10-Q 1 form10q_q310.txt QUARTERLY REPORT - PERIOD ENDING SEPTEMBER 30, 2010 UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-Q |X| QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended September 30, 2010 |_| TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from ....... to ....... COMMISSION FILE NUMBER 1-6702 [GRAPHIC OMITTED] NEXEN INC. Incorporated under the Laws of Canada 98-6000202 (I.R.S. Employer Identification No.) 801 - 7th Avenue S.W. Calgary, Alberta, Canada T2P 3P7 Telephone (403) 699-4000 Web site - WWW.NEXENINC.COM Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No --------------- ---------------- Indicate by check mark whether the registrant has submitted electronically and posted on its corporate web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (ss.232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes No --------------- ---------------- Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer", "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act. Large accelerated filer X Accelerated filer Non-Accelerated filer --- --- --- Smaller reporting company --------- Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes No X --------------- ---------------- On September 30, 2010, there were 525,032,386 common shares issued and outstanding. 1 NEXEN INC. INDEX PART I FINANCIAL INFORMATION PAGE Item 1. Unaudited Consolidated Financial Statements .....................3 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A) ...............................33 Item 3. Quantitative and Qualitative Disclosures about Market Risk .....56 Item 4. Controls and Procedures ........................................56 PART II OTHER INFORMATION Item 1. Legal Proceedings ..............................................57 Item 6. Exhibits .......................................................57 This report should be read in conjunction with our 2009 Annual Report on Form 10-K (2009 Form 10-K) and with our current reports on Forms 10-Q and 8-K filed or furnished during the year. SPECIAL NOTE TO CANADIAN INVESTORS Nexen is a US Securities and Exchange Commission (SEC) registrant and a Form 10-K and related forms filer. Therefore, our reserves estimates and securities regulatory disclosures generally follow SEC requirements. In 2004, certain Canadian regulatory authorities adopted NATIONAL INSTRUMENT 51-101 - STANDARDS OF DISCLOSURE FOR OIL AND GAS ACTIVITIES (NI 51-101) which prescribe that Canadian companies follow certain standards for the preparation and disclosure of reserves and related information. We have been granted certain exemptions from NI 51-101. Please refer to the SPECIAL NOTE TO CANADIAN INVESTORS on page 97 of our 2009 Form 10-K. UNLESS WE INDICATE OTHERWISE, ALL DOLLAR AMOUNTS ($) ARE IN CANADIAN DOLLARS, AND OIL AND GAS VOLUMES, RESERVES AND RELATED PERFORMANCE MEASURES ARE PRESENTED ON A WORKING-INTEREST, BEFORE-ROYALTIES BASIS. WHERE APPROPRIATE, INFORMATION ON AN AFTER-ROYALTIES BASIS IS ALSO PRESENTED. Below is a list of terms specific to the oil and gas industry. They are used throughout this Form 10-Q. /d = per day mcf = thousand cubic feet bbl = barrel mmcf = million cubic feet mbbls = thousand barrels bcf = billion cubic feet mmbbls = million barrels NGL = natural gas liquid mmbtu = million British thermal units WTI = West Texas Intermediate boe = barrel of oil equivalent MW = Megawatt mboe = thousand barrels of oil equivalent GWh = gigawatt hours mmboe = million barrels of oil equivalent Brent = Dated Brent PSCTM = Premium Synthetic CrudeTM NYMEX = New York Mercantile Exchange Gj = Gigajoules In this Form 10-Q, we refer to oil and gas in common units called barrel of oil equivalent (boe). A boe is derived by converting six thousand cubic feet of gas to one barrel of oil (6 mcf/1 bbl). This conversion may be misleading, particularly if used in isolation, as the 6 mcf per bbl ratio is based on an energy equivalency at the burner tip and does not represent a value equivalency at the well head. Electronic copies of our filings with the SEC and the Ontario Securities Commission (OSC) (from November 8, 2002 onward) are available, free of charge, on our web site (WWW.NEXENINC.COM). Filings prior to November 8, 2002 are available free of charge, upon request, by contacting our investor relations department at (403) 699-5931. As soon as reasonably practicable, our filings are made available on our website once they are electronically filed with the SEC or the OSC. Alternatively, the SEC and the OSC each maintain a website (WWW.SEC.GOV and WWW.SEDAR.COM) that contains our reports, proxy and information statements and other published information that have been filed or furnished with the SEC and the OSC. On September 30, 2010, the noon-day exchange rate was US$0.9711 for Cdn$1.00, as reported by the Bank of Canada. 2 PART I ITEM 1. UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS TABLE OF CONTENTS Page Unaudited Consolidated Statement of Income for the Three and Nine Months Ended September 30, 2010 and 2009...............4 Unaudited Consolidated Balance Sheet as at September 30, 2010 and December 31, 2009................................5 Unaudited Consolidated Statement of Cash Flows for the Three and Nine Months Ended September 30, 2010 and 2009...............6 Unaudited Consolidated Statement of Equity for the Three and Nine Months Ended September 30, 2010 and 2009...............7 Unaudited Consolidated Statement of Comprehensive Income for the Three and Nine Months Ended September 30, 2010 and 2009...............8 Notes to Unaudited Consolidated Financial Statements..........................9 3
NEXEN INC. UNAUDITED CONSOLIDATED STATEMENT OF INCOME FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30 Three Months Nine Months Ended September 30 Ended September 30 (Cdn$ millions, except per share amounts) 2010 2009 2010 2009 ------------------------------------------------------------------------------------------------------------------------------ REVENUES AND OTHER INCOME Net Sales 1,416 1,034 4,247 3,176 Marketing and Other (Note 14) 138 296 373 635 -------------------------------------------------------- 1,554 1,330 4,620 3,811 -------------------------------------------------------- EXPENSES Operating 420 297 1,218 872 Depreciation, Depletion, Amortization and Impairment 477 329 1,234 1,087 Transportation and Other 142 180 501 606 General and Administrative 132 108 316 363 Exploration 56 89 199 219 Interest (Note 9) 81 84 238 226 Net Loss from Dispositions (Note 15) 259 - 179 - -------------------------------------------------------- 1,567 1,087 3,885 3,373 -------------------------------------------------------- INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE PROVISION FOR INCOME TAXES (13) 243 735 438 -------------------------------------------------------- PROVISION FOR (RECOVERY OF) INCOME TAXES Current 270 190 793 514 Future (234) (81) (423) (390) -------------------------------------------------------- 36 109 370 124 -------------------------------------------------------- NET INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE NON-CONTROLLING INTERESTS (49) 134 365 314 Less: Net Income Attributable to Canexus Non-Controlling Interests (4) (12) (4) (17) -------------------------------------------------------- NET INCOME (LOSS) FROM CONTINUING OPERATIONS ATTRIBUTABLE TO NEXEN INC. (53) 122 361 297 Net Income (Loss) from Discontinued Operations (Note 15) 590 - 616 (20) -------------------------------------------------------- NET INCOME ATTRIBUTABLE TO NEXEN INC. 537 122 977 277 ======================================================== EARNINGS (LOSS) PER COMMON SHARE FROM CONTINUING OPERATIONS ($/share) (Note 16) Basic (0.10) 0.23 0.69 0.57 ======================================================== Diluted (0.10) 0.23 0.69 0.57 ======================================================== EARNINGS PER COMMON SHARE ($/share) (Note 16) Basic 1.02 0.23 1.86 0.53 ======================================================== Diluted 1.02 0.23 1.86 0.53 ========================================================
SEE ACCOMPANYING NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS. 4 NEXEN INC. UNAUDITED CONSOLIDATED BALANCE SHEET
September 30 December 31 (Cdn$ millions, except share amounts) 2010 2009 ------------------------------------------------------------------------------------------------------------------------------- ASSETS CURRENT ASSETS Cash and Cash Equivalents 1,210 1,700 Restricted Cash 35 198 Accounts Receivable (Note 2) 2,305 2,788 Inventories and Supplies (Note 3) 544 680 Other 142 185 ------------------------------------- Total Current Assets 4,236 5,551 ------------------------------------- PROPERTY, PLANT AND EQUIPMENT Net of Accumulated Depreciation, Depletion, Amortization and Impairment of $10,414 (December 31, 2009 - $10,807) 15,835 15,492 GOODWILL 316 339 FUTURE INCOME TAX ASSETS 1,608 1,148 DEFERRED CHARGES AND OTHER ASSETS (Note 5) 236 370 ------------------------------------- TOTAL ASSETS 22,231 22,900 ===================================== LIABILITIES CURRENT LIABILITIES Accounts Payable and Accrued Liabilities (Note 8) 2,943 3,038 Accrued Interest Payable 78 89 Dividends Payable 26 26 ------------------------------------- Total Current Liabilities 3,047 3,153 ------------------------------------- LONG-TERM DEBT (Note 9) 5,678 7,251 FUTURE INCOME TAX LIABILITIES 3,127 2,811 ASSET RETIREMENT OBLIGATIONS (Note 11) 1,007 1,018 DEFERRED CREDITS AND OTHER LIABILITIES (Note 12) 766 1,021 EQUITY Nexen Inc. Shareholders' Equity Common Shares, no par value Authorized: Unlimited Outstanding: 2010 - 525,032,386 shares 2009 - 522,915,843 shares 1,097 1,049 Contributed Surplus - 1 Retained Earnings 7,621 6,722 Accumulated Other Comprehensive Loss (196) (190) ------------------------------------- Total Nexen Inc. Shareholders' Equity 8,522 7,582 Canexus Non-Controlling Interests 84 64 ------------------------------------- TOTAL EQUITY 8,606 7,646 ------------------------------------- COMMITMENTS, CONTINGENCIES AND GUARANTEES (Note 17) ------------------------------------- TOTAL LIABILITIES AND EQUITY 22,231 22,900 =====================================
SEE ACCOMPANYING NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS. 5
NEXEN INC. UNAUDITED CONSOLIDATED STATEMENT OF CASH FLOWS FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30 Three Months Nine Months Ended September 30 Ended September 30 (Cdn$ millions) 2010 2009 2010 2009 --------------------------------------------------------------------------------------------------------------------------- OPERATING ACTIVITIES Net Income (Loss) from Continuing Operations (49) 134 365 314 Net Income (Loss) from Discontinued Operations 590 - 616 (20) Charges and Credits to Income not Involving Cash (Note 18) (102) 174 433 887 Exploration Expense 56 89 199 219 Changes in Non-Cash Working Capital (Note 18) 212 113 410 193 Other (39) (49) (47) (234) -------------------------------------------------------- 668 461 1,976 1,359 FINANCING ACTIVITIES Repayment of Short-Term Borrowings, Net (156) (1) - (1) Proceeds from Long-Term Notes - 1,081 - 1,081 Proceeds from (Repayment of) Term Credit Facilities, Net (463) (915) (1,540) 728 Proceeds from (Repayment of) Canexus Term Credit Facilities, Net (4) (4) 64 48 Proceeds from Canexus Debentures 60 46 60 46 Dividends Paid on Common Shares (26) (26) (78) (78) Distributions Paid to Canexus Non-Controlling Interests (6) (4) (13) (11) Issue of Common Shares and Exercise of Tandem Options for Shares 9 12 44 42 Other (2) (18) (15) (19) -------------------------------------------------------- (588) 171 (1,478) 1,836 INVESTING ACTIVITIES Capital Expenditures Exploration and Development (554) (586) (1,793) (1,921) Proved Property Acquisitions - - - (755) Energy Marketing, Chemicals, Corporate and Other (38) (69) (172) (198) Proceeds from Dispositions 950 2 1,046 17 Changes in Non-Cash Working Capital (Note 18) (105) 14 (30) (41) Changes in Restricted Cash (43) 93 40 (154) Other (1) (15) (8) (16) -------------------------------------------------------- 209 (561) (917) (3,068) EFFECT OF EXCHANGE RATE CHANGES ON CASH AND CASH EQUIVALENTS (49) (148) (71) (233) -------------------------------------------------------- INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 240 (77) (490) (106) CASH AND CASH EQUIVALENTS - BEGINNING OF PERIOD 970 1,974 1,700 2,003 -------------------------------------------------------- CASH AND CASH EQUIVALENTS - END OF PERIOD (1) 1,210 1,897 1,210 1,897 ========================================================
(1) Cash and cash equivalents at September 30, 2010 consist of cash of $211 million and short-term investments of $999 million (September 30, 2009 - cash of $376 million and short-term investments of $1,521 million). SEE ACCOMPANYING NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS. 6 NEXEN INC. UNAUDITED CONSOLIDATED STATEMENT OF EQUITY FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30
Three Months Nine Months Ended September 30 Ended September 30 (Cdn$ millions) 2010 2009 2010 2009 ------------------------------------------------------------------------------------------------------------------------------- COMMON SHARES, Beginning of Period 1,088 1,011 1,049 981 Issue of Common Shares 9 8 41 37 Exercise of Tandem Options for Shares - 4 3 5 Accrued Liability Relating to Tandem Options Exercised for Common Shares - 2 4 2 --------------------------------------------------------- Balance at End of Period 1,097 1,025 1,097 1,025 ========================================================= CONTRIBUTED SURPLUS, Beginning of Period - 2 1 2 Exercise of Tandem Options - (1) (1) (1) --------------------------------------------------------- Balance at End of Period - 1 - 1 ========================================================= RETAINED EARNINGS, Beginning of Period 7,110 6,393 6,722 6,290 Net Income Attributable to Nexen Inc. 537 122 977 277 Dividends Paid on Common Shares (Note 13) (26) (26) (78) (78) --------------------------------------------------------- Balance at End of Period 7,621 6,489 7,621 6,489 ========================================================= ACCUMULATED OTHER COMPREHENSIVE LOSS, Beginning of Period (189) (157) (190) (134) Other Comprehensive Loss Attributable to Nexen Inc. (7) (26) (6) (49) --------------------------------------------------------- Balance at End of Period (1) (196) (183) (196) (183) ========================================================= (1) Comprised of unrealized foreign currency translation adjustment. CANEXUS NON-CONTROLLING INTERESTS, Beginning of Period 71 54 64 52 Net Income Attributable to Non-Controlling Interests 4 15 4 24 Distributions Due to Non-Controlling Interests (5) (5) (15) (14) Issue of Partnership Units to Non-Controlling Interests 6 1 23 3 Estimated Fair Value of Conversion Feature of Convertible Debenture Issue Attributable to Non-Controlling Interests 8 4 8 4 --------------------------------------------------------- Balance at End of Period 84 69 84 69 =========================================================
SEE ACCOMPANYING NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS. 7
NEXEN INC. UNAUDITED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30 Three Months Nine Months Ended September 30 Ended September 30 (Cdn$ millions) 2010 2009 2010 2009 ------------------------------------------------------------------------------------------------------------------------------- NET INCOME ATTRIBUTABLE TO NEXEN INC. 537 122 977 277 Other Comprehensive Loss, Net of Income Taxes: Foreign Currency Translation Adjustment Net Losses on Investment in Self-Sustaining Foreign Operations (145) (408) (83) (693) Net Gains on Foreign-Denominated Debt Hedges of Self-Sustaining Foreign Operations (1) 138 384 77 646 Realized Translation Adjustments Recognized in Net Income - (2) - (2) ------------------------------------------------------------- Other Comprehensive Loss Attributable to Nexen Inc. (7) (26) (6) (49) ------------------------------------------------------------- COMPREHENSIVE INCOME ATTRIBUTABLE TO NEXEN INC. 530 96 971 228 =============================================================
(1) Net of income tax expense for the three months ended September 30, 2010 of $20 million (2009 - $55 million expense) and net of income tax expense for the nine months ended September 30, 2010 of $12 million (2009 - $93 million expense). SEE ACCOMPANYING NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS. 8 NEXEN INC. NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS Cdn$ millions, except as noted 1. ACCOUNTING POLICIES Our Unaudited Consolidated Financial Statements are prepared in accordance with Canadian Generally Accepted Accounting Principles (GAAP). The impact of significant differences between Canadian and United States GAAP on the Unaudited Consolidated Financial Statements is disclosed in Note 20. In the opinion of management, the Unaudited Consolidated Financial Statements contain all adjustments of a normal and recurring nature necessary to present fairly Nexen Inc.'s (Nexen, we or our) financial position at September 30, 2010 and December 31, 2009 and the results of our operations and our cash flows for the three and nine months ended September 30, 2010 and 2009. We make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the Unaudited Consolidated Financial Statements, and revenues and expenses during the reporting period. Our management reviews these estimates on an ongoing basis, including those related to accruals, litigation, environmental and asset retirement obligations, recoverability of assets, income taxes, fair values of derivative assets and liabilities, capital adequacy and determination of proved reserves. Changes in facts and circumstances may result in revised estimates and actual results may differ from these estimates. The results of operations and cash flows for the three and nine months ended September 30, 2010 are not necessarily indicative of the results of operations or cash flows to be expected for the year ending December 31, 2010. As at October 27, 2010, there are no material subsequent events requiring additional disclosure in or amendment to these financial statements. These Unaudited Consolidated Financial Statements should be read in conjunction with our Audited Consolidated Financial Statements included in our 2009 Form 10-K. The accounting policies we follow are described in Note 1 of the Audited Consolidated Financial Statements included in our 2009 Form 10-K. CHANGES IN ACCOUNTING POLICIES Oil and Gas Reserve Estimates ----------------------------- In early 2010, the Financial Accounting Standards Board issued guidance for OIL AND GAS RESERVE ESTIMATION AND DISCLOSURE, which is effective for years ended December 31, 2009. The guidance: i) expands the definition of oil and gas producing activities to include unconventional sources such as oil sands; ii) changes the price used in reserve estimation from the year-end price to the simple average of the first-day-of-the-month price for the previous 12 months; and iii) requires disclosures for geographic areas that represent 15% or more of proved reserves. We follow the successful efforts method of accounting for our oil and gas activities, which use the estimated proved reserves we believe are recoverable from our oil and gas properties. Specifically, reserves estimates are used to calculate our unit-of-production depletion rates and to assess, when necessary, our oil and gas assets for impairment. Adoption of these amendments changed our estimate of reserves used to calculate depletion in 2010. As a result of the amendments, depletion expense for the three and nine months ended September 30, 2010 increased by $11 million and $35 million, net income decreased by $7 million and $23 million, and earnings per common share decreased by $0.02/share and $0.06/share, respectively. 9
2. ACCOUNTS RECEIVABLE September 30 December 31 2010 2009 ------------------------------------------------------------------------------------------------------------------------------ Trade Energy Marketing 1,300 1,410 Energy Marketing Derivative Contracts (Note 6) 172 466 Oil and Gas 712 823 Chemicals and Other 47 44 --------------------------------------- 2,231 2,743 Non-Trade 121 99 --------------------------------------- 2,352 2,842 Allowance for Doubtful Receivables (47) (54) --------------------------------------- Total 2,305 2,788 =======================================
3. INVENTORIES AND SUPPLIES September 30 December 31 2010 2009 ------------------------------------------------------------------------------------------------------------------------------ Finished Products Energy Marketing 389 548 Oil and Gas 54 25 Chemicals and Other 10 12 --------------------------------------- 453 585 Work in Process 10 7 Field Supplies 81 88 --------------------------------------- Total 544 680 =======================================
4. PROPERTY, PLANT AND EQUIPMENT DEPRECIATION, DEPLETION, AMORTIZATION AND IMPAIRMENT Our DD&A expense in the third quarter of 2010 includes non-cash impairment charges of $61 million at three natural gas properties in the US Gulf of Mexico. Low natural gas prices made these mature shelf properties uneconomic and, as a result, the properties are being shut down and the carrying value was written down to their estimated fair value. Fair value was based on estimated future cash flows using unobservable Level 3 inputs including management's estimate of future production and prices. SUSPENDED EXPLORATION WELL COSTS The following table shows the changes in capitalized exploratory well costs during the nine months ended September 30, 2010 and the year ended December 31, 2009, and does not include amounts that were initially capitalized and subsequently expensed in the same period. Suspended exploration well costs are included in property, plant and equipment.
Nine Months Ended Year Ended September 30 December 31 2010 2009 ------------------------------------------------------------------------------------------------------------------------------ Beginning of Period 794 518 Exploratory Well Costs Capitalized Pending the Determination of Proved Reserves 350 396 Capitalized Exploratory Well Costs Charged to Expense (2) (56) Transfers to Wells, Facilities and Equipment Based on Determination of Proved Reserves (1) (21) Effects of Foreign Exchange Rate Changes (10) (43) --------------------------------------- End of Period 1,131 794 =======================================
10 The following table provides an aging of capitalized exploratory well costs based on the date drilling was completed as at September 30, 2010.
United United Aging of Suspended Exploration Wells Kingdom Canada States Nigeria Total ------------------------------------------------------------------------------------------------------------------------------ Less than 1 year 113 190 85 - 388 1-3 years 155 387 - - 542 4-5 years 55 - 115 - 170 Greater than 5 years - - - 31 31 ------------------------------------------------------------------------------ Total 323 577 200 31 1,131 ==============================================================================
As at September 30, 2010, we have exploratory costs that have been capitalized for more than one year relating to our shale gas exploratory activities in Canada ($387 million), interests in eight exploratory blocks in the North Sea ($210 million), two exploratory blocks in the Gulf of Mexico ($115 million), and our interest in an exploratory block offshore Nigeria ($31 million). These costs relate to projects with successful exploration wells for which we have not been able to recognize proved reserves. We are assessing all of these wells and projects, and are working with our partners to prepare development plans, drill additional appraisal wells or otherwise assess commercial viability. 5. DEFERRED CHARGES AND OTHER ASSETS
September 30 December 31 2010 2009 ------------------------------------------------------------------------------------------------------------------------------ Long-Term Energy Marketing Derivative Contracts (Note 6) 116 225 Defined Benefit Pension Assets 53 60 Long-Term Capital Prepayments 16 27 Other 51 58 ------------------------------------------- Total 236 370 ===========================================
6. FINANCIAL INSTRUMENTS Financial instruments carried at fair value on our balance sheet include cash and cash equivalents, restricted cash and derivatives used for trading and non-trading purposes. Our other financial instruments, including accounts receivable, accounts payable, accrued interest payable, dividends payable, short-term borrowings and long-term debt, are carried at cost or amortized cost. The carrying values of our short-term receivables and payables approximate their fair value because the instruments are near maturity. In our energy marketing group, we enter into contracts to purchase and sell crude oil, as well as 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 fair values are included with accounts receivable or payable and are classified as long-term or short-term based on anticipated settlement date. Any change in fair value is included in marketing and other income. Related amounts posted as margin for exchange-traded positions are recorded in restricted cash. We carry our long-term debt at amortized cost using the effective interest rate method. At September 30, 2010, the estimated fair value of our long-term debt was $6,385 million (December 31, 2009 - $7,594 million) as compared to the carrying value of $5,678 million (December 31, 2009 - $7,251 million). The fair value of long-term debt is estimated based on prices provided by quoted markets and third-party brokers. 11 DERIVATIVES (A) DERIVATIVE CONTRACTS RELATED TO TRADING ACTIVITIES During the quarter, we sold our North American natural gas marketing operations, as described in Note 15. Our energy marketing group primarily focuses on our crude oil marketing activities in North America, Europe and Asia. Our energy marketing group engages in various activities including the purchase and sale of physical commodities and the use of financial instruments such as commodity and foreign exchange futures, forwards and swaps to economically hedge exposures and generate revenue. These contracts are accounted for as derivatives and, where applicable, are presented net on the balance sheet in accordance with netting arrangements. The fair value and carrying amounts related to derivative instruments held by our energy marketing operations are as follows:
September 30 December 31 2010 2009 ------------------------------------------------------------------------------------------------------------------------------ Commodity Contracts 172 463 Foreign Exchange Contracts - 3 --------------------------------------- Accounts Receivable (Note 2) 172 466 --------------------------------------- Commodity Contracts 116 225 --------------------------------------- Deferred Charges and Other Assets (Note 5) (1) 116 225 --------------------------------------- Total Trading Derivative Assets 288 691 ======================================= Commodity Contracts 152 410 Foreign Exchange Contracts - 46 --------------------------------------- Accounts Payable and Accrued Liabilities (Note 8) 152 456 --------------------------------------- Commodity Contracts 119 212 --------------------------------------- Deferred Credits and Other Liabilities (Note 12) (1) 119 212 --------------------------------------- Total Trading Derivative Liabilities 271 668 ======================================= Total Net Trading Derivative Contracts 17 23 =======================================
(1) These derivative contracts settle beyond 12 months and are considered non-current; once settlement is within 12 months, they are included in accounts receivable or accounts payable. Excluding the impact of netting arrangements, the fair value of derivative instruments is as follows:
September 30 December 31 2010 2009 ------------------------------------------------------------------------------------------------------------------------------ Current Trading Assets 582 2,625 Non-Current Trading Assets 311 716 --------------------------------------- Total Trading Derivative Assets 893 3,341 ======================================= Current Trading Liabilities 562 2,615 Non-Current Trading Liabilities 314 703 --------------------------------------- Total Trading Derivative Liabilities 876 3,318 ======================================= --------------------------------------- Total Net Trading Derivative Contracts 17 23 =======================================
12 Trading revenues generated by our energy marketing group include gains and losses on derivative instruments and non-derivative instruments such as physical inventory. During the three and nine months ended September 30, 2010, the following trading revenues were recognized in marketing and other income:
Three Months Ended Nine Months Ended September 30 September 30 2010 2010 --------------------------------------------------------------------------------------------------------------------------- Commodity 84 290 Foreign Exchange (2) (8) ------------------------------------------------------------- Marketing Revenue 82 282 =============================================================
As an energy marketer, we may undertake several transactions during a period to execute a single sale of physical product. Each transaction may be represented by one or more derivative instruments including a physical buy, physical sell, and in many cases, numerous financial instruments for economic hedging and trading purposes. The absolute notional volumes associated with our derivative instrument transactions for the three and nine months ended September 30, 2010, are as follows:
Three Months Ended Nine Months Ended September 30 September 30 2010 2010 --------------------------------------------------------------------------------------------------------------------------- Natural Gas bcf/d 2.9 7.8 Crude Oil mmbbls/d 3.0 3.2 Power GWh/d 0.2 92.8 Foreign Exchange US$ millions 548 2,169 Foreign Exchange Euro millions - 53 -------------------------------------------------------------
(B) DERIVATIVE CONTRACTS RELATED TO NON-TRADING ACTIVITIES The fair value and carrying amounts of derivative instruments related to non-trading activities are as follows:
September 30 December 31 2010 2009 --------------------------------------------------------------------------------------------------------------------------- Accounts Receivable 4 13 Deferred Charges and Other Assets (1) 1 4 ------------------------------------------------------------- Total Non-Trading Derivative Assets 5 17 ============================================================= Accounts Payable and Accrued Liabilities - 26 ------------------------------------------------------------- Total Non-Trading Derivative Liabilities - 26 ============================================================= Total Net Non-Trading Derivative Assets (2) 5 (9) =============================================================
(1) These derivative contracts settle beyond 12 months and are considered non-current. (2) The net fair value of these derivatives is equal to the gross fair value before consideration of netting arrangements and collateral posted or received with counterparties. CRUDE OIL PUT OPTIONS During the quarter, we purchased put options on 20,000 bbls/d of our 2011 crude oil production for $6 million. These options establish a WTI floor price of US$50/bbl on these volumes and provide a base level of price protection without limiting our upside to higher prices. The options settle monthly and are recorded at fair value throughout their term. As a result, changes in forward crude oil prices create gains or losses on these options at each period end. Higher forward crude oil prices at September 30, 2010 reduced the fair value of the options to approximately $5 million. Subsequent to September 30, 2010, we purchased additional crude oil put options on 50,000 bbls/d of our 2011 crude oil production for $17 million. These options establish a WTI floor price of approximately US$56/bbl. 13 In 2009, we purchased put options on 90,000 bbls/d of our 2010 crude oil production for $39 million. These options establish a WTI floor price of US$50/bbl on these volumes. Options on 60,000 bbls/d settle monthly, while the remaining options settle annually. These options are recorded at fair value throughout their term. Higher forward crude oil prices at September 30, 2010 compared to the end of the previous quarter and a shorter term to expiry reduced the fair value of the options to nil.
Change in Fair Value ------------------------------------ Three Months Nine Months Ended Ended Notional Average Fair September 30 September 30 Volumes Term Floor Price Value 2010 2010 ---------------------------------------------------------------------------------------------------------------------------------- (bbls/d) (US$/bbl) WTI Crude Oil Put Options (monthly) 20,000 2011 50 5 (1) (1) WTI Crude Oil Put Options (monthly) 60,000 2010 50 - (2) (13) WTI Crude Oil Put Options (annual) 30,000 2010 50 - - (4) ----------------------------------------------- 5 (3) (18) ===============================================
(C) FAIR VALUE OF DERIVATIVES Our processes for estimating and classifying the fair value of our derivative contracts are consistent with those in place at December 31, 2009. The following table includes our derivatives carried at fair value for our trading and non-trading activities as at September 30, 2010. Financial assets and liabilities are classified in the fair value hierarchy in their entirety based on the lowest level of input that is significant to the fair value measurement. Assessment of the significance of a particular input to the fair value measurement requires judgment and may affect placement within the fair value hierarchy levels.
Net Derivatives at September 30, 2010 Level 1 Level 2 Level 3 Total -------------------------------------------------------------------------------------------------------------------------------- Trading Derivatives (Commodity Contracts) (27) - 44 17 Non-Trading Derivatives - 5 - 5 ------------------------------------------------------- Total (27) 5 44 22 =======================================================
A reconciliation of changes in the fair value of our derivatives classified as Level 3 for the nine months ended September 30, 2010 is provided below:
Level 3 ----------------------------------------------------------------------------------------------------------------------------- Beginning of Period 42 Realized and Unrealized Gains (Losses) 21 Purchases - Settlements (19) Transfers Into Level 3 - Transfers Out of Level 3 - --------------- End of Period 44 =============== Unsettled gains relating to instruments still held as of September 30, 2010 21 ===============
Items classified in Level 3 are generally economically hedged such that gains or losses on positions classified in Level 3 are often offset by gains or losses on positions classified in Level 1 or 2. Transfers into or out of Level 3 represent existing assets and liabilities that were either previously categorized as a higher level for which the inputs became unobservable or assets and liabilities that were previously classified as Level 3 for which the lowest significant input became observable during the period. Fair values of instruments in Level 3 are determined using broker quotes, pricing services and internally-developed inputs. We performed a sensitivity analysis of inputs used to calculate the fair value of Level 3 instruments. Using reasonably possible alternative assumptions, the fair value of Level 3 instruments at September 30, 2010 would change by $2 million (December 31, 2009 - $12 million). 14 7. RISK MANAGEMENT MARKET RISK We invest in significant capital projects, purchase and sell commodities, issue short-term borrowings and long-term debt, and invest in foreign operations. These activities expose us to market risks from changes in commodity prices, foreign currency rates and interest rates, which could affect our earnings and the value of the financial instruments we hold. We use derivatives for trading and non-trading purposes as part of our overall risk management policy to manage portions of these market exposures. The following market risk discussion focuses on the commodity price risk and foreign currency risk related to our financial instruments as our exposure to interest rate risk is immaterial, given that the majority of our debt is fixed rate. COMMODITY PRICE RISK We are exposed to commodity price movements as part of our normal oil and gas operations, particularly in relation to the prices received for our crude oil and natural gas. Commodity price risk related to conventional and synthetic crude oil prices is our most significant market risk exposure. Crude oil and natural gas are sensitive to numerous worldwide factors, many of which are beyond our control, and are generally sold at contract or posted prices. Changes in the global supply and demand fundamentals in the crude oil market and geopolitical events can significantly affect crude oil prices. Changes in crude oil and natural gas prices may significantly affect our results of operations and cash generated from operating activities. Consequently, these changes may also affect the value of our oil and gas properties, our level of spending for exploration and development, and our ability to meet our obligations as they come due. The majority of our oil and gas production is sold under short-term contracts, exposing us to the risk of price movements. Other energy contracts we enter into also expose us to commodity price risk between the time we purchase and sell contracted volumes. We actively manage these risks by using derivative contracts such as commodity put options. Our energy marketing business is primarily focused on marketing and trading physical crude oil in selected regions of the world. We do this by buying and selling physical crude oil, by acquiring and holding rights to physical transportation and storage assets, and by building strong relationships with our customers and suppliers. In order to manage the commodity and foreign exchange price risks that come from this physical business, we use financial derivative contracts including energy-related futures, forwards, swaps and options, as well as foreign currency swaps or forwards. Our risk management activities include prescribed capital limits and the use of tools such as Value-at-Risk (VaR) and stress testing consistent with the methodology used at December 31, 2009. Our period end, high, low and average VaR amounts for the three and nine months ended September 30, 2010 are as follows:
Three Months Nine Months Ended September 30 Ended September 30 Value-at-Risk 2010 2009 2010 2009 -------------------------------------------------------------------------------------------------------------------------------- Period End 8 13 8 13 High 9 15 15 24 Low 4 11 4 11 Average 7 12 10 16 -------------------------------------------------------
If a market shock occurred as in 2008, the key assumptions underlying our VaR estimate could be exceeded and the potential loss could be greater than our estimate. We perform stress tests on a regular basis to complement VaR and assess the impact of abnormal changes in prices on our positions. 15 FOREIGN CURRENCY RISK Foreign currency risk is created by fluctuations in the fair values or cash flows of financial instruments due to changes in foreign exchange rates. A substantial portion of our activities are transacted in or referenced to US dollars including: o sales of crude oil, natural gas and certain chemicals products; o capital spending and expenses for our oil and gas and chemicals operations; o commodity derivative contracts used primarily by our energy marketing group;and o short-term borrowings, long-term debt, and cash & cash equivalents. In our oil and gas operations, we manage our exposure to fluctuations between the US and Canadian dollar by matching our expected net cash flows and borrowings in the same currency. Cash inflows generated by our foreign operations and borrowings on our US-dollar debt facilities are generally used to fund US-dollar capital expenditures and debt repayments. We maintain revolving Canadian and US-dollar borrowing facilities that can be used or repaid depending on expected net cash flows. We designate most of our US-dollar borrowings as a hedge against our US-dollar net investment in self-sustaining foreign operations. The foreign exchange gains or losses related to the effective portion of our designated US-dollar debt are included in accumulated other comprehensive income in equity. Our net investment in self-sustaining foreign operations and our designated US-dollar debt at September 30, 2010 and December 31, 2009 are as follows:
September 30 December 31 (US$ millions) 2010 2009 ------------------------------------------------------------------------------------------------------------------------------ Net Investment in Self-Sustaining Foreign Operations 4,307 4,492 Designated US-Dollar Debt 4,307 4,492 -------------------------------------------
For the three and nine months ended September 30, 2010, the ineffective portion of our US-dollar debt resulted in a net foreign exchange gain of $12 million and a net foreign exchange loss of $6 million, respectively (gain of $11 million and loss of $5 million respectively, net of income tax expense) and is included in marketing and other income. A one cent change in the US dollar to Canadian dollar exchange rate would increase or decrease our accumulated other comprehensive income by approximately $43 million, net of income tax, and would increase or decrease our net income by approximately $4 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. CREDIT RISK Credit risk affects our oil, gas and chemicals operations, and our trading and non-trading derivative activities, and is the risk of loss if counterparties do not fulfill their contractual obligations. Most of our credit exposure is with counterparties in the energy industry, including integrated oil companies, refiners and utilities, and are subject to normal industry credit risk. Approximately 76% of our exposure is with these large energy companies. This concentration of risk within the energy industry is reduced because of our broad base of domestic and international counterparties. Our processes to manage this risk are consistent with those in place at December 31, 2009. 16 At September 30, 2010, only two counterparties individually made up more than 10% of our credit exposure. These counterparties are major integrated oil companies with a strong investment grade credit rating. Four other counterparties made up more than 5% of our credit exposure. The following table illustrates the composition of credit exposure by credit rating.
September 30 December 31 CREDIT RATING 2010 2009 ------------------------------------------------------------------------------------------------------------------------------ A or higher 67% 67% BBB 21% 26% Non-Investment Grade 12% 7% --------------------------------------- TOTAL 100% 100% =======================================
Our maximum counterparty credit exposure at the balance sheet date consists primarily of the carrying amounts on non-derivative financial assets such as cash and cash equivalents, restricted cash, accounts receivable, as well as the fair value of derivative financial assets. We provided an allowance of $47 million for credit risk with our counterparties. In addition, we incorporate the credit risk associated with counterparty default, as well as Nexen's own credit risk, into our estimates of fair value. Collateral received from customers at September 30, 2010 includes $45 million of cash and $224 million of letters of credit. The cash received is included in accounts payable and accrued liabilities. LIQUIDITY RISK Liquidity risk is the risk that we will not be able to meet our financial obligations as they fall due. We require liquidity specifically to fund capital requirements, satisfy financial obligations as they come due, and to operate our energy marketing business. We generally rely on operating cash flows to provide liquidity and we also maintain significant undrawn committed credit facilities. At September 30, 2010, we had approximately $4.4 billion of cash and available committed lines of credit. This includes approximately $1.2 billion of cash and cash equivalents on hand and undrawn term credit facilities of $3.2 billion, of which $289 million was supporting letters of credit at September 30, 2010. These facilities are available until 2014 unless extended. We also have about $466 million of uncommitted credit facilities, none of which was drawn and $82 million of which was supporting letters of credit at September 30, 2010. The following table details the contractual maturities for our non-derivative financial liabilities, including both the principal and interest cash flows at September 30, 2010:
Less than More than Total 1 Year 1-3 Years 4-5 Years 5 Years ------------------------------------------------------------------------------------------------------------------------------ Long-Term Debt 5,787 - 345 799 4,643 Interest on Long-Term Debt (1) 7,668 357 713 651 5,947 --------------------------------------------------------------------------------------- Total 13,455 357 1,058 1,450 10,590 =======================================================================================
(1) Excludes interest on Canexus term credit facilities of $294 million (US$285 million) as the amounts drawn on the facilities fluctuate. Based on amounts drawn at September 30, 2010 and existing variable interest rates, we would be required to pay $12 million per year until the outstanding amounts on the term credit facilities are repaid. The following table details contractual maturities for our derivative financial liabilities. The balance sheet amounts for derivative financial liabilities included below are not materially different from the contractual amounts due on maturity.
Less than More than Total 1 Year 1-3 Years 4-5 Years 5 Years ------------------------------------------------------------------------------------------------------------------------------ Trading Derivatives (Note 6) 271 152 103 11 5 Non-Trading Derivatives (Note 6) - - - - - --------------------------------------------------------------------------------------- Total 271 152 103 11 5 =======================================================================================
The commercial agreements our energy marketing group enter into often include financial assurance provisions that allow us and our counterparties to effectively manage credit risk. The agreements normally require collateral to be posted if an adverse credit-related event occurs, such as a drop in credit ratings to non-investment grade. Based on contracts in place and commodity prices at September 30, 2010, we could be required to post collateral of up to $700 million if we were downgraded to non-investment grade. These obligations are reflected on our balance sheet. The posting of collateral secures the payment of such amounts. In the event of a ratings downgrade, we have trading inventories and receivables that can be more quickly monetized as well as undrawn credit facilities. 17 At September 30, 2010, collateral posted with counterparties includes $15 million of cash and $139 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 $35 million (December 31, 2009 - $198 million), which have been included in restricted cash. 8. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES
September 30 December 31 2010 2009 ------------------------------------------------------------------------------------------------------------------------------ Energy Marketing Payables 1,203 1,366 Energy Marketing Derivative Contracts (Note 6) 152 456 Accrued Payables 653 619 Trade Payables 216 210 Income Taxes Payable 362 179 Stock-Based Compensation 28 72 Other 329 136 --------------------------------------- Total 2,943 3,038 =======================================
9. SHORT-TERM BORROWINGS AND LONG-TERM DEBT
September 30 December 31 2010 2009 ------------------------------------------------------------------------------------------------------------------------------ Canexus Term Credit Facilities, due 2012 (US$285 million drawn) (a) 294 233 Canexus Notes, due 2013 (US$50 million) 51 52 Notes, due 2013 (US$500 million) 515 523 Term Credit Facilities, due 2014 (b) - 1,570 Canexus Convertible Debentures, due 2014 27 46 Notes, due 2015 (US$250 million) 257 262 Canexus Convertible Debentures, due 2015 (c) 60 - Notes, due 2017 (US$250 million) 257 262 Notes, due 2019 (US$300 million) 309 314 Notes, due 2028 (US$200 million) 206 209 Notes, due 2032 (US$500 million) 515 523 Notes, due 2035 (US$790 million) 814 827 Notes, due 2037 (US$1,250 million) 1,287 1,308 Notes, due 2039 (US$700 million) 721 733 Subordinated Debentures, due 2043 (US$460 million) 474 481 --------------------------------------- 5,787 7,343 Unamortized Debt Issue Costs (109) (92) --------------------------------------- Total Long-Term Debt 5,678 7,251 =======================================
(A) CANEXUS TERM CREDIT FACILITIES Canexus has $450 million (US$437 million) of committed, secured term credit facilities available until August 2012. At September 30, 2010, $294 million (US$285 million) was drawn on these facilities (December 31, 2009 - $233 million (US$223 million)). Borrowings are available as Canadian bankers' acceptances, LIBOR-based loans, Canadian prime rate loans or US-dollar base rate loans. Interest is payable monthly at floating rates. The term credit facilities are secured by a floating charge debenture over all of Canexus' assets. The credit facility also contains covenants with respect to certain financial ratios of Canexus. The weighted-average interest rate on the Canexus term credit facilities was 4.3% for the three months ended September 30, 2010 (three months ended September 30, 2009 - 2.0%) and 3.5% for the nine months ended September 30, 2010 (nine months ended September 30, 2009 - 2.3%). 18 (B) TERM CREDIT FACILITIES We have unsecured term credit facilities of $3.2 billion (US$3.1 billion), available until 2014, none of which were drawn at September 30, 2010 (December 31, 2009 - $1.6 billion (US$1.5 billion)). Borrowings are available as Canadian bankers' acceptances, LIBOR-based loans, Canadian prime rate loans, US-dollar base rate loans or British pound call-rate loans. Interest is payable monthly at a floating rate. The weighted-average interest rate on our term credit facilities was 3.1% for the three months ended September 30, 2010 (three months ended September 30, 2009 - 0.9%) and 1.2% for the nine months ended September 30, 2010 (nine months ended September 30, 2009 - 1.0%). At September 30, 2010, $289 million (US$281 million) of these facilities were utilized to support outstanding letters of credit (December 31, 2009 - $407 million (US$389 million)). (C) CANEXUS CONVERTIBLE DEBENTURES In September 2010, Canexus issued $60 million of convertible unsecured subordinated debentures to non-controlling interests. Interest is payable semi-annually at a rate of 5.75%. These debentures mature on December 31, 2015 and are convertible at the holder's option at any time prior to the close of business on the earlier of; i) the maturity date; and, ii) the business day immediately preceding the date specified by Canexus for redemption of the debentures into trust units. The conversion price is $8.30 per trust unit. Canexus has the option to redeem the debentures in whole or in part from time to time subject to the satisfaction of certain conditions. The debentures can be redeemed by Canexus, after January 1, 2014 and before December 31, 2014 (provided that the current market price of the trust units on the date of redemption is not less than 125% of the conversion price) and after December 31, 2014 at a redemption price equal to the principal amount plus accrued and unpaid interest. Canexus may elect to satisfy its obligation to pay interest or repay the principal by issuing trust units at 95% of the current market price at the time of repayment and to pay interest by delivering a sufficient number of trust units to the debenture trustee to satisfy the interest obligation. The estimated fair value of the conversion feature of the convertible debentures amounted to $8 million and was included in non-controlling interests. The amount of the convertible debentures allocated to long-term debt is accreted over the term of the debt using the effective interest rate method. (D) INTEREST EXPENSE
Three Months Nine Months Ended September 30 Ended September 30 2010 2009 2010 2009 -------------------------------------------------------------------------------------------------------------------------------- Long-Term Debt 96 96 284 274 Other 9 4 18 12 ------------------------------------------------------- Total 105 100 302 286 Less: Capitalized (24) (16) (64) (60) ------------------------------------------------------- Total 81 84 238 226 =======================================================
Capitalized interest relates to and is included as part of the cost of our oil and gas properties. The capitalization rates are based on our weighted-average cost of borrowings. (E) SHORT-TERM BORROWINGS Nexen has uncommitted, unsecured credit facilities of approximately $466 million (US$452 million), none of which were drawn at September 30, 2010 (December 31, 2009 - nil). We utilized $82 million (US$80 million) of these facilities to support outstanding letters of credit at September 30, 2010 (December 31, 2009 - $86 million (US$82 million)). Interest is payable at floating rates. 19 10. CAPITAL MANAGEMENT Our objectives and processes for managing our capital structure are consistent with those in place at December 31, 2009. Our capital consists of equity, short-term borrowings, long-term debt and cash and cash equivalents as follows:
September 30 December 31 2010 2009 ------------------------------------------------------------------------------------------------------------------------------ NET DEBT (1) Long-Term Debt 5,678 7,251 Less: Cash and Cash Equivalents (1,210) (1,700) --------------------------------------- Total 4,468 5,551 ======================================= EQUITY (2) 8,606 7,646 =======================================
(1) Includes all of our borrowings and is calculated as long-term debt and short-term borrowings less cash and cash equivalents. (2) Equity is the historical issue of equity and accumulated retained earnings. We monitor the leverage in our capital structure by reviewing the ratio of net debt to adjusted cash flow (cash flow from operating activities before changes in non-cash working capital and other) and interest coverage ratios at various commodity prices. Net debt and adjusted cash flow are non-GAAP measures that are unlikely to be comparable to similar measures presented by others. We calculate net debt using the GAAP measures of long-term debt and short-term borrowings less cash and cash equivalents (excluding restricted cash). We use the ratio of net debt to adjusted cash flow as a key indicator of our leverage and to monitor the strength of our balance sheet. For the twelve months ended September 30, 2010, the net debt to adjusted cash flow was 1.8 times compared to 2.5 times at December 31, 2009. While we typically expect the target ratio to fluctuate between 1.0 and 2.0 times under normalized commodity prices, this can be higher or lower depending on commodity price volatility, where we are in the investment cycle, or when we identify strategic opportunities for additional investment. Whenever we exceed our target ratio, we assess whether we need to identify specific actions to reduce our leverage and lower this ratio back to target levels over time. Our interest coverage ratio monitors our ability to fund the interest requirements associated with our debt. Our interest coverage increased from 8.5 times at the end of 2009 to 9.4 times at September 30, 2010. Interest coverage is calculated by dividing our adjusted EBITDA by interest expense before capitalized interest. Adjusted EBITDA is a non-GAAP measure that is calculated using net income excluding interest expense, provision for income taxes, exploration expenses, DD&A, impairment and other non-cash expenses. The calculation of adjusted EBITDA is set out in the following table and is unlikely to be comparable to similar measures presented by others.
Twelve Months Ended Year Ended September 30 December 31 2010 2009 ------------------------------------------------------------------------------------------------------------------------------ Net Income Attributable to Nexen Inc. 1,236 536 Add: Interest Expense 324 312 Provision for Income Taxes 719 260 Depreciation, Depletion, Amortization and Impairment 1,891 1,802 Exploration Expense 282 302 Recovery of Non-Cash Stock-Based Compensation (77) (10) Change in Fair Value of Crude Oil Put Options 51 251 Other Non-Cash Expenses (605) (136) ------------------------------------------------ Adjusted EBITDA 3,821 3,317 ================================================
20 11. ASSET RETIREMENT OBLIGATIONS Changes in carrying amounts of the asset retirement obligations associated with our Property, Plant & Equipment (PP&E) are as follows:
Nine Months Ended Year Ended September 30 December 31 2010 2009 ------------------------------------------------------------------------------------------------------------------------------ Balance at Beginning of Period 1,053 1,059 Obligations Incurred with Development Activities 26 27 Obligations Settled (27) (42) Accretion Expense 48 70 Revisions to Estimates 108 13 Obligations Associated with Discontinued Activities (122) - Effects of Changes in Foreign Exchange Rate (15) (74) ------------------------------------------------ Balance at End of Period (1), (2) 1,071 1,053 ================================================
(1) Obligations due within 12 months of $64 million (December 31, 2009 - $35 million) have been included in accounts payable and accrued liabilities. (2) Obligations relating to our oil and gas activities amount to $1,030 million (December 31, 2009 - $1,002 million) and obligations relating to our chemicals business amount to $41 million (December 31, 2009 - $51 million). Our total estimated undiscounted inflated asset retirement obligations amount to $2,490 million (December 31, 2009 - $2,341 million). We discounted the total estimated asset retirement obligations using a weighted-average, credit-adjusted, risk-free rate of 6%. Approximately $238 million included in our asset retirement obligations is expected to be settled over the next five years. The remaining obligations settle beyond five years and are expected to be funded by future cash flows from our operations. 12. DEFERRED CREDITS AND OTHER LIABILITIES
September 30 December 31 2010 2009 ------------------------------------------------------------------------------------------------------------------------------ Deferred Tax Credit 409 503 Long-Term Energy Marketing Derivative Contracts (Note 6) 119 212 Defined Benefit Pension Obligations (1) 79 76 Capital Lease Obligations 43 61 Deferred Transportation Revenue - 55 Other 116 114 ------------------------------------------------ Total 766 1,021 ================================================
(1) The obligations are secured by letters of credit drawn on our term credit facilities. 13. SHAREHOLDERS' EQUITY DIVIDENDS Dividends per common share for the three months ended September 30, 2010 were $0.05 per common share (2009 - $0.05). Dividends per common share for the nine months ended September 30, 2010 were $0.15 per common share (2009 - $0.15). Dividends paid to holders of common shares have been designated as "eligible dividends" for Canadian tax purposes. 21 14. MARKETING AND OTHER INCOME
Three Months Nine Months Ended September 30 Ended September 30 2010 2009 2010 2009 -------------------------------------------------------------------------------------------------------------------------------- Marketing Revenue, Net 82 188 282 676 Long Lake Purchased Bitumen Sales 25 - 63 - Change in Fair Value of Crude Oil Put Options (3) (23) (18) (218) Interest 1 1 6 4 Foreign Exchange Gain (Loss) (13) 93 (7) 112 Other 46 37 47 61 ------------------------------------------------------- Total 138 296 373 635 =======================================================
15. DISPOSITIONS Canadian Heavy Oil Asset Disposition ------------------------------------ In May 2010, we signed an agreement to sell our heavy oil properties in Canada. The sale closed in July 2010 after receiving proceeds of $939 million, net of closing adjustments. We realized a gain of $781 million in the third quarter. The results of operations of these properties have been presented as discontinued operations.
Three Months Nine Months Ended September 30 Ended September 30 2010 2009 2010 2009 -------------------------------------------------------------------------------------------------------------------------------- Revenues and Other Income Net Sales 13 63 138 169 Gain on Disposition of Assets 781 - 781 - ------------------------------------------------------- 794 63 919 169 Expenses Operating 5 24 50 74 Depreciation, Depletion, Amortization and Impairment 1 29 35 93 General and Administrative 1 5 10 17 Transportation and Other - 5 2 12 ------------------------------------------------------- 7 63 97 196 ------------------------------------------------------- Income (Loss) before Provision for Income Taxes 787 - 822 (27) Provision for (Recovery of) Future Income Taxes 197 - 206 (7) ------------------------------------------------------- Net Income (Loss) from Discontinued Operations 590 - 616 (20) ======================================================= Earnings (Loss) Per Common Share Basic 1.12 - 1.17 (0.04) ======================================================= Diluted 1.12 - 1.17 (0.04) =======================================================
22 Assets and liabilities on the Consolidated Balance Sheet at December 31, 2009, include the following amounts for discontinued operations. There were no assets and liabilities related to discontinued operations at September 30, 2010.
December 31 2009 ------------------------------------------------------------------------------------------------------------------------------- Property, Plant and Equipment, Net of Accumulated DD&A 331 Asset Retirement Obligations (116) Deferred Credits and Other Liabilities (29) --------------------- Total 186 =====================
Natural Gas Energy Marketing Disposition ---------------------------------------- During the third quarter of 2010, we sold our North American natural gas marketing operations. The sale, which generated proceeds of $11 million, closed in the third quarter and we recognized a non-cash loss of $259 million. On closing, the purchaser acquired our North American natural gas storage and transportation commitments, natural gas inventory, and related financial and physical derivative positions. As is customary with such transactions, not all contracts were assigned to the purchaser by the closing date. We have a total return swap in place with the purchaser to transfer to them the economic results on the unassigned contracts until they are assigned to the purchaser. The total return swap and unassigned contracts are derivative instruments carried at fair value on our balance sheet. The related gains and losses offset each other for the quarter and future periods. In connection with our natural gas energy marketing disposition, we assigned substantially all of our natural gas transportation and storage contracts, reducing our future commitments by $342 million. We agreed to maintain our parental guarantee to the pipeline provider related to one transportation commitment. We are obligated to perform under the guarantee only if the purchaser does not meet its obligation to the pipeline provider. To guarantee its performance, the purchaser provided us with collateral of US$43 million for the maximum exposure under the guarantee. This collateral is included in accounts payable. We expect to cancel this guarantee in the fourth quarter. Canadian Undeveloped Oil Sand Leases ------------------------------------ During the second quarter, we sold our non-core lands in the Athabasca region for proceeds of $81 million. We had no plans to develop these lands for a least a decade. We recognized a gain on sale of $80 million. 16. EARNINGS PER COMMON SHARE We calculate basic earnings per common share using net income divided by the weighted-average number of common shares outstanding. We calculate diluted earnings per common share in the same manner as basic, except we use the weighted-average number of diluted common shares outstanding in the denominator.
Three Months Nine Months Ended September 30 Ended September 30 (millions of shares) 2010 2009 2010 2009 -------------------------------------------------------------------------------------------------------------------------------- Weighted-average number of common shares outstanding 525.0 521.7 524.4 521.0 Shares issuable pursuant to tandem options 4.6 10.3 5.6 10.7 Shares notionally purchased from proceeds of tandem options (3.6) (7.0) (4.4) (7.5) ------------------------------------------------------- Weighted-average number of diluted common shares outstanding 526.0 525.0 525.6 524.2 =======================================================
In calculating the weighted-average number of diluted common shares outstanding for the three and nine months ended September 30, 2010, we excluded 15,496,237 and 16,074,998 tandem options, respectively, because their exercise price was greater than the average common share market price in the period. In calculating the weighted-average number of diluted common shares outstanding for the three and nine months ended September 30, 2009, we excluded 13,077,285 and 13,236,034 tandem options, respectively, because their exercise price was greater than the average common share market price in the period. During the periods presented, outstanding tandem options were the only potential dilutive instruments. 23 17. COMMITMENTS, CONTINGENCIES AND GUARANTEES As described in Note 15 to the Audited Consolidated Financial Statements included in our 2009 Form 10-K, there are a number of lawsuits and claims pending, the ultimate results of which cannot be ascertained at this time. We record costs as they are incurred or become determinable. We believe the resolution of these matters would not have a material adverse effect on our liquidity, consolidated financial position or results of operations. 18. CASH FLOWS (A) CHARGES AND CREDITS TO INCOME NOT INVOLVING CASH
Three Months Nine Months Ended September 30 Ended September 30 2010 2009 2010 2009 -------------------------------------------------------------------------------------------------------------------------------- Depreciation, Depletion, Amortization and Impairment 477 329 1,234 1,087 Stock-Based Compensation (3) (19) (44) 23 Recovery of Future Income Taxes (234) (81) (423) (390) Net Loss on Dispositions 259 - 179 - Non-cash Items Included in Discontinued Operations (583) 29 (540) 86 Change in Fair Value of Crude Oil Put Options 3 23 18 218 Foreign Exchange 1 (117) 2 (154) Other (22) 10 7 17 ------------------------------------------------------- Total (102) 174 433 887 =======================================================
(B) CHANGES IN NON-CASH WORKING CAPITAL
Three Months Nine Months Ended September 30 Ended September 30 2010 2009 2010 2009 -------------------------------------------------------------------------------------------------------------------------------- Accounts Receivable 240 212 6 39 Inventories and Supplies (88) (13) (12) (142) Other Current Assets (32) (24) 46 (12) Accounts Payable and Accrued Liabilities (5) (68) 350 251 Other Current Liabilities (8) 20 (10) 16 ------------------------------------------------------- Total 107 127 380 152 ======================================================= Relating to: Operating Activities 212 113 410 193 Investing Activities (105) 14 (30) (41) ------------------------------------------------------- Total 107 127 380 152 =======================================================
(C) OTHER CASH FLOW INFORMATION
Three Months Nine Months Ended September 30 Ended September 30 2010 2009 2010 2009 -------------------------------------------------------------------------------------------------------------------------------- Interest Paid 103 70 293 248 Income Taxes Paid 376 179 626 247 -------------------------------------------------------
Cash flow from other operating activities includes cash outflows related to geological and geophysical expenditures of $31 million for the three months ended September 30, 2010 (2009 - $16 million) and $60 million for the nine months ended September 30, 2010 (2009 - $59 million). 24 19. OPERATING SEGMENTS AND RELATED INFORMATION Nexen is involved in activities relating to Oil and Gas, Energy Marketing and Chemicals in various geographic locations as described in Note 20 to the Audited Consolidated Financial Statements included in our 2009 Form 10-K. THREE MONTHS ENDED SEPTEMBER 30, 2010
Energy Corporate Oil and Gas Marketing Chemicals and Other Total ------------------------------------------------------------------------------------------------------------------------------------ United United Other Kingdom Canada(1) Syncrude States Yemen Countries(2) ------------------------------------------------------------ Net Sales 753 117 130 98 179 13 8 118 - 1,416 Marketing and Other 5 25 2 - 4 - 104 13 (15)(3) 138 ------------------------------------------------------------------------------------------------------ Total Revenues 758 142 132 98 183 13 112 131 (15) 1,554 Less: Expenses Operating 84 112 74 23 38 1 8 80 - 420 Depreciation, Depletion, Amortization and Impairment 212 67 12 127 29 3 4 13 10 477 Transportation and Other 1 56 5 - 2 1 62 12 3 142 General and Administrative 5 15 1 17 2 7 19 8 58 132 Exploration 11 7 - 18 - 20(4) - - - 56 Interest - - - - - - - 4 77 81 Net Loss on Dispositions - - - - - - 259 - - 259 ------------------------------------------------------------------------------------------------------ Income (Loss) from Continuing Operations before Income Taxes 445 (115) 40 (87) 112 (19) (240) 14 (163) (13) Less: Provision for (Recovery Of) Income Taxes 223 (28) 10 (31) 39 (17) (94) 4 (70) 36 Less: Non-Controlling Interests - - - - - - - 4 - 4 Add: Net Income from Discontinued Operations - 564 - - - - 26 - - 590 ------------------------------------------------------------------------------------------------------ NET INCOME (LOSS) 222 477 30 (56) 73 (2) (120) 6 (93) 537 ====================================================================================================== IDENTIFIABLE ASSETS 4,912 7,915(5) 1,302 1,675 207 1,344(6) 2,247(7) 771 1,858 22,231 ====================================================================================================== Capital Expenditures ------------------------------------------------------------------------------------------------------ EXPLORATION & DEVELOPMENT 187 169 28 28 13 129 9 19 10 592 ====================================================================================================== Property, Plant and Equipment Cost 6,530 8,600 1,531 3,993 2,453 1,267 234 1,244 397 26,249 Less: Accumulated DD&A 3,170 827 301 2,713 2,367 100 70 592 274 10,414 ------------------------------------------------------------------------------------------------------ NET BOOK VALUE 3,360 7,773(5) 1,230 1,280 86 1,167(6) 164 652 123 15,835 ======================================================================================================
(1) Includes results of operations from conventional, oilsands, shale gas and CBM. (2) Includes results of operations from producing activities in Colombia. (3) Includes interest income of $1 million, foreign exchange losses of $13 million and a decrease in the fair value of crude oil put options of $3 million. (4) Includes exploration activities primarily in Nigeria, Norway and Colombia. (5) Includes PP&E costs of $6,133 million related to our insitu oil sands projects (Long Lake and future phases). (6) Includes PP&E costs of $1,119 million related to Nigeria. (7) Approximately 82% of Marketing's identifiable assets are accounts receivable and inventories. 25 THREE MONTHS ENDED SEPTEMBER 30, 2009
Energy Corporate Oil and Gas Marketing Chemicals and Other Total ------------------------------------------------------------------------------------------------------------------------------------ United United Other Kingdom Canada Syncrude States Yemen Countries(1) ------------------------------------------------------------ Net Sales 478 29 137 74 176 16 9 115 - 1,034 Marketing and Other 5 (6) - - 3 6 188 29 71(2) 296 ------------------------------------------------------------------------------------------------------ Total Revenues 483 23 137 74 179 22 197 144 71 1,330 Less: Expenses Operating 71 18 62 23 49 2 5 67 - 297 Depreciation, Depletion, Amortization and Impairment 162 30 13 67 19 2 14 12 10 329 Transportation and Other 3 3 5 2 7 - 141 13 6 180 General and Administrative (3) 8 11 - 13 4 5 19 9 39 108 Exploration 7 24 - 40 - 18(4) - - - 89 Interest - - - - - - - 2 82 84 ------------------------------------------------------------------------------------------------------ Income (Loss) from Continuing Operations before Income Taxes 232 (63) 57 (71) 100 (5) 18 41 (66) 243 Less: Provision for (Recovery of) Income Taxes 102 (15) 14 (30) 35 (5) 8 9 (9) 109 Less: Non-Controlling Interests - - - - - - - 12 - 12 Add: Net Income from Discontinued Operations - - - - - - - - - - ------------------------------------------------------------------------------------------------------ NET INCOME (LOSS) 130 (48) 43 (41) 65 - 10 20 (57) 122 ====================================================================================================== IDENTIFIABLE ASSETS 5,157 7,756(5) 1,244 1,880 241 976 3,114(6) 704 1,997 23,069 ====================================================================================================== Capital Expenditures ------------------------------------------------------------------------------------------------------ EXPLORATION & DEVELOPMENT 165 177 17 77 11 139 9 53 7 655 ====================================================================================================== Property, Plant and Equipment Cost 6,165 9,558 1,424 3,957 2,516 782 250 1,086 356 26,094 Less: Accumulated DD&A 2,396 1,955 264 2,507 2,369 97 78 552 234 10,452 ------------------------------------------------------------------------------------------------------ NET BOOK VALUE 3,769 7,603(5) 1,160 1,450 147 685 172 534 122 15,642 ======================================================================================================
(1) Includes results of operations from producing activities in Colombia. (2) Includes interest income of $1 million, foreign exchange gains of $93 million and a decrease in the fair value of crude oil put options of $23 million. (3) Includes recovery of stock-based compensation expense of $5 million. (4) Includes exploration activities primarily in Norway, Nigeria and Colombia. (5) Includes PP&E costs of $5,946 million related to our insitu oil sands projects (Long Lake and future phases). (6) Approximately 80% of Marketing's identifiable assets are accounts receivable and inventories. 26 NINE MONTHS ENDED SEPTEMBER 30, 2010
Energy Corporate Oil and Gas Marketing Chemicals and Other Total ------------------------------------------------------------------------------------------------------------------------------------ United United Other Kingdom Canada(1) Syncrude States Yemen Countries(2) ------------------------------------------------------------ Net Sales 2,243 353 416 310 518 42 29 336 - 4,247 Marketing and Other 14 63 4 1 12 - 282 13 (16)(3) 373 ------------------------------------------------------------------------------------------------------ Total Revenues 2,257 416 420 311 530 42 311 349 (16) 4,620 Less: Expenses Operating 237 327 212 70 115 4 25 228 - 1,218 Depreciation, Depletion, Amortization and Impairment 578 192 39 250 88 7 14 36 30 1,234 Transportation and Other 4 147 16 2 8 1 274 38 11 501 General and Administrative (4) 18 29 1 41 2 18 51 25 131 316 Exploration 42 20 - 47 - 90 (5) - - - 199 Interest - - - - - - - 7 231 238 Net Loss on Dispositions - (80) - - - - 259 - - 179 ------------------------------------------------------------------------------------------------------ Income (Loss) from Continuing Operations before Income Taxes 1,378 (219) 152 (99) 317 (78) (312) 15 (419) 735 Less: Provision for (Recovery of) Income Taxes 689 (55) 38 (35) 111 (70) (122) 4 (190) 370 Less: Non-Controlling Interests - - - - - - - 4 - 4 Add: Net Income from Discontinued Operations - 590 - - - - 26 - - 616 ------------------------------------------------------------------------------------------------------ NET INCOME (LOSS) 689 426 114 (64) 206 (8) (164) 7 (229) 977 ====================================================================================================== IDENTIFIABLE ASSETS 4,912 7,915(6) 1,302 1,675 207 1,344(7) 2,247(8) 771 1,858 22,231 ====================================================================================================== Capital Expenditures ------------------------------------------------------------------------------------------------------ EXPLORATION & DEVELOPMENT 460 662 71 156 40 404 25 121 26 1,965 ====================================================================================================== Property, Plant and Equipment Cost 6,530 8,600 1,531 3,993 2,453 1,267 234 1,244 397 26,249 Less: Accumulated DD&A 3,170 827 301 2,713 2,367 100 70 592 274 10,414 ------------------------------------------------------------------------------------------------------ NET BOOK VALUE 3,360 7,773(6) 1,230 1,280 86 1,167(7) 164 652 123 15,835 ======================================================================================================
(1) Includes results of operations from conventional, oilsands, shale gas and CBM. (2) Includes results of operations from producing activities in Colombia. (3) Includes interest income of $6 million, foreign exchange losses of $7 million, decrease in the fair value of crude oil put options of $18 million and other gains of $3 million. (4) Includes recovery of stock-based compensation expense of $34 million. (5) Includes exploration activities primarily in Norway and Colombia. (6) Includes PP&E costs of $6,133 million related to our insitu oil sands projects (Long Lake and future phases). (7) Includes PP&E costs of $1,119 million related to Nigeria. (8) Approximately 82% of Marketing's identifiable assets are accounts receivable and inventories. 27 NINE MONTHS ENDED SEPTEMBER 30, 2009
Energy Corporate Oil and Gas Marketing Chemicals and Other Total ------------------------------------------------------------------------------------------------------------------------------------ United United Other Kingdom Canada Syncrude States Yemen Countries(1) ------------------------------------------------------------ Net Sales 1,574 112 320 225 513 55 29 348 - 3,176 Marketing and Other 13 2 1 - 10 6 676 44 (117)(2) 635 ------------------------------------------------------------------------------------------------------ Total Revenues 1,587 114 321 225 523 61 705 392 (117) 3,811 Less: Expenses Operating 175 51 205 73 145 6 21 196 - 872 Depreciation, Depletion, Amortization and Impairment 537 91 33 215 92 11 21 53 34 1,087 Transportation and Other 14 7 17 18 25 - 469 37 19 606 General and Administrative (3) 15 41 1 51 5 29 68 34 119 363 Exploration 26 53 - 87 - 53(4) - - - 219 Interest - - - - - - - 6 220 226 ------------------------------------------------------------------------------------------------------ Income (Loss) from Continuing Operations before Income Taxes 820 (129) 65 (219) 256 (38) 126 66 (509) 438 Less: Provision for (Recovery of) Income Taxes 358 (32) 16 (81) 89 (29) 52 15 (264) 124 Less: Non-Controlling Interests - - - - - - - 17 - 17 Add: Net Loss from Discontinued Operations - (20) - - - - - - - (20) ------------------------------------------------------------------------------------------------------ NET INCOME (LOSS) 462 (117) 49 (138) 167 (9) 74 34 (245) 277 ====================================================================================================== IDENTIFIABLE ASSETS 5,157 7,756(5) 1,244 1,880 241 976 3,114(6) 704 1,997 23,069 ====================================================================================================== Capital Expenditures Exploration & Development 500 708 56 217 62 378 20 161 17 2,119 Proved Property Acquisitions - 755 - - - - - - - 755 ------------------------------------------------------------------------------------------------------ TOTAL 500 1,463 56 217 62 378 20 161 17 2,874 ====================================================================================================== Property, Plant and Equipment Cost 6,165 9,558 1,424 3,957 2,516 782 250 1,086 356 26,094 Less: Accumulated DD&A 2,396 1,955 264 2,507 2,369 97 78 552 234 10,452 ------------------------------------------------------------------------------------------------------ NET BOOK VALUE 3,769 7,603(5) 1,160 1,450 147 685 172 534 122 15,642 ======================================================================================================
(1) Includes results of operations from producing activities in Colombia. (2) Includes interest income of $4 million, foreign exchange gains of $112 million, decrease in the fair value of crude oil put options of $218 million and other losses of $15 million. (3) Includes stock-based compensation expense of $51 million. (4) Includes exploration activities primarily in Norway, Nigeria and Colombia. (5) Includes PP&E costs of $5,946 million related to our insitu oil sands projects (Long Lake and future phases). (6) Approximately 80% of Marketing's identifiable assets are accounts receivable and inventories. 28 20. DIFFERENCES BETWEEN CANADIAN AND US GENERALLY ACCEPTED ACCOUNTING PRINCIPLES The Unaudited Consolidated Financial Statements have been prepared in accordance with Canadian GAAP. The US GAAP Unaudited Consolidated Statements and summaries of differences from Canadian GAAP are as follows:
UNAUDITED CONSOLIDATED STATEMENT OF INCOME - US GAAP FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30 Three Months Nine Months Ended September 30 Ended September 30 (Cdn$ millions, except per share amounts) 2010 2009 2010 2009 --------------------------------------------------------------------------------------------------------------------------------- REVENUES AND OTHER INCOME Net Sales 1,416 1,034 4,247 3,176 Marketing and Other (v); (vi) 129 344 432 702 -------------------------------------------------------- 1,545 1,378 4,679 3,878 -------------------------------------------------------- EXPENSES Operating 420 297 1,218 872 Depreciation, Depletion, Amortization and Impairment 477 329 1,234 1,087 Transportation and Other (v) 142 186 501 604 General and Administrative (iv) 123 84 295 377 Exploration 56 89 199 219 Interest 81 84 238 226 Net Loss on Dispositions 259 - 179 - -------------------------------------------------------- 1,558 1,069 3,864 3,385 -------------------------------------------------------- INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE PROVISION FOR INCOME TAXES (13) 309 815 493 -------------------------------------------------------- PROVISION FOR (RECOVERY OF) INCOME TAXES Current 270 190 793 514 Deferred (iv); (vi) (235) (68) (399) (377) -------------------------------------------------------- 35 122 394 137 -------------------------------------------------------- NET INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE NON-CONTROLLING INTERESTS (48) 187 421 356 Less: Net Income Attributable to Canexus Non-Controlling Interests (4) (12) (4) (17) -------------------------------------------------------- NET INCOME (LOSS) FROM CONTINUING OPERATIONS ATTRIBUTABLE TO NEXEN INC. (52) 175 417 339 Net Income (Loss) from Discontinued Operations 590 - 616 (20) -------------------------------------------------------- NET INCOME ATTRIBUTABLE TO NEXEN INC. - US GAAP(1) 538 175 1,033 319 ======================================================== EARNINGS (LOSS) PER COMMON SHARE FROM CONTINUING OPERATIONS ($/share) Basic (0.10) 0.34 0.79 0.65 ======================================================== Diluted (0.10) 0.33 0.79 0.65 ======================================================== EARNINGS PER COMMON SHARE ($/share) Basic 1.03 0.34 1.97 0.61 ======================================================== Diluted 1.03 0.33 1.97 0.61 ========================================================
(1) RECONCILIATION OF CANADIAN AND US GAAP NET INCOME Three Months Nine Months Ended September 30 Ended September 30 2010 2009 2010 2009 --------------------------------------------------------------------------------------------------------------------------------- Net Income Attributable to Nexen Inc - Canadian GAAP 537 122 977 277 Impact of US Principles, Net of Income Taxes: Stock-based Compensation (iv) 7 17 16 (11) Inventory Valuation (vi) (6) 29 40 46 Deferred Taxes (vii) - 7 - 7 -------------------------------------------------------- Net Income Attributable to Nexen Inc - US GAAP 538 175 1,033 319 ========================================================
29
UNAUDITED CONSOLIDATED BALANCE SHEET - US GAAP September 30 December 31 (Cdn$ millions, except share amounts) 2010 2009 -------------------------------------------------------------------------------------------------------------------------------- ASSETS CURRENT ASSETS Cash and Cash Equivalents 1,210 1,700 Restricted Cash 35 198 Accounts Receivable 2,305 2,788 Inventories and Supplies (vi) 533 610 Other 142 185 ---------------------------------------- Total Current Assets 4,225 5,481 ---------------------------------------- PROPERTY, PLANT AND EQUIPMENT Net of Accumulated Depreciation, Depletion, Amortization and Impairment of $10,807 (December 31, 2009 - $11,200) (i); (iii) 15,786 15,443 GOODWILL 316 339 DEFERRED INCOME TAX ASSETS 1,608 1,148 DEFERRED CHARGES AND OTHER ASSETS 236 370 ---------------------------------------- TOTAL ASSETS 22,171 22,781 ======================================== LIABILITIES CURRENT LIABILITIES Accounts Payable and Accrued Liabilities (iv) 3,015 3,131 Accrued Interest Payable 78 89 Dividends Payable 26 26 ---------------------------------------- Total Current Liabilities 3,119 3,246 ---------------------------------------- LONG-TERM DEBT 5,678 7,251 DEFERRED INCOME TAX LIABILITIES (i); (ii); (iv); (vi); (vii) 3,060 2,720 ASSET RETIREMENT OBLIGATIONS 1,007 1,018 DEFERRED CREDITS AND OTHER LIABILITIES (ii) 871 1,126 EQUITY Nexen Inc. Shareholders' Equity Common Shares, no par value Authorized: Unlimited Outstanding: 2010 - 525,032,386 shares 2009 - 522,915,843 shares 1,097 1,049 Contributed Surplus - 1 Retained Earnings (i); (iii); (iv); (vi); (vii) 7,530 6,575 Accumulated Other Comprehensive Loss (ii) (275) (269) ---------------------------------------- Total Nexen Inc. Shareholders' Equity 8,352 7,356 Canexus Non-Controlling Interests 84 64 ---------------------------------------- TOTAL EQUITY 8,436 7,420 ---------------------------------------- COMMITMENTS, CONTINGENCIES AND GUARANTEES TOTAL LIABILITIES AND EQUITY 22,171 22,781 ========================================
30 UNAUDITED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME - US GAAP FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30
Three Months Nine Months Ended September 30 Ended September 30 2010 2009 2010 2009 ------------------------------------------------------------------------------------------------------------------------------- Net Income Attributable to Nexen Inc. - US GAAP 538 175 1,033 319 Other Comprehensive Loss, Net of Income Taxes: Foreign Currency Translation Adjustment (7) (26) (6) (49) ------------------------------------------------------ Comprehensive Income Attributable to Nexen Inc. - US GAAP 531 149 1,027 270 ======================================================
UNAUDITED CONSOLIDATED STATEMENT OF ACCUMULATED OTHER COMPREHENSIVE LOSS - US GAAP September 30 December 31 2010 2009 --------------------------------------------------------------------------------------------------------------------------------- Foreign Currency Translation Adjustment (196) (190) Unamortized Defined Benefit Pension Plan Costs (ii) (79) (79) ------------------------------------------ Accumulated Other Comprehensive Loss (275) (269) ==========================================
There are currently no differences between our Canadian and US GAAP Cash Flow and as such we have not presented a separate US GAAP Cash Flow Statement. NOTES TO THE UNAUDITED CONSOLIDATED US GAAP FINANCIAL STATEMENTS: i. Under Canadian GAAP, we deferred certain development costs to PP&E. Under US principles, these costs have been included in operating expenses in prior years. As a result, PP&E is lower under US GAAP by $30 million (December 31, 2009 - $30 million) and deferred income tax liabilities are lower by $11 million (December 31, 2009 - $11 million). ii. US GAAP requires the recognition of the over-funded and under-funded status of a defined benefit plan on the balance sheet as an asset or liability. At September 30, 2010 and December 31, 2009, the unfunded amount of our defined benefit pension plans that was not included in the pension liability under Canadian GAAP was $105 million. This amount has been included in deferred credits and other liabilities and $79 million, net of income taxes, has been included in Accumulated Other Comprehensive Loss (AOCL). iii. On January 1, 2003, we adopted ACCOUNTING FOR ASSET RETIREMENT OBLIGATIONS for US GAAP reporting purposes. We adopted the equivalent Canadian standard for asset retirement obligations on January 1, 2004. These standards are consistent except for the adoption date which results in our PP&E under US GAAP being lower by $19 million. iv. Under Canadian principles, we record obligations for liability-based stock compensation plans using the intrinsic-value method of accounting. Under US principles, obligations for liability-based stock compensation plans are recorded using the fair-value method of accounting. In addition, under Canadian principles, we retroactively adopted EIC-162 which required the accelerated recognition of stock-based compensation expense for all stock-based awards made to our retired and retirement-eligible employees. However, US GAAP required the accelerated recognition of stock-based compensation expense for such employees for awards granted on or after January 1, 2006. As a result under US GAAP: o general and administrative (G&A) expense is lower by $9 million and $21 million, ($7 million and $16 million, net of income taxes), for the three and nine months ended September 30, 2010, (2009 - lower by $24 million and higher by $14 million, respectively, ($17 million and $11 million, net of income taxes)); and o accounts payable and accrued liabilities are higher by $72 million as at September 30, 2010 (December 31, 2009 - $93 million) and deferred income tax liabilities are $21 million lower (December 31, 2009 - $26 million). v. Under US GAAP, asset disposition gains and losses are included with transportation and other expense. For the three and nine months ended September 30, 2010 there were no gains or losses reclassified from marketing and other income to transportation and other expense (losses of $6 million and gains of $2 million, respectively were reclassified for the three and nine months ended September 30, 2009). 31 vi. Under Canadian GAAP, we carry our commodity inventory held for trading purposes at fair value, less any costs to sell. Under US GAAP, we are required to carry this inventory at the lower of cost or net realizable value. As a result: o marketing and other income is lower by $9 million and higher by $59 million (lower by $6 million and higher by $40 million, net of income taxes) for the three and nine months ended September 30, 2010 (2009 - higher by $42 million and $69 million ($29 million and $46 million, net of income taxes)); and o inventories are lower by $11 million as at September 30, 2010 (December 31, 2009 - lower by $70 million) and deferred income tax liabilities are $4 million lower (December 31, 2009 - lower by $23 million). vii. Under US GAAP, we are required to apply FIN48 ACCOUNTING FOR UNCERTAINTY IN INCOME TAXES regarding accounting and disclosure for uncertain tax positions. As at September 30, 2010, the total amount of our unrecognized tax benefit was approximately $296 million, all of which, if recognized, would affect our effective tax rate. To the extent interest and penalties may be assessed by taxing authorities on any underpayment of income tax, such amounts have been accrued and are classified as a component of income taxes in the Unaudited Consolidated Statement of Income. As at September 30, 2010, the total amount of interest and penalties related to uncertain tax positions recognized in deferred income tax liabilities in the US GAAP - Unaudited Consolidated Balance Sheet was approximately $9 million. We had no interest or penalties included in the US GAAP - Unaudited Consolidated Statement of Income for the three and nine months ended September 30, 2010. Our income tax filings are subject to audit by taxation authorities and as at September 30, 2010 the following tax years remained subject to examination, (i) Canada - 1985 to date (ii) United Kingdom - 2008 to date and (iii) United States - 2005 to date. We do not anticipate any material changes to the unrecognized tax benefits previously disclosed within the next 12 months. NEW ACCOUNTING PRONOUNCEMENTS - US GAAP In January 2010, the Financial Accounting Standards Board issued guidance to improve financial instrument fair value measurement disclosures. The guidance requires entities to describe transfers between the three levels of the fair value hierarchy and present items separately in the level 3 reconciliation. This guidance is consistent with fair value measurement disclosures adopted for Canadian GAAP in 2009. Adoption of this guidance did not have an impact on our results of operations or financial position. 32 ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (MD&A) THE FOLLOWING SHOULD BE READ IN CONJUNCTION WITH THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS INCLUDED IN THIS REPORT. THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS HAVE BEEN PREPARED IN ACCORDANCE WITH GENERALLY ACCEPTED ACCOUNTING PRINCIPLES (GAAP) IN CANADA. THE IMPACT OF THE SIGNIFICANT DIFFERENCES BETWEEN CANADIAN AND UNITED STATES (US) ACCOUNTING PRINCIPLES ON THE FINANCIAL STATEMENTS IS DISCLOSED IN NOTE 20 TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS. THE DATE OF THIS DISCUSSION IS OCTOBER 27, 2010. UNLESS OTHERWISE NOTED, TABULAR AMOUNTS ARE IN MILLIONS OF CANADIAN DOLLARS. THE DISCUSSION AND ANALYSIS OF OUR OIL AND GAS ACTIVITIES WITH RESPECT TO OIL AND GAS VOLUMES, RESERVES AND RELATED PERFORMANCE MEASURES IS PRESENTED ON A WORKING-INTEREST, BEFORE-ROYALTIES BASIS. WE MEASURE OUR PERFORMANCE IN THIS MANNER CONSISTENT WITH OTHER CANADIAN OIL AND GAS COMPANIES. WHERE APPROPRIATE, INFORMATION ON A NET, AFTER-ROYALTIES BASIS IS ALSO PRESENTED. NOTE: CANADIAN INVESTORS SHOULD READ THE SPECIAL NOTE TO CANADIAN INVESTORS ON PAGE 97 OF OUR 2009 FORM 10-K WHICH HIGHLIGHTS DIFFERENCES BETWEEN OUR RESERVES ESTIMATES AND RELATED DISCLOSURES THAT ARE OTHERWISE REQUIRED BY CANADIAN REGULATORY AUTHORITIES. WE MAKE ESTIMATES AND ASSUMPTIONS THAT AFFECT THE REPORTED AMOUNTS OF OUR ASSETS AND LIABILITIES AND THE DISCLOSURE OF CONTINGENT ASSETS AND LIABILITIES AT THE DATE OF THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS AND OUR REVENUES AND EXPENSES DURING THE REPORTED PERIOD. OUR MANAGEMENT REVIEWS THESE ESTIMATES, INCLUDING THOSE RELATED TO ACCRUALS, LITIGATION, ENVIRONMENTAL AND ASSET RETIREMENT OBLIGATIONS, INCOME TAXES, FAIR VALUES OF DERIVATIVE CONTRACT ASSETS AND LIABILITIES AND THE DETERMINATION OF PROVED RESERVES ON AN ONGOING BASIS. CHANGES IN FACTS AND CIRCUMSTANCES MAY RESULT IN REVISED ESTIMATES AND ACTUAL RESULTS MAY DIFFER FROM THESE ESTIMATES. EXECUTIVE SUMMARY OF THIRD QUARTER RESULTS
Three Months Nine Months Ended September 30 Ended September 30 (Cdn$ millions, except as indicated) 2010 2009 2010 2009 ------------------------------------------------------------------------------------------------------------------------------------ Production before Royalties (mboe/d) 239 214 246 235 Production after Royalties (mboe/d) 213 184 218 206 Nexen's Average Realized Oil and Gas Price (Cdn$/boe) 68.21 63.00 68.60 56.89 Cash Flow from Operating Activities 668 461 1,976 1,359 Net Income Attributable to Nexen Inc. 537 122 977 277 Earnings per Common Share, Basic ($/share) 1.02 0.23 1.86 0.53 Capital Investment 592 655 1,965 2,119 Acquisition of Additional Interest in Long Lake - - - 755 Net Debt (1) 4,468 5,532 4,468 5,532 ----------------------------------------------------
(1) Net debt is a non-GAAP measure and is defined as long-term debt and short-term borrowings less cash and cash equivalents. Net income increased significantly from a year ago as we completed the sale of our Canadian heavy oil properties during the quarter. Production for the quarter increased 12% from last year despite the sale of our heavy oil properties, temporary downtime at Scott/Telford and Syncrude, and natural declines in Yemen. Commodity prices were higher than last year and we realized an average oil and gas price of $68.21/boe, an increase of 8% over last year. The impact of higher benchmark crude oil prices is partially mitigated by the weaker US dollar. At our Long Lake oil sands project, bitumen production volumes have doubled since the beginning of the year to over 31,500 bbls/d (gross). In the Horn River, we completed fracing the eight shale gas wells we drilled earlier this year allowing us to start production here earlier than scheduled. Investment during the quarter focused on progressing our major development project at Usan to first oil production in 2012, fracing and completing our shale gas eight well pad at Horn River and on exploration activities in the North Sea. During the quarter, we commenced activities on the West Rochelle and Polecat prospects in the UK North Sea. At West Rochelle, we successfully confirmed gas and oil in the reservoir and are sidetracking the well to further delineate the discovery. In the Gulf of Mexico, the drilling moratorium has been lifted, and we plan to move forward with the drilling of our exploration prospects at Kakuna and Angel Fire and with the appraisal of our Appomattox discovery. 33 During the quarter, we completed the sale of our Canadian heavy oil properties. The sale generated cash proceeds of $939 million, after closing adjustments, and we realized a pre-tax gain of approximately $781 million. The heavy oil properties produced approximately 15,000 boe/d during the second quarter and had proved reserves of 39 million boe at December 31, 2009. We also completed the sale of our Energy Marketing natural gas operations, generating proceeds of approximately $11 million and a non-cash loss of $259 million. With these sales, we achieved our target of generating proceeds of approximately $1.0 billion from non-core asset sales. We now expect to generate approximately $1.5 billion of proceeds once we complete our disposition program, including the sale of our Canexus investment expected in the next year. We used the proceeds from the disposition of our Canadian heavy oil properties to pay down our short-term borrowings and term credit facilities. Our available liquidity is approximately $4.4 billion and includes cash on hand of approximately $1.2 billion and undrawn lines of credit of approximately $3.2 billion. Debt maturities in the next five years can be repaid from current cash on hand and cash flow from operating activities. The average term-to-maturity of our long-term debt is approximately 21 years. We believe our significant liquidity, combined with strong operating cash netbacks, provides us with the financial flexibility to carry out our investment programs. CAPITAL INVESTMENT Our strategy is to build a sustainable energy company focused in three areas: conventional exploration and development, oil sands, and unconventional gas. We are committed to growing long-term value for our shareholders responsibly and are advancing our plans to achieve this as described below. We are currently investing primarily in: o ramping up Long Lake safely and reliably; o progressing construction of our Usan project and continuing to explore our acreage, offshore Nigeria; o advancing area development plans for our Golden Eagle area in the UK North Sea; o appraising exploration successes at Appomattox and Knotty Head in the Gulf of Mexico; o targeting a number of exploration prospects, primarily in the North Sea and Gulf of Mexico; and o advancing our Horn River shale gas play and building our shale gas land position in northeast British Columbia. Details of our capital programs are set out below: Three Months Ended Nine Months Ended September 30 September 30 2010 2010 -------------------------------------------------------------------------------- Oil and Gas United Kingdom 187 460 Canada 120 505 Synthetic (mainly Long Lake Phase 1) 49 157 Syncrude 28 71 United States 28 156 Yemen 13 40 Nigeria 118 336 Other Countries 11 68 --------------------------------------- 554 1,793 Chemicals 19 121 Energy Marketing, Corporate and Other 19 51 --------------------------------------- Total Capital 592 1,965 ======================================= UNITED KINGDOM - NORTH SEA During the quarter, we commenced activities on the West Rochelle and Polecat prospects and are evaluating drilling results. At West Rochelle, we have successfully confirmed gas and oil pay in the reservoir and are sidetracking the well to further delineate the discovery. This well is a potential tieback to Scott. Polecat is a potential tieback to Buzzard. We plan to drill the Bluebell prospect before year end, a potential southerly extension of the Buzzard field. Elsewhere in the North Sea, we continue to expand our acreage position in the Golden Eagle area, which includes our discoveries at Golden Eagle, Hobby and Pink. We intend to drill an exploration well here early next year. Golden Eagle area development supports standalone facilities and is economic with oil prices significantly lower than they are currently. We are advancing area development plans, doing initial engineering and preparing cost 34 estimates for potential sanctioning in 2011. We have a 34% interest in both Golden Eagle and Hobby, a 46% interest in Pink, and operate all three. In late October, the UK Government announced that, subject to completion of the award process, we were the successful applicant for 10 licenses covering 18 blocks in the UK North Sea 26th Offshore Oil and Gas Licensing Round. Most of these blocks are near our existing acreage and infrastructure. CANADA - HORN RIVER SHALE GAS During the quarter, we completed a 144 frac program on our eight-well pad in the Horn River at a pace of 3.5 fracs per day with a 100% frac success rate. Earlier this year, we completed our drilling campaign here at an average rate of under 25 days per well. Compared to our previous program, these wells were drilled in 35% fewer days and were 80% longer. We recently started production testing these wells and expect to reach peak production rates of 50 mmcf/d this winter. We plan to follow up this successful program with a nine well pad that would start drilling this winter. The wells would be fraced and completed next summer with first production in the fourth quarter of 2011. This allows us to advance our Horn River play while we progress our plans for an 18-well pad to be drilled next winter with first production expected in late 2012. We have approximately 90,000 acres at Dilly Creek in the Horn River basin. Following our success at a June land sale, we now have over 300,000 acres of shale gas lands in the Horn River, Cordova and Liard basins in northeast British Columbia. SYNTHETIC At Long Lake, bitumen production to feed the upgrader continues to ramp up following the completion of the turnaround last fall. We have improved steam reliability and are continuously optimizing our wells. The resulting improvements in well capability have enabled us to increase our steam injection to 165,000 bbls/d and gross bitumen production volumes to over 31,500 bbls/d, our highest rate yet. 78 of 91 well pairs are now on production and steam is circulating in an additional six pairs. These circulating wells are expected to be converted to production in the coming months. The table below shows gross monthly bitumen production volumes for the current year. We own a 65% operated interest in the Long Lake project. Gross Bitumen Month Volumes (bbls/d) -------------------------------------------------------------------------------- January 2010 16,300 February 2010 17,700 March 2010 21,900 April 2010 24,400 May 2010 23,600 June 2010 26,900 July 2010 28,700 August 2010 26,500 September 2010 24,000 October 2010 - Month to date 30,000 As we provide consistent steam to the reservoir, we are focusing on optimizing steam injection and individual well performance. To support increased well productivity, we have converted 65 wells from gas lift to electric submersible pumping (ESPs). The remainder will be converted in due course. This provides us with more flexibility to optimize steam injection and grow bitumen production. In addition, we have taken the opportunity to upsize the ESPs in our best producers. We have recently completed our first set of acid stimulations on eight producing wells. These optimizations allow us to draw more fluids into the wells, increasing bitumen production. Third quarter production volumes were impacted as we shut in these wells to complete these activities. Following the turnaround late last year, production volumes returned to pre-turnaround rates in December. Since that time, we have made the following progress: O Steam injection has increased from 100,000 bbls/d to 165,000 bbls/d; O Bitumen production has doubled to over 31,500 bbls/d (gross); O The number of wells producing at an average of design rates has increased from 10 to 24; and O The all-in steam-to-oil ratio (SOR) has decreased from approximately 6 to 5.2. This includes 51 wells that are still in the steam circulation stage or early in their growth cycle. As these wells transition to SAGD production, the increase in production rates should result in a continued decrease in SOR. 35 As previously announced, we have a number of initiatives underway to increase bitumen volumes. These include: O Bringing on the remaining 13 wells to SAGD production; O Completing our ESP conversion program; O Optimizing producing wells; and O Developing two additional well pads and engineering two more once-through steam generators, which will add 10 to 15% to our steam capacity. We expect these to be available over the next 18 to 24 months. We are committed to the development of our significant oil sands resource and plan to develop the next phase in two smaller SAGD stages of about 40,000 bbls/d each with upgrading available after ramp up. UNITED STATES - GULF OF MEXICO The drilling moratorium in the Gulf of Mexico was lifted earlier this month and we are working to recommence exploration and appraisal drilling. The moratorium had no impact on our shelf and deep-water production and rig standby costs are expected to be minimal. Throughout the duration of the moratorium, the first of our deepwater rigs was used by a co-contractor and on the second rig, we are close to completing discussions with the rig provider regarding our contract. In the first quarter, we made a significant discovery in the deep-water at Appomattox, located in Mississippi Canyon blocks 391 and 392. Drilling activities resulted in an oil discovery following an exploration well and two appraisal sidetracks. We plan to further appraise this discovery once permits are received. Appomattox is the third discovery in the area following earlier discoveries at Shiloh and Vicksburg. Our drilling plans also include further appraisal at Vicksburg which is located six miles east of Appomattox and has the potential to be co-developed. We have a 25% interest in Vicksburg and a 20% interest in Appomattox and Shiloh. Shell Offshore Inc. operates all three discoveries. Our plans to drill two additional exploration wells this year (Kakuna and Angel Fire) with our two new deep-water drilling rigs were delayed by the drilling moratorium. We have submitted applications for permits to drill these two prospects. OFFSHORE WEST AFRICA Development of the Usan field is progressing well with first production on-track for 2012. The development includes a floating production, storage and offloading (FPSO) vessel with the ability to process 180,000 bbls/d (36,000 bbls/d net to us) and store up to two million barrels of oil. Major topside modules have been lifted onto the FPSO deck and the FPSO unit is 88% complete. We have a 20% interest in exploration and development on this block and Total E&P Nigeria Limited is the operator. We continue to explore offshore West Africa and previously announced a successful exploration well at Owowo in the southern portion of Oil Prospecting License (OPL) 223. We have an 18% interest in this discovery. 36 FINANCIAL RESULTS CHANGE IN NET INCOME
2010 VS 2009 -------------------------------------------------- Three Months Nine Months Ended September 30 Ended September 30 ------------------------------------------------------------------------------------------------------------------------------ NET INCOME AT SEPTEMBER 30, 2009(1) 122 277 ------------------------------------------------- Favorable (unfavorable) variances(2): Realized Commodity Prices Crude Oil 56 578 Natural Gas 21 33 ------------------------------------------------- Total Price Variance 77 611 Production Volumes, After Royalties Crude Oil 210 276 Natural Gas 5 55 Changes in Crude Oil Inventory For Sale 38 110 ------------------------------------------------- Total Volume Variance 253 441 Oil and Gas Operating Expense (88) (286) Oil and Gas Depreciation, Depletion, Amortization and Impairment (129) (117) Exploration Expense 33 20 Energy Marketing Revenue, Net (9) (203) Chemicals Contribution (18) (46) General and Administrative Expense (3) (20) 54 Interest Expense 3 (12) Current Income Taxes (80) (279) Future Income Taxes (44) (180) Change in Fair Value of Crude Oil Put Options 20 201 Canadian Heavy Oil Disposition Gain 781 781 Natural Gas Energy Marketing Disposition Loss (259) (259) Other (105) (26) ------------------------------------------------- NET INCOME AT SEPTEMBER 30, 2010 (1) 537 977 =================================================
(1) Includes results of discontinued operations (See Note 15 of our Unaudited Consolidated Financial Statements). (2) All amounts are presented before provision for income taxes. (3) Includes stock-based compensation expense. Significant variances in net income are explained further in the following sections. 37 OIL & GAS PRODUCTION (BEFORE ROYALTIES)(1)
Three Months Nine Months Ended September 30 Ended September 30 2010 2009 2010 2009 ---------------------------------------------------------------------------------------------------------------------------- Crude Oil and Liquids (mbbls/d) United Kingdom 106.3 73.7 103.4 91.6 Yemen 41.6 48.7 41.8 51.5 Syncrude 19.1 22.5 20.7 19.1 Long Lake Bitumen 16.7 5.5 15.0 7.6 United States 9.9 9.5 9.9 10.6 Canada (2) 2.9 14.2 10.0 14.9 Other Countries 2.0 2.6 2.1 3.9 --------------------------------------------------- 198.5 176.7 202.9 199.2 --------------------------------------------------- Natural Gas (mmcf/d) United Kingdom 27 17 36 18 United States 102 63 100 58 Canada (2) 113 143 124 139 --------------------------------------------------- 242 223 260 215 --------------------------------------------------- Total Production (mboe/d) 239 214 246 235 ===================================================
PRODUCTION (AFTER ROYALTIES)
Three Months Nine Months Ended September 30 Ended September 30 2010 2009 2010 2009 ---------------------------------------------------------------------------------------------------------------------------- Crude Oil and Liquids (mbbls/d) United Kingdom 106.3 73.7 103.4 91.6 Yemen 23.5 28.3 22.9 31.0 Syncrude 17.9 20.0 19.1 17.6 Long Lake Bitumen 16.0 5.5 14.3 7.6 United States 8.9 8.5 8.9 9.6 Canada (2) 2.3 10.9 7.7 11.6 Other Countries 1.9 2.4 2.0 3.6 --------------------------------------------------- 176.8 149.3 178.3 172.6 --------------------------------------------------- Natural Gas (mmcf/d) United Kingdom 27 17 36 17 United States 89 56 86 52 Canada (2) 104 137 114 130 --------------------------------------------------- 220 210 236 199 --------------------------------------------------- Total Production (mboe/d) 213 184 218 206 ===================================================
(1) We have presented production volumes before royalties as we measure our performance on this basis consistent with other Canadian oil and gas companies. (2) Includes the following production from discontinued operations. See Note 15 of our Unaudited Consolidated Financial Statements.
Three Months Nine Months Ended September 30 Ended September 30 2010 2009 2010 2009 ---------------------------------------------------------------------------------------------------------------------------- Before Royalties Crude Oil and NGLs (mbbls/d) 2.9 14.2 10.0 14.9 Natural Gas (mmcf/d) 2.2 13.2 8.3 13.7 After Royalties Crude Oil and NGLs (mbbls/d) 2.3 10.9 7.7 11.6 Natural Gas (mmcf/d) 2.1 11.2 7.2 11.6 ---------------------------------------------------
38 HIGHER VOLUMES INCREASED NET INCOME FOR THE QUARTER BY $253 MILLION Production before royalties increased 12% and production after royalties increased 16%, compared to the third quarter last year. Higher production in the North Sea, Long Lake and the Gulf of Mexico was partially offset by the sale of our Canadian heavy oil properties in July and natural field declines in Yemen. Compared to the second quarter, production before royalties increased 1% after taking into account the sale of our heavy oil assets. Temporarily lower production at Syncrude was offset by stronger production rates in the North Sea. The following table summarizes our production volume changes since last quarter:
Before After (mboe/d) Royalties Royalties ---------------------------------------------------------------------------------------------------------------------------- Production, second quarter 2010 248 218 Production related to disposed properties (1) (12) (9) ------------------------------------------ 236 209 Production changes from continuing operations: United Kingdom 6 6 Yemen 1 1 United States 1 1 Canada (1) (1) Syncrude (4) (3) ------------------------------------------ Production, third quarter 2010 239 213 ==========================================
(1) Heavy oil properties were sold in late July 2010. Production volumes discussed in this section represent before-royalties volumes, net to our working interest. UNITED KINGDOM Production volumes in the UK North Sea increased 45% from last year and 6% from the previous quarter as higher volumes at Buzzard and Ettrick were partially offset by downtime at Scott/Telford. Buzzard production averaged 84,200 boe/d for the quarter. This was 18% higher than the second quarter when production from Buzzard was impacted by a three-week shutdown to install the fourth platform topsides and complete repairs to the main separator unit. Production was 42% higher than the third quarter of 2009 when Buzzard was shut-in for four weeks of downtime to install the jackets for the fourth platform and prepare the tie-ins. We are progressing towards the start up of the new platform and fourth quarter Buzzard volumes are expected to be approximately 70 to 90% of normal. Production is expected to return to full rates around year end. Production from our Ettrick field increased 33% during the quarter and produced 18,900 boe/d net to us, compared to 14,200 boe/d in the second quarter. Production at Scott/Telford averaged 5,700 boe/d compared to 17,800 boe/d the previous quarter. A valve failure on the third-party owned Forties pipeline system shut in production on the Scott platform for eight weeks during the quarter. We used some of this time to complete our planned maintenance activities while the operator repaired the valve. Production restarted in September and has since returned at rates of about 20,000 boe/d, net to us. CANADA During the quarter, we sold our heavy oil properties in Canada that produced approximately 15,000 boe/d in the second quarter. Production on our remaining natural gas properties in Canada was 5% and 10% lower than the previous quarter and last year, respectively, as a result of natural declines and reduced capital investment. At our shale gas project in the Dilly Creek area of the Horn River basin in north-east British Columbia, we successfully completed a 144 frac program on our eight-well pad. We recently started production testing these wells and expect to reach peak production rates of 50 mmcf/d this winter. LONG LAKE At Long Lake, quarterly bitumen production volumes were 26,000 boe/d gross (17,000 boe/d net to us), compared to 25,000 boe/d gross (16,000 boe/d net) in the previous quarter. Production ramp up over the summer was impacted by downtime related to SAGD well optimization activities (such as ESP upsizes and acid stimulations) and temporary steam interruptions. These interruptions were caused by unplanned upgrader downtime related to the air separation unit and power outages caused by a lightning strike. We are back on-stream and are producing over 31,500 bbls/d (gross) of bitumen. 39 SYNCRUDE Our share of Syncrude production fell 18% from the prior quarter and 15% from last year, averaging 19,100 boe/d for the quarter. The decrease was a result of maintenance work on the sour water treatment unit and vacuum distillation unit, and the scheduled turnaround of Coker 8-1 late in the quarter. This turnaround is now complete and no further downtime is scheduled at Syncrude this year. UNITED STATES Production in the Gulf of Mexico averaged 26,900 boe/d, 4% higher than the previous quarter. The increased volumes were primarily due to strong performance at Longhorn and Wrigley. Compared to the same period last year, production increased 35% primarily as a result of the Longhorn development which came on-stream in late 2009. Production at Longhorn averaged 8,600 boe/d in the quarter. The drilling moratorium in the Gulf of Mexico had no significant impact on our shelf and deep-water production during the quarter and we continue to expect our Gulf of Mexico production for the year to average between 20,000 and 28,000 boe/d before royalties (17,000 and 25,000 boe/d after royalties). YEMEN Yemen production averaged 41,600 boe/d for the period, up slightly from the previous quarter, but down 15% from last year. The production decline is consistent with expectations as the fields mature and development drilling is reduced as we approach the scheduled end of the contract term. During the quarter, we drilled two development wells with a further three expected to be drilled by the end of the year. Production declines in Yemen are expected to continue as we focus on maximizing recovery of the remaining reserves. We are continuing discussions with the Yemen government and our partners on a contract extension for the Masila block beyond the current expiry date of December 17, 2011. There is no assurance that this extension will be received. OTHER COUNTRIES Our share of production from the Guando field in Colombia averaged 2,000 boe/d for the quarter. This was 5% lower than the previous quarter and 23% lower than the same period last year due to natural field declines. 40
COMMODITY PRICES Three Months Nine Months Ended September 30 Ended September 30 2010 2009 2010 2009 -------------------------------------------------------------------------------------------------------------------------------- CRUDE OIL West Texas Intermediate (WTI) (US$/bbl) 76.20 68.30 77.65 57.00 Dated Brent (Brent) (US$/bbl) 76.86 68.27 77.13 57.16 ------------------------------------------------------- Benchmark Differentials (1) (US$/bbl) Heavy Oil 15.89 10.39 13.17 9.10 Mars 1.53 1.90 1.70 1.17 Masila (0.63) (0.54) 0.11 0.15 Realized Prices from Producing Assets (Cdn$/bbl) United Kingdom 77.45 73.15 77.29 63.78 Yemen 79.33 76.31 80.07 65.22 Syncrude 78.27 74.54 79.78 67.26 Long Lake Synthetic 70.64 - 74.44 - United States 73.72 72.27 75.46 61.60 Canada 61.56 59.88 61.39 50.10 Other Countries 75.93 70.49 76.58 55.89 Corporate Average (Cdn$/bbl) 77.03 72.95 77.09 63.15 ------------------------------------------------------- NATURAL GAS New York Mercantile Exchange (US$/mmbtu) 4.24 3.44 4.54 3.91 AECO (Cdn$/mcf) 3.52 2.87 4.09 3.89 ------------------------------------------------------- Realized Prices from Producing Assets (Cdn$/mcf) United Kingdom 5.11 2.64 4.89 4.04 United States 4.70 3.56 5.27 4.59 Canada 3.43 2.85 4.08 3.67 Corporate Average (Cdn$/mcf) 4.18 3.04 4.67 3.96 ------------------------------------------------------- NEXEN'S AVERAGE REALIZED OIL AND GAS PRICE (Cdn$/boe) 68.21 63.00 68.60 56.89 ------------------------------------------------------- AVERAGE FOREIGN EXCHANGE RATE - Canadian to US Dollar 0.9624 0.9108 0.9656 0.8546 -------------------------------------------------------
(1) These differentials are a discount/(premium) to WTI. HIGHER COMMODITY PRICES INCREASED QUARTERLY NET INCOME BY $77 MILLION WTI and Brent prices were down 2% from the previous quarter. Compared to last year, benchmark crude prices are 12% higher but the impact of the increase was mitigated by a stronger Canadian dollar. Our realized oil price averaged $77.03/bbl for the quarter, 6% higher than last year and 1% higher than the second quarter. Natural gas prices fell from the previous quarter with NYMEX averaging US$4.24/mmbtu and AECO averaging $3.52/mcf, a decrease of 2% and 4% respectively. This reduced our realized gas price by 5%. Compared to the same period last year, our realized gas price is 38% higher as NYMEX and AECO increased 23%. The Canadian dollar strengthened against the US dollar since last year. This strengthening reduced net sales by approximately $74 million, as our realized crude oil and natural gas prices were $4.36/bbl and $0.24/mcf lower, respectively. However, the weaker US dollar lowers our US dollar denominated costs and debt when translated to Canadian dollars. 41 CRUDE OIL REFERENCE PRICES WTI traded between US$70/bbl and US$80/bbl during the quarter as prices responded to shifting oil demand expectations. Robust economic growth in developing countries accounts for almost 90% of 2010 global oil demand growth of 2 million bbls/day. In contrast, developed countries burdened with high debt levels are suffering from tepid economic growth and numerous market fears including: double-dip recession, deflation, sovereign debt default in Europe, and fiscal policy shifts from stimulus to austerity. The forward crude oil price curve remains in contango which indicates that market expectations are that higher prices will be required in the future to ration supply. Globally there are two economies. Developing countries are experiencing strong economic growth while developed countries are recovering slowly and tentatively from a deep financially-led recession. The US Federal Reserve flagged deflation as a significant concern and signaled that it will, if necessary, engage in quantitative easing to stem this risk. Because oil is a US-dollar priced global commodity, quantitative easing would apply upward pressure to crude oil prices, as well as encourage financial investments in oil as investors use oil to hedge their exposure to a declining US dollar. Global onshore crude oil and refined product inventory levels are at five year highs which is an impediment to higher crude oil prices and a contributor to the contango structure in the forward price curve. However, oil inventories have been drawn down as the developing economies continue to increase their oil demand. In October, crude prices remained above US$80/bbl as the US dollar continued to weaken. OPEC recently reiterated that they believe no change to current production levels is required. CRUDE OIL DIFFERENTIALS In Canada, heavy oil differentials were volatile. Enbridge pipeline shutdowns widened heavy oil differentials as heavy crude takeaway capacity was restricted. With the resumption of the Enbridge pipelines in late September, the heavy differential has narrowed to more normal levels. Brent traded at a premium to WTI for most of the quarter. Historically, Brent has traded at a discount to WTI because surplus North Sea crude oil was exported to the US market. With declining North Sea crude production and exports, this differential can shift to positive or negative depending on short term supply and demand factors. The differential favoured Brent in the third quarter because high inventory levels at Cushing depressed the price of WTI and North Sea maintenance reduced supply available for export. Mars is a medium sour crude that is priced to compete with comparable international import alternatives. The Mars differential narrowed relative to WTI mainly due to downward pressure on WTI from inventory builds on land at Cushing. The Masila price strengthened relative to WTI following the movement in the WTI/Brent differential and the relative strength of Asian demand. NATURAL GAS REFERENCE PRICES NYMEX natural gas prices remained low due to warm weather reducing demand while supply remained strong. Producers continue to drill despite low prices. Gas prices are expected to remain low until inventory levels are reduced by lower supply or higher demand from economic growth or weather-related events. 42 OPERATING EXPENSES(1)
Three Months Nine Months Ended September 30 Ended September 30 (Cdn$/boe) 2010 2009 2010 2009 ---------------------------------------------------------------------------------------------------------------------------- Operating expenses based on our production before royalties (2) Conventional Oil and Gas 9.19 11.56 9.18 9.41 Long Lake Synthetic (3) 85.20 - 101.73 - Syncrude 41.49 29.50 37.46 39.26 Average Oil and Gas 15.72 13.60 15.44 11.97 --------------------------------------------------- Operating expenses based on our production after royalties Conventional Oil and Gas 10.50 13.45 10.54 10.90 Long Lake Synthetic (3) 89.19 - 106.46 - Syncrude 44.20 33.19 40.53 42.67 Average Oil and Gas 17.78 15.76 17.56 13.79 ---------------------------------------------------
(1) Includes results of discontinued operations (See Note 15 of our Unaudited Consolidated Financial Statements). (2) Operating expenses per boe are our total oil and gas operating costs divided by our working interest production before royalties. We use production before royalties to monitor our performance consistent with other Canadian oil and gas companies. (3) Excludes activities related to third-party bitumen purchased, processed and sold. HIGHER OPERATING EXPENSES REDUCED QUARTERLY NET INCOME BY $88 MILLION Operating costs increased $88 million or 35% from the third quarter of 2009 primarily due to costs associated with our Long Lake project. As of January 1, 2010, we ceased capitalizing our Long Lake start-up costs. As Long Lake operating costs are mainly fixed, increasing volumes improved our per unit operating cost about 10% from the previous quarter. When fully ramped up, we expect Long Lake operating costs to be about $25 to $30/bbl. Our production mix has changed as a result of the sale of our heavy oil properties in Canada, higher production at Buzzard and Ettrick, and natural declines in Yemen. This reduced our average oil and gas operating cost by $0.93/boe. The stronger Canadian dollar reduced our corporate average by $0.42/boe as operating costs of our international and US assets are denominated in US dollars. In Canada, the sale of our heavy oil properties reduced operating costs by $19 million from the same period last year. In the UK North Sea, Buzzard operating costs were slightly higher than the previous year. Elsewhere in the UK North Sea, higher production volumes reduced the average unit cost at Ettrick, while at Scott, the per unit cost increased as a result of downtime experienced in the quarter. Combined, these items reduced our corporate average by $0.20/boe. In Yemen, operating costs were down 20% due to reduced maintenance costs. This decreased our corporate average cost by $0.43/boe. In the US Gulf of Mexico, higher production was only partially offset by increased operating costs, reducing our corporate average by $0.02/boe. At Syncrude, maintenance costs associated with the Coker 8-1 turnaround and lower production volumes increased our corporate average by $0.98/boe. 43 DEPRECIATION, DEPLETION, AMORTIZATION AND IMPAIRMENT (DD&A)(1)
Three Months Nine Months Ended September 30 Ended September 30 (Cdn$/boe) 2010 2009 2010 2009 ---------------------------------------------------------------------------------------------------------------------------- DD&A based on our production before royalties (2) Conventional Oil and Gas 18.70 19.14 17.61 18.71 Long Lake Synthetic 23.90 - 22.48 - Syncrude 7.09 6.12 6.93 6.29 Average Oil and Gas 18.05 17.66 16.94 17.64 --------------------------------------------------- DD&A based on our production after royalties Conventional Oil and Gas 21.38 22.26 20.21 21.67 Long Lake Synthetic 24.89 - 23.37 - Syncrude 7.56 6.88 7.49 6.83 Average Oil and Gas 20.39 20.46 19.24 20.32 ---------------------------------------------------
(1) Includes results of discontinued operations (See Note 15 of our Unaudited Consolidated Financial Statements). (2) DD&A per boe is our DD&A for oil and gas operations divided by our working interest production before royalties. We use production before royalties to monitor our performance consistent with other Canadian oil and gas companies. HIGHER OIL AND GAS DD&A DECREASED NET INCOME FOR THE QUARTER BY $129 MILLION Our DD&A expense in the third quarter of 2010 includes non-cash impairment charges of $61 million at three small natural gas properties in the US Gulf of Mexico. Low natural gas prices made these mature shelf properties uneconomic and as a result, the properties are being shut down and the carrying value was written down to their estimated fair value. DD&A costs increased $68 million or $0.39/boe, excluding the impact of the impairment. The change in our production mix increased our corporate average DD&A rate by $0.97/boe. Depletion rates at Ettrick, Longhorn and Long Lake are higher than our corporate average. Depletion at Long Lake increased our consolidated average cost by $1.22/boe. Additionally, the stronger Canadian dollar reduced our corporate average by $0.75/boe as depletion of our international and US assets is denominated in US dollars. Canada increased our corporate average DD&A rate by $0.29/boe, despite a decrease in our DD&A expense of $28 million due to the disposition of the heavy oil properties. This increase was driven by higher DD&A rates at our CBM and natural gas properties, where low natural gas prices at the end of 2009 reduced reserves. At Buzzard, successful drilling last year enabled us to recognize additional proved reserves at the end of 2009, which lowered the field depletion rate and reduced our corporate average by $0.72/boe. The remainder of our UK fields decreased our corporate average by $0.25/boe, primarily driven by increased reserves at Telford and reduced capital costs at Ettrick. Depletion rates in Yemen increased our corporate average $0.53/boe. As the fields mature and production declines, our capital is focused on recovering the remaining reserves, thereby increasing our depletion rates. In the US Gulf of Mexico, positive reserve revisions at the end of 2009, combined with lower estimates for future abandonment costs, reduced our corporate average depletion rate by $0.95/boe. 44
EXPLORATION EXPENSE(1) Three Months Nine Months Ended September 30 Ended September 30 2010 2009 2010 2009 -------------------------------------------------------------------------------------------------------------------------------- Seismic 31 16 60 59 Unsuccessful Drilling - 51 42 78 Other 25 22 97 82 ------------------------------------------------------- Total Exploration Expense 56 89 199 219 =======================================================
(1) Includes results of discontinued operations (See Note 15 of our Unaudited Consolidated Financial Statements). LOWER EXPLORATION EXPENSE INCREASED NET INCOME FOR THE QUARTER BY $33 MILLION In the Gulf of Mexico, we continue to evaluate our discovery at Appomattox where we have drilled an exploratory well and two appraisal sidetracks. The drilling moratorium in the Gulf of Mexico was lifted earlier in October. Once drilling in the Gulf of Mexico resumes, we plan to conduct further appraisals here. Appomattox is the third discovery in the area following previous successful drilling at Shiloh and Vicksburg. Our drilling plans also include further appraisal at Vicksburg which is located six miles east of Appomattox and has the potential to be co-developed. We have a 25% interest in Vicksburg and a 20% interest in Appomattox and Shiloh, with Shell Offshore Inc. operating all three. In the UK, we are currently engaged in an active exploration and development program. This includes: o advancing area development options for the Golden Eagle area, including doing initial engineering and preparing cost estimates for potential sanctioning in 2011. The Golden Eagle area includes our 34% operated interest in Golden Eagle and Hobby and our 46% operated interest in Pink; o completing a successful appraisal well at Blackbird, six kilometres south of our Ettrick field, early in the quarter. Blackbird is a potential tie-back to the Ettrick FPSO. We have an 80% operated interest at Blackbird; o evaluating drilling results from our Polecat prospect. Polecat is a potential tie back to Buzzard; and o reviewing the results from our appraisal well at West Rochelle, where we have a 44% non-operated interest, as we successfully confirmed gas and oil pay there. We are sidetracking the well to further delineate the discovery. This well is a potential tieback to Scott. Exploration expense decreased 37% or $33 million, as we did not incur any unsuccessful drilling costs during the quarter. In the third quarter of 2009, we expensed drilling costs related to our Antietam well in the Gulf of Mexico and our CBM properties in Canada. This decrease was partially offset as we incurred higher expenditures in the UK North Sea and US Gulf of Mexico to acquire additional seismic data for further exploration. 45
ENERGY MARKETING Three Months Nine Months Ended September 30 Ended September 30 2010 2009 2010 2009 -------------------------------------------------------------------------------------------------------------------------------- Physical Sales (1) 7,213 9,711 25,517 29,719 Physical Purchases (1) (7,112) (9,605) (25,099) (29,011) Net Financial Transactions (2) (20) 117 (48) (111) Change in Fair Market Value of Inventory 1 (35) (88) 79 ------------------------------------------------------- Marketing Revenue 82 188 282 676 Transportation Expense (64) (145) (275) (473) Other - 4 4 8 ------------------------------------------------------- NET MARKETING REVENUE 18 47 11 211 ======================================================= CONTRIBUTION TO NET MARKETING REVENUE BY REGION North America 18 33 4 192 International - 14 7 19 ------------------------------------------------------- NET MARKETING REVENUE 18 47 11 211 DD&A (4) (14) (14) (21) General and Administrative (19) (19) (51) (68) Other 24 4 1 4 Natural Gas Energy Marketing Disposition Loss (259) - (259) - ======================================================= MARKETING CONTRIBUTION TO INCOME BEFORE INCOME TAXES (240) 18 (312) 126 ======================================================= NORTH AMERICA NATURAL GAS Physical Sales Volumes (3) (bcf/d) 1.8 4.9 3.3 4.9 Transportation Capacity (bcf/d) 0.1 1.5 0.1 1.5 Storage Capacity (bcf) 0.9 32.5 0.9 32.5 Financial Volumes (4) (bcf/d) 0.2 8.7 3.0 11.4 CRUDE OIL Physical Sales Volumes (3) (mbbls/d) 797 802 795 837 Storage Capacity (mmbbls) 2.7 3.1 2.7 3.1 Financial Volumes (4) (mbbls/d) 830 699 793 796 POWER Physical Sales Volumes (3) (GWh/d) 9 14 9 9 Generation Capacity (MW) 95 95 95 95 INTERNATIONAL CRUDE OIL Physical Sales Volumes (3) (mbbls/d) 59 93 81 97 Financial Volumes (4) (mbbls/d) 736 681 921 765 VALUE-AT-RISK (5) Quarter-end 8 13 8 13 High 9 15 15 24 Low 4 11 4 11 Average 7 12 10 16 -------------------------------------------------------
(1) Marketing's physical sales, physical purchases and net financial transactions are reported within marketing revenue as detailed in the notes to the unaudited consolidated financial statements. (2) Net financial transactions include all gains and losses on financial derivatives and the unrealized portion of gains and losses on physical purchase and sale contracts. (3) Excludes inter-segment transactions. Physical volumes represent amounts delivered during the quarter. (4) Financial volumes represent amounts largely acquired to economically hedge physical transactions during the quarter. (5) Refer to our Consolidated Audited Financial Statements for the year ended December 31, 2009 for a description of Value-at-Risk. 46 LOWER CONTRIBUTION FROM ENERGY MARKETING DECREASED NET INCOME BY $9 MILLION During the quarter, we completed the sale of our North America natural gas marketing operations. Net proceeds of $11 million were received and a non-cash loss of $259 million was recognized, primarily related to the transfer of long-term physical transportation commitments. The value of these transportation commitments decreased substantially largely because of the increase in gas supply in North America reducing the need for transport services. Subsequent to the sale, we retained a small natural gas operation to support our upstream production and other third party producers in western Canada. Overall, third quarter revenue was lower than last year due to lower income from our North American gas and UK gas and power operations, which were sold during the year. Revenue from our global crude oil marketing business was relatively consistent compared to last year. In the third quarter, our crude oil marketing business captured gains on shifting differentials, blending opportunities and physical and inventory management. These same strategies generated gains in the third quarter of 2009. Compared to the second quarter of 2010, third quarter results were improved from reduced losses from North American natural gas. This was offset by losses on a strengthening Canadian dollar compared to gains on a weakening dollar in the second quarter. COMPOSITION OF NET MARKETING REVENUE
Three Months Nine Months Ended September 30 Ended September 30 2010 2009 2010 2009 -------------------------------------------------------------------------------------------------------------------------------- Trading Activities (Physical and Related Financial) 16 43 3 201 Other Activities 2 4 8 10 ------------------------------------------------------- Total Net Marketing Revenue 18 47 11 211 =======================================================
TRADING ACTIVITIES In our energy marketing group, we enter into contracts to purchase and sell crude oil, as well as 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 fair values are included with accounts receivable or payable and are classified as long-term or short-term based on anticipated settlement date. OTHER ACTIVITIES We earn income from our power generation facilities at Balzac and Soderglen. FAIR VALUE OF DERIVATIVE CONTRACTS Our processes for estimating and classifying the fair value of our derivative contracts are consistent with those in place at December 31, 2009. At September 30, 2010, the fair value of our derivative contracts in our energy marketing trading activities was $17 million. 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 (13) (14) - - (27) Level 2 - Based on Other Observable Pricing Inputs (1) - - - - - Level 3 - Based on Unobservable Pricing Inputs 33 11 - - 44 ------------------------------------------------------------------ Total 20 (3) - - 17 ==================================================================
(1) As at September 30, 2010, Level 2 unrealized gains and losses net to nil. 47 CHANGES IN FAIR VALUE OF DERIVATIVE CONTRACTS Total ------------------------------------------------------------------------------ Fair Value at December 31, 2009 23 Change in Fair Value of Contracts 61 Net Losses (Gains) on Contracts Sold (39) Net Losses (Gains) on Contracts Closed (28) Changes in Valuation Techniques and Assumptions (1) - ----------- Fair Value at September 30, 2010 17 =========== (1) Our valuation methodology has been applied consistently in each period. The fair values of our derivative contracts will be realized over time as the related contracts settle. Until then, the value of certain contracts will vary with forward commodity prices and price differentials. The average term of our derivative contracts is approximately 1.3 years. CHEMICALS LOWER CHEMICALS CONTRIBUTION DECREASED NET INCOME BY $18 MILLION Chlorate revenues in North America increased slightly over last year as higher volumes were offset by a decline in prices due to a stronger Canadian dollar. In Brazil, higher volumes and prices combined to increase revenues by 17%. Chlor-alkali revenue in North America was consistent with the same period last year. In late June, the technology conversion project (TCP) at the North Vancouver chlor-alkali facility successfully started up and the facilities continued to ramp up during the third quarter. We expect that TCP will contribute $35 to $40 million in incremental operating cash flow annually, through lower operating costs and volume expansion. In Brazil, chlor-alkali revenues were comparable to the prior year. Operating costs were higher during the quarter primarily as a result of expenditures incurred to source product for chlor-alkali customers during the start up and ramp up of the TCP. Chemicals net income was lower by $14 million during the quarter as a result of reduced foreign exchange gains. CORPORATE EXPENSES GENERAL AND ADMINISTRATIVE (G&A)(1)
Three Months Nine Months Ended September 30 Ended September 30 2010 2009 2010 2009 -------------------------------------------------------------------------------------------------------------------------------- General and Administrative Expense before Stock-Based Compensation 134 118 360 329 Stock-Based Compensation (2) (1) (5) (34) 51 ------------------------------------------------------- Total General and Administrative Expense 133 113 326 380 =======================================================
(1) Includes results of discontinued operations (See Note 15 of our Unaudited Consolidated Financial Statements). (2) Includes cash and non-cash expenses related to our tandem option and stock appreciation rights plans. HIGHER G&A COSTS DECREASED NET INCOME BY $20 MILLION During the quarter, G&A expenditures before stock-based compensation increased 14% from the same period last year. The increase was primarily as a result of costs related to our non-core asset disposition program. Fluctuations in our share price create volatility in our net income as we account for stock-based compensation using the intrinsic-value method. During the quarter, our share price decreased marginally and we reversed approximately $3 million of non-cash stock-based compensation that was recognized in prior periods. 48 INTEREST
Three Months Nine Months Ended September 30 Ended September 30 2010 2009 2010 2009 -------------------------------------------------------------------------------------------------------------------------------- Interest 105 100 302 286 Less: Capitalized (24) (16) (64) (60) ------------------------------------------------------- Net Interest Expense 81 84 238 226 ======================================================= Effective Interest Rate 6.3% 5.2% 5.7% 4.9% -------------------------------------------------------
LOWER NET INTEREST EXPENSE INCREASED NET INCOME BY $3 MILLION Interest costs before capitalized interest increased $12 million as a result of higher interest on fixed-term debt issued in July 2009 and additional costs related to the Canexus facilities. This was partially offset by a stronger Canadian dollar which decreased our US-denominated interest expense by $7 million. Capitalized interest was $8 million higher than 2009. We continue to capitalize interest on the Usan project, offshore West Africa, the fourth platform at Buzzard and future phases of Long Lake. INCOME TAXES(1)
Three Months Nine Months Ended September 30 Ended September 30 2010 2009 2010 2009 -------------------------------------------------------------------------------------------------------------------------------- Current 270 190 793 514 Future (37) (81) (217) (397) ------------------------------------------------------- Total Provision for Income Taxes 233 109 576 117 =======================================================
(1) Includes results of discontinued operations (See Note 15 of our Unaudited Consolidated Financial Statements). HIGHER TAXES REDUCED NET INCOME BY $124 MILLION Our total provision for income taxes increased during the quarter primarily as a result of the net gains on our non-core asset disposition program. Additionally, our operating results improved relative to last year, resulting in higher tax expense. Our future tax expense in 2009 includes the impact of the decrease in the value of our crude oil put options and the effect of reduced Canadian tax rates. Our income tax provision includes current taxes in the United Kingdom, Yemen, Norway, Colombia and the United States. OTHER
Three Months Nine Months Ended September 30 Ended September 30 2010 2009 2010 2009 -------------------------------------------------------------------------------------------------------------------------------- Decrease in Fair Value of Crude Oil Put Options (3) (23) (18) (218) -------------------------------------------------------
During the quarter, we purchased put options on 20,000 bbls/d of our 2011 crude oil production. These options establish a WTI floor price of US$50/bbl and provide a base level of price protection without limiting our upside to higher prices. The options settle monthly and are recorded at fair value throughout their term. As a result, changes in forward crude oil prices create gains or losses on these options at each period end. The put options were purchased for $6 million and are carried at fair value. As at September 30, 2010 the fair value of the options was approximately $5 million and we recorded a fair value loss of $1 million for the quarter. Subsequent to September 30, 2010, we purchased additional crude oil put options on 50,000 bbls/d of our 2011 crude oil production for $17 million. These options establish a WTI floor price of approximately US$56/bbl. In the fourth quarter of 2009, we purchased put options on 90,000 bbls/d of our 2010 crude oil production, establishing a WTI floor price of US$50/bbl. Options on 60,000 bbls/d settle monthly, while the remaining options settle annually. These options are recorded at fair value throughout their term. The put options were purchased for $39 million and are carried at fair value. As at September 30, 2010, higher forward crude oil prices reduced the fair value of the options to nil. 49 LIQUIDITY AND CAPITAL RESOURCES CAPITAL STRUCTURE September 30 December 31 2010 2009 ------------------------------------------------------------------------------- NET DEBT (1) Bank Debt 282 1,803 Public Senior Notes 4,936 4,982 --------------------------------- Total Senior Debt 5,218 6,785 Subordinated Debt 460 466 --------------------------------- Total Debt 5,678 7,251 Less: Cash and Cash Equivalents (1,210) (1,700) --------------------------------- TOTAL NET DEBT 4,468 5,551 ================================= EQUITY AT HISTORIC ISSUE COST 8,606 7,646 ================================= (1) Includes all of our borrowings and is calculated as long-term debt and short-term borrowings less cash and cash equivalents. NET DEBT Our net debt levels are directly related to our operating cash flows and capital expenditure activities. Changes in net debt are related to:
Three Months Ended Nine Months Ended September 30 September 30 2010 2010 -------------------------------------------------------------------------------------------------------------------------------- Capital Investment (592) (1,965) Cash Flow from Operating Activities (1) 668 1,976 ------------------------------------------------ 76 11 Proceeds on Disposition of Assets 950 1,046 Dividends on Common Shares (26) (78) Issue of Common Shares 9 44 Changes in Restricted Cash Requirements (43) 40 Foreign Exchange Translation of US-dollar Debt and Cash 136 50 Other (99) (30) ------------------------------------------------ Decrease in Net Debt 1,003 1,083 ================================================
(1) Includes changes in non-cash working capital. For the three and nine months ended September 30, 2010, inflows of $212 million and $410 million, respectively, was included. Net debt was reduced by over $1 billion since the end of last year, primarily as a result of proceeds received from our non-core asset dispositions. The proceeds were used to repay our short-term borrowings and drawn term credit facilities. The stronger Canadian dollar also reduced our US-dollar denominated debt when translated into Canadian dollars. Operating cash flows in the oil and gas industry can be volatile as short-term commodity prices are driven by existing supply and demand fundamentals and market volatility. We periodically invest through the lows of the current commodity market to create future growth and value for our shareholders for the long-term. Changes in our non-cash working capital can vary between quarters as our energy marketing net working capital position fluctuates depending on timing of settlement of outstanding positions, the movement in commodity prices and inventory cycles. 50 CHANGE IN WORKING CAPITAL
September 30 December 31 Increase/ 2010 2009 (Decrease) ---------------------------------------------------------------------------------------------------------------------------- Cash and Cash Equivalents 1,210 1,700 (490) Restricted Cash 35 198 (163) Accounts Receivable 2,305 2,788 (483) Inventories and Supplies 544 680 (136) Accounts Payable and Accrued Liabilities (2,943) (3,038) 95 Other 38 70 (32) ------------------------------------------------------ Net Working Capital 1,189 2,398 ==================================
Our working capital has been reduced since year end as we used cash to fund our 2010 capital program and repay outstanding term credit facilities. Timing of cash tax remittances to governments during the year create fluctuations in cash taxes payable between quarters. In addition, our working capital decreased since year end from the sale of our North American natural gas operations, which included transferring derivative contracts, natural gas inventory, transportation and storage commitments and cash margins (restricted cash) to the purchaser. OUTLOOK FOR REMAINDER OF 2010 We expect our 2010 production to range between 230,000 and 280,000 boe/d (200,000 and 250,000 boe/d after royalties). Our future liquidity and ability to fully fund capital requirements generally depend upon operating cash flows, existing working capital, unused committed credit facilities, and our ability to access debt and equity markets. Given the long cycle time of some of our development projects and volatile commodity prices, it is not unusual in any year for capital expenditures to exceed our cash flow. Changes in commodity prices, particularly crude oil as it represents approximately 85% of our current production, can impact our operating cash flows. We use short-term contracts to sell the majority of our oil and gas production, exposing us to short-term price movements. A US$1/bbl change in WTI above US$50/bbl is projected to increase or decrease our cash flow from operating activities, after cash taxes, by approximately $9 million for the remainder of the year. Our exposure to a $0.01 change in the US to Canadian dollar exchange rate is projected to increase or decrease our cash flow by approximately $7 million for the remainder of 2010. While commodity prices can fluctuate significantly in the short term, we believe that over the longer term, commodity prices will continue to remain strong as a result of continued growth in world demand and delays or shortages in supply growth. We believe that our existing liquidity, balance sheet capacity and capital investment flexibility provide us with the ability to fund our ongoing obligations during periods of lower commodity prices. We have incurred approximately 80% of our 2010 planned capital investment program to date. During the quarter, our capital investment was concentrated on i) exploration and appraisal drilling in the UK North Sea; ii) progressing our northeast British Columbia shale gas play; and iii) developing our Usan project offshore Nigeria. We expect our capital investment in the fourth quarter to continue to focus on these projects. At September 30, 2010, our available liquidity is $4.4 billion. This consists of approximately $1.2 billion cash on hand and unsecured term credit facilities of $3.2 billion, which are available until 2014. Our term credit facilities supported $289 million of outstanding letters of credit at the end of the quarter. We also have $466 million of uncommitted, unsecured credit facilities, none of which was drawn and $82 million is being used to support outstanding letters of credit. The average length-to-maturity of our public debt is approximately 21 years. CONTRACTUAL OBLIGATIONS, COMMITMENTS AND GUARANTEES We have assumed various contractual obligations and commitments in the normal course of our operations and financing activities. We included these obligations and commitments in our MD&A in our 2009 Form 10-K. In connection with our natural gas energy marketing disposition, we assigned substantially all of our natural gas transportation and storage contracts to the purchaser, reducing our future commitments by $342 million. We agreed to maintain our parental guarantee to the pipeline provider related to one transportation commitment. We are obligated to perform under the guarantee only if the purchaser does not meet its obligation to the pipeline provider. To guarantee its performance, the purchaser provided us with collateral of US$43 million which is included in accounts payable. We expect to cancel this guarantee in the fourth quarter. 51 There have been no other significant developments since year-end. CONTINGENCIES There are a number of lawsuits and claims pending, the ultimate result of which cannot be ascertained at this time. We record costs as they are incurred or become determinable. We believe the resolution of these matters would not have a material adverse effect on our liquidity, consolidated financial position or results of operations. These matters are described in LEGAL PROCEEDINGS in Item 3 contained in our 2009 Form 10-K. There have been no significant developments since year-end. NEW ACCOUNTING PRONOUNCEMENTS CANADIAN PRONOUNCEMENTS INTERNATIONAL FINANCIAL REPORTING STANDARDS ADOPTION PLAN We are required to adopt International Financial Reporting Standards (IFRS) for our interim and annual financial reporting purposes beginning January 1, 2011. A project team, consisting of dedicated and experienced personnel who have IFRS knowledge, has been set up to manage this transition and to ensure successful implementation within the required timeframe. We provided an update on the status of our project in our 2009 Annual Report on Form 10-K, including a summary of accounting differences between Canadian GAAP and IFRS. During the quarter, work continued on reviewing our opening transitional IFRS differences at January 1, 2010 and reviewing the impact on our 2010 results of operations and financial position. SUMMARY OF ACCOUNTING DIFFERENCES BETWEEN CANADIAN GAAP AND IFRS We determined that the majority of our existing Canadian GAAP oil and gas accounting policies are acceptable under IFRS as we use successful efforts accounting for our oil and gas activities. However, detailed analysis has identified differences, the most significant of which will impact certain aspects of our accounting for property, plant and equipment, asset retirement obligations, accounting for income taxes, and share-based payments on IFRS adoption on January 1, 2010. In addition, IFRS provides for certain one-time mandatory and optional adjustments to our opening IFRS balance sheet. These impacts on our opening IFRS balance sheet are described below. Generally, most of these transitional adjustments will be offset through opening retained earnings on January 1, 2010. PROPERTY, PLANT AND EQUIPMENT Significant components of property, plant and equipment (PP&E) with different useful lives must be accounted for and depreciated separately. Instances of major maintenance, turnarounds or inspections must also be capitalized and depreciated until the next scheduled major maintenance activity. Our current policy is to expense these items unless they result in improvements that increase capacity or extend the useful life. We expect that retrospective application will increase our net PP&E on January 1, 2010. ASSET RETIREMENT OBLIGATIONS There are differences in the calculation methodology for determining asset retirement obligations, the most significant of which is the use of a risk-free rate to discount our obligations under IFRS. Under Canadian GAAP, our obligations were discounted using a credit-adjusted risk-free discount rate. Additionally, liabilities must be re-measured at each balance sheet date using current discount rates under IFRS, whereas under Canadian GAAP, discount rates do not change once the liability is recorded. We expect the transitional impact of these adjustments will increase our accrued asset retirement obligations on January 1, 2010. ACCOUNTING FOR INCOME TAXES IFRS requires us to recognize tax credits related to a one-time tax deduction in the UK in the period in which they occur. Canadian GAAP requires us to defer recognition of the benefit until the assets are recognized in income by way of a sale to a third party or depletion through use. Additionally, in transitioning to IFRS, our deferred tax liability will be impacted by the tax effects resulting from the IFRS changes discussed in this section. SHARE-BASED PAYMENTS We use the intrinsic method to account for our cash-settled stock-based compensation under Canadian GAAP. We will use a fair value model such as Black-Scholes to value our stock-based compensation under IFRS. We expect that the IFRS requirement to value stock-based compensation at fair value each reporting period may result in less volatility in our reported earnings each period. We expect the transitional impact of this adjustment will increase our accrued liabilities on January 1, 2010. 52 ONE TIME ADJUSTMENTS ON TRANSITION TO IFRS IFRS allows certain adjustments to financial information on transition where retrospective restatement would either be onerous or would not provide more useful information. We expect to make one-time transitional adjustments on January 1, 2010 as follows: o PP&E will be decreased to reflect the use of fair value as deemed cost on transition for certain of our assets where the carrying values of the assets are in excess of their fair values. o Defined benefit pension obligations will be increased to reflect previously unrecognized actuarial losses. o Accumulated foreign exchange gains and losses within accumulated other comprehensive income will be reclassed to retained earnings rather than retrospectively restating the balance. At this time, we cannot quantify with certainty the impact that the adoption of IFRS will have on our future results of operations or financial position. We expect that the net impact of adopting IFRS will reduce our shareholders' equity by less than 5% and the impact on our cash flows from operating activities will be immaterial. Additional disclosure of the key elements of our plan and progress on the project will be provided as we move toward the changeover date. We continue to monitor the development of new standards and any changes will be incorporated as required. US PRONOUNCEMENTS In January 2010, the Financial Accounting Standards Board issued guidance to improve fair value measurement disclosures. The guidance requires entities to describe transfers between the three levels of the fair value hierarchy and present items separately in the level 3 reconciliation. This guidance is consistent with fair value measurement disclosures adopted for Canadian GAAP in 2009. Adoption of this guidance did not have an impact on our results of operations or financial position. EQUITY SECURITY REPURCHASES During the quarter, we made no purchases of our equity securities. 53 SUMMARY OF QUARTERLY RESULTS
2008 | 2009 | 2010 ---------|--------------------------------------|---------------------------- (Cdn$ millions, except per share amounts) Dec | Mar Jun Sep Dec | Mar Jun Sep ------------------------------------------------------------------------------------------------------------------------------- Net Sales from Continuing Operations 1,214 1,004 1,138 1,034 1,486 1,432 1,399 1,416 Net Income (Loss) from Continuing Operations (185) 152 23 122 256 172 242 (53) Net Income (Loss) from Discontinued Operations 4 (17) (3) - 3 13 13 590 ----------------------------------------------------------------------------- Net Income (Loss) (181) 135 20 122 259 185 255 537 ============================================================================= Earnings (Loss) Per Common Share from Continuing Operations ($/share) Basic (0.36) 0.28 0.05 0.23 0.49 0.33 0.46 (0.10) Diluted (0.36) 0.28 0.05 0.23 0.48 0.33 0.46 (0.10) Earnings (Loss) Per Common Share ($/share) Basic (0.35) 0.26 0.04 0.23 0.50 0.35 0.49 1.02 Diluted (0.35) 0.26 0.04 0.23 0.49 0.35 0.49 1.02 -----------------------------------------------------------------------------
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS Certain statements in this report, including those appearing in MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS, constitute "forward-looking statements" (within the meaning of the United States PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995, as amended) or "forward-looking information" (within the meaning of applicable Canadian securities legislation). Such statements or information (together "forward-looking statements") are generally identifiable by the forward-looking terminology used such as "ANTICIPATE", "BELIEVE", "INTEND", "PLAN", "EXPECT", "ESTIMATE", "BUDGET", "OUTLOOK", "FORECAST" or other similar words, and include statements relating to or associated with individual wells, regions or projects. Any statements regarding the following are forward-looking statements: o future crude oil, natural gas or chemicals prices; o future production levels; o future capital expenditures, their timing and their allocation to exploration and development activities; o future earnings; o future asset acquisitions or dispositions; o future sources of funding for our capital program; o future debt levels; o availability of committed credit facilities; o possible commerciality; o development plans or capacity expansions; o the expectation that we have the ability to substantially grow production at our oil sands facilities through controlled expansions; o the expectation of achieving the production design rates from our oil sands facilities; o the expectation that our oil sands production facilities continue to develop better and more sustainable practices; o the expectation of cheaper and more technologically advanced operations; o the expected timing and associated production impact of facilities turnarounds and maintenance; o the expectation that we can continue to operate our offshore exploration, development and production facilities safely and profitably; o future ability to execute dispositions of assets or businesses; o future sources of liquidity, cash flows and their uses; o future drilling of new wells; o ultimate recoverability of current and long-term assets; 54 o ultimate recoverability of reserves or resources; o expected finding and development costs; o expected operating costs; o future cost recovery oil revenues from our Yemen operations; o future demand for chemical products; o estimates on a per share basis; o future foreign currency exchange rates; o future expenditures and future allowances relating to environmental matters; o dates by which certain areas will be developed, will come on-stream or reach expected operating capacity; and o changes in any of the foregoing. Statements relating to "reserves" or "resources" are forward-looking statements, as they involve the implied assessment, based on estimates and assumptions, that the reserves and resources described exist in the quantities predicted or estimated, and can be profitably produced in the future. The forward-looking statements are subject to known and unknown risks and uncertainties and other factors which may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Such factors include, among others: o market prices for oil and gas and chemical products; o our ability to explore, develop, produce, upgrade and transport crude oil and natural gas to markets; o ultimate effectiveness of design or design modification to facilities; o the results of exploration and development drilling and related activities; o the cumulative impact of oil sands development on the environment; o the impact of technology on operations and processes and how new complex technology may not perform as expected; o the availability of pipeline and global refining capacity; o risks inherent to the operations of any large, complex refinery units, especially the integration between production operations and an upgrader facility; o availability of third-party bitumen for use in our oil sands production facilities; o labour and material shortages; o risk related to accidents, blowouts and spills in connection with our offshore exploration, development and production activities, particularly our deepwater activities; o direct and indirect risk related to the imposition of moratoriums, suspensions or cancellations of our offshore exploration, development and production operations, particular our deepwater activities; o the impact of severe weather on our offshore exploration, development and production activities, particularly our deepwater activities; o the effectiveness and reliability of our technology in harsh and unpredictable environments; o risks related to the actions of our agents and contractors; o volatility in energy trading markets; o foreign-currency exchange rates; o economic conditions in the countries and regions in which we carry on business; o governmental actions including changes to taxes or royalties, changes in environmental and other laws and regulations including without limitation, those related to our offshore exploration, development and production activities; o renegotiations of contracts; o results of litigation, arbitration or regulatory proceedings; o political uncertainty, including actions by terrorists, insurgent or other groups, or other armed conflict, including conflict between states; and o other factors, many of which are beyond our control. These risks, uncertainties and other factors and their possible impact are discussed more fully in the sections titled RISK FACTORS in Item 1A and QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK and in Item 7A of our 2009 Form 10-K and in Part II, Item 1A of our 2010 second quarter Form 10-Q. 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 our assessment of all information at that time. 55 Although we believe that the expectations conveyed by the forward-looking statements are reasonable based on information available to us on the date such forward-looking statements were made, no assurances can be given as to future results, levels of activity and achievements. Undue reliance should not be placed on the statements contained herein, which are made as of the date hereof and, except as required by law, we undertake no obligation to update publicly or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The forward-looking statements contained herein are expressly qualified by this cautionary statement. ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK We are exposed to normal market risks inherent in the oil and gas, energy marketing and chemicals business, including commodity price risk, foreign-currency exchange rate risk, interest rate risk and credit risk. We recognize these risks and manage our operations to minimize our exposures to the extent practical. These are addressed in the unaudited consolidated financial statements. CREDIT RISK Most of our credit exposures are with counterparties in the energy industry, including integrated oil companies, crude oil refiners and utilities and are subject to normal industry credit risk. At September 30, 2010: o approximately 88% of our credit exposures were investment grade; o approximately 76% of our credit exposures were with a diverse group of integrated oil companies, crude oil refiners and marketers, and large utilities; and o only two counterparties individually made up more than 10% of our credit exposure. These counterparties are major integrated oil companies with strong investment grade credit ratings. Further information presented on market risks can be found in Item 7A on pages 92-94 in our 2009 Form 10-K and have not materially changed since December 31, 2009. ITEM 4. CONTROLS AND PROCEDURES EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES The Company's Chief Executive Officer and Chief Financial Officer have designed disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the SECURITIES EXCHANGE ACT OF 1934), or caused such disclosure controls and procedures to be designed under their supervision, to ensure that material information relating to the Company is made known to them, particularly during the period in which this report is prepared. They have evaluated the effectiveness of such disclosure controls and procedures as of the end of the period covered by this report ("Evaluation Date"). Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that, as of the Evaluation Date, the Company's disclosure controls and procedures are effective (i) to ensure that information required to be disclosed by us in reports that the Company files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission rules and forms; and (ii) to ensure that information required to be disclosed in the reports that the Company files or submits under the Exchange Act is accumulated and communicated to our management, including the Company's Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosures. The Company's management, including its Chief Executive Officer and Chief Financial Officer, does not expect that the Company's disclosure controls and procedures or internal controls will prevent all possible error and fraud. The Company's disclosure controls and procedures are, however, designed to provide reasonable assurance of achieving their objectives, and the Company's Chief Executive Officer and Chief Financial Officer have concluded that the Company's financial controls and procedures are effective at that reasonable assurance level. 56 CHANGES IN INTERNAL CONTROLS We have continually had in place systems relating to internal control over financial reporting. There has not been any change in the Company's internal control during the first nine months of 2010 that has materially affected, or is reasonably likely to materially affect, the Company's internal control over financial reporting. PART II ITEM 1. LEGAL PROCEEDINGS Information in response to this item is included in Part I, Item 1 in Note 17 " Commitments, Contingencies and Guarantees" and is incorporated by reference into Part II of this Quarterly Report on Form 10-Q. On October 22, 2010, Syncrude Canada Ltd., in which Nexen owns a non-operating 7.23% interest, was sentenced by the Alberta Provincial Court under the provincial Environmental Protection and Enhancement Act and the federal Migratory Birds Convention Act for harming wildlife. The total sentence under both acts was approximately $3 million ($216,900 net to Nexen). ITEM 4. (REMOVED AND RESERVED) ITEM 6. EXHIBITS 31.1 Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 31.2 Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 32.1 Certification of periodic report by Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 32.2 Certification of periodic report by Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Company has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on November 3, 2010. NEXEN INC. /s/ Marvin F. Romanow /s/ Brendon T. Muller --------------------- --------------------- Marvin F. Romanow Brendon T. Muller President and Chief Executive Officer Controller (Principal Executive Officer) (Principal Accounting Officer) 57