News Releases
Nexen Inc. Delivers Strong Fourth Quarter and Annual Financial Results in 2007
CALGARY, ALBERTA--(Feb. 14, 2008) - Nexen Inc. -
2007 Highlights:
- Record annual cash flow of $3.5 billion ($6.56/share)-an increase of 30% over 2006
- Annual earnings of $1.1 billion ($2.06/share)-an increase of 81% over 2006
- Production after royalties growth of 33% for the year
- Proved reserve additions of 102 million boe, replacing approximately 110% of 2007 production
- 400 million bbls of probable reserves added for Long Lake Phase 2
- All wells steaming at Long Lake and upgrader on track for mid 2008 start up
- Ettrick project on track for mid 2008 start up
- Exploration success in the Gulf of Mexico and the UK North Sea
Three Months Ended Twelve Months Ended
December 31 December 31
-------------------- ---------------------
(Cdn$ millions) 2007 2006 2007 2006
----------------------------------------------------------------------------
Production (mboe/d)(1)
Before Royalties 262 207 254 212
After Royalties 214 161 207 156
Net Sales 1,597 920 5,583 3,936
Cash Flow from Operations(2) 1,079 673 3,458 2,669
Per Common Share ($/share)(2) 2.04 1.28 6.56 5.09
Net Income 194 77 1,086 601
Per Common Share ($/share) 0.37 0.15 2.06 1.15
Capital Expenditures 914 951 3,524 3,458
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1. Production and reserves in this release also include 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. 11.
Quarterly cash flow was over $1 billion for the first time in company history and cash flow for the year grew 30% to a record $3.5 billion. With strong oil and gas production from our Buzzard field in the North Sea, attractive commodity prices and high cash operating margins, we had solid financial results for the fourth quarter and the year. Average benchmark WTI prices for the year increased by 9%, yet we successfully grew our cash netbacks per barrel by 32%. This exceptional netback growth reflects our changing production mix as our production transitions to high margin barrels from Buzzard where unit operating costs are low and we are not subject to royalties. We expect to continue generating higher company-wide cash netbacks as the premium synthetic crude oil we will produce at Long Lake adds to our future production volumes.
"The record cash flow we generated reflects our significant production growth in 2007," commented Charlie Fischer, Nexen's President and Chief Executive Officer. "Our accomplishments last year position us for solid growth in 2008 as we bring Long Lake and Ettrick on stream, gain a full year of production from Buzzard, evaluate our recent discoveries and continue our exploration program."
Net income for the fourth quarter amounted to $194 million and we generated $1.1 billion of net income for the year. Our net income was reduced by non-cash charges for impairment, stock-based compensation and exploration expense. In the Gulf of Mexico, we recorded a non-cash impairment charge of approximately $238 million, after tax ($366 million, before tax) relating to Aspen and three of our shelf properties. This largely reflects disappointing results from our 2007 capital investment program in the United States. We use the more conservative successful efforts method to account for our oil and gas operations. This requires the assessment of impairment on a property by property basis compared to the country level assessment allowed by the full cost method.
"We are disappointed with last year's capital investment program at Aspen," stated Fischer. "Despite the impairment, Aspen has been a good asset and we expect to generate a full cycle rate of return here of over 30%."
Our quarterly net income was also reduced by $31 million, after tax, for stock-based compensation expense and $76 million, after tax, of exploration expense, primarily relating to seismic expenditures.
In our marketing division, results were below their 2006 record contribution. In North American gas markets, limited market and weather-related events presented fewer trading opportunities as natural gas time and location spreads remained relatively stable throughout the year. With respect to our crude oil trading activities, we were not positioned to take advantage of changing oil markets where crude oil spot prices rose suddenly without a corresponding rise in forward prices.
Oil and Gas Production
Quarterly Production Quarterly Production
before Royalties after Royalties
Crude Oil, NGLs and
Natural Gas (mboe/d) Q4 2007 Q3 2007 Q4 2007 Q3 2007
--------------------------------------------------- ----------------------
North Sea 96 93 96 93
Yemen 66 70 34 39
Canada 37 35 31 29
United States 34 31 29 26
Other Countries 6 7 5 6
Syncrude 23 25 19 21
---------------------- ----------------------
Total 262 261 214 214
---------------------- ----------------------
Annual Production Annual Production
before Royalties after Royalties
Crude Oil, NGLs and
Natural Gas (mboe/d) 2007 2006 2007 2006
--------------------------------------------------- ----------------------
North Sea 84 20 84 20
Yemen 72 93 40 52
Canada 37 38 30 31
United States 33 36 29 31
Other Countries 6 6 5 6
Syncrude 22 19 19 16
---------------------- ----------------------
Total 254 212 207 156
---------------------- ----------------------
Our fourth quarter production averaged 262,000 boe/d (214,000 boe/d after royalties) with Buzzard contributing 75,000 boe/d to our volumes. During the quarter, we shut in production from the Buzzard platform following storm damage to one of the power generation turbine stacks. The damage was repaired within a few days. Reliability issues with the acid gas removal system at Buzzard also temporarily reduced production volumes. These issues have largely been resolved and Buzzard is now performing well, with our share of production averaging over 95,500 boe/d (221,000 boe/d gross) for the month of January this year.
Our annual production averaged 254,000 boe/d (207,000 boe/d after royalties) as compared to 212,000 boe/d (156,000 boe/d after royalties) in 2006. This resulted in industry-leading production after royalties growth of 33%, but was less than the 50% growth we forecasted a year ago. Project start-up and ramp-up delays, coupled with disappointing results from development drilling at Aspen, caused our 2007 production to be less than originally forecast. At Buzzard, commissioning of all systems took longer than expected but this work is now complete and the platform is performing well. At Long Lake, project start up was deferred approximately six months to allow for completion of the air separation and sulphur recovery units. Despite these timing setbacks, project returns have not been impacted.
In 2008, we expect additional production growth over 2007 and expect production to range from 260,000 to 280,000 boe/d (220,000 to 240,000 boe/d after royalties). For the month of January 2008, our production was approximately 275,000 boe/d (233,000 boe/d after royalties).
2007 Capital Investment and Reserves
"Our strategy is to generate high value production growth for our shareholders and we are doing this by building material sustainable businesses in the deep-water Gulf of Mexico, Athabasca oil sands, North Sea and offshore West Africa," said Fischer. "Long Lake, Knotty Head and Usan will contribute significant value when they come on stream. Projects of this size tend to have longer cycle-times and result in step changes to our production profile."
In 2007, we added 102 mmboe of proved reserves and invested approximately $2.6 billion in oil and gas exploration and development activities, replacing approximately 110% of our production. Our total proved and probable reserves now total approximately two billion boe.
2007 Capital Investment(1) (Cdn$ millions)
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United Other Insitu
Kingdom Yemen International US Canada Oil Sands Syncrude Total
----------------------------------------------------------------------------
Core Asset
Development 228 124 22 384 124 - 36 918
Major
Development 308 - - 28 103 279 - 718
Early-stage
Development - - 31 2 21 105 - 159
Exploration 129 15 90 335 121 6 - 696
Proved
Property
Acquisitions 46 - - 104 1 - - 151
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Total Oil
and Gas
Investment 711 139 143 853 370 390 36 2,642
Long Lake
Upgrader - - - - - 591 - 591
Marketing,
Corporate,
Chemicals
and Other - - 4 - 114 - - 118
Capitalized
Interest 15 - - - - 158 - 173
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Total Capital
Investment 726 139 147 853 484 1,139 36 3,524
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% of Total 21% 4% 4% 24% 14% 32% 1% 100%
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1. Includes geological and geophysical expenditures of $123 million.
Shown below is a summary of our year on year reserve changes. A detailed
reconciliation table can be found on page 10 of this release.
2007 Reserves Continuity
----------------------------------------------------------------------------
Oil and Gas Activities
-------------------------------------------
United Other
mmboe Kingdom Yemen International US Canada
----------------------------------------------------------------------------
PROVED RESERVES (1)
Dec. 31, 2006 182 66 40 73 118
Net Changes 55 3 - 1 13
Production (30) (28)(4) (2) (12) (13)
-------------------------------------------
Dec. 31, 2007 207 41 38 62 118
-------------------------------------------
PROBABLE RESERVES (1,2)
Dec. 31, 2006 160 22 59 99 62
Conversions to
Proved (48) (4) - (1) (4)
Other Net
Changes 32 (3) 1 (38) -
-------------------------------------------
Dec. 31, 2007 144 15 60 60 58
-------------------------------------------
TOTAL PROVED +
PROBABLE RESERVES (1,2)
Dec. 31, 2006 342 88 99 172 180
Net Changes 39 (4) 1 (38) 9
Production (30) (28) (2) (12) (13)
-------------------------------------------
Dec. 31, 2007 351 56 98 122 176
-------------------------------------------
2007 Reserves Continuity
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Oil and Gas Activities Mining
------------------------------------
Total Oil Total Oil, Gas
mmboe Bitumen and Gas Syncrude(3) and Mining
------------------------------------------------------------
PROVED RESERVES (1)
Dec. 31, 2006 246 725 324 1,049
Net Changes 22 94 8 102
Production - (85) (8) (93)
-----------------------------------------------
Dec. 31, 2007 268 734 324 1,058
-----------------------------------------------
PROBABLE RESERVES (1,2)
Dec. 31, 2006 154 556 46 602
Conversions to
Proved (22) (79) (8) (87)
Other Net
Changes 391 383 8 391
-----------------------------------------------
Dec. 31, 2007 523 860 46 906
-----------------------------------------------
TOTAL PROVED +
PROBABLE RESERVES (1,2)
Dec. 31, 2006 400 1,281 370 1,651
Net Changes 391 398 8 406
Production - (85) (8) (93)
-----------------------------------------------
Dec. 31, 2007 791 1,594 370 1,964
-----------------------------------------------
1. We internally evaluate all of our reserves and have at least 80% of our
proved reserves assessed by independent qualified consultants each year;
98% were assessed this year. Our reserves are also reviewed and approved
by our Reserves Committee and our Board of Directors. Reserves represent
our working interest before royalties at year-end constant pricing using
SEC rules. Gas is converted to equivalent oil at a 6:1 ratio.
2. Probable reserves are determined according to SPE/WPC definitions. US
investors should read the Cautionary Note to US Investors at the end of
this release.
3. US investors should read the Cautionary Note to US Investors at the end
of this release.
4. Production includes volumes used for fuel in Yemen.
United Kingdom
In the UK, we invested $726 million. This included $160 million at Buzzard where we drilled six development wells and added 46 mmboe of proved reserves. Increases in both the reservoir size and overall recovery factor from successful drilling and production performance resulted in these proved reserve adds.
"Buzzard has been a great project for us and is one of the few mega-projects worldwide in the last several years to be completed virtually on time and on budget. In addition, the Buzzard facility is capable of handling higher production volumes than we first thought," commented Fischer. "Oil prices are almost three times higher than when we first acquired this asset and we have successfully increased our proved plus probable reserves by 74 mmboe or 35%, creating significant value for shareholders. We are optimistic that this asset will generate even more value as we believe there is room for recovery factors to improve further."
Our Ettrick development in the North Sea is progressing well towards first oil mid 2008. In 2007, we invested approximately $260 million and added 4 mmboe of proved reserves and 1 mmboe of probable reserves. To date, we have recognized 46 mmboe of proved plus probable reserves here. This development will utilize a leased floating production, storage and offloading vessel (FPSO) designed to handle 30,000 bbls/d of oil and 35 mmcf/d of gas. We expect to ramp up to production of approximately 30,000 boe/d gross by the end of the year. We operate Ettrick with an 80% working interest. We have also identified a number of exploration opportunities in the immediate area that could be future tie-backs to Ettrick. We have plans to drill at least two of these opportunities this year.
At Scott/Telford and Farragon, we added 5 mmboe of proved reserves as a result of successful development well drilling.
Elsewhere, we are assessing development alternatives for our Golden Eagle discovery where we have a 34% operated working interest. At Kildare, we are planning to drill an appraisal well this year. The discovery well was drilled to a depth of approximately 14,100 feet and encountered approximately 91 feet of net pay. We also completed an appraisal well at Selkirk which confirmed commercial quantities of hydrocarbons and we are currently reviewing development options. We have a 38% operated working interest here.
At Bugle, we are currently drilling an appraisal well. Well results are still being analyzed but initial test results are encouraging. We have a 41% working interest here.
"Our strategy in the UK is working well," commented Fischer. "These satellite discoveries are in the same areas as our large operations at Buzzard, Scott/Telford and Ettrick. This infrastructure provides opportunities for quick tie-backs which will generate incremental value for shareholders."
Yemen
Yemen remains a significant asset for us and is expected to generate approximately 15% of our projected 2008 cash flow. In 2007, we invested $139 million and added 3 mmboe of proved reserves. In 2008, we expect to produce between 50,000 and 55,000 boe/d before royalties here.
Offshore West Africa
The Usan field development, located in Nigeria on offshore Block OPL-222, continues to move forward. We expect the project to advance to the execution phase shortly and this will facilitate the award of major deep-water facilities contracts. The project will have the ability to process an average of 180,000 bbls/d of oil during the initial production plateau period through a new FPSO with a two million barrel storage capacity. We have a 20% interest in exploration and development on this block.
United States
In the Gulf of Mexico, we reduced our proved reserve estimates for Aspen and a few shelf properties by approximately 13 mmboe. At Aspen, disappointing results from our recent investment in development drilling resulted in reserve reductions of 7 mmboe. While we were encouraged by well log data indicating thick pay zones, well deliverability rates could not be sustained. This likely indicates barriers within this section of the reservoir that are not apparent elsewhere. On the shelf, negative reserve revisions of 6 mmboe primarily relate to gas properties, where unsatisfactory investment results, production performance and revised mapping resulted in a downward revision to reserves estimates.
"While we are disappointed with our capital investment performance and the reserve reductions in the Gulf of Mexico, these revisions have no impact on our production guidance for 2008," commented Fischer. "In 2008, we plan to keep capital reinvestment with respect to our shelf assets to a minimum."
At Longhorn, where we have a 25% working interest, we completed drilling an appraisal well which exceeded our expectations and encountered approximately 400 feet of net gas pay in multiple sands. We added 3 mmboe of proved and 3 mmboe of probable reserves here. The Longhorn project has been sanctioned and development will consist of subsea tie-backs to a host facility with first production expected in 2009.
In late 2007, we invested $104 million to acquire three producing deep-water properties at Garden Banks Block 205 and Green Canyon Blocks 137 and 6/50. These properties added 7 mmboe of proved reserves and are currently producing approximately 3,000 boe/d. Drilling of a development well at Green Canyon 6/50 is underway and we expect production from this well to add up to 5,000 boe/d to support our 2008 annual volumes.
Elsewhere, we had positive proved reserve additions and revisions of 4 mmboe, primarily at Gunnison and on the shelf as a result of performance and drilling activities.
At Knotty Head, we continue to pursue rig availability in the short term to allow us to spud an appraisal well. To date, we have evaluated two rigs but determined that these rigs did not have the drilling capability required. We have contracted two new deep-water drilling rigs that are scheduled to arrive in mid 2009 and 2010, respectively.
Our 2007 exploration program resulted in discoveries at Vicksburg, Mississippi Canyon 72 and South Marsh Island 257. The Vicksburg discovery well, located on De Soto Canyon Block 353 in the Eastern Gulf of Mexico, was drilled to a depth of approximately 25,400 feet and encountered a hydrocarbon column of 300 feet. Core was recovered from the well and studies are underway to assess the productivity of the column. Additional drilling in the area is planned in 2008. We have a 25% non-operated working interest in this discovery. Shell is the operator with a 57.5% working interest and Plains Exploration & Production Company holds the remaining 17.5% interest. In the same area, we participated in a discovery well in 2003 at Shiloh located on DeSoto Canyon Block 269, that was drilled by Shell. This well was drilled to a total depth of approximately 24,000 feet, encountered hydrocarbons and was temporarily abandoned pending further evaluation of the area. We have a 20% non-operated working interest in Shiloh. Shell operates and owns the remaining 80% working interest.
In the Eastern Gulf of Mexico, where the discoveries at Shiloh and Vicksburg are located, we have identified a number of additional exploration opportunities in the region. We also have the right to extend our acreage position through the acquisition of working interests in various blocks recently awarded to Shell as a result of their participation in Lease Sale 205 late last year.
"We are excited about the recent discovery at Vicksburg," said Fischer. "When we combine this with the previous discovery at Shiloh, the exploration opportunities we have identified and our access to acreage in the area, this has the potential to become a significant part of our Gulf of Mexico business."
Our other discoveries at Mississippi Canyon 72 and South Marsh Island 257 are currently being evaluated. Both discoveries are expected to come on production in 2008. We have working interests of 33% and 34.5% respectively in these discoveries.
Canada
In Canada, we are developing the first commercial coalbed methane (CBM) project in the Mannville coals. In 2007, we invested $173 million in exploration and development activities on our CBM lands. This generated 5 mmboe of proved reserves. To date, we have recognized approximately 36 mmboe of proved plus probable CBM reserves. Our ability to recognize proved reserves in this resource play type is limited until we have sufficient production history to assess long-term decline rates. We expect our CBM reserves to grow over the coming years as additional wells are drilled, development work progresses and more production history is obtained.
Elsewhere, we added 8 mmboe of proved reserves relating to our conventional heavy oil and gas properties largely as a result of positive price revisions and development drilling.
In northeast British Columbia, we have a material land position of approximately 190 net sections in an emerging Devonian shale gas play which has the potential to be one of the most significant shale gas plays in Canada. We are currently evaluating this opportunity with a program of drilling, completing and production testing.
Long Lake
In 2007, we invested a total of $1.1 billion to develop our insitu oil sands resource. This included approximately $1 billion on the first phase of Long Lake, $591 million of which related to the upgrader. At Long Lake, we added 22 mmbbls of proved bitumen reserves based on further delineation of the lease and an increase in recovery factors based on performance from analogous reservoirs. We also added approximately 400 mmbbls of probable bitumen reserves associated with delineation work on Phase 2.
Long Lake continues to progress well towards first production of premium synthetic crude in mid 2008. We are currently injecting steam into the reservoir through all well pads. We have started converting wells to SAGD operation and we have also recently started up our first cogeneration unit which allows us to produce electricity and build our steaming capacity. The second cogeneration unit is expected to start up towards the end of the first quarter. We expect bitumen production to ramp up in the spring and we are on track to have sufficient bitumen production for the start up of the upgrader. The bitumen production capacity of the SAGD facilities is approximately 72,000 bbls/d (36,000 bbls/d net to Nexen).
At the end of 2007, construction of the upgrader was 97% complete and commissioning is progressing well. We have turned over the hydrocracker, the OrCrude(TM) unit and all main plant utilities to operations. The gasifier and air separation unit were essentially mechanically complete at year end 2007, and we are completing final electrical and insulation work. Construction of the sulphur recovery unit is expected to be completed by the end of the first quarter, in sufficient time for first production of synthetic crude oil in mid 2008. Production of premium synthetic crude will ramp up to full rates over a 12 to 18 month period following initial upgrader start up. The upgrader is designed to produce approximately 60,000 bbls/d (30,000 bbls/d net to Nexen) of premium synthetic crude.
The total cost estimate for the Project remains unchanged at between $5.8 billion and $6.1 billion (between $2.90 billion and $3.05 billion net).
"We are excited about bringing our first oil sands project on stream this year and we are committed to the safe and steady start up of all facilities," said Fischer. "At current natural gas prices we expect to enjoy a cost advantage of approximately $10/bbl over competing technologies once Long Lake is fully ramped up in late 2009, as the patented process minimizes the need for purchased natural gas."
We are planning to increase synthetic crude oil production as we sequentially develop our lands with additional 60,000 bbls/d (30,000 bbls/d net) phases using the same technology and design as Long Lake.
Syncrude
At Syncrude, we invested $36 million in 2007 and converted 8 mmboe of probable reserves to proved reserves. In 2008, we have turnarounds scheduled in the second and third quarters and expect annual production of between 20,000 and 25,000 bbls/d before royalties.
Quarterly Dividend
The Board of Directors has declared the regular quarterly dividend of $0.025 per common share payable April 1, 2008, to shareholders of record on March 10, 2008.
Nexen Inc. is an independent, Canadian-based global energy company, listed on the Toronto and New York stock exchanges under the symbol NXY. We are uniquely positioned for growth in the North Sea, deep-water Gulf of Mexico, the Athabasca oil sands of Alberta, the Middle East and offshore West Africa. We add value for shareholders through successful full-cycle oil and gas exploration and development and leadership in ethics, integrity and environmental protection.
Conference Call
Charlie Fischer, President and CEO, and Marvin Romanow, Executive Vice President and CFO, will host a conference call to discuss our fourth quarter and year end financial and operating results and expectations for the future.
Date: February 14, 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:
416-340-2216 (Toronto)
866-898-9626 (North American toll-free)
800-8989-6323 (Global toll-free)
A replay of the call will be available for two weeks starting at 9:00 a.m. Mountain Time, by calling 416-695-5800 (Toronto) or 800-408-3053 (toll-free) passcode 3250781 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, 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 reserves or resources, expected finding and development costs, 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 and transport crude oil and natural gas to markets; the results of exploration and development drilling and related activities; volatility in energy trading markets; foreign-currency exchange rates; economic conditions in the countries and regions in which we carry on business; 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 2006 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" and "recoverable resources" which are inherently more uncertain than proved reserves. These terms are not used in our filings with the SEC. Our reserves and related performance measures represent our working interest before royalties, unless otherwise indicated. Please refer to our Annual Report on Form 10-K available from us or the SEC for further reserve disclosure.
In addition, under SEC regulations, the Syncrude oil sands operations are considered mining activities rather than oil and gas activities. Production, reserves and related measures in this release include results from the Company's share of Syncrude.
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 2006 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.
Nexen Inc.
2007 Reserve Continuity Table
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Oil and Gas Activities
----------------------------------------------------------------------------
International US Canada
----------------------- -------- -----------------
United Other
Yemen Kingdom Intl
mmboe Oil Oil Gas Oil Oil Gas Oil Gas Bitumen
----------------------------------------------------------------------------
PROVED RESERVES (1)
Dec. 31, 2006 66 179 3 40 34 39 57 61 246
Extensions and
Discoveries 2 10 - - 1 3 1 6 -
Acquisitions - 1 - - 3 8 - - -
Dispositions - - - - - (2) - - -
Revisions 1 43 1 - (7) (5) 4 2 22
Production (28)(4) (30) - (2) (6) (6) (6) (7) -
------------------------------------------------------
Dec. 31, 2007 41 203 4 38 25 37 56 62 268
------------------------------------------------------
PROBABLE RESERVES (1,2)
Dec. 31, 2006 22 152 8 59 69 30 22 40 154
Extensions, Discoveries
& Conversions (4) (29) (2) - - 2 1 (2) 378
Acquisitions - 2 - - 1 6 - - -
Dispositions - - - - (15) (9) - - -
Revisions (3) 14 (1) 1 (16) (8) 1 (4) (9)
------------------------------------------------------
Dec. 31, 2007 15 139 5 60 39 21 24 34 523
------------------------------------------------------
PROVED + PROBABLE RESERVES (1,2)
Dec. 31, 2006 88 331 11 99 103 69 79 101 400
Extensions, Discoveries
& Conversions (2) (19) (2) - 1 5 2 4 378
Acquisitions - 3 - - 4 14 - - -
Dispositions - - - - (15) (11) - - -
Revisions (2) 57 - 1 (23) (13) 5 (2) 13
Production (28)(4) (30) - (2) (6) (6) (6) (7) -
------------------------------------------------------
Dec. 31, 2007 56 342 9 98 64 58 80 96 791
------------------------------------------------------
Mining
----------- Total
Syncrude(3) Oil, Gas
Total and
mmboe Oil and Gas Mining
----------------------------------------------------------------------------
PROVED RESERVES
Dec. 31, 2006 725 324 1,049
Extensions and Discoveries 23 8 31
Acquisitions 12 - 12
Dispositions (2) - (2)
Revisions 61 - 61
Production (85) (8) (93)
-----------------------------------
Dec. 31, 2007 734 324 1,058
-----------------------------------
PROBABLE RESERVES (1,2)
Dec. 31, 2006 556 46 602
Extensions, Discoveries & Conversions 344 - 344
Acquisitions 9 - 9
Dispositions (24) - (24)
Revisions (25) - (25)
-----------------------------------
Dec. 31, 2007 860 46 906
-----------------------------------
PROVED + PROBABABLE RESERVES (1,2)
Dec. 31, 2006 1,281 370 1,651
Extensions, Discoveries & Conversions 367 8 375
Acquisitions 21 - 21
Dispositions (26) - (26)
Revisions 36 - 36
Production (85) (8) (93)
-----------------------------------
Dec. 31, 2007 1,594 370 1,964
-----------------------------------
1. We internally evaluate all of our reserves and have at least 80% of our
proved reserves assessed by independent qualified consultants each year;
98% were assessed this year. Our reserves are also reviewed and approved
by our Reserves Committee and our Board of Directors. Reserves represent
our working interest before royalties at year-end constant pricing using
SEC rules. Gas is converted to equivalent oil at a 6:1 ratio.
2. Probable reserves are determined according to SPE/WPC definitions. US
investors should read the Cautionary Note to US Investors at the end of
this release.
3. US investors should read the Cautionary Note to US Investors at the end
of this release.
4. Production includes volumes used for fuel in Yemen.
Nexen Inc.
Financial Highlights
Three Months Twelve Months
Ended December 31 Ended December 31
(Cdn$ millions) 2007 2006 2007 2006
----------------------------------------------------------------------------
Net Sales 1,597 920 5,583 3,936
Cash Flow from Operations 1,079 673 3,458 2,669
Per Common Share
($/share)(1) 2.04 1.28 6.56 5.09
Net Income 194 77 1,086 601
Per Common Share
($/share)(1) 0.37 0.15 2.06 1.15
Capital Investment,
including Acquisitions(2) 870 900 3,401 3,408
Net Debt(3) 4,404 4,730 4,404 4,730
Common Shares Outstanding
(millions of shares)(1) 528.3 525.0 528.3 525.0
-----------------------------------------------
(1) Restated to reflect a two-for-one stock split in the second quarter of
2007.
(2) Includes oil and gas development, exploration, and expenditures for
other property, plant and equipment.
(3) Net Debt is defined as long-term debt and short-term borrowings, less
cash and cash equivalents.
Cash Flow from Operations (1)
Three Months Twelve Months
Ended December 31 Ended December 31
(Cdn$ millions) 2007 2006 2007 2006
----------------------------------------------------------------------------
Oil & Gas and Syncrude
Yemen(2) 153 189 664 877
Canada 49 41 179 229
United States 125 127 480 573
United Kingdom 685 92 2,101 477
Other Countries 26 19 87 94
Marketing 9 147 73 432
Syncrude 90 65 319 240
-----------------------------------------------
1,137 680 3,903 2,922
Chemicals 28 17 90 83
-----------------------------------------------
1,165 697 3,993 3,005
Interest and Other Corporate
Items (74) (75) (350) (254)
Income Taxes(3) (12) 51 (185) (82)
-----------------------------------------------
Cash Flow from Operations(1) 1,079 673 3,458 2,669
-----------------------------------------------
-----------------------------------------------
(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. 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.
Reconciliation of Cash Three Months Twelve Months
Flow from Operations Ended December 31 Ended December 31
(Cdn$ millions) 2007 2006 2007 2006
------------------------------------------------------------------------
Cash Flow from Operating
Activities 703 590 2,830 2,374
Changes in Non-Cash
Working Capital 329 85 348 177
Other 54 (2) 307 41
Amortization of Premium for
Crude Oil Put Options (7) (17) (27) (74)
Provision for Non-
Recurring Arbitration - 17 - 151
-----------------------------------------------
Cash Flow from Operations 1,079 673 3,458 2,669
-----------------------------------------------
-----------------------------------------------
Weighted-average Number of
Common Shares Outstanding
(millions of shares) 528.1 524.9 527.1 524.2
-----------------------------------------------
Cash Flow from Operations
Per Common Share
($/share) 2.04 1.28 6.56 5.09
-----------------------------------------------
-----------------------------------------------
(2) After in-country cash taxes of $75 million for the three months ended
December 31, 2007 (2006 -- $62 million) and $249 million for the year
ended December 31, 2007 (2006 -- $286 million).
(3) Excludes in-country cash taxes in Yemen.
Nexen Inc.
Production Volumes (before royalties) (1)
Three Months Twelve Months
Ended December 31 Ended December 31
2007 2006 2007 2006
----------------------------------------------------------------------------
Crude Oil and NGLs (mbbls/d)
Yemen 66.2 83.7 71.6 92.9
Canada 16.4 18.3 17.1 20.0
United States 13.9 14.6 16.4 17.0
United Kingdom 93.4 21.6 81.2 16.9
Other Countries 6.2 6.0 6.2 6.3
Syncrude (2) (mbbls/d) 22.6 21.9 22.1 18.7
-----------------------------------------------
218.7 166.1 214.6 171.8
-----------------------------------------------
Natural Gas (mmcf/d)
Canada 124 118 118 108
United States 119 111 101 111
United Kingdom 19 14 16 20
-----------------------------------------------
262 243 235 239
-----------------------------------------------
Total Production (mboe/d) 262 207 254 212
-----------------------------------------------
-----------------------------------------------
Production Volumes (after royalties)
Three Months Twelve Months
Ended December 31 Ended December 31
2007 2006 2007 2006
----------------------------------------------------------------------------
Crude Oil and NGLs (mbbls/d)
Yemen 33.8 51.9 39.8 51.8
Canada 12.9 14.5 13.4 15.8
United States 12.2 12.8 14.5 15.0
United Kingdom 93.3 21.6 81.2 16.9
Other Countries 5.7 5.5 5.7 5.7
Syncrude (2) (mbbls/d) 18.7 20.2 18.8 16.9
-----------------------------------------------
176.6 126.5 173.4 122.1
-----------------------------------------------
Natural Gas (mmcf/d)
Canada 105 98 98 91
United States 102 94 86 94
United Kingdom 19 14 16 20
-----------------------------------------------
226 206 200 205
-----------------------------------------------
Total Production (mboe/d) 214 161 207 156
-----------------------------------------------
-----------------------------------------------
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 - 2007 Year
-----------------------------------
(all dollar amounts in Cdn$ unless noted) 1st 2nd 3rd 4th 2007
----------------------------------------------------------------------------
PRICES:
WTI Crude Oil (US$/bbl) 58.16 65.03 75.38 90.69 72.31
Nexen Average - Oil (Cdn$/bbl) 61.69 72.27 75.86 82.80 73.43
NYMEX Natural Gas (US$/mmbtu) 7.18 7.66 6.24 7.39 7.12
Nexen Average - Gas (Cdn$/mcf) 7.58 7.52 5.80 6.47 6.81
----------------------------------------------------------------------------
NETBACKS:
Canada - Heavy Oil
Sales (mbbls/d) 17.8 17.2 16.9 16.4 17.1
Price Received ($/bbl) 41.71 41.89 46.76 46.07 44.07
Royalties & Other 9.16 9.52 10.93 10.04 9.91
Operating Costs 13.65 15.14 14.53 15.22 14.62
----------------------------------------------------------------------------
Netback 18.90 17.23 21.30 20.81 19.54
----------------------------------------------------------------------------
Canada - Natural Gas
Sales (mmcf/d) 118 116 112 124 118
Price Received ($/mcf) 7.16 7.06 5.17 5.88 6.32
Royalties & Other 1.26 1.09 0.78 0.86 1.00
Operating Costs 1.59 1.81 2.52 1.71 1.90
----------------------------------------------------------------------------
Netback 4.31 4.16 1.87 3.31 3.42
----------------------------------------------------------------------------
Yemen
Sales (mbbls/d) 77.5 72.7 69.9 66.2 71.5
Price Received ($/bbl) 63.02 77.34 78.27 88.24 76.29
Royalties & Other 28.17 33.84 34.73 43.04 34.69
Operating Costs 6.07 6.29 6.72 7.24 6.56
In-country Taxes 6.38 9.89 10.03 12.18 9.52
----------------------------------------------------------------------------
Netback 22.40 27.32 26.79 25.78 25.52
----------------------------------------------------------------------------
Syncrude
Sales (mbbls/d) 21.4 19.0 25.2 22.6 22.1
Price Received ($/bbl) 70.03 77.12 82.09 88.33 79.76
Royalties & Other 8.26 10.33 13.42 15.33 12.02
Operating Costs 24.40 29.91 22.37 27.52 25.80
----------------------------------------------------------------------------
Netback 37.37 36.88 46.30 45.48 41.94
----------------------------------------------------------------------------
Total
Quarters - 2006 Year
-----------------------------------
(all dollar amounts in Cdn$ unless noted) 1st 2nd 3rd 4th 2006
----------------------------------------------------------------------------
PRICES:
WTI Crude Oil (US$/bbl) 63.48 70.70 70.48 60.21 66.22
Nexen Average - Oil (Cdn$/bbl) 63.11 72.90 73.06 60.89 67.50
NYMEX Natural Gas (US$/mmbtu) 7.87 6.67 6.14 7.26 6.99
Nexen Average - Gas (Cdn$/mcf) 8.71 6.68 6.39 6.84 7.18
----------------------------------------------------------------------------
NETBACKS:
Canada - Heavy Oil
Sales (mbbls/d) 21.9 20.1 19.0 18.3 19.8
Price Received ($/bbl) 30.00 51.67 52.95 37.61 42.79
Royalties & Other 6.25 11.38 12.55 8.43 9.58
Operating Costs 11.47 11.66 12.61 12.98 12.15
----------------------------------------------------------------------------
Netback 12.28 28.63 27.79 16.20 21.06
----------------------------------------------------------------------------
Canada - Natural Gas
Sales (mmcf/d) 106 104 106 118 108
Price Received ($/mcf) 7.65 6.21 5.78 6.37 6.49
Royalties & Other 1.17 0.89 0.90 0.98 0.97
Operating Costs 1.27 1.33 1.33 1.64 1.38
----------------------------------------------------------------------------
Netback 5.21 3.99 3.55 3.75 4.14
----------------------------------------------------------------------------
Yemen
Sales (mbbls/d) 102.6 94.5 88.8 85.1 92.7
Price Received ($/bbl) 68.32 76.86 76.08 64.90 71.57
Royalties & Other 32.73 34.60 34.80 26.76 32.32
Operating Costs 3.88 4.39 4.53 5.11 4.45
In-country Taxes 7.20 9.46 9.29 7.94 8.45
----------------------------------------------------------------------------
Netback 24.51 28.41 27.46 25.09 26.35
----------------------------------------------------------------------------
Syncrude
Sales (mbbls/d) 14.8 17.4 20.5 21.9 18.7
Price Received ($/bbl) 69.95 79.50 77.53 63.37 72.32
Royalties & Other 6.68 7.95 8.54 4.79 6.93
Operating Costs 40.12 27.84 21.69 24.42 27.53
----------------------------------------------------------------------------
Netback 23.15 43.71 47.30 34.16 37.86
----------------------------------------------------------------------------
(1) Defined as average sales price less royalties and other, operating
costs, and in-country taxes in Yemen.
Nexen Inc.
Oil and Gas Prices and Cash Netback (1) (continued)
Total
Quarters - 2007 Year
-----------------------------------
(all dollar amounts in Cdn$ unless noted) 1st 2nd 3rd 4th 2007
----------------------------------------------------------------------------
United States
Crude Oil:
Sales (mbbls/d) 21.6 16.0 14.1 13.9 16.4
Price Received ($/bbl) 58.49 68.18 74.43 84.33 69.83
Natural Gas:
Sales (mmcf/d) 101 86 98 119 101
Price Received ($/mcf) 8.58 8.85 6.75 7.27 7.80
Total Sales Volume (mboe/d) 38.4 30.4 30.5 33.8 33.3
Price Received ($/boe) 55.44 61.04 56.28 60.32 58.16
Royalties & Other 6.78 7.71 7.28 8.13 7.45
Operating Costs 8.11 9.46 7.40 8.78 8.43
----------------------------------------------------------------------------
Netback 40.55 43.87 41.60 43.41 42.28
----------------------------------------------------------------------------
United Kingdom
Crude Oil:
Sales (mbbls/d) 58.8 87.2 83.6 94.5 81.1
Price Received ($/bbl) 64.33 74.07 78.06 84.06 76.30
Natural Gas:
Sales (mmcf/d) 13 13 16 21 16
Price Received ($/mcf) 3.87 3.32 4.99 5.84 4.71
Total Sales Volume (mboe/d) 60.8 89.3 86.3 98.0 83.7
Price Received ($/boe) 62.92 72.75 76.56 82.29 74.79
Operating Costs 9.60 6.59 6.28 6.23 6.94
----------------------------------------------------------------------------
Netback 53.32 66.16 70.28 76.06 67.85
----------------------------------------------------------------------------
Other Countries
Sales (mbbls/d) 5.8 6.2 6.5 6.2 6.2
Price Received ($/bbl) 59.81 68.04 76.29 79.74 71.29
Royalties & Other 4.80 5.62 6.46 6.60 5.90
Operating Costs 2.97 3.39 3.34 4.13 3.45
----------------------------------------------------------------------------
Netback 52.04 59.03 66.49 69.01 61.94
----------------------------------------------------------------------------
Company-Wide
Oil and Gas Sales (mboe/d) 241.5 254.1 253.9 263.9 253.4
Price Received ($/boe) 59.13 68.48 69.82 75.50 68.46
Royalties & Other 12.26 12.65 13.02 14.37 13.10
Operating Costs 9.67 9.41 9.26 9.46 9.45
In-country Taxes 2.05 2.83 2.76 3.05 2.69
----------------------------------------------------------------------------
Netback 35.15 43.59 44.78 48.62 43.22
----------------------------------------------------------------------------
Total
Quarters - 2006 Year
-----------------------------------
(all dollar amounts in Cdn$ unless noted) 1st 2nd 3rd 4th 2006
----------------------------------------------------------------------------
United States
Crude Oil:
Sales (mbbls/d) 19.3 17.8 16.7 14.6 17.0
Price Received ($/bbl) 63.73 70.23 70.23 58.09 65.80
Natural Gas:
Sales (mmcf/d) 120 107 105 111 111
Price Received ($/mcf) 9.06 7.51 7.18 7.56 7.86
Total Sales Volume (mboe/d) 39.3 35.6 34.1 33.0 35.5
Price Received ($/boe) 58.97 57.60 56.35 50.97 56.12
Royalties & Other 7.96 7.62 7.42 7.06 7.53
Operating Costs 8.47 7.00 8.42 8.78 8.17
----------------------------------------------------------------------------
Netback 42.54 42.98 40.51 35.13 40.42
----------------------------------------------------------------------------
United Kingdom
Crude Oil:
Sales (mbbls/d) 17.6 17.9 13.8 16.2 16.3
Price Received ($/bbl) 69.02 73.24 77.73 65.67 71.19
Natural Gas:
Sales (mmcf/d) 24 29 10 15 19
Price Received ($/mcf) 11.82 5.52 5.57 5.52 7.43
Total Sales Volume (mboe/d) 21.5 22.8 15.4 18.6 19.6
Price Received ($/boe) 69.37 64.59 73.13 61.38 66.81
Operating Costs 11.24 9.59 15.12 10.18 11.28
----------------------------------------------------------------------------
Netback 58.13 55.00 58.01 51.20 55.53
----------------------------------------------------------------------------
Other Countries
Sales (mbbls/d) 5.8 6.6 6.7 6.0 6.3
Price Received ($/bbl) 58.81 69.63 74.05 60.22 66.09
Royalties & Other 4.71 5.92 6.33 4.89 5.51
Operating Costs 2.27 2.74 2.55 3.93 2.87
----------------------------------------------------------------------------
Netback 51.83 60.97 65.17 51.40 57.71
----------------------------------------------------------------------------
Company-Wide
Oil and Gas Sales (mboe/d) 223.5 214.5 202.1 202.6 210.6
Price Received ($/boe) 61.11 66.78 66.82 56.95 62.92
Royalties & Other 18.04 18.95 19.25 14.38 17.68
Operating Costs 8.78 8.21 8.72 9.40 8.77
In-country Taxes 3.31 4.17 4.08 3.33 3.72
----------------------------------------------------------------------------
Netback 30.98 35.45 34.77 29.84 32.75
----------------------------------------------------------------------------
(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 Twelve Months Ended December 31
Three Months Twelve Months
(Cdn$ millions, except per share Ended December 31 Ended December 31
amounts) 2007 2006 2007 2006
----------------------------------------------------------------------------
Revenues and Other Income
Net Sales 1,597 920 5,583 3,936
Marketing and Other (Note 14) 249 361 1,021 1,450
--------------------------------------
1,846 1,281 6,604 5,386
--------------------------------------
Expenses
Operating 303 253 1,165 955
Depreciation, Depletion,
Amortization and Impairment
(Note 4) 724 354 1,767 1,124
Transportation and Other 214 245 908 1,041
General and Administrative 127 176 374 555
Exploration 105 131 326 362
Interest (Note 7) 34 18 168 53
--------------------------------------
1,507 1,177 4,708 4,090
--------------------------------------
Income before Income Taxes 339 104 1,896 1,296
--------------------------------------
Provision for Income Taxes
Current 87 11 434 368
Future 55 16 358 315
--------------------------------------
142 27 792 683
--------------------------------------
Net Income before Non-Controlling
Interests 197 77 1,104 613
Less: Net Income Attributable to
Non-Controlling Interests 3 - 18 12
--------------------------------------
Net Income 194 77 1,086 601
--------------------------------------
--------------------------------------
Earnings Per Common Share ($/share)
Basic (Note 12) 0.37 0.15 2.06 1.15
--------------------------------------
--------------------------------------
Diluted (Note 12) 0.36 0.14 2.02 1.12
--------------------------------------
--------------------------------------
See accompanying notes to the Unaudited Consolidated Financial Statements.
Nexen Inc.
Unaudited Consolidated Balance Sheet
December 31 December 31
(Cdn$ millions, except share amounts) 2007 2006
----------------------------------------------------------------------------
Assets
Current Assets
Cash and Cash Equivalents 206 101
Restricted Cash and Margin Deposits 203 197
Accounts Receivable (Note 2) 3,502 2,951
Inventories and Supplies (Note 3) 659 786
Future Income Tax Assets 18 479
Other 71 67
--------------------------------
Total Current Assets 4,659 4,581
--------------------------------
Property, Plant and Equipment (Note 4)
Net of Accumulated Depreciation,
Depletion, Amortization and
Impairment of $7,195 (December 31, 2006 -
$6,399) 12,498 11,739
Future Income Tax Assets 268 141
Deferred Charges and Other Assets (Note 5) 324 318
Goodwill 326 377
--------------------------------
Total Assets 18,075 17,156
--------------------------------
--------------------------------
Liabilities and Shareholders' Equity
Current Liabilities
Short-Term Borrowings (Note 7) - 158
Accounts Payable and Accrued Liabilities 4,180 3,879
Accrued Interest Payable 54 55
Dividends Payable 13 13
--------------------------------
Total Current Liabilities 4,247 4,105
--------------------------------
Long-Term Debt (Note 7) 4,610 4,673
Future Income Tax Liabilities 2,290 2,468
Asset Retirement Obligations (Note 8) 792 683
Deferred Credits and Other Liabilities
(Note 9) 459 516
Non-Controlling Interests 67 75
Shareholders' Equity (Note 11)
Common Shares, no par value
Authorized: Unlimited
Outstanding: 2007 - 528,304,813 shares
2006 - 525,026,412 shares 917 821
Contributed Surplus 3 4
Retained Earnings 4,983 3,972
Accumulated Other Comprehensive Income
(Note 1) (293) (161)
--------------------------------
Total Shareholders' Equity 5,610 4,636
--------------------------------
Commitments, Contingencies and Guarantees
(Note 15)
--------------------------------
Total Liabilities and Shareholders' Equity 18,075 17,156
--------------------------------
--------------------------------
See accompanying notes to the Unaudited Consolidated Financial Statements.
Nexen Inc.
Unaudited Consolidated Statement of Cash Flow
For the Three and Twelve Months Ended December 31
Three Months Twelve Months
Ended December 31 Ended December 31
(Cdn $ millions) 2007 2006 2007 2006
----------------------------------------------------------------------------
Operating Activities
Net Income 194 77 1,086 601
Charges and Credits to Income not
Involving Cash (Note 13) 787 465 2,073 1,629
Exploration Expense 105 131 326 362
Changes in Non-Cash Working Capital
(Note 13) (329) (85) (348) (177)
Other (Note 13) (54) 2 (307) (41)
--------------------------------------
703 590 2,830 2,374
Financing Activities
Proceeds from (Repayment of)
Long-Term Notes and Debentures
(Note 7) - (93) 1,660 (93)
Proceeds from (Repayment of) Term
Credit Facilities, Net (Note 7) 70 493 (697) 1,044
Proceeds from Term Credit
Facilities of Canexus, Net 15 (2) 60 2
Repayment of Medium-Term Notes
(Note 7) - - (150) -
Proceeds from (Repayment of)
Short-Term Borrowings, Net 2 38 (150) 160
Dividends on Common Shares (14) (13) (53) (52)
Issue of Common Shares and Exercise
of Stock Options 12 7 56 48
Other (6) (7) (49) (28)
--------------------------------------
79 423 677 1,081
Investing Activities
Capital Expenditures
Exploration and Development (823) (868) (3,132) (3,198)
Proved Property Acquisitions (1) (1) (151) (13)
Chemicals, Corporate and Other (46) (31) (118) (119)
Business Acquisitions, Net of Cash
Acquired - - - (78)
Proceeds on Disposition of Assets 4 2 4 27
Changes in Restricted Cash and
Margin Deposits 5 (87) (16) (127)
Changes in Non-Cash Working Capital
(Note 13) 119 19 130 134
Other 17 8 2 (14)
--------------------------------------
(725) (958) (3,281) (3,388)
Effect of Exchange Rate Changes on
Cash and Cash Equivalents (23) 15 (121) (14)
--------------------------------------
Increase in Cash and Cash
Equivalents 34 70 105 53
Cash and Cash Equivalents -
Beginning of Period 172 31 101 48
--------------------------------------
Cash and Cash Equivalents - End of
Period 206 101 206 101
--------------------------------------
--------------------------------------
See accompanying notes to the Unaudited Consolidated Financial Statements.
Nexen Inc.
Unaudited Consolidated Statements of Shareholders' Equity
For the Three and Twelve Months Ended December 31
Three Months Twelve months
Ended December 31 Ended December 31
(Cdn $ millions) 2007 2006 2007 2006
----------------------------------------------------------------------------
Common Shares
Balance at Beginning of Period 891 809 821 732
Issue of Common Shares 4 4 32 32
Proceeds from Tandem Options
Exercised for Shares 8 3 24 16
Accrued Liability Relating to
Tandem Options Exercised for
Shares 14 5 40 41
--------------------------------------
Balance at End of Period 917 821 917 821
--------------------------------------
--------------------------------------
Contributed Surplus
Balance at Beginning of Period 3 3 4 2
Stock-Based Compensation Expense - 1 1 2
Exercise of Tandem Options - - (2) -
--------------------------------------
Balance at End of Period 3 4 3 4
--------------------------------------
--------------------------------------
Retained Earnings
Balance at Beginning of Period 4,825 3,908 3,972 3,423
Net Income 194 77 1,086 601
Dividends on Common Shares (14) (13) (53) (52)
Transition Adjustment Resulting
from Adoption of New Inventory
Standard (Note 1) (22) - (22) -
--------------------------------------
Balance at End of Period 4,983 3,972 4,983 3,972
--------------------------------------
--------------------------------------
Accumulated Other Comprehensive Loss
Balance at Beginning of Period (304) (232) (161) (161)
Opening Cumulative Foreign
Currency Translation Adjustment
(Note 1) - - - -
Opening Derivatives Designated as
Cash Flow Hedges (Note 1) - - 61 -
Other Comprehensive Income (Loss) 11 71 (193) -
--------------------------------------
Balance at End of Period (293) (161) (293) (161)
--------------------------------------
--------------------------------------
Nexen Inc.
Unaudited Consolidated Statement of Comprehensive Income
For the Three and Twelve months Ended December 31
Three Months Twelve Months
Ended December 31 Ended December 31
(Cdn $ millions) 2007 2006 2007 2006
----------------------------------------------------------------------------
Net Income 194 77 1,086 601
Other Comprehensive Income (Loss),
Net of Income Taxes:
Foreign Currency Translation
Adjustment:
Net Gains (Losses) on Investment
in Self-Sustaining Foreign
Operations (45) 234 (867) 16
Net Gains (Losses) on Hedges of
Self-Sustaining Foreign
Operations (1) 59 (165) 738 (20)
Realized Translation Adjustments
Recognized in Net Income (2) (3) 2 (3) 4
Cash Flow Hedges:
Realized Mark-to-Market Gains
Recognized in Net Income - - (61) -
Other Comprehensive Loss, Net of --------------------------------------
Income Taxes 11 71 (193) -
--------------------------------------
Comprehensive Income 205 148 893 601
--------------------------------------
--------------------------------------
(1) Net of income tax recovery for the three months ended December 31, 2007
of $16 million (2006 - $6 million expense) and income tax expense for
the twelve months ended December 31, 2007 of $97 million (2006 - $12
million recovery).
(2) Net of income tax recovery for the three months ended December 31, 2007
of $1 million (2006 - $1 million expense) and twelve months ended
December 31, 2007 of $1 million (2006 - $1 million expense).
See accompanying notes to the Unaudited Consolidated Financial Statements.
Nexen Inc.
Notes to Unaudited Consolidated Financial Statements
Cdn$ millions, except as noted
1. ACCOUNTING POLICIES
Our Unaudited Consolidated Financial Statements are prepared in accordance with Canadian Generally Accepted Accounting Principles (GAAP). 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 December 31, 2007 and the results of our operations and our cash flows for the three and twelve months December 31, 2007 and 2006.
We make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the Unaudited Consolidated Financial Statements, and revenues and expenses during the reporting period. Our management reviews these estimates, including those related to accruals, litigation, environmental and asset retirement obligations, income taxes, derivative contract assets and liabilities and determination of proved reserves, on an ongoing basis. Changes in facts and circumstances may result in revised estimates and actual results may differ from these estimates.
These Unaudited Consolidated Financial Statements should be read in conjunction with our Audited Consolidated Financial Statements included in our 2006 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 2006 Annual Report on Form 10-K.
Change in Accounting Policies
Financial Instruments
On January 1, 2007, we adopted the following new accounting standards issued by the Canadian Accounting Standards Board (AcSB): Financial Instruments-Recognition and Measurement (Section 3855), Hedges (Section 3865) and Comprehensive Income (Section 1530).
Financial Instruments-Recognition and Measurement
Section 3855 requires all financial assets and liabilities to be carried at fair value in the Consolidated Balance Sheet with the exception of loans and receivables, investments that are intended to be held to maturity, and non-trading financial liabilities which are to be carried at cost or amortized cost.
Realized and unrealized gains and losses on financial assets and liabilities carried at fair value are recognized in net income in the periods such gains and losses arise. Transaction costs related to these financial assets and liabilities are included in net income when incurred. Unrealized gains and losses on financial assets and liabilities carried at cost or amortized cost are recognized in net income when these assets or liabilities settle.
We hold financial instruments that were carried at fair value prior to the adoption of Section 3855 as described in Note 10. The valuation methods we use to determine the fair value of these financial instruments remain unchanged. Financial instruments we carry at cost or amortized cost include our accounts receivable, accounts payable, short-term and long-term debt. The carrying value of short-term receivables and payables approximates their fair value. On adoption of Section 3855, we carry our long-term debt at amortized cost using the effective interest rate method. Accordingly, we have reclassified debt discounts previously included in deferred charges and other assets as unamortized debt issue costs, reducing the carrying value of our long-term debt.
Hedges
Section 3865 prescribes new standards for hedge accounting. For cash flow hedges, changes in the fair value of a financial instrument designated as a cash flow hedge are recognized in net income in the same period as the hedged item. Any fair value change in the financial instrument before that period is recognized on the balance sheet. The effective portion of this fair value change is recognized in other comprehensive income with any ineffectiveness recognized in net income during the period of change.
For fair value hedges, both the financial instrument designated as a fair value hedge and the underlying commitment are recognized on the balance sheet at fair value. Changes in the fair value of both are reflected in net income.
Adoption of these new standards for hedge accounting required us to record unrealized mark-to-market gains on cash flow hedges that were previously not included on our Consolidated Balance Sheet at December 31, 2006, as an adjustment to the opening balance of accumulated other comprehensive income (see Note 10).
Comprehensive Income
Section 1530 provides for a new statement of comprehensive income and establishes accumulated other comprehensive income as a separate component of shareholders' equity. The statement of comprehensive income reflects changes in accumulated other comprehensive income and includes the effective portion of changes in the fair value of financial instruments designated as cash flow hedges, as well as changes in foreign currency translation amounts arising from our self-sustaining foreign operations, together with the impact of any related hedges. Amounts included in accumulated other comprehensive income are reclassified to income when realized. On adoption of Section 1530, cumulative foreign currency translation adjustments relating to our self-sustaining foreign operations were reclassed to accumulated other comprehensive income and comparative amounts have been restated.
Impact of Adoption
We adopted these standards prospectively. Comparative amounts for prior periods have not been restated with the exception of amounts related to cumulative foreign currency translation adjustments. Adoption of these standards as at January 1, 2007 had the following impact on our Consolidated Balance Sheet:
January 1, 2007
Increase/(Decrease)
----------------------------------------------------------------------------
To Include Unrealized Mark-to-Market Gains on Cash
Flow Hedges at December 31, 2006:
Accounts Receivable 25
Accounts Payable and Accrued Liabilities (65)
Future Income Tax Liabilities 29
Accumulated Other Comprehensive Income 61
To Include Cumulative Foreign Currency Translation in
Accumulated Other Comprehensive Income:
Cumulative Foreign Currency Translation Adjustment 161
Accumulated Other Comprehensive Income (161)
To Include Unamortized Debt Issue Costs with
Long-Term Debt:
Deferred Charges and Other Assets (59)
Long-Term Debt (59)
---------------------
Inventories
The AcSB issued Inventories (Section 3031), which is effective January 1, 2008. We adopted this standard prospectively in the fourth quarter of 2007 in accordance with the transitional provisions. 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. Section 3031 also clarifies that major spare parts and standby equipment not in use should be included in PP&E. On adoption of Section 3031, we reclassed $51 million from inventories and supplies to PP&E related to major spare parts.
Prior periods presented have not been restated and adoption of the standard
had the following impact:
Three Months Ended
October 1, 2007 December 31, 2007
Increase/(Decrease) Increase
----------------------------------------------------------------------------
Inventories and Supplies (86) 79
Property, Plant and Equipment 51 -
Future Income Tax Liabilities (13) 27
Retained Earnings (22) -
Marketing and Other - 79
Provision for Future Income Taxes - 27
Net Income - 52
Basic/Diluted Earnings Per Share
($/share) - $0.10
-----------------------------------------
New Accounting Pronouncements
In December 2006, the Canadian Accounting Standards Board (AcSB) issued two new Sections in relation to financial instruments: Section 3862, Financial Instruments - Disclosures, and Section 3863, Financial Instruments - Presentation. Both sections are effective for annual and interim periods for fiscal years beginning on or after October 1, 2007 and will require additional disclosures for our financial instruments.
In December 2006, the AcSB issued Section 1535, Capital Disclosures, requiring disclosure of information about an entity's capital and the objectives, policies, and processes for managing capital. The standard is effective for annual periods beginning on or after October 1, 2007 and will require additional disclosure.
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 are currently evaluating the impact these sections will have on our results of operations or financial position.
In January 2006, the AcSB adopted a strategic plan for the direction of accounting standards in Canada. Accounting standards for public companies in Canada are expected to converge with the International Financial Reporting Standards (IFRS) by 2011. The timing for convergence has not been confirmed by the AcSB. We continue to monitor and assess the impact of these convergence efforts.
2. ACCOUNTS RECEIVABLE
December 31 December 31
2007 2006
----------------------------------------------------------------------------
Trade
Marketing 2,501 2,226
Oil and Gas 819 600
Chemicals and Other 60 58
--------------------------
3,380 2,884
Non-Trade 132 80
--------------------------
3,512 2,964
Allowance for Doubtful Receivables (10) (13)
--------------------------
Total 3,502 2,951
--------------------------
--------------------------
3. INVENTORIES AND SUPPLIES
December 31 December 31
2007 2006
Finished Products
Marketing (1) 577 609
Oil and Gas 14 21
Chemicals and Other 13 14
--------------------------
604 644
Work in Process 3 5
Field Supplies (Note 1) 52 137
--------------------------
Total 659 786
--------------------------
--------------------------
(1) Marketing consists of commodity inventories held for trading purposes.
At December 31, 2006, these inventories were carried at the lower of
cost and net realizable value. On October 1, 2007, we adopted Section
3031 and at December 31, 2007, marketing inventories are carried at fair
value, less any costs to sell (see Note 1).
4. DEPRECIATION, DEPLETION, AMORTIZATION AND IMPAIRMENT
In the fourth quarter of 2007, our DD&A expense includes $366 million of impairment expense primarily related to our Aspen, Vermillion 320/340 and West Cameron 170 properties in the Gulf of Mexico as we had poor results from capital investments and lower reserve estimates. At Aspen, disappointing results from our recent investment in development drilling resulted in negative reserve revisions. At Vermillion 320/340 and West Cameron 170, negative reserve revisions primarily relate to gas properties, where unsatisfactory investment results, production performance, revised mapping and higher projected operating costs resulted in a downward revision to reserves estimates. These properties were written down to their fair value equal to their estimated total future cash flows, discounted for the time value of money.
5. DEFERRED CHARGES AND OTHER ASSETS
December 31 December 31
2007 2006
----------------------------------------------------------------------------
Long-Term Marketing Derivative Contracts (Note 10d) 248 153
Deferred Financing Costs (Note 1) - 59
Asset Retirement Remediation Fund 13 13
Crude Oil Put Options (Note 10b) - 19
Other 63 74
--------------------------
Total 324 318
--------------------------
--------------------------
6. SUSPENDED WELL COSTS
The following table shows the changes in capitalized exploratory well costs during the years ended December 31, 2007 and 2006, and does not include amounts that were initially capitalized and subsequently expensed in the same period. Capitalized exploratory well costs are included in PP&E.
Twelve
Twelve Months
Months Ended Ended
December 31 December 31
2007 2006
----------------------------------------------------------------------------
Balance at Beginning of Period 226 252
Additions to Capitalized Exploratory Well Costs
Pending the Determination of Proved Reserves 215 129
Capitalized Exploratory Well Costs Charged to
Expense (10) (70)
Transfers to Wells, Facilities and Equipment
Based on Determination of Proved Reserves (74) (84)
Effects of Foreign Exchange (31) (1)
--------------------------
Balance at End of Period 326 226
--------------------------
--------------------------
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.
December 31 December 31
2007 2006
----------------------------------------------------------------------------
Capitalized for a Period of One Year or Less 202 179
Capitalized for a Period of Greater than One Year 124 47
--------------------------
Balance at End of Period 326 226
--------------------------
--------------------------
Number of Projects that have Exploratory Well
Costs Capitalized for a Period Greater than One Year 5 4
--------------------------
As at December 31, 2007, we have exploratory costs that have been capitalized for more than one year relating to our interest in an exploratory block in the Gulf of Mexico ($51 million), our coalbed methane exploratory activities in Canada ($31 million), exploratory activities on Block 51 in Yemen ($18 million), our interest in an exploratory block, offshore Nigeria ($18 million) and an exploratory block in the North Sea ($6 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.
7. LONG-TERM DEBT AND SHORT-TERM BORROWINGS
December 31 December 31
2007 2006
----------------------------------------------------------------------------
Term Credit Facilities (US$214 million) (a) 211 1,078
Canexus LP Term Credit Facilities (US$204 million) 202 174
Medium-Term Notes, due 2007 (1) - 150
Medium-Term Notes, due 2008 (2) 125 125
Notes, due 2013 (US$500 million) 494 583
Notes, due 2015 (US$250 million) 247 291
Notes, due 2017 (US$250 million) (b) 247 -
Notes, due 2028 (US$200 million) 198 233
Notes, due 2032 (US$500 million) 494 583
Notes, due 2035 (US$790 million) 781 920
Notes, due 2037 (US$1,250 million) (c) 1,235 -
Subordinated Debentures, due 2043 (US$460 million) 454 536
--------------------------
4,688 4,673
Unamortized Debt Issue Costs (Note 1) (78) -
--------------------------
Total Long-Term Debt 4,610 4,673
--------------------------
--------------------------
(1) Amounts due July 2007 were not included in current liabilities as we
refinanced this amount with our term credit facilities.
(2) Amounts due June 2008 are not included in current liabilities as we
expect to refinance this amount with our term credit facilities.
(a) Term credit facilities
We have unsecured term credit facilities of US$3 billion, which are available to 2012. At December 31, 2007, $211 million (US$214 million) was drawn on these facilities (2006 - $1,078 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 5.5 % for the three months ended December 31, 2007 (2006 - 5.9%) and 5.8% for the twelve months ended December 31, 2007 (2006 - 5.7%). At December 31, 2007, $283 million of these facilities were utilized to support outstanding letters of credit (2006 - $294 million).
(b) Notes, due 2017
In May 2007, we issued US$250 million of 10 year notes. Interest is payable semi-annually at a rate of 5.65% and the principal is to be repaid in May 2017. We 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 0.2%. The proceeds were used to repay outstanding term credit facilities.
(c) Notes, due 2037
In May 2007, we issued US$1,250 million of 30 year notes. Interest is payable semi-annually at a rate of 6.4% and the principal is to be repaid in May 2037. We 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 0.35%. The proceeds were used to repay outstanding term credit facilities.
(d) Interest expense
Three Months Twelve Months
Ended December 31 Ended December 31
2007 2006 2007 2006
----------------------------------------------------------------------------
Long-Term Debt 79 76 323 275
Other 4 4 18 19
---------------------------------------
83 80 341 294
Less: Capitalized (49) (62) (173) (241)
---------------------------------------
Total 34 18 168 53
---------------------------------------
---------------------------------------
Capitalized interest relates to and is included as part of the cost of our oil and gas and Syncrude properties. The capitalization rates are based on our weighted-average cost of borrowings.
(e) Short-term borrowings
Nexen has uncommitted, unsecured credit facilities of approximately $665 million, none of which were drawn at December 31, 2007 (2006 - $158 million). We have also utilized $196 million of these facilities to support outstanding letters of credit at December 31, 2007 (2006 - $252 million). Interest is payable at floating rates. The weighted-average interest rate on our short-term borrowings was 5.3% for the three months ended December 31, 2007 (2006 - 5.8%) and 5.8% for the twelve months ended December 31, 2007 (2006 - 5.5%).
8. ASSET RETIREMENT OBLIGATIONS
Changes in carrying amounts of the asset retirement obligations associated with our property, plant and equipment are as follows:
Twelve
Twelve Months
Months Ended Ended
December 31 December 31
2007 2006
----------------------------------------------------------------------------
Balance at Beginning of Period 704 611
Obligations Incurred with Development Activities 105 75
Obligations Discharged with Disposed Properties - (1)
Expenditures Made on Asset Retirements (23) (44)
Accretion 44 37
Revisions to Estimates 79 (10)
Effects of Foreign Exchange (77) 36
--------------------------
Balance at End of Period (1)(2) 832 704
--------------------------
--------------------------
(1) Obligations due within 12 months of $40 million (December 31, 2006 - $21
million) have been included in accounts payable and accrued liabilities.
(2) Obligations relating to our oil and gas activities amount to $786
million (December 31, 2006 - $658 million) and obligations relating to
our chemicals business amount to $46 million (December 31, 2006 - $46
million).
Our total estimated undiscounted asset retirement obligations amount to $2,165 million (2006 - $1,770 million). We have discounted the total estimated asset retirement obligations using a weighted-average, credit-adjusted risk-free rate of 5.9%. Approximately $137 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. The estimated future recoverable reserves at Syncrude are significant and given the long life of this asset, we are unable to determine when asset retirement activities would take place. Furthermore, the Syncrude plant can continue to run indefinitely with ongoing maintenance activities. The retirement obligations for these assets will be recorded in the first year in which the lives of the assets are determinable.
9. DEFERRED CREDITS AND OTHER LIABILITIES
December 31 December 31
2007 2006
----------------------------------------------------------------------------
Long-Term Marketing Derivative Contracts (Note 10d) 163 199
Deferred Transportation Revenue 82 89
Fixed-Price Natural Gas Contracts and Swaps (Note 10b) 48 74
Defined Benefit Pension Obligations 57 48
Capital Lease Obligations 52 48
Other 57 58
--------------------------
Total 459 516
--------------------------
--------------------------
10. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT
We use derivatives in our marketing group for trading purposes and we also use derivatives to manage commodity price risk and foreign currency exchange rate risk for non-trading purposes. Our derivative instruments are carried at fair value on the balance sheet. Our other financial instruments are carried at cost or amortized cost. The carrying value of short-term receivables and payables approximates their fair value because the instruments are near maturity.
(a) Carrying value and estimated fair value of derivatives and financial instruments
The carrying values, fair values, and unrecognized gains or losses on our outstanding derivatives and long-term financial assets and liabilities are:
December 31, 2007 December 31, 2006
----------------------------------------------------------------------------
Carrying Fair Unrecognized Carrying Fair Unrecognized
Value Value Gain/(Loss) Value Value Gain/(Loss)
------------------------------- --------------------------------
Commodity
Price Risk
Non-Trading
Activities
Crude Oil
Put Options - - - 19 19 -
Fixed-Price
Natural Gas
Contracts (70) (70) - (96) (96) -
Natural Gas
Swaps (9) (9) - (8) (8) -
Trading
Activities
Crude Oil
and Natural
Gas 15 15 - 372 372 -
Future Sale
of Gas
Inventory - - - - 25 25
Foreign
Currency
Exchange
Rate Risk
Non-Trading
Activities 1 1 - - - -
Trading
Activities (9) (9) - (12) (12) -
------------------------------- --------------------------------
Total
Derivatives (72) (72) - 275 300 25
------------------------------- --------------------------------
------------------------------- --------------------------------
Other
Financial
Liabilities
Long-Term
Debt (4,610) (4,692) (82) (4,673) (4,728) (55)
------------------------------- --------------------------------
------------------------------- --------------------------------
The estimated fair value of all derivative instruments is based on quoted market prices and, if not available, on estimates from third-party brokers or dealers. Other financial assets used in the normal course of business include cash and cash equivalents, restricted cash and margin deposits and accounts receivable. Other financial liabilities include accounts payable, accrued interest payable, short-term borrowings and long-term debt. Fair value of long-term debt is estimated based on third-party brokers and quoted market prices.
(b) Commodity price risk management
Non-Trading Activities
The majority of our oil and gas production is sold under short-term contracts, exposing us to short-term price movements. Other energy contracts we enter into also expose us to commodity price risk between the time we purchase and sell contracted volumes. From time to time, we actively manage these risks by using commodity futures, forwards, swaps and options.
Crude oil put options
In 2007, we purchased put options on 36 million barrels or approximately 100,000 bbls/d of our 2008 crude oil production. These options established an annual average Dated Brent floor price of US$50/bbl on these volumes. The put options were purchased for $24 million and the fair value at December 31, 2007 was $nil. We recorded a loss of $12 million in marketing and other on the Unaudited Consolidated Statement of Income during the quarter.
In 2006, we purchased WTI crude oil put options on 105,000 bbls/d of our 2007 crude oil production at a cost of $26 million. These options established an annual average WTI floor price of US$50/bbl on these volumes. The 2007 WTI crude oil put options were not used and have expired. The fair value at December 31, 2006 was $19 million, which we included in marketing and other as a loss of $19 million in 2007 on the Unaudited Consolidated Statement of Income.
Fixed-price natural gas contracts and natural gas swaps
In July and August 2005, we sold certain Canadian oil and gas properties and retained fixed-price natural gas sales contracts that were previously associated with those properties. Since these contracts are no longer used in the normal course of our oil and gas operations, they have been included in the Unaudited Consolidated Balance Sheet at fair value. Amounts settling within 12 months are included in accounts payable and amounts settling beyond that included in deferred credits and other liabilities. Any change in fair value is included in marketing and other in the Unaudited Consolidated Statement of Income.
Notional Average Fair
Volumes Term Price Value
----------------------------------------------------------------------------
(Gj/d) ($/Gj) (Cdn$ millions)
Fixed-Price Natural Gas
Contracts 15,514 2008 2.46 (22)
15,514 2009 - 2010 2.56 - 2.77 (48)
---------------
(70)
---------------
---------------
Following the sale of the Canadian oil and gas properties, we entered into natural gas swaps to economically hedge our exposure to the fixed-price natural gas contracts. The natural gas swaps are included in our Unaudited Consolidated Balance Sheet with amounts settling within 12 months included in accounts payable and amounts settling beyond that are included in deferred credits and other liabilities. Any change in fair value is included in marketing and other in the Unaudited Consolidated Statement of Income.
Notional Average Fair
Volumes Term Price Value
----------------------------------------------------------------------------
(Gj/d) ($/Gj) (Cdn$ millions)
Natural Gas Swaps 15,514 2008 7.60 (6)
15,514 2009 - 2010 7.60 (3)
---------------
(9)
---------------
---------------
Trading Activities
Crude oil and natural gas
We enter into physical purchase and sales contracts as well as financial commodity contracts to enhance our price realizations and lock in our margins. The physical and financial commodity contracts (derivative contracts) are stated at fair value. The $15 million fair value of the commodity contracts at December 31, 2007 (2006 - $372 million) is included in the Unaudited Consolidated Balance Sheet and any change in fair value is included in marketing and other in the Unaudited Consolidated Statement of Income.
Future sale of gas inventory
In an attempt to mitigate the exposure to fluctuations in cash flow from changes in the price of natural gas we have certain NYMEX futures contracts and swaps in place, which effectively lock in our margins on the future sale of our natural gas inventory in storage. From time to time we have designated in writing some of these derivative contracts as cash flow hedges of the future sale of our storage inventory.
At December 31, 2006, we held NYMEX natural gas futures contracts and swaps that were designated as cash flow hedges on the future sale of natural gas inventory. On adoption of Section 3865 (see Note 1), the fair value of $25 million related to these cash flow hedges was included in accounts receivable and gains of $16 million, net of income taxes, were included in accumulated other comprehensive income (AOCI). During the first quarter of 2007, the inventory was sold and these gains were recognized in marketing and other in the Unaudited Consolidated Statement of Income.
In late 2006, we de-designated certain futures contracts that had been designated as cash flow hedges of future sales of our natural gas in storage. These contracts were de-designated since it became uncertain that the future sales of natural gas would occur within the designated time frame. As it was reasonably possible that the future sales could have taken place as designated at the inception of the hedging relationship, gains of $65 million on the futures contracts were deferred in accounts payable at December 31, 2006. The adoption of Section 3865 on January 1, 2007 (see Note 1), required that the deferred gains ($45 million, net of income taxes) be reclassified to AOCI. The gains were recognized in marketing and other in the Unaudited Consolidated Statement of Income during the first quarter of 2007.
At December 31, 2007, there were no designated cash flow hedges in place.
(c) Foreign currency exchange rate risk management
Non-Trading Activities
US dollar call options - Canexus
The operations of Canexus are exposed to changes in the US-dollar exchange rate as a portion of their sales are denominated in US dollars while most of its costs are in Canadian dollars. Canexus periodically purchases US-dollar call options to reduce this exposure to fluctuations in the Canadian-US dollar exchange rate. Under outstanding option contracts at December 31, 2007, Canexus LP has the right to sell US$5 million monthly and purchase Canadian dollars at an exchange rate of US$0.95 for the period September 1, 2007 to February 29, 2008. The fair value of these contracts at December 31, 2007 was $1 million. Changes in fair value are included in marketing and other in the Unaudited Consolidated Statement of Income.
Trading Activities
Our sales and purchases of crude oil and natural gas are generally transacted in or referenced to the US dollar, as are most of the financial commodity contracts used by our marketing group. However, we pay for many of our purchases in Canadian dollars. We enter into US-dollar forward contracts and swaps to manage this exposure. Losses of $9 million on our US-dollar forward contracts and swaps at December 31, 2007 (2006 - $12 million) are included in the Unaudited Consolidated Balance Sheet. Any change in fair value is included in marketing and other in the Unaudited Consolidated Statement of Income.
(d) Total carrying value of derivative contracts related to trading activities
Amounts related to derivative instruments held by our marketing operation are equal to fair value as we use mark-to-market accounting and are as follows:
December 31 December 31
2007 2006
----------------------------------------------------------------------------
Accounts Receivable 334 731
Deferred Charges and Other Assets (1) 248 153
--------------------------
Total Derivative Contract Assets 582 884
--------------------------
--------------------------
Accounts Payable and Accrued Liabilities 413 325
Deferred Credits and Other Liabilities (1) 163 199
--------------------------
Total Derivative Contract Liabilities 576 524
--------------------------
--------------------------
Total Derivative Contract Net Assets (2) 6 360
--------------------------
--------------------------
(1) These derivative contracts settle beyond 12 months and are considered
non-current.
(2) Comprised of $15 million (2006 -- $372 million) related to commodity
contracts and losses of $9 million (2006 -- $12 million loss) related
to US-dollar forward contracts and swaps.
Our exchange-traded derivative contracts are subject to margin requirements. We have margin deposits of $203 million (2006 - $197 million), which have been included in restricted cash and margin deposits on our Unaudited Consolidated Balance Sheet at December 31, 2007.
11. SHAREHOLDERS' EQUITY
Dividends
Dividends per common share for the three months ended December 31, 2007 were $0.025 (2006 - $0.025). Dividends per common share for the 12 months ended December 31, 2007 were $0.10 (2006 - $0.10). Dividends paid to holders of common shares have been designated as "eligible dividends" for Canadian tax purposes.
12. EARNINGS PER COMMON SHARE
Our shareholders approved a split of our issued and outstanding common shares on a two-for-one basis at our annual and special meeting on April 26, 2007. All common share and per common share amounts have been retroactively restated to reflect this share split.
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 Twelve Months
Ended December 31 Ended December 31
(millions of shares) 2007 2006 2007 2006
----------------------------------------------------------------------------
Weighted-average number of common
shares outstanding 528.1 524.9 527.1 524.2
Shares issuable pursuant to tandem
options 21.3 26.2 26.6 27.7
Shares to be purchased from proceeds of
tandem options (12.4) (13.4) (15.7) (14.0)
--------------------------------------
Weighted-average number of diluted
common shares outstanding 537.0 537.7 538.0 537.9
--------------------------------------
--------------------------------------
In calculating the weighted-average number of diluted common shares outstanding for the three and twelve months ended December 31, 2007, we excluded 4,081,000 and 49,333 tandem options respectively, because their exercise price was greater than the average common share market price in those periods. In calculating the weighted-average number of diluted common shares outstanding for the three and twelve months ended December 31, 2006, we excluded 1,661,600 and 422,566 tandem options respectively, because their exercise price was greater than the average common share market price in those periods. During the periods presented, outstanding tandem options were the only potential dilutive instruments.
13. CASH FLOWS
(a) Charges and credits to income not involving cash
Three Months Twelve Months
Ended December 31 Ended December 31
2007 2006 2007 2006
----------------------------------------------------------------------------
Depreciation, Depletion, Amortization
and Impairment 724 354 1,767 1,124
Stock-Based Compensation 23 57 (109) 101
Future Income Taxes 55 16 358 315
Change in Fair Value of Crude Oil Put
Options 12 5 43 11
Net Income Attributable to
Non-Controlling Interests 3 - 18 12
Other (30) 33 (4) 66
--------------------------------------
Total 787 465 2,073 1,629
--------------------------------------
--------------------------------------
(b) Changes in non-cash working capital
Three Months Twelve Months
Ended December 31 Ended December 31
2007 2006 2007 2006
----------------------------------------------------------------------------
Accounts Receivable (852) (212) (797) 345
Inventories and Supplies (118) (55) (97) (302)
Other Current Assets 3 15 (15) (14)
Accounts Payable and Accrued
Liabilities 771 168 691 (72)
Accrued Interest Payable (14) 18 - -
--------------------------------------
Total (210) (66) (218) (43)
--------------------------------------
--------------------------------------
Relating to:
Operating Activities (329) (85) (348) (177)
Investing Activities 119 19 130 134
--------------------------------------
Total (210) (66) (218) (43)
--------------------------------------
--------------------------------------
(c) Other cash flow information
Three Months Twelve Months
Ended December 31 Ended December 31
2007 2006 2007 2006
----------------------------------------------------------------------------
Interest Paid 95 61 328 278
Income Taxes Paid 124 81 408 398
--------------------------------------
Cash flow from other operating activities includes cash outflows related to geological and geophysical expenditures of $44 million for the three months ended December 31, 2007 (2006 - $51 million) and $123 million for the twelve months ended December 31, 2007 (2006 - $128 million).
14. MARKETING AND OTHER
Three Months Twelve Months
Ended December 31 Ended December 31
2007 2006 2007 2006
----------------------------------------------------------------------------
Marketing Revenue, Net 209 350 959 1,309
Business Interruption Insurance
Proceeds (1) - 30 - 154
Change in Fair Value of Crude Oil Put
Options (12) (5) (43) (11)
Interest 10 9 39 36
Foreign Exchange Gains (Losses) 32 (23) (22) (72)
Other 10 - 88 34
--------------------------------------
Total 249 361 1,021 1,450
--------------------------------------
--------------------------------------
(1) In 2006, we received business interruption insurance proceeds related to
production losses caused by Gulf of Mexico hurricanes in 2005 and by
generator failures in our UK operations in 2005.
15. COMMITMENTS, CONTINGENCIES AND GUARANTEES
As described in Note 15 to the Audited Consolidated Financial Statements included in our 2006 Annual Report on Form 10-K, there are a number of lawsuits and claims pending, the ultimate results of which cannot be ascertained at this time. We record costs as they are incurred or become determinable. We believe the resolution of these matters would not have a material adverse effect on our liquidity, consolidated financial position or results of operations.
16. 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 2006 Annual Report on Form 10-K.
Three months ended December 31, 2007
(Cdn $ millions) Oil and Gas
----------------------------------------------------------------------------
United United Other
Yemen Canada States Kingdom Countries(1)
------------------------------------------------
Net Sales 275 112 162 741 42
Marketing and Other 2 2 - 4 -
------------------------------------------------
Total Revenues 277 114 162 745 42
Less: Expenses
Operating 44 43 27 56 2
Depreciation, Depletion,
Amortization and
Impairment 37 43 429(3) 176 -
Transportation and Other 2 4 - - -
General and
Administrative (4) 4 20 19 3 18
Exploration - 9 39 19 38(5)
Interest - - - - -
------------------------------------------------
Income (Loss) before
Income Taxes 190 (5) (352) 491 (16)
Less: Provision for
(Recovery of) Income
Taxes 72 (1) (121) 222 (4)
Less: Non-Controlling
Interests - - - - -
------------------------------------------------
Net Income (Loss) 118 (4) (231) 269 (12)
------------------------------------------------
------------------------------------------------
Identifiable Assets 359 5,379(6) 1,640 4,642 317
------------------------------------------------
------------------------------------------------
Capital Expenditures
Development and Other 29 405 49 117 18
Exploration 1 36 122 25 12
Proved Property
Acquisitions - 1 - - -
------------------------------------------------
30 442 171 142 30
------------------------------------------------
------------------------------------------------
Property, Plant and Equipment
Cost 2,178 6,736 3,069 4,723 263
Less: Accumulated DD&A 1,950 1,597 1,765 908 77
------------------------------------------------
Net Book Value 228 5,139(6) 1,304 3,815 186
------------------------------------------------
------------------------------------------------
Corporate
Energy and
(Cdn $ millions) Marketing Syncrude Chemicals Other Total
----------------------------------------------------------------------------
Net Sales 12 151 102 - 1,597
Marketing and Other 209 - 2 30(2) 249
------------------------------------------------
Total Revenues 221 151 104 30 1,846
Less: Expenses
Operating 8 57 66 - 303
Depreciation, Depletion,
Amortization and
Impairment 3 14 12 10 724
Transportation and Other 186 4 10 8 214
General and
Administrative (4) 19 - 7 37 127
Exploration - - - - 105
Interest - - 2 32 34
------------------------------------------------
Income (Loss) before
Income Taxes 5 76 7 (57) 339
Less: Provision for
(Recovery of) Income
Taxes (4) 19 1 (42) 142
Less: Non-Controlling
Interests - - 3 - 3
------------------------------------------------
Net Income (Loss) 9 57 3 (15) 194
------------------------------------------------
------------------------------------------------
Identifiable Assets 3,663(7) 1,212 487 376 18,075
------------------------------------------------
------------------------------------------------
Capital Expenditures
Development and Other 2 9 23 21 673
Exploration - - - - 196
Proved Property
Acquisitions - - - - 1
------------------------------------------------
2 9 23 21 870
------------------------------------------------
------------------------------------------------
Property, Plant and Equipment
Cost 246 1,332 831 315 19,693
Less: Accumulated DD&A 62 205 463 168 7,195
------------------------------------------------
Net Book Value 184 1,127 368 147 12,498
------------------------------------------------
------------------------------------------------
(1) Includes results of operations from producing activities in Colombia.
(2) Includes interest income of $10 million, foreign exchange gains of $32
million and decrease in the fair value of crude oil put options of $12
million.
(3) Includes impairment charges of $366 million related to oil and gas
properties in the Gulf of Mexico.
(4) Includes stock-based compensation expense of $54 million.
(5) Includes exploration activities primarily in Nigeria, Norway and
Colombia.
(6) Includes costs of $3,695 million related to our Long Lake Project (Phase
1 and future phases).
(7) Approximately 84% of Marketing's identifiable assets are accounts
receivable and inventories.
Twelve months ended December 31, 2007
(Cdn $ millions) Oil and Gas
----------------------------------------------------------------------------
United United Other
Yemen Canada States Kingdom Countries(1)
------------------------------------------------
Net Sales 1,086 441 616 2,285 148
Marketing and Other 10 6 - 39 -
------------------------------------------------
Total Revenues 1,096 447 616 2,324 148
Less: Expenses
Operating 171 173 102 212 8
Depreciation, Depletion,
Amortization and
Impairment 213 166 641(3) 599 8
Transportation and Other 8 22 - - -
General and
Administrative (4) (6) 50 38 3 40
Exploration 5 27 134 69 91(5)
Interest - - - - -
------------------------------------------------
Income (Loss) before
Income Taxes 705 9 (299) 1,441 1
Less: Provision for
(Recovery of) Income
Taxes 248 3 (103) 712 -
Less: Non-Controlling
Interests - - - - -
------------------------------------------------
Net Income (Loss) 457 6 (196) 729 1
------------------------------------------------
------------------------------------------------
Identifiable Assets 359 5,379(6) 1,640 4,642 317
------------------------------------------------
------------------------------------------------
Capital Expenditures
Development and Other 124 1,381 414 551 53
Exploration 12 123 275 119 44
Proved Property
Acquisitions - 1 104(8) 46(9) -
------------------------------------------------
136 1,505 793 716 97
------------------------------------------------
------------------------------------------------
Property, Plant and Equipment
Cost 2,178 6,736 3,069 4,723 263
Less: Accumulated DD&A 1,950 1,597 1,765 908 77
------------------------------------------------
Net Book Value 228 5,139(6) 1,304 3,815 186
------------------------------------------------
------------------------------------------------
Corporate
Energy and
Marketing Syncrude Chemicals Other Total
----------------------------------------------------------------------------
Net Sales 48 545 414 - 5,583
Marketing and Other 959 - 33 (26)(2) 1,021
------------------------------------------------
Total Revenues 1,007 545 447 (26) 6,604
Less: Expenses
Operating 34 208 257 - 1,165
Depreciation, Depletion,
Amortization and
Impairment 13 53 45 29 1,767
Transportation and Other 806 17 39 16 908
General and
Administrative (4) 87 1 31 130 374
Exploration - - - - 326
Interest - - 11 157 168
------------------------------------------------
Income (Loss) before
Income Taxes 67 266 64 (358) 1,896
Less: Provision for
(Recovery of) Income
Taxes 21 75 18 (182) 792
Less: Non-Controlling
Interests - - 18 - 18
------------------------------------------------
Net Income (Loss) 46 191 28 (176) 1,086
------------------------------------------------
------------------------------------------------
Identifiable Assets 3,663(7) 1,212 487 376 18,075
------------------------------------------------
------------------------------------------------
Capital Expenditures
Development and Other 4 36 62 52 2,677
Exploration - - - - 573
Proved Property
Acquisitions - - - - 151
------------------------------------------------
4 36 62 52 3,401
------------------------------------------------
------------------------------------------------
Property, Plant and Equipment
Cost 246 1,332 831 315 19,693
Less: Accumulated DD&A 62 205 463 168 7,195
------------------------------------------------
Net Book Value 184 1,127 368 147 12,498
------------------------------------------------
------------------------------------------------
(1) Includes results of operations from producing activities in Colombia.
(2) Includes interest income of $39 million, foreign exchange losses of $22
million and decrease in the fair value of crude oil put options of $43
million.
(3) Includes impairment charges of $366 million related to oil and gas
properties in the Gulf of Mexico.
(4) Includes stock-based compensation expense of $38 million.
(5) Includes exploration activities primarily in Nigeria, Norway and
Colombia.
(6) Includes costs of $3,695 million related to our Long Lake Project (Phase
1 and future phases).
(7) Approximately 84% of Marketing's identifiable assets are accounts
receivable and inventories.
(8) Includes acquisition of producing properties in the Gulf of Mexico.
(9) Includes acquisition of additional interests in the Scott and Telford
fields.
Three months ended December 31, 2006
(Cdn $ millions) Oil and Gas
----------------------------------------------------------------------------
United United Other
Yemen Canada States Kingdom Countries(1)
------------------------------------------------
Net Sales 299 108 133 105 31
Marketing and Other 2 - 30 4 -
------------------------------------------------
Total Revenues 301 108 163 109 31
Less: Expenses
Operating 41 40 27 17 3
Depreciation, Depletion,
Amortization and
Impairment (3) 79 47 141 48 2
Transportation and Other 2 11 - - 1
General and
Administrative (5) 6 24 14 8 14
Exploration 3 8 74 13 33(6)
Interest - - - - -
------------------------------------------------
Income (Loss) before
Income Taxes 170 (22) (93) 23 (22)
Less: Provision for
(Recovery of) Income
Taxes 58 25 (31) 45 (9)
Less: Non-Controlling
Interests - - - - -
------------------------------------------------
Net Income (Loss) 112 (47) (62) (22) (13)
------------------------------------------------
------------------------------------------------
Identifiable Assets 464 3,923(7) 1,620 5,490 245
------------------------------------------------
------------------------------------------------
Capital Expenditures
Development and Other 35 374 143 186 8
Exploration 9 21 22 27 31
Proved Property
Acquisitions - 1 - - -
------------------------------------------------
44 396 165 213 39
------------------------------------------------
------------------------------------------------
Property, Plant and Equipment
Cost 2,404 5,216 2,889 4,710 249
Less: Accumulated DD&A 2,128 1,448 1,445 432 78
------------------------------------------------
Net Book Value 276 3,768(7) 1,444 4,278 171
------------------------------------------------
------------------------------------------------
Corporate
Energy and
Marketing Syncrude Chemicals Other Total
----------------------------------------------------------------------------
Net Sales 25 118 101 - 920
Marketing and Other 350 - (6) (19)(2) 361
------------------------------------------------
Total Revenues 375 118 95 (19) 1,281
Less: Expenses
Operating 13 48 64 - 253
Depreciation, Depletion,
Amortization and
Impairment (3) 6 14 10 7 354
Transportation and Other 198 4 9 20(4) 245
General and
Administrative (5) 19 1 9 81 176
Exploration - - - - 131
Interest - - 3 15 18
------------------------------------------------
Income (Loss) before
Income Taxes 139 51 - (142) 104
Less: Provision for
(Recovery of) Income
Taxes 38 15 1 (115) 27
Less: Non-Controlling
Interests - - - - -
------------------------------------------------
Net Income (Loss) 101 36 (1) (27) 77
------------------------------------------------
------------------------------------------------
Identifiable Assets 3,528(8) 1,186 459 241 17,156
------------------------------------------------
------------------------------------------------
Capital Expenditures
Development and Other 3 12 13 15 789
Exploration - - - - 110
Proved Property
Acquisitions - - - - 1
------------------------------------------------
3 12 13 15 900
------------------------------------------------
------------------------------------------------
Property, Plant and Equipment
Cost 226 1,304 854 286 18,138
Less: Accumulated DD&A 47 179 494 148 6,399
------------------------------------------------
Net Book Value 179 1,125 360 138 11,739
------------------------------------------------
------------------------------------------------
(1) Includes results of operations from producing activities in Colombia.
(2) Includes interest income of $9 million, foreign exchange losses of $23
million and decrease in the fair value of crude oil put options of $5
million.
(3) Includes an impairment charge of $93 million, primarily relating to two
natural gas producing properties in the Gulf of Mexico.
(4) Includes $17 million (US$15 million) accrual with respect to the Block
51 arbitration.
(5) Includes stock-based compensation expense recovery of $71 million.
(6) Includes exploration activities primarily in Nigeria, Norway and
Colombia.
(7) Includes costs of $2,444 million related to our Long Lake Project (Phase
1 and future phases).
(8) Approximately 80% of Marketing's identifiable assets are accounts
receivable and inventories.
Twelve months ended December 31, 2006
(Cdn $ millions) Oil and Gas
----------------------------------------------------------------------------
United United Other
Yemen Canada States Kingdom Countries(1)
------------------------------------------------
Net Sales 1,328 459 629 477 139
Marketing and Other 8 7 81(2) 85(3) 1
------------------------------------------------
Total Revenues 1,336 466 710 562 140
Less: Expenses
Operating 151 143 106 80 8
Depreciation, Depletion,
Amortization and
Impairment (5) 327 162 296 216 10
Transportation and Other 6 33 - - 1
General and
Administrative (7) 17 80 58 14 44
Exploration 4 26 214 46 72(8)
Interest - - - - -
------------------------------------------------
Income (Loss) before
Income Taxes 831 22 36 206 5
Less: Provision for
(Recovery of) Income
Taxes 289 7 13 378(9) 1
Less: Non-Controlling
Interests - - - - -
------------------------------------------------
Net Income (Loss) 542 15 23 (172) 4
------------------------------------------------
------------------------------------------------
Identifiable Assets 464 3,923(10) 1,620 5,490 245
------------------------------------------------
------------------------------------------------
Capital Expenditures
Development and Other 145 1,434 418 596 28
Exploration 37 163 177 62 52
Proved Property
Acquisitions - 12 - 1 -
------------------------------------------------
182 1,609 595 659 80
------------------------------------------------
------------------------------------------------
Property, Plant and Equipment
Cost 2,404 5,216 2,889 4,710 249
Less: Accumulated DD&A 2,128 1,448 1,445 432 78
------------------------------------------------
Net Book Value 276 3,768(10) 1,444 4,278 171
------------------------------------------------
------------------------------------------------
Corporate
Energy and
Marketing Syncrude Chemicals Other Total
----------------------------------------------------------------------------
Net Sales 51 446 407 - 3,936
Marketing and Other 1,309 - 6 (47)(4) 1,450
------------------------------------------------
Total Revenues 1,360 446 413 (47) 5,386
Less: Expenses
Operating 31 187 249 - 955
Depreciation, Depletion,
Amortization and
Impairment (5) 12 33 40 28 1,124
Transportation and Other 789 18 40 154(6) 1,041
General and
Administrative (7) 112 1 29 200 555
Exploration - - - - 362
Interest - - 11 42 53
------------------------------------------------
Income (Loss) before
Income Taxes 416 207 44 (471) 1,296
Less: Provision for
(Recovery of) Income
Taxes 151 66 15 (237) 683
Less: Non-Controlling
Interests - - 12 - 12
------------------------------------------------
Net Income (Loss) 265 141 17 (234) 601
------------------------------------------------
------------------------------------------------
Identifiable Assets 3,528(11) 1,186 459 241 17,156
------------------------------------------------
------------------------------------------------
Capital Expenditures
Development and Other 47 86 27 45 2,826
Exploration - - - - 491
Proved Property
Acquisitions - - - - 13
------------------------------------------------
47 86 27 45 3,330
------------------------------------------------
------------------------------------------------
Property, Plant and Equipment
Cost 226 1,304 854 286 18,138
Less: Accumulated DD&A 47 179 494 148 6,399
------------------------------------------------
Net Book Value 179 1,125 360 138 11,739
------------------------------------------------
------------------------------------------------
(1) Includes results of operations from producing activities in Colombia.
(2) Includes $80 million of business interruption insurance proceeds
related to production losses caused by Gulf of Mexico hurricanes in
2005.
(3) Includes proceeds of $74 million from business interruption insurance
claims for generator failures in 2005 at our UK oil and gas operations.
(4) Includes interest income of $36 million, foreign exchange losses of $72
million and decrease in the fair value of crude oil put options of $11
million.
(5) Includes an impairment charge of $93 million, primarily relating to two
natural gas producing properties in the Gulf of Mexico.
(6) Includes $151 million (US$135 million) accrual with respect to the
Block 51 arbitration.
(7) Includes stock-based compensation expense of $210 million.
(8) Includes exploration activities primarily in Nigeria, Norway and
Colombia.
(9) Includes future income tax expense of $277 million related to an
increase in the supplemental tax rate on oil and gas activities in the
United Kingdom.
(10) Includes costs of $2,444 million related to our Long Lake Project
(Phase 1 and future phases).
(11) Approximately 80% of Marketing's identifiable assets are accounts
receivable and inventories.
Michael J. Harris, CA
Vice President, Investor Relations
(403) 699-4688
or
Lavonne Zdunich, CA
Analyst, Investor Relations
(403) 699-5821
or
Sean Noe, P.Eng
Analyst, Investor Relations
(403) 699-4494
or
Nexen Inc.
801 - 7th Ave SW
Calgary, Alberta, Canada T2P 3P7
Website: www.nexeninc.com
