EX-99 2 ex99-1form8k_q106.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 ------------------------------------------------------------------------------ N E W S R E L E A S E ------------------------------------------------------------------------------ For immediate release NEXEN REPORTS STRONG CASH FLOW AND MAJOR PROJECTS ON TRACK FIRST QUARTER HIGHLIGHTS: o MAJOR PROJECTS CONTINUE ON SCHEDULE AND ON BUDGET--PRODUCTION BEFORE ROYALTIES EXPECTED TO GROW 50% TO BETWEEN 300,000 AND 350,000 BOE/D IN 2007 o SUCCESSFUL WELL AT ALAMINOS CANYON BLOCK 856 IN THE GULF OF MEXICO o KNOTTY HEAD SIDETRACK WELL SUCCESSFULLY CONCLUDED--GROSS RECOVERABLE RESOURCE ESTIMATE 200 TO 500 MMBOE o ETTRICK DEVELOPMENT SANCTIONED--EXPECTED TO ADD 16,000 BOE/D TO OUR 2008 PRODUCTION o CASH FLOW OF $2.57 PER SHARE o RECORDED NON-CASH TAX EXPENSE OF $277 MILLION TO REFLECT INCREASE IN UK SUPPLEMENTAL TAX o PRODUCTION BEFORE ROYALTIES AVERAGES 222,000 BOE/D THREE MONTHS ENDED THREE MONTHS ENDED MARCH 31 DECEMBER 31 ---------------------------------------- (Cdn$ millions) 2006 2005 2005 ------------------------------------------------------------------------------- Production (mboe/d)(1) Before Royalties 222 260 225 After Royalties 159 183 165 Net Sales 980 916 1,073 Cash Flow from Operations(2) 673 520 772 Per Common Share ($/share)(2) 2.57 2.00 2.96 Net Income (Loss) (79) 37 300 Per Common Share ($/share) (0.30) 0.14 1.15 Capital Expenditures 753 599 731 ------------------------------------------------------------------------------- (1) Production includes our share of Syncrude oil sands. US investors should read the Cautionary Note to US Investors at the end of this release. (2) For reconciliation of this non-GAAP measure see Cash Flow from Operations on pg. 7. CALGARY, ALBERTA, APRIL 27, 2006 - Strong commodity prices and an outstanding contribution by marketing resulted in $673 million of cash flow. We recorded a loss of $79 million in the quarter. Excluding the non-cash tax expense of $277 million in the United Kingdom and after-tax stock-based compensation expense of $92 million, adjusted earnings were $290 million. We believe these adjusted earnings more accurately reflect the results of operations for the quarter. Our marketing division generated excellent results during the quarter, recognizing $166 million of pre-tax income. We generated this income in a number of ways. We used our storage and transportation infrastructure to move gas to markets. In addition, we utilized our infrastructure positions to take advantage of location and time spreads. Volatile natural gas markets in North America also presented excellent trading opportunities as weather and the impact of last season's hurricanes in the Gulf of 1 Mexico caused significant fluctuations in natural gas prices, especially between various producing and consuming regions. In a December 2005 pre-budget announcement, the United Kingdom government announced that it intended to increase the supplemental corporate tax applicable to North Sea oil and gas companies from 10% to 20%, effective January 1, 2006. Legislation to give effect to this tax increase was introduced to the UK parliament during the quarter. This increased tax rate has increased our future income taxes and resulted in a non-cash tax expense of $277 million ($1.06/share) in the quarter. We also recognized $139 million ($92 million after tax, $0.35/share) of stock-based compensation expense, resulting from a 16% increase in our share price during the quarter that added $2.3 billion in shareholder value. Approximately 26% of this expense was in cash, while the balance represents the change in value of our accrued stock-based compensation. Exploration expense totaled $103 million ($68 million after tax) for the quarter. It includes the cost of seismic and unsuccessful drilling at Zanzibar and Black Cat in the North Sea, Pathfinder in the Gulf of Mexico and Ukot South offshore West Africa. "Overall I am pleased with the quarter," commented Charlie Fischer, Nexen's President and Chief Executive Officer. "All of our core businesses performed well, our key development projects are on track and our marketing group enjoyed another great quarter."
OIL AND GAS PRODUCTION PRODUCTION BEFORE ROYALTIES PRODUCTION AFTER ROYALTIES Crude Oil, NGLs and Q1 2006 Q4 2005 Q1 2006 Q4 2005 Natural Gas (mboe/d) ------------------------------------------------------------------------------------------ Yemen 102 108 54 60 North Sea 20 22 20 22 Canada 40 39 33 31 United States 39 35 34 31 Other Countries 6 5 5 5 Syncrude 15 16 13 16 ----------------------------------------------------------------- TOTAL 222 225 159 165 -----------------------------------------------------------------
Our first quarter production averaged 222,000 boe/d (159,000 boe/d after royalties), consistent with the fourth quarter of 2005, despite mechanical problems at the Scott platform in the North Sea and reduced volumes at Block 51 in Yemen due to drilling delays. In the Gulf of Mexico, production increased as volumes were restored following hurricanes Rita and Katrina. However, the increase was less than expected as approximately 10% of our Gulf production remains shut-in due to damage to third-party infrastructure. We expect to have this production on stream during the third quarter of this year. "Our quarterly production met our expectation," said Fischer. "With incremental volumes in the second half of the year from Syncrude Stage 3 and first production from Buzzard in the North Sea late in the year, we continue to expect annual production to average between 220,000 and 240,000 boe/d before royalties." "This year is setting us up for outstanding growth in 2007 and beyond," continued Fischer. "Our major projects are progressing on time and on budget and we are on track to increase production after royalties by approximately 50% over the next 18 months. With low royalties on much of our new production, we expect equally impressive growth in cash flow, assuming prices remain strong." 2 LONG LAKE PROJECT ON SCHEDULE AND ON BUDGET At Long Lake, we have completed engineering, procurement and development drilling. We are nearing completion of module fabrication and assembly and are well advanced in field construction. Approximately 78% of total project costs have been committed and they are in-line with our original cost estimates. All SAGD wells have been drilled and 82% have been completed. SAGD module fabrication is almost complete with 85% of modules on site. Upgrader module fabrication is advancing with over 75% of our modules completed and approximately 27% of modules on site. Our SAGD construction is over 55% complete while the upgrader is just under 40% complete. To date, we have been successful in attracting labour to our site allowing the project to remain on time. Although labour productivity to date has been 20% below expectation, a large portion of our workforce has just been mobilized on our site and we expect to improve productivity as the workforce is familiarized with the site and their scope of work. If labour productivity remains unchanged for the remainder of the project, we believe costs can be largely managed within our contingency. Given the advanced state of the overall project, we believe the risk of a material cost overrun is low. We are on track to begin steam injection in late 2006 and to begin operating the upgrader in the second half of 2007. Production capacity for this phase of Long Lake is approximately 60,000 bbls/d (30,000 bbls/d net to Nexen) of premium synthetic crude. Our plan is to expand oil sands production to approximately 240,000 bbls/d (120,000 bbls/d net to Nexen) over the next 10 years in phases of 60,000 bbls/d (30,000 bbls/d net to Nexen) using the same technology and design as installed at Long Lake. We are currently progressing Phase 2 development. We have ordered several major vessels, completed our largest core hole drilling and seismic program, and are finalizing regulatory applications. With sanctioning anticipated in 2008, Phase 2 is expected to commence synthetic crude oil production in 2011. BUZZARD ON TRACK FOR FIRST OIL IN LATE 2006 Our Buzzard development in the North Sea remains on schedule and on budget. It is over 90% complete and first oil is scheduled for late this year. During the quarter, we began drilling the water injection wells, continued drilling the development wells and substantially completed fabrication of the utilities and production decks. These decks are scheduled to be installed this summer. At its peak, Buzzard should add approximately 85,000 boe/d to our production and generate between $1.6 and $1.7 billion of annual pre-tax cash flow, assuming oil prices of US$50/bbl for WTI. We have a 43.2% operated working interest in Buzzard. ETTRICK DEVELOPMENT BEGINS During the quarter, we commenced development of the Ettrick field in the North Sea where we have an 80% operated working interest. The development consists of three production wells and three water injectors tied back to a leased floating production, storage and offloading (FPSO) vessel. Design capacities of the FPSO are 30,000 bbls/d of oil processing, 35 mmcf/d of gas compression and 55,000 bbls/d of water injection. We plan to begin drilling the development wells in 2007 and install and commission the FPSO in 2008. Production from the field is expected to begin in early 2008, with our share reaching approximately 16,000 boe/d. 3 SYNCRUDE STAGE 3 EXPANSION NEARING COMPLETION The Syncrude Stage 3 expansion is nearing completion with commissioning well underway. The expansion is expected to be on stream by mid-year, adding approximately 8,000 bbls/d of production capacity, net to Nexen. COALBED METHANE (CBM) DEVELOPMENT CONTINUES In Canada, we continue to develop the first commercial CBM project in Mannville coals. We currently have eight rigs drilling and are constructing gas processing facilities. Two of these facilities have been completed and two more are expected to be finalized in the third quarter. When fully operational, these four plants will have processing capacity of 94 mmcf/d (38 mmcf/d net to Nexen). Our CBM production is currently at 4 mmcf/d. We expect this to increase to over 30 mmcf/d by year-end and continue to grow as we add further processing capacity. We are targeting to add at least 150 mmcf/d of production by 2011, generating attractive full-cycle rates of return at gas prices significantly lower than the current market. "We are very excited about CBM," stated Fischer. "Our longer term production target is based on developing less than half of our CBM lands giving us significant opportunity to further develop and sustain our growth in CBM." DRILLING UPDATE--SUCCESS AT ALAMINOS CANYON BLOCK 856 In the Gulf of Mexico, the drilling of the exploration well Alaminos Canyon Block 856 No. 1 has been successfully completed. The block is located approximately 140 miles east of the southern Texas coast and is immediately adjacent to the Great White discovery. The well was drilled by the operator, Total E&P USA, Inc., in 7,600 feet of water to a total depth of 14,600 feet and encountered approximately 290 feet of oil pay in two oil-bearing zones. An appraisal well will be drilled to further assess the extent of the accumulation. We have a 30% non-operated interest in the block and a 10% non-operated interest in the Tobago discovery, located approximately seven miles east. In the Gulf, we also completed a sidetrack well to delineate the Knotty Head discovery. The well was drilled downdip with a bottom-hole location approximately 4,500 feet to the south of the original wellbore. The sidetrack encountered all reservoirs seen in the discovery well and contained approximately 400 feet of net oil pay. Based on drilling results to date, our estimate of the recoverable resource from the field is between 200 and 500 million equivalent barrels. We believe the majority of this resource is located on our acreage. Additional appraisal work is being planned to further define the prospect, determine ultimate reserves and formulate an optimal development plan. We have a 25% operated interest here. For the remainder of the year, we expect to drill 15 to 17 exploration wells and have rigs lined up for all but one of these wells. In the Gulf, we plan to drill seven or eight additional exploration wells. In the North Sea, we have two exploration wells planned for the second half of this year. On Block 51 in Yemen, we are appraising a discovery at BAK-K, located approximately 65 kilometers northwest of our processing facilities. We are encouraged by the presence of oil on this part of the block and plan to drill two or three additional wells during the year to further evaluate and delineate this prospect. "With our portfolio of assets throughout the world, we are building capacity to be successful and sustainable over the long term," commented Fischer. "Our major development projects will add significant growth in 2007. And projects like Knotty Head in the Gulf of Mexico, OPL-222 offshore West Africa, CBM and future phases of Long Lake will ensure production growth well beyond 2010." 4 QUARTERLY DIVIDEND The Board of Directors has declared the regular quarterly dividend of $0.05 per common share payable July 1, 2006, to shareholders of record on June 10, 2006. Nexen Inc. is an independent, Canadian-based global energy company, listed on the Toronto and New York stock exchanges under the symbol NXY. We are uniquely positioned for growth in the North Sea, deep-water Gulf of Mexico, the Athabasca oil sands of Alberta, the Middle East and offshore West Africa. We add value for shareholders through successful full-cycle oil and gas exploration and development and leadership in ethics, integrity and environmental protection. For further information, please contact: KEVIN FINN Vice President, Investor Relations (403) 699-5166 GRANT DREGER, CA Manager, Investor Relations (403) 699-5273 801 - 7th Ave SW Calgary, Alberta, Canada T2P 3P7 www.nexeninc.com CONFERENCE CALL Charlie Fischer, President and CEO, and Marvin Romanow, Executive Vice-President and CFO, will host a conference call to discuss our financial and operating results and expectations for the future. Date: April 27, 2006 Time: 12:30 p.m. Mountain Time (2:30 p.m. Eastern Time) To listen to the conference call, please call one of the following: 416-641-6105 (Toronto) 866-696-5895 (North American toll-free) 800-8989-6323 (Global toll-free) A replay of the call will be available for two weeks starting at 2:30 p.m. Mountain Time, by calling 416-695-5800 (Toronto) or 800-408-3053 (toll-free) passcode 3183222 followed by the pound sign. A live and on demand webcast 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, AND INCLUDE STATEMENTS RELATING TO FUTURE PRODUCTION ASSOCIATED WITH OUR COALBED METHANE, LONG LAKE, SYNCRUDE, NORTH SEA AND WEST AFRICA PROJECTS. 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 5 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; RESULTS OF LITIGATION, ARBITRATION OR REGULATORY PROCEEDINGS; 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 OR ABILITY TO EXECUTE ON THE DISPOSITION OF ASSETS OR BUSINESSES, 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 2005 ANNUAL REPORT ON FORM 10-K FOR FURTHER DISCUSSION OF THE RISK FACTORS. CAUTIONARY NOTE TO US 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. IN ADDITION, UNDER SEC REGULATIONS, THE SYNCRUDE OIL SANDS OPERATIONS ARE CONSIDERED MINING ACTIVITIES RATHER THAN OIL AND GAS ACTIVITIES. PRODUCTION, RESERVES AND RELATED MEASURES IN THIS RELEASE INCLUDE RESULTS FROM THE COMPANY'S SHARE OF SYNCRUDE. 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). HOWEVER, 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. PLEASE READ THE "SPECIAL NOTE TO CANADIAN INVESTORS" IN ITEM 7A IN OUR 2005 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 OR TO CONVEY SPECIFIC ADVICE. RESERVE ESTIMATION IS HIGHLY TECHNICAL AND REQUIRES PROFESSIONAL COLLABORATION AND JUDGMENT. THE DIFFERENCES BETWEEN SEC REQUIREMENTS AND NI 51-101 MAY BE MATERIAL. 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. 6 NEXEN INC. FINANCIAL HIGHLIGHTS Three Months Ended March 31 (Cdn$ millions) 2006 2005 ------------------------------------------------------------------------------- Net Sales (1) 980 916 Cash Flow from Operations (1) 673 520 Per Common Share ($/share) 2.57 2.00 Net Income (Loss) (1) (79) 37 Per Common Share ($/share) (0.30) 0.14 Capital Expenditures (2) 753 599 Net Debt (3) 3,832 4,348 Common Shares Outstanding (millions of shares) 261.7 260.0 ------------------------------------------------------------------------------- (1) Includes discontinued operations as discussed in Note 15 to our Unaudited Consolidated Financial Statements. (2) Includes oil and gas development, exploration, and expenditures for other property, plant and equipment. (3) Net Debt is defined as long-term debt less working capital. CASH FLOW FROM OPERATIONS (1) Three Months Ended March 31 (Cdn$ millions) 2006 2005 ------------------------------------------------------------------------------- Oil & Gas and Syncrude Yemen (2) 221 189 Canada (3) 54 84 United States 142 169 United Kingdom 113 77 Other Countries 21 10 Marketing 175 36 Syncrude 25 23 ------------------ 751 588 Chemicals 22 23 ------------------ 773 611 Interest and Other Corporate Items (58) (71) Income Taxes (4) (42) (20) ------------------ Cash Flow from Operations (1) 673 520 ================== (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 Ended March 31 (Cdn$ millions) 2006 2005 --------------------------------------------------------------------------- Cash Flow from Operating Activities 734 442 Changes in Non-Cash Working Capital (73) 53 Other 31 42 Amortization of Premium for Crude Oil Put Options (19) (17) ----------------- Cash Flow from Operations 673 520 ================= Weighted-average Number of Common Shares Outstanding (millions of shares) 261.6 259.4 ----------------- Cash Flow from Operations Per Common Share ($/share) 2.57 2.00 ================= (2) After in-country cash taxes of $67 million for the three months ended March 31, 2006 (2005 - $59 million). (3) Includes discontinued operations as discussed in Note 15 to our Unaudited Consolidated Financial Statements. (4) Excludes in-country cash taxes in Yemen. 7 NEXEN INC. PRODUCTION VOLUMES (BEFORE ROYALTIES) (1) Three Months Ended March 31 2006 2005 ------------------------------------------------------------------------------- Crude Oil and NGLs (mbbls/d) Yemen 102.4 114.3 Canada (2) 22.2 34.7 United States 19.3 28.5 United Kingdom 15.7 14.9 Other Countries 5.8 5.9 Syncrude (3) 14.8 11.4 ------------------ 180.2 209.7 ------------------ Natural Gas (mmcf/d) Canada (2) 106 143 United States 120 127 United Kingdom 23 29 ------------------ 249 299 ------------------ Total Production (mboe/d) 222 260 ================== PRODUCTION VOLUMES (AFTER ROYALTIES) Three Months Ended March 31 2006 2005 ------------------------------------------------------------------------------- Crude Oil and NGLs (mbbls/d) Yemen 53.7 57.7 Canada (2) 17.8 27.5 United States 17.0 25.2 United Kingdom 15.7 14.9 Other Countries 5.3 5.4 Syncrude (3) 13.4 11.3 ------------------ 122.9 142.0 ------------------ Natural Gas (mmcf/d) Canada (2) 89 111 United States 102 108 United Kingdom 23 29 ------------------ 214 248 ------------------ Total Production (mboe/d) 159 183 ================== Notes: (1) We have presented production volumes before royalties as we measure our performance on this basis consistent with other Canadian oil and gas companies. (2) Includes discontinued operations as discussed in Note 15 to our Unaudited Consolidated Financial Statements. (3) Considered a mining operation for US reporting purposes. 8
NEXEN INC. OIL AND GAS PRICES AND CASH NETBACK (1) TOTAL Quarters - 2006 Quarters - 2005 YEAR (all dollar amounts in Cdn$ ------------------------------------------------------------------- unless noted) 1st 1st 2nd 3rd 4th 2005 -------------------------------------------------------------------------------------------------------- PRICES: WTI Crude Oil (US$/bbl) 63.48 49.85 53.17 63.52 59.78 56.58 Nexen Average - Oil (Cdn$/bbl) 63.11 51.33 55.45 68.99 60.89 58.98 NYMEX Natural Gas (US$/mmbtu) 7.87 6.48 6.95 9.69 12.86 8.99 Nexen Average - Gas (Cdn$/mcf) 8.71 6.98 7.39 9.68 12.18 8.89 -------------------------------------------------------------------------------------------------------- NETBACKS: CANADA - LIGHT OIL AND NGLS Sales (mbbls/d) -- 11.5 12.0 4.7 -- 7.1 Price Received ($/bbl) -- 55.37 58.06 67.04 -- 58.55 Royalties & Other -- 12.08 10.98 14.75 -- 12.69 Operating Costs -- 9.77 6.29 6.45 -- 7.97 -------------------------------------------------------------------------------------------------------- Netback -- 33.52 40.79 45.84 -- 37.89 -------------------------------------------------------------------------------------------------------- CANADA - HEAVY OIL Sales (mbbls/d) 21.9 22.7 22.1 21.2 21.1 21.8 Price Received ($/bbl) 30.00 26.15 30.87 47.53 34.41 34.62 Royalties & Other 6.25 6.05 8.47 11.80 7.96 8.17 Operating Costs 11.47 10.55 10.86 11.42 12.55 10.40 -------------------------------------------------------------------------------------------------------- Netback 12.28 9.55 11.54 24.31 13.90 16.05 -------------------------------------------------------------------------------------------------------- CANADA - TOTAL OIL Sales (mbbls/d) 21.9 34.2 34.1 25.9 21.1 28.9 Price Received ($/bbl) 30.00 35.99 40.47 51.05 34.41 40.51 Royalties & Other 6.25 8.12 9.39 12.39 7.96 9.28 Operating Costs 11.47 10.29 9.25 10.53 12.55 9.80 -------------------------------------------------------------------------------------------------------- Netback 12.28 17.58 21.83 28.13 13.90 21.43 -------------------------------------------------------------------------------------------------------- CANADA - NATURAL GAS Sales (mmcf/d) 106 143 141 111 102 124 Price Received ($/mcf) 7.65 5.80 6.30 8.19 10.75 7.51 Royalties & Other 1.17 1.17 1.21 1.26 1.63 1.33 Operating Costs 1.27 0.71 0.74 0.80 1.21 1.00 -------------------------------------------------------------------------------------------------------- Netback 5.21 3.92 4.35 6.13 7.91 5.18 -------------------------------------------------------------------------------------------------------- YEMEN Sales (mbbls/d) 102.6 115.0 112.6 116.8 108.3 113.2 Price Received ($/bbl) 68.32 54.38 58.08 72.04 63.39 62.07 Royalties & Other 32.73 27.08 26.30 33.20 28.06 28.71 Operating Costs 3.88 3.33 3.72 3.46 4.03 3.63 In-country Taxes 7.20 5.67 6.91 8.61 7.47 7.17 -------------------------------------------------------------------------------------------------------- Netback 24.51 18.30 21.15 26.77 23.83 22.56 -------------------------------------------------------------------------------------------------------- SYNCRUDE Sales (mbbls/d) 14.8 11.4 16.9 17.2 16.3 15.5 Price Received ($/bbl) 69.95 65.15 66.93 78.93 70.79 71.00 Royalties & Other 6.68 0.65 0.65 0.78 0.72 0.71 Operating Costs 40.12 39.91 20.76 23.22 28.36 26.95 -------------------------------------------------------------------------------------------------------- Netback 23.15 24.59 45.52 54.93 41.71 43.34 --------------------------------------------------------------------------------------------------------
(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 - 2006 Quarters - 2005 YEAR (all dollar amounts in Cdn$ ------------------------------------------------------------------- unless noted) 1st 1st 2nd 3rd 4th 2005 ------------------------------------------------------------------------------------------------------- UNITED STATES Crude Oil: Sales (mbbls/d) 19.3 28.5 23.0 18.4 18.9 22.2 Price Received ($/bbl) 63.73 50.90 54.96 68.30 60.32 57.63 Natural Gas: Sales (mmcf/d) 120 127 120 122 98 116 Price Received ($/mcf) 9.06 8.32 9.01 11.57 13.95 10.56 Total Sales Volume (mboe/d) 39.3 49.6 43.0 38.7 35.2 41.6 Price Received ($/boe) 58.97 50.48 54.54 68.91 71.14 60.26 Royalties & Other 7.96 6.48 7.31 9.60 9.47 8.06 Operating Costs 8.47 4.91 5.70 6.95 8.47 6.35 ------------------------------------------------------------------------------------------------------- Netback 42.54 39.09 41.53 52.36 53.20 45.85 ------------------------------------------------------------------------------------------------------- UNITED KINGDOM Crude Oil: Sales (mbbls/d) 17.6 17.5 11.7 10.4 15.6 13.8 Price Received ($/bbl) 69.02 54.53 59.02 65.87 64.75 60.55 Natural Gas: Sales (mmcf/d) 24 26 15 13 30 21 Price Received ($/mcf) 11.82 6.92 5.45 4.84 11.26 7.86 Total Sales Volume (mboe/d) 21.5 21.9 14.3 12.6 20.6 17.3 Price Received ($/boe) 69.37 51.92 54.31 59.39 65.42 57.83 Royalties & Other -- -- -- -- -- -- Operating Costs 11.24 12.59 21.69 19.30 9.95 14.90 ------------------------------------------------------------------------------------------------------- Netback 58.13 39.33 32.62 40.09 55.47 42.93 ------------------------------------------------------------------------------------------------------- OTHER COUNTRIES Sales (mbbls/d) 5.8 5.6 6.2 5.3 6.3 5.9 Price Received ($/bbl) 58.81 46.63 53.70 65.82 72.75 59.96 Royalties & Other 4.71 3.68 6.01 5.07 5.96 5.23 Operating Costs 2.27 2.32 9.27 3.20 7.03 5.55 ------------------------------------------------------------------------------------------------------- Netback 51.83 40.63 38.42 57.55 59.76 49.18 ------------------------------------------------------------------------------------------------------- COMPANY-WIDE Oil and Gas Sales (mboe/d) 223.5 261.6 250.4 235.2 225.2 243.0 Price Received ($/boe) 61.11 49.55 53.45 67.09 62.97 57.97 Royalties & Other 18.04 14.94 15.22 20.21 16.66 16.70 Operating Costs 8.78 6.94 7.18 7.21 8.18 7.36 In-country Taxes 3.31 2.49 3.10 4.28 3.59 3.34 ------------------------------------------------------------------------------------------------------- Netback 30.98 25.18 27.95 35.39 34.54 30.57 -------------------------------------------------------------------------------------------------------
(1) Defined as average sales price less royalties and other, operating costs, and in-country taxes in Yemen. 10
NEXEN INC. UNAUDITED CONSOLIDATED STATEMENT OF INCOME (LOSS) FOR THE THREE MONTHS ENDED MARCH 31 Cdn$ millions, except per share amounts 2006 2005 ------------------------------------------------------------------------------------------------------------------------ REVENUES AND OTHER INCOME Net Sales 980 856 Marketing and Other (Note 14) 426 67 --------------------------- 1,406 923 --------------------------- EXPENSES Operating 250 213 Depreciation, Depletion, Amortization and Impairment 266 239 Transportation and Other 260 203 General and Administrative 214 181 Exploration 103 27 Interest (Note 7) 9 34 --------------------------- 1,102 897 --------------------------- INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES 304 26 --------------------------- PROVISION FOR INCOME TAXES Current 109 79 Future (Note 18) 271 (72) --------------------------- 380 7 --------------------------- NET INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE NON-CONTROLLING INTERESTS (76) 19 Net Income Attributable to Non-Controlling Interests 3 - --------------------------- NET INCOME (LOSS) FROM CONTINUING OPERATIONS (79) 19 Net Income from Discontinued Operations (Note 15) - 18 --------------------------- NET INCOME (LOSS) (79) 37 =========================== EARNINGS (LOSS) PER COMMON SHARE FROM CONTINUING OPERATIONS ($/share) Basic (Note 12) (0.30) 0.07 =========================== Diluted (Note 12) (0.30) 0.07 =========================== EARNINGS (LOSS) PER COMMON SHARE ($/share) Basic (Note 12) (0.30) 0.14 =========================== Diluted (Note 12) (0.30) 0.14 ===========================
SEE ACCOMPANYING NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS. 11
NEXEN INC. UNAUDITED CONSOLIDATED BALANCE SHEET Cdn$ millions, except share amounts March 31 December 31 2006 2005 ----------------------------------------------------------------------------------------------------------- ASSETS CURRENT ASSETS Cash and Cash Equivalents 30 48 Restricted Cash 124 70 Accounts Receivable (Note 3) 2,374 3,151 Inventories and Supplies (Note 4) 651 504 Other 42 51 ---------------------------------- Total Current Assets 3,221 3,824 ---------------------------------- PROPERTY, PLANT AND EQUIPMENT Net of Accumulated Depreciation, Depletion, Amortization and Impairment of $5,705 (December 31, 2005 - $5,468) 10,011 9,594 FUTURE INCOME TAX ASSETS 562 410 DEFERRED CHARGES AND OTHER ASSETS (Note 5) 325 398 GOODWILL 379 364 ---------------------------------- 14,498 14,590 ================================== LIABILITIES AND SHAREHOLDERS' EQUITY CURRENT LIABILITIES Short-Term Borrowings (Note 7) 36 - Accounts Payable and Accrued Liabilities 3,274 3,710 Accrued Interest Payable 39 55 Dividends Payable 13 13 ---------------------------------- Total Current Liabilities 3,362 3,778 ---------------------------------- LONG-TERM DEBT (Note 7) 3,691 3,687 FUTURE INCOME TAX LIABILITIES 2,385 1,960 ASSET RETIREMENT OBLIGATIONS (Note 8) 605 590 DEFERRED CREDITS AND OTHER LIABILITIES (Note 9) 429 479 NON-CONTROLLING INTERESTS (Note 2) 85 88 SHAREHOLDERS' EQUITY (Note 11) Common Shares, no par value Authorized: Unlimited Outstanding: 2006 - 261,674,080 shares 2005 - 261,140,571 shares 763 732 Contributed Surplus 2 2 Retained Earnings 3,343 3,435 Cumulative Foreign Currency Translation Adjustment (167) (161) ---------------------------------- Total Shareholders' Equity 3,941 4,008 ---------------------------------- COMMITMENTS, CONTINGENCIES AND GUARANTEES (Note 16) 14,498 14,590 ==================================
SEE ACCOMPANYING NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS. 12
NEXEN INC. UNAUDITED CONSOLIDATED STATEMENT OF CASH FLOWS FOR THE THREE MONTHS ENDED MARCH 31 Cdn$ millions 2006 2005 ------------------------------------------------------------------------------------------------------------------------ OPERATING ACTIVITIES Net Income (Loss) from Continuing Operations (79) 19 Net Income from Discontinued Operations - 18 Charges and Credits to Income not Involving Cash (Note 13) 668 473 Exploration Expense 103 27 Changes in Non-Cash Working Capital (Note 13) 73 (53) Other (31) (42) ---------------------------- 734 442 FINANCING ACTIVITIES Proceeds from (Repayment of) Term Credit Facilities, Net (4) 138 Proceeds from Long-Term Debt - 1,253 Repayment of Long-Term Debt - (1,241) Proceeds from (Repayment of) Short-Term Borrowings, Net 35 (10) Dividends on Common Shares (13) (13) Issue of Common Shares 13 32 Other (7) (16) ---------------------------- 24 143 INVESTING ACTIVITIES Capital Expenditures Exploration and Development (719) (594) Proved Property Acquisitions (3) (1) Chemicals, Corporate and Other (31) (4) Proceeds on Disposition of Assets - 2 Changes in Restricted Cash (54) - Changes in Non-Cash Working Capital (Note 13) 23 (14) Other 7 16 ---------------------------- (777) (595) EFFECT OF EXCHANGE RATE CHANGES ON CASH AND CASH EQUIVALENTS 1 7 ---------------------------- DECREASE IN CASH AND CASH EQUIVALENTS (18) (3) CASH AND CASH EQUIVALENTS - BEGINNING OF PERIOD 48 73 ---------------------------- CASH AND CASH EQUIVALENTS - END OF PERIOD 30 70 ============================
SEE ACCOMPANYING NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS. 13
NEXEN INC. UNAUDITED CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY FOR THE THREE MONTHS ENDED MARCH 31 Cdn$ millions 2006 2005 ------------------------------------------------------------------------------------------------------------- COMMON SHARES Balance at January 1 732 637 Issue of Common Shares 5 15 Exercise of Stock Options 8 17 Previously Recognized Liability Relating to Stock Options Exercised 18 15 ------------------------- Balance at March 31 763 684 ========================= CONTRIBUTED SURPLUS Balance at January 1 2 - Stock-Based Compensation Expense - 1 ------------------------- Balance at March 31 2 1 ========================= RETAINED EARNINGS Balance at January 1 3,435 2,335 Net Income (Loss) (79) 37 Dividends on Common Shares (13) (13) ------------------------- Balance at March 31 3,343 2,359 ========================= CUMULATIVE FOREIGN CURRENCY TRANSLATION ADJUSTMENT Balance at January 1 (161) (105) Translation Adjustment, Net of Income Taxes (6) 10 ------------------------- Balance at March 31 (167) (95) =========================
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 Our Unaudited Consolidated Financial Statements are prepared in accordance with Canadian Generally Accepted Accounting Principles (GAAP). The impact of significant differences between Canadian and United States (US) GAAP on the Unaudited Consolidated Financial Statements is disclosed in Note 20. In the opinion of management, the Unaudited Consolidated Financial Statements contain all adjustments of a normal and recurring nature necessary to present fairly Nexen Inc.'s (Nexen, we or our) financial position at March 31, 2006 and the results of our operations and our cash flows for the three months ended March 31, 2006 and 2005. We make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the Unaudited Consolidated Financial Statements, and revenues and expenses during the reporting period. Our management reviews these estimates, including those related to accruals, litigation, environmental and 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 ended March 31, 2006 are not necessarily indicative of the results of operations or cash flows to be expected for the year ending December 31, 2006. The note disclosure requirements for annual consolidated financial statements provide additional disclosure to that required for interim consolidated financial statements. Accordingly, these Unaudited Consolidated Financial Statements should be read in conjunction with our Audited Consolidated Financial Statements included in our 2005 Annual Report on Form 10-K. The accounting policies we follow are described in Note 1 of the Audited Consolidated Financial Statements included in our 2005 Annual Report on Form 10-K. RECLASSIFICATION Certain comparative figures have been reclassified to ensure consistency with current period presentation. 2. CANEXUS INCOME FUND In June 2005, our board of directors approved a plan to monetize our chemicals operations through the creation of an income trust and the issuance of trust units in an initial public offering. This initial public offering closed on August 18, 2005, with Canexus Income Fund (Canexus) issuing 30 million units at a price of $10 per unit for gross proceeds of $300 million ($284 million, net of underwriters' commissions). Concurrent with the closing of the offering, Canexus acquired a 36.5% interest in Canexus Limited Partnership (Canexus LP) using the net proceeds from the initial public offering. Canexus LP acquired Nexen's chemicals business for approximately $1 billion, comprised of the net proceeds from Canexus' initial public offering and $200 million (US$167 million) of bank debt, plus the issuance of 52.3 million exchangeable limited partnership units (Exchangeable LP Units) of Canexus LP. At that time, the Exchangeable LP Units held by Nexen represented a 63.5% interest in Canexus LP. The Exchangeable LP Units held by Nexen are exchangeable on a one-for-one basis for trust units of Canexus. As a result, the Exchangeable LP Units owned by Nexen were exchangeable into 52.3 million trust units which represented 63.5% of the outstanding trust units of Canexus assuming exchange of the Exchangeable LP Units. On September 16, 2005, the underwriters of the initial public offering exercised a portion of their over-allotment option to purchase 1.75 million trust units at $10 per unit for gross proceeds of $18 million ($17 million, net of underwriters' commissions). As a result, Nexen exchanged 1.75 million of its Exchangeable LP Units for $17 million in net proceeds. After this exchange, Nexen has a 61.4% interest in Canexus LP represented by 50.5 million Exchangeable LP Units. The initial public offering, together with the exercise of the over-allotment, resulted in total net proceeds to Nexen of $301 million. These transactions diluted our interest in our chemicals operations. As a result of this dilution, we recorded a gain of $193 million during the third quarter of 2005. 15 We have the right to nominate a majority of the members of the board of Canexus Limited, the corporation with responsibility for the strategic management and operational decisions of Canexus and Canexus LP. Nexen has nominated two representatives to the 10-member board of Canexus Limited. Since we have retained effective control of our chemicals business, the results, assets and liabilities of this business have been included in these financial statements. The non-Nexen ownership interests in our chemicals business are shown as non-controlling interests. During the quarter, $7 million of distributions were paid to non-Nexen ownership interests. 3. ACCOUNTS RECEIVABLE
March 31 December 31 (Cdn$ millions) 2006 2005 ------------------------------------------------------------------------------------------------------------------------------ Trade Marketing 1,652 2,400 Oil and Gas 565 614 Chemicals and Other 72 48 ------------------------------- 2,289 3,062 Non-Trade 92 96 ------------------------------- 2,381 3,158 Allowance for Doubtful Accounts (7) (7) ------------------------------- Total 2,374 3,151 ===============================
4. INVENTORIES AND SUPPLIES
March 31 December 31 (Cdn$ millions) 2006 2005 ------------------------------------------------------------------------------------------------------------------------------ Finished Products Marketing 468 320 Oil and Gas 1 11 Chemicals and Other 11 15 ------------------------------- 480 346 Work in Process 6 6 Field Supplies 165 152 ------------------------------- Total 651 504 ===============================
5. DEFERRED CHARGES AND OTHER ASSETS
March 31 December 31 (Cdn$ millions) 2006 2005 ------------------------------------------------------------------------------------------------------------------------------ Long-Term Marketing Derivative Contracts (Note 10) 181 232 Deferred Financing Costs 62 63 Asset Retirement Remediation Fund 14 14 Crude Oil Put Options - 4 Other 68 85 ------------------------------- Total 325 398 ===============================
6. SUSPENDED WELL COSTS The following table shows the changes in capitalized exploratory well costs included in property, plant and equipment during the three month period ended March 31, 2006 and the year ended December 31, 2005, and does not include amounts that were initially capitalized and subsequently expensed in the same period.
March 31 December 31 (Cdn$ millions) 2006 2005 ------------------------------------------------------------------------------------------------------------------------------ Balance at Beginning of Period 252 116 Additions to Capitalized Exploratory Well Costs Pending the Determination of Proved Reserves 64 174 Capitalized Exploratory Well Costs Charged to Expense (33) (27) Transfers to Wells, Facilities and Equipment Based on Determination of Proved Reserves - (3) Effects of Foreign Exchange - (8) ------------------------------- Balance at End of Period 283 252 ===============================
16 The following table shows the aging of capitalized exploratory well costs based on the date drilling was completed and the number of projects for which exploratory well costs have been capitalized for a period greater than one year since the completion of drilling.
March 31 December 31 (Cdn$ millions) 2006 2005 ------------------------------------------------------------------------------------------------------------------------------ Capitalized for a Period of One Year or Less 182 165 Capitalized for a Period of Greater than One Year 101 87 ------------------------------- Balance at End of Period 283 252 =============================== Number of Projects that have Exploratory Well Costs Capitalized for a Period Greater than One Year 4 3 -------------------------------
As at March 31, 2006, we have exploratory costs that have been capitalized for more than one year relating to our interest in an exploratory block, offshore Nigeria ($68 million), our interest in two exploratory blocks in the Gulf of Mexico ($17 million) and coal bed methane exploratory activities in Canada ($16 million). Exploratory costs offshore Nigeria were first capitalized in 1998 and we have subsequently drilled a further seven successful wells on the block. The joint venture partners have finalized pre-development design studies and have submitted a field development plan for government approval. Drilling activity has resumed and an appraisal and exploration program is currently in progress. When final regulatory approvals have been received and the project has been sanctioned, we will book proved reserves. We have capitalized costs related to successful wells drilled in 2004, 2005 and 2006 in the Gulf of Mexico, and in Canada, we have capitalized exploratory costs relating to our coal bed methane projects. We are currently assessing all of these wells and projects, and we are working with our partners to prepare development plans. 7. LONG-TERM DEBT AND SHORT-TERM BORROWINGS
March 31 December 31 (Cdn$ millions) 2006 2005 ------------------------------------------------------------------------------------------------------------------------------ Canexus LP Term Credit Facilities (US$147 million drawn) 172 171 Term Credit Facilities - - Debentures, due 2006 (1) 92 93 Medium-Term Notes, due 2007 150 150 Medium-Term Notes, due 2008 125 125 Notes, due 2013 (US$500 million) 584 583 Notes, due 2015 (US$250 million) 292 292 Notes, due 2028 (US$200 million) 233 233 Notes, due 2032 (US$500 million) 584 583 Notes, due 2035 (US$790 million) 922 921 Subordinated Debentures, due 2043 (US$460 million) 537 536 ------------------------------- 3,691 3,687 ===============================
Note: (1) Includes $50 million of principal that was effectively converted through a currency exchange contract to US$37 million. (a) INTEREST EXPENSE
Three Months Ended March 31 (Cdn$ millions) 2006 2005 ------------------------------------------------------------------------------------------------------------------------------ Long-Term Debt 62 62 Other 4 5 ------------------------------- 66 67 Less: Capitalized (57) (33) ------------------------------- Total 9 34 ===============================
Capitalized interest relates to and is included as part of the cost of our oil and gas and Syncrude properties. The capitalization rates are based on our weighted-average cost of borrowings. (b) SHORT-TERM BORROWINGS Nexen has uncommitted, unsecured credit facilities of approximately $732 million, of which $36 million was drawn at March 31, 2006 (December 31, 2005 - nil). We have utilized $173 million of these facilities to support outstanding 17 letters of credit at March 31, 2006 (December 31, 2005 - $468 million) principally relating to our marketing business. Interest is payable at floating rates. During the first three months of 2006, the weighted average interest rate on our short-term borrowings was 4.8% (2005 - 3.6%). (c) TERM CREDIT FACILITIES We have committed unsecured, term credit facilities of $2.4 billion, which are available to 2010. The lenders have the option to extend the term annually. Borrowings are available as Canadian bankers' acceptances, LIBOR-based loans, Canadian prime loans, US-dollar base rate loans or British pound call-rate loans. Interest is payable monthly at floating rates. During the first three months of 2006, the weighted average interest rate on our term credit facilities was 5.2% (2005 - 4.4%). At March 31, 2006, $142 million of these facilities were utilized to support outstanding letters of credit (December 31, 2005 - $250 million) principally relating to our marketing business. 8. ASSET RETIREMENT OBLIGATIONS Changes in carrying amounts of the asset retirement obligations associated with our property, plant and equipment for the three months ended March 31, 2006 and the year ended December 31, 2005, are as follows:
March 31 December 31 (Cdn$ millions) 2006 2005 --------------------------------------------------------------------------------------------- Balance at Beginning of Period 611 468 Obligations Assumed with Development Activities 9 72 Obligations Discharged with Disposed Properties - (37) Expenditures Made on Asset Retirements (3) (34) Accretion 9 26 Revisions to Estimates (3) 138 Effects of Foreign Exchange 3 (22) ------------------------------- Balance at End of Period (1,2) 626 611 ===============================
Notes: (1) Obligations due within 12 months of $21 million (December 31, 2005 - $21 million) have been included in accounts payable and accrued liabilities. (2) Obligations relating to our oil and gas activities amount to $579 million (December 31, 2005 - $564 million) and obligations relating to our chemicals business amount to $47 million (December 31, 2005 - $47 million). Our total estimated undiscounted asset retirement obligations amount to $1,497 million (December 31, 2005 - $1,471 million). We have discounted the total estimated asset retirement obligations using a weighted-average, credit-adjusted risk-free rate of 5.7%. Approximately $85 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. In connection with the sale of our chemicals business to Canexus LP, we have contributed $14 million to a remediation fund to be used for asset retirement obligations associated with the assets sold. This is included on our Unaudited Consolidated Balance Sheet as part of deferred charges and other assets. We own interests in assets for which the fair value of the asset retirement obligations cannot be reasonably determined because the assets currently have an indeterminate life and we cannot determine when remediation activities would take place. These assets include our interest in Syncrude's upgrader and sulphur pile. The estimated future recoverable reserves at Syncrude are significant and given the long life of this asset, we are unable to determine when asset retirement activities would take place. Furthermore, the Syncrude plant can continue to run indefinitely with ongoing maintenance activities. The retirement obligations for these assets will be recorded in the first year in which the lives of the assets are determinable. 9. DEFERRED CREDITS AND OTHER LIABILITIES
March 31 December 31 (Cdn$ millions) 2006 2005 --------------------------------------------------------------------------------------------- Fixed Price Natural Gas Contracts (Note 10) 107 128 Long Term Marketing Derivative Contracts (Note 10) 101 124 Deferred Transportation 89 87 Stock-Based Compensation Liability 34 53 Defined Benefit Pension Obligation 41 39 Other 57 48 ------------------------------- Total 429 479 ===============================
18 10. DERIVATIVE INSTRUMENTS AND FINANCIAL RISK MANAGEMENT (a) CARRYING VALUE AND ESTIMATED FAIR VALUE OF DERIVATIVE AND FINANCIAL 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) MARCH 31, 2006 DECEMBER 31, 2005 -------------------------------------------------------------------------------------- ----------------------------------- Carrying Fair Unrecognized Carrying Fair Unrecognized Value Value Gain/(Loss) Value Value Gain/(Loss) ---------- ---------- --------------- --------- -------- ---------------- Commodity Price Risk Non-Trading Activities Crude Oil Put Options - - - 4 4 - Fixed Price Natural Gas Contracts (138) (138) - (175) (175) - Natural Gas Swaps 5 5 - 29 29 - Trading Activities Crude Oil and Natural Gas 209 209 - 161 161 - Future Sale of Gas Inventory - (4) (4) - (35) (35) Foreign Currency Risk Non-Trading Activities 11 11 - 14 14 - Trading Activities 4 4 - 8 8 - ------------------------------------- ----------------------------------- Total Derivatives 91 87 (4) 41 6 (35) ===================================== =================================== Financial Assets and Liabilities Long-Term Debt (3,691) (3,773) (82) (3,687) (3,863) (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 cash equivalents, restricted cash, amounts receivable and short-term obligations approximates their fair value because the instruments are near maturity. (b) COMMODITY PRICE RISK MANAGEMENT NON-TRADING ACTIVITIES We generally sell our crude oil and natural gas under short-term market based contracts. CRUDE OIL PUT OPTIONS We purchased WTI crude oil put options to manage the commodity price risk exposure of a portion of our oil production in 2005 and 2006. These options establish an annual average WTI floor price of US$43/bbl in 2005 and US$38/bbl in 2006 at a cost of $144 million. The 2005 WTI crude oil put options were not used and have expired. The 2006 WTI crude oil put options are stated at fair value on our balance sheet. Any change in fair value is included in marketing and other on the Unaudited Consolidated Statement of Income (Loss).
Notional Average Fair Volumes Term Price Value ------------------------------------------------------------------------------------------------------------------------------ (bbls/d) (US$/bbl) (Cdn$ millions) WTI Crude Oil Put Options 30,000 2006 39 - 20,000 2006 38 - 10,000 2006 36 - --------------- - ===============
19 FIXED-PRICE NATURAL GAS CONTRACTS AND NATURAL GAS SWAPS In July and August 2005, we sold certain Canadian oil and gas properties and we retained fixed-price natural gas sales contracts that were previously associated with those properties. Since these contracts are no longer used in the normal course of our oil and gas operations, they have been marked-to-market and are included in the Unaudited Consolidated Balance Sheet. Any change in fair value is included in Marketing and Other in the Unaudited Consolidated Statement of Income (Loss).
Notional Average Fair Volumes Term Price Value ------------------------------------------------------------------------------------------------------------------------------ (Gj/d) ($/Gj) (Cdn$ millions) Fixed-Price Natural Gas Contracts 22,034 2006 2.28 - 3.72 (31) 15,514 2007 - 2010 2.47 - 2.77 (107) --------------- (138) ===============
Following the sale of the Canadian oil and gas properties, we entered into natural gas swaps to economically hedge our exposure to the fixed-price natural gas sales contracts. Any change in fair value is included in Marketing and Other in the Unaudited Consolidated Statement of Income (Loss).
Notional Average Fair Volumes Term Price Value ------------------------------------------------------------------------------------------------------------------------------ (Gj/d) ($/Gj) (Cdn$ millions) Natural Gas Swaps 22,034 2006 9.02 - 11.81 (12) 15,514 2007 - 2010 7.45 17 --------------- 5 ===============
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 $209 million fair value of the derivative contracts at March 31, 2006 is included in the Unaudited Consolidated Balance Sheet and any change is included in Marketing and Other in the Unaudited Consolidated Statement of Income (Loss). FUTURE SALE OF GAS INVENTORY We have certain NYMEX futures contracts and swaps in place, which effectively lock in our margins on the future sale of our natural gas inventory in storage. We have designated, in writing, some of these derivative contracts as cash flow hedges of the future sale of our storage inventory. As a result, gains and losses on these designated futures contracts and swaps are recognized in net income when the inventory in storage is sold. The principal terms of these outstanding contracts and the unrecognized losses at March 31, 2006 are:
Hedged Average Unrecognized Volumes Month Price Loss ------------------------------------------------------------------------------------------------------------------------------ (mmcf) (US$/mcf) (Cdn$ millions) NYMEX Natural Gas Futures 11,000 January 2007 10.42 (4) ---------------- (4) ================
(c) FOREIGN CURRENCY EXCHANGE RATE RISK MANAGEMENT NON-TRADING ACTIVITIES
Fair Amount Term Rate Value ------------------------------------------------------------------------------------------------------------------------------ (for US$1.00) (Cdn$ millions) Foreign Currency Call Options - Buzzard (i) (pound)102 million 2006 2.00 - US Dollar Call Options - Canexus (ii) US$9.5 million monthly 2006 0.813 3 Foreign Currency Swap (iii) US$37 million 2006 0.736 8 ---------------- 11 ================
(i) FOREIGN CURRENCY CALL OPTIONS - BUZZARD Our Buzzard development project in the North Sea creates foreign currency exposure as a portion of the capital costs are denominated in British pounds and Euros. To reduce our exposure to fluctuations in these currencies relative 20 to the US dollar, we purchased foreign currency call options in early 2005, which effectively set a ceiling on most of our British pound and Euro spending exposure from March 2005 through to the end of 2006. Any change in fair value is included in marketing and other in the Unaudited Consolidated Statement of Income (Loss). (ii) US DOLLAR CALL OPTIONS - CANEXUS The operations of Canexus are exposed to changes in the US-dollar exchange rate as a portion of its sales are denominated in US dollars. In connection with the initial public offering of Canexus, we purchased US-dollar call options to reduce this exposure to fluctuations in the Canadian-US dollar exchange rate. Canexus has the right to sell US$9.5 million monthly and purchase Canadian dollars at an exchange rate of US$0.813 until August 2006. Any change in fair value is included in marketing and other in the Unaudited Consolidated Statement of Income (Loss). On April 3, 2006, Canexus purchased additional US-dollar foreign exchange options. Under the new options contract, Canexus has the right to sell US $5 million monthly and purchase Canadian dollars at an exchange rate of US$0.85 for the period August 16, 2006 to January 10, 2007. (iii) FOREIGN CURRENCY SWAP We occasionally use derivative instruments to effectively convert cash flows from Canadian to US dollars and vice versa. At March 31, 2006, we held a foreign currency derivative instrument that obligates us and the counterparty to exchange principal and interest amounts. In November 2006, we will pay US$37 million and receive Cdn$50 million. Any change in fair value is included in marketing and other in the Unaudited Consolidated Statement of Income (Loss). TRADING ACTIVITIES 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 $4 million fair value of our US dollar forward contracts at March 31, 2006 is included in the Unaudited Consolidated Balance Sheet. Any change in fair value is included in marketing and other in the Unaudited Consolidated Statement of Income (Loss). (d) TOTAL CARRYING VALUE OF DERIVATIVE CONTRACTS RELATED TO TRADING ACTIVITIES Amounts related to derivative contracts held by our marketing operation are equal to fair value as we use mark-to-market accounting. The amounts are as follows: March 31 December 31 (Cdn$ millions) 2006 2005 ------------------------------------------------------------------------------ Accounts Receivable 348 382 Deferred Charges and Other Assets (1) 181 232 -------------------------- Total Derivative Contract Assets 529 614 ========================== Accounts Payable and Accrued Liabilities 215 321 Deferred Credits and Other Liabilities (1) 101 124 -------------------------- Total Derivative Contract Liabilities 316 445 ========================== Total Derivative Contract Net Assets (2) 213 169 ========================== Note: (1) These derivative contracts settle beyond 12 months and are considered non-current. (2) Comprised of $209 million (2005 - $161 million) related to commodity contracts and $4 million (2005 - $8 million) related to US-dollar forward contracts and swaps. Our exchange-traded derivative contracts are subject to margin deposit requirements. We are required to advance cash to counterparties in order to satisfy these requirements. We have margin deposits of US$63 million ($73 million) at March 31, 2006 (December 31, 2005 - nil), which have been included with restricted cash on our Unaudited Consolidated Balance Sheet. 11. SHAREHOLDERS' EQUITY DIVIDENDS Dividends per common share for the three months ended March 31, 2006 were $0.05 (2005 - $0.05). 21 12. EARNINGS PER COMMON SHARE Our shareholders approved a split of our issued and outstanding common shares on a two-for-one basis at our annual and special meeting on April 27, 2005. All common share and per common share amounts have been restated to retroactively reflect this share split. We calculate basic earnings per common share from continuing operations using net income from continuing operations divided by the weighted-average number of common shares outstanding. We calculate basic earnings per common share using net income 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 Ended March 31 (millions of shares) 2006 2005 ------------------------------------------------------------------------------------------------------------------- Weighted-Average Number of Common Shares Outstanding 261.6 259.4 Shares Issuable Pursuant to Stock Options - 14.8 Notional Shares to be Purchased from Proceeds of Stock Options - (10.7) ------------------------------ Weighted-Average Number of Diluted Common Shares Outstanding 261.6 263.5 ==============================
In calculating the weighted-average number of diluted common shares outstanding for the three months ended March 31, 2006, all options were excluded because they have an anti-dilutive impact on the loss per share amounts. In calculating the weighted-average number of diluted common shares outstanding for the three months ended March 31, 2005, all options were included because their exercise price was less than the quarterly average common share market price in the period. During the periods presented, outstanding stock options were the only potential dilutive or anti-dilutive instruments. 13. CASH FLOWS (a) CHARGES AND CREDITS TO INCOME NOT INVOLVING CASH
Three Months Ended March 31 (Cdn$ millions) 2006 2005 ----------------------------------------------------------------------------------------------------------------- Depreciation, Depletion, Amortization and Impairment 266 239 Stock-Based Compensation 102 100 Future Income Taxes 271 (72) Change in Fair Value of Crude Oil Put Options 4 173 Non-Cash Items included in Discontinued Operations - 30 Net Income Attributable to Non-Controlling Interests 3 - Other 22 3 ---------------------------- Total 668 473 ============================
(b) CHANGES IN NON-CASH WORKING CAPITAL
Three Months Ended March 31 (Cdn$ millions) 2006 2005 ------------------------------------------------------------------------------------------------------------------- Accounts Receivable 829 67 Inventories and Supplies (150) (99) Other Current Assets 5 4 Accounts Payable and Accrued Liabilities (571) (45) Accrued Interest Payable (17) 6 ------------------------------ Total 96 (67) ============================== Relating to: Operating Activities 73 (53) Investing Activities 23 (14) ------------------------------ Total 96 (67) ==============================
22 (c) OTHER CASH FLOW INFORMATION
Three Months Ended March 31 (Cdn$ millions) 2006 2005 ------------------------------------------------------------------------------------------ Interest Paid 80 56 Income Taxes Paid 70 62 -----------------------------
14. MARKETING AND OTHER
Three Months Ended March 31 (Cdn$ millions) 2006 2005 ------------------------------------------------------------------------------------------ Marketing Revenue, Net 437 224 Change in Fair Value of Crude Oil Put Options (4) (173) Interest 9 3 Foreign Exchange Gains (Losses) (21) 10 Other 5 3 ----------------------------- Total 426 67 =============================
15. DISCONTINUED OPERATIONS In the third quarter of 2005, we sold certain Canadian conventional oil and gas properties in southeast Saskatchewan, northwest Saskatchewan, northeast British Columbia and the Alberta foothills. The results of operations of these properties have been presented as discontinued operations. The sales closed in the third quarter of 2005 with net proceeds of $900 million after closing adjustments, and we realized gains of $225 million. These gains are net of losses attributable to pipeline contracts and fixed price gas sales contracts associated with these properties that we have retained, but no longer use in connection with our oil and gas business.
Three Months Ended March 31 (Cdn$ millions, except per share amounts) 2006 2005 ------------------------------------------------------------------------------------------- Revenues and Other Income Net Sales - 60 Expenses Operating - 12 Depreciation, Depletion, Amortization and Impairment - 17 Exploration Expense - 1 ------------------------------ Income before Income Taxes - 30 Future Income Taxes - 12 ------------------------------ Net Income from Discontinued Operations - 18 ============================== Earnings Per Common Share ($/share) Basic (Note 12) - 0.07 ============================== Diluted (Note 12) - 0.07 ==============================
16. COMMITMENTS, CONTINGENCIES AND GUARANTEES As described in Note 15 to the Audited Consolidated Financial Statements included in our 2005 Annual Report on Form 10-K and described below, there are a number of lawsuits and claims pending, the ultimate results of which cannot be ascertained at this time. We record costs as they are incurred or become determinable. We believe the resolution of these matters would not have a material adverse effect on our liquidity, consolidated financial position or results of operations. In June 2003, a subsidiary of Occidental Petroleum Corporation (Occidental) initiated an arbitration against us at the International Court of Arbitration of the International Chamber of Commerce (ICC Court) regarding an Area of Mutual Interest agreement relating to two small areas (the Heijah/Tawila Extension Lands) of Block 51 in the Republic of Yemen. In April 2006, the ICC Court released its partial award which held that we were obliged to offer Occidental the right to acquire 50% of our interest in the Heijah/Tawila Extension Lands and that we breached that obligation. The result of this award is that Occidental is entitled to monetary damages. The ICC Court did not 23 determine the amount of damages due to Occidental in this partial award. These damages will be determined at the conclusion of the second and final phase of the arbitration which will likely occur in 2007. The amount of damages cannot be reasonably estimated at this time. Resolution of this matter is not expected to have a material adverse effect on our liquidity, consolidated financial position or results of operations. 17. PENSION AND OTHER POST RETIREMENT BENEFITS (a) NET PENSION EXPENSE RECOGNIZED UNDER OUR DEFINED BENEFIT PENSION PLANS
Three Months Ended March 31 (Cdn$ millions) 2006 2005 -------------------------------------------------------------------------------------------- Nexen Cost of Benefits Earned by Employees 4 2 Interest Cost on Benefits Earned 3 3 Expected Return on Plan Assets (3) (2) Net Amortization and Deferral 1 1 ----------------------------- Net Pension Expense 5 4 ----------------------------- Canexus Cost of Benefits Earned by Employees 1 - Interest Cost on Benefits Earned 1 - Expected Return on Plan Assets (1) - Net Amortization and Deferral - - ----------------------------- Net Pension Expense 1 - ----------------------------- Syncrude Cost of Benefits Earned by Employees 1 1 Interest Cost on Benefits Earned 1 2 Expected Return on Plan Assets (1) (1) Net Amortization and Deferral 1 - ----------------------------- Net Pension Expense 2 2 ----------------------------- Total 8 6 =============================
(b) EMPLOYER FUNDING CONTRIBUTIONS Our expected total funding contributions for 2006 disclosed in Note 16 to the Audited Consolidated Financial Statements in our 2005 Annual Report on Form 10-K have not changed for the Nexen and Canexus defined benefit pension plans and our share of Syncrude's defined benefit pension plan. 18. PROVISION FOR FUTURE INCOME TAXES During the three months ended March 31, 2006, we recorded a future income tax expense of $277 million related to an increase in tax rates on oil and gas activities in the United Kingdom. Legislation was introduced to the United Kingdom parliament during the quarter to increase the supplemental tax rate from 10% to 20%, effective January 1, 2006. 24 19. OPERATING SEGMENTS AND RELATED INFORMATION Nexen is involved in activities relating to Oil and Gas, Syncrude and Chemicals in various geographic locations as described in Note 20 to the Audited Consolidated Financial Statements included in our 2005 Annual Report on Form 10-K.
THREE MONTHS ENDED MARCH 31, 2006 Corporate and (Cdn$ millions) Oil and Gas Syncrude(1) Chemicals Other Total ---------------------------------------------------------------------------------------------------------------------------------- Other United United Countries Yemen Canada States Kingdom (2) Marketing ------------------------------------------------------- Net Sales 328 111 181 134 28 7 84 107 - 980 Marketing and Other 3 1 - 2 - 437 - - (17)(3) 426 ---------------------- -------------------------------------------------------------------------- 331 112 181 136 28 444 84 107 (17) 1,406 Less: Expenses Operating 36 34 30 22 2 7 53 66 - 250 Depreciation, Depletion, Amortization and Impairment 77 37 55 71 2 3 5 10 6 266 Transportation and Other 2 10 - - - 232 6 10 - 260 General and Administrative(4) 14 41 34 4 15 36 - 7 63 214 Exploration - 6 62 20 15 (5) - - - - 103 Interest - - - - - - - 2 7 9 ---------------------- -------------------------------------------------------------------------- Income (Loss) from Continuing Operations before Income Taxes 202 (16) - 19 (6) 166 20 12 (93) 304 ======================================================================================== Less: Provision for Income Taxes (6), (7) 380 Less: Non-Controlling Interests 3 ------ Net Loss (79) ====== Identifiable Assets 630 2,789 1,414 4,966 188 2,743 (8) 1,146 470 152 14,498 ================================================================================================= Capital Expenditures Development and Other 47 325 64 120 9 22 37 2 7 633 Exploration 5 46 40 19 7 - - - - 117 Proved Property Acquisitions - 2 - 1 - - - - - 3 ------------------------------------------------------------------------------------------------- 52 373 104 140 16 22 37 2 7 753 ================================================================================================= Property, Plant and Equipment Cost 2,299 3,991 2,491 4,139 256 185 1,275 829 251 15,716 Less: Accumulated DD&A 1,921 1,334 1,213 275 120 74 173 466 129 5,705 ------------------------------------------------------------------------------------------------- Net Book Value 378 2,657 1,278 3,864 136 111 1,102 363 122 10,011 =================================================================================================
Notes: (1) Syncrude is considered a mining operation for US reporting purposes. Property, plant and equipment at March 31, 2006 include mineral rights of $6 million. (2) Includes results of operations from producing activities in Colombia. (3) Includes interest income of $8 million, foreign exchange losses of $21 million and decrease in the fair value of crude oil put options of $4 million. (4) Includes stock-based compensation expense of $139 million. (5) Includes exploration activities primarily in Nigeria and Colombia. (6) Includes Yemen cash taxes of $67 million. (7) Includes future income tax expense of $277 million related to an increase in the supplemental tax rate on oil and gas activities in the United Kingdom (see Note 18). (8) Approximately 77% of Marketing's identifiable assets are accounts receivable and inventories. 25
THREE MONTHS ENDED MARCH 31, 2005 Corporate and (Cdn$ millions) Oil and Gas Syncrude(1) Chemicals Other Total --------------------------------------------------------------------------------------------------------------------------------- Other United United Countries Yemen Canada States Kingdom (2) Marketing ------------------------------------------------------- Net Sales 283 86 197 102 22 4 66 96 - 856 Marketing and Other 1 1 - - - 224 - 1 (160) (3) 67 ---------------------------------------------------------------------------------------------------- 284 87 197 102 22 228 66 97 (160) 923 Less: Expenses Operating 35 29 22 25 1 6 40 55 - 213 Depreciation, Depletion, Amortization and Impairment 65 35 66 46 4 3 4 10 6 239 Transportation and Other 1 5 - - - 172 3 10 12 203 General and Administrative (4) 10 32 18 1 18 17 - 15 70 181 Exploration 1 5 10 3 8 (5) - - - - 27 Interest - - - - - - - - 34 34 ---------------------------------------------------------------------------------------------------- Income (Loss) from Continuing Operations before Income Taxes 172 (19) 81 27 (9) 30 19 7 (282) 26 ========================================================================================== Less: Provision for Income Taxes (6) 7 Add: Net Income from Discontinued Operations 18 ------ Net Income 37 ====== Identifiable Assets 758 2,172 1,387 4,538 202 2,020 (7) 954 494 111 12,636 ==================================================================================================== Capital Expenditures Development and Other 63 214 19 140 4 1 44 1 2 488 Exploration 8 20 72 3 7 - - - - 110 Proved Property Acquisitions - 1 - - - - - - - 1 ---------------------------------------------------------------------------------------------------- 71 235 91 143 11 1 44 1 2 599 ==================================================================================================== Property, Plant and Equipment Cost 2,123 2,807 2,299 3,655 542 158 1,074 829 203 13,690 Less: Accumulated DD&A 1,623 1,227 1,064 65 412 67 158 425 97 5,138 ---------------------------------------------------------------------------------------------------- Net Book Value 500 1,580(8) 1,235 3,590 130 91 916 404 106 8,552 ====================================================================================================
Notes: (1) Syncrude is considered a mining operation for US reporting purposes. Property, plant and equipment at March 31, 2005 include mineral rights of $6 million. (2) Includes results of operations from producing activities in Nigeria and Colombia. (3) Includes interest income of $3 million, foreign exchange gains of $10 million and decrease in the fair value of crude oil put options of $173 million. (4) Includes stock-based compensation expense of $125 million. (5) Includes exploration activities primarily in Nigeria and Colombia. (6) Includes Yemen cash taxes of $59 million. (7) Approximately 77% of Marketing's identifiable assets are accounts receivable and inventories. (8) Excludes PP&E costs of $889 million and accumulated depreciation, depletion and amortization of $440 million relating to the Canadian properties disposed of during 2005 (see Note 15). 26 20. DIFFERENCES BETWEEN CANADIAN AND US GENERALLY ACCEPTED ACCOUNTING PRINCIPLES The Unaudited Consolidated Financial Statements have been prepared in accordance with Canadian GAAP. The US GAAP Unaudited Consolidated Statement of Income and Balance Sheet and summaries of differences from Canadian GAAP are as follows: (a) UNAUDITED CONSOLIDATED STATEMENT OF INCOME - US GAAP FOR THE THREE MONTHS ENDED MARCH 31
(Cdn$ millions, except per share amounts) 2006 2005 ------------------------------------------------------------------------------------------------------------------------------ REVENUES AND OTHER INCOME Net Sales 980 856 Marketing and Other (ii) 436 67 ------------ ------------- 1,416 923 ------------ ------------- EXPENSES Operating (iv) 252 215 Depreciation, Depletion, Amortization and Impairment (i) 266 249 Transportation and Other 260 203 General and Administrative (viii) 221 181 Exploration 103 27 Interest 9 34 ------------ ------------- 1,111 909 ------------ ------------- INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES 305 14 ------------ ------------- PROVISION FOR INCOME TAXES Current 109 79 Deferred (ii); (iv); (viii); (ix) (6) (73) ------------ ------------- 103 6 ------------ ------------- NET INCOME FROM CONTINUING OPERATIONS BEFORE NON-CONTROLLING INTERESTS 202 8 Net Income Attributable to Non-Controlling Interests 3 - ------------ ------------- NET INCOME FROM CONTINUING OPERATIONS 199 8 Net Income from Discontinued Operations - 18 ------------ ------------- NET INCOME - US GAAP (1) 199 26 ============ ============= EARNINGS PER COMMON SHARE ($/share) Basic (Note 12) Net Income from Continuing Operations 0.76 0.03 Net Income from Discontinued Operations - 0.07 ------------ ------------- 0.76 0.10 ============ ============= Diluted (Note 12); (x) Net Income from Continuing Operations 0.74 0.03 Net Income from Discontinued Operations - 0.07 ------------ ------------- 0.74 0.10 ============ =============
Note: (1) RECONCILIATION OF CANADIAN AND US GAAP NET INCOME
Three Months Ended March 31 (Cdn$ millions) 2006 2005 ------------------------------------------------------------------------------------------------------------------------------ Net Income/(Loss) - Canadian GAAP (79) 37 Impact of US Principles, Net of Income Taxes: Depreciation, Depletion, Amortization and Impairment (i) - (10) Liability-Based Stock Compensation Plans (viii) (4) - Deferred Income Taxes (ix) 277 - Other (ii); (iv) 5 (1) ------------ ------------- Net Income - US GAAP 199 26 ============ =============
27 (b) UNAUDITED CONSOLIDATED BALANCE SHEET - US GAAP
March 31 December 31 (Cdn$ millions, except share amounts) 2006 2005 ------------------------------------------------------------------------------------------------------------------------------ ASSETS CURRENT ASSETS Cash and Cash Equivalents 30 48 Restricted Cash 124 70 Accounts Receivable 2,374 3,151 Inventories and Supplies 651 504 Other 42 51 ----------------------------- Total Current Assets 3,221 3,824 ----------------------------- PROPERTY, PLANT AND EQUIPMENT Net of Accumulated Depreciation, Depletion, Amortization and Impairment of $6,098 (December 31, 2005 - $5,861) (iv); (vii) 9,965 9,550 DEFERRED INCOME TAX ASSETS (ix) 472 410 DEFERRED CHARGES AND OTHER ASSETS (v); (vi) 272 345 GOODWILL 379 364 ----------------------------- 14,309 14,493 ============================= LIABILITIES AND SHAREHOLDERS' EQUITY CURRENT LIABILITIES Short-Term Borrowings 36 - Accounts Payable and Accrued Liabilities (ii); (viii) 3,285 3,745 Accrued Interest Payable 39 55 Dividends Payable 13 13 ----------------------------- Total Current Liabilities 3,373 3,813 ----------------------------- LONG-TERM DEBT (v) 3,634 3,630 DEFERRED INCOME TAX LIABILITIES (i) - (ix) 1,967 1,906 ASSET RETIREMENT OBLIGATIONS 605 590 DEFERRED CREDITS AND LIABILITIES (vi) 455 505 NON-CONTROLLING INTERESTS 85 88 SHAREHOLDERS' EQUITY Common Shares, no par value Authorized: Unlimited Outstanding: 2006 - 261,674,080 shares 2005 - 261,140,571 shares 763 732 Contributed Surplus 2 2 Retained Earnings (i); (ii); (iv); (viii); (ix) 3,604 3,418 Accumulated Other Comprehensive Income (AOCI) (ii); (iii); (vi) (179) (191) ----------------------------- Total Shareholders' Equity 4,190 3,961 ----------------------------- COMMITMENTS, CONTINGENCIES AND GUARANTEES 14,309 14,493 =============================
(c) UNAUDITED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME - US GAAP FOR THE THREE MONTHS ENDED MARCH 31
(Cdn$ millions) 2006 2005 ------------------------------------------------------------------------------------------------------------------------------ Net Income - US GAAP 199 26 Other Comprehensive Income, Net of Income Taxes: Translation Adjustment (iii) (2) 10 Unrealized Mark-to-Market Gains/(Losses) (ii) 14 (5) --------------------------------- Comprehensive Income 211 31 =================================
28 (d) UNAUDITED CONSOLIDATED STATEMENT OF ACCUMULATED OTHER COMPREHENSIVE INCOME - US GAAP
March 31 December 31 (Cdn$ millions) 2006 2005 ------------------------------------------------------------------------------------------- Translation Adjustment (iii) (163) (161) Unrealized Mark-to-Market Losses - Cash Flow Hedges (ii) (2) (16) Minimum Pension Liability Adjustment (vi) (14) (14) -------------------------- Accumulated Other Comprehensive Income (AOCI) (179) (191) ==========================
NOTES: i. Under US GAAP, 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, additional depreciation, depletion, amortization and impairment expense of $10 million was included in net income for the three months ended March 31, 2005. The difference was fully amortized during 2005. ii. Under US GAAP, 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 during the period of change. FUTURE SALE OF GAS INVENTORY: At December 31, 2005, losses of $35 million were included in accounts payable with respect to futures contracts and swaps we used to hedge commodity price risk on the future sale of our gas inventory as described in Note 10. Losses of $24 million ($16 million, net of income taxes) related to the effective portion were deferred in AOCI until the underlying gas inventory was sold. These losses were reclassified to marketing and other when the contracts were settled in the first quarter of 2006. The ineffective portion of the losses of $11 million ($7 million, net of income taxes) was recognized in net income during 2005. At March 31, 2006, losses of $4 million were included in accounts payable with respect to futures contracts and swaps we used to hedge commodity price risk on the future sale of our gas inventory as described in Note 10. Losses of $3 million ($2 million, net of income taxes) related to the effective portion have been deferred in AOCI until the underlying gas inventory is sold. These losses will be reclassified to marketing and other as the contracts settle over the next 12 months. The ineffective portion of the losses of $1 million ($1 million, net of income taxes) was recognized in net income 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 is reflected in earnings. At March 31, 2006 and at December 31, 2005, we had no fair value hedges in place. iii. Under US GAAP, 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 - US GAAP. iv. Under Canadian GAAP, 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 $2 million ($1 million, net of income taxes) (2005 - $2 million ($1 million, net of taxes)); and o property, plant and equipment is lower under US GAAP by $27 million (December 31, 2005 - $25 million). v. Under US GAAP, discounts on long-term debt are classified as a reduction of long-term debt rather than as deferred charges and other assets. Discounts of $57 million (December 31, 2005 - $57 million) were re-classed and included in long-term debt. 29 vi. Under US GAAP, the amount by which our accrued pension cost is less than the unfunded accumulated benefit obligation is included in AOCI and accrued pension liabilities. As a result, deferred credits and other liabilities are higher by $26 million (December 31, 2005 - $26 million), deferred charges and other assets are higher by $4 million (December 31, 2005 - $4 million) and $22 million ($14 million, net of income taxes) was included in AOCI (December 31, 2005 - $22 million ($14 million, net of income taxes)). vii. On January 1, 2003, we adopted FASB Statement 143, ACCOUNTING FOR ASSET RETIREMENT OBLIGATIONS (FAS 143) for US GAAP reporting purposes. We adopted the equivalent Canadian standard for asset retirement obligations on January 1, 2004. These standards are consistent except for the adoption date which resulted in our property, plant and equipment under US GAAP being lower by $19 million. viii. Under Canadian principles, we record obligations for liability-based stock compensation plans using the intrinsic-value method of accounting. Under US principles, obligations for liability-based stock compensation plans are recorded using the fair value method of accounting. As a result, general and administrative expense and accounts payable and accrued liabilities are higher under US GAAP by $7 million ($4 million, net of income taxes). ix. Under US GAAP, enacted tax rates are used to calculate deferred income taxes, whereas under Canadian GAAP, substantively enacted rates are used. During the quarter, the UK government substantively enacted increases to the supplementary tax on oil and gas activities from 10% to 20%, effective January 1, 2006. This created a $277 million future income tax expense during the first quarter of 2006 under Canadian GAAP. x. Under Canadian GAAP, we excluded all options in calculating the weighted-average number of diluted common shares outstanding at March 31, 2006, because they have an anti-dilutive impact on the loss per share amounts. Under US GAAP the weighted-average number of diluted common shares outstanding for the three months ended March 31, 2006 was 268.5 million shares. (e) STOCK-BASED COMPENSATION CHANGE IN ACCOUNTING POLICY - US GAAP On January 1, 2006, we adopted FASB Statement 123 (revised), SHARE-BASED PAYMENT (Statement 123(R)) using the modified prospective approach and graded vesting amortization. Under Statement 123(R) our tandem options and stock appreciation rights (StARS) are considered liability-based stock compensation plans. Under the modified prospective approach, no amounts are restated in prior periods. Upon adoption of Statement 123(R), we recorded a cumulative effect of a change in accounting principle of $2 million. This amount was recorded in general and administrative expenses in our US GAAP Consolidated Statement of Income. Prior to the adoption of Statement 123(R) we accounted for our liability-based stock compensation plans in accordance with FASB Interpretation 28, ACCOUNTING FOR STOCK APPRECIATION RIGHTS AND OTHER VARIABLE STOCK OPTION OR AWARD PLANS (the intrinsic value method). Accordingly, obligations were accrued on a graded vesting basis and represented the difference between the market value of our common shares and the exercise price of underlying options and rights. Under Statement 123(R), obligations for liability-based stock compensation plans are measured at their fair value, and are re-measured at fair value in each subsequent reporting period. Consistent with Statement 123(R), we account for any stock options that do not include a cash feature (equity-based stock compensation plans), using the fair-value method. The impact of adopting Statement 123(R) on our results for the three months ended March 31, 2006 is as follows:
(Cdn$ millions) Prior to adoption After adoption Increase / of FAS 123(R) of FAS 123(R) (Decrease) ----------------------------------------------------------------------------------------------------------------------------- Income from Continuing Operations before Income Taxes - US GAAP 312 305 (7) Net Income - US GAAP 203 199 (4) Basic Earnings per Common Share - US GAAP ($/share) 0.78 0.76 (0.02) Diluted Earnings per Common Share - US GAAP ($/share) 0.76 0.74 (0.02) -----------------------------------------------------
DESCRIPTION OF STOCK-BASED COMPENSATION PLANS We have granted options to purchase common shares to directors, officers and employees. Each option permits the holder to purchase one Nexen common share at the stated exercise price. Options granted prior to February 2001 vest over four years and are exercisable on a cumulative basis over 10 years. Options granted after February 2001 vest over three years and are exercisable on a cumulative basis over five years. At the time of grant, the exercise price equals the market price. We have common shares reserved for issuance under this plan. 30 In May 2004, we modified our stock option plan to a tandem option plan by including a cash feature. 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. Stock options awarded to our US employees between December 1, 2004 and December 1, 2005 do not include a cash feature. Under our StARs plan established in 2001, employees are entitled to cash payments equal to the excess of the market price of the common shares over the exercise price of the rights. The vesting period and other terms of the plan are similar to the stock option plan. At the time of grant, the exercise price equals the market price. The total number of options and StARS granted and shares reserved for issue under all of our stock-based compensation plans will not exceed 10% of Nexen's total outstanding common shares. We have not made any modifications to our stock-based compensation plans since May 2004. ASSUMPTIONS We use the Generalized Black-Scholes option pricing model to estimate the fair value of our stock-based compensation, with the following assumptions: Expected Annual Dividends per Common Share ($/share) 0.20 Expected Volatility 42% Risk-Free Interest Rate 4.3% - 4.7% Weighted-Average Expected Life of Compensation Instruments (years) 2.8 - 3.0 The basis for our assumptions, among other things, is as follows: o Annual dividend expectations take into account historical dividend payments and reflect our expectation for future payments o Volatility expectations are based on our historical share price volatility. o Our risk-free interest rate assumption is derived from interest rates applicable to Government of Canada bonds taking into account the term of our compensation instruments. o The weighted-average expected life of our compensation instruments is based on our expectation of future exercise patterns of employees in relatively homogenous groups. These future exercise patterns take into account historical exercise experience for each employee group, historical post-vesting employment termination behaviors, and the contractual terms of our stock-based compensation awards and related vesting schedules. o We assume forfeiture rates based on historical experience. Our valuation methodology and assumptions are consistent with those previously used under FAS 123.
STOCK OPTIONS Weighted Weighted Average Weighted Average Remaining Term to Aggregate Average Fair Number Exercise Price Expiry Intrinsic Value Value ------------------------------------------------------------------------------------------------------------------------------ (thousands) ($/option) (years) (Cdn $ millions) ($/option) Balance at December 31, 2005 15,315 28 Granted 18 56 Exercised (892) 17 Forfeited (26) 24 ------------------------------- Balance at March 31, 2006 14,415 28 3.5 517 37 ===================================================================================== Outstanding at March 31, 2006 and Expected to Vest 14,200 28 3.5 507 37 ------------------------------------------------------------------------------------- Exercisable at March 31, 2006 7,270 18 3.0 331 45 -------------------------------------------------------------------------------------
The total intrinsic value of stock options exercised during the three months ended March 31, 2006 was $36 million (2005 - $28 million). At March 31, 2006, we had $103 million of unrecognized compensation expense related to stock options which we expect to recognize over a weighted-average period of 1.4 years. At March 31, 2006, there were 16,743,113 common shares reserved for future issuance under existing stock option plans. 31
STOCK APPRECIATION RIGHTS Weighted Weighted Average Weighted Average Remaining Term to Aggregate Average Fair Number Exercise Price Expiry Intrinsic Value Value ------------------------------------------------------------------------------------------------------------------------------ (thousands) ($/right) (years) (Cdn $ millions) ($/right) Balance at December 31, 2005 5,964 30 Granted 30 60 Exercised for Cash (499) 21 Forfeited (27) 37 ------------------------------- Balance at March 31, 2006 5,468 31 3.5 182 36 ===================================================================================== Outstanding at March 31, 2006 and Expected to Vest 5,187 31 3.5 175 37 ------------------------------------------------------------------------------------- Exercisable at March 31, 2006 1,939 21 2.6 85 44 -------------------------------------------------------------------------------------
The total intrinsic value of stock appreciation rights exercised during the three months ended March 31, 2006 was $21 million (2005 - $9 million). At March 31, 2006, we had $52 million of unrecognized compensation expense related to stock appreciation rights which we expect to recognize over a weighted-average period of 1.3 years. STOCK-BASED COMPENSATION EXPENSE AND PAYMENTS For the three months ended March 31, 2006, total stock-based compensation expense of $146 million ($98 million, net of taxes) (2005 - $125 million, ($84 million, net of taxes)) was included in general and administrative expense in the Consolidated Statement of Income - US GAAP. For the three months ended March 31, 2006, cash proceeds of $8 million were received related to the exercise of stock options (2005 - $17 million). For the three months ended March 31, 2006, cash of $37 million (2005 - $25 million) was paid upon the exercise of stock options and stock appreciation rights. The income tax benefit recorded from the exercise of stock options and stock appreciation rights was $12 million (2005 - $8 million) for the period. NEW ACCOUNTING PRONOUNCEMENTS In September 2005, the Emerging Issues Task Force (EITF) reached a consensus on Issue No. 04-13, ACCOUNTING FOR PURCHASES AND SALES OF INVENTORY WITH THE SAME COUNTERPARTY. This issue addresses the question of when it is appropriate to measure purchases and sales of inventory at fair value and record them in cost of sales and revenues and when they should be recorded as exchanges measured at the book value of the item sold. The EITF concluded that purchases and sales of inventory with the same counterparty that are entered into in contemplation of one another should be combined and recorded as exchanges measured at the book value of the item sold. The consensus should be applied to new arrangements entered into and modifications or renewals of existing agreements, beginning with the second quarter of 2006. We do not expect the adoption of this statement will have a material impact on our results of operations or financial position. In February 2006, the Financial Accounting Standards Board (FASB) issued Statement 155, ACCOUNTING FOR CERTAIN HYBRID INSTRUMENTS, which amends Statement 133, ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES, and Statement 140, ACCOUNTING FOR TRANSFERS AND SERVICING OF FINANCIAL ASSETS AND EXTINGUISHMENTS OF LIABILITIES. Statement 155 permits fair value remeasurement for any hybrid financial instrument that contains an embedded derivative that otherwise would require bifurcation from its host contract in accordance with Statement 133. Statement 155 also clarifies and amends certain other provisions of Statement 133 and Statement 140. This statement is effective for all financial instruments acquired or issued in fiscal years beginning after September 15, 2006. We do not expect the adoption of this statement will have a material impact on our results of operations or financial position. 32