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 June 30, 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 June 30, 2010, there were 524,565,491 common shares issued and outstanding.
1
NEXEN INC.
INDEX
PART I FINANCIAL INFORMATION Page
Item 1. Unaudited Consolidated Financial Statements ..................3
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations (MD&A) ..................33
Item 3. Quantitative and Qualitative Disclosures about Market Risk ..56
Item 4. Controls and Procedures .....................................56
PART II OTHER INFORMATION
Item 1. Legal Proceedings ...........................................57
Item 1A. Risk Factors.................................................57
Item 6. Exhibits ....................................................58
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
Gj = Gigajoules
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 June 30, 2010, the noon-day exchange rate was US$0.9429 for Cdn$1.00, as
reported by the Bank of Canada.
2
PART I
ITEM 1. UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
TABLE OF CONTENTS
Page
Unaudited Consolidated Statement of Income
for the Three and Six Months Ended June 30, 2010 and 2009......................4
Unaudited Consolidated Balance Sheet
as at June 30, 2010 and December 31, 2009......................................5
Unaudited Consolidated Statement of Cash Flows
for the Three and Six Months Ended June 30, 2010 and 2009......................6
Unaudited Consolidated Statement of Equity
for the Three and Six Months Ended June 30, 2010 and 2009......................7
Unaudited Consolidated Statement of Comprehensive Income
for the Three and Six Months Ended June 30, 2010 and 2009......................8
Notes to Unaudited Consolidated Financial Statements...........................9
3
NEXEN INC.
UNAUDITED CONSOLIDATED STATEMENT OF INCOME
FOR THE THREE AND SIX MONTHS ENDED JUNE 30
Three Months Six Months
Ended June 30 Ended June 30
(Cdn$ millions, except per share amounts) 2010 2009 2010 2009
---------------------------------------------------------------------------------------------------------------------------
REVENUES AND OTHER INCOME
Net Sales 1,399 1,138 2,831 2,142
Marketing and Other (Note 14) 164 82 315 339
--------------------------------------------------------
1,563 1,220 3,146 2,481
--------------------------------------------------------
EXPENSES
Operating 399 295 798 575
Depreciation, Depletion, Amortization and Impairment 391 381 757 758
Transportation and Other 159 229 359 426
General and Administrative 70 161 184 255
Exploration 50 77 143 130
Interest (Note 9) 77 74 157 142
--------------------------------------------------------
1,146 1,217 2,398 2,286
--------------------------------------------------------
INCOME FROM CONTINUING OPERATIONS BEFORE PROVISION
FOR INCOME TAXES 417 3 748 195
--------------------------------------------------------
PROVISION FOR (RECOVERY OF) INCOME TAXES
Current 264 206 523 324
Future (84) (228) (189) (309)
--------------------------------------------------------
180 (22) 334 15
--------------------------------------------------------
NET INCOME FROM CONTINUING OPERATIONS BEFORE NON-
CONTROLLING INTERESTS 237 25 414 180
Less: Net Income (Loss) Attributable to Canexus
Non-Controlling Interests (5) 2 - 5
--------------------------------------------------------
NET INCOME FROM CONTINUING OPERATIONS ATTRIBUTABLE
TO NEXEN INC. 242 23 414 175
Net Income (Loss) from Discontinued
Operations (Note 15) 13 (3) 26 (20)
--------------------------------------------------------
NET INCOME ATTRIBUTABLE TO NEXEN INC. 255 20 440 155
========================================================
EARNINGS PER COMMON SHARE FROM
CONTINUING OPERATIONS ($/share)
(Note 16)
Basic 0.46 0.05 0.79 0.33
========================================================
Diluted 0.46 0.05 0.79 0.33
========================================================
Earnings Per Common Share ($/share) (Note 16)
Basic 0.49 0.04 0.84 0.30
========================================================
Diluted 0.49 0.04 0.84 0.30
========================================================
SEE ACCOMPANYING NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS.
4
NEXEN INC.
UNAUDITED CONSOLIDATED BALANCE SHEET
June 30 December 31
(Cdn$ millions, except share amounts) 2010 2009
------------------------------------------------------------------------------------------------------------------------------
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents 970 1,700
Restricted Cash 113 198
Accounts Receivable (Note 2) 2,675 2,788
Inventories and Supplies (Note 3) 621 680
Other 106 185
------------------------------
Total Current Assets 4,485 5,551
------------------------------
PROPERTY, PLANT AND EQUIPMENT
Net of Accumulated Depreciation, Depletion, Amortization and
Impairment of $10,129 (December 31, 2009 - $10,807) 15,755 15,492
GOODWILL 343 339
FUTURE INCOME TAX ASSETS 1,340 1,148
DEFERRED CHARGES AND OTHER ASSETS (NOTE 5) 289 370
ASSETS HELD FOR SALE (NOTE 15) 303 -
------------------------------
TOTAL ASSETS 22,515 22,900
==============================
LIABILITIES
CURRENT LIABILITIES
Short-Term Borrowings (Note 9) 158 -
Accounts Payable and Accrued Liabilities (Note 8) 3,101 3,038
Accrued Interest Payable 89 89
Dividends Payable 26 26
------------------------------
Total Current Liabilities 3,374 3,153
------------------------------
LONG-TERM DEBT (Note 9) 6,283 7,251
FUTURE INCOME TAX LIABILITIES 2,891 2,811
ASSET RETIREMENT OBLIGATIONS (Note 11) 859 1,018
DEFERRED CREDITS AND OTHER LIABILITIES (Note 12) 879 1,021
LIABILITIES ASSOCIATED WITH ASSETS HELD FOR SALE (Note 15) 149 -
EQUITY
Nexen Inc. Shareholders' Equity
Common Shares, no par value
Authorized: Unlimited
Outstanding: 2010 - 524,565,491 shares
2009 - 522,915,843 shares 1,088 1,049
Contributed Surplus - 1
Retained Earnings 7,110 6,722
Accumulated Other Comprehensive Loss (189) (190)
------------------------------
Total Nexen Inc. Shareholders' Equity 8,009 7,582
Canexus Non-Controlling Interests 71 64
------------------------------
TOTAL EQUITY 8,080 7,646
COMMITMENTS, CONTINGENCIES AND GUARANTEES (NOTE 17)
------------------------------
TOTAL LIABILITIES AND EQUITY 22,515 22,900
==============================
SEE ACCOMPANYING NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS.
5
NEXEN INC.
UNAUDITED CONSOLIDATED STATEMENT OF CASH FLOWS
FOR THE THREE AND SIX MONTHS ENDED JUNE 30
Three Months Six Months
Ended June 30 Ended June 30
(Cdn$ millions) 2010 2009 2010 2009
---------------------------------------------------------------------------------------------------------------------------
OPERATING ACTIVITIES
Net Income from Continuing Operations 237 25 414 180
Net Income (Loss) from Discontinued Operations 13 (3) 26 (20)
Charges and Credits to Income not Involving
Cash (Note 18) 270 394 535 713
Exploration Expense 50 77 143 130
Changes in Non-Cash Working Capital (Note 18) (58) (340) 198 80
Other (2) (44) (8) (185)
--------------------------------------------------------
510 109 1,308 898
FINANCING ACTIVITIES
Proceeds from Short-Term Borrowings 156 - 156 -
Proceeds from (Repayment of) Term Credit
Facilities, Net (1,077) 632 (1,077) 1,643
Proceeds from Canexus Term Credit Facilities, Net 46 42 68 52
Dividends Paid on Common Shares (26) (26) (52) (52)
Distributions Paid to Canexus Non-Controlling Interests (2) (4) (7) (7)
Issue of Common Shares and Exercise of Tandem
Options for Shares 10 7 35 30
Other (14) - (13) (1)
--------------------------------------------------------
(907) 651 (890) 1,665
INVESTING ACTIVITIES
Capital Expenditures
Exploration and Development (747) (631) (1,239) (1,335)
Proved Property Acquisitions - - - (755)
Energy Marketing, Chemicals, Corporate and Other (70) (84) (134) (129)
Proceeds on Disposition of Assets 81 1 96 15
Changes in Non-Cash Working Capital (Note 18) (13) (74) 75 (55)
Changes in Restricted Cash 68 67 83 (247)
Other (4) 1 (7) (1)
--------------------------------------------------------
(685) (720) (1,126) (2,507)
EFFECT OF EXCHANGE RATE CHANGES ON CASH AND
CASH EQUIVALENTS 55 (120) (22) (85)
--------------------------------------------------------
DECREASE IN CASH AND CASH EQUIVALENTS (1,027) (80) (730) (29)
CASH AND CASH EQUIVALENTS - BEGINNING OF PERIOD 1,997 2,054 1,700 2,003
--------------------------------------------------------
CASH AND CASH EQUIVALENTS - END OF PERIOD (1) 970 1,974 970 1,974
============== =========================================
(1) Cash and cash equivalents at June 30, 2010 consist of cash of $237 million
and short-term investments of $733 million (June 30, 2009 - cash of $227
million and short-term investments of $1,747 million).
SEE ACCOMPANYING NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS.
6
NEXEN INC.
UNAUDITED CONSOLIDATED STATEMENT OF EQUITY
FOR THE THREE AND SIX MONTHS ENDED JUNE 30
Three Months Six Months
Ended June 30 Ended June 30
(Cdn$ millions) 2010 2009 2010 2009
----------------------------------------------------------------------------------------------------------------------------
COMMON SHARES, Beginning of Period 1,076 1,004 1,049 981
Issue of Common Shares 8 6 32 29
Exercise of Tandem Options for Shares 2 1 3 1
Accrued Liability Relating to Tandem Options
Exercised for Common Shares 2 - 4 -
---------------------------------------------------------
Balance at End of Period 1,088 1,011 1,088 1,011
=========================================================
CONTRIBUTED SURPLUS, Beginning of Period - 2 1 2
Exercise of Tandem Options - - (1) -
---------------------------------------------------------
Balance at End of Period - 2 - 2
=========================================================
RETAINED EARNINGS, Beginning of Period 6,881 6,399 6,722 6,290
Net Income Attributable to Nexen Inc. 255 20 440 155
Dividends Paid on Common Shares (Note 13) (26) (26) (52) (52)
---------------------------------------------------------
Balance at End of Period 7,110 6,393 7,110 6,393
=========================================================
ACCUMULATED OTHER COMPREHENSIVE LOSS,
Beginning of Period (201) (128) (190) (134)
Other Comprehensive Income (Loss) Attributable
to Nexen Inc. 12 (29) 1 (23)
---------------------------------------------------------
Balance at End of Period (1) (189) (157) (189) (157)
=========================================================
(1) Comprised of unrealized foreign currency translation adjustment.
CANEXUS NON-CONTROLLING INTERESTS,
Beginning of Period 71 52 64 52
Net Income Attributable to Non-Controlling Interests (6) 6 - 9
Distributions Paid to Non-Controlling Interests (6) (5) (10) (9)
Issue of Partnership Units to Non-Controlling
Interests 12 1 17 2
---------------------------------------------------------
Balance at End of Period 71 54 71 54
=========================================================
SEE ACCOMPANYING NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS.
7
NEXEN INC.
UNAUDITED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
FOR THE THREE AND SIX MONTHS ENDED JUNE 30
Three Months Six Months
Ended June 30 Ended June 30
(Cdn$ millions) 2010 2009 2010 2009
---------------------------------------------------------------------------------------------------------------------------
NET INCOME ATTRIBUTABLE TO NEXEN INC. 255 20 440 155
Other Comprehensive Income (Loss),
Net of Income Taxes:
Foreign Currency Translation Adjustment
Net Gains (Losses) on Investment in
Self-Sustaining Foreign Operations 209 (459) 62 (285)
Net Gains (Losses) on Foreign-Denominated
Debt Hedges of Self-Sustaining Foreign
Operations (1) (197) 430 (61) 262
--------------------------------------------------------
Other Comprehensive Income (Loss) Attributable
to Nexen Inc. 12 (29) 1 (23)
--------------------------------------------------------
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE
TO NEXEN INC. 267 (9) 441 132
========================================================
(1) Net of income tax recovery for the three months ended June 30, 2010 of $28
million (2009 - $62 million expense) and net of income tax recovery for the
six months ended June 30, 2010 of $8 million (2009 - $38 million expense).
SEE ACCOMPANYING NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS.
8
NEXEN INC.
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
Cdn$ 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 June 30, 2010 and December 31,
2009 and the results of our operations and our cash flows for the three and six
months ended June 30, 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 and six months ended June 30, 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 July 14, 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
In early 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 continuing operations for the three and six
months ended June 30, 2010 increased by $11 million and $24 million, net income
from continuing operations decreased by $7 million and $16 million, and earnings
per common share decreased by $0.02/share and $0.04/share, respectively.
9
2. ACCOUNTS RECEIVABLE
June 30 December 31
2010 2009
-----------------------------------------------------------------------------------------------------------------------
Trade
Energy Marketing 1,515 1,410
Energy Marketing Derivative Contracts (Note 6) 260 466
Oil and Gas 793 823
Chemicals and Other 49 44
---------------------------------------
2,617 2,743
Non-Trade 111 99
---------------------------------------
2,728 2,842
Allowance for Doubtful Receivables (53) (54)
---------------------------------------
Total 2,675 2,788
=======================================
3. INVENTORIES AND SUPPLIES
June 30 December 31
2010 2009
-----------------------------------------------------------------------------------------------------------------------
Finished Products
Energy Marketing 473 548
Oil and Gas 32 25
Chemicals and Other 10 12
---------------------------------------
515 585
Work in Process 7 7
Field Supplies 99 88
---------------------------------------
Total 621 680
==================== ==================
4. SUSPENDED EXPLORATION WELL COSTS
The following table shows the changes in capitalized exploratory well costs
during the six months ended June 30, 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.
Six Months Year Ended
Ended June 30 December 31
2010 2009
-----------------------------------------------------------------------------------------------------------------------
Beginning of Period 794 518
Exploratory Well Costs Capitalized Pending the Determination of
Proved Reserves 206 396
Capitalized Exploratory Well Costs Charged to Expense (2) (56)
Transfers to Wells, Facilities and Equipment Based on
Determination of Proved Reserves (1) (21)
Effects of Foreign Exchange Rate Changes 7 (43)
---------------------------------------
End of Period 1,004 794
=======================================
10
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 as at June 30, 2010.
United United
Aging of Suspended Exploration Wells Kingdom Canada States Nigeria Total
------------------------------------------------------------------------------------------------------------------------------
Less than 1 year 60 162 89 13 324
1-3 years 136 348 44 - 528
4-5 years 57 - 74 - 131
Greater than 5 years - - - 21 21
------------------------------------------------------------------------------
Total 253 510 207 34 1,004
==============================================================================
Number of Wells Capitalized for Greater than
One Year 8 13 2 1 24
==============================================================================
As at June 30, 2010, we have exploratory costs that have been capitalized for
more than one year relating to our shale gas exploratory activities in Canada
($348 million), interests in eight exploratory blocks in the North Sea ($193
million), two exploratory blocks in the Gulf of Mexico ($118 million), and our
interest in an exploratory block offshore Nigeria ($21 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.
5. DEFERRED CHARGES AND OTHER ASSETS
June 30 December 31
2010 2009
------------------------------------------------------------------------------------------------------------------------------
Long-Term Energy Marketing Derivative Contracts (Note 6) 160 225
Defined Benefit Pension Assets 53 60
Long-Term Capital Prepayments 23 27
Other 53 58
-------------------------------------------
Total 289 370
===========================================
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 in the following section details our derivatives and fair values as at
June 30, 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 June 30, 2010, the estimated fair value of our long-term debt was
$6,736 million (December 31, 2009 - $7,594 million) as compared to the carrying
value of $6,283 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:
June 30 December 31
2010 2009
---------------------------------------------------------------------------------------------------------------
Commodity Contracts 260 463
Foreign Exchange Contracts - 3
---------------------------------------
Accounts Receivable (Note 2) 260 466
---------------------------------------
Commodity Contracts 160 225
---------------------------------------
Deferred Charges and Other Assets (Note 5) (1) 160 225
---------------------------------------
Total Trading Derivative Assets 420 691
=======================================
Commodity Contracts 202 410
Foreign Exchange Contracts 6 46
---------------------------------------
Accounts Payable and Accrued Liabilities (Note 8) 208 456
---------------------------------------
Commodity Contracts 156 212
---------------------------------------
Deferred Credits and Other Liabilities (Note 12) (1) 156 212
---------------------------------------
Total Trading Derivative Liabilities 364 668
=======================================
Total Net Trading Derivative Contracts 56 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:
June 30 December 31
2010 2009
---------------------------------------------------------------------------------------------------------------
Current Trading Assets 1,687 2,625
Non-Current Trading Assets 511 716
---------------------------------------
Total Trading Derivative Assets 2,198 3,341
=======================================
Current Trading Liabilities 1,635 2,615
Non-Current Trading Liabilities 507 703
---------------------------------------
Total Trading Derivative Liabilities 2,142 3,318
=======================================
---------------------------------------
Total Net Trading Derivative Contracts 56 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 and six months ended June 30, 2010, the following
trading revenues were recognized in marketing and other income:
Three Months Six Months
Ended June 30 Ended June 30
2010 2010
---------------------------------------------------------------------------------------------------------------
Commodity 113 204
Foreign Exchange (1) (6)
---------------------------------------
Marketing Revenue 112 198
=======================================
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 and six months ended June 30, 2010, are as
follows:
Three Months Six Months
Ended June 30 Ended June 30
2010 2010
---------------------------------------------------------------------------------------------------------------
Natural Gas bcf/d 5.5 9.1
Crude Oil mmbbls/d 3.6 3.4
Power GWh/d 0.5 0.9
Foreign Exchange US$ millions 834 1,621
Foreign Exchange Euro millions - 53
---------------------------------------
(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:
June 30 December 31
2010 2009
---------------------------------------------------------------------------------------------------------------
Accounts Receivable 2 13
Deferred Charges and Other Assets (1) - 4
---------------------------------------
Total Non-Trading Derivative Assets 2 17
=======================================
Accounts Payable and Accrued Liabilities 13 26
---------------------------------------
Total Non-Trading Derivative Liabilities 13 26
=======================================
Total Net Non-Trading Derivative Assets (2) (11) (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.
13
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. Lower forward crude
oil prices at June 30, 2010 compared to the end of the previous quarter
increased the fair value of the options to approximately $2 million.
Change in Fair Value
---------------------------------
Three Months Six Months
Ended Ended
Notional Average Fair June 30, June 30,
Volumes Term Floor Price Value 2010 2010
------------------------------------------------------------------------------------------------------------------------------
(bbls/d) (US$/bbl)
WTI Crude Oil Put Options (monthly) 60,000 2010 50 2 1 (11)
WTI Crude Oil Put Options (annual) 30,000 2010 50 - - (4)
-------------------------------------------
2 1 (15)
===========================================
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.
Change in Fair Value
---------------------------------
Three Months Six Months
Ended Ended
Notional Average Fair June 30, June 30,
Volumes Term Floor Price Value 2010 2010
------------------------------------------------------------------------------------------------------------------------------
(Gj/d) ($/Gj)
Fixed-Price Natural Gas Contracts 15,514 2010 2.28 (3) - (4)
Natural Gas Swaps 15,514 2010 7.60 (10) - 4
-------------------------------------------
(13) - -
===========================================
(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 June 30, 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 June 30, 2010 Level 1 Level 2 Level 3 Total
----------------------------------------------------------------------------------------------------------------------------
Commodity Contracts (85) 123 24 62
Foreign Exchange Contracts - (6) - (6)
-------------------------------------------------------
Trading Derivatives (85) 117 24 56
Non-Trading Derivatives - (11) - (11)
-------------------------------------------------------
Total (85) 106 24 45
=======================================================
14
A reconciliation of changes in the fair value of our derivatives classified as
Level 3 for the six months ended June 30, 2010 is provided below:
Level 3
-------------------------------------------------------------------------------------------
Beginning of Period 42
Realized and Unrealized Gains (Losses) (5)
Purchases -
Settlements (13)
Transfers Into Level 3 -
Transfers Out of Level 3 -
-------------
End of Period 24
=============
Unsettled gains relating to instruments still held as of June 30, 2010 (5)
=============
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 at June 30, 2010 would change by $12
million (December 31, 2009 - $12 million).
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.
15
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.
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 and six months ended June 30, 2010 are as follows:
Three Months Six Months
Ended June 30 Ended June 30
Value-at-Risk 2010 2009 2010 2009
-------------------------------------------------------------------------------------------------------------------
Period End 8 15 8 15
High 15 19 15 24
Low 7 13 7 13
Average 12 15 12 17
------------------------------------------------------
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.
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 June 30, 2010 and December 31, 2009 are as follows:
June 30 December 31
(US$ millions) 2010 2009
-----------------------------------------------------------------------------------------------------------------
Net Investment in Self-Sustaining Foreign Operations 4,513 4,492
Designated US-Dollar Debt 4,513 4,492
-----------------------------------------
For the three and six months ended June 30, 2010, the ineffective portion of our
US-dollar debt resulted in a net foreign exchange loss of $39 million and $18
million, respectively ($34 million and $16 million respectively, net of income
tax expense) and is included in marketing and other income. A one cent change in
the US dollar to Canadian dollar exchange rate would increase or decrease our
accumulated other comprehensive income by approximately $45 million, net of
income tax, and would increase or decrease our net income by approximately $5
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.
16
(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 81% 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 June 30, 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. One other counterparty made up
more than 5% of our credit exposure. The following table illustrates the
composition of credit exposure by credit rating.
June 30 December 31
CREDIT RATING 2010 2009
--------------------------------------------------------------------------------------------------------------
A or higher 65% 67%
BBB 26% 26%
Non-Investment Grade 9% 7%
--------------------------------------
TOTAL 100% 100%
======================================
Our maximum counterparty credit exposure at the balance sheet date consists
primarily of the carrying amounts on non-derivative financial assets such as
cash and cash equivalents, restricted cash, accounts receivable, as well as the
fair value of derivative financial assets. We provided an allowance of $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 June 30, 2010 includes $1 million of cash
and $302 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 June 30, 2010, we had approximately $3.8 billion of cash and available
committed lines of credit. This includes approximately $1 billion of cash and
cash equivalents on hand and undrawn term credit facilities of $2.8 billion, of
which $336 million was supporting letters of credit at June 30, 2010. These
facilities are available until 2014 unless extended. We also have about $467
million of uncommitted credit facilities, of which $158 million was drawn and
$24 million was supporting letters of credit at June 30, 2010.
The following table details the contractual maturities for our non-derivative
financial liabilities, including both the principal and interest cash flows at
June 30, 2010:
Less than More than
Total 1 Year 1-3 Years 4-5 Years 5 Years
-------------------------------------------------------------------------------------------------------------
Long-Term Debt 6,383 - 360 1,304 4,719
Interest on Long-Term Debt (1) 7,970 364 728 675 6,203
---------------------------------------------------------------------------
Total 14,353 364 1,088 1,979 10,922
===========================================================================
(1) Excludes interest on term credit facilities of $477 million (US$450
million) and Canexus term credit facilities of $307 million (US$289
million) as the amounts drawn on the facilities fluctuate. Based on amounts
drawn at June 30, 2010 and existing variable interest rates, we would be
required to pay $28 million per year until the outstanding amounts on the
term credit facilities are repaid.
17
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) 364 208 139 17 -
Non-Trading Derivatives (Note 6) 13 13 - - -
---------------------------------------------------------------------
Total 377 221 139 17 -
=====================================================================
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 June 30, 2010, we could be required to post collateral of up to $785
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 June 30, 2010, collateral posted with counterparties includes $133 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 $113 million (December 31, 2009 - $198 million), which have been
included in restricted cash.
8. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES
June 30 December 31
2010 2009
-------------------------------------------------------------------------------------------------------------
Energy Marketing Payables 1,256 1,366
Energy Marketing Derivative Contracts (Note 6) 208 456
Accrued Payables 658 619
Trade Payables 198 210
Income Taxes Payable 449 179
Stock-Based Compensation 30 72
Other 302 136
-------------------------------------
Total 3,101 3,038
=====================================
9. SHORT-TERM BORROWINGS AND LONG-TERM DEBT
June 30 December 31
2010 2009
-------------------------------------------------------------------------------------------------------------
Canexus Term Credit Facilities, due 2012 (US$289 million drawn) (a) 307 233
Canexus Notes, due 2013 (US$50 million) 53 52
Notes, due 2013 (US$500 million) 530 523
Term Credit Facilities, due 2014 (US$450 million drawn) (b) 477 1,570
Canexus Convertible Debentures, due 2014 32 46
Notes, due 2015 (US$250 million) 265 262
Notes, due 2017 (US$250 million) 265 262
Notes, due 2019 (US$300 million) 318 314
Notes, due 2028 (US$200 million) 212 209
Notes, due 2032 (US$500 million) 530 523
Notes, due 2035 (US$790 million) 838 827
Notes, due 2037 (US$1,250 million) 1,326 1,308
Notes, due 2039 (US$700 million) 742 733
Subordinated Debentures, due 2043 (US$460 million) 488 481
-------------------------------------
6,383 7,343
Unamortized Debt Issue Costs (100) (92)
-------------------------------------
Total Long-Term Debt 6,283 7,251
=====================================
18
(a) CANEXUS TERM CREDIT FACILITIES
Canexus has $451 million (US$425 million) of committed, secured term credit
facilities available until August 2012. At June 30, 2010, $307 million (US$289
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 4.3% for the three months ended June 30, 2010 (three months ended
June 30, 2009 - 2.1%) and 3.0% for the six months ended June 30, 2010 (six
months ended June 30, 2009 - 2.4%).
(b) TERM CREDIT FACILITIES
We have unsecured term credit facilities of $3.2 billion (US$3.1 billion) which
are available until 2014. At June 30, 2010, $477 million (US$450 million) 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 monthly at a floating rate. The weighted-average
interest rate on our term credit facilities was 1.3% for the three months ended
June 30, 2010 (three months ended June 30, 2009 - 1.1%) and 1.1% for the six
months ended June 30, 2010 (six months ended June 30, 2009 - 1.1%). At June 30,
2010, $336 million (US$317 million) of these facilities were utilized to support
outstanding letters of credit (December 31, 2009 - $407 million (US$389
million)).
(c) INTEREST EXPENSE
Three Months Six Months
Ended June 30 Ended June 30
2010 2009 2010 2009
------------------------------------------------------------------------------------------------------------------
Long-Term Debt 94 89 188 178
Other 5 3 9 8
-----------------------------------------------------
Total 99 92 197 186
Less: Capitalized (22) (18) (40) (44)
-----------------------------------------------------
Total 77 74 157 142
=====================================================
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 $467 million
(US$446 million), of which $158 million (US$149 million) were drawn at June 30,
2010 (December 31, 2009 - nil). We also utilized $24 million (US$23 million) of
these facilities to support outstanding letters of credit at June 30, 2010
(December 31, 2009 - $86 million (US$82 million)). Interest is payable at
floating rates.
19
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:
June 30 December 31
2010 2009
---------------------------------------------------------------------------------------------------
NET DEBT (1)
Short-Term Borrowings 158 -
Long-Term Debt 6,283 7,251
--------------------------------------
Total Debt 6,441 7,251
Less: Cash and Cash Equivalents (970) (1,700)
--------------------------------------
Total 5,471 5,551
======================================
EQUITY (2) 8,080 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 June 30, 2010, the net debt to adjusted cash flow was 2.3 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, where 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 identify specific actions 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 9.1 times at June 30, 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.
Twelve Months Year Ended
Ended June 30 December 31
2010 2009
----------------------------------------------------------------------------------------------------
Net Income Attributable to Nexen Inc. 821 536
Add:
Interest Expense 327 312
Provision for Income Taxes 595 260
Depreciation, Depletion, Amortization and Impairment 1,771 1,802
Exploration Expense 315 302
Recovery of Non-Cash Stock-Based Compensation (93) (10)
Change in Fair Value of Crude Oil Put Options 71 251
Other Non-Cash Expenses (161) (136)
--------------------------------------
Adjusted EBITDA 3,646 3,317
======================================
20
11. ASSET RETIREMENT OBLIGATIONS
Changes in carrying amounts of the asset retirement obligations associated with
our Property, Plant & Equipment (PP&E) are as follows:
Six Months Year Ended
Ended June 30 December 31
2010 2009
-----------------------------------------------------------------------------------------------------------------------
Balance at Beginning of Period 1,053 1,059
Obligations Incurred with Development Activities 23 27
Obligations Settled (15) (42)
Accretion Expense 33 70
Revisions to Estimates (35) 13
Obligations Reclassified to Liabilities Associated with Assets Held for Sale (121) -
Effects of Changes in Foreign Exchange Rate (15) (74)
--------------------------------------
Balance at End of Period 1, (2) 923 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 $889 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
$2,167 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 $215 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
June 30 December 31
2010 2009
----------------------------------------------------------------------------------------------------------------------
Deferred Tax Credit 451 503
Long-Term Energy Marketing Derivative Contracts (Note 6) 156 212
Defined Benefit Pension Obligations (1) 77 76
Capital Lease Obligations 43 61
Deferred Transportation Revenue 37 55
Other 115 114
-------------------------------------
Total 879 1,021
=====================================
(1) The obligations are secured by letters of credit drawn on our term credit
facilities.
13. SHAREHOLDERS' EQUITY
DIVIDENDS
Dividends per common share for the three months ended June 30, 2010 were $0.05
per common share (2009 - $0.05). Dividends per common share for the six months
ended June 30, 2010 were $0.10 per common share (2009 - $0.10).Dividends paid to
holders of common shares have been designated as "eligible dividends" for
Canadian tax purposes.
21
14. MARKETING AND OTHER INCOME
Three Months Six Months
Ended June 30 Ended June 30
2010 2009 2010 2009
-------------------------------------------------------------------------------------------------------------------
Marketing Revenue, Net 112 221 198 488
Long Lake Purchased Bitumen Sales 10 - 38 -
Gain on Sale of Assets 83 1 80 8
Change in Fair Value of Crude Oil Put Options 1 (179) (15) (195)
Interest 1 1 5 3
Foreign Exchange Gain (28) - 6 19
Other (1) (15) 38 3 16
------------------------------------------------------
Total 164 82 315 339
======================================================
(1) Includes non-cash mark-to-market losses that will reverse with the sale of
North America Natural Gas Energy Marketing as described in Note 15.
15. ASSET DISPOSITIONS
CANADIAN HEAVY OIL PROPERTIES
During the quarter, we signed an agreement to sell our heavy oil properties in
Canada for proceeds of $975 million before closing adjustments. The sale is
expected to close in the third quarter following receipt of regulatory
approvals. On closing, we expect to realize a gain of over $750 million. The
results of operations from these properties have been presented as discontinued
operations. The properties are considered assets held for sale at June 30, 2010.
The following tables provide the assets and liabilities that are associated with
the heavy oil properties.
June 30
2010
-----------------------------------------------------------------------------------------------------------------
Property, Plant and Equipment, Net of Accumulated DD&A 303
Asset Retirement Obligations (121)
Deferred Credits and Other Liabilities (28)
--------------------
Total 154
====================
Discontinued operations from these assets are:
Three Months Six Months
Ended June 30 Ended June 30
2010 2009 2010 2009
------------------------------------------------------------------------------------------------------------------
Revenues and Other Income
Net Sales 56 62 125 106
-----------------------------------------------------
Expenses
Operating 22 25 45 50
Depreciation, Depletion, Amortization and Impairment 12 32 34 64
General and Administrative 5 6 9 12
Transportation and Other - 3 2 7
-----------------------------------------------------
39 66 90 133
-----------------------------------------------------
Income (Loss) before Provision for Income Taxes 17 (4) 35 (27)
Provision for (Recovery of) Future Income Taxes 4 (1) 9 (7)
-----------------------------------------------------
Net Income (Loss) from Discontinued Operations 13 (3) 26 (20)
=====================================================
Earnings (Loss) Per Common Share
Basic 0.03 (0.01) 0.05 (0.03)
=====================================================
Diluted 0.03 (0.01) 0.05 (0.03)
=====================================================
22
NORTH AMERICA NATURAL GAS ENERGY MARKETING
During the quarter, we signed an agreement to sell our North American natural
gas marketing business. The transaction is expected to close in the third
quarter, subject to customary closing conditions. The sale is expected to be
cash neutral and we expect to recognize a non-cash loss on the sale of between
$250 million and $290 million. On closing, the purchaser will acquire our North
American natural gas business including our storage and transportation
commitments, natural gas inventory, related financial and physical derivative
positions, and margin collateral posted. In the period between signing and
closing, we have agreements with the purchaser which transfers the market risk
of our contracts and inventory to the purchaser unless we breach our obligation
to close the sale. These agreements are derivative instruments carried at fair
value on our balance sheet with gains and losses included in marketing and other
income.
CANADIAN UNDEVELOPED OIL SAND LEASES
During the quarter, we sold our non-core lands in the Athabasca region for
proceeds of $81 million. We had no plans to develop these lands for at least a
decade. We recognized a gain on sale of $80 million.
16. 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 Six Months
Ended June 30 Ended June 30
(millions of shares) 2010 2009 2010 2009
---------------------------------------------------------------------------------------------------------------------
Weighted-average number of common shares outstanding 524.5 521.2 524.0 520.7
Shares issuable pursuant to tandem options 5.8 11.1 6.0 11.2
Shares notionally purchased from proceeds of tandem options (4.1) (6.8) (4.4) (7.9)
-----------------------------------------------------
Weighted-average number of diluted common shares outstanding 526.2 525.5 525.6 524.0
=====================================================
In calculating the weighted-average number of diluted common shares outstanding
for the three and six months ended June 30, 2010, we excluded 16,556,303 and
16,516,379 tandem options, respectively, because their exercise price was
greater than the average common share market price in the period. In calculating
the weighted-average number of diluted common shares outstanding for the three
and six months ended June 30, 2009, we excluded 13,100,342 and 13,158,635 tandem
options, respectively, because their exercise price was greater than the average
common share market price in the period. During the periods presented,
outstanding tandem options were the only potential dilutive instruments.
17. 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 first 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. At June 30, 2010, our total
exposure is $71 million. The guarantees expire at the earlier of the purchaser
replacing the guarantees and September 25, 2010. We are obligated to perform
under the guarantees only if the purchaser does not meet its obligations to the
counterparties. To eliminate our exposure under the guarantees, the purchaser
has provided us an indemnity and an irrevocable letter of credit from a
highly-rated financial institution.
23
18. CASH FLOWS
(a) CHARGES AND CREDITS TO INCOME NOT INVOLVING CASH
Three Months Six Months
Ended June 30 Ended June 30
2010 2009 2010 2009
-------------------------------------------------------------------------------------------------------------------
Depreciation, Depletion, Amortization and Impairment 391 381 757 758
Stock-Based Compensation (40) 42 (41) 42
Recovery of Future Income Taxes (84) (228) (189) (309)
Gain on Sale of Assets (83) (1) (80) (8)
Non-cash Items Included in Discontinued Operations 16 31 43 57
Change in Fair Value of Crude Oil Put Options (1) 179 15 195
Foreign Exchange 42 (24) 1 (37)
Other 29 14 29 15
------------------------------------------------------
Total 270 394 535 713
======================================================
(b) CHANGES IN NON-CASH WORKING CAPITAL
Three Months Six Months
Ended June 30 Ended June 30
2010 2009 2010 2009
-------------------------------------------------------------------------------------------------------------------
Accounts Receivable (16) (471) (234) (173)
Inventories and Supplies (37) (80) 76 (129)
Other Current Assets 5 20 78 12
Accounts Payable and Accrued Liabilities (30) 134 355 319
Other Current Liabilities 7 (17) (2) (4)
------------------------------------------------------
Total (71) (414) 273 25
======================================================
Relating to:
Operating Activities (58) (340) 198 80
Investing Activities (13) (74) 75 (55)
------------------------------------------------------
Total (71) (414) 273 25
======================================================
(c) OTHER CASH FLOW INFORMATION
Three Months Six Months
Ended June 30 Ended June 30
2010 2009 2010 2009
-------------------------------------------------------------------------------------------------------------------
Interest Paid 87 97 190 178
Income Taxes Paid 43 34 250 68
------------------------------------------------------
Cash flow from other operating activities includes cash outflows related to
geological and geophysical expenditures of $17 million for the three months
ended June 30, 2010 (2009 - $31 million) and $29 million for the six months
ended June 30, 2010 (2009 - $43 million).
24
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 JUNE 30, 2010
Energy Corporate
Oil and Gas Marketing Chemicals and Other Total
----------------------------------------------------------------------------------------------------
United United Other
Kingdom Canada Syncrude States Yemen Countries(1)
-------------------------------------------------------------------------------------------
Net Sales 735 125 152 99 157 14 12 105 - 1,399
Marketing and Other 4 90(2) 1 1 3 - 95 (7) (23)(3) 164
-----------------------------------------------------------------------------------------------------
Total Revenues 739 215 153 100 160 14 107 98 (23) 1,563
Less: Expenses
Operating 76 104 71 25 36 2 7 78 - 399
Depreciation, Depletion,
Amortization and
Impairment 198 67 14 59 24 2 5 12 10 391
Transportation and Other 4 37 4 - 3 - 89 14 8 159
General and
Administrative (4) - 2 - 13 (1) 3 11 9 33 70
Exploration 7 6 - 13 - 24(5) - - - 50
Interest - - - - - - - 2 75 77
-----------------------------------------------------------------------------------------------------
Income (Loss) from 454 (1) 64 (10) 98 (17) (5) (17) (149) 417
Continuing Operations
before Income Taxes
Less: Provision for
(Recovery Of) Income Taxes 226 (1) 16 (3) 35 (15) (5) (4) (69) 180
Less: Non-Controlling
Interests - - - - - - - (5) - (5)
Add: Net Income from Assets
Held for Sale - 13 - - - - - - - 13
-----------------------------------------------------------------------------------------------------
NET INCOME (LOSS) 228 13 48 (7) 63 (2) - (8) (80) 255
=====================================================================================================
IDENTIFIABLE ASSETS 4,601 8,117(6) 1,293 1,750 248 1,254(7) 2,648(8) 754 1,850 22,515
=====================================================================================================
Capital Expenditures
-----------------------------------------------------------------------------------------------------
EXPLORATION & DEVELOPMENT 144 355 24 64 17 143 7 53 10 817
=====================================================================================================
Property, Plant and
Equipment
Cost 6,418 8,433 1,504 4,071 2,521 1,169 228 1,222 318 25,884
Less: Accumulated DD&A 3,032 769 292 2,679 2,414 102 64 582 195 10,129
-----------------------------------------------------------------------------------------------------
NET BOOK VALUE 3,386 7,664(6) 1,212 1,392 107 1,067(7) 164 640 123 15,755
=====================================================================================================
(1) Includes results of operations from producing activities in Colombia.
(2) Includes gain of $80 million from the sale of non-core lands in the
Athabasca region.
(3) Includes interest income of $1 million, foreign exchange losses of $28
million, an increase in the fair value of crude oil put options of $1
million and other gains of $3 million.
(4) Includes recovery of stock-based compensation expense of $35 million.
(5) Includes exploration activities primarily in Nigeria, Norway and Colombia.
(6) Includes PP&E costs of $6,108 million related to our insitu oil sands (Long
Lake and future phases).
(7) Includes PP&E costs of $1,016 million related to Nigeria.
(8) Approximately 84% of Marketing's identifiable assets are accounts
receivable and inventories.
25
THREE MONTHS ENDED JUNE 30, 2009
Energy Corporate
Oil and Gas Marketing Chemicals and Other Total
----------------------------------------------------------------------------------------------------
United United Other
Kingdom Canada Syncrude States Yemen Countries(1)
-------------------------------------------------------------------------------------------
Net Sales 618 36 85 88 175 20 7 109 - 1,138
Marketing and Other 4 1 1 - 4 - 221 29 (178)(2) 82
-----------------------------------------------------------------------------------------------------
Total Revenues 622 37 86 88 179 20 228 138 (178) 1,220
Less: Expenses
Operating 53 17 77 27 49 2 8 62 - 295
Depreciation, Depletion,
Amortization and
Impairment 182 30 9 80 32 4 3 29 12 381
Transportation and Other 14 5 5 3 15 - 166 14 7 229
General and
Administrative (3) 5 22 1 24 (3) 16 26 16 54 161
Exploration 11 8 - 37 - 21(4) - - - 77
Interest - - - - - - - 2 72 74
-----------------------------------------------------------------------------------------------------
Income (Loss) from 357 (45) (6) (83) 86 (23) 25 15 (323) 3
Continuing Operations
before Income Taxes
Less: Provision for
(Recovery of) Income Taxes 170 (12) (2) (28) 30 (18) 9 4 (175) (22)
Less: Non-Controlling
Interests - - - - - - - 2 - 2
Add: Net Loss from Assets
Held for Sale - (3) - - - - - - - (3)
-----------------------------------------------------------------------------------------------------
NET INCOME (LOSS) 187 (36) (4) (55) 56 (5) 16 9 (148) 20
=====================================================================================================
IDENTIFIABLE ASSETS 5,831 8,349(5) 1,232 2,043 289 911(6) 3,332(7) 618 1,321 23,926
=====================================================================================================
Capital Expenditures
-----------------------------------------------------------------------------------------------------
EXPLORATION & DEVELOPMENT 158 191 22 72 22 166 3 72 9 715
=====================================================================================================
Property, Plant and
Equipment
Cost 6,500 9,411 1,407 4,270 2,715 723 259 1,005 349 26,639
Less: Accumulated DD&A 2,414 1,899 251 2,680 2,549 116 83 507 223 10,722
-----------------------------------------------------------------------------------------------------
NET BOOK VALUE 4,086 7,512(5) 1,156 1,590 166 607(6) 176 498 126 15,917
=====================================================================================================
(1) Includes results of operations from producing activities in Colombia.
(2) Includes interest income of $1 million and a decrease in the fair value of
crude oil put options of $179 million.
(3) Includes stock-based compensation expense of $56 million.
(4) Includes exploration activities primarily in Nigeria, Norway and Colombia.
(5) Includes PP&E costs of $5,832 million related to our insitu oil sands (Long
Lake and future phases).
(6) Includes PP&E costs of $551 million related to Nigeria.
(7) Approximately 82% of Marketing's identifiable assets are accounts
receivable and inventories.
26
SIX MONTHS ENDED JUNE 30, 2010
Energy Corporate
Oil and Gas Marketing Chemicals and Other Total
----------------------------------------------------------------------------------------------------
United United Other
Kingdom Canada Syncrude States Yemen Countries(1)
-------------------------------------------------------------------------------------------
Net Sales 1,490 236 286 212 339 29 21 218 - 2,831
Marketing and Other 9 118(2) 2 1 8 - 178 - (1)(3) 315
-----------------------------------------------------------------------------------------------------
Total Revenues 1,499 354 288 213 347 29 199 218 (1) 3,146
Less: Expenses
Operating 153 215 138 47 77 3 17 148 - 798
Depreciation, Depletion,
Amortization and
Impairment 366 125 27 123 59 4 10 23 20 757
Transportation and Other 3 91 11 2 6 - 212 26 8 359
General and
Administrative(4) 13 14 - 24 - 11 32 17 73 184
Exploration 31 13 - 29 - 70(5) - - - 143
Interest - - - - - - - 3 154 157
-----------------------------------------------------------------------------------------------------
Income (Loss) from 933 (104) 112 (12) 205 (59) (72) 1 (256) 748
Continuing Operations
before Income Taxes
Less: Provision for
(Recovery of) Income Taxes 466 (27) 28 (4) 72 (53) (28) - (120) 334
Less: Non-Controlling
Interests - - - - - - - - - -
Add: Net Income from Assets
Held for Sale - 26 - - - - - - - 26
-----------------------------------------------------------------------------------------------------
NET INCOME (LOSS) 467 (51) 84 (8) 133 (6) (44) 1 (136) 440
=====================================================================================================
IDENTIFIABLE ASSETS 4,601 8,117(6) 1,293 1,750 248 1,254(7) 2,648(8) 754 1,850 22,515
=====================================================================================================
Capital Expenditures
-----------------------------------------------------------------------------------------------------
EXPLORATION & DEVELOPMENT 273 493 43 128 27 275 16 102 16 1,373
=====================================================================================================
Property, Plant and
Equipment
Cost 6,418 8,433 1,504 4,071 2,521 1,169 228 1,222 318 25,884
Less: Accumulated DD&A 3,032 769 292 2,679 2,414 102 64 582 195 10,129
-----------------------------------------------------------------------------------------------------
NET BOOK VALUE 3,386 7,664(6) 1,212 1,392 107 1,067(7) 164 640 123 15,755
=====================================================================================================
(1) Includes results of operations from producing activities in Colombia.
(2) Includes gain of $80 million from the sale of non-core lands in the
Athabasca region.
(3) Includes interest income of $5 million, foreign exchange gains of $6
million, decrease in the fair value of crude oil put options of $15 million
and other gains of $3 million.
(4) Includes recovery of stock-based compensation expense of $33 million.
(5) Includes exploration activities primarily in Norway and Colombia.
(6) Includes PP&E costs of $6,108 million related to our insitu oil sands (Long
Lake and future phases).
(7) Includes PP&E costs of $1,016 million related to Nigeria.
(8) Approximately 84% of Marketing's identifiable assets are accounts
receivable and inventories.
27
SIX MONTHS ENDED JUNE 30, 2009
Energy Corporate
Oil and Gas Marketing Chemicals and Other Total
----------------------------------------------------------------------------------------------------
United United Other
Kingdom Canada Syncrude States Yemen Countries(1)
-------------------------------------------------------------------------------------------
Net Sales 1,096 83 183 151 337 39 20 233 - 2,142
Marketing and Other 8 8 1 - 7 - 488 15 (188)(2) 339
-----------------------------------------------------------------------------------------------------
Total Revenues 1,104 91 184 151 344 39 508 248 (188) 2,481
Less: Expenses
Operating 104 33 143 50 96 4 16 129 - 575
Depreciation, Depletion,
Amortization and
Impairment 375 61 20 148 73 9 7 41 24 758
Transportation and Other 11 4 12 16 18 - 328 24 13 426
General and
Administrative (3) 7 30 1 38 1 24 49 25 80 255
Exploration 19 29 - 47 - 35(4) - - - 130
Interest - - - - - - - 4 138 142
-----------------------------------------------------------------------------------------------------
Income (Loss) from 588 (66) 8 (148) 156 (33) 108 25 (443) 195
Continuing Operations
before Income Taxes
Less: Provision for
(Recovery of) Income Taxes 256 (17) 2 (51) 54 (24) 44 6 (255) 15
Less: Non-Controlling
Interests - - - - - - - 5 - 5
Add: Net Loss from Assets
Held for Sale - (20) - - - - - - - (20)
-----------------------------------------------------------------------------------------------------
NET INCOME (LOSS) 332 (69) 6 (97) 102 (9) 64 14 (188) 155
=====================================================================================================
IDENTIFIABLE ASSETS 5,831 8,349(5) 1,232 2,043 289 911(6) 3,332(7) 618 1,321 23,926
=====================================================================================================
Capital Expenditures
Exploration & Development 335 531 39 140 51 239 11 108 10 1,464
Proved Property
Acquisitions - 755 - - - - - - - 755
-----------------------------------------------------------------------------------------------------
TOTAL 335 1,286 39 140 51 239 11 108 10 2,219
=====================================================================================================
Property, Plant and
Equipment
Cost 6,500 9,411 1,407 4,270 2,715 723 259 1,005 349 26,639
Less: Accumulated DD&A 2,414 1,899 251 2,680 2,549 116 83 507 223 10,722
-----------------------------------------------------------------------------------------------------
NET BOOK VALUE 4,086 7,512(5) 1,156 1,590 166 607(6) 176 498 126 15,917
=====================================================================================================
(1) Includes results of operations from producing activities in Colombia.
(2) Includes interest income of $3 million, foreign exchange gains of $19
million, decrease in the fair value of crude oil put options of $195
million and other losses of $15 million.
(3) Includes stock-based compensation expense of $56 million.
(4) Includes exploration activities primarily in Norway and Colombia.
(5) Includes PP&E costs of $5,832 million related to our insitu oil sands (Long
Lake and future phases).
(6) Includes PP&E costs of $551 million related to Nigeria.
(7) Approximately 82% of Marketing's identifiable assets are accounts
receivable and inventories.
28
20. DIFFERENCES BETWEEN CANADIAN AND US GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
The Unaudited Consolidated Financial Statements have been prepared in accordance
with Canadian GAAP. The US GAAP Unaudited Consolidated Statements and summaries
of differences from Canadian GAAP are as follows:
UNAUDITED CONSOLIDATED STATEMENT OF INCOME - US GAAP
FOR THE THREE AND SIX MONTHS ENDED JUNE 30
Three Months Six Months
Ended June 30 Ended June 30
(Cdn$ millions, except per share amounts) 2010 2009 2010 2009
----------------------------------------------------------------------------------------------------------------------
REVENUES AND OTHER INCOME
Net Sales 1,399 1,138 2,831 2,142
Marketing and Other (v); (vi) 98 66 303 358
------------------------------------------------------
1,497 1,204 3,134 2,500
------------------------------------------------------
EXPENSES
Operating 399 295 798 575
Depreciation, Depletion, Amortization and Impairment 391 381 757 758
Transportation and Other (v) 76 228 279 418
General and Administrative (iv) 50 191 172 293
Exploration 50 77 143 130
Interest 77 74 157 142
------------------------------------------------------
1,043 1,246 2,306 2,316
------------------------------------------------------
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE
PROVISION FOR INCOME TAXES 454 (42) 828 184
------------------------------------------------------
PROVISION FOR (RECOVERY OF) INCOME TAXES
Current 264 206 523 324
Deferred (iv); (vi) (73) (241) (164) (309)
------------------------------------------------------
191 (35) 359 15
------------------------------------------------------
NET INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE
NON-CONTROLLING INTERESTS 263 (7) 469 169
Less: Net Income (Loss) Attributable to Canexus Non-
Controlling Interests (5) 2 - 5
------------------------------------------------------
NET INCOME (LOSS) FROM CONTINUING OPERATIONS
ATTRIBUTABLE TO NEXEN INC. 268 (9) 469 164
Net Income (Loss) from Discontinued Operations 13 (3) 26 (20)
------------------------------------------------------
NET INCOME (LOSS) ATTRIBUTABLE TO NEXEN INC. - US GAAP (1) 281 (12) 495 144
======================================================
EARNINGS (LOSS) PER COMMON SHARE FROM CONTINUING
OPERATIONS ($/share)
Basic 0.51 (0.02) 0.89 0.31
======================================================
Diluted 0.51 (0.02) 0.89 0.31
======================================================
EARNINGS (LOSS) PER COMMON SHARE ($/share)
Basic 0.54 (0.02) 0.94 0.28
======================================================
Diluted 0.54 (0.02) 0.94 0.28
======================================================
(1) RECONCILIATION OF CANADIAN AND US GAAP NET INCOME Three Months Six Months
Ended June 30 Ended June 30
2010 2009 2010 2009
----------------------------------------------------------------------------------------------------------------------
Net Income Attributable to Nexen Inc - Canadian GAAP 255 20 440 155
Impact of US Principles, Net of Income Taxes:
Stock-based Compensation (iv) 15 (22) 9 (28)
Inventory Valuation (vi) 11 (10) 46 17
------------------------------------------------------
Net Income (Loss) Attributable to Nexen Inc - US GAAP 281 (12) 495 144
======================================================
29
UNAUDITED CONSOLIDATED BALANCE SHEET - US GAAP
June 30 December 31
(Cdn$ millions, except share amounts) 2010 2009
-------------------------------------------------------------------------------------------------------------------
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents 970 1,700
Restricted Cash 113 198
Accounts Receivable 2,675 2,788
Inventories and Supplies (vi) 619 610
Other 106 185
--------------------------------------
Total Current Assets 4,483 5,481
--------------------------------------
PROPERTY, PLANT AND EQUIPMENT
Net of Accumulated Depreciation, Depletion, Amortization and
Impairment of $10,521 (December 31, 2009 - $11,200) (i); (iii) 15,706 15,443
GOODWILL 343 339
DEFERRED INCOME TAX ASSETS 1,340 1,148
DEFERRED CHARGES AND OTHER ASSETS 289 370
ASSETS HELD FOR SALE 303 -
--------------------------------------
TOTAL ASSETS 22,464 22,781
======================================
LIABILITIES
CURRENT LIABILITIES
Short-Term Borrowings 158 -
Accounts Payable and Accrued Liabilities (iv) 3,182 3,131
Accrued Interest Payable 89 89
Dividends Payable 26 26
--------------------------------------
Total Current Liabilities 3,455 3,246
--------------------------------------
LONG-TERM DEBT 6,283 7,251
DEFERRED INCOME TAX LIABILITIES (i); (ii); (iv); (vi); (vii) 2,825 2,720
ASSET RETIREMENT OBLIGATIONS 859 1,018
DEFERRED CREDITS AND OTHER LIABILITIES (ii) 984 1,126
LIABILITIES ASSOCIATED WITH ASSETS HELD FOR SALE 149 -
EQUITY
Nexen Inc. Shareholders' Equity
Common Shares, no par value
Authorized: Unlimited
Outstanding: 2010 - 524,565,491 shares
2009 - 522,915,843 shares 1,088 1,049
Contributed Surplus - 1
Retained Earnings (i); (ii); (iv); (vi); (vii) 7,018 6,575
Accumulated Other Comprehensive Loss (ii) (268) (269)
--------------------------------------
Total Nexen Inc. Shareholders' Equity 7,838 7,356
Canexus Non-Controlling Interests 71 64
--------------------------------------
TOTAL EQUITY 7,909 7,420
--------------------------------------
COMMITMENTS, CONTINGENCIES AND GUARANTEES
TOTAL LIABILITIES AND EQUITY 22,464 22,781
======================================
30
UNAUDITED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME (LOSS) - US GAAP
FOR THE THREE AND SIX MONTHS ENDED JUNE 30
Three Months Six Months
Ended June 30 Ended June 30
2010 2009 2010 2009
------------------------------------------------------------------------------------------------------------------
Net Income (Loss) Attributable to Nexen Inc. - US GAAP 281 (12) 495 144
Other Comprehensive Income (Loss), Net of Income Taxes:
Foreign Currency Translation Adjustment 12 (29) 1 (23)
----------------------------------------------------
Comprehensive Income (Loss) Attributable to Nexen Inc. - US
GAAP 293 (41) 496 121
====================================================
UNAUDITED CONSOLIDATED STATEMENT OF ACCUMULATED OTHER COMPREHENSIVE
LOSS - US GAAP
June 30 December 31
2010 2009
-----------------------------------------------------------------------------------------------------------------
Foreign Currency Translation Adjustment (189) (190)
Unamortized Defined Benefit Pension Plan Costs (ii) (79) (79)
------------------------------------
Accumulated Other Comprehensive Loss (268) (269)
====================================
NOTES TO THE UNAUDITED CONSOLIDATED US GAAP FINANCIAL STATEMENTS:
i. Under Canadian GAAP, we deferred 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
June 30, 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 Loss (AOCL).
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 required the
accelerated recognition of stock-based compensation expense for all
stock-based awards made to our retired and retirement-eligible employees.
However, US GAAP required the accelerated recognition of stock-based
compensation expense for such employees for awards granted on or after
January 1, 2006. As a result under US GAAP:
o general and administrative (G&A) expense is lower by $20 million and
$12 million, ($15 million and $9 million, net of income taxes), for
the three and six months ended June 30, 2010, (2009 - higher by $30
million and $38 million, respectively, ($22 million and $28 million,
net of income taxes)); and
o accounts payable and accrued liabilities are higher by $81 million as
at June 30, 2010 (December 31, 2009 - $93 million).
v. Under US GAAP, asset disposition gains and losses are included with
transportation and other expense. Gains of $83 million and $80 million for
the three and six months ended June 30, 2010, respectively, were
reclassified from marketing and other income to transportation and other
expense (gains of $1 million and $8 million, respectively were reclassified
for the three and six months ended June 30, 2009).
31
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 $17 million and $68 million
($11 million and $46 million, net of income taxes) for the three and
six months ended June 30, 2010 (2009 - lower by $15 million and higher
by $27 million ($10 million and $17 million, net of income taxes));
and
o inventories are lower by $2 million as at June 30, 2010 (December 31,
2009 - lower by $70 million) and deferred income tax liabilities are
$1 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 June 30, 2010, the total amount of our unrecognized tax benefit was
approximately $284 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 June 30, 2010, the total
amount of interest and penalties related to uncertain tax positions
recognized in deferred income tax 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 and six months ended June 30, 2010.
Our income tax filings are subject to audit by taxation authorities and as
at June 30, 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 financial instrument 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.
32
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 JULY 14, 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 SECOND QUARTER RESULTS
Three Months Six Months
Ended June 30 Ended June 30
(Cdn$ millions, except as indicated) 2010 2009 2010 2009
--------------------------------------------------------------------------------------------------------------------------------
Production before Royalties (mboe/d) 248 240 250 246
Production after Royalties (mboe/d) 218 208 220 217
Nexen's Average Realized Oil and Gas Price (Cdn$/boe) 67.46 61.28 68.78 54.28
Cash Flow from Operating Activities 510 109 1,308 898
Net Income Attributable to Nexen Inc. 255 20 440 155
Earnings per Common Share, Basic ($/share) 0.49 0.04 0.84 0.30
Capital Investment 817 715 1,373 1,464
Acquisition of Additional Interest in Long Lake - - - 755
Net Debt (1) 5,471 5,889 5,471 5,889
-------------------------------------------------------
(1) Net debt is a non-GAAP measure and is defined as long-term debt and
short-term borrowings less cash and cash equivalents.
Higher production combined with stronger commodity prices delivered improved
financial results over last year. Production for the quarter increased 3%
despite downtime at Buzzard and natural field declines in Yemen. Higher
production rates at Long Lake, Syncrude and at our Ettrick and Telford fields in
the UK North Sea more than offset scheduled downtime at Buzzard. Our realized
average oil and gas price averaged $67.46/boe for the quarter, 10% higher than
last year as a result of stronger benchmark commodity prices. The weaker US
dollar reduced some of the commodity price increase benefit.
At our Long Lake oil sands project, we are steadily growing bitumen production
volumes each month as we increase steam volumes and the reservoirs heat up. We
expect Long Lake to make positive cash flow contributions later this year as our
bitumen volumes grow.
We successfully completed the installation of the topside facilities on the
fourth platform at Buzzard during the quarter. Elsewhere, our capital investment
focused on progressing our major development project at Usan, offshore Nigeria
to first oil production in 2012, and on exploration activities in the Gulf of
Mexico, the North Sea and shale gas. In addition, we were successful at a recent
land sale in northeast British Columbia where we more than doubled our shale gas
position. To date, we have incurred approximately half of our 2010 planned
capital expenditures.
In the Gulf of Mexico, we continue to evaluate our discovery at Appomattox and
progress plans for follow-up appraisal and exploration, while in the UK North
Sea we are reviewing development options for the Golden Eagle area. Elsewhere in
the UK North Sea, we drilled a successful appraisal well at Blackbird during the
quarter. Blackbird is adjacent to our Ettrick development.
33
The six month drilling moratorium in the Gulf of Mexico has no material impact
on our current operations. Our shelf and deep-water production are unaffected
and we continue to expect our Gulf of Mexico production for the year to average
between 20,000 and 28,000 boe/d before royalties (17,000 and 25,000 boe/d after
royalties).
During the quarter, we entered into agreements to sell our heavy oil assets in
Canada and our natural gas marketing business. The heavy oil properties produced
approximately 15,000 boe/d during the second quarter and had proved reserves of
39 million boe at December 31, 2009. Both transactions are expected to close in
the third quarter, generating net proceeds of almost $1 billion and realizing
net gains of approximately $500 million. We have exceeded our target of
generating $1.0 billion of proceeds from non-core asset sales. We have now
increased our target to approximately $1.5 billion of proceeds once we complete
our disposition program, which includes the sale of our Canexus investment.
Our financial position remains strong with available liquidity of approximately
$3.8 billion. This liquidity includes cash on hand of approximately $1 billion
and undrawn lines of credit of approximately $2.8 billion. After the heavy oil
and natural gas marketing transactions close in the third quarter, we expect our
liquidity to increase by approximately $900 million. Debt maturities in the next
five years can be repaid from current cash on hand and the heavy oil sales
proceeds. The average term-to-maturity of our long-term debt is approximately 19
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
o advancing our Horn River shale gas play with our fracing campaign and
doubling our shale gas land position in northeast British Columbia.
Details of our capital programs are set out below:
Three Months Six Months
Ended June 30 Ended June 30
2010 2010
--------------------------------------------------------------------------------
Oil and Gas
United Kingdom 144 273
Canada 311 385
Synthetic (mainly Long Lake) 44 108
Syncrude 24 43
United States 64 128
Yemen 17 27
Nigeria 126 218
Other Countries 17 57
--------------------------------------
747 1,239
Chemicals 53 102
Energy Marketing, Corporate and Other 17 32
--------------------------------------
Total Capital 817 1,373
======================================
UNITED KINGDOM - NORTH SEA
During the quarter, we completed drilling a successful appraisal well at our
Blackbird oil discovery, a potential tie-back to Ettrick. The well was drilled
in a water depth of approximately 367 feet to a total measured depth of 12,000
feet. We are currently acquiring extensive wireline log and core data over the
reservoir section for further analysis. We plan to complete the well and conduct
a drill stem test later this month. If successful, the well will be suspended
for future use as an oil producer. We have a 79.73% operated interest here.
34
Elsewhere in the North Sea, the Golden Eagle area is a significant development
opportunity for us. We are in the process of completing the acquisition of
additional acreage in the area and plan to drill an exploration well here later
this 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 for sanctioning in 2011. We have a 34% interest in both Golden
Eagle and Hobby, a 46% interest in Pink, and operate all three.
At Buzzard, we have a number of opportunities to potentially add reserves. In
the northern part of the field, we are seeing more oil above the water contact
which should lead to more recoverable oil. In the south, we plan to drill
Bluebell, a possible extension of the Buzzard field. At Polecat, a previous
discovery east of Buzzard, we plan to drill an appraisal well which could be
tied back to the Buzzard platform.
West of the Shetland Islands, we are finalizing plans to drill the North Uist
prospect. We have a 35% non-operated working interest here and expect to drill
the well later this year. This prospect has a target size much larger than
typical North Sea targets.
CANADA - HORN RIVER SHALE GAS
In the first quarter, we completed drilling our eight-well program in the Horn
River and realized substantial cost savings and productivity improvements. Our
average drilling days per well were under 25 days, down 35% from our previous
program while drilling 80% more reservoir length. We recently began fracing
these wells and plan to conduct 18 fracs per well. First production is expected
before year end, ramping up to 50 mmcf/d in early 2011.
As previously announced, we have approximately 90,000 acres at Dilly Creek in
the Horn River basin and 38,000 acres at Cordova. Following our success at a
June land sale, we have increased our position from 128,000 acres to over
300,000 acres of shale gas lands in northeast British Columbia.
SYNTHETIC
The upgrader is performing well and is consistently processing virtually all of
our bitumen production as well as 9,000 bbls/d of purchased bitumen. 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.
Bitumen production to feed the upgrader continues to ramp up following the
completion of the turnaround last fall as we have significantly improved steam
reliability and are optimizing our wells. Steam rates have more than doubled
from pre-turnaround levels and we are currently at all-time highs of about
150,000 bbls/d. As a result, we are injecting more steam into more wells than
ever before with 68 of 91 well pairs now on production and steam circulating in
an additional 13 pairs. These circulating wells will be converted to production
over the next few months.
As we provide consistent steam to the reservoir, we are focusing on optimizing
steam injection and individual well performance. To support increased well
productivity, we have converted 54 wells from gas lift to electric submersible
pumping and expect to convert the remainder, when appropriate. This offers more
flexibility to optimize steam injection and grow bitumen production.
Our all-in steam-to-oil ratio (SOR) is between five and six and 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 production rates with a corresponding decrease in SOR. The SOR of
our mature producing wells is now four and improving.
We continue to pursue inexpensive ways to add bitumen capacity since bitumen
production in excess of upgrader capacity can be sold for an attractive return.
As a result, we are continuing with the development of two additional well pads
and have commenced engineering work to add two more once-through steam
generators over the next 18 to 24 months. These steam generators can be added
for a cost of about $100 million ($150 million gross).
Phase 1 of our Long Lake project is designed to produce 72,000 bbls/d of gross
bitumen, upgraded to approximately 60,000 bbls/d (39,000 bbls/d, net to us) of
PSCTM. We are committed to the development of our oil sands leases and plan to
develop Phase 2 in two smaller SAGD stages of about 40,000 bbls/d each with
upgrading available after ramp up.
UNITED STATES - GULF OF MEXICO
At Knotty Head, we completed drilling an appraisal well before the moratorium.
We are currently evaluating results, considering possible development choices
and continuing our efforts to unitize our lands with adjacent acreage. No other
drilling was planned in the near term. We are the operator of Knotty Head with a
25% working interest.
35
In the first quarter, we made a significant discovery in the deepwater at
Appomattox, located in Mississippi Canyon blocks 391 and 392. This has the
potential to be our best discovery in the Gulf of Mexico. Drilling activities
resulted in a light oil discovery with excellent reservoir quality, following an
exploration well and two appraisal sidetracks. Appomattox is the third discovery
in the area following earlier discoveries at Shiloh and Vicksburg. Additional
appraisal wells for Appomattox were being considered for later in the year but
have been delayed as a result of the drilling moratorium. We continue to
investigate 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.
Our plans to drill two additional exploration wells later this year with two new
deep-water drilling rigs have been delayed by the drilling moratorium. The first
deep-water rig, the Ensco 8501, completed drilling an appraisal well at Knotty
Head and is currently being used by the third party we share the rig with. The
second rig, the Ensco 8502, has arrived in the Gulf and is undergoing sea trials
prior to its acceptance. The drilling moratorium and new regulations may delay
rig acceptance. To date, the moratorium has not resulted in any cash costs and
for the remainder of the six month period, we expect our costs to be modest, if
anything.
OFFSHORE WEST AFRICA
Development of the Usan field is progressing well with first production expected
in 2012. The development includes a floating production and storage offloading
(FPSO) vessel with the ability to process 180,000 bbls/d (36,000 bbls/d net to
us) and store up to two million barrels of oil. In June, major topside modules
were lifted onto the FPSO deck and the FPSO unit is almost 80% complete. 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. We have an 18% interest in this discovery.
YEMEN
Yemen is an important asset for us and continues to generate cash flow in excess
of capital requirements. In December 2011, our production sharing contract with
the Yemen government expires. We are currently working on a possible contract
extension.
36
FINANCIAL RESULTS
CHANGE IN NET INCOME
2010 VS 2009
Three Months Six Months
Ended June 30 Ended June 30
------------------------------------------------------------------------------------------------------------------------------
NET INCOME AT JUNE 30, 2009(1) 20 155
-------------------------------------
Favorable (unfavorable) variances(2):
Realized Commodity Prices
Crude Oil 112 522
Natural Gas 11 12
-------------------------------------
Total Price Variance 123 534
Production Volumes, After Royalties
Crude Oil 81 66
Natural Gas 16 50
Changes in Crude Oil Inventory For Sale 34 72
-------------------------------------
Total Volume Variance 131 188
Oil and Gas Operating Expense (86) (198)
Oil and Gas Depreciation, Depletion, Amortization and Impairment (7) 12
Exploration Expense 27 (13)
Energy Marketing Revenue, Net (43) (194)
Chemicals Contribution (32) (28)
General and Administrative Expense (3) 92 74
Interest Expense (3) (15)
Current Income Taxes (58) (199)
Future Income Taxes (149) (136)
Change in Fair Value of Crude Oil Put Options 181 181
Other 59 79
-------------------------------------
NET INCOME AT JUNE 30, 2010 255 440
=====================================
(1) Includes results of discontinued operations (See Note 15 of our Unaudited
Consolidated Financial Statements).
(2) All amounts are presented before provision for income taxes.
(3) Includes stock-based compensation expense.
Significant variances in net income are explained further in the following
sections.
37
OIL & GAS
PRODUCTION (BEFORE ROYALTIES)(1)
Three Months Six Months
Ended June 30 Ended June 30
2010 2009 2010 2009
----------------------------------------------------------------------------------------------------------------------------
Crude Oil and Liquids (mbbls/d)
United Kingdom 98.2 97.7 101.9 100.7
Canada (2) 13.1 14.9 13.7 15.1
Long Lake Bitumen 16.2 9.3 14.2 8.7
Syncrude 23.4 14.9 21.5 17.3
United States 9.9 12.1 9.8 11.2
Yemen 40.9 51.5 41.9 52.9
Other Countries 2.1 3.6 2.2 4.5
---------------------------------------------------
203.8 204.0 205.2 210.4
---------------------------------------------------
Natural Gas (mmcf/d)
United Kingdom 40 18 40 18
Canada (2) 128 136 130 138
United States 96 61 98 56
---------------------------------------------------
264 215 268 212
---------------------------------------------------
Total Production (mboe/d) 248 240 250 246
===================================================
PRODUCTION (AFTER ROYALTIES)
Three Months Six Months
Ended June 30 Ended June 30
2010 2009 2010 2009
----------------------------------------------------------------------------------------------------------------------------
Crude Oil and Liquids (mbbls/d)
United Kingdom 98.2 97.6 101.9 100.6
Canada (2) 10.0 11.2 10.4 11.8
Long Lake Bitumen 15.7 9.2 13.5 8.6
Syncrude 21.5 13.0 19.7 16.3
United States 8.9 10.9 8.9 10.2
Yemen 22.2 29.0 22.6 32.3
Other Countries 2.0 3.3 2.1 4.2
---------------------------------------------------
178.5 174.2 179.1 184.0
---------------------------------------------------
Natural Gas (mmcf/d)
United Kingdom 40 18 40 18
Canada (2) 117 129 119 127
United States 83 54 85 50
---------------------------------------------------
240 201 244 195
---------------------------------------------------
Total Production (mboe/d) 218 208 220 217
===================================================
(1) We have presented production volumes before royalties as we measure our
performance on this basis consistent with other Canadian oil and gas
companies.
(2) Includes the following production from discontinued operations. See Note 15
of our Unaudited Consolidated Financial Statements.
Three Months Six Months
Ended June 30 Ended June 30
2010 2009 2010 2009
----------------------------------------------------------------------------------------------------------------------------
Before Royalties
Crude Oil and NGLs (mbbls/d) 13.1 14.9 13.7 15.1
Natural Gas (mmcf/d) 11 13 11 15
After Royalties
Crude Oil and NGLs (mbbls/d) 10.0 11.2 10.4 11.8
Natural Gas (mmcf/d) 10 13 10 13
---------------------------------------------------
38
HIGHER VOLUMES INCREASED NET INCOME FOR THE QUARTER BY $131 MILLION
Production before royalties increased 3% from last year as higher Long Lake and
Syncrude production were partially offset by natural declines in Yemen and
Canada. Compared to the previous quarter, production before royalties decreased
2% where lower production in the UK North Sea as a result of temporary downtime
at Buzzard was partially offset by production increases at Long Lake and
Syncrude. Production after royalties was marginally lower than both the prior
quarter and last year.
The following table summarizes our production volume changes since last quarter:
Before After
(mboe/d) Royalties Royalties
-----------------------------------------------------------------------------
Production, first quarter 2010 252 221
Production changes:
Syncrude 4 4
Long Lake Bitumen 4 4
United Kingdom (7) (7)
Canada (2) (2)
Yemen (2) (1)
United States (1) (1)
-----------------------------------
Production, second quarter 2010 248 218
===================================
Production volumes discussed in this section represent before-royalties volumes,
net to our working interest.
UNITED KINGDOM
Production volumes in the UK North Sea decreased 7% from the previous quarter,
while increasing 4% from the second quarter of 2009. The decrease from the prior
quarter was primarily due to the planned downtime at Buzzard to complete the
installation of the new platform to handle produced H2S. While downtime also
reduced production compared to the same period last year, it was more than
offset by higher volumes at Scott/Telford and Ettrick.
Buzzard production averaged 71,100 boe/d for the quarter, 16% lower than the
prior quarter and 19% lower than the second quarter of 2009. As previously
announced, production was shut in at Buzzard in early May to accommodate
installation of the topsides on the fourth platform. During this time, we also
permanently repaired a separator unit that contributed to downtime in the first
quarter. On completion of the installation and maintenance work, Buzzard
produced at reduced rates of approximately 55,000 boe/d. Full production was
restored in late May, two days ahead of schedule.
Production at Scott/Telford averaged 17,800 boe/d. Water injection flowline
limitations at Telford decreased production 13% from the previous quarter.
However, compared to the same period last year, production has increased 75% as
a result of a successful step-out development well, which was tied back to our
Scott platform in the third quarter of 2009. In early July, a valve failure on
the Forties pipeline system required us to shut in our production from the Scott
platform. The operator is currently determining the root cause and the nature of
the repairs. While the operator undertakes this work, we are advancing our
shutdown at Scott that was planned for later this summer.
Production from our Ettrick field more than doubled over the prior quarter and
averaged 14,000 boe/d net to us. Ettrick is currently producing at approximately
24,000 boe/d gross (20,000 boe/d net to us) and continues to ramp up.
CANADA
Production in Canada was 5% lower than the previous quarter and 9% lower than
the second quarter of 2009 primarily as a result of natural declines at our
heavy oil properties. CBM production was slightly reduced due to natural
declines and maintenance work. During the quarter, we agreed to sell our heavy
oil properties to a third party. These properties are producing approximately
15,000 boe/d and the sale is expected to close in the third quarter following
receipt of regulatory approvals.
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 production and decline profile expectations. In
the first quarter, we completed drilling our eight-well program in the Horn
River and realized substantial cost savings and productivity improvements. We
recently began fracing these wells and plan to conduct 18 fracs per well. First
production from these wells is expected before year end, ramping up to 50 mmcf/d
in early 2011.
39
LONG LAKE
Bitumen production to feed the upgrader continues to ramp up following the
completion of the turnaround last fall as we have significantly improved steam
reliability and are optimizing our wells. Steam rates have more than doubled
from pre-turnaround levels and we are currently at all-time highs of about
150,000 bbls/d. As a result, we are injecting more steam into more wells than
ever before with 68 of 91 well pairs now on production and steam circulating in
an additional 13 pairs. These circulating wells will be converted to production
over the next few months. The table below shows gross monthly bitumen production
volumes for the current year.
Gross Bitumen
Month Volumes (bbls/d)
-------------------------------------------------------------------------
January 2010 16,300
February 2010 17,700
March 2010 21,900
April 2010 24,400
May 2010 23,600
June 2010 26,900
July 2010 - Month to date 28,500
-------------------------------------------------------------------------
As we provide consistent steam to the reservoir, we are focusing on optimizing
steam injection and individual well performance. To support increased well
productivity, we have converted 54 wells from gas lift to electric submersible
pumping and expect to convert the remainder, when appropriate. This offers more
flexibility to optimize steam injection and grow bitumen production.
SYNCRUDE
Syncrude production averaged 23,400 boe/d for the quarter. This was 20% higher
than the previous quarter when production was reduced as a result of a
turnaround of the LC finer. Production was 57% higher than last year when Coker
8-3 was undergoing regular maintenance. Additionally, outages in the Pembina
pipeline reduced shipments of synthetic crude in the second quarter of 2009.
UNITED STATES
Production in the Gulf of Mexico averaged 25,900 boe/d, 3% lower than the
previous quarter. The reduced volumes were primarily due to downtime at the
Longhorn field for maintenance work and tie-in of a third-party development to
the Corral platform. Elsewhere in the Gulf, production decreases due to
additional maintenance downtime were offset by successful recompletion projects.
Compared to the same period last year, production increased 16% as a result of
the Longhorn development which came on-stream in late 2009. Production at
Longhorn averaged 7,800 boe/d in the quarter. The impact of this production
increase was partially offset by natural field declines at Aspen, Gunnison and
Wrigley.
The six month drilling moratorium in the Gulf of Mexico has no material impact
on our current operations. Our shelf and deep-water production are unaffected
and we continue to expect our Gulf of Mexico production for the year to average
between 20,000 and 28,000 boe/d before royalties (17,000 and 25,000 boe/d after
royalties).
YEMEN
Yemen production averaged 40,900 boe/d for the quarter, down 4% and 21% from the
previous quarter and last year, respectively. The production decline is
consistent with expectations as the fields mature and development drilling is
reduced as we approach the scheduled end of the contract term. Decline rates
have been moderated as we undertake well recompletions and maintenance to
maximize the existing wells. At Masila, we completed our development drilling
program by drilling 11 wells in the first half of the year. At Block 51, we have
drilled two development wells to date and expect to drill three additional wells
in the second half of the year. Production declines in Yemen are expected to
continue as we focus on maximizing recovery of the remaining reserves.
We continue to work with the Yemen government and our partners to obtain an
extension to our production-sharing agreement beyond the current expiry date of
December 17, 2011. There is no assurance that this extension will be received.
OTHER COUNTRIES
Our share of production from the Guando field in Colombia averaged 2,100 boe/d
for the quarter. This was 9% lower than the previous quarter and 42% lower than
the same period last year. The decrease in volumes is a result of the reduction
in our working interest in the Guando field, effective the second quarter of
2009, on achieving pre-set production levels.
40
COMMODITY PRICES
Three Months Six Months
Ended June 30 Ended June 30
2010 2009 2010 2009
--------------------------------------------------------------------------------------------------------------------------------
CRUDE OIL
West Texas Intermediate (WTI) (US$/bbl) 78.03 59.62 78.37 51.35
Dated Brent (Brent) (US$/bbl) 78.30 58.79 77.26 51.60
-------------------------------------------------------
Benchmark Differentials (1) (US$/bbl)
Heavy Oil 14.37 7.73 11.81 8.45
Mars 0.60 2.27 1.79 0.80
Masila (0.68) 0.93 0.47 0.49
Realized Prices from Producing Assets (Cdn$/bbl)
United Kingdom 77.18 69.42 77.21 60.38
Canada 57.24 56.05 61.37 45.49
Long Lake Synthetic 74.08 - 76.80 -
Syncrude 77.93 71.58 80.46 62.44
United States 73.60 66.23 76.34 57.05
Yemen 80.50 69.40 80.44 60.63
Other Countries 74.77 66.83 76.88 51.63
Corporate Average (Cdn$/bbl) 76.23 68.32 77.11 59.12
-------------------------------------------------------
NATURAL GAS
New York Mercantile Exchange (US$/mmbtu) 4.34 3.81 4.69 4.15
AECO (Cdn$/mcf) 3.66 3.47 4.37 4.41
-------------------------------------------------------
Realized Prices from Producing Assets (Cdn$/mcf)
United Kingdom 4.80 3.67 4.80 4.69
Canada 3.72 3.42 4.38 4.09
United States 5.14 4.58 5.58 5.19
Corporate Average (Cdn$/mcf) 4.42 3.77 4.89 4.43
-------------------------------------------------------
NEXEN'S AVERAGE REALIZED OIL AND GAS PRICE (Cdn$/boe) 67.46 61.28 68.78 54.28
-------------------------------------------------------
AVERAGE FOREIGN EXCHANGE RATE - Canadian to US Dollar 0.9731 0.8571 0.9673 0.8290
-------------------------------------------------------
(1) These differentials are a discount/(premium) to WTI.
HIGHER COMMODITY PRICES INCREASED QUARTERLY NET INCOME BY $123 MILLION
WTI averaged US$78.03/bbl for the quarter, consistent with the previous quarter
but 31% higher when compared to last year. Dated Brent averaged US$78.30/bbl for
the quarter, 3% and 33% higher than the previous quarter and prior year,
respectively. These price increases have been mitigated somewhat by the weaker
US dollar. Our realized oil price averaged $76.23/bbl, 12% higher than the
second quarter of 2009.
Natural gas prices decreased during the quarter, with NYMEX averaging
US$4.34/mmbtu and AECO averaging $3.66/mcf, 14% and 28% lower, respectively than
the previous quarter. As a result, our realized gas price decreased 18% to
average $4.42/mcf. Compared to the same period last year, our realized gas price
is 17% higher as NYMEX increased 14% and AECO increased 6%.
The US dollar has weakened considerably against the Canadian dollar since 2009.
This has reduced our net sales by approximately $181 million, as our realized
crude oil and gas prices were $10.32/bbl and $0.60/mcf lower, respectively.
However, our US-denominated costs and US-denominated debt are also lower when
translated to Canadian dollars as a result of the weaker US dollar.
41
CRUDE OIL REFERENCE PRICES
Crude oil prices were 31% higher than the second quarter 2009. WTI traded
between US$65/bbl and US$80/bbl for the quarter. Prices were volatile due to
conflicting drivers. Weak near-term market fundamentals and concerns about
sovereign debt levels and a double-dip recession placed downward pressure on
crude oil prices, whereas continued investment in commodity markets and strong
oil market fundamentals in the medium term due to stronger demand from emerging
markets and tightening supply, supported prices.
Global crude oil inventory levels remain high and recent OPEC supply growth has
diminished expectations that inventories will be reduced by the typical seasonal
increase in demand. Higher OPEC supply increased US imports of crude oil and
contributed to higher inventory levels at Cushing.
The global economy continues to recover from the financial crisis but the
recovery is tentative and risks remain that could lead to slower global growth
and lower demand for crude oil. There are concerns that the US and Europe could
experience a sustained period of low growth and deflation similar to that
experienced in Japan over the last decade. Countries are facing pressure to
impose fiscal restraints to avoid a debt crisis similar to Greece, and China is
withdrawing economic and financial stimuli because of concerns about inflation
and an overheating economy. Despite these concerns, recent macro-economic
indicators have been positive. Increased world trade flows, higher industrial
production and positive manufacturing surveys results all point to a
strengthening global economy.
Geopolitical events such as expectations of United Nation's sanctions against
Iran, escalating tensions between North and South Korea, continuing attacks to
oil infrastructure in Nigeria and the ongoing wars in Iraq and Afghanistan have
not had a material impact on oil prices during the quarter. However, a much
tighter supply/demand environment will increase price sensitivity to
geopolitical events. The six month drilling moratorium in the US is expected to
delay new field start-ups and accelerate decline rates reducing crude oil supply
which should support future crude oil prices.
CRUDE OIL DIFFERENTIALS
Unplanned turnarounds and refinery downtime caused the heavy oil differential to
fluctuate during the quarter. In June, the differential returned to narrower
levels seen earlier this year. In the longer term, differentials are expected to
be narrower than historic levels due to declining heavy oil production and
excess heavy refinery capacity.
The Brent/WTI differential traded at a premium to WTI for most of the quarter
primarily due to lower WTI prices caused by high inventory levels at Cushing.
Brent prices were also supported by maintenance downtime at North Sea fields
which reduced supply.
The Masila price strengthened relative to WTI following the movement in the
WTI/Brent differential and 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, declining heavy oil
production and high inventory levels at Cushing also supported the Mars
differential.
NATURAL GAS REFERENCE PRICES
NYMEX natural gas prices continued to decline due to warm weather reducing
demand while supply remained strong. Natural gas producers continue to drill
despite low prices, partly to avoid losing land leases. Gas prices are expected
to remain low until inventory levels are reduced by lower supply or increased
demand from strong economic growth, a hot summer or an active hurricane season.
42
OPERATING EXPENSES(1)
Three Months Six Months
Ended June 30 Ended June 30
(Cdn$/boe) 2010 2009 2010 2009
----------------------------------------------------------------------------------------------------------------------------
Operating expenses based on our production before royalties (2)
Conventional Oil and Gas 9.42 8.80 9.18 8.53
Long Lake Synthetic (3) 88.39 - 112.71 -
Syncrude 33.33 57.21 35.64 45.70
Average Oil and Gas 15.07 11.95 15.12 11.27
---------------------------------------------------
Operating expenses based on our production after royalties
Conventional Oil and Gas 10.75 10.28 10.56 9.86
Long Lake Synthetic (3) 91.67 - 117.63 -
Syncrude 36.22 65.36 38.83 48.59
Average Oil and Gas 17.05 13.94 17.24 12.95
---------------------------------------------------
(1) Includes results of discontinued operations (See Note 15 of our Unaudited
Consolidated Financial Statements).
(2) 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.
(3) Excludes activities related to third-party bitumen purchased, processed and
sold.
HIGHER OPERATING EXPENSES REDUCED QUARTERLY NET INCOME BY $86 MILLION
Operating costs increased $86 million or 34% from the previous year primarily
due to costs associated with our Long Lake project. As of January 1, 2010, we
ceased capitalizing our Long Lake start-up costs. Total operating costs at Long
Lake have largely remained flat since the first quarter as most of the costs are
fixed. With growing volumes, our Long Lake per unit operating costs have
improved 43% over the previous quarter. When fully ramped up, we expect Long
Lake operating costs to be about $25 to $30/bbl.
Changes in production mix with i) natural declines in Canada and Yemen; ii)
higher production at Scott/Telford in the North Sea, partially offset by
decreases at Buzzard; iii) increased production at Syncrude; and iv) inclusion
of Long Lake operating costs, have increased our corporate average by $2.48/boe.
The stronger Canadian dollar reduced our corporate average by $1.16/boe as
operating costs of our international and US assets are denominated in US
dollars.
In the UK North Sea, Buzzard operating costs were consistent with the previous
year; however, production was temporarily lower following the installation of
the new platform topside facilities and other planned maintenance work. This
increased our corporate average operating cost by $0.31/boe. Elsewhere in the UK
North Sea, our corporate average was lower by $0.61/boe as higher production at
Scott/Telford and Ettrick reduced our average cost per barrel. We expect to see
these unit costs decrease further as Ettrick ramps up to full production.
As expected, increased maintenance costs and natural declines in Yemen increased
our corporate average cost per barrel by $0.33/boe. We continue to incur costs
to maintain existing well productivity to maximize reserve recoveries and slow
the natural decline of the field. In the US Gulf of Mexico, increased costs of
recompletions and maintenance were partially offset by higher volumes,
increasing our corporate average operating cost by $0.14/boe.
In Canada, lower heavy oil downhole and surface maintenance costs were partially
offset by an increase in natural gas maintenance activities. These costs,
combined with lower production due to natural declines, increased our corporate
average by $0.15/boe. At Syncrude, lower maintenance costs and higher production
volumes decreased our corporate average by $2.30/boe. Coker 8-3 was operating
for the majority of the quarter compared to the same period last year, when a
major scheduled turnaround shut in production for most of the quarter.
43
DEPRECIATION, DEPLETION, AMORTIZATION AND IMPAIRMENT (DD&A)(1)
Three Months Six Months
Ended June 30 Ended June 30
(Cdn$/boe) 2010 2009 2010 2009
----------------------------------------------------------------------------------------------------------------------------
DD&A based on our production before royalties (2)
Conventional Oil and Gas 17.64 18.49 17.09 18.53
Long Lake Synthetic 21.10 - 21.60 -
Syncrude 6.71 6.31 6.85 6.40
Average Oil and Gas 16.79 17.69 16.41 17.64
---------------------------------------------------
DD&A based on our production after royalties
Conventional Oil and Gas 20.14 21.59 19.65 21.43
Long Lake Synthetic 21.85 - 22.43 -
Syncrude 7.29 7.21 7.47 6.80
Average Oil and Gas 18.97 20.64 18.69 20.26
---------------------------------------------------
(1) Includes results of discontinued operations (See Note 15 of our Unaudited
Consolidated Financial Statements).
(2) DD&A per boe is our DD&A for oil and gas operations divided by our working
interest production before royalties. We use production before royalties to
monitor our performance consistent with other Canadian oil and gas
companies.
HIGHER OIL AND GAS DD&A DECREASED NET INCOME FOR THE QUARTER BY $7 MILLION
Our average DD&A per-unit cost decreased $0.90/boe despite an increase in our
DD&A expense of $7 million. The stronger Canadian dollar reduced our corporate
average by $2.29/boe as depletion of our international and US assets is
denominated in US dollars. This was partially offset by changes in our
production mix as temporary decreases in Buzzard production were partially
offset by new production at Ettrick and the commencement of depletion at Long
Lake. This increased our average DD&A rate by $2.18/boe. Buzzard DD&A rates are
lower than our corporate average, whereas per-unit depletion rates at Ettrick
and Long Lake are higher. Depletion at Long Lake increased our consolidated
average cost by $0.90/boe.
In the UK North Sea, additional proved reserves booked at Buzzard at the end of
2009 lowered the depletion rate and reduced our corporate average by $0.55/boe.
The remainder of our UK fields decreased our corporate average by $0.26/boe.
Depletion rates in Yemen increased our corporate average $0.24/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 at the end of 2009, combined with lower
estimates for future abandonment costs, reduced our corporate average depletion
rate of $1.02/boe.
Canadian depletion costs were lower than the second quarter of 2009 decreasing
our corporate average by $0.12/boe. DD&A at our heavy oil properties decreased
$20 million or 63% from last year as: i) depletion rates were lower than last
year due to positive price-related reserve revisions at the end of 2009; and ii)
depletion of these assets ceased when the assets were classified as held for
sale. The effect of this was partially offset by higher natural gas depletion.
Lower natural gas prices at the end of 2009 reduced our CBM and natural gas
reserve estimates and increased our depletion rate.
44
EXPLORATION EXPENSE(1)
Three Months Six Months
Ended June 30 Ended June 30
2010 2009 2010 2009
--------------------------------------------------------------------------------
Seismic 17 31 29 43
Unsuccessful Drilling 1 16 42 27
Other 32 30 72 60
-------------------------------------------------
Total Exploration Expense 50 77 143 130
=================================================
(1) Includes results of discontinued operations (See Note 15 of our Unaudited
Consolidated Financial Statements).
LOWER EXPLORATION EXPENSE INCREASED NET INCOME FOR THE QUARTER BY $27 MILLION
In the Gulf of Mexico, we continue to evaluate our discovery at Appomattox where
we have drilled an exploratory well and two appraisal sidetracks. Appomattox is
the third discovery in the area following previous successful drilling at Shiloh
and Vicksburg. We continue to review potential development options for
Appomattox and Vicksburg. Additional appraisal drilling at Appomattox has been
delayed as a result of the six-month drilling moratorium in the Gulf of Mexico.
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 the Golden Eagle area.
Concept engineering is nearing completion and we expect to sanction development
in the next year. The Golden Eagle area includes our 34% operated interest in
Golden Eagle and Hobby and our 46% operated interest in Pink. During the
quarter, we drilled a successful appraisal well at Blackbird, six kilometres
south of our Ettrick field. Blackbird is a potential tie-back to the Ettrick
FPSO. We have an 80% operated interest at Blackbird. Later this year, we plan to
drill an exploration well at North Uist, west of the Shetlands, where we have a
35% non-operated interest.
Exploration expense decreased 35% or $27 million due to lower seismic and
unsuccessful drilling costs in the Gulf of Mexico. In the second quarter of
2009, we expensed costs related to non-commercial wells at Green Canyon and
Sapphire.
45
ENERGY MARKETING
Three Months Six Months
Ended June 30 Ended June 30
2010 2009 2010 2009
--------------------------------------------------------------------------------------------------------------------------------
Physical Sales (1) 8,188 10,063 18,302 20,008
Physical Purchases (1) (8,091) (9,604) (17,987) (19,406)
Net Financial Transactions (2) 36 (276) (28) (228)
Change in Fair Market Value of Inventory (21) 38 (89) 114
-------------------------------------------------------
Marketing Revenue 112 221 198 488
Transportation Expense (89) (163) (211) (328)
Other 7 (1) 6 4
-------------------------------------------------------
NET MARKETING REVENUE 30 57 (7) 164
=======================================================
CONTRIBUTION TO NET MARKETING REVENUE BY REGION
North America 22 55 (13) 159
Asia 1 6 2 18
Europe 7 (4) 4 (13)
-------------------------------------------------------
NET MARKETING REVENUE 30 57 (7) 164
DD&A (5) (3) (10) (7)
General and Administrative (11) (26) (32) (49)
Other (5) (19) (3) (23) -
-------------------------------------------------------
MARKETING CONTRIBUTION TO INCOME BEFORE INCOME TAXES (5) 25 (72) 108
=======================================================
NORTH AMERICA
NATURAL GAS
Physical Sales Volumes (3) (bcf/d) 3.1 4.6 4.0 4.8
Transportation Capacity (bcf/d) 1.4 1.3 1.4 1.3
Storage Capacity (bcf) 31.0 33.9 31.5 33.9
Financial Volumes (4) (bcf/d) 2.7 10.0 4.3 12.7
CRUDE OIL
Physical Sales Volumes (3) (mbbls/d) 889 873 822 835
Storage Capacity (mbbls) 2,750 2,644 2,858 2,644
Financial Volumes (4) (mbbls/d) 794 667 775 789
POWER
Physical Sales Volumes (3) (GWh/d) 9 10 9 7
Generation Capacity (MW) 87 87 87 87
ASIA
Physical Sales Volumes (3) (mbbls/d) 104 115 92 99
Financial Volumes (4) (mbbls/d) 306 531 330 425
EUROPE
Financial Volumes (4) (mbbls/d) 761 259 685 378
VALUE-AT-RISK
Quarter-end 8 15 8 15
High 15 19 15 24
Low 7 13 7 13
Average 12 15 12 17
-------------------------------------------------------
(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.
(5) Includes non-cash mark-to-market losses that will reverse with the sale of
North America Natural Gas Energy Marketing as described in Note 15 of our
Unaudited Consolidated Financial Statements.
46
LOWER CONTRIBUTION FROM ENERGY MARKETING DECREASED NET INCOME BY $43 MILLION
During the quarter, we signed an agreement to sell our North America natural gas
marketing business. The transaction is expected to close in the third quarter,
subject to customary closing conditions. 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 on closing. 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. In the
period between signing and closing, we have agreements with the purchaser which
transfers the market risk of our contracts and inventory to the purchaser unless
we breach our obligation to close the sale. 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 flow.
Our crude oil team generated modest gains during the quarter through blending
opportunities and a weakening Canadian dollar. At this time last year, our crude
oil group generated modest losses largely due to a strengthening Canadian
dollar. Gains were recognized in the first quarter of 2010 from our blending and
physical business.
Overall, second quarter revenue from energy marketing was lower than the prior
year largely driven by losses from North America natural gas. Since mid-2008,
low natural gas prices, high inventory levels and weak demand in consuming
regions have contributed to narrow location spreads making transportation and
storage assets less valuable. In 2010, the team incurred losses associated with
transportation used in the quarter, while generating gains last year. Those
gains were generated from the hedges in place to protect the assets in future
periods which more than offset losses associated with transportation used in the
quarter. Both our location and time spread strategies showed improved results
from the first quarter due to slightly improved market conditions.
COMPOSITION OF NET MARKETING REVENUE
Three Months Six Months
Ended June 30 Ended June 30
2010 2009 2010 2009
--------------------------------------------------------------------------------------------------------------------------------
Trading Activities (Physical and related Financial) 23 58 (13) 160
Other Activities 7 (1) 6 4
-------------------------------------------------------
Total Net Marketing Revenue 30 57 (7) 164
=======================================================
TRADING ACTIVITIES
In energy marketing, we enter into contracts to purchase and sell crude oil and
natural gas as well as storage and transportation contracts to capture time and
location differences. We also use financial and derivative contracts, including
futures, forwards, swaps and options for hedging and trading purposes. We
account for all financial and derivative contracts not designated as hedges for
accounting purposes using fair value accounting and record the change in fair
value in marketing and other income. The fair value of these instruments is
included with amounts receivable or payable and they are classified as long-term
or short-term based on their anticipated settlement date.
OTHER ACTIVITIES
We enter into fee for service contracts related to transportation, storage and
sales of third-party oil and gas. In addition, we earn income from our power
generation facilities at Balzac and Soderglen.
FAIR VALUE OF DERIVATIVE CONTRACTS
Our processes for estimating and classifying the fair value of our derivative
contracts are consistent with those in place at December 31, 2009.
At June 30, 2010, the fair value of our derivative contracts in our energy
marketing trading activities was $56 million. These derivatives are used to
economically hedge our physical storage and transportation contracts which
cannot be carried at fair value until they are used. Below is a breakdown of the
derivative fair value by valuation method and contract maturity.
MATURITY
--------------------------------------------------------------------------------------------------------------------------------
Less Than More Than
1 year 1-3 years 4-5 years 5 years Total
-----------------------------------------------------------------
Level 1 - Actively Quoted Markets (10) (67) (8) - (85)
Level 2 - Based on Other Observable Pricing Inputs 51 61 2 3 117
Level 3 - Based on Unobservable Pricing Inputs 11 13 - - 24
-----------------------------------------------------------------
Total 52 7 (6) 3 56
=================================================================
47
CHANGES IN FAIR VALUE OF DERIVATIVE CONTRACTS
Total
-------------------------------------------------------------------------------
Fair Value at December 31, 2009 23
Change in Fair Value of Contracts 27
Net Losses (Gains) on Contracts Closed 6
Changes in Valuation Techniques and Assumptions (1) -
-------------------
Fair Value at June 30, 2010 56
===================
(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 two years. Those maturing beyond one year
primarily relate to North American natural gas positions.
CHEMICALS
LOWER CHEMICALS CONTRIBUTION DECREASED NET INCOME BY $32 MILLION
Chlorate revenues in North America were marginally down from last year as higher
sales volumes were offset by a decline in realized prices. Chlorate revenues in
Brazil were consistent with the second quarter of 2009 as higher prices offset
lower volumes.
Chlor-alkali revenue in North America fell 12% from the same period last year as
the impact of a decrease in realized prices was only partially offset by
increased volumes. In late June, the technology conversion project (TCP) at the
North Vancouver chlor-alkali facility successfully started up. It is expected
that TCP will contribute $35 to $40 million in incremental operating cash flow
annually, beginning in the third quarter. These benefits are expected to be
generated by lower operating costs and volume expansion. In Brazil, higher
chlor-alkali prices were offset by lower volumes.
Chemicals net income includes foreign exchange losses of $13 million, compared
to the previous year when it included foreign exchange gains of $24 million.
Additionally, gains of $5 million related to interest swaps and foreign exchange
options and forwards were realized in the second quarter of 2009.
CORPORATE EXPENSES
GENERAL AND ADMINISTRATIVE (G&A)(1)
Three Months Six Months
Ended June 30 Ended June 30
2010 2009 2010 2009
--------------------------------------------------------------------------------------------------------------------------------
General and Administrative Expense before Stock-Based 110 111 226 211
Compensation
Stock-Based Compensation (2) (35) 56 (33) 56
-------------------------------------------------------
Total General and Administrative Expense 75 167 193 267
=======================================================
(1) Includes results of discontinued operations (See Note 15 of our Unaudited
Consolidated Financial Statements).
(2) Includes cash and non-cash expenses related to our tandem option and stock
appreciation rights plans.
LOWER G&A COSTS INCREASED NET INCOME BY $92 MILLION
Total G&A expenditures for the quarter decreased 55% from the same period last
year as a result of a decrease in stock-based compensation expense. Fluctuations
in our share price create volatility in our net income as we account for
stock-based compensation using the intrinsic-value method. During the quarter,
we reversed approximately $40 million of non-cash stock-based compensation that
was recognized in prior periods as our share price decreased 17%. Cash payments
made in connection with our stock-based compensation programs during the three
and six month period ended June 30, 2010 were $5 million and $8 million,
respectively (2009 - $14 million).
48
INTEREST
Three Months Six Months
Ended June 30 Ended June 30
2010 2009 2010 2009
--------------------------------------------------------------------------------------------------------------------------------
Interest 99 92 197 186
Less: Capitalized (22) (18) (40) (44)
-------------------------------------------------------
Net Interest Expense 77 74 157 142
=======================================================
Effective Interest Rate 5.6% 4.5% 5.4% 4.7%
-------------------------------------------------------
HIGHER NET INTEREST EXPENSE REDUCED NET INCOME BY $3 MILLION
Our financing costs increased $7 million from the second quarter of 2009. In
July 2009, we issued US$1 billion of long-term notes which generated additional
interest costs of $20 million. This was partially offset by the strengthening
Canadian dollar which decreased our US-denominated interest expense by $14
million.
Capitalized interest was $4 million higher than 2009. We are no longer
capitalizing interest on our Ettrick development in the North Sea. This decrease
has been offset by higher capitalized interest on our major development project
at Usan, offshore West Africa. We also continue to capitalize interest on the
construction of the new platform at Buzzard and future phases of Long Lake.
INCOME TAXES(1)
Three Months Six Months
Ended June 30 Ended June 30
2010 2009 2010 2009
--------------------------------------------------------------------------------------------------------------------------------
Current 264 206 523 324
Future (80) (229) (180) (316)
-------------------------------------------------------
Total Provision for Income Taxes 184 (23) 343 8
=======================================================
(1) Includes results of discontinued operations (See Note 15 of our Unaudited
Consolidated Financial Statements).
HIGHER TAXES REDUCED NET INCOME BY $207 MILLION
Stronger commodity prices compared to the same period last year caused an
increase to our tax expense. Our future tax expense in 2009 was also impacted by
the significant decrease in the value of our crude oil put options and 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.
OTHER
Three Months Six Months
Ended June 30 Ended June 30
2010 2009 2010 2009
--------------------------------------------------------------------------------------------------------------------------------
Increase (Decrease) in Fair Value of Crude Oil Put Options 1 (179) (15) (195)
-------------------------------------------------------
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. As at June 30, 2010,
the fair value of the options was approximately $2 million, $1 million higher
than the end of the previous quarter but $15 million lower than the end of 2009.
For the three and six month periods ended June 30, 2009, we recorded fair value
losses of $179 million and $195 million, respectively, on our 2009 crude oil put
option program.
During the quarter, we sold our non-core lands in the Athabasca region for
proceeds of $81 million. We had no plans to develop these lands for at least a
decade. We recognized a gain on the sale of $80 million.
49
LIQUIDITY AND CAPITAL RESOURCES
CAPITAL STRUCTURE
June 30 December 31
2010 2009
------------------------------------------------------------------------------------------------------------------------------
NET DEBT (1)
Bank Debt 930 1,803
Public Senior Notes 5,038 4,982
---------------------------------------
Total Senior Debt 5,968 6,785
Subordinated Debt 473 466
---------------------------------------
Total Debt 6,441 7,251
Less: Cash and Cash Equivalents (970) (1,700)
---------------------------------------
TOTAL NET DEBT 5,471 5,551
=======================================
EQUITY AT HISTORIC ISSUE COST 8,080 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:
Three Months Six Months
Ended June 30 Ended June 30
2010 2010
------------------------------------------------------------------------------------------------------------------------------
Capital Investment (817) (1,373)
Cash Flow from Operating Activities (1) 510 1,308
---------------------------------------
(307) (65)
Proceeds on Disposition of Assets 81 96
Dividends on Common Shares (26) (52)
Issue of Common Shares 10 35
Changes in Restricted Cash Requirements 68 83
Foreign Exchange Translation of US-dollar Debt and Cash (227) (86)
Other (13) 69
---------------------------------------
Decrease/(Increase) in Net Debt (414) 80
=======================================
(1) Includes changes in non-cash working capital. For the three and six months
ended June 30, 2010, outflows of $58 million and inflows of $198 million,
respectively, was included.
Our net debt increased approximately $400 million from March 31, primarily as a
result of i) capital investment exceeding cash flow generated from operating
activities; and ii) foreign exchange translation losses on our US-denominated
debt. Net debt is also impacted by changes in working capital. Timing of
receipts from strong June oil and gas sales will be received in July. These are
offset by fluctuations in cash tax remittances to governments. We used cash
generated from operating activities and existing cash on hand to repay a portion
of our outstanding term credit facilities during the quarter, while at the same
time, our available liquidity increased by $200 million during the quarter. Our
available liquidity at June 30, 2010 was approximately $3.8 billion, comprised
of cash on hand and undrawn credit facilities. We expect our available liquidity
to increase by $900 million following the completion of our heavy oil and energy
marketing natural gas sales, anticipated for the third quarter.
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.
50
CHANGE IN WORKING CAPITAL
June 30 December 31 Increase/
2010 2009 (Decrease)
----------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents 970 1,700 (730)
Restricted Cash 113 198 (85)
Accounts Receivable 2,675 2,788 (113)
Inventories and Supplies 621 680 (59)
Short-Term Borrowings (158) - (158)
Accounts Payable and Accrued Liabilities (3,101) (3,038) (63)
Other (9) 70 (79)
------------------------------------------------------
Net Working Capital 1,111 2,398
===================================
Our non-cash working capital balances remain largely unchanged from the end of
2009. Timing of cash tax remittances to governments during the year create
fluctuations in cash taxes payable between quarters.
At June 30, 2010, our restricted cash consists of margin deposits of $113
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).
Our future liquidity and ability to fully fund capital requirements generally
depend 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 $23 million for the
second half of the year. 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 $17 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 continued growth
in world demand and delays or shortages in supply growth. We believe that our
existing liquidity, balance sheet capacity and capital investment flexibility
provide us with the ability to fund our ongoing obligations during periods of
lower commodity prices.
During the first half of the year, we incurred approximately half of our 2010
capital budget. We currently have approximately $1 billion of cash and cash
equivalents on hand and as well as significant undrawn committed credit
facilities available. We also expect to generate over $900 million of additional
liquidity in the third quarter, upon closing the sales of our heavy oil
properties and natural gas marketing businesses. At June 30, 2010, we had
unsecured term credit facilities of US$3.1 billion in place of which US$450
million was drawn and US$317 million is being used to support outstanding
letters of credit. We also have approximately $467 million of uncommitted,
unsecured credit facilities, of which $158 million was drawn and $24 million is
being used to support outstanding letters of credit. The average
length-to-maturity of our public debt is approximately 19 years.
51
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 first 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. At June 30, 2010 our total exposure
is $71 million. The guarantees expire at the earlier of the purchaser replacing
the guarantees and September 25, 2010. We are obligated to perform under the
guarantees only if the purchaser does not meet its obligations to the
counterparties. To eliminate our exposure under the guarantees the purchaser has
provided us an indemnity and an irrevocable 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.
52
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 transition project progress.
------------------------------------------- ------------------------------------------ -----------------------------------------
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 diagnostics phase o Received senior management
IFRS o Senior management approval of approval of IFRS accounting policies
o Identify potential adjustments to IFRS accounting policies o Areas of potential adjustment to
initial IFRS financial statements o Develop draft IFRS financial opening balance sheet identified
o Develop IFRS-compliant financial statements and disclosures o Analysis to support opening balance
statements, including transition sheet adjustments is ongoing
period disclosures o No significant impact on key
performance indicators identified
to date
o Preparation and assessment of Q1
IFRS data is underway
o Data source testing for draft Q1 IFRS
financial statements and note
disclosures are substantially
complete
------------------------------------------- ------------------------------------------ -----------------------------------------
Training and Communication
------------------------------------------- ------------------------------------------ -----------------------------------------
o Develop and deliver targeted IFRS o Delivery of training in 2009 targeted o Targeted training completed in 2009
training to employees and to affected employees o Strategy for follow-up training in
management o Ongoing communication with major 2010 developed
o Ensure internal and external internal and external stakeholders o Training sustainment plan prepared
stakeholders receive ongoing 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 o Be IFRS data capture ready January o System testing for IFRS data capture
adequately support conversion to 1, 2010 complete
IFRS and ongoing financial o Ensure dual GAAP reporting o Dual GAAP reporting capability for
reporting capability throughout 2010 2010 testing complete
o IFRS data capture in the financial
system for Q1 was successful
------------------------------------------- ------------------------------------------ -----------------------------------------
Business Process
------------------------------------------- ------------------------------------------ -----------------------------------------
o Ensure business processes and o Implement necessary business o Necessary changes to business
control environment properly process and key control changes to process have been designed
support conversion to IFRS and ensure adequate internal control o Key controls designed to ensure
ongoing financial reporting over financial reporting adequate internal control over
financial reporting on IFRS results
throughout 2010
o Changes to business processes
being tested
------------------------------------------- ------------------------------------------ -----------------------------------------
At this time, we cannot quantify with certainty 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.
53
US PRONOUNCEMENTS
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.
EQUITY SECURITY REPURCHASES
During the quarter, we made no purchases of our equity securities.
SUMMARY OF QUARTERLY RESULTS
| 2008 | 2009 | 2010
-------------------------------------------------|-------------------|--------------------------------------|------------------
(Cdn$ millions, except per share amounts) | Sep Dec | Mar Jun Sep Dec | Mar Jun
-------------------------------------------------------------------------------------------------------------------------------
Net Sales from Continuing Operations 2,094 1,214 1,004 1,138 1,034 1,486 1,432 1,399
Net Income (Loss) from Continuing Operations 830 (185) 152 23 122 256 172 242
Net Income (Loss) from Discontinued Operations 56 4 (17) (3) - 3 13 13
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Net Income (Loss) 886 (181) 135 20 122 259 185 255
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Earnings (Loss) Per Common Share from
Continuing Operations ($/share)
Basic 1.58 (0.36) 0.28 0.05 0.23 0.49 0.33 0.46
Diluted 1.56 (0.36) 0.28 0.05 0.23 0.48 0.33 0.46
Earnings (Loss) Per Common Share ($/share)
Basic 1.68 (0.35) 0.26 0.04 0.23 0.50 0.35 0.49
Diluted 1.66 (0.35) 0.26 0.04 0.23 0.49 0.35 0.49
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SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS
Certain statements in this report, including those appearing in MANAGEMENT'S
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS,
constitute "forward-looking statements" (within the meaning of the United States
PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995, as amended) or
"forward-looking information" (within the meaning of applicable Canadian
securities legislation). Such statements or information (together
"forward-looking statements") are generally identifiable by the forward-looking
terminology used such as "ANTICIPATE", "BELIEVE", "INTEND", "PLAN", "EXPECT",
"ESTIMATE", "BUDGET", "OUTLOOK", "FORECAST" or other similar words, and include
statements relating to or associated with individual wells, regions or projects.
Any statements regarding the following are forward-looking statements:
o future crude oil, natural gas or chemicals prices;
o future production levels;
o future 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 the expectation that we have the ability to substantially grow production
at our oil sands facilities through controlled expansions;
o the expectation of achieving the production design rates from our oil sands
facilities;
o the expectation that our oil sands production facilities continue to
develop better and more sustainable practices;
o the expectation of cheaper and more technologically advanced operations;
54
o the expected timing and associated production impact of facilities
turnarounds and maintenance;
o the expectation that we can continue to operate our offshore exploration,
development and production facilities safely and profitably;
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 operating costs;
o future cost recovery oil revenues from our Yemen operations;
o future demand for chemical products;
o estimates on a per share basis;
o future foreign currency exchange rates;
o future expenditures and future allowances relating to environmental
matters;
o dates by which certain areas will be developed, will come on-stream or
reach expected operating capacity; and
o changes in any of the foregoing.
Statements relating to "reserves" or "resources" are forward-looking statements,
as they involve the implied assessment, based on estimates and assumptions, that
the reserves and resources described exist in the quantities predicted or
estimated, and can be profitably produced in the future.
The forward-looking statements are subject to known and unknown risks and
uncertainties and other factors which may cause actual results, levels of
activity and achievements to differ materially from those expressed or implied
by such statements. Such factors include, among others:
o market prices for oil and gas and chemical products;
o our ability to explore, develop, produce, upgrade and transport crude oil
and natural gas to markets;
o ultimate effectiveness of design or design modification to facilities;
o the results of exploration and development drilling and related activities;
o the cumulative impact of oil sands development on the environment;
o the impact of technology on operations and processes and how new complex
technology may not perform as expected;
o the availability of pipeline and global refining capacity;
o risks inherent to the operations of any large, complex refinery units,
especially the integration between production operations and an upgrader
facility;
o availability of third-party bitumen for use in our oil sands production
facilities;
o labour and material shortages;
o risk related to accidents, blowouts and spills in connection with our
offshore exploration, development and production activities, particularly
our deepwater activities;
o direct and indirect risk related to the imposition of moratoriums,
suspensions or cancellations of our offshore exploration, development and
production operations, particular our deepwater activities;
o the impact of severe weather on our offshore exploration, development and
production activities, particularly our deepwater activities;
o the effectiveness and reliability of our technology in harsh and
unpredictable environments;
o risks related to the actions of our agents and contractors;
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 including without limitation,
those related to our offshore exploration, development and production
activities;
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.
55
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.
CREDIT RISK
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 June 30, 2010:
o over 95% of our credit exposures were investment grade;
o approximately 81% of our credit exposures were with a diverse group of
integrated oil companies, crude oil refiners and marketers, and large
utilities; and
o only 2 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.
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.
56
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 six months of 2010 that has materially affected, or is
reasonably likely to materially affect, the Company's internal control over
financial reporting.
PART II
ITEM 1. LEGAL PROCEEDINGS
Information in response to this item is included in Part I, Item 1 in Note 17
"Commitments, Contingencies and Guarantees" and is incorporated by reference
into Part II of this Quarterly Report on Form 10-Q.
ITEM 1A. RISK FACTORS
We are also exposed to normal risks typical in the oil and gas exploration,
development and production business, including operational risks, regulatory
risks and the inherent uncertainty of discovery and producability of oil and gas
deposits.
DEEP WATER OPERATIONS
Our deep water operations take place in difficult and unpredictable environments
and are subject to the risk of blowouts and other catastrophic events that could
result in suspension of operations, damage to equipment, harm to individuals and
damage to the environment. While various precautions are taken to reduce the
risks, such efforts cannot eliminate the risk that such events may occur. The
consequences of such catastrophic events occurring in deep water operations can
be more difficult and time-consuming to remedy. As well, the remedy may be made
more difficult or uncertain by the water depths, pressures and cold temperatures
encountered in deep water operations, shortages of equipment and specialists
required to work in these conditions, or the absence of appropriate means to
effectively remedy such consequences. Emergency response plans that we have in
place, to address the environmental impact from spills, leaks, blowouts or other
events in connection with our operations may not be entirely effective in
mitigating the consequences of blowouts or other catastrophic events. Our deep
water operations could also be affected by the actions of our contractors and
agents that could result in similar catastrophic events at their facilities, or
could be indirectly affected by catastrophic events occurring at third-party
deep water operations, which, in either case, could give rise to liability for
us, damage to our equipment, harm to individuals, force a shutdown of our
facilities or operations, or result in a shortage of appropriate equipment or
specialists required to perform our planned operations. It is possible that the
allocation of liabilities and risk of loss arising from deepwater operations and
associated insurance coverage will not be sufficient to address the costs
arising out of such events.
The costs in connection with a blowout or other catastrophic event could be
material and we may not maintain sufficient insurance to address such costs. As
it pertains to these types of deep water risks, we maintain insurance for costs
relating to property damage to our facilities, control of well including
drilling relief wells, removal of wreck, pollution cleanup, bodily injury and
property damage to third parties. We are covered for a maximum loss up to US$1.5
billion, net to our working interest in the well, subject to certain sub-limits
for each of the areas covered. We also carry coverage up to US$50 million for
each of the costs relating to damage to natural resources, and civil fines and
penalties.
The recent explosion and sinking of the Deepwater Horizon rig in the Gulf of
Mexico and the resulting oil spill have resulted in increased scrutiny of deep
water operations by governments, environmental groups, investors and the general
public, not only in the United States but globally. It is anticipated this will
result in increased regulation of deep water operations, increased cost of
compliance with applicable laws, and greater difficulty in permitting deep water
operations. For example, the Obama administration has announced a six-month
moratorium on new deep water well permits. This moratorium has delayed current
exploration and appraisal activities until it is lifted and could ultimately
increase their cost. Possible extensions and/or regulatory changes limiting or
delaying the issuance of drilling permits could delay future exploration and
appraisal programs and ultimately increase their cost. There is a risk that
liability limits under existing regulations could be increased substantially by
the US Government, which would increase our potential liability in the event of
a blowout or other catastrophic event. We also may not be able to access
sufficient pooled liability funds set up in the Gulf of Mexico for costs of a
blowout or other catastrophic event.
Catastrophic events in connection with our deep water operations, such as
blowouts and oil spills, could result in material costs and reputational damage,
and could have a material adverse impact on our credit rating, our ability to
raise capital or the cost of such capital.
Further information on market and operational risks can be found in Item 1A on
pages 40-47 and Item 7A on pages 92 - 94 in our 2009 Form 10-K, which have not
materially changed.
57
ITEM 4. (REMOVED AND RESERVED)
58
ITEM 6. EXHIBITS
10.62 Amended and Restated Credit Agreement dated June 21, 2010 (originally
dated as of July 22, 2005) by and among Nexen Inc., Nexen Holdings
U.S.A. Inc. and Nexen Petroleum U.K. Limited as borrowers, the financial
institutions named therein and other institutions from time to time
party thereto as lenders and The Toronto-Dominion Bank, Toronto Dominion
(Texas) LLC abs The Toronto-Dominion Bank, London Branch as agents of
the lenders (filed as Exhibit 10.1 to Form 8-K filed with the SEC on
June 24, 2010).
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 July 21, 2010.
NEXEN INC.
/s/ Marvin F. Romanow /s/ Brendon T. Muller
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Marvin F. Romanow Brendon T. Muller
President and Chief Executive Officer Controller
(Principal Executive Officer) (Principal Accounting Officer)
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