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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, 2005
[_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from.............to..........
COMMISSION FILE NUMBER 1-6702
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, 2005, there were 129,990,330 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.................................... 24
Item 3. Quantitative and Qualitative Disclosures about Market Risk... 43
Item 4. Controls and Procedures...................................... 43
PART II OTHER INFORMATION
Item 4. Submission of Matters to a Vote of Security Holders.......... 44
Item 6. Exhibits and Reports on Form 8-K............................. 44
This report should be read in conjunction with our 2004 Annual Report on Form
10-K and with our current reports on Form 8-K filed or furnished on January 12,
February 4, February 10, February 25, March 7 and March 11, 2005.
SPECIAL NOTE TO CANADIAN INVESTORS
Nexen is a US Securities and Exchange Commission (SEC) registrant and a Form
10-K and related forms filer. Therefore, our reserves estimates and securities
regulatory disclosures generally follow SEC requirements. In 2004, certain
Canadian regulatory authorities adopted NATIONAL INSTRUMENT 51-101 - STANDARDS
OF DISCLOSURE FOR OIL AND GAS ACTIVITIES (NI 51-101) which prescribe that
Canadian companies follow certain standards for the preparation and disclosure
of reserves and related information. We have been granted certain exemptions
from NI 51-101. Please refer to the SPECIAL NOTE TO CANADIAN INVESTORS on page
72 of our 2004 Annual Report on Form 10-K.
UNLESS WE INDICATE OTHERWISE, ALL DOLLAR AMOUNTS ($) ARE IN CANADIAN DOLLARS,
AND OIL AND GAS VOLUMES, RESERVES AND RELATED PERFORMANCE MEASURES ARE PRESENTED
ON A WORKING-INTEREST, BEFORE-ROYALTIES BASIS. WHERE APPROPRIATE, INFORMATION ON
A NET, AFTER-ROYALTIES BASIS IS PRESENTED IN TABLES. VOLUMES AND RESERVES
INCLUDE SYNCRUDE OPERATIONS UNLESS OTHERWISE NOTED.
Below is a list of terms specific to the oil and gas industry. They are used
throughout the Form 10-Q.
/d = per day mboe = thousand barrels of oil equivalent
bbl = barrel mmboe = million barrels of oil equivalent
mbbls = thousand barrels mcf = thousand cubic feet
mmbbls = million barrels mmcf = million cubic feet
mmbtu = million British thermal units bcf = billion cubic feet
boe = barrels of oil equivalent NGL = natural gas liquid
WTI = West Texas Intermediate
Oil equivalents (boes) are used to aggregate quantities of natural gas with
crude oil by expressing them in a common unit. To calculate equivalents, we use
1 bbl = 6 mcf of natural gas. Boes may be misleading, particularly if used in
isolation. The conversion ratio is based on an energy equivalency conversion
method primarily applicable at the burner tip and does not represent a value
equivalency at the wellhead.
Electronic copies of our filings with the SEC and the Ontario Securities
Commission (OSC) (from November 8, 2002 onward) are available, free of charge,
on our web site (www.nexeninc.com). Filings prior to November 8, 2002 are
available free of charge, upon request, by contacting our investor relations
department at (403) 699-5931. As soon as reasonably practicable, our filings are
made available on our website once they are electronically filed with the SEC or
the OSC. Alternatively, the SEC and the OSC each maintain a website (www.sec.gov
and www.sedar.com) that contain our reports, proxy and information statements
and other published information that have been filed or furnished with the SEC
and the OSC.
On March 31, 2005, the noon-day exchange rate for Cdn$1.00 was US$0.8267 as
reported by the Bank of Canada.
2
PART I
ITEM 1. UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
TABLE OF CONTENTS
Unaudited Consolidated Statement of Income
for the Three Months Ended March 31, 2005 and 2004.............................4
Unaudited Consolidated Balance Sheet
as at March 31, 2005 and December 31, 2004.....................................5
Unaudited Consolidated Statement of Cash Flows
for the Three Months Ended March 31, 2005 and 2004.............................6
Unaudited Consolidated Statement of Shareholders' Equity
for the Three Months Ended March 31, 2005 and March 31, 2004...................7
Notes to Unaudited Consolidated Financial Statements...........................8
3
NEXEN INC.
UNAUDITED CONSOLIDATED STATEMENT OF INCOME
FOR THE THREE MONTHS ENDED MARCH 31
Cdn$ millions, except per share amounts
2005 2004
- ----------------------------------------------------------------------------------------------------
Restated for
Changes in
Accounting Principles
Note 1
REVENUES
Net Sales 916 715
Marketing and Other (Note 11) 72 158
------------------------------------
988 873
------------------------------------
EXPENSES
Operating 225 179
Depreciation, Depletion, Amortization and Impairment 256 174
Transportation and Other 208 142
General and Administrative 181 60
Exploration 28 28
Interest (Note 5) 34 45
------------------------------------
932 628
------------------------------------
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES 56 245
------------------------------------
PROVISION FOR INCOME TAXES
Current 79 53
Future (60) 12
------------------------------------
19 65
------------------------------------
NET INCOME FROM CONTINUING OPERATIONS 37 180
Net Income from Discontinued Operations (Note 12) -- 4
------------------------------------
NET INCOME 37 184
====================================
EARNINGS PER COMMON SHARE FROM CONTINUING OPERATIONS ($/share)
Basic (Note 9) 0.29 1.41
====================================
Diluted (Note 9) 0.28 1.39
====================================
EARNINGS PER COMMON SHARE ($/share)
Basic (Note 9) 0.29 1.44
====================================
Diluted (Note 9) 0.28 1.42
====================================
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
2005 2004
- ----------------------------------------------------------------------------------------------------
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents 70 74
Accounts Receivable (Note 2) 2,075 2,136
Inventories and Supplies (Note 3) 455 351
Other 38 42
-----------------------------
Total Current Assets 2,638 2,603
-----------------------------
PROPERTY, PLANT AND EQUIPMENT
Net of Accumulated Depreciation, Depletion, Amortization and
Impairment of $5,578 (December 31, 2004 - $5,344) 9,001 8,643
GOODWILL 377 375
FUTURE INCOME TAX ASSETS 353 333
DEFERRED CHARGES AND OTHER ASSETS (Note 4) 267 429
-----------------------------
12,636 12,383
=============================
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Short-Term Borrowings 94 100
Accounts Payable and Accrued Liabilities 2,414 2,416
Accrued Interest Payable 41 34
Dividends Payable 13 13
-----------------------------
Total Current Liabilities 2,562 2,563
-----------------------------
LONG-TERM DEBT (Note 5) 4,424 4,259
FUTURE INCOME TAX LIABILITIES 2,095 2,131
ASSET RETIREMENT OBLIGATIONS (Note 6) 433 421
DEFERRED CREDITS AND OTHER LIABILITIES 173 142
SHAREHOLDERS' EQUITY (Note 8)
Common Shares, no par value
Authorized: Unlimited
Outstanding: 2005 - 129,990,330 shares
2004 - 129,199,583 shares 684 637
Contributed Surplus 1 --
Retained Earnings 2,359 2,335
Cumulative Foreign Currency Translation Adjustment (95) (105)
-----------------------------
Total Shareholders' Equity 2,949 2,867
-----------------------------
COMMITMENTS, CONTINGENCIES AND GUARANTEES (Note 13)
12,636 12,383
=============================
SEE ACCOMPANYING NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS.
5
NEXEN INC.
UNAUDITED CONSOLIDATED STATEMENT OF CASH FLOWS
FOR THE THREE MONTHS ENDED MARCH 31
Cdn$ millions
2005 2004
- ------------------------------------------------------------------------------------------------------------
Restated for
Changes in
Accounting Principles
Note 1
OPERATING ACTIVITIES
Net Income from Continuing Operations 37 180
Net Income from Discontinued Operations -- 4
Charges and Credits to Income not Involving Cash (Note 10) 472 202
Exploration Expense 28 28
Changes in Non-Cash Working Capital (Note 10) (53) 120
Other (43) 4
-------------------------------------
441 538
FINANCING ACTIVITIES
Proceeds from Term Credit Facilities, Net 138 --
Proceeds from Long-Term Debt (Note 5) 1,253 --
Repayment of Long-Term Debt (Note 5) (1,241) (300)
Repayment of Short-Term Borrowings, Net (10) --
Redemption of Preferred Securities -- (289)
Dividends on Common Shares (13) (13)
Issue of Common Shares 32 82
Other (16) --
-------------------------------------
143 (520)
INVESTING ACTIVITIES
Capital Expenditures
Exploration and Development (594) (314)
Proved Property Acquisitions (1) --
Chemicals, Corporate and Other (4) (11)
Proceeds on Disposition of Assets 2 --
Changes in Non-Cash Working Capital (Note 10) (14) 8
Other 16 --
-------------------------------------
(595) (317)
EFFECT OF EXCHANGE RATE CHANGES ON CASH
AND CASH EQUIVALENTS 7 12
-------------------------------------
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (4) (287)
CASH AND CASH EQUIVALENTS - BEGINNING OF PERIOD 74 1,087
-------------------------------------
CASH AND CASH EQUIVALENTS - END OF PERIOD 70 800
=====================================
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, 2005 AND MARCH 31, 2004
Cdn$ millions
2005 2004
- ------------------------------------------------------------------------------------------------------------
Restated for
Changes in
Accounting Principles
Note 1
COMMON SHARES
Balance at January 1 637 513
Issue of Common Shares 32 82
Previously Recognized Liability Relating to Stock Options Exercised 15 -
-------------------------------
Balance at March 31 684 595
===============================
CONTRIBUTED SURPLUS
Balance at January 1 -- 1
Stock Based Compensation Expense 1 1
-------------------------------
Balance at March 31 1 2
===============================
RETAINED EARNINGS
Balance at January 1 2,335 1,594
Net Income 37 184
Dividends on Common Shares (13) (13)
-------------------------------
Balance at March 31 2,359 1,765
===============================
CUMULATIVE FOREIGN CURRENCY TRANSLATION ADJUSTMENT
Balance at January 1 (105) (33)
Translation Adjustment, Net of Income Taxes 10 3
-------------------------------
Balance at March 31 (95) (30)
===============================
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 16. 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, 2005 and the results
of our operations and our cash flows for the three months ended March 31, 2005
and 2004.
Management makes estimates and assumptions that affect the reported amounts of
assets and liabilities and disclosure of contingent assets and liabilities at
the date of the Unaudited Consolidated Financial Statements, and revenues and
expenses during the reporting period. Our management reviews these estimates,
including those related to litigation, asset retirement obligations, income
taxes and determination of proved reserves, on an ongoing basis. Changes in
facts and circumstances may result in revised estimates and actual results may
differ from these estimates. The results of operations and cash flows for the
three months ended March 31, 2005 are not necessarily indicative of the results
of operations or cash flows to be expected for the year ending December 31,
2005.
These Unaudited Consolidated Financial Statements should be read in conjunction
with our Audited Consolidated Financial Statements included in our 2004 Annual
Report on Form 10-K. The accounting policies we follow are described in Note 1
of the Audited Consolidated Financial Statements included in our 2004 Annual
Report on Form 10-K.
CHANGES IN ACCOUNTING PRINCIPLES
FINANCIAL INSTRUMENTS
In the fourth quarter of 2004, we retroactively adopted the changes to Canadian
Institute of Chartered Accountants (CICA) standard S.3860, FINANCIAL
INSTRUMENTS. These changes require that fixed-amount contractual obligations
that can be settled by issuing a variable number of equity instruments be
classified as a liability. Our US-dollar denominated preferred and subordinated
securities have these characteristics and accordingly have been reclassified as
long-term debt. Dividends and interest on these securities have been included in
interest expense and issue costs previously charged to retained earnings have
been amortized over the life of the securities. Unamortized issue costs have
been expensed on the redemption of the preferred securities in 2004. Foreign
exchange gains or losses from translation of the US-dollar amounts have been
included as cumulative foreign currency translation adjustments. The change was
adopted retroactively and all prior periods presented have been restated. This
change in accounting principle has no effect on our Unaudited Consolidated
Financial Statements for the three months ended March 31, 2005.
GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
In 2004, we adopted CICA standard S.1100, GENERALLY ACCEPTED ACCOUNTING
PRINCIPLES which eliminated general practice in Canada as a component of GAAP.
Our accounting policy is to include geological and geophysical costs as
operating cash outflows in our Unaudited Consolidated Statement of Cash Flows.
For previous years, we included geological and geophysical costs as investing
cash outflows consistent with industry practice in Canada. In our Unaudited
Consolidated Statement of Cash Flows for the three months ended March 31, 2005,
we included $5 million (March 31, 2004 - $18 million) of geological and
geophysical costs as other operating cash outflows. This change in accounting
policy was adopted prospectively.
IMPACT OF CHANGES IN ACCOUNTING PRINCIPLES
The impact of the changes on our Unaudited Consolidated Statement of Income for
the three months ended March 31, 2004 resulted in additional interest expense of
$3 million for dividends on preferred securities, additional transportation and
other expense of $11 million for the unamortized issue costs on the redemption
of preferred securities, and a corresponding reduction in the provision for
income taxes of $6 million. The impact of these changes in accounting principles
on our Unaudited Consolidated Statement of Income and Earnings per Common Share
for the three months ended March 31, 2004, are shown below.
8
UNAUDITED CONSOLIDATED STATEMENT OF INCOME FOR THE THREE MONTHS
ENDED MARCH 31, 2004
2004
- --------------------------------------------------------------------------------
Transportation and Other Expense as Reported 131
Plus: Unamortized Issue Costs on Redemption of
Preferred Securities 11
---------
Transportation and Other Expense as Restated 142
---------
Interest Expense as Reported 42
Plus: Dividends on Preferred Securities 3
---------
Interest Expense as Restated 45
---------
Provision for Future Income Taxes as Reported 18
Plus: Tax Effect of Changes in Accounting Principles (6)
---------
Provision for Future Income Taxes as Restated 12
---------
NET INCOME AND EARNINGS PER COMMON SHARE FOR THE THREE MONTHS
ENDED MARCH 31, 2004
2004
- --------------------------------------------------------------------------------
Net Income Attributable to Common Shareholders
As Reported 190
Less: Unamortized Issue Costs on Redemption of Preferred
Securities, Net of Income Taxes (6)
---------
As Restated 184
=========
Earnings per Common Share ($/share)
Basic as Reported 1.49
=========
Restated 1.44
=========
Diluted as Reported 1.47
=========
Restated 1.42
=========
RECLASSIFICATION
Certain comparative figures have been reclassified to ensure consistency with
current period presentation.
2. ACCOUNTS RECEIVABLE
MARCH 31 DECEMBER 31
2005 2004
- -------------------------------------------------------------------------------- ----------------
Trade
Marketing 1,275 1,452
Oil and Gas 671 593
Chemicals and Other 56 57
----------- ----------------
2,002 2,102
Non-Trade 80 49
----------- ----------------
2,082 2,151
Allowance for Doubtful Accounts (7) (15)
----------- ----------------
Total 2,075 2,136
=========== ================
9
3 INVENTORIES AND SUPPLIES
MARCH 31 DECEMBER 31
2005 2004
- ----------------------------------------------------------------------------------------------
Finished Products
Marketing 275 199
Oil and Gas 9 6
Chemicals and Other 11 13
-------------------------
295 218
Work in Process 5 4
Field Supplies 155 129
-------------------------
Total 455 351
=========================
4. DEFERRED CHARGES AND OTHER ASSETS
MARCH 31 DECEMBER 31
2005 2004
- ----------------------------------------------------------------------------------------------
Crude Oil Put Options 21 200
Long-Term Marketing Derivative Contracts 115 91
Defined Benefit Pension Plan Asset 11 13
Deferred Financing Costs 71 67
Other 49 58
-------------------------
Total 267 429
=========================
5. LONG-TERM DEBT AND SHORT-TERM BORROWINGS
MARCH 31 DECEMBER 31
2005 2004
- ----------------------------------------------------------------------------------------------
Acquisition Credit Facilities (US$473 million drawn) 572 1,806
Term Credit Facilities (US$180 million drawn) 218 87
Debentures, due 2006 (1) 93 93
Medium-Term Notes, due 2007 150 150
Medium-Term Notes, due 2008 125 125
Notes, due 2013 (US$500 million) 605 602
Notes, due 2015 (US$250 million) (a) 302 --
Notes, due 2028 (US$200 million) 242 241
Notes, due 2032 (US$500 million) 605 602
Notes, due 2035 (US$790 million) (b) 956 --
Subordinated Debentures, due 2043 (US$460 million) 556 553
-------------------------
4,424 4,259
=========================
Note:
(1) Includes $50 million of principal that was effectively converted through a
currency exchange contract to US$37 million.
(a) NOTES, DUE 2015
In March 2005, we issued US$250 million of notes. Interest is payable
semi-annually at a rate of 5.20% and the principal is to be repaid in March
2015. We may redeem part or all of the notes at any time. The redemption price
will be the greater of par and an amount that provides the same yield as a US
Treasury security having a term to maturity equal to the remaining term of the
notes plus 0.15%. The proceeds were used to repay a portion of the Acquisition
Credit Facilities.
(b) NOTES, DUE 2035
In March 2005, we issued US$790 million of notes. Interest is payable
semi-annually at a rate of 5.875% and the principal is to be repaid in March
2035. We may redeem part or all of the notes at any time. The redemption price
will be the greater of par and an amount that provides the same yield as a US
Treasury security having a term to maturity equal to the remaining term of the
notes plus 0.2%. The proceeds were used to repay a portion of the Acquisition
Credit Facilities.
10
(c) INTEREST EXPENSE
THREE MONTHS
ENDED MARCH 31
2005 2004
- --------------------------------------------------------------------------------
Long-Term Debt 62 49
Other 5 3
---------------------
67 52
Less: Capitalized (33) (7)
---------------------
Total 34 45
=====================
Capitalized interest relates to and is included as part of the cost of our oil
and gas property, plant and equipment. The capitalization rates are based on our
weighted-average cost of borrowings.
6. ASSET RETIREMENT OBLIGATIONS
Changes in carrying amounts of the asset retirement obligations associated with
our property, plant and equipment are as follows:
MARCH 31 DECEMBER 31
2005 2004
- --------------------------------------------------------------------------------
Balance at Beginning of Period 468 323
Obligations Assumed with Development Activities 8 12
Obligations Assumed with Business Acquisition -- 134
Obligations Discharged with Disposed Properties -- (4)
Expenditures Made on Asset Retirements (17) (31)
Accretion 6 17
Revisions to Estimates -- 24
Effects of Foreign Exchange 1 (7)
-----------------------
Balance at End of Period (1) 466 468
=======================
Note:
(1) Obligations due within 12 months of $33 million (2004 - $47 million) have
been included in accounts payable and accrued liabilities.
Our total estimated undiscounted asset retirement obligations amount to $766
million (December 31, 2004 - $770 million). We have discounted the total
estimated asset retirement obligations using a weighted-average, credit-adjusted
risk-free rate of 5.7%. Approximately $107 million included in our asset
retirement obligations will be settled over the next five years. The remaining
obligations settle beyond five years and will be funded by future cash flows
from our operations.
We own interests in assets for which the fair value of the asset retirement
obligations cannot be reasonably determined because the assets currently have an
indeterminate life and we cannot determine when remediation activities would
take place. These assets include our interest in Syncrude's upgrader and sulphur
pile.
The estimated future recoverable reserves at Syncrude are significant and given
the long life of this asset, we are unable to determine when asset retirement
activities would take place. Furthermore, the Syncrude plant can continue to run
indefinitely with ongoing maintenance activities.
The retirement obligations for these assets will be recorded in the first year
in which the lives of the assets are determinable.
11
7. DERIVATIVE INSTRUMENTS AND FINANCIAL RISK MANAGEMENT
(a) CARRYING VALUE AND ESTIMATED FAIR VALUE OF DERIVATIVE AND FINANCIAL
INSTRUMENTS
The carrying value, fair value, and unrecognized gains or losses on our
outstanding derivatives and long-term financial assets and liabilities are:
CDN$ MILLIONS MARCH 31, 2005 DECEMBER 31, 2004
- ------------------------------------------------------------------------------------ ------------------------------------
CARRYING FAIR UNRECOGNIZED CARRYING FAIR UNRECOGNIZED
VALUE VALUE GAIN/(LOSS) VALUE VALUE GAIN/(LOSS)
----------------------------------- ------------------------------------
Commodity Price Risk--
Non-Trading Activities
Crude Oil Put Options 27 27 -- 200 200 --
Trading Activities
Crude Oil and Natural Gas 58 58 -- 83 83 --
Future Sale of Gas Inventory -- (1) (1) -- 6 6
Foreign Currency Risk
Non-Trading Activities 11 11 -- 7 7 --
Trading Activities 8 8 -- 10 10 --
------------------------------------ --------------------------------------
Total Derivatives 104 103 (1) 300 306 6
=================================== ======================================
Financial Assets and Liabilities
Long-Term Debt (4,424) (4,576) (152) (4,259) (4,503) (244)
=================================== ======================================
The estimated fair value of all derivative instruments is based on quoted market
prices and, if not available, on estimates from third-party brokers or dealers.
The carrying value of cash and cash equivalents, amounts receivable and
short-term obligations approximates their fair value because the instruments are
near maturity.
(b) COMMODITY PRICE RISK MANAGEMENT
NON-TRADING ACTIVITIES
We generally sell our crude oil and natural gas under short-term market based
contracts.
CRUDE OIL PUT OPTIONS
We purchased WTI crude oil put options to manage the commodity price risk
exposure of a portion of our oil production in 2005 and 2006. These options
establish an annual average WTI floor price of US$43/bbl in 2005 and US$38/bbl
in 2006 at a cost of $144 million and are stated at fair value on our balance
sheet. Any change in fair value is included in marketing and other on the
Unaudited Consolidated Statement of Income.
NOTIONAL AVERAGE MARKET
VOLUMES TERM PRICE (WTI) VALUE
- --------------------------------------------------------------------------------------------
(bbls/d) (US$/bbl) (Cdn$ millions)
WTI Crude Oil Put Options 30,000 2005 44 4
20,000 2005 43 2
10,000 2005 41 -
30,000 2006 39 12
20,000 2006 38 7
10,000 2006 36 2
---------------
---------------
27
===============
TRADING ACTIVITIES
CRUDE OIL AND NATURAL GAS
We enter into physical purchase and sales contracts as well as financial
commodity contracts to enhance our price realizations and lock-in our margins.
The physical and financial commodity contracts (derivative contracts) are stated
at market value. The $58 million fair value of the contracts has been recognized
in net income.
12
FUTURE SALE OF GAS INVENTORY
We have certain NYMEX futures contracts and swaps in place, which effectively
lock-in our margins on the future sale of our natural gas inventory in storage.
We have designated, in writing, some of these derivative contracts as cash flow
hedges of the future sale of our storage inventory. As a result, gains and
losses on these designated futures contracts and swaps are recognized in net
income when the inventory in storage is sold. The principal terms of these
outstanding contracts and the unrecognized losses at March 31, 2005 are:
HEDGED AVERAGE UNRECOGNIZED
VOLUMES MONTH PRICE LOSS
- ---------------------------------------------------------------------------------------------
(mmcf) (US$/mcf) (Cdn$ millions)
NYMEX Natural Gas Futures 5,780 January 2006 8.67 (1)
----------------
(1)
================
(c) FOREIGN CURRENCY EXCHANGE RATE RISK MANAGEMENT
NON-TRADING ACTIVITIES
We occasionally use derivative instruments to effectively convert cash flows
from Canadian to US dollars and vice versa. At March 31, 2005, we held a foreign
currency derivative instrument that obligates us and the counterparty to
exchange principal and interest amounts. In November 2006, we will pay US$37
million and receive Cdn$50 million. We have recognized a gain of $7 million for
the change in fair value of this derivative instrument.
Our Buzzard development project in the North Sea creates foreign currency
exposure as a portion of the capital costs are denominated in British pounds and
Euros. In order to reduce our exposure to fluctuations in these currencies
relative to the US dollar, we purchased foreign currency call options in early
2005 which effectively set a ceiling on most of our British pound and Euro
spending exposure from March 2005 through to the end of 2006. Any change in fair
value is included in marketing and other on the Unaudited Consolidated Statement
of Income.
MARKET
AMOUNT TERM RATE VALUE
- ---------------------------------------------------------------------------------------------------
(for US$1.00) (Cdn$ millions)
Foreign Currency Call Options (pound)246 million 2005 - 2006 1.95 - 2.00 4
(euro)44 million 2005 1.40 --
----------------
4
================
TRADING ACTIVITIES
Our sales and purchases of crude oil and natural gas are generally transacted in
or referenced to the US dollar, as are most of the financial commodity contracts
used by our marketing group. We enter into forward contracts to sell US dollars.
When combined with certain commodity sales contracts, either physical or
financial, these forward contracts allow us to lock-in our margins on the future
sale of crude oil and natural gas. The fair value of our US dollar forward
contracts at March 31, 2005 was $8 million. This fair value has been recognized
in net income and settles within one year.
(d) TOTAL CARRYING VALUE OF DERIVATIVE CONTRACTS RELATED TO TRADING ACTIVITIES
Amounts related to derivative contracts held by our marketing operation are
equal to fair value as we use mark-to-market accounting. The amounts are as
follows:
MARCH 31 DECEMBER 31
CDN$ MILLIONS 2005 2004
- --------------------------------------------------------------------------------
Accounts Receivable 151 177
Deferred Charges and Other Assets (1) 115 91
------------------------
Total Derivative Contract Assets 266 268
========================
Accounts Payable and Accrued Liabilities 152 129
Deferred Credits and Other Liabilities (1) 48 46
------------------------
Total Derivative Contract Liabilities 200 175
========================
Total Derivative Contract Net Assets 66 93
========================
Note:
(1) These derivative contracts settle beyond 12 months and are considered
non-current.
13
8. SHAREHOLDERS' EQUITY
DIVIDENDS
Dividends per common share for the three months ended March 31, 2005 were $0.10
(2004 - $0.10).
9. EARNINGS PER COMMON SHARE
We calculate basic earnings per common share from continuing operations using
net income from continuing operations divided by the weighted-average number of
common shares outstanding. We calculate basic earnings per common share using
net income and the weighted-average number of common shares outstanding. We
calculate diluted earnings per common share from continuing operations and
diluted earnings per common share in the same manner as basic, except we use the
weighted-average number of diluted common shares outstanding in the denominator.
THREE MONTHS
ENDED MARCH 31
(MILLIONS OF SHARES) 2005 2004
- -------------------------------------------------------------------------------------
Weighted-average number of common shares outstanding 129.7 127.5
Shares issuable pursuant to stock options 7.4 7.4
Shares to be purchased from proceeds of stock options (5.3) (5.6)
--------------------
Weighted-average number of diluted common shares outstanding 131.8 129.3
====================
In calculating the weighted-average number of diluted common shares outstanding
for the three months ended March 31, 2005 and March 31, 2004, all options were
included because their exercise price was less than the quarterly average common
share market price in the period. During the periods presented, outstanding
stock options were the only potential dilutive instruments.
10. CASH FLOWS
(a) CHARGES AND CREDITS TO INCOME NOT INVOLVING CASH
THREE MONTHS
ENDED MARCH 31
2005 2004
- -------------------------------------------------------------------------------------
Depreciation, Depletion, Amortization and Impairment 256 174
Stock Based Compensation 100 2
Future Income Taxes (60) 12
Change in Fair Value of Crude Oil Put Options 173 --
Non-Cash Items included in Discontinued Operations -- 8
Unamortized Issue Costs on Redemption of Preferred Securities -- 11
Other 3 (5)
--------------------
Total 472 202
====================
(b) CHANGES IN NON-CASH WORKING CAPITAL
THREE MONTHS
ENDED MARCH 31
2005 2004
- -------------------------------------------------------------------------------------
Accounts Receivable 67 115
Inventories and Supplies (99) (16)
Other Current Assets 4 46
Accounts Payable and Accrued Liabilities (45) (10)
Accrued Interest Payable 6 (7)
--------------------
Total (67) 128
====================
Relating to:
Operating Activities (53) 120
Investing Activities (14) 8
--------------------
Total (67) 128
====================
14
(c) OTHER CASH FLOW INFORMATION
THREE MONTHS
ENDED MARCH 31
2005 2004
- -------------------------------------------------------------------------------------
Interest Paid 56 56
Income Taxes Paid 62 49
--------------------
11. MARKETING AND OTHER
THREE MONTHS
ENDED MARCH 31
2005 2004
- -------------------------------------------------------------------------------------
Marketing Revenue, Net 229 147
Change in Fair Value of Crude Oil Put Options (173) --
Interest 3 2
Foreign Exchange Gains 10 6
Other 3 3
--------------------
Total 72 158
====================
12. DISCONTINUED OPERATIONS
During the fourth quarter of 2004, we concluded production from our Buffalo
field, offshore Australia as anticipated. The results of our operations in
Australia have been treated as discontinued operations, as we have no plans to
continue operations in the country. Remediation and abandonment of the field has
been virtually completed and no gain or loss is expected from these activities.
THREE MONTHS
ENDED MARCH 31
2005 2004
- -------------------------------------------------------------------------------------
Revenues
Net Sales -- 28
Expenses
Operating -- 16
Depreciation, Depletion, Amortization and Impairment -- 8
--------------------
Income before Income Taxes -- 4
Future Income Taxes -- --
--------------------
Net Income from Discontinued Operations -- 4
====================
Earnings Per Common Share ($/share)
Basic (Note 9) -- 0.03
====================
Diluted (Note 9) -- 0.03
====================
Assets and liabilities on the Unaudited Consolidated Balance Sheet include the
following amounts for discontinued operations.
MARCH 31 DECEMBER 31
2005 2004
- --------------------------------------------------------------------------------
Cash and Cash Equivalents 3 1
Accounts Receivable 8 8
Other Current Assets -- 1
Accounts Payable and Accrued Liabilities 8 25
-----------------------
15
13. COMMITMENTS, CONTINGENCIES AND GUARANTEES
As described in Note 12 to the Audited Consolidated Financial Statements
included in our 2004 Annual Report on Form 10-K, there are a number of lawsuits
and claims pending, the ultimate results of which cannot be ascertained at this
time. We record costs as they are incurred or become determinable. We believe
the resolution of these matters would not have a material adverse effect on our
liquidity, consolidated financial position or results of operations.
14. PENSION AND OTHER POST RETIREMENT BENEFITS
(a) NET PENSION EXPENSE RECOGNIZED UNDER OUR DEFINED BENEFIT PENSION PLANS
THREE MONTHS
ENDED MARCH 31
2005 2004
- ------------------------------------------------------------------------------- -------------
Nexen
Cost of Benefits Earned by Employees 2 2
Interest Cost on Benefits Earned 3 3
Actual Return on Plan Assets (4) (4)
Actuarial Losses 3 4
---------------------
Pension Expense Before Adjustments for the Long-Term Nature of
Employee Future Benefit Costs 4 5
Difference Between Actual and Expected Return 2 1
Difference Between Actual and Recognized Actuarial Gains (Losses) (3) (4)
Difference Between Actual and Recognized Past Service Costs 1 --
---------------------
Net Pension Expense 4 2
---------------------
Syncrude
Cost of Benefits Earned by Employees 1 1
Interest Cost on Benefits Earned 2 1
Actual Return on Plan Assets (2) (2)
Actuarial Losses 2 2
------- -------------
Pension Expense Before Adjustments for the Long-Term Nature of
Employee Future Benefit Costs 3 2
Difference Between Actual and Expected Return 1 1
Difference Between Actual and Recognized Actuarial Gains (Losses) (2) (2)
Difference Between Actual and Recognized Past Service Costs -- --
---------------------
Net Pension Expense 2 1
---------------------
Total 6 3
=====================
(b) EMPLOYER FUNDING CONTRIBUTIONS
Our expected total funding contributions for 2005 disclosed in Note 13(e) to the
Audited Consolidated Financial Statements in our 2004 Annual Report on Form 10-K
have not changed for both our Nexen defined benefit pension plan and our share
of Syncrude's defined benefit pension plan.
16
15. OPERATING SEGMENTS AND RELATED INFORMATION
Nexen is involved in activities relating to Oil and Gas, Syncrude and Chemicals
in various geographic locations as described in Note 18 to the Audited
Consolidated Financial Statements included in our 2004 Annual Report on Form
10-K.
THREE MONTHS ENDED MARCH 31, 2005
CORPORATE
AND
(CDN$ MILLIONS) OIL AND GAS SYNCRUDE(1) CHEMICALS OTHER TOTAL
- --------------------------------------------------------------------------------------------------------------------------------
UNITED UNITED OTHER
YEMEN CANADA STATES KINGDOM(2) COUNTRIES MARKETING
------ ------- ------ ---------- --------- ---------
Net Sales 283 146 197 102 22 4 66 96 -- 916
Marketing and Other 1 1 -- -- -- 229 -- 1 (160)(3) 72
--------------------------------------------------------------------------------------------------
Total Revenues 284 147 197 102 22 233 66 97 (160) 988
Less: Expenses
Operating 35 41 22 25 1 6 40 55 -- 225
Depreciation, Depletion,
Amortization and
Impairment 65 52 66 46 4 3 4 10 6 256
Transportation and Other 1 5 -- -- -- 177 3 10 12 208
General and Administrative (4) 1 32 18 -- 28 17 -- 15 70 181
Exploration 1 6 10 3 8(5) -- -- -- -- 28
Interest -- -- -- -- -- -- -- -- 34 34
--------------------------------------------------------------------------------------------------
Income (Loss) from
Continuing Operations
before Income Taxes 181 11 81 28 (19) 30 19 7 (282) 56
==================================================================================================
Less: Provision for Income
Taxes (6) 19
Add: Net Income from
Discontinued Operations --
-------
Net Income 37
=======
Identifiable Assets 758 2,172 1,387 4,538 202 2,020(7) 954 494 111 12,636
==================================================================================================
Capital Expenditures
Development and Other 63 214 19 140 4 1 44 1 2 488
Exploration 8 20 72 3 7 -- -- -- -- 110
Proved Property Acquisitions -- 1 -- -- -- -- -- -- -- 1
--------------------------------------------------------------------------------------------------
71 235 91 143 11 1 44 1 2 599
==================================================================================================
Property, Plant and Equipment
Cost 2,123 3,696 2,299 3,655 542 158 1,074 829 203 14,579
Less: Accumulated DD&A 1,623 1,667 1,064 65 412 67 158 425 97 5,578
--------------------------------------------------------------------------------------------------
Net Book Value 500 2,029 1,235 3,590 130 91 916 404 106 9,001
==================================================================================================
Notes:
(1) Syncrude is considered a mining operation for US reporting purposes.
Property, plant and equipment at March 31, 2005 includes mineral rights of
$6 million.
(2) Includes results of operations from producing activities in Nigeria and
Colombia.
(3) Includes interest income of $3 million, foreign exchange gains of $10
million and decrease in the fair value of crude oil put options of $173
million.
(4) Includes stock based compensation expense of $125 million.
(5) Includes exploration activities primarily in Nigeria and Colombia.
(6) Includes Yemen cash taxes of $59 million.
(7) Approximately 77% of Marketing's identifiable assets are accounts
receivable and inventories.
17
THREE MONTHS ENDED MARCH 31, 2004 (1)
CORPORATE
AND
(CDN$ MILLIONS) OIL AND GAS SYNCRUDE(2) CHEMICALS OTHER TOTAL
- --------------------------------------------------------------------------------------------------------------------------
UNITED OTHER
YEMEN CANADA STATES COUNTRIES(3) MARKETING
----- ------ --------- ----------- ---------
Net Sales 207 144 181 13 3 75 92 -- 715
Marketing and Other 1 1 -- -- 147 -- 1 8(4) 158
-----------------------------------------------------------------------------------------
Total Revenues 208 145 181 13 150 75 93 8 873
Less: Expenses
Operating 28 40 20 1 4 29 57 -- 179
Depreciation, Depletion,
Amortization and
Impairment 38 49 62 4 2 4 10 5 174
Transportation and Other 1 2 -- -- 116 2 10 11 142
General and Administrative (5) 1 12 6 7 11 -- 6 17 60
Exploration -- 7 9 12(6) -- -- -- -- 28
Interest -- -- -- -- -- -- -- 45 45
-----------------------------------------------------------------------------------------
Income (Loss) from Continuing
Operations before Income
Taxes 140 35 84 (11) 17 40 10 (70) 245
=========================================================================================
Less: Provision for Income
Taxes (7) 65
Add: Net Income from
Discontinued Operations 4
--------
Net Income 184
========
Identifiable Assets 686 1,641 1,657 389 1,280(8) 769 469 532 7,423
=========================================================================================
Capital Expenditures
Development and Other 47 91 93 6 -- 50 6 5 298
Exploration 2 4 16 5 -- -- -- -- 27
-----------------------------------------------------------------------------------------
49 95 109 11 -- 50 6 5 325
=========================================================================================
Property, Plant and Equipment
Cost 1,973 3,049 2,289 548 153 868 783 173 9,836
Less: Accumulated DD&A 1,556 1,510 957 426 56 145 391 77 5,118
-----------------------------------------------------------------------------------------
Net Book Value 417 1,539 1,332 122 97 723 392 96 4,718
=========================================================================================
Notes:
(1) Restated to give effect to changes in accounting principles (see Note 1).
(2) Syncrude is considered a mining operation for US reporting purposes.
Property, plant and equipment at March 31, 2004 includes mineral rights of
$6 million
(3) Includes results of operations from producing activities in Australia,
Nigeria and Colombia.
(4) Includes interest income of $2 million and foreign exchange gains of $6
million.
(5) Includes stock based compensation expense of $11 million.
(6) Includes exploration activities primarily in Nigeria and Colombia.
(7) Includes Yemen cash taxes of $46 million.
(8) Approximately 82% of Marketing's identifiable assets are accounts
receivable and inventories.
18
16. DIFFERENCES BETWEEN CANADIAN AND US GENERALLY ACCEPTED ACCOUNTING
PRINCIPLES
The Unaudited Consolidated Financial Statements have been prepared in accordance
with Canadian GAAP. The US GAAP Unaudited Consolidated Statement of Income and
Balance Sheet and summaries of differences from Canadian GAAP are as follows:
(a) UNAUDITED CONSOLIDATED STATEMENT OF INCOME - US GAAP
FOR THE THREE MONTHS ENDED MARCH 31
(CDN$ MILLIONS, EXCEPT PER SHARE AMOUNTS) 2005 2004
- ------------------------------------------------------------------------------------------
REVENUES
Net Sales 916 715
Marketing and Other (ii); (ix) 72 164
------------------
988 879
------------------
EXPENSES
Operating (iv) 227 181
Depreciation, Depletion, Amortization and Impairment (i) 266 185
Transportation and Other 208 140
General and Administrative 181 60
Exploration 28 28
Interest 34 45
------------------
944 639
------------------
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES 44 240
------------------
PROVISION FOR INCOME TAXES
Current 79 53
Deferred (ii); (iv); (viii) (61) 27
------------------
18 80
------------------
NET INCOME FROM CONTINUING OPERATIONS 26 160
Net Income from Discontinued Operations -- 4
------------------
NET INCOME-- US GAAP (1) 26 164
==================
EARNINGS PER COMMON SHARE ($/share)
Basic (Note 9)
Net Income from Continuing Operations 0.20 1.26
Net Income from Discontinued Operations -- 0.03
------------------
0.20 1.29
==================
Diluted (Note 9)
Net Income from Continuing Operations 0.19 1.24
Net Income from Discontinued Operations -- 0.03
------------------
0.19 1.27
==================
Note:
(1) RECONCILIATION OF CANADIAN AND US GAAP NET INCOME
THREE MONTHS
ENDED MARCH 31
(CDN$ MILLIONS) 2005 2004
- -----------------------------------------------------------------------------------
Net Income - Canadian GAAP 37 184
Impact of US Principles, Net of Income Taxes:
Depreciation, Depletion, Amortization and Impairment (i) (10) (11)
Future Income Taxes (viii) -- (15)
Fair Value of Preferred Securities (ix) -- 4
Other (ii); (iv) (1) 2
-----------------
Net Income - US GAAP 26 164
=================
19
(b) UNAUDITED CONSOLIDATED BALANCE SHEET - US GAAP
MARCH 31 DECEMBER 31
(CDN$ MILLIONS, EXCEPT SHARE AMOUNTS) 2005 2004
- ------------------------------------------------------------------------------------------------------------
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents 70 74
Accounts Receivable 2,075 2,142
Inventories and Supplies 455 351
Other 38 42
----------------------------
Total Current Assets 2,638 2,609
----------------------------
PROPERTY, PLANT AND EQUIPMENT
Net of Accumulated Depreciation, Depletion, Amortization and
Impairment of $6,036 (December 31, 2004 - $5,792) (i); (iv); (vii) 8,984 8,638
GOODWILL 377 375
DEFERRED INCOME TAX ASSETS 353 333
DEFERRED CHARGES AND OTHER ASSETS (v) 208 384
----------------------------
12,560 12,339
============================
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Short-Term Borrowings 94 100
Accounts Payable and Accrued Liabilities (ii) 2,415 2,416
Accrued Interest Payable 41 34
Dividends Payable 13 13
----------------------------
Total Current Liabilities 2,563 2,563
----------------------------
LONG-TERM DEBT (v) 4,365 4,214
DEFERRED INCOME TAX LIABILITIES (i) - (ix) 2,062 2,101
ASSET RETIREMENT OBLIGATIONS 433 421
DEFERRED CREDITS AND LIABILITIES (vi) 179 148
SHAREHOLDERS' EQUITY
Common Shares, no par value
Authorized: Unlimited
Outstanding: 2005 - 129,990,330 shares
2004 - 129,199,583 shares 684 637
Contributed Surplus 1 --
Retained Earnings (i); (ii); (iv); (vii); (viii); (ix) 2,373 2,360
Accumulated Other Comprehensive Income (ii); (iii); (vi) (100) (105)
----------------------------
Total Shareholders' Equity 2,958 2,892
----------------------------
COMMITMENTS, CONTINGENCIES AND GUARANTEES
12,560 12,339
============================
(c) UNAUDITED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME - US GAAP FOR THE
THREE MONTHS ENDED MARCH 31
(CDN$ MILLIONS) 2005 2004
- ------------------------------------------------------------------------------------------------------------
Net Income - US GAAP 26 164
Other Comprehensive Income, Net of Income Taxes:
Translation Adjustment (iii) 10 3
Unrealized Mark-to-Market Gain/(Loss) (ii) (5) 6
----------------------------
Comprehensive Income 31 173
============================
20
NOTES:
i. Under US principles, the liability method of accounting for income
taxes was adopted in 1993. In Canada, the liability method was adopted
in 2000. In 1997, we acquired certain oil and gas assets and the amount
paid for these assets differed from the tax basis acquired. Under US
principles, this difference was recorded as a deferred tax liability
with an increase to property, plant and equipment rather than a charge
to retained earnings. As a result:
o additional depreciation, depletion, amortization and impairment of $10
million (2004 - $11 million) was included in net income; and
o property, plant and equipment is higher under US GAAP by $19 million
(December 31, 2004 - $29 million).
ii. 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 GAS INVENTORY: Included in accounts receivable at
December 31, 2004, was $6 million of gains on the futures and basis
swap contracts we used to hedge the commodity price risk on the future
sale of our gas inventory as described in Note 7. These contracts
effectively lock-in profits on our stored gas volumes. Gains of $6
million ($4 million, net of income taxes) related to the effective
portion and deferred in accumulated other comprehensive income (AOCI)
at December 31, 2004, were recognized in marketing and other during the
quarter.
At March 31, 2005, losses of $1 million ($1 million, net of income
taxes) were included in accounts payable and deferred in AOCI until the
underlying gas inventory is sold. The losses will be reclassified to
marketing and other as they settle over the next 12 months. At March
31, 2005, 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, 2005 and at
December 31, 2004, we had no fair value hedges in place.
iii. 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 - US GAAP.
iv. Under Canadian principles, we defer certain development costs and all
pre-operating revenues and costs to property, plant and equipment.
Under US principles, these costs have been included in operating
expenses. As a result:
o operating expenses include pre-operating costs of $2 million ($1
million, net of income taxes) (2004 - $2 million ($1 million, net of
taxes)); and
o property, plant and equipment is lower under US GAAP by $17 million
(December 31, 2004 - $15 million).
v. 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 $59 million (December 31, 2004 - $45 million) have
been included in long-term debt.
vi. 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 $6 million ($4
million, net of income taxes) at March 31, 2005 (December 31, 2004 - $6
million ($4 million, net of income taxes.))
vii. On January 1, 2003 we adopted FASB Statement No. 143, ACCOUNTING FOR
ASSET RETIREMENT OBLIGATIONS (FAS 143) for US GAAP reporting purposes.
We adopted the equivalent Canadian standard for asset retirement
obligations on January 1, 2004. These standards are consistent except
for the adoption date which resulted in our property, plant and
equipment under US GAAP being lower by $19 million.
21
viii. 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 $15 million future income tax recovery
during the first quarter of 2004.
ix. In May 2003, FASB issued Statement No. 150, ACCOUNTING FOR CERTAIN
INSTRUMENTS WITH CHARACTERISTICS OF BOTH LIABILITIES AND EQUITY that
requires certain financial instruments, including our preferred
securities, to be valued at fair value with changes in fair value
recognized through net income.
(CDN$ MILLIONS) GAIN TAX NET GAIN
-------------------------------------------------------------------------------------------
Fair value change from January 1, 2004 to February 9, 2004 (1), (2) 4 -- 4
-----------------------
Notes:
(1) Included in marketing and other.
(2) Redemption date of preferred securities.
NEW ACCOUNTING PRONOUNCEMENTS
In November 2004, the Financial Accounting Standards Board (FASB) issued
Statement 151, INVENTORY COSTS. This statement amends ARB 43 to clarify that:
o abnormal amounts of idle facility expense, freight, handling costs and
wasted material (spoilage) should be recognized as current-period charges;
and
o requires the allocation of fixed production overhead to inventory based on
the normal capacity of the production facilities.
The provisions of this statement are effective for inventory costs incurred
during fiscal years beginning after June 15, 2005. We do not expect the adoption
of this statement will have any material impact on our results of operations or
financial position.
In December 2004, the FASB issued Statement 123(R), SHARE-BASED PAYMENTS. This
statement revises Statement 123, ACCOUNTING FOR STOCK-BASED COMPENSATION, and
supersedes APB Opinion 25, ACCOUNTING FOR STOCK ISSUED TO EMPLOYEES. Statement
123(R) requires all stock-based awards issued to employees to be measured at
fair value and to be expensed in the income statement. This statement is
effective for fiscal years beginning after June 15, 2005.
We are currently expensing stock-based awards issued to employees using the fair
value method for equity based awards and the intrinsic method for liability
based awards. Adoption of this standard will change our expense under US GAAP
for tandem options and stock appreciation rights as these awards will be
measured using the fair value method rather than the intrinsic method. We are
currently evaluating the provisions of Statement 123(R) and have not yet
determined the full impact this statement will have on our results of operations
or financial position under US GAAP.
In December 2004, the FASB issued Statement 153, EXCHANGES OF NONMONETARY
ASSETS, an amendment of APB Opinion 29, ACCOUNTING FOR NONMONETARY TRANSACTIONS.
This amendment eliminates the exception for nonmonetary exchanges of similar
productive assets and replaces it with a general exception for exchanges of
nonmonetary assets that do not have commercial substance. Under Statement 153,
if a nonmonetary exchange of similar productive assets meets a
commercial-substance test and fair value is determinable, the transaction must
be accounted for at fair value resulting in the recognition of any gain or loss.
This statement is effective for nonmonetary transactions in fiscal periods that
begin after June 15, 2005. We do not expect the adoption of this statement will
have any material impact on our results of operations or financial position.
In March 2005, the FASB issued Financial Interpretation 47, ACCOUNTING FOR
CONDITIONAL ASSET RETIREMENT OBLIGATIONS (FIN 47). FIN 47 clarifies that the
term conditional asset retirement obligation as used in FASB Statement No. 143,
ACCOUNTING FOR ASSET RETIREMENT OBLIGATIONS, refers to a legal obligation to
perform an asset retirement activity in which the timing and (or) method of
settlement are conditional on a future event that may or may not be within the
control of the entity. The obligation to perform the asset retirement activity
is unconditional even though uncertainty exists about the timing and (or) method
of settlement. Thus, the timing and (or) method of settlement may be conditional
on a future event. Accordingly, an entity is required to recognize a liability
for the fair value of a conditional asset retirement obligation if the fair
value of the liability can be reasonably estimated. FIN 47 also clarifies when
an entity would have sufficient information to reasonably estimate the fair
value of an asset retirement obligation. FIN 47 is effective no later than the
end of fiscal years ending after December 15, 2005. We do not expect the
adoption of this statement will have a material impact on our results of
operations or financial position.
22
In March 2005, the Emerging Issues Task Force (EITF) reached a consensus on
Issue No. 04-6, ACCOUNTING FOR STRIPPING COSTS INCURRED DURING PRODUCTION IN THE
MINING INDUSTRY. In the mining industry, companies may be required to remove
overburden and other mine waste materials to access mineral deposits. The EITF
concluded that the costs of removing overburden and waste materials, often
referred to as "stripping costs", incurred during the production phase of a mine
are variable production costs that should be included in the costs of the
inventory produced during the period that the stripping costs are incurred.
Issue No. 04-6 is effective for the first reporting period in fiscal years
beginning after December 15, 2005, with early adoption permitted. We do not
expect the adoption of this statement will have a material impact on our results
of operations or financial position.
In April 2005, the Financial Accounting Standards Board (FASB) issued FASB staff
position 19-1 (FSP 19-1) on accounting for suspended well costs. FSP 19-1 amends
FASB Statement No. 19, FINANCIAL ACCOUNTING AND REPORTING BY OIL AND GAS
PRODUCING COMPANIES, for companies using the successful efforts method of
accounting. FSP 19-1 concludes that exploratory well costs should continue to be
capitalized when a well has found a sufficient quantity of reserves to justify
its completion as a producing well and the company is making sufficient progress
assessing the reserves and the economic and operating viability of the well. FSP
19-1 also requires certain disclosures with respect to capitalized exploratory
well costs. This new guidance is effective for the first reporting period
beginning after April 4, 2005 and is to be applied prospectively to existing and
newly capitalized exploratory well costs.
As at March 31, 2005, we have exploratory costs that have been capitalized for
more than one year relating to our interest in an exploratory block, offshore
Nigeria. Exploratory costs were first capitalized in 1998 and we have
subsequently drilled a further seven successful wells on the block. We are
preparing a field development plan for the block with our partners for
submission to the Nigerian government for approval. Once we obtain this approval
and the project has been sanctioned, we will book proved reserves. Capitalized
costs relating to this exploration block as at March 31, 2005 were $79 million
(December 31, 2004 - $77 million). We do not expect the adoption of this
statement will have a material impact on our capitalized costs, our results of
operations or financial position.
23
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
THE FOLLOWING SHOULD BE READ IN CONJUNCTION WITH THE UNAUDITED CONSOLIDATED
FINANCIAL STATEMENTS INCLUDED IN THIS REPORT. THE UNAUDITED CONSOLIDATED
FINANCIAL STATEMENTS HAVE BEEN PREPARED IN ACCORDANCE WITH GENERALLY ACCEPTED
ACCOUNTING PRINCIPLES (GAAP) IN CANADA. THE IMPACT OF THE SIGNIFICANT
DIFFERENCES BETWEEN CANADIAN AND UNITED STATES (US) ACCOUNTING PRINCIPLES ON THE
FINANCIAL STATEMENTS IS DISCLOSED IN NOTE 16 TO THE UNAUDITED CONSOLIDATED
FINANCIAL STATEMENTS. THE DATE OF THIS DISCUSSION IS APRIL 26, 2005.
UNLESS OTHERWISE NOTED, TABULAR AMOUNTS ARE IN MILLIONS OF CANADIAN DOLLARS. THE
DISCUSSION AND ANALYSIS OF OUR OIL AND GAS ACTIVITIES WITH RESPECT TO OIL AND
GAS VOLUMES, RESERVES AND RELATED PERFORMANCE MEASURES IS PRESENTED ON A
WORKING-INTEREST, BEFORE-ROYALTIES BASIS. WE MEASURE OUR PERFORMANCE IN THIS
MANNER CONSISTENT WITH OTHER CANADIAN OIL AND GAS COMPANIES. WHERE APPROPRIATE,
WE HAVE PROVIDED INFORMATION ON A NET, AFTER-ROYALTIES BASIS IN TABULAR FORMAT.
NOTE: CANADIAN INVESTORS SHOULD READ THE SPECIAL NOTE TO CANADIAN INVESTORS ON
PAGE 72 OF OUR 2004 ANNUAL REPORT ON FORM 10-K WHICH HIGHLIGHTS DIFFERENCES
BETWEEN OUR RESERVE ESTIMATES AND RELATED DISCLOSURES THAT ARE OTHERWISE
REQUIRED BY CANADIAN REGULATORY AUTHORITIES.
EXECUTIVE SUMMARY OF FIRST QUARTER RESULTS
THREE MONTHS
ENDED MARCH 31
(CDN$ MILLIONS) 2005 2004
- --------------------------------------------------------------------------------
Net Income 37 184
Earnings per Common Share ($/share) 0.29 1.44
Cash Flow from Operating Activities 441 538
Production, before Royalties (mboe/d) 260 258
Production, after Royalties (mboe/d) 183 176
Nexen's Average Realized Oil and Gas Price (Cdn$/boe) 49.55 40.11
Capital Expenditures 599 325
Net Debt (1) 4,348 1,566
------------------
Note:
(1) Net debt is defined as long-term debt less net working capital.
Strong production and commodity prices generated solid operating results. Net
income was reduced by $173 million to reflect the decrease in market value of
our crude oil put options and by $125 million related to stock-based
compensation.
Following our North Sea acquisition late last year, we purchased put options on
60,000 bbls/d of oil production for 2005 and 2006, for $144 million, to ensure
base cash flow over the next two years to support our investment in major
development projects. These options create an average floor price for this
production of US$43.17/bbl in 2005 and US$38.17/bbl in 2006. Accounting rules
require that these options be recorded at fair value throughout their term. As a
result, changes in forward crude oil prices cause gains or losses to be recorded
on these options each quarter. While a gain of $56 million was recorded in the
fourth quarter of 2004, a significant increase in forward crude oil prices
during the first quarter of 2005 resulted in an expense of $173 million. The
carrying value of these options at the end of the first quarter was $27 million.
We have a broad stock-based compensation plan to attract and retain quality
employees in a highly-competitive environment and we have recorded stock-based
compensation since 2003. Changes in the price of our shares results in increases
or decreases to net income. During the first quarter, our stock price increased
36% or $17.50/share, adding $2.3 billion in shareholder value. As a result, $125
million of stock-based compensation expense was recognized. On an after-tax
basis, this represents 3.6% of the increase in shareholder value. Approximately
20% of this expense was in cash, while the balance represents the change in
value of our accrued stock based compensation.
Notwithstanding our solid operating results, our cash flow from operating
activities decreased by $97 million compared to the first quarter of 2004. In
2005, we have used our cash flow from operating activities to fund remediation
costs of $17 million, primarily with respect to the shut-down of operations in
Australia, and to finance an increase of $99 million in our inventories. The
increased inventories primarily reflect larger gas storage positions as well as
the higher cost of inventoried product. In 2004, a reduction in receivables
contributed $115 million to cash flow from operating activities.
24
Production before royalties increased compared to the fourth quarter of 2004,
with higher rates from Yemen and the North Sea and a solid quarter from Canada,
more than offsetting declines in the US and temporary shortfalls at Syncrude
related to scheduled maintenance.
Our major development projects in the North Sea, at Long Lake, Block 51 in Yemen
and the Syncrude Stage 3 expansion all progressed during the quarter. Our Long
Lake project is now approaching 80% engineered and our Buzzard project is
approximately 65% complete. Both projects remain on time and on budget. Two
discoveries were made in the Gulf of Mexico during the quarter at Wrigley and
Anduin. Wrigley is expected on-stream mid-2006 and we plan to follow up Anduin
later in 2005 to further assess the discovery.
We plan to raise at least $1.5 billion through the sale of assets in 2005 and we
are currently marketing our chemicals assets and certain Canadian conventional
oil and gas properties, which currently produce approximately 22,000 boe/d. The
proceeds from these sales will be used to reduce our outstanding debt and fund
future capital investment.
CAPITAL INVESTMENT
Our capital investment over the next two years is focused on bringing our major
development projects on-stream. To date, we have invested over $3 billion in the
Buzzard, Long Lake and Syncrude Stage 3 development projects. These projects
will start to come on-stream in 2006 and are expected to add almost 120,000
boe/d (net to us) of new production through 2007.
In addition to developing these projects, we are also targeting new
opportunities through on-going exploration and the application of new
technologies. Details of our capital programs are set out below.
NEW GROWTH NEW GROWTH CORE ASSET
(CDN$ MILLIONS) DEVELOPMENT EXPLORATION DEVELOPMENT TOTAL
- -------------------------------------------------------------------------------------------------------------------
Oil and Gas
Synthetic (mainly Long Lake) 176 -- -- 176
United Kingdom 114 3 26 143
Yemen 45 8 18 71
United States -- 72 19 91
Canada 5 20 34 59
Other Countries -- 7 4 11
Syncrude 34 -- 10 44
-------------------------------------------------------------
374 110 111 595
Chemicals, Marketing, Corporate and Other -- -- 4 4
-------------------------------------------------------------
Total Capital 374 110 115 599
=============================================================
As a % of Total Capital 63% 18% 19% 100%
-------------------------------------------------------------
NEW GROWTH DEVELOPMENT
LONG LAKE PROJECT
The Long Lake Project continues to progress well and is on schedule and on
budget. To date, approximately 45% of the project's total costs are committed,
with approximately 28% of these incurred. Cost experience is in line with our
original estimates.
The detailed engineering for the facilities is approaching the 80% engineering
completion milestone, which will facilitate above-ground mechanical construction
commencing on schedule in the second quarter. The SAGD facilities are expected
to be completed in late-2006 and the upgrader in late-2007, with synthetic crude
oil production ramping up to approximately 60,000 bbls/d. Nexen has a 50%
interest in the project.
Commercial SAGD drilling remains ahead of schedule, with close to half our
horizontal wells drilled. Drilling of all 78 well pairs is expected to be
completed during the first quarter of 2006.
25
NORTH SEA DEVELOPMENT
Our Buzzard development in the North Sea remains on budget and on schedule.
During the quarter, we completed construction of the three platform jackets and
finalized the detailed design of the facilities. The wellhead deck fabrication
is also nearing completion. Through the spring and summer, we plan to install
the jackets and the wellhead deck and begin laying the sub-sea pipelines.
Development drilling is planned to begin in the third quarter. Overall, the
Buzzard development is approximately 65% complete.
First production from Buzzard is expected in late-2006, with our share of
expected peak production reaching approximately 80,000 boe/d in 2007. We have a
43.2% operated interest in the field.
Our Farragon field development remains on schedule to begin producing late this
year at between 3,000 and 4,000 boe/d, net to us. We have a non-operated 20%
interest here.
NEW GROWTH EXPLORATION
In the Gulf of Mexico, we are evaluating our Anduin discovery, formulating
development plans for our Wrigley discovery, and are currently drilling the
Vrede, Knotty Head and Big Bend prospects. Both Knotty Head and Vrede are
deep-water, sub-salt prospects in the Green Canyon and Atwater Valley areas,
respectively. Big Bend is a deep-shelf gas prospect in the Mustang Island area.
Results from these wells are expected during the second quarter.
Pathfinder, a third deep-water, sub-salt prospect will commence drilling on
Green Canyon 390, following rig release at Vrede. We have a 25% non-operated
interest in Pathfinder.
The Castleton prospect, on Garden Banks 668, is a potential tie-back to the
Gunnison facilities where we have additional production capacity. This
deep-water well should commence drilling in the second quarter, with results
expected in the third quarter. We have a 30% non-operated interest here.
On Block 51 in Yemen, we finished testing the BAK-I well. The well encountered
non-commercial quantities of oil and has been suspended. We are encouraged by
the presence of oil on this part of the block. We are conducting additional
seismic and plan to drill another well to further evaluate this prospect. At
BAK-J, we are still waiting for necessary high pressure drilling equipment
before re-entering the well and re-commencing drilling activities. We plan to
drill four additional exploration wells on Block 51 this year.
In the North Sea, we began drilling the Saracen prospect on Block 21/2 in early
April, with results expected late in the second quarter. We have a 50% operated
interest in Saracen. During the second quarter, we expect to begin drilling our
Polecat prospect on Block 20/4a, where we have a 40% operated interest. We plan
to drill between two and four more exploration wells in the North Sea this year.
Offshore West Africa, we plan to drill three or four exploration wells prior to
year-end. On OPL-222, offshore Nigeria, we approved drilling the Efere prospect
and expect to commence drilling in the second quarter. As well, we agreed with
partners to launch basic engineering for the development of Usan on a floating
production and storage facility. Both are subject to the approval of the
authorities.
26
FINANCIAL RESULTS
CHANGE IN NET INCOME
2005 VS. 2004
(Cdn$ millions)
- ------------------------------------------------------------------------------------
NET INCOME AT MARCH 31, 2004 (1) 184
==============
Favourable (unfavourable) variances:
Cash Items:
Production volumes, after royalties:
Crude oil 58
Natural gas (11)
--------------
Total Volume Variance 47
Realized commodity prices:
Crude oil 112
Natural gas 9
--------------
Total Price Variance 121
Oil and gas operating expense:
Conventional (19)
Syncrude (11)
--------------
Total Operating Expense Variance (30)
Marketing 20
Chemicals 6
General and administrative
Stock-based compensation paid (16)
Other (7)
Interest expense 11
Current income taxes (26)
Other (3)
--------------
Total Cash Variance 123
Non-Cash Items:
Depreciation, depletion, amortization and impairment
Oil and Gas (72)
Other (2)
General and administrative - stock-based compensation accrual (98)
Future income taxes 72
Decrease in fair value of crude oil put options (173)
Other 3
--------------
Total Non-Cash Variance (270)
--------------
NET INCOME AT MARCH 31, 2005 37
==============
Note:
(1) Includes results of discontinued operations (see Note 12 to our Unaudited
Consolidated Financial Statements).
Significant variances in net income are explained further in the following
sections.
27
OIL & GAS AND SYNCRUDE
PRODUCTION
THREE MONTHS ENDED MARCH 31
2005 2004
- ----------------------------------------------------------------------------------------------
BEFORE AFTER BEFORE AFTER
ROYALTIES(1) ROYALTIES ROYALTIES(1) ROYALTIES
-------------------------------------------------------
Crude Oil and NGLs (mbbls/d)
Yemen 114.3 57.7 114.1 54.0
Canada 34.7 27.5 36.8 28.6
United States 28.5 25.2 26.7 23.5
United Kingdom 14.9 14.9 -- --
Australia (2) -- -- 4.5 4.2
Other Countries 5.9 5.4 4.9 4.2
Syncrude (3) 11.4 11.3 18.3 18.1
-------------------------------------------------------
209.7 142.0 205.3 132.6
-------------------------------------------------------
Natural Gas (mmcf/d)
Canada 143 111 149 120
United States 127 108 167 142
United Kingdom 29 29 -- --
-------------------------------------------------------
299 248 316 262
-------------------------------------------------------
Total (mboe/d) 260 183 258 176
=======================================================
Notes:
(1) We have presented production volumes before royalties as we measure our
performance on this basis consistent with other Canadian oil and gas
companies.
(2) Comprises production from discontinued operations. See Note 12 to our
Unaudited Consolidated Financial Statements.
(3) Considered a mining operation for US reporting purposes.
HIGHER PRODUCTION INCREASED NET INCOME FOR THE QUARTER BY $47 MILLION
Production after royalties increased 4% from the first quarter in 2004.
Production in 2004 included volumes from our operations in Australia that
reached final production in November 2004. Our 2005 production includes volumes
from our North Sea acquisition in the fourth quarter last year. The following
table summarizes our production volume changes quarter on quarter:
BEFORE AFTER
(MBOE/D) ROYALTIES ROYALTIES
- -----------------------------------------------------------------------------------------------
Production, first quarter 2004 258 176
Production changes:
Masila Block in Yemen (18) (8)
Block 51 in Yemen 18 12
Canada (3) (3)
United States (5) (4)
United Kingdom 20 20
Australia (5) (4)
Syncrude (7) (7)
Other 2 1
--------------------------
Production, first quarter 2005 260 183
==========================
Our expected future production increases from known projects will come from
Block 51 in Yemen in 2005, Syncrude in 2006, Buzzard in late-2006, along with
bitumen production in 2006 and synthetic crude in 2007 from the Long Lake
project. Production volumes discussed in this section represent before-royalties
volumes, net to our working interest.
28
YEMEN
Production from Masila decreased 4% from the fourth quarter and 15% from the
first quarter of 2004. Production declines from the Masila project reflect field
maturity and the impact of a reduced development drilling program. In 2004, we
drilled 73 development wells and the partners expect to drill 35 wells in 2005.
Block 51 production began in November 2004 at initial rates of 4,000 bbls/d and
averaged 17,700 bbls/d in the first quarter. We expect that the wells currently
producing through temporary production facilities will maintain volumes until
the commissioning of permanent processing facilities increases production to
approximately 30,000 bbls/d later in the year.
CANADA
Production in Canada was consistent with the previous quarter but lower by 5%
from the first quarter of 2004. The decrease from the beginning of 2004 was in
line with expectations as we continue to maximize the value of our existing
investments. We are contemplating the sale of certain Canadian oil and gas
properties in 2005. Any sale of properties would reduce our 2005 production
volumes with a corresponding effect on cash flow from operating activities.
Production volumes are expected to increase in 2006 with the commencement of
bitumen production from Long Lake.
UNITED STATES
Gulf of Mexico production was 9% lower than the first quarter of 2004 primarily
due to base declines in our shallow-water fields. The declines were partially
offset by higher production from Gunnison. All ten sub-sea wells at Gunnison
were on-stream in 2005 versus the initial three wells on-stream in early-2004.
Production was 15% lower than the fourth quarter of 2004. This was largely due
to lower production at our Aspen field where we experienced increased water
production. We are evaluating a number of options to increase Gulf of Mexico
production, including drilling another well at Aspen. With the current tight
drilling rig market in the deep-water Gulf, this activity is unlikely to occur
until later in the year. Our Aspen field achieved pay-out of our investment in
January 2005, just over two years from first production.
UNITED KINGDOM
The North Sea assets purchased in late 2004 contributed a full quarter of
production. Production from the Scott and Telford fields have exceeded our
expectations and we expect re-completions and additional development drilling to
maintain production rates. Production is expected to increase in late-2006 once
the Buzzard development comes on-stream.
OTHER COUNTRIES
Australia produced its final barrel in November 2004 and abandonment and
reclamation activities are virtually complete. Our Ejulebe field, offshore
Nigeria, continues to produce small volumes as strong crude oil prices keep
operations economical. We expect to discontinue production from Ejulebe in the
second or third quarter.
Production from Colombia averaged 5,600 bbls/d and increased 35% from the first
quarter of 2004 as a result of the development program at Guando. Production was
consistent with the fourth quarter.
SYNCRUDE
Syncrude production fell by 30% from the fourth quarter as a result of the
unsuccessful start-up of a hydrogen plant at the end of January which limited
hydrotreating capacity for the remainder of the quarter. Turnarounds scheduled
for the second quarter were accelerated to February and March to be done
concurrent with repairs to the hydrogen unit. The turnaround and repairs took
longer than expected as a result of labour shortages caused by competing oil
sands projects and additional repairs on some units. Full production has resumed
in the second quarter. We still expect to achieve our 2005 planned production
rate of between 16,000 and 18,000 bbls/d. The start-up of the Stage 3 expansion
is expected to increase our volumes by 8,000 bbls/d in 2006.
29
COMMODITY PRICES
THREE MONTHS
ENDED MARCH 31
2005 2004
- --------------------------------------------------------------------------------
CRUDE OIL AND NGLS
West Texas Intermediate (WTI) (US$/bbl) 49.85 35.15
--------------------
Differentials (1) (US$/bbl)
Masila 6.68 3.82
Heavy Oil 19.33 9.87
Mars 7.15 4.67
Dated Brent 2.35 3.20
Producing Assets (Cdn$/bbl)
Yemen 54.38 41.88
Canada 35.99 32.51
United States 50.90 38.99
United Kingdom 54.53 --
Australia -- 42.60
Other Countries 46.63 37.07
Syncrude 65.15 45.54
Corporate Average (Cdn$/bbl) 51.33 40.22
--------------------
NATURAL GAS
New York Mercantile Exchange (NYMEX) (US$/mmbtu) 6.48 5.73
AECO (Cdn$/mcf) 6.34 6.26
--------------------
Producing Assets (Cdn$/mcf)
Canada 5.80 5.59
United States 8.32 7.63
United Kingdom 6.92 --
Corporate Average (Cdn$/mcf) 6.98 6.63
--------------------
NEXEN'S AVERAGE REALIZED OIL AND GAS PRICE (Cdn$/boe) 49.55 40.11
--------------------
AVERAGE FOREIGN EXCHANGE RATE
Canadian to US Dollar (US$) 0.8152 0.7588
--------------------
Note:
(1) These differentials are a discount to WTI.
HIGHER REALIZED COMMODITY PRICES INCREASED QUARTERLY NET INCOME BY $121 MILLION
In the first quarter, WTI averaged US$49.85/bbl compared to US$35.15/bbl in the
first quarter of 2004 (an increase of 42%). Despite the high WTI price
environment, our corporate average realized oil price over the same period was
$51.33/bbl compared to $40.22/bbl in the first quarter of 2004 (an increase of
28%). While WTI increased by 42%, we are not realizing the full increase in
benchmark prices. 8% of the increase was not realized as a result of the weaker
US dollar and 6% of the increase was not realized as a result of widening crude
oil differentials. Our corporate differential averaged US$8.01/bbl (16% discount
relative to WTI) for the quarter compared to US$4.63/bbl in the first quarter of
2004 (13% discount relative to WTI).
All of our oil sales and most of our gas sales are denominated in or referenced
to US dollars. As a result, the strong Canadian dollar decreased net sales for
the quarter by approximately $60 million, and reduced our realized crude oil and
natural gas prices by approximately $3.80/bbl and $0.50/mcf, respectively,
compared to the first quarter of 2004.
30
CRUDE OIL REFERENCE PRICES
Crude oil prices strengthened throughout the first quarter, with WTI entering
the year around US$45/bbl and climbing to a record-high around US$58/bbl during
the quarter. Despite a well supplied market with inventory levels in the middle
of historic ranges, concerns over sustainable supply and spare capacity have
persisted, pushing benchmark prices to successive all-time highs. Differentials
have had a large impact on our realized prices as we experienced record wide
heavy oil differentials in North America, relatively narrow sour differentials
and extremely narrow Brent/WTI differentials. Although inventory levels are at
reasonable levels, crude oil markets continue to question whether current
production profiles, along with inventories, will be sufficient to meet future
demand, particularly the demand for light/sweet or light/sour crudes.
OPEC has committed to help manage prices, increasing output quotas by 500,000
bbls/d in mid-March and promising another increase of 500,000 bbls/d if prices
remain strong. However, this is expected to have little impact on the tight
market. With little spare production capacity available worldwide and only
modest growth in future production on the horizon, it is becoming difficult for
the market to meet new demand or adapt to pressures from operating disruptions
or political unrest. As a result, continued supply disruptions in the North Sea,
Gulf of Mexico and Canadian oilsands coupled with lacklustre production growth
from Russia and rumors of labour unrest in Nigeria have weighed in to provide
price support.
In mid-April, WTI has declined to around US$50/bbl in light of rising inventory
levels and increased refinery activity. Future prices are expected to be strong
as the forward strip is higher than near-term prices.
CRUDE OIL DIFFERENTIALS
Benchmark LLK heavy crude differentials averaged US$19.33/bbl for the first
quarter compared to the prior year of US$9.87/bbl. This widening is being driven
by increased demand for light oil blends which are used as benchmark prices,
combined with lower heavy oil demand due to seasonal factors and refinery
turnarounds. In addition, price realizations for our heavy oil have decreased in
light of the high cost of condensates for diluent purposes. Condensate costs
have increased following the Syncrude turnarounds, the fire at Suncor's upgrader
and the higher demand for condensate from increasing heavy oil production in
Western Canada. With the refineries coming out of turnaround and regular
seasonal demand picking up, we expect differentials to narrow in the second
quarter. In the US Gulf of Mexico, the Mars differential was US$7.15/bbl. This
differential has narrowed throughout the quarter and remained reasonably narrow
given the strength of WTI, as competing sour crudes have not been making their
way into the Gulf of Mexico market. Instead, these sour crudes have made their
way into the southeast Asian market where demand has been strong.
Our Yemen Masila differential was US$6.68/bbl against US$3.82/bbl in the first
quarter of 2004. Despite being wider than the prior year, the Masila
differential has narrowed throughout the quarter in light of the strong demand
in southeast Asia for crude oil, particularly sweeter blends. The Brent/WTI
differential has also narrowed throughout the quarter averaging US$2.35/bbl.
This has resulted in solid crude oil pricing for our North Sea barrels. Strong
demand from European refiners has pushed Brent up relative to the North American
WTI benchmark. In the winter, Brent barrels typically make their way into the
North American market but the strong demand in Europe has kept the barrels
there.
Syncrude prices reflected a premium to WTI of US$3.26/bbl compared to a discount
of US$0.60/bbl in 2004. The premium is a result of the shortage of synthetic
crude following maintenance and turnaround activity at Syncrude, the fire at
Suncor's upgrader and the higher diluent demand in heavy oil producing areas of
Western Canada.
NATURAL GAS REFERENCE PRICES
Natural gas prices were weak early in the quarter, as the North American market
remained well supplied with only modest withdrawals from storage because of
moderate winter weather. However, prices increased throughout March largely on
the strength of WTI and some colder weather in the east. With storage levels
remaining high heading into summer, we expect prices to be fairly weak through
the second quarter.
31
OPERATING COSTS
THREE MONTHS ENDED MARCH 31
(CDN$/BOE) 2005 2004
- ----------------------------------------------------------------------------------------------------
BEFORE AFTER BEFORE AFTER
ROYALTIES(1) ROYALTIES ROYALTIES(1) ROYALTIES
--------------------------------------------------
Conventional Oil and Gas (2) 5.44 8.00 4.78 7.21
Synthetic Crude Oil
Syncrude 39.91 40.31 17.41 17.59
Total Oil and Gas (2) 6.94 9.94 5.67 8.26
--------------------------------------------------
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) 2004 operating costs include results of discontinued operations (see Note 12
to our Unaudited Consolidated Financial Statements).
HIGHER CONVENTIONAL OIL AND GAS AND SYNCRUDE OPERATING COSTS DECREASED NET
INCOME FOR THE QUARTER BY $30 MILLION
Operating costs increased in the quarter from new higher-cost production from
the North Sea and from turnaround and maintenance activities at Syncrude.
Operating costs in the North Sea averaged $12.59/boe, increasing our corporate
average by $1.15/boe.
Our operations at Masila in Yemen, in Canada and in the shallow-waters of the
Gulf of Mexico are maturing and have increasing operating costs. Increased costs
reflect higher water handling and more workovers to maintain production. These
higher costs over declining production increased our corporate average by
$0.55/boe compared to the first quarter of 2004.
Our Australian operations ceased producing in November 2004 and the exclusion of
these high-cost, late-life barrels reduced our corporate average by $0.66/boe.
Many of the costs in Australia were fixed and the low volumes resulted in high
operating costs per barrel.
US-dollar denominated operating costs were lower when translated to Canadian
dollars as a result of the weak US dollar. Our corporate average was reduced by
$0.25/boe as a result of the weaker US dollar.
Syncrude operating costs per boe were 130% higher than the first quarter of 2004
from turnaround and repair costs spread over reduced volumes. Turnaround costs
were higher than expected as a result of labour shortages in the Athabasca oil
sands region. Syncrude increased our corporate average operating costs by
$0.50/boe. Operating costs at Syncrude are expected to return to normal levels
of between $17.00 and $19.00 per barrel for the remainder of the year as the
turnarounds have been completed and full production has resumed.
DEPRECIATION, DEPLETION, AMORTIZATION AND IMPAIRMENT (DD&A)
THREE MONTHS ENDED MARCH 31
(CDN$/BOE) 2005 2004
- ----------------------------------------------------------------------------------------------------
BEFORE AFTER BEFORE AFTER
ROYALTIES(1) ROYALTIES ROYALTIES(1) ROYALTIES
--------------------------------------------------
Conventional Oil and Gas (2) 10.40 15.28 7.32 11.04
Synthetic Crude Oil
Syncrude 3.56 3.60 2.65 2.68
Average Oil and Gas (2) 10.10 14.47 6.99 10.19
--------------------------------------------------
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) 2004 DD&A includes results of discontinued operations (see Note 12 to our
Unaudited Consolidated Financial Statements).
HIGHER OIL AND GAS DD&A REDUCED NET INCOME FOR THE QUARTER BY $72 MILLION
Oil and gas DD&A was impacted by new production from our North Sea assets and as
a result of additional cost recovery from Block 51 in Yemen. The North Sea
fields purchased in late 2004 include an allocation of the acquisition cost of
our interests in the Scott and Telford fields. North Sea depletion increased our
overall corporate average rate by $2.15/boe for the quarter.
Production from Block 51 in Yemen increased corporate unit depletion by
$1.39/boe in the quarter as a result of carried interest accounting with respect
to the recovery of Block 51 capital costs. Cost increases and lower volumes in
Canada and the US increased the corporate average by $0.50/boe.
32
By way of offset, we benefited from a strong Canadian dollar as the depletion of
our US and international assets is denominated in US dollars. This lowered our
depletion rate by $0.60/boe. Our average oil and gas DD&A was also lowered by
$0.35/bbl in 2005 as we had no depletion with respect to our Australian
operations in the first quarter of 2005.
Lower volumes at Syncrude as a result of turnaround and plant maintenance
activities increased costs per barrel as a portion of Syncrude's DD&A includes
fixed depreciation on operating facilities.
EXPLORATION EXPENSE
THREE MONTHS
ENDED MARCH 31
(CDN$ MILLIONS) 2005 2004
- --------------------------------------------------------------------------------
Seismic 5 18
Unsuccessful Exploration Drilling 8 --
Other 15 10
-------------------
Total Exploration Expense 28 28
===================
New Growth Exploration 110 27
Geological and Geophysical Costs 5 18
-------------------
Total Exploration Expenditures 115 45
===================
Exploration Expense as a % of Exploration Expenditures 24% 62%
-------------------
EXPLORATION EXPENSE WAS CONSISTENT WITH THE PRIOR YEAR
Exploration expense includes additional costs relating to our unsuccessful
Crested Butte exploration well in the Gulf of Mexico.
Exploration capital in the quarter includes expenditures on the Vrede and Knotty
Head deep-water, sub-salt prospects and the Big Bend deep-shelf gas prospect in
the Gulf of Mexico. Results from these wells are expected in the second quarter.
Exploration spending also includes costs related to our Anduin and Wrigley
discoveries in the Gulf of Mexico. Anduin will be further evaluated with
additional appraisal drilling while plans are being formulated to sanction
Wrigley later this year. On Block 51 in Yemen, we finished testing the BAK-I
well which encountered non-commercial quantities of oil and has been suspended.
The BAK-J well on Block 51 in Yemen will be tested further once the necessary
high-pressure drilling equipment is in place later in the quarter. We plan to
test further prospects in the Gulf of Mexico, North Sea, Block 51 and offshore
West Africa in the remainder of the year.
OIL AND GAS MARKETING
THREE MONTHS
ENDED MARCH 31
(CDN$ MILLIONS) 2005 2004
- --------------------------------------------------------------------------------
Marketing Revenue, net 229 147
Transportation (177) (116)
Other (2) (1)
-------------------
Net Revenue 50 30
===================
Physical Sales Volumes (excluding intra-segment transactions)
Crude Oil (mboe/d) 476 416
Natural Gas (mmcf/d) 5,023 4,376
Value-at-Risk
Quarter-end 26 26
High 30 26
Low 20 17
Average 25 21
-------------------
33
HIGHER CONTRIBUTION FROM MARKETING INCREASED NET INCOME BY $20 MILLION
Our gas marketing group continued to generate gains by trading around our
transportation and storage capacity. Transportation capacity allowed us to take
advantage of variable winter weather across North America as we were able to
move gas to capture price differences between markets. During the spring and
summer of 2004, we injected gas into storage when prices were lower. We
generated gains in the first quarter of 2005 by withdrawing 8 bcf of gas from
storage to take advantage of higher winter prices. In addition, we generated
profits on near-term short positions where we were able to buy gas at floating
prices and then sell at higher fixed prices.
Our domestic and international crude oil marketing groups successfully
capitalized on the shape of the forward price curve. Early in the quarter, we
were able to price sales early and purchase later taking advantage of
backwardation in the curve (declining future prices). Later, when the price
curve changed to contango (increasing future prices), we were able to price
sales later and purchase earlier. We also continued to move crude oil between
markets to capitalize on locational price differences.
COMPOSITION OF NET MARKETING REVENUE
THREE MONTHS
ENDED MARCH 31
(CDN$ MILLIONS) 2005 2004
- -----------------------------------------------------------------------------------------------------------
Trading Activities 44 25
Non-Trading Activities 6 5
---------------------------
50 30
===========================
TRADING ACTIVITIES
In marketing, we enter into contracts to purchase and sell crude oil and natural
gas. We also use financial and derivative contracts, including futures,
forwards, swaps and options for hedging and trading purposes. These derivative
contracts are valued as described in the MD&A included in our 2004 Annual Report
on Form 10-K. Results from trading activities include physical purchases and
sales, gains and losses on derivative contracts and income relating to our
storage and transportation assets.
FAIR VALUE OF DERIVATIVE CONTRACTS
At March 31, 2005, the fair value of our derivative contracts not designated as
accounting hedges totalled $66 million. The following table shows the valuation
methods underlying these contracts together with details of contract maturity:
(CDN$ MILLIONS) MATURITY
- ----------------------------------------------------------------------------------------------------------------
LESS THAN MORE THAN
1 YEAR 1-3 YEARS 4-5 YEARS 5 YEARS TOTAL
------------------------------------------------------------
Prices
Actively Quoted Markets (23) 1 -- -- (22)
From Other External Sources 22 54 13 (1) 88
Based on Models and Other Valuation Methods -- -- -- -- -
------------------------------------------------------------
Total (1) 55 13 (1) 66
============================================================
At March 31, 2005, we had $1 million of unrecognized losses on our derivative
contracts designated as accounting hedges of the future sale of our gas
inventory. These losses will be recognized in income when the inventory is sold.
These contracts were valued from actively quoted markets and settle within 12
months.
We do not use option valuation methods to record income on transportation and
storage contracts.
34
CHANGES IN FAIR VALUE OF DERIVATIVE CONTRACTS
CONTRACTS
OUTSTANDING AT CONTRACTS
BEGINNING OF ENTERED INTO
(CDN$ MILLIONS) PERIOD DURING PERIOD TOTAL
- -------------------------------------------------------------------------------------------------------------------
Fair Value at December 31, 2004 93 -- 93
Change in Fair Value of Contracts (32) 55 23
Net Losses (Gains) on Contracts Closed (13) (37) (50)
Changes in Valuation Techniques and Assumptions (1) -- -- --
-------------------------------------------------
Fair Value at March 31, 2005 48 18 66
=================================
Unrecognized Losses on Hedges of Future Sale of Gas Inventory
at March 31, 2005 (1)
---------------
Total Outstanding at March 31, 2005 65
===============
Note:
(1) Our valuation methodology has been applied consistently in each period.
TOTAL CARRYING VALUE OF DERIVATIVE CONTRACTS
MARCH 31 DECEMBER 31
(CDN$ MILLIONS) 2005 2004
- -------------------------------------------------------------------------------------------------------------------
Current Assets 151 177
Non Current Assets 115 91
---------------------------
Total Derivative Contract Assets 266 268
===========================
Current Liabilities 152 129
Non Current Liabilities 48 46
---------------------------
Total Derivative Contract Liabilities 200 175
===========================
Total Derivative Contract Net Assets (1) 66 93
===========================
Note:
(1) Does not include effective hedges. We recognize gains and losses on
effective hedges in the same period as the hedged item.
NON-DERIVATIVE CONTRACTS
We enter into fee for service contracts related to transportation and storage of
third party oil and gas. In addition, we earn income from our power generation
facility. We earned $6 million from these activities in the first quarter (2004
- - $5 million).
In 2003 and 2004, we increased our transportation capacity and were paid to
assume future obligations associated with this capacity. We have $47 million of
deferred revenue on our balance sheet to recognize the liability associated with
these obligations. We are amortizing this deferred revenue to earnings as the
capacity is used.
CHEMICALS
STRONG QUARTERLY CHEMICALS CONTRIBUTION INCREASED NET INCOME BY $6 MILLION
Sales volumes and prices for our chemical products have remained strong since
the end of 2004. Volumes have increased compared to the first quarter of 2004 as
a result of strong demand and higher production capacity from our Brandon plant
expansion completed in October 2004. The weaker US dollar, however, has put
pressure on our US-dollar denominated sales, reducing net sales by $3 million in
the quarter compared to 2004. Sales and operations at our Brazil plant are
strong as a result of continued strong demand from Aracruz Celulose, our primary
customer in Brazil.
Operating costs are lower compared to 2004 as we have taken advantage of our
expanded lower-cost Brandon operations.
We are considering the sale of our chemicals business later this year. Any such
sale would reduce contributions from this business to our 2005 cash flow from
operating activities.
35
CORPORATE EXPENSES
GENERAL AND ADMINISTRATIVE (G&A)
THREE MONTHS
ENDED MARCH 31
(CDN$ MILLIONS) 2005 2004
- ------------------------------------------------------------------------------------------
General and Administrative Expense before Stock Based Compensation 56 49
Stock Based Compensation (1) 125 11
------------------
Total General and Administrative Expense 181 60
==================
Note:
(1) Includes tandem option plan, stock options for our US-based employees and
stock appreciation rights.
HIGHER COSTS DECREASED QUARTERLY NET INCOME BY $121 MILLION
In 2001, we introduced a stock appreciation rights plan for our employees and in
2004 we modified our stock option plan to a tandem option plan. The tandem
option plan gives option holders the right to either purchase common shares at
the exercise price or to receive cash payments equal to the excess of the market
value of the common shares over the exercise price. The obligations resulting
from these plans are revalued each quarter based on our current share price and
the resulting change is included as stock based compensation expense in our G&A
expense. During the first quarter of 2005, our share price increased 36% or
$17.50/share, adding $2.3 billion in shareholder value. As a result, a charge of
$125 million for our tandem option and stock appreciation rights plans was
recognized in the quarter. Stock price volatility will continue to impact our
G&A expense as our share price changes each quarter.
Our other G&A costs have increased from 2004 as a result of increases in
employee compensation and increased regulatory compliance and corporate
governance requirements resulting from Sarbanes-Oxley initiatives.
INTEREST AND FINANCING COSTS
THREE MONTHS
ENDED MARCH 31
(CDN$ MILLIONS) 2005 2004
- ------------------------------------------------------------------------------------------
Interest 67 52
Less: Capitalized Interest (33) (7)
------------------
Net Interest Expense 34 45
==================
LOWER INTEREST EXPENSE INCREASED QUARTERLY NET INCOME BY $11 MILLION
Our financing costs increased compared to 2004 as a result of our 2004 North Sea
acquisition. In late 2004, we drew US$1.5 billion on an acquisition credit
facility to partially finance this acquisition. A portion of these borrowings
were repaid during the quarter with proceeds from the March 2005 issue of
US$1.04 billion of senior public debt. The higher outstanding debt increased
interest expense by $18 million during the quarter, however, the stronger
Canadian dollar lowered our US-dollar denominated interest by $3 million.
We are capitalizing interest on our major development projects in the North Sea,
Syncrude, Long Lake and Block 51 in Yemen. Capitalized interest increased
primarily from the North Sea Buzzard project and additional spending at Long
Lake. We expect that capitalized interest will continue to increase as we spend
additional capital on these projects prior to their completion in 2006 and 2007.
INCOME TAXES
THREE MONTHS
ENDED MARCH 31
(CDN$ MILLIONS) 2005 2004
- ------------------------------------------------------------------------------------------
Current 79 53
Future (60) 12
------------------
Provision for Income Taxes 19 65
==================
Effective Tax Rate 34% 27%
------------------
36
EFFECTIVE TAX RATE FOR THE QUARTER INCREASES FROM 27% TO 34%
In 2004, a 1% corporate income tax rate reduction in Alberta resulted in a $15
million recovery of future income taxes in the first quarter.
Current income taxes include cash taxes in Yemen of $59 million (2004 - $46
million). Our current income tax provision also includes cash taxes in Colombia,
federal and state taxes in the US and capital taxes in Canada.
OTHER
THREE MONTHS
ENDED MARCH 31
(CDN$ MILLIONS) 2005 2004
- -------------------------------------------------------------------------------
Decrease in Fair Value of Crude Oil Put Options (173) --
-------------------
Following our North Sea acquisition late last year, we purchased put options on
60,000 bbls/d of oil production for 2005 and 2006, for $144 million, to ensure
base cash flow over the next two years to support our investment in major
development projects. These options create an average floor price for this
production of US$43.17/bbl in 2005 and US$38.17/bbl in 2006. Accounting rules
require that these options be recorded at fair value throughout their term. As a
result, changes in forward crude oil prices cause gains or losses to be recorded
on these options each quarter. While a gain of $56 million was recorded in the
fourth quarter of 2004, a significant increase in forward crude oil prices
during the first quarter of 2005 resulted in an expense of $173 million. The
carrying value of these options at the end of the first quarter was $27 million.
LIQUIDITY
CAPITAL STRUCTURE
MARCH 31 DECEMBER 31
(CDN$ MILLIONS) 2005 2004
- --------------------------------------------------------------------------------
NET DEBT (1)
Bank Debt 884 1,993
Public Senior Notes 3,078 1,813
-------------------------
Senior Debt 3,962 3,806
Subordinated Debt 556 553
-------------------------
Total Debt 4,518 4,359
Less: Cash and Cash Equivalents (70) (74)
Less: Non-Cash Working Capital (2) (100) (66)
-------------------------
TOTAL NET DEBT 4,348 4,219
=========================
SHAREHOLDERS' EQUITY (3) 2,949 2,867
=========================
Notes:
(1) Includes all of our debt and is calculated as long-term debt less net
working capital.
(2) Excludes short-term borrowings.
(3) At March 31, 2005, there were 129,990,330 common shares and US$460 million
of unsecured subordinated securities outstanding. These subordinated
securities may be redeemed by issuing common shares at our option after
November 8, 2008. The number of shares issuable depends on the common share
price on the redemption date.
During the quarter we issued US$1.04 billion of senior notes with US$250 million
maturing in 10 years and US$790 million maturing in 30 years. This new debt has
increased the average term to maturity of our debt to 22 years. Proceeds from
the debt issue were used to repay a portion of the acquisition credit facility
relating to our North Sea acquisition. Shareholders' equity continues to grow
with our solid financial results. We plan to raise $1.5 billion through asset
sales in 2005 and disposition proceeds will be applied to reduce our total net
debt and fund future capital investment.
37
CHANGE IN WORKING CAPITAL
MARCH 31 DECEMBER 31 INCREASE/
(CDN$ MILLIONS) 2005 2004 (DECREASE)
- -----------------------------------------------------------------------------------------------------
Cash and Cash Equivalents 70 74 (4)
Accounts Receivable 2,075 2,136 (61)
Inventories and Supplies 455 351 104
Accounts Payable and Accrued Liabilities (2,414) (2,416) 2
Other (16) (5) (11)
---------------------------------------
Net Working Capital 170 140 30
=======================================
The decrease in receivables reflects a decrease in our marketing receivables
partially offset by an increase in our oil and gas receivables. The decrease in
marketing receivables was attributable to reduced transaction volumes while the
increase in oil and gas receivables reflects stronger commodity prices and
higher sales volumes. The increase in inventories and supplies results primarily
from higher commodity prices and increases in our gas storage positions.
NET DEBT
Our net debt levels are directly related to our operating cash flows and our
capital expenditure activities. Changes in net debt are related to:
(CDN$ MILLIONS)
- --------------------------------------------------------------------------------
Capital Expenditures 599
Cash Flow from Operating Activities (441)
--------
Excess of Capital Expenditures over Cash Flow 158
Dividends on Common Shares 13
Issue of Common Shares (32)
Other (10)
--------
Increase in Net Debt 129
========
OUTLOOK FOR REMAINDER OF 2005
We continue to expect our 2005 full year production to average between 230,000
and 250,000 boe/d before royalties, but now we expect to achieve these volumes
even after the completion of our planned disposition program later this year. We
have revised our cash flow expectations for the remainder of the year as a
result of strong crude oil prices. We expect to generate approximately $2.2
billion in cash flow (before asset sales, remediation and geological and
geophysical expenditures) in 2005, assuming the following for the remainder of
the year:
- --------------------------------------------------------------------------------
WTI (US$/bbl) 50.00
NYMEX natural gas (US$/mmbtu) 6.50
US to Canadian dollar exchange rate 0.80
---------
Our planned 2005 capital investment program is unchanged at $2.6 billion. This
capital is largely targeted towards our major development projects in the North
Sea, Long Lake, Block 51 in Yemen and Syncrude.
Our future liquidity is primarily dependent on cash flows generated from our
operations, our capital requirements and the flexibility of our capital
structure. We are in the midst of developing a number of major projects and our
capital requirement over the next three years is significant. During the first
quarter, we were able to extend the average term to maturity of our debt by
issuing longer-term debt to repay a portion of the acquisition credit facility
relating to our North Sea acquisition. We also have available undrawn committed
credit facilities which provide us with liquidity to meet future funding
requirements. 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 in our 2004 Annual Report on Form 10-K.
During the quarter, we have entered into additional capital commitments totaling
$498 million related to our major development projects. We expect to incur
approximately $386 million of these commitments in the next twelve months and
approximately $112 million in one to three years time.
38
CONTINGENCIES
There are a number of lawsuits and claims pending, the ultimate results of which
cannot be ascertained at this time. We record costs as they are incurred or
become determinable. We believe the resolution of these matters would not have a
material adverse effect on our liquidity, consolidated financial position or
results of operations. These matters are described in LEGAL PROCEEDINGS in Item
3 contained in our 2004 Annual Report on Form 10-K. There have been no
significant developments since year end.
NEW ACCOUNTING PRONOUNCEMENTS
CANADIAN PRONOUNCEMENTS
In an effort to harmonize Canadian GAAP with US GAAP, the Canadian Accounting
Standards Board (AcSB) has issued sections:
o 1530, COMPREHENSIVE INCOME;
o 3855, FINANCIAL INSTRUMENTS -- RECOGNITION AND MEASUREMENT; and
o 3865, HEDGES.
Under these new standards, all financial assets should be measured at fair value
with the exception of loans, receivables and investments that are intended to be
held to maturity and certain equity investments, which should be measured at
cost. Similarly, all financial liabilities should be measured at fair value when
they are held for trading or they are derivatives.
Gains and losses on financial instruments measured at fair value will be
recognized in the income statement in the periods they arise with the exception
of gains and losses arising from:
o financial assets held for sale, for which unrealized gains and losses are
deferred in other comprehensive income until sold or impaired; and
o certain financial instruments that qualify for hedge accounting.
Sections 3855 and 3865 make use of "other comprehensive income". Other
comprehensive income comprises revenues, expenses, gains and losses that are
recognized in comprehensive income, but are excluded from net income. Unrealized
gains and losses on qualifying hedging instruments, translation of
self-sustaining foreign operations, and unrealized gains or losses on financial
instruments held for sale will be included in other comprehensive income and
reclassified to net income when realized. Comprehensive income and its
components will be a required disclosure under the new standard.
These new standards are effective for fiscal years beginning on or after October
1, 2006 and early adoption is permitted. Adoption of these standards as at March
31, 2005 would have the following impact on our Unaudited Consolidated Financial
Statements:
(CDN$ MILLIONS) INCREASE/(DECREASE)
- --------------------------------------------------------------------------------
Accounts Payable and Accrued Liabilities 1
Shareholders' Equity (1)
-------------------
The AcSB has approved revisions to Section 3830, NON-MONETARY TRANSACTIONS, that
require all non-monetary transactions to be measured at fair value unless:
o the transaction lacks commercial substance;
o the transaction is an exchange of a product or property held for sale in
the ordinary course of business for a product or property to be sold in the
same line of business to facilitate sales to customers other than the
parties to the exchange;
o neither the fair value of the assets or services received nor the fair
value of the assets or services given up is reliably measurable; or
o the transaction is a non-monetary, non-reciprocal transfer to owners that
represents a spin-off or other form of restructuring or liquidation.
The new requirements apply to non-monetary transactions initiated in periods
beginning on or after January 1, 2006. Earlier adoption is permitted as of the
beginning of a period beginning on or after July 1, 2005. We do not expect the
adoption of this section will have any material impact on our results of
operations or financial position.
39
US PRONOUNCEMENTS
In November 2004, the Financial Accounting Standards Board (FASB) issued
Statement 151, INVENTORY COSTS. This statement amends ARB 43 to clarify that:
o abnormal amounts of idle facility expense, freight, handling costs and
wasted material (spoilage) should be recognized as current-period charges;
and
o requires the allocation of fixed production overhead to inventory based on
the normal capacity of the production facilities.
The provisions of this statement are effective for inventory costs incurred
during fiscal years beginning after June 15, 2005. We do not expect the adoption
of this statement will have any material impact on our results of operations or
financial position.
In December 2004, the FASB issued Statement 123(R), SHARE-BASED PAYMENTS. This
statement revises Statement 123, ACCOUNTING FOR STOCK-BASED COMPENSATION, and
supersedes APB Opinion 25, ACCOUNTING FOR STOCK ISSUED TO EMPLOYEES. Statement
123(R) requires all stock-based awards issued to employees to be measured at
fair value and to be expensed in the income statement. This statement is
effective for fiscal years beginning after June 15, 2005.
We are currently expensing stock-based awards issued to employees using the fair
value method for equity based awards and the intrinsic method for liability
based awards. Adoption of this standard will change our expense under US GAAP
for tandem options and stock appreciation rights as these awards will be
measured using the fair value method rather than the intrinsic method. We are
currently evaluating the provisions of Statement 123(R) and have not yet
determined the full impact this statement will have on our results of operations
or financial position under US GAAP.
In December 2004, the FASB issued Statement 153, EXCHANGES OF NONMONETARY
ASSETS, an amendment of APB Opinion 29, ACCOUNTING FOR NONMONETARY TRANSACTIONS.
This amendment eliminates the exception for nonmonetary exchanges of similar
productive assets and replaces it with a general exception for exchanges of
nonmonetary assets that do not have commercial substance. Under Statement 153,
if a nonmonetary exchange of similar productive assets meets a
commercial-substance test and fair value is determinable, the transaction must
be accounted for at fair value resulting in the recognition of any gain or loss.
This statement is effective for nonmonetary transactions in fiscal periods that
begin after June 15, 2005. We do not expect the adoption of this statement will
have any material impact on our results of operations or financial position.
In March 2005, the FASB issued Financial Interpretation 47, ACCOUNTING FOR
CONDITIONAL ASSET RETIREMENT OBLIGATIONS (FIN 47). FIN 47 clarifies that the
term conditional asset retirement obligation as used in FASB Statement No. 143,
ACCOUNTING FOR ASSET RETIREMENT OBLIGATIONS, refers to a legal obligation to
perform an asset retirement activity in which the timing and (or) method of
settlement are conditional on a future event that may or may not be within the
control of the entity. The obligation to perform the asset retirement activity
is unconditional even though uncertainty exists about the timing and (or) method
of settlement. Thus, the timing and (or) method of settlement may be conditional
on a future event. Accordingly, an entity is required to recognize a liability
for the fair value of a conditional asset retirement obligation if the fair
value of the liability can be reasonably estimated. FIN 47 also clarifies when
an entity would have sufficient information to reasonably estimate the fair
value of an asset retirement obligation. FIN 47 is effective no later than the
end of fiscal years ending after December 15, 2005. We do not expect the
adoption of this statement will have a material impact on our results of
operations or financial position.
In March 2005, the Emerging Issues Task Force (EITF) reached a consensus on
Issue No. 04-6, ACCOUNTING FOR STRIPPING COSTS INCURRED DURING PRODUCTION IN THE
MINING INDUSTRY. In the mining industry, companies may be required to remove
overburden and other mine waste materials to access mineral deposits. The EITF
concluded that the costs of removing overburden and waste materials, often
referred to as "stripping costs", incurred during the production phase of a mine
are variable production costs that should be included in the costs of the
inventory produced during the period that the stripping costs are incurred.
Issue No. 04-6 is effective for the first reporting period in fiscal years
beginning after December 15, 2005, with early adoption permitted. We do not
expect the adoption of this statement will have a material impact on our results
of operations or financial position.
In April 2005, the FASB issued staff position 19-1 (FSP 19-1) on accounting for
suspended well costs. FSP 19-1 amends FASB Statement No. 19, FINANCIAL
ACCOUNTING AND REPORTING BY OIL AND GAS PRODUCING COMPANIES, for companies using
the successful efforts method of accounting. FSP 19-1 provides that exploratory
well costs should continue to be capitalized beyond twelve months when a well
has found a sufficient quantity of reserves to justify its completion as a
producing well and the company is making sufficient progress assessing the
reserves and the economic and operating viability of the well. FSP 19-1 also
requires certain disclosures with respect to capitalized exploratory well costs.
This new guidance is effective for the first reporting period beginning after
April 4, 2005 and is to be applied prospectively to existing and newly
capitalized exploratory well costs.
40
As at March 31, 2005, we have exploratory costs that have been capitalized for
more than one year relating to our interest in an exploratory block, offshore
Nigeria. Exploratory costs were first capitalized in 1998 and we have
subsequently drilled a further seven successful wells on the block. We are
preparing a field development plan for the block with our partners for
submission to the Nigerian government for approval. Once we obtain this approval
and the project has been sanctioned, we will book proved reserves. Capitalized
costs relating to this exploration block as at March 31, 2005 were $79 million
(December 31, 2004 - $77 million). We do not expect the adoption of this
statement will have a material impact on our capitalized costs, our results of
operations or financial position.
EQUITY SECURITY REPURCHASES
During the quarter, we made no purchases of our own equity securities.
SUMMARY OF QUARTERLY RESULTS
THREE MONTHS ENDED
--------------------------------------------------------------
2003 2004 2005
----------------------- ------------------------------ -------
(CDN$ MILLIONS) JUN SEPT DEC MAR JUN SEP DEC MAR
- --------------------------------------------------------------------------------- ------------------------------ -------
Net Sales 709 697 660 715 758 837 866 916
Net Income (Loss) from Continuing Operations 240 167 (84)(1) 180 138 220 242 37
Net Income (Loss) from Discontinued Operations 13 4 (2) 4 5 -- 4 --
--------------------------------------------------------------
Net Income (Loss) 253 171 (86) 184 143 220 246 37
==============================================================
Earnings per Common Share from
Continuing Operations ($/share)
Basic 1.95 1.35 (0.67) 1.41 1.07 1.70 1.87 0.29
Diluted 1.94 1.33 (0.66) 1.39 1.06 1.69 1.85 0.28
Earnings per Common Share ($/share)
Basic 2.05 1.38 (0.69) 1.44 1.11 1.70 1.90 0.29
Diluted 2.04 1.36 (0.68) 1.42 1.09 1.69 1.88 0.28
--------------------------------------------------------------
Note:
(1) Includes an impairment charge of $269 million relating to certain Canadian
oil and gas properties.
41
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS
Certain statements in this report, including those appearing in ITEM 2 -
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS, are forward-looking statements.(1) Forward-looking statements are
generally identifiable by terms such as ANTICIPATE, BELIEVE, INTEND, PLAN,
EXPECT, ESTIMATE, BUDGET, OUTLOOK or other similar words, and include statements
relating to future production associated with our Long Lake, North Sea and West
Africa projects.
These statements are subject to known and unknown risks and uncertainties and
other factors which may cause actual results, levels of activity and
achievements to differ materially from those expressed or implied by such
statements. These risks, uncertainties and other factors include:
o market prices for oil, natural gas and chemicals products;
o our ability to produce and transport crude oil and natural gas to markets;
o the results of exploration and development drilling and related activities;
o foreign-currency exchange rates;
o economic conditions in the countries and regions in which we carry on
business;
o governmental actions that increase taxes, change environmental and other
laws and regulations;
o renegotiations of contracts; and
o political uncertainty, including actions by terrorists, insurgent or other
groups, or other armed conflict, including conflict between states.
The above items and their possible impact are discussed more fully in the
section, titled BUSINESS RISK MANAGEMENT in Item 7 and QUANTITATIVE AND
QUALITATIVE DISCLOSURES ABOUT MARKET RISK in Item 7A of our 2004 Annual Report
on Form 10-K.
The impact of any one risk, uncertainty or factor on a particular
forward-looking statement is not determinable with certainty as these are
interdependent and management's future course of action depends upon our
assessment of all information available at that time. Any statements regarding
the following are forward-looking statements:
o future crude oil, natural gas or chemicals prices;
o future production levels;
o future cost recovery oil revenues from our operations in Yemen;
o future capital expenditures and their allocation to exploration and
development activities;
o future asset dispositions;
o future sources of funding for our capital program;
o future debt levels;
o future cash flows and their uses;
o future drilling of new wells;
o ultimate recoverability of reserves;
o expected finding and development costs;
o expected operating costs;
o future demand for chemicals products;
o future expenditures and future allowances relating to environmental
matters; and
o dates by which certain areas will be developed or will come on-stream.
We believe that any forward-looking statements made are reasonable based on
information available to us on the date such statements were made. However, no
assurance can be given as to future results, levels of activity and
achievements. We undertake no obligation to update publicly or revise any
forward-looking statements contained in this report. All subsequent
forward-looking statements, whether written or oral, attributable to us or
persons acting on our behalf are expressly qualified in their entirety by these
cautionary statements.
- ----------------------------
(1) Within the meaning of the United States PRIVATE SECURITIES LITIGATION
REFORM ACT OF 1995, Section 21E of the United States SECURITIES EXCHANGE
ACT OF 1934, as amended, and Section 27A of the United States SECURITIES
ACT OF 1933, as amended.
42
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We are exposed to normal market risks inherent in the oil and gas and chemicals
business, including commodity price risk, foreign-currency rate risk, interest
rate risk and credit risk. We recognize these risks and manage our operations to
minimize our exposures to the extent practical. The information presented on
market risks on pages 68 - 70 in our 2004 Annual Report on Form 10-K has not
changed materially since December 31, 2004.
ITEM 4. CONTROLS AND PROCEDURES
EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES
Our Chief Executive Officer and Chief Financial Officer have evaluated the
effectiveness of our disclosure controls and procedures (as defined in Exchange
Act Rules 13a-15(e) and 15-d-15(e)) as of the end of the period covered by this
report. They concluded that, as of the end of the period covered by this report,
our disclosure controls and procedures were adequate and effective in ensuring
that material information relating to the Company and its consolidated
subsidiaries would be made known to them by others within those entities,
particularly during the period in which this report was being prepared.
Management recognizes that any controls and procedures, no matter how well
designed and operated, can provide only reasonable assurance of achieving the
desired control objectives, and in reaching a reasonable level of assurance,
management necessarily is required to apply its judgment in evaluating the
cost-benefit relationship of possible controls and procedures.
CHANGES IN INTERNAL CONTROLS
We have continually had in place systems relating to internal control over
financial reporting. During the first quarter, we continued to improve and
enhance our financial reporting systems by continuing to implement our existing
Systems, Applications and Products in Data Processing (SAP) systems into our
chemicals operations. The conversion of data and the implementation and
operation of SAP has been continually monitored and reviewed. In addition,
effective April 27th, 2005, Thomas C. O'Neill has been appointed as Chair of
the Audit and Conduct Review Committee. We have evaluated these changes and
confirm that there has not been any change in the Company's internal control
over financial reporting during the first quarter of 2005 that has materially
affected, or is reasonably likely to materially affect, the Company's internal
control over financial reporting. As well, based on these evaluations, there
were no material weaknesses in these internal controls requiring corrective
action. As a result, no such corrective actions were taken.
43
PART II
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) EXHIBITS
31.1 Certification of Chief Executive Officer pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.
31.2 Certification of Chief Financial Officer pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.
32.1 Certification of periodic report by Chief Executive Officer pursuant to
18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.
32.2 Certification of periodic report by Chief Financial Officer pursuant to
18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.
(b) REPORTS ON FORM 8-K
During the quarter ended March 31, 2005, we filed or furnished the following
reports on Form 8-K:
o Current report on Form 8-K/A dated January 12, 2005, to file the pro forma
financial information in connection with the acquisition of EnCana (UK)
Limited.
o Current report on Form 8-K dated February 4, 2005, to file our Certificate
and Amended Articles of Amalgamation.
o Current report on Form 8-K dated February 10, 2005, to furnish our press
release announcing our 2004 annual reserves and annual results.
o Current report on Form 8-K/A Amendment No. 2 dated February 25, 2005 to
file the amended pro forma financial information in connection with the
acquisition of EnCana (UK) Limited.
o Current report on Form 8-K dated March 7, 2005 to file exhibits
incorporated by reference in Form F-9 registration statements.
o Current report on Form 8-K dated March 11, 2005 to furnish our press
release announcing our price offering of US$1.04 billion of 10-year and
30-year senior notes.
Up until the filing of this Form 10-Q, during the quarter beginning April 1,
2005, we filed or furnished the following reports on Form 8-K:
o Current report on Form 8-K dated April 27, 2005, to furnish our press
release announcing our 2005 first quarter results.
44
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the Company has duly caused this report to be signed on its behalf
by the undersigned, thereunto duly authorized, on April 29th, 2005.
NEXEN INC.
/s/ Charles W. Fischer
-------------------------------------
Charles W. Fischer
President and Chief Executive Officer
(Principal Executive Officer)
/s/ Michael J. Harris
-------------------------------------
Michael J. Harris
Controller
(Principal Accounting Officer)
45