Nexen Announces Third Quarter Results
Reduced Buzzard Output Lowers Production; Major Initiatives On Track
(firmenpresse) - CALGARY, ALBERTA -- (Marketwire) -- 10/27/11 -- Nexen Inc. today reported third quarter 2011 operating and financial results as well as continued progress on our major initiatives. We generated cash flow from operations of $516 million ($0.98/share) and net income of $200 million ($0.38/share). Our financial results reflect quarterly production of 186,000 barrels of oil equivalent per day (boe/d). Production was below our expectations primarily due to pipeline constraints and longer time to commission the fourth platform at our Buzzard facility in the UK North Sea. Production at Buzzard has since returned to 208,000 boe/d (gross) during October. All other areas met their production expectations during the quarter.
We continued to advance key projects in all areas of operation during the quarter. In the UK North Sea, we obtained all required partner and government approvals to begin development at Golden Eagle. Offshore West Africa, the Usan floating production and storage offloading vessel (FPSO) was successfully moored and final commissioning activities are underway.
At Long Lake, we saw a 6% increase in quarterly bitumen production and we expect to exit the year in the mid 30,000 bbls/d (gross) range. A portion of the increase came from pad 11, which continues to ramp-up as expected. Additionally, we completed drilling on pad 12 and started drilling on pad 13 while advancing plans for subsequent drilling at both Long Lake and Kinosis as part of our strategy to fill the upgrader.
We successfully advanced our shale gas operations in the Horn River basin as we achieved targeted cost reductions on our 9-well pad. Our joint venture process is also proceeding well.
"While we have made good progress against several key initiatives so far this year, our production has been below our expectations due to the downtime at Buzzard," said Marvin Romanow, President and Chief Executive Officer. "With the work complete and the fourth platform commissioned, we are now able to produce from our full well set at Buzzard."
Summary
Financial
Production
Project Advancements
Our portfolio weighting towards unhedged, Brent-priced oil again bolstered our financial results this quarter. Brent averaged US$113.47 per barrel, a premium of over US$23 per barrel above WTI. Our strategy of buying put options allows us to benefit when prices rise, while providing partial protection if prices decline below certain levels.
Third quarter cash flow from operations was lower compared to the second quarter, primarily due to scheduled maintenance at Scott and Ettrick and weather-related downtime in the Gulf of Mexico. Commodity prices were also slightly lower. Net income was lower due to a $106 million (after-tax) impairment on some of our non-shale Canadian natural gas properties due to sustained low gas prices.
Compared to the third quarter of 2010, cash flow was higher as higher realized prices more than offset lower production. Net income was lower due to a significant gain on the disposition of our Canadian heavy oil properties in Q3 2010.
We continue to expect our capital investment for the year to be between $2.4 billion and $2.7 billion. Net debt rose compared to the prior quarter due to increased drilling and the translation of our US dollar long-term debt into Canadian dollars.
Production rates during the third quarter were primarily impacted by activities at our Buzzard platform, scheduled maintenance at Scott/Telford and Ettrick, and weather-related downtime in the Gulf of Mexico.
Buzzard typically produces 195,000-220,000 boe/d (85,000-95,000 boe/d net to Nexen). Production at Buzzard in the third quarter averaged 114,000 boe/d (49,300 boe/d net to Nexen) as we completed scheduled maintenance, commissioned the fourth platform and were constrained by downtime on the third-party owned Forties and Frigg pipelines. While the maintenance was completed on schedule, production was below our expectations due to longer than expected constraints on the Frigg gas export system. These restrictions required us to reduce oil production to minimize gas flaring for six weeks. The export constraints also delayed commissioning of the fourth platform and we experienced higher than expected downtime during commissioning.
During October, the Buzzard facility has been producing at rates of 208,000 boe/d (90,000 boe/d net to Nexen). This production is from the full set of wells with the fourth platform now operational. This platform will allow us to produce all wells, regardless of H2S levels, to keep Buzzard at full rates and enable the future tieback of discoveries with high H2S content. While we anticipate strong production from Buzzard going forward, we also expect some variability as we continue to increase the rate through the fourth platform.
Yemen production reflects natural field declines with no further development drilling activities as we near the end of the primary Masila contract term on December 17th of this year. While we continued our extension efforts, macro political events in the country have made it difficult to make visible progress. At the same time as we continue our discussions, we are preparing for an orderly exit from the country if our renewal discussions are unsuccessful. We remain focused on secure and reliable operations.
In the Gulf of Mexico, we had a few days of downtime on both our shelf and deepwater production as a result of Tropical Storm Lee. This downtime was within our planned allowance for weather-related disruptions and production returned to normal levels shortly thereafter.
The scheduled coker turnaround at Syncrude began September 8th and production has been correspondingly lower in September and October. The maintenance is nearing completion.
At Long Lake, bitumen production averaged 29,500 bbls/d gross (19,200 bbls/d net to Nexen), up 1,600 bbls/d (6%) from the prior quarter and our highest quarterly volume to date. Bitumen production in the month of September was 30,500 bbls/d (19,900 bbls/d net to Nexen), and has averaged 31,700 bbls/d (20,600 bbls/d net to Nexen) during October.
Pad 11 continues to ramp-up in line with expectations as Q3 production was 1,700 bbls/d compared to 900 bbls/d in the second quarter. September production from the pad averaged 2,000 bbls/d at an SOR of 3.2 as we progressed toward our longer-term expectation of 4,000-8,000 bbls/d.
Full-field monthly SOR continues to fall, and reached 4.8 in September. We remain on track to reach production rates in the mid 30,000 bbls per day (gross) by the end of 2011 as volumes from pad 11 and many of our other better-quality existing wells continue to grow while production from the other wells remains stable.
Unit operating costs at Long Lake averaged $85/bbl in Q3 and include scheduled maintenance costs on the third hot lime softener and the second cogeneration unit. We expect per barrel operating costs to trend downward as production continues to grow. Operating costs have been high year-to-date due to planned and unplanned maintenance activity, along with initiatives to increase upgrader reliability and improve well performance.
Our upgrader on-stream time and Premium Synthetic Crude (PSC™) yield this quarter were similar to the previous quarter, averaging 82 percent and 70 percent, respectively. Cash flow at Long Lake was lower than the previous quarter primarily due to lower PSC™ prices and lower volumes of third-party bitumen processed.
(1)Unit operating costs and realized prices are based on PSC™ volumes sold and exclude activities related to third-party bitumen purchased, processed and sold. Unit operating costs includes energy costs.
Production for the quarter was below our guidance primarily due to longer than expected gas export restrictions and higher than expected variability in Buzzard's operating performance as we commissioned the fourth platform and integrated the new facilities into normal operations.
In the fourth quarter, we expect to see significantly higher volumes at Buzzard as we have returned to normal operating levels, although we expect some fluctuations as we increase the production rate through the new platform. We also expect to see several new sources of production come on-stream, including the Telford and Blackbird tiebacks in the North Sea, and our nine-well shale gas pad in the Horn River. Facility shutdowns will be required at both Telford and Ettrick in order to bring the tiebacks on stream. We will be near the low end of our Yemen guidance if we are unsuccessful in obtaining an extension there. We recently shut down the upgrader at Long Lake for repairs to the air separation unit. With the natural gas pipeline installed this summer, we expect to be able to continue to produce and sell bitumen during this shut-down.
In aggregate, we expect our full-year production to be marginally lower than our previous guidance, primarily as a result of lower volumes at Buzzard during the third quarter and potential variability as we increase the rate through the new platform.
Project Advancements
Nexen has a number of opportunities available with several development and appraisal projects underway, and a large resource base to support long-term 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 third quarter, we continued to progress our action plan to move 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. The FPSO has arrived in Nigeria and has been successfully moored at site. The process of commissioning the FPSO and connecting the sub-sea wells to the facility has begun and is expected to continue into the early part of next year. At peak rates, the Usan project is capable of producing 180,000 boe/d (36,000 boe/d net to Nexen).
UK North Sea - On October 19th, we received approval from the UK Department of Energy & Climate Change to proceed with the Golden Eagle development, a $3.3 billion investment ($1.2 billion net to Nexen) that is expected to produce an estimated 140 mmboe (gross) of proved and probable reserves over an 18-year period.
We are the operator of Golden Eagle and hold a 36.54% working interest in the field. The development has been sanctioned by all of the Golden Eagle co-venturers. Detailed design engineering has commenced and fabrication is scheduled to start before year-end. First oil production is forecast for approximately three years from now, in late 2014, and the development is expected to have an initial gross production rate of up to 70,000 boe/d (26,000 boe/d net to Nexen).
We continue to progress our tieback projects at Telford, Blackbird and Rochelle. We expect to see increased production at Telford and first oil from Blackbird before the end of this year. First production at Rochelle is expected around the end of 2012. Elsewhere in the North Sea, appraisal drilling continues at Polecat, to be followed by an exploration well at Edgware in Q4 2011.
Gulf of Mexico - We returned to drilling in the Gulf of Mexico during the second quarter with the spud of our Kakuna well in late June. We expect to conclude drilling operations at Kakuna in the next few months.
Drilling also started in the third quarter at Appomattox on an appraisal well in the northeast fault block of the structure to follow up on our success in the southern fault block. This well is expected to be complete in the fourth quarter and will be followed by other appraisal and exploration in the area. Nexen has a 20% working interest in Appomattox; the remaining 80% is held by Shell, who is the operator.
Oil Sands
Long Lake - We continue to progress our strategy to increase bitumen production to fill the upgrader. This action plan is focused on the continued drilling of high-quality resource at Long Lake and the advancement of development of a portion of the Kinosis lease.
Our action plan is expected to provide us with an attractive return on capital as each incremental barrel of production contributes significantly to cash flow and profitability given the primarily fixed costs of the Long Lake operation.
In addition to continuing to optimize production from the initial 10 pads, our plans to fill the upgrader include:
Drilling on pad 12 was completed during the third quarter, and drilling on pad 13 continues to proceed as planned. These pads have specifically targeted geologically high-quality areas of the lease and our drilling results are confirming our expectations around reservoir quality. We expect to begin steaming pad 12 in spring 2012 and pad 13 in fall 2012. First oil would then follow about three months later, with ramp-up occurring over the following 18 months.
We continue to work through the engineering and regulatory processes for pads 14 and 15 at Long Lake. Similar work is ongoing for 25-30 wells on the Kinosis lease, which is along the southern border of the Long Lake lease. These wells will be drilled in high-quality resource where our extensive information and analysis indicates that their geological characteristics are similar to our current best-producing areas. Drilling on these pads is expected to take place in 2012 or 2013 with first steam at the end of 2013 or in 2014, subject to regulatory approvals.
We are also continuing work on a non-operated SAGD project at Hangingstone, of which we own 25%. Project sanctioning is expected early next year, and first steam would be in 2015. Our share of production at full rates is expected to be about 6,000 bbls/d.
Shale Gas
Northeast British Columbia - Our shale gas program continued to progress during the third quarter as we fraced and completed our nine-well pad. Start-up activities on this pad are currently underway and the production from this pad should allow us to produce to our current facility limit of 50 mmcf/d until additional facility expansions come online a year from now. We reduced our pad costs to under $700,000/frac on the nine-well pad, 5% below 2010 levels. Since 2009, these costs have dropped almost 70%.
Drilling continues on our first 18-well pad, with start-up scheduled for late 2012 and associated peak field volumes of around 155 mmcf/d expected in early 2013. We expect to be able to reduce our pad costs a further 7-12% on this pad through application of previous learnings and economies of scale.
Our process to secure a JV partner to accelerate value realization for a portion of our northeast BC shale gas asset is proceeding well.
Quarterly Dividend
The Board of Directors has declared the regular quarterly dividend of $0.05 per common share payable January 1st, 2012, to shareholders of record on December 9th, 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 27th, 2010. For more information on our estimates of reserves, please refer to our 2010 Annual Information Form. For more information on our estimates of resource, please refer to our press release dated November 15th, 2010.
Conference Call
Marvin Romanow, President and CEO, and Kevin Reinhart, Executive Vice President and CFO, will discuss the financial and operating results and expectations for the future.
Conference Call Details: Date: October 27th, 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) 340-8527 (Toronto)
(877) 440-9795 (North American toll-free)
(800) 2787-2090 (Global toll-free)
A replay of the call will be available for two weeks starting at 9:00 a.m. Mountain Time, October 27th by calling (905) 694-9451 (Toronto) or (800) 408-3053 (toll-free) passcode 7426133 followed by the pound sign.
We invite you to visit our website at to listen to a live webcast of the conference call. The webcast will be archived under the Investors section of our website.
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 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:
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:
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.
Unaudited Condensed Consolidated Financial Statements For the Three and Nine Months ended September 30, 2011
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Unaudited Condensed Consolidated Statement of Income
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Unaudited Condensed Consolidated Balance Sheet
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Unaudited Condensed Consolidated Statement of Cash Flows
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Unaudited Condensed Consolidated Statement of Changes in Equity
For the Three and Nine Months Ended September 30
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Unaudited Condensed Consolidated Statement of Comprehensive Income
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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 nine months ended September 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 nine months ended September 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 October 26, 2011 and should be read in conjunction with the Audited Consolidated Financial Statements for the year ended December 31, 2010, which have been prepared in accordance with Canadian GAAP.
2. ACCOUNTING POLICIES
The accounting policies 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.
3. ACCOUNTS RECEIVABLE
Receivables are generally on 30-day terms and were current as of September 30, 2011, December 31, 2010 and January 1, 2010.
4. INVENTORIES AND SUPPLIES
5. PROPERTY, PLANT AND EQUIPMENT (PP&E)
(a) Carrying amount of PP&E
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 the third quarter of 2011 includes non-cash impairment charges of $141 million for our Canadian coalbed methane and conventional gas assets included within our Conventional North America segment. Lower estimated future natural gas prices in the quarter resulted in impairment of the properties.
Our DD&A expense for the third quarter of 2010 includes non-cash impairment charges of $59 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 the properties' estimated fair value less costs to sell.
The properties were written down to the higher amount of value in use and estimated fair value less costs to sell. We estimated fair value based on discounted future net cash flows using market-based future prices, an after-tax discount rate of 9% and management's estimate of future production, capital and operating expenditures.
6. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES
7. LONG-TERM DEBT
(a) Term credit facilities
We have unsecured term credit facilities of $3.2 billion (US$3.1 billion) available until 2016, none of which were drawn at either September 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 nine months ended September 30, 2011, we did not incur interest expense on our term credit facilities. At September 30, 2011, $271 million (US$261 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
In the second quarter 2011, we redeemed and cancelled US$500 million of principal from bonds due in 2013. We paid $525 million for the redemption. We recorded a $52 million loss as the difference between carrying value and the redemption price.
(c) Repurchase for Cancellation of Certain 2015 and 2017 Notes
In the first quarter 2011, we repurchased and cancelled US$124 million and US$188 million of principal from the 2015 and 2017 bonds, respectively. We paid $346 million for the repurchase and recorded a $39 million loss as the difference between carrying value and the redemption price.
(d) Short-term borrowings
Nexen has uncommitted, unsecured credit facilities of approximately $466 million (US$449 million), none of which were drawn at either September 30, 2011 or December 31, 2010. We utilized $8 million (US$8 million) of these facilities to support outstanding letters of credit at September 30, 2011 (December 31, 2010-$112 million (US$112 million)). Interest is payable at floating rates.
8. FINANCE EXPENSE
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:
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 3.1% (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 $368 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 September 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 nine months ended September 30, 2011 and 2010.
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 September 30, 2011, there were 527,406,242 common shares outstanding (December 31, 2010 - 525,706,403 shares; January 1, 2010 - 522,915,843 shares). There were no preferred shares issued and outstanding as at September 30, 2011 (December 31, 2010 - nil; January 1, 2010 - nil).
(b) Dividends
Dividends paid per common share for the three months ended September 30, 2011 were $0.05 per common share (three months ended September 30, 2010 - $0.05). Dividends per common share for the nine months ended September 30, 2011 were $0.15 per common share (nine months ended September 30, 2010 - $0.15). Dividends paid to holders of common shares have been designated as "eligible dividends" for Canadian tax purposes. On October 26, 2011, the Board of Directors declared a quarterly dividend of $0.05 per common share, payable January 1, 2012 to the shareholders of record on December 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. Our operating leases, transportation and storage commitments, and drilling rig commitments as at September 30, 2011 have not materially changed from the information previously disclosed in Note 12 to the Unaudited Condensed Consolidated Financial Statements for the three and six months ended June 30, 2011 and Note 15 to the 2010 Audited Consolidated Financial Statements.
13. MARKETING AND OTHER INCOME
DISPOSITIONS
(a) 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.
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 September 30, 2011.
(b) Asset Dispositions
Natural Gas Energy Marketing Disposition
During the third quarter of 2010, we sold our North American natural gas marketing operations. The sale, which generated proceeds of $11 million, closed in the third quarter of 2010 and we recognized a non-cash loss of $259 million, primarily related to the transfer of long-term physical transportation commitments. On closing, the purchaser acquired our North American natural gas storage and transportation commitments, natural gas inventory, and related financial and physical derivative positions.
Canadian Undeveloped Oil Sand Leases
During the second quarter of 2010, we sold our non-core lands in the Athabasca region for proceeds of $81 million. We had no plans to develop these lands for at least a decade. We recognized a gain on sale of $80 million in the second quarter of 2010.
15. CASH FLOWS
(a) Charges and credits to income not involving cash
(b) Changes in non-cash working capital
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. 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 of the Unaudited Condensed Consolidated Financial Statements for the three months ended March 31, 2011. Net income (loss) of our operating segments excludes interest income, interest expense, unallocated corporate expenses and foreign exchange gains and losses. Identifiable assets are those used in the operations of the segments.
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 of the Unaudited Condensed Consolidated Financial Statements for the three months ended March 31, 2011. The consolidated financial statements for the year ended December 31, 2011 will be the first annual financial statements that comply with IFRS by applying existing IFRS with an effective date of December 31, 2011 or earlier. This transition note explains the material adjustments we made to convert our financial statements to IFRS.
Elected Exemptions from Full Retrospective Application
In preparing these Unaudited Condensed Consolidated Financial Statements in accordance with IFRS 1 First-time Adoption of International Financial Reporting Standards (IFRS 1), we applied the following optional exemptions from full retrospective application of IFRS.
(i) Business Combinations
We applied the business combinations exemption to not apply IFRS 3 Business Combinations retrospectively to past business combinations. Accordingly, we have not restated business combinations that took place prior to the transition date.
(ii) Fair Value or Revaluation as Deemed Cost
We elected to measure certain producing oil and gas properties at fair value as at the transition date and use that amount as its deemed cost in the opening IFRS balance sheet.
(iii) Cumulative Translation Differences
We elected to set the cumulative translation account, 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 only from the transition date. As a result, borrowing costs previously capitalized under Canadian GAAP were expensed to retained earnings.
Mandatory Exceptions to Retrospective Application
In preparing these Unaudited Condensed Consolidated Financial Statements in accordance with IFRS 1, we were required to apply the following mandatory exceptions from full retrospective application of IFRS.
(i) Hedge Accounting
Only hedging relationships that satisfied the hedge accounting criteria as of the transition date are reflected as hedges in our results under IFRS. Any derivatives not meeting the IAS 39 Financial Instruments: Recognition and Measurement criteria for hedge accounting were recorded as a non-hedging derivative financial instrument.
(ii) Estimates
Hindsight was not used to create or revise estimates and accordingly, our estimates previously made under Canadian GAAP are consistent with their application under IFRS.
Reconciliations of Canadian GAAP to IFRS
IFRS 1 requires the presentation of a reconciliation of shareholders' equity, net income, comprehensive income, and cash flows for prior periods. The transition from Canadian GAAP to IFRS had no material effect upon previously reported cash flows. The following represents the reconciliations from Canadian GAAP to IFRS for the respective periods for shareholders' equity, net income, and comprehensive income:
(i) Borrowing Costs
We applied the IFRS 1 exemption to prospectively capitalize borrowing costs only from the transition date as described above.
(ii) Asset Retirement Obligations (ARO)
We applied the IFRS 1 exemption for asset retirement obligations and re-measured our ARO as at January 1, 2010 as described above.
(iii) Employee Benefits
We have chosen to include previously unrecognized actuarial gains and losses of our defined benefit pension plans on the balance sheet under IFRS. Under Canadian GAAP, we amortized actuarial gains and losses to income over the estimated average remaining service life, with disclosure of the unrecognized amount in the notes to the Consolidated Financial Statements. On January 1, 2010, we applied the IFRS 1 exemption to recognize the accumulated unrecognized net actuarial loss in retained earnings on transition to IFRS.
(iv) Stock-Based Compensation (SBC)
Under Canadian GAAP, we recorded obligations for liability-based stock compensation plans using the intrinsic-value method of accounting. IFRS requires that we record these SBC obligations at fair value and subsequently re-measure the obligation each reporting period. Our tandem option, stock appreciation rights and restricted share unit plans are considered liability-based stock compensation plans. On transition, we recorded the liability at fair value for unsettled awards.
(v) Property Plant and Equipment
Impairment
Under Canadian GAAP, if indications of impairment exist and the asset's estimated undiscounted future cash flows were lower than 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
(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 $88 million for the three and nine months ended September 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 $28 million and $50 million for the three and nine months ended September 30, 2010, respectively, and $19 million for the twelve months ended December 31, 2010.
(i) Foreign Currency Translation
Transitional adjustments reflect the foreign currency exchange impact of the IFRS adjustments during the respective periods.
(ii) Employee Benefits
As described in Note 2 of the Unaudited Condensed Consolidated Financial Statements for the three months ended March 31, 2011, actuarial gains and losses are recognized directly in other comprehensive income in the period in which they occur. For the twelve months ended December 31, 2010, actuarial losses on our defined benefit plans reduced other comprehensive income by $35 million.
Contacts:
Janet Craig
Vice President, Investor Relations
(403) 699-4230
Pierre Alvarez
Vice President, Corporate Relations
(403) 699-5202
Nexen Inc.
801 - 7th Ave SW
Calgary, Alberta, Canada T2P 3P7
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Datum: 27.10.2011 - 09:30 Uhr
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