EX-99 2 ex99-1form8k_101404.txt EXHIBIT 99.1 EXHIBIT 99.1 ------------ [NEXEN LOGO OMITTED] NEXEN INC. 801 - 7th Ave SW Calgary, AB Canada T2P 3P7 T 403 699.4000 F 403 699.5776 www.nexeninc.com N E W S R E L E A S E For immediate release NEXEN GENERATES STRONG THIRD QUARTER CASH FLOW AND EARNINGS HIGHLIGHTS: o THIRD QUARTER CASH FLOW OF $3.94 PER SHARE AND EARNINGS OF $1.70 PER SHARE o USAN-5, OFFSHORE NIGERIA, DISCOVERS MORE OIL o EXPLORATION PROGRAM GEARING UP - 15 WELLS PLANNED OR DRILLING IN NEXT TWO QUARTERS o LONG LAKE PROJECT REACHES MILESTONE AS COMMERCIAL SAGD DRILLING BEGINS o BRANDON CHEMICALS PLANT EXPANSION COMPLETE
THREE MONTHS ENDED SEPT 30 NINE MONTHS ENDED SEPT 30 -------------------------- ------------------------- (Cdn$ millions) 2004 2003 2004 2003 ---------------------------------------------------------------------------------------------- Production (mboe/d)(1) Before Royalties 244 271 247 272 After Royalties 170 188 171 187 Net Sales 837 716 2,359 2,248 Cash Flow from Operations(2) 508 434 1,353 1,449 Per Common Share ($/share) 3.94 3.38 10.51 11.34 Net Income 220 181 555 695 Per Common Share ($/share) 1.70 1.38 4.31 5.38 Capital Expenditures 395 286 1,086 1,097 Net Debt(3) 1,432 1,811 1,432 1,811 Average Cdn$/US$ exchange rate 0.77 0.73 0.75 0.69 ----------------------------------------------------------------------------------------------
1 2003 production includes 6 mboe/d before royalties (4 mboe/d after royalties) for the quarter, and 8 mboe/d before royalties (6 mboe/d after royalties) year to date for Canadian production sold in September 2003 2 For reconciliation of this non-GAAP measure, see Cash Flow from Operations on pg. 7 3 Including preferred and subordinated securities CALGARY, ALBERTA, OCTOBER 14, 2004 - Nexen achieved solid third quarter cash flow and earnings driven by high commodity prices and attractive margins. This was partially offset by higher exploration expense and slightly lower production in Yemen and Canada. With slower than expected production growth in the United States, compounded by production shut-in for Hurricane Ivan, and the maturing of our Masila fields in Yemen, we have revised our 2004 full-year production guidance downward to 243,000 to 249,000 boe/d. Exploration expense for the quarter totalled $54 million, including the costs of the Shark well in the Gulf of Mexico and two Block 51 exploration wells in Yemen. Shark was an ultra-deep-shelf gas test on South Timbalier 174 that finished drilling during the first quarter of this year. At this time, we have no plans to re-enter the well and we have expensed $25 million (before tax) of well costs. We remain encouraged by the ultra-deep-shelf and are at the forefront of this opportunity. Our operating costs on a per unit basis have increased 27% from 2003 as a result of the Aspen-1 well remediation, higher maintenance in Yemen and Canada, more work-over activity in the Gulf of Mexico, and spreading fixed costs over fewer barrels. These increases were partially offset by the deferral of costs from Australia and Nigeria, as they had no liftings during the quarter. "Assuming oil averages US$40 per barrel and natural gas averages US$5.50 per mmbtu for the fourth quarter, we now expect to generate close to $2 billion in cash flow for the year," commented Charlie Fischer, Nexen's 1 President and Chief Executive Officer. "We are currently evaluating our options for effectively deploying the surplus cash flow we have generated this year, including further reduction in net debt and value accretive additions to our production profile." THIRD QUARTER PRODUCTION
PRODUCTION BEFORE ROYALTIES PRODUCTION AFTER ROYALTIES --------------------------- -------------------------- Crude Oil, NGLs and Natural Gas (mboe/d) Q3 2004 Q2 2004 Q3 2004 Q2 2004 ----------------------------------------------------------------------------------------- Yemen 103 106 51 54 Canada 59 61 45 48 United States 57 48 50 42 Other Countries 7 8 7 7 Syncrude 18 17 17 16 -------------------------------------------------------------- Total 244 240 170 167 -----------------------------------------------------------------------------------------
Overall, our production before royalties increased 2% from the second quarter, averaging 244,300 boe/d. This was driven primarily by higher volumes from the Gulf of Mexico. Gulf of Mexico production increased 18% compared to the second quarter, averaging 56,900 boe/d. Shallow-water production was relatively flat from last quarter at 21,700 boe/d. Deep-water production increased 33% to 35,200 boe/d following the tie-in of a third development well at Aspen, and the tie-in of three development wells and re-completion of a fourth well that had previously sanded-up at Gunnison. Our Gulf of Mexico production growth was slowed by a number of factors. Approximately two-thirds of our production was shut-in for close to four days because of Hurricane Ivan, decreasing our quarterly production by approximately 2,000 boe/d. Rig delays and storms also slowed projects at Vermilion 76, Vermilion 302 and Aspen. Since the Aspen-1 well was remediated in August, water production from this well has decreased substantially. We are currently monitoring the performance of the well and are hopeful that we will see production increase as the water cut declines further. Production from our deep-water Aspen field averaged 24,900 boe/d, compared to 17,500 boe/d during the second quarter. Current field production is approximately 30,000 boe/d. Internationally, production from our Masila Block in Yemen was 3% lower than during the second quarter. Continuing well optimizations and mobilization of a fifth drilling rig are helping to moderate base declines. We have focused the drilling program on our Sunah, Tawila and West Hemiar fields, where we recently drilled higher deliverability wells. Offshore Australia, the Buffalo field returned to production on August 5th and averaged 2,100 bbls/d for the third quarter. This field will be decommissioned at the end of November. Our Guando field, in Colombia, continues to outperform expectations and produced 5,000 bbls/d for the third quarter. Our mature Canadian assets performed as expected during the quarter. Lower results in heavy oil and Hay were partially offset by positive results from our natural gas properties. Syncrude production increased slightly from last quarter as a number of turnarounds scheduled for September were completed earlier in the year. PRODUCTION OUTLOOK
-------------------------------------------------------------------------------------------------------- ORIGINAL 2004 ESTIMATED ANNUAL PRODUCTION REVISED 2004 ESTIMATED ANNUAL PRODUCTION -------------------------------------------------------------------------------------------------------- Before Royalties After Royalties Before Royalties After Royalties (mboe/d) (mboe/d) (mboe/d) (mboe/d) -------------------------------------------------------------------------------------------------------- United States(1) 60-65 55-57 54-56 48-49 Yemen 110-118 58-62 106-107 53-54 Canada(2) 57-65 46-53 59-60 47-48 Syncrude 16-18 16-17 17-18 17-18 Other Countries 7-9 6-8 7-8 6-7 ------------------------------------------------------------------------------------- TOTAL 255 - 275 180 - 195 243-249 171 - 176 --------------------------------------------------------------------------------------------------------
1) US natural gas production is estimated to comprise 45% of total US equivalent production in 2004 2) Canadian natural gas production is estimated to comprise 40% of total Canadian equivalent production in 2004 2 We have reduced our 2004 full year production outlook to 243,000 to 249,000 boe/d. This change reflects reductions in our expectations for Yemen (due to base declines) and the Gulf of Mexico (due to slower than anticipated ramp-up of production from Aspen following remediation of the Aspen-1 well, delays in shallow-water drilling, lower than expected production from Gunnison, and storms in the Gulf). Our current forecast for fourth quarter production of 236,000 to 250,000 boe/d is based on the following distribution: the United States at 56,000 to 65,000 boe/d, Yemen at 101,000 to 103,000 bbls/d, Canada at 56,000 to 58,000 boe/d, Syncrude at 17,000 to 18,000 bbls/d and Other Countries at 6,000 to 7,000 bbls/d. EXPLORATION UPDATE "Our strategy is to grow through the drill-bit and we have a record exploration drilling program planned for the next few months," explained Fischer. "A total of 15 high-impact exploration wells between now and the end of the first quarter of 2005 highlights the depth of our exploration portfolio in our key basins." WEST AFRICA EXPLORATION - THIRD DISCOVERY ON OPL-222, OFFSHORE NIGERIA Total SA announced that its Nigerian Operating subsidiary, Elf Petroleum Nigeria Ltd. (EPNL), has made a significant discovery in the area west of the Usan field in the deepwater OPL-222, offshore southeastern Nigeria. Nexen has a 20% interest in OPL-222. The Usan-5 well, located around 70 miles offshore and 4 miles west of the Usan-1 discovery well in water depths of approximately 2,500 feet, is the fifth successful well in the Usan field area. Oil was sampled at Usan-5 in several levels confirming the presence of additional quantities of oil as well as further potential in previously untested reservoirs. On OML-115, offshore Nigeria, the Ameena-1 well started drilling mid-September to test the Ameena prospect. Results are expected before year-end, and in the event of a discovery an appraisal well will be drilled immediately. Ameena is in 125 feet of water, approximately 40 miles offshore. Early October, we began drilling an exploration well on Block K, offshore Equatorial Guinea, to test our Zorro prospect. Zorro is in 2,125 feet of water approximately 25 miles offshore with results expected by year-end. This prospect is on trend with recent commercial discoveries directly to the northeast. A second exploration well will test another prospect early next year. We are the operator and hold a 50% interest in Block K. GULF OF MEXICO EXPLORATION - ACTIVE EXPLORATION PROGRAM UNDERWAY Our exploration program in the Gulf has geared up during the third and fourth quarters. A total of nine exploration wells are drilling or are expected to be drilling through the balance of this year. All of these wells should have relatively short drilling to production cycle times upon success. Two wells are near our existing Aspen and Gunnison facilities, while the balance is near other existing third-party infrastructure. In early September, we began drilling our 100% owned Crested Butte prospect on Green Canyon 242, three miles northwest of our Aspen field. Drilling was interrupted by Hurricane Ivan, and results from this well are expected by year-end. If successful, this well could be tied-in and on production by 2006. At Dawson Deep, we are currently side-tracking the original well to an optimal location for production through our Gunnison facilities. Results are expected shortly. We have a 15% interest in the well and a 30% interest in the Gunnison facilities. Main Pass 240 is a deep-shelf test, where we have a 45% non-operated interest. This prospect is 40 miles offshore Louisiana in 175 feet of water. The well started drilling in early August, and we were approaching target depth when operations were suspended due to Hurricane Ivan. Subsequent inspection found that the drilling rig had been damaged by the hurricane, delaying drilling by approximately 30 days. We expect to contract another rig to resume drilling this month and have results before year-end. A deep-shelf test at Main Pass 273 is planned following the completion of Main Pass 240. This prospect is 35 miles offshore Louisiana in 200 feet of water. The well should commence drilling before year-end with results expected early next year. We have a 30% non-operated interest in the prospect. At Mustang Island A-110, we expect to begin drilling the Big Bend prospect before year-end. This deep-shelf gas test is 50 miles offshore Texas in 300 feet of water. Results should be available early next year. We have a non-operated 50% interest. 3 At West Cameron 335, we expect to begin drilling the Wind River prospect before year-end. This deep-shelf gas test is 50 miles offshore Louisiana in 75 feet of water. We expect results from this well early next year. We have a 50% non-operated interest. We also plan to start drilling three additional short-cycle time deep-water exploration wells in the Gulf of Mexico during the fourth quarter. The Fawkes prospect located in Garden Banks, Anduin located in Mississippi Canyon, and an additional prospect in Mississippi Canyon, could all be developed with sub-sea tie-backs to existing infrastructure. We are also finalizing plans to drill three high-impact, deep-water, sub-salt tests, with the first of these expected to begin drilling in the first quarter of 2005. "We have three strategic focus areas in the Gulf. The first two are short-cycle time initiatives: drilling around existing infrastructure and deep-shelf gas. The third focus is large reserve targets in the deep-water, which are longer cycle time projects to establish new core areas," said Fischer. "In the event of a discovery, we can bring a short-cycle time well on production in 12 to 24 months." YEMEN EXPLORATION Our 2004 exploration program at East Al Hajr (Block 51) is targeting five independent prospects on the block. During the quarter, we completed drilling a second exploration well and have started a third. The first two exploration wells did not encounter commercial quantities of hydrocarbons and have been abandoned. Results from the third well are expected shortly. Our plans include two more exploration wells to be drilled during the fourth quarter. DEVELOPMENT UPDATE "We have a number of major development projects currently underway," said Fischer. "Early production from Block 51 in Yemen will commence later this year with full production targeted for mid-2005, the Syncrude expansion and Long Lake bitumen production should be on stream in 2006, followed by Long Lake premium synthetic crude in 2007 and OPL-222, offshore Nigeria, beyond that." YEMEN - EAST AL HAJR (BLOCK 51) DEVELOPMENT Development of East Al Hajr (Block 51) in Yemen is on schedule to start producing 5,000 bbls/d in late 2004. All of this year's planned development wells have now been drilled and are being completed and tied-in. All major equipment for the central processing facility has been ordered and we expect construction to be completed during the second quarter of 2005. Production will ramp up to expected peak rates of 25,000 bbls/d in the second half of 2005. We have an 87.5% interest in East Al Hajr. ATHABASCA OIL SANDS - SAGD DRILLING STARTS AT LONG LAKE PROJECT The Long Lake Project remains on schedule and on budget. In September, we saw the start of the commercial steam-assisted-gravity-drainage (SAGD) drilling program. Sixty-five horizontal well pairs will be drilled over the next 18 months, with steam-injection expected late in 2006. These wells, together with the three horizontal well pairs from the SAGD pilot, will deliver up to 72,000 barrels per day of bitumen for upgrading onsite. "The SAGD pilot has been operating now for over a year, helping us to better understand this reservoir," stated Fischer. "Production from the SAGD pilot is currently 1,600 bbls/d." Project engineering and procurement are also progressing as planned. Approximately 40% of total project engineering is complete. More than 80% of the engineering will be completed prior to the start of above-ground construction scheduled for early 2005. Over 95% of the major SAGD equipment and more than 80% of the major upgrader equipment has been ordered. The equipment costs have been in-line with our expectations. As previously announced, we entered into an interim agreement with Enbridge Inc. to provide pipeline transportation services for the Long Lake Project. The agreement provides for an initial contract volume of up to 60,000 bbls/d for a 50 month term, with options to extend the term and expand contract volumes. This interim agreement will be replaced by definitive transportation agreements. 4 "We have made tremendous progress since the project was sanctioned in February," expressed Fischer. "In addition to drilling, current site activities include installation of underground piping, foundation piling, preparation of tank bases, and building of camp facilities." The Long Lake Project will develop and upgrade bitumen into light, sweet, premium synthetic crude (PSC) oil. SAGD bitumen production will commence in 2006, with up to 60,000 bbls/d of upgraded PSC oil production (30,000 net to Nexen) beginning in 2007. This project is the first phase in the development of our bitumen assets at Long Lake. SODERGLEN WIND POWER PROJECT INITIATED We have signed a memorandum of understanding to joint venture with GW Power Corporation to develop a 70MW wind power project about 10 miles south of Fort McLeod, Alberta. Pending regulatory approval, construction of the turbines and towers will begin mid-2005, with commissioning and start-up expected in the fourth quarter of 2005. This project will be one of the largest projects producing electricity from wind energy in southern Alberta, and has potential for further expansion. Nexen will hold a 50% interest in the project. "This is a financially attractive project with many environmental benefits. It also compliments our existing cogeneration power generation capacity at Balzac," explained Fischer. "This supports our marketing group's initiative to generate and sell power to industrial, commercial and public sector customers in Alberta, and should provide carbon offsets that will support our oil sands investments." CHEMICALS - BRANDON PLANT EXPANSION COMPLETE In September, we saw the mechanical completion of the Brandon Chemicals plant expansion, with commissioning and start-up activities planned to be finished by the end of October. The plant is now the largest and one of the most cost-efficient sodium chlorate sites in the world. This expansion, of approximately 65,000 tonnes per year, raises the annual capacity of the plant to over 260,000 tonnes. QUARTERLY DIVIDEND - 118TH CONSECUTIVE DIVIDEND DECLARED The Board of Directors has declared the regular quarterly dividend of $0.10 per common share payable January 1, 2005, to shareholders of record on December 10, 2004. Nexen Inc. is an independent, Canadian-based global energy and chemicals company, listed on the Toronto and New York stock exchanges under the symbol NXY. We are uniquely positioned for growth in the deep-water Gulf of Mexico, the Athabasca oil sands of Alberta, the Middle East and West Africa. We add value for shareholders through successful full-cycle oil and gas exploration and development, a growing industrial bleaching chemicals business, and leadership in ethics, integrity and environmental protection. For further information, please contact: KEVIN FINN GRANT DREGER, CA Vice President, Investor Relations Manager, Investor Relations (403) 699-5166 (403) 699-5273 801 - 7th Ave SW Calgary, Alberta, Canada T2P 3P7 www.nexeninc.com CONFERENCE CALL NOTICE Date: October 14, 2004 Time: 7:00 a.m. Mountain Time (9:00 a.m. Eastern Time) We invite you to learn more about Nexen by joining our 2004 Q3 Conference Call. Charlie Fischer, President and CEO, and other senior executives will discuss the financial and operating results and expectations for the future. 5 To listen to the conference call, please call one of these two lines: 800-814-4861 (North American Toll-Free) 416-640-1907 (Toronto or International) A replay of the call will be available from approximately 11:00 a.m. Eastern Time, October 14, 2004 until midnight, October 28, 2004 by calling 416-640-1917 and entering passcode 21095406 followed by the pound sign. A live and on demand web cast of the conference call will be available at WWW.NEXENINC.COM. FORWARD LOOKING STATEMENTS CERTAIN STATEMENTS IN THIS REPORT CONSTITUTE "FORWARD-LOOKING STATEMENTS" WITHIN THE MEANING OF THE UNITED STATES PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995, SECTION 21E OF THE UNITED STATES SECURITIES EXCHANGE ACT OF 1934, AS AMENDED, AND SECTION 27A OF THE UNITED STATES SECURITIES ACT OF 1933, AS AMENDED. SUCH STATEMENTS ARE GENERALLY IDENTIFIABLE BY THE TERMINOLOGY USED SUCH AS "INTEND", "PLAN", "EXPECT", "ESTIMATE", "BUDGET", "OUTLOOK" OR OTHER SIMILAR WORDS. 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: MARKET PRICES FOR OIL AND GAS AND CHEMICALS PRODUCTS; THE ABILITY TO EXPLORE, DEVELOP, PRODUCE AND TRANSPORT CRUDE OIL AND NATURAL GAS TO MARKETS; THE RESULTS OF EXPLORATION AND DEVELOPMENT DRILLING AND RELATED ACTIVITIES; FOREIGN-CURRENCY EXCHANGE RATES; ECONOMIC CONDITIONS IN THE COUNTRIES AND REGIONS WHERE NEXEN CARRIES ON BUSINESS; ACTIONS BY GOVERNMENTAL AUTHORITIES INCLUDING INCREASES IN TAXES, CHANGES IN ENVIRONMENTAL AND OTHER LAWS AND REGULATIONS; RENEGOTIATIONS OF CONTRACTS; AND POLITICAL UNCERTAINTY, INCLUDING ACTIONS BY INSURGENT OR OTHER ARMED GROUPS OR OTHER CONFLICT. THE IMPACT OF ANY ONE FACTOR ON A PARTICULAR FORWARD-LOOKING STATEMENT IS NOT DETERMINABLE WITH CERTAINTY AS SUCH FACTORS ARE INTERDEPENDENT UPON OTHER FACTORS, AND MANAGEMENT'S COURSE OF ACTION WOULD DEPEND ON ITS ASSESSMENT OF THE FUTURE CONSIDERING ALL INFORMATION THEN AVAILABLE. ANY STATEMENTS AS TO POSSIBLE COMMERCIALITY, DEVELOPMENT PLANS, CAPACITY EXPANSIONS, DRILLING OF NEW WELLS, ULTIMATE RECOVERABILITY OF RESERVES, FUTURE PRODUCTION RATES, CASH FLOWS AND CHANGES IN ANY OF THE FOREGOING ARE FORWARD-LOOKING STATEMENTS. 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. READERS SHOULD ALSO REFER TO ITEMS 7 AND 7A IN OUR 2003 ANNUAL REPORT ON FORM 10-K FOR FURTHER DISCUSSION OF THE RISK FACTORS. CAUTIONARY NOTE TO U.S. INVESTORS - THE UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC) PERMITS OIL AND GAS COMPANIES, IN THEIR FILINGS WITH THE SEC, TO DISCUSS ONLY PROVED RESERVES THAT ARE SUPPORTED BY ACTUAL PRODUCTION OR CONCLUSIVE FORMATION TESTS TO BE ECONOMICALLY AND LEGALLY PRODUCIBLE UNDER EXISTING ECONOMIC AND OPERATING CONDITIONS. IN THIS PRESS RELEASE, WE MAY REFER TO "RECOVERABLE RESERVES", "PROBABLE RESERVES" AND "RECOVERABLE RESOURCES" WHICH ARE INHERENTLY MORE UNCERTAIN THAN PROVED RESERVES. THESE TERMS ARE NOT USED IN OUR FILINGS WITH THE SEC. OUR RESERVES AND RELATED PERFORMANCE MEASURES REPRESENT OUR WORKING INTEREST BEFORE ROYALTIES, UNLESS OTHERWISE INDICATED. PLEASE REFER TO OUR ANNUAL REPORT ON FORM 10-K AVAILABLE FROM US OR THE SEC FOR FURTHER RESERVE DISCLOSURE. CAUTIONARY NOTE TO CANADIAN INVESTORS: NEXEN IS REQUIRED TO DISCLOSE OIL AND GAS ACTIVITIES UNDER NATIONAL INSTRUMENT 51-101-- STANDARDS OF DISCLOSURE FOR OIL AND GAS ACTIVITIES (NI 51-101). THE CANADIAN SECURITIES REGULATORY AUTHORITIES (CSA) HAVE GRANTED US EXEMPTIONS FROM CERTAIN PROVISIONS OF NI 51-101 TO PERMIT US STYLE DISCLOSURE. THESE EXEMPTIONS WERE SOUGHT BECAUSE WE ARE A US SECURITIES AND EXCHANGE COMMISSION (SEC) REGISTRANT AND OUR SECURITIES REGULATORY DISCLOSURES, INCLUDING FORM 10-K AND OTHER RELATED FORMS, MUST COMPLY WITH SEC REQUIREMENTS. OUR DISCLOSURES MAY DIFFER FROM THOSE CANADIAN COMPANIES WHO HAVE NOT RECEIVED SIMILAR EXEMPTIONS UNDER NI 51-101. OUR PROBABLE RESERVES DISCLOSURE APPLIES THE SOCIETY OF PETROLEUM ENGINEERS/WORLD PETROLEUM COUNCIL (SPE/WPC) DEFINITION FOR PROBABLE RESERVES. THE CANADIAN OIL AND GAS EVALUATION HANDBOOK STATES THERE SHOULD NOT BE A SIGNIFICANT DIFFERENCE IN ESTIMATED PROBABLE RESERVE QUANTITIES USING THE SPE/WPC DEFINITION VERSUS NI 51-101. IN THIS PRESS RELEASE, 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 (6MCF:1BBL). THIS CONVERSION MAY BE MISLEADING, PARTICULARLY IF USED IN ISOLATION, SINCE THE 6MCF:1BBL RATIO IS BASED ON AN ENERGY EQUIVALENCY AT THE BURNER TIP AND DOES NOT REPRESENT THE VALUE EQUIVALENCY AT THE WELL HEAD. PLEASE READ THE "SPECIAL NOTE TO CANADIAN INVESTORS" IN ITEM 7A IN OUR 2003 ANNUAL REPORT ON FORM 10-K, FOR A SUMMARY OF THE EXEMPTION GRANTED BY THE CSA AND THE MAJOR DIFFERENCES BETWEEN SEC REQUIREMENTS AND NI 51-101. THE SUMMARY IS NOT INTENDED TO BE ALL-INCLUSIVE NOR TO CONVEY SPECIFIC ADVICE. RESERVE ESTIMATION IS HIGHLY TECHNICAL AND REQUIRES PROFESSIONAL COLLABORATION AND JUDGEMENT. THE DIFFERENCES BETWEEN SEC REQUIREMENTS AND NI 51-101 MAY BE MATERIAL. 6 NEXEN INC. FINANCIAL HIGHLIGHTS
THREE MONTHS NINE MONTHS ENDED SEPTEMBER 30 ENDED SEPTEMBER 30 (Cdn$ millions) 2004 2003 2004 2003 ----------------------------------------------------------------------------------------------------- Net Sales 837 716 2,359 2,248 Cash Flow from Operations(1) 508 434 1,353 1,449 Per Common Share ($/share) 3.94 3.38 10.51 11.34 Net Income(1) 220 181 555 695 Per Common Share ($/share) 1.70 1.38 4.31 5.38 Capital Expenditures(2) 395 286 1,086 1,097 Net Debt(3) 1,432 1,811 1,432 1,811 Common Shares Outstanding (millions of shares) 129.0 124.1 129.0 124.1 -------------------------------------------
Notes: 1 Includes discontinued operations as discussed in Note 10 to our Unaudited Consolidated Financial Statements. 2 Includes $172 million for the acquisition of the 40% interest in Aspen and surrounding acreage in March 2003. 3 Net Debt is defined as long-term debt and preferred and subordinated securities less working capital. CASH FLOW FROM OPERATIONS (1)
THREE MONTHS NINE MONTHS ENDED SEPTEMBER 30 ENDED SEPTEMBER 30 (Cdn$ millions) 2004 2003 2004 2003 ----------------------------------------------------------------------------------------------------- Cash Flow from Operations Oil and Gas Yemen(2) 156 128 430 403 Canada(3) 114 110 311 398 United States 181 151 499 489 Australia -- 10 18 34 Other Countries 10 6 27 22 Marketing 26 16 29 70 Syncrude 56 35 145 88 -------------------------------------------- 543 456 1,459 1,504 Chemicals 21 22 61 61 -------------------------------------------- 564 478 1,520 1,565 Interest and Other Corporate Items (48) (35) (146) (102) Income Taxes(4) (8) (9) (21) (14) -------------------------------------------- Cash Flow from Operations(1) 508 434 1,353 1,449 ============================================
Notes: 1 Defined as cash generated from operating activities before changes in non-cash working capital and other. We evaluate our performance and that of our business segments based on earnings and cash flow from operations. Cash flow from operations is a non-GAAP term that represents cash generated from operating activities before changes in non-cash working capital and other. We consider it a key measure as it demonstrates our ability and the ability of our business segments to generate the cash flow necessary to fund future growth through capital investment and repay debt. Cash flow from operations may not be comparable with the calculation of similar measures for other companies.
THREE MONTHS NINE MONTHS ENDED SEPTEMBER 30 ENDED SEPTEMBER 30 (Cdn$ millions) 2004 2003 2004 2003 ------------------------------------------------------------------------------------------------------ Cash Flow from Operating Activities 418 296 1,273 1,242 Changes in Non-Cash Working Capital 55 125 99 165 Other 35 13 (19) 42 ----------------------------------------- Cash Flow from Operations 508 434 1,353 1,449 Less: Dividends on Preferred Securities -- (16) (3) (50) ----------------------------------------- Cash Flow from Operations Available to Common Shareholders 508 418 1,350 1,399 ========================================= Weighted-average Number of Common Shares Outstanding (millions of shares) 129.0 123.8 128.4 123.4 ----------------------------------------- Cash Flow from Operations Per Common Share ($/share) 3.94 3.38 10.51 11.34 =========================================
2 After in-country cash taxes of $65 million for the three months ended September 30, 2004 (2003 - $51 million) and $168 million for the nine months ended September 30, 2004 (2003 - $150 million). 3 Includes discontinued operations as discussed in Note 10 to our Unaudited Consolidated Financial Statements. 4 Excludes in-country cash taxes in Yemen. 7 NEXEN INC. PRODUCTION VOLUMES (BEFORE ROYALTIES)
THREE MONTHS NINE MONTHS ENDED SEPTEMBER 30 ENDED SEPTEMBER 30 2004 2003 2004 2003 -------------------------------------------------------------------------------------------------------- Oil and Liquids (mbbls/d) Yemen 103.3 115.2 107.8 116.7 Canada(1) 35.6 46.2 36.5 48.7 United States 32.9 31.3 28.5 28.2 Australia 2.1 5.6 3.0 6.5 Other Countries 5.3 5.2 5.1 5.8 Syncrude 17.6 17.5 17.5 15.5 -------------------------------------------- 196.8 221.0 198.4 221.4 -------------------------------------------- Natural Gas (mmcf/d) Canada(1) 141 155 145 158 United States 144 144 148 146 -------------------------------------------- 285 299 293 304 -------------------------------------------- Total (mboe/d) 244 271 247 272 =========================================== PRODUCTION VOLUMES (AFTER ROYALTIES) THREE MONTHS NINE MONTHS ENDED SEPTEMBER 30 ENDED SEPTEMBER 30 2004 2003 2004 2003 --------------------------------------------------------------------------------------------------------- Oil and Liquids (mbbls/d) Yemen 50.8 56.8 53.0 57.2 Canada(1) 27.3 34.4 28.2 36.9 United States 29.1 27.8 25.1 25.0 Australia 1.9 5.4 2.8 5.9 Other Countries 4.9 4.7 4.7 4.9 Syncrude 17.4 17.4 17.3 15.3 -------------------------------------------- 131.4 146.5 131.1 145.2 -------------------------------------------- Natural Gas (mmcf/d) Canada(1) 106 127 114 125 United States 123 122 126 123 -------------------------------------------- 229 249 240 248 -------------------------------------------- Total (mboe/d) 170 188 171 187 ===========================================
Note: 1 2003 includes production from discontinued operations as discussed in Note 10 to our Unaudited Consolidated Financial Statements. 8 NEXEN INC. OIL AND GAS PRICES AND CASH NETBACK (1)
TOTAL QUARTERS - 2004 QUARTERS - 2003 YEAR -------------------------------------------------------------------------------- (all dollar amounts in Cdn$ unless noted) 1st 2nd 3rd 1st 2nd 3rd 4th 2003 ----------------------------------------------------------------------------------------------------------------------------- PRICES: WTI Oil (US $/bbl) 35.15 38.32 43.88 33.86 28.91 30.20 31.18 31.04 Nexen Average - Oil (Cdn $/bbl) 40.22 44.75 50.98 44.93 35.24 36.70 35.56 38.04 NYMEX Gas (US $/mmbtu) 5.73 6.16 5.56 6.32 5.74 4.92 5.42 5.60 Nexen Average - Gas (Cdn $/mcf) 6.63 7.17 6.55 8.35 7.18 6.01 5.91 6.85 ----------------------------------------------------------------------------------------------------------------------------- NETBACKS: CANADA - LIGHT OIL AND NGLS Sales (mbbls/d) 12.4 13.6 12.0 22.1 24.7 19.9 13.7 20.1 Price Received ($/bbl) 41.31 46.37 51.82 46.12 35.84 37.06 35.74 38.92 Royalties and Other 9.41 10.60 12.30 12.15 9.24 10.17 7.68 10.00 Operating Costs 9.09 6.52 6.22 6.87 5.84 5.69 5.85 6.09 ----------------------------------------------------------------------------------------------------------------------------- Netback 22.81 29.25 33.30 27.10 20.76 21.20 22.21 22.83 ----------------------------------------------------------------------------------------------------------------------------- CANADA - HEAVY OIL Sales (mbbls/d) 23.7 22.9 23.0 27.1 25.9 26.3 25.6 26.2 Price Received ($/bbl) 27.92 30.12 36.75 34.06 26.27 26.52 22.77 27.46 Royalties and Other 6.00 6.73 8.77 8.41 5.96 6.22 5.16 6.45 Operating Costs 9.98 10.44 10.05 8.28 8.77 9.31 9.08 8.84 ----------------------------------------------------------------------------------------------------------------------------- Netback 11.94 12.95 17.93 17.37 11.54 10.99 8.53 12.17 ----------------------------------------------------------------------------------------------------------------------------- CANADA - TOTAL OIL Sales (mbbls/d) 36.1 36.5 35.0 49.2 50.6 46.2 39.3 46.3 Price Received ($/bbl) 32.51 36.18 41.94 39.48 30.95 31.07 27.28 32.37 Royalties and Other 7.21 8.19 10.03 10.09 7.56 7.95 6.08 8.02 Operating Costs 9.68 8.98 8.73 7.62 7.34 7.75 7.95 7.65 ----------------------------------------------------------------------------------------------------------------------------- Netback 15.62 19.01 23.18 21.77 16.05 15.37 13.25 16.70 ----------------------------------------------------------------------------------------------------------------------------- CANADA - NATURAL GAS Sales (mmcf/d) 149 145 141 161 159 155 156 158 Price Received ($/mcf) 5.59 5.97 5.43 6.77 5.85 5.14 4.85 5.64 Royalties and Other 1.10 1.11 1.04 1.39 1.19 0.96 0.92 1.12 Operating Costs 0.59 0.69 0.83 0.41 0.51 0.60 0.55 0.52 ----------------------------------------------------------------------------------------------------------------------------- Netback 3.90 4.17 3.56 4.97 4.15 3.58 3.38 4.00 ----------------------------------------------------------------------------------------------------------------------------- YEMEN Sales (mbbls/d) 115.3 105.6 101.5 116.1 117.5 115.7 116.3 116.4 Price Received ($/bbl) 41.88 45.88 53.80 45.69 35.86 38.25 38.13 39.45 Royalties and Other 22.10 22.53 27.40 23.87 17.96 19.40 18.79 19.98 Operating Costs 2.72 2.55 2.91 2.03 2.02 2.12 2.48 2.16 In-country Taxes 4.41 5.88 6.97 4.91 4.48 4.73 4.79 4.73 ----------------------------------------------------------------------------------------------------------------------------- Netback 12.65 14.92 16.52 14.88 11.40 12.00 12.07 12.58 -----------------------------------------------------------------------------------------------------------------------------
Note: 1 Defined as average sales price less royalties and other, operating costs, and in-country taxes in Yemen. 9 NEXEN INC. OIL AND GAS CASH NETBACK (1) (CONTINUED)
TOTAL QUARTERS - 2004 QUARTERS - 2003 YEAR ----------------------------------------------------------------------------- (all dollar amounts in Cdn$ unless noted) 1st 2nd 3rd 1st 2nd 3rd 4th 2003 ----------------------------------------------------------------------------------------------------------------------------- ----------------------------------------------------------------------------------------------------------------------------- UNITED STATES Oil: Sales (mbbls/d) 26.5 25.7 32.9 21.7 31.4 31.3 28.5 28.3 Price Received ($/bbl) 38.99 46.31 49.90 46.00 36.28 36.03 34.79 37.68 Gas: Sales (mmcf/d) 167 134 144 135 157 144 143 145 Price Received ($/mcf) 7.63 8.47 7.64 10.22 8.55 6.95 7.06 8.16 Total Sales Volume (mboe/d) 54.4 48.0 56.9 44.2 57.6 55.3 52.3 52.5 Price Received ($/boe) 42.47 48.38 48.19 53.82 43.07 38.49 38.25 42.88 Royalties and Other 5.90 6.98 6.22 7.83 5.89 5.14 5.13 5.91 Operating Costs 4.13 4.84 7.60 5.32 4.63 3.93 4.14 4.49 ----------------------------------------------------------------------------------------------------------------------------- Netback 32.44 36.56 34.37 40.67 32.55 29.42 28.98 32.48 ----------------------------------------------------------------------------------------------------------------------------- AUSTRALIA Sales (mbbls/d) 7.5 4.8 -- 7.9 5.2 4.7 -- 4.4 Price Received ($/bbl) 42.60 49.84 -- 48.13 36.53 42.09 -- 43.14 Royalties and Other 2.11 2.28 -- 8.83 (0.24) 0.41 -- 3.44 Operating Costs 22.88 34.28 -- 17.60 19.31 19.47 -- 18.60 ----------------------------------------------------------------------------------------------------------------------------- Netback 17.61 13.28 -- 21.70 17.46 22.21 -- 21.10 ----------------------------------------------------------------------------------------------------------------------------- OTHER COUNTRIES Sales (mbbls/d) 4.1 5.8 5.0 5.1 6.7 5.2 4.8 5.4 Price Received ($/bbl) 37.07 44.75 46.22 48.84 34.74 36.03 34.46 38.22 Royalties and Other 1.73 4.94 3.46 11.39 4.52 3.14 4.16 5.69 Operating Costs 2.70 6.28 2.93 8.02 8.81 6.45 6.14 7.47 ----------------------------------------------------------------------------------------------------------------------------- Netback 32.64 33.53 39.83 29.43 21.41 26.44 24.16 25.06 ----------------------------------------------------------------------------------------------------------------------------- SYNCRUDE Sales (mbbls/d) 18.3 16.6 17.6 13.6 15.2 17.5 14.8 15.3 Price Received ($/bbl) 45.54 52.46 55.58 51.84 42.26 41.36 39.22 43.36 Royalties and Other 0.45 0.52 0.55 0.52 0.42 0.59 0.39 0.48 Operating Costs(2) 17.41 20.01 18.87 24.91 24.04 17.06 23.00 21.96 ----------------------------------------------------------------------------------------------------------------------------- Netback 27.68 31.93 36.16 26.41 17.80 23.71 15.83 20.92 ----------------------------------------------------------------------------------------------------------------------------- COMPANY-WIDE Oil and Gas Sales (mboe/d) 260.5 241.5 239.5 262.9 279.3 270.4 253.5 266.6 Price Received ($/boe) 40.11 44.41 48.66 45.84 36.71 36.59 35.54 38.63 Royalties and Other 12.76 13.34 15.30 15.10 10.95 11.36 11.25 12.14 Operating Costs(2) 5.67 6.06 6.25 5.46 5.31 4.94 4.88 5.19 In-country Taxes 1.95 2.57 2.96 2.16 1.88 2.02 2.20 2.06 ----------------------------------------------------------------------------------------------------------------------------- Netback 19.73 22.44 24.15 23.12 18.57 18.27 17.21 19.24 -----------------------------------------------------------------------------------------------------------------------------
Notes: 1 Defined as average sales price less royalties and other, operating costs, and in-country taxes in Yemen. 2 We computed our netback for Syncrude excluding research and development costs. Previously, we included these costs as operating costs. 10 NEXEN INC. UNAUDITED CONSOLIDATED STATEMENT OF INCOME FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30 Cdn$ millions, except per share amounts
THREE MONTHS NINE MONTHS ENDED SEPTEMBER 30 ENDED SEPTEMBER 30 2004 2003 2004 2003 ----------------------------------------------------------------------------------------------------------------- Restated Restated for for Change in Change in Accounting Accounting Principles Principles Note 1 Note 1 REVENUES Net Sales 837 716 2,359 2,248 Marketing and Other (Note 9) 147 131 439 451 ----------------------------------------------- 984 847 2,798 2,699 ----------------------------------------------- EXPENSES Operating 205 184 596 570 Transportation and Other 122 107 389 357 General and Administrative (Note 6) 57 44 247 126 Depreciation, Depletion and Amortization (Note 1) 181 190 541 566 Exploration 54 30 108 109 Interest (Note 4) 35 23 115 76 ----------------------------------------------- 654 578 1,996 1,804 ----------------------------------------------- INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES 330 269 802 895 ----------------------------------------------- PROVISION FOR INCOME TAXES Current 73 60 189 164 Future 37 31 58 51 ----------------------------------------------- 110 91 247 215 ----------------------------------------------- NET INCOME FROM CONTINUING OPERATIONS 220 178 555 680 Net Income from Discontinued Operations (Note 10) -- 3 -- 15 ----------------------------------------------- NET INCOME 220 181 555 695 Dividends on Preferred Securities, Net of Income Taxes -- 10 2 31 ----------------------------------------------- NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS 220 171 553 664 =============================================== EARNINGS PER COMMON SHARE FROM CONTINUING OPERATIONS ($/share) Basic (Note 7) 1.70 1.36 4.31 5.26 =============================================== Diluted (Note 7) 1.69 1.35 4.25 5.22 =============================================== EARNINGS PER COMMON SHARE ($/share) Basic (Note 7) 1.70 1.38 4.31 5.38 =============================================== Diluted (Note 7) 1.69 1.37 4.25 5.34 ===============================================
SEE ACCOMPANYING NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS. 11 NEXEN INC. UNAUDITED CONSOLIDATED BALANCE SHEET Cdn$ millions, except share amounts
SEPTEMBER 30 DECEMBER 31 2004 2003 ---------------------------------------------------------------------------------------------------------------- Restated for Change in Accounting Principles Note 1 ASSETS CURRENT ASSETS Cash and Short-Term Investments 866 1,087 Accounts Receivable (Note 2) 1,549 1,423 Inventories and Supplies (Note 3) 400 270 Other 42 79 ------------------------------ Total Current Assets 2,857 2,859 ------------------------------ PROPERTY, PLANT AND EQUIPMENT (Note 1) Net of Accumulated Depreciation, Depletion and Amortization of $5,310 (December 31, 2003 - $4,907) 4,950 4,550 GOODWILL 36 36 FUTURE INCOME TAX ASSETS 88 108 DEFERRED CHARGES AND OTHER ASSETS 192 153 ------------------------------ 8,123 7,706 ============================== LIABILITIES AND SHAREHOLDERS' EQUITY CURRENT LIABILITIES Current Portion of Long-Term Debt (Note 4) -- 291 Accounts Payable and Accrued Liabilities 1,768 1,404 Accrued Interest Payable 37 44 Dividends Payable 13 12 ------------------------------ Total Current Liabilities 1,818 1,751 ------------------------------ LONG-TERM DEBT (Note 4) 2,438 2,485 FUTURE INCOME TAX LIABILITIES (Note 1) 752 707 ASSET RETIREMENT OBLIGATIONS (Note 1) 309 305 DEFERRED CREDITS AND LIABILITIES 113 68 SHAREHOLDERS' EQUITY (Note 6) Preferred and Subordinated Securities 33 364 Common Shares, no par value Authorized: Unlimited Outstanding: 2004 - 129,018,817 shares 2003 - 125,606,107 shares 629 513 Contributed Surplus -- 1 Retained Earnings (Note 1) 2,179 1,631 Cumulative Foreign Currency Translation Adjustment (148) (119) ------------------------------ Total Shareholders' Equity 2,693 2,390 ------------------------------ COMMITMENTS AND CONTINGENCIES (Note 11) 8,123 7,706 ==============================
SEE ACCOMPANYING NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS. 12 NEXEN INC. UNAUDITED CONSOLIDATED STATEMENT OF CASH FLOWS FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30 Cdn$ millions
THREE MONTHS NINE MONTHS ENDED SEPTEMBER 30 ENDED SEPTEMBER 30 2004 2003 2004 2003 --------------------------------------------------------------------------------------------------------------- Restated for Restated for Change in Change in Accounting Accounting Principles Principles Note 1 Note 1 OPERATING ACTIVITIES Net Income from Continuing Operations 220 178 555 680 Net Income from Discontinued Operations -- 3 -- 15 Charges and Credits to Income not Involving Cash (Note 8) 234 223 690 645 Exploration Expense 54 30 108 109 Changes in Non-Cash Working Capital (Note 8) (55) (125) (99) (165) Other (35) (13) 19 (42) ---------------------------------------------- 418 296 1,273 1,242 FINANCING ACTIVITIES Proceeds from (Repayment of) Term Credit Facilities, Net -- (9) -- 91 Repayment of Long-Term Debt (Note 4) -- -- (300) -- Proceeds from (Repayment of) Short-Term Borrowings, Net -- (19) -- (18) Redemption of Preferred Securities (Note 6) -- -- (289) -- Dividends on Preferred Securities -- (16) (3) (50) Dividends on Common Shares (13) (9) (39) (27) Issue of Common Shares 7 21 116 31 ---------------------------------------------- (6) (32) (515) 27 INVESTING ACTIVITIES Capital Expenditures Exploration and Development (362) (277) (1,017) (911) Proved Property Acquisitions -- -- -- (164) Chemicals, Corporate and Other (33) (9) (69) (22) Proceeds on Disposition of Assets 6 268 10 268 Changes in Non-Cash Working Capital (Note 8) 45 15 107 (16) Other (6) -- (20) -- ---------------------------------------------- (350) (3) (989) (845) EFFECT OF EXCHANGE RATE CHANGES ON CASH AND SHORT-TERM INVESTMENTS (35) 1 10 (129) ---------------------------------------------- INCREASE (DECREASE) IN CASH AND SHORT-TERM INVESTMENTS 27 262 (221) 295 CASH AND SHORT-TERM INVESTMENTS - BEGINNING OF PERIOD 839 92 1,087 59 ---------------------------------------------- CASH AND SHORT-TERM INVESTMENTS - END OF PERIOD 866 354 866 354 ==============================================
SEE ACCOMPANYING NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS. 13 NEXEN INC. UNAUDITED CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2004 AND SEPTEMBER 30, 2003 Cdn$ millions
CUMULATIVE PREFERRED FOREIGN AND CURRENCY SUBORDINATED COMMON CONTRIBUTED RETAINED TRANSLATION SECURITIES SHARES SURPLUS EARNINGS ADJUSTMENT --------------------------------------------------------------------------------------------------------------------------------- Restated for Change in Accounting Principles Note 1 DECEMBER 31, 2003 364 513 1 1,659 (119) Retroactive Adjustment for Change in Accounting Principles (Note 1) -- -- -- (28) -- Exercise of Stock Options -- 90 -- -- -- Issue of Common Shares -- 26 -- -- -- Redemption of Preferred Securities (Note 6) (331) -- -- -- -- Gain on Redemption of Preferred Securities, Net of Income Taxes (Note 6) -- -- -- 34 -- Net Income -- -- -- 555 -- Dividends on Preferred Securities, Net of Income Taxes -- -- -- (2) -- Dividends on Common Shares -- -- -- (39) -- Stock Option Expense prior to Modification to Tandem Options -- -- 2 -- -- Modification of Stock Options to Tandem Options (Note 6) -- -- (3) -- -- Translation Adjustment, Net of Income Taxes -- -- -- -- (29) ----------------------------------------------------------------------------- SEPTEMBER 30, 2004 33 629 -- 2,179 (148) ============================================================================= DECEMBER 31, 2002 724 440 -- 1,069 115 Retroactive Adjustment for Change in Accounting Principles (Note 1) -- -- -- (28) -- Exercise of Stock Options -- 12 -- -- -- Issue of Common Shares -- 19 -- -- -- Net Income -- -- -- 695 -- Dividends on Preferred Securities, Net of Income Taxes -- -- -- (31) -- Dividends on Common Shares -- -- -- (27) -- Translation Adjustment, Net of Income Taxes -- -- -- -- (180) ----------------------------------------------------------------------------- SEPTEMBER 30, 2003 724 471 -- 1,678 (65) =============================================================================
SEE ACCOMPANYING NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS. 14 NEXEN INC. NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS Cdn$ millions except as noted 1. ACCOUNTING POLICIES The Unaudited Consolidated Financial Statements are prepared in accordance with Canadian Generally Accepted Accounting Principles (GAAP). The impact of significant differences between Canadian and US GAAP on the Unaudited Consolidated Financial Statements is disclosed in Note 14. 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, 2004 and the results of our operations and our cash flows for the three and nine months ended September 30, 2004 and 2003. Management makes 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, including those related to litigation, asset retirement obligations, income taxes and 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. The results of operations and cash flows for the three months and nine months ended September 30, 2004 are not necessarily indicative of the results of operations or cash flows to be expected for the year ending December 31, 2004. These Unaudited Consolidated Financial Statements should be read in conjunction with our Audited Consolidated Financial Statements included in our 2003 Annual Report on Form 10-K. Except as described below, the accounting policies we follow are described in Note 1 of the Audited Consolidated Financial Statements included in our 2003 Annual Report on Form 10-K. CHANGE IN ACCOUNTING PRINCIPLES ASSET RETIREMENT OBLIGATIONS On January 1, 2004, we retroactively adopted the Canadian Institute of Chartered Accountants standard S.3110, ASSET RETIREMENT OBLIGATIONS. This new standard requires recognition of a liability for the future retirement obligations associated with our property, plant and equipment, which includes oil and gas wells and facilities, and chemicals plants. The asset retirement obligation is initially measured at fair value and capitalized to property, plant and equipment as an asset retirement cost. The asset retirement obligation accretes until the time the retirement obligation is expected to settle while the asset retirement cost is amortized over the useful life of the underlying property, plant and equipment. The amortization of the asset retirement cost and the accretion of the asset retirement obligation are included in depreciation, depletion and amortization (DD&A). Actual retirement costs are recorded against the obligation when incurred. Any difference between the recorded asset retirement obligation and the actual retirement costs incurred is recorded as a gain or loss in the period of settlement. Our total estimated undiscounted asset retirement obligations amount to $512 million ($514 million - December 31, 2003). We have discounted the total estimated asset retirement obligations using a weighted-average, credit-adjusted risk-free rate of 5.6%. Approximately $68 million included in our asset retirement obligations will be settled over the next five years. The remaining obligations settle beyond five years and will be funded by future cash flows from our operations. We own interests in assets for which the fair value of the asset retirement obligation cannot be reasonably determined because the assets currently have an indeterminate life. These assets include our interest in a gas plant and our interest in Syncrude's upgrader and sulphur pile. The asset retirement obligation for these assets will be recorded in the first year in which the lives of the assets are determinable. 15 We previously provided for dismantlement and site restoration costs on our oil and gas wells and facilities, and chemicals plants based on estimates established by current legislation and industry practices. We recorded a provision for these costs in DD&A based on proved reserves or estimated remaining asset lives. Upon adoption of the new standard, accounting rules require us to restate all prior periods presented to give effect to the change in accounting principles. The impact on net income for the three and nine months ended September 30, 2003 and the impact on our Audited Consolidated Balance Sheet at December 31, 2003, is shown below: UNAUDITED CONSOLIDATED STATEMENT OF INCOME FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2003
THREE MONTHS NINE MONTHS ---------------------------------------------------------------------------------------------------------- Depletion, Depreciation and Amortization as Reported 190 566 Less: Dismantlement and Site Restoration (13) (30) Plus: Asset Retirement Cost Amortization 6 14 Plus: Asset Retirement Obligation Accretion 7 16 -------------------------------- Depletion, Depreciation and Amortization as Restated 190 566 ================================
CONSOLIDATED BALANCE SHEET AS AT DECEMBER 31, 2003
AS REPORTED CHANGE AS RESTATED ---------------------------------------------------------------------------------------------------------- Property, Plant and Equipment 4,469 81 4,550 Asset Retirement Obligations - 305 305 Dismantlement and Site Restoration 179 (179) -- Future Income Tax Liabilities 724 (17) 707 Retained Earnings 1,659 (28) 1,631 ---------------------------------------------
RECLASSIFICATION Certain comparative figures have been reclassified to ensure consistency with current year presentation. 2. ACCOUNTS RECEIVABLE
SEPTEMBER 30 DECEMBER 31 2004 2003 ----------------------------------------------------------------------------------------- ---------------- Trade Marketing 1,169 1,078 Oil and Gas 289 263 Chemicals and Other 54 47 ------------------------------ 1,512 1,388 Non-Trade 53 50 ------------------------------ 1,565 1,438 Allowance for Doubtful Accounts (16) (15) ------------------------------ 1,549 1,423 ============================== 3. INVENTORIES AND SUPPLIES SEPTEMBER 30 DECEMBER 31 2004 2003 ---------------------------------------------------------------------------------------------------------- Finished Products Marketing 235 138 Oil and Gas 17 16 Chemicals and Other 5 12 ------------------------------ 257 166 Work in Process 4 6 Field Supplies 139 98 ------------------------------ 400 270 ==============================
16 4. LONG-TERM DEBT AND SHORT-TERM BORROWINGS
SEPTEMBER 30 DECEMBER 31 2004 2003 ---------------------------------------------------------------------------------------------------------- Unsecured Syndicated Term Credit Facilities -- -- Unsecured Redeemable Notes, due 2004 (a) -- 291 Unsecured Redeemable Debentures, due 2006(1) 96 98 Unsecured Redeemable Medium-Term Notes, due 2007 150 150 Unsecured Redeemable Medium-Term Notes, due 2008 125 125 Unsecured Redeemable Notes, due 2013 (US$500 million) 632 646 Unsecured Redeemable Notes, due 2028 (US$200 million) 253 258 Unsecured Redeemable Notes, due 2032 (US$500 million) 632 646 Unsecured Subordinated Debentures, due 2043 (US$435 million) 550 562 ------------------------------ 2,438 2,776 Less: Current Portion of Long-Term Debt -- (291) ------------------------------ 2,438 2,485 ==============================
Note: 1 Includes $50 million of principal that was effectively converted through a currency exchange contract to US$37 million. (a) UNSECURED REDEEMABLE NOTES, DUE 2004 In February 2004, our US$225 million of notes matured and we repaid the principal at par. (b) INTEREST EXPENSE
THREE MONTHS NINE MONTHS ENDED SEPTEMBER 30 ENDED SEPTEMBER 30 2004 2003 2004 2003 -------------------------------------------------------------------------------------------------------- Long-Term Debt 43 32 133 100 Other 3 3 9 7 ----------------------------------------------- Total 46 35 142 107 Less: Capitalized (11) (12) (27) (31) ----------------------------------------------- 35 23 115 76 ===============================================
Capitalized interest relates to and is included as part of the cost of our oil and gas property, plant and equipment. The capitalization rates are based on our weighted-average cost of borrowings. 17 5. DERIVATIVE INSTRUMENTS AND FINANCIAL RISK MANAGEMENT (a) CARRYING VALUE AND ESTIMATED FAIR VALUE OF DERIVATIVE INSTRUMENTS The carrying value, fair value, and unrecognized gains or losses on our outstanding derivatives and long-term financial assets and liabilities are:
Cdn$ millions SEPTEMBER 30, 2004 DECEMBER 31, 2003 ---------------------------------------------------------------------------------------------------------------------------- Carrying Fair Unrecognized Carrying Fair Unrecognized Net Assets/(Liabilities) Value Value Gain/(Loss) Value Value Gain/(Loss) ------------------------------------ ----------------------------------- Commodity Price Risk - Non-Trading Activities Future Sale of Oil and Gas Production -- -- -- -- (3) (3) Commodity Price Risk - Trading Activities Crude Oil and Natural Gas 112 112 -- 101 101 -- Future Sale of Gas Inventory -- (28) (28) -- (11) (11) Foreign Currency Risk 5 5 -- 5 4 (1) ------------------------------------ ----------------------------------- Total Derivatives 117 89 (28) 106 91 (15) ==================================== =================================== Financial Assets and Liabilities Long-Term Debt (2,438) (2,679) (241) (2,776) (2,997) (221) Preferred and Subordinated Securities (33) (34) (1) (364) (319) 45 ------------------------------------ ----------------------------------- (2,471) (2,713) (242) (3,140) (3,316) (176) ==================================== ===================================
The estimated fair value of all derivative instruments is based on quoted market prices and, if not available, on estimates from third-party brokers or dealers. The carrying value of cash and short-term investments, amounts receivable and short-term obligations approximates their fair value because the instruments are near maturity. (b) COMMODITY PRICE RISK MANAGEMENT NON-TRADING ACTIVITIES FUTURE SALE OF OIL AND GAS PRODUCTION In March 2003, we sold WTI and NYMEX gas forward contracts for the following 12 months to lock-in part of the return on the remaining 40% interest acquired in the Aspen field. The forward contracts fixed our oil and gas prices on the future sales at the contract prices for the hedged volumes, less applicable price differentials. These contracts expired in March 2004. TRADING ACTIVITIES CRUDE OIL AND NATURAL GAS We enter into physical purchase and sales contracts as well as financial commodity contracts to enhance our price realizations and lock-in our margins. The physical and financial commodity contracts (derivative contracts) are stated at market value. The $112 million fair value of the contracts has been recognized in net income. We have certain NYMEX futures contracts and swaps in place, which effectively lock-in our margins on the future sale of our natural gas inventory in storage. To maximize flexibility, we have not designated all of these futures contracts and swaps as accounting hedges. The gains and losses on these undesignated futures contracts and swaps have been recognized in income. We carry our marketing inventory in storage at the lower of cost and net realizable value, while our derivative contracts are stated at fair value. In the second and third quarters of 2004, the fair value of our storage positions increased while the fair value of the corresponding futures contracts decreased. Losses on our undesignated futures contracts have been recognized in net income. The related increase in fair value of our inventory ($41 million at September 30, 2004) will not be recognized in net income until the inventory in storage is sold. 18 FUTURE SALE OF GAS INVENTORY We have certain NYMEX futures contracts and swaps in place, which effectively lock-in our margins on the future sale of our natural gas inventory in storage. We have designated, in writing, some of these derivative contracts as accounting cash flow hedges of the future sale of our storage inventory. As a result, gains and losses on these designated futures contracts and swaps are recognized in net income when the inventory in storage is sold. The principal terms of these outstanding contracts and the unrecognized gains and losses at September 30, 2004 are:
HEDGED AVERAGE UNRECOGNIZED VOLUMES MONTH PRICE GAIN/(LOSS) --------------------------------------------------------------------------------------------------- (mmcf) (US$/mcf) (Cdn$ millions) NYMEX Natural Gas Futures 3,500 December 2004 6.71 (4) 5,740 January 2005 6.82 (9) 6,000 February 2005 6.56 (11) NYMEX Natural Gas Fixed Price Swaps 1,000 December 2004 7.01 (1) 2,200 January 2005 7.15 (2) 500 February 2005 7.09 (1) --------------- --------------- (28) ===============
(c) FOREIGN CURRENCY EXCHANGE RATE RISK Our sales and purchases of crude oil and natural gas are generally transacted in or referenced to the US dollar, as are most of the financial commodity contracts used by our marketing group. We enter into forward contracts to sell US dollars. When combined with certain commodity sales contracts, either physical or financial, these forward contracts allow us to lock-in our margins on the future sale of crude oil and natural gas. The fair value of our US dollar forward contracts at September 30, 2004 was $5 million. This fair value has been recognized in net income and settles within one year. (d) TOTAL CARRYING VALUE OF DERIVATIVE CONTRACTS Amounts related to derivative contracts held by our marketing group that have not been designated as accounting hedges have been recorded at fair value as we use mark-to-market accounting. The amounts are as follows:
SEPTEMBER 30 DECEMBER 31 Cdn$ millions 2004 2003 -------------------------------------------------------------------------------------------------- Accounts Receivable 168 102 Deferred Charges and Other Assets(1) 93 63 ------------------------------ Total Derivative Contract Assets 261 165 ============================== Accounts Payable and Accrued Liabilities 106 34 Deferred Credits and Liabilities(1) 38 25 ------------------------------ Total Derivative Contract Liabilities 144 59 ============================== Total Derivative Contract Net Assets 117 106 ==============================
Note: 1 These derivative contracts settle beyond 12 months and are considered non-current. 6. SHAREHOLDERS' EQUITY (a) PREFERRED SECURITIES In February 2004, we redeemed our US$217 million preferred securities at par. The realized foreign exchange gain of $34 million, net of income taxes, for the difference between the carrying value and the settlement amount was included in retained earnings. (b) STOCK BASED COMPENSATION In May 2004, our shareholders approved modifications to our stock option plan to include a cash feature (tandem option plan). The tandem options give the holders a right to either purchase common shares at the exercise price or to receive cash payments equal to the excess of the market value of the common shares over the exercise price. Similar to our stock appreciation rights, we use the intrinsic-value method to recognize compensation expense associated with our tandem options. Obligations are accrued on a graded vesting basis and represent the difference between the market value of our common shares and the exercise price of the options. The obligations are revalued each reporting period based on the change in the market value of our common shares and the number of options outstanding. 19 Upon modification of the stock option plan, we were required to recognize an obligation for our tandem options. This obligation represented the difference between the market value of our common shares and the weighted-average exercise price of the options. As a result, we recognized an obligation of $85 million for the graded vested portion of the 6.3 million outstanding options on June 30, 2004. In the second quarter, a one-time, non-cash charge of $82 million ($54 million, net of tax) was included in general and administrative expense, net of $3 million previously expensed in respect of our original stock options. (c) DIVIDENDS Dividends per common share for the three months ended September 30, 2004 were $0.10 (2003 - $0.075). Dividends per common share for the nine months ended September 30, 2004 were $0.30 (2003 - $0.225). 7. EARNINGS PER COMMON SHARE We calculate basic earnings per common share from continuing operations using net income from continuing operations less dividends on preferred securities, net of income taxes, divided by the weighted-average number of common shares outstanding. We calculate basic earnings per common share using net income attributable to common shareholders and the weighted-average number of common shares outstanding. We calculate diluted earnings per common share from continuing operations and 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) 2004 2003 2004 2003 -------------------------------------------------------------------------------------------------------------- Weighted-average number of common shares outstanding 129.0 123.8 128.4 123.4 Shares issuable pursuant to stock options 6.3 8.9 6.7 5.1 Shares to be purchased from proceeds of stock options (4.9) (7.4) (5.0) (4.1) ------------------------------------------- Weighted-average number of diluted common shares outstanding 130.4 125.3 130.1 124.4 ===========================================
In calculating the weighted-average number of diluted common shares outstanding for the three and nine months ended September 30, 2004, all options were included because their exercise price was less than the quarterly average common share market price in the period. For the three months ended September 30, 2003, we excluded 36,000 options, and for the nine months ended September 30, 2003, we excluded 4.2 million options, because their exercise price was greater than the average common share market price during those periods. During the periods presented, outstanding stock options were the only potential dilutive instruments. 8. CASH FLOWS (a) CHARGES AND CREDITS TO INCOME NOT INVOLVING CASH
THREE MONTHS NINE MONTHS ENDED SEPTEMBER 30 ENDED SEPTEMBER 30 2004 2003 2004 2003 -------------------------------------------------------------------------------------------------------------- Depreciation, Depletion and Amortization 181 190 541 566 Stock Based Compensation 11 2 100 4 Gain on Disposition of Assets (4) -- (4) -- Future Income Taxes 37 31 58 51 Non-Cash Items included in Discontinued Operations -- 7 -- 35 Other 9 (7) (5) (11) ------------------------------------------- 234 223 690 645 ===========================================
20 (b) CHANGES IN NON-CASH WORKING CAPITAL
THREE MONTHS NINE MONTHS ENDED SEPTEMBER 30 ENDED SEPTEMBER 30 2004 2003 2004 2003 ----------------------------------------------------------------------------------------------------------- Operating Activities Accounts Receivable 17 55 (134) (33) Inventories and Supplies (68) (1) (145) 15 Other Current Assets (18) (25) 37 (23) Accounts Payable and Accrued Liabilities 14 (142) 152 (110) Accrued Interest Payable -- (12) (9) (14) ----------------------------------------------- (55) (125) (99) (165) Investing Activities Accounts Payable and Accrued Liabilities 45 15 107 (16) ----------------------------------------------- Total (10) (110) 8 (181) =============================================== (c) OTHER CASH FLOW INFORMATION THREE MONTHS NINE MONTHS ENDED SEPTEMBER 30 ENDED SEPTEMBER 30 2004 2003 2004 2003 ----------------------------------------------------------------------------------------------------------- Interest Paid 41 45 140 117 Income Taxes Paid 67 48 182 155 ----------------------------------------------- 9. MARKETING AND OTHER THREE MONTHS NINE MONTHS ENDED SEPTEMBER 30 ENDED SEPTEMBER 30 2004 2003 2004 2003 ----------------------------------------------------------------------------------------------------------- Marketing Revenue, Net 144 121 403 416 Interest 3 2 8 6 Foreign Exchange Gains/(Losses) (9) 4 6 8 Other(1) 5 4 18 21 Gain on Disposition of Assets(2) 4 -- 4 -- ----------------------------------------------- 147 131 439 451 ===============================================
Notes: 1 Other income for the three months and nine months ended September 30, 2004 includes $2 million (2003 - $nil) and $9 million (2003 - $12 million), respectively of business interruption proceeds from our insurers. The proceeds result from damage sustained in the Gulf of Mexico during tropical storm Isidore and hurricane Lili in the third and fourth quarters of 2002. 2 Gain on disposition resulted from the sale of minor oil and gas properties. 21 10. DISCONTINUED OPERATIONS On August 28, 2003, we sold certain non-core conventional light oil properties in southeast Saskatchewan in Canada. Net proceeds were $268 million and there was no gain or loss on the sale. The results of operations from these properties are detailed below and shown as discontinued operations in our Unaudited Consolidated Statement of Income.
THREE MONTHS NINE MONTHS ENDED SEPTEMBER 30 ENDED SEPTEMBER 30 2004 2003 2004 2003 ---------------------------------------------------------------------------------------------------------- Revenues Net Sales -- 14 -- 66 Expenses Operating -- 4 -- 16 Depreciation, Depletion and Amortization -- 3 -- 20 Exploration -- -- -- 1 ---------------------------------------------- Income before Income Taxes -- 7 -- 29 Future Income Taxes -- 4 -- 14 ---------------------------------------------- Net Income from Discontinued Operations -- 3 -- 15 ============================================== Earnings Per Common Share ($/share) Basic (Note 7) -- 0.02 -- 0.12 ============================================== Diluted (Note 7) -- 0.02 -- 0.12 ==============================================
11. COMMITMENTS AND CONTINGENCIES As described in Note 10 to the Audited Consolidated Financial Statements included in our 2003 Annual Report on 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. 12. PENSION AND OTHER POST RETIREMENT BENEFITS (a) NET PENSION EXPENSE RECOGNIZED UNDER OUR DEFINED BENEFIT PENSION PLANS
THREE MONTHS NINE MONTHS ENDED SEPTEMBER 30 ENDED SEPTEMBER 30 2004 2003 2004 2003 ---------------------------------------------------------------------------------------------------------- Nexen Cost of Benefits Earned by Employees 2 2 6 6 Interest Cost on Benefits Earned 3 3 9 9 Expected Return on Plan Assets (3) (2) (9) (6) Net Amortization and Deferral -- -- -- -- ---------------------------------------------- 2 3 6 9 ---------------------------------------------- Syncrude Cost of Benefits Earned by Employees 1 1 3 3 Interest Cost on Benefits Earned 1 1 3 3 Expected Return on Plan Assets (1) (1) (3) (3) Net Amortization and Deferral -- -- -- -- ---------------------------------------------- 1 1 3 3 ---------------------------------------------- Total 3 4 9 12 ==============================================
(b) EMPLOYER FUNDING CONTRIBUTIONS Our expected total funding contributions for 2004 disclosed in Note 11(e) to the Audited Consolidated Financial Statements in our 2003 Annual Report on Form 10-K have not changed for both our Nexen defined benefit pension plan and our share of Syncrude's defined benefit pension plan. 22 13. OPERATING SEGMENTS AND RELATED INFORMATION Nexen is involved in activities relating to Oil and Gas, Syncrude and Chemicals in various geographic locations as described in Note 15 to the Audited Consolidated Financial Statements included in our 2003 Annual Report on Form 10-K. THREE MONTHS ENDED SEPTEMBER 30, 2004
Corporate and (Cdn$ millions) Oil and Gas Syncrude(1) Chemicals Other Total ----------------------------------------------------------------------------------------------------------------------------------- United Other Yemen Canada States Australia(2) Countries(3) Marketing(4) -------------------------------------------------------------- Net Sales 247 160 219 -- 19 4 90 98 -- 837 Marketing and Other 1 4(5) 3 -- -- 144 -- 1 (6)(6) 147 ----------------------------------------------------------------------------------------------------- Total Revenues 248 164 222 -- 19 148 90 99 (6) 984 Less: Expenses Operating 27 39 39 -- 3 4 31 62 -- 205 Transportation and Other -- 4 -- -- -- 106 3 9 -- 122 General and Administrative -- 6 4 -- 10 13 -- 8 16 57 Depreciation, Depletion and Amortization 39 49 68 -- 5 3 4 9 4 181 Exploration 1 4 38 -- 11(7) -- -- -- -- 54 Interest -- -- -- -- -- -- -- -- 35 35 ----------------------------------------------------------------------------------------------------- Income (Loss) from Continuing Operations before Income Taxes 181 62 73 -- (10) 22 52 11 (61) 330 ===================================================================================================== Less: Provision for Income Taxes(8) 110 Add: Net Income from Discontinued Operations -- ------ Net Income 220 ====== Identifiable Assets 619 1,793 1,652 40 214 1,666(9) 857 497 785(10) 8,123 ===================================================================================================== Capital Expenditures Development and Other 71 120 40 -- 29 1 57 25 7 350 Exploration 4 8 25 -- 8 -- -- -- -- 45 ----------------------------------------------------------------------------------------------------- 75 128 65 -- 37 1 57 25 7 395 ===================================================================================================== Property, Plant and Equipment Cost 2,032 3,235 2,304 198 362 155 972 814 188 10,260 Less: Accumulated DD&A 1,581 1,576 1,027 198 225 61 152 404 86 5,310 ----------------------------------------------------------------------------------------------------- Net Book Value 451 1,659 1,277 -- 137 94 820 410 102 4,950 =====================================================================================================
Notes: 1 Syncrude is considered a mining operation for US reporting purposes. Property, plant and equipment at September 30, 2004 includes mineral rights of $6 million. 2 There were no crude oil liftings in Australia during the third quarter. 3 Includes results of operations from producing activities in Nigeria and Colombia. 4 We are required to carry our gas inventory at the lower of cost or net realizable value. At September 30, 2004, we have unrecognized gains on this inventory of $41 million as discussed in Note 5. 5 Includes a $4 million gain on disposition resulting from the sale of minor oil and gas properties. 6 Includes interest income of $3 million and foreign exchange losses of $9 million. 7 Includes exploration activities primarily in Nigeria and Colombia. 8 Includes Yemen cash taxes of $65 million. 9 Approximately 84% of Marketing's identifiable assets are accounts receivable and inventories. 10 Approximately 73% of Corporate and Other's identifiable assets are cash and short-term instruments. 23 NINE MONTHS ENDED SEPTEMBER 30, 2004
Corporate and (Cdn$ millions) Oil and Gas Syncrude(1) Chemicals Other Total ----------------------------------------------------------------------------------------------------------------------------------- United Other Yemen Canada States Australia Countries(2) Marketing(3) ------------------------------------------------------------ Net Sales 679 461 581 49 53 10 243 283 -- 2,359 Marketing and Other 3 6(4) 10 -- -- 403 -- 3 14(5) 439 ----------------------------------------------------------------------------------------------------- Total Revenues 682 467 591 49 53 413 243 286 14 2,798 Less: Expenses Operating 80 118 81 31 6 12 90 178 -- 596 Transportation and Other 2 10 -- -- -- 338 8 28 3 389 General and Administrative(6) 2 41 28 -- 39 38 -- 25 74 247 Depreciation, Depletion and Amortization 123 148 185 9 14 8 13 28 13 541 Exploration 2 13 53 -- 40(7) -- -- -- -- 108 Interest -- -- -- -- -- -- -- -- 115 115 ----------------------------------------------------------------------------------------------------- Income (Loss) from Continuing Operations before Income Taxes 473 137 244 9 (46) 17 132 27 (191) 802 ===================================================================================================== Less: Provision for Income Taxes(8) 247 Add: Net Income from Discontinued Operations -- ------ Net Income 555 ====== Identifiable Assets 619 1,793 1,652 40 214 1,666(9) 857 497 785(10) 8,123 ===================================================================================================== Capital Expenditures Development and Other 176 307 199 -- 44 3 155 47 19 950 Exploration 9 20 74 -- 33 -- -- -- -- 136 ----------------------------------------------------------------------------------------------------- 185 327 273 -- 77 3 155 47 19 1,086 ===================================================================================================== Property, Plant and Equipment Cost 2,032 3,235 2,304 198 362 155 972 814 188 10,260 Less: Accumulated DD&A 1,581 1,576 1,027 198 225 61 152 404 86 5,310 ----------------------------------------------------------------------------------------------------- Net Book Value 451 1,659 1,277 -- 137 94 820 410 102 4,950 =====================================================================================================
Notes: 1 Syncrude is considered a mining operation for US reporting purposes. Property, plant and equipment at September 30, 2004 includes mineral rights of $6 million. 2 Includes results of operations from producing activities in Nigeria and Colombia. 3 We are required to carry our gas inventory at the lower of cost or net realizable value. At September 30, 2004, we have unrecognized gains on this inventory of $41 million as discussed in Note 5. 4 Includes a $4 million gain on disposition resulting from the minor sale of oil and gas properties. 5 Includes interest income of $8 million and foreign exchange gains of $6 million. 6 Includes a one-time charge of $82 million related to the modification of our stock option plan as discussed in Note 6. 7 Includes exploration activities primarily in Nigeria, Colombia and Equatorial Guinea. 8 Includes Yemen cash taxes of $168 million. 9 Approximately 84% of Marketing's identifiable assets are accounts receivable and inventories. 10 Approximately 73% of Corporate and Other's identifiable assets are cash and short-term instruments. 24 THREE MONTHS ENDED SEPTEMBER 30, 2003 (1)
Corporate and (Cdn$ millions) Oil and Gas Syncrude(2) Chemicals Other Total -------------------------------------------------------------------------------------------------------------------------------- United Other Yemen Canada(3) States Australia Countries(4) Marketing ---------------------------------------------------------- Net Sales 201 144 170 19 15 7 66 94 -- 716 Marketing and Other 1 1 1 -- -- 121 -- 1 6(5) 131 -------------------------------------------------------------------------------------------------- Total Revenues 202 145 171 19 15 128 66 95 6 847 Less: Expenses Operating 23 38 20 9 3 5 27 59 -- 184 Transportation and Other -- -- (2)(6) -- -- 98 3 8 -- 107 General and Administrative -- 7 2 -- 6 9 1 6 13 44 Depreciation, Depletion and Amortization 41 56 53 6 13 3 3 10 5 190 Exploration 2 8 9 -- 11(7) -- -- -- -- 30 Interest -- -- -- -- -- -- -- -- 23 23 -------------------------------------------------------------------------------------------------- Income (Loss) from Continuing Operations before Income Taxes 136 36 89 4 (18) 13 32 12 (35) 269 ================================================================================================== Less: Provision for Income Taxes(8) 91 Add: Net Income from Discontinued Operations 3 ------ Net Income 181 ====== Identifiable Assets 597 1,872 1,669 39 158 991(9) 658 471 219 6,674 ================================================================================================== Capital Expenditures Development and Other 48 44 50 -- 7 -- 47 2 7 205 Exploration 11 20 34 -- 16 -- -- -- -- 81 Proved Property Acquisitions -- -- -- -- -- -- -- -- -- -- -------------------------------------------------------------------------------------------------- 59 64 84 -- 23 -- 47 2 7 286 ================================================================================================== Property, Plant and Equipment Cost 1,913 2,903 2,177 209 321 156 766 771 185 9,401 Less: Accumulated DD&A 1,524 1,144 874 202 212 51 144 379 90 4,620 -------------------------------------------------------------------------------------------------- Net Book Value 389 1,759 1,303 7 109 105 622 392 95 4,781 ==================================================================================================
Notes: 1 Restated to give effect to a change in accounting principles (see Note 1). 2 Syncrude is considered a mining operation for US reporting purposes. Property, plant and equipment at September 30, 2003 includes mineral rights of $6 million. 3 Excludes results of our non-core conventional light oil assets in southeast Saskatchewan that were sold. These results are shown as discontinued operations (see Note 10). 4 Includes results of operations from producing activities in Nigeria and Colombia. 5 Includes interest income of $2 million and foreign exchange gains of $4 million. 6 Includes the recovery of previously incurred property damage costs from our insurers. The costs were incurred to repair damage caused by Hurricane Lili in 2002. 7 Includes exploration activities primarily in Nigeria and Colombia. 8 Includes Yemen cash taxes of $51 million. 9 Approximately 78% of Marketing's identifiable assets are accounts receivable and inventories. 25 NINE MONTHS ENDED SEPTEMBER 30, 2003 (1)
Corporate and (Cdn$ millions) Oil and Gas Syncrude(2) Chemicals Other Total ------------------------------------------------------------------------------------------------------------------------------- United Other Yemen Canada(3) States Australia Countries(4) Marketing ---------------------------------------------------------- Net Sales 620 475 549 64 51 18 187 284 -- 2,248 Marketing and Other 4 2 14 -- -- 416 -- 1 14(5) 451 -------------------------------------------------------------------------------------------------- Total Revenues 624 477 563 64 51 434 187 285 14 2,699 Less: Expenses Operating 65 107 66 30 13 17 91 181 -- 570 Transportation and Other 3 -- 1 -- -- 319 7 27 -- 357 General and Administrative 3 22 8 -- 16 28 1 16 32 126 Depreciation, Depletion and Amortization 124 167 158 19 29 9 10 37 13 566 Exploration 5 31 42 1 30(6) -- -- -- -- 109 Interest -- -- -- -- -- -- -- -- 76 76 -------------------------------------------------------------------------------------------------- Income (Loss) from Continuing Operations before Income Taxes 424 150 288 14 (37) 61 78 24 (107) 895 ================================================================================================== Less: Provision for Income Taxes(7) 215 Add: Net Income from Discontinued Operations 15 ------ Net Income 695 ====== Identifiable Assets 597 1,872 1,669 39 158 991(8) 658 471 219 6,674 ================================================================================================== Capital Expenditures Development and Other 154 200 177 1 24 -- 136 6 16 714 Exploration 19 47 105 1 47 -- -- -- -- 219 Proved Property Acquisitions -- -- 164(9) -- -- -- -- -- -- 164 -------------------------------------------------------------------------------------------------- 173 247 446 2 71 -- 136 6 16 1,097 ================================================================================================== Property, Plant and Equipment Cost 1,913 2,903 2,177 209 321 156 766 771 185 9,401 Less: Accumulated DD&A 1,524 1,144 874 202 212 51 144 379 90 4,620 -------------------------------------------------------------------------------------------------- Net Book Value 389 1,759 1,303 7 109 105 622 392 95 4,781 ==================================================================================================
Notes: 1 Restated to give effect to a change in accounting principles (see Note 1). 2 Syncrude is considered a mining operation for US reporting purposes. Property, plant and equipment at September 30, 2003 includes mineral rights of $6 million. 3 Excludes results of our non-core conventional light oil assets in southeast Saskatchewan that were sold. These results are shown as discontinued operations (see Note10). 4 Includes results of operations from producing activities in Nigeria and Colombia. 5 Includes interest income of $6 million and foreign exchange gains of $8 million. 6 Includes exploration activities primarily in Nigeria, Colombia and Brazil. 7 Includes Yemen cash taxes of $150 million and a $76 million future tax recovery due to tax rate reductions for Canadian resource activities. 8 Approximately 78% of Marketing's identifiable assets are accounts receivable and inventories. 9 On March 27, 2003 we acquired the residual 40% interest in Aspen in the Gulf of Mexico for US $109 million. 14. 26 14. DIFFERENCES BETWEEN CANADIAN AND US GENERALLY ACCEPTED ACCOUNTING PRINCIPLES The Unaudited Consolidated Financial Statements have been prepared in accordance with Canadian GAAP. The US GAAP Unaudited Consolidated Statement of Income and Balance Sheet and summaries of differences from Canadian GAAP are as follows: (a) UNAUDITED CONSOLIDATED STATEMENT OF INCOME - US GAAP FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30
THREE MONTHS NINE MONTHS ENDED SEPTEMBER 30 ENDED SEPTEMBER 30 (Cdn$ millions, except per share amounts) 2004 2003 2004 2003 ----------------------------------------------------------------------------------------------------------------------- REVENUES Net Sales 837 716 2,359 2,248 Marketing and Other (iv); (xii); (xiii) 142 143 441 464 ---------------------------------------------- 979 859 2,800 2,712 ---------------------------------------------- EXPENSES Operating (vi) 206 184 601 570 Transportation and Other (i); (xii) 118 107 394 357 General and Administrative (xi) 57 44 211 126 Depreciation, Depletion and Amortization (iii) 192 199 573 604 Exploration 54 30 108 109 Interest (i) 35 39 118 126 ---------------------------------------------- 662 603 2,005 1,892 ---------------------------------------------- INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES 317 256 795 820 ---------------------------------------------- PROVISION FOR INCOME TAXES Current 73 60 189 164 Deferred (i); (iv); (vi); (x); (xiii) 36 29 52 111 ---------------------------------------------- 109 89 241 275 ---------------------------------------------- NET INCOME FROM CONTINUING OPERATIONS BEFORE CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLES 208 167 554 545 Net Loss from Discontinued Operations (iii) -- (19) -- (7) Cumulative Effect of Changes in Accounting Principles, Net of Income Taxes (ix); (xiii) -- (11) -- (48) ---------------------------------------------- NET INCOME - US GAAP(1) 208 137 554 490 ============================================== EARNINGS PER COMMON SHARE ($/share) Basic (Note 7) Net Income from Continuing Operations 1.61 1.35 4.32 4.42 Net Loss from Discontinued Operations -- (0.15) -- (0.06) Cumulative Effect of Changes in Accounting Principles -- (0.09) -- (0.39) ---------------------------------------------- 1.61 1.11 4.32 3.97 ============================================== Diluted (Note 7) Net Income from Continuing Operations 1.60 1.33 4.26 4.39 Net Loss from Discontinued Operations -- (0.15) -- (0.06) Cumulative Effect of Changes in Accounting Principles -- (0.09) -- (0.39) ---------------------------------------------- 1.60 1.09 4.26 3.94 ==============================================
Note: 1 RECONCILIATION OF CANADIAN AND US GAAP NET INCOME
THREE MONTHS NINE MONTHS ENDED SEPTEMBER 30 ENDED SEPTEMBER 30 (Cdn$ millions) 2004 2003 2004 2003 ----------------------------------------------------------------------------------------------------------------------- Net Income - Canadian GAAP 220 181 555 695 Impact of US Principles, Net of Income Taxes: Depreciation, Depletion and Amortization (iii) (11) (9) (32) (37) Dividends on Preferred Securities (i) -- (10) (2) (31) Future Income Taxes (x) -- -- -- (76) Issue Costs on Preferred Securities Redeemed (i) -- -- (6) -- Cumulative Effect of Changes in Accounting Principles (ix); -- (11) -- (48) (xiii) Fair Value of Preferred Securities (xiii) -- 5 4 5 Stock Based Compensation included in Retained Earnings (xi) -- -- 36 -- Loss on Disposition (iii) -- (22) -- (22) Other (iv); (vi) (1) 3 (1) 4 ---------------------------------------------- Net Income - US GAAP 208 137 554 490 ==============================================
27 (b) UNAUDITED CONSOLIDATED BALANCE SHEET - US GAAP
SEPTEMBER 30 DECEMBER 31 (Cdn$ millions, except share amounts) 2004 2003 --------------------------------------------------------------------------------------------------------------------- ASSETS CURRENT ASSETS Cash and Short-Term Investments 866 1,087 Accounts Receivable 1,549 1,423 Inventories and Supplies 400 270 Other 42 79 -------------------------------- Total Current Assets 2,857 2,859 -------------------------------- PROPERTY, PLANT AND EQUIPMENT Net of Accumulated Depreciation, Depletion and Amortization of $5,729 (December 31, 2003 - $5,330) (iii); (vi); (ix) 4,959 4,583 GOODWILL 36 36 DEFERRED INCOME TAX ASSETS 88 108 DEFERRED CHARGES AND OTHER ASSETS (i); (vii) 147 117 -------------------------------- 8,087 7,703 ================================ LIABILITIES AND SHAREHOLDERS' EQUITY CURRENT LIABILITIES Current Portion of Long-Term Debt -- 575 Accounts Payable and Accrued Liabilities (iv) 1,796 1,418 Accrued Interest Payable 37 44 Dividends Payable 13 12 -------------------------------- Total Current Liabilities 1,846 2,049 -------------------------------- LONG-TERM DEBT (ii); (vii); (xiii) 2,425 2,472 DEFERRED INCOME TAX LIABILITIES (i) - (xiii) 714 676 ASSET RETIREMENT OBLIGATIONS 309 305 DEFERRED CREDITS AND LIABILITIES (viii) 115 70 SHAREHOLDERS' EQUITY Common Shares, no par value Authorized: Unlimited Outstanding: 2004 - 129,018,817 shares 2003 - 125,606,107 shares 629 513 Contributed Surplus -- 1 Retained Earnings (i); (iii); (iv); (vi); (ix); (x); (xi); (xiii) 2,139 1,660 Accumulated Other Comprehensive Income (i); (ii); (iv); (v); (viii) (90) (43) -------------------------------- Total Shareholders' Equity 2,678 2,131 -------------------------------- COMMITMENTS AND CONTINGENCIES 8,087 7,703 ================================
(c) UNAUDITED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME - US GAAP FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30
THREE MONTHS NINE MONTHS ENDED SEPTEMBER 30 ENDED SEPTEMBER 30 (Cdn$ millions) 2004 2003 2004 2003 -------------------------------------------------------------------------------------------------------------------- Net Income - US GAAP 208 137 554 490 Other Comprehensive Income, Net of Income Taxes: Translation Adjustment (i); (ii); (v) (49) (2) (35) (89) Unrealized Mark-to-Market Gain/(Loss) (iv) (18) 5 (12) 4 ------------------------------------------------ Comprehensive Income 141 140 507 405 ================================================
28 (d) UNAUDITED CONSOLIDATED STATEMENT OF CASH FLOWS Under US principles, dividends on preferred securities of $nil and $3 million for the three and nine months ended September 30, 2004, respectively (September 30, 2003 - $16 million and $50 million) that are included in financing activities would be reported in operating activities. Under US principles, geological and geophysical costs of $15 million and $40 million for the three and nine months ended September 30, 2004, respectively (September 30, 2003 - $10 million and $34 million) that are included in investing activities would be reported in operating activities. NOTES: i. Under US principles, we were required to classify our preferred securities as long-term debt rather than shareholders' equity. As a result: o dividends of $3 million in the first quarter were included in interest expense, with the related income tax of $1 million included in the provision for income taxes; o pre-tax issue costs of $10 million were included in deferred charges and other assets, rather than as an after-tax charge to retained earnings; and o for the three and nine months ended September 30, 2004, foreign-currency translation losses of $nil and $8 million respectively were included in accumulated other comprehensive income (AOCI). In February 2004, we redeemed at par US$217 million of preferred securities. Under Canadian principles, a foreign exchange gain of $34 million, net of income tax, was recognized in retained earnings. Under US principles, this foreign exchange gain had been included in AOCI. Unamortized issue costs of $10 million ($6 million, net of income taxes) were included in transportation and other in the first quarter. ii. Under US principles, all of our subordinated securities are classified as long-term debt. As a result, the $33 million equity component has been included in long-term debt. iii. Under US principles, the liability method of accounting for income taxes was adopted in 1993. In Canada, the liability method was adopted in 2000. In 1997, we acquired certain oil and gas assets and the amount paid for these assets differed from the tax basis acquired. Under US principles, this difference was recorded as a deferred tax liability with an increase to property, plant and equipment rather than a charge to retained earnings. As a result: o additional depreciation, depletion and amortization of $11 million and $32 million was included in net income for the three and nine months ended September 30, 2004, respectively; and o property, plant and equipment is higher under US GAAP by $39 million. During the third quarter of 2003, some of these assets were sold as described in Note 10. With the carrying value of these assets higher under US GAAP, the sale resulted in a loss on disposition of $22 million, net of income taxes of $10 million. This loss was included in our net loss from discontinued operations disclosed on the Unaudited Consolidated Statement of Income - US GAAP. iv. Under US principles, all derivative instruments are recognized on the balance sheet as either an asset or a liability measured at fair value. Changes in the fair value of derivatives are recognized in earnings unless specific hedge criteria are met. CASH FLOW HEDGES Changes in the fair value of derivatives that are designated as cash flow hedges are recognized in earnings in the same period as the hedged item. Any fair value change in a derivative before that period is recognized on the balance sheet. The effective portion of that change is recognized in other comprehensive income with any ineffectiveness recognized in net income. FUTURE SALE OF OIL AND GAS PRODUCTION: Included in accounts payable at December 31, 2003, was a $3 million loss on the forward contracts we used to hedge the commodity price risk on the future sale of a portion of our production from the Aspen field as described in Note 5. These contracts expired in March 2004. The losses ($2 million, net of income taxes), deferred in AOCI at December 31, 2003, were recognized in net sales. 29 FUTURE SALE OF GAS INVENTORY: Included in accounts payable at December 31, 2003, was $11 million of losses on the futures and basis swap contracts we used to hedge the commodity price risk on the future sale of our gas inventory as described in Note 5. These contracts effectively lock-in profits on our stored gas volumes. Losses of $8 million ($5 million, net of income taxes) related to the effective portion and deferred in AOCI at December 31, 2003, were recognized in marketing and other. Additionally, losses of $3 million ($2 million, net of income taxes), related to the ineffective portion, were recognized in marketing and other under Canadian GAAP. Under US GAAP, the ineffective portion was recognized in net income in 2003. At September 30, 2004, losses of $28 million were included in accounts payable. The $27 million ($18 million, net of income taxes) effective portion has been deferred in AOCI until the underlying gas inventory is sold. The losses will be reclassified to marketing and other as they settle over the next 12 months. Additionally, losses of $1 million related to the ineffective portion were included in marketing and other during the quarter. FAIR VALUE HEDGES Both the derivative instrument and the underlying commitment are recognized on the balance sheet at their fair value. The change in fair value of both are reflected in earnings. At September 30, 2004, we had no fair value hedges in place. v. Under US principles, exchange gains and losses arising from the translation of our net investment in self-sustaining foreign operations are included in comprehensive income. Additionally, exchange gains and losses, net of income taxes, from the translation of our US-dollar long-term debt designated as a hedge of our foreign net investment are included in comprehensive income. Cumulative amounts are included in AOCI in the Unaudited Consolidated Balance Sheet. vi. Under Canadian principles, we defer certain development costs and all pre-operating revenues and costs to property, plant and equipment. Under US principles, these costs have been included in operating expenses. As a result: o operating expenses include pre-operating costs of $1 million and $5 million ($3 million, net of income taxes) for the three and nine months ended September 30, 2004, respectively; and o property, plant and equipment is lower under US GAAP by $11 million. vii. Under US principles, discounts on long-term debt are classified as a reduction of long-term debt rather than as deferred charges and other assets. Discounts of $45 million have been included in long-term debt. viii. Under US principles, the amount by which our accrued pension cost is less than the unfunded accumulated benefit obligation is included in AOCI and accrued pension liabilities. This amount was $2 million at September 30, 2004 (December 31, 2003 - $2 million). ix. On January 1, 2003 we adopted FASB Statement No. 143, ACCOUNTING FOR ASSET RETIREMENT OBLIGATIONS (FAS 143) for US GAAP reporting purposes. We adopted the equivalent Canadian standard for asset retirement obligations on January 1, 2004 as described in Note 1. These standards are consistent except for the adoption date. This change in accounting policy has been reported as a cumulative effect adjustment in the Unaudited Consolidated Statement of Income as a loss of $37 million, net of income taxes of $25 million, on January 1, 2003. x. Under US principles, enacted tax rates are used to calculate deferred income taxes, whereas under Canadian GAAP, substantively enacted tax rates are used. Substantively enacted changes in Canadian federal income tax rates created a $76 million deferred income tax recovery during the second quarter of 2003. xi. As described in Note 6 (b), our existing stock option plan was modified to a tandem option plan. An obligation of $85 million was recognized for these tandem options. This resulted in a one-time, non-cash charge to net income of $54 million, net of tax in the second quarter of 2004. Under US principles, the modification of our stock option plan is accounted for by providing us with credit for the pro-forma expense previously disclosed with respect to the stock options modified. The related pro-forma expense was $36 million, which is accounted for as an adjustment to retained earnings with a corresponding decrease to our one-time charge to net income. xii. Under US principles, gains and losses on the disposition of assets are shown as other expense. 30 xiii. In May 2003, FASB issued Statement No. 150, ACCOUNTING FOR CERTAIN INSTRUMENTS WITH CHARACTERISTICS OF BOTH LIABILITIES AND EQUITY that requires certain financial instruments, including our preferred securities, to be valued at fair value with changes in fair value recognized through net income. The change in fair value of our preferred securities up to June 30, 2003 increased the carrying value of our long-term debt by $16 million and was recognized as a loss of $11 million, net of income taxes of $5 million. This was reported as a cumulative effect of a change in an accounting principle at the beginning of the third quarter of 2003. The fair value of our preferred securities decreased by $8 million ($5 million, net of income taxes) in the third quarter of 2003 and this gain was included in marketing and other. A gain of $4 million for the change in fair value up to the redemption date of our preferred securities was included in marketing and other in the first quarter of 2004. 31