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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
|X| QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2005
|_| TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from.............to..........
COMMISSION FILE NUMBER 1-6702
[GRAPHIC OMITTED]
[NEXEN LOGO]
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
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 whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Exchange Act).
Yes [X] No [_]
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 September 30, 2005, there were 260,879,092 common shares issued and
outstanding.
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NEXEN INC.
INDEX
PART I FINANCIAL INFORMATION PAGE
Item 1. Unaudited Consolidated Financial Statements .................. 3
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations...........................30
Item 3. Quantitative and Qualitative Disclosures about Market Risk....50
Item 4. Controls and Procedures.......................................50
PART II OTHER INFORMATION
Item 6. Exhibits......................................................51
This report should be read in conjunction with our 2004 Annual Report on Form
10-K.
SPECIAL NOTE TO CANADIAN INVESTORS
Nexen is a US Securities and Exchange Commission (SEC) registrant and a Form
10-K and related forms filer. Therefore, our reserves estimates and securities
regulatory disclosures generally follow SEC requirements. In 2004, certain
Canadian regulatory authorities adopted NATIONAL INSTRUMENT 51-101 - STANDARDS
OF DISCLOSURE FOR OIL AND GAS ACTIVITIES (NI 51-101) which prescribe that
Canadian companies follow certain standards for the preparation and disclosure
of reserves and related information. We have been granted certain exemptions
from NI 51-101. Please refer to the SPECIAL NOTE TO CANADIAN INVESTORS on page
72 of our 2004 Annual Report on Form 10-K.
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
A NET, AFTER-ROYALTIES BASIS IS PRESENTED IN TABLES. VOLUMES AND RESERVES
INCLUDE SYNCRUDE OPERATIONS UNLESS OTHERWISE NOTED.
Below is a list of terms specific to the oil and gas industry. They are used
throughout the Form 10-Q.
/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
boe = barrels of oil equivalent NGL = natural gas liquid
WTI = West Texas Intermediate
Oil equivalents (boes) are used to aggregate quantities of natural gas with
crude oil by expressing them in a common unit. To calculate equivalents, we use
1 bbl = 6 mcf of natural gas. Boes may be misleading, particularly if used in
isolation. The conversion ratio is based on an energy equivalency conversion
method primarily applicable at the burner tip and does not represent a value
equivalency at the wellhead.
Electronic copies of our filings with the SEC and the Ontario Securities
Commission (OSC) (from November 8, 2002 onward) are available, free of charge,
on our web site (www.nexeninc.com). Filings prior to November 8, 2002 are
available free of charge, upon 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 or
the OSC. Alternatively, the SEC and the OSC each maintain a website (www.sec.gov
and www.sedar.com) that contain our reports, proxy and information statements
and other published information that have been filed or furnished with the SEC
and the OSC.
On September 30, 2005, the noon-day exchange rate for Cdn$1.00 was US$0.8613 as
reported by the Bank of Canada.
2
PART I
ITEM 1. UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
TABLE OF CONTENTS
Unaudited Consolidated Statement of Income
for the Three and Nine Months Ended September 30, 2005 and 2004...............4
Unaudited Consolidated Balance Sheet
as at September 30, 2005 and December 31, 2004................................5
Unaudited Consolidated Statement of Cash Flows
for the Three and Nine Months Ended September 30, 2005 and 2004...............6
Unaudited Consolidated Statement of Shareholders' Equity
for the Three and Nine Months Ended September 30, 2005 and 2004...............7
Notes to Unaudited Consolidated Financial Statements..........................8
3
NEXEN INC.
UNAUDITED CONSOLIDATED STATEMENT OF INCOME
FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30
Cdn$ millions, except per share amounts
THREE MONTHS NINE MONTHS
ENDED SEPTEMBER 30 ENDED SEPTEMBER 30
2005 2004 2005 2004
- ----------------------------------------------------------------------------------------------------------------------
Restated for
Changes in
Accounting
Principles
Note 1
REVENUES
Net Sales 1,094 778 2,859 2,139
Marketing and Other (Note 14) 24 147 343 439
Gain on Dilution of Interest in Chemicals Business (Note 2) 193 - 193 -
-------------------------------------------------
1,311 925 3,395 2,578
-------------------------------------------------
EXPENSES
Operating 221 195 650 534
Depreciation, Depletion, Amortization and Impairment 256 164 748 480
Transportation and Other 201 122 583 400
General and Administrative 342 57 647 247
Exploration 32 54 164 107
Interest (Note 7) 19 35 84 118
-------------------------------------------------
1,071 627 2,876 1,886
-------------------------------------------------
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES 240 298 519 692
-------------------------------------------------
PROVISION FOR INCOME TAXES
Current 95 73 255 189
Future (71) 25 (141) 19
-------------------------------------------------
24 98 114 208
-------------------------------------------------
NET INCOME FROM CONTINUING OPERATIONS
BEFORE NON-CONTROLLING INTERESTS 216 200 405 484
NET INCOME ATTRIBUTABLE TO NON-CONTROLLING INTERESTS 5 - 5 -
-------------------------------------------------
NET INCOME FROM CONTINUING OPERATIONS 211 200 400 484
Net Income from Discontinued Operations (Note 15) 404 20 452 63
-------------------------------------------------
NET INCOME 615 220 852 547
=================================================
EARNINGS PER COMMON SHARE FROM CONTINUING OPERATIONS ($/share)
Basic (Note 12) 0.81 0.77 1.54 1.88
=================================================
Diluted (Note 12) 0.79 0.76 1.51 1.86
=================================================
EARNINGS PER COMMON SHARE ($/share)
Basic (Note 12) 2.36 0.85 3.28 2.13
=================================================
Diluted (Note 12) 2.30 0.84 3.21 2.10
=================================================
SEE ACCOMPANYING NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS.
4
NEXEN INC.
UNAUDITED CONSOLIDATED BALANCE SHEET
Cdn$ millions, except share amounts
SEPTEMBER 30 DECEMBER 31
2005 2004
- --------------------------------------------------------------------------------------------------------------
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents 200 73
Margin Deposits (Note 10) 202 -
Accounts Receivable (Note 3) 2,828 2,100
Inventories and Supplies (Note 4) 514 351
Assets of Discontinued Operations (Note 15) - 38
Other 56 41
------------------------------
Total Current Assets 3,800 2,603
------------------------------
PROPERTY, PLANT AND EQUIPMENT (Note 6)
Net of Accumulated Depreciation, Depletion, Amortization and
Impairment of $5,158 (December 31, 2004-- $4,922) 9,068 8,200
GOODWILL 366 375
FUTURE INCOME TAX ASSETS 395 333
DEFERRED CHARGES AND OTHER ASSETS (Note 5) 366 429
ASSETS OF DISCONTINUED OPERATIONS (Note 15) - 443
------------------------------
13,995 12,383
==============================
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Short-Term Borrowings (Note 7) - 100
Accounts Payable and Accrued Liabilities 3,663 2,377
Accrued Interest Payable 39 34
Dividends Payable 13 13
Liabilities of Discontinued Operations (Note 15) - 39
------------------------------
Total Current Liabilities 3,715 2,563
------------------------------
LONG-TERM DEBT (Note 7) 3,670 4,259
FUTURE INCOME TAX LIABILITIES 1,903 2,023
ASSET RETIREMENT OBLIGATIONS (Note 8) 437 399
DEFERRED CREDITS AND OTHER LIABILITIES (Note 9) 494 142
LIABILITIES OF DISCONTINUED OPERATIONS (Note 15) - 130
NON-CONTROLLING INTERESTS (Note 2) 91 -
SHAREHOLDERS' EQUITY (Note 11)
Common Shares, no par value
Authorized: Unlimited
Outstanding: 2005-- 260,879,092 shares
2004-- 258,399,166 shares 719 637
Contributed Surplus 1 -
Retained Earnings 3,148 2,335
Cumulative Foreign Currency Translation Adjustment (183) (105)
------------------------------
Total Shareholders' Equity 3,685 2,867
------------------------------
COMMITMENTS, CONTINGENCIES AND GUARANTEES (Note 16)
13,995 12,383
==============================
SEE ACCOMPANYING NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS.
5
NEXEN INC.
UNAUDITED CONSOLIDATED STATEMENT OF CASH FLOWS
FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30
Cdn$ millions
THREE MONTHS NINE MONTHS
ENDED SEPTEMBER 30 ENDED SEPTEMBER 30
2005 2004 2005 2004
- ---------------------------------------------------------------------------------------------------------------------------
Restated for Restated for
Changes in Changes in
Accounting Accounting
Principles Principles
Note 1 Note 1
OPERATING ACTIVITIES
Net Income from Continuing Operations 211 200 400 484
Net Income from Discontinued Operations 404 20 452 63
Charges and Credits to Income not Involving Cash (Note 13) (142) 234 666 696
Exploration Expense 32 54 164 107
Changes in Non-Cash Working Capital (Note 13) 216 (55) 120 (99)
Other (79) (50) (127) (21)
------------------------------------------------
642 403 1,675 1,230
FINANCING ACTIVITIES
Repayment of Term Credit Facilities, Net (329) - (67) -
Proceeds from Long-Term Debt (Note 7) - - 1,253 -
Repayment of Long-Term Debt (Note 7) (577) - (1,818) (300)
Repayment of Short-Term Borrowings, Net (48) - (99) -
Redemption of Preferred Securities - - - (289)
Dividends on Common Shares (13) (13) (39) (39)
Issue of Common Shares 11 7 51 116
Net Proceeds from Canexus Initial Public Offering (Note 2) 301 - 301 -
Proceeds from Term Credit Facilities of Canexus, Net (Notes 2 and 7) 173 - 173 -
Other (19) - (35) -
------------------------------------------------
(501) (6) (280) (512)
INVESTING ACTIVITIES
Capital Expenditures
Exploration and Development (624) (347) (1,869) (977)
Proved Property Acquisitions (15) - (21) -
Chemicals, Corporate and Other (9) (33) (33) (69)
Proceeds on Disposition of Assets 904 6 911 10
Changes in Non-Cash Working Capital (Note 13) (81) 45 (54) 107
Changes in Margin Deposits (Note 10) (210) - (210) -
Other - (6) 7 (20)
------------------------------------------------
(35) (335) (1,269) (949)
EFFECT OF EXCHANGE RATE CHANGES ON CASH AND CASH EQUIVALENTS (8) (35) 1 10
------------------------------------------------
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 98 27 127 (221)
CASH AND CASH EQUIVALENTS-- BEGINNING OF PERIOD 102 839 73 1,087
------------------------------------------------
CASH AND CASH EQUIVALENTS-- END OF PERIOD 200 866 200 866
================================================
SEE ACCOMPANYING NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS.
6
NEXEN INC.
UNAUDITED CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY
FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30
Cdn$ millions
THREE MONTHS NINE MONTHS
ENDED SEPTEMBER 30 ENDED SEPTEMBER 30
2005 2004 2005 2004
- --------------------------------------------------------------------------------------------------------------------------------
Restated for
Changes in
Accounting
Principles
Note 1
COMMON SHARES
Balance at Beginning of Period 694 622 637 513
Issue of Common Shares 11 7 51 116
Previously Recognized Liability Relating to Stock Options Exercised 14 - 31 -
----------------------------------------------------
Balance at End of Period 719 629 719 629
====================================================
CONTRIBUTED SURPLUS
Balance at Beginning of Period 1 - - 1
Stock Based Compensation Expense - - 1 (1)
----------------------------------------------------
Balance at End of Period 1 - 1 -
====================================================
RETAINED EARNINGS
Balance at Beginning of Period 2,546 1,895 2,335 1,594
Net Income 615 220 852 547
Dividends on Common Shares (13) (13) (39) (39)
----------------------------------------------------
Balance at End of Period 3,148 2,102 3,148 2,102
====================================================
CUMULATIVE FOREIGN CURRENCY TRANSLATION ADJUSTMENT
Balance at Beginning of Period (82) (19) (105) (33)
Translation Adjustment, Net of Income Taxes (101) (49) (78) (35)
----------------------------------------------------
Balance at End of Period (183) (68) (183) (68)
====================================================
SEE ACCOMPANYING NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS.
7
NEXEN INC.
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
Cdn$ millions except as noted
1. ACCOUNTING POLICIES
The Unaudited Consolidated Financial Statements are prepared in accordance with
Canadian Generally Accepted Accounting Principles (GAAP). The impact of
significant differences between Canadian and US GAAP on the Unaudited
Consolidated Financial Statements is disclosed in Note 19. The consolidated
financial statements include the assets and liabilities of Canexus Limited
Partnership, with an adjustment made for non-controlling interests. In the
opinion of management, the Unaudited Consolidated Financial Statements contain
all adjustments of a normal and recurring nature necessary to present fairly
Nexen Inc.'s (Nexen, we or our) financial position at September 30, 2005 and the
results of our operations and our cash flows for the three and nine months ended
September, 2005 and 2004.
Management makes estimates and assumptions that affect the reported amounts of
assets and liabilities and disclosure of contingent assets and liabilities at
the date of the Unaudited Consolidated Financial Statements, and revenues and
expenses during the reporting period. Our management reviews these estimates,
including those related to litigation, asset retirement obligations, income
taxes and 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. The results of operations and cash flows for the
three and nine months ended September 30, 2005 are not necessarily indicative of
the results of operations or cash flows to be expected for the year ending
December 31, 2005.
These Unaudited Consolidated Financial Statements do not conform in all respects
with the requirements for annual financial statements and therefore should be
read in conjunction with our Audited Consolidated Financial Statements included
in our 2004 Annual Report on Form 10-K. The accounting policies we follow are
described in Note 1 of the Audited Consolidated Financial Statements included in
our 2004 Annual Report on Form 10-K.
CHANGES IN ACCOUNTING PRINCIPLES
FINANCIAL INSTRUMENTS
In the fourth quarter of 2004, we retroactively adopted the changes to Canadian
Institute of Chartered Accountants (CICA) standard S.3860, FINANCIAL
INSTRUMENTS. These changes require that fixed-amount contractual obligations
that can be settled by issuing a variable number of equity instruments be
classified as a liability. Our US-dollar denominated preferred and subordinated
securities have these characteristics and accordingly have been reclassified as
long-term debt. Dividends and interest on these securities have been included in
interest expense and issue costs previously charged to retained earnings have
been amortized over the life of the securities. Unamortized issue costs have
been expensed on the redemption of the preferred securities in 2004. Foreign
exchange gains or losses from translation of the US-dollar amounts have been
included as cumulative foreign currency translation adjustments. The change was
adopted retroactively and all prior periods presented have been restated. This
change in accounting principle has no effect on our Unaudited Consolidated
Financial Statements for the three and nine months ended September 30, 2005.
GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
In 2004, we adopted CICA standard S.1100, GENERALLY ACCEPTED ACCOUNTING
PRINCIPLES which eliminated general industry practice in Canada as a component
of GAAP. Our accounting policy is to include geological and geophysical costs as
operating cash outflows in our Unaudited Consolidated Statement of Cash Flows.
For previous years, we included geological and geophysical costs as investing
cash outflows consistent with industry practice in Canada. In our Unaudited
Consolidated Statement of Cash Flows for the three months ended September 30,
2005, we included $17 million (2004 - $15 million) and for the nine months ended
September 30, 2005, we included $37 million (2004 - $40 million) of geological
and geophysical costs as other operating cash outflows. This change in
accounting policy was adopted prospectively.
IMPACT OF CHANGES IN ACCOUNTING PRINCIPLES
The impact of these changes in accounting principles on our Unaudited
Consolidated Statement of Income and Earnings per Common Share for the three and
nine months ended September 30, 2004, are shown below.
8
UNAUDITED CONSOLIDATED STATEMENT OF INCOME FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2004
THREE MONTHS NINE MONTHS
- ------------------------------------------------------------------------------------------------------------------------------
Transportation and Other Expense as Reported 122 389
Plus: Unamortized Issue Costs on Redemption of Preferred Securities - 11
-------------------------------
Transportation and Other Expense as Restated 122 400
-------------------------------
Interest Expense as Reported 35 115
Plus: Dividends on Preferred Securities - 3
-------------------------------
Interest Expense as Restated 35 118
-------------------------------
Provision for Future Income Taxes as Reported 25 25
Plus: Tax Effect of Changes in Accounting Principles - (6)
-------------------------------
Provision for Future Income Taxes as Restated 25 19
-------------------------------
NET INCOME AND EARNINGS PER COMMON SHARE FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2004
THREE MONTHS NINE MONTHS
- ------------------------------------------------------------------------------------------------------------------------------
Net Income Attributable to Common Shareholders
As Reported 220 553
Less: Unamortized Issue Costs on Redemption of Preferred Securities, Net of Income Taxes - (6)
-------------------------------
As Restated 220 547
===============================
Earnings per Common Share ($/share)
Basic as Reported 0.85 2.15
===============================
Restated 0.85 2.13
===============================
Diluted as Reported 0.84 2.13
===============================
Restated 0.84 2.10
===============================
RECLASSIFICATION
Certain comparative figures have been reclassified to ensure consistency with
current period presentation.
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.
9
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 has currently nominated
two representatives to the ten-member board of Canexus Limited. Since we have
retained effective control of our chemicals business, the 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.
3. ACCOUNTS RECEIVABLE
SEPTEMBER 30 DECEMBER 31
2005 2004
- -----------------------------------------------------------------------------------------------------
Trade
Marketing 2,157 1,452
Oil and Gas 538 557
Chemicals and Other 68 57
-----------------------------
2,763 2,066
Non-Trade 72 49
-----------------------------
2,835 2,115
Allowance for Doubtful Accounts (7) (15)
-----------------------------
Total 2,828 2,100
=============================
4. INVENTORIES AND SUPPLIES
SEPTEMBER 30 DECEMBER 31
2005 2004
- -----------------------------------------------------------------------------------------------------
Finished Products
Marketing 339 199
Oil and Gas 6 6
Chemicals and Other 13 13
-----------------------------
358 218
Work in Process 5 4
Field Supplies 151 129
-----------------------------
Total 514 351
=============================
5. DEFERRED CHARGES AND OTHER ASSETS
SEPTEMBER 30 DECEMBER 31
2005 2004
- -----------------------------------------------------------------------------------------------------
Long-Term Marketing Derivative Contracts 210 91
Crude Oil Put Options 16 200
Defined Benefit Pension Plan Asset 5 13
Deferred Financing Costs 63 67
Asset Retirement Obligation Remediation Fund (Note 8) 14 --
Other 58 58
-----------------------------
Total 366 429
=============================
6. SUSPENDED WELL COSTS
In the third quarter of 2005, we adopted staff position 19-1 (FSP 19-1) issued
by the Financial Accounting Standards Board (FASB) on accounting for suspended
well costs. FSP 19-1 amends FASB Statement No. 19, FINANCIAL ACCOUNTING AND
REPORTING BY OIL AND GAS PRODUCING COMPANIES, for companies using the successful
efforts method of accounting which required that capitalized exploratory well
costs be expensed if related reserves could not be classified as proved within
one year. FSP 19-1 provides that exploratory well costs should continue to be
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. FSP
19-1 also requires certain disclosures with respect to capitalized exploratory
well costs.
10
The following table sets out the changes in capitalized exploratory well costs
during the three and nine month periods ended September 30, 2005 and 2004, and
does not include amounts that were initially capitalized and subsequently
expensed in the same period.
THREE MONTHS NINE MONTHS
ENDED SEPTEMBER 30 ENDED SEPTEMBER 30
2005 2004 2005 2004
- --------------------------------------------------------------------------------------------------------------------
Balance at Beginning of Period 196 119 117 91
Additions to Capitalized Exploratory Well Costs Pending the
Determination of Proved Reserves 100 27 178 51
Effects of Foreign Exchange (14) (8) (13) (4)
-------------------------------------------------
Balance at End of Period 282 138 282 138
=================================================
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 since the completion of drilling.
SEPTEMBER 30 SEPTEMBER 30
2005 2004
- ---------------------------------------------------------------------------------------------------------------------
Capitalized for a Period of One Year or Less 199 75
Capitalized for a Period of Greater than One Year 83 63
----------------------------
Balance at End of Period 282 138
============================
Number of Projects that have Exploratory Well Costs Capitalized for a Period Greater than
One Year 3 2
----------------------------
As at September 30, 2005, we have exploratory costs that have been capitalized
for more than one year relating to our interest in an exploratory block,
offshore Nigeria ($71 million), our interest in exploratory blocks in the Gulf
of Mexico ($5 million) and coal bed methane exploratory activities in Canada ($7
million). Exploratory costs offshore Nigeria were first capitalized in 1998 and
we have subsequently drilled a further seven successful wells on the block. The
joint venture partners have finalized pre-development design studies and are
moving towards the next phase of the project. Drilling activity has resumed and
an appraisal and exploration program is currently in progress. Once final
regulatory approvals have been received and the project has been sanctioned, we
will book proved reserves. We have capitalized costs related to successful wells
drilled in 2004 and 2005 in the Gulf of Mexico and in Canada, we have
capitalized exploratory costs relating to our coal bed methane projects. We are
currently assessing all of these wells and projects and we are working with our
partners to prepare development plans.
7. LONG-TERM DEBT AND SHORT-TERM BORROWINGS
SEPTEMBER 30 DECEMBER 31
2005 2004
- ---------------------------------------------------------------------------------------------------------------------
Acquisition Credit Facilities (a) - 1,806
Canexus LP Term Credit Facilities (US$144 million drawn) (b) 167 -
Term Credit Facilities (c) - 87
Debentures, due 2006 (1) 93 93
Medium-Term Notes, due 2007 150 150
Medium-Term Notes, due 2008 125 125
Notes, due 2013 (US$500 million) 581 602
Notes, due 2015 (US$250 million) (d) 290 -
Notes, due 2028 (US$200 million) 232 241
Notes, due 2032 (US$500 million) 581 602
Notes, due 2035 (US$790 million) (e) 917 -
Subordinated Debentures, due 2043 (US$460 million) 534 553
---------------------------
3,670 4,259
===========================
Note:
(1) Includes $50 million of principal that was effectively converted through a currency exchange contract to
US$37 million.
11
(a) ACQUISITION CREDIT FACILITIES
During the quarter, we repaid in full, amounts outstanding under the bridge
facility used to fund a portion of the purchase price for the acquisition of
EnCana (UK) Limited in 2004. The US$500 million development facility associated
with the acquisition credit facilities was replaced with the renewal of our term
credit facilities during the quarter.
(b) CANEXUS LP TERM CREDIT FACILITIES
Canexus LP has $350 million of committed, unsecured, revolving term credit
facilities which are available until 2009. At September 30, 2005, US$144 million
($167 million) was drawn on these facilities. The lenders have the option to
extend the terms annually. Borrowings are available as Canadian bankers'
acceptances, LIBOR-based loans, Canadian prime loans or US-dollar base rate
loans. Interest is payable monthly at a floating rate. 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).
(c) TERM CREDIT FACILITIES
We have a committed, unsecured, revolving term credit facility of US$2.0 billion
which is available until 2010. At September 30, 2005, these facilities were
undrawn. The lenders have the option to extend the terms annually. Borrowings
are available as Canadian bankers' acceptances, LIBOR-based loans, Canadian
prime loans, US-dollar base rate loans or pound sterling call rate loans.
Interest is payable monthly at a floating rate.
(d) NOTES, DUE 2015
In 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%. The proceeds were used to repay a portion of the Acquisition
Credit Facilities.
(e) NOTES, DUE 2035
In 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%. The proceeds were used to repay a portion of the Acquisition
Credit Facilities.
(f) INTEREST EXPENSE
THREE MONTHS NINE MONTHS
ENDED SEPTEMBER 30 ENDED SEPTEMBER 30
2005 2004 2005 2004
- -----------------------------------------------------------------------------------------
Long-Term Debt 65 43 197 136
Other 3 3 12 9
------------------------------------------
68 46 209 145
Less: Capitalized (49) (11) (125) (27)
------------------------------------------
Total 19 35 84 118
==========================================
Capitalized interest relates to and is included as part of the cost of our oil,
gas and Syncrude properties, plant and equipment. The capitalization rates are
based on our weighted-average cost of borrowings.
(g) SHORT-TERM BORROWINGS
Nexen has unsecured operating loan facilities of approximately $427 million. No
amounts were drawn under these facilities at September 30, 2005 (December 31,
2004 - $100 million). Interest is payable at floating rates. During the first
nine months of 2005, the weighted average interest rate on our short-term
borrowings was 3.4%.
12
8. ASSET RETIREMENT OBLIGATIONS
Changes in carrying amounts of the asset retirement obligations associated with
our property, plant and equipment are as follows:
SEPTEMBER 30 DECEMBER 31
2005 2004
- ------------------------------------------------------------------------------------------------------
Balance at Beginning of Period 468 323
Obligations Assumed with Development Activities 52 12
Obligations Assumed with Business Acquisition - 134
Obligations Discharged with Disposed Properties (38) (4)
Expenditures Made on Asset Retirements (30) (31)
Accretion 19 17
Revisions to Estimates - 24
Effects of Foreign Exchange (21) (7)
------------------------------
Balance at End of Period (1), (2) 450 468
==============================
Notes:
(1) Obligations due within 12 months of $13 million (December 31, 2004 - $47
million) have been included in accounts payable and accrued liabilities.
Obligations related to discontinued operations of $nil (December 31, 2004 -
$22 million) have been included with liabilities of discontinued
operations.
(2) Obligations relating to our oil and gas activities amount to $403 million
(December 31, 2004 - $422 million) and obligations relating to our
chemicals business amount to $47 million (December 31, 2004 - $46 million).
Our total estimated undiscounted asset retirement obligations amount to $750
million (December 31, 2004 - $770 million). We have discounted the total
estimated asset retirement obligations using a weighted-average, credit-adjusted
risk-free rate of 5.7%. Approximately $98 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.
In connection with the sale of our chemicals business to Canexus LP, we have
contributed $14 million to a remediation fund to be used for asset retirement
obligations associated with the assets sold. This is included on our balance
sheet as part of deferred charges and other assets.
We own interests in assets for which the fair value of the asset retirement
obligations cannot be reasonably determined because the assets currently have an
indeterminate life and we cannot determine when remediation activities would
take place. These assets include our interest in Syncrude's upgrader and sulphur
pile. The estimated future recoverable reserves at Syncrude are significant and
given the long life of this asset, we are unable to determine when asset
retirement activities would take place. Furthermore, we believe the Syncrude
plant can continue to run indefinitely with ongoing maintenance activities. The
retirement obligations for these assets will be recorded in the first year in
which the lives of the assets are determinable.
9. DEFERRED CREDITS AND OTHER LIABILITIES
SEPTEMBER 30 DECEMBER 31
2005 2004
- ----------------------------------------------------------------------------------------------------
Long-Term Marketing Derivative Contracts 115 46
Fixed Price Natural Gas Contracts 124 -
Deferred Transportation Revenue 34 33
Stock Based Compensation Liability 75 -
Defined Benefit Pension Obligation 36 32
Other 110 31
----------------------------
Total 494 142
============================
13
10. DERIVATIVE INSTRUMENTS AND FINANCIAL RISK MANAGEMENT
(a) CARRYING VALUE AND ESTIMATED FAIR VALUE OF DERIVATIVE AND FINANCIAL
INSTRUMENTS
The carrying value, fair value, and unrecognized gains or losses on our
outstanding derivatives and long-term financial assets and liabilities are:
Cdn$ millions SEPTEMBER 30, 2005 DECEMBER 31, 2004
- -------------------------------------------------------------------------------------------------------------------------
Carrying Fair Unrecognized Carrying Fair Unrecognized
Value Value Gain/(Loss) Value Value Gain
------------------------------------ -------------------------------------
Commodity Price Risk
Non-Trading Activities
Crude Oil Put Options 16 16 - 200 200 -
Fixed Price Natural Gas Contracts (187) (187) - - (98) (98)
Natural Gas Swaps 25 25 - - - -
Trading Activities
Crude Oil and Natural Gas 42 42 - 83 83 -
Future Sale of Gas Inventory - (121) (121) - 6 6
Foreign Currency Risk
Non-Trading Activities 17 17 - 7 7 -
Trading Activities 10 10 - 10 10 -
------------------------------------ -------------------------------------
Total Derivatives (77) (198) (121) 300 208 (92)
==================================== =====================================
Financial Assets and Liabilities
Long-Term Debt (3,670) (3,854) (184) (4,259) (4,503) (244)
==================================== =====================================
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, 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
We purchased WTI crude oil put options to manage the commodity price risk
exposure of a portion of our oil production in 2005 and 2006. These options
establish an annual average WTI floor price of US$43/bbl in 2005 and US$38/bbl
in 2006 at a cost of $144 million and are stated at fair value on our balance
sheet. Any change in fair value is included in marketing and other on the
Unaudited Consolidated Statement of Income.
NOTIONAL AVERAGE FAIR
VOLUMES TERM PRICE (WTI) VALUE
- ---------------------------------------------------------------------------------------------------
(bbls/d) (US$/bbl) (Cdn$ millions)
WTI Crude Oil Put Options 30,000 2005 44 -
20,000 2005 43 -
10,000 2005 41 -
30,000 2006 39 9
20,000 2006 38 5
10,000 2006 36 2
---------------
16
===============
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 contracts that were previously used in the
operation of those properties. See Note 15.
14
Since these contracts are no longer used in the normal course of our oil and gas
operations, they have been marked-to-market and are included in the Unaudited
Consolidated Balance Sheet. Any change in fair value is included in marketing
and other in the Unaudited Consolidated Statement of Income.
NOTIONAL FAIR
VOLUMES TERM PRICE VALUE
- ------------------------------------------------------------------------------------------------------
(Gj/d) ($/Gj) (Cdn$ millions)
Fixed Price Natural Gas Contracts 22,034 2005 - 2006 2.28 - 3.72 (63)
15,514 2007 - 2010 2.47 - 2.77 (124)
----------------
(187)
================
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 Unaudited Consolidated Statement of Income.
NOTIONAL FAIR
VOLUMES TERM PRICE VALUE
- ------------------------------------------------------------------------------------------------------
(Gj/d) ($/Gj) (Cdn$ millions)
Natural Gas Swaps 22,034 2005 - 2006 9.02 - 11.81 13
15,514 2007 - 2010 7.45 12
----------------
25
================
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 $42 million fair value of the commodity contracts at
September 30, 2005 is included in the Unaudited Consolidated Balance Sheet and
any change in fair value is included in marketing and other on the Unaudited
Consolidated Statement of Income.
FUTURE SALE OF GAS INVENTORY
We have certain NYMEX futures contracts and swaps in place, which effectively
lock-in our margins on the future sale of our natural gas inventory in storage.
We have designated, in writing, some of these derivative contracts as cash flow
hedges of the future sale of our storage inventory. As a result, gains and
losses on these designated futures contracts and swaps are recognized in net
income when the inventory in storage is sold. The principal terms of these
outstanding contracts and the unrecognized losses at September 30, 2005 are:
HEDGED AVERAGE UNRECOGNIZED
VOLUMES MONTH PRICE LOSS
- ---------------------------------------------------------------------------------------------------
(mmcf) (US$/mcf) (Cdn$ millions)
NYMEX Natural Gas Futures 1,520 October 2005 6.96 (12)
1,140 December 2005 10.02 (6)
11,100 January 2006 8.96 (75)
400 February 2006 10.96 (2)
NYMEX Natural Gas Fixed Price Swaps 850 December 2005 8.00 (6)
2,750 January 2006 8.30 (20)
----------------
(121)
================
(c) FOREIGN CURRENCY EXCHANGE RATE RISK MANAGEMENT
NON-TRADING ACTIVITIES
FAIR
AMOUNT TERM RATE VALUE
- ----------------------------------------------------------------------------------------------------------------
(for US$1.00) (Cdn$ millions)
Foreign Currency Call Options - Buzzard (i) (pound)207 million 2005 - 2006 1.95 - 2.00 -
US Dollar Call Options - Canexus (ii) US$11 million 2005 - 2006 0.813 9
Foreign Currency Swap (iii) US$37 million 2006 0.736 8
----------------
17
================
15
(i) BUZZARD
Our Buzzard development project in the North Sea creates foreign currency
exposure as a portion of the capital costs are denominated in British pounds and
Euros. In order to reduce our exposure to fluctuations in these currencies
relative to the US dollar, we purchased foreign currency call options in early
2005 which effectively set a ceiling on most of our British pound and Euro
spending exposure from March 2005 through to the end of 2006. Any change in fair
value is included in marketing and other on the Unaudited Consolidated Statement
of Income.
(ii) CANEXUS
The operations of Canexus are exposed to changes in the US dollar exchange rate
as a portion of their sales are denominated in US dollars. In connection with
the initial public offering of Canexus, we purchased US dollar call options to
reduce this exposure to fluctuations in the Canadian - US dollar exchange rate.
Canexus has the right to sell US$11 million monthly and purchase Canadian
dollars at an exchange rate of US$0.813 until August 2006. Any change in fair
value is included in marketing and other on the Unaudited Consolidated Statement
of Income.
(iii) FOREIGN CURRENCY SWAP
We occasionally use derivative instruments to effectively convert cash flows
from Canadian to US dollars and vice versa. At September 30, 2005, we held a
foreign currency derivative instrument that obligates us and the counterparty to
exchange principal and interest amounts. In November 2006, we will pay US$37
million and receive Cdn$50 million. Any change in fair value is included in
marketing and other on the Unaudited Consolidated Statement of Income.
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. Our marketing group enters into forward contracts
and swaps to sell US dollars. When combined with certain commodity sales
contracts, either physical or financial, these forward contracts and swaps allow
us to lock-in our Canadian dollar margins on the future sale of crude oil and
natural gas. The $10 million fair value of the US dollar forward contracts and
swaps at September 30, 2005 is included in the Unaudited Consolidated Balance
Sheet and any change in fair value is included in marketing and other on the
Unaudited Consolidated Statement of Income.
(d) TOTAL CARRYING VALUE OF DERIVATIVE CONTRACTS RELATED TO TRADING ACTIVITIES
Amounts related to derivative contracts held by our marketing group are equal to
fair value as we use mark-to-market accounting. The amounts are as follows:
SEPTEMBER 30 DECEMBER 31
CDN$ MILLIONS 2005 2004
- -------------------------------------------------------------------------------
Accounts Receivable 508 177
Deferred Charges and Other Assets (1) 210 91
----------------------------
Total Derivative Contract Assets 718 268
============================
Accounts Payable and Accrued Liabilities 551 129
Deferred Credits and Other Liabilities (1) 115 46
----------------------------
Total Derivative Contract Liabilities 666 175
============================
Total Derivative Contract Net Assets (2) 52 93
============================
Notes:
(1) These derivative contracts settle beyond 12 months and are considered
non-current.
(2) Comprised of $42 million (2004 - $83 million) related to commodity
contracts and $10 million (2004 - $10 million) related to US dollar forward
contracts and swaps.
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 US$174 million ($202
million) as at September 30, 2005 (December 31, 2004 - $nil), which have been
presented as margin deposits on our Unaudited Consolidated Balance Sheet.
16
11. SHAREHOLDERS' EQUITY
DIVIDENDS
Dividends per common share for the three months ended September 30, 2005 were
$0.05 (2004 - $0.05). Dividends per common share for the nine months ended
September 30, 2005 were $0.15 (2004 - $0.15).
12. EARNINGS PER COMMON SHARE
Our shareholders approved a split of our issued and outstanding common shares on
a two-for-one basis at our annual and special meeting on April 27, 2005. All
common share and per common share amounts have been restated to retroactively
reflect this share split.
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.
THREE MONTHS NINE MONTHS
ENDED SEPTEMBER 30 ENDED SEPTEMBER 30
(MILLIONS OF SHARES) 2005 2004 2005 2004
- ---------------------------------------------------------------------------------------------------------------
Weighted-average number of common shares outstanding 260.6 258.0 260.1 256.8
Shares issuable pursuant to stock options 12.9 12.6 13.8 13.4
Shares to be purchased from proceeds of stock options (6.4) (9.8) (8.6) (10.0)
-----------------------------------------------
Weighted-average number of diluted common shares outstanding 267.1 260.8 265.3 260.2
===============================================
In calculating the weighted-average number of diluted common shares outstanding
for the three and nine months ended September 30, 2005 and September 30, 2004
all options were included because their exercise price was less than the average
common share market price in the period. During the periods presented,
outstanding stock options were the only potential dilutive instruments.
13. CASH FLOWS
(a) CHARGES AND CREDITS TO INCOME NOT INVOLVING CASH
THREE MONTHS NINE MONTHS
ENDED SEPTEMBER 30 ENDED SEPTEMBER 30
2005 2004 2005 2004
- -------------------------------------------------------------------------------------------------------------
Depreciation, Depletion, Amortization and Impairment 256 164 748 480
Stock Based Compensation 227 11 390 100
Future Income Taxes (71) 25 (141) 19
Change in Fair Value of Crude Oil Put Options 1 - 184 -
Non-Cash Items included in Discontinued Operations (381) 29 (325) 95
Unamortized Issue Costs on Redemption of Preferred Securities - - - 11
Gain on Dilution of Interest in Chemicals Business (193) - (193) -
Net Income Attributable to Non-Controlling Interests 5 - 5 -
Other 14 5 (2) (9)
-----------------------------------------------
Total (142) 234 666 696
===============================================
17
(b) CHANGES IN NON-CASH WORKING CAPITAL
THREE MONTHS NINE MONTHS
ENDED SEPTEMBER 30 ENDED SEPTEMBER 30
2005 2004 2005 2004
- ---------------------------------------------------------------------------------------------------------------
Accounts Receivable (1) (639) 17 (817) (134)
Inventories and Supplies 35 (68) (174) (145)
Other Current Assets (26) (18) (15) 37
Accounts Payable and Accrued Liabilities (1) 783 59 1,067 259
Accrued Interest Payable (18) - 5 (9)
-----------------------------------------------
Total 135 (10) 66 8
===============================================
Relating to:
Operating Activities 216 (55) 120 (99)
Investing Activities (81) 45 (54) 107
-----------------------------------------------
Total 135 (10) 66 8
===============================================
Note:
(1) Includes changes in non-cash working capital related to discontinued
operations.
(c) OTHER CASH FLOW INFORMATION
THREE MONTHS NINE MONTHS
ENDED SEPTEMBER 30 ENDED SEPTEMBER 30
2005 2004 2005 2004
- ---------------------------------------------------------------------------------------------------------------
Interest Paid 80 41 190 143
Income Taxes Paid 96 67 248 182
-----------------------------------------------
14. MARKETING AND OTHER
THREE MONTHS NINE MONTHS
ENDED SEPTEMBER 30 ENDED SEPTEMBER 30
2005 2004 2005 2004
- ---------------------------------------------------------------------------------------------------------------
Marketing Revenue, Net 29 144 481 403
Change in Fair Value of Crude Oil Put Options (1) - (184) -
Interest 4 3 22 8
Foreign Exchange Gains/(Losses) (27) (9) 1 6
Other 19 9 23 22
-----------------------------------------------
Total 24 147 343 439
===============================================
15. DISCONTINUED OPERATIONS
In June 2005, we agreed to sell 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 accounted for as discontinued operations. The sales closed
in the third quarter with 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 contracts associated with these
properties that we have retained but no longer use in connection with our oil
and gas business.
18
During the fourth quarter of 2004, we concluded production from our Buffalo
field, offshore Australia as anticipated. The results of our operations in
Australia have been treated as discontinued operations, as we have no plans to
continue operations in the country. Remediation and abandonment activities are
virtually completed and no gain or loss is expected from these activities.
THREE MONTHS ENDED SEPTEMBER 30
2005 2004
CANADA CANADA AUSTRALIA TOTAL
- ------------------------------------------------------------------------ -----------------------------------
Revenues
Net Sales 27 59 - 59
Gain on Disposition of Assets 225 - - -
-------- ----------------------------------
252 59 - 59
Expenses
Operating 4 10 - 10
Depreciation, Depletion, Amortization and Impairment - 17 - 17
-------- ----------------------------------
Income before Income Taxes 248 32 - 32
Future Income Taxes (156) 12 - 12
-------- ----------------------------------
Net Income from Discontinued Operations 404 20 - 20
========= ===================================
Earnings per Common Share
Basic 1.55 0.08 - 0.08
========= ===================================
Diluted 1.51 0.08 - 0.08
========= ===================================
NINE MONTHS ENDED SEPTEMBER 30
2005 2004
CANADA CANADA AUSTRALIA TOTAL
- ------------------------------------------------------------------------ -----------------------------------
Revenues
Net Sales 154 171 49 220
Gain on Disposition of Assets 225 - - -
-------- ----------------------------------
379 171 49 220
Expenses
Operating 27 31 31 62
Depreciation, Depletion, Amortization and Impairment 28 52 9 61
Exploration Expense 1 1 - 1
-------- ----------------------------------
Income before Income Taxes 323 87 9 96
Future Income Taxes (129) 33 - 33
-------- ----------------------------------
Net Income from Discontinued Operations 452 54 9 63
========= ===================================
Earnings per Common Share
Basic 1.74 0.21 0.04 0.25
========= ===================================
Diluted 1.70 0.21 0.03 0.24
========= ===================================
Assets and liabilities on the Unaudited Consolidated Balance Sheet include the
following amounts for discontinued operations. There were no assets and
liabilities related to discontinued operations at September 30, 2005.
AS AT DECEMBER 31, 2004
CANADA AUSTRALIA TOTAL
- ---------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents - 1 1
Accounts Receivable 28 8 36
Other Current Assets - 1 1
Property, Plant and Equipment, Net 443 - 443
Accounts Payable and Accrued Liabilities 14 25 39
Asset Retirement Obligations 22 - 22
Future Income Tax Liabilities 108 - 108
-------------------- -----------
19
16. COMMITMENTS, CONTINGENCIES AND GUARANTEES
As described in Note 12 to the Audited Consolidated Financial Statements
included in our 2004 Annual Report on Form 10-K, there are a number of lawsuits
and claims pending, the ultimate results of which cannot be ascertained at this
time. 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.
17. PENSION AND OTHER POST RETIREMENT BENEFITS
(a) NET PENSION EXPENSE RECOGNIZED UNDER OUR DEFINED BENEFIT PENSION PLANS
THREE MONTHS NINE MONTHS
ENDED SEPTEMBER 30 ENDED SEPTEMBER 30
2005 2004 2005 2004
- ---------------------------------------------------------------------------------------------------------------
Nexen
Cost of Benefits Earned by Employees 4 2 10 6
Interest Cost on Benefits Earned 3 3 10 9
Expected Return on Plan Assets (3) (3) (8) (9)
Net Amortization and Deferral - - 1 -
------------------------------------------------
Net 4 2 13 6
------------------------------------------------
Syncrude
Cost of Benefits Earned by Employees 1 1 3 3
Interest Cost on Benefits Earned 1 1 4 3
Expected Return on Plan Assets (1) (1) (3) (3)
Net Amortization and Deferral - - - -
-----------------------------------------------
Net 1 1 4 3
-----------------------------------------------
Total 5 3 17 9
================================================
(b) EMPLOYER FUNDING CONTRIBUTIONS
Our expected total funding contributions for 2005 disclosed in Note 13(e) to the
Audited Consolidated Financial Statements in our 2004 Annual Report on Form 10-K
have not changed for both our Nexen defined benefit pension plan and our share
of Syncrude's defined benefit pension plan.
20
18. OPERATING SEGMENTS AND RELATED INFORMATION
Nexen is involved in activities relating to Oil and Gas, Syncrude and Chemicals
in various geographic locations as described in Note 18 to the Audited
Consolidated Financial Statements included in our 2004 Annual Report on Form
10-K.
THREE MONTHS ENDED SEPTEMBER 30, 2005
CORPORATE
AND
(CDN$ MILLIONS) OIL AND GAS SYNCRUDE(1) CHEMICALS OTHER TOTAL
- ---------------------------------------------------------------------------------------------------------------------------------
UNITED UNITED OTHER
YEMEN CANADA STATES KINGDOM COUNTRIES(2) MARKETING
--------------------------------------------------------
Net Sales 417 136 212 69 29 6 124 101 - 1,094
Marketing and Other 3 - - 1 - 29 - 15 (24)(3) 24
Gain on Dilution of Interest
in Chemicals Business - - - - - - - 193 - 193
--------------------------------------------------------------------------------------------------
Total Revenues 420 136 212 70 29 35 124 309 (24) 1,311
Less: Expenses
Operating 36 29 25 23 1 8 37 62 - 221
Depreciation, Depletion,
Amortization and
Impairment 107 35 57 33 2 3 4 9 6 256
Transportation and Other 2 6 - - - 147 5 10 31 201
General and
Administrative (4) 1 39 34 - 70 39 - 12 147 342
Exploration 2 4 10 3 13(5) - - - - 32
Interest - - - - - - - 1 18 19
--------------------------------------------------------------------------------------------------
Income (Loss) from
Continuing Operations
before Income Taxes 272 23 86 11 (57) (162) 78 215 (226) 240
=========================================================================================
Less: Provision for
Income Taxes (6) 24
Less: Non Controlling
Interests 5
Add: Net Income from
Discontinued Operations 404
-------
Net Income 615
========
Identifiable Assets 670 2,103 1,362 4,684 239 3,123(7) 1,067 491 256 13,995
===================================================================================================
Capital Expenditures
Development and Other 53 221 28 131 3 1 55 5 3 500
Exploration 11 26 46 35 15 - - - - 133
Proved Property
Acquisitions - 15 - - - - - - - 15
--------------------------------------------------------------------------------------------------
64 262 74 166 18 1 55 5 3 648
===================================================================================================
Property, Plant and
Equipment
Cost 2,174 3,254 2,308 3,838 252 168 1,179 821 232 14,226
Less: Accumulated DD&A 1,737 1,279 1,106 120 116 69 168 447 116 5,158
---------------------------------------------------------------------------------------------------
Net Book Value 437 1,975 1,202 3,718 136 99 1,011 374 116 9,068
===================================================================================================
Notes:
(1) Syncrude is considered a mining operation for US reporting purposes.
Property, plant and equipment at September 30, 2005 include mineral rights
of $6 million.
(2) Includes results of operations from producing activities in Nigeria and
Colombia.
(3) Includes interest income of $4 million, foreign exchange losses of $27
million and decrease in the fair value of crude oil put options of $1
million.
(4) Includes stock based compensation expense of $260 million.
(5) Includes exploration activities primarily in Nigeria, Colombia and
Equatorial Guinea.
(6) Includes Yemen cash taxes of $93 million.
(7) Approximately 80% of marketing's identifiable assets are accounts
receivable and inventories.
21
NINE MONTHS ENDED SEPTEMBER 30, 2005
CORPORATE
AND
(CDN$ MILLIONS) OIL AND GAS SYNCRUDE(1) CHEMICALS OTHER TOTAL
- ---------------------------------------------------------------------------------------------------------------------------------
UNITED UNITED OTHER
YEMEN CANADA STATES KINGDOM COUNTRIES(2) MARKETING
--------------------------------------------------------
Net Sales 1,025 316 593 242 78 16 292 297 - 2,859
Marketing and Other 6 2 - 1 4 481 - 16 (167)(3) 343
Gain on Dilution of Interest
in Chemicals Business - - - - - - - 193 - 193
--------------------------------------------------------------------------------------------------
Total Revenues 1,031 318 593 243 82 497 292 506 (167) 3,395
Less: Expenses
Operating 109 85 69 76 7 20 110 174 - 650
Depreciation, Depletion,
Amortization and
Impairment 256 105 182 115 11 8 13 42(4) 16 748
Transportation and Other 4 17 - - - 475 13 30 44 583
General and
Administrative (5) 3 93 71 - 117 72 - 39 252 647
Exploration 5 15 83 18 43(6) - - - - 164
Interest - - - - - - - 1 83 84
--------------------------------------------------------------------------------------------------
Income (Loss) from
Continuing Operations
before Income Taxes 654 3 188 34 (96) (78) 156 220 (562) 519
========================================================================================
Less: Provision for
Income Taxes (7) 114
Less: Non Controlling
Interest 5
Add: Net Income from
Discontinued Operations 452
-------
Net Income 852
========
Identifiable Assets 670 2,103 1,362 4,684 239 3,123(8) 1,067 491 256 13,995
===================================================================================================
Capital Expenditures
Development and Other 184 651 95 423 10 14 149 9 10 1,545
Exploration 27 53 178 51 48 - - - - 357
Proved Property
Acquisitions - 17 3 1 - - - - - 21
--------------------------------------------------------------------------------------------------
211 721 276 475 58 14 149 9 10 1,923
===================================================================================================
Property, Plant and Equipment
Cost 2,174 3,254 2,308 3,838 252 168 1,179 821 232 14,226
Less: Accumulated DD&A 1,737 1,279 1,106 120 116 69 168 447 116 5,158
---------------------------------------------------------------------------------------------------
Net Book Value 437 1,975 1,202 3,718 136 99 1,011 374 116 9,068
===================================================================================================
Notes:
(1) Syncrude is considered a mining operation for US reporting purposes.
Property, plant and equipment at September 30, 2005 includes mineral rights
of $6 million.
(2) Includes results of operations from producing activities in Nigeria and
Colombia.
(3) Includes interest income of $22 million, foreign exchange gains of $1
million, decrease in the fair value of crude oil put options of $184
million and decrease in the fair value of foreign currency call options of
$6 million.
(4) Includes impairment charge of $12 million related to the closure of our
sodium chlorate plant in Amherstburg, Ontario.
(5) Includes stock based compensation expense of $450 million.
(6) Includes exploration activities primarily in Nigeria, Colombia and
Equatorial Guinea.
(7) Includes Yemen cash taxes of $222 million.
(8) Approximately 80% of marketing's identifiable assets are accounts
receivable and inventories.
22
THREE MONTHS ENDED SEPTEMBER 30, 2004
CORPORATE
AND
(CDN$ MILLIONS) OIL AND GAS SYNCRUDE(1) CHEMICALS OTHER TOTAL
- -----------------------------------------------------------------------------------------------------------------------------------
UNITED OTHER
YEMEN CANADA STATES COUNTRIES(2) MARKETING
----------------------------------------------------
Net Sales 247 101 219 19 4 90 98 - 778
Marketing and Other 1 4 3 - 144 - 1 (6)(3) 147
------------------------------------------------------------------------------------------------
Total Revenues 248 105 222 19 148 90 99 (6) 925
Less: Expenses
Operating 27 29 39 3 4 31 62 - 195
Depreciation, Depletion,
Amortization and
Impairment 39 32 68 5 3 4 9 4 164
Transportation and Other - 4 - - 106 3 9 - 122
General and Administrative - 6 4 10 13 - 8 16 57
Exploration 1 4 38 11 (4) - - - - 54
Interest - - - - - - - 35 35
------------------------------------------------------------------------------------------------
Income (Loss) from
Continuing Operations before
Income Taxes 181 30 73 (10) 22 52 11 (61) 298
======================================================================================
Less: Provision for Income
Taxes (5) 98
Add: Net Income from
Discontinued Operations 20
---------
Net Income 220
==========
Identifiable Assets 619 1,793 1,652 254 1,666 (6) 857 497 785 8,123
=================================================================================================
Capital Expenditures
Development and Other 71 120 40 29 1 57 25 7 350
Exploration 4 7 17 2 - - - - 30
------------------------------------------------------------------------------------------------
75 127 57 31 1 57 25 7 380
=================================================================================================
Property, Plant and Equipment
Cost 2,032 2,382 2,304 362 155 972 814 188 9,209
Less: Accumulated DD&A 1,581 1,169 1,027 225 61 152 404 86 4,705
------------------------------------------------------------------------------------------------
Net Book Value 451 1,213 1,277 137 94 820 410 102 4,504(7)
=================================================================================================
Notes:
(1) Syncrude is considered a mining operation for US reporting purposes.
Property, plant and equipment at September 30, 2004 includes mineral rights
of $6 million.
(2) Includes results of operations from producing activities in Nigeria and
Colombia.
(3) Includes interest income of $3 million and foreign exchange losses of $9
million.
(4) Includes exploration activities primarily in Nigeria and Colombia.
(5) Includes Yemen cash taxes of $65 million.
(6) Approximately 84% of marketing's identifiable assets are accounts
receivable and inventories.
(7) Excludes property, plant and equipment related to our discontinued
operations. See Note 15.
23
NINE MONTHS ENDED SEPTEMBER 30, 2004
CORPORATE
AND
(CDN$ MILLIONS) OIL AND GAS SYNCRUDE(1) CHEMICALS OTHER TOTAL
- -----------------------------------------------------------------------------------------------------------------------------------
UNITED OTHER
YEMEN CANADA STATES COUNTRIES(2) MARKETING
----------------------------------------------------
Net Sales 679 290 581 53 10 243 283 - 2,139
Marketing and Other 3 6 10 - 403 - 3 14(3) 439
------------------------------------------------------------------------------------------------
Total Revenues 682 296 591 53 413 243 286 14 2,578
Less: Expenses
Operating 80 87 81 6 12 90 178 - 534
Depreciation, Depletion,
Amortization and
Impairment 123 96 185 14 8 13 28 13 480
Transportation and Other 2 10 - - 338 8 28 14 400
General and Administrative (4) 2 41 28 39 38 - 25 74 247
Exploration 2 12 53 40(5) - - - - 107
Interest - - - - - - - 118 118
------------------------------------------------------------------------------------------------
Income (Loss) from
Continuing Operations before
Income Taxes 473 50 244 (46) 17 132 27 (205) 692
=====================================================================================
Less: Provision for Income 208
Taxes (6)
Add: Net Income from
Discontinued Operations 63
---------
Net Income 547
==========
Identifiable Assets 619 1,793 1,652 254 1,666(7) 857 497 785 8,123
=================================================================================================
Capital Expenditures
Development and Other 176 307 199 44 3 155 47 19 950
Exploration 5 14 57 20 - - - - 96
-------------------------------------------------------------------------------------------------
181 321 256 64 3 155 47 19 1,046
=================================================================================================
Property, Plant and Equipment
Cost 2,032 2,382 2,304 362 155 972 814 188 9,209
Less: Accumulated DD&A 1,581 1,169 1,027 225 61 152 404 86 4,705
-------------------------------------------------------------------------------------------------
Net Book Value 451 1,213 1,277 137 94 820 410 102 4,504(8)
=================================================================================================
Notes:
(1) Syncrude is considered a mining operation for US reporting purposes.
Property, plant and equipment at September 30, 2004 includes mineral rights
of $6 million.
(2) Includes results of operations from producing activities in Nigeria and
Colombia.
(3) Includes interest income of $8 million and foreign exchange gains of $6
million.
(4) Includes a one-time charge of $82 million related to the modification of
our stock option plan.
(5) Includes exploration activities primarily in Nigeria, Colombia and
Equatorial Guinea.
(6) Includes Yemen cash taxes of $168 million.
(7) Approximately 84% of marketing's identifiable assets are accounts
receivable and inventories.
(8) Excludes property, plant and equipment related to our discontinued
operations. See Note 15.
24
19. DIFFERENCES BETWEEN CANADIAN AND US GENERALLY ACCEPTED ACCOUNTING
PRINCIPLES
The Unaudited Consolidated Financial Statements have been prepared in accordance
with Canadian GAAP. The US GAAP Unaudited Consolidated Statement of Income and
Balance Sheet and summaries of differences from Canadian GAAP are as follows:
(a) UNAUDITED CONSOLIDATED STATEMENT OF INCOME - US GAAP FOR THE THREE AND NINE
MONTHS ENDED SEPTEMBER 30
THREE MONTHS NINE MONTHS
ENDED SEPTEMBER 30 ENDED SEPTEMBER 30
(CDN$ MILLIONS, EXCEPT PER SHARE AMOUNTS) 2005 2004 2005 2004
- -----------------------------------------------------------------------------------------------------------------------
REVENUES
Net Sales 1,094 778 2,859 2,139
Marketing and Other (ii); (viii) 16 146 335 445
Gain on Dilution of Interest in Chemicals Business 193 - 193 -
----------------------------------------------
1,303 924 3,387 2,584
----------------------------------------------
EXPENSES
Operating (iv) 222 196 655 539
Depreciation, Depletion, Amortization and Impairment (i) 265 175 777 508
Transportation and Other 201 122 583 398
General and Administrative 342 57 647 211
Exploration 32 54 164 107
Interest 19 35 84 118
----------------------------------------------
1,081 639 2,910 1,881
----------------------------------------------
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES 222 285 477 703
----------------------------------------------
PROVISION FOR INCOME TAXES
Current 95 73 255 189
Deferred (ii); (iv) (74) 24 (145) 19
----------------------------------------------
21 97 110 208
----------------------------------------------
NET INCOME FROM CONTINUING OPERATIONS
BEFORE NON-CONTROLLING INTERESTS 201 188 367 495
NET INCOME ATTRIBUTABLE TO NON CONTROLLING INTERESTS 5 - 5 -
----------------------------------------------
NET INCOME FROM CONTINUING OPERATIONS 196 188 362 495
Net Income from Discontinued Operations 404 20 452 59
----------------------------------------------
NET INCOME-- US GAAP (1) 600 208 814 554
===============================================
EARNINGS PER COMMON SHARE ($/share)
Basic (Note 12)
Net Income from Continuing Operations 0.75 0.73 1.39 1.93
Net Income from Discontinued Operations 1.55 0.08 1.74 0.23
---------------------------------------------
2.30 0.81 3.13 2.16
===============================================
Diluted (Note 12)
Net Income from Continuing Operations 0.74 0.72 1.36 1.90
Net Income from Discontinued Operations 1.51 0.08 1.70 0.23
---------------------------------------------
2.25 0.80 3.06 2.13
===============================================
NOTE:
(1) RECONCILIATION OF CANADIAN AND US GAAP NET INCOME THREE MONTHS NINE MONTHS
ENDED SEPTEMBER 30 ENDED SEPTEMBER 30
(CDN$ MILLIONS) 2005 2004 2005 2004
- -----------------------------------------------------------------------------------------------------------------------
Net Income-- Canadian GAAP 615 220 852 547
Impact of US Principles, Net of Income Taxes:
Depreciation, Depletion, Amortization and Impairment (1) (i) (9) (11) (29) (32)
Ineffective Portion of Cash Flow Hedges (ii) (5) - (5) -
Fair Value of Preferred Securities (viii) - - - 4
Stock Based Compensation Included in Retained Earnings - - - 36
Other (ii); (iv) (1) (1) (4) (1)
----------------------------------------------
Net Income-- US GAAP 600 208 814 554
===============================================
Note:
(1) Includes depreciation, depletion, amortization and impairment related to discontinued operations.
25
(b) UNAUDITED CONSOLIDATED BALANCE SHEET - US GAAP
SEPTEMBER 30 DECEMBER 31
(CDN$ MILLIONS, EXCEPT SHARE AMOUNTS) 2005 2004
- -----------------------------------------------------------------------------------------------------------------------
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents 200 73
Margin Deposits 202 -
Accounts Receivable (ii) 2,828 2,106
Inventories and Supplies 514 351
Assets of Discontinued Operations - 38
Other 56 41
-------------------------------
Total Current Assets 3,800 2,609
-------------------------------
PROPERTY, PLANT AND EQUIPMENT
Net of Accumulated Depreciation, Depletion, Amortization and
Impairment of $5,551 (December 31, 2004 - $5,290) (i); (iv); (vii) 9,029 8,189
GOODWILL 366 375
DEFERRED INCOME TAX ASSETS 395 333
DEFERRED CHARGES AND OTHER ASSETS (v) 309 384
ASSETS OF DISCONTINUED OPERATIONS - 449
-------------------------------
13,899 12,339
================================
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Short-Term Borrowings - 100
Accounts Payable and Accrued Liabilities (ii) 3,784 2,377
Accrued Interest Payable 39 34
Dividends Payable 13 13
Liabilities of Discontinued Operations - 39
-------------------------------
Total Current Liabilities 3,836 2,563
-------------------------------
LONG-TERM DEBT (v) 3,613 4,214
DEFERRED INCOME TAX LIABILITIES (i) - (ix) 1,828 1,993
ASSET RETIREMENT OBLIGATIONS 437 399
DEFERRED CREDITS AND LIABILITIES (vi) 500 148
LIABILITIES OF DISCONTINUED OPERATIONS - 130
NON CONTROLLING INTERESTS 91 -
SHAREHOLDERS' EQUITY
Common Shares, no par value
Authorized: Unlimited
Outstanding: 2005 - 260,879,092 shares
2004 - 258,399,166 shares 719 637
Contributed Surplus 1 -
Retained Earnings (i); (ii); (iv); (vii); (viii) 3,135 2,360
Accumulated Other Comprehensive Income (ii); (iii); (vi) (261) (105)
-------------------------------
Total Shareholders' Equity 3,594 2,892
-------------------------------
COMMITMENTS, CONTINGENCIES AND GUARANTEES
13,899 12,339
================================
(c) UNAUDITED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME - US GAAP
FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30
THREE MONTHS NINE MONTHS
ENDED SEPTEMBER 30 ENDED SEPTEMBER 30
(CDN$ MILLIONS) 2005 2004 2005 2004
- -----------------------------------------------------------------------------------------------------------------------
Net Income - US GAAP 600 208 814 554
Other Comprehensive Income, Net of Income Taxes:
Translation Adjustment (iii) (101) (49) (78) (35)
Unrealized Mark-to-Market Loss (ii) (71) (18) (78) (12)
---------------------------------------------------
Comprehensive Income 428 141 658 507
===================================================
26
NOTES:
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 GAAP, this
difference was recorded as a deferred tax liability with an increase to
property, plant and equipment rather than a charge to retained
earnings. As a result:
o additional depreciation, depletion, amortization and impairment of
$9 million and $29 million for the three and nine months ended
September 30, 2005, respectively (2004 - $11 million and $32
million, respectively) was included in net income; and
o property, plant and equipment is higher under US GAAP at December
31, 2004 by $23 million.
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 earnings 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 GAS INVENTORY: Included in accounts receivable at
December 31, 2004, were $6 million of gains on the futures contracts
and swaps we used to hedge the commodity price risk on the future sale
of our gas inventory as described in Note 10. These contracts
effectively lock-in profits on our stored gas volumes. Gains of $6
million ($4 million, net of income taxes) related to the effective
portion and deferred in accumulated other comprehensive income (AOCI)
at December 31, 2004, were recognized in marketing and other during the
first quarter of 2005.
At September 30, 2005, losses of $121 million ($79 million, net of
income taxes) were included in accounts payable and the effective
portion of $113 million ($74 million, net of income taxes) was deferred
in AOCI until the underlying gas inventory is sold. The losses will be
reclassified to marketing and other as they settle over the next 12
months. The ineffective portion of the losses of $8 million ($5
million, net of income taxes) was recognized in net income during the
quarter.
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 earnings. At September 30, 2005 and at
December 31, 2004, 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 Unaudited Consolidated Balance Sheet - US GAAP.
iv. Under Canadian GAAP, we defer certain development costs and all
pre-operating revenues and costs to property, plant and equipment.
Under US GAAP, these costs have been included in operating expenses. As
a result:
o operating expenses include pre-operating costs of $1 million and
$5 million for the three and nine months ended September 30, 2005,
respectively ($1 million and $4 million, respectively, net of
income taxes) (2004 - $1 million and $5 million, respectively ($1
million and $3 million, respectively, net of taxes)); and
o property, plant and equipment is lower under US GAAP by $20
million (December 31, 2004 - $15 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 $57 million (December 31, 2004 - $45 million) have
been included in long-term debt.
vi. Under US GAAP, the amount by which our accrued pension cost is less
than the unfunded accumulated benefit obligation is included in AOCI
and accrued pension liabilities. This amount was $6 million ($4
million, net of income taxes) at September 30, 2005 (December 31, 2004
- $6 million ($4 million, net of income taxes)).
27
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 property, plant and
equipment under US GAAP being lower by $19 million.
viii. In May 2003, FASB issued Statement No. 150, ACCOUNTING FOR CERTAIN
INSTRUMENTS WITH CHARACTERISTICS OF BOTH LIABILITIES AND EQUITY that
requires certain financial instruments, including our preferred
securities, to be valued at fair value with changes in fair value
recognized through net income.
(Cdn$ millions) GAIN TAX NET GAIN
--------------------------------------------------------------------------------------------------
Fair value change from January 1, 2004 to February 9, 2004 (1), (2) 4 - 4
---------------------------
Notes:
(1) Included in marketing and other.
(2) Redemption date of preferred securities.
NEW ACCOUNTING PRONOUNCEMENTS
In November 2004, the Financial Accounting Standards Board (FASB) issued
Statement 151, INVENTORY COSTS. This statement amends Accounting Research
Bulletin 43 to clarify that:
o abnormal amounts of idle facility expense, freight, handling costs and
wasted material (spoilage) should be recognized as current-period charges;
and
o requires the allocation of fixed production overhead to inventory based on
the normal capacity of the production facilities.
The provisions of this statement are effective for inventory costs incurred
during fiscal years beginning after June 15, 2005. We do not expect the adoption
of this statement will have any material impact on our results of operations or
financial position.
In December 2004, the FASB issued Statement 123(R), SHARE-BASED PAYMENTS. This
statement revises Statement 123, ACCOUNTING FOR STOCK-BASED COMPENSATION, and
supersedes APB Opinion 25, ACCOUNTING FOR STOCK ISSUED TO EMPLOYEES. Statement
123(R) requires all stock-based awards issued to employees to be measured at
fair value and to be expensed in the income statement. This statement is
effective for fiscal years beginning after June 15, 2005.
We are currently expensing stock-based awards issued to employees using the fair
value method for equity based awards and the intrinsic method for liability
based awards. Adoption of this standard will change our expense under US GAAP
for tandem options and stock appreciation rights as these awards will be
measured using the fair value method rather than the intrinsic method. We are
currently evaluating the provisions of Statement 123(R) and have not yet
determined the full impact this statement will have on our results of operations
or financial position under US GAAP.
In December 2004, the FASB issued Statement 153, EXCHANGES OF NONMONETARY
ASSETS, an amendment of APB Opinion 29, ACCOUNTING FOR NONMONETARY TRANSACTIONS.
This amendment eliminates the exception for nonmonetary exchanges of similar
productive assets and replaces it with a general exception for exchanges of
nonmonetary assets that do not have commercial substance. Under Statement 153,
if a nonmonetary exchange of similar productive assets meets a
commercial-substance test and fair value is determinable, the transaction must
be accounted for at fair value resulting in the recognition of any gain or loss.
This statement is effective for nonmonetary transactions in fiscal periods that
begin after June 15, 2005. We do not expect the adoption of this statement will
have any material impact on our results of operations or financial position.
28
In March 2005, the FASB issued Financial Interpretation 47, ACCOUNTING FOR
CONDITIONAL ASSET RETIREMENT OBLIGATIONS (FIN 47). FIN 47 clarifies that the
term conditional asset retirement obligation as used in FASB Statement No. 143,
ACCOUNTING FOR ASSET RETIREMENT OBLIGATIONS, refers to a legal obligation to
perform an asset retirement activity in which the timing and (or) method of
settlement are conditional on a future event that may or may not be within the
control of the entity. The obligation to perform the asset retirement activity
is unconditional even though uncertainty exists about the timing and (or) method
of settlement. Thus, the timing and (or) method of settlement may be conditional
on a future event. Accordingly, an entity is required to recognize a liability
for the fair value of a conditional asset retirement obligation if the fair
value of the liability can be reasonably estimated. FIN 47 also clarifies when
an entity would have sufficient information to reasonably estimate the fair
value of an asset retirement obligation. FIN 47 is effective no later than the
end of fiscal years ending after December 15, 2005. We do not expect the
adoption of this statement will have a material impact on our results of
operations or financial position.
In March 2005, the Emerging Issues Task Force (EITF) reached a consensus on
Issue No. 04-6, ACCOUNTING FOR STRIPPING COSTS INCURRED DURING PRODUCTION IN THE
MINING INDUSTRY. In the mining industry, companies may be required to remove
overburden and other mine waste materials to access mineral deposits. The EITF
concluded that the costs of removing overburden and waste materials, often
referred to as "stripping costs", incurred during the production phase of a mine
are variable production costs that should be included in the costs of the
inventory produced during the period that the stripping costs are incurred.
Issue No. 04-6 is effective for the first reporting period in fiscal years
beginning after December 15, 2005, with early adoption permitted. We do not
expect the adoption of this statement will have a material impact on our results
of operations or financial position.
In June 2005, the FASB issued Statement 154, ACCOUNTING CHANGES AND ERROR
CORRECTIONS which replaces APB Opinion 20 and FASB Statement 3. Statement 154
changes the requirements for the accounting and reporting of a change in
accounting principle. Opinion 20 previously required that most voluntary changes
in accounting principle be recognized by including the cumulative effect of the
new accounting principle in net income of the period of the change. Statement
154 now requires retrospective application of changes in accounting principle to
prior period financial statements, unless it is impracticable to determine
either the period-specific effects or the cumulative effect of the change. The
Statement is effective for fiscal years beginning after December 15, 2005. We do
not expect the adoption of this statement will have a material impact on our
results of operations or financial position.
29
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
THE FOLLOWING SHOULD BE READ IN CONJUNCTION WITH THE UNAUDITED CONSOLIDATED
FINANCIAL STATEMENTS INCLUDED IN THIS REPORT. THE UNAUDITED CONSOLIDATED
FINANCIAL STATEMENTS HAVE BEEN PREPARED IN ACCORDANCE WITH GENERALLY ACCEPTED
ACCOUNTING PRINCIPLES (GAAP) IN CANADA. THE IMPACT OF THE SIGNIFICANT
DIFFERENCES BETWEEN CANADIAN AND UNITED STATES (US) ACCOUNTING PRINCIPLES ON THE
FINANCIAL STATEMENTS IS DISCLOSED IN NOTE 19 TO THE UNAUDITED CONSOLIDATED
FINANCIAL STATEMENTS. THE DATE OF THIS DISCUSSION IS OCTOBER 12, 2005.
UNLESS OTHERWISE NOTED, TABULAR AMOUNTS ARE IN MILLIONS OF CANADIAN DOLLARS. THE
DISCUSSION AND ANALYSIS OF OUR OIL, GAS AND SYNCRUDE ACTIVITIES WITH RESPECT TO
OIL AND GAS VOLUMES, RESERVES AND RELATED PERFORMANCE MEASURES IS 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 A NET, AFTER-ROYALTIES BASIS IN TABULAR FORMAT.
NOTE: CANADIAN INVESTORS SHOULD READ THE SPECIAL NOTE TO CANADIAN INVESTORS ON
PAGE 72 OF OUR 2004 ANNUAL REPORT ON FORM 10-K WHICH HIGHLIGHTS DIFFERENCES
BETWEEN OUR RESERVE ESTIMATES AND RELATED DISCLOSURES THAT ARE OTHERWISE
REQUIRED BY CANADIAN REGULATORY AUTHORITIES.
EXECUTIVE SUMMARY OF THIRD QUARTER RESULTS
Three Months Nine Months
Ended September 30 Ended September 30
(Cdn$ millions) 2005 2004 2005 2004
- -------------------------------------------------------------------------------------------------------------
Net Income 615 220 852 547
Earnings per Common Share ($/share) 2.36 0.85 3.28 2.13
Cash Flow from Operating Activities 642 403 1,675 1,230
Production, before Royalties (mboe/d) 232 244 247 247
Production, after Royalties (mboe/d) 164 170 176 171
Nexen's Average Realized Oil and Gas Price (Cdn$/boe) 67.09 48.66 56.44 44.29
Capital Expenditures 648 380 1,923 1,046
Net Debt (1) 3,585 1,432 3,585 1,432
-------------------------------------------------
Note:
(1) Net debt is defined as long-term debt less net working capital.
Our third quarter was characterized by the successful execution of our
divestiture program and record high commodity prices. We sold conventional
Canadian oil and gas properties in Alberta, British Columbia and Saskatchewan
and raised $900 million in proceeds after closing adjustments ($946 million
before closing adjustments primarily related to production during the period
from the effective date of the sales to the closing date). In addition, we
raised $301 million of net proceeds from the initial public offering of our
chemicals operations. Gains of $418 million were generated from these
transactions and proceeds were used to repay debt and fund our development
projects.
Tight refining capacity, along with production disruptions from an active
hurricane season in the Gulf of Mexico, lifted commodity prices to all-time
highs. The record prices contributed to our improved results.
Our marketing group reported a loss of $162 million for the third quarter. As a
marketer of natural gas, we actively hold natural gas in storage and pipeline
capacity to transport gas from Alberta to eastern markets. We use financial
instruments to preserve the economic value of these physical assets. During the
quarter, Hurricanes Katrina and Rita caused volatility in the market. This
resulted in a significant increase in the value of our physical assets. At the
same time, the value of the financial instruments protecting the value of these
assets decreased. While accounting rules require us to recognize the loss on the
financial instruments, they do not allow us to recognize the gain on the
offsetting physical assets until the gas is delivered and sold. At quarter-end,
we had unrecognized gains of $195 million relating to this pipeline and storage
capacity that we expect to realize in net income over the next two quarters as
the gas is delivered and sold in eastern markets.
During the quarter, our stock price increased 49% or $18.25 per share, adding
approximately $5 billion in shareholder value. Our stock price has more than
doubled since the beginning of the year. This has resulted in stock based
compensation expense of $260 million for the quarter and $450 million year to
date.
30
Compared to the second quarter of 2005, our production before royalties declined
by 19,000 boe/d from 251,000 boe/d to 232,000 boe/d. This is largely the result
of selling oil and gas properties in Canada which produced 18,300 boe/d in the
second quarter. These properties contributed 6,500 boe/d to our third quarter
production before the sales closed in July and August. In Yemen, new production
from Block 51 offset base declines in Masila and efforts to enhance recovery
rates from our remaining oil and gas producing properties in Canada yielded
positive results. Our quarterly production, however, was reduced by
approximately 10,000 boe/d from hurricane-related downtime in the Gulf of
Mexico. We expect our average production for the year to be near the mid-point
of our guidance of between 235,000 and 245,000 boe/d, even after our asset
dispositions and the impact of storms in the Gulf.
We progressed our major development projects at Buzzard in the North Sea, at
Long Lake and at Syncrude Stage 3.
CAPITAL INVESTMENT
Capital investment during the third quarter was focused primarily on our major
development projects and on exploration drilling in the Gulf of Mexico, the
North Sea and offshore West Africa. Our capital investment over the next two
years is focused on bringing our major development projects on-stream. To date,
we have invested over $4 billion in the Buzzard, Long Lake and Syncrude Stage 3
development projects. These projects are expected to come on-stream in 2006 and
are expected to add almost 120,000 boe/d (net to us) of new production by the
end of 2007.
In addition to developing these projects, we are also targeting new
opportunities through on-going exploration and the application of new
technologies. Details of our capital programs are set out below.
THREE MONTHS ENDED SEPTEMBER 30, 2005
New Growth New Growth Core Asset
(Cdn$ millions) Development Exploration Development Total
- -----------------------------------------------------------------------------------------------------------------------------
Oil and Gas
Synthetic (mainly Long Lake) 188 - - 188
United Kingdom 114 35 17 166
Yemen 31 11 22 64
United States - 46 28 74
Canada 1 26 47 74
Other Countries - 15 3 18
Syncrude 35 - 20 55
------------------------------------------------------------------
369 133 137 639
Chemicals, Marketing, Corporate and Other - - 9 9
------------------------------------------------------------------
Total Capital 369 133 146 648
==================================================================
As a % of Total Capital 57% 21% 22% 100%
------------------------------------------------------------------
NINE MONTHS ENDED SEPTEMBER 30, 2005
New Growth New Growth Core Asset
(Cdn$ millions) Development Exploration Development Total
- -----------------------------------------------------------------------------------------------------------------------------
Oil and Gas
Synthetic (mainly Long Lake) 555 - - 555
United Kingdom 348 51 76 475
Yemen 128 27 56 211
United States - 178 98 276
Canada 8 53 105 166
Other Countries - 48 10 58
Syncrude 108 - 41 149
------------------------------------------------------------------
1,147 357 386 1,890
Chemicals, Marketing, Corporate and Other - - 33 33
------------------------------------------------------------------
Total Capital 1,147 357 419 1,923
==================================================================
As a % of Total Capital 60% 18% 22% 100%
------------------------------------------------------------------
31
NEW GROWTH DEVELOPMENT
SYNTHETIC (LONG LAKE)
Long Lake continues on schedule and on budget. With detailed engineering largely
completed, approximately 60% of the project's total costs committed, and
approximately 45% of these costs incurred, our experience remains in line with
our original estimates. The major remaining cost uncertainty is related to
labour access and productivity. We are monitoring these factors as field
construction progresses. Long Lake is scheduled to commence steam injection in
late-2006 and synthetic crude oil production in 2007.
We and our joint venture partner, OPTI Canada, are currently planning three
future phases to increase total production to 240,000 bbls/d by 2016 (120,000
bbls/d net to us). Phase 2 will develop the southern portion of the Long Lake
lease, known as Kinosis. Phases 3 and 4 are planned to develop jointly held
lands at Cottonwood and Leismer. Detailed planning for Phase 2 has commenced. In
2006, we will invest in additional drilling and seismic to further evaluate our
leases. We are moving forward with environmental and regulatory applications to
support these staged developments.
Phase 2 steam assisted gravity drainage (SAGD) could be on-stream by late 2010
with upgrader start up by the second half of 2011. Each subsequent phase will
leverage the knowledge and experience gained in the successful development of
previous phases. Future phases will be of a similar size and design to Long
Lake, and consist of SAGD and an integrated upgrader. By keeping the core team
in place and repeating and improving upon existing designs and execution plans,
we expect to gain efficiencies in engineering, module fabrication and on-site
construction.
UNITED KINGDOM
The Buzzard development in the North Sea is over 80% complete and remains on
schedule and on budget. We have installed the platform jackets and wellhead
deck. Export and water injection pipelines have been installed and final tie-in
of these pipelines is ongoing. We are mobilizing the Galaxy 3 drilling rig and
will commence drilling the eight initial development wells shortly. Buzzard is
scheduled to come on-stream late-2006. At its peak, Buzzard is expected to add
approximately 85,000 boe/d of net production and between $1.6 and $1.7 billion
of annual cash flow, assuming a US$50/bbl WTI.
Our Farragon field development remains on schedule to begin producing late this
year at between 3,000 and 4,000 boe/d, net to us.
CANADA (COAL BED METHANE)
We and our partners plan to invest approximately $400 million over the next 18
months to develop coal bed methane from Upper Mannville coals in the Fort
Assiniboine area of Alberta. This capital will be used to drill wells, construct
production and water handling facilities, and expand existing facilities in the
Corbett area. We are currently finalizing our drilling program and expect to
have four drilling rigs active in the Corbett area during the fourth quarter.
NEW GROWTH EXPLORATION
We had two small exploration successes in the North Sea during the quarter: the
Polecat-1 well on Block 20/4a and the Yeoman-1 well on Block 15/18b. We have a
40% interest in Polecat and a 50% interest in Yeoman and operate both
discoveries. We are currently drilling the Black Horse prospect on Block 15/22
and expect to drill one or two additional exploration wells in the North Sea
this year.
One of our core strategies in the deep-water Gulf of Mexico is to explore for
Miocene-aged, subsalt prospects in the Green Canyon, Walker Ridge, and Garden
Banks areas. This strategy produced encouraging results during the second
quarter at our Knotty Head prospect in a shallower, secondary objective
containing good quality sands.
Knotty Head is a large, four-way dip closure located approximately 15 miles
northeast of the Tahiti discovery. The well is continuing to drill towards the
primary objective in the lower Miocene, to a total depth of 32,500 feet. We have
a 25% working interest in Knotty Head.
Elsewhere in the Gulf, Castleton, on Garden Banks 668 has reached its target
depth and is being evaluated. This is a potential tie-back to the Gunnison
facilities where we have available production capacity. We have a 30%
non-operated interest in this well.
Drilling activity on our Pathfinder and Ringo Shallow prospects has been delayed
due to hurricane damage to drilling rigs. Pathfinder, on Green Canyon 390 is
expected to resume drilling late this year. Ringo, on Mississippi Canyon 546, is
expected to begin drilling early next year.
On Block 51 in Yemen, the BAK-I-2 well was abandoned. The BAK-U-1 is currently
testing a basement target north of the BAK-A field. At BAK-J, we expect to
re-enter the well and commence testing and drilling early in the fourth quarter.
32
Offshore West Africa, the Usan-7 and Usan-8 appraisal wells were successfully
drilled during the quarter. The Field Development Plan for Usan on Block 222 has
been approved by the Nigerian National Petroleum Corporation, the concessionaire
of the licence. We are currently seeking approval from the Department of
Petroleum Resources. The plan features development of Usan through 35 subsea
wells connected to a two million barrel floating production and storage facility
by subsea lines and risers. The processing capacity will be around 160,000
barrels of oil per day. The operator has taken initial steps in the tendering
process by publishing pre-qualification notices for contractors. A final
investment decision is expected in 2006 with first oil planned by 2010.
FINANCIAL RESULTS
CHANGE IN NET INCOME
2005 VS 2004
Three Months Nine Months
(Cdn$ millions) Ended September 30 Ended September 30
- --------------------------------------------------------------------------------------------------------------------
NET INCOME AT SEPTEMBER 30, 2004 (1) 220 547
=============================================
Favourable (unfavourable) variances:
Cash Items:
Production volumes, after royalties:
Crude oil (14) 119
Natural gas (10) (24)
Change in crude oil inventory 29 24
---------------------------------------------
Total Volume Variance 5 119
Realized commodity prices:
Crude oil 213 441
Natural gas 61 74
---------------------------------------------
Total Price Variance 274 515
Oil and gas operating expense:
Conventional (10) (57)
Syncrude (6) (20)
---------------------------------------------
Total Operating Expense Variance (16) (77)
Marketing (158) (61)
Chemicals 16 29
General and administrative
Stock-based compensation paid (32) (48)
Other (37) (60)
Interest expense 16 34
Current income taxes (22) (66)
Other (49) (53)
---------------------------------------------
Total Cash Variance (3) 332
Non-Cash Items:
Depreciation, depletion, amortization and impairment
Oil and gas (73) (218)
Other (2) (17)
Exploration expense 22 (57)
General and administrative - stock-based compensation accrual (216) (292)
Future income taxes 264 322
Decrease in fair value of crude oil put options (1) (184)
Gain from divesture programs 418 418
Other (14) 1
---------------------------------------------
Total Non-Cash Variance 398 (27)
---------------------------------------------
NET INCOME AT SEPTEMBER 30, 2005 615 852
=============================================
Note:
(1) Includes results of discontinued operations (see Note 15 to our Unaudited
Consolidated Financial Statements).
Significant variances in net income are explained further in the following
sections.
33
OIL & GAS AND SYNCRUDE
PRODUCTION (BEFORE ROYALTIES) (1)
Three Months Nine Months
Ended September 30 Ended September 30
2005 2004 2005 2004
- ------------------------------------------------------------------------------------------------------------------------------
Oil and Liquids (mbbls/d)
Yemen 113.7 103.3 114.4 107.8
Canada (2) 26.3 35.6 31.8 36.5
United States 18.5 32.9 23.3 28.5
United Kingdom 9.4 - 11.3 -
Australia (3) - 2.1 - 3.0
Other Countries 5.3 5.3 5.5 5.1
Syncrude (4) 17.2 17.6 15.2 17.5
-----------------------------------------------------
190.4 196.8 201.5 198.4
-----------------------------------------------------
Natural Gas (mmcf/d)
Canada (2) 112 141 132 145
United States 122 144 123 148
United Kingdom 14 - 19 -
-----------------------------------------------------
248 285 274 293
-----------------------------------------------------
Total (mboe/d) 232 244 247 247
=====================================================
PRODUCTION (AFTER ROYALTIES)
Three Months Nine Months
Ended September 30 Ended September 30
2005 2004 2005 2004
- ------------------------------------------------------------------------------------------------------------------------------
Oil and Liquids (mbbls/d)
Yemen 61.2 50.8 60.9 53.0
Canada (2) 19.7 27.3 24.5 28.2
United States 16.2 29.1 20.6 25.1
United Kingdom 9.4 - 11.3 -
Australia (3) - 1.9 - 2.8
Other Countries 4.9 4.9 5.2 4.7
Syncrude (4) 17.0 17.4 15.0 17.3
-----------------------------------------------------
128.4 131.4 137.5 131.1
-----------------------------------------------------
Natural Gas (mmcf/d)
Canada (2) 95 106 105 114
United States 103 123 104 126
United Kingdom 14 - 19 -
-----------------------------------------------------
212 229 228 240
-----------------------------------------------------
Total (mboe/d) 164 170 176 171
=====================================================
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 15
to our Unaudited Consolidated Financial Statements.
Three Months Nine Months
Ended September 30 Ended September 30
2005 2004 2005 2004
- ------------------------------------------------------------------------------------------------------------------------------
Before Royalties
Oil and Liquids (mbbls/d) 4.3 11.4 9.0 11.9
Natural Gas (mmcf/d) 13 48 32 48
After Royalties
Oil and Liquids (mbbls/d) 3.3 8.7 7.0 9.0
Natural Gas (mmcf/d) 9 33 22 33
-----------------------------------------------------
(3) Comprises production from discontinued operations. See Note 15 to our
Unaudited Consolidated Financial Statements.
(4) Considered a mining operation for US reporting purposes.
34
LOWER PRODUCTION DECREASED NET INCOME FOR THE QUARTER BY $24 MILLION
Production before royalties decreased 8% from the second quarter as a result of
the sale of Canadian conventional oil and gas properties in Alberta, British
Columbia and Saskatchewan. Our 2005 production includes volumes from our North
Sea acquisition late last year and additional volumes from our Block 51 project
in Yemen. Removing the impact of the asset sales, third quarter production is
comparable to the third quarter of 2004 and year-to-date volumes have increased
2% compared to the same period last year.
The following table summarizes our production volume changes since the last
quarter:
Before After
(mboe/d) Royalties Royalties
- ------------------------------------------------------------------------------
Production, second quarter 2005 251 180
Production changes:
Masila Block in Yemen (7) (4)
Block 51 in Yemen 6 2
Canada, disposition of properties (12) (9)
Gulf of Mexico, Gunnison and the Shelf 6 5
Gulf of Mexico, hurricane-related downtime (10) (9)
Other (2) (1)
----------------------
Production, third quarter 2005 232 164
======================
Our expected future production increases from known projects will come from
Syncrude in 2006, our North Sea Buzzard project in late-2006, along with bitumen
production in 2006 and synthetic crude in 2007 from our Long Lake project.
Production volumes discussed in this section represent before-royalties volumes,
net to our working interest.
YEMEN
Production from Masila decreased 8% from the second quarter. We are continuing
to see strong initial production rates from development wells drilled and our
development drilling program has helped offset the decline rate on our maturing
Masila fields. We continue to strategically invest capital and are managing our
2005 development drilling program accordingly. In 2004, we drilled 73
development wells and we expect to drill at least 35 wells in 2005.
Block 51 production averaged 30,600 bbls/d in the third quarter, an increase of
22% from the second quarter. We are currently producing from ten wells to
partially completed processing facilities which we expect to complete in the
fourth quarter.
CANADA
Production in Canada decreased 23% from the previous quarter as a result of the
sale of oil and gas properties in Alberta, British Columbia and Saskatchewan,
which produced approximately 18,300 boe/d in the second quarter. Production from
operations that were not sold during the quarter decreased 2% from the second
quarter. Canadian production after the sale is primarily from our heavy oil and
natural gas properties in Alberta and Saskatchewan. We are focusing our capital
on drilling shallow gas wells, on our coal bed methane development projects and
on developing new technologies to increase heavy oil recovery rates. Production
volumes are expected to increase starting in 2006 with the commencement of
bitumen production from Long Lake.
UNITED STATES
Gulf of Mexico production decreased from the second quarter of 2005 because of
the adverse effect of hurricanes, tropical storms and pipeline shut-ins.
Hurricane-related downtime resulted in approximately 10,000 boe/d of lost
production during the quarter. With the exception of our platforms at Vermilion
321 and 340, preliminary inspections suggest that our facilities received only
minor damage from the third quarter hurricanes. Hurricane Rita caused topside
damage to the platforms at Vermilion 321 and 340 and further assessments are
underway to determine if there is any structural damage. Production from these
platforms prior to Hurricane Rita was approximately 3,900 boe/d. We carry
insurance that, subject to certain deductibles, we expect will cover property
damage and business interruption. We have expensed insurance related costs and
deductibles of US$19 million during the quarter as a result of the hurricanes.
Production from Aspen continues to be affected by water production. We are
currently working on plans to drill another development well at Aspen to tap
unrecovered reserves. We tied-in an additional sub-sea well during the quarter
on our other major deep-water project at Gunnison. We expect to complete and
tie-in another Gunnison well during the fourth quarter.
Strong rates from development drilling in the shallow-waters completed in the
quarter helped to maintain production volumes from our shelf properties.
Additional development projects on various shelf fields are expected to be
completed during the fourth quarter.
35
UNITED KINGDOM
Third quarter North Sea production from the Scott and Telford fields decreased
slightly from the prior quarter. The Scott platform underwent a significant
maintenance turnaround and facilities upgrade during the second and third
quarters to improve reliability and facility capacity. The facilities upgrades
included significant improvements to the electric, produced water injection,
drilling and metering systems. The overhaul was completed in August. Additional
development drilling in the Scott field is ongoing and our Farragon field
development remains on schedule to begin producing late this year at between
3,000 and 4,000 boe/d. Production is expected to increase in late-2006 once the
Buzzard development comes on-stream.
OTHER COUNTRIES
Production from our Guando field in Colombia averaged 5,300 bbls/d during the
quarter. Production increased from 2004 as a result of our development drilling
program.
Australia produced its final barrel in November 2004 and abandonment and
reclamation activities are complete. We sold our Ejulebe field assets, offshore
Nigeria, in the second quarter.
SYNCRUDE
Syncrude production was consistent with the second quarter even with unscheduled
downtime related to minor repairs on a hydrogen plant, pipeline maintenance and
valve replacements for feed pumps during the quarter. Production was reduced
late in the quarter for the scheduled 52-day turnaround of the vacuum
distillation unit. The start-up of the Stage 3 expansion is expected to increase
our volumes by approximately 8,000 bbls/d in 2006.
COMMODITY PRICES
Three Months Nine Months
Ended September 30 Ended September 30
2005 2004 2005 2004
- ------------------------------------------------------------------------------------------------------------------------------
CRUDE OIL AND NGLS
West Texas Intermediate (WTI) (US$/bbl) 63.52 43.88 55.51 39.11
-----------------------------------------------------
Differentials (1) (US$/bbl)
Masila 5.00 3.70 5.59 3.85
Heavy Oil - LLK 19.17 12.84 19.88 11.44
Mars 6.58 6.08 6.49 5.21
Dated Brent 1.98 - 1.97 -
Producing Assets (Cdn$/bbl)
Yemen 72.04 53.80 61.64 46.97
Canada 51.05 41.94 41.80 36.85
United States 68.30 49.90 56.89 45.44
United Kingdom 65.87 - 58.88 -
Australia - - - 46.00
Other Countries 65.82 46.22 55.22 43.12
Syncrude 78.93 55.58 71.08 51.11
Corporate Average (Cdn$/bbl) 68.99 50.98 58.39 45.17
-----------------------------------------------------
NATURAL GAS
New York Mercantile Exchange (NYMEX) (US$/mmbtu) 9.69 5.56 7.71 5.82
AECO (Cdn$/mcf) 7.75 6.32 7.03 6.34
-----------------------------------------------------
Producing Assets (Cdn$/mcf)
Canada 8.19 5.43 6.66 5.66
United States 11.57 7.64 9.63 7.88
United Kingdom 4.84 - 6.00 -
Corporate Average (Cdn$/mcf) 9.68 6.55 7.95 6.78
-----------------------------------------------------
NEXEN'S AVERAGE REALIZED OIL AND GAS PRICE (Cdn$/boe) 67.09 48.66 56.44 44.29
-----------------------------------------------------
AVERAGE FOREIGN EXCHANGE RATE
Canadian to US Dollar (US$) 0.8325 0.7650 0.8170 0.7530
-----------------------------------------------------
Note:
(1) These differentials are a discount to WTI.
36
HIGHER REALIZED COMMODITY PRICES INCREASED QUARTERLY NET INCOME BY $274 MILLION
WTI continued its run to new record highs in the quarter averaging US$63.52/bbl
compared to US$43.88/bbl in the third quarter of 2004 (an increase of 45%). We
realized record prices for our crude oil, averaging $68.99/bbl in the quarter,
an increase of 35% over the third quarter of 2004. Our realized gas price
increased 48% from a year ago to average $9.68/mcf. NYMEX increased 74% in the
same period averaging US$9.69/mmbtu.
The full benefit of higher benchmark prices did not flow through to our realized
prices as a result of a weaker US dollar during the quarter. All of our oil
sales and most of our gas sales are denominated in or referenced to US dollars.
As a result, the weakening US dollar decreased net sales for the quarter by
approximately $90 million ($230 million for the year to date), and reduced our
realized crude oil and natural gas prices by approximately $6.10/bbl and
$0.85/mcf, respectively, compared to the third quarter of 2004.
CRUDE OIL REFERENCE PRICES
Crude oil prices strengthened throughout the third quarter with WTI ranging from
US$59 to US$71 per barrel. Despite a strong build in US and global crude oil
inventory levels, the effects of Hurricanes Katrina and Rita put pressure on
tight refinery capacity for product inventories, particularly US gasoline and
WTI spiked in the high US$60 per barrel range. While the hurricane damage to oil
infrastructure is still being assessed, the cumulative effects of the two
hurricanes may be significant and energy prices remain vulnerable to further
supply disruptions.
Energy prices have since reverted to pre-Katrina levels. The decline was
prompted by a combination of factors including fear of overall crude oil demand
destruction. The announced release of oil from the US strategic petroleum
reserve and from International Energy Agency member country reserves coupled
with decisions by several refineries to postpone seasonal maintenance has also
resulted in price softening. Any perceived weakening of economic growth or lower
demand as a result of high energy prices will put downward pressure on commodity
prices.
CRUDE OIL DIFFERENTIALS
Our Canadian heavy crude differential averaged US$24.70/bbl. This compares to a
benchmark LLK heavy differential of US$19.17/bbl. In the second quarter, the LLK
heavy differential was US$21.15/bbl. The narrowing of this differential in the
third quarter, despite higher reference prices, was driven by increased demand
for heavy blends relative to light blends. This reflects normal seasonal
narrowing as we headed into the summer asphalt season. Hurricane Katrina caused
further narrowing of the heavy differential during the month of August because
much of the heavy oil production from the Gulf to US mid-continent was shut-in,
thereby increasing the demand for Canadian heavy oil.
In the US Gulf of Mexico, the Mars differential averaged US$6.58/bbl. Mars
strengthened throughout the quarter mainly due to production interruptions from
Hurricane Katrina, but did not outpace WTI, resulting in a slight widening of
the differential. With the additional impact of Hurricane Rita in mid-September,
approximately 94% of oil production and 76% of natural gas production was
shut-in at the end of the quarter, while 18% of refining capacity remains
off-line mainly due to damage at Port Arthur.
Our Yemen Masila differential was US$5.00/bbl. The Masila differential has
narrowed slightly throughout the quarter with continuing strong demand in
south-east Asia for crude oil, particularly sweeter blends.
The Brent/WTI differential has also narrowed throughout the quarter averaging
US$1.98/bbl, resulting in a solid crude oil price for our North Sea barrels. In
the North Sea, increased Norwegian output in July was largely offset by lower
production in August caused by normal summer field maintenance as well as
unplanned outages. The shut-in of BP's Schiehallion field following a fire on
the floating production vessel resulted in lost production of 120,000 barrels
per day for three weeks driving up North Sea prices and narrowing the Brent/WTI
differential.
NATURAL GAS REFERENCE PRICES
Natural gas prices strengthened significantly in the quarter. The average NYMEX
gas price was US$9.69/mmbtu. Prices increased throughout the third quarter
largely reflecting increased demand from prolonged summer heat waves in the east
and the general tightening of the supply/demand balance. Hotter-than-normal
weather reduced the pace at which gas was stored this summer, even before
Hurricanes Katrina and Rita cut output. Upward pressure on prices caused by
hurricane production losses, ahead of expected colder-than-normal winter weather
in key natural gas consuming areas, should support strong prices for the
remainder of 2005.
37
OPERATING COSTS
Three Months Nine Months
Ended September 30 Ended September 30
(Cdn$/boe) 2005 2004 2005 2004
- ------------------------------------------------------------------------------------------------------------------------------
Operating Costs per boe based on our working interest production
before royalties (1)
Conventional Oil and Gas (2) 5.94 5.25 5.85 5.01
Synthetic Crude Oil
Syncrude 23.22 18.87 26.44 18.72
Total Oil and Gas (2) 7.21 6.25 7.11 5.98
-----------------------------------------------------
Operating Costs per boe based on our net production after royalties
Conventional Oil and Gas (2) 8.69 7.93 8.45 7.53
Synthetic Crude Oil
Syncrude 23.46 19.05 26.70 18.91
Total Oil and Gas (2) 10.21 9.11 10.00 8.68
-----------------------------------------------------
Notes:
(1) Operating costs 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.
(2) Operating costs includes results of discontinued operations (see Note 15 to
our Unaudited Consolidated Financial Statements).
HIGHER CONVENTIONAL OIL AND GAS AND SYNCRUDE OPERATING COSTS DECREASED NET
INCOME FOR THE QUARTER BY $16 MILLION
The addition of higher-cost North Sea barrels has increased our corporate
average unit costs since 2004. Our North Sea operating costs per boe were higher
than anticipated following maintenance and repair work from generator failures
and a major maintenance turnaround at Scott during the quarter. Overall, the
North Sea increased our corporate average unit operating costs by $1.03/boe as
compared to the third quarter of 2004.
Unit operating costs at Masila increased from the prior year as a result of
increased service rig activity, additional maintenance and lower volumes. Block
51 costs are higher than Masila reflecting the use of temporary facilities. Our
corporate average increased $0.65/boe from these higher costs.
Our corporate average unit cost decreased $0.80/boe from the third quarter in
2004 as we expensed Aspen-1 intervention costs of $12 million last year.
Workovers on our shelf properties in the Gulf of Mexico, coupled with lower
production and property damage costs not covered by insurance, increased our
corporate average $0.30/boe as to the comparable period in 2004.
The Canadian properties that were sold during the quarter decreased our overall
rate by $0.22/boe. Although we sold high cost production relative to our
corporate average, we expect our overall Canadian operating costs per boe to
increase as we will have a higher proportion of production from our heavy oil
properties. These properties have higher operating costs and lower recovery
rates compared to the lighter oil production that was sold. We are focusing our
efforts on increasing recovery rates from our heavy oil properties through the
development of new technologies.
US-dollar denominated operating costs were lower when translated to Canadian
dollars as a result of the weaker US dollar. Our corporate average was reduced
by $0.25/boe as a result.
Syncrude operating costs were up from the third quarter in 2004. Unplanned
maintenance and repair work in addition to higher energy input costs for fuel
consumed in operations increased our corporate average operating costs by
$0.30/boe in the quarter.
38
DEPRECIATION, DEPLETION, AMORTIZATION AND IMPAIRMENT (DD&A)
Three Months Nine Months
Ended September 30 Ended September 30
(Cdn$/boe) 2005 2004 2005 2004
- ------------------------------------------------------------------------------------------------------------------------------
DD&A per boe based on our working interest production
before royalties (1)
Conventional Oil and Gas (2) 11.65 7.83 10.92 7.59
Synthetic Crude Oil
Syncrude 2.85 2.72 3.19 2.73
Average Oil and Gas (2) 11.01 7.46 10.44 7.25
-----------------------------------------------------
DD&A per boe based on our net production after royalties
Conventional Oil and Gas (2) 17.05 11.85 15.76 11.40
Synthetic Crude Oil
Syncrude 2.88 2.75 3.22 2.75
Average Oil and Gas (2) 15.59 10.88 14.70 10.52
-----------------------------------------------------
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 includes results of discontinued operations (see Note 15 to our
Unaudited Consolidated Financial Statements).
HIGHER OIL AND GAS DD&A REDUCED NET INCOME FOR THE QUARTER BY $73 MILLION
Strong production volumes, new production from our North Sea assets and
additional capital cost recovery from Block 51 in Yemen increased our third
quarter oil and gas DD&A as compared to the third quarter of 2004. The North Sea
fields purchased in late-2004 include an allocation of the acquisition cost of
our interests in the Scott and Telford fields. North Sea depletion increased our
overall corporate average rate by $1.53/boe for the quarter.
Production from Block 51 in Yemen increased our corporate unit depletion by
$3.32/boe in the quarter from 2004 as a result of carried interest accounting
with respect to the recovery of Block 51 capital costs. Strong production and
higher realized oil prices have allowed faster recovery of capital costs we paid
on behalf of the government.
By way of offset, we benefited from a strong Canadian dollar as the depletion of
our US and international assets are denominated in US dollars. This lowered our
depletion rate by $0.68/boe. Depletion from our Canadian assets decreased during
the quarter as properties that were sold were removed from the depletion pool.
This lowered our corporate unit average by $0.63/boe.
EXPLORATION EXPENSE
Three Months Nine Months
Ended September 30 Ended September 30
2005 2004 2005 2004
- ------------------------------------------------------------------------------------------------------------------------------
Seismic 17 15 37 40
Unsuccessful Exploration Drilling 3 27 87 27
Other 12 12 41 41
-----------------------------------------------------
Total Exploration Expense (1) 32 54 165 108
=====================================================
New Growth Exploration 133 30 357 96
Geological and Geophysical Costs 17 15 37 40
-----------------------------------------------------
Total Exploration Expenditures 150 45 394 136
=====================================================
Exploration Expense as a % of Exploration Expenditures 21% 120% 42% 79%
-----------------------------------------------------
Note:
(1) Exploration expense includes results of discontinued operations (see Note
15 to our Unaudited Consolidated Financial Statements).
LOWER EXPLORATION EXPENSE INCREASED QUARTERLY NET INCOME BY $22 MILLION
Exploration expense in the quarter included additional costs relating to the
unsuccessful Vrede well in the Gulf of Mexico which was abandoned in the second
quarter.
39
Exploration capital spending in the third quarter included exploration activity
in the North Sea, the Gulf of Mexico and Yemen. In the North Sea, we had two
small exploration successes at Yeoman-1 on Block 15/18b and at Polecat-1 on
Block 20/4a. We have a 50% interest in Yeoman and a 40% interest in Polecat. We
are currently drilling the Black Horse prospect on Block 15/22 and expect to
drill one or two additional exploration wells in the North Sea this year.
In the Gulf of Mexico, drilling activity continued throughout the quarter on our
Knotty Head prospect as we drill towards our primary objective at a depth of
32,500 feet. We made a discovery earlier in the year on this prospect in a
shallower, secondary objective. Our Castleton prospect on Garden Banks 668
reached its target depth and is being evaluated. We have a 30% non-operated
interest in this well. Drilling activity at the Pathfinder and the Ringo Shallow
prospects has been delayed due to hurricane damage to the drilling rigs.
Pathfinder is expected to resume drilling late this year and Ringo is expected
to begin drilling early next year.
In Yemen, we drilled the BAK-I-2 well on Block 51 which was abandoned. The
BAK-U-1 well is currently testing a basement target north of the BAK-A field. At
BAK-J, we expect to re-enter the well and commence testing and drilling early in
the fourth quarter.
OIL AND GAS MARKETING
Three Months Nine Months
Ended September 30 Ended September 30
(Cdn$ millions) 2005 2004 2005 2004
- ------------------------------------------------------------------------------------------------------------------------------
Marketing Revenue, net 29 144 481 403
Transportation (147) (106) (475) (338)
Other (2) - (4) (2)
-----------------------------------------------------
Net Revenue (120) 38 2 63
-----------------------------------------------------
Physical Sales Volumes (excluding intra-segment transactions)
Crude Oil (mboe/d) 470 445 475 444
Natural Gas (mmcf/d) 4,989 4,929 4,858 4,703
Value-at-Risk
Quarter-end 26 27 26 27
High 30 36 30 36
Low 14 27 14 17
Average 21 33 23 28
-----------------------------------------------------
LOWER CONTRIBUTION FROM MARKETING DECREASED QUARTERLY NET INCOME BY $158 MILLION
In the third quarter, our marketing division recorded a net revenue loss of $120
million. This results in a loss of $162 million after DD&A and general and
administrative expenses. As a marketer of natural gas, we actively hold natural
gas in storage and pipeline capacity to transport gas from Alberta to eastern
markets. We use financial instruments to preserve the economic value of these
physical assets. During the quarter, Hurricanes Katrina and Rita caused
volatility in the market, which resulted in a significant increase in the value
of our physical assets. At the same time, the value of the financial instruments
protecting the value of these assets decreased. Accounting rules require us to
recognize the loss on the financial instruments, but they do not allow us to
recognize the gain on the offsetting assets until the gas is delivered and sold.
The unrecognized economic value of these offsetting assets amounts to $195
million, which we expect to recognize in income over the next two quarters as
the gas is delivered and sold in eastern markets.
With respect to crude oil, our crude oil trading group took advantage of time
spreads to capture gains. In addition, we realized gains from narrowing heavy
and sour differentials by liquidating a portion of our heavy oil and sour oil
inventory positions.
COMPOSITION OF NET MARKETING REVENUE
Three Months Nine Months
Ended September 30 Ended September 30
(Cdn$ millions) 2005 2004 2005 2004
- ------------------------------------------------------------------------------------------------------------------------------
Trading Activities (129) 29 (20) 48
Non-Trading Activities 9 9 22 15
-----------------------------------------------------
(120) 38 2 63
=====================================================
40
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. These derivative
contracts are valued as described in the MD&A included in our 2004 Annual Report
on Form 10-K. Results from trading activities include physical purchases and
sales, gains and losses on derivative contracts and income relating to our
storage and transportation assets.
FAIR VALUE OF MARKETING DERIVATIVE CONTRACTS
At September 30, 2005, the fair value of our marketing derivative contracts not
designated as accounting hedges totalled $52 million. The following table shows
the valuation methods underlying these contracts together with details of
contract maturity:
(Cdn$ millions) MATURITY
- --------------------------------------------------------------------------------------------------------------------------------
less than more than
1 year 1-3 years 4-5 years 5 years Total
--------------------------------------------------------------------
Prices
Actively Quoted Markets 7 (10) - - (3)
From Other External Sources (50) 90 12 3 55
Based on Models and Other Valuation Methods - - - - -
--------------------------------------------------------------------
Total (43) 80 12 3 52
====================================================================
At September 30, 2005, we had $121 million of unrecognized losses on our
marketing derivative contracts designated as accounting hedges of the future
sale of our gas inventory. These losses will be recognized in income when the
related inventory is sold and gains are recognized. These contracts were valued
from actively quoted markets and settle within 12 months.
We do not use option valuation methods to record income on transportation and
storage contracts.
CHANGES IN FAIR VALUE OF MARKETING DERIVATIVE CONTRACTS
Contracts
Outstanding at Contracts
Beginning of Entered into
(Cdn$ millions) Period During Period Total
- -----------------------------------------------------------------------------------------------------------------------------
Fair Value at December 31, 2004 93 - 93
Change in Fair Value of Contracts 259 (70) 189
Net Losses (Gains) on Contracts Closed (37) (193) (230)
Changes in Valuation Techniques and Assumptions (1) - - -
--------------------------------------------------
Fair Value at September 30, 2005 315 (263) 52
==================================
Unrecognized Losses on Hedges of Future Sale of Gas Inventory
at September 30, 2005 (121)
-----------
Total Outstanding at September 30, 2005 (69)
===========
Note:
(1) Our valuation methodology has been applied consistently in each period.
TOTAL CARRYING VALUE OF MARKETING DERIVATIVE CONTRACTS
September 30 December 31
(Cdn$ millions) 2005 2004
- -----------------------------------------------------------------------------------------------------------------------------
Current Assets 508 177
Non Current Assets 210 91
-------------------------------
Total Marketing Derivative Contract Assets 718 268
===============================
Current Liabilities 551 129
Non Current Liabilities 115 46
-------------------------------
Total Marketing Derivative Contract Liabilities 666 175
===============================
Total Marketing Derivative Contract Net Assets (1) 52 93
===============================
Note:
(1) Does not include effective hedges. We recognize gains and losses on
effective hedges in the same period as the hedged item.
41
NON-TRADING ACTIVITIES
We enter into fee for service contracts related to transportation and storage
of third party oil and gas. In addition, we earn income from our power
generation facility. We earned $9 million from these activities in the third
quarter (2004 - $9 million) and $22 million year to date (2004 - $15 million).
In 2003 and 2004, we increased our transportation capacity and were paid to
assume future obligations associated with this capacity. We have $34 million of
deferred revenue on our balance sheet to recognize the liability associated with
these obligations. We are amortizing this deferred revenue to earnings as the
capacity is used.
CHEMICALS
HIGHER CHEMICALS CONTRIBUTION INCREASED NET INCOME BY $16 MILLION
During the quarter, we monetized a portion of our chemicals operations by
creating the Canexus Income Fund through an initial public offering which raised
net proceeds of $301 million. Canexus Income Fund invested the offering proceeds
into Canexus Limited Partnership, which raised US$167 million ($200 million) in
bank debt. Canexus Limited Partnership used the proceeds from Canexus Income
Fund's public offering and the bank debt, together with 50.5 million
exchangeable units of Canexus Limited Partnership to purchase our chemicals
operations. The exchangeable units have a market value of $484 million as of
September 30, 2005. We have retained a 61.4% indirect 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.
Increasing sales volumes and prices continued to generate strong results for the
chemicals business. Sodium chlorate volumes have increased compared to 2004 as a
result of strong demand and higher production capacity from the Brandon plant
expansion completed in October 2004. In addition, the contribution from
chemicals includes $9 million of unrealized currency translation gains arising
substantially from the translation of US dollar long-term debt and $4 million of
income from the change in fair value of US dollar foreign currency call options.
Higher transportation costs, however, reduced chemicals contribution by $1
million. Sales and operations at the Brazil plant are strong as a result of
continued strong demand from Aracruz Celulose, the primary customer in Brazil.
CORPORATE EXPENSES
GENERAL AND ADMINISTRATIVE (G&A)
Three Months Nine Months
Ended September 30 Ended September 30
(Cdn$ millions) 2005 2004 2005 2004
- ------------------------------------------------------------------------------------------------------------------------------
General and Administrative Expense before Stock Based Compensation 82 45 197 137
Stock Based Compensation (1) 260 12 450 110
-----------------------------------------------------
Total General and Administrative Expense 342 57 647 247
=====================================================
Note:
(1) Includes tandem option plan, stock options for our US-based employees and
stock appreciation rights.
HIGHER COSTS DECREASED QUARTERLY INCOME BY $285 MILLION
In 2004, we modified our stock option plan to a tandem plan which gives option
holders the 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. The obligations resulting from these tandem
plans, along with our stock appreciation rights plan are revalued each quarter
based on our current share price and the resulting change is included as stock
based compensation expense. Our share price has more than doubled since the
beginning of the year, adding over $8 billion of shareholder value and creating
a year-to-date expense of $450 million.
Our G&A costs have increased from 2004 as a result of higher employee headcount
with the North Sea acquisition and increases in employee compensation. Higher
insurance costs, increased professional fees and additional director
compensation put further pressure on our costs.
42
INTEREST AND FINANCING COSTS
Three Months Nine Months
Ended September 30 Ended September 30
(Cdn$ millions) 2005 2004 2005 2004
- ------------------------------------------------------------------------------------------------------------------------------
Interest 68 46 209 145
Less: Capitalized Interest (49) (11) (125) (27)
-----------------------------------------------------
Net Interest Expense 19 35 84 118
=====================================================
LOWER NET INTEREST EXPENSE INCREASED QUARTERLY NET INCOME BY $16 MILLION
Our financing costs have increased compared to 2004 as a result of our late-2004
North Sea acquisition. We incurred additional debt to finance a portion of the
acquisition. This higher outstanding debt increased interest expense by $29
million during the quarter and $79 million year to date. However, the stronger
Canadian dollar lowered our US-dollar denominated interest by $7 million during
the quarter and $15 million year to date.
We are capitalizing interest on our major development projects in the North Sea,
Syncrude, Long Lake and Block 51 in Yemen. Capitalized interest increased
primarily from the North Sea Buzzard project and additional spending at Long
Lake. We expect that capitalized interest will continue to increase as we spend
additional capital on these projects prior to their completion in 2006 and 2007.
INCOME TAXES
Three Months Nine Months
Ended September 30 Ended September 30
(Cdn$ millions) 2005 2004 2005 2004
- ------------------------------------------------------------------------------------------------------------------------------
Current 95 73 255 189
Future (227) 37 (270) 52
-----------------------------------------------------
Total Provision for Income Taxes (132) 110 (15) 241
=====================================================
Disclosed as:
Provision for Income Taxes - Continuing Operations 24 98 114 208
Provision for Income Taxes - Discontinued Operations (1) (156) 12 (129) 33
-----------------------------------------------------
Total Provision for Income Taxes (132) 110 (15) 241
=====================================================
Effective Tax Rate (%) (27) 33 (2) 31
-----------------------------------------------------
Note:
(1) See Note 15 to our Unaudited Consolidated Financial Statements.
EFFECTIVE TAX RATE FOR THE QUARTER DECREASES BY 60%
The future tax recovery of $227 million in the third quarter is attributable to
the disposition of our oil and gas producing properties in Canada and the sale
of our chemicals business to Canexus Limited Partnership. As a result of the
dispositions, we revalued our future income tax liabilities for the change in
underlying book and tax values. This revaluation resulted in the reduction of
our future income tax liabilities. In addition, the gains were taxed at lower
capital gains tax rates. Our tax rate for the remainder of the year is expected
to be 33%.
Current income taxes include cash taxes in Yemen of $93 million (2004 - $65
million) for the quarter and $222 million (2004 - $168 million) year to date.
Our current income tax provision also includes cash taxes in Colombia, federal
and state taxes in the US and capital taxes in Canada.
OTHER
Three Months Nine Months
Ended September 30 Ended September 30
(Cdn$ millions) 2005 2004 2005 2004
- ------------------------------------------------------------------------------------------------------------------------------
Gain on Dilution of Interest in Chemicals Business 193 - 193 -
Gain of Disposition of Oil and Gas Assets
included as Discontinued Operations 225 - 225 -
Decrease in Fair Value of Crude Oil Put Options (1) - (184) -
-----------------------------------------------------
43
Following the sale of our chemicals operations to Canexus Limited Partnership,
we recorded a gain on the dilution of our interest from 100% to 61.4% of $193
million. The sale of our Canadian oil and gas properties in Alberta, British
Columbia and Saskatchewan gave rise to a gain on sale of $225 million.
Following our North Sea acquisition late last year, we purchased put options on
60,000 bbls/d of oil production for 2005 and 2006, for $144 million, to ensure
base cash flow over the next two years as we invest in major development
projects. These options create 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 each quarter. While a gain of $56 million was recorded in the
fourth quarter of 2004, a significant increase in forward crude oil prices
during 2005 year to date resulted in an expense of $184 million. The carrying
value of these options at the end of the quarter was $16 million.
LIQUIDITY
CAPITAL STRUCTURE
September 30 December 31
(Cdn$ millions) 2005 2004
- ------------------------------------------------------------------------------
NET DEBT (1)
Bank Debt 167 1,993
Public Senior Notes 2,969 1,813
-----------------------------
Senior Debt 3,136 3,806
Subordinated Debt 534 553
-----------------------------
Total Debt 3,670 4,359
Less: Cash and Cash Equivalents (200) (73)
Less: Margin Deposits (202) -
-----------------------------
3,268 4,286
Non-Cash Working Capital (2) 317 (67)
-----------------------------
TOTAL NET DEBT 3,585 4,219
=============================
SHAREHOLDERS' EQUITY (3) 3,685 2,867
=============================
Notes:
(1) Includes all of our debt and is calculated as long-term debt less net
working capital.
(2) Excludes short-term borrowings.
(3) At September 30, 2005, there were 260,879,092 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.
We have been able to take advantage of strong economic results and successful
asset disposition programs to reduce our debt level and increase our liquidity
since 2004. We have repaid $1.8 billion of bank debt during the year by
refinancing with longer-term debt and by divesting of assets. Earlier in the
year, we issued US$1.04 billion of senior notes with US$250 million maturing in
10 years and US$790 million maturing in 30 years. This new debt increases the
average term to maturity of our debt to 22 years. During the quarter, we
successfully completed the sale of certain Canadian conventional oil and gas
properties for net proceeds of $900 million after closing adjustments. Canexus
raised an additional $301 million of net proceeds in connection with the initial
public offering of our chemicals business in the third quarter. Canexus used the
$301 million of net proceeds and US$167 million of bank debt to purchase our
chemicals business. Funds not used to repay debt will be used to fund future
capital investment.
Our liquidity was also enhanced during the quarter by replacing our existing
$1.7 billion term credit facilities and the US$500 million North Sea development
facility with a new US$2 billion term credit facility available until 2010. We
currently have a shelf prospectus in the US and Canada which allows us to raise
US$1.5 billion of debt or equity.
44
CHANGE IN WORKING CAPITAL
September 30 December 31 Increase/
(Cdn$ millions) 2005 2004 (Decrease)
- ---------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents 200 73 127
Margin Deposits 202 - 202
Accounts Receivable 2,828 2,100 728
Inventories and Supplies 514 351 163
Accounts Payable and Accrued Liabilities (3,663) (2,377) (1,286)
Other 4 (7) 11
-----------------------------------------------
Net Working Capital 85 140 (55)
===============================================
The increase in cash resulted from asset dispositions during the quarter.
Proceeds from asset sales were used to repay debt and fund future capital
investment. During the quarter, we were required to meet margin deposit
requirements relating to certain exchange-traded derivative contracts. At
September 30, 2005, these deposits amounted to US$174 million ($202 million).
Derivative contracts held by our marketing group which settle in less than 12
months are included in both accounts receivable and accounts payable. Higher gas
prices in North America during the quarter increased amounts included in
accounts receivable and accounts payable relating to these contracts.
Inventories and supplies increased primarily from higher gas storage positions
in our marketing group, coupled with the higher cost to purchase gas for storage
and high cost for oil in storage. In addition to the increase in our marketing
payables, other payables have increased since year-end from the increased
current portion of the accrued liability with respect to our stock based
compensation programs. Margin deposits increased which offset the current losses
on the futures positions used by our marketing group to hedge the change in
value of our storage and transportation assets.
NET DEBT
Our net debt levels are directly related to our operating cash flows and our
capital expenditure activities. Changes in net debt are related to:
Nine Months
(Cdn$ millions) Ended September 30
- -------------------------------------------------------------------------------------------------------------
Capital Expenditures 1,923
Cash Flow from Operating Activities (1,675)
-------------------
Excess of Capital Expenditures over Cash Flow 248
Dividends on Common Shares 39
Issue of Common Shares (51)
Net Proceeds from Canexus Initial Public Offering (301)
Foreign Exchange on US-dollar Denominated Debt and Cash (129)
Proceeds on Disposition of Oil and Gas Properties (911)
Increase in Current Obligation Related to Stock Based Compensation 284
Increase in Current Obligation Related to Fixed Price Natural Gas Contracts 63
Costs Related to Divestiture Programs and Debt Issuances 40
Other 84
-------------------
Decrease in Net Debt (634)
===================
OUTLOOK FOR REMAINDER OF 2005
Our original 2005 full year production guidance was for production to average
between 235,000 and 245,000 boe/d before royalties and before asset
dispositions. We expect to remain within this original guidance despite
hurricane-related downtime, unplanned turnaround activity in the North Sea and
our 2005 oil and gas property disposition program. We expect to generate
approximately $2.4 billion in cash flow (before remediation and geological and
geophysical expenditures) in 2005, assuming the following for the remainder of
the year:
- ----------------------------------------------------------------------------
WTI (US$/bbl) 60.00
NYMEX natural gas (US$/mmbtu) 9.00
US to Canadian dollar exchange rate 0.80
--------
45
We have incurred almost $2 billion of our planned capital investment for 2005.
We expect our total capital investment for 2005 to be approximately $2.7
billion. Our 2005 capital program is largely targeted towards our major
development projects in the North Sea, Long Lake, Block 51 in Yemen and
Syncrude. We are also investing in the commercial development of our coal bed
methane project in Alberta, and additional development wells at Masila in Yemen.
Our future liquidity is primarily dependent on cash flows generated from our
operations, our capital requirements and the flexibility of our capital
structure. We are in the midst of developing a number of major projects over the
next two years and our capital requirement to bring them on-stream is
significant. We expect that our cash on hand and future cash flows generated
from operations, especially the significant cash flows we expect to generate
when our Buzzard project comes on-stream in late-2006 will be sufficient to
finance the majority of these known requirements. We also have available undrawn
committed credit facilities which provide us with liquidity to meet future
funding requirements. During the year, we declared common share dividends of
$0.05 per share each quarter.
CONTRACTUAL OBLIGATIONS, COMMITMENTS AND GUARANTEES
We have assumed various contractual obligations and commitments in the normal
course of our operations and financing activities. We have described these
obligations and commitments in our MD&A in our 2004 Annual Report on Form 10-K.
During the nine months ended September 30, 2005, we entered into additional
capital commitments totaling $300 million related to our major development
projects. We expect to incur approximately $290 million of these commitments in
the next twelve months and approximately $10 million in one to three years.
CONTINGENCIES
There are a number of lawsuits and claims pending, the ultimate results of which
cannot be ascertained at this time. 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. These matters are described in LEGAL PROCEEDINGS in Item
3 contained in our 2004 Annual Report on Form 10-K. There have been no
significant developments since year end.
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 held 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.
46
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
September 30, 2005 would have the following impact on our Unaudited Consolidated
Financial Statements:
(Cdn$ millions) Increase/(Decrease)
- ------------------------------------------------------------------------------
Accounts Payable and Accrued Liabilities 121
Future Tax Liability (42)
Shareholders' Equity (79)
--------------------
The AcSB issued Section 3831, NON-MONETARY TRANSACTIONS, which replaces Section
3830 and requires all non-monetary transactions to be measured at fair value
unless:
o the transaction lacks commercial substance;
o the transaction is an exchange of a product or property held for sale in
the ordinary course of business for a product or property to be sold in the
same line of business to facilitate sales to customers other than the
parties to the exchange;
o neither the fair value of the assets or services received nor the fair
value of the assets or services given up is reliably measurable; or
o the transaction is a non-monetary, non-reciprocal transfer to owners that
represents a spin-off or other form of restructuring or liquidation.
The new requirements apply to non-monetary transactions initiated in periods
beginning on or after January 1, 2006. Earlier adoption is permitted as of the
beginning of a period beginning on or after July 1, 2005. We do not expect the
adoption of this section will have any material impact on our results of
operations or financial position.
US PRONOUNCEMENTS
In November 2004, the Financial Accounting Standards Board (FASB) issued
Statement 151, INVENTORY COSTS. This statement amends ARB 43 to clarify that:
o abnormal amounts of idle facility expense, freight, handling costs and
wasted material (spoilage) should be recognized as current-period charges;
and
o requires the allocation of fixed production overhead to inventory based on
the normal capacity of the production facilities.
The provisions of this statement are effective for inventory costs incurred
during fiscal years beginning after June 15, 2005. We do not expect the adoption
of this statement will have any material impact on our results of operations or
financial position.
In December 2004, the FASB issued Statement 123(R), SHARE-BASED PAYMENTS. This
statement revises Statement 123, ACCOUNTING FOR STOCK-BASED COMPENSATION, and
supersedes APB Opinion 25, ACCOUNTING FOR STOCK ISSUED TO EMPLOYEES. Statement
123(R) requires all stock-based awards issued to employees to be measured at
fair value and to be expensed in the income statement. This statement is
effective for fiscal years beginning after June 15, 2005.
We are currently expensing stock-based awards issued to employees using the fair
value method for equity based awards and the intrinsic method for liability
based awards. Adoption of this standard will change our expense under US GAAP
for tandem options and stock appreciation rights as these awards will be
measured using the fair value method rather than the intrinsic method. We are
currently evaluating the provisions of Statement 123(R) and have not yet
determined the full impact this statement will have on our results of operations
or financial position under US GAAP.
In December 2004, the FASB issued Statement 153, EXCHANGES OF NONMONETARY
ASSETS, an amendment of APB Opinion 29, ACCOUNTING FOR NONMONETARY TRANSACTIONS.
This amendment eliminates the exception for nonmonetary exchanges of similar
productive assets and replaces it with a general exception for exchanges of
nonmonetary assets that do not have commercial substance. Under Statement 153,
if a nonmonetary exchange of similar productive assets meets a
commercial-substance test and fair value is determinable, the transaction must
be accounted for at fair value resulting in the recognition of any gain or loss.
This statement is effective for nonmonetary transactions in fiscal periods that
begin after June 15, 2005. We do not expect the adoption of this statement will
have any material impact on our results of operations or financial position.
47
In March 2005, the FASB issued Financial Interpretation 47, ACCOUNTING FOR
CONDITIONAL ASSET RETIREMENT OBLIGATIONS (FIN 47). FIN 47 clarifies that the
term conditional asset retirement obligation as used in FASB Statement No. 143,
ACCOUNTING FOR ASSET RETIREMENT OBLIGATIONS, refers to a legal obligation to
perform an asset retirement activity in which the timing and (or) method of
settlement are conditional on a future event that may or may not be within the
control of the entity. The obligation to perform the asset retirement activity
is unconditional even though uncertainty exists about the timing and (or) method
of settlement. Thus, the timing and (or) method of settlement may be conditional
on a future event. Accordingly, an entity is required to recognize a liability
for the fair value of a conditional asset retirement obligation if the fair
value of the liability can be reasonably estimated. FIN 47 also clarifies when
an entity would have sufficient information to reasonably estimate the fair
value of an asset retirement obligation. FIN 47 is effective no later than the
end of fiscal years ending after December 15, 2005. We do not expect the
adoption of this statement will have a material impact on our results of
operations or financial position.
In March 2005, the Emerging Issues Task Force (EITF) reached a consensus on
Issue No. 04-6, ACCOUNTING FOR STRIPPING COSTS INCURRED DURING PRODUCTION IN THE
MINING INDUSTRY. In the mining industry, companies may be required to remove
overburden and other mine waste materials to access mineral deposits. The EITF
concluded that the costs of removing overburden and waste materials, often
referred to as "stripping costs", incurred during the production phase of a mine
are variable production costs that should be included in the costs of the
inventory produced during the period that the stripping costs are incurred.
Issue No. 04-6 is effective for the first reporting period in fiscal years
beginning after December 15, 2005, with early adoption permitted. We do not
expect the adoption of this statement will have a material impact on our results
of operations or financial position.
In June 2005, the FASB issued Statement 154, ACCOUNTING CHANGES AND ERROR
CORRECTIONS which replaces APB Opinion 20 and FASB Statement 3. Statement 154
changes the requirements for the accounting and reporting of a change in
accounting principle. Opinion 20 previously required that most voluntary changes
in accounting principle be recognized by including the cumulative effect of the
new accounting principle in net income of the period of the change. Statement
154 now requires retrospective application of changes in accounting principle to
prior period financial statements, unless it is impracticable to determine
either the period-specific effects or the cumulative effect of the change. The
Statement is effective for fiscal years beginning after December 15, 2005. We do
not expect the adoption of this statement will have a material impact on our
results of operations or financial position.
EQUITY SECURITY REPURCHASES
During the quarter, we made no purchases of our own equity securities.
SUMMARY OF QUARTERLY RESULTS
Three Months Ended
2003 | 2004 | 2005
--------|------------------------------------|-------------------------
(Cdn$ millions) Dec Mar Jun Sept Dec Mar Jun Sept
-----------------------------------------------------------------------
Net Sales from Continuing Operations 611 664 697 778 805 856 909 1,094
Net Income (Loss) from Continuing Operations (83) (1) 167 117 200 220 19 170 211
Net Income (Loss) from Discontinued Operations (3) 17 26 20 26 18 30 404
-----------------------------------------------------------------------
Net Income (Loss) (86) 184 143 220 246 37 200 615
=======================================================================
Earnings per Common Share from Continuing Operations
($/share)
Basic (0.35) 0.65 0.45 0.77 0.84 0.07 0.65 0.81
Diluted (0.34) 0.64 0.44 0.76 0.83 0.07 0.64 0.79
Earnings per Common Share ($/share)
Basic (0.35) 0.72 0.55 0.85 0.95 0.14 0.77 2.36
Diluted (0.34) 0.71 0.54 0.84 0.94 0.14 0.76 2.30
-----------------------------------------------------------------------
Note:
(1) Includes an impairment charge of $269 million relating to certain Canadian
oil and gas properties.
48
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS
Certain statements in this report, including those appearing in ITEM 2 -
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS, are forward-looking statements.(1) Forward-looking statements are
generally identifiable by terms such as ANTICIPATE, BELIEVE, INTEND, PLAN,
EXPECT, SHOULD, ESTIMATE, BUDGET, OUTLOOK or other similar words, and include
statements relating to future production associated with our Long Lake, North
Sea and West Africa projects.
These statements are subject to known and unknown risks and uncertainties and
other factors which may cause actual results, levels of activity and
achievements to differ materially from those expressed or implied by such
statements. These risks, uncertainties and other factors include:
o market prices for oil, natural gas and chemicals products;
o our ability to produce and transport crude oil and natural gas to markets;
o the results of exploration and development drilling and related activities;
o foreign-currency exchange rates;
o economic conditions in the countries and regions in which we carry on
business;
o governmental actions that increase taxes, change environmental and other
laws and regulations;
o renegotiations of contracts; and
o political uncertainty, including actions by terrorists, insurgent or other
groups, or other armed conflict, including conflict between states.
The above items and their possible impact are discussed more fully in the
section, titled BUSINESS RISK MANAGEMENT in Item 7 and QUANTITATIVE AND
QUALITATIVE DISCLOSURES ABOUT MARKET RISK in Item 7A of our 2004 Annual Report
on Form 10-K.
The impact of any one risk, uncertainty or factor on a particular
forward-looking statement is not determinable with certainty as these are
interdependent and management's future course of action depends upon our
assessment of all information available at that time. Any statements regarding
the following are forward-looking statements:
o future crude oil, natural gas or chemicals prices;
o future production levels;
o future cost recovery oil revenues from our operations in Yemen;
o future capital expenditures and their allocation to exploration and
development activities;
o future asset dispositions;
o future sources of funding for our capital program;
o future debt levels;
o future cash flows and their uses;
o future drilling of new wells;
o ultimate recoverability of reserves;
o future changes to reserves estimates;
o operation, production, reserves and prospects relating to Buzzard, Scott
and Telford fields and other exploration properties acquired pursuant to
our acquisition of EnCana U.K.;
o expected finding and development costs;
o expected operating costs;
o future demand for chemicals products;
o future expenditures and future allowances relating to environmental
matters; and
o dates by which certain areas will be developed or will come on-stream.
We believe that any forward-looking statements made are reasonable based on
information available to us on the date such statements were made. However, no
assurance can be given as to future results, levels of activity and
achievements. We undertake no obligation to update publicly or revise any
forward-looking statements contained in this report. All subsequent
forward-looking statements, whether written or oral, attributable to us or
persons acting on our behalf are expressly qualified in their entirety by these
cautionary statements.
- -------------------
(1) Within the meaning of the United States PRIVATE SECURITIES LITIGATION REFORM
ACT OF 1995, Section 21E of the United States SECURITIES EXCHANGE ACT OF 1934,
as amended, and Section 27A of the United States SECURITIES ACT OF 1933, as
amended.
49
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We are exposed to normal market risks inherent in the oil and gas and chemicals
business, including commodity price risk, foreign-currency rate risk, interest
rate risk and credit risk. We recognize these risks and manage our operations to
minimize our exposures to the extent practical. The information presented on
market risks on pages 68 - 70 in our 2004 Annual Report on Form 10-K has not
changed materially since December 31, 2004.
ITEM 4. CONTROLS AND PROCEDURES
EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES
Our Chief Executive Officer and Chief Financial Officer have evaluated the
effectiveness of our disclosure controls and procedures (as defined in Exchange
Act Rules 13a-15(e) and 15-d-15(e)) as of the end of the period covered by this
report. They concluded that, as of the end of the period covered by this report,
our disclosure controls and procedures were adequate and effective in ensuring
that material information relating to the Company and its consolidated
subsidiaries would be made known to them by others within those entities,
particularly during the period in which this report was being prepared.
Management recognizes that any controls and procedures, no matter how well
designed and operated, can provide only reasonable assurance of achieving the
desired control objectives, and in reaching a reasonable level of assurance,
management necessarily is required to apply its judgment in evaluating the
cost-benefit relationship of possible controls and procedures.
CHANGES IN INTERNAL CONTROLS
We have continually had in place systems relating to internal control over
financial reporting. During 2005, we continued to improve and enhance our
financial reporting systems with the implementation of our existing Systems,
Applications and Products in Data Processing (SAP) systems into our chemicals
operations. The conversion of data and the implementation and operation of SAP
has been continually monitored and reviewed. We have evaluated these changes and
confirm that there has not been any change in the Company's internal control
over financial reporting during the third quarter of 2005 that has materially
affected, or is reasonably likely to materially affect, the Company's internal
control over financial reporting. As well, based on these evaluations, there
were no material weaknesses in these internal controls requiring corrective
action. As a result, no such corrective actions were taken.
50
PART II
ITEM 6. EXHIBITS
- ------- --------
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.
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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 October 17, 2005.
NEXEN INC.
/s/ Charles w. Fischer
---------------------------------
Charles W. Fischer
President and Chief Executive Officer
(Principal Executive Officer)
/s/ Michael J. Harris
---------------------------------
Michael J. Harris
Controller
(Principal Accounting Officer)
52