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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, 2003
[_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from.............to..........
COMMISSION FILE NUMBER 1-6702
[GRAPHIC OMITTED - NEXEN 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, 2003, there were 123,321,135 common shares issued and outstanding.
NEXEN INC.
INDEX
PART I FINANCIAL INFORMATION PAGE
Item 1. Unaudited Consolidated Financial Statements:
Unaudited Consolidated Statement of Income for the Three and
Six Months Ended June 30, 2003 and 2002................................. 3
Unaudited Consolidated Balance Sheet as at June 30, 2003
and December 31, 2002................................................... 4
Unaudited Consolidated Statement of Cash Flows for the Three and
Six Months Ended June 30, 2003 and 2002................................. 5
Unaudited Consolidated Statement of Shareholders' Equity for the
Six Months Ended June 30, 2003 and 2002................................. 6
Notes to Unaudited Consolidated Financial Statements.................... 7-20
Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations.................................................... 21-34
Item 3. Quantitative and Qualitative Disclosures about Market Risk................... 35
Item 4. Controls and Procedures...................................................... 35
PART II OTHER INFORMATION
Item 4. Submission of Matters to a Vote of Security Holders.......................... 36
Item 6. Exhibits and Reports on Form 8-K............................................. 36
Unless we indicate otherwise, all dollar amounts ($) are in Canadian dollars,
and production and reserves are our working interest before royalties. On June
30, 2003, the noon-day exchange rate for Cdn $1.00 was US $0.7378 as reported by
the Bank of Canada. This report should be read in conjunction with our 2002
Annual Report on Form 10-K.
Below is a list of terms specific to the oil and gas industry. They are used
throughout the Form 10-Q.
/d = per day mboe = thousand barrels of oil equivalent
bbl = barrel mmboe = million barrels of oil equivalent
mbbls = thousand barrels mcf = thousand cubic feet
mmbbls = million barrels mmcf = million cubic feet
mmbtu = million British thermal units bcf = billion cubic feet
km = kilometre NGL = natural gas liquid
boe = barrels of oil equivalent
Oil equivalents are used to compare quantities of natural gas with crude oil by
expressing them in a common unit. To calculate equivalents, we use 1 bbl = 6 mcf
of natural gas.
Electronic copies of our filings with the Securities Exchange Commission (from
November 8, 2002 onward) are available, free of charge, through our web site
(www.nexeninc.com). Filings prior to November 8, 2002 are available, free of
charge, upon request, by contacting our investor relations department at (403)
699-5931.
2
NEXEN INC.
UNAUDITED CONSOLIDATED STATEMENT OF INCOME
FOR THE THREE AND SIX MONTHS ENDED JUNE 30
Cdn$ millions
Three Months Six Months
Ended June 30 Ended June 30
2003 2002 2003 2002
- ---------------------------------------------------------------------------------------------------------------------------------
REVENUES
Net Sales (Note 1) 750 644 1,584 1,185
Marketing and Other (Notes 1 and 9) 145 121 320 243
Gain on Disposition of Assets -- -- -- 13
------------------------------------------------------
895 765 1,904 1,441
------------------------------------------------------
EXPENSES
Operating 198 201 402 387
Transportation and Other (Note 1) 116 116 246 232
General and Administrative 45 38 82 76
Depreciation, Depletion and Amortization 202 185 393 365
Exploration 39 43 80 80
Interest (Note 4) 25 28 53 51
------------------------------------------------------
625 611 1,256 1,191
------------------------------------------------------
INCOME BEFORE INCOME TAXES 270 154 648 250
------------------------------------------------------
PROVISION FOR INCOME TAXES
Current 48 58 104 103
Future (41) (5) 30 (19)
------------------------------------------------------
7 53 134 84
------------------------------------------------------
NET INCOME 263 101 514 166
DIVIDENDS ON PREFERRED SECURITIES, NET OF INCOME TAXES 10 11 21 22
------------------------------------------------------
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS 253 90 493 144
======================================================
EARNINGS PER COMMON SHARE ($/share)
Basic (Note 7) 2.05 0.74 4.00 1.18
======================================================
Diluted (Note 7) 2.04 0.73 3.97 1.17
======================================================
SEE ACCOMPANYING NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS.
3
NEXEN INC.
UNAUDITED CONSOLIDATED BALANCE SHEET
Cdn$ millions
JUNE 30 DECEMBER 31
2003 2002
- -----------------------------------------------------------------------------------------------------------------
ASSETS
CURRENT ASSETS
Cash and Short-Term Investments 92 59
Accounts Receivable (Note 2) 1,087 988
Inventories and Supplies (Note 3) 229 256
Other 19 26
---------------------------------
Total Current Assets 1,427 1,329
PROPERTY, PLANT AND EQUIPMENT
Net of Accumulated Depreciation, Depletion and
Amortization of $4,588 (December 31, 2002 - $4,705) 4,912 4,863
GOODWILL 36 36
FUTURE INCOME TAX ASSETS 198 263
DEFERRED CHARGES AND OTHER ASSETS 95 69
---------------------------------
6,668 6,560
=================================
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Short-Term Borrowings (Note 4) 19 18
Accounts Payable and Accrued Liabilities 1,218 1,194
Accrued Interest Payable 34 39
Dividends Payable 9 9
---------------------------------
Total Current Liabilities 1,280 1,260
---------------------------------
LONG-TERM DEBT (Note 4) 1,629 1,844
FUTURE INCOME TAX LIABILITIES 869 873
DISMANTLEMENT AND SITE RESTORATION 181 191
OTHER DEFERRED CREDITS AND LIABILITIES 48 44
SHAREHOLDERS' EQUITY (Note 6)
Preferred Securities 724 724
Common Shares, no par value
Authorized: Unlimited
Outstanding: 2003 - 123,321,135 shares
2002 - 122,965,830 shares 450 440
Retained Earnings 1,544 1,069
Cumulative Foreign Currency Translation Adjustment (57) 115
---------------------------------
Total Shareholders' Equity 2,661 2,348
---------------------------------
COMMITMENTS AND CONTINGENCIES (Note 10)
6,668 6,560
=================================
SEE ACCOMPANYING NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS.
4
NEXEN INC.
UNAUDITED CONSOLIDATED STATEMENT OF CASH FLOWS
FOR THE THREE AND SIX MONTHS ENDED JUNE 30
Cdn$ millions
Three Months Six Months
Ended June 30 Ended June 30
2003 2002 2003 2002
- ---------------------------------------------------------------------------------------------------------------------------------
OPERATING ACTIVITIES
Net Income 263 101 514 166
Charges and Credits to Income not Involving Cash (Note 8) 150 181 421 334
Exploration Expense 39 43 80 80
Changes in Non-Cash Working Capital (Note 8) 26 57 (40) (142)
Other (14) 5 (29) 29
------------------------------------------------------
464 387 946 467
FINANCING ACTIVITIES
Proceeds from Long-Term Debt -- -- 124 793
Repayment of Long-Term Debt (24) -- (24) (420)
Proceeds from (Repayment of) Short-Term Borrowings, Net (13) 67 1 16
Dividends on Preferred Securities (16) (18) (34) (36)
Dividends on Common Shares (9) (9) (18) (18)
Issue of Common Shares 5 29 10 39
Other -- (1) -- (23)
------------------------------------------------------
(57) 68 59 351
INVESTING ACTIVITIES
Capital Expenditures
Exploration and Development (309) (329) (634) (652)
Proved Property Acquisitions -- -- (164) --
Chemicals, Corporate and Other (9) (89) (13) (113)
Proceeds on Disposition of Assets - 3 -- 32
Changes in Non-Cash Working Capital (Note 8) (28) 8 (31) 27
------------------------------------------------------
(346) (407) (842) (706)
EFFECT OF EXCHANGE RATE CHANGES ON CASH
AND SHORT-TERM INVESTMENTS (65) (29) (130) (24)
------------------------------------------------------
INCREASE (DECREASE) IN CASH AND SHORT-TERM INVESTMENTS (4) 19 33 88
CASH AND SHORT-TERM INVESTMENTS - BEGINNING OF PERIOD 96 130 59 61
------------------------------------------------------
CASH AND SHORT-TERM INVESTMENTS - END OF PERIOD 92 149 92 149
======================================================
SEE ACCOMPANYING NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS.
5
NEXEN INC.
UNAUDITED CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY
FOR THE SIX MONTHS ENDED JUNE 30, 2003 AND JUNE 30, 2002
Cdn$ millions
Cumulative
Foreign
Currency
Preferred Common Retained Translation
Securities Shares Earnings Adjustment
- ---------------------------------------------------------------------------------------------------------------------------------
DECEMBER 31, 2002 724 440 1,069 115
Exercise of Stock Options -- 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 1,544 (57)
=====================================================================
Cumulative
Foreign
Currency
Preferred Common Retained Translation
Securities Shares Earnings Adjustment
- ---------------------------------------------------------------------------------------------------------------------------------
DECEMBER 31, 2001 724 389 697 94
Exercise of Stock Options -- 23 -- --
Issue of Common Shares -- 16 -- --
Net Income -- -- 166 --
Dividends on Preferred Securities, Net of
Income Taxes -- -- (22) --
Dividends on Common Shares -- -- (18) --
Translation Adjustment, Net of Income Taxes -- -- -- (16)
---------------------------------------------------------------------
JUNE 30, 2002 724 428 823 78
=====================================================================
SEE ACCOMPANYING NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS.
6
NEXEN INC.
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
Cdn$ millions except as noted
1. ACCOUNTING POLICIES
The Unaudited Consolidated Financial Statements are prepared in accordance with
Canadian Generally Accepted Accounting Principles (GAAP). The impact of
significant differences between Canadian and US GAAP on the Unaudited
Consolidated Financial Statements is disclosed in Note 12. 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, 2003 and the results of
our operations and our cash flows for the three and six months ended June 30,
2003 and 2002.
Management makes estimates and assumptions that affect the reported amounts of
assets and liabilities and disclosure of contingent assets and liabilities at
the date of the Unaudited Consolidated Financial Statements, and revenues and
expenses during the reporting period. Our management reviews these estimates,
including those related to litigation, environmental and dismantlement
liabilities, income taxes and determination of proved reserves on an ongoing
basis. Changes in facts and circumstances may result in revised estimates and
actual results may differ from these estimates. The results of operations and
cash flows for the three and six months ended June 30, 2003 are not necessarily
indicative of the results of operations or cash flows to be expected for the
year ending December 31, 2003.
These Unaudited Consolidated Financial Statements should be read in conjunction
with our Audited Consolidated Financial Statements included in our 2002 Annual
Report on Form 10-K. The accounting policies we follow are in Note 1 of the
Audited Consolidated Financial Statements included in our 2002 Annual Report on
Form 10-K.
CHANGES IN ACCOUNTING POLICIES - MARKETING ACTIVITIES
MARK-TO-MARKET
On October 25, 2002, regulators changed accounting principles, eliminating
mark-to-market accounting for our marketing inventories and our non-derivative
energy contracts. Under the new principles:
o We measure marketing inventories at the lower of cost or market; and
o We record non-derivative energy contracts, including our transportation and
storage capacity contracts, at cost as incurred.
We recorded the change to inventory prospectively as the effects on previous
periods could not be determined. Inventories at October 25, 2002 were attributed
a cost based on their market value on that date. Inventories purchased after
October 25, 2002 have been recorded at cost. We removed the mark-to-market on
our transportation contracts from earnings retroactively to the beginning of
2002. The impact on previous years was immaterial.
PRESENTATION OF TRANSPORTATION
During 2002, we adopted the new interpretation of the Emerging Issues Committee
relating to the presentation of costs for which we are reimbursed. We pay for
the transportation of the crude oil, natural gas and chemicals products that we
market, and then bill our customers for the transportation. Under the new
interpretation, this transportation is presented as a cost to us. Previously, we
netted this cost against our revenue. We show these costs as transportation and
other on the Unaudited Consolidated Statement of Income, resulting in the
following increases:
Three Months Six Months
Ended June 30 Ended June 30
2003 2002 2003 2002
- --------------------------------------------------------------------------------
Increase to:
Net Sales 8 8 18 16
Marketing and Other 102 105 221 209
Transportation and Other 110 113 239 225
-----------------------------------------
Certain comparative figures have been reclassified to ensure consistency with
current year presentation.
7
2. ACCOUNTS RECEIVABLE
June 30 December 31
2003 2002
- -----------------------------------------------------------------------------------------
Trade
Oil and Gas
Marketing 673 574
Other 327 330
Chemicals and Other 49 59
------------------------------
1,049 963
Non-Trade 46 34
------------------------------
1,095 997
Allowance for Doubtful Accounts (8) (9)
------------------------------
1,087 988
==============================
3. INVENTORIES AND SUPPLIES
June 30 December 31
2003 2002
- -----------------------------------------------------------------------------------------
Finished Products
Oil and Gas
Marketing 113 130
Other 3 -
Chemicals and Other 9 13
------------------------------
125 143
Work in Process 7 6
Field Supplies 97 107
------------------------------
229 256
==============================
4. LONG-TERM DEBT AND SHORT-TERM BORROWINGS
June 30 December 31
2003 2002
- -----------------------------------------------------------------------------------------
Unsecured Syndicated Term Credit Facilities -- --
Unsecured Redeemable Notes, due 2004 (a) 305 355
Unsecured Redeemable Debentures, due 2006 100 108
Unsecured Redeemable Medium Term Notes, due 2007 150 150
Unsecured Redeemable Medium Term Notes, due 2008 125 125
Unsecured Redeemable Notes, due 2028 271 316
Unsecured Redeemable Notes, due 2032 678 790
------------------------------
1,629 1,844
==============================
(a) UNSECURED REDEEMABLE NOTES, DUE 2004
The Unsecured Redeemable Notes are due in February 2004. We intend to refinance
this obligation with existing long-term debt facilities, and accordingly, it has
not been included in current liabilities at June 30, 2003.
(b) SHORT-TERM BORROWINGS
Occasionally, we sell the future proceeds of our accounts receivable; however,
we retain a 10% exposure to related credit losses. At June 30, 2003, we sold
$190 million of accounts receivable proceeds (December 31, 2002 - $178 million).
The retained credit exposure of $19 million (December 31, 2002 - $18 million) is
included in short-term borrowings.
8
c) INTEREST EXPENSE
Three Months Six Months
Ended June 30 Ended June 30
2003 2002 2003 2002
- ------------------------------------------------------------------------------
Long-Term Debt 34 34 68 59
Other 2 2 4 3
-------------------------------------------
Total 36 36 72 62
Less: Capitalized 11 8 19 11
-------------------------------------------
25 28 53 51
===========================================
Capitalized interest relates to and is included as part of the cost of oil and
gas properties. The capitalization rates are based on our weighted-average cost
of borrowings.
5. DERIVATIVE INSTRUMENTS AND FINANCIAL RISK MANAGEMENT
(a) COMMODITY PRICE RISK MANAGEMENT
In March 2003, we sold WTI and NYMEX gas forward contracts for the next 12
months to lock in a portion of our return on the purchase of the remaining 40%
interest in the Aspen field. The forward contracts fix our price per bbl and our
price per mmbtu of gas at the contract prices for the hedged volumes, less
applicable price differentials. At June 30, 2003, the fair value of these
instruments was a loss of $1 million. We will recognize the realized gains or
losses on these contracts in the same periods as the hedged production is sold.
Hedged Volumes Period Fixed Price (US$)
- --------------------------------------------------------------------------------
5,000 bbls/d April 2003 - March 2004 28.50/bbl
12,000 mmbtu/d April 2003 - March 2004 5.35/mmbtu
(b) FOREIGN CURRENCY EXCHANGE RATE RISK MANAGEMENT
We manage our exposure to fluctuations between US and Canadian dollars by
minimizing the need to convert between the two currencies. Net revenue from our
foreign operations and our US-dollar borrowings are generally used to fund
US-dollar capital expenditures and debt repayments. All of our US-dollar debt
was designated as a hedge against our net investment in foreign operations. In
early 2003, we de-designated our unsecured syndicated term credit facilities
from the hedge as funds drawn were used to fund US-dollar working capital in our
Canadian operations. Our remaining US-dollar debt continues to be designated as
a hedge against our net investment in foreign operations. The foreign exchange
gains or losses relating to the designated debt continue to be included in the
cumulative foreign currency translation adjustment in shareholders' equity,
while exchange gains and losses on the unsecured syndicated term credit
facilities are included in marketing and other on the Unaudited Consolidated
Statement of Income.
(c) CARRYING VALUE AND ESTIMATED FAIR VALUE OF DERIVATIVE INSTRUMENTS
Assets/(Liabilities) JUNE 30, 2003 DECEMBER 31, 2002
- ---------------------------------------------------------------------------------------------------------------------------
Carrying Fair Unrealized Carrying Fair Unrealized
Value Value Gain/(Loss) Value Value Gain/(Loss)
--------------------------------------------- --------------------------------------------
Long-Term Debt (1,629) (1,883) (254) (1,844) (1,948) (104)
Preferred Securities (724) (661) 63 (724) (756) (32)
---------------------------------------------------------------------------------------------
The estimated fair value of all derivative instruments is based on quoted market
prices and if not available, on estimates from third-party brokers or dealers or
amounts derived from valuation models. The carrying value of cash and short-term
investments, amounts receivable and short-term obligations approximates their
fair value because the instruments are near maturity. Amounts receivable and
payable by our marketing operations related to derivative instruments are equal
to fair value as we use the mark-to-market method to value them. Amounts related
to derivative instruments included in deferred charges and other assets and
other deferred credits and liabilities are $41 million and $9 million,
respectively. These derivative instruments are held by our marketing operation
and settle beyond 2003.
9
6. SHAREHOLDERS' EQUITY
(a) ESTIMATED FAIR VALUE OF STOCK OPTIONS
We use the intrinsic-value method of accounting for stock options. Under this
method, no compensation expense is recognized for stock options granted to
employees and directors. As required under GAAP, we also make certain pro forma
disclosures as if the fair-value method of accounting was applied. The
assumptions for the three and six months ended June 30, 2003 are the same as for
the year ended December 31, 2002, as described in Note 8(f) to the Audited
Consolidated Financial Statements included in our 2002 Annual Report on Form
10-K.
The following shows our pro forma net income and earnings per common share had
we applied the fair-value method of accounting to all stock options outstanding:
Three Months Six Months
Ended June 30 Ended June 30
2003 2002 2003 2002
- -------------------------------------------------------------------------------------------------------------
Net Income Attributable to Common Shareholders:
As Reported 253 90 493 144
Less: Fair Value of Stock Options 7 6 13 12
----------------------------------------------------
Pro Forma 246 84 480 132
====================================================
Earnings Per Common Share ($/share)
Basic as Reported 2.05 0.74 4.00 1.18
====================================================
Pro Forma 2.00 0.69 3.89 1.08
====================================================
Diluted as Reported 2.04 0.73 3.97 1.17
====================================================
Pro Forma 1.98 0.68 3.87 1.06
====================================================
(b) DIVIDENDS
Dividends per common share for the three months ended June 30, 2003 were $0.075
(2002 - $0.075). Dividends per common share for the six months ended June 30,
2003 were $0.15 (2002 - $0.15).
7. EARNINGS PER COMMON SHARE
We calculate 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 using Net Income Attributable to
Common Shareholders and the weighted-average number of diluted common shares
outstanding.
Three Months Six Months
Ended June 30 Ended June 30
(millions of shares) 2003 2002 2003 2002
- ------------------------------------------------------------------------------------------------------------------------------
Weighted-average number of common shares outstanding 123.3 122.3 123.2 121.9
Shares issuable pursuant to stock options 5.1 8.4 5.1 8.3
Shares to be purchased from proceeds of stock options (4.4) (6.3) (4.4) (6.7)
-----------------------------------------------------
Weighted-average number of diluted common shares outstanding 124.0 124.4 123.9 123.5
=====================================================
In calculating diluted earnings per common share for the three months ended June
30, 2003, we excluded 4,179,825 options (2002 - 10,000), and for the six months
ended June 30, 2003 we excluded 4,197,718 options (2002 - 42,000), because the
exercise price was greater than the average market price of our common shares in
those periods. During the periods presented, outstanding stock options were the
only dilutive instrument.
10
8. CASH FLOWS
(a) CHARGES AND CREDITS TO INCOME NOT INVOLVING CASH
Three Months Six Months
Ended June 30 Ended June 30
2003 2002 2003 2002
- ------------------------------------------------------------------------------------------------------------------------------
Depreciation, Depletion and Amortization 202 185 393 365
Gain on Disposition of Assets -- -- -- (13)
Future Income Taxes (41) (5) 30 (19)
Loss (Gain) on Foreign Exchange (13) 5 (4) 4
Other 2 (4) 2 (3)
-----------------------------------------------------
150 181 421 334
=====================================================
(b) CHANGES IN NON-CASH WORKING CAPITAL
Three Months Six Months
Ended June 30 Ended June 30
2003 2002 2003 2002
- ------------------------------------------------------------------------------------------------------------------------------
Operating Activities
Accounts Receivable 578 (116) (98) (400)
Inventories and Supplies (55) 12 26 (46)
Other Current Assets 3 (18) 7 (12)
Accounts Payable and Accrued Liabilities (494) 168 51 292
Accrued Interest Payable 11 14 (5) 17
Effect of Foreign Exchange Rate Changes on Non-Cash Working
Capital (17) (3) (21) 7
-----------------------------------------------------
26 57 (40) (142)
Investing Activities
Accounts Payable and Accrued Liabilities (28) 8 (31) 27
-----------------------------------------------------
Total (2) 65 (71) (115)
=====================================================
(c) OTHER CASH FLOW INFORMATION
Three Months Six Months
Ended June 30 Ended June 30
2003 2002 2003 2002
- ------------------------------------------------------------------------------------------------------------------------------
Interest Paid 22 20 72 42
Income Taxes Paid 53 74 107 114
-----------------------------------------------------
9. MARKETING AND OTHER
Three Months Six Months
Ended June 30 Ended June 30
2003 2002 2003 2002
- ------------------------------------------------------------------------------------------------------------------------------
Marketing Net Revenue 114 124 295 241
Interest 2 2 4 4
Foreign Exchange Gains (Losses) 13 (5) 4 (4)
Other (1) 16 -- 17 2
-----------------------------------------------------
145 121 320 243
=====================================================
Note:
(1) This includes $12 million of business interruption proceeds from our
insurers. The proceeds result from damage sustained in the Gulf of Mexico
during tropical storm Isidore and hurricane Lili in the third and fourth
quarters of 2002.
11
10. COMMITMENTS AND CONTINGENCIES
As described in Note 10 to the Audited Consolidated Financial Statements
included in our 2002 Annual Report on Form 10-K, there are a number of lawsuits
and claims pending, the ultimate results of which cannot be ascertained at this
time. We record costs as they are incurred or become determinable. We believe
the resolution of these matters would not have a material adverse effect on our
consolidated financial position or results of operations.
11. OPERATING SEGMENTS AND RELATED INFORMATION
Nexen is involved in activities relating to Oil and Gas, Syncrude and Chemicals
in various geographic locations as described in Note 15 to the Audited
Consolidated Financial Statements included in our 2002 Annual Report on Form
10-K.
THREE MONTHS ENDED JUNE 30, 2003
(Cdn$ millions) Corporate
and
Oil and Gas Syncrude Chemicals Other Total
- ------------------------------------------------------------------------------------------------------------------------------------
United Other
Yemen Canada States Australia Countries(1) Marketing(2)
-------------------------------------------------------------
Net Sales 191 175 195 17 19 3 58 92 -- 750
Marketing and Other 3 -- 13 -- -- 114 -- -- 15 (3) 145
Gain on Disposition of Assets -- -- -- -- -- -- -- -- -- --
-----------------------------------------------------------------------------------------------------
Total Revenues 194 175 208 17 19 117 58 92 15 895
Less: Expenses
Operating 21 41 25 8 6 5 36 56 -- 198
Transportation and Other 3 -- 2 -- -- 102 -- 9 -- 116
General and Administrative 2 7 3 -- 5 10 -- 5 13 45
Depreciation, Depletion and
Amortization 41 64 56 7 10 3 4 13 4 202
Exploration 1 6 18 1 13 (4) -- -- -- -- 39
Interest -- -- -- -- -- -- -- -- 25 25
-----------------------------------------------------------------------------------------------------
Income (Loss) before Income
Taxes 126 57 104 1 (15) (3) 18 9 (27) 270
=====================================================================================================
Less: Provision for Income
Taxes (5) 7
------
Net Income 263
======
Identifiable Assets 546 2,134 1,487 25 152 1,003 (6) 614 477 230 6,668
=====================================================================================================
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
=====================================================================================================
Notes:
(1) Includes results of operations from producing activities in Nigeria and
Colombia.
(2) Includes results of operations from a natural gas-fired generating facility
in Alberta. In 2002, these results were included in Corporate and Other.
(3) Includes interest income of $2 million and foreign exchange gains of $13
million.
(4) Includes exploration activities primarily in Nigeria, Colombia and Brazil.
(5) Includes Yemen cash taxes of $48 million.
(6) Approximately 79% of Marketing's identifiable assets are accounts
receivable and inventories.
12
SIX MONTHS ENDED JUNE 30, 2003
(Cdn$ millions) Corporate
and
Oil and Gas Syncrude Chemicals Other Total
- ------------------------------------------------------------------------------------------------------------------------------------
United Other
Yemen Canada States Australia Countries(1) Marketing(2)
-------------------------------------------------------------
Net Sales 419 383 379 45 36 11 121 190 -- 1,584
Marketing and Other 3 1 13 -- -- 295 -- -- 8 (3) 320
Gain on Disposition of Assets -- -- -- -- -- -- -- -- -- --
------------------------------------------------------------------------------------------------------
Total Revenues 422 384 392 45 36 306 121 190 8 1,904
Less: Expenses
Operating 42 81 46 21 10 12 68 122 -- 402
Transportation and Other 3 -- 3 -- -- 221 -- 19 -- 246
General and Administrative 3 15 6 -- 10 19 -- 10 19 82
Depreciation, Depletion and
Amortization 83 128 105 13 16 6 7 27 8 393
Exploration 3 24 33 1 19 (4) -- -- -- -- 80
Interest -- -- -- -- -- -- -- -- 53 53
------------------------------------------------------------------------------------------------------
Income (Loss) before Income
Taxes 288 136 199 10 (19) 48 46 12 (72) 648
======================================================================================================
Less: Provision for Income
Taxes (5) 134
------
Net Income 514
======
Identifiable Assets 546 2,134 1,487 25 152 1,003 (6) 614 477 230 6,668
======================================================================================================
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 (7) -- -- -- -- -- -- 164
------------------------------------------------------------------------------------------------------
114 183 362 2 48 -- 89 4 9 811
======================================================================================================
Notes:
(1) Includes results of operations from producing activities in Nigeria and
Colombia.
(2) Includes results of operations from a natural gas-fired generating facility
in Alberta. In 2002, these results were included in Corporate and Other.
(3) Includes interest income of $4 million and foreign exchange gains of $4
million.
(4) Includes exploration activities primarily in Nigeria, Colombia and Brazil.
(5) Includes Yemen cash taxes of $99 million.
(6) Approximately 79% of Marketing's identifiable assets are accounts
receivable and inventories.
(7) On March 27, 2003 we acquired the residual 40% interest in Aspen in the
Gulf of Mexico for US $109 million.
13
THREE MONTHS ENDED JUNE 30, 2002
(Cdn$ millions) Corporate
and
Oil and Gas Syncrude Chemicals Other(1) Total
- ------------------------------------------------------------------------------------------------------------------------------------
United Other
Yemen Canada States Australia Countries(2) Marketing
-----------------------------------------------------------
Net Sales 198 169 79 43 18 -- 48 86 3 644
Marketing and Other -- -- -- -- -- 124 -- -- (3)(3) 121
Gain on Disposition of Assets -- -- -- -- -- -- -- -- -- --
------------------------------------------------------------------------------------------------------
Total Revenues 198 169 79 43 18 124 48 86 -- 765
Less: Expenses
Operating 20 48 26 11 6 -- 36 53 1 201
Transportation and Other -- -- -- -- -- 105 -- 10 1 116
General and Administrative 1 6 2 -- 4 8 -- 7 10 38
Depreciation, Depletion and
Amortization 36 64 33 17 15 2 3 12 3 185
Exploration 16 8 8 1 10 (4) -- -- -- -- 43
Interest -- -- -- -- -- -- -- -- 28 28
------------------------------------------------------------------------------------------------------
Income (Loss) before Income
Taxes 125 43 10 14 (17) 9 9 4 (43) 154
======================================================================================================
Less: Provision for Income
Taxes (5) 53
------
Net Income 101
======
Identifiable Assets 561 2,158 996 88 183 895 (6) 435 528 273 6,117
======================================================================================================
Capital Expenditures
Development and Other 52 36 116 31 -- -- 30 14 75 354
Exploration 5 13 34 1 11 -- -- -- -- 64
------------------------------------------------------------------------------------------------------
57 49 150 32 11 -- 30 14 75 (7) 418
======================================================================================================
Notes:
(1) Includes results of operations from a natural gas-fired generating facility
in Alberta.
(2) Includes results of operations from producing activities in Nigeria and
Colombia.
(3) Includes interest income of $2 million and foreign exchange losses of $5
million.
(4) Includes exploration activities primarily in Nigeria and Colombia.
(5) Includes Yemen cash taxes of $55 million.
(6) Approximately 86% of Marketing's identifiable assets are accounts
receivable and inventories.
(7) Includes $67 million related to the buy out of the lease agreement for the
natural gas-fired generating facility in Alberta.
14
SIX MONTHS ENDED JUNE 30, 2002
(Cdn$ millions) Corporate
and
Oil and Gas Syncrude Chemicals Other(1) Total
- ------------------------------------------------------------------------------------------------------------------------------------
United Other
Yemen Canada States Australia Countries(2) Marketing
-----------------------------------------------------------
Net Sales 362 307 140 65 37 - 98 171 5 1,185
Marketing and Other -- 1 -- -- -- 241 -- 1 -- (3) 243
Gain on Disposition of Assets -- -- -- -- -- -- -- -- 13 (4) 13
------------------------------------------------------------------------------------------------------
Total Revenues 362 308 140 65 37 241 98 172 18 1,441
Less: Expenses
Operating 39 89 49 25 11 -- 63 108 3 387
Transportation and Other -- -- -- -- -- 209 -- 20 3 232
General and Administrative 2 13 4 -- 9 15 -- 12 21 76
Depreciation, Depletion and
Amortization 74 129 65 28 27 4 6 25 7 365
Exploration 19 21 23 1 16 (5) -- -- -- -- 80
Interest -- -- -- -- -- -- -- -- 51 51
------------------------------------------------------------------------------------------------------
Income (Loss) before Income
Taxes 228 56 (1) 11 (26) 13 29 7 (67) 250
======================================================================================================
Less: Provision for Income
Taxes (6) 84
------
Net Income 166
======
Identifiable Assets 561 2,158 996 88 183 895 (7) 435 528 273 6,117
======================================================================================================
Capital Expenditures
Development and Other 95 128 195 46 10 -- 51 30 83 638
Exploration 19 34 55 1 18 -- -- -- -- 127
------------------------------------------------------------------------------------------------------
114 162 250 47 28 -- 51 30 83 (8) 765
======================================================================================================
Notes:
(1) Includes results of operations from a natural gas-fired generating facility
in Alberta.
(2) Includes results of operations from producing activities in Nigeria and
Colombia.
(3) Includes interest income of $4 million and foreign exchange losses of $4
million.
(4) The Moose Jaw asphalt operation was disposed of on January 2, 2002 for
proceeds of $27 million, plus working capital.
(5) Includes exploration activities primarily in Nigeria and Colombia.
(6) Includes Yemen cash taxes of $92 million.
(7) Approximately 86% of Marketing's identifiable assets are accounts
receivable and inventories.
(8) Includes $67 million related to the buy out of the lease agreement for the
natural gas-fired generating facility in Alberta. 12.
15
12. DIFFERENCES BETWEEN CANADIAN AND US GENERALLY ACCEPTED
ACCOUNTING PRINCIPLES
The Unaudited Consolidated Financial Statements have been prepared in accordance
with Canadian GAAP. US GAAP Unaudited Consolidated Financial Statements and
summaries of differences from Canadian GAAP are as follows:
(a) UNAUDITED CONSOLIDATED STATEMENT OF INCOME - US GAAP
FOR THE THREE AND SIX MONTHS ENDED JUNE 30
Three Months Six Months
Ended June 30 Ended June 30
(Cdn$ millions) 2003 2002 2003 2002
- ------------------------------------------------------------------------------------------------------------------------------
REVENUES
Net Sales (iii) 750 644 1,584 1,185
Marketing and Other (v) 146 121 321 243
-----------------------------------------------------
896 765 1,905 1,428
-----------------------------------------------------
EXPENSES
Operating (viii) 198 201 402 374
Transportation and Other 116 116 246 232
General and Administrative 45 38 82 76
Depreciation, Depletion and Amortization (ii); (ix) 216 196 422 388
Exploration 39 43 80 80
Interest (i) 41 46 87 87
-----------------------------------------------------
655 640 1,319 1,237
-----------------------------------------------------
INCOME BEFORE INCOME TAXES 241 125 586 191
-----------------------------------------------------
PROVISION FOR INCOME TAXES
Current 48 58 104 103
Future (i) - (x) 29 (12) 92 (33)
-----------------------------------------------------
77 46 196 70
-----------------------------------------------------
NET INCOME BEFORE CUMULATIVE EFFECT OF A CHANGE IN
ACCOUNTING PRINCIPLE 164 79 390 121
Cumulative Effect of a Change in Accounting Principle on Periods
up to December 31, 2002, Net of Income Taxes of $25 Million (ix) -- -- (37) --
-----------------------------------------------------
NET INCOME - US GAAP (1) 164 79 353 121
=====================================================
EARNINGS PER COMMON SHARE ($/share)
Basic (Note 7) 1.33 0.65 2.86 0.99
=====================================================
Diluted (Note 7) 1.32 0.64 2.85 0.98
=====================================================
Note:
(1) RECONCILIATION OF CANADIAN AND US GAAP NET INCOME
Three Months Six Months
Ended June 30 Ended June 30
(Cdn$ millions) 2003 2002 2003 2002
------------------------------------------------------------------------------------------------------------------
Net Income - Canadian GAAP 263 101 514 166
Impact of US Principles (net of income taxes):
Fair Value of Currency Swap (v) 1 -- 1 --
Dividends on Preferred Securities (i) (10) (11) (21) (22)
Depreciation (ii); (ix) (14) (11) (28) (23)
Future Income Taxes (x) (76) -- (76) --
---------------------------------------------------
Net Income - US GAAP, before Cumulative Effect of a
Change in Accounting Principle 164 79 390 121
Cumulative Effect of a Change in Accounting Principle
on Periods up to December 31, 2002 (ix) -- -- (37) --
---------------------------------------------------
Net Income - US GAAP 164 79 353 121
===================================================
16
(b) UNAUDITED CONSOLIDATED BALANCE SHEET - US GAAP
June 30 December 31
(Cdn$ millions) 2003 2002
- --------------------------------------------------------------------------------------------------------------
ASSETS
CURRENT ASSETS
Cash and Short-Term Investments 92 59
Accounts Receivable (iii) 1,088 990
Inventories and Supplies 229 256
Other 19 26
------------------------------
Total Current Assets 1,428 1,331
PROPERTY, PLANT AND EQUIPMENT
Net of Accumulated Depreciation, Depletion and
Amortization of $5,072 (December 31, 2002 - $4,992) (ii); (ix) 5,195 5,064
GOODWILL 36 36
FUTURE INCOME TAX ASSETS 198 263
DEFERRED CHARGES AND OTHER ASSETS (i); (vi) 99 70
------------------------------
6,956 6,764
==============================
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Short-term Borrowings 19 18
Accounts Payable and Accrued Liabilities (iii) 1,220 1,200
Accrued Interest Payable 34 39
Dividends Payable 9 9
------------------------------
Total Current Liabilities 1,282 1,266
------------------------------
LONG-TERM DEBT (i); (vi) 2,258 2,575
FUTURE INCOME TAX LIABILITIES (i) - (x) 940 876
DISMANTLEMENT AND SITE RESTORATION (ix) - 191
ASSET RETIREMENT OBLIGATION (ix) 355 -
OTHER DEFERRED CREDITS AND LIABILITIES (vii) 52 44
SHAREHOLDERS' EQUITY
Common Shares, no par value
Authorized: Unlimited
Outstanding: 2003 - 123,321,135 shares
2002 - 122,965,830 shares 450 440
Retained Earnings (i); (ii); (v); (ix); (x) 1,615 1,280
Accumulated Other Comprehensive Income (i); (iii); (iv); (vii) 4 92
------------------------------
Total Shareholders' Equity 2,069 1,812
------------------------------
COMMITMENTS AND CONTINGENCIES
6,956 6,764
==============================
(c) UNAUDITED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME - US GAAP
FOR THE THREE AND SIX MONTHS ENDED JUNE 30
Three Months Six Months
Ended June 30 Ended June 30
(Cdn$ millions) 2003 2002 2003 2002
- -----------------------------------------------------------------------------------------------------------
Net Income - US GAAP 164 79 353 121
Other Comprehensive Income, net of income taxes:
Translation Adjustment (i); (iv) (62) 15 (87) 14
Unrealized Mark-to-Market Loss (iii) (4) - (1) -
--------------------------------------------------
Comprehensive Income 98 94 265 135
==================================================
17
(d) UNAUDITED CONSOLIDATED STATEMENT OF CASH FLOWS
Under US principles, dividends on preferred securities of $16 million and $34
million for the three and six months ended June 30, 2003, respectively (June 30,
2002 - $18 million and $36 million) that are included in financing activities
would be reported in operating activities.
Under US principles, geological and geophysical costs of $11 million and $24
million for the three and six months ended June 30, 2003, respectively (June 30,
2002 - $15 million and $35 million) that are included in investing activities
would be reported in operating activities.
(e) OTHER SUPPLEMENTARY INFORMATION
Three Months Six Months
Ended June 30 Ended June 30
2003 2002 2003 2002
- ------------------------------------------------------------------------------------------------------------------------------
Pro Forma Earnings - Fair-Value Method of Accounting
for Stock Options - US GAAP
Net Income - US GAAP
As Reported 164 79 353 121
Less: Fair Value of Stock Options 7 6 13 12
-----------------------------------------------------
Pro Forma 157 73 340 109
=====================================================
Earnings Per Common Share ($/share)
Basic as Reported 1.33 0.65 2.86 0.99
=====================================================
Pro Forma 1.28 0.60 2.76 0.89
=====================================================
Diluted as Reported 1.32 0.64 2.85 0.98
=====================================================
Pro Forma 1.27 0.59 2.75 0.88
=====================================================
NOTES:
i. Under US principles, the preferred securities are classified as
long-term debt rather than shareholders' equity. The pre-tax dividends
are included in interest expense, and the related income tax is
included in the provision for income taxes in the Unaudited
Consolidated Statement of Income. The related pre-tax issue costs are
included in deferred charges and other assets rather than as an
after-tax charge to retained earnings. The foreign-currency translation
gains or losses are included in accumulated other comprehensive income
in the Unaudited Consolidated Balance Sheet. The pre-tax dividends are
included in operating activities in the Unaudited Consolidated
Statement of Cash Flows.
ii. Under US principles, the liability method of accounting for income
taxes was adopted in 1993. In Canada, the liability method was adopted
in 2000. Under US principles, the adjustment on initial adoption was
included in property, plant and equipment rather than retained
earnings. This increases depreciation expense under US principles.
iii. Under US principles, all derivative instruments are recognized on the
balance sheet as either an asset or a liability measured at fair value.
Changes in the fair value of derivatives are recognized in earnings
unless specific hedge criteria are met.
CASH FLOW HEDGES: Changes in the fair value of derivatives that are
designated as cash flow hedges are recognized in earnings in the same
period as the hedged item. Any fair value change in a derivative before
that period is recognized on the balance sheet. The effective portion
of that change is recognized in other comprehensive income with any
ineffectiveness recognized in net sales on the income statement.
Included in accounts payable at June 30, 2003 is $1 million (December
31, 2002 - $nil), fair value for the forward contracts used to hedge a
portion of our cash flow. The contracts limit our exposure to
fluctuations in commodity prices by fixing our cash flow from the sale
of hedged production, as described in Note 5. As of June 30, 2003, the
fair value included in accumulated other comprehensive income was an
unrealized loss of $1 million, net of income taxes. Approximately $1
million of the unrealized loss is expected to be moved to net sales in
the next six months as the underlying production is delivered or the
hedge expires. For the six months ended June 30, 2003, amounts related
to the ineffectiveness of cash flow hedges were included in net sales
and were immaterial.
FAIR VALUE HEDGES: Both the derivative instrument and the underlying
commitment are recognized on the balance sheet at their fair value. Any
changes in the fair value are reflected net in earnings. Included in
both accounts receivable and accounts payable at June 30, 2003 is $1
million (December 31, 2002 - $2 million) related to fair value hedges.
The hedges convert fixed prices for physical delivery of natural gas
into a floating price through a fixed to floating swap. The impact on
earnings is immaterial.
iv. Under US principles, exchange gains and losses arising from the
translation of our net investment in self-sustaining foreign operations
are included in comprehensive income. Additionally, exchange gains and
losses from translation of our US-dollar long-term debt, net of income
taxes, are included in comprehensive income as it has been designated
as a hedge of our foreign net investment. Cumulative amounts are
included in accumulated other comprehensive income in the Unaudited
Consolidated Balance Sheet.
v. Under US principles, a derivative and a cash instrument cannot be
designated in combination as a net investment hedge. Changes in fair
value and foreign exchange gains and losses on our US $37 million
currency swap are included in earnings.
vi. Under US principles, discounts on long-term debt are classified as a
reduction of long-term debt rather than as deferred charges and other
assets.
vii. Under US principles, the amount by which our accrued pension cost is
less than the unfunded accumulated benefit obligation is included in
comprehensive income and accrued pension liabilities. This amount was
$4 million at June 30, 2003 (December 31, 2002 - $4 million).
viii. Under US principles, gains and losses on the disposition of assets are
shown as operating expenses rather than revenues.
ix. On January 1, 2003 we adopted Financial Accounting Standards Board
(FASB) Statement No. 143, "Accounting for Asset Retirement Obligations"
(FAS 143) for US GAAP reporting purposes. FAS 143 requires recognition
of a liability for the future retirement obligations associated with
our property, plant and equipment, which includes oil and gas wells and
facilities, and chemicals plants. These obligations, which generally
relate to dismantlement and site restoration, are initially measured at
fair value, which is the discounted future value of the liability. This
fair value is capitalized as part of the cost of the related asset and
amortized to expense over its useful life. The liability accretes until
we expect to settle the retirement obligation.
This change in accounting policy has been reported as a cumulative
effect adjustment in the Unaudited Consolidated Statement of Income.
Under the old accounting rules, our results would have been:
Three Months Six Months
Ended June 30 Ended June 30
2003 2003
-------------------------------------------------------------------------------------------------------------------
Net Income - US GAAP
As Reported 164 353
Cumulative Effect of Change in Accounting Principle -- 37
Additional Depreciation, Depletion and Amortization, and Accretion 1 3
-------------------------------
Adjusted 165 393
===============================
Earnings per Common Share ($/share)
Basic as Reported 1.33 2.86
===============================
Adjusted 1.34 3.19
===============================
Diluted as Reported 1.32 2.85
===============================
Adjusted 1.33 3.17
===============================
Had FAS 143 been applied during all periods presented, our asset
retirement obligation, including current obligations of $14 million at
December 31, 2002 and $18 million at June 30, 2003, would have been
reported as follows:
As Reported Pro-forma
-----------------------------------------------------------------------
January 1, 2002 182 364
December 31, 2002 205 390
June 30, 2003 373 373
---------------------------
19
We own interests in several assets for which the fair value of the
asset retirement obligation cannot be reasonably determined because the
assets currently have an indeterminate life. These assets include our
interests in two gas plants and our interest in Syncrude's upgrader and
sulfur pile. The asset retirement obligation for these assets will be
recorded in the first year in which the lives of the assets are
determinable.
Had FAS 143 been applied during all periods presented, our June 30,
2002 results would have been reported as follows:
Three Months Six Months
Ended June 30 Ended June 30
2002 2002
-------------------------------------------------------------------------------------------------------------------
Net Income - US GAAP
As Reported 79 121
Less: Additional Depreciation, Depletion and Amortization, and Accretion 2 3
------------------------------
Adjusted 77 118
==============================
Earnings per Common Share ($/share)
Basic as Reported 0.65 0.99
==============================
Adjusted 0.63 0.97
==============================
Diluted as Reported 0.64 0.98
==============================
Adjusted 0.62 0.96
==============================
x. Under US principles, enacted tax rates are used to calculate future
income taxes, whereas under Canadian GAAP, substantively enacted tax
rates are used. Substantively enacted changes in Canadian federal and
provincial income tax rates created a $76 million future income tax
recovery during the quarter.
NEW ACCOUNTING PRONOUNCEMENTS AND UPCOMING CHANGE IN ACCOUNTING POLICY
Our shareholders approved a resolution requiring us to expense stock options. As
a result, we plan to adopt the fair-value method of accounting for stock options
in the fourth quarter of 2003. In January 2003, the US Financial Accounting
Standards Board (FASB) issued Statement No. 148 "Accounting for Stock-Based
Compensation - Transition and Disclosure, an Amendment of FASB Statement No.
123" (FAS 148). FAS 148 amends FAS 123 "Accounting for Stock-Based
Compensation", to provide alternative methods of transition for a voluntary
change to the fair-value method of accounting for stock-based employee
compensation. We plan to adopt the fair-value method of accounting for stock
options in the fourth quarter of 2003 using the prospective method, whereby
compensation cost will be recognized for all options granted on or after January
1, 2003. All stock options granted prior to January 1, 2003 will continue to be
accounted for under Accounting Principles Board Opinion No. 25 "Accounting for
Stock Issued to Employees" (APB 25) unless these stock options are modified or
settled subsequent to adoption. The impact under US GAAP will be immaterial in
2003.
In May 2003, the FASB issued Statement No. 150, "Accounting for Certain
Instruments with Characteristics of Both Liabilities and Equity" (FAS 150). FAS
150 establishes standards for classifying and measuring certain financial
instruments with characteristics of both liabilities and equity. It requires a
financial instrument that is within its scope to be classified as a liability.
Certain financial instruments must be valued at fair value, with changes in fair
value recognized through earnings. FAS 150 is effective at the beginning of the
first interim period beginning after June 15, 2003. It is to be implemented by
reporting the cumulative effect of a change in an accounting principle.
Restatement is not permitted. The impact under US GAAP will be a $16 million
increase in the carrying value of our Preferred Securities along with the
recognition of a loss in the third quarter.
The following standard issued by the FASB does not impact us:
o Statement No. 149 - "Amendment of Statement 133 on Derivative Instruments
and Hedging Activities" effective for contracts entered into or modified
after June 30, 2003 and for hedging relationships designated after June 30,
2003.
20
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 12 TO THE UNAUDITED CONSOLIDATED
FINANCIAL STATEMENTS. UNLESS OTHERWISE NOTED, TABULAR AMOUNTS ARE IN MILLIONS OF
CANADIAN DOLLARS, AND SALES VOLUMES AND PRODUCTION VOLUMES ARE BEFORE ROYALTIES.
WE HAVE PRESENTED OUR WORKING INTEREST BEFORE ROYALTIES AS WE MEASURE OUR
PERFORMANCE ON THIS BASIS CONSISTENT WITH OTHER CANADIAN OIL AND GAS COMPANIES.
SECOND QUARTER HIGHLIGHTS
Our strong financial results continued during the second quarter of 2003 and
contributed to record results for the first half of the year. During the second
quarter of 2003, attractive commodity prices, growth in our US operations and
successful development drilling in Yemen offset a lower contribution from our
marketing operations and the negative effect of a strengthening Canadian dollar
on our net income and cash flow from operations. Our solid results were
complemented by successful exploration drilling on Block 51 in Yemen, successful
appraisal drilling on Block 222 in Nigeria, and our acquisition of additional
exploration opportunities in the deep waters of the Gulf of Mexico. We also
continued our progress on major growth projects in the deep-water Gulf of Mexico
and in the Athabasca oil sands.
Following are the quarterly highlights:
o Record production levels at 280,000 boe/d before royalties.
o Increased net income by 160% and cash flow from operations by 39% from
second quarter 2002.
o Grew production, after royalties, by 11% from the second quarter of 2002
and by 10% from the first quarter of 2003 with higher margin barrels from
Aspen.
o High-value Aspen production contributed to record cash flow from operations
of $179 million for the US. This makes the US the largest contributor to
our cash flow from operations this quarter.
o The decrease in tax rates for Canadian resource activities resulted in a
future tax recovery of $76 million.
Three Months Six Months
Ended June 30 Ended June 30
(Cdn$ millions) 2003 2002 2003 2002
- ------------------------------------------------------------------------------------------------------------------------------
Net Sales 750 644 1,584 1,185
Net Income 263 101 514 166
Earnings per Common Share - Basic ($/share) 2.05 0.74 4.00 1.18
Earnings per Common Share - Diluted ($/share) 2.04 0.73 3.97 1.17
Cash Flow from Operations (1) 452 325 1,015 580
Production, before Royalties (mboe/d) 280 272 272 269
Production, after Royalties (mboe/d) 195 175 186 176
Capital Expenditures (2) 318 418 811 765
-----------------------------------------------------
Notes:
(1) We evaluate our performance and that of our business segments based on
earnings and cash flow from operations. Cash flow from operations is a
non-GAAP term that represents cash generated from operating activities
before changes in non-cash working capital and other. We consider it a key
measure as it demonstrates our ability and the ability of our business
segments to generate the cash flow necessary to fund future growth through
capital investment and repay debt.
Three Months Six Months
Ended June 30 Ended June 30
(Cdn$ millions) 2003 2002 2003 2002
--------------------------------------------------------------------------------------------------
Cash Flow from Operating Activities 464 387 946 467
Changes in Non-Cash Working Capital (26) (57) 40 142
Other 14 (5) 29 (29)
------------------------------------------------
Cash Flow from Operations 452 325 1,015 580
================================================
(2) Includes $164 million relating to the purchase of the remaining working
interest in the Aspen field in March 2003.
21
FINANCIAL RESULTS
CHANGE IN NET INCOME
2003 VS 2002
Three Months Six Months
(Cdn$ millions) Ended June 30 Ended June 30
- -----------------------------------------------------------------------------------------------------------------
NET INCOME AT JUNE 30, 2002 101 166
===============================
Favourable (unfavourable) variances:
Cash Items:
Production volumes, after royalties:
Crude oil 41 47
Natural gas 19 19
Crude oil sales volumes, after royalties -- (12)
Realized commodity prices:
Crude oil (24) 152
Natural gas 64 168
Oil and gas operating expense:
Conventional 10 13
Synthetic -- (5)
Marketing (9) 41
Chemicals 4 5
General and administrative (7) (6)
Interest expense 3 (2)
Current income taxes 10 (1)
Other 16 16
-------------------------------
Total Cash Variance 127 435
Non-Cash Items:
Depreciation, depletion and amortization
Oil and Gas (15) (25)
Other (2) (3)
Exploration expense 4 --
Future income taxes 36 (49)
Gain on disposition of assets -- (13)
Other 12 3
-------------------------------
Total Non-Cash Variance 35 (87)
-------------------------------
NET INCOME AT JUNE 30, 2003 263 514
===============================
BEST QUARTERLY PRODUCTION IN NEXEN'S HISTORY
Solid second quarter 2003 results were driven by record production levels and
strong commodity prices offset by the strengthening Canadian dollar relative to
the US dollar and a lower contribution from our marketing division.
The strengthening Canadian dollar relative to the US dollar reduced our
quarterly net income by $25 million and our quarterly cash flow from operating
activities by $50 million. This is because we translate the results of our
foreign operations from US dollars to Canadian dollars. With a stronger Canadian
dollar, our foreign revenues and realized commodity prices referenced to US
dollars are lower when translated. However, we benefit to the extent that our
foreign operating costs and capital expenditures are also lower when translated.
In addition, most of our fixed-rate debt is denominated in US dollars so this
debt gets cheaper as the Canadian dollar strengthens and has resulted in a $215
million decrease in our fixed-rate debt since December 31, 2002.
Our marketing results declined as 2002 included mark-to-market net revenues on
our inventories. New accounting rules, which came into effect in late 2002, now
require us to exclude mark-to-market gains on our marketing inventories from our
results until these inventories are sold.
Strong commodity prices, record production levels, growth in high-margin barrels
from Aspen and a solid contribution from marketing delivered our best-ever
year-to-date results in 2003. Significant variances in net income are explained
further in the following sections.
22
OIL AND GAS
PRODUCTION VOLUMES (BEFORE ROYALTIES)
Three Months Six Months
Ended June 30 Ended June 30
2003 2002 2003 2002
- -----------------------------------------------------------------------------------------------------------------------------
Oil and Liquids (mbbls/d)
Yemen 118.7 118.1 117.4 118.2
Canada 50.6 57.6 49.9 58.2
United States 31.4 10.4 26.6 10.2
Australia 5.8 16.7 6.9 10.5
Other Countries 6.0 9.9 6.1 10.0
Syncrude 15.2 12.9 14.4 14.7
----------------------------------------------------------------
227.7 225.6 221.3 221.8
----------------------------------------------------------------
Natural Gas (mmcf/d)
Canada 159 160 160 168
United States 157 116 146 117
----------------------------------------------------------------
316 276 306 285
----------------------------------------------------------------
Total (mboe/d) 280 272 272 269
================================================================
PRODUCTION VOLUMES (AFTER ROYALTIES)
Three Months Six Months
Ended June 30 Ended June 30
2003 2002 2003 2002
- -----------------------------------------------------------------------------------------------------------------------------
Oil and Liquids (mbbls/d)
Yemen 59.3 55.9 57.4 55.9
Canada 39.1 44.4 38.2 44.9
United States 28.0 8.6 23.5 8.5
Australia 5.7 12.4 6.1 8.1
Other Countries 4.7 4.9 5.0 6.0
Syncrude 15.1 12.8 14.3 14.6
----------------------------------------------------------------
151.9 139.0 144.5 138.0
----------------------------------------------------------------
Natural Gas (mmcf/d)
Canada 124 123 124 128
United States 132 95 123 97
----------------------------------------------------------------
256 218 247 225
----------------------------------------------------------------
Total (mboe/d) 195 175 186 176
================================================================
RECORD QUARTERLY PRODUCTION INCREASED NET INCOME FOR THE QUARTER BY $60 MILLION
Production, after royalties, grew 11% from the second quarter of 2002 and 10%
from the first quarter of 2003 with the addition of 27,000 boe/d of low royalty
production from our Aspen project in the deep waters of the Gulf of Mexico.
Although our realized commodity price increased by 4% and production volumes,
after royalties, grew by 11% since the second quarter of 2002, we successfully
grew our cash flow from operations by 39%. This reflects our changing production
mix to higher value barrels. On a before royalties basis, production increased
3% compared to the second quarter last year as growth in the US more than offset
declines in Australia, Nigeria and Canada. This is further explained below.
MASILA BLOCK IN YEMEN
o Additional service rig capacity and on-going development drilling on the
Masila Block contributed 228,300 bbls/d, gross (118,700 bbls/d, net to
Nexen) to production.
o We exited the quarter at 119,100 bbls/d, net to Nexen.
o Yemen is expected to achieve its full year production target of 118,100
bbls/d, net to Nexen.
23
CANADA
o Second quarter production of 77,100 boe/d was 9% lower than 2002 due to the
lower productivity of some maturing assets, weather related drilling delays
and increased water cuts at some of our heavy oil properties.
o We are currently soliciting bids for a package of non-core light oil
properties located in the Williston Basin of southeast Saskatchewan. These
properties are currently producing 9,100 (7,100 after royalties) equivalent
barrels per day and we expect the sale to close by the end of the third
quarter. The sales proceeds are expected to be used to reduce our net
debt(1), further strengthening our balance sheet.
US GULF OF MEXICO
o Our deep-water Aspen production boosted US rates by 94% from 2002 to a
quarterly record of 57,600 boe/d. Aspen came onstream in December 2002 and
we acquired the residual interest in this project in late March 2003.
o The acquisition of the additional interest in Aspen added 10,700 boe/d to
our second quarter production volumes. We locked in a portion of our return
on this acquisition by selling approximately 60% of the incremental
production forward to March 2004 at a weighted-average price of US $29.50
per boe. Our cash netback(2) on these hedged volumes is approximately US
$23 per boe. The forward sale of 10% of the acquired reserves has paid for
50% of the purchase price.
o Production at Aspen was partially shut-in during April and May to repair
pipeline and wellhead valve malfunctions. With the problems resolved in
June, we expect production from the Gulf of Mexico to remain around the
55,000 to 60,000 boe/d range for the remainder of the year.
o Production from Aspen is priced off Mars blend, which is the second most
actively traded US crude stream after WTI. Mars was priced at a $3.35/bbl
discount to WTI in the second quarter.
o Eugene Island 295, which was damaged by Hurricane Lili last October,
produced 3,800 boe/d through temporary production equipment. Production is
expected to shift later this year to permanent production facilities to be
installed on an adjacent undamaged drilling platform.
OTHER COUNTRIES
o Production at Buffalo offshore Australia and at Ejulebe offshore Nigeria
declined in the second quarter of 2003 in line with our expectations.
o The B-9 well at Buffalo was suspended due to high water cut.
o Buffalo and Ejulebe are both expected to be fully depleted by 2004.
SYNCRUDE
o Production returned to 18,700 bbls/d, net to Nexen, in early May after the
completion of the spring turnaround and extended coker maintenance.
o With the completion of the turnaround, we expect our share of Syncrude
production to average between 16,000 and 17,000 bbls/d in 2003.
- ----------
(1) Long-term debt less working capital.
(2) Netback is defined as sales price less all per unit costs including
royalties, operating expenses and cash taxes. This is calculated using our
working interest production before royalties.
24
COMMODITY PRICES
Three Months Six Months
Ended June 30 Ended June 30
2003 2002 2003 2002
- ------------------------------------------------------------------------------------------------------------------------------
CRUDE OIL
West Texas Intermediate (WTI) (US$/bbl) 28.91 26.25 31.39 23.95
-----------------------------------------------------
Differentials (US$/bbl):
Masila 3.64 1.90 3.62 1.51
Heavy Oil 7.13 6.08 7.68 5.91
Producing Assets (1) (Cdn$/bbl):
Yemen 35.86 38.34 40.72 35.59
Canada 30.95 31.58 35.08 28.48
United States 36.28 39.65 40.23 36.03
Australia 36.53 37.41 43.52 36.23
Nigeria 37.61 40.17 43.03 37.01
Colombia 31.98 35.50 38.34 32.97
Syncrude 42.26 40.62 46.76 36.97
Corporate Average (1) (Cdn$/bbl) 35.24 36.74 39.87 33.93
-----------------------------------------------------
NATURAL GAS
New York Mercantile Exchange (US$/mmbtu) 5.74 3.44 6.03 2.97
-----------------------------------------------------
Canada (Cdn$/mcf) (1) 5.85 3.83 6.30 3.30
United States (Cdn$/mcf) (1) 8.55 5.50 9.32 4.81
Corporate Average (Cdn$/mcf) (1) 7.18 4.53 7.75 3.92
-----------------------------------------------------
AVERAGE REALIZED OIL AND GAS PRICE (Cdn$/boe) (1) 36.71 35.18 41.12 32.12
-----------------------------------------------------
AVERAGE FOREIGN EXCHANGE RATE
Canadian to US Dollar 0.6939 0.6338 0.6712 0.6313
-----------------------------------------------------
Note:
(1) Prices based on working interest production before royalties.
LOWER REALIZED CRUDE OIL PRICES DECREASED QUARTERLY NET INCOME BY $24 MILLION
REALIZED CRUDE OIL PRICES
o Despite stronger crude oil reference prices compared to the second quarter
of 2002, we realized lower prices for our crude oil as a result of widening
differentials and strengthening of the Canadian dollar relative to the US
dollar.
o All of our oil sales are denominated in or referenced to US dollars. The
strengthening Canadian dollar reduced our realized crude oil price by
around $3.15 per bbl.
CRUDE OIL REFERENCE PRICES
o WTI fell from its highs in the first quarter of 2003 with the removal of
the Iraq war premium and increased supply from Venezuela. Historically low
product inventory levels in the US, delays in sustainable Iraqi production
and concerns over Nigerian supply have kept WTI strong.
o Successful supply management by OPEC combined with uncertainty around the
timing of Iraq's re-entry into the market has pushed prices up above the US
$30/bbl mark. Instability in Iraq and the rest of the Middle East coupled
with supply concerns in Nigeria and Venezuela has created price volatility.
25
HEAVY OIL DIFFERENTIALS
o Approximately 10% of our total corporate production is Canadian heavy oil.
o Differentials narrowed early in the second quarter due to the summer
ramp-up of asphalt producing refineries.
o The heavy differential widened in early July 2003 as demand fell with the
unexpected shut down of a major refinery for turnaround.
o Additionally, heavy oil production from several new projects has caused an
increase in supply.
MASILA DIFFERENTIAL
o Our Masila crude is typically priced off North Sea Brent.
o In the second quarter of 2003, the Masila and Brent differentials, to WTI,
widened as expected. Typically, in the summer months when demand for fuel
oil is down, Brent widens relative to WTI.
HIGHER REALIZED NATURAL GAS PRICES INCREASED QUARTERLY NET INCOME BY $64 MILLION
NATURAL GAS PRICES
o Substantially all of our natural gas sales are denominated in or referenced
to US dollars. The strengthening Canadian dollar reduced our realized gas
price by 35(cent) per mcf. Higher natural gas reference prices increased
our average gas price by $3.00/mcf, more than offsetting the effect of the
strengthening Canadian dollar on our realized prices.
o Natural gas prices remained strong during the second quarter due to
concerns that injections may not be high enough to replenish inventory
before winter.
o Moderate temperatures have recently tempered this upward pressure, with
inventory beginning to build as demand subsides.
OPERATING COSTS
(Based on working interest production before royalties)
Three Months Six Months
Ended June 30 Ended June 30
(Cdn$/boe) 2003 2002 2003 2002
- ------------------------------------------------------------------------------------------------------------------------------
Conventional Oil and Gas 4.23 4.60 4.30 4.55
Synthetic Crude Oil
Syncrude 25.68 30.70 26.01 23.58
Total Oil and Gas (1) 5.40 5.83 5.46 5.56
-----------------------------------------------------
Note:
(1) Operating costs per equivalent barrel are our total oil and gas operating
costs divided by our working interest production before royalties. We use
production before royalties to monitor our performance consistent with
other Canadian oil and gas companies.
LOWER OPERATING COSTS INCREASED NET INCOME FOR THE QUARTER BY $10 MILLION
o Conventional operating costs decreased due to the addition of low cost
volumes from Aspen in the Gulf of Mexico. Additionally, there was no
turnaround at our Balzac gas plant in Canada in 2003.
o Syncrude's operating costs per barrel were down relative to the second
quarter of 2002 due to the timing and duration of the spring turnaround.
Operating costs have increased at Syncrude on a year-to-date basis as a
result of unscheduled maintenance and higher natural gas input prices.
o The strengthening Canadian dollar decreased US dollar denominated operating
costs lowering our corporate average unit operating costs by approximately
25(cent) per boe.
26
DEPRECIATION, DEPLETION AND AMORTIZATION (DD&A)
(Based on working interest production before royalties)
Three Months Six Months
Ended June 30 Ended June 30
(Cdn$/boe) 2003 2002 2003 2002
- ------------------------------------------------------------------------------------------------------------------------------
Conventional Oil and Gas 7.42 6.86 7.43 6.93
Synthetic Crude Oil
Syncrude 2.48 2.40 2.57 2.26
Total Oil and Gas (1) 7.16 6.65 7.17 6.68
-----------------------------------------------------
Note:
(1) DD&A per equivalent barrel 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.
HIGHER OIL AND GAS DD&A REDUCED NET INCOME FOR THE QUARTER BY $15 MILLION
o Higher 2002 finding and development costs have increased our depletion
charge. Certain of these finding and development costs relate to long-cycle
time, capital-intensive projects for which reserves have not yet been
added.
o The strengthening Canadian dollar decreased per unit depletion costs by
approximately 40(cent)per boe in the quarter.
EXPLORATION EXPENSE
Three Months Six Months
Ended June 30 Ended June 30
(Cdn$ millions) 2003 2002 2003 2002
- ------------------------------------------------------------------------------------------------------------------------------
Seismic 11 16 24 36
Unsuccessful Exploration Drilling 11 16 24 21
Other 17 11 32 23
-----------------------------------------------------
Total Exploration Expense 39 43 80 80
=====================================================
Total Exploration Capital 83 64 138 127
-----------------------------------------------------
LOWER EXPLORATION EXPENSE INCREASED NET INCOME FOR THE QUARTER BY $4 MILLION
o Activity in the quarter included dry hole costs in Canada, the Gulf of
Mexico and Brazil, as well as seismic acquisition in the Gulf of Mexico and
Canada.
o Exploration expenditures include successful drilling on Block 51 in Yemen,
as well as successful appraisal drilling in Nigeria on Block 222.
OIL AND GAS MARKETING
Three Months Six Months
Ended June 30 Ended June 30
(Cdn$ millions) 2003 2002 2003 2002
- ------------------------------------------------------------------------------------------------------------------------------
Revenue 114 124 295 241
Transportation (102) (105) (221) (209)
Other (2) -- (1) --
-----------------------------------------------------
10 19 73 32
=====================================================
Marketing contribution to Income before Income Tax (3) 9 48 13
-----------------------------------------------------
Physical Sales Volumes (excluding intra-segment transactions)
Crude Oil (mboe/d) 487 425 479 397
Natural Gas (mmcf/d) 2,797 2,648 3,036 2,352
Value-at-Risk
Quarter End 18 17 18 17
High 25 19 31 19
Low 18 12 16 12
Average 21 16 21 15
-----------------------------------------------------
27
LOWER NET MARKETING REVENUE DECREASED NET INCOME FOR THE QUARTER BY $9 MILLION
o Marketing results were down compared to the first quarter of 2003 due in
part to normal seasonal fluctuations in natural gas marketing. Typically,
profits are recognized in the first and fourth quarters of a year as
seasonal winter demand peaks and summer gas injected into storage is sold.
o In 2002, mark-to-market gains on our storage positions were included in net
income. New accounting rules require us to exclude this from our 2003
results until the inventory is sold despite having futures contracts in
place that lock in the profit on our stored volumes. The market value of
our inventory in storage was $9 million higher than reported for the three
months ended June 30, 2003.
Our marketing operation engages in crude oil and natural gas marketing
activities to enhance prices from the sale of our own oil and gas production,
and for energy trading as described in Note 6(a) to the Audited Consolidated
Financial Statements included in our 2002 Annual Report on Form 10-K.
FAIR VALUE OF DERIVATIVE ENERGY CONTRACTS
At June 30, 2003, the fair value of our derivative energy contracts totalled $44
million. The following table shows the valuation methods underlying these
contracts together with timing of contract maturity:
(Cdn$ millions) MATURITY
- -----------------------------------------------------------------------------------------------------------------------------
less than more than
1 year 1-3 years 4-5 years 5 years Total
--------------------------------------------------------------------
Prices:
Actively quoted 92 25 (9) -- 108
From other external sources (80) 1 15 -- (64)
Based on models and other valuation methods -- -- -- -- -
--------------------------------------------------------------------
Total 12 26 6 -- 44
====================================================================
Contract maturities vary from a single day up to five years. Those maturing
beyond one year are primarily from natural gas related positions.
CHANGES IN FAIR VALUE OF DERIVATIVE ENERGY CONTRACTS
Contracts
Contracts Contracts Entered into
Outstanding at Entered into During Period
Beginning of and Closed and Outstanding
(Cdn$ millions) Period During Period at End of Period Total
- -------------------------------------------------------------------------------------------------------------------------------
Fair value at December 31, 2002 3 -- -- 3
Change in fair value of contracts 20 26 17 63
Net losses (gains) on contracts closed 4 (26) -- (22)
Changes in valuation techniques and assumptions (1) -- -- -- -
---------------------------------------------------------------------
Fair value at June 30, 2003 27 -- 17 44
=====================================================================
Note:
(1) Our valuation methodology has been applied consistently period over period.
This fair value includes:
o offsetting derivatives and physical contracts with limited market risk, and
o positions that are subject to change in value from fluctuating market
prices.
We manage the risk associated with positions exposed to changes in value through
daily monitoring of value-at-risk and by stress testing and scenario analysis.
The value-at-risk calculation estimates the maximum probable loss, given a 95%
confidence level, that we would incur if our open positions were unwound over
two days. At June 30, 2003, our value-at-risk with respect to these positions
was $18 million (December 31, 2002 - $19 million).
28
COMPOSITION OF NET MARKETING REVENUE
Three Months Six Months
Ended June 30 Ended June 30
(Cdn$ millions) 2003 2003
- ------------------------------------------------------------------------------------------------------------------------------
Derivative energy contracts 7 63
Non-derivative energy contracts 5 11
Other (2) (1)
----------------------------------
10 73
==================================
CHEMICALS
HIGHER OPERATING PROFIT INCREASED NET INCOME FOR THE QUARTER BY $4 MILLION
o Chlorine and caustic soda operating profit increased by $5 million due to
improved demand and higher sales prices.
o Lower operating costs resulting from the idling of our Taft, Louisiana
sodium chlorate facility were offset by purchased product costs. The
purchased product allows us to continue to meet the needs of our customers
in the southeastern US.
o The strengthening Canadian dollar relative to the US dollar decreased our
revenue as our products are largely priced in US dollars.
CORPORATE EXPENSES
GENERAL AND ADMINISTRATIVE (G&A)
Three Months Six Months
Ended June 30 Ended June 30
(Cdn$ millions) 2003 2002 2003 2002
- ------------------------------------------------------------------------------------------------------------------------------
General and Administrative 45 38 82 76
================================================
HIGHER COSTS DECREASED QUARTERLY NET INCOME BY $7 MILLION
o Our increasing stock price and solid quarterly results have increased costs
related to our Stock Appreciation Rights and bonus plans by $4 million.
o G&A expenses, after bonuses and stock appreciation rights, increased by $3
million due to increased staffing levels. Staffing level increases are the
result of our major development projects in the US and Canada, and growth
in our Marketing division.
INTEREST
Three Months Six Months
Ended June 30 Ended June 30
(Cdn$ millions) 2003 2002 2003 2002
- ------------------------------------------------------------------------------------------------------------------------------
Interest 36 36 72 62
Less: Capitalized Interest 11 8 19 11
-----------------------------------------------------
Net Interest Expense 25 28 53 51
=====================================================
LOWER INTEREST EXPENSE INCREASED QUARTERLY NET INCOME BY $3 MILLION
o Capitalized interest increased as spending on our major development
projects in the Gulf of Mexico and Canada continued.
o Strengthening Canadian dollar reduced interest expense on our fixed rate
debt denominated in US dollars by $3 million. This has been offset by
interest incurred on the use of our syndicated term credit facilities
during the quarter.
o Higher borrowing rate of 7.875% on our 30-year notes issued in March 2002
contributed to the year to date increase.
29
INCOME TAXES
EFFECTIVE TAX RATE FOR THE QUARTER DECREASES TO 2.6% FROM 34.4%
o The effective rate was low due to a reduction in tax rates for Canadian
resource activities that resulted in a recovery of future income taxes of
$76 million.
o Current income taxes include cash taxes in Yemen of $48 million (2002 - $55
million) for the quarter and $99 million (2002 - $92 million) year to date.
o In the first half of 2003 and 2002, current income taxes include federal
and provincial capital taxes in Canada.
CAPITAL EXPENDITURES
Three Months Six Months
Ended June 30 Ended June 30
(Cdn$ millions) 2003 2002 2003 2002
- -------------------------------------------------------------------------------------------------------------------------------
Yemen 59 57 114 114
Canada 50 49 183 162
United States 118 150 362 250
Australia 1 32 2 47
Other Countries 33 11 48 28
Syncrude 48 30 89 51
Chemicals, Corporate and Other 9 89 13 113
-----------------------------------------------------
318 418 811 765
=====================================================
Development 226 265 496 525
Exploration 83 64 138 127
Acquisition of the Residual 40% Interest in the Aspen Field - - 164 -
Chemicals, Corporate and Other 9 89 13 113
-----------------------------------------------------
318 418 811 765
=====================================================
YEMEN
During the quarter, we successfully drilled the Tammum-1 and Amir-1 exploration
wells on Block 51, located immediately west of our Masila Block 14. We operate
Block 51and hold an 87.5% working interest.
Tammum-1 encountered crude oil in the Qishn and Saar horizons and is currently
being production tested. Amir-1 encountered hydrocarbons and will be tested in
the near future. We are currently drilling a third prospect located 25 kms
northwest of Amir. We are accelerating 3D seismic acquisition and are planning
appraisal drilling to assess the significance of these discoveries.
CANADA
A successful winter drilling program on our leases in the Athabasca region of
Alberta resulted in an increase in the estimate of the recoverable bitumen
resource. The majority of the increase was at Long Lake where the proposed
commercial development lands now have an average of 12 delineation wells per
section.
Our Premium Synthetic Crude project at Long Lake, where we have a 50% working
interest, is progressing on schedule. Pilot testing of the steam assisted
gravity drainage technology is underway and we expect to be producing 3,000 bbls
of bitumen per day from three SAGD pilot wells by mid-2004. The Design Basis
Memorandum for the commercial project is complete and we have commenced detailed
engineering. We expect to receive regulatory approval in the third quarter and
finalize cost estimates so we can make a decision on commercial development
before the end of 2003. Following a declaration of commerciality, facilities
construction will begin in 2004, bitumen production in 2006 and upgrader
start-up in 2007. This project is expected to add 30,000 bbls per day of premium
synthetic oil production, net to Nexen, in 2007 at a cost of $1.5 billion.
30
UNITED STATES
The Gunnison deep-water development project in the Gulf of Mexico remains on
budget and on schedule. The truss SPAR production hull is complete and has been
transported from the construction facility in Finland to a staging area in
Texas. Mooring operations, installation of the production topside and pipeline
tie-ins will be completed during the third and fourth quarters.
Production from the field is scheduled to commence in early 2004 at 30 mmcf of
natural gas and 2,000 bbls of oil per day, net to Nexen, increasing to 50 mmcf
of gas and 9,000 bbls of oil per day late in the year. The current development
plan will fill approximately 75% of the design capacity of the facility, leaving
room for growth from exploration and the processing of third-party volumes.
In May, we entered into an agreement with Shell Exploration and Production
Company to jointly explore a 1,116 square mile area of the deep-water eastern
Gulf of Mexico. The area of mutual interest consists of 124 blocks located in
Mississippi Canyon and Desoto Canyon. Under the terms of the participation
agreement, Nexen is currently earning a 20% interest in the Shiloh prospect,
which is drilling on Desoto Canyon Block 269 in 7,500 feet of water. The
agreement also provides the option to participate in other exploration
opportunities within the joint venture area.
This is our second exploration venture with Shell Exploration. In 2002 we
entered into an agreement to jointly explore a 1,044 square mile area in the
shallow water of the Gulf of Mexico for natural gas in deep Miocene age
reservoirs. The second well under that agreement will test a prospect named
Shark located on South Timbalier 174. It is expected to spud during the third
quarter.
Elsewhere in the Gulf of Mexico, we expect to commence drilling a third
development well at Aspen in the fourth quarter. With success, this will be
followed by an exploration well at Crested Butte, a direct offset to Aspen. An
exploratory test of the Gotcha prospect, located on Alaminos Canyon Block 856,
adjacent to Shell's announced Great White discovery, is expected to commence
drilling late in the fourth quarter or early in 2004.
WEST AFRICA
Offshore Nigeria, the ongoing appraisal of our Ukot and Usan discoveries on
Block 222, in which we hold a 20% working interest, continues to indicate
significant hydrocarbon accumulations. Priority has focussed on the Usan field.
We are continuing to appraise Ukot, and have plans to test other prospects on
the block with significant upside potential which has not been included in the
current resource estimate. The operator, Elf Petroleum Nigeria Limited, on
behalf of the joint venture partners, has applied to the Nigerian National
Petroleum Corporation for granting of an Oil Mining Lease.
SYNCRUDE
Syncrude's Stage 3 expansion is proceeding as expected. Mine site development is
88% complete and on schedule to see bitumen production commencing in the fourth
quarter of this year. The upgrader expansion is 22% complete, with completion
targeted for mid-2005. Our 7.23% share of Syncrude's production is expected to
increase to over 25,000 bbls per day with the completion of the Stage 3
expansion.
CHEMICALS
Our Brandon, Manitoba plant is one of the lowest cost sodium chlorate facilities
in the industry. We are expanding this facility by 33% to 260,000 tonnes per
year to replace higher cost capacity idled earlier this year at Taft, Louisiana.
When complete in the fourth quarter of 2004, this expansion will make Brandon
the largest sodium chlorate facility in the world, significantly enhancing our
competitive position in North America.
31
LIQUIDITY AND CAPITAL STRUCTURE
CAPITAL STRUCTURE
JUNE 30 DECEMBER 31
(Cdn$ millions) 2003 2002
- -------------------------------------------------------------------------------
Bank Debt -- --
Senior Public Debt 1,629 1,844
--------------------------
1,629 1,844
Less: Working Capital 147 69
--------------------------
Net Debt (1) 1,482 1,775
==========================
Shareholders' Equity (2) 2,661 2,348
==========================
Notes:
(1) Long-term debt less working capital.
(2) Included in shareholders' equity are preferred securities of $724 million
(US $476 million). Under US generally accepted accounting principles, these
are considered long-term debt.
The change in net debt from December 31, 2002 to June 30, 2003 resulted from:
Increase (Decrease)
(Cdn$ millions) in Net Debt
- -----------------------------------------------------------------------------
Cash Flow from Operations (1,015)
Capital Expenditures 647
Acquisition of Additional Interest in Aspen Field 164
Dividends on Preferred Securities and Common Shares 52
Foreign Exchange (185)
Other 44
--------------------
Decrease in Net Debt (293)
====================
Our working capital increased $78 million compared to
December 31, 2002 due to the following:
Cash and Short-Term Investments 33
Net Marketing Receivables (1) 15
Inventories and Supplies (27)
Accounts Payable and Accrued Liabilities (1) 71
Decrease in Sale of Accounts Receivable (11)
Other (3)
-------------------
78
===================
Note:
(1) Net Marketing receivables represent accounts receivable less accounts
payable and accrued liabilities for our Marketing division.
o Net marketing receivables increased with higher natural gas prices offset
by weaker crude oil prices.
o Inventories and supplies decreased as natural gas volumes in storage were 3
bcf lower than year end.
o Accounts payable and accrued liabilities decreased due to the strengthening
Canadian dollar relative to the US dollar.
In May 2003 we filed a shelf prospectus with securities regulatory authorities
in Canada for the offering, from time to time until June 2005, of up to $500
million in debt securities (Shelf Prospectus). This Shelf Prospectus replaces a
previous shelf prospectus that expired in June 2003.
32
NEW ACCOUNTING PRONOUNCEMENTS
In February 2003, the Canadian Institute of Chartered Accountants (CICA) issued
Accounting Guideline 14, "Disclosure of Guarantees" (AcG-14). AcG-14 elaborates
on the disclosures required with respect to any obligations we may have under
certain guarantees that we have issued. The disclosure requirements are
effective for interim and annual periods beginning on or after January 1, 2003.
We adopted FASB Interpretation No. 45, "Guarantor's Accounting and Disclosure
Requirements for Guarantees, Including Indirect Guarantees of Indebtedness to
Others", the US equivalent of AcG-14 for the year ended December 31, 2002. There
were no material guarantees outstanding at December 31, 2002 or June 30, 2003.
The following guideline issued by the CICA is not expected to impact us:
o Accounting Guideline 15, "Consolidation of Variable Interest Entities"
effective for annual and interim periods beginning on or after January 1,
2004.
In May 2003, the US Financial Accounting Standards Board (FASB) issued Statement
No. 150, "Accounting for Certain Instruments with Characteristics of Both
Liabilities and Equity" (FAS 150). FAS 150 establishes standards for classifying
and measuring certain financial instruments with characteristics of both
liabilities and equity. It requires a financial instrument that is within its
scope to be classified as a liability. Certain financial instruments must be
valued at fair value, with changes in fair value recognized through earnings.
FAS 150 is effective at the beginning of the first interim period beginning
after June 15, 2003. It is to be implemented by reporting the cumulative effect
of a change in an accounting principle. Restatement is not permitted. The impact
under US GAAP will be a $16 million increase in the carrying value of our
Preferred Securities along with the recognition of a loss in the third quarter.
The following standard issued by the FASB does not impact us:
o Statement No. 149 - "Amendment of Statement 133 on Derivative Instruments
and Hedging Activities" effective for contracts entered into or modified
after June 30, 2003 and for hedging relationships designated after June 30,
2003.
UPCOMING CHANGE IN ACCOUNTING POLICY
In December 2002, the CICA issued an exposure draft that proposes to amend CICA
Handbook Section 3870 "Stock-Based Compensation and Other Stock-Based Payments".
The proposed amendment would require the recognition of expenses for all
employee stock-based compensation transactions for fiscal years beginning on or
after January 1, 2004. Earlier adoption is encouraged. The exposure draft
provides two alternative methods of transition to the fair-value method of
accounting for stock-based employee compensation. In January 2003, the US
Financial Accounting Standards Board (FASB) issued Statement No. 148 "Accounting
for Stock-Based Compensation - Transition and Disclosure, an Amendment of FASB
Statement No. 123" (FAS 148). FAS 148 amends FAS 123 "Accounting for Stock-Based
Compensation", to provide alternative methods of transition for a voluntary
change to the fair-value method of accounting for stock-based employee
compensation.
Our shareholders approved a resolution requiring us to expense stock options. As
a result, we plan to adopt the fair-value method of accounting for stock options
in the fourth quarter of 2003. Our method of adoption, and thus the impact on
our financial statements, under Canadian GAAP will depend on whether or not the
exposure draft is finalized by December 31, 2003. Under US GAAP, we plan to
adopt the fair-value based method using the prospective method, whereby
compensation cost will be recognized for all options granted on or after January
1, 2003. All stock options granted prior to January 1, 2003 will continue to be
accounted for under Accounting Principles Board Opinion No. 25 "Accounting for
Stock Issued to Employees" (APB 25) unless these stock options are modified or
settled subsequent to adoption. The impact of adopting the fair-value based
method under US GAAP will be immaterial in 2003.
33
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS
Certain statements in this report, including those appearing in Item 2 -
Management's Discussion and Analysis of Financial Condition and Results of
Operations, are forward-looking statements.(1) Forward-looking statements are
generally identifiable by terms such as "plan", "expect", "estimate", "budget"
or other similar words.
These statements are subject to known and unknown risks and uncertainties and
other factors which may cause actual results, levels of activity and
achievements to differ materially from those expressed or implied by such
statements. These risks, uncertainties and other factors include:
o market prices for oil, natural gas and chemicals products;
o our ability to produce and transport crude oil and natural gas to markets;
o the results of exploration and development drilling and related activities;
o foreign-currency exchange rates;
o economic conditions in the countries and regions in which we carry on
business;
o governmental actions that increase taxes, change environmental and other
laws and regulations;
o renegotiations of contracts; and
o political uncertainty, including actions by terrorists, insurgent groups or
war.
The above items and their possible impact are discussed more fully in the
section, titled "Business Risk Management" and "Market Risk Management" in Item
7 of our 2002 Annual Report on Form 10-K.
The impact of any one risk, uncertainty or factor on a particular
forward-looking statement is not determinable with certainty as these factors
are interdependent and management's future course of action depends upon our
assessment of all information available at that time. Any statements regarding
the following are forward-looking statements:
o future crude oil, natural gas or chemicals prices;
o future production levels;
o future cost recovery oil revenues and our share of production from our
operations in Yemen;
o future capital expenditures and their allocation to exploration and
development activities;
o future sources of funding for our capital program;
o future debt levels;
o future cash flows and their uses;
o future drilling of new wells;
o ultimate recoverability of reserves;
o expected finding and development costs;
o expected operating costs;
o future demand for chemicals products;
o future expenditures and future allowances relating to environmental
matters; and
o dates by which certain areas will be developed or will come onstream.
We believe that the forward-looking statements made are reasonable based on
information available to us on the date such statements were made. However, no
assurance can be given as to future results, levels of activity and
achievements. All subsequent forward-looking statements, whether written or
oral, attributable to us or persons acting on our behalf are expressly qualified
in their entirety by these cautionary statements.
- ----------
(1) Within the meaning of the United States Private Securities Litigation
Reform Act of 1995, Section 21E of the United States Securities Exchange
Act of 1934, as amended, and Section 27A of the United States Securities
Act of 1933, as amended.
34
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We are exposed to all of the normal market risks inherent within the oil and gas
and chemicals business, including commodity price risk, foreign currency rate
risk, interest rate risk and credit risk. We manage our operations in a manner
intended to minimize our exposure as described in our 2002 Annual Report on Form
10-K. Our sensitivity to key market risks for the remainder of the year are as
follows:
Cash Flow Net
(Cdn$ millions) from Operations Income
- -------------------------------------------------------------------------------------------------------
Estimated remainder of year impact:
Crude Oil - US $1.00/bbl change in WTI 27 21
Natural Gas - US $0.50/mcf change 26 16
Foreign Exchange - $0.01 change in Cdn dollar to US dollar 12 5
-----------------------------
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-14(c) and 15-d-14(c)) within 90 days prior to the filing of this
Form 10-Q (Evaluation Date). They concluded that, as of the Evaluation Date, 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 quarterly report was being prepared. Management
recognizes that any controls and procedures, no matter how well designed and
operated, can provide only reasonable assurance of achieving the desired control
objectives, and in reaching a reasonable level of assurance, management
necessarily is required to apply its judgement in evaluating the cost-benefit
relationship of possible controls and procedures.
CHANGES IN INTERNAL CONTROLS
We have continually had in place systems relating to internal controls and
procedures with respect to our financial information. While we were not of the
belief that our controls had any significant deficiencies or material
weaknesses, we determined that taking advantage of new proven systems technology
could provide a competitive advantage. Accordingly, in 2002 we introduced to
most of our operations a significant change in our internal controls
implementing a Systems, Applications, and Products in Data Processing (SAP)
system. SAP is an integrated, real-time, multi-user, multi-location enterprise
resource planning system, which focuses on financial and management accounting,
and logistics. In the first quarter of 2003, we implemented SAP into our
operations in Colombia and Australia. The conversion of data and the
implementation and operation of SAP has been continually monitored and reviewed.
Based on these evaluations, there were no significant deficiencies or material
weaknesses in these internal controls requiring corrective action. As a result,
no corrective actions were taken.
35
PART II. OTHER INFORMATION
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
The Company's Annual General and Special Meeting of Shareholders was held on May
6, 2003. The following actions were taken at the Meeting, for which proxies were
solicited pursuant to Section 85 of the Securities Act (Ontario):
(a) All ten nominees proposed by management for election to the Board of
Directors, being Charles W. Fischer, Dennis G. Flanagan, David A.
Hentschel, S. Barry Jackson, Kevin J. Jenkins, Thomas C. O'Neill, Francis
M. Saville, Q.C., Richard M. Thomson, John M. Willson and Victor J.
Zaleschuk were elected.
(b) The appointment of Deloitte & Touche LLP, chartered accountants, to serve
as the independent auditors for 2003 was approved.
(c) Reservation of 2,000,000 additional common shares for issuance under the
Stock Option Plan was approved by a vote of 61,761,758 for and 18,052,279
against.
(d) Shareholder proposal to expense stock options was approved by a vote of
44,147,179 for and 34,614,422 against.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) EXHIBITS
99 Notice and Proxy Statement and Information Circular with respect to the
May 6, 2003 Annual General and Special Meeting of Shareholders, dated
March 10, 2003 (filed as Exhibit 1 to the Form 6-K filed by the Registrant
on March 20, 2003 and incorporated herein by reference).
99.1 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.
99.2 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, 2003, Nexen Inc. furnished the following
reports on Form 8-K.
i. Current report on Form 8-K dated May 6, 2003 to furnish Nexen Inc.'s press
release announcing its first quarterly results for fiscal 2003.
During the quarter ended June 30, 2003, Nexen Inc. did not file any reports on
Form 8-K.
36
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 24, 2003.
NEXEN INC.
/s/ Charles W. Fischer
-------------------------------------
Charles W. Fischer
President and Chief Executive Officer
(Principal Executive Officer)
/s/ Michael J. Harris
-------------------------------------
Michael J. Harris
Controller
(Principal Accounting Officer)
37
CERTIFICATIONS
I, Charles W. Fischer, President and Chief Executive Officer, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Nexen Inc.
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and cash
flows of the registrant as of, and for, the periods presented in this
quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
(a) designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities,
particularly during the period in which this quarterly report is being
prepared;
(b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
quarterly report (the "Evaluation Date"); and
(c) presented in this quarterly report our conclusions about the effectiveness
of the disclosure controls and procedures based on our evaluation as of the
Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):
(a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to record,
process, summarize and report financial data and have identified for the
registrant's auditors any material weaknesses in internal controls; and
(b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and material
weaknesses.
Date: July 24, 2003 /s/ Charles W. Fischer
-------------------------------------
Charles W. Fischer
President and Chief Executive Officer
38
CERTIFICATIONS
I, Marvin F. Romanow, Executive Vice-President, and Chief Financial Officer,
certify that:
1. I have reviewed this quarterly report on Form 10-Q of Nexen Inc.
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and cash
flows of the registrant as of, and for, the periods presented in this
quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
(a) designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities,
particularly during the period in which this quarterly report is being
prepared;
(b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
quarterly report (the "Evaluation Date"); and
(c) presented in this quarterly report our conclusions about the effectiveness
of the disclosure controls and procedures based on our evaluation as of the
Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):
(c) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to record,
process, summarize and report financial data and have identified for the
registrant's auditors any material weaknesses in internal controls; and
(d) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and material
weaknesses.
Date: July 24, 2003 /s/ Marvin F. Romanow
----------------------------
Marvin F. Romanow
Executive Vice President
and Chief Financial Officer
39