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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 March 31, 2004
[_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from.............to..........
COMMISSION FILE NUMBER 1-6702
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 March 31, 2004, there were 128,214,588 common shares issued and outstanding.
NEXEN INC.
INDEX
PART I FINANCIAL INFORMATION PAGE
Item 1. Unaudited Consolidated Financial Statements ................................... 3
Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations...................................................... 22
Item 3. Quantitative and Qualitative Disclosures about Market Risk..................... 38
Item 4. Controls and Procedures........................................................ 38
PART II OTHER INFORMATION
Item 4. Submission of Matters to a Vote of Security Holders............................ 39
Item 6. Exhibits and Reports on Form 8-K............................................... 39
This report should be read in conjunction with our 2003 Annual Report on Form
10-K and with our current reports on Form 8-K filed or furnished on February 5,
February 13 and February 23, 2004.
SPECIAL NOTE TO CANADIAN INVESTORS
Nexen is a US Securities and Exchange Commission (SEC) registrant and a Form
10-K and related forms filer. Therefore, our reserves estimates and securities
regulatory disclosures generally follow SEC requirements. In 2003, certain
Canadian regulatory authorities adopted NATIONAL INSTRUMENT 51-101 - STANDARDS
OF DISCLOSURE FOR OIL AND GAS ACTIVITIES (NI 51-101) which prescribe that
Canadian companies follow certain standards for the preparation and disclosure
of reserves and related information. We have been granted certain exemptions
from NI 51-101. Please refer to the SPECIAL NOTE TO CANADIAN INVESTORS on page
60 of our 2003 Annual Report on Form 10-K.
UNLESS WE INDICATE OTHERWISE, ALL DOLLAR AMOUNTS ($) ARE IN CANADIAN DOLLARS,
AND OIL AND GAS VOLUMES, RESERVES AND RELATED PERFORMANCE MEASURES ARE PRESENTED
ON A WORKING-INTEREST, BEFORE-ROYALTIES BASIS. WHERE APPROPRIATE, INFORMATION ON
A NET, AFTER-ROYALTIES BASIS IS PRESENTED IN TABLES.
Below is a list of terms specific to the oil and gas industry. They are used
throughout the Form 10-Q.
/d = per day mboe = thousand barrels of oil equivalent
bbl = barrel mmboe = million barrels of oil equivalent
mbbls = thousand barrels mcf = thousand cubic feet
mmbbls = million barrels mmcf = million cubic feet
mmbtu = million British thermal units bcf = billion cubic feet
boe = barrels of oil equivalent NGL = natural gas liquid
Oil equivalents are used to aggregate quantities of natural gas with crude oil
by expressing them in a common unit. To calculate equivalents, we use 1 bbl = 6
mcf of natural gas.
Electronic copies of our filings with the SEC and the Ontario Securities
Commission (OSC) (from November 8, 2002 onward) are available, free of charge,
on our web site (www.nexeninc.com). Filings prior to November 8, 2002 are
available free of charge, upon request, by contacting our investor relations
department at (403) 699-5931. As soon as reasonably practicable, our filings are
made available on our website once they are electronically filed with the SEC or
the OSC. Alternatively, the SEC and the OSC each maintain a website (www.sec.gov
and www.sedar.com) that contain our reports, proxy and information statements
and other published information that have been filed or furnished with the SEC
and the OSC.
On March 31, 2004, the noon-day exchange rate for Cdn$1.00 was US$0.7631 as
reported by the Bank of Canada.
2
PART I
ITEM 1. UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
TABLE OF CONTENTS
Unaudited Consolidated Statement of Income
for the Three Months Ended March 31, 2004 and 2003...................................... 4
Unaudited Consolidated Balance Sheet
as at March 31, 2004 and December 31, 2003.............................................. 5
Unaudited Consolidated Statement of Cash Flows
for the Three Months Ended March 31, 2004 and 2003...................................... 6
Unaudited Consolidated Statement of Shareholders' Equity
for the Three Months Ended March 31, 2004 and March 31, 2003............................ 7
Notes to Unaudited Consolidated Financial Statements.................................... 8
3
NEXEN INC.
UNAUDITED CONSOLIDATED STATEMENT OF INCOME
FOR THE THREE MONTHS ENDED MARCH 31
Cdn$ millions, except per share amounts
2004 2003
- ---------------------------------------------------------------------------------------------------------
Restated for Change in
Accounting Principles
Note 1
REVENUES
Net Sales 743 806
Marketing and Other (Note 9) 158 175
--------------------------------
901 981
--------------------------------
EXPENSES
Operating 195 196
Transportation and Other 131 132
General and Administrative 60 37
Depreciation, Depletion and Amortization (Note 1) 182 183
Exploration 28 40
Interest (Note 4) 42 28
--------------------------------
638 616
--------------------------------
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES 263 365
--------------------------------
PROVISION FOR INCOME TAXES
Current 53 56
Future 18 65
--------------------------------
71 121
--------------------------------
NET INCOME FROM CONTINUING OPERATIONS 192 244
Net Income from Discontinued Operations (Note 10) -- 7
--------------------------------
NET INCOME 192 251
Dividends on Preferred Securities, Net of Income Taxes 2 11
--------------------------------
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS 190 240
================================
EARNINGS PER COMMON SHARE FROM CONTINUING OPERATIONS ($/share)
Basic (Note 7) 1.49 1.89
================================
Diluted (Note 7) 1.47 1.88
================================
EARNINGS PER COMMON SHARE ($/share)
Basic (Note 7) 1.49 1.95
================================
Diluted (Note 7) 1.47 1.94
================================
SEE ACCOMPANYING NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS.
4
NEXEN INC.
UNAUDITED CONSOLIDATED BALANCE SHEET
Cdn$ millions, except share amounts
March 31 December 31
2004 2003
- ------------------------------------------------------------------------------------------------------------
Restated for Change in
Accounting Principles
Note 1
ASSETS
CURRENT ASSETS
Cash and Short-Term Investments 800 1,087
Accounts Receivable (Note 2) 1,316 1,423
Inventories and Supplies (Note 3) 285 270
Other 33 79
-----------------------------------
Total Current Assets 2,434 2,859
-----------------------------------
PROPERTY, PLANT AND EQUIPMENT (Note 1)
Net of Accumulated Depreciation, Depletion and
Amortization of $5,118 (December 31, 2003 - $4,907) 4,718 4,550
GOODWILL 36 36
FUTURE INCOME TAX ASSETS 99 108
DEFERRED CHARGES AND OTHER ASSETS 136 153
-----------------------------------
7,423 7,706
===================================
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Current Portion of Long-Term Debt (Note 4) -- 291
Accounts Payable and Accrued Liabilities 1,400 1,404
Accrued Interest Payable 38 44
Dividends Payable 13 12
-----------------------------------
Total Current Liabilities 1,451 1,751
-----------------------------------
LONG-TERM DEBT (Note 4) 2,516 2,485
FUTURE INCOME TAX LIABILITIES (Note 1) 719 707
ASSET RETIREMENT OBLIGATIONS (Note 1) 311 305
OTHER DEFERRED CREDITS AND LIABILITIES 64 68
SHAREHOLDERS' EQUITY (Note 6)
Preferred and Subordinated Securities 33 364
Common Shares, no par value
Authorized: Unlimited
Outstanding: 2004 - 128,214,588 shares
2003 - 125,606,107 shares 595 513
Contributed Surplus 2 1
Retained Earnings (Note 1) 1,842 1,631
Cumulative Foreign Currency Translation Adjustment (110) (119)
-----------------------------------
Total Shareholders' Equity 2,362 2,390
-----------------------------------
COMMITMENTS AND CONTINGENCIES (Note 11)
7,423 7,706
===================================
SEE ACCOMPANYING NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS.
5
NEXEN INC.
UNAUDITED CONSOLIDATED STATEMENT OF CASH FLOWS
FOR THE THREE MONTHS ENDED MARCH 31
Cdn$ millions
2004 2003
- -----------------------------------------------------------------------------------------------------------
Restated for Change in
Accounting Principles
Note 1
OPERATING ACTIVITIES
Net Income from Continuing Operations 192 244
Net Income from Discontinued Operations -- 7
Charges and Credits to Income not Involving Cash (Note 8) 197 272
Exploration Expense 28 40
Changes in Non-Cash Working Capital (Note 8) 120 (66)
Other 22 (15)
---------------------------------
559 482
FINANCING ACTIVITIES
Proceeds from (Repayment of) Term Credit Facilities, Net -- 124
Repayment of Long-Term Debt (Note 4) (300) --
Proceeds from (Repayment of) Short-Term Borrowings, Net -- 14
Redemption of Preferred Securities (Note 6) (289) --
Dividends on Preferred Securities (3) (18)
Dividends on Common Shares (13) (9)
Issue of Common Shares 82 5
---------------------------------
(523) 116
INVESTING ACTIVITIES
Capital Expenditures
Exploration and Development (332) (325)
Proved Property Acquisitions -- (164)
Chemicals, Corporate and Other (11) (4)
Changes in Non-Cash Working Capital (Note 8) 8 (3)
---------------------------------
(335) (496)
EFFECT OF EXCHANGE RATE CHANGES ON CASH AND SHORT-TERM INVESTMENTS 12 (65)
---------------------------------
INCREASE (DECREASE) IN CASH AND SHORT-TERM INVESTMENTS (287) 37
CASH AND SHORT-TERM INVESTMENTS - BEGINNING OF PERIOD 1,087 59
---------------------------------
CASH AND SHORT-TERM INVESTMENTS - END OF PERIOD 800 96
=================================
SEE ACCOMPANYING NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS.
6
NEXEN INC.
UNAUDITED CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY
FOR THE THREE MONTHS ENDED MARCH 31, 2004 AND MARCH 31, 2003
Cdn$ millions
Cumulative
Preferred Foreign
and Currency
Subordinated Common Contributed Retained Translation
Securities Shares Surplus Earnings Adjustment
- ------------------------------------------------------------------------------------------------------------------------------
Restated for
Change in
Accounting
Principles
Note 1
DECEMBER 31, 2003 364 513 1 1,659 (119)
Retroactive Adjustment for Change in
Accounting Principles (Note 1) -- -- -- (28) --
Exercise of Stock Options -- 77 -- -- --
Issue of Common Shares -- 5 -- -- --
Redemption of Preferred Shares (Note 6) (331) -- -- -- --
Gain on Redemption of Preferred Securities,
Net of Income Taxes (Note 6) -- -- -- 34 --
Net Income -- -- -- 192 --
Dividends on Preferred Securities, Net of
Income Taxes -- -- -- (2) --
Dividends on Common Shares -- -- -- (13) --
Stock Option Expense -- -- 1 -- --
Translation Adjustment,
Net of Income Taxes -- -- -- -- 9
----------------------------------------------------------------------------
MARCH 31, 2004 33 595 2 1,842 (110)
============================================================================
DECEMBER 31, 2002 724 440 -- 1,069 115
Retroactive Adjustment for Change in
Accounting Principles (Note 1) -- -- -- (28) --
Exercise of Stock Options -- 1 -- -- --
Issue of Common Shares -- 4 -- -- --
Net Income -- -- -- 251 --
Dividends on Preferred Securities, Net of
Income Taxes -- -- -- (11) --
Dividends on Common Shares -- -- -- (9) --
Translation Adjustment,
Net of Income Taxes -- -- -- -- (65)
----------------------------------------------------------------------------
MARCH 31, 2003 724 445 -- 1,272 50
============================================================================
SEE ACCOMPANYING NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS.
7
NEXEN INC.
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
Cdn$ millions except as noted
1. ACCOUNTING POLICIES
The Unaudited Consolidated Financial Statements are prepared in accordance with
Canadian Generally Accepted Accounting Principles (GAAP). The impact of
significant differences between Canadian and US GAAP on the Unaudited
Consolidated Financial Statements is disclosed in Note 15. 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 March 31, 2004 and the results
of our operations and our cash flows for the three months ended March 31, 2004
and 2003.
Management makes estimates and assumptions that affect the reported amounts of
assets and liabilities and disclosure of contingent assets and liabilities at
the date of the Unaudited Consolidated Financial Statements, and revenues and
expenses during the reporting period. Our management reviews these estimates,
including those related to litigation, asset retirement obligations, income
taxes and determination of proved reserves, on an ongoing basis. Changes in
facts and circumstances may result in revised estimates and actual results may
differ from these estimates. The results of operations and cash flows for the
three months ended March 31, 2004 are not necessarily indicative of the results
of operations or cash flows to be expected for the year ending December 31,
2004.
These Unaudited Consolidated Financial Statements should be read in conjunction
with our Audited Consolidated Financial Statements included in our 2003 Annual
Report on Form 10-K. Except as described below, the accounting policies we
follow are described in Note 1 of the Audited Consolidated Financial Statements
included in our 2003 Annual Report on Form 10-K.
CHANGES IN ACCOUNTING PRINCIPLES
ASSET RETIREMENT OBLIGATIONS
On January 1, 2004, we retroactively adopted the Canadian Institute of Chartered
Accountants standard S.3110, ASSET RETIREMENT OBLIGATIONS. This new standard
requires recognition of a liability for the future retirement obligations
associated with our property, plant and equipment, which includes oil and gas
wells and facilities, and chemicals plants. The asset retirement obligation is
initially measured at fair value and capitalized to property, plant and
equipment as an asset retirement cost. The asset retirement obligation accretes
until the time the retirement obligation is expected to settle while the asset
retirement cost is amortized over the useful life of the underlying property,
plant and equipment.
The amortization of the asset retirement cost and the accretion of the asset
retirement obligation are included in depreciation, depletion and amortization
(DD&A). Actual retirement costs are recorded against the obligation when
incurred. Any difference between the recorded asset retirement obligation and
the actual retirement costs incurred is recorded as a gain or loss during the
period of settlement.
Our total estimated undiscounted asset retirement obligations amount to $511
million ($514 million - December 31, 2003). We have discounted the total
estimated asset retirement obligations using a weighted-average, credit-adjusted
risk-free rate of 5.6%. Approximately $75 million included in our asset
retirement obligations will be settled over the next five years. The remaining
obligations settle beyond five years and will be funded by future cash flows
from our operations.
We own interests in assets for which the fair value of the asset retirement
obligation cannot be reasonably determined because the assets currently have an
indeterminate life. These assets include our interest in a gas plant and our
interest in Syncrude's upgrader and sulphur inventory. The asset retirement
obligation for these assets will be recorded in the first year in which the
lives of the assets are determinable.
8
We previously provided for dismantlement and site restoration costs on our oil
and gas wells and facilities, and chemicals plants based on estimates
established by current legislation and industry practices. We recorded a
provision for these costs in DD&A based on proved reserves or estimated
remaining asset lives. Upon adoption of the new standard, accounting rules
require us to restate all prior periods presented to give effect to the change
in accounting principles. The impact on net income for the three months ended
March 31, 2003 and the impact on our Audited Consolidated Balance Sheet at
December 31, 2003, is shown below:
UNAUDITED CONSOLIDATED STATEMENT OF INCOME FOR THE THREE MONTHS ENDED
MARCH 31, 2003
Depletion, Depreciation and Amortization as Reported 183
Less: Dismantlement and Site Restoration (8)
Plus: Asset Retirement Cost Amortization 4
Plus: Asset Retirement Obligation Accretion 4
--------
Depletion, Depreciation and Amortization as Restated 183
========
CONSOLIDATED BALANCE SHEET AS AT DECEMBER 31, 2003
Cdn$ millions As Reported Change As Restated
- -------------------------------------------------------------------------------
Property, Plant and Equipment 4,469 81 4,550
Asset Retirement Obligations -- 305 305
Dismantlement and Site Restoration 179 (179) --
Future Income Tax Liabilities 724 (17) 707
Retained Earnings 1,659 (28) 1,631
---------------------------------------
RECLASSIFICATION
Certain comparative figures have been reclassified to ensure consistency with
current year presentation.
2. ACCOUNTS RECEIVABLE
March 31 December 31
2004 2003
- -------------------------------------------------------------------------------
Trade
Marketing 901 1,078
Oil and Gas 301 263
Chemicals and Other 52 47
--------------------------
1,254 1,388
Non-Trade 77 50
--------------------------
1,331 1,438
Allowance for Doubtful Accounts (15) (15)
--------------------------
1,316 1,423
==========================
3. INVENTORIES AND SUPPLIES
March 31 December 31
2004 2003
- -------------------------------------------------------------------------------
Finished Products
Marketing 145 138
Oil and Gas 10 16
Chemicals and Other 7 12
--------------------------
162 166
Work in Process 6 6
Field Supplies 117 98
--------------------------
285 270
==========================
9
4. LONG-TERM DEBT AND SHORT-TERM BORROWINGS
March 31 December 31
2004 2003
- -------------------------------------------------------------------------------
Unsecured Syndicated Term Credit Facilities -- --
Unsecured Redeemable Notes, due 2004 (a) -- 291
Unsecured Redeemable Debentures, due 2006 98 98
Unsecured Redeemable Medium-Term Notes, due 2007 150 150
Unsecured Redeemable Medium-Term Notes, due 2008 125 125
Unsecured Redeemable Notes, due 2013 655 646
Unsecured Redeemable Notes, due 2028 262 258
Unsecured Redeemable Notes, due 2032 655 646
Unsecured Subordinated Debentures, due 2043 571 562
--------------------------
2,516 2,776
Less: Current Portion of Long-Term Debt -- (291)
--------------------------
2,516 2,485
==========================
(a) UNSECURED REDEEMABLE NOTES, DUE 2004
In February 2004, our US$225 million of notes matured and we repaid the
principal at par.
(b) INTEREST EXPENSE
Three Months
Ended March 31
2004 2003
- ------------------------------------------------------------------------------
Long-Term Debt 46 34
Other 3 2
-------------------------
Total 49 36
Less: Capitalized (7) (8)
-------------------------
42 28
=========================
Capitalized interest relates to and is included as part of the cost of oil and
gas properties. The capitalization rates are based on our weighted-average cost
of borrowings.
10
5. DERIVATIVE INSTRUMENTS AND FINANCIAL RISK MANAGEMENT
(a) CARRYING VALUE AND ESTIMATED FAIR VALUE OF DERIVATIVE INSTRUMENTS
The carrying value, fair value, and unrecognized gains or losses on our
outstanding derivatives and long-term financial assets and liabilities are:
Cdn$ millions MARCH 31, 2004 DECEMBER 31, 2003
- --------------------------------------------------------------------------------- --------------------------------------
Carrying Fair Unrecognized Carrying Fair Unrecognized
Value Value Gain/(Loss) Value Value Gain/(Loss)
- --------------------------------------------------------------------------------- --------------------------------------
Net Assets/(Liabilities)
Commodity Price Risk -
Non-Trading Activities
Future Sale of Oil and Gas
Production -- -- -- -- (3) (3)
Commodity Price Risk-
Trading Activities
Crude Oil and Natural Gas 79 79 -- 106 106 --
Future Sale of Gas Inventory -- (1) (1) -- (11) (11)
Foreign Currency Risk 1 1 -- -- (1) (1)
--------------------------------------- --------------------------------------
Total Derivatives 80 79 (1) 106 91 (15)
======================================= ======================================
Financial Assets and Liabilities
Long-Term Debt (2,516) (2,815) (299) (2,485) (2,706) (221)
Preferred and Subordinated
Securities (33) (35) (2) (364) (319) 45
--------------------------------------- --------------------------------------
(2,549) (2,850) (301) (2,849) (3,025) (176)
======================================= ======================================
The estimated fair value of all derivative instruments is based on quoted market
prices and, if not available, on estimates from third-party brokers or dealers.
The carrying value of cash and short-term investments, amounts receivable and
short-term obligations approximates their fair value because the instruments are
near maturity.
(a) COMMODITY PRICE RISK MANAGEMENT
NON-TRADING ACTIVITIES
FUTURE SALE OF OIL AND GAS PRODUCTION
In March 2003, we sold WTI and NYMEX gas forward contracts for the next 12
months to lock-in part of the return on the remaining 40% interest acquired in
the Aspen field. The forward contracts fixed our oil and gas prices on the
future sales at the contract prices for the hedged volumes, less applicable
price differentials. These contracts expired in March 2004.
TRADING ACTIVITIES
FUTURE SALE OF GAS INVENTORY
Our marketing inventory is carried at the lower of cost and net realizable value
while generally our derivative contracts are stated at market value. To better
match our accounting with our economic exposure, we have designated certain
NYMEX natural gas futures contracts as hedges of our price risk on the future
sale of our inventory. These financial contracts have been designated in writing
as cash flow hedges. The principal terms of these outstanding contracts and the
unrecognized losses at March 31, 2004 are:
Hedged Average Unrecognized
Volumes Month Price Gain/(Loss)
- ----------------------------------------------------------------------------------------------
(mmcf) (US$/mcf) (Cdn$ millions)
NYMEX Natural Gas Futures 650 April 2004 4.67 --
3,000 February 2005 6.15 (1)
------------
(1)
============
11
TOTAL CARRYING VALUE OF DERIVATIVE ENERGY CONTRACTS
Amounts related to derivative energy contracts held by our marketing operation
are equal to fair value as we use mark-to-market accounting. The amounts are as
follows at:
March 31 December 31
Cdn$ millions 2004 2003
- -------------------------------------------------------------------------------
Accounts Receivable 81 102
Deferred Charges and Other Assets(1) 55 63
--------------------------
Total Derivative Energy Contract Assets 136 165
==========================
Accounts Payable and Accrued Liabilities 37 34
Other Deferred Credits and Liabilities(1) 20 25
--------------------------
Total Derivative Energy Contract Liabilities 57 59
==========================
Total Derivative Energy Contract Net Assets 79 106
==========================
Note:
(1) These derivative contracts settle beyond 12 months and are considered
non-current.
6. SHAREHOLDERS' EQUITY
(a) PREFERRED SECURITIES
In February 2004, we redeemed our US$217 million preferred securities at par.
The realized foreign exchange gain of $34 million, net of income taxes, for the
difference between the carrying value and the settlement amount was included in
retained earnings.
(b) PRO FORMA NET INCOME - FAIR-VALUE METHOD OF ACCOUNTING FOR STOCK OPTIONS
For options granted prior to January 1, 2003, we use the intrinsic-value based
method and recognize no compensation expense. For options granted after January
1, 2003, we use the fair-value based method and expense them over the vesting
period.
The following shows our pro forma net income and earnings per common share had
we applied the fair-value method to account for all options outstanding that
were granted up to December 31, 2002. The assumptions for the three months ended
March 31, 2004 are the same as for the year ended December 31, 2003, as
described in Note 7(f) to the Audited Consolidated Financial Statements included
in our 2003 Annual Report on Form 10-K.
Three Months
Ended March 31
2004 2003
- -------------------------------------------------------------------------------------------------------
Expense Attributable to all Stock Options Granted - Fair-Value Method 6 6
Less: Stock Options Expensed - Post-2002 Stock Option Grants (1) --
----------------------------
Expense Attributable to Pre-2003 Stock Option Grants 5 6
Net Income Attributable to Common Shareholders
As Reported 190 240
----------------------------
Pro Forma 185 234
============================
Earnings Per Common Share ($/share)
Basic as Reported 1.49 1.95
============================
Pro Forma 1.45 1.90
============================
Diluted as Reported 1.47 1.94
============================
Pro Forma 1.43 1.89
============================
(c) DIVIDENDS
Dividends per common share for the three months ended March 31, 2004 were $0.10
(2003 - $0.075).
12
7. EARNINGS PER COMMON SHARE
We calculate basic earnings per common share from continuing operations using
net income from continuing operations less dividends on preferred securities,
net of income taxes, divided by the weighted-average number of common shares
outstanding. We calculate basic earnings per common share using net income
attributable to common shareholders and the weighted-average number of common
shares outstanding. We calculate diluted earnings per common share from
continuing operations and diluted earnings per common share in the same manner
as basic, except we use the weighted-average number of diluted common shares
outstanding in the denominator.
Three Months
Ended March 31
(millions of shares) 2004 2003
- ---------------------------------------------------------------------------------------------
Weighted-average number of common shares outstanding 127.5 123.1
Shares issuable pursuant to stock options 7.4 5.1
Shares to be purchased from proceeds of stock options (5.6) (4.4)
------------------------
Weighted-average number of diluted common shares outstanding 129.3 123.8
========================
In calculating the weighted-average number of diluted common shares outstanding
for the three months ended March 31, 2004, all options were included because
their exercise price was less than the quarterly average common share market
price in the period. For the three months ended March 31, 2003, 4.2 million
options were excluded because their exercise price was greater than the
quarterly average common share market price. 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
Ended March 31
2004 2003
- ------------------------------------------------------------------------------
Depreciation, Depletion and Amortization 182 183
Future Income Taxes 18 65
Non-Cash Items included in Discontinued Operations -- 15
Other (3) 9
------------------------
197 272
========================
(b) CHANGES IN NON-CASH WORKING CAPITAL
Three Months
Ended March 31
2004 2003
- ------------------------------------------------------------------------------
Operating Activities
Accounts Receivable 115 (671)
Inventories and Supplies (16) 70
Other Current Assets 46 1
Accounts Payable and Accrued Liabilities (18) 548
Accrued Interest Payable (7) (14)
------------------------
120 (66)
Investing Activities
Accounts Payable and Accrued Liabilities 8 (3)
------------------------
Total 128 (69)
========================
13
(c) OTHER CASH FLOW INFORMATION
Three Months
Ended March 31
2004 2003
- ------------------------------------------------------------------------------
Interest Paid 53 50
Income Taxes Paid 49 54
------------------------
9. MARKETING AND OTHER
Three Months
Ended March 31
2004 2003
- ------------------------------------------------------------------------------
Marketing Revenue, Net 147 181
Interest 2 2
Foreign Exchange Gains (Losses) 6 (9)
Other 3 1
------------------------
158 175
========================
10. DISCONTINUED OPERATIONS
On August 28, 2003, we sold certain non-core conventional light oil properties
in southeast Saskatchewan in Canada. Net proceeds were $268 million and there
was no gain or loss on the sale. The results of operations from these properties
are detailed below and shown as discontinued operations in our Unaudited
Consolidated Statement of Income.
Three Months
Ended March 31
2004 2003
- ------------------------------------------------------------------------------
Revenues
Net Sales -- 28
Expenses
Operating -- 6
Depreciation, Depletion and Amortization -- 8
Exploration -- 1
------------------------
Income before Income Taxes -- 13
Future Income Taxes -- 6
------------------------
Net Income from Discontinued Operations -- 7
========================
Earnings Per Common Share ($/share)
Basic (Note 7) -- 0.06
========================
Diluted (Note 7) -- 0.06
========================
11. COMMITMENTS AND CONTINGENCIES
As described in Note 10 to the Audited Consolidated Financial Statements
included in our 2003 Annual Report on Form 10-K, there are a number of lawsuits
and claims pending, the ultimate results of which cannot be ascertained at this
time. We record costs as they are incurred or become determinable. We believe
the resolution of these matters would not have a material adverse effect on our
liquidity, consolidated financial position or results of operations.
14
12. PENSION AND OTHER POST RETIREMENT BENEFITS
(a) NET PENSION EXPENSE RECOGNIZED UNDER OUR DEFINED BENEFIT PENSION PLANS
Three Months
Ended March 31
2004 2003
- -------------------------------------------------------------------------------
Nexen
Cost of Benefits Earned by Employees 2 2
Interest Cost on Benefits Earned 3 3
Expected Return on Plan Assets (3) (2)
Net Amortization and Deferral -- --
------------------------
Net 2 3
------------------------
Syncrude
Cost of Benefits Earned by Employees 1 1
Interest Cost on Benefits Earned 1 1
Expected Return on Plan Assets (1) (1)
Net Amortization and Deferral -- --
------------------------
Net 1 1
------------------------
Total 3 4
========================
(b) EMPLOYER FUNDING CONTRIBUTIONS
Our expected total funding contributions for 2004 disclosed in Note 11(e) to the
Audited Consolidated Financial Statements in our 2003 Annual Report on Form 10-K
have not changed for both our Nexen defined benefit pension plan and our share
of Syncrude's defined benefit pension plan.
13. SUBSEQUENT EVENT
On May 4, 2004, our shareholders approved amendments to our stock option plan
including the conversion of the plan to a tandem option plan. Upon conversion of
the plan, we anticipate a one-time charge to net income of approximately $70 to
$80 million after tax. This estimated charge represents the "in-the-money"
amount of our stock options on a graded vesting basis assuming a $55 stock price
and 6.5 million outstanding options at the time of plan conversion.
15
14. OPERATING SEGMENTS AND RELATED INFORMATION
Nexen is involved in activities relating to Oil and Gas, Syncrude and Chemicals
in various geographic locations as described in Note 15 to the Audited
Consolidated Financial Statements included in our 2003 Annual Report on Form
10-K.
THREE MONTHS ENDED MARCH 31, 2004
(Cdn$ millions) Corporate
and
Oil and Gas Syncrude(1) Chemicals Other Total
- ------------------------------------------------------------------------------------------------------------------------------------
United Other
Yemen Canada States Australia Countries(2) Marketing
-----------------------------------------------------------------------------------------------------
Net Sales 207 144 181 28 13 3 75 92 -- 743
Marketing and Other 1 1 -- -- -- 147 -- 1 8(3) 158
-----------------------------------------------------------------------------------------------------
Total Revenues 208 145 181 28 13 150 75 93 8 901
Less: Expenses
Operating 28 40 20 16 1 4 29 57 -- 195
Transportation and Other 1 2 -- -- -- 116 2 10 -- 131
General and Administrative 1 12 6 -- 7 11 -- 6 17 60
Depreciation, Depletion
and Amortization 38 49 62 8 4 2 4 10 5 182
Exploration -- 7 9 -- 12(4) -- -- -- -- 28
Interest -- -- -- -- -- -- -- -- 42 42
-----------------------------------------------------------------------------------------------------
Income (Loss) from
Continuing Operations
before Income Taxes 140 35 84 4 (11) 17 40 10 (56) 263
===========================================================================================
Less: Provision for Income
Taxes(5) 71
Add: Net Income from
Discontinued Operations -
------
Net Income 192
======
Identifiable Assets 686 1,641 1,657 28 361 1,280(6) 769 469 532 7,423
=====================================================================================================
Capital Expenditures
Development and Other 47 91 93 -- 6 -- 50 6 5 298
Exploration 2 8 24 -- 11 -- -- -- -- 45
-----------------------------------------------------------------------------------------------------
49 99 117 -- 17 -- 50 6 5 343
=====================================================================================================
Property, Plant and Equipment
Cost 1,973 3,049 2,289 205 343 153 868 783 173 9,836
Less: Accumulated DD&A 1,556 1,510 957 205 221 56 145 391 77 5,118
-----------------------------------------------------------------------------------------------------
Net Book Value 417 1,539 1,332 -- 122 97 723 392 96 4,718
=====================================================================================================
Notes:
(1) Syncrude is considered a mining operation for US reporting purposes.
(2) Includes results of operations from producing activities in Nigeria and
Colombia.
(3) Includes interest income of $2 million and foreign exchange gains of $6
million.
(4) Includes exploration activities primarily in Nigeria and Colombia.
(5) Includes Yemen cash taxes of $46 million.
(6) Approximately 82% of Marketing's identifiable assets are accounts
receivable and inventories.
16
THREE MONTHS ENDED MARCH 31, 2003 (1)
(Cdn$ millions) Corporate
and
Oil and Gas Syncrude(2) Chemicals Other Total
- ------------------------------------------------------------------------------------------------------------------------------------
United Other
Yemen Canada(3) States Australia Countries(4) Marketing
-----------------------------------------------------------------------------------------------------
Net Sales 228 180 184 28 17 8 63 98 -- 806
Marketing and Other -- 1 -- -- -- 181 -- -- (7)(5) 175
-----------------------------------------------------------------------------------------------------
Total Revenues 228 181 184 28 17 189 63 98 (7) 981
Less: Expenses
Operating 21 34 21 13 4 7 30 66 -- 196
Transportation and Other -- -- 1 -- -- 119 2 10 -- 132
General and Administrative 1 8 3 -- 5 9 -- 5 6 37
Depreciation, Depletion
and Amortization 42 56 49 6 6 3 3 14 4 183
Exploration 2 17 15 -- 6(6) -- -- -- -- 40
Interest -- -- -- -- -- -- -- -- 28 28
-----------------------------------------------------------------------------------------------------
Income (Loss) from
Continuing Operations
before Income Taxes 162 66 95 9 (4) 51 28 3 (45) 365
===========================================================================================
Less: Provision for Income
Taxes(7) 121
Add: Net Income from
Discontinued Operations 7
------
Net Income 251
======
Identifiable Assets 601 2,223 1,590 59 149 1,507(8) 572 506 186 7,393
=====================================================================================================
Capital Expenditures
Development and Other 54 115 55 -- 5 -- 41 1 3 274
Exploration 1 18 25 1 10 -- -- -- -- 55
Proved Property Acquisitions -- -- 164(9) -- -- -- -- -- -- 164
-----------------------------------------------------------------------------------------------------
55 133 244 1 15 -- 41 1 3 493
=====================================================================================================
Property, Plant and Equipment
Cost 1,962 3,286 2,295 225 314 156 679 789 148 9,854
Less: Accumulated DD&A 1,572 1,226 948 202 208 46 145 365 59 4,771
-----------------------------------------------------------------------------------------------------
Net Book Value 390 2,060 1,347 23 106 110 534 424 89 5,083
=====================================================================================================
Notes:
(1) Restated to give effect to a change in accounting principles (see Note 1).
(2) Syncrude is considered a mining operation for US reporting purposes.
(3) Excludes results of our non-core conventional light oil assets in southeast
Saskatchewan that were sold. These results are shown as discontinued
operations (see Note 10).
(4) Includes results of operations from producing activities in Nigeria and
Colombia.
(5) Includes interest income of $2 million and foreign exchange losses of $9
million.
(6) Includes exploration activities primarily in Nigeria and Colombia.
(7) Includes Yemen cash taxes of $51 million.
(8) Approximately 87% of Marketing's identifiable assets are accounts
receivable and inventories.
(9) On March 27, 2003, we acquired the residual 40% interest in Aspen in the
Gulf of Mexico for US$109 million.
17
15. DIFFERENCES BETWEEN CANADIAN AND US GENERALLY ACCEPTED ACCOUNTING
PRINCIPLES
The Unaudited Consolidated Financial Statements have been prepared in accordance
with Canadian GAAP. The US GAAP Unaudited Consolidated Statement of Income and
Balance Sheet and summaries of differences from Canadian GAAP are as follows:
(a) UNAUDITED CONSOLIDATED STATEMENT OF INCOME - US GAAP
FOR THE THREE MONTHS ENDED MARCH 31
(Cdn$ millions, except per share amounts) 2004 2003
- ---------------------------------------------------------------------------------------------------------------------
REVENUES
Net Sales 743 806
Marketing and Other (i); (iv) 164 175
------------------------------
907 981
------------------------------
EXPENSES
Operating (vi) 197 196
Transportation and Other (i) 140 132
General and Administrative 60 37
Depreciation, Depletion and Amortization (iii) 193 198
Exploration 28 40
Interest (i) 45 46
------------------------------
663 649
------------------------------
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES 244 332
------------------------------
PROVISION FOR INCOME TAXES
Current 53 56
Deferred (i); (vi); (x) 27 57
------------------------------
80 113
------------------------------
NET INCOME FROM CONTINUING OPERATIONS BEFORE CUMULATIVE EFFECT
OF A CHANGE IN ACCOUNTING PRINCIPLES 164 219
Net Income from Discontinued Operations -- 7
Cumulative Effect of a Change in Accounting Principles, Net of Income Taxes (ix) -- (37)
------------------------------
NET INCOME - US GAAP(1) 164 189
==============================
EARNINGS PER COMMON SHARE ($/share)
Basic (Note 7)
Net Income from Continuing Operations 1.29 1.77
Net Income from Discontinued Operations - 0.06
Cumulative Effect of a Change in Accounting Principles - (0.30)
------------------------------
1.29 1.53
==============================
Diluted (Note 7)
Net Income from Continuing Operations 1.27 1.77
Net Income from Discontinued Operations - 0.06
Cumulative Effect of a Change in Accounting Principles - (0.30)
------------------------------
1.27 1.53
==============================
Note:
(1) RECONCILIATION OF CANADIAN AND US GAAP NET INCOME
Three Months
Ended March 31
(Cdn$ millions) 2004 2003
- -------------------------------------------------------------------------------------------------------
Net Income - Canadian GAAP 192 251
Impact of US Principles, Net of Income Taxes:
Depreciation, Depletion and Amortization (iii) (11) (14)
Dividends on Preferred Securities (i) (2) (11)
Future Income Taxes (x) (15) --
Issue Costs on Preferred Securities Redeemed (i) (6) --
Cumulative Effect of Changes in Accounting Principles (ix) -- (37)
Fair Value of Preferred Securities (i) 4 --
Other (iv); (vi) 2 --
---------------------------
Net Income - US GAAP 164 189
===========================
18
(b) UNAUDITED CONSOLIDATED BALANCE SHEET - US GAAP
March 31 December 31
(Cdn$ millions, except per share amounts) 2004 2003
- --------------------------------------------------------------------------------------------------------------------
ASSETS
CURRENT ASSETS
Cash and Short-Term Investments 800 1,087
Accounts Receivable 1,316 1,423
Inventories and Supplies 285 270
Other 33 79
----------------------------------
Total Current Assets 2,434 2,859
----------------------------------
PROPERTY, PLANT AND EQUIPMENT
Net of Accumulated Depreciation, Depletion and
Amortization of $5,516 (December 31, 2003 - $5,330) (iii); (vi); (ix) 4,751 4,583
GOODWILL 36 36
DEFERRED INCOME TAX ASSETS 99 108
DEFERRED CHARGES AND OTHER ASSETS (i); (vii) 90 117
----------------------------------
7,410 7,703
==================================
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Current Portion of Long-Term Debt -- 575
Accounts Payable and Accrued Liabilities (iv) 1,401 1,418
Accrued Interest Payable 38 44
Dividends Payable 13 12
----------------------------------
Total Current Liabilities 1,452 2,049
----------------------------------
LONG-TERM DEBT (i); (ii); (vii) 2,503 2,472
DEFERRED INCOME TAX LIABILITIES (i) - (x) 704 676
ASSET RETIREMENT OBLIGATIONS 311 305
OTHER DEFERRED CREDITS AND LIABILITIES (viii) 66 70
SHAREHOLDERS' EQUITY
Common Shares, no par value
Authorized: Unlimited
Outstanding: 2004 - 128,214,588 shares
2003 - 125,606,107 shares 595 513
Contributed Surplus 2 1
Retained Earnings (i); (iii); (iv); (vi); (ix); (x) 1,811 1,660
Accumulated Other Comprehensive Income (i); (ii); (iv); (v); (viii) (34) (43)
----------------------------------
Total Shareholders' Equity 2,374 2,131
----------------------------------
COMMITMENTS AND CONTINGENCIES
7,410 7,703
==================================
(c) UNAUDITED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME - US GAAP FOR THE
THREE MONTHS ENDED MARCH 31
(Cdn$ millions) 2004 2003
- ------------------------------------------------------------------------------------------------------------------
Net Income - US GAAP 164 189
Other Comprehensive Income, Net of Income Taxes:
Translation Adjustment (i); (ii); (v) 3 (25)
Unrealized Mark-to-Market Gain (iv) 6 3
--------------------------------
Comprehensive Income 173 167
================================
19
(d) UNAUDITED CONSOLIDATED STATEMENT OF CASH FLOWS
Under US principles, dividends on preferred securities of $3 million for the
three months ended March 31, 2004 (March 31, 2003 - $18 million) that are
included in financing activities would be reported in operating activities.
Under US principles, geological and geophysical costs of $18 million for the
three months ended March 31, 2004 (March 31, 2003 - $13 million) that are
included in investing activities would be reported in operating activities.
(e) OTHER SUPPLEMENTARY INFORMATION
Three Months
Ended March 31
2004 2003
- ------------------------------------------------------------------------------------------------------------------
Pro Forma Earnings - Fair-Value Method of Accounting for Stock Options - US GAAP
Net Income - US GAAP
As Reported 164 189
Plus: Fair Value of Stock Options Granted after December 31, 2002 1 --
Less: Fair Value of All Stock Options Granted (6) (6)
----------------------------
Pro Forma 159 183
----------------------------
Earnings Per Common Share ($/share)
Basic as Reported 1.29 1.53
============================
Pro Forma 1.25 1.48
============================
Diluted as Reported 1.27 1.53
============================
Pro Forma 1.23 1.48
============================
NOTES:
i. Under US principles, we are required to classify our preferred
securities as long-term debt rather than shareholders' equity. As a
result:
o dividends of $3 million during the quarter were included in
interest expense, with the related income tax of $1 million
included in the provision for income taxes;
o pre-tax issue costs of $10 million were included in deferred
charges and other assets, rather than as an after-tax charge to
retained earnings; and
o foreign-currency translation losses of $8 million during the
quarter were included in accumulated other comprehensive income
(AOCI).
Under US principles, we are also required to recognize in earnings the
change in fair value of the preferred securities. As a result, a gain
of $4 million for the change in fair value up to the redemption date
was included in marketing and other.
In February 2004, we redeemed at par US$217 million of preferred
securities. Under Canadian principles, a foreign exchange gain of $34
million, net of income tax, was recognized in retained earnings. Under
US principles, this foreign exchange gain had been included in AOCI.
Unamortized issue costs of $10 million were included in transportation
and other.
ii. Under US principles, all of our subordinated securities are classified
as long-term debt. As a result, the $33 million equity component has
been included in long-term debt.
iii. Under US principles, the liability method of accounting for income
taxes was adopted in 1993. In Canada, the liability method was adopted
in 2000. In 1997, we acquired certain oil and gas assets and the amount
paid for these assets differed from the tax basis acquired. Under US
principles, this difference was recorded as a deferred tax liability
with an increase to property, plant and equipment rather than a charge
to retained earnings. As a result, additional depreciation, depletion
and amortization of $11 million was included in net income during the
quarter.
20
iv. Under US principles, all derivative instruments are recognized on the
balance sheet as either an asset or a liability measured at fair value.
Changes in the fair value of derivatives are recognized in earnings
unless specific hedge criteria are met.
CASH FLOW HEDGES
Changes in the fair value of derivatives that are designated as cash
flow hedges are recognized in earnings in the same period as the hedged
item. Any fair value change in a derivative before that period is
recognized on the balance sheet. The effective portion of that change
is recognized in other comprehensive income with any ineffectiveness
recognized in net income.
FUTURE SALE OF OIL AND GAS PRODUCTION: Included in accounts payable at
December 31, 2003, was a $3 million loss on the forward contracts we
used to hedge the commodity price risk in the future sale of a portion
of our production from the Aspen field as described in Note 5. These
contracts expired in March 2004. The losses ($2 million, net of income
tax), deferred in AOCI at December 31, 2003, were recognized in net
sales during the quarter.
FUTURE SALE OF GAS INVENTORY: Included in accounts payable at December
31, 2003, was $11 million of losses on the futures and basis swap
contracts we used to hedge the commodity price risk in the future sale
of our gas inventory as described in Note 5. These contracts lock in
profits on our stored gas volumes. Losses of $8 million ($5 million,
net of income taxes) related to the effective portion and deferred in
AOCI at December 31, 2003, were recognized in marketing and other
during the quarter. Additionally, losses of $3 million ($2 million, net
of income taxes), related to the ineffective portion, were recognized
in marketing and other under Canadian GAAP. Under US GAAP, the
ineffective portion was recognized in net income in 2003.
At March 31, 2004, losses of $1 million were included in accounts
payable. The effective portion of the losses of $1 million, net of
income taxes, have been deferred in AOCI until the underlying gas
inventory is sold. All the deferred losses will be reclassified to
marketing and other in the next 12 months. At March 31, 2004, the
ineffective portion was $nil.
FAIR VALUE HEDGES
Both the derivative instrument and the underlying commitment are
recognized on the balance sheet at their fair value. The change in fair
value of both are reflected in earnings. At March 31, 2004, we had no
fair value hedges in place.
v. Under US principles, exchange gains and losses arising from the
translation of our net investment in self-sustaining foreign operations
are included in comprehensive income. Additionally, exchange gains and
losses, net of income taxes, from the translation of our US-dollar
long-term debt designated as a hedge of our foreign net investment are
included in comprehensive income. Cumulative amounts are included in
AOCI in the Unaudited Consolidated Balance Sheet.
vi. Under Canadian principles, we defer certain development costs and all
pre-operating revenues and costs to property, plant and equipment. For
the three months ended March 31, 2004, we deferred $2 million of
pre-operating expenses. Under US principles, these costs have been
included in operating expenses.
vii. Under US principles, discounts on long-term debt are classified as a
reduction of long-term debt rather than as deferred charges and other
assets. Discounts of $46 million have been included in long-term debt.
viii. Under US principles, the amount by which our accrued pension cost is
less than the unfunded accumulated benefit obligation is included in
AOCI and accrued pension liabilities. This amount was $2 million at
March 31, 2004 (December31, 2003 - $2 million).
ix. On January 1, 2003 we adopted FASB Statement No. 143, ACCOUNTING FOR
ASSET RETIREMENT OBLIGATIONS (FAS 143) for US GAAP reporting purposes.
We adopted the equivalent Canadian standard for asset retirement
obligations on January 1, 2004 as described in Note 1. These standards
are consistent except for the adoption date.
This change in accounting policy has been reported as a cumulative
effect adjustment in the Unaudited Consolidated Statement of Income as
a loss of $37 million, net of income taxes of $25 million on January 1,
2003.
x. Under US principles, enacted tax rates are used to calculate future
income taxes, whereas under Canadian GAAP, substantively enacted tax
rates are used. Substantively enacted changes in Canadian provincial
income tax rates created a $15 million future income tax recovery
during the first quarter of 2004.
21
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
THE FOLLOWING SHOULD BE READ IN CONJUNCTION WITH THE UNAUDITED CONSOLIDATED
FINANCIAL STATEMENTS INCLUDED IN THIS REPORT. THE UNAUDITED CONSOLIDATED
FINANCIAL STATEMENTS HAVE BEEN PREPARED IN ACCORDANCE WITH GENERALLY ACCEPTED
ACCOUNTING PRINCIPLES (GAAP) IN CANADA. THE IMPACT OF THE SIGNIFICANT
DIFFERENCES BETWEEN CANADIAN AND UNITED STATES (US) ACCOUNTING PRINCIPLES ON THE
FINANCIAL STATEMENTS IS DISCLOSED IN NOTE 15 TO THE UNAUDITED CONSOLIDATED
FINANCIAL STATEMENTS.
UNLESS OTHERWISE NOTED, TABULAR AMOUNTS ARE IN MILLIONS OF CANADIAN DOLLARS. THE
DISCUSSION AND ANALYSIS OF OUR OIL AND GAS ACTIVITIES WITH RESPECT TO OIL AND
GAS VOLUMES, RESERVES AND RELATED PERFORMANCE MEASURES IS PRESENTED ON A
WORKING-INTEREST, BEFORE-ROYALTIES BASIS. WE MEASURE OUR PERFORMANCE IN THIS
MANNER CONSISTENT WITH OTHER CANADIAN OIL AND GAS COMPANIES. WHERE APPROPRIATE,
WE HAVE PROVIDED INFORMATION ON A NET, AFTER-ROYALTY BASIS IN TABULAR FORMAT.
NOTE: CANADIAN INVESTORS SHOULD READ THE SPECIAL NOTE TO CANADIAN INVESTORS ON
PAGE 60 IN OUR 2003 ANNUAL REPORT ON FORM 10-K WHICH HIGHLIGHTS DIFFERENCES
BETWEEN OUR RESERVE ESTIMATES AND RELATED DISCLOSURES THAT ARE OTHERWISE
REQUIRED BY CANADIAN REGULATORY AUTHORITIES.
EXECUTIVE SUMMARY OF FIRST QUARTER RESULTS
Three Months
Ended March 31
(Cdn$ millions) 2004 2003
- -------------------------------------------------------------------------------
Net Income 192 251
Earnings per Common Share ($/share) 1.49 1.95
Cash Flow from Operations(1) 417 563
Production, before Royalties (mboe/d) 258 264
Production, after Royalties (mboe/d) 176 177
Capital Expenditures 343 493
High commodity prices and continuing growth of high-margin production in the
Gulf of Mexico led to strong financial results for the quarter. The stronger
Canadian dollar and higher costs combined with a smaller contribution from
marketing reduced our financial results relative to 2003.
The stronger Canadian dollar has continued to erode our realized commodity
prices, causing our net income and cash flow from operations to be lower than
their highs in the first quarter of 2003. Our realized average sales price for
our oil and gas production was $45.84/boe in the first quarter of 2003 compared
to $40.11/boe in 2004. Despite this decrease in our sales revenue, we benefit to
the extent our foreign operating costs and capital expenditures are also reduced
when translated. Compared to the first quarter of 2003, the stronger Canadian
dollar relative to the US dollar reduced our quarterly net income by
approximately $45 million and our quarterly cash flow from operating activities
by $85 million. Less volatile gas markets in North America reduced the record
contribution of our marketing operation in 2003.
Our core operations in Canada, the shallow-water Gulf of Mexico, and Masila are
continuing to generate significant free cash flow. This has allowed us to
continue our strategic focus in the deep-water Gulf of Mexico, offshore West
Africa, the Athabasca oil sands and the Middle East, and to continue to
strengthen our balance sheet.
Note:
(1) We evaluate our performance and that of our business segments based on
earnings and cash flow from operations. Cash flow from operations is a non-GAAP
term that represents cash generated from operating activities before changes in
non-cash working capital and other. We consider it a key measure as it
demonstrates our ability and the ability of our business segments to generate
the cash flow necessary to fund future growth through capital investment and
repay debt. Cash flow from operations may not be comparable with the calculation
of similar measures for other companies.
Three Months
Ended March 31
(Cdn$ millions) 2004 2003
- ------------------------------------------------------------------------------
Cash Flow from Operating Activities 559 482
Changes in Non-Cash Working Capital (120) 66
Other (22) 15
---------------------------
Cash Flow from Operations 417 563
===========================
22
On February 3, 2004, we announced our proved reserves estimates as at December
31, 2003. The announcement included negative reserves revisions in the amount of
67 million boe, representing 8% of our total world-wide reserves. Of this
amount, 60 million boe related to our conventional proved reserves in Canada
which resulted in a non-cash, after-tax impairment charge of $175 million in the
fourth quarter of 2003. Over 80% of this charge related to conventional heavy
oil reserves.
The following table explains these reserves revisions:
Future
Production Changes in
Reduction Profile Economic
(mmboe) in PUD's Changes Assumptions Total
- -------------------------------------------------------------------------------
Canada (17) (30) (13) (60)
Yemen (11) -- -- (11)
Other -- 4 -- 4
------------------------------------------------------------
(28) (26) (13) (67)
============================================================
Of the total revisions, 26 million boe related to heavy oil reserves, 22 million
boe related to light and medium oil reserves and 19 million boe related to
natural gas reserves. With respect to the revisions in Canada, 17 million boe
resulted from a reduction in proved undeveloped reserves (PUD's) based on
drilling results and geological mapping, 30 million boe resulted from changes in
the estimated future production profiles of certain properties and 13 million
boe was attributable to changes in late field-life economic assumptions
primarily related to changes in year-end Canadian dollar prices and our
estimates of future operating costs. In Yemen, we reduced our estimate of Masila
Block proved reserves by 11 million barrels based on drilling results and new
geological mapping.
These revisions have no impact on our production guidance for 2004.
In February 2004, our Board sanctioned the Long Lake Synthetic Crude Oil Project
and we booked 200 million barrels of proved reserves.
CAPITAL INVESTMENT
Three Months
Ended March 31
(Cdn$ millions) 2004 2003
- ---------------------------------------------------------------------------------------------
Yemen 49 55
Canada 57 97
Long Lake Synthetic 42 36
United States 117 244
Other Countries 17 16
Syncrude 50 41
Chemicals, Corporate and Other 11 4
----------------------------
343 493
============================
Development 287 270
Exploration 45 55
Acquisition of the Residual 40% Interest in the Aspen Field -- 164
Chemicals, Corporate and Other 11 4
----------------------------
343 493
============================
23
GULF OF MEXICO
ASPEN
Development drilling at Aspen continued in the first quarter. With the tie-in of
our third development well, we expect production from Aspen to increase to
30,000 boe per day in the third quarter.
GUNNISON
Gunnison, our second deep-water Gulf of Mexico field, came on stream in December
with three of the field's ten wells producing. Since year-end, we have completed
the fourth and fifth development wells at Gunnison and are currently producing
140 million cubic feet of gas and 12,000 barrels of oil per day. As the
remaining wells are completed, field production is expected to increase to peak
daily rates between 165 and 180 million cubic feet of gas and 28,000 and 30,000
barrels of oil by year-end. Our 30% share of peak daily rates will range between
55 to 60 million cubic feet per day of gas and between 9,000 and 10,000 barrels
of oil per day.
OTHER
We completed drilling activities at the Dawson Deep prospect located
approximately three miles from the Gunnison production facility on Garden Banks
Block 625. We hold a 15% interest in this discovery and are currently evaluating
opportunities for subsea development and tie-back to Gunnison. We expect to
drill several additional prospects in the Gunnison area this year.
In March, we acquired a 13.34% interest in the Tobago prospect. Tobago is
located in 7,500 feet of water on Alaminos Canyon Block 859 and the east half of
Block 858, between the Great White and Trident discoveries. The first
exploration well on the prospect recently completed drilling. The well
encountered hydrocarbons. Tobago could be part of any Alaminos Canyon area
development that may be built in the future to produce a number of other
existing discoveries.
At the recent Central Gulf of Mexico lease sale 190, we were high bidder on 9
blocks, one of which included the Knotty Head prospect on Green Canyon 512.
MIDDLE EAST
MASILA
We continued to invest in development drilling for our Masila project to
maintain production rates from this area. Twenty development wells were
completed during the quarter, with 60 to 70 additional wells expected in the
remainder of the year. We have installed a duplicate single point mooring buoy
and offshore loading system to ensure reliable operations.
BLOCK 51
Development is progressing at our Bashair al Khair-A (BAK) field, where our
interest is 87.5%. To date, we have drilled eight successful delineation wells
and four development wells, with six additional development wells planned for
later this year. Engineering work on a 35,000 bbls/d central processing
facility, a gathering system, and pipeline tie-back (capacity - 100,000 bbls/d)
to our Masila export system is advancing. Construction is scheduled to start in
June 2004, with production beginning in early 2005. Peak production is expected
to reach between 20,000 and 25,000 boe/d during the first quarter of 2005.
We believe that Block 51 holds further potential, some of which we will test
through the drilling of six exploration wells in the second half of the year. We
have also oversized the facilities in anticipation of further success.
OFFSHORE WEST AFRICA
Offshore Nigeria, Nexen is reviewing development plans for the Usan field on
OPL-222, where we have a 20% interest. On the exploration front, the Usan West-1
exploration well, located 4 miles west of the main Usan field will commence
drilling later this month in 2,400 feet of water. Usan West-1 is the first well
in a multi-well exploration program designed to test a series of independent
prospects on the block.
On OML-115, offshore Nigeria, seismic acquisition has been completed. Seismic
reprocessing is currently underway on Block K, offshore Equatorial Guinea. We
expect to drill on each of these blocks in the second half of this year, after
seismic interpretation has been completed.
24
ATHABASCA OIL SANDS
SYNTHETIC OIL AT LONG LAKE
In February, our Board of Directors approved proceeding with commercial
development of the Long Lake Synthetic Crude Oil project where we hold a 50%
interest. As a result, we converted 200 million barrels of probable reserves for
this project to proved reserves. The Long Lake project will develop
approximately 15% of our Athabasca bitumen resource and will upgrade this
bitumen into a high-quality, light, sweet, premium synthetic crude oil (PSC).
The project will ramp up to produce 60,000 barrels of PSC per day (30,000 net to
Nexen), beginning in 2007.
Clearing and grading of the facilities site has commenced and long lead-time
equipment is being ordered. Facilities construction is scheduled to begin in the
third quarter of 2004, with the steam-assisted-gravity-drainage facilities
completed in 2006 and the upgrader facilities in 2007.
SYNCRUDE
At the Syncrude Joint Venture, progress on the Stage 3 expansion is continuing.
We expect this expansion to add 110,000 barrels per day (8,000 net to Nexen) of
production. Recent analysis by Syncrude and independent experts indicates a
delayed start-up to mid-2006, contributing to an increased gross capital cost
from an estimated $5.7 billion to $7.8 billion. Of the total $7.8 billion,
approximately $2 billion is attributable to costs related to base plant
improvements, product quality enhancements and environmental mitigation
measures. The Syncrude owners are currently reviewing the gross capital costs
and timing for the Stage 3 expansion. We have a 7.23% interest in the Syncrude
Joint Venture.
25
FINANCIAL RESULTS
CHANGE IN NET INCOME
(Cdn$ millions) 2004 VS. 2003
- ---------------------------------------------------------------------------------------------------
NET INCOME AT MARCH 31, 2003(1) 251
=============
Favourable (unfavourable) variances:
Cash Items:
Production volumes, after royalties:
Crude oil (5)
Natural gas 20
Crude oil sales volumes, after royalties 2
Realized commodity prices:
Crude oil (56)
Natural gas (41)
Oil and gas operating expense:
Conventional (6)
Syncrude 1
Marketing (33)
Chemicals 4
General and administrative (23)
Interest expense (14)
Current income taxes 3
Other 2
-------------
Total Cash Variance (146)
Non-Cash Items:
Depreciation, depletion and amortization
Oil and Gas 6
Other 3
Exploration expense 13
Future income taxes 53
Other 12
-------------
Total Non-Cash Variance 87
-------------
NET INCOME AT MARCH 31, 2004 192
=============
Note:
(1) Includes results of discontinued operations (see Note 10 to our Unaudited
Consolidated Financial Statements).
Significant variances in net income are explained further in the following
sections.
26
OIL AND GAS
PRODUCTION
Three Months Ended March 31
2004 2003
- --------------------------------------------------------------------------------------------------------------------------
Before After Before After
Royalties Royalties Royalties Royalties
-------------------------------------------------------------------
Oil and Liquids (mbbls/d)
Yemen 114.1 54.0 116.0 55.4
Canada (1) 36.8 28.6 49.2 37.3
United States 26.7 23.5 21.7 19.1
Australia 4.5 4.2 8.0 6.5
Other Countries 4.9 4.2 6.3 5.3
Syncrude 18.3 18.1 13.6 13.5
-------------------------------------------------------------------
205.3 132.6 214.8 137.1
-------------------------------------------------------------------
Natural Gas (mmcf/d)
Canada (1) 149 120 161 124
United States 167 142 135 114
-------------------------------------------------------------------
316 262 296 238
-------------------------------------------------------------------
Total (mboe/d) 258 176 264 177
===================================================================
Note:
(1) 2003 includes the following production from discontinued operations. (See
Note 10 to our Unaudited Consolidated Financial Statements):
(mboe/d) 2004 2003
- -------------------------------------------------------------------------------
Before Royalties -- 9.7
After Royalties -- 7.0
------------------------
QUARTERLY PRODUCTION INCREASED NET INCOME FOR THE QUARTER BY $15 MILLION
Production after royalties was flat compared to 2003, while production before
royalties fell 2% from the first quarter of 2003. Our 2003 production volumes
included volumes attributable to non-core Canadian light oil properties in
southeast Saskatchewan that were sold in August 2003. Excluding these volumes,
our production after royalties increased by more than 4% and before royalties
increased 2%. The following table summarizes our production volume changes:
Before After
mboe/d Royalties Royalties
- -------------------------------------------------------------------------------------------------------------
Production, first quarter 2003 264 177
Sale of non-core Canadian properties (10) (7)
----------------------------
254 170
Deep-water Gulf of Mexico production growth
Aspen 5 4
Gunnison 7 6
Syncrude production increase 5 5
Maturing properties in Canada, Australia, Gulf of Mexico Shelf and Yemen (13) (9)
----------------------------
Production, first quarter 2004 258 176
============================
Our growth in low-royalty production in the deep waters of the Gulf of Mexico
and at Syncrude have more than offset the lower production volumes from our
maturing conventional assets. The change in production mix to higher-margin
volumes has increased our cash flow at constant prices.
MASILA BLOCK IN YEMEN
Production before royalties decreased 2% consistent with the ongoing decline in
the field's base production. As the field matures, we continue to drill more
development wells and perform more workovers to manage the declines. Our
expanded drilling program late in 2003 successfully increased our production to
120,000 barrels per day (net to us). Our rate has since decreased to 112,000
barrels as our development drilling has slowed with delays in approvals. Upon
receiving the anticipated approvals, we expect to stabilize production and
achieve our target of 112,000 bbls/d for the year.
27
CANADA
Our conventional assets in the Western Canadian Sedimentary Basin continue to
mature. Of the total 20% decrease, two-thirds was due to the August 2003 sale of
non-core, light-oil properties in southeast Saskatchewan. The remaining decrease
reflected natural production rate declines as we continue to limit our capital
investment in mature assets. These declines relate primarily to our heavy oil
properties as water cuts have increased and wells at Edam have sanded up.
We expect our conventional production to remain relatively flat for the
remainder of the year as we continue to manage the fields, optimizing the
remaining production. However, we expect increases as our Long Lake project
starts up with the production of bitumen in 2006 and synthetic crude in 2007.
GULF OF MEXICO
Growth in the Gulf of Mexico continued, increasing production 23% compared to
the first quarter of 2003. Production additions and optimization activities on
our shelf assets at Eugene Island 295 and Eugene Island 255 offset expected
declines on other shelf properties.
Our March 2003 acquisition of the remaining 40% interest in the Aspen field
boosted production in comparison to last year. Water cuts on our Aspen 1 well
have been increasing and we experienced two days of downtime on our Aspen 2 well
as we began additional development drilling and gathered pressure build-up data
on Aspen 2. This data allowed us to increase rates on Aspen 2. We are continuing
to review well data and to assess optimization opportunities that would allow us
to maximize production. We expect Aspen production to increase from current
rates of 18,700 equivalent barrels to over 30,000 equivalent barrels in the
third quarter when our third development well comes on-stream.
With three wells producing and the fourth on-stream late in the quarter,
Gunnison delivered 7,000 boe per day (net to us), increasing total production
from the Gulf by 16%. In April, the fifth development well was completed
increasing daily rates to 10,000 boe (net to us). We expect Gunnison production
rates to increase to 17,000 boe (net to us) by the end of the year. Our
deep-water volumes continue to deliver increasing returns, contributing cash
netbacks that are twice our corporate average.
With new deep-water production on-stream and ongoing optimization of our shelf
assets, we expect the Gulf of Mexico to remain our fastest growing area in 2004.
We estimate our production rates will reach over 75,000 boe by year end.
OTHER COUNTRIES
Although production from Buffalo, offshore Australia and at Ejulebe, offshore
Nigeria declined as expected, the areas continued to benefit from high commodity
prices. We expect final production from Australia and Nigeria later in the year.
Our successful 2003 development program in Colombia increased daily production
rates to 4,100 barrels, 83% higher than the first quarter of 2003. Once our
full-field waterflood program on Guando is complete, rates should increase to
5,000 barrels late in the year.
SYNCRUDE
Syncrude production increased 35% compared to the first quarter of 2003. Gross
production of 253,000 bbls per day (18,300 net to us) set a new first quarter
production record. Maintenance and turnaround activities in 2003 delivered
greater operational reliability. With the exception of some minor repairs,
little maintenance was required during the first quarter of 2004.
28
COMMODITY PRICES
Three Months
Ended March 31
2004 2003
- --------------------------------------------------------------------------------
CRUDE OIL AND NGLS
West Texas Intermediate (WTI) (US$/bbl) 35.15 33.86
-------------------------
Differentials(1) (US$/bbl):
Masila 3.82 2.99
Heavy Oil 9.87 8.23
Mars 4.67 4.77
Realized Prices (Cdn$/bbl):
Yemen 41.88 45.69
Canada 32.51 39.48
United States 38.99 46.00
Syncrude 45.54 51.84
Australia 42.60 48.13
Other Countries 37.07 48.84
Corporate Average (Cdn$/bbl) 40.22 44.93
-------------------------
NATURAL GAS
New York Mercantile Exchange (NYMEX) (US$/mmbtu) 5.73 6.32
AECO (Cdn$/mcf) 6.26 7.51
-------------------------
Realized Prices (Cdn$/mcf):
Canada 5.59 6.77
United States 7.63 10.22
Corporate Average (Cdn$/mcf) 6.63 8.35
-------------------------
AVERAGE REALIZED OIL AND GAS PRICE (Cdn$/boe) 40.11 45.84
AVERAGE FOREIGN EXCHANGE RATE
Canadian to US Dollar (US$) 0.7588 0.6622
-------------------------
Note:
(1) These differentials are a discount to WTI.
LOWER REALIZED COMMODITY PRICES DECREASED QUARTERLY NET INCOME BY $97 MILLION
Both crude oil and natural gas commodity prices remained strong in the first
quarter of 2004, with crude oil benchmark prices reaching 10-year highs. Despite
the strength in reference prices, our average realized oil and gas price in
Canadian dollars declined 13% due to the strength of the Canadian dollar
compared to the first quarter of 2003. Widening differentials contributed
modestly to the decline.
All of our oil sales and most of our gas sales are denominated in or referenced
to US dollars. As a result, the strong Canadian dollar decreased net sales by
approximately $100 million, and reduced our realized crude oil price by
approximately $6 per barrel and our realized natural gas price by $1.15 per mcf.
Furthermore, our US-dollar denominated debt is reduced with a strengthening
Canadian dollar.
CRUDE OIL REFERENCE PRICES
Crude oil prices remained strong in the first quarter of 2004 as supply and
demand fundamentals continued to support strong prices. WTI averaged
approximately US$35 per barrel for the quarter reaching highs in excess of US$38
per barrel. These fundamentals include:
o Growing demand from China and India;
o OPEC's ongoing determination to support prices with production cuts;
o The decline in value of the US dollar relative to other major world
currencies;
o Low crude oil and product inventories in North America;
o Concerns over supply disruptions in Venezuela, Nigeria and Iraq; and
o Continued political tension and violence in the Middle East.
29
In addition, concerns over gasoline supplies heading into the summer driving
season, OPEC's announced one million barrel per day production cut and
speculative positions in the oil markets have pushed WTI up 10% since the start
of the year. More recently, increased strategic petroleum reserve purchases by
the US government have fuelled further increases.
Expectations for future crude oil prices are mixed. Strong demand, political
unrest, OPEC discipline and speculation around these events could push WTI
higher. On the other hand, a slowdown in the US or cheating on quotas within
OPEC could drive WTI down.
CRUDE OIL DIFFERENTIALS
Differentials generally widened in the first quarter of 2004 due mostly to the
overall strength in WTI.
In the first quarter 2003, the heavy oil differential narrowed as a result of
supply disruptions in Venezuela and delays in bringing on new Canadian heavy oil
production. In 2004, the Canadian heavy oil differential has widened as demand
for WTI has grown with no matching increase in demand for heavy oil. In general,
demand for lighter crudes increased with growing demand for high quality
gasoline. March differentials widened significantly to average US$10.91 per
barrel as a result of higher marker prices and problems and turnarounds at
several refineries. April differentials have widened further as problems and
unplanned refinery maintenance continued during the month. The heavy
differential is expected to narrow with peak seasonal demand in the spring and
summer.
The Masila differential continued to generally track the Brent/WTI spread. In
part, the differential widened as low product inventory levels in the US
strengthened WTI relative to Brent. Demand for sweeter crudes to fuel increasing
gasoline demand in southeast Asia has also reduced demand for sour crudes like
Masila causing further differential widening.
The Mars differential, which our Aspen production is priced off, remained
comparable to the first quarter of 2003. Supply disruptions from Venezuela or
the cutting of sour OPEC blends could cause Mars to narrow further in the short
term.
NATURAL GAS REFERENCE PRICES
North American natural gas prices were lower in the first quarter of 2004, but
remained strong. In 2004, demand and storage levels returned to more normal
levels during the winter months. While the perception of adequate inventory
levels has placed some downward pressure on gas prices, this was moderated by
cold winter weather, especially in January, long-term supply concerns and strong
crude oil prices. An early start to the injection season has caused inventories
to build, however concerns over the adequacy of supply for next winter are
keeping prices strong.
OPERATING COSTS
Three Months Ended March 31
(Cdn$/boe) 2004 2003
- -----------------------------------------------------------------------------------------------------
Before After Before After
Royalties(1) Royalties Royalties(1) Royalties
--------------------------------------------------------------
Conventional Oil and Gas(2) 4.78 7.21 4.40 6.77
Synthetic Crude Oil
Syncrude 17.41 17.59 24.91 25.07
Total Oil and Gas(2) 5.67 8.26 5.46 8.18
--------------------------------------------------------------
Notes:
(1) Operating costs per boe are our total oil and gas operating costs divided
by our working interest production before royalties. We use production
before royalties to monitor our performance consistent with other Canadian
oil and gas companies.
(2) 2003 operating costs include results of discontinued operations (see Note
10 to our Unaudited Consolidated Financial Statements).
HIGHER OIL AND GAS OPERATING COSTS LOWERED NET INCOME FOR THE QUARTER BY
$5 MILLION
Conventional unit operating costs were higher as workover and maintenance
activities designed to maintain our base production in Yemen and on the shelf in
the Gulf of Mexico increased. Growth in low-cost deep-water production from the
Gulf of Mexico and the stronger Canadian dollar partially offset these
increases.
Higher water-handling costs, and increased maintenance and workover activity in
Yemen increased our total unit operating costs by 40(cent) per boe for the
quarter. Higher unit operating costs offshore Australia contributed a 20(cent)
per boe increase as our fixed costs are spread over fewer barrels.
30
Our production costs in the deep-water of the Gulf of Mexico are about US$1.15
per boe, $4.50 per boe lower than our corporate average as most of the costs in
the deep water are capital related. Offsetting this were higher workover and
maintenance costs on the shelf in the Gulf of Mexico. The strength of the
Canadian dollar reduced US-dollar denominated operating costs, lowering our
corporate unit costs by 39(cent) per boe.
Higher production rates, less maintenance activity and lower natural gas costs
decreased Syncrude operating costs by 30%. With greater operational reliability
planned this year, Syncrude unit operating costs are expected to be between $18
and $19 per barrel for the year including energy costs.
DEPRECIATION, DEPLETION AND AMORTIZATION (DD&A)
Three Months Ended March 31
(Cdn$/boe) 2004 2003
- ---------------------------------------------------------------------------------------------------
Before After Before After
Royalties(1) Royalties Royalties(1) Royalties
--------------------------------------------------------------
Conventional Oil and Gas(2) 7.32 11.04 7.44 11.46
Synthetic Crude Oil
Syncrude 2.65 2.68 2.67 2.70
Average Oil and Gas(2) 6.99 10.19 7.19 10.78
--------------------------------------------------------------
Notes:
(1) DD&A per boe is our DD&A for oil and gas operations divided by our working
interest production before royalties. We use production before royalties to
monitor our performance consistent with other Canadian oil and gas
companies.
(2) 2003 DD&A includes results of discontinued operations (see Note 10 to our
Unaudited Consolidated Financial Statements).
LOWER OIL AND GAS DD&A INCREASED NET INCOME FOR THE QUARTER BY $6 MILLION
Depletion rates decreased due to the strength in the Canadian dollar and the
lower carrying value of our Canadian heavy oil properties following their write
down late last year. We benefited from the strong Canadian dollar as the
depletion of our US and international assets is denominated in US dollars. This
lowered our depletion rate by 72(cent) per boe. The write down of our Canadian
heavy oil properties reduced our depletion rate by 60(cent) per boe. Depletion
of our more capital-intensive deep-water assets offset these savings.
EXPLORATION EXPENSE (1)
Three Months
Ended March 31
(Cdn$ millions) 2004 2003
- -------------------------------------------------------------------------------
Seismic 18 13
Unsuccessful Exploration Drilling -- 13
Other 10 15
------------------------
Total Exploration Expense 28 41
========================
Total Exploration Capital 45 55
Exploration Expense as a % of Exploration Capital (%) 62 75
------------------------
Note:
(1) 2003 exploration expense includes $1 million relating to discontinued
operations (see Note 10 to our Unaudited Consolidated Financial
Statements).
LOWER EXPLORATION EXPENSE INCREASED NET INCOME FOR THE QUARTER BY $13 MILLION
Our exploration efforts during the quarter were primarily focused on seismic
acquisition to finalize locations for drilling later this year. We acquired and
evaluated seismic data on OML-115 in Nigeria and expect to begin drilling our
first prospect this summer. There were no dry hole costs in the quarter. We have
temporarily abandoned our Shark well in the Gulf of Mexico while we continue to
evaluate well data.
31
OIL AND GAS MARKETING
Three Months
Ended March 31
(Cdn$ millions) 2004 2003
- ------------------------------------------------------------------------------------------------
Marketing Revenue, net 147 181
Transportation (116) (119)
Other (1) 1
-------------------------------
Contribution from Marketing 30 63
===============================
Physical Sales Volumes (excluding intra-segment transactions)
Crude Oil (mboe/d) 416 470
Natural Gas (mmcf/d) 4,378 3,614
Value-at-Risk
Quarter-end 26 18
High 26 31
Low 17 16
Average 21 21
-------------------------------
LOWER CONTRIBUTION FROM MARKETING REDUCED NET INCOME BY $33 MILLION
Marketing's quarterly net income was down, given smaller trading margins
associated with the lower price volatility of natural gas. In 2003, we achieved
record results as we used our pipeline capacity to capitalize on widening gas
price differentials between eastern and western North America and we sold 8.5
billion cubic feet of gas in storage when gas prices were exceptionally high.
Although our 2004 results did not match our record in 2003, they continue to be
solid. Our Marketing group generates fee-for-service income from serving the
needs of their clients. In addition, profits were realized on the sale of
natural gas in storage and on trading gas location basis and seasonal spreads.
COMPOSITION OF NET MARKETING REVENUE
Three Months
Ended March 31
(Cdn$ millions) 2004 2003
- ------------------------------------------------------------------------------
Derivative Energy Contracts 25 56
Non-Derivative Energy Contracts 5 7
------------------------
30 63
========================
DERIVATIVE ENERGY CONTRACTS
Our marketing operation engages in crude oil and natural gas marketing
activities to enhance prices from the sale of our own production, and for energy
marketing and trading. We enter into contracts to purchase and sell crude oil
and natural gas. These derivative energy contracts are valued as described in
the MD&A included in our 2003 Annual Report on Form 10-K.
FAIR VALUE OF DERIVATIVE ENERGY CONTRACTS
At March 31, 2004, the fair value of our derivative energy contracts not
designated as hedges totalled $79 million. The following table shows the
valuation methods underlying these contracts together with details of contract
maturity:
(Cdn$ millions) MATURITY
- ------------------------------------------------------------------------------------------------------------------------
less than more than
1 year 1-3 years 4-5 years 5 years Total
---------------------------------------------------------------------
Prices
Actively Quoted Markets 5 1 -- -- 6
From Other External Sources 39 34 2 (2) 73
Based on Models and Other Valuation Methods -- -- -- -- --
---------------------------------------------------------------------
Total 44 35 2 (2) 79
=====================================================================
More than 55% of the unrealized gain is related to contracts that will settle
within 12 months. Contract maturities vary from a single day up to six years.
Those maturing beyond one year are primarily from natural gas related positions.
The relatively short maturity position of our contracts lowers our portfolio
risk.
32
At March 31, 2004, the unrecognized losses on our derivative energy contracts
accounted for as hedges of the future sale of our gas inventory totalled $1
million. The following table shows the valuation methods underlying these
contracts together with details of contract maturity:
(Cdn$ millions) MATURITY
- ------------------------------------------------------------------------------------------------------------------------
less than more than
1 year 1-3 years 4-5 years 5 years Total
---------------------------------------------------------------------
Price
Actively Quoted Markets (1) -- -- -- (1)
From Other External Sources -- -- -- -- --
Based on Models and Other Valuation Models -- -- -- -- --
---------------------------------------------------------------------
Total (1) -- -- -- (1)
=====================================================================
CHANGES IN FAIR VALUE OF DERIVATIVE ENERGY CONTRACTS
Contracts
Contracts Contracts Entered into
Outstanding Entered into During Period
at Beginning and Closed and Outstanding
(Cdn$ millions) of Period During Period at End of Period Total
- ------------------------------------------------------------------------------------------------------------------------------
Fair Value at December 31, 2003 106 -- -- 106
Change in Fair Value of Contracts (12) 21 16 25
Net Losses (Gains) on Contracts Closed (31) (21) -- (52)
Changes in Valuation Techniques and Assumptions(1) -- -- -- --
---------------------------------------------------------------------
Fair Value at March 31, 2004 63 -- 16 79
==================================================
Unrecognized Losses on Hedges of Future Sale
of Gas Inventory at March 31, 2004 (1)
--------
Total Outstanding at March 31, 2004 78
========
Note:
(1) Our valuation methodology has been applied consistently year-over-year.
TOTAL CARRYING VALUE OF DERIVATIVE ENERGY CONTRACTS
March 31 December 31
(Cdn$ millions) 2004 2003
- -------------------------------------------------------------------------------
Current Assets 81 102
Non Current Assets 55 63
--------------------------
Total Derivative Energy Contract Assets 136 165
==========================
Current Liabilities 37 34
Non Current Liabilities 20 25
--------------------------
Total Derivative Energy Contract Liabilities 57 59
==========================
Total Derivative Energy Contract Net Assets(1) 79 106
==========================
Note:
(1) Does not include derivative energy contracts accounted for as hedges.
NON-DERIVATIVE ENERGY CONTRACTS
We enter into fee for service contracts related to transportation and storage of
third party oil and gas. In addition, we earn income from our power generation
facility. We earned $5 million from our non-derivative energy activities in the
first quarter (2003 - $7 million).
33
CHEMICALS
HIGHER CASH FLOW FROM CHEMICALS OPERATIONS INCREASED NET INCOME BY $4 MILLION
Higher productivity, growth in Brazil sales volumes and lower operating costs
increased cash flow from operations. The strong Canadian dollar partially offset
this as it decreased our US-dollar denominated sales. The lower operating costs
were largely the result of the Taft plant closure in the US. Severance costs
related to the closure were paid in 2003. The Taft assets were idled and
transferred to Brandon, Manitoba to allow us to take advantage of lower
electricity costs.
CORPORATE EXPENSES
GENERAL AND ADMINISTRATIVE (G&A)
Three Months
Ended March 31
(Cdn$ millions) 2004 2003
- --------------------------------------------------------------------------------
General and Administrative 60 37
----------------------------
HIGHER COSTS DECREASED QUARTERLY NET INCOME BY $23 MILLION
Approximately $16 million of the G&A increase relates to higher variable
compensation. Our average share price for the first quarter of 2004 was $49.39
compared to $32.24 in 2003. Increasing share prices increase the cost associated
with our employee stock appreciation rights program.
With our major development projects in the deep water of the Gulf of Mexico now
on stream, we have capitalized fewer costs. Rising regulatory compliance
contributed to the remainder.
INTEREST
Three Months
Ended March 31
(Cdn$ millions) 2004 2003
- -------------------------------------------------------------------------------
Interest 49 36
Less: Capitalized Interest (7) (8)
----------------------------
Net Interest Expense 42 28
============================
HIGHER INTEREST EXPENSE REDUCED QUARTERLY NET INCOME BY $14 MILLION
In late 2003 and early 2004, we refinanced our preferred securities with lower
cost debt. As a result, dividends on the preferred securities have been replaced
with interest expense on our new debt. This increase in interest expense has
been partially offset by the strong Canadian dollar, which has lowered our
US-dollar denominated interest expense by $6 million.
INCOME TAXES
Three Months
Ended March 31
(Cdn$ millions) 2004 2003
- ------------------------------------------------------------------------------
Current 53 56
Future 18 65
----------------------------
Provision for Income Taxes 71 121
============================
Effective Tax Rate (%) 27 33
----------------------------
EFFECTIVE TAX RATE FOR THE QUARTER DECREASES TO 27% FROM 33%
A 1% corporate income tax rate reduction in Alberta lowered our effective tax
rate and resulted in a $15 million recovery of future income taxes. Our
effective tax rate for 2004 is expected to be 31%.
Current income taxes include cash taxes in Yemen of $46 million (2003 - $51
million). Our current income tax provision also includes alternative minimum tax
and state taxes in the US and capital taxes in Canada.
34
LIQUIDITY
CAPITAL STRUCTURE
March 31 December 31
(Cdn$ millions) 2004 2003
- ----------------------------------------------------------------------------------------------
Bank Debt -- --
Long-Term Debt 2,516 2,776
------------------------------
2,516 2,776
Less: Cash (800) (1,087)
Less: Non-Cash Working Capital (183) (312)
------------------------------
Net Debt (1) 1,533 1,377
Preferred and Subordinated Securities 33 364
------------------------------
Net Debt, including Preferred and Subordinated Securities 1,566 1,741
==============================
Shareholders' Equity (2),(3) 2,362 2,390
==============================
Notes:
(1) Long-term debt less working capital.
(2) Shareholders' equity includes preferred securities of $331 million (US$217
million) at December 31, 2003 and the equity component of the subordinated
securities of $33 million (US$25 million) at March 31, 2004 and December
31, 2003. Under US generally accepted accounting principles, these are
considered long-term debt.
(3) At March 31, 2004, there were 128,214,588 common shares and US$460 million
of unsecured subordinated securities outstanding. These subordinated
securities may be redeemed by the issuance of common shares at our option
after November 8, 2008. The number of shares to be issued will depend upon
the common share price on the redemption date.
In February 2004, we redeemed US$217 million of preferred securities and repaid
US$225 million of senior notes, which reduced shareholders' equity and debt,
respectively. We took advantage of the low interest rate environment in 2003 and
financed these repayments by issuing US$960 million of public debt in the fourth
quarter. Shareholders' equity remains strong with solid quarterly financial
results and $82 million of proceeds from the issuance of common shares.
CHANGE IN WORKING CAPITAL
March 31 December 31 Increase/
(Cdn$ millions) 2004 2003 (Decrease)
- -----------------------------------------------------------------------------------------------
Cash and Short-Term Investments 800 1,087 (287)
Accounts Receivable 1,316 1,423 (107)
Inventories and Supplies 285 270 15
Accounts Payable and Accrued Liabilities (1,400) (1,404) 4
Other (18) 23 (41)
---------------------------------------------
983 1,399 (416)
=============================================
Cash and short-term investments decreased with the redemption of our preferred
securities and the repayment of our senior notes in February 2004. These
repayments were offset in part by our solid quarterly cash flow from operations
and by proceeds received on the exercise of employee stock options. Our accounts
receivable in marketing decreased as the amount of business transacted in March
decreased with lower seasonal demand. Typically, transaction volumes decrease
heading into the second quarter as seasonal winter demand falls off. This volume
decrease was offset, in part, by stronger commodity prices since year-end.
The decrease in other was related to the prepayment of natural gas storage
inventory in December. This was included in inventory during the quarter.
35
NET DEBT
Our net debt levels are directly related to our operating cash flows and our
capital expenditure activities. During the quarter, we successfully reduced net
debt, including preferred and subordinated securities, by $175 million:
(Cdn$ millions)
- ----------------------------------------------------------------------------------------------
Capital Expenditures 343
Cash Flow from Operations (417)
------------
(74)
Dividends on Preferred Securities and Common Shares 16
Issue of Common Shares (82)
Other (35)
------------
Decrease in Net Debt, including Preferred and Subordinated Securities (175)
============
OUTLOOK FOR REMAINDER OF 2004
Our full-year production outlook is 255,000 to 275,000 boe/d before royalties,
and 180,000 to 195,000 boe/d after royalties. We expect to generate
approximately $1.6 billion in cash flow from operations in 2004 assuming the
following for the remainder of the year:
- ----------------------------------------------------------------------------------------------
WTI (US$/bbl) 30.00
NYMEX natural gas (US$/mmbtu) 4.25
US to Canadian dollar exchange rate 0.75
Our 2004 capital investment program has been increased from $1.8 billion to $1.9
billion. The increase includes another $47 million for the Syncrude Stage 3
expansion and US$56 million of capital relating to our deep-water development
activities at Aspen in the US Gulf of Mexico.
Our future liquidity remains strong given our increasing cash flow from
operations and the ongoing strength of our balance sheet. We continue to
maintain a strong cash position and $1.7 billion of undrawn committed credit
facilities. As a result, we have the necessary resources to fund our capital
programs, dividend requirements and debt repayments, as well as the obligations
that arise from our day-to-day operations. In the first quarter, we declared
common share dividends of $0.10 per share.
CONTRACTUAL OBLIGATIONS, COMMITMENTS AND GUARANTEES
We have assumed various contractual obligations and commitments in the normal
course of our operations and financing activities. We have included these
obligations and commitments in our MD&A included in our 2003 Annual Report on
Form 10-K. These obligations have not changed significantly since year-end.
CONTINGENCIES
There are a number of lawsuits and claims pending, the ultimate results of which
cannot be ascertained at this time. We record costs as they are incurred or
become determinable. We believe the resolution of these matters would not have a
material adverse effect on our liquidity, consolidated financial position or
results of operations. These matters are described in LEGAL PROCEEDINGS in Item
3 contained in our 2003 Annual Report on Form 10-K. There have been no
significant developments since year-end.
NEW ACCOUNTING PRONOUNCEMENTS
In November 2003, the CICA approved an amendment to S.3860, FINANCIAL
INSTRUMENTS - DISCLOSURE AND PRESENTATION to clarify the difference between an
equity and liability instrument. An equity instrument exists only when an
instrument is settled in shares. This amendment is effective for fiscal years
beginning on or after November 1, 2004. Once adopted, the equity component of
our subordinated securities would be reclassified from equity to long-term debt,
and the dividends paid would be classified as interest expense. Adoption of this
amendment at March 31, 2004, would increase long-term debt by $33 million and
decrease subordinated securities by $33 million.
36
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS
Certain statements in this report, including those appearing in ITEM 2 -
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS, are forward-looking statements.(1) Forward-looking statements are
generally identifiable by terms such as ANTICIPATE, BELIEVE, INTEND, PLAN,
EXPECT, ESTIMATE, BUDGET, OUTLOOK or other similar words.
These statements are subject to known and unknown risks and uncertainties and
other factors which may cause actual results, levels of activity and
achievements to differ materially from those expressed or implied by such
statements. These risks, uncertainties and other factors include:
o market prices for oil, natural gas and chemicals products;
o our ability to produce and transport crude oil and natural gas to markets;
o the results of exploration and development drilling and related activities;
o foreign-currency exchange rates;
o economic conditions in the countries and regions in which we carry on
business;
o governmental actions that increase taxes, change environmental and other
laws and regulations;
o renegotiations of contracts; and
o political uncertainty, including actions by terrorists, insurgent or other
groups, or other armed conflict, including conflict between states.
The above items and their possible impact are discussed more fully in the
section, titled BUSINESS RISK MANAGEMENT and MARKET RISK MANAGEMENT in Item 7 of
our 2003 Annual Report on Form 10-K.
The impact of any one risk, uncertainty or factor on a particular
forward-looking statement is not determinable with certainty as these are
interdependent and management's future course of action depends upon our
assessment of all information available at that time. Any statements regarding
the following are forward-looking statements:
o future crude oil, natural gas or chemicals prices;
o future production levels;
o future cost recovery oil revenues from our operations in Yemen;
o future capital expenditures and their allocation to exploration and
development activities;
o future sources of funding for our capital program;
o future debt levels;
o future cash flows and their uses;
o future drilling of new wells;
o ultimate recoverability of reserves;
o expected finding and development costs;
o expected operating costs;
o future demand for chemicals products;
o future expenditures and future allowances relating to environmental
matters; and
o dates by which certain areas will be developed or will come on-stream.
We believe that any forward-looking statements made are reasonable based on
information available to us on the date such statements were made. However, no
assurance can be given as to future results, levels of activity and
achievements. We undertake no obligation to update publicly or revise any
forward-looking statements contained in this report. All subsequent
forward-looking statements, whether written or oral, attributable to us or
persons acting on our behalf are expressly qualified in their entirety by these
cautionary statements.
- --------------------
(1) Within the meaning of the United States PRIVATE SECURITIES LITIGATION
REFORM ACT OF 1995, Section 21E of the United States SECURITIES EXCHANGE
ACT OF 1934, as amended, and Section 27A of the United States SECURITIES
ACT OF 1933, as amended.
37
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We are exposed to all of the normal market risks inherent within the oil and gas
and chemicals business, including commodity price risk, foreign-currency rate
risk, interest rate risk and credit risk. We manage our operations to minimize
our exposure, as described in our 2003 Annual Report on Form 10-K. Our
sensitivities to key market risks for 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 40 31
Natural Gas - US$0.50/mcf change in NYMEX 45 28
Foreign Exchange - $0.01 change in Cdn dollar to US dollar 16 7
------------------------------
ITEM 4. CONTROLS AND PROCEDURES
EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES
Our Chief Executive Officer and Chief Financial Officer have evaluated the
effectiveness of our disclosure controls and procedures (as defined in Exchange
Act Rules 13a-15(e) and 15-d-15(e)) as of the end of the period covered by this
report. They concluded that, as of the end of the period covered by this report,
our disclosure controls and procedures were adequate and effective in ensuring
that material information relating to the Company and its consolidated
subsidiaries would be made known to them by others within those entities,
particularly during the period in which this report was being prepared.
Management recognizes that any controls and procedures, no matter how well
designed and operated, can provide only reasonable assurance of achieving the
desired control objectives, and in reaching a reasonable level of assurance,
management necessarily is required to apply its judgement in evaluating the
cost-benefit relationship of possible controls and procedures.
CHANGES IN INTERNAL CONTROLS
We have continually had in place systems relating to internal control over
financial reporting. There has not been any change in the Company's internal
control over financial reporting during the first quarter of 2004 that has
materially affected, or is reasonably likely to materially affect, the Company's
internal control over financial reporting.
38
PART II
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) EXHIBITS
31.1 Certification of Chief Executive Officer pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.
31.2 Certification of Chief Financial Officer pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.
32.1 Certification of periodic report by Chief Executive Officer pursuant to 18
U.S.C. Section 1350, as adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.
32.2 Certification of periodic report by Chief Financial Officer pursuant to 18
U.S.C. Section 1350, as adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.
(b) REPORTS ON FORM 8-K
During the quarter ended March 31, 2004, we filed or furnished the following
reports on Form 8-K:
o Current report on Form 8-K dated February 5, 2004, to file our press
release announcing our reserves and changes therein as at December 31,
2003 (summarized on page 23).
o Current report on Form 8-K dated February 13, 2004, to furnish our press
release announcing our 2003 annual financial results.
o Current report on Form 8-K dated February 23, 2004, to file our press
release announcing the booking of 200 million barrels of proved reserves
based on Board approval of the commercial development of our Long Lake
Synthetic Crude project.
39
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 May 7, 2004.
NEXEN INC.
/s/ Charles W. Fischer
----------------------
Charles W. Fischer
President and Chief Executive Officer
(Principal Executive Officer)
/s/ Michael J. Harris
---------------------
Michael J. Harris
Controller
(Principal Accounting Officer)
40