Cash Flow, Production and Cash Netbacks Rise From Q3 2011; Major Projects & Deliverables On-Track
CALGARY, ALBERTA--(Marketwire - Feb. 16, 2012) -
Nexen Inc. (TSX, NYSE: NXY) today reported 2011 fourth quarter and annual operating and financial results, and provided a progress update on its strategic priorities for 2012.
In the fourth quarter, we generated cash flow from operations of $585 million ($1.11/share), reflecting a 12% increase in production over the third quarter to 208,000 boe/d (193,000 boe/d after royalties), and cash netbacks from oil and gas operations of $42.85/boe (after-tax).
Net income was $43 million ($0.08/share), reflecting one-time, after-tax charges of $190 million ($0.36/share) related to previous costs associated with our shift away from large, integrated upgrading projects in our future oil sands development strategy, and $127 million after-tax ($0.24/share) for impairments related to our gas assets in Canada and the United States, due to low gas prices.
For the full year, cash flow was $2.4 billion ($4.49/share), net income was $697 million ($1.32/share) and production averaged 207,000 boe/d (186,000 boe/d after royalties). Cash netbacks from oil and gas operations were $40.20/boe (after-tax) in 2011.
The annual results met our expectations for cash flow ($2.1-$2.8 billion) and our revised expectations for production (200,000-215,000 boe/d). Total 2011 capital expenditures of $2.6 billion were also within our expected range of $2.4-$2.7 billion.
"Nexen delivered solid results in the fourth quarter," said Kevin Reinhart, Nexen's interim President & CEO. "Production met expectations, Long Lake generated positive cash flow, and we entered into two joint ventures in the Gulf of Mexico and shale gas with strong partners.
"I'm pleased with the commitment our employees have made to delivering on our strategic priorities for 2012 and beyond," continued Reinhart. "2012 has started off strong. Long Lake production continues to grow and Buzzard is back to operating normally. We advanced our near term production growth projects including Usan, our UK tiebacks and Long Lake pads 12 and 13. We are also excited about our second drilling success on the Appomattox field in the Gulf of Mexico."
Fourth Quarter Overview
-- Cash flow from operations of $585 million ($1.11/share).
-- Net income of $43 million ($0.08/share); reflects $190 million
($0.36/share) after-tax charge related to future oil sands projects and
$127 million ($0.24/share) of after-tax impairments on gas assets in
Canada and the US.
-- Production of 208,000 boe/d (193,000 boe/d after royalties).
-- Cash netback from oil & gas operations of $42.85/boe, after-tax.
-- Long Lake cash flow of $22 million, driven by higher production and
improving yield; this resulted in positive cash flow of $5 million for
the full year.
-- Buzzard production of 186,000 boe/d (80,000 boe/d net to Nexen).
-- Achieved first production from Blackbird tieback in the UK.
-- Started up our 9-well shale gas pad in northeast British Columbia.
-- $700 million joint venture (JV) agreement on northeast British Columbia
shale gas assets, representing a 60% premium to our invested costs;
closing in the first half of 2012.
-- JV agreement on up to six exploration wells in the Gulf of Mexico; deal
completed on a promoted basis and has closed.
2011 Overview
-- Cash flow from operations of $2.4 billion ($4.49/share).
-- Net income of $697 million ($1.32/share).
-- Production of 207,000 boe/d (186,000 boe/d after royalties).
-- Cash netback from oil & gas operations of $40.20/boe, after-tax.
-- Proved reserve additions replacing 96% of production.
-- Strategic transactions: disposed of our interest in Canexus for $458
million (net) and signed JV agreements in northeast British Columbia and
the Gulf of Mexico.
-- Supported CNOOC Limited's acquisition of our partner at Long Lake, OPTI
Canada; CNOOC brings technical and financial capacity to the
partnership.
-- Continued to reduce net debt using proceeds from non-core asset
dispositions.
-- Sanctioned and began construction on the Golden Eagle and Rochelle
developments in the UK North Sea.
-- Developed and commenced action plan to increase production at Long Lake
to fill the upgrader: ramped-up pad 11, drilled pads 12 and 13 and
progressed regulatory process for pads 14, 15 and Kinosis K1A.
-- Commissioned the fourth platform at Buzzard and it is now operating
normally.
2012 Update
-- On track to meet 2012 first quarter production guidance.
-- At Appomattox, we completed drilling in the northeast fault block of
the structure and have confirmed an oil discovery; this followed a
previous success in the south fault block.
-- Usan project in Nigeria on track for start-up; Usan drives 2012 cash
margin expansion.
-- Long Lake bitumen production as of early February approximately 35,000
bbls/d.
-- Long Lake pad 12 and 13 drilling is complete and results met our
expectations; pad 12 on track for first steam this spring, pad 13 to
follow.
-- Telford TAC tieback in the UK North Sea came on-stream in February.
Results Summary
Three Months Ended Year Ended
----------------------------------------------------------------------------
(Cdn$ millions Dec. 31 Sept. 30 Dec. 31 Dec. 31 Dec. 31
unless noted) 2011 2011 2010 2011 2010
----------------------------------------------------------------------------
Brent
(US$/bbl) 109.31 113.47 86.48 111.28 79.47
WTI (US$/bbl) 94.06 89.76 85.12 95.12 79.52
NYMEX natural
gas
(US$/mmbtu) 3.48 4.06 3.97 4.03 4.39
Cash netback
($/boe)(1) 42.85 38.67 35.87 40.20 33.26
Average Daily
Production
(mboe/d)
Before
Royalties 208 186 246 207 246
After
Royalties 193 164 227 186 220
Cash flow from
operations(2) 585 516 556 2,368 2,150
Per common
share
($/share) 1.11 0.98 1.06 4.49 4.10
Net income 43 200 160 697 1,127
Per common
share
($/share) 0.08 0.38 0.30 1.32 2.15
Capital
investment(3) 817 729 685 2,575 2,724
Net debt(4) 3,538 3,454 4,085 3,538 4,085
-------------------------------------------------------------
1. Cash netback is defined as our corporate average cash netback from oil
and gas operations, after-tax.
2. For reconciliation of this non-GAAP measure, see Cash Flow from
Operations on pg. 13
3. Includes geological and geophysical expenditures.
4. Net debt is defined as long-term debt and short-term borrowings less
cash and cash equivalents.
Fourth quarter cash flow from operations increased 13% over the third quarter primarily due to increased production and our rising cash netbacks. Annual cash flow from operations was the highest since 2008 as our weighting to unhedged, Brent-priced oil allowed us to realize premium pricing throughout the year. Brent averaged US$111 in 2011; this represented a $16 premium to WTI.
Net income declined quarter-over-quarter and year-over-year as a result of several items. It reflects a one-time charge of $190 million (after-tax) related to changes in our future oil sands development strategy. Our original strategy was to build duplicates of the existing Long Lake SAGD facilities and upgrader. We now expect to pursue smaller, phased, SAGD-only projects and will consider adding upgrading capacity once we are bitumen-long and economic conditions are favourable. As a result, previously capitalized design and engineering work done on the future phases has been expensed.
Lower annual net income also reflects impairments, primarily on our gas assets, in the third and fourth quarters of 2011, and gains on the sale of our heavy oil properties which increased net income in the third quarter of 2010.
Net debt has declined 13% in the past year and 36% over the past two years based on the success of our non-core asset disposition program.
Production Summary
Average Daily Quarterly Average Daily Quarterly
Production before Royalties Production after Royalties
Crude Oil, NGLs
and Natural Gas
(mboe/d) Q4 2011 Q3 2011 Q4 2010 Q4 2011 Q3 2011 Q4 2010
----------------------------------------------------------------------------
North Sea 102 71 115 102 71 115
Yemen 27 32 40 16 17 23
United States 18 21 27 18 19 28
Canada - Oil &
Gas 20 19 21 20 17 20
Canada -
Syncrude 18 22 23 16 21 21
Canada - Bitumen 21 19 18 19 17 18
Other Countries 2 2 2 2 2 2
------------------------------------------------------------
Total 208 186 246 193 164 227
------------------------------------------------------------
Fourth quarter production increased 12% over the third quarter, primarily due to higher production from Buzzard and Long Lake.
Reliability at Buzzard significantly improved following completion of the commissioning of the fourth platform; our production efficiency rate was 86%. For 2012, we are targeting 85% before planned shutdowns (78% including scheduled downtime).
In the North Sea, the Blackbird tieback to Ettrick came on-stream in November, seven weeks ahead of schedule, and is currently producing to expectations; production in the fourth quarter was approximately 5,000 boe/d (gross). Severe weather resulted in longer than expected downtime to complete the Telford TAC tieback, which was finished in early February.
Long Lake bitumen production averaged 31,500 bbls/d (gross). This represents a 7% increase over the third quarter as production from the first 11 pads continues to increase and facility turnarounds were completed in the third quarter. At Syncrude, production was lower as a result of unscheduled maintenance on a hydrogen plant.
Production in Yemen and the Gulf of Mexico continued to experience natural declines; Yemen production was further reduced with the expiry of our contract for the Masila block in mid-December.
Annual Production before Annual Production after
Royalties Royalties
Crude Oil, NGLs and
Natural Gas (mboe/d) 2011 2010 2011 2010
----------------------------------------------------------------------------
North Sea 90 111 90 111
Yemen 33 41 18 23
United States 22 27 21 25
Canada - Oil & Gas(1) 20 28 19 25
Canada - Syncrude 21 21 19 19
Canada - Bitumen 19 16 17 15
Other Countries 2 2 2 2
----------------------------------------------------
Total 207 246 186 220
----------------------------------------------------
1. 2010 includes production before royalties of 9 mboe/d and production
after royalties of 7 mboe/d from discontinued operations.
Production in 2011 was lower than 2010, primarily as a result of the sale of our heavy oil properties in the third quarter of 2010, natural declines, and production interruptions at Buzzard due to unplanned maintenance, third-party pipeline restrictions, and delays in commissioning the fourth platform.
We met our revised fourth quarter and annual production guidance.
Average Daily Quarterly Average Daily Annual
Production before Production before
Royalties Royalties
Crude Oil, NGLs and Q4 2011 FY 2011
Natural Gas (mboe/d) (prior Q4 2011 (prior FY 2011
estimate) (actual) estimate) (actual)
----------------------------------------------------------------------------
Buzzard 75 - 95 80 61 - 66 62
Other UK 24 - 32 22 28 - 30 28
Yemen 24 - 33 27 32 - 35 33
United States 21 - 24 18 23 - 24 22
Canada - Oil & Gas 19 - 22 20 20 - 21 20
Canada - Syncrude 20 - 23 18 21 - 22 21
Canada - Bitumen 18 - 24 21 18 - 20 19
Other Countries 2 2 2 2
----------------------------------------------------
Total approx. 200 approx. 200
- 230 208 - 215 207
----------------------------------------------------
----------------------------------------------------
Guidance Update
We are on track to achieve 2012 first quarter production guidance. Year-to-date production volumes are a little over 190,000 boe/d compared to our first quarter guidance range of 180,000-220,000 boe/d.
Buzzard has averaged approximately 185,000 boe/d (gross) so far this year, reflecting our operating efficiency of 85%. At Long Lake, bitumen production has increased to recent 7-day rates of approximately 35,000 bbls/d as pad 11 production continues to grow and we focus on production optimization from all wells.
At Long Lake, we have rescheduled the planned maintenance turnaround to take advantage of better labour availability. As a result, the three-week SAGD turnaround and six-week upgrader outage will now take place in the third quarter; they were previously scheduled for the second quarter. We have updated our second and third quarter guidance to reflect this change in timing.
Estimated Average Daily Production before Royalties
Crude Oil, NGLs and
Natural Gas
(mboe/d) Q1 2012 Q2 2012 Q3 2012 Q4 2012 2012 Annual
----------------------------------------------------------------------------
Buzzard 75-95 75-95 50-60 75-95 70 - 85
Other UK 26-34 26-34 20-26 25-32 24 - 32
Canada - Syncrude 22-24 18-20 22-24 22-24 21 - 23
Canada - Bitumen 20-25 20-27 14-18 22-28 19 - 25
West Africa 0-10 13-30 20-35 22-35 14 - 28
United States 15-20 15-20 13-17 15-17 15 - 19
Canada - Oil & Gas 15-20 15-18 15-17 15-20 15 - 19
Other Countries 2 2 2 2 2
--------------------------------------------------------
approx. approx. approx. approx. approx.
180 - 220 190 - 235 160 - 190 205 - 240 185 - 220
--------------------------------------------------------
--------------------------------------------------------
Operational Update
Conventional
Offshore West Africa - Development of the Usan field remains on schedule; the project is our largest source of new production in 2012 and is expected to contribute to significantly stronger corporate cash netbacks this year. Final commissioning activities are in progress and first production is expected in the next month or two. Development activities were not affected by earlier civil unrest in Nigeria.
Usan's facility capacity is 36,000 bbls/d net to Nexen; actual production rates will vary based on well performance, pace of ramp-up and facility uptime.
"First production from Usan will be a major achievement," commented Reinhart. "The project is our newest legacy asset, and will generate significant cash flow for Nexen for many years. It also significantly strengthens our corporate netback, as the margin it generates is higher than our already strong corporate average."
We expect to drill an exploration well at Owowo West in 2012. This well is targeted to follow-up on our earlier success at Owowo South B.
UK North Sea - Following final regulatory approval of the Golden Eagle development early in the fourth quarter, we began work on the fabrication of the facilities, utilizing many of the same teams that oversaw the successful construction of the Buzzard platforms. The work is proceeding on-time and on-budget, and we expect first production in late 2014. The facility will have a capacity of 70,000 boe/d (26,000 boe/d net to Nexen).
We also continue to progress our tieback projects in the North Sea. Blackbird came on-stream through the Ettrick facility in November and is currently producing to expectations. Telford TAC came on-stream in February; Rochelle is proceeding as planned and first production is expected around the end of 2012.
We have an active UK exploration program planned, including the North Uist exploration well west of the Shetland Islands, where drilling is expected to begin late in the first quarter.
Gulf of Mexico - At Appomattox, we followed-up our successful 2010 exploration well in the south fault block with another success in the northeast fault block. The well encountered approximately 150 feet of net oil pay; we are currently completing an evaluation to determine the size of the discovery. Resource on the northeast block would be in addition to the 65 million boe of probable reserves we booked on the south block.
We plan to continue drilling at Appomattox with an appraisal well on the south fault block and a sidetrack into the northwest fault block to test the third major part of the Appomattox structure. We have a 20% interest in Appomattox, the remaining interest is held by Shell Offshore Inc., who is the operator.
At Kakuna, we expect to reach target depth around the end of the first quarter. We expect to drill our next operated exploration well in the Gulf, at Angel Fire, later this year.
Oil Sands
Long Lake - At Long Lake, our focus is on advancing the 60 additional wells to fill the upgrader.
In the fourth quarter, Long Lake showed strong progress. Total production increased 7% over the prior quarter to 31,500 bbls/d of gross bitumen at a steam oil ratio (SOR) of 4.8.
Upgrader yield (PSC
TM barrels per barrel of bitumen) was 76% and facility on-stream time was 78%. Per barrel operating costs were lower than previous quarters, primarily due to the increased production and the higher yield.
These factors contributed to positive cash flow from operations of $22 million in the quarter and $5 million for the full year.
Long Lake Quarterly Operating Metrics
Bitumen Steam Unit
Production Injection Operating Realized
(Gross) (Gross) Cost(1) Cash Flow Price
(bbls/d) (bbls/d) ($/bbl)($ millions) ($/bbl)
----------------------------------------------------------------------------
2011
Q4 31,500 151,000 67 22 97
Q3 29,500 144,000 85 (4) 94
Q2 27,900 152,000 95 6 109
Q1 25,500 146,000 89 (19) 90
2010
Q4 28,100 158,000 86 (9) 83
Q3 25,700 146,000 85 (42) 71
Q2 24,900 137,000 90 (19) 74
Q1 18,700 114,000 154 (58) 81
------------------------------------------------------------
1. Unit operating costs and realized prices are based on PSC
TM and bitumen volumes sold and exclude activities related to third-party bitumen purchased, processed and sold. Unit operating cost includes energy cost.
Over the past few weeks, production at Long Lake has increased to approximately 35,000 bbls/d. This reflects successful and ongoing well optimization initiatives and the growth in pad 11 production. Pad 11 is currently producing approximately 4,500 bbls/d and is continuing to ramp-up. The expected production range for this pad is 4,000 to 8,000 bbls/d.
We are making steady progress on our plans to fill the upgrader. Drilling has concluded on pads 12 and 13, and well completion activities are underway. We remain on track to begin steaming pad 12 in the spring; pad 13 is expected to follow sometime in the late summer or early fall. Production from both pads is expected before the end of the year. These pads specifically targeted higher-quality resource; our drilling results confirm that the resource quality is as we expected.
The regulatory approvals for pads 14, 15 and K1A are progressing. We are awaiting approvals for one or both projects this spring, which would enable us to begin drilling next winter. These wells have geological characteristics similar to our current best-producing wells.
In aggregate, we anticipate these wells will allow us to fill the upgrader over the next several years:
Number of Wells Expected Rates
bbls/d
----------------------------------------------------------------------------
Pad 11 10 4,000 - 8,000
Pads 12 & 13 18 11,000 - 17,000
Pads 14 & 15 10-12 6,000 - 9,000
Kinosis K1A 25-30 15,000 - 25,000
"I am pleased with the progress we are making on our action plan to fill the upgrader," said Reinhart. "We continue to increase production from our existing wells, and are on track to bring on-stream additional wells in the high-quality resource areas."
We are also continuing work on a non-operated SAGD project at Hangingstone, of which we own 25%. The operator has delayed sanctioning of the project until late this year in order to complete the regulatory approval process. We expect the project to come on-stream in 2016 and our share of production at full rates will be about 6,000 bbls/d.
Shale Gas
Northeast British Columbia - We continued our strong execution on our Horn River shale gas program during the quarter. Our 9-well pad started up ahead of schedule and early production results are meeting expectations. Preliminary results indicate initial rates up to 18 mmcf/d per well. We are currently producing at our facility capacity of 50 mmcf/d.
Work continues on our 18-well pad and we remain on-time and on-budget. We anticipate production from this pad will begin in the fourth quarter, in conjunction with an increase in our facility capacity. This is expected to bring our total gross production capacity to 175 mmcf/d.
Our previously announced JV agreement with INPEX CORPORATION and JGC Corporation is expected to close in the second quarter 2012.
2011 Capital Investment and Reserves
In 2011, we invested $2.5 billion in oil and gas activities and added 73 million boe of proved reserves. These reserve additions replaced 96% of our production. On a proved plus probable basis, reserves increased 8%. Detailed tables outlining changes to reserves can be found on page 12 of this release.
2011 Annual Results
Capital Proved Reserve
Investment Production Additions
($ millions) (mmboe) (mmboe)
----------------------------------------------------------------------------
Conventional Oil & Gas 1,525 59 25
Oil Sands 521 14 18
Shale Gas 470 3 30
---------------------------------------------
Total Oil and Gas 2,516 76 73
---------------------------------------------
---------------------------------------------
The proved reserve additions relate primarily to the following areas:
-- Northeast British Columbia shale gas (30 million boe).
-- Buzzard (15 million boe).
-- Long Lake/Kinosis K1A (10 million boe), reflecting a reduction relating
to the lower resource quality areas on Long Lake (84 million boe) more
than offset by additions from the high-quality resource in the K1A area
(94 million boe).
-- Scott/Telford, including the Telford TAC tieback (9 million boe).
-- Syncrude (8 million boe).
We have 1 billion boe of proved reserves and 2.3 billion boe of proved plus probable reserves, representing reserve life indices of 13 years on a proved basis and 30 years on a proved plus probable basis. As previously disclosed, we also have a large inventory of attractive exploration prospects and billions of barrels of oil equivalent in contingent oil sands and shale gas resources. This provides a significant resource base for future growth.
Update on Executive Appointments
Nexen also announced today that Catherine Hughes, Executive Vice President of International, and Alan O'Brien, Senior Vice President, General Counsel & Secretary, have been confirmed in their current roles; both positions were previously held on an interim basis. Una Power, Nexen's Senior Vice President of Corporate Planning & Business Development, has been appointed interim CFO; she also retains oversight for her previous responsibilities. Biographies of Nexen's senior management team are available at
www.nexeninc.com.
Quarterly Dividend
The Board of Directors has declared the regular quarterly dividend of $0.05 per common share payable April 1st, 2012, to shareholders of record on March 9th, 2012.
About Nexen
Nexen Inc. is an independent, Canadian-based global energy company, listed on the Toronto and New York stock exchanges under the symbol NXY. Nexen is focused on three growth strategies: oil sands and shale gas in Western Canada and conventional exploration and development primarily in the North Sea, offshore West Africa and deepwater Gulf of Mexico. Nexen adds value for shareholders through successful full-cycle oil and gas exploration and development, and leadership in ethics, integrity, governance and environmental stewardship.
For further information on our shale gas joint venture, please refer to our press release dated November 29th, 2011. For more information on our estimates of reserves, please refer to our Annual Information Form. For more information on our estimates of resource, please refer to our press release dated November 15th, 2010.
Conference Call
Kevin Reinhart, Interim President & CEO, and Una Power, Interim CFO and Senior Vice President of Corporate Planning & Business Development, will discuss the financial and operating results as well as Nexen's business strategy and future expectations.
The webcast will be archived under the Investors section of our website.
Conference Call Details:
Date: February 16th, 2012
Time: 7:00 a.m. Mountain Time (9:00 a.m. Eastern Time)
To listen to the conference call, please call one of the following:
(416) 340-2218 (Toronto)
(866) 226-1793 (North American toll-free)
(800) 9559-6849 (Global toll-free)
A replay of the call will be available for two weeks starting at 9:00 a.m. Mountain Time, February 16th by calling (905) 694-9451 (Toronto) or (800) 408-3053 (toll-free) passcode 2188506 followed by the pound sign.
Forward-Looking Statements
Certain statements in this release constitute "forward-looking statements" (within the meaning of the United States Private Securities Litigation Reform Act of 1995, 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 royalties and tax levels; future capital expenditures, their timing and their allocation to exploration and development activities; future earnings; future asset acquisitions or dispositions; future sources of funding for our capital program; future debt levels; availability of committed credit facilities; possible commerciality of our projects; development plans or capacity expansions; the expectation that we have the ability to substantially grow production at our oil sands facilities through controlled expansions; the expectation of achieving the production design rates from our oil sands facilities; the expectation that our oil sands production facilities continue to develop better and more sustainable practices; the expectation of cheaper and more technologically advanced operations; the expected design size of our operations; the expected timing and associated production impact of facilities turnarounds and maintenance; the expectation that we can continue to operate our offshore exploration, development and production facilities safely and profitably; future ability to execute dispositions of assets or businesses; future sources of liquidity, 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 cost recovery oil revenues from our Yemen operations; the expectation of our ability to comply with the new safety and environmental rules enacted in the US at a minimal incremental cost, and of receiving necessary drilling permits for our US offshore operations; estimates on a per share basis; future foreign currency exchange rates, future expenditures and future allowances relating to environmental matters and our ability to comply therewith; dates by which certain areas will be developed, come on stream or reach expected operating capacity; 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.
All of the forward-looking statements in this release are qualified by the assumptions that are stated or inherent in such forward-looking statements. Although we believe that these assumptions are reasonable, this list is not exhaustive of the factors that may affect any of the forward-looking statements and the reader should not place an undue reliance on these assumptions and such forward-looking statements. The key assumptions that have been made in connection with the forward-looking statements include the following: that we will conduct our operations and achieve results of operations as anticipated; that our development plans will achieve the expected results; the general continuance of current or, where applicable, assumed industry conditions; the continuation of assumed tax, royalty and regulatory regimes; the accuracy of the estimates of our reserve volumes; commodity price and cost assumptions; the continued availability of adequate cash flow and debt and/or equity financing to fund our capital and operating requirements as needed; and the extent of our liabilities. We believe the material factors, expectations and assumptions reflected in the forward-looking statements are reasonable, but no assurance can be given that these factors, expectations and assumptions will prove to be correct.
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; our ability to explore, develop, produce, upgrade and transport crude oil and natural gas to markets; ultimate effectiveness of design or design modifications to facilities; the results of exploration and development drilling and related activities; the cumulative impact of oil sands development on the environment; the impact of technology on operations and processes and how new complex technology may not perform as expected; the availability of pipeline and global refining capacity; risks inherent to the operations of any large, complex refinery units, especially the integration between production operations and an upgrader facility; availability of third-party bitumen for use in our oil sands production facilities; labour and material shortages; risks related to accidents, blowouts and spills in connection with our offshore exploration, development and production activities, particularly our deepwater activities; direct and indirect risks related to the imposition of moratoriums, suspensions or cancellations of our offshore exploration, development and production operations, particularly our deepwater activities; the impact of severe weather on our offshore exploration, development and production activities, particularly our deepwater activities; the effectiveness and reliability of our technology in harsh and unpredictable environments; risks related to the actions and financial circumstances of our agents, counterparties, contractors, and joint venture parties; 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 including without limitation, those related to our offshore exploration, development and production activities; renegotiations of contracts; results of litigation, arbitration or regulatory proceedings; political uncertainty, including actions by terrorists, insurgent or other groups, or other armed conflict, including conflict between states; and other factors, many of which are beyond our control.
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 forward-looking 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 the Risk Factors contained in our 2010 Annual Information form, and to the Quantitative Disclosures about Market Risk and our Forward Looking Statements contained in our 2010 Management Discussion and Analysis.
Note to Investors on Reserves
The reserves estimates in this disclosure were prepared in February 2012 with an effective date of December 31, 2011. The estimates of reserves and future net revenue and have been internally prepared by an internal qualified reserves evaluator in accordance with National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities ("NI 51-101") and the Canadian Oil and Gas Evaluation Handbook ("COGE Handbook"). Nexen's estimates of reserves prepared in accordance with SEC requirements are attached to its 2011 Annual Information Form.
Investors should note the following fundamental differences between reserves estimates and related disclosures prepared in accordance with NI 51-101 and those prepared in accordance with SEC requirements:
-- SEC reserves estimates are based upon different reserves definitions and
are prepared in accordance with generally recognized industry practices
in the U.S. whereas NI 51-101 reserves are based on definitions and
standards promulgated by the COGE Handbook and generally recognized
industry practices in Canada;
-- SEC reserves definitions differ from NI 51-101 in areas such as the use
of reliable technology, areal extent around a drilled location,
quantities below the lowest known oil and quantities across an undrilled
fault block;
-- the SEC mandates disclosure of proved reserves and the Standardized
Measure of Discounted Future Net Cash Flows and Changes Therein
calculated using the year's monthly average prices and costs held
constant whereas NI 51-101 requires disclosure of reserves and related
future net revenues using forecast prices and costs;
-- the SEC mandates disclosure of reserves by geographic area whereas NI
51-101 requires disclosure of reserves by additional categories and
product types;
-- the SEC does not require the disclosure of future net revenue of proved
and proved plus probable reserves using forecast pricing at various
discount rates;
-- the SEC requires future development costs to be estimated using existing
conditions held constant, whereas NI 51-101 requires estimation using
forecast conditions;
-- the SEC does not require the validation of reserves estimates by
independent qualified reserves evaluators or auditors, whereas, without
an exemption noted below, NI 51-101 requires issuers to engage such
evaluators or auditors to evaluate, audit or review reserves and related
future net revenue attributable to those reserves; and
-- the SEC does not allow proved and probable reserves to be aggregated
whereas NI 51-101 requires issuers to make such aggregation.
The foregoing is a general description of the principal differences only. The differences between SEC requirements and NI 51-101 may be material for certain properties. Please also note:
-- 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. Using the forecast prices
applied to our reserves estimates, the boe conversion ratio based on
wellhead value is approximately 30 mcf: 1 bbl; 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.
Nexen has received an exemption from NI 51-101 that permits us to forego the requirement to have our NI 51-101 reserves and related future net revenue attributable to our reserves evaluated, audited or reviewed by an independent qualified reserves evaluator or auditor. Accordingly, our future net revenue and reserves estimates are based on internal evaluations. Due to the extent and expertise of our internal reserves evaluation resources, our staff's familiarity with our properties and the controls applied to the evaluation process, we believe the reliability of our internally generated reserves estimates is not materially less than would be generated by an independent reserves evaluator.
NI 51-101 Reserves (before royalties, forecast pricing) - December 31, 2011
Other
North Sea Intl (1) United States
---------------------------------------------
(mmboe) Oil Gas Oil Oil Gas
----------------------------------------------------------------------------
PROVED
December 31, 2010 195 11 55 19 22
Discoveries - - - - -
Extensions & Improved Recovery 1 1 1 - -
Acquisitions - - - - -
Revisions 27 1 1 - 1
Divestments - - - - -
---------------------------------------------
Net Additions 28 2 2 - 1
Production (32) (2) (14) (3) (5)
----------------------------------------------------------------------------
December 31, 2011 191 11 43 16 18
----------------------------------------------------------------------------
----------------------------------------------------------------------------
PROBABLE
December 31, 2010 106 10 41 7 13
Discoveries 3 - - 58 6
Extensions & Improved Recovery - - 4 1 1
Acquisitions - - - - -
Revisions 10 (1) (4) - (1)
Divestments - - - - -
---------------------------------------------
Net Additions 13 (1) - 59 6
Conversions (3) (21) (2) (2) (1) (2)
Reclassification to Bitumen (4) - - - - -
----------------------------------------------------------------------------
December 31, 2011 98 7 39 65 17
----------------------------------------------------------------------------
----------------------------------------------------------------------------
PROVED + PROBABLE
December 31, 2010 301 21 96 26 35
Discoveries 3 - - 58 6
Extensions & Improved Recovery 1 1 5 1 1
Acquisitions - - - - -
Revisions 37 - (3) - -
Divestments - - - - -
---------------------------------------------
Net Additions 41 1 2 59 7
Conversions (3) (21) (2) (2) (1) (2)
Reclassification to Bitumen (4) - - - - -
Production (32) (2) (14) (3) (5)
----------------------------------------------------------------------------
December 31, 2011 289 18 82 81 35
----------------------------------------------------------------------------
----------------------------------------------------------------------------
NI 51-101 Reserves (before royalties, forecast pricing) - December 31, 2011
Canada
-----------------------------------
Oil Sand Oil Sand
Gas Insitu Insitu Syncrude Total
---------------------------------------------
Bitumen Synthetic Synthetic Oil and
(mmboe) Gas (2) Oil Oil Gas
----------------------------------------------------------------------------
PROVED
December 31, 2010 71 - 314 324 1,011
Discoveries 7 - - - 7
Extensions & Improved Recovery 16 - 94 8 121
Acquisitions - - - - -
Revisions (1) - (84) - (55)
Divestments - - - - -
---------------------------------------------
Net Additions 22 - 10 8 73
-
Production (7) - (5) (8) (76)
----------------------------------------------------------------------------
December 31, 2011 86 - 319 324 1,008
----------------------------------------------------------------------------
----------------------------------------------------------------------------
PROBABLE
December 31, 2010 18 - 882 46 1,123
Discoveries 29 49 - - 145
Extensions & Improved Recovery 83 - - 8 97
Acquisitions - - - - -
Revisions 4 - (40) - (32)
Divestments - - - - -
---------------------------------------------
Net Additions 116 49 (40) 8 210
Conversions (3) - - (94) (8) (130)
Reclassification to Bitumen (4) - 612 (517) - 95
----------------------------------------------------------------------------
December 31, 2011 134 661 231 46 1,298
----------------------------------------------------------------------------
----------------------------------------------------------------------------
PROVED + PROBABLE
December 31, 2010 89 - 1,196 370 2,134
Discoveries 36 49 - - 152
Extensions & Improved Recovery 99 - 94 16 218
Acquisitions - - - - -
Revisions 3 - (124) - (87)
Divestments - - - - -
---------------------------------------------
Net Additions 138 49 (30) 16 283
Conversions (3) - - (94) (8) (130)
Reclassification to Bitumen (4) - 612 (517) - 95
Production (7) - (5) (8) (76)
----------------------------------------------------------------------------
December 31, 2011 220 661 550 370 2,306
----------------------------------------------------------------------------
----------------------------------------------------------------------------
1. Other International includes Yemen, Nigeria and Colombia.
2. Includes reserves for which there are no definitive plans for upgrading
at this time.
3. Represents probable reserves converted to proved.
4. Reserves reclassified to bitumen as we no longer have sufficient
certainty as to when we will build additional upgrading facilities at
Kinosis.
Nexen Inc.
Financial Highlights
Three Months Ended Twelve Months Ended
Dec 31 Dec 31 Dec 31 Dec 31
(Cdn$ millions, except per-share
amounts) 2011 2010 2011 2010
----------------------------------------------------------------------------
Net Sales (1) 1,665 1,643 6,211 6,090
Cash Flow from Operations (1) 585 556 2,368 2,150
Per Common Share ($/share) 1.11 1.06 4.49 4.10
Net Income (1) 43 160 697 1,127
Per Common Share ($/share) 0.08 0.30 1.32 2.15
Capital Investment (2) 817 685 2,575 2,724
Net Debt (3) 3,538 4,085 3,538 4,085
Common Shares Outstanding (millions
of shares) 527.9 525.7 527.9 525.7
----------------------------------------
1. Includes discontinued operations as discussed in Note 14 to our
Unaudited Condensed Consolidated Financial Statements.
2. Includes oil and gas development, exploration, and expenditures for
other property, plant and equipment.
3. Net debt is defined as long-term debt and short-term borrowings less
cash and cash equivalents.
Cash Flow from Operations (1)
Three Months
Ended Twelve Months Ended
Dec 31 Dec 31 Dec 31 Dec 31
(Cdn$ millions) 2011 2010 2011 2010
----------------------------------------------------------------------------
Conventional Oil & Gas
United Kingdom 854 780 3,085 2,775
North America (2) 46 67 252 359
Other Countries (3) 93 79 390 371
Oil Sands
In Situ 22 (8) 5 (127)
Syncrude 89 95 405 298
----------------------------------------
1,104 1,013 4,137 3,676
Interest, Marketing and Other
Corporate Items (2) (130) (166) (367) (567)
Income Taxes (4) (389) (291) (1,402) (959)
----------------------------------------
Cash Flow from Operations (1) 585 556 2,368 2,150
----------------------------------------
----------------------------------------
1. Defined as cash flow from operating activities before changes in non-
cash working capital and other. We evaluate our performance and that of
our business segments based on earnings and cash flow from operations.
Cash flow from operations is a non-GAAP term that represents cash
generated from operating activities before changes in non-cash working
capital and other. We consider it a key measure as it demonstrates our
ability to generate the cash flow necessary to fund future growth
through capital investment. Cash flow from operations may not be
comparable with the calculation of similar measures for other companies.
Three Months Ended Twelve Months Ended
Dec 31 Dec 31 Dec 31 Dec 31
(Cdn$ millions) 2011 2010 2011 2010
----------------------------------------------------------------------------
Cash Flow from Operating Activities 459 342 2,497 2,392
Changes in Non-Cash Working Capital 32 72 (255) (338)
Other 102 141 158 128
Impact of Annual Crude Oil Put
Options (8) 1 (32) (32)
----------------------------------------
Cash Flow from Operations 585 556 2,368 2,150
----------------------------------------
----------------------------------------
Weighted-average Number of Common
Shares Outstanding (millions of
shares) 527.9 525.6 527.2 524.7
----------------------------------------
Cash Flow from Operations Per Common
Share ($/share) 1.11 1.06 4.49 4.10
----------------------------------------
----------------------------------------
2. Includes discontinued operations as discussed in Note 14 to our
Unaudited Condensed Consolidated Financial Statements.
3. After in-country cash taxes in Yemen of $36 million for the three months
ended December 31, 2011 (December 31, 2010 - $41 million) and $182
million for the twelve months ended December 31, 2011 (December 31, 2010
- $166 million).
4. Excludes in-country cash taxes in Yemen.
Nexen Inc.
Production Volumes (before royalties) (1)
Three Months Twelve Months
Ended Dec 31 Ended Dec 31
2011 2010 2011 2010
----------------------------------------------------------------------------
Crude Oil and Liquids (mbbls/d)
United Kingdom 98.8 109.4 85.0 104.9
Yemen 26.5 40.1 32.9 41.3
Oil Sands - Syncrude 18.2 22.8 20.9 21.2
Oil Sands - Long Lake Bitumen 20.5 18.3 18.6 15.9
United States 7.2 10.1 8.2 9.9
Canada (2) - - - 7.5
Other Countries 1.6 1.9 1.7 2.1
--------------------------------------
172.8 202.6 167.3 202.8
--------------------------------------
Natural Gas (mmcf/d)
United Kingdom 22 33 30 35
United States 66 99 86 99
Canada (2) 124 129 123 126
--------------------------------------
212 261 239 260
--------------------------------------
Total Production (mboe/d) 208 246 207 246
--------------------------------------
--------------------------------------
Production Volumes (after royalties)
Three Months Twelve Months
Ended Dec 31 Ended Dec 31
2011 2010 2011 2010
----------------------------------------------------------------------------
Crude Oil and Liquids (mbbls/d)
United Kingdom 98.3 109.4 84.7 104.8
Yemen 15.5 23.6 18.1 23.1
Oil Sands - Syncrude 16.4 21.0 19.2 19.6
Oil Sands - Long Lake Bitumen 19.4 17.5 17.3 15.1
United States 6.3 9.3 7.4 9.0
Canada (2) - - - 5.8
Other Countries 1.5 1.8 1.6 1.9
--------------------------------------
157.4 182.6 148.3 179.3
--------------------------------------
Natural Gas (mmcf/d)
United Kingdom 22 33 30 35
United States 72 115 78 94
Canada (2) 118 121 117 116
--------------------------------------
212 269 225 245
--------------------------------------
Total Production (mboe/d) 193 227 186 220
--------------------------------------
--------------------------------------
1. We have presented production volumes before royalties as we measure our
performance on this basis consistent with other Canadian oil and gas
companies.
2. Includes the following production from discontinued operations. (See
Note 14 to our Unaudited Condensed Consolidated Financial Statements).
Three Months Twelve Months
Ended Dec 31 Ended Dec 31
2011 2010 2011 2010
----------------------------------------------------------------------------
Before Royalties
Crude Oil and NGLs (mbbls/d) - - - 7.5
Natural Gas (mmcf/d) - - - 6
After Royalties
Crude Oil and NGLs (mbbls/d) - - - 5.8
Natural Gas (mmcf/d) - - - 5
----------------------------------------
Nexen Inc.
Oil and Gas Prices and Cash Netback (1)
Total
Quarters - 2011 Year
----------------------------------
(all dollar amounts in Cdn$ unless noted) 1st 2nd 3rd 4th 2011
----------------------------------------------------------------------------
PRICES:
Brent Crude Oil (US$/bbl) 104.97 117.36 113.47 109.31 111.28
WTI Crude Oil (US$/bbl) 94.10 102.56 89.76 94.06 95.12
Nexen Average - Oil (Cdn$/bbl) 98.37 110.28 103.98 108.44 105.21
NYMEX Natural Gas (US$/mmbtu) 4.20 4.37 4.06 3.48 4.03
AECO Natural Gas (Cdn$/mcf) 3.58 3.54 3.53 3.29 3.48
Nexen Average - Gas (Cdn$/mcf) 4.51 4.75 4.36 3.63 4.31
----------------------------------------------------------------------------
NETBACKS (1):
----------------------------------------------------------------------------
United Kingdom
Crude Oil:
Sales (mbbls/d) 104.2 73.3 75.2 92.7 86.3
Price Received ($/bbl) 99.97 110.67 107.58 110.46 106.76
Natural Gas:
Sales (mmcf/d) 36 37 26 22 30
Price Received ($/mcf) 7.29 8.20 7.28 6.52 7.42
Total Sales Volume (mboe/d) 110.2 79.5 79.5 96.4 91.3
Price Received ($/boe) 96.91 105.87 104.13 107.70 103.32
Royalties & Other - 0.11 0.82 0.54 0.36
Operating Costs 9.85 8.48 14.46 9.99 10.60
In-country Taxes 42.46 42.76 41.00 43.24 42.41
----------------------------------------------------------------------------
Netback 44.60 54.52 47.85 53.93 49.95
----------------------------------------------------------------------------
United States
Crude Oil:
Sales (mbbls/d) 9.2 8.9 7.7 7.2 8.2
Price Received ($/bbl) 91.39 101.89 96.00 110.89 99.65
Natural Gas:
Sales (mmcf/d) 103 96 81 66 86
Price Received ($/mcf) 4.36 4.42 4.27 3.59 4.21
Total Sales Volume (mboe/d) 26.3 24.9 21.2 18.2 22.6
Price Received ($/boe) 48.91 53.56 50.72 57.27 52.31
Royalties & Other 5.65 6.11 5.63 3.31 5.30
Operating Costs 10.43 10.72 11.18 16.73 11.96
----------------------------------------------------------------------------
Netback 32.83 36.73 33.91 37.23 35.05
----------------------------------------------------------------------------
Canada - Natural Gas(2)
Sales (mmcf/d) 97 85 79 112 93
Price Received ($/mcf) 3.65 3.62 3.51 3.08 3.44
Royalties & Other 0.28 0.24 0.27 0.17 0.23
Operating Costs 1.70 1.54 1.65 1.70 1.65
----------------------------------------------------------------------------
Netback 1.67 1.84 1.59 1.21 1.56
----------------------------------------------------------------------------
Yemen
Sales (mbbls/d) 34.9 39.3 31.8 27.8 33.4
Price Received ($/bbl) 101.57 111.77 107.98 111.14 108.11
Royalties & Other 46.98 52.26 49.72 45.94 48.97
Operating Costs 10.75 9.18 13.20 20.48 12.92
In-country Taxes 13.48 16.26 15.49 14.03 14.89
----------------------------------------------------------------------------
Netback 30.36 34.07 29.57 30.69 31.33
----------------------------------------------------------------------------
Total
Quarters - 2010 Year
----------------------------------
(all dollar amounts in Cdn$ unless noted) 1st 2nd 3rd 4th 2010
----------------------------------------------------------------------------
PRICES:
Brent Crude Oil (US$/bbl) 76.23 78.30 76.86 86.48 79.47
WTI Crude Oil (US$/bbl) 78.71 78.03 76.20 85.12 79.52
Nexen Average - Oil (Cdn$/bbl) 78.00 76.23 77.03 84.47 78.94
NYMEX Natural Gas (US$/mmbtu) 5.04 4.34 4.24 3.97 4.39
AECO Natural Gas (Cdn$/mcf) 5.08 3.66 3.52 3.41 3.92
Nexen Average - Gas (Cdn$/mcf) 5.37 4.42 4.18 4.16 4.54
----------------------------------------------------------------------------
NETBACKS (1):
----------------------------------------------------------------------------
United Kingdom
Crude Oil:
Sales (mbbls/d) 106.5 102.1 103.9 110.0 105.6
Price Received ($/bbl) 77.24 77.18 77.45 83.88 79.02
Natural Gas:
Sales (mmcf/d) 33 41 29 38 36
Price Received ($/mcf) 4.81 4.80 5.11 6.34 5.28
Total Sales Volume (mboe/d) 112.1 109.0 108.8 116.3 111.5
Price Received ($/boe) 74.84 74.12 75.35 81.37 76.51
Royalties & Other - - - - -
Operating Costs 7.60 7.85 8.41 9.19 8.28
In-country Taxes 23.48 22.15 23.92 27.64 24.36
----------------------------------------------------------------------------
Netback 43.76 44.12 43.02 44.54 43.87
----------------------------------------------------------------------------
United States
Crude Oil:
Sales (mbbls/d) 9.8 9.9 9.8 10.1 9.9
Price Received ($/bbl) 79.12 73.60 73.72 80.41 76.73
Natural Gas:
Sales (mmcf/d) 101 95 102 99 99
Price Received ($/mcf) 6.00 5.14 4.70 4.05 4.97
Total Sales Volume (mboe/d) 26.6 25.8 26.9 26.6 26.5
Price Received ($/boe) 51.92 47.23 44.85 45.55 47.35
Royalties & Other 4.92 4.86 5.10 (0.63) 3.55
Operating Costs 8.96 10.90 9.44 10.78 10.02
----------------------------------------------------------------------------
Netback 38.04 31.47 30.31 35.40 33.78
----------------------------------------------------------------------------
Canada - Natural Gas(2)
Sales (mmcf/d) 124 121 107 104 114
Price Received ($/mcf) 5.02 3.72 3.43 3.48 3.94
Royalties & Other 0.40 0.34 0.26 0.24 0.32
Operating Costs 1.70 1.89 1.90 1.55 1.76
----------------------------------------------------------------------------
Netback 2.92 1.49 1.27 1.69 1.86
----------------------------------------------------------------------------
Yemen
Sales (mbbls/d) 47.3 39.3 43.5 38.8 42.2
Price Received ($/bbl) 80.39 80.50 79.33 87.82 81.86
Royalties & Other 37.52 36.65 34.75 37.72 36.65
Operating Costs 9.67 10.01 9.46 12.05 10.25
In-country Taxes 10.14 10.97 10.70 11.52 10.80
----------------------------------------------------------------------------
Netback 23.06 22.87 24.42 26.53 24.16
----------------------------------------------------------------------------
1. Netbacks are defined as average sales price less royalties and other,
operating costs and in-country taxes.
2. Includes Canadian conventional, CBM and shale gas activities. Shale gas
was included beginning in Q4, 2011 when it became commercial.
Nexen Inc.
Oil and Gas Cash Netback (1) (continued)
Total
Quarters - 2011 Year
-----------------------------------
(all dollar amounts in Cdn$ unless noted) 1st 2nd 3rd 4th 2011
----------------------------------------------------------------------------
Other Countries
Sales (mbbls/d) 1.8 1.7 1.6 1.6 1.7
Price Received ($/bbl) 93.52 106.57 101.28 110.46 102.71
Royalties & Other 6.22 6.93 6.57 7.03 6.68
Operating Costs 8.11 10.19 8.58 9.65 9.11
----------------------------------------------------------------------------
Netback 79.19 89.45 86.13 93.78 86.92
----------------------------------------------------------------------------
In Situ(2)
Sales (mbbls/d) 12.9 14.3 11.8 16.7 13.9
Price Received ($/bbl) 89.82 108.78 94.15 97.28 98.33
Royalties & Other 3.58 6.05 5.07 5.29 5.05
Operating Costs 89.43 95.34 85.42 67.41 83.44
----------------------------------------------------------------------------
Netback (2) (3.19) 7.39 3.66 24.58 9.84
----------------------------------------------------------------------------
Syncrude
Sales (mbbls/d) 23.2 20.4 21.6 18.2 20.8
Price Received ($/bbl) 94.60 111.79 97.65 104.32 101.73
Royalties & Other 4.30 13.82 4.65 10.59 8.10
Operating Costs 36.11 39.98 37.10 38.24 37.78
----------------------------------------------------------------------------
Netback 54.19 57.99 55.90 55.49 55.85
----------------------------------------------------------------------------
Company-Wide
Oil and Gas Sales (mboe/d) 225.5 194.3 180.7 197.6 199.2
Price Received ($/boe) 85.98 95.31 91.06 94.11 91.46
Royalties & Other 8.74 13.47 10.83 8.62 10.34
Operating & Other Costs (2) 17.32 18.68 20.80 19.56 19.00
In-country Taxes 22.84 20.78 20.76 23.08 21.92
----------------------------------------------------------------------------
Netback 37.08 42.38 38.67 42.85 40.20
----------------------------------------------------------------------------
Total
Quarters - 2010 Year
-----------------------------------
(all dollar amounts in Cdn$ unless noted) 1st 2nd 3rd 4th 2010
----------------------------------------------------------------------------
Other Countries
Sales (mbbls/d) 2.3 2.1 2.0 1.9 2.1
Price Received ($/bbl) 78.88 74.77 75.93 77.63 76.83
Royalties & Other 5.72 5.28 5.22 5.24 5.37
Operating Costs 5.58 7.42 6.98 8.19 6.99
----------------------------------------------------------------------------
Netback 67.58 62.07 63.73 64.20 64.47
----------------------------------------------------------------------------
In Situ(2)
Sales (mbbls/d) 6.6 10.3 11.9 12.1 10.3
Price Received ($/bbl) 81.04 74.08 70.64 82.99 77.07
Royalties & Other 4.37 2.98 3.08 3.81 3.65
Operating Costs 154.00 89.95 84.75 85.61 100.09
----------------------------------------------------------------------------
Netback (2) (77.33)(18.85)(17.19) (6.43)(26.67)
----------------------------------------------------------------------------
Syncrude
Sales (mbbls/d) 19.5 23.4 19.1 22.8 21.2
Price Received ($/bbl) 83.55 77.93 78.27 85.12 81.23
Royalties & Other 7.09 6.37 4.82 6.72 6.27
Operating Costs 35.84 32.67 38.06 31.65 34.34
----------------------------------------------------------------------------
Netback 40.62 38.89 35.39 46.75 40.62
----------------------------------------------------------------------------
Company-Wide
Oil and Gas Sales (mboe/d) 249.1 243.1 232.9 235.9 240.2
Price Received ($/boe) 70.16 67.56 68.23 74.49 70.11
Royalties & Other 9.38 8.05 7.96 7.13 8.16
Operating & Other Costs (2) 14.93 15.85 15.42 15.97 15.48
In-country Taxes 12.49 11.59 13.17 15.52 13.21
----------------------------------------------------------------------------
Netback 33.36 32.07 31.68 35.87 33.26
----------------------------------------------------------------------------
1. Netbacks are defined as average sales price less royalties and other,
operating costs and in-country taxes.
2. Excludes activities related to third-party bitumen purchased, processed
and sold.
Nexen Inc.
Unaudited Condensed Consolidated Statement of Income
For the Three and Twelve Months Ended December 31
Three Months Twelve Months
(Cdn$ millions, except per-share Ended December 31 Ended December 31
amounts) 2011 2010 2011 2010
----------------------------------------------------------------------------
Revenues and Other Income
Net Sales 1,665 1,523 6,169 5,496
Marketing and Other Income (Note 13) 29 19 295 323
--------------------------------------
1,694 1,542 6,464 5,819
--------------------------------------
Expenses
Operating 371 358 1,431 1,336
Depreciation, Depletion, Amortization
and Impairment (Note 5) 799 492 1,913 1,628
Transportation and Other 136 102 425 566
General and Administrative 96 164 300 428
Exploration 90 129 368 328
Finance (Note 8) 58 89 251 362
Loss on Debt Redemption and
Repurchase (Note 7) - - 91 -
Net (Gain) Loss from Dispositions (38) (138) (38) 41
--------------------------------------
1,512 1,196 4,741 4,689
--------------------------------------
Income from Continuing Operations
before Provision for Income Taxes 182 346 1,723 1,130
--------------------------------------
Provision for (Recovery of) Income
Taxes
Current 425 332 1,584 1,125
Deferred (286) (145) (256) (449)
--------------------------------------
139 187 1,328 676
--------------------------------------
Net Income from Continuing Operations 43 159 395 454
Net Income from Discontinued
Operations, Net of Tax (Note 14) - 1 302 673
--------------------------------------
Net Income Attributable to Nexen Inc.
Shareholders 43 160 697 1,127
--------------------------------------
--------------------------------------
Earnings Per Common Share from
Continuing Operations ($/share)
Basic 0.08 0.30 0.75 0.87
--------------------------------------
--------------------------------------
Diluted 0.08 0.30 0.69 0.86
--------------------------------------
--------------------------------------
Earnings Per Common Share ($/share)
Basic 0.08 0.30 1.32 2.15
--------------------------------------
--------------------------------------
Diluted 0.08 0.30 1.24 2.09
--------------------------------------
--------------------------------------
See accompanying notes to the Unaudited Condensed Consolidated Financial Statements.
Nexen Inc.
Unaudited Condensed Consolidated Balance Sheet
December 31 December 31 January 1
(Cdn$ millions) 2011 2010 2010
----------------------------------------------------------------------------
Assets
Current Assets
Cash and Cash Equivalents 845 1,005 1,700
Restricted Cash 45 40 198
Accounts Receivable (Note 3) 2,247 1,789 2,322
Derivative Contracts 119 158 479
Inventories and Supplies (Note 4) 320 550 680
Other 115 133 172
Assets Held for Sale (Note 14) - 729 -
-----------------------------------
Total Current Assets 3,691 4,404 5,551
-----------------------------------
Non-Current Assets
Property, Plant and Equipment (Note 5) 15,571 14,579 14,669
Goodwill 291 286 330
Deferred Income Tax Assets 338 160 75
Derivative Contracts 25 116 229
Other Long-Term Assets 152 102 101
-----------------------------------
Total Assets 20,068 19,647 20,955
-----------------------------------
-----------------------------------
Liabilities
Current Liabilities
Accounts Payable and Accrued
Liabilities (Note 6) 2,867 2,223 2,591
Current Income Taxes Payable 458 345 179
Derivative Contracts 103 168 482
Liabilities Held for Sale (Note 14) - 582 -
-----------------------------------
Total Current Liabilities 3,428 3,318 3,252
-----------------------------------
Non-Current Liabilities
Long-Term Debt (Note 7) 4,383 5,090 7,259
Deferred Income Tax Liabilities 1,488 1,487 1,678
Asset Retirement Obligations (Note 9) 2,010 1,516 1,397
Derivative Contracts 24 115 210
Other Long-Term Liabilities 362 307 372
Equity (Note 11)
Nexen Inc. Shareholders' Equity
Share Capital 1,157 1,111 1,050
Retained Earnings 7,211 6,692 5,704
Cumulative Translation Adjustment 5 (37) -
-----------------------------------
Total Nexen Inc. Shareholders' Equity 8,373 7,766 6,754
Canexus Non-Controlling Interest (Note
14) - 48 33
-----------------------------------
Total Equity 8,373 7,814 6,787
-----------------------------------
Total Liabilities and Equity 20,068 19,647 20,955
-----------------------------------
-----------------------------------
See accompanying notes to Unaudited Condensed Consolidated Financial Statements.
Nexen Inc.
Unaudited Condensed 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) 2011 2010 2011 2010
----------------------------------------------------------------------------
Operating Activities
Net Income from Continuing Operations 43 159 395 454
Net Income from Discontinued
Operations - 1 302 673
Charges and Credits to Income not
Involving Cash (Note 15) 460 266 1,335 727
Exploration Expense 90 129 368 328
Changes in Non-Cash Working Capital
(Note 15) (32) (72) 255 338
Other (102) (141) (158) (128)
--------------------------------------
459 342 2,497 2,392
Financing Activities
Repayment of Term Credit Facilities,
Net - 2 - (1,538)
Repayment of Long-Term Debt (Note 7) - - (871) -
Proceeds from Canexus Long-Term Debt,
Net - (12) - 112
Dividends Paid on Common Shares (27) (26) (105) (104)
Issue of Common Shares and Exercise
of Tandem Options for Shares 7 11 46 55
Other (4) (3) (2) (31)
--------------------------------------
(24) (28) (932) (1,506)
Investing Activities
Capital Expenditures
Exploration, Evaluation, and
Development (723) (467) (2,431) (2,334)
Proved Property Acquisitions - (79) - (79)
Corporate and Other (43) (71) (93) (243)
Proceeds from Dispositions 43 218 518 1,264
Changes in Restricted Cash 6 (3) (4) 37
Changes in Non-Cash Working Capital
(Note 15) 137 (29) 321 (59)
Other 7 (43) (68) (51)
--------------------------------------
(573) (474) (1,757) (1,465)
Effect of Exchange Rate Changes on
Cash and Cash Equivalents (42) (45) 32 (116)
--------------------------------------
Increase (Decrease) in Cash and Cash
Equivalents (180) (205) (160) (695)
Cash and Cash Equivalents - Beginning
of Period 1,025 1,210 1,005 1,700
--------------------------------------
Cash and Cash Equivalents - End of
Period (1) 845 1,005 845 1,005
--------------------------------------
--------------------------------------
1. Cash and cash equivalents at December 31, 2011 consists of cash of $283
million and short-term investments of $562 million (December 31, 2010 -
cash of $345 million and short-term investments of $660 million).
See accompanying notes to the Unaudited Condensed Consolidated Financial Statements.
Nexen Inc.
Unaudited Condensed Consolidated Statement of Changes in Equity
For the Three and Twelve Months Ended December 31
Three Months Twelve Months
Ended December 31 Ended December 31
(Cdn$ millions) 2011 2010 2011 2010
----------------------------------------------------------------------------
Share Capital, Beginning of Period 1,150 1,097 1,111 1,050
Issue of Common Shares 6 9 45 50
Exercise of Tandem Options for
Shares 1 2 1 5
Accrued Liability Relating to Tandem
Options Exercised For Common Shares - 3 - 6
--------------------------------------
Balance at End of Period 1,157 1,111 1,157 1,111
--------------------------------------
--------------------------------------
Retained Earnings, Beginning of Period 7,268 6,593 6,692 5,704
Net Income Attributable to Nexen
Inc. Shareholders 43 160 697 1,127
Actuarial Losses of Defined Benefit
Pension Plans (73) (35) (73) (35)
Dividends on Common Shares (Note 11) (27) (26) (105) (104)
--------------------------------------
Balance at End of Period 7,211 6,692 7,211 6,692
--------------------------------------
--------------------------------------
Cumulative Translation Adjustment,
Beginning of Period 8 (14) (37) -
Currency Translation Adjustment (12) (23) 33 (37)
Realized Translation Adjustments (1) 9 - 9 -
--------------------------------------
Balance at End of Period 5 (37) 5 (37)
--------------------------------------
--------------------------------------
Canexus Non-Controlling Interests,
Beginning of Period - 48 48 33
Net Income Attributable to Non-
Controlling Interests - 1 1 5
Distributions Declared to Non-
Controlling Interests - (5) - (17)
Issue of Partnership Units to Non-
Controlling Interests - 4 - 27
Disposition of Canexus (Note 14) - - (49) -
--------------------------------------
Balance at End of Period - 48 - 48
--------------------------------------
--------------------------------------
1. Net of income tax recovery for the three months ended December 31, 2011
of $6 million (2010 - net of income tax expense of $4 million) and net
of income tax expense for the twelve months ended December 31, 2011 of
$18 million (2010 - net of income tax expense of $4 million).
See accompanying notes to the Unaudited Condensed Consolidated Financial Statements.
Nexen Inc.
Unaudited Condensed Consolidated Statement of Comprehensive Income
For the Three and Twelve Months Ended December 31
Three Months Twelve Months
Ended December 31 Ended December 31
(Cdn$ millions) 2011 2010 2011 2010
----------------------------------------------------------------------------
Net Income Attributable to Nexen Inc.
Shareholders 43 160 697 1,127
Other Comprehensive Income (Loss):
Currency Translation Adjustment
Net Translation Gains (Losses) of
Foreign Operations (91) (176) 109 (264)
Net Translation Gains (Losses) on
US-Denominated Debt Hedging of
Foreign Operations (1) 79 153 (76) 227
--------------------------------------
Total Currency Translation
Adjustment (12) (23) 33 (37)
Actuarial Losses of Defined Benefit
Pension Plans (2) (73) (35) (73) (35)
--------------------------------------
Other Comprehensive Loss (85) (58) (40) (72)
--------------------------------------
Total Comprehensive Income (Loss) (42) 102 657 1,055
--------------------------------------
--------------------------------------
1. Net of income tax expense for the three months ended December 31, 2011
of $11 million (2010 - net of income tax expense of $22 million) and net
of income tax recovery for the twelve months ended December 31, 2011 of
$11 million (2010 - net of income tax expense of $32 million).
2. Net of income tax recovery for the three months ended December 31, 2011
of $24 million (2010 - net of income tax recovery of $11 million) and
net of income tax recovery for the twelve months ended December 31, 2011
of $24 million (2010 - net of income tax recovery of $11 million).
See accompanying notes to the Unaudited Condensed Consolidated Financial Statements.
Nexen Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
Cdn$ millions, except as noted
1. BASIS OF PRESENTATION
Nexen Inc. (Nexen, we or our) is an independent, global energy company with operations in the North Sea, Gulf of Mexico, offshore West Africa, Canada, Yemen and Colombia. Nexen is incorporated and domiciled in Canada and our head office is located at 801-7th Avenue SW, Calgary, Alberta, Canada. Nexen's shares are publicly traded on both the Toronto Stock Exchange and the New York Stock Exchange.
These Unaudited Condensed Consolidated Financial Statements for the three and twelve months ended December 31, 2011 have been prepared in accordance with International Accounting Standard (IAS) 34 Interim Financial Reporting. The Unaudited Condensed Consolidated Financial Statements do not include all of the information required for annual financial statements. Amounts relating to the three and twelve months ended December 31, 2010 were previously presented in accordance with Canadian GAAP. These amounts have been restated as necessary to be compliant with our accounting policies under International Financial Reporting Standards (IFRS) (see Note 2). Reconciliations and descriptions relating to the transition from Canadian GAAP to IFRS are included in Note 17.
The Unaudited Condensed Consolidated Financial Statements were authorized for issue on February 15, 2012 and should be read in conjunction with the Audited Consolidated Financial Statements for the year ended December 31, 2010, which have been prepared in accordance with Canadian GAAP.
2. ACCOUNTING POLICIES
The accounting policies we follow are described in Note 2 of the Unaudited Condensed Consolidated Financial Statements for the three months ended March 31, 2011.
Future Changes in Accounting Policies
As part of our transition to IFRS, we have adopted all IFRS accounting standards in effect on December 31, 2011.
The following standards and interpretations have not been adopted as they apply to future periods. They may result in future changes to our existing accounting policies and other note disclosures. We are evaluating the impacts that these standards may have on our results of operations, financial position and disclosure, except where indicated.
-- IFRS 7 Financial Instruments: Disclosures - in December 2011, the
International Accounting Standards Board (IASB) issued final amendments
to the disclosure requirements for the offsetting of a financial asset
and financial liabilities when offsetting is permitted under IFRS. The
disclosure amendments are required to be adopted retrospectively for
periods beginning January 1, 2013.
-- IFRS 9 Financial Instruments - in November 2009, the IASB issued IFRS 9
to address classification and measurement of financial assets. In
October 2010, the IASB revised the standard to include financial
liabilities. The standard is required to be adopted for periods
beginning January 1, 2015. Portions of the standard remain in
development and the full impact of the standard will not be known until
the project is complete.
-- IFRS 10 Consolidated Financial Statements - in May 2011, the IASB issued
IFRS 10 which provides additional guidance to determine whether an
investee should be consolidated. The guidance applies to all investees,
including special purpose entities. The standard replaces IAS 27 (which
still contains guidance on separate financial statements) and is
required to be adopted for periods beginning January 1, 2013. We do not
expect the adoption of this standard to impact our results of operations
or financial position.
-- IFRS 11 Joint Arrangements - in May 2011, the IASB issued IFRS 11 which
presents a new model for determining whether an entity should account
for joint arrangements using proportionate consolidation or the equity
method. An entity will have to follow the substance rather than legal
form of a joint arrangement and will no longer have a choice of
accounting method. The standard also amends IAS 28 to include joint
ventures and is required to be adopted for periods beginning January 1,
2013.
-- IFRS 12 Disclosure of Interests in Other Entities - in May 2011, the
IASB issued IFRS 12 which aggregates and amends disclosure requirements
included within other standards. The standard requires a company to
provide disclosures about subsidiaries, joint arrangements, associates
and unconsolidated structured entities. The standard is required to be
adopted for periods beginning January 1, 2013. We expect this standard
to result in additional disclosures in our financial statements.
-- IFRS 13 Fair Value Measurement - in May 2011, the IASB issued IFRS 13 to
provide comprehensive guidance for instances where IFRS requires fair
value to be used. The standard provides guidance on determining fair
value and requires disclosures about those measurements. The standard is
required to be adopted for periods beginning January 1, 2013. We do not
expect a material impact on our results of operations or financial
position.
-- IAS 1 Presentation of Items of Other Comprehensive Income - in June
2011, the IASB issued amendments to IAS 1 Presentation of Financial
Statements to separate items of other comprehensive income (OCI) between
those that are reclassed to income and those that do not. The standard
is required to be adopted for periods beginning on or after July 1,
2012. We do not expect a significant change to our presentation of items
of other comprehensive income.
-- IAS 19 Employee Benefits - in June 2011, the IASB issued amendments to
IAS 19 to revise certain aspects of the accounting for pension plans and
other benefits. The amendments eliminate the corridor method of
accounting for defined benefit plans, change the recognition pattern of
gains and losses, and require additional disclosures. The standard is
required to be adopted for periods beginning on or after January 1,
2013.
-- IAS 32 Financial Instruments: Presentation - in December 2011, the IASB
issued amendments to address inconsistencies when applying the
offsetting criteria outlined in this standard. These amendments clarify
certain of the criteria required to be met in order to permit the
offsetting of financial assets and financial liabilities. The standard
is required to be adopted retrospectively for periods beginning January
1, 2014.
3. ACCOUNTS RECEIVABLE
December 31 December 31 January 1
2011 2010 2010
----------------------------------------------------------------------------
Trade
Energy Marketing 1,146 929 1,410
Oil and Gas 1,037 822 823
Other 3 2 44
--------------------------------------
2,186 1,753 2,277
Non-Trade 73 80 99
--------------------------------------
2,259 1,833 2,376
Allowance for Doubtful Receivables (1) (12) (44) (54)
--------------------------------------
Total (2) 2,247 1,789 2,322
--------------------------------------
--------------------------------------
1. Includes a general provision of $1 million and a specific provision
against certain accounts. In 2011, allowance for doubtful receivables
decreased as a result of reassessing prior impairment provisions. In
2010, allowance for doubtful receivables decreased primarily from a
reduction in counterparty credit reserves.
2. At December 31, 2010, accounts receivable related to our chemicals
operations have been included with assets held for sale (see Note 14).
Receivables terms are up to 30-days and were current as of December 31, 2011, December 31, 2010 and January 1, 2010.
4. INVENTORIES AND SUPPLIES
December 31 December 31 January 1
2011 2010 2010
----------------------------------------------------------------------------
Finished Products
Energy Marketing 230 452 548
Oil and Gas 36 35 25
Other - - 12
-------------------------------------
266 487 585
Work in Process 6 5 7
Field Supplies 48 58 88
-------------------------------------
Total (1) 320 550 680
-------------------------------------
-------------------------------------
1. At December 31, 2010, inventories and supplies related to our chemicals
operations have been included with assets held for sale (see Note 14).
5. PROPERTY, PLANT AND EQUIPMENT (PP&E)
(a) Carrying amount of PP&E
Exploration Assets Producing
and Under Oil & Gas Corporate
Evaluation Construction Properties and Other Total
----------------------------------------------------------------------------
Cost
As at January 1,
2010 2,393 1,045 20,020 1,849 25,307
Additions 1,092 693 696 243 2,724
Disposals/
Derecognitions (70) (8) (1,638) (122) (1,838)
Transfers (82) 78 4 - -
Exploration
Expense (328) - - - (328)
Transferred to
Held for Sale - - - (1,207) (1,207)
Other 36 15 408 (3) 456
Effect of
Changes in
Exchange Rate (51) (75) (603) (3) (732)
----------------------------------------------------------
As at December
31, 2010 2,990 1,748 18,887 757 24,382
Additions 1,056 734 693 92 2,575
Disposals/
Derecognitions (303) - (2,004) (18) (2,325)
Transfers (1,253) (216) 1,469 - -
Exploration
Expense (368) - - - (368)
Other 65 31 493 - 589
Effect of
Changes in
Exchange Rate 19 50 294 6 369
----------------------------------------------------------
As at December
31, 2011 2,206 2,347 19,832 837 25,222
----------------------------------------------------------
----------------------------------------------------------
Accumulated
Depreciation,
Depletion &
Amortization
(DD&A)
As at January 1,
2010 360 11 9,325 942 10,638
DD&A 41 - 1,384 119 1,544
Disposals/
Derecognitions (59) (8) (1,378) (62) (1,507)
Impairments - - 139 - 139
Transferred to
Held for Sale - - - (578) (578)
Other 1 - (7) (5) (11)
Effect of
Changes in
Exchange Rate (12) (3) (409) 2 (422)
----------------------------------------------------------
As at December
31, 2010 331 - 9,054 418 9,803
DD&A 50 - 1,210 78 1,338
Disposals/
Derecognitions (12) - (1,938) (75) (2,025)
Impairments - - 322 - 322
Other (6) - (8) - (14)
Effect of
Changes in
Exchange Rate 5 - 220 2 227
----------------------------------------------------------
As at December
31, 2011 368 - 8,860 423 9,651
----------------------------------------------------------
----------------------------------------------------------
Net Book Value
As at January 1,
2010 2,033 1,034 10,695 907 14,669
----------------------------------------------------------
----------------------------------------------------------
As at December
31, 2010 2,659 1,748 9,833 339 14,579
----------------------------------------------------------
----------------------------------------------------------
As at December
31, 2011 1,838 2,347 10,972 414 15,571
----------------------------------------------------------
----------------------------------------------------------
Exploration and evaluation assets mainly comprise of unproved properties and capitalized exploration drilling costs. Assets under construction primarily include our Usan development, offshore Nigeria and developments in the UK North Sea.
(b) Impairment
DD&A expense for 2011 includes non-cash impairment charges of $322 million for our oil and gas properties in our Conventional North America segment. Canadian natural gas assets were impaired $234 million in the second half of 2011 due to lower estimated future natural gas prices and performance-related negative reserve revisions. In the fourth quarter, lower estimated future natural gas prices and higher estimated future abandonment costs resulted in an $88 million impairment of mature Gulf of Mexico properties.
DD&A expense for 2010 includes non-cash impairment charges of $139 million for properties in the US Gulf of Mexico and Canada. In the second half of 2010, low natural gas prices, higher estimated future abandonment costs and declining production performance impaired these properties.
The properties were written down to the higher amount of value-in-use and estimated fair value less costs to sell. We estimated fair value based on discounted future net cash flows using estimated future prices, a discount rate of 9% and management's estimate of future production, capital and operating expenditures.
(c) Asset Derecognitions
Nexen's original strategy for future oil sands development was to build duplicates of the existing Long Lake SAGD facilities and upgrader. We now expect to pursue smaller, phased, SAGD-only projects and we will consider adding upgrading capacity once we are bitumen-long and economic conditions are favourable. As a result, previously capitalized design and engineering costs of $253 million on the future phases have been expensed.
6. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES
December 31 December 31 January 1
2011 2010 2010
----------------------------------------------------------------------------
Energy Marketing Payables 1,287 1,016 1,366
Accrued Payables 1,035 676 619
Trade Payables 288 164 210
Other 122 147 108
Accrued Interest Payable 78 83 89
Stock-Based Compensation 31 111 173
Dividends Payable 26 26 26
--------------------------------------
Total (1) 2,867 2,223 2,591
--------------------------------------
--------------------------------------
1. At December 31, 2010, accounts payable and accrued liabilities related
to our chemicals operations have been included with liabilities held for
sale (see Note 14).
7. LONG-TERM DEBT
December 31 December 31 January 1
2011 2010 2010
----------------------------------------------------------------------------
Term Credit Facilities (a) - - 1,570
Notes, due 2013 (b) - 497 523
Notes, due 2015 (US$126 million) (c) 128 249 262
Notes, due 2017 (US$62 million) (c) 63 249 262
Notes, due 2019 (US$300 million) 305 298 314
Notes, due 2028 (US$200 million) 203 199 209
Notes, due 2032 (US$500 million) 509 497 523
Notes, due 2035 (US$790 million) 804 786 827
Notes, due 2037 (US$1,250 million) 1,271 1,243 1,308
Notes, due 2039 (US$700 million) 712 696 733
Subordinated Debentures, due 2043
(US$460 million) 468 457 481
--------------------------------------
4,463 5,171 7,012
Unamortized Debt Issue Costs (80) (81) (88)
--------------------------------------
4,383 5,090 6,924
Canexus Debt (1) - - 335
--------------------------------------
Total 4,383 5,090 7,259
--------------------------------------
--------------------------------------
1. At December 31, 2010, long-term debt related to our chemicals operations
have been included with liabilities held for sale (see Note 14).
(a) Term credit facilities
We have committed unsecured term credit facilities of $3.8 billion (US$3.7 billion) which were not drawn at either December 31, 2011 or December 31, 2010 (January 1, 2010-$1.6 billion (US$1.5 billion)). Of these facilities, $700 million is available until 2014 and $3.1 billion is available until 2016. 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. At December 31, 2011, $367 million of these facilities were utilized to support outstanding letters of credit (December 31, 2010-$322 million and January 1, 2010-$407 million).
(b) Redemption of Notes, due 2013
In the second quarter 2011, we redeemed and cancelled US$500 million of principal from bonds due in 2013. We paid $525 million for the redemption. We recorded a $52 million loss as the difference between carrying value and the redemption price.
(c) Repurchase for Cancellation of Certain 2015 and 2017 Notes
In the first quarter 2011, we repurchased and cancelled US$124 million and US$188 million of principal from the 2015 and 2017 bonds, respectively. We paid $346 million for the repurchase and recorded a $39 million loss as the difference between carrying value and the redemption price.
(d) Credit Facilities
Nexen has uncommitted, unsecured credit facilities of approximately $180 million (US$178 million), none of which were drawn at December 31, 2011, December 31, 2010 or January 1, 2010. We utilized $17 million of these facilities to support outstanding letters of credit at December 31, 2011 (December 31, 2010-$112 million and January 1, 2010-$86 million). Interest is payable at floating rates.
Nexen has uncommitted, unsecured credit facilities exclusive to letters of credit of approximately $213 million (US$210 million). We utilized $4 million of these facilities to support outstanding letters of credit at December 31, 2011 (December 31, 2010-nil and January 1, 2010-nil).
8. FINANCE EXPENSE
Three Months Twelve Months
Ended December 31 Ended December 31
2011 2010 2011 2010
----------------------------------------------------------------------------
Long-Term Debt Interest Expense 73 92 304 361
Accretion Expense related to Asset
Retirement Obligations (Note 9) 9 16 44 47
Other Interest Expense and Fees 10 4 27 34
----------------------------------------
Total 92 112 375 442
Less: Capitalized at 6.7% (2010 -
5.8%) (34) (23) (124) (80)
----------------------------------------
Total (1) 58 89 251 362
----------------------------------------
----------------------------------------
1. Excludes interest expense related to our chemical operations (see Note
14).
Capitalized interest relates to and is included as part of the cost of our oil and gas properties. The capitalization rates are based on our weighted-average cost of borrowings.
9. ASSET RETIREMENT OBLIGATIONS (ARO)
Changes in the carrying amount of our ARO provisions are as follows:
Twelve Months Twelve Months
Ended December 31 Ended December 31
2011 2010
----------------------------------------------------------------------------
ARO, Beginning of Period 1,571 1,432
Obligations Incurred with Development
Activities 69 81
Changes in Estimates 450 332
Obligations Related to Dispositions (9) (224)
Obligations Settled (72) (43)
Accretion 44 47
Effects of Changes in Foreign Exchange
Rates 23 (54)
-----------------------------------
ARO, End of Period (1) 2,076 1,571
-----------------------------------
-----------------------------------
Of which:
Due within Twelve Months (2) 66 55
Due after Twelve Months 2,010 1,516
---------------------------------
---------------------------------
1. At December 31, 2010, asset retirement obligations related to our
chemicals operations have been included with liabilities held for sale
(see Note 14).
2. Included in accounts payable and accrued liabilities.
ARO represents the present value of estimated remediation and reclamation costs associated with our PP&E. We discounted the estimated asset retirement obligation using a weighted-average, credit-adjusted risk-free rate of 2.6% (2010-3.3%). While the provision for abandonment is based on our best estimates of future costs and the economic lives of the assets involved, there is uncertainty regarding both the amount and timing of incurring these costs. We expect approximately $428 million included in our ARO will be settled over the next five years with the balance settling beyond that. We expect to fund ARO from future cash flows from our operations.
10. RELATED PARTY DISCLOSURES
Major subsidiaries
The Unaudited Condensed Consolidated Financial Statements include the financial statements of Nexen Inc. and our subsidiaries as at December 31, 2011. The following is a list of the major subsidiaries of our operations. Transactions between subsidiaries are eliminated on consolidation. Nexen did not have any material related party transactions with entities outside the consolidated group in the years ended December 31, 2011 and 2010.
Jurisdiction of Principal
Major Subsidiaries Incorporation Activities Ownership
----------------------------------------------------------------------------
Nexen Petroleum UK Limited England and Wales Oil & Gas 100%
Nexen Petroleum Nigeria Limited Nigeria Oil & Gas 100%
Nexen Petroleum Offshore USA Inc. Delaware Oil & Gas 100%
Nexen Marketing Alberta Marketing 100%
Canadian Nexen Petroleum Yemen Yemen Oil & Gas 100%
Nexen Oil Sands Partnership Alberta Oil & Gas 100%
11. EQUITY
(a) Authorized Capital
Authorized share capital consists of an unlimited number of common shares of no par value and an unlimited number of Class A preferred shares of no par value, issuable in series. At December 31, 2011, there were 527,892,635 common shares outstanding (December 31, 2010-525,706,403 shares; January 1, 2010-522,915,843 shares). There were no preferred shares issued and outstanding as at December 31, 2011 (December 31, 2010-nil; January 1, 2010-nil). The rights, privileges, restrictions and conditions attached to common shares include a vote at all meetings of shareholders they are invited to, the receipt of any dividend declared by the board of directors on the common shares, and receipt of all remaining property of Nexen upon dissolution.
(b) Dividends
Dividends paid per common share for the three months ended December 31, 2011 were $0.05 per common share (three months ended December 31, 2010-$0.05). Dividends per common share for the year ended December 31, 2011 were $0.20 per common share (year ended December 31, 2010-$0.20). Dividends paid to holders of common shares have been designated as "eligible dividends" for Canadian tax purposes.
On February 15, 2012, the board of directors declared a quarterly dividend of $0.05 per common share, payable April 1, 2012 to the shareholders of record on March 9, 2012.
12. COMMITMENTS, CONTINGENCIES AND GUARANTEES
As described in Note 15 to the 2010 Audited Consolidated Financial Statements, 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 that payments, if any, related to existing indemnities, would not have a material adverse effect on our liquidity, financial condition or results of operations.
We assume various contractual obligations and commitments in the normal course of our operations. During the quarter, we entered into commitments comprised of the following:
2012 2013 2014 2015 2016 Thereafter
----------------------------------------------------------------------------
Operating Leases - 2 4 4 4 51
Transportation, Processing and
Storage Commitments 15 14 24 13 13 39
Drilling Rig Commitments 59 16 4 - - -
----------------------------------------------
The commitments above are in addition to those included in Note 15 to the 2010 Audited Consolidated Financial Statements. Our operating leases, transportation and storage commitments, and other drilling rig commitments as at December 31, 2011 have not materially changed from the information previously disclosed in our 2010 Audited Consolidated Financial Statements.
13. MARKETING AND OTHER INCOME
Three Months Twelve Months
Ended December 31 Ended December 31
2011 2010 2011 2010
----------------------------------------------------------------------------
Marketing Revenue, Net 21 57 195 337
Insurance Proceeds - - 26 -
Change in Fair Value of Crude Oil Put
Options (29) (22) (23) (41)
Foreign Exchange Gains (Losses) 22 (32) 36 (38)
Other 15 16 61 65
--------------------------------------
Total 29 19 295 323
--------------------------------------
--------------------------------------
14. DISPOSITIONS
(a) Discontinued Operations
In February 2011, we completed the sale of our 62.7% investment in Canexus, which operates a chemicals business, for net proceeds of $458 million and we realized a gain on disposition of $348 million in the first quarter. In the fourth quarter of 2010, we received board approval to sell our interest in Canexus and classified the assets and liabilities as held for sale at December 31, 2010. The gain on sale and results of our chemicals business have been presented as discontinued operations.
In July 2010, we completed the sale of our heavy oil properties in Canada. We received proceeds of $939 million, net of closing adjustments and realized a gain on disposition of $828 million in the third quarter of 2010. The gain on sale and results of operations of these properties have been presented as discontinued operations.
Three Months Ended
December 31
2010
-------------------
Chemicals
----------------------------------------------------------------------------
Revenues and Other Income
Net Sales 120
Other 12
-------------------
132
-------------------
Expenses
Operating 80
Depreciation, Depletion, Amortization and Impairment 15
Transportation and Other 19
General and Administrative 12
Finance 7
-------------------
133
-------------------
Loss before Provision for Income Taxes (1)
Less: Recovery of Deferred Income Taxes (1)
-------------------
Income before Non-Controlling Interests -
Less: Non-Controlling Interests (1)
-------------------
Net Income from Discontinued Operations, Net of Tax 1
-------------------
-------------------
Earnings Per Common Share
Basic 0.00
Diluted 0.00
-------------------
Twelve Months Ended December 31
2011 2010
-----------------------------------------
Chemicals Canada Chemicals Total
----------------------------------------------------------------------------
Revenues and Other Income
Net Sales 42 138 456 594
Other (1) - 25 25
Gain on Disposition 348 828 - 828
-----------------------------------------
389 966 481 1,447
-----------------------------------------
Expenses
Operating 25 50 308 358
Depreciation, Depletion,
Amortization and Impairment 4 20 35 55
Transportation and Other 2 2 60 62
General and Administrative 2 10 38 48
Finance 2 3 19 22
-----------------------------------------
35 85 460 545
-----------------------------------------
Income before Provision for Income
Taxes 354 881 21 902
Less: Provision for Deferred
Income Taxes 51 220 4 224
-----------------------------------------
Income before Non-Controlling
Interests 303 661 17 678
Less: Non-Controlling Interests 1 - 5 5
-----------------------------------------
Net Income from Discontinued
Operations, Net of Tax 302 661 12 673
-----------------------------------------
-----------------------------------------
Earnings Per Common Share
Basic 0.57 1.28
Diluted 0.55 1.23
-----------------------------------------
The following table provides the assets and liabilities that are associated with our chemicals business at December 31, 2010 and January 1, 2010. There were no assets or liabilities related to our chemical operations at December 31, 2011.
December 31 January 1
2010 2010
----------------------------------------------------------------------------
Cash and Cash Equivalents 3 14
Accounts Receivable 48 54
Inventories and Supplies 35 33
Other Current Assets 1 3
Property, Plant and Equipment, Net of Accumulated
DD&A 629 535
Deferred Income Tax Assets 7 4
Other Long-Term Assets 6 11
--------------------------
Assets 729(1) 654
--------------------------
Accounts Payable and Accrued Liabilities 59 64
Accrued Interest Payable 3 -
Long-Term Debt 414 335
Deferred Income Tax Liabilities 15 11
Asset Retirement Obligations 73 74
Other Long-Term Liabilities 18 16
--------------------------
Liabilities 582(1) 500
--------------------------
Equity - Canexus Non-Controlling Interest 48 33
--------------------------
1. Included in assets and liabilities held for sale at December 31, 2010.
Amounts related to prior periods have not been reclassified.
(b) Asset Dispositions
UK North Sea
During the fourth quarter of 2011, we sold our non-operated working interest in the Duart field for proceeds of $38 million. The sale closed in December 2011 and we recognized a gain on sale of $38 million in the fourth quarter of 2011.
UK Undeveloped Lease
During the fourth quarter of 2010, we sold non-core lands in the UK North Sea for proceeds of $17 million. We had no plans to develop these leases. We recognized a gain on disposition of $17 million in the fourth quarter of 2010.
North Dakota/Montana Crude Oil Marketing
During the fourth quarter of 2010, we sold our oil lease gathering, pipelines and storage assets in North Dakota and Montana for proceeds of $201 million. The sale closed in December 2010 and we recognized a gain on disposition of $121 million in the fourth quarter of 2010.
15. CASH FLOWS
(a) Charges and credits to income not involving cash
Three Months Twelve Months
Ended December 31 Ended December 31
2011 2010 2011 2010
----------------------------------------------------------------------------
Depreciation, Depletion,
Amortization and Impairment 799 492 1,913 1,628
Stock-Based Compensation (18) 9 (85) (52)
Loss on Debt Redemption and
Repurchase - - 91 -
Net (Gain) Loss on
Dispositions (26) (138) (38) 41
Non-Cash Items Included in
Discontinued Operations 2 28 (290) (549)
Provision for Deferred
Income Taxes (286) (145) (256) (449)
Foreign Exchange (19) 4 (33) 26
Other 8 16 33 82
------------------------------------------------
Total 460 266 1,335 727
------------------------------------------------
------------------------------------------------
(b) Changes in non-cash working capital
Three Months Twelve Months
Ended December 31 Ended December 31
2011 2010 2011 2010
----------------------------------------------------------------------------
Accounts Receivable (308) 90 (381) 96
Inventories and Supplies 27 (93) 208 (105)
Other Current Assets 39 1 26 47
Accounts Payable and Accrued
Liabilities 347 (99) 723 241
------------------------------------------------
Total 105 (101) 576 279
------------------------------------------------
------------------------------------------------
Relating to:
Operating Activities (32) (72) 255 338
Investing Activities 137 (29) 321 (59)
------------------------------------------------
Total 105 (101) 576 279
------------------------------------------------
------------------------------------------------
(c) Other cash flow information
Three Months Twelve Months
Ended December 31 Ended December 31
2011 2010 2011 2010
----------------------------------------------------------------------------
Interest Paid 87 87 305 380
Income Taxes Paid 342 325 1,448 951
----------------------------------------
16. OPERATING SEGMENTS AND RELATED INFORMATION
Effective in the first quarter of 2011, we amended our segment reporting to reflect changes in our business. In 2010, we disposed of non-core operations including heavy oil operations in Canada, chemicals and certain energy marketing businesses, and increased production at our Long Lake oil sands project. We report our segments to align with our key growth areas, specifically, Conventional Oil and Gas, Oil Sands and Shale Gas. Prior year results have been revised to reflect the presentation changes made in the current year.
Nexen has the following operating segments:
Conventional Oil and Gas: We explore for, develop and produce crude oil and natural gas from conventional sources around the world. Our operations are focused on the UK, North America (Canada and US) and other countries (offshore West Africa, Colombia and Yemen).
Oil Sands: We develop and produce synthetic crude oil from the Athabasca oil sands in northern Alberta. We produce bitumen using in situ and mining technologies and upgrade it into synthetic crude oil before ultimate sale. Our in situ activities are comprised of our operations at Long Lake and future development phases. Our mining activities are conducted through our 7.23% ownership of the Syncrude Joint Venture.
Shale Gas: We explore for and produce unconventional gas from shale formations in northeastern British Columbia. Production and results of operations are included within Conventional Oil and Gas until they become significant.
Corporate and Other includes energy marketing, unallocated items and the results of Canexus prior to its sale in February 2011. The results of Canexus have been presented as discontinued operations.
The accounting policies of our operating segments are the same as those described in Note 2 of our Unaudited Condensed Consolidated Financial Statements for the three months ended March 31, 2011. Net income (loss) of our operating segments excludes interest income, interest expense, unallocated corporate expenses and foreign exchange gains and losses. Identifiable assets are those used in the operations of the segments.
Segmented net income for the three months ended December 31, 2011
Corporate
and
Conventional Oil Sands Other Total
----------------------------------------------------------------------------
Other
United North Countries In
Kingdom America (1,2) Situ Syncrude
----------------------------------------
Net Sales 950 120 182 239 158 16 1,665
Marketing and Other
Income 4 3 9 - - 13 29
--------------------------------------------------------
954 123 191 239 158 29 1,694
Less: Expenses
Operating 88 46 55 108 64 10 371
Depreciation,
Depletion,
Amortization and
Impairment 192 277(3) 10 289(4) 14 17 799
Transportation and
Other 2 10 5 102 5 12 136
General and
Administrative 9 19 6 7 - 55 96
Exploration 52 31 7(5) - - - 90
Finance 1 3 1 1 2 50 58
Net gain from
Dispositions (38) - - - - - (38)
--------------------------------------------------------
Income (Loss) from
Continuing
Operations before
Income Taxes 648 (263) 107 (268) 73 (115) 182
Less: Provision for
(Recovery of)
Income Taxes 384 (79) 38 (67) 17 (154) 139
--------------------------------------------------------
Net Income (Loss) 264 (184) 69 (201) 56 39 43
--------------------------------------------------------
--------------------------------------------------------
Capital Expenditures 214 209 239(6) 88 44 23 817
--------------------------------------------------------
--------------------------------------------------------
(1) Includes results of operations in Yemen and Colombia.
(2) Includes Masila net sales of $135 million and net income of $36 million.
(3) Includes non-cash impairment charges of $181 million in Canada and the US.
(4) Includes non-cash expenses of $253 million related to previously capitalized engineering and design costs.
(5) Includes exploration activities primarily in Nigeria, Norway, Colombia and Poland.
(6) Includes capital expenditures in Nigeria of $193 million.
Segmented net income for the three months ended December 31, 2010
Corporate
and
Conventional Oil Sands Other Total
----------------------------------------------------------------------------
Other
United North Countries In
Kingdom America (1,2) Situ Syncrude
----------------------------------------
Net Sales 872 146 190 141 164 10 1,523
Marketing and Other
Income 3 2 4 - 1 9 19
--------------------------------------------------------
875 148 194 141 165 19 1,542
Less: Expenses
Operating 99 42 44 100 65 8 358
Depreciation,
Depletion,
Amortization and
Impairment 233 177 26 26 14 16 492
Transportation and
Other (3) 7 18 47 5 28 102
General and
Administrative 6 38 15 4 - 101 164
Exploration 25 90 14(3) - - - 129
Finance 5 5 - 1 1 77 89
Gain from
Dispositions (17)(4) - - - - (121)(5) (138)
--------------------------------------------------------
Income (Loss) from
Continuing
Operations before
Income Taxes 527 (211) 77 (37) 80 (90) 346
Less: Provision for
(Recovery of)
Income Taxes 263 (64) 19 (10) 20 (41) 187
--------------------------------------------------------
Income (Loss) from
Continuing
Operations 264 (147) 58 (27) 60 (49) 159
Add: Net Income from
Discontinued
Operations (Note
14) - - - - - 1 1
--------------------------------------------------------
Net Income (Loss) 264 (147) 58 (27) 60 (48) 160
--------------------------------------------------------
--------------------------------------------------------
Capital Expenditures 228 123 189(6) 72 36 37 685
--------------------------------------------------------
--------------------------------------------------------
(1)Includes results of operations in Yemen and Colombia.
(2)Includes Masila net sales of $143 million and net income of $43 million.
(3)Includes exploration activities primarily in Yemen, Nigeria, Norway and Colombia.
(4)Gain on disposition of UK undeveloped lease.
(5)Gain on disposition of North Dakota/Montana Crude Oil Marketing assets.
(6)Includes capital expenditures in Nigeria of $158 million.
Segmented net income for the year ended December 31, 2011
Corporate
and
Conventional Oil Sands Other Total
----------------------------------------------------------------------------
Other
United North Countries In
Kingdom America (1,2) Situ Syncrude
----------------------------------------
Net Sales 3,432 499 781 688 713 56 6,169
Marketing and Other
Income 21 39 21 - 3 211 295
---------------------------------------------------------
3,453 538 802 688 716 267 6,464
Less: Expenses
Operating 353 156 164 439 287 32 1,431
Depreciation,
Depletion,
Amortization and
Impairment 631 708(3) 76 384(4) 60 54 1,913
Transportation
and Other 7 35 28 220 23 112 425
General and
Administrative (8) 74 31 19 1 183 300
Exploration 84 148 134(5) 2 - - 368
Finance 17 16 2 3 6 207 251
Net Loss on Debt
Redemption - - - - - 91 91
Net Gain from
Dispositions (38) - - - - - (38)
---------------------------------------------------------
Income (Loss) from
Continuing
Operations before
Income Taxes 2,407 (599) 367 (379) 339 (412) 1,723
Less: Provision for
(Recovery of)
Income Taxes 1,697 (164) 68 (95) 84 (262) 1,328
---------------------------------------------------------
Income (Loss) from
Continuing
Operations 710 (435) 299 (284) 255 (150) 395
Add: Net Income
from Discontinued
Operations (Note
14) - - - - - 302 302
---------------------------------------------------------
Net Income (Loss) 710 (435) 299 (284) 255 152 697
---------------------------------------------------------
---------------------------------------------------------
Capital
Expenditures 583 694 718(6) 397 124 59 2,575
---------------------------------------------------------
---------------------------------------------------------
(1) Includes results of operations in Yemen and Colombia.
(2) Includes Masila net sales of $588 million and net income of $161 million.
(3) Includes non-cash impairment charges of $322 million in Canada and the US.
(4) Includes non-cash expenses of $253 million related to previously capitalized engineering and design costs.
(5) Includes exploration activities primarily in Nigeria, Norway, Colombia and Poland.
(6) Includes capital expenditures in Nigeria of $542 million.
Segmented net income for the year ended December 31, 2010
Corporate
and
Conventional Oil Sands Other Total
----------------------------------------------------------------------------
Other
United North Countries In
Kingdom America (1,2) Situ Syncrude
-----------------------------------------
Net Sales 3,115 569 750 443 580 39 5,496
Marketing and Other
Income 17 3 16 - 5 282 323
---------------------------------------------------------
3,132 572 766 443 585 321 5,819
Less: Expenses
Operating 337 166 163 373 265 32 1,336
Depreciation,
Depletion,
Amortization
and Impairment 783 519(3) 120 94 53 59 1,628
Transportation
and Other 2 22 27 181 21 313 566
General and
Administrative 22 90 28 14 1 273 428
Exploration 67 156 104(4) 1 - - 328
Finance 17 17 1 3 4 320 362
Net (Gain) Loss
from
Dispositions (17)(5) - - (80)(6) - 138(7) 41
---------------------------------------------------------
Income (Loss) from
Continuing
Operations before
Income Taxes 1,921 (398) 323 (143) 241 (814) 1,130
Less: Provision for
(Recovery of)
Income Taxes 960 (119) 64 (36) 60 (253) 676
---------------------------------------------------------
Income (Loss) from
Continuing
Operations 961 (279) 259 (107) 181 (561) 454
Add: Net Income
from Discontinued
Operations (Note
14) - 635 - - - 38 673
---------------------------------------------------------
Net Income (Loss) 961 356 259 (107) 181 (523) 1,127
---------------------------------------------------------
---------------------------------------------------------
Capital
Expenditures 699 815 652(8) 228 119 211 2,724
---------------------------------------------------------
---------------------------------------------------------
(1)Includes results of operations in Yemen and Colombia.
(2)Includes Masila net sales of $570 million and net income of $156 million.
(3)Includes non-cash impairment charges of $139 million for Canada and the US.
(4)Includes exploration activities primarily in Yemen, Nigeria, Norway and Colombia.
(5)Gain on disposition of UK undeveloped lease.
(6)Gain on disposition of non-core lands in the Athabasca region.
(7)Net loss on disposition of Natural Gas Energy Marketing Business and North Dakota/Montana Crude Oil Marketing assets.
(8)Includes capital expenditures in Nigeria of $495 million.
Segmented assets as at December 31, 2011
Corporate
Conventional Oil Sands and Other Total
----------------------------------------------------------------------------
United North Other
Kingdom America Countries In Situ Syncrude
---------------------------------------------
Total Assets 4,817 3,403 2,138 5,881 1,423 2,406(1) 20,068
--------------------------------------------------------------
--------------------------------------------------------------
Property,
Plant and
Equipment
Cost 7,103 7,256 2,566 5,915 1,733 649 25,222
Less:
Accumulated
DD&A 3,707 4,299 648 205 411 381 9,651
--------------------------------------------------------------
Net Book
Value 3,396 2,957(2) 1,918(3) 5,710(4) 1,322 268 15,571
--------------------------------------------------------------
--------------------------------------------------------------
Goodwill 284 - - - - 7 291
--------------------------------------------------------------
--------------------------------------------------------------
(1)Includes cash of $453 million, and Energy Marketing accounts receivable and inventory of $1,449 million.
(2)Includes capitalized costs of $1,293 million associated with our Canadian shale gas operations.
(3)Includes $1,821 million related to our Usan development, offshore Nigeria.
(4)Includes net book value of $5,050 million for Long Lake Phase 1 and $660 million for future phases of our in situ oil sands projects.
Segmented assets as at December 31, 2010
Corporate
Conventional Oil Sands and Other Total
----------------------------------------------------------------------------
United North Other
Kingdom America Countries In Situ Syncrude
---------------------------------------------
Total Assets 4,249 3,195 1,646 5,782 1,259 3,516(1) 19,647
--------------------------------------------------------------
--------------------------------------------------------------
Property,
Plant and
Equipment
Cost 6,389 6,422 3,700 5,756 1,519 596 24,382
Less:
Accumulated
DD&A 3,055 3,597 2,370 91 359 331 9,803
--------------------------------------------------------------
Net Book
Value 3,334 2,825(2) 1,330(3) 5,665(4) 1,160 265 14,579
--------------------------------------------------------------
--------------------------------------------------------------
Goodwill 277 - - - - 9 286
--------------------------------------------------------------
--------------------------------------------------------------
(1)Includes cash of $817 million, Energy Marketing accounts receivable and inventory of $1,498 million and Chemicals assets of $729 million.
(2)Includes capitalized costs of $938 million associated with our Canadian shale gas operations.
(3)Includes $1,210 million related to our Usan development, offshore Nigeria.
(4)Includes net book value of $4,865 million for Long Lake Phase 1 and $800 million for future phases of our in situ oil sands projects.
Segmented assets as at January 1, 2010
Corporate
Conventional Oil Sands and Other Total
----------------------------------------------------------------------------
United North Other
Kingdom America Countries In Situ Syncrude
---------------------------------------------
Total Assets 4,840 3,146 1,320 5,616 1,165 4,868(1) 20,955
--------------------------------------------------------------
--------------------------------------------------------------
Property,
Plant and
Equipment
Cost 5,884 7,464 3,344 5,523 1,390 1,702 25,307
Less:
Accumulated
DD&A 2,458 4,600 2,387 7 319 867 10,638
--------------------------------------------------------------
Net Book
Value 3,426 2,864(2) 957(3) 5,516(4) 1,071 835 14,669
--------------------------------------------------------------
--------------------------------------------------------------
Goodwill 292 - - - - 38 330
--------------------------------------------------------------
--------------------------------------------------------------
(1)Includes cash of $1,016 million, Energy Marketing accounts receivable and inventory of $2,392 million and Chemicals assets of $654 million.
(2)Includes capitalized costs of $477 million associated with our Canadian shale gas operations.
(3)Includes $760 million related to our Usan development, offshore Nigeria.
(4)Includes net book value of $4,776 million for Long Lake Phase 1 and $740 million for future phases of our in situ oil sands projects.
17. TRANSITION TO IFRS
For all periods up to and including the year ended December 31, 2010, we prepared our Consolidated Financial Statements in accordance with Canadian generally accepted accounting principles (Canadian GAAP). As a publicly listed company in Canada, we are required to prepare consolidated financial statements in accordance with International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB) for all periods after January 1, 2011 including comparative historical information. As we are also publicly listed in the United States, we were required to include a reconciliation of our financial results between Canadian GAAP and US GAAP. The reconciliation to US GAAP is no longer required.
In accordance with transitional provisions, we prepared our opening balance sheet as at January 1, 2010 (the transition date) and 2010 comparative financial information using the accounting policies set out in Note 2 of the Unaudited Condensed Consolidated Financial Statements for the three months ended March 31, 2011. The consolidated financial statements for the year ended December 31, 2011 will be the first annual financial statements that comply with IFRS by applying existing IFRS with an effective date of December 31, 2011 or earlier. This transition note explains the material adjustments we made to convert our financial statements to IFRS.
Elected Exemptions from Full Retrospective Application
In preparing these Unaudited Condensed Consolidated Financial Statements in accordance with IFRS 1 First-time Adoption of International Financial Reporting Standards (IFRS 1), we applied the following optional exemptions from full retrospective application of IFRS.
(i) Business Combinations
We applied the business combinations exemption to not apply IFRS 3 Business Combinations retrospectively to past business combinations. Accordingly, we have not restated business combinations that took place prior to the transition date.
(ii) Fair Value or Revaluation as Deemed Cost
We elected to measure certain producing oil and gas properties at fair value as at the transition date and use that amount as its deemed cost in the opening IFRS balance sheet.
(iii) Cumulative Translation Differences
We elected to set the cumulative translation account to nil at January 1, 2010. This exemption has been applied to all subsidiaries.
(iv) Share-Based Payment Transactions
We elected to use the IFRS 1 exemption whereby the liabilities for share-based payments that had vested or settled prior to January 1, 2010 were not required to be retrospectively restated.
(v) Employee Benefits
We elected to apply the exemption for employee benefits to recognize the accumulated unrecognized net actuarial loss in retained earnings at January 1, 2010. This exemption has been applied to all defined benefit pension plans.
(vi) Asset Retirement Obligations
We applied the exemption from full retrospective application of our asset retirement obligations as permitted for first-time adoption of IFRS. As such, we re-measured ARO as at January 1, 2010. We estimated the amount to be included in the related asset by discounting the liability to the date when the obligation first arose using our best estimates of the historical risk-free discount rates applicable during the intervening period.
(vii) Borrowing Costs
We applied an IFRS transitional exemption to prospectively capitalize borrowing costs only from the transition date. As a result, borrowing costs previously capitalized under Canadian GAAP were expensed to retained earnings.
Mandatory Exceptions to Retrospective Application
In preparing these Unaudited Condensed Consolidated Financial Statements in accordance with IFRS 1, we were required to apply the following mandatory exceptions from full retrospective application of IFRS.
(i) Hedge Accounting
Only hedging relationships that satisfied the hedge accounting criteria as of the transition date are reflected as hedges in our results under IFRS. Any derivatives not meeting the IAS 39 Financial Instruments: Recognition and Measurement criteria for hedge accounting were recorded as a non-hedging derivative financial instrument.
(ii) Estimates
Hindsight was not used to create or revise estimates and accordingly, our estimates previously made under Canadian GAAP are consistent with their application under IFRS.
Reconciliations of Canadian GAAP to IFRS
IFRS 1 requires the presentation of a reconciliation of shareholders' equity, net income, comprehensive income, and cash flows for prior periods. The transition from Canadian GAAP to IFRS had no material effect upon previously reported cash flows. The following represents the reconciliations from Canadian GAAP to IFRS for the respective periods for shareholders' equity, net income, and comprehensive income:
Reconciliation of Shareholders' Equity
January 1 December 31
(Cdn$ millions) Note 2010 2010
----------------------------------------------------------------------------
Shareholders' Equity under Canadian GAAP 7,646 8,791
Differences increasing (decreasing)
reported shareholders' equity:
Borrowing Costs (i) (841) (778)
Asset Retirement Obligations (ii) (228) (241)
Employee Benefits (iii) (104) (150)
Stock-Based Compensation (iv) (96) (92)
Property, Plant & Equipment (v) (124) (90)
Foreign Exchange (vi) (11) -
Long-term Debt (vii) (9) (28)
Income Taxes (viii) 554 429
Other - (27)
--------------------------
Shareholders' Equity under IFRS 6,787 7,814
--------------------------
--------------------------
(i) Borrowing Costs
We applied the IFRS 1 exemption to prospectively capitalize borrowing costs only from the transition date as described above.
(ii) Asset Retirement Obligations (ARO)
We applied the IFRS 1 exemption for asset retirement obligations and re-measured our ARO as at January 1, 2010 as described above.
(iii) Employee Benefits
We have chosen to include previously unrecognized actuarial gains and losses of our defined benefit pension plans on the balance sheet under IFRS. Under Canadian GAAP, we amortized actuarial gains and losses to income over the estimated average remaining service life, with disclosure of the unrecognized amount in the notes to the Consolidated Financial Statements. On January 1, 2010, we applied the IFRS 1 exemption to recognize the accumulated unrecognized net actuarial loss in retained earnings on transition to IFRS.
(iv) Stock-Based Compensation (SBC)
Under Canadian GAAP, we recorded obligations for liability-based stock compensation plans using the intrinsic-value method of accounting. IFRS requires that we record these SBC obligations at fair value and subsequently re-measure the obligation each reporting period. Our tandem option, stock appreciation rights and restricted share unit plans are considered liability-based stock compensation plans. On transition, we recorded the liability at fair value for unsettled awards.
(v) Property, Plant and Equipment
Impairment
Under Canadian GAAP, if indications of impairment exist and the asset's estimated undiscounted future cash flows were lower than its carrying amount, the carrying value was written down to fair value. Under IFRS, if indications of impairments exist, the asset's carrying value is immediately compared to its estimated recoverable amount, which could trigger additional impairment under IFRS. We elected to measure certain producing oil and gas properties at fair value as at the transition date and use that amount as its deemed cost in the opening IFRS balance sheet. As a result, oil and gas properties were written down to fair value of $460 million and resulted in an impairment expense of $91 million on transition.
Componentization
Under Canadian GAAP, we depleted oil and gas capitalized costs using the unit-of-production method on a field-by-field basis and depreciated non-resource capitalized costs based on their estimated useful life. On adoption of IFRS, we reviewed our PP&E to identify each material component that has a significantly different useful life and as a result, adjustments to the accumulated depletion of certain assets resulted in an expense of $51 million on transition to IFRS.
Major Maintenance
Under Canadian GAAP, operating expenses included major maintenance costs that were expensed as incurred. Under IFRS, $18 million was capitalized and depreciated separately until the next planned major maintenance project.
(vi) Foreign Exchange
Foreign Currency Translation
We applied the first-time IFRS adoption exemption to reset our cumulative translation differences to nil on the transition date. Accumulated foreign exchange gains and losses of our self-sustaining foreign operations, net of foreign exchange translation gains and losses of long-term debt designated as hedges are included in retained earnings on the transition date. This one-time adjustment had no impact on shareholders' equity on transition.
Change in Functional Currency
As a result of additional guidance under IFRS, our assessment of the functional currency of a subsidiary changed from Canadian dollars to US dollars to better reflect the economic environment in which it operates.
(vii) Long-Term Debt
Canexus Convertible Debentures
Canexus unitholders have the ability to redeem fund units for cash pursuant to the terms of the trust indenture. Under IFRS, these convertible debentures are considered to be financial liabilities containing an embedded derivative. Under Canadian GAAP, the convertible debentures were considered to be compound instruments with an equity component. Accordingly, the equity component and unamortized deferred transaction costs recorded under Canadian GAAP were derecognized on January 1, 2010 and charged to retained earnings. We elected to recognize the convertible debentures at fair value and to recognize changes in fair value in net income during the period of change.
(viii) Income Taxes
Recognition of Deferred Tax Credit
In 2008, we completed an internal reorganization and financing of our assets in the North Sea, which provided us with a one-time tax deduction in the UK. Canadian GAAP precluded us from recognizing the full estimated benefit of the tax deductions until the assets were recognized in net income either by a sale or depletion through use. As a result, we deferred the initial recognition of the benefit and were amortizing it to future income tax expense over the life of the underlying assets under Canadian GAAP. On adoption of IFRS, no such prohibition exists and we recognized the remaining deferred tax credit in retained earnings on transition to IFRS.
Exceptions
Under Canadian GAAP, deferred taxes were generally provided on all temporary differences. Conversely, IFRS does not recognize deferred taxes on temporary differences arising from the initial recognition of assets or liabilities in transactions that are not business combinations and that affect neither accounting nor taxable profit or loss.
Reconciliation of Net Income
Three Twelve
Months Months
Ended Ended
December 31 December 31
(Cdn$ millions) Note 2010 2010
----------------------------------------------------------------------------
Net Income under Canadian GAAP 220 1,197
Differences increasing (decreasing)
reported net income:
Borrowing Costs (i) 18 63
Asset Retirement Obligations (ii) (4) (13)
Stock-Based Compensation (iii) (20) 3
Property, Plant & Equipment (iv) (43) 34
Long-term Debt (v) (1) (19)
Income Taxes (vi) 2 (136)
Other (12) (2)
--------------------------
Total Differences in Net Income (60) (70)
--------------------------
Net Income under IFRS 160 1,127
--------------------------
--------------------------
(i) Borrowing Costs
We applied an IFRS transitional exemption to prospectively capitalize borrowing costs from the transition date. As a result, borrowing costs previously capitalized under Canadian GAAP were expensed to shareholders' equity. The reduced capitalized amounts decreased DD&A expense during 2010.
(ii) Asset Retirement Obligations (ARO)
Under Canadian GAAP, foreign exchange translation gains and losses arising from the revaluation of GBP-denominated asset retirement obligations were included in net income in the period in which they occurred. Under IFRS, these translation gains and losses are treated as a change in estimate and therefore increase or decrease PP&E with a corresponding impact on net income.
(iii) Stock-Based Compensation (SBC)
As described above, we record obligations for liability-based stock compensation plans at fair value each reporting period. Our tandem option, stock appreciation rights and restricted share unit plans are considered liability-based stock compensation plans. The changes in the SBC fair value in 2010 were recognized in net income.
(iv) Property, Plant and Equipment
Impairment
As described above, certain properties were impaired and written down to fair value on transition. These adjustments reduced IFRS DD&A expense during 2010 by immaterial amounts. In the last half of 2010, additional properties were impaired and written down to fair value. The impairment expense of $46 million reduced net income in the third and fourth quarters.
Major Maintenance Costs
As described above, Canadian GAAP operating expenses included major maintenance costs that were expensed as incurred. Under IFRS, these costs are capitalized and depreciated separately until the next planned major maintenance project. During 2010, we capitalized $18 million of maintenance costs under IFRS that were expensed as operating costs under Canadian GAAP.
Gain on Sale of Heavy Oil Properties
We completed the sale of our Canadian heavy oil properties in the third quarter of 2010. As the adoption of IFRS resulted in different carrying values of property, plant & equipment and asset retirement obligations prior to the sale, our gain on sale under IFRS was $47 million higher.
(v) Long-Term Debt
Canexus Convertible Debentures
As described above, we elected to carry the Canexus convertible debentures at fair value under IFRS. The change in fair value during 2010 was included in net income.
(vi) Income Taxes
Recognition of Deferred Tax Credit
As described above, we amortized a deferred tax credit to income over the life of the underlying asset under Canadian GAAP. Under IFRS, the deferred tax credit was recognized in retained earnings on transition. Therefore, IFRS net income was lower by $29 million and $117 million for the three and twelve months ended December 31, 2010, respectively.
Other
All other adjustments to IFRS net income were tax effected which decreased deferred tax expense $31 and increased $19 million for the three and twelve months ended December 31, 2010, respectively.
Reconciliation of Comprehensive Income
Three Twelve
Months Months
Ended Ended
December 31 December 31
(Cdn$ millions) Note 2010 2010
----------------------------------------------------------------------------
Comprehensive Income under Canadian GAAP 197 1,168
Differences increasing (decreasing)
reported comprehensive income, net of
income taxes:
Differences in net income (60) (70)
Foreign Currency Translation (i) - (8)
Employee Benefits (ii) (35) (35)
--------------------------
Comprehensive Income under IFRS 102 1,055
--------------------------
--------------------------
(i) Foreign Currency Translation
Transitional adjustments reflect the foreign currency exchange impact of the IFRS adjustments during the respective periods.
(ii) Employee Benefits
As described in Note 2 of the Unaudited Condensed Consolidated Financial Statements for the three months ended March 31, 2011, actuarial gains and losses are recognized directly in other comprehensive income in the period in which they occur. For the twelve months ended December 31, 2010, actuarial losses on our defined benefit plans reduced other comprehensive income by $35 million.
Janet Craig
Vice President, Investor Relations
(403) 699-4230
or
Pierre Alvarez
Vice President, Corporate Relations
(403) 699-5202
or
Nexen Inc.
801 - 7th Ave SW
Calgary, Alberta, Canada T2P 3P7
www.nexeninc.com 
