10-K/A 1 form10ka1-2003.txt AMENDMENT NO. 1 UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-K/A AMENDMENT NO. 1 ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE YEAR ENDED DECEMBER 31, 2003 COMMISSION FILE NUMBER 1-6702 NEXEN INC. Incorporated under the Laws of Canada 98-6000202 (I.R.S. Employer Identification No.) 801 - 7th Avenue S.W. Calgary, Alberta, Canada T2P 3P7 Telephone - (403) 699-4000 Web site - www.nexeninc.com SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT: Title Exchange Registered On -------------- ------------- Common shares, no par value The New York Stock Exchange The Toronto Stock Exchange Subordinated Securities, due 2043 The New York Stock Exchange The Toronto Stock Exchange SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT: None. Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months, and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [_] Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X] Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). Yes [X] No [_] On June 30, 2003, the aggregate market value of the voting shares held by non-affiliates of the registrant was approximately Cdn $4.2 billion based on the Toronto Stock Exchange closing price on that date. On January 31, 2004, there were 126,738,410 common shares issued and outstanding. EXPLANATORY NOTE This Amendment No. 1 on Form 10-K/A (this "Amendment") amends the Annual Report on Form 10-K for the year ended December 31, 2003 filed on February 20, 2004 (the "Original Filing"). Nexen Inc. (the "Company") has filed this Amendment to incorporate textual changes in the Executive Summary of 2003 Results section of Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations. Specifically, the changes provide additional information regarding our finding and development costs and reserves replacement costs as requested by the Securities and Exchange Commission. This Amendment has no effect on the Balance Sheet, Statement of Income, and Statement of Changes in Stockholders' Equity, and more specifically, does not affect net income, earnings per share, total cash flows, current assets, total assets, current liabilities, total stockholders' equity or other information as presented in the Original Filing. Other information contained herein has not been updated. Therefore, this Amendment should be read together with other documents that the Company has filed with the Securities and Exchange Commission subsequent to the filing of the Original Filing. Information in such reports and documents updates and supersedes certain information contained in this Amendment. The filing of this Amendment shall not be deemed an admission that the Original Filing, when made, included any known, untrue statement of material fact or knowingly omitted to state a material fact necessary to make a statement not misleading. TABLE OF CONTENTS PAGE PART II Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations....................................3 PART IV Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K..37 UNLESS WE INDICATE OTHERWISE, ALL DOLLAR AMOUNTS ($) ARE IN CANADIAN DOLLARS, AND OIL AND GAS VOLUMES, RESERVES AND RELATED PERFORMANCE MEASURES ARE PRESENTED ON A WORKING INTEREST BEFORE-ROYALTIES BASIS. WHERE APPROPRIATE, INFORMATION ON AN AFTER-ROYALTIES BASIS IS PROVIDED IN TABULAR FORMAT.
Below is a list of terms specific to the oil and gas industry. They are used throughout the Form 10-K. /d = per day mboe = thousand barrels of oil equivalent bbl = barrel mmboe = million barrels of oil equivalent mbbls = thousand barrels mcf = thousand cubic feet mmbbls = million barrels mmcf = million cubic feet mmbtu = million British thermal units bcf = billion cubic feet km = kilometre WTI = West Texas Intermediate NGL = natural gas liquid
Oil equivalents are used to convert quantities of natural gas with crude oil by expressing them in a common unit. To calculate equivalents, we use 1 bbl = 6 mcf of natural gas. The noon-day Canadian to US dollar exchange rates for Cdn $1.00, as reported by the Bank of Canada, were: (US$) DECEMBER 31 AVERAGE HIGH LOW ------------------------------------------------------------------------------- 1999 0.6929 0.6730 0.6929 0.6537 2000 0.6666 0.6733 0.6973 0.6413 2001 0.6279 0.6458 0.6695 0.6241 2002 0.6331 0.6369 0.6618 0.6199 2003 0.7738 0.7135 0.7738 0.6350 On January 31, 2004, the noon-day exchange rate was US$0.7539 for Cdn $1.00. Electronic copies of our filings with the Securities and Exchange Commission (SEC) and the Ontario Securities Commission (OSC) (from November 8, 2002 onward) are available, free of charge, on our website (www.nexeninc.com). Filings prior to November 8, 2002 are available free of charge, upon request, by contacting our investor relations department at (403) 699-5931. As soon as reasonably practicable, our filings are made available on our website once they are electronically filed with the SEC or the OSC. Alternatively, the SEC and the OSC each maintain a website (www.sec.gov and www.sedar.com) that contain our reports, proxy and information statements and other published information that have been filed or furnished with the SEC and the OSC. 1 PART II ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS TABLE OF CONTENTS PAGE Executive Summary of 2003 Results..............................................3 Capital Investment.............................................................6 2003 Capital............................................................7 2004 Estimated Capital..................................................8 Financial Results Year to Year Change in Net Income......................................10 Oil and Gas Production ...................................................11 Commodity Prices...............................................13 Operating Costs................................................15 Depreciation, Depletion and Amortization.......................16 Exploration Expense............................................17 Oil and Gas Marketing..................................................17 Chemicals .............................................................20 Corporate Expenses.....................................................21 Outlook for 2004..............................................................22 Liquidity.....................................................................23 Contingencies.................................................................27 Business Risk Management......................................................28 Market Risk Management........................................................31 Critical Accounting Estimates.................................................33 New Accounting Pronouncements.................................................35 THE FOLLOWING SHOULD BE READ IN CONJUNCTION WITH THE CONSOLIDATED FINANCIAL STATEMENTS INCLUDED IN THIS REPORT. THE CONSOLIDATED FINANCIAL STATEMENTS HAVE BEEN PREPARED IN ACCORDANCE WITH GENERALLY ACCEPTED ACCOUNTING PRINCIPLES (GAAP) IN CANADA. THE IMPACT OF THE SIGNIFICANT DIFFERENCES BETWEEN CANADIAN AND UNITED STATES (US) ACCOUNTING PRINCIPLES ON THE FINANCIAL STATEMENTS IS DISCLOSED IN NOTE 16 TO THE CONSOLIDATED FINANCIAL STATEMENTS. UNLESS OTHERWISE NOTED, TABULAR AMOUNTS ARE IN MILLIONS OF CANADIAN DOLLARS. OUR DISCUSSION AND ANALYSIS OF OUR OIL AND GAS ACTIVITIES WITH RESPECT TO OIL AND GAS VOLUMES, RESERVES AND RELATED PERFORMANCE MEASURES IS PRESENTED ON A WORKING INTEREST BEFORE-ROYALTIES BASIS. WE MEASURE OUR PERFORMANCE IN THIS MANNER CONSISTENT WITH OTHER CANADIAN OIL AND GAS COMPANIES. WHERE APPROPRIATE, WE HAVE PROVIDED INFORMATION ON AN AFTER-ROYALTY BASIS IN TABULAR FORMAT. NOTE: CANADIAN INVESTORS SHOULD READ THE SPECIAL NOTE TO CANADIAN INVESTORS ON PAGE 60 OF OUR 2003 FORM 10-K WHICH HIGHLIGHTS DIFFERENCES BETWEEN OUR RESERVE ESTIMATES AND RELATED DISCLOSURES THAT ARE OTHERWISE REQUIRED BY CANADIAN REGULATORY AUTHORITIES. 2
EXECUTIVE SUMMARY OF 2003 RESULTS (Cdn$ millions) 2003 2002 2001 -------------------------------------------------------------------------------------------- Net Income 639 452 450 Earnings per Common Share ($/share) 4.84 3.34 3.40 Cash Flow from Operations (1) 1,859 1,383 1,423 Production, before royalties (mboe/d) (2) 269 269 268 Production, after royalties (mboe/d) 185 176 184 Capital Expenditures 1,494 1,625 1,404 Proved Reserve Additions, net (mmboe) (2) 38 126 131 Finding and Development Costs (3) before Revisions ($/boe) 11.64 12.41 9.24 Finding and Development Costs (3) after Revisions ($/boe) 29.34 11.15 9.81 Reserves Replacement Costs after Revisions (4) ($/boe) 29.92 11.64 9.80 Net Debt (5) 1,377 1,775 1,460 Net Debt to Cash Flow (times) (6) 0.8 1.4 1.1 -----------------------------
We achieved record financial results in 2003. As the variance table on page 33 shows, the three biggest drivers impacting net income growth were higher-margin volumes primarily in the US, strong oil and gas prices and exceptional marketing results. A strengthening Canadian dollar and an impairment charge largely attributable to heavy oil assets reduced these gains. Overall net income grew 41% over 2002 to $639 million and our cash flow from operations reached a record $1.9 billion. Crude oil prices remained strong in 2003 as supply and demand fundamentals supported higher prices. Instability in the Middle East, growing demand and low inventory levels kept average WTI at US$31.04/bbl. Natural gas prices peaked during the first quarter of the year and again in December, tracking weather patterns in the US. Our marketing group was positioned to take advantage of these fluctuations, benefiting from price differences between the west and the east, as well as between the summer and winter months. The strengthening Canadian dollar relative to the US dollar reduced our net income by $130 million and cash flow from operations by $250 million. This is because our foreign revenues and realized commodity prices, referenced in US dollars, were lower when translated to Canadian dollars. However, we benefit to the extent that our foreign operating costs and capital expenditures are also reduced when translated. In addition, most of our fixed-rate debt is denominated in US dollars so this debt is reduced with a strengthening Canadian dollar. As a result of certain negative reserve revisions in Canada, our net income includes a non-cash impairment charge of $175 million, after-tax, of which almost 90% relates to heavy oil reserves. The revisions resulted from changes to late field-life economic assumptions, a reduction in proved undeveloped reserves based on drilling results and geological mapping, and reassessments of expected future production profiles. The reduction does not affect our production forecast for 2004. Our Canadian oil and gas properties will continue to be a significant source of free cash flow for future investment since the future estimated cash flow from our total conventional Canadian assets is approximately 2.5 times their related carrying value. ---------------------------- (1) We evaluate our performance and that of our business segments based on earnings and cash flow from operations. Cash flow from operations is a non-GAAP term that represents cash generated from operating activities before changes in non-cash working capital and other. We consider it a key measure as it demonstrates our ability and the ability of our business segments to generate the cash flow necessary to fund future growth through capital investment and repay debt. (Cdn$ millions) 2003 2002 2001 -------------------------------------------------------------------------- Cash Flow from Operating Activities 1,469 1,322 1,566 Changes in Non-Cash Working Capital 320 46 (143) Other 70 15 -- ---------------------------- Cash Flow from Operations 1,859 1,383 1,423 ============================ (2) Production, before royalties and reserves include our working interest before royalties. We have presented our working interest before royalties as we measure our performance on this basis consistent with other Canadian oil and gas companies. We have used our year-end pricing assumptions. (3) Finding and Development Costs is defined as oil and gas exploration and development expenditures divided by total proved reserves additions on a before-royalties basis, prior to acquisitions and dispositions. Proved reserves include our working interest before royalties. (4) Reserves Replacement Costs is defined as oil and gas exploration and development expenditures divided by total proved reserves additions on a before-royalties basis, with both including the effects of acquisitions and dispositions. Proved reserves include our working interest before royalties. (5) Long-term debt less net working capital. (6) Net debt divided by cash flow from operations after dividends on Preferred Securities. 3 High-margin barrels from Aspen and now Gunnison replaced declining production in North America and at Buffalo, offshore Australia and Ejulebe, offshore Nigeria - both of which will be fully depleted in 2004. Canada's production was reduced mid-year as we disposed of 9,000 boe/d of non-core light oil properties in southeast Saskatchewan. The revenues and expenses associated with these disposed properties are segregated as discontinued operations in our financial statements. The shift from low-margin production in maturing areas to high-margin production in new growth areas grew overall production after royalties by 5% despite flat production before royalties. In 2004, we expect production before royalties to average between 255,000 and 275,000 boe. Production after royalties will continue to grow with more low-royalty volumes from Gunnison and Aspen. In 2003, we continued our strategy of growing long-term value primarily through grassroots exploration and development. We focused on maximizing returns from our capital investment program growing value beyond simply adding production volumes. Targeting higher returns, we have shifted our capital investment away from higher-cost, maturing North American conventional production into four key basins with significant growth projects as described in Item 1 of this 10-K. Below are highlights of our strategic progress in 2003: One-third of our total $1.5 billion capital budget was invested in the Gulf of Mexico, now our largest cash flow contributor. We advanced our deep-water strategy in 2003 by acquiring the remaining 40% interest in Aspen and becoming operator of our first deep-water project. Aspen's low cost and low royalty production generated cash netbacks of US$23 per boe, nearly twice our corporate average. We added to Aspen's high-margin production by bringing our second deep-water project, Gunnison, on stream ahead of schedule in December 2003. Production is ramping up at Gunnison through 2004 and we expect to tie-in a third development well at Aspen, adding to our improving margins. Exploration continues in 2004 on acreage in the Aspen and Gunnison areas, the eastern Gulf and the shelf deep-gas trend. In 2003, we invested $253 million in the Middle East: 87% on development and exploitation at Masila and the remainder on exploration on Block 51, adjacent to Masila, and in northern Yemen. Activities at Masila were focussed on maintaining existing production rates. Extensions to Masila's Heijah and Tawila fields and appraisal of Block 51 discoveries contributed 63 mmboe of proved reserves in 2003. In 2004, we plan additional delineation drilling on Block 51 to establish even more reserves. With new production from Block 51 planned for 2005, we expect to maintain strong production rates from Yemen for several years. We invested $57 million to continue building our presence offshore West Africa. On Block 222, offshore Nigeria, three appraisal wells at Usan delivered very good results. In addition, one appraisal well was drilled at Ukot. A development plan is being prepared for submission to the Nigerian government. Exploration will continue on this block as well as on OML-115, offshore Nigeria and Block K, offshore Equatorial Guinea - both attractive new prospects we acquired during 2003. To date, we have not booked any proved reserves for our Block 222 discoveries. Proved reserves will be booked once commercial development is approved. Our $96 million investment in the Long Lake project in the Athabasca oil sands allowed us to continue detailed engineering, implement a SAGD pilot, and obtain regulatory approval for the commercial project in 2003. With Board sanctioning of the commercial project in February 2004, we have booked 200 million barrels of proved reserves in 2004. Only 3 million barrels of proved reserves were booked in 2003 related to the SAGD pilot. Construction of commercial facilities will begin this summer. In 2003, we also invested $173 million in Syncrude's Stage 3 expansion, which together with base operations added 26 million barrels of proved reserves at a cost of $7.38 per boe. We expect this expansion to be completed in 2005, adding 8,000 barrels per day of new production to Nexen. Beyond these four basins, capital was invested in our core assets in Canada and the shallow-water Gulf, in Colombia and in our chemicals operations as we expand our Brandon facility and transfer sodium chlorate capacity there from our Taft, Louisiana plant. In Canada, our exploration and development programs in Canada added 16 mmboe of conventional proved reserves. Overall, we added 38 mmboe of net proved reserves as follows: (mmboe) ------------------------------------------------------------------------------- Additions (Extensions and Discoveries) 111 Acquisitions (Aspen) 24 Dispositions (primarily southeast Saskatchewan) (30) Revisions (primarily in Canada) (67) ------ 38 ====== 4 Additions of 111 mmboe of proved reserves replaced 113% of our production at a finding and development (F&D) cost of $11.64 per boe. Our F&D costs have trended upwards over the past few years given the long-lead times associated with our new growth projects. These projects consume large amounts of capital and mismatches are created in the timing of reserve recognition. Over their lives these projects are expected to generate attractive returns and low full-cycle F&D costs. The preceding F&D cost measure of $11.64 per boe does not take into consideration negative reserve additions. This measure was calculated by dividing the capital expenditures incurred during the year as determined in accordance with Canadian generally accepted accounting principles by the reserve volumes added from extensions and discoveries during the year. The calculation included our oil and gas and Syncrude activities and used before-royalty reserve volumes. However, it does not include other changes in reserves during the year relating to negative revisions, acquisitions and dispositions. Additional information on our F&D and reserves replacement costs (RRC) is as follows:
YEAR ENDED DECEMBER 31, 2003 RESERVE ADDITIONS CAPITAL BEFORE ROYALTIES REPORTED MEASURES ------------------------------------------------------------------------------------------------- (Cdn$ millions) (mmboe) (Cdn$/boe) F&D (before revision) 1,276 111 11.64 Reserves revision -- (67) --------------------------------------- F&D (after revision) 1,276 44 29.34 Acquisition 164 24 6.68 Dispositions (279) (30) 9.46 --------------------------------------- RRC 1,161 38 29.92 ==============================================================
Note: Reported Measures may differ from the results achieved by dividing Capital by Reserve Additions Before Royalties due to rounding.
The comparable measures calculated on an after-royalty basis are as follows. YEAR ENDED DECEMBER 31, 2003 RESERVE ADDITIONS CAPITAL AFTER ROYALTIES REPORTED MEASURES ------------------------------------------------------------------------------------------------- (Cdn$ millions) (mmboe) (Cdn$/boe) F&D (before revision) 1,276 76 16.85 Revision -- (42) --------------------------------------- F&D (after revision) 1,276 34 38.02 Acquisition 164 22 7.39 Dispositions (279) (25) 11.16 --------------------------------------- RRC 1,161 31 36.76 ==============================================================
Note: Reported Measures may differ from the results achieved by dividing Capital by Reserve Additions After Royalties due to rounding. The comparable measures derived from the information included in the FAS 69 disclosures in our 2003 Form 10-K, which uses capital expenditures determined in accordance with United States GAAP, excludes our Syncrude activities and is prepared on an after-royalty basis, are as follows.
YEAR ENDED DECEMBER 31, 2003 RESERVE ADDITIONS CAPITAL AFTER ROYALTIES REPORTED MEASURES ------------------------------------------------------------------------------------------------- (Cdn$ millions) (mmboe) (Cdn$/boe) F&D (before revision) 1,266 54 23.45 Revision -- (47) --------------------------------------- F&D (after revision) 1,266 7 180.85 Acquisition 164 22 7.39 Dispositions (279) (25) 11.16 --------------------------------------- RRC 1,151 4 287.85 ==============================================================
Note: Reported Measures may differ from the results achieved by dividing Capital by Reserve Additions After Royalties due to rounding. 5 Readers should refer to Note 16 in the Consolidated Financial Statements included in our 2003 Form 10-K for a description of the differences between Canadian and U.S. GAAP as it pertains to the determination of costs incurred. We also provide the following additional information as requested by the Securities and Exchange Commission (SEC). The reserve additions (before royalties) of 111 million boe from extensions and discoveries related primarily to development drilling on the Masila block in Yemen (32 million), exploration success and commencement of development activities on Block 51 in Yemen (31 million), the Stage 3 expansion at Syncrude (26 million) and development drilling in Canada (16 million). The additions on Block 51 were recognized as proved undeveloped reserves (PUDs) for which additional development capital was planned for 2004 and early 2005 to bring the reserves into production. The net negative reserve revisions of 67 million boe occurred primarily in Canada (60 million) and Yemen (11 million), offset by positive revisions of 4 million elsewhere. In Canada, 30 million resulted from changes in the estimated future production profiles of certain properties, 17 million from a reduction in PUDs based on drilling results and new geological mapping, and 13 million was attributable to changes in late field-life economic assumptions primarily related to changes in year-end Canadian dollar prices and our estimates of future operating costs. In Yemen, we reduced our estimate of the Masila block reserves based on drilling results and new geological mapping. Reserves were also added from the acquisition of the remaining 40% working interest in our producing Aspen field. Reserves dispositions occurred primarily in connection with the sale of certain of our light oil properties in southeast Saskatchewan. Our strategy is to focus a larger portion of our future capital spending on areas where we see the opportunity to grow and create value - the Athabasca oil sands, the deep-waters and deep Shelf gas in the U.S. Gulf of Mexico, the North Sea, offshore West Africa and the Middle East. As a result, we expect our future proved reserve additions to come primarily from these areas, although these areas typically have longer cycle times. As we transition to these areas, our activities on our mature properties in western Canada, the U.S. Shelf and the Masila block in Yemen will focus largely on converting PUDs to producing status, generally resulting in fewer proved reserve additions. Readers are cautioned that F&D and RRC metrics prepared using annual capital expenditures and changes in proved reserves may be misleading as they do not represent full cycle costs due to differences in the timing of recognition of reserves. In some cases, reserves may be recognized even though the majority of the capital required to develop the reserves to bring them into production is yet to be incurred. Conversely, capital incurred during the year may include costs to develop proved reserves that were recognized in previous years. Management does not focus on annual F&D and RRC metrics; instead, management looks to longer term historical trends and full cycle F&D and RRC metrics relative to related netbacks to assess the efficiency and effectiveness of our capital programs. In 2003, we took steps to improve our liquidity and financial flexibility to ensure we are able to fund our multi-year development projects. Record cash flow, disposition proceeds and a strong Canadian dollar reduced net debt and preferred securities by $758 million. Net debt and preferred securities at year-end was 1.0 times cash flow. We also took advantage of the low interest rate environment and issued US$960 million of public debt, enabling us to fund debt maturities, retire our preferred securities and reduce future financing costs. Going forward, we are well positioned for growth. Our 2004 oil and gas capital program of $1.7 billion will continue to support progress on our major development projects and fund an active exploration program, half of which is directed to US exploration. Strong commodity prices are likely to continue partially offset by the impact of a strong Canadian dollar on our US-dollar denominated revenues. Removing the impact of price and exchange rate fluctuations, we expect our improving margins in the US to grow our cash flow from operations by 10% year-over-year. CAPITAL INVESTMENT (Cdn$ millions) 2003 2002 2001 -------------------------------------------------------------------------------- Capital Investment New Growth Exploration 329 259 411 New Growth Development 358 626 110 Core Asset Development 589 592 641 Property Acquisition 164 4 122 -------------------------- Total Oil & Gas 1,440 1,481 1,284 Chemicals, Marketing and Other 54 144 120 -------------------------- Total 1,494 1,625 1,404 ========================== Our capital programs are focused on maximizing returns on every dollar of capital invested. Investment dollars are allocated between: 6 o core assets for short-term growth and free cash flow to fund ongoing capital programs; o development projects that convert our discoveries into new production and cash flow; and o exploration projects for longer-term growth. Given our exploration success over the past several years, we have made significant investments in major development projects in our four key basins. In 2001, we invested in new development projects at Aspen and Gunnison in the deep-water Gulf of Mexico and Syncrude's Stage 3 expansion. In 2002, we continued developing these projects and began scoping out our Long Lake project. We also made discoveries at Usan offshore Nigeria. In 2003, the first of these projects, Aspen came onstream. We converted the discoveries on Block 51 in Yemen into a development project. Late in 2003, our second deep-water project at Gunnison came onstream, with cash netbacks that are twice our corporate average. While our deep-water Gulf investments are already contributing high-value production, driving our corporate margins, our growth projects in the other basins have yet to contribute production and cash flow. Most of these are long-lead time projects, with three to five years between discovery and first production. Although these large capital investments have yet to generate cash flow, the capital invested is not at risk. Over their lives, these projects are expected to generate attractive returns and low full-cycle finding and development costs. The results of our capital programs are detailed below. 2003 CAPITAL In 2003, we invested over $1.4 billion in oil and gas with: o 41% in core assets to maintain existing production levels; o 36% in new growth development projects, and; o 23% in new growth exploration projects. (CDN$ MILLIONS) DEVELOPMENT EXPLORATION OTHER TOTAL -------------------------------------------------------------------------------- Oil and Gas United States 249 147 164 560 Yemen 219 34 -- 253 Nigeria -- 35 -- 35 Canada 259 51 -- 310 Syncrude 195 -- -- 195 Other Countries 25 62 -- 87 ---------------------------------------------- 947 329 164 1,440 Chemicals -- -- 24 24 Marketing, Corporate and Other -- -- 30 30 ---------------------------------------------- Total Capital 947 329 218 1,494 ============================================= In 2004, we plan to invest almost $1.7 billion in oil and gas with: o 35% in core assets to maintain existing production levels; o 45% in new growth development projects, and; o 20% in new growth exploration projects. 7 2004 ESTIMATED CAPITAL (CDN$ MILLIONS) DEVELOPMENT EXPLORATION OTHER TOTAL -------------------------------------------------------------------------------- Oil and Gas United States 175 158 -- 333 Yemen 397 23 -- 420 Nigeria 19 59 -- 78 Canada 130 52 -- 182 Long Lake Synthetic 391 9 -- 400 Syncrude 182 -- -- 182 Other Countries 17 60 -- 77 ----------------------------------------------- 1,311 361 -- 1,672 Chemicals -- -- 53 53 Marketing, Corporate and Other -- -- 41 41 ----------------------------------------------- Total Capital 1,311 361 94 1,766 ============================================== GULF OF MEXICO ASPEN Our deep-water Gulf of Mexico strategy began paying off in 2003. After bringing Aspen on-stream in December 2002, a record 19 months after discovery, we acquired the remaining 40% interest in March 2003 from BP for $164 million. With 100% interest in Aspen, we are now deep-water operators and control the timing of future exploration and development on our acreage in the Greater Aspen area. Aspen's production has low royalties and operating costs, resulting in high-margin production that has already recovered approximately 55% of our investment of US$374 million. A third development well is drilling at Aspen. GUNNISON In 2003, production from our second deep-water project at Gunnison, discovered in 2000, came on-stream. Gunnison's SPAR production facility was completed and moved from Finland to the Gulf mid-summer. We installed the remaining equipment on the production platform, and completed and tied-in the subsea wells. Production came on-stream in December 2003. Gunnison will deliver equally attractive returns as Aspen, with its low royalties and operating costs. EXPLORATION In 2003, we drilled three exploration wells in the Gulf, including a deep-water dry hole at Santa Rosa. Under our first exploration venture with Shell, we have recently finished drilling the Shark prospect on the shelf in search of natural gas in deep shelf sands. No commercial hydrocarbons were encountered and the well is temporarily abandoned while we evaluate the data collected from the well bore. In 2003, we entered into a second exploration venture with Shell to jointly explore a 1,116 square mile area of the deep-water eastern Gulf of Mexico. The area includes 124 blocks located in Mississippi Canyon and Desoto Canyon. Under this exploration venture, we drilled the Shiloh-1 well on Desoto Canyon 269 to a total depth of over 24,000 feet. At Shiloh, we encountered hydrocarbons in non-commercial quantities so the well was written off. We have acquired additional acreage in the area and will continue drilling in hopes of proving-up commercial quantities in the region. In 2004, almost half our exploration capital will be invested in the Gulf of Mexico. Our plans include five high-potential exploration wells: two deep shelf gas prospects on the shelf, Crested Butte offsetting Aspen, a well in Garden Banks, and another in the eastern Gulf of Mexico. MIDDLE EAST MASILA Our primary focus at Masila is to maintain production rates. During 2003, we invested $219 million to drill 94 development wells, construct new facilities, increase water handling capabilities, and perform additional workovers to maintain production rates. We plan to spend US$176 million in 2004 on development projects in the Masila field to drill 90 wells and complete facility enhancements to partially offset the field's natural decline. 8 BLOCK 51 In 2003, we enjoyed exploration success with discoveries in the Baishir al Khair Field (BAK) at BAK-A (formerly Tammum) and BAK-B (formerly Amir). Seven appraisal wells were drilled, encountering oil in the Qishn and Saar horizons, and we began commercial development late in the year. Initial development includes completing the seven wells drilled, ten new development wells, a central processing facility, a gathering system and a tieback to our Masila export system. Based on drilling results to date, we expect to develop in excess of 60 million barrels of reserves and add between 20,000 and 25,000 barrels per day of production capacity in early 2005. The field has additional potential that will be quantified by a 3D seismic program and further delineation drilling in 2004. We are continuing to explore the Block and plan to drill at least six exploration wells in 2004. EXPLORATION In addition to Block 51, we drilled the Husan El Kradis (HEK-1R) exploration well 25 kilometres northwest of BAK-B to test for oil in fractured basement; however, the well was dry. Further exploration is planned in the area. OFFSHORE WEST AFRICA NIGERIA In 2003, we focused on developing our Usan and Ukot discoveries on Block OPL-222. We drilled three appraisal wells at Usan and announced a significant extension of that field. An additional appraisal well at Ukot was also drilled. The operator is preparing a field development plan for submission to the Nigerian government for approval and we expect first production around 2008. In 2004, we plan additional exploration drilling to test the Block's remaining potential. In December 2003, as part of our initiative to expand our position in West Africa, we were assigned an interest in OML-115 offshore Nigeria. We commenced a program to acquire 410 km2 of 3D seismic data over the block and plan to drill one exploration well in 2004. EQUATORIAL GUINEA We acquired a 25% interest in Block K located 100 km offshore. The Block is on trend with the 300-million barrel Ceiba field and other discoveries on Block G to the north. In 2004, we plan to drill two wells to assess Equatorial Guinea's ability to contribute to the growth of our West Africa region. ATHABASCA OIL SANDS SYNCRUDE In 2003, the Stage 3 expansion proceeded as expected. The Aurora 2 bitumen train was completed and successfully placed in production. The upgrader expansion at Mildred Lake is 35% complete, on-track for start-up in 2005. We expect the Stage 3 expansion to increase our share of production to over 25,000 barrels per day. Due to higher engineering, manufacturing and construction costs, the estimated costs of the Stage 3 expansion have increased from initial estimates of $4.1 billion ($296 million net) to $5.7 billion ($412 million net). Activities in 2004 will also focus on replacing bitumen production capacity that will be lost when the southwest quadrant of the Mildred Lake Base Mine is depleted. SYNTHETIC OIL AT LONG LAKE The Long Lake project is progressing rapidly. In 2003, we commenced pilot testing of SAGD technology at Long Lake, obtained Alberta Energy Utilities Board approval and completed more than 15% of the detailed engineering. On February 12, 2004, our Board of Directors approved the Phase 1 commercial development plan. The project will develop approximately 10% of our Athabasca bitumen resource, upgrading this bitumen into high-quality light, sweet synthetic crude oil. As a result of the approval, we have booked 200 million barrels of proved reserves in 2004. In 2004, we expect to continue with detailed engineering, order long-lead time equipment and commence construction at Long Lake to meet a 2006 start-up date for bitumen production and a 2007 start-up date for synthetic crude oil production. Gross capital costs are expected to total $3.4 billion. OTHER EXPLORATION AND CORE ASSET DEVELOPMENT CANADA - CONVENTIONAL As our conventional assets in Western Canada mature, we are focusing on projects that provide the highest return on invested capital. In 2003, we sold over 9,000 barrels of daily production at attractive prices. We've also continued our transition to new sources of production growth such as synthetic crude oil and coal bed methane. CANADA - EXPLORATION 9 We increased our coal bed methane (CBM) land holdings and proceeded with our Corbett pilot, drilling 24 wells. In 2004, we will significantly expand the size of our CBM pilot project at Corbett and expect to decide on commerciality by year-end. We will test four other Upper Mannville CBM prospects and drill a number of gas exploration well in the Alberta foothills. COLOMBIA In 2003, we drilled 31 development wells to increase production rates and test the viability of a waterflood program on the Guando field. In 2004, we plan to drill 24 development wells and implement a full-field waterflood at Guando. We continued exploration in Colombia. One exploration well drilled on the Andino Block tested wet and was abandoned. CHEMICALS During 2003, we focused on increasing reliability and cost reduction at all of our manufacturing facilities. We also began relocating the assets from our Taft facility in Louisiana to Brandon, Manitoba, the lowest-cost sodium chlorate production facility in North America. In 2004, we expect to complete our Brandon expansion including the relocation and installation of the Taft assets. Upon completion of this expansion, the Brandon plant will be the largest sodium chlorate plant in the world. MARKETING, CORPORATE AND OTHER Capital spending in 2003 and planned spending in 2004 includes systems development, computer hardware and software, office equipment and leasehold improvements. FINANCIAL RESULTS
YEAR TO YEAR CHANGE IN NET INCOME (Cdn$ millions) 2003 VS 2002 2002 VS 2001 ---------------------------------------------------------------------------------------------- NET INCOME FOR 2002 AND 2001 452 450 ============================ Favourable (unfavourable) variances: Cash Items: Production volumes, net of royalties: Crude oil 92 30 Natural gas 41 (18) Change in inventory - crude oil sales, net of royalties (25) -- Realized commodity prices: Crude oil 41 183 Natural gas 234 (113) Oil and gas operating expense: Conventional 37 (63) Synthetic (14) 5 Marketing contribution 96 (23) Chemicals contribution (5) 1 General and administrative (38) (16) Interest expense 4 3 Current income taxes 13 (7) Other -- (22) ---------------------------- Total Cash Variance 476 (40) Non-Cash Items: Depreciation, depletion and amortization: Oil and Gas (327) (80) Other (5) (10) Exploration expense (19) 79 Future income taxes 28 79 Other 34 (26) ---------------------------- Total Non-Cash Variance (289) 42 ---------------------------- NET INCOME FOR 2003 AND 2002 639 452 ============================
Significant variances in net income are explained in the sections that follow. 10
OIL AND GAS PRODUCTION 2003 2002 2001 ----------------------------------------------------------------------------------------------------------------------------- Before After Before After Before After Royalties Royalties Royalties Royalties Royalties Royalties -------------------------------------------------------------------------------------------- Oil and Liquids (mbbls/d) Yemen 116.8 57.5 118.0 55.8 118.3 55.5 Canada (1) 46.3 35.4 56.3 43.4 58.0 48.3 United States 28.3 25.0 9.9 8.2 10.0 8.3 Australia 6.1 5.6 12.8 10.3 10.2 9.6 Other Countries 5.4 4.6 8.9 5.2 6.2 5.3 Syncrude 15.3 15.2 16.6 16.5 16.1 15.5 -------------------------------------------------------------------------------------------- 218.2 143.3 222.5 139.4 218.8 142.5 -------------------------------------------------------------------------------------------- Natural Gas (mmcf/d) Canada (1) 158 125 167 128 174 147 United States 145 122 112 93 121 99 -------------------------------------------------------------------------------------------- 303 247 279 221 295 246 -------------------------------------------------------------------------------------------- Total (mboe/d) 269 185 269 176 268 184 ============================================================================================
Note: (1) Includes the following production from discontinued operations. See Note 9 to our Consolidated Financial Statements. (mboe/d) 2003 2002 2001 -------------------------------------------------------------------------- Production Before Royalties 6.2 10.5 11.0 After Royalties 4.6 7.8 8.0 ---------------------------- 2003 VS 2002 - 5% PRODUCTION GROWTH AFTER ROYALTIES ADDED $133 MILLION TO NET INCOME Production after royalties grew 5%, with new low-royalty deep-water production from Aspen and more recently Gunnison, and more cost recovery barrels from Masila in Yemen. At Masila, we received a greater percentage of gross production to recover costs we incurred on the government's behalf. Production before royalties was flat compared to 2002 as growth in our US deep-water production was partially offset by dispositions in Canada, expected production declines offshore Nigeria and Australia, and maturing conventional assets. We expect 2004 production before royalties to average between 255,000 and 275,000 boe - similar to 2003 levels. Production after royalties will continue to grow with more low-royalty volumes from Gunnison and Aspen. MASILA BLOCK IN YEMEN Production before royalties decreased slightly in 2003 consistent with the overall decline in the field's base production. As Masila matures, we continue to drill more development wells, perform more workovers and expand our water handling capacity to manage the declines. Late in 2003, our expanded drilling and workover efforts successfully increased production to 120,000 barrels per day (net to us). While the field's total production decreased in 2003, our share of production after royalties grew due to the cost recovery mechanism in our production sharing contract. We are entitled to recover the costs we have incurred on the government's behalf (up to a 40% limit) through additional production volumes. As recent development drilling, facilities expansion and infrastructure modifications have increased our pool of recoverable costs, we receive a larger portion of total production to recover these costs. CANADA Given the maturity of the Western Canadian Sedimentary Basin, production additions are shrinking and declines are increasing. Our conventional Canadian assets are no exception. We aggressively managed our assets by developing them where we could add value or by selling them at attractive prices where we could not. Our conventional volumes in Canada fell 12% excluding the sale of our non-core properties in southeast Saskatchewan. We are investing the free cash flow from our Canadian assets in more profitable, multi-year development projects. 11 Crude oil production was down 18%. On August 28, 2003, we sold 9,000 boe/d of non-core, light oil properties in the Williston Basin of southeast Saskatchewan for net proceeds of $268 million. The remaining decrease was due to base declines on our heavy oil properties as water cuts increased at Marsden and wells at Edam sanded up. Our natural gas volumes fell 5% as new production from drilling did not offset the natural decline in our gas properties. We expect conventional production to decline modestly in 2004 as our asset base matures. However, this trend will reverse as our Long Lake project starts up with the production of bitumen in 2006 and synthetic crude oil in 2007. GULF OF MEXICO A full year of deep-water Aspen production increased US production rates 84% to record levels in 2003. Production adds and optimization activities at Eugene Island 295 and Vermilion 76 offset declines on the shelf. Aspen came on-stream and began delivering high-margin barrels in December 2002. We then acquired the remaining 40% interest in late March 2003. This acquisition contributed 8,000 boe per day at a cash return of $33.11 per boe in 2003. We locked-in a portion of our return on the acquisition by selling approximately 60% of the acquired production forward to March 2004 at a weighted average price of US$29.50 per boe. The forward sale of 10% of the acquired reserves effectively pays for 70% of the purchase price. Late in 2003, additional deep-water production came on-stream at Gunnison. Three subsea wells were tied-in and were producing 7,200 boe per day at year-end. Our total deep-water production for the year was 24,000 boe per day. Our shelf production was consistent with 2002 levels as we optimized production where possible. We restored production at hurricane-damaged Eugene Island 295 ahead of schedule in February 2003 and continued to deliver solid rates from our Vermilion 76 development. These gains were offset, in part, by lower performance at Eugene Island 18 and West Cameron 170. We expect the deep-water Gulf of Mexico to remain our fastest growing area in 2004 with Gunnison production increasing to 17,000 boe per day. We estimate our US production levels will reach over 70,000 boe per day by the end of the year. OTHER COUNTRIES Our production at Buffalo offshore Australia and at Ejulebe offshore Nigeria declined as expected throughout 2003 as both fields approach the end of their economic life. We expect final production from both in 2004. Colombia production grew 131% with 31 new development wells. Our pilot test confirmed the viability of a waterflood and we are moving to full-field waterflood in 2004. We expect to see volumes increase by 50% in 2004. SYNCRUDE Production decreased 8% in 2003 as an extra turnaround was completed during the year. A 37-day unplanned coker turnaround reduced volumes in the fourth quarter to 14,800 bbls per day. The turnaround delivered greater operational reliability immediately as we exited 2003 at 19,900 bbls per day. We expect the benefits of this turnaround to continue and do not anticipate a coker turnaround in 2004. 2002 VS 2001 - HIGHER PRODUCTION ADDED $12 MILLION TO NET INCOME Production from our core assets in Yemen, Canada and the US remained largely stable year over year. On-going development activities at Masila in Yemen, at Hay in Canada and on the shelf in the US Gulf of Mexico helped maintain production rates. In the US, poor weather in the third and fourth quarters, including tropical storm Isidore and Hurricane Lili caused the temporary shut-in of production, a 6-week delay at Aspen and damage to our Eugene Island 295 production platform. All production, except Eugene Island 295, was restored in the fourth quarter of 2002. Aspen's first well came on-stream in early December 2002 and the second well in late December. Our non-core assets made significant contributions during the year. At Buffalo offshore Australia a successful two-well infill drilling program contributed 7,500 boe per day of incremental production. Ejulebe offshore Nigeria contributed a 27% increase as the reservoir continued to perform better than anticipated. Both Buffalo and Ejulebe were declining at year-end as they were approaching the end of their expected lives. 12
COMMODITY PRICES 2003 2002 2001 -------------------------------------------------------------------------------------------- CRUDE OIL West Texas Intermediate (US$/bbl) 31.04 26.09 25.97 ----------------------------------- Differentials (US$/bbl): Masila 3.03 1.41 3.29 Heavy Oil 8.63 6.49 10.68 Mars 3.53 2.51 4.89 Producing Assets (Cdn$/bbl) Yemen 39.45 38.80 35.05 Canada 32.37 31.13 24.86 United States 37.68 38.88 38.35 Syncrude 43.36 40.89 39.90 Australia 43.14 40.30 38.71 Other Countries 38.22 38.96 37.37 Corporate Average (Cdn$/bbl) 38.04 37.13 33.10 ----------------------------------- NATURAL GAS New York Mercantile Exchange (US$/mmbtu) 5.60 3.37 4.00 AECO (Cdn$/mcf) 6.35 3.84 5.97 ----------------------------------- Producing Assets (Cdn$/mcf) Canada 5.64 3.57 5.02 United States 8.16 5.29 6.66 Corporate Average (Cdn$/mcf) 6.85 4.25 5.69 ----------------------------------- AVERAGE REALIZED OIL AND GAS PRICE (Cdn$/boe) 38.63 35.14 33.28 ----------------------------------- AVERAGE FOREIGN EXCHANGE RATE Canadian to US Dollar 0.7135 0.6369 0.6458 -----------------------------------
2003 VS 2002 - HIGHER REALIZED PRICES ADDED $275 MILLION TO NET INCOME Both crude oil and natural gas commodity prices reached near record levels in 2003 as supply and demand fundamentals supported strong prices. The positive impact of strong crude oil and natural gas reference prices was offset in part by the strengthening Canadian dollar and widening crude oil differentials. All of our oil sales and most of our gas sales are denominated in or referenced to US dollars. As a result, the strengthening Canadian dollar relative to the US dollar reduced our realized crude oil price by $4.50 per bbl and our realized natural gas price by $0.80 per mcf. In total, our net sales decreased $280 million from 2002 levels with the strengthening of the Canadian dollar. The Canadian to US dollar exchange rate closed the year at 77(cent). 13 CRUDE OIL REFERENCE PRICES Supply and demand fundamentals consistently supported strong reference prices throughout 2003. WTI opened and closed the year around US$33 per bbl, with highs of approximately US$38 per barrel and lows around US$25 per barrel. [GRAPHIC OMITTED] [2003 WTI MONTHLY AVERAGE LINE CHART OMITTED] Overall, the higher average WTI prices were supported by: o ongoing concerns over the security and stability of Iraqi production; o higher political risk in the Middle East; o labour disputes, and the resulting and threatened supply disruptions, in Nigeria and Venezuela; o OPEC's determination to hold production quotas in support of their price band; o growing demand in Asia, particularly China and India; o low crude oil and product inventories in North America; and, o the decline in value of the US dollar relative to other major world currencies. These factors, along with speculation around their severity and duration, created volatility in world crude oil prices. In 2004, analysts expect crude oil prices to fall to between US$25 to US$28, as non-OPEC supply from Russia and Iraq grows. An OPEC production cut, escalated Middle East risk or a greater-than-expected economic recovery would put upward pressure on these forecasts. CRUDE OIL DIFFERENTIALS Crude oil differentials widened in 2003 largely in response to the overall strength of WTI. Our Masila differential continued to track the Brent/WTI spread. Despite the strength in WTI during the year, the Brent differential actually remained relatively narrow. Brent prices strengthened with high demand in Europe during the exceptionally warm summer months and growing demand in Asia late in the year. Unexpected platform turnarounds in the North Sea reduced supply, causing the Brent/WTI differential to narrow even further. We expect the Masila differential to remain around US$3 per bbl in 2004. The wider heavy oil differential was largely due to an overall increase in supply from new Canadian heavy oil projects and some temporary decreases in demand from unexpected refinery turnarounds and the August blackout in parts of eastern North America. The heavy oil differential is expected to remain around US$8 per bbl in 2004. The Mars differential impacts the pricing of our Aspen production and averaged US$3.53 per bbl. Again, despite the strength in WTI, the Mars differential was relatively narrow in 2003. The pricing of Mars blend is directly affected by the pricing of sour blends. The instability of Iraqi supply and OPEC production cuts improved the pricing of sour blends and allowed the Mars differential to remain narrow. 14 NATURAL GAS REFERENCE PRICES North American natural gas prices were exceptionally strong during both the first quarter of 2003 and December 2003. Natural gas prices reached almost US$10 per mcf in the first quarter, but more notably did not dip below US$4.40 per mcf throughout the rest of the year. [GRAPHIC OMITTED] [2003 NYMEX MONTHLY AVERAGE LINE CHART OMITTED] Extended cold weather last winter and resulting low storage inventory levels were the major reason for the initial price increase early in the year. Fears of cold weather in the east increased gas prices in December. This also caused the NYMEX/AECO basis to widen significantly late in the year as weather forecasts in the west were suggesting above normal temperatures. We expect natural gas prices to decline to around US$4.25 per mmbtu in 2004. 2002 VS 2001 - HIGHER REALIZED PRICES ADDED $70 MILLION TO NET INCOME WTI contributed little to cash flow growth in 2002, however narrow crude oil differentials contributed around $180 million. At the beginning of 2002, WTI was US$19.73 per barrel and strengthened to close the year at US$31.20 per barrel. Low inventory levels in Europe kept the Brent/WTI differential narrow throughout most of the year. Given that our Masila crude tends to price off Brent, the Masila differential remained narrow along with the Brent/WTI spread. The heavy oil differential was narrow due to the unexpected disruption of heavy oil supply from Venezuela late in 2002. Lower natural gas prices reduced net income by $113 million. Natural gas prices fell in the first part of 2002 as inventories were high, but increased late in the year as cold weather hit the eastern US.
OPERATING COSTS (Cdn$/boe) 2003 2002 2001 ----------------------------------------------------------------------------------------------------------------------------- Before After Before After Before After Royalties(1) Royalties Royalties(1) Royalties Royalties(1) Royalties -------------------------------------------------------------------------------------------- Conventional Oil and Gas Yemen 2.16 4.37 1.95 4.13 1.62 3.47 Canada 6.00 7.76 5.70 7.45 4.87 5.82 United States 4.49 5.19 9.09 10.87 6.01 7.31 Australia 18.60 20.21 9.76 12.14 13.50 14.38 Other Countries 7.47 9.01 6.21 10.69 8.07 9.94 Average Conventional 4.17 6.24 4.60 7.24 3.92 5.88 -------------------------------------------------------------------------------------------- Synthetic Crude Oil Syncrude 21.96 22.18 18.10 18.21 19.43 20.29 Average Oil and Gas 5.19 7.56 5.42 8.26 4.88 7.10 --------------------------------------------------------------------------------------------
Note: (1) Operating costs per boe are our total oil and gas operating costs divided by our working interest production before royalties. We use production before royalties to monitor our performance consistent with other Canadian oil and gas companies. 15 2003 VS 2002 - LOWER OIL AND GAS OPERATING COSTS INCREASED NET INCOME BY $23 MILLION Conventional unit operating costs decreased with the addition of low-cost production from Aspen in the Gulf of Mexico and the strengthening of the Canadian dollar relative to the US dollar. Increased workover and maintenance activity in Yemen and higher water handling costs in Canada partially offset this decrease. Low-cost Aspen production reduced US operating costs by 50% and lowered our corporate average unit operating costs by approximately $0.40 per boe. Aspen production costs are about $1.05 per boe, $3.12 per boe lower than our corporate average for conventional production as most of the costs in our deep-water are capital related. Gunnison will produce at similar attractive operating costs. The strengthening Canadian dollar decreased US-dollar denominated operating costs, lowering our corporate average unit operating costs by approximately $0.25 per boe. Higher repairs, increased maintenance and workover activity resulted in a US$0.40 per barrel increase in Yemen operating costs. We expect ongoing maintenance and workover activities at Masila to keep operating costs around US$1.70 per barrel. As well, unit operating costs offshore Australia and Nigeria increased as fixed costs were spread over declining production volumes. Syncrude operating costs increased 21% due to higher natural gas input costs and increased turnaround and maintenance activity in 2003. Lower volumes also increased unit operating costs as more than 95% of the operating costs are fixed. 2002 VS 2001 - HIGHER OIL AND GAS OPERATING COSTS REDUCED NET INCOME BY $58 MILLION Conventional operating costs increased $0.68 per equivalent barrel due to industry cost pressures in Canada, increased workover and repair activity on the shelf in the Gulf of Mexico and increased water-handling and waterflood costs in Yemen. As well, weather-related shut-ins and storm damage in the Gulf of Mexico and one time flood-related costs in Yemen contributed to the increase. In Australia, per-unit operating costs decreased significantly as fixed costs were spread over more barrels.
DEPRECIATION, DEPLETION AND AMORTIZATION (DD&A) (Cdn$/boe) 2003 2002 2001 ----------------------------------------------------------------------------------------------------------------------------- Before After Before After Before After Royalties(2) Royalties Royalties(2) Royalties Royalties(2) Royalties -------------------------------------------------------------------------------------------- Conventional Oil and Gas Yemen 3.96 8.03 3.47 7.34 2.56 5.48 Canada (1) 9.10 11.76 8.22 10.72 7.14 8.53 United States 10.80 12.47 12.74 15.38 10.59 12.85 Australia 13.31 14.46 10.45 12.99 16.61 17.69 Other Countries 17.09 22.47 13.22 22.90 15.11 18.62 Average Conventional 7.37 11.04 6.84 10.81 5.97 8.98 -------------------------------------------------------------------------------------------- Synthetic Crude Oil Syncrude 2.50 2.53 2.13 2.17 2.03 2.13 Average Oil and Gas 7.09 10.33 6.55 10.01 5.73 8.40 --------------------------------------------------------------------------------------------
Notes: (1) DD&A per boe excludes the impairment charge described in Note 4 of the Consolidated Financial Statements. (2) DD&A per boe is our DD&A for oil and gas operations divided by our working interest production before royalties. We use production before royalties to monitor our performance consistent with other Canadian oil and gas companies. 2003 VS 2002 - HIGHER OIL AND GAS DD&A REDUCED NET INCOME BY $327 MILLION Conventional depletion rates increased with higher 2002 finding and development costs and our changing production mix, as more capital-intensive properties like Aspen contribute growing volumes. These properties, however, deliver higher-margin returns making them a valuable part of our portfolio. We also experienced higher depletion rates offshore Nigeria and Australia, as we prepare to abandon these fields in 2004. The strengthening Canadian dollar offset these increases as our depletion from International and the US is denominated in US dollars. This lowered our corporate average rate by approximately $0.48 per boe. Our DD&A expense for 2003 includes an impairment charge of $269 million ($175 million after-tax) largely attributable to reserve revisions to Canadian heavy oil properties. These reserve revisions were the result of changes to late field-life assumptions with respect to estimated future operating costs, changes to proved undeveloped reserves based on drilling results and geological mapping and reassessments of future estimated production profiles. 16 2002 VS 2001 - HIGHER OIL AND GAS DD&A REDUCED NET INCOME BY $80 MILLION Conventional depletion rates increased with higher 2001 finding and development costs in Canada, Yemen and the Gulf of Mexico and our changing production mix. A decrease in rates in Australia, resulting from successful infill drilling, partially offset these increases.
EXPLORATION EXPENSE (Cdn$ millions) 2003 2002 2001 -------------------------------------------------------------------------------------------- Seismic 62 75 77 Unsuccessful Drilling 70 61 133 Other 68 45 50 --------------------------------- Total Exploration Expense 200 181 260 ================================= Total Exploration Capital 329 259 411 Exploration Expense as a % of Exploration Capital (%) 61 70 63 ---------------------------------
2003 VS 2002 - HIGHER EXPLORATION EXPENSE REDUCED NET INCOME $19 MILLION Exploration expense grew consistent with an increase in our 2003 exploration capital spending. Overall, our exploration program delivered excellent results from the Gulf of Mexico, OPL-222 offshore Nigeria and Block 51 in Yemen. Dry hole and seismic costs in the Gulf of Mexico accounted for over 40% of our exploration expense. Exploration in the Gulf yielded some promising results at Shiloh. At Shiloh, we found hydrocarbons but not commercial quantities, so the well costs were written off. We still plan to actively pursue this prospect, have acquired additional acreage in the area and hope to prove-up commercial quantities in the region. We were unsuccessful at Santa Rosa but continue to pursue opportunities in the area. Dry hole costs also included three wells in the Alberta foothills of Canada, the Andino-1 well in Colombia, the Escargot well offshore Brazil and the HEK well in Yemen on Block 51. In addition, we acquired seismic over a number of prospects. 2002 VS 2001 - LOWER EXPLORATION EXPENSE ADDED $79 MILLION TO NET INCOME Exploration expense was lower in 2002 as we spent less on exploration capital, focusing our efforts on developing earlier exploration successes. Unsuccessful exploration wells included Block 59 in Yemen, Fusa in Colombia, Block BC-20 offshore Brazil and Fergana in the Gulf of Mexico.
OIL AND GAS MARKETING (Cdn$ millions) 2003 2002 2001 ---------------------------------------------------------------------------------------------------------------------------- Revenue 568 496 438 Transportation (398) (423) (342) Other (1) -- -- ---------------------------------------- Net Revenue 169 73 96 ======================================== Marketing contribution to Income from Continuing Operations before Income Tax 111 35 59 ---------------------------------------- Physical Sales Volumes (excluding intra-segment transactions) Crude Oil (mboe/d) 479 412 400 Natural Gas (mmcf/d) 3,301 2,865 2,499 Value-at-Risk Year-end 21 19 19 High 31 28 24 Low 14 12 6 Average 20 17 13 ----------------------------------------
17 2003 VS 2002 - RECORD NET MARKETING REVENUE INCREASED NET INCOME BY $96 MILLION Marketing delivered record financial results growing their cash flow by 132% over 2002. This achievement was driven primarily by exceptional results from our gas marketing and trading group, supplemented by steady profits from our crude oil trading and marketing group. Our natural gas group successfully positioned themselves to benefit from price differences between western Canada and eastern North America, and between summer and winter months. We also added transportation and storage capacity to our contract base. Added transportation capacity allowed us to take advantage of price differences between receipt and delivery points while added storage allowed us to take advantage of varying seasonal demand in the summer and winter months. The continued exit of competitors from the market in 2003 enabled us to acquire contracts on favourable terms, including storage and transportation contracts and natural gas contracts. We also successfully mitigated earlier volatility related to our storage positions by implementing a hedge accounting strategy. Until October 25, 2002, mark-to-market gains on our storage positions were included in net income. New accounting rules required us to exclude these gains from our results in 2003 until the inventory was sold despite having futures contracts in place that locked-in the profit on our stored volumes. At the beginning of the third quarter, we designated certain futures contracts as accounting hedges of the future sale of our stored volumes. As a result, recognition of the mark-to-market gain or loss on the futures contracts is deferred until the inventory is sold. See Note 5 to the Consolidated Financial Statements for further details. 2002 VS 2001 - LOWER NET MARKETING REVENUE REDUCED NET INCOME BY $23 MILLION Marketing delivered solid results in 2002 despite having fewer opportunities. Less price volatility in 2002 resulted in smaller margins. This was offset somewhat by an increase in our marketed volumes, as there were fewer competitors in the market. COMPOSITION OF NET MARKETING REVENUE (Cdn$ millions) 2003 2002 ------------------------------------------------------------------------------ Derivative Energy Contracts 148 58 Non-Derivative Energy Contracts 21 15 ------------------------- 169 73 ========================= DERIVATIVE ENERGY CONTRACTS Our marketing operation engages in crude oil and natural gas marketing activities to enhance prices from the sale of our own production, and for energy marketing and trading. We enter into contracts to purchase and sell crude oil and natural gas. These contracts expose us to commodity price risk between the time contracted volumes are purchased and sold. We actively manage this risk by using physical purchases and sales, energy-related futures, forwards, swaps and options, and by balancing physical and financial contracts in terms of volumes, timing of performance and delivery obligations. However, net open positions may exist, or we may establish them to take advantage of market conditions. Consistent with our management practices, we account for all derivative energy contracts that are not designated as a hedge using mark-to-market accounting, and record the net gain or loss from their revaluation in marketing and other income. The fair value of these instruments is recorded as accounts receivable or payable. They are classified as long-term or short-term based on their anticipated settlement date. We value derivative energy trading contracts daily using: o actively quoted markets such as the New York Mercantile Exchange and the International Petroleum Exchange; and o other external sources such as the Natural Gas Exchange, independent price publications and over-the-counter broker quotes. 18 FAIR VALUE OF DERIVATIVE ENERGY CONTRACTS At December 31, 2003, the fair value of our derivative energy contracts not designated as hedges totalled $106 million (2002 - $3 million). The following table shows the valuation methods underlying these contracts together with details of contract maturity:
(Cdn$ millions) MATURITY ------------------------------------------------------------------------------------------------------------------------------ Less than More than one year 1-3 years 4-5 years 5 years Total ---------------------------------------------------------------------- Prices Actively Quoted Markets (9) 1 -- -- (8) From Other External Sources 77 30 9 (2) 114 Based on Models and Other Valuation Methods -- -- -- -- -- ---------------------------------------------------------------------- Total 68 31 9 (2) 106 ======================================================================
More than 64% of the unrealized gain is related to contracts that will settle in 2004. Contract maturities vary from a single day up to six years. Those maturing beyond one year are primarily from natural gas related positions. The relatively short maturity position of our contracts lowers our portfolio risk. At December 31, 2003, the unrecognized losses on our derivative energy contracts accounted for as hedges of the future sale of our inventory totalled $11 million. The following table shows the valuation methods underlying these contracts together with details of contract maturity:
(Cdn$ millions) MATURITY ------------------------------------------------------------------------------------------------------------------------------ Less than More than one year 1-3 years 4-5 years 5 years Total ---------------------------------------------------------------------- Price Actively Quoted Markets (11) -- -- -- (11) From Other External Sources -- -- -- -- -- Based on Models and Other Valuation Models -- -- -- -- -- ---------------------------------------------------------------------- Total (11) -- -- -- (11) ======================================================================
Our accounting policy does not permit us to record income on transportation and storage contracts using option valuation methods.
CHANGES IN FAIR VALUE OF DERIVATIVE ENERGY CONTRACTS Contracts Contracts Contracts Entered into Outstanding at Entered into During Year Beginning of and Closed and Outstanding (Cdn$ millions) Year During Year at End of Year Total --------------------------------------------------------------------------------------------------------------------------- Fair Value at December 31, 2002 3 -- -- 3 Change in Fair Value of Contracts 6 53 89 148 Net Losses (Gains) on Contracts Closed 2 (53) -- (51) Derivative Energy Contracts Acquired -- -- 6 6 Changes in Valuation Techniques and Assumptions 1 -- -- -- -- ----------------------------------------------------------------- Fair Value at December 31, 2003 11 -- 95 106 ----------------------------------------------------------------- Unrecognized Losses on Hedges of Future Sale of Inventory at December 31, 2003 -- -- (11) (11) ----------------------------------------------------------------- Total Outstanding at December 31, 2003 11 -- 84 95 =================================================================
Note: (1) Our valuation methodology has been applied consistently year over year. 19
TOTAL CARRYING VALUE OF DERIVATIVE ENERGY CONTRACTS (Cdn$ millions) 2003 2002 ---------------------------------------------------------------------------------------------------------------------------- Current Assets 102 42 Non Current Assets 63 14 ----------------------------- Total Derivative Energy Contract Assets 165 56 ============================= Current Liabilities 34 46 Non Current Liabilities 25 7 ----------------------------- Total Derivative Energy Contract Liabilities 59 53 ============================= Total Derivative Energy Contract Net Assets (1) 106 3 =============================
Note: (1) Does not include effective hedges. We recognize gains and losses on effective hedges in the same period as the hedged item. Unrecognized losses on forward contracts for the future sale of oil and gas production are disclosed in Note 5 of the Consolidated Financial Statements. NON-DERIVATIVE ENERGY CONTRACTS We enter into fee for service contracts related to transportation and storage of third party oil and gas. We also earn income from our power generation facility. We earned $21 million from our non-derivative energy activities in 2003 (2002 - $15 million).
CHEMICALS (Cdn$ millions) 2003 2002 2001 ---------------------------------------------------------------------------------------------------------------------------- Net Sales 375 367 373 Sales Volumes (thousand short tons) Sodium chlorate 478 454 457 Chlor-alkali 396 375 365 Operating Profit (1) 95 100 99 Operating Margin (%) 25 27 27 Chemicals contribution to Income from Continuing Operations before Income Taxes 28 27 47 Capacity Utilization (%) 95 85 89 ---------------------------------------
Note: (1) Total revenues less operating costs, transportation and other. 2003 VS 2002 - LOWER CHEMICALS OPERATING PROFIT REDUCED NET INCOME BY $5 MILLION Many of the challenges we successfully managed in 2002 were replaced with new challenges in 2003. Strong North American demand for chlor-alkali and sodium chlorate helped boost sales volumes and prices in 2003. In North America, we manufacture our products in Canada. Most of our sales, however, are into US markets. As the Canadian dollar strengthened, our US-dollar denominated revenues declined, lowering our operating profit by $13 million. Higher natural gas prices in North America put pressure on electricity costs. To deal with these cost pressures, we idled our Taft plant, our highest electricity cost facility, and relocated the assets to Brandon. Our cost savings from idling the plant were offset by product we purchased from other suppliers to satisfy southeastern US customers. Once the assets are installed at Brandon, we expect the savings to flow to our bottom line. The installation of the Taft assets at Brandon should be completed in 2004 eliminating our need for purchased product. 2002 VS 2001 - CHEMICALS OPERATING PROFIT ADDS $1 MILLION TO NET INCOME We faced many challenges in 2002. Slow economic recovery in North America placed downward pressure on sodium chlorate volumes and eroded market prices. Also, increasing energy costs in Louisiana put pressure on our Taft plant. During 2002, margins remained strong due to lower overall energy costs and the shifting of production from higher-cost to lower-cost facilities following the expansion of our Brandon and Brazil facilities. The expansion of these plants increased our depreciation. 20
CORPORATE EXPENSES GENERAL AND ADMINISTRATIVE (Cdn$ millions) 2003 2002 2001 ---------------------------------------------------------------------------------------------------------------------------- General and Administrative Expenses 190 152 136 ---------------------------------------
2003 VS 2002 - HIGHER COSTS AND LOWER RECOVERIES REDUCED NET INCOME BY $38 MILLION Approximately 75% of the G&A increase relates to higher variable compensation: o Record 2003 results increased bonus compensation by $16 million; and o Strong stock prices at year-end increased the value of our employee stock appreciation rights and related expense by $13 million. The continued expansion of our marketing group also increased our staffing costs in 2003. 2002 VS 2001 - HIGHER COSTS REDUCED NET INCOME BY $16 MILLION Approximately 70% of the increase was due to higher staffing levels associated with our record capital investment program and growth in our marketing operations. The remainder resulted from increased pension expense due to poor equity market performance, higher building lease costs and incremental expenses associated with our stock appreciation rights plan.
INTEREST (Cdn$ millions) 2003 2002 2001 ---------------------------------------------------------------------------------------------------------------------------- Interest 148 140 112 Less: Capitalized Interest 43 31 -- --------------------------------------- Net Interest Expense 105 109 112 ======================================= Effective Rate (%) 7.2 7.1 7.6 ---------------------------------------
2003 VS 2002 - LOWER INTEREST EXPENSE INCREASED NET INCOME BY $4 MILLION Total interest costs increased $20 million due to: o Full-year impact of our 30-year notes issued in March 2002, and; o US$960 million issuance of new fixed-rate debt in November 2003. This increase was offset by the strengthening Canadian dollar, which lowered our US-dollar denominated interest expense by $10 million. Net interest expense decreased as capitalized interest related to major development projects costs continued to grow. Capitalized interest is expected to increase in 2004 as we proceed with major development projects at Long Lake and Syncrude. 2002 VS 2001 - LOWER INTEREST EXPENSE ADDED $3 MILLION TO NET INCOME Higher borrowing rate on our new 30-year notes increased interest costs by $28 million. We continued to capitalize interest on our major development projects resulting in lower net interest expense.
INCOME TAXES (Cdn$ millions) 2003 2002 2001 ---------------------------------------------------------------------------------------------------------------------------- Current 210 223 216 Future (40) (12) 67 --------------------------------------- 170 211 283 ======================================= Effective Rate (%) 22 34 40 ---------------------------------------
21 2003 VS 2002 - EFFECTIVE TAX RATE DECLINES FROM 34% TO 22% The 2003 effective tax rate fell primarily due to a reduction in tax rates for Canadian resource activities that resulted in a recovery of future income taxes of $76 million during the second quarter. The effective tax rate for 2004 is expected to be 33%. The majority of our 2003 current income taxes were paid in Yemen. Current taxes include cash taxes in Yemen of $201 million (2002 - $207 million; 2001 - $191 million). During 2003 and 2002, federal and provincial capital taxes were payable in Canada. In 2003, current income taxes also include alternative minimum tax in the United States. 2002 VS 2001 - EFFECTIVE TAX RATE DECLINES FROM 40% TO 34% Rate decreased due to: o lower federal and provincial statutory tax rates for Canadian non-oil and gas operations; o higher portions of income coming from international operations where rates are lower; and o non-taxable capital gain on the sale of our Moose Jaw operations. GAIN OR LOSS ON DISPOSITION OF ASSETS There was no gain or loss on the 2003 sale of our southeast Saskatchewan properties as described in Note 9 to the Consolidated Financial Statements. The net loss in 2002 includes a gain of $13 million on the sale of our asphalt operation in Moose Jaw, Saskatchewan and a loss of $21 million on the sale of a non-operated property by our Canadian oil and gas business segment.
OTHER INCOME (Cdn$ millions) 2003 2002 2001 ---------------------------------------------------------------------------------------------------------------------------- Foreign Exchange Gain (Loss) 6 (3) -- Business Interruption Insurance Proceeds 12 -- -- Interest Income 9 7 17 Other 15 4 20 --------------------------------------- 42 8 37 =======================================
The business interruption insurance proceeds received in 2003 relate to damage sustained in the Gulf of Mexico during tropical storm Isidore and hurricane Lili in the third and fourth quarters of 2002. OUTLOOK FOR 2004 Our largest ever-capital program of $1.8 billion will focus on advancing our major development programs and high-quality exploration in four key basins. Our solid capital structure and surplus liquidity will support this program. In 2004, we plan to invest almost $1.7 billion in oil and gas with: o 35% in core assets to maintain existing production levels; o 45% in new growth development projects, and; o 20% in new growth exploration projects. Details of our 2004 capital investment program are included in the Capital Investment section in the MD&A. This program is consistent with our strategy to grow reserves and production primarily through the drill bit. 22 DAILY PRODUCTION Approximately 45% of our cash flow from core assets will be reinvested in those assets to deliver production between 255,000 and 275,000 boe per day in 2004. The remaining 55% of cash flow will be invested in new growth projects.
2004 ESTIMATED PRODUCTION --------------------------------------- (mboe/d) BEFORE ROYALTIES AFTER ROYALTIES -------------------------------------------------------------------------------------------------- Gulf of Mexico (1) 60 - 65 55 - 57 Yemen, Masila 110 - 118 58 - 62 Canada Conventional (2) 57 - 65 46 - 53 Syncrude 16 - 18 16 - 17 Other International 7 - 9 6 - 8 ----------------=---------------------- Total 255 - 275 180 - 195 =======================================
Notes: (1) US natural gas production is estimated to comprise 45% of total US equivalent production in 2004. (2) Canadian natural gas production is estimated to comprise 33% of total Canadian equivalent production in 2004. Our net production growth will be modest in 2004, as over half our cash flow is invested in major growth projects coming on-stream in 2005 and beyond. Many of these projects have low or no royalties, lower costs and ultimately higher returns than our current producing assets. This changing production mix will improve profitability, even if oil prices trend lower. We expect to generate around $1.3 billion in cash flow from operations in 2004 assuming the following: ------------------------------------------------------------------------------------------------- WTI (US$/bbl) 25.00 NYMEX natural gas (US$/mmbtu) 4.25 US to Canadian dollar exchange rate 0.75 Changes in actual commodity prices and exchange rates will impact our annual cash flow from operations as follows:
(Cdn$ millions) ------------------------------------------------------------------------------------------------- WTI - US $1 change 53 NYMEX natural gas - US $0.50 change 60 Exchange rate - $0.01 change 21
In a price-neutral environment, cash flow from operations would grow by approximately 10% over 2003 and we would see 11% growth in our corporate cash netback. In addition to strong cash flow from our oil & gas operations, we expect solid performance from our chemicals and marketing businesses in 2004. Our chemicals operations anticipate improved cash flow from growing production and lower unit costs as we continue to consolidate production at our low-cost facility in Brandon. Our marketing group also anticipates another profitable year as they continue to increase their presence in core markets in the US midwest and eastern Canada. LIQUIDITY SOURCES AND USES OF CASH Our business strategy is focused on value-based growth through full-cycle exploration and development, supplemented by strategic acquisitions when appropriate. We rely on operating cash flows to fund capital requirements and provide liquidity. We build our opportunity portfolio to provide a balance of short-term, mid-term, and longer-term growth. This enables us to generate ongoing sustainable operating cash flows as shown below:
(Cdn$ millions) 2003 2002 2001 2000 1999 ------------------------------------------------------------------------------------------------------------------------------ Cash Flow from Operations 1,859 1,383 1,423 1,569 780 Capital Expenditures (1,494) (1,625) (1,404) (915) (612) ------------------------------------------------------------------ 365 (242) 19 654 168 ================================================================== WTI (US$/bbl) 31.04 26.09 25.97 30.21 19.24 NYMEX natural gas (US$/mmbtu) 5.60 3.37 4.00 4.31 2.31 ------------------------------------------------------------------
23 The capital investment in our oil and gas operations is primarily funded by our cash flow from operations. Although this spending is mostly discretionary, we rely on prudent capital investment to generate future operating cash flows. Given the long cycle time of some of our development projects, particularly internationally, and the volatility of commodity prices, it is not unusual, in any given year for capital expenditures to exceed our cash flow. In 1998 and 1999, commodity prices were low and we reduced our capital investment. In 2000, commodity prices improved, allowing us to generate sufficient cash flow from operations to buy back 20 million common shares. In 2001 and 2002, we began to invest significantly in two deep-water Gulf of Mexico prospects (Aspen and Gunnison), our Syncrude expansion and our Long Lake project. In 2003, Aspen contributed significantly to our cash flow from operations and in 2004, we expect additional significant contributions from Gunnison. We anticipate cash flows from the Syncrude expansion and Long Lake to commence in 2006 and 2007, respectively. Given the cyclical nature of the upstream oil and gas business, we manage our capital structure so that we are well positioned from a liquidity perspective throughout both positive and negative commodity price cycles. Our capital structure is characterized by a modest level of absolute debt, a long term to maturity and undrawn committed credit facilities.
CAPITAL STRUCTURE (Cdn$ millions) 2003 2002 ----------------------------------------------------------------------------------------------------------------- Bank Debt -- -- Senior Public Debt 2,776 1,844 ----------------------------- 2,776 1,844 Less: Cash 1,087 59 Less: Non-Cash Working Capital (1) 312 10 ----------------------------- Net Debt (2) 1,377 1,775 Preferred and Subordinated Securities 364 724 ----------------------------- Net Debt, including Preferred and Subordinated Securities 1,741 2,499 ============================= Shareholders' Equity (3),(4) 2,418 2,348 ============== ==============
Notes: (1) Excludes current portion of long-term debt. (2) Long-term debt less net working capital. (3) Included in shareholders' equity are preferred and subordinated securities of $364 million (2002 - $724 million). Under US generally accepted accounting principles, these are considered long-term debt. (4) At January 31, 2004, there were 126,738,410 common shares and US$460 million of unsecured subordinated securities outstanding. These subordinated securities may be redeemed by the issuance of common shares at our option after November 8, 2008. The number of shares to be issued will depend upon the common share price on the redemption date. We significantly enhanced our capital structure in 2003: SHAREHOLDERS' EQUITY Continued to strengthen with record net income in 2003. US$500 MILLION OF 5.05% DEBT Issued in November 2003 and maturing in 10 years. Proceeds were used to repay US$225 million of long term debt early in February 2004, and to fund a portion of our 2004 capital investment program. US$460 MILLION OF 7.35% SUBORDINATED DEBENTURES Issued in November 2003 and maturing in 40 years. Proceeds were partially used to redeem our 2047 preferred securities in December 2003 and our 2048 preferred securities in early February 2004. COMMITTED BANK FACILITIES OF $1,656 MILLION All undrawn at year-end with 75% of the facilities available to the end of 2008 and the remainder to the end of 2007. US$1 BILLION UNIVERSAL DEBT SHELF PROSPECTUS Available until October 2005 in the US and Canada. FAVOURABLE DEBT MATURITIES Pre-financed our 2004 debt maturity. Our remaining maturities over the next five years are minimal. The average term to maturity of our debt is 20 years.
24
CHANGE IN WORKING CAPITAL INCREASE/ (Cdn$ millions) 2003 2002 (DECREASE) ---------------------------------------------------------------------------------------------------------------------------- Cash and Short-Term Investments 1,087 59 1,028 Accounts Receivable 1,423 988 435 Inventories and Supplies 270 256 14 Accounts Payable and Accrued Liabilities (1,404) (1,194) (210) Other 23 (40) 63 ---------------------------------------- 1,399 69 1,330 ========================================
Cash and short-term investments increased with our fourth quarter financing activities. We received proceeds of US$960 million when we issued US$500 million of notes and US$460 million of subordinated debentures in November 2003. We used US$701 million of this cash to redeem US$259 million of preferred securities in December 2003, US$217 million of preferred securities in early February 2004 and US$225 million of senior notes in early February 2004. Accounts receivable increased in part because there was no sale of receivables at the end of 2003 compared to the sale of $178 million at the end of 2002. The remainder of the increase was due to higher commodity prices and growth in our marketing business offset by the strengthening of the Canadian dollar relative to the US dollar. The increase in other was related to the prepayment of natural gas storage inventory in December. NET DEBT Our net debt levels are directly related to our operating cash flows and our capital expenditure activities. During the year, we successfully reduced net debt, including preferred and subordinated securities, by $758 million:
(Cdn$ millions) 2003 2002 ------------------------------------------------------------------------------------------------------------- Capital Expenditures 1,494 1,625 Cash Flow from Operations (1,859) (1,383) ------------------------- (365) 242 Dividends on Preferred Securities and Common Shares 104 109 Foreign Exchange Translation of US-dollar Debt and Cash (281) -- Proceeds on Disposition of Assets (293) (49) Issue of Common Shares 73 51 Other 4 (38) ------------------------- Increase (Decrease) in Net Debt, including Preferred and Subordinated Securities (758) 315 =========================
The reduction in net debt has a positive impact on our leverage metrics:
2003 2002 2001 ---------------------------------------------------------------------------------------------------------------------------- Net Debt, including Preferred Securities and Subordinated Securities, to Cash Flow (1) (times) 1.0 1.9 1.6 Interest Coverage (2) (times) 13.3 10.7 13.7 Fixed Charge Coverage (3) (times) 9.5 7.2 8.4 ----------------------------------------
Notes: (1) Cash flow comprises cash flow from operations after dividends on Preferred Securities. (2) Cash flow from operations before interest expense divided by total interest. (3) Cash flow from operations before interest expense divided by total interest plus dividends on Preferred Securities. Our net debt and preferred securities are equal to 1.0 times our 2003 cash flow from operations after dividends on preferred securities. This, together with our coverage ratios, provides us with sufficient financial flexibility and liquidity to pursue our business strategy. 25 FUTURE LIQUIDITY Our future liquidity is primarily dependent on cash flows generated from our operations, our capital investment programs and the flexibility of our capital structure. Assuming WTI of US$25 per bbl for 2004, we expect our 2004 capital investment program and dividend requirements to exceed our cash flow from operations by almost $550 million. Our cash flow from operations is sensitive to changes in commodity prices and exchange rates. For 2004, we expect cash flow from operations of $1.3 billion, assuming the following: ------------------------------------------------------------------------------- WTI (US$/bbl) 25.00 NYMEX natural gas (US$/mmbtu) 4.25 US to Canadian dollar exchange rate 0.75 Changes in commodity prices and exchange rates will impact our cash flow from operations and our borrowing requirements. The impact of a variance, in any one of the above assumptions, on our cash flow from operations is described in the Outlook for 2004 section in the MD&A. If we change our capital investment program, we may draw more or less on our cash balances and our available facilities. We are currently entering a 4-year period of investing in major development projects as we move forward with our projects at Long Lake in Canada and on Block 51 in Yemen. Given our stable operating cash flows, strong cash position and undrawn committed credit facilities, we do not anticipate any problems in funding our capital programs, dividend requirements, and debt repayments or in meeting the obligations that arise from our day-to-day operations. In 2003, we declared common share dividends of $0.325 per common share (2002 - $0.30, 2001 - $0.30). We expect to declare common share dividends of $0.40 per common share in 2004. CONTRACTUAL OBLIGATIONS, COMMITMENTS AND GUARANTEES We have assumed various contractual obligations and commitments in the normal course of our operations and financing activities. These obligations and commitments have been considered when assessing our cash requirements in the above discussion of future liquidity.
(Cdn$ millions) Payments (1) ------------------------------------------------------------------------------------------------------------------------------ Less than More than Total 1 year 1-3 years 4-5 years 5 years ------------------------------------------------------------------------------- Long-Term Debt (1) 2,776 291 98 275 2,112 Preferred and Subordinated Securities (1) 364 331 -- -- 33 Operating Leases (2) 217 33 58 35 91 Transportation and Storage Commitments (2) 580 212 172 85 111 Work Commitments 81 64 17 -- - Dismantlement and Site Restoration 514 18 28 32 436 Other 1 1 -- -- - ------------------------------------------------------------------------------- Total 4,533 950 373 427 2,783 ===============================================================================
Notes: (1) Payment obligations are not discounted and do not include related interest, accretion or dividends. At December 31, 2003, we had cash and short-term investments of $1,087 million. (2) Payments for operating leases and transportation commitments are deducted from our cash flow from operations. Contractual obligations include both financial and non-financial obligations. Financial obligations represent known future cash payments that we are required to make under existing contractual arrangements, such as debt and lease arrangements. Non-financial obligations represent contractual obligations to perform specified activities such as work commitments. Commercial commitments represent contingent obligations that become payable only if certain pre-defined events occur. o Long-term debt amounts are included in our December 31, 2003 Consolidated Balance Sheet. The amount due in 2004 has been included in our current liabilities. Under US GAAP, $331 million of preferred securities and $33 million of subordinated securities would be included in long-term debt. o Operating leases include leases for office space, rail cars, vehicles, the lease of the FPSO in Australia, and our processing agreement with Shell that allows our Aspen production to flow through Shell's processing facilities at the Bullwinkle platform. The terms of the processing agreement give Shell an annual option to take payment in cash or in kind. For 2004, Shell has elected to take payment in kind so the 2004 obligation has been excluded from this table. o Our marketing operation manages various natural gas transportation and storage commitments on behalf of our Canadian oil and gas business and a number of third-party customers. 26 o Work commitments include non-discretionary capital spending related to drilling and seismic commitments in our international operations and development commitments at Syncrude. The remainder of our 2004 capital investment is discretionary. o We have $514 million of future dismantlement and site restoration obligations. As of December 31, 2003, $197 million of these obligations have been provided for on our balance sheet (including $18 million of current liabilities). The timing of any payments is difficult to determine with certainty and the table has been prepared using our best estimates. o We have unfunded obligations under our defined benefit pension and post retirement benefit plans of $84 million. Our unfunded obligation is $43 million and our share of Syncrude's unfunded obligation is $41 million. Our $43 million obligation includes $29 million that is unfunded as a result of statutory limitations. These obligations are backed by letters of credit. During 2003, we contributed $16 million to our defined benefit pension plan. Post year-end positive equity markets have helped restore our defined benefit plan to a fully funded position. o We have excluded our normal purchase arrangements as they are discretionary and are reflected in our expected cash flow from operations and our capital expenditures for 2004. From time to time we enter into contracts that require us to indemnify parties against possible claims, particularly when these contracts relate to the sale of assets. On occasion, we provide indemnifications to the purchaser. Generally, a maximum obligation is not stated. Because the obligation is stated, the overall maximum amount cannot be reasonably estimated. We have not made any significant payments related to these indemnifications. Our Risk Management Committee actively monitors our exposure to the above risks and obtains insurance coverage to satisfy potential or future claims as necessary. We believe these matters would not have a material adverse effect on our liquidity, financial condition or results. CREDIT RATINGS Currently, our senior debt is rated BBB by Standard & Poor's, Baa2 by Moody's Investor Service, Inc. and BBB by Dominion Bond Rating Service. In addition, all rating agencies currently rate our outlook as stable. Our strong financial results, ample liquidity and financial flexibility continue to support our credit rating. FINANCIAL ASSURANCE PROVISIONS IN COMMERCIAL CONTRACTS The commercial agreements our marketing division enters into often include financial assurance provisions that allow Nexen and our counterparties to effectively manage credit risk. The agreements normally require posting collateral (in the form of either cash or a letter of credit) if a buyer's credit rating drops below investment grade, indicating their creditworthiness has deteriorated. Based on the contracts in place and commodity prices at December 31, 2003, we would be required to post collateral of $321 million if we were downgraded to non-investment grade. This obligation is reflected in our balance sheet. The posting of collateral merely accelerates the payment of such amounts. Our committed undrawn credit facilities of $1.7 billion adequately cover any potential collateral requirements. Just as we may be required to post collateral in the event of a downgrade below investment grade, we have similar provisions in many of our customer contracts that allow us to demand certain customers post collateral with us if they are downgraded to non-investment grade. OFF-BALANCE SHEET ARRANGEMENTS None. CONTINGENCIES See Note 10 to the Consolidated Financial Statements in Item 8, which is incorporated herein by reference for a discussion of our contingencies. 27 BUSINESS RISK MANAGEMENT The oil and gas industry is highly competitive, particularly in the following areas: o searching for and developing new sources of crude oil and natural gas reserves; o constructing and operating crude oil and natural gas pipelines and facilities; and o transporting and marketing crude oil, natural gas and other petroleum products. Our competitors include major integrated oil and gas companies and numerous other independent oil and gas companies. The pulp and paper chemicals market is also highly competitive. Key success factors are: o price and product quality; and o logistics and reliability of supply. We are one of the largest producers of sodium chlorate in North America and have continent-wide supply capability. OPERATIONAL RISK Acquiring, developing and exploring for oil and natural gas involves many risks. These include: o encountering unexpected formations or pressures; o premature declines of reservoirs; o blow-outs, well bore collapse, equipment failures and other accidents; o craterings and sour gas releases; o uncontrollable flows of oil, natural gas or well fluids; o adverse weather conditions; and o environmental risks. Although we maintain insurance according to customary industry practice, we cannot fully insure against all of these risks. Losses resulting from the occurrence of these risks may have a material adverse impact. Our future crude oil and natural gas reserves and production, and therefore our operating cash flows and results of operations, are highly dependent upon our success in exploiting our current reserve base and acquiring or discovering additional reserves. Without reserve additions, our existing reserves and production will decline over time as reserves are produced. The business of exploring for, developing or acquiring reserves is capital intensive. If cash flow from operations is insufficient and external sources of capital become limited or unavailable, our ability to make the necessary capital investments to maintain and expand our oil and natural gas reserves could be impaired. UNCERTAINTY OF RESERVE ESTIMATES Oil and gas reserves are integral to assessing our expected future financial performance, preparing our financial statements and making investment decisions. There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves, including many factors beyond our control. The reserves included in this Form 10-K represent estimates only. To estimate the economically recoverable oil and natural gas reserves and related future net cash flows, we incorporate many factors and assumptions including: o expected reservoir characteristics based on geological, geophysical and engineering assessments; o future production rates based on historical performance and expected future operating and investment activities; o future oil and gas prices and quality differentials; o assumed effects of regulation by governmental agencies; and o future development and operating costs. We believe these factors and assumptions are reasonable based on the information available to us at the time we prepared the estimates. However, actual results could vary considerably, which could cause material variances in: o estimated quantities of proved oil and natural gas reserves in aggregate and for any particular group of properties; o reserve classification based on risk of recovery; o future net revenues, including production, revenues, taxes, and development and operating expenditures; and o financial results including the annual rate of depletion and recognition of property impairments. 28 Management is responsible for estimating the quantities of proved oil and natural gas reserves and preparing related disclosures. Estimates and related disclosures are prepared in accordance with SEC requirements, generally accepted industry practices in the US as promulgated by the Society of Petroleum Engineers, and the standards of the Canadian Oil and Gas Evaluation Handbook modified to reflect SEC requirements. Reserve estimates for each property are prepared at least annually by the property's reservoir engineer. They are reviewed by engineers familiar with the property and by divisional management. Senior management, including our CEO, CFO and Board-appointed internal qualified reserves evaluator, meet with divisional reserves personnel to review the estimates and any changes from previous estimates. The internal qualified reserves evaluator assesses whether our reserves estimates and the Standardized Measure of Discounted Future Net Cash Flows and Changes Therein, included in the Supplementary Financial Information, have been prepared in accordance with our reserve standards. His opinion stating that the reserves information has, in all material respects, been prepared according to our reserves standards is included in an exhibit to Form 10-K. We also have at least 80% of our reserve estimates audited annually by independent qualified reserves consultants. Given that the reserves estimates are based on numerous assumptions and interpretations, differences in estimates prepared by us and an independent reserves consultant within 10% are considered immaterial. Differences greater than 10% are resolved. The Board of Directors has established a Reserves Review Committee (Reserves Committee) to assist the Board and the Audit and Conduct Review Committee to oversee the annual review of our oil and gas reserves and related disclosures. The Reserves Committee is comprised of three or more directors, the majority of whom are independent, and each being familiar with estimating oil and gas reserves. The Reserves Committee meets with management periodically to review the reserves process, results and related disclosures. The Reserves Committee appoints and meets with each of the internal qualified reserves evaluator and independent reserves consultants independent of management to review the scope of their work, whether they have had access to sufficient information, the nature and satisfactory resolution of any material differences of opinion, and in the case of the independent reserves consultants, their independence. The Reserves Committee has reviewed Nexen's procedures for preparing the reserve estimates and related disclosures. It has reviewed the information with management, and met with the internal qualified reserves evaluator and the independent qualified reserves consultants. As a result of this, the Reserves Committee is satisfied that the internally-generated reserves are reliable and free of material misstatement. Based on the recommendation of the Reserves Committee, the Board has approved the reserves estimates and related disclosures in the Form 10-K. The estimated discounted future net cash flows from estimated proved reserves included in the Supplementary Financial Information in the Form 10-K are based on prices and costs as of the date of the estimate. Actual future prices and costs may be materially higher or lower. Actual future net cash flows will also be affected by factors such as actual production levels and timing, and changes in governmental regulation or taxation, and may differ materially from estimated cash flows. See the Critical Accounting Estimates section of this MD&A where we discuss the impact of changes in our reserve estimates. POLITICAL RISK We operate in numerous countries, some of which may be considered politically and economically unstable. Our operations and related assets are subject to the risks of actions by governmental authorities, insurgent groups or terrorists. We conduct our business and financial affairs to protect against political, legal, regulatory and economic risks applicable to operations in the various countries where we operate. However, there can be no assurance that we will be successful in protecting ourselves from the impact of these risks. Our Masila operations are important to Yemen, providing 50% of the country's oil production. We are a responsible member of the Yemeni community; we build relationships with its members and involve them in key decisions that impact their lives. We also ensure that they benefit from our presence in their country beyond the revenue they receive from the production we operate. Our strong relationship with the people and Government of Yemen has allowed us to operate there without interruptions for almost 14 years and we anticipate this continuing. Our practices have enabled us to operate successfully, not only in Yemen, but also in other parts of the world. We have developed excellent practices to manage the risks successfully. ENVIRONMENTAL RISK Environmental risks inherent in the oil and gas and chemicals industries are becoming increasingly sensitive as related laws and regulations become more stringent worldwide. Many of these laws and regulations require us to remove or remedy the effect of our activities on the environment at present and former operating sites, including dismantling production facilities and remediating damage caused by the disposal or release of specified substances. 29 We manage our environmental risks through a comprehensive and sophisticated Safety, Environmental and Social Responsibility (SESR) Management System that meets or exceeds ISO14001 criteria and those of similar management systems. Overall guidance and direction is provided by the SESR Committee of the Board of Directors. In addition, senior management, including the CEO and CFO, regularly meets with SESR management to review and approve SESR policies and procedures, provide strategic direction, review performance and ensure that corrective action is taken when necessary. We develop and implement proactive and preventative measures designed to reduce or eliminate future environmental liabilities, we are prudent and responsible in our management of existing environmental liabilities, and we continuously seek opportunities for performance improvement. We also maintain an ongoing awareness of external trends, demands, commitments, events or uncertainties that may reasonably have a material effect on revenues from continuing operations. These actions provide assurance that we meet or exceed appropriate environmental standards worldwide. o At December 31, 2003, $197 million has been provided in the Consolidated Financial Statements for future dismantlement and site restoration costs, currently estimated at $514 million for our oil and gas and chemicals facilities. o During 2003, we recorded a provision for future dismantlement and site restoration costs of $38 million (2002 - $43 million; 2001 - $45 million). o Actual site remediation expenditures for the year were $21 million (2002 - $20 million; 2001 - $24 million). We anticipate actual site remediation expenditures in 2004 to approximate 2003 levels. o We perform periodic internal and external assessments of our operations and adjust our estimates and annual provision accordingly. o During 2002, we conducted an external audit of our management system for safety, environment and social responsibility issues. In general, the review was very positive and the few minor recommendations for improvement are being implemented. o During 2003, we commenced an external operational audit to confirm whether our management system for safety, environment and social responsibility issues is actually being followed. This work is continuing into 2004, but initial reports are very positive. CLIMATE CHANGE The Kyoto Protocol, an agreement to reduce the concentration of certain man-made gases (Green House Gases or GHG) that may be contributing to climate change, was signed by approximately 160 countries since 1997. Canada ratified the Kyoto Protocol in December 2002, but it will not come into effect until it is ratified by Russia. The Kyoto Protocol obliges the Annex 1 countries to meet national targets. Canada's target is an emission reduction of 6% below 1990 levels during the First Commitment period of 2008 to 2012. Economic modeling studies have shown that if emission reductions are met through domestic action in Annex I countries alone, there will be severe negative impacts to those countries' economies, and in particular those such as Canada whose economies are resource and energy intensive. The US government's decision to withdraw from the Kyoto Protocol has serious implications for Canada in the context of a continental or hemispheric energy market. The Canadian government has addressed the uncertainty around ratification and implementation of the Kyoto Protocol by providing the oil and gas sector with limits on cost (a cap of $15 per tonne) and volume (a cap of 55 megatonnes for large industrial emitters) as well as its position on long-term high capital cost projects. However, the government has yet to enact national legislation that will detail the obligations of Canadian industry with respect to emission reduction and management, and it is uncertain at this time when those obligations will be determined. The financial markets have viewed these developments favourably and have issued various analyses in the aftermath of these announcements indicating that implementation of GHG-related legislation should not adversely affect the development of new energy projects such as the oilsands. For years, Nexen has been assessing the impact of climate change developments on our various business interests. We have created a senior management committee (The Climate Change Steering Group) to: consider national and international developments; hear from leading experts with respect to science, business and risk issues; and, consider investment opportunities. As well, Nexen continues to work closely with the Canadian and Alberta governments to assess the impact of regulatory options and provide information on our business to assist governments in their policy deliberations. Nexen maintains a wide range of business contacts to ensure that a full slate of options is available to the corporation in order to meet the obligations that may be imposed by future legislation. Nexen is a Gold level reporter in Canada's Voluntary Challenge and Registry (VCR); our 2002 VCR report includes the observation that we have voluntarily reduced our direct emissions by almost 2 million tons of (CO2) equivalent since we started reporting in 1996. As well, progress has been made toward reduction of our energy inputs per unit of production. In 2003, we initiated another gas gathering project in heavy oil. We are still assessing our 2003 performance and it will be reported to the VCR. 30 Nexen has looked to GHG emission reduction and to offset investments. In 1995, we started capturing, compressing and selling methane gas from our Canadian heavy oil operation instead of venting it to the atmosphere. As a Canadian-based international oil and gas exploration and production company, we have worked closely with the Canadian Clean Development Mechanism/Joint Implementation Office of the Department of Foreign Affairs and International Trade to ensure that Canadian companies get access to low cost/high quality carbon offset investments. Nexen has entered into discussions with the management of several GHG investment pools and continues to evaluate the opportunities associated with biological and geological sequestration of (CO2) and the capture of methane from landfills. We continue to investigate carbon-offset opportunities in each of our core countries in the belief that there may be synergies between our oil and gas activities and carbon investments. We continuously review the feasibility of new and ongoing projects with respect to current social, political and economic factors and will continue to take into account the policy and requirements with respect to GHG when conducting these reviews. We are committed to the principles of full disclosure and will keep our stakeholders apprised of how these issues affect us. Since emission levels applicable to our business operations have not been determined and there are no reliable estimates of the costs of achieving those levels, premature disclosure would be speculative and any financial estimates would be based on arbitrary assumptions of emission levels; however, Canadian government assurances of cost and volume limits suggest that incremental risks and liabilities attributable to addressing climate change policies are manageable. Finally, any indirect risks and liabilities attributable to GHG are too remote and unquantifiable at this time. MARKET RISK MANAGEMENT We are exposed to normal market risks inherent in the oil and gas and chemicals business, including commodity price risk, foreign-currency rate risk, interest rate risk and credit risk. We manage our operations to minimize our exposure, as described in Note 5 to the Consolidated Financial Statements, which is incorporated by reference here.
SENSITIVITIES (Cdn$ millions) Cash Flow Net Income ----------------------------------------------------------------------------------------------------------------------------- Estimated 2004 impact: Crude Oil - US$1.00/bbl change in WTI 53 41 Natural Gas - US$0.50/mcf change 60 38 Foreign Exchange - $0.01 change in US to Cdn Dollar 21 9 ---------------------------------
COMMODITY PRICE RISK Commodity price risk related to conventional and synthetic crude oil prices is our most significant market risk exposure. Crude oil prices and quality differentials are influenced by worldwide factors such as OPEC actions, political events and supply and demand fundamentals. To a lesser extent we are also exposed to natural gas price movements. Natural gas prices are generally influenced by oil prices and North American supply and demand, and to a lesser extent local market conditions. NON-TRADING ACTIVITIES The majority of our production is sold under short-term contracts, exposing us to short-term price movements. Other energy contracts we enter into also expose us to commodity price risk between the time we purchase and sell contracted volumes. From time to time, we actively manage these risks by using commodity futures, forwards, swaps and options. In March 2003, we sold WTI and NYMEX gas forward contracts for the next 12 months to lock-in part of the return on the remaining 40% interest acquired in the Aspen field. The forward contracts fix our oil and gas prices at the contract prices for the hedged volumes, less applicable price differentials as follows:
Hedged Average Volumes Term Price ------------------------------------------------------------------------------------------------------------------------------ (US$) Fixed WTI Price 5,000 bbls/d April 2003 - March 2004 28.50/bbl Fixed NYMEX Price 12,000 mmbtu/d April 2003 - March 2004 5.35/mmbtu
During 2002 and 2001, we purchased fixed-to-floating swaps to modify the terms of certain fixed-price natural gas contracts as we prefer to receive an index-based price for our natural gas. Under the terms of these contracts, we were required to deliver four million cubic feet per day of natural gas to counterparties at prices ranging from $3.06 to $6.08 per mcf. On settlement, we received or paid cash for the difference between the contract and floating rates on the affected volumes. These swaps expired in 2003. 31 MARKETING AND TRADING ACTIVITIES Our marketing operation is involved in the marketing and trading of crude oil and natural gas, through the use of both physical and financial contracts (energy trading activities). These activities expose us to commodity price risk. Open positions exist where not all contracted purchases and sales have been matched, in order to take advantage of market movements. These net open positions allow us to generate income, but also expose us to risk of loss due to fluctuating market prices (market risk) and credit exposure. We control the level of market risk through daily monitoring of our energy-trading portfolio relative to: o prescribed limits for Value-at-Risk (VaR); o nominal size of commodity positions; o stop loss limits; and o stress testing. VaR is a statistical estimate that is reliable when normal market conditions prevail. Our VaR calculation estimates the maximum probable loss given a 95% confidence level that we would incur if we were to unwind our outstanding positions over a two-day period. We estimate VaR using the Variance-Covariance method based on historical commodity price volatility and correlation inputs. Our estimate is based upon the following key assumptions: o changes in commodity prices are normally distributed; o price volatility remains stable; and o price correlation relationships remain stable. If a severe market shock occurred, the key assumptions underlying our VaR estimate could be violated and the potential loss could be greater than our estimate. There were no changes in the methodology we used to estimate VaR in 2003. Stress testing complements our VaR estimate. It is used to ensure that we are not exposed to large losses, not captured by VaR, which might result from infrequent but extreme market conditions. Our Board of Directors has approved formal risk management policies for our energy trading activities. Market and credit risks are monitored daily by a risk group that operates independently and ensures compliance with our risk management policies. The Finance Committee of the Board of Directors and our Risk Management Committee monitor our exposure to the above risks and review the results of energy trading activities regularly. FOREIGN-CURRENCY RATE RISK A substantial portion of our operations are denominated in or referenced to US dollars. These activities include: o prices received for sales of crude oil, natural gas and certain chemicals products; o capital spending and expenses related to our oil and gas and chemicals operations outside Canada; and o short-term and long-term borrowings. We manage our exposure to fluctuations between the US and Canadian dollar by matching our expected net cash flows and borrowings in the same currency. Net revenue from our foreign operations and our US-dollar borrowings are generally used to fund US-dollar capital expenditures and debt repayments. Since the timing of cash inflows and outflows is not necessarily interrelated, particularly for capital expenditures, we maintain revolving US-dollar borrowing facilities that can be used or repaid depending on expected net cash flows. We designate our long-term US-dollar borrowings as a hedge against our US-dollar net investment in foreign operations. We do not have any material exposure to highly inflationary foreign currencies. We occasionally use derivative instruments to effectively convert cash flows from Canadian to US dollars and vice versa. Information regarding our foreign currency net investments, borrowings and related derivative instruments is provided in Note 5 to the Consolidated Financial Statements. INTEREST RATE RISK We are exposed to fluctuations in short-term interest rates from our floating-rate debt and, to a lesser extent, derivative instruments, as their market value is sensitive to interest rate fluctuations. We maintain a portion of our debt capacity in revolving, floating-rate bank facilities with the remainder issued in fixed-rate borrowings. To minimize our exposure to interest rate fluctuations, we occasionally use derivative instruments as described in Note 5 to the Consolidated Financial Statements. At December 31, 2003, we had no floating-rate debt outstanding (2002 - $nil; 2001 - $424 million). 32 CREDIT RISK Credit risk is the risk of loss if customers or counterparties do not fulfill their contractual obligations. Most of our receivables are with customers in the energy industry requiring our products on an ongoing basis. These customers are subject to normal industry credit risk. This concentration of risk within the energy industry is mitigated through our broad domestic and international customer base. It is also possible that derivative instrument counterparties will not fulfill their contractual obligations. We take the following measures to reduce this risk: o we assess the financial strength of our customer and counterparty base through a rigorous credit process; o we limit the total exposure extended to individual counterparties, and may require collateral from some counterparties; o we routinely monitor credit risk exposures, including sector, geographic and corporate concentrations of credit, and report these to our Risk Management Committee and the Finance Committee of the Board; o we set credit limits based on counterparty credit ratings and internal models, which are based primarily on company and industry analysis; o we review counterparty credit limits regularly; and o we use standard agreements that allow for netting of positive and negative exposures associated with a single counterparty. We believe these measures minimize our overall credit risk. However, there can be no assurance that these processes will protect us against all losses from non-performance. At December 31, 2003: o 90% of our counterparty exposures were investment grade; and o only five customers individually made up greater than 5% of our exposure from energy trading activities. All were investment grade. CRITICAL ACCOUNTING ESTIMATES As an oil and gas producer, there are a number of critical estimates underlying the accounting policies we apply when preparing our Consolidated Financial Statements. These critical estimates are discussed below. OIL AND GAS ACCOUNTING - RESERVES DETERMINATION We follow the successful efforts method of accounting for our oil and gas activities, as described in Note 1 to our Consolidated Financial Statements. Successful efforts accounting depends on the estimated reserves we believe are recoverable from our oil and gas properties. The process of estimating reserves is complex. It requires significant judgements and decisions based on available geological, geophysical, engineering and economic data. These estimates may change substantially as additional data from ongoing development activities and production performance becomes available and as economic conditions impacting oil and gas prices and costs change. Our reserve estimates are based on current production forecasts, prices and economic conditions. See Business Risk Management for a complete discussion of our reserves estimation process. Reserve estimates are critical to many of our accounting estimates, including: o Determining whether or not an exploratory well has found economically producible reserves. If successful, we capitalize the costs of the well, and if not, we expense the costs immediately. In 2003, $70 million of our total $180 million spent on exploration drilling was expensed in the year. If none of our drilling had been successful, our net income would have decreased by $72 million after tax. o Calculating our unit-of-production depletion and asset retirement obligation rates. Both proved and proved developed reserve (1) estimates are used to determine rates that are applied to each unit-of-production in calculating our depletion expense and our provision for dismantlement and site restoration. Proved reserves are used where a property is acquired and proved developed reserves are used where a property is drilled and developed. In 2003, oil and gas depletion, before impairment charges, and oil and gas dismantlement and site restoration costs of $636 million and $34 million, respectively, were recorded in depletion, depreciation and amortization expense. If our reserve estimates changed by 10%, our depletion, depreciation and amortization expense would have changed by approximately $50 million, after tax, assuming no other changes to our reserve profile. ---------------- (1) "Proved" oil and gas reserves are the estimated quantities of natural gas, crude oil, condensate and natural gas liquids that geological and engineering data demonstrate with reasonable certainty can be recoverable in future years from known reservoirs under existing economic and operating conditions. Reservoirs are considered "proved" if economic producability is supported by either actual production or a conclusive formation test. "Proved developed" oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operation methods. 33 o Assessing, when necessary, our oil and gas assets for impairment. Estimated future undiscounted cash flows are determined using proved reserves. The critical estimates used to assess impairment, including the impact of changes in reserve estimates, are discussed below. As circumstances change and additional data becomes available, our reserve estimates also change, possibly materially impacting net income. Estimates made by our engineers are reviewed and revised, either upward or downward, as warranted by the new information. Revisions are often required due to changes in well performance, prices, economic conditions and governmental restrictions. Although we make every reasonable effort to ensure that our reserve estimates are accurate, reserve estimation is an inferential science. As a result, the subjective decisions, new geological or production information and a changing environment may impact these estimates. Revisions to our reserve estimates can arise from changes in year-end oil and gas prices, and reservoir performance. Such revisions can be either positive or negative. Reserves information is shown in the Supplementary Financial Information set out in Item 8 of this Form 10-K. It would take a very significant decrease in our proved reserves to limit our ability to borrow money under our term credit facilities, as previously described in Liquidity. OIL AND GAS ACCOUNTING - IMPAIRMENT We evaluate our oil and gas properties for impairment if an adverse event or change occurs. Among other things, this might include falling oil and gas prices, a significant revision to our reserve estimates, changes in operating costs, or significant or adverse political changes. If one of these occurs, we estimate undiscounted future cash flows for affected properties to determine if they are impaired. If the undiscounted future cash flows for a property are less than the carrying amount of that property, we calculate its fair value using a discounted cash flow approach. The property is then written down to its fair value. We assessed our oil and gas properties for impairment following the 2003 revisions to our reserve estimates. As a result of this assessment, it was determined that certain Canadian oil and gas properties were impaired. These properties were written down to their fair value which resulted in an impairment charge of $175 million, after-tax. See Note 4 to the Consolidated Financial Statements for further information. Our cash flow estimates for purposes of our impairment assessments require assumptions about two primary elements - future prices and reserves. Our estimates of future prices require significant judgements about highly uncertain future events. Historically, oil and gas prices have exhibited significant volatility - over the last five years, prices for WTI and NYMEX gas have ranged from US$10/bbl to US$38/bbl and US$2/mmbtu to US$10/mmbtu, respectively. Our forecasts for oil and gas revenues are based on prices derived from a consensus of future price forecasts amongst industry analysts and our own assessments. Our estimates of future cash flows generally assume our long-term price forecast and forecast operating costs. Given the significant assumptions required and the possibility that actual conditions will differ, we consider the assessment of impairment to be a critical accounting estimate. A change in this estimate would impact all except our chemicals business. If we decreased our long-term forecast for WTI crude oil prices by US$1.00-1.50/bbl, our initial assessment of impairment indicators would not change. Although oil and gas prices fluctuate a great deal in the short-term, they are typically stable over a longer-time horizon. This mitigates the potential for impairment. It is difficult to determine and assess the impact of a decrease in our proved reserves on our impairment tests. The relationship between the reserve estimate and the estimated undiscounted cash flows, and the nature of the property-by-property impairment test, is complex. As a result, we are unable to provide a reasonable sensitivity analysis of the impact that a reserve estimate decrease would have on our assessment of impairment. We do, however, have confidence in our reserve estimates. Any impairment charges would lower our net income. 34 NEW ACCOUNTING PRONOUNCEMENTS CANADIAN PRONOUNCEMENTS In December 2001, the Canadian Institute of Chartered Accountants (CICA) issued Accounting Guideline 13, HEDGING RELATIONSHIPS (AcG-13). AcG-13 establishes certain conditions for when hedge accounting may be applied. The guideline is effective for fiscal years beginning on or after July 1, 2003. Adoption of AcG-13 is not expected to have a material impact on our financial position or results of operations as we are already in compliance with Financial Accounting Standards Board (FASB) Statement No. 133, ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES. In September 2002, the CICA approved Section 3063, IMPAIRMENT OF LONG-LIVED ASSETS (S.3063). S.3063 establishes standards for the recognition, measurement and disclosure of the impairment of long-lived assets, and applies to long-lived assets held for use. An impairment loss is recognized when the carrying amount of a long-lived asset is not recoverable and exceeds its fair value. S.3063 is effective for fiscal years beginning on or after April 1, 2003. Adoption of S.3063 is not expected to have a material impact on our financial position or results of operations. In December 2002, the CICA approved Section 3110, ASSET RETIREMENT OBLIGATIONS (S.3110). S.3110 requires liability recognition for retirement obligations associated with our property, plant and equipment. These obligations are initially measured at fair value, which is the discounted future value of the liabilities. This fair value is capitalized as part of the cost of the related assets and amortized to expense over their useful life. The liabilities accrete until we expect to settle the retirement obligations. S.3110 is effective for fiscal years beginning on or after January 1, 2004. The impact on our consolidated balance sheet at January 1, 2004, will be as follows: (Cdn$ millions) Increase/(Decrease) ------------------------------------------------------------------------------- Property, Plant and Equipment 81 Asset Retirement Obligation 126 Future Income Tax Liability (16) Retained Earnings (29) In February 2003, the CICA issued Accounting Guideline 14, DISCLOSURE OF GUARANTEES (AcG-14). AcG-14 establishes the disclosures required for obligations we may have under certain guarantees that we have issued. The disclosure requirements are effective for interim and annual periods beginning on or after January 1, 2003. We adopted FASB Interpretation No. 45, GUARANTOR'S ACCOUNTING AND DISCLOSURE REQUIREMENTS FOR GUARANTEES, INCLUDING INDIRECT GUARANTEES OF INDEBTEDNESS TO OTHERS, the US equivalent of AcG-14 for the year ended December 31, 2002. We have disclosed our guarantees in Note 10. There were no material guarantees outstanding at December 31, 2003. In November 2003, the CICA approved an amendment to Section 3860, FINANCIAL INSTRUMENTS - DISCLOSURE AND PRESENTATION, to clarify the difference between an equity and liability instrument. An equity instrument exists only when an instrument is settled in shares. This amendment is effective for fiscal years beginning on or after November 1, 2004. Once adopted, our preferred and subordinated securities would be reclassified from equity to long term debt, and the dividends paid would be classified as interest expense. Adoption of this amendment at December 31, 2003, would increase long term debt by $313 million, decrease preferred and subordinated securities by $364 million and increase the cumulative translation adjustment by $51 million. The following standards or revisions issued by the CICA do not impact us: o Section 1100, GENERAL ACCOUNTING PRINCIPLES effective for years beginning on or after October 31, 2003. o Section 1400, GENERAL STANDARDS OF FINANCIAL STATEMENT PRESENTATION effective for years beginning on or after October 31, 2003. o Accounting Guideline 15, CONSOLIDATION OF VARIABLE INTEREST ENTITIES, effective for annual and interim periods beginning on or after January 1, 2004. US PRONOUNCEMENTS The following standards issued by the FASB do not impact us: o Statement No. 149, AMENDMENT OF STATEMENT 133 ON DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES, effective for contracts entered into or modified after June 30, 2003 and for hedging relationships designated after June 30, 2003. o Interpretation No. 46, CONSOLIDATION OF VARIABLE INTEREST ENTITIES, effective for financial statements issued after January 31, 2003. 35 PART IV ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K The exhibits filed with this Amendment No. 1 to the Annual Report on Form 10-K/A are listed on the Exhibit Index below. EXHIBITS *31.1 Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. *31.2 Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. *32.1 Certification of periodic report by Chief Executive Officer pursuant to 18 U.S.C., Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. *32.2 Certification of periodic report by Chief Financial Officer pursuant to 18 U.S.C., Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. * Filed herewith 36 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Company has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on March 1, 2005. NEXEN INC. By: /s/ Charles W. Fischer -------------------------- Charles W. Fischer President, Chief Executive Officer and Director (Principal Executive Officer) 37