===============================================================================
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, 2007
|_| 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 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 a large accelerated filer, an
accelerated filer or a non-accelerated filer.
Large accelerated filer [X] Accelerated filer [_] Non-Accelerated filer [_]
Indicate by check mark whether the registrant is a shell company (as defined in
Rule 12b-2).
Yes [_] No [X]
On June 30, 2007, there were 527,149,918 common shares issued and outstanding.
===============================================================================
NEXEN INC.
INDEX
PART I FINANCIAL INFORMATION PAGE
Item 1. Unaudited Consolidated Financial Statements ...................3
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operation............................26
Item 3. Quantitative and Qualitative Disclosures about Market Risk....45
Item 4. Controls and Procedures.......................................45
PART II OTHER INFORMATION
Item 4. Submission of Matters to a Vote of Security Holders...........46
Item 6. Exhibits......................................................46
This report should be read in conjunction with our 2006 Annual Report on Form
10-K, our amended 2006 Form 10-K/A and with our current reports on Form 8-K
filed or furnished during the year.
SPECIAL NOTE TO CANADIAN INVESTORS
Nexen is a US Securities and Exchange Commission (SEC) registrant and a Form
10-K and related forms filer. Therefore, our reserves estimates and securities
regulatory disclosures generally follow SEC requirements. In 2004, certain
Canadian regulatory authorities adopted NATIONAL INSTRUMENT 51-101 - STANDARDS
OF DISCLOSURE FOR OIL AND GAS ACTIVITIES (NI 51-101) which prescribe that
Canadian companies follow certain standards for the preparation and disclosure
of reserves and related information. We have been granted certain exemptions
from NI 51-101. Please refer to the SPECIAL NOTE TO CANADIAN INVESTORS on page
81 of our 2006 Annual Report on Form 10-K.
UNLESS WE INDICATE OTHERWISE, ALL DOLLAR AMOUNTS ($) ARE IN CANADIAN DOLLARS,
AND OIL AND GAS VOLUMES, RESERVES AND RELATED PERFORMANCE MEASURES ARE
PRESENTED ON A WORKING-INTEREST, BEFORE-ROYALTIES BASIS. WHERE APPROPRIATE,
INFORMATION ON AN AFTER-ROYALTIES BASIS IS PRESENTED IN TABULAR FORMAT. VOLUMES
AND RESERVES INCLUDE SYNCRUDE OPERATIONS UNLESS OTHERWISE STATED.
Below is a list of terms specific to the oil and gas industry. They are used
throughout the Form 10-Q.
/d = per day mmboe = million barrels of oil equivalent
bbl = barrel mcf = thousand cubic feet
mbbls = thousand barrels mmcf = million cubic feet
mmbbls = million barrels bcf = billion cubic feet
mmbtu = million British thermal units NGL = natural gas liquid
boe = barrels of oil equivalent WTI = West Texas Intermediate
mboe = thousand barrels of oil equivalent MW = Megawatt
In this 10-Q, we refer to oil and gas in common units called barrel of oil
equivalent (boe). A boe is derived by converting six thousand cubic feet of gas
to one barrel of oil (6 mcf/1 bbl). This conversion may be misleading,
particularly if used in isolation, as the 6 mcf/1 bbl ratio is based on an
energy equivalency at the burner tip and does not represent a value equivalency
at the well head.
Electronic copies of our filings with the SEC and the Ontario Securities
Commission (OSC) (from November 8, 2002 onward) are available, free of charge,
on our web site (www.nexeninc.com). Filings prior to November 8, 2002 are
available free of charge, upon request, by contacting our investor relations
department at (403) 699-5931. As soon as reasonably practicable, our filings
are made available on our website once they are electronically filed with the
SEC or the OSC. Alternatively, the SEC and the OSC each maintain a website
(www.sec.gov and www.sedar.com) that contains our reports, proxy and
information statements and other published information that have been filed or
furnished with the SEC and the OSC.
On June 29, 2007, the noon-day exchange rate was US$0.9404 for Cdn$1.00, as
reported by the Bank of Canada.
2
PART I
ITEM 1. UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
TABLE OF CONTENTS
Page
Unaudited Consolidated Statement of Income
for the Three and Six Months Ended June 30, 2007 and 2006....................4
Unaudited Consolidated Balance Sheet
as at June 30, 2007 and December 31, 2006....................................5
Unaudited Consolidated Statement of Cash Flows
for the Three and Six Months Ended June 30, 2007 and 2006....................6
Unaudited Consolidated Statement of Shareholders' Equity
for the Three and Six Months Ended June 30, 2007 and 2006....................7
Unaudited Consolidated Statement of Comprehensive Income
for the Three and Six Months Ended June 30, 2007 and 2006....................7
Notes to Unaudited Consolidated Financial Statements.........................8
3
NEXEN INC.
UNAUDITED CONSOLIDATED STATEMENT OF INCOME
FOR THE THREE AND SIX MONTHS ENDED JUNE 30
Cdn$ millions, except per share amounts
Three Months Six Months
Ended June 30 Ended June 30
2007 2006 2007 2006
- -------------------------------------------------------------------------------------------------------------------------------
REVENUES AND OTHER INCOME
Net Sales 1,399 1,039 2,539 2,019
Marketing and Other (Note 13) 299 376 547 802
--------------------------------------------------
1,698 1,415 3,086 2,821
--------------------------------------------------
EXPENSES
Operating 289 223 579 473
Depreciation, Depletion, Amortization and Impairment 360 260 694 526
Transportation and Other 210 203 456 463
General and Administrative 38 108 240 328
Exploration 105 46 154 149
Interest (Note 6) 46 11 94 20
--------------------------------------------------
1,048 851 2,217 1,959
--------------------------------------------------
INCOME BEFORE INCOME TAXES 650 564 869 862
--------------------------------------------------
PROVISION FOR INCOME TAXES
Current 151 136 211 245
Future 126 14 161 283
--------------------------------------------------
277 150 372 528
--------------------------------------------------
NET INCOME BEFORE NON-CONTROLLING INTERESTS 373 414 497 334
Less: Net Income Attributable to Non-Controlling Interests (5) (6) (8) (9)
--------------------------------------------------
NET INCOME 368 408 489 325
==================================================
EARNINGS PER COMMON SHARE ($/share)
Basic (Note 11) 0.70 0.78 0.93 0.62
==================================================
Diluted (Note 11) 0.68 0.76 0.91 0.61
==================================================
SEE ACCOMPANYING NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS.
4
NEXEN INC.
UNAUDITED CONSOLIDATED BALANCE SHEET
Cdn$ millions, except share amounts
June 30 December 31
2007 2006
- ------------------------------------------------------------------------------------------------------------------------
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents 158 101
Restricted Cash and Margin Deposits 96 197
Accounts Receivable (Note 2) 2,861 2,951
Inventories and Supplies (Note 3) 857 786
Future Income Tax Assets 277 479
Other 51 67
------------------------------------
Total Current Assets 4,300 4,581
------------------------------------
PROPERTY, PLANT AND EQUIPMENT
Net of Accumulated Depreciation, Depletion, Amortization
and Impairment of $6,502 (December 31, 2006 - $6,399) 12,147 11,739
FUTURE INCOME TAX ASSETS 78 141
DEFERRED CHARGES AND OTHER ASSETS (Note 4) 321 318
GOODWILL 348 377
------------------------------------
TOTAL ASSETS 17,194 17,156
====================================
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Short-Term Borrowings (Note 6) 61 158
Accounts Payable and Accrued Liabilities 3,665 3,879
Accrued Interest Payable 65 55
Dividends Payable 13 13
------------------------------------
Total Current Liabilities 3,804 4,105
------------------------------------
LONG-TERM DEBT (Note 6) 4,852 4,673
FUTURE INCOME TAX LIABILITIES 2,274 2,468
ASSET RETIREMENT OBLIGATIONS (Note 7) 690 683
DEFERRED CREDITS AND OTHER LIABILITIES (Note 8) 421 516
NON-CONTROLLING INTERESTS 73 75
SHAREHOLDERS' EQUITY (Note 10)
Common Shares, no par value
Authorized: Unlimited
Outstanding: 2007 - 527,149,918 shares
2006 - 525,026,412 shares 893 821
Contributed Surplus 5 4
Retained Earnings 4,435 3,972
Accumulated Other Comprehensive Income (Note 1) (253) (161)
------------------------------------
Total Shareholders' Equity 5,080 4,636
------------------------------------
COMMITMENTS, CONTINGENCIES AND GUARANTEES (Note 14)
------------------------------------
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY 17,194 17,156
====================================
SEE ACCOMPANYING NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS.
5
NEXEN INC.
UNAUDITED CONSOLIDATED STATEMENT OF CASH FLOWS
FOR THE THREE AND SIX MONTHS ENDED JUNE 30
Cdn$ millions
Three Months Six Months
Ended June 30 Ended June 30
2007 2006 2007 2006
- ------------------------------------------------------------------------------------------------------------------------------
OPERATING ACTIVITIES
Net Income 368 408 489 325
Charges and Credits to Income not Involving Cash (Note 12) 447 293 882 965
Exploration Expense 105 46 154 149
Changes in Non-Cash Working Capital (Note 12) (304) (377) (272) (304)
Other (34) 4 (223) (27)
--------------------------------------------------------
582 374 1,030 1,108
FINANCING ACTIVITIES
Proceeds from Long-Term Notes 1,660 - 1,660 -
Proceeds from (Repayment of) Term Credit Facilities, Net (1,321) 417 (955) 413
Proceeds from Term Credit Facilities of Canexus 15 - 33 -
Proceeds from (Repayment of) Short-Term Borrowings, Net (44) 50 (92) 85
Dividends on Common Shares (Note 10) (13) (13) (26) (26)
Issue of Common Shares and Exercise of Stock Options 11 24 40 37
Other (28) (7) (35) (14)
--------------------------------------------------------
280 471 625 495
INVESTING ACTIVITIES
Capital Expenditures
Exploration and Development (747) (767) (1,537) (1,486)
Proved Property Acquisitions (45) - (46) (3)
Chemicals, Corporate and Other (27) (52) (47) (62)
Business Acquisitions, Net of Cash Acquired - (57) - (78)
Proceeds on Disposition of Assets - 25 - 25
Changes in Restricted Cash and Margin Deposits 66 66 82 12
Changes in Non-Cash Working Capital (Note 12) 16 36 44 59
Other (10) (11) (14) (4)
--------------------------------------------------------
(747) (760) (1,518) (1,537)
EFFECT OF EXCHANGE RATE CHANGES ON CASH
AND CASH EQUIVALENTS (67) (29) (80) (28)
--------------------------------------------------------
INCREASE IN CASH AND CASH EQUIVALENTS 48 56 57 38
CASH AND CASH EQUIVALENTS - BEGINNING OF PERIOD 110 30 101 48
--------------------------------------------------------
CASH AND CASH EQUIVALENTS - END OF PERIOD 158 86 158 86
========================================================
SEE ACCOMPANYING NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS.
6
NEXEN INC.
UNAUDITED CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY
FOR THE THREE AND SIX MONTHS ENDED JUNE 30
Cdn$ millions
Three Months Six Months
Ended June 30 Ended June 30
2007 2006 2007 2006
- ---------------------------------------------------------------------------------------------------------------------------------
COMMON SHARES
Balance at Beginning of Period 866 763 821 732
Issue of Common Shares 4 21 25 26
Proceeds from Options Exercised for Shares 7 3 15 11
Accrued Liability Relating to Options Exercised for Shares 16 12 32 30
---------------------------------------------------------
Balance at End of Period 893 799 893 799
=========================================================
CONTRIBUTED SURPLUS
Balance at Beginning of Period 4 2 4 2
Stock-Based Compensation Expense 1 1 1 1
---------------------------------------------------------
Balance at End of Period 5 3 5 3
=========================================================
RETAINED EARNINGS
Balance at Beginning of Period 4,080 3,327 3,972 3,423
Net Income 368 408 489 325
Dividends on Common Shares (13) (13) (26) (26)
---------------------------------------------------------
Balance at End of Period 4,435 3,722 4,435 3,722
=========================================================
ACCUMULATED OTHER COMPREHENSIVE INCOME
Balance at Beginning of Period (167) (167) (161) -
Opening Cumulative Foreign Currency Translation Adjustment - - - (161)
(Note 1)
Opening Derivatives Designated as Cash Flow Hedges (Note 1) - - 61 -
Other Comprehensive Income (86) (63) (153) (69)
---------------------------------------------------------
Balance at End of Period (253) (230) (253) (230)
=========================================================
NEXEN INC.
UNAUDITED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
FOR THE THREE AND SIX MONTHS ENDED JUNE 30
Cdn$ millions
Three Months Six Months
Ended June 30 Ended June 30
2007 2006 2007 2006
- ---------------------------------------------------------------------------------------------------------------------------------
Net Income 368 408 489 325
Other Comprehensive Income, Net of Income Taxes:
Foreign Currency Translation Adjustment:
Net Losses on Investment in Self-Sustaining Foreign Operations (437) (220) (495) (218)
Net Gains on Hedges of Self-Sustaining Foreign Operations (1) 353 154 403 147
Realized Translation Adjustments Recognized in Net Income (2) (2) 3 - 2
Cash Flow Hedges:
Realized Mark to Market Gains Recognized in Net Income - - (61) -
---------------------------------------------------------
Other Comprehensive Income (86) (63) (153) (69)
---------------------------------------------------------
Comprehensive Income 282 345 336 256
=========================================================
- ------------
(1) Net of income taxes for the three months ended June 30 of $57 million
(2006 - $19 million) and for the six months ended June 30 of $66 million
(2006 - $18 million).
(2) Net of income taxes for the three months ended June 30 of $1 million (2006
- nil) and six months ended June 30 of $nil (2006 - $nil).
SEE ACCOMPANYING NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS.
7
NEXEN INC.
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
Cdn$ millions except as noted
1. ACCOUNTING POLICIES
Our Unaudited Consolidated Financial Statements are prepared in accordance with
Canadian Generally Accepted Accounting Principles (GAAP). The impact of
significant differences between Canadian and United States (US) GAAP on the
Unaudited Consolidated Financial Statements is disclosed in Note 16. In the
opinion of management, the Unaudited Consolidated Financial Statements contain
all adjustments of a normal and recurring nature necessary to present fairly
Nexen Inc.'s (Nexen, we or our) financial position at June 30, 2007 and the
results of our operations and our cash flows for the three and six months ended
June 30, 2007 and 2006.
We make 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 accruals, litigation, environmental and asset retirement
obligations, income taxes, derivative contract assets and liabilities 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, 2007 are not necessarily indicative of the
results of operations or cash flows to be expected for the year ending December
31, 2007.
These Unaudited Consolidated Financial Statements should be read in conjunction
with our Audited Consolidated Financial Statements included in our 2006 Annual
Report on Form 10-K. Except as described below, the accounting policies we
follow are described in Note 1 of the Audited Consolidated Financial Statements
included in our 2006 Annual Report on Form 10-K.
CHANGE IN ACCOUNTING POLICIES
On January 1, 2007, we adopted the following new accounting standards issued by
the Canadian Accounting Standards Board (AcSB): FINANCIAL
INSTRUMENTS--RECOGNITION AND MEASUREMENT (Section 3855), HEDGES (Section 3865)
and COMPREHENSIVE INCOME (Section 1530).
FINANCIAL INSTRUMENTS--RECOGNITION AND MEASUREMENT
Section 3855 requires all financial assets and liabilities to be carried at
fair value in the Unaudited Consolidated Balance Sheet with the exception of
loans and receivables, investments that are intended to be held to maturity and
non-trading financial liabilities which are to be carried at cost or amortized
cost.
Realized and unrealized gains and losses on financial assets and liabilities
carried at fair value are recognized in the Unaudited Consolidated Statement of
Income in the periods such gains and losses arise. Transaction costs related to
these financial assets and liabilities are included in the Unaudited
Consolidated Statement of Income when incurred. Unrealized gains and losses on
financial assets and liabilities carried at cost or amortized cost are
recognized in the Unaudited Consolidated Statement of Income when these assets
or liabilities settle.
We hold financial instruments that were carried at fair value prior to the
adoption of Section 3855 as described in Note 9. The valuation methods we use
to determine the fair value of these financial instruments remain unchanged.
Financial instruments we carry at cost or amortized cost include our accounts
receivable, accounts payable, short-term and long-term debt. Upon adopting
Section 3855 with respect to the amortized cost using the effective interest
rate method of our long-term debt, we have reclassed deferred financing costs
previously included in deferred charges and other assets as unamortized debt
issue costs which reduce the carrying value of our long-term debt.
HEDGES
Section 3865 prescribes new standards for hedge accounting.
For cash flow hedges, changes in the fair value of a financial instrument
designated as a cash flow hedge are recognized in the Unaudited Consolidated
Statement of Income in the same period as the hedged item. Any fair value
change in the financial instrument before that period is recognized on the
Unaudited Consolidated Balance Sheet. The effective portion of this fair value
change is recognized in other comprehensive income with any ineffectiveness
recognized in the Unaudited Consolidated Statement of Income during the period
of change.
For fair value hedges, both the financial instrument designated as a fair value
hedge and the underlying commitment are recognized on the Unaudited
Consolidated Balance Sheet at fair value. Changes in the fair value of both are
reflected in the Unaudited Consolidated Statement of Income.
8
Adoption of these new standards for hedge accounting required us to record
unrealized mark to market gains on cash flow hedges that were previously not
included on our Unaudited Consolidated Balance Sheet at December 31, 2006 as an
adjustment to the opening balance of accumulated other comprehensive income
(see Note 9).
COMPREHENSIVE INCOME
Section 1530 provides for a new Statement of Comprehensive Income and
establishes accumulated other comprehensive income as a separate component of
shareholders' equity. The Unaudited Consolidated Statement of Comprehensive
Income reflects changes in accumulated other comprehensive income and includes
the effective portion of changes in the fair value of financial instruments
designated as cash flow hedges, as well as changes in foreign currency
translation amounts arising in respect of self-sustaining foreign operations
together with the impact of any related hedges. Amounts included in accumulated
other comprehensive income are reclassified to the Unaudited Consolidated
Statement of Income when realized. On adoption of Section 1530, cumulative
foreign currency translation adjustments relating to our self-sustaining
foreign operations were reclassed to accumulated other comprehensive income and
comparative amounts have been restated.
We adopted these standards prospectively. Comparative amounts for prior periods
have not been restated with the exception of amounts related to cumulative
foreign currency translation adjustments. Adoption of these standards as at
January 1, 2007 had the following impact on our Unaudited Consolidated Balance
Sheet:
January 1, 2007
Increase/(Decrease)
- -----------------------------------------------------------------------------------------------------------------------------------
To Include Unrealized Mark to Market Gains on Cash Flow Hedges at December 31, 2006:
Accounts Receivable 25
Accounts Payable and Accrued Liabilities (65)
Future Income Tax Liabilities 29
Accumulated Other Comprehensive Income 61
To Include Cumulative Foreign Currency Translation in Accumulated Other Comprehensive Income:
Cumulative Foreign Currency Translation Adjustment 161
Accumulated Other Comprehensive Income (161)
To Include Unamortized Debt Issue Costs with Long-Term Debt:
Deferred Charges and Other Assets (59)
Long-Term Debt (59)
---------------------------------
2. ACCOUNTS RECEIVABLE
June 30 December 31
2007 2006
- ---------------------------------------------------------------------------------------------------------------------------------
Trade
Marketing 2,006 2,226
Oil and Gas 705 600
Chemicals and Other 63 58
---------------------------------
2,774 2,884
Non-Trade 99 80
---------------------------------
2,873 2,964
Allowance for Doubtful Receivables (12) (13)
---------------------------------
Total 2,861 2,951
=================================
9
3. INVENTORIES AND SUPPLIES
June 30 December 31
2007 2006
- ---------------------------------------------------------------------------------------------------------------------------------
Finished Products
Marketing 722 609
Oil and Gas 2 21
Chemicals and Other 12 14
-------------------------------
736 644
Work in Process 6 5
Field Supplies 115 137
-------------------------------
Total 857 786
===============================
4. DEFERRED CHARGES AND OTHER ASSETS
June 30 December 31
2007 2006
- -----------------------------------------------------------------------------------------------------------------------------------
Long-Term Marketing Derivative Contracts (Note 9) 208 153
Deferred Financing Costs (Note 1) - 59
Asset Retirement Remediation Fund 14 13
Crude Oil Put Options (Note 9) 23 19
Other 76 74
---------------------------------
Total 321 318
=================================
5. SUSPENDED WELL COSTS
The following table shows the changes in capitalized exploratory well costs
during the six month period ended June 30, 2007 and the year ended December 31,
2006, and does not include amounts that were initially capitalized and
subsequently expensed in the same period.
Six Months Ended Year Ended
June 30 December 31
2007 2006
- -----------------------------------------------------------------------------------------------------------------------------------
Balance at Beginning of Period 226 252
Additions to Capitalized Exploratory Well Costs Pending the
Determination of Proved Reserves 77 129
Capitalized Exploratory Well Costs Charged to Expense (22) (70)
Transfers to Wells, Facilities and Equipment Based on
Determination of Proved Reserves (8) (84)
Effects of Foreign Exchange (18) (1)
---------------------------------------
Balance at End of Period 255 226
=======================================
The following table provides an aging of capitalized exploratory well costs
based on the date drilling was completed and shows the number of projects for
which exploratory well costs have been capitalized for a period greater than
one year after the completion of drilling.
June 30 December 31
2007 2006
- -------------------------------------------------------------------------------------------------------------------------------
Capitalized for a Period of One Year or Less 104 179
Capitalized for a Period of Greater than One Year 151 47
---------------------------------
Balance at End of Period 255 226
=================================
Number of Projects that have Exploratory Well Costs Capitalized for a Period
Greater than One Year 6 4
---------------------------------
As at June 30, 2007, we have exploratory costs that have been capitalized for
more than one year relating to our interest in two exploratory blocks in the
Gulf of Mexico ($98 million), our interest in an exploratory block offshore
Nigeria ($19 million), our coalbed methane exploratory activities in Canada
($17 million), an exploratory well on Block 51 in Yemen ($11 million) and an
exploratory block in the North Sea ($6 million). We have capitalized costs
related to successful wells drilled in Nigeria, Gulf of Mexico, North Sea, and
at Block 51 in Yemen. In Canada, we have capitalized exploratory costs relating
to our coalbed methane projects. We are assessing all of these wells and
projects, and are working with our partners to prepare development plans, drill
additional appraisal wells or to assess commercial viability.
10
6. LONG-TERM DEBT AND SHORT-TERM BORROWINGS
June 30 December 31
2007 2006
- ---------------------------------------------------------------------------------------------------------------------------------
Term Credit Facilities (a) - 1,078
Canexus LP Term Credit Facilities (US$178 million) 189 174
Medium-Term Notes, due 2007 (1) 150 150
Medium-Term Notes, due 2008 125 125
Notes, due 2013 (US$500 million) 532 583
Notes, due 2015 (US$250 million) 266 291
Notes, due 2017 (US$250 million) (b) 266 -
Notes, due 2028 (US$200 million) 213 233
Notes, due 2032 (US$500 million) 532 583
Notes, due 2035 (US$790 million) 840 920
Notes, due 2037 (US$1,250 million) (c) 1,329 -
Subordinated Debentures, due 2043 (US$460 million) 489 536
-----------------------------------
4,931 4,673
Unamortized Debt Issue Costs (Note 1) (79) -
-----------------------------------
Total Long-Term Debt 4,852 4,673
===================================
- ------------
(1) Amounts due July 2007 are not included in current liabilities as we expect
to refinance this amount with our term credit facilities.
(a) TERM CREDIT FACILITIES
We have committed, unsecured term credit facilities of $3.3 billion, which are
available to 2011. The lenders have the option to extend the term annually. At
June 30, 2007 we had not drawn on these facilities (December 31, 2006 - $1,078
million). Borrowings are available as Canadian bankers' acceptances,
LIBOR-based loans, Canadian prime loans, US-dollar base rate loans or British
pound call-rate loans. Interest is payable monthly at floating rates. The
weighted-average interest rate on our term credit facilities was 5.9% for the
three months ended June 30, 2007 (2006 - 5.7%) and 5.9% for the six months
ended June 30, 2007 (2006 - 5.5%). At June 30, 2007, $397 million of these
facilities were utilized to support outstanding letters of credit (December 31,
2006 - $294 million).
(b) NOTES, DUE 2017
In May 2007, we issued US$250 million of 10 year notes. Interest is payable
semi-annually at a rate of 5.65% and the principal is to be repaid in May 2017.
We may redeem part or all of the notes at any time. The redemption price will
be the greater of par and an amount that provides the same yield as a US
Treasury security having a term to maturity equal to the remaining term of the
notes plus 0.2%. The proceeds were used to repay the outstanding term credit
facilities.
(c) NOTES, DUE 2037
In May 2007, we issued US$1,250 million of 30 year notes. Interest is payable
semi-annually at a rate of 6.40% and the principal is to be repaid in May 2037.
We may redeem part or all of the notes at any time. The redemption price will
be the greater of par and an amount that provides the same yield as a US
Treasury security having a term to maturity equal to the remaining term of the
notes plus 0.35%. The proceeds were used to repay the outstanding term credit
facilities.
(d) INTEREST EXPENSE
Three Months Six Months
Ended June 30 Ended June 30
2007 2006 2007 2006
- -----------------------------------------------------------------------------------------------------------------------------------
Long-Term Debt 83 65 164 127
Other 4 6 9 10
---------------------------------------------------
87 71 173 137
Less: Capitalized (41) (60) (79) (117)
---------------------------------------------------
Total 46 11 94 20
===================================================
Capitalized interest relates to and is included as part of the cost of our oil
and gas properties. The capitalization rates are based on our weighted-average
cost of borrowings.
11
(e) SHORT-TERM BORROWINGS
Nexen has uncommitted, unsecured credit facilities of approximately $631
million, of which $61 million (US$57 million) was drawn at June 30, 2007
(December 31, 2006 - $158 million). We have also utilized $130 million of these
facilities to support outstanding letters of credit at June 30, 2007 (December
31, 2006 - $252 million). Interest is payable at floating rates. The
weighted-average interest rate on our short-term borrowings was 5.8% for the
three months ended June 30, 2007 (2006 - 5.4%) and 5.8% for the six months
ended June 30, 2007 (2006 - 5.3%).
7. ASSET RETIREMENT OBLIGATIONS
Changes in carrying amounts of the asset retirement obligations associated with
our property, plant and equipment for the six months ended June 30, 2007 and
the year ended December 31, 2006, are as follows:
Six Months Ended Year Ended
June 30 December 31
2007 2006
- -----------------------------------------------------------------------------------------------------------------------------------
Balance at Beginning of Period 704 611
Obligations Assumed with Development Activities 36 75
Obligations Discharged with Disposed Properties - (1)
Expenditures Made on Asset Retirements (12) (44)
Accretion 22 37
Revisions to Estimates (3) (10)
Effects of Foreign Exchange (36) 36
-----------------------------------------
Balance at End of Period (1,2) 711 704
=========================================
- ------------
(1) Obligations due within 12 months of $21 million (December 31, 2006 - $21
million) have been included in accounts payable and accrued liabilities.
(2) Obligations relating to our oil and gas activities amount to $665 million
(December 31, 2006 - $658 million) and obligations relating to our
chemicals business amount to $46 million (December 31, 2006 - $46
million).
Our total estimated undiscounted asset retirement obligations amount to $1,783
million (December 31, 2006 - $1,770 million). We have discounted the total
estimated asset retirement obligations using a weighted-average,
credit-adjusted risk-free rate of 5.7%. Approximately $94 million included in
our asset retirement obligations will be settled over the next five years. The
remaining obligations settle beyond five years and will be funded by future
cash flows from our operations.
We own interests in assets for which the fair value of the asset retirement
obligations cannot be reasonably determined because the assets currently have
an indeterminate life and we cannot determine when remediation activities would
take place. These assets include our interest in Syncrude's upgrader and
sulphur pile. The estimated future recoverable reserves at Syncrude are
significant and given the long life of this asset, we are unable to determine
when asset retirement activities would take place. Furthermore, the Syncrude
plant can continue to run indefinitely with ongoing maintenance activities. The
retirement obligations for these assets will be recorded in the first year in
which the lives of the assets are determinable.
8. DEFERRED CREDITS AND OTHER LIABILITIES
June 30 December 31
2007 2006
- -----------------------------------------------------------------------------------------------------------------
Long-Term Marketing Derivative Contracts (Note 9) 111 199
Deferred Transportation Revenue 87 89
Fixed-Price Natural Gas Contracts (Note 9) 62 74
Capital Lease Obligations 50 48
Defined Benefit Pension Obligations 50 48
Stock-Based Compensation Liability 13 6
Other 48 52
--------------------------------
Total 421 516
================================
12
9. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT
We use derivatives in our marketing group for trading purposes and we also use
derivatives to manage commodity price risk for non-trading purposes. Our
derivative instruments are carried at fair value on the Unaudited Consolidated
Balance Sheet. Our other financial instruments are carried at cost or amortized
cost.
(a) CARRYING VALUE AND ESTIMATED FAIR VALUE OF FINANCIAL INSTRUMENTS
The carrying value, fair value, and unrecognized gains or losses on our
outstanding derivatives and other financial liabilities are:
JUNE 30, 2007 DECEMBER 31, 2006
- -----------------------------------------------------------------------------------------------------------------------------------
Carrying Fair Unrecognized Carrying Fair Unrecognized
Value Value Gain/(Loss) Value Value Gain/(Loss)
---------------------------------------- -------------------------------------
Derivatives
Commodity Price Risk
Non-Trading Activities
Crude Oil Put Options 23 23 - 19 19 -
Fixed-Price Natural Gas Contracts (85) (85) - (96) (96) -
Natural Gas Swaps (5) (5) - (8) (8) -
Trading Activities
Crude Oil and Natural Gas 129 129 - 372 372 -
Future Sale of Gas Inventory - - - - 25 25
Foreign Currency Exchange Rate Risk
Trading Activities 2 2 - (12) (12) -
------------------------------------ ----------------------------------------
Total Derivatives 64 64 - 275 300 25
==================================== ========================================
Other Financial Liabilities
Long-Term Debt (4,852) (4,819) 33 (4,673) (4,728) (55)
==================================== ========================================
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. Other financial assets used in the normal course of business include
cash and cash equivalents, restricted cash and margin deposits and accounts
receivable. Other financial liabilities include accounts payable, accrued
interest payable, short-term borrowings and long-term debt. Fair value of
long-term debt is estimated based on third-party brokers and quoted market
prices.
(b) COMMODITY PRICE RISK MANAGEMENT
NON-TRADING ACTIVITIES
We generally sell our crude oil and natural gas under short-term market based
contracts.
CRUDE OIL PUT OPTIONS
In 2006, we purchased WTI crude oil put options to provide a base level of
price protection without limiting our upside to higher prices. These options
establish an annual average WTI floor price of US$50/bbl in 2007 on 105,000
bbls/d at a cost of $26 million. The crude oil put options are stated at fair
value and are included in accounts receivable as they settle within 12 months.
Any change in fair value is included in marketing and other on the Unaudited
Consolidated Statement of Income.
During the quarter, we purchased put options on 36 million barrels or about
100,000 bbls/d of our 2008 crude oil production. These options establish a
Dated Brent floor price of US$50/bbl on these volumes and are settled annually.
The put options were purchased for $24 million and are carried at fair value.
Any change in fair value is included in marketing and other income on the
Unaudited Consolidated Statement of Income.
Notional Average Fair
Volumes Term Price Value
- ---------------------------------------------------------------------------------------------
(bbls/d) (US$/bbl) (Cdn$ millions)
WTI Crude Oil Put Options 105,000 2007 50 -
Dated Brent Crude Oil Put Options 100,000 2008 50 23
----------------
23
================
13
FIXED-PRICE NATURAL GAS CONTRACTS AND NATURAL GAS SWAPS
In July and August 2005, we sold certain Canadian oil and gas properties and
retained fixed-price natural gas sales contracts that were previously
associated with those properties. Since these contracts are no longer used in
the normal course of our oil and gas operations, they have been included in the
Unaudited Consolidated Balance Sheet at fair value. Amounts settling within 12
months are included in accounts payable and amounts settling greater than 12
months are included in deferred credits and other liabilities. Any change in
fair value is included in marketing and other in the Unaudited Consolidated
Statement of Income.
Notional Average Fair
Volumes Term Price Value
- -----------------------------------------------------------------------------------------------------------
(Gj/d) ($/Gj) (Cdn$ millions)
Fixed-Price Natural Gas Contracts 15,514 2007 - 2008 2.46 (23)
15,514 2008 - 2010 2.56 - 2.77 (62)
----------
(85)
==========
Following the sale of the Canadian oil and gas properties, we entered into
natural gas swaps to hedge our fixed price exposure with floating natural gas
prices. Any change in fair value is included in marketing and other in the
Unaudited Consolidated Statement of Income. Amounts settling within 12 months
are included in accounts receivable and amounts settling greater than 12 months
are included in deferred charges and other assets.
Notional Average Fair
Volumes Term Price Value
- -----------------------------------------------------------------------------------------------------------
(Gj/d) ($/Gj) (Cdn$ millions)
Natural Gas Swaps 15,514 2007 - 2008 7.60 (5)
15,514 2008 - 2010 7.60 -
----------
(5)
==========
TRADING ACTIVITIES
CRUDE OIL AND NATURAL GAS
We enter into physical purchase and sales contracts as well as financial
commodity contracts to enhance our price realizations and lock in our margins.
The physical and financial commodity contracts (derivative contracts) are
stated at fair value. The $129 million fair value of the derivative contracts
at June 30, 2007 is included in the Unaudited Consolidated Balance Sheet and
any change is included in marketing and other in the Unaudited Consolidated
Statement of Income.
FUTURE SALE OF GAS INVENTORY
In an attempt to mitigate the exposure to fluctuations in cash flow from
changes in the price of natural gas we have certain NYMEX futures contracts and
swaps in place, which effectively lock in our margins on the future sale of our
natural gas inventory in storage. From time to time, we have designated, in
writing, some of these derivative contracts as cash flow hedges of the future
sale of our storage inventory.
With the adoption of Section 3865 HEDGES as described in Note 1, the effective
portion of gains and losses relating to cash flow hedges are now included in
other comprehensive income until the gains or losses are realized in net
income. Prior to the adoption of Section 3865, gains and losses related to
derivatives classified as cash flow hedges were unrecognized.
At December 31, 2006, we held NYMEX natural gas futures contracts and swaps
that were designated as cash flow hedges on the future sale of natural gas
inventory. On adoption of Section 3865, the fair value of $25 million related
to these cash flow hedges was recognized in accounts receivable on January 1,
2007. The fair value gain of $16 million, net of income taxes, was included
with the opening balance of accumulated other comprehensive income (AOCI).
During the first quarter of 2007, the inventory was sold and as a result, gains
on these cash flow hedges were recognized in marketing and other on the
Unaudited Consolidated Statement of Income.
In late 2006, we de-designated certain futures contracts that had been
designated as cash flow hedges of future sales of our natural gas in storage.
These contracts were de-designated since it became uncertain that the future
sales of natural gas would occur within the designated time frame. As it was
reasonably possible that the future sales could have taken place as designated
at the inception of the hedging relationship, gains of $65 million on the
futures contracts were deferred in accounts payable at December 31, 2006. The
adoption of Section 3865 required that the deferred gains ($45 million, net of
income taxes) be reclassified to AOCI on January 1, 2007. The gains were
recognized in marketing and other on the Unaudited Consolidated Statement of
Income during the first quarter of 2007.
At June 30, 2007, there were no cash flow hedges in place.
14
(c) FOREIGN CURRENCY EXCHANGE RATE RISK MANAGEMENT
TRADING ACTIVITIES
Our sales and purchases of crude oil and natural gas are generally transacted
in or referenced to the US dollar, as are most of the financial commodity
contracts used by our marketing group. However, we pay for many of our
purchases in Canadian dollars. We enter into US-dollar forward contracts and
swaps to manage this exposure. Gains and losses on our US-dollar forward
contracts and swaps are included in the Unaudited Consolidated Balance Sheet,
and any change in fair value is included in marketing and other in the
Unaudited Consolidated Statement of Income. At June 30, 2007, the fair value of
our US-dollar forward contracts and swaps was $2 million.
(d) TOTAL CARRYING VALUE OF DERIVATIVE CONTRACTS RELATED TO TRADING ACTIVITIES
Amounts related to derivative instruments held by our marketing operation are
equal to fair value as we use mark-to-market accounting. The amounts are as
follows:
June 30 December 31
2007 2006
- --------------------------------------------------------------------------------------------------------------
Accounts Receivable 365 731
Deferred Charges and Other Assets (1) 208 153
-------------------------------------
Total Derivative Contract Assets 573 884
=====================================
Accounts Payable and Accrued Liabilities 331 325
Deferred Credits and Other Liabilities (1) 111 199
-------------------------------------
Total Derivative Contract Liabilities 442 524
=====================================
Total Derivative Contract Net Assets (2) 131 360
=====================================
- ------------
(1) These derivative contracts settle beyond 12 months and are considered
non-current.
(2) Comprised of $129 million (2006 - $372 million) related to commodity
contracts and gains of $2 million (2006 - losses of $12 million) related
to US-dollar forward contracts and swaps.
Our exchange-traded derivative contracts are subject to margin deposit
requirements. We are required to advance cash to counterparties in order to
satisfy their requirements. We have margin deposits of $96 million (December
31, 2006 - $197 million), which have been included in restricted cash and
margin deposits on our Unaudited Consolidated Balance Sheet at June 30, 2007.
10. SHAREHOLDERS' EQUITY
DIVIDENDS
Dividends per common share for the three months ended June 30, 2007 were $0.025
(2006 - $0.025). Dividends per common share for the six months ended June 30,
2007 were $0.05 (2006 - $0.05). Dividends paid to holders of common shares have
been designated as "eligible dividends" for Canadian tax purposes.
11. EARNINGS PER COMMON SHARE
Our shareholders approved a split of our issued and outstanding common shares
on a two-for-one basis at our annual and special meeting on April 26, 2007. All
common share and per common share amounts have been retroactively restated to
reflect this share split.
15
We calculate basic earnings per common share using net income and the
weighted-average number of common shares outstanding. We calculate diluted
earnings per common share in the same manner as basic, except we use the
weighted-average number of diluted common shares outstanding in the
denominator.
Three Months Six Months
Ended June 30 Ended June 30
(millions of shares) 2007 2006 2007 2006
- ---------------------------------------------------------------------------------------------------------------------------------
Weighted-average number of common shares outstanding 527.0 524.2 526.5 523.8
Shares issuable pursuant to tandem options 26.9 28.4 27.6 28.8
Shares to be purchased from proceeds of tandem options (15.6) (15.1) (15.4) (15.0)
----------------------------------------------------------
Weighted-average number of diluted common shares outstanding 538.3 537.5 538.7 537.6
==========================================================
In calculating the weighted-average number of diluted common shares outstanding
for the three and six months ended June 30, 2007, we excluded 36,000 and 37,667
options respectively, because their exercise price was greater than the average
market price in those periods. In calculating the weighted-average number of
diluted common shares outstanding for the three and six months ended June 30,
2006, all options were included because their exercise price was less than the
quarterly average common share market price in the period. During the periods
presented, outstanding stock options were the only potential dilutive
instruments.
12. CASH FLOWS
(a) CHARGES AND CREDITS TO INCOME NOT INVOLVING CASH
Three Months Six Months
Ended June 30 Ended June 30
2007 2006 2007 2006
- ----------------------------------------------------------------------------------------------------------------------------------
Depreciation, Depletion, Amortization and Impairment 360 260 694 526
Stock-Based Compensation (70) 4 (26) 112
Future Income Taxes 126 14 161 283
Change in Fair Value of Crude Oil Put Options 4 (3) 20 1
Net Income Attributable to Non-Controlling Interests 5 6 8 9
Other 22 12 25 34
-----------------------------------------------------------
Total 447 293 882 965
===========================================================
(b) CHANGES IN NON-CASH WORKING CAPITAL
Three Months Six Months
Ended June 30 Ended June 30
2007 2006 2007 2006
- ----------------------------------------------------------------------------------------------------------------------------------
Accounts Receivable (142) 8 (67) 837
Inventories and Supplies (244) (108) (179) (258)
Other Current Assets 15 16 11 21
Accounts Payable and Accrued Liabilities 54 (272) (4) (843)
Accrued Interest Payable 29 15 11 (2)
-----------------------------------------------------------
Total (288) (341) (228) (245)
===========================================================
Relating to:
Operating Activities (304) (377) (272) (304)
Investing Activities 16 36 44 59
-----------------------------------------------------------
Total (288) (341) (228) (245)
===========================================================
(c) OTHER CASH FLOW INFORMATION
Three Months Six Months
Ended June 30 Ended June 30
2007 2006 2007 2006
- ----------------------------------------------------------------------------------------------------------------------------------
Interest Paid 55 50 156 130
Income Taxes Paid 100 138 157 208
-----------------------------------------------------------
16
13. MARKETING AND OTHER
Three Months Six Months
Ended June 30 Ended June 30
2007 2006 2007 2006
- ----------------------------------------------------------------------------------------------------------------------------------
Marketing Revenue, Net 284 293 531 730
Change in Fair Value of Crude Oil Put Options (4) 3 (20) (1)
Interest 10 11 19 19
Foreign Exchange Losses (38) (27) (43) (48)
Other (1) 47 96 60 102
-----------------------------------------------------------
Total 299 376 547 802
============================================================
- ------------
(1) Other income for the three and six months ended June 30, 2006 includes $74
million of business interruption proceeds received from our insurers
relating to generator failures in 2005 at our UK oil and gas operations.
14. COMMITMENTS, CONTINGENCIES AND GUARANTEES
As described in Note 15 to the Audited Consolidated Financial Statements
included in our 2006 Annual Report on Form 10-K, there are a number of lawsuits
and claims pending, the ultimate results of which cannot be ascertained at this
time. We record costs as they are incurred or become determinable. We believe
the resolution of these matters would not have a material adverse effect on our
liquidity, consolidated financial position or results of operations.
17
15. OPERATING SEGMENTS AND RELATED INFORMATION
Nexen is involved in activities relating to Oil and Gas, Energy Marketing,
Syncrude and Chemicals in various geographic locations as described in Note 20
to the Audited Consolidated Financial Statements included in our 2006 Annual
Report on Form 10-K.
THREE MONTHS ENDED JUNE 30, 2007
Corporate
Energy and
Oil and Gas Marketing Syncrude Chemicals Other Total
- -----------------------------------------------------------------------------------------------------------------------------------
United United Other
Yemen Canada States Kingdom Countries(1)
----------------------------------------------
Net Sales 288 113 148 592 35 7 115 101 - 1,399
Marketing and Other 3 3 - 24 - 284 - 17 (32)(2) 299
---------------------------------------------------------------------------------------------------
Total Revenues 291 116 148 616 35 291 115 118 (32) 1,698
Less: Expenses
Operating 42 42 26 53 2 6 51 67 - 289
Depreciation, Depletion,
Amortization and
Impairment 64 41 62 158 3 3 12 11 6 360
Transportation and Other 1 6 - - - 189 4 8 2 210
General and Administrative (3) (4) 8 (5) (3) 1 23 - 8 10 38
Exploration 2 9 49 18 27(4) - - - - 105
Interest - - - - - - - 3 43 46
---------------------------------------------------------------------------------------------------
Income (Loss)
before Income Taxes 186 10 16 390 2 70 48 21 (93) 650
Less: Provision for (Recovery
of) Income Taxes 64(5) 2 - 202 9 26 13 6 (45) 277
Less: Non-Controlling
Interests - - - - - - - 5 - 5
---------------------------------------------------------------------------------------------------
Net Income (Loss) 122 8 16 188 (7) 44 35 10 (48) 368
===================================================================================================
Identifiable Assets 441 4,543(6) 1,581 5,107 258 3,355(7) 1,186 495 228 17,194
===================================================================================================
Capital Expenditures
Development and Other 31 316 128 158 7 1 8 14 12 675
Exploration 5 12 49 17 16 - - - - 99
Proved Property Acquisitions - - - 45(8) - - - - - 45
---------------------------------------------------------------------------------------------------
36 328 177 220 23 1 8 14 12 819
===================================================================================================
Property, Plant and Equipment
Cost 2,260 5,920 2,878 4,702 241 229 1,314 802 303 18,649
Less: Accumulated DD&A 2,012 1,521 1,406 636 77 52 196 444 158 6,502
---------------------------------------------------------------------------------------------------
Net Book Value 248 4,399(6) 1,472 4,066 164 177 1,118 358 145 12,147
===================================================================================================
- -------------
(1) Includes results of operations from producing activities in Colombia.
(2) Includes interest income of $10 million, foreign exchange losses of $38
million and decrease in the fair value of crude oil put options of $4
million.
(3) Includes recovery of stock-based compensation of $55 million.
(4) Includes exploration activities primarily in Nigeria, Norway and Colombia.
(5) Includes Yemen cash taxes of $65 million.
(6) Includes costs of $3,028 million related to our Long Lake project, which
are not being depreciated, depleted or amortized.
(7) Approximately 81% of Marketing's identifiable assets are accounts
receivable and inventories.
(8) Includes acquisition of additional interests in the Scott and Telford
fields.
18
SIX MONTHS ENDED JUNE 30, 2007
Corporate
Energy and
Oil and Gas Marketing Syncrude Chemicals Other Total
- -----------------------------------------------------------------------------------------------------------------------------------
United United Other
Yemen Canada States Kingdom Countries(1)
----------------------------------------------
Net Sales 531 228 316 936 64 23 234 207 - 2,539
Marketing and Other 6 4 - 28 - 531 - 22 (44)(2) 547
---------------------------------------------------------------------------------------------------
Total Revenues 537 232 316 964 64 554 234 229 (44) 3,086
Less: Expenses
Operating 84 81 54 106 4 19 98 133 - 579
Depreciation, Depletion,
Amortization and
Impairment 122 82 146 272 6 7 25 22 12 694
Transportation and Other 4 13 - - - 409 9 19 2 456
General and Administrative (3) (3) 40 14 2 25 53 - 17 92 240
Exploration 5 14 62 38 35(4) - - - - 154
Interest - - - - - - - 6 88 94
---------------------------------------------------------------------------------------------------
Income (Loss)
before Income Taxes 325 2 40 546 (6) 66 102 32 (238) 869
Less: Provision for (Recovery
of) Income Taxes 113(5) - 14 284 7 26 30 9 (111) 372
Less: Non-Controlling
Interests - - - - - - - 8 - 8
---------------------------------------------------------------------------------------------------
Net Income (Loss) 212 2 26 262 (13) 40 72 15 (127) 489
===================================================================================================
Identifiable Assets 441 4,543(6) 1,581 5,107 258 3,355(7) 1,186 495 228 17,194
===================================================================================================
Capital Expenditures
Development and Other 63 672 267 298 15 1 15 26 20 1,377
Exploration 10 45 63 63 26 - - - - 207
Proved Property Acquisitions - - - 46(8) - - - - - 46
---------------------------------------------------------------------------------------------------
73 717 330 407 41 1 15 26 20 1,630
===================================================================================================
Property, Plant and Equipment
Cost 2,260 5,920 2,878 4,702 241 229 1,314 802 303 18,649
Less: Accumulated DD&A 2,012 1,521 1,406 636 77 52 196 444 158 6,502
---------------------------------------------------------------------------------------------------
Net Book Value 248 4,399(6) 1,472 4,066 164 177 1,118 358 145 12,147
===================================================================================================
- ------------
(1) Includes results of operations from producing activities in Colombia.
(2) Includes interest income of $19 million, foreign exchange losses of $43
million and decrease in the fair value of crude oil put options of $20
million.
(3) Includes stock-based compensation expense of $61 million.
(4) Includes exploration activities primarily in Nigeria, Norway and Colombia.
(5) Includes Yemen cash taxes of $109 million.
(6) Includes costs of $3,028 million related to our Long Lake project, which
are not being depreciated, depleted or amortized.
(7) Approximately 81% of Marketing's identifiable assets are accounts
receivable and inventories.
(8) Includes acquisition of additional interests in the Scott and Telford
fields.
19
THREE MONTHS ENDED JUNE 30, 2006
Corporate
Energy and
Oil and Gas Marketing Syncrude Chemicals Other Total
- -----------------------------------------------------------------------------------------------------------------------------------
United United Other
Yemen Canada States Kingdom Countries(1)
----------------------------------------------
Net Sales 364 122 161 134 39 7 114 98 - 1,039
Marketing and Other 1 5 - 77(2) 1 293 - 12 (13)(3) 376
---------------------------------------------------------------------------------------------------
Total Revenues 365 127 161 211 40 300 114 110 (13) 1,415
Less: Expenses
Operating 38 34 22 20 1 5 44 59 - 223
Depreciation, Depletion,
Amortization and
Impairment 91 38 49 54 3 1 6 10 8 260
Transportation and Other 1 1 - - - 186 5 10 - 203
General and Administrative (4) - 9 10 2 9 39 - 6 33 108
Exploration - 8 15 8 15(5) - - - - 46
Interest - - - - - - - 3 8 11
---------------------------------------------------------------------------------------------------
Income (Loss)
before Income Taxes 235 37 65 127 12 69 59 22 (62) 564
Less: Provision for (Recovery
of) Income Taxes 82(6) (20) 22 42 4 42 19 7 (48) 150
Less: Non-Controlling
Interests - - - - - - - 6 - 6
---------------------------------------------------------------------------------------------------
Net Income (Loss) 153 57 43 85 8 27 40 9 (14) 408
===================================================================================================
Identifiable Assets 540 3,105 1,437 5,081 173 2,698(7) 1,177 462 295 14,968
===================================================================================================
Capital Expenditures
Development and Other 28 309 80 159 4 34 20 8 10 652
Exploration 10 71 72 6 8 - - - - 167
Proved Property Acquisitions - - - - - - - - - -
---------------------------------------------------------------------------------------------------
38 380 152 165 12 34 20 8 10 819
===================================================================================================
Property, Plant and Equipment
Cost 2,235 4,369 2,512 4,129 202 209 1,292 828 262 16,038
Less: Accumulated DD&A 1,923 1,369 1,196 319 70 42 174 474 136 5,703
---------------------------------------------------------------------------------------------------
Net Book Value 312 3,000 1,316 3,810 132 167 1,118 354 126 10,335
===================================================================================================
- ------------
(1) Includes results of operations from producing activities in Colombia.
(2) Includes proceeds of $74 million from business interruption insurance
claims for generator failures in 2005 at our UK oil and gas operations.
(3) Includes interest income of $11 million, foreign exchange losses of $27
million and increase in the fair value of crude oil put options of $3
million.
(4) Includes stock-based compensation expense of $11 million.
(5) Includes exploration activities primarily in Nigeria and Colombia.
(6) Includes Yemen cash taxes of $81 million.
(7) Approximately 84% of Marketing's identifiable assets are accounts
receivable and inventories.
20
SIX MONTHS ENDED JUNE 30, 2006
Corporate
Energy and
Oil and Gas Marketing Syncrude Chemicals Other Total
- -----------------------------------------------------------------------------------------------------------------------------------
United United Other
Yemen Canada States Kingdom Countries(1)
----------------------------------------------
Net Sales 692 233 342 268 67 14 198 205 - 2,019
Marketing and Other 4 6 - 79(2) 1 730 - 12 (30)(3) 802
---------------------------------------------------------------------------------------------------
Total Revenues 696 239 342 347 68 744 198 217 (30) 2,821
Less: Expenses
Operating 74 68 52 42 3 12 97 125 - 473
Depreciation, Depletion,
Amortization and
Impairment 168 75 104 125 5 4 11 20 14 526
Transportation and Other 3 11 - - - 418 11 20 - 463
General and Administrative (4) 14 51 45 6 25 75 - 13 99 328
Exploration - 14 77 28 30(5) - - - - 149
Interest - - - - - - - 5 15 20
---------------------------------------------------------------------------------------------------
Income (Loss)
before Income Taxes 437 20 64 146 5 235 79 34 (158) 862
Less: Provision for (Recovery
of) Income Taxes 153(6) (26) 22 324(7) 2 101 26 11 (85) 528
Less: Non-Controlling
Interests - - - - - - - 9 - 9
---------------------------------------------------------------------------------------------------
Net Income (Loss) 284 46 42 (178) 3 134 53 14 (73) 325
===================================================================================================
Identifiable Assets 540 3,105 1,437 5,081 173 2,698(8) 1,177 462 295 14,968
===================================================================================================
Capital Expenditures
Development and Other 75 634 144 279 13 35 57 10 17 1,264
Exploration 15 117 112 25 15 - - - - 284
Proved Property Acquisitions - 2 - 1 - - - - - 3
---------------------------------------------------------------------------------------------------
90 753 256 305 28 35 57 10 17 1,551
===================================================================================================
Property, Plant and Equipment
Cost 2,235 4,369 2,512 4,129 202 209 1,292 828 262 16,038
Less: Accumulated DD&A 1,923 1,369 1,196 319 70 42 174 474 136 5,703
---------------------------------------------------------------------------------------------------
Net Book Value 312 3,000 1,316 3,810 132 167 1,118 354 126 10,335
===================================================================================================
- ------------
(1) Includes results of operations from producing activities in Colombia.
(2) Includes proceeds of $74 million from business interruption insurance
claims for generator failures in 2005 at our UK oil and gas operations.
(3) Includes interest income of $19 million, foreign exchange losses of $48
million and decrease in the fair value of crude oil put options of $1
million.
(4) Includes stock-based compensation expense of $156 million.
(5) Includes exploration activities primarily in Nigeria and Colombia.
(6) Includes Yemen cash taxes of $148 million.
(7) Includes future income tax expense of $277 million related to an increase
in the supplemental tax rate on oil and gas activities in the United
Kingdom.
(8) Approximately 84% of Marketing's identifiable assets are accounts
receivable and inventories.
21
16. DIFFERENCES BETWEEN CANADIAN AND US GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
The Unaudited Consolidated Financial Statements have been prepared in
accordance with Canadian GAAP. The US GAAP Unaudited Consolidated Statement of
Income and Balance Sheet and summaries of differences from Canadian GAAP are as
follows:
(a) UNAUDITED CONSOLIDATED STATEMENT OF INCOME - US GAAP
FOR THE THREE AND SIX MONTHS ENDED JUNE 30
Three Months Six Months
Ended June 30 Ended June 30
(Cdn$ millions, except per share amounts) 2007 2006 2007 2006
- -----------------------------------------------------------------------------------------------------------------------------
REVENUES AND OTHER INCOME
Net Sales 1,399 1,039 2,539 2,019
Marketing and Other (i) 299 377 545 813
------------------------------------------------
1,698 1,416 3,084 2,832
------------------------------------------------
EXPENSES
Operating (ii) 296 225 592 477
Depreciation, Depletion, Amortization and Impairment 360 260 694 526
Transportation and Other 210 203 456 463
General and Administrative (iv) 51 122 250 343
Exploration 105 46 154 149
Interest 46 11 94 20
------------------------------------------------
1,068 867 2,240 1,978
------------------------------------------------
INCOME BEFORE INCOME TAXES 630 549 844 854
------------------------------------------------
PROVISION FOR INCOME TAXES
Current 151 136 211 245
Deferred (i) - (iv) 120 10 153 4
------------------------------------------------
271 146 364 249
------------------------------------------------
NET INCOME BEFORE NON-CONTROLLING INTERESTS 359 403 480 605
Less: Net Income Attributable to Non-Controlling Interests (5) (6) (8) (9)
------------------------------------------------
NET INCOME - US GAAP (1) 354 397 472 596
================================================
EARNINGS PER COMMON SHARE ($/share)
Basic (Note 11) 0.67 0.76 0.90 1.14
================================================
Diluted (Note 11) 0.66 0.74 0.88 1.11
================================================
- ------------
(1) Reconciliation of Canadian and US GAAP Net Income
Three Months Six Months
Ended June 30 Ended June 30
2007 2006 2007 2006
- --------------------------------------------------------------------------------------------------------------------------------
Net Income - Canadian GAAP 368 408 489 325
Impact of US Principles, Net of Income Taxes:
Ineffective Portion of Cash Flow Hedges (i) - 1 (2) 7
Pre-operating Costs (ii) (5) (2) (8) (3)
Deferred Income Taxes (iii) - - - 277
Liability-based Stock Compensation Plans (iv) (9) (10) (7) (10)
---------------------------------------------------
Net Income - US GAAP 354 397 472 596
=================================================
22
(b) UNAUDITED CONSOLIDATED BALANCE SHEET - US GAAP
June 30 December 31
(Cdn$ millions, except share amounts) 2007 2006
- -------------------------------------------------------------------------------------------------------------------------
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents 158 101
Restricted Cash and Margin Deposits 96 197
Accounts Receivable 2,861 2,976
Inventories and Supplies 857 786
Deferred Income Tax Asset 277 479
Other 51 67
------------------------
Total Current Assets 4,300 4,606
------------------------
PROPERTY, PLANT AND EQUIPMENT
Net of Accumulated Depreciation, Depletion, Amortization and
Impairment of $6,895 (December 31, 2006 - $6,792) (ii); (vi) 12,087 11,692
DEFERRED INCOME TAX ASSETS 78 141
DEFERRED CHARGES AND OTHER ASSETS 321 263
GOODWILL 348 377
------------------------
TOTAL ASSETS 17,134 17,079
========================
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Short-Term Borrowings 61 158
Accounts Payable and Accrued Liabilities (iv) 3,700 3,839
Accrued Interest Payable 65 55
Dividends Payable 13 13
------------------------
Total Current Liabilities 3,839 4,065
------------------------
LONG-TERM DEBT 4,852 4,618
DEFERRED INCOME TAX LIABILITIES (i) - (vi) 2,226 2,427
ASSET RETIREMENT OBLIGATIONS 690 683
DEFERRED CREDITS AND LIABILITIES (v) 502 597
NON-CONTROLLING INTERESTS 73 75
SHAREHOLDERS' EQUITY
Common Shares, no par value
Authorized: Unlimited
Outstanding: 2007 - 527,149,918 shares
2006 - 525,026,412 shares 893 821
Contributed Surplus 5 4
Retained Earnings (i) - (vi) 4,363 3,945
Accumulated Other Comprehensive Income (i); (v) (309) (156)
------------------------
Total Shareholders' Equity 4,952 4,614
------------------------
COMMITMENTS, CONTINGENCIES AND GUARANTEES
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY 17,134 17,079
========================
(c) UNAUDITED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME - US GAAP
FOR THE THREE AND SIX MONTHS ENDED JUNE 30
Three Months Six Months
Ended June 30 Ended June 30
(Cdn$ millions) 2007 2006 2007 2006
- --------------------------------------------------------------------------------------------------------------------------
Net Income - US GAAP 354 397 472 596
Other Comprehensive Income, Net of Income Taxes:
Foreign Currency Translation Adjustment (86) (63) (92) (65)
Change in Mark to Market on Cash Flow Hedges (i) - 6 (61) 20
-------------------------------------------------
Comprehensive Income 268 340 319 551
=================================================
23
(d) UNAUDITED CONSOLIDATED STATEMENT OF ACCUMULATED OTHER COMPREHENSIVE
INCOME - US GAAP
June 30 December 31
(Cdn$ millions) 2007 2006
- -------------------------------------------------------------------------------------------------
Foreign Currency Translation Adjustment (253) (161)
Mark to Market on Cash Flow Hedges (i) - 61
Unamortized Defined Benefit Pension Costs (v) (56) (56)
--------------------------------
(309) (156)
================================
NOTES:
i. Under US GAAP, 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. On January 1, 2007, we adopted the
equivalent Canadian standard for derivative instruments.
CASH FLOW HEDGES
Changes in the fair value of derivatives that are designated as cash flow
hedges are recognized in earnings in the same period as the hedged item.
Any fair value change in a derivative before that period is recognized on
the balance sheet. The effective portion of that change is recognized in
other comprehensive income with any ineffectiveness recognized in net
income during the period of change.
FUTURE SALE OF GAS INVENTORY: At December 31, 2006, accounts receivable
includes gains of $25 million on futures contracts and swaps we used to
hedge commodity price risk on the future sale of our gas inventory. Gains
of $23 million ($16 million, net of income taxes) related to the
effective portion and deferred in AOCI at December 31, 2006, were
recognized in marketing and other in the first quarter of 2007. The
ineffective portion of the gains of $2 million ($2 million, net of income
taxes) was recognized in marketing and other in 2006 under US GAAP. Under
Canadian GAAP, the ineffective portion was recognized in net income in
the first quarter of 2007.
At June 30, 2006, our US GAAP net income includes $11 million ($7
million, net of income taxes) relating to the ineffective portion of cash
flow hedges.
Also included in AOCI at December 31, 2006 are gains of $65 million ($45
million, net of income taxes) related to de-designated cash flow hedges.
These gains were recognized in marketing and other in the first quarter
of 2007. Under Canadian GAAP, these deferred gains are included in
accounts payable and accrued liabilities at December 31, 2006 and have
been recognized in marketing and other income in the first quarter of
2007.
At June 30, 2007, there were no cash flow hedges in place.
FAIR VALUE HEDGES
Both the derivative instrument and the underlying commitment are
recognized on the balance sheet at their fair value. The change in fair
value of both is reflected in earnings. At June 30, 2007 and at December
31, 2006, we had no fair value hedges in place.
ii. Under Canadian GAAP, we defer certain development costs and all
pre-operating revenues and costs to property, plant and equipment. Under
US principles, these costs have been included in operating expenses. As a
result:
o operating expenses include pre-operating costs of $7 million and
$13 million for the three and six months ended June 30, 2007,
respectively ($5 million and $8 million, respectively, net of
income taxes) (2006 - $2 million and $4 million, respectively ($2
million and $3 million, respectively, net of income taxes)); and
o property, plant and equipment is lower under US GAAP by $41 million
(December 31, 2006 - $28 million).
iii. Under US GAAP, enacted tax rates are used to calculate deferred income
taxes, whereas under Canadian GAAP, substantively enacted rates are used.
During the first quarter of 2006, the UK government substantively enacted
increases to the supplementary tax on oil and gas activities from 10% to
20%, effective January 1, 2006. This created a $277 million future income
tax expense during the first quarter of 2006 under Canadian GAAP.
iv. Under Canadian principles, we record obligations for liability-based
stock compensation plans using the intrinsic-value method of accounting.
Under US principles, obligations for liability-based stock compensation
plans are recorded using the fair-value method of accounting. We are also
required to accelerate the recognition of stock-based compensation
expense for all stock-based awards made to our retirement-eligible
employees under Canadian GAAP. However, under US GAAP, the accelerated
recognition for such employees is only required for stock-based awards
granted on or after January 1, 2006. As a result:
24
o general and administrative expense is higher by $13 million and $10
million for the three and six months ended June 30, 2007,
respectively ($9 million and $7 million, respectively, net of
income taxes) (2006 - higher by $14 million and $15 million for the
three and six months ended June, respectively ($10 million and $10
million, respectively, net of income taxes)); and
o accounts payable and accrued liabilities are higher by $35 million
as at June 30, 2007 (December 31, 2006 - $25 million).
v. On December 31, 2006, we adopted FASB Statement 158 EMPLOYERS' ACCOUNTING
FOR DEFINED BENEFIT PENSION AND OTHER POSTRETIREMENT PLANS (FAS 158). At
June 30, 2007, the unfunded amount of our defined benefit pension plans
was $81 million. This amount has been included in deferred credits and
other liabilities and $56 million, net of income taxes has been included
in AOCI. Prior to the adoption of FAS 158 on December 31, 2006, we
included our minimum unfunded pension liability in deferred credits and
other liabilities and in AOCI.
vi. On January 1, 2003, we adopted FASB Statement 143, ACCOUNTING FOR ASSET
RETIREMENT OBLIGATIONS (FAS 143) for US GAAP reporting purposes. We
adopted the equivalent Canadian standard for asset retirement obligations
on January 1, 2004. These standards are consistent except for the
adoption date which results in our property, plant and equipment under US
GAAP being lower by $19 million.
STOCK-BASED COMPENSATION EXPENSE FOR RETIRED AND RETIREMENT-ELIGIBLE EMPLOYEES
Under US GAAP, we recognize stock-based compensation expense for our retired
and retirement-eligible employees over an accelerated vesting period in
accordance with the provisions of Statement 123(R) for stock-based awards
granted to employees on or after January 1, 2006. For stock-based awards
granted prior to the adoption of Statement 123(R), stock-based compensation
expense for our retired and retirement-eligible employees is recognized over a
graded vesting period. If we applied the accelerated vesting provisions of
Statement 123(R) to stock-based awards granted to our retired and
retirement-eligible employees prior to the adoption of Statement 123(R), there
would be no material change to our stock-based compensation expense for the
three and six months ended June 30, 2007 and 2006.
CHANGES IN ACCOUNTING POLICIES - US GAAP
INCOME TAXES
On January 1, 2007, we adopted FASB Interpretation 48 ACCOUNTING FOR
UNCERTAINTY IN INCOME TAXES (FIN 48) with respect to FAS 109 ACCOUNTING FOR
INCOME TAXES regarding accounting and disclosure for uncertain tax positions.
On the adoption of FIN 48, we recorded a cumulative effect of a change in
accounting principle of $28 million. This amount increased our deferred income
tax liabilities, with a corresponding decrease to our retained earnings as at
January 1, 2007 in our US GAAP - Unaudited Consolidated Balance Sheet. As at
January 1 and June 30, 2007, the total amount of our unrecognized tax benefits
was approximately $210 million, all of which, if recognized, would affect our
effective tax rate. As at January 1 and June 30, 2007, the total amount of
interest and penalties in relation to uncertain tax positions recognized in
deferred income tax liabilities in the US GAAP - Unaudited Consolidated Balance
Sheet is approximately $9 million. We had no interest or penalties in the US
GAAP - Unaudited Consolidated Statement of Income for the first half of 2007.
Our income tax filings are subject to audit by taxation authorities and as at
January 1 and June 30, 2007 the following tax years remained subject to
examination; (i) Canada - 1985 to date, (ii) United Kingdom - 2002 to date and
(iii) United States - 2003 to date. We do not anticipate any material changes
to the unrecognized tax benefits previously disclosed within the next twelve
months.
NEW US ACCOUNTING PRONOUNCEMENTS
In September 2006, the Financial Accounting Standards Board (FASB) issued
Statement 157, FAIR VALUE MEASUREMENTS. Statement 157 defines fair value,
establishes a framework for measuring fair value under US generally accepted
accounting principles and expands disclosures about fair value measurements.
This statement is effective for fiscal years beginning after November 15, 2007.
We do not expect the adoption of this statement will have a material impact on
our results of operations or financial position.
Effective December 31, 2006, we adopted the recognition and disclosure
provisions of FASB Statement 158, EMPLOYERS' ACCOUNTING FOR DEFINED BENEFIT
PENSION AND OTHER POSTRETIREMENT PLANS. This statement also requires
measurement of the funded status of a plan as of the balance sheet date. The
measurement provisions of the statement are effective for fiscal years ending
after December 15, 2008. We do not expect the adoption of the change in
measurement date in 2008 to have a material impact on our results of operations
or financial position.
In February 2007, FASB issued Statement 159, THE FAIR VALUE OPTION FOR
FINANCIAL ASSETS AND FINANCIAL LIABILITIES. The statement allows for the
elective measurement of eligible financial instruments and certain other items
at fair value in order to mitigate volatility in reported earnings without
having to apply complex and detailed hedge accounting rules. This statement is
effective for fiscal years beginning after November 15, 2007. We are currently
evaluating the provisions of Statement 159 and have not yet determined the
impact this statement will have on our results from operations or financial
position.
25
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
THE FOLLOWING SHOULD BE READ IN CONJUNCTION WITH THE UNAUDITED CONSOLIDATED
FINANCIAL STATEMENTS INCLUDED IN THIS REPORT. THE UNAUDITED CONSOLIDATED
FINANCIAL STATEMENTS HAVE BEEN PREPARED IN ACCORDANCE WITH GENERALLY ACCEPTED
ACCOUNTING PRINCIPLES (GAAP) IN CANADA. THE IMPACT OF THE SIGNIFICANT
DIFFERENCES BETWEEN CANADIAN AND UNITED STATES (US) ACCOUNTING PRINCIPLES ON
THE FINANCIAL STATEMENTS IS DISCLOSED IN NOTE 16 TO THE UNAUDITED CONSOLIDATED
FINANCIAL STATEMENTS. THE DATE OF THIS DISCUSSION IS JULY 11, 2007.
UNLESS OTHERWISE NOTED, TABULAR AMOUNTS ARE IN MILLIONS OF CANADIAN DOLLARS.
THE DISCUSSION AND ANALYSIS OF OUR OIL AND GAS ACTIVITIES WITH RESPECT TO OIL
AND GAS VOLUMES, RESERVES AND RELATED PERFORMANCE MEASURES IS PRESENTED ON A
WORKING-INTEREST, BEFORE-ROYALTIES BASIS. WE MEASURE OUR PERFORMANCE IN THIS
MANNER CONSISTENT WITH OTHER CANADIAN OIL AND GAS COMPANIES. WHERE APPROPRIATE,
WE HAVE PROVIDED INFORMATION ON A NET, AFTER-ROYALTIES BASIS IN TABULAR FORMAT.
NOTE: CANADIAN INVESTORS SHOULD READ THE SPECIAL NOTE TO CANADIAN INVESTORS ON
PAGE 81 OF OUR 2006 ANNUAL REPORT ON FORM 10-K WHICH HIGHLIGHTS DIFFERENCES
BETWEEN OUR RESERVE ESTIMATES AND RELATED DISCLOSURES THAT ARE OTHERWISE
REQUIRED BY CANADIAN REGULATORY AUTHORITIES.
WE MAKE ESTIMATES AND ASSUMPTIONS THAT AFFECT THE REPORTED AMOUNTS OF OUR
ASSETS AND LIABILITIES AND THE DISCLOSURE OF CONTINGENT ASSETS AND LIABILITIES
AT THE DATE OF THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS AND OUR REVENUES
AND EXPENSES DURING THE REPORTED PERIOD. OUR MANAGEMENT REVIEWS THESE
ESTIMATES, INCLUDING THOSE RELATED TO ACCRUALS, LITIGATION, ENVIRONMENTAL AND
ASSET RETIREMENT OBLIGATIONS, INCOME TAXES, DERIVATIVE CONTRACT ASSETS AND
LIABILITIES AND THE 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.
EXECUTIVE SUMMARY OF SECOND QUARTER RESULTS
Three Months Six Months
Ended June 30 Ended June 30
2007 2006 2007 2006
- -----------------------------------------------------------------------------------------------------------------------
Net Income 368 408 489 325
Earnings per Common Share ($/share) 0.70 0.78 0.93 0.62
Cash Flow from Operating Activities 582 374 1,030 1,108
Production, before Royalties (mboe/d) 253 215 246 219
Production, after Royalties (mboe/d) 208 158 199 159
Nexen's Average Realized Oil and Gas Price (Cdn$/boe) 68.48 66.78 63.95 63.90
Capital Investment, including Acquisitions 819 876 1,630 1,629
Net Debt (1) 4,755 3,930 4,755 3,930
-----------------------------------------------------
- ------------
(1) Net debt is defined as long-term debt and short-term borrowings less cash
and cash equivalents.
Increasing production and high commodity prices generated strong net income and
cash flow from operating activities during the quarter. Our second quarter
realized oil and gas prices increased 3% from the same period in 2006, while
WTI was 8% lower than last year. The impact of WTI prices on our realized
prices is becoming less relevant as approximately 80% of our current production
is priced based on North Sea Brent crude. Brent crude oil prices fell only 1%
during the same period.
Production after royalties increased 9% from the previous quarter by bringing
new high-margin, royalty-free production on stream at Buzzard. At Buzzard,
eight development wells are now tied into the production system and the gas
export system has been commissioned. Increases from Buzzard were partially
offset by natural declines in Yemen and in the Gulf of Mexico. We also
experienced unexpected production downtime at Aspen and Syncrude following
maintenance to third party processing facilities and turnaround advancements.
In the Gulf of Mexico, the Wrigley development began producing in early July
and we expect to bring another development well at Aspen on stream by the end
of the third quarter.
At Long Lake, steaming of the reservoir is going well. While commissioning
activities delayed the startup of our large steam generation units by a few
weeks, we still expect all 81 SAGD well pairs (ten pads) to be circulating
steam by the end of August. As we circulate steam and heat up the reservoir to
establish communication between wells, we will start to produce bitumen. We
expect bitumen production to ramp up to peak rates over a 12 to 24 month
period.
The increase in our net debt compared to last year largely reflects the ongoing
investment at Long Lake and on Ettrick in the UK North Sea. The increase in net
debt was partially offset by the weakening US dollar as our US-dollar
denominated debt was lower when translated to Canadian dollars.
26
CAPITAL INVESTMENT
Our capital investment strategy continues to focus on developing major
projects, exploring our growth basins, maximizing the remaining value of our
core assets and investing in new technology. In 2007, we are investing in:
o Major Development projects such as Long Lake Phase 1, Ettrick in the
North Sea and coalbed methane in Canada;
o Early Stage Developments including Phase 2 of Long Lake, shale gas in
Canada and the Usan project, offshore West Africa;
o New Growth Exploration targeting up to 19 high-impact exploration
prospects, primarily in the Gulf of Mexico and the North Sea; and
o Core Asset Developments in our existing asset base including Wrigley
and Aspen in the Gulf of Mexico.
Details of our capital programs are set out below.
THREE MONTHS ENDED JUNE 30, 2007
Major Early Stage New Growth Core Asset
Development Development Exploration Development Total
- --------------------------------------------------------------------------------------------------------------------------------
Oil and Gas
Synthetic (mainly Long Lake) 258 21 3 - 282
United Kingdom 131 - 17 72 220
Yemen - - 5 31 36
United States 9 - 49 119 177
Canada 22 5 9 10 46
Other Countries - 3 16 4 23
Syncrude - - - 8 8
----------------------------------------------------------------------------
420 29 99 244 792
Chemicals, Marketing, Corporate and Other - - - 27 27
----------------------------------------------------------------------------
Total Capital 420 29 99 271 819
============================================================================
As a % of Total Capital 51% 4% 12% 33% 100%
----------------------------------------------------------------------------
SIX MONTHS ENDED JUNE 30, 2007
Major Early Stage New Growth Core Asset
Development Development Exploration Development Total
- --------------------------------------------------------------------------------------------------------------------------------
Oil and Gas
Synthetic (mainly Long Lake) 513 71 3 - 587
United Kingdom 254 - 63 90 407
Yemen - - 10 63 73
United States 23 - 63 244 330
Canada 44 9 42 35 130
Other Countries - 8 26 7 41
Syncrude - - - 15 15
----------------------------------------------------------------------------
834 88 207 454 1,583
Chemicals, Marketing, Corporate and Other - - - 47 47
----------------------------------------------------------------------------
Total Capital 834 88 207 501 1,630
============================================================================
As a % of Total Capital 51% 5% 13% 31% 100%
----------------------------------------------------------------------------
MAJOR AND EARLY STAGE DEVELOPMENT PROJECTS
SYNTHETIC
At Long Lake, commissioning of our large steam generator units is underway.
While we are experiencing delays in the start up of these units, all 81 SAGD
well pairs (ten pads) are expected to be steaming by the end of August. As we
circulate steam and heat up the reservoir to establish communication between
the wells, we will start to produce bitumen. We expect bitumen production to
ramp up to full rates over a 12 to 24 month period. While our initial
steam-to-oil ratios will be high as we heat up the reservoir, we expect our
steam-to-oil ratio to average approximately 3.0 over the project life.
Upgrader construction is approximately 90% complete and projected to start up
late this year. Full production of premium synthetic crude oil is expected
within 12 to 18 months of upgrader start up. Production capacity for the first
phase of Long Lake is approximately 60,000 bbls/d (30,000 bbls/d net to us) of
premium synthetic crude. Our cost estimate for Phase 1 ranges from $5.0 to $5.3
billion ($2.5 to $2.65 billion net to us).
27
We plan to sequentially develop additional 60,000 bbls/d (30,000 bbls/d net)
phases using the same technology and design as Long Lake. The timing of Phase 2
sanctioning will depend on accumulating sufficient production history from
Phase 1 and receiving additional clarity on fiscal and regulatory policies
related to oil sands development and climate change.
UNITED KINGDOM - ETTRICK
Our Ettrick field development in the North Sea continues to progress well and
is approximately 70% complete. The project will consist of three production
wells and one water injector tied back to a leased floating production, storage
and offloading vessel (FPSO). The FPSO is designed to handle 30,000 bbls/d of
oil, 35 mmcf/d of gas and to re-inject 55,000 bbls/d of water. Production from
the field is expected to commence in mid 2008 with our share averaging
approximately 9,000 boe/d for the year. We have an 80% operated working
interest.
Elsewhere in the North Sea, we are evaluating development options for our
Golden Eagle discovery.
CANADA - COALBED METHANE (CBM)
Our Mannville CBM project in the Fort Assiniboine area of Alberta is currently
producing approximately 24 mmcf/d. We expect this to double by year-end and
continue to grow as we develop additional sections of land in the Corbett,
Thunder and Doris fields using multiple leg-horizontal wells.
OFFSHORE WEST AFRICA
The Usan field development, located in Nigeria on offshore Block OPL-222,
continues to progress toward project sanction. The project will have the
ability to process an average of 180,000 bbls/day of oil during the initial
production plateau period through a new FPSO with a two million barrel storage
capacity. We expect the Usan development to be formally sanctioned this year,
at which time the major deep-water facilities and drilling contracts will be
awarded. We have a 20% interest in exploration and development on this block.
NEW GROWTH EXPLORATION
We are currently drilling our Vicksburg exploration well located on De Soto
Canyon Block 353 in the Eastern Gulf. We expect to have drilling results late
in the third quarter. We have a 25% non-operated working interest.
At Knotty Head located on Green Canyon Block 512, we are expecting to drill our
next appraisal well in the first half of 2008. We have a 25% operated interest
in the field.
At Longhorn (previously named Ringo) located on Mississippi Canyon Block 546,
we have an appraisal well planned later this year and at Alaminos Canyon Block
856 (Great White West), we are continuing to evaluate development options. We
have non-operated working interests of 25% and 30% in these projects,
respectively.
In the North Sea, we are drilling an appraisal well at Selkirk located on Block
22/22b. Results from this well are expected in the third quarter. We have a 38%
operated working interest here. Additionally, we plan to drill an appraisal
well at Bugle, and spud three exploration wells later this year.
Over the next 12 months or so, we expect to drill at least 18 exploration wells
with the majority in the Gulf of Mexico and the UK North Sea. During the
quarter, we were also awarded an additional two licenses in the Norwegian North
Sea.
CORE ASSET DEVELOPMENT
At Buzzard, we currently have eight development wells on stream. The production
ramp up to date has met our expectations and we have sufficient well
deliverability to take advantage of additional processing capacity that may be
available on the platform. The facility is designed to process up to 200,000
bbls/d of oil and 60 mmcf/d of gas.
At our Wrigley development on Mississippi Canyon Block 506, we began producing
early in the third quarter. We expect production to quickly ramp up to 60
mmcf/d (30 mmcf/d net to us). We have a 50% non-operated interest.
At Aspen, we are completing a sidetrack well to exploit a number of deeper
sands. We expect this well to come on stream in the third quarter. We have a
100% operated working interest at Aspen.
28
FINANCIAL RESULTS
CHANGE IN NET INCOME
2007 VS. 2006
Three Months Six Months
Ended June 30 Ended June 30
- -------------------------------------------------------------------------------------------------------------------------
NET INCOME AT JUNE 30, 2006 408 325
=================================
Favourable (unfavourable) variances:
Production Volumes, After Royalties
Crude Oil 360 593
Natural Gas (18) (36)
Change in Crude Oil Inventory 8 2
---------------------------------
Total Volume Variance 350 559
Realized Commodity Prices
Crude Oil (8) (47)
Natural Gas 15 (3)
---------------------------------
Total Price Variance 7 (50)
Oil and Gas Operating Expense
Conventional (50) (90)
Syncrude (7) (1)
---------------------------------
Total Operating Expense Variance (57) (91)
Depreciation, Depletion, Amortization and Impairment
Oil & Gas and Syncrude (99) (165)
Other (1) (3)
---------------------------------
Total Depreciation, Depletion, Amortization and Impairment Variance (100) (168)
Exploration Expense (59) (5)
Energy Marketing Contribution (13) (188)
Chemicals Contribution 2 5
General and Administrative Expense 70 88
Interest Expense (35) (74)
Current Income Taxes (15) 34
Future Income Taxes (112) 122
Other
Decrease in Fair Value of Crude Oil Put Options (7) (19)
Business Interruption Insurance Proceeds (74) (74)
Other 3 25
---------------------------------
NET INCOME AT JUNE 30, 2007 368 489
=================================
Significant variances in net income are explained further in the following
sections.
29
OIL & GAS AND SYNCRUDE
PRODUCTION (BEFORE ROYALTIES) (1)
Three Months Six Months
Ended June 30 Ended June 30
2007 2006 2007 2006
- --------------------------------------------------------------------------------------------------------------------------
Crude Oil and NGLs (mbbls/d)
Yemen 73.3 95.2 75.2 98.8
Canada 17.2 20.6 17.5 21.4
United States 16.0 17.8 18.8 18.5
United Kingdom 85.6 17.2 70.7 16.5
Other Countries 6.2 6.6 6.0 6.2
Syncrude (2) 19.0 17.4 20.2 16.1
-------------------------------------------------------
217.3 174.8 208.4 177.5
-------------------------------------------------------
Natural Gas (mmcf/d)
Canada 116 104 117 105
United States 86 107 93 114
United Kingdom 14 32 14 27
-------------------------------------------------------
216 243 224 246
-------------------------------------------------------
Total (mboe/d) 253 215 246 219
=======================================================
PRODUCTION (AFTER ROYALTIES)
Three Months Six Months
Ended June 30 Ended June 30
2007 2006 2007 2006
- --------------------------------------------------------------------------------------------------------------------------
Crude Oil and NGLs (mbbls/d)
Yemen 41.6 52.3 43.3 53.0
Canada 13.4 16.2 13.8 17.0
United States 14.2 15.6 16.8 16.3
United Kingdom 85.6 17.2 70.7 16.5
Other Countries 5.7 6.0 5.5 5.7
Syncrude (2) 16.4 15.7 17.6 14.5
-------------------------------------------------------
176.9 123.0 167.7 123.0
-------------------------------------------------------
Natural Gas (mmcf/d)
Canada 97 88 96 89
United States 74 91 80 97
United Kingdom 14 32 14 27
-------------------------------------------------------
185 211 190 213
-------------------------------------------------------
Total (mboe/d) 208 158 199 159
=======================================================
- ------------
(1) We have presented production volumes before royalties as we measure our
performance on this basis consistent with other Canadian oil and gas
companies.
(2) Considered a mining operation for US reporting purposes.
30
HIGHER PRODUCTION INCREASED NET INCOME FOR THE QUARTER BY $350 MILLION
Production after royalties increased 9% from the prior quarter and 32% from the
second quarter of 2006 as we continue to ramp up our high-margin, royalty-free
Buzzard production in the UK North Sea. Production before royalties increased
6% from the previous quarter and 18% from the second quarter of 2006.
The following table summarizes our production volume changes since the last
quarter:
Before After
(mboe/d) Royalties Royalties
- --------------------------------------------------------------------------------
Production, first quarter 2007 238 191
Production changes:
United Kingdom 30 30
United States (8) (7)
Yemen (4) (3)
Syncrude (2) (2)
Other (1) (1)
-----------------------
Production, second quarter 2007 253 208
=======================
We expect our production will continue to increase in 2007 by reaching facility
design capacity at Buzzard, from bringing a sidetrack development well on
stream at Aspen and new production from Wrigley in the Gulf of Mexico and from
bitumen production at Long Lake later this year. Long Lake synthetic crude oil
production is expected to begin in late 2007. Production volumes discussed in
this section represent before-royalties volumes, net to our working interest.
YEMEN
Production from the Masila field decreased 6% from the prior quarter and 20%
from the second quarter of 2006. Production declines at Masila reflect the
maturity of the field and the impact of a reduced 2007 development drilling
program. We have drilled nine development wells and four sidetrack wells on the
Masila block to date this year. We plan to drill at least five additional
development wells and seven sidetrack wells in the second half of 2007.
Production declines are expected to continue as we concentrate our capital
spending on maximizing recovery of the remaining reserves on the block.
Block 51 production remained steady from the first quarter; however, our
production decreased 33% from the second quarter of 2006 as a result of natural
declines. Our 2007 capital investment program includes further development of
the BAK A field and we have drilled seven of eleven planned development wells
this year. We are also de-bottlenecking the production facilities to handle
additional water, continuing to optimize wells and completing the water
handling and power plant expansions.
CANADA
Production in Canada was slightly lower than the previous quarter and the
second quarter of 2006. Natural declines at our heavy oil properties were
partially offset by our capital program additions. Declines in our natural gas
properties in the Medicine Hat region have been offset by capital investment in
infill drilling and well optimization activities. CBM production continues to
increase as our wells in the Fort Assiniboine area de-water and we bring
additional development wells and facilities on stream.
Production volumes are expected to increase in the remainder of 2007 from
additional CBM natural gas volumes and new Long Lake bitumen production towards
the end of the year.
UNITED STATES
Gulf of Mexico production decreased 8,100 boe/d or 21% from the prior quarter
largely from downtime caused by equipment maintenance and natural field
declines. Our Aspen production was reduced approximately 1,500 boe/d during the
quarter as processing facilities on the non-operated Bullwinkle platform were
shut-in for approximately twelve days for maintenance. We expect Aspen
production to increase as we are completing a sidetrack on Aspen-1 to exploit a
deeper sand and expect it on stream during the third quarter.
Gunnison production decreased 15% from the prior quarter due to mechanical
problems in one high volume well, while shelf production declined from last
year as a result of lower performance, equipment maintenance and program
delays. Production from our 50% non-operated Wrigley development began early in
the third quarter and we expect to reach peak rates of 60 mmcf/d (30 mmcf/d net
to us) later in the third quarter.
31
UNITED KINGDOM
Buzzard continued to ramp up during the quarter as expected and is approaching
facility design capacity. Production for the quarter averaged 157,500 boe/d
(68,000 boe/d, net to us) from eight development wells. During the quarter, we
commissioned the gas export system and began selling gas through the Frigg
pipeline. We have now commissioned all remaining production systems and are
evaluating the performance of the production facilities. We plan to drill four
additional development wells by the end of the year. We are reviewing
de-bottlenecking opportunities as we maximize production efficiency of the
facilities.
Production on the Scott/Telford fields was 1,500 boe/d lower from the first
quarter despite acquiring additional working interests in the fields early in
the quarter. The decrease was a result of natural declines and downtime related
to maintenance and workover activity. The non-operated Farragon field produced
approximately 2,800 boe/d during the quarter, with lower than expected natural
declines.
OTHER COUNTRIES
Production from our Guando field in Colombia averaged 6,200 bbls/d during the
quarter, 7% above the prior quarter. We began a 35 well infill drilling program
earlier in the year and 14 wells have been drilled to date. We expect
production from Colombia to average between 6,000 and 7,000 bbls/d in 2007.
SYNCRUDE
Syncrude production was 11% lower than the prior quarter due to downtime caused
by an extended turnaround on the LC Finer and by completing a turnaround on
Coker 8-3. Circulation difficulties that restricted the capacity of Coker 8-3
since mid December have now been resolved and we expect higher production for
the remainder of the year.
In 2007, we expect our total-year production from Syncrude to average between
20,000 and 25,000 boe/d.
32
COMMODITY PRICES
Three Months Six Months
Ended June 30 Ended June 30
2007 2006 2007 2006
- ------------------------------------------------------------------------------------------------------------------------
CRUDE OIL AND NGLS
West Texas Intermediate (WTI) (US$/bbl) 65.03 70.70 61.60 67.09
-----------------------------------------------------
Differentials (1) (US$/bbl)
Heavy Oil 20.00 17.88 18.29 23.39
Mars 2.84 6.97 3.97 7.43
Masila (3.33) 2.71 (0.66) 3.24
Dated Brent (3.73) 1.08 (1.66) 1.40
Producing Assets (Cdn$/bbl)
Yemen 77.34 76.86 69.99 72.44
Canada 41.89 51.67 41.80 40.44
United States 68.18 70.23 62.63 66.86
United Kingdom 74.07 73.24 70.18 71.16
Other Countries 68.04 69.63 64.07 64.60
Syncrude 77.12 79.50 73.39 75.14
Corporate Average (Cdn$/bbl) 72.27 72.90 67.20 67.92
-----------------------------------------------------
NATURAL GAS
New York Mercantile Exchange (NYMEX) (US$/mmbtu) 7.66 6.67 7.42 7.27
AECO (Cdn$/GJ) 6.99 5.95 7.03 7.37
-----------------------------------------------------
Producing Assets (Cdn$/mcf)
Canada 7.06 6.21 7.11 6.93
United States 8.85 7.51 8.71 8.33
United Kingdom 3.32 5.52 3.59 8.31
Corporate Average (Cdn$/mcf) 7.52 6.68 7.56 7.70
-----------------------------------------------------
NEXEN'S AVERAGE REALIZED OIL AND GAS PRICE (Cdn$/boe) 68.48 66.78 63.95 63.90
-----------------------------------------------------
AVERAGE FOREIGN EXCHANGE RATE
Canadian to US Dollar 0.9107 0.8918 0.8812 0.8786
-----------------------------------------------------
- ------------
(1) These differentials are a discount/(premium) to WTI.
HIGHER REALIZED COMMODITY PRICES INCREASED QUARTERLY NET INCOME BY $7 MILLION
WTI prices increased 12% over the previous quarter, but were 8% lower than the
second quarter of 2006. We realized higher prices for our crude oil sales as a
result of strong benchmark commodity prices compared to the previous quarter.
Our realized crude oil price averaged $72.27/bbl in the quarter, 17% higher
than the previous quarter. Our realized gas price decreased 1% from the
previous quarter to average $7.52/mcf. NYMEX increased 7% in the same period.
CRUDE OIL REFERENCE PRICES
Crude oil prices remained strong throughout the second quarter of 2007, with
WTI averaging US$65.03/bbl. The trading range for WTI in the quarter was
between US$60.68/bbl and US$71.06/bbl. The main drivers behind strong crude
prices continue to be geopolitical issues in Nigeria and the Middle East,
strong gasoline demand in North America and the threat of a severe 2007
hurricane season in the Gulf of Mexico.
Concerns over geopolitical stability are supporting strong crude oil prices.
Geopolitical risk in Nigeria and Iran, the world's eighth and fourth largest
oil exporters, respectively, play a dominant role in applying upward pressure
on crude prices. Violence in Nigeria continues to create supply outages
reducing production by 800,000 barrels per day or approximately one third of
total Nigerian capacity. In addition, the recent presidential election has
contributed to volatile prices. Aside from Nigeria, on-going tensions involving
Iran and its uranium enrichment program have led US warships to converge in the
Gulf. More recently, Turkey has created new geopolitical concern in the Middle
East. It was reported that Turkish troops have entered northern Iraq, an area
rich in oil. Turkey has denied these reports but stated that the country is
trying to establish temporary security zones near the Iraq border.
33
In the US, supply concerns around gasoline stocks are driving higher crude oil
prices. Reduced refinery utilization and speculation around the impact of the
summer driving season have caused prices to remain high. Hurricane forecasters
are predicting an active US storm season which may rival that of two years ago.
Crude prices have strengthened in anticipation of significant production
disruptions in the Gulf of Mexico. In the current tight supply environment, any
potential supply disruptions can have a significant impact on global crude oil
prices as there is perceived to be little spare capacity.
CRUDE OIL DIFFERENTIALS
In Canada, heavy crude oil differentials averaged US$20.00/bbl (31% of WTI),
compared to US$17.88/bbl in the second quarter of 2006 (25% of WTI). Heavy oil
differentials are wide due to weak demand for heavier crude given the number of
complex refineries off-line and strong light crude prices. The market should
improve as refineries come back on-line and demand increases with the summer
asphalt season.
The Brent/WTI differential strengthened during the second quarter with Brent
trading at a premium averaging US$3.73/bbl compared to a discount of
US$1.08/bbl for the same period last year. The Brent index is becoming
increasingly relevant for us as approximately 80% of our current crude
production is priced based on Brent. Brent historically traded at a discount of
US$1.50 to US$2.00 per barrel to WTI but the spread broke away last year.
Regional issues, such as an overabundance of crude in local storage around the
Cushing, Oklahoma area where WTI is priced and the limited ability to move that
crude to world markets are causing WTI to trade at lower prices than
international crude grades. By comparison, Brent prices are still strong as
multiple transportation options allow it to remain a global crude oil. For the
present time, WTI does not represent a global benchmark price. Demand for WTI
relative to Brent is expected to strengthen during the third quarter as US
refineries are brought back on line and crude stocks at Cushing return to
normal operational levels. Longer term, we expect WTI will be impacted by
weaker world demand growth and by competition from new Canadian oil sands
production.
On the US Gulf Coast, the Mars differential narrowed during the quarter to
reach new historical lows, averaging US$2.84/bbl (4% of WTI) compared to
US$6.97/bbl (10% of WTI) in the same period last year. The narrowing Mars
differential reflects weaker prices for WTI. Offshore US crude such as Mars has
access to water transportation routes preventing it from being impacted by
constraints in WTI pricing.
The Yemen Masila differential narrowed substantially relative to WTI with
Masila trading at a premium averaging US$3.33/bbl compared to a discount of
US$2.71/bbl in the second quarter of 2006. Strong demand growth in China has
been the primary driver for the strengthening of Masila crude. In addition,
stronger Brent pricing has provided upside support since Masila crude is priced
off Brent.
NATURAL GAS REFERENCE PRICES
NYMEX natural gas prices averaged US$7.66/mmbtu for the quarter, compared to
US$6.67/mmbtu in the second quarter of 2006. Natural gas prices strengthened
despite new sources of supply from higher liquefied natural gas (LNG) imports.
European gas prices collapsed in April from mild weather, causing spot LNG
cargoes to be diverted to the US market. However, North American natural gas
prices remained strong during the typically mild shoulder season from support
provided by strong crude oil prices, the possibility of hot summer weather and
a potentially active hurricane season.
OPERATING COSTS
Three Months Six Months
Ended June 30 Ended June 30
(Cdn$/boe) 2007 2006 2007 2006
- ----------------------------------------------------------------------------------------------------------------------------------
Operating costs based on our working interest production before royalties (1)
Conventional Oil and Gas 7.76 6.47 7.99 6.52
Synthetic Crude Oil
Syncrude 29.91 27.84 27.00 33.45
Total Oil and Gas 9.41 8.21 9.54 8.50
-----------------------------------------------
Operating costs based on our net production after royalties
Conventional Oil and Gas 9.50 9.29 9.97 9.41
Synthetic Crude Oil
Syncrude 34.54 30.93 30.89 37.09
Total Oil and Gas 11.48 11.46 11.81 11.96
-----------------------------------------------
- ------------
(1) Operating costs per boe are our total oil and gas operating costs divided
by our working interest production before royalties. We use production
before royalties to monitor our performance consistent with other Canadian
oil and gas companies.
34
HIGHER OIL AND GAS OPERATING COSTS DECREASED NET INCOME FOR THE QUARTER BY
$57 MILLION
Our oil and gas average operating cost was impacted by changes in our
production mix during the quarter. New production from Buzzard in the North Sea
and additional Syncrude production are higher contributors to our total
production. Operating costs on the Buzzard platform are lower than our
corporate average, reducing our consolidated average by $1.64/boe during the
quarter. The impact of Buzzard production increased our operating expense by
$29 million in the quarter. Additional higher-cost production from the Stage 3
expansion at Syncrude increased our corporate average by $0.56/boe.
In Yemen, lower production at Masila and Block 51, together with higher service
rig activity and maintenance programs, have increased our corporate unit
average cost by $0.77/boe. Industry cost pressures caused by the strong
commodity price environment have increased our Gulf of Mexico operating costs.
We have also performed additional down hole and surface maintenance activity to
maintain production rates which has increased costs. These increases, combined
with a decrease in production, increased our corporate average unit operating
cost by $0.41/boe.
In Canada, operating costs increased our corporate average by $0.58/boe. Our
heavy oil properties have higher operating costs per boe as many of our costs
are fixed in nature and heavy oil production volumes are decreasing. Unit
operating costs at CBM are higher initially as we de-water the wells to
stimulate gas production. Costs have also increased as we ramp up our CBM
operations with more wells coming on stream at Fort Assiniboine. We expect
operating costs to decrease over time as the wells de-water and gas production
increases.
Our Scott/Telford costs increased during the quarter as we performed
maintenance and workovers on the platform and producing wells. The additional
maintenance costs and decreases in production volumes have increased our
corporate average by $0.25/boe.
Syncrude operating costs per barrel increased 7% from the second quarter of
2006 primarily as a result of costs incurred from the Coker 8-3 and LC Finer
turnarounds and partially offset by increased production volumes. We expect
unit operating costs to decrease in the third quarter with higher production
rates and less downtime. The impact of the higher Syncrude unit costs increased
our corporate average by $0.21/boe during the quarter.
DEPRECIATION, DEPLETION, AMORTIZATION AND IMPAIRMENT (DD&A)
Three Months Six Months
Ended June 30 Ended June 30
(Cdn$/boe) 2007 2006 2007 2006
- --------------------------------------------------------------------------------------------------------------------------
DD&A based on our working interest production before royalties (1)
Conventional Oil and Gas 15.28 13.18 15.24 13.01
Synthetic Crude Oil
Syncrude 6.79 3.47 6.72 3.61
Average Oil and Gas 14.65 12.39 14.55 12.31
---------------------------------------------------
DD&A based on our net production after royalties
Conventional Oil and Gas 18.71 18.93 19.01 18.78
Synthetic Crude Oil
Syncrude 7.84 3.85 7.68 4.00
Average Oil and Gas 17.86 17.31 18.01 17.33
---------------------------------------------------
- ------------
(1) DD&A per boe is our DD&A for oil and gas operations divided by our working
interest production before royalties. We use production before royalties
to monitor our performance consistent with other Canadian oil and gas
companies.
HIGHER OIL AND GAS DD&A DECREASED NET INCOME FOR THE QUARTER BY $100 MILLION
Our production mix has changed with new volumes added from the Buzzard
development in the North Sea. The impact of new Buzzard production increased
our DD&A expense by $112 million during the quarter. Costs relating to Buzzard
are higher than our corporate average as they include our acquisition cost and
the costs to complete the project, increasing our corporate average by
$1.23/boe. This was partially offset at our Scott and Telford fields where
higher reserves reduced our corporate average $0.53/boe. Buzzard unit depletion
rates are expected to decrease in the next few years as we anticipate booking
additional proved reserves from production experience and from further
development drilling.
In Yemen, lower capital expenditures as a result of our reduced drilling
program decreased our corporate unit depletion rate by $0.08/boe as compared to
the second quarter of 2006.
35
Depletion of our Canadian assets increased our corporate average by $0.16/boe.
This largely reflects the timing of reserve bookings from our CBM projects in
central Alberta, as well as land acquisitions in 2006. We expect our depletion
rate for our coalbed methane projects to decline as the wells de-water and we
are able to recognize additional reserves. Our depletion rate in the Gulf of
Mexico increased our corporate average depletion rate by $1.14/boe compared to
2006 from higher costs related to the additional development well at Aspen and
from reserve reductions at the end of 2006.
Syncrude DD&A includes costs to develop the Stage 3 expansion that came on
stream in mid 2006. The depletion of the expansion costs increased our average
by $0.33/boe.
EXPLORATION EXPENSE
Three Months Six Months
Ended June 30 Ended June 30
2007 2006 2007 2006
- ----------------------------------------------------------------------------------------------------------------
Seismic 50 25 60 47
Unsuccessful Exploration Drilling 33 6 54 71
Other 22 15 40 31
-----------------------------------------------------
Total Exploration Expense 105 46 154 149
=====================================================
New Growth Exploration 99 167 207 284
Geological and Geophysical Costs 50 25 60 47
-----------------------------------------------------
Total Exploration Expenditures 149 192 267 331
-----------------------------------------------------
-----------------------------------------------------
Exploration Expense as a % of Exploration Expenditures 71% 24% 58% 45%
=====================================================
HIGHER EXPLORATION EXPENSE DECREASED NET INCOME FOR THE QUARTER BY $59 MILLION
Exploration capital during the quarter included activity in the Gulf of Mexico,
the North Sea and Colombia. We have four exploration wells currently drilling
in the Gulf of Mexico. In the deepwater, our Vicksburg prospect is being
drilled to a depth of 26,000 feet. Our drilling on the shelf includes three
exploration wells and results are expected in the third quarter.
In the UK North Sea, we expensed $8 million as we plugged and abandoned an
unsuccessful exploration well at Dee. We are currently drilling an appraisal
well at Selkirk located on Block 22/22b and results are expected in the third
quarter. An additional appraisal well at Bugle and three exploration wells are
planned for the second half of the year in the North Sea.
In Colombia, we expensed $10 million of costs related to our unsuccessful
Atalea-1 exploratory well on our Boqueron Deep prospect. In Canada, we incurred
$6 million in dry hole costs on three CBM explorations wells.
Seismic data acquisition was higher during the quarter as a result of the
timing of data acquisitions, particularly in the Gulf of Mexico as we continue
to review our exploration opportunities. Over the next 12 months or so, we
expect to drill at least 18 exploration wells with the majority in the Gulf of
Mexico and the UK North Sea.
36
ENERGY MARKETING
Three Months Six Months
Ended June 30 Ended June 30
2007 2006 2007 2006
- ----------------------------------------------------------------------------------------------------------------------------
Physical Sales (1) 11,503 8,983 22,401 19,441
Physical Purchases (1) (11,260) (8,763) (21,884) (18,889)
Net Financial Transactions (1) 41 73 14 178
--------------------------------------------------------
Net Revenue 284 293 531 730
Transportation Expense (189) (186) (409) (418)
Other 1 2 4 2
--------------------------------------------------------
NET MARKETING REVENUE 96 109 126 314
========================================================
CONTRIBUTION TO NET MARKETING REVENUE BY PRODUCT TYPE:
North American Natural Gas 49 70 74 258
Global Crude Oil 26 34 14 45
North American Power 1 3 8 6
Other 20 2 30 5
--------------------------------------------------------
NET MARKETING REVENUE 96 109 126 314
General and Administrative (23) (39) (53) (75)
--------------------------------------------------------
NET MARKETING REVENUE AFTER GENERAL AND ADMINISTRATIVE 73 70 73 239
Depreciation, Depletion, Amortization and Impairment (3) (1) (7) (4)
--------------------------------------------------------
MARKETING CONTRIBUTION TO INCOME BEFORE INCOME TAXES 70 69 66 235
========================================================
PHYSICAL SALES VOLUMES (2)
North American Natural Gas (bcf/d) 4.9 5.4 5.1 5.4
Global Crude Oil (mbbls/d) 826 660 839 624
North American Power (MW/d) 4,267 4,200 4,407 4,249
VALUE-AT-RISK
Quarter-end 34 20 34 20
High 38 27 38 27
Low 24 18 24 17
Average 30 21 29 21
--------------------------------------------------------
- ------------
(1) Marketing's physical sales, physical purchases and net financial
transactions are reported net on the Unaudited Consolidated Statement of
Income as marketing and other.
(2) Excludes intra-segment transactions.
LOWER NET MARKETING REVENUE DECREASED NET INCOME BY $13 MILLION
Results from our marketing group were lower than the same period last year. In
2006, volatility in the North American natural gas markets and industry
speculation coming off an active 2005 hurricane season widened summer/winter
spreads and narrowed location spreads across the natural gas forward price
curve. Early last year, we positioned ourselves financially to take advantage
of these spreads. In 2007, the natural gas market has not yet presented similar
opportunities to last year as there is reduced speculation on the potential
impact of the 2007 hurricane season. In particular, summer/winter spreads
across the forward price curve are narrower than last year.
Our global crude oil group continues to expand internationally. Our second
quarter results were slightly lower from last year as the contango (increasing
prices) in the crude oil forward price curve decreased late in June 2007 as a
result of strong current month pricing. During the quarter, we realized gains
largely from better pricing of physical sales relative to our purchases, as
well as realizing gains on selling crude oil from storage. Elsewhere, our
European gas and power marketing group had strong results during the quarter by
anticipating weakness in near-term natural gas prices relative to next winter
in the United Kingdom.
Results from our marketing group vary by quarter and historical results are not
necessarily indicative of results to be expected in future quarters. Quarterly
marketing results depend on a variety of factors such as market volatility,
changes in time and location spreads, the manner in which we use our storage
and transportation assets and the change in value of the financial instruments
we use to hedge these assets.
As part of our gas marketing strategy, we hold physical transportation and
storage capacity contracts that allow us to take advantage of pricing
differences between locations (i.e. west vs. east) and time periods (i.e.
summer vs. winter). These capacity contracts have market value, similar to
financial commodity contracts, as future margins realized depend on future
prices and, more importantly, pricing differences. The market value of these
37
capacity contracts varies depending on the change in future prices and pricing
relationships. We routinely hedge the economic value of our capacity contracts
using various types of derivative contracts, thereby limiting volatility in our
economic results. Accounting rules, however, increase volatility in our
reported results since they require us to recognize the change in fair value of
derivative contracts hedging our capacity contracts, but do not allow us to
recognize the change in fair value of the capacity contracts themselves until
the contracts are used. As a result, when prices or pricing relationships
change, we may be required to include gains or losses in our reported results
in different periods even though our underlying economic results may be largely
unchanged.
COMPOSITION OF NET MARKETING REVENUE
Three Months Six Months
Ended June 30 Ended June 30
2007 2006 2007 2006
- ----------------------------------------------------------------------------------------------------------------
Trading Activities 97 107 121 309
Non-Trading Activities (1) 2 5 5
----------------------------------------------------------------
96 109 126 314
================================================================
TRADING ACTIVITIES
In marketing, we enter into contracts to purchase and sell energy products,
primarily for crude oil and natural gas. We also use financial and derivative
contracts, including futures, forwards, swaps and options for hedging and
trading purposes. We account for all derivative contracts not designated as
hedges for accounting purposes using mark-to-market accounting and record the
net gain or loss from their revaluation in marketing and other income. The fair
value of these instruments is included with accounts receivable or payable.
They are classified as long-term or short-term based on their anticipated
settlement date.
We value derivative trading contracts daily using:
o actively quoted markets such as the New York Mercantile Exchange and
the International Petroleum Exchange; and
o other external sources such as the Natural Gas Exchange, independent
price publications and over-the-counter broker quotes.
FAIR VALUE OF DERIVATIVE CONTRACTS
At June 30, 2007, the fair value of our derivative contracts not designated as
accounting hedges totalled $131 million. Below is a breakdown of this fair
value by valuation method and contract maturity.
MATURITY
- -----------------------------------------------------------------------------------------------------------------------------
less than more than
1 year 1-3 years 4-5 years 5 years Total
-------------------------------------------------------------------
Prices
Actively Quoted Markets (60) 17 (10) - (53)
From Other External Sources 94 69 28 (7) 184
Based on Models and Other Valuation Methods - - - - -
-------------------------------------------------------------------
Total 34 86 18 (7) 131
===================================================================
CHANGES IN FAIR VALUE OF DERIVATIVE CONTRACTS
Total
- -----------------------------------------------------------------------------------------------------------------------------
Fair Value at December 31, 2006 360
Change in Fair Value of Contracts 31
Net Losses (Gains) on Contracts Closed (260)
Changes in Valuation Techniques and Assumptions (1) -
-----------
Fair Value at June 30, 2007 131
===========
- ------------
(1) Our valuation methodology has been applied consistently in each period.
The fair values of our derivative contracts will be realized over time as the
contracts settle. Until then, the value of certain contracts will vary with
forward commodity prices and price differentials. While forward prices vary,
the value of the contracts only varies to the extent they are economically
exposed or unprotected. As most of our unrealized value is not economically
exposed, we expect to realize the majority of this fair value.
Contract maturities vary from a single day up to 19 years. Those maturing
beyond one year primarily relate to North American natural gas positions. The
relatively short maturity of our contracts, the high quality of our valuations
from quoted markets and external sources and the limited economic exposure
combine to lower our portfolio risk.
38
NON-TRADING ACTIVITIES
We enter into fee for service contracts related to transportation and storage
of third-party oil and gas. In addition, we earn income from our power
generation facilities at Balzac and Soderglen.
CHEMICALS
HIGHER CHEMICALS CONTRIBUTION INCREASED NET INCOME BY $2 MILLION
North American prices for sodium chlorate remained strong in the second quarter
offsetting a slight decrease in sales volumes arising from unplanned shutdowns
at our North Vancouver chlor-alkali facility, pulp mill outages and higher
electricity costs. Our operations in Brazil remain strong as a result of
continued demand from Aracruz Cellulose, our primary customer in Brazil.
Chemicals net income includes foreign exchange gains of $13 million in the
second quarter (2006 - $7 million) on Canexus US-dollar denominated debt.
CORPORATE EXPENSES
GENERAL AND ADMINISTRATIVE (G&A)
Three Months Six Months
Ended June 30 Ended June 30
2007 2006 2007 2006
- -----------------------------------------------------------------------------------------------------------------------------
General and Administrative Expense before Stock-Based Compensation 93 97 179 172
Stock-Based Compensation (1) (55) 11 61 156
--------------------------------------------------
Total General and Administrative Expense 38 108 240 328
==================================================
- ------------
(1) Includes the tandem option plan, stock options for our US-based employees
and stock appreciation rights.
LOWER COSTS INCREASED QUARTERLY NET INCOME BY $70 MILLION
Changes in our share price create volatility in our net income as we account
for stock-based compensation using the intrinsic-value method. During the
quarter, we recorded a recovery of our stock-based compensation expense as our
share price was lower than at the end of the first quarter. In 2006, our share
price was largely unchanged for the second quarter and we recorded nominal
stock-based compensation expense as a result. Cash payments to employees for
our stock-based compensation programs were $15 million during the second
quarter and $87 million year-to-date.
Reduced performance by our marketing group relative to last year reduced our
accrual for results-based compensation programs. This was largely offset by
additional costs of higher employee levels as we continue to expand our oil and
gas operations internationally and expand our marketing operations in Europe
and North America.
39
INTEREST AND FINANCING COSTS
Three Months Six Months
Ended June 30 Ended June 30
2007 2006 2007 2006
- -----------------------------------------------------------------------------------------------------------------------------
Interest 87 71 173 137
Less: Capitalized Interest (41) (60) (79) (117)
------------------------------------------------------
Net Interest Expense 46 11 94 20
======================================================
HIGHER INTEREST EXPENSE DECREASED QUARTERLY NET INCOME BY $35 MILLION
Our financing costs increased $19 million from the second quarter of 2006 as we
funded capital investment of our Long Lake project and the Ettrick development
in the North Sea with our credit facilities. The stronger Canadian to US dollar
exchange rate reduced our US-dollar denominated interest costs by $3 million
during the quarter. In May 2007, we issued US$1.5 billion of long-term debt,
which was used to repay the term credit facilities.
We capitalized less interest on our major development projects during the
quarter as we completed the Buzzard and Syncrude Stage 3 development projects
in 2006. In 2007, we are capitalizing interest on our Long Lake development in
the Athabasca oil sands and on our Ettrick project in the North Sea.
INCOME TAXES
Three Months Six Months
Ended June 30 Ended June 30
2007 2006 2007 2006
- -----------------------------------------------------------------------------------------------------------------------------
Current 151 136 211 245
Future 126 14 161 283
------------------------------------------------------
Total Provision for Income Taxes 277 150 372 528
======================================================
Effective Tax Rate (%) 43% 27% 43% 61%
------------------------------------------------------
EFFECTIVE TAX RATE INCREASED TO 43%
Current income taxes include cash taxes in Yemen of $65 million (2006 - $81
million) for the quarter and $109 million (2006 - $148 million) year-to-date.
New production from Buzzard in the North Sea, combined with high commodity
prices, resulted in a second quarter current tax provision of $67 million in
the United Kingdom. On a go forward basis, we expect to be cash taxable in the
UK. Our income tax provision also includes current taxes in Colombia and the
United States.
Our provision for future income taxes in the first quarter of 2006 included a
one-time expense of $277 million related to tax rate changes in the UK. In
early 2006, the UK government substantively enacted increases to the
supplementary charge on our North Sea oil and gas activities from 10% to 20%,
effective January 1, 2006. Excluding the charge, our effective 2006
year-to-date tax rate was 29%. Our effective tax rate in 2007 increased to 43%
for the second quarter and year-to-date as we are generating more income in
higher-taxable jurisdictions such as the UK North Sea.
OTHER
Three Months Six Months
Ended June 30 Ended June 30
2007 2006 2007 2006
- -----------------------------------------------------------------------------------------------------------------------------
Change in Fair Value of Crude Oil Put Options (4) 3 (20) (1)
------------------------------------------------------
During the second quarter of 2006, we purchased put options on approximately
105,000 bbls/d of our 2007 crude oil production. These options establish a WTI
floor price of US$50/bbl on these volumes, are settled annually and provide a
base level of price protection without limiting our upside to higher prices.
The put options were purchased for $26 million and are carried at fair value.
At December 31, 2006, the options had a fair value of $19 million. During the
second quarter we recorded a loss of $3 million (2006 - gain of $3 million) and
year to date we recorded a loss of $19 million (2006 - $1 million) for the
change in fair value as a result of the rise in WTI.
During the quarter, we expanded our cash flow protection strategy into 2008 by
purchasing put options on 36 million barrels or approximately 100,000 bbls/d of
our 2008 crude oil production. These options establish an annual Dated Brent
floor price of US$50/bbl on these volumes. The put options were purchased for
$24 million and are carried at fair value. At June 30, 2007, the options had a
fair value of $23 million and we recorded a loss of $1 million for the change
in fair value as a result of the rise in Dated Brent.
40
LIQUIDITY
CAPITAL STRUCTURE
June 30 December 31
2007 2006
- ------------------------------------------------------------------------------------------------
NET DEBT (1)
Bank Debt 250 1,410
Public Senior Notes 4,190 2,885
---------------------------------
Senior Debt 4,440 4,295
Subordinated Debt 473 536
---------------------------------
Total Debt 4,913 4,831
Less: Cash and Cash Equivalents (158) (101)
---------------------------------
TOTAL NET DEBT 4,755 4,730
=================================
SHAREHOLDERS' EQUITY (2) 5,080 4,636
=================================
- ------------
(1) Includes all of our debt and is calculated as long-term debt and
short-term borrowings less cash and cash equivalents.
(2) At June 30, 2007, there were 527,149,918 common shares and US$460 million
of unsecured subordinated securities outstanding. These subordinated
securities may be redeemed by issuing common shares at our option after
November 8, 2008. The number of shares issuable depends on the common
share price on the redemption date.
During the second quarter, we issued US$1.5 billion of senior notes with US$250
million maturing in 10 years and US$1,250 million maturing in 30 years. The
issuance of the new debt increased the average term-to-maturity of our debt to
21 years. Proceeds from the debt issue were used to repay the outstanding term
credit facilities. In June, we also filed a universal base shelf prospectus in
the US and Canada allowing us to potentially raise US$2.5 billion of debt,
equity or other hybrid securities, should the need arise.
NET DEBT
Our net debt levels are directly related to our operating cash flows and our
capital expenditure activities. Changes in net debt for the first six months of
2007 are related to:
- -----------------------------------------------------------------------------------------------
Capital Investment 1,630
Cash Flow from Operating Activities (1,030)
-----------
Excess of Capital Investment over Cash Flow 600
Dividends on Common Shares 26
Issue of Common Shares (40)
Foreign Exchange Translation of US-dollar Debt and Cash (407)
Other (154)
-----------
Increase in Net Debt 25
===========
CHANGE IN WORKING CAPITAL
June 30 December 31 Increase/
2007 2006 (Decrease)
- -----------------------------------------------------------------------------------------------
Cash and Cash Equivalents 158 101 57
Restricted Cash 96 197 (101)
Accounts Receivable 2,861 2,951 (90)
Inventories and Supplies 857 786 71
Future Income Tax Assets 277 479 (202)
Accounts Payable and Accrued Liabilities (3,665) (3,879) 214
Other (27) (1) (26)
---------------------------------------------
Net Working Capital 557 634 (77)
=============================================
Accounts receivable were lower than year end as gains from 2006 on our
marketing derivative contracts were realized during the first quarter of 2007,
partially offset by increases in our oil and gas production. Inventories and
supplies increased as our marketing group acquired additional natural gas and
crude oil inventory to take advantage of trading opportunities. Our accrued
liabilities decreased from the end of 2006 as we settled the Block 51
arbitration early in 2007. Lower accruals for our stock-based compensation
obligations also reduced accounts payable and accrued liabilities.
41
OUTLOOK FOR REMAINDER OF 2007
We expect our 2007 production to be at or slightly below the lower end of our
guidance range of 275,000 to 305,000 boe/d before royalties for the full year.
We expect to generate $3.3 to $3.6 billion in cash flow (before remediation and
geological and geophysical expenditures) in 2007, assuming the following for
the remainder of the year:
- -------------------------------------------------------------------------------
WTI (US$/bbl) 60.00
Brent (US$/bbl) 65.00
NYMEX natural gas (US$/mmbtu) 7.00
Oil & Gas and Syncrude operating costs (Cdn$/boe) 8.75
US to Canadian dollar exchange rate 0.90
--------------
To date, we have incurred almost half of our planned 2007 capital investment.
Our 2007 capital program is largely focused on bringing Long Lake on stream and
advancing the Ettrick development in the North Sea towards completion in 2008.
In addition, we continue to invest in exploration opportunities in our growth
areas.
Our future liquidity is primarily dependent on cash flows generated from our
operations, existing committed credit facilities and our ability to access debt
and equity markets. In July 2007, we are required to repay $150 million of
medium term notes that become due; however, we plan to fund this with our term
credit facilities. At June 30, 2007, we had committed term credit facilities of
$3.3 billion that are available until 2011. At the end of the quarter we had
not drawn on these facilities and utilized $397 million of these facilities to
support letters of credit. We also had $631 million of uncommitted, unsecured
credit facilities, of which $61 million (US$57 million) was drawn at June 30,
2007 and $130 million was utilized to support letters of credit.
In the second quarter, we declared common share dividends of $0.025 per share.
CONTRACTUAL OBLIGATIONS, COMMITMENTS AND GUARANTEES
We have assumed various contractual obligations and commitments in the normal
course of our operations and financing activities. We have included these
obligations and commitments in our MD&A in our 2006 Annual Report on Form 10-K.
In 2007, we entered into work commitments related to a drilling rig, which has
been contracted to work for us in the North Sea, totaling $93 million over the
next two years. There have been no other significant developments since year
end.
CONTINGENCIES
There are a number of lawsuits and claims pending, the ultimate results of
which cannot be ascertained at this time. We record costs as they are incurred
or become determinable. We believe the resolution of these matters would not
have a material adverse effect on our liquidity, consolidated financial
position or results of operations. These matters are described in LEGAL
PROCEEDINGS in Item 3 contained in our 2006 Annual Report on Form 10-K. There
have been no significant developments since year end.
NEW ACCOUNTING PRONOUNCEMENTS
CANADIAN PRONOUNCEMENTS
In December 2006, the Canadian Accounting Standards Board (AcSB) issued two new
Sections in relation to financial instruments: Section 3862, FINANCIAL
INSTRUMENTS - DISCLOSURES, and Section 3863, FINANCIAL INSTRUMENTS -
PRESENTATION. Both sections will become effective for annual and interim
periods beginning on or after October 1, 2007 and will require increased
disclosure of financial instruments.
In December 2006, the AcSB issued Section 1535, CAPITAL DISCLOSURES, requiring
disclosure of information about an entity's capital and the objectives,
policies, and processes for managing capital. The standard is effective for
annual periods beginning on or after October 1, 2007.
In June 2007, the AcSB issued Section 3031, INVENTORIES, which replaces Section
3030. The new section is harmonized with International Accounting Standards and
provides additional guidance on the measurement and disclosure requirements for
inventories. Specifically, Section 3031 requires inventories to be measured at
the lower of cost and net realizable value. The new requirements are effective
for fiscal years beginning on or after January 1, 2008. We do not expect the
adoption of this section to have a material impact on our results of operations
or financial position.
42
US PRONOUNCEMENTS
In September 2006, the Financial Accounting Standards Board (FASB) issued
Statement 157, FAIR VALUE MEASUREMENTS. Statement 157 defines fair value,
establishes a framework for measuring fair value under US generally accepted
accounting principles and expands disclosures about fair value measurements.
This statement is effective for fiscal years beginning after November 15, 2007.
We do not expect the adoption of this statement will have a material impact on
our results of operations or financial position.
Effective December 31, 2006, we adopted the recognition and disclosure
provisions of FASB Statement 158, EMPLOYERS' ACCOUNTING FOR DEFINED BENEFIT
PENSION AND OTHER POSTRETIREMENT PLANS. This statement also requires
measurement of the funded status of a plan as of the balance sheet date. The
measurement provisions of the statement are effective for fiscal years ending
after December 15, 2008. We do not expect the adoption of the change in
measurement date in 2008 to have a material impact on our results of operations
or financial position.
In February 2007, FASB issued Statement 159, THE FAIR VALUE OPTION FOR
FINANCIAL ASSETS AND FINANCIAL LIABILITIES. The statement allows for the
elective measurement of eligible financial instruments and certain other items
at fair value in order to mitigate volatility in reported earnings without
having to apply complex and detailed hedge accounting rules. This statement is
effective for fiscal years beginning after November 15, 2007. We are currently
evaluating the provisions of Statement 159 and have not yet determined the
impact this statement will have on our results from operations or financial
position.
EQUITY SECURITY REPURCHASES
During the quarter, we made no purchases of our own equity securities.
SUMMARY OF QUARTERLY RESULTS
Three Months Ended
2005 | 2006 | 2007
Sep Dec | Mar Jun Sep Dec | Mar Jun
- ----------------------------------------------------------------------------------------------------------------------------------
Net Sales 1,094 1,073 980 1,039 997 920 1,140 1,399
Net Income (Loss) from Continuing Operations 205 303 (83) 408 199 77 121 368
Net Income from Discontinued Operations 404 - - - - - - -
----------------------------------------------------------------------------------
Net Income (Loss) 609 303 (83) 408 199 77 121 368
==================================================================================
Earnings (Loss) per Common Share from
Continuing Operations ($/share)
Basic 0.39 0.58 (0.16) 0.78 0.38 0.15 0.23 0.70
Diluted 0.38 0.56 (0.16) 0.76 0.37 0.14 0.22 0.68
Earnings (Loss) per Common Share ($/share)
Basic 1.17 0.58 (0.16) 0.78 0.38 0.15 0.23 0.70
Diluted 1.13 0.56 (0.16) 0.76 0.37 0.14 0.22 0.68
----------------------------------------------------------------------------------
43
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS
Certain statements in this report, including those appearing in ITEM 7 -
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS, are forward-looking statements.(1) Forward-looking statements are
generally identifiable by terms such as ANTICIPATE, BELIEVE, INTEND, PLAN,
EXPECT, ESTIMATE, BUDGET, OUTLOOK or other similar words, and include
statements relating to expected full year production, cash flow and capital
expenditures as well as future production associated with our coalbed methane,
Long Lake, Syncrude, North Sea, Gulf of Mexico and West Africa projects and
other projects.
These statements are subject to known and unknown risks and uncertainties and
other factors which may cause actual results, levels of activity and
achievements to differ materially from those expressed or implied by such
statements. These risks, uncertainties and other factors include:
o market prices for oil, natural gas and chemicals products;
o our ability to explore, develop, produce and transport crude oil and
natural gas to markets;
o the results of exploration and development drilling and related
activities;
o volatility in energy trading markets;
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 or royalties, change
environmental and other laws and regulations;
o renegotiations of contracts;
o results of litigation, arbitration or regulatory proceedings; and
o political uncertainty, including actions by terrorists, insurgent or other
groups, or other armed conflict, including conflict between states.
The above items and their possible impact are discussed more fully in the
sections titled RISK FACTORS in Item 1A and QUANTITATIVE AND QUALITATIVE
DISCLOSURES ABOUT MARKET RISK in Item 7A of our 2006 Annual Report on Form
10-K.
The impact of any one risk, uncertainty or factor on a particular
forward-looking statement is not determinable with certainty as these are
interdependent and management's future course of action depends upon our
assessment of all information available at that time. Any statements regarding
the following are forward-looking statements:
o future crude oil, natural gas or chemicals prices;
o future production levels;
o future cost recovery oil revenues from our operations in Yemen;
o future capital expenditures and their allocation to exploration and
development activities;
o future asset dispositions;
o future sources of funding for our capital program;
o possible commerciality, development plans or capacity expansions;
o future ability to execute dispositions of assets or businesses;
o future debt levels;
o future cash flows and their uses;
o future drilling of new wells;
o ultimate recoverability of reserves;
o expected finding and development costs;
o expected operating costs;
o future demand for chemicals products;
o future expenditures and future allowances relating to environmental
matters; and
o dates by which certain areas will be developed or will come on-stream.
We believe that any forward-looking statements made are reasonable based on
information available to us on the date such statements were made. However, no
assurance can be given as to future results, levels of activity and
achievements. We undertake no obligation to update publicly or revise any
forward-looking statements contained in this report. All subsequent
forward-looking statements, whether written or oral, attributable to us or
persons acting on our behalf are expressly qualified in their entirety by these
cautionary statements.
- ------------
(1) Within the meaning of the United States PRIVATE SECURITIES LITIGATION
REFORM ACT OF 1995, Section 21E of the United States SECURITIES EXCHANGE
ACT OF 1934, as amended, and Section 27A of the United States SECURITIES
ACT OF 1933, as amended.
44
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We are exposed to normal market risks inherent in the oil and gas and chemicals
business, including commodity price risk, foreign-currency rate risk, interest
rate risk and credit risk. We recognize these risks and manage our operations
to minimize our exposures to the extent practical. The information presented on
market risks in Item 7A on pages 77 - 80 in our 2006 Annual Report on Form 10-K
has not changed materially since December 31, 2006.
ITEM 4. CONTROLS AND PROCEDURES
EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES
Our Chief Executive Officer and Chief Financial Officer have evaluated the
effectiveness of our disclosure controls and procedures (as defined in Exchange
Act Rules 13a-15(e) and 15-d-15(e)) as of the end of the period covered by this
report. They concluded that, as of the end of the period covered by this
report, our disclosure controls and procedures were designed to be and 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 and that the information required to be disclosed by the
Company in the reports that it files or submits under the Securities Exchange
Act is recorded, processed, summarized and reported within the time periods
specified in the SEC's rules and forms. 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 they do
not expect that the Company's disclosure controls and procedures or internal
controls over financial reporting will prevent all errors or fraud. In reaching
a reasonable level of assurance, management necessarily is required to apply
its judgment in evaluating the cost-benefit relationship of possible controls
and procedures.
CHANGES IN INTERNAL CONTROLS
We have continually had in place systems relating to internal control over
financial reporting. There has not been any change in the Company's internal
control over financial reporting during the second quarter of 2007 that has
materially affected, or is reasonably likely to materially affect, the
Company's internal control over financial reporting. As well, based on these
evaluations, there were no material weaknesses in these internal controls
requiring corrective action. As a result, no such corrective actions were
taken.
45
PART II
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Our Annual General and Special Meeting of Shareowners was held on April 26,
2007. The following actions were taken at the Meeting, for which proxies were
solicited pursuant to Section 85 of the Securities Act (Ontario).
(a) Each of the twelve director nominees proposed by management were elected
by a vote, conducted by ballot as follows:
Director For % Withheld %
-------------------------------------------------------------------------- -------------------------------
Charles W. Fischer 174,027,639 99.86 241,238 0.14
Dennis G. Flanagan 174,155,485 99.93 113,392 0.07
David A. Hentschel 173,982,068 99.84 286,809 0.16
S. Barry Jackson 173,459,612 99.54 809,265 0.46
Kevin J. Jenkins 173,468,741 99.54 800,136 0.46
A. Anne McLellan, P.C. 164,547,898 94.42 9,720,979 5.58
Eric P. Newell, O.C. 174,231,395 99.98 37,482 0.02
Thomas C. O'Neill 171,908,416 98.65 2,360,461 1.35
Francis M. Saville, Q.C. 171,605,884 98.47 2,662,993 1.53
Richard M. Thomson, O.C. 171,905,726 98.64 2,363,151 1.36
John M. Willson 173,464,292 99.54 804,585 0.46
Victor J. Zaleschuk 174,230,301 99.98 38,576 0.02
(b) The appointment of Deloitte & Touche LLP, Chartered Accountants, to
serve as the independent auditor for 2007 was approved by a show of
hands. Proxies of 173,949,131 (99.88%) for and 204,889 (0.12%) withheld
were received.
(c) The confirmation of By-Law No. 3 and the repeal of By-Law No. 2 was
approved by a show of hands. Proxies of 174,071,362 (99.95%) for and
82,658 (0.05%) against were received.
(d) The special resolution to amend the Articles of the Corporation to
effect a two-for-one division of the common shares was approved by a
show of hands. Proxies of 174,120,324 (99.98%) for and 32,499 (0.02%)
against were received.
ITEM 6. EXHIBITS
3.16 Certificate and Articles of Amendment of the Registrant dated April 26,
2007 (filed as Exhibit 3.16 to Form 8-K dated April 27, 2007).
4.55 Senior Debt Indenture dated May 4, 2007 between the Registrant and
Deutsche Bank Trust Company Americas, pertaining to the issue of senior
notes from time to time (filed as Exhibit 4.1 to Form 8-K dated May 7,
2007).
4.56 First Supplemental Indenture dated May 4, 2007 to the Trust Indenture
dated May 4, 2007 between the Registrant and Deutsche Bank Trust Company
Americas pertaining to the issuance of US$250 million, 5.65% notes dues
2017 and the issuance of US$1.25 billion, 6.40% notes due 2037 (filed as
Exhibit 4.2 to Form 8-K dated April 12, 2007).
10.48 Indemnification Agreement made between the Registrant and Brendon Muller
as of April 9, 2007 (filed as Exhibit 10.48 to Form 8-K dated April 12,
2007).
10.50 Pricing Agreement dated May 1, 2007 among the Registrant and Banc of
America Securities LLC, Citigroup Global Markets Inc. and Deutsche Bank
Securities Inc., as Underwriters (filed as Exhibit 10.1 to Form 8-K
dated April 12, 2007).
31.1 Certification of Chief Executive Officer pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.
31.2 Certification of Chief Financial Officer pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.
32.1 Certification of periodic report by Chief Executive Officer pursuant to
18 U.S.C., Section 1350, as adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.
32.2 Certification of periodic report by Chief Financial Officer pursuant to
18 U.S.C., Section 1350, as adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.
46
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 12, 2007.
NEXEN INC.
/s/ Charles W. Fischer
------------------------------
Charles W. Fischer
President and Chief Executive Officer
(Principal Executive Officer)
/s/ Brendon T. Muller
-------------------------------
Brendon T. Muller
Controller
(Principal Accounting Officer)
47