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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, 2003
[_] 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]
[LOGO - NEXEN INC.]
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, 2003, there were 124,061,475 common shares issued and
outstanding.
NEXEN INC.
INDEX
PART I FINANCIAL INFORMATION PAGE
Item 1. Unaudited Consolidated Financial Statements:
Unaudited Consolidated Statement of Income for the Three and
Nine Months Ended September 30, 2003 and 2002........................... 3
Unaudited Consolidated Balance Sheet as at September 30, 2003
and December 31, 2002................................................... 4
Unaudited Consolidated Statement of Cash Flows for the Three and
Nine Months Ended September 30, 2003 and 2002........................... 5
Unaudited Consolidated Statement of Shareholders' Equity for the
Nine Months Ended September 30, 2003 and 2002........................... 6
Notes to Unaudited Consolidated Financial Statements.................... 7-22
Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations............................................... 23-36
Item 3. Quantitative and Qualitative Disclosures about Market Risk.............. 37
Item 4. Controls and Procedures................................................. 37
PART II OTHER INFORMATION
Item 4. Submission of Matters to a Vote of Security Holders..................... 38
Item 6. Exhibits and Reports on Form 8-K........................................ 38
Unless we indicate otherwise, all dollar amounts ($) are in Canadian dollars,
and production and reserves are our working interest before royalties. On
September 30, 2003, the noon-day exchange rate for Cdn $1.00 was US $0.7405 as
reported by the Bank of Canada. This report should be read in conjunction with
our 2002 Annual Report on Form 10-K.
Below is a list of terms specific to the oil and gas industry. They are used
throughout the Form 10-Q.
/d = per day mboe = thousand barrels of oil equivalent
bbl = barrel mmboe = million barrels of oil equivalent
mbbls = thousand barrels mcf = thousand cubic feet
mmbbls = million barrels mmcf = million cubic feet
mmbtu = million British thermal units bcf = billion cubic feet
boe = barrels of oil equivalent NGL = natural gas liquid
Oil equivalents are used to compare quantities of natural gas with crude oil by
expressing them in a common unit. To calculate equivalents, we use 1 bbl = 6 mcf
of natural gas.
Electronic copies of our filings with the Securities Exchange Commission (from
November 8, 2002 onward) are available, free of charge, through our web site
(www.nexeninc.com). Filings prior to November 8, 2002 are available, free of
charge, upon request, by contacting our investor relations department at (403)
699-5931.
2
NEXEN INC.
UNAUDITED CONSOLIDATED STATEMENT OF INCOME
FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30
Cdn$ millions
Three Months Nine Months
Ended September 30 Ended September 30
2003 2002 2003 2002
- ------------------------------------------------------------------------------------------------------------------
REVENUES
Net Sales (Note 1) 716 687 2,248 1,825
Marketing and Other (Notes 1 and 9) 131 118 451 361
Gain on Disposition of Assets -- -- -- 13
--------------------------------------------------
847 805 2,699 2,199
--------------------------------------------------
EXPENSES
Operating 187 185 577 558
Transportation and Other (Note 1) 104 117 350 349
General and Administrative 44 36 126 112
Depreciation, Depletion and Amortization 190 174 566 522
Exploration 30 32 109 106
Interest (Note 4) 23 29 76 80
--------------------------------------------------
578 573 1,804 1,727
--------------------------------------------------
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES 269 232 895 472
--------------------------------------------------
PROVISION FOR INCOME TAXES
Current 60 69 164 172
Future 31 13 51 (13)
--------------------------------------------------
91 82 215 159
--------------------------------------------------
NET INCOME FROM CONTINUING OPERATIONS 178 150 680 313
Net Income from Discontinued Operations (Note 10) 3 7 15 10
--------------------------------------------------
NET INCOME 181 157 695 323
Dividends on Preferred Securities, Net of Income Taxes 10 11 31 33
--------------------------------------------------
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS 171 146 664 290
==================================================
EARNINGS PER COMMON SHARE FROM CONTINUING OPERATIONS ($/share)
Basic (Note 7) 1.36 1.14 5.26 2.30
==================================================
Diluted (Note 7) 1.35 1.11 5.22 2.27
==================================================
EARNINGS PER COMMON SHARE ($/share)
Basic (Note 7) 1.38 1.20 5.38 2.38
==================================================
Diluted (Note 7) 1.37 1.17 5.34 2.35
==================================================
SEE ACCOMPANYING NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS.
3
NEXEN INC.
UNAUDITED CONSOLIDATED BALANCE SHEET
Cdn$ millions
September 30 December 31
2003 2002
- ---------------------------------------------------------------------------------------------------
ASSETS
CURRENT ASSETS
Cash and Short-Term Investments 354 59
Accounts Receivable (Note 2) 996 988
Inventories and Supplies (Note 3) 229 256
Other 44 26
---------------------------------
Total Current Assets 1,623 1,329
---------------------------------
PROPERTY, PLANT AND EQUIPMENT
Net of Accumulated Depreciation, Depletion and
Amortization of $4,499 (December 31, 2002 - $4,705) 4,696 4,863
GOODWILL 36 36
FUTURE INCOME TAX ASSETS 141 263
DEFERRED CHARGES AND OTHER ASSETS 93 69
---------------------------------
6,589 6,560
=================================
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Short-Term Borrowings (Note 4) -- 18
Accounts Payable and Accrued Liabilities 1,056 1,194
Accrued Interest Payable 21 39
Dividends Payable 9 9
---------------------------------
Total Current Liabilities 1,086 1,260
---------------------------------
LONG-TERM DEBT (Note 4) 1,624 1,844
FUTURE INCOME TAX LIABILITIES 834 873
DISMANTLEMENT AND SITE RESTORATION 170 191
OTHER DEFERRED CREDITS AND LIABILITIES 39 44
SHAREHOLDERS' EQUITY (Note 6)
Preferred Securities 724 724
Common Shares, no par value
Authorized: Unlimited
Outstanding: 2003 - 124,061,475 shares
2002 - 122,965,830 shares 471 440
Retained Earnings 1,706 1,069
Cumulative Foreign Currency Translation Adjustment (65) 115
---------------------------------
Total Shareholders' Equity 2,836 2,348
---------------------------------
COMMITMENTS AND CONTINGENCIES (Note 11)
6,589 6,560
=================================
SEE ACCOMPANYING NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS.
4
NEXEN INC.
UNAUDITED CONSOLIDATED STATEMENT OF CASH FLOWS
FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30
Cdn$ millions
Three Months Nine Months
Ended September 30 Ended September 30
2003 2002 2003 2002
- ------------------------------------------------------------------------------------------------------------------
OPERATING ACTIVITIES
Net Income from Continuing Operations 178 150 680 313
Net Income from Discontinued Operations 3 7 15 10
Charges and Credits to Income not Involving Cash (Note 8) 223 205 645 545
Exploration Expense 30 32 109 106
Changes in Non-Cash Working Capital (Note 8) (125) 15 (165) (92)
Other (13) (7) (42) (13)
--------------------------------------------------
296 402 1,242 869
FINANCING ACTIVITIES
Proceeds from Long-Term Notes and Debentures -- -- -- 790
Proceeds from (Repayment of) Term Credit Facilities, Net (9) 89 91 (328)
Repayment of Short-Term Borrowings (19) (35) (18) (19)
Dividends on Preferred Securities (16) (18) (50) (54)
Dividends on Common Shares (9) (9) (27) (27)
Issue of Common Shares 21 7 31 46
Other -- -- -- (23)
--------------------------------------------------
(32) 34 27 385
INVESTING ACTIVITIES
Capital Expenditures
Exploration and Development (277) (405) (911) (1,057)
Proved Property Acquisitions -- -- (164) --
Chemicals, Corporate and Other (9) (9) (22) (122)
Proceeds on Disposition of Assets 268 2 268 34
Changes in Non-Cash Working Capital (Note 8) 15 (58) (16) (31)
--------------------------------------------------
(3) (470) (845) (1,176)
EFFECT OF EXCHANGE RATE CHANGES ON CASH
AND SHORT-TERM INVESTMENTS 1 8 (129) (16)
--------------------------------------------------
INCREASE (DECREASE) IN CASH AND SHORT-TERM INVESTMENTS 262 (26) 295 62
CASH AND SHORT-TERM INVESTMENTS - BEGINNING OF PERIOD 92 149 59 61
--------------------------------------------------
CASH AND SHORT-TERM INVESTMENTS - END OF PERIOD 354 123 354 123
==================================================
SEE ACCOMPANYING NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS.
5
NEXEN INC.
UNAUDITED CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2003 AND SEPTEMBER 30, 2002
Cdn$ millions
Cumulative
Foreign
Currency
Preferred Common Retained Translation
Securities Shares Earnings Adjustment
- ---------------------------------------------------------------------------------------------------------------------------------
DECEMBER 31, 2002 724 440 1,069 115
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 1,706 (65)
=====================================================================
Cumulative
Foreign
Currency
Preferred Common Retained Translation
Securities Shares Earnings Adjustment
- ---------------------------------------------------------------------------------------------------------------------------------
DECEMBER 31, 2001 724 389 697 94
Exercise of Stock Options -- 26 -- --
Issue of Common Shares -- 20 -- --
Net Income -- -- 323 --
Dividends on Preferred Securities, Net of
Income Taxes -- -- (33) --
Dividends on Common Shares -- -- (27) --
Translation Adjustment, Net of Income Taxes -- -- -- (8)
---------------------------------------------------------------------
SEPTEMBER 30, 2002 724 435 960 86
=====================================================================
SEE ACCOMPANYING NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS.
6
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 13. 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, 2003 and the
results of our operations and our cash flows for the three and nine months ended
September 30, 2003 and 2002.
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, environmental and dismantlement
liabilities, income taxes and determination of proved reserves on an ongoing
basis. Changes in facts and circumstances may result in revised estimates and
actual results may differ from these estimates. The results of operations and
cash flows for the three and nine months ended September 30, 2003 are not
necessarily indicative of the results of operations or cash flows to be expected
for the year ending December 31, 2003.
These Unaudited Consolidated Financial Statements should be read in conjunction
with our Audited Consolidated Financial Statements included in our 2002 Annual
Report on Form 10-K. The accounting policies we follow are in Note 1 of the
Audited Consolidated Financial Statements included in our 2002 Annual Report on
Form 10-K.
CHANGES IN ACCOUNTING POLICIES - MARKETING ACTIVITIES
MARK-TO-MARKET
On October 25, 2002, regulators changed accounting principles, eliminating
mark-to-market accounting for our marketing inventories and our non-derivative
energy contracts. Under the new principles:
o We measure marketing inventories at the lower of cost or market; and
o We record non-derivative energy contracts, including our transportation and
storage capacity contracts, at cost as incurred.
We recorded the change to inventory prospectively as the effects on previous
periods could not be determined. Inventories at October 25, 2002 were attributed
a cost based on their market value on that date. Inventories purchased after
October 25, 2002 have been recorded at cost. We removed the mark-to-market on
our transportation contracts from earnings retroactively to the beginning of
2002. The impact on previous years was immaterial.
PRESENTATION OF TRANSPORTATION
During 2002, we adopted the new interpretation of the Emerging Issues Committee
relating to the presentation of transportation costs for which we are
reimbursed. We pay for the transportation of the crude oil, natural gas and
chemicals products that we market, and then bill our customers for the
transportation. Under the new interpretation, this transportation is presented
as a cost to us. Previously, we netted this cost against our revenue. We show
these costs as transportation and other on the Unaudited Consolidated Statement
of Income, resulting in the following increases:
Three Months Nine Months
Ended September 30 Ended September 30
2003 2002 2003 2002
- ------------------------------------------------------------------------------------------
Increase to:
Net Sales 8 9 26 25
Marketing and Other 98 106 319 315
Transportation and Other 106 115 345 340
------------------------------------------------------
Certain comparative figures have been reclassified to ensure consistency with
current year presentation.
7
2. ACCOUNTS RECEIVABLE
September 30 December 31
2003 2002
- --------------------------------------------------------------------------------
Trade
Oil and Gas
Marketing 673 574
Other 258 330
Chemicals and Other 51 59
-------------------------------
982 963
Non-Trade 30 34
-------------------------------
1,012 997
Allowance for Doubtful Accounts (16) (9)
-------------------------------
996 988
===============================
3. INVENTORIES AND SUPPLIES
September 30 December 31
2003 2002
- --------------------------------------------------------------------------------
Finished Products
Oil and Gas
Marketing 105 130
Other 5 --
Chemicals and Other 7 13
-------------------------------
117 143
Work in Process 6 6
Field Supplies 106 107
-------------------------------
229 256
===============================
4. LONG-TERM DEBT AND SHORT-TERM BORROWINGS
September 30 December 31
2003 2002
- --------------------------------------------------------------------------------
Unsecured Syndicated Term Credit Facilities -- --
Unsecured Redeemable Notes, due 2004 (a) 304 355
Unsecured Redeemable Debentures, due 2006 100 108
Unsecured Redeemable Medium Term Notes, due 2007 150 150
Unsecured Redeemable Medium Term Notes, due 2008 125 125
Unsecured Redeemable Notes, due 2028 270 316
Unsecured Redeemable Notes, due 2032 675 790
-------------------------------
1,624 1,844
===============================
(a) UNSECURED REDEEMABLE NOTES, DUE 2004
The Unsecured Redeemable Notes are due in February 2004. We intend to refinance
this obligation with existing long-term debt facilities, and accordingly, it has
not been included in current liabilities at September 30, 2003.
(b) SHORT-TERM BORROWINGS
Occasionally, we sell the future proceeds of our accounts receivable but retain
a 10% exposure to related credit losses. At September 30, 2003, we sold $nil of
accounts receivable proceeds (December 31, 2002 - $178 million). The retained
credit exposure of $nil (December 31, 2002 - $18 million) is included in
short-term borrowings.
8
(c) INTEREST EXPENSE
Three Months Nine Months
Ended September 30 Ended September 30
2003 2002 2003 2002
- --------------------------------------------------------------------------------
Long-Term Debt 32 36 100 95
Other 3 2 7 5
-----------------------------------------------------
Total 35 38 107 100
Less: Capitalized 12 9 31 20
-----------------------------------------------------
23 29 76 80
=====================================================
Capitalized interest relates to and is included as part of the cost of oil and
gas properties. The capitalization rates are based on our weighted-average cost
of borrowings.
5. DERIVATIVE INSTRUMENTS AND FINANCIAL RISK MANAGEMENT
(a) COMMODITY PRICE RISK MANAGEMENT
NON-TRADING ACTIVITIES
In March 2003, we sold WTI and NYMEX gas forward contracts for the next 12
months to lock in a portion of our return on the purchase of the remaining 40%
interest in the Aspen field. The forward contracts fix our price per bbl of oil
and our price per mmbtu of gas at the contract prices for the hedged volumes,
less applicable price differentials. At September 30, 2003, the fair value of
the unexpired contracts was a gain of $1 million, which represents the change in
fair value since March 2003. This gain has not been recognized as we recognize
gains or losses on these contracts in the same periods as the hedged production
is sold.
Hedged Volumes Period Fixed Price (US$)
- --------------------------------------------------------------------------------
5,000 bbls/d April 2003 - March 2004 28.50/bbl
12,000 mmbtu/d April 2003 - March 2004 5.35/mmbtu
TRADING ACTIVITIES
Our marketing operation engages in crude oil and natural gas marketing
activities to enhance prices received for our own production and for energy
trading. As part of our energy trading strategy, we inject natural gas into
storage to take advantage of seasonal changes in demand. These storage positions
expose us to changes in market prices. To mitigate this price risk we use
futures contracts or a combination of futures contracts and basis swaps to hedge
our exposure.
As indicated in Note 1, regulators changed accounting principles that eliminated
mark-to-market accounting for our marketing inventories. Accordingly, our
financial contracts were marked-to-market while our inventory was not. To better
match our accounting with our economic exposure, we began designating certain
NYMEX natural gas futures contracts and AECO/NYMEX basis swaps in July 2003 as
hedges of our price risk on the future sale of our inventory.
We have designated in writing certain of our financial contracts as cash flow
hedges. At September 30, 2003, the total fair value of these contracts was $3
million and the change in fair value since designation was a net gain of $5
million. The change in the anticipated cash flows from the sale of inventory
since we designated certain financial contracts was a net loss of $5 million. We
will recognize the realized gains or losses on these contracts in the same
periods as the gas in storage is sold.
NYMEX NATURAL GAS FUTURES
Notional Amount (mmcf) Month Price (US$/mcf)
- --------------------------------------------------------------------------------
540 October 2003 5.48
1,000 November 2003 5.02
1,180 December 2003 5.81
8,030 January 2004 5.31 - 5.92
1,800 February 2004 5.16 - 5.38
AECO/NYMEX BASIS SWAPS
Notional Amount (mmcf) Month Price (US$/mcf)
- --------------------------------------------------------------------------------
1,000 January 2004 0.59
9
(b) FOREIGN CURRENCY EXCHANGE RATE RISK MANAGEMENT
We manage our exposure to fluctuations between US and Canadian dollars by
minimizing the need to convert between the two currencies. Net revenue from our
foreign operations and our US-dollar borrowings are generally used to fund
US-dollar capital expenditures and debt repayments. All of our US-dollar debt
was designated as a hedge against our net investment in foreign operations. In
early 2003, we de-designated our unsecured syndicated term credit facilities
from the hedge as funds drawn were used to fund US-dollar working capital in our
Canadian operations. Our remaining US-dollar debt continued to be designated as
a hedge against our net investment in foreign operations. In the third quarter
of 2003, we re-designated our unsecured syndicated term credit facilities as a
hedge of our net investment in foreign operations, as US-dollar funds drawn were
no longer funding working capital in our Canadian operations. The foreign
exchange gains or losses relating to the designated debt are included in the
cumulative foreign currency translation adjustment in shareholders' equity,
while exchange gains and losses on the unsecured syndicated term credit
facilities during the de-designated period were included in marketing and other
on the Unaudited Consolidated Statement of Income.
(c) CARRYING VALUE AND ESTIMATED FAIR VALUE OF DERIVATIVE INSTRUMENTS
Assets/(Liabilities) SEPTEMBER 30, 2003 DECEMBER 31, 2002
- -------------------------------------------------------------------------------------------------------------
Carrying Fair Unrealized Carrying Fair Unrealized
Value Value Gain/(Loss) Value Value Gain/(Loss)
----------------------------------------- ------------------------------------------
Long-Term Debt (1,624) (1,829) (205) (1,844) (1,948) (104)
Preferred Securities (724) (651) 73 (724) (756) (32)
-------------------------------------------------------------------------------------
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 or
amounts derived from valuation models. 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. Amounts receivable and
payable by our marketing operations related to derivative instruments are equal
to fair value as we use the mark-to-market method to value them. Amounts related
to derivative instruments included in deferred charges and other assets and
other deferred credits and liabilities are $40 million and $6 million,
respectively. These derivative instruments are held by our marketing operation
and settle beyond 12 months.
6. SHAREHOLDERS' EQUITY
(a) ESTIMATED FAIR VALUE OF STOCK OPTIONS
We use the intrinsic-value method of accounting for stock options. Under this
method, no compensation expense is recognized for stock options granted to
employees and directors. As required under GAAP, we also make certain pro forma
disclosures as if the fair-value method of accounting was applied. The
assumptions for the three and nine months ended September 30, 2003 are the same
as for the year ended December 31, 2002, as described in Note 8(f) to the
Audited Consolidated Financial Statements included in our 2002 Annual Report on
Form 10-K.
The following shows our pro forma net income and earnings per common share had
we applied the fair-value method of accounting to all stock options outstanding:
Three Months Nine Months
Ended September 30 Ended September 30
2003 2002 2003 2002
- ------------------------------------------------------------------------------------------------------
Net Income Attributable to Common Shareholders:
As Reported 171 146 664 290
Less: Fair Value of Stock Options 6 6 19 18
-----------------------------------------------------
Pro Forma 165 140 645 272
=====================================================
Earnings Per Common Share ($/share)
Basic as Reported 1.38 1.20 5.38 2.38
=====================================================
Pro Forma 1.33 1.14 5.22 2.23
=====================================================
Diluted as Reported 1.37 1.17 5.34 2.35
=====================================================
Pro Forma 1.32 1.13 5.18 2.20
=====================================================
10
(b DIVIDENDS
Dividends per common share for the three months ended September 30, 2003 were
$0.075 (2002 - $0.075). Dividends per common share for the nine months ended
September 30, 2003 were $0.225 (2002 - $0.225).
7. EARNINGS PER COMMON SHARE
We calculate basic and diluted earnings per common share from continuing
operations using net income from continuing operations less dividends on
preferred securities, net of income taxes, and the weighted-average number of
common shares outstanding and the weighted-average number of diluted common
shares outstanding, respectively. We calculate basic and diluted earnings per
common share using net income attributable to common shareholders, and the
weighted-average number of common shares outstanding and the weighted-average
number of diluted common shares outstanding, respectively.
Three Months Nine Months
Ended September 30 Ended September 30
(millions of shares) 2003 2002 2003 2002
- ----------------------------------------------------------------------------------------------------------------------
Weighted-average number of common shares outstanding 123.8 122.8 123.4 122.2
Shares issuable pursuant to stock options 8.9 8.1 5.1 8.1
Shares to be purchased from proceeds of stock options (7.4) (6.4) (4.1) (6.5)
------------------------------------------------------
Weighted-average number of diluted common shares outstanding 125.3 124.5 124.4 123.8
======================================================
In calculating diluted earnings per common share for the three months ended
September 30, 2003, we excluded 36,000 options (2002 - 20,500), and for the nine
months ended September 30, 2003 we excluded 4,125,869 options (2002 - 35,000),
because the exercise price was greater than the average market price of our
common shares in those periods. During the periods presented, outstanding stock
options were the only dilutive instrument.
8. CASH FLOWS
(a) CHARGES AND CREDITS TO INCOME NOT INVOLVING CASH
Three Months Nine Months
Ended September 30 Ended September 30
2003 2002 2003 2002
- ----------------------------------------------------------------------------------------------------------------------
Depreciation, Depletion and Amortization 190 174 566 522
Gain on Disposition of Assets -- -- -- (13)
Future Income Taxes 31 13 51 (13)
Loss (Gain) on Foreign Exchange (4) (1) (8) 3
Non-Cash Items included in Discontinued Operations 7 16 35 46
Other (1) 3 1 --
------------------------------------------------------
223 205 645 545
======================================================
(b) CHANGES IN NON-CASH WORKING CAPITAL
Three Months Nine Months
Ended September 30 Ended September 30
2003 2002 2003 2002
- ----------------------------------------------------------------------------------------------------------------------
Operating Activities
Accounts Receivable 55 79 (33) (267)
Inventories and Supplies (1) 78 15 29
Other Current Assets (25) 12 (23) (7)
Accounts Payable and Accrued Liabilities (142) (139) (110) 150
Accrued Interest Payable (12) (15) (14) 3
------------------------------------------------------
(125) 15 (165) (92)
Investing Activities
Accounts Payable and Accrued Liabilities 15 (58) (16) (31)
------------------------------------------------------
Total (110) (43) (181) (123)
======================================================
11
(c) OTHER CASH FLOW INFORMATION
Three Months Nine Months
Ended September 30 Ended September 30
2003 2002 2003 2002
- ----------------------------------------------------------------------------------------------------------------------
Interest Paid 45 53 117 95
Income Taxes Paid 48 68 155 182
------------------------------------------------------
9. MARKETING AND OTHER
Three Months Nine Months
Ended September 30 Ended September 30
2003 2002 2003 2002
- ----------------------------------------------------------------------------------------------------------------------
Marketing Revenue, Net 121 114 416 355
Interest 2 2 6 6
Foreign Exchange Gains (Losses) 4 1 8 (3)
Other 4 1 21 3
------------------------------------------------------
131 118 451 361
======================================================
Other year to date includes $12 million 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.
10. DISCONTINUED OPERATIONS
On August 28, 2003, we sold a number of our non-core conventional light oil
properties located in southeast Saskatchewan in Canada. Net proceeds were $268
million and there was no gain or loss on the sale. The disposition was
undertaken to improve our capacity to fund our major development projects over
the next few years. The results of operations from these properties are detailed
below and shown as discontinued operations in our Unaudited Consolidated
Statement of Income.
Three Months Nine Months
Ended September 30 Ended September 30
2003 2002 2003 2002
- ----------------------------------------------------------------------------------------------------------------------
Revenues
Net Sales 14 29 66 76
Expenses
Operating 4 6 16 20
Depreciation, Depletion and Amortization 3 9 20 26
Exploration -- 1 1 7
------------------------------------------------------
Income before Income Taxes 7 13 29 23
Future Income Taxes 4 6 14 13
------------------------------------------------------
Net Income 3 7 15 10
======================================================
Earnings Per Common Share ($/share)
Basic (Note 7) 0.02 0.06 0.12 0.08
======================================================
Diluted (Note 7) 0.02 0.06 0.12 0.08
======================================================
The assets and liabilities on the Unaudited Consolidated Balance Sheet include
the following amounts with respect to discontinued operations.
September 30 December 31
2003 2002
- --------------------------------------------------------------------------------
Accounts Receivable -- 12
Property, Plant and Equipment -- 289
Accounts Payable and Accrued Liabilities 3 9
Dismantlement and Site Restoration -- 10
---------------------------------
12
11. COMMITMENTS AND CONTINGENCIES
As described in Note 10 to the Audited Consolidated Financial Statements
included in our 2002 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
consolidated financial position or results of operations.
12. 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 2002 Annual Report on Form
10-K.
THREE MONTHS ENDED SEPTEMBER 30, 2003
(Cdn$ millions) Corporate
and
Oil and Gas Syncrude Chemicals Other Total
- ------------------------------------------------------------------------------------------------------------------------------
United Other
Yemen Canada (1) States Australia Countries (2) Marketing (3)
---------------------------------------------------------------
Net Sales 201 144 170 19 15 7 66 94 -- 716
Marketing and Other 1 1 1 -- -- 121 -- 1 6(4) 131
Gain on Disposition of Assets -- -- -- -- -- -- -- -- -- --
------------------------------------------------------------------------------------------------
Total Revenues 202 145 171 19 15 128 66 95 6 847
Less: Expenses
Operating 23 38 20 9 3 5 30 59 -- 187
Transportation and Other -- -- (2)(5) -- -- 98 -- 8 -- 104
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(6) -- -- -- -- 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 (7) 91
Add: Net Income from
Discontinued Operations 3
------
Net Income 181
======
Identifiable Assets 597 1,831 1,642 36 155 991(8) 651 467 219 6,589
================================================================================================
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
================================================================================================
Notes:
1 Excludes results of the non-core conventional light oil assets in southeast
Saskatchewan that were sold. These results are shown as discontinued
operations (see Note 10).
2 Includes results of operations from producing activities in Nigeria and
Colombia.
3 Includes results of operations from a natural gas-fired generating facility
in Alberta. In 2002, these results were included in Corporate and Other.
4 Includes interest income of $2 million and foreign exchange gains of $4
million.
5 Includes the recovery of previously incurred property damage costs from our
insurers. The costs were incurred to repair damage caused by Hurricane
Lili.
6 Includes exploration activities primarily in Nigeria and Colombia.
7 Includes Yemen cash taxes of $51 million.
8 Approximately 78% of Marketing's identifiable assets are accounts
receivable and inventories.
13
NINE MONTHS ENDED SEPTEMBER 30, 2003
(Cdn$ millions) Corporate
and
Oil and Gas Syncrude Chemicals Other Total
- ------------------------------------------------------------------------------------------------------------------------------
United Other
Yemen Canada (1) States Australia Countries (2) Marketing (3)
---------------------------------------------------------------
Net Sales 620 475 549 64 51 18 187 284 -- 2,248
Marketing and Other 4 2 14 -- -- 416 -- 1 14(4) 451
Gain on Disposition of Assets -- -- -- -- -- -- -- -- -- --
------------------------------------------------------------------------------------------------
Total Revenues 624 477 563 64 51 434 187 285 14 2,699
Less: Expenses
Operating 65 107 66 30 13 17 98 181 -- 577
Transportation and Other 3 -- 1 -- -- 319 -- 27 -- 350
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(5) -- -- -- -- 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 (6) 215
Add: Net Income from
Discontinued Operations 15
------
Net Income 695
======
Identifiable Assets 597 1,831 1,642 36 155 991(7) 651 467 219 6,589
================================================================================================
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(8) -- -- -- -- -- -- 164
------------------------------------------------------------------------------------------------
173 247 446 2 71 -- 136 6 16 1,097
================================================================================================
Notes:
1 Excludes results of the non-core conventional light oil assets in southeast
Saskatchewan that were sold. These results are shown as discontinued
operations (see Note 10).
2 Includes results of operations from producing activities in Nigeria and
Colombia.
3 Includes results of operations from a natural gas-fired generating facility
in Alberta. In 2002, these results were included in Corporate and Other.
4 Includes interest income of $6 million and foreign exchange gains of $8
million.
5 Includes exploration activities primarily in Nigeria, Colombia and Brazil.
6 Includes Yemen cash taxes of $150 million and a $76 million future tax
recovery due to a tax rate reduction for Canadian resource activities.
7 Approximately 78% of Marketing's identifiable assets are accounts
receivable and inventories.
8 On March 27, 2003 we acquired the residual 40% interest in Aspen in the
Gulf of Mexico for US $109 million.
14
THREE MONTHS ENDED SEPTEMBER 30, 2002
(Cdn$ millions) Corporate
and
Oil and Gas Syncrude Chemicals Other (1) Total
- ------------------------------------------------------------------------------------------------------------------------------
United Other
Yemen Canada (2) States Australia Countries (3) Marketing
-----------------------------------------------------------
Net Sales 214 144 72 60 23 -- 75 97 2 687
Marketing and Other -- 1 -- -- -- 114 -- -- 3(4) 118
Gain on Disposition of Assets -- -- -- -- -- -- -- -- -- --
------------------------------------------------------------------------------------------------
Total Revenues 214 145 72 60 23 114 75 97 5 805
Less: Expenses
Operating 21 38 21 12 8 -- 24 60 1 185
Transportation and Other -- -- 2 -- -- 106 -- 9 -- 117
General and Administrative 2 4 3 -- 7 8 -- 4 8 36
Depreciation, Depletion and
Amortization 40 54 34 15 9 2 4 13 3 174
Exploration 1 6 8 1 16(5) -- -- -- -- 32
Interest -- -- -- -- -- -- -- -- 29 29
------------------------------------------------------------------------------------------------
Income (Loss) from Continuing
Operations before Income
Taxes 150 43 4 32 (17) (2) 47 11 (36) 232
======================================================================================
Less: Provision for Income
Taxes (6) 82
Add: Net Income from
Discontinued Operations 7
------
Net Income 157
======
Identifiable Assets 655 2,143 1,246 107 146 784(7) 487 540 231 6,339
================================================================================================
Capital Expenditures
Development and Other 48 44 199 -- 3 1 40 6 2 343
Exploration 3 13 33 2 20 -- -- -- -- 71
------------------------------------------------------------------------------------------------
51 57 232 2 23 1 40 6 2 414
================================================================================================
Notes:
1 Includes results of operations from a natural gas-fired generating facility
in Alberta.
2 Excludes results of the non-core conventional light oil assets in southeast
Saskatchewan that were sold. These results are shown as discontinued
operations (see Note 10).
3 Includes results of operations from producing activities in Nigeria and
Colombia.
4 Includes interest income of $2 million and foreign exchange gains of $1
million.
5 Includes exploration activities primarily in Nigeria and Colombia.
6 Includes Yemen cash taxes of $57 million.
7 Approximately 83% of Marketing's identifiable assets are accounts
receivable and inventories.
15
NINE MONTHS ENDED SEPTEMBER 30, 2002
(Cdn$ millions) Corporate
and
Oil and Gas Syncrude Chemicals Other (1) Total
- ------------------------------------------------------------------------------------------------------------------------------
United Other
Yemen Canada (2) States Australia Countries (3) Marketing
-----------------------------------------------------------
Net Sales 576 404 212 125 60 -- 173 268 7 1,825
Marketing and Other -- 2 -- -- -- 355 -- 1 3(4) 361
Gain on Disposition of Assets -- -- -- -- -- -- -- -- 13(5) 13
------------------------------------------------------------------------------------------------
Total Revenues 576 406 212 125 60 355 173 269 23 2,199
Less: Expenses
Operating 60 113 70 37 19 -- 87 168 4 558
Transportation and Other -- -- 2 -- -- 315 -- 29 3 349
General and Administrative 4 17 7 -- 16 23 -- 16 29 112
Depreciation, Depletion and
Amortization 114 166 99 43 36 6 10 38 10 522
Exploration 20 21 31 2 32(6) -- -- -- -- 106
Interest -- -- -- -- -- -- -- -- 80 80
------------------------------------------------------------------------------------------------
Income (Loss) from Continuing
Operations before Income
Taxes 378 89 3 43 (43) 11 76 18 (103) 472
======================================================================================
Less: Provision for Income
Taxes(7) 159
Add: Net Income from
Discontinued Operations 10
------
Net Income 323
======
Identifiable Assets 655 2,143 1,246 107 146 784(8) 487 540 231 6,339
================================================================================================
Capital Expenditures
Development and Other 143 172 394 46 13 1 91 36 85 981
Exploration 22 47 88 3 38 -- -- -- -- 198
------------------------------------------------------------------------------------------------
165 219 482 49 51 1 91 36 85(9) 1,179
================================================================================================
Notes:
1 Includes results of operations from a natural gas-fired generating facility
in Alberta.
2 Excludes results of the non-core conventional light oil assets in southeast
Saskatchewan that were sold. These results are shown as discontinued
operations (see Note 10).
3 Includes results of operations from producing activities in Nigeria and
Colombia.
4 Includes interest income of $6 million and foreign exchange losses of $3
million.
5 The Moose Jaw asphalt operation was disposed of on January 2, 2002 for
proceeds of $27 million, plus working capital.
6 Includes exploration activities primarily in Nigeria and Colombia.
7 Includes Yemen cash taxes of $149 million.
8 Approximately 83% of Marketing's identifiable assets are accounts
receivable and inventories.
9 Includes $67 million related to the buy out of a lease agreement for a
natural gas-fired generating facility in Alberta.
16
13. DIFFERENCES BETWEEN CANADIAN AND US GENERALLY ACCEPTED ACCOUNTING
PRINCIPLES
The Unaudited Consolidated Financial Statements have been prepared in accordance
with Canadian GAAP. US GAAP Unaudited Consolidated Financial Statements and
summaries of differences from Canadian GAAP are as follows:
(a) UNAUDITED CONSOLIDATED STATEMENT OF INCOME - US GAAP FOR THE THREE AND
NINE MONTHS ENDED SEPTEMBER 30
Three Months Nine Months
Ended September 30 Ended September 30
(Cdn$ millions) 2003 2002 2003 2002
- -----------------------------------------------------------------------------------------------------------------------------
REVENUES
Net Sales (iii) 716 687 2,248 1,825
Marketing and Other (v); (xi) 143 118 464 361
----------------------------------------------------
859 805 2,712 2,186
----------------------------------------------------
EXPENSES
Operating 187 185 577 558
Transportation and Other (viii) 104 117 350 336
General and Administrative 44 36 126 112
Depreciation, Depletion and Amortization (ii); (ix) 199 186 604 557
Exploration 30 32 109 106
Interest (i) 39 47 126 134
----------------------------------------------------
603 603 1,892 1,803
----------------------------------------------------
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES 256 202 820 383
----------------------------------------------------
PROVISION FOR INCOME TAXES
Current 60 69 164 172
Deferred (i) - (xi) 29 6 111 (34)
----------------------------------------------------
89 75 275 138
----------------------------------------------------
NET INCOME FROM CONTINUING OPERATIONS BEFORE CUMULATIVE EFFECT
OF CHANGES IN ACCOUNTING PRINCIPLES 167 127 545 245
Net (Loss) Income from Discontinued Operations (ii) (19) 7 (7) 10
Cumulative Effect of Changes in Accounting Principles,
Net of Income Taxes (ix); (xi) (11) -- (48) --
----------------------------------------------------
NET INCOME - US GAAP(1) 137 134 490 255
====================================================
EARNINGS PER COMMON SHARE ($/share)
Basic (Note 7)
Net Income from Continuing Operations 1.35 1.03 4.42 2.01
Net (Loss) Income from Discontinued Operations (Note 10) (0.15) 0.06 (0.06) 0.08
Cumulative Effect of Changes in Accounting Principles (0.09) -- (0.39) --
----------------------------------------------------
1.11 1.09 3.97 2.09
====================================================
Diluted (Note 7)
Net Income from Continuing Operations 1.33 1.02 4.39 1.98
Net (Loss) Income from Discontinued Operations (Note 10) (0.15) 0.06 (0.06) 0.08
Cumulative Effect of Changes in Accounting Principles (0.09) -- (0.39) --
----------------------------------------------------
1.09 1.08 3.94 2.06
====================================================
17
Note:
1 RECONCILIATION OF CANADIAN AND US GAAP NET INCOME
Three Months Nine Months
Ended September 30 Ended September 30
(Cdn$ millions) 2003 2002 2003 2002
-----------------------------------------------------------------------------------------------------------
Net Income - Canadian GAAP 181 157 695 323
Impact of US Principles, Net of Income Taxes:
Fair Value of Currency Swap (v) 3 -- 4 --
Fair Value of Preferred Securities (xi) 5 -- 5 --
Depreciation, Depletion and Amortization (ii); (ix) (9) (12) (37) (35)
Dividends on Preferred Securities (i) (10) (11) (31) (33)
Future Income Taxes (x) -- -- (76) --
Loss on Disposition (ii) (22) -- (22) --
Cumulative Effect of Changes
in Accounting Principles (ix); (xi) (11) -- (48) --
--------------------------------------------------
Net Income - US GAAP 137 134 490 255
==================================================
(b) UNAUDITED CONSOLIDATED BALANCE SHEET - US GAAP
September 30 December 31
(Cdn$ millions) 2003 2002
- -----------------------------------------------------------------------------------------------------------------------------
ASSETS
CURRENT ASSETS
Cash and Short-Term Investments 354 59
Accounts Receivable (iii) 1,002 990
Inventories and Supplies 229 256
Other 44 26
---------------------------------
Total Current Assets 1,629 1,331
PROPERTY, PLANT AND EQUIPMENT
Net of Accumulated Depreciation, Depletion and
Amortization of $4,895 (December 31, 2002 - $4,992) (ii); (ix) 4,935 5,064
GOODWILL 36 36
DEFERRED INCOME TAX ASSETS 141 263
DEFERRED CHARGES AND OTHER ASSETS (i); (vi) 97 70
---------------------------------
6,838 6,764
=================================
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Short-term Borrowings -- 18
Accounts Payable and Accrued Liabilities (iii) 1,056 1,200
Accrued Interest Payable 21 39
Dividends Payable 9 9
---------------------------------
Total Current Liabilities 1,086 1,266
---------------------------------
LONG-TERM DEBT (i); (vi); (xi) 2,259 2,575
DEFERRED INCOME TAX LIABILITIES (i) - (xi) 888 876
DISMANTLEMENT AND SITE RESTORATION (ix) -- 191
ASSET RETIREMENT OBLIGATION (ix) 341 --
OTHER DEFERRED CREDITS AND LIABILITIES (vii) 43 44
SHAREHOLDERS' EQUITY
Common Shares, no par value
Authorized: Unlimited
Outstanding: 2003 - 124,061,475 shares
2002 - 122,965,830 shares 471 440
Retained Earnings (i); (ii); (v); (ix); (x); (xi) 1,743 1,280
Accumulated Other Comprehensive Income (i); (iii); (iv); (vii) 7 92
---------------------------------
Total Shareholders' Equity 2,221 1,812
---------------------------------
COMMITMENTS AND CONTINGENCIES
6,838 6,764
=================================
18
(c) UNAUDITED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME - US GAAP FOR
THE THREE AND NINE MONTHS ENDED SEPTEMBER 30
Three Months Nine Months
Ended September 30 Ended September 30
(Cdn$ millions) 2003 2002 2003 2002
- -----------------------------------------------------------------------------------------------------------------------------
Net Income - US GAAP 137 134 490 255
Other Comprehensive Income, net of income taxes:
Translation Adjustment (i); (iv) (2) (17) (89) (3)
Unrealized Mark-to-Market Gain (Loss) (iii) 5 -- 4 --
----------------------------------------------------
Comprehensive Income 140 117 405 252
====================================================
(d) UNAUDITED CONSOLIDATED STATEMENT OF CASH FLOWS
Under US principles, dividends on preferred securities of $16 million and $50
million for the three and nine months ended September 30, 2003, respectively
(September 30, 2002 - $18 million and $54 million) that are included in
financing activities would be reported in operating activities.
Under US principles, geological and geophysical costs of $10 million and $34
million for the three and nine months ended September 30, 2003, respectively
(September 30, 2002 - $13 million and $48 million) that are included in
investing activities would be reported in operating activities.
(e) OTHER SUPPLEMENTARY INFORMATION
Three Months Nine Months
Ended September 30 Ended September 30
2003 2002 2003 2002
- -----------------------------------------------------------------------------------------------------------------------------
Pro Forma Earnings - Fair-Value Method of Accounting
for Stock Options - US GAAP
Net Income - US GAAP 137 134 490 255
As Reported
Less: Fair Value of Stock Options 6 6 19 18
----------------------------------------------------
Pro Forma 131 128 471 237
====================================================
Earnings Per Common Share ($/share)
Basic as Reported 1.11 1.09 3.97 2.09
====================================================
Pro Forma 1.06 1.04 3.82 1.94
====================================================
Diluted as Reported 1.09 1.08 3.94 2.06
====================================================
Pro Forma 1.04 1.03 3.79 1.91
====================================================
NOTES:
i. Under US principles, the preferred securities are classified as
long-term debt rather than shareholders' equity. The pre-tax dividends
are included in interest expense, and the related income tax is
included in the provision for income taxes in the Unaudited
Consolidated Statement of Income. The related pre-tax issue costs are
included in deferred charges and other assets rather than as an
after-tax charge to retained earnings. The foreign-currency translation
gains or losses are included in accumulated other comprehensive income
in the Unaudited Consolidated Balance Sheet. The pre-tax dividends are
included in operating activities in the Unaudited Consolidated
Statement of Cash Flows.
ii. 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, depreciation expense under US
principles is higher.
During the quarter, 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 has been included in our net income
(loss) from discontinued operations disclosed on the Unaudited
Consolidated Statement of Income - US GAAP.
19
iii. 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 sales on the income statement.
Included in accounts receivable at September 30, 2003 is $1 million
(December 31, 2002 - $nil), fair value of the forward contracts used to
hedge a portion of our production from the Aspen field as described in
Note 5. The contracts limit our exposure to fluctuations in commodity
prices by fixing our cash flow from the sale of hedged production. As
of September 30, 2003, the fair value included in accumulated other
comprehensive income was an unrealized gain of $1 million, net of
income taxes. The unrealized gain is expected to be moved to net sales
in the next twelve months as the underlying production is delivered or
the hedge expires. For the three and nine months ended September 30,
2003, amounts related to the ineffectiveness of cash flow hedges were
included in net sales and were immaterial.
At September 30, 2003, the total fair value of the futures and basis
swap contracts used to hedge the future sale of our gas storage, as
described in Note 5, was $3 million and the change in fair value since
designation was a net gain of $5 million. The change in fair value
since designation included in accumulated other comprehensive income
was an unrealized gain of $3 million, net of income taxes. The loss of
$2 million on the future contracts prior to designation was included in
marketing and other on the Unaudited Consolidated Statement of Income.
All of the unrealized gain is expected to be moved to marketing and
other in the next twelve months as the gas in storage is sold. For the
three and nine months ended September 30, 2003, amounts related to the
ineffectiveness of cash flow hedges were included in marketing and
other and were immaterial.
FAIR VALUE HEDGES: Both the derivative instrument and the underlying
commitment are recognized on the balance sheet at their fair value. Any
changes in the fair value are reflected net in earnings. Included in
both accounts receivable and accounts payable at September 30, 2003 is
$nil (December 31, 2002 - $2 million) related to fair value hedges. The
hedges convert fixed prices for physical delivery of natural gas into a
floating price through a fixed to floating swap. The impact on earnings
is immaterial.
iv. 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
accumulated other comprehensive income in the Unaudited Consolidated
Balance Sheet.
v. Under US principles, a derivative and a cash instrument cannot be
designated in combination as a net investment hedge. Changes in fair
value and foreign exchange gains and losses on our US $37 million
currency swap are included in earnings.
vi. 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.
vii. Under US principles, the amount by which our accrued pension cost is
less than the unfunded accumulated benefit obligation is included in
comprehensive income and accrued pension liabilities. This amount was
$4 million at September 30, 2003 (December 31, 2002 - $4 million).
viii. Under US principles, gains and losses on the disposition of assets are
shown as other expenses rather than revenues.
ix. On January 1, 2003 we adopted Financial Accounting Standards Board
(FASB) Statement No. 143, "Accounting for Asset Retirement Obligations"
(FAS 143) for US GAAP reporting purposes. FAS 143 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. These obligations, which generally
relate to dismantlement and site restoration, are initially measured at
fair value, which is the discounted future value of the liability. This
fair value is capitalized as part of the cost of the related asset and
amortized to expense over its useful life. The liability accretes until
we expect to settle the retirement obligation.
20
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 $25 million. Under the
old accounting rules, our results would have been:
Three Months Nine Months
Ended September 30 Ended September 30
2003 2003
------------------------------------------------------------------------------------------------------------------
Net Income - US GAAP
As Reported 137 490
Cumulative Effect of Change in Accounting Principle 37
Depreciation, Depletion and Amortization, and
Accretion (1) 2
---------------------------------------------
Adjusted 136 529
=============================================
Earnings per Common Share ($/share)
Basic as Reported 1.11 3.97
=============================================
Adjusted 1.09 4.29
=============================================
Diluted as Reported 1.09 3.94
=============================================
Adjusted 1.08 4.25
=============================================
Had FAS 143 been applied during all periods presented, our asset
retirement obligation, including current obligations of $14 million at
December 31, 2002 and $18 million at September 30, 2003, would have
been reported as follows:
As Reported Pro-forma
------------------------------------------------------------------------------------------------------------------
January 1, 2002 182 364
December 31, 2002 205 390
September 30, 2003 359 359
--------------------------------
We own interests in several assets for which the fair value of the
asset retirement obligation cannot be reasonably determined because the
assets currently have an indeterminate life. These assets include our
interests in two gas plants and our interest in Syncrude's upgrader and
sulfur pile. The asset retirement obligation for these assets will be
recorded in the first year in which the lives of the assets are
determinable.
Had FAS 143 been applied during all periods presented, our September
30, 2002 results would have been reported as follows:
Three Months Nine Months
Ended September 30 Ended September 30
2002 2002
------------------------------------------------------------------------------------------------------------------
Net Income - US GAAP
As Reported 134 255
Depreciation, Depletion and Amortization,
and Accretion -- (3)
---------------------------------------------
Adjusted 134 252
=============================================
Earnings per Common Share ($/share)
Basic as Reported 1.09 2.09
=============================================
Adjusted 1.09 2.06
=============================================
Diluted as Reported 1.08 2.06
=============================================
Adjusted 1.08 2.04
=============================================
x. Under US principles, enacted tax rates are used to calculate future
income taxes, whereas under Canadian GAAP, substantively enacted tax
rates are used. Substantively enacted changes in Canadian federal and
provincial income tax rates created a $76 million future income tax
recovery during the second quarter of 2003.
21
xi. In May 2003, FASB issued Statement No. 150, "Accounting for Certain
Instruments with Characteristics of Both Liabilities and Equity" that
establishes standards for classifying and measuring certain financial
instruments with characteristics of both liabilities and equity.
Certain financial instruments, including our preferred securities, must
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 during the third quarter. Since
adopting the change in accounting principle at the beginning of the
quarter, the fair value of our preferred securities has decreased by $8
million and this gain was included in marketing and other. The tax
effect of $3 million on this gain increased our deferred income tax
provision.
NEW ACCOUNTING PRONOUNCEMENTS AND UPCOMING CHANGE IN ACCOUNTING POLICY
Our shareholders approved a resolution requiring us to expense stock options. As
a result, we plan to adopt the fair-value method of accounting for stock options
in the fourth quarter of 2003. In January 2003, the US Financial Accounting
Standards Board (FASB) issued Statement No. 148 "Accounting for Stock-Based
Compensation - Transition and Disclosure, an Amendment of FASB Statement No.
123" (FAS 148). FAS 148 amends FAS 123 "Accounting for Stock-Based
Compensation", to provide alternative methods of transition for a voluntary
change to the fair-value method of accounting for stock-based employee
compensation. We plan to adopt the fair-value method of accounting for stock
options in the fourth quarter of 2003 using the prospective method, whereby
compensation cost will be recognized for all options granted on or after January
1, 2003. All stock options granted prior to January 1, 2003 will continue to be
accounted for under Accounting Principles Board Opinion No. 25 "Accounting for
Stock Issued to Employees" (APB 25) unless these stock options are modified or
settled subsequent to adoption. The impact under US GAAP will be immaterial in
2003.
The following standard issued by the FASB does not impact us:
o Statement No. 149 - "Amendment of Statement 133 on Derivative Instruments
and Hedging Activities" effective for contracts entered into or modified
after June 30, 2003 and for hedging relationships designated after June 30,
2003.
22
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 13 TO THE UNAUDITED CONSOLIDATED
FINANCIAL STATEMENTS. UNLESS OTHERWISE NOTED, TABULAR AMOUNTS ARE IN MILLIONS OF
CANADIAN DOLLARS, AND SALES VOLUMES AND PRODUCTION VOLUMES ARE BEFORE ROYALTIES.
WE HAVE PRESENTED OUR WORKING INTEREST BEFORE ROYALTIES AS WE MEASURE OUR
PERFORMANCE ON THIS BASIS CONSISTENT WITH OTHER CANADIAN OIL AND GAS COMPANIES.
THIRD QUARTER HIGHLIGHTS
Strong third quarter financial results continue to drive us towards record
results for the year. During the third quarter of 2003, attractive commodity
prices, US production growth and growing cash margins, fuelled by reduced unit
operating costs and lower royalties, offset the negative effect of a
strengthening Canadian dollar on our net income and cash flow from operations.
Our solid results were complemented by continued drilling success on Block 51 in
Yemen, expansion in West Africa and the acquisition of eight new exploratory
blocks in the western Gulf of Mexico. We also continued our progress on major
growth projects in the deep water Gulf of Mexico and in the Athabasca oil sands.
Following are the quarterly highlights:
o Grew production, after royalties, by 3% from the third quarter of 2002.
o Increased net income by 15% and cash flow from operations by 10% from third
quarter 2002 despite a drop of 3% in realized prices.
o Sold non-core light oil properties in southeast Saskatchewan for net
proceeds of $268 million.
o Growth in production from new discoveries in the Gulf of Mexico made the US
our largest cash flow contributor for the second consecutive quarter.
o Reduced net debt by $688 million since December 31, 2002.
Three Months Nine Months
Ended September 30 Ended September 30
(Cdn$ millions) 2003 2002 2003 2002
- -----------------------------------------------------------------------------------------------------------------------------
Net Sales (1) 730 716 2,314 1,901
Net Income (1) 181 157 695 323
Earnings per Common Share - Basic ($/share) 1.38 1.20 5.38 2.38
Earnings per Common Share - Diluted ($/share) 1.37 1.17 5.34 2.35
Cash Flow from Operations (1),(2) 434 394 1,449 974
Production, before Royalties (mboe/d) (1) 271 275 272 271
Production, after Royalties (mboe/d) (1) 188 182 187 178
Capital Expenditures (3) 286 414 1,097 1,179
----------------------------------------------------
Notes:
1 Includes results of discontinued operations (see Note 10 to our Unaudited
Consolidated Financial Statements).
2 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 repay debt.
Three Months Nine Months
Ended September 30 Ended September 30
(Cdn$ millions) 2003 2002 2003 2002
-----------------------------------------------------------------------------------------------------------
Cash Flow from Operating Activities 296 402 1,242 869
Changes in Non-Cash Working Capital 125 (15) 165 92
Other 13 7 42 13
-------------------------------------------------
Cash Flow from Operations 434 394 1,449 974
=================================================
3 Includes $164 million relating to the purchase of the remaining working
interest in the Aspen field in March 2003.
23
FINANCIAL RESULTS
CHANGE IN NET INCOME
2003 VS 2002
Three Months Nine Months
(Cdn$ millions) Ended September 30 Ended September 30
- ----------------------------------------------------------------------------------------------------------------
NET INCOME AT SEPTEMBER 30, 2002 (1) 157 323
==============================================
Favourable (unfavourable) variances:
Cash Items:
Production volumes, after royalties:
Crude oil 7 54
Natural gas 7 26
Crude oil sales volumes, after royalties -- (12)
Realized commodity prices:
Crude oil (53) 99
Natural gas 51 219
Oil and gas operating expense:
Conventional 9 22
Syncrude (6) (11)
Marketing 17 58
Chemicals -- 5
General and administrative (8) (14)
Interest expense 6 4
Current income taxes 9 8
Other 1 17
----------------------------------------------
Total Cash Variance 40 475
Non-Cash Items:
Depreciation, depletion and amortization
Oil and Gas (11) (36)
Other 1 (2)
Exploration expense 3 3
Future income taxes (16) (65)
Gain on disposition of assets -- (13)
Other 7 10
----------------------------------------------
Total Non-Cash Variance (16) (103)
----------------------------------------------
NET INCOME AT SEPTEMBER 30, 2003 (1) 181 695
==============================================
Note:
1 Includes results of discontinued operations (see Note 10 to our Unaudited
Consolidated Financial Statements).
QUARTERLY NET INCOME INCREASES 15%
Solid third quarter 2003 results were driven by growing net production levels,
attractive commodity prices and a solid contribution from marketing. The
strengthening Canadian dollar relative to the US dollar offset these gains.
The strengthening Canadian dollar relative to the US dollar reduced our
quarterly net income by $38 million (year to date $76 million) and cash flow
from operating activities by $65 million (year to date $129 million). This is
because we translate the results of our foreign operations from US dollars to
Canadian dollars. With a stronger Canadian dollar, our foreign revenues and
realized commodity prices referenced to US dollars are lower when translated.
However, we benefit to the extent that our foreign operating costs and capital
expenditures are also reduced when translated. In addition, most of our
fixed-rate debt is denominated in US dollars so this debt gets cheaper as the
Canadian dollar strengthens and has resulted in a decrease of $220 million in
our fixed-rate debt since December 31, 2002. For accounting purposes our US
dollar denominated debt is treated as a hedge of our foreign operations. As a
result, our earnings do not reflect foreign exchange gains or losses on the
revaluation of this debt.
Strong commodity prices, growing net production levels, high-margin barrels from
reduced royalties and operating costs and a solid contribution from marketing
delivered our best-ever year to date results in 2003. Significant variances in
net income are explained further in the following sections.
24
OIL AND GAS
PRODUCTION VOLUMES (BEFORE ROYALTIES) (1)
Three Months Nine Months
Ended September 30 Ended September 30
2003 2002 2003 2002
- ---------------------------------------------------------------------------------------------------------------
Oil and Liquids (mbbls/d)
Yemen 115.2 118.5 116.7 118.3
Canada 46.2 55.3 48.7 57.3
United States 31.3 8.9 28.2 9.8
Australia 5.6 18.9 6.5 13.3
Other Countries 5.2 7.9 5.8 9.3
Syncrude 17.5 18.9 15.5 16.1
---------------------------------------------------------------
221.0 228.4 221.4 224.1
---------------------------------------------------------------
Natural Gas (mmcf/d)
Canada 155 167 158 167
United States 144 115 146 116
---------------------------------------------------------------
299 282 304 283
---------------------------------------------------------------
Total (mboe/d) 271 275 272 271
===============================================================
PRODUCTION VOLUMES (AFTER ROYALTIES) (1)
Three Months Nine Months
Ended September 30 Ended September 30
2003 2002 2003 2002
- ---------------------------------------------------------------------------------------------------------------
Oil and Liquids (mbbls/d)
Yemen 56.8 56.5 57.2 56.1
Canada 34.4 42.7 36.9 44.1
United States 27.8 7.4 25.0 8.1
Australia 5.4 14.8 5.9 10.4
Other Countries 4.7 4.6 4.9 5.5
Syncrude 17.4 18.7 15.3 16.0
---------------------------------------------------------------
146.5 144.7 145.2 140.2
---------------------------------------------------------------
Natural Gas (mmcf/d)
Canada 127 128 125 128
United States 122 95 123 97
---------------------------------------------------------------
249 223 248 225
---------------------------------------------------------------
Total (mboe/d) 188 182 187 178
===============================================================
Note:
1 Includes results of discontinued operations.
QUARTERLY PRODUCTION INCREASED NET INCOME FOR THE QUARTER BY $14 MILLION
Although production before royalties decreased by 1%, production after royalties
grew 3% from the third quarter of 2002. This growth is largely attributable to
the addition of 28,000 boe/d of low royalty Aspen production from the deep
waters of the Gulf of Mexico. As our production mix shifts to more deep water
barrels from Aspen and Gunnison projects, we will continue to see our net
production grow. On a before royalties basis, the production decrease of 1%
compared to the third quarter last year is due to expected declines in
International and Canada and the sale of non-core properties in Canada offset by
growth in the US. This is further explained below.
25
MASILA BLOCK IN YEMEN
o Third quarter production of 115,200 bbls/d was 3% lower than 2002.
o To ensure the acquisition of high quality seismic data we slowed
development drilling on the Tawila and Heijah fields to minimize noise
interference.
o While gross production decreased 3%, under the terms of the production
sharing contract our share of production after royalties largely remained
the same. Returns on the Masila Block remain very attractive.
CANADA
o Third quarter production of 72,100 boe/d was 11,100 boe/d lower than 2002
due in part to the sale of non-core producing assets in southeast
Saskatchewan.
o On August 28, 2003, non-core light oil properties located in the Williston
Basin of southeast Saskatchewan were sold for net proceeds of $268 million.
These properties produced approximately 9,000 boe/d.
o We are continuing to invest in future growth opportunities including
premium synthetic crude at Long Lake, coal bed methane and enhanced oil
recovery techniques for heavy oil.
US GULF OF MEXICO
o Our deep water Aspen production boosted US rates by 97% from 2002 to 55,300
boe/d. Aspen came onstream in December 2002 and we acquired the remaining
40% interest in this project in late March 2003.
o The additional interest in Aspen contributed 11,200 boe/d to our third
quarter production volumes. We locked in a portion of our return on this
acquisition by selling approximately 60% of the incremental production
forward to March 2004 at a weighted-average price of US $29.50 per boe. Our
cash netback (1) on these hedged volumes is approximately US $23 per boe.
The forward sale of 10% of the acquired reserves has paid for 50% of the
purchase price.
o Production at Aspen was 28,000 boe/d during the quarter and was partially
shut-in for four days in September to repair wellhead valve malfunctions
following the shut-in of the Shell Bullwinkle platform. With the problems
resolved, we expect production from the Gulf of Mexico to remain just under
55,000 boe/d for the remainder of 2003.
o Production from Aspen is priced off Mars blend, which is the second most
actively traded US crude stream after WTI. Mars was priced at a US
$3.25/bbl discount to WTI in the third quarter.
o Eugene Island 295, which was damaged by Hurricane Lili last October,
produced 15 mmcf per day in the third quarter. Production of approximately
25 mmcf per day of natural gas was shut-in for 37 days in the quarter to
permanently replace temporary production facilities. Insurance claims will
be submitted for this lost production.
OTHER COUNTRIES
o Production at Buffalo offshore Australia and at Ejulebe offshore Nigeria
declined in the third quarter of 2003 in line with our expectations.
o Buffalo and Ejulebe are both expected to be fully depleted by early to
mid-2004.
o Colombia production grew modestly in the quarter as drilling at Guando was
completed quicker than anticipated.
SYNCRUDE
o Enhanced operational reliability, following the spring turnaround and coker
maintenance, contributed strong July and August production rates at 18,500
bbls/d. September production dropped slightly due to a planned turnaround
of the vacuum distillation unit.
o Due to an unplanned coker turnaround during the fourth quarter of 2003, we
expect our share of Syncrude production to average around 15,500 bbls/d in
2003.
- ------------------------
1 Netback is defined as sales price less all per unit costs including
royalties, operating expenses and cash taxes. This is calculated using our
working interest production before royalties.
26
COMMODITY PRICES
Three Months Nine Months
Ended September 30 Ended September 30
2003 2002 2003 2002
- ---------------------------------------------------------------------------------------------------------------
CRUDE OIL
West Texas Intermediate (WTI) (US$/bbl) 30.20 28.30 30.99 25.40
----------------------------------------------------
Differentials (US$/bbl):
Masila 2.44 1.02 3.22 1.36
Heavy Oil 8.77 5.98 8.04 5.94
Producing Assets (1) (Cdn$/bbl):
Yemen 38.25 42.29 39.89 37.79
Canada 31.07 35.17 33.83 30.66
United States 36.03 41.73 38.65 37.78
Australia 42.09 43.57 43.14 39.40
Nigeria 39.26 41.63 42.33 38.64
Colombia 34.87 41.09 36.94 35.92
Syncrude 41.36 44.26 44.70 39.85
Corporate Average (1) (Cdn$/bbl) 36.70 40.77 38.80 36.26
----------------------------------------------------
NATURAL GAS
New York Mercantile Exchange (NYMEX) (US$/mmbtu) 4.92 3.21 5.66 3.05
----------------------------------------------------
Canada (Cdn$/mcf) (1) 5.14 3.05 5.91 3.21
United States (Cdn$/mcf) (1) 6.95 4.93 8.53 4.85
Corporate Average (Cdn$/mcf) (1) 6.01 3.82 7.17 3.89
----------------------------------------------------
AVERAGE REALIZED OIL AND GAS PRICE (Cdn$/boe) (1) 36.59 37.71 39.60 34.01
----------------------------------------------------
AVERAGE FOREIGN EXCHANGE RATE
Canadian to US Dollar 0.7263 0.6463 0.6886 0.6356
----------------------------------------------------
Note:
1 Prices based on working interest production before royalties.
LOWER REALIZED CRUDE OIL PRICES DECREASED QUARTERLY NET INCOME BY $53 MILLION
REALIZED CRUDE OIL PRICES
o Despite stronger crude oil reference prices compared to the third quarter
of 2002, we realized lower prices for our crude oil as a result of widening
differentials and the strengthening of the Canadian dollar relative to the
US dollar.
o All of our oil sales are denominated in or referenced to US dollars. The
strengthening Canadian dollar reduced our realized crude oil price by
around $4.55 per bbl.
CRUDE OIL REFERENCE PRICES
o Strength in WTI reference prices late in the second quarter continued early
into the third quarter with highs of US $32 per bbl. This high was fuelled
by concerns over the security of Iraqi production, OPEC's determination to
hold their production quotas, low crude and product inventory levels in
North America and supply concerns in Nigeria and Venezuela.
o Late in the third quarter, WTI fell off these highs to average between US
$27 and $29 per barrel. Rising inventory levels in North America, growth in
Iraqi and Venezuelan exports and the end of the summer driving season were
contributors.
o At the end of the quarter, WTI strengthened after OPEC announced on
September 24th a 900,000 barrel per day reduction to their production
quotas starting in November.
27
HEAVY OIL DIFFERENTIALS
o Approximately 10% of our total corporate production is Canadian heavy oil.
o Differentials began widening early in the quarter with new Canadian heavy
oil supply entering the market and with the unexpected turnaround of a
major refinery.
o The power blackout in the east shut down a number of refineries in August.
This decreased heavy oil demand causing differentials to remain wide.
o Late in the quarter, the differential widened further, to around US $9 per
barrel, with the end of the summer asphalt season.
MASILA DIFFERENTIAL
o Our Masila crude is typically priced off North Sea Brent.
o In the third quarter of 2003, the Masila and Brent differentials to WTI
narrowed, as exceptionally warm weather in Europe caused a sharp increase
in demand to help fuel air conditioning and refrigeration.
o Differentials continued to narrow as supply from the North Sea decreased
due to maintenance on several platforms and demand for Brent crude in Asia
increased.
HIGHER REALIZED NATURAL GAS PRICES INCREASED QUARTERLY NET INCOME BY $51 MILLION
NATURAL GAS PRICES
o Substantially all of our natural gas sales are denominated in or referenced
to US dollars. The strengthening Canadian dollar reduced our realized gas
price by 75(cent) per mcf. Higher natural gas reference prices increased
our average gas price by $2.94 per mcf, more than offsetting the effect of
the strengthening Canadian dollar on our realized prices.
o Natural gas prices fluctuated during the third quarter and receded from
earlier highs as storage levels in the east returned to more normal levels
with seasonal demand reduced by moderate summer weather.
o The basis between Alberta gas and NYMEX gas narrowed significantly late in
the third quarter of 2003 as warm temperatures in California increased
demand for Alberta gas and moderate temperatures in the east kept demand
for NYMEX gas stable.
OPERATING COSTS (1)
(Based on working interest production before royalties)
Three Months Nine Months
Ended September 30 Ended September 30
(Cdn$/boe) 2003 2002 2003 2002
- ----------------------------------------------------------------------------------------------------
Conventional Oil and Gas 4.11 4.55 4.25 4.52
Synthetic Crude Oil
Syncrude 18.83 14.37 23.27 18.95
Total Oil and Gas (2) 5.06 5.23 5.33 5.37
----------------------------------------------------
Notes:
1 Includes results of discontinued operations (see Note 10 to our Unaudited
Consolidated Financial Statements).
2 Operating costs per equivalent barrel 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.
LOWER OPERATING COSTS INCREASED NET INCOME FOR THE QUARTER BY $3 MILLION
o Decreases in conventional operating costs due to the addition of low-cost
volumes from Aspen and the strengthening of the Canadian dollar were
partially offset by higher repairs and maintenance costs in Yemen.
o Syncrude's operating costs per barrel were up relative to the third quarter
of 2002 due to the turnaround of the vacuum distillation unit in September
2003 and higher natural gas input prices. Operating costs have increased on
a year to date basis as a result of unscheduled maintenance and higher
natural gas input prices.
o The strengthening Canadian dollar decreased US-dollar denominated operating
costs lowering our corporate average unit operating costs by approximately
23(cent) per boe.
28
DEPRECIATION, DEPLETION AND AMORTIZATION (DD&A) (1)
(Based on working interest production before royalties)
Three Months Nine Months
Ended September 30 Ended September 30
(Cdn$/boe) 2003 2002 2003 2002
- ----------------------------------------------------------------------------------------------------
Conventional Oil and Gas 7.36 6.86 7.41 6.91
Synthetic Crude Oil
Syncrude 2.38 2.01 2.50 2.16
Total Oil and Gas (2) 7.04 6.53 7.13 6.63
----------------------------------------------------
Notes:
1 Includes results of discontinued operations (see Note 10 to our Unaudited
Consolidated Financial Statements).
2 Operating costs per equivalent barrel 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.
HIGHER OIL AND GAS DD&A REDUCED NET INCOME FOR THE QUARTER BY $11 MILLION
o Higher 2002 finding and development costs coupled with our changing
production mix, as a larger portion of our production comes from
capital-intensive but higher margin properties, has increased our depletion
charge.
o The strengthening Canadian dollar decreased per unit depletion costs by
approximately 50(cent)per boe in the quarter.
EXPLORATION EXPENSE (1)
Three Months Nine Months
Ended September 30 Ended September 30
(Cdn$ millions) 2003 2002 2003 2002
- ----------------------------------------------------------------------------------------------------
Seismic 10 12 34 48
Unsuccessful Exploration Drilling 6 6 30 27
Other 14 15 46 38
----------------------------------------------------
Total Exploration Expense 30 33 110 113
====================================================
Total Exploration Capital 81 71 219 198
----------------------------------------------------
Note:
1 Includes results of discontinued operations (see Note 10 to our Unaudited
Consolidated Financial Statements).
LOWER EXPLORATION EXPENSE INCREASED NET INCOME FOR THE QUARTER BY $3 MILLION
o Activity in the quarter included dry hole costs in Canada as well as
seismic acquisition in the Gulf of Mexico, Canada and Nigeria.
o Exploration capital includes successful drilling on Block 51 in Yemen,
successful appraisal drilling in Nigeria on Block 222 and on-going drilling
and evaluation of our deep water Shiloh exploration well.
29
OIL AND GAS MARKETING
Our marketing operation engages in crude oil and natural gas marketing
activities to enhance prices from the sale of our own oil and gas production,
and for energy trading as described in Note 6(a) to the Audited Consolidated
Financial Statements included in our 2002 Annual Report on Form 10-K.
Three Months Nine Months
Ended September 30 Ended September 30
(Cdn$ millions) 2003 2002 2003 2002
- --------------------------------------------------------------------------------------------------------------------
Revenue, Net 121 114 416 355
Transportation (98) (106) (319) (315)
Other 2 -- 1 --
----------------------------------------------------
25 8 98 40
====================================================
Marketing Contribution to Income from Continuing Operations
before Income Tax 13 (2) 61 11
----------------------------------------------------
Physical Sales Volumes (excluding intra-segment transactions)
Crude Oil (mboe/d) 424 383 460 393
Natural Gas (mmcf/d) 2,951 2,661 3,007 2,456
Value-at-Risk
Quarter End 22 19 22 19
High 26 22 31 22
Low 14 17 14 12
Average 19 20 20 17
----------------------------------------------------
HIGHER NET MARKETING REVENUE INCREASED NET INCOME FOR THE QUARTER BY $17 MILLION
o Marketing results were strong in the third quarter 2003 as we successfully
capitalized on Brent/Dubai spreads and heavy differentials for crude oil.
Our natural gas trading group profited from spreads between Alberta and the
US midwest, and Alberta and eastern Canada.
o In 2002, mark-to-market gains on our storage positions were included in net
income. New accounting rules require us to exclude this from our 2003
results until the inventory is sold despite having futures contracts in
place that lock in the profit on our stored volumes. At the beginning of
the third quarter, we designated certain futures contracts as accounting
hedges of the future sale of our stored volumes. As a result, we defer
recognition of the mark-to-market gain or loss on the futures contracts
until such time as the inventory is sold. This accounting treatment better
matches fair value changes in the futures contracts and inventory. See Note
5 to the Unaudited Consolidated Financial Statements for further details.
FAIR VALUE OF DERIVATIVE ENERGY CONTRACTS
At September 30, 2003, the fair value of our derivative energy contracts
totalled $46 million. The following table shows the valuation methods underlying
these contracts together with timing of contract maturity:
(Cdn$ millions) MATURITY
- ----------------------------------------------------------------------------------------------------------------------------
Less than More than
1 year 1-3 years 4-5 years 5 years Total
------------------------------------------------------------------
Prices:
Actively quoted 247 150 21 -- 418
From other external sources (235) (122) (16) 1 (372)
Based on models and other valuation methods -- -- -- -- --
------------------------------------------------------------------
Total 12 28 5 1 46
==================================================================
Contract maturities vary from a single day up to five years. Those maturing
beyond one year are primarily from natural gas related positions.
30
CHANGES IN FAIR VALUE OF DERIVATIVE ENERGY 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, 2002 3 -- -- 3
Change in fair value of contracts 17 42 25 84
Net losses (gains) on contracts closed 1 (42) -- (41)
Changes in valuation techniques and assumptions (1) -- -- -- --
-------------------------------------------------------------------
Fair value at September 30, 2003 21 -- 25 46
===================================================================
Note:
1 Our valuation methodology has been applied consistently period over period.
This fair value includes:
o offsetting derivatives and physical contracts with limited market risk, and
o positions that are subject to change in value from fluctuating market
prices.
We manage the risk associated with positions exposed to changes in value through
daily monitoring of value-at-risk and by stress testing and scenario analysis.
The value-at-risk calculation estimates the maximum probable loss, given a 95%
confidence level, that we would incur if our open positions were unwound over
two days. At September 30, 2003, our value-at-risk with respect to these
positions was $22 million (December 31, 2002 - $19 million).
COMPOSITION OF NET MARKETING REVENUE
Three Months Nine Months
Ended September 30 Ended September 30
(Cdn$ millions) 2003 2003
- --------------------------------------------------------------------------------------------
Derivative energy contracts 21 84
Non-derivative energy contracts 2 13
Other 2 1
--------------------------------------------
25 98
============================================
CHEMICALS
CHEMICALS OPERATING PROFIT WAS CONSISTENT WITH THIRD QUARTER 2002
o Strong chlor-alkali prices were offset by lower North American chlorate
prices, lower Brazil sales volumes and a strong Canadian dollar. The
strengthening Canadian dollar relative to the US dollar decreases our
revenue as our products are largely priced in US dollars.
o Lower operating costs resulting from the idling of our Taft, Louisiana
sodium chlorate assets were largely offset by purchased product costs. The
purchased product allows us to continue to meet the needs of our customers
in the southeastern US.
CORPORATE EXPENSES
GENERAL AND ADMINISTRATIVE (G&A)
Three Months Nine Months
Ended September 30 Ended September 30
(Cdn$ millions) 2003 2002 2003 2002
- ------------------------------------------------------------------------------------------
General and Administrative 44 36 126 112
====================================================
HIGHER COSTS DECREASED QUARTERLY NET INCOME BY $8 MILLION
o Our increasing stock price has increased costs related to our Stock
Appreciation Rights plan by $3 million.
o G&A expenses, excluding stock appreciation rights, increased by $3 million
due to increased staffing levels. Staffing level increases are the result
of our major development projects in the US and Canada, and growth in our
Marketing division.
31
INTEREST
Three Months Nine Months
Ended September 30 Ended September 30
(Cdn$ millions) 2003 2002 2003 2002
- --------------------------------------------------------------------------------------------
Interest 35 38 107 100
Less: Capitalized Interest 12 9 31 20
----------------------------------------------------
Net Interest Expense 23 29 76 80
====================================================
LOWER INTEREST EXPENSE INCREASED QUARTERLY NET INCOME BY $6 MILLION
o Capitalized interest increased with increased spending on our major
development projects in the Gulf of Mexico and Canada.
o Strengthening Canadian dollar reduced interest expense on our fixed rate
debt denominated in US dollars by $3 million.
o Higher borrowing rate of 7.875% on our 30-year notes issued in March 2002
contributed to the year to date increase.
INCOME TAXES (1)
Three Months Nine Months
Ended September 30 Ended September 30
(Cdn$ millions) 2003 2002 2003 2002
- --------------------------------------------------------------------------------------------
Current Income Taxes 60 69 164 172
Future Income Taxes 35 19 65 --
----------------------------------------------------
Provision for Income Taxes 95 88 229 172
====================================================
Effective Tax Rate (%) 34.4 36.0 24.8 34.7
----------------------------------------------------
Note:
1 Includes results of discontinued operations (see Note 10 to our Unaudited
Consolidated Financial Statements).
EFFECTIVE TAX RATE FOR THE QUARTER DECREASES TO 34.4% FROM 36.0%
o The effective quarterly tax rate was lower due to a reduction in tax rates
for Canadian resource activities.
o The effective year to date tax rate was lower due to a reduction in tax
rates for Canadian resource activities that resulted in a recovery of
future income taxes of $76 million during the second quarter of 2003.
o Current income taxes include cash taxes in Yemen of $51 million (2002 - $57
million) for the quarter and $150 million (2002 - $149 million) year to
date.
o During 2003 and 2002, current income taxes include federal and provincial
capital taxes in Canada. In 2003, current income taxes also included
alternative minimum tax in the United States.
CAPITAL EXPENDITURES
Three Months Nine Months
Ended September 30 Ended September 30
(Cdn$ millions) 2003 2002 2003 2002
- --------------------------------------------------------------------------------------------------------------------
Yemen 59 51 173 165
Canada 64 57 247 219
United States 84 232 446 482
Australia -- 2 2 49
Other Countries 23 23 71 51
Syncrude 47 40 136 91
Chemicals, Corporate and Other 9 9 22 122
----------------------------------------------------
286 414 1,097 1,179
====================================================
Development 196 334 692 859
Exploration 81 71 219 198
Acquisition of the Residual 40% Interest in the Aspen Field -- -- 164 --
Chemicals, Corporate and Other 9 9 22 122
----------------------------------------------------
286 414 1,097 1,179
====================================================
32
YEMEN
Exploration of Block 51, located immediately west of our Masila Block 14,
continued during the quarter. We commenced appraisal of the Tammum discovery.
The first appraisal well, Tammum-2, was drilled approximately 800 meters west of
the Tammum-1 discovery well and encountered hydrocarbons. The second appraisal
well, Tammum-3 was drilled one kilometer southwest of the discovery well and
also encountered hydrocarbons, indicating a thickening trend to the southwest. A
fourth appraisal well, Tammum-4 is currently drilling northwest of the discovery
well. A 3D seismic program is underway to help with the appraisal program and a
broader 2D program is planned to identify further exploration prospects on the
block.
The Husn El Kradis (HEK)-1R exploration well was drilled approximately 25
kilometers northwest of Tammum-1 to test for oil in fractured basement. This
well encountered water and has been abandoned. Further exploration of the area
is planned.
CANADA
Our Premium Synthetic Crude project at Long Lake cleared a significant
regulatory hurdle during the quarter, receiving approval from the Energy
Utilities Board of Alberta. Our steam assisted gravity drainage pilot project is
performing as anticipated and Long Lake bitumen is currently being processed
through the primary upgrader demonstration plant. Detailed engineering is
approaching 15% completion and we expect to finalize cost estimates so we can
make a decision on commercial development by year-end. Following project
sanctioning by Nexen and OPTI, facilities construction will begin in 2004,
bitumen production in 2006 and upgrader start-up in 2007. This project is
expected to increase Nexen's crude oil production in 2007 by 30,000 barrels per
day at a cost of $1.5 billion.
UNITED STATES
The Gunnison deep water development project in the Gulf of Mexico remains on
schedule and on budget. The truss SPAR production hull has been transported to
its location on Garden Banks Block 668 and mooring operations and installation
of the production topsides are complete. Construction of the gathering system is
also complete and final tie-ins will be conducted during the fourth quarter.
Production from the field is scheduled to commence in early 2004 at 35 million
cubic feet of natural gas and 1,500 barrels of oil per day, net to Nexen,
increasing to 50 million cubic feet of gas and 8,500 barrels of oil per day late
in 2004. The current development plan will fill approximately 75% of the design
capacity of the facility, leaving room for growth from exploration and the
processing of third-party volumes. We have a 30% interest in Gunnison.
During the quarter, the deep water Shiloh-1 exploration well on Desoto Canyon
269 was drilled to a total depth of over 24,000 feet. The well was logged and
cored prior to being suspended pending evaluation of all data. We have a 20%
interest in the well.
We plan to drill a third development well in the Aspen field in the fourth
quarter. Success at Aspen-3 will be followed by an exploration well at Crested
Butte, a direct offset to Aspen.
We are currently drilling an exploration well at Shark, located in shallow water
on South Timbalier 174. This well is exploring for natural gas in deep
Miocene-age sands. An exploratory test of the Gotcha prospect, located on
Alaminos Canyon Block 856 adjacent to Shell's announced Great White discovery,
is expected to be drilled in 2004.
WEST AFRICA
Elf Petroleum Nigeria Ltd. (EPNL), a subsidiary of Total, the operator of deep
water Oil Prospecting License (OPL) 222, announced a significant extension of
the Usan field discovery. The Usan-4 appraisal well, located around 110
kilometres offshore and 5 kilometres south of the Usan-1 discovery well in water
depths of approximately 750 metres, is the third successful appraisal of the
Usan field discovered in 2002. Two zones were tested in the Usan-4 well and
flowed at 4,400 and 6,300 barrels of oil per day under restricted flow
conditions. Usan-4 confirmed the presence of commercial quantities of oil, as
well as additional potential, in previously untested reservoirs.
Nigerian National Petroleum Corp. (NNPC) is concessionaire for OPL 222 under a
production sharing contract operated by the Nigerian subsidiary of Total, EPNL
(20%), in partnership with Chevron Petroleum Nigeria Ltd. (30%), Esso
Exploration & Production Nigeria (Offshore East) (30%), and Nexen Petroleum
Nigeria Ltd. (20%).
Offshore Equatorial Guinea, we acquired a 25% interest in Block K, a deep water
Production Sharing Contract located 100 kilometers offshore. We will operate the
Block in partnership with Repsol Exploracion Guinea, S.A. (25%) and Vanco
Equatorial Guinea Ltd. (50%). Block K is on trend with the 300-million barrel
Ceiba field and other discoveries on Block G to the north. We plan to complete
seismic reprocessing and drill one exploration well in the second quarter of
2004.
33
SYNCRUDE
Syncrude's Stage 3 expansion is also proceeding as expected. Mine site
development is 98% complete and on schedule to see bitumen production commencing
in October of this year. The upgrader expansion is 30% complete, with completion
targeted for mid-2005. Our 7.23% share of Syncrude's production is expected to
increase to over 25,000 barrels per day with the completion of the Stage 3
expansion.
LIQUIDITY AND CAPITAL STRUCTURE
CAPITAL STRUCTURE
September 30 December 31
(Cdn$ millions) 2003 2002
- ------------------------------------------------------------------------------------------------
Amounts Drawn on Unsecured Syndicated Term Credit Facilities -- --
Senior Public Debt 1,624 1,844
--------------------------------
1,624 1,844
Less: Working Capital 537 69
--------------------------------
Net Debt (1) 1,087 1,775
================================
Shareholders' Equity (2) 2,836 2,348
================================
Notes:
1 Long-term debt less working capital.
2 Included in shareholders' equity are preferred securities of $724 million
(US $476 million). Under US generally accepted accounting principles, these
are considered long-term debt.
The change in net debt from December 31, 2002 to September 30, 2003 resulted
from:
Increase (Decrease)
(Cdn$ millions) in Net Debt
- -----------------------------------------------------------------------------------------------------
Cash Flow from Operations (1,449)
Capital Expenditures 933
Acquisition of the Residual 40% Interest in the Aspen Field 164
Net Proceeds on Disposition of Assets (268)
Dividends on Preferred Securities and Common Shares 77
Foreign Exchange (163)
Other 18
---------------------
Decrease in Net Debt (688)
=====================
Our working capital increased $468 million compared to December 31, 2002 due to
the following:
Increase in Cash and Short-Term Investments 295
Increase in Accounts Receivable (1) 69
Increase in Net Marketing Receivables (1) 33
Decrease in Accounts Payable and Accrued Liabilities (1) 44
Other 27
---------------------
468
=====================
Note:
1 Net marketing receivables represent accounts receivable less accounts
payable and accrued liabilities for our Marketing division.
o The increase in cash and short-term investments reflects the proceeds
received on the sale of our non-core properties in southeast Saskatchewan.
o Accounts receivable increased because there was no sale of receivables at
the end of the third quarter compared to December 31, 2002. Lower joint
venture receivables partially offset this increase.
o Net marketing receivables increased as a result of higher natural gas
prices offset by weaker crude oil prices.
o Accounts payable and accrued liabilities decreased due to the timing of
capital expenditures and the strengthening Canadian dollar relative to the
US dollar.
In October 2003, we filed a preliminary shelf prospectus with securities
commissions in the US and Canada allowing for the offering of up to US $1
billion in debt securities until late 2005.
34
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 consolidated financial position or results of
operations.
A subsidiary of Occidental Petroleum Corporation has requested the International
Chamber of Commerce arbitrate a settlement around ownership of two small areas
of Block 51 in Yemen. Occidental believes they have a right to a 50% interest in
these two areas based on an area of mutual interest agreement assigned to them
by Pecten International Company. This agreement has since expired. Prior to
expiry, the agreement provided that we were to offer the counterparty a 50%
interest upon our proposing to conduct petroleum development operations in these
areas. Since the expiry of this agreement, we have commenced exploration
activities on Block 51, including within the two small areas. Given that the
agreement has expired and we have not proposed to conduct petroleum development
operations, we believe Occidental's claim is without merit and we intend to
vigorously defend our contractual rights.
NEW ACCOUNTING PRONOUNCEMENTS
In September 2003, the CICA issued an amendment to CICA Handbook Section 3870
"Stock-Based Compensation and Other Stock-Based Payments". The amendment
provides two alternative methods of transition to the fair-value method of
accounting for stock-based employee compensation - prospective and retroactive
methods. In January 2003, the US Financial Accounting Standards Board (FASB)
issued Statement No. 148 "Accounting for Stock-Based Compensation - Transition
and Disclosure, an Amendment of FASB Statement No. 123" (FAS 148). FAS 148
amends FAS 123 "Accounting for Stock-Based Compensation", to provide alternative
methods of transition for a voluntary change to the fair-value method of
accounting for stock-based employee compensation. Both the Canadian and US
amendments only apply to voluntary transitions before January 1, 2004. Our
shareholders approved a resolution requiring us to expense stock options. As a
result, we plan to adopt the fair-value method of accounting for stock options
in the fourth quarter of 2003. We plan to adopt the fair-value based method
prospectively, whereby compensation cost will be recognized for all options
granted on or after January 1, 2003. All stock options granted prior to January
1, 2003 will continue to be accounted for under Accounting Principles Board
Opinion No. 25 "Accounting for Stock Issued to Employees" (APB 25) unless these
stock options are modified or settled subsequent to adoption. The impact of
adopting the fair-value based method will be immaterial in 2003.
In February 2003, the CICA issued Accounting Guideline 14, "Disclosure of
Guarantees" (AcG-14). AcG-14 elaborates on the disclosures required with respect
to any obligations we may have under certain guarantees that we have issued. The
disclosure requirements are effective for interim and annual periods beginning
on or after January 1, 2003. We adopted FASB Interpretation No. 45, "Guarantor's
Accounting and Disclosure Requirements for Guarantees, Including Indirect
Guarantees of Indebtedness to Others", the US equivalent of AcG-14 for the year
ended December 31, 2002. There were no material guarantees outstanding at
December 31, 2002 or September 30, 2003.
The following guideline issued by the CICA is not expected to impact us:
o Accounting Guideline 15, "Consolidation of Variable Interest Entities"
effective for annual and interim periods beginning on or after January 1,
2004.
The following standard issued by the FASB does not impact us:
o Statement No. 149 - "Amendment of Statement 133 on Derivative Instruments
and Hedging Activities" effective for contracts entered into or modified
after June 30, 2003 and for hedging relationships designated after June 30,
2003.
35
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 "plan", "expect", "estimate", "budget"
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 product supply and demand;
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 groups or
war.
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 2002 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 factors
are interdependent and management's future course of action depends upon our
assessment of all information available at that time. Amongst other things, 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 and our share of production 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 onstream.
We believe that the 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. 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.
36
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 in a manner
intended to minimize our exposure as described in our 2002 Annual Report on Form
10-K. Our sensitivity to key market risks for the remainder of the year are as
follows:
Cash Flow Net
(Cdn$ millions) from Operations Income
- --------------------------------------------------------------------------------------------------
Estimated remainder of year impact:
Crude Oil - US $1.00/bbl change in WTI 13 10
Natural Gas - US $0.50/mcf change 13 8
Foreign Exchange - $0.01 change in Cdn dollar to US dollar 6 2
----------------------------------
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 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 Nexen and its
consolidated subsidiaries would be made known to them by others within those
entities, particularly during the period in which this quarterly 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 judgement in
evaluating the cost-benefit relationship of possible controls and procedures.
CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING
We have continually had in place systems relating to internal controls and
procedures with respect to our financial information. There has not been any
change in our internal control over financial reporting during the period
covered by this report that has materially affected, or is reasonably likely to
materially affect, our internal control over financial reporting.
37
PART II. OTHER INFORMATION
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, 2003, we filed or furnished the following
reports on Form 8-K.
i. Current report on Form 8-K dated July 8, 2003 to file our press release
announcing a preliminary resource estimate for Usan field on Block 222,
Nigeria.
ii. Current report on Form 8-K dated July 17, 2003 to furnish our press
release announcing our second quarterly results for fiscal 2003.
38
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 24, 2003.
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)
39