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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 June 30, 2004
[_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from.............to..........
COMMISSION FILE NUMBER 1-6702
[GRAPHIC OMITTED - COMPANY LOGO]
NEXEN INC.
Incorporated under the Laws of Canada
98-6000202
(I.R.S. Employer Identification No.)
801 - 7th Avenue S.W.
Calgary, Alberta, Canada T2P 3P7
Telephone (403) 699-4000
Web site - www.nexeninc.com
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months, and (2) has been subject to such filing requirements
for the past 90 days.
Yes [X] No [_]
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Act).
Yes [X] No [_]
On June 30, 2004, there were 128,870,800 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.... 41
Item 4. Controls and Procedures....................................... 41
PART II OTHER INFORMATION
Item 4. Submission of Matters to a Vote of Security Holders........... 42
Item 6. Exhibits and Reports on Form 8-K.............................. 42
This report should be read in conjunction with our 2003 Annual Report on Form
10-K and with our current reports on Form 8-K filed or furnished on February 5,
February 13, February 23 and May 4, 2004.
SPECIAL NOTE TO CANADIAN INVESTORS
Nexen is a US Securities and Exchange Commission (SEC) registrant and a Form
10-K and related forms filer. Therefore, our reserves estimates and securities
regulatory disclosures generally follow SEC requirements. In 2003, certain
Canadian regulatory authorities adopted NATIONAL INSTRUMENT 51-101 - STANDARDS
OF DISCLOSURE FOR OIL AND GAS ACTIVITIES (NI 51-101) which prescribe that
Canadian companies follow certain standards for the preparation and disclosure
of reserves and related information. We have been granted certain exemptions
from NI 51-101. Please refer to the SPECIAL NOTE TO CANADIAN INVESTORS on page
60 of our 2003 Annual Report on Form 10-K.
UNLESS WE INDICATE OTHERWISE, ALL DOLLAR AMOUNTS ($) ARE IN CANADIAN DOLLARS,
AND OIL AND GAS VOLUMES, RESERVES AND RELATED PERFORMANCE MEASURES ARE PRESENTED
ON A WORKING-INTEREST, BEFORE-ROYALTIES BASIS. WHERE APPROPRIATE, INFORMATION ON
A NET, AFTER-ROYALTIES BASIS IS PRESENTED IN TABLES.
Below is a list of terms specific to the oil and gas industry. They are used
throughout the Form 10-Q.
/d = per day mboe = thousand barrels of oil equivalent
bbl = barrel mmboe = million barrels of oil equivalent
mbbls = thousand barrels mcf = thousand cubic feet
mmbbls = million barrels mmcf = million cubic feet
mmbtu = million British thermal units bcf = billion cubic feet
boe = barrels of oil equivalent NGL = natural gas liquid
Oil equivalents (boes) are used to aggregate quantities of natural gas with
crude oil by expressing them in a common unit. To calculate equivalents, we use
1 bbl = 6 mcf of natural gas. Boes may be misleading, particularly if used in
isolation. The conversion ratio is based on an energy equivalency conversion
method primarily applicable at the burner tip and does not represent a value
equivalency at the wellhead.
Electronic copies of our filings with the SEC and the Ontario Securities
Commission (OSC) (from November 8, 2002 onward) are available, free of charge,
on our web site (www.nexeninc.com). Filings prior to November 8, 2002 are
available free of charge, upon request, by contacting our investor relations
department at (403) 699-5931. As soon as reasonably practicable, our filings are
made available on our website once they are electronically filed with the SEC or
the OSC. Alternatively, the SEC and the OSC each maintain a website (www.sec.gov
and www.sedar.com) that contain our reports, proxy and information statements
and other published information that have been filed or furnished with the SEC
and the OSC.
On June 30, 2004, the noon-day exchange rate for Cdn$1.00 was US$0.7460 as
reported by the Bank of Canada.
2
PART I
ITEM 1. UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
TABLE OF CONTENTS
Unaudited Consolidated Statement of Income
for the Three and Six Months Ended June 30, 2004 and 2003...... 4
Unaudited Consolidated Balance Sheet
as at June 30, 2004 and December 31, 2003...................... 5
Unaudited Consolidated Statement of Cash Flows
for the Three and Six Months Ended June 30, 2004 and 2003...... 6
Unaudited Consolidated Statement of Shareholders' Equity
for the Six Months Ended June 30, 2004 and 2003................ 7
Notes to Unaudited Consolidated Financial Statements........... 8
3
NEXEN INC.
UNAUDITED CONSOLIDATED STATEMENT OF INCOME
FOR THE THREE AND SIX MONTHS ENDED JUNE 30
Cdn$ millions, except per share amounts
Three Months Six Months
Ended June 30 Ended June 30
2004 2003 2004 2003
- ---------------------------------------------------------------------------------------------------------------------------
Restated Restated
for Change for Change
in in
Accounting Accounting
Principles Principles
Note 1 Note 1
REVENUES
Net Sales 779 726 1,522 1,532
Marketing and Other (Note 9) 134 145 292 320
-----------------------------------------------------
913 871 1,814 1,852
-----------------------------------------------------
EXPENSES
Operating 196 190 391 386
Transportation and Other 136 118 267 250
General and Administrative (Note 6) 130 45 190 82
Depreciation, Depletion and Amortization (Note 1) 178 193 360 376
Exploration 26 39 54 79
Interest (Note 4) 38 25 80 53
-----------------------------------------------------
704 610 1,342 1,226
-----------------------------------------------------
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES 209 261 472 626
-----------------------------------------------------
PROVISION FOR INCOME TAXES
Current 63 48 116 104
Future 3 (45) 21 20
-----------------------------------------------------
66 3 137 124
-----------------------------------------------------
NET INCOME FROM CONTINUING OPERATIONS 143 258 335 502
Net Income from Discontinued Operations (Note 10) -- 5 -- 12
-----------------------------------------------------
NET INCOME 143 263 335 514
Dividends on Preferred Securities, Net of Income Taxes -- 10 2 21
-----------------------------------------------------
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS 143 253 333 493
=====================================================
EARNINGS PER COMMON SHARE FROM CONTINUING OPERATIONS ($/share)
Basic (Note 7) 1.11 2.01 2.60 3.90
=====================================================
Diluted (Note 7) 1.09 2.00 2.56 3.87
=====================================================
EARNINGS PER COMMON SHARE ($/share)
Basic (Note 7) 1.11 2.05 2.60 4.00
=====================================================
Diluted (Note 7) 1.09 2.04 2.56 3.97
=====================================================
See accompanying notes to the unaudited consolidated financial statements.
4
NEXEN INC.
UNAUDITED CONSOLIDATED BALANCE SHEET
Cdn$ millions, except share amounts
June 30 December 31
2004 2003
- ----------------------------------------------------------------------------------------------------
Restated for
Change in
Accounting
Principles
Note 1
ASSETS
CURRENT ASSETS
Cash and Short-Term Investments 839 1,087
Accounts Receivable (Note 2) 1,590 1,423
Inventories and Supplies (Note 3) 350 270
Other 24 79
----------------------------
Total Current Assets 2,803 2,859
----------------------------
PROPERTY, PLANT AND EQUIPMENT (Note 1)
Net of Accumulated Depreciation, Depletion and
Amortization of $5,366 (December 31, 2003 - $4,907) 4,909 4,550
GOODWILL 36 36
FUTURE INCOME TAX ASSETS 91 108
DEFERRED CHARGES AND OTHER ASSETS 149 153
----------------------------
7,988 7,706
============================
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Current Portion of Long-Term Debt (Note 4) -- 291
Accounts Payable and Accrued Liabilities 1,707 1,404
Accrued Interest Payable 37 44
Dividends Payable 13 12
----------------------------
Total Current Liabilities 1,757 1,751
----------------------------
LONG-TERM DEBT (Note 4) 2,566 2,485
FUTURE INCOME TAX LIABILITIES (Note 1) 707 707
ASSET RETIREMENT OBLIGATIONS (Note 1) 318 305
DEFERRED CREDITS AND LIABILITIES 112 68
SHAREHOLDERS' EQUITY (Note 6)
Preferred and Subordinated Securities 33 364
Common Shares, no par value
Authorized: Unlimited
Outstanding: 2004 - 128,870,800 shares
2003 - 125,606,107 shares 622 513
Contributed Surplus -- 1
Retained Earnings (Note 1) 1,972 1,631
Cumulative Foreign Currency Translation Adjustment (99) (119)
----------------------------
Total Shareholders' Equity 2,528 2,390
----------------------------
COMMITMENTS AND CONTINGENCIES (Note 11)
7,988 7,706
============================
See accompanying notes to the unaudited consolidated financial statements.
5
NEXEN INC.
UNAUDITED CONSOLIDATED STATEMENT OF CASH FLOWS
FOR THE THREE AND SIX MONTHS ENDED JUNE 30
Cdn$ millions
Three Months Six Months
Ended June 30 Ended June 30
2004 2003 2004 2003
- ----------------------------------------------------------------------------------------------------------------------------
Restated for Restated for
Change in Change in
Accounting Accounting
Principles Principles
Note 1 Note 1
OPERATING ACTIVITIES
Net Income from Continuing Operations 143 258 335 502
Net Income from Discontinued Operations -- 5 -- 12
Charges and Credits to Income not Involving Cash (Note 8) 259 150 456 422
Exploration Expense 26 39 54 79
Changes in Non-Cash Working Capital (Note 8) (164) 26 (44) (40)
Other 32 (14) 54 (29)
-----------------------------------------------------
296 464 855 946
FINANCING ACTIVITIES
Proceeds from (Repayment of) Term Credit Facilities, Net -- (24) -- 100
Repayment of Long-Term Debt (Note 4) -- -- (300) --
Proceeds from (Repayment of) Short-Term Borrowings, Net -- (13) -- 1
Redemption of Preferred Securities (Note 6) -- -- (289) --
Dividends on Preferred Securities -- (16) (3) (34)
Dividends on Common Shares (13) (9) (26) (18)
Issue of Common Shares 27 5 109 10
-----------------------------------------------------
14 (57) (509) 59
INVESTING ACTIVITIES
Capital Expenditures
Exploration and Development (323) (309) (655) (634)
Proved Property Acquisitions -- -- -- (164)
Chemicals, Corporate and Other (25) (9) (36) (13)
Proceeds on Disposition of Assets 4 -- 4 --
Changes in Non-Cash Working Capital (Note 8) 54 (28) 62 (31)
Other (14) -- (14) --
-----------------------------------------------------
(304) (346) (639) (842)
EFFECT OF EXCHANGE RATE CHANGES ON CASH
AND SHORT-TERM INVESTMENTS 33 (65) 45 (130)
-----------------------------------------------------
INCREASE (DECREASE) IN CASH AND SHORT-TERM INVESTMENTS 39 (4) (248) 33
CASH AND SHORT-TERM INVESTMENTS - BEGINNING OF PERIOD 800 96 1,087 59
-----------------------------------------------------
CASH AND SHORT-TERM INVESTMENTS - END OF PERIOD 839 92 839 92
======================================================
See accompanying notes to the unaudited consolidated financial statements.
6
NEXEN INC.
UNAUDITED CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY
FOR THE SIX MONTHS ENDED JUNE 30, 2004 AND JUNE 30, 2003
Cdn$ millions
Cumulative
Preferred Foreign
and Currency
Subordinated Common Contributed Retained Translation
Securities Shares Surplus Earnings Adjustment
- ------------------------------------------------------------------------------------------------------------------------------
Restated for
Change in
Accounting
Principles
Note 1
DECEMBER 31, 2003 364 513 1 1,659 (119)
Retroactive Adjustment for Change in
Accounting Principles (Note 1) -- -- -- (28) --
Exercise of Stock Options -- 89 -- -- --
Issue of Common Shares -- 20 -- -- --
Redemption of Preferred Securities (Note 6) (331) -- -- -- --
Gain on Redemption of Preferred Securities,
Net of Income Taxes (Note 6) -- -- -- 34 --
Net Income -- -- -- 335 --
Dividends on Preferred Securities,
Net of Income Taxes -- -- -- (2) --
Dividends on Common Shares -- -- -- (26) --
Modification of Stock Options
to Tandem Options (Note 6) -- -- (1) -- --
Translation Adjustment,
Net of Income Taxes -- -- -- -- 20
---------------------------------------------------------------------------
JUNE 30, 2004 33 622 -- 1,972 (99)
===========================================================================
DECEMBER 31, 2002 724 440 -- 1,069 115
Retroactive Adjustment for Change in
Accounting Principles (Note 1) -- -- -- (28) --
Exercise of Stock Options -- 2 -- -- --
Issue of Common Shares -- 8 -- -- --
Net Income -- -- -- 514 --
Dividends on Preferred Securities,
Net of Income Taxes -- -- -- (21) --
Dividends on Common Shares -- -- -- (18) --
Translation Adjustment,
Net of Income Taxes -- -- -- -- (172)
---------------------------------------------------------------------------
JUNE 30, 2003 724 450 -- 1,516 (57)
===========================================================================
See accompanying notes to the unaudited consolidated financial statements.
7
NEXEN INC.
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
Cdn$ millions except as noted
1. ACCOUNTING POLICIES
The Unaudited Consolidated Financial Statements are prepared in accordance with
Canadian Generally Accepted Accounting Principles (GAAP). The impact of
significant differences between Canadian and US GAAP on the Unaudited
Consolidated Financial Statements is disclosed in Note 14. In the opinion of
management, the Unaudited Consolidated Financial Statements contain all
adjustments of a normal and recurring nature necessary to present fairly Nexen
Inc.'s (Nexen, we or our) financial position at June 30, 2004 and the results of
our operations and our cash flows for the three and six months ended June 30,
2004 and 2003.
Management makes estimates and assumptions that affect the reported amounts of
assets and liabilities and disclosure of contingent assets and liabilities at
the date of the Unaudited Consolidated Financial Statements, and revenues and
expenses during the reporting period. Our management reviews these estimates,
including those related to litigation, asset retirement obligations, income
taxes and determination of proved reserves, on an ongoing basis. Changes in
facts and circumstances may result in revised estimates and actual results may
differ from these estimates. The results of operations and cash flows for the
three months and six months ended June 30, 2004 are not necessarily indicative
of the results of operations or cash flows to be expected for the year ending
December 31, 2004.
These Unaudited Consolidated Financial Statements should be read in conjunction
with our Audited Consolidated Financial Statements included in our 2003 Annual
Report on Form 10-K. Except as described below, the accounting policies we
follow are described in Note 1 of the Audited Consolidated Financial Statements
included in our 2003 Annual Report on Form 10-K.
CHANGE IN ACCOUNTING PRINCIPLES
ASSET RETIREMENT OBLIGATIONS
On January 1, 2004, we retroactively adopted the Canadian Institute of Chartered
Accountants standard S.3110, ASSET RETIREMENT OBLIGATIONS. This new standard
requires recognition of a liability for the future retirement obligations
associated with our property, plant and equipment, which includes oil and gas
wells and facilities, and chemicals plants. The asset retirement obligation is
initially measured at fair value and capitalized to property, plant and
equipment as an asset retirement cost. The asset retirement obligation accretes
until the time the retirement obligation is expected to settle while the asset
retirement cost is amortized over the useful life of the underlying property,
plant and equipment.
The amortization of the asset retirement cost and the accretion of the asset
retirement obligation are included in depreciation, depletion and amortization
(DD&A). Actual retirement costs are recorded against the obligation when
incurred. Any difference between the recorded asset retirement obligation and
the actual retirement costs incurred is recorded as a gain or loss in the period
of settlement.
Our total estimated undiscounted asset retirement obligations amount to $512
million ($514 million - December 31, 2003). We have discounted the total
estimated asset retirement obligations using a weighted-average, credit-adjusted
risk-free rate of 5.6%. Approximately $73 million included in our asset
retirement obligations will be settled over the next five years. The remaining
obligations settle beyond five years and will be funded by future cash flows
from our operations.
We own interests in assets for which the fair value of the asset retirement
obligation cannot be reasonably determined because the assets currently have an
indeterminate life. These assets include our interest in a gas plant and our
interest in Syncrude's upgrader and sulphur inventory. The asset retirement
obligation for these assets will be recorded in the first year in which the
lives of the assets are determinable.
8
We previously provided for dismantlement and site restoration costs on our oil
and gas wells and facilities, and chemicals plants based on estimates
established by current legislation and industry practices. We recorded a
provision for these costs in DD&A based on proved reserves or estimated
remaining asset lives. Upon adoption of the new standard, accounting rules
require us to restate all prior periods presented to give effect to the change
in accounting principles. The impact on net income for the three and six months
ended June 30, 2003 and the impact on our Audited Consolidated Balance Sheet at
December 31, 2003, is shown below:
UNAUDITED CONSOLIDATED STATEMENT OF INCOME FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2003
Three Months Six Months
- -------------------------------------------------------------------------------------------------------------
Depletion, Depreciation and Amortization as Reported 193 376
Less: Dismantlement and Site Restoration (9) (17)
Plus: Asset Retirement Cost Amortization 4 8
Plus: Asset Retirement Obligation Accretion 5 9
--------------------------------
Depletion, Depreciation and Amortization as Restated 193 376
================================
CONSOLIDATED BALANCE SHEET AS AT DECEMBER 31, 2003
As Reported Change As Restated
- -------------------------------------------------------------------------------------------------------------
Property, Plant and Equipment 4,469 81 4,550
Asset Retirement Obligations -- 305 305
Dismantlement and Site Restoration 179 (179) --
Future Income Tax Liabilities 724 (17) 707
Retained Earnings 1,659 (28) 1,631
--------------------------------------------------
RECLASSIFICATION
Certain comparative figures have been reclassified to ensure consistency with
current year presentation.
2. ACCOUNTS RECEIVABLE
June 30 December 31
2004 2003
- ------------------------------------------------------------------------------------------------------------
Trade
Marketing 1,216 1,078
Oil and Gas 286 263
Chemicals and Other 57 47
-------------------------------
1,559 1,388
Non-Trade 47 50
-------------------------------
1,606 1,438
Allowance for Doubtful Accounts (16) (15)
-------------------------------
1,590 1,423
===============================
3. INVENTORIES AND SUPPLIES
June 30 December 31
2004 2003
- ------------------------------------------------------------------------------------------------------------
Finished Products
Marketing 188 138
Oil and Gas 5 16
Chemicals and Other 7 12
-------------------------------
200 166
Work in Process 7 6
Field Supplies 143 98
-------------------------------
350 270
===============================
9
4. LONG-TERM DEBT AND SHORT-TERM BORROWINGS
June 30 December 31
2004 2003
- -------------------------------------------------------------------------------------------------------------
Unsecured Syndicated Term Credit Facilities -- --
Unsecured Redeemable Notes, due 2004 (a) -- 291
Unsecured Redeemable Debentures, due 2006 (1) 100 98
Unsecured Redeemable Medium-Term Notes, due 2007 150 150
Unsecured Redeemable Medium-Term Notes, due 2008 125 125
Unsecured Redeemable Notes, due 2013 (US$500 million) 670 646
Unsecured Redeemable Notes, due 2028 (US$200 million) 268 258
Unsecured Redeemable Notes, due 2032 (US$500 million) 670 646
Unsecured Subordinated Debentures, due 2043 (US$435 million) 583 562
--------------------------------
2,566 2,776
Less: Current Portion of Long-Term Debt -- (291)
--------------------------------
2,566 2,485
================================
Note:
(1) Includes $50 million of principal that was effectively converted through a
currency exchange contract to US$37 million.
(a) UNSECURED REDEEMABLE NOTES, DUE 2004
In February 2004, our US$225 million of notes matured and we repaid the
principal at par.
(b) INTEREST EXPENSE
Three Months Six Months
Ended June 30 Ended June 30
2004 2003 2004 2003
- -------------------------------------------------------------------------------------------------------------
Long-Term Debt 44 34 90 68
Other 3 2 6 4
-----------------------------------------------------
Total 47 36 96 72
Less: Capitalized (9) (11) (16) (19)
-----------------------------------------------------
38 25 80 53
=====================================================
Capitalized interest relates to and is included as part of the cost of oil and
gas properties. The capitalization rates are based on our weighted-average cost
of borrowings.
10
5. DERIVATIVE INSTRUMENTS AND FINANCIAL RISK MANAGEMENT
(a) CARRYING VALUE AND ESTIMATED FAIR VALUE OF DERIVATIVE INSTRUMENTS
The carrying value, fair value, and unrecognized gains or losses on our
outstanding derivatives and long-term financial assets and liabilities are:
Cdn$ millions JUNE 30, 2004 DECEMBER 31, 2003
- ------------------------------------------------------------------------------------------------------------------------------
Carrying Fair Unrecognized Carrying Fair Unrecognized
Net Assets/(Liabilities) Value Value Gain/(Loss) Value Value Gain/(Loss)
------------------------------------ -------------------------------------
Commodity Price Risk -
Non-Trading Activities
Future Sale of Oil and Gas
Production -- -- -- -- (3) (3)
Commodity Price Risk -
Trading Activities
Crude Oil and Natural Gas 70 70 -- 101 101 --
Future Sale of Gas Inventory -- -- -- -- (11) (11)
Foreign Currency Risk 2 2 -- 5 4 (1)
---------- --------- --------------- ---------- --------- ----------------
Total Derivatives 72 72 -- 106 91 (15)
==================================== =====================================
Financial Assets and Liabilities
Long-Term Debt (2,566) (2,722) (156) (2,485) (2,706) (221)
Preferred and Subordinated
Securities (33) (34) (1) (364) (319) 45
------------------------------------ -------------------------------------
(2,599) (2,756) (157) (2,849) (3,025) (176)
==================================== =====================================
The estimated fair value of all derivative instruments is based on quoted market
prices and, if not available, on estimates from third-party brokers or dealers.
The carrying value of cash and short-term investments, amounts receivable and
short-term obligations approximates their fair value because the instruments are
near maturity.
(b) COMMODITY PRICE RISK MANAGEMENT
NON-TRADING ACTIVITIES
FUTURE SALE OF OIL AND GAS PRODUCTION
In March 2003, we sold WTI and NYMEX gas forward contracts for the next 12
months to lock-in part of the return on the remaining 40% interest acquired in
the Aspen field. The forward contracts fixed our oil and gas prices on the
future sales at the contract prices for the hedged volumes, less applicable
price differentials. These contracts expired in March 2004.
TRADING ACTIVITIES
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 $70 million fair value of the contracts has been recognized
in net income.
We have certain NYMEX futures contracts in place which effectively lock-in our
margins on the future sale of our natural gas inventory in storage. To maximize
sales flexibility, we have not designated these futures contracts as accounting
hedges of the future sale of our inventory. We carry our marketing inventory in
storage at the lower of cost and net realizable value, while our derivative
contracts are stated at fair value.
In the second quarter of 2004, the fair value of our storage positions increased
while the fair value of the corresponding futures contracts decreased. Losses on
our undesignated futures contracts have been recognized in net income. The
related increase in fair value of our inventory ($21 million at June 30, 2004)
will not be recognized in net income until the inventory in storage is sold.
11
FUTURE SALE OF GAS INVENTORY
We have certain NYMEX futures contracts in place, which effectively lock-in our
margins on the future sale of our natural gas inventory in storage. We have
designated, in writing, these futures contracts as accounting hedges of the
future sale of our storage inventory. As a result, gains and losses on these
designated futures contracts are recognized in net income when the inventory in
storage is sold. The principal terms of these outstanding contracts and the
unrecognized gains and losses at June 30, 2004 are:
Hedged Average Unrecognized
Volumes Month Price Gain/(Loss)
- ------------------------------------------------------------------------------------------------------------
(mmcf ) (US$/mcf ) (Cdn$ millions)
NYMEX Natural Gas Futures 5,000 February 2005 6.49 (2)
NYMEX Natural Gas Fixed Price Swaps 1,000 December 2004 7.01 --
2,200 January 2005 7.15 1
500 February 2005 6.99 1
------------
--
============
(c) FOREIGN CURRENCY EXCHANGE RATE RISK
Our sales and purchases of crude oil and natural gas are generally transacted in
or referenced to the US dollar, as are most of the financial commodity contracts
used by our marketing group. We enter into forward contracts to sell US dollars.
When combined with certain commodity sales contracts, either physical or
financial, these forward contracts allow us to lock-in our margins on the future
sale of crude oil and natural gas. The fair value of our US dollar forward
contracts at June 30, 2004 was $2 million. This fair value has been recognized
in net income and settles within one year.
(d) TOTAL CARRYING VALUE OF DERIVATIVE ENERGY CONTRACTS
Amounts related to derivative energy contracts held by our marketing operation
that have not been designated as accounting hedges have been recorded at fair
value as we use mark-to-market accounting. The amounts are as follows at:
June 30 December 31
Cdn $millions 2004 2003
- ------------------------------------------------------------------------------------------------------------
Accounts Receivable 135 102
Deferred Charges and Other Assets (1) 54 63
-------------------------------
Total Derivative Energy Contract Assets 189 165
===============================
Accounts Payable and Accrued Liabilities 78 34
Deferred Credits and Liabilities (1) 39 25
-------------------------------
Total Derivative Energy Contract Liabilities 117 59
===============================
Total Derivative Energy Contract Net Assets 72 106
===============================
Note:
(1) These derivative contracts settle beyond 12 months and are considered
non-current.
6. SHAREHOLDERS' EQUITY
(a) PREFERRED SECURITIES
In February 2004, we redeemed our US$217 million preferred securities at par.
The realized foreign exchange gain of $34 million, net of income taxes, for the
difference between the carrying value and the settlement amount was included in
retained earnings.
(b) STOCK BASED COMPENSATION
In May 2004, our shareholders approved our proposal to modify our existing stock
option plan to include a cash feature (tandem option plan). The tandem options
give the holders a right to either purchase common shares at the exercise price
or to receive cash payments equal to the excess of the market value of the
common shares over the exercise price.
Similar to our stock appreciation rights, we use the intrinsic-value method to
recognize compensation expense associated with our tandem options. Obligations
are accrued on a graded vesting basis and represent the difference between the
market value of our common shares and the exercise price of the options. The
obligations are revalued each reporting period based on the change in the market
value of our common shares.
12
Upon modification of the existing stock option plan, we are required to
recognize an obligation for our tandem options. This obligation represents the
difference between the market value of our common shares and the
weighted-average exercise price of the options. As a result, we have recognized
an obligation of $85 million for the graded vested portion of the 6.3 million
outstanding options on June 30, 2004. A one-time, non-cash charge of $82 million
($54 million, net of tax) was included in general and administrative expense,
net of $3 million previously expensed in respect of our original stock options.
The amount previously expensed has been removed from contributed surplus.
(c) DIVIDENDS
Dividends per common share for the three months ended June 30, 2004 were $0.10
(2003 - $0.075). Dividends per common share for the six months ended June 30,
2004 were $0.20 (2003 - $0.15).
7. EARNINGS PER COMMON SHARE
We calculate basic earnings per common share from continuing operations using
net income from continuing operations less dividends on preferred securities,
net of income taxes, divided by the weighted-average number of common shares
outstanding. We calculate basic earnings per common share using net income
attributable to common shareholders and the weighted-average number of common
shares outstanding. We calculate diluted earnings per common share from
continuing operations and diluted earnings per common share in the same manner
as basic, except we use the weighted-average number of diluted common shares
outstanding in the denominator.
Three Months Six Months
Ended June 30 Ended June 30
(millions of shares) 2004 2003 2004 2003
- ------------------------------------------------------------------------------------------------------------------------------
Weighted-average number of common shares outstanding 128.8 123.3 128.2 123.2
Shares issuable pursuant to stock options 6.4 5.1 6.9 5.1
Shares to be purchased from proceeds of stock options (4.4) (4.4) (4.8) (4.4)
-------------------------- --------------------------
Weighted-average number of diluted common shares outstanding 130.8 124.0 130.3 123.9
=====================================================
In calculating the weighted-average number of diluted common shares outstanding
for the three and six months ended June 30, 2004, all options were included
because their exercise price was less than the quarterly average common share
market price in the period. For the three and six months ended June 30, 2003,
4.2 million options were excluded because their exercise price was greater than
the quarterly average common share market price. During the periods presented,
outstanding stock options were the only dilutive instrument.
8. CASH FLOWS
(a) CHARGES AND CREDITS TO INCOME NOT INVOLVING CASH
Three Months Six Months
Ended June 30 Ended June 30
2004 2003 2004 2003
- ------------------------------------------------------------------------------------------------------------------------------
Depreciation, Depletion and Amortization 178 193 360 376
Stock Based Compensation 87 2 89 2
Future Income Taxes 3 (45) 21 20
Non-Cash Items included in Discontinued Operations -- 13 -- 28
Other (9) (13) (14) (4)
-----------------------------------------------------
259 150 456 422
=====================================================
13
(b) CHANGES IN NON-CASH WORKING CAPITAL
Three Months Six Months
Ended June 30 Ended June 30
2004 2003 2004 2003
- ------------------------------------------------------------------------------------------------------------------------------
Operating Activities
Accounts Receivable (266) 583 (151) (88)
Inventories and Supplies (61) (66) (77) 4
Other Current Assets 9 1 55 2
Accounts Payable and Accrued Liabilities 156 (504) 138 44
Accrued Interest Payable (2) 12 (9) (2)
-----------------------------------------------------
(164) 26 (44) (40)
Investing Activities
Accounts Payable and Accrued Liabilities 54 (28) 62 (31)
-----------------------------------------------------
Total (110) (2) 18 (71)
=====================================================
(c) OTHER CASH FLOW INFORMATION
Three Months Six Months
Ended June 30 Ended June 30
2004 2003 2004 2003
- ------------------------------------------------------------------------------------------------------------------------------
Interest Paid 46 22 99 72
Income Taxes Paid 66 53 115 107
-----------------------------------------------------
9. MARKETING AND OTHER
Three Months Six Months
Ended June 30 Ended June 30
2004 2003 2004 2003
- ------------------------------------------------------------------------------------------------------------------------------
Marketing Revenue, Net 112 114 259 295
Interest 3 2 5 4
Foreign Exchange Gains 9 13 15 4
Other (1) 10 16 13 17
-----------------------------------------------------
134 145 292 320
=====================================================
Note:
(1) Other income for the three months ended June 30, 2004 includes $7 million
(2003 - $12 million) of business interruption proceeds from our insurers.
The proceeds result from damage sustained in the Gulf of Mexico during
tropical storm Isidore and hurricane Lili in the third and fourth quarters
of 2002.
14
10. DISCONTINUED OPERATIONS
On August 28, 2003, we sold certain non-core conventional light oil properties
in southeast Saskatchewan in Canada. Net proceeds were $268 million and there
was no gain or loss on the sale. The results of operations from these properties
are detailed below and shown as discontinued operations in our Unaudited
Consolidated Statement of Income.
Three Months Six Months
Ended June 30 Ended June 30
2004 2003 2004 2003
- ------------------------------------------------------------------------------------------------------------------------------
Revenues
Net Sales -- 24 -- 52
Expenses
Operating -- 6 -- 12
Depreciation, Depletion and Amortization -- 9 -- 17
Exploration -- -- -- 1
-----------------------------------------------------
Income before Income Taxes -- 9 -- 22
Future Income Taxes -- 4 -- 10
-----------------------------------------------------
Net Income from Discontinued Operations -- 5 -- 12
=====================================================
Earnings Per Common Share ($/share)
Basic (Note 7) -- 0.04 -- 0.10
=====================================================
Diluted (Note 7) -- 0.04 -- 0.10
=====================================================
11. COMMITMENTS AND CONTINGENCIES
As described in Note 10 to the Audited Consolidated Financial Statements
included in our 2003 Annual Report on Form 10-K, there are a number of lawsuits
and claims pending, the ultimate results of which cannot be ascertained at this
time. We record costs as they are incurred or become determinable. We believe
the resolution of these matters would not have a material adverse effect on our
liquidity, consolidated financial position or results of operations.
12. PENSION AND OTHER POST RETIREMENT BENEFITS
(a) NET PENSION EXPENSE RECOGNIZED UNDER OUR DEFINED BENEFIT PENSION PLANS
Three Months Six Months
Ended June 30 Ended June 30
2004 2003 2004 2003
- ------------------------------------------------------------------------------------------------------------------------------
Nexen
Cost of Benefits Earned by Employees 2 2 4 4
Interest Cost on Benefits Earned 3 3 6 6
Expected Return on Plan Assets (3) (2) (6) (4)
Net Amortization and Deferral -- -- -- --
-----------------------------------------------------
Net 2 3 4 6
-----------------------------------------------------
Syncrude
Cost of Benefits Earned by Employees 1 1 2 2
Interest Cost on Benefits Earned 1 1 2 2
Expected Return on Plan Assets (1) (1) (2) (2)
Net Amortization and Deferral -- -- -- --
-----------------------------------------------------
Net 1 1 2 2
-----------------------------------------------------
Total 3 4 6 8
=====================================================
(b) EMPLOYER FUNDING CONTRIBUTIONS
Our expected total funding contributions for 2004 disclosed in Note 11(e) to the
Audited Consolidated Financial Statements in our 2003 Annual Report on Form 10-K
have not changed for both our Nexen defined benefit pension plan and our share
of Syncrude's defined benefit pension plan.
15
13. OPERATING SEGMENTS AND RELATED INFORMATION
Nexen is involved in activities relating to Oil and Gas, Syncrude and Chemicals
in various geographic locations as described in Note 15 to the Audited
Consolidated Financial Statements included in our 2003 Annual Report on Form
10-K.
THREE MONTHS ENDED JUNE 30, 2004
Corporate
and
(Cdn$ millions) Oil and Gas Syncrude(1) Chemicals Other Total
- ------------------------------------------------------------------------------------------------------------------------------------
United Other
Yemen Canada States Australia Countries(2) Marketing(3)
----------------------------------------------------------
Net Sales 225 157 181 21 21 3 78 93 -- 779
Marketing and Other 1 1 7 -- -- 112 -- 1 12(4) 134
-----------------------------------------------------------------------------------------------------
Total Revenues 226 158 188 21 21 115 78 94 12 913
Less: Expenses
Operating 25 39 22 15 2 4 30 59 -- 196
Transportation and Other 1 4 -- -- -- 116 3 9 3 136
General and Administrative(5) 1 23 18 -- 22 14 -- 11 41 130
Depreciation, Depletion and
Amortization 46 50 55 1 5 3 5 9 4 178
Exploration 1 2 6 -- 17(6) -- -- -- -- 26
Interest -- -- -- -- -- -- -- -- 38 38
-----------------------------------------------------------------------------------------------------
Income (Loss) from
Continuing Operations
before Income Taxes 152 40 87 5 (25) (22) 40 6 (74) 209
============================================================================================
Less: Provision for Income
Taxes(7) 66
Add: Net Income from
Discontinued Operations --
------
Net Income 143
======
Identifiable Assets 674 1,704 1,750 38 211 1,650(8) 802 486 673 7,988
=====================================================================================================
Capital Expenditures
Development and Other 58 96 66 -- 9 2 48 16 7 302
Exploration 3 4 25 -- 14 -- -- -- -- 46
-----------------------------------------------------------------------------------------------------
61 100 91 -- 23 2 48 16 7 348
=====================================================================================================
Property, Plant and Equipment
Cost 2,080 3,149 2,429 209 355 155 915 802 181 10,275
Less: Accumulated DD&A 1,638 1,562 1,039 209 230 59 148 400 81 5,366
-----------------------------------------------------------------------------------------------------
Net Book Value 442 1,587 1,390 -- 125 96 767 402 100 4,909
=====================================================================================================
Notes:
(1) Syncrude is considered a mining operation for US reporting purposes.
Property, plant and equipment at June 30, 2004 includes mineral rights of
$6 million.
(2) Includes results of operations from producing activities in Nigeria and
Colombia.
(3) We are required to carry our gas inventory at the lower of cost or net
realizable value. At June 30, 2004, we have unrecognized gains on this
inventory of $21 million as discussed in Note 5.
(4) Includes interest income of $3 million and foreign exchange gains of $9
million.
(5) Includes a one-time charge of $82 million related to the modification of
our stock option plan as discussed in Note 6.
(6) Includes exploration activities primarily in Nigeria, Colombia and
Equatorial Guinea.
(7) Includes Yemen cash taxes of $57 million.
(8) Approximately 85% of Marketing's identifiable assets are accounts
receivable and inventories.
16
SIX MONTHS ENDED JUNE 30, 2004
Corporate
and
(Cdn$ millions) Oil and Gas Syncrude(1) Chemicals Other Total
- ------------------------------------------------------------------------------------------------------------------------------------
United Other
Yemen Canada States Australia Countries(2) Marketing(3)
----------------------------------------------------------
Net Sales 432 301 362 49 34 6 153 185 -- 1,522
Marketing and Other 2 2 7 -- -- 259 -- 2 20(4) 292
-----------------------------------------------------------------------------------------------------
Total Revenues 434 303 369 49 34 265 153 187 20 1,814
Less: Expenses
Operating 53 79 42 31 3 8 59 116 -- 391
Transportation and Other 2 6 -- -- -- 232 5 19 3 267
General and Administrative(5) 2 35 24 -- 29 25 -- 17 58 190
Depreciation, Depletion and
Amortization 84 99 117 9 9 5 9 19 9 360
Exploration 1 9 15 -- 29(6) -- -- -- -- 54
Interest -- -- -- -- -- -- -- -- 80 80
-----------------------------------------------------------------------------------------------------
Income (Loss) from
Continuing Operations
before Income Taxes 292 75 171 9 (36) (5) 80 16 (130) 472
============================================================================================
Less: Provision for Income
Taxes(7) 137
Add: Net Income from
Discontinued Operations --
-----
Net Income 335
=====
Identifiable Assets 674 1,704 1,750 38 211 1,650(8) 802 486 673 7,988
=====================================================================================================
Capital Expenditures
Development and Other 105 187 159 -- 15 2 98 22 12 600
Exploration 5 12 49 -- 25 -- -- -- -- 91
-----------------------------------------------------------------------------------------------------
110 199 208 -- 40 2 98 22 12 691
=====================================================================================================
Property, Plant and Equipment
Cost 2,080 3,149 2,429 209 355 155 915 802 181 10,275
Less: Accumulated DD&A 1,638 1,562 1,039 209 230 59 148 400 81 5,366
-----------------------------------------------------------------------------------------------------
Net Book Value 442 1,587 1,390 -- 125 96 767 402 100 4,909
=====================================================================================================
Notes:
(1) Syncrude is considered a mining operation for US reporting purposes.
Property, plant and equipment at June 30, 2004 includes mineral rights of
$6 million.
(2) Includes results of operations from producing activities in Nigeria and
Colombia.
(3) We are required to carry our gas inventory at the lower of cost or net
realizable value. At June 30, 2004, we have unrecognized gains on this
inventory of $21 million as discussed in Note 5.
(4) Includes interest income of $5 million and foreign exchange gains of $15
million.
(5) Includes a one-time charge of $82 million related to the modification of
our stock option plan as discussed in Note 6.
(6) Includes exploration activities primarily in Nigeria, Colombia and
Equatorial Guinea.
(7) Includes Yemen cash taxes of $103 million.
(8) Approximately 85% of Marketing's identifiable assets are accounts
receivable and inventories.
17
THREE MONTHS ENDED JUNE 30, 2003 (1)
Corporate
and
(Cdn$ millions) Oil and Gas Syncrude(2) Chemicals Other Total
- ------------------------------------------------------------------------------------------------------------------------------------
United Other
Yemen Canada(3) States Australia Countries(4) Marketing
----------------------------------------------------------
Net Sales 191 151 195 17 19 3 58 92 -- 726
Marketing and Other 3 -- 13 -- -- 114 -- -- 15(5) 145
----------------------------------------------------------------------------------------------------
Total Revenues 194 151 208 17 19 117 58 92 15 871
Less: Expenses
Operating 21 35 25 8 6 5 34 56 -- 190
Transportation and Other 3 -- 2 -- -- 102 2 9 -- 118
General and Administrative 2 7 3 -- 5 10 -- 5 13 45
Depreciation, Depletion and
Amortization 41 55 56 7 10 3 4 13 4 193
Exploration 1 6 18 1 13(6) -- -- -- -- 39
Interest -- -- -- -- -- -- -- -- 25 25
----------------------------------------------------------------------------------------------------
Income (Loss) from
Continuing Operations
before Income Taxes 126 48 104 1 (15) (3) 18 9 (27) 261
===========================================================================================
Less: Provision for Income
Taxes(7) 3
Add: Net Income from
Discontinued Operations 5
------
Net Income 263
======
Identifiable Assets 546 2,177 1,515 29 155 1,004(8) 621 481 230 6,758
====================================================================================================
Capital Expenditures
Development and Other 52 41 72 1 12 -- 48 3 6 235
Exploration 7 9 46 -- 21 -- -- -- -- 83
Proved Property Acquisitions -- -- -- -- -- -- -- -- -- --
----------------------------------------------------------------------------------------------------
59 50 118 1 33 -- 48 3 6 318
====================================================================================================
Property, Plant and Equipment
Cost 1,865 3,319 2,179 210 311 156 719 769 178 9,706
Less: Accumulated DD&A 1,489 1,282 891 196 202 48 141 369 85 4,703
----------------------------------------------------------------------------------------------------
Net Book Value 376 2,037 1,288 14 109 108 578 400 93 5,003
====================================================================================================
Notes:
(1) Restated to give effect to a change in accounting principles (see Note 1).
(2) Syncrude is considered a mining operation for US reporting purposes.
Property, plant and equipment at June 30, 2003 includes mineral rights of
$6 million.
(3) Excludes results of our non-core conventional light oil assets in southeast
Saskatchewan that were sold. These results are shown as discontinued
operations (see Note 10).
(4) Includes results of operations from producing activities in Nigeria and
Colombia.
(5) Includes interest income of $2 million and foreign exchange gains of $13
million.
(6) Includes exploration activities primarily in Nigeria, Colombia and Brazil.
(7) Includes Yemen cash taxes of $48 million.
(8) Approximately 79% of Marketing's identifiable assets are accounts
receivable and inventories.
18
SIX MONTHS ENDED JUNE 30, 2003 (1)
Corporate
and
(Cdn$ millions) Oil and Gas Syncrude(2) Chemicals Other Total
- ------------------------------------------------------------------------------------------------------------------------------------
United Other
Yemen Canada(3) States Australia Countries(4) Marketing
----------------------------------------------------------
Net Sales 419 331 379 45 36 11 121 190 -- 1,532
Marketing and Other 3 1 13 -- -- 295 -- -- 8(5) 320
------------------------------------------------------------------------------------------------------
Total Revenues 422 332 392 45 36 306 121 190 8 1,852
Less: Expenses
Operating 42 69 46 21 10 12 64 122 -- 386
Transportation and Other 3 -- 3 -- -- 221 4 19 -- 250
General and Administrative 3 15 6 -- 10 19 -- 10 19 82
Depreciation, Depletion and
Amortization 83 111 105 13 16 6 7 27 8 376
Exploration 3 23 33 1 19(6) -- -- -- -- 79
Interest -- -- -- -- -- -- -- -- 53 53
------------------------------------------------------------------------------------------------------
Income (Loss) from
Continuing Operations
before Income Taxes 288 114 199 10 (19) 48 46 12 (72) 626
=============================================================================================
Less: Provision for Income
Taxes(7) 124
Add: Net Income from
Discontinued Operations 12
------
Net Income 514
======
Identifiable Assets 546 2,177 1,515 29 155 1,004(8) 621 481 230 6,758
======================================================================================================
Capital Expenditures
Development and Other 106 156 127 1 17 -- 89 4 9 509
Exploration 8 27 71 1 31 -- -- -- -- 138
Proved Property Acquisitions -- -- 164(9) -- -- -- -- -- -- 164
------------------------------------------------------------------------------------------------------
114 183 362 2 48 -- 89 4 9 811
======================================================================================================
Property, Plant and Equipment
Cost 1,865 3,319 2,179 210 311 156 719 769 178 9,706
Less: Accumulated DD&A 1,489 1,282 891 196 202 48 141 369 85 4,703
------------------------------------------------------------------------------------------------------
Net Book Value 376 2,037 1,288 14 109 108 578 400 93 5,003
======================================================================================================
Notes:
(1) Restated to give effect to a change in accounting principles (see Note 1).
(2) Syncrude is considered a mining operation for US reporting purposes.
Property, plant and equipment at June 30, 2003 includes mineral rights of
$6 million.
(3) Excludes results of our non-core conventional light oil assets in southeast
Saskatchewan that were sold. These results are shown as discontinued
operations (see Note 10).
(4) Includes results of operations from producing activities in Nigeria and
Colombia.
(5) Includes interest income of $4 million and foreign exchange gains of $4
million.
(6) Includes exploration activities primarily in Nigeria, Colombia and Brazil.
(7) Includes Yemen cash taxes of $99 million.
(8) Approximately 79% of Marketing's identifiable assets are accounts
receivable and inventories.
(9) On March 27, 2003 we acquired the residual 40% interest in Aspen in the
Gulf of Mexico for US $109 million.
19
14. DIFFERENCES BETWEEN CANADIAN AND US GENERALLY ACCEPTED ACCOUNTING
PRINCIPLES
The Unaudited Consolidated Financial Statements have been prepared in accordance
with Canadian GAAP. The US GAAP Unaudited Consolidated Statement of Income and
Balance Sheet and summaries of differences from Canadian GAAP are as follows:
(a) UNAUDITED CONSOLIDATED STATEMENT OF INCOME - US GAAP FOR THE THREE AND SIX
MONTHS ENDED JUNE 30
Three Months Six Months
Ended June 30 Ended June 30
(Cdn$ millions, except per share amounts) 2004 2003 2004 2003
- ------------------------------------------------------------------------------------------------------------------------------
REVENUES
Net Sales 779 726 1,522 1,532
Marketing and Other (i); (iv) 134 146 299 321
-----------------------------------------------------
913 872 1,821 1,853
-----------------------------------------------------
EXPENSES
Operating (vi) 198 190 395 386
Transportation and Other (i) 136 118 276 250
General and Administrative (xi) 94 45 154 82
Depreciation, Depletion and Amortization (iii) 188 207 381 405
Exploration 26 39 54 79
Interest (i) 38 41 83 87
-----------------------------------------------------
680 640 1,343 1,289
-----------------------------------------------------
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES 233 232 478 564
-----------------------------------------------------
PROVISION FOR INCOME TAXES
Current 63 48 116 104
Deferred (i); (iv); (vi); (x) (12) 25 16 82
-----------------------------------------------------
51 73 132 186
-----------------------------------------------------
NET INCOME FROM CONTINUING OPERATIONS BEFORE CUMULATIVE EFFECT
OF A CHANGE IN ACCOUNTING PRINCIPLES 182 159 346 378
Net Income from Discontinued Operations -- 5 -- 12
Cumulative Effect of a Change in Accounting Principles,
Net of Income Taxes (ix) -- -- -- (37)
-----------------------------------------------------
NET INCOME - US GAAP(1) 182 164 346 353
=====================================================
EARNINGS PER COMMON SHARE ($/share)
Basic (Note 7)
Net Income from Continuing Operations 1.41 1.29 2.70 3.06
Net Income from Discontinued Operations -- 0.04 -- 0.10
Cumulative Effect of a Change in Accounting Principles -- -- -- (0.30)
-----------------------------------------------------
1.41 1.33 2.70 2.86
=====================================================
Diluted (Note 7)
Net Income from Continuing Operations 1.39 1.28 2.66 3.05
Net Income from Discontinued Operations -- 0.04 -- 0.10
Cumulative Effect of a Change in Accounting Principles -- -- -- (0.30)
-----------------------------------------------------
1.39 1.32 2.66 2.85
=====================================================
Note:
(1) RECONCILIATION OF CANADIAN AND US GAAP NET INCOME
Three Months Six Months
Ended June 30 Ended June 30
(Cdn$ millions) 2004 2003 2004 2003
- -------------------------------------------------------------------------------------------------------------------------
Net Income - Canadian GAAP 143 263 335 514
Impact of US Principles, Net of Income Taxes:
Depreciation, Depletion and Amortization (iii) (10) (14) (21) (28)
Dividends on Preferred Securities (i) -- (10) (2) (21)
Future Income Taxes (x) 15 (76) -- (76)
Issue Costs on Preferred Securities Redeemed (i) -- -- (6) --
Cumulative Effect of Change in Accounting Principles (ix) -- -- -- (37)
Fair Value of Preferred Securities (i) -- -- 4 --
Stock based compensation included in retained earnings (xi) 36 -- 36 --
Other (iv); (vi) (2) 1 -- 1
------------------------------------------------
Net Income - US GAAP 182 164 346 353
================================================
20
(b) UNAUDITED CONSOLIDATED BALANCE SHEET - US GAAP
June 30 December 31
(Cdn$ millions, except share amounts) 2004 2003
- ------------------------------------------------------------------------------------------------------------------------------
ASSETS
CURRENT ASSETS
Cash and Short-Term Investments 839 1,087
Accounts Receivable 1,590 1,423
Inventories and Supplies 350 270
Other 24 79
----------------------------------
Total Current Assets 2,803 2,859
----------------------------------
PROPERTY, PLANT AND EQUIPMENT
Net of Accumulated Depreciation, Depletion and
Amortization of $5,774 (December 31, 2003 - $5,330) (iii); (vi); (ix) 4,930 4,583
GOODWILL 36 36
DEFERRED INCOME TAX ASSETS 91 108
DEFERRED CHARGES AND OTHER ASSETS (i); (vii) 104 117
----------------------------------
7,964 7,703
==================================
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Current Portion of Long-Term Debt -- 575
Accounts Payable and Accrued Liabilities (iv) 1,707 1,418
Accrued Interest Payable 37 44
Dividends Payable 13 12
----------------------------------
Total Current Liabilities 1,757 2,049
----------------------------------
LONG-TERM DEBT (i); (ii); (vii) 2,555 2,472
DEFERRED INCOME TAX LIABILITIES (i) - (x) 677 676
ASSET RETIREMENT OBLIGATIONS 318 305
DEFERRED CREDITS AND LIABILITIES (viii) 114 70
SHAREHOLDERS' EQUITY
Common Shares, no par value
Authorized: Unlimited
Outstanding: 2004 - 128,870,800 shares
2003 - 125,606,107 shares 622 513
Contributed Surplus -- 1
Retained Earnings (i); (iii); (iv); (vi); (ix); (xi) 1,944 1,660
Accumulated Other Comprehensive Income (i); (ii); (iv); (v); (viii) (23) (43)
----------------------------------
Total Shareholders' Equity 2,543 2,131
----------------------------------
COMMITMENTS AND CONTINGENCIES
7,964 7,703
==================================
(c) UNAUDITED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME - US GAAP FOR THE
THREE AND SIX MONTHS ENDED JUNE 30
Three Months Six Months
Ended June 30 Ended June 30
(Cdn$ millions) 2004 2003 2004 2003
- ------------------------------------------------------------------------------------------------------------------------------
Net Income - US GAAP 182 164 346 353
Other Comprehensive Income, Net of Income Taxes:
Translation Adjustment (i); (ii); (v) 11 (62) 14 (87)
Unrealized Mark-to-Market Gain/(Loss) (iv) -- (4) 6 (1)
-----------------------------------------------------
Comprehensive Income 193 98 366 265
=====================================================
21
(d) UNAUDITED CONSOLIDATED STATEMENT OF CASH FLOWS
Under US principles, dividends on preferred securities of $nil and $3 million
for the three and six months ended June 30, 2004, respectively (June 30, 2003 -
$16 million and $34 million) that are included in financing activities would be
reported in operating activities.
Under US principles, geological and geophysical costs of $7 million and $25
million for the three and six months ended June 30, 2004, respectively (June 30,
2003 - $11 million and $24 million) that are included in investing activities
would be reported in operating activities.
NOTES:
i. Under US principles, we are required to classify our preferred securities
as long-term debt rather than shareholders' equity. As a result:
o dividends of $3 million in the first quarter were included in interest
expense, with the related income tax of $1 million included in the
provision for income taxes;
o pre-tax issue costs of $10 million were included in deferred charges
and other assets, rather than as an after-tax charge to retained
earnings; and
o for the three and six months ended June 30, 2004, foreign-currency
translation losses of $nil and $8 million respectively were included
in accumulated other comprehensive income (AOCI).
Under US principles, we are also required to recognize in earnings the
change in fair value of the preferred securities. As a result, a gain of
$4 million for the change in fair value up to the redemption date was
included in marketing and other in the first quarter.
In February 2004, we redeemed at par US$217 million of preferred
securities. Under Canadian principles, a foreign exchange gain of $34
million, net of income tax, was recognized in retained earnings. Under US
principles, this foreign exchange gain had been included in AOCI.
Unamortized issue costs of $10 million ($6 million, net of income taxes)
were included in transportation and other in the first quarter.
ii. Under US principles, all of our subordinated securities are classified as
long-term debt. As a result, the $33 million equity component has been
included in long-term debt.
iii. Under US principles, the liability method of accounting for income taxes
was adopted in 1993. In Canada, the liability method was adopted in 2000.
In 1997, we acquired certain oil and gas assets and the amount paid for
these assets differed from the tax basis acquired. Under US principles,
this difference was recorded as a deferred tax liability with an increase
to property, plant and equipment rather than a charge to retained
earnings. As a result:
o additional depreciation, depletion and amortization of $10 million and
$21 million was included in net income for the three and six months
ended June 30, 2004, respectively; and
o property, plant and equipment is higher under US GAAP by $50 million.
iv. Under US principles, all derivative instruments are recognized on the
balance sheet as either an asset or a liability measured at fair value.
Changes in the fair value of derivatives are recognized in earnings unless
specific hedge criteria are met.
CASH FLOW HEDGES
Changes in the fair value of derivatives that are designated as cash flow
hedges are recognized in earnings in the same period as the hedged item.
Any fair value change in a derivative before that period is recognized on
the balance sheet. The effective portion of that change is recognized in
other comprehensive income with any ineffectiveness recognized in net
income.
FUTURE SALE OF OIL AND GAS PRODUCTION: Included in accounts payable at
December 31, 2003, was a $3 million loss on the forward contracts we used
to hedge the commodity price risk on the future sale of a portion of our
production from the Aspen field as described in Note 5. These contracts
expired in March 2004. The losses ($2 million, net of income taxes),
deferred in AOCI at December 31, 2003, were recognized in net sales.
22
FUTURE SALE OF GAS INVENTORY: Included in accounts payable at December 31,
2003, was $11 million of losses on the futures and basis swap contracts we
used to hedge the commodity price risk on the future sale of our gas
inventory as described in Note 5. These contracts effectively lock-in
profits on our stored gas volumes. Losses of $8 million ($5 million, net
of income taxes) related to the effective portion and deferred in AOCI at
December 31, 2003, were recognized in marketing and other. Additionally,
losses of $3 million ($2 million, net of income taxes), related to the
ineffective portion, were recognized in marketing and other under Canadian
GAAP. Under US GAAP, the ineffective portion was recognized in net income
in 2003.
At June 30, 2004, net gains of $nil million were included in accounts
payable. The effective portion of the net gains have been deferred in AOCI
until the underlying gas inventory is sold. All the deferred losses will
be reclassified to marketing and other in the next 12 months. At June 30,
2004, the ineffective portion was $nil.
FAIR VALUE HEDGES
Both the derivative instrument and the underlying commitment are
recognized on the balance sheet at their fair value. The change in fair
value of both are reflected in earnings. At June 30, 2004, we had no fair
value hedges in place.
v. Under US principles, exchange gains and losses arising from the
translation of our net investment in self-sustaining foreign operations
are included in comprehensive income. Additionally, exchange gains and
losses, net of income taxes, from the translation of our US-dollar
long-term debt designated as a hedge of our foreign net investment are
included in comprehensive income. Cumulative amounts are included in AOCI
in the Unaudited Consolidated Balance Sheet.
vi. Under Canadian principles, we defer certain development costs and all
pre-operating revenues and costs to property, plant and equipment. Under
US principles, these costs have been included in operating expenses. As a
result:
o operating expenses include pre-operating costs of $2 million and $4
million ($3 million, net of income taxes) for the three and six months
ended June 30, 2004, respectively; and
o property, plant and equipment is lower under US GAAP by $10 million.
vii. Under US principles, discounts on long-term debt are classified as a
reduction of long-term debt rather than as deferred charges and other
assets. Discounts of $45 million have been included in long-term debt.
viii. Under US principles, the amount by which our accrued pension cost is less
than the unfunded accumulated benefit obligation is included in AOCI and
accrued pension liabilities. This amount was $2 million at June 30, 2004
(December 31, 2003 - $2 million).
ix. On January 1, 2003 we adopted FASB Statement No. 143, ACCOUNTING FOR ASSET
RETIREMENT OBLIGATIONS (FAS 143) for US GAAP reporting purposes. We
adopted the equivalent Canadian standard for asset retirement obligations
on January 1, 2004 as described in Note 1. These standards are consistent
except for the adoption date.
This change in accounting policy has been reported as a cumulative effect
adjustment in the Unaudited Consolidated Statement of Income as a loss of
$37 million, net of income taxes of $25 million on January 1, 2003.
x. Under US principles, enacted tax rates are used to calculate 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. In the second quarter, the income tax rates were enacted
and the $15 million future income tax recovery was recorded in the US GAAP
net income.
In the second quarter of 2003, substantively enacted changes in Canadian
federal and provincial income tax rates created a $76 million future
income tax recovery under Canadian GAAP.
xi. As described in Note 6 (b), our existing stock option plan was modified to
a tandem option plan. An obligation of $85 million has been recognized for
these tandem options. This resulted in a one-time, non-cash charge to net
income of $54 million, net of tax. Under US principles, the modification
to our stock option plan is accounted for by providing us with credit for
the pro-forma expense previously disclosed with respect to the stock
options modified. The related pro-forma expense is $36 million, which is
accounted for as an adjustment to retained earnings with a corresponding
decrease to our one-time charge to net income.
23
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
THE FOLLOWING SHOULD BE READ IN CONJUNCTION WITH THE UNAUDITED CONSOLIDATED
FINANCIAL STATEMENTS INCLUDED IN THIS REPORT. THE UNAUDITED CONSOLIDATED
FINANCIAL STATEMENTS HAVE BEEN PREPARED IN ACCORDANCE WITH GENERALLY ACCEPTED
ACCOUNTING PRINCIPLES (GAAP) IN CANADA. THE IMPACT OF THE SIGNIFICANT
DIFFERENCES BETWEEN CANADIAN AND UNITED STATES (US) ACCOUNTING PRINCIPLES ON THE
FINANCIAL STATEMENTS IS DISCLOSED IN NOTE 14 TO THE UNAUDITED CONSOLIDATED
FINANCIAL STATEMENTS.
UNLESS OTHERWISE NOTED, TABULAR AMOUNTS ARE IN MILLIONS OF CANADIAN DOLLARS. THE
DISCUSSION AND ANALYSIS OF OUR OIL AND GAS ACTIVITIES WITH RESPECT TO OIL AND
GAS VOLUMES, RESERVES AND RELATED PERFORMANCE MEASURES IS PRESENTED ON A
WORKING-INTEREST, BEFORE-ROYALTIES BASIS. WE MEASURE OUR PERFORMANCE IN THIS
MANNER CONSISTENT WITH OTHER CANADIAN OIL AND GAS COMPANIES. WHERE APPROPRIATE,
WE HAVE PROVIDED INFORMATION ON A NET, AFTER-ROYALTIES BASIS IN TABULAR FORMAT.
NOTE: CANADIAN INVESTORS SHOULD READ THE SPECIAL NOTE TO CANADIAN INVESTORS ON
PAGE 60 IN OUR 2003 ANNUAL REPORT ON FORM 10-K WHICH HIGHLIGHTS DIFFERENCES
BETWEEN OUR RESERVE ESTIMATES AND RELATED DISCLOSURES THAT ARE OTHERWISE
REQUIRED BY CANADIAN REGULATORY AUTHORITIES.
EXECUTIVE SUMMARY OF SECOND QUARTER RESULTS
Three Months Six Months
Ended June 30 Ended June 30
(Cdn$ millions) 2004 2003 2004 2003
- --------------------------------------------------------------------------------
Net Income 143 263 335 514
Earnings per Common Share ($/share) 1.11 2.05 2.60 4.00
Cash Flow from Operations (1) 428 452 845 1,015
Production, before Royalties (mboe/d) 240 280 249 272
Production, after Royalties (mboe/d) 167 195 172 186
Capital Expenditures 348 318 691 811
We delivered strong quarterly net income and cash flow driven by high commodity
prices. This was offset by lower production, a stronger Canadian dollar and a
one-time charge for stock-based compensation. In the second quarter, we
recognized a non-cash expense of $54 million (after tax) as our shareholders
approved the conversion of our stock option plan to a tandem option plan.
Record production in the second quarter of last year was unmatched as we sold
assets in the third quarter of 2003 and experienced declines on some of our
mature assets. In addition, delays in development drilling in the Gulf of Mexico
and an unscheduled shutdown at Buffalo, offshore Australia, caused temporary
shortfalls. With the tie-in of the third Aspen development well, current
corporate production is over 250,000 boe/d and will continue to grow in the
second half of the year. Production increases are expected to come with the
tie-in of additional wells at Gunnison and more development drilling on the
shelf in the Gulf of Mexico. Buffalo will also contribute when it is brought
back on-stream in late July. We expect final production from Nigeria and
Australia late in the year.
While the Canadian dollar has declined in value relative to the US dollar since
year end, it still remains strong compared to the second quarter of 2003. With a
stronger Canadian dollar, our foreign revenues and realized commodity prices,
referenced in US dollars, were lower when translated to Canadian dollars.
Despite the decrease in our sales revenue, we benefit to the extent our foreign
operating costs and capital expenditures are also reduced when translated.
Compared to the second quarter of 2003, the stronger Canadian dollar reduced our
quarterly net income by approximately $25 million and our quarterly cash flow
from operating activities by $35 million. In addition, most of our fixed-rate
debt is denominated in US dollars so this debt is reduced with a strengthening
Canadian dollar.
Note:
1 We evaluate our performance and that of our business segments based on
earnings and cash flow from operations. Cash flow from operations is a
non-GAAP term that represents cash generated from operating activities before
changes in non-cash working capital and other. We consider it a key measure
as it demonstrates our ability and the ability of our business segments to
generate the cash flow necessary to fund future growth through capital
investment and to repay debt. Cash flow from operations may not be comparable
with the calculation of similar measures for other companies.
Three Months Six Months
Ended June 30 Ended June 30
(Cdn$ millions) 2004 2003 2004 2003
-----------------------------------------------------------------------------
Cash Flow from Operating Activities 296 464 855 946
Changes in Non-Cash Working Capital 164 (26) 44 40
Other (32) 14 (54) 29
----------------------------------
Cash Flow from Operations 428 452 845 1,015
==================================
24
Our core operations in Canada, the shallow-water Gulf of Mexico, and the Masila
Block in Yemen continue to generate significant free cash flow. This allows us
to pursue our strategic focus in the deep-water Gulf of Mexico, offshore West
Africa, the Athabasca oil sands and the Middle East, and to continue to
strengthen our balance sheet.
CAPITAL INVESTMENT
Three Months Six Months
Ended June 30 Ended June 30
(Cdn$ millions) 2004 2003 2004 2003
- -----------------------------------------------------------------------------------------
Development 277 226 564 496
Exploration 46 83 91 138
Acquisition of Remaining Interest in the Aspen Field -- -- -- 164
Chemicals, Corporate and Other 25 9 36 13
-------------------------------
348 318 691 811
===============================
In the second quarter of 2004, we continued to advance our strategy with
investment in our major development projects. These development projects at Long
Lake and Syncrude in the Athabasca region, on Block 51 in Yemen and OPL-222 in
Nigeria make up almost 40% of our total capital investment in the second
quarter. While these projects have yet to contribute to our production and cash
flow, the capital invested is not at risk. Over their lives, these projects are
expected to generate attractive margins and low full-cycle finding and
development costs. Total capital invested in these new growth development
projects to date is over $800 million.
In addition to developing these projects, we also targeted new opportunities
through on-going exploration and research into new technologies. Details of our
capital programs are set out below.
Three Months Six Months
Ended June 30 Ended June 30
(Cdn$ millions) 2004 2003 2004 2003
- ----------------------------------------------------------------------------------------
Yemen 61 59 110 114
Canada 32 30 89 127
Long Lake Synthetic Crude 68 20 110 56
Gulf of Mexico 91 118 208 362
Other Countries 23 34 40 50
Syncrude 48 48 98 89
Chemicals, Corporate and Other 25 9 36 13
------------------------------
348 318 691 811
==============================
MIDDLE EAST
BLOCK 51
Development of our BAK-A field on East Al Hajr (Block 51) in Yemen is on
schedule to commence early production in late 2004. To date, 16 of the 17
planned development wells have been drilled. The final one will be drilled in
the third quarter. Contracts are currently being awarded for construction of the
central processing facility, gathering system, and pipeline tieback to our
Masila export system. Pipeline construction began in June. Full production from
BAK-A is expected to commence during the second quarter of 2005 at 25,000
bbls/d. We have an 87.5% interest in East Al Hajr.
One exploration well was drilled on Block 51 during the quarter. The well will
be tested at a future date. We plan to drill five additional independent
prospects this year with the next exploration well to start drilling early in
the third quarter.
ATHABASCA OIL SANDS
SYNTHETIC OIL AT LONG LAKE
Our Long Lake Synthetic Crude Oil project remains on schedule and on budget. We
have focused on purchasing major equipment, materials and services; developing
detailed schedules; site clearing and civil engineering work; and completing
detailed engineering work.
To date, over 80% of the major equipment for the steam-assisted-gravity-drainage
(SAGD) production facilities and over 45% of the equipment for the upgrader have
been purchased. Site clearing has been completed and rough grading is underway.
Drilling of 65 SAGD well pairs for the project will start in the third quarter
of 2004. Fabrication of the more than 700 equipment modules required by the
project begins in the fourth quarter, with on-site mechanical work commencing in
the first quarter of 2005.
25
The Long Lake project will develop and upgrade bitumen into a high-quality,
light, sweet, premium synthetic crude oil. SAGD bitumen production is expected
to commence in 2006, with 60,000 bbls/d of upgraded premium synthetic crude oil
production (30,000 net to us) beginning in 2007. This project is the first phase
in the development of our bitumen assets at Long Lake.
SYNCRUDE
Construction progress continues at Syncrude. The upgrader expansion (UE-1) is
48% complete with targeted completion by the end of 2005. The UE-1 program is
part of the Stage 3 expansion that will add 110,000 barrels per day (8,000 net
to us) of production. The Stage 3 expansion is expected to start-up in early
2006 at an estimated cost of $7.8 billion ($564 million net to us).
GULF OF MEXICO
ASPEN
The third development well at Aspen was completed and tied-in to existing
infrastructure at the Bullwinkle platform during the quarter. Production began
in early July bringing our total current field production up to 30,000 boe per
day. As we continue to ramp-up production, the overall field rate will increase
to approximately 36,000 equivalent barrels. We also purchased new 3D seismic
data over the field to help provide better imaging of the field pays and to
further evaluate opportunities in deeper sands.
GUNNISON
The sixth and seventh Gunnison development wells were completed during the
quarter. The sixth well was brought on-stream in May as expected. On the
seventh, we experienced complications as we encountered tar when the well was
perforated. We are evaluating alternatives for remediation and expect to
recomplete the well in the third quarter. The final three development wells will
be tied-in during the second half of the year.
OTHER
Exploration activity during the second quarter was minimal as we focused our
efforts on development activities at Aspen and Gunnison. We expect to drill a
number of high-potential exploration wells in the Gulf of Mexico in the second
half of the year. These include prospects at Crested Butte, three miles
northwest of our Aspen field; Anduin in the Mississippi Canyon; and a deep-shelf
test at Main Pass 240. We are finalizing our technical evaluation of a number of
additional deep-shelf gas prospects and expect to begin drilling four or more of
these before year end.
An exploration well on the Tobago prospect, on Alaminos Canyon Block 859 and the
east half of Block 858, encountered commercial quantities of hydrocarbons but
was temporarily plugged and abandoned. We expect Tobago to be part of a future
Alaminos Canyon regional development.
WEST AFRICA
Offshore Nigeria, the Usan West-1 exploration well located on OPL-222 commenced
drilling on May 17th. This well is four miles west of the main Usan field and is
testing a separate structure. Results are expected during the third quarter. We
anticipate two additional wells will be drilled on the block this year. We are
working with our partners to finalize a field development plan for Usan by year
end.
On OML-115, we will spud our Ameena prospect in mid-August, and if successful,
we will move the rig and drill an appraisal well. Ameena is in 125 feet of
water, approximately 40 miles offshore Nigeria.
On Block K, offshore Equatorial Guinea, we plan to drill two exploration
prospects which are on trend with recent commercial discoveries directly to the
north-east. The first well is expected to spud in September.
OTHER
CHEMICALS
Our Brandon expansion is well underway with an expected start-up in the fourth
quarter. We are expanding this facility by 33% to 260,000 tonnes to replace
higher cost capacity idled in 2002 at our Taft, Louisiana plant.
26
FINANCIAL RESULTS
CHANGE IN NET INCOME
2004 VS 2003
Three Months Six Months
(Cdn$ millions) Ended June 30 Ended June 30
- ------------------------------------------------------------------------------------------------------------
NET INCOME AT JUNE 30, 2003 (1) 263 514
===================================
Favourable (unfavourable) variances:
Cash Items:
Production volumes, after royalties:
Crude oil (77) (82)
Natural gas (21) (1)
Crude oil sales volumes, after royalties 8 10
Realized commodity prices:
Crude oil 116 60
Natural gas 2 (39)
Oil and gas operating expense:
Conventional (2) (8)
Syncrude 4 5
Marketing (15) (48)
Chemicals (1) 3
General and administrative -- (21)
Interest expense (13) (27)
Current income taxes (15) (12)
Other (10) (8)
-----------------------------------
Total Cash Variance (24) (168)
Non-Cash Items:
Depreciation, depletion and amortization
Oil and Gas 20 25
Other 4 8
Exploration expense 13 26
General and administrative - stock based compensation (85) (87)
Future income taxes (44) 9
Other (4) 8
-----------------------------------
Total Non-Cash Variance (96) (11)
-----------------------------------
NET INCOME AT JUNE 30, 2004 143 335
===================================
Note:
(1) Includes results of discontinued operations (see Note 10 to our Unaudited
Consolidated Financial Statements).
Significant variances in net income are explained further in the following
sections.
27
OIL AND GAS
PRODUCTION (BEFORE ROYALTIES)
Three Months Six Months
Ended June 30 Ended June 30
2004 2003 2004 2003
- -----------------------------------------------------------------------------------------------------------------------------
Oil and Liquids (mbbls/d)
Yemen 106.1 118.7 110.1 117.4
Canada (1) 37.1 50.6 36.9 49.9
Gulf of Mexico 25.8 31.4 26.3 26.6
Australia 2.4 5.8 3.4 6.9
Other Countries 5.2 6.0 5.0 6.1
Syncrude 16.6 15.2 17.4 14.4
-----------------------------------------------------
193.2 227.7 199.1 221.3
-----------------------------------------------------
Natural Gas (mmcf/d)
Canada 145 159 147 160
Gulf of Mexico 134 157 150 146
-----------------------------------------------------
279 316 297 306
-----------------------------------------------------
Total (mboe/d) 240 280 249 272
=====================================================
PRODUCTION (AFTER ROYALTIES)
Three Months Six Months
Ended June 30 Ended June 30
2004 2003 2004 2003
- ------------------------------------------------------------------------------------------------------------------------------
Oil and Liquids (mbbls/d)
Yemen 54.1 59.3 54.1 57.4
Canada (1) 28.8 39.1 28.7 38.2
Gulf of Mexico 22.7 28.0 23.1 23.5
Australia 2.3 5.7 3.3 6.1
Other Countries 4.7 4.7 4.5 5.0
Syncrude 16.4 15.1 17.3 14.3
-----------------------------------------------------
129.0 151.9 131.0 144.5
-----------------------------------------------------
Natural Gas (mmcf/d)
Canada 117 124 118 124
Gulf of Mexico 114 132 128 123
-----------------------------------------------------
231 256 246 247
-----------------------------------------------------
Total (mboe/d) 167 195 172 186
=====================================================
Note:
(1) 2003 includes the following oil production from discontinued operations
(See Note 10 to our Unaudited Consolidated Financial Statements):
Three Six
Months Ended Months Ended
(mboe/d) June 30, 2003 June 30, 2003
- ----------------------------------------------------------------------------------------------------
Before Royalties 9.2 9.5
After Royalties 6.7 6.8
-------------------------------
28
LOWER PRODUCTION DECREASED NET INCOME FOR THE QUARTER BY $98 MILLION
Production after royalties fell 14% from the second quarter of 2003 and 5% from
the first quarter of 2004. Our 2003 production included volumes from our
non-core Canadian light oil properties in southeast Saskatchewan that were sold
in August 2003. Excluding these volumes, our production after royalties
decreased 11%. The following table summarizes our production volume changes:
Before After
(mboe/d) Royalties Royalties
- ------------------------------------------------------------------------------------------------------------------------------
Production, second quarter 2003 280 195
Sale of non-core Canadian properties (9) (7)
--------------------------
271 188
Base production changes:
Masila Block in Yemen (13) (7)
Canada (7) (5)
Gunnison in the Gulf of Mexico 9 8
Shelf in the Gulf of Mexico (4) (3)
--------------------------
256 181
Delayed development drilling - Aspen and the Shelf in the Gulf of Mexico (14) (12)
Unscheduled downtime at Buffalo in Australia (2) (2)
--------------------------
Production, second quarter 2004 240 167
==========================
While we were unable to match our record production levels of the second quarter
in 2003, we have been positioning ourselves through activities in the Gulf of
Mexico to increase production in the second half of the year. These production
increases have already begun. Current production is over 250,000 equivalent
daily barrels company-wide and we expect further growth in the second half of
the year. Future production increases will come from Block 51 in 2005, Syncrude
in 2006 and Long Lake in 2007.
MASILA BLOCK IN YEMEN
Second quarter production decreased 11% compared to 2003 given the maturity of
the field and lower overall productivity from new wells drilled this year. As
the field matures, we continue to drill more development wells and perform more
field maintenance to combat the natural base declines. An additional service rig
will be added to meet the demands of ongoing field maintenance.
CANADA
Our conventional assets in the Western Canadian Sedimentary Basin continue to
mature. The August 2003 sale of non-core, light-oil properties in southeast
Saskatchewan accounted for over 50% of the decrease from the second quarter of
2003. The remaining decrease reflects natural production rate declines as we
continue to limit our investment in these mature assets. Through successful
asset management, our second quarter production was similar to the first quarter
of 2004 at 61,000 boe/d.
We expect our conventional production to remain relatively flat for the
remainder of the year as we invest selectively to develop new production,
continue to manage the fields and pursue optimization opportunities. However, we
expect increases as our Long Lake project starts up with bitumen production in
2006 and synthetic crude in 2007.
GULF OF MEXICO
Quarterly production from the Gulf of Mexico was 13% lower than the first
quarter and 17% lower than 2003 as we continued to manage declines on our
conventional Shelf assets and, more recently, higher water cuts at Aspen.
Production rates from Aspen decreased to approximately 17,500 boes per day due
to higher water production from Aspen-1 and downtime for the drilling,
completion and tie-in of the third development well. We stabilized the water cut
at Aspen-1 and we plan to remediate this well later this summer to further
reduce water production.
In early July, we completed and tied-in the third development well at Aspen.
With the third well on-stream, current production from Aspen has increased to
around 30,000 boe/d. To complete the tie-in, we shut-in Aspen-1 and 2 for five
days and moved production from both wells to a smaller flow line. Both wells
will continue to flow at restricted rates until the third well is fully
on-stream. As we continue to ramp-up production from the third development well,
we expect overall field production will increase to approximately 36,000 boe/d,
with further increases expected from the Aspen-1 work over.
29
We now have five producing wells at Gunnison, which delivered 8,600 boe/d of
production during the quarter. We have experienced some temporary setbacks with
one of our early wells sanding-off, after producing 75% of its expected
reserves, and our seventh completion encountering tar on perforation. We expect
to recomplete the sanded-off well and repair the seventh well in the third
quarter. We plan to complete three additional wells during the third and fourth
quarters increasing production rates to around 13,000 boe/d by year end.
Natural gas production from our shelf properties declined as development
drilling was delayed. Our shelf drilling program commenced late in the second
quarter. Development activities at Vermilion 302 and West Cameron 170 added
about 3,000 boe/d to production early in the third quarter. On-going development
activities at Vermilion 302 and West Cameron 170, as well as drilling at
Vermilion 76 are expected to contribute further increases.
With the addition of the third Aspen development well, development drilling on
the shelf, the tie-in of additional Gunnison wells and workover on Aspen-1, Gulf
of Mexico production rates are expected to reach approximately 75,000 boe/d by
year end.
OTHER COUNTRIES
Australia experienced an unscheduled shutdown in late May, which reduced
quarterly production from first quarter levels by 47%. Production is expected to
resume in late July. We expect final production from Australia and Nigeria later
in the year.
Production from Colombia continued to increase as a result of our successful
2003 development program. Second quarter production of 4,700 bbls/d showed an
increase of 15% compared to the first quarter.
SYNCRUDE
Syncrude year to date production is 21% higher than 2003. Syncrude achieved a
new monthly production record in May, producing 8.4 million barrels with our
share averaging 19,700 bbls/d. Maintenance and turnaround activities completed
in 2003 have delivered greater operational reliability. Production was down
slightly from the first quarter of 2004 as we completed planned minor
turnarounds in April and June. We anticipate modest downtime for the remainder
of the year, which will allow us to maintain production rates between 18,000 -
20,000 bbls/d (net to us).
30
COMMODITY PRICES
Three Months Six Months
Ended June 30 Ended June 30
2004 2003 2004 2003
- -----------------------------------------------------------------------------------------------------------------
CRUDE OIL AND NGLS
West Texas Intermediate (WTI) (US$/bbl) 38.32 28.91 36.73 31.39
----------------------------------------------------
Differentials (1) (US$/bbl):
Masila 4.05 3.64 3.93 3.62
Heavy Oil 11.62 7.13 10.74 7.68
Mars 4.89 3.35 4.77 3.86
Realized Prices (Cdn$/bbl):
Yemen 45.88 35.86 43.80 40.72
Canada 36.18 30.95 34.36 35.08
United States 46.30 36.28 42.60 40.23
Syncrude 52.46 42.26 48.83 46.76
Australia 49.84 36.53 45.44 43.52
Other Countries 44.75 34.74 41.54 40.72
Corporate Average (Cdn$/bbl) 44.75 35.24 42.37 39.87
----------------------------------------------------
NATURAL GAS
New York Mercantile Exchange (NYMEX) (US$/mmbtu) 6.16 5.74 5.94 6.03
AECO (Cdn$/mcf) 6.45 6.63 6.36 7.07
----------------------------------------------------
Realized Prices (Cdn$/mcf):
Canada 5.97 5.85 5.74 6.30
United States 8.47 8.55 8.00 9.32
Corporate Average (Cdn$/mcf) 7.17 7.18 6.88 7.75
----------------------------------------------------
AVERAGE REALIZED OIL AND GAS PRICE (Cdn$/boe) 44.41 36.71 42.18 41.12
----------------------------------------------------
AVERAGE FOREIGN EXCHANGE RATE
Canadian to US Dollar (US$) 0.7358 0.6939 0.7472 0.6712
----------------------------------------------------
Note:
(1) These differentials are a discount to WTI.
HIGHER REALIZED COMMODITY PRICES INCREASED QUARTERLY NET INCOME BY $118 MILLION
Both crude oil and natural gas commodity prices remained strong in the second
quarter of 2004, with crude oil benchmark prices reaching record highs. The
strength in reference prices was partially offset by the impact of the stronger
Canadian dollar on our realized prices.
All of our oil sales and most of our gas sales are denominated in or referenced
to US dollars. As a result, the strong Canadian dollar decreased net sales by
approximately $40 million, and reduced our realized crude oil price by
approximately $2.70 per barrel and our realized natural gas price by $0.40 per
mcf.
CRUDE OIL REFERENCE PRICES
Crude oil prices remained strong in the second quarter with WTI averaging
US$38.32 per barrel. Strength, as well as volatility, in the quarter has come
from concerns around the growing terrorist threat in the Middle East, tight
gasoline supplies in North America and the weakness of the US dollar relative to
other major currencies. We saw WTI trade as low as US$33.30 per barrel in the
quarter and as high as US$42.38 per barrel.
Record strength in WTI has come amid concerns over the security of Saudi
Arabia's crude oil supply. With Saudi Arabia having the only spare capacity of
any significance, events in that country have a marked impact on world crude oil
prices. Recent terrorist attacks on oil facilities and targeted attacks on
foreign oil workers have pushed WTI up above US$40 per barrel on several
occasions.
31
OPEC's announced increase combined with a reported increase in gasoline supplies
and the unwinding of long speculative positions led to a drop of almost US$6 per
barrel for WTI over an eight-day period, the biggest crude oil price drop since
March of 2003. Analysts, however, believe that OPEC's announced increase is
largely irrelevant as the organization is already producing more than 500
thousand barrels per day above their new quota.
Supply concerns and speculation around those concerns will likely continue to
support higher crude prices but will also continue to generate volatility. With
the oil and gas industry currently trying to feed the fastest world economic
growth in 20 years and worldwide surplus production capacity at record lows,
events that threaten to disrupt even a small amount of supply can and have had a
significant impact on world crude oil prices. The recent volatility seems likely
to continue as speculators take advantage of instability resulting from recent
world events.
Late in the quarter, Norway's labour dispute, gasoline refinery shutdowns in the
US and Europe and more terrorist attacks in the Middle East pushed prices back
towards the US$40 per barrel level. The early transfer of power in Iraq, the end
of the Norwegian labour dispute and OPEC's assurance that quota increases would
proceed seemed to temper the rise in prices. WTI settled back down between
US$35-37 per barrel, but only temporarily. Concerns over terrorist attacks on
Iraqi pipelines and the threatened bankruptcy of Yukos, which represents 20% of
Russian crude oil production, recently pushed prices back above US$39 per
barrel.
CRUDE OIL DIFFERENTIALS
Differentials remained wide in the second quarter of 2004 due mostly to the
overall strength in market prices.
Overall, the heavy differential has widened due to the demand for lighter blends
to feed the growing demand for gasoline, higher reference prices and unplanned
maintenance at a number of refineries. In June, the heavy differential narrowed
slightly as refinery turnarounds were completed.
Our Masila differential continued to track the Brent/WTI spread, which was
largely consistent with first quarter levels. While the summer driving season in
North America increased demand for WTI relative to Brent, the increased OPEC
production brought more supply into the US market to meet the increased demand.
This has kept the Brent/WTI spread largely unchanged this quarter. The Masila
differential widened slightly in the year due to increased gasoline demand in
southeast Asia. The demand for gasoline has fuelled demand for sweeter crudes,
which reduces demand for sour crudes like Masila.
The Mars differential affects the pricing of our Aspen crude and has widened
with the delivery of most of the increased OPEC production to the US Gulf Coast.
NATURAL GAS REFERENCE PRICES
North American natural gas prices increased in the second quarter of 2004. While
demand and storage levels have returned to more normal levels, the strength of
WTI has kept gas prices high. Injections have caused inventories to build,
however concerns over the adequacy of supply for next winter are keeping prices
strong.
OPERATING COSTS
Three Months Six Months
Ended June 30 Ended June 30
(Cdn$/boe) 2004 2003 2004 2003
- ------------------------------------------------------------------------------------------------------------------------------
Operating Costs per boe based on our working interest production before
royalties (1)
Conventional Oil and Gas (2) 5.03 4.23 4.90 4.30
Synthetic Crude Oil
Syncrude 20.01 24.04 18.65 24.44
Total Oil and Gas (2) 6.06 5.32 5.86 5.39
-------------------------------------------
Operating Costs per boe based on our net production after royalties
Conventional Oil and Gas (2) 7.42 6.33 7.33 6.45
Synthetic Crude Oil
Syncrude 20.21 24.23 18.83 24.62
Total Oil and Gas (2) 8.66 7.71 8.48 7.85
-------------------------------------------
Notes:
(1) Operating costs per boe are our total oil and gas operating costs divided
by our working interest production before royalties. We use production
before royalties to monitor our performance consistent with other Canadian
oil and gas companies.
(2) 2003 operating costs include results of discontinued operations (see Note
10 to our Unaudited Consolidated Financial Statements).
32
HIGHER CONVENTIONAL OIL AND GAS OPERATING COSTS REDUCED NET INCOME FOR THE
QUARTER BY $2 MILLION
Higher costs associated with late-life barrels in Australia, increased water
handling and maintenance activity in Yemen and Canada, and fixed costs and
remediation activity in the Gulf of Mexico increased our corporate unit
operating costs.
Offshore Australia, lower volumes put pressure on unit operating costs,
increasing our corporate unit costs by 35(cent) per boe. With fixed costs spread
over fewer barrels in Australia, our unit operating costs increased. Unit cost
savings will be realized when the production of these higher cost barrels in
Australia comes to an end later this year. Higher water handling and disposal
costs, coupled with increased maintenance and workover activity in Yemen and
Canada increased our corporate unit operating costs by 65(cent) per boe for the
quarter. With fewer barrels in the US Gulf of Mexico, fixed costs contributed a
10(cent) per boe increase in corporate unit costs.
The strength of the Canadian dollar reduced our US-dollar denominated operating
costs, lowering our corporate unit costs by 20(cent) per boe.
LOWER OPERATING EXPENSE AT SYNCRUDE INCREASED NET INCOME FOR THE QUARTER
BY $4 MILLION
Less maintenance activity at Syncrude decreased synthetic operating costs by
17%, contributing 35(cent) per boe of savings to corporate unit costs. However,
as more expensive Syncrude barrels were a larger portion of our total corporate
production in the second quarter, our corporate unit operating costs increased
by 20(cent) per boe. With greater operational reliability expected this year,
Syncrude unit operating costs should be between $18 and $19 per barrel for the
year including energy costs.
DEPRECIATION, DEPLETION AND AMORTIZATION (DD&A)
Three Months Six Months
Ended June 30 Ended June 30
(Cdn$/boe) 2004 2003 2004 2003
- ------------------------------------------------------------------------------------------------------------------------------
DD&A per boe based on our working interest production before royalties (1)
Conventional Oil and Gas (2) 7.65 7.42 7.48 7.43
Synthetic Crude Oil
Syncrude 2.81 2.48 2.73 2.57
Average Oil and Gas (2) 7.32 7.16 7.15 7.17
-------------------------------------------
DD&A per boe based on our net production after royalties
Conventional Oil and Gas (2) 11.28 10.83 11.19 11.13
Synthetic Crude Oil
Syncrude 2.84 2.50 2.76 2.60
Average Oil and Gas (2) 10.46 10.19 10.35 10.47
-------------------------------------------
Notes:
(1) DD&A per boe is our DD&A for oil and gas operations divided by our working
interest production before royalties. We use production before royalties to
monitor our performance consistent with other Canadian oil and gas
companies.
(2) 2003 DD&A includes results of discontinued operations (see Note 10 to our
Unaudited Consolidated Financial Statements).
LOWER OIL AND GAS DD&A INCREASED NET INCOME FOR THE QUARTER BY $20 MILLION
Although lower oil and gas DD&A increased net income in total, our corporate
depletion rate increased. Depletion for Yemen increased our corporate rate
65(cent) per boe as the Block 59 signing bonus was amortized in the quarter.
Higher depletion from our more capital-intensive deep water properties in the US
Gulf of Mexico increased corporate rates by 45(cent).
Offsetting the increase was the benefit from the strong Canadian dollar as the
depletion of our US and international assets are denominated in US dollars. This
lowered our depletion rate by 30(cent) per boe. As well, our Canadian heavy oil
properties were written down at year end and both Australia and Nigeria are
nearly fully depleted. The write down of our Canadian heavy oil properties
reduced our depletion rate by 30(cent) per boe, while Australia and Nigeria
contributed a combined reduction of 35(cent).
Syncrude depletion rates increased reflecting the depletable costs of the Aurora
2 bitumen train which came into service in late 2003.
33
EXPLORATION EXPENSE (1)
Three Months Six Months
Ended June 30 Ended June 30
(Cdn$ millions) 2004 2003 2004 2003
- ----------------------------------------------------------------------------------------------------------------------------
Seismic 7 11 25 24
Unsuccessful Exploration Drilling -- 11 -- 24
Other 19 17 29 32
------------------------------------------------
Total Exploration Expense 26 39 54 80
================================================
Total Exploration Capital 46 83 91 138
Exploration Expense as a % of Exploration Capital (%) 57 47 59 58
------------------------------------------------
Note:
(1) 2003 exploration expense for the six months ended June 30 includes $1
million relating to discontinued operations (see Note 10 to our Unaudited
Consolidated Financial Statements).
LOWER EXPLORATION EXPENSE INCREASED NET INCOME FOR THE QUARTER BY $13 MILLION
Our exploration efforts were primarily focused on seismic acquisition with data
gathered offshore West Africa to help evaluate the potential of the offshore
shelf and deep water areas of the Niger delta. We also acquired additional data
on the Aspen field in the Gulf of Mexico to provide better imaging for the
evaluation of field pays and deeper potential. Our exploration drilling is
expected to increase during the second half of the year.
OIL AND GAS MARKETING
Three Months Six Months
Ended June 30 Ended June 30
(Cdn$ millions) 2004 2003 2004 2003
- ------------------------------------------------------------------------------------------------------------------------------
Marketing Revenue, net 112 114 259 295
Transportation (116) (102) (232) (221)
Other (1) (2) (2) (1)
-----------------------------------------------------
Contribution from Marketing (5) 10 25 73
=====================================================
Physical Sales Volumes (excluding intra-segment transactions)
Crude Oil (mboe/d) 471 487 443 479
Natural Gas (mmcf/d) 4,470 2,797 4,589 3,036
Value-at-Risk
Quarter-end 35 18 35 18
High 36 25 36 31
Low 22 18 17 16
Average 29 21 25 21
-----------------------------------------------------
LOWER CONTRIBUTION FROM MARKETING REDUCED NET INCOME BY $15 MILLION
We use gas storage positions to take advantage of higher winter gas prices and
we mitigate the price risk on our gas inventory by using matching futures
contracts to lock-in profits. While the futures contracts are marked to market
each period, our gas inventory is carried at the lower of cost or net realizable
value. In the second quarter, we built a 20 bcf gas position for this purpose.
With prices rising in the second quarter, our storage position increased in
value while the futures contracts lost value. We are not able to recognize the
value increase on our inventory as we are required to carry our inventory at
cost until it is sold. We are, however, required to recognize losses on the
futures contracts to the extent we have not designated them as accounting hedges
of our inventory. At June 30, 2004, we had unrecognized gains on our inventory
of $21 million. This excess of fair value over carrying value will be recognized
in our future earnings as the inventory is sold.
Our gas in storage at the end of the quarter was 55% higher than at June 30,
2003, which caused us to have more futures contract volumes in place to mitigate
our price risk on this storage position. As a result, our exposure to mark to
market losses on our futures contracts increased. Gains on our storage positions
which offset these losses will be recognized when the positions are settled.
34
COMPOSITION OF NET MARKETING REVENUE
Three Months Six Months
Ended June 30 Ended June 30
(Cdn$ millions) 2004 2003 2004 2003
- ------------------------------------------------------------------------------------------------------------------------------
Derivative Energy Contracts (6) 7 19 63
Non-Derivative Energy Contracts 1 3 6 10
-----------------------------------------------------
(5) 10 25 73
=====================================================
DERIVATIVE ENERGY CONTRACTS
Our marketing operation engages in crude oil and natural gas marketing
activities to enhance prices from the sale of our own production, and for energy
marketing and trading. We enter into contracts to purchase and sell crude oil
and natural gas. These derivative energy contracts are valued as described in
the MD&A included in our 2003 Annual Report on Form 10-K.
FAIR VALUE OF DERIVATIVE ENERGY CONTRACTS
At June 30, 2004, the fair value of our derivative energy contracts not
designated as accounting hedges totalled $72 million. The following table shows
the valuation methods underlying these contracts together with details of
contract maturity:
(Cdn$ millions) MATURITY
- ------------------------------------------------------------------------------------------------------------------------------
less than more than
1 year 1-3 years 4-5 years 5 years Total
--------------------------------------------------------------------
Prices
Actively Quoted Markets 27 1 -- -- 28
From Other External Sources 30 22 (3) (5) 44
Based on Models and Other Valuation Methods -- -- -- -- --
--------------------------------------------------------------------
Total 57 23 (3) (5) 72
========================================= ==========================
More than 79% of the unrealized gain is related to contracts that will settle
within 12 months. Contract maturities vary from a single day up to six years.
Those maturing beyond one year are primarily from natural gas related positions.
The relatively short maturity position of our contracts lowers our portfolio
risk.
At June 30, 2004, the unrecognized losses on our derivative energy contracts
designated as accounting hedges of the future sale of our gas inventory netted
to $nil. These contracts were valued from actively quoted markets and settle
within 12 months.
CHANGES IN FAIR VALUE OF DERIVATIVE ENERGY CONTRACTS
Contracts
Contracts Contracts Entered into
Outstanding at Entered into During Period
Beginning of and Closed and Outstanding
(Cdn$ millions) Period During Period (2) at End of Period Total
- -----------------------------------------------------------------------------------------------------------------------------
Fair Value at December 31, 2003 106 -- -- 106
Change in Fair Value of Contracts (10) -- 29 19
Net Losses (Gains) on Contracts Closed (53) -- -- (53)
Changes in Valuation Techniques and Assumptions (1) -- -- -- --
-------------------------------------------------------------------
Fair Value at June 30, 2004 43 -- 29 72
===================================================================
Unrecognized Losses (Gains) on Hedges of Future Sale
of Gas Inventory at June 30, 2004 --
---------------
Total Outstanding at June 30, 2004 72
===============
Note:
(1) Our valuation methodology has been applied consistently in each period.
(2) Gains of $21 million were realized on contracts entered into and closed
during the first quarter of 2004, while losses of $21 million were realized
during the second quarter of 2004.
35
TOTAL CARRYING VALUE OF DERIVATIVE ENERGY CONTRACTS
June 30 December 31
(Cdn$ millions) 2004 2003
- -------------------------------------------------------------------------------------------
Current Assets 135 102
Non Current Assets 54 63
-------------------------------
Total Derivative Energy Contract Assets 189 165
===============================
Current Liabilities 78 34
Non Current Liabilities 39 25
-------------------------------
Total Derivative Energy Contract Liabilities 117 59
===============================
Total Derivative Energy Contract Net Assets (1) 72 106
===============================
Note:
(1) Does not include derivative energy contracts accounted for as hedges.
NON-DERIVATIVE ENERGY CONTRACTS
We enter into fee for service contracts related to transportation and storage of
third party oil and gas. In addition, we earn income from our power generation
facility. We earned $1 million from our non-derivative energy activities in the
second quarter (2003 - $3 million) and $6 million (2003 - $10 million) year to
date.
CHEMICALS
LOWER CASH FLOW FROM CHEMICALS DECREASED NET INCOME BY $1 MILLION
Higher sales volumes and higher prices in North America and Brazil were offset
by the effect of the stronger Canadian dollar. Sales volumes increased 4% during
the quarter compared to 2003 but the strong Canadian dollar reduced US-dollar
denominated sales by 2%. Operating costs have increased as a result of the
higher sales volumes but we are not benefiting from foreign exchange savings on
these costs as they are denominated primarily in Canadian dollars.
CORPORATE EXPENSES
GENERAL AND ADMINISTRATIVE (G&A)
Three Months Six Months
Ended June 30 Ended June 30
(Cdn$ millions) 2004 2003 2004 2003
- ----------------------------------------------------------------------------------------------------------------
General and Administrative 130 45 190 82
----------------------------------------------------
HIGHER COSTS DECREASED QUARTERLY NET INCOME BY $85 MILLION
Our quarterly G&A costs before considering the modification of our stock option
plan are largely unchanged. During the quarter, our shareholders approved the
modification of our stock option plan to a tandem option plan, which gives the
option holder the choice of receiving cash or stock upon exercise. The adoption
of this plan created a one-time increase to our G&A expense in the second
quarter of $82 million ($54 million, after tax) which represents the
in-the-money amount of our stock options on a graded vesting basis.
The majority of the year to date increase relates to higher variable
compensation. Our average share price for the first half of the year was $50.52
per share compared to $31.81 in 2003. An increasing share price increases the
cost of our stock appreciation rights program. Most of this increase took place
in the first quarter of this year.
INTEREST AND FINANCING COSTS
Three Months Six Months
Ended June 30 Ended June 30
(Cdn$ millions) 2004 2003 2004 2003
- -----------------------------------------------------------------------------------------------------------------
Interest 47 36 96 72
Less: Capitalized Interest (9) (11) (16) (19)
-----------------------------------------------------
Net Interest Expense 38 25 80 53
=====================================================
36
HIGHER INTEREST EXPENSE REDUCED QUARTERLY NET INCOME BY $13 MILLION
In late 2003 and early 2004, we refinanced our preferred securities with lower
cost debt. As a result, dividends on the preferred securities have been replaced
with interest expense on our new debt. This increase in interest expense has
been partially offset by the strong Canadian dollar, which lowered our US-dollar
denominated interest expense by $3 million in the quarter. The replacement of
our preferred securities with subordinated debt has reduced our overall cost of
financing by almost 20%.
Three Months Six Months
Ended June 30 Ended June 30
(Cdn$ millions) 2004 2003 2004 2003
- ----------------------------------------------------------------------------------------------------------------
Interest 47 36 96 72
Dividends on Preferred Securities -- 16 3 34
----------------------------------------------------
Total Financing Cost 47 52 99 106
====================================================
Effective Interest Rate (%) 6.8 8.4 6.9 8.4
----------------------------------------------------
INCOME TAXES
Three Months Six Months
Ended June 30 Ended June 30
(Cdn$ millions) 2004 2003 2004 2003
- ----------------------------------------------------------------------------------------------------------------
Current 63 48 116 104
Future 3 (45) 21 20
----------------------------------------------------
Provision for Income Taxes 66 3 137 124
====================================================
Effective Tax Rate (%) 32 1 29 20
----------------------------------------------------
EFFECTIVE TAX RATE FOR THE QUARTER INCREASES FROM 1% TO 32%
The low effective tax rate for the second quarter of 2003 was the result of a
reduction in tax rates for Canadian resource activities, which resulted in a
recovery of future income taxes of $76 million. 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. Our effective tax rate for 2004 is expected
to be 31%.
Current income taxes include cash taxes in Yemen of $57 million (2003 - $48
million) for the quarter and $103 million (2003 - $99 million) year to date. Our
current income tax provision also includes current and alternative minimum tax
and state taxes in the US and capital taxes in Canada.
LIQUIDITY
CAPITAL STRUCTURE
June 30 December 31
(Cdn$ millions) 2004 2003
- --------------------------------------------------------------------------------------------- --------------- ---------------
Bank Debt - -
Long-Term Debt 2,566 2,776
--------------- ---------------
2,566 2,776
Less: Current Assets (2,803) (2,859)
Plus: Current Liabilities 1,757 1,460
--------------- ---------------
--------------- ---------------
Net Debt (1) 1,520 1,377
Preferred and Subordinated Securities 33 364
--------------- ---------------
--------------- ---------------
Net Debt, including Preferred and Subordinated Securities 1,553 1,741
=============== ===============
=============== ===============
Shareholders' Equity (2, 3) 2,528 2,390
=============== ===============
Notes:
(1) Long-term debt less working capital.
(2) Shareholders' equity includes preferred securities of $331 million (US$217
million) at December 31, 2003 and the equity component of the subordinated
securities of $33 million (US$25 million) at June 30, 2004 and December 31,
2003. Under US generally accepted accounting principles, these are
considered long-term debt.
(3) At June 30, 2004, there were 128,870,800 common shares and US$460 million
of unsecured subordinated securities outstanding. These subordinated
securities may be redeemed by the issuance of common shares at our option
after November 8, 2008. The number of shares to be issued will depend upon
the common share price on the redemption date.
In February 2004, we redeemed US$217 million of preferred securities and repaid
US$225 million of senior notes, which reduced shareholders' equity and debt,
respectively. We took advantage of the low interest rate environment in 2003 and
financed these repayments by issuing US$960 million of public debt in the fourth
quarter. Shareholders' equity remains strong with solid financial results and
$109 million of proceeds from the issuance of common shares. Proceeds from the
issuance of common shares are primarily from the exercise of employee stock
options.
37
CHANGE IN WORKING CAPITAL
June 30 December 31 Increase/
(Cdn$ millions) 2004 2003 (Decrease)
- ------------------------------------------------------------------------------------------------------
Cash and Short-Term Investments 839 1,087 (248)
Accounts Receivable 1,590 1,423 167
Inventories and Supplies 350 270 80
Accounts Payable and Accrued Liabilities (1,707) (1,404) (303)
Other (26) 23 (49)
------------------------------------------
1,046 1,399 (353)
==========================================
Cash and short-term investments decreased with the redemption of our preferred
securities and the repayment of our senior notes in February 2004. These
repayments were offset in part by our solid year to date cash flow from
operations and proceeds received on the exercise of employee stock options. Oil
and gas receivables increased since year end primarily due to stronger commodity
prices. Marketing receivables increased during the quarter as a result of
stronger commodity prices and higher natural gas marketing and trading activity.
The increase in inventory and supplies since year end was caused by higher gas
volumes in storage. Inventory levels for marketing tend to increase in the
spring and summer and are withdrawn during the winter months. Higher field
inventory levels in Yemen reflect the build up of supplies that will be used in
our Block 51 development program later this year.
Accounts payable and accrued liabilities are higher as a result of higher
capital accruals for our Long Lake project and our third development well at
Aspen. The $85 million obligation related to our tandem option plan recognized
during the quarter also increased our accrued liabilities. Marketing payables
increased as a result of higher natural gas marketing and trading activity and
the building of our storage position.
The decrease in other was related to the prepayment of natural gas inventory in
storage in December. This was included in inventory during the first quarter.
NET DEBT
Our net debt levels are directly related to our operating cash flows and our
capital expenditure activities. Since December 31, 2003, we have successfully
reduced net debt, including preferred and subordinated securities by $188
million:
Six Months
(Cdn$ millions) Ended June 30
- -----------------------------------------------------------------------------
Capital Expenditures (691)
Cash Flow from Operations 845
-----------------
154
Dividends on Preferred Securities and Common Shares (29)
Issue of Common Shares 109
Other (46)
-----------------
Decrease in Net Debt, including Preferred and
Subordinated Securities 188
=================
38
OUTLOOK FOR REMAINDER OF 2004
Our full-year production outlook is 255,000 - 275,000 boe/d before royalties.
While our outlook remains consistent with previous guidance, we now expect to be
at or slightly below the lower end of the range given recent setbacks and
delays. We expect to generate approximately $1.7 billion in cash flow from
operations in 2004 assuming the following for the remainder of the year:
- --------------------------------------------------------------------
WTI (US$/bbl) 30.00
NYMEX natural gas (US$/mmbtu) 4.25
US to Canadian dollar exchange rate 0.75
Our 2004 capital investment program has been increased from $1.8 billion to $1.9
billion.
Our future liquidity remains strong given our increasing cash flow from
operations and the ongoing strength of our balance sheet. We continue to
maintain a strong cash position and $1.7 billion of undrawn committed credit
facilities. As a result, we have the necessary resources to fund our capital
programs, dividend requirements and debt repayments, as well as the obligations
that arise from our day-to-day operations. We declared common share dividends of
$0.10 per share in the first and second quarters.
CONTRACTUAL OBLIGATIONS, COMMITMENTS AND GUARANTEES
We have assumed various contractual obligations and commitments in the normal
course of our operations and financing activities. We have included these
obligations and commitments in our MD&A in our 2003 Annual Report on Form 10-K.
During the quarter, we added $365 million of purchase commitments related to the
development of our Long Lake project in northern Alberta. Approximately 30% of
the obligation has been incurred as the related work was completed.
CONTINGENCIES
There are a number of lawsuits and claims pending, the ultimate results of which
cannot be ascertained at this time. We record costs as they are incurred or
become determinable. We believe the resolution of these matters would not have a
material adverse effect on our liquidity, consolidated financial position or
results of operations. These matters are described in LEGAL PROCEEDINGS in Item
3 contained in our 2003 Annual Report on Form 10-K. There have been no
significant developments since year end.
NEW ACCOUNTING PRONOUNCEMENTS
In November 2003, the CICA approved an amendment to S.3860, FINANCIAL
INSTRUMENTS - DISCLOSURE AND PRESENTATION to clarify the difference between an
equity and liability instrument. An equity instrument exists only when an
instrument is settled in shares. This amendment is effective for fiscal years
beginning on or after November 1, 2004. Once adopted, the equity component of
our subordinated securities would be reclassified from equity to long-term debt,
and the dividends paid would be classified as interest expense. Adoption of this
amendment at June 30, 2004, would increase long-term debt by $33 million and
decrease subordinated securities by $33 million.
39
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS
Certain statements in this report, including those appearing in ITEM 2 -
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS, are forward-looking statements.(1) Forward-looking statements are
generally identifiable by terms such as ANTICIPATE, BELIEVE, INTEND, PLAN,
EXPECT, ESTIMATE, BUDGET, OUTLOOK or other similar words.
These statements are subject to known and unknown risks and uncertainties and
other factors which may cause actual results, levels of activity and
achievements to differ materially from those expressed or implied by such
statements. These risks, uncertainties and other factors include:
o market prices for oil, natural gas and chemicals products;
o our ability to produce and transport crude oil and natural gas to markets;
o the results of exploration and development drilling and related activities;
o foreign-currency exchange rates;
o economic conditions in the countries and regions in which we carry on
business;
o governmental actions that increase taxes, change environmental and other
laws and regulations;
o renegotiations of contracts; and
o political uncertainty, including actions by terrorists, insurgent or other
groups, or other armed conflict, including conflict between states.
The above items and their possible impact are discussed more fully in the
section, titled BUSINESS RISK Management and MARKET RISK MANAGEMENT in Item 7 of
our 2003 Annual Report on Form 10-K.
The impact of any one risk, uncertainty or factor on a particular
forward-looking statement is not determinable with certainty as these are
interdependent and management's future course of action depends upon our
assessment of all information available at that time. Any statements regarding
the following are forward-looking statements:
o future crude oil, natural gas or chemicals prices;
o future production levels;
o future cost recovery oil revenues from our operations in Yemen;
o future capital expenditures and their allocation to exploration and
development activities;
o future sources of funding for our capital program;
o future debt levels;
o future cash flows and their uses;
o future drilling of new wells;
o ultimate recoverability of reserves;
o expected finding and development costs;
o expected operating costs;
o future demand for chemicals products;
o future expenditures and future allowances relating to environmental
matters; and
o dates by which certain areas will be developed or will come on-stream.
We believe that any forward-looking statements made are reasonable based on
information available to us on the date such statements were made. However, no
assurance can be given as to future results, levels of activity and
achievements. We undertake no obligation to update publicly or revise any
forward-looking statements contained in this report. All subsequent
forward-looking statements, whether written or oral, attributable to us or
persons acting on our behalf are expressly qualified in their entirety by these
cautionary statements.
- ------------
(1) Within the meaning of the United States PRIVATE SECURITIES LITIGATION
REFORM ACT OF 1995, Section 21E of the United States SECURITIES EXCHANGE
ACT OF 1934, as amended, and Section 27A of the United States SECURITIES
ACT OF 1933, as amended.
40
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We are exposed to all of the normal market risks inherent within the oil and gas
and chemicals business, including commodity price risk, foreign-currency rate
risk, interest rate risk and credit risk. We manage our operations to minimize
our exposure, as described in our 2003 Annual Report on Form 10-K. Our
sensitivities to key market risks for 2004 are as follows:
Cash Flow Net
(Cdn$ millions) from Operations Income
- -------------------------------------------------------------------------------------------------------
Estimated 2004 impact:
Crude Oil - US$1.00/bbl change in WTI 55 40
Natural Gas - US$0.50/mcf change in NYMEX 63 40
Foreign Exchange - $0.01 change in Cdn dollar to US dollar 27 13
----------------------------------
ITEM 4. CONTROLS AND PROCEDURES
EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES
Our Chief Executive Officer and Chief Financial Officer have evaluated the
effectiveness of our disclosure controls and procedures (as defined in Exchange
Act Rules 13a-15(e) and 15-d-15(e)) as of the end of the period covered by this
report. They concluded that, as of the end of the period covered by this report,
our disclosure controls and procedures were adequate and effective in ensuring
that material information relating to the Company and its consolidated
subsidiaries would be made known to them by others within those entities,
particularly during the period in which this report was being prepared.
Management recognizes that any controls and procedures, no matter how well
designed and operated, can provide only reasonable assurance of achieving the
desired control objectives, and in reaching a reasonable level of assurance,
management necessarily is required to apply its judgment in evaluating the
cost-benefit relationship of possible controls and procedures.
CHANGES IN INTERNAL CONTROLS
We have continually had in place systems relating to internal control over
financial reporting. There has not been any change in the Company's internal
control over financial reporting during the second quarter of 2004 that has
materially affected, or is reasonably likely to materially affect, the Company's
internal control over financial reporting.
41
PART II
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Our Annual General and Special Meeting of Shareholders was held on May 4, 2004.
The following actions were taken at the Meeting, for which proxies were
solicited pursuant to Section 85 of the Securities Act (Ontario).
(a) All eleven nominees proposed by management for election to the Board of
Directors were elected by a vote of:
Director Total Votes For
--------------------------------------------------------------
Charles W. Fischer 91,605,590
Dennis G. Flanagan 91,862,489
David A. Hentschel 91,853,639
S. Barry Jackson 91,613,701
Kevin J. Jenkins 91,611,489
Eric P. Newell, O.C. 91,613,901
Thomas C. O'Neill 91,861,901
Francis M. Saville, Q.C. 91,862,001
Richard M. Thomson, O.C. 91,614,001
John M. Willson 91,862,481
Victor J. Zaleschuk 75,575,157
(b) The appointment of Deloitte & Touche LLP, Chartered Accountants, to serve
as the independent auditors for 2004 was approved by a vote of 91,654,184
(99.68%) for and 292,595 (0.32%) withheld.
(c) The confirmation, without amendment, of By-Law No. 2 and the repeal of
By-Law No. 1 were approved by a vote of 74,531,261 (80.98%) for and
17,504,045 (19.02%) against.
(d) The reservation of 2,750,000 additional common shares for issue under the
Stock Option Plan was approved by a vote of 63,445,497 (70.84%) for and
26,119,970 (29.16%) against.
(e) The amendments to the Stock Option Plan, including the conversion to a
Tandem Option Plan, were approved by a vote of 65,391,252 (73.01%) for and
24,171,330 (26.99%) against.
(f) The shareholder proposal for the use of performance and time-based
restricted shares for future senior executive equity compensation plans
was defeated by a vote of 22,555,926 (25.20%) for and 66,955,034 (74.80%)
against.
(g) The shareholder proposal for the issue of a climate change risks and
liabilities report was defeated by a vote of 1,751,959 (1.96%) for and
87,756,321 (98.04%) against.
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 June 30, 2004, we filed or furnished the following
reports on Form 8-K:
o On May 4, 2004, we furnished a current report on Form 8-K under item 12
to furnish our press release announcing our first quarter results for
fiscal 2004.
42
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 July 19, 2004.
NEXEN INC.
/s/ Charles W. Fischer
-----------------------------------
Charles W. Fischer
President and Chief Executive Officer
(Principal Executive Officer)
/s/ Michael J. Harris
-----------------------------------
Michael J. Harris
Controller
(Principal Accounting Officer)
43