Nexen Announces Third Quarter Results
CALGARY, ALBERTA -- (Marketwire) -- 10/28/10 -- Nexen Inc. announces third quarter cash flow of $485 million and net income of $537 million. Quarterly net income reflects the successful sales of our heavy oil properties in Canada and our North American natural gas marketing business.
We continue to focus on execution excellence in all areas of our portfolio. In the Horn River, we completed fracing, at an industry leading pace, the eight shale gas wells we drilled earlier this year, allowing us to start production here earlier than scheduled. At our Long Lake oil sands project, bitumen production volumes have doubled since the beginning of the year to over 31,500 bbls/d. On the conventional side of our business, we have had major discoveries in each of our three key basins in the past 18 months-Golden Eagle area in the North Sea, Owowo, offshore West Africa and Appomattox in the deep-water Gulf of Mexico, where we recently announced a gross resource estimate in excess of 250 million boe.
With production growth from Long Lake, the start up of new Horn River production in the fourth quarter and Usan on schedule to start in 2012, we are on track to deliver 70,000 boe/d of new production over the next two years. In addition, we are continuing discussions with the Yemen government on a contract extension for the Masila block. Golden Eagle, Appomattox, Knotty Head, Owowo, more shale gas and additional oil sands phases will contribute to future production volumes.
We have completed the sale of our heavy oil assets and our North American natural gas marketing business and increased our target of generating $1.0 billion from our non-core asset disposition program to $1.5 billion, with the sale of our investment in Canexus expected in the next year.
In the Gulf of Mexico, the drilling moratorium has been lifted, and we plan to move forward with the drilling of our exciting exploration prospects at Kakuna and Angel Fire and with the appraisal of our Appomattox discovery.
Third quarter highlights include:
- Quarterly cash flow of $485 million ($0.92/share) and net income of $537 million ($1.02/share)
- Quarterly production before royalties of 239,000 boe/d (213,000 boe/d after royalties)
- Long Lake gross bitumen production has increased from 16,000 to over 31,500 bbls/d since January
- Successful Horn River shale gas frac program at industry-leading pace
- Completed sale of Canadian heavy oil properties for exceptional metrics; generated proceeds of approximately $1 billion when combined with sale of North American natural gas marketing business
- Appomattox resource estimated to be in excess of 250 million boe gross
- Annual production guidance expected to be well within our range of between 230,000 and 280,000 boe/d (200,000 and 250,000 boe/d after royalties), while absorbing the impact of asset sales and unscheduled downtime in the North Sea
- Reduced net debt by over $1 billion since the beginning of the year
Quarterly Results
Three Months Ended Nine Months Ended
September 30 September 30
----------------------------------------
(Cdn$ millions) 2010 2009 2010 2009
----------------------------------------------------------------------------
Production (mboe/d)
Before Royalties 239 214 246 235
After Royalties 213 184 218 206
Cash Flow from Operations(1) 485 379 1,583 1,379
Per Common Share ($/share)(1) 0.92 0.73 3.02 2.65
Net Income 537 122 977 277
Per Common Share ($/share) 1.02 0.23 1.86 0.53
Capital Investment(2,3) 623 671 2,025 2,933
Net Debt(4) 4,468 5,532 4,468 5,532
1. For reconciliation of this non-GAAP measure, see Cash Flow from
Operations on pg. 9.
2. Includes geological and geophysical expenditures.
3. Q1 2009 includes $755 million for the acquisition of an additional 15%
interest in Long Lake from our partner.
4. Net debt is defined as long-term debt and short-term borrowings less
cash and cash equivalents.
Quarterly cash flow from operations was $485 million and net income was $537 million. In comparison to the same quarter last year, our cash flow has increased from stronger production and commodity prices. Quarterly net income reflected a net gain of $522 million ($414 million after tax) on the successful completion of non-core asset sales.
Our net debt is down over $1 billion from a year ago as a result of assets sales. Even with these asset sales, we are currently producing between 245,000 and 255,000 boe/d, which is similar to our 2009 annual volumes. We expect our net debt to decline further once we sell our Canexus interest.
Quarterly Production
Quarterly Quarterly
Production before Production
Royalties after Royalties
Crude Oil, NGLs
and Natural Gas
(mboe/d) Q3 2010 Q2 2010 Q3 2010 Q2 2010
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North Sea 111 105 111 105
Yemen 41 41 23 22
United States 27 26 24 23
Canada - Oil & Gas 19 20 17 17
Canada - Syncrude 19 23 18 22
Canada - Bitumen 17 16 16 15
Other Countries 2 2 2 2
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236 233 211 206
Canadian Heavy oil
production sold 3 15 2 12
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Total 239 248 213 218
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For the third quarter, production excluding the sale of heavy oil volumes grew from 233,000 boe/d to 236,000 boe/d compared to the previous quarter. Production grew despite the eight weeks of downtime at Scott/Telford in the North Sea to allow the operator of the Forties pipeline to repair a valve failure. Production here has returned at rates of about 20,000 boe/d net to us.
At Buzzard, quarterly volumes were 195,000 boe/d gross (84,000 boe/d net to us) up from 165,000 boe/d (71,000 boe/d net to us). In the second quarter, production from Buzzard was impacted by a three-week shutdown to install the fourth platform topsides and complete repairs to the main separator unit. We are progressing towards the start up of the new platform and fourth quarter Buzzard volumes are expected to be approximately 70 to 90% of normal. Production is expected to return to full rates around year end. Elsewhere in the North Sea, Ettrick is performing well and we produced 19,000 boe/d net to us, compared to 14,000 boe/d in the previous quarter.
At Long Lake, quarterly bitumen volumes were 26,000 boe/d gross (17,000 boe/d net to us), compared to 25,000 boe/d gross (16,000 boe/d net) in the previous quarter. Production ramp up over the summer was impacted by downtime related to SAGD well optimization activities (such as electric submersible pump (ESP) upsizes and acid stimulations) and temporary steam interruptions. These interruptions were caused by unplanned upgrader downtime related to the air separation unit and power outages caused by a lightning strike. We are back on-stream and are producing over 31,500 bbls/d.
At Syncrude, production was down for a scheduled turnaround late in the third quarter. This turnaround is now complete and no further downtime is scheduled at Syncrude this year.
'We are on track to be well within our original annual production guidance range of 230,000 to 280,000 boe/d,' stated Marvin Romanow, Nexen's President and Chief Executive Officer. 'And we continue to be on track to deliver new production volumes of approximately 70,000 boe/d over the next two years from Long Lake, Usan and shale gas.'
Sale of Heavy Oil Assets and North American Natural Gas Marketing Business Complete
During the quarter, we completed the sale of our heavy oil properties in Western Canada for approximately $975 million. These properties produced approximately 15,000 boe/d in the second quarter and had proved reserves of 39 million boe at December 31, 2009. We also completed the sale of our North American natural gas marketing business during the quarter.
'We have achieved excellent value on the sale of our non-core assets,' said Romanow. 'We now expect to generate approximately $1.5 billion from all asset sales, once we complete our disposition program which includes the sale of our interest in Canexus over the next twelve months. The proceeds will be used to develop the strong success we are having across our portfolio.'
Long Lake-Bitumen Production Over 31,500 bbls/d
Bitumen production to feed the upgrader continues to ramp up following the completion of the turnaround last fall. We have improved steam reliability and are continuously optimizing our wells. The resulting improvements in well capability have enabled us to increase our steam injection to 165,000 bbls/d and bitumen production volumes to over 31,500 bbls/d our highest rate yet. 78 of 91 well pairs are now on production and steam is circulating in an additional 6 pairs. These circulating wells will be converted to production in the coming months.
The table below shows gross monthly bitumen production volumes for the current year.
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Month Long Lake Monthly Bitumen Volumes Gross
(bbls/d)
----------------------------------------------------------------------------
January 2010 16,300
February 2010 17,700
March 2010 21,900
April 2010 24,400
May 2010 23,600
June 2010 26,900
July 2010 28,700
August 2010 26,500
September 2010 24,000
October 2010-MTD 30,000
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'As volumes continue to increase, Long Lake is approaching breakeven and we expect to generate positive cash flow shortly,' stated Romanow. 'This will be an important milestone and shows the future cash generating ability of Long Lake as we continue to ramp up.'
As we provide consistent steam to the reservoir, we are focusing on optimizing steam injection and individual well performance. To support increased well productivity, we have converted 65 wells from gas lift to ESP. The remainder will be converted in due course. This provides us with more flexibility to optimize steam injection and grow bitumen production. In addition, we have taken the opportunity to upsize the ESPs in our best producers. We have recently completed our first set of acid stimulations on 8 producing wells. These optimizations allow us to draw more fluids into the wells, increasing bitumen production. Third quarter production volumes were impacted as we shut in these wells to complete these activities.
Following the turnaround late last year, production volumes returned to pre-turnaround rates in December. Since that time, we have made the following progress:
- Steam injection has increased from 100,000 bbls/d to 165,000 bbls/d;
- Bitumen production has doubled to over 31,500 bbls/d;
- The number of wells producing at an average of design rates has increased from 10 to 24; and
- The all-in steam-to-oil ratio (SOR) has decreased from approximately 6 to 5.2. This includes 51 wells that are still in the steam circulation stage or early in their growth cycle. As these wells transition to SAGD production, the increase in production rates will result in a continued decrease in SOR.
As previously announced, we have a number of initiatives underway to increase bitumen volumes. These include:
- Bringing on the remaining 13 wells to SAGD production;
- Completing our ESP conversion program;
- Optimizing producing wells; and
- Developing two additional well pads and engineering two more once-through steam generators, which will add 10 to 15% to our steam capacity. We expect these to be available over the next 18 to 24 months.
We are committed to the development of our significant oil sands resource and plan to develop the next phase in two smaller SAGD stages of about 40,000 bbls/d each with upgrading available after ramp up.
'Developing the next phase of our oil sands in smaller SAGD stages with sequenced upgrading will lead to faster ramp ups,' added Romanow. 'This sequenced approach allows us to spread our capital investment over a longer period since two-thirds of the capital investment is in the upgrader.'
Global Exploration-Moratorium Lifted in the Gulf of Mexico
United States
The drilling moratorium in the Gulf of Mexico was lifted earlier this month and we are working to recommence exploration and appraisal drilling. The moratorium had no impact on our shelf and deep-water production and rig stand-by costs are expected to be minimal. Throughout the duration of the moratorium the first of our deep-water rigs was used by a co-contractor and on the second rig, we are close to completing discussions with the rig provider regarding our contract.
In the first quarter, we made a significant discovery in the deep-water at Appomattox, located in Mississippi Canyon blocks 391 and 392. Drilling activities resulted in an oil discovery with excellent reservoir quality following an exploration well and two appraisal sidetracks. Based on the results of this drilling, our estimate of recoverable contingent resource for this discovery exceeds 250 million barrels of oil equivalent (gross) with upside potential. We plan to further appraise this discovery once permits are received.
Appomattox is the third discovery in the area following earlier discoveries at Shiloh and Vicksburg. Our drilling plans also include further appraisal at Vicksburg which is located six miles east of Appomattox and has the potential to be co-developed. We have a 25% interest in Vicksburg and a 20% interest in Appomattox and Shiloh. Shell Offshore Inc. operates all three discoveries.
Our plans to drill two additional exploration wells this year (Kakuna and Angel Fire) with our two new deep-water drilling rigs were delayed by the drilling moratorium. We have submitted applications for permits to drill these two exciting prospects.
'We have an exciting inventory of prospects and discoveries in the Gulf of Mexico. Our discovery at Appomattox is world class and has the potential to be our best discovery ever here,' commented Romanow. 'We are working to further delineate the significant upside identified by this discovery.'
North Sea
During the quarter, we commenced activities on the West Rochelle and Polecat prospects and are evaluating drilling results. At West Rochelle, we have successfully confirmed gas and oil pay in an excellent quality reservoir and are sidetracking the well to further delineate the discovery. This well is a potential tieback to Scott. Polecat is a potential tieback to Buzzard. We plan to drill the Bluebell prospect before year end, a potential southerly extension of the Buzzard field.
Elsewhere in the North Sea, we continue to expand our acreage position in the Golden Eagle area, which includes our discoveries at Golden Eagle, Hobby and Pink. Our current estimate of recoverable contingent resource here is 150 million boe or more (over 55 million boe, net to us). We intend to drill an exploration well here early next year. Golden Eagle area development supports standalone facilities and is economic with oil prices significantly lower than they are currently. We are advancing area development plans, doing initial engineering and preparing cost estimates for sanctioning in 2011. We have a 34% interest in both Golden Eagle and Hobby, a 46% interest in Pink, and operate all three. Earlier this week, the UK Government announced that, subject to completion of the award process, we were the successful applicant for 10 licenses covering 18 blocks in the UK North Sea 26th Offshore Oil and Gas Licensing Round. Most of these blocks are near our existing acreage and infrastructure, and will enhance our ongoing exploration program where we are having a great deal of success.
Conventional Development-Usan Development Continues
Offshore West Africa
Development of the Usan field is progressing well with first production on-track for 2012. The development includes a floating production, storage and offloading (FPSO) vessel with the ability to process 180,000 bbls/d (36,000 bbls/d net to us) and store up to two million barrels of oil. Major topside modules have been lifted onto the FPSO deck and the FPSO unit is 88% complete. We have a 20% interest in exploration and development on this block and Total E&P Nigeria Limited is the operator.
We continue to explore offshore West Africa and previously announced a successful exploration well at Owowo in the southern portion of Oil Prospecting License (OPL) 223. We have an 18% interest in this discovery.
'Usan is a significant step-change in our production growth, adding 36,000 boe/d of the 70,000 boe/d that we expect to bring on stream over the next two years,' stated Romanow. 'As we move forward here, our success at Owowo makes us more optimistic about the other exploration prospects.'
Shale Gas-Industry Leading Program Execution
During the quarter, we completed a 144 frac program on our eight-well pad in the Horn River at an industry-leading pace of 3.5 fracs per day with a 100% frac success rate. Earlier this year, we completed our drilling campaign here at an average rate of under 25 days per well. Compared to our previous program, these wells were drilled in 35% fewer days and were 80% longer. We recently started production testing these wells and expect to reach peak production rates of 50 mmcf/d this winter. We plan to follow up this successful program with a nine well pad that would start drilling this winter. The wells would be fraced and completed next summer with first production in the fourth quarter of 2011. This allows us to advance our Horn River play while we progress our plans for an 18-well pad to be drilled next winter with first production expected in late 2012.
'Our performance in the Horn River continues to be top quartile with the successful execution of our drilling and frac strategies. This type of execution will lead to higher returns on this business,' commented Romanow. 'This play is expected to earn a ten percent rate of return with gas prices at US$4/mcf.'
We have approximately 90,000 acres at Dilly Creek in the Horn River basin. As previously announced, our Dilly Creek lands contain between 3 and 6 trillion cubic feet (0.5 to 1.0 billion barrels of oil equivalent) of recoverable contingent resource, assuming a 20% recovery factor. Following our success at a June land sale, we now have over 300,000 acres of highly prospective shale gas lands in the Horn River, Cordova and Liard basins in northeast British Columbia.
Say on Pay
During the past year, we have monitored governance developments with respect to say on pay. With recent guidance from the SEC, we plan to offer shareholders an opportunity to provide input on our approach to executive compensation with a non-binding say on pay advisory vote at our 2011 annual general meeting.
Quarterly Dividend
The Board of Directors has declared the regular quarterly dividend of $0.05 per common share payable January 1, 2011, to shareholders of record on December 10, 2010. Shareholders are advised that the dividend is an eligible dividend for Canadian Income Tax purposes.
Nexen Inc. is an independent, Canadian-based global energy company, listed on the Toronto and New York stock exchanges under the symbol NXY. We are focused on three growth strategies: oil sands and unconventional gas in Western Canada and conventional exploration and development primarily in the North Sea, offshore West Africa and deep-water Gulf of Mexico. We add value for shareholders through successful full-cycle oil and gas exploration and development, and leadership in ethics, integrity, governance and environmental stewardship.
Information on our previously announced recoverable contingent shale gas, Golden Eagle area and Appomattox resource were provided in our press releases dated April 22, 2008, September 3, 2009, and September 27, 2010 respectively. Information with respect to forward-looking statements and cautionary notes is set out below.
Conference Call
Marvin Romanow, President and CEO, and Kevin Reinhart, Executive Vice President and CFO, will host a conference call to discuss our third quarter financial and operating results and expectations for the future.
Date: October 28, 2010
Time: 7:00am Mountain Time (9:00am Eastern Time)
To listen to the conference call, please call one of the following:
416-695-6616 (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 9:00am Mountain Time, by calling 416-695-5800 (Toronto) or 800-408-3053 (toll-free) passcode 5026270 followed by the pound sign.
A live and on demand webcast of the conference call will be available at www.nexeninc.com.
Forward-Looking Statements
Certain statements in this report constitute 'forward-looking statements' (within the meaning of the United States Private Securities Litigation Reform Act of 1995) 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 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; development plans or capacity expansions; the expectation that we have the ability to substantially grow production at our oilsands facilities through controlled expansions; the expectation of achieving the production design rates from our oilsands facilities; the expectation that our oilsands production facilities continue to develop better and more sustainable practices; the expectation of cheaper and more technologically advanced 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; 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; 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.
The forward-looking statements are subject to known and unknown risks and uncertainties and other factors which may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Such factors include, among others: market prices for oil and gas and chemicals products; our ability to explore, develop, produce, upgrade and transport crude oil and natural gas to markets; ultimate effectiveness of design or design modifications to facilities; the results of exploration and development drilling and related activities; the cumulative impact of oilsands 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 operation 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 oilsands production facilities; labour and material shortages; risk related to accidents, blowouts and spills in connection with our offshore exploration, development and production activities, particularly our deepwater activities; direct and indirect risk related to the imposition of moratoriums, suspensions or cancellations on 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 of our agents and contractors; 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; and 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 statements contained herein, which are made as of the date hereof and, except as required by law, Nexen undertakes no obligation to update publicly or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The forward-looking statements contained herein are expressly qualified by this cautionary statement. Readers should also refer to Items 1A and 7A in our 2009 Annual Report on Form 10-K and Part II, Item 1A in our second quarter 2010 Quarterly Report on Form 10-Q for further discussion of the risk factors.
Cautionary Note to US Investors
In this disclosure, we may refer to 'recoverable reserves', 'recoverable resources' and 'recoverable contingent 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 Report on Form 10-K available from us or the SEC for further reserve disclosure.
Cautionary Note to Canadian Investors
Nexen is an SEC registrant and a voluntary Form 10-K (and related forms) filer. Therefore, our reserves estimates and securities regulatory disclosures follow SEC requirements. In Canada, National Instrument 51-101-Standards of Disclosure for Oil and Gas Activities (NI 51-101) prescribes that Canadian companies follow certain standards for the preparation and disclosure of reserves and related information. Nexen's reserves disclosures are made in reliance upon exemptions granted to it by Canadian securities regulators from certain requirements of NI 51-101 which permits us to:
- prepare our reserves estimates and related disclosures in accordance with SEC disclosure requirements, generally accepted industry practices in the US and the Canadian Oil and Gas Evaluation Handbook (COGE Handbook) standards modified to reflect SEC requirements;
- substitute those SEC disclosures for much of the annual disclosure required by NI 51-101; and
- rely upon internally-generated reserves estimates and the Standardized Measure of Discounted Future Net Cash Flows and Changes Therein, included in the Supplementary Financial Information, without the requirement to have those estimates evaluated or audited by independent qualified reserves consultants.
As a result of these exemptions, Nexen's disclosures may differ from other Canadian companies and Canadian investors should note the following fundamental differences in reserves estimates and related disclosures contained in the Form 10-K:
- SEC registrants apply SEC reserves definitions and prepare their reserves estimates in accordance with SEC requirements and generally accepted industry practices in the US whereas NI 51-101 requires adherence to the definitions and standards promulgated by the COGE Handbook;
- the SEC's technical rules in estimating reserves differ from NI 51-101 in areas such as the use of reliable technology, aerial 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 12-month average prices and costs only whereas NI 51-101 requires disclosure of reserves and related future net revenues using forecast prices;
- the SEC mandates disclosure of reserves by geographic area only whereas NI 51-101 requires disclosure of more reserve categories and product types;
- the SEC prescribes certain information about proved and probable undeveloped reserves and future developments costs whereas NI 51-101 requirements are different;
- the SEC does not require disclosure of finding and development (F&D) costs per boe of proved reserves additions whereas NI 51-101 requires that various F&D costs per boe and additional information be disclosed;
- the SEC leaves the engagement of independent qualified reserves consultants to the discretion of a company's board of directors whereas NI 51-101 requires issuers to engage such evaluators;
- the SEC does not allow proved and probable reserves to be aggregated whereas NI 51-101 requires issuers disclose such; and
- the reserves disclosures in this document have not been reviewed by the independent qualified reserves consultants whereas NI 51-101 requires them to review it.
The foregoing is a general description of the principal differences only. The differences between SEC requirements and NI 51-101 may be material.
NI 51-101 requires that we make the following disclosures:
- we use oil equivalents (boe) to express quantities of natural gas and crude oil in a common unit. A conversion ratio of 6 mcf of natural gas to 1 barrel of oil is used. Boe may be misleading, particularly if used in isolation. The conversion ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead; and
- because reserves data are based on judgments regarding future events actual results will vary and the variations may be material. Variations as a result of future events are expected to be consistent with the fact that reserves are categorized according to the probability of their recovery.
Resources
Nexen's estimates of contingent resources are based on definitions set out in the Canadian Oil and Gas Evaluation Handbook which generally describe contingent resources as those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Such contingencies may include, but are not limited to, factors such as economic, legal, environmental, political and regulatory matters or a lack of markets. Specific contingencies precluding these contingent resources being classified as reserves include but are not limited to: future drilling program results, drilling and completions optimization, stakeholder and regulatory approval of future drilling and infrastructure plans, access to required infrastructure, economic fiscal terms, a lower level of delineation, the absence of regulatory approvals, detailed design estimates and near-term development plans, and general uncertainties associated with this early stage of evaluation. The estimated range of contingent resources reflects conservative and optimistic likelihoods of recovery. However, there is no certainty that it will be commercially viable to produce any portion of these contingent resources.
Nexen's estimates of discovered resources (equivalent to discovered petroleum initially-in-place) are based on definitions set out in the Canadian Oil and Gas Evaluation Handbook which generally describe discovered resources as those quantities of petroleum estimated, as of a given date, to be contained in known accumulations prior to production. Discovered resources do not represent recoverable volumes. We disclose additional information regarding resource estimates in accordance with NI 51-101. These disclosures can be found on our website and on SEDAR.
Cautionary statement: In the case of discovered resources or a subcategory of discovered resources other than reserves, there is no certainty that it will be commercially viable to produce any portion of the resources. In the case of undiscovered resources or a subcategory of undiscovered resources, there is no certainty that any portion of the resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the resources.
Nexen Inc.
Financial Highlights
Three Months Nine Months
Ended September 30 Ended September 30
(Cdn$ millions) 2010 2009 2010 2009
----------------------------------------------------------------------------
Net Sales (1) 1,429 1,097 4,385 3,345
Cash Flow from Operations (1) 485 379 1,583 1,379
Per Common Share ($/share) 0.92 0.73 3.02 2.65
Net Income (1) 537 122 977 277
Per Common Share ($/share) 1.02 0.23 1.86 0.53
Capital Investment (2) 623 671 2,025 2,933
Net Debt (3) 4,468 5,532 4,468 5,532
Common Shares Outstanding (millions
of shares) 525.0 521.8 525.0 521.8
----------------------------------------
(1) Includes discontinued operations as discussed in Note 15 to our
Unaudited 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 Nine Months
Ended September 30 Ended September 30
(Cdn$ millions) 2010 2009 2010 2009
----------------------------------------------------------------------------
Oil & Gas
United Kingdom 670 400 1,996 1,382
Yemen (2) 97 79 278 244
Syncrude 53 70 192 98
United States 57 34 193 87
Canada (3) (34) 23 (18) 85
Other Countries 3 13 13 30
Marketing - 29 (42) 147
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846 648 2,612 2,073
Chemicals 14 29 46 84
----------------------------------------
860 677 2,658 2,157
Interest and Other Corporate Items (148) (147) (407) (369)
Income Taxes (4) (227) (151) (668) (409)
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Cash Flow from Operations (1) 485 379 1,583 1,379
----------------------------------------
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(1) Defined as cash flow from operating activities before changes in
non-cash working capital and other. We evaluate our performance and that
of our business segments based on earnings and cash flow from
operations. Cash flow from operations is a non-GAAP term that represents
cash generated from operating activities before changes in non-cash
working capital and other and excludes items of a non-recurring nature.
We consider it a key measure as it demonstrates our ability and the
ability of our business segments to generate the cash flow necessary to
fund future growth through capital investment and repay debt. Cash flow
from operations may not be comparable with the calculation of similar
measures for other companies.
Three Months Nine Months
Ended September 30 Ended September 30
(Cdn$ millions) 2010 2009 2010 2009
----------------------------------------------------------------------------
Cash Flow from Operating Activities 668 461 1,976 1,359
Changes in Non-Cash Working Capital (212) (113) (410) (193)
Other 39 49 47 234
Impact of Annual Crude Oil Put
Options (10) (18) (30) (21)
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Cash Flow from Operations 485 379 1,583 1,379
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Weighted-average Number of Common
Shares Outstanding
(millions of shares) 525.0 521.7 524.4 521.0
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Cash Flow from Operations Per Common
Share ($/share) 0.92 0.73 3.02 2.65
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(2) After in-country cash taxes of $43 million for the three months ended
September 30, 2010 (2009 - $39 million) and $125 million for the nine
months ended September 30, 2010 (2009 - $105 million).
(3) Includes discontinued operations as discussed in Note 15 to our
Unaudited Consolidated Financial Statements.
(4) Excludes in-country cash taxes in Yemen.
Nexen Inc.
Production Volumes (before royalties) (1)
Three Months Nine Months
Ended September 30 Ended September 30
2010 2009 2010 2009
----------------------------------------------------------------------------
Crude Oil and Liquids (mbbls/d)
United Kingdom 106.3 73.7 103.4 91.6
Yemen 41.6 48.7 41.8 51.5
Syncrude 19.1 22.5 20.7 19.1
Long Lake Bitumen 16.7 5.5 15.0 7.6
United States 9.9 9.5 9.9 10.6
Canada (2) 2.9 14.2 10.0 14.9
Other Countries 2.0 2.6 2.1 3.9
----------------------------------------
198.5 176.7 202.9 199.2
----------------------------------------
Natural Gas (mmcf/d)
United Kingdom 27 17 36 18
United States 102 63 100 58
Canada (2) 113 143 124 139
----------------------------------------
242 223 260 215
----------------------------------------
Total Production (mboe/d) 239 214 246 235
----------------------------------------
----------------------------------------
Production Volumes (after royalties)
Three Months Nine Months
Ended September 30 Ended September 30
2010 2009 2010 2009
----------------------------------------------------------------------------
Crude Oil and Liquids (mbbls/d)
United Kingdom 106.3 73.7 103.4 91.6
Yemen 23.5 28.3 22.9 31.0
Syncrude 17.9 20.0 19.1 17.6
Long Lake Bitumen 16.0 5.5 14.3 7.6
United States 8.9 8.5 8.9 9.6
Canada (2) 2.3 10.9 7.7 11.6
Other Countries 1.9 2.4 2.0 3.6
----------------------------------------
176.8 149.3 178.3 172.6
----------------------------------------
Natural Gas (mmcf/d)
United Kingdom 27 17 36 17
United States 89 56 86 52
Canada (2) 104 137 114 130
----------------------------------------
220 210 236 199
----------------------------------------
Total Production (mboe/d) 213 184 218 206
----------------------------------------
----------------------------------------
(1) We have presented production volumes before royalties as we measure our
performance on this basis consistent with other Canadian oil and gas
companies.
(2) Includes the following production from discontinued operations in Note
15 to our Unaudited Consolidated Financial Statements.
Three Months Nine Months
Ended September 30 Ended September 30
2010 2009 2010 2009
----------------------------------------------------------------------------
Before Royalties
Crude Oil and NGLs (mbbls/d) 2.9 14.2 10.0 14.9
Natural Gas (mmcf/d) 2.2 13.2 8.3 13.7
After Royalties
Crude Oil and NGLs (mbbls/d) 2.3 10.9 7.7 11.6
Natural Gas (mmcf/d) 2.1 11.2 7.2 11.6
----------------------------------------
Nexen Inc.
Oil and Gas Prices and Cash Netback (1)
Total
(all dollar amounts Quarters - 2010 Quarters - 2009 Year
in Cdn$ unless --------------------------------------------------------
noted) 1st 2nd 3rd 1st 2nd 3rd 4th 2009
----------------------------------------------------------------------------
PRICES:
WTI Crude Oil
(US$/bbl) 78.71 78.03 76.20 43.08 59.62 68.30 76.19 61.80
Nexen Average - Oil
(Cdn$/bbl) 78.00 76.23 77.03 50.41 68.32 72.95 76.39 66.85
NYMEX Natural Gas
(US$/mmbtu) 5.04 4.34 4.24 4.48 3.81 3.44 4.91 4.16
Nexen Average - Gas
(Cdn$/mcf) 5.37 4.42 4.18 5.11 3.77 3.04 4.31 4.06
----------------------------------------------------------------------------
NETBACKS:
United Kingdom
Crude Oil:
Sales (mbbls/d) 106.5 102.1 103.9 100.8 97.0 70.4 119.6 96.9
Price Received
($/bbl) 77.25 77.18 77.45 51.60 69.42 73.15 76.40 67.70
Natural Gas:
Sales (mmcf/d) 33 41 29 21 17 17 43 24
Price Received
($/mcf) 4.81 4.80 5.11 5.50 3.67 2.64 3.82 3.95
Total Sales Volume
(mboe/d) 112.1 109.0 108.8 104.3 99.8 73.2 126.8 101.0
Price Received
($/boe) 74.84 74.12 75.35 50.97 68.10 70.95 73.39 65.93
Operating Costs 7.60 7.71 8.40 5.48 5.85 10.34 6.77 6.87
----------------------------------------------------------------------------
Netback 67.24 66.41 66.95 45.49 62.25 60.61 66.62 59.06
----------------------------------------------------------------------------
Canada - Heavy Oil
Sales (mbbls/d) 14.0 13.1 3.0 15.4 14.7 14.0 13.5 14.4
Price Received
($/bbl) 65.26 57.24 61.56 35.35 56.05 59.88 62.53 53.04
Royalties & Other 14.47 13.23 13.45 6.86 12.83 13.47 14.07 11.70
Operating & Other
Costs 15.81 16.02 18.49 15.42 16.41 16.21 16.73 16.17
----------------------------------------------------------------------------
Netback 34.98 27.99 29.62 13.07 26.81 30.20 31.73 25.17
----------------------------------------------------------------------------
Canada - Natural Gas
Sales (mmcf/d) 124 121 107 137 134 136 130 134
Price Received
($/mcf) 5.02 3.72 3.43 4.75 3.42 2.85 4.14 3.78
Royalties & Other 0.40 0.34 0.26 0.59 0.15 0.21 0.34 0.32
Operating Costs 1.70 1.89 1.90 1.54 1.59 1.82 2.10 1.76
----------------------------------------------------------------------------
Netback 2.92 1.49 1.27 2.62 1.68 0.82 1.70 1.70
----------------------------------------------------------------------------
Long Lake (2)
Sales (mbbls/d) 6.6 10.3 11.9 - - - - -
Price Received
($/bbl) 81.04 74.08 70.64 - - - - -
Royalties & Other 4.37 3.65 3.08 - - - - -
Operating Costs 155.40 88.39 85.20 - - - - -
----------------------------------------------------------------------------
Netback (2) (78.73) (17.96) (17.64) - - - - -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Syncrude
Sales (mbbls/d) 19.5 23.4 19.1 19.8 14.9 22.5 23.7 20.2
Price Received
($/bbl) 83.55 77.93 78.27 55.48 71.58 74.54 79.83 70.96
Royalties & Other 7.09 6.37 4.82 0.40 8.84 8.31 6.75 6.04
Operating Costs 38.43 33.33 41.49 36.95 57.21 29.50 27.93 35.92
----------------------------------------------------------------------------
Netback 38.03 38.23 31.96 18.13 5.53 36.73 45.15 29.00
----------------------------------------------------------------------------
(1) Defined as average sales price less royalties and other, operating
costs, and in-country taxes in Yemen.
(2) Excludes activities related to third-party bitumen purchased, processed
and sold.
Nexen Inc.
Oil and Gas Cash Netback (1) (continued)
Total
(all dollar amounts Quarters - 2010 Quarters - 2009 Year
in Cdn$ unless --------------------------------------------------------
noted) 1st 2nd 3rd 1st 2nd 3rd 4th 2009
----------------------------------------------------------------------------
United States
Crude Oil:
Sales (mbbls/d) 9.8 9.9 9.8 10.4 12.1 9.5 10.0 10.5
Price Received
($/bbl) 79.12 73.60 73.72 46.27 66.23 72.27 75.75 65.01
Natural Gas:
Sales (mmcf/d) 101 95 102 50 61 63 84 65
Price Received
($/mcf) 6.00 5.14 4.70 5.93 4.58 3.56 4.83 4.67
Total Sales Volume
(mboe/d) 26.6 25.8 26.9 18.8 22.2 20.0 23.9 21.2
Price Received
($/boe) 51.92 47.23 44.85 41.50 48.53 45.43 48.55 46.27
Royalties & Other 4.92 4.86 5.10 4.52 4.94 4.77 5.21 4.89
Operating Costs 8.96 10.90 9.44 13.79 13.11 12.40 11.32 12.58
----------------------------------------------------------------------------
Netback 38.04 31.47 30.31 23.19 30.48 28.26 32.02 28.80
----------------------------------------------------------------------------
Yemen
Sales (mbbls/d) 47.3 39.3 43.5 54.7 51.4 43.2 46.2 48.8
Price Received
($/bbl) 80.39 80.50 79.33 52.30 69.40 76.31 78.93 68.49
Royalties & Other 37.52 36.65 34.75 19.43 31.94 32.08 33.71 28.94
Operating Costs 9.67 10.01 9.46 9.62 10.39 12.43 10.62 10.69
In-country Taxes 10.14 10.97 10.70 4.92 9.01 9.70 10.17 8.31
----------------------------------------------------------------------------
Netback 23.06 22.87 24.42 18.33 18.06 22.10 24.43 20.55
----------------------------------------------------------------------------
Other Countries
Sales (mbbls/d) 2.3 2.1 2.0 5.5 3.6 2.6 2.4 3.5
Price Received
($/bbl) 78.88 74.77 75.93 41.68 66.83 70.49 74.10 59.05
Royalties & Other 5.72 5.28 5.22 3.26 5.17 5.38 5.48 4.52
Operating Costs 5.58 7.42 6.98 4.81 5.73 5.70 9.52 6.03
----------------------------------------------------------------------------
Netback 67.58 62.07 63.73 33.61 55.93 59.41 59.10 48.50
----------------------------------------------------------------------------
Company-Wide
Oil and Gas Sales
(mboe/d) 251.1 243.1 232.9 241.4 228.9 198.2 258.1 231.6
Price Received
($/boe) 70.16 67.46 68.21 47.56 61.28 63.00 68.04 60.02
Royalties & Other 9.32 8.14 7.96 5.64 9.23 9.58 8.09 8.06
Operating & Other
Costs 15.17 15.07 15.72 10.62 11.95 13.60 10.86 11.66
In-country Taxes 1.91 1.77 2.00 1.11 2.02 2.11 1.82 1.75
----------------------------------------------------------------------------
Netback 43.76 42.48 42.53 30.19 38.08 37.71 47.27 38.55
----------------------------------------------------------------------------
(1) Defined as average sales price less royalties and other, operating
costs, and in-country taxes in Yemen.
Nexen Inc.
Unaudited Consolidated Statement of Income
For the Three and Nine Months Ended September 30
Three Months Nine Months
(Cdn$ millions, except per share Ended September 30 Ended September 30
amounts) 2010 2009 2010 2009
----------------------------------------------------------------------------
Revenues and Other Income
Net Sales 1,416 1,034 4,247 3,176
Marketing and Other (Note 14) 138 296 373 635
---------------------------------------
1,554 1,330 4,620 3,811
---------------------------------------
Expenses
Operating 420 297 1,218 872
Depreciation, Depletion,
Amortization and Impairment 477 329 1,234 1,087
Transportation and Other 142 180 501 606
General and Administrative 132 108 316 363
Exploration 56 89 199 219
Interest (Note 9) 81 84 238 226
Net Loss from Dispositions
(Note 15) 259 - 179 -
---------------------------------------
1,567 1,087 3,885 3,373
---------------------------------------
Income (Loss) from Continuing
Operations before Provision for
Income Taxes (13) 243 735 438
---------------------------------------
Provision for (Recovery of) Income
Taxes
Current 270 190 793 514
Future (234) (81) (423) (390)
---------------------------------------
36 109 370 124
---------------------------------------
Net Income (Loss) from Continuing
Operations before
Non-Controlling Interests (49) 134 365 314
Less: Net Income Attributable to
Canexus Non-Controlling Interests (4) (12) (4) (17)
---------------------------------------
Net Income (Loss) from Continuing
Operations Attributable to
Nexen Inc. (53) 122 361 297
Net Income (Loss) from Discontinued
Operations (Note 15) 590 - 616 (20)
---------------------------------------
Net Income Attributable to
Nexen Inc. 537 122 977 277
---------------------------------------
---------------------------------------
Earnings (Loss) Per Common Share
from Continuing Operations
($/share) (Note 16)
Basic (0.10) 0.23 0.69 0.57
---------------------------------------
---------------------------------------
Diluted (0.10) 0.23 0.69 0.57
---------------------------------------
---------------------------------------
Earnings Per Common Share ($/share)
(Note 16)
Basic 1.02 0.23 1.86 0.53
---------------------------------------
---------------------------------------
Diluted 1.02 0.23 1.86 0.53
---------------------------------------
---------------------------------------
See accompanying notes to the Unaudited Consolidated Financial Statements.
Nexen Inc.
Unaudited Consolidated Balance Sheet
September 30 December 31
(Cdn$ millions, except share amounts) 2010 2009
----------------------------------------------------------------------------
Assets
Current Assets
Cash and Cash Equivalents 1,210 1,700
Restricted Cash 35 198
Accounts Receivable (Note 2) 2,305 2,788
Inventories and Supplies (Note 3) 544 680
Other 142 185
-----------------------------
Total Current Assets 4,236 5,551
-----------------------------
Property, Plant and Equipment
Net of Accumulated Depreciation, Depletion,
Amortization and Impairment of $10,414
(December 31, 2009 - $10,807) 15,835 15,492
Goodwill 316 339
Future Income Tax Assets 1,608 1,148
Deferred Charges and Other Assets (Note 5) 236 370
-----------------------------
Total Assets 22,231 22,900
-----------------------------
-----------------------------
Liabilities
Current Liabilities
Accounts Payable and Accrued Liabilities
(Note 8) 2,943 3,038
Accrued Interest Payable 78 89
Dividends Payable 26 26
-----------------------------
Total Current Liabilities 3,047 3,153
-----------------------------
Long-Term Debt (Note 9) 5,678 7,251
Future Income Tax Liabilities 3,127 2,811
Asset Retirement Obligations (Note 11) 1,007 1,018
Deferred Credits and Other Liabilities (Note 12) 766 1,021
Equity
Nexen Inc. Shareholders' Equity
Common Shares, no par value
Authorized: Unlimited
Outstanding: 2010 - 525,032,386 shares
2009 - 522,915,843 shares 1,097 1,049
Contributed Surplus - 1
Retained Earnings 7,621 6,722
Accumulated Other Comprehensive Loss (196) (190)
-----------------------------
Total Nexen Inc. Shareholders' Equity 8,522 7,582
Canexus Non-Controlling Interests 84 64
-----------------------------
Total Equity 8,606 7,646
Commitments, Contingencies and Guarantees
(Note 17)
-----------------------------
Total Liabilities and Equity 22,231 22,900
-----------------------------
-----------------------------
See accompanying notes to the Unaudited Consolidated Financial Statements.
Nexen Inc.
Unaudited Consolidated Statement of Cash Flows
For the Three and Nine Months Ended September 30
Three Months Nine Months
Ended September 30 Ended September 30
(Cdn$ millions) 2010 2009 2010 2009
----------------------------------------------------------------------------
Operating Activities
Net Income (Loss) from Continuing
Operations (49) 134 365 314
Net Income (Loss) from Discontinued
Operations 590 - 616 (20)
Charges and Credits to Income not
Involving Cash (Note 18) (102) 174 433 887
Exploration Expense 56 89 199 219
Changes in Non-Cash Working Capital
(Note 18) 212 113 410 193
Other (39) (49) (47) (234)
---------------------------------------
668 461 1,976 1,359
Financing Activities
Repayment of Short-Term Borrowings,
Net (156) (1) - (1)
Proceeds from Long-Term Notes - 1,081 - 1,081
Proceeds from (Repayment of) Term
Credit Facilities, Net (463) (915) (1,540) 728
Proceeds from (Repayment of)
Canexus Term Credit Facilities,
Net (4) (4) 64 48
Proceeds from Canexus Debentures 60 46 60 46
Dividends Paid on Common Shares (26) (26) (78) (78)
Distributions Paid to Canexus
Non-Controlling Interests (6) (4) (13) (11)
Issue of Common Shares and Exercise
of Tandem Options for Shares 9 12 44 42
Other (2) (18) (15) (19)
---------------------------------------
(588) 171 (1,478) 1,836
Investing Activities
Capital Expenditures
Exploration and Development (554) (586) (1,793) (1,921)
Proved Property Acquisitions - - - (755)
Energy Marketing, Chemicals,
Corporate and Other (38) (69) (172) (198)
Proceeds from Dispositions 950 2 1,046 17
Changes in Non-Cash Working Capital
(Note 18) (105) 14 (30) (41)
Changes in Restricted Cash (43) 93 40 (154)
Other (1) (15) (8) (16)
---------------------------------------
209 (561) (917) (3,068)
Effect of Exchange Rate Changes on
Cash and Cash Equivalents (49) (148) (71) (233)
---------------------------------------
Increase (Decrease) in Cash and Cash
Equivalents 240 (77) (490) (106)
---------------------------------------
Cash and Cash Equivalents -
Beginning of Period 970 1,974 1,700 2,003
---------------------------------------
Cash and Cash Equivalents - End of
Period (1) 1,210 1,897 1,210 1,897
---------------------------------------
---------------------------------------
(1) Cash and cash equivalents at September 30, 2010 consist of cash of $211
million and short-term investments of $999 million (September 30, 2009
- cash of $376 million and short-term investments of $1,521 million).
See accompanying notes to the Unaudited Consolidated Financial Statements.
Nexen Inc.
Unaudited Consolidated Statement of Equity
For the Three and Nine Months Ended September 30
Three Months Nine Months
Ended September 30 Ended September 30
(Cdn$ millions) 2010 2009 2010 2009
----------------------------------------------------------------------------
Common Shares, Beginning of Period 1,088 1,011 1,049 981
Issue of Common Shares 9 8 41 37
Exercise of Tandem Options for
Shares - 4 3 5
Accrued Liability Relating to
Tandem Options Exercised for
Common Shares - 2 4 2
---------------------------------------
Balance at End of Period 1,097 1,025 1,097 1,025
---------------------------------------
---------------------------------------
Contributed Surplus, Beginning of
Period - 2 1 2
Exercise of Tandem Options - (1) (1) (1)
---------------------------------------
Balance at End of Period - 1 - 1
---------------------------------------
---------------------------------------
Retained Earnings, Beginning of
Period 7,110 6,393 6,722 6,290
Net Income Attributable to
Nexen Inc. 537 122 977 277
Dividends Paid on Common Shares
(Note 13) (26) (26) (78) (78)
---------------------------------------
Balance at End of Period 7,621 6,489 7,621 6,489
---------------------------------------
---------------------------------------
Accumulated Other Comprehensive Loss,
Beginning of Period (189) (157) (190) (134)
Other Comprehensive Loss
Attributable to Nexen Inc. (7) (26) (6) (49)
---------------------------------------
Balance at End of Period (1) (196) (183) (196) (183)
---------------------------------------
---------------------------------------
(1) Comprised of unrealized foreign
currency translation adjustment.
Canexus Non-Controlling Interests,
Beginning of Period 71 54 64 52
Net Income Attributable to
Non-Controlling Interests 4 15 4 24
Distributions Due to
Non-Controlling Interests (5) (5) (15) (14)
Issue of Partnership Units to
Non-Controlling Interests 6 1 23 3
Estimated Fair Value of Conversion
Feature of Convertible Debenture
Issue Attributable to
Non-Controlling Interests 8 4 8 4
---------------------------------------
Balance at End of Period 84 69 84 69
---------------------------------------
---------------------------------------
See accompanying notes to the Unaudited Consolidated Financial Statements.
Nexen Inc.
Unaudited Consolidated Statement of Comprehensive Income
For the Three and Nine Months Ended September 30
Three Months Nine Months
Ended September 30 Ended September 30
(Cdn$ millions) 2010 2009 2010 2009
----------------------------------------------------------------------------
Net Income Attributable to
Nexen Inc. 537 122 977 277
Other Comprehensive Loss,
Net of Income Taxes:
Foreign Currency Translation
Adjustment
Net Losses on Investment in
Self-Sustaining Foreign
Operations (145) (408) (83) (693)
Net Gains on Foreign-Denominated
Debt Hedges of Self-Sustaining
Foreign Operations (1) 138 384 77 646
Realized Translation Adjustments
Recognized in Net Income - (2) - (2)
---------------------------------------
Other Comprehensive Loss
Attributable to Nexen Inc. (7) (26) (6) (49)
---------------------------------------
Comprehensive Income Attributable
to Nexen Inc. 530 96 971 228
---------------------------------------
---------------------------------------
(1) Net of income tax expense for the three months ended September 30, 2010
of $20 million (2009 - $55 million expense) and net of income tax
expense for the nine months ended September 30, 2010 of $12 million
(2009 - $93 million expense).
See accompanying notes to the Unaudited Consolidated Financial Statements.
Nexen Inc.
Notes to Unaudited Consolidated Financial Statements
Cdn$ millions, except as noted
1. ACCOUNTING POLICIES
Our Unaudited Consolidated Financial Statements are prepared in accordance with Canadian Generally Accepted Accounting Principles (GAAP). The impact of significant differences between Canadian and United States GAAP on the Unaudited Consolidated Financial Statements is disclosed in Note 20. In the opinion of management, the Unaudited Consolidated Financial Statements contain all adjustments of a normal and recurring nature necessary to present fairly Nexen Inc.'s (Nexen, we or our) financial position at September 30, 2010 and December 31, 2009 and the results of our operations and our cash flows for the three and nine months ended September 30, 2010 and 2009.
We make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the Unaudited Consolidated Financial Statements, and revenues and expenses during the reporting period. Our management reviews these estimates on an ongoing basis, including those related to accruals, litigation, environmental and asset retirement obligations, recoverability of assets, income taxes, fair values of derivative assets and liabilities, capital adequacy and determination of proved reserves. Changes in facts and circumstances may result in revised estimates and actual results may differ from these estimates. The results of operations and cash flows for the three and nine months ended September 30, 2010 are not necessarily indicative of the results of operations or cash flows to be expected for the year ending December 31, 2010. As at October 27, 2010, there are no material subsequent events requiring additional disclosure in or amendment to these financial statements.
These Unaudited Consolidated Financial Statements should be read in conjunction with our Audited Consolidated Financial Statements included in our 2009 Form 10-K. The accounting policies we follow are described in Note 1 of the Audited Consolidated Financial Statements included in our 2009 Form 10-K.
Changes in Accounting Policies
Oil and Gas Reserve Estimates
In early 2010, the Financial Accounting Standards Board issued guidance for Oil and Gas Reserve Estimation and Disclosure, which is effective for years ended December 31, 2009. The guidance: i) expands the definition of oil and gas producing activities to include unconventional sources such as oil sands; ii) changes the price used in reserve estimation from the year-end price to the simple average of the first-day-of-the-month price for the previous 12 months; and iii) requires disclosures for geographic areas that represent 15% or more of proved reserves.
We follow the successful efforts method of accounting for our oil and gas activities, which use the estimated proved reserves we believe are recoverable from our oil and gas properties. Specifically, reserves estimates are used to calculate our unit-of-production depletion rates and to assess, when necessary, our oil and gas assets for impairment. Adoption of these amendments changed our estimate of reserves used to calculate depletion in 2010. As a result of the amendments, depletion expense for the three and nine months ended September 30, 2010 increased by $11 million and $35 million, net income decreased by $7 million and $23 million, and earnings per common share decreased by $0.02/share and $0.06/share, respectively.
2. ACCOUNTS RECEIVABLE
September 30 December 31
2010 2009
----------------------------------------------------------------------------
Trade
Energy Marketing 1,300 1,410
Energy Marketing Derivative Contracts (Note 6) 172 466
Oil and Gas 712 823
Chemicals and Other 47 44
-----------------------------
2,231 2,743
Non-Trade 121 99
-----------------------------
2,352 2,842
Allowance for Doubtful Receivables (47) (54)
-----------------------------
Total 2,305 2,788
-----------------------------
-----------------------------
3. INVENTORIES AND SUPPLIES
September 30 December 31
2010 2009
----------------------------------------------------------------------------
Finished Products
Energy Marketing 389 548
Oil and Gas 54 25
Chemicals and Other 10 12
-----------------------------
453 585
Work in Process 10 7
Field Supplies 81 88
-----------------------------
Total 544 680
-----------------------------
-----------------------------
4. PROPERTY, PLANT AND EQUIPMENT
Depreciation, Depletion, Amortization and Impairment
Our DD&A expense in the third quarter of 2010 includes non-cash impairment charges of $61 million at three natural gas properties in the US Gulf of Mexico. Low natural gas prices made these mature shelf properties uneconomic and, as a result, the properties are being shut down and the carrying value was written down to their estimated fair value. Fair value was based on estimated future cash flows using unobservable Level 3 inputs including management's estimate of future production and prices.
Suspended Exploration Well Costs
The following table shows the changes in capitalized exploratory well costs during the nine months ended September 30, 2010 and the year ended December 31, 2009, and does not include amounts that were initially capitalized and subsequently expensed in the same period. Suspended exploration well costs are included in property, plant and equipment.
Nine Months Ended Year Ended
September 30 December 31
2010 2009
----------------------------------------------------------------------------
Beginning of Period 794 518
Exploratory Well Costs Capitalized
Pending the Determination of
Proved Reserves 350 396
Capitalized Exploratory Well Costs
Charged to Expense (2) (56)
Transfers to Wells, Facilities and
Equipment Based on Determination of
Proved Reserves (1) (21)
Effects of Foreign Exchange Rate Changes (10) (43)
-----------------------------
End of Period 1,131 794
-----------------------------
-----------------------------
The following table provides an aging of capitalized exploratory well costs based on the date drilling was completed as at September 30, 2010.
Aging of Suspended United United
Exploration Wells Kingdom Canada States Nigeria Total
----------------------------------------------------------------------------
Less than 1 year 113 190 85 - 388
1-3 years 155 387 - - 542
4-5 years 55 - 115 - 170
Greater than 5 years - - - 31 31
--------------------------------------------------
Total 323 577 200 31 1,131
--------------------------------------------------
--------------------------------------------------
As at September 30, 2010, we have exploratory costs that have been capitalized for more than one year relating to our shale gas exploratory activities in Canada ($387 million), interests in eight exploratory blocks in the North Sea ($210 million), two exploratory blocks in the Gulf of Mexico ($115 million), and our interest in an exploratory block offshore Nigeria ($31 million). These costs relate to projects with successful exploration wells for which we have not been able to recognize proved reserves. We are assessing all of these wells and projects, and are working with our partners to prepare development plans, drill additional appraisal wells or otherwise assess commercial viability.
5. DEFERRED CHARGES AND OTHER ASSETS
September 30 December 31
2010 2009
----------------------------------------------------------------------------
Long-Term Energy Marketing Derivative
Contracts (Note 6) 116 225
Defined Benefit Pension Assets 53 60
Long-Term Capital Prepayments 16 27
Other 51 58
-----------------------------
Total 236 370
-----------------------------
-----------------------------
6. FINANCIAL INSTRUMENTS
Financial instruments carried at fair value on our balance sheet include cash and cash equivalents, restricted cash and derivatives used for trading and non-trading purposes. Our other financial instruments, including accounts receivable, accounts payable, accrued interest payable, dividends payable, short-term borrowings and long-term debt, are carried at cost or amortized cost. The carrying values of our short-term receivables and payables approximate their fair value because the instruments are near maturity.
In our energy marketing group, we enter into contracts to purchase and sell crude oil, as well as other energy commodities, and use derivative contracts, including futures, forwards, swaps and options, for hedging and trading purposes (collectively derivatives). We also use derivatives to manage commodity price risk and foreign currency risk for non-trading purposes. We categorize our derivative instruments as trading or non-trading activities and carry the instruments at fair value on our balance sheet. The fair values are included with accounts receivable or payable and are classified as long-term or short-term based on anticipated settlement date. Any change in fair value is included in marketing and other income. Related amounts posted as margin for exchange-traded positions are recorded in restricted cash.
We carry our long-term debt at amortized cost using the effective interest rate method. At September 30, 2010, the estimated fair value of our long-term debt was $6,385 million (December 31, 2009 - $7,594 million) as compared to the carrying value of $5,678 million (December 31, 2009 - $7,251 million). The fair value of long-term debt is estimated based on prices provided by quoted markets and third-party brokers.
Derivatives
(a) Derivative contracts related to trading activities
During the quarter, we sold our North American natural gas marketing operations, as described in Note 15. Our energy marketing group primarily focuses on our crude oil marketing activities in North America, Europe and Asia.
Our energy marketing group engages in various activities including the purchase and sale of physical commodities and the use of financial instruments such as commodity and foreign exchange futures, forwards and swaps to economically hedge exposures and generate revenue. These contracts are accounted for as derivatives and, where applicable, are presented net on the balance sheet in accordance with netting arrangements. The fair value and carrying amounts related to derivative instruments held by our energy marketing operations are as follows:
September 30 December 31
2010 2009
----------------------------------------------------------------------------
Commodity Contracts 172 463
Foreign Exchange Contracts - 3
-----------------------------
Accounts Receivable (Note 2) 172 466
-----------------------------
Commodity Contracts 116 225
-----------------------------
Deferred Charges and Other Assets (Note 5)(1) 116 225
-----------------------------
Total Trading Derivative Assets 288 691
-----------------------------
-----------------------------
Commodity Contracts 152 410
Foreign Exchange Contracts - 46
-----------------------------
Accounts Payable and Accrued Liabilities (Note 8) 152 456
-----------------------------
Commodity Contracts 119 212
-----------------------------
Deferred Credits and Other Liabilities
(Note 12)(1) 119 212
-----------------------------
Total Trading Derivative Liabilities 271 668
-----------------------------
-----------------------------
Total Net Trading Derivative Contracts 17 23
-----------------------------
-----------------------------
(1) These derivative contracts settle beyond 12 months and are considered
non-current; once settlement is within 12 months, they are included in
accounts receivable or accounts payable.
Excluding the impact of netting arrangements, the fair value of derivative
instruments is as follows:
September 30 December 31
2010 2009
----------------------------------------------------------------------------
Current Trading Assets 582 2,625
Non-Current Trading Assets 311 716
-----------------------------
Total Trading Derivative Assets 893 3,341
-----------------------------
-----------------------------
Current Trading Liabilities 562 2,615
Non-Current Trading Liabilities 314 703
-----------------------------
Total Trading Derivative Liabilities 876 3,318
-----------------------------
-----------------------------
-----------------------------
Total Net Trading Derivative Contracts 17 23
-----------------------------
-----------------------------
Trading revenues generated by our energy marketing group include gains and losses on derivative instruments and non-derivative instruments such as physical inventory. During the three and nine months ended September 30, 2010, the following trading revenues were recognized in marketing and other income:
Three Nine
Months Ended Months Ended
September 30 September 30
2010 2010
----------------------------------------------------------------------------
Commodity 84 290
Foreign Exchange (2) (8)
-----------------------------
Marketing Revenue 82 282
-----------------------------
-----------------------------
As an energy marketer, we may undertake several transactions during a period to execute a single sale of physical product. Each transaction may be represented by one or more derivative instruments including a physical buy, physical sell, and in many cases, numerous financial instruments for economic hedging and trading purposes. The absolute notional volumes associated with our derivative instrument transactions for the three and nine months ended September 30, 2010, are as follows:
Three Nine
Months Ended Months Ended
September 30 September 30
2010 2010
----------------------------------------------------------------------------
Natural Gas bcf/d 2.9 7.8
Crude Oil mmbbls/d 3.0 3.2
Power GWh/d 0.2 92.8
Foreign Exchange US$ millions 548 2,169
Foreign Exchange Euro millions - 53
-----------------------------
(b) Derivative contracts related to non-trading activities
The fair value and carrying amounts of derivative instruments related to
non-trading activities are as follows:
September 30 December 31
2010 2009
----------------------------------------------------------------------------
Accounts Receivable 4 13
Deferred Charges and Other Assets (1) 1 4
-----------------------------
Total Non-Trading Derivative Assets 5 17
-----------------------------
-----------------------------
Accounts Payable and Accrued Liabilities - 26
-----------------------------
Total Non-Trading Derivative Liabilities - 26
-----------------------------
-----------------------------
Total Net Non-Trading Derivative Assets (2) 5 (9)
-----------------------------
-----------------------------
(1) These derivative contracts settle beyond 12 months and are considered
non-current.
(2) The net fair value of these derivatives is equal to the gross fair
value before consideration of netting arrangements and collateral
posted or received with counterparties.
Crude oil put options
During the quarter, we purchased put options on 20,000 bbls/d of our 2011 crude oil production for $6 million. These options establish a WTI floor price of US$50/bbl on these volumes and provide a base level of price protection without limiting our upside to higher prices. The options settle monthly and are recorded at fair value throughout their term. As a result, changes in forward crude oil prices create gains or losses on these options at each period end. Higher forward crude oil prices at September 30, 2010 reduced the fair value of the options to approximately $5 million.
Subsequent to September 30, 2010, we purchased additional crude oil put options on 50,000 bbls/d of our 2011 crude oil production for $17 million. These options establish a WTI floor price of approximately US$56/bbl.
In 2009, we purchased put options on 90,000 bbls/d of our 2010 crude oil production for $39 million. These options establish a WTI floor price of US$50/bbl on these volumes. Options on 60,000 bbls/d settle monthly, while the remaining options settle annually. These options are recorded at fair value throughout their term. Higher forward crude oil prices at September 30, 2010 compared to the end of the previous quarter and a shorter term to expiry reduced the fair value of the options to nil.
Change in Fair Value
-----------------------------
Three Months Nine Months
Ended Ended
Notional Average Fair September 30 September 30
Volumes Term Floor Price Value 2010 2010
----------------------------------------------------------------------------
(bbls/d) (US$/bbl)
WTI Crude Oil
Put Options
(monthly) 20,000 2011 (1) (1)
WTI Crude Oil
Put Options
(monthly) 60,000 2010 (2) (13)
WTI Crude Oil
Put Options
(annual) 30,000 2010 - (4)
-----------------------------
(3) (18)
-----------------------------
-----------------------------
(c) Fair value of derivatives
Our processes for estimating and classifying the fair value of our derivative contracts are consistent with those in place at December 31, 2009. The following table includes our derivatives carried at fair value for our trading and non-trading activities as at September 30, 2010. Financial assets and liabilities are classified in the fair value hierarchy in their entirety based on the lowest level of input that is significant to the fair value measurement. Assessment of the significance of a particular input to the fair value measurement requires judgment and may affect placement within the fair value hierarchy levels.
Net Derivatives at
September 30, 2010 Level 1 Level 2 Level 3 Total
----------------------------------------------------------------------------
Trading Derivatives
(Commodity Contracts) (27) - 44 17
Non-Trading Derivatives - 5 - 5
-----------------------------------------
Total (27) 5 44 22
-----------------------------------------
-----------------------------------------
A reconciliation of changes in the fair value of our derivatives classified
as Level 3 for the nine months ended September 30, 2010 is provided below:
Level 3
----------------------------------------------------------------------------
Beginning of Period 42
Realized and Unrealized Gains (Losses) 21
Purchases -
Settlements (19)
Transfers Into Level 3 -
Transfers Out of Level 3 -
------------
End of Period 44
------------
------------
Unsettled gains relating to instruments
still held as of September 30, 2010 21
------------
------------
Items classified in Level 3 are generally economically hedged such that gains or losses on positions classified in Level 3 are often offset by gains or losses on positions classified in Level 1 or 2. Transfers into or out of Level 3 represent existing assets and liabilities that were either previously categorized as a higher level for which the inputs became unobservable or assets and liabilities that were previously classified as Level 3 for which the lowest significant input became observable during the period. Fair values of instruments in Level 3 are determined using broker quotes, pricing services and internally-developed inputs. We performed a sensitivity analysis of inputs used to calculate the fair value of Level 3 instruments. Using reasonably possible alternative assumptions, the fair value of Level 3 instruments at September 30, 2010 would change by $2 million (December 31, 2009 - $12 million).
7. RISK MANAGEMENT
(a) Market risk
We invest in significant capital projects, purchase and sell commodities, issue short-term borrowings and long-term debt, and invest in foreign operations. These activities expose us to market risks from changes in commodity prices, foreign currency rates and interest rates, which could affect our earnings and the value of the financial instruments we hold. We use derivatives for trading and non-trading purposes as part of our overall risk management policy to manage portions of these market exposures.
The following market risk discussion focuses on the commodity price risk and foreign currency risk related to our financial instruments as our exposure to interest rate risk is immaterial, given that the majority of our debt is fixed rate.
Commodity price risk
We are exposed to commodity price movements as part of our normal oil and gas operations, particularly in relation to the prices received for our crude oil and natural gas. Commodity price risk related to conventional and synthetic crude oil prices is our most significant market risk exposure. Crude oil and natural gas are sensitive to numerous worldwide factors, many of which are beyond our control, and are generally sold at contract or posted prices. Changes in the global supply and demand fundamentals in the crude oil market and geopolitical events can significantly affect crude oil prices. Changes in crude oil and natural gas prices may significantly affect our results of operations and cash generated from operating activities. Consequently, these changes may also affect the value of our oil and gas properties, our level of spending for exploration and development, and our ability to meet our obligations as they come due.
The majority of our oil and gas production is sold under short-term contracts, exposing us to the risk of price movements. Other energy contracts we enter into also expose us to commodity price risk between the time we purchase and sell contracted volumes. We actively manage these risks by using derivative contracts such as commodity put options.
Our energy marketing business is primarily focused on marketing and trading physical crude oil in selected regions of the world. We do this by buying and selling physical crude oil, by acquiring and holding rights to physical transportation and storage assets, and by building strong relationships with our customers and suppliers.
In order to manage the commodity and foreign exchange price risks that come from this physical business, we use financial derivative contracts including energy-related futures, forwards, swaps and options, as well as foreign currency swaps or forwards.
Our risk management activities include prescribed capital limits and the use of tools such as Value-at-Risk (VaR) and stress testing consistent with the methodology used at December 31, 2009. Our period end, high, low and average VaR amounts for the three and nine months ended September 30, 2010 are as follows:
Three Months Nine Months
Ended September 30 Ended September 30
Value-at-Risk 2010 2009 2010 2009
----------------------------------------------------------------------------
Period End 8 13 8 13
High 9 15 15 24
Low 4 11 4 11
Average 7 12 10 16
----------------------------------------
If a market shock occurred as in 2008, the key assumptions underlying our VaR estimate could be exceeded and the potential loss could be greater than our estimate. We perform stress tests on a regular basis to complement VaR and assess the impact of abnormal changes in prices on our positions.
Foreign currency risk
Foreign currency risk is created by fluctuations in the fair values or cash flows of financial instruments due to changes in foreign exchange rates. A substantial portion of our activities are transacted in or referenced to US dollars including:
- sales of crude oil, natural gas and certain chemicals products;
- capital spending and expenses for our oil and gas and chemicals operations;
- commodity derivative contracts used primarily by our energy marketing group; and
- short-term borrowings, long-term debt, and cash & cash equivalents.
In our oil and gas operations, we manage our exposure to fluctuations between the US and Canadian dollar by matching our expected net cash flows and borrowings in the same currency. Cash inflows generated by our foreign operations and borrowings on our US-dollar debt facilities are generally used to fund US-dollar capital expenditures and debt repayments. We maintain revolving Canadian and US-dollar borrowing facilities that can be used or repaid depending on expected net cash flows.
We designate most of our US-dollar borrowings as a hedge against our US-dollar net investment in self-sustaining foreign operations. The foreign exchange gains or losses related to the effective portion of our designated US-dollar debt are included in accumulated other comprehensive income in equity. Our net investment in self-sustaining foreign operations and our designated US-dollar debt at September 30, 2010 and December 31, 2009 are as follows:
September 30 December 31
(US$ millions) 2010 2009
----------------------------------------------------------------------------
Net Investment in Self-Sustaining
Foreign Operations 4,307 4,492
Designated US-Dollar Debt 4,307 4,492
-----------------------------
For the three and nine months ended September 30, 2010, the ineffective portion of our US-dollar debt resulted in a net foreign exchange gain of $12 million and a net foreign exchange loss of $6 million, respectively (gain of $11 million and loss of $5 million respectively, net of income tax expense) and is included in marketing and other income. A one cent change in the US dollar to Canadian dollar exchange rate would increase or decrease our accumulated other comprehensive income by approximately $43 million, net of income tax, and would increase or decrease our net income by approximately $4 million, net of income tax.
We also have exposures to currencies other than the US dollar including a portion of our UK operating expenses, capital spending and future asset retirement obligations which are denominated in British Pounds and Euros. We do not have any material exposure to highly inflationary foreign currencies. In our energy marketing group, we enter into transactions in various currencies including Canadian and US dollars, British Pounds and Euros. We may actively manage significant currency exposures using forward contracts and swaps.
(b) Credit risk
Credit risk affects our oil, gas and chemicals operations, and our trading and non-trading derivative activities, and is the risk of loss if counterparties do not fulfill their contractual obligations. Most of our credit exposure is with counterparties in the energy industry, including integrated oil companies, refiners and utilities, and are subject to normal industry credit risk. Approximately 76% of our exposure is with these large energy companies. This concentration of risk within the energy industry is reduced because of our broad base of domestic and international counterparties. Our processes to manage this risk are consistent with those in place at December 31, 2009.
At September 30, 2010, only two counterparties individually made up more than 10% of our credit exposure. These counterparties are major integrated oil companies with a strong investment grade credit rating. Four other counterparties made up more than 5% of our credit exposure. The following table illustrates the composition of credit exposure by credit rating.
September 30 December 31
Credit Rating 2010 2009
----------------------------------------------------------------------------
A or higher 67% 67%
BBB 21% 26%
Non-Investment Grade 12% 7%
-----------------------------
Total 100% 100%
-----------------------------
-----------------------------
Our maximum counterparty credit exposure at the balance sheet date consists primarily of the carrying amounts on non-derivative financial assets such as cash and cash equivalents, restricted cash, accounts receivable, as well as the fair value of derivative financial assets. We provided an allowance of $47 million for credit risk with our counterparties. In addition, we incorporate the credit risk associated with counterparty default, as well as Nexen's own credit risk, into our estimates of fair value.
Collateral received from customers at September 30, 2010 includes $45 million of cash and $224 million of letters of credit. The cash received is included in accounts payable and accrued liabilities.
(c) Liquidity risk
Liquidity risk is the risk that we will not be able to meet our financial obligations as they fall due. We require liquidity specifically to fund capital requirements, satisfy financial obligations as they come due, and to operate our energy marketing business. We generally rely on operating cash flows to provide liquidity and we also maintain significant undrawn committed credit facilities. At September 30, 2010, we had approximately $4.4 billion of cash and available committed lines of credit. This includes approximately $1.2 billion of cash and cash equivalents on hand and undrawn term credit facilities of $3.2 billion, of which $289 million was supporting letters of credit at September 30, 2010. These facilities are available until 2014 unless extended. We also have about $466 million of uncommitted credit facilities, none of which was drawn and $82 million of which was supporting letters of credit at September 30, 2010.
The following table details the contractual maturities for our non-derivative financial liabilities, including both the principal and interest cash flows at September 30, 2010:
Total Less than 1 1-3 Years 4-5 Years Greater than
Year 5 Years
----------------------------------------------------------------------------
Long-Term Debt 5,787 - 345 799 4,643
Interest on
Long-Term Debt(1) 7,668 357 713 651 5,947
----------------------------------------------------------
Total 13,455 357 1,058 1,450 10,590
----------------------------------------------------------
----------------------------------------------------------
(1) Excludes interest on Canexus term credit facilities of $294 million
(US$285 million) as the amounts drawn on the facilities fluctuate.
Based on amounts drawn at September 30, 2010 and existing variable
interest rates, we would be required to pay $12 million per year until
the outstanding amounts on the term credit facilities are repaid.
The following table details contractual maturities for our derivative
financial liabilities. The balance sheet amounts for derivative
financial liabilities included below are not materially different from
the contractual amounts due on maturity.
Total Less than 1 1-3 Years 4-5 Years Greater than
Year 5 Years
----------------------------------------------------------------------------
Trading Derivatives
(Note 6) 271 152 103 11 5
Non-Trading
Derivatives (Note 6) - - - - -
----------------------------------------------------------
Total 271 152 103 11 5
----------------------------------------------------------
----------------------------------------------------------
The commercial agreements our energy marketing group enter into often include financial assurance provisions that allow us and our counterparties to effectively manage credit risk. The agreements normally require collateral to be posted if an adverse credit-related event occurs, such as a drop in credit ratings to non-investment grade. Based on contracts in place and commodity prices at September 30, 2010, we could be required to post collateral of up to $700 million if we were downgraded to non-investment grade. These obligations are reflected on our balance sheet. The posting of collateral secures the payment of such amounts. In the event of a ratings downgrade, we have trading inventories and receivables that can be more quickly monetized as well as undrawn credit facilities.
At September 30, 2010, collateral posted with counterparties includes $15 million of cash and $139 million of letters of credit related to our trading activities. Cash posted is included with our accounts receivable. Cash collateral is not normally applied to contract settlement. Once a contract has been settled, the collateral amounts are refunded. If there is a default, the cash is retained. Our exchange-traded derivative contracts are also subject to margin requirements. We have margin deposits of $35 million (December 31, 2009 - $198 million), which have been included in restricted cash.
8. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES
September 30 December 31
2010 2009
----------------------------------------------------------------------------
Energy Marketing Payables 1,203 1,366
Energy Marketing Derivative Contracts (Note 6) 152 456
Accrued Payables 653 619
Trade Payables 216 210
Income Taxes Payable 362 179
Stock-Based Compensation 28 72
Other 329 136
----------------------------
Total 2,943 3,038
----------------------------
----------------------------
9. SHORT-TERM BORROWINGS AND LONG-TERM DEBT
September 30 December 31
2010 2009
----------------------------------------------------------------------------
Canexus Term Credit Facilities, due 2012
(US$285 million drawn) (a) 294 233
Canexus Notes, due 2013 (US$50 million) 51 52
Notes, due 2013 (US$500 million) 515 523
Term Credit Facilities, due 2014 (b) - 1,570
Canexus Convertible Debentures, due 2014 27 46
Notes, due 2015 (US$250 million) 257 262
Canexus Convertible Debentures, due 2015 (c) 60 -
Notes, due 2017 (US$250 million) 257 262
Notes, due 2019 (US$300 million) 309 314
Notes, due 2028 (US$200 million) 206 209
Notes, due 2032 (US$500 million) 515 523
Notes, due 2035 (US$790 million) 814 827
Notes, due 2037 (US$1,250 million) 1,287 1,308
Notes, due 2039 (US$700 million) 721 733
Subordinated Debentures, due 2043 (US$460
million) 474 481
----------------------------
5,787 7,343
Unamortized Debt Issue Costs (109) (92)
----------------------------
Total Long-Term Debt 5,678 7,251
----------------------------
----------------------------
(a) Canexus term credit facilities
Canexus has $450 million (US$437 million) of committed, secured term credit facilities available until August 2012. At September 30, 2010, $294 million (US$285 million) was drawn on these facilities (December 31, 2009 - $233 million (US$223 million)). Borrowings are available as Canadian bankers' acceptances, LIBOR-based loans, Canadian prime rate loans or US-dollar base rate loans. Interest is payable monthly at floating rates. The term credit facilities are secured by a floating charge debenture over all of Canexus' assets. The credit facility also contains covenants with respect to certain financial ratios of Canexus. The weighted-average interest rate on the Canexus term credit facilities was 4.3% for the three months ended September 30, 2010 (three months ended September 30, 2009 - 2.0%) and 3.5% for the nine months ended September 30, 2010 (nine months ended September 30, 2009 - 2.3%).
(b) Term credit facilities
We have unsecured term credit facilities of $3.2 billion (US$3.1 billion), available until 2014, none of which were drawn at September 30, 2010 (December 31, 2009 - $1.6 billion (US$1.5 billion)). 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 monthly at a floating rate. The weighted-average interest rate on our term credit facilities was 3.1% for the three months ended September 30, 2010 (three months ended September 30, 2009 - 0.9%) and 1.2% for the nine months ended September 30, 2010 (nine months ended September 30, 2009 - 1.0%). At September 30, 2010, $289 million (US$281 million) of these facilities were utilized to support outstanding letters of credit (December 31, 2009 - $407 million (US$389 million)).
(c) Canexus convertible debentures
In September 2010, Canexus issued $60 million of convertible unsecured subordinated debentures to non-controlling interests. Interest is payable semi-annually at a rate of 5.75%. These debentures mature on December 31, 2015 and are convertible at the holder's option at any time prior to the close of business on the earlier of; i) the maturity date; and, ii) the business day immediately preceding the date specified by Canexus for redemption of the debentures into trust units. The conversion price is $8.30 per trust unit.
Canexus has the option to redeem the debentures in whole or in part from time to time subject to the satisfaction of certain conditions. The debentures can be redeemed by Canexus, after January 1, 2014 and before December 31, 2014 (provided that the current market price of the trust units on the date of redemption is not less than 125% of the conversion price) and after December 31, 2014 at a redemption price equal to the principal amount plus accrued and unpaid interest. Canexus may elect to satisfy its obligation to pay interest or repay the principal by issuing trust units at 95% of the current market price at the time of repayment and to pay interest by delivering a sufficient number of trust units to the debenture trustee to satisfy the interest obligation.
The estimated fair value of the conversion feature of the convertible debentures amounted to $8 million and was included in non-controlling interests. The amount of the convertible debentures allocated to long-term debt is accreted over the term of the debt using the effective interest rate method.
(d) Interest expense
Three Months Nine Months
Ended September 30 Ended September 30
2010 2009 2010 2009
----------------------------------------------------------------------------
Long-Term Debt 96 96 284 274
Other 9 4 18 12
---------------------------------------
Total 105 100 302 286
Less: Capitalized (24) (16) (64) (60)
---------------------------------------
Total 81 84 238 226
---------------------------------------
---------------------------------------
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.
(e) Short-term borrowings
Nexen has uncommitted, unsecured credit facilities of approximately $466 million (US$452 million), none of which were drawn at September 30, 2010 (December 31, 2009 - nil). We utilized $82 million (US$80 million) of these facilities to support outstanding letters of credit at September 30, 2010 (December 31, 2009 - $86 million (US$82 million)). Interest is payable at floating rates.
10. CAPITAL MANAGEMENT
Our objectives and processes for managing our capital structure are consistent with those in place at December 31, 2009. Our capital consists of equity, short-term borrowings, long-term debt and cash and cash equivalents as follows:
September 30 December 31
2010 2009
----------------------------------------------------------------------------
Net Debt (1)
Long-Term Debt 5,678 7,251
Less: Cash and Cash Equivalents (1,210) (1,700)
----------------------------
Total 4,468 5,551
----------------------------
----------------------------
Equity (2) 8,606 7,646
----------------------------
----------------------------
(1) Includes all of our borrowings and is calculated as long-term debt and
short-term borrowings less cash and cash equivalents.
(2) Equity is the historical issue of equity and accumulated retained
earnings.
We monitor the leverage in our capital structure by reviewing the ratio of net debt to adjusted cash flow (cash flow from operating activities before changes in non-cash working capital and other) and interest coverage ratios at various commodity prices. Net debt and adjusted cash flow are non-GAAP measures that are unlikely to be comparable to similar measures presented by others. We calculate net debt using the GAAP measures of long-term debt and short-term borrowings less cash and cash equivalents (excluding restricted cash).
We use the ratio of net debt to adjusted cash flow as a key indicator of our leverage and to monitor the strength of our balance sheet. For the twelve months ended September 30, 2010, the net debt to adjusted cash flow was 1.8 times compared to 2.5 times at December 31, 2009. While we typically expect the target ratio to fluctuate between 1.0 and 2.0 times under normalized commodity prices, this can be higher or lower depending on commodity price volatility, where we are in the investment cycle, or when we identify strategic opportunities for additional investment. Whenever we exceed our target ratio, we assess whether we need to identify specific actions to reduce our leverage and lower this ratio back to target levels over time.
Our interest coverage ratio monitors our ability to fund the interest requirements associated with our debt. Our interest coverage increased from 8.5 times at the end of 2009 to 9.4 times at September 30, 2010. Interest coverage is calculated by dividing our adjusted EBITDA by interest expense before capitalized interest. Adjusted EBITDA is a non-GAAP measure that is calculated using net income excluding interest expense, provision for income taxes, exploration expenses, DD&A, impairment and other non-cash expenses. The calculation of adjusted EBITDA is set out in the following table and is unlikely to be comparable to similar measures presented by others.
Twelve Months Ended Year Ended
September 30 December 31
2010 2009
----------------------------------------------------------------------------
Net Income Attributable to Nexen Inc. 1,236 536
Add:
Interest Expense 324 312
Provision for Income Taxes 719 260
Depreciation, Depletion, Amortization
and Impairment 1,891 1,802
Exploration Expense 282 302
Recovery of Non-Cash Stock-Based
Compensation (77) (10)
Change in Fair Value of Crude Oil Put
Options 51 251
Other Non-Cash Expenses (605) (136)
----------------------------
Adjusted EBITDA 3,821 3,317
----------------------------
----------------------------
11. ASSET RETIREMENT OBLIGATIONS
Changes in carrying amounts of the asset retirement obligations associated with our Property, Plant & Equipment (PP&E) are as follows:
Nine Months Ended Year Ended
September 30 December 31
2010 2009
----------------------------------------------------------------------------
Balance at Beginning of Period 1,053 1,059
Obligations Incurred with Development
Activities 26 27
Obligations Settled (27) (42)
Accretion Expense 48 70
Revisions to Estimates 108 13
Obligations Associated with Discontinued
Activities (122) -
Effects of Changes in Foreign Exchange
Rate (15) (74)
----------------------------
Balance at End of Period (1)(2) 1,071 1,053
----------------------------
----------------------------
(1) Obligations due within 12 months of $64 million (December 31, 2009 -
$35 million) have been included in accounts payable and accrued
liabilities.
(2) Obligations relating to our oil and gas activities amount to $1,030
million (December 31, 2009 - $1,002 million) and obligations relating
to our chemicals business amount to $41 million (December 31, 2009 - $51
million).
Our total estimated undiscounted inflated asset retirement obligations amount to $2,490 million (December 31, 2009 - $2,341 million). We discounted the total estimated asset retirement obligations using a weighted-average, credit-adjusted, risk-free rate of 6%. Approximately $238 million included in our asset retirement obligations is expected to be settled over the next five years. The remaining obligations settle beyond five years and are expected to be funded by future cash flows from our operations.
12. DEFERRED CREDITS AND OTHER LIABILITIES
September 30 December 31
2010 2009
----------------------------------------------------------------------------
Deferred Tax Credit 409 503
Long-Term Energy Marketing Derivative Contracts
(Note 6) 119 212
Defined Benefit Pension Obligations (1) 79 76
Capital Lease Obligations 43 61
Deferred Transportation Revenue - 55
Other 116 114
----------------------------
Total 766 1,021
----------------------------
----------------------------
(1) The obligations are secured by letters of credit drawn on our term
credit facilities.
13. SHAREHOLDERS' EQUITY
Dividends
Dividends per common share for the three months ended September 30, 2010 were $0.05 per common share (2009 - $0.05). Dividends per common share for the nine months ended September 30, 2010 were $0.15 per common share (2009 - $0.15). Dividends paid to holders of common shares have been designated as 'eligible dividends' for Canadian tax purposes.
14. MARKETING AND OTHER INCOME
Three Months Nine Months
Ended September 30 Ended September 30
2010 2009 2010 2009
----------------------------------------------------------------------------
Marketing Revenue, Net 82 188 282 676
Long Lake Purchased Bitumen Sales 25 - 63 -
Change in Fair Value of Crude Oil Put
Options (3) (23) (18) (218)
Interest 1 1 6 4
Foreign Exchange Gain (Loss) (13) 93 (7) 112
Other 46 37 47 61
---------------------------------------
Total 138 296 373 635
---------------------------------------
---------------------------------------
15. DISPOSITIONS
Canadian Heavy Oil Asset Disposition
In May 2010, we signed an agreement to sell our heavy oil properties in Canada. The sale closed in July 2010 after receiving proceeds of $939 million, net of closing adjustments. We realized a gain of $781 million in the third quarter. The results of operations of these properties have been presented as discontinued operations.
Three Months Nine Months
Ended September 30 Ended September 30
2010 2009 2010 2009
----------------------------------------------------------------------------
Revenues and Other Income
Net Sales 13 63 138 169
Gain on Disposition of Assets 781 - 781 -
---------------------------------------
794 63 919 169
Expenses
Operating 5 24 50 74
Depreciation, Depletion, Amortization
and Impairment 1 29 35 93
General and Administrative 1 5 10 17
Transportation and Other - 5 2 12
---------------------------------------
7 63 97 196
---------------------------------------
Income (Loss) before Provision for
Income Taxes 787 - 822 (27)
Provision for (Recovery of) Future
Income Taxes 197 - 206 (7)
---------------------------------------
Net Income (Loss) from Discontinued
Operations 590 - 616 (20)
---------------------------------------
---------------------------------------
Earnings (Loss) Per Common Share
Basic 1.12 - 1.17 (0.04)
---------------------------------------
---------------------------------------
Diluted 1.12 - 1.17 (0.04)
---------------------------------------
---------------------------------------
Assets and liabilities on the Consolidated Balance Sheet at December 31, 2009, include the following amounts for discontinued operations. There were no assets and liabilities related to discontinued operations at September 30, 2010.
December 31
2009
----------------------------------------------------------------------------
Property, Plant and Equipment, Net of Accumulated DD&A 331
Asset Retirement Obligations (116)
Deferred Credits and Other Liabilities (29)
-------------
Total 186
-------------
-------------
Natural Gas Energy Marketing Disposition
During the third quarter of 2010, we sold our North American natural gas marketing operations. The sale, which generated proceeds of $11 million, closed in the third quarter and we recognized a non-cash loss of $259 million. On closing, the purchaser acquired our North American natural gas storage and transportation commitments, natural gas inventory, and related financial and physical derivative positions. As is customary with such transactions, not all contracts were assigned to the purchaser by the closing date. We have a total return swap in place with the purchaser to transfer to them the economic results on the unassigned contracts until they are assigned to the purchaser. The total return swap and unassigned contracts are derivative instruments carried at fair value on our balance sheet. The related gains and losses offset each other for the quarter and future periods.
In connection with our natural gas energy marketing disposition, we assigned substantially all of our natural gas transportation and storage contracts, reducing our future commitments by $342 million. We agreed to maintain our parental guarantee to the pipeline provider related to one transportation commitment. We are obligated to perform under the guarantee only if the purchaser does not meet its obligation to the pipeline provider. To guarantee its performance, the purchaser provided us with collateral of US$43 million for the maximum exposure under the guarantee. This collateral is included in accounts payable. We expect to cancel this guarantee in the fourth quarter.
Canadian Undeveloped Oil Sand Leases
During the second quarter, we sold our non-core lands in the Athabasca region for proceeds of $81 million. We had no plans to develop these lands for a least a decade. We recognized a gain on sale of $80 million.
16. EARNINGS PER COMMON SHARE
We calculate basic earnings per common share using net income divided by the weighted-average number of common shares outstanding. We calculate diluted earnings per common share in the same manner as basic, except we use the weighted-average number of diluted common shares outstanding in the denominator.
Three Months Nine Months
Ended September 30 Ended September 30
(millions of shares) 2010 2009 2010 2009
----------------------------------------------------------------------------
Weighted-average number of common
shares outstanding 525.0 521.7 524.4 521.0
Shares issuable pursuant to tandem
options 4.6 10.3 5.6 10.7
Shares notionally purchased from
proceeds of tandem options (3.6) (7.0) (4.4) (7.5)
---------------------------------------
Weighted-average number of diluted
common shares outstanding 526.0 525.0 525.6 524.2
---------------------------------------
---------------------------------------
In calculating the weighted-average number of diluted common shares outstanding for the three and nine months ended September 30, 2010, we excluded 15,496,237 and 16,074,998 tandem options, respectively, because their exercise price was greater than the average common share market price in the period. In calculating the weighted-average number of diluted common shares outstanding for the three and nine months ended September 30, 2009, we excluded 13,077,285 and 13,236,034 tandem options, respectively, because their exercise price was greater than the average common share market price in the period. During the periods presented, outstanding tandem options were the only potential dilutive instruments.
17. COMMITMENTS, CONTINGENCIES AND GUARANTEES
As described in Note 15 to the Audited Consolidated Financial Statements included in our 2009 Form 10-K, there are a number of lawsuits and claims pending, the ultimate results of which cannot be ascertained at this time. We record costs as they are incurred or become determinable. We believe the resolution of these matters would not have a material adverse effect on our liquidity, consolidated financial position or results of operations.
18. CASH FLOWS
(a) Charges and credits to income not involving cash
Three Months Nine Months
Ended September 30 Ended September 30
2010 2009 2010 2009
----------------------------------------------------------------------------
Depreciation, Depletion, Amortization
and Impairment 477 329 1,234 1,087
Stock-Based Compensation (3) (19) (44) 23
Recovery of Future Income Taxes (234) (81) (423) (390)
Net Loss on Dispositions 259 - 179 -
Non-cash Items Included in
Discontinued Operations (583) 29 (540) 86
Change in Fair Value of Crude Oil Put
Options 3 23 18 218
Foreign Exchange 1 (117) 2 (154)
Other (22) 10 7 17
---------------------------------------
Total (102) 174 433 887
---------------------------------------
---------------------------------------
(b) Changes in non-cash working capital
Three Months Nine Months
Ended September 30 Ended September 30
2010 2009 2010 2009
----------------------------------------------------------------------------
Accounts Receivable 240 212 6 39
Inventories and Supplies (88) (13) (12) (142)
Other Current Assets (32) (24) 46 (12)
Accounts Payable and Accrued
Liabilities (5) (68) 350 251
Other Current Liabilities (8) 20 (10) 16
---------------------------------------
Total 107 127 380 152
---------------------------------------
---------------------------------------
Relating to:
Operating Activities 212 113 410 193
Investing Activities (105) 14 (30) (41)
---------------------------------------
Total 107 127 380 152
---------------------------------------
---------------------------------------
(c) Other cash flow information
Three Months Nine Months
Ended September 30 Ended September 30
2010 2009 2010 2009
----------------------------------------------------------------------------
Interest Paid 103 70 293 248
Income Taxes Paid 376 179 626 247
---------------------------------------
Cash flow from other operating activities includes cash outflows related to geological and geophysical expenditures of $31 million for the three months ended September 30, 2010 (2009 - $16 million) and $60 million for the nine months ended September 30, 2010 (2009 - $59 million).
19. OPERATING SEGMENTS AND RELATED INFORMATION
Nexen is involved in activities relating to Oil and Gas, Energy Marketing and Chemicals in various geographic locations as described in Note 20 to the Audited Consolidated Financial Statements included in our 2009 Form 10-K.
Three months ended September 30, 2010
Oil and Gas
----------------------------------------------------------------------------
United United Other
Kingdom Canada (1) Syncrude States Yemen Countries(2)
----------------------------------------------------------
Net Sales 753 117 130 98 179 13
Marketing and
Other 5 25 2 - 4 -
----------------------------------------------------------
Total Revenues 758 142 132 98 183 13
Less: Expenses
Operating 84 112 74 23 38 1
Depreciation,
Depletion,
Amortization and
Impairment 212 67 12 127 29 3
Transportation
and Other 1 56 5 - 2 1
General and
Administrative 5 15 1 17 2 7
Exploration 11 7 - 18 - 20 (4)
Interest - - - - - -
Net Loss on
Dispositions - - - - - -
----------------------------------------------------------
Income (Loss) from
Continuing
Operations
before Income
Taxes 445 (115) 40 (87) 112 (19)
Less: Provision
for (Recovery
Of) Income Taxes 223 (28) 10 (31) 39 (17)
Less:
Non-Controlling
Interests - - - - - -
Add: Net Income
from Discontinued
Operations - 564 - - - -
----------------------------------------------------------
Net Income (Loss) 222 477 30 (56) 73 (2)
----------------------------------------------------------
----------------------------------------------------------
Identifiable
Assets 4,912 7,915 (5) 1,302 1,675 207 1,344 (6)
----------------------------------------------------------
----------------------------------------------------------
Capital
Expenditures
----------------------------------------------------------
Exploration &
Development 187 169 28 28 13 129
----------------------------------------------------------
----------------------------------------------------------
Property, Plant
and Equipment
Cost 6,530 8,600 1,531 3,993 2,453 1,267
Less: Accumulated
DD&A 3,170 827 301 2,713 2,367 100
----------------------------------------------------------
Net Book Value 3,360 7,773 (5) 1,230 1,280 86 1,167 (6)
----------------------------------------------------------
----------------------------------------------------------
Energy Corporate
Marketing Chemicals and Other Total
----------------------------------------------------------------------------
Net Sales 8 118 - 1,416
Marketing and Other 104 13 (15) (3) 138
---------------------------------------
Total Revenues 112 131 (15) 1,554
Less: Expenses
Operating 8 80 - 420
Depreciation, Depletion,
Amortization and
Impairment 4 13 10 477
Transportation and Other 62 12 3 142
General and Administrative 19 8 58 132
Exploration - - - 56
Interest - 4 77 81
Net Loss on Dispositions 259 - - 259
---------------------------------------
Income (Loss) from
Continuing Operations
before Income Taxes (240) 14 (163) (13)
Less: Provision for (Recovery
Of) Income Taxes (94) 4 (70) 36
Less: Non-Controlling
Interests - 4 - 4
Add: Net Income from
Discontinued Operations 26 - - 590
---------------------------------------
Net Income (Loss) (120) 6 (93) 537
---------------------------------------
---------------------------------------
Identifiable Assets 2,247 (7) 771 1,858 22,231
---------------------------------------
---------------------------------------
Capital Expenditures
---------------------------------------
Exploration & Development 9 19 10 592
---------------------------------------
---------------------------------------
Property, Plant and Equipment
Cost 234 1,244 397 26,249
Less: Accumulated DD&A 70 592 274 10,414
---------------------------------------
Net Book Value 164 652 123 15,835
---------------------------------------
---------------------------------------
(1) Includes results of operations from conventional, oilsands, shale gas
and CBM.
(2) Includes results of operations from producing activities in Colombia.
(3) Includes interest income of $1 million, foreign exchange losses of $13
million and a decrease in the fair value of crude oil put options of $3
million.
(4) Includes exploration activities primarily in Nigeria, Norway and
Colombia.
(5) Includes PP&E costs of $6,133 million related to our insitu oil sands
projects (Long Lake and future phases).
(6) Includes PP&E costs of $1,119 million related to Nigeria.
(7) Approximately 82% of Marketing's identifiable assets are accounts
receivable and inventories.
Three months ended September 30, 2009
Oil and Gas
----------------------------------------------------------------------------
United United Other
Kingdom Canada Syncrude States Yemen Countries(1)
----------------------------------------------------------
Net Sales 478 29 137 74 176 16
Marketing and
Other 5 (6) - - 3 6
----------------------------------------------------------
Total Revenues 483 23 137 74 179 22
Less: Expenses
Operating 71 18 62 23 49 2
Depreciation,
Depletion,
Amortization and
Impairment 162 30 13 67 19 2
Transportation
and Other 3 3 5 2 7 -
General and
Administrative(3) 8 11 - 13 4 5
Exploration 7 24 - 40 - 18 (4)
Interest - - - - - -
----------------------------------------------------------
Income (Loss) from
Continuing
Operations
before Income
Taxes 232 (63) 57 (71) 100 (5)
Less: Provision
for (Recovery
of) Income Taxes 102 (15) 14 (30) 35 (5)
Less:
Non-Controlling
Interests - - - - - -
Add: Net Income
from Discontinued
Operations - - - - - -
----------------------------------------------------------
Net Income (Loss) 130 (48) 43 (41) 65 -
----------------------------------------------------------
----------------------------------------------------------
Identifiable
Assets 5,157 7,756 (5) 1,244 1,880 241 976
----------------------------------------------------------
----------------------------------------------------------
Capital
Expenditures
----------------------------------------------------------
Exploration &
Development 165 177 17 77 11 139
----------------------------------------------------------
----------------------------------------------------------
Property, Plant
and Equipment
Cost 6,165 9,558 1,424 3,957 2,516 782
Less: Accumulated
DD&A 2,396 1,955 264 2,507 2,369 97
----------------------------------------------------------
Net Book Value 3,769 7,603 (5) 1,160 1,450 147 685
----------------------------------------------------------
----------------------------------------------------------
Energy Corporate
Marketing Chemicals and Other Total
----------------------------------------------------------------------------
Net Sales 9 115 - 1,034
Marketing and Other 188 29 71 (2) 296
---------------------------------------
Total Revenues 197 144 71 1,330
Less: Expenses
Operating 5 67 - 297
Depreciation, Depletion, Amortization
and Impairment 14 12 10 329
Transportation and Other 141 13 6 180
General and Administrative(3) 19 9 39 108
Exploration - - - 89
Interest - 2 82 84
---------------------------------------
Income (Loss) from
Continuing Operations before Income
Taxes 18 41 (66) 243
Less: Provision for (Recovery
of) Income Taxes 8 9 (9) 109
Less: Non-Controlling Interests - 12 - 12
Add: Net Income from
Discontinued Operations - - - -
---------------------------------------
Net Income (Loss) 10 20 (57) 122
---------------------------------------
---------------------------------------
Identifiable Assets 3,114 (6) 704 1,997 23,069
---------------------------------------
---------------------------------------
Capital Expenditures
---------------------------------------
Exploration & Development 9 53 7 655
---------------------------------------
---------------------------------------
Property, Plant and Equipment
Cost 250 1,086 356 26,094
Less: Accumulated DD&A 78 552 234 10,452
---------------------------------------
Net Book Value 172 534 122 15,642
---------------------------------------
---------------------------------------
(1) Includes results of operations from producing activities in Colombia.
(2) Includes interest income of $1 million, foreign exchange gains of $93
million and a decrease in the fair value of crude oil put options of
$23 million.
(3) Includes recovery of stock-based compensation expense of $5 million.
(4) Includes exploration activities primarily in Norway, Nigeria and
Colombia.
(5) Includes PP&E costs of $5,946 million related to our insitu oil sands
projects (Long Lake and future phases).
(6) Approximately 80% of Marketing's identifiable assets are accounts
receivable and inventories.
Nine months ended September 30, 2010
Oil and Gas
----------------------------------------------------------------------------
United United Other
Kingdom Canada(1) Syncrude States Yemen Countries (2)
----------------------------------------------------------
Net Sales 2,243 353 416 310 518 42
Marketing and
Other 14 63 4 1 12 -
----------------------------------------------------------
Total Revenues 2,257 416 420 311 530 42
Less: Expenses
Operating 237 327 212 70 115 4
Depreciation,
Depletion,
Amortization and
Impairment 578 192 39 250 88 7
Transportation
and Other 4 147 16 2 8 1
General and
Administrative(4) 18 29 1 41 2 18
Exploration 42 20 - 47 - 90 (5)
Interest - - - - - -
Net Loss on
Dispositions - (80) - - - -
----------------------------------------------------------
Income (Loss) from
Continuing
Operations
before Income
Taxes 1,378 (219) 152 (99) 317 (78)
Less: Provision
for (Recovery
of) Income Taxes 689 (55) 38 (35) 111 (70)
Less:
Non-Controlling
Interests - - - - - -
Add: Net Income
from Discontinued
Operations - 590 - - - -
----------------------------------------------------------
Net Income (Loss) 689 426 114 (64) 206 (8)
----------------------------------------------------------
----------------------------------------------------------
Identifiable
Assets 4,912 7,915 (6) 1,302 1,675 207 1,344 (7)
----------------------------------------------------------
----------------------------------------------------------
Capital
Expenditures
----------------------------------------------------------
Exploration &
Development 460 662 71 156 40 404
----------------------------------------------------------
----------------------------------------------------------
Property, Plant
and Equipment
Cost 6,530 8,600 1,531 3,993 2,453 1,267
Less: Accumulated
DD&A 3,170 827 301 2,713 2,367 100
----------------------------------------------------------
Net Book Value 3,360 7,773 (6) 1,230 1,280 86 1,167 (7)
----------------------------------------------------------
----------------------------------------------------------
Energy Corporate
Marketing Chemicals and Other Total
----------------------------------------------------------------------------
Net Sales 29 336 - 4,247
Marketing and Other 282 13 (16) (3) 373
---------------------------------------
Total Revenues 311 349 (16) 4,620
Less: Expenses
Operating 25 228 - 1,218
Depreciation, Depletion,
Amortization and Impairment 14 36 30 1,234
Transportation and Other 274 38 11 501
General and Administrative (4) 51 25 131 316
Exploration - - - 199
Interest - 7 231 238
Net Loss on Dispositions 259 - - 179
---------------------------------------
Income (Loss) from Continuing
Operations before Income Taxes (312) 15 (419) 735
Less: Provision for (Recovery
of) Income Taxes (122) 4 (190) 370
Less: Non-Controlling Interests - 4 - 4
Add: Net Income from
Discontinued Operations 26 - - 616
---------------------------------------
Net Income (Loss) (164) 7 (229) 977
---------------------------------------
---------------------------------------
Identifiable Assets 2,247 (8) 771 1,858 22,231
---------------------------------------
---------------------------------------
Capital Expenditures
---------------------------------------
Exploration & Development 25 121 26 1,965
---------------------------------------
---------------------------------------
Property, Plant and Equipment
Cost 234 1,244 397 26,249
Less: Accumulated DD&A 70 592 274 10,414
---------------------------------------
Net Book Value 164 652 123 15,835
---------------------------------------
---------------------------------------
(1) Includes results of operations from conventional, oilsands, shale gas
and CBM.
(2) Includes results of operations from producing activities in Colombia.
(3) Includes interest income of $6 million, foreign exchange losses of $7
million, decrease in the fair value of crude oil put options of $18
million and other gains of $3 million.
(4) Includes recovery of stock-based compensation expense of $34 million.
(5) Includes exploration activities primarily in Norway and Colombia.
(6) Includes PP&E costs of $6,133 million related to our insitu oil sands
projects (Long Lake and future phases).
(7) Includes PP&E costs of $1,119 million related to Nigeria.
(8) Approximately 82% of Marketing's identifiable assets are accounts
receivable and inventories.
Nine months ended September 30, 2009
Oil and Gas
----------------------------------------------------------------------------
United United Other
Kingdom Canada Syncrude States Yemen Countries (1)
----------------------------------------------------------
Net Sales 1,574 112 320 225 513 55
Marketing and
Other 13 2 1 - 10 6
----------------------------------------------------------
Total Revenues 1,587 114 321 225 523 61
Less: Expenses
Operating 175 51 205 73 145 6
Depreciation,
Depletion,
Amortization and
Impairment 537 91 33 215 92 11
Transportation
and Other 14 7 17 18 25 -
General and
Administrative (3) 15 41 1 51 5 29
Exploration 26 53 - 87 -- 53 (4)
Interest - - - - - -
----------------------------------------------------------
Income (Loss) from
Continuing
Operations
before Income
Taxes 820 (129) 65 (219) 256 (38)
Less: Provision
for (Recovery
of) Income Taxes 358 (32) 16 (81) 89 (29)
Less:
Non-Controlling
Interests - - - - - -
Add: Net Loss from
Discontinued
Operations - (20) - - - -
----------------------------------------------------------
Net Income (Loss) 462 (117) 49 (138) 167 (9)
----------------------------------------------------------
----------------------------------------------------------
Identifiable
Assets 5,157 7,756 (5) 1,244 1,880 241 976
----------------------------------------------------------
----------------------------------------------------------
Capital
Expenditures
Exploration &
Development 500 708 56 217 62 378
Proved Property
Acquisitions - 755 - - - -
----------------------------------------------------------
Total 500 1,463 56 217 62 378
----------------------------------------------------------
----------------------------------------------------------
Property, Plant
and Equipment
Cost 6,165 9,558 1,424 3,957 2,516 782
Less: Accumulated
DD&A 2,396 1,955 264 2,507 2,369 97
----------------------------------------------------------
Net Book Value 3,769 7,603 (5) 1,160 1,450 147 685
----------------------------------------------------------
----------------------------------------------------------
Energy Corporate
Marketing Chemicals and Other Total
----------------------------------------------------------------------------
Net Sales 29 348 - 3,176
Marketing and Other 676 44 (117) (2) 635
---------------------------------------
Total Revenues 705 392 (117) 3,811
Less: Expenses
Operating 21 196 - 872
Depreciation, Depletion,
Amortization and Impairment 21 53 34 1,087
Transportation and Other 469 37 19 606
General and Administrative (3) 68 34 119 363
Exploration - - - 219
Interest - 6 220 226
---------------------------------------
Income (Loss) from Continuing
Operations before Income Taxes 126 66 (509) 438
Less: Provision for (Recovery
of) Income Taxes 52 15 (264) 124
Less: Non-Controlling
Interests - 17 - 17
Add: Net Loss from
Discontinued Operations - - - (20)
---------------------------------------
Net Income (Loss) 74 34 (245) 277
---------------------------------------
---------------------------------------
Identifiable Assets 3,114 (6) 704 1,997 23,069
---------------------------------------
---------------------------------------
Capital Expenditures
Exploration & Development 20 161 17 2,119
Proved Property Acquisitions - - - 755
---------------------------------------
Total 20 161 17 2,874
---------------------------------------
---------------------------------------
Property, Plant and Equipment
Cost 250 1,086 356 26,094
Less: Accumulated DD&A 78 552 234 10,452
---------------------------------------
Net Book Value 172 534 122 15,642
---------------------------------------
---------------------------------------
(1) Includes results of operations from producing activities in Colombia.
(2) Includes interest income of $4 million, foreign exchange gains of $112
million, decrease in the fair value of crude oil put options of $218
million and other losses of $15 million.
(3) Includes stock-based compensation expense of $51 million.
(4) Includes exploration activities primarily in Norway, Nigeria and
Colombia.
(5) Includes PP&E costs of $5,946 million related to our insitu oil sands
projects (Long Lake and future phases).
(6) Approximately 80% of Marketing's identifiable assets are accounts
receivable and inventories.
20. DIFFERENCES BETWEEN CANADIAN AND US GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
The Unaudited Consolidated Financial Statements have been prepared in accordance with Canadian GAAP. The US GAAP Unaudited Consolidated Statements and summaries of differences from Canadian GAAP are as follows:
Unaudited Consolidated Statement of Income - US GAAP
For the Three and Nine Months Ended September 30
Three Months Nine Months
(Cdn$ millions, except per share Ended September 30 Ended September 30
amounts) 2010 2009 2010 2009
----------------------------------------------------------------------------
Revenues and Other Income
Net Sales 1,416 1,034 4,247 3,176
Marketing and Other (v); (vi) 129 344 432 702
---------------------------------------
1,545 1,378 4,679 3,878
---------------------------------------
Expenses
Operating 420 297 1,218 872
Depreciation, Depletion, Amortization
and Impairment 477 329 1,234 1,087
Transportation and Other (v) 142 186 501 604
General and Administrative (iv) 123 84 295 377
Exploration 56 89 199 219
Interest 81 84 238 226
Net Loss on Dispositions 259 - 179 -
---------------------------------------
1,558 1,069 3,864 3,385
---------------------------------------
Income (Loss) from Continuing
Operations before Provision for
Income Taxes (13) 309 815 493
---------------------------------------
Provision for (Recovery of) Income
Taxes
Current 270 190 793 514
Deferred (iv); (vi) (235) (68) (399) (377)
---------------------------------------
35 122 394 137
---------------------------------------
Net Income (Loss) from Continuing
Operations before Non
Controlling Interests (48) 187 421 356
Less: Net Income Attributable to
Canexus Non-Controlling
Interests (4) (12) (4) (17)
---------------------------------------
Net Income (Loss) from Continuing
Operations Attributable to
Nexen Inc. (52) 175 417 339
Net Income (Loss) from Discontinued
Operations 590 - 616 (20)
---------------------------------------
Net Income Attributable to Nexen Inc.
- US GAAP (1) 538 175 1,033 319
---------------------------------------
---------------------------------------
Earnings (Loss) Per Common Share from
Continuing Operations ($/share)
Basic (0.10) 0.34 0.79 0.65
---------------------------------------
---------------------------------------
Diluted (0.10) 0.33 0.79 0.65
---------------------------------------
---------------------------------------
Earnings Per Common Share ($/share)
Basic 1.03 0.34 1.97 0.61
---------------------------------------
---------------------------------------
Diluted 1.03 0.33 1.97 0.61
---------------------------------------
---------------------------------------
(1) Reconciliation of Canadian and US GAAP Net Income
Three Months Nine Months
Ended September 30 Ended September 30
2010 2009 2010 2009
----------------------------------------------------------------------------
Net Income Attributable to Nexen Inc
- Canadian GAAP 537 122 977 277
Impact of US Principles, Net of
Income Taxes:
Stock-based Compensation (iv) 7 17 16 (11)
Inventory Valuation (vi) (6) 29 40 46
Deferred Taxes (vii) - 7 - 7
----------------------------------------
Net Income Attributable to Nexen Inc
- US GAAP 538 175 1,033 319
----------------------------------------
----------------------------------------
Unaudited Consolidated Balance Sheet - US GAAP
September 30 December 31
(Cdn$ millions, except share amounts) 2010 2009
----------------------------------------------------------------------------
Assets
Current Assets
Cash and Cash Equivalents 1,210 1,700
Restricted Cash 35 198
Accounts Receivable 2,305 2,788
Inventories and Supplies (vi) 533 610
Other 142 185
----------------------------
Total Current Assets 4,225 5,481
----------------------------
Property, Plant and Equipment
Net of Accumulated Depreciation, Depletion,
Amortization and Impairment of $10,807
(December 31, 2009 - $11,200) (i); (iii) 15,786 15,443
Goodwill 316 339
Deferred Income Tax Assets 1,608 1,148
Deferred Charges and Other Assets 236 370
----------------------------
Total Assets 22,171 22,781
----------------------------
----------------------------
Liabilities
Current Liabilities
Accounts Payable and Accrued Liabilities (iv) 3,015 3,131
Accrued Interest Payable 78 89
Dividends Payable 26 26
----------------------------
Total Current Liabilities 3,119 3,246
----------------------------
Long-Term Debt 5,678 7,251
Deferred Income Tax Liabilities (i); (ii); (iv);
(vi); (vii) 3,060 2,720
Asset Retirement Obligations 1,007 1,018
Deferred Credits and Other Liabilities (ii) 871 1,126
Equity
Nexen Inc. Shareholders' Equity
Common Shares, no par value
Authorized: Unlimited
Outstanding: 2010 - 525,032,386 shares
2009 - 522,915,843 shares 1,097 1,049
Contributed Surplus - 1
Retained Earnings (i); (iii); (iv); (vi); (vii) 7,530 6,575
Accumulated Other Comprehensive Loss (ii) (275) (269)
----------------------------
Total Nexen Inc. Shareholders' Equity 8,352 7,356
Canexus Non-Controlling Interests 84 64
----------------------------
Total Equity 8,436 7,420
----------------------------
Commitments, Contingencies and Guarantees
Total Liabilities and Equity 22,171 22,781
----------------------------
----------------------------
Unaudited Consolidated Statement of Comprehensive Income - US GAAP
For the Three and Nine Months Ended September 30
Three Months Nine Months
Ended September 30 Ended September 30
2010 2009 2010 2009
----------------------------------------------------------------------------
Net Income Attributable to Nexen
Inc. - US GAAP 538 175 1,033 319
Other Comprehensive Loss, Net of
Income Taxes:
Foreign Currency Translation
Adjustment (7) (26) (6) (49)
---------------------------------------
Comprehensive Income Attributable to
Nexen Inc. - US GAAP 531 149 1,027 270
---------------------------------------
---------------------------------------
Unaudited Consolidated Statement of Accumulated Other Comprehensive
Loss - US GAAP
September 30 December 31
2010 2009
----------------------------------------------------------------------------
Foreign Currency Translation
Adjustment (196) (190)
Unamortized Defined Benefit Pension
Plan Costs (ii) (79) (79)
-----------------------------
Accumulated Other Comprehensive Loss (275) (269)
-----------------------------
-----------------------------
There are currently no differences between our Canadian and US GAAP Cash Flow and as such we have not presented a separate US GAAP Cash Flow Statement.
Notes to the Unaudited Consolidated US GAAP Financial Statements:
i. Under Canadian GAAP, we deferred certain development costs to PP&E. Under US principles, these costs have been included in operating expenses in prior years. As a result, PP&E is lower under US GAAP by $30 million (December 31, 2009 - $30 million) and deferred income tax liabilities are lower by $11 million (December 31, 2009 - $11 million).
ii. US GAAP requires the recognition of the over-funded and under-funded status of a defined benefit plan on the balance sheet as an asset or liability. At September 30, 2010 and December 31, 2009, the unfunded amount of our defined benefit pension plans that was not included in the pension liability under Canadian GAAP was $105 million. This amount has been included in deferred credits and other liabilities and $79 million, net of income taxes, has been included in Accumulated Other Comprehensive Loss (AOCL).
iii. On January 1, 2003, we adopted Accounting for Asset Retirement Obligations for US GAAP reporting purposes. We adopted the equivalent Canadian standard for asset retirement obligations on January 1, 2004. These standards are consistent except for the adoption date which results in our PP&E under US GAAP being lower by $19 million.
iv. Under Canadian principles, we record obligations for liability-based stock compensation plans using the intrinsic-value method of accounting. Under US principles, obligations for liability-based stock compensation plans are recorded using the fair-value method of accounting. In addition, under Canadian principles, we retroactively adopted EIC-162 which required the accelerated recognition of stock-based compensation expense for all stock-based awards made to our retired and retirement-eligible employees. However, US GAAP required the accelerated recognition of stock-based compensation expense for such employees for awards granted on or after January 1, 2006. As a result under US GAAP:
- general and administrative (G&A) expense is lower by $9 million and $21 million, ($7 million and $16 million, net of income taxes), for the three and nine months ended September 30, 2010, (2009 - lower by $24 million and higher by $14 million, respectively, ($17 million and $11 million, net of income taxes)); and
- accounts payable and accrued liabilities are higher by $72 million as at September 30, 2010 (December 31, 2009 - $93 million) and deferred income tax liabilities are $21 million lower (December 31, 2009 - $26 million).
v. Under US GAAP, asset disposition gains and losses are included with transportation and other expense. For the three and nine months ended September 30, 2010 there were no gains or losses reclassified from marketing and other income to transportation and other expense (losses of $6 million and gains of $2 million, respectively were reclassified for the three and nine months ended September 30, 2009).
vi. Under Canadian GAAP, we carry our commodity inventory held for trading purposes at fair value, less any costs to sell. Under US GAAP, we are required to carry this inventory at the lower of cost or net realizable value. As a result:
- marketing and other income is lower by $9 million and higher by $59 million (lower by $6 million and higher by $40 million, net of income taxes) for the three and nine months ended September 30, 2010 (2009 - higher by $42 million and $69 million ($29 million and $46 million, net of income taxes)); and
- inventories are lower by $11 million as at September 30, 2010 (December 31, 2009 - lower by $70 million) and deferred income tax liabilities are $4 million lower (December 31, 2009 - lower by $23 million).
vii. Under US GAAP, we are required to apply FIN48 Accounting for Uncertainty in Income Taxes regarding accounting and disclosure for uncertain tax positions.
As at September 30, 2010, the total amount of our unrecognized tax benefit was approximately $296 million, all of which, if recognized, would affect our effective tax rate. To the extent interest and penalties may be assessed by taxing authorities on any underpayment of income tax, such amounts have been accrued and are classified as a component of income taxes in the Unaudited Consolidated Statement of Income. As at September 30, 2010, the total amount of interest and penalties related to uncertain tax positions recognized in deferred income tax liabilities in the US GAAP - Unaudited Consolidated Balance Sheet was approximately $9 million. We had no interest or penalties included in the US GAAP - Unaudited Consolidated Statement of Income for the three and nine months ended September 30, 2010.
Our income tax filings are subject to audit by taxation authorities and as at September 30, 2010 the following tax years remained subject to examination, (i) Canada - 1985 to date (ii) United Kingdom - 2008 to date and (iii) United States - 2005 to date. We do not anticipate any material changes to the unrecognized tax benefits previously disclosed within the next 12 months.
New Accounting Pronouncements - US GAAP
In January 2010, the Financial Accounting Standards Board issued guidance to improve financial instrument fair value measurement disclosures. The guidance requires entities to describe transfers between the three levels of the fair value hierarchy and present items separately in the level 3 reconciliation. This guidance is consistent with fair value measurement disclosures adopted for Canadian GAAP in 2009. Adoption of this guidance did not have an impact on our results of operations or financial position.
Contacts:
Michael J. Harris, CA
Vice President, Investor Relations
(403) 699-4688
Lavonne Zdunich, CA
Manager, Investor Relations
(403) 699-5821
Tim Chatten, P.Eng
Analyst, Investor Relations
(403) 699-4244
Pierre Alvarez
Vice President, Corporate Relations
(403) 699-6291
Kevin Reinhart, CA
Executive Vice President and CFO
(403) 699-5931
Nexen Inc.
801 - 7th Ave SW
Calgary, Alberta, Canada T2P 3P7
www.nexeninc.com
