CALGARY, ALBERTA--(Marketwire - April 27, 2011) -
Nexen Inc. reported solid first quarter 2011 financial results today, generating increased cash flow from operations and net income over the fourth quarter of 2010.
The company also reported progress on several important growth milestones, including Board of Director approval to proceed with the development of Golden Eagle. At Long Lake, initiatives to increase independence between our SAGD and upgrader facilities were advanced. In the Horn River shale gas basin, the drilling of a nine-well program resulted in a new regional record for the fewest days to successfully drill a horizontal well. In addition, we completed our non-core asset disposition program with the sale of our investment in Canexus, contributing to the $1.7 billion generated from the disposition program.
"We had a strong start to the year and our portfolio is delivering solid financial results. We completed our divestment program, which narrowed our business focus, strengthened our balance sheet, and our growth strategies are on track," said Marvin Romanow, President and Chief Executive Officer. "On the operational side, the Board's approval of our Golden Eagle development is a significant step forward in advancing our plans to deliver value from our portfolio of development opportunities."
First Quarter Highlights
-- Quarterly cash flow from operations of $669 million and net income of
$202 million delivered 20% and 26% increases over the fourth quarter of
2010, respectively. We benefited from a well-positioned production
portfolio, which is heavily weighted to Brent-priced oil.
-- Quarterly production of 232,000 boe/d (207,000 boe/d after royalties)
was impacted by unscheduled maintenance at Buzzard and work to
commission the fourth platform. Production is expected to increase in
May as most of this work is now complete.
-- Board of Directors approved the Golden Eagle development project; on-
track to deliver growth in 2014.
-- Generated gross proceeds of $477 million from the sale of our investment
in Canexus. Our disposition program contributed to a greater than 40%
reduction in net debt over the past two years.
-- Received approval for the Rochelle field development plan as a tie-back
to Scott.
-- Advanced ramp up initiatives at Long Lake including the completion of a
natural gas pipeline, putting pad 11 into production, and initiating
drilling on pads 12 and 13.
-- Continued record drilling pace at our shale gas operations in the Horn
River with a nine-well drilling program underway.
Financial Summary
During the quarter, we successfully completed our conversion project to
begin reporting in accordance with International Financial Reporting
Standards (IFRS). We restated our 2010 financial statements to IFRS which
had no material impact on our operating cash flows and reduced 2010 net
income by 6%. Further details are included in Note 18 of our first quarter
2011 Unaudited Condensed Consolidated Financial Statements.
(Cdn$ millions)
Q1 2011 Q4 2010 Q1 2010
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Production (mboe/d)
Before Royalties 232 246 252
After Royalties 207 227 221
Cash flow from operations(1) 669 556 549
Per common share ($/share) 1.27 1.06 1.04
Net income 202 160 141
Per common share ($/share) 0.38 0.30 0.27
Capital investment(2) 499 685 570
Net debt(3) 3,350 4,085 5,069
----------------------------------------
(1) For reconciliation of this non-GAAP measure, see Cash Flow from
Operations on pg. 9.
(2) Includes geological and geophysical expenditures.
(3) Net debt is defined as long-term debt and short-term borrowings less
cash and cash equivalents.
The strong financial results reflect our production portfolio, which is heavily weighted to Brent crude oil pricing. Brent averaged US$105/bbl in the first quarter, a premium of US$11/bbl over WTI, compared to a Brent average price of US$86/bbl in the prior quarter. First quarter financial results also benefited from our strategic approach to hedging, which provides protection if prices decline below certain levels, but does not limit the upside potential when prices are high. Production for the quarter was impacted by unscheduled maintenance at Buzzard and commissioning the fourth platform at Buzzard.
While cash flow and net income increased with higher Brent prices, the results were impacted by an oil and gas tax rate increase in the UK. This resulted in a cash tax increase of $66 million and an additional $270 million non-cash reduction in net income from adjusting the deferred tax accounting liability. This was partially offset by a $299 million after-tax gain on the sale of Canexus, which generated gross proceeds of $477 million.
The divestment program over the past 18 months was successful in capturing value, narrowing our focus on our core growth strategies and increasing our financial capacity. This program contributed to a decreased in net debt from $5.7 billion to $3.3 billion (40%) over the past two years. We also reduced our refinancing obligations for the next seven years to $200 million by removing near-term debt maturities. Nexen retains access to liquidity of approximately $4 billion. This consists of approximately $1 billion of cash on hand and $3 billion of undrawn credit facilities.
Production
Quarterly Production before Quarterly Production after
Royalties Royalties
Crude Oil, NGLs and
Natural Gas
(mboe/d) Q1 2011 Q4 2010 Q1 2010 Q1 2011 Q4 2010 Q1 2010
----------------------------------------------- ---------------------------
North Sea 103 115 112 103 115 112
Yemen 38 40 43 20 23 23
United States 26 27 27 23 28 24
Canada - Oil & Gas 23 21 36 21 20 31
Canada - Syncrude 23 23 20 22 21 18
Canada - Bitumen 17 18 12 16 18 11
Other Countries 2 2 2 2 2 2
--------------------------- ---------------------------
Total 232 246 252 207 227 221
--------------------------- ---------------------------
Production averaged 232,000 boe/d during the quarter, compared to 246,000 boe/d during the fourth quarter of 2010. The decrease is due to lower production at Buzzard, which was impacted by unscheduled maintenance to the gas compressor cooling system and commissioning the fourth platform. This reduced first quarter production at Buzzard to 71,000 boe/d (net to Nexen) from the 85,000 to 90,000 boe/d level when there is no maintenance downtime. Work to repair the cooling system is nearly complete. The fourth platform at Buzzard, which will process the sour gas stream and extend plateau rates, is expected to be fully commissioned in May.
Production at Long Lake during the first quarter averaged 25,500 bbls/d gross (16,600 bbls/d net to Nexen), down 2,600 bbls/d from the fourth quarter of 2010. Production was impacted by scheduled maintenance of a hot lime softening unit and work on several well pad facilities done concurrently to reduce future production impact. We continue to work through high water saturation zones and expect to see production increases through increased steam injection, well optimization and the ramp up of the new pad 11 wells. The upgrader performed well during the period with an on-stream factor of 93% and premium synthetic crude (PSC) yield of 74%, up from 90% and 67%, respectively, from the fourth quarter of 2010. During April, Nexen completed maintenance on a second hot lime softener and a cogeneration unit. A third hot lime softener and the other cogeneration unit are scheduled to undergo maintenance in August. This maintenance temporarily impacts production and increases operating costs.
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Bitumen Steam Unit
Production (Gross) Injection (Gross) Operating Costs (1)
------------------ ----------------- -------------------
bbls/d bbls/d $/bbl
2011
------------------------------------------------------------------
Q1 25,500 146,000 89
------------------------------------------------------------------
2010
------------------------------------------------------------------
Q4 28,100 158,000 86
------------------------------------------------------------------
Q3 25,700 146,000 85
------------------------------------------------------------------
Q2 24,900 137,000 90
------------------------------------------------------------------
Q1 18,700 114,000 154
------------------------------------------------------------------
2009
------------------------------------------------------------------
Q4 13,600 77,000 150
------------------------------------------------------------------
Q3 8,500 48,000 180
------------------------------------------------------------------
Q2 14,300 75,000 160
------------------------------------------------------------------
Q1 12,500 66,000 220
------------------------------------------------------------------
(1) Unit operating costs are based on volumes sold and exclude activities
related to third-party bitumen purchased, processed and sold.
In Yemen, civil unrest in the country has not impacted operations, production or shipments. Safety and security continues to be the primary focus and contingency plans are in place in the event of a disruption. Contract extension negotiations for the Masila block have not progressed during this period.
We expect to meet our production guidance of 230,000 to 270,000 boe/d. Achieving the upper end of the range is now a lower probability due to first quarter production at Buzzard and Long Lake. We expect production to increase in the second half of the year with higher volumes from improved Buzzard uptime, Telford and Blackbird tie-ins, shale gas nine-well pad start up, and Long Lake pad 11 ramp-up. We are evaluating the planned three week turnaround at Buzzard currently scheduled for September to see if it can be deferred or the duration of the outage reduced.
Board of Directors Approves Golden Eagle Development
The company's growth strategy achieved an important milestone when the Board of Directors approved plans to proceed with the Golden Eagle project in the North Sea. Golden Eagle will be a two-platform standalone facility with production capacity of approximately 70,000 boe/d (approximately 25,500 boe/d net to Nexen). Nexen is the operator of the project with a 36.5% working interest.
Assuming partner and regulatory approval is granted, project sanction is expected in mid-2011. First oil is expected in late 2014.
"Golden Eagle is the largest oil discovery in the North Sea since Buzzard and is a key component of our growth plan," said Romanow. "This project is economically attractive at oil prices much lower than today."
The total cost to develop Golden Eagle is US$3.3 billion, with Nexen's share at approximately US$1.2 billion. This investment continues to be attractive despite the decision of the UK government to increase the tax rate levied on oil and gas activities. The impact of the tax increase is mitigated for taxable entities, like Nexen, by reinvesting in the country.
"While I believe the government's decision to increase taxes will discourage new investment, our near term plans for the UK North Sea remain robust due to the size and quality of our discoveries," said Romanow. "We also have a competitive advantage because of the extensive infrastructure and resources that we have in the region. We have successfully developed other large projects in the North Sea and this experience gives us confidence the project can be completed on schedule and on budget."
Growth Initiatives
Nexen has numerous opportunities available with several projects in development, others to appraise and a large resource base that is expected to sustain growth well into the future. This growth strategy includes plans to add approximately 70,000 boe/d of new production over the next 18 to 24 months. Longer-term projects include Golden Eagle, Appomattox, Knotty Head, Owowo and Kinosis. During the quarter, these plans achieved the following key milestones:
Conventional
Offshore West Africa -- Progress on the development of the Usan field remains on track for first oil next year. The floating production, storage and offloading (FPSO) vessel fabrication is now 95% complete. The FPSO is expected to arrive in the field for installation this summer. At full capacity, the project is expected to produce 36,000 boe/d net to Nexen. Nexen has a 20% interest in Usan. Project joint venture partners are Total E&P Nigeria Limited (the operator), ExxonMobil and Chevron.
Gulf of Mexico -- The US government has commenced issuing drilling permits and Nexen remains confident its appraisal drilling plans for Appomattox (a joint venture with Shell, who is the operator) will be approved this year. Nexen estimates the recoverable contingent resource for this discovery exceeds 250 million boe (gross) with upside potential. Nexen has a 20% working interest in the Appomattox and a 25% working interest in the nearby Vicksburg discoveries. On the exploration front, drilling the Kakuna and Angel Fire sub-salt prospects later this year is expected to begin once permits are received. We have successfully completed a farm-out of a partial interest in the Kakuna well on a promoted basis. Further farm-out negotiations continue.
UK North Sea -- Nexen is progressing two tieback projects at Telford and Blackbird, which are on track to deliver increased production this year. These projects, when combined with Rochelle which now has an approved field development plan, are expected to contribute approximately 10,000 to 20,000 boe/d net to Nexen by the end of 2012. Longer term, the company plans to proceed with further drilling north of Golden Eagle, complete an appraisal of the Polecat discovery and drill a number of exploration prospects.
Shale Gas
Horn River -- Nexen also achieved significant progress on its shale gas strategy during the first quarter. Production from the eight-well pad continues to meet expectations. With its current nine-well pad, Nexen continued its industry-leading execution, setting a record for the fastest well drilled successfully in the region - 14 days for a horizontal well over 4,500 metres. Production from the nine-well pad is expected on-stream in the fourth quarter. We plan to commence drilling an 18-well pad this summer and it is expected to come on-stream in the fourth quarter of 2012. Shale gas production is expected to increase by 60 to 120 mmcf/d (10,000 to 20,000 boe/d) over the next two years. The company also continues to seek a joint venture partner to accelerate value realization for various portions of our shale gas acreage.
Poland -- During the quarter, Nexen entered into an agreement with Marathon Oil Corporation to jointly explore 10 concessions in Poland's Paleozoic shale play. Under the terms of the agreement, Nexen acquires a 40% working interest in the concessions, which encompass more than two million acres. Marathon plans to acquire 2D seismic during the first half of 2011, followed by the drilling of one or two wells in the fourth quarter of 2011 and potentially drilling seven to eight wells during 2012. Total capital expenditures to Nexen are estimated at about $100 million over the next two years. Marathon is the operator. The opportunity provides exposure to growing European gas demand where prices are significantly higher than in North America.
Oil Sands
Nexen continues to make progress on various initiatives to support the ramp-up of production and improve operational performance. Seven of the ten wells on pad 11 have completed initial steaming and production commenced late in the first quarter of 2011. We recently completed the installation of additional natural gas pipeline capacity that is expected to be in service this summer, enabling more consistent steam generation independent of upgrader operations. Nexen commenced drilling of the 18 wells on pads 12 and 13, and steaming and production are expected to begin next year. Work continues on the addition of two once-through steam generators that are expected to add 10 to 15% to the existing steam capacity late 2012. Work also continues on a diluent recovery unit to allow for continued production of dilbit for sale when the upgrader is down.
One of the key learnings from Long Lake relates to our strategy around resource development. Nexen's original strategy was to minimize capital investment by prioritizing the development of the resource closest to the upgrader rather than developing the highest quality areas in priority. Nexen has focused on high-grading the resource development with pads 11 through 13, which are among the highest quality resource on the lease. We are assessing accelerating the development of additional pads on high-quality resource to grow bitumen volumes.
These initiatives increase the overall project cost by 10 to 15%. These incremental investments are highly economic. On a full-cycle basis, robust oil prices and high-quality upgraded crude will deliver strong cash flows and return on capital employed.
Work on the Kinosis project also continues. Extensive core hole analysis on this reservoir confirms this is a high-quality resource. We are committed to the development of our oil sands leases and plan to develop Kinosis in two smaller SAGD stages of about 40,000 bbls/d each with upgrading available after ramp up.
Quarterly Dividend
The Board of Directors has declared the regular quarterly dividend of $0.05 per common share payable July 1, 2011, to shareholders of record on June 10, 2011.
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 Appomattox resource disclosure, please refer to our press release dated September 27, 2010.
Conference Call
Marvin Romanow, President and CEO, and Kevin Reinhart, Executive Vice President and CFO, will host a conference call to discuss our first quarter 2011 financial results.
Date: April 27, 2011
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:
416-695-7848 (Toronto)
800-766-6630 (North American toll-free)
800-4222-8835 (Global toll-free)
A replay of the call will be available for two weeks starting at 9:00 a.m. Mountain Time, by calling 905-694-9451 (Toronto) or 800-408-3053 (toll-free) passcode 4406421 followed by the pound sign.
A live and on demand webcast of the conference call will be available at
www.nexeninc.com.
Forward-Looking Statements
Certain statements in this 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 negotiating of an extension to certain of our production sharing agreements; 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; future demand for chemicals products; 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.
Cautionary Note to US Investors
In this disclosure, we may refer to "recoverable reserves", "recoverable resources", "recoverable contingent resources" and "prospective resources" which are inherently more uncertain than proved reserves or probable reserves. These terms are not used in our filings with the SEC. Our reserves and related performance measures represent our working interest before royalties, unless otherwise indicated. Please refer to our Annual Information Form available under our profile on SEDAR at
www.sedar.com for further reserves disclosure.
Cautionary Note to Canadian Investors
Nexen has received an exemption from the securities regulatory authorities in the various provinces of Canada from certain requirements of National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities ("NI 51-101") that permits us to disclose reserves estimates and related disclosures that have been prepared in accordance with SEC requirements.
As a result of this exemption, Nexen's disclosures may differ from other Canadian companies and investors should note the following fundamental differences between reserves estimates and related disclosures prepared in accordance with SEC requirements and those prepared in accordance with NI 51-101:
-- SEC reserves estimates are based upon different reserves definitions and
are prepared in accordance with generally recognized industry practices
in the US whereas NI 51-101 reserves are based on definitions and
standards promulgated by the Canadian Oil and Gas Evaluation Handbook
("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; 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 also received an exemption from NI 51-101 that permits us to forego the requirement to have our 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.
Resources
The resource estimates contained in this news release were made on September 30, 2010 and were prepared by qualified reserves evaluators. The estimated contingent and prospective resources in this news release reflects all of our low, high and best case of recoverable resources. A "best estimate" is the best estimate of the quantity of resources that will actually be recovered. It is equally likely that the actual quantities recovered will be greater or less than the best estimate. Those resources that fall within the best estimate have a 50% confidence level that the actual quantities recovered will equal or exceed the estimate. The 'low estimate' and 'high estimate' are considered to be conservative and optimistic estimates of resources with 90% and 10% confidence respectively. Nexen's estimates of contingent and prospective resources are based on definitions set out in the Canadian Oil and Gas Evaluation Handbook. Contingent resources are quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Prospective resources are quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects.
Contingencies on resources may include, but are not limited to, factors such as economic, legal, environmental, political and regulatory matters or a lack of markets. Specific oil sands contingencies precluding these contingent resources being classified as reserves include but are not limited to: project sanction, the cost and effectiveness of steam-assisted gravity drainage application, stakeholder and regulatory approvals, access to required services and infrastructure, oil prices and a demonstration of economic viability. There is no certainty that it will be commercially viable to produce any portion of these contingent oil sands resources.
Specific shale gas contingencies precluding these contingent resources being classified as reserves include but are not limited to: future drilling program and testing results, project sanction, the cost and effectiveness of fracing optimization, stakeholder and regulatory approvals, access to required services and field development infrastructure, gas prices and a demonstration of economic viability. There is no certainty that it will be commercially viable to produce any portion of these contingent shale gas resources. In the case of shale gas prospective resources there is no certainty that any portion of the resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the resources.
Cautionary statement: In the case of discovered resources or a subcategory of discovered resources other than reserves, there is no certainty that it will be commercially viable to produce any portion of the resources. In the case of undiscovered resources or a subcategory of undiscovered resources, there is no certainty that any portion of the resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the resources.
Nexen Inc.
Financial Highlights
Three Months
Ended March 31
(Cdn$ millions) 2011 2010
----------------------------------------------------------------------------
Net Sales (1) 1,637 1,501
Cash Flow from Operations (1) 669 549
Per Common Share ($/share) 1.27 1.04
Net Income (1) 202 141
Per Common Share ($/share) 0.38 0.27
Capital Investment (2) 499 570
Net Debt (3) 3,350 5,069
Common Shares Outstanding (millions of shares) 526.7 524.0
--------------------------
(1) Includes discontinued operations as discussed in Note 15 of 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 March 31
(Cdn$ millions) 2011 2010
----------------------------------------------------------------------------
Conventional Oil & Gas
United Kingdom 887 667
North America (2) 65 138
Other Countries (3) 96 105
Oil Sands
In Situ (19) (58)
Syncrude 107 65
--------------------------
1,136 917
Interest, Marketing and Other Corporate Items (2) (85) (152)
Income Taxes (4) (382) (216)
--------------------------
Cash Flow from Operations (1) 669 549
--------------------------
--------------------------
(1) Defined as cash flow from operating activities before changes in non-
cash working capital and other. We evaluate our performance and that of
our business segments based on earnings and cash flow from operations.
Cash flow from operations is a non-GAAP term that represents cash
generated from operating activities before changes in non-cash working
capital and other and excludes items of a non-recurring nature. We
consider it a key measure as it demonstrates our ability 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 March 31
(Cdn$ millions) 2011 2010
----------------------------------------------------------------------------
Cash Flow from Operating Activities 730 802
Changes in Non-Cash Working Capital Including
Income Taxes and Interest Payable (66) (256)
Other 13 13
Impact of Annual Crude Oil Put Options (8) (10)
--------------------------
Cash Flow from Operations 669 549
--------------------------
--------------------------
Weighted-average Number of Common Shares
Outstanding (millions of shares) 526.3 523.6
--------------------------
Cash Flow from Operations Per Common Share
($/share) 1.27 1.04
--------------------------
--------------------------
(2) Includes discontinued operations as discussed in Note 15 of our
Unaudited Condensed Consolidated Financial Statements.
(3) After in-country cash taxes of $42 million for the three months ended
March 31, 2011 (2010 - $43 million)
(4) Excludes in-country cash taxes in Yemen.
Nexen Inc.
Production Volumes (before royalties) (1)
Three Months
Ended March 31
2011 2010
----------------------------------------------------------------------------
Crude Oil and Liquids (mbbls/d)
United Kingdom 97.1 105.6
Yemen 38.2 42.8
Syncrude 23.2 19.5
Long Lake Bitumen 16.6 12.1
United States 9.2 9.8
Canada (2) - 14.2
Other Countries 1.8 2.3
--------------------------
186.1 206.3
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Natural Gas (mmcf/d)
Canada (2) 136 133
United States 103 101
United Kingdom 34 40
--------------------------
273 274
--------------------------
Total Production (mboe/d) 232 252
--------------------------
--------------------------
Production Volumes (after royalties)
Three Months
Ended March 31
2011 2010
----------------------------------------------------------------------------
Crude Oil and Liquids (mbbls/d)
United Kingdom 97.0 105.6
Yemen 20.6 23.1
Syncrude 22.2 17.8
Long Lake Bitumen 15.7 11.3
United States 8.2 8.9
Canada (2) - 11.0
Other Countries 1.7 2.1
--------------------------
165.4 179.8
--------------------------
Natural Gas (mmcf/d)
Canada (2) 128 121
United States 89 88
United Kingdom 34 40
--------------------------
251 249
--------------------------
Total Production (mboe/d) 207 221
--------------------------
--------------------------
(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 heavy oil discontinued operations
in Note 15 of our Unaudited Condensed Consolidated Financial Statements.
Three Months Ended March 31
2011 2010
----------------------------------------------------------------------------
Before Royalties
Crude Oil and NGLs (mbbls/d) - 14.2
Natural Gas (mmcf/d) - 12
After Royalties
Crude Oil and NGLs (mbbls/d) - 11.0
Natural Gas (mmcf/d) - 10
----------------------------
Nexen Inc.
Oil and Gas Prices and Cash Netback (1)
Total
Quarters - 2011 Quarters - 2010 Year
------------------------------------------------------
(all dollar amounts in 1st 1st 2nd 3rd 4th 2010
Cdn$ unless noted)
----------------------------------------------------------------------------
PRICES:
Brent Crude Oil
(US$/bbl) 104.97 76.23 78.30 76.86 86.48 79.47
WTI Crude Oil
(US$/bbl) 94.10 78.71 78.03 76.20 85.12 79.52
Nexen Average - Oil
(Cdn$/bbl) 98.37 78.00 76.23 77.03 84.47 78.94
NYMEX Natural Gas
(US$/mmbtu) 4.20 5.04 4.34 4.24 3.97 4.39
Nexen Average - Gas
(Cdn$/mcf) 4.51 5.37 4.42 4.18 4.16 4.54
----------------------------------------------------------------------------
NETBACKS (1):
Conventional Oil and
Gas
----------------------------------------------------------------------------
United Kingdom
Crude Oil:
Sales (mbbls/d) 104.2 106.5 102.1 103.9 110.0 105.6
Price Received
($/bbl) 99.97 77.24 77.18 77.45 83.88 79.02
Natural Gas:
Sales (mmcf/d) 36 33 41 29 38 36
Price Received
($/mcf) 7.29 4.81 4.80 5.11 6.34 5.28
Total Sales Volume
(mboe/d) 110.2 112.1 109.0 108.8 116.3 111.5
Price Received
($/boe) 96.91 74.84 74.12 75.35 81.37 76.51
Operating Costs 9.85 7.60 7.85 8.41 9.19 8.28
----------------------------------------------------------------------------
Netback 87.06 67.24 66.27 66.94 72.18 68.23
----------------------------------------------------------------------------
United States
Crude Oil:
Sales (mbbls/d) 9.2 9.8 9.9 9.8 10.1 9.9
Price Received
($/bbl) 91.39 79.12 73.60 73.72 80.41 76.73
Natural Gas:
Sales (mmcf/d) 103 101 95 102 99 99
Price Received
($/mcf) 4.36 6.00 5.14 4.70 4.05 4.97
Total Sales Volume
(mboe/d) 26.3 26.6 25.8 26.9 26.6 26.5
Price Received
($/boe) 48.91 51.92 47.23 44.85 45.55 47.35
Royalties & Other 5.65 4.92 4.86 5.10 (0.63) 3.55
Operating Costs 10.43 8.96 10.90 9.44 10.78 10.02
----------------------------------------------------------------------------
Netback 32.83 38.04 31.47 30.31 35.40 33.78
----------------------------------------------------------------------------
Canada - Natural Gas
Sales (mmcf/d) 97 124 121 107 104 114
Price Received
($/mcf) 3.65 5.02 3.72 3.43 3.48 3.94
Royalties & Other 0.28 0.40 0.34 0.26 0.24 0.32
Operating Costs 1.70 1.70 1.89 1.90 1.55 1.76
----------------------------------------------------------------------------
Netback 1.67 2.92 1.49 1.27 1.69 1.86
----------------------------------------------------------------------------
Yemen
Sales (mbbls/d) 34.9 47.3 39.3 43.5 38.8 42.2
Price Received
($/bbl) 101.57 80.39 80.50 79.33 87.82 81.86
Royalties & Other 46.98 37.52 36.65 34.75 37.72 36.65
Operating Costs 10.75 9.67 10.01 9.46 12.05 10.25
In-country Taxes 13.48 10.14 10.97 10.70 11.52 10.80
----------------------------------------------------------------------------
Netback 30.36 23.06 22.87 24.42 26.53 24.16
----------------------------------------------------------------------------
(1) Defined as average sales price less royalties and other, operating
costs, and in-country taxes in Yemen.
(2) Excludes sales related to shale gas activities in north eastern British
Columbia.
Nexen Inc.
Oil and Gas Prices and Cash Netback (1) (continued)
Total
Quarters - 2011 Quarters - 2010 Year
------------------------------------------------------
(all dollar amounts in 1st 1st 2nd 3rd 4th 2010
Cdn$ unless noted)
----------------------------------------------------------------------------
Conventional Oil and
Gas (continued)
----------------------------------------------------------------------------
Other Countries
Sales (mbbls/d) 1.8 2.3 2.1 2.0 1.9 2.1
Price Received
($/bbl) 93.52 78.88 74.77 75.93 77.63 76.83
Royalties & Other 6.22 5.72 5.28 5.22 5.24 5.37
Operating Costs 8.11 5.58 7.42 6.98 8.19 6.99
----------------------------------------------------------------------------
Netback 79.19 67.58 62.07 63.73 64.20 64.47
----------------------------------------------------------------------------
Oil Sands
----------------------------------------------------------------------------
In Situ(2)
Sales (mbbls/d) 12.9 6.6 10.3 11.9 12.1 10.3
Price Received
($/bbl) 89.82 81.04 74.08 70.64 82.99 77.07
Royalties & Other 3.58 4.37 2.98 3.08 3.81 3.65
Operating Costs 89.43 154.00 89.95 84.75 85.61 100.09
----------------------------------------------------------------------------
Netback (2) (3.19) (77.33) (18.84) (17.19) (6.43) (26.67)
----------------------------------------------------------------------------
Syncrude
Sales (mbbls/d) 23.2 19.5 23.4 19.1 22.8 21.2
Price Received
($/bbl) 94.60 83.55 77.93 78.27 85.12 81.23
Royalties & Other 4.30 7.09 6.37 4.82 6.72 6.27
Operating Costs 36.11 35.84 32.67 38.06 31.65 34.34
----------------------------------------------------------------------------
Netback 54.19 40.62 38.89 35.39 46.75 40.62
----------------------------------------------------------------------------
Company-Wide
Oil and Gas Sales
(mboe/d) 225.5 249.1 243.1 232.9 235.9 240.2
Price Received ($/boe) 85.98 70.16 67.56 68.23 74.49 70.11
Royalties & Other 8.74 9.38 8.05 7.96 7.13 8.16
Operating & Other
Costs (2) 17.32 14.93 15.85 15.42 15.97 15.48
In-country Taxes 2.08 1.92 1.76 2.00 1.89 1.90
----------------------------------------------------------------------------
Netback 57.84 43.92 41.90 42.85 49.50 44.57
----------------------------------------------------------------------------
(1) Defined as average sales price less royalties and other, operating
costs, and in-country taxes in Yemen.
(2) Excludes activities related to third-party bitumen purchased, processed
and sold. Sales volumes and amounts relate to sales made to third
parties during the period.
Nexen Inc.
Unaudited Condensed Consolidated Statement of Income
For the Three Months Ended March 31
(Cdn$ millions, except per share amounts) 2011 2010
----------------------------------------------------------------------------
Revenues and Other Income
Net Sales 1,595 1,319
Marketing and Other Income (Note 13) 49 119
--------------------------
1,644 1,438
--------------------------
Expenses
Operating 363 323
Depreciation, Depletion, Amortization and
Impairment 370 343
Transportation and Other 67 193
General and Administrative 105 109
Exploration 126 93
Finance (Note 8) 74 89
Loss on Debt Redemption and Repurchase (Note 7) 90 -
--------------------------
1,195 1,150
--------------------------
Income from Continuing Operations before Provision
for Income Taxes 449 288
--------------------------
Provision for (Recovery of) Income Taxes (Note 14)
Current 424 259
Deferred 125 (82)
--------------------------
549 177
--------------------------
Net Income (Loss) from Continuing Operations (100) 111
Net Income from Discontinued Operations, Net of
Tax (Note 15) 302 30
--------------------------
Net Income Attributable to Nexen Inc. 202 141
--------------------------
--------------------------
Earnings (Loss) Per Common Share from Continuing
Operations ($/share)
Basic (0.19) 0.21
--------------------------
--------------------------
Diluted (0.19) 0.20
--------------------------
--------------------------
Earnings Per Common Share ($/share)
Basic 0.38 0.27
--------------------------
--------------------------
Diluted 0.38 0.26
--------------------------
--------------------------
See accompanying notes to the Unaudited Condensed Consolidated Financial
Statements.
Nexen Inc.
Unaudited Condensed Consolidated Balance Sheet
March 31 December 31 January 1
(Cdn$ millions) 2011 2010 2010
----------------------------------------------------------------------------
Assets
Current Assets
Cash and Cash Equivalents 1,374 1,005 1,700
Restricted Cash 36 40 198
Accounts Receivable (Note 3) 2,145 1,789 2,322
Derivative Contracts 122 149 466
Inventories and Supplies
(Note 4) 502 550 680
Other 126 142 185
Assets Held for Sale (Note
15) - 729 -
---------------------------------------------
Total Current Assets 4,305 4,404 5,551
---------------------------------------------
Non-Current Assets
Property, Plant and
Equipment (Note 5) 14,518 14,579 14,669
Goodwill 280 286 330
Deferred Tax Assets 171 160 75
Derivative Contracts 63 116 225
Other Long-Term Assets 138 102 105
---------------------------------------------
Total Assets 19,475 19,647 20,955
---------------------------------------------
---------------------------------------------
Liabilities
Current Liabilities
Accounts Payable and Accrued
Liabilities
(Note 6) 2,946 2,459 2,681
Current Portion of Long-Term
Debt (Note 7) 534 - -
Derivative Contracts 170 168 456
Accrued Interest Payable 68 83 89
Dividends Payable 26 26 26
Liabilities Held for Sale
(Note 15) - 582 -
---------------------------------------------
Total Current Liabilities 3,744 3,318 3,252
---------------------------------------------
Non-Current Liabilities
Long-Term Debt (Note 7) 4,190 5,090 7,259
Deferred Tax Liabilities 1,678 1,487 1,678
Asset Retirement Obligations
(Note 9) 1,528 1,516 1,397
Derivative Contracts 64 115 210
Other Long-Term Liabilities 317 307 372
Equity (Note 11)
Nexen Inc. Shareholders'
Equity
Common Shares 1,134 1,111 1,050
Retained Earnings 6,868 6,692 5,704
Accumulated Other
Comprehensive Loss (48) (37) -
---------------------------------------------
Total Nexen Inc.
Shareholders' Equity 7,954 7,766 6,754
Canexus Non-Controlling
Interests (Note 15) - 48 33
---------------------------------------------
Total Equity 7,954 7,814 6,787
Commitments, Contingencies
and Guarantees (Note 12)
---------------------------------------------
Total Liabilities and Equity 19,475 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 Months Ended March 31
(Cdn$ millions) 2011 2010
----------------------------------------------------------------------------
Operating Activities
Net Income (Loss) from Continuing Operations (100) 111
Net Income from Discontinued Operations 302 30
Charges and Credits to Income not Involving Cash
(Note 16) 838 664
Exploration Expense 126 93
Income Taxes Paid (391) (207)
Interest Paid (64) (89)
Changes in Non-Cash Working Capital (Note 16) 32 213
Other (13) (13)
--------------------------
730 802
Financing Activities
Repayment of Long-term Debt (Note 7) (346) -
Proceeds from Canexus Long-term Debt, Net 5 22
Dividends Paid on Common Shares (26) (26)
Issue of Common Shares and Exercise of Tandem
Options for Shares 23 25
Other 2 (4)
--------------------------
(342) 17
Investing Activities
Capital Expenditures
Exploration, Evaluation, and Development (448) (478)
Capitalized Interest Paid (28) (18)
Corporate and Other (17) (64)
Proceeds from Dispositions 462 15
Changes in Restricted Cash (9) 15
Changes in Non-Cash Working Capital (Note 16) 84 88
Other (52) (3)
--------------------------
(8) (445)
Effect of Exchange Rate Changes on Cash and Cash
Equivalents (11) (77)
--------------------------
Increase in Cash and Cash Equivalents 369 297
Cash and Cash Equivalents - Beginning of Period 1,005 1,700
--------------------------
Cash and Cash Equivalents - End of Period (1) 1,374 1,997
--------------------------
--------------------------
(1) Cash and cash equivalents at March 31, 2011 consists of cash of $299
million and short-term investments of $1,075 million (March 31, 2010 -
cash of $257 million and short-term investments of $1,740 million).
See accompanying notes to the Unaudited Condensed Consolidated Financial
Statements.
Nexen Inc.
Unaudited Condensed Consolidated Statement of Changes in Equity
For the Three Months Ended March 31
(Cdn$ millions) 2011 2010
----------------------------------------------------------------------------
Common Shares, Beginning of Period 1,111 1,050
Issue of Common Shares 23 24
Exercise of Tandem Options for Shares - 1
Accrued Liability Relating to Tandem Options
Exercised for Common Shares - 2
--------------------------
Balance at End of Period 1,134 1,077
--------------------------
--------------------------
Retained Earnings, Beginning of Period 6,692 5,704
Net Income Attributable to Nexen Inc. 202 141
Dividends on Common Shares (Note 11) (26) (26)
--------------------------
Balance at End of Period 6,868 5,819
--------------------------
--------------------------
Accumulated Other Comprehensive Loss, Beginning of
Period (37) -
Other Comprehensive Loss Attributable to Nexen
Inc. (11) (13)
--------------------------
Balance at End of Period (48) (13)
--------------------------
--------------------------
Canexus Non-Controlling Interests, Beginning of
Period 48 33
Net Income Attributable to Non-Controlling
Interests 1 5
Distributions Declared to Non-Controlling
Interests - (4)
Issue of Partnership Units to Non-Controlling
Interests - 5
Disposition of Canexus (Note 15) (49) -
--------------------------
Balance at End of Period - 39
--------------------------
--------------------------
See accompanying notes to the Unaudited Condensed Consolidated Financial
Statements.
Nexen Inc.
Unaudited Condensed Consolidated Statement of Comprehensive Income
For the Three Months Ended March 31
(Cdn$ millions) 2011 2010
----------------------------------------------------------------------------
Net Income 202 141
Other Comprehensive Loss, Net of Income Taxes:
Foreign Currency Translation Adjustment
Net Losses on Investment in Self-Sustaining
Foreign Operations (104) (155)
Net Gains on Foreign-Denominated Debt Hedging
Self-Sustaining
Foreign Operations (1) 93 142
--------------------------
Other Comprehensive Loss Attributable to Nexen
Inc. (11) (13)
--------------------------
Total Comprehensive Income 191 128
--------------------------
--------------------------
(1) Net of income tax expense for the three months ended March 31, 2011 of
$13 million (2010 - net of income tax expense of $20 million).
See accompanying notes to the Unaudited Condensed Consolidated Financial
Statements.
Nexen Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
Cdn$ 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. 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 months ended March 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 months ended March 31, 2010 and as at 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 IFRS, which are included in Note 2. Reconciliations and descriptions relating to the transition from Canadian GAAP to IFRS are included in Note 18.
The Unaudited Condensed Consolidated Financial Statements were authorized for issue on April 26, 2011 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 set out below were used to prepare the opening IFRS consolidated balance sheet at January 1, 2010 for the purposes of transitioning to IFRS, and have been applied consistently for all periods presented in these Unaudited Condensed Consolidated Financial Statements.
(a) Consolidation
The Unaudited Condensed Consolidated Financial Statements include the accounts of Nexen and our subsidiary companies (Nexen, we or our). All subsidiary companies are wholly owned, with the exception of Canexus Limited Partnership and its subsidiaries (Canexus). All intercompany accounts and transactions are eliminated upon consolidation.
In February 2011, we completed the sale of our 62.7% interest in Canexus. Prior to the sale, all assets, liabilities and results of operations of Canexus were consolidated and included in our Consolidated Financial Statements. Non-Nexen ownership interests in Canexus were shown as non-controlling interests. The operating results of Canexus for the three months ending March 31, 2011 and 2010 have been included in discontinued operations and the assets and liabilities were reclassified as held for sale as at December 31, 2010 (see Note 15).
We proportionately consolidate our undivided interests in oil and gas exploration, development and production activities conducted under joint venture arrangements. While the joint ventures under which these activities are carried out do not comprise distinct legal entities, they are operating entities. The significant operating policies of which are, by contractual arrangement, jointly controlled by all working interest parties.
(b) Use of Estimates and Judgments
The preparation of financial statements in conformity with IFRS requires management to make judgments, estimates and assumptions that affect the application of accounting policies and the reported amounts of assets, liabilities, income and expenses. Judgments, estimates and underlying assumptions are reviewed on a continuous basis and are based on management's experience and other factors, including expectations of future events that are believed to be reasonable under the circumstances.
In preparing our financial statements, we make judgments regarding the application of our accounting policies. Significant judgments relate to the capitalization and depletion of oil and gas exploration and development costs, determination of functional currency for subsidiaries and the identification of cash-generating units.
The financial statement areas that require significant estimates and assumptions are set out on the next page.
Oil and Gas Accounting - Reserves Determination
The process of estimating reserves is complex. It requires significant estimates based on available geological, geophysical, engineering and economic data. To estimate the economically recoverable crude oil and natural gas reserves and related future net cash flows, we incorporate many factors and assumptions including the expected reservoir characteristics, future commodity prices and costs and assumed effects of regulation by governmental agencies. Reserves are used to calculate the depletion of the capitalized oil and gas costs and for impairment purposes as described in Note 2(g).
Property, Plant and Equipment
We evaluate our long-lived assets (oil and gas properties and goodwill) for impairment if indications exist. Cash flow estimates for our impairment assessments require assumptions and estimates about the following primary elements-future prices, future operating and development costs, remaining recoverable reserves and discount rates. In assessing the carrying values of our unproved properties, we make assumptions about our future plans for those properties, the remaining terms of the leases and any other factors that may be indicators of potential impairment.
Asset Retirement Obligations
In estimating our future asset retirement obligations, we make assumptions about activities that occur many years into the future including the cost and timing of such activities. Additionally, interpretation of contracts and regulations is required by management as to what constitutes removal and remediation. The ultimate financial impact is not clearly known as asset removal and remediation techniques and costs are constantly changing, as are legal, regulatory, environmental, political, safety and other such considerations. In arriving at amounts recorded, numerous assumptions and estimates are made on ultimate settlement amounts, inflation factors, discount rates, timing and expected changes in legal, regulatory, environmental, political and safety environments.
Commitments, Contingencies and Guarantees
By their nature, contingencies will only be resolved when one or more future events transpire. The assessment of contingencies inherently involves estimating the outcome of future events.
Income Taxes
We carry on business in several countries and as a result, are subject to income taxes in numerous jurisdictions. The determination of income tax is inherently complex and we are required to interpret continually changing regulations and make certain estimates and assumptions about future events. While income tax filings are subject to audits and reassessments, we believe we have adequately provided for all income tax obligations. However, changes in facts and circumstances as a result of income tax audits, reassessments, jurisprudence and any new legislation may result in an increase or decrease in our provision for income taxes.
Derivatives and Fair Value Measurements
The fair value of derivative contracts is estimated wherever possible, based on quoted market prices, and if not available, on estimates from third-party brokers. Another significant assumption that we use in determining the fair value of derivatives is market data or assumptions that market participants would use when pricing the asset or liability, including assumptions about risk. The actual settlement of derivatives could differ materially from the fair value recorded and could impact future results.
(c) Cash and Cash Equivalents
Cash and cash equivalents includes short-term, highly liquid investments that mature within three months of their purchase.
(d) Restricted Cash
Restricted cash includes margin deposits relating to our exchange-traded derivative contracts used in our energy marketing business.
(e) Accounts Receivable
Accounts receivable are recorded based on our revenue recognition policy (see Note 2(n)). Our allowance for doubtful accounts provides for specific doubtful receivables, as well as general counterparty credit risk evaluated using observable market information and internal assessments.
(f) Inventories and Supplies
Inventories and supplies, other than inventory held for trading purposes, are stated at the lower of cost and net realizable value. Cost is determined using the first-in, first-out method. Inventory costs include expenditures and other costs, including depletion and depreciation, directly or indirectly incurred in bringing the inventory to its existing condition.
Commodity inventories in our energy marketing operations that are held for trading purposes are carried at fair value, less any costs to sell. Any changes in fair value are included as gains or losses in marketing and other income during the period of change.
(g) Property, Plant and Equipment (PP&E)
PP&E includes capitalized costs related to our exploration and evaluation expenditures, assets under construction and capitalized costs related to our producing oil and gas properties.
Exploration and Evaluation (E&E) Expenditures
Pre-License Expenditures
Pre-license expenditures are expensed in the period in which they are incurred.
License and Property Acquisition Expenditures
Exploration license and leasehold property acquisition expenditures are intangible assets that are capitalized as E&E costs in PP&E and are reviewed periodically for indications of potential impairment. This review includes confirming that exploration drilling is under way, firmly planned or that it has been determined, or work is under way to determine, that the discovery is economically viable based on a range of technical and commercial considerations, and sufficient progress is being made to establish development plans and timing. If no future activity is planned, the remaining balance of the capitalized license and property acquisition costs is expensed. Licenses are amortized on a straight-line basis over the estimated period of exploration. Once proved reserves are discovered, technical feasibility and commercial viability are established and we decide to proceed with development, the remaining capitalized expenditure is transferred to either assets under construction or producing oil and gas assets.
Other Exploration and Evaluation Expenditures
Other exploration and evaluation costs, including drilling costs directly attributable to an identifiable well, are initially capitalized as an intangible asset until evaluation activities of the exploration play are completed. If hydrocarbons are not found or not found in commercial quantities, the costs are expensed. If hydrocarbons are found and are likely to be capable of commercial development, the costs continue to be capitalized. These costs are reviewed periodically for indications of potential impairment. Capitalized costs are transferred to assets under construction or producing oil and gas assets after assessing the estimated fair value of the property and recognizing any potential impairment loss. Geological and geophysical costs and annual lease rental costs are expensed as incurred.
Producing Oil and Gas Properties
Producing oil and gas properties are carried at cost less accumulated depletion, depreciation, amortization, and impairment losses. The cost of an asset includes the initial purchase price and directly attributable expenditures to find, develop, construct and complete the asset. This includes installation or completion of infrastructure facilities such as platforms, pipelines and the drilling of development wells, including unsuccessful development or delineation wells. Any costs directly attributable to bringing the asset to the location and condition necessary to operate as intended by management and which result in an identifiable future benefit are also capitalized. This includes the initial estimate of any asset retirement obligation and, for qualifying assets, capitalized interest. Improvements that increase capacity or extend the useful lives of the related assets are capitalized. Major spare parts and standby equipment whose useful life is expected to last longer than one year are included in capitalized costs.
Major Maintenance and Repairs
Expenditures on major maintenance of our producing assets include the cost of replacement assets or parts of assets, inspection costs or overhaul costs. Where an asset, or part of an asset that was separately depreciated, is replaced and it is probable that there are future economic benefits associated with the item, the expenditure is capitalized and the carrying amount of the replaced item is derecognized. Inspection costs associated with major maintenance programs and necessary for continued operation of the asset are capitalized and amortized over the period to the next inspection. All other maintenance costs are expensed as incurred.
Research and Development
We engage in research and development activities to develop or improve processing techniques to extract crude oil and natural gas. Research involves investigations to gain new knowledge. Development involves translating that knowledge into a new technology or process. Research costs are expensed as incurred. Development costs are deferred once technical feasibility is established and we intend to proceed with development. We defer these costs in PP&E until the asset is substantially complete and ready for productive use. Otherwise, development costs are expensed as incurred.
Non-Monetary Asset Swaps
Exchanges or swaps of non-monetary assets are measured at fair value unless the exchange transaction lacks commercial substance or neither the fair value of the assets given up nor the assets received can be reliably estimated. The cost of the acquired asset is measured at the fair value of the asset given up, unless the fair value of the asset received is more clearly evident. Where fair value is not used, the cost of the acquired asset is measured at the carrying amount of the asset given up. Any gain or loss on de-recognition of the asset given up is included in net income.
Depreciation, Depletion, Amortization and Impairment (DD&A)
Unproved property costs and major projects under construction or development are not depreciated or depleted until commercial production commences. We amortize unproved land acquisition costs over the remaining lease term.
We review the useful lives of capitalized costs for producing oil and gas properties to determine the appropriate method of amortization. Typically, we deplete oil and gas capitalized costs using the unit-of-production method. Development drilling, equipping costs and other facility costs are depleted over remaining proved developed reserves and proved property acquisition costs are depleted over remaining proved reserves. Other facilities, plant and equipment which have significantly different useful lives than the associated proved reserves are depreciated in accordance with the asset's future use. Depletion is considered a cost of inventory when the oil and gas is produced. When the inventory is sold the depletion is charged to DD&A expense.
Depreciation methods, useful lives and residual values are reviewed annually, with any amendments considered to be a change in estimate and accounted for prospectively.
Impairment
Each reporting date, we assess whether there is an indication that an asset may be impaired. If any indication exists, we estimate the asset's recoverable amount. An asset's recoverable amount is the higher of an asset's or cash-generating unit's (CGU) fair value less any costs to sell or value-in-use. Where an asset does not generate separately identifiable cash flows, we perform an impairment test on CGUs which are the smallest grouping of assets that generate independent, identifiable cash inflows. Where the carrying amount of an asset or CGU exceeds its recoverable amount, the asset is considered impaired and written down to its recoverable amount. In assessing value-in-use, the estimated future cash flows are discounted to their present value using a discount rate that reflects current market assessments of the time value of money and the risks specific to the asset. In determining fair value less costs to sell, an appropriate valuation model is used. These calculations are corroborated by external valuation metrics or other available fair value indicators wherever possible.
In assessing the carrying values of our unproved properties, we take into account future plans for those properties, the remaining terms of the leases and any other factors that may be indicators of potential impairment.
For assets excluding goodwill, an assessment is made each reporting date as to whether there is an indication that previously recognized impairment losses no longer exist or has decreased. If such indication exists, an estimate of the asset's or CGU's recoverable amount is reviewed. A previously recognized impairment loss is reversed to the extent that the events or circumstances that triggered the original impairment have changed. The reversal is limited so that the carrying amount of the asset does not exceed its recoverable amount, nor exceed the carrying amount that would have been determined, net of DD&A, had no impairment loss been recognized for the asset in prior years.
(h) Capitalized Borrowing Costs
We capitalize interest on major development projects until construction is complete using the weighted-average interest rate on all of our borrowings. Capitalized interest cannot exceed the actual interest incurred.
(i) Carried Interest
We conduct certain international operations jointly with foreign governments in accordance with production-sharing agreements pursuant to which proved reserves are recognized using the economic interest method. Under these agreements, we pay both our share and the government's share of operating and capital costs. We recover the government's share of these costs from future revenues or production over several years. The government's share of operating costs is included in operating expense when incurred, and capital costs are included in PP&E and expensed to DD&A in the year recovered. All recoveries are recorded as revenue in the year of recovery.
(j) Goodwill
Goodwill acquired in a business combination is initially recorded at cost, and for impairment testing purposes, is allocated to each of the CGUs that are expected to benefit from the expenditure. After initial recognition, goodwill is measured at cost less any accumulated impairment losses. We test goodwill for impairment at least annually or more frequently if events or circumstances indicate that goodwill may be impaired. We base our test on the assessment of the recoverable amount of the CGU. Where the recoverable amount of the CGU is less than the carrying amount, we reduce the carrying value to the estimated recoverable amount and a goodwill impairment loss is included in net income.
(k) Financial Instruments and Hedging Activities
All financial assets and liabilities are recognized on the balance sheet initially at fair value when we become a party to the contractual provisions of the instrument. Subsequent measurement of the financial instruments is based on their classification. We classify each financial instrument into one of the following categories: financial assets and liabilities at fair value through profit or loss, loans or receivables, financial assets held to maturity, financial assets available for sale and other financial liabilities. The classification depends on the characteristics and the purpose for which the financial instruments were acquired. Except in limited circumstances, the classification of financial instruments is not subsequently changed.
Financial instruments carried at fair value on our balance sheet include cash and cash equivalents, restricted cash and derivatives. Realized and unrealized gains and losses from financial assets and liabilities carried at fair value are recognized in net income in the periods such gains and losses arise. Transaction costs related to these financial assets and liabilities are included in net income when incurred.
Financial instruments we carry at cost or amortized cost include our accounts receivable, accounts payable and accrued liabilities, accrued interest payable, dividends payable, short-term borrowings and long-term debt. Transaction costs are included in net income when incurred for these types of financial instruments except long-term debt. These transaction costs are included with the initial fair value, and the instrument is carried at amortized cost using the effective interest rate method. Gains and losses on financial assets and liabilities carried at cost or amortized cost are recognized in net income when these assets or liabilities settle.
Derivatives
We use derivative instruments such as physical purchase and sales contracts, exchange-traded futures and options, and non-exchange traded forwards, swaps and options for marketing and trading crude oil and natural gas and to manage fluctuations in commodity prices, foreign currency exchange rates and interest rates. We record these instruments at fair value at each balance sheet date and changes in fair value are included in marketing and other income during the period of change unless the requirements for hedge accounting are met.
Hedge accounting
Hedge accounting is allowed when there is a high degree of correlation between price movements in the derivative instruments and the items designated as being hedged. Nexen formally documents all hedges and the risk management objectives at the inception of the hedge. Derivative instruments that have been designated and qualify for hedge accounting are classified as either cash flow or fair value hedges.
For cash flow hedges, changes in the fair value of a financial instrument designated as a cash flow hedge are recognized in net income in the same period as the hedged item. Any fair value change in the financial instrument before that period is recognized on the balance sheet. The effective portion of this fair value change is recognized in other comprehensive income, with any ineffectiveness recognized in marketing and other income during the period of change.
For fair value hedges, both the financial instrument designated as a fair value hedge and the underlying commitment are recognized on the balance sheet at fair value. Changes in the fair value of both are reflected in net income.
For hedges of net investments, gains and losses resulting from foreign exchange translation of our net investments in self-sustaining foreign operations and the effective portion of the hedging items are recorded in other comprehensive income. Amounts included in accumulated other comprehensive income are reclassified to income when realized.
(l) Provisions and Contingencies
Provisions are recognized when we have a present obligation (legal or constructive) as a result of a past event, it is probable that an outflow of resources will be required to settle the obligation and a reliable estimate can be made of the amount of the obligation. Where appropriate, the future cash flow estimates are adjusted to reflect the risks specific to the liability.
If the effect of the time value of money is material, provisions are determined by discounting the expected future cash flows at a pre-tax rate that reflects current market assessments of the time value of money. Where discounting is used, the accretion of the provision due to the passage of time is recognized within finance costs.
Contingent liabilities are possible obligations which will be confirmed by future events that are not necessarily within our control, or are present obligations where the obligation cannot be measured reliably or it is not probable that settlement will be required. Contingent liabilities are disclosed only if the possibility of settlement is greater than remote. Contingent liabilities are not recorded in the financial statements.
Asset Retirement Obligations and Environmental Expenditures
We provide for asset retirement obligations (ARO) on our resource properties, facilities, production platforms, pipelines and other facilities based on estimates established by current legislation and industry practices. ARO is initially measured at fair value and capitalized to PP&E as an asset retirement cost. The liability is estimated by discounting expected future cash flows required to settle the liability using a risk-free rate. The estimated future asset retirement costs may be adjusted for risks such as project, physical, regulatory and timing. The estimates are reviewed periodically. Changes in the provision as a result of changes in the estimated future costs or discount rates are added to or deducted from the cost of the PP&E in the period of the change. The liability accretes for the effect of time value of money until it is expected to settle. The asset retirement cost is amortized through DD&A over the life of the related asset. Actual asset retirement expenditures are recorded against the obligation when incurred. Any difference between the accrued liability and the actual expenditures incurred is recorded as a gain or loss in the settlement period.
Liabilities for environmental costs are recognized when a clean-up is probable and the associated costs can be reliably estimated. Environmental expenditures that relate to current or future revenues are expensed or capitalized as appropriate.
(m) Pension and Other Post-Retirement Benefits
Our employee post-retirement benefit programs consist of contributory and non-contributory defined benefit and defined contribution pension plans, as well as other post-retirement benefit programs.
For our defined benefit plans, we provide retirement benefits to employees based on their length of service and final average earnings. Benefits paid out of Nexen's defined benefit plan are indexed to 75% of the annual rate of inflation less 1% to a maximum increase of 5%. The cost of pension benefits earned by employees in our defined benefit pension plans is actuarially determined using the projected-benefit method prorated on service and our best estimate of the plans' investment performance, salary escalations and retirement ages of employees. To calculate the plans' expected returns, assets are measured at fair value. Fair value measurement of the defined benefit assets are limited to the sum of any recognized net actuarial losses and past service costs, and the net present value of any economic benefit available in the form of surplus refunds to the plan or reductions in future contributions to the plan. Vested past service costs arising from plan amendments are recognized in other comprehensive income (OCI) immediately. Unvested past service costs are amortized over the expected average service life until they become vested. Net actuarial gains and losses are included in OCI as incurred with immediate recognition in retained earnings.
Our defined contribution pension plan benefits are based on plan contributions. Company contributions to the defined contribution plan are expensed as incurred. Other post-retirement benefits include group life and supplemental health insurance for eligible employees and their dependants.
(n) Revenue Recognition
Revenue from the production of oil and gas is recognized when title passes to the customer. In Canada and the US, our customers primarily take title when the oil or gas reaches the end of the pipeline. For our other international operations, our customers generally take title when the crude oil is loaded onto tankers. When we sell more or less crude oil or natural gas than we produce, production overlifts and underlifts occur. We record overlifts as liabilities and underlifts as assets. We settle these over time as liftings are equalized or in cash when production ends.
Revenue represents Nexen's share and is recorded net of royalty obligations to governments and other mineral interest owners. For our international operations, all government interests, except for income taxes, are considered royalty obligations. Our revenue also includes the recovery of carried interest costs paid on behalf of foreign governments in international locations.
(o) Foreign Currency Translation
Our foreign operations, which are considered financially and operationally independent, are translated from their functional currency into Canadian dollars at the balance sheet date exchange rate for assets and liabilities and at the monthly average exchange rate for revenues and expenses. Gains and losses resulting from this translation are included in other comprehensive income.
We have designated our US-dollar debt as a hedge against our net investment in US-dollar self-sustaining foreign operations. Gains and losses resulting from the translation of the designated US-dollar debt are included in other comprehensive income. If our US-dollar debt, net of income taxes, exceeds our US-dollar investment in foreign operations, then the translation gains or losses attributable to such excess are included in marketing and other income.
Monetary balance sheet amounts denominated in a currency other than a functional currency are translated into the functional currency using exchange rates at the balance sheet dates. Gains and losses arising from this translation are included in marketing and other income. Non-monetary balance sheet amounts denominated in a currency other than a functional currency are translated using historical exchange rates at the time of the transaction.
(p) Transportation
We pay to transport the oil and gas products that we have sold and often bill our customers for the transportation. This transportation cost is included in as transportation and other expense. Amounts billed to our customers are presented within marketing and other income.
(q) Leases
We classify leases entered into as either finance or operating leases. Leases that transfer substantially all of the risks and benefits of ownership to us are capitalized as finance leases within PP&E and other liabilities. All other leases are recorded as operating leases and expensed as incurred within operating expenses.
(r) Stock-Based Compensation
Our stock-based compensation consists of tandem option (TOPs), stock appreciation right (STARs) and restricted share unit (RSUs) plans.
TOPs to purchase common shares are granted to officers and employees at the discretion of the board of directors. Each TOP gives the holder a right to either purchase one Nexen common share at the exercise price or to receive a cash payment equal to the excess of the market price of the common share over the exercise price. Options granted vest over three years and are exercisable on a cumulative basis over five years. At the time of the grant, the exercise price equals the market price of the common share. Beginning in 2010, certain options granted contain a performance vesting condition.
We record obligations for the outstanding TOPs using the fair-value method of accounting and recognize compensation expense in the consolidated statement of income. Obligations are accrued on a graded vesting basis and revalued each reporting period based on the change in the estimated fair value of the options outstanding. We reduce the liability when the options are surrendered for cash. When the options are exercised for stock, the accrued liability is transferred to share capital.
Under our STARs plan, employees are entitled to cash payments equal to the excess of market price of the common share over the exercise price of the right. The vesting period and other terms of the plan are similar to the TOPs plan and include a performance vesting condition for certain awards. At the time of grant, the exercise price equals market price of the common share. We account for STARs to employees on the same basis as our TOPs. Obligations are accrued as compensation expense over the graded vesting period of the STARs.
The fair value of each TOP and STAR is estimated using the Black-Scholes option pricing methodology, which takes into account share performance, market conditions, and other terms and conditions. For those awards that contain a performance vesting condition, we use the Monte Carlo option pricing model to simulate expected returns and estimate the fair value. This is applied to the reward criteria of the performance TOPs and STARs to give an expected value each measurement date.
Under our RSU plan, employees are entitled to receive a cash payment equal to the average closing market price of one common share for the 20 days prior to the vesting date for each RSU granted. All RSUs vest evenly over three years and are exercised and paid as they vest. The liability for RSUs is revalued each period based on the market price of our common shares and the number of graded vested RSUs outstanding.
For employees eligible to retire during the vesting period, the compensation expense is recognized over the period from the grant date to the retirement eligibility date on a graded vesting basis. In instances where an employee is eligible to retire on the grant date of the stock-based award, compensation expense is recognized in full at that date.
(s) Income Taxes
Income tax expense comprises current amounts payable and deferred tax. Income tax expense is recognized in net income except to the extent that it relates to items recognized directly in equity.
Current tax is the expected tax payable on the taxable income for the year, using tax rates enacted or substantively enacted at the reporting date, and any adjustment to taxes payable in respect of previous years. Current tax assets and liabilities are offset to the extent the entity has the legal right to settle on a net basis.
Deferred tax assets and liabilities are recognized for temporary differences between reported amounts for financial statement and tax purposes. Deferred tax is not recognized for the following temporary differences: i) initial recognition of tax assets or liabilities in a transaction that is not a business combination and that affects neither accounting nor taxable profit or loss, ii) differences relating to investments in subsidiaries to the extent that it is probable that they will not reverse in the foreseeable future, and iii) the initial recognition of goodwill. Deferred tax assets are only recognized for temporary differences, unused tax losses and unused tax credits if it is probable that future tax amounts will arise to utilize those amounts.
Deferred tax assets and liabilities are measured at tax rates that are expected to be applied to temporary differences when they reverse, based on the tax rates and laws that have been enacted or substantively enacted by the reporting date. Deferred tax assets and tax liabilities are offset to the extent there is a legal right to settle on a net basis.
We do not provide for foreign withholding taxes on the undistributed earnings of our foreign subsidiaries, as we intend to invest such earnings indefinitely in foreign operations.
(t) Changes in Accounting Policies
As part of our transition to IFRS, we will adopt 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 do not expect the impact of such changes to be material to the Unaudited Condensed Consolidated Financial Statements:
-- IFRS 9 Financial Instruments - in November 2009, the International
Accounting Standards Board (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, 2013.
Portions of the standard remain in development and the full impact of
the standard will not be known until the project is complete.
3. ACCOUNTS RECEIVABLE
March 31 December 31 January 1
2011 2010 2010
----------------------------------------------------------------------------
Trade
Energy Marketing 1,255 929 1,410
Oil and Gas 802 822 823
Other 4 2 44
---------------------------------------
2,061 1,753 2,277
Non-Trade 125 80 99
---------------------------------------
2,186 1,833 2,376
Allowance for Doubtful Receivables (41) (44) (54)
---------------------------------------
Total (1) 2,145 1,789 2,322
---------------------------------------
---------------------------------------
(1) At December 31, 2010, accounts receivable related to our chemicals
operations have been included with assets held for sale (see Note 15).
Receivables are generally on 30-day terms and are current as of March 31, 2011, December 31, 2010 and January 1, 2010.
4. INVENTORIES AND SUPPLIES
March 31 December 31 January 1
2011 2010 2010
----------------------------------------------------------------------------
Finished Products
Energy Marketing 415 452 548
Oil and Gas 24 35 25
Other - - 12
---------------------------------------
439 487 585
Work in Process 5 5 7
Field Supplies 58 58 88
---------------------------------------
Total (1) 502 550 680
---------------------------------------
---------------------------------------
(1) At December 31, 2010, inventories and supplies related to our chemicals
operations have been included with assets held for sale (see Note 15).
5. PROPERTY, PLANT AND EQUIPMENT
(a) Carrying amount of PP&E
Exploration Producing
and Assets 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 1,021 708 1,104 240 3,073
Disposals/
Derecognitions (70) (8) (1,638) (122) (1,838)
Transfers (82) 78 4 - -
Exploration
Expense (219) - (2) - (221)
Transferred to
Held for Sale - - - (1,207) (1,207)
Effect of Changes
in Exchange Rate (51) (75) (603) (3) (732)
--------------------------------------------------------
As at December 31,
2010 2,992 1,748 18,885 757 24,382
Additions 202 135 159 17 513
Disposals/
Derecognitions (37) - (1) (7) (45)
Transfers (42) 39 3 - -
Exploration
Expense (65) - - - (65)
Effect of Changes
in Exchange Rate (24) (40) (246) (4) (314)
--------------------------------------------------------
As at March 31,
2011 3,026 1,882 18,800 763 24,471
--------------------------------------------------------
--------------------------------------------------------
Accumulated 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)
Impairment Losses - - 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 13 - 336 21 370
Disposals/
Derecognitions (4) - - (4) (8)
Other - - (16) 1 (15)
Effect of Changes
in Exchange Rate (6) - (190) (1) (197)
--------------------------------------------------------
As at March 31,
2011 334 - 9,184 435 9,953
--------------------------------------------------------
--------------------------------------------------------
Net Book Value
As at January 1,
2010 2,033 1,034 10,695 907 14,669
--------------------------------------------------------
--------------------------------------------------------
As at December 31,
2010 2,661 1,748 9,831 339 14,579
--------------------------------------------------------
--------------------------------------------------------
As at March 31,
2011 2,692 1,882 9,616 328 14,518
--------------------------------------------------------
--------------------------------------------------------
Exploration and evaluation assets mainly comprise of unproved properties and capitalized exploration drilling costs. Assets under construction include our Usan development, offshore Nigeria.
(b) Impairment
Our 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 reduced properties estimated future cash flows, which resulted in impairments for properties in the US Gulf of Mexico and Canada.
These properties were written down to their estimated fair value based on their estimated future discounted net cash flows. The estimated future cash flows incorporate a risk-adjusted discount rate and management's estimates of future prices, capital expenditures and production.
6. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES
March 31 December 31 January 1
2011 2010 2010
----------------------------------------------------------------------------
Energy Marketing Payables 1,208 1,016 1,366
Accrued Payables 708 676 619
Income Taxes Payable 427 345 179
Trade Payables 191 164 210
Stock-Based Compensation 131 111 173
Other 281 147 134
---------------------------------------
Total (1) 2,946 2,459 2,681
---------------------------------------
---------------------------------------
(1) At December 31, 2010, accounts payable and accrued liabilities related
to our chemicals operations have been included with assets held for sale
(see Note 15).
7. LONG-TERM DEBT
March 31 December 31 January 1
2011 2010 2010
----------------------------------------------------------------------------
Term Credit Facilities, due 2014 (a) - - 1,570
Notes, due 2013 (US$500 million) (b) 534 497 523
Notes, due 2015 (US$126 million) (c) 122 249 262
Notes, due 2017 (US$62 million) (c) 60 249 262
Notes, due 2019 (US$300 million) 292 298 314
Notes, due 2028 (US$200 million) 194 199 209
Notes, due 2032 (US$500 million) 486 497 523
Notes, due 2035 (US$790 million) 768 786 827
Notes, due 2037 (US$1,250 million) 1,215 1,243 1,308
Notes, due 2039 (US$700 million) 680 696 733
Subordinated Debentures, due 2043
(US$460 million) 447 457 481
---------------------------------------
4,798 5,171 7,012
Unamortized debt issue costs (74) (81) (88)
---------------------------------------
4,724 5,090 6,924
Canexus debt - - 335
Current Portion of Long-Term Debt (534) - -
---------------------------------------
Total 4,190 5,090 7,259
---------------------------------------
---------------------------------------
(a) Term credit facilities
We have unsecured term credit facilities of $3 billion (US$3 billion) available until 2014 none of which were drawn at either March 31, 2011 or December 31, 2010. 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. During the three months ended March 31, 2011, we did not incur any interest expense on our term credit facilities. The weighted-average interest rate on our term credit facilities for the three months ended March 31, 2010 was 0.9%. At March 31, 2011, $394 million (US$405 million) of these facilities were utilized to support outstanding letters of credit (December 31, 2010 - $322 million (US$324 million)).
(b) Redemption of Notes, due 2013
During the quarter, we notified holders of the US$500 million of bonds due in 2013 of early redemption in April 2011. At March 31, 2011, we included the bonds in current payables at the expected redemption price of $534 million and recorded a $51 million loss as the difference between amortized cost and the expected redemption price.
(c) Repurchase for Cancellation of Certain 2015 and 2017 Notes
During the quarter, 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 amortized cost and the redemption price.
(d) Short-term borrowings
Nexen has uncommitted, unsecured credit facilities of approximately $464 million (US$478 million), none of which were drawn at either March 31, 2011 or December 31, 2010. We utilized $52 million (US$54 million) of these facilities to support outstanding letters of credit at March 31, 2011 (December 31, 2010-$112 million (US$112 million)). Interest is payable at floating rates.
8. FINANCE EXPENSE
Three Months Ended March 31
2011 2010
----------------------------------------------------------------------------
Long-Term Debt Interest Expense 84 91
Accretion Expense related to Asset
Retirement Obligations (Note 9) 11 10
Other Interest Expense 7 4
----------------------------------
Total 102 105
Less: Capitalized at 6.5% (2010 - 5.2%) (28) (16)
----------------------------------
Total (1) 74 89
----------------------------------
----------------------------------
(1) Excludes interest expense related to our chemical operations (see Note
15).
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:
Three Months Ended Twelve Months Ended
March 31 2011 December 31 2010
----------------------------------------------------------------------------
ARO, Beginning of Period 1,571 1,432
Obligations Incurred with
Development Activities 9 81
Changes in Estimates 12 332
Obligations Related to Dispositions (2) (224)
Obligations Settled (13) (43)
Accretion 11 47
Effects of Changes in Foreign
Exchange Rate (7) (54)
----------------------------------------
ARO, End of Period 1,581 1,571
----------------------------------------
----------------------------------------
Of which:
Due within Twelve Months (1) 53 55
Due after Twelve Months 1,528 1,516
----------------------------------------
----------------------------------------
(1) Included in accounts payable and accrued liabilities.
ARO represents the present value of estimated remediation and reclamation costs associated with our PP&E. We have discounted the estimated asset retirement obligation using a weighted-average risk-free rate of 3.3% (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 $361 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 and joint ventures
The Unaudited Condensed Consolidated Financial Statements include the financial statements of Nexen Inc. and our subsidiaries as at March 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 three months ended March 31, 2011 and 2010.
Major subsidiaries Country of Principal
Incorporation Activities Ownership
----------------------------------------------------------------------------
Nexen Petroleum UK Limited United Kingdom Oil & Gas 100%
Nexen Ettrick UK Limited United Kingdom Oil & Gas 100%
Nexen Petroleum Nigeria Limited Nigeria Oil & Gas 100%
Nexen Petroleum Offshore USA Inc United States Oil & Gas 100%
Canadian Nexen Petroleum Yemen Yemen Oil & Gas 100%
Canadian Nexen Petroleum East Al
Hajr Canada Oil & Gas 100%
Nexen Petroleum Colombia Limited Jersey Oil & Gas 100%
Nexen Exploration Norge AS Norway Oil & Gas 100%
Nexen Med Hat-Hatton Partnership Canada Oil & Gas 100%
Nexen Crossfield Partnership Canada Oil & Gas 100%
Nexen Marketing Canada Marketing 100%
Nexen Energy Marketing USA Inc United States Marketing 100%
Joint Venture
Syncrude Canada Oil & Gas 7.23%
11. EQUITY
(a) Common Shares
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 March 31, 2011, there were 526,680,528 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 (December 31, 2010 - Nil; January 1, 2010 - Nil).
(b) Dividends
Dividends paid per common share for the three months ended March 31, 2011 were $0.05 per common share (three months ended March 31, 2010 - $0.05). Dividends paid to holders of common shares have been designated as "eligible dividends" for Canadian tax purposes. On April 26, 2011, the Board of Directors declared a quarterly dividend of $0.05 per common share, payable July 1, 2011 to the shareholders of record on June 10, 2011.
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. Our operating leases, transportation and storage commitments, and drilling rig commitments as at March 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 Ended March 31
2011 2010
----------------------------------------------------------------------------
Marketing Revenue, Net 51 83
Long Lake Purchased Bitumen Sales 3 28
Change in Fair Value of Crude Oil Put
Options (7) (16)
Interest 1 4
Foreign Exchange Gains (Losses) (22) 9
Other 23 11
----------------------------------
Total 49 119
----------------------------------
----------------------------------
14. INCOME TAXES
(a) Reconciliation of Effective Tax Rate to the Canadian Statutory Tax Rate
Three Months Ended March 31
2011 2010
----------------------------------------------------------------------------
Income from Continuing Operations before
Provision for Income Taxes 449 288
Provision for Income Taxes Computed at the
Canadian Statutory Rate 113 72
Add (Deduct) the Tax Effect of:
Foreign Tax Rate Differential 192 107
Higher (Lower) Tax Rates on Capital
Gains (7) (8)
Effect of Changes in Tax Rates (1) 270 -
Non-Deductible Expenses and Other (19) 6
----------------------------------
Provision for Income Taxes 549 177
----------------------------------
----------------------------------
Effective Tax Rate 122% 61%
----------------------------------
(1) Effective March 24, 2011, the UK government substantively enacted an
increase to the supplementary tax rate on our North Sea oil and gas
activities by 12%, which increased the statutory oil and gas income tax
rate to 62%. This rate change increased our deferred income tax
liabilities, resulting in a one-time non-cash charge of $270 million to
deferred tax expense.
At March 31, 2011, we had unrecognized deferred tax assets related to Nigerian investment tax credits totaling $553 million (March 31, 2010 - $378 million). These assets will be recognized for accounting purposes as it becomes more likely than not that they will be utilized.
15. DISCONTINUED OPERATIONS
In February 2011, we completed the sale of our 62.7% investment in Canexus Limited Partnership, which operates the chemicals business, for net proceeds of $458 million and realized a gain 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 of $828 million in the third quarter. The gain on sale and results of operations of these properties have been presented as discontinued operations.
March 31 March 31
2011 2010
--------------------------------------------
Chemicals Canada Chemicals Total
----------------------------------------------------------------------------
Revenues and Other Income
Net Sales 42 69 113 182
Other (1) - 7 7
Gain on Disposition 348 - - -
--------------------------------------------
389 69 120 189
Expenses
Operating 25 23 70 93
Depreciation, Depletion,
Amortization and Impairment 4 13 6 19
Transportation and Other 2 2 16 18
General and Administrative 2 4 10 14
Finance 2 1 1 2
--------------------------------------------
35 43 103 146
--------------------------------------------
Income before Provision for
Income Taxes 354 26 17 43
Provision for Deferred Income
Taxes 51 5 4 9
--------------------------------------------
Income before Non-Controlling
Interests 303 21 13 34
Less: Non-Controlling Interests 1 - 4 4
--------------------------------------------
Net Income from Discontinued
Operations, Net of Tax 302 21 9 30
--------------------------------------------
--------------------------------------------
Earnings Per Common Share
Basic 0.57 0.06
Diluted 0.57 0.06
--------------------------------------------
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 March 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.
16. CASH FLOWS
(a) Charges and credits to income not involving cash
Three Months Ended March 31
2011 2010
----------------------------------------------------------------------------
Depreciation, Depletion, Amortization and
Impairment 370 343
Finance 74 89
Stock-Based Compensation 27 2
Loss on Debt Redemption and Repurchase 90 -
Non-cash Items Included in Discontinued
Operations (290) 33
Provision for Income Taxes 549 177
Foreign Exchange 23 2
Other (5) 18
----------------------------------
Total 838 664
----------------------------------
----------------------------------
(b) Changes in non-cash working capital
Three Months Ended March 31
2011 2010
----------------------------------------------------------------------------
Accounts Receivable (328) (218)
Inventories and Supplies 21 113
Other Current Assets 8 73
Accounts Payable and Accrued Liabilities 415 333
----------------------------------
Total 116 301
----------------------------------
----------------------------------
Relating to:
Operating Activities 32 213
Investing Activities 84 88
----------------------------------
Total 116 301
----------------------------------
----------------------------------
17. 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 energy marketing businesses and ramped-up production at Long Lake. We report our segments to align with our key growth strategies, specifically, Conventional Oil and Gas, Oil Sands and Unconventional Gas. Prior period results have been revised to reflect the presentation changes made in the current period.
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 (Yemen, offshore West Africa, Colombia and Norway).
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 ownership of 7.23% of the Syncrude Joint Venture.
Unconventional 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. Canexus manufactures, markets and distributes industrial chemicals, principally sodium chlorate, chlorine, muriatic acid and caustic soda. In February 2011, we completed the sale of our 62.7% investment in Canexus. The results of our chemicals business have been presented as discontinued operations.
The accounting policies of our operating segments are the same as those described in Note 2. Net income 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 March 31, 2011
Corporate
Conventional Oil Sands and Other Total
----------------------------------------------------------------------------
Other
United North Countries In
Kingdom America (1) Situ Syncrude
------------------------------------------
Net Sales 962 133 185 112 189 14 1,595
Marketing and
Other Income 16 2 4 3 - 24 49
-----------------------------------------------------------
978 135 189 115 189 38 1,644
Less: Expenses
Operating 98 40 35 107 75 8 363
Depreciation,
Depletion,
Amortization and
Impairment 182 105 25 29 16 13 370
Transportation
and Other - 4 5 18 6 34 67
General and
Administrative (12) 33 15 11 - 58 105
Exploration 4 59 63(2) - - - 126
Finance 5 4 - 1 1 63 74
Net Loss on
Debt
Redemption - - - - - 90 90
-----------------------------------------------------------
Income (Loss)
from Continuing
Operations before
Income
Taxes 701 (110) 46 (51) 91 (228) 449
Less: Provision
for (Recovery
of) Income Taxes 686 (31) (18) (13) 23 (98) 549
-----------------------------------------------------------
Income (Loss)
from Continuing
Operations 15 (79) 64 (38) 68 (130) (100)
Add: Net Income
from
Discontinued
Operations - - - - - 302 302
-----------------------------------------------------------
Net Income (Loss) 15 (79) 64 (38) 68 172 202
-----------------------------------------------------------
-----------------------------------------------------------
Capital
Expenditures 73 118 142 129 19 12 493
-----------------------------------------------------------
-----------------------------------------------------------
(1) Includes results of conventional crude oil and natural gas operations in
Yemen and Colombia.
(2) Includes exploration activities primarily in Yemen, Nigeria, Norway and
Colombia.
Segmented net income for the three months ended March 31, 2010
Corporate
Conventional Oil Sands and Other Total
----------------------------------------------------------------------------
Other
United North Countries In
Kingdom America (1) Situ Syncrude
------------------------------------------
Net Sales 755 161 197 63 134 9 1,319
Marketing and
Other Income 5 - 5 28 1 80 119
-----------------------------------------------------------
760 161 202 91 135 89 1,438
Less: Expenses
Operating 77 38 42 95 62 9 323
Depreciation,
Depletion,
Amortization and
Impairment 164 98 37 15 14 15 343
Transportation
and Other 3 5 3 51 7 124 193
General and
Administrative 13 19 9 4 - 64 109
Exploration 24 23 46(2) - - - 93
Finance 4 4 - 1 1 79 89
-----------------------------------------------------------
Income (Loss)
from Continuing
Operations
before Income
Taxes 475 (26) 65 (75) 51 (202) 288
Less: Provision
for (Recovery
of) Income Taxes 238 (7) (1) (19) 13 (47) 177
-----------------------------------------------------------
Income (Loss)
from Continuing
Operations 237 (19) 66 (56) 38 (155) 111
Add: Net Income
from
Discontinued
Operations - 21 - - - 9 30
-----------------------------------------------------------
Net Income (Loss) 237 2 66 (56) 38 (146) 141
-----------------------------------------------------------
-----------------------------------------------------------
Capital
Expenditures 123 145 139 64 24 65 560
-----------------------------------------------------------
-----------------------------------------------------------
(1) Includes results of conventional crude oil and natural gas operations in
Yemen and Colombia.
(2) (Includes exploration activities primarily in Yemen, Nigeria, Norway and
Colombia.
Segmented assets as at March 31, 2011
Corporate
Conventional Oil Sands and Other Total
----------------------------------------------------------------------------
United North Other
Kingdom America Countries In Situ Syncrude
----------------------------------------------
Identifiable
Assets 4,293 3,184 1,743 5,903 1,264 3,088 19,475
---------------------------------------------------------------
---------------------------------------------------------------
Property,
Plant and
Equipment
Cost 6,290 6,435 3,724 5,885 1,538 599 24,471
Less:
Accumulated
DD&A 3,151 3,630 2,342 116 374 340 9,953
---------------------------------------------------------------
Net Book
Value 3,139 2,805(1) 1,382(2) 5,769(3) 1,164 259 14,518
---------------------------------------------------------------
---------------------------------------------------------------
Goodwill 271 - - - - 9 280
---------------------------------------------------------------
---------------------------------------------------------------
(1) Includes capitalized costs associated with our Canadian shale gas
operations of $1,005 million.
(2) Includes $1,286 million related to our Usan development, offshore
Nigeria.
(3) Includes capitalized costs of $4,929 million for Long Lake Phase 1 and
capitalized costs of $840 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
----------------------------------------------
Identifiable
Assets 4,249 3,195 1,646 5,782 1,259 3,516 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 1,330 5,665 1,160 265 14,579
---------------------------------------------------------------
---------------------------------------------------------------
Goodwill 277 - - - - 9 286
---------------------------------------------------------------
---------------------------------------------------------------
Segmented assets as at January 1, 2010
Corporate
Conventional Oil Sands and Other Total
----------------------------------------------------------------------------
United North Other
Kingdom America Countries In Situ Syncrude
----------------------------------------------
Identifiable
Assets 4,840 3,146 1,320 5,616 1,165 4,868 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 2,864 957 5,516 1,071 835 14,669
---------------------------------------------------------------
---------------------------------------------------------------
Goodwill 292 - - - - 38 330
---------------------------------------------------------------
---------------------------------------------------------------
18. 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) 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 financial information using the accounting policies set out in Note 2. 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 adjust our financial statements to IFRS.
Elected Exemptions from Full Retrospective Application
In preparing these 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, which is included in accumulated other comprehensive income, 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 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 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 March 31 December 31
(Cdn$ millions) Note 2010 2010 2010
----------------------------------------------------------------------------
Shareholders' Equity under
Canadian GAAP 7,646 7,827 8,791
Differences increasing
(decreasing) reported
shareholders' equity:
Borrowing Costs (i) (841) (830) (778)
Asset Retirement
Obligations (ii) (228) (245) (241)
Employee Benefits (iii) (104) (104) (150)
Stock-Based Compensation (iv) (96) (104) (92)
Property, Plant & Equipment (v) (124) (116) (90)
Foreign Currency (vi) (11) (12) -
Long-term Debt (vii) (9) (13) (28)
Income Taxes (viii) 554 527 429
Other - (9) (27)
------------------------------------
Shareholders' Equity under
IFRS 6,787 6,921 7,814
------------------------------------
------------------------------------
(i) Borrowing Costs
We applied the IFRS 1 exemption to prospectively capitalize borrowing costs from the transition date as discussed 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 discussed 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 it's 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 were required on transition to IFRS.
Major Maintenance
Under 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.
(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 amortized 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 affects neither accounting nor taxable profit or loss.
Reconciliation of Net Income
----------------------------
(Cdn$ millions) March 31 December 31
For the year to date periods ended Note 2010 2010
----------------------------------------------------------------------------
Net Income under Canadian GAAP 185 1,197
Differences increasing (decreasing)
reported net income:
Borrowing Costs (i) 11 63
Asset Retirement Obligations (ii) (17) (13)
Stock-Based Compensation (iii) (9) 3
Property, Plant & Equipment (iv) 8 34
Long-term Debt (v) (4) (19)
Income Taxes (vi) (27) (136)
Other (6) (2)
--------------------------
Total Differences in Net Income (44) (70)
--------------------------
Net Income under IFRS 141 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 $30 million for the three months ended March 31, 2010 and lower by $117 million for the twelve months ended December 31, 2010.
Other
All other adjustments to IFRS net income were tax effected which increased deferred tax expense by $3 million for the three months ended March 31, 2010 and $19 million for the twelve months ended December 31, 2010.
Reconciliation of Comprehensive Income
--------------------------------------
(Cdn$ millions) March 31 December 31
For the year to date periods ended Note 2010 2010
----------------------------------------------------------------------------
Comprehensive income under Canadian
GAAP 174 1,168
Differences increasing (decreasing)
reported comprehensive income, net
of income taxes:
Differences in net income (44) (70)
Foreign currency translation (i) (2) (8)
Employee benefits (ii) - (35)
--------------------------
Comprehensive Income under IFRS 128 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, 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.
For investor relations inquiries, please contact:
Tim Chatten, P.Eng
Analyst, Investor Relations
(403) 699-4244
or
Kevin Reinhart
Chief Financial Officer
(403) 699-5931
or
For media and general inquiries, please contact:
Patti Lewis
Director, Corporate Communications
(403) 699-6119
or
Nexen Inc.
801 - 7th Ave SW
Calgary, Alberta, Canada T2P 3P7
www.nexeninc.com 
