$250 million).
(c) DEBENTURES, DUE 2006
During November 1996, we issued $100 million of unsecured 10 year
redeemable debentures. Interest was payable semi-annually at a rate of 6.85%.
In December 1996, $50 million of this obligation was effectively converted
through a foreign currency swap with a Canadian chartered bank to a US$37
million liability bearing interest at 6.75% for the term of the debentures. In
November 2006, we repaid the outstanding debentures of $100 million and
realized a gain of $7 million on the foreign currency swap.
(d) MEDIUM-TERM NOTES, DUE 2007
During July 1997, we issued $150 million of notes. Interest is payable
semi-annually at a rate of 6.45%, and the principal is to be repaid in July
2007. 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
Government of Canada Bond having a term to maturity equal to the remaining
89
term of the notes plus 0.125%. Amounts due July 2007 have not been included in
current liabilities as we expect to refinance this amount with our term credit
facilities.
(e) MEDIUM-TERM NOTES, DUE 2008
During October 1997, we issued $125 million of notes. Interest is payable
semi-annually at a rate of 6.3%, and the principal is to be repaid in June
2008. 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
Government of Canada Bond having a term to maturity equal to the remaining term
of the notes plus 0.125%.
(f) NOTES, DUE 2013
During November 2003, we issued US$500 million of notes. Interest is
payable semi-annually at a rate of 5.05%, and the principal is to be repaid in
November 2013. 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 0.2%.
(g) NOTES, DUE 2015
During March 2005, we issued US$250 million of notes. Interest is payable
semi-annually at a rate of 5.20%, and the principal is to be repaid in March
2015. 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%.
(h) 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 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%.
(i) 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%.
(j) 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 0.2%.
(k) 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 on or after November 8, 2008. The redemption price is equal to the
par value of the principal amount plus any accrued and unpaid interest to the
redemption date. We may choose to redeem the principal amount with either cash
or common shares.
(l) LONG-TERM DEBT REPAYMENTS
- -------------------------------------------------------------------------------
2007 150
- -------------------------------------------------------------------------------
2008 125
- -------------------------------------------------------------------------------
2009 -
- -------------------------------------------------------------------------------
2010 174
- -------------------------------------------------------------------------------
2011 1,078
- -------------------------------------------------------------------------------
Thereafter 3,146
- -------------------------------------------------------------------------------
TOTAL DEBT REPAYMENTS 4,673
===============================================================================
90
(m) DEBT COVENANTS
Some of our debt instruments contain covenants with respect to certain
financial ratios and our ability to grant security. At December 31, 2006, we
were in compliance with all covenants.
(n) SHORT-TERM BORROWINGS
Nexen has uncommitted, unsecured credit facilities of approximately $632
million. At December 31, 2006, $158 million (US$136 million) was drawn under
these facilities (December 31, 2005--nil). We have also utilized $252 million
of these facilities to support outstanding letters of credit at December 31,
2006 (2005--$468 million). Interest is payable at floating rates. During 2006,
the weighted-average interest rate on our short-term borrowings was 5.5%
(2005--3.6%).
(o) INTEREST EXPENSE
2006 2005 2004
- -------------------------------------------------------------------------------
Long-Term Debt 275 260 182
- -------------------------------------------------------------------------------
Other 19 15 12
- -------------------------------------------------------------------------------
Total 294 275 194
- -------------------------------------------------------------------------------
Less: Capitalized (241) (178) (51)
- -------------------------------------------------------------------------------
TOTAL INTEREST EXPENSE 53 97 143
==============================================================================
Capitalized interest relates to and is included as part of the cost of oil
and gas and Syncrude properties. The capitalization rates are based on our
weighted-average cost of borrowings.
9. ASSET RETIREMENT OBLIGATIONS
Changes in carrying amounts of the asset retirement obligations associated
with our PP&E are as follows:
2006 2005
- -------------------------------------------------------------------------------
Balance at Beginning of Year 611 468
- -------------------------------------------------------------------------------
Obligations Assumed with Development Activities 75 72
- -------------------------------------------------------------------------------
Obligations Discharged with Disposed Properties (1) (37)
- -------------------------------------------------------------------------------
Expenditures Made on Asset Retirements (44) (34)
- -------------------------------------------------------------------------------
Accretion 37 26
- -------------------------------------------------------------------------------
Revisions to Estimates (10) 138
- -------------------------------------------------------------------------------
Effects of Foreign Exchange 36 (22)
- -------------------------------------------------------------------------------
BALANCE AT END OF YEAR 1, 2 704 611
==============================================================================
NOTES:
(1) OBLIGATIONS DUE WITHIN 12 MONTHS OF $21 MILLION (2005--$21 MILLION) HAVE
BEEN INCLUDED IN ACCOUNTS PAYABLE AND ACCRUED LIABILITIES.
(2) OBLIGATIONS RELATING TO OUR OIL AND GAS ACTIVITIES AMOUNT TO $658 MILLION
(2005--$564 MILLION) AND OBLIGATIONS RELATING TO OUR CHEMICALS BUSINESS
AMOUNT TO $46 MILLION (2005--$47 MILLION).
91
Our total estimated undiscounted asset retirement obligations amount to
$1,770 million. We have discounted the total estimated asset retirement
obligations using a weighted-average, credit-adjusted risk-free rate of 5.7%.
Approximately $97 million included in our asset retirement obligations will be
settled over the next five years. The remaining obligations settle beyond five
years and will be funded by future cash flows from our operations.
We own interests in assets for which the fair value of the asset
retirement obligations cannot be reasonably determined because the assets
currently have an indeterminate life and we cannot determine when remediation
activities would take place. These assets include our interest in Syncrude's
upgrader and sulphur pile. The estimated future recoverable reserves at
Syncrude are significant and given the long life of this asset, we are unable
to determine when asset retirement activities would take place. Furthermore,
the Syncrude plant can continue to run indefinitely with ongoing maintenance
activities. The retirement obligations for these assets will be recorded in the
first year in which the lives of the assets are determinable.
10. DEFERRED CHARGES AND OTHER ASSETS
2006 2005
- -------------------------------------------------------------------------------
Long-Term Marketing Derivative Contracts (Note 7d) 153 232
- -------------------------------------------------------------------------------
Deferred Financing Costs 59 63
- -------------------------------------------------------------------------------
Asset Retirement Remediation Fund 13 14
- -------------------------------------------------------------------------------
Crude Oil Put Options (Note 7a) 19 4
- -------------------------------------------------------------------------------
Other 74 85
- -------------------------------------------------------------------------------
TOTAL 318 398
==============================================================================
11. DEFERRED CREDITS AND OTHER LIABILITIES
2006 2005
- -------------------------------------------------------------------------------
Fixed-Price Natural Gas Contracts (Note 7b) 74 128
- -------------------------------------------------------------------------------
Long-Term Marketing Derivative Contracts (Note 7d) 199 124
- -------------------------------------------------------------------------------
Deferred Transportation Revenue 89 87
- -------------------------------------------------------------------------------
Stock-Based Compensation Liability 6 53
- -------------------------------------------------------------------------------
Defined Benefit Pension Obligations (Note 16) 48 39
- -------------------------------------------------------------------------------
Capital Lease Obligations 48 9
- -------------------------------------------------------------------------------
Other 52 39
- -------------------------------------------------------------------------------
TOTAL 516 479
==============================================================================
12. SHAREHOLDERS' 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.
92
(b) ISSUED COMMON SHARES AND DIVIDENDS
(thousands of shares) 2006 2005 2004
- --------------------------------------------------------------------------------
Beginning of Year 261,141 258,399 251,212
- --------------------------------------------------------------------------------
Issue of Common Shares for Cash
- --------------------------------------------------------------------------------
Exercise of Tandem Options 846 1,823 5,902
- --------------------------------------------------------------------------------
Dividend Reinvestment Plan 276 605 895
- --------------------------------------------------------------------------------
Employee Flow-through Shares 250 314 390
- --------------------------------------------------------------------------------
END OF YEAR 262,513 261,141 258,399
===============================================================================
DIVIDENDS DECLARED PER COMMON SHARE ($/share) 0.20 0.20 0.20
- --------------------------------------------------------------------------------
CASH CONSIDERATION (Cdn$ millions)
- --------------------------------------------------------------------------------
Exercise of Tandem Options 16 29 93
- --------------------------------------------------------------------------------
Dividend Reinvestment Plan 16 20 21
- --------------------------------------------------------------------------------
Employee Flow-through Shares 16 9 10
- --------------------------------------------------------------------------------
48 58 124
===============================================================================
At December 31, 2006, there were 498,831 common shares (2005--774,915;
2004--1,379,874) reserved for issuance under the Dividend Reinvestment Plan.
(c) TANDEM OPTIONS
In May 2004, our shareholders approved the modification of our stock
option plan to a tandem option plan by including a cash feature. The tandem
options give the holders a right to either purchase common shares at the
exercise price or to receive cash payments equal to the excess of the market
value of the common shares over the exercise price.
Similar to our stock appreciation rights, we use the intrinsic-value
method to recognize compensation expense associated with our tandem options.
Obligations are accrued on a graded-vesting basis and represent the difference
between the market value of our common shares and the exercise price of the
options. The obligations are revalued each reporting period based on the change
in the market value of our common shares and the number of graded-vested
options outstanding.
Upon modification of the stock option plan, we were required to recognize
an obligation for our tandem options. This obligation represented the
difference between the market value of our common shares and the
weighted-average exercise price of the options. As a result, we recognized an
obligation of $85 million for the graded-vested portion of the options
outstanding on June 30, 2004. In the second quarter of 2004, a one-time,
non-cash charge of $82 million was included in general and administrative
expense, net of $3 million previously expensed in respect of our original stock
options.
Following the introduction of the AMERICAN JOB CREATION ACT OF 2004 in the
US, stock options awarded to our US employees between December 1, 2004 and
December 1, 2005 did not include a tandem option cash feature. We use the
fair-value method to recognize compensation expense associated with these
options. The expense is recognized over the vesting period of the options with
a corresponding increase to contributed surplus. This resulted in compensation
expense in 2006 of $2 million (2005 --$2 million; 2004--$0.1 million), which
was included in general and administrative expense. In 2005, US tax regulations
were modified and as a result, tandem options have been issued to our US
employees after December 1, 2005. These options are expensed using the
intrinsic-method described above.
93
We have granted options to purchase common shares to directors, officers
and employees. Each option permits the holder to purchase one Nexen common
share at the stated exercise price. Options granted prior to February 2001 vest
over four years and are exercisable on a cumulative basis over 10 years.
Options granted after February 2001 vest over three years and are exercisable
on a cumulative basis over five years. At the time of grant, the exercise price
equals the market price. The following options have been granted:
2006 2005 2004
WEIGHTED WEIGHTED WEIGHTED
AVERAGE AVERAGE AVERAGE
EXERCISE EXERCISE EXERCISE
OPTIONS PRICE OPTIONS PRICE OPTIONS PRICE
(thousands) ($/option) (thousands) ($/option) (thousands) ($/option)
- ----------------------------------------------------------------------------------------------------------------------------
Balance at Beginning of Year 15,315 28 16,276 20 18,406 17
- ----------------------------------------------------------------------------------------------------------------------------
Granted 2,400 63 3,392 55 4,224 25
- ----------------------------------------------------------------------------------------------------------------------------
Exercised for Stock (846) 18 (1,823) 16 (5,902) 15
- ----------------------------------------------------------------------------------------------------------------------------
Surrendered for Cash (1,522) 18 (2,089) 17 (289) 17
- ----------------------------------------------------------------------------------------------------------------------------
Forfeited (105) 38 (441) 22 (163) 17
- ----------------------------------------------------------------------------------------------------------------------------
BALANCE AT END OF YEAR 15,242 35 15,315 28 16,276 20
============================================================================================================================
- ----------------------------------------------------------------------------------------------------------------------------
Options Exercisable at End of Year 9,345 24 8,131 19 8,455 17
- ----------------------------------------------------------------------------------------------------------------------------
Common Shares Reserved
for Issuance Under the
Tandem Option Plan 16,235 17,290 19,172
============================================================================================================================
The range of exercise prices of options outstanding and exercisable at
December 31, 2006 is as follows:
OUTSTANDING OPTIONS EXERCISABLE OPTIONS
WEIGHTED WEIGHTED WEIGHTED
AVERAGE AVERAGE AVERAGE
NUMBER OF EXERCISE YEARS NUMBER OF EXERCISE
OPTIONS PRICE TO EXPIRY OPTIONS PRICE
(thousands) ($/option) (years) (thousands) ($/option)
- ---------------------------------------------------------------------------------------------------------------------------
$5.00 to $9.99 178 9 2 178 9
- ---------------------------------------------------------------------------------------------------------------------------
$10.00 to $14.99 788 14 2 788 14
- ---------------------------------------------------------------------------------------------------------------------------
$15.00 to $19.99 3,032 18 3 3,032 18
- ---------------------------------------------------------------------------------------------------------------------------
$20.00 to $24.99 2,792 23 2 2,462 22
- ---------------------------------------------------------------------------------------------------------------------------
$25.00 to $29.99 2,768 25 3 1,778 25
- ---------------------------------------------------------------------------------------------------------------------------
$30.00 to $34.99 14 31 3 2 31
- ---------------------------------------------------------------------------------------------------------------------------
$35.00 to $39.99 - - - - -
- ---------------------------------------------------------------------------------------------------------------------------
$40.00 to $44.99 2 40 4 1 40
- ---------------------------------------------------------------------------------------------------------------------------
$45.00 to $49.99 13 47 4 5 47
- ---------------------------------------------------------------------------------------------------------------------------
$50.00 to $54.99 3,254 55 4 1,099 54
- ---------------------------------------------------------------------------------------------------------------------------
$55.00 to $59.99 12 57 4 - -
- ---------------------------------------------------------------------------------------------------------------------------
$60.00 to $64.99 2,383 63 5 - -
- ---------------------------------------------------------------------------------------------------------------------------
$65.00 to $69.99 3 66 4 - -
- ---------------------------------------------------------------------------------------------------------------------------
$70.00 to $74.99 3 71 5 - -
- ---------------------------------------------------------------------------------------------------------------------------
TOTAL OPTIONS 15,242 9,345
===========================================================================================================================
94
(d) STOCK APPRECIATION RIGHTS
Under our stock appreciation rights (StARs) plan established in 2001,
employees are entitled to cash payments equal to the excess of the market price
of the common shares over the exercise price of the right. The vesting period
and other terms of the plan are similar to the tandem option plan. The total
rights granted and outstanding at any time cannot exceed 10% of Nexen's total
outstanding common shares. At the time of grant, the exercise price equals the
market price. The following stock appreciation rights have been granted:
2006 2005 2004
WEIGHTED WEIGHTED WEIGHTED
AVERAGE AVERAGE AVERAGE
EXERCISE EXERCISE EXERCISE
STARS PRICE STARS PRICE STARS PRICE
(thousands) ($/StAR) (thousands) ($/StAR) (thousands) ($/StAR)
- -------------------------------------------------------------------------------------------------------------------------------
Balance at Beginning of Year 5,964 30 6,436 22 4,809 18
- -------------------------------------------------------------------------------------------------------------------------------
Granted 2,254 63 1,443 55 2,609 25
- -------------------------------------------------------------------------------------------------------------------------------
Exercised for Cash (1,082) 21 (1,455) 19 (867) 16
- -------------------------------------------------------------------------------------------------------------------------------
Forfeited (191) 38 (460) 23 (115) 18
- -------------------------------------------------------------------------------------------------------------------------------
BALANCE AT END OF YEAR 6,945 42 5,964 30 6,436 22
===============================================================================================================================
StARs Exercisable at End
of Year 3,076 27 2,426 21 2,021 17
- -------------------------------------------------------------------------------------------------------------------------------
The range of exercise prices of StARs outstanding and exercisable at
December 31, 2006 is as follows:
OUTSTANDING STARS EXERCISABLE STARS
WEIGHTED
AVERAGE WEIGHTED WEIGHTED
EXERCISE AVERAGE YEARS AVERAGE
NUMBER OF STARS PRICE TO EXPIRY NUMBER OF STARS EXERCISE PRICE
(thousands) ($/StAR) (years) (thousands) ($/StAR)
- -------------------------------------------------------------------------------------------------------------------------------
$15.00 to $19.99 513 17 1 513 17
- -------------------------------------------------------------------------------------------------------------------------------
$20.00 to $24.99 991 22 2 985 22
- -------------------------------------------------------------------------------------------------------------------------------
$25.00 to $29.99 1,859 25 3 1,138 25
- -------------------------------------------------------------------------------------------------------------------------------
$30.00 to $34.99 18 33 3 6 33
- -------------------------------------------------------------------------------------------------------------------------------
$35.00 to $39.99 9 37 4 1 37
- -------------------------------------------------------------------------------------------------------------------------------
$40.00 to $44.99 8 41 4 3 41
- -------------------------------------------------------------------------------------------------------------------------------
$45.00 to $49.99 38 48 4 12 48
- -------------------------------------------------------------------------------------------------------------------------------
$50.00 to $54.99 1,256 55 4 418 55
- -------------------------------------------------------------------------------------------------------------------------------
$55.00 to $59.99 29 57 4 - -
- -------------------------------------------------------------------------------------------------------------------------------
$60.00 to $64.99 2,213 63 5 - -
- -------------------------------------------------------------------------------------------------------------------------------
$65.00 to $69.99 11 66 4 - -
- -------------------------------------------------------------------------------------------------------------------------------
TOTAL STARS 6,945 3,076
===============================================================================================================================
13. EARNINGS PER COMMON SHARE
We calculate basic earnings per common share from continuing operations
using net income from continuing operations divided by the weighted-average
number of common shares outstanding. We calculate basic earnings per common
share using net income and the weighted-average number of common shares
outstanding. We calculate diluted earnings per common share from continuing
operations and diluted earnings per common share in the same manner as basic,
except we use the weighted-average number of diluted common shares outstanding
in the denominator.
95
(millions of shares) 2006 2005 2004
- ----------------------------------------------------------------------------------------------------
Weighted-Average Number of Common Shares Outstanding 262.1 260.4 257.3
- ----------------------------------------------------------------------------------------------------
Shares Issuable Pursuant to Stock Options 13.9 13.4 13.1
- ----------------------------------------------------------------------------------------------------
Shares to be Purchased from Proceeds of Stock Options (7.1) (7.4) (9.8)
- ----------------------------------------------------------------------------------------------------
WEIGHTED-AVERAGE NUMBER OF DILUTED COMMON SHARES OUTSTANDING 268.9 266.4 260.6
====================================================================================================
In calculating the weighted-average number of diluted common shares
outstanding for the year ended December 31, 2006, we excluded 211,283 options
(2005--280,708; 2004--348,200), because their exercise price was greater than
the annual average common share market price in those periods. During the last
three years, outstanding stock options were the only potential dilutive
instruments.
14. DISCONTINUED OPERATIONS
In the third quarter of 2005, we sold certain Canadian conventional oil
and gas properties in southeast Saskatchewan, northwest Saskatchewan, northeast
British Columbia and the Alberta foothills. The results of operations of these
properties have been presented as discontinued operations. The sales closed in
the third quarter of 2005 with net proceeds of $900 million after closing
adjustments, and we realized gains of $225 million. These gains are net of
losses attributable to pipeline contracts and fixed-price gas sales contracts
associated with these properties that we have retained, but no longer use in
connection with our oil and gas business.
During the fourth quarter of 2004, we concluded production from our
Buffalo field, offshore Australia. The results of our operations in Australia
have been presented as discontinued operations, as we have no plans to continue
operations in the country. Remediation and abandonment activities have been
completed, and no gain or loss was recognized.
The results of operations from these properties in Australia and Canada
are detailed below and shown as discontinued operations in our Consolidated
Statement of Income.
2005 2004
CANADA CANADA AUSTRALIA TOTAL
- -----------------------------------------------------------------------------------------------------
Revenues and Other Income
- -----------------------------------------------------------------------------------------------------
Net Sales 154 232 75 307
- -----------------------------------------------------------------------------------------------------
Marketing and Other - 1 - 1
- -----------------------------------------------------------------------------------------------------
Gain on Disposition of Assets 225 - - -
- -----------------------------------------------------------------------------------------------------
379 233 75 308
- -----------------------------------------------------------------------------------------------------
Expenses
- -----------------------------------------------------------------------------------------------------
Operating 27 40 53 93
- -----------------------------------------------------------------------------------------------------
Depreciation, Depletion, Amortization and Impairment 28 70 9 79
- -----------------------------------------------------------------------------------------------------
Exploration Expense 1 3 - 3
- -----------------------------------------------------------------------------------------------------
Income before Income Taxes 323 120 13 133
- -----------------------------------------------------------------------------------------------------
Provision for Future Income Taxes (129) 50 - 50
- -----------------------------------------------------------------------------------------------------
NET INCOME FROM DISCONTINUED OPERATIONS 452 70 13 83
=====================================================================================================
EARNINGS PER COMMON SHARE ($/share)
- -----------------------------------------------------------------------------------------------------
Basic (Note 13) 1.74 0.27 0.05 0.32
- -----------------------------------------------------------------------------------------------------
Diluted (Note 13) 1.70 0.27 0.05 0.32
=====================================================================================================
There were no assets and liabilities related to discontinued operations as
at December 31, 2006.
96
15. COMMITMENTS, CONTINGENCIES AND GUARANTEES
2007 2008 2009 2010 2011 THEREAFTER
- --------------------------------------------------------------------------------------------------
Operating Leases 44 109 127 123 117 232
- --------------------------------------------------------------------------------------------------
Transportation and Storage Commitments 424 165 97 70 53 118
- --------------------------------------------------------------------------------------------------
468 274 224 193 170 350
==================================================================================================
In June 2003, a subsidiary of Occidental Petroleum Corporation
(Occidental) initiated an arbitration against us at the International Court of
Arbitration of the International Chamber of Commerce (ICC Court) regarding an
Area of Mutual Interest agreement relating to certain portions of Block 51 in
the Republic of Yemen. In April 2006, the ICC Court concluded that we breached
this agreement and as a result, Occidental was entitled to monetary damages. In
late 2006, we agreed to settle the arbitration with Occidental for US$135
million. No further amounts are expected to be payable under the settlement.
This amount was accrued and included in other expenses in our Consolidated
Statement of Income during 2006.
We have a number of lawsuits and claims pending including income tax
reassessments (see Note 18), for which we currently cannot determine the
ultimate result. We record costs as they are incurred or become determinable.
We believe the resolution of these matters would not have a material adverse
effect on our liquidity, consolidated financial position or results of
operations.
During 2006, total rental expense was $49 million (2005--$47 million;
2004--$45 million).
From time to time, we enter into certain types of contracts that require
us to indemnify parties against 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 amount 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 such matters, would not have a material adverse effect on our
liquidity, financial condition or results of operations.
16. PENSION AND OTHER POST-RETIREMENT BENEFITS
Nexen and Canexus have contributory and non-contributory defined benefit
and defined contribution pension plans, which together cover substantially all
employees. Syncrude has a defined benefit plan for its employees, and we
disclose only our proportionate share of this plan. Under the defined benefit
plans, we provide benefits to retirees based on their length of service and
final average 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%. On the establishment of Canexus in 2005, the portion of the projected
benefit obligation and fair value of plan assets relating to Canexus employees
was transferred to Canexus from Nexen.
97
(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.
2006 2005
NEXEN CANEXUS SYNCRUDE NEXEN CANEXUS SYNCRUDE
- -------------------------------------------------------------------------------------------------------------------------------
CHANGE IN PROJECTED BENEFIT OBLIGATION (PBO)
- -------------------------------------------------------------------------------------------------------------------------------
Beginning of Year 223 49 109 217 - 91
- -------------------------------------------------------------------------------------------------------------------------------
Service Cost 16 3 5 15 1 4
- -------------------------------------------------------------------------------------------------------------------------------
Interest Cost 12 3 5 12 1 5
- -------------------------------------------------------------------------------------------------------------------------------
Plan Participants' Contributions 3 1 1 3 - 1
- -------------------------------------------------------------------------------------------------------------------------------
Actuarial Loss/(Gain) 9 2 - 33 (2) 11
- -------------------------------------------------------------------------------------------------------------------------------
Benefits Paid (11) - (4) (8) - (3)
- -------------------------------------------------------------------------------------------------------------------------------
Transfer to Canexus - - - (49) 49 -
- -------------------------------------------------------------------------------------------------------------------------------
END OF YEAR 1 252 58 116 223 49 109
===============================================================================================================================
CHANGE IN FAIR VALUE OF PLAN ASSETS
- -------------------------------------------------------------------------------------------------------------------------------
Beginning of Year 146 40 58 171 - 50
- -------------------------------------------------------------------------------------------------------------------------------
Actual Return on Plan Assets 23 6 8 18 - 6
- -------------------------------------------------------------------------------------------------------------------------------
Employer's Contribution 24 3 5 2 - 4
- -------------------------------------------------------------------------------------------------------------------------------
Plan Participants' Contributions 3 1 1 3 - 1
- -------------------------------------------------------------------------------------------------------------------------------
Benefits Paid (11) - (3) (8) - (3)
- -------------------------------------------------------------------------------------------------------------------------------
Transfer to Canexus - - - (40) 40 -
- -------------------------------------------------------------------------------------------------------------------------------
END OF YEAR 185 50 69 146 40 58
===============================================================================================================================
RECONCILIATION OF FUNDED STATUS
- -------------------------------------------------------------------------------------------------------------------------------
Funded Status 2 (67) (8) (47) (77) (9) (51)
- -------------------------------------------------------------------------------------------------------------------------------
Unamortized Transitional Obligation - - - 1 - -
- -------------------------------------------------------------------------------------------------------------------------------
Unamortized Prior Service Costs 3 - - 3 - -
Unamortized Net Actuarial Loss 39 7 32 44 9 38
- -------------------------------------------------------------------------------------------------------------------------------
PENSION LIABILITY (25) (1) (15) (29) - (13)
===============================================================================================================================
PENSION LIABILITY RECOGNIZED
- -------------------------------------------------------------------------------------------------------------------------------
Deferred Charges and Other Assets 10 - - - - -
- -------------------------------------------------------------------------------------------------------------------------------
Accounts Payable and Accrued Liabilities (1) - (2) (1) - (2)
- -------------------------------------------------------------------------------------------------------------------------------
Other Deferred Credits and Liabilities (Note 11) (34) (1) (13) (28) - (11)
- -------------------------------------------------------------------------------------------------------------------------------
PENSION LIABILITY (25) (1) (15) (29) - (13)
===============================================================================================================================
Assumptions (%)
- -------------------------------------------------------------------------------------------------------------------------------
Accrued Benefit Obligation at December 31
- -------------------------------------------------------------------------------------------------------------------------------
Discount Rate 5.00 5.00 5.00 5.25 5.25 5.00
- -------------------------------------------------------------------------------------------------------------------------------
Long-Term Rate of Employee Compensation Increase 4.00 4.00 4.00 4.00 4.00 4.00
- -------------------------------------------------------------------------------------------------------------------------------
Benefit Cost for Year Ended December 31 3
- -------------------------------------------------------------------------------------------------------------------------------
Discount Rate 5.25 5.25 5.00 5.00 5.00 5.00
- -------------------------------------------------------------------------------------------------------------------------------
Long-Term Rate of Employee Compensation Increase 4.00 4.00 4.00 4.00 4.00 4.00
- -------------------------------------------------------------------------------------------------------------------------------
Long-Term Annual Rate of Return on Plan Assets 4 7.00 6.50 8.50 7.00 6.50 8.50
===============================================================================================================================
NOTES:
(1) THE ACCUMULATED BENEFIT OBLIGATIONS (THE PROJECTED BENEFIT OBLIGATION
EXCLUDING FUTURE SALARY INCREASES) OF THE NEXEN AND CANEXUS PLANS WERE
$180 MILLION AND $44 MILLION AT DECEMBER 31, 2006, RESPECTIVELY
(2005--$161 MILLION AND $36 MILLION, RESPECTIVELY). NEXEN'S SUPPLEMENTAL
PENSION PLAN'S ACCUMULATED BENEFIT OBLIGATION WAS $35 MILLION AT DECEMBER
31, 2006 (2005--$29 MILLION). NEXEN'S SHARE OF SYNCRUDE'S EMPLOYEE PENSION
PLAN'S ACCUMULATED BENEFIT OBLIGATION WAS $89 MILLION AT DECEMBER 31, 2006
(2005--$82 MILLION).
(2) INCLUDES UNFUNDED OBLIGATIONS FOR SUPPLEMENTAL BENEFITS TO THE EXTENT THAT
THE BENEFIT IS LIMITED BY STATUTORY GUIDELINES. AT DECEMBER 31, 2006, THE
PBO FOR NEXEN'S SUPPLEMENTAL BENEFITS WAS $53 MILLION (2005--$43 MILLION)
AND $1 MILLION FOR CANEXUS (2005--$1 MILLION).
(3) THE ASSUMPTIONS HAVE BEEN USED TO CALCULATE THE RECOGNIZED EXPENSE FOR
NEXEN AND CANEXUS. THERE WERE NO CHANGES TO THE ASSUMPTIONS BETWEEN THE
MEASUREMENT DATE AND DECEMBER 31, 2006. SYNCRUDE'S MEASUREMENT DATE WAS
DECEMBER 31, 2006.
(4) 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.
98
Net Pension Expense Recognized Under Our Defined Benefit Pension Plans
2006 2005 2004
- ---------------------------------------------------------------------------------------------------
NEXEN
- ---------------------------------------------------------------------------------------------------
Cost of Benefits Earned by Employees 16 15 8
- ---------------------------------------------------------------------------------------------------
Interest Cost on Benefits Earned 12 12 12
- ---------------------------------------------------------------------------------------------------
Actual Return on Plan Assets (23) (18) (16)
- ---------------------------------------------------------------------------------------------------
Actuarial Losses 9 33 10
- ---------------------------------------------------------------------------------------------------
Pension Expense Before Adjustments for the Long-Term Nature of
Employee Future Benefit Costs 14 42 14
- ---------------------------------------------------------------------------------------------------
Difference Between Actual and Expected Return on Plan Assets 12 8 5
- ---------------------------------------------------------------------------------------------------
Difference Between Actual and Recognized Actuarial Losses (7) (32) (10)
- ---------------------------------------------------------------------------------------------------
Difference Between Actual and Recognized Past Service Costs 1 - 1
- ---------------------------------------------------------------------------------------------------
NET PENSION EXPENSE 20 18 10
===================================================================================================
CANEXUS
- ---------------------------------------------------------------------------------------------------
Cost of Benefits Earned by Employees 3 1 -
- ---------------------------------------------------------------------------------------------------
Interest Cost on Benefits Earned 3 1 -
- ---------------------------------------------------------------------------------------------------
Actual Return on Plan Assets (6) - -
- ---------------------------------------------------------------------------------------------------
Actuarial (Gains)/Losses 2 (2) -
- ---------------------------------------------------------------------------------------------------
Pension Expense Before Adjustments for the Long-Term Nature of
Employee Future Benefit Costs 2 - -
- ---------------------------------------------------------------------------------------------------
Difference Between Actual and Expected Return on Plan Assets 3 (1) -
- ---------------------------------------------------------------------------------------------------
Difference Between Actual and Recognized Actuarial Gains (2) 2 -
- ---------------------------------------------------------------------------------------------------
Difference Between Actual and Recognized Past Service Costs - - -
- ---------------------------------------------------------------------------------------------------
NET PENSION EXPENSE 3 1 -
===================================================================================================
SYNCRUDE
- ---------------------------------------------------------------------------------------------------
Cost of Benefits Earned by Employees 5 4 3
- ---------------------------------------------------------------------------------------------------
Interest Cost on Benefits Earned 5 5 5
- ---------------------------------------------------------------------------------------------------
Actual Return on Plan Assets (8) (6) (5)
- ---------------------------------------------------------------------------------------------------
Actuarial Losses - 11 7
- ---------------------------------------------------------------------------------------------------
Pension Expense Before Adjustments for the Long-Term Nature of
Employee Future Benefit Costs 2 14 10
- ---------------------------------------------------------------------------------------------------
Difference Between Actual and Expected Return on Plan Assets 3 2 1
- ---------------------------------------------------------------------------------------------------
Difference Between Actual and Recognized Actuarial Losses 2 (8) (6)
- ---------------------------------------------------------------------------------------------------
Difference Between Actual and Recognized Past Service Costs - - -
- ---------------------------------------------------------------------------------------------------
NET PENSION EXPENSE 7 8 5
===================================================================================================
TOTAL NET PENSION EXPENSE 30 27 15
===================================================================================================
(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 Committees of Nexen and Canexus. Nexen's and Canexus'
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.
99
Syncrude's pension plan is governed and administered separately from ours.
Syncrude's investment assets are subject to similar investment goals, policies
and strategies.
EXPECTED
(%) 2007 2006 2005
- -------------------------------------------------------------------------------
NEXEN
- -------------------------------------------------------------------------------
Equity Securities 65 60 60
- -------------------------------------------------------------------------------
Debt Securities 35 40 40
- -------------------------------------------------------------------------------
Real Estate - - -
- -------------------------------------------------------------------------------
Other - - -
- -------------------------------------------------------------------------------
TOTAL 100 100 100
===============================================================================
- -------------------------------------------------------------------------------
CANEXUS
- -------------------------------------------------------------------------------
Equity Securities 50 60 60
- -------------------------------------------------------------------------------
Debt Securities 50 40 40
- -------------------------------------------------------------------------------
Real Estate - - -
- -------------------------------------------------------------------------------
Other - - -
- -------------------------------------------------------------------------------
TOTAL 100 100 100
===============================================================================
- -------------------------------------------------------------------------------
SYNCRUDE
- -------------------------------------------------------------------------------
Equity Securities 70 70 70
- -------------------------------------------------------------------------------
Debt Securities 30 30 30
- -------------------------------------------------------------------------------
Real Estate - - -
- -------------------------------------------------------------------------------
Other - - -
- -------------------------------------------------------------------------------
TOTAL 100 100 100
===============================================================================
(c) DEFINED CONTRIBUTION PENSION PLANS
Under these plans, pension benefits are based on plan contributions.
During 2006, Canadian pension expense for these plans was $4 million (2005--$4
million; 2004--$4 million). During 2006, US pension expense for these plans was
$4 million (2005--$4 million; 2004--$3 million).
(d) POST-RETIREMENT BENEFITS
Nexen provides certain post-retirement benefits, including group life and
supplemental health insurance, to eligible employees and their dependents.
These costs are fully accrued as compensation in the period employees work;
however, these future obligations are not funded. The present value of Nexen
employees' future post retirement benefits at December 31, 2006 was $6 million
(2005--$4 million) and $2 million for Canexus (2005--$2 million).
(e) EMPLOYER FUNDING CONTRIBUTIONS AND BENEFIT PAYMENTS
Canadian regulators have prescribed funding requirements for our defined
benefit plans. Our funding contributions over the last three years have met
these requirements and also included additional discretionary contributions
permitted by law. For our defined contribution plans, we make contributions on
behalf of our employees and no further obligation exists. Our funding
contributions for the defined benefit plans are:
Defined Benefit Contributions EXPECTED
2007 2006 2005
- -------------------------------------------------------------------------------
Nexen 11 24 2
- -------------------------------------------------------------------------------
Canexus 2 3 -
- -------------------------------------------------------------------------------
Syncrude 5 5 4
- -------------------------------------------------------------------------------
TOTAL FUNDING CONTRIBUTIONS 18 32 6
===============================================================================
100
Our most recent funding valuation was prepared as of June 30, 2006. Our
next funding valuation is required by June 30, 2009. Canexus' most recent
funding valuation was prepared as of August 18, 2005, and their next funding
valuation is required by December 31, 2007. Syncrude's most recent funding
valuation was prepared as of December 31, 2006, and their next funding
valuation is December 31, 2008.
Our total benefit payments in 2006 were $11 million for Nexen (2005--$8
million). Our share of Syncrude's total benefit payments in 2006 was $4 million
(2005--$3 million). Our estimated future payments are as follows:
DEFINED BENEFIT OTHER
NEXEN CANEXUS SYNCRUDE NEXEN CANEXUS SYNCRUDE
- -----------------------------------------------------------------------------------------------------------
2007 9 1 3 1 - -
- -----------------------------------------------------------------------------------------------------------
2008 9 1 3 2 - -
- -----------------------------------------------------------------------------------------------------------
2009 10 1 4 2 - -
- -----------------------------------------------------------------------------------------------------------
2010 11 1 4 2 - -
- -----------------------------------------------------------------------------------------------------------
2011 11 2 4 2 - -
- -----------------------------------------------------------------------------------------------------------
2012--2016 71 15 29 18 - 1
===========================================================================================================
17. MARKETING AND OTHER
2006 2005 2004
- -----------------------------------------------------------------------------------------------------------
Marketing Revenue, Net 1,309 847 608
- -----------------------------------------------------------------------------------------------------------
Business Interruption Insurance Proceeds (1) 154 2 10
- -----------------------------------------------------------------------------------------------------------
Change in Fair Value of Crude Oil Put Options (11) (196) 56
- -----------------------------------------------------------------------------------------------------------
Interest 36 29 12
- -----------------------------------------------------------------------------------------------------------
Foreign Exchange Losses (72) (19) (13)
- -----------------------------------------------------------------------------------------------------------
Gains on Disposition of Assets (2) 4 4 24
- -----------------------------------------------------------------------------------------------------------
Other 30 35 16
- -----------------------------------------------------------------------------------------------------------
TOTAL MARKETING AND OTHER 1,450 702 713
===========================================================================================================
NOTES:
(1) IN 2006, WE RECEIVED BUSINESS INTERRUPTION INSURANCE PROCEEDS RELATED TO
PRODUCTION LOSSES CAUSED BY GULF OF MEXICO HURRICANES IN 2005 AND BY
GENERATOR FAILURES IN OUR UK OPERATIONS IN 2005.
(2) GAINS ON DISPOSITION OF ASSETS RESULTED FROM THE SALE OF MINOR OIL AND GAS
ASSETS IN OUR CANADIAN OPERATIONS IN 2006 AND 2004 AND FROM THE SALE OF
OUR EJULEBE ASSETS, OFFSHORE NIGERIA IN 2005.
18. INCOME TAXES
(a) TEMPORARY DIFFERENCES
2006 2005
FUTURE FUTURE FUTURE FUTURE
INCOME TAX INCOME TAX INCOME TAX INCOME TAX
ASSETS LIABILITIES ASSETS LIABILITIES
Property, Plant and Equipment, Net 26 2,420 31 1,780
- -----------------------------------------------------------------------------------------------------
Tax Losses Carried Forward 594 - 370 -
- -----------------------------------------------------------------------------------------------------
Deferred Income - 48 - 175
- -----------------------------------------------------------------------------------------------------
Recoverable Taxes - - 9 -
- -----------------------------------------------------------------------------------------------------
TOTAL (1) 620 2,468 410 1,955
=====================================================================================================
NOTE:
(1) 2006 INCLUDES FUTURE INCOME TAX ASSETS OF $479 MILLION THAT WE EXPECT TO
REALIZE IN THE FOLLOWING TWELVE MONTHS HAVE BEEN INCLUDED IN CURRENT
ASSETS.
101
(b) CANADIAN AND FOREIGN INCOME TAXES
2006 2005 2004
- ------------------------------------------------------------------------------------------------
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES
- ------------------------------------------------------------------------------------------------
Canadian (352) (396) 24
- ------------------------------------------------------------------------------------------------
Foreign 1,648 1,326 1,003
- ------------------------------------------------------------------------------------------------
1,296 930 1,027
- ------------------------------------------------------------------------------------------------
PROVISION FOR INCOME TAXES
- ------------------------------------------------------------------------------------------------
Current
- ------------------------------------------------------------------------------------------------
Canadian 14 1 6
- ------------------------------------------------------------------------------------------------
Foreign 354 338 242
- ------------------------------------------------------------------------------------------------
368 339 248
- ------------------------------------------------------------------------------------------------
Future
- ------------------------------------------------------------------------------------------------
Canadian (96) (206) (3)
- ------------------------------------------------------------------------------------------------
Foreign 411 101 72
- ------------------------------------------------------------------------------------------------
315 (105) 69
- ------------------------------------------------------------------------------------------------
683 234 317
TOTAL PROVISION FOR INCOME TAXES
================================================================================================
The Canadian and foreign components of the provision for income taxes are
based on the jurisdiction in which income is taxed. Foreign taxes relate mainly
to Yemen, Colombia, the United Kingdom and the United States and include Yemen
cash taxes of $286 million (2005--$296 million; 2004--$227 million).
(c) RECONCILIATION OF EFFECTIVE TAX RATE TO THE CANADIAN STATUTORY TAX RATE
2006 2005 2004
- --------------------------------------------------------------------------------------------------
Income before Income Taxes From Continuing Operations 1,296 930 1,027
- --------------------------------------------------------------------------------------------------
- --------------------------------------------------------------------------------------------------
Provision for Income Taxes Computed at the Canadian Statutory Rate 401 318 354
- --------------------------------------------------------------------------------------------------
Add (Deduct) the Tax Effect of:
- --------------------------------------------------------------------------------------------------
Royalties, Rentals and Similar Payments to Provincial Governments 15 24 20
- --------------------------------------------------------------------------------------------------
Resource Allowance and Provincial Tax Rebates (15) (24) (29)
- --------------------------------------------------------------------------------------------------
Lower Foreign Tax Rates (9) (40) (22)
- --------------------------------------------------------------------------------------------------
Additional Canadian Tax on Canadian Resource Income 10 6 7
- --------------------------------------------------------------------------------------------------
Lower Tax Rates on Capital Gains (3) (54) -
- --------------------------------------------------------------------------------------------------
Federal and Provincial Capital Tax 13 5 6
- --------------------------------------------------------------------------------------------------
Effect of Changes in Tax Rates 245 - (15)
- --------------------------------------------------------------------------------------------------
Non-Deductible Expenses and Other 26 (1) (4)
- --------------------------------------------------------------------------------------------------
PROVISION FOR INCOME TAXES 683 234 317
==================================================================================================
During the first quarter of 2006, we recorded a future income tax expense
of $277 million related to an increase in the supplemental tax rate on oil and
gas activities in the United Kingdom. Legislation was introduced to the United
Kingdom parliament during the first quarter to increase the supplemental tax
rate from 10% to 20%, effective January 1, 2006.
In 2006 and 2004, the federal and some provincial governments in Canada
reduced statutory income tax rates. This reduced our liability and provision
for future income taxes by $32 million and $15 million in 2006 and 2004,
respectively.
102
(d) AVAILABLE UNUSED TAX LOSSES AND TAX CONTINGENCIES
At December 31, 2006 and 2005, we had unused tax losses totalling $1,258
million and $965 million, respectively, mostly from our UK operations. The
majority of these losses have no expiry date.
Nexen's income tax filings are subject to audit by taxation authorities.
There are audits in progress and items under review, some of which may increase
our tax liability. In addition, we have filed notices of objection with respect
to 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.
At the time of acquisition, Wascana, a predecessor company, had
outstanding taxation issues in dispute from prior taxation years. Wascana
disagreed with issues raised and has filed notices of objection. The value of
the tax pools acquired at the time of acquisition reflected our evaluation of
the potential impact of these issues.
19. CASH FLOWS
(a) CHARGES AND CREDITS TO INCOME NOT INVOLVING CASH
2006 2005 2004
- ---------------------------------------------------------------------------------------------------------
Depreciation, Depletion, Amortization and Impairment 1,124 1,052 674
- ---------------------------------------------------------------------------------------------------------
Stock-Based Compensation 101 428 74
- ---------------------------------------------------------------------------------------------------------
Gains on Disposition of Assets (4) (4) (24)
- ---------------------------------------------------------------------------------------------------------
Provision for Future Income Taxes 315 (105) 69
- ---------------------------------------------------------------------------------------------------------
Change in Fair Value of Crude Oil Put Options 11 196 (56)
- ---------------------------------------------------------------------------------------------------------
Non-Cash Items included in Discontinued Operations - (325) 132
- ---------------------------------------------------------------------------------------------------------
Unamortized Issue Costs on Preferred Securities Redemption - - 11
- ---------------------------------------------------------------------------------------------------------
Gain on Dilution of Interest in Chemicals Business - (193) -
- ---------------------------------------------------------------------------------------------------------
Net Income Attributable to Non-Controlling Interests 12 8 -
- ---------------------------------------------------------------------------------------------------------
Other 70 24 26
- ---------------------------------------------------------------------------------------------------------
TOTAL 1,629 1,081 906
=========================================================================================================
(b) CHANGES IN NON-CASH WORKING CAPITAL
2006 2005 2004
- ---------------------------------------------------------------------------------------------------------
Accounts Receivable 345 (1,078) (454)
- ---------------------------------------------------------------------------------------------------------
Inventories and Supplies (302) (163) (106)
- ---------------------------------------------------------------------------------------------------------
Other Current Assets (14) (10) 44
- ---------------------------------------------------------------------------------------------------------
Accounts Payable and Accrued Liabilities (72) 982 650
- ---------------------------------------------------------------------------------------------------------
Other - 20 (12)
- ---------------------------------------------------------------------------------------------------------
TOTAL (43) (249) 122
- ---------------------------------------------------------------------------------------------------------
- ---------------------------------------------------------------------------------------------------------
Relating to:
- ---------------------------------------------------------------------------------------------------------
Operating Activities (177) (195) (122)
- ---------------------------------------------------------------------------------------------------------
Investing Activities 134 (54) 244
- ---------------------------------------------------------------------------------------------------------
TOTAL (43) (249) 122
=========================================================================================================
103
(c) OTHER CASH FLOW INFORMATION
2006 2005 2004
- -------------------------------------------------------------------------------
Interest Paid 278 237 190
- -------------------------------------------------------------------------------
Income Taxes Paid 398 325 249
===============================================================================
In 2004, other operating activity cash outflows include $144 million for
the purchase of crude oil put options.
20. OPERATING SEGMENTS AND RELATED INFORMATION
Nexen has the following operating segments in various industries and
geographic locations:
OIL AND GAS: We explore for, develop and produce crude oil, natural gas
and related products around the world. We manage our operations to reflect
differences in the regulatory environments and risk factors for each country.
Our core operations are onshore in Yemen and Canada, and offshore in the US
Gulf of Mexico and the UK North Sea. Our other operations are primarily in West
Africa and Colombia.
ENERGY MARKETING: Our marketing group sells our crude oil and natural gas,
markets third-party crude oil and natural gas and engages in energy trading,
including electricity generation.
SYNCRUDE: We own 7.23% of the Syncrude Joint Venture, which develops and
produces synthetic crude oil from mining bitumen in the oil sands in northern
Alberta.
CHEMICALS: Through our investment in Canexus LP, we manufacture, market
and distribute industrial chemicals, principally sodium chlorate, chlorine,
acid and caustic soda. We produce sodium chlorate at four facilities in Canada
and one in Brazil. We produce chlorine, caustic soda and muriatic acid at
chlor-alkali facilities in Canada and Brazil.
The accounting policies of our operating segments are the same as those
described in Note 1. Net income of our operating segments excludes interest
income, interest expense, unallocated corporate expenses and foreign exchange
gains and losses with the exception of Chemicals. Identifiable assets are those
used in the operations of the segments.
104
2006 OPERATING AND GEOGRAPHIC SEGMENTS
CORPORATE
ENERGY AND
OIL AND GAS MARKETING SYNCRUDE CHEMICALS OTHER TOTAL
------------------------------------------------------------------------------------------------------
OTHER
YEMEN CANADA US UK COUNTRIES
(Cdn$ millions) (1)
- ----------------------------------------------------------------------------------------------------------------------------------
Net Sales (2) 1,328 459 629 477 139 51 446 407(3) - 3,936
- ----------------------------------------------------------------------------------------------------------------------------------
Marketing and Other 8 7 81(4) 85(5) 1 1,309 - 6 (47)(6) 1,450
- ----------------------------------------------------------------------------------------------------------------------------------
1,336 466 710 562 140 1,360 446 413 (47) 5,386
- ----------------------------------------------------------------------------------------------------------------------------------
Less: Expenses
- ----------------------------------------------------------------------------------------------------------------------------------
Operating 151 143 106 80 8 31 187 249 - 955
- ----------------------------------------------------------------------------------------------------------------------------------
Depreciation,
Depletion,
Amortization and
Impairment (7) 327 162 296 216 10 12 33 40 28 1,124
- ----------------------------------------------------------------------------------------------------------------------------------
Transportation and Other 6 33 - - 1 789 18 40 154(8) 1,041
- ----------------------------------------------------------------------------------------------------------------------------------
General and
Administrative (9) 17 80 58 14 44 112 1 29 200 555
- ----------------------------------------------------------------------------------------------------------------------------------
Exploration 4 26 214 46 72(10) - - - - 362
- ----------------------------------------------------------------------------------------------------------------------------------
Interest - - - - - - - 11 42 53
- ----------------------------------------------------------------------------------------------------------------------------------
Income (Loss) from
Continuing Operations
before Income Taxes 831 22 36 206 5 416 207 44 (471) 1,296
- ----------------------------------------------------------------------------------------------------------------------------------
Less: Provision for
(Recovery of) Income
Taxes (11) 289 7 13 378(12) 1 151 66 15 (237) 683
- ----------------------------------------------------------------------------------------------------------------------------------
Net Income (Loss) from
Continuing Operations 542 15 23 (172) 4 265 141 29 (234) 613
- ----------------------------------------------------------------------------------------------------------------------------------
Less: Non-Controlling
Interests - - - - - - - 12 - 12
- ----------------------------------------------------------------------------------------------------------------------------------
NET INCOME (LOSS) 542 15 23 (172) 4 265 141 17 (234) 601
- ----------------------------------------------------------------------------------------------------------------------------------
IDENTIFIABLE ASSETS 464 3,923 1,620 5,490 245 3,528(13) 1,186 459 241 17,156
- ----------------------------------------------------------------------------------------------------------------------------------
Capital Expenditures
- ----------------------------------------------------------------------------------------------------------------------------------
Development and Other 145 1,434 418 596 28 47 86 27 45 2,826
- ----------------------------------------------------------------------------------------------------------------------------------
Exploration 37 163 177 62 52 - - - - 491
- ----------------------------------------------------------------------------------------------------------------------------------
Proved Property
Acquisitions - 12 - 1 - - - - - 13
- ----------------------------------------------------------------------------------------------------------------------------------
TOTAL CAPITAL EXPENDITURES 182 1,609 595 659 80 47 86 27 45 3,330
- ----------------------------------------------------------------------------------------------------------------------------------
Property, Plant and
Equipment
Cost 2,404 5,216 2,889 4,710 249 226 1,304 854 286 18,138
- ----------------------------------------------------------------------------------------------------------------------------------
Less: Accumulated DD&A 2,128 1,448 1,445 432 78 47 179 494 148 6,399
- ----------------------------------------------------------------------------------------------------------------------------------
NET BOOK VALUE (2) 276 3,768 1,444 4,278 171 179 1,125 360 138 11,739
- ----------------------------------------------------------------------------------------------------------------------------------
GOODWILL - - - 325 - 52 - - - 377
==================================================================================================================================
NOTES:
(1) INCLUDES RESULTS OF OPERATIONS FROM PRODUCING ACTIVITIES IN COLOMBIA.
(2) NET SALES MADE FROM ALL SEGMENTS ORIGINATING IN CANADA: 1,095
PP&E LOCATED IN CANADA: 5,483
(3) NET SALES FOR OUR CHEMICALS OPERATIONS INCLUDE:
CANADA 139
UNITED STATES 185
BRAZIL 83
---
TOTAL 407
---
(4) INCLUDES $80 MILLION OF BUSINESS INTERRUPTION INSURANCE PROCEEDS RELATED
TO PRODUCTION LOSSES CAUSED BY GULF OF MEXICO HURRICANES IN 2005.
(5) INCLUDES $74 MILLION OF BUSINESS INTERRUPTION INSURANCE PROCEEDS FOR
GENERATOR FAILURES IN 2005.
(6) INCLUDES INTEREST INCOME OF $36 MILLION, FOREIGN EXCHANGE LOSSES OF $72
MILLION AND DECREASE IN THE FAIR VALUE OF CRUDE OIL PUT OPTIONS OF $11
MILLION.
(7) INCLUDES AN IMPAIRMENT CHARGE OF $93 MILLION, PRIMARILY RELATING TO TWO
NATURAL GAS PROPERTIES IN THE GULF OF MEXICO.
(8) INCLUDES $151 MILLION (US$135 MILLION) ACCRUAL WITH RESPECT TO THE BLOCK
51 ARBITRATION SETTLEMENT (SEE NOTE 15).
(9) INCLUDES STOCK-BASED COMPENSATION EXPENSE OF $210 MILLION.
(10) INCLUDES EXPLORATION ACTIVITIES PRIMARILY IN NIGERIA, NORWAY AND COLOMBIA.
(11) THE PROVISION FOR (RECOVERY OF) INCOME TAXES FOR FOREIGN LOCATIONS IS
BASED ON IN-COUNTRY TAXES ON FOREIGN INCOME. FOR OIL AND GAS LOCATIONS
WITH NO OPERATING ACTIVITIES, THE PROVISION IS BASED ON THE TAX
JURISDICTION OF THE ENTITY PERFORMING THE ACTIVITY.
(12) INCLUDES FUTURE INCOME TAX EXPENSE OF $277 MILLION RELATED TO AN INCREASE
IN THE SUPPLEMENTAL TAX RATE ON OIL AND GAS ACTIVITIES IN THE UNITED
KINGDOM (SEE NOTE 18).
(13) APPROXIMATELY 80% OF MARKETING'S IDENTIFIABLE ASSETS ARE ACCOUNTS
RECEIVABLE AND INVENTORIES.
105
2005 OPERATING AND GEOGRAPHIC SEGMENTS
CORPORATE
ENERGY AND
OIL AND GAS MARKETING SYNCRUDE CHEMICALS OTHER TOTAL
------------------------------------------------------------------------------------------------------
OTHER
YEMEN CANADA US UK COUNTRIES
(Cdn$ millions) (1) (2)
- ----------------------------------------------------------------------------------------------------------------------------------
Net Sales (3) 1,377 455 792 366 119 28 397 398(4) - 3,932
- ----------------------------------------------------------------------------------------------------------------------------------
Marketing and Other 8 3 2 16 4 847 - 15 (193)(5) 702
- ----------------------------------------------------------------------------------------------------------------------------------
Gain on Dilution of
Interest
in Chemicals Business - - - - - - - 193 - 193
- ----------------------------------------------------------------------------------------------------------------------------------
1,385 458 794 382 123 875 397 606 (193) 4,827
- ----------------------------------------------------------------------------------------------------------------------------------
Less: Expenses
- ----------------------------------------------------------------------------------------------------------------------------------
Operating 150 121 96 95 12 30 152 237 - 893
- ----------------------------------------------------------------------------------------------------------------------------------
Depreciation, Depletion,
Amortization and
Impairment 354 140 234 210 13 11 17 51(6) 22 1,052
- ----------------------------------------------------------------------------------------------------------------------------------
Transportation and Other 6 23 1 - 2 641 21 40 62 796
- ----------------------------------------------------------------------------------------------------------------------------------
General and
Administrative (7) 42 107 88 8 101 89 1 45 328 809
- ----------------------------------------------------------------------------------------------------------------------------------
Exploration 12 23 100 51 64(8) - - - - 250
- ----------------------------------------------------------------------------------------------------------------------------------
Interest - - - - - - - 3 94 97
- ----------------------------------------------------------------------------------------------------------------------------------
Income (Loss) from
Continuing Operations
before Income Taxes 821 44 275 18 (69) 104 206 230 (699) 930
- ----------------------------------------------------------------------------------------------------------------------------------
Less: Provision for
(Recovery of) Income
Taxes (9) 285 13 98 7 (13) 41 60 15 (272) 234
- ----------------------------------------------------------------------------------------------------------------------------------
Net Income (Loss) from
Continuing Operations 536 31 177 11 (56) 63 146 215 (427) 696
- ----------------------------------------------------------------------------------------------------------------------------------
Less: Non-Controlling
Interests - - - - - - - 8 - 8
- ----------------------------------------------------------------------------------------------------------------------------------
Add: Net Income from
Discontinued Operations - 452 - - - - - - - 452
- ----------------------------------------------------------------------------------------------------------------------------------
NET INCOME (LOSS) 536 483 177 11 (56) 63 146 207 (427) 1,140
- ----------------------------------------------------------------------------------------------------------------------------------
IDENTIFIABLE ASSETS 635 2,449 1,433 4,775 183 3,165(10) 1,135 482 333 14,590
- ----------------------------------------------------------------------------------------------------------------------------------
Capital Expenditures
- ----------------------------------------------------------------------------------------------------------------------------------
Development and Other 236 947 148 566 14 16 197 14 24 2,162
- ----------------------------------------------------------------------------------------------------------------------------------
Exploration 41 90 211 59 55 - - - - 456
- ----------------------------------------------------------------------------------------------------------------------------------
Proved Property
Acquisitions - 17 3 - - - - - - 20
- ----------------------------------------------------------------------------------------------------------------------------------
TOTAL CAPITAL EXPENDITURES 277 1,054 362 625 69 16 197 14 24 2,638
- ----------------------------------------------------------------------------------------------------------------------------------
Property, Plant and
Equipment
Cost 2,243 3,631 2,437 4,013 249 177 1,240 827 245 15,062
- ----------------------------------------------------------------------------------------------------------------------------------
Less: Accumulated DD&A 1,841 1,311 1,159 216 119 72 171 456 123 5,468
- ----------------------------------------------------------------------------------------------------------------------------------
NET BOOK VALUE (3) 402 2,320 1,278 3,797 130 105 1,069 371 122 9,594
- ----------------------------------------------------------------------------------------------------------------------------------
GOODWILL - - - 325 - 39 - - - 364
==================================================================================================================================
NOTES:
(1) DURING THE THIRD QUARTER OF 2005, WE CONCLUDED THE SALE OF CANADIAN
CONVENTIONAL OIL AND GAS PROPERTIES. THE RESULTS OF THESE PROPERTIES ARE
SHOWN AS DISCONTINUED OPERATIONS (SEE NOTE 14).
(2) INCLUDES RESULTS OF OPERATIONS FROM PRODUCING ACTIVITIES IN NIGERIA AND
COLOMBIA.
(3) NET SALES MADE FROM ALL SEGMENTS ORIGINATING IN CANADA: 1,014
PP&E LOCATED IN CANADA: 3,899
(4) NET SALES FOR OUR CHEMICALS OPERATIONS INCLUDE:
CANADA 132
UNITED STATES 198
BRAZIL 68
---
TOTAL 398
---
(5) INCLUDES INTEREST INCOME OF $29 MILLION, FOREIGN EXCHANGE LOSSES OF $19
MILLION, DECREASE IN THE FAIR VALUE OF CRUDE OIL PUT OPTIONS OF $196
MILLION AND DECREASE IN THE FAIR VALUE OF FOREIGN CURRENCY CALL OPTIONS OF
$7 MILLION.
(6) INCLUDES IMPAIRMENT CHARGE OF $12 MILLION RELATED TO THE CLOSURE OF OUR
SODIUM CHLORATE PLANT IN AMHERSTBURG, ONTARIO.
(7) INCLUDES STOCK-BASED COMPENSATION EXPENSE OF $507 MILLION.
(8) INCLUDES EXPLORATION ACTIVITIES PRIMARILY IN NIGERIA, COLOMBIA AND
EQUATORIAL GUINEA.
(9) THE PROVISION FOR (RECOVERY OF) INCOME TAXES FOR FOREIGN LOCATIONS IS
BASED ON IN-COUNTRY TAXES ON FOREIGN INCOME. FOR OIL AND GAS LOCATIONS
WITH NO OPERATING ACTIVITIES, THE PROVISION IS BASED ON THE TAX
JURISDICTION OF THE ENTITY PERFORMING THE ACTIVITY.
(10) APPROXIMATELY 86% OF MARKETING'S IDENTIFIABLE ASSETS ARE ACCOUNTS
RECEIVABLE AND INVENTORIES.
106
2004 OPERATING AND GEOGRAPHIC SEGMENTS
CORPORATE
OIL AND GAS ENERGY AND
MARKETING SYNCRUDE CHEMICALS OTHER TOTAL
----------------------------------------------------------------------------------------------------
OTHER
YEMEN CANADA US UK COUNTRIES
(Cdn$ millions) (1) (2)
- -----------------------------------------------------------------------------------------------------------------------------------
Net Sales (3) 921 390 811 36 73 14 321 378(4) - 2,944
- -----------------------------------------------------------------------------------------------------------------------------------
Marketing and Other 5 27 11 - 2 608 - 5 55(5) 713
- -----------------------------------------------------------------------------------------------------------------------------------
926 417 822 36 75 622 321 383 55 3,657
- -----------------------------------------------------------------------------------------------------------------------------------
Less: Expenses
- -----------------------------------------------------------------------------------------------------------------------------------
Operating 109 116 106 6 7 16 125 237 - 722
- -----------------------------------------------------------------------------------------------------------------------------------
Depreciation, Depletion,
Amortization and
Impairment 169 128 258 18 18 10 18 37 18 674
- -----------------------------------------------------------------------------------------------------------------------------------
Transportation and Other 5 15 - - - 451 12 41 25 549
- -----------------------------------------------------------------------------------------------------------------------------------
General and Administrative 4 42 30 - 47 58 1 28 89 299
- -----------------------------------------------------------------------------------------------------------------------------------
Exploration 2 18 138 3 82(6) - - - - 243
- -----------------------------------------------------------------------------------------------------------------------------------
Interest - - - - - - - - 143 143
- -----------------------------------------------------------------------------------------------------------------------------------
Income (Loss) from
Continuing Operations
before Income Taxes 637 98 290 9 (79) 87 165 40 (220) 1,027
- -----------------------------------------------------------------------------------------------------------------------------------
Less: Provision for (Recovery
of) Income Taxes (7) 222 28 104 4 1 28 47 13 (130) 317
- -----------------------------------------------------------------------------------------------------------------------------------
Net Income (Loss) from
Continuing Operations 415 70 186 5 (80) 59 118 27 (90) 710
- -----------------------------------------------------------------------------------------------------------------------------------
Add: Net Income from
Discontinued Operations (8) - 70 - - 13 - - - - 83
- -----------------------------------------------------------------------------------------------------------------------------------
NET INCOME (LOSS) 415 140 186 5 (67) 59 118 27 (90) 793
- -----------------------------------------------------------------------------------------------------------------------------------
IDENTIFIABLE ASSETS 564 1,979 1,359 4,446 218 2,030(9) 912 497 378 12,383
- -----------------------------------------------------------------------------------------------------------------------------------
Capital Expenditures
- -----------------------------------------------------------------------------------------------------------------------------------
Development and Other 267 491 267 53 24 4 214 58 33 1,411
- -----------------------------------------------------------------------------------------------------------------------------------
Exploration 19 46 133 4 64 - - - - 266
- -----------------------------------------------------------------------------------------------------------------------------------
Proved Property Acquisitions - 4 - - - - - - - 4
- -----------------------------------------------------------------------------------------------------------------------------------
TOTAL CAPITAL EXPENDITURES 286 541 400 57 88 4 214 58 33 1,681
- -----------------------------------------------------------------------------------------------------------------------------------
Property, Plant and
Equipment Cost 2,038 2,603 2,249 3,499 535 157 1,030 815 201 13,127
- -----------------------------------------------------------------------------------------------------------------------------------
Less: Accumulated DD&A 1,550 1,195 1,037 16 408 64 155 409 90 4,924
- -----------------------------------------------------------------------------------------------------------------------------------
NET BOOK VALUE (3) 488 1,408(10) 1,212 3,483 127 93 875 406 111 8,203
- -----------------------------------------------------------------------------------------------------------------------------------
GOODWILL - - - 339 - 36 - - - 375
===================================================================================================================================
NOTES:
(1) ON DECEMBER 1, 2004, WE ACQUIRED ENCANA (UK) LIMITED (SEE NOTE 3).
(2) INCLUDES RESULTS OF OPERATIONS FROM PRODUCING ACTIVITIES IN NIGERIA,
COLOMBIA, AND AUSTRALIA.
(3) NET SALES MADE FROM ALL SEGMENTS ORIGINATING IN CANADA: 1,242
PP&E LOCATED IN CANADA: 3,198
(4) NET SALES FOR OUR CHEMICALS OPERATIONS INCLUDE:
CANADA 135
UNITED STATES 184
BRAZIL 59
---
TOTAL 378
---
(5) INCLUDES INTEREST INCOME OF $12 MILLION, FOREIGN EXCHANGE LOSSES OF $13
MILLION AND UNREALIZED MARK-TO-MARKET GAINS ON CRUDE OIL PUT OPTIONS OF
$56 MILLION.
(6) INCLUDES EXPLORATION ACTIVITIES PRIMARILY IN NIGERIA AND COLOMBIA.
(7) THE PROVISION FOR (RECOVERY OF) INCOME TAXES FOR FOREIGN LOCATIONS IS
BASED ON IN-COUNTRY TAXES ON FOREIGN INCOME. FOR OIL AND GAS LOCATIONS
WITH NO OPERATING ACTIVITIES, THE PROVISION IS BASED ON THE TAX
JURISDICTION OF THE ENTITY PERFORMING THE ACTIVITY.
(8) IN THE FOURTH QUARTER OF 2004, WE CONCLUDED PRODUCTION ACTIVITIES IN
AUSTRALIA. DURING THE THIRD QUARTER OF 2005, WE CONCLUDED THE SALE OF
CERTAIN CANADIAN CONVENTIONAL OIL AND GAS PROPERTIES. THE COMBINED RESULTS
OF THESE DISPOSITIONS ARE SHOWN AS DISCONTINUED OPERATIONS (SEE NOTE 14).
(9) APPROXIMATELY 81% OF MARKETING'S IDENTIFIABLE ASSETS ARE ACCOUNTS
RECEIVABLE AND INVENTORIES.
(10) EXCLUDES PP&E COSTS OF $860 MILLION AND ACCUMULATED DD&A OF $420 MILLION
RELATING TO THE CANADIAN PROPERTIES DISPOSED OF DURING 2005 (SEE NOTE 14).
107
21. DIFFERENCES BETWEEN CANADIAN AND US GENERALLY ACCEPTED ACCOUNTING
PRINCIPLES
The Consolidated Financial Statements have been prepared in accordance
with Canadian GAAP. US GAAP Consolidated Financial Statements and summaries of
differences from Canadian GAAP are as follows:
CONSOLIDATED STATEMENT OF INCOME--US GAAP
FOR THE THREE YEARS ENDED DECEMBER 31, 2006
(Cdn$ millions, except per share amounts) 2006 2005 2004
- -------------------------------------------------------------------------------------------------------
Revenues and Other Income
- -------------------------------------------------------------------------------------------------------
Net Sales 3,936 3,932 2,944
- -------------------------------------------------------------------------------------------------------
Marketing and Other (ii); (x); (xi) 1,459 687 696
- -------------------------------------------------------------------------------------------------------
Gain on Dilution of Interest in Chemicals Business - 193 -
- -------------------------------------------------------------------------------------------------------
5,395 4,812 3,640
- -------------------------------------------------------------------------------------------------------
Expenses
- -------------------------------------------------------------------------------------------------------
Operating (iv) 958 903 731
- -------------------------------------------------------------------------------------------------------
Depreciation, Depletion, Amortization and Impairment (i) 1,124 1,081 716
- -------------------------------------------------------------------------------------------------------
Transportation and Other (x) 1,037 792 524
- -------------------------------------------------------------------------------------------------------
General and Administrative (viii); (ix) 597 792 263
- -------------------------------------------------------------------------------------------------------
Exploration 362 250 243
- -------------------------------------------------------------------------------------------------------
Interest 53 97 143
- -------------------------------------------------------------------------------------------------------
4,131 3,915 2,620
- -------------------------------------------------------------------------------------------------------
Income from Continuing Operations before Income Taxes 1,264 897 1,020
- -------------------------------------------------------------------------------------------------------
Provision for Income Taxes
- -------------------------------------------------------------------------------------------------------
Current 368 339 248
- -------------------------------------------------------------------------------------------------------
Deferred (ii) - (xi) 305 (108) 67
- -------------------------------------------------------------------------------------------------------
673 231 315
- -------------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------------
Net Income from Continuing Operations before Non-Controlling Interests 591 666 705
- -------------------------------------------------------------------------------------------------------
Net Income Attributable to Non-Controlling Interests 12 8 -
- -------------------------------------------------------------------------------------------------------
Net Income from Continuing Operations 579 658 705
- -------------------------------------------------------------------------------------------------------
Net Income from Discontinued Operations - 452 83
- -------------------------------------------------------------------------------------------------------
579 1,110 788
NET INCOME--US GAAP (1)
=======================================================================================================
EARNINGS PER COMMON SHARE ($/share)
- -------------------------------------------------------------------------------------------------------
Basic (Note 13)
- -------------------------------------------------------------------------------------------------------
Net Income from Continuing Operations 2.21 2.52 2.74
- -------------------------------------------------------------------------------------------------------
Net Income from Discontinued Operations - 1.74 0.32
- -------------------------------------------------------------------------------------------------------
2.21 4.26 3.06
- -------------------------------------------------------------------------------------------------------
Diluted (Note 13)
- -------------------------------------------------------------------------------------------------------
Net Income from Continuing Operations 2.15 2.47 2.71
- -------------------------------------------------------------------------------------------------------
Net Income from Discontinued Operations - 1.70 0.32
- -------------------------------------------------------------------------------------------------------
2.15 4.17 3.03
=======================================================================================================
NOTE:
(1) RECONCILIATION OF CANADIAN AND US GAAP NET INCOME
(Cdn$ millions) 2006 2005 2004
- -------------------------------------------------------------------------------------------------------
Net Income--Canadian GAAP 601 1,140 793
- -------------------------------------------------------------------------------------------------------
Impact of US Principles, Net of Income Taxes:
- -------------------------------------------------------------------------------------------------------
Depreciation, Depletion, Amortization and Impairment (i) - (29) (42)
- -------------------------------------------------------------------------------------------------------
Stock-Based Compensation (viii); (ix) (29) 12 36
- -------------------------------------------------------------------------------------------------------
Other (ii); (iv); (xi) 7 (13) 1
- -------------------------------------------------------------------------------------------------------
NET INCOME--US GAAP 579 1,110 788
=======================================================================================================
108
CONSOLIDATED BALANCE SHEET--US GAAP
DECEMBER 31, 2006 AND 2005
(Cdn$ millions, except share amounts) 2006 2005
- -------------------------------------------------------------------------------------------------------
ASSETS
- -------------------------------------------------------------------------------------------------------
Current Assets
- -------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents 101 48
- -------------------------------------------------------------------------------------------------------
Restricted Cash and Margin Deposits 197 70
- -------------------------------------------------------------------------------------------------------
Accounts Receivable (ii) 2,976 3,151
- -------------------------------------------------------------------------------------------------------
Inventories and Supplies 786 504
- -------------------------------------------------------------------------------------------------------
Deferred Income Tax Assets 479 -
- -------------------------------------------------------------------------------------------------------
Other 67 51
- -------------------------------------------------------------------------------------------------------
Total Current Assets 4,606 3,824
- -------------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------------
Property, Plant and Equipment 11,692 9,550
Net of Accumulated Depreciation, Depletion, Amortization and
Impairment of $6,792 (December 31, 2005--$5,861) (iv); (vii)
- -------------------------------------------------------------------------------------------------------
Goodwill 377 364
- -------------------------------------------------------------------------------------------------------
Deferred Income Tax Assets 141 410
- -------------------------------------------------------------------------------------------------------
Deferred Charges and Other Assets (v); (vi) 263 345
- -------------------------------------------------------------------------------------------------------
17,079 14,493
TOTAL ASSETS
=======================================================================================================
- -------------------------------------------------------------------------------------------------------
LIABILITIES AND SHAREHOLDERS' EQUITY
- -------------------------------------------------------------------------------------------------------
Current Liabilities
- -------------------------------------------------------------------------------------------------------
Short-Term Borrowings 158 -
- -------------------------------------------------------------------------------------------------------
Accounts Payable and Accrued Liabilities (ii); (ix) 3,839 3,745
- -------------------------------------------------------------------------------------------------------
Accrued Interest Payable 55 55
- -------------------------------------------------------------------------------------------------------
Dividends Payable 13 13
- -------------------------------------------------------------------------------------------------------
Total Current Liabilities 4,065 3,813
- -------------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------------
Long-Term Debt (v) 4,618 3,630
- -------------------------------------------------------------------------------------------------------
Deferred Income Tax Liabilities (i) - (xi) 2,427 1,906
- -------------------------------------------------------------------------------------------------------
Asset Retirement Obligations 683 590
- -------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities (vi) 597 505
- -------------------------------------------------------------------------------------------------------
Non-Controlling Interests 75 88
- -------------------------------------------------------------------------------------------------------
Shareholders' Equity
Common Shares, no par value
- -------------------------------------------------------------------------------------------------------
Authorized: Unlimited
- -------------------------------------------------------------------------------------------------------
Outstanding: 2006--262,513,206 shares
- -------------------------------------------------------------------------------------------------------
2005--261,140,571 shares 821 732
- -------------------------------------------------------------------------------------------------------
Contributed Surplus 4 2
- -------------------------------------------------------------------------------------------------------
Retained Earnings (i) - (xi) 3,945 3,418
- -------------------------------------------------------------------------------------------------------
Accumulated Other Comprehensive Income (ii); (iii); (vi) (156) (191)
- -------------------------------------------------------------------------------------------------------
Total Shareholders' Equity 4,614 3,961
- -------------------------------------------------------------------------------------------------------
Commitments, Contingencies and Guarantees
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY 17,079 14,493
=======================================================================================================
109
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME--US GAAP
FOR THE THREE YEARS ENDED DECEMBER 31, 2006
(Cdn$ millions) 2006 2005 2004
- -----------------------------------------------------------------------------------------------------
Net Income--US GAAP 579 1,110 788
- -----------------------------------------------------------------------------------------------------
Other Comprehensive Income, Net of Income Taxes:
- -----------------------------------------------------------------------------------------------------
Translation Adjustment (iii) - (56) (72)
- -----------------------------------------------------------------------------------------------------
Unrealized Mark-to-Market Gain (Loss) (ii) 77 (20) 11
- -----------------------------------------------------------------------------------------------------
Minimum Unfunded Pension Liability (vi) 5 (10) (1)
- -----------------------------------------------------------------------------------------------------
COMPREHENSIVE INCOME 661 1,024 726
=====================================================================================================
CONSOLIDATED STATEMENT OF ACCUMULATED OTHER COMPREHENSIVE INCOME--US GAAP
DECEMBER 31, 2006 AND 2005
(Cdn$ millions) 2006 2005
- ------------------------------------------------------------------------------------------------------
Translation Adjustment (iii) (161) (161)
- ------------------------------------------------------------------------------------------------------
Unrealized Mark-to-Market Gains (Losses) (ii) 61 (16)
- ------------------------------------------------------------------------------------------------------
Minimum Pension Liability Adjustment (vi) - (14)
- ------------------------------------------------------------------------------------------------------
Unamortized Defined Benefit Pension Plan Costs (vi) (56) -
- ------------------------------------------------------------------------------------------------------
ACCUMULATED OTHER COMPREHENSIVE INCOME (AOCI) (156) (191)
======================================================================================================
NOTES TO THE CONSOLIDATED US GAAP FINANCIAL STATEMENTS:
i. Under US GAAP, the liability method of accounting for income taxes was
adopted in 1993. In Canada, the liability method was adopted in 2000. In
1997, we acquired certain oil and gas assets and the amount paid for these
assets differed from the tax basis acquired. Under US principles, this
difference was recorded as a deferred tax liability with an increase to
PP&E rather than a charge to retained earnings. As a result, additional
depreciation, depletion, amortization and impairment of $29 million was
included in net income during 2005 (2004--$42 million). The difference was
fully amortized during 2005.
ii. Under US GAAP, all derivative instruments are recognized on the balance
sheet as either an asset or a liability measured at fair value. Changes in
the fair value of derivatives are recognized in earnings unless specific
hedge criteria are met.
Cash flow hedges
Changes in the fair value of derivatives that are designated as cash
flow hedges are recognized in net income in the same period as the hedged
item. Any fair value change in a derivative before that period is
recognized on the balance sheet. The effective portion of that change is
recognized in other comprehensive income with any ineffectiveness
recognized in net income.
FUTURE SALE OF OIL AND GAS PRODUCTION: At December 31, 2003, accounts
payable includes a $3 million loss on forward contracts we used to hedge
commodity price risk on the future sale of a portion of our production
from the Aspen field. These contracts expired in March 2004. Losses ($2
million, net of income taxes), that were deferred in accumulated other
comprehensive income (AOCI) at December 31, 2003, were recognized in net
sales in 2004.
FUTURE SALE OF GAS INVENTORY: At December 31, 2003, accounts payable
includes $11 million of losses on futures and basis swap contracts we used
to hedge commodity price risk on the future sale of our gas inventory.
Losses of $8 million ($5 million, net of income taxes), related to the
effective portion and deferred in AOCI at December 31, 2003, were
recognized in marketing and other in 2004. Additionally, losses of $3
million ($2 million, net of income taxes), related to the ineffective
portion, were recognized in marketing and other under US GAAP in 2003.
Under Canadian GAAP, the ineffective portion was recognized in net income
in 2004.
At December 31, 2004, accounts receivable includes $6 million of gains
on futures contracts and swaps we used to hedge commodity price risk on
the future sale of our gas inventory. Gains of $6 million ($4 million net
of income taxes), related to the effective portion and deferred in AOCI at
December 31, 2004, were recognized in marketing and other in 2005.
110
At December 31, 2005, accounts payable includes losses of $35 million
on futures contracts and swaps we used to hedge commodity price risk on
the future sale of our gas inventory. Losses of $24 million ($16 million,
net of income taxes), related to the effective portion and deferred in
AOCI at December 31, 2005, were recognized in marketing and other in
2006. The ineffective portion of the losses of $11 million ($7 million,
net of income taxes) was recognized in US GAAP net income in 2005. Under
Canadian GAAP, the ineffective portion was recognized in marketing and
other in 2006.
At December 31, 2006, accounts receivable includes gains of $25
million on futures contracts and swaps we used to hedge commodity price
risk on the future sale of our gas inventory. Gains of $23 million ($16
million, net of income taxes), related to the effective portion, have
been deferred in AOCI until the underlying gas inventory is sold. These
gains will be reclassified to marketing and other as the contracts settle
over the next 12 months. The ineffective portion of the gains of $2
million ($2 million, net of taxes) was recognized in marketing and other
in 2006.
Also included in AOCI at December 31, 2006 are gains of $65 million
($45 million, net of income taxes) related to de-designated cash flow
hedges as described in Note 7(b). These gains will be reclassified to
marketing and other over the next 12 months. Under Canadian GAAP, these
deferred gains are included in accounts payable and accrued liabilities.
Fair value hedges
Both the derivative instrument and the underlying commitment are
recognized on the balance sheet at their fair value. The change in fair
value of both are reflected in net income. At December 31, 2006, we had
no fair value hedges in place.
iii. Under US GAAP, exchange gains and losses arising from the translation of
our net investment in self-sustaining foreign operations are included in
comprehensive income. Additionally, exchange gains and losses, net of
income taxes, from the translation of our US-dollar long-term debt
designated as a hedge of our foreign net investment are included in
comprehensive income. Cumulative amounts are included in AOCI in the
Consolidated Balance Sheet--US GAAP.
iv. Under Canadian GAAP, we defer certain development costs and all
pre-operating revenues and costs to PP&E. Under US GAAP, these costs have
been included in operating expenses. As a result:
o operating expenses include pre-operating costs of $3 million ($2
million, net of income taxes) (2005--$10 million ($6 million net
of income taxes); 2004--$9 million ($6 million, net of income
taxes)); and
o PP&E is lower under US GAAP by $28 million (December 31,
2005--$25 million).
v. Under US GAAP, discounts on long-term debt are classified as a reduction
of long-term debt rather than as deferred charges and other assets.
Discounts of $55 million (December 31, 2005--$57 million) have been
included in long-term debt.
vi. On December 31, 2006, we adopted FASB Statement No. 158 EMPLOYERS'
ACCOUNTING FOR DEFINED BENEFIT PENSION AND OTHER POSTRETIREMENT PLANS as
described under changes in accounting policy--US GAAP. At year-end, the
unfunded amount of our defined benefit pension plans was $81 million.
This amount has been included in deferred credits and other liabilities
and $56 million, net of income taxes, has been included in AOCI. Prior to
the adoption of FAS 158 on December 31, 2006, we included our minimum
unfunded pension liability in deferred credits and other liabilities and
in AOCI. At December 31, 2005, $26 million was included in deferred
credits and other liabilities, $4 million was included in deferred
charges and other assets and $14 million, net of income taxes was
included in AOCI. During the year, our minimum unfunded pension liability
decreased by $5 million, net of income taxes (2005 - increased by $10
million, net of income taxes; 2004 - increased by $1 million, net of
income taxes).
vii. On January 1, 2003, we adopted FASB Statement No. 143, ACCOUNTING FOR
ASSET RETIREMENT OBLIGATIONS (FAS 143) for US GAAP reporting purposes. We
adopted the equivalent Canadian standard for asset retirement obligations
on January 1, 2004. These standards are consistent, except for the
adoption date, which resulted in our PP&E under US GAAP being lower by
$19 million.
viii. As described in Note 12(c), our existing stock option plan was modified
to a tandem option plan in 2004 to include a cash feature. Prior to the
modification of our stock option plan, we accounted for stock options
using the fair-value method. Following the addition of the cash feature,
we account for stock options using the intrinsic-value method. As a
result of the plan modification, we recognized an obligation of $85
million for our tandem options under both Canadian and US GAAP. This
resulted in a one-time, non-cash expense to net income for Canadian GAAP
purposes of $54 million, net of tax, in the second quarter of 2004. For
US GAAP purposes, $36 million of this expense was recognized as a
reduction of US GAAP retained earnings
111
and $18 million was recognized as an expense to our second quarter 2004
US GAAP net income. The reduction of US GAAP retained earnings was made
in respect of stock options granted prior to the adoption of FAS 123 on
January 1, 2003.
ix. Under Canadian principles, we record obligations for liability-based
stock compensation plans using the intrinsic-value method of accounting.
Under US principles, effective January 1, 2006 obligations for
liability-based stock compensation plans are recorded using the
fair-value method of accounting. In addition, under Canadian principles
as disclosed in Note 1(u), we retroactively adopted EIC-162 which
requires the accelerated recognition of stock-based compensation expense
for all stock-based awards made to our retired and retirement-eligible
employees. However, under US GAAP, the accelerated recognition of
stock-based compensation expense for such employees is only required in
respect of stock-based awards granted on or after January 1, 2006. As a
result:
o general and administrative expense is higher by $42 million ($29
million, net of income taxes) for the year ended December 31,
2006 (2005--lower by $17 million ($12 million, net of income
taxes));
o accounts payable and accrued liabilities are higher by $25
million at December 31, 2006 (2005--lower by $17 million); and
o the impact for 2004 is not material.
x. Under US GAAP, gains and losses on the disposition of assets are included
with transportation and other expense. Gains in 2006 of $4 million, 2005
of $4 million, and 2004 of $24 million were reclassified from marketing
and other to transportation and other.
xi. In May 2003, the FASB issued Statement No. 150, ACCOUNTING FOR CERTAIN
INSTRUMENTS WITH CHARACTERISTICS OF BOTH LIABILITIES AND EQUITY that
requires certain financial instruments, including our preferred
securities, to be valued at fair value with changes in fair value
recognized through net income. The $4 million increase in fair value from
January 1, 2004 to February 9, 2004 (redemption date of preferred
securities) was included in net income for the year ended December 31,
2004.
CHANGES IN ACCOUNTING POLICIES--US GAAP
STOCK-BASED COMPENSATION
On January 1, 2006, we adopted FASB Statement 123 (revised), SHARE-BASED
PAYMENT (Statement 123(R)) using the modified prospective approach and graded
vesting amortization. Under Statement 123(R), our tandem options and stock
appreciation rights (StARS) are considered liability-based stock compensation
plans. Under the modified prospective approach, no amounts are restated in
prior periods. Upon adoption of Statement 123(R), we recorded a cumulative
effect of a change in accounting principle of $2 million. This amount was
recorded in general and administrative expenses in our US GAAP Consolidated
Statement of Income in 2006.
Prior to the adoption of Statement 123(R), we accounted for our
liability-based stock compensation plans in accordance with FASB Interpretation
28, ACCOUNTING FOR STOCK APPRECIATION RIGHTS AND OTHER VARIABLE STOCK OPTION OR
AWARD PLANS (the intrinsic-value method). Accordingly, obligations were accrued
on a graded vesting basis and represented the difference between the market
value of our common shares and the exercise price of underlying options and
rights. Under Statement 123(R), obligations for liability-based stock
compensation plans are measured at their fair value, and are remeasured at fair
value in each subsequent reporting period.
Consistent with Statement 123(R), we account for any stock options that
do not include a cash feature (equity-based stock compensation plans), using
the fair-value method.
The impact of adopting Statement 123(R) on our results for the year ended
December 31, 2006 is as follows:
PRIOR TO AFTER
ADOPTION OF ADOPTION OF INCREASE/
(Cdn$ millions) FAS 123(R) FAS 123(R) (DECREASE)
- ----------------------------------------------------------------------------------------------------------------------
Income from Continuing Operations before Income Taxes --US GAAP 1,306 1,264 (42)
- ----------------------------------------------------------------------------------------------------------------------
Net Income--US GAAP 608 579 (29)
- ----------------------------------------------------------------------------------------------------------------------
Basic Earnings per Common Share--US GAAP ($/share) 2.32 2.21 (0.11)
- ----------------------------------------------------------------------------------------------------------------------
Diluted Earnings per Common Share--US GAAP ($/share) 2.26 2.15 (0.11)
======================================================================================================================
112
ASSUMPTIONS
We use the Generalized Black-Scholes option pricing model to estimate the
fair value of our stock-based compensation, with the following assumptions:
Expected Annual Dividends per Common Share ($/share) 0.20
Expected Volatility 40%
Risk-Free Interest Rate 4.3% - 4.4%
Weighted-Average Expected Life of Compensation Instruments (in years) 2.8 - 3.0
These assumptions are based on multiple factors, including historical
exercise patterns of employees in relatively homogenous groups with respect to
exercise and post-vesting employment termination behaviors, expected future
exercising patterns for those same homogenous groups, the implied volatility of
our stock price, our expected future dividend levels and the interest rate for
Government of Canada bonds. Our valuation methodology and assumptions are
consistent with those previously used under FAS 123.
STOCK OPTIONS
WEIGHTED
WEIGHTED AVERAGE WEIGHTED
AVERAGE REMAINING AGGREGATE AVERAGE
EXERCISE TERM TO INTRINSIC FAIR
NUMBER PRICE EXPIRY VALUE VALUE
(thousands) ($/option) (years) (Cdn$ millions) ($/option)
- ---------------------------------------------------------------------------------------------------------------------------
Outstanding at December 31, 2006 15,242 35 3.2 450 33
- ---------------------------------------------------------------------------------------------------------------------------
Outstanding at December 31, 2006
and Expected to Vest 15,156 35 3.2 445 34
- ---------------------------------------------------------------------------------------------------------------------------
Exercisable at December 31, 2006 9,345 24 2.6 373 39
===========================================================================================================================
The total intrinsic value of stock options exercised during the year
ended December 31, 2006 was $109 million (2005 - $83 million; 2004 - $60
million). As at December 31, 2006, we had $77 million of unrecognized
compensation expense related to stock options which we expect to recognize over
a weighted-average period of 1.5 years.
STOCK APPRECIATION RIGHTS
WEIGHTED
WEIGHTED AVERAGE WEIGHTED
AVERAGE REMAINING AGGREGATE AVERAGE
EXERCISE TERM TO INTRINSIC FAIR
NUMBER PRICE EXPIRY VALUE VALUE
(thousands) ($/option) (years) (Cdn$ millions) ($/option)
- ---------------------------------------------------------------------------------------------------------------------------
Outstanding at December 31, 2006 6,945 42 3.5 154 29
- ---------------------------------------------------------------------------------------------------------------------------
Outstanding at December 31, 2006
and Expected to Vest 6,759 42 3.5 151 30
- ---------------------------------------------------------------------------------------------------------------------------
Exercisable at December 31, 2006 3,076 27 2.6 115 38
===========================================================================================================================
The total intrinsic value of stock appreciation rights exercised during
the year ended December 31, 2006 was $46 million (2005--$34 million; 2004--$7
million). As at December 31, 2006, we had $54 million of unrecognized
compensation expense related to stock appreciation rights which we expect to
recognize over a weighted-average period of 1.6 years.
STOCK-BASED COMPENSATION EXPENSE AND PAYMENTS
For the year ended December 31, 2006, stock-based compensation expense of
$252 million (2005--$490 million; 2004--$57 million) was included in general
and administrative expense in the Consolidated Statement of Income--US GAAP.
For the year ended December 31, 2006, cash proceeds of $16 million were
received related to the exercise of stock options (2005--$29 million; 2004--$93
million).
113
For the year ended December 31, 2006, cash of $119 million (2005--$74
million; 2004--$10 million) was paid upon the exercise of stock options and
stock appreciation rights. The income tax benefit recorded from the exercise of
stock options and stock appreciation rights was $37 million (2005--$24 million;
2004--$3 million) for the period.
STOCK BASED COMPENSATION EXPENSE FOR RETIRED AND RETIREMENT ELIGIBLE EMPLOYEES
We recognize stock-based compensation expense for our retired and
retirement-eligible employees over an accelerated graded vesting period in
accordance with the provisions of Statement 123(R) for stock-based awards
granted to employees on or after January 1, 2006. For stock-based awards
granted prior to the adoption of Statement 123(R), stock-based compensation
expense for our retired and retirement-eligible employees is recognized over a
graded vesting period. If we applied the accelerated graded vesting provisions
of Statement 123(R) to stock-based awards granted to our retired and
retirement-eligible employees prior to the adoption of Statement 123(R), our
stock-based compensation expense would decrease by $10 million for the year
ended December 31, 2006 (2005--increase by $19 million; 2004--increase by $2
million).
PENSION AND OTHER POST-RETIREMENT BENEFITS
On December 31, 2006, we adopted FASB Statement 158, EMPLOYERS'
ACCOUNTING FOR DEFINED BENEFIT PENSION AND OTHER POSTRETIREMENT PLANS
(Statement 158), which requires, among other things, the recognition of the
over-funded and under-funded status of a defined benefit plan on the balance
sheet as an asset or liability. The initial impact of the standard due to
unrecognized prior service costs or credits and net actuarial gains or losses
as well as subsequent changes in the funded status is recognized as a component
of AOCI in shareholders' equity. Additional minimum pension liabilities and
related intangible assets are also de-recognized upon adoption of Statement
158.
The impact of adopting Statement 158 at December 31, 2006 reduced
deferred charges and other assets by $4 million, reduced deferred future income
tax liabilities by $22 million, increased deferred credits and other
liabilities by $65 million and decreased AOCI by $47 million. The impact
considered the additional minimum pension liability at December 31, 2006 prior
to the adoption of Statement 158.
NEW ACCOUNTING PRONOUNCEMENTS
In February 2006, the FASB issued Statement 155, ACCOUNTING FOR CERTAIN
HYBRID INSTRUMENTS, which amends Statement 133, ACCOUNTING FOR DERIVATIVE
INSTRUMENTS AND HEDGING ACTIVITIES, and Statement 140, ACCOUNTING FOR TRANSFERS
AND SERVICING OF FINANCIAL ASSETS AND EXTINGUISHMENTS OF LIABILITIES. Statement
155 permits fair value re-measurement for any hybrid financial instrument that
contains an embedded derivative that otherwise would require bifurcation from
its host contract in accordance with Statement 133. Statement 155 also
clarifies other provisions of Statement 133 and Statement 140. This statement
is effective for all financial instruments acquired or issued in fiscal years
beginning after September 15, 2006. We do not expect adoption of this statement
will have a material impact on our results of operations or financial position.
In July 2006, FASB issued FIN 48 ACCOUNTING FOR UNCERTAINTY IN INCOME
TAXES with respect to FAS 109 ACCOUNTING FOR INCOME TAXES regarding accounting
for and disclosure of uncertain tax positions. This guidance seeks to reduce
the diversity in practice associated with certain aspects of the recognition
and measurement related to accounting for income taxes. This interpretation is
effective for fiscal years beginning after December 15, 2006. Adoption of this
standard is expected to increase our future income tax liabilities by no more
than $30 million and decrease our retained earnings by a corresponding amount.
In September 2006, FASB issued Statement 157, FAIR VALUE MEASUREMENTS.
Statement 157 defines fair value, establishes a framework for measuring fair
value under US generally accepted accounting principles and expands disclosures
about fair value measurements. This statement is effective for fiscal years
beginning after November 15, 2007. We do not expect the adoption of this
statement will have a material impact on our results of operations or financial
position.
114
SUPPLEMENTARY DATA (UNAUDITED)
QUARTERLY FINANCIAL DATA IN ACCORDANCE WITH CANADIAN AND US GAAP
QUARTER ENDED
MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31
(Cdn$ millions) 2006 2005 2006 2005 2006 2005 2006 2005
- ------------------------------------------------------------------------------------------------------------------------
Net Sales (1) 980 856 1,039 909 997 1,094 920 1,073
- ------------------------------------------------------------------------------------------------------------------------
Income (Loss) from Continuing Operations before
Income Taxes is Comprised of: (4)
- ------------------------------------------------------------------------------------------------------------------------
Oil and Gas (1), (2) 196 247 476 193 372 330 56 319
- ------------------------------------------------------------------------------------------------------------------------
Energy Marketing 166 30 69 54 42 (162) 139 182
- ------------------------------------------------------------------------------------------------------------------------
Syncrude 20 19 59 59 77 78 51 50
- ------------------------------------------------------------------------------------------------------------------------
Chemicals (3) 12 7 22 (2) 10 215 - 10
- ------------------------------------------------------------------------------------------------------------------------
Corporate and Other (66) (286) (92) (55) (171) (230) (142) (128)
========================================================================================================================
328 17 534 249 330 231 104 433
========================================================================================================================
NET INCOME (LOSS) FROM CONTINUING
OPERATIONS--CANADIAN GAAP (4) (83) 13 408 167 199 205 77 303
- ------------------------------------------------------------------------------------------------------------------------
US GAAP Adjustments 282 (5) (11) (9) (283) (9) (10) (7)
========================================================================================================================
NET INCOME (LOSS) FROM CONTINUING
OPERATIONS--US GAAP 199 8 397 158 (84) 196 67 296
========================================================================================================================
NET INCOME (LOSS)--CANADIAN GAAP (4) (83) 31 408 197 199 609 77 303
- ------------------------------------------------------------------------------------------------------------------------
US GAAP Adjustments 282 (5) (11) (9) (283) (9) (10) (7)
========================================================================================================================
NET INCOME (LOSS)--US GAAP 199 26 397 188 (84) 600 67 296
========================================================================================================================
EARNINGS (LOSS) PER COMMON SHARE FROM CONTINUING OPERATIONS
($/share)
- ------------------------------------------------------------------------------------------------------------------------
Canadian GAAP--Basic (0.32) 0.06 1.56 0.64 0.76 0.79 0.29 1.16
- ------------------------------------------------------------------------------------------------------------------------
Canadian GAAP--Diluted (0.32) 0.06 1.53 0.63 0.74 0.77 0.29 1.13
- ------------------------------------------------------------------------------------------------------------------------
US GAAP--Basic 0.76 0.03 1.52 0.61 (0.33) 0.75 0.26 1.13
- ------------------------------------------------------------------------------------------------------------------------
US GAAP--Diluted 0.74 0.03 1.48 0.60 (0.33) 0.73 0.25 1.11
- ------------------------------------------------------------------------------------------------------------------------
EARNINGS (LOSS) PER COMMON
SHARE ($/share)
- ------------------------------------------------------------------------------------------------------------------------
Canadian GAAP--Basic (0.32) 0.13 1.56 0.76 0.76 2.34 0.29 1.16
- ------------------------------------------------------------------------------------------------------------------------
Canadian GAAP--Diluted (0.32) 0.13 1.53 0.75 0.74 2.28 0.29 1.13
- ------------------------------------------------------------------------------------------------------------------------
US GAAP--Basic 0.76 0.10 1.52 0.72 (0.33) 2.31 0.26 1.13
- ------------------------------------------------------------------------------------------------------------------------
US GAAP--Diluted 0.74 0.10 1.48 0.71 (0.33) 2.25 0.25 1.11
- ------------------------------------------------------------------------------------------------------------------------
DIVIDENDS DECLARED (5) 0.05 0.05 0.05 0.05 0.05 0.05 0.05 0.05
========================================================================================================================
COMMON SHARE PRICES ($/share)
- ------------------------------------------------------------------------------------------------------------------------
Toronto Stock Exchange--High 68.10 35.50 69.50 39.85 71.22 60.67 65.79 59.54
- ------------------------------------------------------------------------------------------------------------------------
Toronto Stock Exchange--Low 54.34 23.55 50.82 29.53 52.13 40.25 52.91 43.77
- ------------------------------------------------------------------------------------------------------------------------
New York Stock Exchange--High (US$) 59.94 29.18 61.68 32.32 63.65 51.73 58.37 51.69
- ------------------------------------------------------------------------------------------------------------------------
New York Stock Exchange--Low (US$) 46.98 19.44 45.63 23.28 46.70 31.95 46.90 36.80
========================================================================================================================
NOTES:
(1) EXCLUDES RESULTS OF CANADIAN CONVENTIONAL OIL AND GAS PROPERTIES SOLD IN
THE THIRD QUARTER OF 2005 IN SOUTHEAST SASKATCHEWAN, NORTHWEST
SASKATCHEWAN, NORTHEAST BRITISH COLUMBIA AND THE ALBERTA FOOTHILLS. THESE
RESULTS ARE SHOWN AS DISCONTINUED OPERATIONS (SEE NOTE 14 TO THE
CONSOLIDATED FINANCIAL STATEMENTS).
(2) THE FOURTH QUARTER OF 2006 INCLUDES AN IMPAIRMENT CHARGE OF $93 MILLION,
PRIMARILY RELATING TO TWO NATURAL GAS PROPERTIES IN THE GULF OF MEXICO.
(3) CHEMICALS OPERATING PROFIT INCLUDES A DILUTION GAIN OF $193 MILLION IN
THE THIRD QUARTER OF 2005 AS THE RESULT OF THE CANEXUS INITIAL PUBLIC
OFFERING.
(4) INCLUDES THE IMPACT OF CHANGES IN ACCOUNTING POLICIES AS DESCRIBED IN
NOTE 1(U) TO THE CONSOLIDATED FINANCIAL STATEMENTS.
(5) IN FEBRUARY 2007, THE BOARD OF DIRECTORS DECLARED A QUARTERLY DIVIDEND OF
$0.05 PER COMMON SHARE, PAYABLE APRIL 1, 2007, TO SHAREHOLDERS OF RECORD
ON MARCH 10, 2007.
(6) AT DECEMBER 31, 2006, THERE WERE 1,454 REGISTERED HOLDERS OF COMMON
SHARES AND 262,513,206 COMMON SHARES OUTSTANDING.
115
OIL AND GAS PRODUCING ACTIVITIES AND SYNCRUDE OPERATIONS (UNAUDITED)
The following oil and gas information is provided in accordance with the
FASB Statement No. 69 DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES. It
also includes information relating to our interest in Syncrude as it produces a
crude oil product similar to our oil and gas activities even though these
operations are considered mining activities under SEC regulations.
A. RESERVE QUANTITY INFORMATION
Our net proved reserves and changes in those reserves for our
conventional operations (excluding Syncrude) are disclosed below. The net
proved reserves represent management's best estimate of proved oil and natural
gas reserves after royalties. Reserve estimates for each property are prepared
internally each year, and at least 80% of the reserves (including Syncrude)
have been assessed by independent qualified reserves consultants.
Estimates of crude oil and natural gas proved reserves are determined
through analysis of geological and engineering data, and demonstrate reasonable
certainty that they are recoverable from known reservoirs under economic and
operating conditions that existed at year end. See Critical Accounting
Estimates in Item 7 for a description of our reserves estimation process.
OTHER
UNITED COUNTRIES
TOTAL YEMEN (1) CANADA UNITED STATES KINGDOM (3)
Conventional oil and bitumen are in
mmbbls and natural gas is in bcf OIL GAS OIL OIL GAS BITUMEN OIL GAS OIL GAS OIL
(2)
- ----------------------------------------------------------------------------------------------------------------------------------
PROVED DEVELOPED AND
UNDEVELOPED RESERVES (4)
- ----------------------------------------------------------------------------------------------------------------------------------
DECEMBER 31, 2003 289 661 110 97 405 4 67 256 - - 11
- ----------------------------------------------------------------------------------------------------------------------------------
Extensions and Discoveries 244 33 1 3 18 239 1 15 - - -
- ----------------------------------------------------------------------------------------------------------------------------------
Purchases of Reserves in Place 127 23 - 1 - - - - 126 23 -
- ----------------------------------------------------------------------------------------------------------------------------------
Sales of Reserves in Place (1) (3) - (1) (2) - - (1) - - -
- ----------------------------------------------------------------------------------------------------------------------------------
Revisions of Previous Estimates (265) (25) (12) (11) (7) (243) (6) (9) 3 (9) 4
- ----------------------------------------------------------------------------------------------------------------------------------
Production (43) (89) (19) (10) (42) - (10) (46) (1) (1) (3)
==================================================================================================================================
DECEMBER 31, 2004 351 600 80 79 372 - 52 215 128 13 12
- ----------------------------------------------------------------------------------------------------------------------------------
Extensions and Discoveries 15 111 5 4 47 - 1 57 5 7 -
- ----------------------------------------------------------------------------------------------------------------------------------
Purchases of Reserves in Place 2 - - 2 - - - - - - -
- ----------------------------------------------------------------------------------------------------------------------------------
Sales of Reserves in Place (28) (80) - (28) (80) - - - - - -
- ----------------------------------------------------------------------------------------------------------------------------------
Revisions of Previous Estimates 9 (18) (3) 2 3 - (5) (21) 15 - -
- ----------------------------------------------------------------------------------------------------------------------------------
Production (45) (81) (23) (9) (37) - (7) (36) (5) (8) (1)
==================================================================================================================================
DECEMBER 31, 2005 304 532 59 50 305 - 41 215 143 12 11
- ----------------------------------------------------------------------------------------------------------------------------------
Extensions and Discoveries 52 89 1 1 54 - 2 26 23 9 25
- ----------------------------------------------------------------------------------------------------------------------------------
Purchases of Reserves in Place - 1 - - 1 - - - - - -
- ----------------------------------------------------------------------------------------------------------------------------------
Sales of Reserves in Place - - - - - - - - - - -
- ----------------------------------------------------------------------------------------------------------------------------------
Revisions of Previous Estimates 231 (16) (3) 3 (13) 219 (8) (12) 19 9 1
- ----------------------------------------------------------------------------------------------------------------------------------
Production (38) (74) (19) (6) (33) - (5) (34) (6) (7) (2)
==================================================================================================================================
DECEMBER 31, 2006 549 532 38 48 314 219 30 195 179 23 35
==================================================================================================================================
PROVED DEVELOPED RESERVES (5)
- ----------------------------------------------------------------------------------------------------------------------------------
December 31, 2004 199 518 49 72 348 - 48 166 20 4 10
- ----------------------------------------------------------------------------------------------------------------------------------
December 31, 2005 154 438 46 44 275 - 37 161 17 2 10
- ----------------------------------------------------------------------------------------------------------------------------------
DECEMBER 31, 2006 286 460 33 44 287 40 28 161 131 12 10
==================================================================================================================================
NOTES:
(1) UNDER THE TERMS OF THE MASILA AND THE BLOCK 51 PRODUCTION SHARING
CONTRACTS, PRODUCTION IS DIVIDED INTO COST RECOVERY OIL AND PROFIT OIL.
COST RECOVERY OIL PROVIDES FOR THE RECOVERY OF ALL OUR COSTS AND THOSE OF
OUR PARTNERS. REMAINING PRODUCTION IS PROFIT OIL, WHICH IS SHARED BETWEEN
THE PARTNERS AND THE GOVERNMENT OF YEMEN BASED ON PRODUCTION RATES, WITH
THE PARTNERS' SHARE RANGING FROM 20% TO 33%. 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 HAVE BEEN 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 WILL INCREASE AS OIL PRICES DECREASE (AND VICE VERSA)
AS THE BARRELS NECESSARY TO ACHIEVE COST RECOVERY CHANGE WITH PREVAILING
OIL PRICES. PRODUCTION INCLUDES VOLUMES USED FOR FUEL.
(2) REPRESENTS BITUMEN RESERVES FROM THE INSITU RECOVERY OF CANADIAN OIL
SANDS, RATHER THAN UPGRADED SYNTHETIC CRUDE OIL RESERVES TO BE SOLD.
(3) REPRESENTS RESERVES IN NIGERIA AND COLOMBIA.
(4) PROVED OIL AND GAS RESERVES ARE THE ESTIMATED QUANTITIES OF NATURAL GAS,
CRUDE OIL, CONDENSATE AND NATURAL GAS LIQUIDS THAT GEOLOGICAL AND
ENGINEERING DATA DEMONSTRATE WITH REASONABLE CERTAINTY CAN BE RECOVERED
IN FUTURE YEARS FROM KNOWN RESERVOIRS UNDER EXISTING ECONOMIC AND
OPERATING CONDITIONS. RESERVES ARE CONSIDERED "PROVED" IF THEY CAN BE
PRODUCED ECONOMICALLY, AS DEMONSTRATED BY EITHER ACTUAL PRODUCTION OR
CONCLUSIVE FORMATION TEST.
(5) PROVED DEVELOPED OIL AND GAS RESERVES ARE EXPECTED TO BE RECOVERED
THROUGH EXISTING WELLS WITH EXISTING EQUIPMENT AND OPERATING METHODS.
116
Our net proved reserves and changes in those reserves for our Syncrude
operations are disclosed below. Additional disclosures required by SEC Industry
Guide 7 are on pages 22 and 23. The net proved reserves represent management's
best estimate of proved synthetic reserves after royalties.
Estimates of Syncrude's synthetic crude oil reserves are based on
detailed geological and engineering assessments of the bitumen volume in-place,
the mining plan, historical extraction recovery and upgrading yield factors,
installed plant operating capacity and operating approval limits. The in-place
volume, depth and grade are established through extensive and closely spaced
core drilling. In accordance with the approved mining plan, there are an
estimated 1,780 million tons of economically extractable oil sands in the Base
and North Mines, with an average bitumen grade of 10.6 weight percent. The
Aurora North Mine contains an estimated 4,810 million tons of economically
extractable oil sands at an average bitumen grade of 11.2 weight percent.
Aurora South Lease 31 contains measured economically extractable oil sands of
4,309 million tons at an average bitumen grade of 10.8 weight percent.
SYNTHETIC CRUDE OIL
BASE MINE
AND NORTH AURORA (2) TOTAL
(millions of barrels) MINE (1)
- --------------------------------------------------------------------------------------------------------
DECEMBER 31, 2003 55 193 248
- --------------------------------------------------------------------------------------------------------
Revision of Previous Estimates (1) (5) (6)
- --------------------------------------------------------------------------------------------------------
Extensions and Discoveries - 19 19
- --------------------------------------------------------------------------------------------------------
Production (4) (2) (6)
- --------------------------------------------------------------------------------------------------------
DECEMBER 31, 2004 50 205 255
- --------------------------------------------------------------------------------------------------------
- (4) (4)
Revision of Previous Estimates
- --------------------------------------------------------------------------------------------------------
Extensions and Discoveries - 19 19
- --------------------------------------------------------------------------------------------------------
Production (3) (3) (6)
- --------------------------------------------------------------------------------------------------------
DECEMBER 31, 2005 47 217 264
- --------------------------------------------------------------------------------------------------------
Revision of Previous Estimates 1 4 5
- --------------------------------------------------------------------------------------------------------
Extensions and Discoveries - 11 11
- --------------------------------------------------------------------------------------------------------
Production (3) (3) (6)
- --------------------------------------------------------------------------------------------------------
DECEMBER 31, 2006 45 229 274
========================================================================================================
NOTES:
(1) LEASES 17 AND 22
(2) LEASES 10, 12, 31 AND 34.
117
B. CAPITALIZED COSTS (EXCLUDING SYNCRUDE OPERATIONS)
PROVED UNPROVED ACCUMULATED CAPITALIZED
(Cdn$ millions) PROPERTIES PROPERTIES DD&A COSTS
- -------------------------------------------------------------------------------------------------------------
DECEMBER 31, 2006
- -------------------------------------------------------------------------------------------------------------
Yemen 2,404 - (2,128) 276
- -------------------------------------------------------------------------------------------------------------
Canada 3,787 227 (1,467) 2,547
- -------------------------------------------------------------------------------------------------------------
United States 2,768 121 (1,445) 1,444
- -------------------------------------------------------------------------------------------------------------
United Kingdom 4,325 385 (432) 4,278
- -------------------------------------------------------------------------------------------------------------
Other Countries 99 150 (78) 171
- -------------------------------------------------------------------------------------------------------------
TOTAL CAPITALIZED COSTS 13,383 883 (5,550) 8,716
=============================================================================================================
DECEMBER 31, 2005
- -------------------------------------------------------------------------------------------------------------
Yemen 2,243 - (1,841) 402
- -------------------------------------------------------------------------------------------------------------
Canada 3,463 143 (1,330) 2,276
- -------------------------------------------------------------------------------------------------------------
United States 2,323 114 (1,159) 1,278
- -------------------------------------------------------------------------------------------------------------
United Kingdom 3,603 410 (216) 3,797
- -------------------------------------------------------------------------------------------------------------
Other Countries 88 161 (119) 130
- -------------------------------------------------------------------------------------------------------------
TOTAL CAPITALIZED COSTS 11,720 828 (4,665) 7,883
=============================================================================================================
DECEMBER 31, 2004
- -------------------------------------------------------------------------------------------------------------
Yemen 2,022 16 (1,550) 488
- -------------------------------------------------------------------------------------------------------------
Canada 3,732 136 (2,025) 1,843
- -------------------------------------------------------------------------------------------------------------
United States 2,102 147 (1,037) 1,212
- -------------------------------------------------------------------------------------------------------------
United Kingdom 3,117 382 (16) 3,483
- -------------------------------------------------------------------------------------------------------------
Other Countries 437 98 (408) 127
- -------------------------------------------------------------------------------------------------------------
TOTAL CAPITALIZED COSTS 11,410 779 (5,036) 7,153
=============================================================================================================
C. COSTS INCURRED (EXCLUDING SYNCRUDE OPERATIONS)
OIL AND GAS
TOTAL
OIL
AND UNITED UNITED
(Cdn$ millions) GAS YEMEN CANADA STATES KINGDOM OTHER
- ---------------------------------------------------------------------------------------------------------------
YEAR ENDED DECEMBER 31, 2006
- ---------------------------------------------------------------------------------------------------------------
Property Acquisition Costs
- ---------------------------------------------------------------------------------------------------------------
Proved 13 - 12 - 1 -
- ---------------------------------------------------------------------------------------------------------------
Unproved 125 - 105 19 1 -
- ---------------------------------------------------------------------------------------------------------------
Exploration Costs 514 37 74 242 71 90
- ---------------------------------------------------------------------------------------------------------------
Development Costs 2,051 145 884 399 595 28
- ---------------------------------------------------------------------------------------------------------------
Asset Retirement Costs 69 4 5 4 56 -
- ---------------------------------------------------------------------------------------------------------------
TOTAL COSTS INCURRED 2,772 186 1,080 664 724 118
===============================================================================================================
YEAR ENDED DECEMBER 31, 2005
- ---------------------------------------------------------------------------------------------------------------
Property Acquisition Costs
- ---------------------------------------------------------------------------------------------------------------
Proved 20 - 17 3 - -
- ---------------------------------------------------------------------------------------------------------------
Unproved 15 - - 9 6 -
- ---------------------------------------------------------------------------------------------------------------
Exploration Costs 509 44 97 235 61 72
- ---------------------------------------------------------------------------------------------------------------
Development Costs 1,896 236 947 139 560 14
- ---------------------------------------------------------------------------------------------------------------
Asset Retirement Costs 196 13 58 45 80 -
- ---------------------------------------------------------------------------------------------------------------
TOTAL COSTS INCURRED 2,636 293 1,119 431 707 86
===============================================================================================================
YEAR ENDED DECEMBER 31, 2004
- ---------------------------------------------------------------------------------------------------------------
Property Acquisition Costs
- ---------------------------------------------------------------------------------------------------------------
Proved 1,774 - 4 - 1,770 -
- ---------------------------------------------------------------------------------------------------------------
Unproved 1,491 - - - 1,491 -
- ---------------------------------------------------------------------------------------------------------------
Exploration Costs 339 22 56 162 4 95
- ---------------------------------------------------------------------------------------------------------------
Development Costs 1,102 267 491 267 53 24
- ---------------------------------------------------------------------------------------------------------------
Asset Retirement Costs 168 3 27 4 134 -
- ---------------------------------------------------------------------------------------------------------------
TOTAL COSTS INCURRED 4,874 292 578 433 3,452 119
===============================================================================================================
118
D. RESULTS OF OPERATIONS FOR PRODUCING ACTIVITIES (EXCLUDING SYNCRUDE OPERATIONS)
OIL AND GAS
TOTAL
OIL OTHER
AND CANADA UNITED UNITED COUNTRIES
(Cdn$ millions) GAS YEMEN (1) STATES KINGDOM (1)
- --------------------------------------------------------------------------------------------------------------
YEAR ENDED DECEMBER 31, 2006
- --------------------------------------------------------------------------------------------------------------
Net Sales 3,032 1,328 459 629 477 139
- --------------------------------------------------------------------------------------------------------------
Production Costs 491 151 146 106 80 8
- --------------------------------------------------------------------------------------------------------------
Exploration Expense 362 4 26 214 46 72
- --------------------------------------------------------------------------------------------------------------
Depreciation, Depletion,
Amortization and Impairment 1,011 327 162 296 216 10
- --------------------------------------------------------------------------------------------------------------
Other Expenses (Income) 71 15 106 (23) (71) 44
- --------------------------------------------------------------------------------------------------------------
1,097 831 19 36 206 5
- --------------------------------------------------------------------------------------------------------------
Income Tax Provision 687 289 6 13 378 1
- --------------------------------------------------------------------------------------------------------------
RESULTS OF OPERATIONS 410 542 13 23 (172) 4
==============================================================================================================
YEAR ENDED DECEMBER 31, 2005
- --------------------------------------------------------------------------------------------------------------
Net Sales 3,263 1,377 609 792 366 119
- --------------------------------------------------------------------------------------------------------------
Production Costs 511 150 158 96 95 12
- --------------------------------------------------------------------------------------------------------------
Exploration Expense 251 12 24 100 51 64
- --------------------------------------------------------------------------------------------------------------
Depreciation, Depletion,
Amortization and Impairment 1,008 354 197 234 210 13
- --------------------------------------------------------------------------------------------------------------
Other Expenses (Income) 335 40 125 83 (8) 95
- --------------------------------------------------------------------------------------------------------------
1,158 821 105 279 18 (65)
- --------------------------------------------------------------------------------------------------------------
Income Tax Provision (Recovery) 411 285 32 99 7 (12)
- --------------------------------------------------------------------------------------------------------------
RESULTS OF OPERATIONS 747 536 73 180 11 (53)
==============================================================================================================
YEAR ENDED DECEMBER 31, 2004
- --------------------------------------------------------------------------------------------------------------
Net Sales 2,538 921 622 811 36 148
- --------------------------------------------------------------------------------------------------------------
Production Costs 437 109 156 106 6 60
- --------------------------------------------------------------------------------------------------------------
Exploration Expense 246 2 21 138 3 82
- --------------------------------------------------------------------------------------------------------------
Depreciation, Depletion,
Amortization and Impairment 712 169 240 258 18 27
- --------------------------------------------------------------------------------------------------------------
Other Expenses 106 4 38 19 - 45
- --------------------------------------------------------------------------------------------------------------
1,037 637 167 290 9 (66)
- --------------------------------------------------------------------------------------------------------------
Income Tax Provision 406 222 75 104 4 1
- --------------------------------------------------------------------------------------------------------------
RESULTS OF OPERATIONS 631 415 92 186 5 (67)
==============================================================================================================
NOTE:
(1) 2005 AND 2004 INCLUDE RESULTS OF DISCONTINUED OPERATIONS (SEE NOTE 14).
119
E. STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS AND CHANGES
THEREIN (EXCLUDING SYNCRUDE OPERATIONS)
The following disclosure is based on estimates of net proved reserves
(excluding Syncrude) and the period during which they are expected to be
produced. Future cash inflows are computed by applying year-end prices to our
after royalty share of estimated annual future production from proved oil and
gas reserves (excluding Syncrude operations). Future development and production
costs to be incurred in producing and further developing the proved reserves
are based on year-end 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 in any way reflect the current
economic value of our oil and gas producing properties or the present value of
their estimated future cash flows as:
o no economic value is attributed to probable and possible reserves;
o use of a 10% discount rate is arbitrary; and
o prices change constantly from year-end levels.
120
UNITED UNITED OTHER
(Cdn$ millions) TOTAL YEMEN CANADA STATES KINGDOM COUNTRIES
- --------------------------------------------------------------------------------------------------------------
DECEMBER 31, 2006
- --------------------------------------------------------------------------------------------------------------
Future Cash Inflows 32,247 2,330 12,678 3,151 11,437 2,651
- --------------------------------------------------------------------------------------------------------------
Future Production Costs 9,523 606 5,615 791 2,236 275
- --------------------------------------------------------------------------------------------------------------
Future Development Costs 3,190 115 1,156 332 891 696
- --------------------------------------------------------------------------------------------------------------
Future Dismantlement and Site
Restoration Costs, Net 1,006 11 289 197 471 38
- --------------------------------------------------------------------------------------------------------------
Future Income Tax 5,204 489 753 450 3,308 204
==============================================================================================================
Future Net Cash Flows 13,324 1,109 4,865 1,381 4,531 1,438
- --------------------------------------------------------------------------------------------------------------
10% Discount Factor 4,951 106 2,484 321 970 1,070
- --------------------------------------------------------------------------------------------------------------
STANDARDIZED MEASURE 8,373 1,003 2,381 1,060 3,561 368
==============================================================================================================
- --------------------------------------------------------------------------------------------------------------
DECEMBER 31, 2005
- --------------------------------------------------------------------------------------------------------------
Future Cash Inflows 23,040 3,675 4,558 5,002 9,190 615
- --------------------------------------------------------------------------------------------------------------
Future Production Costs 5,477 807 1,886 811 1,892 81
- --------------------------------------------------------------------------------------------------------------
Future Development Costs 1,093 153 124 268 534 14
- --------------------------------------------------------------------------------------------------------------
Future Dismantlement and Site
Restoration Costs, Net 778 20 180 193 381 4
- --------------------------------------------------------------------------------------------------------------
Future Income Tax 4,496 795 244 1,107 2,172 178
==============================================================================================================
Future Net Cash Flows 11,196 1,900 2,124 2,623 4,211 338
- --------------------------------------------------------------------------------------------------------------
10% Discount Factor 3,154 338 811 697 1,209 99
- --------------------------------------------------------------------------------------------------------------
STANDARDIZED MEASURE 8,042 1,562 1,313 1,926 3,002 239
==============================================================================================================
- --------------------------------------------------------------------------------------------------------------
DECEMBER 31, 2004
- --------------------------------------------------------------------------------------------------------------
Future Cash Inflows 18,950 3,779 4,747 4,085 5,852 487
- --------------------------------------------------------------------------------------------------------------
Future Production Costs 4,781 722 2,135 613 1,271 40
- --------------------------------------------------------------------------------------------------------------
Future Development Costs 1,477 275 100 185 903 14
- --------------------------------------------------------------------------------------------------------------
Future Dismantlement and Site
Restoration Costs, Net 626 4 149 129 336 8
- --------------------------------------------------------------------------------------------------------------
Future Income Tax 2,798 388 382 845 1,058 125
==============================================================================================================
Future Net Cash Flows 9,268 2,390 1,981 2,313 2,284 300
- --------------------------------------------------------------------------------------------------------------
10% Discount Factor 2,978 499 760 631 1,011 77
- --------------------------------------------------------------------------------------------------------------
STANDARDIZED MEASURE 6,290 1,891 1,221 1,682 1,273 223
==============================================================================================================
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) 2006 2005 2004
- --------------------------------------------------------------------------------------------------------------
Beginning of Year 8,042 6,290 5,517
- --------------------------------------------------------------------------------------------------------------
Sales and Transfers of Oil and Gas Produced, Net of Production Costs (2,291) (2,028) (1,674)
- --------------------------------------------------------------------------------------------------------------
Net Changes in Prices and Production Costs Related to Future Production (1,065) 3,302 142
- --------------------------------------------------------------------------------------------------------------
Extensions, Discoveries and Improved Recovery, Less Related Costs 1 695 977 (71)
- --------------------------------------------------------------------------------------------------------------
Changes in Estimated Future Development and Dismantlement Costs (692) (135) (122)
- --------------------------------------------------------------------------------------------------------------
Previous Estimated Future Development and Dismantlement Costs
Incurred During The Period 1,048 638 604
- --------------------------------------------------------------------------------------------------------------
Revisions of Previous Quantity Estimates 1,936 478 (223)
- --------------------------------------------------------------------------------------------------------------
Accretion of Discount 1,117 799 692
- --------------------------------------------------------------------------------------------------------------
Purchases of Reserves in Place 2 15 1,764
- --------------------------------------------------------------------------------------------------------------
Sales of Reserves in Place (2) (882) (20)
- --------------------------------------------------------------------------------------------------------------
Net Change in Income Taxes (417) (1,412) (319)
- --------------------------------------------------------------------------------------------------------------
END OF YEAR 8,373 8,042 6,290
==============================================================================================================
NOTE:
(1) 2004 INCLUDES APPROXIMATELY $230 MILLION OF NEGATIVE DISCOUNTED FUTURE
NET CASH FLOWS RELATING TO BITUMEN RESERVES BASED ON YEAR-END
ASSUMPTIONS.
121
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
EXHIBITS
23.1* Consent of Independent Registered Chartered Accountants
23.2* Consent of William M. Cobb & Associates, Inc.
23.3* Consent of Ryder Scott Company, L.P.
23.4* Consent of McDaniel & Associates Consultants Ltd.
23.5* Consent of DeGolyer and MacNaughton.
31.1* Certification of Chief Executive Officer pursuant to Section 302
of the Sarbanes-Oxley Act of 2002.
31.2* Certification of Chief Financial Officer pursuant to Section 302
of the Sarbanes-Oxley Act of 2002.
32.1* Certification of periodic report by Chief Executive Officer
pursuant to 18 U.S.C., Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.
32.2* Certification of periodic report by Chief Financial Officer
pursuant to 18 U.S.C., Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.
* FILED WITH THIS FORM 10-K.
122
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Company has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized, on April 2, 2007.
NEXEN INC.
By: /s/ Charles W. Fischer
--------------------------
Charles W. Fischer
President, Chief Executive
Officer and Director
(Principal Executive Officer)
123