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Nexen's Third Quarter Results: Record Cash Flow CALGARY, ALBERTA--(MARKET WIRE)--Oct 29, 2008 -- Nexen delivered excellent third quarter results including
the highest quarterly cash flow in our history. Highlights
include: - Cash flow of $1.7 billion ($3.20/share) - Net income of $886 million ($1.68/share) - Production before royalties of 249,000 boe/d-impacted by hurricanes in the Gulf of Mexico - Long Lake bitumen production ramping up and reservoir performing well; upgrader units starting-up and first synthetic crude production imminent - Exploration success in the UK North Sea at Blackbird and Pink
Three Months Ended Nine Months Ended
September 30 September 30
--------------------------------------------
(Cdn$ millions) 2008 2007 2008 2007
----------------------------------------------------------------------------
Production (mboe/d)(1)
Before Royalties 249 261 257 251
After Royalties 209 214 214 204
Net Sales 2,213 1,446 6,154 3,985
Cash Flow from Operations(2) 1,685 868 3,670 2,379
Per Common Share ($/share)(2) 3.20 1.65 6.95 4.52
Net Income 886 403 1,896 892
Per Common Share ($/share) 1.68 0.77 3.59 1.69
Capital Expenditures 725 901 2,149 2,531
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(1) Production includes our share of Syncrude oil sands. US investors should
read the Cautionary Note to US Investors at the end of this release.
(2) For reconciliation of this non-GAAP measure see Cash Flow from
Operations on pg. 9.Financial Results-Building Cash in Uncertain Financial Markets During the quarter, our cash flow from operations was a record $1.7 billion. With no hedges in place and over 85% of our production weighted to crude oil, we were able to realize significant benefits from high oil prices. Even though oil prices started to fall towards the end of the third quarter, a strengthening US dollar relative to the Canadian dollar has kept our price realizations high. For the first nine months of the year, we have generated almost $3.7 billion of cash flow and this has exceeded our capital investment by over $1.5 billion. In the third quarter, we used $300 million of this excess to buy back approximately 10 million shares under our Normal Course Issuer Bid and we are continuing to buy back shares as we believe our stock is significantly undervalued. With the tightening credit markets, we realize cash is a valuable asset and we are building our cash reserves during this uncertain time. The average length to maturity of our public debt is approximately 20 years and our earliest maturities comprise our term credit facilities, which are available until 2012. For the full year, we expect our cash flow to be around $4.4 billion based on today's commodity prices and foreign exchange rates. Our cash netbacks continue to be among the highest in the industry as much of our production has low operating costs and low royalties. As a result, our producing assets are very capable of handling the recent decline in commodity prices. "In this marketplace, cash is king and we have substantial liquidity," stated Charlie Fischer, Nexen's President and Chief Executive Officer. "We are slowing capital expenditures to build cash during this period of global financial uncertainty and to ensure that the projects we undertake continue to generate attractive full-cycle returns. With our large capital projects at Long Lake and Buzzard behind us, the significant cash flow these projects generate will ensure that we remain strong during the downturn and well-positioned to take advantage of opportunities that will create value for our shareholders." Significant Items Affecting our Results Net income was a record $886 million for the quarter and includes a recovery of $408 million ($241 million after tax) for stock-based compensation resulting from the drop in our share price since the end of the second quarter. This recovery reverses the stock-based compensation charges we reported in previous quarters. We are required to mark-to-market our employee stock based compensation programs to reflect changes in the closing price of our stock as of the last day of each quarter. The difference between the closing price and the exercise price of our employee stock options is then expensed or recovered, as the case may be. During the third quarter, we completed an internal reorganization and financing of our assets in the North Sea which provided us with additional one-time tax deductions in the UK. We drew on our bank lines to complete the reorganization. This, together with falling commodity prices, will cause our expected 2008 tax liability to be lower than previously expected. As a result, we have adjusted our tax accrual and quarterly cash flow has increased accordingly. Following this reorganization, we are well positioned to move forward with our development and exploration plans in the North Sea. In the short term, these plans include the upcoming commissioning and start-up of Ettrick and our investment in the previously announced fourth platform at Buzzard to process hydrogen sulphide. Longer term, our plans include the future development of recent discoveries at Golden Eagle, Blackbird and Pink and an active exploration program. Refocusing our Marketing Division Our marketing division reported a cash flow loss of $65 million in the third quarter, reflecting continued but reduced losses from our natural gas marketing business which were partially offset by strong contributions from crude oil marketing. During the quarter, we recognized some gains on the use of physical storage and transportation assets and we have unrecognized gains, that we expect to realize on the future use of these assets, that more than offset the quarterly loss reported. Over the past few months, we have been simplifying our marketing strategies and positions to better support our underlying physical business which has been built around storage, blending and transportation. To this end, we are reducing our trading levels in an orderly fashion recognizing the challenging economic environment and we have reduced the overall size of our trading business to reduce volatility and focus on the physical side of our business. We are exiting trading positions that do not support our physical business and we are continuing to reduce trading exposures. This is reflected in the quarterly financial results from this division. Compared to the same time last year, our North American natural gas and crude oil financial trading volumes are down by approximately 43% and 40%, respectively. "We have made significant progress to date in refocusing our marketing business and getting back to basics, and this restructuring will continue in the coming months," said Fischer. "Despite the challenges this division has faced over the last two quarters, our marketing activities have contributed over $580 million to our cash flow over the last five years."
Quarterly Production Impacted by Hurricanes
Production before Production after
Crude Oil, NGLs and Royalties Royalties
Natural Gas (mboe/d) Q3 2008 Q2 2008 Q3 2008 Q2 2008
----------------------------------------------------------------------------
North Sea 103 103 103 103
Yemen 54 58 30 30
Canada - Oil & Gas 38 37 30 30
Canada - Bitumen 5 3 5 3
United States 20 28 17 24
Other Countries 6 6 5 5
Syncrude 23 19 19 16
------------------------------------------------
Total 249 254 209 211
------------------------------------------------Our third quarter production volumes averaged 249,000 boe/d (209,000 boe/d after royalties). Buzzard continues to perform well and contributed 89,600 boe/d (207,500 boe/d gross) to our quarterly volumes. Gulf of Mexico production was negatively impacted by hurricanes Gustav and Ike. While we incurred only minor damage from Gustav, Ike caused significant damage to a number of our properties, but more importantly, to surrounding infrastructure. Most of our deep-water production is currently shut-in awaiting facility or downstream pipeline repairs. Gunnison received minor damage while at Aspen and Wrigley, third-party host facilities were damaged. These fields are expected to resume production this year but timing is uncertain because of reliance on third-party repairs. Our Green Canyon 6, 50 and 137 fields are shut-in following the destruction of a third-party processing platform. We are currently evaluating alternative production options for these fields. On the shelf, Vermilion 321/340 incurred substantial damage to the lower decks on some of the platforms. We do not expect production there to be restored until 2009. A number of our other shelf properties have been brought back online and we are currently producing 6,500 boe/d compared to 30,000 boe/d prior to the storms. For the fourth quarter, we expect our Gulf of Mexico production to average between 10,000 and 20,000 boe/d. Volumes will depend on the timing of repair work and the readiness of third-party infrastructure, such as production platforms and pipelines. We carry insurance coverage for physical damage caused by hurricanes, subject to certain deductibles. Syncrude volumes were strong during the quarter as a result of improved uptime. In the second quarter, production was down as a result of maintenance to a sulphur unit that took longer than expected. In early September, turnaround work commenced on one of Syncrude's cokers. This turnaround was completed on schedule in mid October but following the start-up of the coker, unexpected vibrations were experienced on a fuel gas compressor. Unplanned compressor repair work has delayed the coker restart until early November, after which we expect production volumes to return to 25,000 bbls/d, net to us. Long Lake-Bitumen Production Ramping Up Commissioning of the gasifier was delayed by about three weeks. Upon initial test firing, mechanical issues were identified with several automated valves and the burners required change-out. The burner change-out work has been completed and the automated valves have been repaired. The valves have been reinstalled and the gasifier is in the process of being refired. Once the gasifier achieves steady state operations, the hydrocracker and sulphur units will be started and we expect first synthetic production to commence shortly thereafter. On the bitumen front, the reservoir is performing well, the reliability of our surface facilities is improving, steam injection rates are at their highest levels since SAGD start-up and production rates are increasing. In the field, 45 of the total 81 well pairs have now been converted to SAGD operation, gross production rates averaged 15,200 bbls/d for the first half of October and recently exceeded 19,000 bbls/d. The average steam to oil ratio (SOR) for the wells that have been converted to SAGD operation is currently about 4.0. About one-quarter of these wells are already at or below our long-term SOR expectation of 3.0 and approximately 10% have achieved targeted bitumen production rates. We expect to reach full design rates of 72,000 bbls/d of bitumen production (36,000 bbls/d net to us), upgraded to approximately 60,000 bbls/d of Premium Sweet Crude (PSC(TM)) late next year or early 2010. "After years of construction at Long Lake, we are pleased to be very close to first production of synthetic crude. Commissioning and start-up of the upgrader is a complex and rigorous process and these activities will be carried out with full attention to safety and the environment," stated Fischer. "We expect Long Lake to generate significant value for our shareholders as the patented process substantially reduces the need to purchase natural gas, a key cost driver in oilsands projects." Phase 1 of Long Lake will develop approximately 10% of our oil sands inventory. We are engaged in engineering and planning for Phase 2 and have received regulatory approval for the Phase 2 upgrader. Ultimately, the sanctioning of Phase 2 will depend on multiple factors including the initial performance of Phase 1, receiving regulatory approval for Phase 2 SAGD operations, receiving clarity on proposed climate change regulations, finalizing cost estimates and an improved economic environment. "We are committed to the development of our oil sands leases in a measured and responsible manner," commented Fischer. "However, given continuing cost pressures in the industry, uncertain financial markets and lower commodity prices, we believe it is best to be patient in the near term." North Sea Continues Successful Exploration Program In the North Sea, we drilled a discovery at Pink that encountered 57 feet of net oil pay. This discovery was followed up with a sidetrack delineation well that encountered 134 feet of net oil pay. These results are encouraging and consistent with pre-drill estimates. We see additional prospects in the area and are currently assessing them. Pink is a candidate for co-development with Golden Eagle where we are currently reviewing development options. We have a 34% operated interest in Golden Eagle and a 46% operated working interest in Pink. During the quarter, we also made a discovery at Blackbird which is located six kilometres south of our operated Ettrick field. The well encountered 111 feet of net pay in multiple zones, was drill-stem tested and flowed at an average restricted rate of 3,800 bbls/d. Further appraisal is planned with a view to tieing Blackbird back to Ettrick. We operate both Ettrick and Blackbird and have an 80% working interest in each. Delivery of the floating production, storage and offloading vessel (FPSO) we are leasing for Ettrick has been delayed until December following commissioning delays in Singapore. The cost of these delays is borne by the owner of the FPSO. First production is now scheduled for early 2009. Production volumes are expected to average between approximately 15,000 and 20,000 boe/d in 2009. The FPSO is designed to handle 30,000 bbls/d of oil and 35 mmcf/d of gas and has capacity for nearby discoveries such as Blackbird. Gulf of Mexico-Encouraging Hydrocarbon Shows at Cote de Mer At our Cote de Mer prospect, located on the Louisiana coast, exploration drilling was interrupted by hurricanes Gustav and Ike. Upon resuming drilling operations, we experienced drilling difficulties. We have encountered the target reservoir but have not yet reached the target depth of 21,900 feet. We are encouraged by the preliminary data obtained and are currently conducting pipe recovery operations in order to resume drilling to reach target depth. We have a 37.5% working interest in this prospect. In the Eastern Gulf of Mexico, we drilled the Fredericksburg exploration well. Target sands were reached but we did not encounter commercial hydrocarbons. This was the third prospect to be drilled in the area following earlier successes at Vicksburg and Shiloh. We remain optimistic about the potential of this emerging play and are currently working with Shell, the operator, to finalize 2009 plans for this area. We expect to drill an additional well here next year and have a feasibility study underway to assess development options for Vicksburg. We have a 25% interest in Vicksburg and a 20% interest in Shiloh and Fredericksburg. Development of the Longhorn discovery continues and first production is expected mid-year 2009 with a peak production rate of approximately 200 mmcf/d gross (50 mmcf/d, net to us). We have a 25% non-operated working interest here and ENI is the operator. At Knotty Head, we plan to drill an appraisal well in 2009 when the first of our two new deep-water drilling rigs arrives. We have a 25% operated interest in the field. Shale Gas Drilling Program Continues Following the success of last winter's drilling program in the Horn River basin in northeast British Columbia, we decided to drill two horizontal wells this summer. The wells have been drilled and are being fraced. The results from these wells will be taken into consideration as we plan our upcoming winter program for the area. This shale gas play has the potential to become one of the most significant shale gas plays in North America. It has been compared to the Barnett Shale in Texas by other operators in the area as it displays similar rock properties and play characteristics. We have approximately 88,000 acres in the Dilly Creek area of the Horn River basin with a 100% working interest. As previously announced, we estimate these lands contain between 3 and 6 trillion cubic feet (0.5 to 1.0 billion barrels of oil equivalent) of recoverable contingent resource which could double our total proved reserves. Further appraisal activity is required before these estimates can be finalized and commerciality established. "Shale gas is a great addition to our portfolio of assets," said Fischer. "The potential resource size is significant and its short cycle-time development complements our longer cycle-time projects by providing visible near-term growth." Coalbed Methane (CBM) Production Increases Our CBM production continues to increase and averaged 45 mmcf/d for the quarter. Since the beginning of the year, our production has increased approximately 60% as our existing wells dewater and we bring new ones on-stream. Performance is in line with expectations and underlines the increasing value of our CBM assets. Offshore West Africa, the Usan Development Progresses Development of the Usan field, offshore Nigeria is fully underway. The field development plan includes an FPSO vessel with a storage capacity of two million barrels of oil. All major contracts for deep-water facilities are proceeding with detailed engineering and early procurement of equipment and materials. The Usan field is expected to come on stream in early 2012 and will ramp up to a peak production rate of 180,000 bbls/d (36,000 bbls/d net to us). The Usan field development is located in OML 138 and is covered by the original production sharing contract for OPL 222 issued in 1993, with the Nigerian National Petroleum Corporation as concessionaire. The contract conveys the right to develop and produce crude oil and continue with exploration activity. We are currently processing three-dimensional seismic in anticipation of further exploratory drilling in the area in 2009. The Usan field was discovered in 2002 and is located approximately 100 km offshore in water depths ranging from 750 to 850 meters. Drilling of the development wells is expected to commence next year. Nexen has a 20% interest in exploration and development along with Elf Petroleum Nigeria Limited (20% and Operator), Chevron Petroleum Nigeria Limited (30%) and Esso Exploration and Production Nigeria (Offshore East) Limited (30%). Quarterly Dividend The Board of Directors has declared the regular quarterly dividend of $0.05 per common share payable January 1, 2009, to shareholders of record on December 10, 2008. Shareholders are advised that the dividend is an eligible dividend for Canadian Income Tax purposes. Nexen Inc. is an independent, Canadian-based global energy company, listed on the Toronto and New York stock exchanges under the symbol NXY. We are uniquely positioned for growth in the North Sea, Western Canada (including the Athabasca oil sands of Alberta and unconventional gas resource plays such as coalbed methane and shale gas), deep-water Gulf of Mexico, offshore West Africa and the Middle East. We add value for shareholders through successful full-cycle oil and gas exploration and development and leadership in ethics, integrity, governance and environmental protection. Information with respect to forward-looking statements and cautionary notes is set out below. Conference Call Charlie Fischer, President and CEO, and Marvin Romanow, Executive Vice- President and CFO, will host a conference call to discuss our financial and operating results and expectations for the future. Date: October 29, 2008 Time: 7:00 a.m. Mountain Time (9:00 a.m. Eastern Time) To listen to the conference call, please call one of the following: 416-641-2140 (Toronto) 800-952-4972 (North American toll-free) 800-6578-9898 (Global toll-free) A replay of the call will be available for two weeks starting at 2:30 p.m. Mountain Time, by calling 416-695-5800 (Toronto) or 800-408-3053 (toll-free) passcode 3273332 followed by the pound sign. A live and on demand webcast of the conference call will be available at www.nexeninc.com. Forward-Looking Statements Certain statements in this report constitute "forward-looking statements" (within the meaning of the United States Private Securities Litigation Reform Act of 1995, Section 21E of the United States Securities Exchange Act of 1934, as amended, and Section 27A of the United States Securities Act of 1933, as amended) or "forward-looking information" (within the meaning of applicable Canadian securities legislation). Such statements or information ("forward-looking statements") are generally identifiable by the terminology used such as "anticipate", "believe", "intend", "plan", "expect", "estimate", "budget", "outlook" or other similar words and include statements relating to or associated with individual wells, regions or projects. Any statements as to possible future crude oil, natural gas or chemicals prices, future production levels, future cost recovery oil revenues from our Yemen operations, future capital expenditures and their allocation to exploration and development activities, future earnings, future asset dispositions, future sources of funding for our capital program, future debt levels, availability of committed credit facilities, possible commerciality, development plans or capacity expansions, future ability to execute dispositions of assets or businesses, future cash flows and their uses, future drilling of new wells, ultimate recoverability of current and long-term assets, ultimate recoverability of reserves or resources, expected finding and development costs, expected operating performance, including expected reliability of operations and expected operating costs, future demand for chemicals products, estimates on a per share basis, sales, future expenditures and future allowances relating to environmental matters and dates by which certain areas will be developed or will come on stream, and changes in any of the foregoing are forward-looking statements. Statements relating to "reserves" or "resources" are forward-looking statements, as they involve the implied assessment, based on estimates and assumptions that the reserves and resources described exist in the quantities predicted or estimated, and can be profitably produced in the future. The forward-looking statements are subject to known and unknown risks and uncertainties and other factors which may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Such factors include, among others: market prices for oil and gas and chemicals products; our ability to explore, develop, produce, upgrade and transport crude oil and natural gas to markets; the results of exploration and development drilling and related activities; the risks inherent in operating in harsh climates; the risks inherent in operating significant facilities which process hazardous and potentially explosive materials under high temperature and pressure; volatility in energy trading markets; foreign-currency exchange rates; economic conditions in the countries and regions in which we carry on business including the increasing costs of materials and labour and the ability of suppliers to meet delivery schedules and cost estimates; governmental actions including changes to taxes or royalties, changes in environmental and other laws and regulations; renegotiations of contracts; results of litigation, arbitration or regulatory proceedings; and political uncertainty, including actions by terrorists, insurgent or other groups, or other armed conflict, including conflict between states. The impact of any one risk, uncertainty or factor on a particular forward-looking statement is not determinable with certainty as these factors are interdependent, and management's future course of action would depend on our assessment of all information at that time. Although we believe that the expectations conveyed by the forward-looking statements are reasonable based on information available to us on the date such forward-looking statements were made, no assurances can be given as to future results, levels of activity and achievements. Undue reliance should not be placed on the statements contained herein, which are made as of the date hereof and, except as required by law, Nexen undertakes no obligation to update publicly or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The forward-looking statements contained herein are expressly qualified by this cautionary statement. Readers should also refer to Items 1A and 7A in our 2007 Annual Report on Form 10-K for further discussion of the risk factors. Cautionary Note to US Investors The United States Securities and Exchange Commission (SEC) permits oil and gas companies, in their filings with the SEC, to discuss only proved reserves that are supported by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. In this disclosure, we may refer to "recoverable reserves", "probable reserves", "recoverable resources" and "recoverable contingent resources" which are inherently more uncertain than proved reserves. These terms are not used in our filings with the SEC. Our reserves and related performance measures represent our working interest before royalties, unless otherwise indicated. Please refer to our Annual Report on Form 10-K available from us or the SEC for further reserve disclosure. In addition, under SEC regulations, the Syncrude oil sands operations are considered mining activities rather than oil and gas activities. Production, reserves and related measures in this release include results from the Company's share of Syncrude. Under SEC regulations, we are required to recognize bitumen reserves rather than the upgraded premium synthetic crude oil we will produce and sell from Long Lake. Cautionary Note to Canadian Investors Nexen is required to disclose oil and gas activities under National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities (NI 51-101). However, the Canadian securities regulatory authorities (CSA) have granted us exemptions from certain provisions of NI 51-101 to permit US style disclosure. These exemptions were sought because we are a US Securities and Exchange Commission (SEC) registrant and our securities regulatory disclosures, including Form 10-K and other related forms, must comply with SEC requirements. Our disclosures may differ from those of Canadian companies who have not received similar exemptions under NI 51-101. Please read the "Special Note to Canadian Investors" in Item 7A in our 2007 Annual Report on Form 10-K, for a summary of the exemption granted by the CSA and the major differences between SEC requirements and NI 51-101. The summary is not intended to be all-inclusive or to convey specific advice. Reserve estimation is highly technical and requires professional collaboration and judgment. Because reserves data are based on judgments regarding future events, actual results will vary and the variations may be material. Variations as a result of future events are expected to be consistent with the fact that reserves are categorized according to the probability of their recovery. Please note that the differences between SEC requirements and NI 51-101 may be material. Our probable reserves disclosure applies the Society of Petroleum Engineers/World Petroleum Council (SPE/WPC) definition for probable reserves. The Canadian Oil and Gas Evaluation Handbook states there should not be a significant difference in estimated probable reserve quantities using the SPE/WPC definition versus NI 51-101. In this disclosure, we refer to oil and gas in common units called barrel of oil equivalent (boe). A boe is derived by converting six thousand cubic feet of gas to one barrel of oil (6mcf:1bbl). This conversion may be misleading, particularly if used in isolation, since the 6mcf:1bbl ratio is based on an energy equivalency at the burner tip and does not represent the value equivalency at the well head. Resources Nexen's estimates of contingent resources are based on definitions set out in the Canadian Oil and Gas Evaluation Handbook which generally describe contingent resources as those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Such contingencies may include, but are not limited to, factors such as economic, legal, environmental, political and regulatory matters or a lack of markets. Specific contingencies precluding these contingent resources being classified as reserves include but are not limited to: future drilling program results, drilling and completions optimization, stakeholder and regulatory approval of future drilling and infrastructure plans, access to required infrastructure, economic fiscal terms, a lower level of delineation, the absence of regulatory approvals, detailed design estimates and near-term development plans, and general uncertainties associated with this early stage of evaluation. The estimated range of contingent resources reflects conservative and optimistic likelihoods of recovery. However, there is no certainty that it will be commercially viable to produce any portion of these contingent resources. Nexen's estimates of discovered resources (equivalent to discovered petroleum initially-in-place) are based on definitions set out in the Canadian Oil and Gas Evaluation Handbook which generally describe discovered resources as those quantities of petroleum estimated, as of a given date, to be contained in known accumulations prior to production. Discovered resources do not represent recoverable volumes. We disclose additional information regarding resource estimates in accordance with NI 51-101. These disclosures can be found on our website and on SEDAR. Cautionary statement: In the case of discovered resources or a subcategory of discovered resources other than reserves, there is no certainty that it will be commercially viable to produce any portion of the resources. In the case of undiscovered resources or a subcategory of undiscovered resources, there is no certainty that any portion of the resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the resources.
Nexen Inc.
Financial Highlights
Three Months Nine Months
Ended September 30 Ended September 30
(Cdn$ millions) 2008 2007 2008 2007
----------------------------------------------------------------------------
Net Sales 2,213 1,446 6,154 3,985
Cash Flow from Operations 1,685 868 3,670 2,379
Per Common Share ($/share) 3.20 1.65 6.95 4.52
Net Income 886 403 1,896 892
Per Common Share ($/share) 1.68 0.77 3.59 1.69
Capital Investment (1) 725 901 2,149 2,531
Net Debt (2) 3,914 4,393 3,914 4,393
Common Shares Outstanding
(millions of shares) 521.0 527.4 521.0 527.4
--------------------------------------------
(1) Includes oil and gas development, exploration, and expenditures for
other property, plant and equipment.
(2) Net debt is defined as long-term debt and short-term borrowings less
cash and cash equivalents.
Cash Flow from Operations (1)
Three Months Nine Months
Ended September 30 Ended September 30
(Cdn$ millions) 2008 2007 2008 2007
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Oil & Gas and Syncrude
United Kingdom 1,056 563 2,857 1,416
Yemen (2) 195 171 543 511
Canada 131 35 344 130
United States 93 109 405 355
Other Countries 45 29 108 61
Marketing (65) (7) (216) 64
Syncrude 151 102 350 229
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1,606 1,002 4,391 2,766
Chemicals 28 26 60 62
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1,634 1,028 4,451 2,828
Interest and Other
Corporate Items (56) (89) (203) (276)
Income Taxes (3) 107 (71) (578) (173)
--------------------------------------------
Cash Flow from Operations (1) 1,685 868 3,670 2,379
--------------------------------------------
--------------------------------------------
(1) Defined as cash flow from operating activities before changes in
non-cash working capital and other. We evaluate our performance and
that of our business segments based on earnings and cash flow from
operations. Cash flow from operations is a non-GAAP term that
represents cash generated from operating activities before changes in
non-cash working capital and other and excludes items of a
non-recurring nature. We consider it a key measure as it demonstrates
our ability and the ability of our business segments to generate the
cash flow necessary to fund future growth through capital investment
and repay debt. Cash flow from operations may not be comparable with
the calculation of similar measures for other companies.
Three Months Nine Months
Ended September 30 Ended September 30
(Cdn$ millions) 2008 2007 2008 2007
----------------------------------------------------------------------------
Cash Flow from Operating
Activities 968 1,097 3,299 2,127
Changes in Non-Cash
Working Capital 840 (253) 468 19
Other (117) 30 (79) 253
Amortization of Premium for
Crude Oil Put Options (6) (6) (18) (20)
--------------------------------------------
Cash Flow from Operations 1,685 868 3,670 2,379
--------------------------------------------
--------------------------------------------
Weighted-average Number
of Common Shares Outstanding
(millions of shares) 525.9 527.4 528.3 526.8
--------------------------------------------
Cash Flow from Operations Per
Common Share ($/share) 3.20 1.65 6.95 4.52
--------------------------------------------
--------------------------------------------
(2) After in-country cash taxes of $81 million for the three months ended
September 30, 2008 (2007 -- $65 million) and $239 million for the nine
months ended September 30, 2008 (2007 - $174 million).
(3) Excludes in-country cash taxes in Yemen.
Nexen Inc.
Production Volumes (before royalties) (1)
Three Months Nine Months
Ended September 30 Ended September 30
2008 2007 2008 2007
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Crude Oil and NGLs (mbbls/d)
United Kingdom 100.0 90.0 102.0 77.2
Yemen 54.1 69.8 58.0 73.3
Canada 16.0 17.0 16.2 17.3
United States 8.5 14.2 11.2 17.3
Other Countries 5.7 6.5 5.7 6.2
Long Lake Bitumen 5.2 - 3.0 -
Syncrude (mbbls/d) (2) 22.9 25.2 20.4 21.9
-------------------------------------------
212.4 222.7 216.5 213.2
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Natural Gas (mmcf/d)
Canada 133 111 128 115
United States 70 98 94 95
United Kingdom 17 18 19 15
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220 227 241 225
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Total Production (mboe/d) 249 261 257 251
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-------------------------------------------
Production Volumes (after royalties)
Three Months Nine Months
Ended September 30 Ended September 30
2008 2007 2008 2007
----------------------------------------------------------------------------
Crude Oil and NGLs (mbbls/d)
United Kingdom 100.0 90.0 102.0 77.2
Yemen 29.9 39.0 30.3 41.8
Canada 12.0 12.9 12.3 13.5
United States 7.3 12.5 9.7 15.3
Other Countries 5.1 6.0 5.3 5.7
Long Lake Bitumen 5.2 - 3.0 -
Syncrude (mbbls/d) (2) 18.9 21.1 17.3 18.8
-------------------------------------------
178.4 181.5 179.9 172.3
-------------------------------------------
Natural Gas (mmcf/d)
Canada 107 94 107 96
United States 60 83 80 81
United Kingdom 17 18 19 15
-------------------------------------------
184 195 206 192
-------------------------------------------
Total Production (mboe/d) 209 214 214 204
-------------------------------------------
-------------------------------------------
Notes:
(1) We have presented production volumes before royalties as we measure our
performance on this basis consistent with other Canadian oil and gas
companies.
(2) Considered a mining operation for US reporting purposes.
Nexen Inc.
Oil and Gas Prices and Cash Netback (1)
Total
Quarters - 2008 Quarters - 2007 Year
(all dollar amounts -----------------------------------------------------
in Cdn$ unless noted) 1st 2nd 3rd 1st 2nd 3rd 4th 2007
----------------------------------------------------------------------------
PRICES:
WTI Crude Oil
(US$/bbl) 97.90 123.98 117.98 58.16 65.03 75.38 90.69 72.31
Nexen Average - Oil
(Cdn$/bbl) 93.00 118.00 115.56 61.69 72.27 75.86 82.80 73.43
NYMEX Natural Gas
(US$/mmbtu) 8.75 11.48 8.95 7.18 7.66 6.24 7.39 7.12
Nexen Average - Gas
(Cdn$/mcf) 7.97 10.21 8.65 7.58 7.52 5.80 6.47 6.81
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NETBACKS:
Canada - Heavy Oil
Sales (mbbls/d) 16.2 16.4 16.0 17.8 17.2 16.9 16.4 17.1
Price Received
($/bbl) 65.94 93.16 97.91 41.71 41.89 46.76 46.07 44.07
Royalties & Other 16.65 22.61 24.24 9.16 9.52 10.93 10.04 9.91
Operating Costs 15.76 17.17 16.99 13.65 15.14 14.53 15.22 14.62
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Netback 33.53 53.38 56.68 18.90 17.23 21.30 20.81 19.54
----------------------------------------------------------------------------
Canada - Natural Gas
Sales (mmcf/d) 127 126 133 118 116 112 124 118
Price Received
($/mcf) 7.57 9.67 8.00 7.16 7.06 5.17 5.88 6.32
Royalties & Other 1.18 1.53 1.52 1.26 1.09 0.78 0.86 1.00
Operating Costs 1.67 1.84 1.84 1.59 1.81 2.52 1.71 1.90
----------------------------------------------------------------------------
Netback 4.72 6.30 4.64 4.31 4.16 1.87 3.31 3.42
----------------------------------------------------------------------------
Yemen
Sales (mbbls/d) 62.5 57.4 54.2 77.5 72.7 69.9 66.2 71.5
Price Received
($/bbl) 96.57 120.39 115.92 63.02 77.34 78.27 88.24 76.29
Royalties & Other 48.07 59.21 52.47 28.17 33.84 34.73 43.04 34.69
Operating Costs 7.76 8.80 7.82 6.07 6.29 6.72 7.24 6.56
In-country Taxes 11.82 17.45 16.11 6.38 9.89 10.03 12.18 9.52
----------------------------------------------------------------------------
Netback 28.92 34.93 39.52 22.40 27.32 26.79 25.78 25.52
----------------------------------------------------------------------------
Syncrude
Sales (mbbls/d) 19.3 19.1 22.9 21.4 19.0 25.2 22.6 22.1
Price Received
($/bbl) 101.70 130.90 126.56 70.03 77.12 82.09 88.33 79.76
Royalties & Other 11.93 22.08 21.89 8.26 10.33 13.42 15.33 12.02
Operating Costs 35.16 45.09 32.40 24.40 29.91 22.37 27.52 25.80
----------------------------------------------------------------------------
Netback 54.61 63.73 72.27 37.37 36.88 46.30 45.48 41.94
----------------------------------------------------------------------------
United States
Crude Oil:
Sales (mbbls/d) 13.7 11.3 8.5 21.6 16.0 14.1 13.9 16.4
Price Received
($/bbl) 94.07 120.77 122.46 58.49 68.18 74.43 84.33 69.83
Natural Gas:
Sales (mmcf/d) 112 99 70 101 86 98 119 101
Price Received
($/mcf) 9.03 11.80 10.14 8.58 8.85 6.75 7.27 7.80
Total Sales Volume
(mboe/d) 32.4 27.8 20.2 38.4 30.4 30.5 33.8 33.3
Price Received
($/boe) 71.10 91.08 86.75 55.44 61.04 56.28 60.32 58.16
Royalties & Other 9.53 12.88 12.30 6.78 7.71 7.28 8.13 7.45
Operating Costs 8.20 9.28 15.62 8.11 9.46 7.40 8.78 8.43
----------------------------------------------------------------------------
Netback 53.37 68.92 58.83 40.55 43.87 41.60 43.41 42.28
----------------------------------------------------------------------------
United Kingdom
Crude Oil:
Sales (mbbls/d) 108.9 89.0 107.0 58.8 87.2 83.6 94.5 81.1
Price Received
($/bbl) 93.38 118.24 114.89 64.33 74.07 78.06 84.06 76.30
Natural Gas:
Sales (mmcf/d) 22 24 18 13 13 16 21 16
Price Received
($/mcf) 6.82 7.06 7.53 3.87 3.32 4.99 5.84 4.71
Total Sales Volume
(mboe/d) 112.6 93.0 110.0 60.8 89.3 86.3 98.0 83.7
Price Received
($/boe) 91.67 114.95 112.99 62.92 72.75 76.56 82.29 74.79
Operating Costs 5.67 7.42 6.71 9.60 6.59 6.28 6.23 6.94
----------------------------------------------------------------------------
Netback 86.00 107.53 106.28 53.32 66.16 70.28 76.06 67.85
----------------------------------------------------------------------------
Other Countries
Sales (mbbls/d) 6.0 5.7 5.7 5.8 6.2 6.5 6.2 6.2
Price Received
($/bbl) 91.85 113.18 120.11 59.81 68.04 76.29 79.74 71.29
Royalties & Other 7.46 8.95 9.42 4.80 5.62 6.46 6.60 5.90
Operating Costs 4.74 4.43 5.14 2.97 3.39 3.34 4.13 3.45
----------------------------------------------------------------------------
Netback 79.65 99.80 105.55 52.04 59.03 66.49 69.01 61.94
----------------------------------------------------------------------------
Company-Wide
Oil and Gas Sales
(mboe/d) 270.1 240.4 250.9 241.5 254.1 253.9 263.9 253.4
Price Received
($/boe) 85.90 108.26 106.22 59.13 68.48 69.82 75.50 68.46
Royalties & Other 14.87 19.92 16.98 12.26 12.65 13.02 14.37 13.10
Operating Costs 9.46 11.89 10.90 9.67 9.41 9.26 9.46 9.45
In-country Taxes 2.74 4.16 3.48 2.05 2.83 2.76 3.05 2.69
----------------------------------------------------------------------------
Netback 58.83 72.29 74.86 35.15 43.59 44.78 48.62 43.22
----------------------------------------------------------------------------
(1) Defined as average sales price less royalties and other, operating
costs, and in-country taxes in Yemen.
Nexen Inc.
Unaudited Consolidated Statement of Income
For the Three and Nine Months Ended September 30
Three Months Nine Months
(Cdn$ millions, except per share Ended September 30 Ended September 30
amounts) 2008 2007 2008 2007
----------------------------------------------------------------------------
Revenues and Other Income
Net Sales 2,213 1,446 6,154 3,985
Marketing and Other (Note 16) 131 226 387 773
----------------------------------------
2,344 1,672 6,541 4,758
----------------------------------------
Expenses
Operating 341 283 998 862
Depreciation, Depletion, Amortization
and Impairment 386 349 1,084 1,043
Transportation and Other 291 238 691 694
General and Administrative (Note 17) (308) 7 165 247
Exploration 112 67 245 221
Interest (Note 7) 16 40 59 134
----------------------------------------
838 984 3,242 3,201
----------------------------------------
Income before Income Taxes 1,506 688 3,299 1,557
----------------------------------------
Provision for Income Taxes
Current (26) 136 817 347
Future 645 142 583 303
----------------------------------------
619 278 1,400 650
----------------------------------------
Net Income before Non-Controlling
Interests 887 410 1,899 907
Less: Net Income Attributable to
Non-Controlling Interests (1) (7) (3) (15)
----------------------------------------
Net Income 886 403 1,896 892
----------------------------------------
----------------------------------------
Earnings Per Common Share ($/share)
Basic (Note 14) 1.68 0.77 3.59 1.69
----------------------------------------
----------------------------------------
Diluted (Note 14) 1.66 0.75 3.53 1.66
----------------------------------------
----------------------------------------
See accompanying notes to the Unaudited Consolidated Financial Statements.
Nexen Inc.
Unaudited Consolidated Balance Sheet
September 30 December 31
(Cdn$ millions, except share amounts) 2008 2007
----------------------------------------------------------------------------
Assets
Current Assets
Cash and Cash Equivalents 1,772 206
Restricted Cash 65 203
Accounts Receivable (Note 2) 4,369 3,502
Inventories and Supplies (Note 3) 813 659
Other 163 89
-----------------------------
Total Current Assets 7,182 4,659
-----------------------------
Property, Plant and Equipment
Net of Accumulated Depreciation, Depletion,
Amortization and Impairment of $8,566
(December 31, 2007 - $7,195) 13,968 12,498
Future Income Tax Assets 348 268
Deferred Charges and Other Assets (Note 4) 370 324
Goodwill 347 326
-----------------------------
Total Assets 22,215 18,075
-----------------------------
-----------------------------
Liabilities and Shareholders' Equity
Current Liabilities
Accounts Payable and Accrued Liabilities
(Note 6) 4,475 4,135
Income Taxes Payable 70 45
Accrued Interest Payable 67 54
Dividends Payable 27 13
-----------------------------
Total Current Liabilities 4,639 4,247
-----------------------------
Long-Term Debt (Note 7) 5,686 4,610
Future Income Tax Liabilities 2,507 2,290
Asset Retirement Obligations (Note 9) 925 792
Deferred Credits and Other Liabilities
(Note 10) 1,136 459
Non-Controlling Interests 59 67
Shareholders' Equity (Note 13)
Common Shares, no par value
Authorized: Unlimited
Outstanding: 2008 - 520,969,101 shares
2007 - 528,304,813 shares 963 917
Contributed Surplus 2 3
Retained Earnings 6,531 4,983
Accumulated Other Comprehensive Loss (233) (293)
-----------------------------
Total Shareholders' Equity 7,263 5,610
-----------------------------
Commitments, Contingencies and Guarantees
(Note 18)
----------------------------------------------------------------------------
Total Liabilities and Shareholders' Equity 22,215 18,075
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes to the Unaudited Consolidated Financial Statements.
Nexen Inc.
Unaudited Consolidated Statement of Cash Flows
For the Three and Nine Months Ended September 30
Three Months Nine Months
Ended September 30 Ended September 30
(Cdn$ millions) 2008 2007 2008 2007
----------------------------------------------------------------------------
Operating Activities
Net Income 886 403 1,896 892
Charges and Credits to Income not
Involving Cash (Note 15) 693 404 1,547 1,286
Exploration Expense 112 67 245 221
Changes in Non-Cash Working Capital
(Note 15) (840) 253 (468) (19)
Other 117 (30) 79 (253)
----------------------------------------
968 1,097 3,299 2,127
Financing Activities
Repayment of Short-Term Borrowings,
Net (4) (60) (4) (152)
Proceeds from (Repayment of) Term
Credit Facilities, Net 1,031 188 803 (767)
Repayment of Medium-Term Notes
(Note 7) - (150) (125) (150)
Proceeds from Long-Term Notes - - - 1,660
Proceeds from (Repayment of) Canexus
Term Credit Facilities, Net (9) 12 (19) 45
Proceeds from Canexus Notes (Note 7) - - 51 -
Dividends on Common Shares (26) (13) (66) (39)
Issue of Common Shares and Exercise
of Tandem Options 8 4 48 44
Repurchase of Common Shares for
Cancellation (Note 13) (300) - (300) -
Changes in Non-Cash Working Capital
(Note 15) 10 - 10 -
Other (2) (8) (11) (43)
----------------------------------------
708 (27) 387 598
Investing Activities
Capital Expenditures
Exploration and Development (689) (772) (2,064) (2,309)
Proved Property Acquisitions - (104) (2) (150)
Chemicals, Corporate and Other (36) (25) (83) (72)
Changes in Restricted Cash 196 (103) 143 (21)
Changes in Non-Cash Working Capital
(Note 15) (66) (33) (120) 11
Other 36 (1) (61) (15)
----------------------------------------
(559) (1,038) (2,187) (2,556)
Effect of Exchange Rate Changes on
Cash and Cash Equivalents 41 (18) 67 (98)
Increase in Cash and Cash Equivalents 1,158 14 1,566 71
Cash and Cash Equivalents - Beginning
of Period 614 158 206 101
----------------------------------------
Cash and Cash Equivalents - End of
Period 1,772 172 1,772 172
----------------------------------------
----------------------------------------
See accompanying notes to the Unaudited Consolidated Financial Statements.
Nexen Inc.
Unaudited Consolidated Statement of Shareholders' Equity
For the Three and Nine Months Ended September 30
Three Months Nine Months
Ended September 30 Ended September 30
(Cdn$ millions) 2008 2007 2008 2007
----------------------------------------------------------------------------
Common Shares
Balance at Beginning of Period 972 893 917 821
Issue of Common Shares 8 3 32 28
Proceeds from Tandem Options
Exercised for Shares - 1 16 16
Accrued Liability Relating to Tandem
Options Exercised for Shares 1 (6) 16 26
Repurchased under Normal Course
Issuer Bid (Note 13) (18) - (18) -
----------------------------------------
Balance at End of Period 963 891 963 891
----------------------------------------
----------------------------------------
Contributed Surplus
Balance at Beginning of Period 2 5 3 4
Stock-Based Compensation Expense - - - 1
Exercise of Tandem Options - (2) (1) (2)
----------------------------------------
Balance at End of Period 2 3 2 3
----------------------------------------
----------------------------------------
Retained Earnings
Balance at Beginning of Period 5,953 4,435 4,983 3,972
Net Income 886 403 1,896 892
Dividends on Common Shares (Note 13) (26) (13) (66) (39)
Repurchase of Common Shares (Note 13) (282) - (282) -
----------------------------------------------------------------------------
Balance at End of Period 6,531 4,825 6,531 4,825
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Accumulated Other Comprehensive Loss
Balance at Beginning of Period (274) (253) (293) (161)
Opening Derivatives Designated as
Cash Flow Hedges - - - 61
Other Comprehensive Income/(Loss) 41 (51) 60 (204)
----------------------------------------------------------------------------
Balance at End of Period (233) (304) (233) (304)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Nexen Inc.
Unaudited Consolidated Statement of Comprehensive Income
For the Three and Nine Months Ended September 30
Three Months Nine Months
Ended September 30 Ended September 30
(Cdn$ millions) 2008 2007 2008 2007
----------------------------------------------------------------------------
Net Income 886 403 1,896 892
Other Comprehensive Income, Net of
Income Taxes:
Foreign Currency Translation
Adjustment:
Net Gains (Losses) on Investment in
Self-Sustaining Foreign Operations 221 (327) 365 (822)
Net Gains (Losses) on Hedges of
Self-Sustaining Foreign Operations
(1) (180) 276 (305) 679
Cash Flow Hedges:
Realized Mark-to-Market Gains
Recognized in Net Income - - - (61)
--------------------------------------
Other Comprehensive Income/(Loss) 41 (51) 60 (204)
--------------------------------------
Comprehensive Income 927 352 1,956 688
--------------------------------------
--------------------------------------
(1) Net of income tax recovery for the three months ended September 30, 2008
of $26 million (2007 - net of income tax expense of $47 million) and net
of income tax recovery for the nine months ended September 30, 2008 of
$45 million (2007 - net of income tax expense of $113 million).
See accompanying notes to the Unaudited Consolidated Financial Statements.
Nexen Inc.
Notes to Unaudited Consolidated Financial Statements
Cdn$ millions, except as noted1. ACCOUNTING POLICIES Our Unaudited Consolidated Financial Statements are prepared in accordance with Canadian Generally Accepted Accounting Principles (GAAP). The impact of significant differences between Canadian and United States GAAP on the Unaudited Consolidated Financial Statements is disclosed in Note 20. In the opinion of management, the Unaudited Consolidated Financial Statements contain all adjustments of a normal and recurring nature necessary to present fairly Nexen Inc.'s (Nexen, we or our) financial position at September 30, 2008 and December 31, 2007 and the results of our operations and our cash flows for the three and nine months ended September 30, 2008 and 2007. We make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the Unaudited Consolidated Financial Statements, and revenues and expenses during the reporting period. Our management reviews these estimates on an ongoing basis, including those related to accruals, litigation, environmental and asset retirement obligations, income taxes, fair values of derivative contract assets and liabilities and determination of proved reserves. Changes in facts and circumstances may result in revised estimates and actual results may differ from these estimates. The results of operations and cash flows for the three and nine months ended September 30, 2008 are not necessarily indicative of the results of operations or cash flows to be expected for the year ending December 31, 2008. These Unaudited Consolidated Financial Statements should be read in conjunction with our Audited Consolidated Financial Statements included in our 2007 Annual Report on Form 10-K. Except as described below, the accounting policies we follow are described in Note 1 of the Audited Consolidated Financial Statements included in our 2007 Annual Report on Form 10-K. Change in Accounting Policies Inventories In 2007, we adopted the Canadian Institute of Chartered Accountants (CICA) Section 3031 Inventories issued by the Canadian Accounting Standards Board (AcSB). Effective October 1, 2007, we began carrying the commodity inventories held for trading by our energy marketing group at fair value, less any costs to sell. This standard was adopted prospectively and our results for the first nine months of 2007 have not been restated for this change in accounting policy. Capital Disclosures On January 1, 2008, we prospectively adopted CICA Section 1535 Capital Disclosures issued by the AcSB. This Section establishes standards for disclosing information about an entity's objectives, policies and processes for managing its capital structure. The disclosures have been included in Note 8. Financial Instruments Disclosures and Presentation On January 1, 2008, we prospectively adopted the following new standards issued by the AcSB: Financial Instruments - Disclosure (Section 3862) and Financial Instruments - Presentation (Section 3863). These accounting standards replaced Financial Instruments - Disclosure and Presentation (Section 3861). The disclosures required by Section 3862 and 3863 provide additional information on the risks associated with our financial instruments and how we manage those risks. The additional disclosures required by these standards are provided in Notes 11 and 12. New Accounting Pronouncements In February 2008, the AcSB confirmed that all Canadian publicly accountable enterprises will be required to adopt International Financial Reporting Standards (IFRS) for interim and annual reporting purposes for fiscal years beginning on or after January 1, 2011. We are currently assessing the impact of the convergence of Canadian GAAP with IFRS on our results of operations, financial position and disclosures. A project team has been set up to manage this transition and to ensure successful implementation within the required timeframe. We will provide disclosures of the key elements of our plan and progress on the project as the information becomes available during the transition period. In February 2008, the AcSB issued Section 3064, Goodwill and Intangible Assets and amended Section 1000, Financial Statement Concepts clarifying the criteria for the recognition of assets, intangible assets and internally developed intangible assets. Items that no longer meet the definition of an asset are no longer recognized with assets. The standard is effective for fiscal years beginning on or after October 1, 2008 and early adoption is permitted. We do not expect the adoption of this section to have a material impact on our results of operations and financial position.
2. ACCOUNTS RECEIVABLE
September 30 December 31
2008 2007
----------------------------------------------------------------------------
Trade
Marketing 3,083 2,501
Oil and Gas 1,046 819
Chemicals and Other 56 60
----------------------------
4,185 3,380
Non-Trade 227 132
----------------------------
4,412 3,512
Allowance for Doubtful Receivables (43) (10)
----------------------------
Total 4,369 3,502
----------------------------
----------------------------
3. INVENTORIES AND SUPPLIES
September 30 December 31
2008 2007
----------------------------------------------------------------------------
Finished Products
Marketing 721 577
Oil and Gas 18 14
Chemicals and Other 18 13
----------------------------
757 604
Work in Process 4 3
Field Supplies 52 52
----------------------------
Total 813 659
----------------------------
----------------------------
4. DEFERRED CHARGES AND OTHER ASSETS
September 30 December 31
2008 2007
----------------------------------------------------------------------------
Long-Term Energy Marketing Derivative Contracts
(Note 11) 217 248
Long-Term Capital Prepayments 77 9
Crude Oil Put Options and Natural Gas Swaps
(Note 11) 15 -
Asset Retirement Remediation Fund 13 13
Other 48 54
----------------------------
Total 370 324
----------------------------
----------------------------5. SUSPENDED WELL COSTS The following table shows the changes in capitalized exploratory well costs during the nine months ended September 30, 2008 and the year ended December 31, 2007, and does not include amounts that were initially capitalized and subsequently expensed in the same period. Capitalized exploratory well costs are included in property, plant and equipment (PP&E).
Nine Months Year
Ended Ended
September 30 December 31
2008 2007
----------------------------------------------------------------------------
Balance at Beginning of Period 326 226
Additions to Capitalized Exploratory Well
Costs Pending the Determination of Proved
Reserves 146 215
Capitalized Exploratory Well Costs Charged
to Expense (27) (10)
Transfers to Wells, Facilities and Equipment
Based on Determination of Proved Reserves (31) (74)
Effects of Foreign Exchange 14 (31)
----------------------------
Balance at End of Period 428 326
----------------------------
----------------------------The following table provides an aging of capitalized exploratory well costs based on the date drilling was completed and shows the number of projects for which exploratory well costs have been capitalized for a period greater than one year after the completion of drilling.
September 30 December 31
2008 2007
----------------------------------------------------------------------------
Capitalized for a Period of One Year or Less 150 202
Capitalized for a Period of Greater than
One Year 278 124
----------------------------
Balance at End of Period 428 326
----------------------------
----------------------------
Number of Projects that have Exploratory Well
Costs Capitalized for a Period Greater than
One Year 8 5
----------------------------As at September 30, 2008, we have exploratory costs that have been capitalized for more than one year relating to our interests in two exploratory blocks in the Gulf of Mexico ($102 million), our coalbed methane exploratory activities in Canada ($92 million), three exploratory blocks in the North Sea ($56 million), our interest in an exploratory block, offshore Nigeria ($19 million) and exploratory activities on Block 51 in Yemen ($9 million). These costs relate to projects with successful exploration wells for which we have not been able to record proved reserves. We are assessing all of these wells and projects, and are working with our partners to prepare development plans, drill additional appraisal wells or to assess commercial viability.
6. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES
September 30 December 31
2008 2007
----------------------------------------------------------------------------
Accrued Payables 2,908 2,546
Energy Marketing Derivative Contracts (Note 11) 723 413
Trade Payables 425 578
Stock-based Compensation (Note 17) 167 393
Other 252 205
----------------------------
Total 4,475 4,135
----------------------------
----------------------------
7. LONG-TERM DEBT AND SHORT-TERM BORROWINGS
September 30 December 31
2008 2007
----------------------------------------------------------------------------
Term Credit Facilities (US$1,000 million) (a) 1,060 211
Canexus Limited Partnership Term Credit
Facilities (US$186 million) (b) 197 202
Medium-Term Notes, due 2008 (c) - 125
Canexus Notes, due 2013 (US$50 million) (d) 53 -
Notes, due 2013 (US$500 million) 530 494
Notes, due 2015 (US$250 million) 265 247
Notes, due 2017 (US$250 million) 265 247
Notes, due 2028 (US$200 million) 212 198
Notes, due 2032 (US$500 million) 530 494
Notes, due 2035 (US$790 million) 837 781
Notes, due 2037 (US$1,250 million) 1,325 1,235
Subordinated Debentures, due 2043
(US$460 million) 488 454
----------------------------
5,762 4,688
Less: Unamortized Debt Issue Costs (76) (78)
----------------------------
Total 5,686 4,610
----------------------------
----------------------------(a) Term credit facilities We have unsecured term credit facilities of US$3 billion available to 2012, of which US$1 billion was drawn at September 30, 2008 (December 31, 2007 - US$214 million). Borrowings are available as Canadian bankers' acceptances, LIBOR-based loans, Canadian prime rate loans, US-dollar base rate loans or British pound call-rate loans. Interest is payable at floating rates. The weighted-average interest rate on our term credit facilities was 3.5% for the three months ended September 30, 2008 (2007 - 5.9%) and 3.6% for the nine months ended September 30, 2008 (2007 - 5.9%). At September 30, 2008, $458 million of these facilities were utilized to support outstanding letters of credit (December 31, 2007 - $283 million). (b) Canexus Limited Partnership term credit facilities Canexus Limited Partnership (Canexus) has committed, secured term credit facilities of $410 million available until 2011. At September 30, 2008, $197 million (US$186 million) was drawn on these facilities (December 31, 2007 - $202 million). Borrowings are available as Canadian bankers' acceptances, LIBOR-based loans, Canadian prime rate loans or US-dollar base rate loans. Interest is payable monthly at floating rates. The term credit facilities are secured by a floating charge debenture over all of Canexus' assets. The credit facility also contains covenants with respect to certain financial ratios. The weighted-average interest rate on our term credit facilities was 4.6% for the three months ended September 30, 2008 (2007 - 6.2%) and 4.5% for the nine months ended September 30, 2008 (2007 - 6.2%). (c) Medium-term notes, due 2008 During October 1997, we issued $125 million of notes. Interest was payable semi-annually at a rate of 6.3% and the principal was repaid in the second quarter of 2008. (d) Canexus notes, due 2013 During the second quarter of 2008, Canexus issued US$50 million of notes. Interest is payable quarterly at a rate of 6.57%, and the principal is to be repaid in May 2013. Canexus may redeem part or all of the notes at any time. The redemption price will be the greater of par and an amount that provides the same yield as a US Treasury security having a term to maturity equal to the remaining term of the notes plus 0.20%.
(e) Interest expense
Three Months Nine Months
Ended Ended
September 30 September 30
2008 2007 2008 2007
----------------------------------------------------------------------------
Long-Term Debt 75 80 220 244
Other 5 5 15 14
------------------------------------
80 85 235 258
Less: Capitalized (64) (45) (176) (124)
------------------------------------
Total 16 40 59 134
------------------------------------
------------------------------------Capitalized interest relates to and is included as part of the cost of our oil and gas properties under development. The capitalization rates are based on our weighted-average cost of borrowings. (f) Short-term borrowings Nexen has uncommitted, unsecured credit facilities of approximately $657 million, none of which were drawn at September 30, 2008 (December 31, 2007 - nil). We utilized $30 million of these facilities to support outstanding letters of credit at September 30, 2008 (December 31, 2007 - $196 million). Interest is payable at floating rates. The weighted-average interest rate on our short-term borrowings was 3.6% for the three months ended September 30, 2008 (2007 - 5.8%) and 3.2% for the nine months ended September 30, 2008 (2007 - 5.8%). 8. CAPITAL DISCLOSURES Our objective for managing our capital structure is to ensure that we have the financial capacity, liquidity and flexibility to fund our investment in full-cycle exploration and development of conventional and unconventional resources and for energy marketing activities. We generally rely on operating cash flows to fund capital investments. However, given the long cycle-time of some of our development projects which require significant capital investment prior to cash flow generation and volatile commodity prices, it is not unusual for capital expenditures to exceed our cash flow from operating activities in any given period. As such, our financing needs depend on where we are in a particular development cycle. This requires us to maintain financial flexibility and liquidity. Our capital management policies are aimed at: - maintaining an appropriate balance between short-term debt, long-term debt and equity; - maintaining sufficient undrawn committed credit capacity to provide liquidity; - ensuring ample covenant room permitting us to draw on credit lines as required; - maintaining a reasonable level of leverage; and - ensuring we maintain a credit rating that is appropriate for our circumstances. We have the ability to make adjustments to our capital structure by issuing additional equity or debt, returning cash to shareholders and making adjustments to our capital investment programs. Our capital consists of shareholders' equity, short-term and long-term debt and cash and cash equivalents as follows:
September 30 December 31
2008 2007
----------------------------------------------------------------------------
Net Debt (1)
Bank Debt 1,257 413
Senior Notes 3,956 3,758
----------------------------
Senior Debt 5,213 4,171
Subordinated Debt 473 439
----------------------------
Total Debt 5,686 4,610
Less: Cash and Cash Equivalents (1,772) (206)
----------------------------
Total Net Debt 3,914 4,404
----------------------------
----------------------------
Shareholders' Equity 7,263 5,610
----------------------------
----------------------------
(1) Includes all of our borrowings and is calculated as long-term debt and
short-term borrowings less cash and cash equivalents.We monitor the leverage in our capital structure by reviewing the ratio of net debt to cash flow from operating activities as well as interest coverage ratios. We use the ratio of net debt to cash flow from operating activities as a key indicator of our leverage and to monitor the strength of our balance sheet. Net debt is a non-GAAP measure which is calculated using the GAAP measures of long-term debt and short-term borrowings less cash and cash equivalents (excluding restricted cash). For the twelve months ended September 30, 2008, our net debt to cash flow from operating activities ratio was 1.0 times compared to 1.6 times at December 31, 2007. While we typically expect the target ratio to fluctuate between 1.0 and 2.0 times under normalized commodity prices, this can be higher when we identify strategic opportunities requiring additional investment. Whenever we exceed our target ratio, we assess whether to implement a strategy to reduce our leverage and lower this ratio back to target levels. In the past, each time we exceeded our internal net debt to cash flow from operating activities target band, we successfully brought our leverage down through asset sales and capital investment management. Our interest coverage ratio allows us to monitor our ability to fund the interest requirements associated with our debt. Our interest coverage strengthened in 2008 from 12.1 times at the end of 2007 to 18.1 times at September 30, 2008. Interest coverage is calculated by dividing our twelve-month trailing earnings before interest, taxes, depreciation, depletion, amortization and impairment (EBITDA) by interest expense before capitalized interest. EBITDA is a non-GAAP measure which is calculated using net income excluding interest expense, provision for income taxes, exploration expenses, depreciation, depletion, amortization and impairment (DD&A) and other non-cash expenses. The calculation of EBITDA is set out in the following table.
Twelve Months Twelve Months
Ended Ended
September 30 December 31
2008 2007
----------------------------------------------------------------------------
Net Income 2,090 1,086
Add:
Interest Expense 93 168
Provision for Income Taxes 1,542 792
Depreciation, Depletion, Amortization and
Impairment 1,808 1,767
Exploration Expense 350 326
Other Non-Cash Expenses (112) (52)
----------------------------
EBITDA 5,771 4,087
----------------------------
----------------------------
9. ASSET RETIREMENT OBLIGATIONS
Changes in carrying amounts of the asset retirement obligations associated
with our property, plant and equipment are as follows:
Nine Months Year
Ended Ended
September 30 December 31
2008 2007
----------------------------------------------------------------------------
Balance at Beginning of Period 832 704
Obligations Incurred with Development
Activities 17 105
Expenditures Made on Asset Retirements (30) (23)
Accretion 41 44
Revisions to Estimates 102 79
Effects of Foreign Exchange 3 (77)
----------------------------
Balance at End of Period (1,) (2) 965 832
----------------------------
----------------------------
(1) Obligations due within 12 months of $40 million (December 31, 2007 - $40
million) have been included in accounts payable and accrued liabilities.
(2) Obligations relating to our oil and gas activities amount to $916
million (December 31, 2007 - $786 million) and obligations relating to
our chemicals business amount to $49 million (December 31, 2007 - $46
million).Our total estimated undiscounted inflated asset retirement obligations amount to $2,350 million (December 31, 2007 - $2,165 million). We have discounted the total estimated asset retirement obligations using a weighted-average, credit-adjusted, risk-free rate of 6.1%. Approximately $132 million included in our asset retirement obligations will be settled over the next five years. The remaining obligations settle beyond five years and will be funded by future cash flows from our operations. We own interests in assets for which the fair value of the asset retirement obligations cannot be reasonably determined because the assets currently have an indeterminate life and we cannot determine when remediation activities would take place. These assets include our interest in Syncrude's upgrader and sulphur pile, and our interest in the Long Lake upgrader. The estimated future recoverable reserves at Syncrude and Long Lake are significant and given the long life of these assets, we are unable to determine when asset retirement activities would take place. Furthermore, the Syncrude plant and the Long Lake upgrader can both continue to run indefinitely with ongoing maintenance activities. The retirement obligations for these assets will be recorded in the first year in which the obligation to remediate becomes determinable.
10. DEFERRED CREDITS AND OTHER LIABILITIES
September 30 December 31
2008 2007
----------------------------------------------------------------------------
Deferred Tax Credit 649 -
Long-Term Energy Marketing Derivative
Contracts (Note 11) 183 163
Deferred Transportation Revenue 68 82
Fixed-Price Natural Gas Contracts and Swaps
(Note 11) 35 51
Defined Benefit Pension Obligations 62 57
Capital Lease Obligations 53 52
Long-Term Stock-based Compensation - 2
Other 86 52
----------------------------
Total 1,136 459
----------------------------
----------------------------During the quarter, we completed an internal reorganization and financing of our assets in the North Sea which provided us with an additional one-time tax deduction in the UK. As these transactions were completed within our consolidated group, we are unable to recognize the benefit of the tax deductions until the assets are recognized in income by way of a sale to a third party or depletion through use. Accordingly, we have deferred recognizing $649 million of tax credits in our consolidated income statement. 11. FINANCIAL INSTRUMENTS Financial instruments carried at fair value on our balance sheet include cash and cash equivalents, restricted cash and derivatives used for trading and non-trading purposes. Our other financial instruments including accounts receivable, accounts payable, income taxes payable, accrued interest payable, dividends payable, short-term borrowings and long-term debt are carried at cost or amortized cost. The carrying value of our short-term receivable and payables approximates their fair value because the instruments are near maturity. In our energy marketing group, we enter into contracts to purchase and sell crude oil and natural gas and use derivative contracts, including futures, forwards, swaps and options, for hedging and trading purposes (collectively derivatives). We also use derivatives to manage commodity price risk and foreign currency risk for non-trading purposes. We categorize our derivative instruments as trading or non-trading activities and carry the instruments at fair value on our balance sheet. The derivatives section below details our derivatives and fair values as at September 30, 2008. The fair values are included with accounts receivable or payable and are classified as long-term or short-term based on anticipated settlement date. Any change in fair value is included in marketing and other income. We carry our long-term debt at amortized cost using the effective interest rate method. At September 30, 2008, the estimated fair value of our long-term debt was $4,940 million (December 31, 2007 - $4,692 million) as compared to the carrying value of $5,686 million (December 31, 2007 - $4,610 million). The fair value of long-term debt is estimated based on prices provided by quoted markets and third-party brokers. Derivatives (a) Total carrying value of derivative contracts related to trading activities The fair value and carrying amounts related to derivative instruments held by our energy marketing operations are as follows:
September 30 December 31
2008 2007
----------------------------------------------------------------------------
Accounts Receivable 781 334
Deferred Charges and Other Assets (1) 217 248
----------------------------
Total Derivative Assets 998 582
----------------------------
----------------------------
Accounts Payable and Accrued Liabilities 723 413
Deferred Credits and Other Liabilities (1) 183 163
----------------------------
Total Derivative Liabilities 906 576
----------------------------
----------------------------
Total Net Derivatives related to Trading
Activities (2) 92 6
----------------------------
----------------------------
(1) These derivative contracts settle beyond 12 months and are considered
non-current.
(2) Comprised of $107 million (2007 - $15 million) related to commodity
contracts and losses of $15 million (2007 - $9 million loss) related to
US-dollar forward contracts and swaps.(b) Total carrying value of derivative contracts related to non-trading activities The fair value and carrying amounts related to derivative instruments related to non-trading activities are as follows:
September 30 December 31
2008 2007
----------------------------------------------------------------------------
Accounts Receivable - -
Deferred Charges and Other Assets (1) 15 1
-----------------------------
Total Derivative Assets 15 1
-----------------------------
-----------------------------
Accounts Payable and Accrued Liabilities 27 28
Deferred Credits and Other Liabilities (1) 35 51
-----------------------------
Total Derivative Liabilities 62 79
-----------------------------
-----------------------------
Total Net Derivatives related to Non-Trading
Activities (47) (78)
-----------------------------
-----------------------------
(1) These derivative contracts settle beyond 12 months and are considered
non-current.Crude oil put options In 2008, we purchased put options on approximately 70,000 bbls/d of our 2009 crude oil production. These options establish an annual average Brent floor price of US$60/bbl on these volumes. In September 2008, Lehman Brothers filed for bankruptcy protection. This impacts approximately 36% (or 25,000 bbls/d) of our 2009 put options and the carrying value of these put options has been reduced to nil. In 2007, we purchased put options on 36 million barrels or approximately 100,000 bbls/d of our 2008 crude oil production. These options establish an annual average Dated Brent floor price of US$50/bbl on these volumes. The put options are carried at fair value within amounts receivable and are classified as long-term or short-term based on their anticipated settlement date. Any change in fair value is included in marketing and other income.
Notional Average Fair
Volumes Term Floor Price Value
----------------------------------------------------------------------------
(bbls/d) (US$/bbl) (Cdn$ millions)
Dated Brent Crude Oil Put
Options 100,000 2008 50 -
Dated Brent Crude Oil Put
Options 45,000 2009 60 13
----------------
13
----------------
----------------Fixed-price natural gas contracts and natural gas swaps We have fixed-price natural gas sales contracts and offsetting natural gas swaps that are not part of our trading activities. These sales contracts and swaps are carried at fair value and are classified as long-term or short-term based on their anticipated settlement date. Any change in fair value is included in marketing and other income.
Notional Average
Volumes Term Price
----------------------------------------------------------------------------
(Gj/d) ($/Gj) (Cdn$ millions)
Fixed-Price Natural Gas
Contracts 15,514 2008 2.46 (24)
15,514 2009 - 2010 2.56 - 2.77 (35)
Natural Gas Swaps 15,514 2008 7.60 (3)
15,514 2009 - 2010 7.60 2
----------------
(60)
----------------
----------------(c) Fair value of derivatives Wherever possible, the estimated fair value of our derivative instruments is based on quoted market prices, and if not available, on estimates from third-party brokers. We utilize market data or assumptions that market participants would use when pricing the asset or liability, including assumptions about risk. As a basis for establishing fair value, we utilize a mid-market pricing convention between bid and ask and then adjust our pricing to the ask price when we have a net open sell position and the bid price when we have a net open buy position. We incorporate the credit risk associated with counterparty default into our estimates of fair value. Inputs to fair valuations may be readily observable, market-corroborated, or generally unobservable. We utilize valuation techniques that maximize the use of observable inputs wherever possible and minimize the use of unobservable inputs. To value longer-term transactions and transactions in less active markets for which pricing information is not generally available, unobservable inputs may be used. We classify the fair value of our derivatives according to the following hierarchy based on the amount of observable inputs used to value the instruments. - Level 1 - Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of financial instruments such as exchange-traded derivatives and we use information from markets such as the New York Mercantile Exchange and the International Petroleum Exchange. - Level 2 - Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reported date. Level 2 valuations are based on inputs, including quoted forward prices for commodities, time value, volatility factors, and broker quotations, which can be observed or corroborated in the marketplace. Instruments in this category include non-exchange traded derivatives such as over-the-counter physical forwards and options. We obtain information from sources such as the Natural Gas Exchange, independent price publications and over-the-counter broker quotes. - Level 3 - Valuations in this level are based on inputs which are less observable, unavailable or where the observable data does not support the majority of the instrument's fair value. Level 3 instruments include longer-term transactions, transactions in less active markets or transactions at locations for which pricing information is not available. In these instances, internally developed methodologies are used to determine fair value which primarily includes extrapolation of observable future prices to similar locations, similar instruments or later time periods. The following table includes our derivatives that are carried at fair value on a recurring basis for our trading and non-trading activities as at September 30, 2008. Financial assets and liabilities are classified in the fair value hierarchy in their entirety based on the lowest level of input that is significant to the fair value measurement. Assessment of the significance of a particular input to the fair value measurement requires judgment and may affect placement within the fair value hierarchy levels.
Level 1 Level 2 Level 3 Total
---------------------------------------
Net Derivatives
Trading Derivatives 136 (44) - 92
Non-Trading Derivatives - (47) - (47)
---------------------------------------
Total Net Derivatives 136 (91) - 45
---------------------------------------
---------------------------------------
A reconciliation of changes in the fair value of our derivatives classified
as Level 3 for the nine months ended September 30, 2008 is provided below:
Level 3
----------------------------------------------------------------------------
Fair Value at January 1, 2008 (7)
Realized and unrealized gains (losses) 5
Purchases, issuances and settlements (3)
Transfers in and/or out of Level 3 5
---------
Fair Value at September 30, 2008 -
---------
---------
Unsettled gains (losses) relating to instruments still held as of
September 30, 2008 10
---------
---------Transfers in and/or out represent existing assets and liabilities that were either previously categorized as a higher level for which the inputs became unobservable or assets and liabilities that were previously classified as Level 3 for which the lowest significant input became observable during the period. 12. RISK MANAGEMENT (a) Market Risk We invest in significant capital projects, purchase and sell commodities, issue short and long-term debt and invest in foreign operations. These activities expose us to market risk from changes in commodity prices, foreign exchange rates and interest rates, which affect our earnings and the value of the financial instruments we hold. We use derivatives for trading and non-trading purposes as part of our overall risk management policy to manage exposures to market risk that result from these activities. The following market risk discussion relates primarily to commodity price risk and foreign exchange risk related to our financial instruments. Our exposure to interest rate risk is immaterial. Commodity price risk We are exposed to commodity price movements as part of our normal oil and gas operations, particularly in relation to the prices received for our crude oil and natural gas. Commodity price risk related to conventional and synthetic crude oil prices is our most significant market risk exposure. Crude oil and natural gas are sensitive to numerous worldwide factors, many of which are beyond our control, and are generally sold at contract or posted prices. Changes in world crude oil and natural gas prices may significantly affect our results of operations and cash generated from operating activities. Consequently, such prices also may affect the value of our oil and gas properties and our level of spending for exploration and development. The majority of our oil and gas production is sold under short-term contracts, exposing us to the risk of price movements. Other energy contracts we enter into also expose us to commodity price risk between the time we purchase and sell contracted volumes. We periodically manage these risks by using derivative contracts such as commodity put options. Our energy marketing group markets and trades crude oil, natural gas, NGLs, ethanol and power through physical purchase and sales contracts, as well as financial commodity contracts. These activities expose us to commodity price risk, as well as foreign currency risk and volatility within these markets. Our energy marketing group actively manages risk by utilizing energy and currency derivatives. We typically take advantage of location, time and quality spreads using physical and financial contracts. Our marketing group also tries to take advantage of volatility within commodity markets and can establish net open commodity positions to take advantage of existing market conditions. Volatility within various commodity markets can vary and change over time. While this volatility gives us opportunities, it can also cause our results to vary significantly between periods. We attempt to manage the associated risk and take on positions based on market intelligence; however, it is possible that we could incur financial loss. Open positions exist when not all contracted purchases and sales terms have been matched. These net open positions allow us to generate income, but also expose us to risk of loss due to fluctuating market prices (market risk sensitivities in our portfolio). We manage the level of market risk through daily monitoring of our energy trading activities relative to: - prescribed limits for Value-at-Risk (VaR); - nominal size of commodity positions; - stop loss limits; and - stress testing. VaR is a statistical estimate assuming normal market conditions exist. 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 primarily by using the Variance-Covariance method based on historical commodity price volatility, correlation inputs where available and by historical simulation in other situations. Our estimate is based upon the following key assumptions: - changes in commodity prices follow a statistical pattern of distribution; - price volatility remains stable; and - price correlation relationships remain stable. If a severe market shock occurred, the key assumptions underlying our VaR estimate could be exceeded and the potential loss could be greater than our estimate. We also use stress testing using extreme market movements which complements our VaR estimates. Stress testing is used to quantify potential unexpected losses from low probability market movements. Our VaR analysis incorporates our derivative positions, non-derivative transportation and storage contracts and assets, as well as our commodity trading inventories.
Our quarter end, high, low, and average VaR amounts for the three and nine
months ended September 30 are as follows:
Three Months Nine Months
Ended September 30 Ended September 30
2008 2007 2008 2007
----------------------------------------------------------------------------
Value-at-Risk
Quarter End 27 34 27 34
High 33 38 40 38
Low 19 28 19 24
Average 29 33 31 31
----------------------------------------Foreign currency risk Foreign exchange risk is created by fluctuations in the fair values or cash flows of financial instruments due to changes in foreign exchange rates. A substantial portion of our activities are transacted in or referenced to US dollars including: - sales of crude oil, natural gas and certain chemicals products; - capital spending and expenses for our oil and gas, Syncrude and chemicals operations; - commodity derivative contracts used primarily by our energy marketing group; and - short-term and long-term borrowings. In our oil and gas operations, we manage our exposure to fluctuations between the US and Canadian dollar by matching our expected net cash flows and borrowings in the same currency. Net revenue from our foreign operations and our US-dollar borrowings are generally used to fund US-dollar capital expenditures and debt repayments. We maintain revolving Canadian and US-dollar borrowing facilities that can be used or repaid depending on expected net cash flows. We designate our US-dollar borrowings as a hedge against our US-dollar net investment in self-sustaining foreign operations. At September 30, 2008, we had US$5,436 million of long-term debt issued in US dollars and a one cent change in the US dollar to Canadian dollar exchange rate would increase or decrease our accumulated other comprehensive income by approximately $54 million, before income tax. In our energy marketing group, the majority of the financial commodity contracts are denominated in US dollars. We enter into US-dollar forward contracts and swaps to manage this exposure. We also have exposures to currencies other than the US dollar. A portion of our United Kingdom operating expenses, capital spending and future asset retirement obligations are denominated in British pounds and Euros. We do not have any material exposure to highly inflationary foreign currencies. (b) Credit Risk Credit risk affects both our trading and non-trading activities and is the risk of loss if counterparties do not fulfill their contractual obligations. The majority of our accounts receivable are with counterparties in the energy industry, including integrated oil companies, refiners and utilities, and are subject to normal industry credit risk. Approximately 85% of our accounts receivable are with these large energy companies. This concentration of risk within the energy industry is reduced because of our broad base of domestic and international counterparties. We assess the financial strength of our counterparties, including those involved in marketing and other commodity arrangements, and we limit the total exposure to individual counterparties. As well, a number of our contracts contain provisions that allow us to demand the posting of collateral in the event of a downgrade to a non-investment grade credit rating. Credit risk, including credit concentrations, is routinely reported to management. We also use standard agreements that allow for the netting of exposures associated with a single counterparty. We believe this minimizes our overall credit risk. However, there can be no assurance that these processes will protect us against all losses from non-performance. At September 30, 2008: - over 96% of our credit exposures were investment grade; - approximately 85% of our credit exposures were with integrated oil companies, crude oil refiners & marketers and large utilities; and - only two counterparties individually made up more than 5% of our credit exposure, and one of these counterparties made up more than 10% of our credit exposure. Both counterparties are super major integrated oil companies with strong investment grade ratings. In light of current market conditions, we have increased our monitoring of credit exposure. We review our counterparty credit risks daily to effectively limit our exposures. In September, Lehman Brothers filed for bankruptcy protection and our exposure at the time was approximately $38 million. This amount was written off in the quarter however we continue to pursue recovery of these amounts. Our maximum counterparty credit exposure at the balance sheet date consists primarily of the carrying amounts of non-derivative financial assets such as accounts receivable, as well as the fair value of derivative financial assets. There are no significant amounts past due at the balance sheet date for which we have not provided. Collateral received from customers at September 30, 2008 includes $62 million of cash and $603 million of letters of credit. The cash received is included in our accounts payable and accrued liabilities. (c) Liquidity Risk Liquidity risk is the risk that we will not be able to meet our financial obligations as they fall due. We require liquidity specifically to fund capital requirements, satisfy financial obligations as they become due, and to engage in our energy marketing business. We generally rely on operating cash flows to provide liquidity and we also maintain significant undrawn committed credit facilities. At September 30, 2008, we had $1.8 billion of cash and cash equivalents on hand. Approximately US$1 billion of this amount was a result of draws made on our term credit facilities, which were used for an internal reorganization and financing of our North Sea assets. In addition, we have undrawn term credit facilities of US$1.6 billion. These facilities are available until 2012. We also have $657 million of undrawn, uncommitted credit facilities, of which $30 million was supporting letters of credit at September 30, 2008. The following table details the contractual maturities for our non-derivative financial liabilities, including both the principal and interest cash flows at September 30, 2008:
Less Greater
than 1 1-3 4-5 than 5
Total Year Years Years Years
----------------------------------------------------------------------------
Long-Term Debt 5,762 - - 1,257 4,505
Interest on Long-Term
Debt (1) 6,708 286 572 572 5,278
------------------------------------------------
Total 12,470 286 572 1,829 9,783
------------------------------------------------
------------------------------------------------
(1) Excludes interest on term credit facilities of $3.2 billion and Canexus
LP term credit facilities of $410 million as the amounts drawn on the
facilities fluctuate. As a result, we are unable to provide a reasonable
estimate of the interest.
The following table details contractual maturities for our derivative
financial liabilities. The balance sheet amounts for derivative financial
liabilities included below are not materially different from the contractual
amounts due on maturity.
Less Greater
than 1 1-3 4-5 than 5
Total Year Years Years Years
----------------------------------------------------------------------------
Trading Derivatives 906 723 183 - -
Non-Trading Derivatives 62 27 35 - -
------------------------------------------------
Total 968 750 218 - -
------------------------------------------------
------------------------------------------------The commercial agreements our energy marketing group enters into often include financial assurance provisions that allow us and our counterparties to effectively manage credit risk. The agreements normally require collateral to be posted if an adverse credit-related event, such as a drop in credit ratings, occurs. Based on contracts in place and commodity prices at September 30, 2008, we could be required to post collateral of up to $1.6 billion if we were downgraded to non-investment grade. These obligations are reflected on our balance sheet. The posting of collateral merely secures the payment of such amounts. In the event of a ratings downgrade, we have trading inventories and receivables that can be quickly monetized as well as significant undrawn credit facilities. At September 30, 2008, collateral posted with counterparties includes $73 million of cash and $296 million of letters of credit related to our trading activities. Cash posted is included with our accounts receivable. Cash collateral is not normally applied to contract settlement. Once a contract has been settled, the collateral amounts are refunded. If there is a default, the cash is retained. Our exchange-traded derivative contracts are also subject to margin requirements. We have margin deposits of $65 million (December 31, 2007 - $203 million), which have been included in restricted cash. 13. SHAREHOLDERS' EQUITY (a) Dividends Dividends per common share for the three months ended September 30, 2008 were $0.05 per common share (2007 - $0.025). Dividends per common share for the nine months ended September 30, 2008 were $0.125 (2007 - $0.075). Dividends paid to holders of common shares have been designated as "eligible dividends" for Canadian tax purposes. (b) Normal Course Issuer Bid In July 2008, we received approval from the Toronto Stock Exchange (TSX) for a Normal Course Issuer Bid (Bid). Under the Bid, we are allowed to repurchase for cancellation up to 10% of our public float of common shares, approximately 53 million shares. Purchases under the Bid commenced August 6, 2008 and can be made until August 5, 2009. Purchases can be made on the open market through the TSX and the New York Stock Exchange at the market price at the time of acquisition. During the quarter, we purchased 10 million common shares at an average price of $30.05 per common share for a total cost of $300 million. Of the amount paid, $18 million reduced the book value of our common shares. The cost to repurchase common shares in excess of their average book value has been charged to retained earnings ($282 million). 14. EARNINGS PER COMMON SHARE We calculate basic earnings per common share using net income and the weighted-average number of common shares outstanding. We calculate diluted earnings per common share in the same manner as basic, except we use the weighted-average number of diluted common shares outstanding in the denominator.
Three Months Nine Months
Ended September 30 Ended September 30
(millions of shares) 2008 2007 2008 2007
----------------------------------------------------------------------------
Weighted-average number of common
shares outstanding 525.9 527.4 528.3 526.8
Shares issuable pursuant to tandem
options 19.6 25.7 24.9 27.0
Shares notionally purchased from
proceeds of tandem options (13.0) (15.3) (16.2) (15.2)
--------------------------------------
Weighted-average number of diluted
common shares outstanding 532.5 537.8 537.0 538.6
--------------------------------------
--------------------------------------In calculating the weighted-average number of diluted common shares outstanding for the three and nine months ended September 30, 2008, we excluded 4,019,880 and 40,000 tandem options, respectively, because their exercise price was greater than the average common share market price in the period. In calculating the weighted-average number of diluted common shares outstanding for the three and nine months ended September 30, 2007, we excluded 80,000 and 45,445 tandem options respectively, because their exercise price was greater than the average common share market price in the period. During the periods presented, outstanding tandem options were the only potential dilutive instruments.
15. CASH FLOWS
(a) Charges and credits to income not involving cash
Three Months Nine Months
Ended September 30 Ended September 30
2008 2007 2008 2007
----------------------------------------------------------------------------
Depreciation, Depletion,
Amortization and Impairment 386 349 1,084 1,043
Stock-Based Compensation (410) (106) (210) (132)
Future Income Taxes 645 142 583 303
Change in Fair Value of Crude Oil
Put Options (9) 11 1 31
Net Income Attributable to
Non-Controlling Interests 1 7 3 15
Allowance for Doubtful Accounts 38 (2) 34 (3)
Other 42 3 52 29
--------------------------------------
Total 693 404 1,547 1,286
--------------------------------------
--------------------------------------
(b) Changes in non-cash working capital
Three Months Nine Months
Ended September 30 Ended September 30
2008 2007 2008 2007
----------------------------------------------------------------------------
Accounts Receivable 503 122 (821) 55
Inventories and Supplies 260 200 (128) 21
Other Current Assets (64) (29) (80) (18)
Accounts Payable and Accrued
Liabilities (862) (96) 496 (156)
Income Taxes Payable (745) 20 (71) 76
Accrued Interest Payable 12 3 13 14
Dividends Payable - - 13 -
--------------------------------------
Total (896) 220 (578) (8)
--------------------------------------
--------------------------------------
Relating to:
Operating Activities (840) 253 (468) (19)
Financing Activities 10 - 10 -
Investing Activities (66) (33) (120) 11
--------------------------------------
Total (896) 220 (578) (8)
--------------------------------------
--------------------------------------
(c) Other cash flow information
Three Months Nine Months
Ended September 30 Ended September 30
2008 2007 2008 2007
----------------------------------------------------------------------------
Interest Paid 64 77 212 233
Income Taxes Paid 655 127 816 284
--------------------------------------
Cash flow from other operating activities includes cash outflows related to
geological and geophysical expenditures of $38 million for the three months
ended September 30, 2008 (2007 - $19 million) and $72 million for the nine
months ended September 30, 2008 (2007 - $79 million).
16. MARKETING AND OTHER INCOME
Three Months Nine Months
Ended September 30 Ended September 30
2008 2007 2008 2007
----------------------------------------------------------------------------
Marketing Revenue, Net 149 219 381 750
Change in Fair Value of Crude Oil Put
Options 9 (11) (1) (31)
Interest 7 10 20 29
Foreign Exchange Losses (33) (11) (34) (54)
Other (1) 19 21 79
--------------------------------------
Total 131 226 387 773
--------------------------------------
--------------------------------------17. STOCK BASED COMPENSATION We account for our stock-based compensation programs using the intrinsic-value method and therefore fluctuating share prices create volatility in our net income. We recovered non-cash stock-based compensation costs that were previously expensed, of $410 million for the three months ended September 30, 2008 (2007 - $106 million) and $210 million for the nine months ended September 30, 2008 (2007 - $132 million). Cash payments made in connection with out stock-based compensation programs during the quarter amounted to $2 million (2007 - $29 million) and year-to-date payments totaled $89 million (2007 - $116 million). These amounts are included in general and administrative expense. 18. COMMITMENTS, CONTINGENCIES AND GUARANTEES As described in Note 15 to the Audited Consolidated Financial Statements included in our 2007 10-K, there are a number of lawsuits and claims pending, the ultimate results of which cannot be ascertained at this time. We record costs as they are incurred or become determinable. We believe the resolution of these matters would not have a material adverse effect on our liquidity, consolidated financial position or results of operations. 19. OPERATING SEGMENTS AND RELATED INFORMATION Nexen is involved in activities relating to Oil and Gas, Energy Marketing, Syncrude and Chemicals in various geographic locations as described in Note 20 to the Audited Consolidated Financial Statements included in our 2007 Annual Report on Form 10-K.
Three months ended September 30, 2008
(Cdn$ millions) Oil and Gas
----------------------------------------------------------------------------
United United Other
Yemen Canada States Kingdom Countries (1)
---------------------------------------------------
Net Sales 317 192 139 1,141 56
Marketing and Other 2 1 - 6 1
---------------------------------------------------
Total Revenues 319 193 139 1,147 57
Less: Expenses
Operating 39 48 29 66 2
Depreciation, Depletion,
Amortization and
Impairment 46 50 56 192 4
Transportation and Other 3 - 1 21 -
General and
Administrative (3) (20) (66) (28) (19) (45)
Exploration 2 5 41 18 46 (4)
Interest - - - - -
---------------------------------------------------
Income (Loss)
before Income Taxes 249 156 40 869 50
Less: Provisions for
(Recovery of) Income
Taxes 86 44 13 444 (3)
Less: Non-Controlling
Interests - - - - -
---------------------------------------------------
Net Income (Loss) 163 112 27 425 53
---------------------------------------------------
---------------------------------------------------
Identifiable Assets 365 6,301 (5) 1,951 6,502 536
---------------------------------------------------
---------------------------------------------------
Capital Expenditures
Development and Other 29 245 46 189 35
Exploration - 34 38 43 11
---------------------------------------------------
29 279 84 232 46
---------------------------------------------------
---------------------------------------------------
Property, Plant and
Equipment
Cost 2,402 7,697 3,670 5,558 358
Less: Accumulated DD&A 2,220 1,725 2,072 1,456 95
---------------------------------------------------
Net Book Value 182 5,972 (5) 1,598 4,102 263
---------------------------------------------------
---------------------------------------------------
Corporate
Energy and
(Cdn$ millions) Marketing Syncrude Chemicals Other Total
----------------------------------------------------------------------------
Net Sales 17 220 131 - 2,213
Marketing and Other 149 3 (12) (19) (2) 131
---------------------------------------------------
Total Revenues 166 223 119 (19) 2,344
Less: Expenses
Operating 10 68 79 - 341
Depreciation, Depletion,
Amortization and
Impairment 4 12 11 11 386
Transportation and Other 235 4 12 15 291
General and
Administrative (3) (4) - 9 (135) (308)
Exploration - - - - 112
Interest - - 3 13 16
---------------------------------------------------
Income (Loss)
before Income Taxes (79) 139 5 77 1,506
Less: Provisions for
(Recovery of) Income
Taxes (20) 40 2 13 619
Less: Non-Controlling
Interests - - 1 - 1
---------------------------------------------------
Net Income (Loss) (59) 99 2 64 886
---------------------------------------------------
---------------------------------------------------
Identifiable Assets 4,468 (6) 1,218 541 333 22,215
---------------------------------------------------
---------------------------------------------------
Capital Expenditures
Development and Other 2 19 24 10 599
Exploration - - - - 126
--------------------------------------------------
2 19 24 10 725
---------------------------------------------------
---------------------------------------------------
Property, Plant and
Equipment
Cost 268 1,363 896 322 22,534
Less: Accumulated DD&A 72 232 495 199 8,566
---------------------------------------------------
Net Book Value 196 1,131 401 123 13,968
---------------------------------------------------
---------------------------------------------------
(1) Includes results of operations from producing activities in Colombia.
(2) Includes interest income of $7 million, foreign exchange losses of $33
million, increase in the fair value of crude oil put options of $9
million and other losses of $2 million.
(3) Includes recovery of stock-based compensation expense of $408 million.
(4) Includes exploration activities primarily in Norway and Colombia.
(5) Includes costs of $4,432 million related to our Synthetic group (Long
Lake Phase 1 and future phases) which are not being depreciated,
depleted or amortized.
(6) Approximately 85% of Marketing's identifiable assets are accounts
receivable and inventories.
Nine months ended September 30, 2008
(Cdn$ millions) Oil and Gas
----------------------------------------------------------------------------
United United Other
Yemen Canada States Kingdom Countries (1)
---------------------------------------------------
Net Sales 912 545 518 3,053 156
Marketing and Other 9 2 4 17 2
---------------------------------------------------
Total Revenues 921 547 522 3,070 158
Less: Expenses
Operating 129 137 77 186 7
Depreciation, Depletion,
Amortization and
Impairment 120 144 192 505 12
Transportation and Other 7 10 2 21 -
General and
Administrative (3,4) (9) 13 23 (7) 14
Exploration 2 41 70 42 90 (5)
Interest - - - - -
---------------------------------------------------
Income (Loss)
before Income Taxes 672 202 158 2,323 35
Less: Provisions for
(Recovery of) Income
Taxes 234 57 55 1,181 (3)
Less: Non-Controlling
Interests - - - - -
---------------------------------------------------
Net Income (Loss) 438 145 103 1,142 38
---------------------------------------------------
---------------------------------------------------
Identifiable Assets 365 6,301 (6) 1,951 6,502 536
---------------------------------------------------
---------------------------------------------------
Capital Expenditures
Development and Other 61 855 180 410 73
Exploration 9 146 147 114 30
Proved Property
Acquisition - 2 - - -
---------------------------------------------------
70 1,003 327 524 103
---------------------------------------------------
---------------------------------------------------
Property, Plant and
Equipment
Cost 2,402 7,697 3,670 5,558 358
Less: Accumulated DD&A 2,220 1,725 2,072 1,456 95
---------------------------------------------------
Net Book Value 182 5,972 (6) 1,598 4,102 263
---------------------------------------------------
---------------------------------------------------
Corporate
Energy and
(Cdn$ millions) Marketing Syncrude Chemicals Other Total
----------------------------------------------------------------------------
Net Sales 52 567 351 - 6,154
Marketing and Other 381 3 (13) (18) (2) 387
---------------------------------------------------
Total Revenues 433 570 338 (18) 6,541
Less: Expenses
Operating 33 208 221 - 998
Depreciation, Depletion,
Amortization and
Impairment 11 36 32 32 1,084
Transportation and Other 574 11 41 25 691
General and
Administrative (3,4) 63 1 24 43 165
Exploration - - - - 245
Interest - - 8 51 59
---------------------------------------------------
Income (Loss)
before Income Taxes (248) 314 12 (169) 3,299
Less: Provisions for
(Recovery of) Income
Taxes (72) 89 5 (146) 1,400
Less: Non-Controlling
Interests - - 3 - 3
---------------------------------------------------
Net Income (Loss) (176) 225 4 (23) 1,896
---------------------------------------------------
---------------------------------------------------
Identifiable Assets 4,468 (7) 1,218 541 333 22,215
---------------------------------------------------
---------------------------------------------------
Capital Expenditures
Development and Other 3 39 57 23 1,701
Exploration - - - - 446
Proved Property
Acquisition - - - - 2
---------------------------------------------------
3 39 57 23 2,149
---------------------------------------------------
---------------------------------------------------
Property, Plant and
Equipment
Cost 268 1,363 896 322 22,534
Less: Accumulated DD&A 72 232 495 199 8,566
---------------------------------------------------
Net Book Value 196 1,131 401 123 13,968
---------------------------------------------------
---------------------------------------------------
(1) Includes results of operations from producing activities in Colombia.
(2) Includes interest income of $20 million, foreign exchange losses of $34
million, decrease in the fair value of crude oil put options of $1
million and other losses of $3 million.
(3) Includes a severance accrual of $7 million in connection with North
Vancouver technology conversion project.
(4) Includes recovery of stock-based compensation expense of $121 million.
(5) Includes exploration activities primarily in Norway and Colombia.
(6) Includes costs of $4,432 million related to our Synthetic group (Long
Lake Phase 1 and future phases) which are not being depreciated,
depleted or amortized.
(7) Approximately 85% of Marketing's identifiable assets are accounts
receivable and inventories.
Three months ended September 30, 2007
(Cdn$ millions) Oil and Gas
----------------------------------------------------------------------------
United United Other
Yemen Canada States Kingdom Countries (1)
---------------------------------------------------
Net Sales 280 101 137 608 42
Marketing and Other 2 - 1 7 -
---------------------------------------------------
Total Revenues 282 101 138 615 42
Less: Expenses
Operating 43 49 21 50 2
Depreciation, Depletion,
Amortization and
Impairment 54 41 66 151 2
Transportation and Other 2 5 - - -
General and
Administrative (3) (7) (10) 5 (2) (3)
Exploration - 4 33 12 18 (4)
Interest - - - - -
---------------------------------------------------
Income (Loss)
before Income Taxes 190 12 13 404 23
Less: Provisions for
(Recovery of) Income
Taxes 63 4 4 206 (3)
Less: Non-Controlling
Interests - - - - -
---------------------------------------------------
Net Income (Loss) 127 8 9 198 26
---------------------------------------------------
---------------------------------------------------
Identifiable Assets 378 4,961 (5) 1,786 4,616 272
---------------------------------------------------
---------------------------------------------------
Capital Expenditures
Development and Other 32 304 98 136 20
Exploration 1 42 90 31 6
Proved Property
Acquisition - - 104 (7) - -
---------------------------------------------------
33 346 292 167 26
---------------------------------------------------
---------------------------------------------------
Property, Plant and
Equipment
Cost 2,148 6,265 2,921 4,576 243
Less: Accumulated DD&A 1,930 1,560 1,349 746 75
---------------------------------------------------
Net Book Value 218 4,705 (5) 1,572 3,830 168
---------------------------------------------------
---------------------------------------------------
Corporate
Energy and
(Cdn$ millions) Marketing Syncrude Chemicals Other Total
----------------------------------------------------------------------------
Net Sales 13 160 105 - 1,446
Marketing and Other 219 - 9 (12) (2) 226
---------------------------------------------------
Total Revenues 232 160 114 (12) 1,672
Less: Expenses
Operating 7 53 58 - 283
Depreciation, Depletion,
Amortization and
Impairment 3 14 11 7 349
Transportation and Other 211 4 10 6 238
General and
Administrative (3) 15 1 7 1 7
Exploration - - - - 67
Interest - - 3 37 40
---------------------------------------------------
Income (Loss)
before Income Taxes (4) 88 25 (63) 688
Less: Provisions for
(Recovery of) Income
Taxes (1) 26 8 (29) 278
Less: Non-Controlling
Interests - - 7 - 7
---------------------------------------------------
Net Income (Loss) (3) 62 10 (34) 403
---------------------------------------------------
---------------------------------------------------
Identifiable Assets 2,983 (6) 1,190 470 215 16,871
---------------------------------------------------
---------------------------------------------------
Capital Expenditures
Development and Other 1 12 13 11 627
Exploration - - - - 170
Proved Property
Acquisition - - - - 104
---------------------------------------------------
1 12 13 11 901
---------------------------------------------------
---------------------------------------------------
Property, Plant and
Equipment
Cost 230 1,324 809 314 18,830
Less: Accumulated DD&A 54 209 452 164 6,539
---------------------------------------------------
Net Book Value 176 1,115 357 150 12,291
---------------------------------------------------
---------------------------------------------------
(1) Includes results of operations from producing activities in Colombia.
(2) Includes interest income of $10 million, foreign exchange losses of $11
million and decrease in the fair value of crude oil put options of $11
million.
(3) Includes recovery of stock-based compensation expense of $77 million.
(4) Includes exploration activities primarily in Nigeria, Norway and
Colombia.
(5) Includes costs of $2,533 million related to our Synthetic group (Long
Lake Phase 1 and future phases) which are not being depreciated,
depleted or amortized.
(6) Approximately 77% of Marketing's identifiable assets are accounts
receivable and inventories.
(7) Includes acquisition of producing properties in the Gulf of Mexico.
Nine months ended September 30, 2007
(Cdn$ millions) Oil and Gas
----------------------------------------------------------------------------
United United Other
Yemen Canada States Kingdom Countries (1)
---------------------------------------------------
Net Sales 811 329 453 1,544 106
Marketing and Other 8 4 1 35 -
---------------------------------------------------
Total Revenues 819 333 454 1,579 106
Less: Expenses
Operating 127 130 75 156 6
Depreciation, Depletion,
Amortization and
Impairment 176 123 212 423 8
Transportation and Other 6 18 - - -
General and
Administrative (3) (10) 30 19 - 22
Exploration 5 18 95 50 53 (4)
Interest - - - - -
---------------------------------------------------
Income (Loss)
before Income Taxes 515 14 53 950 17
Less: Provisions for
(Recovery of) Income
Taxes 176 4 18 490 4
Less: Non-Controlling
Interests - - - - -
---------------------------------------------------
Net Income (Loss) 339 10 35 460 13
---------------------------------------------------
---------------------------------------------------
Identifiable Assets 378 4,961 (5) 1,786 4,616 272
---------------------------------------------------
---------------------------------------------------
Capital Expenditures
Development and Other 95 976 365 434 35
Exploration 11 87 153 94 32
Proved Property
Acquisition - - 104 (7) 46 (8) -
---------------------------------------------------
106 1,063 622 574 67
---------------------------------------------------
---------------------------------------------------
Property, Plant and
Equipment
Cost 2,148 6,265 2,921 4,576 243
Less: Accumulated DD&A 1,930 1,560 1,349 746 75
---------------------------------------------------
Net Book Value 218 4,705 (5) 1,572 3,830 168
---------------------------------------------------
---------------------------------------------------
Corporate
Energy and
(Cdn$ millions) Marketing Syncrude Chemicals Other Total
----------------------------------------------------------------------------
Net Sales 36 394 312 - 3,985
Marketing and Other 750 - 31 (56) (2) 773
---------------------------------------------------
Total Revenues 786 394 343 (56) 4,758
Less: Expenses
Operating 26 151 191 - 862
Depreciation, Depletion,
Amortization and
Impairment 10 39 33 19 1,043
Transportation and Other 620 13 29 8 694
General and
Administrative (3) 68 1 24 93 247
Exploration - - - - 221
Interest - - 9 125 134
---------------------------------------------------
Income (Loss)
before Income Taxes 62 190 57 (301) 1,557
Less: Provisions for
(Recovery of) Income
Taxes 25 56 17 (140) 650
Less: Non-Controlling
Interests - - 15 - 15
---------------------------------------------------
Net Income (Loss) 37 134 25 (161) 892
---------------------------------------------------
---------------------------------------------------
Identifiable Assets 2,983 (6) 1,190 470 215 16,871
---------------------------------------------------
---------------------------------------------------
Capital Expenditures
Development and Other 2 27 39 31 2,004
Exploration - - - - 377
Proved Property
Acquisition - - - - 150
---------------------------------------------------
2 27 39 31 2,531
---------------------------------------------------
---------------------------------------------------
Property, Plant and
Equipment
Cost 230 1,324 809 314 18,830
Less: Accumulated DD&A 54 209 452 164 6,539
---------------------------------------------------
Net Book Value 176 1,115 357 150 12,291
---------------------------------------------------
---------------------------------------------------
(1) Includes results of operations from producing activities in Colombia.
(2) Includes interest income of $29 million, foreign exchange losses of $54
million and decrease in the fair value of crude oil put options of $31
million.
(3) Includes recovery of stock-based compensation expense of $16 million.
(4) Includes exploration activities primarily in Nigeria, Norway and
Colombia.
(5) Includes costs of $2,533 million related to our Synthetic group (Long
Lake Phase 1 and future phases) which are not being depreciated,
depleted or amortized.
(6) Approximately 77% of Marketing's identifiable assets are accounts
receivable and inventories.
(7) Includes acquisition of producing properties in the Gulf of Mexico.
(8) Includes acquisition of additional interests in the Scott and Telford
fields.20. DIFFERENCES BETWEEN CANADIAN AND US GENERALLY ACCEPTED ACCOUNTING PRINCIPLES The Unaudited Consolidated Financial Statements have been prepared in accordance with Canadian GAAP. The US GAAP Unaudited Consolidated Statement of Income and Balance Sheet and summaries of differences from Canadian GAAP are as follows:
(a) Unaudited Consolidated Statement of Income - US GAAP
For the Three and Nine Months Ended September 30
Three Months Nine Months
(Cdn$ millions, except per share Ended September 30 Ended September 30
amounts) 2008 2007 2008 2007
----------------------------------------------------------------------------
Revenues and Other Income
Net Sales 2,213 1,446 6,154 3,985
Marketing and Other (vii); (viii) 366 226 470 771
--------------------------------------
2,579 1,672 6,624 4,756
--------------------------------------
Expenses
Operating (ii) 341 292 998 884
Depreciation, Depletion, Amortization
and Impairment 386 349 1,084 1,043
Transportation and Other (viii) 291 238 687 694
General and Administrative (iii) (272) 18 180 268
Exploration 112 67 245 221
Interest 16 40 59 134
--------------------------------------
874 1,004 3,253 3,244
--------------------------------------
Income before Income Taxes 1,705 668 3,371 1,512
--------------------------------------
Provision for Income Taxes
Current (26) 136 817 347
Deferred (i) - (vii) 724 137 610 290
--------------------------------------
698 273 1,427 637
--------------------------------------
Net Income before Non-Controlling
Interests 1,007 395 1,944 875
Less: Net Income Attributable to
Non-Controlling Interests (1) (7) (3) (15)
--------------------------------------
Net Income - US GAAP (1) 1,006 388 1,941 860
--------------------------------------
--------------------------------------
Earnings Per Common Share ($/share)
Basic (Note 14) 1.91 0.74 3.67 1.63
--------------------------------------
--------------------------------------
Diluted (Note 14) 1.89 0.72 3.61 1.60
--------------------------------------
--------------------------------------
Note:
(1) Reconciliation of Canadian and US GAAP Net Income)
Three Months Nine Months
Ended September 30 Ended September 30
2008 2007 2008 2007
----------------------------------------------------------------------------
Net Income - Canadian GAAP 886 403 1,896 892
Impact of US Principles, Net of
Income Taxes:
Ineffective Portion of Cash Flow
Hedges (i) - - - (2)
Pre-operating Costs (ii) - (7) - (15)
Inventory Valuation (vii) 146 - 56 -
Stock-based Compensation (iii) (26) (8) (11) (15)
--------------------------------------
Net Income - US GAAP 1,006 388 1,941 860
--------------------------------------
--------------------------------------
(b) Unaudited Consolidated Balance Sheet - US GAAP
September 30 December 31
(Cdn$ millions, except share amounts) 2008 2007
----------------------------------------------------------------------------
Assets
Current Assets
Cash and Cash Equivalents 1,772 206
Restricted Cash 65 203
Accounts Receivable 4,369 3,502
Inventories and Supplies (vii) 856 615
Other 163 89
-----------------------------
Total Current Assets 7,225 4,615
Property, Plant and Equipment
Net of Accumulated Depreciation, Depletion,
Amortization and Impairment of $8,959
(December 31, 2007 - $7,588) (ii); (v) 13,919 12,449
Goodwill 347 326
Deferred Income Tax Assets 348 268
Deferred Charges and Other Assets 370 324
-----------------------------
Total Assets 22,209 17,982
-----------------------------
-----------------------------
Liabilities and Shareholders' Equity
Current Liabilities
Accounts Payable and Accrued Liabilities (iii) 4,543 4,188
Income Taxes Payable 70 45
Accrued Interest Payable 67 54
Dividends Payable 27 13
-----------------------------
Total Current Liabilities 4,707 4,300
-----------------------------
Long-Term Debt 5,686 4,610
Deferred Income Tax Liabilities (i) - (vii) 2,474 2,230
Asset Retirement Obligations 925 792
Deferred Credits and Other Liabilities (iv) 1,211 534
Non-Controlling Interests 59 67
Shareholders' Equity
Common Shares, no par value
Authorized: Unlimited
Outstanding: 2008 - 520,969,101 shares
2007 - 528,304,813 shares 963 917
Contributed Surplus 2 3
Retained Earnings (i) - (vii) 6,469 4,876
Accumulated Other Comprehensive Loss (i); (iv) (287) (347)
-----------------------------
Total Shareholders' Equity 7,147 5,449
-----------------------------
Commitments, Contingencies and Guarantees
Total Liabilities and Shareholders' Equity 22,209 17,982
-----------------------------
-----------------------------
(c) Unaudited Consolidated Statement of Comprehensive Income - US GAAP
For the Three and Nine Months Ended September 30
Three Months Nine Months
Ended September 30 Ended September 30
(Cdn$ millions) 2008 2007 2008 2007
----------------------------------------------------------------------------
Net Income - US GAAP 1,006 388 1,941 860
Other Comprehensive Income, Net of
Income Taxes:
Foreign Currency Translation Adjustment 41 (51) 60 (143)
Change in Mark to Market on Cash Flow
Hedges (i) - - - (61)
-------------------------------------
Comprehensive Income 1,047 337 2,001 656
-------------------------------------
-------------------------------------
(d) Unaudited Consolidated Statement of Accumulated Other Comprehensive Loss
- US GAAP
September 30 December 31
(Cdn$ millions) 2008 2007
----------------------------------------------------------------------------
Foreign Currency Translation Adjustment (233) (293)
Unamortized Defined Benefit Pension Costs (iv) (54) (54)
-----------------------------
(287) (347)
-----------------------------
-----------------------------Notes: i. Under US GAAP, all derivative instruments are recognized on the balance sheet as either an asset or a liability measured at fair value. Changes in the fair value of derivatives are recognized in earnings unless specific hedge criteria are met. On January 1, 2007, we adopted the equivalent Canadian standard for derivative instruments. Future sale of gas inventory: At December 31, 2006, we included $25 million of gains on cash flow hedges in accounts receivable. Accumulated Other Comprehensive Income (AOCI) includes the effective portion of $23 million ($16 million, net of taxes) and $2 million ($2 million, net of taxes) of the ineffective portion was included in our 2006 US GAAP net income. Under Canadian GAAP, these gains were recognized in the first quarter of 2007. At September 30, 2008, there were no cash flow hedges in place. ii. Under Canadian GAAP, we defer certain development costs and all pre-operating revenues and costs to property, plant and equipment. Under US principles, these costs have been included in operating expenses. As a result: - operating expenses include pre-operating costs of $9 million and $22 million for the three and nine months ended September 30, 2007, respectively ($7 million and $15 million, respectively, net of income taxes); and - property, plant and equipment is lower under US GAAP by $30 million (December 31, 2007 - $30 million). iii. Under Canadian principles, we record obligations for liability-based stock compensation plans using the intrinsic-value method of accounting. Under US principles, obligations for liability-based stock compensation plans are recorded using the fair-value method of accounting. We are also required to accelerate the recognition of stock-based compensation expense for all stock-based awards made to our retirement-eligible employees under Canadian GAAP. However, under US GAAP, the accelerated recognition for such employees is only required for stock-based awards granted on or after January 1, 2006. As a result under US GAAP: - general and administrative expense is higher by $36 million and $15 million ($26 million and $11 million, respectively, net of income taxes) for the three and nine months ended September 30, 2008, respectively (2007 - higher by $11 million and $21 million, respectively, ($8 million and $15 million, respectively, net of income taxes)); and - accounts payable and accrued liabilities are higher by $68 million as at September 30, 2008 (December 31, 2007 - $53 million). iv. On December 31, 2006, we adopted the Financial Accounting Standards Board (FASB) Statement 158 Employers' Accounting for Defined Benefit Pension and other Postretirement Plans (FAS 158). At September 30, 2008, the unfunded amount of our defined benefit pension plans was $75 million. This amount has been included in deferred credits and other liabilities and $54 million, net of income taxes has been included in AOCI. v. On January 1, 2003, we adopted FASB Statement 143, Accounting for Asset Retirement Obligations (FAS 143) for US GAAP reporting purposes. We adopted the equivalent Canadian standard for asset retirement obligations on January 1, 2004. These standards are consistent except for the adoption date which results in our property, plant and equipment under US GAAP being lower by $19 million. vi. On January 1, 2007, we adopted FASB Interpretation 48, Accounting for Uncertainty in Income Taxes (FIN 48) with respect to FAS 109 Accounting for Income Taxes regarding accounting and disclosure for uncertain tax positions. On the adoption of FIN 48, we recorded a cumulative effect of a change in accounting principle of $28 million. This amount increased our deferred income tax liabilities, with a corresponding decrease to our retained earnings as at January 1, 2007 in our US GAAP - Unaudited Consolidated Balance Sheet. As at September 30, 2008, the total amount of our unrecognized tax benefit was approximately $227 million, all of which, if recognized, would affect our effective tax rate. As at September 30, 2008, the total amount of interest and penalties in relation to uncertain tax positions recognized in deferred income tax liabilities in the US GAAP - Unaudited Consolidated Balance Sheet is approximately $11 million. We had no interest or penalties in the US GAAP - Unaudited Consolidated Statement of Income for the first nine months of 2008. Our income tax filings are subject to audit by taxation authorities and as at September 30, 2008 the following tax years remained subject to examination: (i) Canada - 1985 to date, (ii) United Kingdom - 2002 to date and (iii) United States - 2004 to date. We do not anticipate any material changes to the unrecognized tax benefits previously disclosed within the next twelve months. vii. Under Canadian GAAP, we began carrying our commodity inventory held for trading purposes at fair value, less any costs to sell, effective October 31, 2007. Under US GAAP, we are required to carry this inventory at the lower of cost or net realizable value. As a result: - marketing and other income is higher by $235 million and $87 million ($146 million and $56 million, net of income taxes) for the three months and nine months ended September 30, 2008, respectively; and - inventories are higher by $43 million as at September 30, 2008 (December 31, 2007 - lower by $44 million). viii. Under US GAAP, asset disposition gains and losses are included with transportation and other expense. Gains of $nil and $4 million for the three and nine months ended September 30, 2008 were reclassified from marketing and other income to transportation and other expense ($nil for the three and nine months ended September 30, 2007). Changes in Accounting Policies - US GAAP On January 1, 2008, we adopted FASB Statement 157 Fair Value Measurements which defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. The adoption of this statement did not have a material impact on our results of operations or financial position. The additional disclosures required by the statement are included in Note 11. New Accounting Pronouncements - US GAAP Effective December 31, 2006, we adopted the recognition and disclosure provisions of FASB Statement 158, Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans. This statement also requires measurement of the funded status of a plan as of the balance sheet date. The measurement provisions of the statement are effective for fiscal years ending after December 15, 2008. We do not expect the adoption of the change in measurement date in 2008 will have a material impact on our results of operations or financial position. In December 2007, FASB issued Statement 141 (revised), Business Combinations. Statement 141 establishes principles and requirements of the acquisition method for business combinations and related disclosures. This statement is effective for fiscal years beginning on or after December 15, 2008. We do not expect the adoption of this statement will have a material impact on our results of operations or financial position. In December 2007, FASB issued Statement 160, Non-controlling Interests In Consolidated Financial Statements, an amendment of ARB No. 51. This statement clarifies that a non-controlling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. This statement is effective for fiscal years beginning on or after December 15, 2008. We do not expect the adoption of this statement to have a material impact on our results of operations or financial position. In March 2008, FASB issued Statement 161, Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement 133. The statement requires qualitative disclosures about the objectives and strategies for using derivatives, quantitative data about the fair value of gains and losses on derivative contracts and details of credit-risk-related contingent features in their hedged position. The statement also requires the disclosure of the location and amounts of derivative instruments in the financial statements. This statement is effective for fiscal years and interim periods beginning on or after November 15, 2008. We do not expect the adoption of this statement to have a material impact on our results of operations or financial position. In October 2008, FASB issued FSP FAS 157-3, Determining the Fair Value of a Financial Asset When the Market for That Asset is Not Active. This position clarifies the application of FASB statement 157 in a market that is not active and provides an example to illustrate key considerations in such a situation. This position is effective upon the issuance date of October 10, 2008. We have reviewed the position and have determined that the impact of adoption is not material on our results of operation or financial position. Contact: Contacts:
Michael J. Harris, CA
Vice President, Investor Relations
(403) 699-4688
Lavonne Zdunich, CA
Analyst, Investor Relations
(403) 699-5821
Tim Chatten, P.Eng
Analyst, Investor Relations
(403) 699-4244
801 - 7th Ave SW
Calgary, Alberta, Canada T2P 3P7
Website: http://www.nexeninc.com
Source: Nexen Inc.
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