Attached files
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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
|X| QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE
ACT OF 1934 For the quarterly period ended September 30, 2009
|_| TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934 For the transition period from ....... to .......
COMMISSION FILE NUMBER 1-6702
[GRAPHIC OMITTED]
NEXEN 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 (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes [X] No [_]
Indicate by check mark whether the registrant has submitted electronically and
posted on its corporate Web site, if any, every Interactive Data File required
to be submitted and posted pursuant to Rule 405 of Regulation S-T (ss.232.405 of
this chapter) during the preceding 12 months (or for such shorter period that
the registrant was required to submit and post such files).
Yes [_] No [_]
Indicate by check mark whether the registrant is a large accelerated filer, an
accelerated filer, a non-accelerated filer, or a smaller reporting company. See
the definitions of "large accelerated filer", "accelerated filer" and "smaller
reporting company" in Rule 12b-2 of the Exchange Act.
Large accelerated filer [X] Accelerated filer [_]
Non-Accelerated filer [_] Smaller reporting company [_]
Indicate by check mark whether the registrant is a shell company (as defined in
Rule 12b-2 of the Exchange Act).
Yes [_] No [X]
On September 30, 2009, there were 521,846,559 common shares issued and
outstanding.
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NEXEN INC.
INDEX
PART I FINANCIAL INFORMATION PAGE
Item 1. Unaudited Consolidated Financial Statements ..................3
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations (MD&A) ..................30
Item 3. Quantitative and Qualitative Disclosures about
Market Risk .................................................50
Item 4. Controls and Procedures .....................................50
PART II OTHER INFORMATION
Item 1. Legal Proceedings ...........................................52
Item 6. Exhibits ....................................................52
This report should be read in conjunction with our 2008 Annual Report on Form
10-K (2008 Form 10-K) and with our current reports on Forms 10-Q and 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
79 of our 2008 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 ALSO PRESENTED. VOLUMES AND RESERVES INCLUDE
SYNCRUDE MINING 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 mcf = thousand cubic feet
bbl = barrel mmcf = million cubic feet
mbbls = thousand barrels bcf = billion cubic feet
mmbbls = million barrels NGL = natural gas liquid
mmbtu = million British thermal units WTI = West Texas Intermediate
boe = barrel of oil equivalent MW = megawatt
mboe = thousand barrels of oil equivalent GWh = gigawatt hours
mmboe = million barrels of oil equivalent Brent = Dated Brent
PSC(TM) = Premium Synthetic Crude(TM) NYMEX = New York Mercantile Exchange
In this Form 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 per 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 September 30, 2009, the noon-day exchange rate was US$0.9327 for Cdn$1.00, as
reported by the Bank of Canada.
2
PART I
ITEM 1. UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
TABLE OF CONTENTS
Page
Unaudited Consolidated Statement of Income
for the Three and Nine Months Ended September 30, 2009 and 2008.............4
Unaudited Consolidated Balance Sheet
as at September 30, 2009 and December 31, 2008..............................5
Unaudited Consolidated Statement of Cash Flows
for the Three and Nine Months Ended September 30, 2009 and 2008.............6
Unaudited Consolidated Statement of Shareholders' Equity
for the Three and Nine Months Ended September 30, 2009 and 2008.............7
Unaudited Consolidated Statement of Comprehensive Income
for the Three and Nine Months Ended September 30, 2009 and 2008.............7
Notes to Unaudited Consolidated Financial Statements........................8
3
NEXEN INC.
UNAUDITED CONSOLIDATED STATEMENT OF INCOME
FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30
Three Months Nine Months
Ended September 30 Ended September 30
(Cdn$ millions, except per share amounts) 2009 2008 2009 2008
-----------------------------------------------------------------------------------------------------------------------
REVENUES AND OTHER INCOME
Net Sales 1,097 2,213 3,345 6,154
Marketing and Other (Note 14) 296 131 635 387
----------------------------------------------
1,393 2,344 3,980 6,541
----------------------------------------------
EXPENSES
Operating 321 341 946 998
Depreciation, Depletion, Amortization and Impairment 358 386 1,180 1,084
Transportation and Other 185 291 618 691
General and Administrative 113 (308) 380 165
Exploration 89 112 219 245
Interest (Note 9) 84 16 226 59
----------------------------------------------
1,150 838 3,569 3,242
----------------------------------------------
INCOME BEFORE PROVISION FOR INCOME TAXES 243 1,506 411 3,299
----------------------------------------------
PROVISION FOR (RECOVERY OF) INCOME TAXES
Current 190 (26) 514 817
Future (81) 645 (397) 583
----------------------------------------------
109 619 117 1,400
----------------------------------------------
NET INCOME 134 887 294 1,899
Less: Net Income Attributable to Canexus Non-Controlling Interests (12) (1) (17) (3)
----------------------------------------------
NET INCOME ATTRIBUTABLE TO NEXEN INC. 122 886 277 1,896
==============================================
EARNINGS PER COMMON SHARE ($/share) (Note 15)
Basic 0.23 1.68 0.53 3.59
==============================================
Diluted 0.23 1.66 0.53 3.53
==============================================
SEE ACCOMPANYING NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS.
4
NEXEN INC.
UNAUDITED CONSOLIDATED BALANCE SHEET
September 30 December 31
(Cdn$ millions, except share amounts) 2009 2008
--------------------------------------------------------------------------------------------------------------
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents 1,897 2,003
Restricted Cash (Note 7) 216 103
Accounts Receivable (Note 2) 2,877 3,163
Inventories and Supplies (Note 3) 590 484
Other 199 169
------------------------------------
Total Current Assets 5,779 5,922
------------------------------------
PROPERTY, PLANT AND EQUIPMENT
Net of Accumulated Depreciation, Depletion, Amortization and
Impairment of $10,452 (December 31, 2008 - $10,393) 15,642 14,922
GOODWILL 346 390
FUTURE INCOME TAX ASSETS 916 351
DEFERRED CHARGES AND OTHER ASSETS (Note 5) 386 570
------------------------------------
TOTAL ASSETS 23,069 22,155
====================================
LIABILITIES
CURRENT LIABILITIES
Accounts Payable and Accrued Liabilities (Note 8) 3,358 3,326
Accrued Interest Payable 81 67
Dividends Payable 26 26
------------------------------------
Total Current Liabilities 3,465 3,419
------------------------------------
LONG-TERM DEBT (Note 9) 7,429 6,578
FUTURE INCOME TAX LIABILITIES 2,698 2,619
ASSET RETIREMENT OBLIGATIONS (Note 11) 992 1,024
DEFERRED CREDITS AND OTHER LIABILITIES (Note 12) 1,084 1,324
SHAREHOLDERS' EQUITY (Note 13)
Nexen Inc. Shareholders' Equity
Common Shares, no par value
Authorized: Unlimited
Outstanding: 2009 - 521,846,559 shares
2008 - 519,448,590 shares 1,025 981
Contributed Surplus 1 2
Retained Earnings 6,489 6,290
Accumulated Other Comprehensive Loss (183) (134)
------------------------------------
Total Nexen Inc. Shareholders' Equity 7,332 7,139
Canexus Non-Controlling Interests 69 52
------------------------------------
TOTAL SHAREHOLDERS' EQUITY 7,401 7,191
COMMITMENTS, CONTINGENCIES AND GUARANTEES (Note 16)
------------------------------------
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY 23,069 22,155
====================================
SEE ACCOMPANYING NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS.
5
NEXEN INC.
UNAUDITED CONSOLIDATED STATEMENT OF CASH FLOWS
FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30
Three Months Nine Months
Ended September 30 Ended September 30
(Cdn$ millions) 2009 2008 2009 2008
---------------------------------------------------------------------------------------------------------------------------
OPERATING ACTIVITIES
Net Income 134 887 294 1,899
Charges and Credits to Income not Involving Cash (Note 17) 174 692 887 1,544
Exploration Expense 89 112 219 245
Changes in Non-Cash Working Capital (Note 17) 113 (840) 193 (468)
Other (49) 117 (234) 79
------------------------------------------------
461 968 1,359 3,299
FINANCING ACTIVITIES
Proceeds from Long-Term Notes 1,081 - 1,081 -
Proceeds from (Repayment of) Term Credit Facilities, Net (915) 1,031 728 803
Proceeds from (Repayment of) Canexus Term Credit Facilities, Net (4) (9) 48 (19)
Proceeds from Canexus Debentures 46 - 46 -
Proceeds from Canexus Notes - - - 51
Repayment of Medium-Term Notes - - - (125)
Repayment of Short-Term Borrowings (1) (4) (1) (4)
Dividends on Common Shares (26) (26) (78) (66)
Distributions Paid to Canexus Non-Controlling Interests (4) (4) (11) (11)
Issue of Common Shares and Exercise of Tandem Options for Shares 12 8 42 48
Repurchase of Common Shares for Cancellation - (300) - (300)
Changes in Non-Cash Working Capital (Note 17) - 10 - 10
Other (18) 2 (19) -
------------------------------------------------
171 708 1,836 387
INVESTING ACTIVITIES
Capital Expenditures
Exploration and Development (586) (689) (1,921) (2,064)
Proved Property Acquisitions - - (755) (2)
Energy Marketing, Chemicals, Corporate and Other (69) (36) (198) (83)
Proceeds on Disposition of Assets 2 - 17 -
Changes in Restricted Cash 93 196 (154) 143
Changes in Non-Cash Working Capital (Note 17) 14 (66) (41) (120)
Other (15) 36 (16) (61)
------------------------------------------------
(561) (559) (3,068) (2,187)
EFFECT OF EXCHANGE RATE CHANGES ON CASH AND CASH EQUIVALENTS (148) 41 (233) 67
------------------------------------------------
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (77) 1,158 (106) 1,566
CASH AND CASH EQUIVALENTS - BEGINNING OF PERIOD 1,974 614 2,003 206
------------------------------------------------
CASH AND CASH EQUIVALENTS - END OF PERIOD (1) 1,897 1,772 1,897 1,772
================================================
(1) Cash and cash equivalents at September 30, 2009 consist of cash of $376
million and short-term investments of $1,521 million (September 30, 2008 -
cash of $26 million and short-term investments of $1,746 million).
SEE ACCOMPANYING NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS.
6
NEXEN INC.
UNAUDITED CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY
FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30
Three Months Nine Months
Ended September 30 Ended September 30
(Cdn$ millions) 2009 2008 2009 2008
---------------------------------------------------------------------------------------------------------------------------
COMMON SHARES, Beginning of Period 1,011 972 981 917
Issue of Common Shares 8 8 37 32
Exercise of Tandem Options for Shares 4 - 5 16
Accrued Liability Relating to Tandem Options Exercised for Common
Shares 2 1 2 16
Repurchased Under Normal Course Issuer Bid - (18) - (18)
----------------------------------------------
Balance at End of Period 1,025 963 1,025 963
==============================================
CONTRIBUTED SURPLUS, Beginning of Period 2 2 2 3
Exercise of Tandem Options (1) - (1) (1)
----------------------------------------------
Balance at End of Period 1 2 1 2
==============================================
RETAINED EARNINGS, Beginning of Period 6,393 5,953 6,290 4,983
Net Income Attributable to Nexen Inc. 122 886 277 1,896
Dividends on Common Shares (Note 13) (26) (26) (78) (66)
Repurchase of Common Shares for Cancellation - (282) - (282)
----------------------------------------------
Balance at End of Period 6,489 6,531 6,489 6,531
==============================================
ACCUMULATED OTHER COMPREHENSIVE LOSS, Beginning of Period (157) (274) (134) (293)
Other Comprehensive Income (Loss) (26) 41 (49) 60
----------------------------------------------
Balance at End of Period (183) (233) (183) (233)
==============================================
CANEXUS NON-CONTROLLING INTERESTS, Beginning of Period 54 62 52 67
Net Income Attributable to Non-Controlling Interests 15 1 24 3
Distributions Declared to Non-Controlling Interests (5) (5) (14) (13)
Issue of Partnership Units to Non-Controlling Interests under
Distribution Reinvestment Plan 1 1 3 2
Estimated Fair Value of Conversion Feature of Convertible Debenture
Issue Attributable to Non-Controlling Interests 4 - 4 -
----------------------------------------------
Balance at End of Period 69 59 69 59
==============================================
NEXEN INC.
UNAUDITED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30
Three Months Nine Months
Ended September 30 Ended September 30
(Cdn$ millions) 2009 2008 2009 2008
-----------------------------------------------------------------------------------------------------------------------------
NET INCOME ATTRIBUTABLE TO NEXEN INC. 122 886 277 1,896
Other Comprehensive Income (Loss), Net of Income Taxes:
Foreign Currency Translation Adjustment
Net Gains (Losses) on Investment in Self-Sustaining Foreign
Operations (408) 221 (693) 365
Net Gains (Losses) on Foreign-Denominated Debt Hedging Self-
Sustaining Foreign Operations(1) 384 (180) 646 (305)
Realized Translation Adjustments Recognized in Net Income (2) - (2) -
----------------------------------------------
Other Comprehensive Income (Loss) (26) 41 (49) 60
----------------------------------------------
COMPREHENSIVE INCOME ATTRIBUTABLE TO NEXEN INC. 96 927 228 1,956
==============================================
(1) Net of income tax expense for the three months ended September 30, 2009 of
$55 million (2008 - $26 million recovery) and net of income tax expense for
the nine months ended September 30, 2009 of $93 million (2008 - $45 million
recovery).
SEE ACCOMPANYING NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS.
7
NEXEN INC.
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
Cdn$ 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 GAAP on the Unaudited
Consolidated Financial Statements is disclosed in Note 19. 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 September 30, 2009 and December
31, 2008 and the results of our operations and our cash flows for the three and
nine months ended September 30, 2009 and 2008.
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 on an
ongoing basis, including those related to accruals, litigation, environmental
and asset retirement obligations, recoverability of assets, income taxes, fair
values of derivative assets and liabilities, capital adequacy and determination
of proved reserves. 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 nine months ended September 30, 2009
are not necessarily indicative of the results of operations or cash flows to be
expected for the year ending December 31, 2009. As at October 27, 2009, there
are no material subsequent events requiring additional disclosure in or
amendment to these financial statements.
These Unaudited Consolidated Financial Statements should be read in conjunction
with our Audited Consolidated Financial Statements included in our 2008 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 2008
Form 10-K.
CHANGES IN ACCOUNTING POLICIES
GOODWILL AND INTANGIBLE ASSETS
On January 1, 2009, we retrospectively adopted the Canadian Institute of
Chartered Accountants (CICA) Section 3064, GOODWILL AND INTANGIBLE ASSETS issued
by the AcSB. This section clarifies the criteria for the recognition of assets,
intangible assets and internally developed intangible assets. Adoption of this
standard did not have a material impact on our results of operations or
financial position.
BUSINESS COMBINATIONS
On January 1, 2009, we prospectively adopted CICA Section 1582, BUSINESS
COMBINATIONS issued by the AcSB. This section establishes principles and
requirements of the acquisition method for business combinations and related
disclosures. Adoption of this statement did not have a material impact on our
results of operations or financial position.
CONSOLIDATED FINANCIAL STATEMENTS AND NON-CONTROLLING INTERESTS
On January 1, 2009, we adopted CICA Sections 1601, CONSOLIDATED FINANCIAL
STATEMENTS, and 1602, NON-CONTROLLING INTERESTS issued by the AcSB. Section 1601
establishes standards for the preparation of consolidated financial statements.
Section 1602 provides guidance on accounting for non-controlling interests in
consolidated financial statements subsequent to a business combination. Adoption
of these statements did not have a material impact on our results of operations
or financial position. The presentation changes have been included in the
Unaudited Consolidated Financial Statements as applicable.
2. ACCOUNTS RECEIVABLE
September 30 December 31
2009 2008
-----------------------------------------------------------------------------------------------------------------------------
Trade
Energy Marketing 1,489 1,501
Energy Marketing Derivative Contracts (Note 6) 552 755
Oil and Gas 657 639
Chemicals and Other 47 68
------------------------------------------
2,745 2,963
Non-Trade 186 270
------------------------------------------
2,931 3,233
Allowance for Doubtful Receivables (54) (70)
------------------------------------------
Total 2,877 3,163
==========================================
8
3. INVENTORIES AND SUPPLIES
September 30 December 31
2009 2008
-----------------------------------------------------------------------------------------------------------------------------
Finished Products
Energy Marketing 449 384
Oil and Gas 32 17
Chemicals and Other 11 16
------------------------------------------
492 417
Work in Process 8 6
Field Supplies 90 61
------------------------------------------
Total 590 484
==========================================
4. SUSPENDED EXPLORATION WELL COSTS
The following table shows the changes in capitalized exploratory well costs
during the nine months ended September 30, 2009 and the year ended December 31,
2008, and does not include amounts that were initially capitalized and
subsequently expensed in the same period. Suspended exploration well costs are
included in property, plant and equipment.
Nine Months Ended Year Ended
September 30 December 31
2009 2008
-----------------------------------------------------------------------------------------------------------------------------
Beginning of Period 518 326
Exploratory Well Costs Capitalized Pending the Determination of
Proved Reserves 186 254
Capitalized Exploratory Well Costs Charged to Expense (32) (81)
Transfers to Wells, Facilities and Equipment Based on
Determination of Proved Reserves (17) (29)
Effects of Foreign Exchange Rate Changes (37) 48
------------------------------------------
End of Period 618 518
==========================================
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.
September 30 December 31
2009 2008
-----------------------------------------------------------------------------------------------------------------------------
Capitalized for a Period of One Year or Less 189 239
Capitalized for a Period of Greater than One Year 429 279
------------------------------------------
Total 618 518
==========================================
Number of Projects that have Exploratory Well Costs Capitalized for a Period
Greater than One Year 11 7
------------------------------------------
As at September 30, 2009, we have exploratory costs that have been capitalized
for more than one year relating to our interests in six exploratory blocks in
the North Sea ($178 million), certain coalbed methane and shale gas exploratory
activities in Canada ($120 million), two exploratory blocks in the Gulf of
Mexico ($112 million), and our interest in an exploratory block offshore Nigeria
($19 million). These costs relate to projects with successful exploration wells
for which we have not been able to recognize proved reserves. 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.
9
5. DEFERRED CHARGES AND OTHER ASSETS
September 30 December 31
2009 2008
-----------------------------------------------------------------------------------------------------------------------------
Crude Oil Put Options and Natural Gas Swaps (Note 6) (1) - 234
Long-Term Energy Marketing Derivative Contracts (Note 6) 241 217
Long-Term Capital Prepayments 42 61
Asset Retirement Remediation Fund 9 9
Defined Benefit Pension Assets 46 3
Other 48 46
------------------------------------------
Total 386 570
==========================================
(1) The crude oil put options were reclassified to other current assets in the
first quarter as they settle within 12 months.
6. FINANCIAL INSTRUMENTS
Financial instruments carried at fair value on our balance sheet include cash
and cash equivalents, restricted cash and derivatives used for trading and
non-trading purposes. Our other financial instruments, including accounts
receivable, accounts payable, accrued interest payable, dividends payable,
short-term borrowings and long-term debt, are carried at cost or amortized cost.
The carrying values of our short-term receivables and payables approximate their
fair value as the instruments are near maturity.
In our energy marketing group, we enter into contracts to purchase and sell
crude oil, natural gas and other energy commodities, and use derivative
contracts, including futures, forwards, swaps and options, for hedging and
trading purposes (collectively derivatives). We also use derivatives to manage
commodity price risk and foreign currency risk for non-trading purposes. We
categorize our derivative instruments as trading or non-trading activities and
carry the instruments at fair value on our balance sheet. The derivatives
section below details our derivatives and fair values as at September 30, 2009.
The fair values are included with accounts receivable or payable and are
classified as long-term or short-term based on anticipated settlement date. Any
change in fair value is included in marketing and other income.
We carry our long-term debt at amortized cost using the effective interest rate
method. At September 30, 2009, the estimated fair value of our long-term debt
was $7,531 million (December 31, 2008 - $5,686 million) as compared to the
carrying value of $7,429 million (December 31, 2008 - $6,578 million). The fair
value of long-term debt is estimated based on prices provided by quoted markets
and third-party brokers.
10
DERIVATIVES
(a) DERIVATIVE CONTRACTS RELATED TO TRADING ACTIVITIES
Our energy marketing group engages in various activities including the purchase
and sale of physical commodities and the use of financial instruments such as
commodity and foreign exchange futures, forwards and swaps to economically hedge
exposures and generate revenue. These contracts are accounted for as derivatives
and, where applicable, are presented net on the balance sheet in accordance with
netting arrangements. The fair value and carrying amounts related to derivative
instruments held by our energy marketing operations are as follows:
September 30 December 31
2009 2008
----------------------------------------------------------------------------------------------------------------------------
Commodity Contracts 537 742
Foreign Exchange Contracts 15 13
------------------------------------------
Accounts Receivable (Note 2) 552 755
------------------------------------------
Commodity Contracts 241 213
Foreign Exchange Contracts - 4
------------------------------------------
Deferred Charges and Other Assets (Note 5) (1) 241 217
------------------------------------------
Total Trading Derivative Assets 793 972
==========================================
Commodity Contracts 516 585
Foreign Exchange Contracts 56 30
------------------------------------------
Accounts Payable and Accrued Liabilities (Note 8) 572 615
------------------------------------------
Commodity Contracts 228 248
Foreign Exchange Contracts - 46
------------------------------------------
Deferred Credits and Other Liabilities (Note 12) (1) 228 294
------------------------------------------
Total Trading Derivative Liabilities 800 909
==========================================
Total Net Trading Derivative Contracts (7) 63
==========================================
(1) These derivative contracts settle beyond 12 months and are considered
non-current; once settlement is within 12 months, they are included in
accounts receivable or accounts payable.
Excluding the impact of netting arrangements, the fair value of derivative
instruments is as follows:
September 30
2009
-----------------------------------------------------------------------------------------------------------------------------
Current Trading Assets 3,608
Non-Current Trading Assets 1,031
---------------------
Total Trading Derivative Assets 4,639
=====================
Current Trading Liabilities 3,628
Non-Current Trading Liabilities 1,018
---------------------
Total Trading Derivative Liabilities 4,646
=====================
---------------------
Total Net Trading Derivative Contracts (7)
=====================
Trading revenues generated by our energy marketing group include gains and
losses on derivative instruments and non-derivative instruments such as physical
inventory. During the three and nine months ended September 30, 2009, the
following trading revenues were recognized in marketing and other income:
Three Months Nine Months
Ended September 30 Ended September 30
2009 2009
------------------------------------------------------------------------------------------------------------------------------
Commodity 177 748
Foreign Exchange 11 (72)
--------------------------------------------
Marketing Revenue (Note 14) 188 676
============================================
11
As an energy marketer, we may undertake several transactions during a period to
execute a single sale of physical product. Each transaction may be represented
by one or more derivative instruments including a physical buy, physical sell,
and in many cases, numerous financial instruments for economically hedging and
trading purposes. The absolute notional volumes associated with our derivative
instrument transactions are as follows:
Three Months Nine Months
Ended September 30 Ended September 30
2009 2009
-----------------------------------------------------------------------------------------------------------------------------
Natural Gas bcf/d 19.3 22.2
Crude Oil mmbbls/d 3.1 3.6
Power GWh/d 236.1 231.0
Foreign Exchange USD millions 742 1,973
Foreign Exchange Euro millions 48 308
-----------------------------------------------
(b) DERIVATIVE CONTRACTS RELATED TO NON-TRADING ACTIVITIES
The fair value and carrying amounts of derivative instruments related to
non-trading activities are as follows:
September 30 December 31
2009 2008
------------------------------------------------------------------------------------------------------------------------------
Accounts Receivable 12 6
Deferred Charges and Other Assets (Note 5) (1) - 234
--------------------------------------------
Total Non-Trading Derivative Assets 12 240
============================================
Accounts Payable and Accrued Liabilities 27 21
Deferred Credits and Other Liabilities (1) 7 26
--------------------------------------------
Total Non-Trading Derivative Liabilities 34 47
============================================
Total Net Non-Trading Derivative Contracts (2) (22) 193
============================================
(1) These derivative contracts settle beyond 12 months and are considered
non-current.
(2) The net fair value of these derivatives is equal to the gross fair value
before consideration of netting arrangements and collateral posted or
received with counterparties.
CRUDE OIL PUT OPTIONS
In 2008, we purchased put options on approximately 70,000 bbls/d of our 2009
crude oil production for $14 million. These options establish an annual average
Dated Brent floor price of US$60/bbl on these volumes. In September 2008, Lehman
Brothers filed for bankruptcy protection. This impacts approximately 25,000
bbls/d of our 2009 put options and the carrying value of these put options has
been reduced to nil. The crude oil put options are carried at fair value and are
classified as long-term or short-term based on their anticipated settlement
date. Fair value of the put options is supported by multiple quotes obtained
from third party brokers, which were validated with observable market data to
the extent possible. With the rise in Dated Brent oil price since the beginning
of the year, the fair value of the crude oil put options decreased. This
decrease is included in marketing and other income.
Change in Fair Value
-----------------------------------
Three Months Nine Months
Ended Ended
Notional Average Fair September 30 September 30
Volumes Term Floor Price Value 2009 2009
-------------------------------------------------------------------------------------------------------------------------------
(bbls/d) (US$/bbl)
Dated Brent Crude Oil Put Options 45,000 2009 60 12 (23) (218)
Dated Brent Crude Oil Put Options 25,000 2009 60 - - -
-------------------------------------------------
12 (23) (218)
=================================================
12
FIXED-PRICE NATURAL GAS CONTRACTS AND NATURAL GAS SWAPS
We have fixed-price natural gas sales contracts and offsetting natural gas swaps
that are not part of our trading activities. These sales contracts and swaps are
carried at fair value and are classified as long-term or short-term based on
their anticipated settlement date. The change in fair value of the fixed price
natural gas contracts and natural gas swaps is included in marketing and other
income.
Change in Fair Value
-----------------------------------
Three Months Nine Months
Ended Ended
Notional Average Fair September 30 September 30
Volumes Term Price Value 2009 2009
-------------------------------------------------------------------------------------------------------------------------------
(Gj/d) ($/Gj)
Fixed-Price Natural Gas Contracts 15,514 2009 2.28 (14) (2) 7
15,514 2010 2.28 (5) 4 21
Natural Gas Swaps 15,514 2009 7.60 (13) 3 (19)
15,514 2010 7.60 (2) 2 (3)
----------------------------------------------
(34) 7 6
==============================================
(c) FAIR VALUE OF DERIVATIVES
Our processes for estimating and classifying the fair value of our derivative
contracts are consistent with those in place at December 31, 2008. The following
table includes our derivatives carried at fair value for our trading and
non-trading activities as at September 30, 2009. Financial assets and
liabilities are classified in the fair value hierarchy in their entirety based
on the lowest level of input that is significant to the fair value measurement.
Assessment of the significance of a particular input to the fair value
measurement requires judgment and may affect placement within the fair value
hierarchy levels.
Net Derivatives Level 1 Level 2 Level 3 Total
------------------------------------------------------------------------------------------------------------------------------
Trading Derivatives (180) 151 22 (7)
Non-Trading Derivatives - (22) - (22)
---------------------------------------------------------
Total (180) 129 22 (29)
=========================================================
A reconciliation of changes in the fair value of our derivatives classified as
Level 3 for the nine months ended September 30, 2009 is provided below:
Level 3
------------------------------------------------------------------------------------------------------------------------------
Beginning of Period (82)
Realized and Unrealized Gains (Losses) 57
Purchases, Issuances and Settlements 55
Transfers In and/or Out of Level 3 (8)
---------------
End of Period 22
===============
Unsettled Gains (Losses) Relating to Instruments Still Held as of September 30, 2009 49
===============
Trading derivatives classified in Level 3 are generally economically hedged such
that gains or losses on positions classified in Level 3 are often offset by
gains or losses on positions classified in Level 1 or 2. Transfers into or out
of Level 3 represent existing assets and liabilities that were either previously
categorized as a higher level for which the inputs became unobservable or assets
and liabilities that were previously classified as Level 3 for which the lowest
significant input became observable during the period.
7. RISK MANAGEMENT
(a) MARKET RISK
We invest in significant capital projects, purchase and sell commodities, issue
short-term borrowings and long-term debt, and invest in foreign operations.
These activities expose us to market risks from changes in commodity prices,
foreign exchange rates and interest rates, which affect our earnings and the
value of the financial instruments we hold. We use derivatives for trading and
non-trading purposes as part of our overall risk management policy to manage
these market exposures.
The following market risk discussion focuses on the commodity price risk and
foreign currency risk related to our financial instruments as our exposure to
interest rate risk is immaterial as substantially all of our debt is fixed rate.
13
COMMODITY PRICE RISK
We are exposed to commodity price movements as part of our normal oil and gas
operations, particularly in relation to the prices received for our crude oil
and natural gas. Commodity price risk related to conventional and synthetic
crude oil prices is our most significant market risk exposure. Crude oil and
natural gas are sensitive to numerous worldwide factors and are generally sold
at contract or posted prices. Changes in the global supply and demand
fundamentals in the crude oil market and geopolitical events can significantly
affect crude oil prices, while natural gas prices are affected primarily by
North American supply and demand fundamentals. Changes in crude oil and natural
gas prices may significantly affect our results of operations and cash generated
from operating activities. Consequently, these changes may also affect the value
of our oil and gas properties, our level of spending for exploration and
development, and our ability to meet our obligations as they come due.
The majority of our oil and gas production is sold under short-term contracts,
exposing us to the risk of price movements. Other energy contracts also expose
us to commodity price risk during the time between when we purchase and sell
contracted volumes. We periodically manage these risks by using derivative
contracts such as commodity put options.
Our energy marketing business is focused on providing services for our customers
and suppliers to meet their energy commodity needs. We market and trade physical
energy commodities including crude oil, natural gas, electricity and other
commodities in selected regions of the world. We accomplish this by buying and
selling physical commodities, by acquiring and holding rights to physical
transportation and storage assets for these commodities, and by building strong
relationships with our customers and suppliers. In order to manage the commodity
and foreign exchange price risks that are generated by this physical business,
we use financial derivative contracts including energy-related futures,
forwards, swaps and options, as well as foreign currency swaps or forwards.
We also seek to profit from our views on the future movement of energy commodity
pricing relationships, primarily between different locations, time periods or
product qualities. We do this by holding open positions, where the terms of
physical or financial contracts are not completely matched to offsetting
positions. We may also carry exposures to the absolute change in commodity
prices based on our market views or as a consequence of managing our physical
and financial positions on a daily basis.
Our risk management activities include prescribed capital limits and the use of
tools such as Value-at-Risk (VaR) and stress testing consistent with the
methodology used at December 31, 2008. Our period end, high, low and average VaR
amounts for the three and nine months ended September 30, 2009 are as follows:
Three Months Nine Months
Ended September 30 Ended September 30
Value-at-Risk 2009 2008 2009 2008
----------------------------------------------------------------------------------------------------------------------------
Period End 13 27 13 27
High 15 33 24 40
Low 11 19 11 19
Average 12 29 16 31
---------------------------------------------------
If market shocks occur in 2009 as they did in 2008, the key assumptions
underlying our VaR estimate could be exceeded and the potential loss could be
greater than our estimate. We perform stress tests on a regular basis to
complement VaR and assess the impact of non-normal changes in prices on our
positions.
FOREIGN CURRENCY RISK
Foreign currency risk is created by fluctuations in the fair values or cash
flows of financial instruments due to changes in foreign exchange rates. A
substantial portion of our activities are transacted in or referenced to US
dollars including:
o sales of crude oil, natural gas and certain chemicals products;
o capital spending and expenses for our oil and gas, Syncrude and chemicals
operations;
o commodity derivative contracts used primarily by our energy marketing
group; and
o short-term borrowings and long-term debt.
In our oil and gas operations, we manage our exposure to fluctuations between
the US and Canadian dollar by matching our expected net cash flows and
borrowings in the same currency. Net revenue from our foreign operations and our
US-dollar borrowings are generally used to fund US-dollar capital expenditures
and debt repayments. We maintain revolving Canadian and US-dollar borrowing
facilities that can be used or repaid depending on expected cash flows. We
designate a portion of our US-dollar borrowings as a hedge against our US-dollar
net investment in self-sustaining foreign operations.
14
The foreign exchange gains or losses related to the effective portion of our
designated US-dollar debt are included in accumulated other comprehensive income
in shareholders' equity. Our net investment in self-sustaining foreign
operations and our designated US-dollar debt at September 30, 2009 and December
31, 2008 are as follows:
September 30 December 31
(US$ millions) 2009 2008
------------------------------------------------------------------------------------------------------------------------------
Net Investment in Self-Sustaining Foreign Operations 4,272 4,662
Designated US-Dollar Debt 4,272 4,545
-------------------------------------------
For the three and nine month periods ended September 30, 2009, the ineffective
portion of our US-dollar debt resulted in a net foreign exchange gain of $78
million and $135 million, respectively ($68 million and $118 million,
respectively, net of income tax expense) and is included in marketing and other
income. A one cent change in the US dollar to Canadian dollar exchange rate
would increase or decrease our accumulated other comprehensive income by
approximately $43 million, net of income tax, and would increase or decrease our
net income by approximately $8 million, net of income tax.
We also have modest exposures to currencies other than the US dollar including a
portion of our UK operating expenses, capital spending and future asset
retirement obligations which are denominated in British Pounds and Euros. We do
not have any material exposure to highly inflationary foreign currencies. In our
energy marketing group, we enter into transactions in various currencies
including Canadian and US dollars, British Pounds and Euros. We may actively
manage significant currency exposures using forward contracts and swaps.
(b) CREDIT RISK
Credit risk affects our oil, gas and chemicals operations and trading and
non-trading derivative activities is the risk of loss if counterparties do not
fulfill their contractual obligations. Most of our credit exposure is with
counterparties in the energy industry, including integrated oil companies, crude
oil refiners and utilities, and are subject to normal industry credit risk.
Approximately 74% of our exposure is with these large energy companies. This
concentration of risk within the energy industry is reduced because of our broad
base of domestic and international counterparties. Our processes to manage this
risk are consistent with those in place at December 31, 2008.
At September 30, 2009, only one counterparty individually made up more than 10%
of our credit exposure. This counterparty is a major integrated oil company with
a strong investment grade credit rating. No other counterparties made up more
than 5% of our credit exposure. The following table illustrates the composition
of credit exposure by credit rating.
September 30 December 31
CREDIT RATING 2009 2008
-----------------------------------------------------------------------------------------------------------------------------
A or higher 71% 65%
BBB 22% 29%
Non-Investment Grade 7% 6%
------------------------------------------
TOTAL 100% 100%
==========================================
Our maximum counterparty credit exposure at the balance sheet date consists
primarily of the carrying amounts on non-derivative financial assets such as
cash and cash equivalents, restricted cash, accounts receivable, as well as the
fair value of derivative financial assets. We provided an allowance of $54
million for credit risk with our counterparties. In addition, we incorporate the
credit risk associated with counterparty default, as well as Nexen's own credit
risk, into our estimates of fair value.
Collateral received from customers at September 30, 2009 includes $51 million of
cash and $506 million of letters of credit. The cash received reflects customer
deposits that are included in accounts payable and accrued liabilities.
(c) LIQUIDITY RISK
Liquidity risk is the risk that we will not be able to meet our financial
obligations as they become due. We require liquidity specifically to fund
capital requirements, satisfy financial obligations as they become due, and to
operate our energy marketing business. We generally rely on operating cash flows
to provide liquidity and we also maintain significant undrawn committed credit
facilities. At September 30, 2009, we had approximately $3.2 billion of cash and
available committed lines of credit. This includes $1.9 billion of cash and cash
equivalents on hand. In addition, we have undrawn term credit facilities of $1.7
billion, of which $427 million was supporting letters of credit at September 30,
2009. These facilities are available until 2012. We also have about $493 million
of undrawn, uncommitted credit facilities at September 30, 2009.
15
The following table details the contractual maturities for our non-derivative
financial liabilities, including both the principal and interest cash flows at
September 30, 2009:
less than more than
Total 1 Year 1-3 Years 4-5 Years 5 Years
------------------------------------------------------------------------------------------------------------------------------
Long-Term Debt (1) 7,522 - 1,847 590 5,085
Interest on Long-Term Debt (2) 8,340 369 739 712 6,520
---------------------------------------------------------------------------------------
Total 15,862 369 2,586 1,302 11,605
=======================================================================================
(1) Excludes cash and cash equivalents currently available.
(2) Excludes interest on term credit facilities of $3.3 billion and Canexus
term credit facilities of $452 million as the amounts drawn on the
facilities fluctuate. Based on amounts drawn at September 30, 2009 and
current interest rates, we would be required to pay $20 million per year
until the outstanding amounts on the term credit facilities are repaid.
The following table details contractual maturities for our derivative financial
liabilities. The balance sheet amounts for derivative financial liabilities
included below are not materially different from the contractual amounts due on
maturity.
less than more than
Total 1 Year 1-3 Years 4-5 Years 5 Years
------------------------------------------------------------------------------------------------------------------------------
Trading Derivatives (Note 6) 800 572 189 39 -
Non-Trading Derivatives (Note 6) 34 27 7 - -
---------------------------------------------------------------------------------------
Total 834 599 196 39 -
=======================================================================================
The commercial agreements our energy marketing group enter into often include
financial assurance provisions that allow us and our counterparties to
effectively manage credit risk. The agreements normally require collateral to be
posted if an adverse credit-related event occurs, such as a drop in credit
rating. Based on contracts in place and commodity prices at September 30, 2009,
we could be required to post collateral of up to $975 million if we were
downgraded to non-investment grade. This represents the maximum amount of
collateral that we would be required to post assuming a severe event that causes
all rating agencies to simultaneously downgrade us and no actions are taken by
us to mitigate our exposure. This amount includes trade payables of $686 million
and derivative contracts with a fair value of $289 million. All of these
obligations are included on our September 30, 2009 balance sheet. In the event
of a ratings downgrade, we could monetize our trading inventories and
receivables and draw on our existing credit facilities to meet our collateral
obligations. Further various actions can be taken, in anticipation of a
downgrade that would reduce the maximum amount of collateral we would need to
provide.
At September 30, 2009, collateral posted with counterparties includes $14
million of cash and $330 million of letters of credit related to our trading
activities. Cash posted is included with our accounts receivable. Cash
collateral is not normally applied to contract settlement. Once a contract has
been settled, the collateral amounts are refunded. If there is a default, the
cash is retained. Our exchange-traded derivative contracts are also subject to
margin requirements. We have margin deposits of $216 million (December 31, 2008
- $103 million), which have been included in restricted cash.
8. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES
September 30 December 31
2009 2008
-----------------------------------------------------------------------------------------------------------------------------
Energy Marketing 1,437 1,286
Accrued Payables 699 887
Energy Marketing Derivative Contracts (Note 6) 572 615
Income Taxes Payable 209 69
Trade Payables 208 251
Stock-Based Compensation 109 97
Other 124 121
------------------------------------------
Total 3,358 3,326
==========================================
16
9. SHORT-TERM BORROWINGS AND LONG-TERM DEBT
September 30 December 31
2009 2008
------------------------------------------------------------------------------------------------------------------------------
Canexus Term Credit Facilities, due 2011 (US$223 million drawn) (a) 239 223
Term Credit Facilities, due 2012 (US$1.5 billion drawn) (b) 1,608 1,225
Canexus Notes, due 2013 (US$50 million) 54 61
Notes, due 2013 (US$500 million) 536 612
Canexus Convertible Debentures, due 2014 (c) 46 -
Notes, due 2015 (US$250 million) 268 306
Notes, due 2017 (US$250 million) 268 306
Notes, due 2019 (US$300 million) (d) 322 -
Notes, due 2028 (US$200 million) 214 245
Notes, due 2032 (US$500 million) 536 612
Notes, due 2035 (US$790 million) 847 968
Notes, due 2037 (US$1,250 million) 1,340 1,531
Notes, due 2039 (US$700 million) (e) 751 -
Subordinated Debentures, due 2043 (US$460 million) 493 563
-------------------------------------------
7,522 6,652
Unamortized Debt Issue Costs (93) (74)
-------------------------------------------
Total 7,429 6,578
===========================================
(a) CANEXUS TERM CREDIT FACILITIES
Canexus has $452 million (US$422 million) of committed, secured term credit
facilities, $431 million (US$402 million) of which is available until 2011, with
the balance due 2013. At September 30, 2009, $239 million (US$223 million) was
drawn on these facilities (December 31, 2008 - $223 million (US$182 million)).
Borrowings are available as Canadian bankers' acceptances, LIBOR-based loans,
Canadian prime rate loans or US-dollar base rate loans. Interest is payable
monthly at floating rates. The term credit facilities are secured by a floating
charge debenture over all of Canexus' assets. The credit facility also contains
covenants with respect to certain financial ratios of Canexus. The
weighted-average interest rate on the Canexus term credit facilities was 2.0%
for the three months ended September 30, 2009 (three months ended September 30,
2008 - 4.6%) and 2.3% for the nine months ended September 30, 2009 (nine months
ended September 30, 2008 - 4.5%).
(b) TERM CREDIT FACILITIES
We have unsecured term credit facilities of $3.3 billion (US$3.1 billion)
available until 2012. At September 30, 2009, $1.6 billion (US$1.5 billion) was
drawn on these facilities (December 31, 2008 - $1.2 billion (US$1 billion)).
Borrowings are available as Canadian bankers' acceptances, LIBOR-based loans,
Canadian prime rate loans, US-dollar base rate loans or British pound call-rate
loans. Interest is payable at floating rates. The weighted-average interest rate
on our term credit facilities was 0.9% for the three months ended September 30,
2009 (three months ended September 30, 2008 - 3.5%) and 1.0% for the nine months
ended September 30, 2009 (nine months ended September 30, 2008 - 3.6%). At
September 30, 2009, $427 million (US$398 million) of these facilities were
utilized to support outstanding letters of credit (December 31, 2008 - $381
million (US$311 million)).
(c) CANEXUS CONVERTIBLE DEBENTURES
In August 2009, Canexus issued $46 million of convertible unsecured subordinated
debentures to non-controlling interests. Interest is payable semi-annually at a
rate of 8.00%. These debentures mature on December 31, 2014 and are convertible
at the holder's option at any time prior to the close of business on the earlier
of i) the maturity date and ii) the business day immediately preceding the date
specified by Canexus for redemption of the debentures into trust units. The
conversion price is $5.10 per trust unit.
Canexus has the option to redeem the debentures in whole or in part from time to
time subject to the satisfaction of certain conditions, after December 31, 2012
but before maturity, at a redemption price equal to the principal amount and
unpaid interest. Canexus may elect to satisfy its obligation to pay interest or
repay the principal by issuing trust units at market value.
The estimated fair value of the conversion feature of the convertible debentures
amounted to $4 million and was included in non-controlling interests, in
shareholders' equity. The amount of the convertible debentures allocated to
long-term debt is being amortized over the term of the debt using the effective
interest rate method.
Concurrent with the issuance, we acquired $40 million of debentures from Canexus
with substantially the same terms which allow us to protect against dilution of
our ownership interest at our option. These debentures are eliminated on
consolidation.
17
(d) NOTES, DUE 2019
In July 2009, we issued US$300 million of notes. Interest is payable
semi-annually at a rate of 6.20%, and the principal is to be repaid in July
2019. 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 0.40%.
(e) NOTES, DUE 2039
In July 2009, we issued US$700 million of notes. Interest is payable
semi-annually at a rate of 7.50%, and the principal is to be repaid in July
2039. 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 0.45%.
(f) INTEREST EXPENSE
Three Months Nine Months
Ended September 30 Ended September 30
2009 2008 2009 2008
----------------------------------------------------------------------------------------------------------------------------
Long-Term Debt 96 75 274 220
Other 4 5 12 15
---------------------------------------------------
Total 100 80 286 235
Less: Capitalized (16) (64) (60) (176)
---------------------------------------------------
Total 84 16 226 59
===================================================
Capitalized interest relates to and is included as part of the cost of our oil
and gas and Syncrude properties. The capitalization rates are based on our
weighted-average cost of borrowings.
(g) SHORT-TERM BORROWINGS
Nexen has uncommitted, unsecured credit facilities of approximately $493 million
(US$459 million), none of which were drawn at September 30, 2009 (December 31,
2008 - nil). We utilized $119 million (US$111 million) of these facilities to
support outstanding letters of credit at September 30, 2009 (December 31, 2008 -
$29 million (US$24 million)). Interest is payable at floating rates. The
weighted-average interest rate on our short-term borrowings was nil for the
three months ended September 30, 2009 (three months ended September 30, 2008 -
3.6%) and 2.1% for the nine months ended September 30, 2009 (nine months ended
September 30, 2008 - 3.2%).
10. CAPITAL MANAGEMENT
Our objectives and processes for managing our capital structure are consistent
with those in place at December 31, 2008. Our capital consists of shareholders'
equity, short-term borrowings, long-term debt and cash and cash equivalents as
follows:
September 30 December 31
2009 2008
------------------------------------------------------------------------------------------------------------------------------
NET DEBT (1)
Long-Term Debt 7,429 6,578
Less: Cash and Cash Equivalents (1,897) (2,003)
------------------------------------
Total 5,532 4,575
====================================
SHAREHOLDERS' EQUITY 7,401 7,191
====================================
(1) Includes all of our borrowings and is calculated as long-term debt and
short-term borrowings less cash and cash equivalents.
We monitor the leverage in our capital structure by reviewing the ratio of net
debt to cash flow from operating activities and interest coverage ratios at
various commodity prices.
We use the ratio of net debt to cash flow from operating activities as a key
indicator of our leverage and to monitor the strength of our balance sheet. Net
debt is a non-GAAP measure that does not have any standard meaning prescribed by
GAAP and therefore may not be comparable to similar measures presented by
others. We calculate net debt using the GAAP measures of long-term debt and
short-term borrowings less cash and cash equivalents (excluding restricted
cash).
For the twelve months ended September 30, 2009, our net debt to cash flow from
operating activities ratio was 2.3 times compared to 1.1 times at December 31,
2008. While we typically expect the target ratio to fluctuate between 1.0 and
18
2.0 times under normalized commodity prices, this can be higher or lower
depending on commodity price volatility or when we identify strategic
opportunities requiring additional investment. Whenever we exceed our target
ratio, we assess whether we need to develop a strategy to reduce our leverage
and lower this ratio back to target levels over time.
Our interest coverage ratio monitors our ability to fund the interest
requirements associated with our debt. Our interest coverage was 7.2 times at
September 30, 2009 (December 31, 2008 - 15.6 times). Interest coverage is
calculated by dividing our twelve-month trailing adjusted EBITDA by interest
expense before capitalized interest. Adjusted EBITDA is a non-GAAP measure. The
calculation of adjusted EBITDA is set out in the following table and is unlikely
to be comparable to similar measures presented by others.
Twelve Months Ended Year Ended
September 30 December 31
2009 2008
------------------------------------------------------------------------------------------------------------------------------
Net Income Attributable to Nexen Inc. 96 1,715
Add:
Interest Expense 261 94
Provision for Income Taxes 174 1,457
Depreciation, Depletion, Amortization and Impairment 2,110 2,014
Exploration Expense 376 402
Recovery of Non-Cash Stock-Based Compensation (39) (272)
Change in Fair Value of Crude Oil Put Options 14 (203)
Other Non-Cash Expenses (210) (1)
----------------------------------------------
Adjusted EBITDA 2,782 5,206
==============================================
11. ASSET RETIREMENT OBLIGATIONS
Changes in carrying amounts of the asset retirement obligations associated with
our Property, Plant & Equipment (PP&E) are as follows:
Nine Months Ended Year Ended
September 30 December 31
2009 2008
-------------------------------------------------------------------------------------------------------------------------------
Balance at Beginning of Period 1,059 832
Obligations Incurred with Development Activities 25 32
Obligations Discharged with Disposed Properties (2) -
Obligations Settled (25) (45)
Accretion Expense 51 58
Revisions to Estimates (19) 159
Effects of Changes in Foreign Exchange Rate (62) 23
----------------------------------------------
Balance at End of Period (1)(2) 1,027 1,059
==============================================
(1) Obligations due within 12 months of $35 million (December 31, 2008 - $35
million) have been included in accounts payable and accrued liabilities.
(2) Obligations relating to our oil and gas activities amount to $979 million
(December 31, 2008 - $1,009 million) and obligations relating to our
chemicals business amount to $48 million (December 31, 2008 - $50 million).
Our total estimated undiscounted inflated asset retirement obligations amount to
$2,353 million (December 31, 2008 - $2,393 million). We have discounted the
total estimated asset retirement obligations using a weighted-average,
credit-adjusted, risk-free rate of 5.9%. Approximately $367 million included in
our asset retirement obligations is expected to be settled over the next five
years. The remaining obligations settle beyond five years and are expected to be
funded by future cash flows from our operations.
12. DEFERRED CREDITS AND OTHER LIABILITIES
September 30 December 31
2009 2008
-------------------------------------------------------------------------------------------------------------------------------
Deferred Tax Credit 542 709
Long-Term Energy Marketing Derivative Contracts (Note 6) 228 294
Defined Benefit Pension Obligations 71 67
Capital Lease Obligations 61 53
Deferred Transportation Revenue 57 69
Other 125 132
----------------------------------------------
Total 1,084 1,324
==============================================
19
13. SHAREHOLDERS' EQUITY
DIVIDENDS
Dividends per common share for the three months ended September 30, 2009 were
$0.05 per common share (2008 - $0.05). Dividends per common share for the nine
months ended September 30, 2009 were $0.15 per common share (2008 - $0.125).
Dividends paid to holders of common shares have been designated as "eligible
dividends" for Canadian tax purposes.
14. MARKETING AND OTHER INCOME
Three Months Nine Months
Ended September 30 Ended September 30
2009 2008 2009 2008
----------------------------------------------------------------------------------------------------------------------------
Marketing Revenue, Net (Note 6) 188 149 676 381
Change in Fair Value of Crude Oil Put Options (Note 6) (23) 9 (218) (1)
Interest 1 7 4 20
Foreign Exchange Gains (Losses) 93 (33) 112 (34)
Other 37 (1) 61 21
---------------------------------------------------
Total 296 131 635 387
===================================================
15. EARNINGS PER COMMON SHARE
We calculate basic earnings per common share using net income divided by 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 Nine Months
Ended September 30 Ended September 30
(millions of shares) 2009 2008 2009 2008
----------------------------------------------------------------------------------------------------------------------------
Weighted-average number of common shares outstanding 521.7 525.9 521.0 528.3
Shares issuable pursuant to tandem options 10.3 19.6 10.7 24.9
Shares notionally purchased from proceeds of tandem options (7.0) (13.0) (7.5) (16.2)
---------------------------------------------------
Weighted-average number of diluted common shares outstanding 525.0 532.5 524.2 537.0
===================================================
In calculating the weighted-average number of diluted common shares outstanding
for the three and nine months ended September 30, 2009, we excluded 13,077,285
and 13,236,034 tandem options, respectively, because their exercise price was
greater than the average common share market price in the period. In calculating
the weighted-average number of diluted common shares outstanding for the three
and nine months ended September 30, 2008, we excluded 4,019,880 and 40,000
tandem options, respectively, because their exercise price was greater than the
average common share market price in the period. During the periods presented,
outstanding tandem options were the only potential dilutive instruments.
16. COMMITMENTS, CONTINGENCIES AND GUARANTEES
As described in Note 16 to the Audited Consolidated Financial Statements
included in our 2008 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 continue to believe
the resolution of these matters would not have a material adverse effect on our
liquidity, consolidated financial position or results of operations. There have
been no significant developments since year-end.
20
17. CASH FLOWS
(a) CHARGES AND CREDITS TO INCOME NOT INVOLVING CASH
Three Months Nine Months
Ended September 30 Ended September 30
2009 2008 2009 2008
----------------------------------------------------------------------------------------------------------------------------
Depreciation, Depletion, Amortization and Impairment 358 386 1,180 1,084
Stock-Based Compensation (19) (410) 23 (210)
Provision for (Recovery of) Future Income Taxes (81) 645 (397) 583
Change in Fair Value of Crude Oil Put Options 23 (9) 218 1
Allowance for Doubtful Accounts (4) 38 (5) 34
Foreign Exchange (117) 43 (154) 48
Other 14 (1) 22 4
---------------------------------------------------
Total 174 692 887 1,544
===================================================
(b) CHANGES IN NON-CASH WORKING CAPITAL
Three Months Nine Months
Ended September 30 Ended September 30
2009 2008 2009 2008
----------------------------------------------------------------------------------------------------------------------------
Accounts Receivable 212 503 39 (821)
Inventories and Supplies (13) 260 (142) (128)
Other Current Assets (24) (64) (12) (80)
Accounts Payable and Accrued Liabilities (68) (1,607) 251 425
Other Current Liabilities 20 12 16 26
---------------------------------------------------
Total 127 (896) 152 (578)
===================================================
Relating to:
Operating Activities 113 (840) 193 (468)
Financing Activities - 10 - 10
Investing Activities 14 (66) (41) (120)
---------------------------------------------------
Total 127 (896) 152 (578)
===================================================
(c) OTHER CASH FLOW INFORMATION
Three Months Nine Months
Ended September 30 Ended September 30
2009 2008 2009 2008
----------------------------------------------------------------------------------------------------------------------------
Interest Paid 70 64 248 212
Income Taxes Paid 179 655 247 816
---------------------------------------------------
Cash flow from other operating activities includes cash outflows related to
geological and geophysical expenditures of $16 million for the three months
ended September 30, 2009 (2008 - $38 million) and $59 million for the nine
months ended September 30, 2009 (2008 - $72 million).
21
18. OPERATING SEGMENTS AND RELATED INFORMATION
Nexen is involved in activities relating to Oil and Gas, Syncrude, Energy
Marketing and Chemicals in various geographic locations as described in Note 22
to the Audited Consolidated Financial Statements included in our 2008 Form 10-K.
THREE MONTHS ENDED SEPTEMBER 30, 2009
Energy Corporate
Oil and Gas Syncrude Marketing Chemicals and Other Total
---------------------------------------------------------------------------------------------------------
United United Other
Yemen Canada States Kingdom Countries (1)
--------------------------------------------------
Net Sales 176 92 74 478 16 137 9 115 - 1,097
Marketing and Other 3 (6) - 5 6 - 188 29 71 (2) 296
---------------------------------------------------------------------------------------------------------
Total Revenues 179 86 74 483 22 137 197 144 71 1,393
Less: Expenses
Operating 49 42 23 71 2 62 5 67 - 321
Depreciation, Depletion,
Amortization and
Impairment 19 59 67 162 2 13 14 12 10 358
Transportation and Other 7 8 2 3 - 5 141 13 6 185
General and
Administrative (3) 4 16 13 8 5 - 19 9 39 113
Exploration - 24 40 7 18 (4) - - - - 89
Interest - - - - - - - 2 82 84
---------------------------------------------------------------------------------------------------------
Income (Loss)
before Income Taxes 100 (63) (71) 232 (5) 57 18 41 (66) 243
Less: Provisions for
(Recovery
of) Income Taxes 35 (15) (30) 102 (5) 14 8 9 (9) 109
Less: Non-Controlling
Interests - - - - - - - 12 - 12
---------------------------------------------------------------------------------------------------------
Net Income (Loss) 65 (48) (41) 130 - 43 10 20 (57) 122
=========================================================================================================
Identifiable Assets 241 7,756 (5) 1,880 5,157 976 1,244 3,114 (6) 704 1,997 23,069
=========================================================================================================
Capital Expenditures
Development and Other 11 135 31 133 130 17 9 53 7 526
Exploration - 42 46 32 9 - - - - 129
---------------------------------------------------------------------------------------------------------
11 177 77 165 139 17 9 53 7 655
=========================================================================================================
Property, Plant and
Equipment
Cost 2,516 9,558 3,957 6,165 782 1,424 250 1,086 356 26,094
Less: Accumulated DD&A 2,369 1,955 2,507 2,396 97 264 78 552 234 10,452
---------------------------------------------------------------------------------------------------------
Net Book Value 147 7,603 (5) 1,450 3,769 685 1,160 172 534 122 15,642
=========================================================================================================
(1) Includes results of operations from producing activities in Colombia.
(2) Includes interest income of $1 million, foreign exchange gains of $93
million and decrease in the fair value of crude oil put options of $23
million.
(3) Includes recovery of stock-based compensation expense of $5 million.
(4) Includes exploration activities primarily in Norway, Nigeria and Colombia.
(5) Includes costs of $5,946 million related to our insitu oil sands projects
(Long Lake and future phases).
(6) Approximately 80% of Marketing's identifiable assets are accounts
receivable and inventories.
22
THREE MONTHS ENDED SEPTEMBER 30, 2008
Energy Corporate
Oil and Gas Syncrude Marketing Chemicals and Other Total
---------------------------------------------------------------------------------------------------------
United United Other
Yemen Canada States Kingdom Countries (1)
--------------------------------------------------
Net Sales 317 192 139 1,141 56 220 17 131 - 2,213
Marketing and Other 2 1 - 6 1 3 149 (12) (19) (2) 131
---------------------------------------------------------------------------------------------------------
Total Revenues 319 193 139 1,147 57 223 166 119 (19) 2,344
Less: Expenses
Operating 39 48 29 66 2 68 10 79 - 341
Depreciation, Depletion,
Amortization and
Impairment 46 50 56 192 4 12 4 11 11 386
Transportation and Other 3 - 1 21 - 4 235 12 15 291
General and
Administrative (3) (20) (66) (28) (19) (45) - (4) 9 (135) (308)
Exploration 2 5 41 18 46 (4) - - - - 112
Interest - - - - - - - 3 13 16
---------------------------------------------------------------------------------------------------------
Income (Loss)
before Income Taxes 249 156 40 869 50 139 (79) 5 77 1,506
Less: Provisions for
(Recovery of) Income Taxes 86 44 13 444 (3) 40 (20) 2 13 619
Less: Non-Controlling
Interests - - - - - - - 1 - 1
---------------------------------------------------------------------------------------------------------
Net Income (Loss) 163 112 27 425 53 99 (59) 2 64 886
=========================================================================================================
Identifiable Assets 365 6,301 (5) 1,951 6,502 536 1,218 4,468 (6) 541 333 22,215
=========================================================================================================
Capital Expenditures
Development and Other 29 245 46 189 35 19 2 24 10 599
Exploration - 34 38 43 11 - - - - 126
---------------------------------------------------------------------------------------------------------
29 279 84 232 46 19 2 24 10 725
=========================================================================================================
Property, Plant and
Equipment
Cost 2,402 7,697 3,670 5,558 358 1,363 268 896 322 22,534
Less: Accumulated DD&A 2,220 1,725 2,072 1,456 95 232 72 495 199 8,566
---------------------------------------------------------------------------------------------------------
Net Book Value 182 5,972 (5) 1,598 4,102 263 1,131 196 401 123 13,968
=========================================================================================================
(1) Includes results of operations from producing activities in Colombia.
(2) Includes interest income of $7 million, foreign exchange losses of $33
million, increase in the fair value of crude oil put options of $9 million
and other losses of $2 million.
(3) Includes recovery of stock-based compensation expense of $408 million.
(4) Includes exploration activities primarily in Norway and Colombia.
(5) Includes costs of $4,432 million related to our insitu oil sands projects
(Long Lake and future phases).
(6) Approximately 85% of Marketing's identifiable assets are accounts
receivable and inventories.
23
NINE MONTHS ENDED SEPTEMBER 30, 2009
Energy Corporate
Oil and Gas Syncrude Marketing Chemicals and Other Total
---------------------------------------------------------------------------------------------------------
United United Other
Yemen Canada States Kingdom Countries (1)
--------------------------------------------------
Net Sales 513 281 225 1,574 55 320 29 348 - 3,345
Marketing and Other 10 2 - 13 6 1 676 44 (117) (2) 635
---------------------------------------------------------------------------------------------------------
Total Revenues 523 283 225 1,587 61 321 705 392 (117) 3,980
Less: Expenses
Operating 145 125 73 175 6 205 21 196 - 946
Depreciation, Depletion,
Amortization and
Impairment 92 184 215 537 11 33 21 53 34 1,180
Transportation and Other 25 19 18 14 - 17 469 37 19 618
General and
Administrative (3) 5 58 51 15 29 1 68 34 119 380
Exploration - 53 87 26 53 (4) - - - - 219
Interest - - - - - - - 6 220 226
---------------------------------------------------------------------------------------------------------
Income (Loss)
before Income Taxes 256 (156) (219) 820 (38) 65 126 66 (509) 411
Less: Provisions for
(Recovery
of) Income Taxes 89 (39) (81) 358 (29) 16 52 15 (264) 117
Less: Non-Controlling
Interests - - - - - - - 17 - 17
---------------------------------------------------------------------------------------------------------
Net Income (Loss) 167 (117) (138) 462 (9) 49 74 34 (245) 277
=========================================================================================================
Identifiable Assets 241 7,756 (5) 1,880 5,157 976 1,244 3,114 (6) 704 1,997 23,069
=========================================================================================================
Capital Expenditures
Development and Other 62 519 106 391 328 56 20 161 17 1,660
Exploration - 189 111 109 50 - - - - 459
Proved Property
Acquisitions - 755 - - - - - - - 755
---------------------------------------------------------------------------------------------------------
62 1,463 217 500 378 56 20 161 17 2,874
=========================================================================================================
Property, Plant and
Equipment
Cost 2,516 9,558 3,957 6,165 782 1,424 250 1,086 356 26,094
Less: Accumulated DD&A 2,369 1,955 2,507 2,396 97 264 78 552 234 10,452
---------------------------------------------------------------------------------------------------------
Net Book Value 147 7,603 (5) 1,450 3,769 685 1,160 172 534 122 15,642
=========================================================================================================
(1) Includes results of operations from producing activities in Colombia.
(2) Includes interest income of $4 million, foreign exchange gains of $112
million, decrease in the fair value of crude oil put options of $218
million and other losses of $15 million.
(3) Includes stock-based compensation expense of $51 million.
(4) Includes exploration activities primarily in Norway, Nigeria and Colombia.
(5) Includes costs of $5,946 million related to our insitu oil sands projects
(Long Lake and future phases).
(6) Approximately 80% of Marketing's identifiable assets are accounts
receivable and inventories.
24
NINE MONTHS ENDED SEPTEMBER 30, 2008
Energy Corporate
Oil and Gas Syncrude Marketing Chemicals and Other Total
---------------------------------------------------------------------------------------------------------
United United Other
Yemen Canada States Kingdom Countries (1)
--------------------------------------------------
Net Sales 912 545 518 3,053 156 567 52 351 - 6,154
Marketing and Other 9 2 4 17 2 3 381 (13) (18) (2) 387
---------------------------------------------------------------------------------------------------------
Total Revenues 921 547 522 3,070 158 570 433 338 (18) 6,541
Less: Expenses
Operating 129 137 77 186 7 208 33 221 - 998
Depreciation, Depletion,
Amortization and
Impairment 120 144 192 505 12 36 11 32 32 1,084
Transportation and Other 7 10 2 21 - 11 574 41 25 691
General and
Administrative (3) (4) (9) 13 23 (7) 14 1 63 24 43 165
Exploration 2 41 70 42 90 (5) - - - - 245
Interest - - - - - - - 8 51 59
---------------------------------------------------------------------------------------------------------
Income (Loss)
before Income Taxes 672 202 158 2,323 35 314 (248) 12 (169) 3,299
Less: Provisions for
(Recovery of) Income Taxes 234 57 55 1,181 (3) 89 (72) 5 (146) 1,400
Less: Non-Controlling
Interests - - - - - - - 3 - 3
---------------------------------------------------------------------------------------------------------
Net Income (Loss) 438 145 103 1,142 38 225 (176) 4 (23) 1,896
=========================================================================================================
Identifiable Assets 365 6,301 (6) 1,951 6,502 536 1,218 4,468 (7) 541 333 22,215
=========================================================================================================
Capital Expenditures
Development and Other 61 855 180 410 73 39 3 57 23 1,701
Exploration 9 146 147 114 30 - - - - 446
Proved Property
Acquisitions - 2 - - - - - - - 2
---------------------------------------------------------------------------------------------------------
70 1,003 327 524 103 39 3 57 23 2,149
=========================================================================================================
Property, Plant and
Equipment
Cost 2,402 7,697 3,670 5,558 358 1,363 268 896 322 22,534
Less: Accumulated DD&A 2,220 1,725 2,072 1,456 95 232 72 495 199 8,566
---------------------------------------------------------------------------------------------------------
Net Book Value 182 5,972 (6) 1,598 4,102 263 1,131 196 401 123 13,968
=========================================================================================================
(1) Includes results of operations from producing activities in Colombia.
(2) Includes interest income of $20 million, foreign exchange losses of $34
million, decrease in the fair value of crude oil put options of $1 million
and other losses of $3 million.
(3) Includes severance accrual of $7 million in connection with North Vancouver
technology conversion project.
(4) Includes a recovery of stock-based compensation expense of $121 million.
(5) Includes exploration activities primarily in Norway and Colombia.
(6) Includes costs of $4,432 million related to our insitu oil sands projects
(Long Lake and future phases).
(7) Approximately 85% of Marketing's identifiable assets are accounts
receivable and inventories.
25
19. DIFFERENCES BETWEEN CANADIAN AND US GENERALLY ACCEPTED ACCOUNTING
PRINCIPLES
The Unaudited Consolidated Financial Statements have been prepared in accordance
with Canadian GAAP. The US GAAP Unaudited Consolidated Statements and summaries
of differences from Canadian GAAP are as follows:
UNAUDITED CONSOLIDATED STATEMENT OF INCOME - US GAAP
FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30
Three Months Nine Months
Ended September 30 Ended September 30
(Cdn$ millions, except per share amounts) 2009 2008 2009 2008
----------------------------------------------------------------------------------------------------------------------------
REVENUES AND OTHER INCOME
Net Sales 1,097 2,213 3,345 6,154
Marketing and Other (v); (vi) 344 366 702 470
---------------------------------------------------
1,441 2,579 4,047 6,624
---------------------------------------------------
EXPENSES
Operating 321 341 946 998
Depreciation, Depletion, Amortization and Impairment 358 386 1,180 1,084
Transportation and Other (v) 191 291 616 687
General and Administrative (iv) 89 (272) 394 180
Exploration 89 112 219 245
Interest 84 16 226 59
---------------------------------------------------
1,132 874 3,581 3,253
---------------------------------------------------
INCOME BEFORE PROVISION FOR INCOME TAXES 309 1,705 466 3,371
---------------------------------------------------
PROVISION FOR (RECOVERY OF) INCOME TAXES
Current 190 (26) 514 817
Deferred (iv); (vi); (vii) (68) 724 (384) 610
---------------------------------------------------
122 698 130 1,427
---------------------------------------------------
NET INCOME 187 1,007 336 1,944
Less: Net Income Attributable to Non-Controlling Interests (12) (1) (17) (3)
---------------------------------------------------
NET INCOME ATTRIBUTABLE TO NEXEN INC. - US GAAP (1) 175 1,006 319 1,941
===================================================
EARNINGS PER COMMON SHARE ($/share) (Note 15)
Basic 0.34 1.91 0.61 3.67
===================================================
Diluted 0.33 1.89 0.61 3.61
===================================================
(1) RECONCILIATION OF CANADIAN AND US GAAP NET INCOME
Three Months Nine Months
Ended September 30 Ended September 30
2009 2008 2009 2008
----------------------------------------------------------------------------------------------------------------------------
Net Income Attributable to Nexen Inc - Canadian GAAP 122 886 277 1,896
Impact of US Principles, Net of Income Taxes:
Stock-based Compensation (iv) 17 (26) (11) (11)
Inventory Valuation (vi) 29 146 46 56
Deferred Taxes (vii) 7 - 7 -
---------------------------------------------------
Net Income Attributable to Nexen Inc - US GAAP 175 1,006 319 1,941
===================================================
26
UNAUDITED CONSOLIDATED BALANCE SHEET - US GAAP
September 30 December 31
(Cdn$ millions, except share amounts) 2009 2008
--------------------------------------------------------------------------------------------------------------------------------
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents 1,897 2,003
Restricted Cash 216 103
Accounts Receivable 2,877 3,163
Inventories and Supplies (vi) 601 426
Other 199 169
--------------------------------------
Total Current Assets 5,790 5,864
--------------------------------------
PROPERTY, PLANT AND EQUIPMENT
Net of Accumulated Depreciation, Depletion, Amortization and
Impairment of $10,845 (December 31, 2008 - $10,786) (i); (iii) 15,593 14,873
GOODWILL 346 390
DEFERRED INCOME TAX ASSETS 916 351
DEFERRED CHARGES AND OTHER ASSETS 386 570
--------------------------------------
TOTAL ASSETS 23,031 22,048
======================================
LIABILITIES
CURRENT LIABILITIES
Accounts Payable and Accrued Liabilities (iv) 3,430 3,384
Accrued Interest Payable 81 67
Dividends Payable 26 26
--------------------------------------
Total Current Liabilities 3,537 3,477
--------------------------------------
LONG-TERM DEBT 7,429 6,578
DEFERRED INCOME TAX LIABILITIES (i); (ii); (iv); (vi); (vii) 2,635 2,543
ASSET RETIREMENT OBLIGATIONS 992 1,024
DEFERRED CREDITS AND OTHER LIABILITIES (ii) 1,188 1,428
SHAREHOLDERS' EQUITY
Nexen Inc. Shareholders' Equity
Common Shares, no par value
Authorized: Unlimited
Outstanding: 2009 - 521,846,559 shares
2008 - 519,448,590 shares 1,025 981
Contributed Surplus 1 2
Retained Earnings (i) - (vii) 6,413 6,172
Accumulated Other Comprehensive Loss (ii) (258) (209)
--------------------------------------
Total Nexen Inc. Shareholders' Equity 7,181 6,946
Canexus Non-Controlling Interests 69 52
--------------------------------------
TOTAL SHAREHOLDERS EQUITY 7,250 6,998
--------------------------------------
COMMITMENTS, CONTINGENCIES AND GUARANTEES (Note 16)
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY 23,031 22,048
======================================
UNAUDITED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME - US GAAP
FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30
Three Months Nine Months
Ended September 30 Ended September 30
2009 2008 2009 2008
--------------------------------------------------------------------------------------------------------------------------------
Net Income Attributable to Nexen Inc. - US GAAP 175 1,006 319 1,941
Other Comprehensive Income (Loss), Net of Income Taxes:
Foreign Currency Translation Adjustment (26) 41 (49) 60
---------------------------------------------------
Comprehensive Income Attributable to Nexen Inc. - US GAAP 149 1,047 270 2,001
===================================================
27
UNAUDITED CONSOLIDATED STATEMENT OF ACCUMULATED OTHER COMPREHENSIVE LOSS - US GAAP
September 30 December 31
2009 2008
-------------------------------------------------------------------------------------------------------------------------------
Foreign Currency Translation Adjustment (183) (134)
Unamortized Defined Benefit Pension Plan Costs (ii) (75) (75)
----------------------------------------
Accumulated Other Comprehensive Loss (258) (209)
========================================
NOTES TO THE UNAUDITED CONSOLIDATED US GAAP FINANCIAL STATEMENTS:
i. Under Canadian GAAP, we defer certain development costs to PP&E. Under US
principles, these costs have been included in operating expenses in prior
years. As a result PP&E is lower under US GAAP by $30 million (December
31, 2008 - $30 million).
ii. US GAAP requires the recognition of the over-funded and under-funded
status of a defined benefit plan on the balance sheet as an asset or
liability. At September 30, 2009 and December 31, 2008, the unfunded
amount of our defined benefit pension plans that was not included in the
pension liability under Canadian GAAP was $104 million. This amount has
been included in deferred credits and other liabilities and $75 million,
net of income taxes, has been included in Accumulated Other Comprehensive
Income (AOCI).
iii. On January 1, 2003, we adopted ACCOUNTING FOR ASSET RETIREMENT OBLIGATIONS
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
PP&E under US GAAP being lower by $19 million.
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. In addition, under
Canadian principles, we retroactively adopted EIC-162 which requires the
accelerated recognition of stock-based compensation expense for all
stock-based awards made to our retired and retirement-eligible employees.
However, US GAAP requires the accelerated recognition of stock-based
compensation expense for such employees for awards granted on or after
January 1, 2006. As a result under US GAAP:
o general and administrative (G&A) expense is lower by $24 million and
higher by $14 million ($17 million and $11 million, net of income
taxes) for the three and nine months ended September 30, 2009,
respectively (2008 - higher by $36 million and $15 million,
respectively ($26 million and $11 million, net of income taxes));
and
o accounts payable and accrued liabilities are higher by $72 million
as at September 30, 2009 (December 31, 2008 - $58 million).
v. Under US GAAP, asset disposition gains and losses are included with
transportation and other expense. Losses of $6 million and gains of $2
million for the three and nine months ended September 30, 2009,
respectively, were reclassified from marketing and other income to
transportation and other expense (gains of nil and $4 million were
reclassified for the three and nine months ended September 30, 2008).
vi. Under Canadian GAAP, we carry our commodity inventory held for trading
purposes at fair value, less any costs to sell. Under US GAAP, we are
required to carry this inventory at the lower of cost or net realizable
value. As a result:
o marketing and other income is higher by $42 million and $69 million
($29 million and $46 million, net of income taxes) for the three and
nine months ended September 30, 2009, respectively (2008 - higher by
$235 million and $87 million ($146 million and $56 million, net of
income taxes)); and
o inventories are higher by $11 million as at September 30, 2009
(December 31, 2008 - lower by $58 million).
vii. On January 1, 2007, we adopted ACCOUNTING FOR UNCERTAINTY IN INCOME TAXES
regarding accounting and disclosure for uncertain tax positions. On the
adoption of this US guidance, we recorded a cumulative effect of a change
in accounting principle of $28 million. This amount increased our deferred
income tax liabilities, and decreased our retained earnings as at January
1, 2007 in our US GAAP - Unaudited Consolidated Balance Sheet. During the
quarter our uncertain tax position changed. As a result:
o Deferred income tax expense is lower by $7 million for the three and
nine months ended September 30, 2009 (2008 - nil); and
o Deferred income tax liabilities are higher by $21 million as at
September 30, 2009 (December 31, 2008 - higher by $28 million).
As at September 30, 2009, the total amount of our unrecognized tax benefit
was approximately $273 million, all of which, if recognized, would affect
our effective tax rate. To the extent interest and penalties may be
assessed by taxing authorities on any underpayment of income tax, such
amounts have been accrued and are classified as a component of income
taxes in the Unaudited Consolidated Statement of Income. As at September
30, 2009, the total amount of interest
28
and penalties related to uncertain tax positions recognized in deferred income
tax liabilities in the US GAAP - Unaudited Consolidated Balance Sheet was
approximately $7 million. We had no interest or penalties included in the US
GAAP - Unaudited Consolidated Statement of Income for the three and nine months
ended September 30, 2009.
Our income tax filings are subject to audit by taxation authorities and as at
September 30, 2009 the following tax years remained subject to examination, (i)
Canada - 1985 to date (ii) United Kingdom - 2007 to date and (iii) United States
- 2005 to date. We do not anticipate any material changes to the unrecognized
tax benefits previously disclosed within the next 12 months.
CHANGES IN ACCOUNTING POLICIES - US GAAP
Business Combinations
On January 1, 2009, we prospectively adopted BUSINESS COMBINATIONS which
establishes principles and requirements of the acquisition method for business
combinations and related disclosures. The adoption of this statement did not
impact our results of operations or financial position.
NON-CONTROLLING INTERESTS
On January 1, 2009, we prospectively adopted NON-CONTROLLING INTERESTS IN
CONSOLIDATED FINANCIAL STATEMENTS. This statement clarifies that a
non-controlling interest in a subsidiary is an ownership interest in the
consolidated entity that should be reported as equity in the consolidated
financial statements. The adoption of this statement did not have a material
impact on our results of operations or financial position. The presentation
changes have been included in the Consolidated Financial Statements, as
applicable.
DERIVATIVE AND HEDGING ACCOUNTING AND DISCLOSURES
On January 1, 2009, we prospectively adopted DISCLOSURES ABOUT DERIVATIVE
INSTRUMENTS AND HEDGING ACTIVITIES. The statement requires qualitative
disclosures about the objectives and strategies for using derivatives,
quantitative data about the fair value of gains and losses on derivative
contracts and details of credit-risk-related contingent features in their hedged
position. The statement also requires the disclosure of the location and amounts
of derivative instruments in the financial statements. The disclosures required
by this standard are provided in Notes 6 and 7.
On April 1, 2009, we prospectively adopted three changes to FASB guidance
intended to improve guidance and disclosures on fair value measurement and
impairments. The positions clarify fair value accounting specifically regarding:
inactive markets and distressed transactions, other-than-temporary impairments,
and expanded fair value disclosures for financial instruments in interim
periods. The adoption of these positions did not have a material impact on our
results of operation or financial position.
SUBSEQUENT EVENTS
On April 1, 2009, we prospectively adopted SUBSEQUENT EVENTS. The new standard
reflects the existing principles of current subsequent events accounting
guidance and retains the notion and definition of "available to be issued"
financial statements. The new standard requires disclosure of the date through
which subsequent events have been evaluated and clarifies that original issuance
of financial statements means both "issued" or "available to be issued". The
adoption of this standard did not have a material impact on our results of
operation or financial position.
NEW ACCOUNTING PRONOUNCEMENTS - US GAAP
In December 2008, FASB issued EMPLOYERS DISCLOSURES ABOUT POSTRETIREMENT BENEFIT
PLAN ASSETS. This position provides guidance on disclosures about plan assets of
a defined benefit pension or other postretirement plans. This position is
effective for fiscal years ending after December 15, 2009. We do not expect the
adoption of this statement to materially impact our results of operations or
financial position.
In June 2009, FASB issued AMENDMENTS TO CONSOLIDATION OF VARIABLE INTEREST
ENTITIES. It retains the scope of the previous guidance with the addition of
entities previously considered qualifying special-purpose entities and
eliminates the previous quantitative approach for a qualitative analysis in
determining whether the enterprise's variable interest or interests give it a
controlling financial interest in a variable interest entity. The Statement is
further amended to require ongoing reassessments of whether an enterprise is the
primary beneficiary of a variable interest entity and requires enhanced
disclosures about an enterprise's involvement in a variable interest entity. The
Statement is effective at the beginning of the first annual reporting period
after November 15, 2009. We do not expect the adoption of this statement to have
a material impact on our results of operations or financial position.
29
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS (MD&A)
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 19 TO THE UNAUDITED CONSOLIDATED
FINANCIAL STATEMENTS. THE DATE OF THIS DISCUSSION IS OCTOBER 27, 2009.
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 IS ALSO PRESENTED.
NOTE: CANADIAN INVESTORS SHOULD READ THE SPECIAL NOTE TO CANADIAN INVESTORS ON
PAGE 79 OF OUR 2008 ANNUAL REPORT OF FORM 10-K (2008 FORM 10-K) WHICH HIGHLIGHTS
DIFFERENCES BETWEEN OUR RESERVES 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, FAIR VALUES OF 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 THIRD QUARTER RESULTS
Three Months Nine Months
Ended September 30 Ended September 30
(Cdn$ millions, except as indicated) 2009 2008 2009 2008
----------------------------------------------------------------------------------------------------------------------------
Production before Royalties (mboe/d) 214 249 235 257
Production after Royalties (mboe/d) 184 209 206 214
Nexen's Average Realized Oil and Gas Price (Cdn$/boe) 63.00 106.22 56.89 99.64
Cash Flow from Operating Activities 461 968 1,359 3,299
Net Income Attributable to Nexen Inc. 122 886 277 1,896
Earnings per Common Share, Basic ($/share) 0.23 1.68 0.53 3.59
Capital Investment 655 725 2,119 2,149
Acquisition of Additional Interest in Long Lake - - 755 -
Net Debt (1) 5,532 3,914 5,532 3,914
---------------------------------------------------
(1) Net debt is a non-GAAP measure and is defined as long-term debt and
short-term borrowings less cash and cash equivalents.
Planned maintenance and turnaround activity in the UK North Sea, Long Lake and
the Gulf of Mexico temporarily reduced our production during the third quarter.
Production was approximately 39,000 boe/d lower (based on production rates
immediately prior) as a result of these activities. In the North Sea, the shut
down of Buzzard and Scott/Telford was designed to coincide with a six week
slowdown for routine maintenance on the Forties pipeline. During the shutdown,
we successfully completed the fourth platform jacket installation and tie in at
Buzzard and performed planned maintenance at Scott/Telford. With this work
behind us and the start-up of Ettrick towards the end of the quarter, we are
currently producing approximately 275,000 boe/d and we expect production to
remain strong throughout the remainder of the year.
Commodity prices were slightly higher than the previous quarter, but were
considerably lower than a year ago. Our realized quarterly oil and gas price
increased 3% from the prior quarter to average $63.00/boe, but it remains
approximately 40% below last year's realized price. With 85% of our production
weighted to oil, we continue to be highly levered to increasing oil prices.
Our capital investment during the quarter focused on developing our Usan project
offshore Nigeria, advancing our shale gas knowledge and capabilities, and
appraising the Golden Eagle area discoveries in the UK North Sea. We are
currently reviewing development options for the Golden Eagle area, which
includes our Hobby and Pink discoveries. We are also making significant progress
with our shale gas project in the Dilly Creek area of the Horn River basin in
north-east British Columbia. During the quarter, we concluded a three-well
drilling and completion program and now have five shale gas wells on-stream. In
the Eastern Gulf of Mexico, we are currently drilling an exploratory well at
Appomattox, about six miles west of our discovery at Vicksburg. Our Longhorn
development in the Gulf of Mexico recently came on stream in late October.
At Long Lake, we achieved a major milestone at the end of August, when the
solvent de-asphalter and thermal cracker units were successfully put into
operation. As a result, we expect our PSC(TM) yield to increase to our design
yield of approximately
30
80%. In September, we successfully completed the previously announced turnaround
to replace valves, clean-out our hot lime softeners, isolate our water treatment
trains and perform a number of other planned maintenance activities to improve
reliability and operability. We also completed the installation of electric
submersible pumps (ESPs) in some of our SAGD wells. With the turnaround complete
we have resumed steaming our wells and bitumen volumes are ramping up.
Our financial position remains strong. We have available liquidity of
approximately US$3.3 billion, comprised of cash on hand and undrawn lines of
credit. We have no significant debt maturities until 2012 and the average
term-to-maturity of our long-term debt is approximately 17 years. We believe our
significant liquidity, combined with strong operating cash netbacks, provides us
with the financial flexibility to carry out our investment programs.
CAPITAL INVESTMENT
Our strategy is to build a sustainable energy company focused in three areas:
oil sands, unconventional gas and select conventional exploration and
exploitation. We are committed to growing long-term value for our shareholders
responsibly and are advancing our plans to achieve this as described below.
In 2009, we brought both Ettrick in the North Sea and Longhorn in the Gulf of
Mexico on stream. We are currently investing primarily in:
o ramping up Long Lake safely and reliably;
o developing our Usan project and continuing to explore our additional
acreage, offshore Nigeria;
o advancing appraisal of our Golden Eagle, Hobby and Pink discoveries in
the UK North Sea;
o targeting a number of exploration prospects, primarily in the North
Sea and Gulf of Mexico; and
o advancing our Horn River shale gas play in north-east British
Columbia.
Details of our capital programs are set out below:
THREE MONTHS ENDED SEPTEMBER 30, 2009
Major Early Stage New Growth Core Asset
Development Development Exploration Development Total
----------------------------------------------------------------------------------------------------------------------------------
Oil and Gas
United Kingdom 12 - 32 121 165
Nigeria 129 - 1 - 130
Synthetic (mainly Long Lake) (1) 101 15 - - 116
Canada - - 42 19 61
United States 25 - 46 6 77
Yemen - - - 11 11
Other Countries - - 8 1 9
Syncrude - - - 17 17
---------------------------------------------------------------------------
267 15 129 175 586
Chemicals 53 - - - 53
Energy Marketing, Corporate and Other - - - 16 16
---------------------------------------------------------------------------
Total Capital 320 15 129 191 655
===========================================================================
As a % of Total Capital 49% 2% 20% 29% 100%
---------------------------------------------------------------------------
(1) Includes $72 million of capitalized start-up costs.
31
NINE MONTHS ENDED SEPTEMBER 30, 2009
Major Early Stage New Growth Core Asset
Development Development Exploration Development Total
----------------------------------------------------------------------------------------------------------------------------------
Oil and Gas
Long Lake Acquisition 755 - - - 755
United Kingdom 114 6 109 271 500
Nigeria 326 - 20 - 346
Synthetic (mainly Long Lake) (1) 366 78 1 - 445
Canada - 2 188 73 263
United States 94 - 111 12 217
Yemen - - - 62 62
Other Countries - - 30 2 32
Syncrude - - - 56 56
----------------------------------------------------------------------------
1,655 86 459 476 2,676
Chemicals 161 - - - 161
Energy Marketing, Corporate and Other - - - 37 37
----------------------------------------------------------------------------
Total Capital 1,816 86 459 513 2,874
============================================================================
As a % of Total Capital 63% 3% 16% 18% 100%
--------------------------------=-------------------------------------------
(1) Includes $223 million of capitalized start-up costs.
UNITED KINGDOM - NORTH SEA
Our Ettrick development in the North Sea produced first oil in mid August and we
have tested the floating production, storage and offloading vessel (FPSO) up to
its design rates. Field production will ramp-up as we commission the gas system.
We have a 2008 discovery at Blackbird which could be a future tie-back to
Ettrick. We operate both Ettrick and Blackbird, with a 79.73% working interest
in each.
The Golden Eagle area has emerged as a significant development opportunity. We
expect development of the area will be economic with oil prices as low as
US$40/bbl and require standalone facilities due to its size. Project sanction is
targeted for 2010. Appraisal activity continues and we have now drilled 13 wells
in the area.
As we move into 2010, we are finalizing exploration plans to drill the North
Uist prospect, west of the Shetland Islands and the Brand prospect in the
Norwegian North Sea. These prospects have target sizes well above our typical
North Sea target size.
OFFSHORE WEST AFRICA
Development of the Usan field on block OML 138, offshore Nigeria is fully
underway. The field development plan includes a FPSO vessel with a storage
capacity of two million barrels of oil. Development drilling is underway and the
FPSO hull is under construction. The Usan field is expected to come on stream in
2012 and will ramp up to a peak production rate of 180,000 bbls/d (36,000 bbls/d
net to us). Nexen has a 20% interest in exploration and development on this
block and Total E&P Nigeria Limited is the operator.
Earlier this year, we completed drilling an exploration well in the southern
portion of Oil Prospecting License (OPL) 223, offshore West Africa. The Owowo
South B-1 well was drilled in a water depth of 670 metres and is located 20
kilometres northeast of the Usan field, currently under development. We expect
to announce drilling results shortly.
Under the production sharing contract governing OPL 223, the Nigerian National
Petroleum Corporation (NNPC) is concessionaire of the license, which is operated
by Total Exploration & Production Nigeria Ltd. Nexen has an 18% interest in the
well. As is typical in many jurisdictions, the Nigerian Government is reviewing
its existing petroleum fiscal terms, the impact of which on our projects is not
yet known.
SYNTHETIC
The turnaround at Long Lake is complete and we have resumed steaming our wells.
Steam production is increasing. Bitumen production is back up to pre-turnaround
rates of 10,000 to 12,000 bbls/d (gross) (6,500 to 7,800 bbls/d net to Nexen)
and growing. The upgrader has recently restarted.
The turnaround activities focused on replacing valves, cleaning out the hot lime
softeners and isolating the water treatment trains, and we performed a number of
other planned maintenance activities to improve reliability and operability.
These activities were successfully completed within the period of scheduled
downtime. We also installed ESPs in a number of our SAGD wells. This will allow
us to have better pressure control and ultimately reduce our overall
steam-to-oil ratio ("SOR").
32
In addition, we recently completed the steam de-bottleneck project which will
increase our SAGD steam production capacity to over 230,000 bbls/d. Start-up of
the de-bottleneck project will proceed as required to support the SAGD ramp-up.
We continue to expect a long-term SOR of 3.0 over the life of the project.
With respect to the Upgrader, we have now operated all units including the
solvent de-asphalter and the thermal cracker. These units are necessary to
achieve our target yield of approximately 80%. In addition, Syngas is being used
in all SAGD operations. This allows us to decrease operating costs by reducing
the requirement for purchased natural gas.
Phase 1 of our Long Lake project is designed to produce 72,000 bbls/d of gross
bitumen, upgraded to approximately 60,000 bbls/d (39,000 bbls/d, net to us) of
PSC(TM). We have a 65% interest in the project and the joint venture lands. We
are the sole operator of the resource and the upgrader. We expect Long Lake will
generate significant value with 40 years of production at a $10/bbl margin
advantage.
CANADA - HORN RIVER SHALE GAS
Following the conclusion of our recent three-well drilling and completion
program, we continue to make significant progress on our substantial Horn River
shale gas position in north-east British Columbia. With five shale gas wells now
on-stream, we are producing approximately 15 mmcf/d with the majority of
production coming from the three new wells. These wells have a higher frac
density than our earlier wells. Our land position here has the potential to
support 500 to 700 wells.
Substantial cost savings and productivity improvements were realized with this
drilling and completion program. We took advantage of improved equipment
utilization, drilled longer wells, initiated more fracs per well and maintained
an industry-leading frac pace of 26 fracs in 15 days while achieving a 100%
success rate on our frac program.
We have approximately 88,000 acres in the Dilly Creek area of the Horn River
basin with a 100% working interest. Further appraisal activity is required
before our reserve estimates can be finalized and commerciality established.
UNITED STATES - GULF OF MEXICO
In late October, we started production from the Longhorn development. The field
is expected to reach peak production of approximately 200 mmcf/d or 33,000 boe/d
gross (50 mmcf/d or 8,000 boe/d, net to us) early next year. We have a 25%
non-operated working interest in this project and ENI is the operator.
In the Gulf of Mexico, the arrival of the Ensco 8501 rig has allowed us to start
drilling our Knotty Head appraisal well. The well spud earlier this month and we
expect results in the second quarter of 2010. A second deep-water drilling rig
is expected to arrive in mid 2010. This will allow us to start drilling more of
our identified prospects.
In the Eastern Gulf, we recently spud the Appomattox prospect, which is located
six miles west of our Vicksburg discovery. Drilling results are expected early
next year. During the quarter, we completed drilling the Antietam prospect. The
well encountered thick good quality sand, but was wet. We have a 25% interest in
Vicksburg and a 20% interest in Appomattox and Shiloh, an earlier discovery.
Shell operates all three discoveries.
33
FINANCIAL RESULTS
CHANGE IN NET INCOME
2009 VS. 2008
------------------------------------------------
Three Months Ended Nine Months Ended
September 30 September 30
--------------------------------------------------------------------------------------------------------------------------------
NET INCOME AT SEPTEMBER 30, 2008 886 1,896
------------------------------------------------
Favorable (unfavorable) variances(1):
Realized Commodity Prices
Crude Oil (581) (1,994)
Natural Gas (106) (266)
------------------------------------------------
Total Price Variance (687) (2,260)
Production Volumes, After Royalties
Crude Oil (310) (379)
Natural Gas 17 (30)
Changes in Crude Oil Inventory Pending Sale (112) (114)
------------------------------------------------
Total Volume Variance (405) (523)
Oil and Gas Operating Expense 3 15
Oil and Gas Depreciation, Depletion, Amortization and Impairment
38 (63)
Exploration Expense 23 26
Energy Marketing Revenue, Net 130 389
Chemicals Contribution 24 46
General and Administrative Expense (2) (421) (215)
Interest Expense (68) (167)
Current Income Taxes (216) 303
Future Income Taxes 726 980
Other
Decrease in Fair Value of Crude Oil Put Options (32) (217)
Other 121 67
------------------------------------------------
NET INCOME AT SEPTEMBER 30, 2009 122 277
================================================
(1) All amounts are presented before provision for income taxes.
(2) Includes stock-based compensation expense.
Significant variances in net income are explained further in the following
sections.
34
OIL & GAS AND SYNCRUDE
PRODUCTION (BEFORE ROYALTIES) (1)
Three Months Nine Months
Ended September 30 Ended September 30
2009 2008 2009 2008
------------------------------------------------------------------------------------------------------------------------------
Crude Oil and Liquids (mbbls/d)
United Kingdom 73.7 100.0 91.6 102.0
Yemen 48.7 54.1 51.5 58.0
Canada 14.2 16.0 14.9 16.2
United States 9.5 8.5 10.6 11.2
Long Lake Bitumen (2) 5.5 5.2 7.6 3.0
Other Countries 2.6 5.7 3.9 5.7
Syncrude (mbbls/d) (3) 22.5 22.9 19.1 20.4
-----------------------------------------------------
176.7 212.4 199.2 216.5
-----------------------------------------------------
Natural Gas (mmcf/d)
United Kingdom 17 17 18 19
Canada 143 133 139 128
United States 63 70 58 94
-----------------------------------------------------
223 220 215 241
-----------------------------------------------------
Total Production (mboe/d) 214 249 235 257
=====================================================
PRODUCTION (AFTER ROYALTIES)
Three Months Nine Months
Ended September 30 Ended September 30
2009 2008 2009 2008
------------------------------------------------------------------------------------------------------------------------------
Crude Oil and Liquids (mbbls/d)
United Kingdom 73.7 100.0 91.6 102.0
Yemen 28.3 29.9 31.0 30.3
Canada 10.9 12.0 11.6 12.3
United States 8.5 7.3 9.6 9.7
Long Lake Bitumen (2) 5.5 5.2 7.6 3.0
Other Countries 2.4 5.1 3.6 5.3
Syncrude (mbbls/d) (3) 20.0 18.9 17.6 17.3
-------------------------------------------------------
149.3 178.4 172.6 179.9
-------------------------------------------------------
Natural Gas (mmcf/d)
United Kingdom 17 17 17 19
Canada 137 107 130 107
United States 56 60 52 80
-------------------------------------------------------
210 184 199 206
-------------------------------------------------------
Total Production (mboe/d) 184 209 206 214
=======================================================
(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) Pre-operating revenues and costs associated with Long Lake bitumen are
capitalized as development costs until we reach commercial operations.
(3) Currently considered a mining operation for US reporting purposes.
LOWER VOLUMES DECREASED NET INCOME FOR THE QUARTER BY $405 MILLION
Production before royalties was 11% lower from the prior quarter and 14% lower
from the third quarter of 2008. Our production was primarily lower due to
previously announced planned turnarounds and maintenance activities at a number
of our fields. At Buzzard, we were impacted by routine Forties pipeline
maintenance. During this downtime, we installed the jackets for the fourth
platform. At Scott/Telford, we completed a major turnaround which resulted in
the field being shutdown for approximately five weeks. Elsewhere, a planned
turnaround was completed late in the third quarter at Long Lake and in the Gulf
of Mexico, maintenance activities at third-party hosted facilities impacted
production from the Aspen and Wrigley fields. Lower volumes were partially
offset by: i) first oil from Ettrick; ii) a step-out development well at
Telford; iii) increased shale gas production at Horn River; and iv) higher
production at Syncrude, following the completion of a turnaround in the first
half of the year.
35
The following table summarizes our production volume changes since last quarter:
Before After
(mboe/d) Royalties Royalties
----------------------------------------------------------------------------------------------------------------------------
Production, second quarter 2009 240 208
Production changes:
Syncrude 8 7
Canada - 1
United Kingdom (24) (24)
Long Lake Bitumen (4) (4)
Yemen (3) (1)
United States (2) (2)
Other (1) (1)
------------------------------------------
Production, third quarter 2009 214 184
==========================================
Production volumes discussed in this section represent before-royalties volumes,
net to our working interest.
UNITED KINGDOM
Production volumes in the UK North Sea were approximately 25% lower as a result
of previously announced downtime for maintenance and turnaround activity at
Buzzard and Scott/Telford.
Our share of production from the Buzzard field averaged approximately 60,000
boe/d (138,000 boe/d gross) during the quarter. This was 32% lower than the
previous quarter and 34% lower than the third quarter of 2008. The lower
production was due to four weeks of planned downtime, scheduled to coincide with
a six week slowdown of the Forties pipeline for routine maintenance. During the
downtime, we successfully installed the jackets for the fourth platform and
prepared the tie-ins. This platform will allow us to handle higher levels of
hydrogen sulphide and maintain peak production until at least 2014. Buzzard
production has since returned to full rates and is currently producing between
200,000 and 220,000 boe/d gross.
Production at Scott/Telford was 6% lower from the prior quarter as the platform
was shut down for approximately five weeks for planned maintenance, coinciding
with the Forties pipeline shutdown. Scott/Telford production increased 9%
compared to the third quarter of 2008 primarily due to new production from a
step-out development well at Telford. This well was completed in September and
is tied back to our Scott platform. Production from our non-operated fields at
Duart and Farragon averaged 1,700 boe/d for the quarter.
The Ettrick field began producing in mid August. Ettrick contributed 5,800 boe/d
during the quarter and has been successfully produced at rates that allowed us
to test the design capacity of the floating production, storage and offloading
vessel (FPSO). In addition, we have a nearby discovery at Blackbird which could
be a future tie-back to Ettrick, further enhancing the economics of this
development.
YEMEN
Yemen production decreased 5% and 10% from the prior quarter and the third
quarter of 2008, respectively. The decline is consistent with our expectations
as the fields mature and as we drill fewer development wells. In the third
quarter of 2009, we drilled one development well. Production declines are
expected to continue as we focus on maximizing recovery of the remaining
reserves.
CANADA
Production in Canada has remained flat. Slightly lower conventional production
from our heavy oil properties was offset somewhat by increasing coalbed methane
(CBM) production. CBM production for the quarter averaged 52 mmcf/d, 7 mmcf/d
higher than the same period in 2008 and consistent with the prior quarter.
We continue to make significant progress on our substantial Horn River shale gas
position in north-east British Columbia. During the quarter, we concluded a
three-well drilling and completion program. We now have five shale gas wells
on-stream and are producing approximately 15 mmcf/d with the majority of
production coming from the three new wells.
LONG LAKE
Bitumen production for the quarter averaged 5,500 boe/d (8,500 boe/d gross),
down 3,800 boe/d from the prior quarter, while the facility sold approximately
3,200 boe/d (4,900 boe/d gross) of bitumen and 1,900 boe/d (2,900 boe/d gross)
of premium synthetic crude (PSC(TM)).
Production volumes decreased as a result of water treatment issues and a
previously announced turnaround in September. During the turnaround, we replaced
valves, cleaned hot lime softeners, isolated water treatment trains and
performed a number of other planned maintenance activities to improve
reliability and operability. We installed ESPs in a number of our SAGD
36
wells. With the turnaround complete we have resumed steaming the wells and
bitumen volumes are back up to pre-turnaround levels of 10,000 to 12,000 bbls/d
(gross) (6,500 to 7,800 bbls/d net to Nexen).
The last two major upgrader units, the solvent de-asphalter and thermal cracker,
were successfully put into operation at the end of August. This allows us to
transition from gasifying vacuum residue, which contains some lighter parts of
the barrel, to gasifying asphaltenes, the heaviest part of the barrel. As a
result, we expect our PSC(TM) yield to increase to our target yield of
approximately 80%.
In addition, we recently completed the steam de-bottleneck project which will
increase our SAGD steam production capacity to over 230,000 bbls/d. Start-up of
the de-bottleneck project will proceed as required to support the SAGD ramp-up.
UNITED STATES
Gulf of Mexico production volumes were 10% lower than the prior quarter. In the
deep water, maintenance activities at third-party hosted facilities impacted
production from the Aspen and Wrigley fields. These declines were partially
offset by producing for a full quarter on the shelf at Eugene Island 295, as
production was brought back on stream at the end of June, following last year's
hurricane damage.
Production volumes were 1% lower than the third quarter of 2008 as our Green
Canyon 6, 50 and 137 deep-water fields remain shut-in following Hurricane Ike in
2008, which caused the destruction of the third-party processing platform.
Production is expected to return in late 2010 or 2011, after reconstruction of
the platform is completed. This decrease was substantially offset as Aspen
production increased during the full quarter as compared to the same period last
year when hurricane interruptions curtailed production. Aspen production is also
higher as a result of additional water handling facilities being installed on
the third-party platform earlier this year. At the end of the third quarter
2009, production in the Gulf of Mexico was approximately 22,000 boe/d.
Production from our non-operated Longhorn development has now started. The
development is a four-well subsea tie-back to the Corral platform located 19
miles northwest of the field. The field is expected to reach peak production of
approximately 200 mmcf/d or 33,000 boe/d gross (50 mmcf/d or 8,000 boe/d, net to
us) early next year.
OTHER COUNTRIES
Our share of production from the Guando field in Colombia averaged 2,600 boe/d
during the quarter, 1,000 boe/d lower than the prior quarter and 3,100 boe/d
lower than the third quarter of 2008. The lower volumes reflect the reduced
working interest of the Guando field effective in the second quarter of 2009.
Under the terms of our license, our working interest in the Guando field
decreased from 20% to 10% in May 2009 after cumulative production from the field
reached 60 million barrels.
SYNCRUDE
Syncrude production was 51% higher than the previous quarter and 2% lower than
the third quarter of 2008. Production volumes were higher than the previous
quarter when we had; i) a scheduled turnaround on Coker 8-3; ii) maintenance on
Coker 8-1; and iii) fewer shipments of synthetic crude as a result of outages on
the Pembina pipeline. The higher production rates were partially offset by
unscheduled maintenance on the Vacuum Distillation Unit in the third quarter.
37
COMMODITY PRICES
Three Months Nine Months
Ended September 30 Ended September 30
2009 2008 2009 2008
----------------------------------------------------------------------------------------------------------------------------
CRUDE OIL
Dated Brent (Brent) (US$/bbl) 68.27 114.78 57.16 111.02
West Texas Intermediate (WTI) (US$/bbl) 68.30 117.98 57.00 113.29
---------------------------------------------------
Benchmark Differentials (1) (US$/bbl)
Heavy Oil 10.39 17.74 9.10 20.55
Mars 1.90 5.38 1.17 6.42
Masila (0.54) 5.01 0.15 3.75
Realized Prices from Producing Assets (Cdn$/bbl)
United Kingdom 73.15 114.89 63.78 108.21
Yemen 76.31 115.92 65.22 110.46
Canada 59.88 97.91 50.10 85.69
United States 72.27 122.46 61.60 110.29
Other Countries 70.49 120.11 55.89 108.03
Syncrude 74.54 126.56 67.26 120.12
Corporate Average (Cdn$/bbl) 72.95 115.56 63.15 108.36
---------------------------------------------------
NATURAL GAS
New York Mercantile Exchange (US$/mmbtu) 3.44 8.95 3.91 9.73
AECO (Cdn$/mcf) 2.87 8.76 3.89 8.13
---------------------------------------------------
Realized Prices from Producing Assets (Cdn$/mcf)
United Kingdom 2.64 7.53 4.04 7.11
Canada 2.85 8.00 3.67 8.33
United States 3.56 10.14 4.59 10.28
Corporate Average (Cdn$/mcf) 3.04 8.65 3.96 9.03
---------------------------------------------------
NEXEN'S AVERAGE REALIZED OIL AND GAS PRICE (Cdn$/boe) 63.00 106.22 56.89 99.64
---------------------------------------------------
AVERAGE FOREIGN EXCHANGE RATE - Canadian to US Dollar 0.9108 0.9599 0.8546 0.9817
---------------------------------------------------
(1) These differentials are a discount/(premium) to WTI.
LOWER COMMODITY PRICES REDUCED QUARTERLY NET INCOME BY $687 MILLION
Crude oil prices strengthened 15% during the quarter with Brent, which the
majority of our production is priced off, averaging US$68.27/bbl and WTI
averaging US$68.30/bbl. However, crude prices were approximately 42% lower
compared to the record prices in the third quarter last year. The impact of
lower commodity prices from last year was mitigated somewhat by the
strengthening US dollar. Our realized crude oil sales price averaged $72.95/bbl,
37% lower than the third quarter of 2008.
Natural gas prices continued to struggle during the quarter with NYMEX averaging
US$3.44/mmbtu and AECO averaging $2.87/mcf. This was a decline of 10% and 17%,
respectively from the previous quarter, and approximately 66% lower than last
year. As most of our natural gas sales are priced based on NYMEX and AECO
benchmark prices, these declines resulted in a realized average gas sales price
of $3.04/mcf, 19% lower than the previous quarter and 65% lower than last year.
Compared to the third quarter of 2008, the US dollar strengthened against the
Canadian dollar. As a result, our realized crude oil price increased by
$3.73/bbl, while our realized natural gas price increased by $0.16/mcf. This
increased our net sales by approximately $50 million. Compared to the previous
quarter however, the US dollar weakened against the Canadian dollar, decreasing
our net sales by approximately $62 million. This reduced our realized crude oil
and natural gas prices by $4.57/bbl and $0.19/mcf, respectively.
CRUDE OIL REFERENCE PRICES
During the third quarter, WTI traded from a low of US$59.52/bbl to a high of
US$74.37/bbl. The main drivers supporting recent increases in crude oil prices
included a continuing rally in US equity markets, positive investment flows into
commodity markets due to the weakening US dollar and a more optimistic outlook
on the global economic recovery.
38
However, near-term supply/demand fundamentals have not improved as global
inventory levels and spare capacity remain high and demand has been slow to
recover. Economic indicators continue to be mixed and uncertainty remains about
the shape of the recovery over the next few years. Most countries are expected
to show positive third quarter growth, consumer confidence has increased, and
industrial surveys show improvement. However, unemployment is expected to remain
high, US mortgage default rates have continued to increase, and questions remain
concerning the sustainability of future economic growth without support from
government spending.
Geopolitical events during the quarter such as concerns over Iran's nuclear
enrichment program, ongoing unrest in Iraq and Afghanistan and requests for
stronger regulation of energy markets and futures trading appear to have had
little impact on price.
CRUDE OIL DIFFERENTIALS
The heavy oil differential continued to be narrower than historic levels due to
increasing North American heavy oil refinery capacity, cuts in medium crude oil
production by OPEC, strong fuel oil prices and lower heavy oil supply from
Mexico. Line-fill requirements for the Keystone pipeline in North America are
expected to offset the impact of colder winter weather which has historically
caused differentials to widen in the winter season.
The Brent/WTI differential was volatile during the quarter. Brent traded at a
premium to WTI early in the third quarter due to depressed WTI pricing caused by
high inventory levels at Cushing and reduced supply in the North Sea due to
maintenance downtime. However, as US inventories decreased through the quarter,
the differential reverted to a discount to WTI.
Higher Cushing inventory levels also contributed to the narrower Masila
differential. The Masila price strengthened relative to Brent, reflecting strong
demand from China and other Asian countries.
The Mars differential was narrow during July and August but widened in September
as inventories fell at Cushing.
NATURAL GAS REFERENCE PRICES
NYMEX natural gas prices were volatile during the quarter. Relative to last
year, low prices were driven by declines in industrial and power demand and high
inventory levels as natural gas producers have been slow to respond to lower
prices by reducing supply. Despite the fundamentals, prices strengthened during
the quarter to a high of US$5/mmbtu at the end of September. Continuing weak gas
prices are forecasted as strong supply additions are expected from shale gas,
tight gas and new LNG volumes from Russia and the Middle East.
OPERATING EXPENSES
Three Months Nine Months
Ended September 30 Ended September 30
(Cdn$/boe) 2009 2008 2009 2008
------------------------------------------------------------------------------------------------------------------------------
Operating expenses based on our production before royalties (1)
Conventional Oil and Gas 11.56 8.75 9.41 8.38
Synthetic Crude Oil
Syncrude 29.50 32.40 39.26 37.22
Average Oil and Gas 13.60 10.90 11.97 10.70
-----------------------------------------------------
Operating expenses based on our production after royalties
Conventional Oil and Gas 13.45 10.38 10.90 10.09
Synthetic Crude Oil
Syncrude 33.19 39.23 42.67 44.01
Average Oil and Gas 15.76 12.96 13.79 12.87
-----------------------------------------------------
(1) Operating expenses 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.
LOWER OPERATING EXPENSES INCREASED NET INCOME FOR THE QUARTER BY $3 MILLION
Our corporate average oil and gas operating cost increased $2.70/boe compared to
the third quarter of 2008. Changes in production mix due to various temporary
shutdowns for maintenance during the quarter resulted in lower production
volumes. However, we continued to incur fixed operating costs at the same time.
The lower volumes and fixed operating costs increased our per unit costs by
$1.62/boe. The stronger US dollar resulted in higher US-dollar denominated
operating costs, increasing our corporate average by $0.60/boe.
In the UK North Sea, absolute operating costs at Buzzard decreased compared with
the same period last year due to previously announced downtime. However, per
unit operating costs were higher as additional costs were incurred for
maintenance during the shut down, combined with lower production volumes. This
increased our corporate average by $0.56/boe. At Scott/Telford, we similarly
39
incurred higher operating costs per barrel due to planned maintenance downtime.
This, combined with the start up of Ettrick where operating costs per barrel are
higher than our corporate average, increased our corporate average by $0.22/boe.
In Yemen, we continue to incur costs to maintain existing well productivity to
maximize reserve recoveries and slow the natural decline of the field. These
costs, combined with production declines, increased our corporate average
operating cost by $0.73/boe. In the US Gulf of Mexico, lower repair and
maintenance costs and higher volumes reduced the consolidated average unit cost
by $0.59/boe.
Canada reduced our corporate average by $0.11/boe from lower utility and
downhole workover costs, while lower natural gas prices and maintenance costs at
Syncrude decreased our corporate average by $0.33/boe.
DEPRECIATION, DEPLETION, AMORTIZATION AND IMPAIRMENT (DD&A)
Three Months Nine Months
Ended September 30 Ended September 30
(Cdn$/boe) 2009 2008 2009 2008
----------------------------------------------------------------------------------------------------------------------------
DD&A based on our production before royalties (1)
Conventional Oil and Gas 19.14 16.08 18.71 15.05
Synthetic Crude Oil
Syncrude 6.12 6.10 6.29 6.47
Average Oil and Gas 17.66 15.17 17.64 14.36
----------------------------------------------------
DD&A based on our production after royalties
Conventional Oil and Gas 22.26 19.08 21.67 18.13
Synthetic Crude Oil
Syncrude 6.88 7.38 6.83 7.65
Average Oil and Gas 20.46 18.03 20.32 17.27
----------------------------------------------------
(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.
LOWER OIL AND GAS DD&A INCREASED NET INCOME FOR THE QUARTER BY $38 MILLION
Our corporate average DD&A cost per barrel increased $2.49/boe over last year.
However, lower production as a result of maintenance and turnaround activity
during the quarter reduced our absolute oil and gas DD&A expense by 11%. The
stronger US dollar increased our corporate average by $1.09/boe as depletion of
our international and US assets is denominated in US dollars.
Our production mix was impacted as a result of lower production caused by
maintenance downtime in the UK North Sea and natural declines in Yemen. This
change in production mix increased our overall corporate average by $0.51/boe.
In the UK North Sea, our Buzzard depletion rate decreased from the same period
last year as successful development drilling increased our proved reserve
estimates at the end of 2008. This lower depletion rate reduced our corporate
average by $0.06/boe. Elsewhere in the UK, higher depletion rates at Ettrick and
Scott/Telford increased our corporate average by $1.18/boe. The depletion rate
at our mature Scott/Telford fields increased compared to last year as a result
of downward price-related reserve revisions at the end of 2008.
Lower depletion rates in Yemen, due to lower capital expenditures from drilling
fewer development wells and higher reserve estimates, reduced our corporate
average by $1.23/boe. In the Gulf of Mexico, higher estimates for future
abandonment costs and downward price-related reserve revisions at the end of
2008 resulted in higher depletion rates, increasing our corporate average rate
by $0.31/boe.
Canadian depletion increased our corporate average by $0.69/boe. Depletion rates
at our heavy oil properties were also up due to downward price-related revisions
to our proved reserves at the end of 2008. This was partially offset by lower
depletion rates at our CBM properties where additional proved reserves were
recognized through improved recovery rates.
40
EXPLORATION EXPENSE
Three Months Nine Months
Ended September 30 Ended September 30
2009 2008 2009 2008
-----------------------------------------------------------------------------------------------------------------------------
Seismic 16 38 59 72
Unsuccessful Drilling 51 50 78 101
Other 22 24 82 72
----------------------------------------------------
Total Exploration Expense 89 112 219 245
====================================================
New Growth Exploration 129 126 459 446
Geological and Geophysical Costs 16 38 59 72
----------------------------------------------------
Total Exploration Expenditures 145 164 518 518
====================================================
Exploration Expense as a % of Exploration Expenditures 61% 68% 42% 47%
----------------------------------------------------
LOWER EXPLORATION EXPENSE INCREASED NET INCOME FOR THE QUARTER BY $23 MILLION
Exploration expenditures were $19 million lower than the same period last year
primarily due to lower seismic acquisition costs. During the quarter, we focused
on: i) furthering our appraisal of the Golden Eagle area in the UK North Sea;
ii) investing in our shale gas exploration program at Dilly Creek; and iii)
advancing our deep water exploration program in the Eastern Gulf of Mexico.
We have significant exploration success in the Golden Eagle area, which includes
our 34% operated interest in Golden Eagle and Hobby, and our 46% operated
interest in Pink. We have drilled three exploration and ten appraisal wells,
with additional appraisal wells due in the fourth quarter. We are evaluating
development options as we move towards project sanction.
We continue to make significant progress on our shale gas project in the Dilly
Creek area of the Horn River basin in north-east British Columbia, where we have
approximately 88,000 acres with a 100% working interest. During the quarter, we
concluded a three-well fracing and completion program and now have five shale
gas wells on stream. Substantial cost savings and productivity improvements were
realized with this drilling and completion program.
In the Eastern Gulf of Mexico, we are currently drilling an exploratory well at
Appomattox, about six miles west of our discovery at Vicksburg. The well was
spud in September and drilling operations are ongoing. Elsewhere, we continue to
evaluate drilling results from our Owowo South B-1 well, 20 kilometers northeast
of the Usan field, offshore Nigeria.
Exploration expense was $23 million lower than the same period last year, mainly
related to lower seismic acquisition costs. Our exploration expense includes
costs to acquire seismic data in the Gulf of Mexico and North Sea.
Unsuccessful drilling expense during the quarter includes CBM drilling costs in
Canada and an unsuccessful well in the Eastern Gulf of Mexico. We expensed costs
of $20 million related to our CBM exploration activities in central Alberta on
those properties where we have no future development plans. Our Antietam well in
the Eastern Gulf of Mexico was drilled to a depth of 23,000 feet. The well
encountered thick good quality sand, but was wet. The well was subsequently
plugged and abandoned, and we expensed drilling costs of $31 million. In the
third quarter of 2008, exploration expense included unsuccessful drilling costs
of $26 million related to our Fredericksburg well in the US Gulf of Mexico and
$6 million for our Yeoman well in the UK North Sea.
41
ENERGY MARKETING
Three Months Nine Months
Ended September 30 Ended September 30
2009 2008 2009 2008
----------------------------------------------------------------------------------------------------------------------------
Physical Sales (1) 9,711 16,479 29,719 48,987
Physical Purchases (1) (9,605) (16,255) (29,011) (48,077)
Net Financial Transactions (2) 117 239 (111) (365)
Change in Fair Market Value of Inventory (35) (314) 79 (164)
---------------------------------------------------
Marketing Revenue 188 149 676 381
Transportation Expense (145) (197) (473) (536)
Other 4 7 8 19
---------------------------------------------------
NET MARKETING REVENUE 47 (41) 211 (136)
===================================================
CONTRIBUTION TO NET MARKETING REVENUE BY REGION
North America 33 (53) 192 (131)
Asia 4 2 22 10
Europe 10 10 (3) (15)
---------------------------------------------------
NET MARKETING REVENUE 47 (41) 211 (136)
DD&A (14) (4) (21) (11)
General and Administrative (19) 4 (68) (63)
Allowance for Doubtful Receivables 4 (38) 4 (38)
---------------------------------------------------
MARKETING CONTRIBUTION TO INCOME BEFORE INCOME TAXES 18 (79) 126 (248)
===================================================
NORTH AMERICA
NATURAL GAS
Physical Sales Volumes (3) (bcf/d) 4.9 7.0 4.9 7.0
Transportation Capacity (bcf/d) 1.5 2.1 1.5 2.1
Storage Capacity (bcf) 32.5 49.3 32.5 49.3
Financial Volumes (4) (bcf/d) 8.7 12.5 11.4 19.2
CRUDE OIL
Physical Sales Volumes (3) (mbbls/d) 802 645 837 649
Storage Capacity (mmbbls) 3.1 3.2 3.1 3.2
Financial Volumes (4) (mbbls/d) 699 1,454 796 1,429
POWER
Physical Sales Volumes (3) (GWh/d) 14 5 9 5
Generation Capacity (MW) 87 87 87 87
ASIA
Physical Sales Volumes (3) (mbbls/d) 93 82 97 103
Financial Volumes (4) (mbbls/d) 420 365 425 324
EUROPE
NATURAL GAS
Physical Sales Volumes (3) (bcf/d) 1.2 1.1 1.2 1.2
Storage Capacity (bcf) 3.1 3.8 3.1 3.8
CRUDE OIL
Financial Volumes (4) (mbbls/d) 261 216 340 970
POWER
Physical Sales Volumes (3) (GWh/d) 6 6 6 5
VALUE-AT-RISK
Quarter-end 13 27 13 27
High 15 33 24 40
Low 11 19 11 19
Average 12 29 16 31
---------------------------------------------------
(1) Marketing's physical sales, physical purchases and net financial
transactions are reported within marketing revenue as detailed in the notes
to the unaudited consolidated financial statements.
(2) Net financial transactions include all gains and losses on financial
derivatives and the unrealized portion of gains and losses on physical
purchase and sale contracts.
(3) Excludes inter-segment transactions. Physical volumes represent amounts
delivered during the quarter.
(4) Financial volumes represent amounts largely acquired to economically hedge
physical transactions during the quarter.
42
HIGHER CONTRIBUTION FROM ENERGY MARKETING INCREASED NET INCOME BY $130 MILLION
During the quarter, we initiated a strategic review of our energy marketing
natural gas and power businesses. This review continues to align our marketing
activities with our upstream oil and gas businesses. The review may include the
sale of all or part of these businesses and is expected to continue into 2010.
Data rooms are ready and numerous parties have expressed interest.
In the interim, our energy marketing team continues to focus on optimizing our
physical marketing business with all groups contributing positive results in the
quarter. In particular, positive returns generated by active asset optimization
by the natural gas team more than offset the impact of narrowing transportation
spreads. The global crude oil team continued to profit from the contango crude
oil forward curve.
Our energy marketing results in 2009 are significantly improved over 2008. Last
year, we incurred losses in our natural gas business, due to narrowing spreads
between supply regions and consuming markets, and on certain physical basis
contracts and losses on contracts used to protect the value of some of our
physical capacity contracts. The losses were offset somewhat by gains from
blending crude oil. Late in the year, the team began exiting positions and
working to reduce trading levels and the overall size of our North American gas
business.
Our results last year also included a $38 million provision for our exposure to
Lehman Brothers who filed for bankruptcy protection in September 2008.
Our third quarter results were consistent relative to the second quarter. This
was due to improved results from the global crude oil teams who profited from
the contango curve offset by lower income from the North America gas team. The
gas team recognized mark-to-market losses on derivatives that protect our
storage and inventory assets, and losses on the value of inventory associated
with lower prompt gas prices. We expect to see some recovery in the fourth
quarter in the value of our physical assets as we move towards higher seasonal
prices for winter.
Results from our energy 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.
COMPOSITION OF NET MARKETING REVENUE
Three Months Nine Months
Ended September 30 Ended September 30
2009 2008 2009 2008
----------------------------------------------------------------------------------------------------------------------------
Trading Activities (Physical and related Financial) 43 (49) 201 (157)
Non-Trading Activities 4 8 10 21
---------------------------------------------------
Total Net Marketing Revenue 47 (41) 211 (136)
===================================================
TRADING ACTIVITIES
In energy marketing, we enter into contracts to purchase and sell crude oil and
natural gas as well as storage and transportation contracts to capture time and
location differences. We also use financial and derivative contracts, including
futures, forwards, swaps and options for hedging and trading purposes. We
account for all financial and derivative contracts not designated as hedges for
accounting purposes using fair value accounting and record the change in fair
value in marketing and other income. The fair value of these instruments is
included with amounts receivable or payable and they are classified as long-term
or short-term based on their anticipated settlement date.
OTHER ACTIVITIES
We enter into fee for service contracts related to transportation, storage and
sales of third-party oil and gas. In addition, we earn income from our power
generation facilities at Balzac and Soderglen.
FAIR VALUE OF DERIVATIVE CONTRACTS
Our processes for estimating and classifying the fair value of our derivative
contracts are consistent with those in place at December 31, 2008.
43
At September 30, 2009, the fair value of our derivative contracts in our energy
marketing trading activities was a net liability of $7 million. These
derivatives are used to economically hedge our physical storage and
transportation contracts which cannot be carried at fair value until they are
used. Below is a breakdown of the derivative fair value by valuation method and
contract maturity.
MATURITY
------------------------------------------------------------------------------------------------------- -----------------------
less than more than
1 year 1-3 years 4-5 years 5 years Total
------------------------------------------ -----------------------
Level 1 - Actively Quoted Markets (106) (54) (20) - (180)
Level 2 - Based on Other Observable Pricing Inputs 82 53 9 7 151
Level 3 - Based on Unobservable Pricing Inputs 4 17 1 - 22
------------------------------------------ -----------------------
Total (20) 16 (10) 7 (7)
========================================== =======================
CHANGES IN FAIR VALUE OF DERIVATIVE CONTRACTS
Total
------------------------------------------------------------------------------------------------------------------------------
Fair Value at December 31, 2008 63
Change in Fair Value of Contracts 116
Net Losses (Gains) on Contracts Closed (186)
Changes in Valuation Techniques and Assumptions (1) -
----------------
Fair Value at September 30, 2009 (7)
================
(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
related contracts settle. Until then, the value of certain contracts will vary
with forward commodity prices and price differentials. The average term of our
derivative contracts is approximately 1.3 years. Those maturing beyond one year
primarily relate to North American natural gas positions.
CHEMICALS
HIGHER CHEMICALS CONTRIBUTION INCREASED NET INCOME BY $24 MILLION
Third quarter chemicals revenue experienced a decline in both chlor-alkali and
chlorate sales in North America and Brazil. North America chlorate revenue
decreased 4% from the same period last year, as a 12% reduction in sales volumes
attributable to the global economic downturn was only partially offset by higher
prices. North America chlor-alkali revenue decreased 11% over the same period
due to a combination of lower volumes and weaker caustic prices. In Brazil,
lower prices and sales volumes reduced chlorate and chlor-alkali revenues by 10%
and 42%, respectively. Chlor-alkali revenues in Brazil were lower as a result of
fewer sales of purchased product as this activity generates no gross margin.
Chemicals contribution increased from the same period last year as the stronger
Canadian dollar at September 30, 2009 generated unrealized foreign exchange
gains of $24 million on the Canexus US-dollar denominated debt. This was higher
than the third quarter of 2008 when our chemicals operations recognized foreign
exchange translation losses of $12 million.
CORPORATE EXPENSES
GENERAL AND ADMINISTRATIVE (G&A)
Three Months Nine Months
Ended September 30 Ended September 30
2009 2008 2009 2008
------------------------------------------------------------------------------------------------------------------------------
General and Administrative Expense before Stock-Based Compensation 118 100 329 286
Stock-Based Compensation (1) (5) (408) 51 (121)
----------------------- ----------------------
Total General and Administrative Expense 113 (308) 380 165
======================= ======================
(1) Includes cash and non-cash expenses related to our tandem option and stock
appreciation rights plans.
HIGHER G&A COSTS DECREASED NET INCOME BY $421 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,
our share price decreased 4% and we reversed approximately $19 million of
non-cash stock-based compensation expense that we had previously recognized. In
the same period last year, our share price was lower by 39% resulting in a $410
million reversal of previously recognized stock-based compensation expense. Cash
payments made in connection with our stock-based compensation programs during
the three and nine month periods ended September 30, 2009 were $14 million and
$28 million respectively (2008 - $2 million and $89 million, respectively).
44
INTEREST
Three Months Nine Months
Ended September 30 Ended September 30
2009 2008 2009 2008
------------------------------------------------------------------------------------------------------------------------------
Interest 100 80 286 235
Less: Capitalized (16) (64) (60) (176)
----------------------------------------------
Net Interest Expense 84 16 226 59
==============================================
Effective Interest Rate 5.2% 6.1% 4.9% 4.6%
----------------------------------------------
HIGHER NET INTEREST EXPENSE REDUCED NET INCOME BY $68 MILLION
Our financing costs increased $20 million from the third quarter of 2008. In
July 2009, we issued US$1 billion of long-term notes and additional interest in
the quarter related to this debt was $13 million. In addition, the stronger US
dollar increased our interest expense by $6 million. Interest expense on our
term credit facilities was slightly higher than the third quarter of 2008, as
additional borrowings were partially offset by lower interest rates on floating
rate debt.
Capitalized interest on our Long Lake Project was $51 million lower than the
previous year as construction of the facilities was completed earlier in the
year. We also ceased capitalizing interest on Ettrick during the quarter. These
decreases were partially offset by capitalizing additional interest on
construction of the fourth platform at Buzzard and on our major development at
Usan, offshore West Africa.
INCOME TAXES
Three Months Nine Months
Ended September 30 Ended September 30
2009 2008 2009 2008
------------------------------------------------------------------------------------------------------------------------------
Current 190 (26) 514 817
Future (81) 645 (397) 583
----------------------------------------------
Total Provision for Income Taxes 109 619 117 1,400
==============================================
LOWER TAXES INCREASED NET INCOME BY $510 MILLION
Our provision for income taxes decreased $510 million as compared to the third
quarter of 2008 due to lower commodity prices and production in 2009 and a
significant reversal of stock-based compensation expense in 2008. In the third
quarter of 2008, we completed an internal reorganization and financing of our
North Sea assets which provided us with an additional one-time current tax
reduction. Our income tax provision includes current taxes in the UK, Yemen,
Norway, Colombia and the US.
OTHER
Three Months Nine Months
Ended September 30 Ended September 30
2009 2008 2009 2008
------------------------------------------------------------------------------- ----------------------------------------------
Decrease in Fair Value of Crude Oil Put Options (23) 9 (218) (1)
----------------------------------------------
During the first quarter of 2008, we purchased put options on approximately
70,000 bbls/d of our 2009 crude oil production. These options establish a Dated
Brent floor price of US$60/bbl, are settled annually and provide a base level of
price protection without limiting our upside to higher prices. The put options
were purchased for $14 million and are carried at fair value. During the third
quarter of 2008, Lehman Brothers, one of the put option counterparties, filed
for bankruptcy protection impacting 25,000 bbls/d of our 2009 put options. The
carrying value of these put options has been reduced to nil. At September 30,
2009, the remaining options had a fair value of $12 million, $218 million lower
than the end of 2008.
45
LIQUIDITY AND CAPITAL RESOURCES
CAPITAL STRUCTURE
September 30 December 31
2009 2008
-----------------------------------------------------------------------------------------------------------------------------
NET DEBT (1)
Bank Debt 1,847 1,448
Public Senior Notes 5,064 4,582
--------------------------------------
Total Senior Debt 6,911 6,030
Subordinated Debt 518 548
--------------------------------------
Total Debt 7,429 6,578
Less: Cash and Cash Equivalents (1,897) (2,003)
--------------------------------------
TOTAL NET DEBT 5,532 4,575
======================================
SHAREHOLDERS' EQUITY 7,401 7,191
======================================
(1) Includes all of our borrowings and is calculated as long-term debt and
short-term borrowings less cash and cash equivalents.
During the quarter, we issued US$1 billion of senior notes with US$300 million
maturing in 10 years and US$700 million maturing in 30 years. The issuance of
the new debt increased the average term-to-maturity of our debt to 17 years.
Proceeds from the debt issue were used to repay a portion of our outstanding
term credit facilities as well as for general corporate purposes.
NET DEBT
Our net debt levels are directly related to our operating cash flows and our
capital expenditure activities. Changes in net debt are related to:
Three Months Nine Months
Ended Ended
September 30 September 30
2009 2009
-----------------------------------------------------------------------------------------------------------------------------
Capital Investment 655 2,119
Acquisition of Additional Working Interest at Long Lake - 755
Cash Flow from Operating Activities (1) (461) (1,359)
--------------------------------------
Deficiency 194 1,515
Dividends on Common Shares 26 78
Issue of Common Shares (12) (42)
Changes in Restricted Cash (93) 154
Foreign Exchange Translation of US-dollar Debt and Cash (470) (797)
Other (2) 49
--------------------------------------
Increase (Decrease) in Net Debt (357) 957
======================================
(1) Includes changes in non-cash working capital. For the three months ended
September 30, $113 million was included as a source of cash flow and for
the nine months ended September 30, $193 million was included as a source
of cash flow.
Our net debt decreased from June 30, 2009 primarily as a result of the Canadian
dollar strengthening relative to the US dollar. This impact was partially offset
as our quarterly capital investment exceeded our cash flow from operating
activities by $194 million. Our available liquidity at September 30, 2009 was
approximately US$3.3 billion, comprised of cash on hand and undrawn credit
facilities. Operating cash flows in the oil and gas industry can be volatile as
short-term commodity prices are driven by existing supply and demand
fundamentals and market volatility. We invest through the lows of the current
commodity market to create future growth and value for our shareholders for the
long-term. Changes in our non-cash working capital can vary between quarters as
our energy marketing net working capital position fluctuates depending on timing
of settlement of outstanding positions, the movement in commodity prices and
inventory cycles.
46
CHANGE IN WORKING CAPITAL
September 30 December 31 Increase/
2009 2008 (Decrease)
----------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents 1,897 2,003 (106)
Restricted Cash 216 103 113
Accounts Receivable 2,877 3,163 (286)
Inventories and Supplies 590 484 106
Accounts Payable and Accrued Liabilities (3,358) (3,326) (32)
Other 92 76 16
------------------------------------------------------
Net Working Capital 2,314 2,503
===================================
Accounts receivable in our energy marketing group decreased since year end as we
reduced our trading activity to focus on supporting our core physical business
as a producer/marketer. Commodity inventory increased since 2008 as our trading
inventory is carried at fair value and was higher than year end as a result of
stronger crude oil prices.
At September 30, 2009, our restricted cash consists of margin deposits of $216
million (December 31, 2008 - $103 million) related to exchange-traded derivative
financial contracts used by our energy marketing group to hedge physical
commodities, and storage, transportation and customer sales contracts. We are
required to maintain margin for net out-of-the-money derivative financial
contracts. The increase in margin primarily relates to derivative financial
contracts protecting our natural gas positions. Our physical positions gained in
value in a declining gas price environment while the derivative financial
contracts protecting these positions declined in value. Additional margin was
required to cover the increase in the net out-of-the-money derivative financial
contracts.
OUTLOOK FOR REMAINDER OF 2009
Following the completion of turnaround and maintenance activity in the third
quarter and the start up of new production, we are currently producing
approximately 275,000 boe/d. With production ramping up at Ettrick, Longhorn and
Long Lake, we expect fourth quarter production volumes will remain strong.
Our future liquidity and ability to fund capital requirements generally depends
upon operating cash flows, existing working capital, unused committed credit
facilities, and our ability to access debt and equity markets. Given the long
cycle time of some of our development projects and volatile commodity prices, it
is not unusual in any year for capital expenditures to exceed our cash flow.
Changes in commodity prices, particularly crude oil as it represents over 85% of
our current production, can impact our operating cash flows. We use short-term
contracts to sell the majority of our oil and gas production, exposing us to
short-term price movements. A US$1/bbl change in WTI above US$60/bbl is
projected to increase or decrease our cash flow from operating activities, after
cash taxes, by approximately $13 million for the remainder of 2009. Our exposure
to a $0.01 change in the US to Canadian dollar exchange rate is projected to
increase or decrease our cash flow by approximately $9 million for the remainder
of 2009. While commodity prices can fluctuate significantly in the short term,
we believe that over the longer term, commodity prices will continue to
strengthen as a result of growth in world demand and delays or shortages in
supply growth. We believe that our existing liquidity, balance sheet capacity
and capital investment flexibility provides us with the ability to fund our
obligations during periods of lower commodity prices.
We have incurred approximately 80% of our 2009 planned capital expenditures to
date and also acquired an additional 15% working interest in Long Lake. During
the quarter, our capital was concentrated on developing our Usan project
offshore Nigeria, appraising the Golden Eagle/Hobby area, advancing work on the
fourth platform at Buzzard, bringing our Ettrick and Longhorn developments on
stream, and on progressing our Horn River shale gas play in northeastern British
Columbia.
During the first nine months of 2009, lower commodity prices reduced our cash
flow from operating activities relative to the same period last year. Over the
same period, we have invested approximately $2.1 billion in capital projects and
another $755 million to acquire an additional 15% in the Long Lake Project. As
our capital expenditures exceeded our cash flow from operating activities, we
drew upon our available liquidity and issued US$1 billion of long-term debt. We
currently have approximately $1.9 billion of cash and cash equivalents on hand
and as well as significant undrawn committed credit facilities available. At
September 30, 2009, we had unsecured term credit facilities of US$3.1 billion in
place that are available until 2012, of which US$1.5 billion was drawn and
US$398 million was used to support outstanding letters of credit. We also have
approximately $493 million of undrawn, uncommitted, unsecured credit facilities,
of which $119 million was used to support outstanding letters of credit. The
average length-to-maturity of our public debt is approximately 17 years.
In the third quarter, our board of directors declared a quarterly common share
dividend of $0.05 per share.
47
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 2008 Form 10-K. There have been
no significant developments since year-end.
CONTINGENCIES
There are a number of lawsuits and claims pending, the ultimate result 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 2008 Form 10-K. There have been no significant developments
since year-end.
NEW ACCOUNTING PRONOUNCEMENTS
CANADIAN PRONOUNCEMENTS
All Canadian publicly accountable enterprises will be required to adopt
International Financial Reporting Standards (IFRS) for interim and annual
reporting purposes for fiscal years beginning on or after January 1, 2011. We
have set up a project team to manage this transition and to ensure successful
implementation within the required timeframe.
We are currently assessing the impact of adopting IFRS on our results of
operations, financial position, disclosures and financial systems. We have
completed our diagnostic phase and are in the midst of the implementation phase.
To date, we determined that the majority of our existing oil and gas accounting
policies are acceptable under current IFRS standards. IFRS does not prescribe
specific accounting guidance for extractive industries such as oil and gas,
other than for costs associated with the exploration and evaluation phase. Our
detailed analysis has identified differences that will impact certain aspects of
our accounting for property, plant and equipment, asset retirement obligations,
and long-term asset impairments. We expect to complete the implementation phase
early in 2010. We are also currently evaluating the impact of exemptions and
exceptions available to first-time IFRS adopters which give relief from
retrospective application of IFRS. We continue to monitor changes to IFRS
standards prior to adoption in 2011. Training sessions have been ongoing
throughout the company and will continue into 2010.
At this time, we cannot quantify the impact that the adoption of IFRS will have
on our future results of operations or future financial position. Additional
disclosure of the key elements of our plan and progress on the project will be
provided as we move towards the changeover date.
US PRONOUNCEMENTS
In December 2008, the Financial Accounting Standards Board (FASB) issued
EMPLOYERS DISCLOSURES ABOUT POSTRETIREMENT BENEFIT PLAN ASSETS. This position
provides guidance on disclosures about plan assets of a defined benefit pension
plan or other postretirement plans. This position is effective for fiscal years
ending after December 15, 2009. We do not expect the adoption of this statement
to materially impact our results of operations or financial position.
In June 2009, FASB issued AMENDMENTS TO CONSOLIDATION OF VARIABLE INTEREST
ENTITIES. It retains the scope of the previous guidance with the addition of
entities previously considered qualifying special-purpose entities and
eliminates the previous quantitative approach for a qualitative analysis in
determining whether the enterprise's variable interest or interests give it a
controlling financial interest in a variable interest entity. The Statement is
further amended to require ongoing reassessments of whether an enterprise is the
primary beneficiary of a variable interest entity and requires enhanced
disclosures about an enterprise's involvement in a variable interest entity. The
Statement is effective at the beginning the first annual reporting period after
November 15, 2009. We do not expect the adoption of this statement to have a
material impact on our results of operations or financial position.
EQUITY SECURITY REPURCHASES
During the quarter, we made no purchases of our own equity securities.
48
SUMMARY OF QUARTERLY RESULTS
2007 | 2008 | 2009
----------------------------------------------------------|----------------------------------------|-----------------------------
(Cdn$ millions, except per share amounts) Dec | Mar Jun Sep Dec | Mar Jun Sep
----------------------------------------------------------|----------------------------------------|-----------------------------
Net Sales 1,598 1,870 2,071 2,213 1,270 1,048 1,200 1,097
Net Income (Loss) 194 630 380 886 (181) 135 20 122
Earnings (Loss) Per Common Share ($/share)
Basic 0.37 1.19 0.72 1.68 (0.35) 0.26 0.04 0.23
Diluted 0.36 1.17 0.70 1.66 (0.35) 0.26 0.04 0.23
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SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS
Certain statements in this report, including those appearing in MANAGEMENT'S
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS,
constitute "forward-looking statements" (within the meaning of the United States
PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995, as amended) or
"forward-looking information" (within the meaning of applicable Canadian
securities legislation). Such statements or information (together
"forward-looking statements") are generally identifiable by the forward-looking
terminology used such as "ANTICIPATE", "BELIEVE", "INTEND", "PLAN", "EXPECT",
"ESTIMATE", "BUDGET", "OUTLOOK", "FORECAST" or other similar words, and include
statements relating to or associated with individual wells, regions or projects.
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 Yemen operations;
o future capital expenditures and their allocation to exploration and
development activities;
o future earnings;
o future asset acquisitions or dispositions;
o future sources of funding for our capital program;
o future debt levels;
o availability of committed credit facilities;
o possible commerciality;
o development plans or capacity expansions;
o future ability to execute dispositions of assets or businesses;
o future sources of liquidity, cash flows and their uses;
o future drilling of new wells;
o ultimate recoverability of current and long-term assets;
o ultimate recoverability of reserves or resources;
o expected finding and development costs;
o expected operations costs;
o future demand for chemical products;
o estimates on a per share basis;
o future foreign currency exchange rates;
o future expenditures and future allowances relating to environmental
matters;
o dates by which certain areas will be developed, will come on-stream or
reach expected operating capacity; and
o changes in any of the foregoing.
Statements relating to "reserves" or "resources" are forward-looking statements,
as they involve the implied assessment, based on estimates and assumptions, that
the reserves and resources described exist in the quantities predicted or
estimated, and can be profitably produced in the future.
The forward-looking 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. Such factors include, among others:
o market prices for oil and gas and chemical products;
o our ability to explore, develop, produce and transport crude oil and
natural gas to markets;
49
o ultimate effectiveness of design modification to facilities;
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 including changes to taxes or royalties, changes in
environmental and other laws and regulations;
o renegotiations of contracts;
o results of litigation, arbitration or regulatory proceedings;
o political uncertainty, including actions by terrorists, insurgent or other
groups, or other armed conflict, including conflict between states; and
o other factors, many of which are beyond our control.
These risks, uncertainties and other factors 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 and in Item 7A of our
2008 Form 10-K. The impact of any one risk, uncertainty or factor on a
particular forward-looking statement is not determinable with certainty as these
factors are interdependent, and management's future course of action would
depend on an assessment of all information at that time.
Although we believe that the expectations conveyed by the forward-looking
statements are reasonable based on information available to us on the date such
forward-looking statements were made, no assurances can be given as to future
results, levels of activity and achievements. Undue reliance should not be
placed on the statements contained herein, which are made as of the date hereof
and, except as required by law, we undertake no obligation to update publicly or
revise any forward-looking statements, whether as a result of new information,
future events or otherwise. The forward-looking statements contained herein are
expressly qualified by this cautionary statement.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We are exposed to normal market risks inherent in the oil and gas, energy
marketing and chemicals business, including commodity price risk,
foreign-currency exchange rate risk, interest rate risk and credit risk. We
recognize these risks and manage our operations to minimize our exposures to the
extent practical. These are addressed in the unaudited consolidated financial
statements.
Most of our credit exposures are with counterparties in the energy industry,
including integrated oil companies, crude oil refiners and utilities and are
subject to normal industry credit risk.
At September 30, 2009:
o over 93% of our credit exposures were investment grade;
o approximately 74% of our credit exposures were with integrated oil
companies, crude oil refiners and marketers, and large utilities; and
o only one counterparty individually made up more than 10% of our credit
exposure. This counterparty is a major integrated oil company with a strong
investment grade credit rating.
Further information presented on market risks can be found in Item 7A on pages
75 - 78 in our 2008 Form 10-K and have not materially changed since December 31,
2008.
ITEM 4. CONTROLS AND PROCEDURES
EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES
The Company's Chief Executive Officer and Chief Financial Officer have designed
disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e)
under the SECURITIES EXCHANGE ACT OF 1934), or caused such disclosure controls
and procedures to be designed under their supervision, to ensure that material
information relating to the Company is made known to them, particularly during
the period in which this report is prepared. They have evaluated the
effectiveness of such disclosure controls and procedures as of the end of the
period covered by this report ("Evaluation Date"). Based upon that evaluation,
the Chief Executive Officer and Chief Financial Officer concluded that, as of
the Evaluation Date, the Company's disclosure controls and procedures are
effective (i) to ensure that information required to be disclosed by us in
reports that the Company files or submits under the Exchange Act is recorded,
processed, summarized and reported within the time periods specified in the
Securities and Exchange Commission rules and forms; and (ii) to ensure that
information required to be disclosed in the reports that the Company files or
submits under the Exchange Act is accumulated and communicated to our
management, including the Company's Chief Executive Officer and Chief Financial
Officer, to allow timely decisions regarding required disclosures.
50
The Company's management, including its Chief Executive Officer and Chief
Financial Officer, does not expect that the Company's disclosure controls and
procedures or internal controls will prevent all possible error and fraud. The
Company's disclosure controls and procedures are, however, designed to provide
reasonable assurance of achieving their objectives, and the Company's Chief
Executive Officer and Chief Financial Officer have concluded that the Company's
financial controls and procedures are effective at that reasonable assurance
level.
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 first nine months of 2009 that has
materially affected, or is reasonably likely to materially affect, the Company's
internal control over financial reporting.
51
PART II
Item 1. Legal Proceedings
Information in response to this item is included in Part I, Item 1 in Note 16
"Commitments, Contingencies and Guarantees" and is incorporated by reference
into Part II of this Quarterly Report on Form 10-Q.
Item 6. Exhibits
4.58 Second Supplemental Indenture dated July 30, 2009 between the
Registrant and Deutsche Bank Trust Company Americas pertaining to
the issuance of US$300 million, 6.20% senior notes due 2019 and the
issuance of US$700 million, 7.50% senior notes due 2039
(incorporated by reference to Exhibit 4.2 to Form 8-K dated July 30,
2009).
10.58 Pricing Agreement dated July 27, 2009 among the Registrant and Banc
of America Securities LLC, BNP Paribas Securities Corp., Deutsche
Bank Securities Inc., and HSBC Securities (USA) Inc. as Underwriters
(incorporated by reference to Exhibit 10.1 to Form 8-K dated July
30, 2009).
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.
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 November 3, 2009.
NEXEN INC.
/s/ Marvin F. Romanow
---------------------
Marvin F. Romanow
President and Chief Executive Officer
(Principal Executive Officer)
/s/ Brendon T. Muller
---------------------
Brendon T. Muller
Controller
(Principal Accounting Officer)
52
