10-Q 1 form10q_209.txt FOR QUARTER ENDED 6-30-09 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, 2009 [_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from ..... to ......... COMMISSION FILE NUMBER 1-6702 [GRAPHIC OMITTED] NEXEN INC. Incorporated under the Laws of Canada 98-6000202 (I.R.S. Employer Identification No.) 801 - 7th Avenue S.W. Calgary, Alberta, Canada T2P 3P7 Telephone (403) 699-4000 Web site - WWW.NEXENINC.COM Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [ ] Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (ss.232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes [ ] No [ ] Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer", "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act. Large accelerated filer [X] Accelerated filer [ ] Non-Accelerated filer [ ] Smaller reporting company [ ] Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes [ ] No [X] On June 30, 2009, there were 521,205,270 common shares issued and outstanding. NEXEN INC. INDEX PART I FINANCIAL INFORMATION PAGE Item 1. Unaudited Consolidated Financial Statements .....................3 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A) ...............................29 Item 3. Quantitative and Qualitative Disclosures about Market Risk .....49 Item 4. Controls and Procedures ........................................49 PART II OTHER INFORMATION Item 1. Legal Proceedings ..............................................50 Item 4. Submission of Matters to a Vote of Security Holders ............50 Item 6. Exhibits .......................................................50 This report should be read in conjunction with our 2008 Annual Report on Form 10-K (2008 Form 10-K) and with our current reports on Forms 8-K filed or furnished during the year. SPECIAL NOTE TO CANADIAN INVESTORS Nexen is a US Securities and Exchange Commission (SEC) registrant and a Form 10-K and related forms filer. Therefore, our reserves estimates and securities regulatory disclosures generally follow SEC requirements. In 2004, certain Canadian regulatory authorities adopted NATIONAL INSTRUMENT 51-101 - STANDARDS OF DISCLOSURE FOR OIL AND GAS ACTIVITIES (NI 51-101) which prescribe that Canadian companies follow certain standards for the preparation and disclosure of reserves and related information. We have been granted certain exemptions from NI 51-101. Please refer to the SPECIAL NOTE TO CANADIAN INVESTORS on page 79 of our 2008 Form 10-K. UNLESS WE INDICATE OTHERWISE, ALL DOLLAR AMOUNTS ($) ARE IN CANADIAN DOLLARS, AND OIL AND GAS VOLUMES, RESERVES AND RELATED PERFORMANCE MEASURES ARE PRESENTED ON A WORKING-INTEREST, BEFORE-ROYALTIES BASIS. WHERE APPROPRIATE, INFORMATION ON AN AFTER-ROYALTIES BASIS IS PRESENTED IN TABULAR FORMAT. VOLUMES AND RESERVES INCLUDE SYNCRUDE OPERATIONS UNLESS OTHERWISE STATED. Below is a list of terms specific to the oil and gas industry. They are used throughout the Form 10-Q.
/d = per day mcf = thousand cubic feet bbl = barrel mmcf = million cubic feet mbbls = thousand barrels bcf = billion cubic feet mmbbls = million barrels NGL = natural gas liquid mmbtu = million British thermal units WTI = West Texas Intermediate boe = barrel of oil equivalent MW = megawatt mboe = thousand barrels of oil equivalent GWh = gigawatt hours mmboe = million barrels of oil equivalent Brent = Dated Brent PSCTM = Premium Synthetic CrudeTM NYMEX = New York Mercantile Exchange
In this Form 10-Q, we refer to oil and gas in common units called barrel of oil equivalent (boe). A boe is derived by converting six thousand cubic feet of gas to one barrel of oil (6 mcf/1 bbl). This conversion may be misleading, particularly if used in isolation, as the 6 mcf/1 bbl ratio is based on an energy equivalency at the burner tip and does not represent a value equivalency at the well head. Electronic copies of our filings with the SEC and the Ontario Securities Commission (OSC) (from November 8, 2002 onward) are available, free of charge, on our web site (WWW.NEXENINC.COM). Filings prior to November 8, 2002 are available free of charge, upon request, by contacting our investor relations department at (403) 699-5931. As soon as reasonably practicable, our filings are made available on our website once they are electronically filed with the SEC or the OSC. Alternatively, the SEC and the OSC each maintain a website (WWW.SEC.GOV and WWW.SEDAR.COM) that contains our reports, proxy and information statements and other published information that have been filed or furnished with the SEC and the OSC. On June 30, 2009, the noon-day exchange rate was US$0.8602 for Cdn$1.00, as reported by the Bank of Canada. 2 PART I ITEM 1. UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS TABLE OF CONTENTS Page Unaudited Consolidated Statement of Income for the Three and Six Months Ended June 30, 2009 and 2008....................4 Unaudited Consolidated Balance Sheet as at June 30, 2009 and December 31, 2008....................................5 Unaudited Consolidated Statement of Cash Flows for the Three and Six Months Ended June 30, 2009 and 2008....................6 Unaudited Consolidated Statement of Shareholders' Equity for the Three and Six Months Ended June 30, 2009 and 2008....................7 Unaudited Consolidated Statement of Comprehensive Income for the Three and Six Months Ended June 30, 2009 and 2008....................7 Notes to Unaudited Consolidated Financial Statements.........................8 3
NEXEN INC. UNAUDITED CONSOLIDATED STATEMENT OF INCOME FOR THE THREE AND SIX MONTHS ENDED JUNE 30 Three Months Six Months Ended June 30 Ended June 30 (Cdn$ millions, except per share amounts) 2009 2008 2009 2008 ------------------------------------------------------------------------------------------------------------- REVENUES AND OTHER INCOME Net Sales 1,200 2,071 2,248 3,941 Marketing and Other (Note 15) 82 34 339 256 ------------------------------------------- 1,282 2,105 2,587 4,197 ------------------------------------------- EXPENSES Operating 320 348 625 657 Depreciation, Depletion, Amortization and Impairment 413 334 822 698 Transportation and Other 232 195 433 400 General and Administrative 167 418 267 473 Exploration 77 101 130 133 Interest (Note 10) 74 16 142 43 ------------------------------------------- 1,283 1,412 2,419 2,404 ------------------------------------------- INCOME (LOSS) BEFORE PROVISION FOR INCOME TAXES (1) 693 168 1,793 ------------------------------------------- PROVISION FOR (RECOVERY OF) INCOME TAXES Current 206 451 324 843 Future (229) (139) (316) (62) ------------------------------------------- (23) 312 8 781 ------------------------------------------- NET INCOME 22 381 160 1,012 Less: Net Income Attributable to Non-Controlling Interests (2) (1) (5) (2) ------------------------------------------- NET INCOME ATTRIBUTABLE TO NEXEN INC. 20 380 155 1,010 =========================================== EARNINGS PER COMMON SHARE ($/share) (Note 16) Basic 0.04 0.72 0.30 1.91 =========================================== Diluted 0.04 0.70 0.30 1.87 ===========================================
SEE ACCOMPANYING NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS. 4
NEXEN INC. UNAUDITED CONSOLIDATED BALANCE SHEET June 30 December 31 (Cdn$ millions, except share amounts) 2009 2008 ---------------------------------------------------------------------------------------------------- ASSETS CURRENT ASSETS Cash and Cash Equivalents 1,974 2,003 Restricted Cash (Notes 2 and 8) 335 103 Accounts Receivable (Note 3) 3,272 3,163 Inventories and Supplies (Note 4) 598 484 Other 167 169 ---------------------------- Total Current Assets 6,346 5,922 ---------------------------- PROPERTY, PLANT AND EQUIPMENT Net of Accumulated Depreciation, Depletion, Amortization and Impairment of $10,722 (December 31, 2008 - $10,393) 15,917 14,922 GOODWILL 372 390 FUTURE INCOME TAX ASSETS 921 351 DEFERRED CHARGES AND OTHER ASSETS (Note 6) 370 570 ---------------------------- TOTAL ASSETS 23,926 22,155 ============================ LIABILITIES CURRENT LIABILITIES Accounts Payable and Accrued Liabilities (Note 9) 3,608 3,326 Accrued Interest Payable 63 67 Dividends Payable 26 26 ---------------------------- Total Current Liabilities 3,697 3,419 ---------------------------- LONG-TERM DEBT (Note 10) 7,863 6,578 FUTURE INCOME TAX LIABILITIES 2,852 2,619 ASSET RETIREMENT OBLIGATIONS (Note 12) 1,044 1,024 DEFERRED CREDITS AND OTHER LIABILITIES (Note 13) 1,167 1,324 SHAREHOLDERS' EQUITY (Note 14) Nexen Inc. Shareholders' Equity Common Shares, no par value Authorized: Unlimited Outstanding: 2009 - 521,205,270 shares 2008 - 519,448,590 shares 1,011 981 Contributed Surplus 2 2 Retained Earnings 6,393 6,290 Accumulated Other Comprehensive Loss (157) (134) ---------------------------- Total Nexen Inc. Shareholders' Equity 7,249 7,139 Non-Controlling Interests 54 52 ---------------------------- TOTAL SHAREHOLDERS' EQUITY 7,303 7,191 COMMITMENTS, CONTINGENCIES AND GUARANTEES (Note 17) ---------------------------- TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY 23,926 22,155 ============================
SEE ACCOMPANYING NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS. 5
NEXEN INC. UNAUDITED CONSOLIDATED STATEMENT OF CASH FLOWS FOR THE THREE AND SIX MONTHS ENDED JUNE 30 Three Months Six Months Ended June 30 Ended June 30 (Cdn$ millions) 2009 2008 2009 2008 --------------------------------------------------------------------------------------------------------------------- OPERATING ACTIVITIES Net Income 22 381 160 1,012 Charges and Credits to Income not Involving Cash (Note 18) 394 470 713 852 Exploration Expense 77 101 130 133 Changes in Non-Cash Working Capital (Note 18) (340) 232 80 372 Other (44) (21) (185) (38) --------------------------------------------- 109 1,163 898 2,331 FINANCING ACTIVITIES Proceeds from (Repayment of) Term Credit Facilities, Net 632 - 1,643 (228) Proceeds from (Repayment of) Canexus Term Credit Facilities, Net 42 (18) 52 (10) Proceeds from Canexus Notes - 51 - 51 Repayment of Medium-Term Notes - (125) - (125) Dividends on Common Shares (26) (27) (52) (40) Distributions Paid to Non-Controlling Interests (4) (3) (7) (7) Issue of Common Shares and Exercise of Tandem Options for Shares 7 14 30 40 Other - (2) (1) (2) --------------------------------------------- 651 (110) 1,665 (321) INVESTING ACTIVITIES Capital Expenditures Exploration and Development (631) (606) (1,335) (1,375) Proved Property Acquisitions - (2) (755) (2) Marketing, Chemicals, Corporate and Other (84) (30) (129) (47) Proceeds on Disposition of Assets 1 - 15 - Changes in Restricted Cash 67 (174) (247) (53) Changes in Non-Cash Working Capital (Note 18) (74) (76) (55) (54) Other 1 (70) (1) (97) --------------------------------------------- (720) (958) (2,507) (1,628) EFFECT OF EXCHANGE RATE CHANGES ON CASH AND CASH EQUIVALENTS (120) (5) (85) 26 --------------------------------------------- INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (80) 90 (29) 408 CASH AND CASH EQUIVALENTS - BEGINNING OF PERIOD 2,054 524 2,003 206 --------------------------------------------- CASH AND CASH EQUIVALENTS - END OF PERIOD (1) 1,974 614 1,974 614 =============================================
(1) Cash and cash equivalents at June 30, 2009 consist of cash of $227 million and short-term investments of $1,747 million (June 30, 2008 - cash of $32 million and short-term investments of $582 million). SEE ACCOMPANYING NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS. 6
NEXEN INC. UNAUDITED CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY FOR THE THREE AND SIX MONTHS ENDED JUNE 30 Three Months Six Months Ended June 30 Ended June 30 (Cdn$ millions) 2009 2008 2009 2008 ------------------------------------------------------------------------------------------------------------------------- COMMON SHARES, Beginning of Period 1,004 949 981 917 Issue of Common Shares 6 4 29 24 Exercise of Tandem Options for Shares 1 10 1 16 Accrued Liability Relating to Tandem Options Exercised for Common Shares - 9 - 15 -------------------------------------------- Balance at End of Period 1,011 972 1,011 972 ============================================ CONTRIBUTED SURPLUS, Beginning of Period 2 3 2 3 Exercise of Tandem Options - (1) - (1) -------------------------------------------- Balance at End of Period 2 2 2 2 ============================================ RETAINED EARNINGS, Beginning of Period 6,399 5,600 6,290 4,983 Net Income Attributable to Nexen Inc. 20 380 155 1,010 Dividends on Common Shares (Note 14) (26) (27) (52) (40) -------------------------------------------- Balance at End of Period 6,393 5,953 6,393 5,953 ============================================ ACCUMULATED OTHER COMPREHENSIVE LOSS, Beginning of Period (128) (266) (134) (293) Other Comprehensive Income (Loss) (29) (8) (23) 19 -------------------------------------------- Balance at End of Period (157) (274) (157) (274) ============================================ NON-CONTROLLING INTERESTS, Beginning of Period 52 64 52 67 Net Income Attributable to Non-Controlling Interests 6 1 9 2 Distributions Declared to Non-Controlling Interests (5) (4) (9) (8) Issue of Partnership Units to Non-Controlling Interests under Distribution Reinvestment Plan 1 1 2 1 -------------------------------------------- Balance at End of Period 54 62 54 62 ============================================ NEXEN INC. UNAUDITED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME (LOSS) FOR THE THREE AND SIX MONTHS ENDED JUNE 30 Three Months Six Months Ended June 30 Ended June 30 (Cdn$ millions) 2009 2008 2009 2008 ------------------------------------------------------------------------------------------------------------------------- NET INCOME ATTRIBUTABLE TO NEXEN INC. 20 380 155 1,010 Other Comprehensive Income (Loss), Net of Income Taxes: Foreign Currency Translation Adjustment Net Gains (Losses) on Investment in Self-Sustaining Foreign Operations (459) (42) (285) 144 Net Gains (Losses) on Foreign-Denominated Debt Hedging Self- Sustaining Foreign Operations(1) 430 34 262 (125) -------------------------------------------- Other Comprehensive Income (Loss) (29) (8) (23) 19 -------------------------------------------- COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO NEXEN INC. (9) 372 132 1,029 ============================================
(1) Net of income tax expense for the three months ended June 30, 2009 of $62 million (2008 - $4 million expense) and net of income tax expense for the six months ended June 30, 2009 of $38 million (2008 - $19 million recovery). SEE ACCOMPANYING NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS. 7 NEXEN INC. NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS Cdn$ millions, except as noted 1. ACCOUNTING POLICIES Our Unaudited Consolidated Financial Statements are prepared in accordance with Canadian Generally Accepted Accounting Principles (GAAP). The impact of significant differences between Canadian and United States GAAP on the Unaudited Consolidated Financial Statements is disclosed in Note 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, 2009 and December 31, 2008 and the results of our operations and our cash flows for the three and six months ended June 30, 2009 and 2008. We make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the Unaudited Consolidated Financial Statements, and revenues and expenses during the reporting period. Our management reviews these estimates on an ongoing basis, including those related to accruals, litigation, environmental and asset retirement obligations, recoverability of assets, income taxes, fair values of derivative assets and liabilities, capital adequacy and determination of proved reserves. Changes in facts and circumstances may result in revised estimates and actual results may differ from these estimates. The results of operations and cash flows for the three and six months ended June 30, 2009 are not necessarily indicative of the results of operations or cash flows to be expected for the year ending December 31, 2009. As at July 15, 2009, there are no material subsequent events requiring additional disclosure in or amendment to these financial statements. These Unaudited Consolidated Financial Statements should be read in conjunction with our Audited Consolidated Financial Statements included in our 2008 Form 10-K. Except as described below, the accounting policies we follow are described in Note 1 of the Audited Consolidated Financial Statements included in our 2008 Form 10-K. CHANGES IN ACCOUNTING POLICIES GOODWILL AND INTANGIBLE ASSETS On January 1, 2009, we retrospectively adopted the Canadian Institute of Chartered Accountants (CICA) Section 3064, GOODWILL AND INTANGIBLE ASSETS issued by the AcSB. This section clarifies the criteria for the recognition of assets, intangible assets and internally developed intangible assets. Adoption of this standard did not have a material impact on our results of operations or financial position. Business Combinations On January 1, 2009, we prospectively adopted CICA Section 1582, BUSINESS COMBINATIONS issued by the AcSB. This section establishes principles and requirements of the acquisition method for business combinations and related disclosures. Adoption of this statement did not have a material impact on our results of operations or financial position. CONSOLIDATED FINANCIAL STATEMENTS AND NON-CONTROLLING INTERESTS On January 1, 2009, we adopted CICA Sections 1601, CONSOLIDATED FINANCIAL STATEMENTS, and 1602, NON-CONTROLLING INTERESTS issued by the AcSB. Section 1601 establishes standards for the preparation of consolidated financial statements. Section 1602 provides guidance on accounting for non-controlling interests in consolidated financial statements subsequent to a business combination. Adoption of these statements did not have a material impact on our results of operations or financial position. The retrospective presentation changes have been included in the Unaudited Consolidated Financial Statements as applicable. 8 2. RESTRICTED CASH At June 30, 2009, our restricted cash consists of margin deposits of $335 million (December 31, 2008 - $103 million) related to exchange-traded derivative financial contracts used by our energy marketing group to hedge physical commodities, and storage, transportation and customer sales contracts. We are required to maintain margin for net out-of-the-money derivative financial contracts. The increase in margin primarily relates to derivative financial contracts hedging our natural gas positions. Declining natural gas prices and widening time spreads increased the value of storage and fixed price customer sales contracts. Concurrently, the derivative financial contracts hedging these positions declined in value. Additional margin was required to cover the increase in the net out-of-the-money derivative financial contracts. 3. ACCOUNTS RECEIVABLE
June 30 December 31 2009 2008 ----------------------------------------------------------------------------------------- Trade Energy Marketing 1,682 1,501 Energy Marketing Derivative Contracts (Note 7) 614 755 Oil and Gas 778 639 Chemicals and Other 47 68 ----------------------------- 3,121 2,963 Non-Trade 215 270 ----------------------------- 3,336 3,233 Allowance for Doubtful Receivables (64) (70) ----------------------------- Total 3,272 3,163 =============================
4. INVENTORIES AND SUPPLIES
June 30 December 31 2009 2008 ----------------------------------------------------------------------------------------- Finished Products Energy Marketing 466 384 Oil and Gas 21 17 Chemicals and Other 14 16 ----------------------------- 501 417 Work in Process 9 6 Field Supplies 88 61 ----------------------------- Total 598 484 =============================
5. SUSPENDED EXPLORATION WELL COSTS The following table shows the changes in capitalized exploratory well costs during the six months ended June 30, 2009 and the year ended December 31, 2008, and does not include amounts that were initially capitalized and subsequently expensed in the same period. Suspended exploration well costs are included in property, plant and equipment.
Six Months Ended Year Ended June 30 December 31 2009 2008 ----------------------------------------------------------------------------------------------- Beginning of Period 518 326 Exploratory Well Costs Capitalized Pending the Determination of Proved Reserves 175 254 Capitalized Exploratory Well Costs Charged to Expense (21) (81) Transfers to Wells, Facilities and Equipment Based on Determination of Proved Reserves - (29) Effects of Foreign Exchange Rate Changes (21) 48 ----------------------------------- End of Period 651 518 ===================================
9 The following table provides an aging of capitalized exploratory well costs based on the date drilling was completed and shows the number of projects for which exploratory well costs have been capitalized for a period greater than one year after the completion of drilling.
June 30 December 31 2009 2008 ------------------------------------------------------------------------------------------ Capitalized for a Period of One Year or Less 356 239 Capitalized for a Period of Greater than One Year 295 279 ------------------------------ Total 651 518 ============================== Number of Projects that have Exploratory Well Costs Capitalized for a Period Greater than One Year 9 7 ------------------------------
As at June 30, 2009, we have exploratory costs that have been capitalized for more than one year relating to our interests in two exploratory blocks in the Gulf of Mexico ($120 million), certain coalbed methane and shale gas exploratory activities in Canada ($77 million), four exploratory blocks in the North Sea ($78 million), and our interest in an exploratory block offshore Nigeria ($20 million). These costs relate to projects with exploration wells for which we have not been able to recognize proved reserves. We are assessing all of these wells and projects, and are working with our partners to prepare development plans, drill additional appraisal wells or to assess commercial viability. 6. DEFERRED CHARGES AND OTHER ASSETS
June 30 December 31 2009 2008 ------------------------------------------------------------------------------------------ Crude Oil Put Options and Natural Gas Swaps (Note 7) (1) - 234 Long-Term Energy Marketing Derivative Contracts (Note 7) 230 217 Long-Term Capital Prepayments 40 61 Asset Retirement Remediation Fund 7 9 Defined Benefit Pension Assets 47 3 Other 46 46 ------------------------------ Total 370 570 ==============================
(1) The crude oil put options were reclassified to other current assets in the first quarter as they settle within 12 months. 7. FINANCIAL INSTRUMENTS Financial instruments carried at fair value on our balance sheet include cash and cash equivalents, restricted cash and derivatives used for trading and non-trading purposes. Our other financial instruments, including accounts receivable, accounts payable, accrued interest payable, dividends payable, short-term borrowings and long-term debt, are carried at cost or amortized cost. The carrying values of our short-term receivables and payables approximate their fair value as the instruments are near maturity. In our energy marketing group, we enter into contracts to purchase and sell crude oil, natural gas and other energy commodities, and use derivative contracts, including futures, forwards, swaps and options, for hedging and trading purposes (collectively derivatives). We also use derivatives to manage commodity price risk and foreign currency risk for non-trading purposes. We categorize our derivative instruments as trading or non-trading activities and carry the instruments at fair value on our balance sheet. The derivatives section below details our derivatives and fair values as at June 30, 2009. The fair values are included with accounts receivable or payable and are classified as long-term or short-term based on anticipated settlement date. Any change in fair value is included in marketing and other income. We carry our long-term debt at amortized cost using the effective interest rate method. At June 30, 2009, the estimated fair value of our long-term debt was $7,571 million (December 31, 2008 - $5,686 million) as compared to the carrying value of $7,863 million (December 31, 2008 - $6,578 million). The fair value of long-term debt is estimated based on prices provided by quoted markets and third-party brokers. 10 DERIVATIVES (a) DERIVATIVE CONTRACTS RELATED TO TRADING ACTIVITIES Our energy marketing group engages in various activities including the purchase and sale of physical commodities and the use of financial instruments such as commodity and foreign exchange futures, forwards and swaps to economically hedge exposures and generate revenue. These contracts are accounted for as derivatives and, where applicable, are presented net on the balance sheet in accordance with netting arrangements. The fair value and carrying amounts related to derivative instruments held by our energy marketing operations are as follows:
June 30 December 31 2009 2008 ---------------------------------------------------------------------------------------------------- Commodity Contracts 609 742 Foreign Exchange Contracts 5 13 ---------------------------------------- Accounts Receivable (Note 3) 614 755 ---------------------------------------- Commodity Contracts 229 213 Foreign Exchange Contracts 1 4 ---------------------------------------- Deferred Charges and Other Assets (Note 6) (1) 230 217 ---------------------------------------- Total Trading Derivative Assets 844 972 ======================================== Commodity Contracts 616 585 Foreign Exchange Contracts 37 30 ---------------------------------------- Accounts Payable and Accrued Liabilities (Note 9) 653 615 ---------------------------------------- Commodity Contracts 216 248 Foreign Exchange Contracts 10 46 ---------------------------------------- Deferred Credits and Other Liabilities (Note 13) (1) 226 294 ---------------------------------------- Total Trading Derivative Liabilities 879 909 ======================================== Total Net Trading Derivative Contracts (35) 63 ========================================
(1) These derivative contracts settle beyond 12 months and are considered non-current; once within 12 months, they are included in accounts receivable or accounts payable. Excluding the impact of netting arrangements, the gross fair value of derivative instruments is as follows:
June 30 2009 ----------------------------------------------------------------------------------------------------- Current Trading Assets 4,320 Non-Current Trading Assets 1,208 ------------------ Total Trading Derivative Assets 5,528 ================== Current Trading Liabilities 4,359 Non-Current Trading Liabilities 1,204 ------------------ Total Trading Derivative Liabilities 5,563 ================== ------------------ Total Net Trading Derivative Contracts (35) ==================
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, 2009, the following trading revenues were recognized in marketing and other income:
Three Months Six Months Ended June 30 Ended June 30 2009 2009 --------------------------------------------------------------------------------- -------------------- Commodity 223 571 Foreign Exchange (2) (83) --------------------- -------------------- Marketing Revenue 221 488 ===================== ====================
11 As an energy marketer, we may undertake several transactions during a period to execute a single sale of physical product. Each transaction may be represented by one or more derivative instruments including a physical buy, physical sell, and in many cases, numerous financial instruments for economically hedging and trading purposes. The absolute notional volumes associated with our derivative instrument transactions are as follows:
Three Months Ended Six Months June 30 Ended June 30 2009 2009 ---------------------------------------------------------------------------------------------------------------- Natural Gas bcf/d 18.8 23.7 Crude Oil mmbbls/d 3.9 3.8 Power GWh/d 244.4 228.4 Foreign Exchange USD millions 852 1,230 Foreign Exchange Euro millions 107 260 -----------------------------------------
(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 2009 2008 --------------------------------------------------------------------------------------------------------------- Accounts Receivable 36 6 Deferred Charges and Other Assets (Note 6) (1) - 234 ----------------------------------------- Total Non-Trading Derivative Assets 36 240 ========================================= Accounts Payable and Accrued Liabilities 28 21 Deferred Credits and Other Liabilities (Note 13) (1) 13 26 ----------------------------------------- Total Non-Trading Derivative Liabilities 41 47 ========================================= Total Net Non-Trading Derivative Assets (2) (5) 193 =========================================
(1) These derivative contracts settle beyond 12 months and are considered non-current. (2) The net fair value of these derivatives is equal to the gross fair value before consideration of netting arrangements and collateral posted or received with counterparties. CRUDE OIL PUT OPTIONS In 2008, we purchased put options on approximately 70,000 bbls/d of our 2009 crude oil production for $14 million. These options establish an annual average Dated Brent floor price of US$60/bbl on these volumes. In September 2008, Lehman Brothers filed for bankruptcy protection. This impacts approximately 25,000 bbls/d of our 2009 put options and the carrying value of these put options has been reduced to nil. The crude oil put options are carried at fair value and are classified as long-term or short-term based on their anticipated settlement date. Fair value of the put options is supported by multiple quotes obtained from third party brokers, which were validated with observable market data to the extent possible. With the rise in Dated Brent oil price, the fair value of the crude oil put options decreased, which is included in marketing and other income.
Change in Fair Value ------------------------------ Three Months Six Months Notional Average Fair Ended Ended Volumes Term Floor Price Value June 30, 2009 June 30, 2009 ---------------------------------------------------------------------------------------------------------------- (bbls/d) (US$/bbl) Dated Brent Crude Oil Put Options 45,000 2009 60 36 (179) (195) Dated Brent Crude Oil Put Options 25,000 2009 60 - - - ------------------------------------------ 36 (179) (195) ==========================================
12 FIXED-PRICE NATURAL GAS CONTRACTS AND NATURAL GAS SWAPS We have fixed-price natural gas sales contracts and offsetting natural gas swaps that are not part of our trading activities. These sales contracts and swaps are carried at fair value and are classified as long-term or short-term based on their anticipated settlement date. The change in fair value of the fixed price natural gas contracts and natural gas swaps is included in marketing and other income.
Change in Fair Value ------------------------------ Three Months Six Months Notional Average Fair Ended Ended Volumes Term Price Value June 30, 2009 June 30, 2009 ---------------------------------------------------------------------------------------------------------------- (Gj/d) ($/Gj) Fixed-Price Natural Gas Contracts 15,514 2009 2.28 (12) (1) 9 15,514 2010 2.28 (9) 6 17 Natural Gas Swaps 15,514 2009 7.60 (16) - (22) 15,514 2010 7.60 (4) 2 (5) ----------------------------------------- (41) 7 (1) =========================================
(c) FAIR VALUE OF DERIVATIVES Our processes for estimating and classifying the fair value of our derivative contracts are consistent with those in place at December 31, 2008. The following table includes our derivatives carried at fair value for our trading and non-trading activities as at June 30, 2009. Financial assets and liabilities are classified in the fair value hierarchy in their entirety based on the lowest level of input that is significant to the fair value measurement. Assessment of the significance of a particular input to the fair value measurement requires judgment and may affect placement within the fair value hierarchy levels.
Net Derivatives Level 1 Level 2 Level 3 Total ---------------------------------------------------------------------------------------------------------------- Trading Derivatives (201) 162 4 (35) Non-Trading Derivatives - (5) - (5) ---------------------------------------------------- Total (201) 157 4 (40) ==================================================== A reconciliation of changes in the fair value of our derivatives classified as Level 3 for the six months ended June 30, 2009 is provided below: Level 3 --------------------------------------------------------------------------------------------------------------- Beginning of Period (82) Realized and Unrealized Gains (Losses) 49 Purchases, Issuances and Settlements 46 Transfers In and/or Out of Level 3 (9) ------------- End of Period 4 ============= Unsettled Gains (Losses) Relating to Instruments Still Held as of June 30, 2009 41 =============
Trading derivatives classified in Level 3 are generally economically hedged such that gains or losses on positions classified in Level 3 are often offset by gains or losses on positions classified in Level 1 or 2. Transfers into or out of Level 3 represent existing assets and liabilities that were either previously categorized as a higher level for which the inputs became unobservable or assets and liabilities that were previously classified as Level 3 for which the lowest significant input became observable during the period. 8. RISK MANAGEMENT (a) MARKET RISK We invest in significant capital projects, purchase and sell commodities, issue short-term borrowings and long-term debt, and invest in foreign operations. These activities expose us to market risks from changes in commodity prices, foreign exchange rates and interest rates, which affect our earnings and the value of the financial instruments we hold. We use derivatives for trading and non-trading purposes as part of our overall risk management policy to manage these market exposures. The following market risk discussion focuses on the commodity price risk and foreign currency risk related to our financial instruments as our exposure to interest rate risk is immaterial. 13 COMMODITY PRICE RISK We are exposed to commodity price movements as part of our normal oil and gas operations, particularly in relation to the prices received for our crude oil and natural gas. Commodity price risk related to conventional and synthetic crude oil prices is our most significant market risk exposure. Crude oil and natural gas are sensitive to numerous worldwide factors, 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 periodically manage these risks by using derivative contracts such as commodity put options. Our energy marketing business is focused on providing services for our customers and suppliers to meet their energy commodity needs. We market and trade physical energy commodities including crude oil, natural gas, electricity and other commodities in selected regions of the world. We accomplish this by buying and selling physical commodities, by acquiring and holding rights to physical transportation and storage assets for these commodities, and by building strong relationships with our customers and suppliers. In order to manage the commodity and foreign exchange price risks that are generated by this physical business, we use financial derivative contracts including energy-related futures, forwards, swaps and options, as well as foreign currency swaps or forwards. We also seek to profit from our views on the future movement of energy commodity pricing relationships, primarily between different locations, time periods or product qualities. We do this by holding open positions, where the terms of physical or financial contracts are not completely matched to offsetting positions. We may also carry exposures to the absolute change in commodity prices based on our market views or as a consequence of managing our physical and financial positions on a daily basis. Our risk management activities make use of tools such as Value-at-Risk (VaR) and stress testing consistent with the methodology used at December 31, 2008. Our period end, high, low and average VaR amounts for the three and six months ended June 30, 2009 are as follows: Three Months Six Months Ended June 30 Ended June 30 Value-at-Risk 2009 2008 2009 2008 -------------------------------------------------------------------------------- Period End 15 31 15 31 High 19 40 24 40 Low 13 29 13 21 Average 15 34 17 32 ---------------------------------------- If market shocks occur in 2009 as they did in 2008, the key assumptions underlying our VaR estimate could be exceeded and the potential loss could be greater than our estimate. We perform stress tests on a regular basis to complement VaR and assess the impact of non-normal changes in prices on our positions. FOREIGN CURRENCY RISK Foreign currency risk is created by fluctuations in the fair values or cash flows of financial instruments due to changes in foreign exchange rates. A substantial portion of our activities are transacted in or referenced to US dollars including: o sales of crude oil, natural gas and certain chemicals products; o capital spending and expenses for our oil and gas, Syncrude and chemicals operations; o commodity derivative contracts used primarily by our energy marketing group; and o short-term borrowings and long-term debt. In our oil and gas operations, we manage our exposure to fluctuations between the US and Canadian dollar by matching our expected net cash flows and borrowings in the same currency. Net revenue from our foreign operations and our US-dollar borrowings are generally used to fund US-dollar capital expenditures and debt repayments. We maintain revolving Canadian and US-dollar borrowing facilities that can be used or repaid depending on expected cash flows. We designate a portion of our US-dollar borrowings as a hedge against our US-dollar net investment in self-sustaining foreign operations. 14 The effective portion of the foreign exchange gains or losses related to 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, 2009 and December 31, 2008 are as follows:
June 30 December 31 (US$ millions) 2009 2008 ------------------------------------------------------------------------------------------ Net Investment in Self-Sustaining Foreign Operations 4,350 4,662 Designated US-Dollar Debt 4,350 4,545 ------------------------------
For the three and six months ended June 30, 2009, the ineffective portion of the net foreign exchange gain was $41 million and $57 million, respectively ($36 million and $50 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 $44 million, net of income tax and would increase or decrease our net income by approximately $8 million, net of income tax. We also have exposures to currencies other than the US dollar including a portion of our UK operating expenses, capital spending and future asset retirement obligations which are denominated in British Pounds and Euros. We do not have any material exposure to highly inflationary foreign currencies. In our energy marketing group, we enter into transactions in various currencies including Canadian and US dollars, British Pounds and Euros. We may actively manage significant currency exposures using forward contracts and swaps. (b) CREDIT RISK Credit risk affects both our trading and non-trading 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, crude oil refiners and utilities, and are subject to normal industry credit risk. Approximately 94% of our exposure is with these large energy companies. This concentration of risk within the energy industry is reduced because of our broad base of domestic and international counterparties. Our processes to manage this risk are consistent with those in place at December 31, 2008. At June 30, 2009, only one counterparty individually made up more than 10% of our credit exposure. This counterparty is a major integrated oil company with a strong investment grade credit rating. No other counterparties made up more than 5% of our credit exposure. The following table illustrates the composition of credit exposure by credit rating.
June 30 December 31 CREDIT RATING 2009 2008 ------------------------------------------------------------------------------------------ A or higher 68% 65% BBB 26% 29% Non-Investment Grade 6% 6% ------------------------------ TOTAL 100% 100% ==============================
Our maximum counterparty credit exposure at the balance sheet date consists primarily of the carrying amounts on non-derivative financial assets such as cash and cash equivalents, restricted cash, accounts receivable, as well as the fair value of derivative financial assets. We provided an allowance of $64 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, 2009 includes $102 million of cash and $553 million of letters of credit. The cash received reflects customer deposits that are included in accounts payable and accrued liabilities. (c) LIQUIDITY RISK Liquidity risk is the risk that we will not be able to meet our financial obligations as they become due. We require liquidity specifically to fund capital requirements, satisfy financial obligations as they become due, and to operate our energy marketing business. We generally rely on operating cash flows to provide liquidity and we also maintain significant undrawn committed credit facilities. At June 30, 2009, we had approximately $2.5 billion of cash and available committed lines of credit. This includes $2.0 billion of cash and cash equivalents on hand. In addition, we have undrawn term credit facilities of $0.9 billion, of which $0.4 billion was supporting letters of credit at June 30, 2009. These facilities are available until 2012. We also have about $0.5 billion of undrawn, uncommitted credit facilities at June 30, 2009. 15 The following table details the contractual maturities for our non-derivative financial liabilities, including both the principal and interest cash flows at June 30, 2009:
Less than More Than Total 1 Year 1-3 Years 4-5 Years 5 Years -------------------------------------------------------------------------------------- Long-Term Debt (1) 7,935 - 251 3,384 4,300 Interest on Long-Term Debt (2) 7,067 314 628 607 5,518 ------------------------------------------------------- Total 15,002 314 879 3,991 9,818 =======================================================
(1) Excludes cash and cash equivalents currently available. (2) Excludes interest on term credit facilities of $3.6 billion and Canexus term credit facilities of $455 million as the amounts drawn on the facilities fluctuate. Based on amounts drawn at June 30, 2009 and current interest rates, we would be required to pay $33 million per year until the outstanding amounts on the term credit facilities are repaid. The following table details contractual maturities for our derivative financial liabilities. The balance sheet amounts for derivative financial liabilities included below are not materially different from the contractual amounts due on maturity.
Less than More Than Total 1 Year 1-3 Years 4-5 Years 5 Years -------------------------------------------------------------------------------------- Trading Derivatives (Note 7) 879 653 131 25 70 Non-Trading Derivatives (Note 7) 41 28 13 - - ------------------------------------------------------- Total 920 681 144 25 70 =======================================================
The commercial agreements our energy marketing group enter into often include financial assurance provisions that allow us and our counterparties to effectively manage credit risk. The agreements normally require collateral to be posted if an adverse credit-related event occurs, such as a drop in credit rating. Based on contracts in place and commodity prices at June 30, 2009, we could be required to post collateral of up to $1.1 billion if we were downgraded to non-investment grade. This represents the maximum amount of collateral that we would be required to post assuming a severe event that causes all rating agencies to simultaneously downgrade us. This amount includes trade payables of $795 million and derivative contracts with a fair value of $313 million. All of these obligations are included on our June 30, 2009 balance sheet. In the event of a ratings downgrade, we could monetize our trading inventories and receivables and draw on our existing credit facilities to meet our collateral obligations. Various actions can be taken, in anticipation of a downgrade that would reduce the maximum amount of collateral we would need to provide. At June 30, 2009, collateral posted with counterparties includes $15 million of cash and $209 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 $335 million (December 31, 2008 - $103 million), which have been included in restricted cash. 9. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES
June 30 December 31 2009 2008 ------------------------------------------------------------------------------------------------ Accrued Payables 1,808 2,033 Energy Marketing Derivative Contracts (Note 7) 653 615 Trade Payables 505 303 Stock-Based Compensation 130 97 Income Taxes Payable 206 69 Other 306 209 ------------------------------------ Total 3,608 3,326 ====================================
16 10. SHORT-TERM BORROWINGS AND LONG-TERM DEBT
June 30 December 31 2009 2008 ------------------------------------------------------------------------------------------------------- Canexus Term Credit Facilities, due 2011 (US$227 million drawn) (a) 263 223 Term Credit Facilities, due 2012 (US$2.3 billion drawn) (b) 2,732 1,225 Canexus Notes, due 2013 (US$50 million) 58 61 Notes, due 2013 (US$500 million) 581 612 Notes, due 2015 (US$250 million) 291 306 Notes, due 2017 (US$250 million) 291 306 Notes, due 2028 (US$200 million) 232 245 Notes, due 2032 (US$500 million) 581 612 Notes, due 2035 (US$790 million) 918 968 Notes, due 2037 (US$1,250 million) 1,453 1,531 Subordinated Debentures, due 2043 (US$460 million) 535 563 --------------------------------- 7,935 6,652 Unamortized Debt Issue Costs (72) (74) --------------------------------- Total 7,863 6,578 =================================
(a) CANEXUS TERM CREDIT FACILITIES Canexus has $455 million (US$391 million) of committed, secured term credit facilities, $432 million (US$371 million) of which is available until 2011, with the balance due 2013. At June 30, 2009, $263 million (US$227 million) was drawn on these facilities (December 31, 2008 - $223 million (US$182 million)). Borrowings are available as Canadian bankers' acceptances, LIBOR-based loans, Canadian prime rate loans or US-dollar base rate loans. Interest is payable monthly at floating rates. The term credit facilities are secured by a floating charge debenture over all of Canexus' assets. The credit facility also contains covenants with respect to certain financial ratios of Canexus. The weighted-average interest rate on the Canexus term credit facilities was 2.1% for the three months ended June 30, 2009 (three months ended June 30, 2008 - 4.6%) and 2.4% for the six months ended June 30, 2009 (six months ended June 30, 2008 - 4.5%). (b) TERM CREDIT FACILITIES We have unsecured term credit facilities of $3.6 billion (US$3.1 billion) available until 2012. At June 30, 2009, $2.7 billion (US$2.3 billion) was drawn on these facilities (December 31, 2008 - $1.2 billion (US$1 billion)). Borrowings are available as Canadian bankers' acceptances, LIBOR-based loans, Canadian prime rate loans, US-dollar base rate loans or British pound call-rate loans. Interest is payable at floating rates. The weighted-average interest rate on our term credit facilities was 1.1% for the three months ended June 30, 2009 (three months ended June 30, 2008 - 3.3%) and 1.1% for the six months ended June 30, 2009 (six months ended June 30, 2008 - 3.7%). At June 30, 2009, $392 million (US$337 million) of these facilities were utilized to support outstanding letters of credit (December 31, 2008 - $381 million (US$311 million)). (c) INTEREST EXPENSE
Three Months Six Months Ended June 30 Ended June 30 2009 2008 2009 2008 ----------------------------------------------------------------------------------------------------- Long-Term Debt 89 69 178 145 Other 3 6 8 10 --------------------------------------------- Total 92 75 186 155 Less: Capitalized (18) (59) (44) (112) --------------------------------------------- Total 74 16 142 43 =============================================
Capitalized interest relates to and is included as part of the cost of our oil and gas and Syncrude properties. The capitalization rates are based on our weighted-average cost of borrowings. (d) SHORT-TERM BORROWINGS Nexen has uncommitted, unsecured credit facilities of approximately $496 million (US$427 million), none of which were drawn at June 30, 2009 (December 31, 2008 - nil). We utilized $33 million (US$28 million) of these facilities to support outstanding letters of credit at June 30, 2009 (December 31, 2008 - $29 million (US$24 million)). Interest is payable at floating rates. The weighted-average interest rate on our short-term borrowings was 0.9% for the three months ended June 30, 2009 (three months ended June 30, 2008 - 3.7%) and 2.1% for the six months ended June 30, 2009 (six months ended June 30, 2008 - 3.8%). 17 11. CAPITAL MANAGEMENT Our objectives and processes for managing our capital structure are consistent with those in place at December 31, 2008. Our capital consists of shareholders' equity, short-term borrowings, long-term debt and cash and cash equivalents as follows:
June 30 December 31 2009 2008 ------------------------------------------------------------------------------------------- NET DEBT (1) Long-Term Debt 7,863 6,578 Less: Cash and Cash Equivalents (1,974) (2,003) ------------------------------- Total 5,889 4,575 =============================== SHAREHOLDERS' EQUITY 7,303 7,191 ===============================
(1) Includes all of our borrowings and is calculated as long-term debt and short-term borrowings less cash and cash equivalents. We monitor the leverage in our capital structure by reviewing the ratio of net debt to cash flow from operating activities and interest coverage ratios at various commodity prices. We use the ratio of net debt to cash flow from operating activities as a key indicator of our leverage and to monitor the strength of our balance sheet. Net debt is a non-GAAP measure that does not have any standard meaning prescribed by GAAP and therefore may not be comparable to similar measures presented by others. We calculate net debt using the GAAP measures of long-term debt and short-term borrowings less cash and cash equivalents (excluding restricted cash). For the twelve months ended June 30, 2009, our net debt to cash flow from operating activities ratio was 2.1 times compared to 1.1 times at December 31, 2008. While we typically expect the target ratio to fluctuate between 1.0 and 2.0 times under normalized commodity prices, this can be higher when we identify strategic opportunities requiring additional investment. Whenever we exceed our target ratio, we assess whether we need to develop a strategy to reduce our leverage and lower this ratio back to target levels over time. Our interest coverage ratio monitors our ability to fund the interest requirements associated with our debt. Our interest coverage was 10.4 times at June 30, 2009 (December 31, 2008 - 15.6 times). Interest coverage is calculated by dividing our twelve-month trailing adjusted EBITDA by interest expense before capitalized interest. Adjusted EBITDA is a non-GAAP measure. The calculation of Adjusted EBITDA is set out in the following table and is unlikely to be comparable to similar measures presented by others.
Twelve Months Year Ended Ended June 30 December 31 2009 2008 ---------------------------------------------------------------------------------------------------- Net Income 860 1,715 Add: Interest Expense 193 94 Provision for Income Taxes 684 1,457 Depreciation, Depletion, Amortization and Impairment 2,138 2,014 Exploration Expense 399 402 Recovery of Non-Cash Stock-Based Compensation (430) (272) Change in Fair Value of Crude Oil Put Options (18) (203) Other Non-Cash Expenses (34) (1) --------------------------------------- Adjusted EBITDA 3,792 5,206 =======================================
18 12. 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 2009 2008 ------------------------------------------------------------------------------------------------- Balance at Beginning of Period 1,059 832 Obligations Incurred with Development Activities 22 32 Obligations Settled (16) (45) Accretion Expense 34 58 Revisions to Estimates (25) 159 Effects of Changes in Foreign Exchange Rate 5 23 ------------------------------------- Balance at End of Period (1), (2) 1,079 1,059 =====================================
(1) Obligations due within 12 months of $35 million (December 31, 2008 - $35 million) have been included in accounts payable and accrued liabilities. (2) Obligations relating to our oil and gas activities amount to $1,028 million (December 31, 2008 - $1,009 million) and obligations relating to our chemicals business amount to $51 million (December 31, 2008 - $50 million). Our total estimated undiscounted inflated asset retirement obligations amount to $2,470 million (December 31, 2008 - $2,393 million). We have discounted the total estimated asset retirement obligations using a weighted-average, credit-adjusted, risk-free rate of 5.9%. Approximately $396 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.
13. DEFERRED CREDITS AND OTHER LIABILITIES June 30 December 31 2009 2008 ------------------------------------------------------------------------------------------------- Deferred Tax Credit 616 709 Long-Term Energy Marketing Derivative Contracts (Note 7) 226 294 Deferred Transportation Revenue 61 69 Fixed-Price Natural Gas Contracts and Swaps (Note 7) 13 26 Defined Benefit Pension Obligations 70 67 Capital Lease Obligations 62 53 Other 119 106 ------------------------------------- Total 1,167 1,324 =====================================
14. SHAREHOLDERS' EQUITY DIVIDENDS Dividends per common share for the six months ended June 30, 2009 were $0.10 per common share (2008 - $0.075). Dividends paid to holders of common shares have been designated as "eligible dividends" for Canadian tax purposes.
15. MARKETING AND OTHER INCOME Three Months Six Months Ended June 30 Ended June 30 2009 2008 2009 2008 ----------------------------------------------------------------------------------------------------- Marketing Revenue, Net (Note 7) 221 21 488 232 Change in Fair Value of Crude Oil Put Options (Note 7) (179) (10) (195) (10) Interest 1 3 3 13 Foreign Exchange Gains (Losses) - (6) 19 (1) Other 39 26 24 22 ----------------------------------------- Total 82 34 339 256 =========================================
19 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) 2009 2008 2009 2008 ------------------------------------------------------------------------------------------------------------------- Weighted-average number of common shares outstanding 521.2 530.0 520.7 529.5 Shares issuable pursuant to tandem options 11.1 24.9 11.2 25.7 Shares notionally purchased from proceeds of tandem options (6.8) (14.4) (7.9) (16.4) --------------------------------------------------- Weighted-average number of diluted common shares outstanding 525.5 540.5 524.0 538.8 ===================================================
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. In calculating the weighted-average number of diluted common shares outstanding for the three and six months ended June 30, 2008, we excluded 1,667 and 25,833 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 16 to the Audited Consolidated Financial Statements included in our 2008 Form 10-K, there are a number of lawsuits and claims pending, the ultimate results of which cannot be ascertained at this time. We record costs as they are incurred or become determinable. We continue to believe the resolution of these matters would not have a material adverse effect on our liquidity, consolidated financial position or results of operations. There have been no significant developments since year-end. 18. CASH FLOWS (a) CHARGES AND CREDITS TO INCOME NOT INVOLVING CASH
Three Months Six Months Ended June 30 Ended June 30 2009 2008 2009 2008 -------------------------------------------------------------------------------------------------------------- Depreciation, Depletion, Amortization and Impairment 413 334 822 698 Stock-Based Compensation 42 259 42 200 Recovery of Future Income Taxes (229) (139) (316) (62) Change in Fair Value of Crude Oil Put Options 179 10 195 10 Other (11) 6 (30) 6 -------------------------------------------------- Total 394 470 713 852 ==================================================
(b) CHANGES IN NON-CASH WORKING CAPITAL
Three Months Six Months Ended June 30 Ended June 30 2009 2008 2009 2008 -------------------------------------------------------------------------------------------------------------- Accounts Receivable (471) (878) (173) (1,324) Inventories and Supplies (80) (310) (129) (388) Other Current Assets 20 (6) 12 (16) Accounts Payable and Accrued Liabilities 134 1,349 319 2,032 Other (17) 1 (4) 14 -------------------------------------------------- Total (414) 156 25 318 ================================================== Relating to: Operating Activities (340) 232 80 372 Investing Activities (74) (76) (55) (54) -------------------------------------------------- Total (414) 156 25 318 ==================================================
20 (c) OTHER CASH FLOW INFORMATION
Three Months Six Months Ended June 30 Ended June 30 2009 2008 2009 2008 -------------------------------------------------------------------------------------------------------------- Interest Paid 97 82 178 148 Income Taxes Paid 34 76 68 161 --------------------------------------------------
Cash flow from other operating activities includes cash outflows related to geological and geophysical expenditures of $31 million for the three months ended June 30, 2009 (2008 - $24 million) and $43 million for the six months ended June 30, 2009 (2008 - $34 million). 19. OPERATING SEGMENTS AND RELATED INFORMATION Nexen is involved in activities relating to Oil and Gas, Energy Marketing, Syncrude and Chemicals in various geographic locations as described in Note 22 to the Audited Consolidated Financial Statements included in our 2008 Form 10-K.
THREE MONTHS ENDED JUNE 30, 2009 Corporate Energy and Oil and Gas Syncrude Marketing Chemicals Other Total ---------------------------------------------------------------------------------------------------------------------------------- United United Other Yemen Canada States Kingdom Countries(1) ----------------------------------------------- Net Sales 175 98 88 618 20 85 7 109 - 1,200 Marketing and Other 4 1 - 4 - 1 221 29 (178)(2) 82 ----------------------------------------------------------------------------------------------------- Total Revenues 179 99 88 622 20 86 228 138 (178) 1,282 Less: Expenses Operating 49 42 27 53 2 77 8 62 - 320 Depreciation, Depletion, Amortization and Impairment 32 62 80 182 4 9 3 29 12 413 Transportation and Other 15 8 3 14 - 5 166 14 7 232 General and Administrative (3) (3) 28 24 5 16 1 26 16 54 167 Exploration - 8 37 11 21 (4) - - - - 77 Interest - - - - - - - 2 72 74 ----------------------------------------------------------------------------------------------------- Income (Loss) before Income Taxes 86 (49) (83) 357 (23) (6) 25 15 (323) (1) Less: Provisions for (Recovery 30 (13) (28) 170 (18) (2) 9 4 (175) (23) of) Income Taxes Less: Non-Controlling Interests - - - - - - - 2 - 2 ----------------------------------------------------------------------------------------------------- Net Income (Loss) 56 (36) (55) 187 (5) (4) 16 9 (148) 20 ===================================================================================================== Identifiable Assets 289 8,349(5) 2,043 5,831 911 1,232 3,332 (6) 618 1,321 23,926 ===================================================================================================== Capital Expenditures Development and Other 22 138 33 109 140 22 3 72 9 548 Exploration - 53 39 49 26 - - - - 167 ----------------------------------------------------------------------------------------------------- 22 191 72 158 166 22 3 72 9 715 ===================================================================================================== Property, Plant and Equipment Cost 2,715 9,411 4,270 6,500 723 1,407 259 1,005 349 26,639 Less: Accumulated DD&A 2,549 1,899 2,680 2,414 116 251 83 507 223 10,722 ----------------------------------------------------------------------------------------------------- Net Book Value 166 7,512(5) 1,590 4,086 607 1,156 176 498 126 15,917 =====================================================================================================
(1) Includes results of operations from producing activities in Colombia. (2) Includes interest income of $1 million and 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 Norway, Nigeria and Colombia. (5) Includes costs of $5,832 million related to our insitu oil sands projects (Long Lake and future phases). (6) Approximately 82% of Marketing's identifiable assets are accounts receivable and inventories. 21
THREE MONTHS ENDED JUNE 30,2008 Corporate Energy and Oil and Gas Syncrude Marketing Chemicals Other Total ----------------------------------------------------------------------------------------------------------------------------------- United United Other Yemen Canada States Kingdom Countries(1) ----------------------------------------------- Net Sales 319 206 198 973 54 189 21 111 - 2,071 Marketing and Other 3 1 3 10 1 - 21 6 (11)(2) 34 ------------------------------------------------------------------------------------------------------- Total Revenues 322 207 201 983 55 189 42 117 (11) 2,105 Less: Expenses Operating 45 47 24 63 2 78 14 75 - 348 Depreciation, Depletion, Amortization and Impairment 40 47 62 143 4 12 4 11 11 334 Transportation and Other 2 5 - - - 2 166 10 10 195 General and Administrative (3) 13 78 45 13 58 - 41 8 162 418 Exploration - 32 23 17 29 (4) - - - - 101 Interest - - - - - - - 2 14 16 ------------------------------------------------------------------------------------------------------- Income (Loss) before Income Taxes 222 (2) 47 747 (38) 97 (183) 11 (208) 693 Less: Provisions for (Recovery 78 (1) 17 378 (3) 27 (53) 3 (134) 312 of) Income Taxes Less: Non-Controlling Interests - - - - - - - 1 - 1 ------------------------------------------------------------------------------------------------------- Net Income (Loss) 144 (1) 30 369 (35) 70 (130) 7 (74) 380 ======================================================================================================= Identifiable Assets 340 6,092 (5) 1,856 4,911 494 1,256 5,551 (6) 525 679 21,704 ======================================================================================================= Capital Expenditures Development and Other 14 259 55 121 10 11 1 20 9 500 Exploration 4 26 42 55 9 - - - - 136 Proved Property Acquisition - 2 - - - - - - - 2 ------------------------------------------------------------------------------------------------------- 18 287 97 176 19 11 1 20 9 638 ======================================================================================================= Property, Plant and Equipment Cost 2,284 7,424 3,480 5,128 310 1,348 264 866 312 21,416 Less: Accumulated DD&A 2,088 1,682 1,937 1,235 88 223 68 483 187 7,991 ------------------------------------------------------------------------------------------------------- Net Book Value 196 5,742 (5) 1,543 3,893 222 1,125 196 383 125 13,425 =======================================================================================================
(1) Includes results of operations from producing activities in Colombia. (2) Includes interest income of $3 million, foreign exchange losses of $6 million, decrease in the fair value of crude oil put options of $10 million and other gains of $2 million. (3) Includes stock-based compensation expense of $328 million. (4) Includes exploration activities primarily in Norway and Colombia. (5) Includes costs of $4,223 million related to our insitu oil sands projects (Long Lake and future phases). (6) Approximately 83% of Marketing's identifiable assets are accounts receivable and inventories. 22
SIX MONTHS ENDED JUNE 30,2009 Corporate Energy and Oil and Gas Syncrude Marketing Chemicals Other Total ----------------------------------------------------------------------------------------------------------------------------------- United United Other Yemen Canada States Kingdom Countries(1) ----------------------------------------------- Net Sales 337 189 151 1,096 39 183 20 233 - 2,248 Marketing and Other 7 8 - 8 - 1 488 15 (188) (2) 339 ------------------------------------------------------------------------------------------------------- Total Revenues 344 197 151 1,104 39 184 508 248 (188) 2,587 Less: Expenses Operating 96 83 50 104 4 143 16 129 - 625 Depreciation, Depletion, Amortization and Impairment 73 125 148 375 9 20 7 41 24 822 Transportation and Other 18 11 16 11 - 12 328 24 13 433 General and Administrative (3) 1 42 38 7 24 1 49 25 80 267 Exploration - 29 47 19 35 (4) - - - - 130 Interest - - - - - - - 4 138 142 ------------------------------------------------------------------------------------------------------- Income (Loss) before Income Taxes 156 (93) (148) 588 (33) 8 108 25 (443) 168 Less: Provisions for (Recovery 54 (24) (51) 256 (24) 2 44 6 (255) 8 of) Income Taxes Less: Non-Controlling Interests - - - - - - - 5 - 5 ------------------------------------------------------------------------------------------------------- Net Income (Loss) 102 (69) (97) 332 (9) 6 64 14 (188) 155 ======================================================================================================= Identifiable Assets 289 8,349 (5) 2,043 5,831 911 1,232 3,332 (6) 618 1,321 23,926 ======================================================================================================= Capital Expenditures Development and Other 51 384 75 258 198 39 11 108 10 1,134 Exploration - 147 65 77 41 - - - - 330 Proved Property Acquisitions - 755 - - - - - - - 755 ------------------------------------------------------------------------------------------------------- 51 1,286 140 335 239 39 11 108 10 2,219 ======================================================================================================= Property, Plant and Equipment Cost 2,715 9,411 4,270 6,500 723 1,407 259 1,005 349 26,639 Less: Accumulated DD&A 2,549 1,899 2,680 2,414 116 251 83 507 223 10,722 ------------------------------------------------------------------------------------------------------- Net Book Value 166 7,512 (5) 1,590 4,086 607 1,156 176 498 126 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, Nigeria and Colombia. (5) Includes costs of $5,832 million related to our insitu oil sands projects (Long Lake and future phases). (6) Approximately 82% of Marketing's identifiable assets are accounts receivable and inventories. 23
SIX MONTHS ENDED JUNE 30,2008 Corporate Energy and Oil and Gas Syncrude Marketing Chemicals Other Total ----------------------------------------------------------------------------------------------------------------------------------- United United Other Yemen Canada States Kingdom Countries(1) ----------------------------------------------- Net Sales 595 353 379 1,912 100 347 35 220 - 3,941 Marketing and Other 7 1 4 11 1 - 232 (1) 1 (2) 256 ------------------------------------------------------------------------------------------------------- Total Revenues 602 354 383 1,923 101 347 267 219 1 4,197 Less: Expenses Operating 90 89 48 120 5 140 23 142 - 657 Depreciation, Depletion, Amortization and Impairment 74 94 136 313 8 24 7 21 21 698 Transportation and Other 4 10 1 - - 7 339 29 (3) 10 400 General and Administrative (4) 11 79 51 12 59 1 67 15 178 473 Exploration - 36 29 24 44 (5) - - - - 133 Interest - - - - - - - 5 38 43 ------------------------------------------------------------------------------------------------------- Income (Loss) before Income Taxes 423 46 118 1,454 (15) 175 (169) 7 (246) 1,793 Less: Provisions for (Recovery 148 13 42 737 - 49 (52) 3 (159) 781 of) Income Taxes Less: Non-Controlling Interests - - - - - - - 2 - 2 ------------------------------------------------------------------------------------------------------- Net Income (Loss) 275 33 76 717 (15) 126 (117) 2 (87) 1,010 ======================================================================================================= Identifiable Assets 340 6,092 (6) 1,856 4,911 494 1,256 5,551 (7) 525 679 21,704 ======================================================================================================= Capital Expenditures Development and Other 32 610 134 221 38 20 1 33 13 1,102 Exploration 9 112 109 71 19 - - - - 320 Proved Property Acquisitions - 2 - - - - - - - 2 ------------------------------------------------------------------------------------------------------- 41 724 243 292 57 20 1 33 13 1,424 ======================================================================================================= Property, Plant and Equipment Cost 2,284 7,424 3,480 5,128 310 1,348 264 866 312 21,416 Less: Accumulated DD&A 2,088 1,682 1,937 1,235 88 223 68 483 187 7,991 ------------------------------------------------------------------------------------------------------- Net Book Value 196 5,742 (6) 1,543 3,893 222 1,125 196 383 125 13,425 =======================================================================================================
(1) Includes results of operations from producing activities in Colombia. (2) Includes interest income of $13 million, foreign exchange losses of $1 million, decrease in the fair value of crude oil put options of $10 million and other losses of $1 million. (3) Includes severance accrual of $7 million in connection with North Vancouver technology conversion project. (4) Includes stock-based compensation expense of $287 million. (5) Includes exploration activities primarily in Norway and Colombia. (6) Includes costs of $4,223 million related to our insitu oil sands projects (Long Lake and future phases). (7) Approximately 83% of Marketing's identifiable assets are accounts receivable and inventories. 24 20. DIFFERENCES BETWEEN CANADIAN AND US GENERALLY ACCEPTED ACCOUNTING PRINCIPLES The Unaudited Consolidated Financial Statements have been prepared in accordance with Canadian GAAP. The US GAAP Unaudited Consolidated Statements and summaries of differences from Canadian GAAP are as follows:
UNAUDITED CONSOLIDATED STATEMENT OF INCOME (LOSS) - US GAAP FOR THE THREE AND SIX MONTHS ENDED JUNE 30 Three Months Six Months Ended June 30 Ended June 30 (Cdn$ millions, except per share amounts) 2009 2008 2009 2008 ---------------------------------------------------------------------------------------------------------------------------- REVENUES AND OTHER INCOME Net Sales 1,200 2,071 2,248 3,941 Marketing and Other (v); (vi) 66 (102) 358 104 --------------------------------------------------- 1,266 1,969 2,606 4,045 --------------------------------------------------- EXPENSES Operating (i) 320 347 625 657 Depreciation, Depletion, Amortization and Impairment 413 334 822 698 Transportation and Other (v) 231 191 425 396 General and Administrative (iv) 197 390 305 452 Exploration 77 101 130 133 Interest 74 16 142 43 --------------------------------------------------- 1,312 1,379 2,449 2,379 --------------------------------------------------- INCOME (LOSS) BEFORE PROVISION FOR INCOME TAXES (46) 590 157 1,666 --------------------------------------------------- PROVISION FOR (RECOVERY OF) INCOME TAXES Current 206 451 324 843 Deferred (iv); (vi) (242) (180) (316) (114) --------------------------------------------------- (36) 271 8 729 --------------------------------------------------- NET INCOME (LOSS) (10) 319 149 937 Less: Net Income Attributable to Non-Controlling Interests (2) (1) (5) (2) --------------------------------------------------- NET INCOME (LOSS) ATTRIBUTABLE TO NEXEN INC. - US GAAP (1) (12) 318 144 935 =================================================== EARNINGS (LOSS) PER COMMON SHARE ($/share) (Note 16) Basic (0.02) 0.60 0.28 1.77 =================================================== Diluted (0.02) 0.59 0.28 1.74 ---------------------------------------------------
(1) RECONCILIATION OF CANADIAN AND US GAAP NET INCOME (LOSS)
Three Months Six Months Ended June 30 Ended June 30 2009 2008 2009 2008 ---------------------------------------------------------------------------------------------------------------------------- Net Income - Canadian GAAP 20 380 155 1,010 Impact of US Principles, Net of Income Taxes: Stock-based Compensation (iv) (22) 20 (28) 15 Inventory Valuation (vi) (10) (83) 17 (90) Other - 1 - - --------------------------------------------------- Net Income (Loss) - US GAAP (12) 318 144 935 ===================================================
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UNAUDITED CONSOLIDATED BALANCE SHEET - US GAAP June 30 December 31 (Cdn$ millions, except share amounts) 2009 2008 ----------------------------------------------------------------------------------------------------------------- ASSETS CURRENT ASSETS Cash and Cash Equivalents 1,974 2,003 Restricted Cash 335 103 Accounts Receivable 3,272 3,163 Inventories and Supplies (vi) 567 426 Other 167 169 ----------------------------------- Total Current Assets 6,315 5,864 ----------------------------------- PROPERTY, PLANT AND EQUIPMENT Net of Accumulated Depreciation, Depletion, Amortization and Impairment of $11,115 (December 31, 2008 - $10,786) (i); (iii) 15,868 14,873 GOODWILL 372 390 DEFERRED INCOME TAX ASSETS 921 351 DEFERRED CHARGES AND OTHER ASSETS 370 570 ----------------------------------- TOTAL ASSETS 23,846 22,048 =================================== LIABILITIES AND SHAREHOLDERS' EQUITY CURRENT LIABILITIES Accounts Payable and Accrued Liabilities (iv) 3,704 3,384 Accrued Interest Payable 63 67 Dividends Payable 26 26 ----------------------------------- Total Current Liabilities 3,793 3,477 ----------------------------------- LONG-TERM DEBT 7,863 6,578 DEFERRED INCOME TAX LIABILITIES (i); (ii); (iv); (vi); (vii) 2,776 2,543 ASSET RETIREMENT OBLIGATIONS 1,044 1,024 DEFERRED CREDITS AND OTHER LIABILITIES (ii) 1,271 1,428 SHAREHOLDERS' EQUITY Nexen Inc. Shareholders' Equity Common Shares, no par value Authorized: Unlimited Outstanding: 2009 - 521,205,270 shares 2008 - 519,448,590 shares 1,011 981 Contributed Surplus 2 2 Retained Earnings (i) - (vii) 6,264 6,172 Accumulated Other Comprehensive Loss (ii) (232) (209) ----------------------------------- Total Nexen Inc. Shareholders' Equity 7,045 6,946 Non-Controlling Interests 54 52 ----------------------------------- TOTAL SHAREHOLDERS EQUITY 7,099 6,998 ----------------------------------- COMMITMENTS, CONTINGENCIES AND GUARANTEES TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY 23,846 22,048 ===================================
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 2009 2008 2009 2008 ---------------------------------------------------------------------------------------------------------------------------- Net Income (Loss) Attributable to Nexen Inc. - US GAAP (12) 318 144 935 Other Comprehensive Income (Loss), Net of Income Taxes: Foreign Currency Translation Adjustment (29) (8) (23) 19 --------------------------------------------------- Comprehensive Income (Loss) Attributable to Nexen Inc. (41) 310 121 954 ===================================================
26
UNAUDITED CONSOLIDATED STATEMENT OF ACCUMULATED OTHER COMPREHENSIVE LOSS - US GAAP June 30 December 31 2009 2008 ---------------------------------------------------------------------------------------------------------------------- Foreign Currency Translation Adjustment (157) (134) Unamortized Defined Benefit Pension Plan Costs (ii) (75) (75) ---------------------------------------- Accumulated Other Comprehensive Loss (232) (209) ========================================
NOTES TO THE UNAUDITED CONSOLIDATED US GAAP FINANCIAL STATEMENTS: i. Under Canadian GAAP, we defer certain development costs to PP&E. Under US principles, these costs have been included in operating expenses. As a result PP&E is lower under US GAAP by $30 million (December 31, 2008 - $30 million). ii. US GAAP requires the recognition of the over-funded and under-funded status of a defined benefit plan on the balance sheet as an asset or liability. At June 30, 2009, the unfunded amount of our defined benefit pension plans that was not included in the Pension Liability under Canadian GAAP was $104 million. This amount has been included in deferred credits and other liabilities and $75 million, net of income taxes, has been included in AOCI. iii. On January 1, 2003, we adopted FASB Statement 143, ACCOUNTING FOR ASSET RETIREMENT OBLIGATIONS (FAS 143) for US GAAP reporting purposes. We adopted the equivalent Canadian standard for asset retirement obligations on January 1, 2004. These standards are consistent except for the adoption date which results in our PP&E under US GAAP being lower by $19 million. iv. Under Canadian principles, we record obligations for liability-based stock compensation plans using the intrinsic-value method of accounting. Under US principles, obligations for liability-based stock compensation plans are recorded using the fair-value method of accounting. In addition, under Canadian principles, we retroactively adopted EIC-162 which requires the accelerated recognition of stock-based compensation expense for all stock-based awards made to our retired and retirement-eligible employees. However, US GAAP requires the accelerated recognition of stock-based compensation expense for such employees for awards granted on or after January 1, 2006. As a result: o general and administrative (G&A) expense is higher by $30 million and $38 million ($22 million and $28 million, net of income taxes) for the three and six months ended June 30, 2009, respectively (2008 - lower by $28 million and $21 million, respectively ($20 million and $15 million, net of income taxes)); and o accounts payable and accrued liabilities are higher by $96 million as at June 30, 2009 (December 31, 2008 - $58 million). v. Under US GAAP, asset disposition gains and losses are included with transportation and other expense. Gains of $1 million and $8 million for the three and six months ended June 30, 2009, respectively, were reclassified from marketing and other income to transportation and other expense (gains of $4 million were reclassified for the three and six months ended June 30, 2008). vi. Under Canadian GAAP, we carry our commodity inventory held for trading purposes at fair value, less any costs to sell. Under US GAAP, we are required to carry this inventory at the lower of cost or net realizable value. As a result: o marketing and other income is lower by $15 million and higher by $27 million ($10 million and $17 million, net of income taxes) for the three and six months ended June 30, 2009, respectively (2008 - lower by $132 million and $148 million ($83 million and $90 million, net of income taxes)); and o inventories are lower by $31 million as at June 30, 2009 (December 31, 2008 - lower by $58 million). vii. On January 1, 2007, we adopted Financial Accounting Standards Board (FASB) Interpretation 48, ACCOUNTING FOR UNCERTAINTY IN INCOME TAXES (FIN 48) regarding accounting and disclosure for uncertain tax positions. On the adoption of FIN 48, we recorded a cumulative effect of a change in accounting principle of $28 million. This amount increased our deferred income tax liabilities, and decreased our retained earnings as at January 1, 2007 in our US GAAP - Unaudited Consolidated Balance Sheet. As at June 30, 2009, the total amount of our unrecognized tax benefit was approximately $269 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, 2009, 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 - Consolidated Statement of Income for the three and six months ended June 30, 2009. 27 Our income tax filings are subject to audit by taxation authorities and as at June 30, 2009 the following tax years remained subject to examination, (i) Canada - 1985 to date (ii) United Kingdom - 2007 to date and (iii) United States - 2005 to date. We do not anticipate any material changes to the unrecognized tax benefits previously disclosed within the next 12 months. CHANGES IN ACCOUNTING POLICIES - US GAAP Business Combinations On January 1, 2009, we prospectively adopted FASB Statement 141 (R), BUSINESS COMBINATIONS. Statement 141 establishes principles and requirements of the acquisition method for business combinations and related disclosures. The adoption of this statement did not impact our results of operations or financial position. NON-CONTROLLING INTERESTS On January 1, 2009, we prospectively adopted FASB Statement 160, NON-CONTROLLING INTERESTS IN CONSOLIDATED FINANCIAL STATEMENTS. This statement clarifies that a non-controlling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. The adoption of this statement did not have a material impact on our results of operations or financial position. The presentation changes have been included in the Consolidated Financial Statements, as applicable. DERIVATIVE AND HEDGING ACCOUNTING AND DISCLOSURES On January 1, 2009, we prospectively adopted FASB Statement 161, DISCLOSURES ABOUT DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES. The statement requires qualitative disclosures about the objectives and strategies for using derivatives, quantitative data about the fair value of gains and losses on derivative contracts and details of credit-risk-related contingent features in their hedged position. The statement also requires the disclosure of the location and amounts of derivative instruments in the financial statements. The disclosures required by this standard are provided in Notes 7 and 8. On April 1, 2009, we prospectively adopted three FASB staff positions to improve guidance and disclosures on fair value measurement and impairments. The positions clarify fair value accounting specifically regarding: inactive markets and distressed transactions; other-than-temporary impairments; and expanded fair value disclosures for financial instruments in interim periods. The adoption of these positions did not have a material impact on our results of operation or financial position. SUBSEQUENT EVENTS On April 1, 2009, we prospectively adopted Statement 165, SUBSEQUENT EVENTS. The new standard reflects the existing principles of current subsequent events accounting guidance and retains the notion and definition of "available to be issued" financial statements. The new standard requires disclosure of the date through which subsequent events have been evaluated and clarifies that original issuance of financial statements means both "issued" or "available to be issued". The adoption of this standard did not have a material impact on our results of operation or financial position. NEW ACCOUNTING PRONOUNCEMENTS - US GAAP In December 2008, FASB issued FSP FAS 132(R) -1, EMPLOYERS DISCLOSURES ABOUT POSTRETIREMENT BENEFIT PLAN ASSETS. This position provides guidance on disclosures about plan assets of a defined benefit pension or other postretirement plans. This position is effective for fiscal years ending after December 15, 2009. We do not expect the adoption of this statement to materially impact our results of operations or financial position. In June 2009, FASB issued Statement 167, AMENDMENTS TO FASB INTERPRETATION NO. 46 (R). It retains the scope of Interpretation 46(R) with the addition of entities previously considered qualifying special-purpose entities and eliminates the previous quantitative approach for a qualitative analysis in determining whether the enterprise's variable interest or interests give it a controlling financial interest in a variable interest entity. The Statement further amends Interpretation 46(R) to require ongoing reassessments of whether an enterprise is the primary beneficiary of a variable interest entity and requires enhanced disclosures about an enterprise's involvement in a variable interest entity. The Statement is effective at the beginning of the first annual reporting period after November 15, 2009. We do not expect the adoption of this statement to have a material impact on our results of operations or financial position. 28 ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (MD&A) THE FOLLOWING SHOULD BE READ IN CONJUNCTION WITH THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS INCLUDED IN THIS REPORT. THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS HAVE BEEN PREPARED IN ACCORDANCE WITH GENERALLY ACCEPTED ACCOUNTING PRINCIPLES (GAAP) IN CANADA. THE IMPACT OF THE SIGNIFICANT DIFFERENCES BETWEEN CANADIAN AND UNITED STATES (US) ACCOUNTING PRINCIPLES ON THE FINANCIAL STATEMENTS IS DISCLOSED IN NOTE 20 TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS. THE DATE OF THIS DISCUSSION IS JULY 15, 2009. UNLESS OTHERWISE NOTED, TABULAR AMOUNTS ARE IN MILLIONS OF CANADIAN DOLLARS. THE DISCUSSION AND ANALYSIS OF OUR OIL AND GAS ACTIVITIES WITH RESPECT TO OIL AND GAS VOLUMES, RESERVES AND RELATED PERFORMANCE MEASURES IS PRESENTED ON A WORKING-INTEREST, BEFORE-ROYALTIES BASIS. WE MEASURE OUR PERFORMANCE IN THIS MANNER CONSISTENT WITH OTHER CANADIAN OIL AND GAS COMPANIES. WHERE APPROPRIATE, WE HAVE PROVIDED INFORMATION ON A NET, AFTER-ROYALTIES BASIS IN TABULAR FORMAT. NOTE: CANADIAN INVESTORS SHOULD READ THE SPECIAL NOTE TO CANADIAN INVESTORS ON PAGE 79 OF OUR 2008 ANNUAL REPORT OF FORM 10-K (2008 FORM 10-K) WHICH HIGHLIGHTS DIFFERENCES BETWEEN OUR RESERVES ESTIMATES AND RELATED DISCLOSURES THAT ARE OTHERWISE REQUIRED BY CANADIAN REGULATORY AUTHORITIES. WE MAKE ESTIMATES AND ASSUMPTIONS THAT AFFECT THE REPORTED AMOUNTS OF OUR ASSETS AND LIABILITIES AND THE DISCLOSURE OF CONTINGENT ASSETS AND LIABILITIES AT THE DATE OF THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS AND OUR REVENUES AND EXPENSES DURING THE REPORTED PERIOD. OUR MANAGEMENT REVIEWS THESE ESTIMATES, INCLUDING THOSE RELATED TO ACCRUALS, LITIGATION, ENVIRONMENTAL AND ASSET RETIREMENT OBLIGATIONS, INCOME TAXES, FAIR VALUES OF DERIVATIVE CONTRACT ASSETS AND LIABILITIES AND THE DETERMINATION OF PROVED RESERVES ON AN ONGOING BASIS. CHANGES IN FACTS AND CIRCUMSTANCES MAY RESULT IN REVISED ESTIMATES AND ACTUAL RESULTS MAY DIFFER FROM THESE ESTIMATES.
EXECUTIVE SUMMARY OF SECOND QUARTER RESULTS Three Months Six Months Ended June 30 Ended June 30 2009 2008 2009 2008 --------------------------------------------------------------------------------------------------------------------------- Production before Royalties (mboe/d) 240 254 246 261 Production after Royalties (mboe/d) 208 211 217 217 Nexen's Average Realized Oil and Gas Price (Cdn$/boe) 61.28 108.26 54.28 96.36 Cash Flow from Operating Activities (1) 109 1,163 898 2,331 Net Income Attributable to Nexen Inc. 20 380 155 1,010 Earnings per Common Share, Basic ($/share) 0.04 0.72 0.30 1.91 Capital Investment 715 638 1,464 1,424 Acquisition of Additional Interest in Long Lake - - 755 - Net Debt (2) 5,889 3,835 5,889 3,835 --------------------------------------------------
(1) Cash flow from operating activities includes $340 million used to finance non-cash working capital requirements in the second quarter of 2009. (2) Net debt is a non-GAAP measure and is defined as long-term debt and short-term borrowings less cash and cash equivalents. Production before royalties averaged 240,000 boe/d in the quarter, 5% below the previous quarter. The decrease reflects planned maintenance downtime at Buzzard and Syncrude, and natural declines in Yemen. Buzzard continues to deliver strong results, with rates averaging 87,500 boe/d, net to us, during the quarter. Excluding the downtime, Buzzard produced at rates averaging 96,700 boe/d, net to us. In the Gulf of Mexico, all of the shut-in production has been restored following the 2008 hurricane interruptions with the exception of about 4,000 boe/d which is expected to return to production in 2010 or 2011, after reconstruction of a destroyed platform. At Long Lake, SAGD bitumen quarterly production averaged 9,300 bbls/d, net to us and we achieved record steam injection rates driven by water treatment modifications. Commodity prices strengthened during the quarter, but are considerably lower than a year ago. Our realized quarterly oil and gas price increased 29% from the prior quarter to average $61.28/boe, but was 43% lower than the prior year. Despite the drop in commodity prices, our cash netbacks remain strong. Our second quarter net income was impacted by the reduced value of our crude oil put options as we are required to carry the options at fair value. With oil prices increasing throughout the second quarter, the fair value of our put options fell considerably, reducing our net income $179 million before tax. The put options have an annual average Dated Brent strike price of US$60/bbl and would be in-the-money if prices average US$70/bbl or lower for the rest of the year. Additional stock-based compensation expense reduced our net income a further $56 million before tax during the quarter. Our capital investment is focused on developing our Usan project offshore Nigeria and on exploration activities in the North Sea, particularly in the Golden Eagle area, both of which are expected to be economic at current prices. We achieved exploration success during the quarter at Hobby in the UK North Sea and at Owowo, offshore West Africa. We are also advancing work on the fourth platform at Buzzard, which should allow us to extend the production plateau of the field for several years. We expect to bring our Ettrick and Longhorn developments on stream later this year. 29 Our financial position remains strong. We have available liquidity of approximately US$2.5 billion, comprised of cash on hand and undrawn lines of credit. We have no significant debt maturities until 2012 and the average term-to-maturity of our long-term debt is approximately 15 years. We believe our significant liquidity, combined with strong operating cash netbacks, provides us with the financial flexibility to carry out our investment programs. CAPITAL INVESTMENT Our strategy is to build a sustainable energy company focused in three areas: oil sands, unconventional gas and select conventional exploration and exploitation. We are committed to grow long-term value for our shareholders responsibly and are advancing our plans to achieve this as described below. In 2009, we are investing primarily in: o bringing Ettrick in the North Sea and Longhorn in the Gulf of Mexico on stream later this year; o ramping up Long Lake safely and reliably; o developing our Usan project and continuing to explore our additional acreage, offshore Nigeria; o advancing exploration and appraisal of our Golden Eagle area in the UK North Sea; o targeting a number of exploration prospects, primarily in the North Sea and Gulf of Mexico; and o advancing our Horn River shale gas play in northeastern British Columbia. Details of our capital programs are set out below:
THREE MONTHS ENDED JUNE 30, 2009 Major Early Stage New Growth Core Asset Development Development Exploration Development Total --------------------------------------------------------------------------------------------------------------------- Oil and Gas United Kingdom 21 - 49 88 158 Nigeria 139 - 17 - 156 Synthetic (mainly Long Lake) 95 (1) 23 - - 118 Canada - - 53 20 73 United States 32 - 39 1 72 Yemen - - - 22 22 Other Countries - - 9 1 10 Syncrude - - - 22 22 --------------------------------------------------------------------------- 287 23 167 154 631 Chemicals 72 - - - 72 Energy Marketing, Corporate and Other - - - 12 12 --------------------------------------------------------------------------- Total Capital 359 23 167 166 715 =============== =============== =============== ============== ============ As a % of Total Capital 50% 3% 24% 23% 100% --------------------------------------------------------------------------- (1) Includes $60 million of capitalized start-up costs. SIX MONTHS ENDED JUNE 30, 2009 Major Early Stage New Growth Core Asset Development Development Exploration Development Total --------------------------------------------------------------------------------------------------------------------- Oil and Gas Long Lake Acquisition 755 - - - 755 United Kingdom 102 6 77 150 335 Synthetic (mainly Long Lake) 265 (1) 63 1 - 329 Nigeria 197 - 19 - 216 Canada - 2 146 54 202 United States 69 - 65 6 140 Yemen - - - 51 51 Other Countries - - 22 1 23 Syncrude - - - 39 39 --------------------------------------------------------------------------- 1,388 71 330 301 2,090 Chemicals 108 - - - 108 Energy Marketing, Corporate and Other - - - 21 21 --------------------------------------------------------------------------- Total Capital 1,496 71 330 322 2,219 =============== =============== =============== ============== ============ As a % of Total Capital 67% 3% 15% 15% 100% ---------------------------------------------------------------------------
(1) Includes $151 million of capitalized start-up costs. 30 SYNTHETIC The ramp up of Long Lake is progressing and the reservoir continues to perform as expected given the amount of steam that has been injected. Steam volumes have been limited by our ability to treat water. In May 2009, we successfully completed a project to add supplementary heat to the hot lime softeners (HLS) in the water treatment plant. We also completed routine maintenance work to remove deposits which typically build up in water treatment plants. Steam production increased in June 2009 and we have achieved record injection rates of approximately 95,000 bbls/d and gross bitumen production rates of approximately 18,000 bbls/d. There are currently 41 of 81 well pairs on production and we are producing at a steam-to-oil ratio (SOR) which ranges between 4.0 and 5.0. We continue to expect a long-term SOR of 3.0 over the life of the project. Bitumen production volumes for the second quarter set a new record and averaged approximately 14,300 bbls/d (gross), an increase of 7% over the first quarter. Production volumes have been impacted by downtime associated with improvements made to the HLS units. We plan to replace valves and conduct maintenance on our water treatment plant during the third quarter to further optimize our steam production. The cost of these activities will not be significant and will result in scheduled downtime in the third quarter, impacting bitumen and premium synthetic crude (PSCTM) production. As steam generation increases, all wells are expected to be converted to production mode. With respect to the Upgrader, all major units are operational and Syngas is being used in SAGD operations. This allows us to decrease operating costs by reducing the requirement for purchased natural gas. The solvent de-asphalter and thermal cracker units are expected to start shortly and will allow us to transition from gasifying vacuum residue, which contains some lighter parts of the barrel, to gasifying asphaltenes, the heaviest part of the barrel. As a result, we expect our PSCTM yield to increase from approximately 60% to 80%. During the ramp up phase, we expect periods of downtime but anticipate that the stability of operations will continue to improve. We expect to reach full design rates of 72,000 bbls/d of gross bitumen production, upgraded to approximately 60,000 bbls/d (39,000 bbls/d, net to us) of PSCTM in 2010. We have a 65% interest in the Long Lake project and joint venture lands. We are the sole operator of the resource and upgrader. This allows us to maximize operational efficiencies and reduce the cost of managing the project. UNITED KINGDOM - NORTH SEA The Golden Eagle area is emerging as a potentially significant development opportunity. Our current estimates of recoverable resource are at the high end of our pre-drill estimates. We expect development of the area will be economic at approximately US$40/bbl and should support standalone facilities with project sanction targeted for 2010. In 2007, we drilled the initial Golden Eagle discovery well in what is now the Golden Eagle area. This well, and a subsequent sidetrack to the north, indicated the presence of a high quality reservoir and testing of the initial discovery well demonstrated production rates of approximately 5,000 boe/d. In 2008, we drilled our Pink discovery well further south, between the Golden Eagle discovery well and Buzzard. We encountered hydrocarbons in a high quality reservoir. We successfully sidetracked the well to the west. We recently completed an appraisal well here and the results are being assessed. In January 2009, we drilled the Hobby discovery. The well encountered light sweet oil with an API of 37 degrees and was tested at a constrained rate of 5,550 bbls/d with a 56/64 inch choke. We have subsequently drilled three successful sidetracks from the discovery well and an appraisal well. In the second half of the year, we expect to continue the appraisal drilling program for the Hobby discovery. We have a 34% operated interest in both Hobby and Golden Eagle and a 46% operated working interest in Pink. Elsewhere in the UK North Sea, our Ettrick development is expected to produce first oil in the next few weeks. The project is expected to add approximately 12,000 to 16,000 boe/d to our production volumes for the remainder of the year. Ettrick will produce to a leased floating production, storage and offloading vessel (FPSO) designed to handle 30,000 bbls/d of oil and 35 mmcf/d of gas. We have a discovery at Blackbird which could be a future tie-back to Ettrick. We operate both Ettrick and Blackbird, with a 79.73% working interest in each. UNITED STATES - GULF OF MEXICO In the Eastern Gulf of Mexico, we have previously made two discoveries at Vicksburg and Shiloh. We are currently reviewing tie-back options to existing platforms for the Vicksburg discovery and expect to drill an appraisal well here in 2010. In addition, we recently spud the Antietam prospect, which is located three miles west of our Shiloh discovery. Drilling results are expected in the third quarter. Later this year, we also expect to drill an exploration well at Appomattox, about six miles west of Vicksburg. We have a 25% interest in Vicksburg and a 20% interest in Antietam, Appomattox and Shiloh, with Shell operating all four. 31 Longhorn is expected to commence production shortly. We expect peak production of approximately 200 mmcf/d or 33,000 boe/d gross (50 mmcf/d or 8,000 boe/d, net to us). A fourth development well for the project, Leo, exceeded expectations and has extended our reserve base. We have a 25% non-operated working interest and ENI is the operator. At Knotty Head, we plan to start drilling an appraisal well in the fourth quarter of 2009 after the first of our two new deep-water drilling rigs arrives. The rig left the Singapore shipyard in mid-June and is expected to enter the Gulf of Mexico in August and begin deep-water sea trials. This new rig has been contracted at attractive day rates, which are significantly better than industry average. We are currently negotiating the terms of an agreement to jointly develop Knotty Head and Pony. We have a 25% operated interest in Knotty Head. CANADA - HORN RIVER SHALE GAS During the quarter, we put two horizontal wells on production at Dilly Creek that were drilled last summer and completed in the first quarter of 2009. Initial production rates for the first month averaged 850 mcf/d per frac. These results are in line with previous tests and those of our competitors. We drilled three additional wells earlier this year and we recently began fracing these wells. We are starting to see efficiencies in our shale gas program as the time to complete the initial fracs in our new program is substantially less than our previous experience. We plan to complete and tie-in these wells in the third quarter. By the end of the year, we expect to have six wells on production at a total exit rate ranging between 12 and 18 mmcf/d. Our drilling activity to date has allowed us to secure tenure on the majority of our Dilly Creek lands. Only two more wells are required to secure the remainder. Primary tenure in the Horn River basin is four years and drilling activity and extensions increases this up to 18 years. The Horn River basin has the potential to become the most significant shale gas play in North America as it has the highest resource density and excellent well productivity. We have approximately 88,000 acres in the Dilly Creek area and 38,000 acres in the Cordova area in northeast British Columbia with a 100% working interest in each. Further appraisal activity is required before our reserve estimates can be finalized and commerciality established. OFFSHORE WEST AFRICA We recently completed drilling an exploration well in the southern portion of Oil Prospecting License (OPL) 223, offshore West Africa. The Owowo South B-1 well was drilled in a water depth of 670 metres and is located 20 kilometres northeast of the Usan field, currently under development. Drilling results are under evaluation. Under the production sharing contract governing OPL 223, the Nigerian National Petroleum Corporation (NNPC) is concessionaire of the license, which is operated by Total Exploration & Production Nigeria Ltd. (18%) with its co-venturers: Nexen Petroleum Exploration & Production Nigeria Ltd. (18%), Chevron Nigeria Deepwater F Ltd. (27%), Esso Exploration and Production Nigeria (Upstream) Ltd. (27%) and Nigerian Petroleum Development Company (NPDC) Ltd. (10%). As is typical in many jurisdictions, the Nigerian government is reviewing its existing petroleum fiscal terms, the impact of which on our projects is not yet known. Development of the Usan field on block OML 138, offshore Nigeria is fully underway. The field development plan includes a FPSO vessel with a storage capacity of two million barrels of oil. Development drilling has begun and throughout the course of the year, the FPSO hull will be constructed. The Usan field is expected to come on stream in 2012 and will ramp up to a peak production rate of 180,000 bbls/d (36,000 bbls/d, net to us). Nexen has a 20% interest in exploration and development along with Total E&P Nigeria Limited (20% and Operator), Chevron Petroleum Nigeria Limited (30%) and Esso Exploration and Production Nigeria (Offshore East) Limited (30%). CHEMICALS Major construction of the technology conversion project (TCP) at the North Vancouver chlor-alkali facility is progressing and is scheduled for mechanical completion in late 2009, with start-up near the end of the first quarter of 2010. This project is expected to provide Canexus with the ability to produce chlor-alkali products at a lower cost. This advantage, together with added capacity, we believe should generate an estimated $35-$43 million annually in incremental cash flow, beginning in 2010. 32 FINANCIAL RESULTS CHANGE IN NET INCOME
2009 VS. 2008 Three Months Six Months Ended June 30 Ended June 30 -------------------------------------------------------------------------------------------------------------------- NET INCOME AT JUNE 30, 2008 380 1,010 ======================================== Favorable (unfavorable) variances(1): Realized Commodity Prices Crude Oil (689) (1,413) Natural Gas (114) (160) ---------------------------------------- Total Price Variance (803) (1,573) Production Volumes, After Royalties Crude Oil (84) (69) Natural Gas (15) (47) Changes in Crude Oil Inventory Pending Sale 47 (2) ---------------------------------------- Total Volume Variance (52) (118) Oil and Gas Operating Expense 9 12 Oil and Gas Depreciation, Depletion, Amortization and Impairment (61) (101) Exploration Expense 24 3 Energy Marketing Revenue, Net 192 259 Chemicals Contribution 10 22 General and Administrative Expense (2) 251 206 Interest Expense (58) (99) Current Income Taxes 245 519 Future Income Taxes 90 254 Other Decrease in Fair Value of Crude Oil Put Options (169) (185) Other (38) (54) ---------------------------------------- NET INCOME AT JUNE 30, 2009 20 155 ========================================
(1) All amounts are presented before provision for income taxes. (2) Includes stock-based compensation expense. Significant variances in net income are explained further in the following sections. 33 OIL & GAS AND SYNCRUDE PRODUCTION (BEFORE ROYALTIES) (1)
Three Months Six Months Ended June 30 Ended June 30 2009 2008 2009 2008 ---------------------------------------------------------------------------------------------------------- Crude Oil and Liquids (mbbls/d) United Kingdom 97.7 100.3 100.7 103.1 Yemen 51.5 57.6 52.9 59.9 Canada 14.9 16.4 15.1 16.3 United States 12.1 11.3 11.2 12.5 Long Lake Bitumen (2) 9.3 3.2 8.7 1.9 Other Countries 3.6 5.7 4.5 5.8 Syncrude (mbbls/d) (3) 14.9 19.1 17.3 19.2 --------------------------------------------------- 204.0 213.6 210.4 218.7 --------------------------------------------------- Natural Gas (mmcf/d) United Kingdom 18 19 18 20 Canada 136 126 138 127 United States 61 99 56 105 --------------------------------------------------- 215 244 212 252 --------------------------------------------------- Total Production (mboe/d) 240 254 246 261 ===================================================
PRODUCTION (AFTER ROYALTIES) Three Months Six Months Ended June 30 Ended June 30 2009 2008 2009 2008 ---------------------------------------------------------------------------------------------------------- Crude Oil and Liquids (mbbls/d) United Kingdom 97.6 100.3 100.6 103.1 Yemen 29.0 29.2 32.3 30.4 Canada 11.2 12.6 11.8 12.4 United States 10.9 9.7 10.2 10.9 Long Lake Bitumen (2) 9.2 3.2 8.6 1.9 Other Countries 3.3 5.2 4.2 5.4 Syncrude (mbbls/d) (3) 13.0 15.9 16.3 16.4 --------------------------------------------------- 174.2 176.1 184.0 180.5 --------------------------------------------------- Natural Gas (mmcf/d) United Kingdom 18 19 18 20 Canada 129 108 127 107 United States 54 85 50 90 --------------------------------------------------- 201 212 195 217 --------------------------------------------------- Total Production (mboe/d) 208 211 217 217 ===================================================
(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) Pre-operating revenues and costs associated with Long Lake bitumen are capitalized as development costs until we reach commercial operations. (3) Considered a mining operation for US reporting purposes. LOWER VOLUMES DECREASED NET INCOME FOR THE QUARTER BY $52 MILLION Production before royalties decreased 5% from the prior quarter and 6% from the second quarter of 2008. Planned downtime at Buzzard to return the drilling rig after completing rig modifications, natural declines in Yemen and turnaround activity at Syncrude all contributed to the decrease. These decreases were partially offset by higher bitumen production volumes at Long Lake and restored production in the Gulf of Mexico following last year's hurricane interruptions. The decrease from the second quarter of 2008 largely reflects lower rates in Yemen and the UK North Sea and production that remains shut-in in the Gulf of Mexico, partially offset by higher bitumen production at Long Lake. Production before royalties was 8% lower than the prior quarter and 1% lower from the second quarter of 2008. 34 The following table summarizes our production volume changes since last quarter: Before After (mboe/d) Royalties Royalties -------------------------------------------------------------------------------- Production, first quarter 2009 252 225 Production changes: United States 4 3 Long Lake Bitumen 1 1 Canada (1) - Other (2) (1) Yemen (3) (7) Syncrude (5) (7) United Kingdom (6) (6) ----------------------------------- Production, second quarter 2009 240 208 =================================== Production volumes discussed in this section represent before-royalties volumes, net to our working interest. UNITED KINGDOM Production volumes in the UK North Sea were 6% and 3% lower than the prior quarter and the same period last year, respectively. Our share of production from the Buzzard field averaged 87,500 boe/d (202,500 boe/d gross) during the second quarter of 2009. While this was slightly higher than last year, production was 5,200 boe/d lower than the previous quarter as Buzzard production was shut in for approximately seven days while the Galaxy III drilling rig was reinstalled on the platform. Production from Buzzard has since returned to full rates. Construction of the fourth platform at Buzzard continues and we plan to install the jackets for this platform during the third quarter. This will result in approximately four weeks of downtime, which is scheduled to coincide with an expected six week slowdown of the Forties pipeline for routine maintenance. The fourth platform will allow us to handle higher levels of hydrogen sulphide and maintain peak production until at least 2014. Production at Scott/Telford remained consistent with the prior quarter; however, natural declines and unplanned maintenance reduced production 17% compared to the second quarter of 2008. Scott/Telford will be shut down for approximately five weeks for planned maintenance during the third quarter, also coinciding with Forties shutdown. Production from our non-operated fields at Duart and Farragon averaged 2,900 boe/d during the quarter. Our Ettrick development is expected to produce first oil in the third quarter. The project is expected to add approximately 12,000 to 16,000 boe/d to our production volumes for the remainder of the year. Ettrick will produce to a leased floating production, storage and offloading vessel designed to handle 30,000 bbls/d of oil and 35 mmcf/d of gas. YEMEN Yemen production decreased 6% and 11% from the prior quarter and the second quarter of 2008, respectively. This decline is consistent with our expectations as the field matures. Our drilling program is focused on maximizing reserve recoveries and economic returns. In the second quarter of 2009, we drilled seven development wells. Production declines are expected to continue as we focus on maximizing recovery of the remaining reserves and on obtaining economic returns on the block. CANADA Production in Canada was 2% lower than the previous quarter and consistent with the same period last year. Conventional production from our heavy oil properties was slightly lower due to natural field declines. We have reduced our heavy oil capital program and are focusing on cost efficiency to maximize economic returns. Lower heavy oil production was offset somewhat by increasing coalbed methane (CBM) production. CBM quarterly production averaged 52 mmcf/d and was 11 mmcf/d higher than the second quarter of 2008. LONG LAKE Bitumen production averaged 9,300 boe/d (14,300 boe/d gross) during the quarter, an increase of 7% from the prior quarter. To date, the upgrader has produced approximately 700,000 bbls (gross) of premium synthetic crude (PSCTM). PSCTM volumes tripled in the quarter by progressing the Upgrader ramp up. In May 2009, we successfully completed a project to add supplementary heat to the HLS units in the water treatment plant. We also completed routine 35 maintenance work to remove deposits which typically build up in water treatment plants. Steam production increased in the quarter and we have achieved record injection rates of approximately 95,000 bbls/d and gross bitumen production rates of approximately 18,000 bbls/d. There are currently 41 of 81 well pairs on production and we are producing at a steam-to-oil ratio (SOR) which ranges between 4.0 and 5.0. We continue to expect a long term SOR of 3.0 over the life of the project. Production volumes have been impacted by downtime associated with improvements made to the HLS units. We plan to replace valves and conduct maintenance on our water treatment plant during the third quarter to further optimize our steam production. The cost of these activities will not be significant and will result in scheduled downtime in the third quarter, impacting bitumen and PSCTM production. As steam generation increases, all wells are expected to be converted to production mode. With respect to the Upgrader, all major units are operational and Syngas is being used in SAGD operations. This allows us to decrease operating costs by reducing the requirement for purchased natural gas. The solvent de-asphalter and thermal cracker units are expected to start shortly and will allow us to transition from gasifying vacuum residue, which contains some lighter parts of the barrel, to gasifying asphaltenes, the heaviest part of the barrel. As a result, we expect our PSCTM yield to increase from approximately 60% to 80%. UNITED STATES Gulf of Mexico production volumes were 18% higher than the prior quarter as we continued to restore shut-in production from our hurricane-affected properties. Our Wrigley field came back on stream in late April and we anticipate that field production will be restored to pre-hurricane rates in the second half of the year. The increase was offset slightly by natural production declines at Gunnison. Production volumes from Wrigley will be limited for approximately three weeks in the third quarter to complete corrosion mitigation work. Production volumes were 20% lower than the same period last year primarily due to production shut-in by the hurricane interruptions. This was partially offset by higher rates on the properties that are currently producing as a result of successful workovers and recompletions. Following the 2008 hurricane interruptions, approximately 4,000 boe/d remains shut in and is expected to return to production in 2010 or 2011, after reconstruction of a destroyed platform. At the end of the second quarter 2009, our production in the Gulf of Mexico was approximately 24,000 boe/d. We expect production to start up from our non-operated Longhorn development in the deep water shortly. The development is a three well subsea tie-back to the Corral platform located 19 miles northwest of the field, with plans underway to tie-in a fourth well that was successfully drilled earlier in the year. OTHER COUNTRIES Our share of production from the Guando field in Colombia averaged 3,600 boe/d during the quarter, approximately 2,000 boe/d lower than the prior quarter and the second quarter of 2008. The decrease reflects the reduction of our working interest during the quarter. Under the terms of our license, our working interest in the Guando field decreased from 20% to 10% in May 2009 when cumulative production from the field reached 60 million barrels. SYNCRUDE Syncrude production was 25% lower than the previous quarter and 22% lower than the second quarter of 2008. The scheduled turnaround of Coker 8-3 took longer than anticipated, resulting in lower production volumes. Maintenance on Coker 8-1 and fewer shipments of synthetic crude as a result of outages on the Pembina pipeline also contributed to reduced production. Syncrude is currently producing 25,000 bbls/d (net to us) early in the third quarter. 36 COMMODITY PRICES
Three Months Six Months Ended June 30 Ended June 30 2009 2008 2009 2008 -------------------------------------------------------------------------------------------------------------- CRUDE OIL West Texas Intermediate (WTI) (US$/bbl) 59.62 123.98 51.35 110.94 Dated Brent (Brent) (US$/bbl) 58.79 121.38 51.60 109.14 -------------------------------------------------- Benchmark Differentials (1) (US$/bbl) Heavy Oil 7.73 22.08 8.45 21.96 Mars 2.27 6.96 0.80 6.94 Masila 0.93 3.92 0.49 3.12 Realized Prices from Producing Assets (Cdn$/bbl) United Kingdom 69.42 118.24 60.38 104.56 Yemen 69.40 120.39 60.63 107.97 Canada 56.05 93.16 45.49 79.62 United States 66.23 120.77 57.05 106.11 Other Countries 66.83 113.18 51.63 102.21 Syncrude 71.58 130.90 62.44 116.24 Corporate Average (Cdn$/bbl) 68.32 118.00 59.12 104.68 -------------------------------------------------- NATURAL GAS New York Mercantile Exchange (US$/mmbtu) 3.81 11.48 4.15 10.12 AECO (Cdn$/mcf) 3.47 8.86 4.41 7.81 -------------------------------------------------- Realized Prices from Producing Assets (Cdn$/mcf) United Kingdom 3.67 7.06 4.69 6.95 Canada 3.42 9.67 4.09 8.50 United States 4.58 11.80 5.19 10.33 Corporate Average (Cdn$/mcf) 3.77 10.21 4.43 9.07 -------------------------------------------------- NEXEN'S AVERAGE REALIZED OIL AND GAS PRICE (Cdn$/boe) 61.28 108.26 54.28 96.36 -------------------------------------------------- AVERAGE FOREIGN EXCHANGE RATE - Canadian to US Dollar 0.8571 0.9900 0.8290 0.9929 --------------------------------------------------
(1) These differentials are a discount/(premium) to WTI. LOWER COMMODITY PRICES DECREASED QUARTERLY NET INCOME BY $803 MILLION WTI averaged US$59.62/bbl for the quarter, 38% higher than the previous quarter, but 52% lower than the second quarter of 2008. Brent increased 32% from the first quarter of 2009 and fell 52% from last year. The effect of the lower commodity prices from last year was mitigated somewhat by the strengthening US dollar. Our realized crude oil sales price averaged $68.32/bbl, 36% higher than the previous quarter and 42% lower than the second quarter of 2008. NYMEX and AECO natural gas prices decreased 15% and 35%, respectively from the previous quarter and 67% and 61%, respectively from the same period last year. Our realized average gas sales price decreased 26% and 63%, respectively, as compared to the same periods. Most of our natural gas sales are priced based on NYMEX and AECO benchmark prices. The US dollar strengthened relative to last year, increasing our sales by approximately $147 million compared to the second quarter of 2008. This increase is represented by higher realized crude oil and natural gas prices of $9.17/bbl and $0.51/mcf, respectively. However, the US dollar weakened against the Canadian dollar during the second quarter, reducing net sales by approximately $74 million. Our second quarter realized crude oil and natural gas sales prices are $4.62/bbl and $0.25/mcf lower, respectively. CRUDE OIL REFERENCE PRICES Crude oil prices increased during the quarter, driven mainly by a rally in equity markets and positive investment flows into commodity markets due to the weakening US dollar and concerns about rising inflation. Current crude oil price levels are not supported by near-term demand/supply fundamentals indicating that the market may be driven more by medium term forecasts. Crude oil prices were supported by positive signs for the global economy, particularly in Asia, and optimism that the worst of the recession may be over. However, OECD economies 37 are still fragile and global trade remains weak. The apparent beginning of economic recovery has not yet improved short-term fundamentals in these countries and inventory levels, particularly distillate and product inventories, remain high although US gasoline inventories are at the lower end of the five year range. Geopolitical events during the quarter had little impact on price as OPEC has spare production capacity of almost five million barrels per day. Early in the third quarter, this optimism waned and crude oil benchmark prices fell approximately 10%-15% in the first two weeks of July. CRUDE OIL DIFFERENTIALS The narrower heavy oil differential was driven by cuts in medium crude oil quotas by OPEC, strong fuel oil prices and lower heavy oil supply from Mexico. Differentials are expected to widen as refineries reduce coking runs due to lower margins. However, the approaching asphalt season should continue to support heavy oil prices. The Brent/WTI differential was volatile during the quarter. Initial premiums over WTI were due to depressed WTI pricing caused by high inventory levels at Cushing. However, as inventories decreased throughout the quarter, the differential reverted to a discount. Lower Cushing inventory levels also contributed to the wider Masila differential. The Masila price strengthened relative to Brent, reflecting strong demand from China and other Asian countries. The Mars differential continued to widen during the second quarter due to stronger WTI prices. NATURAL GAS REFERENCE PRICES Lower natural gas prices were driven by declines in industrial and power demand and high inventory levels as natural gas producers have been slow to respond to lower prices by reducing supply. Continuing weak North American gas prices are forecasted as strong supply additions are expected from shale gas, tight gas and new LNG volumes from Russia and the Middle East. Large storage capacity in the US is also expected to increase LNG imports whenever international supply exceeds demand. OPERATING EXPENSES
Three Months Six Months Ended June 30 Ended June 30 (Cdn$/boe) 2009 2008 2009 2008 ---------------------------------------------------------------------------------------------------------------------------- Operating expenses based on our production before royalties (1) Conventional Oil and Gas 8.80 9.01 8.53 8.20 Synthetic Crude Oil Syncrude 57.21 45.09 45.70 40.10 Average Oil and Gas 11.95 11.89 11.27 10.60 --------------------------------------------------- Operating expenses based on our production after royalties Conventional Oil and Gas 10.28 10.97 9.86 9.95 Synthetic Crude Oil Syncrude 65.36 54.28 48.59 46.78 Average Oil and Gas 13.94 14.45 12.95 12.83 ---------------------------------------------------
(1) Operating expenses per boe are our total oil and gas operating costs divided by our working interest production before royalties. We use production before royalties to monitor our performance consistent with other Canadian oil and gas companies. LOWER OPERATING EXPENSES INCREASED NET INCOME FOR THE QUARTER BY $9 MILLION Our corporate average decreased $1.03/boe as a result of lower maintenance expenses in the UK North Sea, Canada and the US Gulf of Mexico. These savings were offset by the stronger US dollar, which increased our corporate average by $1.09/boe for the quarter. Production from our lower cost areas such as Buzzard made up more of our total consolidated production relative to last year, which lowered our overall corporate average by $0.78/boe. In the UK North Sea, lower production tariffs at Buzzard reduced our corporate average by $0.54/boe. The other UK North Sea operating areas decreased our corporate average by $0.28/boe as production declines only partially offset the impact of lower operating costs. In Yemen, we continue to concentrate our efforts on maximizing reserve recoveries and slowing the natural decline of the fields by maintaining existing wells. At Block 51, a combination of higher production rates and lower maintenance costs lowered our corporate average by $0.11/boe. In the US Gulf of Mexico, lower downhole maintenance costs were offset by lower production volumes, increasing our corporate average by $0.15/boe. In Canada, lower utility and downhole workover costs reduced our corporate average by $0.24/boe. At Syncrude, maintenance and turnaround costs were consistent with the same period last year. However, the downtime associated with the maintenance activity was longer this year resulting in lower production. This increased our corporate average by $0.79/boe. 38 DEPRECIATION, DEPLETION, AMORTIZATION AND IMPAIRMENT (DD&A)
Three Months Six Months Ended June 30 Ended June 30 (Cdn$/boe) 2009 2008 2009 2008 ------------------------------------------------------------------------------------------------------------- DD&A based on our production before royalties (1) Conventional Oil and Gas 18.49 14.72 18.53 14.55 Synthetic Crude Oil Syncrude 6.31 6.53 6.40 6.70 Average Oil and Gas 17.69 14.07 17.64 13.96 --------------------------------------------------- DD&A based on our production after royalties Conventional Oil and Gas 21.59 17.91 21.43 17.65 Synthetic Crude Oil Syncrude 7.21 7.86 6.80 7.81 Average Oil and Gas 20.64 17.11 20.26 16.88 ---------------------------------------------------
(1) DD&A per boe is our DD&A for oil and gas operations divided by our working interest production before royalties. We use production before royalties to monitor our performance consistent with other Canadian oil and gas companies. HIGHER OIL AND GAS DD&A DECREASED NET INCOME FOR THE QUARTER BY $61 MILLION Our oil and gas DD&A expense increased 20% over the same period last year. The strengthening US dollar relative to the second quarter of 2008 increased our corporate average by $2.48/boe, as depletion of our international and US assets is denominated in US dollars. In the UK North Sea, our Buzzard depletion rate was lower than the same period last year as successful development drilling increased our proved reserve estimates at the end of 2008. The lower depletion rate reduced our corporate average by $0.23/boe. Elsewhere in the UK, our corporate average is $0.29/boe higher primarily as a result of downward economic reserve revisions due to low 2008 year end prices at our mature Scott/Telford fields at the end of 2008. In Yemen, the impact of lower capital expenditures from drilling fewer development wells decreased our corporate unit depletion rate by $0.51/boe as compared to the second quarter of 2008. In the Gulf of Mexico, higher estimates for future abandonment costs and downward year end price-related reserve revisions at the end of 2008 resulted in higher depletion rates, increasing our corporate average rate by $0.81/boe. Canadian depletion increased our corporate average by $0.71/boe from the same period last year. Higher depletion rates for heavy oil properties were realized as lower year-end commodity prices reduced our proved reserves. This was partially offset by lower depletion rates for our CBM properties as additional proved reserves were recognized through improved recovery rates. 39 EXPLORATION EXPENSE
Three Months Six Months Ended June 30 Ended June 30 2009 2008 2009 2008 ---------------------------------------------------------------------------------------------------------------------------- Seismic 31 24 43 34 Unsuccessful Drilling 16 51 27 51 Other 30 26 60 48 --------------------------------------------------- Total Exploration Expense 77 101 130 133 =================================================== New Growth Exploration 167 136 330 320 Geological and Geophysical Costs 31 24 43 34 --------------------------------------------------- Total Exploration Expenditures 198 160 373 354 =================================================== Exploration Expense as a % of Exploration Expenditures 39% 63% 35% 38% ---------------------------------------------------
LOWER EXPLORATION EXPENSE INCREASED NET INCOME FOR THE QUARTER BY $24 MILLION Our exploration expenditures were $38 million higher than the same period last year as we invested in our shale gas exploration program at Dilly Creek, successfully drilled the Owowo exploration well offshore Nigeria and continued to appraise the Golden Eagle area in the UK North Sea. In 2007, we drilled the initial Golden Eagle discovery well in what is now the Golden Eagle area, and followed up with another success further south at Pink in 2008. In January 2009, we drilled the Hobby discovery. We have subsequently drilled successful sidetracks and appraisal wells on the Pink and Hobby wells. In the second half of the year, we expect to continue the appraisal drilling program for the Hobby discovery. In the Eastern Gulf of Mexico, we previously made two discoveries at Vicksburg and Shiloh. We are currently reviewing tie-back options to existing platforms for the Vicksburg discovery and expect to drill an appraisal well here in 2010. In addition, we recently spud the Antietam prospect, which is located three miles west of our Shiloh discovery. Drilling results are expected in the third quarter. Later this year, we also expect to drill an exploration well at Appomattox, about six miles west of Vicksburg. We have a 25% interest in Vicksburg and a 20% interest in Antietam, Appomattox and Shiloh, with Shell operating all four. We recently completed drilling an exploration well in the southern portion of Oil Prospecting License (OPL) 223, offshore West Africa. The Owowo South B-1 well was drilled in a water depth of 670 metres and is located 20 kilometres northeast of the Usan field, currently under development. Drilling results are under evaluation. Exploration expense was lower by $24 million compared with the same period in the prior year. In 2008, we expensed $30 million of unsuccessful exploration drilling associated with our CBM plays in Canada. Our exploration expense also includes costs of $25 million to acquire seismic data in the US Gulf of Mexico and North Sea. 40 ENERGY MARKETING
Three Months Six Months Ended June 30 Ended June 30 2009 2008 2009 2008 ------------------------------------------------------------------------------------------------------------- Physical Sales (1) 10,063 18,281 20,008 32,508 Physical Purchases (1) (9,604) (18,084) (19,406) (31,822) Net Financial Transactions (1) (276) (317) (228) (604) Change in Fair Market Value of Inventory 38 141 114 150 --------------------------------------------------- Marketing Revenue 221 21 488 232 Transportation Expense (163) (166) (328) (339) Other (1) 7 4 12 --------------------------------------------------- NET MARKETING REVENUE 57 (138) 164 (95) =================================================== CONTRIBUTION TO NET MARKETING REVENUE BY REGION North America 55 (123) 159 (78) Asia 6 4 18 8 Europe (4) (19) (13) (25) --------------------------------------------------- NET MARKETING REVENUE 57 (138) 164 (95) DD&A (3) (4) (7) (7) General and Administrative (26) (41) (49) (67) Allowance for Doubtful Receivables (3) - - - --------------------------------------------------- MARKETING CONTRIBUTION TO INCOME BEFORE INCOME TAXES 25 (183) 108 (169) =================================================== NORTH AMERICA NATURAL GAS Physical Sales Volumes (2) (bcf/d) 4.6 7.3 4.8 7.0 Transportation Capacity (bcf/d) 1.3 2.0 1.3 2.0 Storage Capacity (bcf) 33.9 54.2 33.9 54.2 Financial Volumes (3) (bcf/d) 10.0 18.8 12.7 22.6 CRUDE OIL Physical Sales Volumes (2) (mbbls/d) 873 689 835 669 Storage Capacity (mbbls) 2,644 2,699 2,644 2,699 Financial Volumes (3) (mbbls/d) 667 1,420 789 1,416 POWER Physical Sales Volumes (2) (GWh/d) 10 5 7 5 Generation Capacity (MW) 87 87 87 87 ASIA Physical Sales Volumes (2) (mbbls/d) 115 113 99 114 Financial Volumes (3) (mbbls/d) 531 337 425 302 EUROPE NATURAL GAS Physical Sales Volumes (2) (bcf/d) 0.9 1.0 1.1 1.2 Storage Capacity (bcf) 3.1 3.7 3.1 3.7 CRUDE OIL Financial Volumes (3) (mbbls/d) 259 598 378 1,352 POWER Physical Sales Volumes (2) (GWh/d) 5 5 6 5 VALUE-AT-RISK Quarter-end 15 31 15 31 High 19 40 24 40 Low 13 29 13 21 Average 15 34 17 32 ---------------------------------------------------
(1) Marketing's physical sales, physical purchases and net financial transactions are reported net on the Unaudited Consolidated Statement of Income as marketing and other. (2) Excludes intra-segment transactions. Physical volumes represent amounts delivered during the quarter. (3) Financial volumes represent amounts largely acquired to economically hedge physical transactions during the quarter. 41 HIGHER CONTRIBUTION FROM ENERGY MARKETING INCREASED NET INCOME BY $192 MILLION Energy marketing strategies and positions focused on optimizing our physical marketing business during the quarter with the North America natural gas storage strategy benefiting economically from widening time spreads and the global crude oil teams continuing to profit from the contango forward curve. In 2008, the North America natural gas team incurred financial losses on basis positions that were designed to take advantage of narrowing locational price differentials between the western supply regions and eastern consuming markets in North America with the addition of new pipeline capacity. Strong NYMEX gas prices worked against these physical gas market fundamentals widening out location differentials in supply regions last year. We have since refocused energy marketing on the physical business of marketing and optimization for both the gas and crude oil teams which involves buying, selling, holding and moving product. Relative to the first quarter of 2009, the second quarter began the seasonal injection cycle with low natural gas prices and high inventory levels in North America. Weak demand in the market caused location spreads to narrow across the entire transportation portfolio. Despite this economic environment, time spreads widened supporting our storage strategy as we continue to build inventory for the winter season. On a reported basis, we recognized net gains on the derivatives that protect our economic exposure of our physical transportation and storage strategies. The North America crude oil group continued to profit from contango in the market during the second quarter, although the crude oil contango curve was flatter than the first quarter. The gains from this strategy were offset by widening differentials and the significant strengthening of the Canadian dollar. Results from our marketing group vary by quarter and historical results are not necessarily indicative of results to be expected in future quarters. Quarterly marketing results depend on a variety of factors such as market volatility, changes in time and location spreads, the manner in which we use our storage and transportation assets and the change in value of the financial instruments we use to hedge these assets. COMPOSITION OF NET MARKETING REVENUE
Three Months Six Months Ended June 30 Ended June 30 2009 2008 2009 2008 ---------------------------------------------------------------------------------------------------------------------------- Trading Activities (Physical and related Financial) 58 (145) 160 (108) Non-Trading Activities (1) 7 4 13 --------------------------------------------------- Total Net Marketing Revenue 57 (138) 164 (95) ===================================================
TRADING ACTIVITIES In energy marketing, we enter into contracts to purchase and sell crude oil and natural gas as well as storage and transportation contracts to capture time and location differences. We also use financial and derivative contracts, including futures, forwards, swaps and options for hedging and trading purposes. We account for all financial and derivative contracts not designated as hedges for accounting purposes using fair value accounting and record the change in fair value in marketing and other income. The fair value of these instruments is included with amounts receivable or payable and they are classified as long-term or short-term based on their anticipated settlement date. OTHER ACTIVITIES We enter into fee for service contracts related to transportation, storage and sales of third-party oil and gas. In addition, we earn income from our power generation facilities at Balzac and Soderglen. FAIR VALUE OF DERIVATIVE CONTRACTS Our processes for estimating and classifying the fair value of our derivative contracts are consistent with those in place at December 31, 2008. At June 30, 2009, the fair value of our derivative contracts in our energy marketing trading activities was a net loss of $35 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 (124) (56) (21) - (201) Level 2 - Based on Other Observable Pricing Inputs 92 58 7 5 162 Level 3 - Based on Unobservable Pricing Inputs (7) 10 1 - 4 ----------------------------------------------------------- Total (39) 12 (13) 5 (35) ===========================================================
42 CHANGES IN FAIR VALUE OF DERIVATIVE CONTRACTS
Total ---------------------------------------------------------------------------------------------------------------- Fair Value at December 31, 2008 63 Change in Fair Value of Contracts 37 Net Losses (Gains) on Contracts Closed (135) Changes in Valuation Techniques and Assumptions (1) - --------------- Fair Value at June 30, 2009 (35) ===============
(1) Our valuation methodology has been applied consistently in each period. The fair values of our derivative contracts will be realized over time as the related contracts settle. Until then, the value of certain contracts will vary with forward commodity prices and price differentials. The average term of our derivative contracts is approximately 1.2 years. Those maturing beyond one year primarily relate to North American natural gas positions. CHEMICALS HIGHER CHEMICALS CONTRIBUTION INCREASED NET INCOME BY $10 MILLION North America chlorate sales decreased slightly from the second quarter of 2008 as the effect of stronger prices was offset by a 21% decrease in sales volumes as a result of the global economic downturn. Chlor-alkali revenue increased 17% from the same period last year primarily as a result of higher caustic prices. In Brazil, chlorate revenues declined slightly as higher prices were offset by lower sales volumes, while chlor-alkali revenues were down 33% as a result of fewer sales of purchased product as this activity generates no gross margin. Chemicals net income includes foreign exchange gains of $24 million on the Canexus US-dollar denominated debt, as well as gains of $5 million related to interest rate swaps and foreign exchange options and forward contracts. During the quarter, we reduced the carrying value of the sodium chlorate assets at the Bruderheim plant by $17 million as it is no longer in use. They also incurred $3 million of decommissioning and other costs in connection with the plant closure. CORPORATE EXPENSES GENERAL AND ADMINISTRATIVE (G&A)
Three Months Six Months Ended June 30 Ended June 30 2009 2008 2009 2008 ---------------------------------------------------------------------------------------------------------------- General and Administrative Expense before Stock-Based Compensation 111 90 211 186 Stock-Based Compensation (1) 56 328 56 287 ------------------------------------------ Total General and Administrative Expense 167 418 267 473 ==========================================
(1) Includes cash and non-cash expenses related to our tandem option and stock appreciation rights plans. LOWER G&A COSTS INCREASED NET INCOME BY $251 MILLION Lower stock-based compensation expense reduced our second quarter G&A expense from the prior year by $272 million. Changes in our share price create volatility in our net income as we account for stock-based compensation using the intrinsic-value method. Our share price increased 18% during the quarter, compared to a 33% increase last year. The impact of the current increase in our share price on stock-based compensation expense is reduced as many of our stock-based awards are below their exercise price. Cash payments made in connection with our stock-based compensation programs during the three and six month periods ended June 30, 2009 were $14 million (2008 - $69 million and $87 million, respectively). G&A expense before stock-based compensation increased $14 million primarily as a result of higher employee costs in the US where we have been recruiting experienced staff to prepare for the two new-build Ensco rigs, due to arrive on location later this year and mid 2010. 43 INTEREST
Three Months Six Months Ended June 30 Ended June 30 2009 2008 2009 2008 ----------------------------------------------------------------------------------------------- Interest 92 75 186 155 Less: Capitalized (18) (59) (44) (112) ------------------------------------------- Net Interest Expense 74 16 142 43 =========================================== Effective Interest Rate 4.5% 6.3% 4.7% 3.1% -------------------------------------------
HIGHER NET INTEREST EXPENSE REDUCED NET INCOME BY $58 MILLION Our financing costs increased $17 million from the second quarter of 2008 as the stronger US dollar increased our interest expense by $15 million. Additional borrowings on our term credit facilities increased our interest expense by $5 million. This was partially offset by lower interest rates on our floating rate debt and by repaying medium-term notes in June 2008. Capitalized interest on our Long Lake Project was $49 million lower than the previous year as construction of the facilities was completed earlier in the year. This decrease was partially offset by capitalizing additional interest on construction of the fourth platform at Buzzard and on our other major developments at Ettrick in the UK North Sea and at Usan, offshore West Africa. INCOME TAXES
Three Months Six Months Ended June 30 Ended June 30 2009 2008 2009 2008 ----------------------------------------------------------------------------------------------- Current 206 451 324 843 Future (229) (139) (316) (62) ------------------------------------------- Total Provision for (Recovery of) Income Taxes (23) 312 8 781 ===========================================
LOWER TAXES INCREASED NET INCOME BY $335 MILLION During the second quarter, lower commodity prices and a decrease in the value of our crude oil put options contributed to lower tax expense. We also reduced tax expense relative to last year as we continue to amortize a portion of the deferred tax credit arising from the 2008 internal reorganization of our North Sea assets. Our income tax provision includes current taxes in the UK, Yemen, Norway, Colombia and the US. OTHER
Three Months Six Months Ended June 30 Ended June 30 2009 2008 2009 2008 ----------------------------------------------------------------------------------------------- Decrease in Fair Value of Crude Oil Put Options (179) (10) (195) (10) -------------------------------------------
During the first quarter of 2008, we purchased put options on approximately 70,000 bbls/d of our 2009 crude oil production. These options establish a Dated Brent floor price of US$60/bbl, are settled annually and provide a base level of price protection without limiting our upside to higher prices. The put options were purchased for $14 million and are carried at fair value. During the third quarter of 2008, Lehman Brothers, one of the put option counterparties, filed for bankruptcy protection impacting 25,000 bbls/d of our 2009 put options. The carrying value of these put options has been reduced to nil. At June 30, 2009, the remaining options had a fair value of $36 million, $195 million lower than the end of 2008. The decrease in fair value this year was caused by strengthening Dated Brent crude oil prices. The put options will be in-the-money at the end of the year if prices average US$70/bbl or lower for the remainder of the year. 44 LIQUIDITY AND CAPITAL RESOURCES CAPITAL STRUCTURE
June 30 December 31 2009 2008 ---------------------------------------------------------------------------------------------------------------- NET DEBT (1) Bank Debt 2,995 1,448 Public Senior Notes 4,348 4,582 -------------------------------------- Total Senior Debt 7,343 6,030 Subordinated Debt 520 548 -------------------------------------- Total Debt 7,863 6,578 Less: Cash and Cash Equivalents (1,974) (2,003) -------------------------------------- TOTAL NET DEBT 5,889 4,575 ====================================== SHAREHOLDERS' EQUITY 7,303 7,191 ======================================
(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 2009 2009 ---------------------------------------------------------------------------------------------------------------- Capital Investment 715 1,464 Acquisition of Additional Working Interest at Long Lake - 755 Cash Flow from Operating Activities (1) (109) (898) ------------------------------------ Deficiency 606 1,321 Dividends on Common Shares 26 52 Issue of Common Shares (7) (30) Changes in Restricted Cash (67) 247 Foreign Exchange Translation of US-dollar Debt and Cash (465) (327) Other 59 51 ------------------------------------ Increase in Net Debt 152 1,314 ====================================
(1) Includes use of cash for the three months ended June 30 of $340 million for changes in non-cash working capital and a source of cash for the six months ended June 30 of $80 million for changes in non-cash working capital. Our net debt increased from March 31, 2009 despite the Canadian dollar strengthening against the US dollar during the quarter. This impact was offset as our second quarter capital investment exceeded our cash flow from operating activities. Our available liquidity at June 30, 2009 was approximately US$2.5 billion, comprised of cash on hand and undrawn credit facilities. Operating cash flows in the oil and gas industry can be volatile as short-term commodity prices are driven by existing supply and demand fundamentals and market volatility. We invest through the lows of the current commodity market to create future growth and value for our shareholders for the long-term. Changes in our non-cash working capital can vary between quarters as our energy marketing net working capital position fluctuates depending on timing of settlement of outstanding positions and the movement in commodity prices. CHANGE IN WORKING CAPITAL
June 30 December 31 Increase/ 2009 2008 (Decrease) --------------------------------------------------------------------------------------------------------------- Cash and Cash Equivalents 1,974 2,003 (29) Restricted Cash 335 103 232 Accounts Receivable 3,272 3,163 109 Inventories and Supplies 598 484 114 Accounts Payable and Accrued Liabilities (3,608) (3,326) 282 Other 78 76 2 -------------------------------------------------- Net Working Capital 2,649 2,503 ==================================
45 Accounts receivable and accounts payable in our energy marketing group increased since year end primarily as a result of higher crude oil prices. These increases have been partially offset by lower natural gas volumes caused by reducing activity to focus on supporting our core physical business as a producer/marketer. Earlier in the year, our energy marketing group reduced commodity inventory by selling natural gas in storage during the winter season. We took advantage of low seasonal natural gas markets and acquired additional volumes in the second quarter for storage until the 2009/2010 winter heating season. In June, we liquidated a portion of our crude oil inventory and the proceeds will be received in July. At June 30, 2009, our restricted cash consists of margin deposits of $335 million (December 31, 2008 - $103 million) related to exchange-traded derivative financial contracts used by our energy marketing group to hedge physical commodities, and storage, transportation and customer sales contracts. We are required to maintain margin for net out-of-the-money derivative financial contracts. The increase in margin primarily relates to derivative financial contracts hedging our natural gas positions. Declining natural gas prices and widening time spreads increased the value of storage and fixed price customer sales contracts. Concurrently, the derivative financial contracts hedging these positions declined in value. Additional margin was required to cover the increase in the net out-of-the-money derivative financial contracts. The increase in other assets is primarily represented by the Dated Brent crude oil put options fair value of $36 million. The annual options mature at the end of 2009 and were reclassed from long-term to current assets during the first quarter. OUTLOOK FOR REMAINDER OF 2009 We expected our 2009 production to range between 255,000 and 270,000 boe/d before royalties. With the longer than expected turnaround at Syncrude and the ongoing ramp-up of Long Lake, we now expect to be towards the low end of our annual guidance. Our future liquidity and ability to fund capital requirements generally depends upon operating cash flows, our existing working capital, our unused committed credit facilities, and our ability to access debt and equity markets. Given the long cycle time of some of our development projects and volatile commodity prices, it is not unusual in any year for capital expenditures to exceed our cash flow. Changes in commodity prices, particularly crude oil as it represents over 85% of our production, can impact our operating cash flows. We use short-term contracts to sell the majority of our oil and gas production, exposing us to short-term price movements. A US$1/bbl change in WTI above US$60/bbl is projected to increase or decrease our 2009 cash flow from operating activities, after cash taxes, by approximately $26 million for the remainder of 2009. Our exposure to a $0.01 change in the US to Canadian dollar exchange rate is projected to increase or decrease our 2009 cash flow by approximately $15 million for the remainder of 2009. While commodity prices can fluctuate significantly in the short term, we believe that over the longer term, commodity prices will increase as a result of growth in world demand and delays or shortages in supply growth. We believe that our existing liquidity and balance sheet capacity and capital investment flexibility provides us with the ability to fund our obligations during periods of lower commodity prices. We have incurred approximately 55% of our 2009 planned capital expenditures to date and acquired the additional 15% working interest in Long Lake. During the quarter, our capital has been concentrated on developing our Usan project offshore Nigeria, appraising our Golden Eagle/Hobby area, advancing work on the fourth platform at Buzzard, bringing our Ettrick and Longhorn developments on stream in the third quarter and on progressing our Horn River shale gas play in northeastern British Columbia. We expect to invest capital of approximately $1 billion during the remainder of the year on our development projects described above. During the first six months of 2009, lower commodity prices reduced our cash flow from operating activities relative to the same period last year. Over the same period, we have invested almost $1.5 billion in capital projects and another $755 million to acquire an additional 15% in the Long Lake Project. As our capital expenditures exceeded our cash flow from operating activities, we drew upon our available liquidity. We currently have approximately $2.0 billion of cash and cash equivalents on hand and as well as significant undrawn committed credit facilities available. At June 30, 2009, we had unsecured term credit facilities of US$3.1 billion in place that are available until 2012, of which US$2.3 billion was drawn and US$337 million was used to support outstanding letters of credit. We also have approximately $496 million of undrawn, uncommitted, unsecured credit facilities, of which $33 million was used to support outstanding letters of credit. The average length-to-maturity of our public debt is approximately 15 years. In June 2009, we filed a universal base shelf prospectus in the US and Canada, allowing us to potentially issue up to US$3.5 billion of debt, equity or other hybrid securities, should the need arise. This replaces our existing shelf prospectus that expired during the quarter. In the second quarter, our board of directors declared a quarterly common share dividend of $0.05 per share. 46 CONTRACTUAL OBLIGATIONS, COMMITMENTS AND GUARANTEES We have assumed various contractual obligations and commitments in the normal course of our operations and financing activities. We have included these obligations and commitments in our MD&A in our 2008 Form 10-K. There have been no significant developments since year-end. CONTINGENCIES There are a number of lawsuits and claims pending, the ultimate result of which cannot be ascertained at this time. We record costs as they are incurred or become determinable. We believe the resolution of these matters would not have a material adverse effect on our liquidity, consolidated financial position or results of operations. These matters are described in LEGAL PROCEEDINGS in Item 3 contained in our 2008 Form 10-K. There have been no significant developments since year-end. NEW ACCOUNTING PRONOUNCEMENTS CANADIAN PRONOUNCEMENTS All Canadian publicly accountable enterprises will be required to adopt International Financial Reporting Standards (IFRS) for interim and annual reporting purposes for fiscal years beginning on or after January 1, 2011. We are currently assessing the impact of the convergence of Canadian GAAP with IFRS on our results of operations, financial position and disclosures. A project team has been set up to manage this transition and to ensure successful implementation within the required timeframe. Details of our IFRS adoption plan can be found in our 2008 Form 10-K. We will provide additional disclosures of key elements of our plan and progress of the project as the information becomes available. US PRONOUNCEMENTS In December 2008, the Financial Accounting Standards Board (FASB) issued FSP FAS 132(R)-1, EMPLOYERS DISCLOSURES ABOUT POSTRETIREMENT BENEFIT PLAN ASSETS. This position provides guidance on disclosures about plan assets of a defined benefit pension plan or other postretirement plans. This position is effective for fiscal years ending after December 15, 2009. We do not expect the adoption of this statement to materially impact our results of operations or financial position. In June 2009, FASB issued Statement 167, AMENDMENTS TO FASB INTERPRETATION NO. 46 (R). It retains the scope of Interpretation 46(R) with the addition of entities previously considered qualifying special-purpose entities and eliminates the previous quantitative approach for a qualitative analysis in determining whether the enterprise's variable interest or interests give it a controlling financial interest in a variable interest entity. The Statement further amends Interpretation 46(R) to require ongoing reassessments of whether an enterprise is the primary beneficiary of a variable interest entity and requires enhanced disclosures about an enterprise's involvement in a variable interest entity. The Statement is effective at the beginning the first annual reporting period after November 15, 2009. We do not expect the adoption of this statement to have a material impact on our results of operations or financial position. EQUITY SECURITY REPURCHASES During the quarter, we made no purchases of our own equity securities. SUMMARY OF QUARTERLY RESULTS
2007 | 2008 | 2009 (Cdn$ millions, except per share amounts) Sept Dec | Mar Jun Sep Dec | Mar Jun ---------------------------------------------------------------------|--------------------------------------|------------------ Net Sales 1,446 1,598 1,870 2,071 2,213 1,270 1,048 1,200 Net Income (Loss) 403 194 630 380 886 (181) 135 20 Earnings (Loss) Per Common Share ($/share) Basic 0.77 0.37 1.19 0.72 1.68 (0.35) 0.26 0.04 Diluted 0.75 0.36 1.17 0.70 1.66 (0.35) 0.26 0.04 ----------------------------------------------------- -----------------------
47 SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS Certain statements in this report, including those appearing in MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS, constitute "forward-looking statements" (within the meaning of the United States PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995, as amended) or "forward-looking information" (within the meaning of applicable Canadian securities legislation). Such statements or information (together "forward-looking statements") are generally identifiable by the forward-looking terminology used such as "ANTICIPATE", "BELIEVE", "INTEND", "PLAN", "EXPECT", "ESTIMATE", "BUDGET", "OUTLOOK", "FORECAST" or other similar words, and include statements relating to or associated with individual wells, regions or projects. Any statements regarding the following are forward-looking statements: o future crude oil, natural gas or chemicals prices; o future production levels; o future cost recovery oil revenues from our Yemen operations; o future capital expenditures and their allocation to exploration and development activities; o future earnings; o future asset acquisitions or dispositions; o future sources of funding for our capital program; o future debt levels; o availability of committed credit facilities; o possible commerciality; o development plans or capacity expansions; o future ability to execute dispositions of assets or businesses; o future sources of liquidity, cash flows and their uses; o future drilling of new wells; o ultimate recoverability of current and long-term assets; o ultimate recoverability of reserves or resources; o expected finding and development costs; o expected operations costs; o future demand for chemical products; o estimates on a per share basis; o future foreign currency exchange rates; o future expenditures and future allowances relating to environmental matters; o dates by which certain areas will be developed, will come on-stream or reach expected operating capacity; and o changes in any of the foregoing. Statements relating to "reserves" or "resources" are forward-looking statements, as they involve the implied assessment, based on estimates and assumptions, that the reserves and resources described exist in the quantities predicted or estimated, and can be profitably produced in the future. The forward-looking statements are subject to known and unknown risks and uncertainties and other factors which may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Such factors include, among others: o market prices for oil and gas and chemical products; o our ability to explore, develop, produce and transport crude oil and natural gas to markets; o ultimate effectiveness of design modification to facilities; o the results of exploration and development drilling and related activities; o volatility in energy trading markets; o foreign-currency exchange rates; o economic conditions in the countries and regions in which we carry on business; o governmental actions including changes to taxes or royalties, changes in environmental and other laws and regulations; o renegotiations of contracts; o results of litigation, arbitration or regulatory proceedings; o political uncertainty, including actions by terrorists, insurgent or other groups, or other armed conflict, including conflict between states; and o other factors, many of which are beyond our control. These risks, uncertainties and other factors and their possible impact are discussed more fully in the sections titled RISK FACTORS in Item 1A and QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK and in Item 7A of our 48 2008 Form 10-K. The impact of any one risk, uncertainty or factor on a particular forward-looking statement is not determinable with certainty as these factors are interdependent, and management's future course of action would depend on an assessment of all information at that time. Although we believe that the expectations conveyed by the forward-looking statements are reasonable based on information available to us on the date such forward-looking statements were made, no assurances can be given as to future results, levels of activity and achievements. Undue reliance should not be placed on the statements contained herein, which are made as of the date hereof and, except as required by law, we undertake no obligation to update publicly or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The forward-looking statements contained herein are expressly qualified by this cautionary statement. ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK We are exposed to normal market risks inherent in the oil and gas, energy marketing and chemicals business, including commodity price risk, foreign-currency exchange rate risk, interest rate risk and credit risk. We recognize these risks and manage our operations to minimize our exposures to the extent practical. 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, 2009: o over 94% of our credit exposures were investment grade; o approximately 94% of our credit exposures were with integrated oil companies, crude oil refiners and marketers and large utilities; and o only one counterparty individually made up more than 10% of our credit exposure. This counterparty is a major integrated oil company with a strong investment grade credit rating. Further information presented on market risks can be found in Item 7A on pages 75 - 78 in our 2008 Form 10-K and have not materially changed since December 31, 2008. ITEM 4. CONTROLS AND PROCEDURES EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES The Company's Chief Executive Officer and Chief Financial Officer have designed disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the SECURITIES EXCHANGE ACT OF 1934), or caused such disclosure controls and procedures to be designed under their supervision, to ensure that material information relating to the Company is made known to them, particularly during the period in which this report is prepared. They have evaluated the effectiveness of such disclosure controls and procedures as of the end of the period covered by this report ("Evaluation Date"). Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that, as of the Evaluation Date, the Company's disclosure controls and procedures are effective (i) to ensure that information required to be disclosed by us in reports that the Company files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission rules and forms; and (ii) to ensure that information required to be disclosed in the reports that the Company files or submits under the Exchange Act is accumulated and communicated to our management, including the Company's Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosures. The Company's management, including its Chief Executive Officer and Chief Financial Officer, does not expect that the Company's disclosure controls and procedures or internal controls will prevent all possible error and fraud. The Company's disclosure controls and procedures are, however, designed to provide reasonable assurance of achieving their objectives, and the Company's Chief Executive Officer and Chief Financial Officer have concluded that the Company's financial controls and procedures are effective at that reasonable assurance level. CHANGES IN INTERNAL CONTROLS We have continually had in place systems relating to internal control over financial reporting. There has not been any change in the Company's internal control over financial reporting during the first six months of 2009 that has materially affected, or is reasonably likely to materially affect, the Company's internal control over financial reporting. 49 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 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS Our Annual General Meeting of Shareowners (the "Meeting") was held on April 28, 2009. The following actions were taken at the Meeting, for which proxies were solicited pursuant to Section 85 of the Securities Act (Ontario). (a) Each of the twelve director nominees proposed by management were elected by a vote, conducted by ballot as follows:
Director For % Withheld % ----------------------------------------------------------------------------------- William B. Berry 323,405,852 97.43 8,546,464 2.57 Robert G. Bertram 328,579,673 98.98 3,372,643 1.02 Dennis G. Flanagan 328,542,912 98.97 3,409,404 1.03 S. Barry Jackson 295,817,201 89.11 36,135,115 10.89 Kevin J. Jenkins 295,664,095 89.07 36,288,221 10.93 A. Anne McLellan, P.C. 267,038,872 80.44 64,913,444 19.56 Eric P. Newell, O.C. 328,524,629 98.97 3,427,687 1.03 Thomas C. O'Neill 287,426,933 86.59 44,525,383 13.41 Marvin F. Romanow 328,470,752 98.95 3,481,564 1.05 Francis M. Saville, Q.C. 262,005,721 78.93 69,946,595 21.07 John M. Willson 295,702,503 89.08 36,249,813 10.92 Victor J. Zaleschuk 328,427,870 98.94 3,524,446 1.06
(b) The appointment of Deloitte & Touche LLP, Chartered Accountants, to serve as the independent auditors for 2009 was approved by a show of hands. Proxies of 330,644,003 (99.66%) for and 1,133,157 (0.34%) withheld were received. ITEM 6. EXHIBITS 10.57 Termination of Employment and Retirement Agreement between the Registrant and Roger D. Thomas dated May 12, 2009. 31.1 Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 31.2 Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 32.1 Certification of periodic report by Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 32.2 Certification of periodic report by Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Company has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on July 21, 2009. NEXEN INC. /s/ Marvin F. Romanow ------------------------- Marvin F. Romanow President and Chief Executive Officer (Principal Executive Officer) /s/ Brendon T. Muller ------------------------- Brendon T. Muller Controller (Principal Accounting Officer) 50