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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, 2004
|_| 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 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 Act).
Yes [X] No [_]
On September 30, 2004, there were 129,018,817 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......................................25
Item 3. Quantitative and Qualitative Disclosures about Market Risk.....43
Item 4. Controls and Procedures........................................43
PART II OTHER INFORMATION
Item 4. Submission of Matters to a Vote of Security Holders............44
Item 6. Exhibits and Reports on Form 8-K...............................44
This report should be read in conjunction with our 2003 Annual Report on Form
10-K and with our current reports on Form 8-K filed or furnished on February 5,
February 13, February 23, May 4 and July 15, 2004.
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 2003, 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
60 of our 2003 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.
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
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, 2004, the noon-day exchange rate for Cdn$1.00 was US$0.7912 as
reported by the Bank of Canada.
2
PART I
ITEM 1. UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
TABLE OF CONTENTS
Unaudited Consolidated Statement of Income
for the Three and Nine Months Ended September 30, 2004 and 2003................4
Unaudited Consolidated Balance Sheet
as at September 30, 2004 and December 31, 2003.................................5
Unaudited Consolidated Statement of Cash Flows
for the Three and Nine Months Ended September 30, 2004 and 2003................6
Unaudited Consolidated Statement of Shareholders' Equity
for the Nine Months Ended September 30, 2004 and 2003..........................7
Notes to Unaudited Consolidated Financial Statements...........................8
3
NEXEN INC.
UNAUDITED CONSOLIDATED STATEMENT OF INCOME
FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30
Cdn$ millions, except per share amounts
THREE MONTHS NINE MONTHS
ENDED SEPTEMBER 30 ENDED SEPTEMBER 30
2004 2003 2004 2003
- -----------------------------------------------------------------------------------------------------------------
Restated Restated
for for
Change in Change in
Accounting Accounting
Principles Principles
Note 1 Note 1
REVENUES
Net Sales 837 716 2,359 2,248
Marketing and Other (Note 9) 147 131 439 451
-----------------------------------------------
984 847 2,798 2,699
-----------------------------------------------
EXPENSES
Operating 205 184 596 570
Transportation and Other 122 107 389 357
General and Administrative (Note 6) 57 44 247 126
Depreciation, Depletion and Amortization (Note 1) 181 190 541 566
Exploration 54 30 108 109
Interest (Note 4) 35 23 115 76
-----------------------------------------------
654 578 1,996 1,804
-----------------------------------------------
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES 330 269 802 895
-----------------------------------------------
PROVISION FOR INCOME TAXES
Current 73 60 189 164
Future 37 31 58 51
-----------------------------------------------
110 91 247 215
-----------------------------------------------
NET INCOME FROM CONTINUING OPERATIONS 220 178 555 680
Net Income from Discontinued Operations (Note 10) -- 3 -- 15
-----------------------------------------------
NET INCOME 220 181 555 695
Dividends on Preferred Securities, Net of Income Taxes -- 10 2 31
-----------------------------------------------
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS 220 171 553 664
===============================================
EARNINGS PER COMMON SHARE FROM CONTINUING OPERATIONS ($/share)
Basic (Note 7) 1.70 1.36 4.31 5.26
===============================================
Diluted (Note 7) 1.69 1.35 4.25 5.22
===============================================
EARNINGS PER COMMON SHARE ($/share)
Basic (Note 7) 1.70 1.38 4.31 5.38
===============================================
Diluted (Note 7) 1.69 1.37 4.25 5.34
===============================================
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
2004 2003
- ---------------------------------------------------------------------------------------------------
Restated for
Change in
Accounting
Principles
Note 1
ASSETS
CURRENT ASSETS
Cash and Short-Term Investments 866 1,087
Accounts Receivable (Note 2) 1,549 1,423
Inventories and Supplies (Note 3) 400 270
Other 42 79
------------------------------
Total Current Assets 2,857 2,859
------------------------------
PROPERTY, PLANT AND EQUIPMENT (Note 1)
Net of Accumulated Depreciation, Depletion and
Amortization of $5,310 (December 31, 2003 - $4,907) 4,950 4,550
GOODWILL 36 36
FUTURE INCOME TAX ASSETS 88 108
DEFERRED CHARGES AND OTHER ASSETS 192 153
------------------------------
8,123 7,706
==============================
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Current Portion of Long-Term Debt (Note 4) -- 291
Accounts Payable and Accrued Liabilities 1,768 1,404
Accrued Interest Payable 37 44
Dividends Payable 13 12
------------------------------
Total Current Liabilities 1,818 1,751
------------------------------
LONG-TERM DEBT (Note 4) 2,438 2,485
FUTURE INCOME TAX LIABILITIES (Note 1) 752 707
ASSET RETIREMENT OBLIGATIONS (Note 1) 309 305
DEFERRED CREDITS AND LIABILITIES 113 68
SHAREHOLDERS' EQUITY (Note 6)
Preferred and Subordinated Securities 33 364
Common Shares, no par value
Authorized: Unlimited
Outstanding: 2004 - 129,018,817 shares
2003 - 125,606,107 shares 629 513
Contributed Surplus -- 1
Retained Earnings (Note 1) 2,179 1,631
Cumulative Foreign Currency Translation Adjustment (148) (119)
------------------------------
Total Shareholders' Equity 2,693 2,390
------------------------------
COMMITMENTS AND CONTINGENCIES (Note 11)
8,123 7,706
==============================
SEE ACCOMPANYING NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS.
5
NEXEN INC.
UNAUDITED CONSOLIDATED STATEMENT OF CASH FLOWS
FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30
Cdn$ millions
THREE MONTHS NINE MONTHS
ENDED SEPTEMBER 30 ENDED SEPTEMBER 30
2004 2003 2004 2003
- ---------------------------------------------------------------------------------------------------------------
Restated for Restated for
Change in Change in
Accounting Accounting
Principles Principles
Note 1 Note 1
OPERATING ACTIVITIES
Net Income from Continuing Operations 220 178 555 680
Net Income from Discontinued Operations -- 3 -- 15
Charges and Credits to Income not Involving Cash (Note 8) 234 223 690 645
Exploration Expense 54 30 108 109
Changes in Non-Cash Working Capital (Note 8) (55) (125) (99) (165)
Other (35) (13) 19 (42)
----------------------------------------------
418 296 1,273 1,242
FINANCING ACTIVITIES
Proceeds from (Repayment of) Term Credit Facilities, Net -- (9) -- 91
Repayment of Long-Term Debt (Note 4) -- -- (300) --
Proceeds from (Repayment of) Short-Term Borrowings, Net -- (19) -- (18)
Redemption of Preferred Securities (Note 6) -- -- (289) --
Dividends on Preferred Securities -- (16) (3) (50)
Dividends on Common Shares (13) (9) (39) (27)
Issue of Common Shares 7 21 116 31
----------------------------------------------
(6) (32) (515) 27
INVESTING ACTIVITIES
Capital Expenditures
Exploration and Development (362) (277) (1,017) (911)
Proved Property Acquisitions -- -- -- (164)
Chemicals, Corporate and Other (33) (9) (69) (22)
Proceeds on Disposition of Assets 6 268 10 268
Changes in Non-Cash Working Capital (Note 8) 45 15 107 (16)
Other (6) -- (20) --
----------------------------------------------
(350) (3) (989) (845)
EFFECT OF EXCHANGE RATE CHANGES ON CASH
AND SHORT-TERM INVESTMENTS (35) 1 10 (129)
----------------------------------------------
INCREASE (DECREASE) IN CASH AND SHORT-TERM INVESTMENTS 27 262 (221) 295
CASH AND SHORT-TERM INVESTMENTS - BEGINNING OF PERIOD 839 92 1,087 59
----------------------------------------------
CASH AND SHORT-TERM INVESTMENTS - END OF PERIOD 866 354 866 354
==============================================
SEE ACCOMPANYING NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS.
6
NEXEN INC.
UNAUDITED CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2004 AND SEPTEMBER 30, 2003
Cdn$ millions
CUMULATIVE
PREFERRED FOREIGN
AND CURRENCY
SUBORDINATED COMMON CONTRIBUTED RETAINED TRANSLATION
SECURITIES SHARES SURPLUS EARNINGS ADJUSTMENT
- ---------------------------------------------------------------------------------------------------------------------------------
Restated for
Change in
Accounting
Principles
Note 1
DECEMBER 31, 2003 364 513 1 1,659 (119)
Retroactive Adjustment for Change in
Accounting Principles (Note 1) -- -- -- (28) --
Exercise of Stock Options -- 90 -- -- --
Issue of Common Shares -- 26 -- -- --
Redemption of Preferred Securities (Note 6) (331) -- -- -- --
Gain on Redemption of Preferred Securities,
Net of Income Taxes (Note 6) -- -- -- 34 --
Net Income -- -- -- 555 --
Dividends on Preferred Securities,
Net of Income Taxes -- -- -- (2) --
Dividends on Common Shares -- -- -- (39) --
Stock Option Expense prior to
Modification to Tandem Options -- -- 2 -- --
Modification of Stock Options
to Tandem Options (Note 6) -- -- (3) -- --
Translation Adjustment,
Net of Income Taxes -- -- -- -- (29)
-----------------------------------------------------------------------------
SEPTEMBER 30, 2004 33 629 -- 2,179 (148)
=============================================================================
DECEMBER 31, 2002 724 440 -- 1,069 115
Retroactive Adjustment for Change in
Accounting Principles (Note 1) -- -- -- (28) --
Exercise of Stock Options -- 12 -- -- --
Issue of Common Shares -- 19 -- -- --
Net Income -- -- -- 695 --
Dividends on Preferred Securities,
Net of Income Taxes -- -- -- (31) --
Dividends on Common Shares -- -- -- (27) --
Translation Adjustment,
Net of Income Taxes -- -- -- -- (180)
-----------------------------------------------------------------------------
SEPTEMBER 30, 2003 724 471 -- 1,678 (65)
=============================================================================
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 14. 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, 2004 and the
results of our operations and our cash flows for the three and nine months ended
September 30, 2004 and 2003.
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 months and nine months ended September 30, 2004 are not necessarily
indicative of the results of operations or cash flows to be expected for the
year ending December 31, 2004.
These Unaudited Consolidated Financial Statements should be read in conjunction
with our Audited Consolidated Financial Statements included in our 2003 Annual
Report on Form 10-K. Except as described below, the accounting policies we
follow are described in Note 1 of the Audited Consolidated Financial Statements
included in our 2003 Annual Report on Form 10-K.
CHANGE IN ACCOUNTING PRINCIPLES
ASSET RETIREMENT OBLIGATIONS
On January 1, 2004, we retroactively adopted the Canadian Institute of Chartered
Accountants standard S.3110, ASSET RETIREMENT OBLIGATIONS. This new standard
requires recognition of a liability for the future retirement obligations
associated with our property, plant and equipment, which includes oil and gas
wells and facilities, and chemicals plants. The asset retirement obligation is
initially measured at fair value and capitalized to property, plant and
equipment as an asset retirement cost. The asset retirement obligation accretes
until the time the retirement obligation is expected to settle while the asset
retirement cost is amortized over the useful life of the underlying property,
plant and equipment.
The amortization of the asset retirement cost and the accretion of the asset
retirement obligation are included in depreciation, depletion and amortization
(DD&A). Actual retirement costs are recorded against the obligation when
incurred. Any difference between the recorded asset retirement obligation and
the actual retirement costs incurred is recorded as a gain or loss in the period
of settlement.
Our total estimated undiscounted asset retirement obligations amount to $512
million ($514 million - December 31, 2003). We have discounted the total
estimated asset retirement obligations using a weighted-average, credit-adjusted
risk-free rate of 5.6%. Approximately $68 million included in our asset
retirement obligations will be settled over the next five years. The remaining
obligations settle beyond five years and will be funded by future cash flows
from our operations.
We own interests in assets for which the fair value of the asset retirement
obligation cannot be reasonably determined because the assets currently have an
indeterminate life. These assets include our interest in a gas plant and our
interest in Syncrude's upgrader and sulphur pile. The asset retirement
obligation for these assets will be recorded in the first year in which the
lives of the assets are determinable.
8
We previously provided for dismantlement and site restoration costs on our oil
and gas wells and facilities, and chemicals plants based on estimates
established by current legislation and industry practices. We recorded a
provision for these costs in DD&A based on proved reserves or estimated
remaining asset lives. Upon adoption of the new standard, accounting rules
require us to restate all prior periods presented to give effect to the change
in accounting principles. The impact on net income for the three and nine months
ended September 30, 2003 and the impact on our Audited Consolidated Balance
Sheet at December 31, 2003, is shown below:
UNAUDITED CONSOLIDATED STATEMENT OF INCOME FOR THE THREE AND NINE MONTHS ENDED
SEPTEMBER 30, 2003
THREE MONTHS NINE MONTHS
- ----------------------------------------------------------------------------------------------------------
Depletion, Depreciation and Amortization as Reported 190 566
Less: Dismantlement and Site Restoration (13) (30)
Plus: Asset Retirement Cost Amortization 6 14
Plus: Asset Retirement Obligation Accretion 7 16
--------------------------------
Depletion, Depreciation and Amortization as Restated 190 566
================================
CONSOLIDATED BALANCE SHEET AS AT DECEMBER 31, 2003
AS REPORTED CHANGE AS RESTATED
- ----------------------------------------------------------------------------------------------------------
Property, Plant and Equipment 4,469 81 4,550
Asset Retirement Obligations - 305 305
Dismantlement and Site Restoration 179 (179) --
Future Income Tax Liabilities 724 (17) 707
Retained Earnings 1,659 (28) 1,631
---------------------------------------------
RECLASSIFICATION
Certain comparative figures have been reclassified to ensure consistency with
current year presentation.
2. ACCOUNTS RECEIVABLE
SEPTEMBER 30 DECEMBER 31
2004 2003
- ----------------------------------------------------------------------------------------- ----------------
Trade
Marketing 1,169 1,078
Oil and Gas 289 263
Chemicals and Other 54 47
------------------------------
1,512 1,388
Non-Trade 53 50
------------------------------
1,565 1,438
Allowance for Doubtful Accounts (16) (15)
------------------------------
1,549 1,423
==============================
3. INVENTORIES AND SUPPLIES
SEPTEMBER 30 DECEMBER 31
2004 2003
- ----------------------------------------------------------------------------------------------------------
Finished Products
Marketing 235 138
Oil and Gas 17 16
Chemicals and Other 5 12
------------------------------
257 166
Work in Process 4 6
Field Supplies 139 98
------------------------------
400 270
==============================
9
4. LONG-TERM DEBT AND SHORT-TERM BORROWINGS
SEPTEMBER 30 DECEMBER 31
2004 2003
- ----------------------------------------------------------------------------------------------------------
Unsecured Syndicated Term Credit Facilities -- --
Unsecured Redeemable Notes, due 2004 (a) -- 291
Unsecured Redeemable Debentures, due 2006(1) 96 98
Unsecured Redeemable Medium-Term Notes, due 2007 150 150
Unsecured Redeemable Medium-Term Notes, due 2008 125 125
Unsecured Redeemable Notes, due 2013 (US$500 million) 632 646
Unsecured Redeemable Notes, due 2028 (US$200 million) 253 258
Unsecured Redeemable Notes, due 2032 (US$500 million) 632 646
Unsecured Subordinated Debentures, due 2043 (US$435 million) 550 562
------------------------------
2,438 2,776
Less: Current Portion of Long-Term Debt -- (291)
------------------------------
2,438 2,485
==============================
Note:
1 Includes $50 million of principal that was effectively converted through a
currency exchange contract to US$37 million.
(a) UNSECURED REDEEMABLE NOTES, DUE 2004
In February 2004, our US$225 million of notes matured and we repaid the
principal at par.
(b) INTEREST EXPENSE
THREE MONTHS NINE MONTHS
ENDED SEPTEMBER 30 ENDED SEPTEMBER 30
2004 2003 2004 2003
- --------------------------------------------------------------------------------------------------------
Long-Term Debt 43 32 133 100
Other 3 3 9 7
-----------------------------------------------
Total 46 35 142 107
Less: Capitalized (11) (12) (27) (31)
-----------------------------------------------
35 23 115 76
===============================================
Capitalized interest relates to and is included as part of the cost of our oil
and gas property, plant and equipment. The capitalization rates are based on our
weighted-average cost of borrowings.
10
5. DERIVATIVE INSTRUMENTS AND FINANCIAL RISK MANAGEMENT
(a) CARRYING VALUE AND ESTIMATED FAIR VALUE OF DERIVATIVE INSTRUMENTS
The carrying value, fair value, and unrecognized gains or losses on our
outstanding derivatives and long-term financial assets and liabilities are:
Cdn$ millions SEPTEMBER 30, 2004 DECEMBER 31, 2003
- ----------------------------------------------------------------------------------------------------------------------------
Carrying Fair Unrecognized Carrying Fair Unrecognized
Net Assets/(Liabilities) Value Value Gain/(Loss) Value Value Gain/(Loss)
------------------------------------ -----------------------------------
Commodity Price Risk -
Non-Trading Activities
Future Sale of Oil and Gas
Production -- -- -- -- (3) (3)
Commodity Price Risk -
Trading Activities
Crude Oil and Natural Gas 112 112 -- 101 101 --
Future Sale of Gas Inventory -- (28) (28) -- (11) (11)
Foreign Currency Risk 5 5 -- 5 4 (1)
------------------------------------ -----------------------------------
Total Derivatives 117 89 (28) 106 91 (15)
==================================== ===================================
Financial Assets and Liabilities
Long-Term Debt (2,438) (2,679) (241) (2,776) (2,997) (221)
Preferred and Subordinated
Securities (33) (34) (1) (364) (319) 45
------------------------------------ -----------------------------------
(2,471) (2,713) (242) (3,140) (3,316) (176)
==================================== ===================================
The estimated fair value of all derivative instruments is based on quoted market
prices and, if not available, on estimates from third-party brokers or dealers.
The carrying value of cash and short-term investments, amounts receivable and
short-term obligations approximates their fair value because the instruments are
near maturity.
(b) COMMODITY PRICE RISK MANAGEMENT
NON-TRADING ACTIVITIES
FUTURE SALE OF OIL AND GAS PRODUCTION
In March 2003, we sold WTI and NYMEX gas forward contracts for the following 12
months to lock-in part of the return on the remaining 40% interest acquired in
the Aspen field. The forward contracts fixed our oil and gas prices on the
future sales at the contract prices for the hedged volumes, less applicable
price differentials. These contracts expired in March 2004.
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 $112 million fair value of the contracts has been
recognized in net income.
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.
To maximize flexibility, we have not designated all of these futures contracts
and swaps as accounting hedges. The gains and losses on these undesignated
futures contracts and swaps have been recognized in income.
We carry our marketing inventory in storage at the lower of cost and net
realizable value, while our derivative contracts are stated at fair value. In
the second and third quarters of 2004, the fair value of our storage positions
increased while the fair value of the corresponding futures contracts decreased.
Losses on our undesignated futures contracts have been recognized in net income.
The related increase in fair value of our inventory ($41 million at September
30, 2004) will not be recognized in net income until the inventory in storage is
sold.
11
FUTURE SALE OF GAS INVENTORY
We have certain NYMEX futures contracts and swaps in place, which effectively
lock-in our margins on the future sale of our natural gas inventory in storage.
We have designated, in writing, some of these derivative contracts as accounting
cash flow hedges of the future sale of our storage inventory. As a result, gains
and losses on these designated futures contracts and swaps are recognized in net
income when the inventory in storage is sold. The principal terms of these
outstanding contracts and the unrecognized gains and losses at September 30,
2004 are:
HEDGED AVERAGE UNRECOGNIZED
VOLUMES MONTH PRICE GAIN/(LOSS)
- ---------------------------------------------------------------------------------------------------
(mmcf) (US$/mcf) (Cdn$ millions)
NYMEX Natural Gas Futures 3,500 December 2004 6.71 (4)
5,740 January 2005 6.82 (9)
6,000 February 2005 6.56 (11)
NYMEX Natural Gas Fixed Price Swaps 1,000 December 2004 7.01 (1)
2,200 January 2005 7.15 (2)
500 February 2005 7.09 (1)
---------------
---------------
(28)
===============
(c) FOREIGN CURRENCY EXCHANGE RATE RISK
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. We enter into forward contracts to sell US dollars.
When combined with certain commodity sales contracts, either physical or
financial, these forward contracts allow us to lock-in our margins on the future
sale of crude oil and natural gas. The fair value of our US dollar forward
contracts at September 30, 2004 was $5 million. This fair value has been
recognized in net income and settles within one year.
(d) TOTAL CARRYING VALUE OF DERIVATIVE CONTRACTS
Amounts related to derivative contracts held by our marketing group that have
not been designated as accounting hedges have been recorded at fair value as we
use mark-to-market accounting. The amounts are as follows:
SEPTEMBER 30 DECEMBER 31
Cdn$ millions 2004 2003
- --------------------------------------------------------------------------------------------------
Accounts Receivable 168 102
Deferred Charges and Other Assets(1) 93 63
------------------------------
Total Derivative Contract Assets 261 165
==============================
Accounts Payable and Accrued Liabilities 106 34
Deferred Credits and Liabilities(1) 38 25
------------------------------
Total Derivative Contract Liabilities 144 59
==============================
Total Derivative Contract Net Assets 117 106
==============================
Note:
1 These derivative contracts settle beyond 12 months and are considered
non-current.
6. SHAREHOLDERS' EQUITY
(a) PREFERRED SECURITIES
In February 2004, we redeemed our US$217 million preferred securities at par.
The realized foreign exchange gain of $34 million, net of income taxes, for the
difference between the carrying value and the settlement amount was included in
retained earnings.
(b) STOCK BASED COMPENSATION
In May 2004, our shareholders approved modifications to our stock option plan to
include a cash feature (tandem option plan). The tandem options give the holders
a right to either purchase common shares at the exercise price or to receive
cash payments equal to the excess of the market value of the common shares over
the exercise price.
Similar to our stock appreciation rights, we use the intrinsic-value method to
recognize compensation expense associated with our tandem options. Obligations
are accrued on a graded vesting basis and represent the difference between the
market value of our common shares and the exercise price of the options. The
obligations are revalued each reporting period based on the change in the market
value of our common shares and the number of options outstanding.
12
Upon modification of the stock option plan, we were required to recognize an
obligation for our tandem options. This obligation represented the difference
between the market value of our common shares and the weighted-average exercise
price of the options. As a result, we recognized an obligation of $85 million
for the graded vested portion of the 6.3 million outstanding options on June 30,
2004. In the second quarter, a one-time, non-cash charge of $82 million ($54
million, net of tax) was included in general and administrative expense, net of
$3 million previously expensed in respect of our original stock options.
(c) DIVIDENDS
Dividends per common share for the three months ended September 30, 2004 were
$0.10 (2003 - $0.075). Dividends per common share for the nine months ended
September 30, 2004 were $0.30 (2003 - $0.225).
7. EARNINGS PER COMMON SHARE
We calculate basic earnings per common share from continuing operations using
net income from continuing operations less dividends on preferred securities,
net of income taxes, divided by the weighted-average number of common shares
outstanding. We calculate basic earnings per common share using net income
attributable to common shareholders 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) 2004 2003 2004 2003
- --------------------------------------------------------------------------------------------------------------
Weighted-average number of common shares outstanding 129.0 123.8 128.4 123.4
Shares issuable pursuant to stock options 6.3 8.9 6.7 5.1
Shares to be purchased from proceeds of stock options (4.9) (7.4) (5.0) (4.1)
-------------------------------------------
Weighted-average number of diluted common shares outstanding 130.4 125.3 130.1 124.4
===========================================
In calculating the weighted-average number of diluted common shares outstanding
for the three and nine months ended September 30, 2004, all options were
included because their exercise price was less than the quarterly average common
share market price in the period. For the three months ended September 30, 2003,
we excluded 36,000 options, and for the nine months ended September 30, 2003, we
excluded 4.2 million options, because their exercise price was greater than the
average common share market price during those periods. During the periods
presented, outstanding stock options were the only potential dilutive
instruments.
8. CASH FLOWS
(a) CHARGES AND CREDITS TO INCOME NOT INVOLVING CASH
THREE MONTHS NINE MONTHS
ENDED SEPTEMBER 30 ENDED SEPTEMBER 30
2004 2003 2004 2003
- --------------------------------------------------------------------------------------------------------------
Depreciation, Depletion and Amortization 181 190 541 566
Stock Based Compensation 11 2 100 4
Gain on Disposition of Assets (4) -- (4) --
Future Income Taxes 37 31 58 51
Non-Cash Items included in Discontinued Operations -- 7 -- 35
Other 9 (7) (5) (11)
-------------------------------------------
234 223 690 645
===========================================
13
(b) CHANGES IN NON-CASH WORKING CAPITAL
THREE MONTHS NINE MONTHS
ENDED SEPTEMBER 30 ENDED SEPTEMBER 30
2004 2003 2004 2003
- -----------------------------------------------------------------------------------------------------------
Operating Activities
Accounts Receivable 17 55 (134) (33)
Inventories and Supplies (68) (1) (145) 15
Other Current Assets (18) (25) 37 (23)
Accounts Payable and Accrued Liabilities 14 (142) 152 (110)
Accrued Interest Payable -- (12) (9) (14)
-----------------------------------------------
(55) (125) (99) (165)
Investing Activities
Accounts Payable and Accrued Liabilities 45 15 107 (16)
-----------------------------------------------
Total (10) (110) 8 (181)
===============================================
(c) OTHER CASH FLOW INFORMATION
THREE MONTHS NINE MONTHS
ENDED SEPTEMBER 30 ENDED SEPTEMBER 30
2004 2003 2004 2003
- -----------------------------------------------------------------------------------------------------------
Interest Paid 41 45 140 117
Income Taxes Paid 67 48 182 155
-----------------------------------------------
9. MARKETING AND OTHER
THREE MONTHS NINE MONTHS
ENDED SEPTEMBER 30 ENDED SEPTEMBER 30
2004 2003 2004 2003
- -----------------------------------------------------------------------------------------------------------
Marketing Revenue, Net 144 121 403 416
Interest 3 2 8 6
Foreign Exchange Gains/(Losses) (9) 4 6 8
Other(1) 5 4 18 21
Gain on Disposition of Assets(2) 4 -- 4 --
-----------------------------------------------
147 131 439 451
===============================================
Notes:
1 Other income for the three months and nine months ended September 30, 2004
includes $2 million (2003 - $nil) and $9 million (2003 - $12 million),
respectively of business interruption proceeds from our insurers. The
proceeds result from damage sustained in the Gulf of Mexico during tropical
storm Isidore and hurricane Lili in the third and fourth quarters of 2002.
2 Gain on disposition resulted from the sale of minor oil and gas properties.
14
10. DISCONTINUED OPERATIONS
On August 28, 2003, we sold certain non-core conventional light oil properties
in southeast Saskatchewan in Canada. Net proceeds were $268 million and there
was no gain or loss on the sale. The results of operations from these properties
are detailed below and shown as discontinued operations in our Unaudited
Consolidated Statement of Income.
THREE MONTHS NINE MONTHS
ENDED SEPTEMBER 30 ENDED SEPTEMBER 30
2004 2003 2004 2003
- ----------------------------------------------------------------------------------------------------------
Revenues
Net Sales -- 14 -- 66
Expenses
Operating -- 4 -- 16
Depreciation, Depletion and Amortization -- 3 -- 20
Exploration -- -- -- 1
----------------------------------------------
Income before Income Taxes -- 7 -- 29
Future Income Taxes -- 4 -- 14
----------------------------------------------
Net Income from Discontinued Operations -- 3 -- 15
==============================================
Earnings Per Common Share ($/share)
Basic (Note 7) -- 0.02 -- 0.12
==============================================
Diluted (Note 7) -- 0.02 -- 0.12
==============================================
11. COMMITMENTS AND CONTINGENCIES
As described in Note 10 to the Audited Consolidated Financial Statements
included in our 2003 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.
12. 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
2004 2003 2004 2003
- ----------------------------------------------------------------------------------------------------------
Nexen
Cost of Benefits Earned by Employees 2 2 6 6
Interest Cost on Benefits Earned 3 3 9 9
Expected Return on Plan Assets (3) (2) (9) (6)
Net Amortization and Deferral -- -- -- --
----------------------------------------------
2 3 6 9
----------------------------------------------
Syncrude
Cost of Benefits Earned by Employees 1 1 3 3
Interest Cost on Benefits Earned 1 1 3 3
Expected Return on Plan Assets (1) (1) (3) (3)
Net Amortization and Deferral -- -- -- --
----------------------------------------------
1 1 3 3
----------------------------------------------
Total 3 4 9 12
==============================================
(b) EMPLOYER FUNDING CONTRIBUTIONS
Our expected total funding contributions for 2004 disclosed in Note 11(e) to the
Audited Consolidated Financial Statements in our 2003 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.
15
13. 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 15 to the Audited
Consolidated Financial Statements included in our 2003 Annual Report on Form
10-K.
THREE MONTHS ENDED SEPTEMBER 30, 2004
Corporate
and
(Cdn$ millions) Oil and Gas Syncrude(1) Chemicals Other Total
- -----------------------------------------------------------------------------------------------------------------------------------
United Other
Yemen Canada States Australia(2) Countries(3) Marketing(4)
--------------------------------------------------------------
Net Sales 247 160 219 -- 19 4 90 98 -- 837
Marketing and Other 1 4(5) 3 -- -- 144 -- 1 (6)(6) 147
-----------------------------------------------------------------------------------------------------
Total Revenues 248 164 222 -- 19 148 90 99 (6) 984
Less: Expenses
Operating 27 39 39 -- 3 4 31 62 -- 205
Transportation and Other -- 4 -- -- -- 106 3 9 -- 122
General and Administrative -- 6 4 -- 10 13 -- 8 16 57
Depreciation, Depletion and
Amortization 39 49 68 -- 5 3 4 9 4 181
Exploration 1 4 38 -- 11(7) -- -- -- -- 54
Interest -- -- -- -- -- -- -- -- 35 35
-----------------------------------------------------------------------------------------------------
Income (Loss) from
Continuing Operations
before Income Taxes 181 62 73 -- (10) 22 52 11 (61) 330
=====================================================================================================
Less: Provision for Income
Taxes(8) 110
Add: Net Income from
Discontinued Operations --
------
Net Income 220
======
Identifiable Assets 619 1,793 1,652 40 214 1,666(9) 857 497 785(10) 8,123
=====================================================================================================
Capital Expenditures
Development and Other 71 120 40 -- 29 1 57 25 7 350
Exploration 4 8 25 -- 8 -- -- -- -- 45
-----------------------------------------------------------------------------------------------------
75 128 65 -- 37 1 57 25 7 395
=====================================================================================================
Property, Plant and Equipment
Cost 2,032 3,235 2,304 198 362 155 972 814 188 10,260
Less: Accumulated DD&A 1,581 1,576 1,027 198 225 61 152 404 86 5,310
-----------------------------------------------------------------------------------------------------
Net Book Value 451 1,659 1,277 -- 137 94 820 410 102 4,950
=====================================================================================================
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 There were no crude oil liftings in Australia during the third quarter.
3 Includes results of operations from producing activities in Nigeria and
Colombia.
4 We are required to carry our gas inventory at the lower of cost or net
realizable value. At September 30, 2004, we have unrecognized gains on this
inventory of $41 million as discussed in Note 5.
5 Includes a $4 million gain on disposition resulting from the sale of minor
oil and gas properties.
6 Includes interest income of $3 million and foreign exchange losses of $9
million.
7 Includes exploration activities primarily in Nigeria and Colombia.
8 Includes Yemen cash taxes of $65 million.
9 Approximately 84% of Marketing's identifiable assets are accounts receivable
and inventories.
10 Approximately 73% of Corporate and Other's identifiable assets are cash and
short-term instruments.
16
NINE MONTHS ENDED SEPTEMBER 30, 2004
Corporate
and
(Cdn$ millions) Oil and Gas Syncrude(1) Chemicals Other Total
- -----------------------------------------------------------------------------------------------------------------------------------
United Other
Yemen Canada States Australia Countries(2) Marketing(3)
------------------------------------------------------------
Net Sales 679 461 581 49 53 10 243 283 -- 2,359
Marketing and Other 3 6(4) 10 -- -- 403 -- 3 14(5) 439
-----------------------------------------------------------------------------------------------------
Total Revenues 682 467 591 49 53 413 243 286 14 2,798
Less: Expenses
Operating 80 118 81 31 6 12 90 178 -- 596
Transportation and Other 2 10 -- -- -- 338 8 28 3 389
General and Administrative(6) 2 41 28 -- 39 38 -- 25 74 247
Depreciation, Depletion and
Amortization 123 148 185 9 14 8 13 28 13 541
Exploration 2 13 53 -- 40(7) -- -- -- -- 108
Interest -- -- -- -- -- -- -- -- 115 115
-----------------------------------------------------------------------------------------------------
Income (Loss) from
Continuing Operations
before Income Taxes 473 137 244 9 (46) 17 132 27 (191) 802
=====================================================================================================
Less: Provision for Income
Taxes(8) 247
Add: Net Income from
Discontinued Operations --
------
Net Income 555
======
Identifiable Assets 619 1,793 1,652 40 214 1,666(9) 857 497 785(10) 8,123
=====================================================================================================
Capital Expenditures
Development and Other 176 307 199 -- 44 3 155 47 19 950
Exploration 9 20 74 -- 33 -- -- -- -- 136
-----------------------------------------------------------------------------------------------------
185 327 273 -- 77 3 155 47 19 1,086
=====================================================================================================
Property, Plant and Equipment
Cost 2,032 3,235 2,304 198 362 155 972 814 188 10,260
Less: Accumulated DD&A 1,581 1,576 1,027 198 225 61 152 404 86 5,310
-----------------------------------------------------------------------------------------------------
Net Book Value 451 1,659 1,277 -- 137 94 820 410 102 4,950
=====================================================================================================
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 We are required to carry our gas inventory at the lower of cost or net
realizable value. At September 30, 2004, we have unrecognized gains on this
inventory of $41 million as discussed in Note 5.
4 Includes a $4 million gain on disposition resulting from the minor sale of
oil and gas properties.
5 Includes interest income of $8 million and foreign exchange gains of $6
million.
6 Includes a one-time charge of $82 million related to the modification of our
stock option plan as discussed in Note 6.
7 Includes exploration activities primarily in Nigeria, Colombia and Equatorial
Guinea.
8 Includes Yemen cash taxes of $168 million.
9 Approximately 84% of Marketing's identifiable assets are accounts receivable
and inventories.
10 Approximately 73% of Corporate and Other's identifiable assets are cash and
short-term instruments.
17
THREE MONTHS ENDED SEPTEMBER 30, 2003 (1)
Corporate
and
(Cdn$ millions) Oil and Gas Syncrude(2) Chemicals Other Total
- --------------------------------------------------------------------------------------------------------------------------------
United Other
Yemen Canada(3) States Australia Countries(4) Marketing
----------------------------------------------------------
Net Sales 201 144 170 19 15 7 66 94 -- 716
Marketing and Other 1 1 1 -- -- 121 -- 1 6(5) 131
--------------------------------------------------------------------------------------------------
Total Revenues 202 145 171 19 15 128 66 95 6 847
Less: Expenses
Operating 23 38 20 9 3 5 27 59 -- 184
Transportation and Other -- -- (2)(6) -- -- 98 3 8 -- 107
General and Administrative -- 7 2 -- 6 9 1 6 13 44
Depreciation, Depletion and
Amortization 41 56 53 6 13 3 3 10 5 190
Exploration 2 8 9 -- 11(7) -- -- -- -- 30
Interest -- -- -- -- -- -- -- -- 23 23
--------------------------------------------------------------------------------------------------
Income (Loss) from
Continuing Operations
before Income Taxes 136 36 89 4 (18) 13 32 12 (35) 269
==================================================================================================
Less: Provision for Income
Taxes(8) 91
Add: Net Income from
Discontinued Operations 3
------
Net Income 181
======
Identifiable Assets 597 1,872 1,669 39 158 991(9) 658 471 219 6,674
==================================================================================================
Capital Expenditures
Development and Other 48 44 50 -- 7 -- 47 2 7 205
Exploration 11 20 34 -- 16 -- -- -- -- 81
Proved Property Acquisitions -- -- -- -- -- -- -- -- -- --
--------------------------------------------------------------------------------------------------
59 64 84 -- 23 -- 47 2 7 286
==================================================================================================
Property, Plant and Equipment
Cost 1,913 2,903 2,177 209 321 156 766 771 185 9,401
Less: Accumulated DD&A 1,524 1,144 874 202 212 51 144 379 90 4,620
--------------------------------------------------------------------------------------------------
Net Book Value 389 1,759 1,303 7 109 105 622 392 95 4,781
==================================================================================================
Notes:
1 Restated to give effect to a change in accounting principles (see Note 1).
2 Syncrude is considered a mining operation for US reporting purposes.
Property, plant and equipment at September 30, 2003 includes mineral rights
of $6 million.
3 Excludes results of our non-core conventional light oil assets in southeast
Saskatchewan that were sold. These results are shown as discontinued
operations (see Note 10).
4 Includes results of operations from producing activities in Nigeria and
Colombia.
5 Includes interest income of $2 million and foreign exchange gains of $4
million.
6 Includes the recovery of previously incurred property damage costs from our
insurers. The costs were incurred to repair damage caused by Hurricane Lili
in 2002.
7 Includes exploration activities primarily in Nigeria and Colombia.
8 Includes Yemen cash taxes of $51 million.
9 Approximately 78% of Marketing's identifiable assets are accounts receivable
and inventories.
18
NINE MONTHS ENDED SEPTEMBER 30, 2003 (1)
Corporate
and
(Cdn$ millions) Oil and Gas Syncrude(2) Chemicals Other Total
- -------------------------------------------------------------------------------------------------------------------------------
United Other
Yemen Canada(3) States Australia Countries(4) Marketing
----------------------------------------------------------
Net Sales 620 475 549 64 51 18 187 284 -- 2,248
Marketing and Other 4 2 14 -- -- 416 -- 1 14(5) 451
--------------------------------------------------------------------------------------------------
Total Revenues 624 477 563 64 51 434 187 285 14 2,699
Less: Expenses
Operating 65 107 66 30 13 17 91 181 -- 570
Transportation and Other 3 -- 1 -- -- 319 7 27 -- 357
General and Administrative 3 22 8 -- 16 28 1 16 32 126
Depreciation, Depletion and
Amortization 124 167 158 19 29 9 10 37 13 566
Exploration 5 31 42 1 30(6) -- -- -- -- 109
Interest -- -- -- -- -- -- -- -- 76 76
--------------------------------------------------------------------------------------------------
Income (Loss) from
Continuing Operations
before Income Taxes 424 150 288 14 (37) 61 78 24 (107) 895
==================================================================================================
Less: Provision for Income
Taxes(7) 215
Add: Net Income from
Discontinued Operations 15
------
Net Income 695
======
Identifiable Assets 597 1,872 1,669 39 158 991(8) 658 471 219 6,674
==================================================================================================
Capital Expenditures
Development and Other 154 200 177 1 24 -- 136 6 16 714
Exploration 19 47 105 1 47 -- -- -- -- 219
Proved Property Acquisitions -- -- 164(9) -- -- -- -- -- -- 164
--------------------------------------------------------------------------------------------------
173 247 446 2 71 -- 136 6 16 1,097
==================================================================================================
Property, Plant and Equipment
Cost 1,913 2,903 2,177 209 321 156 766 771 185 9,401
Less: Accumulated DD&A 1,524 1,144 874 202 212 51 144 379 90 4,620
--------------------------------------------------------------------------------------------------
Net Book Value 389 1,759 1,303 7 109 105 622 392 95 4,781
==================================================================================================
Notes:
1 Restated to give effect to a change in accounting principles (see Note 1).
2 Syncrude is considered a mining operation for US reporting purposes.
Property, plant and equipment at September 30, 2003 includes mineral rights
of $6 million.
3 Excludes results of our non-core conventional light oil assets in southeast
Saskatchewan that were sold. These results are shown as discontinued
operations (see Note10).
4 Includes results of operations from producing activities in Nigeria and
Colombia.
5 Includes interest income of $6 million and foreign exchange gains of $8
million.
6 Includes exploration activities primarily in Nigeria, Colombia and Brazil.
7 Includes Yemen cash taxes of $150 million and a $76 million future tax
recovery due to tax rate reductions for Canadian resource activities.
8 Approximately 78% of Marketing's identifiable assets are accounts receivable
and inventories.
9 On March 27, 2003 we acquired the residual 40% interest in Aspen in the Gulf
of Mexico for US $109 million. 14.
19
14. DIFFERENCES BETWEEN CANADIAN AND US GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
The Unaudited Consolidated Financial Statements have been prepared in accordance
with Canadian GAAP. The US GAAP Unaudited Consolidated Statement of Income and
Balance Sheet and summaries of differences from Canadian GAAP are as follows:
(a) UNAUDITED CONSOLIDATED STATEMENT OF INCOME - US GAAP
FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30
THREE MONTHS NINE MONTHS
ENDED SEPTEMBER 30 ENDED SEPTEMBER 30
(Cdn$ millions, except per share amounts) 2004 2003 2004 2003
- -----------------------------------------------------------------------------------------------------------------------
REVENUES
Net Sales 837 716 2,359 2,248
Marketing and Other (iv); (xii); (xiii) 142 143 441 464
----------------------------------------------
979 859 2,800 2,712
----------------------------------------------
EXPENSES
Operating (vi) 206 184 601 570
Transportation and Other (i); (xii) 118 107 394 357
General and Administrative (xi) 57 44 211 126
Depreciation, Depletion and Amortization (iii) 192 199 573 604
Exploration 54 30 108 109
Interest (i) 35 39 118 126
----------------------------------------------
662 603 2,005 1,892
----------------------------------------------
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES 317 256 795 820
----------------------------------------------
PROVISION FOR INCOME TAXES
Current 73 60 189 164
Deferred (i); (iv); (vi); (x); (xiii) 36 29 52 111
----------------------------------------------
109 89 241 275
----------------------------------------------
NET INCOME FROM CONTINUING OPERATIONS BEFORE CUMULATIVE EFFECT
OF A CHANGE IN ACCOUNTING PRINCIPLES 208 167 554 545
Net Loss from Discontinued Operations (iii) -- (19) -- (7)
Cumulative Effect of Changes in Accounting Principles,
Net of Income Taxes (ix); (xiii) -- (11) -- (48)
----------------------------------------------
NET INCOME - US GAAP(1) 208 137 554 490
==============================================
EARNINGS PER COMMON SHARE ($/share)
Basic (Note 7)
Net Income from Continuing Operations 1.61 1.35 4.32 4.42
Net Loss from Discontinued Operations -- (0.15) -- (0.06)
Cumulative Effect of Changes in Accounting Principles -- (0.09) -- (0.39)
----------------------------------------------
1.61 1.11 4.32 3.97
==============================================
Diluted (Note 7)
Net Income from Continuing Operations 1.60 1.33 4.26 4.39
Net Loss from Discontinued Operations -- (0.15) -- (0.06)
Cumulative Effect of Changes in Accounting Principles -- (0.09) -- (0.39)
----------------------------------------------
1.60 1.09 4.26 3.94
==============================================
Note:
1 RECONCILIATION OF CANADIAN AND US GAAP NET INCOME
THREE MONTHS NINE MONTHS
ENDED SEPTEMBER 30 ENDED SEPTEMBER 30
(Cdn$ millions) 2004 2003 2004 2003
- -----------------------------------------------------------------------------------------------------------------------
Net Income - Canadian GAAP 220 181 555 695
Impact of US Principles, Net of Income Taxes:
Depreciation, Depletion and Amortization (iii) (11) (9) (32) (37)
Dividends on Preferred Securities (i) -- (10) (2) (31)
Future Income Taxes (x) -- -- -- (76)
Issue Costs on Preferred Securities Redeemed (i) -- -- (6) --
Cumulative Effect of Changes in Accounting Principles (ix); -- (11) -- (48)
(xiii)
Fair Value of Preferred Securities (xiii) -- 5 4 5
Stock Based Compensation included in Retained Earnings (xi) -- -- 36 --
Loss on Disposition (iii) -- (22) -- (22)
Other (iv); (vi) (1) 3 (1) 4
----------------------------------------------
Net Income - US GAAP 208 137 554 490
==============================================
20
(b) UNAUDITED CONSOLIDATED BALANCE SHEET - US GAAP
SEPTEMBER 30 DECEMBER 31
(Cdn$ millions, except share amounts) 2004 2003
- ---------------------------------------------------------------------------------------------------------------------
ASSETS
CURRENT ASSETS
Cash and Short-Term Investments 866 1,087
Accounts Receivable 1,549 1,423
Inventories and Supplies 400 270
Other 42 79
--------------------------------
Total Current Assets 2,857 2,859
--------------------------------
PROPERTY, PLANT AND EQUIPMENT
Net of Accumulated Depreciation, Depletion and
Amortization of $5,729 (December 31, 2003 - $5,330) (iii); (vi); (ix) 4,959 4,583
GOODWILL 36 36
DEFERRED INCOME TAX ASSETS 88 108
DEFERRED CHARGES AND OTHER ASSETS (i); (vii) 147 117
--------------------------------
8,087 7,703
================================
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Current Portion of Long-Term Debt -- 575
Accounts Payable and Accrued Liabilities (iv) 1,796 1,418
Accrued Interest Payable 37 44
Dividends Payable 13 12
--------------------------------
Total Current Liabilities 1,846 2,049
--------------------------------
LONG-TERM DEBT (ii); (vii); (xiii) 2,425 2,472
DEFERRED INCOME TAX LIABILITIES (i) - (xiii) 714 676
ASSET RETIREMENT OBLIGATIONS 309 305
DEFERRED CREDITS AND LIABILITIES (viii) 115 70
SHAREHOLDERS' EQUITY
Common Shares, no par value
Authorized: Unlimited
Outstanding: 2004 - 129,018,817 shares
2003 - 125,606,107 shares 629 513
Contributed Surplus -- 1
Retained Earnings (i); (iii); (iv); (vi); (ix); (x); (xi); (xiii) 2,139 1,660
Accumulated Other Comprehensive Income (i); (ii); (iv); (v); (viii) (90) (43)
--------------------------------
Total Shareholders' Equity 2,678 2,131
--------------------------------
COMMITMENTS AND CONTINGENCIES
8,087 7,703
================================
(c) UNAUDITED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME - US GAAP FOR THE
THREE AND NINE MONTHS ENDED SEPTEMBER 30
THREE MONTHS NINE MONTHS
ENDED SEPTEMBER 30 ENDED SEPTEMBER 30
(Cdn$ millions) 2004 2003 2004 2003
- --------------------------------------------------------------------------------------------------------------------
Net Income - US GAAP 208 137 554 490
Other Comprehensive Income, Net of Income Taxes:
Translation Adjustment (i); (ii); (v) (49) (2) (35) (89)
Unrealized Mark-to-Market Gain/(Loss) (iv) (18) 5 (12) 4
------------------------------------------------
Comprehensive Income 141 140 507 405
================================================
21
(d) UNAUDITED CONSOLIDATED STATEMENT OF CASH FLOWS
Under US principles, dividends on preferred securities of $nil and $3 million
for the three and nine months ended September 30, 2004, respectively (September
30, 2003 - $16 million and $50 million) that are included in financing
activities would be reported in operating activities.
Under US principles, geological and geophysical costs of $15 million and $40
million for the three and nine months ended September 30, 2004, respectively
(September 30, 2003 - $10 million and $34 million) that are included in
investing activities would be reported in operating activities.
NOTES:
i. Under US principles, we were required to classify our preferred
securities as long-term debt rather than shareholders' equity. As a
result:
o dividends of $3 million in the first quarter were included in
interest expense, with the related income tax of $1 million
included in the provision for income taxes;
o pre-tax issue costs of $10 million were included in deferred
charges and other assets, rather than as an after-tax charge to
retained earnings; and
o for the three and nine months ended September 30, 2004,
foreign-currency translation losses of $nil and $8 million
respectively were included in accumulated other comprehensive
income (AOCI).
In February 2004, we redeemed at par US$217 million of preferred
securities. Under Canadian principles, a foreign exchange gain of $34
million, net of income tax, was recognized in retained earnings. Under
US principles, this foreign exchange gain had been included in AOCI.
Unamortized issue costs of $10 million ($6 million, net of income
taxes) were included in transportation and other in the first quarter.
ii. Under US principles, all of our subordinated securities are classified
as long-term debt. As a result, the $33 million equity component has
been included in long-term debt.
iii. Under US principles, the liability method of accounting for income
taxes was adopted in 1993. In Canada, the liability method was adopted
in 2000. In 1997, we acquired certain oil and gas assets and the amount
paid for these assets differed from the tax basis acquired. Under US
principles, this difference was recorded as a deferred tax liability
with an increase to property, plant and equipment rather than a charge
to retained earnings. As a result:
o additional depreciation, depletion and amortization of $11 million
and $32 million was included in net income for the three and nine
months ended September 30, 2004, respectively; and
o property, plant and equipment is higher under US GAAP by $39
million.
During the third quarter of 2003, some of these assets were sold as
described in Note 10. With the carrying value of these assets higher
under US GAAP, the sale resulted in a loss on disposition of $22
million, net of income taxes of $10 million. This loss was included in
our net loss from discontinued operations disclosed on the Unaudited
Consolidated Statement of Income - US GAAP.
iv. Under US principles, 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 OIL AND GAS PRODUCTION: Included in accounts payable at
December 31, 2003, was a $3 million loss on the forward contracts we
used to hedge the commodity price risk on the future sale of a portion
of our production from the Aspen field as described in Note 5. These
contracts expired in March 2004. The losses ($2 million, net of income
taxes), deferred in AOCI at December 31, 2003, were recognized in net
sales.
22
FUTURE SALE OF GAS INVENTORY: Included in accounts payable at December
31, 2003, was $11 million of losses on the futures and basis swap
contracts we used to hedge the commodity price risk on the future sale
of our gas inventory as described in Note 5. These contracts
effectively lock-in profits on our stored gas volumes. Losses of $8
million ($5 million, net of income taxes) related to the effective
portion and deferred in AOCI at December 31, 2003, were recognized in
marketing and other. Additionally, losses of $3 million ($2 million,
net of income taxes), related to the ineffective portion, were
recognized in marketing and other under Canadian GAAP. Under US GAAP,
the ineffective portion was recognized in net income in 2003.
At September 30, 2004, losses of $28 million were included in accounts
payable. The $27 million ($18 million, net of income taxes) effective
portion has been 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. Additionally, losses of $1 million
related to the ineffective portion were included in marketing and other
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, 2004, we had
no fair value hedges in place.
v. Under US principles, 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.
vi. Under Canadian principles, we defer certain development costs and all
pre-operating revenues and costs to property, plant and equipment.
Under US principles, these costs have been included in operating
expenses. As a result:
o operating expenses include pre-operating costs of $1 million and
$5 million ($3 million, net of income taxes) for the three and
nine months ended September 30, 2004, respectively; and
o property, plant and equipment is lower under US GAAP by $11
million.
vii. Under US principles, discounts on long-term debt are classified as a
reduction of long-term debt rather than as deferred charges and other
assets. Discounts of $45 million have been included in long-term debt.
viii. Under US principles, 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 $2 million at
September 30, 2004 (December 31, 2003 - $2 million).
ix. 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 as described in Note 1. These standards
are consistent except for the adoption date.
This change in accounting policy has been reported as a cumulative
effect adjustment in the Unaudited Consolidated Statement of Income as
a loss of $37 million, net of income taxes of $25 million, on January
1, 2003.
x. Under US principles, enacted tax rates are used to calculate deferred
income taxes, whereas under Canadian GAAP, substantively enacted tax
rates are used. Substantively enacted changes in Canadian federal
income tax rates created a $76 million deferred income tax recovery
during the second quarter of 2003.
xi. As described in Note 6 (b), our existing stock option plan was modified
to a tandem option plan. An obligation of $85 million was recognized
for these tandem options. This resulted in a one-time, non-cash charge
to net income of $54 million, net of tax in the second quarter of 2004.
Under US principles, the modification of our stock option plan is
accounted for by providing us with credit for the pro-forma expense
previously disclosed with respect to the stock options modified. The
related pro-forma expense was $36 million, which is accounted for as an
adjustment to retained earnings with a corresponding decrease to our
one-time charge to net income.
xii. Under US principles, gains and losses on the disposition of assets are
shown as other expense.
23
xiii. 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. The change in fair value of our
preferred securities up to June 30, 2003 increased the carrying value
of our long-term debt by $16 million and was recognized as a loss of
$11 million, net of income taxes of $5 million. This was reported as a
cumulative effect of a change in an accounting principle at the
beginning of the third quarter of 2003. The fair value of our preferred
securities decreased by $8 million ($5 million, net of income taxes) in
the third quarter of 2003 and this gain was included in marketing and
other. A gain of $4 million for the change in fair value up to the
redemption date of our preferred securities was included in marketing
and other in the first quarter of 2004.
24
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
THE FOLLOWING SHOULD BE READ IN CONJUNCTION WITH THE UNAUDITED CONSOLIDATED
FINANCIAL STATEMENTS INCLUDED IN THIS REPORT. THE UNAUDITED CONSOLIDATED
FINANCIAL STATEMENTS HAVE BEEN PREPARED IN ACCORDANCE WITH GENERALLY ACCEPTED
ACCOUNTING PRINCIPLES (GAAP) IN CANADA. THE IMPACT OF THE SIGNIFICANT
DIFFERENCES BETWEEN CANADIAN AND UNITED STATES (US) ACCOUNTING PRINCIPLES ON THE
FINANCIAL STATEMENTS IS DISCLOSED IN NOTE 14 TO THE UNAUDITED CONSOLIDATED
FINANCIAL STATEMENTS.
UNLESS OTHERWISE NOTED, TABULAR AMOUNTS ARE IN MILLIONS OF CANADIAN DOLLARS. THE
DISCUSSION AND ANALYSIS OF OUR OIL AND GAS ACTIVITIES WITH RESPECT TO OIL AND
GAS VOLUMES, RESERVES AND RELATED PERFORMANCE MEASURES IS PRESENTED ON A
WORKING-INTEREST, BEFORE-ROYALTIES BASIS. WE MEASURE OUR PERFORMANCE IN THIS
MANNER CONSISTENT WITH OTHER CANADIAN OIL AND GAS COMPANIES. WHERE APPROPRIATE,
WE HAVE PROVIDED INFORMATION ON A NET, AFTER-ROYALTIES BASIS IN TABULAR FORMAT.
NOTE: CANADIAN INVESTORS SHOULD READ THE SPECIAL NOTE TO CANADIAN INVESTORS ON
PAGE 60 IN OUR 2003 ANNUAL REPORT ON FORM 10-K WHICH HIGHLIGHTS DIFFERENCES
BETWEEN OUR RESERVE ESTIMATES AND RELATED DISCLOSURES THAT ARE OTHERWISE
REQUIRED BY CANADIAN REGULATORY AUTHORITIES.
EXECUTIVE SUMMARY OF THIRD QUARTER RESULTS
THREE MONTHS NINE MONTHS
ENDED SEPTEMBER 30 ENDED SEPTEMBER 30
(CDN$ MILLIONS) 2004 2003 2004 2003
- --------------------------------------------------------------------------------------------------------
Net Income 220 181 555 695
Earnings per Common Share ($/share) 1.70 1.38 4.31 5.38
Cash Flow from Operations(1) 508 434 1,353 1,449
Production, before Royalties (mboe/d) 244 271 247 272
Production, after Royalties (mboe/d) 170 188 171 187
Capital Expenditures 395 286 1,086 1,097
--------------------------------------------------
We generated strong quarterly net income and cash flow from high commodity
prices and attractive margins. This was partially offset by higher exploration
expense and lower production compared to the third quarter of 2003.
Production grew from the second quarter with incremental production from our
third development well at Aspen. Compared to the third quarter of 2003, our
production rates were lower as our base production has declined in Yemen and
Canada, and we sold light oil properties in Canada in August 2003. In addition,
we were forced to shut-in approximately 45,000 equivalent barrels per day of
production from the Gulf of Mexico for three to four days in September due to
Hurricane Ivan. Despite the production declines, we earn very attractive cash
netbacks from our base assets. Our third quarter cash netback was $24.15 per
boe, 8% higher than the second quarter and a 32% increase over 2003. Our base
assets in Canada, the shallow-water Gulf of Mexico, and the Masila Block in
Yemen will continue to generate significant free cash flow for the foreseeable
future to assist in funding our ongoing major development and exploration
programs. Going forward, we expect to see final production from Buffalo,
Australia and Ejulebe, Nigeria, along with declines in our maturing assets in
Yemen and Canada. Additional volumes will come from Block 51 in Yemen in late
2004 and Syncrude in late 2005, along with bitumen production in 2006 and
synthetic crude in 2007 from the Long Lake project.
Substantial progress was made in the quarter on some of our major development
projects. A key milestone was reached at our Long Lake project in northern
Alberta with the commencement of the commercial sixty-five well SAGD drilling
program. We also advanced our Block 51 development in Yemen. Production on Block
51 is expected to commence later in the year, reaching peak production in the
second quarter of 2005. On the exploration front, our Usan-5 well, offshore
Nigeria was successful. We have an active exploration program scheduled for the
next two quarters with fifteen planned wells in the Gulf of Mexico, on Block 51
in Yemen and offshore West Africa.
Note:
1 We evaluate our performance and that of our business segments based on
earnings and cash flow from operations. Cash flow from operations is a
non-GAAP term that represents cash generated from operating activities before
changes in non-cash working capital and other. We consider it a key measure
as it demonstrates our ability and the ability of our business segments to
generate the cash flow necessary to fund future growth through capital
investment and to repay debt. Cash flow from operations may not be comparable
with the calculation of similar measures for other companies.
THREE MONTHS NINE MONTHS
ENDED SEPTEMBER 30 ENDED SEPTEMBER 30
(CDN$ MILLIONS) 2004 2003 2004 2003
------------------------------------------------------------------------------------------------
Cash Flow from Operating Activities 418 296 1,273 1,242
Changes in Non-Cash Working Capital 55 125 99 165
Other 35 13 (19) 42
---------------------- -------------------------
Cash Flow from Operations 508 434 1,353 1,449
================================================
25
CAPITAL INVESTMENT
THREE MONTHS NINE MONTHS
ENDED SEPTEMBER 30 ENDED SEPTEMBER 30
(CDN$ MILLIONS) 2004 2003 2004 2003
- ------------------------------------------------------------------------------------------------------------------
Development 317 196 881 692
Exploration 45 81 136 219
Acquisition of Remaining Interest in the Aspen Field -- -- -- 164
Chemicals, Corporate and Other 33 9 69 22
---------------------------------------------------
395 286 1,086 1,097
===================================================
In the third quarter of 2004, we continued to advance our strategy with
investments in our major development projects. These projects at Long Lake and
Syncrude in the Athabasca oil sands region, on Block 51 in Yemen and OPL-222 in
Nigeria made up almost 45% of our total capital investment in the third quarter.
While these projects have yet to contribute to our production and cash flow,
they are attractive commercial investments without exploration risk. Over their
lives, these projects are expected to generate attractive margins and low
full-cycle finding and development costs. Total capital invested in these new
growth development projects to date is almost $1 billion and this will grow over
the next few years.
In addition to developing these projects, we are also targeting new
opportunities through on-going exploration and research into new technologies.
Details of our capital programs are set out below.
THREE MONTHS NINE MONTHS
ENDED SEPTEMBER 30 ENDED SEPTEMBER 30
(CDN$ MILLIONS) 2004 2003 2004 2003
- -----------------------------------------------------------------------------------------------------------------
Yemen 75 59 185 173
Athabasca Oil Sands
Long Lake Synthetic Crude 81 18 191 74
Syncrude 57 47 155 136
Canada 47 46 136 173
Gulf of Mexico 65 84 273 446
West Africa and Other Countries 37 23 77 73
Chemicals, Corporate and Other 33 9 69 22
--------------------------------------------------
395 286 1,086 1,097
==================================================
YEMEN
BLOCK 51
Development of East Al Hajr (Block 51) in Yemen is on schedule to start
producing 5,000 bbls/d in late 2004. All of this year's planned development
wells have now been drilled and are being completed and tied-in. All major
equipment for the 35,000 bbls/d central processing facility (CPF) has been
ordered and we expect construction to be completed during the second quarter of
2005. Construction will include a pipeline tie-back (capacity - 100,000 bbls/d)
to connect the CPF to our Masila export system. We expect production to reach
peak rates of 25,000 bbls/d in the second half of 2005. We have an 87.5%
interest in East Al Hajr.
Our 2004 exploration program at East Al Hajr (Block 51) is targeting five
independent prospects on the block. During the quarter, we completed drilling a
second exploration well and have started a third. The first two exploration
wells did not encounter commercial quantities of hydrocarbons and have been
abandoned. Results from the third well are expected shortly. We plan to drill
the remaining two exploration wells during the fourth quarter.
ATHABASCA OIL SANDS
SYNTHETIC CRUDE AT LONG LAKE
The Long Lake Project remains on schedule and on budget. In September, we saw
the start of the commercial steam-assisted-gravity-drainage (SAGD) drilling
program. Sixty-five horizontal well pairs will be drilled over the next 18
months, with steam-injection expected late in 2006. These wells, together with
the three horizontal well pairs from the SAGD pilot, will deliver up to 72,000
barrels per day of bitumen for upgrading onsite.
Project engineering and procurement are also progressing as planned.
Approximately 40% of total project engineering is complete. More than 80% of the
engineering will be completed prior to the start of above-ground construction
scheduled for early 2005. Over 95% of the major SAGD equipment and more than 80%
of the major upgrader equipment has been ordered. The equipment costs have been
in-line with our expectations.
26
We entered into an interim agreement with Enbridge Inc. to provide pipeline
transportation services for the Long Lake Project. The agreement provides for an
initial contract volume of up to 60,000 bbls/d for a 50 month term, with options
to extend the term and expand contract volumes. This interim agreement will be
replaced by definitive transportation agreements.
The Long Lake project will develop and upgrade bitumen into light, sweet,
premium synthetic crude (PSC) oil. SAGD bitumen production will commence in
2006, with up to 60,000 bbls/d of upgraded PSC oil production (30,000 net to
Nexen) beginning in 2007. This project is the first phase in the development of
our bitumen assets at Long Lake.
SYNCRUDE
Overall construction progress at the upgrader expansion (UE-1) is approximately
65% complete, slightly ahead of plan. The UE-1 program is part of the Stage 3
expansion that will add 110,000 barrels per day (8,000 net to Nexen) of
production. The Stage 3 expansion is expected to start-up in late 2005 or early
2006 at an estimated cost of $7.8 billion ($564 million net to Nexen).
CANADA
We continued to invest selectively in our conventional assets in Canada by
focusing resources on our higher return projects. In our coal bed methane
project, we continued our planned expansion program at the Corbett pilot.
GULF OF MEXICO
DEVELOPMENT
During the third quarter we tied-in the third development well at Aspen and the
field is currently producing 30,000 boe per day. At Gunnison, we tied-in three
development wells and re-completed a fourth well that had previously sanded-up.
EXPLORATION
Our exploration program in the Gulf has geared up during the third and fourth
quarters. A total of nine exploration wells are drilling or are expected to be
drilling through the balance of this year. All of these wells should have
relatively short drilling to production cycle times upon success. Two wells are
near our existing Aspen and Gunnison facilities, while the remainder are near
existing third-party infrastructure.
In early September, we began drilling our 100% owned Crested Butte prospect on
Green Canyon 242, three miles northwest of our Aspen field. Drilling was
interrupted by Hurricane Ivan, and results from this well are expected by
year-end. If successful, this well could be tied-in and on production by 2006.
At Dawson Deep, we are currently side-tracking the original well to an optimal
location for production through our Gunnison facilities. Results are expected
shortly. We have a 15% interest in the well and a 30% interest in the Gunnison
facilities.
Main Pass 240 is a deep-shelf test, where we have a 45% non-operated interest.
This prospect is 40 miles offshore Louisiana in 175 feet of water. The well
started drilling in early August, and we were approaching target depth when
operations were suspended due to Hurricane Ivan. Subsequent inspection found
that the drilling rig had been damaged by the hurricane, delaying drilling by
approximately 30 days. We expect to contract another rig to resume drilling this
month and have results before year-end.
A deep-shelf test at Main Pass 273 is planned following the completion of Main
Pass 240. This prospect is 35 miles offshore Louisiana in 200 feet of water. The
well should commence drilling before year-end with results expected early next
year. We have a 30% non-operated interest in the prospect.
At Mustang Island A-110, we expect to begin drilling the Big Bend prospect
before year-end. This deep-shelf gas test is 50 miles offshore Texas in 300 feet
of water. Results should be available early next year. We have a non-operated
50% interest.
At West Cameron 335, we expect to begin drilling the Wind River prospect before
year-end. This deep-shelf gas test is 50 miles offshore Louisiana in 75 feet of
water. We expect results from this well early next year. We have a 50%
non-operated interest.
We also plan to start drilling three additional short-cycle time deep-water
exploration wells in the Gulf of Mexico during the fourth quarter. The Fawkes
prospect located in Garden Banks, Anduin located in Mississippi Canyon, and an
additional prospect in Mississippi Canyon, could all be developed with sub-sea
tie-backs to existing infrastructure.
We are also finalizing plans to drill three high-impact, deep-water, sub-salt
tests, with the first of these expected to begin drilling in the first quarter
of 2005.
27
WEST AFRICA
Total SA announced that its Nigerian operating subsidiary, Elf Petroleum Nigeria
Ltd., has made a significant deepwater discovery in the area west of the Usan
field on OPL-222, offshore southeastern Nigeria. Nexen has a 20% interest in
OPL-222. The Usan-5 well, located around 70 miles offshore and 4 miles west of
the Usan-1 discovery well in water depths of approximately 2,500 feet, is the
fifth successful well in the Usan field area. Oil was sampled at Usan-5 in
several levels confirming the presence of additional quantities of oil as well
as further potential in previously untested reservoirs.
On OML-115, offshore Nigeria, the Ameena-1 well started drilling mid-September
to test the Ameena prospect. Results are expected before year-end, and in the
event of a discovery on Ameena, an appraisal well will be drilled immediately.
Ameena is in 125 feet of water, approximately 40 miles offshore.
Early October, we began drilling an exploration well on Block K, offshore
Equatorial Guinea, to test our Zorro prospect. Zorro is in 2,125 feet of water
approximately 25 miles offshore with results expected by year-end. This prospect
is on trend with recent commercial discoveries directly to the northeast. A
second exploration well will test another prospect early next year. We are the
operator and hold a 50% interest in Block K.
CHEMICALS
In September, we saw the mechanical completion of the Brandon Chemicals plant
expansion, with commissioning and start-up activities planned to be finished by
the end of October. The plant is now the largest and one of the most
cost-efficient sodium chlorate sites in the world. This expansion, of
approximately 65,000 tonnes per year, raises the annual capacity of the plant to
over 260,000 tonnes.
OTHER
We have signed a memorandum of understanding to joint venture with GW Power
Corporation to develop a 70MW wind power project about 10 miles south of Fort
McLeod, Alberta. Pending regulatory approval, construction of the turbines and
towers will begin mid-2005, with commissioning and start-up expected in the
fourth quarter of 2005. This project will be one of the largest projects
producing electricity from wind energy in southern Alberta and has potential for
further expansion. We will hold a 50% interest in the project.
28
FINANCIAL RESULTS
CHANGE IN NET INCOME
2004 VS 2003
THREE MONTHS NINE MONTHS
(CDN$ MILLIONS) ENDED SEPTEMBER 30 ENDED SEPTEMBER 30
- -----------------------------------------------------------------------------------------------------------
NET INCOME AT SEPTEMBER 30, 2003(1) 181 695
============================================
Favourable (unfavourable) variances:
Cash Items:
Production volumes, after royalties:
Crude oil (38) (120)
Natural gas (13) (14)
Crude oil sales volumes, after royalties 5 15
Realized commodity prices:
Crude oil 139 199
Natural gas 13 (26)
Oil and gas operating expense:
Conventional (11) (19)
Syncrude (4) 1
Marketing 13 (35)
Chemicals -- 3
General and administrative (4) (25)
Interest expense (12) (39)
Current income taxes (13) (25)
Other (3) (11)
--------------------------------------------
Total Cash Variance 72 (96)
Non-Cash Items:
Depreciation, depletion and amortization
Oil and Gas 10 35
Other 2 10
Exploration expense (24) 2
General and administrative - stock based compensation (9) (96)
Future income taxes (2) 7
Other (10) (2)
--------------------------------------------
Total Non-Cash Variance (33) (44)
--------------------------------------------
NET INCOME AT SEPTEMBER 30, 2004 220 555
============================================
Note:
1 Includes results of discontinued operations (see Note 10 to our Unaudited
Consolidated Financial Statements).
Significant variances in net income are explained further in the following
sections.
29
OIL AND GAS
PRODUCTION VOLUMES (BEFORE ROYALTIES)
THREE MONTHS NINE MONTHS
ENDED SEPTEMBER 30 ENDED SEPTEMBER 30
2004 2003 2004 2003
- -------------------------------------------------------------------------------------------
Oil and Liquids (mbbls/d)
Yemen 103.3 115.2 107.8 116.7
Canada(1) 35.6 46.2 36.5 48.7
Gulf of Mexico 32.9 31.3 28.5 28.2
Australia 2.1 5.6 3.0 6.5
Other Countries 5.3 5.2 5.1 5.8
Syncrude 17.6 17.5 17.5 15.5
--------------------------------------------
196.8 221.0 198.4 221.4
--------------------------------------------
Natural Gas (mmcf/d)
Canada 141 155 145 158
Gulf of Mexico 144 144 148 146
--------------------------------------------
285 299 293 304
--------------------------------------------
Total (mboe/d) 244 271 247 272
===========================================
PRODUCTION VOLUMES (AFTER ROYALTIES)
THREE MONTHS NINE MONTHS
ENDED SEPTEMBER 30 ENDED SEPTEMBER 30
2004 2003 2004 2003
- --------------------------------------------------------------------------------------------
Oil and Liquids (mbbls/d)
Yemen 50.8 56.8 53.0 57.2
Canada(1) 27.3 34.4 28.2 36.9
Gulf of Mexico 29.1 27.8 25.1 25.0
Australia 1.9 5.4 2.8 5.9
Other Countries 4.9 4.7 4.7 4.9
Syncrude 17.4 17.4 17.3 15.3
--------------------------------------------
131.4 146.5 131.1 145.2
--------------------------------------------
Natural Gas (mmcf/d)
Canada 106 127 114 125
Gulf of Mexico 123 122 126 123
--------------------------------------------
229 249 240 248
--------------------------------------------
Total (mboe/d) 170 188 171 187
===========================================
Note:
1 2003 includes the following oil production from discontinued operations (see
Note 10 to our Unaudited Consolidated Financial Statements):
THREE MONTHS NINE MONTHS
ENDED SEPTEMBER 30 ENDED SEPTEMBER 30
(mboe/d) 2003 2003
--------------------------------------------------------------------------------------
Before Royalties 5.9 8.3
After Royalties 4.2 6.1
-----------------------------------------
30
LOWER PRODUCTION DECREASED NET INCOME FOR THE QUARTER BY $51 MILLION
Production after royalties increased 2% from the second quarter but fell 10%
from the third quarter of 2003. Our 2003 production included volumes from our
non-core Canadian light oil properties in southeast Saskatchewan that were sold
in August 2003. Excluding these volumes, our production after royalties
decreased 8%. The following table summarizes our production volume changes:
BEFORE AFTER
(mboe/d) ROYALTIES ROYALTIES
- --------------------------------------------------------------------------------
Production, third quarter 2003 271 188
Sale of non-core Canadian properties (6) (4)
-----------------
265 184
Base production changes:
Masila Block in Yemen (12) (6)
Canada (7) (5)
Gulf of Mexico 6 4
Australia (2) (2)
-----------------
250 175
Temporary production changes:
Gulf of Mexico production shut-in due to Hurricane Ivan (2) (1)
Unscheduled downtime at Buffalo in Australia (2) (2)
Aspen intervention downtime (2) (2)
-----------------
Production, third quarter 2004 244 170
=================
Our known future production increases will come from Block 51 in Yemen in 2005
and Syncrude in late 2005 or early 2006, along with bitumen production in 2006
and synthetic crude in 2007 from the Long Lake project.
MASILA BLOCK IN YEMEN
Third quarter production decreased 3% from the second quarter and 10% compared
to the third quarter of 2003. Development drilling and continuing well
optimizations in the quarter helped to offset base declines. As the field
matures, we continue development drilling and field maintenance to mitigate
natural declines. Approximately 50 of the expected 80 development wells for 2004
have been drilled and the remainder will be completed by year-end. While we have
experienced lower drilling success rates as the field matures, we have recently
drilled wells that delivered strong initial production rates. This has caused
average initial rates from new wells in our 2004 development drilling program to
increase from 1,200 to 1,500 bbls per day. With our current development drilling
and field maintenance programs, we expect to maintain current production rates
for the remainder of the year.
CANADA
Production from our assets in Canada was down modestly from the second quarter
and 11% from the third quarter of 2003, after adjusting for the August 2003 sale
of non-core, light-oil properties in southeast Saskatchewan. Our conventional
assets in the Western Canadian Sedimentary Basin are maturing and we continue to
limit our investment in these assets. We expect our conventional production to
remain relatively flat for the remainder of the year as we invest selectively to
develop new production, continue to manage the fields and pursue optimization
opportunities. However, we expect increases as the Long Lake project starts up
with bitumen production in 2006 and synthetic crude in 2007.
GULF OF MEXICO
Quarterly production from the Gulf of Mexico increased 18% from the second
quarter as we brought the third Aspen development well on-stream and realized
increased production from Gunnison with the continued tie-in of the remaining
development wells. The shut-in of 45,000 boe for three to four days during
Hurricane Ivan, resulted in the temporary loss of 2,000 boe per day for the
quarter and the indirect loss of production as a result of delayed activity.
With respect to the third quarter of 2003, production was 3% higher primarily
from the addition of the Gunnison production offset by declines and drilling
delays on our conventional Shelf properties.
Production from our Aspen field was 43% higher than the second quarter as the
third development well in the project came on-stream July 3rd. Production was
gradually ramped up from this well throughout the quarter. In August, we
completed an intervention on Aspen-1 to reduce high water cuts. The well was
shut in for most of August to complete this work. While field oil and gas rates
have remained steady, water production has been reduced by more than 50% and we
believe there is potential for water production to decrease further and oil
production to increase as we continue to produce from this well. Current
production from Aspen with all three wells on-stream is averaging approximately
30,000 boe per day and we expect to maintain that rate for the remainder of the
year.
31
We completed and tied-in three wells at our Gunnison project during the quarter.
In addition, we were able to re-complete an earlier well that sanded off during
the second quarter. We now have nine producing wells at Gunnison and the field
produced 10,300 boe per day (net to Nexen) during the quarter. Repairs on the
last non-producing well, which encountered tar during completion, were
unsuccessful. We are currently drilling a side-track away from the tar and
expect to bring this well on-stream late in the fourth quarter. We expect our
exit volumes at year-end from Gunnison to be approximately 11,500 boe per day
(net to Nexen).
Production from our Shelf assets was relatively flat from the second quarter but
was 22% lower compared to the third quarter of 2003. Base declines and delays in
our 2004 development drilling program contributed to the lower rates compared to
2003. Successful development drilling at Vermilion 302 and West Cameron 170
added 4,700 boe per day of new gas production during the quarter. Higher than
expected declines and storm-related drilling rig delays at Vermilion 76 were the
main cause for the decline in production rates from 2003. Growth on the Shelf
during the fourth quarter is expected to come from the Vermilion 302 program and
from Vermilion 76 where we currently have two rigs working on a six-well
drilling program.
With a full quarter of production from Aspen and Gunnison and additional
development drilling on the Shelf, Gulf of Mexico production rates are expected
to average approximately 56,000 to 65,000 boe/d for the fourth quarter.
OTHER COUNTRIES
Australia experienced an unscheduled shutdown in late May, which reduced
quarterly production rates by 1,500 bbls per day in the third quarter. Full
production resumed in early August. Base production on the Buffalo field in
Australia declined 2,000 bbls per day compared to the third quarter of 2003 as
the field approaches the end of its life in November. We also anticipate that
production from Ejulebe in Nigeria will end later this year.
Production from Colombia grew modestly from the second quarter to 5,000 bbls per
day and was 31% higher than the third quarter of 2003 as we continue to
implement our development program.
SYNCRUDE
Syncrude continues to provide stable production. Production was up 6% from the
second quarter as minor turnarounds were completed in April and June and no
major downtime was experienced in the third quarter. We anticipate modest
downtime for the remainder of the year, which should result in production rates
of between 17,000 to 18,000 bbls/d (net to Nexen) for the fourth quarter.
32
COMMODITY PRICES
THREE MONTHS NINE MONTHS
ENDED SEPTEMBER 30 ENDED SEPTEMBER 30
2004 2003 2004 2003
- -------------------------------------------------------------------------------------------------------------------
CRUDE OIL AND NGLS
West Texas Intermediate (WTI) (US$/bbl) 43.88 30.20 39.11 30.99
----------------------------------------------------
Differentials(1) (US$/bbl):
Masila 3.70 2.44 3.85 3.22
Heavy Oil 12.84 8.77 11.44 8.04
Mars 6.08 3.25 5.21 3.66
Realized Prices (Cdn$/bbl):
Yemen 53.80 38.25 46.97 39.89
Canada 41.94 31.07 36.85 33.83
United States 49.90 36.03 45.44 38.65
Syncrude 55.58 41.36 51.11 44.70
Australia -- 42.09 46.00 43.14
Other Countries 46.22 36.03 43.12 39.30
Corporate Average (Cdn$/bbl) 50.98 36.70 45.17 38.80
----------------------------------------------------
NATURAL GAS
New York Mercantile Exchange (NYMEX) (US$/mmbtu) 5.56 4.92 5.82 5.66
AECO (Cdn$/mcf) 6.32 5.96 6.34 6.70
----------------------------------------------------
Realized Prices (Cdn$/mcf):
Canada 5.43 5.14 5.66 5.91
United States 7.64 6.95 7.88 8.53
Corporate Average (Cdn$/mcf) 6.55 6.01 6.78 7.17
----------------------------------------------------
AVERAGE REALIZED OIL AND GAS PRICE (Cdn$/boe) 48.66 36.59 44.29 39.60
----------------------------------------------------
AVERAGE FOREIGN EXCHANGE RATE
Canadian to US Dollar (US$) 0.7650 0.7263 0.7530 0.6886
----------------------------------------------------
Note:
1 These differentials are a discount to WTI.
HIGHER REALIZED COMMODITY PRICES INCREASED QUARTERLY NET INCOME BY $152 MILLION
Both crude oil and natural gas commodity prices remained strong in the third
quarter of 2004, with crude oil benchmark prices reaching record highs. The
strength in reference prices was partially offset by the impact of a stronger
Canadian dollar on our realized prices.
All of our oil sales and most of our gas sales are denominated in or referenced
to US dollars. As a result, the strong Canadian dollar decreased net sales for
the quarter by approximately $35 million, and reduced our realized crude oil
price by approximately $2.70 per barrel and our realized natural gas price by
$0.35 per mcf compared to the third quarter of 2003.
CRUDE OIL REFERENCE PRICES
Crude oil prices remained strong overall, with increased volatility as WTI
ranged from US$38 to over US$50 per barrel. WTI climbed to a new record high in
September due to heightened concerns around supply given relatively limited
spare capacity overall. Potential supply disruptions, including:
o terrorist activities in Iraq;
o concerns over Yukos in Russia;
o on-going civil unrest in Nigeria and Venezuela; and
o the threat of terrorist activities in either Saudi Arabia or the US,
have caused significant upward price movement, as OPEC's ability to access
additional capacity no longer seems sufficient to ensure a stable supply chain.
More recently, hurricane activity in the Gulf of Mexico has pushed prices up as
supply disruptions have driven down already low North American crude and product
inventory levels. With strong global demand and low product inventory levels,
events that threaten to disrupt even a small amount of supply continue to have a
significant impact on world crude oil prices.
33
With added speculation around supply disruptions, we have seen increased
volatility. WTI's steep retreat from US$49.40 per barrel in late August was
driven mainly by speculator profit taking. During the last two weeks of August,
the number of contracts held dropped by almost 20,000, correlating with a
US$4.63 per barrel drop in WTI. While this caused some market correction, we
have continued to see strong monthly averages, between US$42 and 46 per barrel,
for WTI.
Given the strong supply and demand fundamentals, fears around possible
disruptions and concerns over spare capacity, neither OPEC's announced one
million barrel per day increase on September 15, 2004, nor the subsequent
announcement by Saudi Arabia to increase capacity had much impact on prices.
Late in the quarter, WTI broke through US$50.00 per barrel on news of large
product inventory draws in North America and the threat of increased rebel
activity in the Niger delta. With over 550,000 daily barrels of Gulf production
shut-in due to hurricane damage, concerns around low product inventory levels
have increased.
CRUDE OIL DIFFERENTIALS
Crude oil differentials have widened primarily due to the overall strength in
market prices. The Canadian heavy oil differential increased to US$12.84 per
barrel from US$11.62 in the second quarter. This is because sweeter blends, such
as WTI, are in greater demand as they yield more diesel, heating oil and
gasoline than heavy and sour blends. Also, incremental Middle East barrels
resulting from increased OPEC quotas are sour and heavy, which has increased the
supply of heavy barrels. With world demand growing, in particular for gasoline
and diesel, heavy oil differentials have widened. We expect the heavy oil
differential to remain wide for the remainder of the year.
The Masila differential averaged US$3.70 per barrel, narrowing slightly from
second quarter levels. Masila continued to track the Brent/WTI spread early in
the quarter. While the summer driving season in North America increased demand
for WTI relative to Brent, supply fundamentals offset the summer driving season
impact. Platform turnarounds in the North Sea reduced the supply of Brent and
new OPEC production increased supply into the US, keeping the differential
narrow. With worldwide demand growing for the sweeter blends, the differential
for our sour Masila barrels widened, relative to both WTI and Brent, late in the
quarter.
The Mars differential widened to US$6.08 per barrel from US$4.89 per barrel for
the second quarter. Like heavier crudes, the sour differential has widened as a
greater premium is being placed on sweeter blends. Also, the new OPEC production
making its way to the US Gulf Coast is largely sour and is competing directly
with the Mars blend.
NATURAL GAS REFERENCE PRICES
Natural gas prices weakened in the third quarter compared to the second quarter
with NYMEX averaging US$5.56 per mmbtu. Cooler than normal summer weather and a
strong build in storage over the summer placed downward pressure on gas prices
in early September. With reports of 24 bcf per day of Gulf gas shut-in due to
hurricane damage, prices strengthened to US$6.80 per mmbtu late in the quarter.
Concerns around winter gas supply have decreased as the market is currently well
supplied and storage levels are more than 250 bcf higher than last year.
OPERATING COSTS
THREE MONTHS NINE MONTHS
ENDED SEPTEMBER 30 ENDED SEPTEMBER 30
(Cdn$/boe) 2004 2003 2004 2003
- ------------------------------------------------------------------------------------------------------------------------------
Operating Costs per boe based on our working interest production
before royalties(1)
Conventional Oil and Gas(2) 5.25 4.11 5.01 4.25
Synthetic Crude Oil
Syncrude 18.87 17.06 18.72 21.63
Total Oil and Gas(2) 6.25 4.94 5.98 5.24
-----------------------------------------------------
Operating Costs per boe based on our net production after royalties
Conventional Oil and Gas(2) 7.93 6.14 7.53 6.36
Synthetic Crude Oil
Syncrude 19.05 17.30 18.91 21.88
Total Oil and Gas(2) 9.11 7.17 8.68 7.63
-----------------------------------------------------
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 2003 operating costs include results of discontinued operations (see Note 10
to our Unaudited Consolidated Financial Statements).
34
HIGHER CONVENTIONAL OIL AND GAS OPERATING COSTS DECREASED NET INCOME FOR THE
QUARTER BY $11 MILLION AND HIGHER OPERATING EXPENSE AT SYNCRUDE DECREASED NET
INCOME FOR THE QUARTER BY $4 MILLION
Our operating costs have increased as a result of the Aspen-1 well remediation,
higher maintenance in Yemen and Canada, more workover activity in the Gulf of
Mexico and the spread of fixed costs over fewer barrels. These increases were
partially offset by the deferral of costs from Australia and Nigeria. These
costs have been deferred in inventory as none of these high-cost late-life
barrels were lifted in the quarter.
Aspen-1 intervention costs of $12 million were expensed during the quarter.
These costs were higher than expected as storm activity in the Gulf extended the
work. These costs, together with higher workover activities on the Shelf,
contributed a $1.10 per boe increase to our corporate unit costs in the quarter.
Flow line replacements, higher water handling costs and increased maintenance at
Masila in Yemen increased our corporate unit operating costs by 40(cent) per
boe. However, these increased Yemen costs only reduce our corporate netbacks by
9(cent) per boe as a result of the cost recovery mechanism contained in our
production sharing contract with the Government of Yemen.
The inclusion of the costs from Australia and Nigeria in inventory effectively
reduced our corporate unit operating costs by 45(cent). These costs will be
included in operating costs in the fourth quarter when the inventory is sold.
Operating costs in Canada have increased our corporate average by 25(cent) per
boe from 2003 as a result of higher maintenance and heavy oil workover programs.
However, as more expensive Canadian barrels were a smaller portion of our total
corporate production in the third quarter, this contributed a 15(cent) per boe
decrease to our corporate unit operating costs.
The strength of the Canadian dollar reduced our US-dollar denominated operating
costs, contributing a 15(cent) reduction to our corporate unit costs.
Syncrude operating costs increased 11% on a per unit basis compared to 2003
increasing our total corporate unit costs by 15(cent) per boe. Higher natural
gas input costs and increased maintenance caused the majority of the increase.
As more expensive Syncrude barrels were a larger portion of our total corporate
production in the third quarter, our corporate unit operating costs increased by
15(cent) per boe. With greater operational reliability expected this year,
Syncrude unit operating costs should be between $18 and $19 per barrel for the
full year including the cost of purchased energy.
DEPRECIATION, DEPLETION AND AMORTIZATION (DD&A)
THREE MONTHS NINE MONTHS
ENDED SEPTEMBER 30 ENDED SEPTEMBER 30
(CDN$/BOE) 2004 2003 2004 2003
- -------------------------------------------------------------------------------------------------------------------
DD&A per boe based on our working interest production
before royalties(1)
Conventional Oil and Gas(2) 7.83 7.36 7.59 7.41
Synthetic Crude Oil
Syncrude 2.72 2.38 2.73 2.50
Average Oil and Gas(2) 7.46 7.04 7.25 7.13
----------------------------------------------------
DD&A per boe based on our net production after royalties
Conventional Oil and Gas(2) 11.85 11.01 11.40 11.09
Synthetic Crude Oil
Syncrude 2.75 2.42 2.75 2.53
Average Oil and Gas(2) 10.88 10.21 10.52 10.38
----------------------------------------------------
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 2003 DD&A includes results of discontinued operations (see Note 10 to our
Unaudited Consolidated Financial Statements).
LOWER OIL AND GAS DD&A INCREASED NET INCOME FOR THE QUARTER BY $10 MILLION
Although lower oil and gas DD&A increased net income in total, our corporate
depletion rate on a per unit basis increased. Higher depletion from our more
capital-intensive deep water properties in the US Gulf of Mexico has increased
corporate rates by $1.10. These properties, however, benefit from lower unit
operating costs as most of the costs are capital in nature.
Offsetting the increase was the benefit of a strong Canadian dollar as the
depletion of our US and international assets is denominated in US dollars. This
lowered our depletion rate by 25(cent) per boe. Both Australia and Nigeria are
nearly fully depleted and contributed a combined reduction of 40(cent).
Syncrude depletion rates increased reflecting the depletable costs of the Aurora
2 bitumen train which came into service in late 2003.
35
EXPLORATION EXPENSE(1)
THREE MONTHS NINE MONTHS
ENDED SEPTEMBER 30 ENDED SEPTEMBER 30
(Cdn$ millions) 2004 2003 2004 2003
- ---------------------------------------------------------------------------------------------------------------
Seismic 15 10 40 34
Unsuccessful Exploration Drilling 27 6 27 30
Other 12 14 41 46
------------------------------------------------------
Total Exploration Expense 54 30 108 110
======================================================
Total Exploration Capital 45 81 136 219
Exploration Expense as a % of Exploration Capital (%) 120 37 79 50
------------------------------------------------------
Note:
1 2003 exploration expense for the nine months ended September 30 includes $1
million relating to discontinued operations (see Note 10 to our Unaudited
Consolidated Financial Statements).
HIGHER EXPLORATION EXPENSE REDUCED NET INCOME FOR THE QUARTER BY $24 MILLION
Exploration expense for the quarter included the costs of the Shark well in the
Gulf of Mexico, an ultra-deep-shelf gas test on South Timbalier 174 that
finished drilling during the first quarter of this year. At this time, we have
no plans to re-enter the well and we have expensed $25 million of well costs. We
remain encouraged by the ultra-deep-shelf and are at the forefront of this
opportunity. We also expensed two unsuccessful exploration wells on Block 51 in
Yemen during the quarter after encountering non-commercial amounts of
hydrocarbons.
Exploration capital in the quarter included the Usan-5 well on OPL-222 offshore
Nigeria, three deep-water and deep-shelf wells in the Gulf of Mexico, two
exploration wells on Block 51 in Yemen and the spudding of our Ameena prospect
on OML-115 in mid-September. The Usan-5 well was successful and an appraisal
well is currently drilling. We have identified six additional deep-water and
deep-shelf targets in the Gulf to test in the fourth quarter. We also plan to
test additional prospects on Block 51 in Yemen and offshore West Africa in the
remainder of the year.
OIL AND GAS MARKETING
THREE MONTHS NINE MONTHS
ENDED SEPTEMBER 30 ENDED SEPTEMBER 30
(Cdn$ millions) 2004 2003 2004 2003
- ---------------------------------------------------------------------------------------------------------------------
Marketing Revenue, net 144 121 403 416
Transportation (106) (98) (338) (319)
Other -- 2 (2) 1
---------------------------------------------------
Contribution from Marketing 38 25 63 98
===================================================
Physical Sales Volumes (excluding intra-segment transactions)
Crude Oil (mboe/d) 445 424 444 460
Natural Gas (mmcf/d) 4,929 2,951 4,703 3,007
Value-at-Risk
Quarter-end 27 22 27 22
High 36 26 36 31
Low 27 14 17 14
Average 33 19 28 20
---------------------------------------------------
HIGHER CONTRIBUTION FROM MARKETING INCREASED NET INCOME BY $13 MILLION
Marketing's quarterly contribution largely reflects profits generated by our gas
marketing group. We built a position assuming summer prices would decline
relative to winter prices. As a result of summer/winter spreads widening
throughout most of the summer, our short summer (fixed price sale) and long
winter (fixed price purchase) gas positions generated profits. In addition, we
continue to acquire transportation and natural gas contracts on favourable terms
from competitors exiting the market and we were able to profit from these
acquisitions.
We have natural gas in storage which has been hedged economically with futures
contracts and swaps. Some of these futures contracts and swaps have been
designated as accounting hedges, which helps reduce the earnings volatility
caused by the mark-to-market of these contracts. At the end of our third
quarter, we have 26 bcf of natural gas in storage, 19 bcf of which has been
hedged for accounting purposes.
36
Our natural gas in storage is required to be carried at the lower of cost or net
realizable value, which prevents us from recognizing any increase in its value.
However, mark-to-market losses on our futures contracts and swaps are required
to be recorded in our earnings unless the contracts have been designated as
accounting hedges. The losses on the designated futures contracts and swaps,
together with the gains expected on the future sale of our gas in storage, will
be recognized in earnings when the gas is sold.
At September 30, 2004, we have $41 million of unrecognized gains on our natural
gas in storage that is economically hedged but not hedged for accounting
purposes. Mark-to-market losses on the futures contracts and swaps that
economically hedge these storage positions have been included in our earnings.
Our crude oil marketing group also contributed to our quarterly results by
accelerating the pricing of future sales to take advantage of high crude oil
prices.
COMPOSITION OF NET MARKETING REVENUE
THREE MONTHS NINE MONTHS
ENDED SEPTEMBER 30 ENDED SEPTEMBER 30
(Cdn$ millions) 2004 2003 2004 2003
- ----------------------------------------------------------------------------------------
Derivative Contracts 29 21 48 84
Non-Derivative Contracts 9 4 15 14
----------------------------------------------
38 25 63 98
==============================================
DERIVATIVE CONTRACTS
Our marketing operation engages in crude oil, natural gas and power marketing
activities to enhance prices from the sale of our own production, and for energy
marketing and trading. We enter into contracts to purchase and sell crude oil
and natural gas. These derivative contracts are valued as described in the MD&A
included in our 2003 Annual Report on Form 10-K.
FAIR VALUE OF DERIVATIVE CONTRACTS
At September 30, 2004, the fair value of our derivative contracts not designated
as accounting hedges totalled $117 million. The following table shows the
valuation methods underlying these contracts together with details of contract
maturity:
(CDN$ MILLIONS) MATURITY
- ------------------------------------------------------------------------------------------------------------------------------
LESS THAN MORE THAN
<1 YEAR 1-3 YEARS 4-5 YEARS 5 YEARS TOTAL
----------------------------------------------------------------------
Prices
Actively Quoted Markets 25 14 -- -- 39
From Other External Sources 37 41 -- -- 78
Based on Models and Other Valuation Methods -- -- -- -- --
----------------------------------------------------------------------
Total 62 55 -- -- 117
======================================================================
More than 50% of the unrealized but recognized gains are related to contracts
that will settle within 12 months. Contract maturities vary from a single day up
to six years. Those maturing beyond one year are primarily from natural gas
related positions. The relatively short maturity position of our contracts
lowers our portfolio risk.
At September 30, 2004, we had $28 million of unrecognized losses on our
derivative contracts designated as accounting hedges of the future sale of our
gas inventory. These losses, together with the gains expected on the future sale
of our gas inventory, will be recognized in income when the inventory is sold.
These contracts were valued from actively quoted markets and settle within 12
months.
37
CHANGES IN FAIR VALUE OF DERIVATIVE CONTRACTS
CONTRACTS
CONTRACTS CONTRACTS ENTERED INTO
OUTSTANDING AT ENTERED INTO DURING PERIOD
BEGINNING OF AND CLOSED AND OUTSTANDING
(CDN$ MILLIONS) PERIOD DURING PERIOD AT END OF PERIOD TOTAL
- ---------------------------------------------------------------------------------------------------------------------------------
Fair Value at December 31, 2003 106 -- -- 106
Change in Fair Value of Contracts (15) (21) 84 48
Net Losses (Gains) on Contracts Closed (58) 21 -- (37)
Changes in Valuation Techniques and Assumptions(1) -- -- -- --
---------------------------------------------------------------------
Fair Value at September 30, 2004 33 -- 84 117
=====================================================
Unrecognized Losses on Hedges of Future Sale
of Gas Inventory at September 30, 2004 (28)
---------
Total Outstanding at September 30, 2004 89
=========
Note:
1 Our valuation methodology has been applied consistently in each period.
TOTAL CARRYING VALUE OF DERIVATIVE CONTRACTS
SEPTEMBER 30 DECEMBER 31
(CDN$ MILLIONS) 2004 2003
- ------------------------------------------------------------------------------------------------------------------------------
Current Assets 168 102
Non Current Assets 93 63
------------------------------
Total Derivative Contract Assets 261 165
==============================
Current Liabilities 106 34
Non Current Liabilities 38 25
------------------------------
Total Derivative Contract Liabilities 144 59
==============================
Total Derivative Contract Net Assets 1 117 106
==============================
Note:
1 Does not include derivative contracts accounted for as hedges.
NON-DERIVATIVE CONTRACTS
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 our non-derivative activities in the third
quarter (2003 - $4 million) and $15 million (2003 - $14 million) year to date.
CHEMICALS
CASH CONTRIBUTION FROM CHEMICALS FOR THE QUARTER WAS CONSISTENT WITH THE
PRIOR YEAR
Higher sales volumes in North America and Brazil were offset by the effect of
the stronger Canadian dollar. Sales volumes increased 4% during the quarter
compared to 2003 but the strong Canadian dollar reduced US-dollar denominated
sales by $1 million. Operating costs have increased as a result of the higher
sales volumes but we are not benefiting from foreign exchange savings on these
costs as they are denominated primarily in Canadian dollars. Higher electricity
input costs have also put pressure on operating costs.
CORPORATE EXPENSES
GENERAL AND ADMINISTRATIVE (G&A)
THREE MONTHS NINE MONTHS
ENDED SEPTEMBER 30 ENDED SEPTEMBER 30
(CDN$ MILLIONS) 2004 2003 2004 2003
- ------------------------------------------------------------------------------------------------------------------------------
General and Administrative 57 44 247 126
-----------------------------------------------------
38
HIGHER COSTS DECREASED QUARTERLY NET INCOME BY $13 MILLION
During the second quarter, our shareholders approved the modification of our
stock option plan to a tandem option plan, creating a one-time G&A expense of
$82 million ($54 million, after tax). Our tandem option obligations are revalued
each reporting period based on the change in the market value of our common
shares. In the third quarter, the additional graded vesting of tandem options,
coupled with a share price increase from $52.00 to $52.75 per share, increased
our tandem option obligation and G&A expense by $9 million.
With our major development projects in the deep water of the Gulf of Mexico now
on stream, we have capitalized fewer costs. Higher regulatory compliance costs,
including costs associated with our Sarbanes-Oxley internal control
documentation project, contributed to the increase.
INTEREST AND FINANCING COSTS
THREE MONTHS NINE MONTHS
ENDED SEPTEMBER 30 ENDED SEPTEMBER 30
(CDN$ MILLIONS) 2004 2003 2004 2003
- ------------------------------------------------------------------------------------------------------
Interest 46 35 142 107
Less: Capitalized Interest (11) (12) (27) (31)
------------------------------------------------
Net Interest Expense 35 23 115 76
================================================
HIGHER INTEREST EXPENSE REDUCED QUARTERLY NET INCOME BY $12 MILLION
In late 2003 and early 2004, we refinanced our preferred securities with lower
cost debt. As a result, dividends on the preferred securities have been replaced
with interest expense on our new debt. This increase in interest expense has
been partially offset by the strong Canadian dollar, which lowered our US-dollar
denominated interest expense by $2 million in the quarter. Refinancing our
preferred securities reduced our effective interest rate by 17% compared to
2003.
THREE MONTHS NINE MONTHS
ENDED SEPTEMBER 30 ENDED SEPTEMBER 30
(CDN$ MILLIONS) 2004 2003 2004 2003
- ----------------------------------------------------------------------------------------------------------
Interest 46 35 142 107
Dividends on Preferred Securities -- 16 3 50
----------------------------------------------------
Total Financing Cost 46 51 145 157
====================================================
Effective Interest Rate (%) 6.8 8.2 6.9 8.2
----------------------------------------------------
INCOME TAXES
THREE MONTHS NINE MONTHS
ENDED SEPTEMBER 30 ENDED SEPTEMBER 30
(CDN$ MILLIONS) 2004 2003 2004 2003
- ---------------------------------------------------------------------------------------------------------
Current 73 60 189 164
Future 37 31 58 51
---------------------------------------------------
Provision for Income Taxes 110 91 247 215
===================================================
Effective Tax Rate (%) 33 34 31 24
---------------------------------------------------
EFFECTIVE TAX RATE FOR THE QUARTER DECREASES FROM 34% TO 33%
In 2004, a 1% corporate income tax rate reduction in Alberta resulted in a $15
million recovery of future income taxes in the first quarter. The low effective
tax rate for the first nine months of 2003 was the result of a reduction in tax
rates for Canadian resource activities, which created a recovery of future
income taxes of $76 million in the second quarter of 2003. Our effective tax
rate for 2004 is expected to be 31%.
Current income taxes include cash taxes in Yemen of $65 million (2003 - $51
million) for the quarter and $168 million (2003 - $150 million) year to date.
Our current income tax provision also includes current and alternative minimum
tax and state taxes in the US and capital taxes in Canada.
39
LIQUIDITY
CAPITAL STRUCTURE
SEPTEMBER 30 DECEMBER 31
(CDN$ MILLIONS) 2004 2003
- -------------------------------------------------------------------------------------------------------------
Bank Debt -- --
Long-Term Debt 2,438 2,776
------------- ---------------
2,438 2,776
Less: Current Assets (2,857) (2,859)
Plus: Current Liabilities 1,818 1,460
-----------------------------
Net Debt(1) 1,399 1,377
Preferred and Subordinated Securities 33 364
-----------------------------
Net Debt, including Preferred and Subordinated Securities 1,432 1,741
=============================
Shareholders' Equity, excluding Preferred and Subordinated Securities(2) 2,660 2,026
=============================
Notes:
1 Long-term debt less working capital.
2 At September 30, 2004, there were 129,018,817 common shares and US$460
million of unsecured subordinated securities outstanding. These subordinated
securities may be redeemed by the issuance of common shares at our option
after November 8, 2008. The number of shares to be issued will depend upon
the common share price on the redemption date.
In February 2004, we redeemed US$217 million of preferred securities and repaid
US$225 million of senior notes, which reduced shareholders' equity and debt,
respectively. We took advantage of the low interest rate environment in and
financed these repayments by issuing US$960 million of public debt in the fourth
quarter of 2003. Shareholders' equity remains strong with solid financial
results and $116 million of proceeds from the issuance of common shares.
Proceeds from the issuance of common shares are primarily from the exercise of
employee stock options.
CHANGE IN WORKING CAPITAL
SEPTEMBER 30 DECEMBER 31 INCREASE/
(CDN$ MILLIONS) 2004 2003 (DECREASE)
- -------------------------------------------------------------------------------------------------
Cash and Short-Term Investments 866 1,087 (221)
Accounts Receivable 1,549 1,423 126
Inventories and Supplies 400 270 130
Accounts Payable and Accrued Liabilities (1,768) (1,404) (364)
Other (8) 23 (31)
-------------------------------------------
Net Working Capital 1,039 1,399 (360)
===========================================
Cash and short-term investments decreased with the redemption of our preferred
securities and the repayment of our senior notes in February 2004. These
repayments have been offset in part by our solid year to date cash flow from
operations and proceeds received on the exercise of employee stock options. Oil
and gas receivables increased since year end reflecting stronger commodity
prices. Marketing receivables increased during the year from stronger crude oil
prices and higher natural gas marketing and trading activity.
The increase in inventories and supplies was driven largely by an increase in
our gas volumes in storage. Typically, our gas marketing group purchases gas for
injection into storage during the spring and summer when gas prices are lower.
These volumes are withdrawn during the winter when gas prices are higher. Higher
field inventory levels reflect the build up of supplies for use in our Block 51
development program in Yemen and in our fourth quarter drilling program in the
Gulf of Mexico.
Accounts payable and accrued liabilities are higher as a result of higher
capital accruals for the Long Lake project and our increased exploration
drilling during the quarter. Our accrued liabilities have increased since
year-end reflecting our tandem option plan obligation of $93 million. Marketing
payables increased as a result of higher natural gas marketing and trading
activity and the building of our storage position.
In December, other included a prepayment for the purchase of natural gas
inventory in 2004. This was included in inventory during the first quarter.
40
NET DEBT
Our net debt levels are directly related to our operating cash flows and our
capital expenditure activities. Since December 31, 2003, we have successfully
reduced net debt, including preferred and subordinated securities by $309
million:
NINE MONTHS
(CDN$ MILLIONS) ENDED SEPTEMBER 30
- -----------------------------------------------------------------------------
Capital Expenditures (1,086)
Cash Flow from Operations 1,353
--------------------
267
Dividends on Preferred Securities and Common Shares (42)
Issue of Common Shares 116
Other (32)
--------------------
Decrease in Net Debt, including Preferred and
Subordinated Securities 309
====================
OUTLOOK FOR REMAINDER OF 2004
We have reduced our 2004 full year production outlook to 243,000 to 249,000
boe/d before royalties. This change reflects reductions in our expectations for
Yemen (due to base declines) and the Gulf of Mexico (due to the slower than
anticipated ramp-up of production from Aspen following remediation of the
Aspen-1 well, delays in our shallow-water drilling program, lower than expected
production from Gunnison and storms in the Gulf). We expect to generate almost
$2 billion in cash flow from operations in 2004 assuming the following for the
remainder of the year:
- -----------------------------------------------------------------------------
WTI (US$/bbl) 40.00
NYMEX natural gas (US$/mmbtu) 5.50
US to Canadian dollar exchange rate 0.75
----------
Our 2004 capital investment program has been increased from $1.8 billion to
$1.9 billion.
Our future liquidity remains strong given our increasing cash flow from
operations and the ongoing strength of our balance sheet. We continue to
maintain a strong cash position and $1.7 billion of undrawn committed credit
facilities. As a result, we have the necessary resources to fund our capital
programs, dividend requirements and debt repayments, as well as the obligations
that arise from our day-to-day operations. We declared common share dividends of
$0.10 per share each quarter in 2004.
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 included these
obligations and commitments in our MD&A in our 2003 Annual Report on Form 10-K.
During the year, we have entered into new capital commitments totaling $455
million related to our major development projects. We expect to incur
approximately $345 million of these commitments in the next twelve months and
approximately $110 million in one to three years time.
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 2003 Annual Report on Form 10-K. There have been no
significant developments since year end.
NEW ACCOUNTING PRONOUNCEMENTS
In November 2003, the CICA approved an amendment to S.3860, FINANCIAL
INSTRUMENTS - DISCLOSURE AND PRESENTATION to clarify the difference between an
equity and liability instrument. An equity instrument exists only when an
instrument is settled in shares. This amendment is effective for fiscal years
beginning on or after November 1, 2004. Once adopted, the equity component of
our subordinated securities would be reclassified from equity to long-term debt,
and the dividends paid would be classified as interest expense. Adoption of this
amendment at September 30, 2004, would increase long-term debt by $33 million
and decrease subordinated securities by $33 million.
41
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, ESTIMATE, BUDGET, OUTLOOK or other similar words.
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 and MARKET RISK MANAGEMENT in Item 7 of
our 2003 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 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 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.
42
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We are exposed to all of the normal market risks inherent within the oil and gas
and chemicals business, including commodity price risk, foreign-currency rate
risk, interest rate risk and credit risk. We manage our operations to minimize
our exposure, as described in our 2003 Annual Report on Form 10-K. Our
sensitivities to key market risks for 2004 are as follows:
CASH FLOW NET
(CDN$ MILLIONS) FROM OPERATIONS INCOME
- -------------------------------------------------------------------------------------------------------
Estimated full year impact for 2004:
Crude Oil - US$1.00/bbl change in WTI 53 39
Natural Gas - US$0.50/mcf change in NYMEX 60 38
Foreign Exchange - $0.01 change in Cdn dollar to US dollar 30 15
-----------------------------
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. There has not been any change in the Company's internal
control over financial reporting during the third quarter of 2004 that has
materially affected, or is reasonably likely to materially affect, the Company's
internal control over financial reporting. During the third quarter, we
continued to improve and enhance our financial reporting systems by implementing
our existing Systems, Applications, and Products in Data Processing (SAP) system
into our chemical operations. The conversion of data and the implementation and
operation of SAP has been continually monitored and reviewed. Based on these
evaluations, there were no significant deficiencies or material weaknesses in
these internal controls requiring corrective action. As a result, no corrective
actions were taken.
43
PART II
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) 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.
(b) REPORTS ON FORM 8-K
During the quarter ended September 30, 2004, we filed or furnished the following
reports on Form 8-K:
o On July 15, 2004, we furnished a current report on Form 8-K under item
12 to furnish our press release announcing our second quarter results
for fiscal 2004.
44
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 18, 2004.
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)
45