CALGARY, ALBERTA--(Marketwire - July 14, 2011) - Nexen Inc. today reported second quarter 2011 operating and financial results, led by strong oil prices, high netbacks, and a portfolio weighted towards unhedged, Brent-priced oil. We generated cash flow from operations of $598 million ($1.13/share) and net income of $252 million ($0.48/share). Production of 204,000 barrels of oil equivalent per day (boe/d) reflects maintenance activities at our Buzzard platform in the UK North Sea which are expected to be completed in August. In light of our production in the first half of the year, we now expect company-wide production before royalties for the year to average between 210,000 and 230,000 boe/d.
During the quarter, we achieved several milestones. Our Usan project remains on track, with the floating production and storage offloading vessel (FPSO) enroute to site. The project is expected to achieve first oil in the first half of 2012. In our oil sands business, Long Lake production increased 9% over the first quarter and generated positive cash flow for the quarter. In June, we processed 45,000 barrels per day (bbls/d) of proprietary and third- party bitumen volumes (28,900 bbls/d and 16,100 bbls/day respectively) achieving approximately 65% of upgrader capacity. We continued to advance various initiatives for resource development to fill the upgrader. We also continued our industry-leading execution in our shale gas business with the drilling of a nine-well pad. We began fracing and completion activities during the quarter, and first production from this pad is expected in the fourth quarter. We also commenced drilling an 18-well pad.
Our exploration efforts advanced in the Gulf of Mexico. We received a drilling permit for our Kakuna exploration well and commenced drilling late in June. Our partner, Shell, received a drilling permit for an appraisal well to follow up our Appomattox discovery.
"While we are disappointed with the downtime at Buzzard, we are making steady progress in all areas of our business. We continue to focus on developing our attractive opportunity portfolio and are advancing our near-term and longer-term value contributors to our business," said Marvin Romanow, President and Chief Executive Officer.
"The Gulf of Mexico is a key component of our significant resource potential, and we are excited to be back to drilling," continued Mr. Romanow. "We've spent the past several years building an attractive prospect inventory in the Gulf, and the value of the opportunity in this area was highlighted by the Appomattox discovery last year. Along with the North Sea and West Africa, the Gulf is expected to be integral to growing our conventional business for many years to come."
Highlights
Financial
- Cash flow from operations of $598 million ($1.13/share) and net income of $252 million ($0.48/share).
- Oil and gas operations generated a cash netback of $59.87/boe ($42.76/boe after tax).
- Achieved our first quarterly positive cash flow at Long Lake.
- Net debt decreased approximately 50% from a year ago. It is expected to increase in the second half of the year as our capital program is weighted more towards the latter half of the year as we increase our drilling activities.
Production
- Production of 204,000 boe/d (180,000 boe/d after royalties) was impacted by Buzzard's unscheduled maintenance and interruptions to a third-party operated natural gas export pipeline which constrain oil production to minimize gas flaring. We also had unscheduled downtime at Syncrude.
- At Long Lake, production increased 9% over the prior quarter to 27,900 bbls/d gross (18,100 bbls/d net to Nexen).
Project Advancements
- Received drilling permits for the Appomattox appraisal well and Kakuna exploration well in the deepwater Gulf of Mexico. Commenced drilling the Kakuna well and brought in Statoil USA E&P Inc. as a partner on a promoted basis.
- Continued industry-leading pace of drilling at our shale gas operations in the Horn River. We have strong interest in our joint venture process.
- Advancing various projects to develop high quality resource to fill the Long Lake upgrader, including acceleration of development of a portion of the Kinosis lease.
- Successfully ran the Long Lake upgrader at approximately 65% of capacity, with an on-stream factor of 96% during June.
- Continued drilling on pads 12 and 13 at Long Lake, and converted several pad 11 wells from circulation to production.
- Usan FPSO set sail for location offshore Nigeria, West Africa.
Financial Summary Three Months Ended Six Months Ended ---------------------------------------------------------------------------- June 30 March 31 June 30 June 30 June 30 (Cdn$ millions) 2011 2011 2010 2011 2010 ---------------------------------------------------------------------------- Average Daily Production (mboe/d) Before Royalties 204 232 248 218 250 After Royalties 180 207 218 194 220 Cash flow from operations(1) 598 669 549 1,267 1,098 Per common share ($/share) 1.13 1.27 1.05 2.40 2.09 Net income 252 202 245 454 386 Per common share ($/share) 0.48 0.38 0.47 0.86 0.74 Capital investment(2) 530 499 840 1,029 1,410 Net debt(3) 2,838 3,350 5,492 2,838 5,492 ---------------------------------------------- (1) For reconciliation of this non-GAAP measure, see Cash Flow from Operations on pg. 11. (2) Includes geological and geophysical expenditures. (3) Net debt is defined as long-term debt and short-term borrowings less cash and cash equivalents.
Our portfolio weighting towards unhedged, Brent-priced oil contributed to strong cash flow in the quarter. Brent averaged US$117.36 per barrel, a premium of US$14.80 per barrel over WTI. Our approach to hedging allows us to benefit when prices rise, while giving us some protection if prices decline below certain levels. Higher realized crude oil prices, which averaged $110.28 per barrel, partially offset lower production from temporary downtime at Buzzard and Syncrude and natural declines in Yemen. Also contributing to cash flow was our Long Lake operation, which generated its first positive quarterly cash flow of $6 million as compared to a loss of $19 million in the first quarter. Higher production, prices and upgrader throughput contributed to this positive cash flow.
Net income increased from the prior quarter. The first quarter included the impact of the UK tax rate change which resulted in an accrual for higher income taxes of $336 million. This was partially offset by a $299 million after-tax gain on the sale of Canexus.
Net debt has declined about 50% over the past year following our successful asset disposition program and a stronger Canadian dollar. This amount is expected to rise in the second half of the year due to the timing of our capital spending and working capital changes. Capital investment is expected to increase in the latter half of the year with the increased drilling in the Gulf of Mexico, the North Sea and for Canadian shale gas and oil sands.
Production Average Daily Quarterly Average Daily Quarterly Production before Royalties Production after Royalties Crude Oil, NGLs and Natural Gas (mboe/d) Q2 2011 Q1 2011 Q2 2010 Q2 2011 Q1 2011 Q2 2010 ---------------------------------------------------------------------------- North Sea 84 103 105 84 103 105 Yemen 35 38 41 19 20 22 United States 25 26 26 22 23 23 Canada - Oil & Gas(1) 20 23 35 19 21 29 Canada - Syncrude 20 23 23 18 22 22 Canada - Bitumen 18 17 16 17 16 15 Other Countries 2 2 2 1 2 2 --------------------------------------------------------- Total 204 232 248 180 207 218 --------------------------------------------------------- (1) Q2, 2010 includes production before royalties of 15 mboe/d and production after royalties of 12 mboe/d from discontinued operations as disclosed in Note 14 to our Unaudited Condensed Consolidated Financial Statements
The Buzzard field continues to be our largest producing asset and typically contributes 85,000 to 95,000 boe/d net to Nexen. Production in the quarter averaged 114,000 boe/d (49,000 boe/d net to Nexen). This reflects unscheduled maintenance to repair the cooling system and interruptions to a third-party operated natural gas export pipeline which constrain oil production to minimize gas flaring. While the repair work proceeded on schedule, production was lower than expected due to the gas export restrictions. Production is expected to be back to full rates in August.
We utilized Buzzard's downtime to bring forward maintenance work originally scheduled for September. Further maintenance work will be advanced to August when the third-party operated Forties pipeline system undergoes a one-week shutdown. As a result, the September shutdown will not be required.
Yemen production reflects natural field declines following the completion of development drilling activities as we near the end of the primary contract term in December of this year, and by the two-day shutdown during a labour strike. This was the longest disruption in our Yemen operations since production began in 1993. Following a successful restart, the facility quickly returned to normal production. We remain confident that we can continue to manage our operations during the current period of uncertainty in the country. Safety and security continue to be our primary focus.
Unscheduled maintenance on the LC Finer and the Vacuum Distillation Unit impacted Syncrude production. The repairs have been completed and production subsequently returned to full rates.
At Long Lake, bitumen production averaged 27,900 bbls/d gross (18,100 bbls/d net to Nexen), up 2,300 bbls/d from the first quarter. Production is increasing as a result of higher steam injection following the hot lime softener (HLS) scheduled maintenance, well optimizations and the continuing ramp-up of the new pad 11 wells. Production at the end of June was approximately 30,000 bbls/d and we expect production from Long Lake to continue to increase into the mid-30,000 bbls/d range by year-end.
Long Lake Quarterly Operating Results ------------------------------------------------------------------------- Bitumen Steam Unit Production (Gross) Injection (Gross) Operating Costs(1) ----------------------------------------------------------------- bbls/d bbls/d $/bbl 2011 Q2 27,900 152,000 95 Q1 25,500 146,000 89 2010 Q4 28,100 158,000 86 Q3 25,700 146,000 85 Q2 24,900 137,000 90 Q1 18,700 114,000 154 2009 Q4 13,600 77,000 150 Q3 8,500 48,000 180 Q2 14,300 75,000 160 Q1 12,500 66,000 220 (1) Unit operating costs are based on volumes sold and exclude activities related to third-party bitumen purchased, processed and sold.
Unit operating costs temporarily increased in the first half of this year due to planned and unplanned maintenance, along with initiatives to increase upgrader reliability and improve well performance. The first quarter included planned maintenance of the first HLS unit. The second quarter included planned maintenance on the second HLS unit and a cogeneration unit, as well as unplanned maintenance on the sulphur recovery units and gasifiers. The third HLS unit and second cogeneration unit are scheduled to undergo maintenance in August. Despite this increase in operating costs, the facility generated positive cash flow for the quarter due to higher production and prices, and increased upgrader throughput from Long Lake and third-party sourced bitumen.
Guidance Update
We generate a large portion of our production volumes from a relatively small number of high-netback fields. While our focus on developing high-netback legacy assets provides us with a competitive advantage in our operating areas and delivers attractive value, it results in our production being sensitive to operating rates in these areas.
Given the impact of operational events at Buzzard and Long Lake in the first half of the year, our annual production before royalties is now expected to be 210,000 to 230,000 boe/d. This is lower than we expected in May largely as a result of the gas export restrictions. The range reflects variability of production at Buzzard as we complete the cooling system repairs and the final stages of commissioning the fourth platform that will allow us to produce from our full suite of wells regardless of H2S levels. It also reflects variability in the Long Lake ramp-up, timing of Telford and Blackbird well tie-ins, and potential for hurricane disruptions in the Gulf of Mexico. The following provides production ranges by quarter and major areas:
Average Daily Annual Production before Average Daily Quarterly Production Royalties before Royalties 2011 Crude Oil, NGLs and Q1 2011 Q2 2011 Q3 2011 Q4 2011 Annual Natural Gas (mboe/d) (actual) (actual) (estimate) (estimate) (estimate) ---------------------------------------------------------------------------- Buzzard 71 49 67 - 74 82 - 95 67 - 72 Other UK 32 35 23 - 27 24 - 32 28 - 32 Yemen 38 35 32 - 34 24 - 33 32 - 35 United States 26 25 20 - 24 21 - 24 23 - 25 Canada - Oil & Gas 23 20 19 - 21 19 - 22 20 - 22 Canada - Syncrude 23 20 19 - 22 20 - 23 20 - 22 Canada - Bitumen 17 18 18 - 21 18 - 24 18 - 20 Other Countries 2 2 2 2 2 ------------------------------------------------------- Total 232 204 200 - 225 210 - 255 210 - 230 ------------------------------------------------------- -------------------------------------------------------
The production guidance for the various areas reflect:
- In the UK:
-- Buzzard repairs of the cooling system and completion of the start-up of the fourth platform continues into the third quarter. The facility will also be taken down in early August for the planned one-week shutdown of the third-party operated Forties pipeline. Once the fourth platform is available, production is expected to be strong as we will be able to almost double the number of available wells as we bring our higher concentration sour producers onstream.
-- Planned maintenance activities at Scott and Ettrick in the third quarter.
-- Production is expected to increase late in the year with the start-up of production from the tie-ins of the Telford TAC well to the Scott facility, and the Blackbird field to the Ettrick facility.
- In Yemen, production will continue with natural field declines. Our current contract expires in mid-December unless we receive a contract extension.
- In the U.S., the range of production is based on the potential for hurricane-related disruptions through the third quarter and into the early part of the fourth quarter.
- At Long Lake, the ongoing ramp-up of pad 11 and well optimizations are expected to contribute to modest production growth over the remainder of the year.
We expect to add new production next year with Usan coming on-stream in the first half of the year and the start-up of our 18-well shale gas pad and Long Lake pad 12 in the fourth quarter of the year.
Project Advancements
Nexen has numerous opportunities available with several development and appraisal projects underway, and a large resource base to support growth. Near-term projects include new production from a Telford development well; the Blackbird field tie-in; ongoing shale gas drilling; and the Rochelle development. Longer-term projects include Golden Eagle, Appomattox, Knotty Head and Owowo, along with further oil sands and shale gas development.
During the second quarter, we made significant progress on our key milestones in moving these projects into production and cash flow.
Conventional
Offshore West Africa - Development of the Usan field remains on track for first oil in the first half of 2012. Fabrication of the FPSO vessel in Korea is now complete. The FPSO is under tow and expected to arrive on location offshore Nigeria this summer for hook-up to the wells and commissioning. At full capacity, the project is capable of producing 180,000 boe/d (36,000 boe/d net to Nexen). Nexen has a 20% interest in Usan and the project joint venture partners are Total E&P Nigeria Limited (the operator), ExxonMobil and Chevron.
Gulf of Mexico - Shell, the operator of the Appomattox discovery, received approval of the supplemental Exploration Plan for a multi-well exploration and appraisal drilling program on the Appomattox discovery. They received a drilling permit for the first appraisal well and expect to spud it in the third quarter. This is the first of three wells planned to appraise Appomattox and adjacent structures. Nexen estimates the recoverable contingent resource for this discovery exceeds 250 million boe (gross) with further upside potential. Nexen has a 20% working interest in Appomattox and a 25% working interest in the nearby Vicksburg discovery.
Nexen received approval to drill the Kakuna exploration well which spud in late June in the vicinity of the producing Tahiti field and various other discoveries. Following the Kakuna well, we expect to drill the Angel Fire prospect once the drilling permit is approved. Farm-out negotiations continue on exploration prospects in the Gulf of Mexico.
UK North Sea - The approval process for the Golden Eagle development continues to progress well. Development of the field is expected to commence once all partners complete their approval processes and regulatory approvals are in place, which we expect to occur later this summer.
Regulatory approval was received for the Blackbird tieback to the Ettrick facility. We also continue to progress the tie-in of the Telford TAC well to the Scott platform. Blackbird and Telford are both on track to deliver increased production late this year. These projects, when combined with the Rochelle tie-back to the Scott platform, are expected to contribute approximately 10,000 to 20,000 boe/d net to Nexen by the end of 2012. Over the next 12 months, the company plans to drill an appraisal of the Polecat discovery and a number of exploration prospects, including the North Uist well west of the Shetland Islands.
Oil Sands
Long Lake - Our primary focus is on increasing our bitumen production to fill the upgrader. This provides us with an attractive return on capital as the predominantly fixed cost nature of the operation means that each incremental barrel of production contributes significantly to cash flow and profitability. With the upgrader operating at an average of about 50% capacity during the quarter, we generated positive cash flow. At full capacity and US$90 WTI, the project is expected to generate about $800 million of cash flow annually.
Our strategy for filling the upgrader includes:
- growth in production from the initial 10 pads;
- ramp-up of pad 11;
- start-up of pads 12 and 13 that are currently being drilled;
- drilling of pads 14 and 15 which we are targeting to commence drilling in 2012;
- identifying future drilling on the Long Lake and Kinosis leases; and
- processing of third-party sourced bitumen in the interim to enhance returns from this facility.
We believe the continued drilling of high-quality resource on Long Lake and the advancement of Kinosis drilling is the most economic and expedient strategy to grow and sustain our proprietary bitumen volumes to fill the upgrader.
Initially, we expected to fill the upgrader from the first 11 pads that are now on-stream; however, we underestimated the impact lean zones and shales would have on production rates and steam-oil ratio (SOR). We better understand the correlation between reservoir characteristics and production and SOR, based on the range of well performance we experienced in the initial wells. This understanding allows us to target the best quality resource for development that is analogous to the wells in our initial set that are exhibiting good performance. It also confirms that our oil sands lands, including undeveloped areas on the Long Lake lease, contain attractive resource.
We expect production from pads 1 to 11 to continue to increase over time from additional steam, heating through the lean zones, the ramp-up of wells as they mature, and well work-over activities. Production from pad 11 is currently approximately 1,700 bbls/d and is expected to contribute 4,000 to 8,000 bbls/d at maturity.
Pads 12 and 13 were the first to be targeted at the higher quality resource from across the entire lease rather than concentrating on the resource in the vicinity of the upgrader. Well logs and core data indicate these 18 wells are similar to our best producing wells on the lease, which are meeting or exceeding expectations. They also compare favorably with wells drilled on leases by other companies that match our performance expectations. Drilling on the two pads is in progress. Pad 12 is expected to start steaming in the second quarter of next year and pad 13 in the third quarter. Production is expected about three months after first steam and is expected to ramp-up to full rates over the following 12 to 18 months. We expect production from these two pads to contribute 11,000 to 17,000 bbls/d at maturity.
We plan to commence drilling 10 to 12 wells on pads 14 and 15 in 2012, subject to regulatory approvals. First steam to these wells is expected in late 2013. These wells are also targeting high quality resource. We expect production from these two pads to contribute 6,000 to 9,000 bbls/d at maturity.
We are also progressing the acceleration of the development of 25 to 30 wells at Kinosis, which is along the southern border of the Long Lake lease. Our core-hole analysis and reservoir understanding of Kinosis confirms the resource here has minimal lean zones and shale barriers. Well log and core data show these to be analogous to our best producing wells on Long Lake. Also, with core-holes in place and regulatory approval at an advanced stage, we expect to be able to develop these well pairs faster than for pads beyond 14 and 15. Production from these wells is expected to contribute 15,000 to 25,000 bbls/d at maturity. We expect to provide details regarding timing and cost of this opportunity later this year.
We expect these wells to fill the upgrader and offset production declines in the initial 10 pads.
To further evaluate our Long Lake and Kinosis leases for future development, we are proceeding with a 200 well core-hole drilling program this winter. This program supports our sustaining development activities to keep the Long Lake upgrader full and to begin development of the rest of the Kinosis lease using our bitumen-leading strategy. This strategy allows us to ramp-up SAGD production while retaining flexibility in the timing of building additional upgraders to enhance the economics of the developments.
We are also planning to participate with a 25% working interest in a non-operated SAGD project at Hangingstone. Project sanctioning is expected late this year or early next year, and first steam would be in about late 2014. Our share of production at full rates is expected to be about 6,000 bbls/d.
The upgrader continued to perform well with an on-stream factor of 91% and premium synthetic crude (PSC) yield of 70% compared to 93% and 74%, respectively, in the first quarter. In June, we successfully processed 45,000 bbls/d of produced and purchased bitumen, reaching upgrader throughput of about 65% of capacity. We will continue to purchase and upgrade third-party volumes when market and operating conditions are appropriate.
Shale Gas
Northeast British Columbia - Our shale gas strategy is progressing as planned and production from the eight-well pad at Horn River brought on-stream late last year continues to meet expectations. Horn River production averaged approximately 40 million cubic feet (mmcf/d) during the quarter. Plans to increase production at Horn River later this year continued to progress with our successful drilling program on the nine-well pad, where we once again set industry benchmarks for drilling days per well, including one well drilled in a record 14 days. We also began fracing and completion activities on the wells during the quarter. Production from this nine-well pad is expected on-stream in the fourth quarter but will be limited to our existing facility capacity of about 50 mmcf/d. This capacity increases to 175 mmcf/d in late 2012 to coincide with the start-up of production from our 18-well pad. We commenced drilling this pad in late June and production is expected to come on-stream in the fourth quarter of 2012. Additional facility capacity is planned to be added as our production increases. Our process to seek a joint venture partner to accelerate value realization for a portion of our shale gas asset is proceeding on schedule with numerous parties accessing the data room.
Director Appointments
During the second quarter, Nexen appointed two new directors to our Board, Thomas Ebbern and Arthur Scace, C.M., Q.C. Thomas Ebbern began his career as a geophysicist, and has recently held positions as managing director at Macquarie Capital Markets Canada Ltd., and managing director at Tristone Capital Inc., an energy advisory firm. Arthur Scace comes with a distinguished career in law, where he was former partner and chair of McCarthy Tetrault LLP. He has also sat on various boards, and was the former Chair of the Bank of Nova Scotia.
Quarterly Dividend
The Board of Directors has declared the regular quarterly dividend of $0.05 per common share payable October 1, 2011, to shareholders of record on September 9, 2011.
About Nexen
Nexen Inc. is an independent, Canadian-based global energy company, listed on the Toronto and New York stock exchanges under the symbol NXY. Nexen is focused on three growth strategies: oil sands and shale gas in Western Canada and conventional exploration and development primarily in the North Sea, offshore West Africa and deepwater Gulf of Mexico. Nexen adds value for shareholders through successful full-cycle oil and gas exploration and development, and leadership in ethics, integrity, governance and environmental stewardship.
For further information on Appomattox resource disclosure, please refer to our press release dated September 27, 2010.
Conference Call
Marvin Romanow, President and CEO, and Kevin Reinhart, Executive Vice President and CFO, will host a conference call to discuss our second quarter 2011 financial results.
Date: July 14, 2011
Time: 7:00 a.m. Mountain Time (9:00 a.m. Eastern Time)
To listen to the conference call, please call one of the following:
416-340-2216 (Toronto)
866-226-1792 (North American toll-free)
800-9559-6853 (Global toll-free)
A replay of the call will be available for two weeks starting at 9:00 a.m. Mountain Time, by calling 905-694-9451 (Toronto) or 800-408-3053 (toll-free) passcode 6758230 followed by the pound sign.
A live and on demand webcast of the conference call will be available at www.nexeninc.com.
Forward-Looking Statements
Certain statements in this release constitute "forward-looking statements" (within the meaning of the United States Private Securities Litigation Reform Act of 1995, as amended) or "forward-looking information" (within the meaning of applicable Canadian securities legislation). Such statements or information (together "forward-looking statements") are generally identifiable by the forward-looking terminology used such as "anticipate", "believe", "intend", "plan", "expect", "estimate", "budget", "outlook", "forecast" or other similar words and include statements relating to or associated with individual wells, regions or projects.
Any statements as to possible future crude oil, natural gas or chemicals prices; future production levels; future royalties and tax levels; future capital expenditures, their timing and their allocation to exploration and development activities; future earnings; future asset acquisitions or dispositions; future sources of funding for our capital program; future debt levels; availability of committed credit facilities; possible commerciality of our projects; development plans or capacity expansions; the expectation that we have the ability to substantially grow production at our oil sands facilities through controlled expansions; the expectation of achieving the production design rates from our oil sands facilities; the expectation that our oil sands production facilities continue to develop better and more sustainable practices; the expectation of cheaper and more technologically advanced operations; the expected design size of our operations; the expected timing and associated production impact of facilities turnarounds and maintenance; the expectation that we can continue to operate our offshore exploration, development and production facilities safely and profitably; future ability to execute dispositions of assets or businesses; future sources of liquidity, cash flows and their uses; future drilling of new wells; ultimate recoverability of current and long-term assets; ultimate recoverability of reserves or resources; expected finding and development costs; expected operating costs, future cost recovery oil revenues from our Yemen operations; the expectation of negotiating of an extension to certain of our production sharing agreements; the expectation of our ability to comply with the new safety and environmental rules enacted in the US at a minimal incremental cost, and of receiving necessary drilling permits for our US offshore operations; future demand for chemicals products; estimates on a per share basis; future foreign currency exchange rates, future expenditures and future allowances relating to environmental matters and our ability to comply therewith; dates by which certain areas will be developed, come on stream or reach expected operating capacity; and changes in any of the foregoing are forward-looking statements. Statements relating to "reserves" or "resources" are forward-looking statements, as they involve the implied assessment, based on estimates and assumptions that the reserves and resources described exist in the quantities predicted or estimated, and can be profitably produced in the future.
All of the forward-looking statements in this release are qualified by the assumptions that are stated or inherent in such forward-looking statements. Although we believe that these assumptions are reasonable, this list is not exhaustive of the factors that may affect any of the forward-looking statements and the reader should not place an undue reliance on these assumptions and such forward-looking statements. The key assumptions that have been made in connection with the forward-looking statements include the following: that we will conduct our operations and achieve results of operations as anticipated; that our development plans will achieve the expected results; the general continuance of current or, where applicable, assumed industry conditions; the continuation of assumed tax, royalty and regulatory regimes; the accuracy of the estimates of our reserve volumes; commodity price and cost assumptions; the continued availability of adequate cash flow and debt and/or equity financing to fund our capital and operating requirements as needed; and the extent of our liabilities. We believe the material factors, expectations and assumptions reflected in the forward-looking statements are reasonable, but no assurance can be given that these factors, expectations and assumptions will prove to be correct.
The forward-looking statements are subject to known and unknown risks and uncertainties and other factors which may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Such factors include, among others: market prices for oil and gas; our ability to explore, develop, produce, upgrade and transport crude oil and natural gas to markets; ultimate effectiveness of design or design modifications to facilities; the results of exploration and development drilling and related activities; the cumulative impact of oil sands development on the environment; the impact of technology on operations and processes and how new complex technology may not perform as expected; the availability of pipeline and global refining capacity; risks inherent to the operations of any large, complex refinery units, especially the integration between production operations and an upgrader facility; availability of third-party bitumen for use in our oil sands production facilities; labour and material shortages; risks related to accidents, blowouts and spills in connection with our offshore exploration, development and production activities, particularly our deepwater activities; direct and indirect risks related to the imposition of moratoriums, suspensions or cancellations of our offshore exploration, development and production operations, particularly our deepwater activities; the impact of severe weather on our offshore exploration, development and production activities, particularly our deepwater activities; the effectiveness and reliability of our technology in harsh and unpredictable environments; risks related to the actions and financial circumstances of our agents, counterparties, contractors, and joint venture parties; volatility in energy trading markets; foreign currency exchange rates; economic conditions in the countries and regions in which we carry on business; governmental actions including changes to taxes or royalties, changes in environmental and other laws and regulations including without limitation, those related to our offshore exploration, development and production activities; renegotiations of contracts; results of litigation, arbitration or regulatory proceedings; political uncertainty, including actions by terrorists, insurgent or other groups, or other armed conflict, including conflict between states; and other factors, many of which are beyond our control.
The impact of any one risk, uncertainty or factor on a particular forward-looking statement is not determinable with certainty as these factors are interdependent, and management's future course of action would depend on our assessment of all information at that time. Although we believe that the expectations conveyed by the forward-looking statements are reasonable based on information available to us on the date such forward-looking statements were made, no assurances can be given as to future results, levels of activity and achievements. Undue reliance should not be placed on the forward-looking statements contained herein, which are made as of the date hereof and, except as required by law, Nexen undertakes no obligation to update publicly or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The forward-looking statements contained herein are expressly qualified by this cautionary statement. Readers should also refer to the Risk Factors contained in our 2010 Annual Information form, and to the Quantitative Disclosures about Market Risk and our Forward Looking Statements contained in our 2010 Management Discussion and Analysis.
Cautionary Note to US Investors
In this disclosure, we may refer to "recoverable reserves", "recoverable resources", "recoverable contingent resources" and "prospective resources" which are inherently more uncertain than proved reserves or probable reserves. These terms are not used in our filings with the SEC. Our reserves and related performance measures represent our working interest before royalties, unless otherwise indicated. Please refer to our Annual Information Form available under our profile on SEDAR at www.sedar.com for further reserves disclosure.
Cautionary Note to Canadian Investors
Nexen has received an exemption from the securities regulatory authorities in the various provinces of Canada from certain requirements of National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities ("NI 51-101") that permits us to disclose reserves estimates and related disclosures that have been prepared in accordance with SEC requirements.
As a result of this exemption, Nexen's disclosures may differ from other Canadian companies and investors should note the following fundamental differences between reserves estimates and related disclosures prepared in accordance with SEC requirements and those prepared in accordance with NI 51-101:
- SEC reserves estimates are based upon different reserves definitions and are prepared in accordance with generally recognized industry practices in the US whereas NI 51-101 reserves are based on definitions and standards promulgated by the Canadian Oil and Gas Evaluation Handbook ("COGE Handbook") and generally recognized industry practices in Canada;
- SEC reserves definitions differ from NI 51-101 in areas such as the use of reliable technology, areal extent around a drilled location, quantities below the lowest known oil and quantities across an undrilled fault block;
- the SEC mandates disclosure of proved reserves and the Standardized Measure of Discounted Future Net Cash Flows and Changes Therein calculated using the year's monthly average prices and costs held constant whereas NI 51-101 requires disclosure of reserves and related future net revenues using forecast prices and costs;
- the SEC mandates disclosure of reserves by geographic area whereas NI 51-101 requires disclosure of reserves by additional categories and product types;
- the SEC does not require the disclosure of future net revenue of proved and proved plus probable reserves using forecast pricing at various discount rates;
- the SEC requires future development costs to be estimated using existing conditions held constant, whereas NI 51-101 requires estimation using forecast conditions;
- the SEC does not require the validation of reserves estimates by independent qualified reserves evaluators or auditors, whereas, without an exemption noted below, NI 51-101 requires issuers to engage such evaluators or auditors to evaluate, audit or review reserves and related future net revenue attributable to those reserves; and
- the SEC does not allow proved and probable reserves to be aggregated whereas NI 51-101 requires issuers to make such aggregation.
The foregoing is a general description of the principal differences only. The differences between SEC requirements and NI 51-101 may be material for certain properties. Please also note:
- we use oil equivalents (boe) to express quantities of natural gas and crude oil in a common unit. A conversion ratio of 6 mcf of natural gas to 1 barrel of oil is used. Boe may be misleading, particularly if used in isolation. The conversion ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead; and
- because reserves data are based on judgments regarding future events actual results will vary and the variations may be material. Variations as a result of future events are expected to be consistent with the fact that reserves are categorized according to the probability of their recovery.
Nexen has also received an exemption from NI 51-101 that permits us to forego the requirement to have our reserves and related future net revenue attributable to our reserves evaluated, audited or reviewed by an independent qualified reserves evaluator or auditor. Accordingly, our future net revenue and reserves estimates are based on internal evaluations. Due to the extent and expertise of our internal reserves evaluation resources, our staff's familiarity with our properties and the controls applied to the evaluation process, we believe the reliability of our internally generated reserves estimates is not materially less than would be generated by an independent reserves evaluator.
Resources
The resource estimates contained in this news release were announced on September 27, 2010 and were prepared by qualified reserves evaluators. The estimated contingent and prospective resources in this news release reflects all of our low, high and best case of recoverable resources. A "best estimate" is the best estimate of the quantity of resources that will actually be recovered. It is equally likely that the actual quantities recovered will be greater or less than the best estimate. Those resources that fall within the best estimate have a 50% confidence level that the actual quantities recovered will equal or exceed the estimate. The 'low estimate' and 'high estimate' are considered to be conservative and optimistic estimates of resources with 90% and 10% confidence respectively. Nexen's estimates of contingent and prospective resources are based on definitions set out in the Canadian Oil and Gas Evaluation Handbook. Contingent resources are quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Prospective resources are quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects.
Contingencies on resources may include, but are not limited to, factors such as economic, legal, environmental, political and regulatory matters or a lack of markets. Specific oil sands contingencies precluding these contingent resources being classified as reserves include but are not limited to: project sanction, the cost and effectiveness of steam-assisted gravity drainage application, stakeholder and regulatory approvals, access to required services and infrastructure, oil prices and a demonstration of economic viability. There is no certainty that it will be commercially viable to produce any portion of these contingent oil sands resources.
Specific shale gas contingencies precluding these contingent resources being classified as reserves include but are not limited to: future drilling program and testing results, project sanction, the cost and effectiveness of fracing optimization, stakeholder and regulatory approvals, access to required services and field development infrastructure, gas prices and a demonstration of economic viability. There is no certainty that it will be commercially viable to produce any portion of these contingent shale gas resources. In the case of shale gas prospective resources there is no certainty that any portion of the resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the resources.
Cautionary statement: In the case of discovered resources or a subcategory of discovered resources other than reserves, there is no certainty that it will be commercially viable to produce any portion of the resources. In the case of undiscovered resources or a subcategory of undiscovered resources, there is no certainty that any portion of the resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the resources.
Nexen Inc. Financial Highlights Three Months Ended Six Months Ended June 30 March 31 June 30 June 30 June 30 (Cdn$ millions) 2011 2011 2010 2011 2010 ---------------------------------------------------------------------------- Net Sales (1) 1,507 1,640 1,466 3,147 2,995 Cash Flow from Operations (1) 598 669 549 1,267 1,098 Per Common Share ($/share) 1.13 1.27 1.05 2.40 2.10 Net Income (1) 252 202 245 454 386 Per Common Share ($/share) 0.48 0.38 0.47 0.86 0.74 Capital Investment (2) 530 499 840 1,029 1,410 Net Debt (3) 2,838 3,350 5,492 2,838 5,492 Common Shares Outstanding (millions of shares) 527.0 526.7 524.6 527.0 524.6 -------------------------------------------- (1) Includes discontinued operations as discussed in Note 14 to our Unaudited Condensed Consolidated Financial Statements. (2) Includes oil and gas development, exploration, and expenditures for other property, plant and equipment. (3) Net debt is defined as long-term debt and short-term borrowings less cash and cash equivalents. Cash Flow from Operations(1) Three Months Ended Six Months Ended June 30 March 31 June 30 June 30 June 30 (Cdn$ millions) 2011 2011 2010 2011 2010 ---------------------------------------------------------------------------- Conventional Oil & Gas United Kingdom 699 887 658 1,586 1,325 North America (2) 91 65 91 156 229 Other Countries (3) 115 96 86 211 191 Oil Sands In Situ 6 (19) (19) (13) (77) Syncrude 103 107 80 210 145 ------------------------------------------------ 1,014 1,136 896 2,150 1,813 Interest, Marketing and Other Corporate Items (2) (90) (85) (122) (175) (274) Income Taxes (4) (326) (382) (225) (708) (441) ------------------------------------------------ Cash Flow from Operations(1) 598 669 549 1,267 1,098 ------------------------------------------------ ------------------------------------------------ (1) Defined as cash flow from operating activities before changes in non-cash working capital and other. We evaluate our performance and that of our business segments based on earnings and cash flow from operations. Cash flow from operations is a non-GAAP term that represents cash generated from operating activities before changes in non-cash working capital and other. We consider it a key measure as it demonstrates our ability to generate the cash flow necessary to fund future growth through capital investment. Cash flow from operations may not be comparable with the calculation of similar measures for other companies. Three Months Ended Six Months Ended June 30 March 31 June 30 June 30 June 30 (Cdn$ millions) 2011 2011 2010 2011 2010 ---------------------------------------------------------------------------- Cash Flow from Operating Activities 995 736 533 1,731 1,345 Changes in Non-Cash Working Capital Including Income Taxes and Interest Payable (405) (66) 58 (471) (198) Other 16 7 (30) 23 (27) Impact of Annual Crude Oil Put Options (8) (8) (12) (16) (22) -------------------------------------------------- Cash Flow from Operations 598 669 549 1,267 1,098 -------------------------------------------------- -------------------------------------------------- Weighted-average Number of Common Shares Outstanding (millions of shares) 527.0 526.3 524.5 526.6 524.0 -------------------------------------------------- Cash Flow from Operations Per Common Share ($/share) 1.13 1.27 1.05 2.40 2.10 -------------------------------------------------- -------------------------------------------------- (2) Includes discontinued operations as discussed in Note 14 to our Unaudited Condensed Consolidated Financial Statements. (3) After in-country cash taxes in Yemen of $58 million for the three months ended June 30, 2011 (March 31, 2011 - $42 million; June 30, 2010 - $39 million) and $100 million for the six months ended June 30, 2011 (2010 - $82 million). (4) Excludes in-country cash taxes in Yemen. Nexen Inc. Production Volumes (before royalties)(1) Three Months Six Months Ended June 30 Ended June 30 2011 2010 2011 2010 ---------------------------------------------------------------------------- Crude Oil and Liquids (mbbls/d) United Kingdom 77.6 98.2 87.3 101.9 Yemen 34.7 40.9 36.5 41.9 Oil Sands - Syncrude 20.4 23.4 21.8 21.5 Oil Sands - Long Lake Bitumen 18.1 16.2 17.4 14.2 United States 8.9 9.9 9.0 9.8 Canada (2) - 13.1 - 13.7 Other Countries 1.8 2.1 1.7 2.2 ------------------------------------- 161.5 203.8 173.7 205.2 ------------------------------------- Natural Gas (mmcf/d) United Kingdom 37 40 36 40 United States 96 96 99 98 Canada (2) 124 128 130 130 ------------------------------------- 257 264 265 268 ------------------------------------- Total Production (mboe/d) 204 248 218 250 ------------------------------------- ------------------------------------- Production Volumes (after royalties) Three Months Six Months Ended June 30 Ended June 30 2011 2010 2011 2010 ---------------------------------------------------------------------------- Crude Oil and Liquids (mbbls/d) United Kingdom 77.3 98.2 87.1 101.9 Yemen 18.8 22.2 19.7 22.6 Oil Sands - Syncrude 17.8 21.5 20.1 19.7 Oil Sands - Long Lake Bitumen 16.9 15.7 16.3 13.5 United States 8.0 8.9 8.1 8.9 Canada (2) - 10.0 - 10.4 Other Countries 1.6 2.0 1.6 2.1 ------------------------------------- 140.4 178.5 152.9 179.1 ------------------------------------- Natural Gas (mmcf/d) United Kingdom 37 40 36 40 United States 83 83 86 85 Canada (2) 119 117 123 119 ------------------------------------- 239 240 245 244 ------------------------------------- Total Production (mboe/d) 180 218 194 220 ------------------------------------- ------------------------------------- (1) We have presented production volumes before royalties as we measure our performance on this basis consistent with other Canadian oil and gas companies. (2) Includes the following production from discontinued operations in Note 14 to our Unaudited Condensed Consolidated Financial Statements. Three Months Six Months Ended June 30 Ended June 30 2011 2010 2011 2010 ---------------------------------------------------------------------------- Before Royalties Crude Oil and NGLs (mbbls/d) - 13.1 - 13.7 Natural Gas (mmcf/d) - 11 - 11 After Royalties Crude Oil and NGLs (mbbls/d) - 10.0 - 10.4 Natural Gas (mmcf/d) - 10 - 10 ------------------------------------ Nexen Inc. Oil and Gas Prices and Cash Netback(1) (all dollar amounts in Total Cdn$ unless Quarters - 2011 Quarters - 2010 Year noted) 1st 2nd 3rd 4th 1st 2nd 3rd 4th 2010 ---------------------------------------------------------------------------- PRICES: Brent Crude Oil (US$/bbl) 104.97 117.36 76.23 78.30 76.86 86.48 79.47 WTI Crude Oil (US$/bbl) 94.10 102.56 78.71 78.03 76.20 85.12 79.52 Nexen Average - Oil (Cdn$/bbl) 98.37 110.28 78.00 76.23 77.03 84.47 78.94 NYMEX Natural Gas (US$/mmbtu) 4.20 4.37 5.04 4.34 4.24 3.97 4.39 AECO Natural Gas (Cdn$/mcf) 3.58 3.54 5.08 3.66 3.52 3.41 3.92 Nexen Average - Gas (Cdn$/mcf) 4.51 4.75 5.37 4.42 4.18 4.16 4.54 ---------------------------------------------------------------------------- NETBACKS(1): ---------------------------------------------------------------------------- United Kingdom Crude Oil: Sales (mbbls/d) 104.2 73.3 106.5 102.1 103.9 110.0 105.6 Price Received ($/bbl) 99.97 110.55 77.24 77.18 77.45 83.88 79.02 Natural Gas: Sales (mmcf/d) 36 37 33 41 29 38 36 Price Received ($/mcf) 7.29 8.20 4.81 4.80 5.11 6.34 5.28 Total Sales Volume (mboe/d) 110.2 79.5 112.1 109.0 108.8 116.3 111.5 Price Received ($/boe) 96.91 105.76 74.84 74.12 75.35 81.37 76.51 Operating Costs 9.85 8.48 7.60 7.85 8.41 9.19 8.28 ---------------------------------------------------------------------------- Netback 87.06 97.28 67.24 66.27 66.94 72.18 68.23 ---------------------------------------------------------------------------- United States Crude Oil: Sales (mbbls/d) 9.2 8.9 9.8 9.9 9.8 10.1 9.9 Price Received ($/bbl) 91.39 101.89 79.12 73.60 73.72 80.41 76.73 Natural Gas: Sales (mmcf/d) 103 96 101 95 102 99 99 Price Received ($/mcf) 4.36 4.42 6.00 5.14 4.70 4.05 4.97 Total Sales Volume (mboe/d) 26.3 24.9 26.6 25.8 26.9 26.6 26.5 Price Received ($/boe) 48.91 53.56 51.92 47.23 44.85 45.55 47.35 Royalties & Other 5.65 6.11 4.92 4.86 5.10 (0.63) 3.55 Operating Costs 10.43 10.72 8.96 10.90 9.44 10.78 10.02 ---------------------------------------------------------------------------- Netback 32.83 36.73 38.04 31.47 30.31 35.40 33.78 ---------------------------------------------------------------------------- Canada - Natural Gas Sales (mmcf/d)(2) 97 85 124 121 107 104 114 Price Received ($/mcf) 3.65 3.62 5.02 3.72 3.43 3.48 3.94 Royalties & Other 0.28 0.24 0.40 0.34 0.26 0.24 0.32 Operating Costs 1.70 1.54 1.70 1.89 1.90 1.55 1.76 ---------------------------------------------------------------------------- Netback 1.67 1.84 2.92 1.49 1.27 1.69 1.86 ---------------------------------------------------------------------------- Yemen Sales (mbbls/d) 34.9 39.3 47.3 39.3 43.5 38.8 42.2 Price Received ($/bbl) 101.57 111.77 80.39 80.50 79.33 87.82 81.86 Royalties & Other 46.98 52.26 37.52 36.65 34.75 37.72 36.65 Operating Costs 10.75 9.18 9.67 10.01 9.46 12.05 10.25 In-country Taxes 13.48 16.26 10.14 10.97 10.70 11.52 10.80 ---------------------------------------------------------------------------- Netback 30.36 34.07 23.06 22.87 24.42 26.53 24.16 ---------------------------------------------------------------------------- (1) Defined as average sales price less royalties and other, operating costs, and in-country taxes in Yemen. (2) Excludes sales related to shale gas activities in north eastern British Columbia. (all dollar amounts in Total Cdn$ unless Quarters - 2011 Quarters - 2010 Year noted) 1st 2nd 3rd 4th 1st 2nd 3rd 4th 2010 ---------------------------------------------------------------------------- Other Countries Sales (mbbls/d) 1.8 1.7 2.3 2.1 2.0 1.9 2.1 Price Received ($/bbl) 93.52 106.57 78.88 74.77 75.93 77.63 76.83 Royalties & Other 6.22 6.93 5.72 5.28 5.22 5.24 5.37 Operating Costs 8.11 10.19 5.58 7.42 6.98 8.19 6.99 ---------------------------------------------------------------------------- Netback 79.19 89.45 67.58 62.07 63.73 64.20 64.47 ---------------------------------------------------------------------------- In Situ (2) Sales (mbbls/d) 12.9 14.3 6.6 10.3 11.9 12.1 10.3 Price Received ($/bbl) 89.82 108.78 81.04 74.08 70.64 82.99 77.07 Royalties & Other 3.58 6.05 4.37 2.98 3.08 3.81 3.65 Operating Costs 89.43 95.34 154.00 89.95 84.75 85.61 100.09 ---------------------------------------------------------------------------- Netback (2) (3.19) 7.39 (77.33) (18.84)(17.19) (6.43)(26.67) ---------------------------------------------------------------------------- Syncrude Sales (mbbls/d) 23.2 20.4 19.5 23.4 19.1 22.8 21.2 Price Received ($/bbl) 94.60 111.79 83.55 77.93 78.27 85.12 81.23 Royalties & Other 4.30 13.82 7.09 6.37 4.82 6.72 6.27 Operating Costs 36.11 39.98 35.84 32.67 38.06 31.65 34.34 ---------------------------------------------------------------------------- Netback 54.19 57.99 40.62 38.89 35.39 46.75 40.62 ---------------------------------------------------------------------------- Company-Wide Oil and Gas Sales (mboe/d) 225.5 196.4 249.1 243.1 232.9 235.9 240.2 Price Received ($/boe) 85.98 95.26 70.16 67.56 68.23 74.49 70.11 Royalties & Other 8.74 13.42 9.38 8.05 7.96 7.13 8.16 Operating & Other Costs(2) 17.32 18.68 14.93 15.85 15.42 15.97 15.48 In-country Taxes 2.08 3.29 1.92 1.76 2.00 1.89 1.90 ---------------------------------------------------------------------------- Netback 57.84 59.87 43.92 41.90 42.85 49.50 44.57 ---------------------------------------------------------------------------- (1) Defined as average sales price less royalties and other, operating costs, and in-country taxes in Yemen. (2) Excludes activities related to third-party bitumen purchased, processed and sold. Sales volumes and amounts relate to PSC sales made to third parties during the period. Nexen Inc. Unaudited Condensed Consolidated Statement of Income For the Three and Six Months Ended June 30 Three Months Six Months (Cdn$ millions, except per share Ended June 30 Ended June 30 amounts) 2011 2010 2011 2010 ---------------------------------------------------------------------------- Revenues and Other Income Net Sales 1,507 1,305 3,105 2,652 Marketing and Other Income (Note 13) 95 96 141 187 ------------------------------------- 1,602 1,401 3,246 2,839 ------------------------------------- Expenses Operating 341 321 704 644 Depreciation, Depletion, Amortization and Impairment 335 358 705 701 Transportation and Other 112 141 179 334 General and Administrative 76 40 181 149 Exploration 93 50 219 143 Finance (Note 8) 60 97 134 186 Loss on Debt Redemption and Repurchase (Note 7) 1 - 91 - Net Gain from Dispositions - (80) - (80) ------------------------------------- 1,018 927 2,213 2,077 ------------------------------------- Income from Continuing Operations before Provision for Income Taxes 584 474 1,033 762 ------------------------------------- Provision for (Recovery of) Income Taxes Current 384 264 808 523 Deferred (52) (28) 73 (110) ------------------------------------- 332 236 881 413 ------------------------------------- Net Income from Continuing Operations 252 238 152 349 Net Income from Discontinued Operations, Net of Tax (Note 14) - 7 302 37 ------------------------------------- Net Income Attributable to Nexen Inc. 252 245 454 386 ------------------------------------- ------------------------------------- Earnings Per Common Share from Continuing Operations ($/share) Basic 0.48 0.45 0.29 0.66 ------------------------------------- ------------------------------------- Diluted 0.45 0.42 0.27 0.62 ------------------------------------- ------------------------------------- Earnings Per Common Share ($/share) Basic 0.48 0.47 0.86 0.74 ------------------------------------- ------------------------------------- Diluted 0.45 0.43 0.84 0.69 ------------------------------------- ------------------------------------- See accompanying notes to the Unaudited Condensed Consolidated Financial Statements. Nexen Inc. Unaudited Condensed Consolidated Balance Sheet June 30 December 31 January 1 (Cdn$ millions) 2011 2010 2010 ---------------------------------------------------------------------------- Assets Current Assets Cash and Cash Equivalents 1,312 1,005 1,700 Restricted Cash 50 40 198 Accounts Receivable (Note 3) 1,871 1,789 2,322 Derivative Contracts 80 149 466 Inventories and Supplies (Note 4) 344 550 680 Other 148 142 185 Assets Held for Sale (Note 14) - 729 - --------------------------------- Total Current Assets 3,805 4,404 5,551 --------------------------------- Non-Current Assets Property, Plant and Equipment (Note 5) 14,628 14,579 14,669 Goodwill 276 286 330 Deferred Income Tax Assets 175 160 75 Derivative Contracts 27 116 225 Other Long-Term Assets 149 102 105 --------------------------------- Total Assets 19,060 19,647 20,955 --------------------------------- --------------------------------- Liabilities Current Liabilities Accounts Payable and Accrued Liabilities (Note 6) 2,988 2,459 2,681 Derivative Contracts 88 168 456 Accrued Interest Payable 74 83 89 Dividends Payable 26 26 26 Liabilities Held for Sale (Note 14) - 582 - --------------------------------- Total Current Liabilities 3,176 3,318 3,252 --------------------------------- Non-Current Liabilities Long-Term Debt (Note 7) 4,150 5,090 7,259 Deferred Income Tax Liabilities 1,636 1,487 1,678 Asset Retirement Obligations (Note 9) 1,561 1,516 1,397 Derivative Contracts 35 115 210 Other Long-Term Liabilities 321 307 372 Equity (Note 11) Nexen Inc. Shareholders' Equity Common Shares 1,142 1,111 1,050 Retained Earnings 7,094 6,692 5,704 Accumulated Other Comprehensive Loss (55) (37) - --------------------------------- Total Nexen Inc. Shareholders' Equity 8,181 7,766 6,754 Canexus Non-Controlling Interest (Note 14) - 48 33 --------------------------------- Total Equity 8,181 7,814 6,787 Commitments, Contingencies and Guarantees (Note 12) --------------------------------- Total Liabilities and Equity 19,060 19,647 20,955 --------------------------------- --------------------------------- See accompanying notes to Unaudited Condensed Consolidated Financial Statements. Nexen Inc. Unaudited Condensed Consolidated Statement of Cash Flows For the Three and Six Months Ended June 30 Three Months Six Months Ended June 30 Ended June 30 (Cdn$ millions) 2011 2010 2011 2010 ---------------------------------------------------------------------------- Operating Activities Net Income from Continuing Operations 252 238 152 349 Net Income from Discontinued Operations - 7 302 37 Charges and Credits to Income not Involving Cash (Note 15) 694 638 1,532 1,302 Exploration Expense 93 50 219 143 Income Taxes Paid (69) (43) (460) (250) Interest Paid (66) (101) (130) (190) Changes in Non-Cash Working Capital (Note 15) 121 (286) 153 (73) Other (11) 30 (18) 27 ------------------------------------- 1,014 533 1,750 1,345 Financing Activities Proceeds from Short-Term Borrowings - 156 - 156 Repayment of Term Credit Facilities, Net - (1,077) - (1,077) Repayment of Long-Term Debt (Note 7) (525) - (871) - Proceeds from Canexus Long-Term Debt, Net - 46 5 68 Dividends Paid on Common Shares (26) (26) (52) (52) Issue of Common Shares and Exercise of Tandem Options for Shares 8 10 31 35 Other (6) (16) (4) (20) ------------------------------------- (549) (907) (891) (890) Investing Activities Capital Expenditures Exploration, Evaluation, and Development (481) (748) (935) (1,236) Capitalized Interest Paid (29) (22) (57) (40) Corporate and Other (20) (70) (37) (134) Proceeds from Dispositions 12 81 474 96 Changes in Restricted Cash (2) 68 (11) 83 Changes in Non-Cash Working Capital (Note 15) 31 (13) 115 75 Other (23) (4) (75) (7) ------------------------------------- (512) (708) (526) (1,163) Effect of Exchange Rate Changes on Cash and Cash Equivalents (15) 55 (26) (22) ------------------------------------- Increase (Decrease) in Cash and Cash Equivalents (62) (1,027) 307 (730) Cash and Cash Equivalents - Beginning of Period 1,374 1,997 1,005 1,700 ------------------------------------- Cash and Cash Equivalents - End of Period (1) 1,312 970 1,312 970 ------------------------------------- ------------------------------------- (1) Cash and cash equivalents at June 30, 2011 consists of cash of $218 million and short-term investments of $1,094 million (June 30, 2010 - cash of $237 million and short-term investments of $733 million). See accompanying notes to the Unaudited Condensed Consolidated Financial Statements. Nexen Inc. Unaudited Condensed Consolidated Statement of Changes in Equity For the Three and Six Months Ended June 30 Three Months Six Months Ended June 30 Ended June 30 (Cdn$ millions) 2011 2010 2011 2010 ---------------------------------------------------------------------------- Common Shares, Beginning of Period 1,134 1,077 1,111 1,050 Issue of Common Shares 8 8 31 32 Exercise of Tandem Options for Shares - 2 - 3 Accrued Liability Relating to Tandem Options Exercised for Common Shares - 1 - 3 ------------------------------------- Balance at End of Period 1,142 1,088 1,142 1,088 ------------------------------------- ------------------------------------- Retained Earnings, Beginning of Period 6,868 5,819 6,692 5,704 Net Income Attributable to Nexen Inc. 252 245 454 386 Dividends on Common Shares (Note 11) (26) (26) (52) (52) ------------------------------------- Balance at End of Period 7,094 6,038 7,094 6,038 ------------------------------------- ------------------------------------- Accumulated Other Comprehensive Loss, Beginning of Period (48) (13) (37) - Other Comprehensive Income (Loss) Attributable to Nexen Inc. (7) 8 (18) (5) ------------------------------------- Balance at End of Period (55) (5) (55) (5) ------------------------------------- ------------------------------------- Canexus Non-Controlling Interests, Beginning of Period - 39 48 33 Net Income Attributable to Non-Controlling Interests - (6) 1 (1) Distributions Declared to Non-Controlling Interests - (3) - (7) Issue of Partnership Units to Non-Controlling Interests - 12 - 17 Disposition of Canexus (Note 14) - - (49) - ------------------------------------- Balance at End of Period - 42 - 42 ------------------------------------- ------------------------------------- See accompanying notes to the Unaudited Condensed Consolidated Financial Statements. Nexen Inc. Unaudited Condensed Consolidated Statement of Comprehensive Income For the Three and Six Months Ended June 30 Three Months Six Months Ended June 30 Ended June 30 (Cdn$ millions) 2011 2010 2011 2010 ---------------------------------------------------------------------------- Net Income 252 245 454 386 Other Comprehensive Income (Loss), Net of Income Taxes: Foreign Currency Translation Adjustment Net Gains (Losses) on Investment in Self-Sustaining Foreign Operations (35) 221 (139) 66 Net Gains (Losses) on Foreign-Denominated Debt Hedging of Self-Sustaining Foreign Operations (1) 28 (213) 121 (71) ------------------------------------- Other Comprehensive Income (Loss) Attributable to Nexen Inc. (7) 8 (18) (5) ------------------------------------- Total Comprehensive Income 245 253 436 381 ------------------------------------- ------------------------------------- (1) Net of income tax expense for the three months ended June 30, 2011 of $4 million (2010 - net of income tax recovery of $31 million) and net of income tax expense for the six months ended June 30, 2011 of $17 million (2010 - net of income tax recovery of $11 million). See accompanying notes to the Unaudited Condensed Consolidated Financial Statements.
Nexen Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
Cdn$ millions, except as noted
1. BASIS OF PRESENTATION
Nexen Inc. (Nexen, we or our) is an independent, global energy company with operations in the North Sea, Gulf of Mexico, offshore West Africa, Canada, Yemen and Colombia. Nexen is incorporated and domiciled in Canada. Nexen's shares are publicly traded on both the Toronto Stock Exchange and the New York Stock Exchange.
These Unaudited Condensed Consolidated Financial Statements for the three and six months ended June 30, 2011 have been prepared in accordance with International Accounting Standard (IAS) 34 Interim Financial Reporting. The Unaudited Condensed Consolidated Financial Statements do not include all of the information required for annual financial statements. Amounts relating to the three and six months ended June 30, 2010 and as at December 31, 2010 were previously presented in accordance with Canadian GAAP. These amounts have been restated as necessary to be compliant with our accounting policies under International Financial Reporting Standards ("IFRS") (see Note 2). Reconciliations and descriptions relating to the transition from Canadian GAAP to IFRS are included in Note 17.
The Unaudited Condensed Consolidated Financial Statements were authorized for issue on July 13, 2011 and should be read in conjunction with the Audited Consolidated Financial Statements for the year ended December 31, 2010, which have been prepared in accordance with Canadian GAAP.
2. ACCOUNTING POLICIES
The accounting policies we follow are described in Note 2 of the Unaudited Condensed Consolidated Financial Statements for the three months ended March 31, 2011.
Future Changes in Accounting Policies
As part of our transition to IFRS, we will adopt all IFRS accounting standards in effect on December 31, 2011.
The following standards and interpretations have not been adopted as they apply to future periods. They may result in future changes to our existing accounting policies and other note disclosures. We are currently evaluating the impact that these standards will have on our results of operations and financial position:
-- IFRS 9 Financial Instruments - in November 2009, the International Accounting Standards Board (IASB) issued IFRS 9 to address classification and measurement of financial assets. In October 2010, the IASB revised the standard to include financial liabilities. The standard is required to be adopted for periods beginning January 1, 2013. Portions of the standard remain in development and the full impact of the standard will not be known until the project is complete. -- IFRS 10 Consolidated Financial Statements - in May 2011, the IASB issued IFRS 10 which provides additional guidance to determine whether an investee should be consolidated. The guidance applies to all investees, including special purpose entities. The standard is required to be adopted for periods beginning January 1, 2013. We are evaluating the impact that this standard may have on our results of operations and financial position. -- IFRS 11 Joint Arrangements - in May 2011, the IASB issued IFRS 11 which presents a new model for determining whether an entity should account for joint arrangements using proportionate consolidation or the equity method. An entity will have to follow the substance rather than legal form of a joint arrangement and will no longer have a choice of accounting method. The standard is required to be adopted for periods beginning January 1, 2013. We are evaluating the impact that this standard may have on our results of operations and financial position. -- IFRS 12 Disclosure of Interests in Other Entities - in May 2011, the IASB issued IFRS 12 which aggregates and amends disclosure requirements included within other standards. The standard requires a company to provide disclosures about subsidiaries, joint arrangements, associates and unconsolidated structured entities. The standard is required to be adopted for periods beginning January 1, 2013. We are evaluating the impact that this standard may have on our results of operations and financial position. -- IFRS 13 Fair Value Measurement - in May 2011, the IASB issued IFRS 13 to provide comprehensive guidance for instances where IFRS requires fair value to be used. The standard provides guidance on determining fair value and requires disclosures about those measurements. The standard is required to be adopted for periods beginning January 1, 2013. We are evaluating the impact that this standard may have on our results of operations and financial position. -- IAS 1 Presentation of Items of Other Comprehensive Income - in June 2011, the IASB issued amendments to IAS 1 Presentation of Financial Statements to split items of other comprehensive income (OCI) between those that are reclassed to income and those that do not. The standard is required to be adopted for periods beginning on or after July 1, 2012. We are evaluating the impact that this standard may have on our results of operations and financial position. -- IAS 19 Employee Benefits - in June 2011, the IASB issued amendments to IAS 19 to revise certain aspects of the accounting for pension plans and other benefits. The amendments eliminate the corridor method of accounting for defined benefit plans, change the recognition pattern of gains and losses, and require additional disclosures. The standard is required to be adopted for periods beginning on or after January 1, 2013. We are evaluating the impact that this standard may have on our results of operations and financial position. 3. ACCOUNTS RECEIVABLE June 30 December 31 January 1 2011 2010 2010 ---------------------------------------------------------------------------- Trade Energy Marketing 1,069 929 1,410 Oil and Gas 706 822 823 Other 6 2 44 -------------------------------------- 1,781 1,753 2,277 Non-Trade 131 80 99 -------------------------------------- 1,912 1,833 2,376 Allowance for Doubtful Receivables (41) (44) (54) -------------------------------------- Total (1) 1,871 1,789 2,322 -------------------------------------- -------------------------------------- (1) At December 31, 2010, accounts receivable related to our chemicals operations have been included with assets held for sale (see Note 14). Receivables are generally on 30-day terms and were current as of June 30, 2011, December 31, 2010 and January 1, 2010. 4. INVENTORIES AND SUPPLIES June 30 December 31 January 1 2011 2010 2010 ---------------------------------------------------------------------------- Finished Products Energy Marketing 223 452 548 Oil and Gas 58 35 25 Other - - 12 -------------------------------------- 281 487 585 Work in Process 7 5 7 Field Supplies 56 58 88 -------------------------------------- Total (1) 344 550 680 -------------------------------------- -------------------------------------- (1) At December 31, 2010, inventories and supplies related to our chemicals operations have been included with assets held for sale (see Note 14). 5. PROPERTY, PLANT AND EQUIPMENT (a) Carrying amount of PP&E Exploration Producing and Assets Under Oil & Gas Corporate Evaluation Construction Properties and Other Total ---------------------------------------------------------------------------- Cost As at January 1, 2010 2,393 1,045 20,020 1,849 25,307 Additions 1,092 693 696 243 2,724 Disposals/ Derecognitions (70) (8) (1,638) (122) (1,838) Transfers (82) 78 4 - - Exploration Expense (326) - (2) - (328) Transferred to Held for Sale - - - (1,207) (1,207) Other 36 15 408 (3) 456 Effect of Changes in Exchange Rate (51) (75) (603) (3) (732) --------------------------------------------------------- As at December 31, 2010 2,992 1,748 18,885 757 24,382 Additions 427 270 294 37 1,028 Disposals/ Derecognitions (43) - (51) (11) (105) Transfers (235) 235 - - - Exploration Expense (218) - (1) - (219) Other 77 17 44 - 138 Effect of Changes in Exchange Rate (27) (59) (330) (3) (419) --------------------------------------------------------- As at June 30, 2011 2,973 2,211 18,841 780 24,805 --------------------------------------------------------- --------------------------------------------------------- Accumulated DD&A As at January 1, 2010 360 11 9,325 942 10,638 DD&A 41 - 1,384 119 1,544 Disposals/ Derecognitions (59) (8) (1,378) (62) (1,507) Impairment Losses - - 139 - 139 Transferred to Held for Sale - - - (578) (578) Other 1 - (7) (5) (11) Effect of Changes in Exchange Rate (12) (3) (409) 2 (422) --------------------------------------------------------- As at December 31, 2010 331 - 9,054 418 9,803 DD&A 24 - 645 36 705 Disposals/ Derecognitions (7) - (51) (8) (66) Other - - (2) - (2) Effect of Changes in Exchange Rate (7) - (253) (3) (263) --------------------------------------------------------- As at June 30, 2011 341 - 9,393 443 10,177 --------------------------------------------------------- --------------------------------------------------------- Net Book Value As at January 1, 2010 2,033 1,034 10,695 907 14,669 --------------------------------------------------------- --------------------------------------------------------- As at December 31, 2010 2,661 1,748 9,831 339 14,579 --------------------------------------------------------- --------------------------------------------------------- As at June 30, 2011 2,632 2,211 9,448 337 14,628 --------------------------------------------------------- ---------------------------------------------------------
Exploration and evaluation assets mainly comprise of unproved properties and capitalized exploration drilling costs. Assets under construction include our Usan development, offshore Nigeria.
(b) Impairment
Our DD&A expense for 2010 includes non-cash impairment charges of $139 million for properties in the US Gulf of Mexico and Canada. In the second half of 2010, low natural gas prices, higher estimated future abandonment costs and declining production performance reduced properties' estimated future cash flows, which resulted in impairments for properties in the US Gulf of Mexico and Canada.
These properties were written down to their estimated fair value based on their estimated future discounted net cash flows. The estimated future cash flows incorporate a risk-adjusted discount rate and management's estimates of future prices, capital expenditures and production.
6. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES
June 30 December 31 January 1 2011 2010 2010 ---------------------------------------------------------------------------- Energy Marketing Payables 1,051 1,016 1,366 Accrued Payables 664 676 619 Income Taxes Payable 733 345 179 Trade Payables 176 164 210 Stock-Based Compensation 99 111 173 Other 265 147 134 ----------------------------------- Total (1) 2,988 2,459 2,681 ----------------------------------- ----------------------------------- (1) At December 31, 2010, accounts payable and accrued liabilities related to our chemicals operations have been included with liabilities held for sale (see Note 14). 7. LONG-TERM DEBT June 30 December 31 January 1 2011 2010 2010 ---------------------------------------------------------------------------- Term Credit Facilities, due 2016 (a) - - 1,570 Notes, due 2013 (US$500 million) (b) - 497 523 Notes, due 2015 (US$126 million) (c) 121 249 262 Notes, due 2017 (US$62 million) (c) 60 249 262 Notes, due 2019 (US$300 million) 289 298 314 Notes, due 2028 (US$200 million) 193 199 209 Notes, due 2032 (US$500 million) 482 497 523 Notes, due 2035 (US$790 million) 762 786 827 Notes, due 2037 (US$1,250 million) 1,205 1,243 1,308 Notes, due 2039 (US$700 million) 675 696 733 Subordinated Debentures, due 2043 (US$460 million) 444 457 481 ------------------------------------- 4,231 5,171 7,012 Unamortized debt issue costs (81) (81) (88) ------------------------------------- 4,150 5,090 6,924 Canexus debt - - 335 ------------------------------------- Total 4,150 5,090 7,259 ------------------------------------- -------------------------------------
(a) Term credit facilities
We have unsecured term credit facilities of $3 billion (US$3.1 billion) available until 2016, none of which were drawn at either June 30, 2011 or December 31, 2010. Borrowings are available as Canadian bankers' acceptances, LIBOR-based loans, Canadian prime rate loans, US-dollar base rate loans or British pound call-rate loans. Interest is payable at floating rates. During the six months ended June 30, 2011, we did not incur any interest expense on our term credit facilities. The weighted-average interest rate on our term credit facilities for the three months ended June 30, 2010 was 1.3% and 1.1% for the six months ended June 30, 2010. At June 30, 2011, $279 million (US$289 million) of these facilities were utilized to support outstanding letters of credit (December 31, 2010 - $322 million (US$324 million)).
(b) Redemption of Notes, due 2013
During the quarter, we redeemed and cancelled US$500 million of principal from bonds due in 2013. We paid $525 million for the redemption. We recorded a $52 million loss during the first quarter as the difference between carrying value and the redemption price.
(c) Repurchase for Cancellation of Certain 2015 and 2017 Notes
In the first quarter, we repurchased and cancelled US$124 million and US$188 million of principal from the 2015 and 2017 bonds, respectively. We paid $346 million for the repurchase and recorded a $39 million loss as the difference between carrying value and the redemption price.
(d) Short-term borrowings
Nexen has uncommitted, unsecured credit facilities of approximately $463 million (US$481 million), none of which were drawn at either June 30, 2011 or December 31, 2010. We utilized $24 million (US$25 million) of these facilities to support outstanding letters of credit at June 30, 2011 (December 31, 2010-$112 million (US$112 million)). Interest is payable at floating rates.
8. FINANCE EXPENSE
Three Months Six Months Ended June 30 Ended June 30 2011 2010 2011 2010 ---------------------------------------------------------------------------- Long-Term Debt Interest Expense 74 89 158 180 Accretion Expense related to Asset Retirement Obligations (Note 9) 12 9 23 19 Other Interest Expense 3 17 10 21 --------------------------------- Total 89 115 191 220 Less: Capitalized at 6.5% (2010 - 5.2%) (29) (18) (57) (34) --------------------------------- Total (1) 60 97 134 186 --------------------------------- --------------------------------- (1) Excludes interest expense related to our chemical operations (see Note 14).
Capitalized interest relates to and is included as part of the cost of our oil and gas properties. The capitalization rates are based on our weighted-average cost of borrowings.
9. ASSET RETIREMENT OBLIGATIONS (ARO)
Changes in the carrying amount of our ARO provisions are as follows:
Six Months Twelve Months Ended June Ended December 30 31 2011 2010 ---------------------------------------------------------------------------- ARO, Beginning of Period 1,571 1,432 Obligations Incurred with Development Activities 19 81 Changes in Estimates 42 332 Obligations Related to Dispositions (3) (224) Obligations Settled (25) (43) Accretion 23 47 Effects of Changes in Foreign Exchange Rate (13) (54) -------------------------------- ARO, End of Period 1,614 1,571 -------------------------------- -------------------------------- Of which: Due within Twelve Months (1) 53 55 Due after Twelve Months 1,561 1,516 -------------------------------- -------------------------------- (1) Included in accounts payable and accrued liabilities.
ARO represents the present value of estimated remediation and reclamation costs associated with our PP&E. We have discounted the estimated asset retirement obligation using a weighted-average risk-free rate of 3.0% (2010-3.3%). While the provision for abandonment is based on our best estimates of future costs and the economic lives of the assets involved, there is uncertainty regarding both the amount and timing of incurring these costs. We expect approximately $367 million included in our ARO will be settled over the next five years with the balance settling beyond that. We expect to fund ARO from future cash flows from our operations.
10. RELATED PARTY DISCLOSURES
Major subsidiaries and joint ventures
The Unaudited Condensed Consolidated Financial Statements include the financial statements of Nexen Inc. and our subsidiaries as at June 30, 2011. The following is a list of the major subsidiaries of our operations. Transactions between subsidiaries are eliminated on consolidation. Nexen did not have any material related party transactions with entities outside the consolidated group in the six months ended June 30, 2011 and 2010.
Country of Principal Major subsidiaries Incorporation Activities Ownership ---------------------------------------------------------------------------- Nexen Petroleum UK Limited United Kingdom Oil & Gas 100% Nexen Ettrick UK Limited United Kingdom Oil & Gas 100% Nexen Petroleum Dragon UK Limited United Kingdom Oil & Gas 100% Nexen Petroleum Nigeria Limited Nigeria Oil & Gas 100% Nexen Petroleum Offshore USA Inc United States Oil & Gas 100% Canadian Nexen Petroleum Yemen Yemen Oil & Gas 100% Canadian Nexen Petroleum East Al Hajr Canada Oil & Gas 100% Nexen Petroleum Colombia Limited Jersey Oil & Gas 100% Nexen Med Hat-Hatton Partnership Canada Oil & Gas 100% Nexen Crossfield Partnership Canada Oil & Gas 100% Nexen Marketing Canada Marketing 100% Nexen Energy Marketing Europe United Kingdom Marketing 100% Nexen Energy Marketing USA Inc United States Marketing 100% Joint Venture Syncrude Canada Oil & Gas 7.23%
11. EQUITY
(a) Common Shares
Authorized share capital consists of an unlimited number of common shares of no par value and an unlimited number of Class A preferred shares of no par value, issuable in series. At June 30, 2011, there were 527,014,110 common shares outstanding (December 31, 2010 - 525,706,403 shares; January 1, 2010 - 522,915,843 shares). There were no preferred shares issued and outstanding (December 31, 2010 - nil; January 1, 2010 - nil).
(b) Dividends
Dividends paid per common share for the three months ended June 30, 2011 were $0.05 per common share (three months ended June 30, 2010 - $0.05). Dividends per common share for the six months ended June 30, 2011 were $0.10 per common share (six months ended June 30, 2010 - $0.10). Dividends paid to holders of common shares have been designated as "eligible dividends" for Canadian tax purposes. On July 13, 2011, the Board of Directors declared a quarterly dividend of $0.05 per common share, payable October 1, 2011 to the shareholders of record on September 9, 2011.
12. COMMITMENTS, CONTINGENCIES AND GUARANTEES
As described in Note 15 to the 2010 Audited Consolidated Financial Statements, there are a number of lawsuits and claims pending, the ultimate results of which cannot be ascertained at this time. We record costs as they are incurred or become determinable. We believe that payments, if any, related to existing indemnities, would not have a material adverse effect on our liquidity, financial condition or results of operations.
We assume various contractual obligations and commitments in the normal course of our operations. During the quarter, we entered into new drilling rig commitments in the UK North Sea and made additional office lease commitments, comprised of the following:
2011 2012 2013 2014 2015 Thereafter ---------------------------------------------------------------------------- Drilling Rig Commitments 39 71 12 - - - Operating Lease Commitments - 2 5 6 7 50 ---------------------------------------------
The commitments above are in addition to those included in Note 15 to the 2010 Audited Consolidated Financial Statements. Our operating leases, transportation and storage commitments, and other drilling rig commitments as at June 30, 2011 have not materially changed from the information previously disclosed in our 2010 Audited Consolidated Financial Statements.
13. MARKETING AND OTHER INCOME
Three Months Six Months Ended June 30 Ended June 30 2011 2010 2011 2010 ---------------------------------------------------------------------------- Marketing Revenue, Net 51 113 102 196 Insurance Proceeds 26 - 26 - Change in Fair Value of Crude Oil Put Options - 2 (7) (14) Foreign Exchange Gains (Losses) 6 (11) (16) (2) Other 12 (8) 36 7 --------------------------------- Total 95 96 141 187 --------------------------------- ---------------------------------
14. DISCONTINUED OPERATIONS
In February 2011, we completed the sale of our 62.7% investment in Canexus Limited Partnership, which operates a chemicals business, for net proceeds of $458 million and we realized a gain on disposition of $348 million in the first quarter. In the fourth quarter of 2010, we received board approval to sell our interest in Canexus and classified the assets and liabilities as held for sale at December 31, 2010. The gain on sale and results of our chemicals business have been presented as discontinued operations.
In July 2010, we completed the sale of our heavy oil properties in Canada. We received proceeds of $939 million, net of closing adjustments and realized a gain on disposition of $828 million in the third quarter of 2010. The gain on sale and results of operations of these properties have been presented as discontinued operations.
Three Months Ended June 30 2010 ------------------------------- Canada Chemicals Total ---------------------------------------------------------------------------- Revenues and Other Income Net Sales 56 105 161 Other - (7) (7) ------------------------------- 56 98 154 ------------------------------- Expenses Operating 22 78 100 Depreciation, Depletion, Amortization and Impairment 7 8 15 Transportation and Other - 12 12 General and Administrative 5 8 13 Finance 2 6 8 ------------------------------- 36 112 148 ------------------------------- Income (Loss) before Provision for Income Taxes 20 (14) 6 Less: Provision for Deferred Income Taxes 5 (3) 2 ------------------------------- Income (Loss) before Non-Controlling Interest 15 (11) 4 Less: Non-Controlling Interest - (3) (3) ------------------------------- Net Income (Loss) from Discontinued Operations, Net of Tax 15 (8) 7 ------------------------------- ------------------------------- Earnings Per Common Share Basic 0.02 Diluted 0.01 ------------------------------- Six Months Ended June 30 ------------------------------------- 2011 2010 ------------------------------------- Chemicals Canada Chemicals Total ---------------------------------------------------------------------------- Revenues and Other Income Net Sales 42 125 218 343 Other (1) - - - Gain on Disposition 348 - - - ------------------------------------- 389 125 218 343 ------------------------------------- Expenses Operating 25 45 148 193 Depreciation, Depletion, Amortization and Impairment 4 20 14 34 Transportation and Other 2 2 28 30 General and Administrative 2 9 18 27 Finance 2 3 7 10 ------------------------------------- 35 79 215 294 ------------------------------------- Income before Provision for Income Taxes 354 46 3 49 Less: Provision for Deferred Income Taxes 51 10 1 11 ------------------------------------- Income before Non-Controlling Interest 303 36 2 38 Less: Non-Controlling Interest 1 - 1 1 ------------------------------------- Net Income from Discontinued Operations, Net of Tax 302 36 1 37 ------------------------------------- ------------------------------------- Earnings Per Common Share Basic 0.57 0.08 Diluted 0.57 0.07 -------------------------------------
The following table provides the assets and liabilities that are associated with our chemicals business at December 31, 2010 and January 1, 2010. There were no assets or liabilities related to our chemical operations at June 30, 2011.
December 31 January 1 2010 2010 ---------------------------------------------------------------------------- Cash and Cash Equivalents 3 14 Accounts Receivable 48 54 Inventories and Supplies 35 33 Other Current Assets 1 3 Property, Plant and Equipment, Net of Accumulated DD&A 629 535 Deferred Income Tax Assets 7 4 Other Long-Term Assets 6 11 ----------------------- Assets 729 (1) 654 ----------------------- Accounts Payable and Accrued Liabilities 59 64 Accrued Interest Payable 3 - Long-Term Debt 414 335 Deferred Income Tax Liabilities 15 11 Asset Retirement Obligations 73 74 Other Long-Term Liabilities 18 16 ----------------------- Liabilities 582 (1) 500 ----------------------- Equity - Canexus Non-Controlling Interest 48 33 ----------------------- (1) Included in assets and liabilities held for sale at December 31, 2010. 15. CASH FLOWS (a) Charges and credits to income not involving cash Three Months Six Months Ended June 30 Ended June 30 2011 2010 2011 2010 ---------------------------------------------------------------------------- Depreciation, Depletion, Amortization and Impairment 335 358 705 701 Finance 60 97 134 186 Stock-Based Compensation (29) (61) (2) (59) Loss on Debt Redemption and Repurchase 1 - 91 - Non-cash Items Included in Discontinued Operations - 27 (290) 60 Provision for Income Taxes 332 236 881 413 Foreign Exchange (6) (1) 17 1 Other 1 (18) (4) - --------------------------------- Total 694 638 1,532 1,302 --------------------------------- --------------------------------- (b) Changes in non-cash working capital Three Months Six Months Ended June 30 Ended June 30 2011 2010 2011 2010 ---------------------------------------------------------------------------- Accounts Receivable 194 (16) (134) (234) Inventories and Supplies 163 (37) 184 76 Other Current Assets (17) 5 (9) 78 Accounts Payable and Accrued Liabilities (188) (251) 227 82 --------------------------------- Total 152 (299) 268 2 --------------------------------- --------------------------------- Relating to: Operating Activities 121 (286) 153 (73) Investing Activities 31 (13) 115 75 --------------------------------- Total 152 (299) 268 2 --------------------------------- ---------------------------------
16. OPERATING SEGMENTS AND RELATED INFORMATION
Effective in the first quarter of 2011, we amended our segment reporting to reflect changes in our business. In 2010, we disposed of non-core operations including heavy oil operations in Canada, chemicals and certain energy marketing businesses, and ramped up production at Long Lake. We report our segments to align with our key growth strategies, specifically, Conventional Oil and Gas, Oil Sands and Unconventional Gas. Prior period results have been revised to reflect the presentation changes made in the current period.
Nexen has the following operating segments:
Conventional Oil and Gas: We explore for, develop and produce crude oil and natural gas from conventional sources around the world. Our operations are focused on the UK, North America (Canada and US) and other countries (Yemen, offshore West Africa and Colombia).
Oil Sands: We develop and produce synthetic crude oil from the Athabasca oil sands in northern Alberta. We produce bitumen using in situ and mining technologies and upgrade it into synthetic crude oil before ultimate sale. Our in situ activities are comprised of our operations at Long Lake and future development phases. Our mining activities are conducted through our 7.23% ownership of the Syncrude Joint Venture.
Unconventional Gas: We explore for and produce unconventional gas from shale formations in northeastern British Columbia and Poland. Production and results of operations are included within Conventional Oil and Gas until they become significant.
Corporate and Other includes energy marketing, unallocated items and the results of Canexus prior to its sale in February 2011. Canexus manufactures, markets and distributes industrial chemicals, principally sodium chlorate, chlorine, muriatic acid and caustic soda. The results of our chemicals business have been presented as discontinued operations.
The accounting policies of our operating segments are the same as those described in Note 2. Net income of our operating segments excludes interest income, interest expense, unallocated corporate expenses and foreign exchange gains and losses. Identifiable assets are those used in the operations of the segments.
Segmented net income for the three months ended June 30, 2011
Corporate and Conventional Oil Sands Other Total ---------------------------------------------------------------------------- Other United North Countries In Kingdom America (1) Situ Syncrude ------------------------------------------- Net Sales 764 134 229 188 181 11 1,507 Marketing and Other Income 1 30 3 - 1 60 95 ----------------------------------------------------------- 765 164 232 188 182 71 1,602 Less: Expenses Operating 61 36 35 127 75 7 341 Depreciation, Depletion, Amortization and Impairment 133 116 23 36 14 13 335 Transportation and Other - 11 11 51 6 33 112 General and Administrative 2 19 8 2 - 45 76 Exploration 13 41 37 (2) 2 - - 93 Finance 5 4 1 - 2 48 60 Net Loss on Debt Redemption - - - - - 1 1 ----------------------------------------------------------- Income (Loss) from Continuing Operations before Income Taxes 551 (63) 117 (30) 85 (76) 584 Less: Provision for (Recovery of) Income Taxes 326 (15) 22 (7) 21 (15) 332 ----------------------------------------------------------- Net Income (Loss) 225 (48) 95 (23) 64 (61) 252 ----------------------------------------------------------- ----------------------------------------------------------- Capital Expenditures 104 123 171 91 27 14 530 ----------------------------------------------------------- ----------------------------------------------------------- (1) Includes results of conventional crude oil and natural gas operations in Yemen and Colombia. (2) Includes exploration activities primarily in Yemen, Nigeria, Norway, Colombia and Poland. Segmented net income for the three months ended June 30, 2010 Corporate and Conventional Oil Sands Other Total ---------------------------------------------------------------------------- Other United North Countries In Kingdom America (1) Situ Syncrude ------------------------------------------- Net Sales 735 133 171 102 152 12 1,305 Marketing and Other Income 4 1 3 - 1 87 96 ------------------------------------------------------------ 739 134 174 102 153 99 1,401 Less: Expenses Operating 77 44 38 85 70 7 321 Depreciation, Depletion, Amortization and Impairment 189 92 25 25 13 14 358 Transportation and Other 1 5 3 32 4 96 141 General and Administrative - 11 (1) - - 30 40 Exploration 7 18 24 (2) 1 - - 50 Finance 4 4 - - 1 88 97 Net Gain from Dispositions - - - (80)(3) - - (80) ------------------------------------------------------------ Income (Loss) from Continuing Operations before Income Taxes 461 (40) 85 39 65 (136) 474 Less: Provision for (Recovery of) Income Taxes 230 (10) 22 10 16 (32) 236 ------------------------------------------------------------ Income (Loss) from Continuing Operations 231 (30) 63 29 49 (104) 238 Add: Net Income (Loss) from Discontinued Operations (Note 14) - 15 - - - (8) 7 ------------------------------------------------------------ Net Income (Loss) 231 (15) 63 29 49 (112) 245 ------------------------------------------------------------ ------------------------------------------------------------ Capital Expenditures 150 380 170 45 25 70 840 ------------------------------------------------------------ ------------------------------------------------------------ (1) Includes results of conventional crude oil and natural gas operations in Yemen and Colombia. (2) Includes exploration activities primarily in Yemen, Nigeria, Norway and Colombia. (3) Gain on disposition of non-core lands in the Athabasca region. Segmented net income for the six months ended June 30, 2011 Corporate and Conventional Oil Sands Other Total ---------------------------------------------------------------------------- Other United North Countries In Kingdom America (1) Situ Syncrude ------------------------------------------- Net Sales 1,726 267 414 303 370 25 3,105 Marketing and Other Income 17 32 7 - 1 84 141 ----------------------------------------------------------- 1,743 299 421 303 371 109 3,246 Less: Expenses Operating 159 76 70 234 150 15 704 Depreciation, Depletion, Amortization and Impairment 315 221 48 65 30 26 705 Transportation and Other - 15 16 69 12 67 179 General and Administrative (10) 52 23 13 - 103 181 Exploration 17 100 100 (2) 2 - - 219 Finance 10 8 1 1 3 111 134 Net Loss on Debt Redemption - - - - - 91 91 ----------------------------------------------------------- Income (Loss) from Continuing Operations before Income Taxes 1,252 (173) 163 (81) 176 (304) 1,033 Less: Provision for (Recovery of) Income Taxes 1,012 (46) 4 (20) 44 (113) 881 ----------------------------------------------------------- Income (Loss) from Continuing Operations 240 (127) 159 (61) 132 (191) 152 Add: Net Income from Discontinued Operations (Note 14) - - - - - 302 302 ----------------------------------------------------------- Net Income (Loss) 240 (127) 159 (61) 132 111 454 ----------------------------------------------------------- ----------------------------------------------------------- Capital Expenditures 178 242 317 220 46 26 1,029 ----------------------------------------------------------- ----------------------------------------------------------- (1) Includes results of conventional crude oil and natural gas operations in Yemen and Colombia. (2) Includes exploration activities primarily in Yemen, Nigeria, Norway, Colombia and Poland. Segmented net income for the six months ended June 30, 2010 Corporate and Conventional Oil Sands Other Total ---------------------------------------------------------------------------- Other United North Countries In Kingdom America (1) Situ Syncrude ------------------------------------------- Net Sales 1,490 294 368 193 286 21 2,652 Marketing and Other Income 9 1 8 - 2 167 187 ------------------------------------------------------------ 1,499 295 376 193 288 188 2,839 Less: Expenses Operating 154 82 80 180 132 16 644 Depreciation, Depletion, Amortization and Impairment 353 190 62 40 27 29 701 Transportation and Other 4 10 6 83 11 220 334 General and Administrative 13 30 8 4 - 94 149 Exploration 31 41 70 (2) 1 - - 143 Finance 8 8 - 1 2 167 186 Net Gain from Dispositions - - - (80)(3) - - (80) ------------------------------------------------------------ Income (Loss) from Continuing Operations before Income Taxes 936 (66) 150 (36) 116 (338) 762 Less: Provision for (Recovery of) Income Taxes 468 (17) 21 (9) 29 (79) 413 ------------------------------------------------------------ Income (Loss) from Continuing Operations 468 (49) 129 (27) 87 (259) 349 Add: Net Income from Discontinued Operations (Note 14) - 36 - - - 1 37 ------------------------------------------------------------ Net Income (Loss) 468 (13) 129 (27) 87 (258) 386 ------------------------------------------------------------ ------------------------------------------------------------ Capital Expenditures 277 527 313 109 49 135 1,410 ------------------------------------------------------------ ------------------------------------------------------------ (1) Includes results of conventional crude oil and natural gas operations in Yemen and Colombia. (2) Includes exploration activities primarily in Yemen, Nigeria, Norway and Colombia. (3) Gain on disposition of non-core lands in the Athabasca region. Segmented assets as at June 30, 2011 Corporate Conventional Oil Sands and Other Total ---------------------------------------------------------------------------- United North Other In Kingdom America Countries Situ Syncrude -------------------------------------------- Total Assets 4,423 3,199 1,822 5,982 1,272 2,362 (1) 19,060 -------------------------------------------------------------- -------------------------------------------------------------- Property, Plant and Equipment Cost 6,332 6,484 3,840 5,975 1,563 611 24,805 Less: Accumulated DD&A 3,277 3,670 2,348 145 387 350 10,177 -------------------------------------------------------------- Net Book Value 3,055 2,814(2) 1,492(3) 5,830(4) 1,176 261 14,628 ------------------------------------------------------------- ------------------------------------------------------------- Goodwill 269 - - - - 7 276 ------------------------------------------------------------- ------------------------------------------------------------- (1) Includes cash of $583 million, and Energy Marketing accounts receivable and inventory of $1,292 million. (2) Includes capitalized costs of $1,070 million associated with our Canadian shale gas operations. (3) Includes $1,398 million related to our Usan development, offshore Nigeria. (4) Includes net book value of $4,962 million for Long Lake Phase 1 and $868 million for future phases of our in situ oil sands projects. Segmented assets as at December 31, 2010 Corporate Conventional Oil Sands and Other Total ---------------------------------------------------------------------------- United North Other In Kingdom America Countries Situ Syncrude -------------------------------------------- Total Assets 4,249 3,195 1,646 5,782 1,259 3,516 (1) 19,647 ------------------------------------------------------------- ------------------------------------------------------------- Property, Plant and Equipment Cost 6,389 6,422 3,700 5,756 1,519 596 24,382 Less: Accumulated DD&A 3,055 3,597 2,370 91 359 331 9,803 ------------------------------------------------------------- Net Book Value 3,334 2,825(2) 1,330(3) 5,665(4) 1,160 265 14,579 ------------------------------------------------------------- ------------------------------------------------------------- Goodwill 277 - - - - 9 286 ------------------------------------------------------------- ------------------------------------------------------------- (1) Includes cash of $817 million, Energy Marketing accounts receivable and inventory of $1,381 million and Chemicals assets of $729 million. (2) Includes capitalized costs of $938 million associated with our Canadian shale gas operations. (3) Includes $1,210 million related to our Usan development, offshore Nigeria. (4) Includes net book value of $4,865 million for Long Lake Phase 1 and $800 million for future phases of our in situ oil sands projects. Segmented assets as at January 1, 2010 Corporate Conventional Oil Sands and Other Total ---------------------------------------------------------------------------- United North Other In Kingdom America Countries Situ Syncrude -------------------------------------------- Total Assets 4,840 3,146 1,320 5,616 1,165 4,868 (1) 20,955 ------------------------------------------------------------- ------------------------------------------------------------- Property, Plant and Equipment Cost 5,884 7,464 3,344 5,523 1,390 1,702 25,307 Less: Accumulated DD&A 2,458 4,600 2,387 7 319 867 10,638 ------------------------------------------------------------- Net Book Value 3,426 2,864(2) 957(3) 5,516(4) 1,071 835 14,669 ------------------------------------------------------------- ------------------------------------------------------------- Goodwill 292 - - - - 38 330 ------------------------------------------------------------- ------------------------------------------------------------- (1) Includes cash of $1,016 million, Energy Marketing accounts receivable and inventory of $1,958 million and Chemicals assets of $654 million. (2) Includes capitalized costs of $477 million associated with our Canadian shale gas operations. (3) Includes $760 million related to our Usan development, offshore Nigeria. (4) Includes net book value of $4,776 million for Long Lake Phase 1 and $740 million for future phases of our in situ oil sands projects.
17. TRANSITION TO IFRS
For all periods up to and including the year ended December 31, 2010, we prepared our Consolidated Financial Statements in accordance with Canadian generally accepted accounting principles (Canadian GAAP). As a publicly listed company in Canada, we are required to prepare consolidated financial statements in accordance with International Financial Reporting Standards (IFRS) for all periods after January 1, 2011 including comparative historical information. As we are also publicly listed in the United States, we were required to include a reconciliation of our financial results between Canadian GAAP and US GAAP. The reconciliation to US GAAP is no longer required.
In accordance with transitional provisions, we prepared our opening balance sheet as at January 1, 2010 (the transition date) and 2010 comparative financial information using the accounting policies set out in Note 2. The consolidated financial statements for the year ended December 31, 2011 will be the first annual financial statements that comply with IFRS by applying existing IFRS with an effective date of December 31, 2011 or earlier. This transition note explains the material adjustments we made to convert our financial statements to IFRS.
Elected Exemptions from Full Retrospective Application
In preparing these Unaudited Condensed Consolidated Financial Statements in accordance with IFRS 1 First-time Adoption of International Financial Reporting Standards (IFRS 1), we applied the following optional exemptions from full retrospective application of IFRS.
(i) Business Combinations
We applied the business combinations exemption to not apply IFRS 3 Business Combinations retrospectively to past business combinations. Accordingly, we have not restated business combinations that took place prior to the transition date.
(ii) Fair Value or Revaluation as Deemed Cost
We elected to measure certain producing oil and gas properties at fair value as at the transition date and use that amount as its deemed cost in the opening IFRS balance sheet.
(iii) Cumulative Translation Differences
We elected to set the cumulative translation account, which is included in accumulated other comprehensive income, to nil at January 1, 2010. This exemption has been applied to all subsidiaries.
(iv) Share-based Payment Transactions
We elected to use the IFRS 1 exemption whereby the liabilities for share-based payments that had vested or settled prior to January 1, 2010 were not required to be retrospectively restated.
(v) Employee Benefits
We elected to apply the exemption for employee benefits to recognize the accumulated unrecognized net actuarial loss in retained earnings at January 1, 2010. This exemption has been applied to all defined benefit pension plans.
(vi) Asset Retirement Obligations
We applied the exemption from full retrospective application of our asset retirement obligations as permitted for first-time adoption of IFRS. As such, we re-measured ARO as at January 1, 2010. We estimated the amount to be included in the related asset by discounting the liability to the date when the obligation first arose using our best estimates of the historical risk-free discount rates applicable during the intervening period.
(vii) Borrowing Costs
We applied an IFRS transitional exemption to prospectively capitalize borrowing costs from the transition date. As a result, borrowing costs previously capitalized under Canadian GAAP were expensed to retained earnings.
Mandatory Exceptions to Retrospective Application
In preparing these Unaudited Condensed Consolidated Financial Statements in accordance with IFRS 1, we were required to apply the following mandatory exceptions from full retrospective application of IFRS.
(i) Hedge Accounting
Only hedging relationships that satisfied the hedge accounting criteria as of the transition date are reflected as hedges in our results under IFRS. Any derivatives not meeting the IAS 39 Financial Instruments: Recognition and Measurement criteria for hedge accounting were recorded as a non-hedging derivative financial instrument.
(ii) Estimates
Hindsight was not used to create or revise estimates and accordingly, our estimates previously made under Canadian GAAP are consistent with their application under IFRS.
Reconciliations of Canadian GAAP to IFRS
IFRS 1 requires the presentation of a reconciliation of shareholders' equity, net income, comprehensive income, and cash flows for prior periods. The transition from Canadian GAAP to IFRS had no material effect upon previously reported cash flows. The following represents the reconciliations from Canadian GAAP to IFRS for the respective periods for shareholders' equity, net income, and comprehensive income:
Reconciliation of Shareholders' Equity
January 1 June 30 December 31 (Cdn$ millions) Note 2010 2010 2010 ---------------------------------------------------------------------------- Shareholders' Equity under Canadian GAAP 7,646 8,080 8,791 Differences increasing (decreasing) reported shareholders' equity: Borrowing Costs (i) (841) (814) (778) Asset Retirement Obligations (ii) (228) (252) (241) Employee Benefits (iii) (104) (104) (150) Stock-Based Compensation (iv) (96) (81) (92) Property, Plant & Equipment (v) (124) (112) (90) Foreign Exchange (vi) (11) (9) - Long-term Debt (vii) (9) (26) (28) Income Taxes (viii) 554 473 429 Other - 8 (27) --------------------------------- Shareholders' Equity under IFRS 6,787 7,163 7,814 --------------------------------- ---------------------------------
(i) Borrowing Costs
We applied the IFRS 1 exemption to prospectively capitalize borrowing costs from the transition date as described above.
(ii) Asset Retirement Obligations (ARO)
We applied the IFRS 1 exemption for asset retirement obligations and re-measured our ARO as at January 1, 2010 as described above.
(iii) Employee Benefits
We have chosen to include previously unrecognized actuarial gains and losses of our defined benefit pension plans on the balance sheet under IFRS. Under Canadian GAAP, we amortized actuarial gains and losses to income over the estimated average remaining service life, with disclosure of the unrecognized amount in the notes to the Consolidated Financial Statements. On January 1, 2010, we applied the IFRS 1 exemption to recognize the accumulated unrecognized net actuarial loss in retained earnings on transition to IFRS.
(iv) Stock-Based Compensation (SBC)
Under Canadian GAAP, we recorded obligations for liability-based stock compensation plans using the intrinsic-value method of accounting. IFRS requires that we record these SBC obligations at fair value and subsequently re-measure the obligation each reporting period. Our tandem option, stock appreciation rights and restricted share unit plans are considered liability-based stock compensation plans. On transition, we recorded the liability at fair value for unsettled awards.
(v) Property Plant and Equipment
Impairment
Under Canadian GAAP, if indications of impairment exist and the asset's estimated undiscounted future cash flows were lower than it's carrying amount, the carrying value was written down to fair value. Under IFRS, if indications of impairments exist, the asset's carrying value is immediately compared to its estimated recoverable amount, which could trigger additional impairment under IFRS. We elected to measure certain producing oil and gas properties at fair value as at the transition date and use that amount as its deemed cost in the opening IFRS balance sheet. As a result, oil and gas properties were written down to fair value of $460 million and resulted in an impairment expense of $91 million on transition.
Componentization
Under Canadian GAAP, we depleted oil and gas capitalized costs using the unit-of-production method on a field-by-field basis and depreciated non-resource capitalized costs based on their estimated useful life. On adoption of IFRS, we reviewed our PP&E to identify each material component that has a significantly different useful life and as a result, adjustments to the accumulated depletion of certain assets were required on transition to IFRS.
Major Maintenance
Under Canadian GAAP, operating expenses included major maintenance costs that were expensed as incurred. Under IFRS, these costs are capitalized and depreciated separately until the next planned major maintenance project.
(vi) Foreign Exchange
Foreign Currency Translation
We applied the first-time IFRS adoption exemption to reset our cumulative translation differences to nil on the transition date. Accumulated foreign exchange gains and losses of our self-sustaining foreign operations, net of foreign exchange translation gains and losses of long-term debt designated as hedges are included in retained earnings on the transition date. This one-time adjustment had no impact on shareholders' equity on transition.
Change in Functional Currency
As a result of additional guidance under IFRS, our assessment of the functional currency of a subsidiary changed from Canadian dollars to US dollars to better reflect the economic environment in which it operates.
(vii) Long-Term Debt
Canexus Convertible Debentures
Canexus unitholders have the ability to redeem fund units for cash pursuant to the terms of the trust indenture. Under IFRS, these convertible debentures are considered to be financial liabilities containing an embedded derivative. Under Canadian GAAP, the convertible debentures were considered to be compound instruments with an equity component. Accordingly, the equity component and unamortized deferred transaction costs recorded under Canadian GAAP were derecognized on January 1, 2010 and charged to retained earnings. We elected to recognize the convertible debentures at fair value and to recognize changes in fair value in net income during the period of change.
(viii) Income Taxes
Recognition of Deferred Tax Credit
In 2008, we completed an internal reorganization and financing of our assets in the North Sea, which provided us with a one-time tax deduction in the UK. Canadian GAAP precluded us from recognizing the full estimated benefit of the tax deductions until the assets were recognized in net income either by a sale or depletion through use. As a result, we deferred the initial recognition of the benefit and were amortizing it to future income tax expense over the life of the underlying assets under Canadian GAAP. On adoption of IFRS, no such prohibition exists and we recognized the remaining deferred tax credit in retained earnings on transition to IFRS.
Exceptions
Under Canadian GAAP, deferred taxes were generally provided on all temporary differences. Conversely, IFRS does not recognize deferred taxes on temporary differences arising from the initial recognition of assets or liabilities in transactions that are not business combinations and that affect neither accounting nor taxable profit or loss.
Reconciliation of Net Income
Three Months Six Months Twelve Ended Ended Months Ended June 30 June 30 December 31 (Cdn$ millions) Note 2010 2010 2010 ---------------------------------------------------------------------------- Net Income under Canadian GAAP 255 440 1,197 Differences increasing (decreasing) reported net income: Borrowing Costs (i) 16 27 63 Asset Retirement Obligations (ii) (7) (24) (13) Stock-Based Compensation (iii) 23 14 3 Property, Plant & Equipment (iv) 4 12 34 Long-term Debt (v) (13) (17) (19) Income Taxes (vi) (54) (81) (136) Other 21 15 (2) ---------------------------------------- Total Differences in Net Income (10) (54) (70) ---------------------------------------- Net Income under IFRS 245 386 1,127 ---------------------------------------- ----------------------------------------
(i) Borrowing Costs
We applied an IFRS transitional exemption to prospectively capitalize borrowing costs from the transition date. As a result, borrowing costs previously capitalized under Canadian GAAP were expensed to shareholders' equity. The reduced capitalized amounts decreased DD&A expense during 2010.
(ii) Asset Retirement Obligations (ARO)
Under Canadian GAAP, foreign exchange translation gains and losses arising from the revaluation of GBP-denominated asset retirement obligations were included in net income in the period in which they occurred. Under IFRS, these translation gains and losses are treated as a change in estimate and therefore increase or decrease PP&E with a corresponding impact on net income.
(iii) Stock-Based Compensation (SBC)
As described above, we record obligations for liability-based stock compensation plans at fair value each reporting period. Our tandem option, stock appreciation rights and restricted share unit plans are considered liability-based stock compensation plans. The changes in the SBC fair value in 2010 were recognized in net income.
(iv) Property Plant and Equipment
Impairment
As described above, certain properties were impaired and written down to fair value on transition. These adjustments reduced IFRS DD&A expense during 2010 by immaterial amounts. In the last half of 2010, additional properties were impaired and written down to fair value. The impairment expense of $46 million reduced net income in the third and fourth quarters.
Major Maintenance Costs
As described above, Canadian GAAP operating expenses included major maintenance costs that were expensed as incurred. Under IFRS, these costs are capitalized and depreciated separately until the next planned major maintenance project. During 2010, we capitalized $18 million of maintenance costs under IFRS that were expensed as operating costs under Canadian GAAP.
Gain on Sale of Heavy Oil Properties
We completed the sale of our Canadian heavy oil properties in the third quarter of 2010. As the adoption of IFRS resulted in different carrying values of property, plant & equipment and asset retirement obligations prior to the sale, our gain on sale under IFRS was $47 million higher.
(v) Long-Term Debt
Canexus Convertible Debentures
As described above, we elected to carry the Canexus convertible debentures at fair value under IFRS. The change in fair value during 2010 was included in net income.
(vi) Income Taxes
Recognition of Deferred Tax Credit
As described above, we amortized a deferred tax credit to income over the life of the underlying asset under Canadian GAAP. Under IFRS, the deferred tax credit was recognized in retained earnings on transition. Therefore, IFRS net income was lower by $29 million and $59 million for the three and six months ended June 30, 2010, respectively, and lower by $117 million for the twelve months ended December 31, 2010.
Other
All other adjustments to IFRS net income were tax effected which increased deferred tax expense by $25 million and $22 million for the three and six months ended June 30, 2010, respectively, and $19 million for the twelve months ended December 31, 2010.
Reconciliation of Comprehensive Income
Three Months Six Months Twelve Ended Ended Months Ended June 30 June 30 December 31 (Cdn$ millions) Note 2010 2010 2010 ---------------------------------------------------------------------------- Comprehensive income under Canadian GAAP 267 441 1,168 Differences increasing (decreasing) reported comprehensive income, net of income taxes: Differences in net income (10) (54) (70) Foreign Currency Translation (i) (4) (6) (8) Employee Benefits (ii) - - (35) ---------------------------------------- Comprehensive Income under IFRS 253 381 1,055 ---------------------------------------- ----------------------------------------
(i) Foreign Currency Translation
Transitional adjustments reflect the foreign currency exchange impact of the IFRS adjustments during the respective periods.
(ii) Employee Benefits
As described in Note 2, actuarial gains and losses are recognized directly in other comprehensive income in the period in which they occur. For the twelve months ended December 31, 2010, actuarial losses on our defined benefit plans reduced other comprehensive income by $35 million.
Contact Information:
Vice President, Investor Relations
(403) 699-4230
Kim Woima, CA
Manager, Investor Relations
(403) 699-5821
Pierre Alvarez
Vice President, Corporate Relations
(403) 699-5202
Nexen Inc.
801 - 7th Ave SW
Calgary, Alberta, Canada T2P 3P7
www.nexeninc.com