News Releases
Nexen Announces Fourth Quarter and Annual Financial Results
CALGARY, ALBERTA--(Feb. 12, 2009) - Nexen achieved record financial results in 2008, generating cash flow of more than $4.2 billion ($8.04/share) and earnings of $1.7 billion ($3.26/share). Record oil prices during the first half of the year contributed to these results. In the latter part of the year, oil prices fell significantly and this impacted our fourth quarter results. Highlights are as follows:
- Quarterly cash flow of $559 million ($1.08/share)
- Quarterly earnings loss of $181 million ($(0.35)/share) after non-cash impairment charges of $317 million, after tax
- Annual production after royalties of 210,000 boe/d (250,000 boe/d before royalties), a modest increase over 2007 despite hurricane downtime
- Produced first premium synthetic crude oil at Long Lake in January 2009; current SAGD production at all-time high; upgrader consistently operating at expected start-up rates
- Exciting drilling success in the UK North Sea, expanding the Golden Eagle area
- Proved reserve additions of 74 million boe from capital investment program
- Acquired an additional 15% in the Long Lake project and joint venture lands-Nexen is sole operator of SAGD operations and upgrader
- Financial position remains strong-liquidity of over $3.5 billion after acquiring additional Long Lake working interest
Three Months Ended Twelve Months Ended
December 31 December 31
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(Cdn$ millions) 2008 2007 2008 2007
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Production (mboe/d)(1)
Before Royalties 230 262 250 254
After Royalties 198 214 210 207
Net Sales 1,270 1,597 7,424 5,583
Cash Flow from Operations(2) 559 1,079 4,229 3,458
Per Common Share ($/share)(2) 1.08 2.04 8.04 6.56
Net Income (Loss) (181) 194 1,715 1,086
Per Common Share ($/share) (0.35) 0.37 3.26 2.06
Capital Expenditures 917 870 3,066 3,401
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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. 16.
Financial Results-Record Annual Results but Different Times Now
In 2008, we generated record cash flow in excess of $4.2 billion and earnings of approximately $1.7 billion, reflecting strong production from our Buzzard field in the North Sea and record commodity prices during the year. We also benefited from industry-leading cash netbacks, driven by low royalties and low company-wide conventional operating costs, which averaged $8.68/boe last year.
WTI averaged US$99.65/bbl for the year, an increase of 38% over 2007. In the fourth quarter of 2008, WTI was significantly lower averaging US$58.73/bbl. After reaching an all-time high of US$147.27/bbl in the first half of the year, WTI dropped significantly by year end to US$44.60/bbl. As a result, fourth quarter cash flow was $559 million, down approximately 50% from a year ago when the quarterly average for WTI was US$90.69/bbl. Net income for the quarter was a loss of $181 million after impairment charges of $317 million and marketing losses of $131 million, both after tax.
"The past year has been both exciting and volatile," commented Marvin Romanow, Nexen's President and Chief Executive Officer. "In the first half of the year, we saw record oil prices but these quickly disappeared when the recession took hold and demand for oil fell for the first time in almost 30 years. While the current environment is challenging from both a commodity price and credit perspective, Nexen is well positioned. We have excellent assets, a strong balance sheet and our cash netbacks continue to be among the highest in the industry which will help drive superior relative financial performance. In addition, our exploration program is delivering exciting discoveries in the North Sea."
Significant Items Affecting our Quarterly Results
Asset Impairments
During the quarter, we recorded non-cash impairment charges of approximately $317 million, after tax ($568 million, before tax) relating to some properties in the UK North Sea and the Gulf of Mexico. In the North Sea, we recognized an impairment charge of $318 million relating to our Selkirk and Ettrick properties. At Selkirk, we expensed $62 million of allocated acquisition costs as we have no firm development plans here. At Ettrick, the impairment charge largely reflects higher drilling costs and lower reserve estimates. In the Gulf of Mexico, our impairment charge relates primarily to four shelf properties ($143 million) and our Green Canyon 6 deep-water property ($107 million). On the shelf, these late-life, mature assets are sensitive to near-term commodity prices. At Green Canyon 6, the impairment charge reflects higher costs after Hurricane Ike destroyed a third-party production platform in the third quarter of 2008. This has resulted in unexpected costs to construct new production facilities and, following an evaluation of options, we expect to have production back on stream in late 2010.
Marketing Division
Our marketing division reported a cash flow loss of approximately $140 million for the fourth quarter. This follows cash flow losses previously reported for the second and third quarters. These losses are primarily attributable to natural gas location spread trading activities. Since mid 2008, we have been exiting positions that do not support our physical marketing business and we have been scaling back our trading activities in an orderly fashion to minimize losses on closing positions. This has been a challenging process given the lack of liquidity in the market, fewer counterparties and deteriorating commodity prices that have eroded natural gas spreads.
The losses we incurred in mid 2008 related to positions we had taken that were expected to benefit from strengthening natural gas prices in the US Rockies following the addition of new pipeline capacity in the region. Delays in the start-up of this pipeline worked against these positions and resulted in losses as we closed out of them mid year. This left us with trading positions that were expected to benefit from widening east-west location spreads later in the year driven by typical winter demand in eastern consuming gas markets. As we worked to reduce this trading exposure, we were faced with a rapidly deteriorating economic environment in which natural gas prices fell from highs of over US$13.00/mmbtu in the summer to winter prices around US$6.00/mmbtu in December and US$4.50/mmbtu today, a period normally characterized by increasing prices. These falling natural gas prices compressed spreads causing losses in the third quarter and additional losses in the fourth quarter as the widening spreads we were positioned for did not materialize and spreads narrowed even further despite cold weather in the east due to demand destruction in the economy. We exited the last of these positions in January 2009.
Our fourth quarter marketing results also include a loss from our NGL business. Over the years, we have been developing this business to take advantage of growing demand for green fuels, such as ethanol, denaturant and propane. The quarterly loss reflects declining margins for these products following substantial demand reduction caused by the current economic environment. We are in the process of exiting our ethanol and propane businesses and we expect to complete this by the end of the first quarter.
"2008 was a difficult year for our marketing business," said Romanow. "Since the middle of the year, we have been refocusing this division and reducing the size of our trading levels. In response to the rapidly deteriorating economic environment and limited liquidity, we have been carefully choosing our exit points. With the gas trading positions we recently exited, the refocusing of our gas marketing business back to physical transportation and storage is now complete. So far this year, the results from our marketing division are slightly positive."
Strong Liquidity Serving Us Well
We are well positioned to weather the downturn in the economy given our strong liquidity. In 2008, our cash flow exceeded our capital investment by over $1 billion. We used this excess to repurchase approximately 12 million shares for $338 million and build our cash balances. Recently, we used a portion of this cash to fund the acquisition of an additional 15% in the Long Lake project and joint venture lands. Going forward, we have over $3.5 billion of available liquidity, comprised of cash of approximately $1.8 billion, with the remainder in undrawn committed credit lines. We have no debt maturities until 2012 and the average term of our public debt is approximately 18 years.
For 2009, we have announced an oil and gas capital investment budget of $2.6 billion that is self funding at WTI US$60/bbl. While our financial position is strong and we have excellent assets, we will monitor our capital spending and proceed cautiously as the year unfolds.
"As the world stands today, it is unlikely we will carry out our whole 2009 capital program," noted Romanow. "This will preserve liquidity and allow us to take advantage of strategic opportunities as they arise such as appraising our new discoveries in the North Sea. These discoveries are economic to develop in the current commodity price environment."
Much of our production has low operating costs and low royalties, and this is generating cash netbacks that are among the highest in the industry. As a result, our assets are capable of generating positive cash flows despite recent declines in commodity prices. To help ensure base cash flow, we have put options on 45,000 bbls/d of our production with an average 2009 strike price of US$60/bbl Brent.
Quarterly Production
Quarterly Quarterly
Production before Production after
Royalties Royalties
Crude Oil, NGLs and
Natural Gas (mboe/d) Q4 2008 Q3 2008 Q4 2008 Q3 2008
-------------------------------------------------------- -------------------
North Sea 95 103 95 103
Yemen 52 54 32 30
Canada - Oil & Gas 39 38 31 30
Canada - Bitumen 7 5 6 5
United States 9 20 8 17
Other Countries 6 6 5 5
Syncrude 22 23 21 19
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Total 230 249 198 209
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Our fourth quarter production averaged 230,000 boe/d (198,000 boe/d after royalties). A significant portion of our Gulf of Mexico production remains shut-in following hurricanes in the third quarter of 2008. Our US production was approximately 30,000 boe/d prior to the hurricanes and was reduced to 6,000 boe/d after. In the fourth quarter, we restored production at Gunnison, West Cameron and Eugene Island and recently resumed production at Aspen, increasing our Gulf of Mexico production to approximately 17,000 boe/d. We expect our Wrigley field to come back on stream by the end of the first quarter although timing ultimately depends on repairs to third-party facilities. At Green Canyon 6, 50 and 137, production remains shut-in following the destruction of a host processing platform. We are evaluating options for these fields. In the UK, production was lower during the quarter on account of maintenance downtime at all fields. Buzzard contributed 85,000 boe/d (197,000 boe/d gross) to our quarterly volumes compared to 89,600 boe/d (207,500 boe/d gross) in the third quarter.
Annual Production
Annual
Production Annual
before Production
Royalties after Royalties
Crude Oil, NGLs and
Natural Gas (mboe/d) 2008 2007 2008 2007
-------------------------------------------------------- -------------------
North Sea 103 84 103 84
Yemen 56 72 31 40
Canada - Oil & Gas 38 37 30 30
Canada - Bitumen 4 - 4 -
United States 22 33 19 29
Other Countries 6 6 5 5
Syncrude 21 22 18 19
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Total 250 254 210 207
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Our annual production averaged 250,000 boe/d (210,000 boe/d after royalties). Buzzard performed well and contributed 88,200 boe/d (204,200 boe/d gross) compared to 64,200 boe/d (148,500 boe/d gross) in 2007 when it was ramping up. This increase was offset by declines at our maturing fields in Yemen and hurricane interruptions in the Gulf of Mexico.
In 2009, we expect our production after royalties to grow approximately 10% compared to 2008 and range from 225,000 to 240,000 boe/d (255,000 to 270,000 boe/d before royalties). This growth is due to the start-up of Ettrick in the North Sea, Longhorn in the Gulf of Mexico and ramping up production at Long Lake. Our production at Long Lake will also be at a higher working interest than in 2008.
2008 Capital Investment and Reserves
2008 Capital Investment(1) (Cdn$ millions)
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Insitu
United Other Oil
Kingdom Yemen International US Canada Sands Syncrude Total
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Core Asset
Development 277 92 13 164 103 - 55 704
Major
Development 238 - 174 87 63 330 - 892
Early-stage
Development - - - - 11 144 - 155
Exploration 157 9 130 195 226 2 - 719
Proved
Property
Acquisitions - - - - 2 20 - 22
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Total Oil and
Gas
Investment 672 101 317 446 405 496 55 2,492
Long Lake
Upgrader - - - - - 322 - 322
Marketing,
Corporate,
Chemicals and
Other - - - - 149 - - 149
Capitalized
Interest 30 - 3 - - 207 - 240
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Total Capital
Investment 702 101 320 446 554 1,025 55 3,203
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% of Total 22% 3% 10% 14% 17% 32% 2% 100%
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1. Includes geological and geophysical expenditures of $137 million.
Shown below is a summary of our year-on-year reserve changes. A detailed reconciliation table can be found on page 15 of this release.
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2008 Reserves Continuity
Oil and Gas Activities
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United Other
mmboe Kingdom Yemen International US Canada
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PROVED RESERVES (1)
Dec. 31, 2007 207 41 38 62 118
Economic
Revisions (16) - (2) (5) (27)
Activities(5) 22 12 - - 13
Production (38) (22)(4) (2) (8) (14)
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Dec. 31, 2008 175 31 34 49 90
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PROBABLE RESERVES (1,2)
Dec. 31, 2007 144 15 60 60 58
Economic
Revisions (2) (1) 2 (16) (8)
Conversions to
Proved (32) (1) - (2) (2)
Activities(5) 26 - (1) (18) (12)
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Dec. 31, 2008 136 13 61 24 36
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TOTAL PROVED + PROBABLE RESERVES (1,2)
Dec. 31, 2007 351 56 98 122 176
Economic
Revisions (18) (1) - (21) (35)
Activities(5) 16 11 (1) (20) (1)
Production (38) (22)(4) (2) (8) (14)
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Dec. 31, 2008 311 44 95 73 126
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2008 Reserves Continuity
Oil and Gas Activities Mining
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Bitumen Total Oil Syncrude(3) Total Oil, Gas
mmboe and Gas and Mining
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PROVED RESERVES
Dec. 31, 2007 268 734 324 1,058
Economic
Revisions - (50) - (50)
Activities(5) 19 66 8 74
Production (2) (86) (8) (94)
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Dec. 31, 2008 285 664 324 988
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PROBABLE RESERVES (1,2)
Dec. 31, 2007 523 860 46 906
Economic
Revisions - (25) - (25)
Conversions to
Proved (7) (44) (8) (52)
Activities(5) 216 211 8 219
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Dec. 31, 2008 732 1,002 46 1,048
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TOTAL PROVED + PROBABLE RESERVES (1,2)
Dec. 31, 2007 791 1,594 370 1,964
Economic
Revisions - (75) - (75)
Activities(5) 228 233 8 241
Production (2) (86) (8) (94)
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Dec. 31, 2008 1,017 1,666 370 2,036
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1. We internally evaluate all of our reserves and have at least 80% of our
proved reserves assessed by independent qualified consultants each year;
99% 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 estimated using The Canadian Oil and Gas Evaluation
handbook (COGEH) standards. 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.
5. Includes extensions, discoveries, conversions and performance revisions.
Understanding our Capital Efficiency
In 2008, we invested approximately $2.5 billion in oil and gas exploration and development activities and added 74 million boe of proved reserves before negative economic revisions of 50 million boe. Under SEC regulations, we are required to use year-end pricing to determine our proved reserves. Low commodity prices at December 31, 2008 caused virtually all of our negative economic revisions. These revisions represent only 5% of our total proved reserves and may come back in an improved commodity price environment. On an after-royalties basis, our proved reserves total 926 million boe at December 31, 2008 compared to 917 million boe at December 31, 2007.
"Last year, we invested approximately 45% of our oil and gas capital in next generation, new growth projects such as the Usan development offshore West Africa, shale gas, CBM, future oil sands phases and conventional exploration," said Romanow. "These projects are characterized by multi-year investments where capital is invested, in some instances, many years before reserves can be recognized. Measuring proved reserves additions against capital expenditures for a one-year period, and in some cases a three-year period, is not meaningful and doesn't tell the whole Nexen story."
Over the past three years, we have invested approximately $8.2 billion on our oil and gas business and added 467 million boe of proved reserves. The following table shows where we have made this investment together with proved reserve adds net of revisions:
Capital Proved Reserve Adds
Investment net of Revisions
(Cdn$ millions) (mmboe)
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Shale Gas 315 -
Coalbed Methane (CBM) 535 28
Oil Sands 1,900 316
Conventional 5,450 123
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8,200 467
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Our projects generate attractive full cycle metrics but capital efficiency in the near term is impacted by the timing of reserve bookings. For example, our three-year investment on shale gas totals $315 million and we have not yet booked any proved reserves. While initial results announced by ourselves and our competitors indicate there is significant resource potential here, we are not able to book any reserves until commerciality is declared and actual production supports our expectation.
Similarly, we have invested $535 million over the past three years developing our CBM lands and we have only recognized 28 million boe of proved reserves so far. Initially, we are only allowed to book proved reserves for this new play type based on actual production history rather than expected long-term decline rates. As our CBM production volumes rise, we will be able to book more proved reserves.
On the conventional side, our three-year investment totals approximately $5.5 billion and we have added 123 million boe of proved reserves. This includes $1.6 billion in exploration which has resulted in several discoveries in the UK North Sea and in the Gulf of Mexico, such as Golden Eagle, Pink, Hobby, Rochelle, Blackbird, Knotty Head and Vicksburg. To date, we have booked minimal proved reserves for these discoveries. We expect to book the related reserves in the coming years as these discoveries are sanctioned for development.
In the Gulf of Mexico, our three-year deep-water investment on Aspen amounted to $390 million. Results from this investment over this period were disappointing and reserve adds were minimal. On a full-cycle basis, Aspen has generated attractive returns and paid out in early 2005, just over two years from first production.
For our other conventional oil and gas properties, we have invested approximately $3.5 billion over the last three years. This investment resulted in 142 million boe of proved reserve adds.
Capital Program Review
United Kingdom
We invested $702 million in the UK last year. This included approximately $250 million at Buzzard and added 29 million boe of proved reserves. Successful drilling and production performance resulted in increases in both reservoir size and overall recovery factor which led to these proved reserve adds. These additions were offset by negative economic revisions of 10 mmboe due to low year-end prices.
"Buzzard has been a great project for us and is generating exceptional value for shareholders," said Romanow. "Since we first acquired this asset, we have successfully increased our proved plus probable reserves by 101 million boe or 49%, and extended our production plateau by over three years. The facility is consistently operating above original design expectations and even at US$40/bbl Brent, we generate over $1 billion of annual pre-tax cash flow."
In 2009, Buzzard will continue to be a significant contributor to our cash flow and production volumes. Throughout the year, we will continue construction of the fourth platform containing production sweetening facilities designed to handle higher levels of hydrogen sulphide. During the third quarter, we plan to install the jackets for this platform and complete tie-in operations, pending installation of the topsides. This will result in about one month of downtime which coincides with a six week planned slowdown of the Forties pipeline.
Our Ettrick development in the North Sea is progressing towards first oil in the next few months. In 2008, we invested approximately $260 million and to date we have recognized 20 million boe of proved plus probable reserves here. This is after 12 million boe of negative proved revisions that we incurred in 2008. These revisions relate to low year-end oil prices and disappointing drilling results that lowered our reserve estimates. The Ettrick development consists of 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 Ettrick to add approximately 10,000 boe/d to our 2009 production volumes. We also have a discovery at Blackbird which could be a future tie-back to Ettrick. We have no proven reserves booked for Blackbird. In 2009, we plan to drill an appraisal well here. We operate both Ettrick and Blackbird, with an 80% working interest in each.
We recently drilled a successful appraisal well at Rochelle on Block 15/27 in the North Sea. The well encountered 77 feet of net pay, was drill stem tested and flowed at an average restricted rate of 41 mmcf/d of gas and 2,300 bbls/d of oil condensate from a 72/64-inch fixed choke. We are evaluating future appraisal and fast track development options and have a 44% non-operated working interest in this well.
Elsewhere, we are assessing future appraisal and development alternatives for the growing Golden Eagle area. This area includes exciting discoveries at Golden Eagle, Pink and most recently, Hobby where initial results indicate a significant column of high-quality net pay which is at the high end of our pre-drill expectations. We are planning to drill multiple sidetracks to determine the extent of both this discovery and Golden Eagle. Hobby is located on Block 20/1N approximately 1.5 km west of the Golden Eagle discovery. We have a 34% interest in both Hobby and Golden Eagle, 46% interest in Pink and operate all three. We have identified additional prospects in the area and have plans for further exploratory and appraisal drilling this year.
"Our strategy in the UK is working well and we have had exciting success with our exploration and exploitation program," commented Romanow. "We have a number of satellite discoveries that are in the same areas as our large operations at Buzzard, Scott/Telford and Ettrick. This infrastructure provides opportunities for quick cost effective tie-backs."
Yemen
Yemen remains a significant asset for us and continues to generate cash flow in excess of capital requirements. In 2008, we invested $101 million and added 12 million boe of proved reserves. We will continue to maximize the value of these assets over their remaining contract terms and expect 2009 annual production of between 40,000 and 45,000 boe/d, before royalties.
Other International
Development of the Usan field, offshore West Africa, is underway with first production expected in 2012. In 2008, our capital investment at Usan on block OML 138 focused on detailed engineering, procurement and the initial fabrication of equipment. The development of Usan includes a FPSO with the ability to process 180,000 bbls/d and store up to two million barrels of oil. In 2009, we are scheduled to start fabrication of the FPSO hull and topside facilities, begin development drilling, and complete detailed engineering and procurement. We are also evaluating plans for further exploration on this block. We have a 20% interest in exploration and development along with Total E&P Nigeria Limited (20% and Operator), Chevron Petroleum Nigeria Limited (30%) and Esso Exploration and Production Nigeria (Offshore East) Limited (30%).
In the fourth quarter of 2008, Nigerian authorities approved the acquisition of interests in offshore block OPL 223. We have a 20% funding interest and 18% beneficial interest in this block. Our partners are Total E&P Nigeria Limited (18% and Operator), ChevronTexaco Nigeria Deepwater F Limited (27%), Esso Exploration and Production (Upstream) Limited (27%) and Nigerian Petroleum Development Company Limited (10% carried interest). During 2009, we plan to advance evaluation of the prospects on this block.
Other International also includes our producing assets in Colombia and our exploration program in the Norwegian North Sea.
United States
Development of Longhorn continues to progress with first production expected in mid 2009. This development comprises four sub-sea wells tied in to the ENI operated Corral Platform, previously known as the Crystal Platform. We expect peak production rates in excess of 200 mmcf/d gross (50 mmcf/d net to us) by year end. In 2008, we invested $87 million developing Longhorn and to date have recognized 13 million boe of proved plus probable reserves here. We have a 25% non-operated working interest in Longhorn and ENI is the operator.
In 2008, our exploration program primarily focused on the deep-water. In the Eastern Gulf of Mexico, we drilled the Fredericksburg exploration well. Target sands were reached but we did not encounter commercial hydrocarbons. This was the third prospect to be drilled in the area following earlier successes at Vicksburg and Shiloh. We remain optimistic about the potential of this emerging play and expect to drill up to two exploration wells and one appraisal well in the area in 2009. In addition, we have a feasibility study underway to assess development options for Vicksburg. We have a 25% interest in Vicksburg and a 20% interest in Shiloh with Shell operating both.
At our Cote de Mer prospect, located on the Louisiana coast, exploratory drilling was interrupted by hurricanes Gustav and Ike. Following successful pipe recovery operations, the well was sidetracked to a depth of 21,700 feet, and penetrated the target zone. We continue to be encouraged by the logging data received to date, and are attempting to drill the remaining 600 feet of the target interval. We have a 37.5% working interest in this prospect.
In 2008, we invested $164 million to add production volumes from the Green Canyon 6 area and to recomplete wells on our producing properties.
Canada
As conventional basins in Canada mature, we are focusing our investment on unconventional resource plays such as shale gas and CBM. In northeast British Columbia, we have a material land position of approximately 126,000 acres with a 100% working interest in an emerging Devonian shale gas play. This play has the potential to be one of the most significant shale gas plays in North America. Our landholdings include approximately 88,000 acres in the Dilly Creek area of the Horn River basin. In 2008, we invested approximately $180 million to drill, complete and test wells, and build infrastructure. One horizontal well was completed and tied in last winter and is producing at rates in line with our expectations and competitor wells. We expect to complete and tie-in two wells later this winter. We continue to construct all season roads to provide year-round access to our lands. In 2009, we plan to enhance our understanding of optimal drilling and fracing techniques for this play with an investment plan that includes drilling and testing multiple wells from a single pad. We expect three of these wells to be drilled and completed by mid year and on production before winter. The remaining wells will be drilled later subject to favorable economic and financial conditions. As previously announced, we estimate our Dilly Creek lands contain between 3 and 6 trillion cubic feet (0.5 to 1.0 billion barrels of oil equivalent) of recoverable contingent resource. Further appraisal activity is required before we can finalize these estimates, establish commerciality and book reserves.
"We are encouraged by the manner in which Horn River development is progressing," said Romanow. "By working together with our peers on the construction of roads, pipelines and processing facilities, we are achieving economies of scale and reducing our environmental footprint."
In 2008, we invested approximately $115 million in exploration and development activities on our CBM lands and recognized 10 million boe of proved reserves. To date, we have recognized approximately 40 million boe of proved plus probable CBM reserves. 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. Our CBM production continues to increase as existing wells dewater and we bring new ones on stream. In 2008, our production increased 65% and we exited the year producing approximately 50 mmcf/d. Performance is in line with expectations and underscores the increasing value of our CBM assets.
Elsewhere in Canada, we increased our proved reserves by 3 million boe but these additions were offset by negative economic revisions of 27 million boe largely relating to our conventional heavy oil properties. These economic revisions were determined in accordance with SEC rules that require the use of year-end commodity prices and operating costs even though we believe year-end operating costs do not reflect the current economic downturn and low commodity price environment.
"With conventional basins declining in Canada, we have allocated approximately 80% of our Canadian capital investment, excluding oil sands, to our unconventional resource plays such as shale gas and CBM," commented Romanow. "Our strategy is to move early and we have built material land positions that would be difficult to replicate today. We believe the resource potential on our lands is significant. For example, shale gas alone could potentially double our proved reserves."
Insitu Oil Sands - Long Lake
In 2008, we invested a total of $1.0 billion to develop our insitu oil sands resource. This included approximately $847 million on the first phase of Long Lake, $425 million of which related to the upgrader. At Long Lake, we added 19 million bbls of proved bitumen reserves based on further core-hole delineation of the lease. We also added 216 million bbls of probable bitumen reserves associated with delineation work relating to Phase 2 which we believe has substantial long-term value given the margin advantage our technology provides.
In late January 2009, we completed the acquisition of an additional 15% interest in the Long Lake project and the joint venture lands from OPTI Canada Inc. for $735 million. We also became sole operator of the resource and upgrader. We expect this will create operational efficiencies and reduce the cost of managing Long Lake. We now own 65% of the Long Lake project and joint venture lands. With the completion of this acquisition, our total company proved reserves have increased by approximately 9%. These additions will be booked in 2009.
"We are delighted with this transaction," stated Romanow. "We were able to increase our interest in a world-class asset that we know and understand well, and we were able to do this at less than sunk cost. This acquisition is a great example of how we are able to use our strong financial position to take advantage of opportunities to generate shareholder value."
We recently reached a significant milestone at Long Lake when we produced first Premium Synthetic Crude (PSC(TM)) from the upgrader. The main process units in the upgrader have been successfully started up and are operating. Syngas from the upgrader is being used in SAGD operations and this has significantly reduced the need for purchased natural gas. Currently, we are producing between 10,000 and 15,000 bbls/d gross of upgraded on-spec product. The upgrader is expected to ramp up to full design rates of approximately 60,000 bbls/d (39,000 bbls/d net to us) over the next 12 to 18 months. As the upgrader ramps up to full capacity, we expect that there will be periods of downtime as we work through the early stages of production. This periodic downtime is normal and consistent with industry experience.
"We are very pleased to have Long Lake on stream," said Romanow. "The production of first synthetic crude proves our technology works. The upgrader is consistently operating at expected start-up rates, producing on-spec premium synthetic crude oil and generating syngas which we are using in our integrated operations for SAGD and hydrogen production. As production volumes ramp up, we will begin to see our $10/bbl cost advantage materialize. This is a world-class facility that we expect will provide steady and predictable production and cash flow for the next 40 years."
On the bitumen front, the reservoir is performing well but our overall ramp up has been affected by a variety of surface issues that have limited the amount of steam we have been able to inject into the reservoir over the past few months. Since steam injection rates directly impact bitumen production rates, when our ability to generate steam is limited, our bitumen production is lower. Most recently, our SAGD production stalled as a result of power disruptions, extreme cold weather and water treating issues. As we recover from power disruptions and cold weather, our production rates have increased. We are currently producing 20,000 bbls/d gross, the highest we have seen to date. With respect to water treating issues, we are working on solutions to get more heat into the front end of the water treating process to supplement the heat returns from the reservoir. Given steaming constraints, we have been forced to allocate our steam and accordingly we have 32 of the 81 well pairs on production. On average, these well pairs are producing at approximately 75% of their design rates after 11 months of SAGD operation. This is inline with expectations, as we expected a ramp up period of 12 to 18 months. The average steam to oil ratio (SOR) for these wells is currently less than 4.0. As we increase our steam capacity, we will bring on all remaining wells.
Phase 1 of Long Lake will develop approximately 10% of our oil sands inventory. The sanctioning of Phase 2 will depend on multiple factors including the initial performance of Phase 1, receiving regulatory approval for Phase 2 SAGD operations, receiving clarity on proposed climate change regulations, finalizing cost estimates and an improved economic environment. We therefore do not expect to sanction Phase 2 until mid 2010 at the earliest. In 2009, we plan to advance detailed engineering on the SAGD and upgrader facilities for Phase 2 of Long Lake and conduct core hole drilling to further delineate our leases.
Syncrude
At Syncrude, we invested $55 million in 2008 and converted 8 million boe of probable reserves to proved reserves. In 2009, we have one coker turnaround scheduled in the second quarter and expect annual production of between 20,000 and 25,000 bbls/d before royalties.
Quarterly Dividend
During 2008, we doubled our quarterly dividend to shareholders from $0.025 to $0.05 per common share. The Board of Directors has declared the regular quarterly dividend of $0.05 per common share payable April 1, 2009, to shareholders of record on March 10, 2009. Shareholders are advised that the dividend is an eligible dividend for Canadian Income Tax purposes.
Nexen Inc. is an independent, Canadian-based global energy company, listed on the Toronto and New York stock exchanges under the symbol NXY. We are uniquely positioned for growth in the North Sea, Western Canada (including the Athabasca oil sands of Alberta and unconventional gas resource plays such as coalbed methane and shale gas), deep-water Gulf of Mexico, offshore West Africa and the Middle East. We add value for shareholders through successful full-cycle oil and gas exploration and development and leadership in ethics, integrity, governance and environmental protection.
Conference Call
Marvin Romanow, President and CEO, and Kevin Reinhart, Senior 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 12, 2009
Time: 7:00 a.m. Mountain Time (9:00 a.m. Eastern Time)
To listen to the conference call, please call one of the following:
416-641-2140 (Toronto)
800-952-4972 (North American toll-free)
800-6578-9898 (Global toll-free)
A replay of the call will be available for two weeks starting at 9:00 a.m.
Mountain Time, by calling 416-695-5800 (Toronto) or 800-408-3053 (toll-free)
passcode 3280706 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 (together "forward-looking statements") are generally identifiable by the forward-looking terminology used such as "anticipate", "believe", "intend", "plan", "expect", "estimate", "budget", "outlook", "forecast" or other similar words and include statements relating to or associated with individual wells, regions or projects. Any statements as to possible future crude oil, natural gas or chemicals prices, future production levels, future cost recovery oil revenues from our Yemen operations, future capital expenditures and their allocation to exploration and development activities, future earnings, future asset dispositions, future sources of funding for our capital program, future debt levels, availability of committed credit facilities, possible commerciality, development plans or capacity expansions, future ability to execute dispositions of assets or businesses, future cash flows and their uses, future drilling of new wells, ultimate recoverability of current and long-term assets, ultimate recoverability of reserves or resources, expected finding and development costs, expected operating costs, future demand for chemicals products, estimates on a per share basis, sales, future expenditures and future allowances relating to environmental matters and dates by which certain areas will be developed or will come on stream, and changes in any of the foregoing are forward-looking statements. Statements relating to "reserves" or "resources" are forward-looking statements, as they involve the implied assessment, based on estimates and assumptions that the reserves and resources described exist in the quantities predicted or estimated, and can be profitably produced in the future.
The forward-looking statements are subject to known and unknown risks and uncertainties and other factors which may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Such factors include, among others: market prices for oil and gas and chemicals products; our ability to explore, develop, produce, upgrade and transport crude oil and natural gas to markets; the results of exploration and development drilling and related activities; 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 2007 Annual Report on Form 10-K for further discussion of the risk factors.
Cautionary Note to US Investors
The United States Securities and Exchange Commission (SEC) permits oil and gas companies, in their filings with the SEC, to discuss only proved reserves that are supported by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. In this disclosure, we may refer to "recoverable reserves", "probable reserves", "recoverable resources" and "recoverable contingent resources" which are inherently more uncertain than proved reserves. These terms are not used in our filings with the SEC. Our reserves and related performance measures represent our working interest before royalties, unless otherwise indicated. Please refer to our Annual Report on Form 10-K available from us or the SEC for further reserve disclosure.
In addition, under SEC regulations, the Syncrude oil sands operations are considered mining activities rather than oil and gas activities. Production, reserves and related measures in this release include results from the Company's share of Syncrude.
Under SEC regulations, we are required to recognize bitumen reserves rather than the upgraded premium synthetic crude oil we will produce and sell from Long Lake.
Cautionary Note to Canadian Investors
Nexen is an SEC registrant and a voluntary Form 10-K (and related forms) filer. Therefore, our reserves estimates and securities regulatory disclosures follow SEC requirements. In Canada, National Instrument 51-101-Standards of Disclosure for Oil and Gas Activities (NI 51-101) prescribes that Canadian companies follow certain standards for the preparation and disclosure of reserves and related information. Nexen reserves disclosures are made in reliance upon exemptions granted to Nexen by Canadian securities regulators from certain requirements of NI 51-101 which permits us to:
- prepare our reserves estimates and related disclosures in accordance with SEC disclosure requirements, generally accepted industry practices in the US and the standards of the Canadian Oil and Gas Evaluation Handbook (COGE Handbook) modified to reflect SEC requirements;
- substitute those SEC disclosures for much of the annual disclosure required by NI 51-101; and
- rely upon internally-generated reserves estimates and the Standardized Measure of Discounted Future Net Cash Flows and Changes Therein, included in the Supplementary Financial Information, without the requirement to have those estimates evaluated or audited by independent qualified reserves evaluators.
As a result of these exemptions, Nexen's disclosures may differ from other Canadian companies and Canadian investors should note the following fundamental differences in reserves estimates and related disclosures contained herein:
- SEC registrants apply SEC reserves definitions and prepare their proved reserves estimates in accordance with SEC requirements and generally accepted industry practices in the US whereas NI 51-101 requires adherence to the definitions and standards promulgated by the COGE Handbook;
- the SEC mandates disclosure of proved reserves and the Standardized Measure of Discounted Future Net Cash Flows and Changes Therein calculated using year-end constant prices and costs only whereas NI 51-101 requires disclosure of reserves and related future net revenues using forecast prices;
- the SEC mandates disclosure of proved and proved developed reserves by geographic region only whereas NI 51-101 requires disclosure of more reserve categories and product types;
- the SEC does not prescribe the nature of the information required in connection with proved undeveloped reserves and future development costs whereas NI 51-101 requires certain detailed information regarding proved undeveloped reserves, related development plans and future development costs;
- the SEC does not require disclosure of finding and development (F&D) costs per boe of proved reserves additions whereas NI 51-101 requires that various F&D costs per boe be disclosed. NI 51-101 requires that F&D costs be calculated by dividing the aggregate of exploration and development costs incurred in the current year and the change in estimated future development costs relating to proved reserves by the additions to proved reserves in the current year. However, this will generally not reflect full cycle finding and development costs related to reserve additions for the year;
- the SEC leaves the engagement of independent qualified reserves evaluators to the discretion of a company's board of directors whereas NI 51-101 requires issuers to engage such evaluators and to file their reports;
- the SEC does not consider the upgrading component of our integrated oil sands project at Long Lake as an oil and gas activity, and therefore permits recognition of bitumen reserves only. NI 51-101 specifically includes such activity as an oil and gas activity and recognizes synthetic oil as a product type, and therefore permits recognition of synthetic reserves. At year end, we have recognized 285 million barrels before royalties of proved bitumen reserves (282 million barrels after royalties) under SEC requirements, whereas under NI 51-101 we would have recognized 233 million barrels before royalties of proved synthetic reserves (231 million barrels after royalties);
- the SEC considers our Syncrude operation as a mining activity rather than an oil and gas activity, and therefore does not permit related reserves to be included with oil and gas reserves. NI 51-101 specifically includes such activity as an oil and gas activity and recognizes synthetic oil as a product type, and therefore permits them to be included with oil and gas reserves. We have provided a separate table showing our share of the Syncrude proved reserves as well as the additional disclosures relating to mining activities required by SEC requirements; and
- any reserves data in this document reflects our estimates of reserves. While we obtain an independent assessment of a portion of our reserves estimates, no independent qualified reserves evaluator or auditor was involved in the preparation of the reserves data disclosed in this Form 10-K.
The foregoing is a general description of the principal differences only. Please note that the differences between SEC requirements
and NI 51-101 may be material.
NI 51-101 requires that we make the following disclosures:
- we use oil equivalents (boe) to express quantities of natural gas and crude oil in a common unit. A conversion ratio of 6 mcf of natural gas to 1 barrel of oil is used. Boe may be misleading, particularly if used in isolation. The conversion ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead; and
- 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.
Resources
Nexen's estimates of contingent resources are based on definitions set out in the Canadian Oil and Gas Evaluation Handbook which generally describe contingent resources as those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Such contingencies may include, but are not limited to, factors such as economic, legal, environmental, political and regulatory matters or a lack of markets. Specific contingencies precluding these contingent resources being classified as reserves include but are not limited to: future drilling program results, drilling and completions optimization, stakeholder and regulatory approval of future drilling and infrastructure plans, access to required infrastructure, economic fiscal terms, a lower level of delineation, the absence of regulatory approvals, detailed design estimates and near-term development plans, and general uncertainties associated with this early stage of evaluation. The estimated range of contingent resources reflects conservative and optimistic likelihoods of recovery. However, there is no certainty that it will be commercially viable to produce any portion of these contingent resources.
Nexen's estimates of discovered resources (equivalent to discovered petroleum initially-in-place) are based on definitions set out in the Canadian Oil and Gas Evaluation Handbook which generally describe discovered resources as those quantities of petroleum estimated, as of a given date, to be contained in known accumulations prior to production. Discovered resources do not represent recoverable volumes. We disclose additional information regarding resource estimates in accordance with NI 51-101. These disclosures can be found on our website and on SEDAR.
Cautionary statement: In the case of discovered resources or a subcategory of discovered resources other than reserves, there is no certainty that it will be commercially viable to produce any portion of the resources. In the case of undiscovered resources or a subcategory of undiscovered resources, there is no certainty that any portion of the resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the resources.
Nexen Inc.
2008 Reserve Continuity Table
----------------------------------------------------------------------------
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, 2007 41 203 4 38 25 37 56 62 268
Extensions and
Discoveries 1 5 - - - 1 2 6 19
Performance
Revisions 11 17 - - 2 (3) (2) 7 -
Economic
Revisions - (16) - (2) (4) (1) (24) (3) -
Production (22)(4) (37) (1) (2) (3) (5) (6) (8) (2)
------------------------------------------------------
Dec. 31, 2008 31 172 3 34 20 29 26 64 285
------------------------------------------------------
PROBABLE RESERVES (1,2)
Dec. 31, 2007 15 139 5 60 39 21 24 34 523
Extensions,
Discoveries &
Conversions (1) (23) - - - (2) 1 (1) 209
Performance
Revisions - 18 (1) (1) (17) (1) (8) (6) -
Economic
Revisions (1) (2) - 2 (14) (2) (4) (4) -
------------------------------------------------------
Dec. 31, 2008 13 132 4 61 8 16 13 23 732
------------------------------------------------------
PROVED + PROBABLE RESERVES (1,2)
Dec. 31, 2007 56 342 9 98 64 58 80 96 791
Extensions,
Discoveries &
Conversions - (18) - - - (1) 3 5 228
Performance
Revisions 11 35 (1) (1) (15) (4) (10) 1 -
Economic
Revisions (1) (18) - - (18) (3) (28) (7) -
Production (22)(4) (37) (1) (2) (3) (5) (6) (8) (2)
------------------------------------------------------
Dec. 31, 2008 44 304 7 95 28 45 39 87 1,017
------------------------------------------------------
----------------------------------------------------------------------------
Mining Total
Total Oil ------------- Oil, Gas
and Gas Syncrude (3) and Mining
----------------------------------------------------------------------------
PROVED RESERVES (1)
Dec. 31, 2007 734 324 1,058
Extensions and
Discoveries 34 8 42
Performance
Revisions 32 - 32
Economic
Revisions (50) - (50)
Production (86) (8) (94)
-------------------------------------
Dec. 31, 2008 664 324 988
-------------------------------------
PROBABLE RESERVES (1,2)
Dec. 31, 2007 860 46 906
Extensions,
Discoveries &
Conversions 183 - 183
Performance
Revisions (16) - (16)
Economic
Revisions (25) - (25)
-------------------------------------
Dec. 31, 2008 1,002 46 1,048
-------------------------------------
PROVED + PROBABLE RESERVES (1,2)
Dec. 31, 2007 1,594 370 1,964
Extensions,
Discoveries &
Conversions 217 8 225
Performance
Revisions 16 - 16
Economic
Revisions (75) - (75)
Production (86) (8) (94)
-------------------------------------
Dec. 31, 2008 1,666 370 2,036
-------------------------------------
1. We internally evaluate all of our reserves and have at least 80% of our
proved reserves assessed by independent qualified consultants each year;
99% 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 estimated using COGEH standards. US investors
should read the Cautionary Note to US Investors in this release.
3. US investors should read the Cautionary Note to US Investors in 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) 2008 2007 2008 2007
----------------------------------------------------------------------------
Net Sales 1,270 1,597 7,424 5,583
Cash Flow from Operations 559 1,079 4,229 3,458
Per Common Share ($/share) 1.08 2.04 8.04 6.56
Net Income (Loss) (181) 194 1,715 1,086
Per Common Share ($/share) (0.35) 0.37 3.26 2.06
Capital Investment (1) 917 870 3,066 3,401
Net Debt (2) 4,575 4,404 4,575 4,404
Common Shares Outstanding (millions
of shares) 519.4 528.3 519.4 528.3
---------------------------------------
(1) Includes oil and gas development, exploration, and expenditures for
other property, plant and equipment.
(2) Net debt is defined as long-term debt and short-term borrowings less
cash and cash equivalents.
Cash Flow from Operations (1)
Three Months Twelve Months
Ended December 31 Ended December 31
(Cdn$ millions) 2008 2007 2008 2007
----------------------------------------------------------------------------
Oil & Gas and Syncrude
United Kingdom 451 685 3,308 2,101
Yemen (2) 95 153 638 664
Canada 45 49 389 179
United States 103 125 508 480
Other Countries 25 26 133 87
Marketing (140) 9 (356) 73
Syncrude 50 90 400 319
---------------------------------------
629 1,137 5,020 3,903
Chemicals 25 28 85 90
---------------------------------------
654 1,165 5,105 3,993
Interest and Other Corporate Items (89) (74) (292) (350)
Income Taxes (3) (6) (12) (584) (185)
---------------------------------------
Cash Flow from Operations (1) 559 1,079 4,229 3,458
---------------------------------------
---------------------------------------
(1) Defined as cash flow from operating activities before changes in
non-cash working capital and other. We evaluate our performance and that
of our business segments based on earnings and cash flow from
operations. Cash flow from operations is a non-GAAP term that represents
cash generated from operating activities before changes in non-cash
working capital and other and excludes items of a non-recurring nature.
We consider it a key measure as it demonstrates our ability and the
ability of our business segments to generate the cash flow necessary to
fund future growth through capital investment and repay debt. Cash flow
from operations may not be comparable with the calculation of similar
measures for other companies.
Three Months Twelve Months
Ended December 31 Ended December 31
(Cdn$ millions) 2008 2007 2008 2007
----------------------------------------------------------------------------
Cash Flow from Operating Activities 1,055 703 4,354 2,830
Changes in Non-Cash Working Capital (587) 329 (119) 348
Other 97 54 18 307
Amortization of Premium for Crude
Oil Put Options (6) (7) (24) (27)
---------------------------------------
Cash Flow from Operations 559 1,079 4,229 3,458
---------------------------------------
---------------------------------------
Weighted-average Number of Common Shares
Outstanding (millions of shares) 519.5 528.1 526.1 527.1
---------------------------------------
Cash Flow from Operations Per
Common Share ($/share) 1.08 2.04 8.04 6.56
---------------------------------------
---------------------------------------
(2) After in-country cash taxes of $36 million for the three months ended
December 31, 2008 (2007 - $75 million) and $275 million for the year
ended December 31, 2008 (2008 - $249 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
2008 2007 2008 2007
----------------------------------------------------------------------------
Crude Oil and NGLs (mbbls/d)
United Kingdom 92.4 93.4 99.7 81.2
Yemen 52.6 66.2 56.6 71.6
Canada 16.2 16.4 16.2 17.1
United States 3.8 13.9 9.3 16.4
Other Countries 5.8 6.2 5.8 6.2
Long Lake Bitumen 6.6 - 3.9 -
Syncrude (mbbls/d) (2) 22.3 22.6 20.9 22.1
---------------------------------------
199.7 218.7 212.4 214.6
---------------------------------------
Natural Gas (mmcf/d)
United Kingdom 15 19 18 16
Canada 138 124 131 118
United States 31 119 78 101
---------------------------------------
184 262 227 235
---------------------------------------
Total Production (mboe/d) 230 262 250 254
---------------------------------------
---------------------------------------
Production Volumes (after royalties)
Three Months Twelve Months
Ended December 31 Ended December 31
2008 2007 2008 2007
----------------------------------------------------------------------------
Crude Oil and NGLs (mbbls/d)
United Kingdom 92.4 93.3 99.7 81.2
Yemen 31.7 33.8 30.6 39.8
Canada 12.4 12.9 12.3 13.4
United States 3.3 12.2 8.1 14.5
Other Countries 5.4 5.7 5.3 5.7
Long Lake Bitumen 6.5 - 3.9 -
Syncrude (mbbls/d) (2) 20.8 18.7 18.2 18.8
---------------------------------------
172.5 176.6 178.1 173.4
---------------------------------------
Natural Gas (mmcf/d)
United Kingdom 15 19 18 16
Canada 112 105 109 98
United States 26 102 66 86
---------------------------------------
153 226 193 200
---------------------------------------
Total Production (mboe/d) 198 214 210 207
---------------------------------------
---------------------------------------
Notes:
(1) We have presented production volumes before royalties as we measure our
performance on this basis consistent with other Canadian oil and gas
companies.
(2) Considered a mining operation for US reporting purposes.
Nexen Inc.
Oil and Gas Prices and Cash Netback (1)
Total
Quarters - 2008 Year
------------------------------------
(all dollar amounts in Cdn$ unless noted) 1st 2nd 3rd 4th 2008
----------------------------------------------------------------------------
PRICES:
WTI Crude Oil (US$/bbl) 97.90 123.98 117.98 58.73 99.65
Nexen Average - Oil (Cdn$/bbl) 93.00 118.00 115.56 59.90 96.92
NYMEX Natural Gas (US$/mmbtu) 8.75 11.48 8.95 6.41 8.90
Nexen Average - Gas (Cdn$/mcf) 7.97 10.21 8.65 6.34 8.44
----------------------------------------------------------------------------
NETBACKS:
Canada - Heavy Oil
Sales (mbbls/d) 16.2 16.4 16.0 16.2 16.2
Price Received ($/bbl) 65.94 93.16 97.91 41.14 74.51
Royalties & Other 16.65 22.61 24.24 8.81 18.07
Operating Costs 15.76 17.17 16.99 16.69 16.66
----------------------------------------------------------------------------
Netback 33.53 53.38 56.68 15.64 39.78
----------------------------------------------------------------------------
Canada - Natural Gas
Sales (mmcf/d) 127 126 133 138 131
Price Received ($/mcf) 7.57 9.67 8.00 6.06 7.73
Royalties & Other 1.18 1.53 1.52 1.07 1.32
Operating Costs 1.67 1.84 1.84 1.66 1.75
----------------------------------------------------------------------------
Netback 4.72 6.30 4.64 3.33 4.66
----------------------------------------------------------------------------
Yemen
Sales (mbbls/d) 62.5 57.4 54.2 51.7 56.4
Price Received ($/bbl) 96.57 120.39 115.92 64.48 99.87
Royalties & Other 48.07 59.21 52.47 26.33 46.94
Operating Costs 7.76 8.80 7.82 9.80 8.51
In-country Taxes 11.82 17.45 16.11 7.60 13.31
----------------------------------------------------------------------------
Netback 28.92 34.93 39.52 20.75 31.11
----------------------------------------------------------------------------
Syncrude
Sales (mbbls/d) 19.3 19.1 22.9 22.3 20.9
Price Received ($/bbl) 101.70 130.90 126.56 65.48 105.47
Royalties & Other 11.93 22.08 21.89 4.97 15.11
Operating Costs 35.16 45.09 32.40 34.67 36.53
----------------------------------------------------------------------------
Netback 54.61 63.73 72.27 25.84 53.83
----------------------------------------------------------------------------
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
----------------------------------------------------------------------------
(1) Defined as average sales price less royalties and other, operating
costs, and in-country taxes in Yemen.
Nexen Inc.
Oil and Gas Cash Netback (1) (continued)
Total
Quarters - 2008 Year
-----------------------------------------------
(all dollar amounts in Cdn$
unless noted) 1st 2nd 3rd 4th 2008
----------------------------------------------------------------------------
United States
Crude Oil:
Sales (mbbls/d) 13.7 11.3 8.5 3.8 9.3
Price Received ($/bbl) 94.07 120.77 122.46 58.43 104.94
Natural Gas:
Sales (mmcf/d) 112 99 70 31 78
Price Received ($/mcf) 9.03 11.80 10.14 8.09 10.07
Total Sales Volume (mboe/d) 32.4 27.8 20.2 8.9 22.3
Price Received ($/boe) 71.10 91.08 86.75 52.77 79.02
Royalties & Other 9.53 12.88 12.30 7.89 11.03
Operating Costs 8.20 9.28 15.62 21.58 11.57
----------------------------------------------------------------------------
Netback 53.37 68.92 58.83 23.30 56.42
----------------------------------------------------------------------------
United Kingdom
Crude Oil:
Sales (mbbls/d) 108.9 89.0 107.0 96.4 100.3
Price Received ($/bbl) 93.38 118.24 114.89 58.6 96.23
Natural Gas:
Sales (mmcf/d) 22 24 18 16 20
Price Received ($/mcf) 6.82 7.06 7.53 5.44 6.78
Total Sales Volume (mboe/d) 112.6 93.0 110.0 99.0 103.7
Price Received ($/boe) 91.67 114.95 112.99 57.91 94.45
Operating Costs 5.67 7.42 6.71 7.39 6.75
----------------------------------------------------------------------------
Netback 86.00 107.53 106.28 50.52 87.70
----------------------------------------------------------------------------
Other Countries
Sales (mbbls/d) 6.0 5.7 5.7 5.8 5.8
Price Received ($/bbl) 91.85 113.18 120.11 72.43 98.98
Royalties & Other 7.46 8.95 9.42 5.81 7.88
Operating Costs 4.74 4.43 5.14 3.79 4.52
----------------------------------------------------------------------------
Netback 79.65 99.80 105.55 62.83 86.58
----------------------------------------------------------------------------
Company-Wide
Oil and Gas Sales (mboe/d) 270.1 240.4 250.9 226.9 247.0
Price Received ($/boe) 85.90 108.26 106.22 56.94 89.78
Royalties & Other 14.87 19.92 16.98 8.22 15.06
Operating Costs 9.46 11.89 10.90 12.01 11.04
In-country Taxes 2.74 4.16 3.48 1.73 3.04
----------------------------------------------------------------------------
Netback 58.83 72.29 74.86 34.98 60.64
----------------------------------------------------------------------------
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
----------------------------------------------------------------------------
(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
Ended December 31 Ended December 31
(Cdn$ millions, except per share
amounts) 2008 2007 2008 2007
----------------------------------------------------------------------------
Revenues and Other Income
Net Sales 1,270 1,597 7,424 5,583
Marketing and Other (Note 14) 426 249 813 1,021
---------------------------------------
1,696 1,846 8,237 6,604
---------------------------------------
Expenses
Operating 337 303 1,335 1,165
Depreciation, Depletion, Amortization
and Impairment (Note 4) 930 724 2,014 1,767
Transportation and Other 276 214 967 908
General and Administrative 92 127 257 374
Exploration 157 105 402 326
Interest (Note 9) 35 34 94 168
---------------------------------------
1,827 1,507 5,069 4,708
---------------------------------------
Income (Loss) before Provision for
Income Taxes (131) 339 3,168 1,896
---------------------------------------
Provision for Income Taxes
Current 42 87 859 434
Future 15 55 598 358
---------------------------------------
57 142 1,457 792
---------------------------------------
Net Income (Loss) before
Non-Controlling Interests (188) 197 1,711 1,104
Less: Net Income (Loss) Attributable
to Non-Controlling Interests (7) 3 (4) 18
---------------------------------------
Net Income (Loss) (181) 194 1,715 1,086
---------------------------------------
---------------------------------------
Earnings (Loss) Per Common Share
($/share)
Basic (Note 15) (0.35) 0.37 3.26 2.06
---------------------------------------
---------------------------------------
Diluted (Note 15) (0.35) 0.36 3.22 2.02
---------------------------------------
---------------------------------------
See accompanying notes to the Unaudited Consolidated Financial Statements.
Nexen Inc.
Unaudited Consolidated Balance Sheet
December 31 December 31
(Cdn$ millions, except share amounts) 2008 2007
----------------------------------------------------------------------------
Assets
Current Assets
Cash and Cash Equivalents 2,003 206
Restricted Cash 103 203
Accounts Receivable (Note 2) 3,163 3,502
Inventories and Supplies (Note 3) 484 659
Other 169 89
----------------------------
Total Current Assets 5,922 4,659
----------------------------
Property, Plant and Equipment (Note 4)
Net of Accumulated Depreciation, Depletion,
Amortization and Impairment of $10,393
(December 31, 2007 - $7,195) 14,922 12,498
Goodwill 390 326
Future Income Tax Assets 351 268
Deferred Charges and Other Assets (Note 5) 570 324
----------------------------
Total Assets 22,155 18,075
----------------------------
----------------------------
Liabilities and Shareholders' Equity
Current Liabilities
Accounts Payable and Accrued Liabilities
(Note 8) 3,326 4,180
Accrued Interest Payable 67 54
Dividends Payable 26 13
----------------------------
Total Current Liabilities 3,419 4,247
----------------------------
Long-Term Debt (Note 9) 6,578 4,610
Future Income Tax Liabilities 2,619 2,290
Asset Retirement Obligations (Note 11) 1,024 792
Deferred Credits and Other Liabilities (Note 12) 1,324 459
Non-Controlling Interests 52 67
Shareholders' Equity (Note 13)
Common Shares, no par value
Authorized: Unlimited
Outstanding: 2008 - 519,448,590 shares
2007 - 528,304,813 shares 981 917
Contributed Surplus 2 3
Retained Earnings 6,290 4,983
Accumulated Other Comprehensive Loss (134) (293)
----------------------------
Total Shareholders' Equity 7,139 5,610
----------------------------
Commitments, Contingencies and Guarantees (Note 16)
----------------------------
Total Liabilities and Shareholders' Equity 22,155 18,075
----------------------------
----------------------------
See accompanying notes to the Unaudited Consolidated Financial Statements.
Nexen Inc.
Unaudited Consolidated Statement of Cash Flows
For the Three and Twelve Months Ended December 31
Three Months Twelve Months
Ended December 31 Ended December 31
(Cdn$ millions) 2008 2007 2008 2007
----------------------------------------------------------------------------
Operating Activities
Net Income (Loss) (181) 194 1,715 1,086
Charges and Credits to Income not
Involving Cash (Note 17) 589 787 2,136 2,073
Exploration Expense 157 105 402 326
Changes in Non-Cash Working Capital
(Note 17) 587 (329) 119 (348)
Other (97) (54) (18) (307)
---------------------------------------
1,055 703 4,354 2,830
Financing Activities
Proceeds from Long-Term Notes - - - 1,660
Repayment of Medium-Term Notes - - (125) (150)
Proceeds from (Repayment of) Term
Credit Facilities, Net - 70 803 (697)
Proceeds from (Repayment of)
Short-Term Borrowings, Net - 2 (4) (150)
Proceeds from Canexus Notes - - 51 -
Proceeds from (Repayment of) Term
Credit Facilities of Canexus, Net (1) 15 (20) 60
Dividends on Common Shares (26) (14) (92) (53)
Distributions Paid to Non-Controlling
Interests (6) (6) (17) (28)
Issue of Common Shares and Exercise of
Tandem Options for Shares 16 12 64 56
Repurchase of Common Shares for
Cancellation (Note 13) (38) - (338) -
Changes in Non-Cash Working Capital
(Note 17) (10) - - -
Other - - - (21)
---------------------------------------
(65) 79 322 677
Investing Activities
Capital Expenditures
Exploration and Development (831) (823) (2,895) (3,132)
Proved Property Acquisitions (20) (1) (22) (151)
Chemicals, Corporate and Other (66) (46) (149) (118)
Changes in Non-Cash Working Capital
(Note 17) (4) 119 (124) 130
Changes in Restricted Cash (37) 5 106 (16)
Other (44) 21 (105) 6
---------------------------------------
(1,002) (725) (3,189) (3,281)
Effect of Exchange Rate Changes on
Cash and Cash Equivalents 243 (23) 310 (121)
---------------------------------------
Increase in Cash and Cash Equivalents 231 34 1,797 105
Cash and Cash Equivalents - Beginning
of Period 1,772 172 206 101
---------------------------------------
Cash and Cash Equivalents - End of
Period 2,003 206 2,003 206
---------------------------------------
---------------------------------------
Cash and cash equivalents at December 31, 2008 consists of cash of $355
million and short-term investments of $1,648 million.
See accompanying notes to the Unaudited Consolidated Financial Statements.
Nexen Inc.
Unaudited Consolidated Statement of Shareholders' Equity
For the Three and Twelve Months Ended December 31
Three Months Twelve Months
Ended December 31 Ended December 31
(Cdn$ millions) 2008 2007 2008 2007
----------------------------------------------------------------------------
Common Shares
Balance at Beginning of Period 963 891 917 821
Issue of Common Shares 9 4 41 32
Exercise of Tandem Options for Shares 7 8 23 24
Accrued Liability Relating to Tandem
Options Exercised for Common Shares 6 14 22 40
Repurchased under Normal Course Issuer
Bid (Note 13) (4) - (22) -
---------------------------------------
Balance at End of Period 981 917 981 917
---------------------------------------
---------------------------------------
Contributed Surplus
Balance at Beginning of Period 2 3 3 4
Stock-Based Compensation Expense - - - 1
Exercise of Tandem Options - - (1) (2)
---------------------------------------
Balance at End of Period 2 3 2 3
---------------------------------------
---------------------------------------
Retained Earnings
Balance at Beginning of Period 6,531 4,825 4,983 3,972
Net Income (Loss) (181) 194 1,715 1,086
Dividends on Common Shares (Note 13) (26) (14) (92) (53)
Transition Adjustment on Adoption of
New Inventory Standard - (22) - (22)
Repurchase of Common Shares for
Cancellation (Note 13) (34) - (316) -
---------------------------------------
Balance at End of Period 6,290 4,983 6,290 4,983
---------------------------------------
---------------------------------------
Accumulated Other Comprehensive Loss
Balance at Beginning of Period (233) (304) (293) (161)
Opening Derivatives Designated as
Cash Flow Hedges - - - 61
Other Comprehensive Income (Loss) 99 11 159 (193)
---------------------------------------
Balance at End of Period (134) (293) (134) (293)
---------------------------------------
---------------------------------------
Nexen Inc.
Unaudited Consolidated Statement of Comprehensive Income (Loss)
For the Three and Twelve Months Ended December 31
Three Months Twelve Months
Ended December 31 Ended December 31
(Cdn$ millions) 2008 2007 2008 2007
----------------------------------------------------------------------------
Net Income (Loss) (181) 194 1,715 1,086
Other Comprehensive Income (Loss), Net
of Income Taxes:
Foreign Currency Translation Adjustment:
Net Gains (Losses) on Investment in
Self-Sustaining Foreign Operations 863 (45) 1,228 (867)
Net Gains (Losses) on Debt Hedges of
Self-Sustaining Foreign
Operations (1) (757) 59 (1,062) 738
Realized Translation Adjustments
Recognized in Net Income (Loss) (7) (3) (7) (3)
Cash Flow Hedges:
Realized Mark-to-Market Gains
Recognized in Net Income (Loss) - - - (61)
---------------------------------------
Other Comprehensive Income (Loss) 99 11 159 (193)
---------------------------------------
Comprehensive Income (Loss) (82) 205 1,874 893
---------------------------------------
---------------------------------------
(1) Net of income tax recovery for the three months ended December 31, 2008
of $100 million (2007 - $16 million) and for the twelve months ended
December 31, 2008 of $145 million (2007 - $97 million expense).
See accompanying notes to the Unaudited Consolidated Financial Statements.
Nexen Inc.
Notes to Unaudited Consolidated Financial Statements
Cdn$ 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, 2008 and 2007 and the results of our operations and our cash flows for the three and twelve months ended December 31, 2008 and 2007.
We make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the Unaudited Consolidated Financial Statements, and revenues and expenses during the reporting period. Our management reviews these estimates on an ongoing basis, including those related to accruals, litigation, environmental and asset retirement obligations, recoverability of assets, income taxes, fair values of derivative assets and liabilities, capital adequacy and determination of proved reserves. 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 2007 Annual Report on Form 10-K. Except as described below, the accounting policies we follow are described in Note 1 of the Audited Consolidated Financial Statements included in our 2007 Annual Report on Form 10-K.
Change in Accounting Policies
Capital Disclosures
On January 1, 2008, we prospectively adopted CICA Section 1535 Capital Disclosures issued by the AcSB. This Section establishes standards for disclosing information about an entity's objectives, policies and processes for managing its capital structure. The disclosures have been included in Note 10.
Financial Instruments Disclosures and Presentation
On January 1, 2008, we prospectively adopted the following new standards issued by the AcSB: Financial Instruments - Disclosure (Section 3862) and Financial Instruments - Presentation (Section 3863). These accounting standards replaced Financial Instruments - Disclosure and Presentation (Section 3861). The disclosures required by Section 3862 and 3863 provide additional information on the risks associated with our financial instruments and how we manage those risks. The additional disclosures required by these standards are provided in Notes 6 and 7.
New Accounting Pronouncements
In February 2008, the AcSB confirmed that all Canadian publicly accountable enterprises will be required to adopt International Financial Reporting Standards (IFRS) for interim and annual reporting purposes for fiscal years beginning on or after January 1, 2011. We are currently assessing the impact of the convergence of Canadian GAAP with IFRS on our results of operations, financial position and disclosures. A project team has been set up to manage this transition and to ensure successful implementation within the required timeframe.
In February 2008, the AcSB issued Section 3064, Goodwill and Intangible Assets and amended Section 1000, Financial Statement Concepts clarifying the criteria for recognizing assets, intangible assets and internally developed intangible assets. Items that no longer meet the definition of an asset are no longer recognized with assets. The standard is effective for fiscal years beginning on or after October 1, 2008 and early adoption is permitted. We do not expect the adoption of this section to have a material impact on our results of operations or financial position.
In January 2009, the AcSB issued Section 1582, Business Combinations, which replaces former guidance on business combinations. Section 1582 establishes principles and requirements of the acquisition method for business combinations and related disclosures. This statement applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after January 2011 with earlier application permitted. We plan to adopt this standard prospectively effective January 1, 2009 and do not expect the adoption of this statement to have a material impact on our results of operations or financial position.
In January 2009, the AcSB issued Sections 1601, Consolidated Financial Statements, and 1602, Non-controlling Interests, which replaces existing guidance. Section 1601 establishes standards for the preparation of consolidated financial statements. Section1602 provides guidance on accounting for a non-controlling interest in a subsidiary in consolidated financial statements subsequent to a business combination. These standards are effective on or after the beginning of the first annual reporting period beginning on or after January 2011 with earlier application permitted. We plan to adopt these standards effective January 1, 2009 and do not expect the adoption will have a material impact on our results of operations or financial position.
2. ACCOUNTS RECEIVABLE
December 31 December 31
2008 2007
----------------------------------------------------------------------------
Trade
Energy Marketing 2,256 2,501
Oil and Gas 639 819
Chemicals and Other 68 60
----------------------------
2,963 3,380
Non-Trade 270 132
----------------------------
3,233 3,512
Allowance for Doubtful Receivables (70) (10)
----------------------------
Total 3,163 3,502
----------------------------
----------------------------
3. INVENTORIES AND SUPPLIES
December 31 December 31
2008 2007
----------------------------------------------------------------------------
Finished Products
Energy Marketing 384 577
Oil and Gas 17 14
Chemicals and Other 16 13
----------------------------
417 604
Work in Process 6 3
Field Supplies 61 52
----------------------------
Total 484 659
----------------------------
----------------------------
4. PROPERTY PLANT AND EQUIPMENT
Depreciation, Depletion, Amortization and Impairment
In the fourth quarter of 2008, our DD&A expense includes $568 million of impairment expense relating to oil and gas properties in the Gulf of Mexico and North Sea. These properties were written down to their estimated fair value based on their estimated total future discounted net cash flows.
In the Gulf of Mexico, we reduced the carrying value of four shelf properties by $143 million, primarily as a result of low oil and gas prices and higher estimated asset remediation costs. These late-life, mature properties have a shorter production horizon, and therefore are sensitive to near-term commodity prices and to higher abandonment costs. Inflationary pressures in the oil and gas industry increased the estimated future costs to remediate the assets. At Green Canyon 6, we reduced the carrying value of our assets by $107 million to reflect the impact of Hurricane Ike which destroyed a third-party production platform in the third quarter of 2008. This resulted in unexpected and uninsured costs to rebuild facilities.
In the North Sea, we reduced the carrying value of our Ettrick project by $256 million, primarily due to higher costs and lower reserve estimates following drilling and testing activities. We also expensed costs of $62 million related to our Selkirk discovery as we currently have no firm plans to continue with development.
In 2007, our fourth quarter DD&A expense includes $366 million of impairment expense primarily related to our Aspen, Vermilion 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 investment in development drilling resulted in negative reserve revisions. At Vermilion 320/340 and West Cameron 170, negative reserve revisions primarily related 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 estimated fair value equal to estimated total future discounted net cash flows.
Suspended Exploration Well Costs
The following table shows the changes in capitalized exploratory well costs during the years ended December 31, 2008 and 2007, and does not include amounts that were initially capitalized and subsequently expensed in the same period.
Twelve Months Twelve Months
Ended December 31 Ended December 31
2008 2007
----------------------------------------------------------------------------
Balance at Beginning of Period 326 226
Exploratory Well Costs Capitalized
Pending the Determination of Proved
Reserves 254 215
Capitalized Exploratory Well Costs
Charged to Expense (81) (10)
Transfers to Wells, Facilities and
Equipment Based on Determination of
Proved Reserves (29) (74)
Effects of Foreign Exchange
Rate Changes 48 (31)
--------------------------------------
End of Period 518 326
--------------------------------------
--------------------------------------
The following table provides an aging of capitalized exploratory well costs based on the date drilling was completed and shows the number of projects for which exploratory well costs have been capitalized for a period greater than one year after the completion of drilling.
December 31 December 31
2008 2007
----------------------------------------------------------------------------
Capitalized for a Period of One Year or Less 239 202
Capitalized for a Period of Greater than One Year 279 124
---------------------------
Total 518 326
---------------------------
---------------------------
Number of Projects with Exploratory Well
Costs Capitalized for a Period Greater than
One Year 7 5
---------------------------
As at December 31, 2008, we have exploratory costs that have been capitalized for more than one year relating to our interests in two exploratory blocks in the Gulf of Mexico ($120 million), our coalbed methane exploratory activities in Canada ($70 million), three exploratory blocks in the North Sea ($67 million) and our interest in an exploratory block offshore Nigeria ($22 million). These costs relate to projects with 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.
5. DEFERRED CHARGES AND OTHER ASSETS
December 31 December 31
2008 2007
----------------------------------------------------------------------------
Crude Oil Put Options and Natural Gas Swaps
(Note 6b) 234 1
Long-Term Energy Marketing Derivative Contracts
(Note 6a) 217 248
Long-Term Capital Prepayments 61 9
Asset Retirement Remediation Fund 9 13
Other 49 53
----------------------------
Total 570 324
----------------------------
----------------------------
6. FINANCIAL INSTRUMENTS
Financial instruments carried at fair value on our balance sheet include cash and cash equivalents, restricted cash and derivatives used for trading and non-trading purposes. Our other financial instruments including accounts receivable, accounts payable, income taxes payable, accrued interest payable, dividends payable, short-term borrowings and long-term debt are carried at cost or amortized cost. The carrying value of our short-term receivables and payables approximates their fair value because the instruments are near maturity.
In our energy marketing group, we enter into contracts to purchase and sell crude oil, natural gas and other energy commodities, and use derivative contracts, including futures, forwards, swaps and options, for hedging and trading purposes (collectively derivatives). We also use derivatives to manage commodity price risk and foreign currency risk for non-trading purposes. We categorize our derivative instruments as trading or non-trading activities and carry the instruments at fair value on our balance sheet. The fair values are included with amounts receivable or payable and are classified as long-term or short-term based on anticipated settlement date. Any change in fair value is included in marketing and other income.
We carry our long-term debt at amortized cost using the effective interest rate method. At December 31, 2008, the estimated fair value of our long-term debt was $5,686 million (December 31, 2007 - $4,692 million) as compared to the carrying value of $6,578 million (December 31, 2007 - $4,610 million). The fair value of long-term debt is estimated based on prices provided by quoted markets and third-party brokers. The recent economic crisis impacted market prices for corporate bonds and as a result, the estimated fair value of our long-term debt was lower in the fourth quarter of 2008.
Derivatives
(a) Total carrying value of derivative contracts related to trading activities
The fair value and carrying amounts related to derivative instruments held by our energy marketing operations are as follows:
December 31 December 31
2008 2007
----------------------------------------------------------------------------
Accounts Receivable 755 334
Deferred Charges and Other Assets (1) 217 248
----------------------------
Total Trading Derivative Assets 972 582
----------------------------
----------------------------
Accounts Payable and Accrued Liabilities 615 413
Deferred Credits and Other Liabilities (1) 294 163
----------------------------
Total Trading Derivative Liabilities 909 576
----------------------------
----------------------------
Total Net Trading Derivative Assets (2) 63 6
----------------------------
----------------------------
(1) These derivative contracts settle beyond 12 months and are considered
non-current.
(2) Comprised of $122 million (2007 - $15 million) related to commodity
contracts and net losses of $59 million (2007 - $9 million loss)
related to US-dollar and Euro forward contracts and swaps.
(b) Total carrying value of derivative contracts related to non-trading
activities
The fair value and carrying amounts related to derivative instruments
related to non-trading activities are as follows:
December 31 December 31
2008 2007
----------------------------------------------------------------------------
Accounts Receivable 6 -
Deferred Charges and Other Assets (1) 234 1
----------------------------
Total Non-Trading Derivative Assets 240 1
----------------------------
----------------------------
Accounts Payable and Accrued Liabilities 21 28
Deferred Credits and Other Liabilities (1) 26 51
----------------------------
Total Non-Trading Derivative Liabilities 47 79
----------------------------
----------------------------
Total Net Non-Trading Derivative Assets
(Liabilities) 193 (78)
----------------------------
----------------------------
(1) These derivative contracts settle beyond 12 months and are considered
non-current.
Crude oil put options
In 2008, we purchased put options on approximately 70,000 bbls/d of our 2009 crude oil production for $14 million. These options establish an annual average Dated Brent floor price of US$60/bbl on these volumes. In September 2008, Lehman Brothers filed for bankruptcy protection. This impacts 25,000 bbls/d of our 2009 put options and the carrying value of these put options has been reduced to nil.
In 2007, we purchased put options on approximately 100,000 bbls/d of our 2008 crude oil production for $24 million. These options established an annual average Dated Brent floor price of US$50/bbl on these volumes. These put options expired out of the money.
The crude oil put options are carried at fair value and are classified as long-term or short-term based on their anticipated settlement date. Fair value of the put options is supported by multiple quotes obtained from third party brokers, which were validated with observable market data to the extent possible. Any change in fair value is included in marketing and other income.
Notional Average Fair
Volumes Term Floor Price Value
----------------------------------------------------------------------------
(bbls/d) (US$/bbl) (Cdn$ millions)
Dated Brent Crude Oil
Put Options 45,000 2009 60 233
Dated Brent Crude Oil
Put Options 25,000 2009 60 -
----------------
233
----------------
----------------
Fixed-price natural gas contracts and natural gas swaps
We have fixed-price natural gas sales contracts and offsetting natural gas
swaps that are not part of our trading activities. These sales contracts
and swaps are carried at fair value and are classified as long-term or
short-term based on their anticipated settlement date. Any change in fair
value is included in marketing and other income.
Notional Average Fair
Volumes Term Price Value
----------------------------------------------------------------------------
(Gj/d) ($/Gj) (Cdn$ millions)
Fixed-Price Natural Gas
Contracts 15,514 2009 2.28 (21)
15,514 2010 2.28 (26)
Natural Gas Swaps 15,514 2009 7.60 6
15,514 2010 7.60 1
------------------------------------------------
(40)
----------------
----------------
(c) Fair value of derivatives
For purposes of estimating the fair value of our derivative contracts, wherever possible, we utilize quoted market prices, and if not available, estimates from third-party brokers. These broker estimates are corroborated with multiple sources and/or other observable market data utilizing assumptions that market participants would use when pricing the asset or liability, including assumptions about risk and market liquidity. Inputs to fair valuations may be readily observable, market-corroborated, or generally unobservable. We utilize valuation techniques that seek to maximize the use of observable inputs and minimize the use of unobservable inputs. To value longer-term transactions and transactions in less active markets for which pricing information is not generally available, unobservable inputs may be used.
As a basis for establishing fair value, we utilize a mid-market pricing convention between bid and ask and then adjust our pricing to the ask price when we have a net short position and the bid price when we have a net long position. This adjustment reflects an estimated exit price and incorporates the impact of liquidity when the bid-ask spread widens in less liquid markets. We incorporate the credit risk associated with counterparty default, as well as our own credit risk, into our estimates of fair value.
We classify the fair value of our derivatives according to the following hierarchy based on the amount of observable inputs used to value the instruments.
- Level 1 - Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 consists of financial instruments such as exchange-traded derivatives and we use information from markets such as the New York Mercantile Exchange.
- Level 2 - Pricing inputs are other than quoted prices in active markets included in Level 1. Prices in Level 2 are either directly or indirectly observable as of the reported date. Level 2 valuations are based on inputs, including quoted forward prices for commodities, time value, volatility factors, and broker quotations, which can be substantially observed or corroborated in the marketplace. Instruments in this category include non-exchange traded derivatives such as over-the-counter physical forwards and options, including those which have prices similar to quoted market prices. We obtain information from sources such as the Natural Gas Exchange, independent price publications and over-the-counter broker quotes.
- Level 3 - Valuations in this level are those with inputs which are less observable, unavailable or where the observable data does not support the majority of the instrument's fair value. Level 3 instruments may include items based on pricing services or broker quotes where we are unable to verify the observability of inputs into their prices. Level 3 instruments include longer-term transactions, transactions in less active markets or transactions at locations for which pricing information is not available. In these instances, internally developed methodologies are used to determine fair value which primarily includes extrapolation of observable future prices to similar locations, similar instruments or later time periods.
The following table includes our derivatives that are carried at fair value for our trading and non-trading activities as at December 31, 2008. Financial assets and liabilities are classified in the fair value hierarchy in their entirety based on the lowest level of input that is significant to the fair value measurement. Assessment of the significance of a particular input to the fair value measurement requires judgment and may affect placement within the fair value hierarchy levels.
Net Derivatives Level 1 Level 2 Level 3 Total
----------------------------------------------------------------------------
Trading Derivatives 13 132 (82) 63
Non-Trading Derivatives - 193 - 193
----------------------------------------
Total 13 325 (82) 256
----------------------------------------
----------------------------------------
A reconciliation of changes in the fair value of our derivatives classified
as Level 3 for the twelve month period ended December 31, 2008 is provided
below:
Level 3
----------------------------------------------------------------------------
Beginning of Period (7)
Realized and unrealized gains (losses) (64)
Purchases, issuances and settlements (9)
Transfers in and/or out of Level 3 (2)
---------
End of Period (82)
---------
---------
Unsettled gains (losses) relating to instruments still
held as of December 31, 2008 16
---------
---------
Items classified in Level 3 are generally economically hedged such that gains or losses on positions classified in Level 3 are often offset by gains or losses on positions classified in Level 1 or 2. Transfers into or out of Level 3 represent existing assets and liabilities that were either previously categorized as a higher level for which the inputs became unobservable or assets and liabilities that were previously classified as Level 3 for which the lowest significant input became observable during the period.
7. RISK MANAGEMENT
(a) Market Risk
We invest in significant capital projects, purchase and sell commodities, issue short-term borrowings and long-term debt and invest in foreign operations. These activities expose us to market risk from changes in commodity prices, foreign currency rates and interest rates, which could affect our earnings and the value of the financial instruments we hold. We use derivatives for trading and non-trading purposes as part of our overall risk management policy to manage these market risk exposures.
The following market risk discussion relates primarily to commodity price risk and foreign currency risk related to our financial instruments as our exposure to interest rate risk is immaterial.
Commodity price risk
We are exposed to commodity price movements as part of our normal oil and gas operations, particularly in relation to the prices received for our crude oil and natural gas. Commodity price risk related to conventional and synthetic crude oil prices is our most significant market risk exposure. Crude oil and natural gas are sensitive to numerous worldwide factors, many of which are beyond our control, and are generally sold at contract or posted prices. Changes in global supply and demand fundamentals in the crude oil market and geopolitical events can significantly affect crude oil prices. Changes in crude oil and natural gas prices may significantly affect our results of operations and cash generated from operating activities. Consequently, these changes also may affect the value of our oil and gas properties, our level of spending for exploration and development, and our ability to meet our obligations as they come due.
The majority of our oil and gas production is sold under short-term contracts, exposing us to the risk of near-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. We actively manage these risks by using derivative contracts such as commodity put options.
Our energy marketing business is focused on providing services to our customers and suppliers to meet their energy commodity needs. We market and trade physical energy commodities in selected regions of the world including crude oil, natural gas, electricity and other commodities. We do this by buying and selling physical commodities, by acquiring and holding rights to physical transportation and storage assets for these commodities, and by building strong relationships with our customers and suppliers.
In order to manage the commodity and foreign exchange price risks that come from this physical business, we use financial derivative contracts including energy-related futures, forwards, swaps and options, as well as currency swaps or forwards.
We also seek to profit from our views on the future movement of energy commodity pricing relationships, primarily between different locations, time periods or qualities. We do this by holding open positions, where the terms of physical or financial contracts are not completely matched to offsetting positions. We may also carry exposures to the absolute change in commodity prices based on our market views or as a consequence of managing our physical and financial positions on a day to day basis.
Our risk management activities make use of tools such as Value at Risk (VaR) and stress testing. VaR is a statistical estimate of the expected profit or loss of a portfolio of positions assuming normal market conditions. We use a 95% confidence interval and an assumed two day holding period in our measure, although actual results can differ from this estimate in non-normal market conditions, or if positions are held longer than two days based on market views or a lack of market liquidity to exit them, which is typical for long-term assets and may apply to nearer term positions. We estimate VaR primarily by using the Variance-Covariance method based on historical commodity price volatility and correlation inputs where available, and by historical simulation in other situations. Our estimate is based upon the following key assumptions:
- changes in commodity prices are either normally or "T" (for natural gas since May 2006) distributed;
- price volatility remains stable; and
- price correlation relationships remain stable.
We have defined VaR limits for different segments of our business. These limits are calculated on an economic basis and include physical and financial derivatives, as well as physical transportation and storage capacity contracts accounted for as executory contracts in our financial statements. We monitor our positions against these VaR limits daily. Our period end, high, low, and average VaR amounts for the three and twelve months ended December 31 are as follows:
Three Months Twelve Months
Ended December 31 Ended December 31
Value-at-Risk (Cdn$ millions) 2008 2007 2008 2007
----------------------------------------------------------------------------
Period End 25 34 25 26
High 30 38 40 38
Low 23 28 19 24
Average 26 33 30 30
----------------------------------------------------------------------------
If market shock occurred as in 2008, the key assumptions underlying our VaR estimate could be exceeded and the potential loss could be greater than our estimate. We perform stress tests on a regular basis to complement VaR and assess the impact of non-normal changes in prices on our positions.
Foreign currency risk
Foreign currency risk is created by fluctuations in the fair values or cash flows of financial instruments due to changes in foreign exchange rates. A substantial portion of our activities are transacted in or referenced to US dollars including:
- sales of crude oil, natural gas and certain chemicals products;
- capital spending and expenses for our oil and gas, Syncrude and chemicals operations;
- commodity derivative contracts used primarily by our energy marketing group; and
- short-term borrowings and long-term debt.
In our oil and gas operations, we manage our exposure to fluctuations between the US and Canadian dollar by maintaining our expected net cash flows and borrowings in the same currency. Cash inflows generated by our foreign operations and borrowings on our US-dollar debt facilities are generally used to fund US-dollar capital expenditures and debt repayments. We maintain revolving Canadian and US-dollar borrowing facilities that can be used or repaid depending on expected net cash flows. We designate most of our US-dollar borrowings as a hedge against our US-dollar net investment in self-sustaining foreign operations. At December 31, 2008, we had US$5,432 million of long-term debt issued in US dollars and a one cent change in the US dollar to Canadian dollar exchange rate would increase or decrease our accumulated other comprehensive income by approximately $52 million, before income tax.
We also have exposures to currencies other than the US dollar including a portion of our UK operating expenses, capital spending and future asset retirement obligations which are denominated in British pounds and Euros. We do not have any material exposure to highly inflationary foreign currencies. In our energy marketing group, we enter into transactions in various currencies including Canadian and US dollars, British pounds and Euros. We actively manage significant currency exposures using forward contracts and swaps.
(b) Credit Risk
Credit risk affects both our trading and non-trading activities and is the risk of loss if counterparties do not fulfill their contractual obligations. Most of our credit exposures are with counterparties in the energy industry, including integrated oil companies, refiners and utilities, and are subject to normal industry credit risk. Approximately 71% of our exposure is with these large energy companies. This concentration of risk within the energy industry is reduced because of our broad base of domestic and international counterparties. We take the following measures to reduce this risk:
- assess the financial strength of our counterparties through a rigorous credit analysis process;
- limit the total exposure extended to individual counterparties, and may require collateral from some counterparties;
- routinely monitor credit risk exposures, including sector, geographic and corporate concentrations of credit, and report these to our Risk Management Committee and the Finance Committee of the board;
- set credit limits based on rating agency credit ratings and internal assessments based on company and industry analysis;
- review counterparty credit limits regularly; and
- use standard agreements that allow for the netting of exposures associated with a single counterparty.
We believe these measures minimize our overall credit risk. However, there can be no assurance that these processes will protect us against all losses from non-performance. During 2008, we have taken the following specific actions for certain counterparties deemed to be at higher risk of non-performance:
- ceased trading activities;
- significantly reduced and, in some cases, revoked credit privileges;
- redirected business to i) exchanges or clearing houses; and ii) entities with physical-based operations;
- increased "set off" arrangements with counterparties; and
- increased collateral and margining requirements where possible.
At December 31, 2008, only one counterparty individually made up more than 10% of our credit exposure. This counterparty is a major integrated oil company with a strong investment grade rating. No other counterparties made up more than 5% of our credit exposure. The following table illustrates the composition of credit exposure by credit rating.
December 31 December 31
Credit Rating 2008 2007
----------------------------------------------------------------------------
A or higher 65% 68%
BBB 29% 27%
Non-Investment Grade 6% 5%
---------------------------
Total 100% 100%
---------------------------
Our maximum counterparty credit exposure at the balance sheet date consists primarily of the carrying amounts of non-derivative financial assets such as accounts receivable, cash and cash equivalents, restricted cash, as well as the fair value of derivative financial assets. In September 2008, Lehman Brothers filed for bankruptcy protection and our exposure at the time was approximately $39 million. This amount was provided for even though we continue to pursue recovery. We also provided an additional $15 million allowance for credit risk with our counterparties during the year. In addition, we incorporate the credit risk associated with counterparty default, as well as Nexen's own credit risk, into our estimates of fair value.
Collateral received from customers at December 31, 2008 includes $90 million of cash and $311 million of letters of credit. The cash received is included in accounts payable and accrued liabilities.
(c) Liquidity Risk
Liquidity risk is the risk that we will not be able to meet our financial obligations as they fall due. We require liquidity specifically to fund capital requirements, satisfy financial obligations as they become due, and to operate in our energy marketing business. We generally rely on operating cash flows to provide liquidity and we also maintain significant undrawn committed credit facilities. At December 31, 2008, we had about $4.5 billion of cash and available committed lines of credit (US$3.7 billion). This includes $2 billion of cash and cash equivalents on hand. Of this amount, approximately US$1 billion was a result of draws made on our term credit facilities, which were used for an internal reorganization and financing of our North Sea assets. In addition, we have undrawn term credit facilities of $2.5 billion (US$2.1 billion), of which $381 million (US$311 million) was supporting letters of credit at December 31, 2008. These facilities are available until 2012. We also have $613 million (US$501 million) of undrawn, uncommitted credit facilities, of which $29 million (US$24 million) was supporting letters of credit at year end. Subsequent to year end, we used $735 million of our available liquidity to acquire an additional 15% interest in the Long Lake Project.
The following table details the contractual maturities for our non-derivative financial liabilities, including both the principal and interest cash flows at December 31, 2008:
less than 1-3 4-5 greater than
Total 1 Year Years Years 5 Years
----------------------------------------------------------------------------
Long-Term Debt 6,652 - 223 1,898 4,531
Interest on
Long-Term Debt (1) 7,611 331 662 657 5,961
---------------------------------------------------------
Total 14,263 331 885 2,555 10,492
---------------------------------------------------------
---------------------------------------------------------
(1) Excludes interest on term credit facilities of $3.7 billion
(US$3.1 billion) and Canexus term credit facilities of $420 million
(US$343 million) as the amounts drawn on the facilities fluctuate.
Based on amounts drawn at December 31, 2008 and existing variable
interest rates, we would be required to pay $19 million per year until
the outstanding amounts on the term credit facilities are repaid.
The following table details contractual maturities for our derivative financial liabilities. The balance sheet amounts for derivative financial liabilities included below are not materially different from the contractual amounts due on maturity.
less than 1-3 4-5 greater than
Total 1 Year Years Years 5 Years
----------------------------------------------------------------------------
Trading Derivatives 909 615 264 25 5
Non-Trading
Derivatives 47 21 26 - -
-------------------------------------------------------
Total 956 636 290 25 5
-------------------------------------------------------
-------------------------------------------------------
The commercial agreements our energy marketing group enters into often include financial assurance provisions that allow us and our counterparties to effectively manage credit risk. The agreements normally require collateral to be posted if an adverse credit-related event occurs, such as a drop in credit ratings to non-investment grade. Based on contracts in place and commodity prices at December 31, 2008, we could be required to post collateral of up to $1.3 billion if we were downgraded to non-investment grade. These obligations are reflected on our balance sheet. The posting of collateral secures the payment of such amounts. In the event of a ratings downgrade, we have trading inventories and receivables that can be quickly monetized as well as significant undrawn credit facilities.
At December 31, 2008, collateral we have posted with counterparties includes $60 million of cash and $194 million of letters of credit related to our trading activities. Cash posted is included with our accounts receivable. Cash collateral is not normally applied to contract settlement. Once a contract has been settled, the collateral amounts are refunded. If there is a default, the cash is retained.
Our exchange-traded derivative contracts are also subject to margin requirements. We have margin deposits of $103 million (December 31, 2007 - $203 million), which have been included in restricted cash.
8. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES
December 31 December 31
2008 2007
----------------------------------------------------------------------------
Accrued Payables 2,033 2,546
Energy Marketing Derivative Contracts (Note 6a) 615 413
Trade Payables 303 578
Stock-based Compensation 97 393
Income Taxes Payable 69 45
Other 209 205
----------------------------
Total 3,326 4,180
----------------------------
----------------------------
9. LONG-TERM DEBT AND SHORT-TERM BORROWINGS
December 31 December 31
2008 2007
----------------------------------------------------------------------------
Medium-Term Notes, due 2008 (a) - 125
Canexus Term Credit Facilities, due 2011
(US$182 million drawn) (b) 223 202
Term Credit Facilities, due 2012
(US$1 billion drawn) (c) 1,225 211
Canexus Notes, due 2013 (US$50 million) (d) 61 -
Notes, due 2013 (US$500 million) 612 494
Notes, due 2015 (US$250 million) 306 247
Notes, due 2017 (US$250 million) 306 247
Notes, due 2028 (US$200 million) 245 198
Notes, due 2032 (US$500 million) 612 494
Notes, due 2035 (US$790 million) 968 781
Notes, due 2037 (US$1,250 million) 1,531 1,235
Subordinated Debentures, due 2043 (US$460 million) 563 454
---------------------------
6,652 4,688
Unamortized Debt Issue Costs (74) (78)
---------------------------
Total 6,578 4,610
---------------------------
---------------------------
(a) Medium-term notes, due 2008
During October 1997, we issued $125 million of notes with interest payable semi-annually at a rate of 6.3%. The principal of $125 million was repaid in full in June 2008.
(b) Canexus term credit facilities
Canexus has $420 million (US$343 million) of committed, secured term credit facilities, available until 2011. At December 31, 2008, $223 million (US$182 million) was drawn on these facilities (2007 - $202 million (US$204 million)). Borrowings are available as Canadian bankers' acceptances, LIBOR-based loans, Canadian prime rate loans or US-dollar base rate loans. Interest is payable monthly at floating rates. The term credit facilities are secured by a floating charge debenture over all of Canexus' assets. The credit facility also contains covenants with respect to certain financial ratios for Canexus. The weighted-average interest rate on the Canexus term credit facilities was 4.2% for the three months ended December 31, 2008 (2007 - 5.9%) and 4.4% for the twelve months ended December 31, 2008 (2007 - 6.1%).
(c) Term credit facilities
We have unsecured term credit facilities of $3.7 billion (US$3.1 billion), available until 2012. At December 31, 2008 $1.2 billion (US$1 billion) was drawn on these facilities (2007 - $211 million (US$214 million)). Borrowings are available as Canadian bankers' acceptances, LIBOR-based loans, Canadian prime rate loans, US-dollar base rate loans or British pound call-rate loans. Interest is payable at floating rates. The weighted-average interest rate on our term credit facilities was 2.1% for the three months ended December 31, 2008 (2007 - 5.5%) and 2.8% for the twelve months ended December 31, 2008 (2007 - 5.8%). At December 31, 2008, $381 million (US$311 million) of these facilities were utilized to support outstanding letters of credit (December 31, 2007 - $283 million (US$286 million).
(d) Canexus notes, due 2013
During the second quarter of 2008, Canexus issued US$50 million of notes. Interest is payable quarterly at a rate of 6.57%, and the principal is to be repaid in May 2013. Canexus may redeem part or all of the notes at any time. The redemption price will be the greater of par and an amount that provides the same yield as a US Treasury security having a term to maturity equal to the remaining term of the notes plus 0.2%.
(e) Short-term borrowings
Nexen has uncommitted, unsecured credit facilities of approximately $613 million (US$501 million), none of which were drawn at December 31, 2008 (2007 - nil). We utilized $29 million (US$24 million) of these facilities to support outstanding letters of credit at December 31, 2008 (December 31, 2007 - $196 million (US$198 million)). Interest is payable at floating rates. The weighted-average interest rate on our short-term borrowings was 2.2% for the three months ended December 31, 2008 (2007 - 5.3%) and 3.2% for the twelve months ended December 31, 2008 (2007 - 5.8%).
(f) Interest expense
Three Months Twelve Months
Ended December 31 Ended December 31
2008 2007 2008 2007
----------------------------------------------------------------------------
Long-Term Debt 95 79 315 323
Other 4 4 19 18
---------------------------------------
99 83 334 341
Less: Capitalized (64) (49) (240) (173)
---------------------------------------
Total 35 34 94 168
---------------------------------------
---------------------------------------
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.
10. CAPITAL DISCLOSURES
Our objective for managing our capital structure is to ensure that we have the financial capacity, liquidity and flexibility to fund our investment in full-cycle exploration and development of conventional and unconventional resources and for energy marketing activities. We generally rely on operating cash flows to fund capital investments. However, given the long cycle-time of some of our development projects which require significant capital investment prior to cash flow generation and volatile commodity prices, it is not unusual for capital expenditures to exceed our cash flow from operating activities in any given period. As such, our financing needs depend on the timing of expected net cash flows in a particular development or commodity cycle. This requires us to maintain financial flexibility and liquidity. Our capital management policies are aimed at:
- maintaining an appropriate balance between short-term borrowings, long-term debt and shareholders' equity;
- maintaining sufficient undrawn committed credit capacity to provide liquidity;
- ensuring ample covenant room permitting us to draw on credit lines as required; and
- ensuring we maintain a credit rating that is appropriate for our circumstances.
We have the ability to make adjustments to our capital structure by issuing additional equity or debt, returning cash to shareholders and making adjustments to our capital investment programs. Our capital consists of shareholders' equity, short-term borrowings, long-term debt, and cash and cash equivalents as follows:
December 31 December 31
Net Debt (1) 2008 2007
----------------------------------------------------------------------------
Long-term Debt 6,578 4,610
Less: Cash and Cash Equivalents (2,003) (206)
----------------------------
Total 4,575 4,404
----------------------------
----------------------------
Shareholders' Equity 7,139 5,610
----------------------------
----------------------------
(1) Includes all of our borrowings and is calculated as long-term debt and
short-term borrowings less cash and cash equivalents.
We monitor the leverage in our capital structure by reviewing the ratio of net debt to cash flow from operating activities and interest coverage ratios at various commodity prices.
We use the ratio of net debt to cash flow from operating activities as a key indicator of our leverage and to monitor the strength of our balance sheet. Net debt is a non-GAAP measure that does not have any standard meaning prescribed by GAAP and is therefore unlikely to be comparable to similar measures presented by others. We calculate net debt using the GAAP measures of long-term debt and short-term borrowings less cash and cash equivalents (excluding restricted cash).
For the twelve months ended December 31, 2008, our net debt to cash flow from operating activities ratio was 1.1 times compared to 1.6 times at December 31, 2007. While we typically expect the target ratio to fluctuate between 1.0 and 2.0 times under normalized commodity prices, this can be higher when we identify strategic opportunities requiring additional investment. Whenever we exceed our target ratio, we develop a strategy to reduce our leverage and lower this ratio back to target levels over time.
Our interest coverage ratio allows us to monitor our ability to fund the interest requirements associated with our debt. Our interest coverage strengthened in 2008 from 12.1 times at the end of 2007 to 15.6 times at December 31, 2008.
Interest coverage is calculated by dividing our twelve-month trailing earnings before interest, taxes, DD&A (EBITDA) by interest expense before capitalized interest. EBITDA is a non-GAAP measure which is calculated using net income excluding interest expense, provision for income taxes, exploration expenses, DD&A, impairment and other non-cash expenses. The calculation of EBITDA is set out in the following table.
Twelve Months Ended Twelve Months Ended
December 31 December 31
2008 2007
----------------------------------------------------------------------------
Net Income 1,715 1,086
Add:
Interest Expense 94 168
Provision for Income Taxes 1,457 792
Depreciation, Depletion,
Amortization and Impairment 2,014 1,767
Exploration Expense 402 326
Recovery of Non-Cash Stock-Based
Compensation (272) (109)
Change in Fair Value of Crude
Oil Put Options (203) 43
Other Non-Cash Expenses (1) 14
-------------------------------------------
EBITDA 5,206 4,087
-------------------------------------------
-------------------------------------------
11. ASSET RETIREMENT OBLIGATIONS
Changes in carrying amounts of the asset retirement obligations associated
with our property, plant and equipment are as follows:
Twelve Months Ended Twelve Months Ended
December 31 December 31
2008 2007
----------------------------------------------------------------------------
Balance at Beginning of Period 832 704
Obligations Incurred with
Development Activities 32 105
Obligations Settled (45) (23)
Accretion Expense 58 44
Revisions to Estimates 159 79
Effects of Changes in Foreign
Exchange Rate 23 (77)
--------------------------------------------
End of Period (1, 2) 1,059 832
--------------------------------------------
--------------------------------------------
(1) Obligations due within 12 months of $35 million (2007 - $40 million)
have been included in accounts payable and accrued liabilities.
(2) Obligations relating to our oil and gas activities amount to $1,009
million (2007 - $786 million) and obligations relating to our chemicals
business amount to $50 million (2007 - $46 million).
Our total estimated undiscounted inflated asset retirement obligations amount to $2,393 million (2007 - $2,165 million). We have discounted the total estimated asset retirement obligations using a weighted-average, credit-adjusted, risk-free rate of 5.9% (2007-5.9%). Approximately $409 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.
12. DEFERRED CREDITS AND OTHER LIABILITIES
December 31 December 31
2008 2007
----------------------------------------------------------------------------
Deferred Tax Credit 709 -
Long-Term Energy Marketing Derivative Contracts
(Note 6a) 294 163
Deferred Transportation Revenue 69 82
Fixed-Price Natural Gas Contracts and Swaps (Note 6b) 26 51
Defined Benefit Pension Obligations 67 57
Capital Lease Obligations 53 52
Other 106 54
----------------------------
Total 1,324 459
----------------------------
----------------------------
During the third quarter of 2008, we completed an internal reorganization and financing of our assets in the North Sea which provided us with an additional one-time tax deduction in the UK. As these transactions were completed within our consolidated group, we are unable to recognize the benefit of the tax deductions until the assets are recognized in income by way of a sale to a third party or depletion through use. Accordingly, we have deferred recognizing $709 million of tax deductions in our unaudited consolidated statement of income.
13. SHAREHOLDERS' EQUITY
(a) Dividends
Dividends per common share for the three months ended December 31, 2008 were $0.05 per common share (2007 - $0.025). Dividends per common share for the twelve months ended December 31, 2008 were $0.18 (2007 - $0.10). Dividends paid to holders of common shares have been designated as "eligible dividends" for Canadian tax purposes.
(b) Normal Course Issuer Bid
In July 2008, we received approval from the Toronto Stock Exchange (TSX) for a Normal Course Issuer Bid to repurchase up to a maximum of 52,914,046 common shares between August 6, 2008 and August 5, 2009. During the three months ended December 31, 2008, we repurchased and cancelled approximately two million common shares acquired on the open market through the TSX at an average price of $17.66 per common share, totaling $38 million. Of the amount paid, $4 million reduced the book value of our common shares and the excess of $34 million reduced retained earnings. During the twelve months ended December 31, 2008, we repurchased and cancelled approximately 12 million common shares acquired on the open market through the TSX at an average price of $27.85 per common share, totaling $338 million. Of the amount paid, $22 million reduced the book value of our common shares and the excess of $316 million reduced retained earnings.
14. MARKETING AND OTHER INCOME
Three Months Twelve Months
Ended December 31 Ended December 31
2008 2007 2008 2007
----------------------------------------------------------------------------
Marketing Revenue, Net 86 209 467 959
Change in Fair Value of Crude Oil
Put Options 204 (12) 203 (43)
Interest 8 10 28 39
Foreign Exchange Gains (Losses) 162 32 128 (22)
Other (34) 10 (13) 88
---------------------------------------
Total 426 249 813 1,021
---------------------------------------
---------------------------------------
15. EARNINGS PER COMMON SHARE
We calculate basic earnings per common share using net income divided by
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) 2008 2007 2008 2007
----------------------------------------------------------------------------
Weighted-average number of
common shares, basic 519.5 528.1 526.1 527.1
Shares issuable pursuant to
tandem options - 21.3 18.8 26.6
Shares to be notionally purchased
from proceeds of tandem options - (12.4) (12.7) (15.7)
---------------------------------------
Weighted-average number of common
shares, diluted 519.5 537.0 532.2 538.0
---------------------------------------
---------------------------------------
In calculating the weighted-average number of diluted common shares outstanding for the three months ended December 31, 2008, all tandem options were excluded because they have an anti-dilutive impact on the loss per share amounts. In calculating the weighted-average number of diluted common shares outstanding for the twelve months ended December 31, 2008, we excluded 5,694,055 tandem options, because their exercise price was greater than the average common share market price in the period. In calculating the weighted-average number of diluted common shares outstanding for the three and 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 the period. During the periods presented, outstanding tandem options were the only potential dilutive instruments.
16. COMMITMENTS, CONTINGENCIES AND GUARANTEES
As described in Note 15 to the Audited Consolidated Financial Statements included in our 2007 10-K, there are a number of lawsuits and claims pending, the ultimate results of which cannot be ascertained at this time. We record costs as they are incurred or become determinable. We believe the resolution of these matters would not have a material adverse effect on our liquidity, consolidated financial position or results of operations.
17. CASH FLOWS
(a) Charges and credits to income not involving cash
Three Months Twelve Months
Ended December 31 Ended December 31
2008 2007 2008 2007
----------------------------------------------------------------------------
Depreciation, Depletion,
Amortization and Impairment 930 724 2,014 1,767
Stock-Based Compensation (62) 23 (272) (109)
Provision for Future Income Taxes 15 55 598 358
Change in Fair Value of Crude Oil
Put Options (204) 12 (203) 43
Net Income (Loss) Attributable to
Non-Controlling Interests (7) 3 (4) 18
Other (83) (30) 3 (4)
---------------------------------------
Total 589 787 2,136 2,073
---------------------------------------
---------------------------------------
(b) Changes in non-cash working capital
Three Months Twelve Months
Ended December 31 Ended December 31
2008 2007 2008 2007
----------------------------------------------------------------------------
Accounts Receivable 1,771 (852) 950 (797)
Inventories and Supplies 374 (118) 246 (97)
Other Current Assets 85 3 5 (15)
Accounts Payable and Accrued
Liabilities (1,657) 771 (1,232) 691
Other - (14) 26 -
---------------------------------------
Total 573 (210) (5) (218)
---------------------------------------
---------------------------------------
Relating to:
Operating Activities 587 (329) 119 (348)
Financing Activities (10) - - -
Investing Activities (4) 119 (124) 130
---------------------------------------
Total 573 (210) (5) (218)
---------------------------------------
---------------------------------------
(c) Other cash flow information
Three Months Twelve Months
Ended December 31 Ended December 31
2008 2007 2008 2007
----------------------------------------------------------------------------
Interest Paid 107 95 319 328
Income Taxes Paid 239 124 1,055 408
---------------------------------------
Cash flow from other operating activities includes cash outflows related to geological and geophysical expenditures of $65 million for the three months ended December 31, 2008 (2007 - $44 million) and $137 million for the twelve months ended December 31, 2008 (2007 - $123 million).
18. SUBSEQUENT EVENT
In January 2009, we completed the acquisition of an additional 15% interest in the Long Lake Project and the joint venture lands for $735 million.
19. OPERATING SEGMENTS AND RELATED INFORMATION
Nexen is involved in activities relating to Oil and Gas, Energy Marketing, Syncrude and Chemicals in various geographic locations as described in Note 20 to the Audited Consolidated Financial Statements included in our 2007 Annual Report on Form 10-K.
Three months ended December 31, 2008
(Cdn$ millions) Oil and Gas
----------------------------------------------------------------------------
United United Other
Yemen Canada States Kingdom Countries(1)
--------------------------------------------------
Net Sales 181 111 147 527 36
Marketing and Other 3 1 - (12) (2)
--------------------------------------------------
Total Revenues 184 112 147 515 34
Less: Expenses
Operating 47 45 17 67 3
Depreciation, Depletion,
Amortization and
Impairment (3) 40 64 283 494 5
Transportation and Other 2 2 1 (2) -
General and
Administrative (4) 2 7 15 (1) (1)
Exploration 3 38 39 44 33(5)
Interest - - - - -
--------------------------------------------------
Income (Loss)
before Income Taxes 90 (44) (208) (87) (6)
Less: Provisions for (Recovery
of) Income Taxes 30 (12) (74) (55) (1)
Less: Non-Controlling
Interests - - - - -
--------------------------------------------------
Net Income (Loss) 60 (32) (134) (32) (5)
--------------------------------------------------
--------------------------------------------------
Identifiable Assets 342 6,643(6) 2,044 6,632 701
--------------------------------------------------
--------------------------------------------------
Capital Expenditures
Development and Other 31 325 71 135 117
Exploration - 79 7 32 18
Proved Property Acquisitions - 20 - - -
--------------------------------------------------
31 424 78 167 135
--------------------------------------------------
--------------------------------------------------
Property, Plant and Equipment
Cost 2,808 8,134 4,398 6,532 554
Less: Accumulated DD&A 2,610 1,786 2,702 2,159 113
--------------------------------------------------
Net Book Value 198 6,348(6) 1,696 4,373 441
--------------------------------------------------
--------------------------------------------------
Corporate
Energy and
(Cdn$ millions) Marketing Syncrude Chemicals Other Total
----------------------------------------------------------------------------
Net Sales 18 124 126 - 1,270
Marketing and Other 86 3 (37) 384 (2) 426
------------------------------------------------------
Total Revenues 104 127 89 384 1,696
Less: Expenses
Operating 10 72 76 - 337
Depreciation, Depletion,
Amortization and
Impairment (3) 8 13 12 11 930
Transportation and Other 231 5 14 23 276
General and
Administrative (4) 16 - 9 45 92
Exploration - - - - 157
Interest - - 4 31 35
------------------------------------------------------
Income (Loss)
before Income Taxes (161) 37 (26) 274 (131)
Less: Provisions for
(Recovery of) Income Taxes (30) 10 (3) 192 57
Less: Non-Controlling
Interests - - (7) - (7)
------------------------------------------------------
Net Income (Loss) (131) 27 (16) 82 (181)
------------------------------------------------------
------------------------------------------------------
Identifiable Assets 3,280(7) 1,198 573 742 22,155
------------------------------------------------------
------------------------------------------------------
Capital Expenditures
Development and Other 5 16 31 30 761
Exploration - - - - 136
Proved Property
Acquisitions - - - - 20
------------------------------------------------------
5 16 31 30 917
------------------------------------------------------
------------------------------------------------------
Property, Plant and
Equipment
Cost 246 1,372 940 331 25,315
Less: Accumulated
DD&A 76 236 507 204 10,393
------------------------------------------------------
Net Book Value 170 1,136 433 127 14,922
------------------------------------------------------
------------------------------------------------------
(1) Includes results of operations from producing activities in Colombia.
(2) Includes interest income of $8 million, foreign exchange gains of $162
million, increase in the fair value of crude oil put options of $204
million and other gains of $10 million.
(3) Includes an impairment charge related to oil and gas properties in the
UK North Sea and the US Gulf of Mexico of $318 million and $250 million
respectively.
(4) Includes recovery of stock-based compensation expense of $39 million.
(5) Includes exploration activities primarily in Norway and Colombia.
(6) Includes costs of $4,742 million related to our in-situ oil sands (Long
Lake and future phases), which are not being depreciated, depleted or
amortized.
(7) 79% of Marketing's identifiable assets are accounts receivable and
inventories.
Twelve months ended December 31, 2008
(Cdn$ millions) Oil and Gas
----------------------------------------------------------------------------
United United Other
Yemen Canada States Kingdom Countries(1)
--------------------------------------------------
Net Sales 1,093 656 665 3,580 192
Marketing and Other 12 3 4 5 -
--------------------------------------------------
Total Revenues 1,105 659 669 3,585 192
Less: Expenses
Operating 176 182 94 253 10
Depreciation, Depletion,
Amortization and
Impairment (3) 160 208 475 999 17
Transportation and Other 9 12 3 19 -
General and Administrative
(4) (7) 20 38 (8) 13
Exploration 5 79 109 86 123(5)
Interest - - - - -
--------------------------------------------------
Income (Loss)
before Income Taxes 762 158 (50) 2,236 29
Less: Provisions for
(Recovery of) Income
Taxes 264 45 (19) 1,126 (4)
Less: Non-Controlling
Interests - - - - -
--------------------------------------------------
Net Income (Loss) 498 113 (31) 1,110 33
--------------------------------------------------
--------------------------------------------------
Identifiable Assets 342 6,643(6) 2,044 6,632 701
--------------------------------------------------
--------------------------------------------------
Capital Expenditures
Development and Other 92 1,180 251 545 190
Exploration 9 225 154 146 48
Proved Property
Acquisition - 22 - - -
--------------------------------------------------
101 1,427 405 691 238
--------------------------------------------------
--------------------------------------------------
Property, Plant and
Equipment
Cost 2,808 8,134 4,398 6,532 554
Less: Accumulated DD&A 2,610 1,786 2,702 2,159 113
--------------------------------------------------
Net Book Value 198 6,348(6) 1,696 4,373 441
--------------------------------------------------
--------------------------------------------------
Corporate
Energy and
(Cdn$ millions) Marketing Syncrude Chemicals Other Total
----------------------------------------------------------------------------
Net Sales 70 691 477 - 7,424
Marketing and Other 467 6 (50) 366(2) 813
------------------------------------------------------
Total Revenues 537 697 427 366 8,237
Less: Expenses
Operating 43 280 297 - 1,335
Depreciation,
Depletion,
Amortization and
Impairment (3) 19 49 44 43 2,014
Transportation and
Other 805 16 55 48 967
General and
Administrative (4) 79 1 33 88 257
Exploration - - - - 402
Interest - - 12 82 94
------------------------------------------------------
Income (Loss)
before Income Taxes (409) 351 (14) 105 3,168
Less: Provisions for
(Recovery of) Income
Taxes (102) 99 2 46 1,457
Less: Non-Controlling
Interests - - (4) - (4)
------------------------------------------------------
Net Income (Loss) (307) 252 (12) 59 1,715
------------------------------------------------------
------------------------------------------------------
Identifiable Assets 3,280(7) 1,198 573 742 22,155
------------------------------------------------------
------------------------------------------------------
Capital Expenditures
Development and Other 8 55 88 53 2,462
Exploration - - - - 582
Proved Property
Acquisition - - - - 22
------------------------------------------------------
8 55 88 53 3,066
------------------------------------------------------
------------------------------------------------------
Property, Plant and
Equipment
Cost 246 1,372 940 331 25,315
Less: Accumulated
DD&A 76 236 507 204 10,393
------------------------------------------------------
Net Book Value 170 1,136 433 127 14,922
------------------------------------------------------
------------------------------------------------------
(1) Includes results of operations from producing activities in Colombia.
(2) Includes interest income of $28 million, foreign exchange gains of $128
million, increase in the fair value of crude oil put options of $203
million and other income of $7 million.
(3) Includes an impairment charge related to oil and gas properties in the
UK North Sea and Gulf of Mexico of $318 million and $250 million
respectively.
(4) Includes recovery of stock based compensation expense of $160 million.
(5) Includes exploration activities primarily in Norway and Colombia.
(6) Includes cost of $4,742 related to our in-situ oil sands (Long Lake and
future phases), which are not being depreciated, depleted or amortized.
(7) 79% of Marketing's identifiable assets are accounts receivable and
inventories.
Three months ended December 31, 2007
(Cdn$ 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 (3) 37 43 429 176 -
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: Provisions 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) 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: Provisions 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 $3,695 million related to our in-situ oil sands (Long
Lake and future phases), which are not being depreciated, depleted or
amortized.
(7) 84% of Marketing's identifiable assets are accounts receivable and
inventories.
Twelve months ended December 31, 2007
(Cdn$ 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 (3) 213 166 641 599 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: Provisions 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
(Cdn$ millions) 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 (3) 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: Provisions 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 in-situ oil sands (Long
Lake and future phases), which are not being depreciated, depleted or
amortized.
(7) 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.
Michael J. Harris, CA
Vice President, Investor Relations
(403) 699-4688
or
Lavonne Zdunich, CA
Analyst, Investor Relations
(403) 699-5821
or
Tim Chatten, P.Eng
Analyst, Investor Relations
(403) 699-4244
or
Nexen Inc.
801 - 7th Ave SW
Calgary, Alberta, Canada T2P 3P7
Website: www.nexeninc.com
