Attached files
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
|X| QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE
ACT OF 1934 For the quarterly period ended March 31, 2010
|_| 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 March 31, 2010, there were 524,046,867 common shares issued and outstanding.
NEXEN INC.
INDEX
PART I FINANCIAL INFORMATION PAGE
Item 1. Unaudited Consolidated Financial Statements ..... ................3
Item 2. Management's Discussion and Analysis of Financial
Conditionand Results of Operations (MD&A) .......................29
Item 3. Quantitative and Qualitative Disclosures about Market Risk ......50
Item 4. Controls and Procedures .........................................51
PART II OTHER INFORMATION
Item 1. Legal Proceedings ...............................................52
Item 6. Exhibits ........................................................52
This report should be read in conjunction with our 2009 Annual Report on Form
10-K (2009 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
97 of our 2009 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.
Below is a list of terms specific to the oil and gas industry. They are used
throughout this 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
PSCTM = Premium Synthetic CrudeTM 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 March 31, 2010, the noon-day exchange rate was US$0.9846 for Cdn$1.00, as
reported by the Bank of Canada.
2
PART I
ITEM 1. UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
TABLE OF CONTENTS
Page
Unaudited Consolidated Statement of Income
for the Three Months Ended March 31, 2010 and 2009............................4
Unaudited Consolidated Balance Sheet
as at March 31, 2010 and December 31, 2009....................................5
Unaudited Consolidated Statement of Cash Flows
for the Three Months Ended March 31, 2010 and 2009............................6
Unaudited Consolidated Statement of Equity
for the Three Months Ended March 31, 2010 and 2009............................7
Unaudited Consolidated Statement of Comprehensive Income
for the Three Months Ended March 31, 2010 and 2009............................8
Notes to Unaudited Consolidated Financial Statements..........................9
3
NEXEN INC.
UNAUDITED CONSOLIDATED STATEMENT OF INCOME
FOR THE THREE MONTHS ENDED MARCH 31
(Cdn$ millions, except per share amounts) 2010 2009
---------------------------------------------------- ------------- -----------
REVENUES AND OTHER INCOME
Net Sales 1,501 1,048
Marketing and Other (Note 14) 151 257
------------- -----------
1,652 1,305
------------- -----------
EXPENSES
Operating 422 305
Depreciation, Depletion,
Amortization and Impairment 388 409
Transportation and Other 202 201
General and Administrative 118 100
Exploration 93 53
Interest (Note 9) 80 68
------------- -----------
1,303 1,136
------------- -----------
INCOME BEFORE PROVISION FOR INCOME TAXES 349 169
------------- -----------
PROVISION FOR (RECOVERY OF) INCOME TAXES
Current 259 118
Future (100) (87)
------------- -----------
159 31
------------- -----------
NET INCOME 190 138
Less: Net Income Attributable
to Canexus Non-Controlling Interests 5 3
------------- -------------
NET INCOME ATTRIBUTABLE TO NEXEN INC. 185 135
============= =============
EARNINGS PER COMMON SHARE ($/share) (Note 15)
Basic 0.35 0.26
============= =============
Diluted 0.35 0.26
============= =============
SEE ACCOMPANYING NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS.
4
NEXEN INC.
UNAUDITED CONSOLIDATED BALANCE SHEET
March 31 December 31
(Cdn$ millions, except share amounts) 2010 2009
------------------------------------------------- ------------- ----------------
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents 1,997 1,700
Restricted Cash 178 198
Accounts Receivable (Note 2) 2,635 2,788
Inventories and Supplies (Note 3) 574 680
Other 102 185
------------- ----------------
Total Current Assets 5,486 5,551
------------- ----------------
PROPERTY, PLANT AND EQUIPMENT
Net of Accumulated Depreciation,
Depletion, Amortization and Impairment
of $10,931 (December 31, 2009 - $10,807) 15,381 15,492
GOODWILL 330 339
FUTURE INCOME TAX ASSETS 1,238 1,148
DEFERRED CHARGES AND OTHER ASSETS (Note 5) 328 370
------------- ----------------
TOTAL ASSETS 22,763 22,900
============= ================
LIABILITIES
CURRENT LIABILITIES
Accounts Payable and Accrued
Liabilities (Note 8) 3,084 3,038
Accrued Interest Payable 77 89
Dividends Payable 26 26
------------- ----------------
Total Current Liabilities 3,187 3,153
------------- ----------------
LONG-TERM DEBT (Note 9) 7,054 7,251
FUTURE INCOME TAX LIABILITIES 2,804 2,811
ASSET RETIREMENT OBLIGATIONS (Note 11) 932 1,018
DEFERRED CREDITS AND OTHER LIABILITIES
(Note 12) 959 1,021
EQUITY
Nexen Inc. Shareholders' Equity
Common Shares, no par value
Authorized: Unlimited
Outstanding: 2010 - 524,046,867 shares
2009 - 522,915,843 shares 1,076 1,049
Contributed Surplus - 1
Retained Earnings 6,881 6,722
Accumulated Other Comprehensive Loss (201) (190)
------------- ----------------
Total Nexen Inc. Shareholders' Equity 7,756 7,582
Canexus Non-Controlling Interests 71 64
------------- ----------------
TOTAL EQUITY 7,827 7,646
COMMITMENTS, CONTINGENCIES AND
GUARANTEES (Note 16)
------------- ----------------
TOTAL LIABILITIES AND EQUITY 22,763 22,900
============= ================
SEE ACCOMPANYING NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS.
5
NEXEN INC.
UNAUDITED CONSOLIDATED STATEMENT OF CASH FLOWS
FOR THE THREE MONTHS ENDED MARCH 31
(Cdn$ millions) 2010 2009
-------------------------------------------------- ------------- ---------------
OPERATING ACTIVITIES
Net Income 190 138
Charges and Credits to Income not
Involving Cash (Note 17) 265 319
Exploration Expense 93 53
Changes in Non-Cash Working Capital (Note 17) 256 420
Other (6) (141)
------------- ---------------
798 789
FINANCING ACTIVITIES
Proceeds from (Repayment of) Term Credit
Facilities, Net - 1,011
Proceeds from (Repayment of) Canexus Term
Credit Facilities, Net 22 10
Dividends Paid on Common Shares (26) (26)
Distributions Paid to Canexus
Non-Controlling Interests (4) (4)
Issue of Common Shares and Exercise of
Tandem Options for Shares 25 23
------------- ---------------
17 1,014
INVESTING ACTIVITIES
Capital Expenditures
Exploration and Development (492) (702)
Proved Property Acquisitions - (757)
Energy Marketing, Chemicals, Corporate
and Other (64) (45)
Proceeds on Disposition of Assets 15 14
Changes in Non-Cash Working Capital (Note 17) 88 19
Changes in Restricted Cash 15 (314)
Other (3) (2)
------------- ---------------
(441) (1,787)
EFFECT OF EXCHANGE RATE CHANGES ON CASH AND
CASH EQUIVALENTS (77) 35
------------- ---------------
INCREASE IN CASH AND CASH EQUIVALENTS 297 51
CASH AND CASH EQUIVALENTS - BEGINNING OF PERIOD 1,700 2,003
------------- ---------------
CASH AND CASH EQUIVALENTS - END OF PERIOD (1) 1,997 2,054
============= ===============
(1) Cash and cash equivalents at March 31, 2010 consist of cash of $257 million
and short-term investments of $1,740 million (March 31, 2009 - cash of $182
million and short-term investments of $1,872 million).
SEE ACCOMPANYING NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS.
6
NEXEN INC.
UNAUDITED CONSOLIDATED STATEMENT OF EQUITY
FOR THE THREE MONTHS ENDED MARCH 31
(Cdn$ millions) 2010 2009
------------------------------------------------- ------------- ----------------
COMMON SHARES, Beginning of Period 1,049 981
Issue of Common Shares 24 23
Exercise of Tandem Options for Shares 1 -
Accrued Liability Relating to Tandem
Options Exercised for Common Shares 2 -
------------- ----------------
Balance at End of Period 1,076 1,004
============= ================
CONTRIBUTED SURPLUS, Beginning of Period 1 2
Exercise of Tandem Options (1) -
------------- ----------------
Balance at End of Period - 2
============= ================
RETAINED EARNINGS, Beginning of Period 6,722 6,290
Net Income Attributable to Nexen Inc. 185 135
Dividends Paid on Common Shares (Note 13) (26) (26)
------------- ----------------
Balance at End of Period 6,881 6,399
============= ================
ACCUMULATED OTHER COMPREHENSIVE LOSS,
Beginning of Period (190) (134)
Other Comprehensive Income (Loss)
Attributable to Nexen Inc. (11) 6
------------- ----------------
Balance at End of Period (1) (201) (128)
============= ================
(1) Comprised of unrealized foreign currency translation adjustment.
CANEXUS NON-CONTROLLING INTERESTS, Beginning
of Period 64 52
Net Income Attributable to
Non-Controlling Interests 6 3
Distributions Paid to Non-Controlling Interests (4) (4)
Issue of Partnership Units to
Non-Controlling Interests 5 1
------------- ----------------
Balance at End of Period 71 52
============= ================
SEE ACCOMPANYING NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS.
7
NEXEN INC.
UNAUDITED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
FOR THE THREE MONTHS ENDED MARCH 31
(Cdn$ millions) 2010 2009
------------------------------------------------------- ---------- -------------
NET INCOME ATTRIBUTABLE TO NEXEN INC. 185 135
Other Comprehensive Income (Loss), Net of
Income Taxes:
Foreign Currency Translation Adjustment
Net Gains (Losses) on Investment in
Self-Sustaining Foreign Operations (147) 174
Net Gains (Losses) on Foreign-Denominated
Debt Hedges of Self-Sustaining
Foreign Operations (1) 136 (168)
---------- -------------
Other Comprehensive Income (Loss)
Attributable to Nexen Inc. (11) 6
---------- -------------
COMPREHENSIVE INCOME ATTRIBUTABLE TO NEXEN INC. 174 141
========== =============
(1) Net of income tax expense for the three months ended March 31, 2010 of $20
million (2009 - $24 million recovery).
SEE ACCOMPANYING NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS.
8
NEXEN INC.
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
Cdn$ 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 20. In the opinion of
management, the Unaudited Consolidated Financial Statements contain all
adjustments of a normal and recurring nature necessary to present fairly Nexen
Inc.'s (Nexen, we or our) financial position at March 31, 2010 and December 31,
2009 and the results of our operations and our cash flows for the three months
ended March 31, 2010 and 2009.
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 months ended March 31, 2010 are not
necessarily indicative of the results of operations or cash flows to be expected
for the year ending December 31, 2010. As at April 26, 2010, 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 2009 Form
10-K. The accounting policies we follow are described in Note 1 of the Audited
Consolidated Financial Statements included in our 2009 Form 10-K.
CHANGES IN ACCOUNTING POLICIES
Oil and Gas Reserve Estimates
On January 6, 2010, the Financial Accounting Standards Board issued guidance for
OIL AND GAS RESERVE ESTIMATION AND DISCLOSURE, which is effective for years
ended December 31, 2009. The guidance expands the definition of oil and gas
producing activities to: i) include unconventional sources such as oil sands;
ii) change the price used in reserve estimation from the year-end price to the
simple average of the first-day-of-the-month price for the previous 12 months,
and iii) require disclosures for geographic areas that represent 15% or more of
proved reserves.
We follow the successful efforts method of accounting for our oil and gas
activities, which use the estimated proved reserves we believe are recoverable
from our oil and gas properties. Specifically, reserves estimates are used to
calculate our unit-of-production depletion rates and to assess, when necessary,
our oil and gas assets for impairment. Adoption of these amendments changed our
estimate of reserves used to calculate depletion in 2010. As a result of the
amendments, depletion expense for the three months ended March 31, 2010
increased by $14 million, net income decreased by $9 million, and earnings per
common share decreased by $0.02/share.
2. ACCOUNTS RECEIVABLE
March 31 December 31
2010 2009
--------------------------------------------------- -------------- -------------
Trade
Energy Marketing 1,385 1,410
Energy Marketing Derivative Contracts (Note 6) 267 466
Oil and Gas 867 823
Chemicals and Other 46 44
-------------- -------------
2,565 2,743
Non-Trade 123 99
-------------- -------------
2,688 2,842
Allowance for Doubtful Receivables (53) (54)
-------------- -------------
Total 2,635 2,788
============== =============
9
3. INVENTORIES AND SUPPLIES
March 31 December 31
2010 2009
-------------------------------------------------- ----------- -----------
Finished Products
Energy Marketing 442 548
Oil and Gas 25 25
Chemicals and Other 12 12
----------- -----------
479 585
Work in Process 10 7
Field Supplies 85 88
----------- -----------
Total 574 680
=========== ===========
4. SUSPENDED EXPLORATION WELL COSTS
The following table shows the changes in capitalized exploratory well costs
during the three months ended March 31, 2010 and the year ended December 31,
2009, 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.
Three Months Ended Year Ended
March 31 December 31
2010 2009
------------------------------------------------ --------------- -------------
Beginning of Period 794 518
Exploratory Well Costs Capitalized Pending
the Determination of Proved Reserves 146 396
Capitalized Exploratory Well Costs Charged
to Expense (2) (56)
Transfers to Wells, Facilities and Equipment
Based on Determination of Proved Reserves - (21)
Effects of Foreign Exchange Rate Changes (14) (43)
--------------- -------------
End of Period 924 794
=============== =============
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.
March 31 December 31
2010 2009
----------------------------------------------------- ------------- ------------
Capitalized for a Period of One Year or Less 425 383
Capitalized for a Period of Greater than One Year 499 411
------------- ------------
Total 924 794
============= ============
Number of Projects that have Exploratory Well Costs
Capitalized for a Period Greater than One Year 13 12
------------- ------------
10
As at March 31, 2010, we have exploratory costs that have been capitalized for
more than one year relating to our interests in eight exploratory blocks in the
North Sea ($174 million), certain coalbed methane and shale gas exploratory
activities in Canada ($194 million), two exploratory blocks in the Gulf of
Mexico ($113 million), and our interest in an exploratory block offshore Nigeria
($18 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 otherwise assess
commercial viability.
Aging of Suspended
Exploration Wells Greater United United
than One Year Kingdom Canada States Nigeria Total
------------------------- ---------- ---------- ---------- ---------- ----------
1-3 years 119 194 42 - 355
4-5 years 55 - 71 - 126
Greater than 5 years - - - 18 18
---------- ---------- ---------- ---------- ----------
Total 174 194 113 18 499
========== ========== ========== =========+ ==========
5. DEFERRED CHARGES AND OTHER ASSETS
March 31 December 31
2010 2009
-------------------------------------------------- --------------- -------------
Long-Term Energy Marketing Derivative
Contracts (Note 6) 200 225
Crude Oil Put Options and Natural Gas
Swaps (Note 6) - 4
Defined Benefit Pension Assets 56 60
Long-Term Capital Prepayments 23 27
Other 49 54
--------------- -------------
Total 328 370
=============== =============
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 because 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 March 31, 2010. 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. Related amounts posted as
margin for exchange traded positions are recorded in restricted cash.
We carry our long-term debt at amortized cost using the effective interest rate
method. At March 31, 2010, the estimated fair value of our long-term debt was
$7,337 million (December 31, 2009 - $7,594 million) as compared to the carrying
value of $7,054 million (December 31, 2009 - $7,251 million). The fair value of
long-term debt is estimated based on prices provided by quoted markets and
third-party brokers.
11
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:
March 31 December 31
2010 2009
------------------------------------------------------- ----------- ------------
Commodity Contracts 267 463
Foreign Exchange Contracts - 3
----------- ------------
Accounts Receivable (Note 2) 267 466
----------- ------------
Commodity Contracts 200 225
----------- ------------
Deferred Charges and Other Assets (Note 5)(1) 200 225
----------- ------------
Total Trading Derivative Assets 467 691
=========== ============
Commodity Contracts 212 410
Foreign Exchange Contracts 13 46
----------- ------------
Accounts Payable and Accrued Liabilities (Note 8) 225 456
----------- ------------
Commodity Contracts 198 212
Foreign Exchange Contracts 1 -
----------- ------------
Deferred Credits and Other Liabilities (Note 12) 199 212
----------- ------------
Total Trading Derivative Liabilities 424 668
=========== ============
Total Net Trading Derivative Contracts 43 23
=========== ============
(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:
March 31 December 31
2010 2009
--------------------------------------------- ---------------- ----------------
Current Trading Assets 2,116 2,625
Non-Current Trading Assets 613 716
---------------- ----------------
Total Trading Derivative Assets 2,729 3,341
================ ================
Current Trading Liabilities 2,074 2,615
Non-Current Trading Liabilities 612 703
---------------- ----------------
Total Trading Derivative Liabilities 2,686 3,318
================ ================
---------------- ----------------
Total Net Trading Derivative Contracts 43 23
================ ================
12
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 months ended March 31, 2010 and 2009, the following
trading revenues were recognized in marketing and other income:
Three Months Ended March 31
2010 2009
----------------------------------------------- ---------------- ---------------
Commodity 91 270
Foreign Exchange (5) (3)
---------------- ---------------
Marketing Revenue 86 267
================ ===============
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 economic hedging and
trading purposes. The absolute notional volumes associated with our derivative
instrument transactions for the three months ended March 31, 2010 and 2009, are
as follows:
Three Months Ended March 31
2010 2009
------------------------------------------------- --------------- --------------
Natural Gas bcf/d 15.2 28.6
Crude Oil mmbbls/d 3.3 3.8
Power GWh/d 280.8 212.3
Foreign Exchange US$ millions 787 378
Foreign Exchange Euro millions 53 153
--------------- --------------
(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:
March 31 December 31
2010 2009
----------------------------------------------------- ------------- -----------
Accounts Receivable 1 13
Deferred Charges and Other Assets (Note 5) (1) - 4
------------- -----------
Total Non-Trading Derivative Assets 1 17
============= ===========
Accounts Payable and Accrued Liabilities (Note 8) 20 26
------------- -----------
Total Non-Trading Derivative Liabilities 20 26
============= ===========
Total Net Non-Trading Derivative Assets (2) (19) (9)
============= ===========
(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 2009, we purchased put options on 90,000 bbls/d of our 2010 crude oil
production for $39 million. These options establish a WTI floor price of
US$50/bbl on these volumes and provide a base level of price protection without
limiting our upside to higher prices. Options on 60,000 bbls/d settle monthly,
while the remaining options settle annually. These options are recorded at fair
value throughout their term. As a result, changes in forward crude oil prices
create gains or losses on these options at each period end. At March 31, 2010,
higher crude oil prices reduced the fair value of the options to approximately
$1 million, and we recorded a fair value loss during the period of $16 million
in marketing and other income.
Three Months Ended March 31, 2010
--------------------------------
Notional Average Fair Change in
Volumes Term Floor Price Value Fair Value
------------------------------------- -------------- ---------- --------------- -------------- -----------------
(bbls/d) (US$/bbl)
WTI Crude Oil Put Options (monthly) 60,000 2010 50 1 (12)
WTI Crude Oil Put Options (annual) 30,000 2010 50 - (4)
-------------- -----------------
1 (16)
============== =================
13
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 current based on their anticipated
settlement date. Any change in fair value is included in marketing and other
income.
Three Months Ended March 31, 2010
----------------------------------
Notional Average Fair Change in
Volumes Term Price Value Fair Value
------------------------------------ -------------- ---------- --------------- ---------------- -----------------
(Gj/d) ($/Gj)
Fixed-Price Natural Gas Contracts 15,514 2010 2.28 (4) (7)
Natural Gas Swaps 15,514 2010 7.60 (16) 7
---------------- -----------------
(20) -
================ =================
(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, 2009. The following
table includes our derivatives carried at fair value for our trading and
non-trading activities as at March 31, 2010. 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 at March 31, 2010 Level 1 Level 2 Level 3 Total
-------------------------------------- --------- --------- --------- ----------
Commodity Contracts (156) 175 38 57
Foreign Exchange Contracts - (14) - (14)
--------- --------- --------- ----------
Trading Derivatives (156) 161 38 43
Non-Trading Derivatives - (19) - (19)
--------- --------- --------- ----------
Total (156) 142 38 24
========= ========= ========= ==========
A reconciliation of changes in the fair value of our derivatives classified as
Level 3 for the three months ended March 31, 2010 is provided below:
Level 3
---------------------------------------------------------------- ---------------
Beginning of Period 42
Realized and Unrealized Gains (Losses) 7
Purchases -
Settlements (11)
Transfers Into Level 3 -
Transfers Out of Level 3 -
---------------
End of Period 38
===============
Unsettled gains relating to instruments still
held as of March 31, 2010 7
===============
Items 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. Fair values of instruments in Level 3
are determined using broker quotes, pricing services and internally-developed
inputs. We performed a sensitivity analysis of inputs used to calculate the fair
value of Level 3 instruments. Using reasonably possible alternative assumptions,
the fair value of Level 3 instruments would change by $13 million (December 31,
2009 - $12 million).
14
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 currency rates and interest rates, which could 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, given that the majority of our debt is fixed
rate.
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, many of which are
beyond our control, 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. 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 we enter into
also expose us to commodity price risk between the time we purchase and sell
contracted volumes. We actively manage these risks by using derivative contracts
such as commodity put options.
Our energy marketing business is focused on providing services to our customers
and suppliers to meet their energy commodity needs. We market and trade physical
energy commodities in selected regions of the world, including crude oil,
natural gas, electricity and other commodities. We do 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 come from
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.
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, 2009. Our period end, high, low and average VaR
amounts for the three months ended March 31, 2010 and the year ended December
31, 2009, are as follows:
Three Months Ended Year Ended
March 31 December 31
Value-at-Risk 2010 2009
--------------------------------------- -------------------- ------------------
Period End 13 11
High 15 24
Low 9 9
Average 12 15
-------------------- ------------------
If a market shock occurred as 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 abnormal changes in prices on our positions.
15
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 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. Cash inflows generated by our foreign
operations and borrowings on our US-dollar debt facilities 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 net cash flows.
We designate most of our US-dollar borrowings as a hedge against our US-dollar
net investment in self-sustaining foreign operations. 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 March 31, 2010 and December 31, 2009 are as follows:
March 31 December 31
(US$ millions) 2010 2009
---------------------------------------------------- ------------- -------------
Net Investment in Self-Sustaining Foreign Operations 4,523 4,492
Designated US-Dollar Debt 4,523 4,492
------------- -------------
For the three month period ended March 31, 2010, the ineffective portion of our
US-dollar debt resulted in a net foreign exchange gain of $21 million ($19
million, 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 $45 million, net of income tax, and would increase or decrease our
net income by approximately $6 million, net of income tax.
We also have 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 our trading and
non-trading derivative activities, and 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,
refiners and utilities, and are subject to normal industry credit risk.
Approximately 70% 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, 2009.
At March 31, 2010, only two counterparties individually made up more than 10% of
our credit exposure. These counterparties are major integrated oil companies
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.
March 31 December 31
CREDIT RATING 2010 2009
------------------------------------------------- --------------- -------------
A or higher 67% 67%
BBB 25% 26%
Non-Investment Grade 8% 7%
--------------- -------------
TOTAL 100% 100%
=============== =============
16
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 $53
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 March 31, 2010 includes $1 million of cash
and $319 million of letters of credit. The cash received is 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 fall due. We require liquidity specifically to fund capital
requirements, satisfy financial obligations as they come 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 March 31, 2010, we had approximately $3.6 billion of cash and available
committed lines of credit. This includes $2 billion of cash and cash equivalents
on hand and undrawn term credit facilities of $1.6 billion, of which $391
million was supporting letters of credit at March 31, 2010. These facilities are
available until 2012 unless extended. We also have about $466 million of
undrawn, uncommitted credit facilities, of which $116 million was supporting
letters of credit at March 31, 2010.
The following table details the contractual maturities for our non-derivative
financial liabilities, including both the principal and interest cash flows at
March 31, 2010:
Less than More than
Total 1 Year 1-3 Years 4-5 Years 5 Years
------------------------------ ---------- -------- ---------- --------- --------
Long-Term Debt 7,144 - 1,771 854 4,519
Interest on Long-Term Debt (1) 7,724 350 700 658 6,016
---------- -------- ---------- --------- --------
Total 14,868 350 2,471 1,512 10,535
========== ======== ========== ========= ========
(1) Excludes interest on term credit facilities of $1.5 billion (US$1.5
billion) and Canexus term credit facilities of $247 million (US$244
million) as the amounts drawn on the facilities fluctuate. Based on amounts
drawn at March 31, 2010 and existing variable interest rates, we would be
required to pay $18 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) 424 225 173 26 -
Non-Trading Derivatives (Note 6) 20 20 - - -
----- --------- ---------- --------- ----------
Total 444 245 173 26 -
===== ========= ========== ========= ==========
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
ratings to non-investment grade. Based on contracts in place and commodity
prices at March 31, 2010, we could be required to post collateral of up to
$1,016 million if we were downgraded to non-investment grade. These obligations
are reflected on our balance sheet. The posting of collateral secures the
payment of such amounts. In the event of a ratings downgrade, we have trading
inventories and receivables that can be quickly monetized as well as undrawn
credit facilities.
At March 31, 2010, collateral posted with counterparties includes $5 million of
cash and $299 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 $178 million (December 31, 2009 - $198
million), which have been included in restricted cash.
17
8. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES
March 31 December 31
2010 2009
-------------------------------------------------- ------------- ---------------
Energy Marketing Payables 1,422 1,366
Energy Marketing Derivative Contracts (Note 6) 225 456
Accrued Payables 615 619
Trade Payables 245 210
Income Taxes Payable 233 179
Stock-Based Compensation 68 72
Other 276 136
------------- ---------------
Total 3,084 3,038
============= ===============
9. SHORT-TERM BORROWINGS AND LONG-TERM DEBT
March 31 December 31
2010 2009
----------------------------------------------------- ------------- ------------
Canexus Term Credit Facilities, due 2012
(US$244 million drawn) (a) 247 233
Term Credit Facilities, due 2012
(US$1.5 billion drawn) (b) 1,523 1,570
Canexus Notes, due 2013 (US$50 million) 51 52
Notes, due 2013 (US$500 million) 508 523
Canexus Convertible Debentures, due 2014 41 46
Notes, due 2015 (US$250 million) 254 262
Notes, due 2017 (US$250 million) 254 262
Notes, due 2019 (US$300 million) 305 314
Notes, due 2028 (US$200 million) 203 209
Notes, due 2032 (US$500 million) 508 523
Notes, due 2035 (US$790 million) 802 827
Notes, due 2037 (US$1,250 million) 1,270 1,308
Notes, due 2039 (US$700 million) 711 733
Subordinated Debentures, due 2043
(US$460 million) 467 481
------------- ------------
7,144 7,343
Unamortized Debt Issue Costs (90) (92)
------------- ------------
Total 7,054 7,251
============= ============
(a) CANEXUS TERM CREDIT FACILITIES
Canexus has $450 million (US$444 million) of committed, secured term credit
facilities available until 2012. At March 31, 2010, $247 million (US$244
million) was drawn on these facilities (December 31, 2009 - $233 million (US$223
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 1.5% for the three months ended March 31, 2010 (three months
ended March 31, 2009 - 2.7%).
(b) TERM CREDIT FACILITIES
We have unsecured term credit facilities of $3.1 billion (US$3.1 billion)
available until 2012. At March 31, 2010, $1.5 billion (US$1.5 billion) was drawn
on these facilities (December 31, 2009 - $1.6 billion (US$1.5 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 March 31, 2010
(three months ended March 31, 2009 - 1.1%). At March 31, 2010, $391 million
(US$385 million) of these facilities were utilized to support outstanding
letters of credit (December 31, 2009 - $407 million (US$389 million)).
18
(c) INTEREST EXPENSE
Three Months Ended March 31
---------------------------
2010 2009
------------------------------------------------- ------------- -------------
Long-Term Debt 94 89
Other 4 5
------------- -------------
Total 98 94
Less: Capitalized (18) (26)
------------- -------------
Total 80 68
============= =============
Capitalized interest relates to and is included as part of the cost of our oil
and gas properties. The capitalization rates are based on our weighted-average
cost of borrowings.
(d) SHORT-TERM BORROWINGS
Nexen has uncommitted, unsecured credit facilities of approximately $466 million
(US$459 million), none of which were drawn at March 31, 2010 (December 31, 2009
- nil). We utilized $116 million (US$114 million) of these facilities to support
outstanding letters of credit at March 31, 2010 (December 31, 2009 - $86 million
(US$82 million)). Interest is payable at floating rates.
10. CAPITAL MANAGEMENT
Our objectives and processes for managing our capital structure are consistent
with those in place at December 31, 2009. Our capital consists of equity,
short-term borrowings, long-term debt and cash and cash equivalents as follows:
March 31 December 31
2010 2009
------------------------------------------------- --------------- --------------
NET DEBT (1)
Long-Term Debt 7,054 7,251
Less: Cash and Cash Equivalents (1,997) (1,700)
--------------- --------------
Total 5,057 5,551
=============== ==============
EQUITY (2) 7,827 7,646
=============== ==============
(1) Includes all of our borrowings and is calculated as long-term debt and
short-term borrowings less cash and cash equivalents.
(2) Equity is the historical issue of equity and accumulated retained earnings.
We monitor the leverage in our capital structure by reviewing the ratio of net
debt to adjusted cash flow (cash flow from operating activities before changes
in non-cash working capital and other) and interest coverage ratios at various
commodity prices. Net debt and adjusted cash flow are non-GAAP measures that are
unlikely to 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).
We use the ratio of net debt to adjusted cash flow as a key indicator of our
leverage and to monitor the strength of our balance sheet. For the twelve months
ended March 31, 2010, the net debt to adjusted cash flow was 2.2 times compared
to 2.5 times at December 31, 2009. While we typically expect the target ratio to
fluctuate between 1.0 and 2.0 times under normalized commodity prices, this can
be higher or lower depending on commodity price volatility, when we are in the
investment cycle, 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 increased from 8.5
times at the end of 2009 to 8.9 times at March 31, 2010. Interest coverage is
calculated by dividing our adjusted EBITDA by interest expense before
capitalized interest. Adjusted EBITDA is a non-GAAP measure that is calculated
using net income excluding interest expense, provision for income taxes,
exploration expenses, DD&A, impairment and other non-cash expenses. The
calculation of adjusted EBITDA is set out in the following table and is unlikely
to be comparable to similar measures presented by others.
19
Twelve Months Year Ended
Ended March 31 December 31
2010 2009
-------------------------------------------------- ------------- ------------
Net Income Attributable to Nexen Inc. 586 536
Add:
Interest Expense 324 312
Provision for Income Taxes 388 260
Depreciation, Depletion, Amortization
and Impairment 1,781 1,802
Exploration Expense 342 302
Recovery of Non-Cash Stock-Based Compensation (11) (10)
Change in Fair Value of Crude Oil Put Options 251 251
Other Non-Cash Expenses (153) (136)
------------- ------------
Adjusted EBITDA 3,508 3,317
============= ============
11. ASSET RETIREMENT OBLIGATIONS
Changes in carrying amounts of the asset retirement obligations associated with
our Property, Plant & Equipment (PP&E) are as follows:
Three Months Year Ended
Ended March 31 December 31
2010 2009
--------------------------------------------------- -------------- -------------
Balance at Beginning of Period 1,053 1,059
Obligations Incurred with Development Activities 7 27
Obligations Settled (11) (42)
Accretion Expense 17 70
Revisions to Estimates (32) 13
Effects of Changes in Foreign Exchange Rate (38) (74)
-------------- -------------
Balance at End of Period (1), (2) 996 1,053
============== =============
(1) Obligations due within 12 months of $64 million (December 31, 2009 - $35
million) have been included in accounts payable and accrued liabilities.
(2) Obligations relating to our oil and gas activities amount to $962 million
(December 31, 2009 - $1,002 million) and obligations relating to our
chemicals business amount to $34 million (December 31, 2009 - $51 million).
Our total estimated undiscounted inflated asset retirement obligations amount to
$2,261 million (December 31, 2009 - $2,341 million). We discounted the total
estimated asset retirement obligations using a weighted-average, credit-
adjusted, risk-free rate of 5.9%. Approximately $298 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
March 31 December 31
2010 2009
------------------------------------------------------- ----------- ------------
Deferred Tax Credit 460 503
Long-Term Energy Marketing Derivative Contracts (Note 6) 199 212
Defined Benefit Pension Obligations 75 76
Capital Lease Obligations 60 61
Deferred Transportation Revenue 52 55
Other 113 114
----------- ------------
Total 959 1,021
=========== ============
20
13. SHAREHOLDERS' EQUITY
DIVIDENDS
Dividends per common share for the three months ended March 31, 2010 were $0.05
per common share (2009 - $0.05). Dividends paid to holders of common shares have
been designated as "eligible dividends" for Canadian tax purposes.
14. MARKETING AND OTHER INCOME
Three Months Ended March 31
---------------------------
2010 2009
---------------------------------------------------- ------------ -------------
Marketing Revenue, Net 86 267
Long Lake Purchased Bitumen Sales 28 -
Change in Fair Value of Crude Oil Put Options (16) (16)
Interest 4 2
Foreign Exchange Gains 34 19
Other 15 (15)
------------ -------------
Total 151 257
============ =============
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 Ended March 31
---------------------------
(millions of shares) 2010 2009
---------------------------------------------------- ------------- -------------
Weighted-average number of common shares outstanding 523.6 520.2
Shares issuable pursuant to tandem options 6.3 7.6
Shares notionally purchased from proceeds of
tandem options (4.8) (5.1)
------------- -------------
Weighted-average number of diluted common shares
outstanding 525.1 522.7
============= =============
In calculating the weighted-average number of diluted common shares outstanding
for the three months ended March 31, 2010, we excluded 16,476,455 tandem
options, 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 months ended March 31, 2009, we
excluded 4,103,560 tandem options, 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 15 to the Audited Consolidated Financial Statements
included in our 2009 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.
During the quarter, we sold our European gas and power marketing business. We
agreed to maintain our parental guarantees to the existing counterparties until
the purchaser is able to replace them. The guarantees expire at the earlier of
the purchaser replacing the guarantees and July 25, 2010. We are obligated to
perform under the guarantees only if the purchaser does not meet its obligations
to the counterparties. Our total exposure is $275 million for which the
purchaser has provided us with an indemnity and a letter of credit from a highly
rated financial institution.
21
17. CASH FLOWS
(a) CHARGES AND CREDITS TO INCOME NOT INVOLVING CASH
Three Months Ended March 31
---------------------------
2010 2009
---------------------------------------------------- -------------- ------------
Depreciation, Depletion, Amortization and Impairment 388 409
Stock-Based Compensation (1) -
Loss (Gains) on Disposition of Assets 3 (7)
Recovery of Future Income Taxes (100) (87)
Change in Fair Value of Crude Oil Put Options 16 16
Foreign Exchange (41) (13)
Other - 1
-------------- ------------
Total 265 319
============== ============
(b) CHANGES IN NON-CASH WORKING CAPITAL
Three Months Ended March 31
2010 2009
---------------------------------------------------- -------------- ------------
Accounts Receivable (218) 298
Inventories and Supplies 113 (49)
Other Current Assets 73 (8)
Accounts Payable and Accrued Liabilities 385 185
Other Current Liabilities (9) 13
-------------- ------------
Total 344 439
============== ============
Relating to:
Operating Activities 256 420
Investing Activities 88 19
-------------- ------------
Total 344 439
============== ============
(c) OTHER CASH FLOW INFORMATION
Three Months Ended March 31
2010 2009
--------------------------------------------------- -------------- -------------
Interest Paid 103 81
Income Taxes Paid 207 34
-------------- -------------
Cash flow from other operating activities includes cash outflows related to
geological and geophysical expenditures of $12 million for the three months
ended March 31, 2010 (2009 - $12 million).
18. SUBSEQUENT EVENTS
In April 2010, we substantially completed negotiations for the sale of our North
American natural gas marketing business subject to finalizing documentation and
customary closing conditions. We expect to sign the agreement in the second
quarter and close the sale in the third quarter. The sale is expected to be cash
neutral and we expect to recognize a non-cash loss on the sale of between $250
and $290 million. This loss primarily relates to the transfer of long-term
natural gas physical transportation commitments that are less valuable with
increased gas supplies that reduce the need for transport services. Although
volatile on a quarterly basis, we have had success with our marketing business
over the last 10 years generating about $800 million of cash.
22
19. OPERATING SEGMENTS AND RELATED INFORMATION
Nexen is involved in activities relating to Oil and Gas, Energy Marketing and
Chemicals in various geographic locations as described in Note 20 to the Audited
Consolidated Financial Statements included in our 2009 Form 10-K.
THREE MONTHS ENDED MARCH 31, 2010
Energy Corporate
Oil and Gas Marketing Chemicals and Other Total
----------------------------- ----------------------------------------------------------- ---------- ---------- ----------- --------
United United Other
Kingdom Canada Syncrude States Yemen Countries(1)
---------- --------- -------- --------- --------- -----------
Net Sales 755 180 134 113 182 15 9 113 - 1,501
Marketing and Other 5 28 1 - 5 - 83 7 22(2) 151
---------- --------- -------- --------- --------- ---------- ---------- ---------- ----------- --------
Total Revenues 760 208 135 113 187 15 92 120 22 1,652
Less: Expenses
Operating 77 134 67 22 41 1 10 70 - 422
Depreciation, Depletion,
Amortization and
Impairment 168 80 13 64 35 2 5 11 10 388
Transportation and Other (1) 56 7 2 3 - 123 12 - 202
General and
Administrative (3) 13 16 - 11 1 8 21 8 40 118
Exploration 24 7 - 16 - 46(4) - - - 93
Interest - - - - - - - 1 79 80
---------- --------- -------- --------- --------- ---------- ---------- ---------- ----------- --------
Income (Loss)
before Income Taxes 479 (85) 48 (2) 107 (42) (67) 18 (107) 349
Less: Provision for
(Recovery 240 (21) 12 (1) 37 (38) (23) 4 (51) 159
of) Income Taxes
Less: Non-Controlling
Interests - - - - - - - 5 - 5
---------- --------- -------- --------- --------- ---------- ---------- ---------- ----------- --------
NET INCOME (LOSS) 239 (64) 36 (1) 70 (4) (44) 9 (56) 185
========== ========= ======== ========= ========= ========== ========== ========== =========== ========
IDENTIFIABLE ASSETS 4,696 7,848(5) 1,292 1,717 257 1,141 2,588(6) 701 2,523 22,763
========== ========= ======== ========= ========= ========== ========== ========== =========== ========
Capital Expenditures
Development and Other 88 70 19 15 10 91 9 49 6 357
Exploration 41 68 - 49 - 41 - - - 199
---------- --------- -------- --------- --------- ---------- ---------- ---------- ----------- --------
TOTAL 129 138 19 64 10 132 9 49 6 556
========== ========= ======== ========= ========= ========== ========== ========== =========== ========
Property, Plant and
Equipment
Cost 6,027 9,781 1,482 3,828 2,397 991 265 1,164 377 26,312
Less: Accumulated DD&A 2,745 2,108 281 2,504 2,286 97 88 570 252 10,931
---------- --------- -------- --------- --------- ---------- ---------- ---------- ----------- --------
NET BOOK VALUE 3,282 7,673(5) 1,201 1,324 111 894 177 594 125 15,381
========== ========= ======== ========= ========= ========== ========== ========== =========== ========
(1) Includes results of operations from producing activities in Colombia.
(2) Includes interest income of $4 million, foreign exchange gains of $34
million and a decrease in the fair value of crude oil put options of $16
million.
(3) Includes stock-based compensation expense of $2 million.
(4) Includes exploration activities primarily in Nigeria, Norway and Colombia.
(5) Includes costs of $6,088 million related to our insitu oil sands (Long Lake
and future phases).
(6) Approximately 79% of Marketing's identifiable assets are accounts
receivable and inventories.
23
THREE MONTHS ENDED MARCH 31, 2009
Energy Corporate
Oil and Gas Marketing Chemicals and Other Total
----------------------------- ----------------------------------------------------------- ---------- ---------- ----------- --------
United United Other
Kingdom Canada Syncrude States Yemen Countries(1)
---------- --------- -------- --------- --------- -----------
Net Sales 478 91 98 63 162 19 13 124 - 1,048
Marketing and Other 4 7 - - 3 - 267 (14) (10)(2) 257
---------- --------- -------- --------- --------- ---------- ---------- ---------- ----------- --------
Total Revenues 482 98 98 63 165 19 280 110 (10) 1,305
Less: Expenses
Operating 51 41 66 23 47 2 8 67 - 305
Depreciation, Depletion,
Amortization and
Impairment 193 63 11 68 41 5 4 12 12 409
Transportation and Other (3) 3 7 13 3 - 162 10 6 201
General and Administrative 2 14 - 14 4 8 23 9 26 100
Exploration 8 21 - 10 - 14(3) - - - 53
Interest - - - - - - - 2 66 68
---------- --------- -------- --------- --------- ---------- ---------- ---------- ----------- --------
Income (Loss)
before Income Taxes 231 (44) 14 (65) 70 (10) 83 10 (120) 169
Less: Provision for
(Recovery 86 (11) 4 (23) 24 (6) 35 2 (80) 31
of) Income Taxes
Less: Non-Controlling
Interests - - - - - - - 3 - 3
---------- --------- -------- --------- --------- ---------- ---------- ---------- ----------- --------
NET INCOME (LOSS) 145 (33) 10 (42) 46 (4) 48 5 (40) 135
=========== ========= ======== ========= ========= ========== ========== ========== =========== =========
IDENTIFIABLE ASSETS 6,403 7,678(4) 1,212 2,100 400 807 3,035(5) 594 1,390 23,619
=========== ========= ======== ========= ========= ========== ========== ========== =========== =========
Capital Expenditures
Development and Other 149 244 17 42 29 58 8 36 1 584
Exploration 28 94 - 26 - 15 - - - 163
Proved Property
Acquisitions - 757 - - - - - - - 757
---------- --------- -------- --------- --------- ---------- ---------- ---------- ----------- --------
TOTAL 177 1,095 17 68 29 73 8 36 1 1,504
=========== ========= ======== ========= ========= ========== ========== ========== =========== =========
Property, Plant and
Equipment
Cost 6,869 9,225 1,386 4,591 2,920 636 256 983 332 27,198
Less: Accumulated DD&A 2,419 1,843 244 2,850 2,729 121 80 523 212 11,021
---------- --------- -------- --------- --------- ---------- ---------- ---------- ----------- --------
NET BOOK VALUE 4,450 7,382(4) 1,142 1,741 191 515 176 460 120 16,177
=========== ========= ======== ========= ========= ========== ========== ========== =========== =========
(1) Includes results of operations from producing activities in Colombia.
(2) Includes interest income of $2 million, foreign exchange gains of $19
million, decrease in the fair value of crude oil put options of $16 million
and other losses of $15 million.
(3) Includes exploration activities primarily in Norway and Colombia.
(4) Includes costs of $5,658 million related to our insitu oil sands (Long Lake
and future phases).
(5) Approximately 77% of Marketing's identifiable assets are accounts
receivable and inventories.
24
20. DIFFERENCES BETWEEN CANADIAN AND US GENERALLY ACCEPTED ACCOUNTING
PRINCIPLES
The Unaudited Consolidated Financial Statements have been prepared in accordance
with Canadian GAAP. The US GAAP Unaudited Consolidated Statements and summaries
of differences from Canadian GAAP are as follows:
UNAUDITED CONSOLIDATED STATEMENT OF INCOME - US GAAP
FOR THE THREE MONTHS ENDED MARCH 31
(Cdn$ millions, except per share amounts) 2010 2009
------------------------------------------------------ ------------- -----------
REVENUES AND OTHER INCOME
Net Sales 1,501 1,048
Marketing and Other (v); (vi) 205 292
------------- -----------
1,706 1,340
------------- -----------
EXPENSES
Operating 422 305
Depreciation, Depletion, Amortization
and Impairment 388 409
Transportation and Other (v) 205 194
General and Administrative (iv) 126 108
Exploration 93 53
Interest 80 68
------------- -----------
1,314 1,137
------------- -----------
INCOME BEFORE PROVISION FOR INCOME TAXES 392 203
------------- -----------
PROVISION FOR (RECOVERY OF) INCOME TAXES
Current 259 118
Deferred (iv); (vi); (vii) (86) (74)
------------- -----------
173 44
------------- -----------
NET INCOME - US GAAP 219 159
Less: Net Income Attributable to
Non-Controlling Interests 5 3
------------- -----------
NET INCOME ATTRIBUTABLE TO NEXEN INC. - US GAAP (1) 214 156
============= ===========
EARNINGS PER COMMON SHARE ($/share) (Note 15)
Basic 0.41 0.30
============= ===========
Diluted 0.41 0.30
============= ===========
(1) RECONCILIATION OF CANADIAN AND US GAAP NET INCOME
Three Month March 31
-------------------------
2010 2009
------------------------------------------------------ ------------- -----------
Net Income Attributable to Nexen Inc - Canadian GAAP 185 135
Impact of US Principles, Net of Income Taxes:
Stock-based Compensation (iv) (6) -
Inventory Valuation (vi) 35 (6)
Deferred Taxes (vii) - 27
------------- -----------
Net Income Attributable to Nexen Inc - US GAAP 214 156
============= ===========
25
UNAUDITED CONSOLIDATED BALANCE SHEET - US GAAP
March 31 December 31
(Cdn$ millions, except share amounts) 2010 2009
------------------------------------------------------ ------------ ------------
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents 1,997 1,700
Restricted Cash 178 198
Accounts Receivable 2,635 2,788
Inventories and Supplies (vi) 555 610
Other 102 185
------------ ------------
Total Current Assets 5,467 5,481
------------ ------------
PROPERTY, PLANT AND EQUIPMENT
Net of Accumulated Depreciation, Depletion,
Amortization and Impairment of $11,324
(December 31, 2009 - $11,200) (i); (iii) 15,332 15,443
GOODWILL 330 339
DEFERRED INCOME TAX ASSETS 1,238 1,148
DEFERRED CHARGES AND OTHER ASSETS 328 370
------------ ------------
TOTAL ASSETS 22,695 22,781
============ ============
LIABILITIES
CURRENT LIABILITIES
Accounts Payable and Accrued Liabilities (iv) 3,185 3,131
Accrued Interest Payable 77 89
Dividends Payable 26 26
------------ ------------
Total Current Liabilities 3,288 3,246
------------ ------------
LONG-TERM DEBT 7,054 7,251
DEFERRED INCOME TAX LIABILITIES (i);
(ii); (iv); (vi); (vii) 2,727 2,720
ASSET RETIREMENT OBLIGATIONS 932 1,018
DEFERRED CREDITS AND OTHER LIABILITIES (ii) 1,064 1,126
EQUITY
Nexen Inc. Shareholders' Equity
Common Shares, no par value
Authorized: Unlimited
Outstanding: 2010 - 524,046,867 shares
2009 - 522,915,843 shares 1,076 1,049
Contributed Surplus - 1
Retained Earnings (i); (ii); (iv); (vi); (vii) 6,763 6,575
Accumulated Other Comprehensive Loss (ii) (280) (269)
------------ ------------
Total Nexen Inc. Shareholders' Equity 7,559 7,356
Canexus Non-Controlling Interests 71 64
------------ ------------
TOTAL EQUITY 7,630 7,420
------------ ------------
COMMITMENTS, CONTINGENCIES AND GUARANTEES (Note 16)
TOTAL LIABILITIES AND EQUITY 22,695 22,781
============ ============
UNAUDITED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME - US GAAP
FOR THE THREE MONTHS ENDED MARCH 31
Three Months Ended March 31
---------------------------
2010 2009
--------------------------------------------------- -------------- -------------
Net Income Attributable to Nexen Inc. - US GAAP 214 156
Other Comprehensive Income (Loss), Net of Income Taxes:
Foreign Currency Translation Adjustment (11) 6
-------------- -------------
Comprehensive Income Attributable to
Nexen Inc. - US GAAP 203 162
============== =============
26
UNAUDITED CONSOLIDATED STATEMENT OF ACCUMULATED OTHER COMPREHENSIVE LOSS - US
GAAP
March 31 December 31
2010 2009
--------------------------------------------------- -------------- -------------
Foreign Currency Translation Adjustment (201) (190)
Unamortized Defined Benefit Pension Plan Costs (ii) (79) (79)
-------------- -------------
Accumulated Other Comprehensive Loss (280) (269)
============== =============
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, 2009 - $30 million) and deferred income tax liabilities are lower by
$11 million (December 31, 2009 - $11 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
March 31, 2010 and December 31, 2009, the unfunded amount of our defined
benefit pension plans that was not included in the pension liability under
Canadian GAAP was $105 million. This amount has been included in deferred
credits and other liabilities and $79 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 higher by $8 million, ($6
million, net of income taxes), for the three months ended March 31,
2010, (2009 - higher by $8 million ($6 million, net of income taxes));
and
o accounts payable and accrued liabilities are higher by $101 million as
at March 31, 2010 (December 31, 2009 - $93 million).
v. Under US GAAP, asset disposition gains and losses are included with
transportation and other expense. Losses of $3 million for the three months
ended March 31, 2010, were reclassified from marketing and other income to
transportation and other expense (gains of $7 million were reclassified for
the three months ended March 31, 2009).
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 $51 million ($35 million, net
of income taxes) for the three months ended March 31, 2010 (2009 -
higher by $42 million ($27 million, net of income taxes)); and
o inventories are lower by $19 million as at March 31, 2010 (December
31, 2009 - lower by $70 million) and deferred income tax liabilities
are $7 million lower (December 31, 2009 - lower by $23 million).
vii. Under US GAAP, we are required to apply FIN48 ACCOUNTING FOR UNCERTAINTY IN
INCOME TAXES regarding accounting and disclosure for uncertain tax
positions.
As at March 31, 2010, the total amount of our unrecognized tax benefit was
approximately $279 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 March 31, 2010, the total
amount of interest and penalties related to uncertain tax positions
recognized in deferred income tax
27
liabilities in the US GAAP - Unaudited Consolidated Balance Sheet was
approximately $8 million. We had no interest or penalties included in the
US GAAP - Unaudited Consolidated Statement of Income for the three months
ended March 31, 2010.
Our income tax filings are subject to audit by taxation authorities and as
at March 31, 2010 the following tax years remained subject to examination,
(i) Canada - 1985 to date (ii) United Kingdom - 2008 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.
NEW ACCOUNTING PRONOUNCEMENTS - US GAAP
In January 2010, the Financial Accounting Standards Board issued guidance to
improve fair value measurement disclosures. The guidance requires entities to
describe transfers between the three levels of the fair value hierarchy and
present items separately in the level 3 reconciliation. This guidance is
consistent with fair value measurement disclosures adopted for Canadian GAAP in
2009. Adoption of this guidance did not have an impact on our results of
operations or financial position.
28
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 20 TO THE UNAUDITED CONSOLIDATED
FINANCIAL STATEMENTS. THE DATE OF THIS DISCUSSION IS APRIL 26, 2010.
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,
INFORMATION ON A NET, AFTER-ROYALTIES BASIS IS ALSO PRESENTED.
NOTE: CANADIAN INVESTORS SHOULD READ THE SPECIAL NOTE TO CANADIAN INVESTORS ON
PAGE 97 OF OUR 2009 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 FIRST QUARTER RESULTS
Three Months Ended March 31
---------------------------
(Cdn$ millions, except as indicated) 2010 2009
--------------------------------------------------- -------------- -------------
Production before Royalties (mboe/d) 252 252
Production after Royalties (mboe/d) 221 225
Nexen's Average Realized Oil and Gas
Price (Cdn$/boe) 70.16 47.56
Cash Flow from Operating Activities 798 789
Net Income Attributable to Nexen Inc. 185 135
Earnings per Common Share, Basic ($/share) 0.35 0.26
Capital Investment 556 747
Acquisition of Additional Interest in Long Lake - 757
Net Debt (1) 5,057 5,737
-------------- -------------
(1) Net debt is a non-GAAP measure and is defined as long-term debt and
short-term borrowings less cash and cash equivalents.
Production for the quarter was consistent with last year. Production increases
at Long Lake, the Gulf of Mexico and at Ettrick and Telford in the UK North Sea
were offset by natural declines at Yemen and maintenance downtime at Buzzard for
repairs to the separator unit. Our realized average oil and gas price averaged
$70.16/boe for the quarter, 48% higher than last year as a result of stronger
benchmark commodity prices. The stronger Canadian dollar relative to the US
dollar reduced the benefit of the higher commodity prices. The combined impact
of higher prices and steady production, offset by lower energy marketing cash
flow, resulted in a 37% increase in net income.
At our Long Lake oil sands project, we are steadily growing bitumen production
volumes each month as we increase steam volumes. Our first quarter results
include start-up losses of $57 million at Long Lake. We expect Long Lake to make
positive cash flow contributions later this year as our bitumen volumes grow.
We incurred approximately 20% of our 2010 capital budget to date. Our
expenditures have focused on our major developments at Long Lake and Usan,
offshore West Africa, exploration in the Gulf of Mexico and the North Sea, and
advancing our shale gas project in north-east British Columbia.
29
During the quarter, we made a significant oil discovery at Appomattox in Eastern
Gulf of Mexico where we drilled an exploratory well and two appraisal
sidetracks. Appomattox is the third discovery in the area following earlier
discoveries at Shiloh and Vicksburg. Additional exploration and appraisal wells
for Appomattox are planned for later this year.
Our financial position remains strong with available liquidity of approximately
$3.6 billion. This liquidity includes cash on hand of $2 billion and undrawn
lines of credit of approximately $1.6 billion. 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:
conventional exploration and development, oil sands, and unconventional gas. We
are committed to growing long-term value for our shareholders responsibly and
are advancing our plans to achieve this as described below.
We are currently investing primarily in:
o ramping up Long Lake safely and reliably;
o progressing construction of our Usan project and continuing to explore our
acreage, offshore Nigeria;
o advancing development plans for our Golden Eagle area in the UK North Sea;
o appraising exploration successes at Appomattox and Knotty Head in the Gulf
of Mexico;
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 MARCH 31, 2010
New Growth
Major Early Stage Exploration Core Asset
Development Development Development Total
------------------------------------------------ ----------------- ---------------- --------------- ----------------- ------------
Oil and Gas
United Kingdom 22 - 41 66 129
Canada - - 68 6 74
Synthetic (mainly Long Lake) - 15 - 49 64
Syncrude - - - 19 19
United States - - 49 15 64
Yemen - - - 10 10
Nigeria 91 - 1 - 92
Other Countries - - 40 - 40
----------------- ---------------- --------------- ----------------- ------------
113 15 199 165 492
Chemicals - - - 49 49
Energy Marketing, Corporate and Other - - - 15 15
----------------- ---------------- --------------- ----------------- ------------
Total Capital 113 15 199 229 556
================= ================ =============== ================= ============
As a % of Total Capital 20% 3% 36% 41% 100%
----------------- ---------------- --------------- ----------------- ------------
UNITED KINGDOM - NORTH SEA
The Golden Eagle area has emerged as a significant development opportunity for
us. We are in the process of completing the acquisition of additional land in
the area and plan to drill an exploration well here mid-year. Golden Eagle area
development supports standalone facilities and is economic with oil prices
significantly lower than they are currently. We are assessing development
options for the area and will select an appropriate configuration prior to
sanctioning in 2011. We have a 34% interest in both Golden Eagle and Hobby, a
46% interest in Pink, and operate all three.
West of the Shetland Islands, we are finalizing plans to drill the North Uist
prospect. We have a 35% working interest here and expect to drill the well in
the second half of 2010. This prospect has a target size much larger than
typical North Sea targets. BP is the operator with a 45% working interest.
30
CANADA - HORN RIVER SHALE GAS
We have finished drilling our eight-well program and continue to make
significant progress on lowering costs and gaining access to the shale reservoir
on our substantial Horn River shale gas position in north-east British Columbia.
We plan to complete these wells in the second half of the year with 18 fracs per
well. First production from these wells is expected before year end, ramping up
to 50 mmcf/d.
Substantial cost savings and productivity improvements were realized with this
drilling program and our average drilling days per well were under 25 days. We
currently expect that with an 18 well program, we could reduce our all-in costs
even further to under $0.6 million per frac. Our production results to date,
together with those of our competitors, indicate that recovery factors should be
higher than our estimate of 20%. Additional production history will determine
recovery factors.
SYNTHETIC
Since the completion of the turnaround last fall, bitumen volumes have been
consistently growing. Long Lake's gross bitumen production has grown from 14,000
bbls/d in the fourth quarter of 2009 to 19,000 bbls/d in the first quarter of
2010. In March, gross bitumen production averaged 22,000 bbls/d. We are
currently producing approximately 25,000 bbls/d and are seeing production
increases from both new wells and from optimization of mature producers. This
represents an 80% increase over average pre-turnaround rates.
Production growth reflects significant improvement in steam reliability since
the turnaround and steam rates are at all-time highs of about 140,000 bbls/d and
increasing. This represents a 100% increase over pre-turnaround rates. As a
result, we are injecting more steam into more wells than ever before with 64
well pairs now on production and steam circulating in an additional 15 pairs.
These circulating wells will be converted to production over the next few
months.
Our all-in steam-to-oil ratio (SOR) is between 5 and 6 but this includes steam
to wells that are still in the steam circulation stage and wells early in their
growth cycle. As our circulating wells start producing bitumen, we expect to see
an increase in bitumen production rates with a corresponding decrease in SOR.
The SOR of our producing wells is approximately 5, and includes well pairs
recently converted to production that are in the early stages of ramp up. We
continue to expect a long term SOR of 3.0 over the life of the project.
The upgrader facility is also performing consistently. Since the turnaround, the
upgrader has experienced 90% uptime, compared to 50% before and is producing
high quality premium synthetic crude (PSCTM). For the quarter, our realized
price for Long Lake PSCTM averaged over $81/bbl. The gasification process is
working, creating a low-cost fuel source which reduces our need to purchase
natural gas for operations and will generate a significant margin advantage over
our peers, even at current low gas prices.
UNITED STATES - GULF OF MEXICO
During the quarter, we made a significant discovery in the Eastern Gulf of
Mexico at Appomattox, located in Mississippi Canyon blocks 391 and 392. Drilling
activities resulted in an oil discovery with excellent reservoir quality,
following an exploration well and two appraisal sidetracks. The discovery well,
located in 7,217 feet of water, was drilled to a depth of 25,077 feet true
vertical depth. An appraisal sidetrack was drilled to approximately 25,950 feet
true vertical depth. The second sidetrack was undertaken to further delineate
the discovery. Well results have exceeded our pre-drill expectations.
Appomattox is the third discovery in the area following earlier discoveries at
Shiloh and Vicksburg. Additional appraisal wells for Appomattox are planned for
later in the year and we are investigating development options for Appomattox
and Vicksburg, located six miles east. We have a 25% interest in Vicksburg and a
20% interest in Appomattox and Shiloh. Shell Offshore Inc. operates all three
discoveries.
Elsewhere in the deep water, we completed drilling an appraisal well at Knotty
Head and are currently evaluating results and possible development choices.
Drilling operations with our new deep-water rig exceeded expectations. We
completed the well in approximately 15% less time than expected and 20% below
planned cost. We are continuing our efforts to unitize our lands with adjacent
acreage. We are operator of Knotty Head with a 25% working interest. A second
deep-water drilling rig is expected to arrive later this year which will allow
us to start drilling our other identified prospects.
OFFSHORE WEST AFRICA
Development of the Usan field, offshore West Africa, is progressing well with
first production expected in 2012. The development includes a floating
production and storage (FPSO) vessel with the ability to process 180,000
31
bbls/d (36,000 bbls/d net to us) and store up to two million barrels of oil. We
have a 20% interest in exploration and development on this block and Total E&P
Nigeria Limited is the operator.
We continue to explore offshore West Africa and previously announced a
successful exploration well at Owowo in the southern portion of Oil Prospecting
License (OPL) 223. Other exploration prospects are under evaluation for
drilling.
FINANCIAL RESULTS
CHANGE IN NET INCOME
2010 VS 2009
------------------------------------------------------------- ------------------
NET INCOME AT MARCH 31, 2009 135
------------------
Favorable (unfavorable) variances(1):
Realized Commodity Prices
Crude Oil 410
Natural Gas 1
------------------
Total Price Variance 411
Production Volumes, After Royalties
Crude Oil (15)
Natural Gas 34
Changes in Crude Oil Inventory For Sale 38
------------------
Total Volume Variance 57
Oil and Gas Operating Expense (112)
Oil and Gas Depreciation, Depletion,
Amortization and Impairment 19
Exploration Expense (40)
Energy Marketing Revenue, Net (151)
Chemicals Contribution 4
General and Administrative Expense (2) (18)
Interest Expense (12)
Current Income Taxes (141)
Future Income Taxes 13
Other 20
------------------
NET INCOME AT MARCH 31, 2010 185
==================
(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.
32
OIL & GAS
PRODUCTION
Three Months Ended March 31
---------------------------------------------------
2010 2009
------------------------- -------------------------
Before After Before After
Royalties(1) Royalties Royalties(1) Royalties
---------------------------- ------------ ------------ ------------ ------------
Crude Oil and Liquids
(mbbls/d)
United Kingdom 105.6 105.6 103.8 103.8
Canada 14.2 11.0 15.5 12.3
Long Lake Bitumen 12.1 11.3 8.1 8.1
Syncrude 19.5 17.8 19.8 19.6
United States 9.8 8.9 10.4 9.5
Yemen 42.8 23.1 54.5 35.7
Other Countries 2.3 2.1 5.5 5.1
------------ ------------ ------------ ------------
206.3 179.8 217.6 194.1
------------ ------------ ------------ ------------
Natural Gas (mmcf/d)
United Kingdom 40 40 18 18
Canada 133 121 137 122
United States 101 88 50 45
------------ ------------ ------------ ------------
274 249 205 185
------------ ------------ ------------ ------------
Total Production (mboe/d) 252 221 252 225
============ ============ ============ ============
(1) We have presented production volumes before royalties as we measure our
performance on this basis consistent with other Canadian oil and gas
companies.
HIGHER SALES VOLUMES INCREASED NET INCOME FOR THE QUARTER BY $57 MILLION
Production before royalties remained consistent with the same period in 2009.
Production increases included i) restoring Gulf of Mexico gas production which
was shut in due to Hurricane Ike and new production at Longhorn; ii) new volumes
from Ettrick and Telford in the UK North Sea; and iii) ramping up Long Lake
bitumen production. These increases were offset by i) natural declines in Yemen;
ii) reduced working interest in Colombia; iii) lower production in Canada; and
iv) temporary downtime at Buzzard. Compared to the fourth quarter of 2009,
production before royalties decreased 5% as a result of downtime at Buzzard and
Ettrick in the UK North Sea and an advanced turnaround at Syncrude. This was
partially offset by increased production at Long Lake and the ramp up of
Longhorn in the Gulf of Mexico.
The following table summarizes our production volume changes since last quarter:
Before After
(mboe/d) Royalties Royalties
--------------------------------------------------- --------------- ------------
Production, fourth quarter 2009 265 235
Production changes:
Long Lake Bitumen 3 2
United States 3 2
Canada (1) -
Yemen (2) (3)
Syncrude (4) (3)
United Kingdom (12) (12)
--------------- ------------
Production, first quarter 2010 252 221
=============== ============
Production volumes discussed in this section represent before-royalties volumes,
net to our working interest.
33
UNITED KINGDOM
Production volumes in the UK North Sea averaged 112,300 boe/d in the quarter, 5%
higher than the first quarter of 2009 but 10% lower than the previous quarter.
The decrease from the previous quarter was primarily a result of downtime at
Buzzard for repairs to the separator unit and drilling rig movement and
commissioning activities at Ettrick which required a shut in of the FPSO vessel.
Buzzard production averaged 84,600 boe/d during the quarter, 2% below the
previous quarter and 9% lower than the first quarter last year. Routine
monitoring of equipment on the Buzzard platform during the quarter identified
repairs that were required to the separator unit. The repair work lasted a week,
during which time Buzzard produced at reduced rates of approximately 50,000
boe/d (gross). Production was subsequently restored to full capacity. Further
activities are scheduled to permanently repair the separator unit. This work is
timed to coincide with our planned two week shutdown to install the topsides of
the fourth platform in the second quarter.
Production at Scott/Telford decreased 15% from the prior quarter to average
20,400 boe/d as a result of well intervention work at Scott and scheduled
maintenance at Telford. Production has almost doubled compared to the first
quarter of 2009 as a result of a successful step-out development well at
Telford. This well was completed in the third quarter of 2009 and is tied back
to our Scott platform. Production from our non-operated fields at Duart and
Farragon averaged 2,300 boe/d for the quarter.
Production from our Ettrick field averaged 5,000 boe/d for the quarter as we
continue to ramp up the facilities and safely commission all systems. Production
was 55% lower than the previous quarter as a result of commissioning activities
and a two week shut-in for rig movements relating to drilling and completion
activities in the area. Production was shut in for two weeks as a result.
Ettrick production has been restored, is currently producing at rates around
20,000 boe/d gross (16,000 boe/d net to us) and continues to ramp up.
CANADA
Production in Canada decreased 5% from the first quarter of 2009 and remained
comparable with the fourth quarter. Heavy oil production has remained strong as
we successfully implemented strategies to maximize recoveries from our existing
wells while minimizing capital investment. CBM production was consistent quarter
over quarter and averaged 48 mmcf/d.
We continue to invest in our shale gas project in the Dilly Creek area of the
Horn River basin in north-east British Columbia. We currently have six wells on
production and they are meeting expectations with respect to production and
decline profiles. During the quarter, we finished drilling an eight-well program
to further test the play. We plan to complete these wells in the second half of
the year. First production is from these wells expected before year end, ramping
up to 50 mmcf/d.
LONG LAKE
Since the completion of the turnaround last fall, bitumen volumes have been
consistently growing. Long Lake's gross bitumen production has grown from 14,000
bbls/d in the fourth quarter of 2009 to 19,000 bbls/d in the first quarter of
2010. In March, gross bitumen production averaged 22,000 bbls/d. We are
currently producing approximately 25,000 bbls/d and are seeing production
increases from both new wells and from optimization of mature producers. This
represents an 80% increase over average pre-turnaround rates. The table below
shows gross bitumen production volumes since the turnaround. We have a 65%
interest in Long Lake.
Gross Bitumen
Month Volumes (bbls/d)
--------------------------------------------------------- ----------------------
October 2009 8,600
November 2009 15,200
December 2009 16,200
January 2010 16,300
February 2010 17,700
March 2010 21,900
April 2010 - Month to date 24,500
--------------------------------------------------------- ----------------------
Production growth reflects significant improvement in steam reliability since
the turnaround and steam rates are at all-time highs of about 140,000 bbls/d and
increasing. This represents a 100% increase over pre-turnaround rates. As a
result, we are injecting more steam into more wells than ever before with 64
well pairs now on production and steam circulating in an additional 15 pairs.
These circulating wells will be converted to production over the next few
months.
34
SYNCRUDE
Syncrude production averaged 19,500 boe/d for the quarter, down 18% from the
previous quarter and marginally lower than the first quarter of 2009. Production
volumes were reduced as a turnaround of the LC finer originally planned for the
second quarter was advanced to January. The turnaround was completed in mid
March and is now back to full rates. A coker turnaround is scheduled in the
third quarter.
UNITED STATES
Production in the Gulf of Mexico averaged 26,600 boe/d, 42% higher than the same
period last year. The increase in production primarily came from our
non-operated Longhorn development, which averaged 8,900 boe/d for the quarter.
Production during the first quarter of 2009 was reduced as several fields
remained shut in as a result of Hurricane Ike. These fields resumed full
production in the second quarter of 2009. These increases have been offset by
natural declines primarily at Gunnison.
Production in the US increased 11% from the prior quarter. The impact of
increases from ramping up production at Longhorn were partially offset by lower
production at Mississippi Canyon 72 and Wrigley.
YEMEN
Yemen production decreased 5% from the previous quarter and 21% from the first
quarter of 2009. The decline is consistent with our expectations as the field
matures and from reduced development drilling. During the quarter at Masila, we
drilled four development wells and plan to drill up to seven more development
wells later this year. At Block 51, we recently obtained approval to drill,
complete and tie-in five additional development wells in the remainder of 2010.
Production declines in Yemen are expected to continue as we focus on maximizing
recovery of the remaining reserves.
We are working with the Yemen government and our partners to potentially extend
our production-sharing agreement beyond the current expiry date of December
2011. There is no assurance that this extension will be received.
OTHER COUNTRIES
Our share of production from the Guando field in Colombia averaged 2,300 boe/d
for the quarter. While this was consistent with the previous quarter, it was 58%
lower than the first quarter of 2009 as lower volumes reflect the reduced
working interest of the Guando field, effective the second quarter of 2009, once
we achieved pre-set production levels.
35
COMMODITY PRICES
Three Months Ended March 31
---------------------------
2010 2009
---------------------------------------------------- -------------- ------------
CRUDE OIL
West Texas Intermediate (WTI) (US$/bbl) 78.71 43.08
Dated Brent (Brent) (US$/bbl) 76.23 44.40
-------------- ------------
Benchmark Differentials (1) (US$/bbl)
Heavy Oil 9.25 9.17
Mars 2.97 (0.66)
Masila 1.62 0.05
Realized Prices from Producing Assets (Cdn$/bbl)
United Kingdom 77.25 51.60
Canada 65.26 35.35
Long Lake Synthetic 81.04 -
Syncrude 83.55 55.48
United States 79.12 46.27
Yemen 80.39 52.30
Other Countries 78.88 41.68
Corporate Average (Cdn$/bbl) 78.00 50.41
-------------- ------------
NATURAL GAS
New York Mercantile Exchange (US$/mmbtu) 5.04 4.48
AECO (Cdn$/mcf) 5.08 5.34
-------------- ------------
Realized Prices from Producing Assets (Cdn$/mcf)
United Kingdom 4.81 5.50
Canada 5.02 4.75
United States 6.00 5.93
Corporate Average (Cdn$/mcf) 5.37 5.11
-------------- ------------
NEXEN'S AVERAGE REALIZED OIL AND GAS PRICE (Cdn$/boe) 70.16 47.56
-------------- ------------
AVERAGE FOREIGN EXCHANGE RATE - Canadian to US Dollar 0.9615 0.8028
-------------- ------------
(1) These differentials are a discount/(premium) to WTI.
HIGHER COMMODITY PRICES INCREASED QUARTERLY NET INCOME BY $411 MILLION
Crude oil prices continued to strengthen during the quarter with WTI averaging
US$78.71/bbl, an increase of 83% over the same period last year and 3% higher
than the prior quarter. Dated Brent increased 72% and 2% when compared to the
same periods, averaging US$76.23/bbl for the quarter. The impact of higher
commodity prices was reduced somewhat as the Canadian dollar strengthened
compared to the US dollar over the same period last year. Our realized oil price
averaged $78.00/bbl, 55% higher than the first quarter of 2009 and 2% higher
than the previous quarter.
Natural gas prices were higher as NYMEX averaged US$5.04/mmbtu, 13% higher than
the first quarter of 2009 and 3% higher than the previous quarter. AECO averaged
Cdn$5.08/mcf during the first quarter, 27% above the prior quarter. Compared to
the same period last year, AECO decreased 5% as the Canadian dollar has
strengthened. Our realized gas price averaged $5.37/mcf, 25% higher than the
prior quarter and 5% higher than the first quarter of 2009.
The Canadian dollar strengthened considerably against the US dollar, compared to
the same period last year. This reduced our net sales by approximately $260
million, as our realized crude oil and gas prices were $15.42/bbl and $1.06/mcf
lower, respectively. However, our US-dollar denominated long-term debt,
operating expenses and capital expenditures are lower when translated to
Canadian dollar as a result of the weaker US dollar.
36
CRUDE OIL REFERENCE PRICES
Crude oil prices were 83% higher than the first quarter 2009. WTI traded above
US$80/bbl for most of March, supported by positive economic news, strong Asian
demand and cold weather.
Demand/supply fundamentals for crude oil improved from better-than-expected
world economic growth. OPEC continues to have spare production capacity but oil
demand is forecasted to reach record levels by year end. Demand growth is
exceeding non-OPEC supply growth resulting in reduction to spare capacity.
Continued strong demand growth from emerging markets has redirected supplies
away from the Atlantic basin and reduced floating inventory levels. More
recently, demand for WTI increased as Canadian synthetic crude oil production
has been constrained due to outages.
World-wide economic indicators appear relatively strong but there are concerns
over sovereign credit risks, global fiscal imbalances and the timing and impact
of the withdrawal of government fiscal and monetary stimuli. Most OECD countries
have experienced GDP growth but it has been unbalanced with relatively strong
growth in the US compared to minimal growth in Europe. China has seen strong
growth but the government has taken actions to moderate this because of concerns
about inflation and an overheating economy. Global economic growth remains a
downside risk. A risk to commodity prices continues to be the lack of demand in
developed markets.
Crude oil prices were supported late last year by the weakening US dollar. To
date in 2010, the US dollar strengthened against the Euro and British Pound but
this did not appear to impact crude oil prices. The US dollar is expected to
weaken during 2010 which should continue to support higher crude oil prices.
The recent strength in crude oil prices has been partially attributed to
geopolitical events such as concerns over Iran's nuclear enrichment program, the
ongoing wars in Iraq and Afghanistan and threats of attacks to oil
infrastructure in Nigeria. A much tighter supply/demand environment, and reduced
spare capacity should increase price sensitivity to geopolitical events.
CRUDE OIL DIFFERENTIALS
The heavy oil differential continued to be narrower than historic levels due to
declining heavy oil production and excess heavy refinery capacity. There was a
slight widening of differentials in March primarily due to lower heavy fuel oil
prices.
The Brent/WTI differential widened due to stronger WTI demand as a result of
Canadian synthetic production outages and strong gasoline demand. Rising
transatlantic freight rates also contributed to the wider differential.
The Masila price strengthened relative to Brent, reflecting strong demand from
China and other Asian countries that are the primary buyers of Masila crude.
Excess global refining capacity, OPEC cuts in medium crude and declining heavy
oil production also supported the Mars differential.
NATURAL GAS REFERENCE PRICES
NYMEX natural gas prices declined throughout the quarter as an early spring
reduced heating demand and increased storage levels. Shale gas supply continues
to grow despite lower prices. This new supply and the warmer spring weather are
driving market concerns over higher storage levels despite the expected addition
of new storage capacity in 2010. Some near-term support for demand includes
industrial demand growth from a stronger economy, strong power demand due to an
expected warmer summer than 2009, low US hydro power generation and higher
coal-fired power costs. However, continuing weak gas prices are forecast as
strong supply additions are expected from shale gas, tight gas and new LNG
volumes imported from Russia and the Middle East.
37
OPERATING EXPENSES
Three Months Ended March 31
---------------------------------------------------
(Cdn$/boe) 2010 2009
---------------------------- ------------------------- -------------------------
Before After Before After
Royalties(1) Royalties Royalties(1) Royalties
------------ ------------ ------------ ------------
Conventional Oil and Gas 13.18 15.20 8.27 9.47
Syncrude 38.43 42.01 36.95 37.31
Average Oil and Gas 15.14 17.38 10.62 12.03
------------ ------------ ------------ ------------
(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.
HIGHER OPERATING EXPENSES REDUCED QUARTERLY NET INCOME BY $112 MILLION
Operating costs increased $112 million from the same period last year. The
majority of the increase relates to costs associated with our Long Lake project.
As of January 1, 2010, we ceased capitalizing our Long Lake operations as the
facility was reliably operating as designed following the successful turnaround
late last year. These costs are now included in operating expenses. The addition
of these costs increased our per-unit average cost as bitumen production is
still ramping up while costs at Long Lake are mostly fixed and do not vary
significantly with production rates. We expect our average per-unit operating
costs to decrease as bitumen production rates increase.
During the quarter, the strengthening Canadian dollar decreased our US dollar
denominated operating costs, reducing our corporate average operating cost by
$1.07/boe. Additionally, changes in production mix with natural declines in
Canada and Yemen offset by increases in the North Sea and the Gulf of Mexico,
decreased our corporate average by $0.11/boe.
In the UK North Sea, Buzzard operating costs were higher due to additional
maintenance expense and higher transportation tariffs. These higher costs,
combined with lower volumes due to temporary downtime, increased our corporate
average operating cost by $0.61/boe. Elsewhere in the UK North Sea, operating
costs increased our corporate average by $0.22/boe. At Ettrick, operating costs
per barrel are higher than our corporate average because of the costs associated
with the leased FPSO and from not being at full production rates yet. These
higher average operating costs have been partially offset by lower average
per-unit costs at Scott/Telford as a result of higher volumes.
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 $0.38/boe. In the US Gulf of Mexico, the effect of increased
operating costs due to higher repair and maintenance expenditures was partially
offset by higher volumes, increasing our corporate average operating cost by
$0.04/boe.
Natural declines in Canada reduced production volumes, increasing our corporate
average by $0.12/boe. At Syncrude, higher maintenance costs and lower production
volumes associated with the turnaround of the LC finer increased our corporate
average by $0.11/boe.
38
DEPRECIATION, DEPLETION, AMORTIZATION AND IMPAIRMENT (DD&A)
Three Months Ended March 31
---------------------------------------------------
(Cdn$/boe) 2010 2009
---------------------------- ------------------------- -------------------------
Before After Before After
Royalties(1) Royalties Royalties(1) Royalties
------------ ------------ ------------ ------------
Conventional Oil and Gas 16.79 19.35 18.58 21.27
Syncrude 7.03 7.68 6.46 6.53
Average Oil and Gas 16.03 18.40 17.59 19.91
------------ ------------ ------------ ------------
(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 $19 MILLION
Our average per-unit DD&A cost decreased $1.56/boe from the same period last
year. The stronger Canadian dollar reduced our corporate average by $2.08/boe as
depletion of our international and US assets is denominated in US dollars. This
was partially offset by changes in our production mix which increased our
average DD&A rate by $1.59/boe. The change in production mix was partially
driven by lower production at Buzzard, offset by new volumes at Ettrick and Long
Lake. Buzzard DD&A rates are lower than our corporate average while DD&A at
Ettrick and Long Lake is higher.
During the quarter, we began depleting our Long Lake assets. The Long Lake
depletion rate is higher than our corporate average and increased our
consolidated average depletion cost by $0.76/boe.
In the UK North Sea, our Buzzard depletion rate decreased from last year as
successful development drilling increased our proved reserve estimates at the
end of 2009. This lower depletion rate reduced our corporate average by
$0.60/boe. Elsewhere in the UK, successful development drilling at Telford
increased proved reserve estimates at the end of 2009, which significantly
reduced the Scott/Telford depletion rate. This was partially offset by new
volumes from the Ettrick field, decreasing our corporate average by $0.86/boe.
Depletion rates in Yemen increased our corporate average $0.33/boe. As the
fields mature and production declines, our capital is focused on accessing the
remaining reserves, thereby increasing our depletion rates. In the Gulf of
Mexico, positive reserve revisions and lower estimates for future abandonment
costs reduced our corporate average depletion rate of $1.04/boe.
Higher Canadian depletion costs increased our corporate average by $0.27/boe.
Our 2010 depletion rates are higher at our CBM and natural gas properties as
reserve estimates at the end of 2009 were reduced by lower gas prices. The
higher depletion rates on our natural gas properties were partially offset by
lower rates on our heavy oil properties, where we had positive price-related
proved reserves revisions at the end of 2009.
39
EXPLORATION EXPENSE
Three Months Ended March 31
---------------------------
2010 2009
---------------------------------------------------- ------------- -------------
Seismic 12 12
Unsuccessful Drilling 41 11
Other 40 30
------------- -------------
Total Exploration Expense 93 53
============= =============
New Growth Exploration 199 163
Geological and Geophysical Costs 12 12
------------- -------------
Total Exploration Expenditures 211 175
============= =============
Exploration Expense as a % of Exploration
Expenditures 44% 30%
------------- -------------
HIGHER EXPLORATION EXPENSE DECREASED NET INCOME FOR THE QUARTER BY $40 MILLION
Exploration expenditures increased $36 million or 22% from the same period last
year as we continue to invest in our core basins in the Gulf of Mexico, the
North Sea and Canada.
In the Eastern Gulf of Mexico, we made a significant oil discovery at
Appomattox, where we drilled an exploratory well and two appraisal sidetracks.
Appomattox is the third discovery in the area following previous successful
drilling at Shiloh and Vicksburg. Additional appraisal wells for Appomattox are
planned for later in the year and we are investigating development options for
Appomattox and Vicksburg, located six miles east. We have a 25% interest in
Vicksburg and a 20% interest in Appomattox and Shiloh, with Shell Offshore Inc.
operating all three.
In the UK, we are assessing development options for our Golden Eagle area to
determine the appropriate configuration. We are in the process of completing the
acquisition of additional land in the area and plan to drill an exploration well
here mid-year. The Golden Eagle area includes our 34% operated interest in
Golden Eagle and Hobby and our 46% operated interest in Pink. We plan to drill
up to five additional exploration and appraisal wells in 2010.
In Canada, we are investing in our shale gas project in the Dilly Creek area of
the Horn River basin in north-east British Columbia. We currently have six wells
on production and they are meeting expectations with respect to production and
decline profiles. During the quarter, we successfully drilled an eight well pad
to further test the play. These wells are expected to be on stream later this
year following completion operations. In north-east British Columbia, we have
approximately 90,000 acres in the Dilly Creek area and a further 38,000 acres in
the Cordova area, with a 100% working interest in each.
Exploration expense increased $40 million or 75% from the same period last year
as higher unsuccessful drilling costs were partially offset by a decrease in
exploration G&A. During the quarter, we drilled two unsuccessful wells in the
North Sea. The Brand well in Norway and the Deacon well in the UK failed to
encounter hydrocarbons and we expensed drilling costs of $25 million and $14
million, respectively.
40
ENERGY MARKETING
Three Months Ended March 31
---------------------------
2010 2009
---------------------------------------------------- ------------- -------------
Physical Sales (1) 10,114 9,945
Physical Purchases (1) (9,896) (9,802)
Net Financial Transactions (2) (64) 48
Change in Fair Market Value of Inventory (68) 76
------------- -------------
Marketing Revenue 86 267
Transportation Expense (122) (165)
Other (1) 5
------------- -------------
NET MARKETING REVENUE (37) 107
============= =============
CONTRIBUTION TO NET MARKETING REVENUE BY REGION
North America (35) 104
Asia 1 12
Europe (3) (9)
------------- -------------
NET MARKETING REVENUE (37) 107
DD&A (5) (4)
General and Administrative (21) (23)
Other (4) 3
------------- -------------
MARKETING CONTRIBUTION TO INCOME BEFORE
INCOME TAXES (67) 83
============= =============
NORTH AMERICA
NATURAL GAS
Physical Sales Volumes (3) (bcf/d) 4.8 5.1
Transportation Capacity (bcf/d) 1.5 1.6
Storage Capacity (bcf) 31.9 33.5
Financial Volumes (4) (bcf/d) 6.0 15.6
CRUDE OIL
Physical Sales Volumes (3) (mbbls/d) 754 806
Storage Capacity (mbbls) 2,968 2,757
Financial Volumes (4) (mbbls/d) 755 915
POWER
Physical Sales Volumes (3) (GWh/d) 10 5
Generation Capacity (MW) 87 87
ASIA
Physical Sales Volumes (3) (mbbls/d) 91 129
Financial Volumes (4) (mbbls/d) 290 322
EUROPE
Financial Volumes (4) (mbbls/d) 603 507
VALUE-AT-RISK
Quarter-end 13 19
High 15 24
Low 9 18
Average 12 20
------------- -------------
(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.
41
LOWER CONTRIBUTION FROM ENERGY MARKETING DECREASED NET INCOME BY $151 MILLION
During the quarter, we continued our strategic review resulting in the
successful sale of the European gas and power business, which generated $15
million of cash proceeds. We have substantially completed negotiations for the
sale of our North American natural gas business subject to finalizing
documentation and customary closing conditions. We expect to sign the agreement
in the second quarter and close the sale in the third quarter. The sale is
expected to be cash neutral and we expect to recognize a non-cash loss of
between $250 and $290 million. This loss primarily relates to the transfer of
long-term natural gas physical transportation commitments that are less valuable
with increased gas supplies that reduce the need for transport services.
Although volatile on a quarterly basis, we have had success with our marketing
business over the last 10 years generating about $800 million of positive cash
flow.
Results from energy marketing are lower than last year's results as a result of
strong crude oil results in the first quarter of 2009 and strong natural gas
income reported in the fourth quarter, together with lower results this quarter.
In 2010, the group's results were lower as global crude demand increased prices
and flattened the forward contango curve. Early in the first quarter, gains were
generated from blending physical crudes and inventory management strategies.
These were substantially offset late in the quarter by a flattening forward
contango curve, widening heavy differentials and a weaker US dollar. In 2009,
record results were generated from the steep crude oil forward price curve as
near-term crude oil prices were negatively impacted by the global economic
recession.
During the first quarter of 2010, our North America natural gas business
continued to face a challenging environment as declining natural gas spot prices
reduced the reported value of our gas inventories and transportation spreads
between producing and consuming regions remained narrow impacting our ability to
generate profits as we moved gas to different regions. These losses partially
offset related gains reported in the previous quarter.
The first quarter natural gas losses in 2009 were due to exiting the last of our
2008 basis trading positions as we eliminated this activity. Our inventory and
time spread strategy experienced losses in both the first quarters of 2010 and
2009, largely related to the declining value of inventory. Typically, natural
gas prices fall in the first part of the year as winter demand declines and the
injection season begins. Our inventory is valued at the spot market price and
losses were reported in the first quarter as natural gas prices decreased
relative to year end. Losses on this strategy were consistent year over year. We
recognized gains in the fourth quarter as spot natural gas prices increased from
stronger winter demand.
Results from our marketing group vary by quarter and historical results are not
necessarily indicative of results to be expected in future quarters. Quarterly
marketing results depend on a variety of factors such as market volatility,
changes in time and location spreads, the manner in which we use our storage and
transportation assets and the change in value of the financial instruments we
use to hedge these assets.
COMPOSITION OF NET MARKETING REVENUE
Three Months Ended March 31
---------------------------
2010 2009
--------------------------------------------------- --------------- ------------
Trading Activities (Physical and related Financial) (38) 101
Non-Trading Activities 1 6
--------------- ------------
Total Net Marketing Revenue (37) 107
=============== ============
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.
42
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, 2009.
At March 31, 2010, the fair value of our derivative contracts in our energy
marketing trading activities was $43 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 1-3 4-5 More than
1 year years years 5 years Total
--------- ------- ------- ---------- -----
Level 1 - Actively Quoted Markets (68) (79) (9) - (156)
Level 2 - Based on Other Observable
Pricing Inputs 93 52 10 6 161
Level 3 - Based on Unobservable
Pricing Inputs 17 21 - - 38
--------- ------- ------- ---------- -----
Total 42 (6) 1 6 43
========= ======= ======= ========== =====
CHANGES IN FAIR VALUE OF DERIVATIVE CONTRACTS
Total
------------------------------------------------------------------- ------------
Fair Value at December 31, 2009 23
Change in Fair Value of Contracts 19
Net Losses (Gains) on Contracts Closed 1
Changes in Valuation Techniques and Assumptions (1) -
------------
Fair Value at March 31, 2010 43
============
(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 1.2 years. Those maturing beyond one year
primarily relate to North American natural gas positions.
CHEMICALS
HIGHER CHEMICALS CONTRIBUTION INCREASED NET INCOME BY $4 MILLION
Chlor-alkali and chlorate sales revenues in North America were lower during the
quarter than the same period last year. Chlorate revenue decreased 8% despite a
12% increase in volumes, as the average price received was 18% lower than last
year. Chlor-alkali sale volumes remained consistent; however, price decreases
due to competition reduced our revenue by 12%. In Brazil, our revenues were
consistent with the first quarter of 2009, as the impact of a slight increase in
volumes was offset by a small decrease in price.
The stronger Canadian dollar at March 31, 2010 generated foreign exchange gains
of $7 million on the Canexus US-dollar denominated debt. This was higher than
the first quarter of 2009 when our chemicals operations recognized foreign
exchange translation losses of $6 million.
43
CORPORATE EXPENSES
GENERAL AND ADMINISTRATIVE (G&A)
Three Months Ended March 31
---------------------------
2010 2009
--------------------------------------------------- -------------- -------------
General and Administrative Expense before
Stock-Based Compensation 116 100
Stock-Based Compensation (1) 2 -
-------------- -------------
Total General and Administrative Expense 118 100
============== =============
(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 $18 MILLION
G&A expenditures before stock-based compensation increased 16% from the first
quarter of 2009 primarily as a result of higher employee costs.
Fluctuations in our share price create volatility in our net income as we
account for stock-based compensation using the intrinsic-value method.
Stock-based compensation increased marginally during the quarter as our share
price was largely unchanged from the end of 2009. Cash payments made in
connection with our stock-based compensation programs during the three month
period ended March 31, 2010 were $3 million (2009 - nil).
INTEREST
Three Months Ended March 31
---------------------------
2010 2009
--------------------------------------------------- -------------- -------------
Interest 98 94
Less: Capitalized (18) (26)
-------------- -------------
Net Interest Expense 80 68
============== =============
Effective Interest Rate 5.2% 4.9%
-------------- -------------
HIGHER NET INTEREST EXPENSE REDUCED NET INCOME BY $12 MILLION
Our financing costs increased $4 million from the first quarter of 2009. In July
2009, we issued US$1 billion of long-term notes and additional interest expense
in the quarter related to this debt was $17 million. This was partially offset
by the strengthening Canadian dollar which decreased our US-denominated interest
expense by $13 million.
Capitalized interest was $8 million lower than 2009 as we completed major
development projects. Construction completion of our Long Lake Phase 1
facilities and our Ettrick project in the UK North Sea reduced capitalized
interest by $10 million and $8 million, respectively. These decreases were
partially offset by $6 million of additional capitalized interest on our major
development project at Usan, offshore West Africa. We also continue to
capitalize interest on the construction of the fourth platform at Buzzard and on
our Chemicals technical conversion project in North Vancouver.
INCOME TAXES
Three Months Ended March 31
---------------------------
2010 2009
--------------------------------------------------- -------------- -------------
Current 259 118
Future (100) (87)
-------------- -------------
Total Provision for Income Taxes 159 31
============== =============
HIGHER TAXES REDUCED NET INCOME BY $128 MILLION
Stronger commodity prices in the first quarter compared to the same period last
resulted in an increase to our tax expense. Our future tax expense in 2009 also
included the effect of a reduction in Canadian tax rates. Our income tax
provision includes current taxes in the United Kingdom, Yemen, Norway, Colombia
and the United States.
44
OTHER
Three Months Ended March 31
---------------------------
2010 2009
--------------------------------------------------- -------------- -------------
Decrease in Fair Value of Crude Oil Put Options (16) (16)
-------------- -------------
In the fourth quarter of 2009, we purchased put options on 90,000 bbls/d of our
2010 crude oil production. These options establish a WTI floor price of
US$50/bbl and provide a base level of price protection without limiting our
upside to higher prices. Options on 60,000 bbls/d settle monthly, while the
remaining options settle annually. These options are recorded at fair value
throughout their term. As a result, changes in forward crude oil prices create
gains or losses on these options at each period end. The put options were
purchased for $39 million and are carried at fair value. At March 31, 2010,
higher crude oil prices reduced the fair value of the options to approximately
$1 million, $16 million lower than the end of 2009. In 2009, we recorded a fair
value loss of $16 million on our 2009 crude oil put option program.
LIQUIDITY AND CAPITAL RESOURCES
CAPITAL STRUCTURE
March 31 December 31
2010 2009
---------------------------------------------------- ------------- -------------
NET DEBT (1)
Bank Debt 1,770 1,803
Public Senior Notes 4,831 4,982
------------- -------------
Total Senior Debt 6,601 6,785
Subordinated Debt 453 466
------------- -------------
Total Debt 7,054 7,251
Less: Cash and Cash Equivalents (1,997) (1,700)
------------- -------------
TOTAL NET DEBT 5,057 5,551
============= =============
EQUITY 7,827 7,646
============= =============
(1) Includes all of our borrowings and is calculated as long-term debt and
short-term borrowings less cash and cash equivalents.
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:
--------------------------------------------------------------------------------
Capital Investment (556)
Cash Flow from Operating Activities (1) 798
-----------
Excess Cash Generated 242
Dividends on Common Shares (26)
Issue of Common Shares 25
Changes in Restricted Cash 15
Foreign Exchange Translation of US-dollar Debt and Cash 141
Other 97
-----------
-----------
Decrease in Net Debt 494
===========
(1) Includes changes in non-cash working capital. For the three months ended
March 31, 2010, $256 million was included as a source of cash flow.
Our net debt decreased approximately $500 million from December 31, 2009 as our
cash flow from operating activities exceeded our first quarter capital
investment by $242 million. Additionally, the stronger Canadian dollar relative
to the US dollar, decreased our US dollar denominated debt and US dollar cash.
This reduced net debt by $141 million. Our available liquidity at March 31, 2010
was approximately $3.6 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 periodically 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.
45
CHANGE IN WORKING CAPITAL
March 31 December 31 Increase/
2010 2009 (Decrease)
---------------------------------------- ------------ ------------ ------------
Cash and Cash Equivalents 1,997 1,700 297
Restricted Cash 178 198 (20)
Accounts Receivable 2,635 2,788 (153)
Inventories and Supplies 574 680 (106)
Accounts Payable and Accrued Liabilities (3,084) (3,038) (46)
Other (1) 70 (71)
------------ ------------ ------------
Net Working Capital 2,299 2,398
============ ============
We generated cash from reducing working capital requirements since the end of
2009. Cash was generated by selling commodity inventory held by our energy
marketing group and timing of crude oil sales in the UK. We sold natural gas
trading inventory during the winter heating season. In addition, we are reducing
our trading activity to focus on supporting our core physical business as a
producer/marketer. Working capital was also reduced from the timing of current
tax payments to governments.
At March 31, 2010, our restricted cash consists of margin deposits of $178
million (December 31, 2009 - $198 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.
OUTLOOK FOR REMAINDER OF 2010
We expect our 2010 production to range between 230,000 and 280,000 boe/d
(200,000 and 250,000 boe/d after royalties). We expect to continue to fund our
2010 capital investment program using cash flow from operating activities.
Our future liquidity and ability to fully 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
approximately 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$50/bbl is projected to increase or decrease our cash flow from
operating activities, after cash taxes, by approximately $36 million for the
remainder of 2010. 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 $27 million for the remainder of 2010. While commodity prices can
fluctuate significantly in the short term, we believe that over the longer term,
commodity prices will continue to remain strong 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.
During the first three months of 2010, we have incurred approximately 20% of our
2010 capital budget and generated cash flow from operating activities in excess
of our capital investment by $242 million. We currently have approximately $2
billion of cash and cash equivalents on hand and as well as significant undrawn
committed credit facilities available. At March 31, 2010, 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$385 million was used to support
outstanding letters of credit. We also have approximately $466 million of
undrawn, uncommitted, unsecured credit facilities, of which $116 million was
used to support outstanding letters of credit. The average length-to-maturity of
our public debt is approximately 17 years.
46
CONTRACTUAL OBLIGATIONS, COMMITMENTS AND GUARANTEES
We have assumed various contractual obligations and commitments in the normal
course of our operations and financing activities. We included these obligations
and commitments in our MD&A in our 2009 Form 10-K.
During the quarter, we sold our European gas and power marketing business. We
agreed to maintain our parental guarantees to the existing counterparties until
the purchaser is able to replace them. The guarantees expire at the earlier of
the purchaser replacing the guarantees and July 25, 2010. We are obligated to
perform under the guarantees only if the purchaser does not meet its obligations
to the counterparties. Our total exposure is $275 million for which the
purchaser has provided us an indemnity and a letter of credit from a highly
rated financial institution.
There have been no other 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 2009 Form 10-K. There have been no significant developments
since year-end.
47
NEW ACCOUNTING PRONOUNCEMENTS
CANADIAN PRONOUNCEMENTS
INTERNATIONAL FINANCIAL REPORTING STANDARDS ADOPTION PLAN
We are required to adopt International Financial Reporting Standards (IFRS) for
our interim and annual financial reporting purposes beginning January 1, 2011. A
project team, consisting of dedicated and experienced personnel who have IFRS
knowledge, has been set up to manage this transition and to ensure successful
implementation within the required timeframe.
We provided an update on the status of our project in our 2009 Annual Report on
Form 10-K, including a summary of accounting differences between Canadian GAAP
and IFRS.
The following chart is a summary of our progress since our previous update.
Significant changes are highlighted below:
------------------------------------------- ------------------------------------------ -----------------------------------------
KEY ACTIVITY KEY MILESTONE STATUS
------------------------------------------- ------------------------------------------ -----------------------------------------
Financial Information
------------------------------------------- ------------------------------------------ -----------------------------------------
o Identify differences between Canadian o Comprehensive analysis of IFRS o Comprehensive analysis completed
GAAP and IFRS differences identified in the mid 2009
o Revise accounting policies under IFRS diagnostics phase o Received senior management approval
o Identify potential adjustments to o Senior management approval of IFRS of IFRS accounting policies
initial IFRS financial statements accounting policies o Areas of potential adjustment to
o Develop IFRS-compliant financial o Develop draft IFRS financial opening balance sheet identified
statements, including transition statements and disclosures o ANALYSIS TO SUPPORT OPENING
period disclosures BALANCE SHEET ADJUSTMENTS IS
UNDERWAY
o DRAFT IFRS FINANCIAL STATEMENTS AND
NOTE DISCLOSURES ARE SUBSTANTIALLY
COMPLETE
------------------------------------------- ------------------------------------------ -----------------------------------------
Training and Communication
------------------------------------------- ------------------------------------------ -----------------------------------------
o Develop and deliver targeted IFRS o Delivery of training in 2009 o Targeted training completed in 2009
training to employees and management targeted to affected employees o Strategy for follow-up training in
o Ensure internal and external o Ongoing communication with major 2010 developed
stakeholders receive ongoing internal and external stakeholders o Regular communication with Project
appropriate communications Steering Committee, senior
o Develop and deliver targeted IFRS management and Audit Committee
training to senior management and throughout the year
Board of Directors o Quarterly disclosure of project
status in MD&A
------------------------------------------- ------------------------------------------ -----------------------------------------
Information Technology
------------------------------------------- ------------------------------------------ -----------------------------------------
o Ensure systems are able to adequately o Be IFRS data capture ready o System testing for IFRS data
support conversion to IFRS and January 1, 2010 capture complete
ongoing financial reporting o Ensure dual GAAP reporting o Dual GAAP reporting capability
capability throughout 2010 testing complete
o IFRS DATA CAPTURE IN THE
FINANCIAL SYSTEM HAS COMMENCED
------------------------------------------- ------------------------------------------ -----------------------------------------
Business Process
------------------------------------------- ------------------------------------------ -----------------------------------------
o Ensure business processes and control o Implement necessary business process o Necessary changes to business
environment properly support and key control changes to ensure process have been designed
conversion to IFRS and ongoing adequate internal control over o Key controls designed to ensure
financial reporting financial reporting adequate internal control over
financial reporting on IFRS results
throughout 2010
------------------------------------------- ------------------------------------------ -----------------------------------------
At this time, we cannot quantify the impact that the adoption of IFRS will have
on our future results of operations or financial position. Additional disclosure
of the key elements of our plan and progress on the project will be provided as
we move toward the changeover date. We continue to monitor the development of
new standards and any changes will be incorporated as required.
US PRONOUNCEMENTS
In January 2010, the Financial Accounting Standards Board (FASB) issued guidance
to improve fair value measurement disclosures. The guidance requires entities to
describe transfers between the three levels of the fair value hierarchy and
present items separately in the level 3 reconciliation. This guidance is
consistent with fair value measurement disclosures adopted for Canadian GAAP in
2009. Adoption of this guidance did not have an impact on our results of
operations or financial position.
48
EQUITY SECURITY REPURCHASES
During the quarter, we made no purchases of our own equity securities.
SUMMARY OF QUARTERLY RESULTS
2008 | 2009 | 2010
----------------------------|--------------------------------------|---------
(Cdn$ millions, except per share amounts) Jun Sep Dec | Mar Jun Sep Dec | Mar
------------------------------------------------- --------- --------- --------|--------- --------- --------- --------|---------
Net Sales 2,071 2,213 1,270 | 1,048 1,200 1,097 1,550 | 1,501
| |
Net Income (Loss) 380 886 (181)| 135 20 122 259| 185
| |
Earnings (Loss) Per Common Share ($/share) | |
Basic 0.72 1.68 (0.35)| 0.26 0.04 0.23 0.50 | 0.35
Diluted 0.70 1.66 (0.35)| 0.26 0.04 0.23 0.49 | 0.35
--------- --------- --------|--------- --------- --------- --------|---------
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 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.
49
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;
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
2009 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 March 31, 2010:
o over 96% of our credit exposures were investment grade;
o approximately 70% of our credit exposures were with a diverse group of
integrated oil companies, crude oil refiners and marketers, and large
utilities; and
o only two counterparties individually made up more than 10% of our credit
exposure. These counterparties are major integrated oil companies with
strong investment grade credit ratings.
Further information presented on market risks can be found in Item 7A on pages
92 - 94 in our 2009 Form 10-K and have not materially changed since December 31,
2009.
50
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.
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 during the first three months of 2010 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
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 April 30, 2010.
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
