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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
|X| QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934 For the quarterly period ended March 31, 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
[LOGO OMITTED]
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 April 30, 2003, there were 123,285,023 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 Months Ended March 31, 2003 and 2002.............................. 3
Unaudited Consolidated Balance Sheet as at March 31, 2003
and December 31, 2002................................................... 4
Unaudited Consolidated Statement of Cash Flows for the
Three Months Ended March 31, 2003 and 2002.............................. 5
Unaudited Consolidated Statement of Shareholders' Equity for the
Three Months Ended March 31, 2003 and March 31, 2002.................... 6
Notes to Unaudited Consolidated Financial Statements.................... 7-16
Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations.................................................... 17-27
Item 3. Quantitative and Qualitative Disclosures about Market Risk................... 28
Item 4. Controls and Procedures...................................................... 28
PART II OTHER INFORMATION
Item 4. Submission of Matters to a Vote of Security Holders.......................... 29
Item 6. Exhibits and Reports on Form 8-K............................................. 29
Unless we indicate otherwise, all dollar amounts ($) are in Canadian dollars,
and production and reserves are our working interest before royalties. On March
31, 2003, the noon-day exchange rate for Cdn $1.00 was US $0.6806 as reported by
the Bank of Canada. This report should be read in conjunction with our 2002
Annual Report on Form 10-K.
Below is a list of terms specific to the oil and gas industry. They are used
throughout the Form 10-Q.
/d = per day mboe = thousand barrels of oil equivalent
bbl = barrel mmboe = million barrels of oil equivalent
mbbls = thousand barrels mcf = thousand cubic feet
mmbbls = million barrels mmcf = million cubic feet
mmbtu = million British thermal units bcf = billion cubic feet
km = kilometre WTI = West Texas Intermediate
boe = barrels of oil equivalent NGL = natural gas liquid
Oil equivalents are used to compare quantities of natural gas with crude oil by
expressing them in a common unit. To calculate equivalents, we use 1 bbl = 6 mcf
of natural gas.
Electronic copies of our filings with the Securities Exchange Commission (from
November 8, 2002 onward) are available, free of charge, on our web site
(www.nexeninc.com). Filings prior to November 8, 2002 are available, free of
charge, upon request, by contacting our investor relations department at (403)
699-5931.
2
NEXEN INC.
UNAUDITED CONSOLIDATED STATEMENT OF INCOME
FOR THE THREE MONTHS ENDED MARCH 31
Cdn$ millions
2003 2002
- --------------------------------------------------------------------------------
REVENUES
Net Sales (Note 1) 834 541
Marketing and Other (Note 1) 175 122
Gain on Disposition of Assets -- 13
-------------------
1,009 676
-------------------
EXPENSES
Operating 204 186
Transportation and Other (Note 1) 130 116
General and Administrative 37 38
Depreciation, Depletion and Amortization 191 180
Exploration 41 37
Interest (Note 4) 28 23
-------------------
631 580
-------------------
INCOME BEFORE INCOME TAXES 378 96
-------------------
PROVISION FOR INCOME TAXES
Current 56 45
Future 71 (14)
-------------------
127 31
-------------------
NET INCOME 251 65
DIVIDENDS ON PREFERRED SECURITIES, NET OF INCOME TAXES 11 11
-------------------
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS 240 54
===================
EARNINGS PER COMMON SHARE ($/share)
Basic (Note 7) 1.95 0.44
===================
Diluted (Note 7) 1.94 0.44
===================
SEE ACCOMPANYING NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS.
3
NEXEN INC.
UNAUDITED CONSOLIDATED BALANCE SHEET
Cdn$ millions
MARCH 31 DECEMBER 31
2003 2002
- -------------------------------------------------------------------------------
ASSETS
CURRENT ASSETS
Cash and Short-Term Investments 96 59
Accounts Receivable (Note 2) 1,665 988
Inventories and Supplies (Note 3) 174 256
Other 22 26
----------------------
Total Current Assets 1,957 1,329
PROPERTY, PLANT AND EQUIPMENT 4,988 4,863
GOODWILL 36 36
FUTURE INCOME TAX ASSETS 239 263
DEFERRED CHARGES AND OTHER ASSETS 79 69
----------------------
7,299 6,560
======================
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Short-Term Borrowings (Note 4) 32 18
Accounts Payable and Accrued Liabilities 1,736 1,194
Accrued Interest Payable 23 39
Dividends Payable 9 9
----------------------
Total Current Liabilities 1,800 1,260
----------------------
LONG-TERM DEBT (Note 4) 1,812 1,844
FUTURE INCOME TAX LIABILITIES 935 873
DISMANTLEMENT AND SITE RESTORATION 188 191
OTHER DEFERRED CREDITS AND LIABILITIES 45 44
SHAREHOLDERS' EQUITY (Note 6)
Preferred Securities 724 724
Common Shares, no par value
Authorized: Unlimited
Outstanding: 2003 - 123,137,779 shares
2002 - 122,965,830 shares 445 440
Retained Earnings 1,300 1,069
Cumulative Foreign Currency Translation
Adjustment 50 115
----------------------
Total Shareholders' Equity 2,519 2,348
----------------------
COMMITMENTS AND CONTINGENCIES (Note 8)
7,299 6,560
======================
SEE ACCOMPANYING NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS.
4
NEXEN INC.
UNAUDITED CONSOLIDATED STATEMENT OF CASH FLOWS
FOR THE THREE MONTHS ENDED MARCH 31
Cdn$ millions
2003 2002
- --------------------------------------------------------------------------------
OPERATING ACTIVITIES
Net Income 251 65
Charges and Credits to Income not Involving Cash 271 153
Exploration Expense 41 37
Changes in Non-Cash Working Capital (66) (199)
Other (15) 24
---------------
482 80
FINANCING ACTIVITIES
Proceeds from Long-Term Debt 124 793
Repayment of Long-Term Debt -- (420)
Proceeds from (Repayment of) Short-Term Borrowings, Net 14 (51)
Dividends on Preferred Securities (18) (18)
Dividends on Common Shares (9) (9)
Issue of Common Shares 5 10
Other -- (22)
---------------
116 283
INVESTING ACTIVITIES
Capital Expenditures
Exploration and Development (325) (323)
Proved Property Acquisitions (164) --
Chemicals, Corporate and Other (4) (24)
Proceeds on Disposition of Assets -- 29
Changes in Non-Cash Working Capital (3) 19
---------------
(496) (299)
EFFECT OF EXCHANGE RATE CHANGES ON CASH AND
SHORT-TERM INVESTMENTS (65) 5
---------------
INCREASE IN CASH AND SHORT-TERM INVESTMENTS 37 69
CASH AND SHORT-TERM INVESTMENTS - BEGINNING OF PERIOD 59 61
---------------
CASH AND SHORT-TERM INVESTMENTS - END OF PERIOD 96 130
===============
Interest Paid 50 22
===============
Income Taxes Paid 54 40
===============
SEE ACCOMPANYING NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS.
5
NEXEN INC.
UNAUDITED CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY
FOR THE THREE MONTHS ENDED MARCH 31, 2003 AND MARCH 31, 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 -- 1 -- --
Issue of Common Shares -- 4 -- --
Net Income -- -- 251 --
Dividends on Preferred Securities, Net of
Income Taxes -- -- (11) --
Dividends on Common Shares -- -- (9) --
Translation Adjustment, Net of Income Taxes -- -- -- (65)
------------------------------------------------------
MARCH 31, 2003 724 445 1,300 50
======================================================
Cumulative
Foreign
Currency
Preferred Common Retained Translation
Securities Shares Earnings Adjustment
- -------------------------------------------------------------------------------------------------------------
DECEMBER 31, 2001 724 389 697 94
Exercise of Stock Options -- 5 -- --
Issue of Common Shares -- 5 -- --
Net Income -- -- 65 --
Dividends on Preferred Securities, Net of
Income Taxes -- -- (11) --
Dividends on Common Shares -- -- (9) --
Translation Adjustment, Net of Income Taxes -- -- -- (1)
------------------------------------------------------
MARCH 31, 2002 724 399 742 93
======================================================
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 10. In the opinion of
management, the Unaudited Consolidated Financial Statements contain all
adjustments of a normal and recurring nature necessary to present fairly Nexen
Inc.'s (Nexen, we or our) financial position at March 31, 2003 and the results
of our operations and our cash flows for the three months ended March 31, 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. Actual results can differ from those
estimates. The results of operations and cash flows for the three months ended
March 31, 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
Ended March 31
2003 2002
- --------------------------------------------------------------------------------
Increase to:
Net Sales 10 8
Marketing and Other 119 104
Transportation and Other 129 112
------------------
Certain comparative figures have been reclassified to ensure consistency with
current year presentation.
7
2. ACCOUNTS RECEIVABLE
March 31 December 31
2003 2002
- --------------------------------------------------------------------------------
Trade
Oil and Gas
Marketing 1,252 574
Other 334 330
Chemicals and Other 53 59
---------------------------
1,639 963
Non-Trade 35 34
---------------------------
1,674 997
Allowance for Doubtful Accounts (9) (9)
---------------------------
1,665 988
===========================
3. INVENTORIES AND SUPPLIES
March 31 December 31
2003 2002
- --------------------------------------------------------------------------------
Finished Products
Oil and Gas
Marketing 59 130
Other 3 --
Chemicals and Other 6 13
---------------------------
68 143
Work in Process 6 6
Field Supplies 100 107
---------------------------
174 256
===========================
4. LONG-TERM DEBT
March 31 December 31
2003 2002
- --------------------------------------------------------------------------------
Unsecured Syndicated Term Credit Facilities 73 --
Unsecured Redeemable Notes, due 2004 (a) 331 355
Unsecured Redeemable Debentures, due 2006 104 108
Unsecured Redeemable Medium Term Notes, due 2007 150 150
Unsecured Redeemable Medium Term Notes, due 2008 125 125
Unsecured Redeemable Notes, due 2028 294 316
Unsecured Redeemable Notes, due 2032 735 790
---------------------------
1,812 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 March 31, 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 March 31, 2003, we sold
$220 million of accounts receivable proceeds (December 31, 2002 - $178 million).
The retained credit exposure of $22 million (December 31, 2002 - $18 million) is
included in short-term borrowings.
8
(C) INTEREST EXPENSE
Three Months
Ended March 31
2003 2002
- --------------------------------------------------------------------------------
Long-Term Debt 34 25
Other 2 1
----------------
Total 36 26
Less: Capitalized 8 3
----------------
28 23
================
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
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 March 31, 2003, the fair value of these
instruments was $5 million. We will recognize the realized gains or losses on
these contracts in the same periods as the hedged production is sold.
Hedged Volumes Period Fixed Price (US$)
- --------------------------------------------------------------------------------
5,000 bbls/d April 2003 - March 2004 28.50/bbl
12,000 mmbtu/d April 2003 - March 2004 5.35/mmbtu
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 months ended March 31, 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
Ended March 31
2003 2002
- --------------------------------------------------------------------------------
Net Income Attributable to Common Shareholders
As Reported 240 54
Less: Fair Value of Stock Options 6 6
------------------
Pro Forma 234 48
==================
Earnings Per Common Share ($/share)
Basic as Reported 1.95 0.44
==================
Pro Forma 1.90 0.40
==================
Diluted as Reported 1.94 0.44
==================
Pro Forma 1.89 0.39
==================
(B) DIVIDENDS
Dividends per common share for the three months ended March 31, 2003 were $0.075
(2002 - $0.075).
9
7. EARNINGS PER COMMON SHARE
We calculate earnings per common share using Net Income Attributable to Common
Shareholders and the weighted-average number of common shares outstanding. We
calculate diluted earnings per common share using Net Income Attributable to
Common Shareholders and the weighted-average number of diluted common shares
outstanding.
Three Months
Ended March 31
(millions of shares) 2003 2002
- -------------------------------------------------------------------------------
Weighted-average number of common shares outstanding 123.1 121.5
Shares issuable pursuant to stock options 5.1 5.8
Shares to be purchased from proceeds of stock options (4.4) (4.5)
---------------
Weighted-average number of diluted common shares outstanding 123.8 122.8
===============
In calculating diluted earnings per common share, we excluded 4.2 million
options (2002 - 2.9 million) because the exercise price was greater than the
average market price of our common shares in those periods. During the periods
presented, outstanding stock options were the only dilutive instrument.
8. COMMITMENTS AND CONTINGENCIES
As described in Note 10 to the Audited Consolidated Financial Statements
included in our 2002 Annual Report on Form 10-K, there are a number of lawsuits
and claims pending, the ultimate results of which cannot be ascertained at this
time. We record costs as they are incurred or become determinable. We believe
the resolution of these matters would not have a material adverse effect on our
consolidated financial position or results of operations.
10
9. OPERATING SEGMENTS AND RELATED INFORMATION
Nexen is involved in activities relating to Oil and Gas, Syncrude and Chemicals
in various geographic locations as described in Note 15 to the Audited
Consolidated Financial Statements included in our 2002 Annual Report on Form
10-K.
MARCH 31, 2003
(Cdn$ millions)
Corporate
and
Oil and Gas Syncrude Chemicals Other Total
- ------------------------------------------------------------------------------------------------------------------------------------
United Other
Yemen Canada States Australia Countries(1) Marketing(2)
------------------------------------------------------------
Net Sales 228 208 184 28 17 8 63 98 -- 834
Marketing and Other -- 1 -- -- -- 181 -- -- (7)(3) 175
Gain on Disposition of Assets -- -- -- -- -- -- -- -- -- --
----------------------------------------------------------------------------------------------------
Total Revenues 228 209 184 28 17 189 63 98 (7) 1,009
Less: Expenses
Operating 21 40 21 13 4 7 32 66 -- 204
Transportation and Other -- -- 1 -- -- 119 -- 10 -- 130
General and Administrative 1 8 3 -- 5 9 -- 5 6 37
Depreciation, Depletion and
Amortization 42 64 49 6 6 3 3 14 4 191
Exploration 2 18 15 -- 6(4) -- -- -- -- 41
Interest -- -- -- -- -- -- -- -- 28 28
----------------------------------------------------------------------------------------------------
Income (Loss) before Income
Taxes 162 79 95 9 (4) 51 28 3 (45) 378
==========================================================================================
Less: Provision for Income
Taxes(5) 127
------
Net Income 251
======
Identifiable Assets 601 2,179 1,561 54 146 1,506(6) 565 501 186 7,299
====================================================================================================
Capital Expenditures
Development and Other 54 115 55 -- 5 -- 41 1 3 274
Exploration 1 18 25 1 10 -- -- -- -- 55
Proved Property Acquisitions -- -- 164(7) -- -- -- -- -- -- 164
----------------------------------------------------------------------------------------------------
55 133 244 1 15 -- 41 1 3 493
====================================================================================================
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 losses of $9
million.
(4) Includes exploration activities primarily in Nigeria and Colombia.
(5) Includes Yemen cash taxes of $51 million.
(6) Approximately 84% of Marketing's identifiable assets are accounts
receivable.
(7) On March 27, 2003 we acquired the residual 40% interest in Aspen in the
Gulf of Mexico for US $109 million.
11
MARCH 31, 2002
(Cdn$ millions)
Corporate
and
Oil and Gas Syncrude Chemicals Other(1) Total
- ------------------------------------------------------------------------------------------------------------------------------------
United Other
Yemen Canada States Australia Countries(2) Marketing
----------------------------------------------------------
Net Sales 164 138 61 22 19 -- 50 85 2 541
Marketing and Other -- 1 -- -- -- 117 -- 1 3(3) 122
Gain on Disposition of
Assets -- -- -- -- -- -- -- -- 13(4) 13
----------------------------------------------------------------------------------------------------
Total Revenues 164 139 61 22 19 117 50 86 18 676
Less: Expenses
Operating 19 41 23 14 5 -- 27 55 2 186
Transportation and Other -- -- -- -- -- 104 -- 10 2 116
General and Administrative 1 7 2 -- 5 7 -- 5 11 38
Depreciation, Depletion and
Amortization 38 65 32 11 12 2 3 13 4 180
Exploration 3 13 15 -- 6(5) -- -- -- -- 37
Interest -- -- -- -- -- -- -- -- 23 23
----------------------------------------------------------------------------------------------------
Income (Loss) before Income
Taxes 103 13 (11) (3) (9) 4 20 3 (24) 96
===========================================================================================
Less: Provision for Income
Taxes(6) 31
------
Net Income 65
======
Identifiable Assets 553 2,188 976 74 188 766(7) 405 528 175 5,853
====================================================================================================
Capital Expenditures
Development and Other 43 92 79 15 10 -- 21 16 8 284
Exploration 14 21 21 -- 7 -- -- -- -- 63
----------------------------------------------------------------------------------------------------
57 113 100 15 17 -- 21 16 8 347
====================================================================================================
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.
(3) Includes interest income of $2 million and foreign exchange gains of $1
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 $37 million.
(7) Approximately 67% of Marketing's identifiable assets are accounts
receivable.
12
10. DIFFERENCES BETWEEN CANADIAN AND US GENERALLY ACCEPTED ACCOUNTING
PRINCIPLES
The Unaudited Consolidated Financial Statements have been prepared in accordance
with Canadian GAAP. Canadian principles differ from US GAAP as follows:
(A) UNAUDITED CONSOLIDATED STATEMENT OF INCOME
Three Months
Ended March 31
2003 2002
- --------------------------------------------------------------------------------------------------
Net Income - Canadian GAAP 251 65
Impact of US Principles:
Dividends on Preferred Securities, Net of Income Tax
of $7 million (2002 - $7 million)(i) (11) (11)
Depreciation, Net of Income Tax of $1 million
(2002 - $nil) (ii); (viii) (14) (12)
----------------------
Net Income - US GAAP, before Cumulative Effect of a
Change in Accounting Principle 226 42
Cumulative Effect of a Change in Accounting Principle on
periods up to December 31, 2002, Net of Income Tax of
$25 million (viii) (37) --
----------------------
Net Income - US GAAP (vii) 189 42
======================
Earnings per Common Share - US GAAP ($/share)
Basic 1.53 0.35
======================
Diluted 1.53 0.34
======================
Pro forma Earnings - Fair-value Method of Accounting for Stock Options
Net Income
As Reported 189 42
Less: Fair Value of Stock Options 6 6
----------------------
Pro Forma 183 36
======================
Earnings Per Common Share ($/share)
Basic as Reported 1.53 0.35
======================
Pro Forma 1.48 0.30
======================
Diluted as Reported 1.53 0.34
======================
Pro Forma 1.48 0.29
======================
(B) UNAUDITED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
Three Months
Ended March 31
2003 2002
- --------------------------------------------------------------------------------------------------
Net Income - US GAAP 189 42
Translation Adjustment, Net of Income Tax of $34
million (2002 - $nil) (i); (iv) (25) (1)
Unrealized Mark-to-Market Gains, Net of Income
Tax of $2 million (2002 - $nil) (iii) 3 --
----------------------
Comprehensive Income 167 41
======================
13
(C) UNAUDITED CONSOLIDATED BALANCE SHEET
March 31, 2003 December 31, 2002
- ------------------------------------------------------------------------------------------------------------------------------
Canadian US Canadian US
GAAP GAAP GAAP GAAP
--------------------------- ------------------------------
Assets
Accounts Receivable (iii) 1,665 1,672 988 990
Property, Plant and Equipment, Net (ii); (viii) 4,988 5,293 4,863 5,064
Deferred Charges and Other Assets (i); (v) 79 81 69 70
Liabilities and Shareholders' Equity
Accounts Payable and Accrued Liabilities (iii); (vi) 1,736 1,742 1,194 1,200
Long-Term Debt (i); (v) 1,812 2,495 1,844 2,575
Future Income Tax Liabilities (i)-- (viii) 935 922 873 876
Dismantlement and Site Restoration (viii) 188 -- 191 191
Asset Retirement Obligation (viii) -- 370 -- --
Preferred Securities (i) 724 -- 724 --
Retained Earnings (i); (ii); (v); (viii) 1,300 1,460 1,069 1,280
Cumulative Foreign Currency Translation
Adjustment (iv) 50 -- 115 --
Accumulated Other Comprehensive Income (i); (iii); (iv); (v) -- 70 -- 92
------------------------------------------------------------
(D) UNAUDITED CONSOLIDATED STATEMENT OF CASH FLOWS
Under US principles, dividends on preferred securities of $18 million for the
three months ended March 31, 2003 (March 31, 2002 - $18 million) that are
included in financing activities would be reported in operating activities.
Under US principles, geological and geophysical costs of $13 million for the
three months ended March 31, 2003 (March 31, 2002 - $20 million) that are
included in investing activities would be reported in operating activities.
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 receivable at March 31, 2003 is $5 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
hedged production, as described in Note 5. As of March 31, 2003, the
fair value included in accumulated other comprehensive income was an
unrealized gain of $3 million, net of income taxes. Approximately $2
million of the unrealized gain will be moved to net sales in the next
nine months as the underlying production is delivered or the hedge
expires. For the period ended March 31, 2003, gains related to the
ineffectiveness of cash flow hedges were included in net sales and were
immaterial.
14
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 March 31, 2003 is $2
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, 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.
v. Under US principles, discounts on long-term debt are classified as a
reduction of long-term debt rather than as deferred charges and other
assets.
vi. 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 March 31, 2003.
vii. Under US principles, gains and losses on the disposition of assets are
shown as operating expenses rather than revenues.
viii. 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 Consolidated Statement of Income. Under the
old accounting rules, our results would have been:
Three Months
Ended March 31
2003
-------------------------------------------------------------------------------------------------------------------
Net Income
As Reported 189
Cumulative Effect of Change in Accounting Principle, Net of Income Taxes of $25 million 37
Additional Depreciation, Depletion and Amortization, and Accretion, Net of Income Taxes
of $1 million 2
---------------
Adjusted 228
===============
Earnings per Common Share ($/share)
Basic as Reported 1.53
===============
Adjusted 1.85
===============
Diluted as Reported 1.53
===============
Adjusted 1.84
===============
Had FAS 143 been applied during all periods presented, our asset
retirement obligation, including current obligations of $14 million at
December 31, 2002 and March 31, 2003, would have been reported as
follows:
As Reported Pro-forma
---------------------------------------------------------------------
January 1, 2002 182 364
December 31, 2002 205 390
March 31, 2003 384 384
----------------------------
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.
15
Had FAS 143 been applied during all periods presented, our March 31,
2002 results would have been reported as follows:
Three Months
Ended March 31
2002
-------------------------------------------------------------------------------------------------------------------
Net Income
As Reported 42
Less: Additional Depreciation, Depletion and Amortization, and Accretion, Net of Income Taxes
of $nil 1
------------
Adjusted 41
============
Earnings per Common Share ($/share)
Basic as Reported 0.35
============
Adjusted 0.34
============
Diluted as Reported 0.34
============
Adjusted 0.33
============
16
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 10 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.
FIRST QUARTER HIGHLIGHTS
We achieved record quarterly financial results for the first quarter of 2003,
fueled by attractive oil and gas prices, strong growth in our US operations, and
strong performance from our marketing operations. We also made significant
progress on major growth projects in the deep-water Gulf of Mexico, offshore
Nigeria and in the Athabasca oil sands.
Following are the quarterly highlights:
o Increased net income by 286% and cash flow from operations by 121% from
first quarter 2002.
o Grew production, after royalties, with higher margin barrels from Aspen.
o Acquired the remaining 40% interest in Aspen and the remaining interests in
five exploration blocks in the greater Aspen area.
Three Months
Ended March 31
(Cdn$ millions) 2003 2002
- -------------------------------------------------------------------------------
Net Sales 834 541
Net Income 251 65
Earnings per Common Share - Basic ($/share) 1.95 0.44
Earnings per Common Share - Diluted ($/share) 1.94 0.44
Cash Flow from Operations (1) 563 255
Production, before Royalties (mboe/d) 264 267
Production, after Royalties (mboe/d) 177 175
Capital Expenditures (2) 493 347
---------------------------
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
Ended March 31
(Cdn$ millions) 2003 2002
----------------------------------------------------------
Cash Flow from Operating Activities 482 80
Changes in Non-Cash Working Capital 66 199
Other 15 (24)
-------------------
Cash Flow from Operations 563 255
===================
(2) Includes $164 million relating to the purchase of the remaining working
interest in the Aspen field.
17
FINANCIAL RESULTS
CHANGE IN NET INCOME
(Cdn$ millions) 2003 VS 2002
- -------------------------------------------------------------------------------
NET INCOME AT MARCH 31, 2002 65
=============
Favourable (unfavourable) variances:
Cash Items:
Production volumes, after royalties:
Crude oil 6
Natural gas -
Crude oil sales volumes, after royalties (12)
Commodity prices:
Crude oil 176
Natural gas 104
Oil and gas operating expense:
Conventional 3
Synthetic (5)
Marketing 50
Chemicals 1
General and administrative 1
Interest expense (5)
Current income taxes (11)
-------------
Total Cash Variance 308
Non-Cash Items:
Depreciation, depletion and amortization
Oil and Gas (10)
Other (1)
Exploration expense (4)
Future income taxes (85)
Gain on disposition of assets (13)
Other (9)
-------------
Total Non-Cash Variance (122)
-------------
NET INCOME AT MARCH 31, 2003 251
=============
BEST QUARTERLY RESULTS IN NEXEN'S HISTORY
Our record results for the first quarter of 2003 are due to strong commodity
prices, a solid contribution from our marketing division and the addition of
higher margin production volumes. In 2002, our crude oil sales volumes included
the sale of 2001 year-end inventories. This resulted in lower crude oil sales
volumes for the first quarter of 2003 relative to the prior year. Significant
variances in net income are explained further in the following sections.
18
OIL AND GAS
PRODUCTION
Three Months Three Months
Ended March 31 Ended March 31
2003 2002
- ------------------------------------------------------------------------------------------------
Before After Before After
Royalties Royalties Royalties Royalties
-------------------------------------------------------------
Oil and Liquids (mbbls/d)
Yemen 116.0 55.4 118.4 55.8
Canada 49.2 37.3 58.9 45.1
United States 21.7 19.1 10.1 8.4
Australia 8.0 6.5 4.2 3.8
Other Countries 6.3 5.3 10.0 7.1
Syncrude 13.6 13.5 16.6 16.4
-------------------------------------------------------------
214.8 137.1 218.2 136.6
-------------------------------------------------------------
Natural Gas (mmcf/d)
Canada 161 124 175 134
United States 135 114 119 99
-------------------------------------------------------------
296 238 294 233
-------------------------------------------------------------
Total (mboe/d) 264 177 267 175
=============================================================
HIGH-MARGIN BARRELS INCREASED NET INCOME BY $6 MILLION
Production after royalties grew with the addition of low royalty production from
Aspen. These low royalty, low operating cost barrels from Aspen contributed 11%
to cash flow and will allow us to grow our margins even if commodity prices
remain constant. With the addition of further high-margin barrels from Aspen in
the deep waters of the Gulf of Mexico late in the quarter, production is
expected to continue growing in 2003. On a before royalties basis, first quarter
2003 production decreased slightly compared to first quarter last year, as
growth in the US was offset by temporary shortfalls in Yemen, Syncrude and at
Hay in Canada. This is further explained below.
MASILA BLOCK IN YEMEN
o Downtime to replace pump equipment reduced production rates.
o Development drilling on the Masila Block allowed us to exit the quarter at
120,000 bbls/d, net to Nexen.
o With additional service rig capacity and development drilling, production
volumes have been restored and we expect Yemen to achieve its full year
production target of 118,000 bbls/d, net to Nexen.
US GULF OF MEXICO
o Our deep-water Aspen project, which came onstream in December 2002, boosted
US production in the first quarter 2003 by 16,000 boe/d. Production at
Aspen was ramped up over the quarter to 18,000 boe/d in March.
o Acquisition of the additional 40% interest in Aspen added 12,000 boe/d
starting March 27th. To lock in a portion of our return on this
acquisition, we sold approximately 60% of the incremental production
forward for the next 12 months at a weighted-average price of US $29.50 per
boe. Our cash netback(1) on these hedged volumes is approximately US $23
per boe.
o Aspen is currently producing 30,000 boe/d.
o In the shallow waters of the Gulf, base production shortfalls experienced
in 2002 were mitigated through development drilling and workover activity.
o Production from Eugene Island 295, previously shut-in due to hurricane
damage, was brought back onstream in late February. We installed rental
production equipment on the undamaged drilling platform allowing production
earlier than anticipated.
- ----------------
(1) Netback is defined as sales price less all per unit costs including
royalties, operating expenses and cash taxes. This is calculated using our
working interest production before royalties.
19
CANADA
o First quarter production of 76,000 boe/day averaged 14% lower than first
quarter last year.
o Cold weather in the first two months of 2003 caused freezing of flowlines
and equipment, resulting in temporary shortfalls for our heavy oil and
shallow gas assets.
o Corrosion repair work and a turnaround at Hay added to these temporary
shortfalls. Following a successful winter drilling program, the Hay field
produced 9,600 bbls/d in April.
o Increasing water cuts at some of our heavy oil properties also contributed
to the decline.
o Our current production volumes in Canada are 78,000 boe/d. We are
considering the sale of minor, non-core producing properties to determine
if incremental value can be realized.
BUFFALO OFFSHORE AUSTRALIA
o First quarter 2002 production was reduced because of a two-week shut-in for
drilling and a three-week shut-in for mechanical problems.
o Successful infill drilling late in the second quarter of 2002 continued
delivering strong production in 2003.
o Buffalo is expected to be fully depleted in 2004.
SYNCRUDE
o Temporary production shortfalls in the first quarter 2003 were caused by
unscheduled maintenance on the hydrotreater and heat exchanger, the delay
of the December 2002 turnaround and the advancement of the coker shutdown
to March 27th.
o Production is expected to return to 18,000 to 19,000 bbls/d (net to Nexen)
in early May after the completion of the coker turnaround.
o With completion of the coker turnaround, we expect our share of Syncrude
production to average approximately 16,600 bbls/d in 2003.
COMMODITY PRICES
Three Months
Ended March 31
2003 2002
- ------------------------------------------------------------------------------
CRUDE OIL
West Texas Intermediate (US$/bbl) 33.86 21.64
---------------------
Differentials (US$/bbl):
Masila 2.99 1.11
Heavy Oil 8.23 5.74
Producing Assets(1) (Cdn$/bbl):
Yemen 45.69 32.75
Canada 39.48 25.42
United States 46.00 32.25
Syncrude 51.84 34.10
Australia 48.13 33.72
Nigeria 49.53 33.40
Colombia 48.01 30.13
Corporate Average(1) (Cdn$/bbl) 44.93 31.00
---------------------
NATURAL GAS
New York Mercantile Exchange (US$/mmbtu) 6.32 2.50
---------------------
Canada (Cdn$/mcf)(1) 6.77 2.80
United States (Cdn$/mcf)(1) 10.22 4.14
Corporate Average (Cdn$/mcf)(1) 8.35 3.34
---------------------
Note:
(1) Prices based on working interest production before royalties.
20
HIGHER REALIZED PRICES ADDED $280 MILLION TO NET INCOME
STRONG CRUDE OIL PRICES
o During the first quarter of 2003, the Middle East war premium, low
inventory levels and supply concerns, compounded by weather-related demand
put upward pressure on WTI until late March.
o During February, US inventory levels and temperatures at their lowest
levels in ten years drove WTI to highs close to US $40 per barrel.
o Late in March, WTI fell to around US $28 per barrel. The war premium
decreased and supply uncertainty subsided as US troops secured key oil
fields in Iraq and additional supply from OPEC moved into the North
American market.
HEAVY OIL DIFFERENTIALS
o The heavy differential remained relatively narrow in early 2003 relative to
WTI. Increasing heavy supply from Venezuela and Saudi Arabia had limited
impact until late February. The recent ramp-up of asphalt producing
refineries and delayed start-up of new production from Canadian heavy oil
projects offset the impact of the increased supply, keeping the heavy
differential narrower than expected.
o The heavy differential is expected to remain relatively narrow with peak
seasonal demand in the spring and summer.
o Approximately 13% of our crude oil production is Canadian heavy oil.
MASILA DIFFERENTIAL
o Our Masila crude is typically priced in the market based on North Sea
Brent.
o In early 2003, the Brent/WTI differential widened as OPEC production quota
increases alleviated supply concerns in Europe and labour unrest in
Venezuela caused supply disruptions on the US Gulf coast.
o Late in the quarter, the Brent/WTI differential began to narrow as the
incremental OPEC volumes made their way into the North American market.
NATURAL GAS PRICES
o Cold weather in early 2003 combined with low storage levels and supply
concerns drove NYMEX natural gas prices over US $10 per mmbtu in February
2003.
o Prices have receded from these highs during March and April but have
remained above US $5.00. Warmer weather has decreased demand. Inventory
levels remain at historically low levels.
o We expect natural gas prices to remain strong relative to historical prices
due to inventory and supply concerns.
OPERATING COSTS
(Based on working interest production before royalties)
Three Months
Ended March 31
(Cdn$/boe) 2003 2002
- -------------------------------------------------------------------------------
Conventional Oil and Gas 4.40 4.45
Synthetic Crude Oil
Syncrude 26.40 17.97
Total Oil and Gas(1) 5.54 5.27
---------------------
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.
OPERATING COSTS DECREASED NET INCOME BY $2 MILLION
o Decreased conventional operating costs reflect lower operating costs per
barrel for Aspen production as well as fewer workovers in the Gulf of
Mexico in 2003.
o Higher operating costs at Syncrude are due to volume shortfalls, costs of
unscheduled maintenance and higher natural gas input prices.
21
DEPRECIATION, DEPLETION AND AMORTIZATION (DD&A)
(Based on working interest production before royalties)
Three Months
Ended March 31
(Cdn$/boe) 2003 2002
- -----------------------------------------------------------------------------
Conventional Oil and Gas 7.44 7.01
Synthetic Crude Oil
Syncrude 2.67 2.15
Total Oil and Gas(1) 7.19 6.72
---------------------
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 BY $10 MILLION
o Higher 2002 finding and development costs coupled with our changing
production mix, as a larger portion of our production comes from more
capital-intensive but higher margin properties, has increased our depletion
charge.
EXPLORATION EXPENSE
Three Months
Ended March 31
(Cdn$ millions) 2003 2002
- ----------------------------------------------------------------------------
Seismic 13 20
Unsuccessful Drilling 13 5
Other 15 12
-----------------
Total Exploration Expense 41 37
=================
Total Exploration Capital 55 63
-----------------
HIGHER EXPLORATION EXPENSE DECREASED NET INCOME BY $4 MILLION
o Activity in the quarter included dry hole costs in Canada and seismic
acquisition in the Gulf of Mexico and Canada.
o Three deep gas wells were expensed in Canada during the quarter.
OIL AND GAS MARKETING
Three Months
Ended March 31
(Cdn$ millions) 2003 2002
- ------------------------------------------------------------------------------
Revenue 182 117
Transportation (119) (104)
---------------------
Net Revenue 63 13
=====================
Marketing contribution to Income before Income Tax 51 4
---------------------
Physical Sales Volumes (excluding intra-segment
transactions)
Crude Oil (mboe/d) 470 369
Natural Gas (mmcf/d) 3,614 2,536
Value-at-Risk
Quarter End 18 15
High 31 19
Low 16 14
Average 21 15
---------------------
22
HIGHER NET MARKETING REVENUE INCREASED NET INCOME BY $50 MILLION
During the first quarter of 2003, our marketing operation contributed
significantly to our results.
o We capitalized on the widening gas price differential between eastern and
western North America. We held pipeline capacity allowing us to move
western Canadian gas to eastern Canada.
o We also profited from a flattening of the Brent and WTI forward curve as
the war premium eroded. In addition, we profited from a widening in the
Brent/Dubai spread, which resulted from increased supply of lower quality
Saudi crude oil production and disruptions in Nigeria.
o We sold gas in storage of 8.5 billion cubic feet during the quarter
allowing us to recognize gains that were previously unrecognized.
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 March 31, 2003, the fair value of our derivative energy contracts totalled
$79 million. The following table shows the valuation methods underlying these
contracts together with timing of contract maturity:
(Cdn$ millions) MATURITY
- -----------------------------------------------------------------------------------------------------------------------------
less than greater than
1 year 1-3 years 4-5 years 5 years Total
-------------------------------------------------------------------
Prices:
Actively quoted 185 (2) (12) -- 171
From other external sources (125) 16 17 -- (92)
Based on models and other valuation methods -- -- -- -- --
-------------------------------------------------------------------
Total 60 14 5 -- 79
===================================================================
Contract maturities vary from a single day up to five years. The majority of our
contracts mature in less than one year. 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 8 11 37 56
Net losses (gains) on contracts closed 31 (11) -- 20
Changes in valuation techniques and assumptions(1) -- -- -- --
------------------------------------------------------------------
Fair value at March 31, 2003 42 -- 37 79
==================================================================
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 subject 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 March 31, 2003, our value-at-risk with respect to these positions
was $18 million (December 31, 2002 - $19 million).
23
COMPOSITION OF NET MARKETING REVENUE
Three Months
Ended March 31
(Cdn$ millions) 2003
- -----------------------------------------------------------------------------
Derivative energy contracts 56
Non-derivative energy contracts 6
Power 1
--------------
Net Marketing Revenue 63
==============
CHEMICALS
HIGHER OPERATING PROFIT INCREASED NET INCOME BY $1 MILLION
o Chlor-alkali operating profit increased by $6 million due to improved
demand and substantially stronger chlorine prices.
o Sodium chlorate operating profit decreased due to price erosion and
severance costs related to idling a plant at Taft.
o Expansion at Brazil contributed an additional $1 million to operating
profit.
CORPORATE EXPENSES
GENERAL AND ADMINISTRATIVE (G&A)
Three Months
Ended March 31
(Cdn$ millions) 2003 2002
- -------------------------------------------------------------------------------
General and Administrative 37 38
========================
LOWER COSTS INCREASED NET INCOME BY $1 MILLION
o Recovery of previously expensed amounts related to our Stock Appreciation
Rights plan reduced G&A by $3 million.
o These recoveries were offset by increased staffing levels associated with
growth in Marketing and capital investment programs.
INTEREST
Three Months
Ended March 31
(Cdn$ millions) 2003 2002
- ------------------------------------------------------------------------------
Interest 36 26
Less: Capitalized Interest 8 3
-----------------------
Net Interest Expense 28 23
=======================
HIGHER INTEREST EXPENSE REDUCED NET INCOME BY $5 MILLION
o Higher borrowing rate of 7.875% on our 30-year notes issued in March 2002
contributed to the increase.
o Capitalized interest increased as spending on our major development
projects in the Gulf of Mexico and Canada continued.
INCOME TAXES
EFFECTIVE TAX RATE INCREASES TO 33.6% FROM 32.2%
o The rate was lower in 2002 as the $13 million gain on the sale of our
asphalt operations was sheltered by existing capital loss carryforwards.
o Current income taxes include cash taxes in Yemen of $51 million (2002 - $37
million).
o In the first quarter of 2003 and 2002, current income taxes include federal
and provincial capital taxes in Canada.
24
CAPITAL EXPENDITURES
Capital investment during the quarter totaled $493 million, an increase of $146
million over the same period in 2002. This includes $164 million for our
acquisition of the residual 40% interest in the Aspen field. The rest of our
capital expenditures related primarily to oil and gas development ($270 million)
and exploration activities ($55 million).
UNITED STATES
In late March, we acquired the remaining 40% interest in Aspen and five
exploration blocks in the Greater Aspen area from BP Exploration and Production
Inc. for US $113 million, after closing adjustments. This acquisition increased
our interest in Aspen to 100%, established Nexen as a deep-water operator, and
increased our exploration acreage in the Greater Aspen area to over 80,000 net
acres.
The additional 40% interest added 12,000 boe per day to our production starting
March 27th. To solidify our return, we sold approximately 60% of the incremental
production forward for the next 12 months at an average price of US $29.50 per
boe. Aspen is located in 3,150 feet of water on Green Canyon Block 243. The
Aspen field came on-stream in December 2002 and is now producing 30,000 boe per
day, of which 15% is natural gas. We expect production from the field to average
25,000 boe per day in 2003.
Gunnison, our second deep-water project in the Gulf of Mexico, is on budget and
on schedule for production startup in early 2004. First production, initially
from three subsea gas wells, will increase throughout the year and reach peak
rates late next year. Approximately half of this production will be natural gas.
All 10 development wells have been drilled and completion of three subsea wells
has begun. The SPAR production facility is expected to be installed in the
second half of 2003. Our share of the design capacity is 12,000 barrels of oil
and 60 million cubic feet of gas per day. We expect to fill approximately 75% of
this capacity with the current development plans, leaving room for growth from
exploration and processing of third-party volumes. We have a 30% interest in
Gunnison.
Elsewhere in the Gulf of Mexico, we expect to drill up to four exploration wells
this year, including our deep-water Gotcha prospect and a deep Miocene gas
prospect on the shelf.
NIGERIA
Block 222 is located approximately 60 miles offshore Nigeria in the Gulf of
Guinea, in water depths ranging from 600 feet to 3,300 feet. The Block contains
two discoveries to date at Ukot and Usan, located approximately six miles apart.
During the second quarter, we were very encouraged by the positive results of
two appraisal wells - Usan-2 and Usan-3.
The two discovery wells and two appraisal wells have all encountered several
oil-bearing horizons. A fifth well appraising the Ukot structure commenced
drilling in April.
Delineation of the Usan and Ukot fields and further exploration of Block 222 is
planned and the partners are analyzing the well and seismic data to continue
appraisal of the Block. 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.
YEMEN
Our drilling program at Masila is ongoing and in the second quarter 2003 we plan
to drill two exploration wells on Block 51, immediately to the west of Masila.
SYNTHETIC CRUDE
In conjunction with our Premium Synthetic Crude project at Long Lake, pilot
testing of the steam assisted gravity drainage technology is underway. Three
well pairs have been drilled, facilities are in place and steam injection began
in April. Later this summer, we plan to process Long Lake bitumen through the
primary upgrading demonstration plant. We are currently completing the Design
Basis Memorandum for the commercial upgrader, which defines the scope and
performance expectations of the various process units. We expect to complete
this work soon and move into the detailed engineering phase. We expect to
receive regulatory approval in the third quarter with a decision on commercial
development late this year. Following commerciality, facilities construction
would begin in 2004, with bitumen production in 2006 and upgrader start-up in
2007. Our Premium Synthetic Crude project is expected to add 30,000 barrels per
day of synthetic oil production to Nexen in 2007.
Syncrude's Stage 3 expansion is proceeding well. The project includes expanding
the Aurora mine and extraction facility and increasing the output from the
Mildred Lake upgrader by 50%. The mine site development is 66% complete and on
schedule for bitumen production in the fourth quarter this year. The upgrader
expansion is 16% complete, with completion targeted for mid-2005. Our 7.23%
share of Syncrude's production is expected to increase to over 25,000 barrels
per day with the completion of the Stage 3 expansion. Total costs for the
expansion are estimated at $5.7 billion ($410 million net to Nexen).
25
LIQUIDITY AND CAPITAL STRUCTURE
CAPITAL STRUCTURE
MARCH 31 DECEMBER 31
(Cdn$ millions) 2003 2002
- --------------------------------------------------------------------------------
Bank Debt 73 --
Senior Public Debt 1,739 1,844
-------------------------
1,812 1,844
Less: Working Capital 157 69
-------------------------
Net Debt(1) 1,655 1,775
=========================
Shareholders' Equity(2) 2,519 2,348
=========================
Notes:
(1) Long-term debt less working capital.
(2) Included in shareholders' equity are preferred securities of $724 million
(US $476 million). Under US generally accepted accounting principles, these
are considered long-term debt.
The change in net debt from December 31, 2002 to March 31, 2003 resulted from:
Increase (Decrease)
(Cdn$ millions) in Net Debt
- -------------------------------------------------------------------------------
Capital Expenditures 329
Acquisition of Additional Interest in Aspen Field 164
Cash Flow from Operations (563)
Dividends on Preferred Securities and Common Shares 27
Foreign Exchange (90)
Other 13
--------------------
Decrease in Net Debt (120)
====================
o Net debt decreased as cash flow from operations exceeded capital
expenditures, dividend payments and the cost of acquiring the additional
40% working interest in the Aspen field.
o The strengthening Canadian dollar relative to the US dollar also decreased
our net debt.
o Our working capital increased $88 million compared to December 31, 2002 as
increased cash on hand and higher net receivable balances more than offset
decreased inventories. Receivables, including net marketing receivables,
increased on the strength of crude oil and gas prices. Inventories
decreased over year-end as we sold 8.5 bcf of gas held by Marketing at
year-end.
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 March 31, 2003.
26
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.
27
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. There have been no significant changes in our exposure to these market
risks since December 31, 2002.
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). 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.
28
PART II. OTHER INFORMATION
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
During the three months ended March 31, 2003, no matters were submitted to a
vote of security holders.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(A) EXHIBITS
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 three months ended March 31, 2003, Nexen did not file or furnish any
reports on Form 8-K.
29
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the Company has duly caused this report to be signed on its behalf
by the undersigned, thereunto duly authorized, on May 12, 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)
30
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: May 12, 2003 /s/ Charles W. Fischer
-----------------------------
Charles W. Fischer
President and Chief Executive
Officer
31
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: May 12, 2003 /s/ Marvin F. Romanow
-----------------------------
Marvin F. Romanow
Executive Vice President
and Chief Financial Officer
32